Publications
186 results found
Go J, Bortone I, Smalley PC, et al., 2014, Predicting Vertical Flow Barriers Using Tracer Diffusion in Partially Saturated, Layered Porous Media, Transport in Porous Media
Iglauer S, Muggeridge A, 2013, The Impact of Tides on the Capillary Transition Zone, TRANSPORT IN POROUS MEDIA, Vol: 97, Pages: 87-103, ISSN: 0169-3913
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- Citations: 2
Jackson MD, Gomes JLMA, Mostaghimi P, et al., 2013, Reservoir modeling for flow simulation using surfaces, adaptive unstructured meshes and control-volume-finite-element methods, Pages: 774-792
We present new approaches to reservoir modeling and flow simulation that dispose of the pillar-grid concept that has persisted since reservoir simulation began. This results in significant improvements to the representation of multi-scale geological heterogeneity and the prediction of flow through that heterogeneity. The research builds on 20+ years of development of innovative numerical methods in geophysical fluid mechanics, refined and modified to deal with the unique challenges associated with reservoir simulation. Geological heterogeneities, whether structural, stratigraphic, sedimentologic or diagenetic in origin, are represented as discrete volumes bounded by surfaces, without reference to a pre-defined grid. Petrophysical properties are uniform within the geologically-defined rock volumes, rather than within grid-cells. The resulting model is discretized for flow simulation using an unstructured, tetrahedral mesh that honors the architecture of the surfaces. This approach allows heterogeneity over multiple length-scales to be explicitly captured using fewer cells than conventional corner-point or unstructured grids. Multiphase flow is simulated using a novel mixed finite element formulation centered on a new family of tetrahedral element types, PN(DG)-PN+1, which has a discontinuous Nth-order polynomial representation for velocity and a continuous (order N+1) representation for pressure. This method exactly represents Darcy force balances on unstructured meshes and thus accurately calculates pressure, velocity and saturation fields throughout the domain. Computational costs are reduced through (i) efficient parallelization and (ii) automatic mesh adaptivity in time and space. Within each rock volume, the mesh coarsens and refines to capture key flow processes, whilst preserving the surface-based representation of geological heterogeneity. Computational effort is thus focused on regions of the model where it is most required. Having validated the approach aga
Al-Hadhrami M, Alkindi A, Muggeridge AH, 2013, Experimental investigations into the effect of heterogeneities on the recovery of heavy oil by VAPEX
We report a series of laboratory experiments investigating oil drainage rates using VAPour Extraction (VAPEX) in both homogenous and heterogeneous systems (including layered and single discontinuous shales). All experiments were performed in well-characterized glass bead packs using glycerol and ethanol as analogues of heavy oil and solvent respectively. All the porous medium and fluid properties (including permeability, porosity, viscosity, density, diffusion and dispersion) were measured independently. The experimentally measured rates were compared to the estimates derived from the Butler and Mokrys analytical model. In addition, numerical simulations were performed to validate whether the physical diffusion boundaries were captured correctly. The Butler and Mokrys analytical model substantially underestimated the drainage rates in all cases, even when the effects of convective dispersion and end point density difference were factored in. The observed oil drainage rates from the layered packs were between the rates observed in homogeneous packs formed from high permeability beads (the upper bound) and from packs with low permeability beads ( the lower bound). A single discontinuous shale significantly reduced the oil drainage rates. The numerical simulations under-predicted the oil drainage rates, although the pattem of solvent-oil distribution was correctly captured. The performance of the layered system could be predicted from the homogenous models by using the arithmetic average of the various layers' permeability. Overall, we suggest that these types of heterogeneity have little impact on VAPEX performance except through their influence on the effective permeability of the reservoir.
Rashid B, Fagbowore O, Muggeridge AH, 2012, Using dimensionless numbers to assess EOR in heterogeneous reservoirs
Dimensionless numbers such as mobility ratio and the viscous to gravity ratio provide a convenient way of assessing the flow regime and thus ranking performance when designing secondary and tertiary oil recovery processes. Until recently, however, their application has been limited to homogeneous reservoirs due to a) the lack of a robust heterogeneity index and b) the fact that the viscous to gravity ratio depends upon reservoir permeability and thus heterogeneity. In this paper we present 3D phase diagrams showing how recovery and breakthrough time depend upon mobility ratio, viscous-to-gravity ratio and heterogeneity. We review the literature on the application of dimensionless numbers to identify flow regime in oil recovery processes and select a recently developed heterogeneity index based upon vorticity to characterize heterogeneity. The index has been previously verified using heterogeneous reservoir descriptions taken from SPE10 model 2. We use the phase-diagrams to identify dominant flow regimes and provide criteria based on the dimensionless numbers for identifying those flow regimes when assessing alternative EOR processes.
Rashid B, Fagbowore O, Muggeridge AH, 2012, Using dimensionless numbers to assess EOR in heterogeneous reservoirs
Dimensionless numbers such as mobility ratio and the viscous to gravity ratio provide a convenient way of assessing the flow regime and thus ranking performance when designing secondary and tertiary oil recovery processes. Until recently, however, their application has been limited to homogeneous reservoirs due to a) the lack of a robust heterogeneity index and b) the fact that the viscous to gravity ratio depends upon reservoir permeability and thus heterogeneity. In this paper we present 3D phase diagrams showing how recovery and breakthrough time depend upon mobility ratio, viscous-to-gravity ratio and heterogeneity. We review the literature on the application of dimensionless numbers to identify flow regime in oil recovery processes and select a recently developed heterogeneity index based upon vorticity to characterize heterogeneity. The index has been previously verified using heterogeneous reservoir descriptions taken from SPE10 model 2. We use the phase-diagrams to identify dominant flow regimes and provide criteria based on the dimensionless numbers for identifying those flow regimes when assessing alternative EOR processes.
Rashid B, Muggeridge A, Bal A-L, et al., 2012, Quantifying the impact of permeability heterogeneity on secondary recovery performance, SPE Journal
Rashid B, Bal A-L, Williams GJJ, et al., 2012, Using vorticity to quantify the relative importance of heterogeneity, viscosity ratio, gravity and diffusion on oil recovery, Computational Geosciences: modeling, simulation and data analysis, Vol: 16, Pages: 409-422
Iglauer S, Muggeridge A, 2012, TIME DEPENDENCE OF FREE FALL GRAVITY DRAINAGE IN UNCONSOLIDATED SAND, JOURNAL OF POROUS MEDIA, Vol: 15, Pages: 721-733, ISSN: 1091-028X
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- Citations: 4
Cairns G, Jakubowicz H, Lonergan L, et al., 2012, Using time-lapse seismic monitoring to identify trapping mechanisms during CO2 sequestration, International Journal of Greenhouse Gas Control, Vol: 11, Pages: 316-325
We show that it may be possible to distinguish between structurally- and capillary-trapped CO2 using time-lapse seismic monitoring of geological CO2 sequestration. Commercial reservoir simulation software was used to predict CO2 saturation in a saline aquifer over time. The output was combined with a rock physics model to calculate the elastic and seismic properties of the aquifer. As the seismic response depends on both fluid content and distribution, appropriate end-member fluid-distribution models were used to predict the possible range of seismic responses. We propose that different fluid-distribution models should be used for capillary- and structurally-trapped CO2 in a reservoir; the Hill average should be used for high, mobile CO2 saturations found during structural trapping whilst the Gassmann-Reuss average should be used for low, immobile CO2 saturations resulting from residual trapping. Far-offset seismic data was used to interpret reflections produced by the different trapping phases and cross-plotting was used to determine the trapping phase. Results indicate that structurally-trapped CO2 can be seismically imaged irrespective of fluid distribution and, importantly, a reflection may be generated off the interface between residually- and structurally-trapped CO2.
Go J, Smalley PC, Muggeridge A, 2012, Using reservoir mixing to evaluate reservoir compartmentalization from appraisal data – validation using data from the Horn Mountain field, Gulf of Mexico, Petroleum Geoscience, Vol: 18, Pages: 305-314
Muggeridge A, Mahmode H, 2012, Hydrodynamic aquifer or reservoir compartmentalization?, AAPG Bulletin, Vol: 96, Pages: 315-336
Zainee AH, Alkindi A, Muggeridge A, 2011, Investigations into oil recovery and drainage rates during vapour extraction (VAPEX) of heavy oils, Pages: 182-201
Heavy oil recovery using the Vapour Extraction (VAPEX) process is a promising EOR technique as it is more energy-efficient than thermal recovery processes. It works via similar mechanisms to SAGD but uses solvent vapour to dilute the oil rather than heat to reduce viscosity. As a result it can be used in situations where steam would not work e.g. thin oil columns above water. An analytic VAPEX model to predict oil rate was first proposed by Butler and Mokrys (1989) as a solvent analogue of a model for predicting oil rate from SAGD. This model however has been found by many authors to under-predict the oil production rates in porous media despite accurately predicting the oil rates in experiments using Hele-Shaw cells. This paper presents an analytic expression for the solvent-oil distribution during VAPEX as well as a modified expression of the Butler-Mokrys model that improves prediction of oil drainage rate. A validated numerical simulation model was also used to investigate the oil drainage rate sensitivity to reservoir thickness, length, permeability, well placement, density difference and viscosity ratio. Simulation results were compared against the predicted rates using both the original and modified Butler-Mokrys models. The impact of using dispersion rather than molecular diffusion coefficients in the analytic model was also investigated. Predictions using the modified Butler-Mokrys model combined with longitudinal dispersion coefficient were found to be in good agreement with simulated results. Predictions using the original Butler-Mokrys model meanwhile were consistently lower than the simulated rates. Simulations showed that drainage rates have a lower than square root dependency on reservoir height. They also showed that the Butler-Mokrys model breaks down at high height/length aspect ratios where the underlying assumptions no longer apply. However in long thin reservoirs both stabilised oil drainage rate and cumulative production were insensitive to the
Al Rabaani AS, Muggeridge A, 2011, The contribution of different oil recovery mechanisms for heavy and light oil during thermally assisted gas-oil gravity, Pages: 161-181
Thermally Assisted Gas-Oil Gravity Drainage (TA-GOGD) is an EOR process for fractured reservoirs. Steam is injected and flows through the high permeability fracture network heating the rock matrix and the oil contained within that matrix. A range of processes then occur that contribute to improving oil recovery including gas evolving from the heated oil, oil viscosity reduction, distillation, connate water evaporation and, in carbonate reservoirs, carbon dioxide generation. In this paper, the relative importance of these different recovery mechanisms for heavy and light oil are investigated using numerical simulation. The advantage of using numerical simulation is that we can include or neglect the various recovery mechanisms in order to determine their contribution to overall recovery. We use real field rock and fluid properties taken from typical Middle Eastern carbonate reservoirs. The contributions of each mechanism were compared in terms of cumulative oil recovery and cumulative oil steam ratio after 0.5 and 1 PVI for two different average matrix block sizes These results demonstrate that it is important to characterise the rate of CO2 generation (which depends on rock mineralogy) and steam distillation of the oil (which relies on good PVT data) in order to predict oil rate, however predictions and timings of ultimate oil recovery are less sensitive to the quality of the input data. This is because the relative contribution of each recovery mechanism varies with time. CO2 generation, water imbibition and oil thermal expansion were significant in the early period of steam injection with CO2 generation contributing up to 36% of recovery for light oil reservoirs. However, these mechanisms had a reduced impact on recovery at later times when distillation, thermal gas drive, viscosity reduction and gravity drainage were observed to play the major role in recovery. It is also important to be able to quantify the rate of wettability alteration during steam injection a
Alkindi AS, Al-Wahaibi YM, Muggeridge AH, 2011, Experimental and Numerical Investigations Into Oil-Drainage Rates During Vapor Extraction of Heavy Oils, SPE JOURNAL, Vol: 16, Pages: 343-357, ISSN: 1086-055X
Smalley PC, Muggeridge A, 2011, Reservoir Compartmentalization: get it before it gets you, Reservoir Compartmentalization, Editors: Jolley, Fisher, Ainsworth, Vrolijk, Delisle, Publisher: Geological Society of London, Pages: 25-42, ISBN: 9781862393165
Alkindi A, Al-Wahaibi Y, Bijeljic B, et al., 2011, Investigation of longitudinal and transverse dispersion in stable displacements with a high viscosity and density contrast between the fluids, Journal of Contaminant Hydrology, Vol: 120-121, Pages: 170-183
Rashid B, Bal A, Williams G, et al., 2010, Quantifying the impact of permeability heterogeneity on secondary recovery performance, Pages: 4073-4083
A new and improved heterogeneity index is introduced that uses the shear-strain rate of the single phase velocity field to characterise heterogeneity in terms of its impact on performance. This index's ability to rank heterogeneous reservoir models is compared with that of the Dykstra-Parsons coefficient and the dynamic Lorenz coefficient. The new index is able to rank reservoirs, both accurately and quickly, based on performance for both miscible and immiscible fluids at a range of different mobility ratios. In contrast both the Dykstra-Parsons coefficient and the dynamic Lorenz coefficient are found to lack the sensitivity needed to be able to estimate the time to breakthrough of the displacing fluid and the recovery of oil at one pore volume injected. Copyright 2010, Society of Petroleum Engineers.
Cairns C, Jakubowicz H, Lonergan L, et al., 2010, Sensitivity of seismic modelling to different fluid distributions for carbon capture and storage, Pages: 4247-4251
The ability of time-lapse seismic surveys to monitor carbon dioxide sequestration is explored using a rock physics model. We investigate the effects of reservoir depth on the seismic response, and its ability to detect CO2 and distinguish saturation changes. We examine the effect of the fluid distribution on the magnitude of the seismic response and the potential to use this to distinguish different reservoir models of CO2 distribution. This analysis suggests that the presence of CO2 can easily be found using traditional seismic surveys, with some potential to distinguish CO2 saturation and distribution. © 2010, European Association of Geoscientists and Engineers.
Rashid B, Bal AL, Williams GJJ, et al., 2010, Quantifying of the impact of reservoir heterogeneity on recovery using shear and vorticity
We have used the vorticity of the displacement velocity, as defined by Heller (1966), to derive dimensionless numbers to be used to quantify the relative impact of viscosity ratio, gravity, diffusion and dispersion, and permeability heterogeneity on reservoir flow behaviour. We have used this approach to introduce a new objective measure of the impact of permeability and porosity heterogeneity on reservoir flow behaviour. Buoyancy forces are quantified using a gravity to viscous ratio (G) and diffusion/ dispersion using the transverse dispersion number. Detailed simulation of first contact miscible gas/solvent displacements through a range of geologically realistic reservoir models is used to show that the new heterogeneity number, in conjunction with the dimensionless numbers, can be used to provide meaningful results for real non-linear reservoir flows. This study goes some way towards developing a unified mathematical framework to determine under which flow conditions reservoir heterogeneity becomes more important than other physical processes.
Rashid B, Bal AL, Williams GJJ, et al., 2010, Quantifying of the impact of reservoir heterogeneity on recovery using shear and vorticity
We have used the vorticity of the displacement velocity, as defined by Heller (1966), to derive dimensionless numbers to be used to quantify the relative impact of viscosity ratio, gravity, diffusion and dispersion, and permeability heterogeneity on reservoir flow behaviour. We have used this approach to introduce a new objective measure of the impact of permeability and porosity heterogeneity on reservoir flow behaviour. Buoyancy forces are quantified using a gravity to viscous ratio (G) and diffusion/ dispersion using the transverse dispersion number. Detailed simulation of first contact miscible gas/solvent displacements through a range of geologically realistic reservoir models is used to show that the new heterogeneity number, in conjunction with the dimensionless numbers, can be used to provide meaningful results for real non-linear reservoir flows. This study goes some way towards developing a unified mathematical framework to determine under which flow conditions reservoir heterogeneity becomes more important than other physical processes.
Tungdumrongsub S, Muggeridge A, 2010, Layering and oil recovery: The impact of permeability contrast, gravity, viscosity and dispersion, Pages: 2546-2556
The vertical sweep efficiency of all secondary and tertiary oil recovery processes will be affected by the viscosity and density contrast between the oil and the displacing fluid as well as the existence of layers in the reservoir and the permeability contrast between those layers. Mixing between injected and reservoir fluids driven by physical dispersion will alter the effect of these factors on some enhanced oil recovery processes such as miscible gas injection or low salinity water injection. If physical dispersion is large enough it may result in vertical sweep efficiencies close to 100% but will thereby reduce the microscopic sweep efficiency of the EOR process. This paper investigates the impact of variations in permeability contrast, gravity, viscosity, and dispersion on the oil recovery from a first-contact miscible gas injection scheme in a two layered reservoir. The variations are characterized in terms of mobility ratio, viscous to gravity ratio, layer permeability contrast, vertical to horizontal permeability ratio and the transverse dispersion number proposed by Lake and Hirasaki (1981). The reservoir behaviour is quantified at early and late time in terms of breakthrough time, oil recovery at 1 PVI and late time and solvent cut. Overall, dispersion dominates oil recovery when the transverse dispersion number is greater than one regardless of mobility ratio, layer permeability contrast or viscous to gravity ratio. The transverse dispersion number can be used to evaluate the impact of cross-layer mixing on vertical sweep for a far wider range of flow regimes than originally investigated by Lake and Hirasaki (1981). This work demonstrates that the transverse dispersion number can and should be used to assess whether vertical or microscopic sweep efficiency will be dominant in any displacements where dispersion may have an impact on recovery. © 2010, European Association of Geoscientists and Engineers.
Alkindi A, Muggeridge A, Al-Wahaibi Y, 2010, Experimental investigation into the influence of convective dispersion and model height on oil drainage rates during VAPEX, Pages: 249-265
Vapour extraction (VAPEX) has received considerable attention as an enhanced heavy oil recovery process. Like SAGD it relies on significantly reducing the oil viscosity but has the advantage over SAGD that it will be effective in thin or deep reservoirs where thermal methods are impractical due excessive heat losses. Nonetheless field applications of VAPEX have been limited partly due to difficulties in predicting the high oil rates observed in laboratory experiments and thus in upscaling the results to field scale. In this paper, we present a laboratory investigation of the VAPEX process using analogue fluids in a well characterized glass bead pack. The experiments were focused specifically on determining the role of convective dispersion and reservoir thickness on drainage rates. Longitudinal and transverse dispersion coefficients were measured with and without gravity in order to quantify the impact of interstitial velocities and contrasts in the fluids' viscosity and density on the rate of mixing as encountered in VAPEX. The experimental measurements of oil drainage rates were higher than predicted by the standard Butler-Mokrys analytical model assuming diffusion-controlled mass transfer. The use of measured dispersion coefficients however significantly improved the model predictions. In addition, the results found drainage rates to have a higher than square root dependency on model height. The combined effects of the roles of convective dispersion and model height on drainage rates were incorporated into a predictive model that satisfactorily matched measured rates in the laboratory. © 2010, Society of Petroleum Engineers.
Cairns G, Jakubowicz H, Lonergan L, et al., 2010, Issues regarding the use of time-lapse seismic surveys to monitor CO<inf>2</inf> sequestration, Pages: 1236-1240
A rock physics model was built to provide a link between geological modeling, reservoir engineering and the time-lapse seismic response to CO2 injection. This model was used to examine the influence of factors such as reservoir depth and fluid distribution on the seismic attributes. Depth was shown to be an important control on the magnitude of the response, with the largest change found at shallow depths. Therefore a tradeoff is required between the need to sequester CO2 deeply for safety and the ability of seismic surveys to detect CO2. Synthetic zero-offset seismic showed a detectable change in response for small amounts of CO2 but this is heavily dependent on fluid distribution. The zero-offset response shows limited success distinguishing higher saturation changes and Amplitude Variation with Offset (AVO) may be required to provide this information. The distribution of the fluids in the reservoir was shown to be a significant control on the magnitude of the P-wave response and it’s the relationship with saturation. This may allow reservoir engineers to distinguish between mobile and immobile CO2, enhancing the understanding of the trapping in the reservoir. The ability to do this is heavily frequency dependent and may require high frequency seismic data such as cross-well tomography.
Al-Wahaibi YM, Muggeridge AH, Grattoni CA, 2009, Gas-oil non-equilibrium in multicontact miscible displacements within homogeneous porous media, JOURNAL OF PETROLEUM SCIENCE AND ENGINEERING, Vol: 68, Pages: 71-80, ISSN: 0920-4105
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- Citations: 13
Mahani H, Muggeridge AH, Ashjari MA, 2009, Vorticity as a measure of heterogeneity for improving coarse grid generation, PETROLEUM GEOSCIENCE, Vol: 15, Pages: 91-102, ISSN: 1354-0793
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- Citations: 10
Al-Wahaibi YM, Muggeridge AH, Grattoni CA, 2009, A Numerical Study on the Effect of Cross-Bedding Heterogeneity Geometry on Oil Recovery via Condensing and Vaporizing Gas Drive Processes, PETROLEUM SCIENCE AND TECHNOLOGY, Vol: 27, Pages: 1604-1620, ISSN: 1091-6466
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- Citations: 1
Alkindi AS, Al-Wahaibi YM, Muggeridge AH, 2008, Physical Properties (Density, Excess Molar Volume, Viscosity, Surface Tension, and Refractive Index) of Ethanol plus Glycerol, JOURNAL OF CHEMICAL AND ENGINEERING DATA, Vol: 53, Pages: 2793-2796, ISSN: 0021-9568
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- Citations: 62
Al Rabaani A, Blunt M, Muggeridge A, 2008, Calculation of a Critical Steam Injection Rate for Thermally-Assisted Gas-Oil Gravity Drainage, SPE IOR Symposium
Alkindi A, Al-Wahaibi Y, Muggeridge A, 2008, An experimental investigation into the influence of diffusion and dispersion on heavy oil recovery by vapex, Pages: 2364-2376
This paper investigates the role of convective dispersion on oil recovery by VAPEX using an analogue fluid system of ethanol and glycerol in well-characterized glass bead packs. Laboratory studies of VAPEX in porous media result in significantly high production rates than predicted either by analytic models derived from Hele-Shaw experiments or numerical simulations. Previous workers have obtained an improved match between experiment and simulation by artificially increasing the diffusion coefficient of the injected vapour into the oil. Justifications for this increase include convective dispersion, an increased surface area due to the formation of oil films on sand grains, imbibition of oil into those films and a greater dependence on drainage height. Convective dispersion seems to be the most plausible mechanism. A first contact miscible liquid-liquid system was used in these experiments so that all mechanisms contributing to increased-mixing apart from convective dispersion were eliminated. Improved onfidence and prediction of VAPEX oil drainage rates will increase the likelihood of field scale application of VAPEX. This has been limited, due to difficulties in predicting the outcome on the laboratory scale and upscaling the results. Longitudinal and transverse dispersion coefficients were measured experimentally as a function of flow-rate and viscosity ratio, with and without gravity. Vapex drainage experiments were performed over a range of injection rates. More than 80% of oil in place recovered after one pore volume of solvent injection. The oil drainage rates were compared with those predicted by the Butler-Mokrys analytical model using either molecular diffusion or convective dispersion. Using measured convective dispersion improved prediction of oil drainage rate by over 50%. Nonetheless experimental oil dranage rates were still slightly higher than predicted. These results indicate that convective dispersion needs to be included in mixing calculations in
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