Permeability Hysteresis Research Articles

WITHDRAWN: Experimental and numerical-modeling investigation of relative permeability hysteresis during cyclic injection-production in underground gas storage

WITHDRAWN: Experimental and numerical-modeling investigation of relative permeability hysteresis during cyclic injection-production in underground gas storage

The Effect of Different Freeze-Thaw Cycles on Mortar Gas Permeability and Pore Structure

Two different freeze-thaw cycles (FTC) are considered in this study to assess the related impact on gas permeability and micro-pore structure of a mortar. These are the water-freezing/water-thawing (WF-WT) and the air-freezing/air-thawing (AF-AT) cycles. The problem is addressed experimentally through an advanced nuclear magnetic resonance (NMR) technique able to provide meaningful information on the relationships among gas permeability, pore structure, mechanical properties, and the number of cycles. It is shown that the mortar gas permeability increases with the number of FTCs, the increase factor being 20 and 12.83 after 40 cycles for the WF-WT and AF-AT, respectively. The results also confirm that gas permeability hysteresis phenomena occur during the confining pressure loading and unloading process.

Magnetic indicators for evaluating plastic strains in electrical steel: Toward non-destructive assessment of the magnetic losses

Electric steel is widely used for magnetic conversion of electrical energy such as in electric motors and power transformers. Electric steel sheets are cut using mechanical methods (such as punching) during manufacturing. These methods induce local plastic strains, which lead to overall degradation in magnetic performance.Plasticity and magnetic losses are physically related in electrical steel. It is impossible to measure the magnetic losses on the production line using standard methods. Non-destructive testing (NDT) based on magnetization mechanisms is a promising alternative, giving access to local plastic strains and indirectly to local magnetic losses.In this study, a setup was designed to stimulate the magnetization mechanisms separately while maintaining the same experimental conditions. The magnetization processes related to the domain wall kinetics were revealed to be more correlated to plastic strain. The magnetic incremental permeability hysteresis area and maximal value, and the coercivity associated with Barkhausen noise were found to be the best plastic strain indicators. Additional tests in an NDT context confirmed the correlations, the equal applicability of the proposed indicators, and their viability in predicting static hysteresis loss.

An Analytical Model for Hysteretic Pressure-Sensitive Permeability of Nanoporous Media

Hysteretic pressure-sensitive permeability of nanohybrids composed of substantial nanopores is critical to characterizing fluid flow through nanoporous media. Due to the nanoscale effect (gas slippage), complex and heterogeneous pore structures of nanoporous media, the essential controls on permeability hysteresis of nanohybrids are not determined. In this study, a hysteretic pressure sensitive permeability model for nitrogen flow through dry nanoporous media is proposed. The derived model takes into account the nanoscale effect and pore deformation due to effective stress. The model is validated by comparing it with the experimental data. The results show that the calculated permeability and porosity are consistent with the measured results with the maximum relative error of 6.08% and 0.5%, respectively. Moreover, the hysteretic pressure-sensitive permeability of nanohybrids is related to effective stress, gas slippage, pore microstructure parameters, grain quadrilateral angle, and the loss rate of grain quadrilateral angle. The nanoscale effect is crucial to the permeability of nanoporous media. In addition, as impacted by the comprehensive impact of multiple relevant influential parameters, permeability during the pressure unloading process is not a monotonous function but presents complicated shapes. The proposed model can explain, quantify, and predict the permeability hysteresis effect of nanoporous media reasonably well.

Impacts of relative permeability hysteresis, wettability, and injection/withdrawal schemes on underground hydrogen storage in saline aquifers

Underground hydrogen storage (UHS) is a key strategy in the implementation of a large-scale hydrogen (H2) economy and promotion of renewable energy development/utilization. For UHS in water-wet saline aquifers, H2 displaces in-situ brine during injection; during well shut-in and H2 withdrawal,brine imbibes back into the flow paths where it displaces some H2. These processes are influenced by H2-brine transport physics, H2-brine-rock interactions and injection/withdrawal schemes, which, in turn, determine H2 storage capacities and injection/withdrawal efficiency. However, these effects are poorly understood. Therefore, this work focuses onthe impact of relative permeability hysteresis (RPH), wettability, and H2 withdrawal rate on UHS performance in a saline aquifer. Furthermore, differences between UHS and CO2 geo-storage (CGS) are examined.The primary findings include: 1) RPH results in a smaller H2 withdrawal factor (H2-WF), but a larger H2 withdrawal purity (H2-WP); 2) H2-WF increases with rock hydrophobicity, while H2-WP is mostly insensitive to rock wettability; 3) under similar storage conditions, H2-WF and H2-WP are approximately 10% less than CO2-WF and CO2-WP.These insights demonstrate the significance ofRPH and rock wettability on UHS performance and provides guidance on H2 injection/withdrawal scheme optimization. This study aids in the implementation of an industry-scale hydrogen economy.

Impact of geological and operational conditions on underground hydrogen storage

Transition toward renewable energies is an important step to tackle climate change and to build a sustainable energy system. Fluctuation in availability of renewable energy sources is a major issue leading to demand and supply imbalance. To solve this mismatch, surplus energy can be converted to green hydrogen (H2) through water electrolysis and be stored underground. Here we study the injection, storage, and production of H2 in a three-dimensional heterogeneous aquifer system. The goal is to understand how H2 storage is affected by vertical anisotropy ratio, temperature, injection and production period, relative permeability (kr) hysteresis, well perforation placement, and cushion gas type. For each case, we study how stored H2 is distributed in different forms: mobile, residually trapped, dissolved, and produced. We also quantify volume of extracted water. Results suggest that H2 recovery is successful if 1) the aquifer is more anisotropic and has lower temperature, 2) low density and viscosity cushion gas is injected prior to H2 storage, 3) injection and production perforations are placed at the bottom and top of aquifer, respectively, and 4) shut-in period between injection and production stages is minimized. Results demonstrate that kr hysteresis is critical to assess the amount of residually trapped H2.

Hysteresis in permeability evolution simulated for a sandstone by mineral precipitation and dissolution

Abstract. Mineral dissolution and precipitation can substantially affect rock permeability, which is a critical parameter for a broad range of geological subsurface applications. Virtual experiments on digital pore-scale samples represent a powerful and flexible approach to understand the impact of microstructural alterations on evolving hydraulic rock behaviour and quantify trends in permeability. In the present study, porosity-permeability relations are simulated for a precipitation-dissolution cycle within a typical reservoir sandstone. A hysteresis in permeability is observed depending on the geochemical process and dominating reaction regime, whereby permeability of the six investigated reaction paths varies by more than two orders of magnitude at a porosity of 17 %. Controlling parameters for this hysteresis phenomenon are the closure and re-opening of micro-scale flow channels, derived from changes in pore throat diameter and connectivity of the pore network. In general, a transport-limited regime exhibits a stronger impact on permeability than a reaction-limited regime, which uniformly alters the pore space. In case of mineral precipitation, higher permeability reduction results from successive clogging of pore throats, whereas in case of dissolution, permeability significantly increases due to a widening of existing flow paths. Both, the geochemical process and dominating reaction regime govern characteristic microstructural alterations, which cannot be simply reversed by the inversion of the geochemical processes itself. Hence, permeability evolution clearly depends on the hydrogeochemical history of the sample.

Understanding Hysteresis and Gas Trapping in Dissociating Hydrate-Bearing Sediments Using Pore Network Modeling and Three-Dimensional Imaging

Hysteresis behavior is a key factor in exploring dynamic water and gas flow in dissociating hydrate-bearing sediments (HBS). In this study, we combined microfocus X-ray computed tomography and a pore network model to investigate the effect of hydrate dissociation on gas trapping and hysteresis in capillary pressure, Pc and relative permeability, kr in different wettability systems. The results show that the hydrate dissociation process involves secondary hydrate formation, which promotes gas trapping. The effective residual gas saturation in the water-wet system was significantly higher than that in the gas-wet system due to snap-off. Gas trapping has a huge impact on the hysteresis in Pc and kr between the drying and wetting cycles in HBS. This work will improve the fundamental understanding of the permeability properties of HBS so that gas and water production can be better assessed.

Physics-Based Proxy Modeling of CO2 Sequestration in Deep Saline Aquifers

The geological sequestration of CO2 in deep saline aquifers is one of the most effective strategies to reduce greenhouse emissions from the stationary point sources of CO2. However, it is a complex task to quantify the storage capacity of an aquifer as it is a function of various geological characteristics and operational decisions. This study applies physics-based proxy modeling by using multiple machine learning (ML) models to predict the CO2 trapping scenarios in a deep saline aquifer. A compositional reservoir simulator was used to develop a base case proxy model to simulate the CO2 trapping mechanisms (i.e., residual, solubility, and mineral trapping) for 275 years following a 25-year CO2 injection period in a deep saline aquifer. An expansive dataset comprising 19,800 data points was generated by varying several key geological and decision parameters to simulate multiple iterations of the base case model. The dataset was used to develop, train, and validate four robust ML models—multilayer perceptron (MLP), random forest (RF), support vector regression (SVR), and extreme gradient boosting (XGB). We analyzed the sequestered CO2 using the ML models by residual, solubility, and mineral trapping mechanisms. Based on the statistical accuracy results, with a coefficient of determination (R2) value of over 0.999, both RF and XGB had an excellent predictive ability for the cross-validated dataset. The proposed XGB model has the best CO2 trapping performance prediction with R2 values of 0.99988, 0.99968, and 0.99985 for residual trapping, mineralized trapping, and dissolution trapping mechanisms, respectively. Furthermore, a feature importance analysis for the RF algorithm identified reservoir monitoring time as the most critical feature dictating changes in CO2 trapping performance, while relative permeability hysteresis, permeability, and porosity of the reservoir were some of the key geological parameters. For XGB, however, the importance of uncertain geologic parameters varied based on different trapping mechanisms. The findings from this study show that the physics-based smart proxy models can be used as a robust predictive tool to estimate the sequestration of CO2 in deep saline aquifers with similar reservoir characteristics.

Influence of capillary pressure boundary conditions and hysteresis on CO2-water relative permeability

This study examines the effect of capillary pressure boundary conditions and hysteresis on CO2-water relative permeability. We perform drainage and imbibition injections into a Berea sandstone core and a sintered glass core. The cores receive three injection stages: water, then water-saturated CO2 representing drainage, and finally CO2-saturated water representing imbibition. Pressure difference and fluid production are recorded. To generate relative permeability using these data, we propose that the conventional Johnson–Bossler–Naumann (JBN) method be modified to incorporate capillary pressure boundary conditions. We then compare the results yielded by the JBN and modified-JBN methods, which generate relative permeability for post-breakthrough water saturation. To generate relative permeability for all states of saturation, history matching is used, in which the relative permeability of a numerical model is tuned until the simulated data match the experimental data.For drainage, history-matched relative permeability curves are found to be significantly closer to modified-JBN estimates than to JBN estimates. This indicates that the proposed modified-JBN method can provide a more accurate initial guess for history matching. In addition, using the initial guess generated by modified-JBN is found to reduce the chance of non-unique history-matched relative permeability curves.For imbibition, the CO2-water relative permeability curve is generated directly from history matching because the experimental data are too sparse to apply the JBN or modified-JBN method. Both CO2 and water imbibition relative permeability are found to differ from the drainage relative permeabilities. This so-called relative permeability hysteresis is attributed to contact angle hysteresis. In addition, imbibition CO2-water relative permeability is found to be sensitive to imbibition capillary pressure boundary conditions.

Role of relative permeability hysteresis in modified salinity water flooding

Many laboratory and field scale trials have shown that modified salinity water flooding increases the mobility of oil and improves oil recovery. However, field scale simulation of the process guided by core flooding data leads to inaccurate prediction of oil recovery if the effect of the saturation history of the reservoir on relative permeability is ignored. Here, we address this problem by proposing three models illustrating the interplay among wettability alteration, hysteresis effect, and fluid flow transport in porous media. The models provide the variation of imbibition and secondary drainage saturation curves versus salinity caused by wettability alteration. Our simulations show that including hysteresis together with the wettability alteration process can better quantify the re-trapping of the oil that is mobilized due to wettability alteration of the reservoir. We further show that in the capillary transition zone, where water saturation varies from top to bottom of the reservoir, oil recovery continues for a long time, although the water cut starts early, in comparison with a reservoir with an initial uniform water saturation. Despite many experiments conducted for advanced waterflooding, our observations show that measuring the secondary drainage and imbibition saturation curves is essential and serves as a valuable input for the field scale simulation of modified salinity waterflooding of water flooded reservoirs with highly non-uniform saturation history.

Role of Relative Permeability Hysteresis in Modified Salinity Water Flooding

Role of Relative Permeability Hysteresis in Modified Salinity Water Flooding

Hysteresis effect of three-phase fluids in the high-intensity injection–production process of sandstone underground gas storages

The unique high-intensity injection–production process of underground gas storages causes changes in reservoir and seepage parameters, which are crucial for safe and efficient operation. However, these parameters changes are frequently ignored in numerical simulations. In this study, two representative rock samples were selected for an experiment on relative permeability under the condition of high-speed injection and production. It was confirmed that multiphase fluid seepage in pores will produce hysteresis effect, which can limit the free exchange between different fluids in the process of injection and production. Based on the experiment results analysis, a mathematical model of the relative permeability hysteresis effect of three-phase fluid reservoir was established and applied to the numerical simulation of an underground gas storage. The influence of hysteresis effect on the numerical simulation process was evaluated, and the difference in the macro distribution law of oil, gas, and water in the stages of gas-reservoir development and underground gas storage injection-production was analysed. It shows that the relative permeability hysteresis effect must be activated in the injection–production process; otherwise, the actual seepage law of fluids and the range of transition zones cannot be accurately characterised; therefore, a high fitting accuracy cannot be achieved.

The Effect of Relative Permeability Hysteresis on the Design of an Optimal Water-Alternating-Gas (WAG) Process

Summary Water-alternating gas (WAG) as a tertiary recovery method is applied to oil reservoirs at a later stage of reservoir life to more or less success depending on field and operation. Uncertainty in WAG optimization has been shown to be dependent on several factors including reservoir characterization, WAG timing, and its operation. In this paper, we comprehensively explore WAG optimization in the context of WAG operating parameters and hysteresis, the first paper to explore both simultaneously. WAG operating parameters have been analyzed and optimized at both the core and field scale with a general conclusion that the timing, miscibility, WAG ratio, cycle time, and number of cycles play a varying role in the WAG optimization. Reservoir characterization has considered well configuration, oil type, rock properties, and hysteresis in relative permeability. Due to the cyclic nature of WAG and the dependency of the relative permeability on the saturation history, the relative permeability hysteresis modeling plays a key role in WAG performance whereby different hysteresis models will predict different results, as shown in literature. In this paper, we consider the choice of the hysteresis model and WAG operating parameters on WAG optimization. First, a sensitivity analysis is performed to evaluate the effect of hysteresis models (no hysteresis, Carlson, and Killough) on a large number of WAG development scenarios sampled by the Latin hypercube sampling method. Next, optimizations were conducted to compare and analyze the optimum recovery factor and corresponding optimal WAG operating parameters for various combinations of hysteresis models. The results of the study indicate that excluding hysteresis modeling from simulations would likely lead to a higher predicted produced volume of the nonwetting phases, that is, oil and gas, and a lower predicted produced volume of the wetting phase, that is, water. Also, the optimal recovery factor as well as the optimal WAG operating parameters can be significantly affected by the choice of the hysteresis models.

Effects of Diffusion, Adsorption, and Hysteresis on Huff-n-Puff Performance in Ultratight Reservoirs with Different Fluid Types and Injection Gases

Cyclic solvent injection, known as solvent huff-n-puff, is one of the promising techniques for enhancing oil recovery from shale reservoirs. This study investigates the huff-n-puff performance in ultratight shale reservoirs by conducting large-scale numerical simulations for a wide range of reservoir fluid types (retrograde condensate, volatile oil, and black oil) and different injection gases (CO2, C2H6, and C3H8). A dual-porosity compositional model is utilized to comprehensively evaluate the impact of multicomponent diffusion, adsorption, and hysteresis on the production performance of each reservoir fluid and the retention capacity of the injection gases. The results show that the huff-n-puff process improves oil recovery by 4–6% when injected with 10% PV of gas. Huff-n-puff efficiency increases with decreasing gas-oil ratio (GOR). C2H6 provides the highest recovery for the black oil and volatile oil systems, and CO2 provides the highest recovery for retrograde condensate fluid type. Diffusion and adsorption are essential mechanisms to be considered when modeling gas injection in shale reservoirs. However, the relative permeability hysteresis effect is not significant. Diffusion impact increases with GOR, while adsorption impact decreases with increasing GOR. Oil density reduction caused by diffusion is observed more during the soaking period considering that the diffusion of the injected gas caused a low prediction error, while adsorption for the injected gas showed a noticeable error.

Assessment of two-phase relative permeability hysteresis models for oil/water, gas/water and gas/oil systems in mixed-wet porous media

Accurate determination of relative permeability curves and their hysteresis is vital for reliable prediction of the performance of oil and gas reservoirs under enhanced recovery processes. Two out of the three available approaches to simulate three-phase relative permeability hysteresis are based on two-phase hysteresis. A few options (e.g., Carlson, Killough and Jargon models) are available in commercial reservoir simulators to account for hysteresis in relative permeability curves under two-phase flow. These models are based on the assumptions of water-wet state of the rocks, while most of the reservoir rocks are mixed-wet. As a result the aim of the present work is to evaluate the performance of these hysteresis models for mixed-wet systems. In addition to the above models, more recent ones such as Beattie et al., Kjosavik et al., Spiteri et al. are also evaluated by coupling an in-house MATLAB code with the Eclipse simulator. The assessments of models are performed by comparing their predictions with those of previously reported comprehensive set of experimentally measured relative permeabilities for different two-phase systems. All possible two phase fluid/fluid systems i.e. oil/water, gas/water and gas/oil are considered. The interfacial tension in the case of oil/gas system is extra low (i.e. 0.04 mN.m−1) and it represents near-miscible condition. It is concluded that hysteresis models developed by Killough and Carlson are unable to accurately predict hysteresis effect on relative permeability in oil/gas system under extra low IFT and mixed-wettability. However, either of Killough and Carlson models could provide satisfactory results in gas/water and oil/water systems, respectively. Beattie et al. model that is not used in Eclipse gave a better fit to experimental data in oil/gas system, but it couldn't provide a suitable fit with experimental data in the cases of gas/water and oil/water systems. For different fluids systems, Kjosavik et al. model results were approximately close to the Killough model during the imbibition process and Beattie et al. during the drainage process. Even the results of the best models in each category of the two phase systems are not very satisfactorily. This study highlights the lack of a versatile hysteresis model to capture the hysteresis effect in all possible two phase systems for the mixed-wettability. As a result it is vital that modified or even novel hysteresis models in the case of mixed-wet system be developed.

Hysteresis characteristics of oxidation-thermodynamic for residual coal in goaf under uniaxial stress

During coal-mining processes underground, the coal spontaneous combustion caused by air leakage of narrow coal pillars and residual coal in goaf under pressure not only threatens the safety of mining of coal resources, but also leads to serious casualties. Therefore, the research of multi-field coupling for broken coal could be helpful to reveal the spontaneous combustion law of narrow coal pillars and residual coal in goaf and find the key for coal-fire prevention and control. Therefore, the uniaxial compression equipped with a temperature-programmed device is applied to conduct stress-heating tests on five types of coal particle sizes. Moreover, based on the Hertz contact deformation principle under the three-particle model, the thermodynamic hysteresis characteristics of broken coal under uniaxial stresses are theoretically analyzed. The results are shown as follows: (i) Uniaxial stress leads to significant hysteresis effects on the critical temperature of coal spontaneous combustion, heating rate, Graham’s Ratio-R2 temperature coefficient and pyrolysis temperature. (ii) As the particle radius increases, the growth rate of the exothermic intensity is suppressed, while it has no inhibitory effect on the critical temperature of the minimum exothermic intensity. (iii) The extreme point for the limit parameter of coal spontaneous combustion and the critical temperature shows the same corresponding hysteresis under uniaxial stress. The particle size ratio changes the limit parameter of coal spontaneous combustion obviously, and coal with a large particle size would reduce the risk of spontaneous combustion. (iv) The stress–strain curves and the stress-porosity curves are divided into stages, and it is found that the critical uniaxial stress of the porosity and strain of each coal sample is up to 4 MPa. Moreover, the temperature is the main reason for the hysteresis of permeability. The stress sensitivity of permeability declines with the effective stress rising, increases with the temperature going up, and decreases with the coal particle size reducing. (v) The hysteresis effect of uniaxial stress on coal spontaneous combustion first increases, then decreases, and finally increases.

A solution to the permalloy problem—A micromagnetic analysis with magnetostriction

A long-standing puzzle in the understanding of magnetic materials is the “Permalloy problem,” i.e., why the particular composition of Permalloy, Fe21.5Ni78.5, achieves a dramatic drop in hysteresis and concomitant increase in initial permeability, while its material constants show no obvious signal of this behavior. In fact, the anisotropy constant κ1 and the magnetostriction constants λ100,λ111 all vanish at various nearby, but distinctly different, compositions than Fe21.5Ni78.5. These compositions are in fact outside the compositional region where the main drop in hysteresis occurs. We use our newly developed coercivity tool [A. Renuka Balakrishna and R. D. James, Acta Mater. 208, 116697 (2021)] to identify a delicate balance between local instabilities and magnetic material constants that lead to a dramatic decrease in coercivity at the Permalloy composition Fe21.5Ni78.5. Our results demonstrate that specific values of magnetostriction constants and anisotropy constants are necessary for the dramatic drop of hysteresis at 78.5% Ni. Our findings are in agreement with the Permalloy experiments and provide theoretical guidance for the development of other low hysteresis magnetic alloys.

English

Based on the theoretical analysis of capillary hysteresis and relative permeability hysteresis and reservoir numerical simulation, a water injection strategy study was conducted for an offshore weak volatile oil fields after long-term depletion development. The results show that if the capillary hysteresis and relative permeability hysteresis are not considered, the recovery prediction results of the subsequent water injection development will be too small and large, respectively, which is inconsistent with the actual situation. Compared with conventional water injection, cyclic water injection can increase the recovery rate by 1.1%. Its oil displacement presents the characteristics of “three zones and two bands” along the direction from injection to production with water enrichment zone, water stagnation and oil drainage band, oil enrichment zone, oil stagnation and gas drainage band and secondary gas generation zone, respectively. To reduce the influence of the secondary gas cap, the water injection strategy after long-term depletion development includes two slugs of enhanced water injection and cyclic water injection. The timing to turn from enhanced water injection to cyclic water injection is when the formation pressure recovers to bubble point pressure. The optimal half-period of the cyclic water injection phase is 2 months. After the oilfield changed from depletion development to water injection development, the decline rate was improved from 20.8 to -12.7%. The double-slug water injection strategy considering the hysteresis effect can improve the recovery factor by 18.3%, and provide a practical basis for the efficient development of weak volatile reservoirs. Key words: Capillary force hysteresis, relative permeability hysteresis, weak volatile reservoir, cyclic water injection, water injection strategy.

CO2 geological sequestration in multiscale heterogeneous aquifers: Effects of heterogeneity, connectivity, impurity, and hysteresis

Fundamental understanding of processes controlling geological carbon sequestration (GCS) requires flow and transport modeling in well-characterized aquifer sedimentary deposits. We use three-dimensional, heterogeneous models based on new field studies which incorporate the most important aspects of multiscale architecture in fluvial aquifers. In addition, we use the associated facies-dependent constitutive relations for both relative permeability and capillary pressure curves and their hysteresis. The novelty of this work is to evaluate how CO2 fate and transport is controlled by (1) the spatial organization, volume proportions, and connectivity of sedimentary facies types, (2) facies-dependent constitutive relations and their hysteretic behavior, and (3) presence and/or absence of dissolved components such as methane (CH4) in brine. Model results suggest that the amounts of snap-off and solubility trapping are enhanced by increasing the volume proportion and degree of connectivity of high-permeability facies types. Results also demonstrate that ignoring relative permeability hysteresis leads to underestimation of snap-off trapping and overestimation of solubility trapping. In contrast, neglecting capillary pressure hysteresis (i.e., non-hysteretic Pc) results in overestimation of snap-off trapping and underestimation of solubility trapping. If capillary pressure is totally neglected (i.e., Pc = 0), the amount of trapped CO2 by snap-off and dissolution are, respectively, overestimated and underestimated. Competitive CO2 and CH4 dissolution in brine results in exsolution of CH4 from the aqueous phase into the gaseous phase. Facies connectivity and constitutive relations are also critical for the transport of exsolved CH4. However, disregarding dissolved CH4 leads to overestimation of CO2 trapping capacities.