Rima Chatterjee

Detection of overpressure zones and a statistical model for pore pressure estimation from well logs in the Krishna‐Godavari Basin, India

Abnormally high pressures, measured by repeat formation tester (RFT) and detected by well log data from 10 wells in the Krishna-Godavari (K-G) Basin, occur in the Vadaparru Shale of Miocene and Raghavapuram Shale of Early Cretaceous age. Overpressures generated by disequilibrium compaction, and pore pressures have been estimated using the conventional Eaton sonic equation with an exponent of 3.0. The observed abnormal pore pressure gradient ranges from 11.85 to 13.10 MPa/km, whereas fracture pressure gradient varies from 17.40 to 19.78 MPa/km. The magnitude of vertical stress (Sv) has a gradient from 21.00 to 23.10 MPa/km. The minimum horizontal principal stress (Sh) magnitude is found to vary from 64 to 77% of the Sv in normally pressured to overpressured sediments. A multiple linear regression model with a squared multiple correlation coefficient (R2) of 0.94 is proposed for pore pressure prediction from gamma ray, density and sonic logs to focus on efficient drilling operations and to prevent borehole instability. The statistical model has been calibrated with the RFT data from five wells covering about 3400 sq. km area of the onshore K-G Basin. The model predicted pore pressure values are in close agreement with the actual RFT data for another four wells including a well in the offshore K-G Basin. Hence, the proposed regression model may be useful for predicting pore pressure from other well logs in the K-G Basin.

Formation evaluation of fractured basement, Cambay Basin, India

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.

Magnitude, mechanisms and prediction of abnormal pore pressure using well data in the Krishna Godavari Basin, East coast of India

Abnormal pressures are encountered during exploration drilling in different parts of Krishna–Godavari Basin on the east coast of India. The nature and stratigraphic occurrences of the overpressure zones vary across the basin. Three different clusters of wells, covering a large part of the basin encompassing both onshore- and offshore-drilled wells, are analyzed to capture this variation. A wide range of pore-pressure gradients from normal to as high as 18 MPa/km was observed in the present data set. The tops of overpressure zones demonstrate a large range from 2200 to 3000 m (6562 to 9842 ft). These depths generally correspond to either a Miocene deltaic sequence or Cretaceous synrift and postrift sequences. Available well data reveal two main reasons for the development of overpressure. Considerably high pore-pressure regimes in the Cretaceous sequence in the eastern corner of the basin are found to be mainly caused by gas generation, whereas disequilibrium compaction is proposed as the main cause for overpressure in the other parts of the basin. The outcome of this analysis provides a fair idea of the nature, magnitude, and distribution of the overpressure, and this will also help to strategize further exploration activities in the basin.

Overpressure Zones in Relation to In Situ Stress for the Krishna-Godavari Basin, Eastern Continental Margin of India: Implications for Hydrocarbon Prospectivity

An analysis for over pressure zone (OPZ) prevailing in parts of the Krishna-Godavari Basin (KG-B) at the Eastern Continental Margin of India (ECMI) is found promising from the viewpoint of its hydrocarbon potentials. Pressure coefficients estimated from pore pressure studies reveal that there is a rather extensive (lateral) OPZ in the study area than hitherto expected with maximum pressure coefficient of 1.31 or more. The stress magnitudes like vertical stress (Sv), minimum horizontal stress (Sh) and pore pressure gradient (PPG) and fracture pressure gradient (FPG) are predicted from well log data for 15 available wells distributed over an area of 6022 km2 in KG-B. The wells are drilled to depths of 3660 m on-land (#Wells 1–9) and up to 4000 m in offshore (#Wells 10–15). The PPG ranges from 11.85 to 13.10 MPa/km, whereas, the FPG varies from 17.40 to 19.78 MPa/km in sediments penetrated by the wells displaying normal pressured sediment to a significantly higher value of 19.78 MPa/km for the over-pressured sediments. The values of vertical stress gradient (VSG) varies from 14.67 to 23.10 MPa/km, whereas, the values of Sh magnitude varies from 64 to 77 % of the Sv in normally-pressured to over-pressured sediments. VSG, PPG and FPG tend to decrease with corresponding increase in water column for the studied offshore wells. These results are utilized for constructing contour maps for observing the variations in the VSG and in the OPZ-top, also for constructing PPG contour map in 3D along the vertical section connecting all 15 wells extending from onshore to offshore regions. Any significant increase in pore pressure means the decrease of effective horizontal stress in respect of depth. As a result, the safety windows or safe mud-weight windows (the difference between PPG and FPG corresponding to particular depth interval in a well) will also decrease with the increase of PPG and FPG. Analytical approach adopted above is then critically examined to recommend how a priori steps based on petrophysical characters of a formation are closely monitored in time and optimum mud weight maintained during drilling.

Post-stack seismic inversion and attribute analysis in shallow offshore of Krishna-Godavari basin, India

Seismic attributes such as: amplitude envelope, instantaneous phase and cosine of instantaneous phase of 2D post-stack seismic data facilitates structural and stratigraphic interpretation of shallow marine offshore, Krishna-Godavari basin. Two seismic sections namely, X and Y oriented N-S passing through wells W-1 andW-2 respectively are considered for seismic attribute analysis and porosity prediction. The gamma ray log trend indicates deposition of cleaning upward sediment. Coarsening upward, clayey-silty-sandy bodies, making a series of about 50-60 m thickness, have been evidenced from the gamma ray log. An extensional structural style comprising growth faults is associated with the progradational style of deposition. Four seismic zones have been distinguished. These zones differ in amplitude, frequency and continuity of the reflectors. Channel sands of Cretaceous age of Raghavapuram shale are identified in well log, seismic section and its acoustic impedance section. Major stratigraphic horizons along with faults extending to basement are marked with the help of attribute analysis. Porosity is mapped from transformation of acoustic impedance. The shales/unconsolidated sediments measure a high porosity with low impedance and the more porous sands are in an intermediate range. The predicted impedance and porosity values may be erroneous beyond the drilled depth because of non availability of well log data for calibration.

Estimation of In-situ Stress and Coal Bed Methane Potential of Coal Seams from Analysis of Well Logs, Ground Mapping and Laboratory Data in Central Part of Jharia Coalfield—An Overview

Well log data of thirty (30) boreholes from central part of Jharia coalfield have been analysed for estimation of petrophysical and rock mechanical properties of coal seams to facilitate assessment of Coal Bed Methane (CBM) reservoir potentiality of those coal seam. Wells from Jharia area showed 18 major correlatable seams, intersected between 214 and 1324 m depth. The resistivity, density and natural gamma ray log data from the wells of the study area have been utilized for: (a) Estimation of permeability of coal seams from resistivity log data; (b) Computation of in-situ stress magnitudes—vertical stress, effective vertical stress and effective horizontal stress at seam horizons; (c) Establish relationship between in-situ stress and permeability; (d) Estimation of gas content of coal seams and identification of most potential zones for CBM exploration. It is observed that the permeability values ranging from 0.82 to 1.12 md with average gas content of 11.50 to 11.75 cc/gm. By comparing gas content, coal seam thickness as well as coal bed permeability of these major coal seams, the most viable CBM potential zone is mapped for this area.

Application of nuclear magnetic resonance logs for evaluating low-resistivity reservoirs: a case study from the Cambay basin, India

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 17?m in the wells under the study area. The formation has been characterized by a high surface area; thus irreducible water saturation (Swi) 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.

Well log data analysis for lithology and fluid identification in Krishna-Godavari Basin, India

Well log analysis provides the information on petrophysical properties of reservoir rock and its fluid content. The present study depicts interpretation of well log responses such as gamma ray, resistivity, density and neutron logs from six wells, namely W-1, W-2, W-9, W-12, W-13 and W-14 under the study area of Krishna-Godavari (K-G) basin. The logs have been used primarily for identification of lithology and hydrocarbon-bearing zones. The gamma ray log trend indicates deposition of cleaning upward sediment. Coarsening upward, clayey-silty-sandy bodies have been evidenced from the gamma ray log. Gas-bearing zones are characterised by low gamma ray, high deep resistivity and crossover between neutron and density logs. Total 14 numbers of hydrocarbon-bearing zones are identified from wells W-9, W-12, W-13 and W-14 using conventional log analysis. Crossplotting techniques are adopted for identification of lithology and fluid type using log responses. Crossplots, namely P-impedance vs. S-impedance, P-impedance vs. ratio of P-wave and S-wave velocities (Vp/Vs) and lambda-mu-rho (LMR), have been analysed to discriminate between lithology and fluid types. Vp/Vs vs. P-impedance crossplot is able to detect gas sand, brine sand and shale whereas P-impedance vs. S-impedance crossplot detects shale and sand trends only. LMR technique, i.e. λρ vs. μρ crossplot is able to discriminate gas sand, brine sand, carbonate and shale. The LMR crossplot improves the detectability and sensitivity of fluid types and carbonate lithology over other crossplotting techniques. Petrophysical parameters like volume of shale, effective porosity and water saturation in the hydrocarbon-bearing zones in these wells range from 5 to 37%, from 11 to 36 and from 10 to 50% respectively. The estimated petrophysical parameters and lithology are validated with limited core samples and cutting samples from five wells under the study area.

Fracture and stress orientation from borehole image logs: A case study from Cambay basin, India

The Deccan trap basalt, laid down by multiple lava flows during upper Cretaceous to Paleocene times forms the basement of current study in Cambay basin. As such, there is great interest and value in fracture detection and evaluation of fractured basement reservoirs in the Cambay basin. The procedure for identification and evaluation of natural as well as induced fractures in basaltic basement of the Cambay basin is presented in this work. In this study formation micro-imager (FMI) and extended range micro-imager (XRMI) log data for fracture identification is used. The Deccan trap basaltic basement of the study area, comprising five wells in the Tarapur-Cambay block, has potential for holding commercial hydrocarbon due to the presence of fractures and weathered basement. Both image logs (FMI, XRMI) identify three types of fracture including open (conductive), partially open and closed (resistive) fractures, of which open and partially open fractures are important for hydrocarbon accumulation. Fracture dip ranges from 10° to 80°. Image logs have also identified washout, breakout and drilling-induced fracture zones. The strike direction of the open natural fractures for four wells varies from N60°E to N30°E whereas the strike direction of most natural fracture in the fifth well is oriented towards N20°W. The orientations of drilling-induced fractures and breakouts may be interpreted for the in-situ stress direction over the logged interval. Drilling-induced tensile fractures, identified over the depth interval of 1969–1972 m, and borehole breakouts over the interval of 1953–1955 m in one well, suggest an orientation of maximum in-situ horizontal compressive stress (SH) lies in the north-south direction. The azimuths of open natural fractures in the same well vary from north-south to N30°E. It is expected that the direction of fluid flow will be controlled by open natural fractures and therefore would be in a direction parallel to the SH direction, which is orthogonal to the minimum horizontal stress (Sh) direction. The orientations observed are consistent with the present day SH direction in the study area of Cambay basin.

Relationship of Coal bed Permeability with Vertical Stress from Well Log data: A Case study from Raniganj CoalField, India

Summary Characterization of coal in term of its physical properties like porosity and permeability has generally been performed on limited sample volumes such as plugs or cores. A methodology is proposed for estimation of permeability for a macro-cleat system of coal from well log derived porosity and from known cleat spacing for Rangamati area of Raniganj Coalfield, India. Data of seven numbers of wells were available from the study area. Geological logs of these boreholes recorded occurrence of four major consistent coalseams (A, B, C & D) at different depths, varying between 53 to 200m in the area. Permeability values of four coalseams with thickness varying between 2-5 m encountered in the seven wells have been correlated with vertical (overburden) stress. Permeability value ranges from 0.5 md at depth of 200 m to 18 md at shallower depth of 53 m while vertical stress decreases from 4.566 MPa to 1.254 MPa respectively. Permeability value of coalseam decreases with increase in vertical stress. Regression analysis between permeability & vertical stress of the coalseams show 2 nd order polynomial, as the best fit curves. Goodness of fit (R 2 ) for the 2 nd order regressions between vertical stress and permeability for individual coalseams varies between 0.86 and 0.99.