Gas reservoir characteristics of the Lower Gondwana Shales in Raniganj Basin of Eastern India

In India, Raniganj basin has become a prime target for shale gas exploration. Investigated shale core samples obtained from 9 boreholes during exploratory drilling with laterally varying depth from 11 to 1480 m. A substantial amount of organic matter in shale beds having cumulative thickness of 86 m, 327 m and 126 m are found in Raniganj, Barren Measures and Barakar Formations respectively. The total organic content (TOC) of shales signifies poor to excellent (1.01-12.73 wt%), while the values of S1 and S2 revealed poor to good source rock generation potential, accentuating thermally immature to moderately mature shale reservoir. The various plots like HI vs. OI, HI vs. TOC, S2 vs. TOC, PI vs. S1 and S2, implies that studied shales are gas prone containing type II/III and type III kerogen except sample no 17, which has shown type IV kerogen owing to effects of nearby igneous intrusive. Comparatively less sorption in Raniganj shales reflecting low TOC content, whereas Barren Measures and Barakar shales has moderate sorption capacities controlled by organic matter and clay minerals. Low pressure N2 adsorption-desorption isotherms are used to categorise pore geometry such as cylindrical, slit-shaped and bottle neck pores in Raniganj, Barren Measures and Barakar shales respectively. Organic content have no significant influence over the surface area, because intensified thermal stress could have caused the destruction of thinner organic pores which reduced the involvement of organic pores in surface area. The pores are classified into four types using scanning electron microscopy (SEM) taking into account the origin, size and shape of pores, i) dissolved pores - developed due to the effect of groundwater or de-carbonic acid, ii) open pores associated with organic matter - formed during thermal cracking of kerogen, iii) Intergranular pores - formed due to incomplete cementation and iv) micro fractures - owed to tectonic movements or structural activities in the basin. The in-situ gas content obtained from canister test varies from 1.937 to 2.307 m3/t, 0.378-3.035 m3/t and 0.424-1.937 m3/t for Raniganj, Barren Measures and Barakar shales respectively however, large cumulative thickness, high TOC, moderate sorption capacity, well developed pore geometry and significant surface area encourages the exploration and production development of shale gas in Raniganj basin. The estimated recoverable shale gas resource is 30.76 billion cubic meter (BCM) for Raniganj, 103.76 BCM for Barren Measures and 41.69 BCM for Barakar shales. This study would help the operators to fulfil the gap of lack of adequate knowledge to develop the shale gas play in this basin.