Miscible Displacement Processes Research Articles

The characteristics of produced oils in the miscible CO2 displacement process

CO2 flooding is an effective technique for enhancing oil recovery by changing the hydrocarbon fluid’s characteristics. One of the fundamental mechanisms of the interaction between CO2 and hydrocarbon fluid by miscible CO2 injection is the extraction phenomenon of the hydrocarbon components by CO2. It results in altered produced and residual oil characteristics. This study aims to examine the characterizations of produced oil during the process of CO2 displacement. It is critical to anticipate any issues that can arise from miscible CO2 flooding, such as asphaltene deposition. A light-dead oil sample from an Indonesian oil field was used in this investigation. The miscible CO2 displacement process was conducted by a slim tube experiment at operating temperature of 90°C and 70°C, which represents the reservoir and surface temperature, respectively. The properties of produced oil were further characterized by analyzing the composition based on its polarity, including saturate, aromatic, resin, and asphaltene. The results show that increasing injection pressures decrease resin and asphaltene fractions in produced oil. Furthermore, the proportions of asphaltene and resin fractions in the crude sample exhibit a significant decrease when conducted at a lower temperature in comparison to when carried out at a higher temperature. This study helps to explain how the displacement process by CO2 affects the properties of the produced oil.

MD-CFD simulation on the miscible displacement process of hydrocarbon gas flooding under deep reservoir conditions

In this study, the microscopic miscible mechanism and the macroscopic flow characteristics of hydrocarbon gas and crude oil are investigated by combining molecular dynamic (MD) simulation and computational fluid dynamics (CFD) simulation. Under the deep reservoir conditions, the MD results manifest that compared with water flooding, hydrocarbon gas flooding could be more miscible with oil molecules, due to their stronger interactions. Based on the calculated density, viscosity and diffusion coefficient by the MD method, the CFD model is constructed to study the miscible displacement process of hydrocarbon gas flooding at 413 K and 50 MPa. The CFD results illustrate that the ability of oil displacement of different injection mediums follows the order of methane > ethane > propane > water. Because of the oil-gas miscibility, hydrocarbon gas could weaken the negative effect of the porosity and the wettability, leading to the decrease of the residual oil (RO) content. Moreover, the multi-component injection method is proposed for multi-scale porous media including nano-pore and micron-pore with small pore size. Notably, the variable velocity injection method is firstly designed for enhanced oil recovery. Compared with the constant low-velocity method, the RO content and the injection time of this method are effectively reduced by 12.4% and 66.7%, respectively.

Effect Of Composition Variation With Depth On Volatile Oil Reservoirs

It has been known that the distribution of hydrocarbon components in a fluid column is affected of gravity. Many authors have shown the effect of composition variation within a hydrocarbon column due to gravity. In thick reservoirs as the depth increases, the mole fraction of the lighter hydrocarbon decreases, whereas the heavy fraction increases. These variations may affect reservoir fluid properties considerably. In studying reservoir processes, especially with miscible displacements, it is essential to have of underlying mechanisms. In this paper, we investigate the effect of composition variation with depth on volatile oil under depletion and miscible gas processes. A ternary diagram was used to identify the process displacement mechanisms at different locations. A new efficient compositional simulationapproach was used to model the volatile oil reservoir bahaviour. It was shown that the decreasing light component with depth caused different miscible displacement processes as the oil composition move toward limiting tie line in the ternary diagram. Saturation and reservoir pressures variation with depth were not linear in a thick reservoir. This non linearity increased with the increased in volatility of the oil. In the case of depletion, the concentration of light component decreased below its original composition in the produced layers. In vaporising-gas drive the light component gradually vaporized from the bottom to the top of reservoir, whereas the intermediate component decreased below its original composition from the bottom to the top of the reservoir

A lattice Boltzmann study of miscible displacement containing dissolution reaction in porous medium

The miscible displacement with fluid-solid dissolution reaction in a porous medium is a typical process in many industrial applications, such as underground-water pollution decontamination, and oil recovery or geological sequestration of carbon dioxide. It is a significant problem in engineering and physics applications. As is well known, the dissolution reaction can change the structure of the porous medium, which will have a great influence on the miscible displacement process. However, the relationship between the displacement process and the dissolution reaction in a porous medium has not been fully studied. In this study, the miscible displacement with dissolution in a porous medium is simulated by a lattice Boltzmann method (LBM). The study focuses on the influence of the internal structure change on the displacement process, and the further quantitative analyzing of the changes of the porosity and displacement efficiency by changing the Damkohler number (<i>Da</i>) and the Pèlcet number (<i>Pe</i>). The results show that when<i> Da</i> is large enough, the dissolution reaction will generate a few wormholes in the porous medium, and the displacement fluid will leave the porous medium along the wormholes, resulting in the decrease of the displacement efficiency. As <i>Da</i> increases, the reaction goes faster, the rate of change in porosity increases, and the wormholes become wider, thereby indeed yielding a larger displacement efficiency. With the increase of <i>Pe</i>, the fingerings develop faster, the rate of change in porosity decreases, and the displacement efficiency decreases as well.

Numerical simulation and laboratory experiments of CO2 sequestration and being as cushion gas in underground natural gas storage reservoirs

Underground natural gas storage reservoir is generally used to stabilize the natural gas supply to meet the high and low peak of gas consumption. In addition, in the case of depleted gas reservoirs, the leftover native gas or cheap inert gas being as the cushion gas is needed to maintain reservoir pressure and ensure the stability of gas storage. In recent years, injecting CO2 for use as the cushion gas has drawn great attention for its potential to sequestrate the greenhouse gas underground and improve the operating efficiency of the working gas. In this study, a three-dimensional component model coupled with convection and diffusion is firstly constructed to describe the flow and miscible displacement processes affected by mixing in the porous media surrounding storage wells, and a fully implicit numerical model is established based on unstructured tri-prism meshes and a hybrid control volume finite element (CVFE) and finite-difference (FD) method. Secondly, mixing experiments of CO2 as cushion gas are carried out, the results are verified by numerical model, and good agreement between measured and computed data is achieved. Finally, through the numerical simulation of the hypothetical cases and orthogonal experiments, it is can be concluded that: CO2 is more suitable as cushion gas than natural gas itself and N2, injecting CO2 through corner wells at the bottom layer can effectively prevent the working gas escaping, and help to store more CO2 and slow down the mixing zone runs up, and the high production rate will help to control the mixing zone at a lower position and obtain greater gas recovery.

Simultaneous Occurrence of Miscible and Immiscible Displacement Processes During Solvent Displacement of Heavy Oil: A Parametric Analysis Using Visual Capillary-Tube Experiments

Summary Oil/solvent mixing is essential during solvent-injection applications to reduce the viscosity of oil, but mass transfer by diffusion becomes slower because the oil becomes heavier. Thus, an interface exists between the oil and solvent at certain times, being stronger in the beginning of the process. This results in an immiscible displacement controlled by the capillary forces while mixing is in progress. It is of practical and fundamental importance to determine the mechanisms responsible for the displacement of heavy oil and the behavior of solvents (acting as both immiscible and miscible displacement agents) because it could be advantageous to accelerate the dilution of heavy oil in many circumstances, including heterogeneous (fractured, layered, wormholed) systems. This is a complex process consisting of multiple pore phases (oil, solvent, their mixtures, and aqueous and vapor phases) at the same time, while different mechanisms such as capillary imbibition, miscible interaction (diffusion and convection), and gravity also act simultaneously. To investigate this complex phenomenon for different oil/solvent systems, a novel experimental method was used. The underlying mechanisms that dominate the solvent displacement process were comprehensively identified. The movement and evolution of interfaces among different fluid phases in glass capillary tubes were observed and recorded. Oil samples with different viscosities were used to examine the effects of oil viscosity on the mass transfer accelerated by imbibition transfer. The effects of temperature, wettability, and boundary conditions on the interaction of miscible fluid pairs were also studied. Pentane, heptane, and decane were used as the solvent phases. Advanced photographic techniques using ultraviolet (UV) light and dyed fluids were applied to better track the flow of different phases in the mixing zone. The experiments demonstrated a slowly smearing interface between the solvent and viscous oil. A unique natural convection was induced, with the combined effect of gravity, diffusion (mixing), and capillarity all contributing to the recovery of heavy oil. On the basis of the saturation method, boundary condition, and the Bond number, four different motion modes of mixing zone and interfaces of miscible fluids in the capillary tube were revealed and categorized to identify the degree of interface development (immiscible flooding). Also, the mixing zone, mass flux, and flow behavior were quantified using dimensionless parameters. The results indicate that priority may be given to a solvent with a high interfacial tension (IFT) for the solvent-based oil-recovery technique because of a strong imbibition and further enhancement of the dilution and displacement processes under conditions of a similar viscosity ratio. The data provided will be useful for the accuracy of modeling studies, especially for complex geologies where oil/solvent interaction is critically difficult to develop in order for mixing to occur.

Stable and unstable miscible displacements in layered porous media

The effect of permeability heterogeneities and viscosity variations on miscible displacement processes in porous media is examined using high-resolution numerical simulations and reduced theoretical modelling. The planar injection of one fluid into a fluid-saturated, two-dimensional porous medium with a permeability that varies perpendicular to the flow direction is studied. Three cases are considered, in which the injected fluid is equally viscous, more viscous or less viscous than the ambient fluid. In general it is found that the flow in each case evolves through three regimes. At early times, the flow exhibits the concentration evolves diffusively, independent of both the permeability structure and the viscosity ratio. At intermediate times, the flow exhibits different dynamics including channelling and fingering, depending on whether the injected fluid is more or less viscous than the ambient fluid, and depending on the relative magnitude of the viscosity and permeability variations. Finally, at late times, the flow becomes independent of the viscosity ratio and dominated by shear-enhanced (Taylor) dispersion. For each of the regimes identified above, we develop reduced-order models for the evolution of the transversely averaged concentration and compare them to the full numerical simulations.

Blocking Behavior of Organic Solid Phase in the Carbon Dioxide Multiphase and Multicomponent Displacement Process

Better dealing with carbon issues can support the management of current greenhouse gas emissions while achieving energy economic diversification and energy security. Carbon dioxide displacement has become the most acknowledged and practical method in enhanced oil recovery system. This is because of its oil sweep efficiency and ability to reduce the level of greenhouse gas emission. Nevertheless, it would lead to the organic solid phase deposition, which causes the changes of the wettability and the damages of wellbores and reservoirs. In this study, we used slim tube test and component test to research the dynamic characteristics of displacement process. In addition, the mechanism of porous media blockage was also investigated. Results show that when the displacement pressure closed to the minimum miscibility pressure, reservoir blockage in pore throat could happen. Component test characterizes that during near miscible displacement process, the components of oil sample varied obviously, the variation range of peak component carbon marks fluctuated strongly. Crude oil component differentiation could happen after carbon dioxide fully contacted with oil. Besides, the rapid extraction mechanism of aromatic hydrocarbons played a significant role in this process under such condition. The reason is that the solubility of saturated hydrocarbons to asphaltene and non-hydrocarbons is obviously weaker than aromatic hydrocarbons. Controlling the pressure is considered as an important link to prevent the occurrence of blocking in the carbon dioxide multiphase and multicomponent displacement process.

An Australian first initiative to re-develop the first commercial onshore oilfield into a CO2 miscible-EOR project

The Moonie onshore oil field discovered in 1961, was the first commercial oil discovery in Australia. The field was purchased by Bridgeport Energy Limited (BEL) from Santos in late 2015. An Australian first initiative by BEL is to enhance oil production from the field using tertiary recovery CO2 miscible flood to maximise field oil recovery. The process involves an evaluation of well injection strategies for a miscible displacement process using reservoir simulation modelling. In addition, the project jointly addresses community concerns regarding the rise in greenhouse gas emissions by sourcing 60000–120000 tonnes/annum of CO2 from a nearby power station and/or an ethanol plant. Justified by laboratory experiments and reservoir compositional simulations, BEL’s project timeline to implement a CO2-enhanced oil recovery (EOR) pilot could start from 2020 followed by a 2–3-year full field oil production acceleration project if additional CO2 can be sourced. Based on incremental recovery and operational consideration, an injection well in the southern end of the field surrounded by six existing producers has been selected as a pilot flood. Positive indicative economics are achieved by the efficient displacement with CO2 of 8000 scf/bbl of incremental oil. Full field dynamic modelling predicts a further 8% oil recovery factor by injecting 60 Bcf of CO2 over five years, which could store in excess of three million tonnes of CO2. For the pilot, more than 90% of the injected CO2 will remain in the Precipice sandstone reservoir. However, the efficiency and viability of a CO2-EOR project is subject to successful implementation of the miscibility modelling, logistics and injection strategy and uncertainty quantification. To propel the project into the execution phase a fast-multiphase reservoir simulator has been implemented to complete a probabilistic range of results in optimal time.

An improved correlation to determine minimum miscibility pressure of CO2–oil system

An accurate and reliable estimation of minimum miscibility pressure (MMP) of CO2–oil system is a critical task for the design and implementation of CO2 miscible displacement process. In this study, an improved CO2–oil MMP correlation was developed to predict the MMP values for both pure and impure CO2 injection cases based on ten influential factors, i.e. reservoir temperature (TR), molecular weight of C7+ oil components (MWC7+), mole fraction of volatile oil components (xvol), mole fraction of C2C4 oil components (xC2-C4), mole fraction of C5C6 oil components (xC5-C6), and the gas stream mole fractions of CO2 (yCO2), H2S (yH2S), C1 (yC1), hydrocarbons (yHC) and N2 (yN2). The accuracy of the improved correlation was evaluated against experimental data reported in literature concurrently with those estimated by several renowned correlations. It was found that the improved correlation provided higher prediction accuracy and consistency with literature experimental data than other literature correlations. In addition, the predictive capability of the improved correlation was further validated by predicting an experimentally measured CO2–oil MMP data, and it showed an accurate result with the absolute deviation of 4.15%. Besides, the differential analysis of the improved correlation was analyzed to estimate the impact of parameters uncertainty in the original MMP data on the calculated results. Also, sensitivity analysis was performed to analyze the influence of each parameter on MMP qualitatively and quantitatively. The results revealed that the increase of xC2-C4, xC5-C6 and yH2S lead to the decrease of MMP, while the increase of TR, MWC7+, xvol, yCO2, yC1, yHC and yN2 tend to increase the MMP. Overall, the relevance of each parameter with MMP follows the order of TR > xC5-C6 > MWC7+ >xvol > yH2S > yHC > yCO2 >yC1 >yN2 >xC2-C4.

Overview of Carbon Dioxide Injection and Water-Alternating-Gas Sensitivity

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 179569, “Overview of CO2 Injection and WAG Sensitivity in SACROC,” by Reza Barati Ghahfarokhi, SPE, The University of Kansas, and Steve Pennell, Michael Matson, SPE, and Mark Linroth, SPE, Kinder Morgan, prepared for the 2016 SPE Improved Oil Recovery Conference, Tulsa, 11–13 April. The paper has not been peer reviewed. This paper presents an overview of the SACROC Unit’s activity focusing on different carbon dioxide (CO2) injection and water-alternating-gas (WAG) projects that have made the SACROC unit one of the most successful CO2 injection projects in the world. The main objectives of this were was to review CO2 injection and injection-rate losses with respect to the CO2/WAG miscible displacement process in the SACROC Unit and recommend an injection strategy for WAG-sensitive patterns. Introduction The Kelly-Snyder field is the largest of a chain of fields along the Pennsylvanian Horseshoe atoll in the Midland Basin. Within this field, the Scurry Area Canyon Reef Operators Committee (SACROC) Unit covers approximately 56,000 acres with 2,800 million STB of original oil in place (OOIP). Limestone is the dominant mineral within the Canyon Reef formation, and less than 3% of the formation exists as thin sections of shale (1–10 ft in thickness) that are important stratigraphic markers. The formation is divided into four major zones: the Cisco, the Green Zone (GZ), the Upper Middle Canyon, and the Lower Middle Canyon (LMC). Of these, the GZ shows the highest matrix permeability, significant nonmatrix-flow features, and high-conductivity channels. Moreover, the transition zone (TZ) below the oil/water contact has recently been developed in parts of the SACROC Unit. Review Primary Production. Completed in November 1948, the Standard No. 1 Jessie Brown 2 was drilled to 6,700 ft and produced 530 B/D from the Canyon Reef Formation. Located 9 miles northwest of Snyder, Texas, this well was the discovery well of the North Snyder field. The Texas Railroad Commission eventually merged this field with the neighboring Kelly field upon recognizing that both fields produce from the same reservoir. The reservoir thickness varies from 10 ft on the flanks to 900 ft on the crest of the reef. A map of the unit’s 3D structure and thickness is shown in Fig. 1. By late 1950, 1,600 production wells had been drilled on the Kelly- Snyder field on irregular 40-acre spacing.

Operator-based linearization approach for modeling of multiphase multi-component flow in porous media

A new approach for the linearization of governing equations that describe flow and transport in porous media is proposed in this work. It is based on an approximate representation of the exact physics of the problem, which is similar to an approximate representation of space and time discretization performed in conventional simulation. The governing equations are introduced as a combination of operators, dependent on spatially altered properties and operators, fully controlled by nonlinear properties of fluid and rock. Next, a parametrization in the physics space of the problem is introduced. The property-based operators are approximated using direct interpolation in the space of nonlinear unknowns. The discrete version of the governing equations is constructed as a combination of operators that approximate both nonlinear physics and discretization in time and space. This approach is applied to the reservoir simulation of miscible and immiscible displacement processes. The performance of the method demonstrates a convergence of simulation results by resolution in physical space with the improved performance.

Numerical Modeling of Miscible Viscous Fingering Instabilities by High-Order Methods

In this paper, a high-order method is used to simulate the viscous fingering fluid instability during the miscible displacement process in porous media, on structured and unstructured grids. The numerical model incorporates decoupling in time, discontinuous Galerkin method of high order, flux reconstruction and parallel implicit solvers to produce an accurate and efficient predictive tool for finger growth. This paper shows that the proposed numerical approach is a competitive method to simulate several viscous fingering problems, such as rectilinear flow, density-driven flow and radial flow. The numerical model does not suffer from grid orientation, and accurately measures finger growth rate. Convergence of the fingering pattern is obtained under mesh refinement and increased polynomial degree.

The impact of residual water on CH4-CO2 dispersion in consolidated rock cores

Assessment of the viability of enhanced gas recovery (EGR), in which CO2 is injected into natural gas reservoirs, requires accurate and appropriate reservoir simulations. These necessitate provision of parameters describing dispersion between the fluids. Here we systematically measure fluid dispersion in various rock cores (sandstones and carbonates), both dry and at irreducible water saturation, at reservoir conditions. In this manner we evaluate the impact of the irreducible water on the miscible displacement processes. As such this represents the first measurement of dispersion as a function of water saturation for supercritical gases in consolidated media. Complementary measurements of water spatial distribution along the rock axis, as well as the pore size distribution occupied by the water were performed using magnetic resonance techniques. Irreducible water was found to increase dispersivity by a factor of up to 7.3. The dispersion coefficient (K) was measured as a function of velocity and the data for both dry and water-containing samples were successfully combined on a K–Péclet number (Pe) plot, enabling ready future inclusion into EGR reservoir models. The power-law dependence of K upon Pe produced an exponent of 1.2 for dry and water-saturated sandstones and 1.4 for dry and water-saturated carbonates, consistent with literature results (Bijeljic et al., 2011; Honari et al., 2015).

Pore-scale simulation of miscible displacement in porous media using the lattice Boltzmann method

A numerical model based on the lattice Boltzmann method is presented to investigate the viscous fingering phenomena of miscible displacement processes in porous media, which involves the fluid flow, heat transfer and mass transport. Especially, temperature- and concentration-dependent pore-fluid viscosity is considered. A complete list is derived and given for the conversion of relevant physical variables to lattice units to facilitate the understanding and implementation of the coupled problems involving fluid flow, heat transfer and mass transport using the LBM. To demonstrate the proposed model capacity, two different complex geometry microstructures using high resolution micro-computed tomography (micro-CT) images of core sample have been obtained and incorporated as computation geometries for modeling miscible displacement processes in porous media. The viscous fingering phenomena of miscible displacement processes are simulated in two different cases, namely in a channel and a porous medium respectively. Some influencing factors on the miscible displacement process, such as the pore-scale microstructure, Le number and Re number, are studied in great detail. The related simulation results have demonstrated that: (1) the existence of the pore-scale microstructure can have a significant effect on the front morphologies and front propagation speed in the miscible displacement process; (2) as the Le number increases, the fluid front and thermal front evolve differently, with the thermal front being less unstable due to more diffusion; (3) a larger Re number can lead to an increase in the propagation speed of the front.

Pore-Scale Study of Miscible Displacements in Porous Media Using Lattice Boltzmann Method

In the past few years, the miscible displacements in porous media were usually simulated by some semiempirical models based on the volume averaging at the representative elementary volume scale. To better understand the microscopic mechanism of the viscous fingering phenomenon in porous media for miscible fluids, in this paper the miscible displacements processes in porous media are studied using the lattice Boltzmann method (LBM) at the pore scale. First, the code of LBM is tested by simulating the displacement process of two miscible fluids with the same viscosity between two parallel plates which is the well-known Taylor–Aris dispersion problem, and comparing the results with the theoretical predictions. Then, the effects of the Peclet number Pe, the viscosity ratio M and the structure of the porous media on the displacement phenomenon are investigated, and the location and velocity of the finger tip, the displacement efficiency are also studied. In this paper, the displacement efficiency is calculated by $$1-m$$ , here the quantity m is defined as $$m=V_M/V_T$$ , where $$V_M$$ is the volume of more viscous fluids (the displaced fluid) left behind the finger tip, $$V_T$$ is the total pore volume behind the finger tip. It can be found that the “interface” of two fluids will become clearer with the increasing of the Peclet number. As Pe and M are large enough, the viscous fingering phenomenon will occur, and in the front of the finger, “mushroom-like” pattern can be observed. Besides, with the increasing of Pe or M the quantity m will be increased too, i.e., the displacement efficiency will be decreased. While Pe (or M) is greater than a certain value, the growth rate of the quantity m will slow down. The same trend was observed for the miscible displacement in capillary tubes or Hele–Shaw cells. Besides, changing the structure of the porous media makes the finger pattern different. The present simulation results provide a good understanding of the microscopic mechanism of the miscible displacement process in porous media, and also show that the LBM can be a useful tool for investigation miscible fluids behavior in porous media.

Experimental investigation of dispersion phenomenon in a fractured porous medium

Dispersion of fluids flowing through porous media is an important phenomenon in miscible displacement. Dispersion causes instability of miscible displacement flooding; therefore, to obtain and maintain the miscibility zone, the porous medium dispersivity should be considered in displacing fluid volume calculation. Many works have been carried out to investigate the dispersion phenomenon in porous media in terms of theory, laboratory experiments and modeling. What is still necessary is to study the effects of presence of fracture in a porous medium on dispersion coefficient or dispersivity. In this work dispersion phenomenon in a fractured porous medium has been investigated through a series of miscible displacement tests on homogeneous sandstone core samples. Tests were repeated on the same core samples with induced fracture in the flow direction. The effects of fracture on miscible displacement flooding have been studied by comparison of the results of dispersion tests in the absence and presence of fracture. In the presence of fracture, breakthrough time reduced and the tail of effluent S-shaped curve smeared. Moreover, the slope of S-shaped curve at 1 pore volume of injected fluid was lower than homogeneous case which means dispersion coefficient increased. The results presented in this work provide an insight to the understanding of dispersion phenomenon for modeling of miscible displacement process through naturally fractured reservoirs.

Dynamic stability characteristics of fluid flow in CO2 miscible displacements in porous media

The dynamic stability characteristics of fluid flow in miscible displacement processes were investigated by using a magnetic resonance imaging apparatus and simulated by a lattice-Boltzmann method at elevated pressures.

Magnetic resonance imaging analysis on the in-situ mixing zone of CO2 miscible displacement flows in porous media

The in-situ mixing zone represents dynamic characteristics of CO2 miscible displacement flows, which is important for carbon dioxide enhanced oil recovery (CO2-EOR) projects. However, the migration characteristics of the in-situ mixing zone under reservoir conditions has been neither well studied nor fully understood. The in-situ mixing zone with the flowing mixture of supercritical CO2 and n-decane (nC10) was investigated by using a magnetic resonance imaging apparatus at a reservoir condition of 8.5 MPa and 37.8 °C in porous media. The experimental results showed that the CO2-frontal velocity was larger than the mixing-frontal velocity. The mixing zone length was linearly declined in the miscible displacement process. And the declining rate of the mixing zone length was increased with injection rate. It indicates that the mixing zone length is not constant in a vertically stable CO2 misible displacement and a volume contraction due to phase behavior effects may occur. Then, an error function based on the convection-dispersion equation was fitted with CO2 miscible displacement experiments. The error function was well fitted both at a series of fixed core positions and a series of fixed displacement times. Furthermore, the longitudinal dispersion coefficients (Klx and Klt) and the longitudinal Peclet numbers (Ped and PeL) were quantified from the fitting results. The evolutions of the longitudinal dispersion coefficient were reduced along the displacement time. And the declining rate was increased with injection rate. And with proceeding, the longitudinal dispersion coefficient was tending towards stability and constant. But the evolutions of the longitudinal Peclet numbers were increased along the displacement time. And the increasing rate was increased with injection rate.

Measuring miscible fluid displacement in porous media with magnetic resonance imaging

AbstractThe development of new quantitative magnetic resonance imaging (MRI) technologies open new opportunities for measurements of mass transport in porous media. The current work examines a simple miscible displacement process of H2O and D2O in porous media samples. Laboratory measurements of dispersion in porous media traditionally monitor the effluent intensity of an injected tracer. We employ MRI to obtain quantitative water saturation profiles, and to measure dispersion in rock core plugs. The saturation profiles are modeled with PHREEQC, a fluid transport modeling program. We demonstrate how independent magnetic resonance measurements can be employed to estimate three important input parameters for PHREEQC, mobile porosity, immobile porosity, and dispersivity. Bulk Carr Purcell Meiboom Gill (CPMG) T2 distribution measurements were undertaken to estimate mobile and immobile porosity. Bulk alternating‐pulsed‐gradient‐stimulated‐echo (APGSTE) measurements were undertaken to measure dispersivity. The imaging method employed, T2 mapping Spin Echo Single Point Imaging (SE‐SPI), also provides information about the pore size distributions in the rock cores, and how the fluid occupancy of the pores changes during the displacement process.