Displacement Front Research Articles

Assessment of the Influence of Water Saturation and Capillary Pressure Gradients on Size Formation of Two-Phase Filtration Zone in Compressed Low-Permeable Reservoir

The paper examines the influence of capillary pressure and water saturation ratio gradients on the size of the two-phase filtration zone during flooding of a low-permeable reservoir. Variations of water saturation ratio s in the zone of two-phase filtration are associated with the pressure variation of water injected into the reservoir; moreover the law of variation of water saturation ratio s(r, t) must correspond to the variation of injection pressure, i.e. it must be described by the same functions, as the functions of water pressure variation, but be subject to its own boundary conditions. The paper considers five options of s(r, t) dependency on time and coordinates.
 In order to estimate the influence of formation and fluid compressibility, the authors examine Rapoport – Lis model for incompressible media with a violated lower limit for Darcy’s law application and a time-dependent radius of oil displacement by water. When the lower limit for Darcy’s law application is violated, the radius of the displacement front depends on the value of capillary pressure gradient and the assignment of s function. 
 It is shown that displacement front radii contain coefficients that carry information about physical properties of the reservoir and the displacement fluid. A comparison of two-phase filtration radii for incompressible and compressible reservoirs is performed.
 The influence of capillary pressure gradient and functional dependencies of water saturation ratio on oil displacement in low-permeable reservoirs is assessed.
 It is identified that capillary pressure gradient has practically no effect on the size of the two-phase filtration zone and the share of water in the arbitrary point of the formation, whereas the variation of water saturation ratio and reservoir compressibility exert a significant influence thereupon.

Experimental study on the CO2-decane displacement front behavior in high permeability sand evaluated by magnetic resonance imaging

CO2 flooding has been proven to be an effective method to improve oil recovery, and the interface characteristics of the displacement front directly affect the oil recovery and CO2 utilization efficiency in reservoirs. In this study, we aimed to investigate the in situ interfacial behavior during CO2 flooding using high-resolution magnetic resonance imaging (MRI). A series of CO2 flooding tests were carried out using upward and downward injection methods consisting of different rates (28, 56 and 112 pore volume (PV)/day) in porous media. The unstable CO2 front is indicated to significantly impact the gas sweep efficiency, which is not favorable for oil recovery and leads to low energy utilization efficiency. For downward injection, subordinate displacement of CO2 was observed after breakthrough, which can improve oil recovery. The optimum oil recovery and CO2 utilization factor were obtained under upward injection at a low rate in the immiscible state, which was controlled by the stable interface behavior. From the perspective of CO2 storage, miscible flooding improved the storage volume by more than 25% compared to immiscible flooding. For high permeability oil reservoirs, the oil recovery and gas sequestration can be synthetically optimized by adjusting the injection rates and phase state.

Dynamic Contact Angle Reformulates Pore-Scale Fluid-Fluid Displacement at Ultralow Interfacial Tension

Summary Surfactant flooding is an effective enhanced oil recovery method in which the oil/water interfacial tension (IFT) is reduced to ultralow values (<0.01 mN/m). The microscopic fluid-fluid displacement has been extensively studied at high IFT (>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.

A New Method for Potential Evaluation of Compound Flooding of Tertiary Oil Recovery

Compound flooding and tertiary oil recovery is one of the leading methods to improve recovery efficiency in oil and gas development in China, Because there are certain requirements on the exploitation environment and technology in the process of petroleum exploitation, it is necessary to evaluate and analyze the reservoir potential in advance. Currently, our research team has integrated this method into the tertiary oil production potential evaluation software EORSYS3.0. In this paper, a new combined flooding potential prediction model is established to improve the accuracy of reservoir potential prediction results by changing the reservoir water cut of displacement front viscosity.

Experimental evaluation of live oil oxidation together with its physical properties during air injection in a tight oil reservoir

In this paper, an integrated and pragmatic framework has been developed to experimentally determine the live oil oxidation with its physical properties and evaluate performance of air injection in a tight reservoir. In addition to continuously measuring interfacial tension, slim tube tests were performed to monitor and quantify miscibility between air and live oil collected from the Upper Triassic Yanchang Formation of the Chang 7 tight oil reservoir in the Ordos Basin, China. The displacement experiments showed that oil recovery factor of air injection is obviously higher than that of nitrogen injection in core plugs collected from the tight oil reservoir, while static and dynamic oxidation experiments were then conducted to identify the inherent oxidation mechanisms. The comparative core displacement experiments of live oil by air and nitrogen injection under reservoir temperature and pressure were carried out to evaluate the enhanced oil recovery (EOR) performance of air injection. It is found that heat released by the oxygen addition reaction under the formation conditions of 60.0 °C and 16.00 MPa leads to the bond scission reaction. The gas generated by the bond scission reaction forms a flue gas displacement front together with the remaining nitrogen contained in the air. Although miscibility cannot be achieved, air injection followed by the oxygen addition reaction and the bond scission reaction can reduce oil viscosity and thus increase its flowability. As for the commonly experimental studies with dead oils excluding porous media, the oxidation degree and the corresponding physical properties are normally overestimated since light components are limited in the dead oils and porous media constrain the corresponding oxidation.

Fluid Displacement in a Dual-Permeability Medium with Local Capillary Equilibrium

The solution to the Buckley–Leverett problem in fractured porous media is investigated by applying the dual-porosity dual-permeability model. It is shown that the dual-permeability medium is equivalent to an upscaled homogenized medium at long injection times when local capillary equilibrium is established. Simple analytical relationships for the petrophysical properties and saturation functions of the equivalent medium are derived. The upscaled relative permeability and the fractional flow function can exhibit kinks, resulting in more complicated solutions to the Buckley–Leverett problem as compared to the classical case. It is found that immiscible displacement in fractured porous media leads to the appearance of saturation profiles with several displacement fronts and rarefaction waves. Up to four solution types are possible, which are constrained in a solution map constructed in the space of the dimensionless parameters of the problem. It is shown that, for particular parameters, the displacing fluid moves faster through the matrix than through the fractures.

Increase of condensation for gas-condensate discharges at the finishing stage of development

Based on a two-phase multicomponent filtration model, the process of retrograde condensate extraction at the final stage of the development of a gas-condensate reservoir was investigated, with the creation of a volume of ethane rims in the reservoir with subsequent injection of the separated gas. It has been established that ethane dissolves in a retrograde condensate during continuous mass exchange between the phases of the system, creates a shaft of liquid hydrocarbons higher than critical at the front of displacement, at which two-phase filtration begins, which allows for the development of reserves of retrograde hydrocarbon condensate and, ultimately, provides effective reservoir development.

The Impact of Wettability and Surface Roughness on Fluid Displacement and Capillary Trapping in 2‐D and 3‐D Porous Media: 1. Wettability‐Controlled Phase Transition of Trapping Efficiency in Glass Beads Packs

AbstractFluid invasion, displacement of one fluid by another in porous media, is important in a large number of industrial and natural processes. Of special interest is the trapping of gas and oil clusters. We study the impact of wettability on fluid pattern formation and capillary trapping in three‐dimensional glass beads packs (dmean = 1 mm) during fluid invasion at capillary numbers of 10−7 using μ‐CT. The invading fluid was water, and the defending fluid was air. The contact angle of the glass beads was altered between 5° and 115° using Piranha cleaning and silanization. We analyzed the front morphology of the invading fluid, the residual gas saturation, the fluid occupation frequency of pores, and the morphology and statistics of the trapped gas clusters. We found a sharp transition (crossover) at a critical contact angle θc = 96°. Below θc the morphology of the displacement front was flat and compact caused by the strong smoothing effect of cooperative filling. Above θc the morphology of the displacement front was fractal and ramified caused by single bursts (Haines jumps). Across this dynamical phase transition the trapping efficiency changes from no trapping to maximal trapping. For θ > θc the experimental results show that invasion percolation governs the fluid displacement. Strong indicators are the universal scaling behavior of the size distribution of large clusters (relative data error εdata < 1%) and their linear surface‐volume relationship (R2 = 0.99).

Efficient Preparation of Nano-Starch Particles and Its Mechanism of Enhanced Oil Recovery in Low-Permeability Oil Reservoirs

Summary As development of low-permeability oil reservoirs continues to increase, it urgently needs an efficient enhanced oil recovery (EOR) technology to adapt to the new situation and requirement of oilfield exploitation. Although the application of nanomaterials for the EOR of low-permeability oil reservoirs has initially obtained good results, the types of currently used nanomaterials in the field of EOR are limited, and the mechanism of EOR is still unclear. In this paper, a type of nanosized starch particle is efficiently prepared using the method of precipitation with the help of ultrasonic oscillation. Under ultrasonic oscillation, the viscosity of starch paste can be significantly decreased, which is beneficial for the precipitation of starch nanoparticles. After ultrasonic oscillation, the size of the developed nanoparticles is smaller and controlled during the precipitation of starch paste using ethanol as the precipitating agent. The developed nanosized starch particles are suitable for the low-permeability oil reservoirs with low-salinity water. Subsequently, the mechanism of EOR of the developed nanosized starch particles is systematically studied through laboratory experiments. In addition to changing the wettability of rock surface and decreasing oil/water interfacial tension (IFT), the nanosized starch particles can effectively change the motion state of water molecules and cause the change of the structure of water molecules. In the low-permeability core, the displacement front of the nanosized starch solution is uniform, and the sweep volume of the nanosized starch solution flooding is large. Because of a higher sweep volume and a smaller adsorption loss, nanosized starch solution flooding can achieve a better effect of oil recovery than surfactant flooding in 30 m of low-permeability porous medium. The conclusions can provide a new guidance for EOR technology to support the efficient development of low-permeability oil reservoirs.

Experimental study on viscous fingering in Hele-Shaw cell under acoustic impact

Viscous fingering shaped as curvature of the fluid displacement fronts are usually formed in porous media and Hele-Shaw cell when a liquid with a high viscosity is displaced by a liquid with a lower viscosity. Such interfacial instability is undesirable in many displacement processes, and mainly in oil production. We present the results of physical modeling of the displacement of viscous oil by air in Hele-Shaw cell. As a method of suppressing undesirable interphase instability, the effect of elastic vibrations on the process is proposed. The experiment was performed in stationary conditions and under acoustic action on the displacement process. In the absence of superimposed vibrations, the growth rate of viscous finger is 2.15 times higher than the speed of liquid flow at the cell border. The imposition of acoustic oscillations can both accelerate and slow down the growth rate of viscous fingers depending on their frequency. The paper discusses the peculiarities of the development of viscous fingering. The results are compared with the calculated data.

Geometry-Driven Detection, Tracking and Visual Analysis of Viscous and Gravitational Fingers.

Viscous and gravitational flow instabilities cause a displacement front to break up into finger-like fluids. The detection and evolutionary analysis of these fingering instabilities are critical in multiple scientific disciplines such as fluid mechanics and hydrogeology. However, previous detection methods of the viscous and gravitational fingers are based on density thresholding, which provides limited geometric information of the fingers. The geometric structures of fingers and their evolution are important yet little studied in the literature. In this article, we explore the geometric detection and evolution of the fingers in detail to elucidate the dynamics of the instability. We propose a ridge voxel detection method to guide the extraction of finger cores from three-dimensional (3D) scalar fields. After skeletonizing finger cores into skeletons, we design a spanning tree based approach to capture how fingers branch spatially from the finger skeletons. Finally, we devise a novel geometric-glyph augmented tracking graph to study how the fingers and their branches grow, merge, and split over time. Feedback from earth scientists demonstrates the usefulness of our approach to performing spatio-temporal geometric analyses of fingers.

Permeability Impairment and Salt Precipitation Patterns During CO2 Injection Into Single Natural Brine‐Filled Fractures

AbstractFormation dry‐out in fracture‐dominated geological reservoirs may alter the fracture space, impair rock absolute permeability, and cause a significant decrease in well injectivity. In this study, we numerically model the dry‐out processes occurring during supercritical CO2 (scCO2) injection into single brine‐filled fractures and evaluate the potential for salt precipitation under increasing effective normal stresses in the evaporative regime. We use an open‐source, parallel finite‐element framework to numerically model two‐phase flow through 2‐D fracture planes with aperture fields taken from naturally fractured granite cores at the Grimsel Test Site in Switzerland. Our results reveal a displacement front and a subsequent dry‐out front in all simulated scenarios, where higher effective stresses caused more flow channeling, higher rates of water evaporation, and larger volumes of salt precipitates. However, despite the larger salt volumes, the permeability impairment was lower at higher effective normal stresses. We conclude that the spatial distribution of the salt, precipitated in fractures with heterogeneous aperture fields, strongly affects the absolute permeability impairment caused by formation dry‐out. The numerical simulations assist in understanding the behavior of the injectivity in fractures and fracture networks during subsurface applications that involve scCO2 injection into brine.

One of the feasibilities of oil recovery increase in embedded-inhomogeneous reservoir

The paper reviews the feasibility of oil recovery increase in embedded-ingomogeneous reservoir with hydrodynamically isolated layers of various permeability applying chemical agents. As the chemical agents, electrical-chemical modified natural water (catolyte) and catolyte-based polyacrylamide agent (PAA) are used. For oil recovery increase of the inhomogeneous reservoirs, an ecologically safe catolyte with all the properties characteristic for the alkali is applied. For the alignment of displacement front in the layers of different permeability and the flooding decrease of high-permeable reservoir, the polyacrylamide is used. This combined method was previously conducted in homogenous model and showed high efficiency. It allowed testing the method of oil displacement in embedded-ingomogeneous reservoir model. The effectiveness is achieved using catolyte and catoly- te-based PAA solutions in embedded-inhomogeneous reservoir in oil displacement process. Due to this, the low-permeability la-yer is much more involved into the process and the oil recovery factor increases.

Efficiency of Urea Solutions in Enhanced Oil Recovery.

We examine the applicability of urea solutions as a novel cost-effective chemical for enhanced oil recovery processes. Two sandpack flooding experiments were conducted using 5 and 10 wt % urea solutions. Another flooding experiment was also carried out using the same sandpack with fresh water and used as a reference. Supporting experiments such as interfacial tension (IFT), viscosity of water in oil (W/O) emulsions, total acid number (TAN), and Fourier-transform infrared (FTIR) spectroscopy were conducted to confirm the generation of in situ surfactants by reacting urea solutions with the naphthenic acids in bitumen and evaluate their impact on the oil recovery. The analyses of FTIR, IFT, TAN, and viscosity measurements support the generation of in situ surfactants that leads to the formation of stable water in oil emulsions and hence a more stable displacement front resulting in higher oil recovery.

Static and dynamic behavior of CO2 enhanced oil recovery in nanoslits: Effects of mineral type and oil components

In the present study, the oil miscibility and displacement of CO2/oil systems in nanoslits referred to three minerals (e.g., quartz, calcite and kaolinite) were characterized by molecular dynamics simulations. First, the mode of oil migration was identified to be affected by the difference in the interaction between CO2/C10 and solid surface. In the meantime, we recognized that the stability of displacement front was critical to ensure the smooth migration of oil phase. Besides, the oil molecules were more likely to undergo two-way mass transfer between oil and gas in the multi-component system. Nevertheless, the oil phase exhibited obviously poor mobility and higher viscosity in dynamic system, thereby inhibiting the oil phase that contained multi-components from being displaced and detached. Overall, the study highlights the effect of mineral types and oil components on the oil miscibility and displacement in CO2 flooding, which probably boosting the development of low permeability reservoirs.

Influencing factors and application prospects of CO2 flooding in heterogeneous glutenite reservoirs

In recent years, large amounts of CO2 emissions have led to many environmental problems. Developing a reasonable approach to carbon dioxide emissions is one of the most important issues for the sustainable development of human civilization. Compared with CO2 geological storage, CO2 flooding has greater advantages and a higher utilization efficiency. CO2 flooding technology has been successfully applied to many types of reservoirs, such as conventional sandstone reservoirs, low-permeability reservoirs, and carbonates. In this paper, the feasibility of CO2 flooding in glutenite reservoirs is studied. First, the glutenite reservoir is divided into fine stages, and reasonable vertical development units are determined. On this basis, the distribution scale, genetic environment and formation mode of the glutenite reservoir are characterized in detail and their spatial distribution rules are depicted in three dimensions. Then, the influencing factors of CO2 flooding in the glutenite reservoir are analysed via reservoir numerical simulation technology. The effects of reservoir thickness, reservoir heterogeneity, macropores, dominant channels and fracturing on CO2 flooding efficiency are evaluated individually, and a set of reasonable parameters constituting an evaluation system for CO2 flooding in the glutenite reservoir is established. Finally, based on parameter optimization, the disadvantaged conditions of CO2 flooding in glutenite reservoirs are optimized, and their effects are gradually eliminated. In view of the characteristics of glutenite reservoirs, a unique three-dimensional well pattern arrangement is designed, different injection modes are optimized, and suitable injection agents are tested. These methods are conducive to improving the effect of reservoir parameters on CO2 flooding efficiency, allowing these reservoirs to be used for CO2 flooding. Based on these new methods, the displacement effect of the Yanjia-Yongan glutenite reservoir is predicted. Our results show that the reservoir has been developed efficiently and achieved a high recovery rate, the displacement front of the CO2 has become more uniform, and the sweep range has become wider. After extending the successful application of CO2 flooding in this reservoir to all of the glutenite reservoirs in the entirety of the Bohaiwan Basin, we predict that the oil recovery rate may reach 40%, with a cumulative oil recovery rate of approximately 3.04 × 108 t and a total CO2 consumption of 1.672 × 108 t. Thus, the proposed approach not only can improve the atmospheric environment but can also greatly improve the efficiency of oil displacement.

Complexity of Fault Rupture and Fluid Leakage in Shale: Insights From a Controlled Fault Activation Experiment

AbstractWe observed rupture growth caused by controlled fluid injections at 340‐m depth within a fault zone in the low‐permeability Opalinus Clay in the Mont Terri Underground Research Laboratory (Switzerland). The rupture mechanisms were evaluated using measurements of the three‐component borehole wall displacements and fluid pressure in two sections of the fault zone and located horizontally 3 m apart from each other. One section was set across a secondary segment of the fault and used for stepwise fluid injection intended to trigger rupture growth. The other section was set across the principal shear zone of the fault for monitoring. After stepwise pressure increase up to 5.95 MPa at injection, rupture initiated as slip activation, followed by an overall opening of the fault planes connected to the injection. After 19 s of continued injection, displacements arrived at the monitoring point on the principal shear zone. These displacements are about 2.4 times larger than in the secondary fault segment. Overall, the displacements corresponded to a normal fault activation. About 9 s after the displacement front arrived, a strong pressure increase of 4.17 MPa was measured at the monitoring point, indicating a hydraulic connection had formed along the initially very low permeability fault planes between the injection and the monitoring points. Our analyses highlight that the fault activation is consistent with the state of stress but that injection pressure must be close to the normal stress acting on the fault for permeability to be generated and for fluid leakage to occur.

Rapid classification of primary cementing flows

We develop a simplified approach to predicting the displacement front behaviour of two Herschel-Bulkley fluids displacing one another along a narrow eccentric annulus in turbulent and mixed regimes. The approach involves the use of scaling arguments to reduce the full system of equations to a single hyperbolic equation that models the displacement front evolution. Analysis of the flux function is sufficient to predict whether or not the front will elongate along the annulus. Predictions of the simplified model are compared with a two-dimensional annular displacement model, showing good predictive abilities. The underlying eccentric annular flow is important in the industrial process of primary cementing. More specifically, the proposed method is aimed to provide a quick and reliable computational framework for analyzing primary cementing flows, leading to more successful cementing designs.

Методика восстановления оптимального режима функционирования системы пласт – скважина с учетом неустойчивости фронта вытеснения

Методика восстановления оптимального режима функционирования системы пласт – скважина с учетом неустойчивости фронта вытеснения

Experimental study ofin-situW/O emulsification during the injection of MgSO4and Na2CO3solutions in a glass micromodel

In-situemulsification of injected brines of various types is gaining increased attention for the purpose of enhanced oil recovery. The present experimental study aims at evaluating the impact of injecting various solutions of Na2CO3and MgSO4 at different flow rates resembling those in the reservoir and near wellbore using a glass micromodel with different permeability regions. Emulsification process was visualized through the injection of deionized water and different brines at different flow rates. The experimental results showed that the extent of emulsions produced in the vicinity of the micromodel exit was profoundly higher than those at the entrance of the micromodel. The injection of Na2CO3brine after deionized water caused the impact of emulsification process more efficiently for attaining higher oil recovery than that for the MgSO4brine. For instance, the injection of MgSO4solution after water flooding increased oil recovery only up to 1%, while the equivalent figure for Na2CO3was 28%. It was also found that lower flow rate of injection would cause the displacement front to be broadened since the injected fluid had more time to interact with the oil phase. Finally, lower injection flow rate reduced the viscous force of the displacing fluid which led to lesser occurrence of viscous fingering phenomenon.