Polymer flooding – Does Microscopic Displacement Efficiency Matter?

Polymer flooding is an enhanced oil recovery (EOR) technique that aims to enhance the stability of the flood front in order to increase sweep efficiency and thereby increase hydrocarbon recovery. Polymer flooding studies often focus on large-scale sweep efficiency and neglect the impact of the pore-scale displacement efficiency of the multi-phase flow. This work explores the pore-scale behavior of water vs polymer flooding, and examines the impact of rock surface wettability on the microscopic displacement efficiency using digital rock physics. In this study, a micro-CT image of a sandstone rock sample was numerically simulated for both water and polymer flooding under oil-wet and water-wet conditions. All simulations were performed at a capillary number of 1E-5, corresponding to a capillary dominated flow regime. Results of the four two-phase flow imbibition simulations are analyzed with respect to displacement character, water phase break-through, viscous/capillary fingering, and trapped oil. In the water-wet scenario, differences between water flood and polymer flood are small, with the flood front giving a piston-like displacement and breakthrough occurring at about 0.4 pore volume (PV) for both types of injected fluid. On the other hand, for the oil-wet scenario, water flood and polymer flood show significant differences. In the water flood, fingering occurs and much of the oil is bypassed early on, whereas the polymer flood displaces more oil and thereby provides better microscopic sweep efficiency throughout the flood and especially around breakthrough. Overall the results for this rock sample indicate that water flood and polymer flood provide similar recovery for a water-wet condition, while the reduced mobility ratio of polymer flood gives significantly improved recovery for an oil-wet condition by avoiding the onset of microscopic (pore-scale) fingering that occurs in the water flood. This study suggests that depending on the rock-fluid conditions, the use of polymer can impact microscopic sweep efficiency, in addition to the well-known effect on macroscopic sweep behavior.La inyección de polímeros es una técnica de recobro mejorado de petróleo (EOR) que tiene como objetivo mejorar la estabilidad del frente de inyección para aumentar la eficiencia del desplazamiento de hidrocarburos y, por lo tanto, incrementar el factor de recobro. Lo estudios de inyección de polímeros a menudo se centran en la eficiencia del desplazamiento a gran escala e ignoran el impacto de los mecanismos de desplazamiento a escala microscópica, y rara vez evalúan la variabilidad de parámetros de flujo multifásico en el medio poroso. Este trabajo explora el comportamiento del agua contra la inyección de polímeros en el medio poroso, y examina el impacto de la humectabilidad de la superficie de la roca en la eficiencia de desplazamiento microscópico, utilizando tomografía computarizada de rayos X en muestras de roca. En este estudio, se simuló numéricamente una imagen de microtomografía computarizada de una muestra de roca arenisca, para un proceso de inyección de agua y polímeros en condiciones de mojabilidad al aceite y al agua. Todas las simulaciones se realizaron a un número capilar de 1E-5, correspondiente a un régimen de flujo dominado por fuerzas capilares y que es típico del flujo en yacimientos de hidrocarburos. Los resultados de las cuatro simulaciones de imbibición de flujo de dos fases se analizan con respecto al carácter desplazante, el avance de la fase acuosa, la digitación viscosa y capilar, y el aceite atrapado. En el escenario de mojabilidad al agua, las diferencias entre la inyección de agua y la inyección de polímeros son pequeñas, dado que el frente de inyección produce un  desplazamiento en forma de pistón y un avance que se produce a aproximadamente 0,4 volúmenes porosos para ambos tipos de fluido inyectado. Por otro lado, para el escenario de mojabilidad al petróleo, la inyección de agua y la inyección de polímeros muestran diferencias significativas. En la inyección de agua, se produce digitación y gran parte del petróleo se pasa por alto al principio; mientras que la inyección de polímeros desplaza más aceite y, por lo tanto, proporciona una mejor eficiencia de desplazamiento microscópico durante la inyección, especialmente alrededor de la ruptura. En general, los resultados para esta muestra de roca indican que la inyección de agua y la inyección de polímeros proporcionan un efecto de recobro similar para una condición de mojabilidad al agua, mientras que la relación de movilidad reducida de la inyección de polímeros proporciona un efecto de recobro significativamente mejorado para una condición de mojabilidad al aceite, al evitar la aparición de digitación microscópica (a escala de poro) que se produce en la inyección de agua. Este estudio sugiere que, dependiendo de las condiciones roca-fluido, el uso del polímero puede impactar la eficiencia de desplazamiento microscópico, además del efecto conocido sobre el comportamiento del desplazamiento macroscópico

Digital rock workflow to calculate wettability distribution in a reservoir rock

Wettability has a strong influence on multi-phase flow behavior through reservoir rock. Reservoir rocks tend to have spatially varying wettability. Prior to contact with oil, rocks are almost always naturally water-wet. As oil invades the pore-space over geologic time, the initial water-wet state may be altered in certain locations due to adhesion of substances within the oil phase to the grains. Mechanisms of wettability alteration depend on various properties such as pressure, temperature, mineral chemistry, surface roughness and fluid composition. In this study wettability alteration in a reservoir rock is studied through direct simulation using multiphase Lattice Boltzmann method where the computational grid is constructed from segmented micro-CT images of the rock sample. The pore-grain interface is defined by a triangulated surface mesh for accurate fluxes near boundary and local curvature calculation. A capillary pressure drainage simulation is conducted in a water-wet Berea sandstone sample initially filled with water. When oil invades the pore space as the capillary pressure is increased, a fraction of the pore-grain surface is altered towards an oil-wet condition, as determined by a novel wettability alteration process. This process calculates local curvature at every surface element of the rock, obtains local capillary pressure from the simulation and assumes a disjoining pressure to determine water-film breakage at every location of the pore-grain surface. As a result, a spatially varying rock wettability is created. Using this new wettability distribution, the simulation is continued to allow the fluid phases to redistribute accordingly. The process is iteratively carried out until both fluid saturation and wettability distribution converged at a given applied capillary pressure. Afterwards, the pressure is ramped up to the next stage and the process is repeated again. It has been found that the wettability alteration is a slow dynamic process where the non-wetting phase can gradually invade finer pore space as the surrounding grain wettability is altered. In this study, it has also been found that wettability alteration of the reservoir rock produces lower connate water saturation during primary drainage compared to the simulation results without alteration. The resulting spatially varying wettability distribution from primary drainage is used for a subsequent water flooding simulation to calculate water-oil relative permeability curves. The methodology presented in this work can be leveraged to better understand and predict an improved mixed wetting conditions found in the reservoir rocks which is needed for more accurate displacement tests such as relative permeability simulations

Pore-scale Analysis of CO

For storage in deep saline formations, where CO2 is injected into the pore spaces of rocks previously occupied by saline groundwater (brine), relative permeability is a key input parameter for predictive models. CO2 injectivity is considered to reach the maximum value at the CO2 endpoint relative permeability when brine saturation becomes irreducible. The objective of this study is to investigate the effect of viscosity ratio, interfacial tension and wettability on relative permeability during CO2-brine drainage. A multiphase lattice Boltzmann model (LBM) is employed to numerically measure pore-scale dynamics in CO2-brine flow in the sample of Berea sandstone. CO2/brine with interfacial tension from 30 to 45 mN/m and viscosity ratio from 0.05 to 0.17 (the range of values expected for typical storage reservoirs conditions) are carried out to systematically assess the influence on the relative permeability curves. Although CO2 storage in sandstone saline aquifers is predominantly water wet, there are contradictory results as to the magnitude of the contact angle and its variation with fluid conditions. Therefore, the range of wetting conditions is studied to gain a better insight into the effect of wettability on supercritical CO2 displacement. In this study, it is observed that interfacial tension variations play a trivial impact while both of viscosity ratio and wettability are likely to have a significant effect on relative permeability curves under representative condition of storage reservoirs. We also perform a near-wellbore scale geomechanics analysis to investigate the impact of relative permeability on CO2 injectivity. The result shows that water-wet condition facilitates the CO2 injection when there is no fracture induced

Micromechanics Digital Rock: Parameterization of Consolidation Level using a Grain Contact Model

The mechanical behaviour of sedimentary rocks is conditioned by the interactions at the grain-grain contacts. We present a micromechanics digital rock workflow based on a cohesive contact model and introduce a general parameterization that can capture two extreme contact behaviours: free grains and fixed grains, as well as any intermediate degree of grain consolidation. With this parametric cohesive contact model, we can simulate a wide range of sedimentary rocks, from unconsolidated to well-consolidated rocks. We present a benchmark study on several samples and compare with laboratory-measured elastic moduli to calibrate its degree of consolidation. Simulations that do not include the grain contact modelling, tend to overestimate the elastic moduli, which manifests the significance of this contribution to capture well the grain contact behaviour. To demonstrate the impact of properly capturing the degree of consolidation on the rock strength and failure pattern, we present results for numerical uniaxial compression testing. This workflow provides physics-based solution to complex grain contact behaviour, which complements laboratory core analysis, and can be useful to reveal underlying grain-scale processes governing rock mechanical behaviour

Towards Multiscale Digital Rocks: Application of a Sub-Resolution Production Model to a multiscale Sandstone

Many digital rock methodologies use a direct simulation approach, where only resolved pores are accounted for. This approach limits the types of rocks that can be analyzed, excluding some types of carbonates, unconventionals, and complex sandstones from the digital rock analysis. This is due to the challenge for single scale imaging to capture the full range of relevant pore sizes present in multiscale rocks. In this paper, a physical model is presented, within the context of an established direct simulation approach, to predict the production of hydrocarbons including the contribution of sub-resolution pores. The direct simulation component of the model employs a multiphase lattice Boltzmann method to simulate multiphase fluid flow displacement in resolved pores. In the production model, the amount of hydrocarbons present in the sub-resolution pores is identified and a physical description of the production behavior is provided. This allows a relative permeability curve to be predicted for rocks where mobile hydrocarbons are present in pores smaller than the image resolution. This simplified model for the oil movement in the unresolved pore space is based on a physical interpretation of different regions marked by simulation resolution limits in a USBM wettability test curve. The proposed methodology is applied to high-resolution microCT images of a sandstone that contains pores at multiple scales, some resolved and some not resolved. To allow for benchmarking, experimental routine and special core analysis data was also obtained. Good agreement to experimental results is observed, specifically in absolute and relative permeability. The presented multiscale model has the potential to extend the classes of reservoir rocks eligible for digital rock analysis and paves the way for further advancements in the modelling of multiscale rocks, particularly unconventionals and carbonates

Multi-scale Digital Rock: Application of a multi-scale multi-phase workflow to a Carbonate reservoir rock

In some of the challenging digital rock applications the trade-off between model resolution and representative elemental volume is not captured in a single resolution model satisfying the minimum requirements for both aspects. In the wide range of lithofacies found in carbonate reservoir rocks, some facies fall in this category, where large pores, ooids or vugs, are connected by small scale porous structures that could have orders of magnitude smaller pores. In these cases a multi-scale digital rock approach is needed. We recently developed an extension to a digital rock workflow that includes a way to handle sub-resolution pore structures in single phase and multi-phase flow scenarios in addition to regular resolvable pore structures. Here we present an application of this methodology to a multi-scale limestone carbonate rock. A microCT image captures the large pores for this sample, but does not resolve all the pores smaller than the pixel size. A three phase image segmentation that considers pore, solid and under-resolved pores or porous media (PM) is generated. A high resolution confocal image model is obtained for a representative region of the smaller pores or PM region. A set of constitutive relationships (namely permeability vs. porosity, capillary pressure vs saturation and relative permeability vs saturation) are obtained by simulation from the high resolution confocal model. The low resolution segmented image, a porosity distribution image, and the constitutive relationships for the PM are input in an extended LBM multi-scale multi-phase solver. First we present results for absolute permeability and show a parametric study on PM permeability. The model recovers the expected behaviour when the PM regions are considered pore or solid. A consistent value of permeability with experiments is obtained when we use the PM permeability from the high resolution model. To demonstrate the multi-phase behaviour, we present results for capillary pressure imbibition multi-scale simulations. Here a small model for a dual porosity system is created in order to compare single scale results with the multi-scale solver. Finally, capillary imbibition results for the whole domain are shown and different wettability scenario results are discussed. This application illustrates a novel multi-scale simulation approach that can address a long standing problem in digital rock

Whipple’s disease: misdiagnosed as sarcoidosis with further tricuspid valve endocarditis and pulmonary embolism – a case report

GH Whipple described a 36-year-old physician in 1907 with gradual loss of weight and strength, stools consisting chiefly of neutral fat and fatty acids, indefinite abdominal signs and a peculiar multiple arthritis. The patient died of this progressive illness. Whipple called it intestinal lipodystrophy since he observed accumulation of large masses of neutral fats and fatty acids in the lymph spaces. It was renamed Whipple’s disease in 1949. An infectious aetiology was suspected as early as Whipple’s initial report. However, successful treatment with antibiotics was not reported until 1952, which resulted in dramatic clinical responses. The cause is now known to be Tropheryma whipplei. Light and electron microscopy of infected tissue identified a gram-positive, non-acid-fast, periodic acid-Schiff (PAS) positive bacillus with a characteristic trilamellar plasma membrane resembling that of gram-negative bacteria. Whipple’s disease is extremely rare. It is a systemic infectious disorder affecting mostly middle-aged white men. The clinical presentation is often non-specific, which may make its diagnosis difficult. The four cardinal clinical manifestations are arthralgias, weight loss, diarrhoea and abdominal pain. The frequently vague articular symptoms can precede the diagnosis of Whipple’s disease by an average of 6–8 years. Lymph nodes and other tissues may present diagnostic problems, since the changes in routinely stained sections may mimic those of sarcoidosis. The detection of PAS-positive histiocytes in the small intestine remains the mainstay of the diagnosis, although Whipple’s disease without gastrointestinal involvement is described. We illustrate a case in which, retrospectively, the clinical presentation would have been typical for Whipple’s disease. However, the clinical presentation and the histological examinations of lymph nodes, liver biopsies and ascites initially were misinterpreted as sarcoidosis with consecutive immunosuppressive therapy and progressive worsening of the patient’s health presenting at least as sepsis with endocarditis

Polymer flooding – Does Microscopic Displacement Efficiency Matter?

Polymer flooding is an enhanced oil recovery (EOR) technique that aims to enhance the stability of the flood front in order to increase sweep efficiency and thereby increase hydrocarbon recovery. Polymer flooding studies often focus on large-scale sweep efficiency and neglect the impact of the pore-scale displacement efficiency of the multi-phase flow. This work explores the pore-scale behavior of water vs polymer flooding, and examines the impact of rock surface wettability on the microscopic displacement efficiency using digital rock physics. In this study, a micro-CT image of a sandstone rock sample was numerically simulated for both water and polymer flooding under oil-wet and water-wet conditions. All simulations were performed at a capillary number of 1E-5, corresponding to a capillary dominated flow regime. Results of the four two-phase flow imbibition simulations are analyzed with respect to displacement character, water phase break-through, viscous/capillary fingering, and trapped oil. In the water-wet scenario, differences between water flood and polymer flood are small, with the flood front giving a piston-like displacement and breakthrough occurring at about 0.4 pore volume (PV) for both types of injected fluid. On the other hand, for the oil-wet scenario, water flood and polymer flood show significant differences. In the water flood, fingering occurs and much of the oil is bypassed early on, whereas the polymer flood displaces more oil and thereby provides better microscopic sweep efficiency throughout the flood and especially around breakthrough. Overall the results for this rock sample indicate that water flood and polymer flood provide similar recovery for a water-wet condition, while the reduced mobility ratio of polymer flood gives significantly improved recovery for an oil-wet condition by avoiding the onset of microscopic (pore-scale) fingering that occurs in the water flood. This study suggests that depending on the rock-fluid conditions, the use of polymer can impact microscopic sweep efficiency, in addition to the well-known effect on macroscopic sweep behavior.La inyección de polímeros es una técnica de recobro mejorado de petróleo (EOR) que tiene como objetivo mejorar la estabilidad del frente de inyección para aumentar la eficiencia del desplazamiento de hidrocarburos y, por lo tanto, incrementar el factor de recobro. Lo estudios de inyección de polímeros a menudo se centran en la eficiencia del desplazamiento a gran escala e ignoran el impacto de los mecanismos de desplazamiento a escala microscópica, y rara vez evalúan la variabilidad de parámetros de flujo multifásico en el medio poroso. Este trabajo explora el comportamiento del agua contra la inyección de polímeros en el medio poroso, y examina el impacto de la humectabilidad de la superficie de la roca en la eficiencia de desplazamiento microscópico, utilizando tomografía computarizada de rayos X en muestras de roca. En este estudio, se simuló numéricamente una imagen de microtomografía computarizada de una muestra de roca arenisca, para un proceso de inyección de agua y polímeros en condiciones de mojabilidad al aceite y al agua. Todas las simulaciones se realizaron a un número capilar de 1E-5, correspondiente a un régimen de flujo dominado por fuerzas capilares y que es típico del flujo en yacimientos de hidrocarburos. Los resultados de las cuatro simulaciones de imbibición de flujo de dos fases se analizan con respecto al carácter desplazante, el avance de la fase acuosa, la digitación viscosa y capilar, y el aceite atrapado. En el escenario de mojabilidad al agua, las diferencias entre la inyección de agua y la inyección de polímeros son pequeñas, dado que el frente de inyección produce un  desplazamiento en forma de pistón y un avance que se produce a aproximadamente 0,4 volúmenes porosos para ambos tipos de fluido inyectado. Por otro lado, para el escenario de mojabilidad al petróleo, la inyección de agua y la inyección de polímeros muestran diferencias significativas. En la inyección de agua, se produce digitación y gran parte del petróleo se pasa por alto al principio; mientras que la inyección de polímeros desplaza más aceite y, por lo tanto, proporciona una mejor eficiencia de desplazamiento microscópico durante la inyección, especialmente alrededor de la ruptura. En general, los resultados para esta muestra de roca indican que la inyección de agua y la inyección de polímeros proporcionan un efecto de recobro similar para una condición de mojabilidad al agua, mientras que la relación de movilidad reducida de la inyección de polímeros proporciona un efecto de recobro significativamente mejorado para una condición de mojabilidad al aceite, al evitar la aparición de digitación microscópica (a escala de poro) que se produce en la inyección de agua. Este estudio sugiere que, dependiendo de las condiciones roca-fluido, el uso del polímero puede impactar la eficiencia de desplazamiento microscópico, además del efecto conocido sobre el comportamiento del desplazamiento macroscópico