Dynamic Relative Permeability Research Articles

Refined Prediction Method for Production Performance of Deep-Water Turbidite Sandstone Oilfield: A Case Study of AKPO in Niger Delta Basin, West Africa.

Deep-water oilfields frequently employ large or superlarge well spacing, leading to significant production dynamics influenced by reservoir factors. Traditional methodologies often disregard these influences, resulting in poor accuracy. Therefore, an enhanced prediction methodology rooted in reservoir characteristics is proposed. This approach introduces the dynamic relative permeability law as a bridge, capturing macroscopic oil/water movement within the reservoir. For the first time, it integrates production dynamics with key controlling reservoir factors, encompassing reservoir architecture, injection-production connectivity, and reservoir heterogeneity. The results indicate that (1) In deep-water turbidite sandstone fields with ultralarge injector-producer well spacings, the distribution of oil-water movement is primarily influenced by reservoir connectivity and heterogeneity. The injection water sweeping ability coefficient can quantitatively describe the water flooding capacity, with a strong negative correlation between the injection water sweeping ability coefficient and interwell nonconnectivity coefficient and reservoir homogeneity coefficient. This suggests that better reservoir connectivity or weaker heterogeneity results in stronger water flooding capacity, leading to a wider range of water flooding under the same injection volume. (2) For regions with strong water flooding capacity (injection water sweeping ability coefficient 0.30-0.80), the water-free production period is the main production stage, with a focus on improving the planar flooding conditions. For regions with poor water flooding capacity (injection water sweeping ability coefficient 0.00-0.10), the middle and late water-cut periods are the main production stages, with a focus on improving interlayer dynamic differences in the later stages. For regions with moderate water flooding capacity (injection water sweeping ability coefficient 0.10-0.30), the initial focus should be on expanding planar flooding, followed by a focus on improving interlayer dynamic differences in the later stages. (3) The dynamic relative permeability law, capable of comprehensively portraying the reservoir's influence on macroscopic oil/water movement, emerges as a rational choice for production performance prediction in such contexts. Our method can improve the accuracy, compared with traditional method without geographical factors, from 45% to 90% during water-cut rising stage and 31% to 81% during production declining stage. The high prediction accuracy (90%) observed in the AKPO oilfields underscores the method's efficacy in directing on-site optimization and adjustments for the development of deep-water turbidite sandstone oilfields.

A novel model for oil reservoirs considering stress sensitivity and dynamic relative permeability

ABSTRACT Stress sensitivity and dynamic relative permeability are undeniable phenomenon in oil reservoir numerical simulation. In this paper, a complex two-phase flow model was established considering the deformation of porous media and relative permeability dynamic changes during water injection. A sensitivity analysis on this new model is carried out. The results reveal that stress sensitivity is a key factor that cannot be ignored when using reservoir numerical simulation to calculate water saturation. When the stress-sensitivity coefficient is not considered, the average water saturation of the model is 51.59%. When the stress-sensitivity coefficient is 0.12MPa−1, the average water saturation of the model is 48.45%. After considering stress sensitivity, the average water saturation of the model decreases by 6.1%. The water saturation difference between the new model and the traditional model is mainly reflected in the vicinity of the water injection well. Additionally, the influence of the range of changes in reservoir permeability on the calculation of water saturation by the new model cannot be ignored.

Numerical modeling on high-temperature and high-pressure gas condensate recovery considering the viscosity variation and dynamic relative permeability

Numerical modeling on high-temperature and high-pressure gas condensate recovery considering the viscosity variation and dynamic relative permeability

Dynamic Relative Permeabilities for Partially Saturated Porous Media Accounting for Viscous Coupling Effects: An Analytical Solution

We present an analytical model to compute frequency-dependent relative permeability functions for partially saturated porous media accounting for viscous coupling effects. For this, we consider the oscillatory motion of two immiscible fluid phases and solve the Navier–Stokes equations at the pore scale using suitable interface conditions between fluids. These calculations are combined with the generalized two-phase flow Darcy equations to obtain the corresponding upscaled macroscopic fluxes. By means of an analog pore model consisting of a bundle of cylindrical capillaries in which pore fluids are distributed in a concentric manner, we find closed analytical expressions for the complex-valued and frequency- and saturation-dependent relative permeability functions. These expressions allow for a direct assessment of viscous coupling effects on oscillatory flow for all frequencies and saturations. Our results show that viscous coupling effects significantly affect flow characteristics in the viscous and inertial regimes. Dynamic relative permeabilities are affected by the pore fluid densities and viscosities. Moreover, viscous coupling effects may induce two critical frequencies in the dynamic relative permeability curves, a characteristic that cannot be addressed by extending the classic dynamic permeability definition to partially saturated scenarios using effective fluids. The theoretical derivations and results presented in this work have implications for the estimation and interpretation of seismic and seismoelectric responses of partially saturated porous media.

Upscaled Dynamic Relative Permeability for Unstable CO2 Flow in Stratified Porous Media

In geologic porous media, layering is ubiquitous on all length scales ranging from sub-mm compositional laminations to km-thick formations. The current study presents a general framework for estimating the two-phase viscous limit dynamic relative permeability (k_{r} ) for non-communicating stratified sedimentary rocks. The approach is a two-stage upscaling taking into account the influence of nested heterogeneity at intra- and inter-layer scales. Sub-layer heterogeneities, promoting microflow instabilities in individual layers, are modelled by tuning input relative permeability parameters based on the viscosity contrast between fluids. Macroscopic flow instability at the domain scale is tackled by a new analytical solution for the saturation distribution in stratified media considering the complexities of frontal advance theory. For each layer, three flow stages are considered, each with its unique time-dependent behaviour. The overall solution is presented as a set of equations derived by overlapping of the solutions in different layers. The upscaled dynamic k_{r} is figured out by history matching. The practicality of the method is demonstrated in application to measurements collected from the Otway International Research Facility, Victoria, Australia. The results show the significant impact of layer separation on the upscaled endpoint saturations in addition to required modifications on the current k_{r} formulas. A comparison with conventionally modelled steady-state sweep highlights the inadequacy of steady-state upscaling for viscous limit flows. The applicability of the method to estimate k_{r} from the unsteady-state lab experiments conducted on heterogeneous cores is also discussed.

Role of heterogeneous surface wettability on dynamic immiscible displacement, capillary pressure, and relative permeability in a CO2-water-rock system

Surface wettability is one of the major factors that regulate immiscible fluid displacement in porous media. However, the role of pore-scale wettability heterogeneity on dynamic immiscible displacement is rarely investigated. This study investigated the impact of pore-scale wettability heterogeneity on immiscible two-fluid displacement and the resulting macroscopic constitutive relations, including the capillary pressure-water saturation (Pc-Sw) and relative permeability curves. A digital Bentheimer sandstone model was obtained from X-ray micro-computed tomography (micro-CT) scanning and the rock surface wettability fields were generated based on in-situ measurements of contact angles. A graphics processing unit-accelerated lattice Boltzmann model was employed to simulate the immiscible displacement processes through the primary drainage, imbibition, and second drainage stages in a CO2-water-rock system. We found that pore-scale surface wettability heterogeneity caused noticeable local supercritical CO2 (scCO2) and water redistribution under less water-wet conditions. At the continuum scale, the Pc-Sw curves under the heterogeneous wetting condition were overall similar to those under the homogeneous wetting condition. This is because the impact of local wettability heterogeneity on the large-scale Pc-Sw curve was statistically averaged out at the entire-sample scale. The only difference was that heterogeneous wettability led to a negative entry pressure at the primary drainage stage under the intermediate-wet condition, which was caused by local, scCO2-wet surfaces. The impact of pore-scale wettability heterogeneity was more noticeable on the relative permeability curves. Particularly, the variation of the scCO2 relative permeability curve in the heterogeneous wettability scenario was more significant than that in the homogenous wettability scenario. This suggests that pore-scale wettability heterogeneity enhances the coalescence and snap-off behaviors of scCO2 blobs. This is the first study that systematically investigated the role of pore-scale wettability heterogeneity on dynamic immiscible displacement and associated Pc-Sw curves in complicated, three-dimensional porous media.

A Prediction Method for Flow-Stop Time in Deep-Water Volatile Oilfields: A Case Study of Akpo Oilfield in Niger Delta Basin

Due to the difference in oil and water density, the wellhead pressure continues to decrease with water-cut rising in deep-water volatile oilfields. Once it is close to the lower limit, the production well will stop flowing. This phenomenon seriously affects the production and recoverable reserves. By taking the dynamic relative permeability which can reflect the macroscopic movement of oil and water in the reservoir as an intermediate bridge, production performance has been combined with dominant reservoir factors, including reservoir structure, reservoir connectivity, and heterogeneity. By the statistical analysis of actual data, this paper clarified the quantitative relationships between dominant reservoir factors and production performance and established the refined prediction methods for production dynamics including water-cut and liquid production rate. A prediction method for the wellhead pressure was further established, and the flow-stop time of single well can be accurately predicted. The results can be used in annual production forecast and recoverable reserve evaluation. This method had been successfully applied in Akpo oilfields in the Niger Basin. The results show that the production dynamics are significantly affected by reservoir factors in deep-water turbidite sandstone reservoir and the prediction method considering reservoir factors will be much more applicable. In deep-water volatile oilfields, the flow-stop risk of the production well in middle and high water-cut stages is very great and is mainly affected by the water-cut and liquid production rate. Judging from the application effect of Akpo oilfields, this method has high prediction accuracy and can be used to guide optimization and adjustment in deep-water oilfields.

Effect of Hydrate Dissociation and Axial Strain on the Permeability of Hydrate-Bearing Sand during the Creep Process

Summary The relative permeability (kr) and capillary pressure (Pc) are essential components to predict the gas and water flow in hydrate-bearing reservoirs. In this study, we analyze the dynamic gas and water relative permeability (krg and krw) during the continuous creep process of hydrate-bearing sand (HBS) under conditions of thermal-stimulated hydrate dissociation using computed tomography (CT) and the pore network model (PNM). The dynamic sample region extraction method for CT images is adopted by considering the deformation of HBS in the vertical direction. The pore structure of the HBS was visualized and reconstructed by CT scanning. The 3D pore network is built after image processing; then, gas and water flow processes are analyzed by the PNM. The results show that krw is highly consistent with two main pore structure factors: the pore space size and connectivity variation. krg is greatly affected by an increasing number of narrow flow channels in the HBS during the creep process. In addition, the irreducible water saturation (Swir) during the creep process is mainly affected by the joint effect of the pore size, throat size, and pore space connectivity. The preferential flow directions of the gas and water change from vertical to horizontal along with the progression of creep.

A Comprehensive Model for Estimating Stimulated Reservoir Volume Based on Flowback Data in Shale Gas Reservoirs

Stimulated reservoir volume (SRV) which is generated by horizontal drilling with multistage hydraulic fracturing governs the production in the shale gas reservoirs. Although microseismic data has been used to estimate the SRV, it is high-priced and sometimes overestimated. Additionally, the effect of stress sensitivity on SRV is not considered in abnormal overpressure areas. Thus, the objective of this work is to characterize subsurface fracture networks with stress sensitivity of permeability through the shale gas well production data of the early flowback stage. The flowback regions are first identified with the flowback data of two shale gas wells in South China. Then, we measured the permeability stress sensitivity of the core after fracturing, coupled to the dynamic relative permeability (DRP) calculation to obtain an accurate and simple DRP curve. After that, a comprehensive model is built considering dynamic two-phase relative permeability function and stress sensitivity. Finally, we compared the calculated results with the microseismic data. The results show that the proposed model could reasonably predict the SRV using the flowback data after fracturing. Additionally, compared with the microseismic data, the stress sensitivity should be included, especially in the abnormal overpressure block. It is believed that this mathematical model is accurate and useful. The work provides an efficient approach to estimate stimulated reservoir volume in the shale gas reservoirs.

Simulation study of relative permeability and the dynamic capillarity of waterflooding in tight oil reservoirs

Relative permeability (kr) and the capillary pressure (Pc) are the central key elements defining the multiphase fluids flow behavior in the porous media. However, the dynamic capillarity should consider the dynamic relative permeability and the dynamic capillary pressure while performing waterflooding process in extremely low permeable formations. In order to improve the oil production, the advanced horizontal well drilling along with multiple hydraulic fracturing is generally instigated to penetrate the unconventional resources. The aim of this study is to consider the dynamic capillarity in a commercial reservoir simulation, while utilizing the data gained from the dynamic and steady experiments of the relative permeability and the capillary pressure impacts during waterflooding process in the core plugs of unconventional tight oil reservoirs. The commercial reservoir simulation conducted sensitivity analyses using Computer Modeling Group simulator. The outcomes show that the well production of the reservoir is overestimated while implementing steady data for forecasting due to which the oil saturation decreases more equally and further rapidly. Additionally, the forecast of the well production estimated to breakthrough sooner. However, neglecting the dynamic capillarity causes a huge breakthrough of water influx. Therefore, the core objective of this study is to probe the consequences of taking into consideration the dynamic capillarity in ultra-low permeable formations while giving an alternative perspective to forecast the production of the hydraulically fractured unconventional tight oil reservoirs.

A black-oil approach to model produced gas injection in both conventional and tight oil-rich reservoirs to enhance oil recovery

A robust compositionally extended black-oil simulation approach is developed, which is capable of including the effect of large gas-oil capillary pressure for first contact miscible (FCM), and immiscible gas injection. The simulation methodology is applied to gas flooding in both high and very low permeability reservoirs. For a high permeability conventional reservoir, simulations use a five-spot pattern with different reservoir pressures to mimic both FCM and immiscible displacements. The results show that the simple modified black-oil approach can model well both immiscible and miscible floods, as long as the minimum miscibility pressure (MMP) is matched. For a tight oil-rich reservoir, primary depletion and huff-n-puff gas injection are simulated including the effect of large gas-oil capillary pressure in flow and in flash calculation on recovery. Finally, a dynamic gas-oil relative permeability correlation that accounts for the compositional changes owing to the produced gas injection is introduced and applied to correct for changes in interfacial tension (IFT), and its effect on oil recovery is examined. The results show that the new black-oil approach can model these processes well and could be implemented when fully compositional simulations are computationally too time consuming. For the first time, a black-oil type reservoir simulation method is used to simulate near-miscible and immiscible produced gas injection enhanced oil recovery. It provides a fast and robust alternative for large-scale reservoir simulation with the purpose of flaring/venting reduction through reinjecting the produced gas into the reservoir for EOR.

The second critical capillary number for chemical flooding in low permeability reservoirs: Experimental and numerical investigations

High capillary numbers are often adopted for chemical flooding in reservoirs to achieve the highest oil recovery. A high capillary number may be disadvantageous for high and medium permeability formations, while no experimental or field data are available for low permeability formations. In this work, through the use of a newly designed experimental apparatus for the measurement of the dynamic capillary pressure in low permeability formations, chemical flooding experiments on sandstone core samples (1–10 mD) were conducted to investigate the effects of high capillary numbers (0.001–2). In addition, these effects were examined through numerical production simulations on a real low permeability reservoir. The dynamic capillary pressure and relative permeability were measured to reveal the dynamic fluid flow characteristics. The dynamic contact angle was investigated to explore the dynamic interface properties. The results show that there is a second critical capillary number (higher than 0.02) that can be used to optimize the chemical flooding performance in low permeability reservoirs. Moreover, the oil relative permeability reaches its highest value at the second critical capillary number, while the water relative permeability always increases with the increase in the capillary number. The dynamic contact angle will reach approximately 180° at a high capillary number, causing an oil film to remain. An optimized capillary number range is proposed for chemical flooding in low permeability reservoirs.

Dynamic Relative Permeability and Simulation of WAG Injection Processes

In this work, we investigate the impact of mobility changes due to flow reversals from co-current to counter-current flow on the displacement performance of water alternating gas (WAG) injection processes. In WAG processes, the injected gas will migrate toward the top of the formation while the injected water will migrate toward the bottom of the formation. The segregation of gas, oil and water phases will result in counter-current flow occurring in the vertical direction in some portions of the reservoir during the displacement process. Previous experimental and theoretical studies of counter-current flow have shown that the relative mobility of each of the phases in a porous medium is considerably less when counter-current flow prevails as compared to co-current flow settings. A reduction of the relative permeability in the vertical direction results in a dynamic anisotropy in phase mobilities. This effect has, to the best of our knowledge, not previously been considered in the modeling and simulation of WAG processes. A new flow model that accounts for flow reversals in the vertical direction has been implemented and tested in a three-phase compositional reservoir simulator. In order to investigate the impact of flow reversals, results from the new flow model are compared to cases where counter-current flow effects on the phase mobilities are ignored. A range of displacement settings, covering relevant slug sizes, have been investigated to gauge the impact of mobility reductions due to flow reversals. Significant differences, in terms of saturation distribution, producing GOR and oil recovery, are observed between the conventional flow model (ignoring mobility reductions due to counter-current flow) and the proposed new model that accounts for reductions in phase mobility during counter-current flow. Accordingly, we recommend that an explicit representation of flow transitions between co-current and counter-current flow (and the related impact on phase mobilities) should be considered to ensure accurate and optimal design of WAG injection processes.

Capillarity characters measurement and effects analysis in different permeability formations during waterflooding

In the description of multiphase flow in porous media, dynamic capillarity is typically ignored. While some studies suggest that dynamic capillarity can be ignored in high permeability rock, it cannot be overlooked in low permeability rock. In this work, dynamic capillarity, in various permeability formations, was investigated through specially designed experiments and the impact on field production is simulated. First, capillarity characters (capillary pressure-saturation relationships and relative permeability curves) were obtained during the static and dynamic waterflooding process conducted in different permeability core samples under in-situ reservoir conditions. The dynamic coefficients were calculated locally and compared. Then experimental results were subjected to sensitivity analyses, through numerical simulation studies using CMG (IMEX), to determine the dynamic capillary effects on different permeability cases. The results show that (a) a low permeability formation constitutes a much larger dynamic coefficient, thus resulting in a significant difference between dynamic and static capillary pressures; (b) the lower the rock permeability, the larger the difference between static and dynamic relative permeability curves; (c) the dynamic capillary pressure in low permeability formations, compared with static capillary pressure, can be notably large, causing irregular differences in phase behavior and pressure distribution. This work demonstrates the importance of considering dynamic capillarity in low permeability reservoirs.

Scale dependency of dynamic relative permeability–satuartion curves in relation with fluid viscosity and dynamic capillary pressure effect

Capillary pressure-saturation-relative permeability relationships (Pc-Sw-Kr) are functions of importance in modeling and simulations of the hydrodynamics of two-phase flow in porous media. These relationships are found to be affected by porous medium and fluid properties but the manner in which they are affected is a topic of intense discussion. For example, reported trends in fluid viscosity and boundary conditions effects have been found to be contrary to each other in different studies. In this work, we determine the dependency of dynamic Kr-Sw relationships (averaged data) on domain scale in addition to investigating the effects of fluid viscosity and boundary pressure using silicone oil (i.e. 200 and 1000 cSt) and water as the respective non-wetting and wetting fluids with a view to eliminating some of the uncertainties reported in the literature. Water relative permeability, Krw, was found to increase with increasing wetting phase saturation but decreases with the increase in viscosity ratio. On the other hand, the oil relative permeability, Krnw, was found to increase with the increasing non-wetting phase saturation in addition to the increase in viscosity ratio. Also, it was found that with the increasing boundary pressure Krw decreases while Krnw increases. The influence of scale on relative permeability was slightly indicated in the non-wetting phase with Krnw decreasing as domain size increases. Effect of mea- surement location on dynamic relative permeability was explored which is rarely found in the literature. Comparison was also made between Kr-Sw relationships obtained under static and dynamic condition. Finally, mobility ratio (m) and dynamic coefficient (s) were plotted as a function of water saturation (Sw), which showed that m decreases as s increases at a given saturation, or vice versa.

Pore-scale numerical investigations of fluid flow in porous media using lattice Boltzmann method

Purpose – Lattice Boltzmann method (LBM) is employed to explore friction factor of single-phase fluid flow through porous media and the effects of local porous structure including geometry of grains in porous media and specific surface of porous media on two-phase flow dynamic behavior, phase distribution and relative permeability. The paper aims to discuss this issue. Design/methodology/approach – The 3D single-phase LBM model and the 2D multi-component multi-phase Shan-Chen LBM model (S-C model) are developed for fluid flow through porous media. For the solid site, the bounce back scheme is used with non-slip boundary condition. Findings – The predicted friction factor for single-phase fluid flow agrees well with experimental data and the well-known correlation. Compared with porous media with square grains, the two-phase fluids in porous media with circle grains are more connected and continuous, and consequently the relative permeability is higher. As for the factor of specific porous media surface, the relative permeability of wetting fluids varies a little in two systems with different specific surface areas. In addition, the relative permeability of non-wetting fluid decreases with the increasing of specific surface of porous media due to the large flow resistance. Originality/value – Fluid-fluid interaction and fluid-solid interaction in the SC LBM model are presented, and schemes to obtain immiscible two-phase flow and different contact angles are discussed. Two-off mechanisms acting on the wetting fluids is proposed to illustrate the relative permeability of wetting fluids varies a little in two systems with different specific surface.

Modelling flowback as a transient two-phase depletion process

The existing rate transient models for fractured horizontal wells assume single-phase fluid flow. This assumption is violated in early times, when hydraulic fractures (HF) are filled with fracturing water and hydrocarbon. This calls for a model that captures the transient 2-phase (gas/oil + water) flow in HF, and can be used for history matching rate/pressure data measured during flowback operations. This paper extends the existing linear dual-porosity model (DPM) and develops a flowback analysis model (FAM) which accounts for transient 2-phase flow in HF.FAM assumes that water-saturation in HF drops with time, which causes a non-linear increase in relative-permeability. Hence, it adopts an explicit dynamic-relative-permeability (DRP) function of time for the hydrocarbon-phase to account for water-saturation drop in HF. The resulting DRP function is obtained by integrating cumulative flowback hydrocarbon + water (from 15 tight-oil, tight-gas and shale-gas multifractured horizontal wells) data with drainage relative-permeability curves from existing literature. DRP is then incorporated into the DPM to obtain FAM flow equations. These flow equations capture the fluid physics from flowback till “full” hydrocarbon production.The FAM equations are solved using Laplace transforms. Type-curves are generated by numerically inverting the resulting Laplace-space solutions to time-space using the Gaver-Stefhest algorithm. FAM converges to DPM at the limit of constant water-saturation. Flow-regimes observed comprise linear, bilinear, and boundary dominated. This paper proposes an interpretation workflow for analysing flowback data. The application of this workflow on 2-phase rate + pressure flowback data from a shale gas well provides a means to (1) estimate effective HF half-length and volume of interconnected secondary fractures, (2) evaluate flowback performance and (3) forecast hydrocarbon recovery. The results encourage the industry to start careful and accurate data measurement immediately when wells are put on flowback.

Determination of dynamic relative permeability in ultra-low permeability sandstones via X-ray CT technique

Forced oil–water displacement is the crucial mechanisms of secondary oil recovery. The knowledge of relative permeability is required in the simulation of multiphase flow in porous media. Obvious dynamic effect of capillary pressure occurs in that the formation of ultra-low permeability reservoir (the permeability is <1 × 10−3 μm2) is tight and the pores and throats are very small. In addition, the significant capillary end effect causes serious errors when calculating relative permeabilities. For these reasons, the JBN method (neglecting capillary pressure) does not apply. Therefore, the dynamic capillary pressure and capillary end effects should be taken into account. This work focuses on calculating two-phase relative permeability of ultra-low permeability reservoir through considering the dynamic capillary pressure and eliminating the influence of capillary end effects. Firstly, laboratory core scale measurements of in situ water phase saturation history based on X-ray CT scanning technique were used to estimate relative permeability. Secondly, a mathematical model of two-phase relative permeability considering the dynamic capillary pressure was established. The basic problem formulations, as well as the more specific equations, were given, and the results of comparison using experimental data are presented and discussed. Results indicate that the dynamic capillary pressure measured at laboratory core scale in ultra-low permeability rocks has a significant influence on the estimation of unsteady-state relative permeability. The mathematical calculating method was compared with the history matching method and the results were close, suggesting reliability for ultra-low permeability reservoirs. Importantly, the proposed methods allow measurement of relative permeability from a single experiment. Potentially this represents a great time savings.

Magnetic properties of epoxy-bonded iron–gallium particulate composites

This paper presents the production process and the results of investigations into the microstructure and magnetic properties of epoxy-bonded iron–gallium (Galfenol) particulate composites. The manufactured composites consist of powdered Fe80Ga20 alloy particles of three different size distributions (ranging from 20 to 200 μm), bonded in an epoxy matrix with a filling factor of 0.80. The filling factor is defined as the ratio of the volume of Fe–Ga powder to the total volume of the composite’s constituents. The microstructure of the powdered alloy has been examined using x-ray diffractometry (XRD), and Mössbauer spectroscopy. Results for the measured magnetic hysteresis loop (B–H curve), static magnetostriction (λ) versus applied field and dynamic relative permeability (μr33) are presented for the alloy in the forms of bulk material, powders and composites subsequently manufactured. The highest value of magnetostriction (360 ppm) has been found in the composite with grain size in the range of 50–100 μm. On reversing the magnetic field direction, large magnetostrictive hysteresis for these samples has been observed. The value of μr33 at a given applied magnetic bias field has been found to decrease with decreasing particle size.

Dynamic magnetoelastic properties of epoxy-bonded Sm0.88Nd0.12Fe1.93 pseudo-1-3 negative magnetostrictive particulate composite

Pseudo-1-3 negative magnetostrictive particulate composite is prepared by embedding and aligning light rare earth (Sm and Nd)-based negative magnetostrictive Sm0.88Nd0.12Fe1.93 particles with randomly distributed sizes of 10–180 μm in a passive epoxy matrix using a particle volume fraction of 0.5. The dynamic magnetoelastic properties of the composite are investigated as a function of both magnetic bias field and frequency under a constant magnetic drive field. The dynamic relative permeability (μr33) exhibits a flat frequency response with no observable dispersion at all bias field levels, except for the fundamental shape resonance range of 40–50 kHz. The free (μr33T) and clamped (μr33S) relative permeabilities attain their maximum values at low bias field levels of ≤10 kA/m because of the relatively easy 180° domain-wall motion. The elastic modulus at constant magnetic field strength (E3H) and that at constant magnetic flux density (E3B) show a maximum negative-ΔE effect, accompanying a maximum dynamic strain coefficient (d33) of −2 nm/A, at about 100 kA/m due to the maximum motion of non-180° domain walls.