97 results found
Gray F, Anabaraonye BU, Crawshaw JP, et al., 2021, ( )Pore-scale dissolution mechanisms in calcite-CO2-brine systems: The impact of non-linear reaction kinetics and coupled ion transport, GEOCHIMICA ET COSMOCHIMICA ACTA, Vol: 305, Pages: 323-338, ISSN: 0016-7037
- Author Web Link
- Citations: 1
Zacharoudiou I, Boek ES, Crawshaw J, 2020, Pore-Scale Modeling of Drainage Displacement Patterns in Association With Geological Sequestration of CO2, WATER RESOURCES RESEARCH, Vol: 56, ISSN: 0043-1397
- Author Web Link
- Citations: 3
Liyanage R, Russell A, Crawshaw JP, et al., 2020, Direct experimental observations of the impact of viscosity contrast on convective mixing in a three-dimensional porous medium, Physics of Fluids, Vol: 32, Pages: 1-10, ISSN: 1070-6631
Analog fluids have been widely used to mimic the convective mixing of carbon dioxide into brine in the study of geological carbon storage. Although these fluid systems had many characteristics of the real system, the viscosity contrast between the resident fluid and the invading front was significantly different and largely overlooked. We used x-ray computed tomography to image convective mixing in a three-dimensional porous medium formed of glass beads and compared two invading fluids that had a viscosity 3.5× and 16× that of the resident fluid. The macroscopic behavior such as the dissolution rate and onset time scaled well with the viscosity contrast. However, with a more viscous invading fluid, fundamentally different plume structures and final mixing state were observed due in large part to greater dispersion.
Ekanem EM, Berg S, De S, et al., 2020, Signature of elastic turbulence of viscoelastic fluid flow in a single pore throat, Physical Review E: Statistical, Nonlinear, and Soft Matter Physics, Vol: 101, Pages: 042605 – 1-042605 – 14, ISSN: 1539-3755
When a viscoelastic fluid, such as an aqueous polymer solution, flows through a porous medium, the fluid undergoes a repetitive expansion and contraction as it passes from one pore to the next. Above a critical flow rate, the interaction between the viscoelastic nature of the polymer and the pore configuration results in spatial and temporal flow instabilities reminiscent of turbulentlike behavior, even though the Reynolds number Re≪1. To investigate whether this is caused by many repeated pore body–pore throat sequences, or simply a consequence of the converging (diverging) nature present in a single pore throat, we performed experiments using anionic hydrolyzed polyacrylamide (HPAM) in a microfluidic flow geometry representing a single pore throat. This allows the viscoelastic fluid to be characterized at increasing flow rates using microparticle image velocimetry in combination with pressure drop measurements. The key finding is that the effect, popularly known as “elastic turbulence,” occurs already in a single pore throat geometry. The critical Deborah number at which the transition in rheological flow behavior from pseudoplastic (shear thinning) to dilatant (shear thickening) strongly depends on the ionic strength, the type of cation in the anionic HPAM solution, and the nature of pore configuration. The transition towards the elastic turbulence regime was found to directly correlate with an increase in normal stresses. The topology parameter, Qf, computed from the velocity distribution, suggests that the “shear thickening” regime, where much of the elastic turbulence occurs in a single pore throat, is a consequence of viscoelastic normal stresses that cause a complex flow field. This flow field consists of extensional, shear, and rotational features around the constriction, as well as upstream and downstream of the constriction. Furthermore, this elastic turbulence regime, has high-pressure fluctuations, with a power-law decay ex
Anabaraonye BU, Crawshaw JP, Trusler JPM, 2019, Brine chemistry effects in calcite dissolution kinetics at reservoir conditions, Chemical Geology, Vol: 509, Pages: 92-102, ISSN: 0009-2541
Understanding the chemical interactions between CO 2 -saturated brine systems and reservoir rocks is essential for predicting the fate of CO 2 following injection into a geological reservoir. In this work, the dissolution rates of calcite (CaCO 3 ) in CO 2 -saturated brines were measured at temperatures between 325 K and 373 K and at pressures up to 10 MPa. The experiments were performed in batch reactors implementing the rotating disk technique in order to eliminate the influence of fluid-surface mass transport resistance and obtain surface reaction rates. Three aqueous brine systems were investigated in this study: NaCl at a molality m = 2.5 mol·kg −1 , NaHCO 3 with m ranging from (0.005 to 1) mol·kg −1 and a multicomponent Na-Mg-K-Cl-SO 4 -HCO 3 brine system with an ionic strength of 1.8 mol·kg −1 . Measured dissolution rates were compared with predictions from previously published models. Activity calculations were performed according to the Pitzer model as implemented in the PHREEQC geochemical simulator. Calcite dissolution rates in NaCl and the multicomponent brine system showed minor increases when compared to the (CO 2 + H 2 O) system at identical conditions, despite the lower concentration of dissolved CO 2 . These trends are consistent with the expected minor decreases in solution pH. In NaHCO 3 systems, consistent with increase in solution pH, significant decreases in dissolution rates were observed. In addition, these systems significantly deviated from model predictions at higher salt molalities. Vertical scanning interferometry (VSI) was used to examine the mineral surfaces before and after dissolution experiments to provide qualitative information on saturation states and dissolution mechanism.
Liyanage R, Cen J, Krevor S, et al., 2019, Multidimensional observations of dissolution-driven convection in simple porous media using X-ray CT scanning, Transport in Porous Media, Vol: 126, Pages: 355-378, ISSN: 0169-3913
We present an experimental study of dissolution-driven convection in a three-dimensional porous medium formed from a dense random packing of glass beads. Measurements are conducted using the model fluid system MEG/water in the regime of Rayleigh numbers, Ra=2000−5000. X-ray computed tomography is applied to image the spatial and temporal evolution of the solute plume non-invasively. The tomograms are used to compute macroscopic quantities including the rate of dissolution and horizontally averaged concentration profiles, and enable the visualisation of the flow patterns that arise upon mixing at a spatial resolution of about (2×2×2)mm3. The latter highlights that under this Ra regime convection becomes truly three-dimensional with the emergence of characteristic patterns that closely resemble the dynamical flow structures produced by high-resolution numerical simulations reported in the literature. We observe that the mixing process evolves systematically through three stages, starting from pure diffusion, followed by convection-dominated and shutdown. A modified diffusion equation is applied to model the convective process with an onset time of convection that compares favourably with the literature data and an effective diffusion coefficient that is almost two orders of magnitude larger than the molecular diffusivity of the solute. The comparison of the experimental observations of convective mixing against their numerical counterparts of the purely diffusive scenario enables the estimation of a non-dimensional convective mass flux in terms of the Sherwood number, Sh=0.025Ra. We observe that the latter scales linearly with Ra, in agreement with both experimental and numerical studies on thermal convection over the same Ra regime.
Eguagie E, Berg S, Crawshaw J, et al., 2019, Flexible coiled polymer dynamics in a single pore throat with effects of flow resistance and normal stresses
We investigate the challenges involved in the use of polymer flooding as a chemical enhanced oil recovery (cEOR) technique for improving mobility ratio and enhancing macroscopic sweep efficiency. Flexible coiled polymers in porous media undergo stretching in a spatially heterogeneous structure. Due to the viscoelasticity of these polymers, they stretch continuously depending on their previous deformation until their elastic limit is reached and relaxation occurs. Previous research has proposed that at a certain critical flow rate, the relaxation of polymers cause an increase in viscosity and in turn a better mobility for enhancing microscopic sweep in porous media. However, others have reported that the increased viscosity in porous media is not so much related to the elasticity but more on the normal stresses that occur when polymers are sheared in porous media flow. One similar fact is that as increased viscosity is observed an enhanced pressured drop occurs and the flow becomes highly unstable even at laminar flow regime. This unstable flow is termed the elastic instability or turbulence but the details of this kind of turbulence, its consequences and applicability on the impact of oil recovery is not understood. In this work, we experimentally investigate the flow behaviors of flexible coiled polymers of hydrolyzed polyacrylamide (HPAM) based on a single pore throat geometry using a microfluidic device. The aim is to adequately parameterize the effects of the normal stress difference in shear and extension as a function of the geometry and intrinsic characteristics of the polymer solutions at different Deborah (De) numbers. Hence, we carry out pressure drop and particle image velocimetry experiments and results showed a critical De at which polymer viscosity increases as well as the normal stress difference. It was also observed that the flow resistance might be a function of both the elasticity and the normal stresses in shear flow, however, extensional stresse
Eguagie E, Berg S, Crawshaw J, et al., 2019, Flexible coiled polymer dynamics in a single pore throat with effects of flow resistance and normal stresses
© 2019 European Association of Geoscientists and Engineers, EAGE. All Rights Reserved. We investigate the challenges involved in the use of polymer flooding as a chemical enhanced oil recovery (cEOR) technique for improving mobility ratio and enhancing macroscopic sweep efficiency. Flexible coiled polymers in porous media undergo stretching in a spatially heterogeneous structure. Due to the viscoelasticity of these polymers, they stretch continuously depending on their previous deformation until their elastic limit is reached and relaxation occurs. Previous research has proposed that at a certain critical flow rate, the relaxation of polymers cause an increase in viscosity and in turn a better mobility for enhancing microscopic sweep in porous media. However, others have reported that the increased viscosity in porous media is not so much related to the elasticity but more on the normal stresses that occur when polymers are sheared in porous media flow. One similar fact is that as increased viscosity is observed an enhanced pressured drop occurs and the flow becomes highly unstable even at laminar flow regime. This unstable flow is termed the elastic instability or turbulence but the details of this kind of turbulence, its consequences and applicability on the impact of oil recovery is not understood. In this work, we experimentally investigate the flow behaviors of flexible coiled polymers of hydrolyzed polyacrylamide (HPAM) based on a single pore throat geometry using a microfluidic device. The aim is to adequately parameterize the effects of the normal stress difference in shear and extension as a function of the geometry and intrinsic characteristics of the polymer solutions at different Deborah (De) numbers. Hence, we carry out pressure drop and particle image velocimetry experiments and results showed a critical De at which polymer viscosity increases as well as the normal stress difference. It was also observed that the flow resistance might be a functio
Singh K, Anabaraonye BU, Blunt MJ, et al., 2018, Partial dissolution of carbonate rock grains during reactive CO<inf>2</inf>-saturated brine injection under reservoir conditions, Advances in Water Resources, Vol: 122, Pages: 27-36, ISSN: 0309-1708
One of the major concerns of carbon capture and storage (CCS) projects is the prediction of the long-term storage security of injected CO2. When injected underground in saline aquifers or depleted oil and gas fields, CO2mixes with the resident brine to form carbonic acid. The carbonic acid can react with the host carbonate rock, and alter the rock structure and flow properties. In this study, we have used X-ray micro-tomography and focused ion beam scanning electron microscopy (FIB-SEM) techniques to investigate the dissolution behavior in wettability-altered carbonate rocks at the nm- to µm-scale, to investigate CO2storage in depleted oil fields that have oil-wet or mixed-wet conditions. Our novel procedure of injecting oil after reactive transport has revealed previously unidentified (ghost) regions of partially-dissolved rock grains that were difficult to identify in X-ray tomographic images after dissolution from single fluid phase experiments. We show that these ghost regions have a significantly higher porosity and pore sizes that are an order of magnitude larger than that of unreacted grains. The average thickness of the ghost regions as well as the overall rock dissolution decreases with increasing distance from the injection point. During dissolution micro-porous rock retains much of its original fabric. This suggests that considering the solid part of these ghost regions as macro (bulk) pore space can result in the overestimation of porosity and permeability predicted from segmented X-ray tomographic images, or indeed from reactive transport models that assume a uniform, sharp reaction front at the grain surface.
Gray F, Anabaraonye B, Shah S, et al., 2018, Chemical mechanisms of dissolution of calcite by HCl in porous media: simulations and experiment, Advances in Water Resources, Vol: 121, Pages: 369-387, ISSN: 0309-1708
We use a pore-scale dissolution model to simulate the dissolution of calcite by HCl in two different systems and compare with experiment. The model couples flow and transport with chemical reactions at the mineral surface and in the fluid bulk. Firstly, we inject HCl through a single channel drilled through a solid calcite core as a simple validation case, and as a model system with which to elucidate the chemical mechanisms of the dissolution process. The overall dissolution rate is compared to a corresponding experiment. Close agreement with experimental and simulated dissolution rates is found, which also serves to validate the model. We also define a new form of effective Damkohler number which can be obtained from simulated chemical distributions, and show how this gives a more precise measure of the balance of transport and reaction. Secondly, we inject HCl into a Ketton carbonate rock core at high flow rate, which leads to wormhole formation, and compare to experiment. The simulation matches the experimental mass dissolution rate extracted from the micro-CT images, and predicts the resulting morphological changes reasonably well. The permeability change though is greater in the experiment than in the simulation, and this is shown to be due to more elongated wormhole formation in experiment. Possible reasons for this are discussed, including uncertainties in diffusion coefficients, and calcite density variations and micro-porosity in the Ketton grains. The distribution of chemical species from the simulation then permits a detailed understanding of the rate-controlling mechanisms at work, including the relative importance of the H+–calcite and H2CO3–calcite dissolution pathways.
Zacharoudiou I, Boek E, Crawshaw J, 2018, The impact of drainage displacement patterns and Haines jumps on CO2 storage efficiency, Scientific Reports, Vol: 8, ISSN: 2045-2322
Injection of CO2 deep underground into porous rocks, such as saline aquifers, appears to be a promising tool for reducing CO2 emissions and the consequent climate change. During this process CO2 displaces brine from individual pores and the sequence in which this happens determines the efficiency with which the rock is filled with CO2 at the large scale. At the pore scale, displacements are controlled by the balance of capillary, viscous and inertial forces. We simulate this process by a numerical technique, multi-GPU Lattice Boltzmann, using X-ray images of the rock pores. The simulations show the three types of fluid displacement patterns, at the larger scale, that have been previously observed in both experiments and simulations: viscous fingering, capillary fingering and stable displacement. Here we examine the impact of the patterns on storage efficiency and then focus on slow flows, where displacements at the pore scale typically happen by sudden jumps in the position of the interface between brine and CO2, Haines jumps. During these jumps, the fluid in surrounding pores can rearrange in a way that prevent later displacements in nearby pores, potentially reducing the efficiency with which the CO2 fills the total available volume in the rock.
Rufai AK, Crawshaw JP, 2018, Capillary disconnect during drying in model porous media at different wettability, 21st International Drying Symposium (IDS), Publisher: UNIV POLITECNICA VALENCIA, Pages: 1237-1244
Yu W, Liu T, Crawshaw J, et al., 2018, Ultrafiltration and nanofiltration membrane fouling by natural organic matter: Mechanisms and mitigation by pre-ozonation and pH, Water Research, Vol: 139, Pages: 353-362, ISSN: 0043-1354
The fouling of ultrafiltration (UF) and nanofiltration (NF) membranes during the treatment of surface waters continues to be of concern and the particular role of natural organic matter (NOM) requires further investigation. In this study the effect of pH and surface charge on membrane fouling during the treatment of samples of a representative surface water (Hyde Park recreational lake) were evaluated, together with the impact of pre-ozonation. While biopolymers in the surface water could be removed by the UF membrane, smaller molecular weight (MW) fractions of NOM were poorly removed, confirming the importance of membrane pore size. For NF membranes the removal of smaller MW fractions (800 Da–10 kDa) was less than expected from their pore size; however, nearly all of the hydrophobic, humic-type substances could be removed by the hydrophilic NF membranes for all MW distributions (greater than 90%). The results indicated the importance of the charge and hydrophilic nature of the NOM. Thus, the hydrophilic NF membrane could remove the hydrophobic organic matter, but not the hydrophilic substances. Increasing charge effects (more negative zeta potentials) with increasing solution pH were found to enhance organics removal and reduce fouling (flux decline), most likely through greater membrane surface repulsion. Pre-ozonation of the surface water increased the hydrophilic fraction and anionic charge of NOM and altered their size distributions. This resulted in a decreased fouling (less flux decline) for the UF and smaller pore NF, but a slight increase in fouling for the larger pore NF. The differences in the NF behavior are believed to relate to the relative sizes of ozonated organic fractions and the NF pores; a similar size of ozonated organic fractions and the NF pores causes significant membrane fouling.
Rufai AK, Crawshaw J, 2018, Effect of wettability changes on evaporation rate and the permeability impairment due to salt deposition, ACS Earth and Space Chemistry, Vol: 2, Pages: 320-329, ISSN: 2472-3452
Pore-scale visualization was employed to investigate evaporative drying of brine and associated salt deposition at different wetting conditions, using a 2.5D etched-silicon/glass micromodel based on a thin section image of a carbonate rock. We also compared air drying with CO2 drying, with the latter having important applications in CO2 sequestration processes. The resulting permeability impairment was also measured. For deionized water in a water-wet model, we observed the three classical periods of evaporation: the constant rate period (CRP), the falling rate period (FRP), and the receding front period (RFP). The length of the deionized water CRP was much shorter for a uniformly oil-wet model, but mixed wettability made little difference to the drying process. For brine systems at all wetting conditions, the dry area became linear with the square root of time after a short CRP. This is due to the deposited salt acting as a physical barrier to hydraulic connectivity, unlike the case of deionized water, which is due to capillary disconnection from the fracture channel. For the water-wet model, we observed two regions of a linear downward trend in the matrix and fracture permeability measurements. A similar trend was observed for the mixed-wet systems. However, for the oil-wet systems, fracture permeability only changes slightly even for 360 g/L brine, a result of the absence of salt deposits in the fracture caused by the early rupture of the liquid-wetting films needed to aid hydraulic connectivity. Overall, matrix permeability for all wetting conditions decreased with increasing brine concentration and was almost total for the 360 g/L brine. Finally, using CO2 rather than air as carrier gas makes the brine phase more wetting, especially in the deionized water case, with the result that hydraulic connectivity was maintained for longer in the CO2 case compared to dry out with air.
Rufai AK, Crawshaw J, 2017, Micromodel Observations of Evaporative Drying and Salt Deposition in Porous Media, Physics of Fluids, Vol: 29, ISSN: 1070-6631
Most evaporation experiments using artificial porous media have focused on single capillaries or sand packs. We have carried out, for the first time, evaporation studies on a 2.5D micromodel based on a thin section of a sucrosic dolomite rock. This allowed direct visual observation of pore-scale processes in a network of pores. NaCl solutions from 0 wt. % (de-ionized water) to 36 wt. % (saturated brine) were evaporated by passing dry air through a channel in front of the micromodel matrix. For de-ionized water, we observed the three classical periods of evaporation: the constant rate period (CRP) in which liquid remains connected to the matrix surface, the falling rate period, and the receding front period, in which the capillary connection is broken and water transport becomes dominated by vapour diffusion. However, when brine was dried in the micromodel, we observed that the length of the CRP decreased with increasing brine concentration and became almost non-existent for the saturated brine. In the experiments with brine, the mass lost by evaporation became linear with the square root of time after the short CRP. However, this is unlikely to be due to capillary disconnection from the surface of the matrix, as salt crystals continued to be deposited in the channel above the matrix. We propose that this is due to salt deposition at the matrix surface progressively impeding hydraulic connectivity to the evaporating surface.
Li X, Peng C, Crawshaw JP, et al., 2017, The pH of CO<inf>2</inf>-saturated aqueous NaCl and NaHCO<inf>3</inf>solutions at temperatures between 308 K and 373 K at pressures up to 15 MPa, Fluid Phase Equilibria, Vol: 458, Pages: 253-263, ISSN: 0378-3812
The pH is a critical variable for carbon storage in saline aquifers because it affects the reaction rate and equilibrium state of the reservoir rocks, thus influencing the rates of mineral dissolution or precipitation and the integrity of caprocks. In this work, high-pressure pH and Ag/AgCl-reference electrodes were used to measure the pH of CO 2 -saturated aqueous solutions of NaCl and NaHCO 3 . The expanded uncertainty of the pH measurements is 0.20 at 95% probability. For CO 2 -saturated NaCl(aq), measurements were carried out at total pressures from (0.37 to 15.3) MPa and temperatures from (308 to 373) K with NaCl molalities of (1, 3 and 5) mol·kg −1 . For CO 2 -saturated NaHCO 3 (aq), the pH was measured at total pressures from (0.2 to 15.3) MPa and temperatures from (308 to 353) K with NaHCO 3 molalities of (0.01, 0.1 and 1) mol·kg −1 . The pH was found to decrease with increase in pressure and with decrease in temperature for both CO 2 -saturated NaCl and NaHCO 3 solutions. For CO 2 -saturated NaCl(aq), the pH was observed to decrease with increase of salt molality, while for CO 2 -saturated NaHCO 3 , the opposite behaviour was observed. The results have been compared with predictions obtained from the PHREEQC geochemical simulator (version 3.3.9) incorporating the Pitzer activity-coefficient model with parameters taken from the literature. For CO 2 -saturated NaCl(aq), agreement to within ±0.2 pH units was observed in most cases, although deviations of up to 0.3 were found at the highest molality. In the case of CO 2 -saturated NaHCO 3 (aq), the experimental data were found to deviate increasingly from the model with increasing salt molality and, at 1 mol·kg −1 , the model underestimated the pH by between 0.3 and 0.7 units.
Liyanage R, Crawshaw, Krevor, et al., 2017, Multidimensional Imaging of Density Driven Convection in a Porous Medium, 13th International Conference on Greenhouse Gas Control Technologies, GHGT-13, Publisher: Elsevier, Pages: 4981-4985, ISSN: 1876-6102
Carbon dioxide (CO2) sequestration is a climate change mitigation technique which relies on residual and solubility trapping in injection locations with saline aquifers. The dissolution of CO2 into resident brines results in density-driven convection which further enhances the geological trapping potential. We report on the use of an analogue fluid pair to investigate density-driven convection in 3D in an unconsolidated bead pack. X-ray computed tomography (CT) is used to image density-driven convection in the opaque porous medium non-invasively. Two studies have been conducted that differ by the Rayleigh number (Ra) of the system, which in this study is changed by altering the maximum density difference of the fluid pair. We observe the same general mixing pattern in both studies. Initially, many high density fingers move downward through the bead pack and as time progresses these coalesce and form larger dominate flow paths. However, we also observe that a higher Rayleigh number leads to the denser plume moving faster towards the bottom of the system. Due to the finite size of the system, this in turn leads to early convective shut-down.
Zacharoudiou I, Chapman E, Boek E, et al., 2017, Pore-filling events in single junction micro-models with corresponding lattice Boltzmann simulations, Journal of Fluid Mechanics, Vol: 824, Pages: 550-573, ISSN: 0022-1120
The aim of this work is to better understand fluid displacement mechanisms at the pore scale in relation to capillary-filling rules. Using specifically designed micro-models we investigate the role of pore body shape on fluid displacement during drainage and imbibition via quasi-static and spontaneous experiments at ambient conditions. The experimental results are directly compared to lattice Boltzmann (LB) simulations. The critical pore-filling pressures for the quasi-static experiments agree well with those predicted by the Young–Laplace equation and follow the expected filling events. However, the spontaneous imbibition experimental results differ from those predicted by the Young–Laplace equation; instead of entering the narrowest available downstream throat the wetting phase enters an adjacent throat first. Thus, pore geometry plays a vital role as it becomes the main deciding factor in the displacement pathways. Current pore network models used to predict displacement at the field scale may need to be revised as they currently use the filling rules proposed by Lenormand et al. (J. Fluid Mech., vol. 135, 1983, pp. 337–353). Energy balance arguments are particularly insightful in understanding the aspects affecting capillary-filling rules. Moreover, simulation results on spontaneous imbibition, in excellent agreement with theoretical predictions, reveal that the capillary number itself is not sufficient to characterise the two phase flow. The Ohnesorge number, which gives the relative importance of viscous forces over inertial and capillary forces, is required to fully describe the fluid flow, along with the viscosity ratio.
Hu R, Crawshaw J, 2017, Measurement of the Rheology of Crude Oil in Equilibrium with CO2 at Reservoir Conditions., Journal of Visualized Experiments, Vol: 124, ISSN: 1940-087X
A rheometer system to measure the rheology of crude oil in equilibrium with carbon dioxide (CO2) at high temperatures and pressures is described. The system comprises a high-pressure rheometer which is connected to a circulation loop. The rheometer has a rotational flow-through measurement cell with two alternative geometries: coaxial cylinder and double gap. The circulation loop contains a mixer, to bring the crude oil sample into equilibrium with CO2, and a gear pump that transports the mixture from the mixer to the rheometer and recycles it back to the mixer. The CO2 and crude oil are brought to equilibrium by stirring and circulation and the rheology of the saturated mixture is measured by the rheometer. The system is used to measure the rheological properties of Zuata crude oil (and its toluene dilution) in equilibrium with CO2 at elevated pressures up to 220 bar and a temperature of 50 °C. The results show that CO2 addition changes the oil rheology significantly, initially reducing the viscosity as the CO2 pressure is increased and then increasing the viscosity above a threshold pressure. The non-Newtonian response of the crude is also seen to change with the addition of CO2.
Boek ES, Zacharoudiou I, Gray F, et al., 2017, Multiphase-Flow and Reactive-Transport Validation Studies at the Pore Scale by Use of Lattice Boltzmann Computer Simulations, SPE Annual Technical Conference and Exhibition, Publisher: SOC PETROLEUM ENG, Pages: 940-949, ISSN: 1086-055X
Welch NJ, Gray F, Butcher AR, et al., 2017, High-resolution 3D FIB-SEM image analysis and validation of numerical simulations of nanometre-scale porous ceramic with comparisons to experimental results, Transport in Porous Media, Vol: 118, Pages: 373-392, ISSN: 0169-3913
The development of focused ion beam-scanning electron microscopy (FIB-SEM) techniques has allowed high-resolution 3D imaging of nanometre-scale porous materials. These systems are of important interest to the oil and gas sector, as well as for the safe long-term storage of carbon and nuclear waste. This work focuses on validating the accurate representation of sample pore space in FIB-SEM-reconstructed volumes and the predicted permeability of these systems from subsequent single-phase flow simulations using a highly homogeneous nanometre-scale, mesoporous (2–50 nm) to macroporous (>50 nm), porous ceramic in initial developments for digital rock physics. The limited volume of investigation available from FIB-SEM has precluded direct quantitative validation of petrophysical parameters estimated from such studies on rock samples due to sample heterogeneity, large variations in recorded sample pore sizes and lack of pore connectivity. By using homogeneous synthetic ceramic samples we have shown that lattice-Boltzmann flow simulations using processed FIB-SEM images are capable of predicting the permeability of a homogeneous material dominated by 10–100 nanometre-scale pores (similar, albeit simpler, to those in natural samples) at the much larger scale where permeability measurements become practical. This result shows the LB flow simulations can be used with confidence in pores at this scale allowing future work to focus on sample preparation techniques for samples sensitive to drying and multiple FIB-SEM site selection for the population of larger-scale models for heterogeneous systems.
Shah SM, Crawshaw JP, Gray F, et al., 2017, Convex hull approach for determining rock representative elementary volume for multiple petrophysical parameters using pore-scale imaging and Lattice-Boltzmann modelling, Advances in Water Resources, Vol: 104, Pages: 65-75, ISSN: 0309-1708
In the last decade, the study of fluid flow in porous media has developed considerably due to the combination of X-ray Micro Computed Tomography (micro-CT) and advances in computational methods for solving complex fluid flow equations directly or indirectly on reconstructed three-dimensional pore space images. In this study, we calculate porosity and single phase permeability using micro-CT imaging and Lattice Boltzmann (LB) simulations for 8 different porous media: beadpacks (with bead sizes 50 µm and 350 µm), sandpacks (LV60 and HST95), sandstones (Berea, Clashach and Doddington) and a carbonate (Ketton). Combining the observed porosity and calculated single phase permeability, we shed new light on the existence and size of the Representative Element of Volume (REV) capturing the different scales of heterogeneity from the pore-scale imaging. Our study applies the concept of the ‘Convex Hull’ to calculate the REV by considering the two main macroscopic petrophysical parameters, porosity and single phase permeability, simultaneously. The shape of the hull can be used to identify strong correlation between the parameters or greatly differing convergence rates. To further enhance computational efficiency we note that the area of the convex hull (for well-chosen parameters such as the log of the permeability and the porosity) decays exponentially with sub-sample size so that only a few small simulations are needed to determine the system size needed to calculate the parameters to high accuracy (small convex hull area). Finally we propose using a characteristic length such as the pore size to choose an efficient absolute voxel size for the numerical rock.
Rufai A, Crawshaw J, Maitland G, 2016, Capillary disconnect during evaporation in porous media: Visualization of transition from stage-1 to stage-2 evaporation regime, 2016 AIChE Annual Meeting, Pages: 219-219
Hu R, Trusler JPM, Crawshaw JP, 2016, Effect of CO2 Dissolution on the Rheology of a Heavy Oil/Water Emulsion, 17th International Conference on Petroleum Phase Behavior and Fouling (PetroPhase), Publisher: American Chemical Society, Pages: 3399-3408, ISSN: 0887-0624
During the later stages of flow from an oil well, water inevitably appears in the produced fluids. When crude oil and water are energetically mixed by constrictions in the production tubing, emulsions can form. Heavy crudes may also contain surface-active agents that can stabilize the emulsion, resulting in persistent flow problems. If carbon dioxide is injected into such a reservoir (e.g., for CO2 enhanced oil recovery), then CO2 will dissolve into both oil and water phases affecting the emulsion properties; however, this aspect has been neglected in the literature thus far. This paper presents a study of the rheology of oil/water emulsion altered by carbon dioxide. The emulsion was prepared by blending 50 wt % water and 50 wt % Zuata heavy crude oil in a high shear mixer (Silverson), resulting in a water-in-oil emulsion. The emulsion was subsequently stable at ambient conditions for several weeks without the addition of any surfactants. A high-pressure rheometer system coupled to a mixing vessel and fluid circulation loop allowed the emulsion to be brought into equilibrium with CO2, and its rheology was then measured at a temperature of 50 °C and pressures from ambient to 120 bar. The emulsion without dissolved CO2 was found to be slightly shear thinning below a critical shear rate, above which the viscosity jumped to a much lower value. The CO2 dissolution had two effects: first, it reduced the emulsion viscosity at low shear while preserving the shear thinning behavior, and second, increasing the CO2 pressure in equilibrium with the emulsion increased the critical shear rate at which the viscosity jump occurred. At shear rates above the jump, the emulsion viscosity dropped to a level lower than that of the original continuous phase (oil). It is likely that the viscosity jump occurred as a result of phase inversion; however, this was difficult to observe directly. The jump was reversed (with some hysteresis) as the shear rate was reduced again. Dissolved CO2
Shah SM, Crawshaw JP, Boek ES, 2016, Three-dimensional imaging of porous media using confocal laser scanning microscopy, Journal of Microscopy, Vol: 265, Pages: 261-271, ISSN: 0022-2720
SummaryIn the last decade, imaging techniques capable of reconstructing three-dimensional (3-D) pore-scale model have played a pivotal role in the study of fluid flow through complex porous media. In this study, we present advances in the application of confocal laser scanning microscopy (CLSM) to image, reconstruct and characterize complex porous geological materials with hydrocarbon reservoir and CO2 storage potential. CLSM has a unique capability of producing 3-D thin optical sections of a material, with a wide field of view and submicron resolution in the lateral and axial planes. However, CLSM is limited in the depth (z-dimension) that can be imaged in porous materials. In this study, we introduce a ‘grind and slice’ technique to overcome this limitation. We discuss the practical and technical aspects of the confocal imaging technique with application to complex rock samples including Mt. Gambier and Ketton carbonates. We then describe the complete workflow of image processing to filtering and segmenting the raw 3-D confocal volumetric data into pores and grains. Finally, we use the resulting 3-D pore-scale binarized confocal data obtained to quantitatively determine petrophysical pore-scale properties such as total porosity, macro- and microporosity and single-phase permeability using lattice Boltzmann (LB) simulations, validated by experiments.Lay descriptionIn this study, a method is described to apply confocal laser scanning microscopy (CLSM) to image, reconstruct and characterize statistically the 3-D pore space of geological rock samples. Confocal Laser Scanning Microscope has a unique capability of producing very thin optical sections of a material, with submicron resolution in the lateral and axial planes. The limitation of CLSM is the restriction on acquiring depth (z-dimension) information because the observed light intensity is attenuated with depth due to absorption and scattering by the material. It is an extension of the methods curren
Hu R, Crawshaw JP, Trusler JPM, et al., 2016, Rheology and phase behavior of carbon dioxide and crude oil mixtures, Energy & Fuels, Vol: 31, Pages: 5776-5784, ISSN: 0887-0624
The rheology of Zuata heavy crude oil, saturated with carbon dioxide, was studied at a temperature of 50 °C and pressures up to 220 bar. Observations of phase behavior were also reported and used to interpret the rheological data. The crude oil is very viscous and non-Newtonian at ambient pressure, but when brought into equilibrium with CO2, the non-Newtonian behavior was weakened and eventually disappeared at high CO2 pressures. When diluted with 10 and 30 wt % toluene, the diluted crude oils and their mixtures with CO2 behaved as Newtonian fluids. The CO2-saturated mixture of the crude oil samples showed an exponential decrease in viscosity with increasing CO2 pressure but an increase in viscosity at higher pressures. During observation through a view cell, the CO2 dissolution caused a swelling effect on the original crude oil. When saturated with CO2, the swelling effect also occurred on the 10 wt % diluted crude oil but the volume of the oil-rich phase was decreased at higher pressures. However, for the 30 wt % diluted crude oil, a second liquid phase was observed on top of the oil-rich phase, at pressures higher than the CO2 critical point. The mixture viscosity was inversely proportional to the CO2 solubility.
Gray F, Cen J, Shah SM, et al., 2016, Simulating dispersion in porous media and the influence of segmentation on stagnancy in carbonates, Advances in Water Resources, Vol: 97, Pages: 1-10, ISSN: 1872-9657
Understanding the transport of chemical components in porous media is fundamentally important to many reservoir processes such as contaminant transport and reactive flows involved in CO2 sequestration. Carbonate rocks in particular present difficulties for pore-scale simulations because they contain large amounts of sub-micron porosity. In this work, we introduce a new hybrid simulation model to calculate hydrodynamic dispersion in pore-scale images of real porous media and use this to elucidate the origins and behaviour of stagnant zones arising in transport simulations using micro-CT images of carbonates. For this purpose a stochastic particle model for simulating the transport of a solute is coupled to a Lattice-Boltzmann algorithm to calculate the flow field. The particle method incorporates second order spatial and temporal resolution to resolve finer features of the domain. We demonstrate how dispersion coefficients can be accurately obtained in capillaries, where corresponding analytical solutions are available, even when these are resolved to just a few lattice units. Then we compute molecular displacement distributions for pore-spaces of varying complexity: a pack of beads; a Bentheimer sandstone; and a Portland carbonate. Our calculated propagator distributions are compared directly with recent experimental PFG-NMR propagator distributions (Scheven et al., 2005; Mitchell et al., 2008), the latter excluding spin relaxation mechanisms. We observe that the calculated transport propagators can be quantitatively compared with the experimental distribution, provided that spin relaxations in the experiment are excluded, and good agreement is found for both the sandstone and the carbonate. However, due to the absence of explicit micro-porosity from the carbonate pore space image used for flow field simulations we note that there are fundamental differences in the physical origins of the stagnant zones for micro-porous rocks between simulation and experiment. We sh
Peng C, Anabaraonye BU, Crawshaw JP, et al., 2016, Kinetics of carbonate mineral dissolution in CO2-acidified brines at storage reservoir conditions., Faraday Discussions, Vol: 192, Pages: 545-560, ISSN: 1364-5498
We report experimental measurements of the dissolution rate of several carbonate minerals in CO2-saturated water or brine at temperatures between 323 K and 373 K and at pressures up to 15 MPa. The dissolution kinetics of pure calcite were studied in CO2-saturated NaCl brines with molalities of up to 5 mol kg(-1). The results of these experiments were found to depend only weakly on the brine molality and to conform reasonably well with a kinetic model involving two parallel first-order reactions: one involving reactions with protons and the other involving reaction with carbonic acid. The dissolution rates of dolomite and magnesite were studied in both aqueous HCl solution and in CO2-saturated water. For these minerals, the dissolution rates could be explained by a simpler kinetic model involving only direct reaction between protons and the mineral surface. Finally, the rates of dissolution of two carbonate-reservoir analogue minerals (Ketton limestone and North-Sea chalk) in CO2-saturated water were found to follow the same kinetics as found for pure calcite. Vertical scanning interferometry was used to study the surface morphology of unreacted and reacted samples. The results of the present study may find application in reactive-flow simulations of CO2-injection into carbonate-mineral saline aquifers.
Shah SMK, Gray F, Crawshaw J, et al., 2015, Micro-computed tomography pore-scale study of flow in porous media: Effect of voxel resolution, Advances in Water Resources, Vol: 95, Pages: 276-287, ISSN: 1872-9657
A fundamental understanding of flow in porous media at the pore-scale is necessary to be able to upscale average displacement processes from core to reservoir scale. The study of fluid flow in porous media at the pore-scale consists of two key procedures: Imaging - reconstruction of three-dimensional (3D) pore space images; and modelling such as with single and two-phase flow simulations with Lattice-Boltzmann (LB) or Pore-Network (PN) Modelling. Here we analyse pore-scale results to predict petrophysical properties such as porosity, single-phase permeability and multi-phase properties at different length scales. The fundamental issue is to understand the image resolution dependency of transport properties, in order to up-scale the flow physics from pore to core scale. In this work, we use a high resolution micro-computed tomography (micro-CT) scanner to image and reconstruct three dimensional pore-scale images of five sandstones (Bentheimer, Berea, Clashach, Doddington and Stainton) and five complex carbonates (Ketton, Estaillades, Middle Eastern sample 3, Middle Eastern sample 5 and Indiana Limestone 1) at four different voxel resolutions (4.4 µm, 6.2 µm, 8.3 µm and 10.2 µm), scanning the same physical field of view. Implementing three phase segmentation (macro-pore phase, intermediate phase and grain phase) on pore-scale images helps to understand the importance of connected macro-porosity in the fluid flow for the samples studied. We then compute the petrophysical properties for all the samples using PN and LB simulations in order to study the influence of voxel resolution on petrophysical properties. We then introduce a numerical coarsening scheme which is used to coarsen a high voxel resolution image (4.4 µm) to lower resolutions (6.2 µm, 8.3 µm and 10.2 µm) and study the impact of coarsening data on macroscopic and multi-phase properties. Numerical coarsening of high resolution data is found to be superior to us
Hu R, Crawshaw JP, Trusler JPM, et al., 2015, Rheology of Diluted Heavy Crude Oil Saturated with Carbon Dioxide, Energy & Fuels, Vol: 29, Pages: 2785-2789, ISSN: 0887-0624
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