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ANALYSIS OF SHALE GAS EXPLORATION IN INDIA AND A CASE STUDY Partha Sarathi Basak* and B.Chandrashekhara Rao *Oil and Natural Gas Corporation Ltd., VRC(Panvel), WOB, Mumbai. E-mail: [email protected] Abstract: Natural gas forms 9 per cent of the total commercial energy mix in India, but demand far exceeds supply. Part of the demand is made up by the import of liquefied natural gas (LNG). Several power plants, which were in operation or ready for commissioning, or in an advanced state of construction, representing about 10,000 MW of generation capacity, were however, idle for want of gas. The exploration and production of shale gas in the United States (USA) has been a game changer, making the country self-sufficient in natural gas over the last few years. This has created considerable excitement globally. India is also looking at exploring shale gas domestically to fill in the supply– demand gap. Keywords: Shale plays, Thermogenic gas window Introduction: Sedimentary rocks are types of rock that are formed by the deposition of material at the Earth's surface and within bodies of water. Sedimentation is the collective name for processes that cause mineral and/or organic particles (detritus) to settle and accumulate or minerals to precipitate from a solution. Particles that form a sedimentary rock by accumulating are called sediment. Before being deposited, sediment was formed by weathering and erosion in a source area, and then transported to the place of deposition by water, wind, ice, mass movement or glaciers which are called agents of denudation. The process in the rock cycle which forms shale is called compaction. The fine particles that compose shale can remain suspended in water long after the larger and denser particles of sand have deposited. Shales are typically deposited in very slow moving water and are often found in lakes and lagoonal deposits, in river deltas, on floodplains and offshore from beach sands. They can also be deposited on the continental shelf, in relatively deep, quiet water. Shale gas is natural gas that is found trapped within shale formations. Shale gas areas are often known as resource plays (as opposed to exploration plays). The geological risk of not finding gas is low in resource plays, but the potential profits per successful well are usually also lower. Shale has low matrix permeability, so gas production in commercial quantities requires fractures to provide permeability. Shale gas has been produced for years from shales with natural fractures. The shale gas boom in recent years has been due to modern technology in hydraulic fracturing (fracking) to create extensive artificial fractures around well bores. Shales that host economic quantities of gas have a number of common properties. They are rich in organic material (0.5% to 25%) and are usually mature petroleum source rocks in the thermogenic gas window, where high heat and pressure have converted petroleum to natural gas. Shale gas extraction: Natural gas (mainly methane) is generally classified under two heads: (a) conventional gas, and (b) unconventional gas. Most of the natural gas that is produced globally comes under the category of conventional gas where, after drilling in a sedimentary basin that is rich in gas, the gas migrates through porous rocks into reservoirs and flows freely to the surface where it is collected, treated, and then piped to various users. Shale gas on the other hand is located in rocks of very low permeability and does not easily flow. Therefore, the technique for recovery of shale gas is quite different from that of conventional gas. Conventional gas can occur by itself or in association with oil. Coal bed methane (CBM), which is extracted from coal beds, is also an unconventional gas and, in terms of depth, occurs much closer to the land surface than other similar gases. However, shale rock is sometimes found 3,000 metres below the surface. Therefore, after deep vertical drilling, there are techniques to drill horizontally for considerable distances in various directions to extract the gas rich shale. A mixture of water, chemicals, and sand is then injected into the well at very high pressures (8,000 psi) to create a number of fissures in the rock to release the gas. The process of using water for breaking up the rock is known as “hydrofracturing” or “fracking”. The chemicals help in water and gas flow and tiny particles of sand enter the fissures to keep them open and allow the gas to flow to the surface. This injection has to be done several times over the life of the well. The number of wells to be drilled for shale gas far exceeds the number of wells required in the case of conventional gas. Shale gas sedimentary basins in India HYDROLIC FRACTURING (FRACKING) The Cabinet Committee on Economic Affairs (CCEA) approved the proposal of the Ministry of Petroleum and Natural Gas on the policy on exploration and exploitation of shale gas and oil by National Oil Companies (NOCs), namely ONGC and Oil India Limited, on acreages they already own. As per the policy, the NOCs will undertake a mandatory minimum work programme in a fixed time frame for shale gas and oil exploration and exploitation, so that there is optimum accretion and development of shale gas and oil resources. According to U.S. Energy Information Administration India may have as much as 96 trillion cubic feet (tcf) of recoverable shale gas reserves. India has identified 56 Shale Blocks for Exploration: Indian state owned energy firms, ONGC and Oil India have identified 56 shale gas blocks which have potential to be explored. “Under the first phase of assessment of shale gas and oil, exploration and exploitation, at present, 56 Petroleum Exploration Lease (PEL)/ Petroleum Mining Lease (PML) blocks have been identified by National Oil Companies (NOCs). ONGC has zeroed in on 50 blocks and Oil India on six. These blocks are located in the states of Assam (7 blocks), Arunachal Pradesh (1 block), Gujarat (28 blocks), Rajasthan (1 block), Andhra Pradesh (10 blocks) and Tamil Nadu (9 blocks). They are expected to cover three major basins, i.e., Cambay, Krishna-Godavari, and Raniganj (Damodar basin). According to the Oil and Natural Gas Corporation (ONGC), there are about 34 tcf of shale gas in the Damodar basin alone (compared to India’s total conventional gas reserves of 47 tcf of which 8 tcf are recoverable. India gave a go ahead to the much awaited shale oil and gas policy boosting prospects of exploration of the unconventional gas in the country. ONGC put India on shale gas exploration map: India begun its first commercial exploration of shale gas — natural gas that is found trapped within shale formations below the earth surface with state-run Oil and Natural Gas Corporation (ONGC) launching drilling operations at Jambusar near Vadodara in Gujarat. The government has recently announced its shale gas policy for exploitation of this very important non-conventional hydrocarbon resource. Announcement of the second phase of shale gas policy is being made in the near future. As per the policy, ONGC would get 50 blocks in the first phase, while another 75 blocks in the second and 50 blocks in the third phase. Oil India would take up five blocks each in all three phases. It was ONGC that first tasted shale gas in a pilot project at Ichhapur in Burdwan, West Bengal. ONGC tied up with ConocoPhillips for technical assistance to explore Cambay, KG, Cauvery and Bengal basins for shale gas. Each assessment phase for no-objection certificates would extend up to three years and a company would be allowed to take up the second phase after the first phase is completed. 2 ONGC had drilled the first well in Jambusar (JMSGA) to exploit the natural gas trapped within the shale formations located in Cambay basin, which is estimated to have a shale gas potential of 20 TCF (trillion cubic feet). ONGC successfully drilled the shale gas pilot well JMSGA in Cambay Shale, which is the principal source of hydrocarbons in the basin and has huge thickness in the Broach depression of Cambay Basin. Jambusar area constitutes a broad terrace with the depocentre of Cambay Shale extending towards west. Appreciable thickness of Cambay Shale source rock facies, to the tune of around 800- 1000m is expected in UmraJambusar area. However, there is not much direct information available on the stratigraphy, mineralogy and petro physical properties of this main target of shale gas/oil. But Coring of approximately 144M in shale was planned in the first well. The proposed well JMSGA was planned in the jambusar area where the Cambay Shale Top is expected around 2300m and with target depth at 3300m to cover the entire interesting zone. The results of the first exploratory well will open a new chapter in shale-gas exploration in the country. In Cambay region of Gujarat.India has recoverable shale gas reserves of around 90 TCF, which can satiate India’s energy demand for 26 years. Cambay is one of the basins that have been identified as potentially-bearing shale resources. But apart from the Cambay basin, the ONGC will also explore KrishnaGodavari, Cauvery and Vindhyan sedimentary basins for shale gas in the near future. Shale gas is natural gas trapped within layers of shale rock and can be utilised as cooking gas and for other commercial purposes. ONGC estimates India’s shale gas reserve in the range of 500 to 2000 trillion cubic meters. Geophysics has a role in Shale plays: Sometimes it is helpful to remember that 3-D seismic was originally intended to be a development tool rather than an exploration tool. This is important in today’s shale plays, where the common cry is, “We don’t need seismic to find the shale. We already know where it is.”Yes, but few of any operators understand how it behaves, why one fracture stage within a well produces 10 times more oil or gas than its neighbor, or how to find sweet spots to overcome that inequity. It takes 3-D seismic in account. The role of seismic has evolved to be far more than simply a tool for mapping major structures and looking for closure, these are not critical to prospectivity in shale gas. As 3D seismic data are often the only far-field data available predrilling, these data remain important to optimizing field development. The conventional uses of seismic data as a tool to avoid hazards, geosteer (optimizing in-zone drilling and minimizing porpoising that can create completion issues) with long reach horizontals remains important. However, it is the integration of seismic data with engineering and rock physics data that is providing new avenues of data exploitation. Seismic data are being used to predict closure stress and stress anisotropy, which can be calibrated with data and analysis from hydraulic fracturing. Additionally, the integration of surface seismic data with microseismic provides a means of fine-tuning the estimation of stimulated rock volume. The traditional role of seismic will continue to be important for mapping horizons of interest and mapping major faults and more subtle structural trends that may impact drilling and/or completion and production. In general, major faults are avoided during horizontal drilling (where possible) as the behaviour of faults during stimulation is difficult to predict, as is the stress field around some faults. Standard seismic attributes such as coherence and curvature are being successfully utilized to map major and subtle faults and structural trends. Geophysicists, however, have found that the rock properties that underpin the seismic response of rocks are the same as the properties of interest to the stimulation engineers. This has opened the door for innovations in advanced seismic studies that not only enforce the relevance of geophysics in shale gas, but provide the opportunity for companies to gain material competitive advantage through geophysical technological innovation. The production from unconventional reservoir like shale gas has been possible because of horizontal drilling and hydraulic fracturing technologies. Efficient implementation of both of these technologies needs an accurate subsurface model for horizontal drilling in the target layer, and for understanding of the rock properties to design fracture jobs. Shales are very heterogeneous and therefore well data alone may not be sufficient to map the subsurface. Geophysical data can provide accurate 3D subsurface images as shown below (Fig.A & B). Fig.A 3 Fig.B Chitravati sub-basin of Cuddapah basin: The crescent shaped Cuddapah Basin, also called as Cuddapah super group is an epi-cratonic basin of Proterozoic age situated in the state of Andhra Pradesh. The super group with its western convex and eastern concave margins is of 440km long with a maximum width of 145km at its centre and covers 44,500 sq.km area. The western margin of the basin shows minimum deformation and the eastern concave margin is intensely faulted and affected by thrusts (Raman and Murthy, 1997).The Basin is grouped under category-IV sedimentary basins of India by DGH having possible existence of hydrocarbons. Natural gas leakage from a borewell at Vengannapalli village located in the south-eastern part of the basin (Chitravati sub basin) near Tadipatri town has made attention to all geoscientists for search of hydrocarbons in Cuddapah basin. Total intensity aeromagnetic anomaly map of exposed Basement complex and the Papagni sub-basin (After R.K.Kishore and Ch.Ramarao, 2004) Reconnaissance near-surface soil geochemical surveys and geo-microbiological surveys were conducted at seepage site as well as covering the entire Cuddapah basin by NGRI geoscientists, Hyderabad. The results of the surveys were concluded with possible accumulation of thermogenic gaseous hydrocarbons in the subsurface Cuddapah basin (Kalpana et al, 2010, A.M.Dayal et al, 2007 and M.A.Rasheed et al, 2008) Occurrence of unconformity and fracture related uranium deposits were identified along the western convex margin (covers entire western basin margin suture) by the scientists of Atomic Mineral Division, Hyderabad. Shale gas prospectivity in Cuddapah basin: Vempalli shales of Papaghni Formation and Tadipatri shales of Chitravati Formation preserved in Chitravati sub-basin are the potential source rock shales for generation and accumulation of shale gas. Analysis of magnetic profiles yielded a total thickness of 1300m for the Papaghni rocks and 5.3km for the entire suite of Papaghni & Chitravati group of rocks (R.R.Kishore & Ch.Rama Rao, 2004). Geological map of Cuddapah basin -high potential for shale gas 4 The Cuddapah supergroup has been divided into Papaghni, Chitravati, Nallamalai, Srisailam, Kurnool and Palnad groups/sub-basins from Southwest to northeast. Each group/Sub-basin is separated either an unconformity or a disconformity. The polycyclic evolution of the Cuddapah basin indicated by multiple transgression and regression cycles is explained by thermally driven crustal sagging alternating with extensional stretching (Ramam and Murty, 1997). The adsorbed soil gas survey in the area has indicated the presence of thermogenic gaseous charge, not influenced by secondary effects during migration and absorption on sub-surface. Source of these gases may be thermogenic / Kerogen III type. The geological and geophysical studies reveal that Tadpatri shales (Chitravati group) can be potential source rocks for hydrocarbons. The Papaghni and Chitravati groups are mostly undisturbed and have the pre-requisites, which can be favourable for generation and accumulation of hydrocarbons. Landsat imagery of Chitravati sub-basin showing lineaments Analysis: Saunders et al (1999) has indicated that hydrocarbon microseepage from the reservoirs most probably involves buoyant colloidal size “microbubble” movement of light hydrocarbons (principally methane to butanes) ascending relatively rapidly through a water filled network of fractures, joints and bedding planes. A commercial uranium deposit occurs at Cement field, Oklahoma (Olmsted, 1975; Allen and Thomas, 1984). Cone and Alley (1985) suggested a genetic relationship of surface uranium concentration with subsurface oil field in Libson valley, Utah. Eargle and Weeks (1961) reported an association between uranium roll-fronts in Karnes county, Texas and oil and gas fields down dip. Occurrence of rich stromatolitic assemblages in Vempalli and Chitravati formations (favourable for development of source rocks) and association of sills and dykes with these formations (Favourable for making matured source rocks and generation of gaseous hydrocarbons) indicate hydrocarbon generation and accumulation in commercial quantities of gas and associated tar/bitumen residues. Magnetic and Telluric surveys carried out by the earlier workers in Chitravati sub-basin indicate the sediment thickness in Chitravati sub-basin from west to east varies from 0 to 5km. With this analogy, the thickness in the study area which is falling in between is expected to be around 3kms (Figure.7). Northwest-southeast and northeast-southwest basement controlled natural fractures are observed from the tectonic map and land-sat imagery (Figure.2). These natural fractures give advantage to the development of secondary porosity in the shales and are the favourable accumulations of shale gas. Basement depth map of a part of the southewestern region of the Cuddapah basin derived from aeromagnetic data (After Prasanti Lakshmi and H.V.Ram Babu) 2. Complete source rock analysis of out-cropping Vempalli shales and Tadipatri shales is required in the study area. 3. Detailed near-surface geochemical surveys are to be carried out to identify the potential anomalies and their relation to lineaments. 4. Geophysical surveys (2D and 3D) are to be carried out in the study area to derive a seismo-geological model. 5. Few wildcat wells are to be drilled to identify and delineate the potential shale gas zones. Conclusion: Acknowledgements: 1. Analysis of the available data generated by the earlier workers indicate the Chitravati sub-basin of Cuddapah basin contains commercial accumulation of shale gas and associated tar/bitumen deposits and may be the future giant shale gas field in India. Authors are thankful to the Oil & Natural Gas Corporation Ltd for emphasizing the need of energy security by way of exploring unconventional energy resource like shale gas. 5