Vinod Atmaram Mendhe

Evaluation of shale gas reservoir in Barakar and barren measures formations of north and south Karanpura Coalfields, Jharkhand

India recognizes the strategic importance for developing shale gas resources like other countries in the world. Shale gas reservoirs are known to be difficult for extracting gas in comparison to conventional reservoirs. Recently, due to high prices of gas, rising demand and enhancement in recovery technologies has attracted the Indian energy industries to explore the shale gas resource. Coal and lignite are the prime source of energy in India and these resources are well explored, while shale is ignored, despite it being associated with coal and lignite bearing formations. The paper presents reservoir characteristics of shale horizons in Barren Measures and Barakar formations of north and south Karanpura coalfields. Shale core samples were collected from exploratory boreholes in air tight canisters. In-situ gas content and adsorption capacities ascertained to be 0.51–1.69 m3/t and 3.90–5.82 m3/trespectively. Desorbed gas derived from canisters contains CH4, C2H6, C3H8, CO2, N2 and O2 and varies from 76.19–82.63, 0.38–0.76, 0.10–0.50, 8.65–12.34, 9.89–19.34 and 0.56–2.24 vol. % respectively. The permeability and porosity determined under reservoir simulated confining pressure is varying from 0.41–0.75 mD and 0.89–2.28 % respectively. The plots of Rock Eval S2vs TOC and HI against Calc. VRo% indicates that all shale samples belong to Type III kerogen, which is prone to generate gas. It is evaluated that insitu gas content, sorption capacity, saturation level and low permeability of shale beds are critical parameters for development of shale gas resource in the studied area.

Petrographic characterization and langmuir volume of shales from Raniganj coal basin, India

Shale gas is becoming a very important energy resource throughout the world. 10 borehole samples of varying depths from 755–1480m belonging to Barren Measures (upper Permian), Raniganj (upper Permian) and Panchet (lower Triassic) formations of Raniganj coal basin have been selected. Various analyses have been carried out viz. technological, elemental composition, X-ray diffraction, Fourier transform infrared (FTIR), rock eval pyrolysis, organic petrography and sorption analyses. Different types of organo-petrographic entities viz. sandy clay, clayey sand, organosandy-clay, humic clay and organic clay were identified. Shaly-microlithotypes were also differentiated. The macerals (organic matter in shales) exhibit normal maturity course. Sorption studies were used for estimating Langmuir volume of shale samples which depicts good correlation with total organic carbon (TOC), organic clay and organo-silty-clay separately. Langmuir volume was also observed to indicate good correlation with shaly-microlithotype which point towards positive role of organic matter and clay association in gas adsorption. Vt60 (volume of vitrinite grains with reflectance greater than 0.60%) indicates that Barren Measures and Raniganj Formation has good hydrocarbon generation potential.

Organo-petrographic and pore facets of Permian shale beds of Jharia Basin with implications to shale gas reservoir

The shale deposits of Damodar Valley have received great attention since preliminary studies indicate their potential for shale gas. However, fundamental information allied to shale gas reservoir characteristics are still rare in India, as exploration is in the primary stage. In this study, Barakar shale beds of eastern part of Jharia Basin are evaluated for gas reservoir characteristics. It is evident that Barakar shales are carbonaceous, silty, contains sub-angular flecks of quartz and mica, irregular hair-line fractures and showing lithological variations along the bedding planes, signifying terrestrial-fluviatile deposits under reducing environment. The values of TOC varies from 1.21 wt.% to 17.32 wt.%, indicating good source rock potentiality. The vitrinite, liptinite, inertinite and mineral matter ranging from 0.28 vol.% to 12.98 vol.%, 0.17 vol.% to 3.23 vol.%, 0.23 vol.% to 9.05 vol.%, and 74.74 vol.% to 99.10 vol.%, respectively. The ternary facies plot of maceral composition substantiated that Barakar shales are vitrinite rich and placed in the thermal-dry gas prone region. The low values of the surface area determined following different methods point towards low methane storage capacity, this is because of diagenesis and alterations of potash feldspar responsible for pore blocking effect. The pore size distribution signifying the micro to mesoporous nature, while Type II sorption curve with the H2 type of hysteresis pattern, specifies the heterogeneity in pore structure mainly combined-slit and bottle neck pores.

Management of Coalbed Methane and Coal Mine Produced Water for Beneficial Use in Damodar Basin of India

In India, coalbed methane (CBM) is rapidly emerging source of natural gas with current production levels of about 1.35 million metric standard cubic metres per day (mmscm/day) and expected to rise to 7 mmscm/day by 2020. CBM extraction associated with pumping of large amount of formation water to reduce hydrostatic pressure existing on gas-bearing coalbeds. At this time out of 32 awarded CBM blocks, only 6 blocks have commenced recovery of methane gas from about 200 wells, with water producing rate more than 20 m3 per well per day. Out of 424 underground coal mines, only 10–20 places, mine water is being used for domestic, washing of coal and other industrial uses with or without treatment. The high cost of water disposal and lack of efficient technology for treatment are barriers to advance development of CBM reserves in the country. If large amount of CBM and mine-produced water handled economically and treated efficiently to make it acceptable for different uses or surface discharge, it may become a source of fresh water. Produced water samples were collected from CBM production wells and different coal mines water disposal heads in various locations of Damodar basin and analysed using ICPMS and water analysis kit for the assessment of water quality. In CBM water the physical parameters like pH, electrical conductivity, TDS and alkalinity observed in the range of 7.23–8.72, 1678–5436 µs/cm, 1124.26–3642.26 mg/L and 1650–2150 mg/L respectively, whereas in coal mine water, it varies from 6.78 to 8.58, 623–1513 µs/cm, 417.41–1013.71 mg/L and 100–800 mg/L respectively. CBM water is mainly of Na–HCO3 type and coal mine water is Ca–Mg–SO4 and HCO3–Cl–SO4 type. Much of the produced water has total dissolve solids (TDS) content <3000 mg/L and can potentially be put to beneficial use within and outside the CBM industry. Sodium adsorption ratio (SAR) was calculated for each sample using concentration of sodium to the sum of the concentrations of calcium and magnesium. The higher the SAR, the greater the potential for reduced permeability, which reduces infiltration, reduces hydraulic conductivity, and causes surface crusting. Trace metal concentrations have a very similar range of distribution in both CBM and coal mine water. With minimal processing, much of this water may be used for a variety of industrial and agricultural purposes controlling pH, electrical conductivity, alkalinity, bicarbonate, sodium, fluoride, metals and SAR values. Drinking water availability is the major issue in Damodar basin; however the large quantity of water generated from CBM production wells can be potential freshwater sources for various applications, including potable consumption after RO treatment. This investigation employs CBM and mine water management strategies considering the spectrum of geologic, hydrologic and geochemical parameters to ensure environmental protection, foster beneficial use, treatment options of produced waters and improving reservoir performance. The CBM-produced water is derived from virgin multiple deep aquifer system having higher concentrations of Na+ and HCO3 −, while mine water is of shallow aquifer continuously flushed by seasonal rain water percolation and water drainage system employed in underground coal mine. It also reviews specific water treatment options and associated economics for managing CBM-produced water in Damodar basin.

Coalbed Methane: Present Status and Scope of Enhanced Recovery Through CO 2 Sequestration in India

Enhancing coalbed methane recovery through injection of CO2 in depleted low pressure coal reservoir is a potential, economic and environmentally suitable solution to reduce greenhouse gas emissions. In India, commercial coalbed methane (CBM) production has been started since 2007 at Raniganj and Sohagpur basins and subsequently to Jharia and Bokaro coalfields. CBM reservoirs are at low pressure, and after some years of production through primary reduction of hydrostatic pressure, rate of recovery declines and harms the well economics. In a secondary drive, the CO2 or CO2 + N2 or other mixture of gases can be injected to enhance the methane recovery and to maintain reservoir pressure. Studies conducted so far support stronger affinity of CO2 to the coal molecule, displacing each methane molecule by 2–3 molecules of CO2. Coal may adsorb more carbon dioxide than methane and that carbon dioxide is preferentially adsorbed onto the coal structure over methane (with 2:1 ratio). High-pressure methane and CO2 sorption measurements were carried out for various coal seams in India. On the basis of CO2 sorption capacity, seam thickness and extension, the suitable sites and their storage capacities estimated to be 4459 Mt for CO2. It is assumed that this quantity of storage is sufficient to store over 20% of total gas emission from the present power plants over their lifetime. The sites close to the operating thermal power units may be the most appropriate for CO2 sequestration as the transportation cost of the gas will be minimum. The rate of CO2 generation and total CO2 generated within the life span of a thermal power station presuming 20 years more from the date will be helpful for enhanced coalbed methane (ECBM) process in the close vicinity of CBM blocks. It is also required that geologic data and experimentally determined mineralization reaction rates and kinetics should be incorporated into geochemical models to predict the permanent storage of CO2 in unmineable deep coals after ECBM recovery.