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Naidu et al: Migration Modelling in the Barmer Basin
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Hydrocarbon generation and migration modelling in the Barmer Basin of western Rajasthan, India: lessons for exploration in rift basins with late stage inversion, uplift and tilting 1
Bodapati S. Naidu, 1&2 now 5Stuart D. Burley, 3John Dolson, 4Paul Farrimond, 1
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Accepted ms in press AAPG Memoir 112: Petroleum System Case Studies
V R. Sunder, 1Vachaspati Kothari and 1Pinak Mohapatra. 1
Cairn India Ltd Pty, DLF Atria, Jacaranda Marg, Gurgaon, India Department of Earth Sciences, University of Keele, Staffordshire, United Kingdom 3 DSP Geosciences and Associates, LLC, Coconut Grove, Miami, Florida, USA 4 Integrated Geochemical Interpretation Ltd, Hallsannery, Bideford, Devon, United Kingdom 5 Murphy Oil Corporation, Petronas Tower 2, Kuala Lumpur, Malaysia 2
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Abstract
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The Barmer Basin of north-west India is a failed, intra-continental rift and established prolific hydrocarbon province. Primary source rocks in the basin are the diatomites and interbedded lacustrine shales of the Paleocene-Eocene Barmer Hill and Dharvi Dungar formations, although subordinate hydrocarbon contributions were generated from Lower Cretaceous lacustrine shales.
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Syn-rift deposition commenced in the Paleocene and peaked in the Eocene, with Barmer Hill Formation shales maturing as early as 55 Ma. Generation continued across the basin through to the Miocene. Kinetic variations in the Barmer Hill Formation source rock enabled the northern prolific Type-1 shallow water lacustrine facies algal kerogen to mature at lower temperatures and generate more oil than the leaner but more deeply buried, transported deep water southern facies Type III land plant kerogen equivalent.
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Migration modelling indicates that cross-fault juxtaposition of Paleocene and Lower Cretaceous reservoirs against downthrown mature source rocks is sufficient to charge all the known giant oilfields in the northern part of the basin. Accumulations in the shallower Dharvi Dungar and Thumbli formations in the central and southern parts of the basin require vertical and lateral migration from the mature Barmer Hill Formation through thick shale sequences, via fault linkages, fill and spill migration, and top seal leakage.
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Post-Miocene Himalayan-related collision inverted and tilted the northern part of the Barmer Basin, terminating generation in this area, while southern kitchens continued subsiding and expelling hydrocarbons. Extensive residual oil shows attest to widespread, large-scale re-migration of reservoired hydrocarbons in the uplifted northern basins as tilted structures spilled up-dip or were breached during inversion erosion. As a result, many of the present day accumulations are significantly smaller than peak burial accumulations.
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Simple mass-balance calculations indicate that significantly more oil was generated in the basin than has so far been discovered. Much of this oil was lost from the basin during uplift and tilting as breached structures were successively exposed. Such extensive loss of accumulated hydrocarbons is likely to be typical of inverted rift basins.
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12/04/2016
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Naidu et al: Migration Modelling in the Barmer Basin
Accepted ms in press AAPG Memoir 112: Petroleum System Case Studies
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Introduction
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The Barmer Basin of north-western Rajasthan, India (Figure 1), contains some 6 BBOE (billion
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barrels oil equivalent) of proven gross in place resources (STOIIP) in 38 discovered fields and over
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3 BBOE of prospective resources in undrilled leads and prospects. It is a relatively new hydrocarbon
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province successfully explored only over the last 15 years (Sisoda and Singh, 2000; Compton,
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2009; Dolson et al., 2015). Sediment thickness exceeds 6 kilometers in the main depocenters but
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only the main structures in the shallowest 4km of the basin have so far been drilled. The basin is
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now penetrated by almost 300 exploration and appraisal wells with a success rate of over 50%.
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Despite this exploration activity, the Barmer Basin remains a relatively under-explored province,
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certainly when compared with the mature Cambay Basin immediately to the south (Biswas, 1987;
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Banerjee and Rao, 1993; Banerjee et al., 2002; Figure 1). Significant exploration potential remains
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in deeper structural plays and in post-rift stratigraphic traps (Kothari et al., 2015).
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An extensive database on source rock properties, heat flow, reservoir types and seal rock properties
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has been collected from exploration and appraisal wells together with data from scattered outcrops
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around the basin flanks and along the northern, uplifted margin of the basin. A summary of the
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current understanding of the petroleum geology of the basin is given in Dolson et al. (2015) while
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Farrimond et al. (2015) detail aspects of the main source rocks and their properties. This
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contribution describes the construction of, and simulation results from, a pseudo-3D petroleum
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system model calibrated to known hydrocarbon discoveries and shows. The model has been used
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to investigate the distribution of discovered oil and gas fields in the Barmer Basin, the evolution of
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migration pathways and the hydrocarbon charge history as the basin developed.
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Petroleum Geology of the Barmer Basin
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The Barmer Basin is a long (200km) and narrow (
