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Agarwal G.,Schlumberger | Sagar R.,Schlumberger | Behera B.K.,Gujarat State Petroleum Corporation Ltd
Society of Petroleum Engineers - International Petroleum Technology Conference 2012, IPTC 2012

In any reservoir modeling exercise, accurate estimation of initial water saturation is crucial to determine the in-place hydrocarbon volumes. The water saturation in a reservoir is a function of the reservoir rock quality and the capillary forces present. Pore throat size distribution and rock quality strongly influence the amount of capillary-bounded water and mobile water in the reservoir rock. A good understanding and proper classification of rock types based on reservoir quality is essential for reservoir property population. Also, in absence of the core data, the practice of using single-well models and well logs to identify capillary pressure curves and hence water saturation distribution is not ideal for a vast heterogeneous reservoir with many wells. A case study is presented in which extensive core data, in particular RCA and SCAL results, are analyzed. These results are integrated with petrophysical interpretation to identify different classes of sand units based on the reservoir rock quality and amount of clay present. It is uniquely noted in this work that volume of clay, Vclay: was a better basis for rock classification in this reservoir. A numerical method is used to unify and integrate SCAL data acquired over a 1000-m section of the reservoir in more than 10 drilled wells. Parameterized equations are derived to populate initial water saturation in the static or dynamic model. The water saturations obtained from these parametric equations are subsequently validated with the well log saturations and vice versa. These results are further validated by history matching the drillstem test result, showing excellent results. Copyright 2011, International Petroleum Technology Conference. Source

Rapolu N.,Gujarat State Petroleum Corporation Ltd | Mandal P.,CSIR - Central Electrochemical Research Institute
Journal of the Geological Society of India

We present the estimated source parameters from SH-wave spectral modeling of selected 463 aftershocks (2002-06) of the 26 January 2001 Bhuj earthquake, the well-recorded largest continental intraplate earthquake. The estimated seismic moment (Mo), corner frequency (fc), source radius (r) and stress drop (Δσ) for aftershocks of moment magnitude 1.7 to 5.6 range from 3.55×1011 to 2.84×1017 N-m, 1.3 to 11.83 Hz, 107 to 1515 m and 0.13 to 26.7 MPa, respectively, while the errors in fc and Δσ are found to be 1.1 Hz and 1.1 MPa, respectively. We also notice that the near surface attenuation factor (k) values vary from 0.02 to 0.03. Our estimates reveal that the stress drop values show more scatter (Mo0.5 to 1 is proportional to Δσ) toward the larger Mo values (≥1014.5 N-m), while they show a more systematic nature (Mo3 is proportional to Δσ) for smaller Mo values (<1014.5 N-m), which can be explained as a consequence of a nearly constant rupture radius for smaller aftershocks in the region. The large stress drops (= 10 MPa) associated with events on the north Wagad fault (at 15-30 km depth) and Gedi fault (at 3-15 km depth) can be attributed to the large stress developed at hypocentral depths as a result of high fluid pressure and the presence of mafic intrusive bodies beneath these two fault zones. © 2014 Geological Society of India. Source

Gupta S.D.,Gujarat State Petroleum Corporation Ltd | Chatterjee R.,Indian School of Mines | Farooqui M.Y.,Gujarat State Petroleum Corporation Ltd
Journal of Geophysics and Engineering

Unconventional reservoirs such as fractured basalts, shale gas and tight sand are currently playing an important role in producing a significant amount of hydrocarbon. The Deccan Trap basaltic rocks form the basement of the Cambay Basin, India, and hold commercially producible hydrocarbon. In this study two wells drilled through fractured basalts are chosen for evaluating the lithology, porosity and oil saturation of the reservoir sections. Well logs, such as gamma ray, high resolution resistivity, litho density, compensated neutron and elemental capture spectroscopy, have been used in cross-plotting techniques for lithology and mineral identification. Formation micro imagery log data have been analysed to quantify the fractures and porosity in the fractured reservoirs for a well in the south Ahmedabad block of the Cambay Basin. The results of the analysis of two wells are presented and discussed and they are found to be in good agreement with geological and production data. © 2012 Nanjing Geophysical Research Institute. Source

Behera B.K.,Pandit Deendayal Petroleum University | Danpanich S.,PTT Exploration and Production Public Company Ltd | Laprabang W.,PTT Exploration and Production Public Company Ltd | Heath G.,Chevron | And 2 more authors.
Oilfield Review

High borehole temperatures and pressures pose design challenges for engineers developing formation evaluation tools. Pressure and sampling tools that use motors and pumps require high power to operate and often generate considerably more heat than tools used for basic petrophysical measurements. Traditional solutions to combat temperature and pressure are insufficient for these types of tools. Recent innovations make it possible to obtain downhole pressure measurements and samples and to perform extended well tests in extreme conditions. Copyright © 2012. Source

Chatterjee R.,Indian School of Mines | Gupta S.D.,Gujarat State Petroleum Corporation Ltd | Farooqui M.Y.,Gujarat State Petroleum Corporation Ltd
Journal of Geophysics and Engineering

Low-resistivity pay sands have been identified in four wells, namely: AM-7, AM-8, TA-1 and TA-5, which penetrate the Eocene pay-IV (EP-IV) sand unit of the Kalol formation in the Cambay basin. These wells are located near the Dholka and Kanwara oilfields in the Cambay basin. The main objective of this paper is to evaluate nuclear magnetic resonance (NMR) logs of the low-resistivity reservoirs from these four wells and to determine the petrophysical properties more accurately than conventional logs have done. The thickness of low-resistivity sand varies from 5 to 17m in the wells under the study area. The formation has been characterized by a high surface area; thus irreducible water saturation (S wi) is high. The resistivity of these pay zones varies from 1 to 8 m and the total NMR porosity ranges from 15% to 50%. The free fluid porosity ranges from 2% to 5% in wells TA-1 and TA-5 and 12-20% in wells AM-7 and AM-8. The Timur-Coates/SDR model derived that the permeability of the low-resistivity reservoir ranges from 0.8 to 1.5 md in wells TA-1 and TA-5 and 10-110 md in wells AM-7 and AM-8. © 2012 Sinopec Geophysical Research Institute. Source

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