In this paper, we study the simulation and fault diagnosis of a conventional pumping unit under balanced conditions. As the energy input of sucker-rod pumping (SRP), the motor power contains abundant information about the whole pumping cycle under SRP. It is an important step in oilfield information construction to establish a computer-aided system that is based on motor power diagnosis. Hence, we propose an SRP simulation model for generating motor power. By analyzing the working conditions of six oil wells that contain normal or insufficient liquid supply, gas lock, traveling valve leakage, standing valve leakage, and parting rod, we simulate the motor power of the six wells. In addition, we verify the simulation model using a test well with favorable performance and establish the motor power template set (MPTS) using this simulation model. To allow for computer-aided diagnosis, we propose the use of the area proportion method to extract motor power features. We establish a diagnosis model of oilwell conditions that is based on oblique decision tree and train the diagnosis model using the MPTS. Through the verification of six oil wells in the actual production of the oil field, the diagnosis model shows a favorable response. The test results show that the methods of establishing MPTS and oilwell working-condition diagnosis are feasible.
{"title":"Complete Simulation and Fault Diagnosis of Sucker-Rod Pumping (includes associated comment)","authors":"Bin Zhang, Xian-wen Gao, Xiangyu Li","doi":"10.2118/204215-PA","DOIUrl":"https://doi.org/10.2118/204215-PA","url":null,"abstract":"In this paper, we study the simulation and fault diagnosis of a conventional pumping unit under balanced conditions. As the energy input of sucker-rod pumping (SRP), the motor power contains abundant information about the whole pumping cycle under SRP. It is an important step in oilfield information construction to establish a computer-aided system that is based on motor power diagnosis. Hence, we propose an SRP simulation model for generating motor power. By analyzing the working conditions of six oil wells that contain normal or insufficient liquid supply, gas lock, traveling valve leakage, standing valve leakage, and parting rod, we simulate the motor power of the six wells. In addition, we verify the simulation model using a test well with favorable performance and establish the motor power template set (MPTS) using this simulation model. To allow for computer-aided diagnosis, we propose the use of the area proportion method to extract motor power features. We establish a diagnosis model of oilwell conditions that is based on oblique decision tree and train the diagnosis model using the MPTS. Through the verification of six oil wells in the actual production of the oil field, the diagnosis model shows a favorable response. The test results show that the methods of establishing MPTS and oilwell working-condition diagnosis are feasible.","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":null,"pages":null},"PeriodicalIF":1.2,"publicationDate":"2021-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"67780080","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}
Since its discovery in 1971, numerous matrix stimulations have been performed in South Pars field. However, there are still various challenges surrounding stimulation job design and evaluation methods. To tackle these issues, 16 matrix operations were selected to be analyzed from different phases of the development project of the reservoir. The objective of this study is to introduce an efficient interpretation method to determine optimum treatment volume (gal/ft), compare the effectiveness of diverters, calculate stimulation ratio (SR), and forecast post-acid production behavior from surface treatingdata.The modified inverse injectivity (Iinv) method, which is fully discussed by Safari et al. (2020), is used in this study. The obtained data were analyzed in terms of Iinv decreasing trend, Iinv humps, and pre-/post-acid Iinv during the stimulation process. In addition, pre-/post-stimulation surface testing data are gathered and analyzed. These data are coupled with post-acid Iinv to find a correlation to predict production behavior of treated wells. SR is defined as the ratio of pre-acid Iinv to post-acid Iinv of a treated well. Finally, SR values are validated with available production logging tool (PLT) data from two stimulation operations.First, the obtained results indicated that optimum treatment volume (gal/ft) of acid depends on well conditions. It means that wells with high initial formation damage require more volumes of stimulation fluids. In this regard, wells treated with 27/27 gal/ft treatment volume design [27 gal/ft 28% hydrochloric acid (HCl) and 27 gal/ft 15% viscoelastic surfactant (VES)] were understimulated. Although treatment volume design of 53/53 gal/ft seems to be adequate for low-skin wells, higher treatment volume (gal/ft) would further enhance productivity of highly damaged wells. This result was confirmed by stimulation of a damaged well with treatment volume of 60/60 gal/ft. Finally, the most reliable design applied in the field so far is the 70/70 gal/ft treatment volume. Second, Iinv analyses depicted that better diversion is observed in wells with lower injectivity and higher damage. At the next step, the calculated SR values showed an average deviation of less than 10% from downhole PLT data. Ultimately, the produced results demonstrated that there is a direct relation between the post-acid Iinv and surface drawdown in this field. Therefore, production behavior of treated wells can be correlated by having access to post-acid Iinv.The novelty of this work pertains to use of surface treating data recorded during a stimulation operation to generate Iinv and its associated analysis curves to evaluate performance of matrix stimulation operations. By applying this method, optimum volume of acid and diverter, diversion effectiveness, SR, and an estimation of post-acid surface drawdown can be obtained from the simple surface treating data. The secondary-produced data could lead to a better understanding of carbonate reser
{"title":"An Efficient Interpretation Method for Matrix Acidizing Evaluation and Optimization in Long Heterogeneous Carbonate Reservoirs","authors":"H. Panjalizadeh, Alireza Safari, M. Kamani","doi":"10.2118/203411-PA","DOIUrl":"https://doi.org/10.2118/203411-PA","url":null,"abstract":"Since its discovery in 1971, numerous matrix stimulations have been performed in South Pars field. However, there are still various challenges surrounding stimulation job design and evaluation methods. To tackle these issues, 16 matrix operations were selected to be analyzed from different phases of the development project of the reservoir. The objective of this study is to introduce an efficient interpretation method to determine optimum treatment volume (gal/ft), compare the effectiveness of diverters, calculate stimulation ratio (SR), and forecast post-acid production behavior from surface treatingdata.The modified inverse injectivity (Iinv) method, which is fully discussed by Safari et al. (2020), is used in this study. The obtained data were analyzed in terms of Iinv decreasing trend, Iinv humps, and pre-/post-acid Iinv during the stimulation process. In addition, pre-/post-stimulation surface testing data are gathered and analyzed. These data are coupled with post-acid Iinv to find a correlation to predict production behavior of treated wells. SR is defined as the ratio of pre-acid Iinv to post-acid Iinv of a treated well. Finally, SR values are validated with available production logging tool (PLT) data from two stimulation operations.First, the obtained results indicated that optimum treatment volume (gal/ft) of acid depends on well conditions. It means that wells with high initial formation damage require more volumes of stimulation fluids. In this regard, wells treated with 27/27 gal/ft treatment volume design [27 gal/ft 28% hydrochloric acid (HCl) and 27 gal/ft 15% viscoelastic surfactant (VES)] were understimulated. Although treatment volume design of 53/53 gal/ft seems to be adequate for low-skin wells, higher treatment volume (gal/ft) would further enhance productivity of highly damaged wells. This result was confirmed by stimulation of a damaged well with treatment volume of 60/60 gal/ft. Finally, the most reliable design applied in the field so far is the 70/70 gal/ft treatment volume. Second, Iinv analyses depicted that better diversion is observed in wells with lower injectivity and higher damage. At the next step, the calculated SR values showed an average deviation of less than 10% from downhole PLT data. Ultimately, the produced results demonstrated that there is a direct relation between the post-acid Iinv and surface drawdown in this field. Therefore, production behavior of treated wells can be correlated by having access to post-acid Iinv.The novelty of this work pertains to use of surface treating data recorded during a stimulation operation to generate Iinv and its associated analysis curves to evaluate performance of matrix stimulation operations. By applying this method, optimum volume of acid and diverter, diversion effectiveness, SR, and an estimation of post-acid surface drawdown can be obtained from the simple surface treating data. The secondary-produced data could lead to a better understanding of carbonate reser","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":null,"pages":null},"PeriodicalIF":1.2,"publicationDate":"2021-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"67779927","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}
Accurate prediction of fracture initiation pressure and orientation is paramount to the design of a hydraulic fracture stimulation treatment and is a major factor in the treatment's eventual success. In this study, closed-form analytical approximations of the fracturing stresses are used to develop orientation criteria for relative-to-the-wellbore (longitudinal or transverse) fracture initiation from perforated wells. These criteria were assessed numerically and found to overestimate the occurrence of transverse fracture initiation, which only takes place under a narrow range of conditions in which the tensile strength of the rock formation is lower than a critical value, and the breakdown pressure falls within a “window.” For a case study performed on the Barnett Shale, transverse fracture initiation is shown to take place for breakdown pressures below 4,762 psi, provided that the formation's tensile strength is below 2,482 psi. A robust 3D finite volume numerical model is used to evaluate solutions for the longitudinal and transverse fracturing stresses for a variable wellbore pressure, hence developing correction factors for the existing closed-form approximations. Geomechanical inputs from the Barnett Shale are considered for a horizontal well aligned parallel to the direction of the least compressive horizontal principal stress. The corrected numerically derived expressions can predict initiation pressures for a specific orientation of fracture initiation. Similarly, at known breakdown pressures, the corrected expressions are used to predict the orientation of fracture initiation. Besides wellbore trajectory, the results depend on the perforation direction. For the Barnett Shale case study, which is under a normal faulting stress regime, the perforations on the side of the borehole yield a wider breakdown pressure window by 71% and higher critical tensile strength by 32.5%, compared to perforations on top of the borehole, implying better promotion of transverse fracture initiation. Leakage of fracturing fluid around the wellbore, between the cemented casing and the surrounding rock, reduces the breakdown pressure window by 11% and the critical tensile strength by 65%. Dimensionless plots are employed to present the range of in-situ stress states in which longitudinal or transverse hydraulic fracture initiation is promoted. This is useful for completion engineers; when targeting low permeability formations such as shale reservoirs, multiple transverse fractures must be induced from the horizontal wells, as opposed to longitudinal fracture initiation, which is desired in higher permeability reservoirs or “frac-and-pack” operations.
{"title":"A Semianalytical Modeling Approach for Hydraulic Fracture Initiation and Orientation from Perforated Wells","authors":"Andreas Michael, I. Gupta","doi":"10.2118/204480-PA","DOIUrl":"https://doi.org/10.2118/204480-PA","url":null,"abstract":"Accurate prediction of fracture initiation pressure and orientation is paramount to the design of a hydraulic fracture stimulation treatment and is a major factor in the treatment's eventual success. In this study, closed-form analytical approximations of the fracturing stresses are used to develop orientation criteria for relative-to-the-wellbore (longitudinal or transverse) fracture initiation from perforated wells. These criteria were assessed numerically and found to overestimate the occurrence of transverse fracture initiation, which only takes place under a narrow range of conditions in which the tensile strength of the rock formation is lower than a critical value, and the breakdown pressure falls within a “window.” For a case study performed on the Barnett Shale, transverse fracture initiation is shown to take place for breakdown pressures below 4,762 psi, provided that the formation's tensile strength is below 2,482 psi. A robust 3D finite volume numerical model is used to evaluate solutions for the longitudinal and transverse fracturing stresses for a variable wellbore pressure, hence developing correction factors for the existing closed-form approximations. Geomechanical inputs from the Barnett Shale are considered for a horizontal well aligned parallel to the direction of the least compressive horizontal principal stress. The corrected numerically derived expressions can predict initiation pressures for a specific orientation of fracture initiation. Similarly, at known breakdown pressures, the corrected expressions are used to predict the orientation of fracture initiation. Besides wellbore trajectory, the results depend on the perforation direction. For the Barnett Shale case study, which is under a normal faulting stress regime, the perforations on the side of the borehole yield a wider breakdown pressure window by 71% and higher critical tensile strength by 32.5%, compared to perforations on top of the borehole, implying better promotion of transverse fracture initiation. Leakage of fracturing fluid around the wellbore, between the cemented casing and the surrounding rock, reduces the breakdown pressure window by 11% and the critical tensile strength by 65%. Dimensionless plots are employed to present the range of in-situ stress states in which longitudinal or transverse hydraulic fracture initiation is promoted. This is useful for completion engineers; when targeting low permeability formations such as shale reservoirs, multiple transverse fractures must be induced from the horizontal wells, as opposed to longitudinal fracture initiation, which is desired in higher permeability reservoirs or “frac-and-pack” operations.","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":null,"pages":null},"PeriodicalIF":1.2,"publicationDate":"2021-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"67780434","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}
Xiang Wang, Yangeng He, Fajun Li, Wang Zhen, X. Dou, Xu Hui, Lipei Fu
Monitoring the working conditions of sucker rod pumping wells in a timely and accurate manner is important for oil production. With the development of smart oil fields, more and more sensors are installed on the well, and the monitored data are continuously transmitted to the data center to form big data. In this work, we aim to utilize the big data collected during oil well production and a deep learning technique to build a new generation of intelligent diagnosis model to monitor working condition of sucker rod pumping wells. More than 5×106 of well monitoring records, which covers information from about 1 year for more than 300 wells in an oilfield block, are collected and preprocessed. To show the dynamic changes of the working conditions for the wells, the overlay dynamometer card is proposed and plotted for each data record. The working conditions are divided into 30 types, and the corresponding data set is created. An intelligent diagnosis model using the convolutional neural network (CNN), one of the deep learning frameworks, is proposed. By the convolution and pooling operation, the CNN can extract features of an image implicitly without human effort and prior knowledge. That makes a CNN very suitable for the recognition of the overlay dynamometer cards. The architecture for a working condition diagnosis CNN model is designed. The CNN model consists of 14 layers with six convolutional layers, three pooling layers, and three fully connected layers. The total number of neurons is more than 1.7×106. The overlay dynamometer card data set is used to train and validate the CNN model. The accuracy and efficiency of the model are evaluated. Both the training and validation accuracies of the CNN model are greater than 99% after 10 training epochs. The average training elapsed time for an epoch is 8909.5 seconds, and the average time to diagnosis a sample is 1.3 milliseconds. Based on the trained CNN model, a working condition monitoring software for a sucker rod pumping well is developed. The software runs 7 × 24 hours to diagnosis the working conditions of wells and post a warning to users. It also has a feedback learning workflow to update the CNN model regularly to improve its performance. The on-site run shows that the actual accuracy of the CNN model is greater than 90%.
{"title":"A Working Condition Diagnosis Model of Sucker Rod Pumping Wells Based on Deep Learning","authors":"Xiang Wang, Yangeng He, Fajun Li, Wang Zhen, X. Dou, Xu Hui, Lipei Fu","doi":"10.2118/205015-PA","DOIUrl":"https://doi.org/10.2118/205015-PA","url":null,"abstract":"Monitoring the working conditions of sucker rod pumping wells in a timely and accurate manner is important for oil production. With the development of smart oil fields, more and more sensors are installed on the well, and the monitored data are continuously transmitted to the data center to form big data. In this work, we aim to utilize the big data collected during oil well production and a deep learning technique to build a new generation of intelligent diagnosis model to monitor working condition of sucker rod pumping wells. More than 5×106 of well monitoring records, which covers information from about 1 year for more than 300 wells in an oilfield block, are collected and preprocessed. To show the dynamic changes of the working conditions for the wells, the overlay dynamometer card is proposed and plotted for each data record. The working conditions are divided into 30 types, and the corresponding data set is created. An intelligent diagnosis model using the convolutional neural network (CNN), one of the deep learning frameworks, is proposed. By the convolution and pooling operation, the CNN can extract features of an image implicitly without human effort and prior knowledge. That makes a CNN very suitable for the recognition of the overlay dynamometer cards. The architecture for a working condition diagnosis CNN model is designed. The CNN model consists of 14 layers with six convolutional layers, three pooling layers, and three fully connected layers. The total number of neurons is more than 1.7×106. The overlay dynamometer card data set is used to train and validate the CNN model. The accuracy and efficiency of the model are evaluated. Both the training and validation accuracies of the CNN model are greater than 99% after 10 training epochs. The average training elapsed time for an epoch is 8909.5 seconds, and the average time to diagnosis a sample is 1.3 milliseconds. Based on the trained CNN model, a working condition monitoring software for a sucker rod pumping well is developed. The software runs 7 × 24 hours to diagnosis the working conditions of wells and post a warning to users. It also has a feedback learning workflow to update the CNN model regularly to improve its performance. The on-site run shows that the actual accuracy of the CNN model is greater than 90%.","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":null,"pages":null},"PeriodicalIF":1.2,"publicationDate":"2021-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"67780789","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}
Reserves estimation is an essential part of developing any reservoir. Predicting the long-term production performance and estimated ultimate recovery (EUR) in unconventional wells has always been a challenge. Developing a reliable and accurate production forecast in the oil and gas industry is mandatory because it plays a crucial part in decision-making. Several methods are used to estimate EUR in the oil and gas industry, and each has its advantages and limitations. Decline curve analysis (DCA) is a traditional reserves estimation technique that is widely used to estimate EUR in conventional reservoirs. However, when it comes to unconventional reservoirs, traditional methods are frequently unreliable for predicting production trends for low-permeability plays. In recent years, many approaches have been developed to accommodate the high complexity of unconventional plays and establish reliable estimates of reserves. This paper provides a methodology to predict EUR for multistage hydraulically fractured horizontal wells that outperforms many current methods, incorporates completion data, and overcomes some of the limitations of using DCA or other traditional methods to forecast production. This new approach is introduced to predict EUR for multistage hydraulically fractured horizontal wells and is presented as a workflow consisting of production history matching and forecasting using DCA combined with artificial neural network (ANN) predictive models. The developed workflow combines production history data, forecasting using DCA models and completion data to enhance EUR predictions. The predictive models use ANN techniques to predict EUR given short early production history data (3 months to 2 years). The new approach was developed and tested using actual production and completion data from 989 multistage hydraulically fractured horizontal wells from four different formations. Sixteen models were developed (four models for each formation) varying in terms of input parameters, structure, and the production history data period it requires. The developed models showed high accuracy (correlation coefficients of 0.85 to 0.99) in predicting EUR given only 3 months to 2 years of production data. The developed models use production forecasts from different DCA models along with well completion data to improve EUR predictions. Using completion parameters in predicting EUR along with the typical DCA is a major addition provided by this study. The end product of this work is a comprehensive workflow to predict EUR that can be implemented in different formations by using well completion data along with early production history data.
{"title":"A New Approach To Estimating Ultimate Recovery for Multistage Hydraulically Fractured Horizontal Wells by Utilizing Completion Parameters Using Machine Learning","authors":"Sulaiman A. Alarifi, J. Miskimins","doi":"10.2118/204470-PA","DOIUrl":"https://doi.org/10.2118/204470-PA","url":null,"abstract":"Reserves estimation is an essential part of developing any reservoir. Predicting the long-term production performance and estimated ultimate recovery (EUR) in unconventional wells has always been a challenge. Developing a reliable and accurate production forecast in the oil and gas industry is mandatory because it plays a crucial part in decision-making. Several methods are used to estimate EUR in the oil and gas industry, and each has its advantages and limitations. Decline curve analysis (DCA) is a traditional reserves estimation technique that is widely used to estimate EUR in conventional reservoirs. However, when it comes to unconventional reservoirs, traditional methods are frequently unreliable for predicting production trends for low-permeability plays. In recent years, many approaches have been developed to accommodate the high complexity of unconventional plays and establish reliable estimates of reserves. This paper provides a methodology to predict EUR for multistage hydraulically fractured horizontal wells that outperforms many current methods, incorporates completion data, and overcomes some of the limitations of using DCA or other traditional methods to forecast production. This new approach is introduced to predict EUR for multistage hydraulically fractured horizontal wells and is presented as a workflow consisting of production history matching and forecasting using DCA combined with artificial neural network (ANN) predictive models. The developed workflow combines production history data, forecasting using DCA models and completion data to enhance EUR predictions. The predictive models use ANN techniques to predict EUR given short early production history data (3 months to 2 years). The new approach was developed and tested using actual production and completion data from 989 multistage hydraulically fractured horizontal wells from four different formations. Sixteen models were developed (four models for each formation) varying in terms of input parameters, structure, and the production history data period it requires. The developed models showed high accuracy (correlation coefficients of 0.85 to 0.99) in predicting EUR given only 3 months to 2 years of production data. The developed models use production forecasts from different DCA models along with well completion data to improve EUR predictions. Using completion parameters in predicting EUR along with the typical DCA is a major addition provided by this study. The end product of this work is a comprehensive workflow to predict EUR that can be implemented in different formations by using well completion data along with early production history data.","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":null,"pages":null},"PeriodicalIF":1.2,"publicationDate":"2021-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"67780191","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}
Low-melting-point bismuth- (Bi-) based alloys have recently been proposed for plug-and-abandonment (P&A). Previous experiments have shown the feasibility of BiSn [58-wt% Bi and 42-wt% tin (Sn)] and BiAg [97.5-wt% Bi and 2.5-wt% silver (Ag)] alloy plugs in moderate temperature wells, both across shales and across the shale/sandstone sequence. These were validated in linear and cylindrical wellbore cavity geometries for various differential setting pressures for alloy over air. Until now, all of the experiments for setting alloy plugs have been conducted with air as the wetting fluid. Given the lack of adhesion between minerals and alloy, our concept for providing bond strength and integrity has hinged on providing a bicontinuous structure through alloy penetration into the pore network. For shales, with a positive setting pressure, anchors on the surface, in lieu of pores, have proven to be adequate. With results obtained under excess alloy pressure, we have quantified the effect of setting pressure on the alloy/shale bond quality. With brine as the wetting fluid, imposing an excess pressure on the alloy has not been demonstrated previously. This paper is the continuation of our previously published papers (Zhang et al. 2020a, 2020b), and our objective here is not only to show the possibility of forming a plug under brine but also to quantify the plug’s quality with and without an excess alloy pressure. We first describe an apparatus that controls alloy and brine pressures independently through a semipermeable piston assembly and demonstrate forming alloy plugs in a brine-filled borehole cavity. Based on pressure decay tests across the plug, we demonstrate that wellbore integrity is possible only with a positive alloy pressure over that of brine.
{"title":"Testing Low-Melting-Point Alloy Plug in Model Brine-Filled Wells","authors":"Hua Zhang, T. Ramakrishnan, Q. Elias","doi":"10.2118/205001-PA","DOIUrl":"https://doi.org/10.2118/205001-PA","url":null,"abstract":"Low-melting-point bismuth- (Bi-) based alloys have recently been proposed for plug-and-abandonment (P&A). Previous experiments have shown the feasibility of BiSn [58-wt% Bi and 42-wt% tin (Sn)] and BiAg [97.5-wt% Bi and 2.5-wt% silver (Ag)] alloy plugs in moderate temperature wells, both across shales and across the shale/sandstone sequence. These were validated in linear and cylindrical wellbore cavity geometries for various differential setting pressures for alloy over air. Until now, all of the experiments for setting alloy plugs have been conducted with air as the wetting fluid. Given the lack of adhesion between minerals and alloy, our concept for providing bond strength and integrity has hinged on providing a bicontinuous structure through alloy penetration into the pore network. For shales, with a positive setting pressure, anchors on the surface, in lieu of pores, have proven to be adequate. With results obtained under excess alloy pressure, we have quantified the effect of setting pressure on the alloy/shale bond quality. With brine as the wetting fluid, imposing an excess pressure on the alloy has not been demonstrated previously. This paper is the continuation of our previously published papers (Zhang et al. 2020a, 2020b), and our objective here is not only to show the possibility of forming a plug under brine but also to quantify the plug’s quality with and without an excess alloy pressure. We first describe an apparatus that controls alloy and brine pressures independently through a semipermeable piston assembly and demonstrate forming alloy plugs in a brine-filled borehole cavity. Based on pressure decay tests across the plug, we demonstrate that wellbore integrity is possible only with a positive alloy pressure over that of brine.","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":null,"pages":null},"PeriodicalIF":1.2,"publicationDate":"2021-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"67780522","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}
In multiple-stage hydraulic fracturing treatments performed in horizontal wells, treatment confinement is the state in which fracturing fluid and proppant flow out of the wellbore only through the specific perforations targeted for the fracturing stage. The terms treatment confinement and treatment isolation are synonymous. Isolation from previously treated intervals is a necessary condition for efficient treatment along the lateral. Failure to confine fracturing stages can be a result of failure of the fracture plug to maintain a seal or the development of casing breaches (holes) in the proximity of the fracture plug. Both conditions can be strongly impacted by proppant induced erosion. This paper is a sequel to a previous publication in which casing erosion and breaches were investigated in fracture treated horizontal wells in the Montney Formation (White et al. 2020). Integrated diagnostic methods based on data from treating pressure analysis, fiber-optic measurements, and downhole imaging were applied to investigate the root cause of failure. It was determined that treatment pressure analysis was effective in diagnosing casing and associated fracture plug integrity-loss events. This was achieved by (1) identifying treating pressure trends and anomalies during the main part of the treatment that signify confinement loss, (2) calculating near-wellbore friction at the end of treatments to compare to the friction expected for a confined treatment, and (3) analyzing step-down tests conducted during the pad stage and overflush stage at the end of the treatment to determine the near-wellbore frictional components of perforation friction and near-wellbore tortuosity. This information enables comparison of previous with current treatments for determining the effects of job design and fracture plug modifications on treatment confinement. The objective of this paper is to validate that useful conclusions on the degree of treatment confinement can be made using only stand-alone pressure-based analysis. This is achieved by comparing the analysis results with fiber-optic and post-treatment wellbore imaging measurements. Also highlighted is the use of downhole gauges for accurately calculating pipe friction, which is necessary for accurately calculating bottomhole treating pressure at the active treatment interval.
在水平井多级水力压裂过程中，压裂封闭是指压裂液和支撑剂只能通过压裂段的特定射孔流出井筒的状态。治疗禁闭和治疗隔离是同义词。与先前处理过的层段隔离是沿侧向有效处理的必要条件。限制压裂级数的失败可能是由于压裂塞无法保持密封，或者在压裂塞附近出现套管裂缝(井眼)。这两种情况都可能受到支撑剂侵蚀的强烈影响。本文是前一篇论文的续集，该论文研究了Montney地层压裂水平井的套管侵蚀和裂缝(White et al. 2020)。基于处理压力分析、光纤测量和井下成像数据的综合诊断方法被用于调查故障的根本原因。结果表明，处理压力分析在诊断套管和相关裂缝塞完整性损失事件方面是有效的。这是通过以下方法实现的:(1)识别处理过程中主要部分的处理压力趋势和异常，表明封闭损失;(2)计算处理结束时的近井摩擦，与封闭处理的预期摩擦进行比较;(3)分析处理结束时垫层阶段和溢水阶段进行的降压测试，以确定射孔摩擦和近井弯曲的近井摩擦成分。这些信息可以将以前的处理方法与当前的处理方法进行比较，以确定作业设计和裂缝塞修改对处理限制的影响。本文的目的是验证，在处理限制的程度上，有用的结论可以只使用独立的基于压力的分析。这是通过将分析结果与光纤和处理后的井筒成像测量结果进行比较来实现的。同样值得强调的是使用井下仪表来精确计算管柱摩擦，这对于准确计算主动处理段的井底处理压力是必要的。
{"title":"Pressure-Based Diagnostics for Evaluating Treatment Confinement","authors":"D. Cramer, Junjing Zhang","doi":"10.2118/205003-PA","DOIUrl":"https://doi.org/10.2118/205003-PA","url":null,"abstract":"In multiple-stage hydraulic fracturing treatments performed in horizontal wells, treatment confinement is the state in which fracturing fluid and proppant flow out of the wellbore only through the specific perforations targeted for the fracturing stage. The terms treatment confinement and treatment isolation are synonymous. Isolation from previously treated intervals is a necessary condition for efficient treatment along the lateral. Failure to confine fracturing stages can be a result of failure of the fracture plug to maintain a seal or the development of casing breaches (holes) in the proximity of the fracture plug. Both conditions can be strongly impacted by proppant induced erosion. This paper is a sequel to a previous publication in which casing erosion and breaches were investigated in fracture treated horizontal wells in the Montney Formation (White et al. 2020). Integrated diagnostic methods based on data from treating pressure analysis, fiber-optic measurements, and downhole imaging were applied to investigate the root cause of failure. It was determined that treatment pressure analysis was effective in diagnosing casing and associated fracture plug integrity-loss events. This was achieved by (1) identifying treating pressure trends and anomalies during the main part of the treatment that signify confinement loss, (2) calculating near-wellbore friction at the end of treatments to compare to the friction expected for a confined treatment, and (3) analyzing step-down tests conducted during the pad stage and overflush stage at the end of the treatment to determine the near-wellbore frictional components of perforation friction and near-wellbore tortuosity. This information enables comparison of previous with current treatments for determining the effects of job design and fracture plug modifications on treatment confinement. The objective of this paper is to validate that useful conclusions on the degree of treatment confinement can be made using only stand-alone pressure-based analysis. This is achieved by comparing the analysis results with fiber-optic and post-treatment wellbore imaging measurements. Also highlighted is the use of downhole gauges for accurately calculating pipe friction, which is necessary for accurately calculating bottomhole treating pressure at the active treatment interval.","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":null,"pages":null},"PeriodicalIF":1.2,"publicationDate":"2021-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"67780563","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}
S. Hossain, Obinna Ezulike, Yingkun Fu, H. Dehghanpour
We propose a novel method for estimating average fracture compressibility cf¯ during flowback process and apply it to flowback data from 10 multifractured horizontal wells completed in Woodford (WF) and Meramec (MM) formations. We conduct complementary diagnostic flow-regime analyses and calculate cf¯ by combining a flowing-material-balance (FMB) equation with pressure-normalized-rate (PNR)-decline analysis. Flowback data of these wells show up to 2 weeks of single-phase water production followed by hydrocarbon breakthrough. Plots of water-rate-normalized pressure and its derivative show pronounced unit slopes, suggesting boundary-dominated flow (BDF) of water in fractures during single-phase flow. Water PNR decline curves follow a harmonic trend during single-phase- and multiphase-flow periods. Ultimate water production from the forecasted harmonic trend gives an estimate of initial fracture volume. The cf¯ estimates for these wells are verified by comparing them with the ones from the Aguilera (1999) type curves for natural fractures and experimental data. The results show that our cf¯ estimates (4 to 22×10−5 psi−1) are close to the lower limit of the values estimated by previous studies, which can be explained by the presence of proppants in hydraulic fractures.
{"title":"Average Fracture Compressibility from Flowback Data","authors":"S. Hossain, Obinna Ezulike, Yingkun Fu, H. Dehghanpour","doi":"10.2118/204481-PA","DOIUrl":"https://doi.org/10.2118/204481-PA","url":null,"abstract":"We propose a novel method for estimating average fracture compressibility cf¯ during flowback process and apply it to flowback data from 10 multifractured horizontal wells completed in Woodford (WF) and Meramec (MM) formations. We conduct complementary diagnostic flow-regime analyses and calculate cf¯ by combining a flowing-material-balance (FMB) equation with pressure-normalized-rate (PNR)-decline analysis. Flowback data of these wells show up to 2 weeks of single-phase water production followed by hydrocarbon breakthrough. Plots of water-rate-normalized pressure and its derivative show pronounced unit slopes, suggesting boundary-dominated flow (BDF) of water in fractures during single-phase flow. Water PNR decline curves follow a harmonic trend during single-phase- and multiphase-flow periods. Ultimate water production from the forecasted harmonic trend gives an estimate of initial fracture volume. The cf¯ estimates for these wells are verified by comparing them with the ones from the Aguilera (1999) type curves for natural fractures and experimental data. The results show that our cf¯ estimates (4 to 22×10−5 psi−1) are close to the lower limit of the values estimated by previous studies, which can be explained by the presence of proppants in hydraulic fractures.","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":null,"pages":null},"PeriodicalIF":1.2,"publicationDate":"2021-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"67780440","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}
The development of concentrated and highly stable oil-in-water (O/W) emulsion is considered to be a cost-effective alternative for the transportation of produced heavy crude oils. However, the demulsification of a transported O/W emulsion is necessary once it reaches the destination. This article experimentally investigates the performance of four low-cost chemicals of varying water solubility as potential demulsifiers, independently and in combinations, for demulsifying two Indian heavy crude O/W emulsions prepared for pipeline transportation. The chemical demulsifiers used, in order of their higher water solubility, are: polyethylene glycol 400 (PEG) > polyoxyethylene (20) sorbitan monooleate (Tween-80) > linear alkylbenzene sulfonic acid (LABSA) > n-octylamine (OA). For this study, stable O/W emulsions (in the 60:40 ratio) of two Indian heavy crude oils were prepared using high-frequency ultrasonic waves in the presence of Triton X-100 as a surfactant. Both crude oils were characterized at first based on their physicochemical properties, infrared (IR) spectrum, and rheological properties. Prepared O/W emulsions were characterized based on rheological properties and droplet size. A bottle test method with heating (using a water bath) and enhanced gravity (by centrifuge) has been used to study the demulsification efficiency of used chemicals. Complete demulsification of both emulsions was achieved as desired. The synergetic effect of the interaction between two suitable demulsifiers provided remarkably better performance than that of independent returns, leading to minimization of the amount of demulsifier and the energy requirement for complete demulsification of both emulsions.
{"title":"Experimental Studies on Demulsification of Heavy Crude Oil-in-Water Emulsions by Chemicals, Heating, and Centrifuging","authors":"Shailesh Kumar, V. Rajput, V. Mahto","doi":"10.2118/204452-pa","DOIUrl":"https://doi.org/10.2118/204452-pa","url":null,"abstract":"\u0000 The development of concentrated and highly stable oil-in-water (O/W) emulsion is considered to be a cost-effective alternative for the transportation of produced heavy crude oils. However, the demulsification of a transported O/W emulsion is necessary once it reaches the destination. This article experimentally investigates the performance of four low-cost chemicals of varying water solubility as potential demulsifiers, independently and in combinations, for demulsifying two Indian heavy crude O/W emulsions prepared for pipeline transportation. The chemical demulsifiers used, in order of their higher water solubility, are: polyethylene glycol 400 (PEG) > polyoxyethylene (20) sorbitan monooleate (Tween-80) > linear alkylbenzene sulfonic acid (LABSA) > n-octylamine (OA). For this study, stable O/W emulsions (in the 60:40 ratio) of two Indian heavy crude oils were prepared using high-frequency ultrasonic waves in the presence of Triton X-100 as a surfactant. Both crude oils were characterized at first based on their physicochemical properties, infrared (IR) spectrum, and rheological properties. Prepared O/W emulsions were characterized based on rheological properties and droplet size. A bottle test method with heating (using a water bath) and enhanced gravity (by centrifuge) has been used to study the demulsification efficiency of used chemicals. Complete demulsification of both emulsions was achieved as desired. The synergetic effect of the interaction between two suitable demulsifiers provided remarkably better performance than that of independent returns, leading to minimization of the amount of demulsifier and the energy requirement for complete demulsification of both emulsions.","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":null,"pages":null},"PeriodicalIF":1.2,"publicationDate":"2020-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"42102250","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. Ahmed, I. Hussein, Abdulmujeeb T. Onawole, M. Mahmoud, M. Saad
Iron sulfide scale causes major losses in both upstream and downstream sectors of the hydrocarbon industry. Pyrite is one of the most-difficult forms of iron sulfide scale from a removal point of view. Inorganic acids such as hydrochloric acid (HCl) are not recommended for removing pyrite scales because they have many drawbacks, including low pyrite solubility, high corrosivity to the tubular system, and generation of toxic hydrogen sulfide (H2S). In this work, pyrite-scale dissolution is studied using an ecofriendly formulation of glutamic diacetic acid [L-glutamic acid, N, N-diacetic acid (GLDA)] as an alternative to HCl. Although GLDA has shown potential for removing iron sulfide in general and pyrite scale in particular, still GLDA/pyrite kinetics have not been well-understood. Both experimental and theoretical techniques have been used. The reaction kinetics has been investigated in a rotating-disk apparatus (RDA) at typical reservoir conditions of 150°C and 1,000 psi (Conway et al. 1999). Characterization techniques, including X-ray photoelectron spectroscopy (XPS) and scanning electron microscope (SEM), have been used to study the surface chemistry before and after treatment with GLDA, and the results support pyrite removal. Furthermore, density-functional-theory (DFT) calculations have been performed to understand the ability of GLDA to dissolve iron sulfide scale at the atomistic level. From the laboratory results, the reaction rate using 20-wt% GLDA (pH of 3.8) was 5.378×10−8 mol/cm2·s. The measured rate outperformed other proposed formulations according to the tetrakis(hydroxymethyl)phosphonium sulfate (THPS) formulation by 15 times. In addition, GLDA surpassed the most recent results on diethylenetriamine penta-acetic acid (DTPA) by nearly an order of magnitude. Moreover, pyrite dissolution in GLDA increases as the disk rotational speed increased, which indicates mass-transfer control with a diffusion coefficient of 1.338×10−7 cm2/s. Furthermore, from molecular modeling using DFT, the binding energy between GLDA and Fe2+ is calculated as –105.97 kcal/mol. The negative value observed correlates with the stability constant and indicates the strong binding affinity to Fe2+. Finally, GLDA could be recommended for pyrite-scale removal because it is biodegradable, less corrosive, free of H2S, and achieved solubility that outperformed THPS- and DTPA-basedformulations.
{"title":"Pyrite-Scale Removal Using Glutamic Diacetic Acid: A Theoretical and Experimental Investigation","authors":"M. Ahmed, I. Hussein, Abdulmujeeb T. Onawole, M. Mahmoud, M. Saad","doi":"10.2118/204478-pa","DOIUrl":"https://doi.org/10.2118/204478-pa","url":null,"abstract":"\u0000 Iron sulfide scale causes major losses in both upstream and downstream sectors of the hydrocarbon industry. Pyrite is one of the most-difficult forms of iron sulfide scale from a removal point of view. Inorganic acids such as hydrochloric acid (HCl) are not recommended for removing pyrite scales because they have many drawbacks, including low pyrite solubility, high corrosivity to the tubular system, and generation of toxic hydrogen sulfide (H2S). In this work, pyrite-scale dissolution is studied using an ecofriendly formulation of glutamic diacetic acid [L-glutamic acid, N, N-diacetic acid (GLDA)] as an alternative to HCl. Although GLDA has shown potential for removing iron sulfide in general and pyrite scale in particular, still GLDA/pyrite kinetics have not been well-understood. Both experimental and theoretical techniques have been used. The reaction kinetics has been investigated in a rotating-disk apparatus (RDA) at typical reservoir conditions of 150°C and 1,000 psi (Conway et al. 1999). Characterization techniques, including X-ray photoelectron spectroscopy (XPS) and scanning electron microscope (SEM), have been used to study the surface chemistry before and after treatment with GLDA, and the results support pyrite removal. Furthermore, density-functional-theory (DFT) calculations have been performed to understand the ability of GLDA to dissolve iron sulfide scale at the atomistic level. From the laboratory results, the reaction rate using 20-wt% GLDA (pH of 3.8) was 5.378×10−8 mol/cm2·s. The measured rate outperformed other proposed formulations according to the tetrakis(hydroxymethyl)phosphonium sulfate (THPS) formulation by 15 times. In addition, GLDA surpassed the most recent results on diethylenetriamine penta-acetic acid (DTPA) by nearly an order of magnitude. Moreover, pyrite dissolution in GLDA increases as the disk rotational speed increased, which indicates mass-transfer control with a diffusion coefficient of 1.338×10−7 cm2/s. Furthermore, from molecular modeling using DFT, the binding energy between GLDA and Fe2+ is calculated as –105.97 kcal/mol. The negative value observed correlates with the stability constant and indicates the strong binding affinity to Fe2+. Finally, GLDA could be recommended for pyrite-scale removal because it is biodegradable, less corrosive, free of H2S, and achieved solubility that outperformed THPS- and DTPA-basedformulations.","PeriodicalId":22071,"journal":{"name":"Spe Production & Operations","volume":null,"pages":null},"PeriodicalIF":1.2,"publicationDate":"2020-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"43471496","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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