183 results found
Andrews E, Muggeridge A, Jones A, et al., 2023, Pore structure and wetting alteration combine to produce the low salinity effect on oil production, Fuel: the science and technology of fuel and energy, Vol: 332, Pages: 1-15, ISSN: 0016-2361
Low salinity water flooding is a promising enhanced oil recovery technique that has been observed, in experiments over a range of scales, to increase oil production by up to 14% in some systems. However, there is still no way of reliably predicting which systems will respond favourably to the technique. This shortcoming is partly because of a relative lack of pore scale observations of low salinity water flooding. This has led to a poor understanding of how mechanisms on the scale of micrometres lead to changes in fluid distribution on the scale of centimetres to reservoir scales. In this work, we use X-ray micro-CT scanning to image unsteady state experiments of tertiary low salinity water flooding in Berea, Castlegate, and Bunter sandstone micro-cores. We observe fluid saturations and characterise the wetting state of samples using imagery of fluid–solid fractional wetting and pore occupancy analysis. In the Berea sample, we observed an additional oil recovery of 3 percentage points during low salinity water flooding, with large volumes of oil displaced from small pores but also re-trapping of mobilised oil in large pores. In the Bunter sandstone, we observed 4 percentage point additional recovery with significant displacement of oil from small pores and no significant retrapping of oil in large pores. However, in the Castlegate sample, we observed just 1 percentage point of additional recovery and relatively small volumes of oil mobilisation. We observe a significant wettability alteration towards more water-wet conditions in the Berea and Bunter sandstones, but no significant alteration in the Castlegate sample. We hypothesise that pore structure, specifically the topology of large pores impacted recovery. We find that poor connectivity of the largest pores in each sample is strongly correlated to additional recovery. This work is the first systematic comparison of the pore scale response to low salinity flooding across multiple sandstone samples. Moreover
Smalley C, Muggeridge A, 2022, Reservoir Compartmentalization: Get it before it gets you, Geological Society Conference on Reservoir Compartmentalization
Keable D, Jones A, Krevor S, et al., 2022, The effect of viscosity ratio and peclet number on miscible viscous fingering in a dele-shaw cell: a combined numerical and experimental study, Transport in Porous Media, Vol: 143, Pages: 23-45, ISSN: 0169-3913
The results from a series of well characterised, unstable, miscible displacement experiments in a Hele-Shaw cell with a quarter five-spot source-sink geometry are presented, with comparisons to detailed numerical simulation. We perform repeated experiments at adverse viscosity ratios from 1 to 20 and Peclet numbers from 104 to 106 capturing the transition from 2D to 3D radial fingering and experimental uncertainty. The open-access dataset provides time-lapse images of the fingering patterns, transient effluent profiles, and meta-information for use in model validation. We find the complexity of the fingering pattern increases with viscosity ratio and Peclet number, and the onset of fingering is delayed compared to linear displacements, likely due to Taylor dispersion stabilisation. The transition from 2D to 3D fingering occurs at a critical Peclet number that is consistent with recent experiments in the literature. 2D numerical simulations with hydrodynamic dispersion and different mesh orientations provide good predictions of breakthrough times and sweep efficiency obtained at intermediate Peclet numbers across the range of viscosity ratios tested, generally within the experimental uncertainty. Specific finger wavelengths, tip shapes, and growth are hard to replicate; model predictions using velocity-dependent longitudinal dispersion or simple molecular diffusion bound the fingering evolution seen in the experiments, but neither fully capture both fine-scale and macroscopic measures. In both cases, simulations predict sharper fingers than the experiment. A weaker dispersion stabilisation seems necessary to capture the experimental fingering at high viscosity ratio, which may also require anisotropic components. 3D models with varying dispersion formulations should be explored in future developments to capture the full range of effects at high viscosity ratio and Peclet number.
Samuel J-S, Muggeridge AH, 2022, Non-Intrusive Reduced Order Modelling for the fast simulation of gas reservoirs, JOURNAL OF NATURAL GAS SCIENCE AND ENGINEERING, Vol: 101, ISSN: 1875-5100
Samuel J-S, Muggeridge AH, 2022, Fast modelling of gas reservoir performance with proper orthogonal decomposition based autoencoder and radial basis function non-intrusive reduced order models, JOURNAL OF PETROLEUM SCIENCE AND ENGINEERING, Vol: 211, ISSN: 0920-4105
Carlino A, Muggeridge AH, Smalley PC, 2022, Rapid Estimation of Carbon Dioxide Stored in CO2 EOR Operations for Screening Purposes
We describe the development, testing, and first application of a rapid method for estimating the CO2 storage potential associated with CO2 enhanced oil recovery in both secondary and tertiary modes. The new method builds on various published empirical models for predicting incremental oil recovery (and hence CO2storage) in solvent floods. It improves the representation of reservoir heterogeneity caused by de positional layering and fracturing. This is then combined with material balance to make site-specific estimates of theCO2 storage potential. We cross-checked predictions from the new method against historical field data for major onshore CO2floods with satisfactory results considering the very approximate nature of the estimation. We then applied the method to a selection of offshore oil reservoirs and found that, generally, the larger the remaining oil, which is a function of initial size and current recovery factor, the greater the CO2 storage potential. We also modelled the case of continued injection after ceasing oil production at, or after, CO2 break through and observed that, as expected, the amount of CO2 stored at breakthrough depends on how early this occurs, which is affected by reservoir heterogeneity, whereas continued injection is limited by the head room between current reservoir pressure and fracture pressure. The overall storage is the result of the interplay between these two mechanisms. In the studied fields/reservoirs, we demonstrated that large amounts ofCO2 can be stored in terms of absolute mass and that storage of these quantities would represent significant abatement of the emissions generated by burning the incremental oil. The new method can be used as a screening tool to identify and rank candidate oil fields for combinedCO2 enhanced oil recovery and storage in regional, national, or corporate portfolios.
Harris C, Jackson SJ, Benham GP, et al., 2021, The impact of heterogeneity on the capillary trapping of CO2 in the Captain Sandstone, International Journal of Greenhouse Gas Control, Vol: 112, Pages: 1-12, ISSN: 1750-5836
A significant uncertainty which remains for CO2 sequestration, is the effect of natural geological heterogeneitiesand hysteresis on capillary trapping over different length scales. This paper uses laboratory data measured incores from the Goldeneye formation of the Captain D Sandstone, North Sea in 1D numerical simulations toevaluate the potential capillary trapping from natural rock heterogeneities across a range of scales, from cm to65m. The impact of different geological realisations, as well as uncertainty in petrophysical properties, on theamount of capillary heterogeneity trapping is estimated. In addition, the validity of upscaling trapping characteristics in terms of the Land trapping parameter is assessed. The numerical models show that the capillaryheterogeneity trapped CO2 saturation may vary between 0 and 14% of the total trapped saturation, dependingupon the geological realisation and petrophysical uncertainty. When upscaling the Land model from core-scaleexperimental data, using the maximum experimental Land trapping parameter could increase the expectedheterogeneity trapping by a factor of 3. Conversely, depending on the form of the imbibition capillary pressurecurve used in the numerical model, including capillary pressure hysteresis may reduce the heterogeneity trapping by up to 70%.
Kampitsis AE, Kostorz WJ, Muggeridge AH, et al., 2021, The life span and dynamics of immiscible viscous fingering in rectilinear displacements (vol 33, 096608, 2021), PHYSICS OF FLUIDS, Vol: 33, ISSN: 1070-6631
- Author Web Link
- Citations: 1
Kampitsis AE, Kostorz WJ, Muggeridge AH, et al., 2021, The life span and dynamics of immiscible viscous fingering in rectilinear displacements, PHYSICS OF FLUIDS, Vol: 33, ISSN: 1070-6631
- Author Web Link
- Citations: 1
Wenck N, Jackson SJ, Manoorkar S, et al., 2021, Simulating Core Floods in Heterogeneous Sandstone and Carbonate Rocks, WATER RESOURCES RESEARCH, Vol: 57, ISSN: 0043-1397
- Author Web Link
- Citations: 4
Tai I, Giddins MA, Muggeridge A, 2021, Improved Calculation of Wellblock Pressures for Numerical Simulation of Non-Newtonian Polymer Injection, SPE JOURNAL, Vol: 26, Pages: 2352-2363, ISSN: 1086-055X
- Author Web Link
- Citations: 2
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
- Author Web Link
- Citations: 2
Andrews E, Muggeridge A, Garfi G, et 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
- Author Web Link
- Citations: 9
Andrews E, Muggeridge A, Jones A, et 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.
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
Smalley PC, Muggeridge AH, Amundrud SS, et 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.
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
- Author Web Link
- Citations: 6
Lei Q, Jackson MD, Muggeridge AH, et 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.
Kampitsis AE, Adam A, Salinas P, et al., 2020, Dynamic adaptive mesh optimisation for immiscible viscous fingering, COMPUTATIONAL GEOSCIENCES, Vol: 24, Pages: 1221-1237, ISSN: 1420-0597
- Author Web Link
- Citations: 10
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.
Smalley PC, Muggeridge AH, Amundrud SS, et 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.
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
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
Zhou Y, Muggeridge AH, Berg CF, et 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
- Author Web Link
- Citations: 6
Abdul Hamid SA, Adam A, Jackson MD, et 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.
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
Alem M, Baig T, Muggeridge A, et 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.
Alem M, Baig T, Muggeridge A, et 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
Kostorz W, Muggeridge A, Jackson M, et 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.
Kampitsis A, Salinas P, Pain C, et 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
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