Hydrocarbon saturation is an important formation parameter and the basis for quantitative reservoir evaluation. However, the saturation models of shaly sandstones contain more parameters than clean sandstones; therefore, determining these parameters for shaly sandstone is difficult. In this study, based on the response of spontaneous potential (SP) logging, the membrane potential equations of shaly sandstone in water-saturated and oil-water states were derived, and an analytical equation of the anomaly amplitude of the SP in shaly sandstone was obtained. On this basis, the influencing factors of the SP anomaly were analyzed. Furthermore, a joint inversion of SP and resistivity was established to calculate oil saturation and cation exchange capacity per unit pore volume (Qv). The SP log was interpreted using the proposed analytical model, and the resistivity log was processed using the Waxman-Smits model. The particle swarm optimization method was used to resolve the objective function. Finally, the method was applied to the Chang 8 Reservoir in Yanchang, on the western edge of the Ordos Basin, China. The resistivity and SP log curves synthesized using the inverse parameters agree with the field logs. The inversion of the saturation and Qv is consistent with core data and oil testing, indicating that the joint inversion method is stable, reliable, and accurate.
{"title":"Joint Inversion of Saturation and Q in Low-Permeability Sandstones Using v Spontaneous Potential and Resistivity Logs","authors":"Peiqiang Zhao, Yuetian Wang, Gaoren Li, Cong Hu, Jiarui Xie, Wei Duan, Zhiqiang Mao","doi":"10.30632/pjv64n5-2023a8","DOIUrl":"https://doi.org/10.30632/pjv64n5-2023a8","url":null,"abstract":"Hydrocarbon saturation is an important formation parameter and the basis for quantitative reservoir evaluation. However, the saturation models of shaly sandstones contain more parameters than clean sandstones; therefore, determining these parameters for shaly sandstone is difficult. In this study, based on the response of spontaneous potential (SP) logging, the membrane potential equations of shaly sandstone in water-saturated and oil-water states were derived, and an analytical equation of the anomaly amplitude of the SP in shaly sandstone was obtained. On this basis, the influencing factors of the SP anomaly were analyzed. Furthermore, a joint inversion of SP and resistivity was established to calculate oil saturation and cation exchange capacity per unit pore volume (Qv). The SP log was interpreted using the proposed analytical model, and the resistivity log was processed using the Waxman-Smits model. The particle swarm optimization method was used to resolve the objective function. Finally, the method was applied to the Chang 8 Reservoir in Yanchang, on the western edge of the Ordos Basin, China. The resistivity and SP log curves synthesized using the inverse parameters agree with the field logs. The inversion of the saturation and Qv is consistent with core data and oil testing, indicating that the joint inversion method is stable, reliable, and accurate.","PeriodicalId":49703,"journal":{"name":"Petrophysics","volume":"26 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"134931122","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pierre Aérens, Pierre Aérens, D. Nicolas Espinoza, Carlos Torres-Verdín
Borehole measurements, such as electrical resistivity, neutron porosity, or nuclear magnetic resonance, are critical for the in-situ petrophysical assessment of subsurface rocks. However, the interpretation of borehole measurements is often subject to uncertainty arising from their sensitivity to the interplay between mud filtrate, connate fluids, and the rock’s pore structure. This uncertainty remains present even in homogeneous geological formations. Mudcake deposition on the borehole wall causes additional complexity, impacting both well construction and formation evaluation. It is, therefore, essential to account for the latter effects and perform appropriate corrections when interpreting borehole measurements. Recently, new experimental procedures were introduced to quantitatively describe the process of mud invasion under realistic rock and fluid conditions, focusing on gas-bearing rocks and without considering how original saturating fluids affected the process of invasion. Both mud-filtrate invasion and filter-cake deposition must be understood and incorporated into numerical and analytical models to reliably interpret borehole measurements and maximize value. This objective can only be fulfilled via experiments. We use X-ray microfocus radiography to examine in real time the processes of mud-filtrate invasion and internal and external mudcake deposition in thin rectangular rock samples. The high-resolution experimental procedure (10 to 30 μm) mimics the borehole and near-wellbore regions and facilitates the time-lapse visualization of in-situ fluid-transport processes in spatially complex rocks. Water- and oil-based muds were injected into rock samples initially saturated with a range of different connate fluids, including viscous liquids, while being continuously scanned with X-rays. Because the injected drilling muds were the same across all experiments, the observed discrepancies between experiments originate from differences in rock properties, heterogeneity and anisotropy, or initial fluid saturation conditions. Experimental results emphasize the effect of rock heterogeneity and initial connate fluid on the spatial distribution of fluids and mudcake formation ensuing from mud-filtrate invasion. Mud-filtrate invasion rates and final average mudcake thicknesses were similar across all cases for a given drilling mud, suggesting that mudcake properties, as opposed to rock properties, were the controlling factors. By contrast, the spatial distribution of fluids in each rock sample varied significantly between cases, highlighting the impact of rock heterogeneity/anisotropy on the process of invasion. Laboratory experiments also emphasize the impact of viscous and/or capillary forces on mud-filtrate flow behavior. The experimental method is efficient and reliable, allowing for a better understanding of the uncertainty of the effects of mud-filtrate invasion on borehole geophysical measurements acquired while or after drilling.
{"title":"High-Resolution Time-Lapse Monitoring of Mud Invasion in Spatially Complex Rocks Using In-Situ X-Ray Radiography","authors":"Pierre Aérens, Pierre Aérens, D. Nicolas Espinoza, Carlos Torres-Verdín","doi":"10.30632/pjv64n5-2023a7","DOIUrl":"https://doi.org/10.30632/pjv64n5-2023a7","url":null,"abstract":"Borehole measurements, such as electrical resistivity, neutron porosity, or nuclear magnetic resonance, are critical for the in-situ petrophysical assessment of subsurface rocks. However, the interpretation of borehole measurements is often subject to uncertainty arising from their sensitivity to the interplay between mud filtrate, connate fluids, and the rock’s pore structure. This uncertainty remains present even in homogeneous geological formations. Mudcake deposition on the borehole wall causes additional complexity, impacting both well construction and formation evaluation. It is, therefore, essential to account for the latter effects and perform appropriate corrections when interpreting borehole measurements. Recently, new experimental procedures were introduced to quantitatively describe the process of mud invasion under realistic rock and fluid conditions, focusing on gas-bearing rocks and without considering how original saturating fluids affected the process of invasion. Both mud-filtrate invasion and filter-cake deposition must be understood and incorporated into numerical and analytical models to reliably interpret borehole measurements and maximize value. This objective can only be fulfilled via experiments. We use X-ray microfocus radiography to examine in real time the processes of mud-filtrate invasion and internal and external mudcake deposition in thin rectangular rock samples. The high-resolution experimental procedure (10 to 30 μm) mimics the borehole and near-wellbore regions and facilitates the time-lapse visualization of in-situ fluid-transport processes in spatially complex rocks. Water- and oil-based muds were injected into rock samples initially saturated with a range of different connate fluids, including viscous liquids, while being continuously scanned with X-rays. Because the injected drilling muds were the same across all experiments, the observed discrepancies between experiments originate from differences in rock properties, heterogeneity and anisotropy, or initial fluid saturation conditions. Experimental results emphasize the effect of rock heterogeneity and initial connate fluid on the spatial distribution of fluids and mudcake formation ensuing from mud-filtrate invasion. Mud-filtrate invasion rates and final average mudcake thicknesses were similar across all cases for a given drilling mud, suggesting that mudcake properties, as opposed to rock properties, were the controlling factors. By contrast, the spatial distribution of fluids in each rock sample varied significantly between cases, highlighting the impact of rock heterogeneity/anisotropy on the process of invasion. Laboratory experiments also emphasize the impact of viscous and/or capillary forces on mud-filtrate flow behavior. The experimental method is efficient and reliable, allowing for a better understanding of the uncertainty of the effects of mud-filtrate invasion on borehole geophysical measurements acquired while or after drilling.","PeriodicalId":49703,"journal":{"name":"Petrophysics","volume":"116 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"134935065","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Potash minerals are the primary source of potassium (K), which is used for the manufacture of gunpowder, fertilizer, and as a sodium-seasoning substitute. Commercial potash minerals are all evaporites. Because potassium-40 (40K) is radioactive (decaying to argon-40 (40Ar) and releasing a gamma ray (GR) in the process), commercial potash mineralization is often discovered when GR (γ ray) logs in petroleum wells drilled through evaporite sequences “go off scale.” However, not all potash minerals may be commercial sources of potassium via underground mining techniques, and potassium is not the only radioactive element. For example, the mineralogy of the McNutt “potash” Member of the Salado Formation in southeast (SE) New Mexico is extremely complex, consisting of multiple thin (i.e., less than 10 ft thick) beds of six low-grade (radioactive) potash minerals, only two of which are commercial for underground mining. There are also four nonradioactive evaporite minerals, one of which may interfere with potash milling chemistry and numerous claystones and marker beds (shales and/or volcanics), with GR count rates comparable to the low-grade potash mineralization in this sequence. Because of this complexity, traditional borehole wireline (WL) and logging-while-drilling (LWD) potash assay techniques, such as GR log-to-core assay transforms, may not be sufficient to identify potentially commercial potash mineralization for underground mining (Teufel, 2008) in SE New Mexico. Crain and Anderson (1966) and Hill (2019) developed linear programming and multimineral analyses, respectively, to estimate potash mineralogy and grades from multiple borehole geophysical measurements. However, both of these approaches require large sets of multiple log measurements. In SE New Mexico, petroleum wells are drilled through the Salado Formation evaporite (including the McNutt “potash” Member) with air, then cased and cemented in place without running WL measurements. Then, the wells are drilled out to total depth (TD) in the underlying sediments with water-based mud. Complete log suites are run from TD to the casing shoe, with only the GR and neutron logs recorded through the cased evaporite sequence for stratigraphic and structural correlation. As a result, essentially all recent oil and gas wells in SE New Mexico have casedhole gamma ray and neutron logs through the Salado evaporite. Hill and Crain (2020) developed a simple crossplot involving only GR and neutron log data, which could discriminate between anhydrous and hydrated potassium evaporite minerals. Logs from these wells could provide a rapid potash screening database if used properly. This technique can be used with both openhole and casedhole petroleum well logs, as well as corehole WL logs, and provides discrimination of commercial potash mineralization from noncommercial (potash and non-potash) radioactive mineralization. Case histories of the use of PID crossplots in evaporite basins of Michigan, Nova Scotia,
{"title":"The Potash Identification (PID) Plot: A Rapid Screening Crossplot for Discrimination of Commercial Potash","authors":"Donald G. Hill, E. Ross Crain, Lawrence W. Teufel","doi":"10.30632/pjv64n5-2023a6","DOIUrl":"https://doi.org/10.30632/pjv64n5-2023a6","url":null,"abstract":"Potash minerals are the primary source of potassium (K), which is used for the manufacture of gunpowder, fertilizer, and as a sodium-seasoning substitute. Commercial potash minerals are all evaporites. Because potassium-40 (40K) is radioactive (decaying to argon-40 (40Ar) and releasing a gamma ray (GR) in the process), commercial potash mineralization is often discovered when GR (γ ray) logs in petroleum wells drilled through evaporite sequences “go off scale.” However, not all potash minerals may be commercial sources of potassium via underground mining techniques, and potassium is not the only radioactive element. For example, the mineralogy of the McNutt “potash” Member of the Salado Formation in southeast (SE) New Mexico is extremely complex, consisting of multiple thin (i.e., less than 10 ft thick) beds of six low-grade (radioactive) potash minerals, only two of which are commercial for underground mining. There are also four nonradioactive evaporite minerals, one of which may interfere with potash milling chemistry and numerous claystones and marker beds (shales and/or volcanics), with GR count rates comparable to the low-grade potash mineralization in this sequence. Because of this complexity, traditional borehole wireline (WL) and logging-while-drilling (LWD) potash assay techniques, such as GR log-to-core assay transforms, may not be sufficient to identify potentially commercial potash mineralization for underground mining (Teufel, 2008) in SE New Mexico. Crain and Anderson (1966) and Hill (2019) developed linear programming and multimineral analyses, respectively, to estimate potash mineralogy and grades from multiple borehole geophysical measurements. However, both of these approaches require large sets of multiple log measurements. In SE New Mexico, petroleum wells are drilled through the Salado Formation evaporite (including the McNutt “potash” Member) with air, then cased and cemented in place without running WL measurements. Then, the wells are drilled out to total depth (TD) in the underlying sediments with water-based mud. Complete log suites are run from TD to the casing shoe, with only the GR and neutron logs recorded through the cased evaporite sequence for stratigraphic and structural correlation. As a result, essentially all recent oil and gas wells in SE New Mexico have casedhole gamma ray and neutron logs through the Salado evaporite. Hill and Crain (2020) developed a simple crossplot involving only GR and neutron log data, which could discriminate between anhydrous and hydrated potassium evaporite minerals. Logs from these wells could provide a rapid potash screening database if used properly. This technique can be used with both openhole and casedhole petroleum well logs, as well as corehole WL logs, and provides discrimination of commercial potash mineralization from noncommercial (potash and non-potash) radioactive mineralization. Case histories of the use of PID crossplots in evaporite basins of Michigan, Nova Scotia,","PeriodicalId":49703,"journal":{"name":"Petrophysics","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"134935003","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2023-10-01DOI: 10.30632/pjv64n5-2023a10
Tarek S. Mohamed, Carlos Torres-Verdín, Oliver C. Mullins
Accurate reservoir characterization is vital for effective decisions made throughout the life cycle of an oilfield reservoir, including management and development. Of all the components of reservoir description, hydraulic connectivity carries the highest amount of uncertainty, where inaccurate connectivity evaluation often results in production underperformance. Shortcomings are faced when applying conventional approaches of connectivity assessment. Seismic surveys are not always sufficient to evaluate lateral connectivity as detected faults can be transmissive or partially transmissive, while some faults are below the detection limits of seismic amplitude measurements. Vertical connectivity represents another uncertainty, where pressure measurements and well logs are often either unable to detect the baffles along oil columns or cannot assess whether detected baffles are relevant seals or flow diverters. Although conventional downhole fluid analysis (DFA) workflows have proven effective in delineating reservoir connectivity, enough DFA data are not always available, and with added complexity, uncertainties arise. Additionally, while equilibrated asphaltene gradients, measured through DFA probes, imply connectivity, ongoing reservoir fluid geodynamics (RFG) processes, such as current hydrocarbon charging, can preclude equilibration in a connected reservoir. Thus, a comprehensive assessment approach, that utilizes all available data streams, is needed to overcome the significant spatial complexity associated with moderately and heavily faulted reservoirs. In this paper, we employed our recently introduced interpretation workflow to evaluate the connectivity of a heavily faulted reservoir in the deepwater Gulf of Mexico. The field was divided into five investigation areas penetrated by 12 wells. Areal downhole fluid analysis (ADFA) was applied to assess local connectivity leading to reservoir-scale connectivity. Through integrating fluid/dynamic and rock/static data, each data type provided insights that were pieced together to enhance consistency and reduce uncertainty. Analyzed data included pressure-volume-temperature (PVT) reports, pressure surveys, well logs, and geochemistry. The study resulted in a verifiable connectivity description where faults, previously regarded as sealing, were classified into sealing or partially transmissive faults; unresolved faults were detected. Fault-block migration was detected, and fault throw was estimated; asphaltenes behavior was used to deduce original field structures prior to faulting. We also examined RFG processes to investigate oil biodegradation, where an asphaltene clustering trend was observed, causing high oil viscosities toward the bottom of one sandstone. A correlation was then derived and successfully implemented to estimate oil viscosity.
{"title":"Enhanced Reservoir Description via Areal Data Integration and Reservoir Fluid Geodynamics: A Case Study From Deepwater Gulf of Mexico","authors":"Tarek S. Mohamed, Carlos Torres-Verdín, Oliver C. Mullins","doi":"10.30632/pjv64n5-2023a10","DOIUrl":"https://doi.org/10.30632/pjv64n5-2023a10","url":null,"abstract":"Accurate reservoir characterization is vital for effective decisions made throughout the life cycle of an oilfield reservoir, including management and development. Of all the components of reservoir description, hydraulic connectivity carries the highest amount of uncertainty, where inaccurate connectivity evaluation often results in production underperformance. Shortcomings are faced when applying conventional approaches of connectivity assessment. Seismic surveys are not always sufficient to evaluate lateral connectivity as detected faults can be transmissive or partially transmissive, while some faults are below the detection limits of seismic amplitude measurements. Vertical connectivity represents another uncertainty, where pressure measurements and well logs are often either unable to detect the baffles along oil columns or cannot assess whether detected baffles are relevant seals or flow diverters. Although conventional downhole fluid analysis (DFA) workflows have proven effective in delineating reservoir connectivity, enough DFA data are not always available, and with added complexity, uncertainties arise. Additionally, while equilibrated asphaltene gradients, measured through DFA probes, imply connectivity, ongoing reservoir fluid geodynamics (RFG) processes, such as current hydrocarbon charging, can preclude equilibration in a connected reservoir. Thus, a comprehensive assessment approach, that utilizes all available data streams, is needed to overcome the significant spatial complexity associated with moderately and heavily faulted reservoirs. In this paper, we employed our recently introduced interpretation workflow to evaluate the connectivity of a heavily faulted reservoir in the deepwater Gulf of Mexico. The field was divided into five investigation areas penetrated by 12 wells. Areal downhole fluid analysis (ADFA) was applied to assess local connectivity leading to reservoir-scale connectivity. Through integrating fluid/dynamic and rock/static data, each data type provided insights that were pieced together to enhance consistency and reduce uncertainty. Analyzed data included pressure-volume-temperature (PVT) reports, pressure surveys, well logs, and geochemistry. The study resulted in a verifiable connectivity description where faults, previously regarded as sealing, were classified into sealing or partially transmissive faults; unresolved faults were detected. Fault-block migration was detected, and fault throw was estimated; asphaltenes behavior was used to deduce original field structures prior to faulting. We also examined RFG processes to investigate oil biodegradation, where an asphaltene clustering trend was observed, causing high oil viscosities toward the bottom of one sandstone. A correlation was then derived and successfully implemented to estimate oil viscosity.","PeriodicalId":49703,"journal":{"name":"Petrophysics","volume":"17 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"134930950","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Core analysis techniques have traditionally been used mainly for hydrocarbon reservoir applications. However, the same techniques are equally applicable to reservoir issues associated with energy transition, such as geothermal prospects, carbon geosequestration, and hydrogen storage. Traditionally, much core analysis has been performed successfully using core plugs. However, this approach has certain drawbacks: (1) the selected plugs may not necessarily be representative of the full range of lithologies, (2) key features (e.g., thin naturally cemented or fractured zones) may be missed, (3) high-resolution detail at the lamina scale may be missed, (4) depth shifting to well logs may not be sufficiently accurate, and (5) this strategy may be more sensitive to missing core. In this paper, we highlight the usefulness of probe core analysis techniques on slabbed core and powdered samples. For many reservoirs relevant to energy transition, it is crucial to have a high-resolution continuous record of petrophysical properties so that key features are not missed. Probe measurements are less destructive, without the need to cut core plugs, and provide: (1) high-resolution data at the lamina scale so that key features and small-scale heterogeneities can be identified, (2) improved depth matching to well-log data, and (3) rapid, cost-effective data. We describe examples highlighting some different probe techniques. While some techniques are well known, such as probe permeability, others, such as probe acoustics, probe luminance (from linear X-ray measurements), and probe magnetics, are less familiar to core analysts but are well suited for analyzing cores from reservoirs associated with energy transition as well as hydrocarbons. For example, potential geothermal prospects involve studying igneous and metamorphic samples (where the main radiogenic heat sources reside) as well as sedimentary samples, and differences in the magnetic susceptibility signals using a small, portable magnetic probe can quickly differentiate the different rock types. Probe acoustics can be used to (1) rapidly identify anisotropy by orienting the acoustic transmitter-receiver bracket in different directions, (2) identify open microfractures via longer transit times, and (3) produce high-resolution porosity profiles after correlation of transit times with some representative plug or well-log porosity data. Probe luminance and associated linear X-ray images, which are related to density, can indicate small-scale heterogeneities that may impact permeability variation and anisotropy and may not be seen from mere visual observations of the slabbed core surface.
{"title":"Probe Screening Techniques for Rapid, High-Resolution Core Analysis and Their Potential Usefulness for Energy Transition Applications","authors":"Emmanuel Okwoli, David K. Potter","doi":"10.30632/pjv64n5-2023a3","DOIUrl":"https://doi.org/10.30632/pjv64n5-2023a3","url":null,"abstract":"Core analysis techniques have traditionally been used mainly for hydrocarbon reservoir applications. However, the same techniques are equally applicable to reservoir issues associated with energy transition, such as geothermal prospects, carbon geosequestration, and hydrogen storage. Traditionally, much core analysis has been performed successfully using core plugs. However, this approach has certain drawbacks: (1) the selected plugs may not necessarily be representative of the full range of lithologies, (2) key features (e.g., thin naturally cemented or fractured zones) may be missed, (3) high-resolution detail at the lamina scale may be missed, (4) depth shifting to well logs may not be sufficiently accurate, and (5) this strategy may be more sensitive to missing core. In this paper, we highlight the usefulness of probe core analysis techniques on slabbed core and powdered samples. For many reservoirs relevant to energy transition, it is crucial to have a high-resolution continuous record of petrophysical properties so that key features are not missed. Probe measurements are less destructive, without the need to cut core plugs, and provide: (1) high-resolution data at the lamina scale so that key features and small-scale heterogeneities can be identified, (2) improved depth matching to well-log data, and (3) rapid, cost-effective data. We describe examples highlighting some different probe techniques. While some techniques are well known, such as probe permeability, others, such as probe acoustics, probe luminance (from linear X-ray measurements), and probe magnetics, are less familiar to core analysts but are well suited for analyzing cores from reservoirs associated with energy transition as well as hydrocarbons. For example, potential geothermal prospects involve studying igneous and metamorphic samples (where the main radiogenic heat sources reside) as well as sedimentary samples, and differences in the magnetic susceptibility signals using a small, portable magnetic probe can quickly differentiate the different rock types. Probe acoustics can be used to (1) rapidly identify anisotropy by orienting the acoustic transmitter-receiver bracket in different directions, (2) identify open microfractures via longer transit times, and (3) produce high-resolution porosity profiles after correlation of transit times with some representative plug or well-log porosity data. Probe luminance and associated linear X-ray images, which are related to density, can indicate small-scale heterogeneities that may impact permeability variation and anisotropy and may not be seen from mere visual observations of the slabbed core surface.","PeriodicalId":49703,"journal":{"name":"Petrophysics","volume":"57 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"134930951","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Nikolaos Karadimitriou, Marios S. Valavanides, Konstantinos Mouravas, Holger Steeb
Conventionally, the relative permeabilities of two immiscible fluid phases flowing in porous media are considered and expressed as functions of saturation. Yet, this has been put into challenge by theoretical, numerical, and laboratory studies of flow in artificial pore network models and real porous media. These works have revealed a significant dependency of the relative permeabilities on the flow rates, especially when the flow regime is capillary to capillary-viscous dominated, and part of the disconnected nonwetting phase remains mobile. These studies suggest that relative permeability models should include the functional dependence on flow intensities. However, revealing the explicit form of such dependence remains a persistent problem. Just recently, a general form of dependence was inferred based on extensive simulations with the DeProF model for steady-state two-phase flows in pore networks. The simulations revealed a systematic dependence of the relative permeabilities on the local flow rate intensities. This dependence can be described analytically by a universal scaling functional form of the actual independent variables of the process, namely, the capillary number, Ca, and the flow rate ratio, r. The proposed scaling incorporated a kernel function, the intrinsic dynamic capillary pressure (IDCP) function, describing the transition between capillarity- and viscosity-dominated flow phenomena. In a parallel laboratory study, SCAL measurements provided a preliminary proof-of-concept on the applicability of the model. In the laboratory study presented here, we examine the applicability of the scaling model by taking extensive, ex-core measurements of relative permeabilities for steady-state co-injections of two immiscible fluids within an artificial microfluidic pore network, across different flow regimes in Ca and r. From these measurements, we calculate the values of the mobility ratio, and we compare these to the corresponding values of the flow rate ratio. We also extract the IDCP curve, the locus of critical flow conditions, whereby the process is more efficient in terms of energy utilization – accounted by the nonwetting phase flow rate per unit of total power provided to the process, as well as the locus of flow conditions of equal relative permeabilities. We show that the degree of consistency between flow rate ratio and mobility ratio values, the IDCP curve, the locus of critical flow conditions, and the locus of equal relative permeabilities, as well as some associated invariant characteristic values, can be used for assessing the extent of end effects and for characterizing the flow as capillary- or viscous-dominated. The proposed scaling introduces new opportunities for enhancing SCAL protocols and their associated applications. These include the characterization of systems and flow conditions, dynamic rock typing, evaluation of capillary end effects, as well as the advancement of more efficient field-scale simulators. Additio
{"title":"Flow-Dependent Relative Permeability Scaling for Steady-State Two-Phase Flow in Porous Media: Laboratory Validation on a Microfluidic Network","authors":"Nikolaos Karadimitriou, Marios S. Valavanides, Konstantinos Mouravas, Holger Steeb","doi":"10.30632/pjv64n5-2023a4","DOIUrl":"https://doi.org/10.30632/pjv64n5-2023a4","url":null,"abstract":"Conventionally, the relative permeabilities of two immiscible fluid phases flowing in porous media are considered and expressed as functions of saturation. Yet, this has been put into challenge by theoretical, numerical, and laboratory studies of flow in artificial pore network models and real porous media. These works have revealed a significant dependency of the relative permeabilities on the flow rates, especially when the flow regime is capillary to capillary-viscous dominated, and part of the disconnected nonwetting phase remains mobile. These studies suggest that relative permeability models should include the functional dependence on flow intensities. However, revealing the explicit form of such dependence remains a persistent problem. Just recently, a general form of dependence was inferred based on extensive simulations with the DeProF model for steady-state two-phase flows in pore networks. The simulations revealed a systematic dependence of the relative permeabilities on the local flow rate intensities. This dependence can be described analytically by a universal scaling functional form of the actual independent variables of the process, namely, the capillary number, Ca, and the flow rate ratio, r. The proposed scaling incorporated a kernel function, the intrinsic dynamic capillary pressure (IDCP) function, describing the transition between capillarity- and viscosity-dominated flow phenomena. In a parallel laboratory study, SCAL measurements provided a preliminary proof-of-concept on the applicability of the model. In the laboratory study presented here, we examine the applicability of the scaling model by taking extensive, ex-core measurements of relative permeabilities for steady-state co-injections of two immiscible fluids within an artificial microfluidic pore network, across different flow regimes in Ca and r. From these measurements, we calculate the values of the mobility ratio, and we compare these to the corresponding values of the flow rate ratio. We also extract the IDCP curve, the locus of critical flow conditions, whereby the process is more efficient in terms of energy utilization – accounted by the nonwetting phase flow rate per unit of total power provided to the process, as well as the locus of flow conditions of equal relative permeabilities. We show that the degree of consistency between flow rate ratio and mobility ratio values, the IDCP curve, the locus of critical flow conditions, and the locus of equal relative permeabilities, as well as some associated invariant characteristic values, can be used for assessing the extent of end effects and for characterizing the flow as capillary- or viscous-dominated. The proposed scaling introduces new opportunities for enhancing SCAL protocols and their associated applications. These include the characterization of systems and flow conditions, dynamic rock typing, evaluation of capillary end effects, as well as the advancement of more efficient field-scale simulators. Additio","PeriodicalId":49703,"journal":{"name":"Petrophysics","volume":"279 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"136117803","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Jean Desroches, Emilie Peyret, Adriaan Gisolf, Ailsa Wilcox, Mauro Di Giovann`i, Aernout Schram de Jong, Siavash Sepehri, Rodney Garrard, Silvio Giger
As part of the Sectoral Plan for Deep Geological Repositories, three potential siting regions are currently being investigated by means of a focused geological exploration program in northern Switzerland. The program involved drilling eight vertical boreholes and one deviated deep borehole with at least two vertical boreholes per siting region. Stress testing was undertaken with a wireline formation testing tool in each borehole (around 20 stress tests per borehole). Improvements in the tool string were introduced step by step to sharpen the range of the stress estimates and enable 100% coverage of the desired lithological column. This is the first time that a single tool string with three packers has been run to perform the complete combination of sleeve fracturing (SF), hydraulic fracturing, and sleeve reopening (SR) tests. A dedicated stress testing protocol was developed to ensure the most robust estimate of the stress in a large variety of formations. A detailed planning process was developed to maximize the success rate and coverage of stress test stations, integrating all available information as it becomes available. A review of the techniques enabled by the new tool string for estimating the closure stress from a stress test, especially in low-permeability formations, is presented, and detailed stress testing examples are provided. A preliminary comparison between the stress estimates for the first two boreholes in the campaign is shown.
{"title":"Stress Measurement Campaign in Scientific Deep Boreholes: Focus on Tools and Methods","authors":"Jean Desroches, Emilie Peyret, Adriaan Gisolf, Ailsa Wilcox, Mauro Di Giovann`i, Aernout Schram de Jong, Siavash Sepehri, Rodney Garrard, Silvio Giger","doi":"10.30632/pjv64n5-2023a2","DOIUrl":"https://doi.org/10.30632/pjv64n5-2023a2","url":null,"abstract":"As part of the Sectoral Plan for Deep Geological Repositories, three potential siting regions are currently being investigated by means of a focused geological exploration program in northern Switzerland. The program involved drilling eight vertical boreholes and one deviated deep borehole with at least two vertical boreholes per siting region. Stress testing was undertaken with a wireline formation testing tool in each borehole (around 20 stress tests per borehole). Improvements in the tool string were introduced step by step to sharpen the range of the stress estimates and enable 100% coverage of the desired lithological column. This is the first time that a single tool string with three packers has been run to perform the complete combination of sleeve fracturing (SF), hydraulic fracturing, and sleeve reopening (SR) tests. A dedicated stress testing protocol was developed to ensure the most robust estimate of the stress in a large variety of formations. A detailed planning process was developed to maximize the success rate and coverage of stress test stations, integrating all available information as it becomes available. A review of the techniques enabled by the new tool string for estimating the closure stress from a stress test, especially in low-permeability formations, is presented, and detailed stress testing examples are provided. A preliminary comparison between the stress estimates for the first two boreholes in the campaign is shown.","PeriodicalId":49703,"journal":{"name":"Petrophysics","volume":"21 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"134930949","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Data quality of well logs and laboratory measurements is crucial for accurate petrophysical interpretations in formations with complex solid compositions, thin beds, and adverse geometrical conditions . In this paper, we introduce a new method to calibrate and verify the reliability of core data and well logs acquired in spatially complex rocks. The method is based on the numerical simulation of well logs to reproduce the effects of borehole environmental conditions and instrument physics on the measurements. Additionally, high-resolution (HR) core data combined with rock typing and multiwell measurement analysis techniques enable the construction of multilayer formation models. We document the successful application of the new core-well-log calibration method to two wells penetrating a clastic formation in the North Sea. While the numerically simulated well logs match the available borehole measurements in the first well, large measurement discrepancies were observed in the second well. Normalization of nuclear logs in the second well based on core data and numerically simulated well logs improved the assessment of bulk density and neutron porosity by 5% and 20%, respectively, while unnormalized nuclear logs overestimated formation porosity. Multiwell comparisons of well logs also confirmed that measurement accuracy was compromised. The problem with data quality was attributed to a probable inadequate tool calibration, although the log header did not indicate any notable issues. Additionally, numerical simulations of nuclear magnetic resonance (NMR) porosity logs indicated a prominent depth mismatch among well logs. The numerical simulation of well logs based on HR core data enables the detection of inconsistent, noisy, and inaccurate measurements, including cases of abnormal borehole environmental corrections causing biases in petrophysical interpretations.
{"title":"Numerical Simulation of Well Logs Based on Core Measurements: An Effective Method for Data Quality Control and Improved Petrophysical Interpretation","authors":"Mohamed Bennis, Carlos Torres-Verdín","doi":"10.30632/pjv64n5-2023a9","DOIUrl":"https://doi.org/10.30632/pjv64n5-2023a9","url":null,"abstract":"Data quality of well logs and laboratory measurements is crucial for accurate petrophysical interpretations in formations with complex solid compositions, thin beds, and adverse geometrical conditions . In this paper, we introduce a new method to calibrate and verify the reliability of core data and well logs acquired in spatially complex rocks. The method is based on the numerical simulation of well logs to reproduce the effects of borehole environmental conditions and instrument physics on the measurements. Additionally, high-resolution (HR) core data combined with rock typing and multiwell measurement analysis techniques enable the construction of multilayer formation models. We document the successful application of the new core-well-log calibration method to two wells penetrating a clastic formation in the North Sea. While the numerically simulated well logs match the available borehole measurements in the first well, large measurement discrepancies were observed in the second well. Normalization of nuclear logs in the second well based on core data and numerically simulated well logs improved the assessment of bulk density and neutron porosity by 5% and 20%, respectively, while unnormalized nuclear logs overestimated formation porosity. Multiwell comparisons of well logs also confirmed that measurement accuracy was compromised. The problem with data quality was attributed to a probable inadequate tool calibration, although the log header did not indicate any notable issues. Additionally, numerical simulations of nuclear magnetic resonance (NMR) porosity logs indicated a prominent depth mismatch among well logs. The numerical simulation of well logs based on HR core data enables the detection of inconsistent, noisy, and inaccurate measurements, including cases of abnormal borehole environmental corrections causing biases in petrophysical interpretations.","PeriodicalId":49703,"journal":{"name":"Petrophysics","volume":"64 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"134930952","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2023-10-01DOI: 10.30632/pjv64n5-2023a11
Mian Umer Shafiq, Hisham Ben Mahmud, Momna Khan, Sophia Nawaz Gishkori, Lei Wang, Maryam Jamil
Dissolution of the wellbore damage is the main target of sandstone acidizing. The presence of minerals like clays, feldspar, zeolites, and alumino-silicates makes acidizing a challenging task because they may form undesired products (precipitates) when reacted with mud acid. Secondary and tertiary reactions are responsible for the formation of these products. To avoid the formation of precipitates, which are formed due to the reaction of conventional acids with minerals, chelating agents were utilized in this research paper. The chelating agents provide the advantage of deep penetration and slow reaction rate. The chelating agents HEDTA (hydroxyethylethylenediaminetriacetic acid), GLDA (tetrasodium glutamate diacetate), and EDTA (ethylethylenediaminetriacetic acid) were allowed to react with Colton sandstone formation under 1,000 psi confining pressure and 180°F temperature. The reacted core samples were tested for different analyses to analyze the effect of chelates on the core sample properties. The analyses performed are elemental analysis, mineral analysis, grain-size analysis, and porosity, particle, and density analysis. In elemental analysis, due to the tight nature of the Colton sandstone, the chelates were not that effective. From mineral analysis, HEDTA proved to be effective in the dissolution of quartz, ankerite, orthoclase, and calcite compared to GLDA and EDTA. According to a porosity analysis investigation, HEDTA produced the most additional pore spaces when reacted with the Colton sandstone formation.
{"title":"Effect of Chelating Agents on Tight Sandstone Formation Mineralogy During Sandstone Acidizing","authors":"Mian Umer Shafiq, Hisham Ben Mahmud, Momna Khan, Sophia Nawaz Gishkori, Lei Wang, Maryam Jamil","doi":"10.30632/pjv64n5-2023a11","DOIUrl":"https://doi.org/10.30632/pjv64n5-2023a11","url":null,"abstract":"Dissolution of the wellbore damage is the main target of sandstone acidizing. The presence of minerals like clays, feldspar, zeolites, and alumino-silicates makes acidizing a challenging task because they may form undesired products (precipitates) when reacted with mud acid. Secondary and tertiary reactions are responsible for the formation of these products. To avoid the formation of precipitates, which are formed due to the reaction of conventional acids with minerals, chelating agents were utilized in this research paper. The chelating agents provide the advantage of deep penetration and slow reaction rate. The chelating agents HEDTA (hydroxyethylethylenediaminetriacetic acid), GLDA (tetrasodium glutamate diacetate), and EDTA (ethylethylenediaminetriacetic acid) were allowed to react with Colton sandstone formation under 1,000 psi confining pressure and 180°F temperature. The reacted core samples were tested for different analyses to analyze the effect of chelates on the core sample properties. The analyses performed are elemental analysis, mineral analysis, grain-size analysis, and porosity, particle, and density analysis. In elemental analysis, due to the tight nature of the Colton sandstone, the chelates were not that effective. From mineral analysis, HEDTA proved to be effective in the dissolution of quartz, ankerite, orthoclase, and calcite compared to GLDA and EDTA. According to a porosity analysis investigation, HEDTA produced the most additional pore spaces when reacted with the Colton sandstone formation.","PeriodicalId":49703,"journal":{"name":"Petrophysics","volume":"153 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"134934806","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Robert Laronga, Erik Borchardt, Barbara Hill, Edgar Velez, Denis Klemin, Sammy Haddad, Elia Haddad, Casey Chadwick, Elham Mahmoodaghdam, Farid Hamichi
Participation in over 80 carbon capture and sequestration (CCS) projects spanning 25 years has led to the evolution of a recommended well-based appraisal workflow for CO2 sequestration in saline aquifers. Interpretation methods are expressly adapted for CCS applications to resolve key reservoir parameters, constrain field-scale modeling, provide answers required for the permitting process, and de-risk unique CCS evaluation challenges, such as Storage capacity Injectivity Containment. A challenge complicating all of the above is the eventual impact of three-way interaction among rock matrix, brine, and (impure) CO2 streams. Most logging, sampling, and laboratory techniques are adapted from established domains such as enhanced oil recovery, underground gas storage, and unconventional reservoir evaluation, though some CCS-specific innovation is also needed. Storage evaluation begins with established methods for lithology, porosity, permeability, and pressure, while special core analysis (SCAL) determines CO2 storage efficiency and relative permeability. Containment evaluation spans multiple disciplines and methods: the petrophysicist’s task to quantify seal capacity relies heavily on laboratory analysis, while geologists leverage downhole imaging tools to verify caprock structural/tectonic integrity. Geomechanics engineers define safe injection pressure via mechanical earth models (MEMs) built on advanced acoustic logs calibrated by core geomechanics, wellbore failure observations, and in-situ stress tests. The impact of rock-brine-CO2 interactions is studied via custom SCAL experiments and/or pore-scale digital rock simulations that rigorously represent chemical and thermal processes. Wireline formation tester samples provide representative formation brine as feedstock for SCAL. Water samples also enable operators to prove injection within regulatory limits while establishing baselines for future monitoring programs. Examples applied to recent CCS projects in North America are presented. All of the above data need to be integrated into a CCS model predicting the CO2 plume behavior across the area of interest and within multiple horizons.
{"title":"Integrated Formation Evaluation for Site-Specific Evaluation, Optimization, and Permitting of Carbon Storage Projects","authors":"Robert Laronga, Erik Borchardt, Barbara Hill, Edgar Velez, Denis Klemin, Sammy Haddad, Elia Haddad, Casey Chadwick, Elham Mahmoodaghdam, Farid Hamichi","doi":"10.30632/pjv64n5-2023a1","DOIUrl":"https://doi.org/10.30632/pjv64n5-2023a1","url":null,"abstract":"Participation in over 80 carbon capture and sequestration (CCS) projects spanning 25 years has led to the evolution of a recommended well-based appraisal workflow for CO2 sequestration in saline aquifers. Interpretation methods are expressly adapted for CCS applications to resolve key reservoir parameters, constrain field-scale modeling, provide answers required for the permitting process, and de-risk unique CCS evaluation challenges, such as Storage capacity Injectivity Containment. A challenge complicating all of the above is the eventual impact of three-way interaction among rock matrix, brine, and (impure) CO2 streams. Most logging, sampling, and laboratory techniques are adapted from established domains such as enhanced oil recovery, underground gas storage, and unconventional reservoir evaluation, though some CCS-specific innovation is also needed. Storage evaluation begins with established methods for lithology, porosity, permeability, and pressure, while special core analysis (SCAL) determines CO2 storage efficiency and relative permeability. Containment evaluation spans multiple disciplines and methods: the petrophysicist’s task to quantify seal capacity relies heavily on laboratory analysis, while geologists leverage downhole imaging tools to verify caprock structural/tectonic integrity. Geomechanics engineers define safe injection pressure via mechanical earth models (MEMs) built on advanced acoustic logs calibrated by core geomechanics, wellbore failure observations, and in-situ stress tests. The impact of rock-brine-CO2 interactions is studied via custom SCAL experiments and/or pore-scale digital rock simulations that rigorously represent chemical and thermal processes. Wireline formation tester samples provide representative formation brine as feedstock for SCAL. Water samples also enable operators to prove injection within regulatory limits while establishing baselines for future monitoring programs. Examples applied to recent CCS projects in North America are presented. All of the above data need to be integrated into a CCS model predicting the CO2 plume behavior across the area of interest and within multiple horizons.","PeriodicalId":49703,"journal":{"name":"Petrophysics","volume":"122 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"134930948","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
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