Reservoir Porous Media Research Articles

Insights into the Injectivity and Propagation Behavior of Preformed Particle Gel (PPG) in a Low-Medium-Permeability Reservoir.

Heterogeneous phase combined flooding (HPCF) has been a promising technology used for enhancing oil recovery in heterogeneous mature reservoirs. However, the injectivity and propagation behavior of preformed particle gel (PPG) in low-medium-permeability reservoir porous media is crucial for HPCF treatment in a low-medium-permeability reservoir. Thus, the injectivity and propagation behavior of preformed particle gel in a low-medium-permeability reservoir were systematically studied by conducting a series of sand pack flooding experiments. The matching factor (δ) was defined as the ratio of the average size of PPG particles to the mean size of pore throats and the pressure difference ratio (β) was proposed to characterize the injectivity and propagation ability of PPG. The results show that with the increase in particle size and the decrease in permeability, the resistance factor and residual resistance factor increase. With the increase in the matching factor, the resistance factor and residual resistance factor increase. The higher the resistance factor and residual resistance factor are, the worse the injectivity of particles is. By fitting the relationship curve, PPG injection and propagation standards were established: when the matching coefficient is less than 55 and β is less than 3.4, PPG can be injected; when the matching coefficient is 55-72 and β is 3.4-6.5, PPG injection is difficult; when the matching coefficient is greater than 72 and β is greater than 6.5, PPG cannot be injected Thus, the matching relationship between PPG particle size and reservoir permeability was obtained. This research will provide theoretical support for further EOR research and field application of heterogeneous phase combined flooding.

Kinetic Model and Numerical Simulation of Microbial Growth, Migration, and Oil Displacement in Reservoir Porous Media.

Microbial enhanced oil recovery (MEOR) is a potential tertiary oil recovery method. However, past research has failed to describe microbial growth and metabolism reasonably, especially quantification of reaction equations and operating parameters is still not clear. The present study investigated the ability of bacteria extracted from Ansai Oilfield for MEOR. Through core flooding experiments, bacteria-treated experiments produced approximately 6.28–9.81% higher oil recovery than control experiments. Then, the microbial reaction kinetic model was established based on laboratory experimental data and mass conservation. Furthermore, the proposed model was validated by matching core flooding experiment results. Lastly, the effects of different injection parameters on bacteria growth, bacteria migration, metabolite migration, residual oil distribution, and oil recovery were studied by establishing a field-scale model. The results indicate that the injected bacteria concentration and nutrient concentration have a great influence on bacteria growth in a reservoir and the low nutrient concentration seriously restricts bacteria growth. Compared with the injected bacteria concentration, nutrient concentration has a decisive effect on bacteria and metabolite migration. The injected bacteria concentration has little effect on oil recovery, while nutrient concentration and slug volume have a significant effect on oil recovery.

Comprehensive Effects of Polymer Flooding on Oil–Water Relative Permeabilities

Abstract Many reports have indicated that, in contrast to waterflooding, oil–water relative permeabilities in polymer flooding are influenced by the polymer properties, such as adsorption and viscoelasticity. Long-term injected polymer solutions flush the reservoir porous media causing wettability alteration and residual oil reduction, which is also an important factor for oil–water relative permeabilities. Therefore, the comprehensive effects of polymer properties and dynamic flushing on two-phase percolation behavior have been the focus of research. In this study, polymer flow experiments, including pre-shearing, relative permeability, and long-term erosion tests, were first conducted. Then, a flushing-interpolation model, including polymer concentration interpolation and surface flux characterization, was developed to dynamically describe the two-phase flow characteristics. Based on the experimental results and the presented dynamic model, polymer-flooding simulations were conducted to analyze the performance of the well and the distribution of the remaining oil. The results indicate that flushing reduces the residual oil saturation, and the viscoelasticity effect further broadens the predominant flushing channels horizontally; both effects lead to higher cumulative oil production and a lower water-cut. Additionally, including the flushing effect in the polymer-flooding model leads to a more reliable numerical prediction of the remaining oil distribution. To account for the comprehensive effects of viscoelasticity and erosion in field applications, water-cut history matching was performed for the studied well group, and the error decreased to 4.39%. Finally, the optimal polymer concentration for high-concentration polymer-flooding programs was determined to be 1450 mg/L.

Chromatography and oil displacement mechanism of a dispersed particle gel strengthened Alkali/Surfactant/Polymer combination flooding system for enhanced oil recovery

In recent years, a newly developed dispersed particle gel (DPG) has attracted significant attention because of its excellent properties and a good application prospect in an enhanced oil recovery process. The preparation method is convenient and easy to scale up for the field application. The dispersed particle gel with sizes ranging from submicron to micron can block the high permeability layers by accumulating in large pore spaces or directly plugging small pore throats. Furthermore, the dispersed particle gels can achieve in-depth profile control due to the elastic deformation and migration into the reservoir's porous media. These characteristics have demonstrated great potential for the dispersed particle gels to strengthen the alkali/surfactant/polymer combination flooding system. The polymers used are the principal sources of viscosity in the system; the surfactant and alkaline produce the synergistic effect by generating the ultralow oil-water interfacial tension. The added dispersed particle gel has a synergistic viscosity increase effect, temperature tolerance, and thermal stability. However, the combined flooding system suffers from the surfactant loss and chromatographic separation that affect the chemical components' synergistic effect for enhanced oil recovery. In this paper, the chromatography separation effects linked to a new method of oil displacement mechanism based on the dispersed particle gel strengthened Alkali/Surfactant/Polymer as a novel combination flooding system was investigated. The addition of dispersed particle gel in the Alkali/Surfactant/Polymer combination flooding system could interleave in the system's network structure and increase the viscosity stability by strengthening the flooding system to improve the oil recovery capacity. The novel dispersed particle gel strengthened alkali/surfactant/polymer flooding systems have a high displacement efficiency and a better-swept volume capacity considering the oilfield requirement for the enhanced oil recovery process. The effects of polymer, surfactant, alkaline, and dispersed particle gel concentration on the combination flooding system were evaluated, furthermore the impact of external factors on the system such as salinity; aging time was described. The results showed that the effects of external factors aging time and salinity slightly affected the system's interfacial reduction capacity. The increase in interface elasticity produced significantly favorable effects on system stability. For the displacement mechanism, when the dispersed particle gel strengthened alkali/surfactant/polymer combination flooding system moved in a porous medium, the dispersed particle gel passed through the pore throat directly or by deformation depending on the system's pressure variation.Furthermore, the phase separation was formed due to the combined component's effects, resulting in the differential migration between the systems, which led to different degrees of chromatographic separation phenomenon to affect the displacement mechanism. As we can see in the micro visualization simulation experiment, the residual oil interacted with Alkali molecules and form the in-situ surfactant, which makes the remaining oil emulsified, as well the surfactant adsorbed by DPG particles, make the crude oil emulsified and get enhanced. The chromatography and micro visualization experiments results of the dispersed particle gel strengthened alkali/surfactant/polymer combination flooding system indicated a favorable application of the system in an enhanced oil recovery process.

Fines migration and permeability decline during reservoir depletion coupled with clay swelling due to low-salinity water injection: An analytical study

Fines migration is crucial for reservoir permeability, involving both fine particle detachment and re-deposition along the flow channels. Fines migration behavior can either promote or obstruct fluid flow within the reservoir and is crucial for productivity optimization that needs fundamental understanding. The present work focuses on the contributions from effective stress build-up due to reservoir depletion and decreases in brine salinity from low-salinity water injection. Particle detachment is studied analytically by using the critical retention concentration function modified with stress and salinity dependents. Increase in formation effective stress leads to deformations within the reservoir configurations due to micro-cracks and reduced pore dimensions. Decreased size of the travelling channels promotes particle detachment, while the critical retention concentration decreases. A sensitivity study reveals that, under influence of effective stress, particle size and fluid velocity are dominant parameters controlling the fines migration by influencing the particle detaching forces. With decreasing brine salinity (e.g. via low-salinity water injection), clay particles that are attached on the pore surface increasingly swell, leading to reduction in effective pore space and flow channel. Decreased pore space directly obstructs travelling of suspended particles and fluids which results in permeability decline. Initial clay particle size is found to be a critical factor controlling particle detachment behavior. Small initial particle sizes are not likely to detach from the pore surface as a result of weak detaching forces, hence the analysis finds the critical retention concentration unchanged resulting in negligible permeability decline as a function of brine salinity. Considering both effects, effective stress and brine salinity, stress-dependent effects dominate salinity-dependent effects at low effective stress while the two contribute equally at high effective stress. Permeability decline is also determined from analytical results of the fine particle critical retention concentration, which emphasizes the roles of effective stress and brine salinity on the flow in reservoir porous media.

Lipid nanostructures as surfactant carriers for enhanced oil recovery

The main challenge faced by enhanced oil recovery processes (EOR) is to further increase production of the residual oil trapped within the reservoir porous media beyond conventional recovery methods. Chemical EOR processes, such as surfactant flooding, could be employed to dislocate the residual oil to a production well through the reduction of the water/oil (w/o) interfacial tension. Surfactant Flooding is an efficient method, but a large part of the injected surfactant is lost by adsorption on the rock surface before reaching the oil site, turning it often economically unfeasible. This work aimed to evaluate the potential of lipid nanostructures as surfactant nanocarriers for the EOR process. In this new concept, nanocarriers formed by hydrophobic nanoparticles (NPs), should be able to store and carry the surfactant molecules through the reservoir porous media, releasing the surfactant only at the w/o interface, triggered by the nanocarriers solubilization. The released surfactant did lead to a w/o interfacial tension reduction, improving the recovery factor. Nanoparticles were produced through nano-emulsification techniques with beeswax (BW) as the lipid structure and nonylphenol ethoxylate (NPE10) as surfactant. The nanocarriers were characterized by dynamic light scattering (DLS), scanning electron microscopy (SEM), differential scanning calorimetry (DSC) and surfactant entrapment in the nanocarriers. Interfacial tension (IFT) measurements and Fourier transform infrared spectroscopy (FTIR) analysis were used to evaluate the surfactant release and unconsolidated sandpack column tests were conducted to evaluate the transport behavior of the NPs system. The results did demonstrate that the nanocarriers should be able to permeate through the porous media and release the surfactant at the w/o interface, reducing the IFT to values compatible with the ones obtained when employing solely the surfactant solution. The effect of the nanoparticles production process, temperature and salt concentration on the efficiency of the nanoparticles in the delivery of the surfactant at the oil/water interface was evaluated and the results showed the great potential of this type of system as surfactant nanocarrier for the EOR process.

Optimization of the Horizontal-Well Hydraulic-Fracture Geometry From Caprock-Integrity Point of View Using Fully Coupled 3D Cohesive Elements

Summary Pre-analysis of the geometry of a hydraulically induced fracture, including fracture width, length, and height, plays a crucial role in a successful hydraulic-fracturing (HF) operation. Besides the geometry of the fracture, the injection rate should be optimal for obtaining desired results such as maintaining sufficient aperture for proppant placement, avoiding screenouts or proppant bridging, and also preventing caprock-integrity failure as a result of an extensively uncontrolled fracture in reservoirs. A sophisticated numerical model derived from the cohesive-elements method has been developed and validated using field data to obtain an insight on the optimal fracture geometry and injection rate that can lead to a safe and efficient operation. The HF operation has been conducted in an oil field in the Persian Gulf with the aim of enhanced oil recovery (EOR) from a limestone reservoir with low matrix permeability in a horizontal wellbore. The concept of the cohesive-elements method with pore pressure as an additional degree of freedom has been applied to a 3D fully coupled HF model to estimate fracture geometry, specifically fracture height as a function of the optimal injection rate in a reservoir porous medium. It was observed that by increasing injection rate, all the fracture-geometry parameters steeply increased, but the fracture height must be controlled to be in the reservoir domain and not surpass the caprock and sublayer. For the reservoir under study with the maximum height of 100 m, length of 250 m, width of 100 m, permeability of 2 md, and porosity of 10%, the optimal fracture height is 73.4 m; the average fracture width and half-length are 12.8 mm and 55.4 m, respectively. Therefore, the optimal injection rate derived from the fracture height and geometry is in this case 4.5 bbl/min. The computed fracture pressure (49.55 MPa = 7,283.85 psi) has been compared with the field fracture pressure (51.02 MPa = 7,500 psi), and the error obtained for these two values is 2.88%, which showed a very good agreement.

Enhancing the Stability of Foam by the Use of Nanoparticles

Foam generation is one of the most promising techniques to overcome gas mobility challenges and improve the sweep efficiency of reservoir fluids. The synergistic effect of surfactant and nanoparticles can help produce a stronger and more stable foam in reservoir porous media. The objective of this work is to assess the ability of anionic surfactant and a mixture of the surfactant and nanoparticles to produce foam for gas mobility control and the enhancement of oil recovery. Static, dynamic, and core flood tests were conducted to evaluate foam strength. Static foam tests in the presence of crude oil showed a clear trend on foam behavior when solid nanoparticles were added to surfactant. As the concentration of nanoparticles increases, the foam half-life increases, too. Foamability tests in Bentheimer sandstone showed better foam generation and stabilization when nanoparticles were used. The addition of nanoaprticles to surfactant solutions resulted in higher pressure drop and, therefore, higher reduction o...

A fully coupled numerical modeling to investigate the role of rock thermo-mechanical properties on reservoir uplifting in steam assisted gravity drainage

One of the crucial consequences of steam assisted gravity drainage (SAGD) process is abnormal reservoir uplifting under thermal steam injection, which can significantly influence the reservoir rock deformation, specifically thin bed reservoirs and causes intensive failures and fractures into the cap rock formations. A thorough understanding of the influences of rock thermo-mechanical properties on reservoir uplifting plays an important role in preventing those aforementioned failures within design and optimization process in SAGD. In addition, coupling of reservoir porous medium and flowing of specific fluid with temperature as an additional degree of freedom with initial pore pressure and in-situ stress condition, are also very challenging parts of geomechanical coupled simulation which would be clearly explained. Thus, a fully coupled thermo-poro-elastic geomechanical model with finite element codes was performed in ABAQUS to investigate the role of rock thermo-mechanical parameters on reservoir vertical uplift during steam injection. It is clearly observed that, any increase in rock thermo-mechanical properties specifically rock’s thermal properties such as specific heat, thermal expansion, and formation’s thermal conductivity, have significant influences on reservoir uplift. So by coupling the temperature as an additional degree of freedom with the coupled pore-fluid stress and diffusion finite element model of SAGD process, the more realistic simulation will be conducted; hence, the errors related to not having heat as an additional degree of freedom will be diminished. In addition, Young’s modulus and specific heat are the rock thermo-mechanical parameters which have the maximum and minimum effects on the reservoir uplift, respectively.

STUDY ON STOCHASTIC FLOW IN LOW PERMEABILITY SANDSTONE OIL RESERVOIR

Reservoir porous medium is random, in terms of oil and gas for low permeability reservoirs. Consider the random nature of the reservoir will enable to improve the accuracy of numerical reservoir simulation. Based on extensive research, for the stochastic nature of the reservoir from the two aspects of physical simulation, numerical simulation, the relevant international studies were reviewed. The research trends of stochastic flow in low permeability oil reservoir were pointed out at last.

Propagation of Interfacially Active Carbon Nanohybrids in Porous Media

Interfacially active carbon nanotube hybrids (nanohybrids) exhibit promising properties for potential applications in reservoir systems. They could be used as modifiers of transport properties as well as nanoscale vehicles for catalyst and contrast agents. In situ catalysis might be used to modify interfacial tension and wettability of the rock wall. The main requirements for any of these applications are the ability to form stable dispersions and to effectively propagate through the reservoir porous medium under the temperature and salinity conditions that are typical in commercial operations. In this work, suspensions of purified multi-walled carbon nanotubes (P-MWNTs) in deionized water and high-salinity brine have been prepared using two commercially available polymers, polyvinyl pyrrolidone (PVP) and hydroxyethyl cellulose (HEC-10). Stable dispersions were put in contact with crushed Berea sandstone, quantifying the amount of nanotubes lost from suspension to estimate the adsorption of these nanotube...

The Study of Coupled Transfer of Heat, Moisture and Air in Reservoir Porous Media

This paper studied on heat and mass transfer mechanism of steam in reservoir porous media, built coupled mathematical models for heat and mass transfer in reservoir porous media. “Black box model” and “white box model” are first proposed in heat and mass process analysis of reservoir porous media. Temperature field has been simulated by CMG-STARS software. Our work will give theoretical basis and technical support for enhanced oil recovery technology.

The Analysis Model of Coupling Heat Flux in Heavy Oil Reservoir and its Application

There are heat-fluid-solid multi-field coupling in the thermal recovery reservoir. At present, the researches on oil reservoir porous media coupling are mostly on fluid-solid. According to the oil reservoir characteristics, this paper puts forward the “white box” analysis model on the heat and mass transfer processes in thermal recovery reservoir. On this basis, the analysis and stimulation of the various porosity effects on heat and mass transfer processes use CMG software. This result can provide theoretical basis for enhancing oil/gas recovery.

Adsorption Studies in Athabasca Core Sample: Virgin and Mild Thermal Cracked Residua

Reservoir upgrading of bitumen and heavy oils may involve the use of moderate to high temperatures (200–350 °C). In the absence of an efficient catalyst that could help split or transfer hydrogen to cracked heavy molecules, these would deteriorate to form denser asphaltenes with high aromaticity typical from thermal cracking. The tendency of these molecules to flocculate/precipitate inside the porous media and eventually impair oil production needs to be investigated. Perhaps in an opposite direction, the reservoir porous media may also offer a way of selectively retaining the incipiently deteriorated asphaltenes, thus avoiding early media plugging. Attending to these issues, adsorption studies of virgin (VR) and visbroken (VB) vacuum residue with a conversion of 28.5 wt % (28.5% VB) from Athabasca bitumen were carried out using Athabasca reservoir core minerals (well 14-27-88 11W4) spanning depths from 264 to 308 m. Adsorption experiments were performed in toluene solutions of the adsorbates, monitored v...

A Parametric Analysis of a Reservoir-Extended Porous Slider Bearing with Self-Circulation and Cavitation Effects

This work considers a porous slider bearing fed by an external contiguous reservoir. The bearing system consists of a lubricating film, a porous medium, and the external reservoir, which runs along the entire length of the porous medium. The Darcy model is used for modeling the flow inside the porous medium. The translational velocity of the reservoir wall and porous medium, together with the convergent-divergent slider lubricating film profile, acts to pump the fluid out of and into the lubricating film and the reservoir, respectively. Cavitation effects are modeled realistically using the switch function and modified equations of the Elrod and Vijayaraghavan models. The model presented herein shows the bearing capable of supporting a load, while simultaneously the convergent/divergent film action (equivalent to an eccentric shaft in a journal bearing) helps by pumping the fluid back and forth between the lubricating region and the reservoir without the use of any external means. Thus, the concept of a bearing using its own action for the circulation of the lubricating fluid for autonomous operation has been proven to be feasible.

Main Mechanism for Stability of THAI-Toe-to-Heel Air Injection

Abstract THAI, or "Toe-to-Heel Air Injection," is an integrated horizontal well process for in situ recovery and upgrading of heavy oil and tar sands bitumen. During extensive studies of the process at the University of Bath, involving more than 50 three-dimensional combustion cell tests, the process has repeatedly demonstrated robust and stable operation. However, the answer to the question: "Why does oxygen breakthrough into the toe of the horizontal well not occur," has not been fully developed. This is now all the more important since the THAI process is about to be tested in the field. In order to maintain stable propagation of the combustion front, sufficient fuel needs to be available ahead of the front. This is fundamental to the in situ combustion (ISC) process, whether in its conventional form, or THAI. When the combustion front approaches close enough to the horizontal producer well, heavy residue can drain into the well. This residue, or coke material, provides a gas seal, preventing the injected air from channeling through to the well. This paper presents post-mortem results of two THAI experiments, in which the horizontal well was cut-open to reveal the extent of heavy oil residue/coke deposition. The visual evidence is supported also by a numerical simulation of the experiment, showing the distribution of coke and oxygen through the oil layer. Introduction In situ combustion (ISC) has, theoretically, always held the promise of high potential rewards for heavy oil recovery. This is basically because, if a stable combustion front at high temperature (500 - 600 ° C) can be propagated through the oil-bearing formation, virtually all of the heavy oil it contacts is displaced. The fundamental principle of ISC, as applied to heavy oil recovery, is well known, as described by Burger et al.(1). ISC is achieved by burning a small fraction of the oil in the reservoir, which releases sufficient reaction energy to create a large increase in reservoir temperature in the combustion front zone, thereby mobilizing and displacing the oil ahead of it. The chemical reactions between oxygen and crude oil are extremely complex, principally because there are a large number of components which can undergo thermal cracking reactions. The overall complexity of the ISC process is increased because of the interaction between chemical reaction and transport processes in reservoir porous media. Although considerable understanding of the ISC process has been gained in recent years, and new guidelines and strategies for field operations have been presented(2, 3), there are still a number of concerns about the process which need to be resolved if its full operational potential is to be realized. These include:Gravity segregation, or gas overriding;Oil banking in the cold region ahead of the combustion front; and,Permeability heterogeneity. Gas overriding, due to the buoyancy effect between the combustion gases and reservoir liquids, exacerbated by permeability contrasts in the reservoir porous media, can cause severe channeling of gas through to the producer well.

The Mechanism of Reduction of Water Mobility by Polymers in Glass Capillary Arrays

Abstract Flow experiments with polymer solutions in arrays of glass capillaries with diameters of 2,5, and 25 microns have produced physical evidence of the mechanism by which polymers and polymeric gels reduce water mobility in porous media. The results indicate that polyacrylamides and polysaccharides reduce the permeability of straight glass polysaccharides reduce the permeability of straight glass capillary arrays by forming an adsorbed layer of polymer on the capillary wall that reduces the polymer on the capillary wall that reduces the effective size of the capillary. The effective thickness of the polymer layer on the glass surface was about 0.2 to 0.3 micron. The thickness was slightly less than the molecular diameter of 0.3 to 0.8 micron of the molecules in 1,200-ppm brine and was found to be independent to pore size for pores with diameters larger than three to four times the average molecular diameter of the polymer in solution. it was concluded that the reduction of water mobility by polymers in a porous medium, over and above the effect of increasing the viscosity, results form an adsorbed layer of polymer on the pore walls, and from mechanical entrapment in pore constrictions and small pores. It was shown that a previously reported sequential polyacrylamide-cation treatment method could polyacrylamide-cation treatment method could be repeated to achieve very large decreases in mobility to brine. The cross-linked layer established during the first sequence was three to five times more effective in reducing the pore diameter than the initial polyacrylamide layer. For example, the average thickness of the cross-linked layer formed with each sequence of particular polyacrylamide (19-percent hydrolyzed) was 1.5 microns, compared with 0.3 microns for the initial polyacrylamide layer. No mixing of polacrylamide and crosslinking solutions was required for this sequential system to be effective, since extensive flushing with water between the solutions in the sequence did not alter the results. Hence, it should not be necessary to propagate highly viscous solutions or gels through a reservoir to develop large residual resistance factors in depth with the sequential system. Introduction Investigators of polymer effects on water mobility in porous media normally have used outcrop sandstones, reservoir cores, glass bead packs, and sand packs, all of which have complex flow paths and surface characteristics that vary somewhat from sample to sample. As a result, it has been difficult to produce direct physical evidence of the mechanism by which polymers and polymeric gels reduce the permeability of these porous media, and researchers have postulated various mechanisms based on the combined interaction of polymer and geometry to explain the observed effects. We used fused-glass capillary arrays to investigate the mechanism of permeability reduction. The glass] arrays provided a means for determining effects of polymer in geometrically simple pores of the same polymer in geometrically simple pores of the same size as those in reservoir porous media; since they could be used repeatedly, the same geometry and surfaces were available for each test. The main purpose of this research was to provide direct physical evidence of how and where provide direct physical evidence of how and where polymers interact with surfaces of porous media. polymers interact with surfaces of porous media. We were primarily concerned with effects caused by polymer adsorption and retention remaining after polymer solutions had been displaced from porous polymer solutions had been displaced from porous media by water. Other aspects of polymer flooding, such as non-Newtonian viscosity effects, inaccessible pore volume, behavior attributed to pore volume, behavior attributed to viscoelastic properties of polymer solutions, salt concentration, pH, polymer molecular weight, and degree of hydrolysis, have been investigated previously in more conventional porous media. previously in more conventional porous media. Additional evidence is provided on how the combination polyacrylamide-cation treatment method,]composed of sequential injection of solutions of polyacrylamide and aluminum citrate, produces large polyacrylamide and aluminum citrate, produces large residual resistance factors to water and brine. This evidence provides a basis for tailoring in-situ polymer networks to the needs of a particular polymer networks to the needs of a particular reservoir SPEJ p. 130