Publications
542 results found
Okabe H, Blunt MJ, 2007, Pore space reconstruction of vuggy carbonates using microtomography and multiple-point statistics, WATER RESOURCES RESEARCH, Vol: 43, ISSN: 0043-1397
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- Citations: 134
Bijeljic B, Blunt MJ, 2007, Pore-scale modeling of transverse dispersion in porous media, WATER RESOURCES RESEARCH, Vol: 43, ISSN: 0043-1397
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- Citations: 106
Al-Kharusi AS, Blunt MJ, 2007, Network extraction from sandstone and carbonate pore space images, JOURNAL OF PETROLEUM SCIENCE AND ENGINEERING, Vol: 56, Pages: 219-231, ISSN: 0920-4105
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- Citations: 192
Di Donato G, Lu H, Tavassoli Z, et al., 2007, Multirate-transfer dual-porosity Modeling of gravity drainage and imbibition, SPE JOURNAL, Vol: 12, Pages: 77-88, ISSN: 1086-055X
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- Citations: 46
Suicmez VS, Piri M, Blunt MJ, 2007, Pore-scale simulation of water alternate gas injection, TRANSPORT IN POROUS MEDIA, Vol: 66, Pages: 259-286, ISSN: 0169-3913
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- Citations: 27
Lu H, Blunt MJ, 2007, General fracture/matrix transfer functions for mixed-wet systems, Pages: 3349-3355
We extend a model of fracture/matrix transfer in dual porosity and dual permeability systems to mixed-wet media, where there can be displacement due to imbibition when the capillary pressure is positive combined with gravity drainage. This can lead to a characteristic recovery curve from the matrix, with a period of rapid imbibition followed by slower recovery as buoyancy overcomes capillary forces. We refine a current general transfer function model (Lu et al., 2006) to accommodate such cases by including transfer due to horizontal and vertical displacement separately. The model is tested against fine-grid simulation in one and two dimensions and accurate predictions are made in all cases; in contrast the conventional Kazemi et al. (1976) model gives poor predictions of rate and ultimate recovery. Copyright 2007, Society of Petroleum Engineers.
Verre F, Blunt MJ, Morrison AK, et al., 2007, Applicability of water shut-off treatment for horizontal wells in heavy oil reservoirs, Pages: 2178-2188
The applicability of water shut-off treatment for horizontal wells in heavy oil reservoirs is analyzed in this study considering two different treatments: inorganic gel and relative permeability modifier (RPM). In the first part of this paper, a general description of heavy oil reservoirs behavior is given, investigating the suitability of the treatment for this type of reservoir. The analysis is then applied to a real case, the Captain field. Captain is a heavy oil, largely homogeneous reservoir exploited with horizontal wells. Due to the presence of many production wells with high water cut, it has been considered a candidate for a water shut-off pilot project. Six different scenarios in a simulation study were considered with the reservoir properties of Captain in order to test the effectiveness of the treatment on production wells. These are typical producer/injector configurations found in a heavy oil field exploited with horizontal wells. The aim is to analyze different water production mechanisms and evaluate the effectiveness of the treatment under different reservoir conditions. The influence of injection rate, oil viscosity, treatment of the injector and polymer adsorption were also investigated. The study showed that the water production mechanism has a strong influence on the effectiveness of water shut-off treatment. In particular, water coning in heavy oil reservoirs can be effectively treated with gel if it is applied to the entire section of the well. Noteworthy is the effect of permeability variations: with lower k <inf>v</inf>/k<inf>h</inf> ratios it is possible to achieve a preferential path for treatment injection delaying effectively the water coming from a lateral injector/aquifer rather than from the water cone. Polymer adsorption has a negative influence on performance for high permeable zones. The treatment is not effective for low water cut wells, low oil viscosities and it is not suitable for injection wells. Copyri
Xie C, Guan Z, Blunt M, et al., 2007, Numerical simulation of oil recovery after cross-linked polymer flooding
Cross-linked polymer flooding can increase oil recovery 10-20% over conventional water flooding, while using a lower concentration of polymer than conventional polymer flooding. Based on production data from a developed oil field, the average incremental oil recovery by polymer flooding is only 10% indicating that much of the oil is bypassed. We need to know how this bypassed oil is distributed to design an optimal development strategy. Numerical simulations have been performed to study the mechanisms of polymer flooding. For the coarsening downward sedimentary cycle, the simulation model was divided into 5 layers with average geometric permeabilities of 100md, 300md, 500md, 980md, and 2190md respectively. Five spot well pattern with 180m distance between each injector and producer has been used. The injecting well was controlled by injection rate of 100m3/d, and shut down as the water ratio reached 98%. Crosslinked polymer injection was introduced after the water cut was as high as 90%, and stopped as the water cut reached 98%. It was found that most of the residual oil after polymer flooding existed in small areas far away from the diagonal line for heterogeneous reservoirs, and in layers with low or intermediate permeabilities for cycle reservoirs.
Xie C, Guan Z, Blunt M, et al., 2007, Numerical simulation of oil recovery after cross-linked polymer flooding
© 2007 Petroleum Society of Canada. Cross-linked polymer flooding can increase oil recovery 10-20% over conventional water flooding, while using a lower concentration of polymer than conventional polymer flooding. Based on production data from a developed oil field, the average incremental oil recovery by polymer flooding is only 10% indicating that much of the oil is bypassed. We need to know how this bypassed oil is distributed to design an optimal development strategy. Numerical simulations have been performed to study the mechanisms of polymer flooding. For the coarsening downward sedimentary cycle, the simulation model was divided into 5 layers with average geometric permeabilities of 100md, 300md, 500md, 980md, and 2190md respectively. Five spot well pattern with 180m distance between each injector and producer has been used. The injecting well was controlled by injection rate of 100m3/d, and shut down as the water ratio reached 98%. Crosslinked polymer injection was introduced after the water cut was as high as 90%, and stopped as the water cut reached 98%. It was found that most of the residual oil after polymer flooding existed in small areas far away from the diagonal line for heterogeneous reservoirs, and in layers with low or intermediate permeabilities for cycle reservoirs.
Beraldo VT, Blunt MJ, Schiozer DJ, et al., 2007, Streamline simulation with an API tracking option, Pages: 1038-1045
There are several offshore oil fields where vertical and horizontal density variations can be found. In order to study this type of reservoir, conventional Black-Oil simulators with an option called API Tracking have been used. This option allows one to define a three-dimensional oil density distribution at the beginning of the simulation and track its variations due movement of oil in the reservoir. Streamline-based simulators can be much faster than conventional finite difference simulators when applied to large and heterogeneous models, which are exactly the most likely to have initial oil property variations. However, current streamline simulators don't have the API Tracking option and can only consider oil with uniform gravity throughout the reservoir. In this work, a 3D incompressible streamline simulator has been modified in order to model oil composition variations, like conventional simulators with API Tracking, keeping the advantages of the streamline method. Mathematically, this option is similar to considering miscible gas injection; this method could also be used to study injection and geological storage of CO2, for instance. To validate this work, comparisons were made between streamline and grid-based simulators. We analyzed saturation distributions and simulation run time using a fine-grid reservoir description, based on the SPE 10 model that represents a North Sea field. The results showed that API tracking can be used with streamline simulators with all the advantages of the method, including reduced run time in relation to conventional simulation, while giving similar results. Copyright 2007, Society of Petroleum Engineers.
Qi R, Beraldo V, LaForce T, et al., 2007, Design of carbon dioxide storage in a north sea aquifer using streamline-based simulation, Pages: 1409-1415
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- Citations: 31
Dong H, Touati M, Blunt MJ, 2007, Pore network modeling: Analysis of pore size distribution of arabian core samples, Pages: 518-522
We use X-ray microtomography (micro-CT) to image rock cuttings of poorly consolidated sandstone and vuggy carbonate from Saudi Arabian oil and gas fields. The cuttings are a few mm across and are imaged to a resolution between 3 and 12 microns. The details of the three-dimensional pore space can be clearly seen. A maximal ball algorithm is used to extract a topologically equivalent pore network: the largest inscribed spheres in the pore space represent pores, with throats representing the connections between them. The results are validated through comparison with networks derived by a different method from idealized sphere packings and Fontainebleau sandstone. The aim of this work is to input the models into pore-scale network models to predict macroscopic properties such as relative permeability and capillary pressure. This acts as a valuable complement to special core analysis, enabling predictions of properties - such as three-phase relative permeabilities and the impact of wettability trends - outside the range of parameters probed experimentally. Furthermore, using microtomography, rock cuttings can be analyzed that are too small for conventional core flood experiments. Copyright 2007, Society of Petroleum Engineers.
Rhodes ME, Blunt MJ, 2007, Advective transport in percolation clusters, PHYSICAL REVIEW E, Vol: 75, ISSN: 2470-0045
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- Citations: 6
Juanes R, Spiteri EJ, Orr FM, et al., 2006, Impact of relative permeability hysteresis on geological CO<sub>2</sub> storage, WATER RESOURCES RESEARCH, Vol: 42, ISSN: 0043-1397
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- Citations: 591
Lu H, Di Donato G, Blunt MJ, 2006, General transfer functions for multiphase flow, Pages: 2342-2349
We propose a physically-motivated formulation for the matrix-fracture transfer function in dual permeability and dual porosity reservoir simulation. The current Barenblatt-Kazemi approach uses a Darcy-like flux from matrix to fracture, assuming a quasi steady-state between the two domains. However, this does not correctly represent the average transfer rate in a dynamic displacement. Based on one-dimensional analytical analyses in the literature we find expressions for the transfer rate accounting for both displacement and fluid expansion. The resultant transfer function is a sum of two terms: a saturation-dependent term representing displacement and a pressure-dependent term representing fluid expansion. The expression reduces to the Barenblatt form for single-phase flow at late times, but more accurately captures the pressure-dependence at early times. For displacement we consider both imbibition and gravity drainage processes. The transfer function is validated through comparison with one-dimensional fine-grid simulations and compared with predictions using the traditional Kazemi et al.3 formulation. We show that our method captures the dynamics of expansion and displacement accurately, giving better predictions than current models, while being numerically more stable. Copyright 2006, Society of Petroleum Engineers.
FAYERS FJ, BLUNT MJ, CHRISTIE MA, 2006, ACCURATE CALIBRATION OF EMPIRICAL VISCOUS FINGERING MODELS, REVUE DE L INSTITUT FRANCAIS DU PETROLE, Vol: 46, Pages: 311-&, ISSN: 0020-2274
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- Citations: 5
Di Donato G, Tavassoli Z, Blunt MJ, 2006, Analytical and numerical analysis of oil recovery by gravity drainage, JOURNAL OF PETROLEUM SCIENCE AND ENGINEERING, Vol: 54, Pages: 55-69, ISSN: 0920-4105
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- Citations: 28
Bijeljic B, Blunt M J, 2006, A Physically-based Description of Dispersion in Porous Media, Annual Technical Conference of the Society of Petroleum Engineers
Juanes R, Blunt MJ, 2006, Analytical solutions to multiphase first-contact miscible models with viscous fingering, TRANSPORT IN POROUS MEDIA, Vol: 64, Pages: 339-373, ISSN: 0169-3913
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- Citations: 20
Rhodes ME, Blunt MJ, 2006, An exact particle tracking algorithm for advective-dispersive transport in networks with complete mixing at nodes, WATER RESOURCES RESEARCH, Vol: 42, ISSN: 0043-1397
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- Citations: 15
Obi EOI, Blunt MJ, 2006, Streamline-based simulation of carbon dioxide storage in a North Sea aquifer, WATER RESOURCES RESEARCH, Vol: 42, ISSN: 0043-1397
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- Citations: 69
Bijeljic B, Blunt MJ, 2006, Pore-scale modeling and continuous time random walk analysis of dispersion in porous media, WATER RESOURCES RESEARCH, Vol: 42, ISSN: 0043-1397
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- Citations: 177
Behbahani HS, Di Donato G, Blunt MJ, 2006, Simulation of counter-current imbibition in water-wet fractured reservoirs, JOURNAL OF PETROLEUM SCIENCE AND ENGINEERING, Vol: 50, Pages: 21-39, ISSN: 0920-4105
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- Citations: 83
Juanes R, Blunt MJ, 2006, Impact of viscous fingering on the prediction of optimum WAG ratio, Pages: 598-609
In miscible flooding, injection of solvent is often combined with water in an attempt to reduce the mobility contrast between injected and displaced fluids, and control the degree of fingering. Using traditional fractional flow theory, Stalkup estimated the optimum water-solvent ratio (or WAG ratio) when viscous fingering effects are ignored, by imposing that the solvent and water fronts travel at the same speed. Here we study how the displacement efficiency and the mobility ratio across the solvent front vary with the WAG ratio, when fingering is included in the analysis. We do so by computing analytical solutions to a one-dimensional model of two-phase, three-component, first-contact miscible flow that includes the macroscopic effects of viscous fingering. The macroscopic model, originally proposed by Blunt and Christie, employs an extension of the Koval fingering model to multiphase flows. The premise is that the only parameter of the model - the effective mobility ratio - must be calibrated dynamically until self-consistency is achieved between the input value and the mobility contrast across the solvent front. This model has been extensively validated by means of high-resolution simulations that capture the details of viscous fingering and carefully-designed laboratory experiments. The results of this paper suggest that, while the prediction of the optimum WAG ratio does not change dramatically by incorporating the effects of viscous fingering, it is beneficial to inject more solvent than estimated by Stalkup's method. We show that, in this case, both the PVI for complete oil recovery and the degree of fingering are minimized. Copyright 2006, Society of Petroleum Engineers, Inc.
Suicmez VS, Piri M, Blunt MJ, 2006, Pore-scale modeling of three-phase WAG injection: Prediction of relative permeabilities and trapping for different displacement cycles, Pages: 61-74
We use a three-dimensional mixed-wet random network model representing Berea sandstone to compute displacement paths and relative permeabilities for water alternating gas (WAG) flooding. First we reproduce cycles of water and gas injection observed in previously published experimental studies. We predict the measured oil, water and gas relative permeabilities accurately. We discuss the hysteresis trends in the water and gas relative permeabilities and compare the behavior of water-wet and oil-wet media. We interpret the results in terms of pore-scale displacements. In water-wet media the water relative permeability is lower in the presence of gas during waterflooding due to an increase in oil/water capillary pressure that causes a decrease in wetting layer conductance. The gas relative permeability is higher for displacement cycles after first gas injection at high gas saturation due to cooperative pore filling, but lower at low saturation due to trapping. In oil-wet media, the water relative permeability remains low until water-filled elements span the system at which point the relative permeability increases rapidly. The gas relative permeability is lower in the presence of water than oil because it is no longer the most non-wetting phase. We show how to use network modeling to develop a physically-based empirical model for three-phase relative permeability. We demonstrate that the relative permeabilities are approximately independent of saturation path when plotted as a function of flowing saturation. The flowing saturation is the saturation minus the amount that is trapped. The amount of oil and gas that is trapped shows a surprising trend with wettability - weakly water-wet media show more trapping of oil and gas than a water-wet system due to the complex competition of different three-phase displacement processes. Further work is needed to explore the full range of behavior as a function of wettability and displacement path. Copyright 2006. Society of Petroleu
Rotondi M, Nicotra G, Godi A, et al., 2006, Hydrocarbon production forecast and uncertainty quantification: A field application, Pages: 1040-1048
Realistic reservoir models are essential for efficient field management and accurate forecasting of hydrocarbon production. Such models, based on the physical description of the reservoir, need to be calibrated or conditioned to historical production data. The process of incorporating dynamic data in the generation of reservoir models, known as history matching, is traditionally done by hand and is a very tedious, time-consuming procedure that, in addition, returns only one single matched model. It has been shown that the best matched model may well not be a good predictor of future performance. In this work, one of the first field applications of the Neighbourhood Algorithm (NA) is presented. The NA is a stochastic sampling algorithm that explores the parameter space, finds an acceptable ensemble of data fitting models and extracts robust information from this ensemble in a Bayesian framework. The aim is to forecast hydrocarbon production accurately and to assess the related uncertainty by means of multiple reservoir models. The NA methodology was extensively applied to an offshore gas field and compared to a previously manually matched model. The Mistral field has been producing for 6 years from 7 wells. Gas and water productions and pressure data were available and the uncertainty quantification was consistently obtained. Algorithm control parameters and objective function definition effects were investigated. The posterior probability density functions of each unknown parameter, calculated taking into account the observed production data, were evaluated. The hydrocarbon production was forecast using Bayesian inference and the economic risk estimated. The overall process was carried out with a significant time reduction compared with the previous manual approach. The results presented suggest that use of stochastic sampling techniques in a Bayesian framework may well be a valid alternative methodology to the traditional industry workflow for the uncertainty quant
Valvatne PH, Piri M, Lopez X, et al., 2005, Predictive pore-scale modeling of single and multiphase flow, Upscaling Multiphase Flow in Porous Media: From Pore to Core and Beyond, Pages: 23-41, ISBN: 9781402035135
We show how to predict flow properties for a variety of rocks using pore-scale modeling with geologically realistic networks. The pore space is represented by a topologically disordered lattice of pores connected by throats that have angular cross-sections. We successfully predict single-phase non-Newtonian rheology, and two and three-phase relative permeability for water-wet media. The pore size distribution of the network can be tuned to match capillary pressure data when a network representation of the system of interest is unavailable. The aim of this work is not simply to match experiments, but to use easily acquired data to estimate difficult to measure properties and to predict trends in data for different rock types or displacement sequences. © 2005 Springer.
Tavassol Z, Zimmerman RW, Blunt MJ, 2005, Analytic analysis for oil recovery during counter-current imbibition in strongly water-wet systems, Upscaling Multiphase Flow in Porous Media: From Pore to Core and Beyond, Pages: 173-189, ISBN: 9781402035135
We study counter-current imbibition, where a strongly wetting phase (water) displaces non-wetting phase spontaneously under the influence of capillary forces such that the non-wetting phase moves in the opposite direction to the water. We use an approximate analytical approach to derive an expression for saturation profile when the viscosity of the non-wetting phase is non-negligible. This makes the approach applicable to water flooding in hydrocarbon reservoirs, or the displacement of non-aqueous phase liquid (NAPL) by water. We find the recovery of non-wetting phase as a function of time for one-dimensional flow. We compare our predictions with experimental results in the literature. Our formulation reproduces experimental data accurately and is superior to previously proposed empirical models. © 2005 Springer.
Spiteri EJ, Juanes R, Blunt MJ, et al., 2005, Relative permeability hysteresis: Trapping models and application to geological CO<inf>2</inf> sequestration
Hysteresis in the relative permeability of the hydrocarbon phase in a two-phase system was studied. A new model of trapping and waterflood relative permeability, which is applicable for the entire range of rock wettability conditions, was proposed. The relevance of relative permeability hysteresis was evaluated for modeling geological CO2 sequestration processes, concentrating on CO2 injection in saline aquifers. In this setting, the CO2 was the nonwetting phase, and trapping of the CO2 is an essential mechanism after the injection phase, during the lateral and upward migration of the CO2 plume. A proper treatment of the nonwetting phase trapping leads to a higher estimate of the amount of CO2 that it is safe to inject. In strongly water-we media, the trapped oil saturation is high but the waterflood relative permeability may be higher than the drainage relative permeability at high oil saturations. In contrast, for strongly oil-wet media, the trapped oil saturation is low but the waterflood relative permeability decreases sharply at high oil-saturations. This is an abstract of a paper presented at the SPE Annual Technical Conference and Exhibition (Dallas, TX 10/9-12/2005).
Calabrese M, Masserano F, Blunt MJ, 2005, Simulation of physical-chemical processes during carbon dioxide sequestration in geological structures
Underground storage of CO2 is one way to reduce atmospheric releases of greenhouse gases. The sequestration of CO2 in a depleted gas reservoir was simulated, incorporating molecular diffusion between CO2 and the natural gas, dispersion, dissolution of CO2 in water, and chemical reactions of the CO2 with the aqueous phase and host rock. The key determinants of storage capacity were injection rate and purity of the gas. At high rates, the CO2 channeled through high permeability streaks giving a low storage capacity. At lower injection rates, the denser CO2 could fall to the bottom of the gas zone and dissolve in the aquifer. Geochemical reactions impacted the long-term fate of the CO2. In assessing CO2 storage, it is important to account for reservoir heterogeneity and dissolution into the aqueous phase. This is an abstract of a paper presented at the SPE Annual Technical Conference and Exhibition (Dallas, TX 10/9-12/2005).
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