Combinations of NMR and dielectric measurements frequently address challenging saturation and wettability determinations in conventional reservoirs. When pore structure effects are addressed, the nuclear magnetic resonance (NMR) characteristics are interpreted based on the evaluations of surface relaxivity, and the dielectric structural response is attributed to the “texture” of the rock matrix. Both pore structure descriptors can be improved if the molecular motions and charge mobility common to the measurements are considered. Similar to the dipolar relaxation equivalence of NMR and dielectric correlation time measurements in the Bloembergen, Purcell, and Pound (BPP) model, we develop a relaxation time correlation assuming representative Maxwell-Wagner relaxations. Dielectric dispersion curves for the carbonate matrix and vug pore components demonstrated by Myers are quantified using a dielectric relaxation time (DRT) model. The modeled pore system fractions are spectrally mapped to the NMR T1 or T2 distributions based on enhanced Debye shielding distances correlated with the conductivity. The characterized NMR distributions are validated with micro-CT pore-size determinations and diffusion correlations. The mapped distributions provide petrophysical insight into the frequently used Archie exponent combination (mn) associated with conductivity tortuosity and additional wettability screening criteria.
{"title":"NMR-Mapped Distributions of Dielectric Dispersion","authors":"J. Funk, M. Myers, L. Hathon","doi":"10.30632/pjv64n3-2023a7","DOIUrl":"https://doi.org/10.30632/pjv64n3-2023a7","url":null,"abstract":"Combinations of NMR and dielectric measurements frequently address challenging saturation and wettability determinations in conventional reservoirs. When pore structure effects are addressed, the nuclear magnetic resonance (NMR) characteristics are interpreted based on the evaluations of surface relaxivity, and the dielectric structural response is attributed to the “texture” of the rock matrix. Both pore structure descriptors can be improved if the molecular motions and charge mobility common to the measurements are considered. Similar to the dipolar relaxation equivalence of NMR and dielectric correlation time measurements in the Bloembergen, Purcell, and Pound (BPP) model, we develop a relaxation time correlation assuming representative Maxwell-Wagner relaxations. Dielectric dispersion curves for the carbonate matrix and vug pore components demonstrated by Myers are quantified using a dielectric relaxation time (DRT) model. The modeled pore system fractions are spectrally mapped to the NMR T1 or T2 distributions based on enhanced Debye shielding distances correlated with the conductivity. The characterized NMR distributions are validated with micro-CT pore-size determinations and diffusion correlations. The mapped distributions provide petrophysical insight into the frequently used Archie exponent combination (mn) associated with conductivity tortuosity and additional wettability screening criteria.","PeriodicalId":170688,"journal":{"name":"Petrophysics – The SPWLA Journal of Formation Evaluation and Reservoir Description","volume":"21 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"122686342","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Mohammad Sadegh Zamiri, Jiangfeng Guo, F. Marica, L. Romero-Zerón, B. Balcom
Shale characterization is complicated by low porosity and low permeability. Nano-porosity and a high degree of heterogeneity present further difficulties. 1H magnetic resonance (MR) methods have great potential to provide quantitative and spatially resolved information on fluids present in porous rocks. The shale MR response, however, is challenging to interpret due to short-lived signals that complicate quantitative signal detection and imaging. Multicomponent signals require high-resolution methods for adequate signal differentiation. MR methods must cope with low measurement sensitivity at low field. In this paper, T1-T2* and Look-Locker T1*-T2* methods were employed to resolve the shale signal for water, oil, and kerogen at high and low field. This permits fluid quantification and kerogen assessment. The T1-T2* measurement was employed to understand and control contrast in the single-point ramped imaging with T1 enhancement (SPRITE) imaging method. This permitted imaging that gave separate images of water and oil. Water absorption/desorption, evaporation, step pyrolysis, and water uptake experiments were monitored using T1-T2* measurement and MR imaging. The results showed (i) the capability of the T1-T2* measurement to differentiate and quantify kerogen, oil, and water in shales, (ii) the characterization of shale heterogeneity on the core plug scale, and (iii) demonstrated the key role of wettability in determining the spatial distribution of water in shales.
{"title":"Shale Characterization Using T1-T2* Magnetic Resonance Relaxation Correlation Measurement at Low and High Magnetic Fields","authors":"Mohammad Sadegh Zamiri, Jiangfeng Guo, F. Marica, L. Romero-Zerón, B. Balcom","doi":"10.30632/pjv64n3-2023a5","DOIUrl":"https://doi.org/10.30632/pjv64n3-2023a5","url":null,"abstract":"Shale characterization is complicated by low porosity and low permeability. Nano-porosity and a high degree of heterogeneity present further difficulties. 1H magnetic resonance (MR) methods have great potential to provide quantitative and spatially resolved information on fluids present in porous rocks. The shale MR response, however, is challenging to interpret due to short-lived signals that complicate quantitative signal detection and imaging. Multicomponent signals require high-resolution methods for adequate signal differentiation. MR methods must cope with low measurement sensitivity at low field. In this paper, T1-T2* and Look-Locker T1*-T2* methods were employed to resolve the shale signal for water, oil, and kerogen at high and low field. This permits fluid quantification and kerogen assessment. The T1-T2* measurement was employed to understand and control contrast in the single-point ramped imaging with T1 enhancement (SPRITE) imaging method. This permitted imaging that gave separate images of water and oil. Water absorption/desorption, evaporation, step pyrolysis, and water uptake experiments were monitored using T1-T2* measurement and MR imaging. The results showed (i) the capability of the T1-T2* measurement to differentiate and quantify kerogen, oil, and water in shales, (ii) the characterization of shale heterogeneity on the core plug scale, and (iii) demonstrated the key role of wettability in determining the spatial distribution of water in shales.","PeriodicalId":170688,"journal":{"name":"Petrophysics – The SPWLA Journal of Formation Evaluation and Reservoir Description","volume":"9 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130648339","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Accurate description and modeling of multiphase fluid flow are of paramount importance for subsurface resource engineering. The main source of information to quantify in-situ rock properties are borehole geophysical measurements, which are very often riddled with uncertainty ensuing from rock heterogeneity/anisotropy and mud-filtrate invasion effects. Therefore, experimental methods are needed to accurately describe and quantify the physics of mud-filtrate invasion and mudcake deposition and its effects on borehole geophysical measurements. We developed a new high-resolution (10 to 50 μm) experimental method to investigate the invasion of water- and oil-based drilling muds into rectangular rock samples using X-ray radiography. During mud injection, rock simples are scanned using high-resolution X-ray radiography, enabling the time-lapse visualization of both mud-filtrate invasion and external/internal mudcake deposition. Our experimental method successfully examines the effects of rock heterogeneity, bedding plane orientation, and anisotropy on the spatial distribution of fluids and mudcake formation resulting from mud-filtrate invasion. It also emphasizes the importance of mud properties on the final fluid saturation state once mudcake seals the borehole. The procedure is fast, accurate, and reliable to quantify the process of mud-filtrate invasion at the core scale, enabling an improved understanding of invasion effects on borehole geophysical measurements following drilling operations, especially in spatially complex rocks such as laminated sandstones and carbonates.
{"title":"Experimental Time-Lapse Visualization of Mud-Filtrate Invasion and Mudcake Deposition Using X-Ray Radiography","authors":"","doi":"10.30632/pjv64n3-2023a9","DOIUrl":"https://doi.org/10.30632/pjv64n3-2023a9","url":null,"abstract":"Accurate description and modeling of multiphase fluid flow are of paramount importance for subsurface resource engineering. The main source of information to quantify in-situ rock properties are borehole geophysical measurements, which are very often riddled with uncertainty ensuing from rock heterogeneity/anisotropy and mud-filtrate invasion effects. Therefore, experimental methods are needed to accurately describe and quantify the physics of mud-filtrate invasion and mudcake deposition and its effects on borehole geophysical measurements. We developed a new high-resolution (10 to 50 μm) experimental method to investigate the invasion of water- and oil-based drilling muds into rectangular rock samples using X-ray radiography. During mud injection, rock simples are scanned using high-resolution X-ray radiography, enabling the time-lapse visualization of both mud-filtrate invasion and external/internal mudcake deposition. Our experimental method successfully examines the effects of rock heterogeneity, bedding plane orientation, and anisotropy on the spatial distribution of fluids and mudcake formation resulting from mud-filtrate invasion. It also emphasizes the importance of mud properties on the final fluid saturation state once mudcake seals the borehole. The procedure is fast, accurate, and reliable to quantify the process of mud-filtrate invasion at the core scale, enabling an improved understanding of invasion effects on borehole geophysical measurements following drilling operations, especially in spatially complex rocks such as laminated sandstones and carbonates.","PeriodicalId":170688,"journal":{"name":"Petrophysics – The SPWLA Journal of Formation Evaluation and Reservoir Description","volume":"45 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"132100618","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
S. Eichmann, Jacob Bouchard, Hooisweng Ow, D. Petkie, M. Poitzsch
Terahertz (THz) spectroscopy is a nondestructive tool used in many industries to analyze materials, including measuring the water content and the distribution of water in biological samples. THz time-domain spectroscopy (THz-TDS) measures the dielectric and structural properties of a sample by probing it with an ultrafast THz pulse and measuring the change in amplitude and phase. In this study, we demonstrate the use of THz-TDS imaging to quickly map lateral (i.e., two-dimensional) variations in microporosity (ϕμ) using the THz attenuation due to water in the pores after clearing the large pores via centrifugation. Three carbonate rock plugs with differing ϕ and pore-size distributions were subsampled for this study. Three water saturation states were produced for each sample: saturated, centrifuged, and dry. At each saturation state, the sample is weighed and imaged using THz-TDS to spatially map and measure ϕμ. The results show that for each sample the ϕμ obtained using THz-TDS imaging is in excellent agreement with that obtained from both mass balance and MICP. In addition, the THz-TDS maps show significant differences in the spatial distribution of the microporosity for samples having similar composition. This method provides a means to measure ϕ and ϕμ while mapping the spatial distribution of ϕμ toward improved petrophysical characterization of carbonate reservoir rocks.
{"title":"THz Imaging to Map the Lateral Microporosity Distribution in Carbonate Rocks","authors":"S. Eichmann, Jacob Bouchard, Hooisweng Ow, D. Petkie, M. Poitzsch","doi":"10.30632/pjv64n3-2023a8","DOIUrl":"https://doi.org/10.30632/pjv64n3-2023a8","url":null,"abstract":"Terahertz (THz) spectroscopy is a nondestructive tool used in many industries to analyze materials, including measuring the water content and the distribution of water in biological samples. THz time-domain spectroscopy (THz-TDS) measures the dielectric and structural properties of a sample by probing it with an ultrafast THz pulse and measuring the change in amplitude and phase. In this study, we demonstrate the use of THz-TDS imaging to quickly map lateral (i.e., two-dimensional) variations in microporosity (ϕμ) using the THz attenuation due to water in the pores after clearing the large pores via centrifugation. Three carbonate rock plugs with differing ϕ and pore-size distributions were subsampled for this study. Three water saturation states were produced for each sample: saturated, centrifuged, and dry. At each saturation state, the sample is weighed and imaged using THz-TDS to spatially map and measure ϕμ. The results show that for each sample the ϕμ obtained using THz-TDS imaging is in excellent agreement with that obtained from both mass balance and MICP. In addition, the THz-TDS maps show significant differences in the spatial distribution of the microporosity for samples having similar composition. This method provides a means to measure ϕ and ϕμ while mapping the spatial distribution of ϕμ toward improved petrophysical characterization of carbonate reservoir rocks.","PeriodicalId":170688,"journal":{"name":"Petrophysics – The SPWLA Journal of Formation Evaluation and Reservoir Description","volume":"98 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124685242","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Quentin Danielczick, Ata Nepesov, Laurent Rochereau, S. Lescoulie, Victor De Oliveira Fernandes, B. Nicot
Technological improvements and innovations are made to offer solutions with superior efficiency in terms of cost, quality, speed, or all of them. In the special core analysis (SCAL) field, the conventional resistivity index measurement (the porous plate technique) is a cost-effective method that provides good-quality results but is very time consuming. For this purpose, several methods were developed to reduce the time taken to acquire resistivity measurements. In 2017, we proposed the ultra-fast capillary pressure and resistivity index measurements (UFPCRI) combining centrifugation, nuclear magnetic resonance (NMR) imaging, and resistivity profiling. Since 2021, the wireless resistivity index (WiRI) method allows the acquisition of capillary pressure and resistivity index in a matter of days. This method is based on a new in-house system to acquire wirelessly resistivity indexes along a rock sample during centrifugation. The determination of the resistivity vs. saturation curve and the n exponent of Archie’s law is done thanks to an optimization algorithm. In this paper, we present the results obtained from multiple simulations and experiments for WiRI, UFPCRI, and porous plate to discuss the advantages and drawbacks of each method in terms of reliability and experimental duration. Six rock samples are studied. A comparison of the three methods regarding Archie’s n exponent, resistivity indexes, and capillary pressure curves is performed.
{"title":"Wireless Acquisition for Resistivity Index in Centrifuge – WiRI: A Comparative Study of Three Pc-RI Methods","authors":"Quentin Danielczick, Ata Nepesov, Laurent Rochereau, S. Lescoulie, Victor De Oliveira Fernandes, B. Nicot","doi":"10.30632/pjv64n3-2023a2","DOIUrl":"https://doi.org/10.30632/pjv64n3-2023a2","url":null,"abstract":"Technological improvements and innovations are made to offer solutions with superior efficiency in terms of cost, quality, speed, or all of them. In the special core analysis (SCAL) field, the conventional resistivity index measurement (the porous plate technique) is a cost-effective method that provides good-quality results but is very time consuming. For this purpose, several methods were developed to reduce the time taken to acquire resistivity measurements. In 2017, we proposed the ultra-fast capillary pressure and resistivity index measurements (UFPCRI) combining centrifugation, nuclear magnetic resonance (NMR) imaging, and resistivity profiling. Since 2021, the wireless resistivity index (WiRI) method allows the acquisition of capillary pressure and resistivity index in a matter of days. This method is based on a new in-house system to acquire wirelessly resistivity indexes along a rock sample during centrifugation. The determination of the resistivity vs. saturation curve and the n exponent of Archie’s law is done thanks to an optimization algorithm. In this paper, we present the results obtained from multiple simulations and experiments for WiRI, UFPCRI, and porous plate to discuss the advantages and drawbacks of each method in terms of reliability and experimental duration. Six rock samples are studied. A comparison of the three methods regarding Archie’s n exponent, resistivity indexes, and capillary pressure curves is performed.","PeriodicalId":170688,"journal":{"name":"Petrophysics – The SPWLA Journal of Formation Evaluation and Reservoir Description","volume":"17 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124958136","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Daria Olszowska, Gabriel Gallardo-Giozza, Domenico Crisafulli, C. Torres‐Verdín
Due to depositional, diagenetic, and structural processes, reservoir rocks are rarely homogeneous, often exhibiting significant short-range variations in elastic properties. Such spatial variability can have measurable effects on macroscopic mechanical properties for drilling and fluid production operations. We describe a new laboratory method for the acquisition of ultrasonic angle-dependent measurements of reflected waves that delivers high-resolution, continuous descriptions of P- and S-wave velocity along the surface of the rock sample. Reflection coefficient vs. incidence angle is the main source of information about rock elastic properties. The acquired measurements are matched to numerical simulations to estimate P- and S-wave velocity and density of the porous sample and their variations within the rock specimen, hence providing continuous descriptions of sample complexity. Data collected from various locations on the rock specimen are subsequently used to construct two-dimensional (2D) models of elastic properties along the surface of the rock sample. P- and S-wave velocities estimated with this method agree well with acoustic transmission measurements for most homogeneous rocks. The spatial resolution of the method is limited by receiver size, measurement frequency, and incidence angle. At high incidence angles, the surface area sensitive to the measurements increases, and consequently, the spatial resolution of the corresponding reflection coefficient decreases across neighboring rock features.
{"title":"Angle-Dependent Ultrasonic Wave Reflection for Estimating High-Resolution Elastic Properties of Complex Rock Samples","authors":"Daria Olszowska, Gabriel Gallardo-Giozza, Domenico Crisafulli, C. Torres‐Verdín","doi":"10.30632/pjv64n3-2023a6","DOIUrl":"https://doi.org/10.30632/pjv64n3-2023a6","url":null,"abstract":"Due to depositional, diagenetic, and structural processes, reservoir rocks are rarely homogeneous, often exhibiting significant short-range variations in elastic properties. Such spatial variability can have measurable effects on macroscopic mechanical properties for drilling and fluid production operations. We describe a new laboratory method for the acquisition of ultrasonic angle-dependent measurements of reflected waves that delivers high-resolution, continuous descriptions of P- and S-wave velocity along the surface of the rock sample. Reflection coefficient vs. incidence angle is the main source of information about rock elastic properties. The acquired measurements are matched to numerical simulations to estimate P- and S-wave velocity and density of the porous sample and their variations within the rock specimen, hence providing continuous descriptions of sample complexity. Data collected from various locations on the rock specimen are subsequently used to construct two-dimensional (2D) models of elastic properties along the surface of the rock sample. P- and S-wave velocities estimated with this method agree well with acoustic transmission measurements for most homogeneous rocks. The spatial resolution of the method is limited by receiver size, measurement frequency, and incidence angle. At high incidence angles, the surface area sensitive to the measurements increases, and consequently, the spatial resolution of the corresponding reflection coefficient decreases across neighboring rock features.","PeriodicalId":170688,"journal":{"name":"Petrophysics – The SPWLA Journal of Formation Evaluation and Reservoir Description","volume":"7 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"114673646","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Ying Gao, T. Sorop, N. Brussee, Hilbert Van der Linde, A. Coorn, M. Appel, S. Berg
Trapped gas saturation (Sgr) plays an important role in subsurface engineering, such as carbon capture and storage, H2 storage efficiency as well as the production of natural gas. Unfortunately, Sgr is notoriously difficult to measure in the laboratory or field. The conventional method of measurement—low-rate unsteady-state coreflooding—is often impacted by gas dissolution effects, resulting in large uncertainties of the measured Sgr. Moreover, it is not understood why this effect occurs, even for brines carefully pre-equilibrated with gas. To address this question, we used high-resolution X-ray computed tomography (micro-CT) imaging techniques to directly visualize the pore-scale processes during gas trapping. Consistent with previous studies, we find that for pre-equilibrated brine, the remaining gas saturation continually decreased with more (pre-equilibrated) brine injected and even after the brine injection was stopped, resulting in very low Sgr values (possibly even zero) at the pore-scale level. Furthermore, we were able to clearly observe the initial trapping of gas by the snap-off effect, followed by a further shrinkage of the gas clusters that had no connected pathway to the outside. Our experimental insights suggest that the effect is related to the effective phase behavior of gas inside the porous medium, which due to the geometric confinement, could be different from the phase behavior of bulk fluids. The underlying mechanism is likely linked to ripening dynamics, which involves a coupling between phase equilibrium and dissolution/partitioning of components, diffusive transport, and capillarity in the geometric confinement of the pore space.
{"title":"Advanced Digital-SCAL Measurements of Gas Trapped in Sandstone","authors":"Ying Gao, T. Sorop, N. Brussee, Hilbert Van der Linde, A. Coorn, M. Appel, S. Berg","doi":"10.30632/pjv64n3-2023a4","DOIUrl":"https://doi.org/10.30632/pjv64n3-2023a4","url":null,"abstract":"Trapped gas saturation (Sgr) plays an important role in subsurface engineering, such as carbon capture and storage, H2 storage efficiency as well as the production of natural gas. Unfortunately, Sgr is notoriously difficult to measure in the laboratory or field. The conventional method of measurement—low-rate unsteady-state coreflooding—is often impacted by gas dissolution effects, resulting in large uncertainties of the measured Sgr. Moreover, it is not understood why this effect occurs, even for brines carefully pre-equilibrated with gas. To address this question, we used high-resolution X-ray computed tomography (micro-CT) imaging techniques to directly visualize the pore-scale processes during gas trapping. Consistent with previous studies, we find that for pre-equilibrated brine, the remaining gas saturation continually decreased with more (pre-equilibrated) brine injected and even after the brine injection was stopped, resulting in very low Sgr values (possibly even zero) at the pore-scale level. Furthermore, we were able to clearly observe the initial trapping of gas by the snap-off effect, followed by a further shrinkage of the gas clusters that had no connected pathway to the outside. Our experimental insights suggest that the effect is related to the effective phase behavior of gas inside the porous medium, which due to the geometric confinement, could be different from the phase behavior of bulk fluids. The underlying mechanism is likely linked to ripening dynamics, which involves a coupling between phase equilibrium and dissolution/partitioning of components, diffusive transport, and capillarity in the geometric confinement of the pore space.","PeriodicalId":170688,"journal":{"name":"Petrophysics – The SPWLA Journal of Formation Evaluation and Reservoir Description","volume":"123 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130863738","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Meysam Nourani, Stefano Pruno, Mohammad Ghasemi, Muhament Meti Fazlija, Bryon Gonzalez, H. Rodvelt
In this study, new parameters referred to as rock resistivity modulus (RRM) and true resistivity modulus (TRM) were defined. Analytical models were developed based on RRM, TRM, and Archie’s equation for predicting formation resistivity factor (FRF) and resistivity index (RI) under overburden pressure conditions. The results indicated that overburden FRF is dependent on FRF at initial pressure (ambient FRF), RRM, and net confining pressure difference. RRM decreases with cementation factor and rock compressibility. The proposed FRF model was validated using 374 actual core data of 79 plug samples (31 sandstone and 48 carbonate plug samples) from three sandstone reservoirs and four carbonate reservoirs, measured under four to six different overburden pressures. The developed FRF model fitted the experimental data with an average relative error of 2% and 3% for sandstone and carbonate samples, respectively. Moreover, the applications and limitations of the models have been investigated and discussed. Further theoretical analysis showed that overburden RI is a function of RI at initial pressure, TRM, and net confining pressure difference. The developed models supplement resistivity measurements and can be applied to estimate FRF, RI, and saturation exponent (n) variations with overburden pressure.
{"title":"Analytical Models for Predicting the Formation Resistivity Factor and Resistivity Index at Overburden Conditions","authors":"Meysam Nourani, Stefano Pruno, Mohammad Ghasemi, Muhament Meti Fazlija, Bryon Gonzalez, H. Rodvelt","doi":"10.30632/pjv64n3-2023a3","DOIUrl":"https://doi.org/10.30632/pjv64n3-2023a3","url":null,"abstract":"In this study, new parameters referred to as rock resistivity modulus (RRM) and true resistivity modulus (TRM) were defined. Analytical models were developed based on RRM, TRM, and Archie’s equation for predicting formation resistivity factor (FRF) and resistivity index (RI) under overburden pressure conditions. The results indicated that overburden FRF is dependent on FRF at initial pressure (ambient FRF), RRM, and net confining pressure difference. RRM decreases with cementation factor and rock compressibility. The proposed FRF model was validated using 374 actual core data of 79 plug samples (31 sandstone and 48 carbonate plug samples) from three sandstone reservoirs and four carbonate reservoirs, measured under four to six different overburden pressures. The developed FRF model fitted the experimental data with an average relative error of 2% and 3% for sandstone and carbonate samples, respectively. Moreover, the applications and limitations of the models have been investigated and discussed. Further theoretical analysis showed that overburden RI is a function of RI at initial pressure, TRM, and net confining pressure difference. The developed models supplement resistivity measurements and can be applied to estimate FRF, RI, and saturation exponent (n) variations with overburden pressure.","PeriodicalId":170688,"journal":{"name":"Petrophysics – The SPWLA Journal of Formation Evaluation and Reservoir Description","volume":"16 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"131182942","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Victor Fernandes, B. Nicot, F. Pairoys, Herni Bertin, J. Lachaud, C. Caubit
Relative permeability and capillary pressure are important parameters in reservoir simulations because it helps in understanding and anticipating oil and/or gas production scenarios over the years. They are both obtained in a laboratory after establishing the required initial conditions. As a matter of fact, before measuring imbibition relative permeability and capillary pressure, it is recommended to set initial rock reservoir conditions by establishing appropriate initial water saturation (Swi) and by aging the core to restore the reservoir wettability. There are several conventional techniques to establish Swi. Viscous flooding is a fast technique, but it may create a non-uniform saturation profile and, in some cases, be inefficient in reaching low Swi targets. Centrifugation is a capillary-driven technique that is also very fast; however, the possibility of not desaturating the outlet face is a significant constraint. In both cases, reversing flow direction is generally performed to flatten the saturation profile; however, this phenomenon is poorly controlled. The application of capillary pressure by porous plate allows targeting a specific value of Swi and generates a uniform saturation profile; however, it is a very time-consuming method. In this paper, we present the Hybrid Drainage Technique (HDT), which couples viscous flooding and porous plate approaches, significantly reducing the experimental duration when setting Swi. Another advantage of the method is the possibility of setting a uniform saturation profile at the targeted Swi. A specific core holder, adapted to nuclear magnetic resonance (NMR) imaging and capable of performing both viscous flooding and porous plate testing without unloading the rock, was designed. Using this core holder enables performing aging and imbibition coreflood testing with no further manipulation of the core sample. Monitoring saturation profiles was made possible by using an NMR imaging setup. The method has been tested and validated on two outcrop samples from Bentheimer (sandstone) and Richemont (limestone), drastically reducing the experimental time of the primary drainage step in comparison to classical porous plate drainage but also leading to uniform water saturation profiles. The experiment duration is reduced, and it enables the realization of coreflooding; therefore, this technique may be used for larger samples classically used in relative permeability experiments. This approach is preferred as it provides faster and more reliable measurements of saturation.
{"title":"Hybrid Technique for Setting Initial Water Saturation on Core Samples","authors":"Victor Fernandes, B. Nicot, F. Pairoys, Herni Bertin, J. Lachaud, C. Caubit","doi":"10.30632/pjv64n3-2023a1","DOIUrl":"https://doi.org/10.30632/pjv64n3-2023a1","url":null,"abstract":"Relative permeability and capillary pressure are important parameters in reservoir simulations because it helps in understanding and anticipating oil and/or gas production scenarios over the years. They are both obtained in a laboratory after establishing the required initial conditions. As a matter of fact, before measuring imbibition relative permeability and capillary pressure, it is recommended to set initial rock reservoir conditions by establishing appropriate initial water saturation (Swi) and by aging the core to restore the reservoir wettability. There are several conventional techniques to establish Swi. Viscous flooding is a fast technique, but it may create a non-uniform saturation profile and, in some cases, be inefficient in reaching low Swi targets. Centrifugation is a capillary-driven technique that is also very fast; however, the possibility of not desaturating the outlet face is a significant constraint. In both cases, reversing flow direction is generally performed to flatten the saturation profile; however, this phenomenon is poorly controlled. The application of capillary pressure by porous plate allows targeting a specific value of Swi and generates a uniform saturation profile; however, it is a very time-consuming method. In this paper, we present the Hybrid Drainage Technique (HDT), which couples viscous flooding and porous plate approaches, significantly reducing the experimental duration when setting Swi. Another advantage of the method is the possibility of setting a uniform saturation profile at the targeted Swi. A specific core holder, adapted to nuclear magnetic resonance (NMR) imaging and capable of performing both viscous flooding and porous plate testing without unloading the rock, was designed. Using this core holder enables performing aging and imbibition coreflood testing with no further manipulation of the core sample. Monitoring saturation profiles was made possible by using an NMR imaging setup. The method has been tested and validated on two outcrop samples from Bentheimer (sandstone) and Richemont (limestone), drastically reducing the experimental time of the primary drainage step in comparison to classical porous plate drainage but also leading to uniform water saturation profiles. The experiment duration is reduced, and it enables the realization of coreflooding; therefore, this technique may be used for larger samples classically used in relative permeability experiments. This approach is preferred as it provides faster and more reliable measurements of saturation.","PeriodicalId":170688,"journal":{"name":"Petrophysics – The SPWLA Journal of Formation Evaluation and Reservoir Description","volume":"10 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"127669878","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2023-04-01DOI: 10.30632/pjv64n2-2023a11
We built a convolution model using machine learning (ML) to calculate induction log responses for one-dimensional (1D) earth models. Compared to analytical forward modeling, the convolution model is extremely fast. ML-based convolution finds accurate induction tool responses from an earth model with layer resistivity and layer boundaries. For a unit induction tool 2C40, the 101-point, 50-ft window convolution model works satisfactorily for a well deviation angle of 60.
{"title":"Machine-Learning-Based Convolution Method for Fast Forward Modeling of Induction Log","authors":"","doi":"10.30632/pjv64n2-2023a11","DOIUrl":"https://doi.org/10.30632/pjv64n2-2023a11","url":null,"abstract":"We built a convolution model using machine learning (ML) to calculate induction log responses for one-dimensional (1D) earth models. Compared to analytical forward modeling, the convolution model is extremely fast. ML-based convolution finds accurate induction tool responses from an earth model with layer resistivity and layer boundaries. For a unit induction tool 2C40, the 101-point, 50-ft window convolution model works satisfactorily for a well deviation angle of 60.","PeriodicalId":170688,"journal":{"name":"Petrophysics – The SPWLA Journal of Formation Evaluation and Reservoir Description","volume":"35 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"132800649","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
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