Evaluating reservoir properties at the pore scale is vital to better estimate hydrocarbon reserves and plan field development. The lacustrine mixed siliciclastic-carbonate deposits of the Upper Paleogene Xiaganchaigou Formation in the west Yingxiongling area form one of the most important hydrocarbon reservoirs in the southwestern Qaidam Basin (China). In this study, we analyzed well samples with X-ray diffraction (XRD), nuclear magnetic resonance (NMR), and mercury injection capillary pressure (MICP) data in integration with scanning electron microscopy (SEM) images to decipher the mineral composition and pore structure characteristics of the Xiaganchaigou Formation. We also calculate the fractal dimensions using MICP, NMR T2 spectrum, and SEM images based on fractal theory models. The results indicate that the mixed siliciclastic-carbonate samples of the upper section of the Xiaganchaigou Formation are mainly formed by dolomite and clay minerals with low siliceous and calcite content. Porosity is relatively low (2.01−9.83%) and positively correlated with dolomite content, thus indicating that the dolomite intercrystalline pores formed by infiltration and reflux dolomitization control the reservoir characteristics. The size of dolomite intercrystalline pores varies between several and hundreds of nanometers. The porosity has a poor correlation with permeability, which indicates that the pores are mostly primary, which lack the transformation of late dissolution. Three types of mixed siliciclastic-carbonate reservoirs are identified according to pore size distribution (<20 nm, 20−300 nm and multiple distribution), calculated using the NMR T2 spectrum. Fractal curves calculated by combining the MICP and NMR data are characterized by multisegments. The number of segments depends on the degree of heterogeneity of pore structure: two segment for high heterogeneity and three segment for low heterogeneity, also indicating a multifractal feature in mixed rock reservoirs. There is a negative correlation trend between porosity and fractal dimensions, and larger pores often have larger fractal dimensions. These results show that MICP-based fractal values are higher than those of NMR-based, which result from unconnected pores that the MICP is unable to reach. Fractal dimensions obtained from SEM have a small and narrow distribution range and are negatively correlated with the number of pores with smaller sizes. In essence, this study shows that the fractal dimension can be a concise index to evaluate the heterogeneity of lacustrine mixed siliciclastic-carbonate reservoirs, which can serve as an important reference for hydrocarbon development plans.
{"title":"Pore Structure and Fractal Characteristics of Mixed Siliciclastic-Carbonate Rocks from the Yingxi Area, Southwest Qaidam Basin, China","authors":"Xinlei Zhang, Zhiqian Gao, V. Maselli, T. Fan","doi":"10.2118/215839-pa","DOIUrl":"https://doi.org/10.2118/215839-pa","url":null,"abstract":"\u0000 Evaluating reservoir properties at the pore scale is vital to better estimate hydrocarbon reserves and plan field development. The lacustrine mixed siliciclastic-carbonate deposits of the Upper Paleogene Xiaganchaigou Formation in the west Yingxiongling area form one of the most important hydrocarbon reservoirs in the southwestern Qaidam Basin (China). In this study, we analyzed well samples with X-ray diffraction (XRD), nuclear magnetic resonance (NMR), and mercury injection capillary pressure (MICP) data in integration with scanning electron microscopy (SEM) images to decipher the mineral composition and pore structure characteristics of the Xiaganchaigou Formation. We also calculate the fractal dimensions using MICP, NMR T2 spectrum, and SEM images based on fractal theory models. The results indicate that the mixed siliciclastic-carbonate samples of the upper section of the Xiaganchaigou Formation are mainly formed by dolomite and clay minerals with low siliceous and calcite content. Porosity is relatively low (2.01−9.83%) and positively correlated with dolomite content, thus indicating that the dolomite intercrystalline pores formed by infiltration and reflux dolomitization control the reservoir characteristics. The size of dolomite intercrystalline pores varies between several and hundreds of nanometers. The porosity has a poor correlation with permeability, which indicates that the pores are mostly primary, which lack the transformation of late dissolution. Three types of mixed siliciclastic-carbonate reservoirs are identified according to pore size distribution (<20 nm, 20−300 nm and multiple distribution), calculated using the NMR T2 spectrum. Fractal curves calculated by combining the MICP and NMR data are characterized by multisegments. The number of segments depends on the degree of heterogeneity of pore structure: two segment for high heterogeneity and three segment for low heterogeneity, also indicating a multifractal feature in mixed rock reservoirs. There is a negative correlation trend between porosity and fractal dimensions, and larger pores often have larger fractal dimensions. These results show that MICP-based fractal values are higher than those of NMR-based, which result from unconnected pores that the MICP is unable to reach. Fractal dimensions obtained from SEM have a small and narrow distribution range and are negatively correlated with the number of pores with smaller sizes. In essence, this study shows that the fractal dimension can be a concise index to evaluate the heterogeneity of lacustrine mixed siliciclastic-carbonate reservoirs, which can serve as an important reference for hydrocarbon development plans.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"78 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2023-07-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74856306","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}
M. Durrani, Syed Atif Rahman, M. Talib, G. Subhani, Bakhtawer Sarosh
Quantitative characterization of deep, tight, and heterogeneous reservoirs plays an important role in identifying hydrocarbon pathways for effective and optimal reservoir field development. In this case study, we used an azimuthal prestack seismic anisotropic inversion approach to estimate attributes of horizontal transverse isotropy (HTI) caused by a set of vertical fractures, oriented cracks, and stress. Anisotropic inversion facilitated the conversion of interface properties to the corresponding layer-based properties, which led to the quantitative interpretation of reservoir properties related to azimuthal variation in seismic amplitudes. To estimate the anisotropy magnitude and the direction of the isotropy axis in HTI media, elastic properties (P-impedance and Vp/Vs) obtained from prestack seismic inversion (using six azimuth × four angle stack) served as inputs. The isotropic low-frequency model (LFM) is used as the foundation of the inversion for all azimuths, and the anisotropy effects are later added by updating the model along the azimuths. The direction of the isotropy plane resulting from the anisotropic inversion is determined by using the maximum horizontal stress as a prior constraint, which eliminates any inherent uncertainty. The workflow used effectively characterized the orientation and density of fractures from the recently discovered oilfield reservoirs of the Paleocene (Lockhart) formation located in Pakistan’s north Potwar Basin. It also helped improve the prediction accuracy for fractures in the study area. According to the observations (fractures) from the exploratory drilled well (D1) in the tight carbonate (Lockhart) reservoir, a significant amount of anisotropy magnitude is observed. This provides the basis for hydrocarbon exploration, field development, and reliable drilling decisions.
{"title":"Azimuthal Prestack Seismic Anisotropic Inversion on a Deep and Tight Carbonate Reservoir From the North Potwar Basin of Pakistan","authors":"M. Durrani, Syed Atif Rahman, M. Talib, G. Subhani, Bakhtawer Sarosh","doi":"10.2118/215851-pa","DOIUrl":"https://doi.org/10.2118/215851-pa","url":null,"abstract":"\u0000 Quantitative characterization of deep, tight, and heterogeneous reservoirs plays an important role in identifying hydrocarbon pathways for effective and optimal reservoir field development. In this case study, we used an azimuthal prestack seismic anisotropic inversion approach to estimate attributes of horizontal transverse isotropy (HTI) caused by a set of vertical fractures, oriented cracks, and stress. Anisotropic inversion facilitated the conversion of interface properties to the corresponding layer-based properties, which led to the quantitative interpretation of reservoir properties related to azimuthal variation in seismic amplitudes. To estimate the anisotropy magnitude and the direction of the isotropy axis in HTI media, elastic properties (P-impedance and Vp/Vs) obtained from prestack seismic inversion (using six azimuth × four angle stack) served as inputs. The isotropic low-frequency model (LFM) is used as the foundation of the inversion for all azimuths, and the anisotropy effects are later added by updating the model along the azimuths. The direction of the isotropy plane resulting from the anisotropic inversion is determined by using the maximum horizontal stress as a prior constraint, which eliminates any inherent uncertainty. The workflow used effectively characterized the orientation and density of fractures from the recently discovered oilfield reservoirs of the Paleocene (Lockhart) formation located in Pakistan’s north Potwar Basin. It also helped improve the prediction accuracy for fractures in the study area. According to the observations (fractures) from the exploratory drilled well (D1) in the tight carbonate (Lockhart) reservoir, a significant amount of anisotropy magnitude is observed. This provides the basis for hydrocarbon exploration, field development, and reliable drilling decisions.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"5 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2023-07-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78375471","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}
One frequently used enhanced heavy oil recovery technique is gas injection, during which heavy oil viscosity is reduced due to diffusion of gaseous components and heavy oil swelling in porous media. Effective diffusivities of gas components are generally assumed to be constants, while no attempts have been made to determine both the concentration-dependent effective diffusivity in porous media saturated with heavy oil and the preferential contribution of each component in a binary/ternary gas mixture. In this study, a pragmatic and robust technique has been proposed to determine the concentration-dependent effective diffusivity of each gas component by reproducing the experimental measurements during pressure decay tests for CO2-C3H8-heavy oil systems in porous media. Experimentally, CO2 and C3H8 are utilized to diffuse into sandpacks fully saturated with heavy oil. Under a constant temperature within a thermostatic chamber, the pressures of the aforementioned gas(es)-heavy oil systems are consistently tracked and saved while gas samples are taken at the start and end of the diffusion tests for gas chromatography analyses. Theoretically, a mass transfer model is formulated to determine effective gas diffusivity in heavy oil as a concentration-dependent function by incorporating Fick’s second law and the modified Peng-Robinson equation of state (PR EOS). The concentration-dependent effective diffusivity for each gas component is ascertained when the measured pressure profiles and gas compositions are matched well to their correspondingly calculated values with minimum deviations. Compared to either a constant assumption or a linear concentration-dependent relation with respect to diffusivity, an exponential concentration-dependent relation leads to more accurately reproducing the measured pressure profiles. Compared with pure CO2, its effective diffusivity in a binary (i.e., CO2 and C3H8) gas system is found to be larger, indicating that C3H8 accelerates the CO2 mass transfer into heavy oil under the same circumstances. Furthermore, this study confirms that a larger tortuosity of a porous medium leads to a longer diffusion path with less contact between gas and liquid phases and that a lower concentration of a gaseous component yields a lower effective diffusivity.
{"title":"Determination of Concentration-Dependent Effective Diffusivity of Each Gas Component of a Binary Mixture in Porous Media Saturated with Heavy Oil under Reservoir Conditions","authors":"Wenyu Zhao, Hyun Woong Jang, Daoyong Yang","doi":"10.2118/215832-pa","DOIUrl":"https://doi.org/10.2118/215832-pa","url":null,"abstract":"\u0000 One frequently used enhanced heavy oil recovery technique is gas injection, during which heavy oil viscosity is reduced due to diffusion of gaseous components and heavy oil swelling in porous media. Effective diffusivities of gas components are generally assumed to be constants, while no attempts have been made to determine both the concentration-dependent effective diffusivity in porous media saturated with heavy oil and the preferential contribution of each component in a binary/ternary gas mixture. In this study, a pragmatic and robust technique has been proposed to determine the concentration-dependent effective diffusivity of each gas component by reproducing the experimental measurements during pressure decay tests for CO2-C3H8-heavy oil systems in porous media. Experimentally, CO2 and C3H8 are utilized to diffuse into sandpacks fully saturated with heavy oil. Under a constant temperature within a thermostatic chamber, the pressures of the aforementioned gas(es)-heavy oil systems are consistently tracked and saved while gas samples are taken at the start and end of the diffusion tests for gas chromatography analyses. Theoretically, a mass transfer model is formulated to determine effective gas diffusivity in heavy oil as a concentration-dependent function by incorporating Fick’s second law and the modified Peng-Robinson equation of state (PR EOS). The concentration-dependent effective diffusivity for each gas component is ascertained when the measured pressure profiles and gas compositions are matched well to their correspondingly calculated values with minimum deviations. Compared to either a constant assumption or a linear concentration-dependent relation with respect to diffusivity, an exponential concentration-dependent relation leads to more accurately reproducing the measured pressure profiles. Compared with pure CO2, its effective diffusivity in a binary (i.e., CO2 and C3H8) gas system is found to be larger, indicating that C3H8 accelerates the CO2 mass transfer into heavy oil under the same circumstances. Furthermore, this study confirms that a larger tortuosity of a porous medium leads to a longer diffusion path with less contact between gas and liquid phases and that a lower concentration of a gaseous component yields a lower effective diffusivity.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"21 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2023-07-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89482789","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}
A. Somoza, B. Rodríguez-Cabo, I. Barrio, M. F. García-Mayoral, A. Soto
Summary About one-half of the proven conventional oil reserves are in carbonate reservoirs. However, conducting surfactant flooding in these reservoirs presents several challenges, including formation heterogeneities, surfactant retention, high temperature and salinity, and oil-wet/mixed-wet conditions. Linear alkylbenzene sulfonates (LASs) are low-cost anionic surfactants that tend to precipitate in high-salinity environments and show high adsorption values in carbonate material. In this paper, the possibility of using petrochemical LASs of different alkyl chain lengths and isomer content to extract oil from carbonate reservoirs was tested using blends with the ionic liquid cocosalkylpentaethoximethylammonium methylsulfate (C1EG). Phase behavior, stability in the presence of divalent ions, and interfacial tension (IFT) measurements were the criteria used to design several optimal formulations containing 36–45% LASs. The structure-performance relationship was further assessed via static adsorption and wettability tests. LASs enriched in isomers with the benzenesulfonic group in external positions of the alkyl chain resulted in lower IFT but significantly higher adsorption, so those surfactants were discarded for the application. Additional oil recoveries achieved with tested formulations ranged from 36.7% to 43.5% of the residual oil in place. The longer the alkyl chain length, the higher the oil recovery. The main mechanism associated with improved oil recovery is IFT reduction. The use of a cost-effective ionic liquid derived from natural raw materials, the stability of the blends, the low adsorption of the chemical, and a significant oil recovery ensure the overall feasibility of the proposal.
{"title":"Experimental Evaluation of Blends Containing Lineal Alkylbenzene Sulfonates for Surfactant Flooding in Carbonate Reservoirs","authors":"A. Somoza, B. Rodríguez-Cabo, I. Barrio, M. F. García-Mayoral, A. Soto","doi":"10.2118/215828-pa","DOIUrl":"https://doi.org/10.2118/215828-pa","url":null,"abstract":"Summary About one-half of the proven conventional oil reserves are in carbonate reservoirs. However, conducting surfactant flooding in these reservoirs presents several challenges, including formation heterogeneities, surfactant retention, high temperature and salinity, and oil-wet/mixed-wet conditions. Linear alkylbenzene sulfonates (LASs) are low-cost anionic surfactants that tend to precipitate in high-salinity environments and show high adsorption values in carbonate material. In this paper, the possibility of using petrochemical LASs of different alkyl chain lengths and isomer content to extract oil from carbonate reservoirs was tested using blends with the ionic liquid cocosalkylpentaethoximethylammonium methylsulfate (C1EG). Phase behavior, stability in the presence of divalent ions, and interfacial tension (IFT) measurements were the criteria used to design several optimal formulations containing 36–45% LASs. The structure-performance relationship was further assessed via static adsorption and wettability tests. LASs enriched in isomers with the benzenesulfonic group in external positions of the alkyl chain resulted in lower IFT but significantly higher adsorption, so those surfactants were discarded for the application. Additional oil recoveries achieved with tested formulations ranged from 36.7% to 43.5% of the residual oil in place. The longer the alkyl chain length, the higher the oil recovery. The main mechanism associated with improved oil recovery is IFT reduction. The use of a cost-effective ionic liquid derived from natural raw materials, the stability of the blends, the low adsorption of the chemical, and a significant oil recovery ensure the overall feasibility of the proposal.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"372 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-06-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"135101222","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}
F. Ciabarri, C. Tarchiani, Gioele Alberelli, F. Chinellato, M. Mele, Junio Alfonso Marini, M. Nickel, H. Borgos, G. Dahl
This work describes a statistical rock-physics-driven inversion of seismic acoustic impedance (AI) and ultradeep azimuthal resistivity (UDAR) log data, acquired while drilling, to estimate porosity, water saturation, and facies classes around the wellbore. Despite their limited resolution, seismic data integrated with electromagnetic resistivity log measurements improve the description of rock properties by considering the coupled effects of pore space and fluid saturation in the joint acoustic and electrical domains. The proposed inversion does not explicitly use a forward model, rather the correlation between the petrophysical properties and the resulting geophysical responses is inferred probabilistically from a training data set. The training set is generated by combining available borehole information with a statistical rock-physics modeling approach. In the inversion process, given colocated measurements of seismic AI and logging-while-drilling (LWD) electromagnetic resistivity data, the pointwise probability distribution of rock properties is derived directly from the training data set by applying the kernel density estimation (KDE) algorithm. A nonparametric statistical approach is used to approximate nonsymmetric volumetric distributions of petrophysical properties and to consider the characteristic nonlinear relationship linking water saturation with resistivity. Given an a priori facies classification template for the samples in the training set, it is possible to model the multimodal, facies-dependent behavior of the petrophysical properties, together with their distinctive correlation patterns. A facies-dependent parameterization allows the effect of lithology on acoustic and resistivity responses to be implicitly considered, even though the target properties of inversion are only porosity and saturation. To provide a realistic uncertainty quantification of the estimated rock properties, a plain Bayesian framework is described to account for rock-physics modeling error and to propagate seismic and resistivity data uncertainties to the inversion results. In this respect, the uncertainty related to the scale difference among the well-log data and seismic is addressed by adopting a scale reconciliation strategy. The main feature of the described inversion lies in its fast implementation based on a look-up table that allows rock properties, with their associated uncertainty, to be estimated in real time following the acquisition and inversion of UDAR data. This gives a robust, straightforward, and fast approach that can be effortlessly integrated into existing workflows to support geosteering operations. The inversion is validated on a clastic oil-bearing reservoir, where geosteering was used to guide the placement of a horizontal appraisal well in a complex structural setting. The results show that the proposed methodology provides realistic estimates of the rock-property distributions around the wellbore to depths of investigation
{"title":"Real-Time Rock-Properties Estimation for Geosteering: Statistical Rock-Physics-Driven Inversion of Seismic Acoustic Impedance and LWD Ultradeep Azimuthal Resistivity","authors":"F. Ciabarri, C. Tarchiani, Gioele Alberelli, F. Chinellato, M. Mele, Junio Alfonso Marini, M. Nickel, H. Borgos, G. Dahl","doi":"10.2118/214407-pa","DOIUrl":"https://doi.org/10.2118/214407-pa","url":null,"abstract":"\u0000 This work describes a statistical rock-physics-driven inversion of seismic acoustic impedance (AI) and ultradeep azimuthal resistivity (UDAR) log data, acquired while drilling, to estimate porosity, water saturation, and facies classes around the wellbore. Despite their limited resolution, seismic data integrated with electromagnetic resistivity log measurements improve the description of rock properties by considering the coupled effects of pore space and fluid saturation in the joint acoustic and electrical domains.\u0000 The proposed inversion does not explicitly use a forward model, rather the correlation between the petrophysical properties and the resulting geophysical responses is inferred probabilistically from a training data set. The training set is generated by combining available borehole information with a statistical rock-physics modeling approach. In the inversion process, given colocated measurements of seismic AI and logging-while-drilling (LWD) electromagnetic resistivity data, the pointwise probability distribution of rock properties is derived directly from the training data set by applying the kernel density estimation (KDE) algorithm. A nonparametric statistical approach is used to approximate nonsymmetric volumetric distributions of petrophysical properties and to consider the characteristic nonlinear relationship linking water saturation with resistivity. Given an a priori facies classification template for the samples in the training set, it is possible to model the multimodal, facies-dependent behavior of the petrophysical properties, together with their distinctive correlation patterns. A facies-dependent parameterization allows the effect of lithology on acoustic and resistivity responses to be implicitly considered, even though the target properties of inversion are only porosity and saturation.\u0000 To provide a realistic uncertainty quantification of the estimated rock properties, a plain Bayesian framework is described to account for rock-physics modeling error and to propagate seismic and resistivity data uncertainties to the inversion results. In this respect, the uncertainty related to the scale difference among the well-log data and seismic is addressed by adopting a scale reconciliation strategy. The main feature of the described inversion lies in its fast implementation based on a look-up table that allows rock properties, with their associated uncertainty, to be estimated in real time following the acquisition and inversion of UDAR data. This gives a robust, straightforward, and fast approach that can be effortlessly integrated into existing workflows to support geosteering operations.\u0000 The inversion is validated on a clastic oil-bearing reservoir, where geosteering was used to guide the placement of a horizontal appraisal well in a complex structural setting. The results show that the proposed methodology provides realistic estimates of the rock-property distributions around the wellbore to depths of investigation","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"4 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2023-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73673236","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}
Zahra Ashena, Hojjat Kabirzadeh, J. W. Kim, Xin Wang, Mohammed Ali
A novel 2.5D intelligent gravity inversion technique has been developed to estimate basement topography. A deep neural network (DNN) is used to address the fundamental nonuniqueness and nonlinearity flaws of geophysical inversions. The training data set is simulated by adopting a new technique. Using parallel computing algorithms, thousands of forward models of the subsurface with their corresponding gravity anomalies are simulated in a few minutes. Each forward model randomly selects the values of its parameter from a set of predefined ranges based on the geological and structural characteristics of the target area. A DNN model is trained based on the simulated data set to conduct the nonlinear inverse mapping of gravity anomalies to basement topography in offshore Abu Dhabi, United Arab Emirates. The performance of the trained model is assessed by making predictions on noise-free and noise-contaminated gravity data. Eventually, the DNN inversion model is used to estimate the basement topography using pseudogravity anomalies. The results show the depth of the basement is between 7.4 km and 9.3 km over the Ghasha hydrocarbon reservoir. This paper is the 2.5D and improved version of the research (SPE-211800-MS) recently presented and published in the Abu Dhabi International Petroleum Exhibition & Conference (31 October–3 November 2022) proceedings.
{"title":"A Novel 2.5D Deep Network Inversion of Gravity Anomalies to Estimate Basement Topography","authors":"Zahra Ashena, Hojjat Kabirzadeh, J. W. Kim, Xin Wang, Mohammed Ali","doi":"10.2118/211800-pa","DOIUrl":"https://doi.org/10.2118/211800-pa","url":null,"abstract":"\u0000 A novel 2.5D intelligent gravity inversion technique has been developed to estimate basement topography. A deep neural network (DNN) is used to address the fundamental nonuniqueness and nonlinearity flaws of geophysical inversions. The training data set is simulated by adopting a new technique. Using parallel computing algorithms, thousands of forward models of the subsurface with their corresponding gravity anomalies are simulated in a few minutes. Each forward model randomly selects the values of its parameter from a set of predefined ranges based on the geological and structural characteristics of the target area. A DNN model is trained based on the simulated data set to conduct the nonlinear inverse mapping of gravity anomalies to basement topography in offshore Abu Dhabi, United Arab Emirates. The performance of the trained model is assessed by making predictions on noise-free and noise-contaminated gravity data. Eventually, the DNN inversion model is used to estimate the basement topography using pseudogravity anomalies. The results show the depth of the basement is between 7.4 km and 9.3 km over the Ghasha hydrocarbon reservoir. This paper is the 2.5D and improved version of the research (SPE-211800-MS) recently presented and published in the Abu Dhabi International Petroleum Exhibition & Conference (31 October–3 November 2022) proceedings.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"3 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2023-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81711103","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}
Marcos Vitor Barbosa Machado, M. Delshad, K. Sepehrnoori
Numerical simulation of the CO2 storage process in porous media, such as in hydrocarbon (gas or oil) depleted reservoirs and in saline aquifers, has been the most indicated tool due to its ability to represent CO2 capacity and the different trapping mechanisms that retain CO2 in the subsurface. Given the complexity of the physicochemical phenomena involved, the modeling needs to incorporate multiphase flow, complex representation of fluids, rock, and rock-fluid interaction properties. These include CO2 reactions with aqueous species and with reservoir rock minerals, in addition to the structural and stratigraphic aspects of the reservoir heterogeneity. These phenomena need to be represented on suitable temporal and spatial scales for accurate predictions of their impacts. Currently, many studies are focused on simulating submodels or sectors of the reservoir, where using finer grids is still practical. This level of grid refinement can be prohibitive, in terms of simulation times, for modeling the entire reservoir. To address this challenge, we propose a new and practical workflow to simulate CO2 storage projects in large field-scale models. When the proposed workflow is applied in both synthetic and real field cases, simulation time is reduced by up to 96% compared to that of the fine-grid model, preserving the same results in representing the aforementioned mechanisms. The workflow is based on classical and standard approaches to handle the high simulation time, but in this study, they are structured and sequenced in three steps. The first one considers the most relevant mechanisms for CO2 storage, ranked from a high-resolution sector model. With the mechanisms prioritized in the previous step, a single-phase upscaling of petrophysical properties can be applied in the field-scale model, followed by adopting a grid with dynamic sizing. The proposed methodology is applied to saline aquifer models in this study, but it can be extended for storage in depleted hydrocarbon reservoirs.
{"title":"A Practical and Innovative Workflow to Support the Numerical Simulation of CO2 Storage in Large Field-Scale Models","authors":"Marcos Vitor Barbosa Machado, M. Delshad, K. Sepehrnoori","doi":"10.2118/215838-pa","DOIUrl":"https://doi.org/10.2118/215838-pa","url":null,"abstract":"\u0000 Numerical simulation of the CO2 storage process in porous media, such as in hydrocarbon (gas or oil) depleted reservoirs and in saline aquifers, has been the most indicated tool due to its ability to represent CO2 capacity and the different trapping mechanisms that retain CO2 in the subsurface. Given the complexity of the physicochemical phenomena involved, the modeling needs to incorporate multiphase flow, complex representation of fluids, rock, and rock-fluid interaction properties. These include CO2 reactions with aqueous species and with reservoir rock minerals, in addition to the structural and stratigraphic aspects of the reservoir heterogeneity. These phenomena need to be represented on suitable temporal and spatial scales for accurate predictions of their impacts. Currently, many studies are focused on simulating submodels or sectors of the reservoir, where using finer grids is still practical. This level of grid refinement can be prohibitive, in terms of simulation times, for modeling the entire reservoir. To address this challenge, we propose a new and practical workflow to simulate CO2 storage projects in large field-scale models. When the proposed workflow is applied in both synthetic and real field cases, simulation time is reduced by up to 96% compared to that of the fine-grid model, preserving the same results in representing the aforementioned mechanisms. The workflow is based on classical and standard approaches to handle the high simulation time, but in this study, they are structured and sequenced in three steps. The first one considers the most relevant mechanisms for CO2 storage, ranked from a high-resolution sector model. With the mechanisms prioritized in the previous step, a single-phase upscaling of petrophysical properties can be applied in the field-scale model, followed by adopting a grid with dynamic sizing. The proposed methodology is applied to saline aquifer models in this study, but it can be extended for storage in depleted hydrocarbon reservoirs.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"12 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2023-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78746613","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}
Manuel Gomes Correia, Gonçalo Oliveira, Denis José Schiozer
Summary The significant quantities of oil contained in fractured karst reservoirs in Brazilian presalt fields add new challenges to the development of upscaling procedures to reduce time on numerical simulations. This work aims to represent multiscale heterogeneities in reservoir simulators based on special connections between matrix, karst, and fracture mediums, both modeled in different grid domains within a single porosity flow model. The objective of this representation is to strike a good balance between accuracy and simulation time. Therefore, this work extends the approach of special connections developed by Correia et al. (2019) to integrate both karst and fracture mediums modeled in different grid domains and block scales. The transmissibility calculation between the three domains is a combination of the conventional formulation based on two-point flux approximation schemes and the matrix-fracture fluid transfer formulation. The flow inside each domain is governed by Darcy’s equation and implicitly solved by the simulator. For proper validation and numerical verification, we applied the methodology to a simple case (two-phase and three-phase flow) and a real case (two-phase flow). For the simple case, the reference model is a refined grid model with (1) an arrangement of large conduits (karsts), which are poorly connected; (2) a well-connected and orthogonal system of fractures; and (3) a background medium (matrix). The real case is a section of a Brazilian presalt field, characterized as a naturally fractured carbonate reservoir. The reference is the geological model. The simulation model consists of a structural model with different gridblock sizes according to the scale of the heterogeneities—small-scale karst geometries, medium-scale matrix properties, and larger-scale fracture features—interconnected by special connections. The results for both cases show a significant performance improvement regarding a dynamic matching response with the reference model, within a suitable simulation time and maintaining the dynamic resolution according to the representative elementary volume of heterogeneities, without using an unstructured grid. In comparison to the reference model, for the simple case and the real case, the simulation time was reduced by 42% and 87%, respectively. The proposed method contributes to a multiscale flow simulation solution to manage heterogeneous geological scenarios using structured grids while preserving the high resolution of small-scale heterogeneities and providing a good relationship between accuracy and simulation time.
{"title":"Special Connections for Representing Multiscale Heterogeneities in Reservoir Simulation","authors":"Manuel Gomes Correia, Gonçalo Oliveira, Denis José Schiozer","doi":"10.2118/200572-pa","DOIUrl":"https://doi.org/10.2118/200572-pa","url":null,"abstract":"Summary The significant quantities of oil contained in fractured karst reservoirs in Brazilian presalt fields add new challenges to the development of upscaling procedures to reduce time on numerical simulations. This work aims to represent multiscale heterogeneities in reservoir simulators based on special connections between matrix, karst, and fracture mediums, both modeled in different grid domains within a single porosity flow model. The objective of this representation is to strike a good balance between accuracy and simulation time. Therefore, this work extends the approach of special connections developed by Correia et al. (2019) to integrate both karst and fracture mediums modeled in different grid domains and block scales. The transmissibility calculation between the three domains is a combination of the conventional formulation based on two-point flux approximation schemes and the matrix-fracture fluid transfer formulation. The flow inside each domain is governed by Darcy’s equation and implicitly solved by the simulator. For proper validation and numerical verification, we applied the methodology to a simple case (two-phase and three-phase flow) and a real case (two-phase flow). For the simple case, the reference model is a refined grid model with (1) an arrangement of large conduits (karsts), which are poorly connected; (2) a well-connected and orthogonal system of fractures; and (3) a background medium (matrix). The real case is a section of a Brazilian presalt field, characterized as a naturally fractured carbonate reservoir. The reference is the geological model. The simulation model consists of a structural model with different gridblock sizes according to the scale of the heterogeneities—small-scale karst geometries, medium-scale matrix properties, and larger-scale fracture features—interconnected by special connections. The results for both cases show a significant performance improvement regarding a dynamic matching response with the reference model, within a suitable simulation time and maintaining the dynamic resolution according to the representative elementary volume of heterogeneities, without using an unstructured grid. In comparison to the reference model, for the simple case and the real case, the simulation time was reduced by 42% and 87%, respectively. The proposed method contributes to a multiscale flow simulation solution to manage heterogeneous geological scenarios using structured grids while preserving the high resolution of small-scale heterogeneities and providing a good relationship between accuracy and simulation time.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"10 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-05-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"135718162","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}
Summary This paper incorporates the findings of our previous publication (Morales and Lee 2022) and identifies, isolates, and quantifies elements in the annually disclosed proved reserves revisions that should not be considered technical or economic revisions. This has resulted in significantly different technical and economic revisions compared to those simplistically and directly derived using a common interpretation of the Financial Accounting Standards Board (FASB) Topic 932-235-50-5 (a) definition. We have assessed the reliability and comparability of the updated technical revisions when used to judge the reasonable certainty of the underlying proved reserves. We have carried out the analysis separating the proved reserves into developed and undeveloped. To derive a realistic data set to generate the updated technical and economic revisions, we reviewed more than 1,000 annual reports (10K and 20F Forms) and more than 600 comment letters from 141 companies filing annual reports to the Securities and Exchange Commission (SEC) during the period 2010–2020, extracting the information related to annual reserves changes and explicitly focusing on the disclosed revisions of previous estimates (RPE). We present evidence showing that the approach followed is robust and more reliable than the simple approach where technical revisions are estimated by simply subtracting the disclosed revisions due to price effects from the disclosed revisions in annual reports. The root causes for the significant differences between the simplistic approach and the one presented in this paper are mainly due to (1) including annual reserves changes due to nontechnical or economic factors as technical revisions, (2) using different interpretations of SEC and FASB regulations, and (3) not providing critical disaggregation information needed to estimate technical, economic, or other types of revisions correctly. Without proper consideration of these issues, the derived technical and economic revisions from disclosed data can be significantly distorted, affecting any conclusions derived. The annual average changes in technical revisions during a representative period, if correctly estimated, can provide an indication of both overstated and understated certainty of proved reserves estimates, which can impact a company’s relative valuation, asset impairment, internal depreciation, profit/loss, standardized measure, unit development costs, and other indicators based on proved reserves, making the reliability of the technical revisions and their actual upward or downward movements of paramount importance. We also highlight the significant different root causes driving the major differences between developed and undeveloped reserves in their annual technical revisions. The results indicate that for some companies that provide most of the information required for proper analysis, the certainty level of their disclosed developed and undeveloped proved reserves points toward an appar
本文结合了我们之前的出版物(Morales and Lee 2022)的研究结果，并识别、分离和量化了年度披露的探明储量修订中不应被视为技术或经济修订的元素。与使用财务会计准则委员会(FASB)主题932-235-50-5 (a)定义的共同解释简单而直接地推导出来的那些相比，这导致了显着不同的技术和经济修订。我们已经评估了更新的技术修订版在判断潜在探明储量的合理确定性时的可靠性和可比性。我们将探明储量分为已开发储量和未开发储量进行了分析。为了获得一个真实的数据集来生成最新的技术和经济修订，我们审查了2010-2020年期间向美国证券交易委员会(SEC)提交年度报告的141家公司的1000多份年度报告(10K和20F表格)和600多封评论信，提取了与年度储备变化相关的信息，并明确关注先前估计(RPE)的披露修订。我们提供的证据表明，所采用的方法比简单的方法更稳健，更可靠，其中通过简单地从年度报告中披露的修订中减去由于价格影响而披露的修订来估计技术修订。简化方法与本文中提出的方法之间存在显著差异的根本原因主要是(1)将非技术或经济因素导致的年度准备金变化作为技术修订，(2)使用对SEC和FASB法规的不同解释，以及(3)没有提供正确估计技术、经济或其他类型修订所需的关键分解信息。如果不适当考虑这些问题，从公开数据中得出的技术和经济修订可能会严重扭曲，从而影响得出的任何结论。如果正确估计，代表性期间技术修订的年平均变化可以提供高估和低估已探明储量估计确定性的指示，这可能影响公司的相对估值、资产减值、内部折旧、损益、标准化计量、单位开发成本和基于已探明储量的其他指标。使技术修订的可靠性及其实际向上或向下的运动至关重要。我们还在其年度技术修订中强调了导致已开发和未开发储量之间重大差异的显著不同的根本原因。结果表明，对于一些提供了适当分析所需的大部分信息的公司，其披露的已开发和未开发探明储量的确定性水平表明，其历史披露的探明储量明显高估。我们的分析表明，已披露的探明储量修订的质量可疑，缺乏可靠性和可比性，并突出了现有指导和当前实践的有限价值。我们提供的证据呼吁FASB和SEC在目前限制所披露的探明储量修订的价值、可靠性和可比性的关键领域提供补充指导。
{"title":"Proved Reserves Revisions: How Reliable Are They?","authors":"Enrique Morales, John Lee","doi":"10.2118/210476-pa","DOIUrl":"https://doi.org/10.2118/210476-pa","url":null,"abstract":"Summary This paper incorporates the findings of our previous publication (Morales and Lee 2022) and identifies, isolates, and quantifies elements in the annually disclosed proved reserves revisions that should not be considered technical or economic revisions. This has resulted in significantly different technical and economic revisions compared to those simplistically and directly derived using a common interpretation of the Financial Accounting Standards Board (FASB) Topic 932-235-50-5 (a) definition. We have assessed the reliability and comparability of the updated technical revisions when used to judge the reasonable certainty of the underlying proved reserves. We have carried out the analysis separating the proved reserves into developed and undeveloped. To derive a realistic data set to generate the updated technical and economic revisions, we reviewed more than 1,000 annual reports (10K and 20F Forms) and more than 600 comment letters from 141 companies filing annual reports to the Securities and Exchange Commission (SEC) during the period 2010–2020, extracting the information related to annual reserves changes and explicitly focusing on the disclosed revisions of previous estimates (RPE). We present evidence showing that the approach followed is robust and more reliable than the simple approach where technical revisions are estimated by simply subtracting the disclosed revisions due to price effects from the disclosed revisions in annual reports. The root causes for the significant differences between the simplistic approach and the one presented in this paper are mainly due to (1) including annual reserves changes due to nontechnical or economic factors as technical revisions, (2) using different interpretations of SEC and FASB regulations, and (3) not providing critical disaggregation information needed to estimate technical, economic, or other types of revisions correctly. Without proper consideration of these issues, the derived technical and economic revisions from disclosed data can be significantly distorted, affecting any conclusions derived. The annual average changes in technical revisions during a representative period, if correctly estimated, can provide an indication of both overstated and understated certainty of proved reserves estimates, which can impact a company’s relative valuation, asset impairment, internal depreciation, profit/loss, standardized measure, unit development costs, and other indicators based on proved reserves, making the reliability of the technical revisions and their actual upward or downward movements of paramount importance. We also highlight the significant different root causes driving the major differences between developed and undeveloped reserves in their annual technical revisions. The results indicate that for some companies that provide most of the information required for proper analysis, the certainty level of their disclosed developed and undeveloped proved reserves points toward an appar","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"19 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-05-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"134989164","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}
Due to strong nonlinearities in the governing diffusivity equation for flow in porous media, numerically assisted rate-transient analysis (RTA) techniques have been suggested for the analysis of multiphase production data from multifractured horizontal wells (MFHWs). However, these methods are based on some limiting assumptions that cannot be generalized for three-phase flow or when relative permeability is unknown. In this study, a new RTA-assisted history-matching technique is proposed to simultaneously match production data and diagnostic plots during the calibration process. In the proposed method, the objective function is modified to include the derivative of the integral of rate-normalized pressure for the primary phases. As such, in the history-matching process using compositional numerical simulation, the flow regimes are also matched, which can increase the reliability of the calibrated numerical model. This approach is applied to a challenging data set of production data from an MFHW completed in a Canadian shale reservoir hosting a near-critical gas condensate fluid. The results demonstrate that when the modified objective function is used, the history-matching scheme will reject models that cannot reproduce the flow regimes even if the production data are visually matched. Another benefit of this modified history-matching workflow is that, unlike other numerically assisted RTA techniques, it is not limited to any specific conceptual model or reservoir geometry. Further, interactions between parameters are accounted for during the calibration process. Including the derivative terms in the objective function can ensure a better history-matched model with improved forecast quality. However, comparing the convergence rates of the history-matching with the standard and modified objective functions indicates that adding the derivative terms comes with an additional computational cost requiring more iterations and a slower convergence rate. In this study, a modified objective function is introduced for the first time to enhance the numerical history-matching process to ensure the resulting calibrated model can also reproduce the observed transient flow regimes. This approach is easy to implement and is not limited to a specific model geometry or any input-output relationship.
{"title":"RTA-Assisted Numerical History-Matching Workflow","authors":"H. Hamdi, C. Clarkson, A. Ghanizadeh","doi":"10.2118/210224-pa","DOIUrl":"https://doi.org/10.2118/210224-pa","url":null,"abstract":"\u0000 Due to strong nonlinearities in the governing diffusivity equation for flow in porous media, numerically assisted rate-transient analysis (RTA) techniques have been suggested for the analysis of multiphase production data from multifractured horizontal wells (MFHWs). However, these methods are based on some limiting assumptions that cannot be generalized for three-phase flow or when relative permeability is unknown. In this study, a new RTA-assisted history-matching technique is proposed to simultaneously match production data and diagnostic plots during the calibration process.\u0000 In the proposed method, the objective function is modified to include the derivative of the integral of rate-normalized pressure for the primary phases. As such, in the history-matching process using compositional numerical simulation, the flow regimes are also matched, which can increase the reliability of the calibrated numerical model. This approach is applied to a challenging data set of production data from an MFHW completed in a Canadian shale reservoir hosting a near-critical gas condensate fluid.\u0000 The results demonstrate that when the modified objective function is used, the history-matching scheme will reject models that cannot reproduce the flow regimes even if the production data are visually matched. Another benefit of this modified history-matching workflow is that, unlike other numerically assisted RTA techniques, it is not limited to any specific conceptual model or reservoir geometry. Further, interactions between parameters are accounted for during the calibration process. Including the derivative terms in the objective function can ensure a better history-matched model with improved forecast quality. However, comparing the convergence rates of the history-matching with the standard and modified objective functions indicates that adding the derivative terms comes with an additional computational cost requiring more iterations and a slower convergence rate.\u0000 In this study, a modified objective function is introduced for the first time to enhance the numerical history-matching process to ensure the resulting calibrated model can also reproduce the observed transient flow regimes. This approach is easy to implement and is not limited to a specific model geometry or any input-output relationship.","PeriodicalId":22066,"journal":{"name":"SPE Reservoir Evaluation & Engineering","volume":"1 1","pages":""},"PeriodicalIF":2.1,"publicationDate":"2023-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91229410","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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