High-resolution X-ray microcomputed tomography (micro-CT) was used to investigate the process of mud-filtrate invasion in laminated and spatially heterogeneous rocks. Laboratory experiments involved the injection of pressurized water-based drilling mud into a borehole located at the center of cylindrical rock core samples that exhibited a range of petrophysical properties, including a cross-bedded sandstone, a finely laminated anisotropic sandstone, an oolitic limestone with significant pore-scale heterogeneity, and a spatially heterogeneous vuggy dolomite. As drilling mud was injected into the initially dry (air-saturated) core samples, high-resolution X-ray micro-CT scanning was continuously performed to visualize the flow of mud filtrate through the core samples during mud-filtrate invasion. Because the properties of the drilling mud were consistent for all of the experimental cases, differences observed in the invasion behavior could be attributed to the unique properties of the core samples. Despite exhibiting a wide range of petrophysical properties, including permeabilities ranging from 8.9 to over 1,800 md, the mud-filtrate invasion rate was similar for all of the experimental cases, aside from a brief initial period of spurt loss that lasted only a few seconds, indicating that properties of the deposited mudcake were responsible for controlling the rate of mud-filtrate invasion rather than the unique properties of the core samples. Conversely, displacement of the invasion front and the spatial distribution of mud filtrate in the core samples differed significantly between cases, both spatially and as a function of time. Initially, mud-filtrate flow in the core samples was dominated by viscous forces, and air was forcibly displaced from around the borehole. Shortly thereafter, we observed a rapid transition to capillary-dominated flow as the deposition of mudcake on the borehole wall quickly reduced the rate of mud-filtrate invasion. As a result of the displacement process being controlled by capillary forces, we observed that mud filtrate within the invaded zone became more uniformly distributed over time, with mud filtrate from around the borehole being drawn further into the core samples. The average mud-filtrate saturation within the invaded zone initially decreased before stabilizing between 43 and 51%, indicating that a significant volume of trapped gas (air) remained behind the invasion front. Experimental results indicate that borehole measurements acquired at early times during the mud-filtrate invasion process, such as those acquired while drilling, may be more sensitive to small-scale heterogeneity than wireline measurements acquired later once capillary forces have caused the mud-filtrate saturation within the invaded zone to become more uniformly distributed. Furthermore, because capillary forces were primarily responsible for controlling the mud-filtrate saturation in the invaded zone, fluids from around the borehole may not
{"title":"Mud-Filtrate Invasion in Laminated and Spatially Heterogeneous Rocks: High-Resolution In-Situ Visualization and Analysis Using Time-Lapse X-Ray Microcomputed Tomography (Micro-CT)","authors":"Colin Schroeder, C. Torres‐Verdín","doi":"10.30632/pjv63n5-2022a4","DOIUrl":"https://doi.org/10.30632/pjv63n5-2022a4","url":null,"abstract":"High-resolution X-ray microcomputed tomography (micro-CT) was used to investigate the process of mud-filtrate invasion in laminated and spatially heterogeneous rocks. Laboratory experiments involved the injection of pressurized water-based drilling mud into a borehole located at the center of cylindrical rock core samples that exhibited a range of petrophysical properties, including a cross-bedded sandstone, a finely laminated anisotropic sandstone, an oolitic limestone with significant pore-scale heterogeneity, and a spatially heterogeneous vuggy dolomite. As drilling mud was injected into the initially dry (air-saturated) core samples, high-resolution X-ray micro-CT scanning was continuously performed to visualize the flow of mud filtrate through the core samples during mud-filtrate invasion. Because the properties of the drilling mud were consistent for all of the experimental cases, differences observed in the invasion behavior could be attributed to the unique properties of the core samples. Despite exhibiting a wide range of petrophysical properties, including permeabilities ranging from 8.9 to over 1,800 md, the mud-filtrate invasion rate was similar for all of the experimental cases, aside from a brief initial period of spurt loss that lasted only a few seconds, indicating that properties of the deposited mudcake were responsible for controlling the rate of mud-filtrate invasion rather than the unique properties of the core samples. Conversely, displacement of the invasion front and the spatial distribution of mud filtrate in the core samples differed significantly between cases, both spatially and as a function of time. Initially, mud-filtrate flow in the core samples was dominated by viscous forces, and air was forcibly displaced from around the borehole. Shortly thereafter, we observed a rapid transition to capillary-dominated flow as the deposition of mudcake on the borehole wall quickly reduced the rate of mud-filtrate invasion. As a result of the displacement process being controlled by capillary forces, we observed that mud filtrate within the invaded zone became more uniformly distributed over time, with mud filtrate from around the borehole being drawn further into the core samples. The average mud-filtrate saturation within the invaded zone initially decreased before stabilizing between 43 and 51%, indicating that a significant volume of trapped gas (air) remained behind the invasion front. Experimental results indicate that borehole measurements acquired at early times during the mud-filtrate invasion process, such as those acquired while drilling, may be more sensitive to small-scale heterogeneity than wireline measurements acquired later once capillary forces have caused the mud-filtrate saturation within the invaded zone to become more uniformly distributed. Furthermore, because capillary forces were primarily responsible for controlling the mud-filtrate saturation in the invaded zone, fluids from around the borehole may not","PeriodicalId":170688,"journal":{"name":"Petrophysics – The SPWLA Journal of Formation Evaluation and Reservoir Description","volume":"1277 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"127434105","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}
Mehdi Alipour K, A. Kasha, A. Sakhaee-Pour, F. Sadooni, H. Al-kuwari
Brooks and Corey (1964) and van Genuchten (1980) proposed the two most widely used relations for approximating capillary pressure. Petroleum engineers apply both, but they were originally proposed to understand the moisture content in soil whose void space differs from that of shale. This paper presents an empirical relation that can capture the nonplateau-like trend and the approximate capillary pressure in shale. It also implements the nonzero entry pressure, which the van Genuchten model cannot capture. This study compares the performance of the proposed model with those of Brooks and Corey and van Genuchten by determining the nonlinear regression coefficient (R2) and the mean square error (MSE). It uses mercury capillary pressure data of US shales available in the literature. The data set comprises 30 samples collected from the Bakken, Eagle Ford, and Greenhorn Formations with average permeability of less than 1 md and average porosity of 5%. The proposed model has applications in characterizing two-phase displacement in shales.
Brooks and Corey(1964)和van Genuchten(1980)提出了两个最广泛使用的近似毛细管压力的关系式。石油工程师使用这两种方法，但它们最初是为了了解空隙空间与页岩不同的土壤中的水分含量。本文提出了一种能够反映页岩非高原样趋势与近似毛管压力的经验关系式。它还实现了van Genuchten模型无法捕获的非零进入压力。本研究通过确定非线性回归系数(R2)和均方误差(MSE)，将所提模型的性能与Brooks、Corey和van Genuchten的模型进行了比较。它使用文献中可用的美国页岩汞毛细管压力数据。该数据集包括从Bakken、Eagle Ford和Greenhorn地层采集的30个样品，平均渗透率小于1 md，平均孔隙度为5%。该模型可用于表征页岩两相驱替。
{"title":"Empirical Relation for Capillary Pressure in Shale","authors":"Mehdi Alipour K, A. Kasha, A. Sakhaee-Pour, F. Sadooni, H. Al-kuwari","doi":"10.30632/pjv63n5-2022a2","DOIUrl":"https://doi.org/10.30632/pjv63n5-2022a2","url":null,"abstract":"Brooks and Corey (1964) and van Genuchten (1980) proposed the two most widely used relations for approximating capillary pressure. Petroleum engineers apply both, but they were originally proposed to understand the moisture content in soil whose void space differs from that of shale. This paper presents an empirical relation that can capture the nonplateau-like trend and the approximate capillary pressure in shale. It also implements the nonzero entry pressure, which the van Genuchten model cannot capture. This study compares the performance of the proposed model with those of Brooks and Corey and van Genuchten by determining the nonlinear regression coefficient (R2) and the mean square error (MSE). It uses mercury capillary pressure data of US shales available in the literature. The data set comprises 30 samples collected from the Bakken, Eagle Ford, and Greenhorn Formations with average permeability of less than 1 md and average porosity of 5%. The proposed model has applications in characterizing two-phase displacement in shales.","PeriodicalId":170688,"journal":{"name":"Petrophysics – The SPWLA Journal of Formation Evaluation and Reservoir Description","volume":"23 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"132541622","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}
A standardized preparation method for rock specimens is required before conducting mechanical tests. Conventional sampling methods produce good results for good-quality rocks. However, during the preparation of standard specimens of rocks found in areas with complex geological conditions, such as dolomite rocks with well-developed fractures, the internal fissures are easily disturbed, leading to sample preparation failure. Inspired by the effectiveness of organic resin solution-based reinforcements in protecting bone and porcelain artifacts during archaeological excavations, this study developed a method to prepare specimens for dolomite infiltration reinforcement using an acrylic resin-in-acetone solution, whereby the mechanical parameters of the rock samples could be recovered upon successful sample preparation. Several tests conducted under optimized ratios of acrylic resin to acetone revealed that a solution mass fraction of 20% produced the best effect on the reinforcement of fractured dolomite from the sampling location and increased the success rate of rock sample preparation from 15 to 54%. The physical and mechanical properties of the specimens after immersion in pure acetone for 48 hours were unaffected. The proposed method provides a reference for rock sampling from areas with developed joint fissures.
{"title":"Coring Method for Dolomite Rocks With Well-Developed Joint Fissures Based on Permeability Reinforcement","authors":"Xinqiang Gao, Zecheng Ma, C.M. Kong, Hao Wang, Zhijun Lang, H. Fan, Yongquan Zhu, Zhen Zhu","doi":"10.30632/pjv63n5-2022a6","DOIUrl":"https://doi.org/10.30632/pjv63n5-2022a6","url":null,"abstract":"A standardized preparation method for rock specimens is required before conducting mechanical tests. Conventional sampling methods produce good results for good-quality rocks. However, during the preparation of standard specimens of rocks found in areas with complex geological conditions, such as dolomite rocks with well-developed fractures, the internal fissures are easily disturbed, leading to sample preparation failure. Inspired by the effectiveness of organic resin solution-based reinforcements in protecting bone and porcelain artifacts during archaeological excavations, this study developed a method to prepare specimens for dolomite infiltration reinforcement using an acrylic resin-in-acetone solution, whereby the mechanical parameters of the rock samples could be recovered upon successful sample preparation. Several tests conducted under optimized ratios of acrylic resin to acetone revealed that a solution mass fraction of 20% produced the best effect on the reinforcement of fractured dolomite from the sampling location and increased the success rate of rock sample preparation from 15 to 54%. The physical and mechanical properties of the specimens after immersion in pure acetone for 48 hours were unaffected. The proposed method provides a reference for rock sampling from areas with developed joint fissures.","PeriodicalId":170688,"journal":{"name":"Petrophysics – The SPWLA Journal of Formation Evaluation and Reservoir Description","volume":"41 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"114223494","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}
The matrix permeability of tight formations is important for many geological and engineering applications, such as CO2 geological sequestration, disposal of nuclear waste, and production of unconventional hydrocarbon and coalbed methane. In the case of hydrocarbon production, the reservoir permeability decreases with decreasing pore pressure or increasing effective stress. Laboratory characterization of the relationship between matrix permeability and effective stress (and pore pressure) is generally time consuming since the current methods are based on the so-called point-by-point approach that measures one permeability data point only with one test run, and the relationship is generally represented with multiple data points. In this paper, we present a method to determine matrix permeability, its relationship with effective stress, and the Biot coefficient of a tight rock sample with three steady-state flow test runs using large pressure gradients. Unlike the traditional steady-state flow method based on linear flow theories, analytical results based on a nonlinear flow theory are used for determining the related relationship and parameters. The gas properties and permeability along the core sample vary with gas pressure and effective stress, while the traditional method treats them as constants for a given test run. To get the same set of parameters, our method only requires three test runs, and each test run of our method takes a much shorter time than the traditional method because our method is based on nonlinear flow theory and thus allows for the use of large pressure gradients. Comparisons of the permeability measurements with those obtained using traditional methods and numerical simulations demonstrate that our new method can get satisfactory results.
{"title":"An Efficient Laboratory Method to Measure Stress-Dependent Tight Rock Permeability With the Steady-State Flow Method","authors":"J. Zhang, Hui-Hai Liu, Jewel Duncan","doi":"10.30632/pjv63n5-2022a3","DOIUrl":"https://doi.org/10.30632/pjv63n5-2022a3","url":null,"abstract":"The matrix permeability of tight formations is important for many geological and engineering applications, such as CO2 geological sequestration, disposal of nuclear waste, and production of unconventional hydrocarbon and coalbed methane. In the case of hydrocarbon production, the reservoir permeability decreases with decreasing pore pressure or increasing effective stress. Laboratory characterization of the relationship between matrix permeability and effective stress (and pore pressure) is generally time consuming since the current methods are based on the so-called point-by-point approach that measures one permeability data point only with one test run, and the relationship is generally represented with multiple data points. In this paper, we present a method to determine matrix permeability, its relationship with effective stress, and the Biot coefficient of a tight rock sample with three steady-state flow test runs using large pressure gradients. Unlike the traditional steady-state flow method based on linear flow theories, analytical results based on a nonlinear flow theory are used for determining the related relationship and parameters. The gas properties and permeability along the core sample vary with gas pressure and effective stress, while the traditional method treats them as constants for a given test run. To get the same set of parameters, our method only requires three test runs, and each test run of our method takes a much shorter time than the traditional method because our method is based on nonlinear flow theory and thus allows for the use of large pressure gradients. Comparisons of the permeability measurements with those obtained using traditional methods and numerical simulations demonstrate that our new method can get satisfactory results.","PeriodicalId":170688,"journal":{"name":"Petrophysics – The SPWLA Journal of Formation Evaluation and Reservoir Description","volume":"2 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124497892","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}
Chengyu Zhou, Linghao Zeng, Yuan Sun, Min Zhou, Mingyao Lei, W. Wan, Yufeng Luo, Bo-Wei Wu, Peng Zhang, Ying Xiao
In order to explore the corrosion effect of CO2 and H2S in oilwell cement, the samples were exposed to a CO2/H2S environment. The permeability, microstructure, chemical composition, and tensile strength of the cement samples were measured by a pulse pore-permeability tester, scanning electron microscope (SEM), X-ray diffraction (XRD), and rock tensile compression tester, respectively. The corrosion behavior and mechanism of the cement samples were analyzed. The experimental results show that the corrosion degree increases with the exposure time, and the permeability increases from 0.0003 md on the seventh day to 0.0646 md on the thirtieth day. It can be concluded from the microscopic morphology that the internal structure of the corroded cement sample is compact, without an obvious loose structure, but there are some particles with different particle sizes. The composition phases of the products after corrosion are mainly calcium carbonate and silica, and the content of calcium carbonate in the corrosion area increases obviously. The tensile strength of the tested cement sample is only 9.8 MPa. The reaction of gaseous CO2 and H2S with calcium-bearing phases in a cement sample is known to cause a lowering of alkalinity, leading to the corrosion of the cement sample. Due to the existence of carbonation, carbon dioxide will gradually diffuse into the interior of the cement sample and react with hydrogen ions, calcium ions, and bicarbonate ions in the pore fluid of the cement sample to form varieties of calcium carbonate, resulting in the shrinkage of the cement sample, surface cracks, and ultimately affecting the compactness and sealing effect of the cement sample.
{"title":"Corrosion Behavior and Mechanism Analysis of Oilwell Cement Under CO2 and H2S Conditions","authors":"Chengyu Zhou, Linghao Zeng, Yuan Sun, Min Zhou, Mingyao Lei, W. Wan, Yufeng Luo, Bo-Wei Wu, Peng Zhang, Ying Xiao","doi":"10.30632/pjv63n5-2022a5","DOIUrl":"https://doi.org/10.30632/pjv63n5-2022a5","url":null,"abstract":"In order to explore the corrosion effect of CO2 and H2S in oilwell cement, the samples were exposed to a CO2/H2S environment. The permeability, microstructure, chemical composition, and tensile strength of the cement samples were measured by a pulse pore-permeability tester, scanning electron microscope (SEM), X-ray diffraction (XRD), and rock tensile compression tester, respectively. The corrosion behavior and mechanism of the cement samples were analyzed. The experimental results show that the corrosion degree increases with the exposure time, and the permeability increases from 0.0003 md on the seventh day to 0.0646 md on the thirtieth day. It can be concluded from the microscopic morphology that the internal structure of the corroded cement sample is compact, without an obvious loose structure, but there are some particles with different particle sizes. The composition phases of the products after corrosion are mainly calcium carbonate and silica, and the content of calcium carbonate in the corrosion area increases obviously. The tensile strength of the tested cement sample is only 9.8 MPa. The reaction of gaseous CO2 and H2S with calcium-bearing phases in a cement sample is known to cause a lowering of alkalinity, leading to the corrosion of the cement sample. Due to the existence of carbonation, carbon dioxide will gradually diffuse into the interior of the cement sample and react with hydrogen ions, calcium ions, and bicarbonate ions in the pore fluid of the cement sample to form varieties of calcium carbonate, resulting in the shrinkage of the cement sample, surface cracks, and ultimately affecting the compactness and sealing effect of the cement sample.","PeriodicalId":170688,"journal":{"name":"Petrophysics – The SPWLA Journal of Formation Evaluation and Reservoir Description","volume":"3 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"127340058","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}
Guiyu Hua, Xueqi Yang, Changhai Xu, Shenglan Lei, G. Zhong
Basement granitic rocks represent potential hydrocarbon reservoirs; however, our understanding of their reservoir properties remains limited. In the Pearl River Mouth Basin (PRMB) of the northern South China Sea continental margin, granitic rocks account for ~57% of the basement in terms of lithology, which provides an excellent opportunity to investigate the characteristics and distribution of basement granitic reservoirs. Here we report results from a log facies analysis of the basement granitic rocks in the PRMB based on conventional well-logging data of 13 exploration wells. In the analysis, methods of change-point analysis for segmentation and fuzzy c-means clustering for log facies classification were integrated. As a result, five log facies (LF), named LF 1 to 5, were identified. These log facies were interpreted by integrating the analysis of the lithologic significance of different well logs, the analogy with similar cases confirmed in the literature, and the calibration from the limited cutting and sidewall coring data. Reservoir properties of the basement granitic rocks in the PRMB are highly varied, depending on the degree of the development of secondary porosities and fractures. It is suggested that the granitic rocks with developed secondary porosities and fractures, as represented by the low density (DEN), high acoustic transit time (AT), and relatively high neutron porosity (NP) log facies (LF 3), have the best reservoir potential, followed by the high gamma ray (GR), relatively high AT, and low NP (LF 2), and the low NP, moderate DEN, and AT (LF 4) log facies with variable amounts of fractures, respectively. Granitic rocks represented by the remaining LF 1 and 5 are overall tight and of poor reservoir properties. Favorable reservoir log facies, consisting of LF 2 through 4, are heterogeneously distributed. These findings will be beneficial to deepening our understanding of the reservoir properties of basement granitic rocks.
{"title":"Log Facies Analysis and Reservoir Properties of Basement Granitic Rocks in the Pearl River Mouth Basin, South China Sea","authors":"Guiyu Hua, Xueqi Yang, Changhai Xu, Shenglan Lei, G. Zhong","doi":"10.30632/pjv63n4-2022a5","DOIUrl":"https://doi.org/10.30632/pjv63n4-2022a5","url":null,"abstract":"Basement granitic rocks represent potential hydrocarbon reservoirs; however, our understanding of their reservoir properties remains limited. In the Pearl River Mouth Basin (PRMB) of the northern South China Sea continental margin, granitic rocks account for ~57% of the basement in terms of lithology, which provides an excellent opportunity to investigate the characteristics and distribution of basement granitic reservoirs. Here we report results from a log facies analysis of the basement granitic rocks in the PRMB based on conventional well-logging data of 13 exploration wells. In the analysis, methods of change-point analysis for segmentation and fuzzy c-means clustering for log facies classification were integrated. As a result, five log facies (LF), named LF 1 to 5, were identified. These log facies were interpreted by integrating the analysis of the lithologic significance of different well logs, the analogy with similar cases confirmed in the literature, and the calibration from the limited cutting and sidewall coring data. Reservoir properties of the basement granitic rocks in the PRMB are highly varied, depending on the degree of the development of secondary porosities and fractures. It is suggested that the granitic rocks with developed secondary porosities and fractures, as represented by the low density (DEN), high acoustic transit time (AT), and relatively high neutron porosity (NP) log facies (LF 3), have the best reservoir potential, followed by the high gamma ray (GR), relatively high AT, and low NP (LF 2), and the low NP, moderate DEN, and AT (LF 4) log facies with variable amounts of fractures, respectively. Granitic rocks represented by the remaining LF 1 and 5 are overall tight and of poor reservoir properties. Favorable reservoir log facies, consisting of LF 2 through 4, are heterogeneously distributed. These findings will be beneficial to deepening our understanding of the reservoir properties of basement granitic rocks.","PeriodicalId":170688,"journal":{"name":"Petrophysics – The SPWLA Journal of Formation Evaluation and Reservoir Description","volume":"84 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"132867156","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}
New hybrid EOS-PVT models have been developed for estimating in-situ fluid properties for retrograde gas condensate fluids. The hybrid models are based on tuned equation of state (EOS) properties for a globally distributed set of quality-controlled (QC) pressure-volume-temperature (PVT) analyses of gas condensates in which the condensate-to-gas ratio (CGR) ranges from ~5 to 350 bbl/MMscf and for which in-situ fluid densities range from ~0.2 to 0.6 g/cm3. The hybrid EOS-PVT models are based on the observation that in-situ fluid densities derived from measured fluid pressure gradients (FPG) are highly correlated with EOS-derived in-situ fluid densities obtained from tuned EOS models and QC PVT data. Using fluid density values calculated using in-situ FPG data, it is now possible to estimate a variety of gas condensate fluid properties such as viscosity, mole fraction of methane (XCH4), density, acoustic velocity, and adiabatic fluid moduli, the latter being a critical input for Gassmann fluid substitution models. The utility of the new hybrid EOS-PVT models lies in their ability to facilitate rapid evaluation of stranded gas resources without having to take a fluid sample for laboratory PVT analysis. Properly executed FPG data also have great utility as a reliable QC for laboratory-measured PVT properties. We present hybrid EOS-PVT models for CGR, viscosity, in-situ fluid density, and acoustic velocity for a broad suite of gas condensates. A significant contribution of this work is the development of a new fluid acoustic properties model that enables estimation of the adiabatic fluid modulus (Kad) for retrograde gas condensates. Using predictive models reported here for fluid density [ρ] and velocity [Vp], the adiabatic fluid modulus is easily calculated. The model reported for fluid velocity was validated with direct measurements of fluid acoustic velocity on a live sample, at in-situ conditions, from the HP/HT Shearwater Field in the Central North Sea (CNS).
{"title":"Predicting In-Situ Physical Properties for Gas Condensates From Fluid Pressure Gradients","authors":"L. T. Bryndzia, M. Kittridge","doi":"10.30632/pjv63n4-2022a1","DOIUrl":"https://doi.org/10.30632/pjv63n4-2022a1","url":null,"abstract":"New hybrid EOS-PVT models have been developed for estimating in-situ fluid properties for retrograde gas condensate fluids. The hybrid models are based on tuned equation of state (EOS) properties for a globally distributed set of quality-controlled (QC) pressure-volume-temperature (PVT) analyses of gas condensates in which the condensate-to-gas ratio (CGR) ranges from ~5 to 350 bbl/MMscf and for which in-situ fluid densities range from ~0.2 to 0.6 g/cm3. The hybrid EOS-PVT models are based on the observation that in-situ fluid densities derived from measured fluid pressure gradients (FPG) are highly correlated with EOS-derived in-situ fluid densities obtained from tuned EOS models and QC PVT data. Using fluid density values calculated using in-situ FPG data, it is now possible to estimate a variety of gas condensate fluid properties such as viscosity, mole fraction of methane (XCH4), density, acoustic velocity, and adiabatic fluid moduli, the latter being a critical input for Gassmann fluid substitution models. The utility of the new hybrid EOS-PVT models lies in their ability to facilitate rapid evaluation of stranded gas resources without having to take a fluid sample for laboratory PVT analysis. Properly executed FPG data also have great utility as a reliable QC for laboratory-measured PVT properties. We present hybrid EOS-PVT models for CGR, viscosity, in-situ fluid density, and acoustic velocity for a broad suite of gas condensates. A significant contribution of this work is the development of a new fluid acoustic properties model that enables estimation of the adiabatic fluid modulus (Kad) for retrograde gas condensates. Using predictive models reported here for fluid density [ρ] and velocity [Vp], the adiabatic fluid modulus is easily calculated. The model reported for fluid velocity was validated with direct measurements of fluid acoustic velocity on a live sample, at in-situ conditions, from the HP/HT Shearwater Field in the Central North Sea (CNS).","PeriodicalId":170688,"journal":{"name":"Petrophysics – The SPWLA Journal of Formation Evaluation and Reservoir Description","volume":"17 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"126637609","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}
This paper presents a fast and transparent Bayesian-based computational method that can be used for the interpretation of well logs. Rather than single values for formation properties, the results are probability distributions. The method is fast because the responses of logging tools, for a large set of formation realizations, are calculated only once and then stored with the realizations in a database. Thereafter, only this database is used for the interpretation of real well logs. The method is transparent because it entirely relies on selecting formation realizations with calculated log responses that are, within a given error margin, equal to the real logging tool responses. Therefore, only internally consistent interpretations can be found. The size of the database is realizable and the log evaluation computation time sufficiently short. The method has been tested with good results on more than 100 wells. Some of the well results are presented and discussed. The presented evaluations use databases of about 300 MB containing about 25 million realizations. Database construction and whole well evaluation each require less than a few seconds.
{"title":"A Fast and Transparent Bayesian Log Interpretation Method","authors":"M. Spalburg","doi":"10.30632/pjv63n4-2022a4","DOIUrl":"https://doi.org/10.30632/pjv63n4-2022a4","url":null,"abstract":"This paper presents a fast and transparent Bayesian-based computational method that can be used for the interpretation of well logs. Rather than single values for formation properties, the results are probability distributions. The method is fast because the responses of logging tools, for a large set of formation realizations, are calculated only once and then stored with the realizations in a database. Thereafter, only this database is used for the interpretation of real well logs. The method is transparent because it entirely relies on selecting formation realizations with calculated log responses that are, within a given error margin, equal to the real logging tool responses. Therefore, only internally consistent interpretations can be found. The size of the database is realizable and the log evaluation computation time sufficiently short. The method has been tested with good results on more than 100 wells. Some of the well results are presented and discussed. The presented evaluations use databases of about 300 MB containing about 25 million realizations. Database construction and whole well evaluation each require less than a few seconds.","PeriodicalId":170688,"journal":{"name":"Petrophysics – The SPWLA Journal of Formation Evaluation and Reservoir Description","volume":"15 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"127174153","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}
Electric and magnetic field responses originating from a primary electric current source have been analytically derived, explored, and employed to explore and detect electrical anomalies due to the presence of a bed boundary in a two-layer model, using the controlled source electromagnetic method. However, previous works on the subject demand in-depth knowledge of mathematics, which could become an obstacle for the practitioner looking to immerse into the realm of induction logging and who needs a straightforward approach to develop their algorithms. Consequently, we introduce the analytical expressions for electric and magnetic field responses to an electric current dipole source arbitrarily oriented in one-dimension (1D) transversely isotropic media. In addition, we apply these equations to examine both electric and magnetic field responses to a distant resistive anomaly from electric transverse electric dipole transmitters. Our analysis shows that magnetic field responses are significantly more sensitive to the anomaly ahead of the tool for a vertical or a horizontal borehole. While the coplanar electric field measurements with conventional electric resistivity tools are known to be sensitive to the resistivity anomaly around the tool, the axial magnetic field measurement using the transverse electric dipole transmitter and the transverse magnetic field measurement using an axial electric dipole transmitter are significantly more sensitive to the anomaly around the tool than any electric field measurements. This deep-looking capability is achieved with a relatively short source-receiver spacing of 10 m. Based on the increased deep-looking capability, we encourage the use of magnetic components from our generalized geosteering tool based on electric dipole sources because it can potentially flag anomalies at a distance 60% further in comparison to the sensitivity of electric measurements.
{"title":"Bed-Detection Sensitivity Employing 1D Response to an Electric Dipole Source in Multilayer Anisotropic Formations","authors":"Joshua Bautista-Anguiano, T. Hagiwara","doi":"10.30632/pjv63n4-2022a3","DOIUrl":"https://doi.org/10.30632/pjv63n4-2022a3","url":null,"abstract":"Electric and magnetic field responses originating from a primary electric current source have been analytically derived, explored, and employed to explore and detect electrical anomalies due to the presence of a bed boundary in a two-layer model, using the controlled source electromagnetic method. However, previous works on the subject demand in-depth knowledge of mathematics, which could become an obstacle for the practitioner looking to immerse into the realm of induction logging and who needs a straightforward approach to develop their algorithms. Consequently, we introduce the analytical expressions for electric and magnetic field responses to an electric current dipole source arbitrarily oriented in one-dimension (1D) transversely isotropic media. In addition, we apply these equations to examine both electric and magnetic field responses to a distant resistive anomaly from electric transverse electric dipole transmitters. Our analysis shows that magnetic field responses are significantly more sensitive to the anomaly ahead of the tool for a vertical or a horizontal borehole. While the coplanar electric field measurements with conventional electric resistivity tools are known to be sensitive to the resistivity anomaly around the tool, the axial magnetic field measurement using the transverse electric dipole transmitter and the transverse magnetic field measurement using an axial electric dipole transmitter are significantly more sensitive to the anomaly around the tool than any electric field measurements. This deep-looking capability is achieved with a relatively short source-receiver spacing of 10 m. Based on the increased deep-looking capability, we encourage the use of magnetic components from our generalized geosteering tool based on electric dipole sources because it can potentially flag anomalies at a distance 60% further in comparison to the sensitivity of electric measurements.","PeriodicalId":170688,"journal":{"name":"Petrophysics – The SPWLA Journal of Formation Evaluation and Reservoir Description","volume":"15 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"114353516","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 : 2022-06-01DOI: 10.30632/pjv63n3-2022a11
M. Dick, D. Veselinović, D. Green
The last 10 years have witnessed numerous new developments and advancements in nuclear magnetic resonance (NMR) rock core analysis both in conventional and unconventional reservoirs. On the hardware side, NMR instruments are now capable of handling hundreds of thousands of radio frequency (RF) pulses, and the pulses can be more closely spaced than ever. This allows measuring samples with very fast relaxation times, which was not possible before. Higher field NMR spectrometers operating at frequencies of ~12 MHz and ~20 MHz (in addition to the standard low-field ~2 MHz instruments) were introduced, which drastically improved the signal-to-noise ratio (SNR) and even allowed two-dimensional (2D) and three-dimensional (3D) NMR imaging to be performed on the samples to complement traditional relaxation measurements. Another consequence of using higher field instruments is that even samples with a very low amount of NMR signal can now provide useful data in a reasonable amount of time. Additional hardware improvements include the development of NMR-compatible high-temperature and high-pressure vessels and faster and more robust electronics and computers, which allow faster data acquisition, processing, and a more user-friendly environment for new NMR pulse sequence design and implementation. Following the hardware improvements, new applications were developed for rock core analysis, including modified Carl-Purcell-Meiboom-Gill (CPMG) pulse sequences for minimizing sample heating. NMR-based wettability, relative permeability, capillary pressure, cuttings, and long core measurements have also been successful. In unconventionals, NMR-based gas isotherm measurements and fluid-typing measurements are now common practices. This review paper sets out to summarize the recent NMR developments in the industry as well as provide references where more details can be found on each topic.
{"title":"Review of Recent Developments in NMR Core Analysis","authors":"M. Dick, D. Veselinović, D. Green","doi":"10.30632/pjv63n3-2022a11","DOIUrl":"https://doi.org/10.30632/pjv63n3-2022a11","url":null,"abstract":"The last 10 years have witnessed numerous new developments and advancements in nuclear magnetic resonance (NMR) rock core analysis both in conventional and unconventional reservoirs. On the hardware side, NMR instruments are now capable of handling hundreds of thousands of radio frequency (RF) pulses, and the pulses can be more closely spaced than ever. This allows measuring samples with very fast relaxation times, which was not possible before. Higher field NMR spectrometers operating at frequencies of ~12 MHz and ~20 MHz (in addition to the standard low-field ~2 MHz instruments) were introduced, which drastically improved the signal-to-noise ratio (SNR) and even allowed two-dimensional (2D) and three-dimensional (3D) NMR imaging to be performed on the samples to complement traditional relaxation measurements. Another consequence of using higher field instruments is that even samples with a very low amount of NMR signal can now provide useful data in a reasonable amount of time. Additional hardware improvements include the development of NMR-compatible high-temperature and high-pressure vessels and faster and more robust electronics and computers, which allow faster data acquisition, processing, and a more user-friendly environment for new NMR pulse sequence design and implementation. Following the hardware improvements, new applications were developed for rock core analysis, including modified Carl-Purcell-Meiboom-Gill (CPMG) pulse sequences for minimizing sample heating. NMR-based wettability, relative permeability, capillary pressure, cuttings, and long core measurements have also been successful. In unconventionals, NMR-based gas isotherm measurements and fluid-typing measurements are now common practices. This review paper sets out to summarize the recent NMR developments in the industry as well as provide references where more details can be found on each topic.","PeriodicalId":170688,"journal":{"name":"Petrophysics – The SPWLA Journal of Formation Evaluation and Reservoir Description","volume":"49 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130090935","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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