Publications
153 results found
Graham GH, Jackson MD, Hampson GJ, 2015, Three-dimensional modeling of clinoforms in shallow-marine reservoirs: Part 1. Concepts and application, AAPG Bulletin, Vol: 99, Pages: 1013-1047, ISSN: 0149-1423
Clinoform surfaces control aspects of facies architecture within shallow-marine parasequences and can also act as barriers or baffles to flow where they are lined by low-permeability lithologies, such as cements or mudstones. Current reservoir modeling techniques are not well suited to capturing clinoforms, particularly if they are numerous, below seismic resolution, and/or difficult to correlate between wells. At present, there are no modeling tools available to automate the generation of multiple three-dimensional clinoform surfaces using a small number of input parameters. Consequently, clinoforms are rarely incorporated in models of shallow-marine reservoirs, even when their potential impact on fluid flow is recognized.A numerical algorithm that generates multiple clinoforms within a volume defined by two bounding surfaces, such as a delta-lobe deposit or shoreface parasequence, is developed. A geometric approach is taken to construct the shape of a clinoform, combining its height relative to the bounding surfaces with a mathematical function that describes clinoform geometry. The method is flexible, allowing the user to define the progradation direction and the parameters that control the geometry and distribution of individual clinoforms. The algorithm is validated via construction of surface-based three-dimensional reservoir models of (1) fluvial-dominated delta-lobe deposits exposed at the outcrop (Cretaceous Ferron Sandstone Member, Utah), and (2) a sparse subsurface data set from a deltaic reservoir (Jurassic Sognefjord Formation, Troll Field, Norwegian North Sea). Resulting flow simulation results demonstrate the value of including algorithm-generated clinoforms in reservoir models, because they may significantly impact hydrocarbon recovery when associated with areally extensive barriers to flow.
Maes J, Muggeridge AH, Jackson MD, et al., 2015, Modelling in-situ upgrading of heavy oil using operator splitting method, Computational Geosciences, Vol: 20, Pages: 581-594, ISSN: 1573-1499
The in-situ upgrading (ISU) of bitumen and oil shale is a very challenging process to model numerically because of the large number of components that need to be modelled using a system of equations that are both highly non-linear and strongly coupled. Operator splitting methods are one way of potentially improving computational performance. Each numerical operator in a process is modelled separately, allowing the best solution method to be used for the given numerical operator. A significant drawback to the approach is that decoupling the governing equations introduces an additional source of numerical error, known as the splitting error. The best splitting method for modelling a given process minimises the splitting error whilst improving computational performance compared to a fully implicit approach. Although operator splitting has been widely used for the modelling of reactive-transport problems, it has not yet been applied to the modelling of ISU. One reason is that it is not clear which operator splitting technique to use. Numerous such techniques are described in the literature and each leads to a different splitting error. While this error has been extensively analysed for linear operators for a wide range of methods, the results cannot be extended to general non-linear systems. It is therefore not clear which of these techniques is most appropriate for the modelling of ISU. In this paper, we investigate the application of various operator splitting techniques to the modelling of the ISU of bitumen and oil shale. The techniques were tested on a simplified model of the physical system in which a solid or heavy liquid component is decomposed by pyrolysis into lighter liquid and gas components. The operator splitting techniques examined include the sequential split operator (SSO), the Strang-Marchuk split operator (SMSO) and the iterative split operator (ISO). They were evaluated on various test cases by considering the evolution of the discretization error as
Jackson MD, Percival JR, Mostaghiml P, et al., 2015, Reservoir modeling for flow simulation by use of surfaces, adaptive unstructured meshes, and an overlapping-control-volume finite-element method, SPE Reservoir Evaluation and Engineering, Vol: 18, Pages: 115-132, ISSN: 1094-6470
We present new approaches to reservoir modeling and flow simulation that dispose of the pillar-grid concept that has persisted since reservoir simulation began. This results in significant improvements to the representation of multiscale geologic heterogeneity and the prediction of flow through that heterogeneity. The research builds on more than 20 years of development of innovative numerical methods in geophysical fluid mechanics, refined and modified to deal with the unique challenges associated with reservoir simulation.Geologic heterogeneities, whether structural, stratigraphic, sedimentologic, or diagenetic in origin, are represented as discrete volumes bounded by surfaces, without reference to a predefined grid. Petrophysical properties are uniform within the geologically defined rock volumes, rather than within grid cells. The resulting model is discretized for flow simulation by use of an unstructured, tetrahedral mesh that honors the architecture of the surfaces. This approach allows heterogeneity over multiple length-scales to be explicitly captured by use of fewer cells than conventional corner-point or unstructured grids.Multiphase flow is simulated by use of a novel mixed finite-element formulation centered on a new family of tetrahedral element types, PN(DG)–PN+1, which has a discontinuous Nth-order polynomial representation for velocity and a continuous (order N +1) representation for pressure. This method exactly represents Darcy-force balances on unstructured meshes and thus accurately calculates pressure, velocity, and saturation fields throughout the domain. Computational costs are reduced through dynamic adaptive-mesh optimization and efficient parallelization. Within each rock volume, the mesh coarsens and refines to capture key flow processes during a simulation, and also preserves the surface-based representation of geologic heterogeneity. Computational effort is thus focused on regions of the model where it is most required.After valid
Mostaghimi P, Percival JR, Pavlidis D, et al., 2015, Anisotropic Mesh Adaptivity and Control Volume Finite Element Methods for Numerical Simulation of Multiphase Flow in Porous Media, MATHEMATICAL GEOSCIENCES, Vol: 47, Pages: 417-440, ISSN: 1874-8961
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- Citations: 35
Maes J, Muggeridge AH, Jackson MD, et al., 2015, Scaling heat and mass flow through porous media during pyrolysis, HEAT AND MASS TRANSFER, Vol: 51, Pages: 313-334, ISSN: 0947-7411
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- Citations: 7
Su K, Latham J-P, Pavlidis D, et al., 2015, Multiphase flow simulation through porous media with explicitly resolved fractures, Geofluids, Vol: 15, Pages: 592-607, ISSN: 1468-8123
Accurate simulation of multiphase flow in fractured porous media remains a challenge. An important problem is the representation of the discontinuous or near discontinuous behaviour of saturation in real geological formations. In the classical continuum approach, a refined mesh is required at the interface between fracture and porous media to capture the steep gradients in saturation and saturation-dependent transport properties. This dramatically increases the computational load when large numbers of fractures are present in the numerical model. A discontinuous finite element method is reported here to model flow in fractured porous media. The governing multiphase porous media flow equations are solved in the adaptive mesh computational fluid dynamics code IC-FERST on unstructured meshes. The method is based on a mixed control volume – discontinuous finite element formulation. This is combined with the PN+1DG-PNDG element pair, which has discontinuous (order N+1) representation for velocity and discontinuous (order N) representation for pressure. A number of test cases are used to evaluate the method's ability to model fracture flow. The first is used to verify the performance of the element pair on structured and unstructured meshes of different resolution. Multiphase flow is then modelled in a range of idealised and simple fracture patterns. Solutions with sharp saturation fronts and computational economy in terms of mesh size are illustrated.
Dilib FA, Jackson MD, Zadeh AM, et al., 2015, Closed-Loop Feedback Control in Intelligent Wells: Application to a Heterogeneous, Thin Oil-Rim Reservoir in the North Sea, SPE RESERVOIR EVALUATION & ENGINEERING, Vol: 18, Pages: 69-83, ISSN: 1094-6470
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- Citations: 12
Jackson MD, 2015, Tools and Techniques: Self-Potential Methods, Treatise on Geophysics: Second Edition, Pages: 261-293, ISBN: 9780444538024
The self-potential (or spontaneous potential) (SP) method comprises the passive measurement of electric potential at the ground surface and in boreholes. SP methods have a number of advantages over other geophysical techniques: They are often cheaper and quicker to implement, requiring only a pair (or more) of suitable electrodes and a high-impedance voltmeter, and data can be obtained over large regions with dense sampling in both space and time. Moreover, SP anomalies are often directly related to the process of interest, such as changes in groundwater flow, chemistry, and/or temperature. The disadvantages largely lie in interpreting the data, which can be more challenging than other geophysical techniques. Similar to gravity and magnetic methods, SP measurements are purely passive, so there is often no way of adjusting source parameters to help identify signals of interest. Moreover, SP signals arise from a variety of sources, and distinguishing these can be challenging. Traditional SP surveys for mineral exploration, and borehole SP logs, have been interpreted qualitatively or semiquantitatively; however, a new generation of inversion techniques for SP measurements are now becoming available, driven by improved understanding of the underlying physical processes and increased computing power. Furthermore, the range and number of applications of the SP methods have rapidly increased in recent years.
Leinov E, Jackson MD, 2014, Experimental measurements of the SP response to concentration and temperature gradients in sandstones with application to subsurface geophysical monitoring, JOURNAL OF GEOPHYSICAL RESEARCH-SOLID EARTH, Vol: 119, Pages: 6855-6876, ISSN: 2169-9313
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- Citations: 22
Solano JMS, Jackson MD, Sparks RSJ, et al., 2014, Evolution of major and trace element composition during melt migration through crystalline mush: Implications for chemical differentiation in the crust, American Journal of Science, Vol: 314, Pages: 895-939, ISSN: 0002-9599
We present the first quantitative model of heat, mass and both majorand trace element transport in a mush undergoing compaction that accounts forcomponent transport and chemical reaction during melt migration and which isapplicable to crustal systems. The model describes the phase behavior of binarysystems (both eutectic and solid solution), with melt and solid compositions determinedfrom phase diagrams using the local temperature and bulk composition. Traceelement concentration is also determined. The results demonstrate that componenttransport and chemical reaction generate compositional variation in both major andtrace elements that is not captured by existing geochemical models. In particular, wefind that, even for the simplest case of a homogenous, insulated column that isinstantaneously melted then allowed to compact, component transport and reactionleads to spatial variations in major element composition that, in this case, producesmelt that is more enriched in incompatible elements than predicted by batch melting.In deep crustal hot zones (DCHZ), created by the repeated intrusion of hot, mantlederivedmagmas, buoyant melt migrating upwards accumulates in high porosity layers,but has a composition corresponding to only a small fraction of batch melting, becauseit has locally equilibrated with mush at low temperature; moreover, melt migration andchemical reaction in a layered protolith may lead to the rapid formation of highporosity melt layers at the interface between different rock compositions. In both ofthese cases, the melt in the high porosity layer(s) is less enriched in incompatible traceelements than predicted if it is assumed that melt with the same major elementcomposition was produced by batch melting. This distinctive decoupling of major andtrace element fractionation may be characteristic of magmas that originate in DCHZ.Application of the model to a number of crustal systems, including the Ivrea-Verbanozone, the Rum layered intrusion, and the Hol
Deveugle PEK, Jackson MD, Hampson GJ, et al., 2014, A comparative study of reservoir modeling techniques and their impact on predicted performance of fluvial-dominated deltaic reservoirs, AAPG BULLETIN, Vol: 98, Pages: 729-763, ISSN: 0149-1423
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- Citations: 26
Fitch PJR, Jackson MD, Hampson GJ, et al., 2014, Interaction of stratigraphic and sedimentological heterogeneities with flow in carbonate ramp reservoirs: impact of fluid properties and production strategy, Petroleum Geoscience, Vol: 20, Pages: 7-26, ISSN: 1354-0793
It is well known that heterogeneities in carbonate reservoirs impact fluid flow during production. However, few studies have examined the impact of the same heterogeneities on flow behaviour with different fluid properties and production scenarios. We use integrated flow simulation and experimental design techniques to investigate the relative, first-order impact of stratigraphic and sedimentological heterogeneities on simulated recovery in carbonate ramp reservoirs. Two production strategies are compared, which promote dominance of either horizontal or vertical flow.We find that the modelled geology is more important than the simulated fluid properties and production scenarios over the ranges tested. Of the heterogeneities modelled here, rock properties and stratigraphic heterogeneities that control reservoir architecture and the spatial distribution of environment of deposition (EOD) belts are important controls on recovery regardless of the production strategy. The presence of cemented hardground surfaces becomes the key control on oil recovery in displacements dominated by vertical flow. Permeability anisotropy is of low importance for all production strategies. The impacts of stratigraphic heterogeneities on recovery factor and water breakthrough are more strongly influenced by fluid properties and well spacing in displacements dominated by vertical flow. These results help to streamline the reservoir modelling process, by identifying key heterogeneities, and to optimize production strategies.
Jackson MD, Hampson GJ, Saunders JH, et al., 2014, Surface-based reservoir modelling for flow simulation, Sediment-body geometry and heterogeneity: analogue studies for modelling the subsurface, Editors: Martinius, Howell, Good, Publisher: Geological Society of London, ISBN: 9781862393721
Dilib FA, Jackson MD, 2013, Closed-Loop Feedback Control for Production Optimization of Intelligent Wells Under Uncertainty, SPE PRODUCTION & OPERATIONS, Vol: 28, Pages: 345-357, ISSN: 1930-1855
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- Citations: 14
Legler B, Johnson HD, Hampson GJ, et al., 2013, Facies model of a fine-grained, tide-dominated delta: lower Dir Abu Lifa Member (Eocene), Western Desert, Egypt, Sedimentology, Vol: 60, Pages: 1313-1356
Existing facies models of tide-dominated deltas largely omit fine-grained, mud-rich successions. Sedimentary facies and sequence stratigraphic analysis of the exceptionally well-preserved Late Eocene Dir Abu Lifa Member (Western Desert, Egypt) aims to bridge this gap. The succession was deposited in a structurally controlled, shallow, macrotidal embayment and deposition was supplemented by fluvial processes but lacked wave influence. The succession contains two stacked, progradational parasequence sets bounded by regionally extensive flooding surfaces. Within this succession two main genetic elements are identified: non-channelised tidal bars and tidal channels. Non-channelised tidal bars comprise coarsening-upward sand bodies, including large, downcurrent-dipping accretion surfaces, sometimes capped by palaeosols indicating emergence. Tidal channels are preserved as single-storey and multilateral bodies filled by: (i) laterally migrating, elongate tidal bars (inclined heterolithic strata, 5 to 25 m thick); (ii) forward-facing lobate bars (sigmoidal heterolithic strata, up to 10 m thick); (iii) side bars displaying oblique to vertical accretion (4 to 7 m thick); or (iv) vertically-accreting mud (1 to 4 m thick). Palaeocurrent data show that channels were swept by bidirectional tidal currents and typically were mutually evasive. Along-strike variability defines a similar large-scale architecture in both parasequence sets: a deeply scoured channel belt characterised by widespread inclined heterolithic strata is eroded from the parasequence-set top, and flanked by stacked, non-channelised tidal bars and smaller channelised bodies. The tide-dominated delta is characterised by: (i) the regressive stratigraphic context; (ii) net-progradational stratigraphic architecture within the succession; (iii) the absence of upward deepening trends and tidal ravinement surfaces; and (iv) architectural relations that demonstrate contemporaneous tidal distributary channel infill and ti
Jackson MD, Gomes JLMA, Mostaghimi P, et al., 2013, Reservoir modeling for flow simulation using surfaces, adaptive unstructured meshes and control-volume-finite-element methods, Pages: 774-792
We present new approaches to reservoir modeling and flow simulation that dispose of the pillar-grid concept that has persisted since reservoir simulation began. This results in significant improvements to the representation of multi-scale geological heterogeneity and the prediction of flow through that heterogeneity. The research builds on 20+ years of development of innovative numerical methods in geophysical fluid mechanics, refined and modified to deal with the unique challenges associated with reservoir simulation. Geological heterogeneities, whether structural, stratigraphic, sedimentologic or diagenetic in origin, are represented as discrete volumes bounded by surfaces, without reference to a pre-defined grid. Petrophysical properties are uniform within the geologically-defined rock volumes, rather than within grid-cells. The resulting model is discretized for flow simulation using an unstructured, tetrahedral mesh that honors the architecture of the surfaces. This approach allows heterogeneity over multiple length-scales to be explicitly captured using fewer cells than conventional corner-point or unstructured grids. Multiphase flow is simulated using a novel mixed finite element formulation centered on a new family of tetrahedral element types, PN(DG)-PN+1, which has a discontinuous Nth-order polynomial representation for velocity and a continuous (order N+1) representation for pressure. This method exactly represents Darcy force balances on unstructured meshes and thus accurately calculates pressure, velocity and saturation fields throughout the domain. Computational costs are reduced through (i) efficient parallelization and (ii) automatic mesh adaptivity in time and space. Within each rock volume, the mesh coarsens and refines to capture key flow processes, whilst preserving the surface-based representation of geological heterogeneity. Computational effort is thus focused on regions of the model where it is most required. Having validated the approach aga
Agar S, Geiger S, Leonide P, et al., 2013, Summary of the AAPG–SPE–SEG Hedberg Research Conference on “Fundamental Controls on Flow in Carbonates”, AAPG Bulletin, Vol: 97, Pages: 533-552
A joint AAPG–Society of Petroleum Engineers–Society of Exploration Geophysicists Hedberg Research Conference was held in Saint-Cyr sur Mer, France, on July 8 to 13, 2012, to review current research and explore future research directions related to improved production from carbonate reservoirs. Eighty-seven scientists from academia and industry (split roughly equally) attended for five days. A primary objective for the conference was to explore novel connections among different disciplines (primarily within geoscience and reservoir engineering) as a way to define new research opportunities. Research areas represented included carbonate sedimentology and stratigraphy, structural geology, geomechanics, hydrology, reactive transport modeling, seismic imaging (including four-dimensional seismic, tomography, and seismic forward modeling), geologic modeling and forward modeling of geologic processes, petrophysics, statistical methods, numerical methods for simulation, reservoir engineering, pore-scale processes, in-situ flow experiments (e.g., x-ray computed tomography), visualization, and methods for data interaction.
Dilib FA, Jackson MD, Mojaddam Zadeh A, et al., 2012, Closed-loop feedback control in intelligent wells: Application to a heterogeneous, thin oil-rim reservoir in the North Sea, Pages: 2534-2550
Important challenges remain in the development of optimized control strategies for intelligent wells, particularly with respect to incorporating the impact of reservoir uncertainty. Most optimization methods are model-based and are effective only if the model or ensemble of models used in the optimization capture all possible reservoir behaviors at the individual well and completion level. This is rarely the case. Moreover, reservoir models are rarely predictive at the spatial and temporal scales required to identify control actions. We evaluate the benefit of using closed-loop control strategies, based on direct feedback between reservoir monitoring and inflow valve settings, within a geologically heterogeneous, thin oil-rim reservoir. A high-resolution sector model is used to capture reservoir heterogeneity, which incorporates a locally refined horizontal grid in the oil zone, to accurately represent the horizontal well geometry and fluid contacts, and capture water and gas flow. Two inflow control strategies are tested. The first is an open-loop approach, using fixed inflow control devices to balance the pressure drawdown along the well, sized prior to installation. The second is a closed-loop, feedback control strategy, employing variable inflow control valves that can be controlled from the surface in response to multiphase flow data obtained downhole. We find that closed-loop control yields positive gains in NPV for the majority of cases investigated, and higher gains than open-loop strategies. Closed-loop control also yields positive gains in NPV even when the reservoir does not behave as expected. Open-loop control is risky, because unpredicted reservoir behavior can lead to negative returns. Moreover, assessing the benefits of inflow control over an arbitrarily fixed well life can be misleading, as observed gains depend on when the calculation is made. Copyright 2012, Society of Petroleum Engineers.
Solano JMS, Jackson MD, Sparks RSJ, et al., 2012, Melt Segregation in Deep Crustal Hot Zones: a Mechanism for Chemical Differentiation, Crustal Assimilation and the Formation of Evolved Magmas, Journal of Petrology, Vol: 53, Pages: 1999-2026, ISSN: 1460-2415
Mantle-derived basaltic sills emplaced in the lower crust provide amechanism for the generation of evolved magmas in deep crustal hotzones (DCHZ).This study uses numerical modelling to characterizethe time required for evolved magma formation, the depth and temperatureat which magma formation occurs, and the composition ofthe magma.The lower crust is assumed to comprise amphibolite. Inan extension of previous DCHZ models, the new model couples heattransfer during the repetitive emplacement of sills with mass transfervia buoyancy-driven melt segregation along grain boundaries.The resultsshed light on the dynamics of DCHZ development and evolution.TheDCHZ comprises a mush of crystals plus interstitial melt,except when a new influx of basaltic magma yields a short-lived(20^200 years) reservoir of melt plus suspended crystals (magma).Melt segregation and accumulation within the mush yields two contrastingmodes of evolved magma formation, which operate over timescalesof c. 10 kyr-1 Myr, depending upon emplacement rate andstyle. In one, favoured by emplacement via over-accretion, or emplacementat high rates, evolved magma forms in the crust overlying theintruded basalt sills, and is composed of crustal partial melt, and residualmelt that has migrated upwards out of the crystallizingbasalt. In the other, favoured by emplacement via under- orintra-accretion, or by emplacement at lower rates, evolved magmaforms in the intruded basalt, and the resulting magma is composedprimarily of residual melt. In all cases, the upward migration ofbuoyant melt yields cooler and more evolved magmas, which arebroadly granitic in composition. Chemical differentiation is thereforedriven by melt migration, because the melt migrates through, andchemically equilibrates with, partially molten rock at progressivelylower temperatures. Crustal assimilation occurs during partial melting,and mixing of crustal and residual melt occurs when residualmelt migrates into the partially molten crust, yielding
Elsheikh AH, Jackson MD, Laforce TC, 2012, Bayesian Reservoir History Matching Considering Model and Parameter Uncertainties, MATHEMATICAL GEOSCIENCES, Vol: 44, Pages: 515-543, ISSN: 1874-8961
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- Citations: 36
Glover PWJ, Walker E, Jackson MD, 2012, Streaming-potential coefficient of reservoir rock: A theoretical model, Geophysics, Vol: 77, Pages: D17-D43, ISSN: 1942-2156
The streaming potential is that electrical potential whichdevelops when an ionic fluid flows through the pores of a rock.It is an old concept that is recently being applied in many fieldsfrom monitoring water fronts in oil reservoirs to understandingthe mechanisms behind synthetic earthquakes. We have carriedout fundamental theoretical modeling of the streaming-potentialcoefficient as a function of pore fluid salinity, pH, and temperatureby modifying the HS equation for use with porous rocksand using input parameters from established fundamental theory(the Debye screening length, the Stern-plane potential, the zetapotential, and the surface conductance). The model also requiresthe density, electrical conductivity, relative electric permittivityand dynamic viscosity of the bulk fluid, for which empiricalmodels are used so that the temperature of the model may bevaried. These parameters are then combined with parametersthat describe the rock microstructure. The resulting theoreticalvalues have been compared with a compilation of data for siliceousmaterials comprising 290 streaming-potential coefficientmeasurements and 269 zeta-potential measurements obtainedexperimentally for 17 matrix-fluid combinations (e.g., sandstonesaturated with KCl), using data from 29 publications.The theoretical model was found to ably describe the main featuresof the data, whether taken together or on a sample by samplebasis. The low-salinity regime was found to be controlled bysurface conduction and rock microstructure, and was sensitiveto changes in porosity, cementation exponent, formation factor,grain size, pore size and pore throat size as well as specific surfaceconductivity. The high-salinity regime was found to be subjectto a zeta-potential offset that allows the streaming-potentialcoefficient to remain significant even as the saturation limit isapproached
Jackson MD, Vinogradov J, 2012, Impact of wettability on laboratory measurements of streaming potential in carbonates, COLLOIDS AND SURFACES A-PHYSICOCHEMICAL AND ENGINEERING ASPECTS, Vol: 393, Pages: 86-95, ISSN: 0927-7757
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- Citations: 64
Jackson MD, Gulamali MY, Leinov E, et al., 2012, Spontaneous Potentials in Hydrocarbon Reservoirs during Waterflooding: Application to Waterfront Monitoring, SPE Journal
Jackson MD, Leinov E, 2012, On the Validity of the “Thin” and “Thick”Double-Layer Assumptions When CalculatingStreaming Currents in Porous Media, International Journal of Geophysics, Vol: 2012, ISSN: 1687-8868
We find that the thin double layer assumption, in which the thickness of the electrical diffuse layer is assumed small comparedto the radius of curvature of a pore or throat, is valid in a capillary tubes model so long as the capillary radius is >200 times thedouble layer thickness, while the thick double layer assumption, in which the diffuse layer is assumed to extend across the entirepore or throat, is valid so long as the capillary radius is >6 times smaller than the double layer thickness. At low surface chargedensity (<10 mC · m−2) or high electrolyte concentration (>0.5 M) the validity criteria are less stringent. Our results suggest thatthe thin double layer assumption is valid in sandstones at low specific surface charge (<10 mC · m−2), but may not be valid insandstones of moderate- to small pore-throat size at higher surface charge if the brine concentration is low (<0.001 M). The thickdouble layer assumption is likely to be valid in mudstones at low brine concentration (<0.1 M) and surface charge (<10 mC·m−2),but at higher surface charge, it is likely to be valid only at low brine concentration (<0.003 M). Consequently, neither assumptionmay be valid in mudstones saturated with natural brines.
Saunders JH, Jackson MD, Pain CC, et al., 2012, Streaming potentials in hydrocarbon reservoir conditions, Geophysics, Vol: 77, Pages: E77-E90
Jackson MD, Butler AP, Vinogradov J, 2012, Measurements of Spontaneous Potential in Chalk with Application to Aquifer Characterisation in the Southern UK, Quarterly Journal of Engineering Geology and Hydrogeology
Jackson MD, Vinogradov J, Saunders JH, et al., 2011, Laboratory Measurements and Numerical Modeling of Streaming Potential for Downhole Monitoring in Intelligent Wells, SPE JOURNAL, Vol: 16, Pages: 625-636, ISSN: 1086-055X
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- Citations: 7
Gulamali MY, Leinov E, Jackson MD, 2011, Self-potential anomalies induced by water injection into hydrocarbon reservoirs, GEOPHYSICS, Vol: 76, Pages: F283-F292, ISSN: 0016-8033
Gulamali MY, Leinov E, Jackson MD, 2011, Self-potential anomalies induced by water injection into hydrocarbon reservoirs, Geophysics, Vol: 76, Pages: F283-F292, ISSN: 1942-2156
The injection of cold water into a hydrocarbon reservoir containingrelatively warmer, more saline formation brine may generateself-potential anomalies as a result of electrokinetic,thermoelectric, and=or electrochemical effects. We havenumerically assessed the relative contributions of these effectsto the overall self-potential signal generated during oil productionin a simple hydrocarbon reservoir model. Our aim was todetermine if measurements of self-potential at a production wellcan be used to detect the movement of water toward the well.The coupling coefficients for the electrochemical and thermoelectricpotentials are uncertain, so we considered four differentmodels for them. We also investigated the effect of altering thesalinities of the formation and injected brines. We found thatthe electrokinetic potential peaked at the location of the saturationfront (reaching values of 0.2 mV even for the most salinebrine considered). Moreover, the value at the production wellincreased as the front approached the well, exceeding the noiselevel ( 0.1 mV). Thermoelectric effects gave rise to largerpotentials in the reservoir (10 mV), but values at the wellwere negligible ð Þ .0:1 mV until after water breakthroughbecause of the lag in the temperature front relative to the saturationfront. Electrochemical potentials were smaller in magnitudethan thermoelectric potentials in the reservoir but were measurableð Þ > 0:1 mV at the well because the salinity front wasclosely associated with the saturation front. When the formationbrine was less saline (1 mol=liter), electrokinetic effects dominated;at higher salinities (5 mol=liter), electrochemicaleffects were significant. We concluded that the measurement ofself-potential signals in a production well may be used to monitorthe movement of water in hydrocarbon reservoirs duringproduction, but further research is required to understand thethermoelectric and electrochemical coupling coefficients in partiallysatu
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