Slack or baggy webs can cause misregistration, wrinkles, and breaks in printing and converting operations. Bagginess appears as non-uniform tautness in the cross direction (CD) of a paper web. The underlying cause is uneven CD tension profiles, for which there are few remedies once the paper is made. Precision measurements of CD tension profiles combined with trials on commercial paper machines have shown that uniform CD distribution of moisture, basis weight, and caliper profiles at the reel are key to avoiding bagginess. However, the most important but infrequently measured factor is the CD moisture profile entering the dryer section. Wetter areas entering the dryers are permanently elongated more than dry areas, leading to greater slackness in the finished paper. In storage, wound-in tension can amplify baggy streaks in paper near the surface of a roll and adjacent to the core. Unwrapped or poorly wrapped rolls exposed to low humidity environments may have baggy centers caused by moisture loss from the roll edges. All of the factors that impact bagginess have been incorporated in a mathematical model that was used to interpret the observations from commercial trials and can be used as a guide to solve future problems.
{"title":"A guide to eliminating baggy webs","authors":"Fred J. Parent, J. Hamel, David Mcdonald","doi":"10.32964/tj20.6.365","DOIUrl":"https://doi.org/10.32964/tj20.6.365","url":null,"abstract":"Slack or baggy webs can cause misregistration, wrinkles, and breaks in printing and converting operations. Bagginess appears as non-uniform tautness in the cross direction (CD) of a paper web. The underlying cause is uneven CD tension profiles, for which there are few remedies once the paper is made.\u0000Precision measurements of CD tension profiles combined with trials on commercial paper machines have shown that uniform CD distribution of moisture, basis weight, and caliper profiles at the reel are key to avoiding bagginess. However, the most important but infrequently measured factor is the CD moisture profile entering the dryer section. Wetter areas entering the dryers are permanently elongated more than dry areas, leading to greater slackness in the finished paper. \u0000In storage, wound-in tension can amplify baggy streaks in paper near the surface of a roll and adjacent to the core. Unwrapped or poorly wrapped rolls exposed to low humidity environments may have baggy centers caused by moisture loss from the roll edges.\u0000All of the factors that impact bagginess have been incorporated in a mathematical model that was used to interpret the observations from commercial trials and can be used as a guide to solve future problems.","PeriodicalId":11075,"journal":{"name":"Day 1 Mon, June 28, 2021","volume":"5 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-07-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88411922","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}
It is foreseeable that recovery boiler particulate emission limits in the United States and Canada will continue to get more stringent with time. Because of this, continued improvement of emission control equipment, as well as a better understanding of how operating parameters affect performance, are necessary. Although electrostatic precipitators (ESPs) are often viewed as a mature technology, many improvements in ESP technology continue to be developed. In recent years, academic efforts have improved the understanding of recovery boiler operating conditions on ESP performance. Additionally, advancements in materials, power supplies, and design continue to improve the efficiency and reliability of ESPs. This paper discusses how recovery boiler and electrostatic precipitator (ESP) operating factors affect ESP performance based on process simulations and practical experience, and how these learnings can be implemented to improve future operation of existing ESPs.
{"title":"New learnings and strategies for meeting future recovery boiler particulate emission limits with existing electrostatic precipitators","authors":"Ivana Sretenović","doi":"10.32964/tj20.6.405","DOIUrl":"https://doi.org/10.32964/tj20.6.405","url":null,"abstract":"It is foreseeable that recovery boiler particulate emission limits in the United States and Canada will continue to get more stringent with time. Because of this, continued improvement of emission control equipment, as well as a better understanding of how operating parameters affect performance, are necessary. \u0000Although electrostatic precipitators (ESPs) are often viewed as a mature technology, many improvements in ESP technology continue to be developed. In recent years, academic efforts have improved the understanding of recovery boiler operating conditions on ESP performance. Additionally, advancements in materials, power supplies, and design continue to improve the efficiency and reliability of ESPs.\u0000This paper discusses how recovery boiler and electrostatic precipitator (ESP) operating factors affect ESP performance based on process simulations and practical experience, and how these learnings can be implemented to improve future operation of existing ESPs.","PeriodicalId":11075,"journal":{"name":"Day 1 Mon, June 28, 2021","volume":"32 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-07-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75287136","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The objective of this study is to determine the effects of the concentration of injected gases on recovery factors. CO2 has been used for flooding because it requires low injection pressures to achieve miscibility. However, the availability of CO2 is an issue. CO2 required for the process is not sufficient for the reservoir under consideration. Moreover, its benefit-cost ratio (b/c) represents another issue; higher volumes of CO2 increases the economic expenditures. An alternative is to inject lean gas or nitrogen along with CO2 to achieve better recoveries at optimum costs and suitable pressure. Slim tube simulation using a commercial simulator is utilized to measure the minimum miscibility pressure (MMP) of an injected gas mixture. The mixture contains CO2/N2 or CO2/lean gas. Using different concentrations in the injected mixture, an effect on the recovery factor is studied. The first 30 runs have 100% concentration of each individual gases i.e. N2, CO2 and lean gas. Based on these runs, the simulation model is validated using the co-relations present in the literature. Gas mixtures of CO2/N2 and CO2/lean gas were then simulated using the compositional model to test the effect on MMP by varying the concentration of each gas in the mixture. By changing the volumes of the gas in the injected mixture, we can find the optimum concentration of each component in the mixture in terms of MMP. From the results obtained through simulation, it can be deduced that higher percentages of CO2 in the mixture would result in reduced minimum miscibility pressure. The addition of a secondary slug to the injected CO2 fluid increases the pressure required to achieve miscibility. Of N2 and Lean gas, Lean gas provided better results as it showed low miscibility pressure responses compared to the same amount of N2 gas. For example, for a case, 50% CO2 and 50 %N2 or lean gas mixture, the MMP for the lean gas mixture is 3500 Psi, while for N2 mixture it was 4667 Psi. However, lean gas is expensive as compared to N2 and N2 is easily available. N2, if used in optimum concentration along with CO2 can produce greater recoveries keeping the process cost-effective while satisfying other constraints. CO2 is widely used for miscible injection, but it presents problems like costs, corrosion, and asphaltene deposition etc. The study can give an idea of the success of carrying out EOR through gas flooding by using N2 and CO2 to enhance recovery at low cost. N2 is easily available from air and it is cheap.
{"title":"A Simulation Study of the Effect of Injecting Carbon Dioxide with Nitrogen or Lean Gas on the Minimum Miscibility Pressure","authors":"Ahmed Gh Mansour, T. Gamadi, Hussain R Saoyleh","doi":"10.2118/200984-ms","DOIUrl":"https://doi.org/10.2118/200984-ms","url":null,"abstract":"\u0000 The objective of this study is to determine the effects of the concentration of injected gases on recovery factors. CO2 has been used for flooding because it requires low injection pressures to achieve miscibility. However, the availability of CO2 is an issue. CO2 required for the process is not sufficient for the reservoir under consideration. Moreover, its benefit-cost ratio (b/c) represents another issue; higher volumes of CO2 increases the economic expenditures. An alternative is to inject lean gas or nitrogen along with CO2 to achieve better recoveries at optimum costs and suitable pressure.\u0000 Slim tube simulation using a commercial simulator is utilized to measure the minimum miscibility pressure (MMP) of an injected gas mixture. The mixture contains CO2/N2 or CO2/lean gas. Using different concentrations in the injected mixture, an effect on the recovery factor is studied. The first 30 runs have 100% concentration of each individual gases i.e. N2, CO2 and lean gas. Based on these runs, the simulation model is validated using the co-relations present in the literature. Gas mixtures of CO2/N2 and CO2/lean gas were then simulated using the compositional model to test the effect on MMP by varying the concentration of each gas in the mixture. By changing the volumes of the gas in the injected mixture, we can find the optimum concentration of each component in the mixture in terms of MMP.\u0000 From the results obtained through simulation, it can be deduced that higher percentages of CO2 in the mixture would result in reduced minimum miscibility pressure. The addition of a secondary slug to the injected CO2 fluid increases the pressure required to achieve miscibility. Of N2 and Lean gas, Lean gas provided better results as it showed low miscibility pressure responses compared to the same amount of N2 gas. For example, for a case, 50% CO2 and 50 %N2 or lean gas mixture, the MMP for the lean gas mixture is 3500 Psi, while for N2 mixture it was 4667 Psi. However, lean gas is expensive as compared to N2 and N2 is easily available. N2, if used in optimum concentration along with CO2 can produce greater recoveries keeping the process cost-effective while satisfying other constraints. CO2 is widely used for miscible injection, but it presents problems like costs, corrosion, and asphaltene deposition etc. The study can give an idea of the success of carrying out EOR through gas flooding by using N2 and CO2 to enhance recovery at low cost. N2 is easily available from air and it is cheap.","PeriodicalId":11075,"journal":{"name":"Day 1 Mon, June 28, 2021","volume":"33 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-06-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90560412","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}
Fiber-optic sensing (FOS) technology is gradually becoming a pervasive tool in the monitoring and surveillance toolkit for reservoir engineers. Traditionally, sensing with fiber optic technology in the form of distributed temperature sensing (DTS) or distributed acoustic sensing (DAS), and most recently distributed strain sensing (DSS), distributed flow sensing (DFS) and distributed pressure sensing (DPS) were done with the fiber being permanently clamped either behind the casing or production tubing. Distributed chemical sensing (DCS) is still in the development phase. The emergence of the composite carbon-rod (CCR) system that can be easily deployed in and out of a well, similar to wireline logging, has opened up a vista of possibilities to obtain many FOS measurements in any well without prior fiber-optic installation. Currently, combinations of distributed FOS data are being used for injection management, well integrity monitoring, well stimulation and production performance optimization, thermal recovery management, etc. Is it possible to integrate many of the distributed FOS measurements in the CCR or a hybrid combination with wireline to obtain multiple measurements with one FOS cable? Each one of FOS has its own use to get certain data, or combination of FOS can be used to make a further interpretation. This paper reviews the state of the art of the FOS technology and the gamut of current different applications of FOS data in the oil and gas (upstream) industry. We present some results of traditional FOS measurements for well integrity monitoring, assessing production and injection flow profile, cross flow behind casing, etc. We propose some nontraditional applications of the technology and suggest a few ways through. Which the technology can be deployed for obtaining some key reservoir description and dynamics data for reservoir performance optimization.
{"title":"Expanding the Envelope of Fiber-Optic Sensing for Reservoir Description and Dynamics","authors":"Abdulaziz Alqasim, Sharidah Alabduh, Muhannad Alabdullateef, Mutaz Alsubhi","doi":"10.2118/200888-ms","DOIUrl":"https://doi.org/10.2118/200888-ms","url":null,"abstract":"\u0000 Fiber-optic sensing (FOS) technology is gradually becoming a pervasive tool in the monitoring and surveillance toolkit for reservoir engineers. Traditionally, sensing with fiber optic technology in the form of distributed temperature sensing (DTS) or distributed acoustic sensing (DAS), and most recently distributed strain sensing (DSS), distributed flow sensing (DFS) and distributed pressure sensing (DPS) were done with the fiber being permanently clamped either behind the casing or production tubing. Distributed chemical sensing (DCS) is still in the development phase. The emergence of the composite carbon-rod (CCR) system that can be easily deployed in and out of a well, similar to wireline logging, has opened up a vista of possibilities to obtain many FOS measurements in any well without prior fiber-optic installation.\u0000 Currently, combinations of distributed FOS data are being used for injection management, well integrity monitoring, well stimulation and production performance optimization, thermal recovery management, etc. Is it possible to integrate many of the distributed FOS measurements in the CCR or a hybrid combination with wireline to obtain multiple measurements with one FOS cable? Each one of FOS has its own use to get certain data, or combination of FOS can be used to make a further interpretation.\u0000 This paper reviews the state of the art of the FOS technology and the gamut of current different applications of FOS data in the oil and gas (upstream) industry. We present some results of traditional FOS measurements for well integrity monitoring, assessing production and injection flow profile, cross flow behind casing, etc.\u0000 We propose some nontraditional applications of the technology and suggest a few ways through. Which the technology can be deployed for obtaining some key reservoir description and dynamics data for reservoir performance optimization.","PeriodicalId":11075,"journal":{"name":"Day 1 Mon, June 28, 2021","volume":"24 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-06-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91005480","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}
M. Rudder, Derval Barzey, Amy Ramlal, Shaleni Gopie, Ronald Alfred
The Ministry of Energy and Energy Industries assessed the National Oil Spill Contingency Plan of Trinidad and Tobago (NOSCP, 2013) for its effectiveness as a preparedness and response mechanism. Using the Readiness Evaluation Tool for Oil Spills (RETOS™), the NOSCP attained a score of 42% in the Level A Assessment. Gaps were identified in areas including National Legislation, Risk Management, Logistics, Training and Exercises, and Operational Response. Further, lessons learned from past spills were examined to highlight deficiencies in oil spill response (OSR) planning and readiness. Proposed updates to the NOSCP include: designation of appropriate Lead Agency depending on the nature of the spill scenario, mandating Oil Spill Risk Assessments, and the use of SIMA as a decision-making tool for oil spill response; development of comprehensive guidelines for Dispersant Use, Oiled Wildlife Response and Oil Spill Waste Management. The NOSCP is being re-designed to facilitate a national response management system that meets best management practice for oil spill contingency planning. This will enable the efficient and effective deployment of the appropriate resources (equipment, expertise and oversight) to mitigate impacts to human health and the environment, and minimize production down time and socio-economic costs.
{"title":"An Assessment of and Proposed Updates to the National Oil Spill Contingency Plan of Trinidad and Tobago Based on the Readiness Evaluation Tool for Oil Spills","authors":"M. Rudder, Derval Barzey, Amy Ramlal, Shaleni Gopie, Ronald Alfred","doi":"10.2118/200965-ms","DOIUrl":"https://doi.org/10.2118/200965-ms","url":null,"abstract":"\u0000 The Ministry of Energy and Energy Industries assessed the National Oil Spill Contingency Plan of Trinidad and Tobago (NOSCP, 2013) for its effectiveness as a preparedness and response mechanism. Using the Readiness Evaluation Tool for Oil Spills (RETOS™), the NOSCP attained a score of 42% in the Level A Assessment. Gaps were identified in areas including National Legislation, Risk Management, Logistics, Training and Exercises, and Operational Response. Further, lessons learned from past spills were examined to highlight deficiencies in oil spill response (OSR) planning and readiness. Proposed updates to the NOSCP include: designation of appropriate Lead Agency depending on the nature of the spill scenario, mandating Oil Spill Risk Assessments, and the use of SIMA as a decision-making tool for oil spill response; development of comprehensive guidelines for Dispersant Use, Oiled Wildlife Response and Oil Spill Waste Management. The NOSCP is being re-designed to facilitate a national response management system that meets best management practice for oil spill contingency planning. This will enable the efficient and effective deployment of the appropriate resources (equipment, expertise and oversight) to mitigate impacts to human health and the environment, and minimize production down time and socio-economic costs.","PeriodicalId":11075,"journal":{"name":"Day 1 Mon, June 28, 2021","volume":"16 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-06-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90842483","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}
Tushara Maharaj, M. Rudder, V. Singh, W. Rajkumar, Vidjaya Ramkhalawan
A Produced Water (PW) Management framework is presented, forming part of an Upstream Effluent Management (UEM) Policy. It addresses the minimization and ultimate elimination of treated and untreated PW discharge by utilization of an integrated management approach to ensure Zero Harmful Discharge (ZHD) to the environment. This approach targeted legislative reform, sustainable PW management practices, monitoring and evaluation, research and development and sustainable production patterns. A Cabinet-appointed Upstream Effluent Management Committee was established for evaluating the status of the upstream, oil and gas, effluent management practices including that of PW and providing recommendations on the way forward. This included determining the challenges in meeting relevant environmental standards; evaluating Best Available Technology (BAT) or Best Practicable Environmental Options (BPEO) for local use and benchmarking local standards against international best practices. Ultimately, a UEM Policy, inclusive of a PW Management Policy, and a revised Water Pollution Rules 2019 (WPR) were developed, submitted and approved by the Cabinet of Trinidad and Tobago. Emerging from data evaluation and committee consultations, it was found that parameters from PW streams, such as Chemical Oxygen Demand (COD), Phenols and Ammoniacal Nitrogen were regularly out of compliance with local permissible limits. Additionally, it was noted that PW management was known to be generally costly, in terms of monitoring, treatment and disposal operations. As such the UEM Committee recommended that measures be taken to facilitate better PW management including, amendments to the Water Pollution Rules 2001 (as amended) and the TTS 547:1998, Specification for the Effluent From Industrial Processes Discharged into the Environment; to focus more on toxic components such as BTEX (Benzene, Toluene, Ethylbenzene and Xylene) and PAH (Polycyclic Aromatic Hydrocarbons); improvement of the chemical evaluation and approval process by the Ministry of Energy and Energy Industries (MEEI) to include a pre-screening step; and the establishment of National Ambient Water Quality Standards, which have been included in the revised WPR. The WPR also encourages re-use as a beneficial discount through the revised annual permit calculation. In addition, Environmental Risk Assessments (ERA) are to be utilized to evaluate the physical, biological and socio-economic environmental standing of the marine environment of Trinidad and Tobago, so as to comprehensively deduce the full impacts of effluent discharge. Trinidad and Tobago has been in oil and gas operations for over 100 years and this integrated management approach for PW introduces a set of novel strategies and tools, geared towards moving in a more environmentally sustainable direction. The approach envisages the use of a more industry-specific regulation that focuses on the toxic components. Furthermore, this method acknowledges that "not-one-si
{"title":"A New Produced Water Management Policy for the Energy Sector of Trinidad and Tobago","authors":"Tushara Maharaj, M. Rudder, V. Singh, W. Rajkumar, Vidjaya Ramkhalawan","doi":"10.2118/200926-ms","DOIUrl":"https://doi.org/10.2118/200926-ms","url":null,"abstract":"A Produced Water (PW) Management framework is presented, forming part of an Upstream Effluent Management (UEM) Policy. It addresses the minimization and ultimate elimination of treated and untreated PW discharge by utilization of an integrated management approach to ensure Zero Harmful Discharge (ZHD) to the environment. This approach targeted legislative reform, sustainable PW management practices, monitoring and evaluation, research and development and sustainable production patterns. A Cabinet-appointed Upstream Effluent Management Committee was established for evaluating the status of the upstream, oil and gas, effluent management practices including that of PW and providing recommendations on the way forward. This included determining the challenges in meeting relevant environmental standards; evaluating Best Available Technology (BAT) or Best Practicable Environmental Options (BPEO) for local use and benchmarking local standards against international best practices. Ultimately, a UEM Policy, inclusive of a PW Management Policy, and a revised Water Pollution Rules 2019 (WPR) were developed, submitted and approved by the Cabinet of Trinidad and Tobago. Emerging from data evaluation and committee consultations, it was found that parameters from PW streams, such as Chemical Oxygen Demand (COD), Phenols and Ammoniacal Nitrogen were regularly out of compliance with local permissible limits. Additionally, it was noted that PW management was known to be generally costly, in terms of monitoring, treatment and disposal operations. As such the UEM Committee recommended that measures be taken to facilitate better PW management including, amendments to the Water Pollution Rules 2001 (as amended) and the TTS 547:1998, Specification for the Effluent From Industrial Processes Discharged into the Environment; to focus more on toxic components such as BTEX (Benzene, Toluene, Ethylbenzene and Xylene) and PAH (Polycyclic Aromatic Hydrocarbons); improvement of the chemical evaluation and approval process by the Ministry of Energy and Energy Industries (MEEI) to include a pre-screening step; and the establishment of National Ambient Water Quality Standards, which have been included in the revised WPR. The WPR also encourages re-use as a beneficial discount through the revised annual permit calculation. In addition, Environmental Risk Assessments (ERA) are to be utilized to evaluate the physical, biological and socio-economic environmental standing of the marine environment of Trinidad and Tobago, so as to comprehensively deduce the full impacts of effluent discharge. Trinidad and Tobago has been in oil and gas operations for over 100 years and this integrated management approach for PW introduces a set of novel strategies and tools, geared towards moving in a more environmentally sustainable direction. The approach envisages the use of a more industry-specific regulation that focuses on the toxic components. Furthermore, this method acknowledges that \"not-one-si","PeriodicalId":11075,"journal":{"name":"Day 1 Mon, June 28, 2021","volume":"9 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-06-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88684705","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}
Despite long production histories, operators of mature oilfields sometimes struggle to account for reservoir compartmentalization. Geological-led workflows do not adequately honor legacy production data since inherent bias is introduced into the process of allocating production by interpreted flow units. This paper details the application of machine learning methods to identify possible reservoir compartments based on legacy production data recorded from individual well completions. We propose an experimental data-driven workflow to rapidly generate multiple scenarios of connected volumes in the subsurface. The workflow is premised upon the logic that well completions draining the same connected reservoir space can exhibit similar production characteristics (rate declines, GOR trends and pressures). We show how the specific challenges of digitized legacy data are solved using outlier detection for error checking and Kalman smoothing imputation for missing data in the structural time series model. Finally, we compare the subsurface grouping of completions obtained by applying unsupervised pattern recognition with Hierarchal clustering. Application of this workflow results in multiple possible scenarios for defining reservoir compartments based on production data trends only. The method is powerful in that, it provides interpretations that are independent of subsurface scenarios generated by more traditional workflows. We demonstrate the potential to integrate interpretations generated from more conventional workflows to increase the robustness of the overall subsurface model. We have leveraged the power of machine learning methods to classify more than forty (40) well completions into discrete reservoir compartments using production characteristics only. This effort would be extremely difficult, or otherwise unreliable given the inherent limitations of human spatial, temporal, and cognitive abilities.
{"title":"Using Machine Learning Methods to Identify Reservoir Compartmentalization in Mature Oilfields from Legacy Production Data","authors":"Kamlesh Ramcharitar, A. Ramdhanie","doi":"10.2118/200979-ms","DOIUrl":"https://doi.org/10.2118/200979-ms","url":null,"abstract":"\u0000 Despite long production histories, operators of mature oilfields sometimes struggle to account for reservoir compartmentalization. Geological-led workflows do not adequately honor legacy production data since inherent bias is introduced into the process of allocating production by interpreted flow units. This paper details the application of machine learning methods to identify possible reservoir compartments based on legacy production data recorded from individual well completions. We propose an experimental data-driven workflow to rapidly generate multiple scenarios of connected volumes in the subsurface. The workflow is premised upon the logic that well completions draining the same connected reservoir space can exhibit similar production characteristics (rate declines, GOR trends and pressures). We show how the specific challenges of digitized legacy data are solved using outlier detection for error checking and Kalman smoothing imputation for missing data in the structural time series model. Finally, we compare the subsurface grouping of completions obtained by applying unsupervised pattern recognition with Hierarchal clustering. Application of this workflow results in multiple possible scenarios for defining reservoir compartments based on production data trends only. The method is powerful in that, it provides interpretations that are independent of subsurface scenarios generated by more traditional workflows. We demonstrate the potential to integrate interpretations generated from more conventional workflows to increase the robustness of the overall subsurface model. We have leveraged the power of machine learning methods to classify more than forty (40) well completions into discrete reservoir compartments using production characteristics only. This effort would be extremely difficult, or otherwise unreliable given the inherent limitations of human spatial, temporal, and cognitive abilities.","PeriodicalId":11075,"journal":{"name":"Day 1 Mon, June 28, 2021","volume":"76 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-06-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79961332","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}
Jhon Manchola, Dianys Ballestero, J. Villasmil, G. Nava
Horizontal drilling is part of the development plan for Rubiales field in Colombia, operated by the National Oil Company. By this, different geosteering technologies have been applied during the infill drilling campaign and, it has varied over time. The multi-boundary detection tool has successful results in terms of net sand percent increase, precise location, and cost decrease, related to drilling operations. Some of the challenges for well placement are thin thickness channels with no lateral continuity (deposition environment), oil-water contact closeness, poor correlation with cutting samples, between others. The technology minimizes risks with the real-time resistivity inversion. This process generates a visual representation of the resistivity profile around the wellbore, including geometric definition, dip, and thickness estimation. These inversion results are used to recommend trajectory adjustments while drilling. The complete geosteering experience in Rubiales with the new technology (more than one hundred sixty producing wells so far) has been classified into three main types of wells: lateral sections drilled in continuous sand intervals; lateral variation of resistivity; and wells with a change of prospective zone by channel discontinuity. The implementation success is described by the net sand percentage increasing, around 16% compared with other technologies. The average drilling length was improved by 20% and the number of geological sidetracks concerning previous stages of exploitation reduced by more than 90%, without affecting the drilling rate. These factors, including the update of the sedimentological models, inclusion of new reserves, and the production increase, are part of the optimization plan.
{"title":"Geosteering Optimization Using the Multi-Boundary Detection Technology in Rubiales' Field, Colombia","authors":"Jhon Manchola, Dianys Ballestero, J. Villasmil, G. Nava","doi":"10.2118/200955-ms","DOIUrl":"https://doi.org/10.2118/200955-ms","url":null,"abstract":"\u0000 Horizontal drilling is part of the development plan for Rubiales field in Colombia, operated by the National Oil Company. By this, different geosteering technologies have been applied during the infill drilling campaign and, it has varied over time. The multi-boundary detection tool has successful results in terms of net sand percent increase, precise location, and cost decrease, related to drilling operations.\u0000 Some of the challenges for well placement are thin thickness channels with no lateral continuity (deposition environment), oil-water contact closeness, poor correlation with cutting samples, between others. The technology minimizes risks with the real-time resistivity inversion. This process generates a visual representation of the resistivity profile around the wellbore, including geometric definition, dip, and thickness estimation.\u0000 These inversion results are used to recommend trajectory adjustments while drilling. The complete geosteering experience in Rubiales with the new technology (more than one hundred sixty producing wells so far) has been classified into three main types of wells: lateral sections drilled in continuous sand intervals; lateral variation of resistivity; and wells with a change of prospective zone by channel discontinuity.\u0000 The implementation success is described by the net sand percentage increasing, around 16% compared with other technologies. The average drilling length was improved by 20% and the number of geological sidetracks concerning previous stages of exploitation reduced by more than 90%, without affecting the drilling rate. These factors, including the update of the sedimentological models, inclusion of new reserves, and the production increase, are part of the optimization plan.","PeriodicalId":11075,"journal":{"name":"Day 1 Mon, June 28, 2021","volume":"73 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-06-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83276798","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The unconventional resources development has grown tremendously as a result of the advancement in horizontal drilling technology coupled with hydraulic fracturing. However, as more wells are drilled and fractured close to each other, frac hits have become a major challenge in these wells. The aim of this work is to investigate the effect of nitrogen injection flow rate and pressure on unloading frac hits gas wells in transient multiphase flow. A numerical simulation model was created using a transient multiphase flow simulator to mimic the unloading process of frac hits by injecting nitrogen from the surface through the annulus section of the well. Many simulation cases were created and analyzed to comprehend the effect of the nitrogen injection rate and pressure on the unloading of frac hits. The model mimicked real field data from currently active well in the Eagle Ford Shale. The results showed that as the nitrogen injection pressure increases, the nitrogen volume and the time to unload the frac hits decrease. On the other hand, increasing the injection rate of nitrogen will increase the nitrogen volume required to unload the frac hits. In addition, the time to unload frac hits will be decreased as the nitrogen injection rate increases. These results indicate that the time required to unload frac hits will be minimized if higher flow rates of nitrogen were utilized. Nonetheless, the volume of nitrogen required to unload the frac hits will be maximized. An important observation to highlight is that the operators can save money by reducing the time for injecting nitrogen. This observation was verified when increasing the injection pressure in the frac hit well in the Eagle Ford Shale, the time of injection was reduced 20%. This study presents the effects of nitrogen injection flow rate and injection pressure for unloading frac hits in gas wells. Due to the lack of published studies about this topic, this work can serve as a practical guideline for unloading frac hits in gas wells.
{"title":"Unloading Frac Hits in Gas Wells: How Does the Nitrogen Injection Rate and Pressure Affect the Unloading Process?","authors":"M. Cedeno","doi":"10.2118/200962-ms","DOIUrl":"https://doi.org/10.2118/200962-ms","url":null,"abstract":"\u0000 The unconventional resources development has grown tremendously as a result of the advancement in horizontal drilling technology coupled with hydraulic fracturing. However, as more wells are drilled and fractured close to each other, frac hits have become a major challenge in these wells. The aim of this work is to investigate the effect of nitrogen injection flow rate and pressure on unloading frac hits gas wells in transient multiphase flow. A numerical simulation model was created using a transient multiphase flow simulator to mimic the unloading process of frac hits by injecting nitrogen from the surface through the annulus section of the well. Many simulation cases were created and analyzed to comprehend the effect of the nitrogen injection rate and pressure on the unloading of frac hits. The model mimicked real field data from currently active well in the Eagle Ford Shale. The results showed that as the nitrogen injection pressure increases, the nitrogen volume and the time to unload the frac hits decrease. On the other hand, increasing the injection rate of nitrogen will increase the nitrogen volume required to unload the frac hits. In addition, the time to unload frac hits will be decreased as the nitrogen injection rate increases. These results indicate that the time required to unload frac hits will be minimized if higher flow rates of nitrogen were utilized. Nonetheless, the volume of nitrogen required to unload the frac hits will be maximized. An important observation to highlight is that the operators can save money by reducing the time for injecting nitrogen. This observation was verified when increasing the injection pressure in the frac hit well in the Eagle Ford Shale, the time of injection was reduced 20%. This study presents the effects of nitrogen injection flow rate and injection pressure for unloading frac hits in gas wells. Due to the lack of published studies about this topic, this work can serve as a practical guideline for unloading frac hits in gas wells.","PeriodicalId":11075,"journal":{"name":"Day 1 Mon, June 28, 2021","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-06-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86414837","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}
Downhole Annular Barrier (DAB) systems employed in intervention can correct integrity and conformance control issues during well lifecycle, extending the productive term in a safe and costeffective manner. These emergent wireline technologies come with unique challenges for logistics, quality control, and engineering, but can also provide solutions to difficult problems, with high value to spend ratio, in the non-rig intervention sector. The paper will review one such successful intervention, completed offshore Trinidad W.I., in a gas well presenting long term Sustained Casing Pressure (SCP). The desired end state of the well was A-Annulus at 0 psi SCP, which would return the well to a safe state and permit a planned infrastructure project to move ahead. Operational objective was isolation of the casing annulus pressure from the source by injecting epoxy into the annular space at depth, forming a 360-degree pressure barrier. The project can be broken down into three main sections. The paper and presentation will address each section with its specific challenges, learnings, and outcomes: Onshore Epoxy and Tool Preparation Each Downhole Annular Barrier job employs a custom recipe epoxy suited to the planned logistics timing and expected bottomhole conditions. Quality control of the epoxy recipe and mixing process as well as temperature control of the batch after mixing is key to the sealing properties of the final epoxy plug. • An Epoxy Lab and Mixing Station was dismantled, air freighted, and reconstituted in Trinidad near to the field operations port. Special insulated offshore CCU were built to transport and contain filled epoxy canisters while maintaining low temperature requirements (near to 0 deg C for up to 30 days). • Build and System Integration Testing (SIT) of the downhole system (anchoring, stroking, hydraulic testing, perforation, and injection) with the electric line system (conveyance, telemetry, power). Offshore Job Execution The DAB system employed is designed to complete multiple operations in a single trip into the well, including perforating and high-pressure epoxy injection, with precise position control and monitoring. This is made possible with the multi-function modular tool. The operation was dynamic by design and contingencies were implemented based on the well response. Multiple epoxy annular plugs were placed into the A Annulus at depth, with high pressure injection. Well Response and Assessment Utilizing advanced annular surface monitoring technology and PvT analysis, precise assessment of the annulus pressure build was recorded throughout the operation. Once the project criteria were met, the operation was successfully concluded.
{"title":"Downhole Annular Barrier Solution for Sustained Casing Pressure - Trinidad Case Study","authors":"J. Olsen, Wayne Hosein, T. Ringe, J. Friedli","doi":"10.2118/200976-ms","DOIUrl":"https://doi.org/10.2118/200976-ms","url":null,"abstract":"\u0000 \u0000 \u0000 Downhole Annular Barrier (DAB) systems employed in intervention can correct integrity and conformance control issues during well lifecycle, extending the productive term in a safe and costeffective manner. These emergent wireline technologies come with unique challenges for logistics, quality control, and engineering, but can also provide solutions to difficult problems, with high value to spend ratio, in the non-rig intervention sector. The paper will review one such successful intervention, completed offshore Trinidad W.I., in a gas well presenting long term Sustained Casing Pressure (SCP). The desired end state of the well was A-Annulus at 0 psi SCP, which would return the well to a safe state and permit a planned infrastructure project to move ahead.\u0000 \u0000 \u0000 \u0000 Operational objective was isolation of the casing annulus pressure from the source by injecting epoxy into the annular space at depth, forming a 360-degree pressure barrier. The project can be broken down into three main sections. The paper and presentation will address each section with its specific challenges, learnings, and outcomes: Onshore Epoxy and Tool Preparation Each Downhole Annular Barrier job employs a custom recipe epoxy suited to the planned logistics timing and expected bottomhole conditions. Quality control of the epoxy recipe and mixing process as well as temperature control of the batch after mixing is key to the sealing properties of the final epoxy plug. • An Epoxy Lab and Mixing Station was dismantled, air freighted, and reconstituted in Trinidad near to the field operations port. Special insulated offshore CCU were built to transport and contain filled epoxy canisters while maintaining low temperature requirements (near to 0 deg C for up to 30 days). • Build and System Integration Testing (SIT) of the downhole system (anchoring, stroking, hydraulic testing, perforation, and injection) with the electric line system (conveyance, telemetry, power). Offshore Job Execution The DAB system employed is designed to complete multiple operations in a single trip into the well, including perforating and high-pressure epoxy injection, with precise position control and monitoring. This is made possible with the multi-function modular tool. The operation was dynamic by design and contingencies were implemented based on the well response. Multiple epoxy annular plugs were placed into the A Annulus at depth, with high pressure injection.\u0000 \u0000 \u0000 \u0000 Well Response and Assessment Utilizing advanced annular surface monitoring technology and PvT analysis, precise assessment of the annulus pressure build was recorded throughout the operation. Once the project criteria were met, the operation was successfully concluded.\u0000","PeriodicalId":11075,"journal":{"name":"Day 1 Mon, June 28, 2021","volume":"56 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-06-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81117220","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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