An integrated pore-pressure modeling approach was adopted to understand the basin architecture from a pressure perspective and its inference toward possible hydrocarbon occurrence. Kriging-based 3D pore-pressure modeling was used with offset well data and seismic velocities to establish the pressure stratigraphy of the northeast coast (NEC) field (southern part) in the Mahanadi Basin. Late Pliocene sediment is moderately pressured ([Formula: see text]), whereas early Pliocene sediment is normally pressured ([Formula: see text]) and compacted, representing a regional seal for this part of the basin. Miocene represents the onset window for major undercompaction and associated high pressures ([Formula: see text]) in conformance with the regional pressure trend. Overpressure distribution and its mechanisms in the late Miocene level across the NEC field shows distinct patterns with highly elevated pressures ([Formula: see text]) in the northern part resulting from a hybrid unloading mechanism, whereas moderate to high pressure ([Formula: see text]) toward the southern part is associated with undercompaction. Regional pressure correlation across the study area suggests a pressure dependent habitat of hydrocarbons in the Miocene and late Pliocene levels. Pressure distribution and an excess pressure pattern within the Miocene stratigraphy shows a regression trend from north to south, possibly indicating a preferred subsurface fluid flow direction, which is supported by high-quality gas reservoirs discovered in the southern part of the study area. A similar but reverse pressure regression trend is observed within the late Pliocene stratigraphy, which is also validated by the presence of gas reservoirs in the northern part of the study area. Major hydrocarbon reservoirs in the Miocene and Pliocene stratigraphy from the southern part of study area exhibit a strong correlation with effective stress distribution. High-quality gas reservoirs are mostly associated with high effective stress ([Formula: see text]), whereas a high probability for reservoirs to be water wet are observed below this threshold value.
Tight reservoir exploration in Barmer basin has huge potential with possible in place volumes of multi billion barrels in reservoirs across the Mesozoic to Cenozoic stratigraphic levels. These tight reservoirs (permeability in the range of 0.01-10 mD) are ideal fraccing candidates for commercial production. One of the critical challenges in tight reservoir exploration is early assessment of permeability and reservoir fluid type identification through wireline formation testing (WFT) to determine flow behavior, frac optimization and expected deliverability after fraccing. The most prospective Barmer Hill (BH) and Fatehgarh (FAT) tight formations from the basin have been tested with new 3D radial probe WFT tool providing significant time and cost optimization opportunities. Good quality fluid samples with very low contamination levels were extracted with less rig time and operational costs from very low permeable BH formation (0.18 mD/cP mobility) and FAT formation (0.35 mD/cP mobility) in 150 and 200 min respectively. 3D radial probe and dual packer module based WFT job were compared for their efficiencies in similar environment. The results show that 3D radial probe has less inflation time (*1/5th), quick fluid detection (*1/10th time), quick and reliable packer deployment, focused fluid flow regime to address the formation heterogeneity and minimum hole sticking issues due to mechanical arms around the probe. In short, 3D radial probe can address both the uncertainties of WFT in tight reservoirs and optimized well testing and frac design for cost effective field development.
Understanding pressure mechanisms and their role in porosity-effective stress relationship is crucial in pore-pressure prediction estimation, particularly in complex geologic and high-temperature regimes. Overpressures are commonly associated with undercompaction and/or unloading mechanisms; those associated with undercompaction generally possess a direct relationship between effective stress and porosity, whereas those associated with unloading do not provide such direct indications from porosity trends. The type of associated unloading mechanism can be correlated when the effective stress and velocity become distorted with the onset of unloading. In the Ravva field, the pore-pressure distribution and overpressure mechanism in the Miocene and below it is a classic example of the unloading mechanism related to chemical compaction, thereby making it difficult to resolve the magnitude and trend of pore pressures. Here, the ratio of P- and S-wave velocities ([Formula: see text]) is analyzed from the drilled locations to understand the effects of lithology, pressure, and fluids on formation velocities and indicates a distinct decreasing trend across the overpressure formations, which I have corresponded to excess pressure resulting from chemical compaction. Across the high-pressured zones, [Formula: see text] ratios show low values compared with normally pressured zones possibly due to the presence of hydrocarbon and/or overpressures. A velocity correction coefficient ranging 0.83–0.71 is resolved for overpressure zones by normalizing the [Formula: see text] values across the normally pressured formations, and thereby assuring that a pore-pressure estimation using corrected velocity from [Formula: see text] analysis shows a high degree of accuracy on prediction trends. Pore-pressure predictions based on [Formula: see text] are a more effective and valid approach in high-temperature settings, in which numerous factors can contribute to pressure generation and a direct effective stress-porosity relationship deviates from the trend.
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