Fluid Flow In Formations Research Articles

Sensitivity analysis of a dual-continuum model system for integrated CO2 sequestration and geothermal extraction in a fractured reservoir

Depleted hydrocarbon reservoirs are considered as the most feasible option for CO2 geological sequestration and utilization. Most of the hydrocarbon reservoirs are naturally fractured. Simulation of fluid flow and heat transfer in these fractured formations remains a significant challenge in reservoir engineering. In this study, a dual-continuum model is developed to simulate integrated CO2 sequestration and CO2-circulated geothermal extraction in a fractured reservoir block in North Oman. The high-dimensional sensitivity of key parameters controlling CO2-brine flow and heat transfer in this matrix-fracture system is quantitatively evaluated by an efficient surrogate modeling approach. The surrogate models are constructed and validated based on a suite of physics-based model simulations. It is found that fracture permeability dominates the CO2 injectivity, storage, circulation and associated geothermal extraction. Response surface analysis shows that the flow area density between matrix-fracture and matrix block length controls the flux interaction between matrix and fracture formations. In contrast, the fracture aperture shows negligible influence in the dual-continuum modeling system. Particularly, sensitivity varying with locations on the response surface is analyzed for defined performance indicators.

The Early Determination Method of Reservoir Drive of Oil Deposits Based on Jamalbayli Indexes

Summary Historically, the concept of “reservoir drive” aimed to simplify the mathematical modeling in reservoir engineering. Within this framework, the energy of the reservoir, particularly its aquifer, was idealized, leading to classifications such as “partial waterdrive,” “full waterdrive,” “gas cap drive,” and so forth. However, in reality, all existing energy sources interact simultaneously within reservoirs. Accordingly, this study aims to develop a new concept for a more realistic description of reservoir drive mechanisms and evaluation of reservoir energy performance. Numerous computer simulations have revealed a strong correlation between the ratio of relative changes in pore volume to relative changes in reservoir pressure and the reservoir’s energy nature and activity level. Moreover, the noted ratio did not depend on production technology, pressure/volume/temperature properties of hydrocarbon systems, rheological properties of reservoir rocks, or other factors. Based on this correlation, specific parameters termed as Jamalbayli Indexes (JI) have been identified to quantitatively describe reservoir energetic performance. JI consist of two parameters. One of them describes the relative change in pore volume per unit of relative change in reservoir pressure, and the second is the relative change in pore volume per unit of relative change in formation porosity. Here, “relative change” means a change in a parameter relative to its original value. These parameters are dimensionless and can have values around or equal to unity. A new conceptual framework for describing reservoir drive mechanisms based on JI has been formulated. According to this framework, reservoir drive mechanism is determined by comparing the computed JI values with unity rather than relying on subjective assessments of the trend of some functional dependencies. For the first time, it has become possible to express the reservoir drive performance quantitatively and determine the level of energy activity of the reservoirs with the help of JI. Additionally, a technique has been developed to evaluate the numerical values of JI for specific oil (including volatile oil) deposits based on the production data at any stage of production. The proposed methodology was tested using data from the eighth horizon of the Russkiy Khutor field in Russia. The test results not only confirmed the reliability of the obtained model but also demonstrated the adequacy of the proposed concept as a whole. Summarizing the results of other works by the authors, the adequacy of the proposed concept for both oil, gas, and gas condensate deposits has been confirmed. The research findings are expected to contribute to updating the traditional principles used for the mathematical problem statements in fluid flow in porous formations. Additional Key Terms and Phrases Reservoir Drive Mechanism; Early Determination Methods; Reservoir Performance Analysis; Production Data Interpretation; Enhanced Oil Recovery; Reservoir Management; Drive Mechanism Identification; Reservoir Fluid Dynamics; Production Rate Analysis; Reservoir Engineering Techniques; Field Development Planning; Reservoir Simulation; Pressure/Volume/Temperature (PVT) Analysis; Production Monitoring and Evaluation drive mechanisms; production data analysis; volatile oil; Jamalbayli indexes; drive performance indexes

Flow prediction of heterogeneous nanoporous media based on physical information neural network

The simulation and prediction of fluid flow in porous media play a profoundly significant role in today's scientific and engineering domains, particularly in gaining a deeper understanding of phenomena such as the migration and fluid flow in underground rock formations and the enhancement of oil recovery rates. The flow of fluids in nanoscale porous media requires consideration of the effects of microscale phenomena, which are challenging to accurately describe using traditional physical models. Currently, research in deep learning for porous media predominantly focuses on conventional porous media, and there is an urgent need for investigations into heterogeneous nanoporous media. Simultaneously, there is a necessity to overcome the limitations of traditional data-driven models lacking physical prior knowledge. Therefore, the integration of physics-informed neural networks, which combine deep learning with physical principles, becomes essential for inferring relatively accurate results from sparse data. In this work, based on the heterogeneity of porous media in shale, we have introduced a deep learning model that couples physical information to predict the flow in heterogeneous nanoscale porous media. In the Physical Information Neural Network model, we utilize point clouds and couple them with deep residual networks. Discrete sampling points are used as inputs, and a multi-level residual connection, along with dimension concatenation, is employed to fuse feature information. The network, through backpropagation, takes into account the Navier-Stokes equations and wall conditions in heterogeneous nanoscale porous media. The results indicate that the apparent permeability and pressure field accuracy are over 90% and 95%, respectively. The Physical Information Neural Network demonstrates promising prospects for predicting flow in nanoscale porous media. Future work will extend to the multiphase complex flow in three-dimensional porous media.

Fluid flow and solute transport simulations in tight geologic formations: Discrete fracture network and continuous time random walk analyses

Understanding the effect of fracture network heterogeneity on flow and transport in tight formations with low permeability values is of great importance in a wide variety of applications, such as groundwater pollution and storage as well as water production. Although numerous studies have investigated solute transport in fractured media, investigation about scale effects on flow and transport in low-permeability aquifers is limited. More specifically, we are not aware of any study that has addressed how the continuous time random walk (CTRW) model parameters vary with scale and fracture network properties. To this end, we performed a set of numerical simulations in sparse fracture networks of sizes L = 20, 35, and 50 m under two different volumetric fracture counts (p30 = 0.05 and 0.1) using the discrete fracture network approach. The fractures in the networks were elliptical in shape, and their radii followed a truncated power-law distribution with exponents α = 1.5, 2, and 2.5. We simulated fluid flow using the Reynolds equation, and solute transport was simulated using particle tracking. The solute transport behavior was quantified by fitting the solution of the CTRW transport equation to the arrival time distributions. Results showed that as the truncated power law exponent α increased, the permeability of the networks decreased. In all the fracture networks studied, we found non-Fickian solute transport behavior deduced from small values of β(0.69≤β≤1.25), the exponent in the truncated power-law arrival time distribution in the CTRW model. In our fracture networks, the aperture size spanned less than one order of magnitude meaning that the fracture permeability distribution was relatively narrow. Therefore, the observed non-Fickian behavior should be attributed to sparse fracture networks and low connectivity. We found that the effective permeability, keff, at p30 = 0.05 was more scale-dependent compared to that at p30 = 0.1 because the fracture networks with p30 = 0.05 were less connected and, thus, more heterogeneous. Our simulation also disclosed the scale dependence of the CTRW model parameters. We conducted multiple linear regression analysis to link the CTRW model parameters to the network size as well as the geometrical and topological properties of the network. Results of regression analysis showed that all the CTRW model parameters except the average solute velocity were significantly dependent on the system size L (p-value < 0.05). Further investigations using a broader range of fracture network properties, such as broader aperture size distributions, smaller and larger network sizes and volumetric fracture counts are still required.

On the Constitutive Equations for Coupled Flow, Chemical Reaction, and Deformation of Porous Media

AbstractDeformation, chemical reactions, fluid flow in geological formations, and many engineering materials are coupled processes. Most existing models of chemical reactions coupled with fluid transport assume the dissolution‐precipitation process or mineral growth in rocks. However, these models have limitations, such as predicting restricted reaction extent due to pore clogging or disregarding porosity changes resulting from mineral growth. Recent studies indicate mineral replacement involves coupled dissolution‐precipitation, maintaining porosity while altering the solid volume. This has multiple practical implications for natural geological processes and within petroleum and environmental engineering. We present a novel model for reaction‐driven mineral expansion that preserves porosity and allows solid volume change. First, we look at fluid‐rock interaction at the pore scale and derive effective rheology of a reacting porous media. On a larger scale, we adopt a two‐phase continuum medium approach to investigate the coupling between reaction, deformation, and fluid flow. Our micromechanical model based on observations assumes that rock or cement consists of an assembly of solid reactive grains, initially composed of a single, pure phase. The reaction occurs at the fluid‐solid contact and progresses into the solid grain material. We approximate the pores and surrounding solid material as an idealized cylindrical shell to simplify the problem and obtain tractable results. We derive macroscopic stress‐strain constitute laws that account for chemical alteration and viscoelastic deformation of porous rocks. Our model explains the possibility of achieving a complete reaction, preservation of porosity during chemical reactions, and dependence of mechanical rock properties on fluid chemistry.

Evaluation of different well control methods concentrating on the application of conventional drilling technique

Over the past few decades, engineering failures have existed, and lack of knowledge, and safety practices have led to various catastrophic events of blowouts causing countless casualties and injuries to workers and individuals all around the world. Well control is a technique in oil and gas activities specifically when drilling oil and gas wells. Hydrostatic pressure and formation pressure should be a priority to prevent reservoir fluids from infiltrating the wellbore. The primary well control is commonly the primary barrier using the fluid column to prevent uncontrolled formation fluid flow into the wellbore by preserving pressure more substantial than formation pressure. The secondary well control provides the same purpose but involves using a piece of equipment known as a Blowout Preventer. The objective of this paper is to evaluate the effectiveness of different well control techniques of various well control methods, including the commonly used in petroleum engineering focusing on the application of conventional drilling. This study was conducted through a literature review. The analysis of the case studies synthesized to provide a comprehensive overview of the various well control methods. The findings suggested that conventional drilling techniques can be effective in controlling wellbore pressures, however, limitations existed in certain situations. Moreover, the parameters required controlling the well during a kick or a blowout is discussed to succeed in the application of well control methods in the oil and gas industry.

Совершенствование проточной части мультифазных ступеней с использованием мультифазного коэффициента относительной скорости движения дискретных частиц

Equations are derived to design and develop the multiphase stages flow path in a diagonal form using the dimensionless multiphase coefficient of the discrete particles relative speed. An analysis was made of the formation fluid flow containing free gas bubbles in the serial multiphase stages flow path of axial and axis-diagonal types in comparison with the developed diagonal-type stages and with inclined-cylindrical and helical blades. It is shown that, compared to the axial and axis-diagonal type stages, multiphase stages of the diagonal type with the inclined-cylindrical and helical blades have higher pressure when operating on the gas-liquid mixtures, especially in the multi-stage design. When operating on water without free gas, pressure and efficiency of the multiphase stages exceed characteristics of the best analogues, which makes it possible to manufacture the full-size pumps operating efficiently on liquid without gas and on the gas-liquid mixture.

Mathematical model of killing an oil horizontal well

The physical picture of the killing fluid and the formation fluid movement in the process of killing a horizontal oil well has been described, a physical and mathematical model of the process has been developed and the limits of the model applicability have been indicated. It is recommended to conduct the killing process in two stages, separated by a technological break. During the first stage, the injected killing fluid fills the tubing, the annulus and the part of the horizontal wellbore. For the duration of the technological break, the denser tubing slowly displaces the formation fluid from the horizontal wellbore into the annulus where the formation fluid floats to the surface in the form of droplets. For the period of the second stage, the remaining amount of tubing is pumped into the well. The model is based on the well-known hydraulic equations for laminar flow of liquids, the solution of the flooded jet problem, as well as the model of one-dimensional vertical inertialess flow of a two-phase medium with incompressible phases. A closed system of equations has been formed taking into account the viscous friction losses on the walls of the horizontal pipe and at the interface between the formation fluid and the killing fluid flows. The solution of this system has been obtained and the values of the main process parameters have been found: velocities and flows of liquid gas and liquid coolant and time of complete replacement of liquid coolant by the killing fluid depending on the inclination angle of the horizontal pipe. It is shown that the character of the movement of the formation fluid drops in the pipe space depends on their volume fraction φ in the mixture with the killing fluid. With the value φ &lt; 1/3 the jelly drops float up with a constant speed, while the jelly droplet radius and the speed of their floating up are unambiguously determined by the jelly stream size, density and viscosity of jelly and liquid hydrocarbon. The graphs of dependence of these parameters on the value of the formation fluid flow have been presented. On the basis of the research the recommendations for the process of killing horizontal oil wells have been formulated.

Совершенствование проточной части десендеров циклонного типа с использованием мультифазного коэффициента относительной скорости движения дискретных частиц

In the oil producing wells with high content of mechanical impurities and free gas, efficiency of the electric centrifugal pump is increased by installing the cyclone-type desenders at its inlet. Desender protects the submersed pump from mechanical impurities entering it by separation and collecting them in a special container. At the same time, the problem of free gas bubbles enlargement is being solved to facilitate their separation into the annulus and thus reduce the free gas content at the pump inlet. Analysis was made of specifics of the formation fluid flow containing mechanical impurities and free gas in the flow path of a cyclone-type separator with the fixed screw. Expressions were derived to determine the dimensionless multiphase coefficient of the discrete particles relative separation rate and of the multiphase similarity criterion. They allow evaluating efficiency of the mechanical impurity separators and developing new highly efficient structures based on the previously created ones. Recommendations are provided for development of the new highly efficient structures.

Impact of clay mineralogy on the petrophysical properties of tight sandstones

A full petrographic and petrophysical characterization of tight sandstones has been conducted as part of ongoing study of Carbon Dioxide Enhanced Oil and Gas Recovery (CO2-EOR/EGR) and CO2sequestration. The main purpose of this study is to give novel perception into the interplay of the rock characteristics and fluid flow in tight formations, which are candidates for EOR/EGR processes (macroscopic sweep vs. microscopic displacement efficiency). To achieve this, several experimental techniques, including routine core analysis, X-ray diffraction (XRD), X-ray fluorescence (XRF), thin sections petrography, Scanning Electron Microscopy (SEM) and capillarity/pore size distributions by using Mercury Injection Capillary Pressure (MICP), Nuclear Magnetic Resonance (NMR), and Micro-Computed Tomography (Micro-CT), were conducted. Three tight sandstone rock samples (Bandera, Kentucky, and Scioto) were used in this work and particular attention was paid to the impact of clay content on rock's pore system and other petrophysical characteristics and hence fluids flow during production process.Results indicate that the presence of fibrous illite clay acting as pore bridging in Bandera and Kentucky samples have blocked the overall micro-pore system causing a significant reduction in the micro-pore throat system to 36% in Bandera sand and 50.9% in Kentucky sample. On the other hand, absence of fibrous illite and the presence of illite platelets in the Scioto sandstone led to a clear preservation of the sample's micro-pore throat attributing to a total of 59.1% of the total pore throat system.A new dimensionless number (dimensionless micro-pore throat modality) was established, defined as the ratio of micro-to macro-pore sizes. This shows that Scioto has the highest value of 1.44 implying that both macro- and micro-pore systems contribute to flow. Therefore, the mitigation of oil bypass from smaller pores should be a key criterion in selecting the proper recovery methods. Results show the effect of clay mineralogy on pore system considering a part of the physical and spatial properties the pore/grain framework of the tight sandstones.

Method of Distributions for Two‐Phase Flow in Heterogeneous Porous Media

AbstractMultiscale heterogeneity and insufficient characterization data for a specific subsurface formation of interest render predictions of multi‐phase fluid flow in geologic formations highly uncertain. Quantification of the uncertainty propagation from the geomodel to the fluid‐flow response is typically done within a probabilistic framework. This task is computationally demanding due to, for example, the slow convergence of Monte Carlo simulations (MCS), especially when computing the tails of a distribution that are necessary for risk assessment and decision‐making under uncertainty. The frozen streamlines method (FROST) accelerates probabilistic predictions of immiscible two‐phase fluid flow problems; however, FROST relies on MCS to compute the travel‐time distribution, which is then used to perform the transport (phase saturation) computations. To alleviate this computational bottleneck, we replace MCS with a deterministic equation for the cumulative distribution function (CDF) of travel time. The resulting CDF‐FROST approach yields the CDF of the saturation field without resorting to sampling‐based strategies. Our numerical experiments demonstrate the high accuracy of CDF‐FROST in computing the CDFs of both saturation and travel time. For the same accuracy, it is about 5 and 10 times faster than FROST and MCS, respectively.

Confinement-Driven Heterogeneous Benzene Crystallization in Silica Nanopores

Nanoconfinement alters the thermodynamics, dynamics, and kinetics of fluids hosted in nanoscale solid nanopores to an extent that depends on the characteristics of the confining space and the chemistry of the confined fluids. Confinement-induced alterations in the phase behavior of confined energetic fluids under high pressure or low temperature are highly relevant to subsurface and subsea phenomena such as fluid flow in porous media, hydrate formation and dissociation, and gas storage capacity. Although extensive efforts have been directed toward understanding the phase behavior of confined fluids, the role of solid–liquid interfaces in the phase transitions of organic liquids has not been resolved yet. In this study, we explore the onset and growth of benzene crystallization confined in 6 nm sized SBA-15 silica nanopores in the temperature range 300–200 K using in situ extended range small-angle and wide-angle X-ray scattering (SAXS/WAXS) measurements and atomistic classical molecular dynamics (MD) simulations. The crystallization onset of confined benzene depresses to 265 K compared to the freezing point of bulk benzene (∼278 K), followed by the continuous growth of the emerged crystals in the pore space with complete crystallization at 200 K. The orientation of the emerged benzene crystals is dominated by parallel (π–π stacking) and perpendicular (T-shape stacking) orientations along the cylindrical pore radius and pore length, respectively. The onset of benzene crystals occurs heterogeneously on the pore surface and grows continuously toward the pore center. Further, confined benzene undergoes a dynamical crossover from fragile to strong dynamics behavior, inferred from the rotational and translational diffusion. The insights provided by this study have significant implications for the phase transitions of confined organic liquids that are relevant to a wide range of applications in the biological, geological, environmental, and chemical fields.

Can we infer the percolation status of 3D fractured media from 2D outcrops?

Fractures and their connectivity are essential for fluid flow in low permeability formations. Geological outcrops can only provide two-dimensional (2D) information, but subsurface fractures are three-dimensional (3D). The percolation status of 3D fracture networks and their 2D cross-section maps are rarely investigated simultaneously. In this work, we construct 3D fracture networks with their geometries characterized by different stochastic distributions. Cross-section maps are taken to mimic real outcrops, and clusters are labeled to check the percolation status of 3D fracture networks and their 2D cross-section maps. The properties, reflecting the connectivity of two essential phases, are summarized and analyzed. We find that clustering effects impact local intersections significantly but have negligible impacts on fracture intensities of 3D fracture networks. The number of intersections per fracture is not a proper percolation parameter for complex 2D and 3D fracture networks. Real fracture networks in the subsurface should be geometrically well-connected and over-percolative if their outcrop maps have a spanning cluster formed. Empirical limits are provided to predict the fracture intensity and connectivity of subsurface 3D fracture networks based on their outcrop maps. If a spanning cluster is formed in the outcrop map, the corresponding 3D fracture networks should be over-percolative, and its fracture intensity can be larger than 3.5 times the intensity at percolation. However, if no spanning cluster is formed in the outcrop map, but the fracture intensity is larger than 0.43 times the intensity at percolation, the corresponding 3D fracture networks can form a spanning cluster and show good connectivity.

Phase-field modeling of wormhole formation and growth in carbonate matrix acidizing

Acidic fluid flow in geologic formations leads to mineral dissolution and, under certain circumstances, to localized dissolution forming a dendritic pattern, known as wormhole. Such patterns of conduits and caves are often observed in karstic aquifer and deliberately engineered in oil and gas well stimulation with acid injection. Two different kinds of instability are thought to cause wormholes. One is heterogeneous property in rocks. The other is a process itself such as reaction infiltration or viscous fingering. To assess each one properly, we need to separate one from the other. While most numerical studies rely on randomly seeded material heterogeneities to induce wormholes, Daccord and Lenormand (1987a) demonstrated that even water injection into a homogeneous plaster can form wormholes. Here, we focus on the process instability driven by reaction-infiltration in homogeneous materials. We apply a phase-field approach, which diffuses a sharp interface in a continuous manner and show that it is capable of simulating wormhole without random seeds by accounting for the energy expenditure in the dissolution topology. We verified the model against the sharp interface counterpart in one-dimensional simulations. We then performed the two-dimensional simulations to qualitatively validate wormhole formation and growth patterns against acid injection experiments on carbonate rocks under radial flow conditions. Our simulation results indicate that the injected acid is rapidly consumed near the acid entry point at low injection rates while the live acid becomes available at the tip of the dissolved cavity under high rates and thus wormhole starts to grow resulting in much faster acid breakthrough.

Techno-Economic Performance of Closed-Loop Geothermal Systems for Heat Production and Electricity Generation

• Closed-loop geothermal systems evaluated for heat and electricity production • Slow heat transfer in rock and limited heat transfer area pose challenges • Targeting high temperatures, existing wells, and multi-laterals beneficial • Relatively high levelized costs for greenfields, unless drilling at low cost Closed-loop geothermal systems, recently referred to as advanced geothermal systems (AGS), have received renewed interest for geothermal heat and power production. These systems consist of a co-axial, U-loop, or other configuration in which the heat transfer or working fluid does not permeate the reservoir but remains within a closed-loop subsurface heat exchanger. Advocates indicate its potential for developing geothermal energy anywhere, independent of site-specific geologic uncertainties, and with limited risk of induced seismicity. Here, we present a technical and economic analysis of closed-loop geothermal systems using a Slender-Body Theory (SBT) model, COMSOL Multiphysics simulator, and the GEOPHIRES analysis tool. We consider a number of different scenarios and evaluate the influence of variations in reservoir temperature (100 to 500℃), well termination depth (2 to 4 km), mass flow rate (10 to 40 kg/s), injection temperature (10 to 40℃), fluid type (liquid water vs. supercritical carbon dioxide), design configuration (co-axial vs. U-loop), and degree of reservoir convection (natural, forced or conduction-only). The resulting average heat production rates range from about 2 to 15 GWh per year for cases considering a co-axial design and from 9 to 67 GWh per year for cases with a U-loop design. Assuming generous economic and operating conditions, estimates of levelized cost of heat range from ∼$20 – $110 per MWh (∼$6 – 32/MMBtu) and ∼$10 – $70 per MWh (∼$3 – $20/MMBtu) for greenfield co-axial and U-loop cases, respectively. In the scenarios in which electricity generation is considered, annual electricity production ranged between 0.12 and 7.5 GWh per year at a levelized cost of electricity from roughly $83 to $2,200 per MWh. In all scenarios, the results exhibit a large rapid drop in production temperature after initiation of operations that levels off to a steady value significantly below the initial reservoir temperature. Operating at lower flow rate increases the production temperature but also lowers the total heat production. The consistently low production temperatures hinder efficient electricity generation in most cases considered. Natural or forced convection can increase thermal output but requires sufficiently high reservoir permeability or formation fluid flow. As expected, overall system costs are heavily dependent on drilling costs; hence, repurposing existing wells could significantly lower capital and levelized costs. In comparison with other types of geothermal systems, our results for closed-loop geothermal systems predict long-term production temperatures considerably below the initial reservoir temperature, and relatively high levelized costs for greenfield closed-loop geothermal systems, particularly for electricity production, unless significant reductions in drilling costs are obtained.

A Study to Investigate the Viscosity Effect on Micro-Confined Fluids Flow in Tight Formations Considering Fluid–Solid Interaction

Understanding different fluids flow behavior confined in microscales has tremendous significance in the development of tight oil reservoirs. In this article, a novel semiempirical model for different confined fluid flow based on the concept of boundary layer thickness, caused by the fluid–solid interaction, is proposed. Micro-tube experiments are carried out to verify the novel model. After the validation, the viscosity effect on the flow rate and Poiseuille number considering the fluid–solid interaction is investigated. Furthermore, the novel model is incorporated into unstructured networks with anisotropy to study the viscosity effect on pore-scale flow in tight formations under the conditions of different displacement pressure gradients, different aspect ratios (ratio of the pore radius to the connecting throat radius), and different coordination numbers. Results show that the viscosity effect on the flow rate and Poiseuille number after considering the fluid–solid interaction induces a great deviation from that in conventional fluid flow. The absolute permeability is not only a parameter related to pore structures but also depends on fluid viscosity. The study provides an effective model for modeling different confined fluid flow in microscales and lays a good foundation for studying fluid flow in tight formations.

Turbulent Nanofluid Flow Analysis Passing a Shell and Tube Thermal Exchanger with Kays-Crawford Model

Temperature dissipation in a proficient mode has turned into a crucial challenge in industrial sectors because of worldwide energy crisis. In heat transfer analysis, shell and tube thermal exchangers is one of the mostly used strategies to control competent heat transfer in industrial progression applications. In this research, a numerical analysis of turbulent flow has been conceded in a shell and tube thermal exchanger using Kays-Crawford model to investigate the thermal performance of pure water and different concentrated water-MWCNT nanofluid. By means of finite element method the Reynold-Averaged Navier-Stokes (RANS) and heat transport equations along with suitable edge conditions have been worked out numerically. The implications of velocity, solid concentration, and temperature of water-MWCNT nanofluid on the fluid flow formation and heat transfer scheme have been inspected thoroughly. The numerical results indicate that the variation of nanoparticles solid volume fraction, inflow fluid velocity and inlet temperature mannerism considerably revolutionize in the flow and thermal completions. It is perceived that using 3% concentrated water-MWCNT nanofluid, higher rate of heat transfer 12.24% is achieved compared that of water and therefore to enhance the efficiency of this heat exchanger. Furthermore, a new correlation has been developed among obtained values of thermal diffusion rate, Reynolds number and volume concentration of nanoparticle and found very good correlation coefficient among the values.

Characteristics of Shale Pores and Surfaces and Their Potential Effects on the Fluid Flow From Shale Formation to Fractures

Fluid flow is critical for the efficient exploitation of shale resources and can be split into two stages: the flow in the artificial fractures and, more importantly, the flow from shale formations to the artificial fractures. In this study, X-ray diffraction, N2 adsorption, mercury intrusion, and ethylene glycol monoethyl ether adsorption were conducted on the shales collected from Es3middle, Es3lower, and Es4upper sub-members in the Dongying Sag to reveal the potential effects of the characteristics and properties of pores and surfaces on the fluid flow in shale formations. The results are indicated as follows: 1) The shales from Es3middle and Es3lower contain more I/S and detrital minerals but less illite and carbonate minerals than those of Es4upper. 2) The shales from Es3middle and Es3lower are mainly composed of smaller pores present in larger surface areas and lead to the steeper slope between the BrunauerEmmettTeller specific surface area (BET-SSA) and pore volumes. 3) Clay minerals mainly contribute to pore development, and carbonate minerals inhibit pore development. All kinds of surface areas (especially the inner surface area) are sourced by clay minerals, while I/S and illite present opposite effects. 4) Pore size and surface properties affect significantly the fluid flow in shale formations. The shales from Es4upper are the favorable interval for shale oil accumulation and flow, especially for the shales with depth ranges of 3360∼3410 m, which possess high carbonates, illite and total organic carbon content, low clay mineral content, large pore volume, high large pore content, and small surface areas. Additionally, fluid composition needs to be paid more concern in the future.

Application of upscaling methods for fluid flow and mass transport in multi-scale heterogeneous media: A critical review

Physical and biogeochemical heterogeneity dramatically impacts fluid flow and reactive solute transport behaviors in geological formations across scales. From micro pores to regional reservoirs, upscaling has been proven to be a valid approach to estimate large-scale parameters by using data measured at small scales. Upscaling has considerable practical importance in oil and gas production, energy storage, carbon geologic sequestration, contamination remediation, and nuclear waste disposal. This review covers, in a comprehensive manner, the upscaling approaches available in the literature and their applications on various processes, such as advection, dispersion, matrix diffusion, sorption, and chemical reactions. We enclose newly developed approaches and distinguish two main categories of upscaling methodologies, deterministic and stochastic. Volume averaging, one of the deterministic methods, has the advantage of upscaling different kinds of parameters and wide applications by requiring only a few assumptions with improved formulations. Stochastic analytical methods have been extensively developed but have limited impacts in practice due to their requirement for global statistical assumptions. With rapid improvements in computing power, numerical solutions have become more popular for upscaling. In order to tackle complex fluid flow and transport problems, the working principles and limitations of these methods are emphasized. Still, a large gap exists between the approach algorithms and real-world applications. To bridge the gap, an integrated upscaling framework is needed to incorporate in the current upscaling algorithms, uncertainty quantification techniques, data sciences, and artificial intelligence to acquire laboratory and field-scale measurements and validate the upscaled models and parameters with multi-scale observations in future geo-energy research.

Simulation of CO2 mineral trapping and permeability alteration in fractured basalt: Implications for geologic carbon sequestration in mafic reservoirs

Basalt formations are potentially attractive targets for carbon capture and sequestration (CCS) on the basis of favorable CO2-water-rock reactions, which result in permanent CO2 isolation through mineral trapping. Recent pilot-scale experiments in Iceland and Washington state, USA, provide promising results that indicate rapid carbon mineralization occurs within basalt reservoirs. Nevertheless, transitioning these pilot-scale results to large-scale industrial CCS operations is fraught with uncertainty because fluid flow in basalt formations is governed by fracture-controlled hydraulic properties that are highly heterogeneous and difficult to map in situ. This uncertainty is exacerbated by feedbacks between multi-phase fluid dynamics (CO2 and water) and fluid-rock reactions, which may result in a reinforcing feedback comprising CO2 mineralization, permeability alteration, and fluid mobility. To begin to understand the feedbacks between multi-phase fluid flow and mineralization in fractured basalt, this study uses reactive transport simulation methods to model CO2 infiltrating a meter-scale, synthetic basalt fracture overlying a storage reservoir while accounting for porosity change due to mineralization and its corresponding effect on permeability and fluid mobility. Results show that (i) carbonate and clay mineralization tends to occur downgradient of a fracture intersection, (ii) mineralization reduces porosity, which leads to permeability reduction and slows free-phase CO2 migration, (iii) stronger porosity-permeability coupling increases the proportion of mineralized carbon while reducing CO2 mass that can enter fracture, which may lead to self-sealing behavior as fluid mobility approaches nil, and (iv) errors caused by unknown porosity-permeability relationships are small in comparison to errors that arise by omitting mineralization-induced permeability reduction when simulating CO2 sequestration scenarios in basalt reservoirs.