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Hybrid journal (It can contain Open Access articles)
ISSN (Print) 1354-0793 - ISSN (Online) 2041-496X
Published by Geological Society of London [10 journals]
- Carbon dioxide storage in the Captain Sandstone aquifer: determination of
in situ stresses and fault-stability analysis
Williams, J. D. O; Fellgett, M. W, Quinn, M. F.
Pages: 211 - 222
Abstract: The Lower Cretaceous Captain Sandstone Member of the Inner Moray Firth has significant potential for the injection and storage of anthropogenic CO2 in saline aquifer parts of the formation. Pre-existing faults constitute a potential risk to storage security owing to the elevated pore pressures likely to result from large-scale fluid injection. Determination of the regional in situ stresses permits mapping of the stress tensor affecting these faults. Either normal or strike-slip faulting conditions are suggested to be prevalent, with the maximum horizontal stress orientated 33°–213°. Slip-tendency analysis indicates that some fault segments are close to being critically stressed under strike-slip stress conditions, with small pore-pressure perturbations of approximately 1.5 MPa potentially causing reactivation of those faults. Greater pore-pressure increases of approximately 5 MPa would be required to reactivate optimally orientated faults under normal faulting or transitional normal/strike-slip faulting conditions at average reservoir depths. The results provide a useful indication of the fault geometries most susceptible to reactivation under current stress conditions. To account for uncertainty in principal stress magnitudes, high differential stresses have been assumed, providing conservative fault-stability estimates. Detailed geological models and data pertaining to pore pressure, rock mechanics and stress will be required to more accurately investigate fault stability.
Issue No: Vol. 22, No. 3 (2016)
- Authors: Williams, J. D. O; Fellgett, M. W, Quinn, M. F.
- Deposition, diagenesis and reservoir potential of non-carbonate
sedimentary rocks from the rift section of Campos Basin, Brazil
Armelenti, G; Goldberg, K, Kuchle, J, De Ros, L. F.
Pages: 223 - 239
Abstract: A new petrographical study was performed on the rift section of the Lagoa Feia Group, Lower Cretaceous of the Campos Basin, eastern Brazilian margin. The primary constituents of the analysed rocks are siliciclastic and volcaniclastic grains, stevensite ooids and peloids, and bioclasts of bivalves and ostracods. This study focused on the clastic, stevensitic and hybrid rocks, as previous studies were limited to the bioclastic rudstones and grainstones that constitute the producing reservoirs. The rift sedimentation was mostly intrabasinal, with extrabasinal contribution concentrated close to half-graben border faults. The mixture of rounded volcanic fragments with angular quartz, feldspars and plutonic fragments in the sandstones and conglomerates indicates recycling of early rift epiclastic deposits, combined with first-cycle sediments eroded from uplifted plutonic basement blocks. Stevensitic ooids and peloids, formed in shallow, alkaline lacustrine environments, were mixed throughout the rift section with bivalve and ostracod bioclasts, and with the clastic sediments. Gravitational redeposition was promoted by intense and recurrent tectonism along the rift margins. The main diagenetic processes in clastic sandstones and conglomerates and hybrid arenites are cementation and grain replacement by smectite, zeolites, calcite and dolomite, mechanical compaction and dissolution of feldspars, volcanic fragments and bioclasts. Stevensitic arenites experienced early cementation and replacement of ooids and peloids by quartz, calcite and dolomite, or intense compaction of stevensitic grains in uncemented areas. Volcaniclastic sandstones and conglomerates with smectite rims, remnant intergranular porosity and grain dissolution may constitute fair hydrocarbon reservoirs. Stevensitic and hybrid arenites with dissolution of stevensite grains, bioclasts and calcite cement may also constitute reservoirs, although with potential quality limited by the poor connection of their pore systems. An understanding of the controls on the depositional and diagenetic evolution of the dominantly intrabasinal, gravitationally redeposited, rift succession will contribute to new exploration strategies for the Campos Basin.
Issue No: Vol. 22, No. 3 (2016)
- Authors: Armelenti, G; Goldberg, K, Kuchle, J, De Ros, L. F.
- Grid-free petroleum reservoir characterization with truncated
pluri-Gaussian simulation: Hekla case study
Zagayevskiy, Y; Deutsch, C. V.
Pages: 241 - 256
Abstract: A new geostatistical grid-free simulation (GFS) method has been developed recently that represents simulated continuous attributes of the natural phenomena, such as stratigraphic surface boundaries or petrophysical properties, as an analytical function of the coordinates of the simulation locations. Thus, GFS resolves challenges related to model regridding, increasing resolution around already simulated locations and integration of newly available data in a consistent manner. The present paper contains further developments in simulation of categorical variables, such as facies, in a grid-free fashion based on the truncated pluri-Gaussian simulation (TPG) paradigm. The resultant simulation engine allows the entire reservoir system to be represented as an analytical stochastic function: that is, values of any reservoir properties are simulated on demand at requested locations in space. The selection of proper variograms of Gaussian continuous variables for simulation of categorical variables in a TPG framework is proposed through a methodology based on Monte Carlo simulation. The variogram models of the underlying Gaussian continuous variables are obtained by minimizing the difference between numerically computed and target indicator variograms. A local optimization approach is suggested for a fast precise derivation of the variograms. The stable variogram model leads to the closest fit to the experimental variograms of the continuous variables. The automatic establishment of a truncation mask based on multidimensional scaling to convert Gaussian continuous variables to categories is also explained. Finally, the proposed GFS algorithm for petroleum reservoir characterization is demonstrated in its full-scale applicability to the Hekla offshore petroleum reservoir located in the North Sea. The results look promising, and should be beneficial to petroleum reservoir modelling in practice.
Issue No: Vol. 22, No. 3 (2016)
- Authors: Zagayevskiy, Y; Deutsch, C. V.
- New theoretical model for predicting and modelling fractures in folded
Gholipour, A. M; Cosgrove, J. W, Ala, M.
Pages: 257 - 280
Abstract: In this study, an attempt has been made to develop a new theoretical model that can be used to predict the fracture spacing/density that develops in a single competent layer and in multilayers as a result of folding. The work is based on earlier analyses concerned with the fracturing of unfolded strata subjected only to layer-normal compression. Such a stress state exists in the upper crust in any tectonically relaxed region where the principal cause of stress is the overburden.Unlike previous studies on theoretical fracture-spacing modelling that are mainly designed for a layer-parallel horizontal-extension system, this study has introduced a new theoretical model for the predicting and modelling of fracture spacing/density in ‘folded’ reservoirs, which contain > 85% of the world's oil and gas traps.This theoretical model is an integrated model: that is, it takes into account both rock mechanical and geometrical properties of the reservoir.The big advantage of the theoretical model developed in this study is that it provides well- and reservoir-scale estimates of the fracture spacing, for both axial and cross-axial fractures (i.e. the dominant fracture sets in folded reservoirs), which can be used for predicting fracture density (the reciprocal of fracture spacing), fracture aperture, the Rock Fracture Potential Index (RFPI), fracture porosity, fracture permeability, the shape factor (sigma) and for optimizing the drilling (i.e. the Optimum Drilling Direction (ODD) and the Optimum Drilling Angle (ODA) to maximize the fracture intersection in the wells) in three dimensions in folded, single layer and multilayer fractured reservoirs.In addition, new approaches are described for quantifying the mechanical bed thickness (MBT) or mechanical unit thickness (MUT), estimating the fracture aperture (w), estimating the distance from the neutral surface (a) and determining the RFPI data that are essential for implementing the theoretical model presented in this paper related to subsurface, folded, fractured reservoirs.The expressions derived for fracture spacing/density, for both axial and cross-axial fracture sets, involve data that are always available for every field development (i.e. seismic, well and core data). An understanding of the distribution of the fracture spacing/density, fracture aperture and the RFPI at an early stage in the development of a fractured reservoir is crucial in selecting a proper field development strategy, managing well placement and for monitoring production from the reservoir.In summary, based on several case studies, one of which is presented in this paper, it can be confirmed that the theoretical model, expressed in equations given in this paper, predicts what has been observed in the folded clastic reservoirs of the study area. It is concluded that curvature alone cannot reveal the location of natural fractures in a reservoir and that the mechanical properties of the reservoir rock play a significant role in the development of a natural fracture system. Rock can accommodate strain by fracturing (i.e. if its RFPI is high) or (if its RFPI is low) use its internal strain storage capability (associated with its mechanical properties: e.g. porosity collapsing, grain sliding and the formation of intra-grain hairline fractures) to consume the stress without the need to accommodate strain by fracturing.
Issue No: Vol. 22, No. 3 (2016)
- Authors: Gholipour, A. M; Cosgrove, J. W, Ala, M.