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  • Conference paper
    Jacquemyn C, Melnikova Y, Jackson MD, Hampson GJ, John CMet al., 2016,

    Geologic modelling using parametric NURBS surfaces

    Most reservoir modelling/simulation workflows represent geological heterogeneity on a pillar-grid defined early in the modelling process. However, it is challenging to represent many common geological features using pillar grids: Examples include intersecting faults, recumbent folds, slumps, and non-monotonic injection structures such as salt diapirs. It is also challenging to represent multi-scale features, because the same number of pillars must be present in all layers so there is little flexibility to adjust the areal grid resolution. We present a surface-based geological modelling (SBGM) workflow that uses NURBS (Non-Uniform Rational B-Splines) surfaces to represent geological heterogeneities without reference to a pre-defined grid. The NURBS surfaces represent a broad range of heterogeneity types, including faults, fractures, stratigraphic surfaces across a range of length-scales, and boundaries between different facies or lithologies. The geological model is constructed using the NURBS surfaces and a mesh created only when required for flow simulation or other calculations. The mesh preserves the geometry of the modelled surfaces. NURBS surfaces are an efficient and flexible tool to model complex geometries and are common in many modelling and engineering disciplines; however, they are rarely used in reservoir modelling. Complex surfaces can be created using a small number of control points; modelling with NURBS surfaces is therefore computationally efficient. We report here a variety of new stochastic approaches to create geological NURBS surfaces, including (1) extrusion of spatially variable cross-sections, (2) parametric 3D geometry templates, and (3) perturbation of control points to yield similar results to some pixel-based geostatistical methods. Surface interactions, such as erosion, stacking or conforming, are enforced to ensure geological relationships are preserved and the boundary representation is watertight. We illustrate our NURBS SBGM approach

  • Conference paper
    Melnikova Y, Jacquemyn C, Osman H, Salinas P, Gorman G, Hampson GJ, Jackson MDet al., 2016,

    Reservoir modelling using parametric surfaces and dynamically adaptive fully unstructured grids

    Geologic heterogeneities play a key role in reservoir performance. Surface based geologic modeling (SBGM) offers an alternative approach to conventional grid-based methods and allows multi-scale geologic features to be captured throughout the modeling process. In SBGM, all geologic features that impact the distribution of material properties, such as porosity and permeability, are modeled as a set of volumes bounded by surfaces. Within these volumes, the material properties are constant. The surfaces have parametric, grid-free representation, which, in principle, allows for unlimited complexity, since no resolution is implied at the stage of modeling and features of any scale can be included. Surface based models are discretized only when required for numerical analysis. We report here a new automated and integrated workflow for creating and meshing stochastic, surfacebased models. Surfaces are represented through non-uniform rational B-splines (NURBS). Multiple relations between surfaces are captured through geologic rules that are translated into Boolean operations (intersection, union, subtraction). Finally, models are discretized using fully unstructured tetrahedral meshes coupled with a geometry-Adaptive sizing function that efficiently approximate complex geometries. We demonstrate the new workflow via examples of multiple erosional channelized geobodies, fault models and a fracture network. We also show finite element flow simulations of the resulting geologic models, using the Imperial College Finite Element Reservoir Simulator (IC-FERST) that features dynamic adaptive mesh optimization. Mesh adaptivity allows us to focus computational effort on the areas of interest, such as the location of water saturation front. The new approach has broad application in modeling subsurface flow.

  • Journal article
    Abushaikha AS, Blunt MJ, Gosselin OR, Pain CC, Jackson MDet al., 2015,

    Interface control volume finite element method for modelling multi-phase fluid flow in highly heterogeneous and fractured reservoirs

    , JOURNAL OF COMPUTATIONAL PHYSICS, Vol: 298, Pages: 41-61, ISSN: 0021-9991
  • Journal article
    Vinogradov J, Jackson MD, 2015,

    Zeta potential in intact natural sandstones at elevated temperatures

    , Geophysical Research Letters, Vol: 42, Pages: 6287-6294, ISSN: 1944-8007

    We report measurements of the zeta potential of natural sandstones saturated with NaCl electrolytes of varying ionic strengths at temperatures up to 150°C. The zeta potential is always negative but decreases in magnitude with increasing temperature at low ionic strength (0.01 M) and is independent of temperature at high ionic strength (0.5 M). The pH also decreases with increasing temperature at low ionic strength but remains constant at high ionic strength. The temperature dependence of the zeta potential can be explained by the temperature dependence of the pH. Our findings are consistent with published models of the zeta potential, so long as the temperature dependence of the pH at low ionic strength is accounted for and can explain the hitherto contradictory results reported in previous studies.

  • Journal article
    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.

  • Journal article
    Graham GH, Jackson MD, Hampson GJ, 2015,

    Three-dimensional modeling of clinoforms in shallow-marine reservoirs: Part 2. Impact on fluid flow and hydrocarbon recovery in fluvial-dominated deltaic reservoirs

    , AAPG Bulletin, Vol: 99, Pages: 1049-1080, ISSN: 0149-1423

    Permeability contrasts associated with clinoforms have been identified as an important control on fluid flow and hydrocarbon recovery in fluvial-dominated deltaic parasequences. However, they are typically neglected in subsurface reservoir models or considered in isolation in reservoir simulation experiments because clinoforms are difficult to capture using current modeling tools. A suite of three-dimensional reservoir models constructed with a novel, stochastic, surface-based clinoform-modeling algorithm and outcrop analog data (Upper Cretaceous Ferron Sandstone Member, Utah) have been used here to quantify the impact of clinoforms on fluid flow in the context of (1) uncertainties in reservoir characterization, such as the presence of channelized fluvial sandbodies and the impact of bed-scale heterogeneity on vertical permeability, and (2) reservoir engineering decisions, including oil production rate. The proportion and distribution of barriers to flow along clinoforms exert the greatest influence on hydrocarbon recovery; equivalent models that neglect these barriers overpredict recovery by up to 35%. Continuity of channelized sandbodies that cut across clinoform tops and vertical permeability within distal delta-front facies influence sweep within clinothems bounded by barriers. Sweep efficiency is reduced when producing at higher rates over shorter periods, because oil is bypassed at the toe of each clinothem. Clinoforms are difficult to detect using production data, but our results indicate that they significantly influence hydrocarbon recovery and their impact is typically larger than that of other geologic heterogeneities regardless of reservoir engineering decisions. Clinoforms should therefore be included in models of fluvial-dominated deltaic reservoirs to accurately predict hydrocarbon recovery and drainage patterns.

  • Journal article
    Maes J, Muggeridge AH, Jackson MD, Quintard M, Lapene Aet 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

  • Journal article
    Jackson MD, Percival JR, Mostaghiml P, Tollit BS, Pavlidis D, Pain CC, Gomes JLMA, El-Sheikh AH, Salinas P, Muggeridge AH, Blunt MJet 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

  • Journal article
    Mostaghimi P, Percival JR, Pavlidis D, Ferrier RJ, Gomes JLMA, Gorman GJ, Jackson MD, Neethling SJ, Pain CCet 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
  • Journal article
    Maes J, Muggeridge AH, Jackson MD, Quintard M, Lapene Aet al., 2015,

    Scaling heat and mass flow through porous media during pyrolysis

    , HEAT AND MASS TRANSFER, Vol: 51, Pages: 313-334, ISSN: 0947-7411
  • Conference paper
    Salinas P, Percival J, Pavlidis D, Xie Z, Gomes J, Pain C, JAckson Met al., 2015,

    A discontinuous overlapping control volume finite element method for multi-phase porous media flow using dynamic unstructured mesh optimization

    , SPE Reservoir Simulation Symposium
  • Journal article
    Su K, Latham J-P, Pavlidis D, Xiang J, Fang F, Mostaghimi P, Percival JR, Pain CC, Jackson MDet 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.

  • Journal article
    Dilib FA, Jackson MD, Zadeh AM, Aasheim R, Arland K, Gyllensten AJ, Erlandsen SMet 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
  • Book chapter
    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.

  • Conference paper
    Jackson MD, Hampson GJ, Rood D, Geiger S, Zhang Z, Sousa MC, Amorim R, Brazil EV, Samavati FF, Guimaraes LNet al., 2015,

    Rapid reservoir modeling: Prototyping of reservoir models, well trajectories and development options using an intuitive, sketch-based interface

    , Pages: 829-845

    Constructing or refining complex reservoir models at the appraisal, development, or production stage is a challenging and time-consuming task that entails a high degree of uncertainty. The challenge is significantly increased by the lack of modeling, simulation and visualization tools that allow prototyping of reservoir models and development concepts, and which are simple and intuitive to use. Conventional modeling workflows, facilitated by commercially available software packages, have remained essentially unchanged for the past decade. However, these are slow, often requiring many months from initial model concepts to flow simulation or other outputs; moreover, many model concepts, such as large scale reservoir architecture, become fixed early in the process and are difficult to retrospectively change. Such workflows are poorly suited to rapid prototyping of a range of reservoir model concepts, well trajectories and development options, and testing of how these might impact on reservoir behavior. We present a new reservoir modeling and simulation approach termed Rapid Reservoir Modeling (RRM) that allows such prototyping and complements existing workflows. In RRM, reservoir geometries that describe geologic heterogeneities (e.g. faults, stratigraphic, sedimentologic and/or diagenetic features) are modelled as discrete volumes bounded by surfaces, without reference to a predefined grid. These surfaces, and also well trajectories, are created and modified using intuitive, interactive techniques from computer visualization, such as Sketch Based Interfaces and Modeling (SBIM). Input data can be sourced from seismic, geocellular or flow simulation models, outcrop analogues, conceptual model libraries or blank screen. RRM outputs can be exported to conventional workflows at any stage. Gridding or meshing of the models within the RRM framework allows rapid calculation of key reservoir properties and dynamic behaviors linked with well trajectories and development plans.

  • Journal article
    Pavlidis D, Gomes JLMA, Salinas P, Pain CC, Tehrani AAK, Moatamedi M, Smith PN, Jones AV, Matar OKet al., 2015,

    Numerical modelling of debris bed water quenching

  • Journal article
    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
  • Journal article
    Solano JMS, Jackson MD, Sparks RSJ, Blundy Jet 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

  • Journal article
    Deveugle PEK, Jackson MD, Hampson GJ, Stewart J, Clough MD, Ehighebolo T, Farrell ME, Calvert CS, Miller JKet 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
  • Journal article
    Fitch PJR, Jackson MD, Hampson GJ, John CMet 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.

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