Fluid Saturation Distribution Research Articles

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.

ON INFLUENCE OF PHYSICAL AND CHEMICAL MODIFICATION OF WETTABILITY OF FILTRATION SURFACE ON INTERCHANGEABILITY OF IMMISCIBLE FLUIDS IN RESERVOIR FORMATIONS

The article presents and discusses the results of experimental studies of the processes of mutual substitution (displacement) of immiscible fluids, proceeding by the mechanism of impregnation and drainage in layered-heterogeneous reservoirs with hydrodynamically connected and separated interlayers.
 Physical modeling of filtration processes, taking into account the similarity criteria, made it possible to establish that during the mutual substitution of immiscible fluids at the phase boundary and lithological differences, nonequilibrium capillary phenomena develop, which, through the action of capillary forces, significantly affect fluid filtration and saturation distribution in an inhomogeneous porous medium. In order to eliminate the influence of the viscous instability factor on the motion of the displacement front, the processes of displacement of a less viscous fluid by a more viscous one were studied.
 It has been established that non-equilibrium capillary phenomena manifest themselves most intensively in reservoirs with a heterophilic surface, where capillary forces can initiate or block fluid flows between differently permeable interlayers. It has been experimentally shown that in layered-heterogeneous reservoirs with a heterophilic filtration surface in the interlayers, capillary phenomena largely determine the nature of the movement of the fluid displacement front (from the almost complete suppression of the “run-up” of the displacement fronts in the interlayers to the formation of an advanced front in the low-permeability interlayer). In order to exclude the influence of errors of a systematic or random nature on the results of the experiments, their reproducibility and the significance of differences were assessed using the statistical criteria of Student and Cochran, which showed the reliability of the above conclusions.
 The results obtained indicate the dominant effect of crossflows between interlayers on the formation of the displacement front of immiscible fluids in layered-heterogeneous reservoirs, especially with a heterophilic wettability characteristic, as well as the possibility of controlling this process by means of physicochemical modification of the wettability conditions of the filtration surface, for example, using surface active substances (surfactants) of various nature and structure.

Microscopic Production Characteristics of Pore Crude Oil and Influencing Factors during Enhanced Oil Recovery by Air Injection in Shale Oil Reservoirs.

High-pressure air injection (HPAI) is one of the effective methods to improve shale oil recovery after the primary depletion process. However, the seepage mechanisms and microscopic production characteristics between air and crude oil are complicated in porous media during the air flooding process. In this paper, an online nuclear magnetic resonance (NMR) dynamic physical simulation method for enhanced oil recovery (EOR) by air injection in shale oil was established by combining high-temperature and high-pressure physical simulation systems with NMR. The microscopic production characteristics of air flooding were investigated by quantifying fluid saturation, recovery, and residual oil distribution in different sizes of pores, and the air displacement mechanism of shale oil was discussed. On this basis, the effects of air oxygen concentration, permeability, injection pressure, and fracture on recovery were studied, and the migration mode of crude oil in fractures was explored. The results show that the shale oil is mainly found in <0.1 μm (small pores), followed by 0.1-1 μm (medium pores), and 1-10 μm (macropores); thus, it is critical to enhancing oil recovery in pores less than 0.1 and 0.1-1 μm. The low-temperature oxidation (LTO) reaction can occur by injecting air into depleted shale reservoirs, which has a certain effect on oil expansion, viscosity reduction, and thermal mixing phases, thereby greatly improving shale oil recovery. There is a positive relationship between air oxygen concentration and oil recovery; the recoveries of small pores and macropores can increase by 3.53 and 4.28%, respectively, and they contribute 45.87-53.68% of the produced oil. High permeability means good pore-throat connectivity and greater oil recovery, and the production degree of crude oil in three types of pores can be increased by 10.36-24.69%. Appropriate injection pressure is beneficial to increasing the oil-gas contact time and delaying gas breakthrough, but high injection pressure will result in early gas channeling, which causes the crude oil in small pores to be difficult to produce. Notably, the matrix can supply oil to fractures due to the mass exchange between matrix fractures and the increase of the oil drainage area, and the recoveries of medium pores and macropores in fractured cores increased by 9.01 and 18.39%, respectively; fractures can act as bridges for matrix crude oil migration, which means that proper fracturing before gas injection can make the EOR better. This study provides a new idea and a theoretical basis for improving shale oil recovery and clarifies the microscopic production characteristics of shale reservoirs.

Dynamic Monitoring and Enhanced Oil Recovery Evaluation of the Water Flooding Process of Liquid Nanofluids in Tight Reservoirs

The CT scanning technology can observe fluid saturation distribution in the rock at different times during water flooding in tight reservoirs. However, this technology has not been used to study the water flooding characteristics in changing the wettability of liquid nanofluids. First, this study evaluated the basic properties of a nonionic liquid nanofluid, including the contact angle (CA), interfacial tension (IFT), and aqueous stability tests. Then, the water flooding process in tight rocks is dynamically monitored by the CT scanning technology. The water flooding characteristics of liquid nanofluids changing reservoir wettability are analyzed by measuring the rock’s water phase saturation distribution at different times. Finally, the spontaneous imbibition experiment evaluated the enhanced oil recovery of liquid nanofluids. The results show that the particle size of the liquid nanofluid is at the nanometer level (7.5 nm) and can change the wettability of oil-wet to water-wet. Liquid nanofluid has low interfacial tension and can exist stably in brine with a high salinity (20,000–50,000 ppm). In water flooding, the front profile of water phase saturation changes obviously, and it is driven forward with a similar “piston” type. Compared with the brine water, the water invasion front gradually becomes uniform, which is strong evidence that a liquid nanofluid can change the wettability of rocks. Besides, the invasion depth of the fracturing fluid with liquid nanofluids is deeper than that of brine water and displaces more oil. Finally, the spontaneous imbibition test shows that the recovery factor of high-concentration (1 wt %) liquid nanofluids increases by 28.9% compared with that of brine water. This paper provides theoretical support for applying liquid nanofluids in tight reservoirs.

Digital rock workflow to calculate wettability distribution in a reservoir rock

Wettability has a strong influence on multi-phase flow behavior through reservoir rock. Reservoir rocks tend to have spatially varying wettability. Prior to contact with oil, rocks are almost always naturally water-wet. As oil invades the pore-space over geologic time, the initial water-wet state may be altered in certain locations due to adhesion of substances within the oil phase to the grains. Mechanisms of wettability alteration depend on various properties such as pressure, temperature, mineral chemistry, surface roughness and fluid composition. In this study wettability alteration in a reservoir rock is studied through direct simulation using multiphase Lattice Boltzmann method where the computational grid is constructed from segmented micro-CT images of the rock sample. The pore-grain interface is defined by a triangulated surface mesh for accurate fluxes near boundary and local curvature calculation. A capillary pressure drainage simulation is conducted in a water-wet Berea sandstone sample initially filled with water. When oil invades the pore space as the capillary pressure is increased, a fraction of the pore-grain surface is altered towards an oil-wet condition, as determined by a novel wettability alteration process. This process calculates local curvature at every surface element of the rock, obtains local capillary pressure from the simulation and assumes a disjoining pressure to determine water-film breakage at every location of the pore-grain surface. As a result, a spatially varying rock wettability is created. Using this new wettability distribution, the simulation is continued to allow the fluid phases to redistribute accordingly. The process is iteratively carried out until both fluid saturation and wettability distribution converged at a given applied capillary pressure. Afterwards, the pressure is ramped up to the next stage and the process is repeated again. It has been found that the wettability alteration is a slow dynamic process where the non-wetting phase can gradually invade finer pore space as the surrounding grain wettability is altered. In this study, it has also been found that wettability alteration of the reservoir rock produces lower connate water saturation during primary drainage compared to the simulation results without alteration. The resulting spatially varying wettability distribution from primary drainage is used for a subsequent water flooding simulation to calculate water-oil relative permeability curves. The methodology presented in this work can be leveraged to better understand and predict an improved mixed wetting conditions found in the reservoir rocks which is needed for more accurate displacement tests such as relative permeability simulations.

Experimental investigation of flow diversion and dynamic retention during polymer flooding in high salinity fractured carbonates using CT imaging

The successful record of polymer flooding in improving oil production from sandstone reservoirs has encouraged the expansion of its application in carbonate reservoirs. However, the existence of natural fractures, high permeability contrast, and harsh conditions of carbonate reservoirs provide significant challenges for achieving an optimized performance of polymer flooding. It is crucial to establish an appropriate polymer that can offer an optimum flow behavior for in-depth mobility control under reservoir conditions. This study presents in-situ saturation monitoring to evaluate the mobility control effect and identify the flow diversion during polymer injection in high salinity fractured and unfractured carbonate rocks. A synthetic polymer, acrylamido tertio-butyl sulfonate (ATBS) was used and prepared in 200,000 ppm brine salinity. The flow behavior of polymer solution was investigated in bulk rheology tests followed by single-phase core flooding experiments. The flooding apparatus was coupled with a CT scanner to produce 3D images for determining the fluid saturation distribution and inaccessible pore volume (IPV) in real time. Accordingly, flow diversion across fracture-matrix system during polymer injection and the dynamic retention after brine post-flush were identified. The flow experiments showed a shear thickening behavior for the injected polymer solution in the fractured core and no degradation was noticed under in-situ conditions. Based on the fluid saturation profiles, the established flow resistance in the fracture region was prominent to induce flow diversion from the fracture into the matrix. Compared to the case in unfractured rock, the IPV in the fractured rock was approximately 2.5 times higher which was at 53% after 1 PV injection. An additional 23% of IPV was subsequently penetrated upon a continuous polymer injection for 5 PV. In post-flush stage, the fractured core retained about 87% of the injected polymer solution at 1 PV which was then minimized to 7% after 10 PV injection. The entrapped polymer in the fractured core was potentially induced by hydrodynamic retention. This work ascertained the potential of polymer flooding to effectively sweep the fractured carbonates at high salinity environment under certain circumstances for a better conformance.

Pore-scale modeling of multiphase flow in porous media using a conditional generative adversarial network (cGAN)

Multiphase flow in porous media is involved in various natural and industrial applications, including water infiltration into soils, carbon geosequestration, and underground hydrogen storage. Understanding the invasion morphology at the pore scale is critical for better prediction of flow properties at the continuum scale in partially saturated permeable media. The deep learning method, as a promising technique to estimate the flow transport processes in porous media, has gained significant attention. However, existing works have mainly focused on single-phase flow, whereas the capability of data-driven techniques has yet to be applied to the pore-scale modeling of fluid–fluid displacement in porous media. Here, the conditional generative adversarial network is applied for pore-scale modeling of multiphase flow in two-dimensional porous media. The network is trained based on a data set of porous media generated using a particle-deposition method, with the corresponding invasion morphologies after the displacement processes calculated using a recently developed interface tracking algorithm. The results demonstrate the capability of data-driven techniques in predicting both fluid saturation and spatial distribution. It is also shown that the method can be generalized to estimate fluid distribution under different wetting conditions and particle shapes. This work represents the first effort at the application of the deep learning method for pore-scale modeling of immiscible fluid displacement and highlights the strength of data-driven techniques for surrogate modeling of multiphase flow in porous media.

Dual-energy CT scan protocol optimization to monitor transient fluid saturation distributions during three-phase flow in sand columns

Surfactant foam injection is a promising in situ remediation technique for aquifers impacted by Non-Aqueous Phase Liquids (NAPL). Though the viscous properties of foam can promote immiscible displacement, pore plugging by foam is a concern in an environmental remediation (ER) context, as maintaining flow conditions may require the application of pressures that exceed soil matrix failure thresholds. Optimization of the technology for ER may be furthered by gaining a better understanding of the relationship between foam morphology and NAPL desaturation. This relationship is poorly understood, partly because the interactions between organic phases and foam occurring at specific positions within the flow field at any given time are difficult to assess quantitatively. A Dual-energy X-ray Computed Tomography (CT) technique was developed to enable the measurement of sand column characteristics, as well as transient fluid saturation profiles within the porous medium during foam injection. The available settings of a medical CT scanner were systematically explored in order to identify the acquisition and reconstruction parameters best suited to image the fluids of interest: 0.4 mm slice thickness, a medium kernel (U40u), peak tube voltages of 140 kVp and 80 kVp, and the addition of a doping agent to the NAPL at a concentration of 20 wt%. Using datasets produced by imaging sand columns at various stages of foam injection experiments, an algorithm was developed in order to extract saturation profiles from CT images. The algorithm included multiple scan averaging to reduce image noise, image registration, and specific matrix operations required for calculating fluid saturation values in two- and three-phase systems. The accuracies of the CT-extracted porosity and fluid saturation data were compared to, and found to be in good agreement with, experimentally determined average porosity and saturation values. The scan parameter optimization method developed here can be applied to future studies involving any combination of site-specific natural materials.

Effect of pore-throat structure on gas-water seepage behaviour in a tight sandstone gas reservoir

In this study, effect of pore-throat structure on gas–water seepage behaviour in a tight gas sandstone formation has been experimentally examined. More specifically, pressure-controlled mercury injection tests were performed to measure capillary pressure and identify the characteristics of a pore-throat structure such as its connectivity and size distributions. According to the pore-throat structure together with its median throat radius, pore-throat skewness, relative sorting coefficient, and cutoff throat volume ratio, the pore-throat structure was then classified into three types, while gas permeabilities under different conditions are corrected with consideration of the slippage effect and different pore-throat structures. Subsequently, seepage characteristics, including distribution of movable fluid saturation, relative permeability, and water locking degree, were quantified using displacement experiments integrated with the nuclear magnetic resonance (NMR) technique for the three classified types of pore-throat structure, respectively. With the deteriorated pore-throat structure, the throat size distribution curves are found to shift to the left, porosity gradually decreases, and the irreducible water saturation gradually increases. Both water saturation at the isotonic point and irreducible water saturation increase, and gas phase relative permeability at the irreducible water saturation together with water relative permeability within the saturation range of simultaneous gas–water flow decreases consecutively, indicating the seepage capacity of gas and water is weakened. With the deteriorated pore-throat structure, the water locking becomes more serious and its corresponding water saturation together with the damage coefficient of gas permeability is larger, and the influence of water on gas phase flow is more significant. The pore-throat structure, especially its connectivity, is found to be the main factor dominating the movable fluid saturation and two-phase seepage characteristics in a tight sandstone gas reservoir. This study allows us to better understand how the pore-throat structure affects the gas–water seepage behaviour in a tight gas reservoir, provided that its characterization has been quantitatively conducted and the seepage patterns are identified and classified within a consistent and unified framework. These findings further provides solid fundamentals for efficient and effective exploitation of tight gas reservoirs.

Advances and challenges in hydraulic fracturing of tight reservoirs: A critical review

The hydraulic fracturing technology has been widely utilized to extract tight resources. Hydraulic fracturing involves rock failures, complex fracture generation, proppant transport and fracture closure. All these behaviors affect the productivity of fractured wells. In this work, the advances and challenges in hydraulic fracturing development of tight reservoirs are summarized from following aspects: the hydraulic fracture propagation, the proppant transport and distribution in hydraulic fractures, the calculation of hydraulic fracture conductivity, and productivity and/or pressure analysis model of multi-stages fractured horizontal wells. Current fracture propagation simulation methods generate only limited propagation paths and cannot truly reflect the complexity of the propagation. The current proppant migration and distribution research is mainly focused on indoor experimental studies of proppant migration in a single fracture or branched fracture, and simulation studies on proppant migration and distribution in a small-scale single slab fracture. Whereas fractures formed after hydraulic fracturing in tight reservoirs are generally complicated. There is a lack of models for calculating complex fracture conductivity that take into consideration the effect of proppant placement and proppant distribution in fractures, fracture surface roughness and dissolution, diffusion, deposition, elastic embedding, and creep caused by stress. The productivity models of fractured horizontal wells are mostly conducted based on the original reservoir fluid saturation and pressure distribution. Most of the studies are focused only on one aspect of the fracturing process. Predications of well performance after fracturing based on these studies are often inconsistent with actual field data. The paper also discusses the future research directions of fracturing in tight reservoirs and the results may be used to promote the development of tight reservoirs.

Pore scale modeling on dissociation and transportation of methane hydrate in porous sediments

Fundamental study on the pore scale dissociation and transportation mechanism of methane hydrate in porous sediments contributes to understanding the heat and mass transfer in the multiple physicochemical and thermal processes. This paper proposes a novel enthalpy-porosity technique coupling with volume of fraction (VOF) method for modeling the phase-change process of the hydrate dissociation and the multi-phase flow. The mathematical models are programed by C language and used as the subroutine for the commercial FLUENT software. The proposed theoretical model is validated by comparison with the experiment and numerical modeling in literature. The distribution of fluid saturation, velocity and temperature in the MH dissociation are presented, analyzed and discussed comparatively. As the first effort in literature, the proposed model can properly simulate the effects of the phase change on the pore structure evolution, multiphase flow, heat and mass transfer and kinetic reaction process in porous media in real-time. Both the normalized permeability of water (KNw) and the normalized absolute permeability (KN) of the porous media with different hydrate saturation are acquired and analyzed comparatively with the results in the previous studies. This study provides a new insight into pore scale modeling on the multiphase flow with phase change.

Electrical imaging of hydraulic fracturing fluid using steel-cased wells and a deep-learning method

Steel-cased wells used as long electrodes (LEs) in a surface-electric or electromagnetic survey can enhance anomalous signals from deep hydraulic fracturing zones filled by injected fluid. Although recent research has been published on the algorithms designed for the simulation of the effect of casings, feasibility studies on resolving the small-scale fracturing fluid flow from surface data are lacking. We have carried out a detectability and recoverability study for a top-casing electric source configuration. Applying a fast 3D DC modeling code using the concept of the equivalent resistor network, the detectability study shows that favorable conditions for detecting the fluid flow direction include multiple electrically coupled wells and different electric conductivities above and below the shale layer. The observed behavior is then modeled through a circuit analog. For the purpose of fracturing fluid imaging, the model for recovery is simplified as a distribution of full fluid saturation on a 2D fracture plane. A deep-learning (DL) framework is adopted to solve the imaging problem, which is difficult for conventional regularized inversions. Our DL implementation uses a supervised deep fully convolutional network to learn the relationship between data patterns on the surface and the model of fracturing fluid distribution, encoded in a large number of synthetic data-model pairs. Once trained, the neural network can make a real-time and pixel-wise prediction of the fluid distribution. The robustness of our DL approach is tested in the presence of ambient noise and inaccuracies in casing conductivity. A reasonably consistent prediction performance has been observed. Our numerical feasibility study results demonstrate that electric surveys using steel casings as LEs have great potentials in real-time monitoring of fracturing fluid flow.

A general capillary equilibrium model to describe drainage experiments in heterogeneous laboratory rock cores

Macroscopic observations of two-phase flow in porous rocks are largely affected by the heterogeneity in continuum properties at length scales smaller than a typical laboratory sample. The ability to discriminate among the rock properties at the origin of the heterogeneity is key to the development of numerical models to be used for prediction. Here, we present a capillary equilibrium model that represents spatial heterogeneity in dual-porosity porous media in terms of the capillary entry pressure, 1/α, and the irreducible wetting phase saturation, Sir. Both parameters are used to scale local capillary pressure curves by using three-dimensional imagery acquired during multi-rate gas/liquid drainage displacements. We verify the proposed approach by considering the case study of a dual-porosity limestone core and use the spatial variation in Sir as proxy for microporosity heterogeneity. The latter places potentially next-to-leading order controls on the observed fluid saturation distribution, which is strongly correlated to the distribution of 1/α. While microporosity is by and large uniform at the observation scale on the order of 0.1 cm3, the spatial correlation of 1/α is on the order of 1 cm and is therefore not statistically represented in the volume of typical laboratory core samples.

Pore structure and fluid saturation of near-oil source low-permeability turbidite sandstone of the Dongying Sag in the Bohai Bay Basin, east China

Pore structure and oil saturation are important parameters in petroleum exploration and development, and the relationship between them is closer in near-oil source reservoirs (with a short-distance migration of oil and gas) than in other reservoirs. Using epoxy-impregnated thin sections, scanning electron microscopy (SEM), conventional core analyses of porosity and permeability, mercury intrusion porosimetry, and well logging, the characteristics of the petrology, physical properties, and pore structure we studied, as well as the relationship between pore structure and fluid saturation (maximum mercury intrusion saturation Smax and oil saturation So) of the near-oil source low-permeability turbidite sandstone reservoirs in the Es3 member of the Dongying Sag, Bohai Bay Basin, eastern China. The results indicate that the turbidite sandstone reservoirs are mainly composed of fine sandstone and siltstone, with porosities and permeabilities ranging from 5 to 25% and 0.1 to 40 mD, respectively, and can be classified as medium to low porosity and extra-low to ultra-low permeability reservoirs. The pore types of high-quality reservoirs are mainly dominated by intergranular pores, both primary and dissolved, probably due to the influence of the acidic fluids generated from the cracking of organic matter. The pore structure is complex with respect to the pore-throat size distribution, and the overall pore-throat radius is small. Several pore structure parameters together affect the fluid saturation distribution, among which the medium pore-throat radius (R50) and medium saturation pressure (P50) are especially correlated with oil saturation. Different pore structure types have different characteristics of fluid saturation distribution, and the oil-bearing grade and oil saturation of the reservoirs above the oil-water contact are typically positively correlated with pore structure. This study will help to classify the pore structure in the wellbore profile and improve the accuracy of the oil saturation calculation by well logging.

Evolution of Production and Transport Characteristics of Steeply-Dipping Ultra-Thick Coalbed Methane Reservoirs

The large spatial variability of in-situ stress and initial reservoir pressure in steeply-dipping ultra-thick coalbed methane (UTCBM) reservoirs exert strong control on the initial distribution of stress-sensitive permeability. This results in significant differences in the propagation of reservoir depressurization, gas production characteristics, distribution of fluid saturation, and evolution of permeability relative to flat-lying and thin counterpart coalbed methane (CBM) reservoirs. We contrast these responses using the Fukang mining area of the Junggar Basin, Xinjiang, China, as a type-example using coupled hydro-mechanical modeling. Production response indicates: (1) Dual peaks in CBM production rate, due to the asynchronous changes in the gas production rate in each the upper and lower sections of the reservoir; (2) higher depressurization and water saturation levels in the lower section of the reservoir relative to the upper at any given distance from the production well that ameliorate with time to be similar to those of standard horizontal reservoirs; (3) the heterogeneity in effective stress is further amplified by the asymmetry of the initial pressure drawdown distribution of the reservoir to exert extreme control on the down-dip evolution of absolute permeability—with implications for production. Field drainage data and simulation results obtained in this study more accurately reflect the drainage characteristics of the steeply-dipping UTCBM reservoirs. For ultra-thick low-rank coal seams, permeability anisotropy plays an important role in determining the utility of horizontal wells and hydraulic fracturing to maximize rates and yields CBM production, and requiring further study.

Insights into the Effects of Pore Size Distribution on the Flowing Behavior of Carbonate Rocks: Linking a Nano-Based Enhanced Oil Recovery Method to Rock Typing.

As a fixed reservoir rock property, pore throat size distribution (PSD) is known to affect the distribution of reservoir fluid saturation strongly. This study aims to investigate the relations between the PSD and the oil–water relative permeabilities of reservoir rock with a focus on the efficiency of surfactant–nanofluid flooding as an enhanced oil recovery (EOR) technique. For this purpose, mercury injection capillary pressure (MICP) tests were conducted on two core plugs with similar rock types (in respect to their flow zone index (FZI) values), which were selected among more than 20 core plugs, to examine the effectiveness of a surfactant–nanoparticle EOR method for reducing the amount of oil left behind after secondary core flooding experiments. Thus, interfacial tension (IFT) and contact angle measurements were carried out to determine the optimum concentrations of an anionic surfactant and silica nanoparticles (NPs) for core flooding experiments. Results of relative permeability tests showed that the PSDs could significantly affect the endpoints of the relative permeability curves, and a large amount of unswept oil could be recovered by flooding a mixture of the alpha olefin sulfonate (AOS) surfactant + silica NPs as an EOR solution. Results of core flooding tests indicated that the injection of AOS + NPs solution in tertiary mode could increase the post-water flooding oil recovery by up to 2.5% and 8.6% for the carbonate core plugs with homogeneous and heterogeneous PSDs, respectively.

Effects of capillary pressures on two-phase flow of immiscible carbon dioxide enhanced oil recovery in fractured media

CO2-EOR in a geological formation not only increases oil production but also ensures geological sequestration of CO2. The capillary pressure is an essential factor during the process of immiscible CO2-EOR in fractured media. Two classical capillary pressure models are adopted to investigate the effects systematically based on a unified pipe-network method. The identical capillary pressures in fractures and the rock matrixes have little effect on the fluid flow and saturation distribution of CO2. This implies that the capillary pressure can be neglected in this condition. The effect cannot be ignored when different capillary pressures are assigned for fractures and rock matrixes. The saturation of CO2 reaches its highest value at the fracture outlet tip if the capillary pressure in a fracture is smaller than that in the rock matrix. The phenomenon of saturation concentration of CO2 at the fracture tip is caused by the capillary pressure difference. For non-connected fractures, the saturation concentration causes CO2 to enter the adjacent fractures more easily. Thus, the capillary pressure difference enlarges the effect of fractures on the CO2 flow, and shorten the breakthrough time of CO2. Hence, both the storage amount of CO2 and the production of oil in geological media are reduced.

Empirical modeling of the saturated shear modulus in oil sands

Seismic reservoir characterization and monitoring require the knowledge of seismic wave velocities and their dependencies on reservoir properties and production-induced changes. In heavy-oil saturated rocks at cold temperatures, due to the nonzero shear rigidity of the fluid, the saturated shear modulus is higher than the dry shear modulus and, consequently, the observed P- and S-wave velocities are higher than Gassmann’s predicted velocities. Appropriate modeling of the saturated shear modulus can greatly enhance the accuracy of quantitative interpretation of spatial fluid saturation and temperature distribution within a reservoir undergoing thermal production. Using a well-log data set of an Athabasca heavy-oil play and measured oil viscosities from core samples, we estimate fluid viscosity, shear modulus, and the American Petroleum Institute (API) gravity logs by training a neural network (NNT) with available well logs. We also estimate the dry shear modulus of heavy-oil saturated rocks using an NNT approach after modeling the pressure variations within the reservoir. Our empirical model uses the apparent shear modulus of the oil, its saturation, porosity, and dry shear modulus to estimate the saturated shear modulus of the rock. We calibrate the model to ultrasonic lab measurements. Available literature data support the validity of the model and show the improved performance compared to the Ciz and Shapiro model. The range of applicability of the model is defined mathematically, and the behavior of the model with respect to the input parameters is examined through sensitivity analyses.

An Injectivity Evaluation Model of Polymer Flooding in Offshore Multilayer Reservoir

Good polymer flood performance evaluation requires an understanding of polymer injectivity. Offshore reservoirs are characterized by unfavorable water–oil mobility ratios, strong heterogeneity, and multilayer production, which collectively contribute to unique challenges. Accordingly, this article presents a semi-analytical model for the evaluation of commingled and zonal injectivity in the entire development phase, which consists of primary water flooding, secondary polymer flooding, and subsequent water flooding. First, we define four flow regions with unique saturation profiles in order to accurately describe the fluid dynamic characteristics between the injector and the producer. Second, the frontal advance equation of polymer flooding is built up based on the theory of polymer–oil fractional flow. The fluid saturation distribution and the injection–production pressure difference are determined with the method of equivalent seepage resistance. Then, the zonal flow rate is obtained by considering the interlayer heterogeneity, and the semi-analytical model for calculating polymer injectivity in a multilayer reservoir is established. The laboratory experiment data verify the reliability of the proposed model. The results indicate the following. (1) The commingled injectivity decreases significantly before polymer breakthrough and increases steadily after polymer breakthrough. The change law of zonal injectivity is consistent with that of commingled injectivity. Due to the influence of interlayer heterogeneity, the quantitative indexes of the zonal flow rate and injection performance are different. The injectivity of the high-permeability layer is better than that of the low-permeability layer. (2) The higher the injection rate and the lower the polymer concentration, the better the injectivity is before polymer breakthrough. An earlier injection time, lower injection rate, larger polymer injection volume, and lower polymer concentration will improve the injectivity after polymer breakthrough. The polymer breakthrough time is a significant indicator in polymer flooding optimization. This study has provided a quick and reasonable model of injectivity evaluation for offshore multilayer reservoirs.

Meso-to-microscale fracture porosity in tight limestones, results of an integrated field and laboratory study

Abstract The complex fluid saturation distribution and influence of microscale and mesoscale fractures on the fluid accumulation and flow properties of carbonates are still interesting challenges for petroleum geologists. For this reason, in order to know the relative role played by the aforementioned features on the storage and migration properties of tight limestones, the present work focuses on a surface analogue cropping out in southern Italy. By first applying a deterministic Discrete Fracture Network (DFN) modelling to a 1 m3 geocellular volume, an amount of 0.3% of fracture porosity and a fracture connectivity configuration above the percolation threshold are computed. In addition to mesoscale fracture porosity, in order to gather information on matrix porosity and microscale fractures, we investigate the pore type, geometry, and textural anisotropy of selected rock plugs by mean of integrated petrophysical, ultrasonic, and optical microscopy analyses experiments. Results show values of connected porosity ranging between 1% and 6%, presence of vugs localized along pre-existing structural heterogeneities, and the predominance of stiff pores within the carbonate matrix. The rare microfractures are mainly oriented orthogonal to bedding. The estimated crack density (0.19) shows that the contribution of fracture porosity at microscale (ɸ = 0.078%) is very low if compared to that of matrix porosity and also a structural configuration above the percolation. The present study therefore documents that the carbonate matrix forms an isotropic medium, which profoundly affects the storage capability of the study limestones. In fact, the amount of storage provided by carbonate matrix and microscale fractures is greater than that due to mesoscale fractures. Moreover, we document that the matrix contribution on porosity is much more significant than the contribution provided by microfractures. Finally, the present work shows the importance of integrating different methodologies on the assessment of fracture porosity at different scales of observation. In fact, a great benefit for development and production operations can be obtained by performing studies of surface analogs, which allow the detailed investigation of rock masses below seismic resolution.