Fluid Displacement Research Articles

High‐pressure high‐temperature fluid displacement by foam injection within a multiblock matrix‐fracture system

AbstractFoam injection has been suggested and demonstrated as a potential gas‐based solution for enhancing oil recovery from underground reservoirs. While the pore‐scale behavior of foam has been investigated for many years, most of those studies were done at room temperature and pressure. A high‐pressure high‐temperature (HPHT) cell was constructed to relax this contributing simplification and evaluate foam behavior under reservoir conditions. The performance of foam injection into a fractured reservoir was investigated experimentally at vertical and horizontal pathways utilizing a 2D microfluidic device. The results showed foam had a higher lamellae density in the fracture network and could direct fluids to the matrix. This was mainly attributed to the created pressure drop in the fractured media dictated by foam self‐tuning ability, which is a higher viscosity in areas with higher conductivity. Generating a viscous crossflow in horizontal tests leads to enhanced recovery relative to gas injection. But the presence of gravity in the vertical tests causes the drainage of the foam film and the segregation of the gas and surfactant solution due to gravity, which ultimately reduces the stability of the foam. Comparing the performance of gas and foam in the vertical injection scenario reveals that foam injection results in a considerably more enhanced oil recovery. The oleic phase had a detrimental impact on foam strength and reduced fluids diversion from fracture to matrix. The sizes of gas bubbles were also larger in the presence of the oleic phase.

The effect of structural damping on flow-induced vibration of a thin elliptical cylinder

This study experimentally investigates the influence of structural damping on the transverse flow-induced vibration (FIV) of an elastically mounted thin elliptical cylinder. The cylinder tested has an elliptical ratio of $\varepsilon = b/a = 5$ , where $a$ and $b$ are the streamwise and cross-flow dimensions, respectively, and a mass ratio (i.e. the total oscillating mass/the displaced fluid mass) of $17.4$ . The FIV response was characterised over a reduced velocity range of $2.30 \leq U^* = U/(\,{{f_{{nw}}}} b) \leq 10.00$ (corresponding to a Reynolds number range of $300 \leq \textit {Re} =(U b)/\nu \leq 1300$ ) and a structural damping ratio range of $3.62\times 10^{-3}\leq \zeta \leq 1.87\times 10^{-1}$ . Here, $U$ is the free stream velocity, ${{f_{{nw}}}}$ is the natural frequency of the system in quiescent fluid (water) and $\nu$ is the kinematic viscosity of the fluid. The FIV response was characterised by four wake–body synchronisation regimes (defined as the matching of the dominant fluid forcing and oscillation frequencies, and labelled regime I, regime II, regime III and the hyper branch) and a desynchronisation region, with the hyper branch representing a high amplitude regime not observed for a circular cylinder. Interestingly, the major vortex shedding mode was predominately two single opposite-signed vortices shed per body vibration cycle. Moreover, hydrogen-bubble-based flow visualisations revealed a secondary vortex street forming in the elongated shear layers associated with largest-scale vibration amplitudes ( $A^* = A/b$ up to $7.7$ ) in the hyper branch and regime II. As the structural damping ratio was increased beyond $1.92 \times 10^{-2}$ , the hyper branch was found to be suppressed. The results have potential ramifications for the efficient extraction of energy from free-flowing water sources, which has become increasingly topical over the last decade.

Comprehensive numerical study of sequential injection of SiO2-nanofluids for enhanced oil recovery

Improving the efficiency of oil production is an important element in reducing the carbon footprint of the oil industry. One of the methods for increasing the efficiency of oil recovery is the use of oil flooding using solutions of various chemical reagents. The paper presents a computational investigation of the oil recovery from a porous micromodel using a nanofluid during sequential injection of water-SiO2 nanofluid-water. The effect of the nanosuspension concentration, duration of injection of the nanosuspension, the starting time point of nanosuspension injection, as well as the influence of oil viscosity on the oil recovery during sequential injection of main displacement fluid and nanosuspensions was investigated. Such a systematic study was performed for the first time. It was found that injection of three pore volumes of nanosuspension increases oil recovery factor by 1.5 times compared to injection of three pore volumes of water. It has been established that, from a practical point of view, it is most effective to increase oil recovery by starting the injection of nanosuspension after injecting two pore volumes of water. This case leads to an increase in recovery factor by 1.35 times compared to the injection of three pore volumes of water. As a result, it was shown that employing sequential injection allows obtaining an oil recovery factor comparable to that corresponding to oil recovery by nanosuspension. Thus, sequential injection makes it possible to significantly reduce the amount of nanoparticles during injection of nanosuspensions, while maintaining a high beneficial effect on the ORF. This is an important positive fact for the further development of this method of increasing oil recovery.

H2-gas diffusion in porous media as observed by NMR

Not only is hydrogen (H2) the simplest and most abundant gas in our universe, it also plays a pivotal role in the decarbonization of our energy. As such hydrogen will be one of the most important critical enablers for industry in the global energy transition. Hydrogen’s low density hinders the wide-scale deployment and therefore, it is important to come to large scale low-cost H2 storage capacity as a source of hydrogen gas. In order, to store the energy in the TW h/GW h-range subsurface storage of hydrogen in depleted hydrocarbon reservoir and/or deep saline aquifers is needed. Concerning the hydrogen storage in depleted gas/oil reservoirs there are still many scientific questions open, which have to be addressed in order to come to reliable, efficient and cost-effective storage [1, 2]. For example, the injected hydrogen will displace the pore residual oil/gas and spread out in a reservoir; a trap structure is needed to prevent the hydrogen from escaping and allowing reproduction of the hydrogen, i.e., leakage is a major concern. Accurate predictions are needed of multi-phase fluid displacement in porous media, e.g., the interaction/displacement of cushion gas and the interactions with the solid matrix.
 In this study we have used NMR to image the diffusion and interaction in porous media. NMR is one the few methods by which H2-gas can be directly imaged in porous media. In order to do so, we have constructed a special NMR setup to measure the diffusion in porous media up to 60 bar. As the relaxation times measured for hydrogen are too short for 3D imaging this setup is limited to 1D measurement [3]. As, to be able to measure also on real porous media containing magnetic impurities, it was chosen to keep the main field at 0.7 T. The present setup is made up of an electromagnet generating a main magnetic field of 0.7 T with a gap of 70 mm and a picture is given in Fig 1. The NMR setup itself is equipped with Anderson gradient coils which can generate up to 0.3 T/m. An RF insert was made which is equipped with a special Faraday-shield, to be able to perform quantitative measurements and as such this setup is directed towards quantitative H2 profile measurements [4].
 For the NMR measurements a special PEEK reactor was purchased, which can be operated on up to 60 bars. The PEEK reactor has an outer diameter of 50 mm and inner diameter of 30 mm with a length of 500 mm. The reactor can be moved through the RF-coil with the help of a stepper motor, hence giving the possibility to measure the H2 content profile over the length of the reactor.
 In the initial tests we looked at the quantitative measurement of H2 as a function of the gas pressure. These initial measurements show that the H2 gas has a T1 in the order of 0.5 ms. Hence, as the signal of the H2 gas is quite low in comparison to the background noise, it was decided to measure the H2 gas at a high repetition rate, i.e., TR=2 ms. The results as function of the gas pressure up in the initial test upto 15 bars are given in Fig 2. As can be seen a clear linear behavior is found and only a minor contribution of the background is observed. In the next experiment the reactor was filled with 0.06 mm glass beads to mimic an ideal porous material and the results are also given in Fig 2. Again, a clear linear behavior can be observed, indicating measurements can also be performed in porous media.
 After this preliminary study in which we have tested the setup, we now intend to conduct measurements on porous glass beads up to 2 mm under various prewetting conditions, e.g., water, NaCl solution, oil and at various pressures. Here we want to measure the exchange of H2 gas by other gases such as N2 up to 60 bar and see the influence of the various prewetting conditions.

Microfluidics for Carbonate Rock Improved Oil Recovery: Some Lessons from Fabrication, Operation, and Image Analysis

Summary After the successful implementation of lab-on-a-chip technology in chemical and biomedical applications, the field of petroleum engineering is currently developing microfluidics as a platform to complement traditional coreflooding experiments. Potentially, microfluidics can offer a fast, efficient, low-footprint, and low-cost method to screen many variables such as injection brine composition, reservoir temperature, and aging history for their effect on crude oil (CRO) release, calcite dissolution, and CO2 storage at the pore scale. Generally, visualization of the fluid displacements is possible, offering valuable mechanistic information. Besides the well-known glass- and silicon-based chips, microfluidic devices mimicking carbonate rock reservoirs are currently being developed as well. In this paper, we discuss different fabrication approaches for carbonate micromodels and their associated applications. One approach in which a glass micromodel is partially functionalized with calcite nanoparticles is discussed in more detail. Both the published works from several research groups and new experimental data from the authors are used to highlight the current capabilities, limitations, and possible extensions of microfluidics for studying carbonate rock systems. The presented insights and reflections should be very helpful in guiding the future designs of microfluidics and subsequent research studies.

Applying a deep-learning surrogate model to simulate and compare achievable oil recovery by different waterflood scenarios

Reservoir pressure depletion is a critical aspect leading to declined oil production. Water flooding becomes mandatory to increase the recovery efficiency from certain reservoirs. Establishing well placements, injection rates, and injection schedules enables improved fluid displacement in such reservoirs. Standard reservoir simulators are widely used to provide near-optimal scenarios for maximizing oil recovery. Such reservoir simulations involved numerous iterations and required significant computational effort. Also, the conventional machine learning methods provide a relatively high uncertainty to predict the considered problem. In this context, a deep-learning surrogate model comprising long short-term memory networks and densely connected networks is proposed to predict cumulative oil production using various waterflood injection well patterns, injection rates, and injection period information. The relevance test clarifies that the oil recovery mainly controls by water injection duration and injection pattern. A total of 1485 data records are considered to validate the model’s performance, demonstrating less than 3.5% absolute average relative error and a prediction versus actual value regression coefficient of 0.99989. In addition, the prediction accuracy of the proposed deep-learning model is also shown to outperform two well-known traditional machine-learning models (i.e. artificial neural networks and support vector regressions).

Development of Microbial Consortium and Its Influencing Factors for Enhanced Oil Recovery after Polymer Flooding: A Review

After polymer flooding, substantial oil and residual polymers remain in reservoirs, leading to plugging and reduced recovery. MEOR (Microbial Enhanced Oil Recovery) aims to release trapped oil by utilizing microorganisms and their byproducts. The microorganisms can use residual HPAM (hydrolyzed polyacrylamide) as an energy source for polymer degradation, addressing reservoir plugging issues and improving oil recovery. However, microorganisms are sensitive to environmental conditions. This paper presents a detailed update of MEOR, including microbial products, mechanisms, and merits and demerits. The effect of the displacement fluid and conditions on microorganisms is thoroughly demonstrated to elucidate their influencing mechanism. Among these factors, HPAM and crosslinkers, which have significant biological toxicity, affect microorganisms and the efficiency of MEOR. Limited research exists on the effect of chemicals on microorganisms’ properties, metabolism, and oil displacement mechanisms. The development of microbial consortium, their metabolic interaction, and oil displacement microprocesses are also discussed. In addition, prior studies lack insights into microorganisms’ interaction and mechanisms using chemicals. Finally, field trials exist to examine the microbial consortium’s efficiency and introduce new technologies. This review mainly explores the influencing factors on microorganisms, and confirms the credibility of MEOR after polymer flooding, providing a scientific basis for improving the theory of MEOR.

Separating fluid and solid contact constraints for hydro-mechanically coupled finite elements discretising fluid displacement

In the simulation of multi-phase porous media in contact with a structure, the contact constraints to be enforced depend on the spatially discretised variables and additional physical considerations. Typically, fluids in porous media behave differently at the contact interface than the solid phase through which they flow. Aspects of numerical modelling and considerations in defining constraints to model such phenomena are discussed in this work. To this end, a hydro-mechanically coupled finite element formulation discretising fluid displacement is supplemented by a mortar contact discretisation scheme enforcing the contact constraints separately for the different phases. Using the proposed multi-phase mortar contact formulation, it is demonstrated for which type of problems such a formulation offers advantages over formulations not distinguishing contact constraints of multiple phases.

Acoustic scattering from spherical shells and its active control

The scattering of sound by a thin spherical shell is considered using an analytic formulation involving spherical harmonics. The integral of the far field scattered intensity, termed the scattered power, can then be expressed in a simple form. At low frequencies the scattered power can be minimised by an appropriate choice of material properties and shell thickness, which is illustrated for both a steel shell and for one in which the mass and stiffness of the shell are equal to those of the displaced fluid. Simulations of feedforward active control are then used to investigate the best possible performance in attenuating the scattered power, although this approach requires knowledge of the incident and scattered sound fields. Feedback control of the shell vibration using structural actuators and sensors is a more practical control strategy since it does not involve the need to separate the incident and scattered contributions. Direct velocity feedback control is considered using collocated and distributed actuators and sensors that spread the applied force and sensed velocity over spherical caps on the surface of the shell. This approach shows effective suppression of the structural shell modes that give rise to significant scattering at their resonant frequencies.

Pore‐Scale Fluid Dynamics Resolved in Pressure Fluctuations at the Darcy Scale

AbstractComplex pore‐scale dynamics have been observed during multiphase flow through porous rocks. These dynamics are not incorporated in large scale models for the migration and trapping of subsurface fluids such as CO2 or hydrogen. We show that fluctuations in pressure measured at the core‐scale (centimeters) can reflect fluid displacements at the pore‐scale (millimeters). The spectral characteristics of pressure data are shown to depend on the flow dynamics, the size of the rock sample, and the heterogeneity of the pore space. These results show that pressure data, transformed into the time‐frequency domain using wavelets, provides information about flow dynamics, across scales, that are otherwise challenging to acquire.

Sour-Rated 10,000-psi System High-Temperature Gas Development Wells: Sustaining the Malaysian National Gas Supply Through a Journey of Optimization in North Malay Basin

Summary High temperature (HT), high carbon dioxide (CO2) coupled with hydrogen sulfide (H2S) contents, and rapid pore pressure fracture gradient (PPFG) pressure ramp increase in gas development wells can lead to significant capital expenditures for operators. Such wells typically need high corrosion resistance alloy material with at least a 10,000-psi (10-ksi)-rated system to complete. The deep reservoirs of the North Malay Basin, offshore peninsular Malaysia, also fall into the described category. In this paper, we aim to share the optimization journey, applications, and learnings of the company’s HT sour-rated 10-ksi gas development wells through several phases, besides fulfilling the gas delivery need for the country. In addition, we identify engineering and operational optimizations to reduce the well’s time and cost while upholding the safety of the crew as a top priority. The sour-rated HT gas development campaign for the company began in the year 2017, followed by a second campaign in the year 2018. Our focus centers on the third campaign, which concluded in the year 2022. A total of four, three, and four wells were drilled and completed in the first, second, and third campaigns respectively. The company’s wells engineering team applied Lean methodologies that covered the entire Plan-Do-Check-Adjust cycle to achieve optimization. Using well data, learning from experiences, working together, maintaining consistency, and pursuing ongoing enhancements are the main factors that ensure positive optimization outcomes. Fit-for-purpose drilling and completions equipment design and application, rig offline capabilities planning, wellhead dummy hanger plug design for offline cementing, intervention-less production packer setting device, offline annulus nitrogen cushion fluids displacement, and other applications will be explained in the paper. In this paper, we describe the operational challenges faced and outline the applied optimizations that led to significant improvements in the well performance compared with targets and previous campaigns. The optimization efforts by the wells team extended from the engineering phase to the execution stage, including the use of in-house digital capabilities to monitor well performance, in alignment with industry practice. The recent campaign post-optimization concluded with no safety incidents, average per well more than 48 days ahead with 39% lower cost than previous campaigns, average of 5.6% overall well nonproductive time (NPT), and achieved first gas to meet the country’s power generation demand. Furthermore, the motivating optimization results also coupled with 25% more production results compared with the prognosed. The positive results of this optimization journey were significantly influenced by transparent, collaborative, and proactive communication across different departments.

Study of Fluid Displacement Processes and Sequestration of CO2 in Coal Reservoirs Using Nuclear Magnetic Resonance Spectroscopy

Study of Fluid Displacement Processes and Sequestration of CO2 in Coal Reservoirs Using Nuclear Magnetic Resonance Spectroscopy

Development and Characterization of CO2-Responsive Intelligent Polymer Sealant.

In this study, we present an innovative intelligent polymer sealant designed to mitigate CO2 leakage during underground geological storage (CCUS). This sealant is formulated by cross-linking CO2-responsive polymers, specifically acrylamide (AM) and N-[3-(dimethylamino) propyl] methacrylamide (DMAPMA), with polyethylenimine (PEI) serving as the cross-linking agent. The polymer sealant's characteristics were systematically investigated, varying the CO2-responsive polymer content (1.5 wt %) and PEI content (0.1-0.6 wt %). A comprehensive analysis encompassing the rheological properties, thermal behavior, conductivity, and microstructures was conducted. Experimental results indicate that the polymer sealant exhibits excellent injectability, rapid response kinetics, thermal stability, and robust mechanical strength. Upon encountering CO2, the polymer system undergoes a transition from sol to gel state, forming a surface-smooth, uniformly porous three-dimensional (3D) network skeleton structure. Remarkably, the gel's modulus remains relatively unaffected by the shear frequency. Core fluid displacement experiments demonstrated a substantial sealing efficiency of 73.6% for CO2 and an impressive subsequent injection water sealing rate of 96.2%, underscoring its superior sealing and migration performance. In conclusion, the proposed CO2-responsive gel sealant exhibits an exceptional potential for successful utilization in CCUS operations. This advancement introduces a novel avenue to enhance the effectiveness of CO2-responsive gel sealants, thereby contributing to the advancement of CO2 leakage mitigation strategies in geological storage scenarios.

Interplay of viscosity and wettability controls fluid displacement in porous media

Interplay of viscosity and wettability controls fluid displacement in porous media

The interaction of gravity currents in a porous layer with a finite edge

The interactions of upper (lighter) and lower (heavier) gravity currents are closely related to fluid-phase resource recovery in porous layers and cleaning of confined spaces. The addition of a second current increases the sweep efficiency of fluid displacement. In this paper, we first derive two ordinary differential equations to describe the interaction of gravity currents in the quasi-steady regime. Two asymptotic regimes are identified, characterised by whether or not the two currents attach to each other, depending on whether the source fluxes are large enough. In the attached regime, a symmetry condition is also identified that describes whether or not the pumping and buoyancy forces balance each other. The model also leads to analytical solutions for the interface shape of the interacting currents in both the detached and attached regimes and for both symmetric and asymmetric currents. For symmetric currents, analytical solutions can also be obtained for the pressure distribution along cap rocks and the sweep efficiency of flooding processes. A particularly interesting aspect is that the displaced fluid remains quiescent at any steady state, regardless of whether the currents attach to each other. Correspondingly, the interface shape of the currents can be described by relatively simple equations and solutions, as if the currents propagate independently in unconfined porous layers. Time transition towards quasi-steady solutions is provided, employing time-dependent numerical solutions of two coupled partial differential equations for dynamic current interaction.

Simulating the displacement of a heavy oil by a lighter oil in an offshore production line

AbstractAn analysis was conducted on the displacement of a heavy fluid by a miscible light fluid in the flow assurance operation of injecting diesel oil to displace heavy oil in an insulated offshore production line. A three‐dimensional computational fluid dynamics model was developed and implemented in OpenFOAM®. It stimulates the production stages, no‐touch time, and oil displacement, considering heat transfer through natural convection and conjugated heat transfer through the solid layers of the pipeline. The specific test case focused on the first 180 m of an existing offshore production line. The simulations revealed two primary mechanisms of mixing: turbulence and secondary flows generated by the pipeline curves. Remarkably, the results demonstrate that by injecting a volume of lighter oil 1.3 times the pipeline volume, approximately 90%–95% of the heavy oil can be effectively removed.

Interfacial dilatational rheology and displacement mechanism of nano‐flooding system

AbstractIn the field of crude oil extraction, nano‐flooding technology can significantly improve the oil displacement efficiency and provide important technical support for tertiary oil recovery. Although a host of studies have been carried out in this domain, its dilatational rheology and displacement mechanism are rarely reported. In order to address this gap in the extant literature, as a crucial component of this investigation, the interfacial rheology of the nano‐flooding system and the simulated crude oil was systematically studied with the aid of the JMP2000A interface expansion rheometer. Meanwhile, a micro‐displacement experiment was carried out to elucidate its displacement mechanism. The obtained results show that the nano‐flooding system initially increases as its concentration, solution pH, and aging time increase, after which a decline is observed. However, with the change of salinity, it shows a trend of increasing first and then decreasing. Moreover, according to the multi‐factor test results yielded by the relevant software, the relative error is less than 5%, which fully meets the needs of the field and provides an important basis for the field construction. The findings further suggest that the modulus between the nano‐flooding system and the simulated crude oil can be increased by 84‐fold (i.e., from 0.9271 to 78.0739 mN/m). In addition, during the displacement process, the fingering phenomenon of the displacement fluid can be reduced via piston‐like displacement. The swept volume also improves the oil washing efficiency of crude oil, demonstrating that the proposed strategy achieves the purpose of enhancing oil recovery.

Double-layer pipe dual-gradient drilling wellbore pressure calculation model and parameters optimization

Deepwater oil and gas extraction face the problem of narrow safety density window, and double-layer pipe dual-gradient drilling is one of the effective ways to solve the problem of narrow safety density window, but the calculation model of borehole pressure and optimization method of drilling parameters for double-layer pipe dual-gradient drilling has not been thoroughly investigated. Based on the fluid dynamics theory, a dual-gradient drilling wellbore pressure calculation model was established, considering the influence of lift pump head size and installation location on the bottom hole pressure and the dynamic changes of wellbore pressure during drilling. Based on the wellbore pressure model and step-out strategy, the optimization model and algorithm of double-layer pipe dual-gradient drilling parameters were established with the minimum bottom hole pressure difference as the objective function and drilling fluid density, displacement, lift pump to bit distance and back pressure as the optimization parameters. Simulation analysis of the optimized drilling parameters (drilling fluid displacement and wellhead return pressure) was carried out using the optimization algorithm. It was found that the optimized drilling parameters could increase the drilling depth, reduce the bottom hole pressure differential and improve the mechanical drilling speed. The above optimization model and method can be used to optimize the drilling parameters for double-layer tubular dual-gradient drilling, which is beneficial to increase the drilling depth and reduce the bottom hole differential pressure.

Primary drainage and waterflood capillary pressures and fluid displacement in a mixed-wet microporous reservoir carbonate

A porous plate technique was developed to measure capillary pressure during both primary drainage and waterflooding in a reservoir carbonate rock sample. During primary drainage, a water-wet ceramic disc at the end of the sample allowed brine to be displaced but prevented the escape of oil while oil was injected at a sequence of increasing pressures. Saturation was measured using high-resolution three-dimensional X-ray imaging from the differences in greyscale (X-ray adsorption) between dry, partially-saturated and completely-saturated images. A two-step displacement process was observed, with the resolvable macro-pores displaced by oil followed by invasion into unresolved micro-porosity with a variation of two orders of magnitude in capillary pressure. The sample was then exposed to crude oil to render some of the solid surfaces oil-wet. A small amount of spontaneous imbibition (displacement at a positive capillary pressure) was observed in micro-porosity. Then an oil-wet porous plate was added to the outlet, so that water could be injected at a sequence of increasing pressures while only oil could escape. As expected, the oil-wet macro-porosity was displaced by brine at a low capillary pressure with a magnitude similar to that seen during drainage (but of opposite sign). Remarkably though the displacement of oil from micro-porosity occurred at a capillary pressure approximately an order of magnitude lower than in drainage, implying the existence of mixed-wettability with fluid menisci that are approximately minimal surfaces. The work demonstrates that in mixed-wet media displacement of oil from micro-porosity can occur at much lower capillary pressures that would be estimated from primary drainage results using the calculated pore size distribution.

Experimental Investigation of Two-Phase Flow Properties of Heterogeneous Rocks Based on X-Ray Microfocus Radiography

Summary An uncommon facet of formation evaluation is the assessment of flow-related in-situ properties of rocks. Most of the models used to describe two-phase flow properties of porous rocks assume homogeneous and/or isotropic media, which is hardly the case with actual reservoir rocks, regardless of scale; carbonates and grain-laminated sandstones are but two common examples of this situation. The degree of spatial complexity of rocks and its effect on the mobility of hydrocarbons are of paramount importance for the description of multiphase fluid flow in most contemporary reservoirs. There is thus a need for experimental and numerical methods that integrate all salient details about fluid-fluid and rock-fluid interactions. Such hybrid, laboratory-simulation projects are necessary to develop realistic models of fractional flow in complex rocks, i.e., saturation-dependent capillary pressure and relative permeability. Furthermore, these two crucial properties are usually measured independently. Capillary pressure is typically assessed using static measurements and unrealistic pressure conditions, whereas relative permeability is evaluated dynamically. Consequently, the disparity between the nature of the two experimental procedures often results in a potentially significant loss of information. We document a new high-resolution visualization technique that provides experimental insight to quantify fluid saturation patterns in heterogeneous rocks which allow for the simultaneous and dynamic evaluation of two-phase flow properties. The experimental apparatus consists of an X-ray microfocus scanner and an automated syringe pump. Rather than using traditional cylindrical cores, thin rectangular rock samples are examined, their thickness being one order of magnitude smaller than the remaining two dimensions. During the experiment, the core is scanned quasicontinuously while the fluids are being injected, allowing for time-lapse visualization of the flood front. Numerical simulations are then conducted to match the experimental data and quantify effective saturation-dependent relative permeability and capillary pressure. The experimental results indicate that flow patterns and in-situ saturations are highly dependent on the nature of the heterogeneity and bedding-plane orientation during both imbibition and drainage cycles. In homogeneous rocks, fluid displacement approaches piston-like behavior. The assessment of capillary pressure and relative permeability is performed by examining the time-lapse water saturation profiles resulting from fluid displacement. In spatially complex rocks, high-resolution time-lapse images reveal preferential flow paths along high-permeability sections and a lowered sweep efficiency. Our experimental procedure emphasizes that capillary pressure and transmissibility differences play an important role in fluid-saturation distribution and sweep efficiency at late times. The method is fast and reliable to assess mixing laws for fluid-transport properties of rocks in spatially complex formations.