International Center for Carbonate Reservoirs

Edinburgh, United Kingdom

International Center for Carbonate Reservoirs

Edinburgh, United Kingdom
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Pak T.,University of Edinburgh | Pak T.,International Center for Carbonate Reservoirs | Pak T.,University of Teesside | Butler I.B.,University of Edinburgh | And 6 more authors.
Proceedings of the National Academy of Sciences of the United States of America | Year: 2015

Using X-ray computed microtomography, we have visualized and quantified the in situ structure of a trapped nonwetting phase (oil) in a highly heterogeneous carbonate rock after injecting a wetting phase (brine) at low and high capillary numbers. We imaged the process of capillary desaturation in 3D and demonstrated its impacts on the trapped nonwetting phase cluster size distribution. We have identified a previously unidentified pore-scale event during capillary desaturation. This pore-scale event, described as droplet fragmentation of the nonwetting phase, occurs in larger pores. It increases volumetric production of the nonwetting phase after capillary trapping and enlarges the fluid-fluid interface, which can enhance mass transfer between the phases. Droplet fragmentation therefore has implications for a range of multiphase flow processes in natural and engineered porous media with complex heterogeneous pore spaces. © 2015 PNAS.

Pak T.,University of Edinburgh | Pak T.,International Center for Carbonate Reservoirs | Butler I.B.,University of Edinburgh | Butler I.B.,International Center for Carbonate Reservoirs | And 8 more authors.
Society of Petroleum Engineers - SPE Reservoir Characterisation and Simulation Conference and Exhibition, RCSC 2013: New Approaches in Characterisation andModelling of Complex Reservoirs | Year: 2013

The physics of multi-phase displacement processes in the individual pores of a connected pore-network of a rock ultimately controls how oil, gas and water move in reservoir rocks and how readily they can be produced. These pore scale processes, including piston-like displacement, snap off, film-flow and fluid redistribution have been studied traditionally in pore-network simulations as well as in 2D micro-model experiments. However, recent advances in X-ray computed micro-tomography (CT) techniques now enable us to visualize and monitor these processes in 3D during in-situ core flooding experiments at pore-scale resolution. This provides new information on the spatial and temporal evolution of oil and water phase clusters and films. In this paper, we present results of a suite of two-phase fluid displacement experiments performed on a dolomite core plug. The experiments consist of a series of fluid injections and in-situ CT scans of the core in certain time steps during the drainage and imbibition displacement processes. The fluid phases are brine and a mineral oil. A simple, low-cost and highly X-ray transparent design for core flooding cells is introduced. Our experiments and CT images allow us to visualize the 3D fluid structures of each phase during fluid displacements in carbonate rocks with excellent clarity. Piston-like displacement and snap off mechanisms have been captured clearly in 3D. In addition, the formation, collapse and reorganisation of brine films surrounding oil blobs in individual pores were clearly visualised. However, the formation of oil films, which could provide connectivity for the hydrocarbon phase at low saturations, could not be observed in these experiments. The observed displacement processes and the particular oil-water/rock configurations seen in the displacements suggest the rock is preferentially water wet. Copyright 2013, Society of Petroleum Engineers.

Chandra V.,Heriot - Watt University | Chandra V.,International Center for Carbonate Reservoirs | Barnett A.,BG Group | Corbett P.,Heriot - Watt University | And 6 more authors.
Marine and Petroleum Geology | Year: 2015

Obtaining a fit-for-purpose rock-type classification that adequately incorporates the key depositional and diagenetic heterogeneities is a prime challenge for carbonate reservoirs. Another prevailing issue is to integrate the static and dynamic data consistently with the rock-typing scheme in order to correctly initialise the reservoir flow simulation model. This paper describes a novel near-wellbore rock-typing and upscaling approach adopted to address the crucial challenges of integrating reservoir rock-typing and simulation in carbonate reservoirs. We demonstrate this workflow through a case study for a highly heterogeneous Eocene-Oligocene limestone reservoir, Field X. Geological studies carried out in Field X suggested that the key permeability pathways are strongly related to the mechanism of reservoir porosity and permeability evolution during late-burial corrosion. The rock-typing and upscaling methodology described in this paper involves the geological-petrophysical classification of the key reservoir heterogeneities through systematic evaluation of the main paragenetic events. Associations between the depositional and late-burial corrosion features, and their impact on reservoir flow properties, were accounted for in our workflow. Employing near-wellbore rock-typing and upscaling workflow yielded consistent initialisation of the Field X reservoir simulation model and therefore improved the accuracy of fluids-in-place calculation. Subsequently, the cumulative production curves computed by the reservoir simulation model of Field X showed closer agreement to the historic production data. The revised Field X simulation model is now much better constrained to the reservoir geology and provides an improved geological-prior for history matching. © 2015 Elsevier Ltd.

Van der Land C.,University of Edinburgh | Van der Land C.,International Center for Carbonate Reservoirs | Van der Land C.,Northumbria University | Wood R.,University of Edinburgh | And 13 more authors.
Marine and Petroleum Geology | Year: 2013

Diagenesis is a major control on the distribution of porosity and permeability in carbonate rocks, and therefore impacts fluid flow in the subsurface. While changes in porosity can be directly related to diagenetic petrographic characteristics such as cement distribution and dissolution features, quantifying how these textures relate to attendant changes in permeability is more challenging. Here, we demonstrate for the first time how pore-scale models, representing typical carbonate sediments and their diagenetic histories, can be used to quantify the evolution of petrophysical properties in carbonate rocks. We generate 3D pore architecture models (i.e. the spatial distribution of solid and pores) from 2D binarized images, representing the typical textural changes of carbonate sediments following hypothetical diagenetic pathways. For each 3D rock model, we extract the pore system and convert this into a network representation that allows flow properties to be calculated. The resulting porosity and permeability evolution scenarios display several 'diagenetic tipping points' where the decrease in permeability is dramatically larger than expected for the associated decrease in porosity. The effects of diagenesis also alter the capillary entry pressures and relative permeabilities of the synthetic cases, providing trends that can be applied to real rocks. Indeed, values of porosity and absolute permeability derived from these synthetic 3D rock models are within the range of values measured from nature. Such diagenetic pathway models can be used to provide constraints on predicted flow behaviour during burial and/or uplift scenarios using 'diagenetic back-stripping' of real carbonate rocks. © 2013 Elsevier Ltd.

Hosa A.,University of Edinburgh | Hosa A.,International Center for Carbonate Reservoirs | Curtis A.,University of Edinburgh | Curtis A.,International Center for Carbonate Reservoirs | And 2 more authors.
Advances in Water Resources | Year: 2016

A common way to simulate fluid flow in porous media is to use Lattice Boltzmann (LB) methods. Permeability predictions from such flow simulations are controlled by parameters whose settings must be calibrated in order to produce realistic modelling results. Herein we focus on the simplest and most commonly used implementation of the LB method: the single-relaxation-time BGK model. A key parameter in the BGK model is the relaxation time τ which controls flow velocity and has a substantial influence on the permeability calculation. Currently there is no rigorous scheme to calibrate its value for models of real media. We show that the standard method of calibration, by matching the flow profile of the analytic Hagen-Poiseuille pipe-flow model, results in a BGK-LB model that is unable to accurately predict permeability even in simple realistic porous media (herein, Fontainebleau sandstone). In order to reconcile the differences between predicted permeability and experimental data, we propose a method to calibrate τ using an enhanced Transitional Markov Chain Monte Carlo method, which is suitable for parallel computer architectures. We also propose a porosity-dependent τ calibration that provides an excellent fit to experimental data and which creates an empirical model that can be used to choose τ for new samples of known porosity. Our Bayesian framework thus provides robust predictions of permeability of realistic porous media, herein demonstrated on the BGK-LB model, and should therefore replace the standard pipe-flow based methods of calibration for more complex media. The calibration methodology can also be extended to more advanced LB methods. © 2016 Elsevier Ltd.

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