Publications
545 results found
AlSofi AM, LaForce TC, Blunt MJ, 2009, Sweep impairment due to polymers shear thinning, Pages: 834-845
Most polymers used in EOR exhibit shear thinning behavior. At least theoretically, shear thickening will improve sweep while shear thinning (pseudoplasticity) will impair it through exacerbating the velocity contrast and/or inducing instability. Despite this, the effect of pseudoplasticity on sweep has not been studied in detail. An in-house streamline simulator has been extended to handle polymer flooding with Newtonian and non-Newtonian behavior. Three main modifications were implemented. First, the polymer mass balance was solved along the streamlines. Second, a polymer multiplier was defined to account for polymers' viscosifying and thinning effects. Finally, an iterative approach was implemented to solve the pressure field. This is needed since the pressure depends on the aqueous phase viscosity, which for non-Newtonian fluids depends on shear stress, and hence the pressure itself. The simulator was then used to investigate pseudoplasticity effects on sweep and recovery in various reservoir models. Two cases were run. The first had a stable connate bank; hence, thinning does not induce instability and the only effect is velocity exacerbation. The second had an unstable connate bank; hence, thinning can induce instability. The results of this work prove the importance of taking polymers' non-Newtonian behavior into account for the successful design and evaluation of polymer flooding projects. This is because pseudoplasticity will impair sweep, which can deteriorate the whole economic picture of a polymer flood. Even if instability is not induced, more pore volumes will be needed, more water will be produced, and in light of a limiting water cut, less oil will be recovered; in other words, higher operations costs, higher processing costs, but less profit. Simulations carried in a 2D heterogeneous model suggest that for unconditionally stable flooding, the injection requirement will double from 2 to 4 pore volumes. In addition, in light of an 80% limiting water cu
Al-Bulushi N, King PR, Blunt MJ, et al., 2009, Development of artificial neural network models for predicting water saturation and fluid distribution, JOURNAL OF PETROLEUM SCIENCE AND ENGINEERING, Vol: 68, Pages: 197-208, ISSN: 0920-4105
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- Citations: 46
Al Mansoori SK, Iglauer S, Pentland CH, et al., 2009, Three-phase measurements of oil and gas trapping in sand packs, ADVANCES IN WATER RESOURCES, Vol: 32, Pages: 1535-1542, ISSN: 0309-1708
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- Citations: 15
Dong H, Blunt MJ, 2009, Pore-network extraction from micro-computerized-tomography images, PHYSICAL REVIEW E, Vol: 80, ISSN: 1539-3755
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- Citations: 764
Talabi O, AlSayari S, Iglauer S, et al., 2009, Pore-scale simulation of NMR response, JOURNAL OF PETROLEUM SCIENCE AND ENGINEERING, Vol: 67, Pages: 168-178, ISSN: 0920-4105
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- Citations: 70
Xie C-J, Guan Z-L, Blunt M, et al., 2009, Numerical Simulation of Oil Recovery After Cross-Linked Polymer Flooding, JOURNAL OF CANADIAN PETROLEUM TECHNOLOGY, Vol: 48, Pages: 37-41, ISSN: 0021-9487
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- Citations: 8
Rhodes M E, Bijeljic B and Blunt M J, 2009, A Rigorous Pore-to-Field-Scale Methodology for Single-Phase Flow Based on Continuous Time Random Walks
Qi R, LaForce TC, Blunt MJ, 2009, Design of carbon dioxide storage in aquifers, INTERNATIONAL JOURNAL OF GREENHOUSE GAS CONTROL, Vol: 3, Pages: 195-205, ISSN: 1750-5836
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- Citations: 147
Frenkel G, Blumenfeld R, King PR, et al., 2009, Topological Analysis of Foams and Tetrahedral Structures, ADVANCED ENGINEERING MATERIALS, Vol: 11, Pages: 169-176, ISSN: 1438-1656
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- Citations: 13
Iglauer S, Wülling W, Pentland CH, et al., 2009, Capillary trapping capacity of rocks and sandpacks, Pages: 1889-1898
We quantify the influence of the initial non-wetting phase saturation and porosity on the residual non-wetting phase saturation based on data in the literature and our own experimental results from sandpacks and consolidated rocks. The principal application of this work is for carbon capture and storage (CCS) where capillary trapping is a rapid and effective way to render the injected CO<inf>2</inf> immobile, guaranteeing safe storage. We introduce the concept of capillary trapping capacity (C<inf>trap</inf>) which is the product of residual saturation and porosity that represents the fraction of the rock volume that can be occupied by a trapped non-wetting phase. We propose empirical fits to the data to correlate trapping capacity and residual saturation to porosity and initial saturation. We show that trapping capacity reaches a maximum of approximately 7% for rock porosities of 20%, which suggests an optimal porosity for CO<inf>2</inf>storage. Copyright 2009, Society of Petroleum Engineers. Copyright 2009, European Association of Geoscientists and Engineers.
AlSofi AM, Blunt MJ, 2009, Streamline-based simulation of non-Newtonian polymer flooding, Pages: 594-607
Current commercial simulators for polymer flooding often make physical assumptions that are not consistent with available experimental data and pore-scale modeling predictions. This may lead to overly optimistic recovery predictions for shear-thinning polymers, while overlooking the potential advantages of reducing flow rate or using shear-thickening agents. We develop a streamline-based simulator that overcomes these limitations and demonstrate how it can be used to design polymer flooding projects. The simulator implements an iterative approach to solve the pressure field since the pressure depends on the aqueous phase viscosity which in turn - for non-Newtonian fluids - depends on shear stress and hence the pressure gradients. This is in contrast to the common approach in commercial simulators where this viscosity-pressure interdependence is ignored, leading to over-estimation of sweep efficiency. Furthermore, in the simulator, non-Newtonian viscosities are defined to be cell-centered while current simulators use a face-approach thereby over-predicting viscosities as well as the stability of the displacing fronts. In addition, we use a physically-based rheological model where non-Newtonian viscosities in two-phase flow are taken at actual effective stresses instead of single-phase equivalents. To validate the simulator, we construct one-dimensional analytical solutions for waterflooding with a non-Newtonian fluid. We then compare our results to those from commercial simulators. We discuss the significance of current assumptions to demonstrate the impact of non-Newtonian behavior on sweep efficiency and recovery. Copyright 2009, Society of Petroleum Engineers.
Rhodes ME, Bijeljic B, Blunt MJ, 2009, A rigorous pore-to-field-scale simulation method for single-phase flow based on continuous-time random walks, SPE Journal, Vol: 14, Pages: 88-94, ISSN: 1086-055X
We propose a pore-to-reservoir simulation approach for single-phase flow. Transport is modeled as a continuous-time random walk (CTRW). Particles make a series of transitions between nodes with a probability ψ(t)dt that a particle will first arrive at a node from a nearest neighbor in a time t to t+dt. A top-down multiscale approach is used to find the flow field. At the micron scale, ψ(t) for particle transitions from pore to pore are found from modeling advection and molecular diffusion in a geologically representative network model. This ψ(t) is used to compute transport on the millimeter-to-centimeter scale. At larger scales, we represent the reservoir as a network of nodes connected by links. For each node-to-node transition, we compute an upscaled ψ(t) from a simulation of transport at the smaller scale. We account for small-scale uncertainty by interpreting ψ(t) probabilistically and running simulations for different possible realizations of the reservoir model. To make the number of computations manageable, ψ(t) is parameterized in terms of subscale heterogeneity and Péclet number, meaning that only a few representative simulations are required. We apply this method by finding ψ(t) for pore-scale flow and using it in a million-cell reservoir model. We show that the macroscopic behavior can be very different from that predicted by assuming that the advection/dispersion equation (ADE) operates at the small scale. Small-scale structure does affect macroscopic transport; increasing the pore-level heterogeneity delays breakthrough and leads to longer late-time tails of the production because the solute spends more time in slow-flowing regions of the domain. We discuss extensions to multiphase flow and the development of a novel network-based probabilistic reservoir-simulation approach. Copyright © 2009 Society of Petroleum Engineers.
Iglauer S, Wülling W, Pentland CH, et al., 2009, Capillary trapping capacity of rocks and sandpacks
We quantify the influence of the initial non-wetting phase saturation and porosity on the residual non-wetting phase saturation based on data in the literature and our own experimental results from sandpacks and consolidated rocks. The principal application of this work is for carbon capture and storage (CCS) where capillary trapping is a rapid and effective way to render the injected CO2 immobile, guaranteeing safe storage. We introduce the concept of capillary trapping capacity (Ctrap) which is the product of residual saturation and porosity that represents the fraction of the rock volume that can be occupied by a trapped non-wetting phase. We propose empirical fits to the data to correlate trapping capacity and residual saturation to porosity and initial saturation. We show that trapping capacity reaches a maximum of approximately 7% for rock porosities of 20%, which suggests an optimal porosity for CO2 storage.
Muller N, Qi R, Mackie E, et al., 2009, CO<sub>2</sub> injection impairment due to halite precipitation, 9th International Conference on Greenhouse Gas Control Technologies, Publisher: ELSEVIER SCIENCE BV, Pages: 3507-3514, ISSN: 1876-6102
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- Citations: 100
Belayneh M, Matthai SK, Blunt MJ, et al., 2009, Comparison of deterministic with stochastic fracture models in water-flooding numerical simulations, AAPG Bulletin, Vol: 93, Pages: 1633-1648
Garcia X, Lateef A, Blunt M, et al., 2009, Numerical study of the effects of particle shape and polydispersity on permeability, Physics Review E, Vol: 80
We study through numerical simulations the dependence of the hydraulic permeability of granular materials on the particle shape and the grain size distribution. Several models of sand are constructed by simulating the settling under gravity of the grains; the friction coefficient is varied to construct packs of different porosity. The size distribution and shapes of the grains mimic real sands. Fluid flow is simulated in the resulting packs using a finite element method and the permeability of the packs is successfully compared with available experimental data. Packs of nonspherical particles are less permeable than sphere packs of the same porosity. Our results indicate that the details of grain shape and size distribution have only a small effect on the permeabilty of the systems studied.
Al-Mansoori S, Iglauer S, Pentland CH, et al., 2009, Three-Phase Measurements of Non-Wetting Phase Trapping in Unconsolidated Sand Packs, 2009 Annual Technical SPE Conference
Talabi O, Alsayari S, Blunt MJ, et al., 2008, Predictive pore-scale modeling: From three-dimensional images to multiphase flow simulations, Pages: 1464-1476
We demonstrate and validate predictive pore-scale modeling: we start with three-dimensional images of small rock samples obtained using micro-CT scanning with a resolution of a few microns, extract networks from these images and then predict multiphase flow properties by simulating capillary-controlled displacement. We study two sand packs, a poorly consolidated sandstone, Berea sandstone and a carbonate. Single-phase flow properties can be computed on a binarized image directly: we calculate the absolute permeability, resistivity and NMR response. We also extract topologically equivalent networks of pores and throats using a maximal ball method. As a quality control we compare single-phase predictions on these networks with those obtained on the images and from experiment: the permeability and NMR response are similar although we tend to underestimate the resistivity. Networks representing consolidated media tend to over-estimate the magnetization decay in an NMR experiment. We then compute multiphase properties, including capillary pressure, relative permeability and NMR response as a function of wettability (the contact angle distribution assigned to pores and throats). Experimental data, where available, is used to validate our predictions; where we know the wettability and pore structure, we are able to predict multiphase flow properties accurately. We show how relative permeability and capillary pressure is affected by rock type - principally the coordination number of the pores and the pore size distribution - and wettability. We suggest that predictive pore-scale modeling combined with micro-CT imaging is a useful tool, complementary to special core analysis, for the determination of single and multiphase flow properties. Copyright 2008, Society of Petroleum Engineers.
Rhodes ME, Bijeljic B, Blunt MJ, 2008, Pore-to-field simulation of single-phase transport using continuous time random walks, ADVANCES IN WATER RESOURCES, Vol: 31, Pages: 1527-1539, ISSN: 0309-1708
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- Citations: 46
Al Rabaani A, Blunt M, Muggeridge A, 2008, Calculation of a Critical Steam Injection Rate for Thermally-Assisted Gas-Oil Gravity Drainage, SPE IOR Symposium
Pentland CH, Iglauer S, Al-Mansoori S, et al., 2008, Measurement of non-wetting phase trapping in sand packs, Denver, SPE Annual Technical Conference and Exhibition 2008, Publisher: Society of Petroleum Engineers
Spiteri EJ, Juanes R, Blunt MJ, et al., 2008, A new model of trapping and relative permeability hysteresis for all wettability characteristics, SPE JOURNAL, Vol: 13, Pages: 277-288, ISSN: 1086-055X
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- Citations: 151
Lu H, Di Donato G, Blunt MJ, 2008, General transfer functions for multiphase flow in fractured reservoirs, SPE JOURNAL, Vol: 13, Pages: 289-297, ISSN: 1086-055X
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- Citations: 39
Al-Kharusi AS, Blunt MJ, 2008, Multiphase flow predictions from carbonate pore space images using extracted network models, WATER RESOURCES RESEARCH, Vol: 44, ISSN: 0043-1397
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- Citations: 40
Suicmez VS, Piri M, Blunt MJ, 2008, Effects of wettability and pore-level displacement on hydrocarbon trapping, ADVANCES IN WATER RESOURCES, Vol: 31, Pages: 503-512, ISSN: 0309-1708
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- Citations: 43
Sochi T, Blunt MJ, 2008, Pore-scale network modeling of Ellis and Herschel-Bulkley fluids, JOURNAL OF PETROLEUM SCIENCE AND ENGINEERING, Vol: 60, Pages: 105-124, ISSN: 0920-4105
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- Citations: 72
Qi R, LaForce TC, Blunt MJ, 2008, Design of carbon dioxide storage in oilfields, Pages: 1730-1741
We extend our study of the design of carbon dioxide, CO2, storage in aquifers (Qi et al., 2007) to oilfields. We demonstrate that pore-scale capillary trapping is an effective and rapid mechanism to render the CO2 immobile in oil reservoirs. We construct analytical solutions to the transport equations, accounting for relative permeability hysteresis. We use this to design an injection strategy where CO2 and brine are injected simultaneously followed by chase brine injection. We study field-scale oil production and CO2 storage using a streamline-based simulator that captures dissolution, dispersion, gravity and rate-limited reactions in three dimensions. While injecting at the optimum WAG ratio gives the fastest oil recovery, this allows CO2 to channel through the reservoir leading to rapid CO2 breakthrough and extensive recycling of the gas. We propose to inject more water than optimum. This allows to CO2 to remain in the reservoir, increases the field life and leads to improved storage of CO2 as a trapped phase. A short period of chase brine injection at the end of the process traps most of the remaining CO2. Copyright 2008, Society of Petroleum Engineers.
Idowu NA, Blunt MJ, 2008, Pore-scale modeling of rate effects in waterflooding, Pages: 1183-1198
We first present a new method to generate stochastic random networks representing the pore space of different rocks with given input pore and throat size distributions and connectivity - these distributions can be obtained from an analysis of pore-space images. The stochastic networks can be arbitrarily large and hence are not limited by the size of the original image. We then develop a rate-dependent network model that accounts for viscous forces by solving for the wetting and non-wetting phase pressure and which allows wetting layer swelling near an advancing flood front. We propose a new time-dependent algorithm by accounting for partial filling of elements. We use the model to study the effects of capillary number (Ncap, the ratio of viscous forces to capillary forces), mobility ratio (M) and network size on imbibition displacement patterns and saturation profiles. By employing large networks we reproduce Buckley-Leverett profiles directly from pore-scale modelling thereby providing a bridge between pore-scale and macro-scale transport. We show how capillary and viscous forces act over different length scales and how this behaviour can be incorporated into averaged mathematical models of the flow. ©2008,Internation Petroleum Tecnology Conference.
Unsal E, Lu H, Matthai SK, et al., 2008, A fracture-only reservoir simulator with physically transfer functions, Pages: 2378-2382
We propose a simulation methodology that combines the strengths of discrete fracture models with conventional dual porosity simulation. Constructing a grid and solving for flow in both fracture and matrix in a discrete fracture model is frequently so computationally demanding that only small systems can be studied. In contrast, while dual porosity models are more computationally efficient and can be applied at the field scale, they average the fracture properties and the transfer of fluids between fracture and matrix. In our approach we capture the complex geometry and connectivity of the fractures through explicit gridding of the fracture network. However, to avoid the prohibitive computational cost associated with gridding both the fracture and the matrix, we apply transfer functions to accommodate the flow of fluids between these two domains. We use a physically-based approach to modeling the transfer that overcomes many of the limitations of current formulations. The model is based on CSMP, an object-oriented discrete fracture simulator. We validate the method through comparison with one-dimensional analytical solutions and comparison with experiments and simulations where both fracture and matrix are represented. We then present three-dimensional simulations of multiphase flow in a geologically realistic fracture network.
Beraldo VT, Blunt MJ, Schiozer DJ, 2008, Compressible streamline-based simulation with changes in oil composition, Pages: 2833-2843
There are several oil fields offshore Brazil with horizontal oil density variations. API tracking, that is available in some commercial finite difference simulators, can deal with such cases by allowing definition of an initial oil gravity distribution and tracking variations of oil density, due to the movement of oil. Streamline-based simulators can be much faster than conventional finite difference simulators when applied to large and heterogeneous models. However, this approach is most accurate and efficient when it is assumed that the rock and fluids are incompressible. In previous work (Beraldo et al, 2007), we presented an incompressible formulation for streamline simulation with an API Tracking option using two components in the oleic phase. This paper presents a compressible formulation for streamlines that also considers API tracking. It extends the work of Cheng et al. (2006) and Osako and Datta-Gupta (2007) by consistently accounting for flux of mass and volume along streamlines. We describe how mass and volume can be mapped between the underlying grid and streamlines to minimize mass balance errors and how consideration of cumulative volume in a streamline can substitute for time-of-flight. The method was implemented in a three-dimensional two-phase streamline-based simulator. Tests based on a Brazilian oilfield model and on the SPE10th Comparative Case demonstrate that the implementation can reproduce the results of a conventional simulator, while being substantially faster for finely-resolved models, even when compressibility is significant. Copyright 2008, Society of Petroleum Engineers.
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