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Summary Polymer flooding is an enhanced oil recovery (EOR) method which improves the mobility ratio and sweep efficiency of a waterflood. In theory, the high viscosity of the polymer reduces its injectivity compared to water. However, field studies have documented much higher polymer injectivity than predicted by theoretical models. There are various reasons for high polymer injectivity. The objective of this work is to predict polymer injectivity in granular media accounting for fluid-induced fractures, water quality, polymer rheology, and undissolved polymers. We perform grain-scale, coupled fluid dynamics and granular mechanics modeling. Fluid-particle interactions are modeled by coupling computational fluid dynamics (CFD) and the discrete element method (DEM). Simulation results show that polymer injection can create fractures in the granular media along the direction perpendicular to the minimum principal stress, thereby reducing wellbore pressure buildup at a constant polymer injection rate. The polymer tends to flow in the direction of fracture propagation in granular media, so the direction of the fracture affects the swept area of the polymer. Polymer rheology, water quality, and undissolved polymer also affect the polymer injectivity. Suspended solid particles may plug pores and reduce the injectivity of polymer by ~25%. Mechanically trapped undissolved polymers can greatly reduce polymer injectivity in low-permeability granular media. This work shows for the first time initiation of polymer-driven fractures in a granular model and demonstrates its implications on polymer injectivity.

Summary An efficient tertiary chemical flood involves the chemicals displacing the oil in a stable manner, so the initially disconnected trapped oil ganglia coalesce into a bank as the flood progresses. However, the location of surfactants and polymers in the core during a chemical flood is difficult or impossible to determine at very fine time and space resolutions. In this work, we bridge this gap by visualizing saturation profiles in a coreflood-on-a-chip, a micromodel that is the same length as a core, and monitoring fluorescent aqueous injectant as displacements occur. We visualize, for the first time, surfactants in and around oil banks at the pore and Darcy scales during low-tension displacements. We present 12 chemical floods in the coreflood-on-a-chip, imaged at the centimeter scale, including six surfactant and six alkali-surfactant-polymer (ASP) floods at low, intermediate, and high initial water saturations. Additionally, we present a micron-scale visualization of an ASP flood under UV light to observe the distribution of surfactant around an oil bank at the pore scale. We found that oil banks formed even during very unfavorable displacements, when surfactant solution (1 cp) displaced oil (80 cp) in a micromodel at intermediate and residual oil saturations. Although our results show saturation profiles are mostly well described by fractional flow theory, the distribution of injected aqueous phase is not. Significant aqueous injectant, including surfactant, flows within and ahead of oil banks.

SummaryNew experiments using polyethylene oxide (PEO) polymer were performed to evaluate its potential for enhanced oil recovery (EOR) applications in low-permeability reservoirs. This is the first time that high molecular weight PEO solutions have been shown to have favorable transport in low-permeability (~20 md) carbonate cores and the first time PEO has been shown to improve oil recovery in a fractured carbonate core. Rheology measurements in synthetic seawater show the higher viscosity of PEO solutions compares favorably to the viscosity of acrylamide–sodium acrylate (AM-AA) copolymers of similar molecular weight because PEO is less sensitive to hardness and high salinity. Filtration experiments using 0.45 μm cellulose filters show very favorable filtration ratios of PEO with a molecular weight of 4 million g/mol, which is consistent with its favorable transport in low-permeability cores. Four coreflood experiments in Texas Cream Limestone (TC Limestone) cores demonstrate the viability of PEO for EOR in low-permeability carbonate rocks. Single-phase experiments show 4 million g/mol PEO solutions transported through 18 and 28 md TC Limestone cores. Oil recovery experiments show 4 million g/mol PEO solutions transported and was more efficient than waterflooding in aged TC Limestone with favorable retention of 40 µg/g rock. An oil recovery experiment in an artificially fractured TC Limestone core improved oil recovery by a remarkable 15% considering the very large fracture-matrix permeability contrast (>7,000). These experimental results as well as other favorable properties of PEO reported in the literature indicate PEO should be considered for some EOR applications, especially in low-permeability reservoirs.

Summary Nanoparticles have great potential to mobilize trapped oil in reservoirs because of their chemical, thermal, and interfacial properties. However, the direct application of magnetic forces on superparamagnetic nanoparticles in reservoir engineering applications has not been extensively investigated. We demonstrate the enhanced oil recovery (EOR) potential of hydrophilic superparamagnetic nanoparticles in oil production by direct observation using microfluidics. We studied the mobilization of oil blobs by a ferrofluid (a suspension of hydrophilic superparamagnetic nanoparticles in water) both in a converging/diverging micromodel channel and in a foot-long pore network micromodel, both with varying depth (so-called 2.5D micromodels). The water-based ferrofluid in all cases was the wetting fluid. Initial ferrofluid flooding experiments in single channels were performed without and then with a static magnetic field. This magnetic field caused oil droplet deformation, dynamic breakup into smaller droplets, and subsequent residual oil saturation reduction. During the flooding, after the magnetic field was applied, significant oil displacement was observed within 2 hours [6 pore volumes injected (PVI)], and 86.2% of the oil that was not mobilized without a magnetic field was mobilized within 64 hours (192 PVI). Then, in experiments in the micromodel and in a Hele-Shaw cell without flooding, we observed self-assembly of oil droplets, indicating the formation of the hydrophilic magnetic nanoparticle microstructures (chains under the magnetic field) and their interaction with the oil blobs. Further ferrofluid flooding experiments were performed in a foot-long micromodel under a rotating magnetic field. The oil saturation was reduced from 44.6 to 33.3% after 17 hours (8.5 PVI) of ferrofluid flooding after the rotating magnetic field was applied. Finally, a discussion of field application of ferrofluid flooding is presented.

Summary Surfactant flooding is an effective enhanced oil recovery method in which the oil/water interfacial tension (IFT) is reduced to ultralow values (10 mN/m). However, the microscopic displacement dynamics can be significantly different when the IFT is ultralow because the dynamic contact angle increases with the increase of the capillary number. In this study, surfactant flooding was performed and visualized in micromodels to investigate the dynamics of multiphase displacement at ultralow IFT. Although the micromodels used were strongly water-wet, the displacements of oil by surfactant solutions at ultralow IFT appeared as drainage. Furthermore, a macroscopic oil film was left behind on the surface, which indicates that a contact line instability occurred during displacements. The shape of the oil/water meniscus was determined by the balance between viscous forces and capillary forces. The meniscus can be significantly distorted by viscous forces at ultralow IFT. Therefore, the water-wet micromodel exhibits an oil-wet behavior at ultralow IFT, and the displacements of oil by surfactant solutions at ultralow IFT manifested as drainage rather than imbibition. The flow behavior is further complicated by the spontaneous formation of microemulsion during displacement. The microemulsion is mainly formed from the residual oil. The formation of a microemulsion bank made the surfactant solution discontinuous, with transport in the form of droplets in the microemulsion bank and displacement front. The novelty of this work is to reveal the effects of dynamic contact angle on the ultralow IFT displacement.

Summary The reduction of pore pressure caused by depletion can induce significant reservoir compaction and loss of permeability, especially in unconsolidated reservoirs. In this paper, we develop a numerical approach on the basis of computer-based simulations of unconsolidated rock samples subjected to mechanical tests that replicate the one-dimensional (1D) strain depletion path and allow for a prediction of permeability loss. The 1D strain stress path is a good approximation for long and thin conventional reservoirs with a compliant caprock. The numerical sample consists of crushable stiff and soft grains (proxies for sand and shale) simulated with the discrete element method (DEM) coupled with the bonded-particle model (BPM). Model parameters are calibrated through numerical single-grain-crushing tests which reproduce the experimentally measured sand strength. Grain crushing induced by the uniaxial strain stress path results in a pronounced reduction of porosity and permeability, which manifests more readily for samples with large grain size. The change of particle-size distribution indicates that high effective stresses cause grain crushing and production of a significant amount of fines that lower permeability. Simulation results indicate that the presence of soft grains and inclusions (e.g., shale fragments) facilitates grain crushing. Reservoir simulations—incorporating the change of porosity and permeability as a compaction table—show that the compaction can enhance cumulative production due to compaction drive but also reduces production rate by impairing the reservoir permeability. This multiscale numerical workflow bridges grain-scale compaction behavior and field-scale reservoir production.

SummaryWe present a study of the low–salinity effect during oil recovery using microfluidics experiments in an attempt to narrow the gap between pore–scale observations and porous–media–flow mechanisms, and to explain one type of low–salinity effect with delayed oil recovery and without the presence of clay. A microfluidic toolbox is used, including single–pore–scale microchannels, a pore–network–scale (approximately 102 pores) micromodel, and a reservoir–on–a–chip model (approximately 104 pores with heterogeneity), all with 2D connectivity. Experiments at the single–pore scale reveal a time–dependent oil dewetting and swelling behavior when a crude–oil droplet is in contact with low–salinity water. An interplay between water chemical potential and oil–phase polar compounds explains this pore–scale observation well. Experiments at the pore–network scale illustrate that the dewetting and swelling of residual oil in the swept region increase the water–flow resistance, modifying the flow field and thus redirecting the flooding liquid into unswept regions. This pore–network–scale effect is re–expressed into a macroscale model as a sweep–efficiency improvement derived from the change of relative permeabilities, which requires time to develop. Finally, experiments on our “reservoir–on–a–chip” model show significant incremental oil recovery during tertiary low–salinity waterflooding and confirm that late–time sweep–efficiency improvement contributes to most of the incremental oil recovery. On the basis of this microfluidic framework, we emphasize the following three findings: Low–salinity tertiary waterflooding can improve oil recovery by an improvement of sweep efficiency, which is a consequence of residual–oil dewetting and swelling.The low–salinity effect can occur without the existence of clay.The wettability alteration and oil swelling are time–dependent processes and should be expressed as a function of oil/water contact time rather than dimensionless time [pore volume (PV)], which explains some observations from previous coreflood experiments.

Summary Water-based polymers are often used to improve oil recovery by increasing sweep efficiency. However, recent laboratory and field work have suggested these polymers, which are often viscoelastic, may also reduce residual oil saturation (ROS). The objective of this work is to investigate the effect of viscoelastic polymers on ROS in Bentheimer sandstones and identify conditions and mechanisms for the improved recovery. Bentheimer sandstones were saturated with a heavy oil (120 cp) and then waterflooded to ROS with brine followed by an inelastic Newtonian fluid (diluted glycerin). These floods were followed by injection of a viscoelastic polymer, hydrolyzed polyacrylamide (HPAM). Significant reduction in residual oil was observed for all corefloods performed at constant pressure drop when the polymer had significant elasticity (determined by the dimensionless Deborah number, NDe). An average residual-oil reduction of 5% original oil in place (OOIP) was found during HPAM polymer floods for NDe of 0.6 to 25. HPAM floods with very-low elasticity (NDe 25). All experiments at constant pressure drop indicate that polymer viscoelasticity reduces the ROS. Results from computed-tomography (CT) scans further support these observations. A correlation between Deborah number and ROS is also presented.

Summary Injecting oil-in-water (O/W) emulsions stabilized with nanoparticles (NPs) or surfactants is a promising option for enhanced oil recovery (EOR) in harsh-condition reservoirs. Stability and rheology of the flowing emulsion in porous media are key factors for the effectiveness of the EOR method. The objective of this study is to use microfluidics to (1) quantitatively evaluate the synergistic effect of surfactants and NPs on emulsion dynamic stability and how NPs affect the emulsion properties, and to (2) investigate how emulsion properties affect the sweep performance in emulsion flooding. A microfluidic device with well-defined channel geometry of a high-permeability pathway and multiple parallel low-permeability pathways was created to represent a fracture/matrix dual-permeability system. Measurement of droplet coalescence frequency during flow is used to quantify the dynamic stability of emulsions. An NP aqueous suspension (2 wt%) shows excellent ability to stabilize the macro-emulsion when mixed with a trace amount of surfactant (0.05 wt%), revealing a synergistic effect between NPs and surfactant. For a stable emulsion, when a pore throat is present in the high-permeability pathway, it was observed that flowing emulsion droplets compress each other and then block the high-permeability pathway at a throat structure, which forces the wetting phase into low-permeability pathways. Droplet size shows little correlation with this blocking effect. Water content was observed to be much higher in the low-permeability pathways than in the high-permeability pathways, indicating different emulsion texture and viscosity in channels of different sizes. Consequently, the assumption of bulk emulsion viscosity in the porous medium is not applicable in the description and modeling of the emulsion-flooding process. Flow of emulsions stabilized by an NP/surfactant mixture shows droplet packing in high-permeability regions that is denser than those stabilized by surfactant only, at high-permeability regions, which is attributed to the enhanced interaction between droplets caused by NPs in the thin liquid film between neighboring oil/water (O/W) interfaces. This effect is shown to enhance the performance of emulsion-blockage effect for sweep-efficiency improvement, showing the advantage of NPs as an emulsion stabilizer during an emulsion-based EOR process.

Summary Non-Darcy flow is often observed near wells and in hydraulic fractures where relatively high velocities occur. In these regions, an empirical model, Forchheimer's equation, is used in place of Darcy's Law. It includes a quadratic correction to the linear model and has been adequately fit to many experimental data sets, while found to be insufficient in others. Furthermore, a number of numerical and theoretical approaches have shown limitations of the Forchheimer model in the laminar flow regime. It is important to understand the applicability of Forchheimer's equation and to be able to obtain good predictions of macroscopic properties so that nonlinear flow can be properly modeled in reservoir simulators. In this work, non-Darcy flow of an incompressible fluid is modeled using a physically representative (Bryant et al. 1993) pore-scale network model. Quantitative and predictive results are obtained using both computer-generated porous media and real sandstones digitized through x-ray computed microtomography (XMT). A new friction factor correlation is developed for laminar flow in converging/diverging ducts using the numerical solution to the Navier-Stokes equations. The new equation is used to describe flow in pore throats of the network model. The permeability and non-Darcy coefficient, β, are determined for these isotropic and anisotropic media in which Forchheimer's equation is applicable. The numerical model is compared to existing experimental data and appears to be at least as successful as correlations for predicting the non-Darcy coefficient in isotropic media. Furthermore, limitations to Forchheimer's equation at both low and high velocities are determined and discussed.

Summary The retention of fracturing fluid in a proppant pack reduces the dimensionless fracture conductivity, Fcd, resulting in poor well productivity regardless of fluid type (gelled oil, crosslinked polymers, viscoelastic surfactants, or foams). Analytical expressions derived in this paper can be used to calculate the extent of fracture cleanup under a set of production conditions. Several dimensionless parameters describing the fluid, fracture, and reservoir properties are introduced that affect the equilibrium cleanup. A second, transient, fracture-cleanup model is also proposed and is used to estimate the dimensionless-parameter values. The equilibrium model predicts that cleanup increases greatly with decreasing dimensionless yield stress of the fracturing fluid. The magnitude of cleanup is also greater for cases in which the permeability ratio of the clean portion of the fracture to the fouled portion is high. The cleanup is expected to increase with an increase in the ratio of reservoir and fracture mobility until an optimum is reached, and then decrease with increasing the mobility ratio. The critical process of parameter estimation is achieved by making experimental measurements and by history matching published fracture flowback data using the transient model.