Changes In Relative Permeability Research Articles

Water, Water Everywhere Using ML and Game Theory To Win at Produced-Water Forecasting

In the Bakken-Three Forks play of the Williston Basin, many oil wells that once produced some water have become water wells that produce some oil, as average oil production has flatlined while water production continues to increase. A complex interplay of stepping out beyond the core to where water saturations are higher, upsizing completions, tighter spacing, and dealing with greater parent-child effects and potential changes in relative permeability is significantly increasing volumes of produced water. Similar situations have been occurring in other basins. This is a serious threat for the US unconventional oil and gas industry, for which produced water has become a $34-billion industry and exposes operators to numerous operational, environmental, and economic risks. Software developers are beginning to adapt advanced machine-learning (ML) methods that have proved successful in forecasting oil production and upgrading them with aspects of game theory to make quick and accurate work of understanding and predicting water production in unconventional plays. Novi Labs (Novi), an Austin-based software company focusing on unconventional shale, has developed a solution that is being applied successfully in the Williston Basin to help disentangle the complex interactions of larger completion designs, changing geology, and tighter spacing that contribute to increased water production. According to the firm’s model, fluid per foot ranks as the most important input variable for increasing water production, ranking above proppant per foot and geologic parameters. Ted Cross, technical advisor at Novi and former senior geologist with Conoco Phillips, presented a paper that discussed the produced water challenge at the 2020 Unconventional Resources Technology Conference (URTeC). “How often does an engineer dash off a simple water forecast, doing something like applying a flat water-to-oil ratio to their water prediction?” Cross asked rhetorically. In unconventional oil fields, water forecasting and pre-drill water predictions have not received attention commensurate with their economic importance. “Quick is still common,” he said. Operators, regulators, and water-disposal companies often rely on simplistic water-cut ratios or basin-level extrapolations that ignore the complex interplay of geology, completions, and spacing decisions on water production. “They are starting to realize and incorporate the fact that water-to-oil ratios will evolve over a well’s life, usually increasing. But the critical thing is that the time they spend on water prediction is a tiny fraction of what they spend on oil, and the methods are less sophisticated and developed,” Cross said. Part of the reason, he explained, is that in the early development of the Eagle Ford, Permian, and some core parts of the Williston, either the original wells didn’t produce large volumes of water or the existing infrastructure around conventional plays was sufficient to handle it. But with field evolution and changing completion designs, water has become a critical issue.

Influence of crucial reservoir properties and microbial kinetic parameters on enhanced oil recovery by microbial flooding under nonisothermal conditions: Mathematical modelling and numerical simulation

In the present study, improved mathematical and numerical models are developed in order to simulate the influence of important reservoir (effective porosity and longitudinal dispersivity), fluid and microbial kinetic (Monod half-saturation constant, substrate to biomass yield coefficient and substrate inhibition) parameters on dynamics of in-Situ microbial enhanced oil recovery (MEOR) processes using Bacillus sp. in a typical sandstone reservoir. This numerical model is a novel attempt to consider the coupled effects of heat transport and substrate-inhibition kinetics on reactive-transport of microbes, substrates and biosurfactants as against the conventional models, thus making the prediction of MEOR processes more realistic and may assist in developing suitable strategies to enhance oil recovery at field scale. In addition, the present model also investigates the changes in relative permeabilities of reservoir fluids (oil and water) and fractional flow of water under the influence of nonisothermal condition, substrate inhibition, along with variations in pore-size distribution index, oil to water viscosity ratio and crude oil API gravity within reservoir during microbial flooding for estimating residual oil recovery. The present model results match significantly well, when verified, with the existing analytical and experimental results, thus proving the model's reliability. The results suggest that under nonisothermal conditions, biosurfactant production is maximum (77.8 mg ml−1) at effective reservoir porosity 23.4%, with low substrate half-saturation constant and high substrate-to-biomass yield coefficient values of 0.018 mg ml−1 and 0.8, respectively. Though biosurfactant production is reduced by more than 80% due to substrate inhibition, which is maximum at inhibition constant value 0.1 mg ml−1, residual oil-saturation is decreased by more than 90% at the end of MEOR process, thus enhancing oil displacement, mobility and hence, improved crude oil recovery. The reactive-transport of substrates, microbes and biosurfactants at injection mean fluid velocity of 1.68 m day−1, are also found to be highly sensitive to reservoir longitudinal dispersivity (αL) and maximum biosurfactants are produced (9.74 mg ml−1) at threshold αL value, 0.37 m, which corresponds to reservoir length of 50 m. Besides, a strategy is suggested to improve the oil recovery efficiency of the present in Situ MEOR approach by characterizing the reservoir for its pore size distribution index, and formation fluids (oil and water) for their viscosity ratios and crude oil API gravities, under nonisothermal and substrate inhibition conditions.

Magnetic-Signature Prediction for Efficient Degaussing of Naval Vessels

Accurate magnetic-signature prediction is the most challenging task in the path of active magnetic-signature minimization. This article discusses the effect of the change in hull thickness, relative permeability, and radius of the object, considering the detailed understanding of the magnetic signatures. The traditional magnetic experiment-based method using a 12-coil structure is implemented for a double hull vessel. However, the time required and effort involved in predicting the magnetic signature is much higher. Hence, a multiple linear regression-based statistical machine-learning (ML) technique for the magnetic signature prediction is proposed. The nonlinear magnetic behavior of the naval vessel is assumed to be linear, because the hysteresis curve in the range of the earth’s ambient field is linear. Hence, a linear relationship is developed between the magnetic signatures and each component of the ambient earth’s magnetic field. The ML-based model also considers the crosstalk among the longitudinal, athwartship, and vertical signatures. The predicted magnetic signatures using the ML technique and the experiment-based techniques are compared. The ML method is found to be accurate, fast, and precise compared with the laboratory-based method, which has strict and continuous requirements for hardware magnetic facility. This method is very simple to implement and directly contributes to the development of the real-time degaussing current calculation algorithm.

Experimental studies of shear-induced changes in two-phase relative permeability

Numerical reservoir simulation is often used as a tool to forecast the production performance of oil and gas fields. Multi-phase flow functions including relative permeability and capillary pressure relationships are important components for modeling fluid distribution and movement in a porous medium, and they are strongly influenced by the pore structure. Often, relative permeability curves are habitually modified, without consideration of geomechanics effects, during the history match process. However, the depletion or injection of oil and gas reservoirs generally alters the effective stress of the system as a result of either decreasing or increasing of pore pressure. This causes changes in grain arrangement or pore structure. In this paper, a series of isotropically consolidated drained triaxial compression tests were conducted to investigate the behavior of very dense, reconstituted specimens at low effective stress conditions. After restoring the specimens to the desired reservoir conditions, the specimens were sheared under a drained compression-loading path. At various levels of axial strain, steady-state process, absolute and relative permeability tests were performed. Our results showed that in two-phase flow, the oil relative permeability was more sensitive to stress in comparison to the water relative permeability. This change of oil relative permeability was up to about 30%. Also, it was noticed from preliminary capillary pressure measurements that both cycles of drainage were significantly affected by the shear-induced contractive and dilative volume changes. This study supports the notion that relative permeability curves, instead of being kept constant, should be updated depending on the in situ stress-strain behavior.

Simple Device to Measure Pressure Using the Stress Impedance Effect of Amorphous Soft Magnetic Thin Film.

A simple micro-machined pressure sensor, based on the stress-impedance (SI) effect, was fabricated herein using typical micro-fabrication technologies. To sense pressure, a 1-µm thin, soft magnetic metallic film of FeSiB was sputtered and used as a diaphragm. Its electrical response (impedance change) was measured under pressure in a frequency band from 5 to 500 MHz. A lumped-element equivalent electric circuit was used to separate the impedance of the soft magnetic metal from other parasitic elements. The impedance change clearly depended on the applied pressure. It was also shown that the impedance change could be explained by a change in relative permeability, according to the theory of the SI effect. The radial stress in the diaphragm and the relative permeability exhibited a linear relationship. At a measurement frequency of 200 MHz, the largest sensor response, with a gauge factor of 385.7, was found. It was in the same order as the conventional sensors. As the proposed device is very simple, it has the potential for application as a cheap pressure sensor.

An Analytical Model to Predict the Effects of Suspended Solids in Injected Water on the Oil Displacement Efficiency during Waterflooding

Suspended solids in the injection water cause impairment of water injectivity during waterflooding operations. Suspended solids affect reservoir properties and decrease the permeability of reservoir rocks causing an increase of injection pressure and a decrease in water injectivity. Removal of all suspended solids from injection water is an expensive and economically unfeasible process. To minimize the effects of suspended solids to the formation, it is necessary to determine an impairment mechanism of suspended solids on oil displacement and, therefore, optimize the water treatment process. In this paper, an analytical model that describes the relationship between injection water quality and impairment mechanisms on oil displacement is presented. A formation impairment was calculated, introducing the parameter called impairment ratio, which represents the ratio between suspended solids and pore size distribution of reservoir rock. Based on the impairment ratio, decreases in porosity and permeability were calculated with changes in capillary pressure, relative permeability, and displacement efficiency. The model was tested for three different types of injection water. Results indicated the presence of formation impairment even with the smallest particles. Suspended solids had the greatest influence on porosity and permeability impairment. The model could be used as input for reservoir modelling studies for monitoring and controlling displacement efficiency during waterflooding as well as for planning and modification of water treatment units.

The Hydraulic Profiling Tool for Hydrogeologic Investigation of Unconsolidated Formations

AbstractThe hydraulic profiling tool (HPT) has become one of the basic tools for investigation of soils and unconsolidated formations over the last 10 years. The HPT is advanced into the subsurface using direct push methods. Clean water is injected into the formation from a small screened port on the side of the probe as it is steadily advanced into the subsurface. A downhole pressure sensor detects the pressure required to inject the water into the formation while an up‐hole flowmeter monitors the water flow rate. An electrical conductivity (EC) array included in the lower end of the probe provides a simultaneous EC log of the bulk formation. The EC log, HPT pressure, and flow rate are logged and displayed onscreen as the probe is advanced. These logs enable the investigator to evaluate vertical changes in relative formation permeability at high resolution. Pressure dissipation tests may be performed at selected depths in coarse‐grained materials to determine the piezometric pressure in saturated formations. This enables the operator to define the piezometric profile and determine the piezometric surface without a well. Post processing of the log in the viewing software provides for calculation of the corrected HPT pressure (Pc) and estimation of hydraulic conductivity (Est. K) within limits (~0.1 to 75 ft/d). In clean, coarse‐grained materials the tandem EC log may be used to estimate groundwater specific conductance based on an Archie's Law model. Cross sections of HPT logs provide an efficient means to define hydrostratigraphy. When combined with contaminant logging tools such as the membrane interface probe (MIP) the HPT data may help to define contaminant migration pathways or contaminated low permeability zones that may result in back diffusion. The HPT can be a useful tool for many geoenvironmental investigations in unconsolidated formations.

Effects of geochemical reactions on multi-phase flow in porous media during CO2 injection

Impacts of fluid-rock geochemical reactions occurring during CO2 injection into underground formations, including CO2 geosequestration, on porosity and single-phase permeability are well documented. However, their impacts on pore structure and multiphase flow behaviour of porous media and therefore on CO2 injectivity and residual trapping potential are yet unknown. We found that CO2-saturated brine-rock interactions in a carbonate rock increased the grains roughness, increased the population of micro and macro pores and decreased the pore volume of medium size pores. These changes in pore structure led to a decrease in the sweep efficiency of the non-wetting phase (gas) during primary drainage. Furthermore, they led to an increase in the relative permeability of the non-wetting phase, a decrease in the relative permeability of the wetting phase (brine) and a reduction in the residual trapping potential of the non-wetting phase. The impacts of reactions on pore structure shifted the relative permeabilities cross point toward more water-wet condition. Finally, these reaction-induced pore structure changes caused a reduction in capillary pressure of the used carbonate rock. For CO2 underground injection applications, such changes in relative permeabilities, residual trapping potential of the non-wetting phase (CO2) and capillary pressure would reduce the CO2 storage capacity and increase the risk of CO2 leakage. Considering these fluid-rock reaction-induced changes is essential for accurate prediction/simulation of reservoir behaviour and risk analysis of the project.

Changes in multi-phase flow properties of carbonate porous media during CO2 injection

Impacts of fluid–rock geochemical reactions occurring during CO2 injection into underground formations, including CO2 geosequestration, on porosity and single-phase permeability are well documented. However, their impacts on pore structure and multi-phase flow behaviour of porous media and, therefore, on CO2 injectivity and residual trapping potential, are yet unknown. We found that CO2-saturated brine–rock interactions in a carbonate rock led to a decrease in the sweep efficiency of the non-wetting phase (gas) during primary drainage. Furthermore, they led to an increase in the relative permeability of the non-wetting phase, a decrease in the relative permeability of the wetting phase (brine) and a reduction in the residual trapping potential of the non-wetting phase. The impacts of reactions on pore structure shifted the relative permeability cross-point towards more water-wet condition. Finally, calcite dissolution caused a reduction in capillary pressure of the used carbonate rock. For CO2 underground injection applications, such changes in relative permeabilities, residual trapping potential of the non-wetting phase (CO2) and capillary pressure would reduce the CO2 storage capacity and increase the risk of CO2 leakage.

Modification of Relative Permeability Curves by ultrasonic Applications

Abstract Ultrasonic waves have been used for improved oil recovery especially from the marginal well in so many areas all over the world. The main mechanism is to supply oil molecules by energy to overcome capillary forces there by restructuring the relative permeability curves and increasing the oil mobility. Monitoring these changes is very important for increasing the oil mobility even after residual oil saturation achieved. The present work investigates the laboratory effects of ultrasonic waves on the relative permeability curves. Five sandstone and carbonate cores were used from Egyptian reservoirs. Their permeabilities range from 67 to 460 md. Acoustic ultrasonic waves of 500 KHZ have been applied. At this frequency, the fluid vibrates out of phase with the solid and is forced out through the pore structure in the agglomerate. This relative fluid motion exerts high viscous stresses at the particle-particle contact points which leads to fracture of the agglomerate and the dispersion of the individual particles. This interaction causes changes in relative permeability of the rock to oil and water. Therefore, the results showed that applying ultrasonic waves has a higher effect in permeability reservoirs (76 md to 460 md) and can mobilize additional quantity of crude oil. The fractional flow curve changes are also addressed and analyzed after wave applications. The aim of this research is to investigate the effect of the ultrasonic wave as a new proposed method to improve oil recovery by changing the relative permeability curves of the reservoirs.

Investigation of effect of stress on eddy current response using phase diagram

This paper presents determination of the stress state of steel bridges, due to stress redistribution because of corrosion or cracking, as a new important parameter in structural health monitoring for evaluating their condition. For this, eddy current testing is used to investigate the effect of change in stress in a steel plate through three-dimensional numerical simulations carried out in the FE software, COMSOL Multiphysics 5.2a. A reflection probe, comprising of an outer exciting coil and an inner detecting coil, is used to characterize the eddy current indices - real, imaginary, and absolute voltages, and phase with respect to the change in relative permeability, which is dependent on stress, lift-off, exciting frequency, and probe size. A new concise method of simultaneously representing the effects of relative permeability and lift-off at an excitation frequency, termed as Phase diagram, is then proposed, which is further used for selection of suitable probe size and excitation frequency for eddy current based stress measurement. It is found that larger probes and lower excitation frequencies are preferable, because of better sensitivity of larger probes to significant lift-offs and uniform trend of change of eddy current indices at lower frequency, requisite of calibration.

Comparison of plasma membrane H+-ATPase response to acid rain stress between rice and soybean.

Acid rain is a global environmental issue due to inhibiting severely plant growth and productivity. To discover the tolerant mechanism in plants under acid rain stress, we studied the difference in response of two crops (rice and soybean) to simulated acid rain (pH5.0 ~ 2.5) at growth and physiological, biochemical and molecular levels during exposure and recovery periods by hydroponics. By analyzing the change in relative growth rate, chlorophyll content and plasma permeability in rice and soybean, we found that rice could tolerate acid rain above pH3.0 whereas soybean could tolerate acid rain above pH4.5. By RT-PCR analyses, immunoprecipitation and enzyme kinetics study, we observed that pH4.5 acid rain promoted the transcriptional expression of H+-ATPase genes and the phosphorylation of H+-ATPase and increased H+-ATPase activity in the two crops for resisting acid stress. The increased degree in soybean was larger than that in rice. Acid rain at pH3.0 still promoted the transcription regulation to maintain H+-ATPase activity higher in rice for resisting stress but caused irreversible inhibition on express of H+-ATPase and decreased H+-ATPase activity in soybean. All results suggest that the different tolerance in rice and soybean to acid rain stress could be associated with difference in plasma membrane H+-ATPase at transcriptional regulation, post-translational modification and the substrate affinity.

An Improved Relative Permeability Model for Gas-Water Displacement in Fractal Porous Media

Many researchers have revealed that relative permeability depends on the gas-water-rock interactions and ultimately affects the fluid flow regime. However, the way that relative permeability changes with fractal porous media has been unclear so far. In this paper, an improved gas-water relative permeability model was proposed to investigate the mechanism of gas-water displacement in fractal porous media. First, this model took the complexity of pore structure, geometric correction factor, water film, and the real gas effect into account. Then, this model was compared with two classical models and verified against available experimental data. Finally, the effects of structural parameters (pore-size distribution fractal dimension and tortuosity fractal dimension) on gas-water relative permeability were investigated. It was found that the sticking water film on the surface of fracture has a negative effect on water relative permeability. The increase of geometric correction factor and the ignorance of real gas effect cause a decrease of gas relative permeability.

Observations during suction bucket installation in sand

Suction buckets represent a viable solution as foundations for offshore wind turbines. Installation in sand is relatively straightforward, albeit with limited understanding of the resulting changes in soil state. This paper describes an experimental methodology that allows for visualisation and quantification of changes in soil state during suction bucket installation, validated in sand. Insights obtained from particle image velocimetry analyses, performed on images of a half-bucket installing against a Perspex window taken in a geotechnical centrifuge are discussed. Compared with the initial self-weight penetration, the deformation mechanism governing the suction-assisted phase shows a preference for the soil below the skirt tips to move inwards and upwards inside the bucket. The installation process is responsible for changes in relative density and permeability within the bucket. In these experiments, the majority of the soil plug heave can be attributed to the soil displaced inwards by the advancing skirts, with a minor contribution caused by dilation. The confidence in the experimental methodology provided through the results of suction bucket installation in sand discussed herein now enables suction bucket installation in more complex seabeds to be investigated.

Gas Relative Permeability and its Evolution During Water Imbibition in Unconventional Reservoir Rocks: Direct Laboratory Measurement and a Conceptual Model

SummaryRelative permeability has a significant impact on gas or oil and water production, and is one of the most complicated properties in unconventional reservoirs. Current understanding of relative permeability for unconventional reservoir rocks is limited, mainly because of a lack of direct measurement of relative permeability for rocks that have a matrix permeability at the submicrodarcy level. Because of the difficulties related to direct measurement, most studies on relative permeability in unconventional reservoirs are based on indirect or modeling methods. In this paper, a modified gas–expansion method for shale matrix–permeability measurement (Peng et al. 2019) was adopted to measure gas relative permeability directly under the scenario of water imbibition for samples from different unconventional reservoir formations. Evolution of gas permeability, along with gas porosity and fracture/matrix interaction, during the process of water redistribution (which mimics what occurs in the shut–in period in real production) was also closely measured. Results show that gas relative permeability in the matrix decreases during water redistribution because of water imbibition from fractures to the matrix coupled with a water–block effect. The water–block effect is more significant at low water saturations than at higher water saturations, leading to a rapid–to–gradual drop of gas relative permeability with increasing water saturation.A conceptual model on water redistribution in a fracture/matrix system and the change of gas and water relative permeability is proposed on the basis of experimental results and observations. Influencing factors including pore size, shape, connectivity, and wettability are taken into account in this conceptual model. The combined effect of these four influencing factors determines the level of residual gas saturation, which is the most important parameter in defining the shape of relative permeability curves. Water relative permeability is predicted on the basis of the conceptual model and the measured gas relative permeability using modified Brooks–Corey equations. Deducing the oil/water relative permeability is also discussed. The implications of relative permeability for gas or oil and water production and potential strategies for optimal production are also discussed in the paper. The hysteresis effect is not included in this study but will be addressed in future work.

Effect of Aluminum and Zinc Nanoparticles on Improving Wettability Conditions in Situ Oil Recovery in Carbonate and Sandstone Reservoirs

The petroleum is a major source of energy of this era. With daily increase in energy demand, new methodologies are proposed to increase recovery factors in petroleum reservoirs. With increasing cumulative production and pressure drop, the wettability of reservoirs are changed to be oil-wet. Accordingly, one way to increase recovery factor from the reservoirs is to change the wettability of the reservoir rock from oil-wet to water-wet using nanoparticles. In this paper the change in relative permeability due to injection of two Nanoparticles, Zinc and Aluminum, is investigated. Two cases of vertical and horizontal wells are considered and the recovery factors are determined and compared. The tests are performed for a five spot injection-production pattern which is designed for simulation in the Eclipse software. The results indicate that of the injection of the Zinc Nanoparticle in the reservoir will lead to increase in recovery factor in a shorter period of time in comparison with the Aluminum Nanoparticle.

Experimental investigation of effect of asphaltene deposition on oil relative permeability, rock wettability alteration, and recovery in WAG process

Asphaltene deposition is considered to be one of the most problems during oil productions. This work describes the effect of asphaltene precipitation and deposition on relative permeability of reservoir rock during water alternating gas (WAG) injection process. The main objective of this work is experimental investigating of relative permeability change of reservoir fluid due to asphaltene deposition on application of WAG process by use of core flood setup. Result of this paper investigate the relative permeability change during WAG process with different asphaltene content that help to make better development decisions for a reservoir with fluid with specific asphaltene content.

The Study of Flow Characteristics During the Decomposition Process in Hydrate-Bearing Porous Media Using Magnetic Resonance Imaging

The flow characteristics during decomposition of hydrate-bearing sediments are the most critical parameters for the gas recovery potential from natural gas hydrate reservoirs. The absolute and relative permeability and the flow field distribution during the decomposition process of hydrate-bearing porous media synthetically created by glass beads are in-situ measured by using magnetic resonance imaging. The absolute permeability value increased slowly, then became stable after the decomposition amount was 50%. The relative permeability change curve is a typical X-shaped cross curve. As the hydrate decomposed, the relative permeability values of the two phases increased, the range of the two-phase co-infiltration zone increased with the increase of relative permeability at the endpoint, and the coexistence water saturation decreased. At the beginning of the decomposition, (hydrate content 100% to 70%), the relative permeability of methane and water rose rapidly from 22% to 51% and from 58% to 70%, respectively. When the amount of the remaining hydrate was less than 50%, the relative permeability curve of the hydrate-bearing glass beads almost kept unchanged. During the hydrate decomposition process, the velocity distribution was very uneven and coincided with the porous media structure.

Comprehensive study of the interactions between the critical dimensionless numbers associated with multiphase flow in 3D porous media

Multiphase flow in porous media is of great interest in many engineering applications, such as geologic carbon sequestration, enhanced oil recovery, and groundwater contamination and remediation. In order to advance the fundamental understanding of multiphase flow in complex three-dimensional (3D) porous media, the interactions between the critical dimensionless numbers, including the contact angle, viscosity ratio, and capillary (Ca) number, were investigated using X-ray micro-computed tomography (micro-CT) scanning and lattice Boltzmann (LB) modeling. In this study, the 3D pore structure information was extracted from micro-CT images and then used as interior boundary conditions of flow modeling in a pore-scale LB simulator to simulate multiphase flow within the pore space. A Berea sandstone sample was scanned and then two-phase flow LB simulations were performed based on the micro-CT images. The LB-simulated water/CO2 distributions agreed well with the micro-CT scanned images. Simulation results showed that a decreasing contact angle causes a decrease in wetting-fluid relative permeability and an increase in non-wetting fluid relative permeability. A rising Ca number increases both wetting and non-wetting fluid relative permeabilities. An increasing viscosity ratio (the ratio of non-wetting fluid viscosity to wetting fluid viscosity) facilitates the increase of non-wetting fluid relative permeability and mitigates the reduction of wetting fluid relative permeability, when the contact angle decreases continuously. The primary novel finding of this study is that the viscosity ratio affects the rate of change of the relative permeability curves for both phases when the contact angle changes continuously. To the best of our knowledge, it is the first time that comprehensive interactions between these dimensionless numbers are demonstrated in a sandstone sample based on real 3D structures. We also investigated the role of the changes of flow direction and sample location on relative permeability curves. Simulation results showed that the change in non-wetting fluid relative permeability was larger when the flow direction was switched from vertical to horizontal, which indicated that there was stronger anisotropy in larger pore networks that were primarily occupied by the non-wetting fluid.

Strain Energy Based Method for Metal Magnetic Memory Effect of Tensile Tested Structures

The metal magnetic memory (MMM) technique has been widely regarded as an effective method to locate stress concentration zones and to identify structural defects. To study its applicability in prognostics of structure damage, a series of static tensile tests and MMM measurement were carried out on the commonly used Q235 steel. The experimental results show that the normal component of self-magnetic-flux-leakage signals \(H_p^z\) is linear with the position in loading direction x and the gradient \(G_{z,x}\) increases with an increase in the external load. 2D magnetostatic finite element analyses indicate that the variations of \(G_{z,x}\) should be due to the change in relative permeability of the specimen after the effect of mechanical loading under geomagnetic field. The strain energy density in the structure during loading is found to be exponentially determined by \(G_{z,x}\) with an adjusted R-squared value of 0.9984. The monotonous correlation enables prediction of structure damage using the MMM technique.