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Fig. 9. Relation between fraction of conversion (f) and production index of all the shales. Note: sample CG 1285 (Barakar Formation) is the heat affected shale, while samples CG 1016 and CG 1020 (Raniganj Formation) shows greater content of micrinites.

Figure 9 Relation between fraction of conversion (f) and production index of all the shales. Note: sample CG 1285 (Barakar Formation) is the heat affected shale, while samples CG 1016 and CG 1020 (Raniganj Formation) shows greater content of micrinites.

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The Raniganj basin, which covers an area of 1900 km? between the Damodar and Ajay rivers, forms the easternmost intracratonic rift The lower Gondwana formations were deposited over the Precam- brian basement. The central part of the Raniganj basin is characterized by the presence of Salma dolerite dyke, which marks a NNW-SSE trending relatively long-lived basement high and runs across the basin (Ghosh, 2002). This basement high separated the eastern and western sub-basins of the Raniganj basin during the deposition of the Damuda Group (Barakar, Barren Measures and Raniganj Formations; Figs. 1 and 3). The lamprophyre intrusives in the Raniganj basin are known to have produced the pyrolized coal (natural coke; jhama). They also continue into the surrounding country rocks (Gee, 1932), even across Fig. 1. Geological map of Raniganj basin (after Gee, 1932; GSI, 2003). Fig. 1a shows the disposition of the Gondwana basins on the Indian peninsular craton. Fig. 1b shows the distribution of Damodar Valley basins within the country while Fig. 1c shows the geological map of Raniganj basin. Explanations — Si: Sitarampur area; Ku: Kulti area; A: Andal area; I: Icchapur area.
The Raniganj basin, which covers an area of 1900 km? between the Damodar and Ajay rivers, forms the easternmost intracratonic rift The lower Gondwana formations were deposited over the Precam- brian basement. The central part of the Raniganj basin is characterized by the presence of Salma dolerite dyke, which marks a NNW-SSE trending relatively long-lived basement high and runs across the basin (Ghosh, 2002). This basement high separated the eastern and western sub-basins of the Raniganj basin during the deposition of the Damuda Group (Barakar, Barren Measures and Raniganj Formations; Figs. 1 and 3). The lamprophyre intrusives in the Raniganj basin are known to have produced the pyrolized coal (natural coke; jhama). They also continue into the surrounding country rocks (Gee, 1932), even across Fig. 1. Geological map of Raniganj basin (after Gee, 1932; GSI, 2003). Fig. 1a shows the disposition of the Gondwana basins on the Indian peninsular craton. Fig. 1b shows the distribution of Damodar Valley basins within the country while Fig. 1c shows the geological map of Raniganj basin. Explanations — Si: Sitarampur area; Ku: Kulti area; A: Andal area; I: Icchapur area.
Fig. 2. a: Cross section between Bhadulia outlier and Panchet hill of the Raniganj basin (after Ghosh, 2002). b: Cross section between Panchet hill and Jaideb high of the Raniganj basin (after Ghosh, 2002).
Fig. 2. a: Cross section between Bhadulia outlier and Panchet hill of the Raniganj basin (after Ghosh, 2002). b: Cross section between Panchet hill and Jaideb high of the Raniganj basin (after Ghosh, 2002).
Fig. 3. Generalized stratigraphic succession of Raniganj basin (after GSI, 2003; Mukhopadhyay et al., 2010). Formation symbols are used on the geologic maps shown on Fig. 1a and b. (#: These formations have not been marked in the geological map in Fig. 1). Note the symbol + represents the potential shale gas horizons.
Fig. 3. Generalized stratigraphic succession of Raniganj basin (after GSI, 2003; Mukhopadhyay et al., 2010). Formation symbols are used on the geologic maps shown on Fig. 1a and b. (#: These formations have not been marked in the geological map in Fig. 1). Note the symbol + represents the potential shale gas horizons.
Explanations — Fm: Formation; SN: sample number; $1: free hydrocarbons present in the rock (mg HC/g of rock); $2: remaining generation potential (mg HC/g of rock); S20: original S2 of the studied shale samples; S3: oxidizable carbon, (mg CO2/g rock); TOC(wt.%): total organic carbon; TOC : original TOC content of the studied shale samples; HI: hydrogen Index, [(S2/TOC) x 100 mg HC/g TOC]; Hlo: original hydrogen index of the studied shale samples; Tmax: maturity parameter based on the temperature at which the maximum amount of pyrolyzate (S2) is generated from the kerogen in a rock sample; PI: production index denoting ratio of free hydrocarbons to total hydrocarbons [S1/(S1 + S2)]; f: fraction of conversion that the kerogen has undergone; BF: Barakar Formation; BMF: Barren Measures Formation; RF: Raniganj Formation; note: Sitarampur, Kulti, Icchapur and Andal areas are marked as Si, Ku, I and A on geological map exhibited in Fig. 1. Table 1
Explanations — Fm: Formation; SN: sample number; $1: free hydrocarbons present in the rock (mg HC/g of rock); $2: remaining generation potential (mg HC/g of rock); S20: original S2 of the studied shale samples; S3: oxidizable carbon, (mg CO2/g rock); TOC(wt.%): total organic carbon; TOC : original TOC content of the studied shale samples; HI: hydrogen Index, [(S2/TOC) x 100 mg HC/g TOC]; Hlo: original hydrogen index of the studied shale samples; Tmax: maturity parameter based on the temperature at which the maximum amount of pyrolyzate (S2) is generated from the kerogen in a rock sample; PI: production index denoting ratio of free hydrocarbons to total hydrocarbons [S1/(S1 + S2)]; f: fraction of conversion that the kerogen has undergone; BF: Barakar Formation; BMF: Barren Measures Formation; RF: Raniganj Formation; note: Sitarampur, Kulti, Icchapur and Andal areas are marked as Si, Ku, I and A on geological map exhibited in Fig. 1. Table 1
Fig. 4. Relationship between genetic potential (GP; mg HC/g rock) and TOC (wt.%) content of the shale samples. Note: sample CG 1285 is the heat affected shale (Barakar Formation). where, T1 = T2 (T1 = water bath temperature; T2 = sample cell tem- perature); P1 = reference cell pressure; V1 = reference cell volume; P2 = equilibrium pressure (reference cell + sample cell); V2 = gas adsorbed volume (volume of sample cell — dead volume — sample volume). The following Langmuir adsorption isotherm pattern is used for plotting and estimation of Langmuir coefficients: where type I, type II, type II] and type IV indicate respective kerogen types. Thus
Fig. 4. Relationship between genetic potential (GP; mg HC/g rock) and TOC (wt.%) content of the shale samples. Note: sample CG 1285 is the heat affected shale (Barakar Formation). where, T1 = T2 (T1 = water bath temperature; T2 = sample cell tem- perature); P1 = reference cell pressure; V1 = reference cell volume; P2 = equilibrium pressure (reference cell + sample cell); V2 = gas adsorbed volume (volume of sample cell — dead volume — sample volume). The following Langmuir adsorption isotherm pattern is used for plotting and estimation of Langmuir coefficients: where type I, type II, type II] and type IV indicate respective kerogen types. Thus
Fig. 5. Photomicrographs showing various macerals. A: view of sample CG 1285 under reflected light showing high bireflectance developed within the vitrinite maceral; B: view of sampl CG 1016 under reflected light showing the presence of collotelinite (Co) with higher reflectance; C: view of sample CG 1020 under reflected light showing the presence of micrinite (Mic within vitrinite; D: view of sample CG 1011 under fluorescence showing the presence of alginite (Algi). Explanations — Py: pyrite; Co: collotelinite; Cy: clay; Mic: micrinite; Algi: alginite
Fig. 5. Photomicrographs showing various macerals. A: view of sample CG 1285 under reflected light showing high bireflectance developed within the vitrinite maceral; B: view of sampl CG 1016 under reflected light showing the presence of collotelinite (Co) with higher reflectance; C: view of sample CG 1020 under reflected light showing the presence of micrinite (Mic within vitrinite; D: view of sample CG 1011 under fluorescence showing the presence of alginite (Algi). Explanations — Py: pyrite; Co: collotelinite; Cy: clay; Mic: micrinite; Algi: alginite
Explanations — Fm: Formation; SN: sample number; VRo: range of reflectance (in oil) of vitrinite grains (%);Romv: mean vitrinite reflectance (in oil, %); EVRo: estimated vitrinite reflec tance from Tynax Values of rock eval pyrolysis (%); 5: standard deviation; v: coefficient of variation (v = 5*100/Romv) %; H: coefficient of non-equality (H = 57*100/Romv) %; T Vto: vitrinite grains (vol.%) with reflectance (in oil) greater than 0.60%; | Vtso: vitrinite grains (vol.%) with reflectance (in oil) smaller than 0.50%; Av: difference between EVRo and Romy; BF: Baraka: Formation; BMF: Barren Measures Formation; RF: Raniganj Formation. Vitrinite reflectance analysis and estimated vitrinite reflectance. Table 2
Explanations — Fm: Formation; SN: sample number; VRo: range of reflectance (in oil) of vitrinite grains (%);Romv: mean vitrinite reflectance (in oil, %); EVRo: estimated vitrinite reflec tance from Tynax Values of rock eval pyrolysis (%); 5: standard deviation; v: coefficient of variation (v = 5*100/Romv) %; H: coefficient of non-equality (H = 57*100/Romv) %; T Vto: vitrinite grains (vol.%) with reflectance (in oil) greater than 0.60%; | Vtso: vitrinite grains (vol.%) with reflectance (in oil) smaller than 0.50%; Av: difference between EVRo and Romy; BF: Baraka: Formation; BMF: Barren Measures Formation; RF: Raniganj Formation. Vitrinite reflectance analysis and estimated vitrinite reflectance. Table 2
Fig. 6. Relation between Romv (%) and EVRo (%) for the Barren Measures and Baraka Formation shales (except CG 1285).
Fig. 6. Relation between Romv (%) and EVRo (%) for the Barren Measures and Baraka Formation shales (except CG 1285).
Fig. 7. Relation between HI and Tmax for the shales belonging to the Barakar Formation (only from the Sitarampur area) and the Barren Measures Formation (only from the Kulti area).
Fig. 7. Relation between HI and Tmax for the shales belonging to the Barakar Formation (only from the Sitarampur area) and the Barren Measures Formation (only from the Kulti area).
Explanations — Fm: formation; SN: sample number; V: vitrinite macerals; I: inertinite macerals; L: liptinite macerals other than alginite; A: alginite macerals; Te: telinite; Co: collotelinite; Vd: vitrodetrinite; CoD: collodetrinite; V"™": sum of vitrinite macerals (mineral matter free basis); Osf: oxysemifusinite; Psf: pyrosemifusinite; Of: oxyfusinite; Pf: pyrofusinite; Ind: inertodetrinite; Mic: micrinite; ™™': sum of inertinite macerals (mineral matter free basis); Spo: sporinite; Ld: liptodetrinite; L"™': sum of liptinite macerals other than alginite (mineral matter free basis); A™™: alginite (mineral matter free basis). Table 3
Explanations — Fm: formation; SN: sample number; V: vitrinite macerals; I: inertinite macerals; L: liptinite macerals other than alginite; A: alginite macerals; Te: telinite; Co: collotelinite; Vd: vitrodetrinite; CoD: collodetrinite; V"™": sum of vitrinite macerals (mineral matter free basis); Osf: oxysemifusinite; Psf: pyrosemifusinite; Of: oxyfusinite; Pf: pyrofusinite; Ind: inertodetrinite; Mic: micrinite; ™™': sum of inertinite macerals (mineral matter free basis); Spo: sporinite; Ld: liptodetrinite; L"™': sum of liptinite macerals other than alginite (mineral matter free basis); A™™: alginite (mineral matter free basis). Table 3
Fig. 8. Relation between fraction of conversion (f) and T,,ax values for the Barakar Forma- tion shales only from the Sitarampur (Si) area. TOC respectively; Table 1). In samples CG 1016 (Fig. 5B) and CG 1020 (Fig. 5C), the higher expulsion is manifested by the formation of pores and greater amount of micrinites through micrinitization process. It should be pointed out that in all the cases the vitrinite macerals have been largely altered thereby increasing their reflectance. This explains
Fig. 8. Relation between fraction of conversion (f) and T,,ax values for the Barakar Forma- tion shales only from the Sitarampur (Si) area. TOC respectively; Table 1). In samples CG 1016 (Fig. 5B) and CG 1020 (Fig. 5C), the higher expulsion is manifested by the formation of pores and greater amount of micrinites through micrinitization process. It should be pointed out that in all the cases the vitrinite macerals have been largely altered thereby increasing their reflectance. This explains
Fig. 11. Relation between dispersed organic matter (total maceral content), vol.% and present day TOC, wt.% content of the studied shale samples. HI values of the Barakar, Barren Measures and Raniganj Formation shales indicate input of dominantly type III organic matter, with admixed type II/Ill at places (Varma et al., 2014c, 2014d, 2015a). However, typifying organic matter based on HI values alone may be er- roneous. Hydrogen indices of organic matter decrease with increasing
Fig. 11. Relation between dispersed organic matter (total maceral content), vol.% and present day TOC, wt.% content of the studied shale samples. HI values of the Barakar, Barren Measures and Raniganj Formation shales indicate input of dominantly type III organic matter, with admixed type II/Ill at places (Varma et al., 2014c, 2014d, 2015a). However, typifying organic matter based on HI values alone may be er- roneous. Hydrogen indices of organic matter decrease with increasing
Fig. 10. V-step reflectograms of few shale samples.
Fig. 10. V-step reflectograms of few shale samples.
Fig. 12. Relation between original TOC content (TOC)), wt.% and DOM (total maceral content), vol.% of the studied shale samples. maturity due to conversion of kerogen to hydrocarbons (Behar and Vandenbroucke, 1987; Behar et al., 1992). Among the Barakar Forma- tion shales from the Kulti (Ku) area (placed within the vitrinite reflec- tance oil window) no relationship was observed between HI and Tinax values; while a strong negative relationship was observed in case of the shales from the Sitarampur (Si) area (R* = 0.97; Fig. 7) owing to their higher maturities placing them within the condensate wet gas window (Varma et al., 2014c). Similarly no relations were observed be- tween the two variables for the shale samples of the Raniganj Formation (Varma et al., 2015a). In general a weak negative trend/no trend is ob- served (R? = 0.15) between HI and Tmax for all the Barren Measures
Fig. 12. Relation between original TOC content (TOC)), wt.% and DOM (total maceral content), vol.% of the studied shale samples. maturity due to conversion of kerogen to hydrocarbons (Behar and Vandenbroucke, 1987; Behar et al., 1992). Among the Barakar Forma- tion shales from the Kulti (Ku) area (placed within the vitrinite reflec- tance oil window) no relationship was observed between HI and Tinax values; while a strong negative relationship was observed in case of the shales from the Sitarampur (Si) area (R* = 0.97; Fig. 7) owing to their higher maturities placing them within the condensate wet gas window (Varma et al., 2014c). Similarly no relations were observed be- tween the two variables for the shale samples of the Raniganj Formation (Varma et al., 2015a). In general a weak negative trend/no trend is ob- served (R? = 0.15) between HI and Tmax for all the Barren Measures
Explanations — Fm: Formation; SN: sample number; W: moisture content; A: ash yield; VM: volatile matter yield; FC: fixed carbon; FR: fuel ratio; BF: Barakar Formation; BMF: Barren Measures Formation; RF: Raniganj Formation. Proximate analysis of shale samples. Table 4
Explanations — Fm: Formation; SN: sample number; W: moisture content; A: ash yield; VM: volatile matter yield; FC: fixed carbon; FR: fuel ratio; BF: Barakar Formation; BMF: Barren Measures Formation; RF: Raniganj Formation. Proximate analysis of shale samples. Table 4
Fig. 13. Relation between fixed carbon (FC) content, wt.% and TOC, wt.% content for studied shale samples. Note: sample CG 1285 (Barakar Formation) is the heat affected shale while samples CG 1013 and CG 1251 (Raniganj Formation) represents the shales with high TOC content. Formation shales. However the coefficient of determination in the plot between HI and T;nax for the samples only from Kulti (Ku) area is higher (R? = 0.52; Fig. 7). Results from petrographic studies also indicate that while the Barakar Formation shales dominantly consists of vitrinites and inertinites, the shales from Barren Measures in addition to vitrinites and inertinites, are marked by input of type I alginites (Fig. 5D) and type
Fig. 13. Relation between fixed carbon (FC) content, wt.% and TOC, wt.% content for studied shale samples. Note: sample CG 1285 (Barakar Formation) is the heat affected shale while samples CG 1013 and CG 1251 (Raniganj Formation) represents the shales with high TOC content. Formation shales. However the coefficient of determination in the plot between HI and T;nax for the samples only from Kulti (Ku) area is higher (R? = 0.52; Fig. 7). Results from petrographic studies also indicate that while the Barakar Formation shales dominantly consists of vitrinites and inertinites, the shales from Barren Measures in addition to vitrinites and inertinites, are marked by input of type I alginites (Fig. 5D) and type
Fig. 14. a: Adsorption isotherms for the samples CG 1001, CG 1002 and CG 1003 (Barren Measures Formation). Explanation — AGC: adsorbed gas content. The reservoir temperatures at which the experiments were carried out are mentioned. b: Adsorption isotherms for the samples CG 1013, CG 1016, CG 1020 and CG 1021 (Raniganj Formation). Explanation — AGC: adsorbed gas content. The reservoir temperatures at which the experiments were carried out are mentioned. Weak correlations were observed between f and Tmax (R* = 0.49) and between f and Romv (R? = 0.46) for the shales from the Barakar Formation. However strong positive relation was observed between f and Tmax (R? = 0.88; Fig. 8) only for the Barakar Formation shales from the Sitarampur area. This further puts forward the fact that fraction of conversion (and decrease in HI) increases with increasing maturity. No relations were observed between f and Tmax and between f and Romv for the shales from the Barren Measures Formation. For the Barren Measures shale samples the maximum fraction of conversion is shown by sample CG 1001 (f = 0.64). In general the f for the Barren Measures Formation shales varies between 0.12-0.64 with an average f of 0.47. As already mentioned, the Barren Measures shales are com- posed of type I alginites, type II sporinites, type III vitrinites and type IV inertinites. Type I alginites and type II sporinites are more prone to conversion than type III vitrinites or type IV inertinites, and thus the Barren Measures Formation shales even though they are within the oil window shows a higher f. The lack of relationship between f and
Fig. 14. a: Adsorption isotherms for the samples CG 1001, CG 1002 and CG 1003 (Barren Measures Formation). Explanation — AGC: adsorbed gas content. The reservoir temperatures at which the experiments were carried out are mentioned. b: Adsorption isotherms for the samples CG 1013, CG 1016, CG 1020 and CG 1021 (Raniganj Formation). Explanation — AGC: adsorbed gas content. The reservoir temperatures at which the experiments were carried out are mentioned. Weak correlations were observed between f and Tmax (R* = 0.49) and between f and Romv (R? = 0.46) for the shales from the Barakar Formation. However strong positive relation was observed between f and Tmax (R? = 0.88; Fig. 8) only for the Barakar Formation shales from the Sitarampur area. This further puts forward the fact that fraction of conversion (and decrease in HI) increases with increasing maturity. No relations were observed between f and Tmax and between f and Romv for the shales from the Barren Measures Formation. For the Barren Measures shale samples the maximum fraction of conversion is shown by sample CG 1001 (f = 0.64). In general the f for the Barren Measures Formation shales varies between 0.12-0.64 with an average f of 0.47. As already mentioned, the Barren Measures shales are com- posed of type I alginites, type II sporinites, type III vitrinites and type IV inertinites. Type I alginites and type II sporinites are more prone to conversion than type III vitrinites or type IV inertinites, and thus the Barren Measures Formation shales even though they are within the oil window shows a higher f. The lack of relationship between f and
Explanations — Fm: Formation; SN: sample number; MSC: methane sorption capacity (mmol/g rock); V,: Langmuir volume (mmol/g rock); MSC*: TOC-normalized methane sorption capacity (mmol/g TOC); V,*: TOC-normalized Langmuir volume (mmol/g TOC); Pi: Langmuir pressure (kPa); BF: Barakar Formation; BMF: Barren Measures Formation; RF: Raniganj Formation; Rt: reservoir temperature (at which the adsorption isotherm experiment was conducted). Methane sorption capacity and Langmuir volume of the analyzed samples Table 5
Explanations — Fm: Formation; SN: sample number; MSC: methane sorption capacity (mmol/g rock); V,: Langmuir volume (mmol/g rock); MSC*: TOC-normalized methane sorption capacity (mmol/g TOC); V,*: TOC-normalized Langmuir volume (mmol/g TOC); Pi: Langmuir pressure (kPa); BF: Barakar Formation; BMF: Barren Measures Formation; RF: Raniganj Formation; Rt: reservoir temperature (at which the adsorption isotherm experiment was conducted). Methane sorption capacity and Langmuir volume of the analyzed samples Table 5
Fig. 15. Relation between Langmuir volume (V,;, mmol/g rock) and TOC, wt.% content for the shales belonging the Raniganj (Fig. 15A) and Barren Measures Formation (Fig. 15B). maturity parameters (Tax and Romv) further substantiates that f is dependent upon kerogen type and would change from one kerogen type to another (Jarvie et al., 2007) at a definite maturity level. The moderate correlation between f and T,,,, and between f and Romv for the dominantly type III shales from the Barakar Formation also indicates the same (Jarvie et al., 2007). the two (Fig. 9), a closer look revealed some important information. Sample CG 1285 (heat affected shale) inspite of having a very high frac- tion of conversion, shows comparatively lower PI value (as S1 is small) indicating expulsion/removal of hydrocarbons from the sample, thus pointing that higher fraction of conversion doesn't necessarily mean higher PI. On the other hand samples CG 1016 and CG 1020 (Raniganj Formation) shows very high PI (0.271 and 0.278 respectively) and fraction of conversion (0.60 and 0.59). In this case, both the samples are marked by larger S1 indicating larger content of free hydrocarbons within them. The higher conversion for these two samples is further explained by the formation of greater amount of micrinites through micrinitization process.
Fig. 15. Relation between Langmuir volume (V,;, mmol/g rock) and TOC, wt.% content for the shales belonging the Raniganj (Fig. 15A) and Barren Measures Formation (Fig. 15B). maturity parameters (Tax and Romv) further substantiates that f is dependent upon kerogen type and would change from one kerogen type to another (Jarvie et al., 2007) at a definite maturity level. The moderate correlation between f and T,,,, and between f and Romv for the dominantly type III shales from the Barakar Formation also indicates the same (Jarvie et al., 2007). the two (Fig. 9), a closer look revealed some important information. Sample CG 1285 (heat affected shale) inspite of having a very high frac- tion of conversion, shows comparatively lower PI value (as S1 is small) indicating expulsion/removal of hydrocarbons from the sample, thus pointing that higher fraction of conversion doesn't necessarily mean higher PI. On the other hand samples CG 1016 and CG 1020 (Raniganj Formation) shows very high PI (0.271 and 0.278 respectively) and fraction of conversion (0.60 and 0.59). In this case, both the samples are marked by larger S1 indicating larger content of free hydrocarbons within them. The higher conversion for these two samples is further explained by the formation of greater amount of micrinites through micrinitization process.
Fig. 16. Relation between ash yield, wt.% and TOC, wt.% content for the shales belonging the Raniganj (Fig. 16A) and Barren Measures Formation (Fig. 16B)
Fig. 16. Relation between ash yield, wt.% and TOC, wt.% content for the shales belonging the Raniganj (Fig. 16A) and Barren Measures Formation (Fig. 16B)
Fig. 17. A: Relation between Langmuir volume normalized to dry ash, mmol/g dry-ash and total vitrinite content, vol.% for the studied shales. B: Relation between Langmuir volume (V,), mmol/g rock and total vitrinite and inertinite content, vol.% for the studied shales. C: Relation between Langmuir volume normalized to dry ash, mmol/g dry-ash and total vitrinite and inertinite content, vol.% for the studied shales.
Fig. 17. A: Relation between Langmuir volume normalized to dry ash, mmol/g dry-ash and total vitrinite content, vol.% for the studied shales. B: Relation between Langmuir volume (V,), mmol/g rock and total vitrinite and inertinite content, vol.% for the studied shales. C: Relation between Langmuir volume normalized to dry ash, mmol/g dry-ash and total vitrinite and inertinite content, vol.% for the studied shales.
Fig. 18. FTIR spectra of samples CG 1283, CG 1284 and CG 1285 (Barakar Formation) in the frequency interval 3200-2500 cm~! showing the aliphatic C-H stretching region with peaks at 2920 and 2850 cm~ !. While samples CG 1282 and CG 1286 having TOC contents of 14.91 and 16.36 wt.% are marked by prominent peaks, sample CG 1285 inspite of having TOC content of 22.37 wt.% has suppressed peaks. This indicates the partial removal of aliphatics caused by the lamprophyre intrusion occurring immediately above the sample.
Fig. 18. FTIR spectra of samples CG 1283, CG 1284 and CG 1285 (Barakar Formation) in the frequency interval 3200-2500 cm~! showing the aliphatic C-H stretching region with peaks at 2920 and 2850 cm~ !. While samples CG 1282 and CG 1286 having TOC contents of 14.91 and 16.36 wt.% are marked by prominent peaks, sample CG 1285 inspite of having TOC content of 22.37 wt.% has suppressed peaks. This indicates the partial removal of aliphatics caused by the lamprophyre intrusion occurring immediately above the sample.
Fig. 19. FTIR spectra of samples CG 1283, CG 1284 and CG 1285 (Barakar Formation) in the frequency interval 3750-3500 cm~!, showing the form of kaolinite in the three samples Note the arrows indicating the peaks of kaolinite in all the three samples. Comparison o! the kaolinite peaks in all the three samples clearly indicates that the kaolinites withir CG 1285 might have undergone certain degree of disordering due to the impact of the lamprophyre intrusion occurring immediately above it.
Fig. 19. FTIR spectra of samples CG 1283, CG 1284 and CG 1285 (Barakar Formation) in the frequency interval 3750-3500 cm~!, showing the form of kaolinite in the three samples Note the arrows indicating the peaks of kaolinite in all the three samples. Comparison o! the kaolinite peaks in all the three samples clearly indicates that the kaolinites withir CG 1285 might have undergone certain degree of disordering due to the impact of the lamprophyre intrusion occurring immediately above it.
Fig. 20. FTIR spectra of shale samples CG 1016 and CG 1020 in the frequency interval 4000-3000 cm~! showing the probable disordering of kaolinite within the two samples. The dotted lines 1 and 2 represent peaks at approximately 3695 and 3625 cm~! respectively.
Fig. 20. FTIR spectra of shale samples CG 1016 and CG 1020 in the frequency interval 4000-3000 cm~! showing the probable disordering of kaolinite within the two samples. The dotted lines 1 and 2 represent peaks at approximately 3695 and 3625 cm~! respectively.
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