Juntai Shi, Fang Yexin, Jiayi Wu, Zheng Sun, Jizhou Tang, Qian Li, Zan Chen, Lu Jiaguo, W. Ke, Yanran Jia, Yabing Wang, Wenming Lu
The low permeability of unconventional gas reservoir makes it difficult to achieve good development effect. Hydraulic fracturing technology and multi-lateral well technology are usually adopted to increase the gas production. What's more, the permeability may change dynamically during the production process because of the effective stress, gas slippage and matrix shrinkage effect. In this paper, we first establish the productivity equation of radial multi-branch horizontal (RMBH) well in unconventional natural gas reservoirs, considering the dynamic change of permeability during the production process. Then, the productivity equation of radial horizontal well with 2 branches is compared with fractured vertical well and conventional horizontal well productivity equations proposed by former researchers. Finally, main factors influencing the productivity of unconventional natural gas RMBH well are analyzed, including well structure parameters, gas formation properties and production stage. Results show that the productivity equation of degenerated RMBH well with 2 branches is proven to be reasonable by comparison with those of vertically fractured well and horizontal well. RMBH well shows more advantage in the formation with relatively large difference between maximum and minimum stresses, indicating that this type of well configuration may be an alternative technique for improving gas production in unconventional gas reservoirs. Sensitivity analyses demonstrate that the gas production rate of RMBH well is sensitive to branch length, branch number, build-up section horizontal distance, and stress dependence effect. The radial horizontal well with 4 branches can achieve a best development effect and economical benefit.
{"title":"Productivity Evaluation of Radial Multi-Branch Horizontal Well in Unconventional Gas Reservoirs Considering Permeability Variation: Model Establishment and Sensitivity Analyses","authors":"Juntai Shi, Fang Yexin, Jiayi Wu, Zheng Sun, Jizhou Tang, Qian Li, Zan Chen, Lu Jiaguo, W. Ke, Yanran Jia, Yabing Wang, Wenming Lu","doi":"10.2523/19955-ms","DOIUrl":"https://doi.org/10.2523/19955-ms","url":null,"abstract":"\u0000 The low permeability of unconventional gas reservoir makes it difficult to achieve good development effect. Hydraulic fracturing technology and multi-lateral well technology are usually adopted to increase the gas production. What's more, the permeability may change dynamically during the production process because of the effective stress, gas slippage and matrix shrinkage effect.\u0000 In this paper, we first establish the productivity equation of radial multi-branch horizontal (RMBH) well in unconventional natural gas reservoirs, considering the dynamic change of permeability during the production process. Then, the productivity equation of radial horizontal well with 2 branches is compared with fractured vertical well and conventional horizontal well productivity equations proposed by former researchers. Finally, main factors influencing the productivity of unconventional natural gas RMBH well are analyzed, including well structure parameters, gas formation properties and production stage.\u0000 Results show that the productivity equation of degenerated RMBH well with 2 branches is proven to be reasonable by comparison with those of vertically fractured well and horizontal well. RMBH well shows more advantage in the formation with relatively large difference between maximum and minimum stresses, indicating that this type of well configuration may be an alternative technique for improving gas production in unconventional gas reservoirs. Sensitivity analyses demonstrate that the gas production rate of RMBH well is sensitive to branch length, branch number, build-up section horizontal distance, and stress dependence effect. The radial horizontal well with 4 branches can achieve a best development effect and economical benefit.","PeriodicalId":11058,"journal":{"name":"Day 2 Tue, January 14, 2020","volume":"50 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2020-01-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86820688","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}
Water is the one of the most important aspect in unconventional resources (UR) where reservoirs are fractured to create cracks in the deep-rock formations and accordingly boost gas and oil production. Large amount of water is daily consumed for fracturing and drilling operations. To streamline the water transportation and conservation in those operations, several nonmetallic (NM) based technologies have been developed replacing the conventional ones. In water transport management there are two types of NM flexible that are used, the retrievable water transfer flexiable piping called layflat hose and the steel reinforce thermoplastic pipe called (S-RTP), which provide a better alternative as they have higher flexibility and faster installation in the field. In addition, fiber reinforced polymer (FRP) modular and bladder/inflatable tanks are water storage systems that have been utilized widely to eliminate the expensive pits construction and enhancing water management. The present papers highlights different NM water transport technologies replacing the current aluminum flowline, which provides many operational advantages. In addition, this paper presents a pipe-in liner technology for pipeline rehabilitation solutions. Besides, the paper presents technical information of modular and inflatable tank that would help eliminating the expensive construction and minimizing water splash/evaporation in the summer season. The technical qualification process of and successful field deployment of Layflat hose will be shared. This study will open the opportunity for further field deployments toward improving the water transport operation and minimizing the environment impact.
{"title":"Nonmetallic Technologies Supporting Water Transport and Store Management in Drilling and Fracturing Operations","authors":"W. Badeghaish, M. Noui-Mehidi, A. Parvez","doi":"10.2523/iptc-19918-ms","DOIUrl":"https://doi.org/10.2523/iptc-19918-ms","url":null,"abstract":"\u0000 Water is the one of the most important aspect in unconventional resources (UR) where reservoirs are fractured to create cracks in the deep-rock formations and accordingly boost gas and oil production. Large amount of water is daily consumed for fracturing and drilling operations. To streamline the water transportation and conservation in those operations, several nonmetallic (NM) based technologies have been developed replacing the conventional ones. In water transport management there are two types of NM flexible that are used, the retrievable water transfer flexiable piping called layflat hose and the steel reinforce thermoplastic pipe called (S-RTP), which provide a better alternative as they have higher flexibility and faster installation in the field. In addition, fiber reinforced polymer (FRP) modular and bladder/inflatable tanks are water storage systems that have been utilized widely to eliminate the expensive pits construction and enhancing water management.\u0000 The present papers highlights different NM water transport technologies replacing the current aluminum flowline, which provides many operational advantages. In addition, this paper presents a pipe-in liner technology for pipeline rehabilitation solutions. Besides, the paper presents technical information of modular and inflatable tank that would help eliminating the expensive construction and minimizing water splash/evaporation in the summer season. The technical qualification process of and successful field deployment of Layflat hose will be shared. This study will open the opportunity for further field deployments toward improving the water transport operation and minimizing the environment impact.","PeriodicalId":11058,"journal":{"name":"Day 2 Tue, January 14, 2020","volume":"58 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2020-01-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84609218","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2020-01-13DOI: 10.2523/iptc-20123-abstract
H. Nooruddin, N. Rahman
A new analytical procedure is introduced for the interpretation of pressure-transient data in oil producers with pronounced water production. The new mathematical model is applicable to flow conditions where segregated flow dominates the displacement process in the reservoir. Here, formation flow capacity and individual magnitudes of oil- and water-phase mobility are also determined, allowing accurate reservoir characterization under such complex flow conditions. Segregated flow is very common in natural porous rocks and is characterized by a sharp interface between oil and water. Hence, our new mathematical model mimics the dynamics of this flow mechanism by taking into consideration the individual contributions of oil and water from each reservoir zone. This novel mathematical model is utilized to extract formation flow capacity and mobility for both phases. An average fluid saturation can also be determined with a reasonable accuracy. The reservoir system in hand is represented by a two-layer model with no crossflow between the different zones in the reservoir. Because of gravity effects, oil is produced from the top layer while water is produced from the bottom one. Each reservoir layer has its own distinct static and dynamic properties, such as porosity, permeability, thickness, and petrophysical properties. A case study based on synthetic reservoir data is presented to demonstrate the application of the mathematical model in characterizing formation rocks. It is observed that conventional well-testing methods could produce inaccurate results when applied to reservoir systems influenced by segregated flow. Using the new model, a correction factor is derived to estimate absolute permeability values from the conventional well-testing analysis, producing a one-to-one transformation between dispersed and segregated flow. The conventional way of interpreting pressure-transient data for two-phase flow displacements under segregated conditions is based on an equivalent single-phase flow model that might produce inaccurate results and invalid estimates of flow capacity and phase mobility. Our new approach, therefore, is more representative for the system under consideration and captures the flow mechanism more robustly.
{"title":"A New Mathematical Formulation for Estimating Flow Capacity and Phase Mobility in Oil-Water Segregated Flow Systems","authors":"H. Nooruddin, N. Rahman","doi":"10.2523/iptc-20123-abstract","DOIUrl":"https://doi.org/10.2523/iptc-20123-abstract","url":null,"abstract":"\u0000 A new analytical procedure is introduced for the interpretation of pressure-transient data in oil producers with pronounced water production. The new mathematical model is applicable to flow conditions where segregated flow dominates the displacement process in the reservoir. Here, formation flow capacity and individual magnitudes of oil- and water-phase mobility are also determined, allowing accurate reservoir characterization under such complex flow conditions.\u0000 Segregated flow is very common in natural porous rocks and is characterized by a sharp interface between oil and water. Hence, our new mathematical model mimics the dynamics of this flow mechanism by taking into consideration the individual contributions of oil and water from each reservoir zone. This novel mathematical model is utilized to extract formation flow capacity and mobility for both phases. An average fluid saturation can also be determined with a reasonable accuracy.\u0000 The reservoir system in hand is represented by a two-layer model with no crossflow between the different zones in the reservoir. Because of gravity effects, oil is produced from the top layer while water is produced from the bottom one. Each reservoir layer has its own distinct static and dynamic properties, such as porosity, permeability, thickness, and petrophysical properties. A case study based on synthetic reservoir data is presented to demonstrate the application of the mathematical model in characterizing formation rocks. It is observed that conventional well-testing methods could produce inaccurate results when applied to reservoir systems influenced by segregated flow. Using the new model, a correction factor is derived to estimate absolute permeability values from the conventional well-testing analysis, producing a one-to-one transformation between dispersed and segregated flow.\u0000 The conventional way of interpreting pressure-transient data for two-phase flow displacements under segregated conditions is based on an equivalent single-phase flow model that might produce inaccurate results and invalid estimates of flow capacity and phase mobility. Our new approach, therefore, is more representative for the system under consideration and captures the flow mechanism more robustly.","PeriodicalId":11058,"journal":{"name":"Day 2 Tue, January 14, 2020","volume":"85 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2020-01-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83918124","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2020-01-13DOI: 10.2523/iptc-20125-abstract
D. Miklashevskiy, V. Shako, I. Borodin, C. Wilson, Dmitry Kortukov, N. Tarelko, O. Zozulya
The objective of this study was to develop a data processing flow for the oil and gas industry enabling the determination of inflow profile and fluid type identification for in well oil-water flows, and to quantify the phase and flow rates using distributed acoustic vibration data, in a near real-time wellbore monitoring scenario. The implementation of the approach will enable alarms to be raised in real-time in zones when changes in the flow rates and phase changes exceed predetermined levels, allowing quantifiable operational decisions. The acoustic data was acquired using a distributed fiber optical (FO) sensing technique and reference hydrophones in a laboratory flow loop equipped with accurate reference flowmeters. The acoustic noise created by the main pipe flow and inflow was studied. Total flow rate varied within the range 0 to 200 m3/d for water and a model of light oil. A set of numerical models was used to support development of the interpretation approaches through an enhanced understanding of the acoustic field in various real wellbore geometries. Two interpretation approaches based on laboratory correlations of acoustic noise energy in a selected frequency range and machine learning algorithms were developed to quantify phase rates from distributed acoustic vibration data induced by turbulent fluid flow in laboratory conditions. It is shown that correlation-based interpretation enables flow quantification and profiling within acceptable uncertainty levels, for a field dataset of distributed vibration measurements and a reference production logging tool (PLT) log in a producing wellbore. The goal of the software development is to provide a quantitative flow characterization from the interpretation of distributed acoustic vibration measurements. This method was tested using field fiber optic datasets combined with reference PLT log data.
{"title":"Approach for Wellbore Production Monitoring Using Distributed Acoustic Noise Measurements","authors":"D. Miklashevskiy, V. Shako, I. Borodin, C. Wilson, Dmitry Kortukov, N. Tarelko, O. Zozulya","doi":"10.2523/iptc-20125-abstract","DOIUrl":"https://doi.org/10.2523/iptc-20125-abstract","url":null,"abstract":"\u0000 The objective of this study was to develop a data processing flow for the oil and gas industry enabling the determination of inflow profile and fluid type identification for in well oil-water flows, and to quantify the phase and flow rates using distributed acoustic vibration data, in a near real-time wellbore monitoring scenario. The implementation of the approach will enable alarms to be raised in real-time in zones when changes in the flow rates and phase changes exceed predetermined levels, allowing quantifiable operational decisions.\u0000 The acoustic data was acquired using a distributed fiber optical (FO) sensing technique and reference hydrophones in a laboratory flow loop equipped with accurate reference flowmeters. The acoustic noise created by the main pipe flow and inflow was studied. Total flow rate varied within the range 0 to 200 m3/d for water and a model of light oil.\u0000 A set of numerical models was used to support development of the interpretation approaches through an enhanced understanding of the acoustic field in various real wellbore geometries.\u0000 Two interpretation approaches based on laboratory correlations of acoustic noise energy in a selected frequency range and machine learning algorithms were developed to quantify phase rates from distributed acoustic vibration data induced by turbulent fluid flow in laboratory conditions.\u0000 It is shown that correlation-based interpretation enables flow quantification and profiling within acceptable uncertainty levels, for a field dataset of distributed vibration measurements and a reference production logging tool (PLT) log in a producing wellbore.\u0000 The goal of the software development is to provide a quantitative flow characterization from the interpretation of distributed acoustic vibration measurements. This method was tested using field fiber optic datasets combined with reference PLT log data.","PeriodicalId":11058,"journal":{"name":"Day 2 Tue, January 14, 2020","volume":"32 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2020-01-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84234442","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}
Polymer flooding is one of the important measures to exploit the remaining oil in the middle and high water cut of oil fields. And the key to the success of the polymer flooding is the selection of the polymer flooding well. Pressure index (PI) and the degree of fullness (FD) are significant parameters, which are commonly used for polymer flooding project design and injection well performance analysis in China, due to their economical application. However, PI and FD are insufficient in discrimination and calculation method, which can only reflect the present heterogeneity of the formation. As a result, efficiency of polymer flooding decision might be not as good as expected. Improved pressure index (IPI) is established on basis of PI and FD. IPI is the ratio of the mean of pressure to the downfall of the wellhead pressure under the condition of unit water injection. The smaller the IPI value, the more the polymer flooding should be made. IPI not only takes the present heterogeneity of the formation into consideration, but also the transformation of pressure variation tendency. And IPI is a dimensionless parameter, which keeps initial advantages of PI and FD—simple and low cost. This method has been applied to nearly 50 Wells. The success rate of polymer flooding exceeds 92%. The measure reduce the water cut at the same time increase oil production. It not only improves the recovery yield, but also brings good economic benefit. In addition, the paper presents a field case study to validate the methodology. IPI is far more accurate than PI and FD. In summary, IPI is not only feasible, but also saves a lot of money. IPI has been applied to several oil fields in Bohai. And the effect is remarkable, which provides a good reference for the development of other oil fields.
{"title":"A New Well Selection Method Based on Improved Pressure Index for Polymer Flooding","authors":"Cunliang Chen, Xiaodong Han, Xue Liu, Cheng Wang","doi":"10.2523/iptc-19959-ms","DOIUrl":"https://doi.org/10.2523/iptc-19959-ms","url":null,"abstract":"\u0000 Polymer flooding is one of the important measures to exploit the remaining oil in the middle and high water cut of oil fields. And the key to the success of the polymer flooding is the selection of the polymer flooding well. Pressure index (PI) and the degree of fullness (FD) are significant parameters, which are commonly used for polymer flooding project design and injection well performance analysis in China, due to their economical application. However, PI and FD are insufficient in discrimination and calculation method, which can only reflect the present heterogeneity of the formation. As a result, efficiency of polymer flooding decision might be not as good as expected.\u0000 Improved pressure index (IPI) is established on basis of PI and FD. IPI is the ratio of the mean of pressure to the downfall of the wellhead pressure under the condition of unit water injection. The smaller the IPI value, the more the polymer flooding should be made. IPI not only takes the present heterogeneity of the formation into consideration, but also the transformation of pressure variation tendency. And IPI is a dimensionless parameter, which keeps initial advantages of PI and FD—simple and low cost.\u0000 This method has been applied to nearly 50 Wells. The success rate of polymer flooding exceeds 92%. The measure reduce the water cut at the same time increase oil production. It not only improves the recovery yield, but also brings good economic benefit. In addition, the paper presents a field case study to validate the methodology. IPI is far more accurate than PI and FD. In summary, IPI is not only feasible, but also saves a lot of money.\u0000 IPI has been applied to several oil fields in Bohai. And the effect is remarkable, which provides a good reference for the development of other oil fields.","PeriodicalId":11058,"journal":{"name":"Day 2 Tue, January 14, 2020","volume":"49 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2020-01-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84328468","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2020-01-13DOI: 10.2523/iptc-19786-abstract
B. Hammadi, Karim Agoudjil, A. Fahem, Fateh Tadjine, Hamza Moussa Benabdellah, A. Makhloufi, Abdelghani Djebrouni, B. Bouchikhi, Toufik Younsi
As a Brown Field, located in North Africa. Approximately 95% of Zarzaitine field wells are utilizing Gas Lift as an artificial lift method. The field has a challenging situation to optimize its Oil production; A detailed understanding of the production sys tem thermohydraulic, facility design and the amount of gas injection will ultimately have a major effect on production target. For this purpose, modeling the entire production system was necessary to properly account for the interdependency of wells and surface equipment and determine the system deliverability as a whole by optimizing Gas Lift injection. This paper presents an approach which was introduced for the first time in this field to ensure gas is used efficiently using a multiphase flow simulator for wells and pipelines to model the entire field Production Network in addition to the Oil producing wells including Gas lift mandrels. The model includes 112 Gas Lift wells with a detailed Gas Lift valves system currently on production, each one has been matched against the latest valid well test, Seven Separation Centers, Production gathering pipelines, Production gathering Center and Gas Lift Injection Center. The study has been executed in three major phases: Well Modeling & Calibration, Network Modeling and Gas Lift Optimization. Total Oil production rate has been defined as an objective function during the optimization phase where the total Injected Gas Lift rate for the entire network and for each individual well have been defined as varying parameters; By having a network model calibrated against field data representing the operational conditions of the asset, performing Gas Lift Optimization was the natural next step. Subsequently, by simulating the production system with different Gas Lift Optimization scenarios to maximize Oil production rate under specific surface facilities constraints using the Production Network Model, a better insight of how gas injection rate affects the total production and an understanding of whether a smarter allocation of the current available gas is possible in comparison to the different scenarios has been accomplished. As a result of this Optimization by applying some local and global constraints a 10% Oil production increase has been achieved. This practice has been shown to be successful as predictive technique in a variety of ways specially for such brown fields with more than 60 years of production history. As a next step, to properly manage the real potential of Brown fields, a full field Integrated Asset Model could be created to capture the interaction between the surface and the sub-surface. This model will account for the complex interactions between reservoir, wells and pipelines.
{"title":"Unlocking the Production Potential of Brown Fields through Gas Lift Optimization GLO","authors":"B. Hammadi, Karim Agoudjil, A. Fahem, Fateh Tadjine, Hamza Moussa Benabdellah, A. Makhloufi, Abdelghani Djebrouni, B. Bouchikhi, Toufik Younsi","doi":"10.2523/iptc-19786-abstract","DOIUrl":"https://doi.org/10.2523/iptc-19786-abstract","url":null,"abstract":"\u0000 As a Brown Field, located in North Africa. Approximately 95% of Zarzaitine field wells are utilizing Gas Lift as an artificial lift method. The field has a challenging situation to optimize its Oil production; A detailed understanding of the production sys tem thermohydraulic, facility design and the amount of gas injection will ultimately have a major effect on production target. For this purpose, modeling the entire production system was necessary to properly account for the interdependency of wells and surface equipment and determine the system deliverability as a whole by optimizing Gas Lift injection.\u0000 This paper presents an approach which was introduced for the first time in this field to ensure gas is used efficiently using a multiphase flow simulator for wells and pipelines to model the entire field Production Network in addition to the Oil producing wells including Gas lift mandrels. The model includes 112 Gas Lift wells with a detailed Gas Lift valves system currently on production, each one has been matched against the latest valid well test, Seven Separation Centers, Production gathering pipelines, Production gathering Center and Gas Lift Injection Center. The study has been executed in three major phases: Well Modeling & Calibration, Network Modeling and Gas Lift Optimization.\u0000 Total Oil production rate has been defined as an objective function during the optimization phase where the total Injected Gas Lift rate for the entire network and for each individual well have been defined as varying parameters; By having a network model calibrated against field data representing the operational conditions of the asset, performing Gas Lift Optimization was the natural next step. Subsequently, by simulating the production system with different Gas Lift Optimization scenarios to maximize Oil production rate under specific surface facilities constraints using the Production Network Model, a better insight of how gas injection rate affects the total production and an understanding of whether a smarter allocation of the current available gas is possible in comparison to the different scenarios has been accomplished. As a result of this Optimization by applying some local and global constraints a 10% Oil production increase has been achieved.\u0000 This practice has been shown to be successful as predictive technique in a variety of ways specially for such brown fields with more than 60 years of production history. As a next step, to properly manage the real potential of Brown fields, a full field Integrated Asset Model could be created to capture the interaction between the surface and the sub-surface. This model will account for the complex interactions between reservoir, wells and pipelines.","PeriodicalId":11058,"journal":{"name":"Day 2 Tue, January 14, 2020","volume":"42 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2020-01-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81311717","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2020-01-13DOI: 10.2523/iptc-19634-abstract
H. A. Sadah, M. Kadem, K. Yateem, M. Dabbous
The demand for permanent downhole monitoring systems (PDHMS's) has been increasing over the last two decades. These systems, along with other real-time and intelligent field technologies, provide real-time data that are crucial to both reservoir and production engineers with reservoir modeling and production strategies. A PDHMS consists of two main parts, which are downhole and surface equipment. Although the installation cost of this equipment might not be significant if installed during initial completion or routine workover, replacing defective downhole equipment is costly as it will require a workover operation. Therefore, it is important to capitalize on all opportunities to retrieve and analyze defective downhole equipment to minimize future malfunction, increase the life expectancy, reduce operational cost, and enhance efficiency. This paper studies several downhole gauge challenges to find out their root causes. This will help in enhancing future designs and reducing the number of downhole gauge replacements. These gauges were retrieved during scheduled workover operations on several wells. They were retrieved and sent to their manufacturers for Dismantle Inspection Failure Analysis (DIFA). The root causes were identified and the recommendations were implemented in all newer models. In many cases, the issue was caused by only one component, which was either downhole gauge malfunctioning or port blockage of the gauge mandrel. The component may vary depending on the gauge manufacturer and model, with the most common causes being the Y-block/Y-splitter, debris and non-properly swaged ferrules. The findings have been utilized by PDHMS manufacturers to amend and enhance their next generations. Taking advantage of as many opportunities as possible to retrieve and study failed equipment will assist oil and service companies to work together for developing more reliable models that can extend their run life even in harsh downhole environments.
{"title":"Permenant Downhole Monitoring System PDHMS Reliability","authors":"H. A. Sadah, M. Kadem, K. Yateem, M. Dabbous","doi":"10.2523/iptc-19634-abstract","DOIUrl":"https://doi.org/10.2523/iptc-19634-abstract","url":null,"abstract":"\u0000 The demand for permanent downhole monitoring systems (PDHMS's) has been increasing over the last two decades. These systems, along with other real-time and intelligent field technologies, provide real-time data that are crucial to both reservoir and production engineers with reservoir modeling and production strategies.\u0000 A PDHMS consists of two main parts, which are downhole and surface equipment. Although the installation cost of this equipment might not be significant if installed during initial completion or routine workover, replacing defective downhole equipment is costly as it will require a workover operation. Therefore, it is important to capitalize on all opportunities to retrieve and analyze defective downhole equipment to minimize future malfunction, increase the life expectancy, reduce operational cost, and enhance efficiency.\u0000 This paper studies several downhole gauge challenges to find out their root causes. This will help in enhancing future designs and reducing the number of downhole gauge replacements. These gauges were retrieved during scheduled workover operations on several wells. They were retrieved and sent to their manufacturers for Dismantle Inspection Failure Analysis (DIFA). The root causes were identified and the recommendations were implemented in all newer models.\u0000 In many cases, the issue was caused by only one component, which was either downhole gauge malfunctioning or port blockage of the gauge mandrel. The component may vary depending on the gauge manufacturer and model, with the most common causes being the Y-block/Y-splitter, debris and non-properly swaged ferrules.\u0000 The findings have been utilized by PDHMS manufacturers to amend and enhance their next generations. Taking advantage of as many opportunities as possible to retrieve and study failed equipment will assist oil and service companies to work together for developing more reliable models that can extend their run life even in harsh downhole environments.","PeriodicalId":11058,"journal":{"name":"Day 2 Tue, January 14, 2020","volume":"09 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2020-01-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89909231","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}
Corrosion inhibition of carbon steel in sour oil and gas production at elevated temperatures (>100°C) and under high shear stress presents a major challenge for operators, especially when compared to inhibition under sweet conditions. The formation of insoluble iron sulfide scales such as pyrrhotite which are less dense and easily break under high shear presents a major challenge with localized corrosion in extreme sour applications. The main objective of this project was to develop a novel sour corrosion inhibitor solution, which would provide both general and localised corrosion inhibition under such extreme conditions. This paper presents key findings from a laboratory protocol designed to select a candidate sour corrosion inhibitor for a sour application. The laboratory tests were carried out in Hastelloy™ C 276 autoclave test rigs designed specifically for high temperature, high pressure, and high shear conditions in a sour environment. The test conditions were 135°C, with a shear stress of 92 Pascal, CO2 and H2S partial pressures of 3.1 and 6.2 bara respectively. White light interferometry was used for surface analysis of the carbon steel coupons after the tests to compliment the corrosion rate data. Results from the project showed the performance of a novel sour corrosion inhibitor specifically designed for high temperature sour gas applications. The corrosion inhibitor showed significant improvement in general and localised corrosion inhibition against carbon steel material compared to the traditional corrosion inhibitors typically used in sour environments. The product identified from the project has shown to provide better protection for carbon steel pipelines under extreme sour production conditions. Cost analysis confirmed that the chemical application could offer a more cost effective solution than the option of using corrosion resistant alloys.
{"title":"Corrosion Inhibition of Carbon Steel in Extreme Sour Application Conditions","authors":"Adedamola Adelusi, W. Mok, Olaoluwa I Olubodun","doi":"10.2523/iptc-20145-ms","DOIUrl":"https://doi.org/10.2523/iptc-20145-ms","url":null,"abstract":"\u0000 Corrosion inhibition of carbon steel in sour oil and gas production at elevated temperatures (>100°C) and under high shear stress presents a major challenge for operators, especially when compared to inhibition under sweet conditions. The formation of insoluble iron sulfide scales such as pyrrhotite which are less dense and easily break under high shear presents a major challenge with localized corrosion in extreme sour applications. The main objective of this project was to develop a novel sour corrosion inhibitor solution, which would provide both general and localised corrosion inhibition under such extreme conditions.\u0000 This paper presents key findings from a laboratory protocol designed to select a candidate sour corrosion inhibitor for a sour application. The laboratory tests were carried out in Hastelloy™ C 276 autoclave test rigs designed specifically for high temperature, high pressure, and high shear conditions in a sour environment. The test conditions were 135°C, with a shear stress of 92 Pascal, CO2 and H2S partial pressures of 3.1 and 6.2 bara respectively.\u0000 White light interferometry was used for surface analysis of the carbon steel coupons after the tests to compliment the corrosion rate data.\u0000 Results from the project showed the performance of a novel sour corrosion inhibitor specifically designed for high temperature sour gas applications. The corrosion inhibitor showed significant improvement in general and localised corrosion inhibition against carbon steel material compared to the traditional corrosion inhibitors typically used in sour environments. The product identified from the project has shown to provide better protection for carbon steel pipelines under extreme sour production conditions. Cost analysis confirmed that the chemical application could offer a more cost effective solution than the option of using corrosion resistant alloys.","PeriodicalId":11058,"journal":{"name":"Day 2 Tue, January 14, 2020","volume":"60 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2020-01-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74392833","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}
Condition monitoring, or CM is the process of monitoring machinery parameters such as vibration and temperature trends at routine intervals, in order to identify any significant change which may indicate developing faults. Vibration Analysis may be considered as one of the most predominant CM techniques used industry wide to carry out predictive maintenance and analysis on rotating equipment. Fault conditions such as unbalance, misalignment, resonance, hydraulic and aerodynamic forces can be detected using a variety of vibration tests and analysis methods. Saudi Aramco Shaybah NGL Recovery Plant Department experienced a failure on a cooling tower right angled gearbox during commissioning. The root cause identified was insufficient lubrication. Although this gearbox was fitted with online fixed instrumentation, set points were too lenient. However, offline vibration troubleshooting techniques highlighted a resonance issue and provided the necessary data to rectify and resolve the high vibration on the fan. Mitigation steps taken included a thorough evaluation of the existing gearbox protection design and Velometer selection. Further vibration data was collected with a portable device for two main reasons: firstly for comparison with the fixed Velometer readings and secondly to measure in the horizontal axis, which is perpendicular to the fixed position. Higher amplitudes were recorded in the horizontal axis as the vertical position where the Velometer is fixed, due to the orientation of the gearbox supporting beam. Resonance or bump tests were conducted on the gearbox to investigate the elevated amplitudes recorded in the horizontal plane. Bump tests proved that the natural frequency of the gearbox coincided with the cooling fans blade pass frequency (BPF). Resonance was proven, therefore had to be addressed in order to avoid component deterioration and imminent failure. Cost and repair or down time was paramount in finding the solution and implementation on all four cooling fans. Fundamentally, the most effective solution was to separate the fan blade pass and the natural frequencies of the right angled gearbox. Removing a resonance condition would reduce the overall vibration amplitude and extend the component life span of the cooling tower rotating parts. This paper will detail the steps taken to investigate and rectify the mechanical failure. In addition it will discuss the relevance of an effective predictive maintenance strategy and the importance of verifying the design of fixed or permanent instrumentation.
{"title":"Cooling Tower Resonance Mitigation Through Vibration Analysis.","authors":"Sean Torrie","doi":"10.2523/19956-abstract","DOIUrl":"https://doi.org/10.2523/19956-abstract","url":null,"abstract":"\u0000 Condition monitoring, or CM is the process of monitoring machinery parameters such as vibration and temperature trends at routine intervals, in order to identify any significant change which may indicate developing faults. Vibration Analysis may be considered as one of the most predominant CM techniques used industry wide to carry out predictive maintenance and analysis on rotating equipment. Fault conditions such as unbalance, misalignment, resonance, hydraulic and aerodynamic forces can be detected using a variety of vibration tests and analysis methods.\u0000 Saudi Aramco Shaybah NGL Recovery Plant Department experienced a failure on a cooling tower right angled gearbox during commissioning. The root cause identified was insufficient lubrication. Although this gearbox was fitted with online fixed instrumentation, set points were too lenient. However, offline vibration troubleshooting techniques highlighted a resonance issue and provided the necessary data to rectify and resolve the high vibration on the fan.\u0000 Mitigation steps taken included a thorough evaluation of the existing gearbox protection design and Velometer selection. Further vibration data was collected with a portable device for two main reasons: firstly for comparison with the fixed Velometer readings and secondly to measure in the horizontal axis, which is perpendicular to the fixed position. Higher amplitudes were recorded in the horizontal axis as the vertical position where the Velometer is fixed, due to the orientation of the gearbox supporting beam. Resonance or bump tests were conducted on the gearbox to investigate the elevated amplitudes recorded in the horizontal plane. Bump tests proved that the natural frequency of the gearbox coincided with the cooling fans blade pass frequency (BPF). Resonance was proven, therefore had to be addressed in order to avoid component deterioration and imminent failure. Cost and repair or down time was paramount in finding the solution and implementation on all four cooling fans. Fundamentally, the most effective solution was to separate the fan blade pass and the natural frequencies of the right angled gearbox. Removing a resonance condition would reduce the overall vibration amplitude and extend the component life span of the cooling tower rotating parts.\u0000 This paper will detail the steps taken to investigate and rectify the mechanical failure. In addition it will discuss the relevance of an effective predictive maintenance strategy and the importance of verifying the design of fixed or permanent instrumentation.","PeriodicalId":11058,"journal":{"name":"Day 2 Tue, January 14, 2020","volume":"8 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2020-01-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85995677","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2020-01-13DOI: 10.2523/iptc-19915-abstract
S. al-Turkey, D. Freile, L. Tagarieva, Mohamed Elyas, G. Schmid
Pulsed-neutron capture (PNC) logs are commonly used to determine formation water saturation in cased-hole environments, often for time-lapse monitoring purposes. This paper describes a new diffusion-corrected sigma algorithm developed for a pulse neutron logging tool. In southeast Kuwait, diffusion-corrected sigma log data was recorded in three wells using an array of four optimally spaced gamma ray detectors above a neutron generator. To calculate a diffusion-corrected sigma, an algorithm based on a dual exponential fit was applied to the time-decay spectrum of the near and far detectors. This calculation separates the formation and borehole decays. This approach provides an apparent formation sigma for the near and far detectors. The algorithm uses the near detector for final sigma, and a diffusion correction to the near sigma is determined by a function of a near-far sigma difference. The diffusion-corrected sigma matched the expected results and provided a good statistical quality—even at high sigma values—because it is based on the near detector with its higher count rate, as demonstrated in the examples presented. Also, the formation sigma was independent of different borehole conditions in which the data was recorded. The final formation sigma results were compared to volumetric results from open-hole data (volume of shale, effective porosity and water saturation) and sigma calculated from open-hole volumetric using material balance. The PNC data recorded in the three wells allowed determination of the most recent oil-water contact (OWC) and update of water encroachment maps from the time-lapse monitoring. Comparing with previous sigma data recorded in these wells, it was concluded a normalization transform is not needed because R2 value of the linear regression is close to 1. The diffusion-corrected sigma algorithm using dual exponential fit showed that this technique was able to extract independent values for borehole sigma and formation sigma for each detector and to perform an accurate diffusion correction. This algorithm will provide reliable sigma values regardless of the borehole conditions in which the data was recorded.
{"title":"Diffusion-Corrected Sigma Using Dual Exponential Fit for Time-Lapse Reservoir Monitoring","authors":"S. al-Turkey, D. Freile, L. Tagarieva, Mohamed Elyas, G. Schmid","doi":"10.2523/iptc-19915-abstract","DOIUrl":"https://doi.org/10.2523/iptc-19915-abstract","url":null,"abstract":"\u0000 Pulsed-neutron capture (PNC) logs are commonly used to determine formation water saturation in cased-hole environments, often for time-lapse monitoring purposes. This paper describes a new diffusion-corrected sigma algorithm developed for a pulse neutron logging tool.\u0000 In southeast Kuwait, diffusion-corrected sigma log data was recorded in three wells using an array of four optimally spaced gamma ray detectors above a neutron generator. To calculate a diffusion-corrected sigma, an algorithm based on a dual exponential fit was applied to the time-decay spectrum of the near and far detectors. This calculation separates the formation and borehole decays. This approach provides an apparent formation sigma for the near and far detectors. The algorithm uses the near detector for final sigma, and a diffusion correction to the near sigma is determined by a function of a near-far sigma difference.\u0000 The diffusion-corrected sigma matched the expected results and provided a good statistical quality—even at high sigma values—because it is based on the near detector with its higher count rate, as demonstrated in the examples presented. Also, the formation sigma was independent of different borehole conditions in which the data was recorded. The final formation sigma results were compared to volumetric results from open-hole data (volume of shale, effective porosity and water saturation) and sigma calculated from open-hole volumetric using material balance. The PNC data recorded in the three wells allowed determination of the most recent oil-water contact (OWC) and update of water encroachment maps from the time-lapse monitoring. Comparing with previous sigma data recorded in these wells, it was concluded a normalization transform is not needed because R2 value of the linear regression is close to 1.\u0000 The diffusion-corrected sigma algorithm using dual exponential fit showed that this technique was able to extract independent values for borehole sigma and formation sigma for each detector and to perform an accurate diffusion correction. This algorithm will provide reliable sigma values regardless of the borehole conditions in which the data was recorded.","PeriodicalId":11058,"journal":{"name":"Day 2 Tue, January 14, 2020","volume":"8 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2020-01-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79794144","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
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