Maintaining a stable borehole and optimizing drilling are still considered to be vital practice for the success of any hydrocarbon field development and planning. The present study deliberates a case study on the estimation of pore pressure and fracture gradient for the recently decommissioned Volve oil field at the North Sea. High resolution geophysical logs drilled through the reservoir formation of the studied field have been used to estimate the overburden, pore pressure, and fracture pressure. The well-known Eaton’s method and Matthews-Kelly’s tools were used for the estimation of pore pressure and fracture gradient, respectively. Estimated outputs were calibrated and validated with the available direct downhole measurements (formation pressure measurements, LOT/FIT). Further, shear failure gradient has been calculated using Mohr-Coulomb rock failure criterion to understand the wellbore stability issues in the studied field. Largely, the pore pressure in the reservoir formation is hydrostatic in nature, except the lower Cretaceous to upper Jurassic shales, which were found to be associated with mild overpressure regimes. This study is an attempt to assess the in-situ stress system of the Volve field if CO2 is injected for geological storage in near future.
Summary Seismic attributes have become successful in illuminating subsurface features and are widely used by interpreters for identifying potential hydrocarbon reservoirs. A case study is presented in the Mahanadi basin lying in the eastern Indian margin, where gas hydrate has been detected by identifying a bottom simulating reflector or BSR on seismic section. The data is conditioned using several post-stack processing steps such as the detailed and background steering followed by dip steered median filter (DSMF). This data is then used for extracting seismic attributes. Spectral decomposition and comparative results of different algorithms used for delineating gas hydrate and free gas underneath.
Understanding the physiography of subsurface structures in the region of Bay of Bengal (BoB) is vital. Since the region of BoB is generally covered by thick sediments, the physiography may not fully reveal the existence of buried structural features. However, such structural features are a key parameter that influences accommodation of subsurface deformation and tectonic events like earthquakes. Here, we address this issue using the integrated analysis and interpretation of gravity and full gravity gradient tensor (FTG) with few seismic profiles available resulting in poor constraints for the whole region. Potential field anomalies of BoB are analyzed for basement's tectonic structures. A 2D model of the deep earth crust is constructed and interpreted with gravity gradients and seismic profiles, which made it possible to obtain a visual image of a deep seated fault below the basement associated with thick sediments strata. Gravity modeling along a NE-SW profile crossing the hypocenter of the earthquake of 21 May 2014 (Mw 6.0) in the northern Bay of Bengal confirms the intraplate earthquake associated with normal dip fault within upper mantle in the region of high sediment thickness. We also observe in the gravity maps the enhanced structural trend of two major ridges, the 850E and the 900E ridge, which are easily resolved using computed full gravity gradients tensor components.
Presentation Date: Monday, September 25, 2017
Start Time: 3:55 PM
Presentation Type: ORAL
The present study deals with delineation of lateral extent of BSR along a line of 2D seismic reflection data in the Krishna-Godavari basin, India passing through NGHP-01-4A and NGHP-01-11A wells. The investigation is further extended to estimate gas hydrate saturation at corresponding sites on the basis of three-phase Biot-type equation for gas hydrate bearing sediments (GHBS). Post-stack model based inversion, constrained with well data is performed to obtain the impedance section. The impedance property is then used as an attribute along with other seismic attributes like instantaneous amplitude and instantaneous frequency for assessing whether the BSR is related to gas hydrates. The level of BSR confirmed is in good agreement with well log data. Density derived porosity log is used to derive the bulk and shear moduli of GHBS, which along with the bulk density is used to model the P-wave velocity. The misfit between the modeled P-wave velocity and the measured P-wave velocity or the sonic log is minimized to estimate the saturation of gas hydrate. The study yields maximum gas hydrate saturation of ~17.5% at a depth of 168 m and ~12% at 143m at NGHP-01-04A and NGHP-01-11A sites respectively.
This paper has been withdrawn from the Technical Program and will not be presented at the 87th SEG Annual Meeting.
This work deals with the estimation of P-wave velocity (VP), S-wave velocity (VS) and density (ρ) from constrained AVO inversion using genetic algorithm and FDR-PSO method, followed by rock physical modeling for saturation of gas-hydrate and free-gas along a seismic line in the Mahanadi basin, India. The VP and thickness obtained from reflection traveltime inversion are used in constrained AVO inversion for the estimation of Vs and density ρ. The VP and VS of hydrate bearing sediments are estimated as 1602 m/s and 406 m/s, and 1610 m/s and 408 m/s using genetic algorithm and FDR-PSO method respectively. Presence of free-gas is indicated by a lowering of VP below the BSR lying at 246 m below sea floor, and an increasing trend in negative reflection coefficients. Comparable elastic parameters within minimum error limits of 0.5 %, obtained by both the methods, show the reliable estimation. Corresponding to the Poisson ratio of 0.4653, the saturation of gas-hydrate is obtained as 4 % using the three-phase Wood equation. The free-gas is estimated as 1% based on Gassmann equation.
Presentation Date: Wednesday, September 27, 2017
Start Time: 11:25 AM
Presentation Type: ORAL
Ghosh, Ranjana (CSIR-National Geophysical Research Institute) | Sen, Mrinal K. (CSIR-National Geophysical Research Institute) | Vedanti, Nimisha (University of Texas at Austin) | Biswas, Reetam (CSIR-National Geophysical Research Institute)
Sleipner gas field in the North Sea is the world’s first industrial scale CO2 injection project designed specifically to reduce the emission of greenhouse gas. Here CO2 separated from natural gas produced at Sleipner gas field is injected into the Utsira sand, which is a major saline aquifer in the North Sea basin. In time-lapse threedimensional seismic data (4D), CO2 plume is imaged as a number of bright sub-horizontal reflections within the reservoir. Correlation of log data with the seismic data indicates that CO2 accumulates within a series of interbedded sandstones and mudstones beneath a thick cap rock of mudstone. Nine reflective horizons have been mapped within the reservoir on the six seismic surveys from 1999 to 2008. Comparison with the baseline seismic survey of 1994 (pre-injection) provides clear impression of the migration of CO2 plume. In this paper, we attempt to model CO2 distribution quantitatively within the reservoir by applying a pressure-dependent differential effective medium (PDEM) theory using 4D seismic data. Pre- and post-injection acoustic impedances are calculated by inverting respectively post-stack seismic data of 1994 and 2001 using a model-based inversion technique. 3D CO2 saturation volume is estimated using PDEM theory from inverted acoustic impedance of the year 2001 taking the reference of that from the results of pre-injection data of the year 1994. Since the gas distribution type is seldom known, we estimate the saturation distribution using both a homogeneous and a patchy distribution pattern in our rock physics model. We estimate saturation for homogeneous distribution of CO2 to be 0-20% and for CO2 as patches of gas as 0-80% of the total porosity within ~200 m thick reservoir unit. 5-7% uncertainty in the predicted CO2 saturation is estimated using a Monte-Carlo simulation technique. Our results indicate that a large amount of CO2 is accumulated as patches of gas within sand layers capped by mud layers, though some amount of gas may have dissolved uniformly with water.
Summary Seismic inverse problem of estimating P-and S-wave reflectivity from seismic traces has recently been revisited using a basis pursuit inversion (BPI) approach. The BPI uses a wedge dictionary to define model constraints, which has been successful in resolving thin beds. Here we have addressed mainly estimation of the regularization weight in BPI. It plays an important role as it acts as a weighting factor and decides how much importance is given to sparsity of the solution over the data fitting. This has been addressed by developing an iteration adaptive analytical formula for estimating λ using Bayesian approach.
Satyavani, N. (CSIR-National Geophysical Research Institute) | Sen, Mrinal K. (CSIR-National Geophysical Research Institute) | Ojha, Maheswar (CSIR-National Geophysical Research Institute) | Sain, Kalachand (CSIR-National Geophysical Research Institute)
Multi-component ocean bottom seismometer (OBS) survey carried out along with the multi-channel seismic survey for gas hydrate exploration in the Mahanadi offshore, India has shown some interesting observations in seismic waveform data. The fast (S1) and slow (S2) axes of propagation are seen in the radial azimuthal gathers of the OBS data, while amplitude nulls and amplitude highs are seen in transverse azimuthal gathers, indicating S-wave splitting. These two features are diagnostic of the existent anisotropy, which are modeled by generating full waveform synthetic seismograms. We interpret the occurrence of anisotropy to be due to the presence of fractures. The density of fracture set and the orientation are delineated by full wave modeling of the OBS data and the strike of this fracture set (~130°N) is delineated from the variation in the P-wave amplitude with azimuth. A qualitative match between the synthetic and the observed data is obtained for a near vertical fracture (angle of about 85°). The seismic image obtained from the high resolution multi-channel (MCS) data correlate well with the OBS results. From the joint interpretation of the OBS and MCS data, we identify a fracture zone that causes an azimuthally varying anisotropy within the sedimentary layers. These zones perhaps act as conduits for the supply of free gas to hydrate bearing layers.