Appendix 3 Brief descriptions of the CO2 storage potential of the sedimentary basins of India, Pakistan and Bangladesh

The sedimentary basins are described below in alphabetical order.

THE ASSAM BASIN

Figure A3. 1 Location of the Assam Basin

Introduction

The Assam Basin (Figure A3.1) covers an area of around 56,000 km2. It is bounded by thrust belts to the north, northeast and southeast, and by the Mikir Hills and Shillong Massif to the southwest (Figure A3.2). It is sometimes referred to as the Assam Shelf, because the rocks within it were deposited in shallow marine to alluvial settings.

Figure A3. 2 Location map of Assam Basin and Northeast India, including major faults and geological formations

Tectonic & Structural Setting

The Assam basin is bounded to the northwest by the Main Himalayan Boundary Thrust, to the northeast by the Mishmi Thrust and to the southeast by the Naga and Disang Thrusts. The area between the Naga and Disang thrusts, which contains other thrusts such as the Margherita Thrust, is known as the Belt of Schuppen. To the southwest, the basin is shallows towards, and is bounded by, the Precambrian rocks of the Mikir Hills and Shillong Massif. To the north of the Shillong Massif, the basin merges with the northernmost part of the Bengal Basin north of the Rangpur Saddle in NW Bangladesh

The current configuration of the basin is due to a combination of the regional north-northeast drift of the Indian plate beneath the Himalayan Boundary Thrust and Mishmi Hills Thrust and westward overriding of the basin by the Burmese plate, which has resulted in the development of NW-oriented Naga and Disang thrusts and the other thrusts within the Belt of Schuppen.

NW-SE-oriented compression, arising from displacements of opposite direction on the Naga Hills and Himalayan thrust belts (Das, 1992), has gently folded the basin into a broad arch known as the Brahmaputra Arch (Figure A3.3). This structure affects both the Basement and Cenozoic strata of the Upper Assam Valley and its axis runs parallel with the Brahmaputra River. It dips off towards the northwest and southeast, and has been dissected by a number of faults (Murty, 1983).

Figure A3. 3 Cross sections through the Assam Basin. See Figure 1 for cross section locations. After Das (1992)

Active Tectonism

The sedimentary rocks within the basin have been disturbed in the recent past by two very large earthquakes - in 1897 and 1950. The great Assam earthquake of 12 June 1897 reduced to rubble all masonry buildings within a region of north-eastern India roughly the size of England, and was felt over an area exceeding that of the great 1755 Lisbon earthquake. The northern edge of the Shillong plateau rose violently by at least 11m. This was due to the rupture of a buried reverse fault approximately 110 km in length on the north side of the Shillong Plateau (Billam and England, 2001).

One of the largest earthquakes recorded seismographically was the magnitude 8.6 or 8.7 Assam event in 1950, which caused ground upheaval and many rock falls in the Mishmi Hills. In the Arbor Hills, 70 villages were destroyed with 156 casualties due to landslides. Rock falls blocked the tributaries of the Brahmaputra. The rockfall damming the river in the Disang valley subsequently broke without causing damage, but one at Subansiri opened after an interval of 8 days causing a wave 7 metres high that submerged several villages and killed 532 people.

Future large-scale earth movements could potentially cause ‘catastrophic’ modification of the basin, reactivating the existing fracture zones in the Itanagar region (Das, 1992).

Stratigraphy

In the Upper Assam Valley, 0-7 km of mainly terrigenous Cenozoic sediments overlie a Precambrian metamorphic/igneous basement. The thickness of the sedimentary cover increases from zero at the Mikir Hills in the southwest to >7 km near the northeast margin of the basin (Bhandari et al. 1973).

Basement rocks

The Precambrian basement consists mainly of crystalline metamorphic rocks, including biotite gneiss, pink granites & quartzites (Bhandari et al. 1973).

Basin fill

Palaeozoic-Mesozoic strata could be present within the Subansiri and Luhit depressions on the NW margin of the Assam Basin, just in front of the Himalayan foothills (Bhandari et al., 1973), but no evidence such strata has yet been discovered (Acharyya et al. 1975) so it is likely that the basin fill is entirely Cenozoic in age, and major basin subsidence commenced during Palaeocene times.

The Cenozoic sequence is divided into two supergroups separated by a major unconformity (Figure A3.4, see also Wandrey 2004). The Naga supergroup consists of Palaeogene sediments deposited in shallow marine-paralic environments. It is further divided into the Jaintia and Barail groups. The overlying Brahmaputra supergroup consists mainly of fluvial and deltaic sediments that are Neogene in age, and are sub-divided into the Surma, Tipam and Moran groups (Bhandari et al. 1973).

Figure A3. 4 Stratigraphy of the Assam Basin, based on Bhandari et al. (1973)

Hydrocarbons

Oil seeps were known in Assam as early as 1825. The first commercial discovery was at Digboi in about 1899 and a refinery had been established there by 1901.

Between 1922 and 1932 Burmah Oil Co. drilled ten structures in the Belt of Schuppen without success. Oil India Ltd (OIL) first discovered oil in the Nahorkatiya field in 1953 and then in 1956 in the Moran Group in the Moran Field. Significant discoveries by ONGC followed during the period 1960-1971 (Murty, 1983).

By 1975, around 500 deep wells had been drilled in the region by OIL and the ONGC (Bhandari et al., 1973). By 1983, due to the discovery of productive pre-Barail sandstone/limestone horizons in the Borholla region south of the Mikir Hills (Murty 1983), almost forty wells had been drilled through the pre-Barail sequence in this area by ONGC (presumably to basement although this is not specified).

The distribution of discoveries strongly suggests that the petroleum source rocks are mature beneath the Naga Thrust and that petroleum is migrating northwards onto the southern flanks of the Brahmaputra arch, i.e. that part of the basin south of the Brahmaputra river. There are no discoveries north of the Brahmaputra River.

Reservoir rocks and seals

The bulk of the oil production in Assam is from the Oligocene Barail Formation and the Miocene Tipam Formation (Raju & Mathur, 1995). Local porosity/permeability variations, and the lenticularity of sand bodies, are key factors controlling the accumulation of hydrocarbons within the Barail (Murty, 1983).

The Tipam Formation has a permeability range of <8-800 mD, and a porosity range of <7-30%. The Girujan Formation represents an effective sub-regional scale seal over the Tipam Formation. It is generally >200 m thick but thins to ∼50 m over structural highs.

Thin sandstone beds within the Upper Palaeocene-Lower Eocene shales of the Langpar Formation and the Lakadong Member of the Sylhet Formation may also have potential as reservoir rocks (Mallick & Raju, 1995). Strata overlying the Langpar Formation include shales, silts and marls, reaching thicknesses of up to 800m, and would likely provide adequate seal potential.

According to Murty (1983), the northern part of the Brahmaputra valley has very poor hydrocarbon prospects because the thinning of sedimentary sequences has resulted in ineffective cap rocks (this could provide an explanation for the absence of oil and gas discoveries north of the Brahmaputra, although, alternatively, petroleum migration from beneath the Naga Thrust may not have reached across the Brahmaputra Arch). If Murty is correct the area north of the Brahmaputra also will have poor CO2 storage potential.

CO2 Storage Potential

The presence of oil fields in the area south of the Brahmaputra River, at several stratigraphic levels in the Cenozoic section, indicates that this part of the Assam Basin has good potential to store buoyant fluids such as supercritical CO2. Several apparently well-sealed reservoir horizons are present. However, there are many abandoned wells in the area, some of which might have to be considered in any storage project.

However, the area is remote from the main part of peninsula India and thus would best provide storage potential for local CO2 sources. Any CO2 transport to Assam from peninsular India would have to be by pipeline around the ‘chicken neck’ to the north of Bangladesh, across Bangladesh, or across Bangladeshi territorial waters. The area is also prone to some of the largest earthquakes ever recorded.

References

Acharyya, S.K., Ghosh, S.C. & Ghosh, R.N. 1975. ‘Stratigraphy of Assam Valley, India: Discussion.’ Bulletin American Association of Petroleum Geologists, 59 (10), 2046-2057.

Bhandari, L.L., Fuloria, R.C. and Sastri, V.V. (1973) ‘Stratigraphy of Assam Valley, India.’ American Association of Petroleum Geologists Bulletin, 57(4), 642-654.

Billam and England (2001)

DAS, J.D. 1992. The Assam Basin: Tectonic Relation to the Surrounding Structural Features and Shillong Plateau. Journal Geological Society of India, 39, 303-311.

Mallick, R.K. and Raju, S.V. (1995) ‘Application of Wireline Logs in Characterization and Evaluation of Generation Potential of Palaeocene-Lower Eocene Source Rocks in Parts of Upper Assam Basin, India.’ In: Swamy, S.N. and Dwivedi (eds.) Second International Petroleum Conference: Petrotech-97, 9-12 January, 1997. 1, 49-63.

Murty, K.N. 1983. Geology and Hydrocarbon Prospects of Assam Shelf – Recent Advances and Present Status. Petroleum Asia Journal.

Raju, S.V. & Mathur, N. 1995. ‘Petroleum geochemistry of a part of Upper Assam Basin, India: a brief overview.’ Organic Geochemistry, 23(11), 55-70.

Rangarao, A. 1983. Geology and Hydrocarbon Potential of a part of Assam-Arakan Basin and its Adjacent Region. Petroleum Asia Journal, November 1983, 127-158.

Wandrey, C.J. 2004. ‘Sylhet-Kopili/Barail-Tipam Composite Total Petroleum System, Assam Geologic Province, India.’ In: Wandrey, C.J. (ed.), Petroleum Systems and Related Geologic Studies in Region 8, South Asia. USGS, 1-19.

THE ASSAM-ARAKAN FOLD BELT

Introduction

The Assam-Arakan Fold Belt (Figure A3.5) runs roughly N-S along the eastern margin of the Bengal Basin, west of the Burmese ranges, through the Indian states of Tripura, Mizoram, Manipur and Cachar, and, in Bangladesh, through the Chittagong Hill Tracts and the easternmost part of the Surma basin.

Figure A3. 5 Location of the Assam-Arakan Fold Belt in NE India and Bangladesh

The fold belt comprises the easternmost part of the Bengal Basin and therefore contains a very thick Cainozoic sedimentary succession (Aubouin 1965, Ganguly 1983). The fold belt has been formed by oblique collision between the Indian and Burmese continental plates from Oligocene times onwards, which continues to the present day. In broad terms, the folds increase in amplitude and intensity from west to east towards the Burmese Ranges, beneath which it is thought that the basin is being subducted.

Generally, the elevation of the region increases eastwards from eastern Bangladesh and Tripura through Mizoram and Manipur towards the Chin Hills of Burma. Concomitantly, the rocks and folds exposed in the eastern part of the fold belt are in general older than those in the western part. As a whole, the exposed rocks in the Tripura-Mizoram-Manipur belt range in age from Late Mesozoic in the east to Palaeogene, Neogene and Recent in the west (Ganguly, 1983).

The region is geographically remote and poor accessibility means that there has been relatively little hydrocarbon exploration in the region, given that it is folded into a number of prominent anticlines oriented approximately N-S. These folds are very clearly visible, and mappable, on satellite images of the region.

Structure

The region comprises a series of subparallel, arcuate, elongated, doubly plunging en-echelon folds trending in an average North-South direction.

A slight convexity of the folds towards the west is seen (Ganguly, 1983). From east to west, the deformation seen in the fold belt becomes progressively younger and less intense. The Tripura and Cachar areas contain younger ‘narrow, box-like’ anticlines separated by ‘wide, flat’ synclines, while the Mizoram area consists of tight, linear synclines (Ganguly, 1983). The structural patterns observed in the Tripura and Cachar regions are diagnostic of basement-involved compressive block-fault styles, which merge into wrench-like features in some places. The structures seen in Mizoram (on the eastern side of the fold belt) appear to grade into detached thrust/fold assemblages.

Stratigraphy

The lithostratigraphy of the Tripura-Manipur region, as presently understood, is illustrated in Figure A3.6. However, it should be borne in mind that the exposed Neogene strata of NE Bangladesh and the Tripura-Cachar-Mizoram region of NE India, which are composed mainly of alternating shales, mudstones, siltstones and sandstones (Ganguly, 1983) were deposited by the Brahmaputra river and its predecessors draining the rising Himalayan mountains. Thus they were deposited in a major outwash area, largely in alluvial and deltaic environments, in a tectonically unstable, rapidly subsiding, basin (Ganguly 1983). They are very difficult to subdivide lithostratigraphically as similar facies of varying age are present within the succession. A sequence stratigraphic subdivision, as attempted by Lindsay et al. 1991) in NW Bangladesh, could prove productive, at least in the less structurally complex western parts of the fold belt.

Figure A3. 6 Lithostratigraphy of the Tripura-Manipur region

A characteristically monotonous argillaceous sequence known as the Disang Shales is exposed in an extensive area south and southeast of the Disang Thrust, in Assam, Cachar, Manipur, Mizoram and parts of Burma southeast of the Naga Hills. The Disang Shales are thought to be approximately 2000 m to 3000 m thick (Banerji, 1979). Despite some scattered gas seeps, this sequence is thought to have poor hydrocarbon prospects due to the lack of reservoir rocks.

To the west of their outcrop, the Disang Shales are overlain by the younger Barail-Surma-Tipam sedimentary sequences.

The rocks exposed in the anticlinal cores in the central and western parts of the fold belt are believed to be equivalents of the Mio-Pliocene Surma Group. They are about 4000 m thick in Tripura, and around 7000 m thick in Mizoram. At least three major transgressive marine cycles are present (Ganguly, 1983). The Surma Group is conventionally further divided into the lower Bhuban unit (more arenaceous), and the upper Boka Bil unit (mainly argillaceous).

The Tipam Group (as seen in the neighbouring Assam Valley) is thought to be represented in the younger arenaceous beds on the flanks of the anticlines, which are Pliocene in age and are >2000 m thick. Sedimentological evidence suggests that parts of the Tipam Group in northern Cachar were deposited under the influence of a tidal regime (Rangarao, 1983). In general however, the sequences of the Tipam (and overlying Dupi Tila) group were deposited under subaqueoussubaerial, fluviatile-lacustrine conditions (Ganguly, 1983).

CO2 storage potential

Gas fields are present in the outer parts of the fold belt, e.g. in the Surma Basin (eastern part of the Bengal Basin, NE Bangladesh), the Chittagong Hill Tracts (SE Bangladesh), Tripura and Mizoram. The presence of the Surma, Barail and Tipam groups in the Cachar-Tripura-Mizoram region, all of which contain sandstones, suggest that potential for aquifer CO2 storage exists in these areas as well, at least west of the outcrops of Disang Shales. However, overpressure, encountered in drilling operations in the fold belt, may be an issue. The main drawback is geographic: the Indian parts of the fold belt are remote from both major CO2 sources and the main part of India,

References

Aubouin, J. 1965. ‘Geosynclines.’ Elsevier Publishing Company, Amsterdam. 335 pp.

Banerji, R.K. 1979. ‘Disang Shale, its Stratigraphy, Sedimentation History and Basin Configuration in North-eastern India and Burma.’ Quarterly Journal of the Geological, Mining and Metallurgical Society of India, 51, 133-142.

Ganguly, S. 1983. Geology and Hydrocarbon Prospects of Tripura-Cachar-Mizoram Region. Petroleum Asia Journal. Nov. 1983, 105-109.

Lindsay, J.F., Holliday, D.W. & Hulbert, A.G. 1991.‘Sequence Stratigraphy and the Evolution of the Ganges-Brahmaputra Delta Complex. Bulletin American Association of Petroleum Geologists, 75(7), 1233-1254.

Rangarao, A. 1983. Geology and Hydrocarbon Potential of a part of Assam-Arakan Basin and its Adjacent Region. Petroleum Asia Journal, November 1983, 127-158.

THE BALOCHISTAN BASIN

 

The Balochistan Basin (Pakistan) covers an area of over 300,000 km2 (see Figure 0.2 for location). From an oil and gas perspective, this basin is the least explored basin in Pakistan. Only six wells had been drilled up to 1997 (of which one was offshore) and, despite several gas shows along the Makran coast, no commercial discoveries have been made.

Structurally, the basin extends offshore, where it is bounded to the south by the Makran offshore trench. To the east it is bounded by the Chaman Transform Zone. To the north it is bounded by the Chagai Volcanic Arc and to the west it extends into Iran. The basin is described in detail by Kadri (1995).

Geologically it comprises an Arc-Trench system. At its southern margin (offshore) the Arabian Oceanic Plate is being subducted beneath the margin of the Eurasian Continental Plate. From south to north the basin can be subdivided into the Makran Tranch, Coastal Makran Depression, Makran Accretionary Prism, Kharan Forearc basin, an inter-arc region and the Chagai Volcanic Arc (see Kadri 1995 for details).

The basin contains 5000 – 15000 m of flysch-type terrigenous slope and shelf sediments and turbidites. All the drilling activity to date has been in the Makran Accretionary Prism, close the coast. This area is structurally complex. There is no shortage of reservoir rocks, but overpressure has proved an operational problem, and this may reduce its potential for CO2 storage.

Because it contains no proven oil and gas fields at present, and is comparatively poorly explored, it is classified at present as having limited potential for CO2 storage. Further research could enhance our perception of its potential however.

References

Kadri, I.B. 1995. Petroleum Geology of Pakistan. Pakistan Petroleum Ltd, Karachi, 275 pp.

THE BARMER BASIN

 

Figure A3. 7 Location of the Barmer Basin

Structure

Geologically, the Barmer Basin is the northernmost segment of the Cambay graben but it is commonly described separately from the Cambay Basin because it is in Rajasthan rather than Gujarat. Structurally it is a narrow N-S-oriented fault-bounded graben. The faulting on its eastern side upthrows basement rocks to outcrop. It is separated from the Jaisalmer Basin, to the north, by the Fateghar Fault, immediately north of which lies the Devikot-Nachna High (Figure A3.7). It appears to be contiguous with the Sanchor depression in the Cambay Basin, immediately to the south.

Stratigraphy

According to Mohan & Sangai (1995), the stratigraphy of the Barmer Basin shows greater similarity to that of the Jaisalmer Basin than the Cambay Basin. At the base of the basin is a Proterozoic succession consisting of the Randha Formation unconformably overlain by the Birmania Formation. A Jurassic succession (comprising the Lathi Formation overlain by the Jaisalmer Formation) overlies this. Above the Jurassic is the Early Cretaceous Sarnu Formation, which is overlain by over 500 m of marine and continental Cretaceous-Eocene strata (Dhar et al., 1974; Pareek, 1976; Khar, 1984), above which is Pleistocene-Recent alluvial cover.

The Proterozoic and Jurassic formations in the Barmer graben are also found in the Jaisalmer Basin to the NW.

Hydrocarbons

Cairn Energy has made several large oil discoveries in the Barmer Basin in recent years. To date over 2 billion barrels of oil in place and an as yet undetermined volume of gas have been discovered by Cairn, in a variety of reservoirs in the basin.

CO2 storage potential

There is likely to be excellent future potential for CO2 storage in the Barmer Basin, both for EOR in the oil fields once these are developed, and in the aquifers. Projected secondary recovery by waterflooding in the main fields is predicted to be only in the order of 9-30% of STOIIP.

THE BENGAL BASIN

 

Figure A3. 8 Location of the Bengal Basin

The Bengal Basin lies in NE India and Bangladesh (Figure A3.8). It covers, in India, an area of 57,000 km2 onshore and 32,000 km2 offshore. It also covers all of Bangladesh apart from the extreme NE and the Chittagong Hill Tracts, which are here included in the Assam-Arakan Fold Belt.

The Bengal Basin is bounded by the Indian shield to the west. To the north it is bounded by the basement rocks of the Shillong Plateau and shallow concealed basement under the Rangpur Saddle in northern Bangladesh.

The basin itself extends eastwards from the Rajmahal coalfields and Rajmahal Traps of West Bengal across Bangladesh. The eastern margin of the basin is folded and forms part of the Assam-Arakan Fold Belt, which runs roughly N-S through the Indian states of Tripura, Mizoram and Cachar, and the Chittagong Hill Tracts of Bangladesh. The Assam-Arakan fold belt is described separately above.

The sedimentary rocks and sediments filling the basin are mostly Cenozoic to Recent in age. However, Permian and Mesozoic rocks underlie the Cenozoic in places.

Tectonic and Structural Setting

Tectonically, the Bengal Basin is a passive margin basin which, since Oligocene times, has been filled with sediment derived from the Himalayas, most of which was transported into the basin by the Ganges and Brahmaputra rivers and their predecessors.

The eastern part of the basin (in eastern Bangladesh, Tripura, Cachar and Mizoram) is folded into a series of anticlines and synclines arising from eastwards-directed subduction of the eastern basin margin beneath the Burmese ranges. The western part of the basin (the main Indian part and western Bangladesh) is not significantly folded and, east of the western basin margin fault zone, the strata simply dip homoclinally east and southeast into the Bay of Bengal. The southern part of the basin spills southwards off the continental crust onto ocean crust at the bottom of the Bay of Bengal, where it forms a huge ocean-bottom fan.

On the western side of the basin, four tectonic zones are recognised (Mukherjea and Neogi, 1993). Raman (1986) shows the location of these tectonic zones and important well locations:

  • The basin margin fault zone,
  • Shelf/platform,
  • Shelf/slope break and
  • Basin deep

Basin Margin Fault Zone

The NNE to SSW-trending basin margin fault zone differentiates an area of shallow crystalline metamorphic basement from the Shelf area. It is truncated to the north by shallow basement ridges that were uplifted during the Mid Miocene and subsided again during the Pliocene.

Shelf Area

The western foreland shelf extends from the Basin Margin Fault Zone to the Eocene hinge zone. The shelf dips gently and homoclinally to the east, and is cut by numerous ‘down to basin’ faults with small down-ESE displacements. Sedimentary sections thicken down dip, and additional marine wedge-shaped sequences develop in the down-dip direction (Mukherjea & Neogi, 1993).

Hinge Zone

This zone separates the western foreland shelf from the basin deep to the east and south. It is defined by a moderate down-ESE flexure in the Sylhet Limestone. The Sylhet Limestone reaches its maximum thickness of 700-1000 m in this zone (Mukherjea & Neogi, 1993).

Basin Deep

This comprises a sedimentary prism 10-15 km thick. Drilling has not yet reached below the Upper Oligocene. Seismic reflection surveys show that the prominent reflector at the top of the Sylhet Limestone loses its definition in the basinal area, possibly due to facies change (Mukherjea & Neogi, 1993).

Stratigraphy

The Bengal Basin is principally a Cenozoic basin. However, the earliest sedimentary rocks in the basin are Gondwana Supergroup strata - mainly coarse arkosic continental facies, but including some coal-bearing sequences, see Figure A3.9. These were eroded from most of the basin during the Mesozoic but are preserved in small, downfaulted grabens in the basement, particularly beneath the Bangladeshi part of the basin. Here coal-bearing sequences form the Jamalganj, Khalaspir and Barapukuria concealed coalfields. Further shallow coal deposits that may eventually be worked by opencast methods are present in the extreme north of the basin. Coal was also found at depth in the Bogra 1 well in Bangladesh.

On the western margin of the basin, basaltic and andesitic lava flows (the Rajmahal Traps) covered the basement and the patchily distributed Gondwana sediments during Late Jurassic – Early Cretaceous times. The eruption of the Rajmahal Traps was most likely associated with the fragmentation of Gondwana and the separation of the eastern margin of the Indian plate from Antarctica and Australia.

The first marine transgression onto the newly formed eastern passive margin of India took place during the Campanian. This marine transgression is represented by the Dhanjaypur Formation (Das and Baq, 1996). The Campanian strata are followed by coarsening upwards successions of clastics - the Bolpur, Ghatal and Jalangi formations of Maastrichtian to Palaeocene age.

The flux of clastic sediments into the basin was drastically reduced during Eocene times, when the basin became a carbonate platform. This period is represented by the (relatively thick) Sylhet Limestone Formation, which is overlain by the (relatively thin) Kopili Shales (Das and Baq, 1996). The Sylhet Limestone is one of the most prominent regional seismic markers. It also occurs in the Mahanadi Basin to the south and the Assam Basin to the NE.

The post-Eocene succession in the Bengal Basin represents the alternating progradation, erosion and transgression of vast alluvial systems resulting from the erosion of the rising Himalayan Mountains (Lindsay et al. 1991). Huge amounts of sediments continued to be deposited today, by the Ganges – Brahmaputra – Meghna river systems, creating one of the world’s biggest modern delta systems and the giant Bengal Fan (Curray, 1994).

Figure A3. 9 Outline lithostratigraphy of the Bengal Basin, adapted from Mukherjea & Neogi (1993)

Hydrocarbons

Hydrocarbon exploration in the Indian part of the Bengal Basin was started in the late 1940s by the Standard Vacuum Oil Company and continued into the 1950s via the Indo-Stanvac Petroleum Project (ISPP). Thereafter, ONGC continued exploration activities on its own. There has been little success to date in the Indian and western Bangladesh parts of the basin. However, there have been several major gas discoveries in the eastern part of the basin, in Bangladesh, where anticlines are present. Recently there have been potentially significant gas discoveries in the Upper Miocene offshore close to the boundary between the Mahanadi and Bengal basins, see http://www.dghindia.org/site/pdfattachments/e_p_reports_2005_06.pdf. If significant, these could have profound implications for the prospectivity of the SW part of the Bengal Basin.

Reservoir rocks and seals

Sandstone reservoir rocks are present in the Oligocene and younger strata, although seals are not proven in the western part of the basin.

Structural closure

There is a lack of well-defined structural closure in the western part of the basin. However, anticlines are well developed in the eastern half of the basin, in Bangladesh, Tripura and Mizoram.

Overpressure

Overpressurisation, caused by rapid Neogene sedimentation (Mukherjea & Neogi, 1993), occurs east of the hinge zone and could be an issue for CO2 injection.

Summary of CO2 Storage Potential

Onshore, the western Bengal Basin may have some CO2 storage potential, but the lack of proven seal and closure means that prospects are classified as limited. Offshore, the south-western Bengal Basin may have good potential if the recent gas discoveries prove significant gas columns can exist. There is excellent potential in eastern Bangladesh, where there are gas fields in the basin both onshore and offshore.

References

Curray, J.R. 1994. Sediment volume and mass beneath the Bay of Bengal. Earth and Planetary Science Letters, 125, 371-383.

Das, S.K. & Baq, S. 1996. Types and Distribution of Stratigraphic Plays in Post-Trappean Sequence of the Bengal Basin, India. Oil and Natural Gas Corporation Limited, India. pp. 14

Lindsay, J.F., Holliday, D.W. & Hulbert, A.G. 1991.‘Sequence Stratigraphy and the Evolution of the Ganges-Brahmaputra Delta Complex. Bulletin American Association of Petroleum Geologists, 75(7), 1233-1254.

Mukherjea, A. & Neogi, B.B. 1993. ‘Status of Exploration in Bengal Basin, West Bengal, India.’ In: Biswas, S.K., Dave, A, Garg, P., Pandey, J, Maithani, A., Thomas, N. J. (editors), Proceedings Second Seminar on Petroliferous Basins of India, Vol 1. Indian Petroleum Publishers, Dehra Dun, India, 93-119.

Raman, K.S., Kumar, S. & Neogi, B.B. 1986. ‘Exploration in Bengal Basin India – An Overview.’ SPE Offshore South East Asia Conference, 6th, Preprints: 1986: 505-512.

THE BIKANER-NAGAUR BASIN

 

Figure A3. 10 Location of the Bikaner-Nagaur Basin

Introduction

The Bikaner-Nagaur Basin forms part of the Indus shelf. It lies in central Rajasthan, to the northeast of the Barmer Basin (Figure A3.10). It covers an area of 36,000 km2.

Stratigraphy

The Bikaner-Nagaur Basin is essentially a Proterozoic to Lower Palaeozoic Basin overlain by a relatively thin succession of younger strata. In the deeper, western part of the basin, the succession typically comprises around 900 m of unfossiliferous sediments thought to be of Precambrian to Early Cambrian age and correlatable with the Marwar Supergroup, overlain by a thin sequence of Permo-Triassic strata and up to 600 m of Jurassic and younger rocks.

Hydrocarbons

Heavy crude oil has been discovered in multiple zones within the Proterozoic to Lower Palaeozoic sequence in all three deep wells drilled up to 1994 (Das Gupta & Bulgauda 1994). The main oil zones are: The Jodhpur Sandstone and the Bilara Dolostone, with further residual oil in the Hanseren Evaporite Formation (in two relatively thin siltstone layers) and the Upper Carbonate. Only the oil in the Jodhpur Sandstone is considered producible at the moment. It has an API gravity of 17°.

The principal cap rock is probably the Lower Palaeozoic salt beds in the Hanseren Evaporite Formation (Das Gupta & Bulgauda 1994).

CO2 storage potential

Some CO2 storage potential may exist in the Proterozoic reservoirs beneath the Hanseren Evaporite Formation, i.e. the Jodhpur Sandstone and the Bilara Dolostone. However, this cannot be quantified at present.

Reference

DAS GUPTA, U. & BULGAUDA, S.S. 1994. An overview of the Geology and Hydrocarbon Occurrences in the Western part of the Bikaner-Nagaur Basin. Indian Journal of Petroleum Geology, 3(1), 1-17.

THE CAMBAY BASIN

Introduction

The Cambay Basin (Figure A3.11) is an intracratonic fault-bounded graben located near the western margin of the Indian craton (Biswas, 1987; Choudhary et al., 1997).

Figure A3. 11 Location map of Cambay Basin

The Basin is bounded by the Saurashtra peninsula to the west, the Mumbai Basin to the south, and by Precambrian rocks and the Deccan Traps to the east (Raju & Srinivasan, 1993). The northern end of Cambay Graben extends north of the Gujarat State boundary into Rajasthan, where it is known as the Barmer Basin. The Barmer Basin, where Cairn Energy have recently made some major oil discoveries, is described separately and not shown on Figure A3.11.

Structure

The Cambay Basin is a roughly NNW-SSE-trending elongate graben. It is generally subdivided into five tectonic blocks, based on recognised basement trends (Nanawati et al. 1995, Biswas et al., 1993, Figure A3.12).

The Basin was initiated at the end of the Cretaceous as a result of strike-slip movement along the Narmada-Son lineament (Roy, 1990).This formed a rift valley between the Saurashtra uplift and the Aravalli Range (Biswas, 1987)2. The main period of basin subsidence occurred during the early Cenozoic (Biswas, 1987). Cenozoic sedimentary rocks deposited on the Deccan Trap reach thicknesses of up to 11000 m (Dhar & Singh 1993).

Figure A3. 12 Major structural blocks of the Cambay Basin

The depressions (the local name for areas of thicker basin fill) become progressively smaller and shallower northwards and, in the northern depressions, major faults are generally orientated parallel to the longitudinal axis of the Cambay graben. In the southern part of the graben, in the Jambusar block major faults are generally transverse and oriented across the Cambay basin (Dhar & Singh 1993).

Thick, synrift megasequences of Palaeocene-early Eocene age are present in the graben. These commonly thicken into listric and planar normal faults, which have tilted pre-rift strata. Many orthogonal transfer faults offset the major half-grabens. Episodic fault movement is indicated by at least three unconformities identified in the syn-rift sequences (Kundal et al., 1993).

A post-rift, thermal phase of subsidence took place during approximately Mid-Eocene to Mid-Miocene times. Later post-rift inversion (Middle Miocene and younger) shown by reverse movement along several listric normal faults, particularly in the Narmada-Tapti block, resulted in the formation of several anticlinal structures in the hanging wall sequences (Kundal et al., 1993, Roy, 1990).

Sanchor-Patan block

In the north of the Cambay Basin, in the Sanchor-Patan block, post-Deccan Trap sediments are up to 4 km thick in the Patan depression and up to 3.5 km thick in the broader Sanchor depression (Dhar & Bhattacharya 1993). The Wasna Horst is a prominent feature, it appears to have remained a positive feature until the end of the Middle Eocene and on it the Deccan Trap is encountered at a relatively shallow 1.1 km (Senapati et al., 1993).

Mehsana-Ahmedabad block

The north part of the Mehsana-Ahmedabad block is divided into eastern and western depressions either side of a N-S trending horst – the Mehsana horst. The south part of the block is dominated by the broad 7 km-deep Wavel depression (Dhar & Bhattacharya, 1993).

Tarapur-Cambay block

The northern margin of the Tarapur-Cambay block is delimited by the Nawagm shear, a NNESSW trending dextral transfer zone (Dhar & Bhattacharya, 1993). The Tarapur-Cambay block is a N-S trending structural depression that initiated as a half graben and became a full graben after deposition of the early synrift Olpad Formation (Dhar & Bhattacharya, 1993).

Jambusar-Broach block

The Jambusar-Broach block is dominated by the deep Broach depression that possibly contains up to 11 km of Cenozoic sedimentary rocks (Dhar & Bhattacharya 1993). It contains the greatest thickness of thermally mature Cambay Shale Formation –the region’s most prolific source rock - and the largest oil field discovered to date in the south Cambay basin; the Gandhar oilfield (Biswas, et al. 1994). Based on deep seismic soundings, 1200 m of pre-Deccan Trap sedimentary rocks may be present beneath the Broach Depression (Kaila et al. 1979).

Narmada-Tapti block

The NE-SW trending Narmada shear zone defines the northern margin of the Narmada-Tapti block (Biswas, et al., 1994). Consequently, most structures in the Narmada block trend ENEWSW (Dhar & Bhattacharya, 1993). This block also contains some large oil and gas fields, e.g. the Ankleshwar field.

Stratigraphy

The stratigraphy of the Cambay Basin is summarised in Figure A3.13. The Basin is underlain by Precambrian igneous and metamorphic basement, which is exposed along its eastern margin (Mukherjee 1983).

Figure A3.13 Summary stratigraphy of the Cambay Basin (adapted from Raju & Srinivasan 1993 and Wani et al. 1995)

Pre-Deccan Trap sedimentary rocks

A Lower Cretaceous sedimentary sequence is exposed on the margins of the Cambay Basin, in the northeast of the Saurashtra peninsula, on the western and part of the eastern margins of the Cambay Basin, as inliers in the Narmada Valley, and to the north of the Cambay Basin in the Barmer area (Mukherjee, 1983). Similar Lower Cretaceous arenaceous fluvial deposits resting on granitic basement have been encountered in wells in the Cambay Basin (Dhar & Singh, 1993 and Senapati et al 1993). Upper Cretaceous sediments were either not deposited or were eroded before the Deccan basalt volcanism (Dhar & Singh, 1993).

Deccan Traps

At the end of the Cretaceous, very extensive subaerial volcanic activity (eruption of the Deccan Traps) occurred in the Cambay, Saurashtra and Kutch basins (Biswas, & Deshpande 1973). The Deccan Trap volcanics are several hundred metres thick on the east and west flanks of the south Cambay Basin (Biswas, et al., 1994). In the Anklesvar deep well, over 3200 m of basalt was penetrated, without encountering its base (Biswas et al. 1994).

Palaeocene- Early Eocene

During the Palaeocene, a sedimentary sequence consisting of several hundred metres of weathering products from the Deccan volcanics (the Olpad Formation) was laid down during the initial stages of rifting, in stacked and overlapping alluvial fans along fault scarps (Biswas, et al., 1994; Biswas, 1987; Raju & Srinivasan, 1993). Surprisingly, this Formation appears to have some petroleum source potential (see below).

The Olpad Formation is unconformably overlain by a fossiliferous petroleum source rock; the late Palaeocene-early Eocene Cambay Shale, which was deposited during the first major marine transgression of the basin (Biswas et al. 1994, Biswas 1987). The Cambay Shale is dark, rich in organic matter and often carbonaceous (Biswas et al. 1994).

The early Eocene transgression that resulted in deposition of the Cambay Shale encroached as far northwards as the northern part of the Mehsana-Ahmedabad block (Raju & Srinivasan, 1993).

Early Middle Eocene to Late Eocene

Above the Cambay Shale, three Eocene transgressive cycles are recognised; early Middle Eocene, Middle Eocene and Late Eocene, deposition in slow regressive cycles occurring in the intervening periods (Raju & Hardas, 1985, Raju & Srinivasan, 1983). In the north Cambay Basin, the regressive cycles were deposited in deltaic-backshore-lagoonal-fluvial environments, whereas in the south Cambay basin a marine deltaic environment prevailed with a tidal gulf separating the two halves of the basin on the Tarapur block (Raju & Hardas, 1985).

Two significant drainage systems developed during Middle Eocene times, depositing the Kalol Formation on the Ahmedabad-Mehsana block and the Anklesvar Formation on the Jambusar-Broach and Narmada-Tapti blocks. The Cambay-Tarapur block (in the centre of the basin) was starved of coarser clastic material and so has poor Middle Eocene reservoir potential (Raju & Srinivasan, 1993).

In the north part of the Cambay Basin, the silty Kadi Formation (potential reservoir rock) overlies the Cambay Shale (potential source rock) and the Kalol Formation (potential reservoir rock) deposited during the Eocene in a fluvial channel to tidal environment (Wani et al., 1995). The Kadi and Kalol formations are difficult to distinguish in the Patan area and so are commonly grouped together and known as the Tharad Formation (Raju & Srinivasan, 1993).

In the south part of the Cambay Basin, the Cambay Shale is overlain by the deltaic Anklesvar Formation. This includes the Hazad Member (important reservoir sandstone), Kanwana Shale, Ardol Member (deltaic sandstone) and Telwa Shale Member (an effective seal).

Late Eocene to Early Miocene

The shaly Tarapur Formation (and its equivalent in the south Cambay basin, the Dadhar Formation) represents a regional cap-rock and was deposited across the whole Cambay Basin in the Latest Eocene to Oligocene (Raju & Srinivasan, 1993).

A further widespread marine transgression in the Upper Oligocene-Lower Miocene resulted in the deposition of the Kathana Formation in the northern part of the basin and the Tarkesvar Formation in the southern part of the basin (Raju, 1968; Biswas, 1994; Wani et al., 1995,)

Miocene to Neogene

There is an unconformity between the Kathan and Tarkesvar Formations and the overlying Early Miocene Babaguru Formation. A further unconformity occurs between the Babaguru Formation and the overlying Kand Formation (Wani et al., 1995; Raju & Srinivasan, 1993). The Jhagadia Formation was deposited unconformably on the Kand during the middle-late Miocene (Wani et al., 1995). During the later Neogene, the Cambay Basin subsided only slowly and the coast retreated further south to its present position (Raju & Srinivasan, 1993).

Hydrocarbons

There are several producing fields in the Cambay Basin. Some 4000 wells have been drilled over 40 years. These have yielded some 2.1 billion barrels of reserves and over 1 Tcf of gas.

In summary:

  • The Cambay Shale (and possibly the Olpad Formation) are the main source rocks.
  • 90% of the confirmed oil and gas reserves are in Middle Eocene reservoir rocks.
  • Reactivation of faults during the early Miocene resulted in the formation of anticlinal structures which later trapped migrating hydrocarbons in fields such as Anklesvar, Kosamba, Motwan, Olpad, Jhagadia and Hazira (Roy 1990).
  • Strong southward tilt of the Broach depression due to subsidence along the Narmada Fault resulted in development of fault-controlled anticlinal features such as the plunging anticline at Gandhar, the closures at Dabka and Daheja and other features (Roy, 1990).
  • About 56% of the discovered hydrocarbons occur in structural traps and 44% in stratigraphic and combination traps (Dhar & Bhattacharya, 1993).
  • The (Oligocene) Tarapur Shale Formation forms a regional cap rock (Raju & Srinivasan, 1993).

The location of the main fields in the Cambay basin is shown in Figure A3.14.

Figure A3.14 Location of the main oil and gas fields in the Cambay Basin (adapted from Raju and Srinivasan 1993, Roy 1990, Dhar & Bhattacharya 1993)

CO2 storage potential

There is good CO2 storage potential in the Cambay Basin.

The main petroleum reservoir rocks, and thus proven sealed reservoirs, are of Middle-Upper Eocene age. Porosity is frequently in the range 2-14% (Hardas et al. 1989, Senapati et al. 1993) and permeability is in the range 0.3-162.5 mD (Senapati et al. 1993, Mandal & Bhattacharya 1997). The Tarapur Shale Formation forms a regional cap rock above these reservoirs (Raju & Srinivasan, 1993).

In the central Cambay Basin, the top of the Middle-Upper Eocene Kalol Formation reservoir is at 880 m -790 m and forms a domal structure (Dhar & Bhattacharya 1993), which may be suitable for CO2 storage. The Anklesvar Formation in the south Cambay Basin is at depths of 750 m to 3100 m, and contains smaller domal structures that may be suitable for CO2 storage (Biswas et al. 1994).

In parts of the Gulf of Cambay, hydrocarbons have been trapped in domal structures capped by the overlying Miocene Kand Shale (Biswas et al., 1994).

The present day geothermal gradient in the Cambay basin is 29.8-35.0°C/km (Singh et al., 1995).

References

Biswas, S. K. 1987. Regional tectonic framework, structure and evolution of the western marginal basins of India. Tectonophysics, 135, 307-327.

Biswas, S. K. 1987. Regional tectonic framework, structure and evolution of the western marginal basins of India. Tectonophysics, 135, 307-327.

Biswas, S.K., Bhasin, A.L. & Ram, J. 1993. Classification of Indian Sedimentary Basins in the Framework of Plate Tectonics. Proceedings of the second seminar on Petroliferous basins of India, Vol. 1, 1-46.

Choudhary, R.N., Bondre, S.A. & Sharma, B.K. 1997. Resistivity-TOC ratio as an indicator of maturity level for oil generation – Cambay basin, India. Proceedings Second International Petroleum Conference and Exhibition PETROTECH-97, New Delhi, pp213-221.

Dhar, P.C. & Bhattacharya, S.K. 1993. Status of exploration in the Cambay basin. In: Biswas, S.K., Dave, A, Garg, P., Pandey, J, Maithani, A., Thomas, N. J. (eds.), Proceedings Second Seminar on Petroliferous basins of India, Vol. 2, Indian Petroleum Publishers, Dehra Dun, India, pp1-32.

Dhar, P.C. & Singh, R.P. 1993. Evolution of Cambay graben. Rifted Basins and aulacogens: Geological and geophysical Approach 1993. Casshyap et al (eds). Pp268-280

Kaila, K.L., Tiwari, H.C. & Tripathi, K.M. 1979. Deep sounding seismic sounding studies along Navibander-Amreli profile. Saurashtra, Gujarat, India. Technical Report National Geophysics Research Laboratory, Hyderabad.

Kundal, J., Wani, M.R., Thakur, R.K. 1993. Structural style in South Cambay Rift and its control on postrift deltaic sedimentation. In: Biswas, S.K., Dave, A, Garg, P., Mandal, A.K. & Bhattacharya, V.K. 1997. Revival of oil production from Linch field of Cambay Basin by solvent stimulation technique. Proceedings Second International Petroleum Conference and Exhibition PETROTECH-97, New Delhi, pp270-284.

Mishra, K.S. 1981. The tectonic setting of Deccan volcanics in southern Saurashtra and northern Gujarat. In: Subbarao, K.V. & Sukheshwala, R.N. (eds), Deccan Volcanism, Geological Society India, Bangalore, pp81-86.

Mukherjee, B.K. & Kapoor, P.N. 1995. ‘Organic Matter Maturation Studies of Tertiary Sequences in Shelf Area of Bengal Basin, India.’ Proceedings of PETROTECH-95, New Delhi Technology Trends in Petroleum Industry, pp373-384.

Nanawati, V., Jain, A.K., Singh, H. & Shukla, R.K. 1995. Efficacy of Olpad formation as source rock in Ahmedabad-Mehsana block of Cambay basin, India. Proceedings PETROTECH-95, Technology Trends in Petroleum Industry, pp245-253.

Pandey, J, Maithani, A., Thomas, N. J. (editors), Proceedings Second Seminar on Petroliferous basins of India, Vol 2, Indian petroleum publishers, Dehra Dun 248001, India, pp79-96

Raju, A.T.R. & Hardas, M.G. 1985 Middle Eocene environments in Cambay basin. Petroleum Asia Journal, 8(11), 86-106.

Raju, A.T.R. & Srinivasan, S. 1983. More hydrocarbons from well explored Cambay basin. In: L L Bhandari, B S Venatachala, R Kumar, S N Swamy, P Garga and D C Srinastava (editors), Petroliferous basins of India. Petroleum Asia Journal, 6(4), 25-35.

Raju, A.T.R. & Srinivasan, S. 1993. Cambay basin - petroleum habitat. In: Biswas, S.K., Dave,

A, Garg, P., Pandey, J, Maithani, A., Thomas, N. J. (editors), Proceedings of the second seminar on Petroliferous basins of India, Vol 2, India petroleum publishers, Dehra Dun, India, pp33-78.

Roy, T.K. 1990. Structural styles in southern Cambay basin India and role of Narmada Geofracture in formation of giant hydrocarbon accumulations. Bulletin ONGC, 27(1), pp15-56.

Senapati, R.B., Singh, N.K., Kumar, A. & Tikku, C.L. 1993. Hydrocarbon prospects of Patan Area, Patan-Sanchor block, north Cambay Basin, India. Bulletin of the Oil and Natural Gas Corporation Limited, 30(2), 59-81.

Wani, M.R. & Kundu, J. 1995. Tectonostratigraphic analysis on Cambay Rift basin India: Leads for future exploration. Proceedings PETROTECH-95, Technology Trends in Petroleum Industry, pp147-164.

The Cauvery Basin

Introduction

The Cauvery Basin (Figure A3.15) is located at the southern end of the east coast of India and lies in the state of Tamil Nadu, south of Chennai (formerly Madras). The Indian part of the basin covers an area of 25,000 km2 onshore and around 35,000 km2 offshore. The offshore part of the basin lies between India and Sri Lanka. The western limits of the basin are formed by exposures of Archaean rocks (which have no CO2 storage potential).

Figure A3. 15 Location of the Cauvery Basin

Structure

Development of the Cauvery Basin resulted from extension between India and Sri Lanka during the break-up of Eastern Gondwanaland (Narasimha Chari et al. 1995) in early Cretaceous times. It is a NE-SW trending pericratonic rift basin containing sedimentary rocks of Early Cretaceous to Recent age.

NE-SW-trending fault movement controlled Early Cretaceous sedimentation and resulted in the development of a series of horsts graben and half-graben. A map of these structural elements is given in Narasimha Chari et al. (1995). In early Cenozoic times the basin was tilted down to the ESE and the blocks and basins were subjected to a series of transgressive-regressive events (Kumaraguru et al. 2005). Consequently the basin fill contains major unconformities and has low regional dips trending towards the ESE.

The various structural elements of the Cauvery Basin are briefly described below:

Pondicherry Sub-basin

Located in the northern part of the Cauvery Basin, this is a linear feature that extends from onshore to offshore. It is bordered by Archean granites and gneisses to the west and by the subsurface Kumbhakonam-Shiyali Ridge to the southeast. Thick lignite beds occur in this depression. They are exploited in the Neyveli Lignite Field.

Kumbhakonam-Shiyali Ridge

A subsurface basement ridge consisting of Precambrian basement overlain by approximately 1.8 km of sedimentary rocks, most of which are of Cenozoic age.

Madanam Ridge

A large dome-shaped feature lying offshore to the north of Madanam, it is offset from the Kumbhakonam-Shiyali Ridge. Cenozoic sediments 1.6-2 km in thickness lie unconformably on basement rocks here.

Thanjavur Sub-basin

This depression is bounded by the Precambrian crystalline shield to the WNW and the Devakottai-Mannargudi Ridge to the ESE. The maximum depth to basement is 3-4 km and the depression gradually shallows towards its margins. The Cenozoic is very thin here.

Tranquebar Sub-basin

The maximum depth of this depression is approximately 4.5 km. It lies partly on- and partly offshore; there is about 2.5 km of Cenozoic sedimentary cover.

Karaikal Ridge

A linear feature, which lies on- and offshore. Depths to basement are in the order of 1 km in the northeast and 2.5 km in the southwest. Cretaceous sediments are absent over large parts of this feature and all the cover is Cenozoic.

Nagapattinum Sub-basin

This depression extends into the Bay of Bengal. Depths to basement reach 4.5 km.

Vedarniyam High

This high is located mostly offshore and connects with the northern tip of Sri Lanka. It contains about 1.5 km of Cenozoic sediments

Devakottai-Mannargudi Ridge

A long ridge extending along the NW margin of Palk Bay that separates the Thanjavur and Ramnad-Palk Bay sub-basins. Depth to basement increases slowly to the northeast, where it is at almost 1 km. There are mainly Cenozoic sediments overlying this ridge.

Palk Bay Sub-basin

This depression lies mainly offshore and contains approximately 4.5 km of sedimentary rocks, nearly half of which are Cenozoic in age. It is petroleum-bearing.

Mannar Sub-basin

This is an offshore feature lying in the Gulf of Mannar. Here Cretaceous rocks overlie the basement.

5.4.1 Stratigraphy

Sedimentary rocks filling the basin range in age from Early Cretaceous to Recent, and are up to 6 km thick. A thick sequence of Cretaceous strata and a moderately thick section of Cenozoic strata overlie the Archean basement. A thin layer of alluvium covers most of the Cenozoic sediments (Mukhopadhyay et al., 2005). The stratigraphy of the onshore Cauvery Basin has recently been revised by Watkinson et al. (2007).

Reservoir rocks and seals

The best reservoir potential for CO2 storage lies in Cretaceous sandstone reservoirs. In general, sandstone reservoirs in the Upper Cretaceous are good quality with intergranular and interconnected dissolution pores, whereas sandstone reservoirs in the Lower Cretaceous are low quality with mainly micropores and few interconnected pores (Lahiri et al., 1997).

The (sealed) hydrocarbon-bearing formations are the Lower Andimadam, Upper Andimadam and Bhuvanagiri/Upper Palk Bay formations – all form part of the Uttatur Group - and the Nannilam Formation, which belongs to the Trichinopoly and Ariyalur Groups (Govindan et al. 2000).

Lowstand fans and wedges may also form good reservoirs (Watkinson et al. 2007, Prabhakar et al. 1993).

Existing oil and gas traps are mainly of combination stratigraphic and structural types.

CO2 Storage Potential

The presence of oil and gas fields in the Cauvery Basin indicates that the potential to store CO2

in this area is high. This is particularly so in Mid- to Upper Cretaceous sequences where reservoir quality is good and there are interbedded seals.

References

Govindan, A., Ananthanarayanan, S. & Vijayalakshmi, K.G. 2000. Cretaceous petroleum system in Cauvery Basin, India. In: Govindan, A. (editor), Franz Kossmat volume; Cretaceous stratigraphy, an update. Memoir Geological Society of India, 46, 365-382.

Kumar, S.P. 1983. Geology and Hydrocarbon Prospects of Krishna Godavari and Cauvery Basins. In: L.L. Bhandari, B.S. Venatachala, R. Kumar, S.N. Swamy, P. Garga & D.C. Srinastava (editors), Petroliferous Basins of India. Petroleum Asia Journal, 6(4) November 1983, pp 57-65.

Lahiri, G. & Hardas, M.G. 1997. Diagenetic effects on sandstone reservoirs of Nannilam Field, Cauvery Basin. Journal Geological Society of India. 49(6), 61-674.

Mukhopadhyay, S.K., Kumaraguru, P, Bandopadhyay, Shyamali. 2005. Depositional model for lignite deposits in Cauvery sedimentary basin, Tamil Nadu. Special Publication Series -Geological Survey of India, 81, 62-100.

Narasimha Chari, M.V., Sahu, J.N., Banerjee, B., Zutshi, P.L. & Kuldeep Chandra. 1995. Evolution of the Cauvery basin, India from subsidence modelling. Marine and Petroleum Geology, 12(6) 667-675.

Prabhakar, K.N., Awasthi, A.K., Roy, S.K., Prakesh, A., Gupta, R. & Kumar, I.J. 1993. Sequence Stratigraphy and Systems Tract Analysis of Nagapattinam Subbasin Cauvery Basin. In: Biswas, S.K., Dave, A, Garg, P., Pandey, J, Maithani, A., Thomas, N. J. (editors), Proceedings of the second seminar on Petroliferous basins of India, Vol. 1, pp203-215.

Ramkumar, M., Stueben, D., & Berner, Z. 2003. Lithostratigraphy, depositional history and sea level changes of the Cauvery Basin, southern India. Geoloshki Anali Balkanskoga Poluostrva, 65; Pages 1-27. Zavod za Regionalnu Geologiju i Paleontologiju, Belgrade, Yugoslavia.

Ramkumar, M., Subramanian, V. & Stueben, D. 2005. Deltaic sedimentation during Cretaceous period in the northern Cauvery Basin, South India; facies architecture, depositional history and sequence stratigraphy. Journal of the Geological Society of India, 66(1), 81-94.

Thomas, N.J., & Sharma, V.N. 1993. Thermal Evolution of Source Rocks in Cauvery Basin. In: Biswas, S.K., Dave, A, Garg, P., Pandey, J, Maithani, A., Thomas, N. J. (editors), Proceedings of the second seminar on Petroliferous basins of India, Vol. 1, 245-254.

Watkinson, M.P., Hart, M.B. & Joshi, A. 2007. Cretaceous tectonostratigraphy and the development of the Cauvery basin, southeast India. Petroleum Geoscience, 13, 181-191.

THE CHHATTISGARH BASIN

 

Figure A3. 16 Location of the Chhattisgarh Basin

Introduction

The Chhattisgarh Basin is an intracratonic Proterozoic sedimentary basin in central India (Figure A3.16). The Proterozoic sedimentary rocks rest unconformably on the Archaean basement complex of the Indian shield. It has not been extensively studied and its depth, tectonics and structural features are poorly known.

5.4.1.1 STRUCTURE

Gravity data suggest that the Chhattisgarh Basin reaches a maximum depth of around 3.5 km (Singh et al. 1990).

5.4.1.2 STRATIGRAPHY

The basin fill (Figure A3.17) comprises a thick succession of sandstone, shale and limestone known as the Chhatisgarh Supergroup (Naqvi & Rogers 1987, Murti 1987, 1996, Das et al. 1992, Datta 1998, Das et al. 2001, Gupta 1998, Datta et al. 1999, Patranabis Deb & Chaudhuri 2002).

The lower part of the succession (the Chandarpur Group) is dominated by sandstone and consists of purple sandstone and buff shales. The upper part (the Raipur Group) is dominated by limestone and shale.

The Chandarpur Group comprises undeformed, unmetamorphosed and gently dipping to subhorizontal strata and is further subdivided into three formations (Figure A3.19).

Figure A3. 17 Stratigraphy of the Chhattisgargh Supergroup

The lowest sequence, known as the Lobardih Formation, comprises up to 120 m of conglomeritic sandstones deposited in alluvial fans and braided river to subtidal environments (Datta et al. 1999).

The overlying Chaporadih Formation (2–10 m) is dominated by thinly laminated mudstone. Towards the top, heterolithic facies composed of coarse-grained ripple beds and mudstone appear. It is believed to represent the deposits of a quiet water shelf occasionally perturbed by storm waves.

The Kansapathar Formation (20–40 m), the topmost unit of the siliciclastic Chandarpur Group, is made up of medium-grained, well sorted, purple coloured quartzarenite, glauconitic in places. It is an extensive sheet-like sand body with a gradational to sharp contact with the underlying unit. It records a fluvial to marine transition (Datta et al. 1999). In general, the individual sandstone beds are 30 cm to 1.5 m thick, are commonly cross-stratified, slightly wavy and sheet-like, but in places show pronounced lenticular geometry.

K–Ar dating of authigenic glauconite from the lower part of the Chhattisgarh Supergroup indicates an age of 700–750 Ma (Kreuzer et al., 1977).

There is no published detailed pertrographic work on the Chhattisgarh Supergroup.

Carbon dioxide storage potential

The CO2 storage potential of this basin cannot be assessed properly on the basis of currently available information. Although it is premature to write it off completely, its Proterozoic age suggests that it is unlikely to contain well sealed, highly porous and permeable reservoir rocks at depth. Therefore its CO2 storage potential is presently classified as limited.

References

Das, D.P., Kundu, A., Das, N., Dutta, D.R., Kumaran, K., Ramamurthy, S., Thanavelu, C. and Rajaiya, V. 1992 Lithostratigraphy and sedimentation of Chattisgarh Basin; Indian Minerals 46, 271–288.

Das, N., Dutta, D.R. and Das, D.P. 2001. Proterozoic cover sediments of southeastern Chattisgarh state and adjoining part of Orissa. Geological Survey of India Special Publication 55, 237–262.

Datta, B. 1998. Stratigraphic and sedimentologic evolution of the Proterozoic siliciclastics in the southern part of Chattisgarh and Khariar, central India; Journal of the Geological Survey of India, 51, 345–360.

Datta, B., Sarkar, S. and Chaudhuri, A.K. 1999. Swaley crossstratification in medium to coarse sandstone produced by oscillatory and combined flows: examples from the Proterozoic Kansapathar Formation, Chattisgarh Basin, M.P., India; Sedimentary Geology 129, 51–70.

Gupta, A. 1998. Hummocky cross-stratification in the Chattisgarh Basin, M.P. and its hydraulic and bathymetric implications. Journal of the Indian Association of Sedimentologists 17(2), 213–224.

Kreuzer, H., Karre, W., Kursten, M., Schnitzer, W.A., Murti, K.S. and Srivastava, N.K. 1977. K/Ar dates of two glauconites from the Chandarpur-Series (Chattisgarh/India): on the stratigraphic status of the late Precambrian basins in central India. Geol. Jb. B28, 23–36.

Moitra, A.K. 1995. Depositional environmental history of Chattisgarh Basin, M.P., based on stromatolites and microbiota. Journal of the Geological Society of India 46(4), 359–368.

Murti, K. S. 1987. Stratigraphy and sedimentation in Chattisgarh Basin; In: Purana basins of peninsular India, Memoir of the Geological Society of India 6, 239–260.

Murti, K.S. 1996. Geology, sedimentation and economic mineral potential of the south-central part of Chattisgarh Basin. Geological Survey of India Memoir 125, 139.

Naqvi, S.M. and Rogers, J.J.W. 1987. Precambrian Geology of India, Oxford University Press, New York, U.S.A., 223pp.

Patranabis Deb, S. and Chaudhuri, A.K. 2002. Stratigraphic architecture of the Proterozoic succession in the eastern Chattisgarth Basin, India: tectonic implications, Sedimentary Geology 147, 105–125.

Singh, V.P., Shanker, D. & Singh, R. 1990. A structural and tectonic synthesis of parts of Archeans, Satpuras and Chhattisgarh basins around Mandalaraipur districts, M.P., India, using gravity field data. Dept. of Science and Technology (DST), New Delhi, Project No. ES/23/119/90, 16pp.

THE CUDDAPAH BASIN

 

Figure A3.18 Location of the Cuddapah Basin

Introduction

The crescent-shaped Cuddapah Basin is a Proterozoic intracratonic sedimentary basin on the eastern margin of the Eastern Dharwar Craton (Figure A3.18). It rests unconformably on Archaean gneiss and granite basement rocks.

Covering an area of about 34,000 km2, the basin contains sedimentary and igneous rocks that dip gently to the east, on average at about 10-15°. It is one of the better studied Proterozoic basins of India (e.g. Rao & Murthy, 1978; Mishra, 1992; Verma & Dutta, 1994; Prasanti Lakshmi & Ram Babu, 2002).

Structure

Based upon aeromagnetic data, the basin may reach a maximum thickness of around 10 km near Muddanuru (Prasanti Lakshmi & Ram Babu, 2002).

Stratigraphy

The Cuddapah Basin contains Proterozoic, predominantly sedimentary rocks which are divided into the Cuddapah and Kurnool supergroups. In places, the sedimentary rocks are interlayered with sills, tuffs and lava flows.

The Cuddapah Supergroup is of middle Proterozoic age (1600–1300 Ma). It is dominantly argillaceous and arenaceous, with subordinate calcareous strata and is divided into three groups, the Papagni, Chitravati and Nallamalai Groups. Rocks of the Nallamalai Group crop out in the eastern part of the basin and are highly disturbed, folded and faulted.

The overlying Kurnool Supergroup, of middle to late Proterozoic age (980–520 Ma), is found in the central part of the basin. It is divided into three subgroups, each of which starts with a quartzite and ends with a shale unit. It is thought to have been deposited in a shallow marine shelf environment.

Igneous rocks

A large lopolithic intrusion, manifested by a positive gravity anomaly, occurs in the southwestern part of the basin. Concentric sills following the arcuate western and south-western margins of the basin occur around the lopolithic intrusion. Mafic sills and dykes occur in and around the basin margins (contemporary dykes occur in the Napier complex of East Antarctica). Dykes and dyke swarms tend to trend in NW-SE and NE-SW directions. The igneous rocks in and around Cuddapah basin vary in age between 650 Ma and 1850 Ma with episodic emplacements and a peak period of activity between 1400 and 1200 Ma.

Carbon dioxide storage potential

The CO2 storage potential of this basin cannot be assessed properly, not least because there is no information available on the porosity and permeability of its potential reservoir rocks. Although it is premature to write it off on the basis of the information outlined above, its great age suggests that it is unlikely to contain well sealed highly porous and permeable reservoir rocks at depth. Therefore its CO2 storage potential is presently classified as limited.

References

Mishra, D.C., 1992. Mid-continental high of Central India and the Gondwana tectonics. Tectonophysics, 212, 153-161.

Prasanti Lakshmi, M. & Ram Babu, H.V. 2002. Basement structure of the southwestern part of the Cuddapah Basin from aeromagnetic anomalies. Current Science, 82(11), 1378-1381.

Rao, B.S.R. & Murthy, I.V.R., 1978. Gravity and magnetic method of prospecting, Arnold Heineman publisher (India) Pvt. Ltd., New Delhi, 390-395.Verma, R. K. and Dutta, U., 1994. Analysis of aeromagnetic anomalies over the central part of the Narmada-Son-Lineament. Pure Applied Geophysics, 142, 383-405.

THE DAMODAR VALLEY BASINS

 

The Damodar Valley lies in the north-eastern part of peninsula India, in the States of Jarkhand and West Bengal. It contains a number of important Gondwana coal-bearing basins.

Structure

The Damodar Valley basins are found within the ENE-WSW-trending Permian to Mesozoic Narmada-Son-Damodar Graben. The graben follows the Satpura Precambrian structural trend, and transects the middle of the Indian shield, forming a major mid-continental rift. It overlies a transtensional pull-apart basin on the same trend that was initiated during Proterozoic times (Biswas 1992). The basins are coal-bearing and the described in detail in Appendix 2.

Stratigraphy

Generally, the Lower Permian sediments of the Damudar Group were deposited unconformably on the Pre-Cambrian basement (Figure A3.19). However, pre-Permian Upper Palaeozoic sediments are present in a few places (Dutta 2002).

Figure A3.19 Summary of stratigraphy and lithology of the Damodar Basins (after Dutta 2002).

The Lower Permian Talchir Formation consists of tillite and other glacial deposits laid down in a braided river system. Overlying the Talchir are coal-bearing rocks of the Barakar Formation, deposited in a meandering river system. The Barakar coal measures gradually gave way to the non-productive strata of the Barren Measures Formation (largely sandstone and shale). In places, principally the Raniganj coalfield, these are overlain by Upper Permian coal measures of the Raniganj Formation, which were less widely deposited (Dutta 2002).

Triassic

Coal measure deposition continued into the Triassic resulting in the deposition of the Panchet Formation, which consists of sandstone, grey and red shales, with only rare coal seams. A relatively short erosional period occurred at the end of the Triassic before deposition of the Jurassic Mahadeva Formation took place.

Jurassic

The Mahadeva Formation consists largely of conglomerates, sandstones and siltstones. It is described as a mineralogically mature unit deposited in a braided river system (Dutta 2002).

Oil and Gas

No oil or gas fields have yet been found in the Damodar Valley basins.

CO2 storage potential

The Damodar Valley basins may have potential for CO2 storage, especially in areas where the coal measures are deeply buried beneath Mesozoic cover and thus less likely to be mined. Potentially, both reservoir rocks and seals are present in the Permian succession and thus the Damodar Valley is classified as having fair potential. However, there is insufficient information on structure, porosity and permeability of the potential reservoir rocks to make a judgement on their true potential.

References

Bhattacharyya, A. & Banerjee, S.N. 1979. Quaternary geology and geomorphology of the Ajay-Bhagirathi valley, Birbim and Murshidabad districts, West Bengal. Indian Journal Earth Sciences, 6, 91-102.

Biswas, S.K. 1992. Tectonic Frame-work and Evolution of Graben Basins of India. Indian Journal of Petroleum Geology, 1(2), 276-292.

Dutta P. 2002. Gondwana Lithstratigraphy of Penninsular India. Gondwana research (Gondwana Newsletter Section) 5(2) pp540-553

Matter, J. M., Assayag, N. and Goldberg D. 2006 Basaltic rocks and their potential to permanently sequester industrial carbon dioxide emissions in 2006 8th International conference on greenhouse gas control technologies, Trondheim, Norway.

Parkash, B. & Kumar, S. 1991. The Indogangetic Basin. In: Tandon, S.K., Pant, C.C. & Casshyap, S.M. (editors), Sedimentary basins of India: Tectonic Context. Gyanodaya Prakashan, Nainital, India, pp 147-170.

Parkash, B., Sharma, B.P. & Roy, 1980. The Siwalik Group (Molasse) – sediments shed by collision of continental plates. Sedimentary Geology, 25, 127-159.

Raiverman, V., Ganju, J.L. & Misra, V.N. 1979. A new look into the stratigraph of Cenozoic sediments of the Himalaya foothills between the Ravi and Yamuna rivers. Geological Survey of India Miscellaneous Publications, 41, 233-246.

Raju, A.T.R. 1979. Basin Analysis and Petroleum Exploration with some examples from Indian Sedimentary Basins. Journal Geological Society of India, 20, 49-60.

Shastri, V.V., Bhandari, L.L., Raju, A.T.R. & Datta, A.K. 1971. Tectonic framework and subsurface stratigraphy of the Ganga Basin. Journal Geological Society India, 12(3), 222-233.

Srinivasan, S. & Khar, B.M. 1995. Frontier Basin Exploration in India – Perspectives and Challenges. Proceedings PETROTECH-95, Technology Trends in Petroleum Industry, New Dehli, pp1-19.

Vijaya and Bhattacharji, T. K., 2002. An Early Cretaceous age for the Rajmahal traps, Panagarh area, West Bengal: palynological evidence. Cretaceous Research 23, pp 789–805.

THE GANGA BASIN

Introduction

A major Cenozoic foreland basin covering an area of over 750,000 km2 lies immediately south of the Himalaya, Karakoram and Hindu Kush mountain ranges. It is the largest sedimentary basin in the subcontinent (Parkash & Kumar, 1991) and originated as a result of the collision of the Indian Plate with the Eurasian Plate in Cenozoic times. For descriptive purposes it is divided into three sections. From west to east these comprise the Indus Basin, the Punjab Shelf and Ganga Basin and the Assam Basin. The Ganga Basin is described below.

The Ganga Basin (Figure A3.20) lies to the south of the main boundary thrust of the Himalayas. It covers an area of some 250,000 km2 (Shastri et al., 1971; Srinivasan & Khar, 1995).

Figure A3.20 Location of the Ganga Basin and Punjab Shelf

To the east the Ganga Basin passes laterally into the Cainozoic and Quaternary alluvium north of the Shillong Plateau and then into the Assam Basin. To the west it passes laterally into the Cainozoic and Quaternary strata of the Punjab Shelf: the boundary between the two basins is somewhat arbitrary but is here taken along the Delhi-Hardwar Basement Ridge.

The Ganga Basin contains, close to the main Himalayan Boundary Thrust on its northern margin, 4-6 km of Cenozoic and Quaternary alluvium that thins southwards and eastwards onto older sedimentary sequences of Mesozoic, Palaeozoic and Precambrian age, and Precambrian basement rocks. Pre-Cenozoic basins thus exist beneath the Cenozoic and Quaternary alluvial deposits of the Ganges plain. A map of depth to basement beneath the Ganga Basin is given in Raiverman et al. (1983).

Fewer wells have been drilled in the Ganga Basin and Punjab Shelf than in prospective areas elsewhere in India. By 1991, there had been only 15 deep exploration wells drilled in the entire Indian section of the Indogangetic Plains.

Structure

The subcrop beneath the Cainozoic and Quaternary Ganga Basin consists mainly of concealed Proterozoic Vindhyan Basin fill and Archaean basement rocks.

As the collision between the Indian and Eurasian plates has progressed and the Main Central Thrust front has advanced southwards, the Ganga Basin depocentre has shifted gradually southwards. Cenozoic sediments deposited in the northern part of the basin, close to the thrust front have been folded and uplifted by the developing thrusts, forming the Siwalik Fold Belt (expressed as the Siwalik Hills). The strata in the southern part of the basin dip and thicken gently to the north.

The basin depocentre trends WNW. It can be subdivided into a series of smaller NE-SW trending sub-basins separated by ridges. The location of these structures reflects major basement features traversing the Indian craton, which can be traced northwards into the Himalayan region (Raju, 1979).

Monghyr-Saharsa Ridge

The eastern end of the Ganga Basin is defined by the Monghyr-Saharsa Ridge. It is a NNE-trending basement high with perhaps no more than 3 km of Siwilak strata lying directly upon basement (Shastri et al., 1971).

East Uttar Pradesh Shelf and Gandak Depression/Basin

The Gandak Depression and East Uttar Pradesh Shelf lie between the Monghyr Ridge to the east and the Faizabad Ridge to the west. Outcropping Vindyhan Group and basement form the southern boundary. To the north the shelf merges with the Gandak depression/basin, where the thickness of the sedimentary sequence increases to 6000 m or more. The basement is thought to be formed mainly by the Satpura Fold belt (Shastri et al., 1971)

In the deepest parts of the Gandak Depression, Mesozoic strata may be present, as a well near Raxaul proved the pre-Siwalik unconformity at 4128 m beneath which was a 67 m thick sequence of uncertain stratigraphic affinity lying above 607 m of strata assigned to the Vindyhan Group.

Faizabad Ridge

The Faizabad Ridge is a major north-easterly trending intrabasinal high. It is the concealed extension of the exposed Bundelkhand Massif.

West Uttar Pradesh Shelf and Sarda Depression/Basin

The West Uttar Pradesh Shelf is perhaps the best understood sub-basin area. At least 6 wells have been drilled and significant amounts of geophysical data have been acquired. To the NE it merges with the Sarda Depression/Basin. The pre-Siwalik unconformity varies in depth from 620 m near Kasgani to perhaps greater than 4,200 m near the Indo-Nepal border (Shastri et al. 1971).

Deli-Hardwar Ridge

The Deli-Hardwar Ridge marks the north-western limit of the Ganga Basin. The basement is shallow and is imaged on seismic reflection data as far NE as the Meerut region.

Stratigraphic and sedimentary details

The oldest sedimentary rocks, beneath the Ganga Basin and Punjab Shelf, which are of Upper Proterozoic to Lower Palaeozoic age, unconformably overlie crystalline basement. They are a series of shallow water platform or shelf limestones, shales and quartz-arenites that are assigned to the Vindyhan Group.

In the Gandak, and possibly the Sarda, Depressions the Vindhyan rocks are overlain by a thin sequence of unknown, possibly Mesozoic, age (Raju, 1979). But in general, Cenozoic strata lie unconformably on a peneplained surface of Vindyhan Group and basement rocks.

Cenozoic deposition commenced with sequences of the Sirmur Series. This is of Palaeogene age.

Over the greater part of the basin the Sirmur Series is overlain by the continental sands and silts of the Lower, Middle and Upper Siwalik Series of Neogene (Mid Miocene to Pliestocene) age, which onlap the Vindhyans and Basement. The thickness of the Siwalik Group varies from a few metres at the southern margin of the basin, to over 4000 m near the mountain front (Shastri et al. 1971). It consists of fluvio-deltaic sediments deposited by southerly flowing rivers draining into the Ganga basin from the Himalayas to the north.

The Cenozoic sediments of the Indogangetic Plain area have, due to exposures in the outer Himalayan belt, been well studied (e.g. Raiverman et al., 1979; Parkash et al., 1980; Parkash & Kumar, 1991). Given the tectonics in the area and continental deposition, local correlations are often difficult, however, the basic stratigraphic subdivisions are:

Neogene Sub-Himalayan System Siwalik Series(Supergroup) Upper
Middle
Lower (Nahan)
Palaeogene Sirmur Series Upper (Kasauli)
Middle (Dagshai)
Lower (Subatha)

Details of the Lower Siwalik

The Lower Siwalik typically comprises highly indurated, compact, fine to coarse grained, grey to bluish grey and purple sandstones interbedded with reddish brown to grey, hard concretionary shales (Parkash et al. 1980). A maximum thickness of c. 2400m is found in the Kotdwara section to the east of Hardwar, where the uppermost 500 m of the sequences is arenaceous. This contains coarse sandstones and some conglomerates with pebbles 1-2 cm in size. Shales are thin and infrequent/almost absent (Parkash et al. 1980).

Southwards, away from the Himalaya, the Lower Siwalik sequences are a sandstone-clay assemblage, with often thick clay beds (Parkash et al. 1980).

Details of the Middle Siwalik

The Middle Siwalik comprises dominantly medium to coarse-grained, friable, cross-bedded sandstones, interbedded with some thin clay beds. Patches of calcite-cemented sandstones form more resistant areas at outcrop. The clays are earthy grey to purple red in colour.

The Middle Siwalik sandstones coarsen upwards, with a near absence of shales and the occasional appearance of conglomerates. In the north of the foldbelt area, the Middle Siwalik sandstones pass into mainly coarse conglomerates (Parkash et al. 1980). Southwards away from the Himalaya, as with the Lower Siwalik sequences, the Middle Siwalik is represented by a sandstone-clay assemblage, with often thick clay beds (Parkash et al. 1980).

Details of the Upper Siwalik

The Upper Siwalik is characterised by conglomerates consisting of pebbles set in an orange-red clayey or sandy matrix. A few shale interbeds are developed (Raju 1967, Raiverman et al. 1975).

The very coarse nature of the Upper Siwalik sequences, along with the near absence of clays, indicates a braided stream environment of deposition for the main part. A similar origin is envisaged for the arenaceous facies of the Lower and Middle Siwalik sediments.

Quaternary strata

The Quaternary sediments of the Indogangetic Plains are subdivided into the Older (Bhangar) and Younger (Khadar) Alluvium. There is evidence that they in places they can be further subdivided into Lateritic Upland, Older Deltaic Plain, Younger Deltaic Plain and Bhagirithi Recent Surface (Battacharyya & Banerjee, 1979). The modern Ganga system is a large braided river.

Well summaries

The following provide summaries of the general stratigraphy and rock type encountered across the Ganga Basin.

Raxaul &num;1

Sequence depth range sediment type
Allluvium & Upper Siwalik 0m – 1500 m grey coarse to medium and pebbly sandstones, friable with Sub ordinate clay, overlain by alluvial sand and silt
Middle Siwalik 1500 m – 3200 m Light grey, medium to fine grained sandstones with mottled siltstone and clay. Some carbonaceous streaks and fossil wood
Lower Siwalik 3200 m – 4128 m brown calcareous claystones with siltstone and fine sandstone
  ------unconformity------  
Mesozoic 4128 m – 4195 m reddish brown quartzitic sandstone with brown shales with bluish green variegations
Vindhyan 4195 m – 4901 m current bedded orthoquartzites, some pebbly and conglomeritic, with metaquartzitic pebblesand thin green to purple shale lenses. Basic igneous rocks are present between 4195-4315 m and 4365-4410 m.

Ujhani #1

Sequence depth range sediment type
Allluvium & Upper Siwalik nodular clays 0 m – 705 m Pebbly and coarse, highly micaceous, grey sandstones with
Middle Siwalik 705 m – 1016 m coarse to medium grained Sandstone with variegated claystones and some carbonaceous streaks. Conglomerate developed above unconformity
  ------Unconformity------  
  1010 m –1269 m grey-greenish/grey dolomitic lst with fractures and intra-formational brecciation
  1269 m –1500 m reddish brown quartz arenite with thin limestone bands towards base
Palaeozoic 1500 m – 1740 m dark grey-brown pyritic shales with thin siltstone bands and brown shales towards top
  1740 m – 1804 m reddish brown argillaceous lst with convolute bedding and slump structures
  1804 m – 1062 m medium grained quartzwacke with quartz arenite bands and thin laminae of grey shales
  ------Unconformity------  
Precambrian 2062 m – 2127 m metaquartzite with sericite schist and phllite

The quartz-arenite-limestone-shale sequence is assigned to the Palaeozoic, showing similarities with a similar sequence proved in the Tilhar well (Shastri et al., 1971).

Wells drilled to the SW of Badaun (near Kasannj) and Tilhar to the east of Badaun, proved similar sequences to the two wells above. However, at Kasanj, the carbonate section contains several anhydrite layers indicating local evaporitic conditions within the shallow marine area.

Hydrocarbons

There are few hydrocarbon exploration wells in this basin and therefore rock properties and hydrocarbon potential are poorly known.

A gas seep is recorded from the Middle Siwalik rocks in the Mindalti syncline in the foothills area. An exploration well testing the Tilhar structure encountered small amounts of gas in the Vindyhan sequence.

CO2 storage potential

The Cainozoic and Quaternary basin contains the largest groundwater reserve in the country, which supports up to one third of the country’s population (Parkask & Kukar, 1991), i.e. approximately one third of a billion people. Thus any CO2 storage in the Ganges Basin would need to consider potential conflicts of interest with water supply.

Numerous aquifer units (fine-coarse grained sandstones and conglomerates) are present throughout the Cenozoic sequence, some of which provide the aquifers for the major towns and cities in the region. Potential traps exist in the Siwalik ranges and over the northern areas of the Indogangetic plain, some of which have been tested by exploration wells.

However, opportunities and potential for CO2 storage in the Ganga Basin appear limited because the main sandstone aquifers provide the groundwater for both agriculture and major centres of population. Consequently, the huge reliance on the aquifer rocks for water supplies may render the area unsuitable, given the risk of possible contamination of the aquifers. Also, whilst potential reservoir sandstones exist, the development of shales that could form potential cap rocks is patchy and unpredictable.

References

Bhattacharyya, A. & Banerjee, S.N. 1979. Quaternary geology and geomorphology of the AjayBhagirathi valley, Birbim and Murshidabad districts, West Bengal. Indian Journal Earth Sciences, 6, 91-102.

Parkash, B. & Kumar, S. 1991. The Indogangetic Basin. In: Tandon, S.K., Pant, C.C. & Casshyap, S.M. (editors), Sedimentary basins of India: Tectonic Context. Gyanodaya Prakashan, Nainital, India, pp. 147-170.

Parkash, B., Sharma, B.P. & Roy, 1980. The Siwalik Group (Molasse) – sediments shed by collision of continental plates. Sedimentary Geology, 25, 127-159.

Raju, A.T.R. 1979. Basin Analysis and Petroleum Exploration with some examples from Indian Sedimentary Basins. Journal Geological Society of India, 20, 49-60.

Raiverman, V., Ganju, J.L. & Misra, V.N. 1979. A new look into the stratigraph of Cenozoic sediments of the Himalaya foothills between the Ravi and Yamuna rivers. Geological Survey of India Miscellaneous Publications, 41, 233-246.

Shastri, V.V., Bhandari, L.L., Raju, A.T.R. & Datta, A.K. 1971. Tectonic framework and subsurface stratigraphy of the Ganga Basin. Journal Geological Society India, 12(3), 222-233.

Srinivasan, S. & Khar, B.M. 1995. Frontier Basin Exploration in India – Perspectives and Challenges. Proceedings PETROTECH-95, Technology Trends in Petroleum Industry, New Delhi, pp1-19.

THE JAISALMER BASIN

 

Figure A3.21 Location of the Jaisalmer Basin

Introduction

The Jaisalmer and Bikaner-Nagaur basins (Figure A3.21) are essentially Late Palaeozoic to Mesozoic basins underlying the easternmost part of the Cenozoic Indus Basin (which is known as the Indus Shelf). The Indus Basin lies mostly in Pakistan, where it contains thicker sequences and is hydrocarbon-bearing, containing both oil (e.g. Karampur) and gas (e.g. Sui and Mari) fields.

The Jaisalmer Basin lies in the extreme west of Rajasthan, northwest of the Barmer Basin, adjacent to the border with Pakistan. It covers an area of about 30,000 km2. A partial, seismically-based map of the basin is presented by Datta (1983).

Stratigraphy

The main sedimentary sequence in the basins is of Permian to Cretaceous age, although the oldest rocks present are Cambrian. During Palaeogene times sedimentation rates slowed and Neogene sequences are thin or even absent across much of the basin.

Structure

The Jaisalmer Basin contains a series of intrabasinal highs and sub-basins (Figure A3.22) which are, from north to south: the Kishangarh sub-basin, the Jaisalmer-Mari High, the Shahrgarh sub-basin, and the Miajlar sub-basin. It adjoins the Barmer Basin (described in Figure A3.22 as the Bikaner-Sanchor Graben).

Figure A3. 9 Structural elements of the Jaisalmer Basin (adapted from Uniyal et al. 1997, Srivasatava et al. 1995, Ministry of Petroleum and Natural Gas 1991).

The Kishangarh subbasin is bounded by the Pokoran Ridge in the NE, which separates it from the Bikaner-Nagaur Basin, and by the Jaisalmer-Mari High to the SW. The maximum thickness of sediments in the basin is about 7 km.

The Jaisalmer-Mari High, originally recognised as a NW-trending basement ridge from a series of linear and parallel gravity highs, represents a complex faulted area rather than a simple upwarp of basement affecting the overlying sediments (Datta, 1983). It is the result of a series of NW-SE trending en echelon wrench faults on either side, stepping the basement up. These affected sedimentation during Mesozoic and Cenozoic times (Khar, 1984).

The Shahrgarh sub basin lies to the SW of the Jaisalmer-Mari High and contains up to 9 km of sedimentary rocks.

The Miajlar sub basin is a little explored marginal area located in the south of the Jaisalmer Basin and recognised mainly from the interpretation of remote sensing and potential field data (Mitra et al., 1993; Mukherjee et al., 1995). The basin covers an area of around 3400 km2 and is bounded in the east by a NW-SE trending fault marking the northern margin of the Barmer Basin. To the north, it is separated from the Shahrgarh Basin by an E-W terrace-like feature in the basement. Some seismic reflection data have been acquired across the area and reveal units with strong, continuous reflections interpreted as arising from Lower Palaeozoic (Vindhyan) strata. The Lunar &num;1 well in the northernmost reaches of the basin has proved some of the concealed strata in the basin (Mukherjee et al., 1995).

Stratigraphic and sedimentological details

In the Jaisalmer Basin, eight sedimentary cycles have been recognised beginning with sequences of the Upper Proterozoic (Vindhyan) and including Indus alluvium of Quaternary age (Datta, 1983).

Figure A3.23 Summary stratigraphy of the Jaisalmer Basin

Sediments from the Proterozoic-Early Palaeozoic cycle (the Birmania/Randa Formations) are thick and represent deeper water sediments, when compared to those deposited in other basins of this age in India. However, exact age relationships and correlation of sediments between sub basins requires further work. Facies types indicate deposition in an extensive epicontinental sea during an arid period (Datta, 1983).

A major hiatus between the first and second cycle represents an orogenic phase resulting from plate collision, following which deposition of the shallow marine Permian Karampur Formation took place as the Indus shelf was inundated by a marine transgression.

The third phase, during Triassic and early Jurassic times, resulted in the deposition of predominantly continental fluvial to brackish deltaic clastic sequences. These are represented by the Shurmarwali and Lathi formations (Lukose, 1972).

During Middle Jurassic to Lower Cretaceous times an extensive stable shelf developed and carbonates were deposited widely. These exceed 1200 m in thickness in places. The basal carbonates contain considerable clastic material, but are cleaner higher up. In late Jurassic times the platform stability may have been disturbed as intense igneous activity commenced close by and further clastic material, represented by the Baisakhi and Badasar formations, entered and was deposited in a shallow marine basin. The Lower Cretaceous Parimar Formation represents a regressive phase with earlier sequences deposited in shallow marine and brackish conditions and culminating in continental conditions towards the top.

The fifth (Aptian – Albian) cycle commenced with deposition of the shallow marine Harur Formation represented by marls and arenaceous limestones along the basin margin and the Goru Formation comprising mainly marine clastics more basinwards. Sedimentation continued until Coniacian times with the development of a predominantly marine marl and carbonate succession, with some clastic beds. A major uplift phase driven by events to the west led to a prominent hiatus in sedimentation from Danian to Lower Palaeocene times. Considerable erosion of the Cretaceous succession occurred along the basin margin during this period.

The sixth sedimentary cycle commenced with the deposition of the clastic-dominated Sanu Formation, representing brackish to shallow marine conditions in late Palaeocene times. The transgression continued into early Eocene times as a series of fine clastics, marls and carbonates of the Khuiala and Bandah formations were deposited during relatively stable conditions. Renewed uplift to the west commenced during Oligocene times and a major regressive phase ensued.

From mid Miocene times, subsidence of the Indus shelf resumed with cycles 7 and 8 represented by deposition of molasse sediments from Middle Miocene to Pliocene times as a result of the onset of the Himalayan orogenic phase. Subsequently the Jaisalmer Basin was uplifted and underwent erosion and supplied clastics to the west and southwest until Quaternary times. Since Quaternary times a thin veneer of fluvial sediments has been laid down unconformably over Middle Miocene strata.

Hydrocarbons

Regional seismic reflection surveys have been acquired across the basin and exploration wells have led to the discovery of several commercial gas fields (Datta 1984). Some light oil has also been encountered, but has yet to be found in commercial quantities. The hydrocarbon potential of the western areas - the Kishangarh and Shahrgarh sub-basins - is generally thought to be good.

Hydrocarbon exploration has concentrated on the flanks of the Jaisalmer-Mari High and most of the structures have shown the presence of gas. Non commercial oil has been found in the Dandewala structure.

Characterisation of gases has proved two different types: those accumulated in Cenozoic (Palaeocene/early Eocene) reservoirs are a mixture of locally formed bacterial gases and thermogenic gas. In Early Cretaceous reservoirs, the gases are thermogenic (Uniyal et al., 1997).

CO2 storage potential

The Jaisalmer Basin has good potential for CO2 storage, particularly in the Kishangarh and Shahrgarh sub basins where a number of gas fields have already proven reservoir and cap rocks in suitable trapping configurations.

References

Datta, A.K. 1983. Geological Evolution and Hydrocarbon Prospects of Rajasthan Basin. Petroleum Asia Journal, November 1983, 93-100.Khar, B.M. 1984. Tectonic framework and hydrocarbon entrapments of Rajasthan Shelf. Bulletin ONGC, 21(1), 13-21.

Luckose, N.G. 1972. Palynologocal evidence on the age of the Lathi Formation, Western Rajasthan, India. Proceedings Seminar on Palaeopalynology and Indian Stratigraphy, pp155-159.

Mitra, D.S., Bhoi, R. & Agarwal, R.P. 1993. Hydrocarbon exploration in Shargarh and Myajlar subbasins of Jaisalmer Basin, Rajasthan, India using remote sensing techniques. Indian Journal Petroleum Geology, 2(1), 31-42.

Mukherjee, B.K., Bhandari, S.K. & Purkayastha, D. 1995. Hydrocarbon Prospects and evidence of Presence of Proterozoic Basin in Lunar-Miajlar Area, Rajasthan. Proceedings of PETROTECH-95, New Delhi Technology Trends in Petroleum Industry, pp.133-145.

Uniyal, A.K., Dwivedi, P., Mittal, A.K., Banerjee, V. & Chandra, U. 1997. Genetic Characterisation and Correlation of Natural Gases in Jaisalmer Basin, India. Proceedings of Second International Conference and Exhibition, Petrotech 97, New Delhi, pp. 117-120. B.R. Publishing Corporation, New Delhi.

THE KONKAN-KERALA BASIN

Introduction

The Konkan- Kerala Basin forms the southern part of the western continental margin of India (Figure A3.27). It covers an area of approximately 77,000 km2 down to the 200 m isobath and about 92,000 km2 down to the 2000 m isobath (Singh & Lal 1993).

Figure A3. 24 Location of the Konkan-Kerala Basin

Eight wells had been drilled in the basin to 1993. No discoveries were made although some hydrocarbon shows were observed (Singh & Lal 1993).

Structure

The onshore area

Only a very small part of the basin is onshore. Neogene and Quaternary sedimentary rocks, generally less than 300 m thick, rest directly on Precambrian basement in the area around Cochin and Trivandrum.

The offshore area

The offshore part of the Konkan-Kerala basin can be divided into six contiguous structural elements (see Singh & Lal, 1993 for map and cross section). From onshore to offshore these comprise: the Shelfal horst-graben complex, Kori-Comorin Depression, Kori-Comorin Ridge, Laxmi-Laccadive Depression, Laxmi-Laccadive Ridge and Arabian Abyssal Plain. The basin’s boundary with the contiguous Mumbai Basin to the north is taken at the Vengurla Arch, a SW-plunging basement arch.

The basin developed as a result of an early Rift Phase that is thought to have terminated in pre-Santonian times (Singh & Lal 1993) and a Post-Rift Phase that followed. Thus, during the Late Cretaceous to Early Palaeocene, and subsequently, sedimentation took place in response to passive subsidence of the continental margin and basinwards tilting of the depositional surface.

Stratigraphy

Figure A3.25 summarises the stratigraphy of the Konkan-Kerala Basin.

Figure A3.25 Generalised stratigraphy of the Konkan-Kerala Basin

The oldest drilled strata in the basin are Cretaceous volcanics. They are overlain by shallow water limestones, sandstones and silts. Santonian to Maastrichtian clastics are present in one of the wells. Latest Cretaceous to Palaeocene volcanics, equivalent in age to the Deccan Traps, overlie these (Ministry of Petroleum and Natural Gas, 1991; Desikachar, 1980).

A prograding shelf depositional system then developed. The Early Eocene to Middle Miocene shelf sediments consist predominantly of limestone and dolomite in the north of the basin, but include coarse clastics in the south.

Late Miocene to Recent sediments consist predominantly of shale and claystone but become sandier close to the coast.

Details of the stratigraphic succession in four of the wells are given in Singh & Lal (1993).

A deep sea borehole drilled on the eastern flank of the Laccadive Ridge penetrated 411m of Palaeocene terrigenous clastic and Eocene to Recent biogenic siliceous sediments and calcareous oozes but did not reach the ocean basalt underneath anticipated to be present at a depth of about 500 m below sea bed (Mitra et al., 1983).

In the north part of the area, a long narrow horst, the Kerala-Laccadive ridge, has been mapped (Mitra et al., 1983). This ridge, and the parallel Kerala-Laccadive Depression run for more than 2000 km N-S. The ridge is though to be composed of basalt. It is capped by recent coral reefs (Mitra et al., 1983).

Hydrocarbons

Source rocks

Boreholes drilled in the Kerala basin appear to indicate a near-absence of potential source rocks near shore. Moreover, no hydrocarbon shows have been found. Speculatively, there may be some potential further west where the sedimentary sequence is thicker (Mitra et al., 1983).

Reservoir rocks

On the southern part of the shelf, the Cochin-1 well encountered Palaeogene coarse sandstones and Miocene-Pliocene terrigenous clastics with coarse sandstones, claystones and numerous lignite streaks and minor limestone. The well bottomed in fractured basalt most likely of Late Cretaceous-Palaeocene age (Mitra et al., 1983).

Potential traps

Speculatively, the series of transgressions and regressions that deposited thick sediments in the basin from Palaeocene to end Miocene times may have formed stratigraphic traps, particularly on the shallower parts of the continental shelf (Desikachar, 1980). The region around the Laccadive and Minoy Islands shows evidence for the presence of upwarps and basins that form potential traps. The hinge zone adjacent to the outer continental shelf could have received hydrocarbons migrating upwards from the deeper oceanic parts of the sequence (Desikachar, 1980). The western shelf of the Kerala coast may have stratigraphic trap reservoirs within the carbonate sequence (Desikachar, 1980).

Additional information on existing wells

The Karwar-1 well, in the north of the Konkan Basin, was drilled on a fault-bounded horst block close to the edge of the Miocene paleoshelf. More than 1000 km of limestones and dolomitic limestones with good secondary porosity were penetrated. The borehole was abandoned due to complications (Mitra et al., 1983).

The Kasargod-1 well was drilled on the flank of a sharp carbonate buildup in the southern part of the Konkan Basin. It penetrated over 1400 m of carbonates underlain by over 520 m of sand and clay. A minor gas show was noted but no major hydrocarbon shows were identified (Mitra et al. 1983).

The K-1-1 well in the northern part of the Kerala Basin (Figure 2) penetrated Oligocene-early Miocene limestones and sandstones at depths of 1200 m and deeper, capped by Mid-Miocene clays.

The CH-1-1 borehole in the central Kerala Basin penetrated Oligocene-Miocene carbonates at depths of more than 800 m capped by late Miocene clays.

The Cochin-1 well in the southern part of the Kerala Basin targeted a Cenozoic fault closure but there were no hydrocarbon shows (Mitra et al. 1983).

CO2 storage potential

Onshore, Cenozoic cover deposited on Precambrian basement is generally less than 300 m thick (Bose et al. 1980) and therefore unsuitable for CO2 storage.

Poor porosity in wells drilled in the Kasargod and Karwar areas, due to cementation and dolomitisation (Sharma et al. 1986), may rule them out as reservoirs for CO2 storage. However, there might be opportunities in the sandstones identified in some of the other wells.

The Late Miocene-Recent section consists mainly of clays and shales in the deeper parts of the basin, and appears likely to form an excellent cap rock.

In general, opportunities to store CO2 in the offshore Konkan-Kerala basin appear to be limited.

References

Desikachar, S.V. 1980. Geology and hydrocarbon prospects of the Kerala west coast basin. Bulletin ONGC, 17(1), June 1980, 25-34.

Ministry of Petroleum and Natural Gas 1991. India: Opportunities for oil and natural gas exploration. Ministry of Petroleum and Natural Gas, Government of India.

Mitra, P., Zutshi, P.L., Chourasia, R.A., Chugh, M.L., Ananthanarayanan, S. & Shukla, B. 1983. Exploration in western offshore basins. In: L.L. Bhandari, B.S. Venatachala, R. Kumar, S.N. Swamy, P. Garga & D.C. Srinastava (editors), Petroliferous basins of India. Petroleum Asia Journal, November 1983, pp15-24.

Singh, N.K. & Lal, N.K. 1993. Geology and petroleum prospects of Konkan-Kerala basin. In: Biswas, S.K., Dave, A, Garg, P., Pandey, J, Maithani, A., Thomas, N. J. (editors), Proceedings of the second seminar on Petroliferous basins of India, Vol. 2, India Petroleum Publishers, Dehra Dun, India, pp461-467.

THE KRISHNA-GODAVARI BASIN

Introduction

Figure A3. 26 Location of the Krishna-Godavari Basin

The Krishna-Godavari Basin is located on the east coast of the Indian peninsula (Figure A3.26). It is named after the two major river systems, the Krishna and Godavari systems, which drain through the basin, across a deltaic plain into the Bay of Bengal. The basin covers an area of approximately 45,000 km2, of which about 20,000 km2 lies onshore and about 25,000 km2 offshore down to the 200 m isobath. Itis one of India’s most prolific hydrocarbon-producing basins: it is now clear that hydrocarbon prospectivity extends well below the 200 m isobath, into deep water in the Bay of Bengal, where a major gas discovery has recently been made (Gupta 2006).

The Krishna-Godavari Basin overlies the SE end of the Prahnita-Godavari Graben, a Gondwana graben filled with ?latest Carboniferous to Early Permian strata. Exposures of Precambrian rocks limit the basin to the south, west and northwest.

Structure

The Krishna-Godavari Basin was formed along the eastern passive, divergent, margin of the Indian craton when India split away from Australia and Antarctica in Early Cretaceous times. Structurally, the Basin consists of a series of en-echelon horsts and graben which divide it into a number of smaller sub-basins (Majumdar et al., 1995).

The Bapatla and Tanuku Ridges divide the onshore part of the basin into three sub-basins - the Krishna,West Godavari and East Godavari sub-basins (Figure A3.27). These are described in more detail below:

Figure A3.27 Map showing the sub-basins and horsts in the onshore and nearshore part of the Krishna-Godavari Basin (adapted from Ministry of Petroleum and Natural Gas 1991)

The Krishna sub-basin

The Krishna sub-basin is the most marginal (westernmost) part of the basin. It is in faulted contact with the surrounding Archean basement to the west. It contains predominantly Cretaceous and older strata.

The Bapatla ridge

The Bapatla ridge lies on the eastern side of the Krishna sub-basin. It extends in a NE-SW direction from onshore into the offshore. The depth to basement over the crest of the ridge is typically about 200 m, increasing to approximately 500 m in the southwest, and therefore probably too shallow for significant CO2 storage. A series of faults lie on the south-eastern margin of the ridge, marking its boundary with the West Godavari sub-basin. Upper Gondwana sedimentary rocks with a thin covering of Miocene-Pliocene strata overlie basement on the ridge.

The West Godavari sub-basin

The West Godavari sub-basin consists of the Kaza-Kaikaluru horst, which remained uplifted during the early Cretaceous, and the Gudivada and Bantumilli grabens. The offshore part of the sub-basin is divided into three separate areas by two NW-SE cross-trends extending from onshore, (Chintalapudi and Avanigadda; Murthy et al. 1995). It is also characterized by a series of NE-SW-trending growth faults and associated Neogene rollover anticlines.

The Tanuku ridge

The Tanuku ridge separates the East and West Godavari sub-basins. Up to 2 km of sedimentary cover is present on top of the ridge (Verma et al. 1993), so it is deep enough for CO2 storage if suitable reservoirs and seals are present.

The East Godavari sub-basin

The East Godavari sub-basin is filled by 2900-5000 m of sedimentary rocks. It contains en echelon faults formed during the Late Cretaceous-early Palaeocene (Rao, 2001). The onshore part of the sub-basin lies beneath the delta formed by the Godavari River and contains small sub-basins and basement highs (Verma et al. 1993).

5.4.2 Hydrocarbons

Hydrocarbons were first discovered in the Krishna-Godavari Basin in 1978 when an onshore well in the Upper Cretaceous Naraspur structure in the East Godavari sub-basin (Rao 2001) produced gas at 4035 m (Venkatarengan & Ray 1993).

The first offshore well, G-1-1, discovered oil and gas in Pliocene sandstone reservoirs. Since then accumulations of hydrocarbons have been discovered in Permian to Pliocene reservoirs (Gupta 2006). Major fields include the highly productive (offshore) Ravva oilfield.

Reliance has recently made a major gas discovery in deep water off the Krishna-Godavari basin.

Reservoirs and seals

The Mandepeta and Golapalli formations contain excellent sandstone reservoir rocks.

The Early Cretaceous Gollapalli Sandstone is locally sealed by clays (red beds) and more generally by the overlying Raghavapuram Shale, which is a regional seal (Rao, 2001).

The Krishna Formation and sandstone layers within the Kaikalur Claystone of Early/Late Cretaceous age have reservoir potential (Rao 2001). In the East Godavari sub-basin, there are Cretaceous reservoirs in the Parsarlapudi Formation and the Razole Volcanics (Venkatarengan & Ray 1993). There is also excellent potential offshore, as exemplified by the oil and gas discoveries there.

CO2 Storage Potential

The Krishna-Godavari basin has excellent CO2 storage potential both onshore and offshore, as the numerous hydrocarbon fields indicate the presence of traps that can retain buoyant fluids at several stratigraphic levels.

References

Gupta, S.K. 2006. Basin architecture and petroleum system of Krishna Godavari Basin, east coast of India. The Leading Edge, 25(7), 830-837.

Majumdar, S. K., Basu, B., Shivasankar, J., Arunachalam, A. & Rangaraju, M. K. 1995. Palakollu-Pasarlapudi Petroleum System, Krishna-Godavari Basin, India. Proceedings of PETROTECH-95, New Delhi Technology Trends in Petroleum Industry.

Murthy, K.S.R., Subrahmanyam, A.S., Lakshminarayana, S., Chandrasekhar, D.V. & Rao, T.C.S. 1995. Some geodynamic aspects of the Krishna-Godavari basin, east coast of India. Continental Shelf Research, 15(7), 779-788.

Prabakaran. S. and Ramesh, P. 1995. Basin Evolution, Stratigraphy and Depositional Systems in Krishna-Godavari Basin India. Proceedings of PETROTECH-95, New Delhi Technology Trends in Petroleum Industry, p229-249

Rao, G.N. 2001. Sedimentation, Stratigraphy, and Petroleum Potential of Krishna-Godavari Basin, East Coast of India. Bulletin American Association of Petroleum Geologists, 85(9), 1623-1643.

Venkatarengan, R. & Ray, D. 1993. Geology and Petroleum Systems, Krishna-Godavari Basin. In: Biswas, S.K., Dave, A, Garg, P., Pandey, J, Maithani, A., Thomas, N. J. (editors), Proceedings of the second seminar on Petroliferous basins of India, Vol. 1, Indian Petroleum Publishers, Dehra Dun, India, p331-353.

Verma, R.K., Satya Narayana, Y. & Chander Sekhar Rao, S. 1993. Gravity Field, Tectonics and Evolution of Krishna-Godavari and Cauvery Basins of India. Indian Journal of Petroleum Geology, 2(2), 39-72.

THE KUTCH BASIN

Introduction

The Kutch Basin (also known as the Kachchh Basin) is a Mesozoic rift basin on the western margin of the Indian craton (Figure A3.28) that is overlain by approximately 900 m of Cenozoic sedimentary rocks. Covering an area of around 71,000 km2 (Ministry of Petroleum and Natural Gas 1991, Biswas 1982), the Kutch Basin comprises a series of fault blocks and half graben bounded by steep faults that follow Precambrian trends (Biswas 1982, 1987).

Figure A3.28 Location of the Kutch Basin

The basin contains over 3000 m of Mesozoic sedimentary rocks overlain by up to 900 m of Cenozoic sediments (Biswas 1991). Deccan Trap basalts cover the Mesozoic strata in the south of the Kutch Basin (Biswas & Deshpande 1973) and the Mesozoic strata in the basin are highly folded, faulted and intruded by igneous rocks (Biswas 1982).

Structure

To the NE, the basin is bounded by the margin of the Indian shield, to the SE it is bounded by the Kathiawar horst block and Saurashtra arch and to the North it is bounded by the Nagar-Parkar ridge (Biswas 1987). It is influenced by the NE-SW Precambrian Delhi-Aravalli faulting trends (Ministry of Petroleum and Natural Gas 1991). Passive basement ridges parallel to Precambrian faults were present during Mesozoic deposition and the faults were later reactivated during Cenozoic uplift (Biswas 1991). The Kutch offshore extension is a gently sloping platform with two regional highs; an extension of the E-W Kutch Mainland Uplift and a NW-SE trending high that follows the Dharwar trend. Mesozoic sediments are exposed in the northern “Island Belt” (Mitra et al. 1983).

Major unconformities in sequences of the Upper Palaeocene, post-Lower Eocene (Ypresian), Upper Eocene, post-Oligocene, Upper Miocene and Early Quaternary indicate relatively recent tectonic movements (Biswas & Deshpande 1983, Biswas 1982).

Hydrocarbons

Five onshore wells and 13 offshore wells have revealed an offshore non-commercial gas accumulation and a few offshore oil shows and onshore gas shows.

Offshore, over 2000m of coarse-grained Upper Palaeocene to Middle Miocene limestones were encountered in a well drilled in a large anticlinal closure. Gas and occasional oil shows were encountered in the Miocene section, with scattered oil shows and infrequent gas shows encountered in the underlying Eocene. The Miocene reservoirs appear to have been flushed (Mitra et al. 1983). Eocene lowstand fans and wedges have been identified on seismic as potential targets for hydrocarbon exploration (Dwivedi et al., 1995).

CO2 storage potential

Over 900 m of Cenozoic sediments are underlain by more than 3000 m of Mesozoic strata (Biswas, 1991).

The Kutch basin is divided into three provinces:

  • Kutch Mainland, near the basin depocentre
  • Pacham Island (where deposition apparently ceased after the Mid-Callovian)
  • Eastern Kutch

In the Kutch Mainland, the Upper Jurassic top Jhuran sandstones are potential reservoir rocks and buried to depths of around 800-1295 m (Biswas 1991). Therefore they are potentially suitable for CO2 storage.

In the Pacham Island area, Mesozoic cover is too thin (<621 m, Biswas 1991) to be of interest for CO2 storage.

In eastern Kutch, sands of the Jurassic Lower Khadir Formation are of sufficient depth (around 990 m - Biswas 1991) to be considered for CO2 storage and they are capped by shales.

In summary, there is likely to be some potential for CO2 storage in the Kutch basin but further study is required to firm it up.

References

Biswas, S.K. 1982. Rift basin in western margin of India with special reference to Kutch basin and its hydrocarbon prospects. Bulletin American Association of Petroleum Geologists, 66(10), 1497-1513.

Biswas, S. K. 1987. Regional tectonic framework, structure and evolution of the western marginal basins of India. Tectonophysics, 135, 307-327.

Biswas, S.K. 1991. Stratigraphy and sedimentary evolution of the Mesozoic basin of Kutch, western India. In: Tandon, S.K., Pant, C.C. & Casshyap, S.M. (editors), Sedimentary basins of India: Tectonic Context. Gyanodaya Prakashan, Nainital, India, 74-103.

Biswas, S.K. & Deshpande, S.V. 1983. Geology and hydrocarbon prospects of Kutch, Saurashtra and Narmada basins. In: L.L. Bhandari, B.S. Venatachala, R. Kumar, S.N. Swamy, P. Garga & D C Srinastava (editors), Petroliferous basins of India. Petroleum Asia Journal, November 1983, 111-126.

Das, B. & Patel, N.P. 1984. Nature of Narmada-Son lineament. Journal Geological Society India, 25(5), 267-276.

Dwivedi, A.K., Thakur, R.K., Bajpai, A.K., Lal, N.K., Sarkar, S. & Srivastava, H.C. 1995. Sequence stratigraphy and systems tracts of Eocene and Miocene sediments in Kutch offshore, India. Proceedings PETROTECH-95, Technology Trends in Petroleum Industry, pp197-206.

Ministry of Petroleum and Natural Gas 1991. India: Opportunities for oil and natural gas exploration. Ministry of Petroleum and Natural Gas, Government of India.

Mitra, P., Zutshi, P.L., Chourasia, R.A., Chugh, M.L., Ananthanarayanan, S. & Shukla, B. 1983. Exploration in western offshore basins. In: L.L. Bhandari, B.S. Venatachala, R. Kumar, S.N. Swamy, P. Garga & D.C. Srinastava (editors), Petroliferous basins of India. Petroleum Asia Journal, November 1983, pp15-24.

Roday, P.R. & Singh, A.K. 1982. Great Boundary Fault: age, kinematic development model and rejuvenative episodes. (Abstract) Seminar on Indian lithosphere: Structure and evolution, Poona Univ., Poona, pp22-23.

THE LOWER INDUS BASIN

 

The Lower Indus Basin (Pakistan) covers an area of about 400,000 km2. It contains several oil and gas discoveries, the largest of which is the Sui gas field (discovered in 1952, with estimated initial recoverable reserves of 8.624 tcf gas).

The basin lies on the western margin of the Indian Plate and deepens steeply to the west. Cross sections of the basin are shown in Kadri (1995). Its eastern margin is formed by the Punjab Shelf and Thar Platform, which are separated by the Jocobabad and Mari-Kandkhot Highs that lie partly in India. The central deepest part of the basin is known as the Sulaiman Depression in the northern part of the basin and the Karachi Trough in the south. The northern and central parts of its western margin are marked by the thrust faults of the Sulaiman and Kirthar fold belts. To the south, the basin extends offshore.

The Thar Platform contains well developed Early to Middle Cretaceous sands that form the reservoirs of all the gas fields in this region. The Punjab Shelf contains some major stratigraphic pinchouts. The Sulaiman depression contains some buried anticlines. The Karachi Trough, which opens up into the Arabian Sea, contains large numbers of anticlines, some of which form gas fields.

A summary of the characteristics of the reservoirs in the basin is given in Kadri (1995).

CO2 storage potential

It is clear that there is significant CO2 storage potential in several parts of the Lower Indus Basin, both in the major gas fields (when depleted) and in aquifers. However, its aquifers support a dense population heavily reliant on agriculture. Therefore there are likely to be conflicts of interest with any proposed CO2 storage.

References

Kadri, I.B. 1995. Petroleum Geology of Pakistan. Pakistan Petroleum Ltd, Karachi, 275 pp.

THE MAHANADI BASIN

 

The Mahanadi Basin (Figure A3.29) developed along the eastern coast of India as a result of the separation of the Indian plate from Antarctica and Australia during Cretaceous times. It lies immediately south of the Bengal Basin and its south-western limit is marked by the prominent 85° East Ridge. The thickest sedimentary succession occurs in the northern part of the area shaded on Figure A3.29.

Figure A3.29 Location of the Mahanadi Basin

The basin as a whole is developed at the junction between the NE-SW-trending coast (a passive continental margin), and the northwest-southeast trending Mahanadi Graben within the Indian shield (Fuloria 1993). The Mahanadi Graben is a Permian/Mesozoic (Gondwana) structural feature.

Structure

The basin is characterised by numerous coast-parallel faults, cross-cut by a few NNW-SSE-trending faults that divide the basin into blocks. The northernmost cross-cutting fault marks the boundary between the offshore Mahanadi Basin and the Bengal Basin. Sinistral strike-slip displacement on this fault totals around 60 km.

Basin Evolution

The first occurrence of rifting, accompanied by subsidence of the Precambrian basement, may have been during Late Jurassic times, although the oldest rocks within the basin are Early Cretaceous volcanics (Fuloria 1993). During Late Cretaceous times, thick clastic sediments were deposited in the fault-controlled depressions in the offshore part of the basin, but virtually no sedimentation occurred onshore.

Early Palaeocene times were marked by a gentle tilting of the offshore basin towards the southeast. Deposition occurred in the offshore basin, but in the onshore basin there is no evidence of sedimentation during the entire Palaeocene-Eocene period (Fuloria 1993).

Upper Eocene to Oligocene strata are absent from all wells and are not encountered anywhere in the Mahanadi Basin (Fuloria, 1993). This is in contrast to the adjacent Bengal Basin, where extensive sedimentation occurred in Upper Eocene to Oligocene times.

Regional subsidence restarted in Miocene times, with evidence of marine transgressions in both the offshore and onshore areas. A high subsidence rate during Middle Miocene times coincided with the rapid uplift of the Himalayas to the north (Fuloria 1993). Since then, subsidence and sedimentation in the onshore and offshore Mahanadi Basin areas has continued almost uninterrupted, although there have been significant fluctuations in the rate of sedimentation.

A stratigraphic breakdown of some of the wells in the Mahanadi basin is given in Fuloria (1993).

Hydrocarbons

Recently there have been potentially significant gas discoveries in the Upper Miocene offshore NE of the Mahanadi Basin, see http://www.dghindia.org/site/pdfattachments/e_p_reports_2005_06.pdf.

Reservoir rocks and seals

Good reservoir rocks exist in the Miocene and older sediments of the offshore shelf zone of the basin. Palaeogene sandstones have good porosities and permeabilities, and some of the carbonates have porosities of about 15%.

As most of the Miocene section is composed of claystones, potentially it could be a good regional cap-rock for hydrocarbon accumulation and CO2 storage.

Good Early Cretaceous sandstone reservoir rocks are present in parts of the onshore basin, with porosities ranging from 15-25%. These reservoirs are effectively capped by both the Mio-Pliocene section and by the upper part of the Early Cretaceous section (Fuloria 1993) and so may have CO2 storage potential.

Summary of CO2 Storage Potential

Good potential probably exists in offshore as shown by the recent gas discoveries on the NE boundary of the basin, where it adjoins the Bengal Basin. The onshore basin could have some CO2 storage potential, but the lack of hydrocarbon discoveries means that the potential in this area is classified as only fair.

References

Fuloria, R.C. 1993. ‘Geology and Hydrocarbon Prospects of Mahanadi Basin, India.’ In: Biswas, S.K., Dave, A, Garg, P., Pandey, J, Maithani, A., Thomas, N. J. (eds.), Proceedings of the Second Seminar on Petroliferous Basins of India, Vol.1, Indian Petroleum Publishers, Dehra Dun, India, pp. 355-370.

THE MUMBAI BASIN

Introduction

The Mumbai Basin (Figure A3.30) is a Cenozoic sedimentary basin located off the west coast of India. It covers an area of around 120,000 km2 up to the 200 m isobath, beyond which there has not yet been any drilling (Ministry of Petroleum and Natural Gas 1991). It lies beneath the widest part of the Indian continental shelf (at around 300 km), which narrows to the north and south to around 60 km (Mitra et al., 1983).

It contains the giant Bombay High oil field and numerous smaller fields.

Figure A3.0 Location of the Mumbai Basin

The basin is bounded to the east by the coastal outcrops of the Deccan Traps and to the north by the Saurashtra Basin. Its southern limit is marked by the Vengural arch which separates it from the Konkan-Kerala basin (Ministry of Petroleum and Natural Gas 1991).

Structure

The thickness of Cenozoic sedimentary rocks offshore is around 1800-2000 m on the Bombay High and exceeds 5000 m in the deepest parts of the Surat Depression (Bhandari & Jain 1984).

Basin development was initiated by fault movement during the latest Upper Cretaceous or early Palaeocene (Sahay 1984). Two major structural episodes have been identified, the first resulting in the development of NNW-SSE-trending structures and the second in later east-west structures (Sahay 1984).

The Bombay High oilfield is a NNW to SSE-trending, doubly plunging anticline with a faulted eastern limb. The anticline is about 65 km long, 23 km wide and covers an area of about 1500 km2 (Rao & Talukdar 1980).

Stratigraphy

The stratigraphy of the Mumbai Basin is summarised in Figure A3.31.

Figure A3.31 Summary stratigraphy of the Mumbai Basin (adapted from Mathur & Nair 1993, Basu et al. 1982 and Biswas 1993)

Generally, Cenozoic sedimentary rocks rest on Deccan Trap basalts, which were probably erupted over a limited period across the Cretaceous-Tertiary boundary, from about 63-66 Ma (Rathore et al. 1997). However, beneath parts of the Bombay High field the basement is formed by Precambrian quartzite, granitic gneiss and schist, and the Deccan Trap is absent.

The oldest Cenozoic strata are Palaeocene to early Eocene basal clastics (Panna, and Vasai formations). These are unconformably overlain by thick middle Eocene limestones (the Bassein Formation). The Bassein Formation was deposited basinwide with the exception of the part of the Bombay High. It is overlain by Upper Eocene to early Oligocene marine limestones with thin shale intervals (the Heera/Mahuva and Mukta formations) and, in the Surat Depression only, by deltaic Oligocene sands and shales (Mathur & Nair, 1993).

Unconformably deposited on these strata is a thick Early to Middle Miocene limestone and shale sequence. The Alibag and Saurashtra Formations are mainly shale with minor limestones, the Ratnagiri Formation is mainly limestone. These formations are followed, often unconformably, by upper Miocene to Pliocene claystones and shales (Tapti/Taraupur/Bandra Formations) (Sahay 1984, Basu et al. 1982).

Hydrocarbons

The Mumbai Basin produced over 60% of the total crude production in India in 1991, the vast majority of which came from the Bombay High field. The Bombay High field is reported to have ultimately recoverable reserves of 4 billion barrels of oil and 7.4 tcf gas according to http://www.hubbertpeak.com/laherrere/GPPI200701.pdf.

Reservoir rocks

In the Bombay High field, oil is produced from lower-middle Miocene limestones and the Bassein Formation (Ministry of Petroleum and Natural Gas 1991, Mitra et al. 1983).

Smaller reservoir intervals are also found in the Middle Miocene L-II carbonate, the S-1 (sandstone) gas pay, and, in the Bombay High, Bombay High East, Ratna and B-57 hydrocarbon fields, the Palaeocene to Lower Eocene basal sand horizon (Mitra et al. 1983). The basal sand sequence is composed of Deccan Trap wash, fluvio-deltaic sand, shale, silt alternating with local marine tongues in the Ratnagiri and south Saurashtra area. Deposition appears to have been fault-controlled (Mitra et al. 1983). Thickness varies from 0-2400 m across the basin (Mishra et al. 1997).

Cap rocks

Post-Miocene shales are expected to form an effective caprock over the entire basin except for the Ratnagiri block, where they are absent (Rao & Talukdar 1980).

Mumbai High Field

The Bombay High field is divided into three main blocks by NE to ENE-WSW-trending faults. The three blocks have oil-water contacts at different depths. All the blocks have a gas cap. The gas cap is at the same depth in the middle and southern blocks (Rao & Talukdar 1980), which therefore probably have a degree of connectivity. The northern block is believed to contain more than half the oil reserves of the entire Mumbai Basin (Rao & Talukdar 1980).

The Bombay High reservoirs are the L-III (Early Miocene), L-II (Middle Miocene), S-1 gas sands (Middle Miocene) and Palaeocene to Early Eocene basal sands (Mitra et al., 1983). The top of the youngest reservoir (L-II) is at around 1100 m.

The top of the main reservoir, L-III is at around 1400 m (Roychoudhury & Deshpande, 1982; Biswas, 1993). It consists of fine-grained bioclastic limestone. It has largely secondary porosity of 0-25% (Roychouldhury & Deshpande, 1982).

Hardas et al. (1989) studied samples of the Panna Formation sandstones (Palaeocene-Early Eocene age) which are a secondary reservoir. They consist of coarse-fine grained and poorly sorted sands with authigenic cements. They can have good primary porosity where it has not been destroyed during diagenesis and good secondary porosity due to dissolution of primary and authigenic minerals, removal of matrix and cement and minor fractures.

Overpressure

High pressures occur in the deeper parts of the Mumbai Basin. They are encountered in Palaeogene to Early Miocene strata in the Saurashtra area, Palaeogene to Early Oligocene strata in the Daman-Tapti area and Palaeocene to Eocene strata in the central graben area (Porwal et al., 1994). They are believed to result from undercompaction due to high sedimentation rates.

CO2 storage potential

The majority of reservoirs in this region are carbonates, so CO2/water/rock reactions may be important. Many, such as those in the Bassein area, are deeply buried, e.g. the top reservoir horizon was encountered at 2295 m in well Bassein-1 (Roychoudhury & Deshpande, 1982). Porosity is variable, commonly ranging from 0-30% in an individual formation. Primary porosity is often only a few percent and secondary porosity is more important (Roychoudhury & Deshpande, 1982).

The post-Miocene shales form a regional cap rock over the whole Mumbai Offshore, except for the Ratnagiri Block.

The Mumbai offshore is a huge area which appears to have good potential for CO2 storage. However, more detailed study is required to determine the most favourable sites: reservoir porosity variation in particular should be considered. Areas of overpressure may have to be avoided if CO2 injection would raise the reservoir pore fluid pressure above acceptable limits.

References

Basu, D.N, Banerjee, A. & Tamhane, D.M. 1982. Facies distribution and petroleum geology of the Bombay offshore basin, India. Journal Petroleum Geology, 5(1), pp51-75

Bhandari, L.L. & Jain, S.K. 1984. Reservoir geology and its role in the development of the L-III reservoir, Bombay High field, India. Journal of Petroleum Geology, 7(1), 27-46.

Biswas, S. K. 1987. Regional tectonic framework, structure and evolution of the western marginal basins of India. Tectonophysics, 135, 307-327.

Biswas, S.K. 1993. Geology of Bombay offshore shelf and hydrocarbon occurrences. Indian Journal of Geology, 65(4), 215-245.

Hardas, M.G., Sharma, S. & Das, K.K. 1989. Diagenesis and secondary porosity: a preliminary appraisal of Tertiary sandstones from Indian sedimentary basins. Bulletin ONGC, 26(1), 31-52.

Mathur, R.B. & Nair, K.M. 1993. Exploration of Bombay offshore basin. In: Biswas, S.K., Dave,

A, Garg, P., Pandey, J, Maithani, A., Thomas, N. J. (editors), Proceedings Second Seminar on Petroliferous basins of India, Vol 2, Indian Petroleum Publishers, Dehra Dun, India, pp365-396.

Ministry of Petroleum and Natural Gas 1991. India: Opportunities for oil and natural gas exploration. Ministry of Petroleum and Natural Gas, Government of India.

Mishra, Y.K., Parida, G. & Ramani, K.K.V. 1997. Stratigraphic-depositional model: an important tool for stratigraphic trap exploration of basal clastic unit in Bombay offshore basin. Proceedings Second International Petroleum Conference and Exhibition PETROTECH-97, New Delhi, pp. 463-474.

Mitra, P., Zutshi, P.L., Chourasia, R.A., Chugh, M.L., Ananthanarayanan, S. & Shukla, B. 1983. Exploration in western offshore basins. In: L.L. Bhandari, B.S. Venatachala, R. Kumar, S.N. Swamy, P. Garga & D.C. Srinastava (editors), Petroliferous basins of India. Petroleum Asia Journal, November 1983, pp15-24.

Mitra, D.S., Bhoi, R. & Agarwal, R.P. 1993. Hydrocarbon exploration in Shargarh and Myajlar subbasins of Jaisalmer Basin, Rajasthan, India using remote sensing techniques. Indian Journal Petroleum Geology, 2(1), 31-42.

Ministry of Petroleum and Natural Gas 1991. India: Opportunities for oil and natural gas exploration. Ministry of Petroleum and Natural Gas, Government of India.

Rao, R.P. & Talukdar, S.N. 1980. Petroleum geology Bombay and high field, India. In: M T Halbouty (editor) Giant oil and gas fields of the decade 1968-1978. American Association Petroleum Geologists’ Memoir, 30, 487-506.

Rathore, S.S. , Vijan, A.R., Prabhu, B.N. & Misra, K.N.K. 1997. Ar-dating of basement rocks of Bombay Offshore basin. Proceedings Second International Petroleum Conference and Exhibition PETROTECH-97, New Delhi, pp583-588.

Roychoudhury, S.C. & Deshpande, S.V. 1982. Regional distribution of carbonate facies, Bombay Offshore Region, India. Bulletin American Association of Petroleum Geologists, 66(10), 1483-1496.

Sahay, B. 1984. A review of the geology and petroleum possibilities of the continental margins of India. Offshore Technology conference 4699, 16th conference May 1984, pp 451-464.

THE NARMADA BASIN

Introduction

The Narmada graben is an ENE-WSW trending depression in the northwest of India. It is bounded by a series of sub-parallel wrench faults that define the Narmada-Son lineament (or geofracture). This is a deep fracture that extends into the Moho at a depth of 35-40 km (Biswas 1987, Kaila et al. 1981, 1985). The Narmada basin (Figure A3.32) is largely confined to the narrow ENE-WSW trending Narmada graben, which is bounded to the north and south by faults, though it opens out at its western end (Biswas & Deshpande 1983).

Figure A3.32 Location of the Narmada Basin

Structure

The major part of the basin lies in a graben along the course of the Narmada-Son lineament. The Narmada-Son lineament forms a tectonic boundary between the shallow marine Late Proterozoic-Palaeozoic Vindhyan strata in the north and transitional Gondwana deposits in the south (Kaila et al. 1981, 1985). This region of India has a complex tectonic history of reactivation of Pre-Cambrian structure. During Early Cretaceous times, reactivation resulted in rifting along the Narmada geofracture with the opening of a basin at its western end (Kaila et al. 1981, 1985; Biswas, 1987). The Narmada rift further opened and received marine sediments during the Late Cretaceous (Biswas 1987). Uplift of the Saurashtra arch to the northwest of the Narmada basin appears to have terminated Cretaceous sedimentation (Biswas 1987).

Deccan Trap basalts of late Cretaceous-early Cenozoic age overlie the Cretaceous sediments. A Cenozoic depocentre (Broach sub-depression) formed where the Narmada rift intersects the Cambay rift (Kaila et al. 1981, Biswas 1987).

Stratigraphy

Cretaceous subsidence in the Narmada basin was restricted to the western part of the rift zone within an embayment widening and deepening towards the west. Maximum subsidence of the basin before deposition of the Deccan Trap basalts was around 1700 m, centred where the central Narmada graben meets the Godavari graben (Biswas, 1987).

Cretaceous sediments were generally deposited directly on Precambrian basement (Figure A3.33). Early Cretaceous fluvio-deltaic deposits (over 1800 m) are present in the west part of Narmada basin (Biswas, 1987). The Lower Cretaceous Nimar Group consists of the rough cross-bedded fluvial Nimar sandstones (with some tabular cross-bedding and deltaic and marine influence in the west where the sandstone is also known as the Songir/Himmatnagar Group) followed by the Uchad/Umrali flagstone in the central and western parts of the basin (Biswas & Deshpande, 1983). The Nimar group gradually thickens towards the west from around 15-30 m to over 150 m (Biswas & Deshpande, 1983). Fluvial fans either side of the graben in the Early Cretaceous contributed to the Nimar Group. The Himmatnagar sandstone appears to indicate the basin opened out to the west (Biswas & Deshpande, 1983).

The Bagh Group (Navagam in western part) consist of nodular limestone (argillaceous, thin bedded becoming less nodular and more shaly westwards), followed by coralline limestone (thick bedded, hard, crystalline, fossiliferous and coarse grained, followed by the Lameta Formation (thick bedded limestone, variable grain size, typically cherty) (Biswas & Deshpande, 1983). The nodular limestones represent the greatest sea depth and the following higher energy environment Coralline limestone represents regression of the sea to intertidal conditions. Further regression resulted in increased clastic input to the Lameta Formation (Biswas & Deshpande, 1983). Part of the Lameta limestone appears to have been deposited where the basin opened out westwards (Biswas & Deshpande, 1983).

Figure A3.33 Stratigraphic summary for the Narmada Basin (after Biswas & Deshpande 1982, Ganjoo 1995, Biswas 1987, Mitra et al. 1983)

Hydrocarbons

No hydrocarbons have yet been found in the Narmada Basin.

CO2 storage potential

In the Narmada basin, over 900 m Deccan Trap covers thin Cretaceous sediments deposited unconformably on pre-Mesozoic sands and igneous basement (Biswas, 1987). The Bagh Formation could potentially store CO2, below the Deccan Trap basalt. However the necessity of drilling through the large thickness of the Deccan Trap may well make the Narmada Basin unfavourable for CO2 storage and at present its potential is considered limited.

References

Biswas, S. K. 1987. Regional tectonic framework, structure and evolution of the western marginal basins of India. Tectonophysics, 135, 307-327.

Biswas, S.K. & Deshpande, S.V. 1983. Geology and hydrocarbon prospects of Kutch, Saurashtra and Narmada basins. In: L.L. Bhandari, B.S. Venatachala, R. Kumar, S.N. Swamy, P. Garga & D C Srinastava (editors), Petroliferous basins of India. Petroleum Asia Journal, November 1983, 111-126.

Kaila, K.L., Krishna, V.G. & Mall, D.M. 1981. Crustal structure along Mehmadabad-Billimora profile in the Cambay basin, India, from deep seismic soundings. Tectonophysics, 76, 99-130.

Kaila, K.L., Reddy, P.R., Dixit, M.M., & Koteswara Rao, P. 1985. Crustal structure across the Narmada-Son lineaments, central India, from deep seismic soundings. Journal Geological Society India, 26(7), 465-486.

THE POTWAR BASIN

 

The Potwar Basin, sometimes known as the Kohat-Potwar or Upper Indus Basin, covers an area of about 40,000 km2. It is bounded to the north and west by the Main Boundary Thrust – the southernmost of the major Himalayan thrusts. It is separated from the Lower Indus Basin to the south by the Salt Range and Sargodha High. It is bounded to the west by the Kurram Fault and to the east by the Jhelum Fault (Kadri 1995, Wandrey et al. 2004).

A map showing the locations of the 18 oil and 3 gas fields in the basin is given in Wandrey et al. 2004, Figure 13). Production started in 1914 from the Khaur field. Oil and gas production occurs from a stratigraphically wide range of reservoirs. A summary of the characteristics of the reservoirs in the basin is given in Kadri (1995). Reservoir rocks include Miocene alluvial sandstones, Paleogene shelf carbonates, Jurassic and Permian continental sandstones, and Cambrian alluvial and shoreface sandstones. Approximately 60% of the reservoirs are carbonates, in which production may be largely from fractures. The sandstone reservoirs have porosities ranging from 5 to 30%, averaging between 12 and 16%. Sandstone reservoir permeability ranges from 1 to >300 mD and averages 4 to 17 mD (Wandrey et al. 2004).

CO2 storage potential

The better sandstone oil and gas reservoirs are likely to have some potential for CO2 storage. Seals include fault truncations and interbedded shales and the thick shales and clays of the Miocene and Pliocene Siwalik Group. In terms of aquifers, the Siwalik Group sandstone reservoirs may have significant storage potential, as should the aquifer portions of the better oil and gas field reservoir sandstones. Consequently the basin is classified as having good CO2 storage potential.

References

Kadri, I.B. 1995. Petroleum Geology of Pakistan. Pakistan Petroleum Ltd, Karachi, 275 pp.

Khan, M.A., Ahmed, R., Raza, H.A., and Kemal, A., 1986, Geology of petroleum in KohatPotwar Depression, Pakistan: American Association of Petroleum Geologists Bulletin, 70(4), 396 – 414.

Wandrey, C.J., Law, B.E. & Shah, S.H.A., 2004. Patala-Nammal Composite Total Petroleum System, Kohat-Potwar Geologic Province, Pakistan. In: Wandrey, C.J. (ed.), Petroleum Systems and Related Geologic Studies in Region 8, South Asia. USGS, 1-19.

THE PUNJAB SHELF

Introduction

Evidence from wells and seismic surveys indicates that the basement surface beneath the Cainozoic strata of the Punjab Shelf dips gently northwards to a depth of at least 4.5 km adjacent in the region of Dasuya in the Himalayan foothills.

Wells

The southern Zira well near Ferozepur proved an approximate 700 m thick Upper and Middle Siwalik succession beneath which it encountered granitic basement rocks (Rao, 1973; Parkash & Kumar, 1991).

The Adampur well near Jullander proved the presence of Lower Siwalik sediments before entering basement at a depth of 2513 m.

The Hashairpur well, drilled to a depth of 3439 m, proved Upper and Middle Siwalik sediments before reaching TD in the Lower Siwalik Group as a result of drilling difficulties (Rao, 1973; Parkash & Kumar, 1991).

The Adampur and Hoshairpur wells may be located on NW-SE trending shallow highs in the basement that die out to the NW around Gurudaspur (Rao, 1973).

North-eastwards from Dasuya, the basement surface continues to deepen and Cenozoic sediments thicken, as indicated by the Janauri &num;1 and &num;2 wells (the latter drilled to over 5 km), which tested the Januari Anticline in the foothills (Rao, 1973). A thick section of Siwalik Group sediments was proved (4790 m) beneath which marble assigned to the basement was encountered.

Folding of the sequence becomes more apparent to the NE up to the Main Boundary Thrust, with the Jawalamukhi and Bahl wells reaching TD before reaching basement (Rao, 1973).

Within the Punjab Shelf, several ridges and depressions are recognised, including:

The Aravalli Horst – extends from Roopnagar on Sutlej to the Sarda River in the SE.

The Dudwa Ridge – E-W trending ridge close to the foothills of Nepal.

CO2 storage potential

The Punjab Shelf is considered to have low CO2 storage potential for the same reasons as the Ganga Basin. It appears to lack consistently developed cap rocks and its aquifers support a dense population heavily reliant on agriculture. Therefore there are likely to be serious conflicts of interest with any proposed CO2 storage.

References

Parkash, B. & Kumar, S. 1991. The Indogangetic Basin. In: Tandon, S.K., Pant, C.C. & Casshyap, S.M. (editors), Sedimentary basins of India: Tectonic Context. Gyanodaya Prakashan, Nainital, India, pp. 147-170.

Rao, 1973. The subsurface geology of the Indogangetic Plains. Journal Geological Society India, 14, 217-242.

THE RAJMAHAL BASIN

 

The Rajmahal Basin is a Gondwana Basin lying immediately to the west of the Rajmahal Traps in northern peninsula India. The Gondwana strata, which include the Permian coal-bearing Barakar Formation, may be present beneath the Rajmahal Trap and are at least patchily developed beneath the western margin of the Bengal Basin. It is possible that they could have some CO2 storage potential beneath the trap but this is far from proven and consequently the basin is classified as have limited potential at present.

References

Mondal, A. 2006. Gondwana Basins in India – Vast Geologic Storage Sites for CO2 Injection. Proceedings of the International Workshop on R&D Challenges in Carbon Capture & Storage Technology for Sustainable Energy Future (IWCCS-07), 12-13 January 2007. National Geophysical Research Institute, Hyderabad.

THE REWA BASIN

 

The Rewa Basin (Figure A3.35) is a Gondwana basin in which sedimentary rocks of Permian-Cretaceous age were deposited on metamorphic basement.

Figure A3.35 Location of the South Rewa Basin

Structure

The Rewa Gondwana basin lies at the northern end of the Son-Mahanadi Graben, which is orientated NNW-SSE, approximately parallel to the Pranhita-Godavari graben, following one of the major Indian Precambrian structural trends (Ghosh 2002). Up to 3.8 km of sedimentary rocks are present in the basin centre (Mondal 2007).

Stratigraphy

The stratigraphic succession (Figure A3.36) is similar to that in the Damodar Valley Gondwana Basins (e.g. Dutta 2002, Shah 2004). However, unlike Damodar Valley or Satpura Basin, the Gondwana sequence of the Rewa Basin is dominated by arenaceous facies. The shale-dominated lower part of the Barren Measures, although locally attaining a thickness of around 100m, is not regionally persistent and hence it can not be considered as cap rock over a large area. Likewise, clay dominated Tiki Formation also has a restricted occurrence in the north-western part of the basin (Mondal 2007.

Figure A3.36 South Rewa Basin stratigraphy, after Singh et al., (2007) and Dutta (2002)

Hydrocarbons

No oil or gas fields or shows have been found in the South Rewa basin.

CO2 Storage Potential

The Coal Measures found on the southern margin of the basin dip towards the basin centre and are buried to significant depths in the basin centre. However, in the absence of suitable cap rocks, this basin is unlikely to provide storage sites, in spite of the presence of reservoir rock over a large area. Consequently it has been classified as having little potential at present.

References

Dutta, P. 2002 Gondwana lithostratigraphy of Peninsular India. Gondwana Research (Gondwana Newsletter Section) 5 (2), 540-553.

Mondal, A. 2006. Gondwana Basins in India – Vast Geologic Storage Sites for CO2 Injection. Proceedings of the International Workshop on R&D Challenges in Carbon Capture & Storage Technology for Sustainable Energy Future (IWCCS-07), 12-13 January 2007. National Geophysical Research Institute, Hyderabad.

Singh, K. J., Goswami, S. and Chandra, S. 2007 Occurrence of cordialities from Lower Gondwana sediments of Ib-River coalfield, Orissa, India: An Indian scenario. Journal of Asian Earth Sciences, 29, 666-684

THE SAURASHTRA BASIN

Introduction

The Saurashtra Basin (Figure A3.37) is a Mesozoic rift basin on the western margin of the Indian Craton on the west coast of India. It covers an area of around 28000 km2 (Sahay 1984, Biswas 1987).

Figure A3.37 Location of the Saurashtra Basin

The Saurashtra Basin is bounded to the north by the Kutch Basin, to the east by the Cambay Basin and to the south by the Surat depression (part of the Mumbai Shelf). To the west it opens out into the Arabian Sea (Biswas & Deshpande 1983).

Structure

The entire area forms a horst block, on which Lower Cretaceous sedimentary rocks are overlain by Deccan Trap basalts and thin Neogene and Quaternary deposits. Deccan Trap basalts are at surface over most of the Saurashtra peninsula (Biswas & Deshpande 1983). Prominent structural ‘noses’ plunging to the NNE are identified in the Cenozoic rocks that overlie the Deccan Trap.

Stratigraphy

Cretaceous sediments on the Saurashtra arch are expected to have a thickness ranging from 2000m on the flanks to 1000m on the crest (Biswas & Deshpande, 1983). Deccan Trap basalt volcanics covered the Saurashtra basin during the Late Cretaceous. The Deccan Trap surface was peneplaned and the south and west coastal margins were covered with marine sediments of the Gaj and Dwaraka Formations during a Neogene transgression (Biswas & Deshpande, 1983).

During the Quaternary, shallow marine sediments were deposited on the coastal margins and subaerial sediments were deposited across the remainder of the basin (Biswas & Deshpande, 1983).

Hydrocarbons

Natural gas was encountered in a borehole drilled at Gogha in 1915 (Johri & Kandpal 1983). In the offshore western part of the Saurashtra arch, a closure in the lower Eocene potentially suitable for hydrocarbon generation and trapping, caused by an older structure has been identified. Other fault closures in the Lower/Middle Eocene have also been mapped (Mitra et al. 1983).

The Cenozoic is too thin to be of interest for hydrocarbon exploration onshore. However, based on the dip of the sediments, offshore Cenozoic thickness could be expected to be much greater (Biswas & Deshpande, 1983). A deep well drilled west of the continental margin encountered over 2000 m of Cenozoic sediments at 2530 m. Palaeocene sediments (which can be seen to pinch out shorewards in seismic sections) would be expected to consist largely of coarse carbonate reservoir or reefal facies deposited along the continental margin. The pinchout may form potential traps (Biswas & Deshpande, 1983).

CO2 storage potential

There is little or no potential onshore but offshore where the sedimentary succession is thicker, there may be limited CO2 storage potential in the Saurashtra Basin.

References

Biswas, S. K. 1987. Regional tectonic framework, structure and evolution of the western marginal basins of India. Tectonophysics, 135, 307-327.

Biswas, S.K. & Deshpande, S.V. 1983. Geology and hydrocarbon prospects of Kutch, Saurashtra and Narmada basins. In: L.L. Bhandari, B.S. Venatachala, R. Kumar, S.N. Swamy, P. Garga & D C Srinastava (editors), Petroliferous basins of India. Petroleum Asia Journal, November 1983, 111-126.

Johri, D.N. & Kandpal, L.D. 1983. Exploration for oil and natural gas in Saurashtra plateau – a geophysical review. Special Publication Geological Survey India, 2, 89-100.

Mitra, P., Zutshi, P.L., Chourasia, R.A., Chugh, M.L., Ananthanarayanan, S. & Shukla, B. 1983. Exploration in western offshore basins. In: L.L. Bhandari, B.S. Venatachala, R. Kumar, S.N. Swamy, P. Garga & D.C. Srinastava (editors), Petroliferous basins of India. Petroleum Asia Journal, November 1983, pp.15-24.

Sahay, B. 1984. A review of the geology and petroleum possibilities of the continental margins of India. Offshore Technology Conference 4699, 16th May 1984, pp 451-464

Singh, B.P., Khan, M.S.R., Goyal, J.P., Dwivedi, P., Sharma, A.K., Mittal, A.K. & Pande, A. 1997. Genetic correlation of biodegraded crude oils from Padra area of Broach-Jambusar block, Cambay basin, India using n-Alkane, biomarker and stable carbon isotopic compositions. Proceedings Second International Petroleum Conference and Exhibition PETROTECH-97, New Delhi, pp237-243.

THE SATPURA BASIN

 

The Satpura Basin is a Gondwana Basin that lies in the heart of peninsula India, along the Narmada-Son lineament. It covers an area of about 5000 km2. It contains an early Permian to Triassic succession similar to that of the other Gondwana basins, but this is unconformably overlain by a Cretaceous succession comprising the Lower Cretaceous Jabalpur Formation, the Upper Cretaceous Lametas Formation and the latest Cretaceous to earliest Palaeocene Deccan Trap. The Pench-Kanhan-Tawa Valley coalfield lies on the southern margin of the basin. This is characterised by a high degree of structural disturbance and E-W faulting. The coalfield also shows evidence of intrusion by dykes associated with the Deccan Traps. The structure of the central part of the basin is less well known. The sandy parts of the Barakar Formation, along with the Bijori and Panchmari formations may provide suitable reservoirs, and the clay-dominated Motur and Denwa Formations could have sealing potential (Mondal 2007). However, until this potential can be firmed up, its CO2 storage potential is classified here limited.

References

Mondal, A. 2006. Gondwana Basins in India – Vast Geologic Storage Sites for CO2 Injection. Proceedings of the International Workshop on R&D Challenges in Carbon Capture & Storage Technology for Sustainable Energy Future (IWCCS-07), 12-13 January 2007. National Geophysical Research Institute, Hyderabad.

THE VINDHYAN BASIN

 

Figure A3.38 Location of the major Proterozoic basins of India

Introduction

The Vindhyan Basin (outcropping parts of which are shown in Figures A3.38 and A3.39) is a large intra-cratonic Proterozoic basin on the northern part of the Indian Shield. It covers an area of about 166400 km2. About 40,000 km2 of the northern part of the basin is concealed beneath Ganges river alluvium and Cenozoic sedimentary rocks. On the basis of geophysical evidence the basin is thought to extend up to (and thus possibly beneath) the frontal thrust of the Himalayas. The southern and south-western parts of the basin are covered by the Deccan Traps. Concealed Vindhyan strata are present as far west as the Moradabad Fault and as far east as the Patna Fault (Figure A3.39).

The exposed Bundelkhand Massif (of Archaean age), and its subsurface continuation the Faizabad Ridge, lie in the centre of the basin. They trend roughly northeast-southwest and divide the basin into two parts, one lying within the Chambal Valley to the west and the other lying in the Son Valley to the east. They influenced sedimentation during deposition of the basin fill.

Figure A3.39 Location map of Vindhyan Basin

Stratigraphy

The basin is of Proterozoic age. Its fill is thought to span the time interval from 1400 Ma to 500 Ma (Prasad & Verma 1991).

The sedimentary rocks that fill the Vindhyan Basin are known as the Vindhyan Supergroup. They are stratified, unmetamorphosed sandstones and shales, with subordinate limestones. They attain a maximum thickness of about 5250 m.

Potential reservoir rocks

No detailed studies of the reservoir properties of the Vindhyan rocks have been made. However, Aswathi (quoted in Srivastava et al.1983) concludes that the interval velocity of the Vindhyan sediments beneath the Ganges plain indicates extremely poor reservoir properties. Peters, Bhatnagar & Singh (1997) also state that Vindhyan sediments have poor primary porosity.

Potential cap rocks

Good shale sequences are present that, if not heavily fractured, might seal any reservoir horizons, especially in the Upper Vindhyan Group.

Structure

There are some apparently suitable structures for CO2 storage in the basin, e.g. along the southeastern boundary of the Bundelkhar Massif, and along the Narmada-Son Lineament, where many anticlinal structures are present in a linear belt.

Summary of carbon dioxide storage potential

The absence of recorded good quality reservoir rocks indicates that CO2 storage potential is likely to be low, and possibly non-existent, despite the thick and widespread sedimentary fill of the basin. However, given the vast area that the basin covers it is probably premature to write it off completely.

References

Prasad, B. & Verma, K.K. 1991. Chapter 4 Vindhyan Basin: A Review. In: Tandon, S.K., Pant, C.C. & Casshyap, S.M. (editors), Sedimentary basins of India: Tectonic Context. Gyanodaya Prakashan, Nainital, India, pp50-62.

Peters, J., Bhatnagar,, P.K. & Singh, S.K. 1997. Potential Fractured Reservoirs in the Vindhyan Super Group and their Relation to Petrographic Characteristics. Proceedings of Second International Conference and Exhibition, Petrotech 97, New Delhi, pp. 239-248. B.R. Publishing Corporation, New Delhi.

Srivastava, B.N., Rana, M.S. & Verma, N.K. 1983. Geology and Hydrocarbon Prospects of the Vindhyan Basin. Petroleum Asia Journal, Nov. 1983, 179-189.

2 There is a Lower Cretaceous sedimentary sequence below the Deccan Trap but this likely predates basin development.