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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.
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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
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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
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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.
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