Imperial College London

ProfessorAnnMuggeridge

Faculty of EngineeringDepartment of Earth Science & Engineering

Consul for Faculty of Engineering and the Business School
 
 
 
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Contact

 

+44 (0)20 7594 7379a.muggeridge Website

 
 
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Location

 

4.51Royal School of MinesSouth Kensington Campus

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Summary

 

Publications

Publication Type
Year
to

171 results found

Kostorz WJ, Muggeridge AH, Jackson MD, 2021, Non-intrusive reduced order modeling: Geometrical framework, high-order models, and a priori analysis of applicability, INTERNATIONAL JOURNAL FOR NUMERICAL METHODS IN ENGINEERING, Vol: 122, Pages: 2545-2565, ISSN: 0029-5981

Journal article

Andrews E, Muggeridge A, Garfi G, Jones A, Krevor Set al., 2021, Pore-Scale X-ray Imaging of Wetting Alteration and Oil Redistribution during Low-Salinity Flooding of Berea Sandstone, ENERGY & FUELS, Vol: 35, Pages: 1197-1207, ISSN: 0887-0624

Journal article

Andrews E, Muggeridge A, Jones A, Krevor Set al., 2021, Pore scale observations of wetting alteration during low salinity water flooding using x-ray micro-ct

This paper describes the first pore scale in-situ observations of wetting alteration on clays during tertiary low salinity flooding. Observations in the laboratory over a range of scales show that reducing the salinity of injected water can alter the wetting state of a rock, making it more water-wet. However, there remains a poor understanding of how this alteration impacts the distribution of fluids over the pore and pore network scale and how it leads to additional oil recovery. In this work, X-ray micro-CT scanning is used to image an unsteady state experiment of tertiary low salinity water flooding in a Berea sandstone core with an altered wettability due to exposure to crude oil. Oil was trapped heterogeneously, at a saturation of 0.62, after flooding with high salinity brine. Subsequent flooding with low salinity brine led to an oil production of three percentage points. To understand the mechanisms for this additional recovery, we characterise the wetting state of the sample using imagery of fluid-solid fractional wetting and fluid pore occupancy analysis. Pore occupancy analysis shows that there is a redistribution of oil from large pores to small pores during low salinity flooding. We observe a decrease in the solid surface area covered by the oil after low salinity flooding, consistent with a change to a less oil-wetting state. Pore by pore analysis of the mineral surface area covered by the oil shows that the wetting alteration during low salinity flooding is more significant on clays which likely control the behaviour. Whilst there was only three percentage points of additional recovery during low salinity flooding, the wetting alteration led to the redistribution of 22% of oil within the rock. The success of low salinity water flooding depends on a wetting alteration and oil mobilisation as well as a pore structure which can facilitate the production of the mobilised oil.

Conference paper

Smalley PC, Muggeridge AH, Kusuma CR, 2020, Patterns of water 87Sr/86Sr variations in oil-, gas- and water-saturated rocks: Implications for fluid communication processes, distances and timescales, Marine and Petroleum Geology, Vol: 122, Pages: 1-22, ISSN: 0264-8172

This study reviews 87Sr/86Sr depth profiles of formation waters sampled by Sr residual salt analysis (Sr RSA) from >100 oil/gas wells and research sites, including reservoirs with clastic and carbonate host rocks and with gas, oil and water as the continuous fluid phase. Globally, the water data form a smooth trend between low seawater-like 87Sr/86Sr ratios (~0.706) at shallow depths and high (~0.724) ratios in deeply buried rocks, where water-rock interaction dominates.We test the hypothesis that 87Sr/86Sr depth profiles in individual wells could be influenced by diffusional mixing processes by developing 1D diffusion mixing equations to simulate compositional patterns through time and comparing them with observed profiles. Different combinations of boundary and initial conditions generate various patterns characteristic of diffusion, including non-steady-state curves relating to incomplete mixing and steady-state patterns (such as vertical or inclined straight lines) where initial heterogeneities have fully mixed. The dataset yielded 193 occurrences of these patterns. Steady-state patterns are more common and longer in water zones, while non-steady-state patterns are more common and longer in oil and gas zones. The detection of diffusional mixing patterns in hydrocarbon-saturated rocks suggests that diffusion is active, although on average a factor of ~13–18 slower, than in comparable water-saturated rocks.Pattern generation and equilibration times were modelled for each non-steady-state pattern and compared with the time since reservoir filling with oil/gas, revealing that 90% of them could have been generated since filling, but 60% of them would already have mixed to steady state had the initial compositional heterogeneities arisen during or before reservoir filling. This is critical evidence that at least some of the initial heterogeneities must have arisen, and subsequently partially mixed, after filling; these patterns tend to be short (<40 m, usu

Journal article

Smalley PC, Muggeridge AH, Amundrud SS, Dalland M, Helvig OS, Høgnesen EJ, Valvatne P, Østhus Aet al., 2020, EOR Screening Including Technical, Operational, Environmental and Economic Factors Reveals Practical EOR Potential Offshore on the Norwegian Continental Shelf, Tulsa, Oklahoma, USA, SPE Improved Oil Recovery Conference, Publisher: Society of Petroleum Engineers

Abstract We present a novel advanced EOR screening approach, adding to an existing technical screening toolkit powerful new practical discriminators based on: (1) Operational complexity of converting existing offshore fields to new EOR processes; (2) Environmental acceptability of each EOR process, given current field configuration; (3) Commercial attractiveness and competitiveness. We apply the new approach to 14 EOR processes across 85 reservoirs from 46 oilfields and discoveries on the offshore Norwegian Continental Shelf (NCS). When the operational, environmental and economic thresholds were included, 45% of the technical opportunities were screened out, and the overall potential recovery increment was ~280 MSm3 (million standard cubic metres), the top processes being HC miscible, low salinity/polymer, low salinity, CO2 miscible, gels. Excluding environmental factors (i.e., assuming environmental issues could be solved by new technologies), the increment is ~340 MSm3, indicating a ~60 MSm3 prize for research into environmentally benign EOR methods. The economic thresholds used here were intentionally set low enough to eliminate only severely commercially challenged opportunities; using higher commercially competitive thresholds would reduce the overall volumes by a further ~40 MSm3. The extension of EOR screening to include operational, environmental and economic criteria is not intended as a substitute for in-depth studies of these factors, but it should help stakeholders make earlier and better-informed decisions about selection of individual EOR opportunities for deeper study, leading to piloting and eventual field-scale deployment. Revealing the sensitivity of each EOR process to operational, environmental and economic factors will also help focus R&D onto the practical, as well as technical, barriers to EOR implementation.

Conference paper

Kostorz WJ, Muggeridge AH, Jackson MD, 2020, An efficient and robust method for parameterized nonintrusive reduced-order modeling, INTERNATIONAL JOURNAL FOR NUMERICAL METHODS IN ENGINEERING, Vol: 121, Pages: 4674-4688, ISSN: 0029-5981

Journal article

Lei Q, Jackson MD, Muggeridge AH, Salinas P, Pain CC, Matar OK, Ă…rland Ket al., 2020, Modelling the reservoir-to-tubing pressure drop imposed by multiple autonomous inflow control devices installed in a single completion joint in a horizontal well, Journal of Petroleum Science and Engineering, Vol: 189, Pages: 1-16, ISSN: 0920-4105

Autonomous inflow control devices (AICDs) are used to introduce an additional pressure drop between the reservoir and the tubing of a production well that depends on the fluid phase flowing into the device: a larger pressure drop is introduced when unwanted phases such as water or gas enter the AICD. The additional pressure drop is typically represented in reservoir simulation models using empirical relationships fitted to experimental data for a single AICD. This approach may not be correct if each completion joint is equipped with multiple AICDs as the flow at different AICDs may be different. We use high-resolution numerical modelling to determine the total additional pressure drop introduced by two AICDs installed in a single completion joint in a horizontal well. The model captures the multiphase flow of oil and water through the inner annulus into each AICD. We explore a number of relevant oil-water inflow scenarios with different flow rates and water cuts. Our results show that if only one AICD is installed, the additional pressure drop is consistent with the experimentalzly-derived empirical formulation. However, if two AICDs are present, there is a significant discrepancy between the additional pressure drop predicted by the simulator and the empirical relationship. This discrepancy occurs because each AICD has a different total and individual phase flow rate, and the final steady-state flow results from a self-organising mechanism emerging from the system. We report the discrepancy as a water cut-dependent correction to the empirical equation, which can be used in reservoir simulation models to better capture the pressure drop across a single completion containing two AICDs. Our findings highlight the importance of understanding how AICDs modify flow into production wells, and have important consequences for improving the representation of advanced wells in reservoir simulation models.

Journal article

Kampitsis AE, Adam A, Salinas P, Pain CC, Muggeridge AH, Jackson MDet al., 2020, Dynamic adaptive mesh optimisation for immiscible viscous fingering, COMPUTATIONAL GEOSCIENCES, Vol: 24, Pages: 1221-1237, ISSN: 1420-0597

Journal article

Hamid SAA, Muggeridge AH, 2020, Fingering regimes in unstable miscible displacements, Physics of Fluids, Vol: 32, Pages: 1-18, ISSN: 1070-6631

We study the life-cycle of miscible fingering, from the early fingering initiation, through their growth and nonlinear interactions to their decay to a single finger at late times. Dimensionless analysis is used to relate the number of fingers, the nature of their nonlinear interactions (spreading, coalescence, tip splitting), and their eventual decay to the viscosity ratio, transverse Peclet number, and anisotropic dispersion. We show that the initial number of fingers that grow is approximately half that predicted by analytical solutions that neglect the impact of longitudinal diffusion smearing the interface between the injected solvent and the displaced fluid. The growth rates of these fingers are also approximately one quarter that predicted by these analyses. Nonetheless, we find that the dynamics of finger interactions over time can be scaled using the most dangerous wavenumber and associated growth rate determined from linear stability analysis. This subsequently allows us to provide a relationship that can be used to estimate when predict when the late time, single finger regime will occur.

Journal article

Smalley PC, Muggeridge AH, Amundrud SS, Dalland M, Helvig OS, Høgnesen EJ, Valvatne P, Østhus Aet al., 2020, EOR screening including technical, operational, environmental and economic factors reveals practical EOR potential offshore on the norwegian continental shelf

We present a novel advanced EOR screening approach, adding to an existing technical screening toolkit powerful new practical discriminators based on: (1) Operational complexity of converting existing offshore fields to new EOR processes; (2) Environmental acceptability of each EOR process, given current field configuration; (3) Commercial attractiveness and competitiveness. We apply the new approach to 14 EOR processes across 85 reservoirs from 46 oilfields and discoveries on the offshore Norwegian Continental Shelf (NCS). When the operational, environmental and economic thresholds were included, 45% of the technical opportunities were screened out, and the overall potential recovery increment was ~280 MSm3 (million standard cubic metres), the top processes being HC miscible, low salinity/polymer, low salinity, CO2 miscible, gels. Excluding environmental factors (i.e., assuming environmental issues could be solved by new technologies), the increment is ~340 MSm3, indicating a ~60 MSm3 prize for research into environmentally benign EOR methods. The economic thresholds used here were intentionally set low enough to eliminate only severely commercially challenged opportunities; using higher commercially competitive thresholds would reduce the overall volumes by a further ~40 MSm3. The extension of EOR screening to include operational, environmental and economic criteria is not intended as a substitute for in-depth studies of these factors, but it should help stakeholders make earlier and better-informed decisions about selection of individual EOR opportunities for deeper study, leading to piloting and eventual field-scale deployment. Revealing the sensitivity of each EOR process to operational, environmental and economic factors will also help focus R&D onto the practical, as well as technical, barriers to EOR implementation.

Conference paper

Samuel JS, Muggeridge AH, 2020, Fast modelling of gas reservoirs using POD-RBF non-intrusive reduced order modelling

We demonstrate that the non-intrusive reduced order model (NIROM) based on proper orthogonal decomposition and radial basis function interpolation is capable of gas reservoir simulation predictions with computational speed-ups of at least an order of magnitude and potentially many orders of magnitude. It can estimate 3-dimensional spatial pressure and saturation distributions as well as production data for unseen gas reservoir simulation scenarios produced at constant bottom hole pressure or gas rate control. The NIROM is created from a series of training simulations performed using a commercial simulator. These simulations produce "snapshots" of the pressure and saturation distributions at equally spaced time intervals. Proper Orthogonal Decomposition (POD) is then used to project these data into a higher dimensional hyperspace. Radial basis functions (RBF) are then used to both estimate the dynamics of the system and the behaviour for unseen inputs (such as well BHP or rate). The approach is demonstrated using 3 different reservoir models, including a realistic reservoir model using data taken from the Norne field. The NIROM simulations produce satisfactory predictions when compared to a commercial simulator, provided the unseen inputs are within the range of training parameters and time scale covered by the simulation. On average, these results were obtained using 10 training runs. The overall improvement in speed is insensitive to reservoir model complexities, such as local grid refinement, water coning or the presence of aquifers. Reservoir models with significant water production require more NIROM simulation subspace vectors to estimate performance, compared with cases without water production. Furthermore, we show that although NIROM works well for constant well controls over time it is less accurate when estimating behaviour when the imposed well rate changes quickly at different times in the simulation. This is the first time that POD-RBF NIROM h

Conference paper

Tai I, Muggeridge A, Giddins MA, 2020, Modified peaceman correction for improved calculation of polymer injectivity in coarse grid numerical simulations

An improved method for calculating the injectivity of non-Newtonian polymers in finite volume, numerical simulation is presented. Non-Newtonian rheologies can significantly impact the performance of a polymer flood. This is especially important in the near wellbore region and at the start of injection. In the near well bore region velocities and shear rates are at a maximum and change rapidly with distance from the well. These effects are expected to be highest at the beginning of a polymer flood due to the near-wellbore region being saturated with more viscous oil. An analytical method for calculating the modified Peaceman pressure equivalent radius when the well block contains only polymer solution is derived and then extended to the case when the well block contains both oil and polymer solution (as occurs at early time). This is done using fractional flow theory to derive well pseudo relative permeability functions. The approach is validated by comparing the results from fine grid radial and coarse grid Cartesian simulation models. The importance of the correction is demonstrated by simulating polymer injection into a realistic field scale model of a viscous oil field. The modified Peaceman radius, combined with well pseudo relative permeabilities, significantly reduces the error when calculating the bottomhole flowing pressure in wells injecting a shear-thinning polymer solution. In the field scale simulation, with injection pressure constrained by the fracture pressure of the rock, our results show that polymer injection can be a viable technique for enhanced oil recovery in this reservoir. The new method leads to higher well injectivity and more optimistic prediction of polymer flood performance, compared to the standard Peaceman calculation used by most reservoir simulators, where non-Newtonian behaviour in the well block is unaccounted for. This paper provides a simple and accurate method to capture the impact of shear thinning behaviour on polymer injectiv

Conference paper

Zhou Y, Muggeridge AH, Berg CF, King Pet al., 2019, Effect of Layering on Incremental Oil Recovery From Tertiary Polymer Flooding, SPE RESERVOIR EVALUATION & ENGINEERING, Vol: 22, Pages: 941-951, ISSN: 1094-6470

Journal article

Abdul Hamid SA, Adam A, Jackson MD, Muggeridge AHet al., 2019, Impact of truncation error and numerical scheme on the simulation of the early time growth of viscous fingering, International Journal for Numerical Methods in Fluids, Vol: 89, Pages: 1-15, ISSN: 0271-2091

The truncation error associated with different numerical schemes (first order finite volume, second order finite difference, control volume finite element) and meshes (fixed Cartesian, fixed structured triangular, fixed unstructured triangular and dynamically adapting unstructured triangular) is quantified in terms of apparent longitudinal and transverse diffusivity in tracer displacements and in terms of the early time growth rate of immiscible viscous fingers. The change in apparent numerical longitudinal diffusivity with element size agrees well with the predictions of Taylor series analysis of truncation error but the apparent, numerical transverse diffusivity is much lower than the longitudinal diffusivity in all cases. Truncation error reduces the growth rate of immiscible viscous fingers for wavenumbers greater than 1 in all cases but does not affect the growth rate of higher wavenumber fingers as much as would be seen if capillary pressure were present. The dynamically adapting mesh in the control volume finite element model gave similar levels of truncation error to much more computationally intensive fine resolution fixed meshes, confirming that these approaches have the potential to significantly reduce the computational effort required to model viscous fingering.

Journal article

Tai I, Muggeridge A, 2019, Evaluation of empirical models for viscous fingering in miscible displacement

© 2019 European Association of Geoscientists and Engineers, EAGE. All Rights Reserved. The performance of miscible gas injection projects can be significantly affected by viscous fingering. This is further complicated by the presence of heterogeneities, as depending on the scale of the heterogeneity, there can be a diffusive, advective or channelling effect. To assess the economic feasibility of a miscible gas injection project, reservoir simulations are needed but very fine grids are required for the fingers to be modelled explicitly. This requires a large amount of computational power and time. To get around this issue, many empirical models have been proposed which model the average behaviour of the viscous fingers, allowing predictions of performance, thus reducing grid size and computational time. Many previous studies have investigated the ability of empirical models to represent fingering in line drives but none have considered flow in a quarter five spot pattern. In this study, a two phase, three component higher-order simulator is used to simulate miscible injection in square line drive and quarter five spot models, with and without heterogeneities. The results of the detailed fingering simulations were compared to the Todd & Longstaff and Fayers empirical models. To account for the effect of heterogeneities, the mixing parameter, w, in the Todd & Longstaff was adjusted using Koval's heterogeneity factor, H_k. The growth rate of the fingers, α, and the final fraction of the cross section occupied by the fingers, a+b, were adjusted in the Fayers model to account for heterogeneities and bypassed oil. The empirical models were implemented in a commercial immiscible reservoir simulator, Eclipse-100 using pseudo relative permeabilities. The detailed simulations indicate that the growth rate of the fingers varies non-linearly with mean concentration in radial flows and this is not captured by either of the empirical models. A modification of th

Conference paper

Alem M, Baig T, Muggeridge A, Jones Aet al., 2019, Predicting the performance of tight gas reservoirs

Engineers need to predict the production characteristics from hydraulically fractured wells in tight gas fields. Decline curve analysis (DCA) has been widely used over many years in conventional oil and gas fields. It is often applied to tight gas, but there is uncertainty regarding the period of production data needed for accurate prediction. In this paper decline curve analysis of simulated production data from models of hydraulically fractured wells is used to to develop improved methods for calibrating decline curve parameters from production data. The well models were constructed using data from the Khazzan field in Oman. The impact of layering, permeability and drainage area on well performance is also investigated. The contribution of each layer to recovery and the mechanisms controlling that contribution is explored. The investigation shows that increasing the amount of production data used to fit a hyperbolic decline curve does not improve predictions of recovery unless that data comes from many years (20 years for a 1mD reservoir) of production. This is because there is a long period of transient flow in tight gas reservoirs that biases the fitting and results in incorrect predictions of late time performance. Better predictions can be made by estimating the time at which boundary dominated flow is first observed (tb), omitting the preceding transient data and fitting the decline curve to a shorter interval of data starting at tb. For single layer cases, tb can be estimated analytically using the permeability, porosity, compressibility and length scale of the drainage volume associated with the well. Alternatively, tb can be determined from the production data allowing improved prediction of performance from 2-layer reservoirs provided that a) there is high crossflow or b) there is no cross-flow and the lower permeability layer either does not experience BDF during the field life time or it is established quickly.

Conference paper

Alem M, Baig T, Muggeridge A, Jones Aet al., 2019, Predicting the performance of tight gas reservoirs

Copyright 2019, Society of Petroleum Engineers. Engineers need to predict the production characteristics from hydraulically fractured wells in tight gas fields. Decline curve analysis (DCA) has been widely used over many years in conventional oil and gas fields. It is often applied to tight gas, but there is uncertainty regarding the period of production data needed for accurate prediction. In this paper decline curve analysis of simulated production data from models of hydraulically fractured wells is used to to develop improved methods for calibrating decline curve parameters from production data. The well models were constructed using data from the Khazzan field in Oman. The impact of layering, permeability and drainage area on well performance is also investigated. The contribution of each layer to recovery and the mechanisms controlling that contribution is explored. The investigation shows that increasing the amount of production data used to fit a hyperbolic decline curve does not improve predictions of recovery unless that data comes from many years (20 years for a 1mD reservoir) of production. This is because there is a long period of transient flow in tight gas reservoirs that biases the fitting and results in incorrect predictions of late time performance. Better predictions can be made by estimating the time at which boundary dominated flow is first observed (tb), omitting the preceding transient data and fitting the decline curve to a shorter interval of data starting at tb. For single layer cases, tb can be estimated analytically using the permeability, porosity, compressibility and length scale of the drainage volume associated with the well. Alternatively, tb can be determined from the production data allowing improved prediction of performance from 2-layer reservoirs provided that a) there is high crossflow or b) there is no cross-flow and the lower permeability layer either does not experience BDF during the field life time or it is established qui

Conference paper

Kostorz W, Muggeridge A, Jackson M, Moncorge Aet al., 2019, Non-intrusive reduced order modelling for reconstruction of saturation distributions

Two new Non-Intrusive Reduced Order Modelling approaches to estimate time varying, spatial distributions of variables from arbitrary unseen inputs are introduced. One is a generalization of an existing ‘dynamic’ approach which requires multiple surrogate evaluations to model the solutions at different time instances, the other is a ‘steady-state’ approach that evaluates all time instances simultaneously, reducing the local approximation error. The ability of these approaches to estimate the water saturation distributions expected during a gas flood through a 2D, dipping reservoir is investigating for a range of unseen input parameters. The range of these parameters has been chosen so that a range of flow regimes will occur, from a gravity tongue to a viscous dominated Buckley-Leverett displacement. A number of practically relevant model error measures were employed as opposed to the standard L2 (Euclidean) norm. The influence of the number and the structure of training simulations for the model was also investigated, by employing two simple experimental design methods. The results show that POD based NIROM approaches are prone to significant deviations from the true model. The main sources of error are due to the non-smooth variation of system responses in hyperspace and the transient nature of the flows as well as the underlying dimensionality reduction. Since the first two sources are properties of the physical system modelled it may be expected that similar problems are likely to arise independently of the interpolation method and the reduction process used.

Conference paper

Kampitsis A, Salinas P, Pain C, Muggeridge A, Jackson Met al., 2019, Mesh adaptivity and parallel computing for 3D simulation of immiscible viscous fingering

We present the recently developed Double Control Volume Finite Element Method (DCVFEM) in combination with dynamic mesh adaptivity in parallel computing to simulate immiscible viscous fingering in two- and three-dimensions. Immiscible viscous fingering may occur during the waterflooding of oil reservoirs, resulting in early breakthrough and poor areal sweep. Similarly to miscible fingering it is triggered by small-scale permeability heterogeneity while it is controlled by the mobility ratio of the fluid and the level of transverse dispersion / capillary pressure. Up to this day, most viscous fingering studies have focussed on the miscible problem since immiscible fingering is significantly more challenging. It requires numerical simulations capable to capture the interaction of the shock front with the capillary pressure, which is a saturation dependent dispersion term. That leads to models with very fine mesh in order to minimise numerical diffusion, resulting in computationally intensive simulations. In this study, we apply the dynamic mesh adaptive DCVFEM in parallel computing to simulate immiscible viscous fingering with capillary pressure. Parallelisation is achieved by using the MPI libraries. Dynamic mesh adaptivity is achieved by mapping of data between meshes. The governing multiphase flow equations are discretised using double control volumes on tetrahedral finite elements. The discontinuous representation for pressure and velocity allows the use of small control volumes, yielding higher resolution of the saturation field. We demonstrate convergence of fingers using our parallel numerical method in 2d and 3d, on fixed and adaptive meshes, quantifying the speed-up due to parallelisation and mesh adaptivity and the achieved accuracy. Dynamic mesh adaptivity allows resolution to be automatically employed where it is required to resolve the fingers with lower resolution elsewhere, enabling capture of complex non-linearity such as tip-splitting. We achieve conv

Conference paper

Tai I, Muggeridge A, 2019, Evaluation of empirical models for viscous fingering in miscible displacement

The performance of miscible gas injection projects can be significantly affected by viscous fingering. This is further complicated by the presence of heterogeneities, as depending on the scale of the heterogeneity, there can be a diffusive, advective or channelling effect. To assess the economic feasibility of a miscible gas injection project, reservoir simulations are needed but very fine grids are required for the fingers to be modelled explicitly. This requires a large amount of computational power and time. To get around this issue, many empirical models have been proposed which model the average behaviour of the viscous fingers, allowing predictions of performance, thus reducing grid size and computational time. Many previous studies have investigated the ability of empirical models to represent fingering in line drives but none have considered flow in a quarter five spot pattern. In this study, a two phase, three component higher-order simulator is used to simulate miscible injection in square line drive and quarter five spot models, with and without heterogeneities. The results of the detailed fingering simulations were compared to the Todd & Longstaff and Fayers empirical models. To account for the effect of heterogeneities, the mixing parameter, w, in the Todd & Longstaff was adjusted using Koval's heterogeneity factor, H_k. The growth rate of the fingers, α, and the final fraction of the cross section occupied by the fingers, a+b, were adjusted in the Fayers model to account for heterogeneities and bypassed oil. The empirical models were implemented in a commercial immiscible reservoir simulator, Eclipse-100 using pseudo relative permeabilities. The detailed simulations indicate that the growth rate of the fingers varies non-linearly with mean concentration in radial flows and this is not captured by either of the empirical models. A modification of the Fayers model is proposed to capture this. For both heterogeneous line drive and quarter fi

Conference paper

Kampitsis A, Salinas P, Pain C, Muggeridge A, Jackson Met al., 2019, Mesh adaptivity and parallel computing for 3D simulation of immiscible viscous fingering

© 2019 European Association of Geoscientists and Engineers, EAGE. All Rights Reserved. We present the recently developed Double Control Volume Finite Element Method (DCVFEM) in combination with dynamic mesh adaptivity in parallel computing to simulate immiscible viscous fingering in two- and three-dimensions. Immiscible viscous fingering may occur during the waterflooding of oil reservoirs, resulting in early breakthrough and poor areal sweep. Similarly to miscible fingering it is triggered by small-scale permeability heterogeneity while it is controlled by the mobility ratio of the fluid and the level of transverse dispersion / capillary pressure. Up to this day, most viscous fingering studies have focussed on the miscible problem since immiscible fingering is significantly more challenging. It requires numerical simulations capable to capture the interaction of the shock front with the capillary pressure, which is a saturation dependent dispersion term. That leads to models with very fine mesh in order to minimise numerical diffusion, resulting in computationally intensive simulations. In this study, we apply the dynamic mesh adaptive DCVFEM in parallel computing to simulate immiscible viscous fingering with capillary pressure. Parallelisation is achieved by using the MPI libraries. Dynamic mesh adaptivity is achieved by mapping of data between meshes. The governing multiphase flow equations are discretised using double control volumes on tetrahedral finite elements. The discontinuous representation for pressure and velocity allows the use of small control volumes, yielding higher resolution of the saturation field. We demonstrate convergence of fingers using our parallel numerical method in 2d and 3d, on fixed and adaptive meshes, quantifying the speed-up due to parallelisation and mesh adaptivity and the achieved accuracy. Dynamic mesh adaptivity allows resolution to be automatically employed where it is required to resolve the fingers with lower resolution

Conference paper

Kostorz W, Muggeridge A, Jackson M, Moncorge Aet al., 2019, Non-intrusive reduced order modelling for reconstruction of saturation distributions

Copyright 2019, Society of Petroleum Engineers. Two new Non-Intrusive Reduced Order Modelling approaches to estimate time varying, spatial distributions of variables from arbitrary unseen inputs are introduced. One is a generalization of an existing ‘dynamic’ approach which requires multiple surrogate evaluations to model the solutions at different time instances, the other is a ‘steady-state’ approach that evaluates all time instances simultaneously, reducing the local approximation error. The ability of these approaches to estimate the water saturation distributions expected during a gas flood through a 2D, dipping reservoir is investigating for a range of unseen input parameters. The range of these parameters has been chosen so that a range of flow regimes will occur, from a gravity tongue to a viscous dominated Buckley-Leverett displacement. A number of practically relevant model error measures were employed as opposed to the standard L2 (Euclidean) norm. The influence of the number and the structure of training simulations for the model was also investigated, by employing two simple experimental design methods. The results show that POD based NIROM approaches are prone to significant deviations from the true model. The main sources of error are due to the non-smooth variation of system responses in hyperspace and the transient nature of the flows as well as the underlying dimensionality reduction. Since the first two sources are properties of the physical system modelled it may be expected that similar problems are likely to arise independently of the interpolation method and the reduction process used.

Conference paper

Alem M, Baig T, Muggeridge A, Jones Aet al., 2019, Predicting the performance of tight gas reservoirs

Copyright 2019, Society of Petroleum Engineers. Engineers need to predict the production characteristics from hydraulically fractured wells in tight gas fields. Decline curve analysis (DCA) has been widely used over many years in conventional oil and gas fields. It is often applied to tight gas, but there is uncertainty regarding the period of production data needed for accurate prediction. In this paper decline curve analysis of simulated production data from models of hydraulically fractured wells is used to to develop improved methods for calibrating decline curve parameters from production data. The well models were constructed using data from the Khazzan field in Oman. The impact of layering, permeability and drainage area on well performance is also investigated. The contribution of each layer to recovery and the mechanisms controlling that contribution is explored. The investigation shows that increasing the amount of production data used to fit a hyperbolic decline curve does not improve predictions of recovery unless that data comes from many years (20 years for a 1mD reservoir) of production. This is because there is a long period of transient flow in tight gas reservoirs that biases the fitting and results in incorrect predictions of late time performance. Better predictions can be made by estimating the time at which boundary dominated flow is first observed (tb), omitting the preceding transient data and fitting the decline curve to a shorter interval of data starting at tb. For single layer cases, tb can be estimated analytically using the permeability, porosity, compressibility and length scale of the drainage volume associated with the well. Alternatively, tb can be determined from the production data allowing improved prediction of performance from 2-layer reservoirs provided that a) there is high crossflow or b) there is no cross-flow and the lower permeability layer either does not experience BDF during the field life time or it is established qui

Conference paper

Hiller T, Ardevol-Murison J, Muggeridge AH, Schroter M, Brinkmann Met al., 2018, The impact of wetting heterogeneity distribution on capillary pressure and macroscopic measures of wettability, SPE Journal, ISSN: 1930-0220

This work investigates how the different length scales of pore scale wetting heterogeneities affect the shape of capillary pressure-saturation (CPS) curves and the derived USBM and Amott-Harvey wettability indices. These macroscopic wettability indices are used to describe bulk rock wettability as the local contact angle (the standard physical measure of wettability) in a sample which is difficult to access andmay vary within and between pores due to changes in mineralogy and the surface coverage of organic materials. Our study combines laboratory experiments and full-scale fluid dynamics simulations employing the multi-phase Stochastic Rotation Dynamics (SRDmc) model. Four model systems were created using monodisperse glass beads. The surface properties of the beads were modified so that half of the surface area in each system was strongly hydrophilic and half was hydrophobic but each system had a different length scaleof wetting heterogeneity, ranging from a fraction of the bead diameter to two bead diameters. There is excellent agreement between the experimental and simulation results. All systems are classified as intermediate wet based on their Amott-Harvey and USBM indices. Examination of the capillary pressure curves shows that the opening of the stable hysteresis loop decreases monotonically as the length scale of the wetting heterogeneities is increased. Hence, our results suggest that macroscopic wettability indices may be used as indicators of ultimate recovery, but are not suited to discriminate between the different flows that occur earlier on in a mixed wettability displacement process.

Journal article

Lei Q, Xie Z, Pavlidis D, Salinas P, Veltin J, Matar O, Pain C, Muggeridge A, Gyllensten A, Jackson Met al., 2018, The shape and motion of gas bubbles in a liquid flowing through a thin annulus, Journal of Fluid Mechanics, Vol: 285, Pages: 1017-1039, ISSN: 0022-1120

We study the shape and motion of gas bubbles in a liquid flowing through a horizontal or slightly inclined thin annulus. Experimental data show that in the horizontal annulus, bubbles develop a unique ‘tadpole-like’ shape with a semi-circular cap and a highly stretched tail. As the annulus is inclined, the bubble tail tends to vanish, resulting in a significant decrease of bubble length. To model the bubble evolution, the thin annulus is conceptualised as a ‘Hele-Shaw’ cell in a curvilinear space. The three-dimensional flow within the cell is represented by a gap-averaged, two-dimensional model, which achieved a close match to the experimental data. The numerical model is further used to investigate the effects of gap thickness and pipe diameter on the bubble behaviour. The mechanism for the semi-circular cap formation is interpreted based on an analogous irrotational flow field around a circular cylinder, based on which a theoretical solution to the bubble velocity is derived. The bubble motion and cap geometry is mainly controlled by the gravitational component perpendicular to the flow direction. The bubble elongation in the horizontal annulus is caused by the buoyancy that moves the bubble to the top of the annulus. However, as the annulus is inclined, the gravitational component parallel to the flow direction becomes important, causing bubble separation at the tail and reduction in bubble length.

Journal article

Gago PA, King P, Muggeridge A, 2018, Fractal growth model for estimating breakthrough time and sweep efficiency when waterflooding geologically heterogeneous rocks, Physical Review Applied, Vol: 10, ISSN: 2331-7019

We describe a fast method for estimating flow through a porous medium with a heterogeneous permeability distribution. The main application is to contaminant transport in aquifers and recovery of oil by waterflooding, where such geological heterogeneities can result in regions of bypassed contaminants or oil. The extent of this bypassing is normally assessed by a numerical flow simulation that can take many hours of computer time. Ideally the impact of uncertainty in the geological description is then evaluated by the performing of many such simulations using different realizations of the permeability distribution. Obviously, a proper Monte Carlo evaluation may be impossible when the flow simulations are so computationally intensive. Consequently, methods from statistical mechanics, such as percolation theory and random walkers (such as diffusion-limited aggregation), have been proposed; however, these methods are limited to geological heterogeneities where the correlation lengths are smaller than the system size or to continuous permeability distributions. Here we describe a growth model that can be used to estimate the breakthrough time of the water (and hence the sweep efficiency) in most types of geologically heterogeneous rocks. We show how the model gives good estimates of the breakthrough time of water at the production well in a fraction of the time needed to perform a full flow simulation.

Journal article

Attar A, Muggeridge A, 2018, Low salinity water injection: Impact of physical diffusion, an aquifer and geological heterogeneity on slug size, JOURNAL OF PETROLEUM SCIENCE AND ENGINEERING, Vol: 166, Pages: 1055-1070, ISSN: 0920-4105

Journal article

Abdul Hamid S, Muggeridge AH, 2018, Analytical solution of polymer slug injection with viscous fingering, Computational Geosciences: modeling, simulation and data analysis, Vol: 22, Pages: 711-723, ISSN: 1420-0597

We present an analytical solution to estimate the minimum polymer slug size needed to ensure that viscous fingering of chase water does not cause its breakdown during secondary oil recovery. Polymer flooding is typically used to improve oil recovery from more viscous oil reservoirs. The polymer is injected as a slug followed by chase water to reduce costs; however, the water is less viscous than the oil. This can result in miscible viscous fingering of the water into the polymer, breaking down the slug and reducing recovery. The solution assumes that the average effect of fingering can be represented by the empirical Todd and Longstaff model. The analytical calculation of minimum slug size is compared against numerical solutions using the Todd and Longstaff model as well as high resolution first contact miscible simulation of the fingering. The ability to rapidly determine the minimum polymer slug size is potentially very useful during enhanced oil recovery (EOR) screening studies.

Journal article

Abdul Hamid SA, Muggeridge A, 2018, Viscous fingering in reservoirs with long aspect ratios, SPE Improved Oil Recovery Conference

© 2018, Society of Petroleum Engineers. This paper investigates the impact of aspect ratio on the growth rate of viscous fingers using high resolution numerical simulation in reservoirs with aspect ratios of up to 30:1. The behaviour of fingers in porous media with such high aspect ratios has been overlooked previously in many previous simulation studies due to limited computational power. Viscous fingering is likely to adversely affect the sweep obtained from any miscible gas injection project. It can also occur during polymer flooding when using chase water following the injection of a polymer slug. It depends upon the viscosity ratio, physical diffusion and dispersion, the geometry of the system and the permeability heterogeneity. It occurs because the interface between a lower viscosity displacing fluid and a higher viscosity displaced fluid is intrinsically unstable. This means that any small perturbation to the interface will cause fingers to grow. It is therefore almost impossible to predict the exact fingering pattern in any given displacement although many previous researchers have shown that it is possible predict average behaviour (such as gas breakthrough time and oil recovery) provided a very refined grid is used such that physical diffusion dominates over numerical diffusion. It is impossible to use such fine grids in field scale simulations. Instead engineers will tend to use standard empirical models such as the Todd and Longstaff or Koval models, calibrated to detailed simulations, to estimate field scale performance. At late times in high aspect ratio systems, we find that one finger dominates the displacement and that this finger grows with the square root of time, rather than linearly. We also observe that this single finger tends to split, during which time the solvent oil interface length grows linearly with time before one finger again dominates and grows with the square root of time. This cycle can repeat several times. We also find that

Conference paper

Muggeridge AH, Alshawaf M, Krevor S, 2018, Experimental Investigation of Cross-flow in Stratified Reservoirs During Polymer Flooding, SPE IMproved Oil Recovery Conference

Conference paper

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