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Dawe R.A.,University of the West Indies | Caruana A.,Tata Consultancy Services Ltd. | Grattoni C.A.,Rock Deformation Research
Transport in Porous Media | Year: 2011

Direct insight into the mechanisms of flow and displacements within small-scale(cm) systems having permeability heterogeneities that are not parallel to the flow direction (cross-bedding and fault zones) have been carried out. In our experiments, we have used visual models with unconsolidated glass bead packs having carefully controlled permeability contrasts to observe the processes with coloured fluids and streamlines. The displacements were followed visually and by video recording for later analysis. The experiments show the significance that heterogeneities have on residual saturations and recovery, as well as the displacement patterns themselves. During a waterflood, high permeability regions can be by-passed due to capillary pressure differences, giving rise to high residual oil saturations in these regions. This study demonstrates the importance of incorporating reservoir heterogeneity into core displacement analysis, but of course the nature of the heterogeneity has to be known. In general, the effects created by the heterogeneities and their unknown boundaries hamper interpretation of flood experiments in heterogeneous real sandstone cores. Our experiments, therefore, offer clear visual information to provide a firmer understanding of the displacement processes during immiscible displacement, to present benchmark data for input to numerical simulators, and to validate the simulator through a comparison with our experimental results for these difficult flow problems. © 2010 Springer Science+Business Media B.V. Source


Dawe R.A.,University of the West Indies | Caruana A.,Grand Harbour Marina Ltd | Grattoni C.A.,Rock Deformation Research
Transport in Porous Media | Year: 2011

The physical effect of multiphase fluid distribution and flow at permeability boundaries has not been fully investigated, particularly at the pore scale (1-100 μm), although such behaviour can significantly affect the overall scaled-up reservoir trapping capacity and production performance. In this article, microscale physical models have been used to qualitatively study the pore scale flow events at permeability boundaries, both high to low and vice versa, to gain a better understanding of the role of these boundaries and water saturation on multiphase displacement behaviour at the pore scale. We have used etched glass models of stripes of large and small (a factor of two) pores with circular matrix. Capillary pressure, which is the controlling parameter is itself dependant on pore size and its spatial distribution, the magnitude of the interfacial tensions and the wettability between the fluids and the solid surface of the models. Sometimes, the only way the non-wetting fluid can penetrate the boundary is through a fortuitous leakage, whereby the presence of an initial saturation reduces the controlling capillary pressure. Examples are demonstrated including mechanisms of end-effects and how capillary boundary resistance (due to capillary forces) can be broken down and fluid movement across the boundary can develop. These micromodel experiments show vividly that connate water can assist in these processes, particularly oil trapping and leakage of water across a permeability boundary. © 2010 Springer Science+Business Media B.V. Source


Tueckmantel C.,University of Leeds | Fisher Q.J.,University of Leeds | Manzocchi T.,University College Dublin | Skachkov S.,University of Leeds | Grattoni C.A.,Rock Deformation Research
Geology | Year: 2012

Fault rocks can function as barriers to subsurface fluid flow and affect the storage of CO2 in geological structures. Even though flow across faults often involves more than one fluid phase, it is typically modeled using only single-phase functions due to a lack of fault rock relative permeability data and complexities in incorporating two-phase flow properties into flow simulations. Here we present two-phase fluid flow data for cataclastic fault rocks in porous sandstone from the 90-Fathom fault (northeast England). The study area represents a field analogue for North Sea saline aquifers of Permian-Triassic age that are currently being considered for CO2 storage. We use the experimental data to populate a synthetic model of a faulted saline aquifer to assess the impact of these fault rocks on CO2 injection. We show that even fault rocks with low clay contents and very limited quartz cementation can act as major baffles to the flow of a non-wetting phase if realistic two-phase properties are taken into account. Consequently, pressure may increase far more rapidly in the storage compartment during CO2 injection than anticipated based on models that only incorporate absolute fault rock permeabilities. To avoid high pressures, which may lead to hydrofracturing and CO2 leakage, either more complex injection strategies need to be adopted or seismic data acquired to ensure the absence of faults in aquifers selected for CO2 storage. © 2012 Geological Society of America. Source


Tueckmantel C.,University of Leeds | Fisher Q.J.,University of Leeds | Grattoni C.A.,Rock Deformation Research | Aplin A.C.,Northumbria University
Marine and Petroleum Geology | Year: 2012

Understanding the impact of faults on fluid flow in the subsurface is important for the extraction of oil, gas and groundwater as well as the geological storage of waste products. We address two problems present in current industry-standard workflows for fault seal analysis that may lead to fault rocks not being represented adequately in computational fluid flow models. Firstly, fluid flow properties of fault rocks are often measured only for small-scale faults with throws not exceeding a few centimetres. Large seismic-scale faults (throws >20 m) are likely to act as baffles or conduits to flow but they are seldom recovered from subsurface cores and consequently fault rock data for them is sparse. Secondly, experimental two-phase fluid flow data is lacking for fault rocks and, consequently, uncertainties exist when modelling flow across faults in the presence of two or more immiscible phases. We present a data set encompassing both single- and two-phase fluid flow properties of fault and host rocks from the 90-Fathom fault and its damage zone at Cullercoats Bay, NE England. Measurements were made on low-throw single and zones of deformation bands as well as on slip-surface cataclasites present along the ∼120 m throw main fault. Samples were analysed using SEM and X-ray tomography prior to petrophysical measurements. We show that single deformation bands, deformation band zones and slip-surface cataclasites exhibit dissimilar single- and two-phase fluid flow properties. This is due to grain-size reduction being more pronounced in slip-surface cataclasites and changes in microstructure being fault-parallel for deformation bands but mostly fault-perpendicular for slip-surface cataclasites. A trend of fault rocks with low absolute permeabilities exhibiting lower relative permeabilities than more permeable rocks at the same capillary pressure is evident. © 2011 Elsevier Ltd. Source


Hossain Z.,Technical University of Denmark | Grattoni C.A.,Rock Deformation Research | Solymar M.,Chalmers University of Technology | Solymar M.,Statoil | Fabricius I.L.,Technical University of Denmark
Petroleum Geoscience | Year: 2011

Nuclear magnetic resonance (NMR) is a useful tool in reservoir evaluation. The objective of this study is to predict petrophysical properties from NMR T 2 distributions. A series of laboratory experiments including core analysis, capillary pressure measurements, NMR T 2 measurements and image analysis were carried out on sixteen greensand samples from two formations in the Nini field of the North Sea. Hermod Formation is weakly cemented, whereas Ty Formation is characterized by microcrystalline quartz cement. The surface area measured by the BET method and the NMR derived surface relaxivity are associated with the micro-porous glauconite grains. The effective specific surface area as calculated from Kozeny's equation and as derived from petrographic image analysis of backscattered electron micrograph's (BSE), as well as the estimated effective surface relaxivity, is associated with macro-pores. Permeability may be predicted from NMR by using Kozeny's equation when surface relaxivity is known. Capillary pressure drainage curves may be predicted from NMR T 2 distribution when pore size distribution within a sample is homogeneous. © 2011 EAGE/Geological Society of London. Source

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