scholarly journals Effect of Thermal Exposure on Oil Shale Saturation and Reservoir Properties

2020 ◽  
Vol 10 (24) ◽  
pp. 9065
Author(s):  
Aliya Mukhametdinova ◽  
Polina Mikhailova ◽  
Elena Kozlova ◽  
Tagir Karamov ◽  
Anatoly Baluev ◽  
...  
Keyword(s):  
Organic Matter ◽  
Organic Matter Content ◽  
Thermal Exposure ◽  
Rock Properties ◽  
Reservoir Properties ◽  
Rock Samples ◽  
The Core ◽  
Core Samples ◽  
Before And After ◽  
Porosity And Permeability

The experimental and numerical modeling of thermal enhanced oil recovery (EOR) requires a detailed laboratory analysis of core properties influenced by thermal exposure. To acquire the robust knowledge on the change in rock saturation and reservoir properties, the fastest way is to examine the rock samples before and after combustion. In the current paper, we studied the shale rock properties, such as core saturation, porosity, and permeability, organic matter content of the rock caused by the combustion front propagation within the experimental modeling of the high-pressure air injection. The study was conducted on Bazhenov shale formation rock samples. We reported the results on porosity and permeability evolution, which was obtained by the gas pressure-decay technique. The measurements revealed a significant increase of porosity (on average, for 9 abs. % of porosity) and permeability (on average, for 1 mD) of core samples after the combustion tube experiment. The scanning electron microscopy showed the changes induced by thermal exposure: the transformation of organic matter with and the formation of new voids and micro and nanofractures in the mineral matrix. Low-field Nuclear Magnetic Resonance (NMR) was chosen as a primary non-disruptive tool for measuring the saturation of core samples in ambient conditions. NMR T1–T2 maps were interpreted to determine the rock fluid categories (bitumen and adsorbed oil, structural and adsorbed water, and mobile oil) before and after the combustion experiment. Changes in the distribution of organic matter within the core sample were examined using 2D Rock-Eval pyrolysis technique. Results demonstrated the relatively uniform distribution of OM inside the core plugs after the combustion.

scholarly journals THE INFLUENCE OF ROCK LITHOGENESIS TYPES ON POROSITY AND PERMEABILITY (THE CASE OF PERMOCARBONIFEROUS DEPOSIT OF THE USINSKOYE FIELD)

2020 ◽  
Vol 20 (2) ◽  
pp. 104-114
Author(s):  
Nikita A. Popov ◽  
◽  
Ivan S. Putilov ◽  
Anastasiia A. Guliaeva ◽  
Ekaterina E. Vinokurova ◽  
...  
Keyword(s):  
Physical Parameters ◽  
Void Space ◽  
Reservoir Properties ◽  
Full Size ◽  
The Core ◽  
Core Samples ◽  
Porosity And Permeability ◽  
Research Findings ◽  
Influence Of Properties ◽  
First Time

The paper analyzes a methodology aimed at differentiation of porosity, permeability and petrographic properties depending on facies attributes. Based on the Dunham classification, we offer in-depth studies of the influence of rock fabric, including full-size core samples, on changes in porosity and permeability. The work deals with the Permo-Carboniferous deposit of the Usinskoye field. Reservoir properties of the considered strata are highly heterogeneous. Along with highly porous and cavernous rocks, there are low porous and fractured varieties in the section, which refer to rocks of various lithological compositions. The porosity and permeability properties were analysed for more than 9,000 standard core samples and approximately 1,000 full-size core samples, taking into account the scale factor and including microfractures, large caverns and rock matrix, commensurable with the sample sizes.The analysis of the maximum variation range is of particular importance for structurally complex carbonate reservoirs. Furthermore, based on the conducted lithologic, petrographic and petrophysical studies, the authors identified four types of reservoirs and eight different types of lithogenesis, as well as estimated geological and physical parameters for each of them. Based on the cumulative correlation plots, four zones of heterogeneity were identified. They are subject to the influence of properties of the core samples of different lithogenesis types. This is the first time that the influence of various petrotypes/lithotypes on changes in the reservoir porosity and permeability has been studied for the Usinskoye field based on the petrographic and petrophysical research findings. All the conducted experiments show that the rocks of the Permo-Carboniferous deposit of the Usinskoye field are extremely heterogeneous in their permeability properties that vary much. Thus, it is necessary to differentiate the core-to-core petrophysical correlations depending on a void space fabric and lithology of rocks.

Microstructure and composition of the periderm of conulariids

2016 ◽  
Vol 90 (3) ◽  
pp. 389-399 ◽  
Author(s):  
Robert C. Ford ◽  
Heyo Van Iten ◽  
George R. Clark
Keyword(s):  
Organic Matter ◽  
Organic Matter Content ◽  
Matter Content ◽  
Mineral Matter ◽  
Upper Ordovician ◽  
The Core ◽  
Critical Point Drying ◽  
Thin Walled ◽  
Electron Imaging ◽  
Aperture Closure

AbstractTransmitted light and scanning electron imaging of sectioned specimens ofConulariaandParaconularia, prepared using HCl etching and critical point drying, revealed that their periderm is composed of extremely thin (approximately 0.5–3 µm), variably distinct microlamellae that are alternately organic poor and organic rich. Organic-rich microlamellae are cross-connected by slender strands of organic matter originally embedded in calcium phosphate, which in etched specimens has been dissolved. Microlamellae may be organized in thicker (approximately 5–75 µm) layers, or macrolamellae, that vary in color and organic matter content, possibly owing to changes in the ambient paleoenvironment. Thickening of the periderm to form transverse ribs and internal carinae was achieved through gradual thickening of individual microlamellae. In the core of the transverse ribs and internal carinae the distinction between organic-rich and organic-poor microlamellae may be reduced, owing to organic material becoming dominant over (former) mineral matter or vice versa. Combined with observations of plicated aperture closure in thin-walled conulariids, includingArchaeoconularia slateri(Reed, 1933) (Upper Ordovician, Scotland) showing smooth folding of midline carinae through angles greater than 90°, these results suggest a structure and original flexibility in the organic-rich biocomposite forming the conulariid periderm that supports its homology to the chitinous lamellar periderm of coronate scyphozoans.

Factors Controlling Porosity Permeability Relationship for Reservoir Quality Prediction: A Case Study of Malay Basin Reservoir, Malaysia

2021 ◽  
Author(s):  
Fadzlin Hasani Kasim ◽  
Budi Priyatna Kantaatmadja ◽  
Wan Nur Wan M Zainudin ◽  
Amita Ali ◽  
Hasnol Hady Ismail ◽  
...  
Keyword(s):  
Reservoir Characterization ◽  
Visual Analysis ◽  
Mineral Dissolution ◽  
Rock Properties ◽  
Reservoir Quality ◽  
Hydrocarbon Potential ◽  
Lower Grade ◽  
Reservoir Properties ◽  
Reservoir Evaluation ◽  
Porosity And Permeability

Abstract Predicting the spatial distribution of rock properties is the key to a successful reservoir evaluation for hydrocarbon potential. However, a reservoir with a complex environmental setting (e.g. shallow marine) becomes more challenging to be characterized due to variations of clay, grain size, compaction, cementation, and other diagenetic effects. The assumption of increasing permeability value with an increase of porosity may not be always the case in such an environment. This study aims to investigate factors controlling the porosity and permeability relationships at Lower J Reservoir of J20, J25, and J30, Malay Basin. Porosity permeability values from routine core analysis were plotted accordingly in four different sets which are: lithofacies based, stratigraphic members based, quartz volume-based, and grain-sized based, to investigate the trend in relating porosity and permeability distribution. Based on petrographical studies, the effect of grain sorting, mineral type, and diagenetic event on reservoir properties was investigated and characterized. The clay type and its morphology were analyzed using X-ray Diffractometer (XRD) and Spectral electron microscopy. Results from porosity and permeability cross-plot show that lithofacies type play a significant control on reservoir quality. It shows that most of the S1 and S2 located at top of the plot while lower grade lithofacies of S41, S42, and S43 distributed at the middle and lower zone of the plot. However, there are certain points of best and lower quality lithofacies not located in the theoretical area. The detailed analysis of petrographic studies shows that the diagenetic effect of cementation and clay coating destroys porosity while mineral dissolution improved porosity. A porosity permeability plot based on stratigraphic members showed that J20 points located at the top indicating less compaction effect to reservoir properties. J25 and J30 points were observed randomly distributed located at the middle and bottom zone suggesting that compaction has less effect on both J25 and J30 sands. Lithofacies description that was done by visual analysis through cores only may not correlate-able with rock properties. This is possibly due to the diagenetic effect which controls porosity and permeability cannot visually be seen at the core. By incorporating petrographical analysis results, the relationship between porosity, permeability, and lithofacies can be further improved for better reservoir characterization. The study might change the conventional concept that lower quality lithofacies does not have economic hydrocarbon potential and unlock more hydrocarbon-bearing reserves especially in these types of environmental settings.

Petrophysical Changes of Sandstone Due to Salt Precipitation and Fines Migration During Carbon Dioxide Injection

2020 ◽  
Vol 17 (2) ◽  
pp. 1207-1213 ◽  
Author(s):  
Muhammad Aslam Md Yusof ◽  
Mohamed Zamrud Zainal ◽  
Ahmad Kamal Idris ◽  
Mohamad Arif Ibrahim ◽  
Shahrul Rizzal M. Yusof ◽  
...  
Keyword(s):  
Carbon Dioxide ◽  
Damage Mechanism ◽  
Salt Precipitation ◽  
Carbon Dioxide Injection ◽  
Fines Migration ◽  
Flow Rates ◽  
The Core ◽  
Core Samples ◽  
Sandstone Rock ◽  
Porosity And Permeability

Sequestration of Carbon Dioxide (CO2) in sandstone formation filled by brine aquifers is widely considered a promising option to reduce the CO2 concentration in the atmosphere. However, the injection of reactive CO2 into sandstone rock creates injectivity problems because of CO2-brine-rock interactions. The injection flow rate and CO2-fluid-rock exposure conditions are important factors that control the intensity of the reactions. The focus of this research was therefore on evaluating the petrophysical modifications in sandstone core samples at distinct flow rates using different CO2 injection schemes. In this research, the porosity and permeability of Berea sandstone samples were measured using PoroPerm equipment. The core samples were initially saturated with dead brine (30 g/l NaCl) followed by injection either by supercritical CO2 (scCO2) only, CO2-saturated brine only and CO2-saturated brine together with scCO2 at different flow rates. During injection, the differential pressure between the core inlet face and outlet face were recorded. Fines from the produced effluent were separated and collected for characterization using Field Emission Scanning Electron Microscope and Energy Dispersive X-ray Spectroscopy (FESEM-EDX). Post-injection porosity and permeability of the core samples were measured and compared with the pre-injection data to monitor changes. All sandstone core specimens showed favorable storage capability features in the form of capillary residual trapping with residual CO2 saturation ranging from 40% to 48%. In addition, all samples experienced important changes in their petrophysical characteristics, which were more pronounced in the event of absolute porosity and permeability, which decreased from 20%–51% to 4%–32%. The suggested harm mechanism is primarily owing to salt precipitation and fines migration. Supported by FESEM images, the proposed damage mechanism is mainly due to salt precipitation and fines migration.

scholarly journals Sedimentology, geochemistry and reservoir properties of Upper Jurassic deep marine sediments (Hareelv Formation) in the Blokelv-1 borehole, Jameson Land Basin, East Greenland

2018 ◽  
pp. 39-64
Author(s):  
Morten Bjerager ◽  
Claus Kjøller ◽  
Mette Olivarius ◽  
Dan Olsen ◽  
Niels H. Schovsbo
Keyword(s):  
Oxygen Depletion ◽  
Upper Jurassic ◽  
High Density ◽  
Core Analysis ◽  
Reservoir Properties ◽  
East Greenland ◽  
Sea Floor ◽  
The Core ◽  
Trace Metal Content ◽  
Porosity And Permeability

The fully cored Blokelv-1 borehole was drilled through Upper Jurassic strata in the central part of the Jameson Land Basin, central East Greenland. The borehole reached a total depth of 233.8 m with nearly 100% recovery of high-quality core. An extensive analytical programme was undertaken on the core; sedimentological interpretation and reservoir characterisation were based on facies analysis combined with conventional core analysis, bulk geochemistry and spectral gamma and density scanning of the core. The Upper Jurassic Hareelv Formation was deposited in relatively deep water in a slope-to-basin setting where background sedimentation was dominated by suspension settling of organic-rich mud in oxygen-depleted conditions. Low- and high-density gravity-flow sandstone interbeds occur throughout the cored succession. About two-thirds of the high-density turbidite sandstones were remobilised and injected into the surrounding mud-rock. The resulting succession comprises nearly equal amounts of mudstones and sandstones in geometrically complex bodies. Ankerite cementation occurs in 37% of the analysed sandstones in varying amounts from minor to pervasive. Such ankerite-cemented sandstones can be identified by their bulk geochemistry where Ca > 2 wt%, Mg > 1 wt% and C > 1 wt%. The analysed mudstones are rich in Al, Fe, Ti and P and poor in Ca, Mg, Na and Mn. The trace-metal content shows a general increase in the upper part of the core reflecting progressive oxygen depletion at the sea floor. The reservoir properties of the Blokelv-1 sandstones were evaluated by both conventional core analysis and using log-derived porosity and permeability curves. The high-density turbidite beds and injectite bodies are a few centimetres to several metres thick and show large variations in porosity and permeability, in the range of 6–26 % for porosity and 0.05–400 mD for permeability. Individual sandstone units that are 1–7 m thick yield a net vertical reservoir thickness of 40 m with porosities of 15–26% and permeabilities of 1–200 mD. Heterolithic sandstone–mudstone units are generally characterised by poor reservoir quality with porosities of 2–14% and permeabilities of 0.1–0.6 mD.

scholarly journals Porosity and Permeability Measurements Integration of The Upper Cretaceous in Balad Field, Central Iraq

2021 ◽  
Vol 54 (1B) ◽  
pp. 24-42
Author(s):  
Fawzi Al-Beyati
Keyword(s):  
Image Analysis ◽  
Log Analysis ◽  
Core Analysis ◽  
Well Log ◽  
Reservoir Properties ◽  
Thin Sections ◽  
Core Samples ◽  
Porosity And Permeability ◽  
Well Log Analysis ◽  
Porosity Range

The corrected porosity image analysis and log data can be used to build 3D models for porosity and permeability. This can be much realistic porosity obtainable because the core test data is not always available due to high cost which is a challenge for petroleum companies and petrophysists. Thus, this method can be used as an advantage of thin section studies and for opening horizon for more studies in the future to obtain reservoir properties. Seventy-two core samples were selected and the same numbers of thin sections were made from Khasib, Sa`di, and Hartha, formations from Ba-1, Ba-4, and Ba-8 wells, Balad Oilfield in Central Iraq to make a comprehensive view of using porosity image analysis software to determine the porosity. The petrophysical description including porosity image analysis was utilized and both laboratory core test analysis and well log analysis were used to correct and calibrate the results. The main reservoir properties including porosity and permeability were measured based on core samples laboratory analysis. The results of porosity obtained from well log analysis and porosity image analysis method are corrected by using SPSS software; the results revealed good correlation coefficients between 0.684 and 0.872. The porosity range values are 9-16% and 9-27% for Khasib and Sa’di in Ba-1 Well, respectively; 10-21%, 9-25%, and 16-27% for Khasib, Sa’di and Hartha in Ba-4 Well, respectively; and 11-24% and 15-24% for Khasib and Hartha in Ba-8 Well, respectively according to petrographic image analysis. By using the laboratory core analysis, the porosity range values are 12-26% and 17-24% for Khasib and Sa’di in Ba-1 Well, respectively; 6-28% and 14-27% for Sa’di and Hartha in Ba-4 Well, respectively; and 17-19% and 15-24% for Sa’di and Hartha in Ba-8 Well, respectively. Finally, the well log analysis showed that the porosity range values are 11-16% and 7-27% for Khasib and Sa’di in Ba-1 Well, respectively; 4-18%, 21-26%, and 16-19% for Khasib, Sa’di and Hartha in Ba-4 Well, respectively; and 9-24% and 15-23% for Khasib and Hartha in Ba-8 Well, respectively. The permeability range values based on laboratory core analysis are 1.51-8.97 md and 0.29-2.77 md for Khasib and Sa’di in Ba-1 Well, respectively; 0.01-24.5 md and 0.28-6.47 md for Sa’di and Hartha in Ba-4 Well, respectively; and 0.86-2.25 md and 0.23-3.66 for Sa’di and Hartha in Ba-8 Well, respectively.

scholarly journals Petrophysical and mechanical rock property database of the Los Humeros and Acoculco geothermal fields (Mexico)

2020 ◽  
Author(s):  
Leandra M. Weydt ◽  
Ángel Andrés Ramírez-Guzmán ◽  
Antonio Pola ◽  
Baptiste Lepillier ◽  
Juliane Kummerow ◽  
...  
Keyword(s):  
Geothermal Field ◽  
Heat Extraction ◽  
Rock Properties ◽  
Triaxial Tests ◽  
Petroleum Reservoir ◽  
Thin Sections ◽  
Rock Property ◽  
Rock Samples ◽  
Core Samples ◽  
Reservoir Assessment

Abstract. Petrophysical and mechanical rock properties are key parameters for the characterization of the deep subsurface in different disciplines such as geothermal heat extraction, petroleum reservoir engineering or mining. They are commonly used for the interpretation of geophysical data and the parameterization of numerical models and thus are the basis for economic reservoir assessment. However, detailed information regarding petrophysical and mechanical rock properties for each relevant target horizon are often scarce, inconsistent or distributed over multiple publications. Therefore, subsurface models are often populated with generalized or assumed values resulting in high uncertainties. Furthermore, diagenetic, metamorphic and hydrothermal processes significantly affect the physiochemical and mechanical properties often leading to a high geological variability. A sound understanding of the controlling factors is needed to identify statistical and causal relationships between the properties as a basis for a profound reservoir assessment and modeling. Within the scope of the GEMex project (EU-H2020, GA Nr. 727550), which aims to develop new transferable exploration and exploitation approaches for enhanced and super-hot unconventional geothermal systems, a new workflow was applied to overcome the gap of knowledge of the reservoir properties. Two caldera complexes located in the northeastern Trans-Mexican Volcanic Belt – the Acoculco and Los Humeros caldera – were selected as demonstration sites. The workflow starts with outcrop analogue and reservoir core sample studies in order to define and characterize the properties of all key units from the basement to the cap rock as well as their mineralogy and geochemistry. This allows the identification of geological heterogeneities on different scales (outcrop analysis, representative rock samples, thin sections and chemical analysis) enabling a profound reservoir property prediction. More than 300 rock samples were taken from representative outcrops inside of the Los Humeros and Acoculco calderas, the surrounding areas and from exhumed fossil systems in Las Minas and Zacatlán. Additionally, 66 core samples from 16 wells of the Los Humeros geothermal field and 8 core samples from well EAC1 of the Acoculco geothermal field were collected. Samples were analyzed for particle and bulk density, porosity, permeability, thermal conductivity, thermal diffusivity, heat capacity, as well as ultra-sonic wave velocities, magnetic susceptibility and electric resistivity. Afterwards, destructive rock mechanical tests (point load tests, uniaxial and triaxial tests) were conducted to determine tensile strength, uniaxial compressive strength, Young’s modulus, Poisson’s ratio, bulk modulus, shear modulus, fracture toughness, cohesion and friction angle. In addition, XRD and XRF analyses were performed on 137 samples to provide information about the mineral assemblage, bulk geochemistry and the intensity of hydrothermal alteration. An extensive rock property database was created (Weydt et al. 2020, http://dx.doi.org/10.25534/tudatalib-201.2), comprising 34 parameters determined on more than 2,160 plugs. More than 31,000 data entries were compiled covering volcanic, sedimentary, metamorphic and igneous rocks from different ages (Jurassic to Holocene), thus facilitating a wide field of applications regarding resource assessment, modeling and statistical analyses.

scholarly journals Study of the lithological characteristics of Domanic deposits of the Pervomayskoe field

Georesursy ◽  
2018 ◽  
Vol 20 (4) ◽  
pp. 324-330
Author(s):  
A. Takhauov ◽  
A. Titov
Keyword(s):  
Organic Matter ◽  
Microscopic Analysis ◽  
Oil Field ◽  
Core Material ◽  
Sharp Change ◽  
Reservoir Properties ◽  
The Core ◽  
The North ◽  
Lithological Composition ◽  
Rock Eval

The paper presents the results of studying rocks of the domanic horizon of the Pervomayskoe oil field represented by core material of the well 467D. In tectonic terms, this well, like the entire Pervomayskoe field, is confined to the axial part of the Kama-Kinel deflection system on the territory of the North-Tatar arch. Administratively, the Pervomayskoe deposit is located on the territories of the Elabuga, Mendeleevsky and Tukaevsky districts of the Republic of Tatarstan. To study the core material presented, different studies were conducted, including a macroscopic description of the core; comparison of the studied rocks with well logging data; optical microscopic analysis; X-ray analysis; determination of reservoir properties of rocks; study of organic matter by the Rock-Eval pyrolysis method. Based on the analysis, it was found that the domanic horizon is composed of rocks containing carbonate and siliceous minerals to varying degrees, occasionally including minor mixtures of other minerals. The section of rocks is characterized by a sharp change in the lithological composition with a thickness of interlayers of several centimeters. According to Rock-Eval data, carbonate-siliceous interlayers have a high content of organic matter. Organic matter in Domanic deposits is characterized as immature and is found in rocks in the form of kerogen.

scholarly journals Evaluation of the thermal effect potential for Bazhenov formation production stimulation based on the experimental data

2017 ◽  
pp. 39-47
Author(s):  
A. A. Erofeev ◽  
A. A. Pachezhercev ◽  
I. A. Karpov ◽  
N. V. Morozov ◽  
A. G. Kalmykov ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Thermal Exposure ◽  
Temperature Treatment ◽  
Fracture System ◽  
Reservoir Pressure ◽  
Bazhenov Formation ◽  
Core Samples ◽  
Recovery Treatment ◽  
Porosity And Permeability ◽  
Scanning Electron

In this paper the temperature treatment impact on Bazhenov formation core samples are shown. Impact was performed by pyrolysis in a temperature range of 300-480 °C and in the closed autoclave in the presence of water at reservoir pressure. It is shown that as a result of thermal exposure at 400 °C pyrolytic peak S2 is reduced by 90-95% and generation potential of rocks almost completely implemented. The microtomographic samples studies combined with scanning electron microscopy allowed to establish the dependence of permeability and porosity of the rocks. It demonstrated that even at 350 °C the fracture system formed in core samples also the porosity and permeability due to impact may increase from several times to several ten times. The results will allow for a more accurate simulation of enhanced oil recovery treatment on Bazhenov formation rocks to increase oil recovery.

The First Visualization of Acid Treatments on Carbonates With 3D Nuclear-Magnetic-Resonance Imaging

SPE Journal ◽  
2015 ◽  
Vol 20 (04) ◽  
pp. 678-688 ◽  
Author(s):  
M.. Krebs ◽  
B.. Lungwitz ◽  
A.. Souza ◽  
A.. Pépin ◽  
S.. Montoya ◽  
...  
Keyword(s):  
Magnetic Resonance Imaging ◽  
Nuclear Magnetic Resonance ◽  
Magnetic Resonance ◽  
Nuclear Magnetic Resonance Imaging ◽  
Resonance Imaging ◽  
Core Flow ◽  
Rock Samples ◽  
The Core ◽  
Core Samples ◽  
Nuclear Magnetic

Summary Carbonate reservoirs often show great heterogeneity in their inner rock structure, and stimulation treatments are often necessary to maintain or establish fluid production. Therefore, core-flow tests are usually conducted to test and model stimulation treatments within a laboratory scale to predict their performance. The visualization of wormholes that were created within core-flow tests requires novel technologies for evaluation and pathway-prediction purposes. Unfortunately, past visualization techniques were always associated with the destruction of the core sample, creating a demand for nondestructive methods. Nuclear-magnetic-resonance imaging (NMRI) is such a method that fulfills the approach of being nondestructive. The technology is widely known by medical applications, and this study developed a procedure on how to use the NMRI technology to visualize wormholes with NMRI in 3D. The study was started by initially choosing and obtaining various core samples that have different contents of calcite and dolomite. These core samples were imaged with the NMRI and microfocus-computed-tomography (µCT) technology in their unchanged state, and basic petrophysical experiments were conducted for initial experiments. The μCT technology was used as a reference visualization technique, because it provides a very high resolution with a corresponding high level of detail. Afterward, core-flow tests were conducted on the core samples with various acid systems and wormholes generated. Finally, the core samples with wormholes were imaged again with the NMRI and μCT technology, whereby the NMRI acquisition technique was improved toward imaging of rock samples, and the results were compared with the μCT results. The NMRI results showed moderate imaging achievements for the unchanged rock samples and high-quality imaging achievements for the extracted wormholes.

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