Lian Chen, Xiaoqiang Peng, Yong Li, Xindong Wang, Song Wang, Hua Luo, Qingchun Gao, Xiyan Song
To improve the penetration performance of polycrystalline diamond compact (PDC) bits in hard-to-penetrate plastic formations, the study of three-ribbed ridge nonplanar PDC cutter technology was carried out. The rock-breaking characteristics of nonplanar cutters are analyzed by comparison with conventional planar cutters and axe-shaped cutters through simulation and indoor experiments. The simulation results show that the planar cutter mainly breaks the rock by shearing and extruding, the axe-shaped cutter mainly breaks the rock by shearing, and the nonplanar PDC cutter mainly relies on its convex ridge structure to penetrate and split the rock. Nonplanar cutter has better penetration performance and cutting stability than planar cutters and axe-shaped cutters. The field test shows that the rate of penetration (ROP) and footage of the developed PDC bit with three-ribbed ridge nonplanar PDC cutters are increased by 133.66% and 176.11% compared with the conventional PDC bit in the hard-to-penetrate plastic formations. The use of nonplanar PDC cutters improves the working stability, rock-breaking efficiency, and service life of the bit. The special three-ribbed ridge structure of the nonplanar cutter has changed the interaction mode between the cutter and the rock. Its successful application in the plastic formation provides a reference for faster drilling of PDC bits in hard-to-penetrate plastic formations.
{"title":"Rock-Breaking Characteristics of Three-Ribbed Ridge Nonplanar Polycrystalline Diamond Compact Cutter and Its Application in Plastic Formations","authors":"Lian Chen, Xiaoqiang Peng, Yong Li, Xindong Wang, Song Wang, Hua Luo, Qingchun Gao, Xiyan Song","doi":"10.2118/221492-pa","DOIUrl":"https://doi.org/10.2118/221492-pa","url":null,"abstract":"\u0000 To improve the penetration performance of polycrystalline diamond compact (PDC) bits in hard-to-penetrate plastic formations, the study of three-ribbed ridge nonplanar PDC cutter technology was carried out. The rock-breaking characteristics of nonplanar cutters are analyzed by comparison with conventional planar cutters and axe-shaped cutters through simulation and indoor experiments. The simulation results show that the planar cutter mainly breaks the rock by shearing and extruding, the axe-shaped cutter mainly breaks the rock by shearing, and the nonplanar PDC cutter mainly relies on its convex ridge structure to penetrate and split the rock. Nonplanar cutter has better penetration performance and cutting stability than planar cutters and axe-shaped cutters. The field test shows that the rate of penetration (ROP) and footage of the developed PDC bit with three-ribbed ridge nonplanar PDC cutters are increased by 133.66% and 176.11% compared with the conventional PDC bit in the hard-to-penetrate plastic formations. The use of nonplanar PDC cutters improves the working stability, rock-breaking efficiency, and service life of the bit. The special three-ribbed ridge structure of the nonplanar cutter has changed the interaction mode between the cutter and the rock. Its successful application in the plastic formation provides a reference for faster drilling of PDC bits in hard-to-penetrate plastic formations.","PeriodicalId":510854,"journal":{"name":"SPE Journal","volume":"54 43","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-07-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141689267","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}
C. A. V. Várady Filho, J. Tenorio, E. T. Lima Junior, J. Santos, R. Dias, F. Cutrim
The casing system plays a crucial role in the integrity of oil and gas wells throughout their life cycle, providing tightness, stability, and support to external loads. In this paper, we apply reliability-based models to the design of tophole casing sections, taking into account uncertainties associated with soil behavior and casing tubulars manufacturing. Typical load scenarios are addressed to estimate the probability of the occurrence of different soil-casing system failure modes. Reliability-based techniques stand out as powerful solutions for structural analysis and design. This work assesses soil characterization data from piezocone tests (CPTu) to statistically describe some mechanical parameters used for conductor and surface casing design. Random variables associated with the material and geometrical properties of tubulars are also considered, based on tubular manufacturing data presented in API TR 5C3 (2018). The probabilistic models are developed by using the first-order reliability method (FORM), an expedited and accurate optimization-based procedure, and applied to various load scenarios to estimate failure probability in the context of tophole casing design. Finite element (FE) modeling is used for the integrity analysis of the soil-casing system. Analyses have been carried out considering the variability associated with undrained soil strength evaluated from CPTu data, as this soil strength is expected to be the most relevant random variable due to its spatial heterogeneity. Other random variables taken into account are the outer diameter and wall thickness of casing tubulars, resulting from the variability in the manufacturing process. Results indicate the feasibility and relevance of the proposed FE-FORM analysis in estimating the probability of the occurrence of relevant failure modes defined following the oil company’s internal regulations, regarding: conductor casing load capacity, surface casing triaxial stress in the noncemented region, and wellhead displacement. For the specific case studies presented, failure probabilities ranged from the order of magnitude of 10-9 to inadmissible values approaching 50%. Concerning how random variables affect the probabilistic response, it is observed that the outer diameter is not significant due to its low dispersion. The novelty consists of considering both in-situ soil information and casing manufacturing data in a reliability-based framework that enables a more robust structural integrity analysis, supporting the decision-making process in tophole design. This solution was implemented in the operator’s internal software and uses real data. Quantifying the soil and casing uncertainties by using a robust statistical-based methodology brings new information, enhancing knowledge about the variability of design parameters and its influence on the structural response.
{"title":"On the Probabilistic Assessment of Tophole Casing Design","authors":"C. A. V. Várady Filho, J. Tenorio, E. T. Lima Junior, J. Santos, R. Dias, F. Cutrim","doi":"10.2118/221493-pa","DOIUrl":"https://doi.org/10.2118/221493-pa","url":null,"abstract":"\u0000 The casing system plays a crucial role in the integrity of oil and gas wells throughout their life cycle, providing tightness, stability, and support to external loads. In this paper, we apply reliability-based models to the design of tophole casing sections, taking into account uncertainties associated with soil behavior and casing tubulars manufacturing. Typical load scenarios are addressed to estimate the probability of the occurrence of different soil-casing system failure modes.\u0000 Reliability-based techniques stand out as powerful solutions for structural analysis and design. This work assesses soil characterization data from piezocone tests (CPTu) to statistically describe some mechanical parameters used for conductor and surface casing design. Random variables associated with the material and geometrical properties of tubulars are also considered, based on tubular manufacturing data presented in API TR 5C3 (2018). The probabilistic models are developed by using the first-order reliability method (FORM), an expedited and accurate optimization-based procedure, and applied to various load scenarios to estimate failure probability in the context of tophole casing design. Finite element (FE) modeling is used for the integrity analysis of the soil-casing system.\u0000 Analyses have been carried out considering the variability associated with undrained soil strength evaluated from CPTu data, as this soil strength is expected to be the most relevant random variable due to its spatial heterogeneity. Other random variables taken into account are the outer diameter and wall thickness of casing tubulars, resulting from the variability in the manufacturing process. Results indicate the feasibility and relevance of the proposed FE-FORM analysis in estimating the probability of the occurrence of relevant failure modes defined following the oil company’s internal regulations, regarding: conductor casing load capacity, surface casing triaxial stress in the noncemented region, and wellhead displacement. For the specific case studies presented, failure probabilities ranged from the order of magnitude of 10-9 to inadmissible values approaching 50%. Concerning how random variables affect the probabilistic response, it is observed that the outer diameter is not significant due to its low dispersion.\u0000 The novelty consists of considering both in-situ soil information and casing manufacturing data in a reliability-based framework that enables a more robust structural integrity analysis, supporting the decision-making process in tophole design. This solution was implemented in the operator’s internal software and uses real data. Quantifying the soil and casing uncertainties by using a robust statistical-based methodology brings new information, enhancing knowledge about the variability of design parameters and its influence on the structural response.","PeriodicalId":510854,"journal":{"name":"SPE Journal","volume":"24 66","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-07-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141699580","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}
As an efficient method for hard rock fracturing, rotary-percussive drilling has been widely used in various scenarios, especially deep drilling. Drilling parameter monitoring and control are necessary to ensure stable and efficient underground drilling processes. However, this may be more difficult in deep, harsh conditions. In this paper, our goal is to establish models based on deep learning for drilling parameter monitoring and optimization. Combining impregnated diamond bits and granite rock samples, we conducted rotary-percussive rock drilling experiments using a rock drilling test rig. Real-time acoustic signals during rotary-percussive drilling were recorded, segmented, and transformed as spectra, which made up a drilling acoustic signal data set. Drilling parameters, including rotational speed (revolutions per minute, RPM), pump flow rate, pump pressure, weight on bit (WOB), torque, and rate of penetration (ROP), were logged in the meantime. Given the acoustic signal as input, we built 1D convolutional neural network (1D-CNN) models for drilling parameter prediction. The prediction results revealed the high efficiency and accuracy of 1D-CNN regression models based on deep learning in drilling condition monitoring. Batch normalization played an essential role in the regression model training processes. Given that these parameters have different units and dimensions, we compared models with different output modes to evaluate the multiparameter prediction performance of the 1D-CNN. Taking RPM, flow rate, pressure, and WOB as independent variables and torque and ROP as dependent variables, we developed a conditional variational autoencoder to realize optimization on drilling parameters based on expected drilling performance.
{"title":"Deep Learning–Assisted Parameter Monitoring and Optimization in Rotary-Percussive Drilling","authors":"Wucheng Sun, Yakun Tao, Zhiming Wang, Songcheng Tan, Longchen Duan, Xiaohong Fang","doi":"10.2118/221497-pa","DOIUrl":"https://doi.org/10.2118/221497-pa","url":null,"abstract":"\u0000 As an efficient method for hard rock fracturing, rotary-percussive drilling has been widely used in various scenarios, especially deep drilling. Drilling parameter monitoring and control are necessary to ensure stable and efficient underground drilling processes. However, this may be more difficult in deep, harsh conditions.\u0000 In this paper, our goal is to establish models based on deep learning for drilling parameter monitoring and optimization. Combining impregnated diamond bits and granite rock samples, we conducted rotary-percussive rock drilling experiments using a rock drilling test rig. Real-time acoustic signals during rotary-percussive drilling were recorded, segmented, and transformed as spectra, which made up a drilling acoustic signal data set. Drilling parameters, including rotational speed (revolutions per minute, RPM), pump flow rate, pump pressure, weight on bit (WOB), torque, and rate of penetration (ROP), were logged in the meantime. Given the acoustic signal as input, we built 1D convolutional neural network (1D-CNN) models for drilling parameter prediction. The prediction results revealed the high efficiency and accuracy of 1D-CNN regression models based on deep learning in drilling condition monitoring. Batch normalization played an essential role in the regression model training processes. Given that these parameters have different units and dimensions, we compared models with different output modes to evaluate the multiparameter prediction performance of the 1D-CNN. Taking RPM, flow rate, pressure, and WOB as independent variables and torque and ROP as dependent variables, we developed a conditional variational autoencoder to realize optimization on drilling parameters based on expected drilling performance.","PeriodicalId":510854,"journal":{"name":"SPE Journal","volume":"32 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-07-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141716655","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}
Mixing of incompatible injection and formation brines leads to the deposition of inorganic sulfate scales such as barite, celestite, and anhydrite in and around production wells. This process is well documented in seawater-flooded clastic reservoirs. One technique to avoid the resulting formation damage is to remove sulfate from seawater before injection using nanofiltration; however, this process is costly. We identify in this paper that it may not always be necessary in higher-temperature carbonate reservoirs. In this paper, we describe the use of reactive transport reservoir simulation to investigate the impact of carbon dioxide (CO2) partitioning and changes in pH, ionic concentrations, and temperature on carbonate reactivity and the sulfate scaling risk in waterflooded carbonate reservoirs. Dissolution and precipitation of calcite, dolomite, gypsum, anhydrite, barite, and celestite are all modeled and found to be coupled through (various) common ion effects. The produced brine compositions are used to calculate the saturation ratios (SRs) and mass of precipitate that may form in the production system. Sensitivity to mineral reaction kinetics, particularly for the dolomite reactions, is accounted for. Results identify that there is a strong relationship between calcite dissolution and dolomite (or other calcium/magnesium carbonate mineral) precipitation reactions, which drive each other and are affected by the availability of CO2 in the residual oil phase. This evolves over time, and as the thermal front propagates, impacts the concentration of calcium and magnesium in the brines traversing the reservoir. Temperature changes around the injection wellbore impact CO2 and mineral solubilities. The concentration of calcium in the displaced brine mix is thus determined more by contact with rock and temperature than by mixing between injection and formation brines. Depending on location relative to the thermal front, this may lead to gypsum or anhydrite precipitation, thereby stripping sulfate out of the injection brine. Thus, the sulfate scaling risk at the production wells is significantly reduced by this sulfate depletion process: The sulfate is stripped out of the seawater as it warms up in the reservoir before it mixes extensively with the formation water and significantly before any mixture of the two brines reaches the production zone. Thus, any loss of permeability is restricted to deep within the reservoir, where the pore volume (PV) that can accommodate mineral precipitation is very large. In this work, we identify that for carbonate reservoirs above 90–100°C, stripping of sulfate due to coupled mineral reactions may reduce or eliminate the need for use of a sulfate reduction plant (SRP). The process is modeled for the first time, accounting for the impact of CO2 partitioning and thermal front propagation. Knowledge of the kinetics of calcium/magnesium carbonate precipitation is shown to be critical in predicting the extent of sulfat
{"title":"Kinetics of In-Situ Calcium Magnesium Carbonate Precipitation and the Need for Desulfation in Seawater-Flooded Carbonate Reservoirs","authors":"Ali M. Al-Behadili, E. Mackay","doi":"10.2118/221486-pa","DOIUrl":"https://doi.org/10.2118/221486-pa","url":null,"abstract":"\u0000 Mixing of incompatible injection and formation brines leads to the deposition of inorganic sulfate scales such as barite, celestite, and anhydrite in and around production wells. This process is well documented in seawater-flooded clastic reservoirs. One technique to avoid the resulting formation damage is to remove sulfate from seawater before injection using nanofiltration; however, this process is costly. We identify in this paper that it may not always be necessary in higher-temperature carbonate reservoirs.\u0000 In this paper, we describe the use of reactive transport reservoir simulation to investigate the impact of carbon dioxide (CO2) partitioning and changes in pH, ionic concentrations, and temperature on carbonate reactivity and the sulfate scaling risk in waterflooded carbonate reservoirs. Dissolution and precipitation of calcite, dolomite, gypsum, anhydrite, barite, and celestite are all modeled and found to be coupled through (various) common ion effects. The produced brine compositions are used to calculate the saturation ratios (SRs) and mass of precipitate that may form in the production system. Sensitivity to mineral reaction kinetics, particularly for the dolomite reactions, is accounted for.\u0000 Results identify that there is a strong relationship between calcite dissolution and dolomite (or other calcium/magnesium carbonate mineral) precipitation reactions, which drive each other and are affected by the availability of CO2 in the residual oil phase. This evolves over time, and as the thermal front propagates, impacts the concentration of calcium and magnesium in the brines traversing the reservoir. Temperature changes around the injection wellbore impact CO2 and mineral solubilities. The concentration of calcium in the displaced brine mix is thus determined more by contact with rock and temperature than by mixing between injection and formation brines. Depending on location relative to the thermal front, this may lead to gypsum or anhydrite precipitation, thereby stripping sulfate out of the injection brine. Thus, the sulfate scaling risk at the production wells is significantly reduced by this sulfate depletion process: The sulfate is stripped out of the seawater as it warms up in the reservoir before it mixes extensively with the formation water and significantly before any mixture of the two brines reaches the production zone. Thus, any loss of permeability is restricted to deep within the reservoir, where the pore volume (PV) that can accommodate mineral precipitation is very large.\u0000 In this work, we identify that for carbonate reservoirs above 90–100°C, stripping of sulfate due to coupled mineral reactions may reduce or eliminate the need for use of a sulfate reduction plant (SRP). The process is modeled for the first time, accounting for the impact of CO2 partitioning and thermal front propagation. Knowledge of the kinetics of calcium/magnesium carbonate precipitation is shown to be critical in predicting the extent of sulfat","PeriodicalId":510854,"journal":{"name":"SPE Journal","volume":"12 4","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-07-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141701655","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}
Chengyuan Xu, Jun Xie, Yili Kang, Lei Liu, Kun Guo, Dan Xue, Zhenjiang You
To address the challenges of formation damage related to drill-in fluid loss into deep reservoir fractures during the drill-in process, we propose pre-propping and temporary plugging (PPTP) technology as an integrated solution in this paper. The PPTP approach combines high-strength bridging (HSB) materials with self-degrading filling (SDF) materials for efficient fracture plugging during lost circulation and effective fracture propping during oil and gas production from deep naturally fractured reservoirs. HSB material with good mechanical properties and SDF material with a controllable degradation cycle are developed and systematically evaluated. Fracture plugging tests and stress sensitivity experiments are conducted to evaluate the transformation effect of fracture plugging zones on fracture propping zones. Research results show that the developed HSB material exhibits a high compressive capacity and friction coefficient, which maintains a crushing rate below 3% under 60 MPa pressure and an average friction coefficient of 1.56. The degradation ratio of SDF material increases with temperature and pH value. The degradation cycle can reach up to 168 hours under the conditions of 120°C and pH = 13, which ensures continuous stable fracture plugging and lost-circulation control during the drill-in process. The PPTP technology, combining HSB and SDF components, efficiently plugs fractures with widths ranging from 1.0 mm to 3.0 mm, with a maximum plugging pressure of up to 10.16 MPa. HSB material props the fractures after SDF degrades, preventing fracture closure and converting the fracture plugging zone into a propping zone. The stress sensitivity damage of reservoir fractures can be effectively mitigated, preserving and enhancing fracture conductivity. Thus, the PPTP technology shows great potential for the integration solution of drill-in fluid loss and formation damage in deep naturally fractured reservoirs.
{"title":"Fracture Pre-propping and Temporary Plugging for Formation Damage Control in Deep Naturally Fractured Tight Reservoirs","authors":"Chengyuan Xu, Jun Xie, Yili Kang, Lei Liu, Kun Guo, Dan Xue, Zhenjiang You","doi":"10.2118/221489-pa","DOIUrl":"https://doi.org/10.2118/221489-pa","url":null,"abstract":"\u0000 To address the challenges of formation damage related to drill-in fluid loss into deep reservoir fractures during the drill-in process, we propose pre-propping and temporary plugging (PPTP) technology as an integrated solution in this paper. The PPTP approach combines high-strength bridging (HSB) materials with self-degrading filling (SDF) materials for efficient fracture plugging during lost circulation and effective fracture propping during oil and gas production from deep naturally fractured reservoirs. HSB material with good mechanical properties and SDF material with a controllable degradation cycle are developed and systematically evaluated. Fracture plugging tests and stress sensitivity experiments are conducted to evaluate the transformation effect of fracture plugging zones on fracture propping zones. Research results show that the developed HSB material exhibits a high compressive capacity and friction coefficient, which maintains a crushing rate below 3% under 60 MPa pressure and an average friction coefficient of 1.56. The degradation ratio of SDF material increases with temperature and pH value. The degradation cycle can reach up to 168 hours under the conditions of 120°C and pH = 13, which ensures continuous stable fracture plugging and lost-circulation control during the drill-in process. The PPTP technology, combining HSB and SDF components, efficiently plugs fractures with widths ranging from 1.0 mm to 3.0 mm, with a maximum plugging pressure of up to 10.16 MPa. HSB material props the fractures after SDF degrades, preventing fracture closure and converting the fracture plugging zone into a propping zone. The stress sensitivity damage of reservoir fractures can be effectively mitigated, preserving and enhancing fracture conductivity. Thus, the PPTP technology shows great potential for the integration solution of drill-in fluid loss and formation damage in deep naturally fractured reservoirs.","PeriodicalId":510854,"journal":{"name":"SPE Journal","volume":"40 5","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-07-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141709848","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}
Historically, the concept of “reservoir drive” aimed to simplify the mathematical modeling in reservoir engineering. Within this framework, the energy of the reservoir, particularly its aquifer, was idealized, leading to classifications such as “partial waterdrive,” “full waterdrive,” “gas cap drive,” and so forth. However, in reality, all existing energy sources interact simultaneously within reservoirs. Accordingly, this study aims to develop a new concept for a more realistic description of reservoir drive mechanisms and evaluation of reservoir energy performance. Numerous computer simulations have revealed a strong correlation between the ratio of relative changes in pore volume to relative changes in reservoir pressure and the reservoir’s energy nature and activity level. Moreover, the noted ratio did not depend on production technology, pressure/volume/temperature properties of hydrocarbon systems, rheological properties of reservoir rocks, or other factors. Based on this correlation, specific parameters termed as Jamalbayli Indexes (JI) have been identified to quantitatively describe reservoir energetic performance. JI consist of two parameters. One of them describes the relative change in pore volume per unit of relative change in reservoir pressure, and the second is the relative change in pore volume per unit of relative change in formation porosity. Here, “relative change” means a change in a parameter relative to its original value. These parameters are dimensionless and can have values around or equal to unity. A new conceptual framework for describing reservoir drive mechanisms based on JI has been formulated. According to this framework, reservoir drive mechanism is determined by comparing the computed JI values with unity rather than relying on subjective assessments of the trend of some functional dependencies. For the first time, it has become possible to express the reservoir drive performance quantitatively and determine the level of energy activity of the reservoirs with the help of JI. Additionally, a technique has been developed to evaluate the numerical values of JI for specific oil (including volatile oil) deposits based on the production data at any stage of production. The proposed methodology was tested using data from the eighth horizon of the Russkiy Khutor field in Russia. The test results not only confirmed the reliability of the obtained model but also demonstrated the adequacy of the proposed concept as a whole. Summarizing the results of other works by the authors, the adequacy of the proposed concept for both oil, gas, and gas condensate deposits has been confirmed. The research findings are expected to contribute to updating the traditional principles used for the mathematical problem statements in fluid flow in porous formations.
历史上，"储层驱动 "的概念旨在简化储层工程的数学模型。在这一框架内，储层（尤其是含水层）的能量被理想化，从而产生了 "部分水驱"、"全水驱"、"气帽驱 "等分类。然而，在现实中，所有现有的能源都同时在水库中相互作用。因此，本研究旨在提出一个新概念，以更真实地描述储层驱动机制和评估储层能量性能。大量的计算机模拟显示，孔隙体积相对变化与储层压力相对变化的比率与储层的能量性质和活动水平之间存在着很强的相关性。此外，该比率并不取决于生产技术、碳氢化合物系统的压力/体积/温度特性、储层岩石的流变特性或其他因素。根据这种相关性，确定了称为贾迈勒拜利指数（JI）的特定参数，用于定量描述储层的能量性能。JI 由两个参数组成。其一是储层压力相对变化单位内孔隙体积的相对变化，其二是地层孔隙度相对变化单位内孔隙体积的相对变化。这里的 "相对变化 "是指参数相对于其原始值的变化。这些参数都是无量纲参数，其值可以接近或等于统一值。在联合执行的基础上，制定了描述储层驱动机制的新概念框架。根据这一框架，水库驱动机制是通过比较计算出的联合强度值与统一值来确定的，而不是依赖于对某些功能依赖性趋势的主观评估。在 JI 的帮助下，首次实现了定量表达水库驱动性能和确定水库能量活动水平。此外，我们还开发了一种技术，可根据任何生产阶段的生产数据，评估特定石油（包括挥发性石油）储藏的 JI 数值。使用俄罗斯 Russkiy Khutor 油田第八层的数据对所提出的方法进行了测试。测试结果不仅证实了所获模型的可靠性，还证明了所提出概念的整体适当性。综合作者的其他研究成果，已证实所提出的概念适用于石油、天然气和凝析气矿床。预计研究成果将有助于更新多孔地层流体流动数学问题陈述的传统原则。
{"title":"The Early Determination Method of Reservoir Drive of Oil Deposits Based on Jamalbayli Indexes","authors":"M. Jamalbayov, Betul Yildirim, Atilla Abdullazada","doi":"10.2118/221480-pa","DOIUrl":"https://doi.org/10.2118/221480-pa","url":null,"abstract":"\u0000 Historically, the concept of “reservoir drive” aimed to simplify the mathematical modeling in reservoir engineering. Within this framework, the energy of the reservoir, particularly its aquifer, was idealized, leading to classifications such as “partial waterdrive,” “full waterdrive,” “gas cap drive,” and so forth. However, in reality, all existing energy sources interact simultaneously within reservoirs. Accordingly, this study aims to develop a new concept for a more realistic description of reservoir drive mechanisms and evaluation of reservoir energy performance. Numerous computer simulations have revealed a strong correlation between the ratio of relative changes in pore volume to relative changes in reservoir pressure and the reservoir’s energy nature and activity level. Moreover, the noted ratio did not depend on production technology, pressure/volume/temperature properties of hydrocarbon systems, rheological properties of reservoir rocks, or other factors. Based on this correlation, specific parameters termed as Jamalbayli Indexes (JI) have been identified to quantitatively describe reservoir energetic performance. JI consist of two parameters. One of them describes the relative change in pore volume per unit of relative change in reservoir pressure, and the second is the relative change in pore volume per unit of relative change in formation porosity. Here, “relative change” means a change in a parameter relative to its original value. These parameters are dimensionless and can have values around or equal to unity. A new conceptual framework for describing reservoir drive mechanisms based on JI has been formulated. According to this framework, reservoir drive mechanism is determined by comparing the computed JI values with unity rather than relying on subjective assessments of the trend of some functional dependencies. For the first time, it has become possible to express the reservoir drive performance quantitatively and determine the level of energy activity of the reservoirs with the help of JI. Additionally, a technique has been developed to evaluate the numerical values of JI for specific oil (including volatile oil) deposits based on the production data at any stage of production. The proposed methodology was tested using data from the eighth horizon of the Russkiy Khutor field in Russia. The test results not only confirmed the reliability of the obtained model but also demonstrated the adequacy of the proposed concept as a whole. Summarizing the results of other works by the authors, the adequacy of the proposed concept for both oil, gas, and gas condensate deposits has been confirmed. The research findings are expected to contribute to updating the traditional principles used for the mathematical problem statements in fluid flow in porous formations.","PeriodicalId":510854,"journal":{"name":"SPE Journal","volume":"4 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-07-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141693875","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}
Wettability is a fundamental parameter significantly influencing fluid distributions, saturations, and relative permeability in porous media. Despite the availability of several wettability measurement techniques, obtaining consistent wettability index results, particularly in tight reservoirs, remains a challenge. Nevertheless, obtaining accurate wettability indices is crucial for gaining a more profound understanding of rock properties and precisely identifying and evaluating oil recovery processes. This study adapts T1-T2 nuclear magnetic resonance (NMR) in twin plugs (cores cut in half from the middle) style wettability measurement for different reservoirs. The fluid typing in different lithologies by T1-T2 NMR is proved to be effective by introducing D2O with a modified pressurization saturation process. Therefore, demarcating the regions requires multiple experiments, including sole brine, sole oil phase, and D2O imbibition processes, to define oil and water distribution regions. Such fluid typing ability enables better accuracy in wettability characterization. The weighing method shows good agreement with the T2 spectrum but lacks the ability to differentiate fluids. It is observed that the same fluid in various porous media displays different divisions of T1/T2 ratios. The wettability index of sandstone, tuff, and shale measured by weighing and T1-T2 NMR method are compared and studied to demonstrate the applicability of different methods. The weighing method and the NMR method, as modified-Amott methods, share the same fundamental principle but differ in their measurement techniques. This study’s T1-T2 NMR wettability indices are −0.52, 0.06, and 0.14, whereas the weighing wettability indices are −0.63, 0.07, and 0.34 of sandstone, tuff, and shale, respectively. In addition to the difference in shale wettability index, there are also differences in shale porosity measured by methods with/without the ability to differentiate the fluid types. The T1-T2 NMR method is more accurate in measuring the wettability of shale because it can distinguish among free water in pores, structural water, and clay-bound water in smectitic clay minerals. If the clay-related water is not treated properly, the hydrophilicity of the shale will be overestimated. Ultimately, four types of pores (water-wet, oil-wet, mixed-wet, and unconnected pores) are classified and quantified by the proposed NMR method.
{"title":"Comparative Laboratory Wettability Study of Sandstone, Tuff, and Shale Using 12-MHz NMR T1-T2 Fluid Typing: Insight of Shale","authors":"Shuoshi Wang, Zheng Gu, Ping Guo, Wenhua Zhao","doi":"10.2118/221496-pa","DOIUrl":"https://doi.org/10.2118/221496-pa","url":null,"abstract":"\u0000 Wettability is a fundamental parameter significantly influencing fluid distributions, saturations, and relative permeability in porous media. Despite the availability of several wettability measurement techniques, obtaining consistent wettability index results, particularly in tight reservoirs, remains a challenge. Nevertheless, obtaining accurate wettability indices is crucial for gaining a more profound understanding of rock properties and precisely identifying and evaluating oil recovery processes. This study adapts T1-T2 nuclear magnetic resonance (NMR) in twin plugs (cores cut in half from the middle) style wettability measurement for different reservoirs. The fluid typing in different lithologies by T1-T2 NMR is proved to be effective by introducing D2O with a modified pressurization saturation process. Therefore, demarcating the regions requires multiple experiments, including sole brine, sole oil phase, and D2O imbibition processes, to define oil and water distribution regions. Such fluid typing ability enables better accuracy in wettability characterization. The weighing method shows good agreement with the T2 spectrum but lacks the ability to differentiate fluids. It is observed that the same fluid in various porous media displays different divisions of T1/T2 ratios. The wettability index of sandstone, tuff, and shale measured by weighing and T1-T2 NMR method are compared and studied to demonstrate the applicability of different methods. The weighing method and the NMR method, as modified-Amott methods, share the same fundamental principle but differ in their measurement techniques. This study’s T1-T2 NMR wettability indices are −0.52, 0.06, and 0.14, whereas the weighing wettability indices are −0.63, 0.07, and 0.34 of sandstone, tuff, and shale, respectively. In addition to the difference in shale wettability index, there are also differences in shale porosity measured by methods with/without the ability to differentiate the fluid types. The T1-T2 NMR method is more accurate in measuring the wettability of shale because it can distinguish among free water in pores, structural water, and clay-bound water in smectitic clay minerals. If the clay-related water is not treated properly, the hydrophilicity of the shale will be overestimated. Ultimately, four types of pores (water-wet, oil-wet, mixed-wet, and unconnected pores) are classified and quantified by the proposed NMR method.","PeriodicalId":510854,"journal":{"name":"SPE Journal","volume":"47 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-07-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141704498","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}
Amidst escalating environmental pressures, energy-intensive industries, particularly the oil and gas sector, are compelled to transition toward sustainable and low-carbon operations, adhering to the constraints of the environmental economy. While conventional reservoirs have been extensively developed, unconventional reservoirs, such as shale reservoirs, are poised to be the focal point in the future. Carbon dioxide enhanced oil recovery (CO2-EOR), a potent development tool proven effective in shale reservoirs, offers substantial carbon storage potential while significantly augmenting production. However, prior studies have solely optimized shale oil CO2-EOR production based on a singular optimization algorithm with net present value (NPV) as the objective function. In this study, we propose a novel NPV concept incorporating a carbon tax, which incorporates carbon taxes regulated by governments or organizations, thereby guiding carbon offsetting in oil reservoirs. We employ the embedded discrete fracture model (EDFM) approach to strike a balance between the accuracy of shale reservoir fracture simulation and computational efficiency, thereby enhancing timely technical guidance in the field. Subsequently, we compare the existing mainstream reservoir optimization algorithms and introduce a novel life cycle CO2 huff ’n’ puff (HnP) optimization workflow based on low-carbon NPV. The optimized NPV of the target reservoir witnessed an increase of 116.30%, while the optimization time was reduced by 89.47%, and the CO2 storage capacity was augmented by 12.58%. The workflow accelerates the simulation of the CO2 HnP in shale reservoirs, optimizing the production efficiency and CO2 storage capacity of shale reservoirs, and facilitating comprehensive and efficient production guidance for the production site.
在不断升级的环境压力下，能源密集型产业，尤其是石油和天然气行业，不得不向可持续和低碳运营转型，并遵守环境经济的约束。在常规储层得到广泛开发的同时，页岩储层等非常规储层有望成为未来的焦点。二氧化碳提高石油采收率（CO2-EOR）是一种在页岩油藏中被证明有效的开发工具，在显著提高产量的同时，还具有巨大的碳储存潜力。然而，之前的研究仅基于以净现值（NPV）为目标函数的单一优化算法来优化页岩油 CO2-EOR 的生产。在本研究中，我们提出了一种包含碳税的新型净现值概念，该概念包含由政府或组织监管的碳税，从而指导油藏中的碳抵消。我们采用嵌入式离散压裂模型（EDFM）方法，在页岩储层压裂模拟的精度和计算效率之间取得平衡，从而加强对现场的及时技术指导。随后，我们比较了现有的主流储层优化算法，并引入了一种基于低碳净现值的新型生命周期二氧化碳吹捧（HnP）优化工作流程。优化后的目标储层净现值提高了 116.30%，优化时间缩短了 89.47%，二氧化碳封存能力提高了 12.58%。该工作流程加速了页岩储层中 CO2 HnP 的模拟，优化了页岩储层的生产效率和 CO2 储量，有利于为生产现场提供全面高效的生产指导。
{"title":"Life Cycle Optimization of CO2 Huff ’n’ Puff in Shale Oil Reservoir Coupling Carbon Tax and Embedded Discrete Fracture Model","authors":"Guangxuan Pan, Sen Wang, Jianchun Xu, Qihong Feng","doi":"10.2118/219770-pa","DOIUrl":"https://doi.org/10.2118/219770-pa","url":null,"abstract":"\u0000 Amidst escalating environmental pressures, energy-intensive industries, particularly the oil and gas sector, are compelled to transition toward sustainable and low-carbon operations, adhering to the constraints of the environmental economy. While conventional reservoirs have been extensively developed, unconventional reservoirs, such as shale reservoirs, are poised to be the focal point in the future. Carbon dioxide enhanced oil recovery (CO2-EOR), a potent development tool proven effective in shale reservoirs, offers substantial carbon storage potential while significantly augmenting production. However, prior studies have solely optimized shale oil CO2-EOR production based on a singular optimization algorithm with net present value (NPV) as the objective function. In this study, we propose a novel NPV concept incorporating a carbon tax, which incorporates carbon taxes regulated by governments or organizations, thereby guiding carbon offsetting in oil reservoirs. We employ the embedded discrete fracture model (EDFM) approach to strike a balance between the accuracy of shale reservoir fracture simulation and computational efficiency, thereby enhancing timely technical guidance in the field. Subsequently, we compare the existing mainstream reservoir optimization algorithms and introduce a novel life cycle CO2 huff ’n’ puff (HnP) optimization workflow based on low-carbon NPV. The optimized NPV of the target reservoir witnessed an increase of 116.30%, while the optimization time was reduced by 89.47%, and the CO2 storage capacity was augmented by 12.58%. The workflow accelerates the simulation of the CO2 HnP in shale reservoirs, optimizing the production efficiency and CO2 storage capacity of shale reservoirs, and facilitating comprehensive and efficient production guidance for the production site.","PeriodicalId":510854,"journal":{"name":"SPE Journal","volume":"2010 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-07-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141851550","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}
Production time-series forecasting for newly drilled wells or those with limited flow and pressure historical data poses a significant challenge, and this problem is exacerbated by the complexities and uncertainties encountered in fractured subsurface systems. While many existing models rely on static features for prediction, the production data progressively offer more informative insights as production unfolds. Leveraging ongoing production data can enhance forecasting accuracy over time. However, effectively integrating the production stream data presents significant model training and updating complexities. We propose two innovative methods to address this challenge: masked recurrent alignment (MRA) and masked encoding decoding (MED). These methods enable the model to continually update its predictions based on historical data. In addition, by incorporating sequence padding and masking, our model can handle inputs of varying lengths without trimming, thereby avoiding the potential loss of valuable training samples. We implement these models with gated recurrent unit (GRU) and evaluate their performance in a case study involving 6,154 shale gas wells in the Central Montney Region. The data set encompasses 39 production-related features, including reservoir properties, completion, and wellhead information. Performance evaluation is based on root mean square error (RMSE) to predict 36-month production from 200 wells during testing. Empirical findings highlight the efficacy of the proposed models in handling challenges associated with variable-length input sequences, showcasing their superior performance. Our research emphasizes the value of including shorter time-series segments, often overlooked, to improve predictive accuracy, especially in scenarios with limited training samples.
{"title":"Dynamic Real-Time Production Forecasting Model for Complex Subsurface Flow Systems with Variable Length Input Sequences","authors":"Ziming Xu, Juliana Y. Leung","doi":"10.2118/221482-pa","DOIUrl":"https://doi.org/10.2118/221482-pa","url":null,"abstract":"\u0000 Production time-series forecasting for newly drilled wells or those with limited flow and pressure historical data poses a significant challenge, and this problem is exacerbated by the complexities and uncertainties encountered in fractured subsurface systems. While many existing models rely on static features for prediction, the production data progressively offer more informative insights as production unfolds. Leveraging ongoing production data can enhance forecasting accuracy over time. However, effectively integrating the production stream data presents significant model training and updating complexities. We propose two innovative methods to address this challenge: masked recurrent alignment (MRA) and masked encoding decoding (MED). These methods enable the model to continually update its predictions based on historical data. In addition, by incorporating sequence padding and masking, our model can handle inputs of varying lengths without trimming, thereby avoiding the potential loss of valuable training samples. We implement these models with gated recurrent unit (GRU) and evaluate their performance in a case study involving 6,154 shale gas wells in the Central Montney Region. The data set encompasses 39 production-related features, including reservoir properties, completion, and wellhead information. Performance evaluation is based on root mean square error (RMSE) to predict 36-month production from 200 wells during testing. Empirical findings highlight the efficacy of the proposed models in handling challenges associated with variable-length input sequences, showcasing their superior performance. Our research emphasizes the value of including shorter time-series segments, often overlooked, to improve predictive accuracy, especially in scenarios with limited training samples.","PeriodicalId":510854,"journal":{"name":"SPE Journal","volume":"259 2‐3","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-07-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141708343","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 systematical review of the largest alkali-surfactant-polymer (ASP) flood project in the world, applied to the largest oil field in China. First, reservoir and fluid characteristics are highlighted. Next, project history is summarized, including laboratory studies, pilot tests, industrial-scale tests, and fieldwide application. Third, typical ASP flooding performance and reservoir management measures from more than 30 years’ experience are presented. In addition, performances of ASP flood and polymer flood in the same field, which is also the largest project in the world, are compared. The Lamadian-Saertu-Xingshugang (La-Sa-Xing) Field in the Daqing Field Complex (including the La-Sa-Xing Field and three smaller satellite fields) is the largest oil field in China. The Upper Cretaceous Saertu-Putaohua-Gaotaizi reservoir has an average porosity of 25% and average permeability of 610 md. The reservoir consists of more than 100 flow units with an average gross and net thickness of 1,377 ft and 394 ft, respectively, and is characterized by significant heterogeneity, both vertically and laterally. The reservoir lies at a depth of 2,566–2,585 ft true vertical depth (TVD), with original reservoir pressure of 1,534–1,740 psi and a reservoir temperature of 113–122°F. Crude oil has an API gravity of 33° and a viscosity of 9 cp at reservoir conditions. The discussed ASP flood project mainly targets high-quality reservoir sands. The field was brought on-stream in 1960 with immediate waterflood. Crossflow and water breakthrough became common issues during water injection, calling for a suitable enhanced oil recovery (EOR) method. The Saertu-Putaohua-Gaotaizi reservoir features favorable conditions for ASP flood, such as temperature, viscosity, permeability, and formation water salinity (7000 mg/L). In addition, the heterogeneous reservoir (permeability variation coefficient of 0.6–0.8) is suitable for ASP flood. ASP flood was studied in the laboratory from 1987 to 1993, followed by five small-scale pilots from 1994 to 1999, all being successful with incremental recoveries of ~20% stock tank oil initially in place (STOIIP). As a result, industrial-scale tests were conducted from 2000 to 2007, resulting in substantial improvement in production from ~4,000 BOPD to greater than 19,000 BOPD. Encouraged by those successes, the ASP project was expanded to fieldwide since December 2007, which is the largest ASP flood project in the industry worldwide. By 2021, daily oil production by ASP flood had reached 96,000 BOPD through 4,825 producers and 4,825 injectors. The actual average incremental recovery factor is 20% over waterflood and 8–10% over polymer flood, resulting in ultimate recovery factor of >60%. Zonal injection and profile modification are effective measures to further improve sweeping efficiency. Scaling is the major challenge during the operation of ASP flood, which is mitigated or remediated by adopting weak alkali ASP, progressive
本文对应用于中国最大油田的世界上最大的碱-表面活性剂-聚合物（ASP）淹没项目进行了系统回顾。首先，重点介绍了储层和流体特征。其次，总结了项目历史，包括实验室研究、先导试验、工业规模试验和全油田应用。第三，介绍了 30 多年来典型的 ASP 淹没性能和油藏管理措施。此外，还比较了同一油田（也是世界上最大的项目）中 ASP 漫灌和聚合物漫灌的性能。大庆油田群（包括拉萨兴油田和三个较小的卫星油田）中的拉马店-萨尔图-杏树岗（拉萨兴）油田是中国最大的油田。上白垩统萨尔图-普陶化-高台子油藏的平均孔隙度为 25%，平均渗透率为 610 md。储油层由 100 多个流动单元组成，平均总厚度和净厚度分别为 1,377 英尺和 394 英尺，纵向和横向均具有显著的异质性。储油层的实际垂直深度（TVD）为 2,566-2,585 英尺，原始储油层压力为 1,534-1,740 psi，储油层温度为 113-122°F。在油藏条件下，原油的 API 重力为 33°，粘度为 9cp。所讨论的 ASP 泛滥项目主要针对优质储层砂。该油田于 1960 年投产，随即开始注水。在注水过程中，横流和水突破成为常见问题，因此需要一种合适的提高石油采收率（EOR）方法。Saertu-Putaohua-Gaotaizi 油藏的温度、粘度、渗透率和地层水盐度（7000 毫克/升）等条件均有利于水淹法。此外，异质储层（渗透率变化系数为 0.6-0.8）也适合 ASP 泄洪。1987 年至 1993 年期间，在实验室对 ASP 油浸进行了研究，随后在 1994 年至 1999 年期间进行了五次小规模试验，均取得了成功，增采率达到约 20% 的储油罐原油（STOIIP）。因此，在 2000 年至 2007 年期间进行了工业规模的试验，使产量从每天约 4,000 桶提高到超过每天 19,000 桶。在这些成功经验的鼓舞下，自 2007 年 12 月起，ASP 项目扩展到整个油田，这是全球业界最大的 ASP 泛注项目。到 2021 年，通过 4,825 台采油机和 4,825 台注入机，ASP 油田的日产油量达到 96,000 BOPD。实际平均提高采收率比注水法高 20%，比聚合物注水法高 8-10%，最终采收率大于 60%。分区注入和剖面修改是进一步提高扫采效率的有效措施。结垢是ASP水淹法运行过程中的主要挑战，可通过采用弱碱ASP、螺杆泵（PCP）、阻垢剂处理以及对受损井进行压裂激励来缓解或修复结垢。截至 2022 年，采用 ASP 水淹法生产的石油产量仍为 88635 BOPD，占油田总产量的 39.9%。在拉萨兴油田实施的世界上最大的ASP水淹项目，从技术和经济上证明了ASP水淹在整个油田的适用性。有效的水库管理措施和 30 多年的经验教训，为业内大型 ASP 漫灌项目提供了宝贵的经验。
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