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Fig. 3. Bar plot showing variations in organic facies derived from Rock-Eval and vitrinite reflectance. permeability considering the core diameter, length, a pressure drop across the core (differential pressure), the gas flow rate at that pressure drop, gas viscosity and the flowing gas temperature (Temco Inc., 1998; 7 ee a a ee ee ee Porosity measurement was carried out by loading the helium gas into the reference chamber and connected to the core holder opening the inlet valve releasing some of the gas into the core and core holder plumbing dead volume. The equilibrium pressure was measured. The

Figure 3 Bar plot showing variations in organic facies derived from Rock-Eval and vitrinite reflectance. permeability considering the core diameter, length, a pressure drop across the core (differential pressure), the gas flow rate at that pressure drop, gas viscosity and the flowing gas temperature (Temco Inc., 1998; 7 ee a a ee ee ee Porosity measurement was carried out by loading the helium gas into the reference chamber and connected to the core holder opening the inlet valve releasing some of the gas into the core and core holder plumbing dead volume. The equilibrium pressure was measured. The

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Fig. 1. Geological map of Raniganj Basin (after Gee, 1932; Dutt, 2003) marked with locations of studied shale core samples.
Fig. 1. Geological map of Raniganj Basin (after Gee, 1932; Dutt, 2003) marked with locations of studied shale core samples.
Fig. 2. Stratigraphic succession of Raniganj Basin (after Dutt, 2003; Mukhopadhyay et al., 2010).
Fig. 2. Stratigraphic succession of Raniganj Basin (after Dutt, 2003; Mukhopadhyay et al., 2010).
Proximate, Rock-Eval parameters and Reflectance values of shale core samples. Explanations: m = meter, IM = inherent moisture, VM = volatile matter, FC = fixed carbon, TOC = total organic carbon, $1 (mg HC/g rock), $2 (mg HC/g rock), S3 (mg CO2/g rock), Tmax = temperature maximum, HI = hydrogen index (S2/TOC x 100, mg HC/g TOC), PI = production index (S1 + S2), VR, = vitrinite reflectance in oil, wt. = weight. Inorganic content is calculated by the formula: [100 - (volatile matter + inherent moisture + TOC)]. Table 1
Proximate, Rock-Eval parameters and Reflectance values of shale core samples. Explanations: m = meter, IM = inherent moisture, VM = volatile matter, FC = fixed carbon, TOC = total organic carbon, $1 (mg HC/g rock), $2 (mg HC/g rock), S3 (mg CO2/g rock), Tmax = temperature maximum, HI = hydrogen index (S2/TOC x 100, mg HC/g TOC), PI = production index (S1 + S2), VR, = vitrinite reflectance in oil, wt. = weight. Inorganic content is calculated by the formula: [100 - (volatile matter + inherent moisture + TOC)]. Table 1
Fig. 4. Delineation of hydrocarbon generative potential by plot of T,,a.vs hydrogen index showing the range of thermal maturity of shale samples as a function of (kerogen) types.
Fig. 4. Delineation of hydrocarbon generative potential by plot of T,,a.vs hydrogen index showing the range of thermal maturity of shale samples as a function of (kerogen) types.
Fig. 5. Vitrinite reflectance is the function of thermal maturity, a) relationship of vM“*! with VR,, b) relationship between FC“ and VR, c) relationship of Tax and VR,
Fig. 5. Vitrinite reflectance is the function of thermal maturity, a) relationship of vM“*! with VR,, b) relationship between FC“ and VR, c) relationship of Tax and VR,
Boyle's law is used to calculate the porosity (Micromeritics Instruments, 2000; Temco Inc., 1998). 3.4. Scanning electron microscopy and energy dispersive X-ray spectroscopy (SEM and EDX)
Boyle's law is used to calculate the porosity (Micromeritics Instruments, 2000; Temco Inc., 1998). 3.4. Scanning electron microscopy and energy dispersive X-ray spectroscopy (SEM and EDX)
Elemental composition obtained through SEM-EDX of shale core samples. Table 2
Elemental composition obtained through SEM-EDX of shale core samples. Table 2
Fig. 7. Triangular plot showing trend of mineral alteration and depositional environment of studied shale formations.
Fig. 7. Triangular plot showing trend of mineral alteration and depositional environment of studied shale formations.
collotelinite maceral vary from 0.52 to 0.98%; 0.73 to 1.03% and 0.73 to 1.14%, respectively for Raniganj, Barren Measures and Barakar shales respectively (Table 1). The Barakar shales are comparatively deep seated than the Raniganj and Barren Measures shales, proving the influence of thermal gradient with the depth of occurrence following Hilt’s law.
collotelinite maceral vary from 0.52 to 0.98%; 0.73 to 1.03% and 0.73 to 1.14%, respectively for Raniganj, Barren Measures and Barakar shales respectively (Table 1). The Barakar shales are comparatively deep seated than the Raniganj and Barren Measures shales, proving the influence of thermal gradient with the depth of occurrence following Hilt’s law.
Fig. 9. SEM images of the Raniganj, Barren Measures and Barakar Formations shales.
Fig. 9. SEM images of the Raniganj, Barren Measures and Barakar Formations shales.
Fig. 10. Pore network model for the Raniganj, Barren Measures and Barakar Formations shales.
Fig. 10. Pore network model for the Raniganj, Barren Measures and Barakar Formations shales.
Results of surface area obtained through low pressure N2 sorption isotherm using different methods. Fig. 11. Multipoint BET plots for surface area determination of Raniganj, Barren Measures and Barakar shales, a) sample nos. SC-11R, SC-14BM and SC-27B, b) sample nos. SC-3R, SC 16BM andSC-24B.
Results of surface area obtained through low pressure N2 sorption isotherm using different methods. Fig. 11. Multipoint BET plots for surface area determination of Raniganj, Barren Measures and Barakar shales, a) sample nos. SC-11R, SC-14BM and SC-27B, b) sample nos. SC-3R, SC 16BM andSC-24B.
Fig. 12. Langmuir plots for shales of Raniganj (a: SC-3R, b: SC-11R), Barren Measures (c: SC-16BM, d: SC-14BM) and Barakar (e: SC-27B, f: SC-24B) Formation
Fig. 12. Langmuir plots for shales of Raniganj (a: SC-3R, b: SC-11R), Barren Measures (c: SC-16BM, d: SC-14BM) and Barakar (e: SC-27B, f: SC-24B) Formation
Results of pore diameter and pore volume obtained through low pressure N2 sorption isotherm using different methods. Table 4
Results of pore diameter and pore volume obtained through low pressure N2 sorption isotherm using different methods. Table 4
Fig. 13. BJH plots used for determination of pore size and pore volume of shales from Raniganj (a: SC-3R, b: SC-11R), Barren Measures (c: SC-16BM, d: SC-14BM) and Barakar (e: SC-27B, f: SC-24B) Formations.
Fig. 13. BJH plots used for determination of pore size and pore volume of shales from Raniganj (a: SC-3R, b: SC-11R), Barren Measures (c: SC-16BM, d: SC-14BM) and Barakar (e: SC-27B, f: SC-24B) Formations.
Fig. 14. DA plots used for determination of pore size and pore volume for shales of Raniganj (a: SC-3R, b: SC-11R), Barren Measures (c: SC-16BM, d: SC-14BM) and Barakar (e: SC-27B, f SC-24B) Formations.
Fig. 14. DA plots used for determination of pore size and pore volume for shales of Raniganj (a: SC-3R, b: SC-11R), Barren Measures (c: SC-16BM, d: SC-14BM) and Barakar (e: SC-27B, f SC-24B) Formations.
Fig. 15. Relationship between average pore sizes with TOC (a), vitrinite reflectance (b), hydrogen index (c) and multipoint BET surface area (d) of shale core sample
Fig. 15. Relationship between average pore sizes with TOC (a), vitrinite reflectance (b), hydrogen index (c) and multipoint BET surface area (d) of shale core sample
Fig. 16. DR plots used for pore volume determination for shales of Raniganj (a: SC-3R, b: SC-11R), Barren Measures (c: SC-16BM, d: SC-14BM) and Barakar (e: SC-27B, f: SC-24B) Formations.
Fig. 16. DR plots used for pore volume determination for shales of Raniganj (a: SC-3R, b: SC-11R), Barren Measures (c: SC-16BM, d: SC-14BM) and Barakar (e: SC-27B, f: SC-24B) Formations.
Fig. 17. DFT plots used to determine the pore volume for shales of Raniganj (a: SC-3R, b: SC-11R), Barren Measures (c: SC-16BM, d: SC-14BM) and Barakar (e: SC-27B, f: SC-24B) Formations.
Fig. 17. DFT plots used to determine the pore volume for shales of Raniganj (a: SC-3R, b: SC-11R), Barren Measures (c: SC-16BM, d: SC-14BM) and Barakar (e: SC-27B, f: SC-24B) Formations.
Fig. 18. t-plot used for micropore volume determination of Raniganj, Barren Measures and Barakar shales.
Fig. 18. t-plot used for micropore volume determination of Raniganj, Barren Measures and Barakar shales.
Fig. 19. The relationship between total pore volumes (TPV) normalized to TOC contents and thermal maturity (VR,%) of studied shale samples
Fig. 19. The relationship between total pore volumes (TPV) normalized to TOC contents and thermal maturity (VR,%) of studied shale samples
Fig. 20. Relationship of pore volume with TOC (a) and VM“ (b) of shale core samples.
Fig. 20. Relationship of pore volume with TOC (a) and VM“ (b) of shale core samples.
Fig. 21. Relationship between multipoint BET surface area with total pore volume (a) and micropore volume (b) of shale core samples.
Fig. 21. Relationship between multipoint BET surface area with total pore volume (a) and micropore volume (b) of shale core samples.
Results of porosity and permeability measured under reservoir simulated confining pressure.
Results of porosity and permeability measured under reservoir simulated confining pressure.
Fig. 23. Geological influences on porosity and permeability, a) relationship of porosity with multipoint BET surface area, b) porosity with average pore size, c) porosity and permeability with depth, d) porosity and permeability with TOC, e) porosity with inorganic content, f) permeability with inorganic content.
Fig. 23. Geological influences on porosity and permeability, a) relationship of porosity with multipoint BET surface area, b) porosity with average pore size, c) porosity and permeability with depth, d) porosity and permeability with TOC, e) porosity with inorganic content, f) permeability with inorganic content.
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