A mature field in central Sumatra, Indonesia, has been producing heavy oil for decades, and it has shown decreased production. The ESP, as the main lifting method, needs to be replaced more frequently due to mechanical damage by congealed oil. Many wells in that field were forced to be deactivated because of congealed oil plugging along the wellbore. The conventional method to tackle this issue is to pump hot water. This practice however did not give sustainable results after the treatment. The remedy of coiled tubing (CT) well cleanout with a wash nozzle has also not been considered successful because the congealed oil is too hard to penetrate. Furthermore, using mechanical devices such as CT milling tools has not been effective because the deposits stick to the mill. Considering the low-production-rate wells, high-rate fluid injection was proposed to meet cost criteria. Although the well was able to produce afterwards, production kept declining due to the production of congealed oil from the formation. A combination of high-pressure jetting tool and organic dissolver fluid was proposed as an alternative method to break the congealed oil. The method uses kinetic energy from the jetting tool to shatter the solidified oil by pumping brine. Afterwards, a fluid mixture composed of organic dissolver and additive is pumped to dissolve the remaining congealed oil. Following the treatments, the pilot well showed significant improvements. The treatment successfully revived well production after the well had stopped producing for more than 3 months. The flowback tank was filled with as much as 10-in.-deep broken oil residue. Such a solid removal has not been accomplished with any other technique. The well has been producing for more than 10 months without any pump issues, and production continues to increase. Another three well candidates with low productivity issues were treated with the same technique. All the wells delivered good results. If, in the future, the congealed oil accumulates again, high-pressure jetting and organic dissolver will be the first method used for remediation. All the wells treated with this approach have been producing significantly more than those treated using any other technique, well beyond the target set by the operator. This study discusses the benefits of combining the techniques of high-pressure jetting, organic dissolver, and high-rate injection to overcome severe congealed oil problems that impair well production. Details the approach are provided, and its effectiveness is compared to other former attempts to solve the congealed oil problem. This case also illustrates the importance of maintaining well interventions to improve production while meeting the cost criteria in this challenging time in the oil and gas industry.
{"title":"Blast from the Past, Solving Severe Congealed Oil Problems by Combining Existing Solutions","authors":"Tirza Hahijary, A. Kusuma, J. Jenie","doi":"10.2118/205730-ms","DOIUrl":"https://doi.org/10.2118/205730-ms","url":null,"abstract":"\u0000 A mature field in central Sumatra, Indonesia, has been producing heavy oil for decades, and it has shown decreased production. The ESP, as the main lifting method, needs to be replaced more frequently due to mechanical damage by congealed oil. Many wells in that field were forced to be deactivated because of congealed oil plugging along the wellbore. The conventional method to tackle this issue is to pump hot water. This practice however did not give sustainable results after the treatment. The remedy of coiled tubing (CT) well cleanout with a wash nozzle has also not been considered successful because the congealed oil is too hard to penetrate. Furthermore, using mechanical devices such as CT milling tools has not been effective because the deposits stick to the mill. Considering the low-production-rate wells, high-rate fluid injection was proposed to meet cost criteria. Although the well was able to produce afterwards, production kept declining due to the production of congealed oil from the formation. A combination of high-pressure jetting tool and organic dissolver fluid was proposed as an alternative method to break the congealed oil. The method uses kinetic energy from the jetting tool to shatter the solidified oil by pumping brine. Afterwards, a fluid mixture composed of organic dissolver and additive is pumped to dissolve the remaining congealed oil.\u0000 Following the treatments, the pilot well showed significant improvements. The treatment successfully revived well production after the well had stopped producing for more than 3 months. The flowback tank was filled with as much as 10-in.-deep broken oil residue. Such a solid removal has not been accomplished with any other technique. The well has been producing for more than 10 months without any pump issues, and production continues to increase. Another three well candidates with low productivity issues were treated with the same technique. All the wells delivered good results. If, in the future, the congealed oil accumulates again, high-pressure jetting and organic dissolver will be the first method used for remediation. All the wells treated with this approach have been producing significantly more than those treated using any other technique, well beyond the target set by the operator.\u0000 This study discusses the benefits of combining the techniques of high-pressure jetting, organic dissolver, and high-rate injection to overcome severe congealed oil problems that impair well production. Details the approach are provided, and its effectiveness is compared to other former attempts to solve the congealed oil problem. This case also illustrates the importance of maintaining well interventions to improve production while meeting the cost criteria in this challenging time in the oil and gas industry.","PeriodicalId":11017,"journal":{"name":"Day 2 Wed, October 13, 2021","volume":"307 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74203586","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 oil and gas industry has been developing various technologies to increase the productivity and recovery of hydrocarbons from conventional and unconventional reservoirs. Reservoir stimulation is an essential operation used to enhance production in many fields around the world. Hydraulic fracturing and acid treatments are the main stimulation methods. Reservoir tunneling concepts are used to drill branched channels in the formation from the main wellbore. With thousands of tunnels drilled to date, it is a viable technique that can improve the recovery of selected reservoirs. This paper reviews the recent developments in reservoir tunneling technologies and their current applications. These tunneling methods can be categorized mainly into water jetting, abrasive jetting, reactive jetting (acid), and needle and mechanical tunneling (radial drilling). The paper includes reviewing and analyzing these techniques based on documented literature results that include simulation studies, lab and yard experiments, field implementation, candidate selection, operational requirements, technology enhancements, advantages, limitations, and challenges of each technique. The paper provides a comprehensive summary of different tunneling techniques focusing on the operational practices, tunneling mechanisms, tunneling depth, and recent advancements available in the market. The most effective applications of the tunneling techniques are in stimulating low permeability, depleted and thin reservoirs, layers close to water zones, and bypassing near wellbore formation damage. The efficiency of creating tunnels is affected by many factors such as reservoir properties, nozzle, and fluid types, etc. The tunnel shape and trajectory are affected by reservoir geological properties. The combination of the tunneling with other stimulation techniques can result in more effective treatments, which enhance the methods of current stimulation. Reservoir tunneling technologies can pave the way to improve hydrocarbon recovery and enable access to unstimulated formations.
{"title":"Enhancing Reservoir Stimulation and Productivity Through Reservoir Tunneling Technologies: A Review on Recent Development","authors":"Eyad A. Alali, M. Bataweel","doi":"10.2118/205552-ms","DOIUrl":"https://doi.org/10.2118/205552-ms","url":null,"abstract":"\u0000 The oil and gas industry has been developing various technologies to increase the productivity and recovery of hydrocarbons from conventional and unconventional reservoirs. Reservoir stimulation is an essential operation used to enhance production in many fields around the world. Hydraulic fracturing and acid treatments are the main stimulation methods. Reservoir tunneling concepts are used to drill branched channels in the formation from the main wellbore. With thousands of tunnels drilled to date, it is a viable technique that can improve the recovery of selected reservoirs.\u0000 This paper reviews the recent developments in reservoir tunneling technologies and their current applications. These tunneling methods can be categorized mainly into water jetting, abrasive jetting, reactive jetting (acid), and needle and mechanical tunneling (radial drilling). The paper includes reviewing and analyzing these techniques based on documented literature results that include simulation studies, lab and yard experiments, field implementation, candidate selection, operational requirements, technology enhancements, advantages, limitations, and challenges of each technique.\u0000 The paper provides a comprehensive summary of different tunneling techniques focusing on the operational practices, tunneling mechanisms, tunneling depth, and recent advancements available in the market. The most effective applications of the tunneling techniques are in stimulating low permeability, depleted and thin reservoirs, layers close to water zones, and bypassing near wellbore formation damage. The efficiency of creating tunnels is affected by many factors such as reservoir properties, nozzle, and fluid types, etc. The tunnel shape and trajectory are affected by reservoir geological properties. The combination of the tunneling with other stimulation techniques can result in more effective treatments, which enhance the methods of current stimulation. Reservoir tunneling technologies can pave the way to improve hydrocarbon recovery and enable access to unstimulated formations.","PeriodicalId":11017,"journal":{"name":"Day 2 Wed, October 13, 2021","volume":"647 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76832096","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}
Edward Jason Wheatley, Gladwin Correia, Samhar Adi, N. Molero, Cremilton Silva, Irma Irais Galvan, G. Mcclelland, A. French, T. Bragaw
Maximizing reservoir contact through extended-reach and mega-reach wells has become a prevalent field development strategy for major offshore operators in the Middle East. This is especially true for the giant oilfield "A", where drilling targets go beyond 40,000 ft. measured depth (MD), with MD/TVD ratios in excess of 4.5:1. Such challenging horizons call for a detailed re-evaluation of well interventions. In 2019, the well surveillance program in the field A required intervention in a mega-reach well with a MD over 35,500 ft. and 4.5:1 MD/TVD ratio. This reach was unthinkable only a few years ago but has been made possible thanks to several recent key technological advancements, such as coiled tubing (CT) equipped with optical fiber and new CT hydraulic tractors, proactive and detailed planning during the drilling phase, the development of highly engineered CT string designs, surface equipment upgrades, and accurate software modeling. The target well is an oil producer with horizontal section beyond 23,000 ft., completed with 6 5/8-in. pre-perforated liner and 23 swellable packers placed across the 8 1/2-in. open hole section. A multiphase production logging tool was selected to assess the production profile along its horizontal drain. With a target depth beyond the reach of conventional wireline, CT equipped with optical fiber emerged as the optimum solution to facilitate reach and overcome the weight and pumping limitations of wired CT. A comprehensive CT reach modeling exercise compared the performance of several 2-in. and 2 3/8-in. CT string designs and identified operational requirements and reach gains from CT hydraulic tractors. As a result, an engineered 2-in. CT tapered string of near 36,700 ft. was developed, capable of being equipped with optical fiber line, while delivering the required flow rate and differential pressure to the CT hydraulic tractor without compromising any operational safety margin. At the time of manufacturing, this was considered the longest CT string ever produced and fitted for downhole telemetry. The operation itself set new records for well interventions in mega-reach wells, with a CT reach above 35,500 ft. MD, including a hydraulic tractoring footage over 15,650 ft. MD with spaced slugs of chemical friction reducer. This case study explains how to develop a safe, robust, and effective solution to mega-reach well challenges using the CT-conveyed optical fiber telemetry technology in one of the deepest wells in the field A, setting a new global record in CT reach. The lessons learned are now the reference for other operators in the Middle East and across the globe for performing interventions in wells that continue to be stretched in its extended reach. It also depicts why telemetry through optical fiber is key to the success of such projects and provides an overview of technology needs for the future of mega-reach well developments.
{"title":"Setting New Milestones for Coiled Tubing Intervention in Mega-Reach Wells","authors":"Edward Jason Wheatley, Gladwin Correia, Samhar Adi, N. Molero, Cremilton Silva, Irma Irais Galvan, G. Mcclelland, A. French, T. Bragaw","doi":"10.2118/205775-ms","DOIUrl":"https://doi.org/10.2118/205775-ms","url":null,"abstract":"\u0000 Maximizing reservoir contact through extended-reach and mega-reach wells has become a prevalent field development strategy for major offshore operators in the Middle East. This is especially true for the giant oilfield \"A\", where drilling targets go beyond 40,000 ft. measured depth (MD), with MD/TVD ratios in excess of 4.5:1. Such challenging horizons call for a detailed re-evaluation of well interventions.\u0000 In 2019, the well surveillance program in the field A required intervention in a mega-reach well with a MD over 35,500 ft. and 4.5:1 MD/TVD ratio. This reach was unthinkable only a few years ago but has been made possible thanks to several recent key technological advancements, such as coiled tubing (CT) equipped with optical fiber and new CT hydraulic tractors, proactive and detailed planning during the drilling phase, the development of highly engineered CT string designs, surface equipment upgrades, and accurate software modeling.\u0000 The target well is an oil producer with horizontal section beyond 23,000 ft., completed with 6 5/8-in. pre-perforated liner and 23 swellable packers placed across the 8 1/2-in. open hole section. A multiphase production logging tool was selected to assess the production profile along its horizontal drain. With a target depth beyond the reach of conventional wireline, CT equipped with optical fiber emerged as the optimum solution to facilitate reach and overcome the weight and pumping limitations of wired CT. A comprehensive CT reach modeling exercise compared the performance of several 2-in. and 2 3/8-in. CT string designs and identified operational requirements and reach gains from CT hydraulic tractors. As a result, an engineered 2-in. CT tapered string of near 36,700 ft. was developed, capable of being equipped with optical fiber line, while delivering the required flow rate and differential pressure to the CT hydraulic tractor without compromising any operational safety margin. At the time of manufacturing, this was considered the longest CT string ever produced and fitted for downhole telemetry. The operation itself set new records for well interventions in mega-reach wells, with a CT reach above 35,500 ft. MD, including a hydraulic tractoring footage over 15,650 ft. MD with spaced slugs of chemical friction reducer.\u0000 This case study explains how to develop a safe, robust, and effective solution to mega-reach well challenges using the CT-conveyed optical fiber telemetry technology in one of the deepest wells in the field A, setting a new global record in CT reach. The lessons learned are now the reference for other operators in the Middle East and across the globe for performing interventions in wells that continue to be stretched in its extended reach. It also depicts why telemetry through optical fiber is key to the success of such projects and provides an overview of technology needs for the future of mega-reach well developments.","PeriodicalId":11017,"journal":{"name":"Day 2 Wed, October 13, 2021","volume":"9 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84006915","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}
K. Umar, Risal Rahman, R. Hidayat, P. S. Kurniawati, R. Marindha, G. D. Dahnil, Gerardus Putra Pancawisna, Danny Hidayat, A. Az-Zariat, F. Utama
The objective of this paper is to present the Mechanical Water Shut-Off (MWSO) strategy for multilayer reservoirs on tubingless well. With 10 open perforated reservoirs and no selectivity option, isolation on water producing reservoir will be the main challenge since production is commingled throughout the lifetime of well. Regular production tests performed through a Multiphase Flowmeter equipment on each offshore platform is a first indicator to monitor the evolution of water production in a well. JM-X well has been experiencing water breakthrough since one week after initial perforation and WGR keep increasing following gas production decline. The strategy was initiated by conducting a bottom hole monitoring survey to identify water sources. Production Logging Tool (PLT) was used to precisely monitor pressure, temperature, water holdup, and fluid rate along the wellbore for further water source and production allocation analysis. Once the water source reservoirs have been identified, MWSO operation was requested. There are several types of MWSO equipment that are commonly used in Offshore Mahakam field each of which has selective economic consideration based on the expected well reserve. Considering operation difficulties and cost, MWSO program was made then will be monitored during the operation time to ensure the operation runs safely and smoothly. MWSO strategy on well JM-X was proven to be able to reduce water production from 900 bpd to only 20 bpd with a significant gain of gas production from 3 MMscfd to 9.2 MMscfd and oil production from 200 bpd to 750 bpd.
{"title":"Successful Water Shut Off Strategy for Multilayer Tubingless Wells at Mahakam Field: JM-X Case Study","authors":"K. Umar, Risal Rahman, R. Hidayat, P. S. Kurniawati, R. Marindha, G. D. Dahnil, Gerardus Putra Pancawisna, Danny Hidayat, A. Az-Zariat, F. Utama","doi":"10.2118/205674-ms","DOIUrl":"https://doi.org/10.2118/205674-ms","url":null,"abstract":"\u0000 The objective of this paper is to present the Mechanical Water Shut-Off (MWSO) strategy for multilayer reservoirs on tubingless well. With 10 open perforated reservoirs and no selectivity option, isolation on water producing reservoir will be the main challenge since production is commingled throughout the lifetime of well. Regular production tests performed through a Multiphase Flowmeter equipment on each offshore platform is a first indicator to monitor the evolution of water production in a well. JM-X well has been experiencing water breakthrough since one week after initial perforation and WGR keep increasing following gas production decline. The strategy was initiated by conducting a bottom hole monitoring survey to identify water sources. Production Logging Tool (PLT) was used to precisely monitor pressure, temperature, water holdup, and fluid rate along the wellbore for further water source and production allocation analysis. Once the water source reservoirs have been identified, MWSO operation was requested. There are several types of MWSO equipment that are commonly used in Offshore Mahakam field each of which has selective economic consideration based on the expected well reserve. Considering operation difficulties and cost, MWSO program was made then will be monitored during the operation time to ensure the operation runs safely and smoothly. MWSO strategy on well JM-X was proven to be able to reduce water production from 900 bpd to only 20 bpd with a significant gain of gas production from 3 MMscfd to 9.2 MMscfd and oil production from 200 bpd to 750 bpd.","PeriodicalId":11017,"journal":{"name":"Day 2 Wed, October 13, 2021","volume":"2 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78421259","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}
Hendro Vico, Riezal Arieffiandhany, I. Sanjaya, Lambertus Francisco, Yasinta Dewi Setiawati, B. R. Wijaya, Agung Arief Wijaya, Andhika Pratama, Arifin Isawiseman, E. Wijaya
The Brani-Field is located offshore Northwest Java and currently produces hydrocarbons from a sandstone reservoir with an average watercut of 83%. Some high watercut wells are prone to scale problems and need repetitive clean outs to overcome production decline. In 2019, downhole scale inhibitor treatment was evaluated and planned for application in these wells. Scale inhibitors are able to prevent the formation of scale so the well is able to deliver higher average oil production with lower intervention cost. In Brani wells, scale deposits are formed in perforations, downhole completion equipment, and flowlines depending on the water composition, temperature, and a reduction in dissolved carbon dioxide partial pressure. These scales deposits restrict the fluid flow causing significant production loss. In extreme conditions, the production tubing was blocked completely with the scale deposits and cease the production. Normally, the scale restriction problem in Brani wells were handled by a combination of mechanical and acidizing treatment using Coiled Tubing (CT) for downhole completion and acidizing treatment for flowline restrictions. These treatment were performed periodically every 2-4 months depending on well conditions with scaling becoming more severe in higher watercut wells. From an economic standpoint, current scale treatment methods lead to very high well intervention costs due to expensive liftboat and CT unit daily rates. The economics of these conventional treatments is further deterred by low yearly average oil production. Evaluation for scale inhibitor treatment started with the candidate selection, fluids compatibility test, core re-gain permeability test, and economic evaluation. BRG-10 well was selected as first candidate due to scale problem severity and low oil production rate. This well normally delivers 140 bopd with 90% watercut, but scale build up in the tubing and flowline prevented the fluids flow and lowered the production to 30 bopd in just two months. Laboratory test results demonstrated that the core regained permeability with the main pill fluids to a relatively high, 77.96% without any fluids compatibility issues. Deployment of a scale inhibitor squeeze treatment in BRG-10 well was executed in Jan 2020 by bullheading 657 bbl inhibitor fluids into the formation. The well was then shut in for 24 hours of soaking time. The post treatment results showed a very promising result with much more stable oil production after 11 months treatment, welltest on December 2020 showed the well was still producing 130 bopd with 90% watercut. Following the successful application in BRG-10, the scale inhibitor treatment was applied in other wells, BRK-7 in June 2020 and BRG-5L in August 2020. So far, those two wells show good production performance with 93 bopd with 85% watercut for BRK-7 and 264 bopd with 76% for BRG-5L.
{"title":"Scale Squeeze Inhibitor as Preventive Treatment in Brani Wells, Offshore North West Java","authors":"Hendro Vico, Riezal Arieffiandhany, I. Sanjaya, Lambertus Francisco, Yasinta Dewi Setiawati, B. R. Wijaya, Agung Arief Wijaya, Andhika Pratama, Arifin Isawiseman, E. Wijaya","doi":"10.2118/205564-ms","DOIUrl":"https://doi.org/10.2118/205564-ms","url":null,"abstract":"\u0000 The Brani-Field is located offshore Northwest Java and currently produces hydrocarbons from a sandstone reservoir with an average watercut of 83%. Some high watercut wells are prone to scale problems and need repetitive clean outs to overcome production decline. In 2019, downhole scale inhibitor treatment was evaluated and planned for application in these wells. Scale inhibitors are able to prevent the formation of scale so the well is able to deliver higher average oil production with lower intervention cost.\u0000 In Brani wells, scale deposits are formed in perforations, downhole completion equipment, and flowlines depending on the water composition, temperature, and a reduction in dissolved carbon dioxide partial pressure. These scales deposits restrict the fluid flow causing significant production loss. In extreme conditions, the production tubing was blocked completely with the scale deposits and cease the production. Normally, the scale restriction problem in Brani wells were handled by a combination of mechanical and acidizing treatment using Coiled Tubing (CT) for downhole completion and acidizing treatment for flowline restrictions. These treatment were performed periodically every 2-4 months depending on well conditions with scaling becoming more severe in higher watercut wells. From an economic standpoint, current scale treatment methods lead to very high well intervention costs due to expensive liftboat and CT unit daily rates. The economics of these conventional treatments is further deterred by low yearly average oil production.\u0000 Evaluation for scale inhibitor treatment started with the candidate selection, fluids compatibility test, core re-gain permeability test, and economic evaluation. BRG-10 well was selected as first candidate due to scale problem severity and low oil production rate. This well normally delivers 140 bopd with 90% watercut, but scale build up in the tubing and flowline prevented the fluids flow and lowered the production to 30 bopd in just two months.\u0000 Laboratory test results demonstrated that the core regained permeability with the main pill fluids to a relatively high, 77.96% without any fluids compatibility issues. Deployment of a scale inhibitor squeeze treatment in BRG-10 well was executed in Jan 2020 by bullheading 657 bbl inhibitor fluids into the formation. The well was then shut in for 24 hours of soaking time. The post treatment results showed a very promising result with much more stable oil production after 11 months treatment, welltest on December 2020 showed the well was still producing 130 bopd with 90% watercut.\u0000 Following the successful application in BRG-10, the scale inhibitor treatment was applied in other wells, BRK-7 in June 2020 and BRG-5L in August 2020. So far, those two wells show good production performance with 93 bopd with 85% watercut for BRK-7 and 264 bopd with 76% for BRG-5L.","PeriodicalId":11017,"journal":{"name":"Day 2 Wed, October 13, 2021","volume":"12 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88732080","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}
In this paper, a nonautonomous delay differential equation of microorganism flocculation is established by considering the influence of external conditions such as seasonal alternation and ocean current movement on the ecological function of microorganism population. At the same time, the dynamic change characteristics of microorganism population in oil spill environment were simulated, and on this basis, the effects of diurnal change and climate change on the parameters of microorganism system were analyzed. From a mathematical point of view, the stochastic microorganism flocculation model exists a T-positive periodic solution. The existence and uniqueness of globally positive equilibrium of the exploited model is studied. Finally, some numerical examples illustrate the results.
{"title":"Periodic Solution of a Stochastic Microorganism Flocculation Model with Distributed Delay","authors":"Xiaojie Mu, D. Jiang","doi":"10.2118/205821-ms","DOIUrl":"https://doi.org/10.2118/205821-ms","url":null,"abstract":"\u0000 In this paper, a nonautonomous delay differential equation of microorganism flocculation is established by considering the influence of external conditions such as seasonal alternation and ocean current movement on the ecological function of microorganism population. At the same time, the dynamic change characteristics of microorganism population in oil spill environment were simulated, and on this basis, the effects of diurnal change and climate change on the parameters of microorganism system were analyzed. From a mathematical point of view, the stochastic microorganism flocculation model exists a T-positive periodic solution. The existence and uniqueness of globally positive equilibrium of the exploited model is studied. Finally, some numerical examples illustrate the results.","PeriodicalId":11017,"journal":{"name":"Day 2 Wed, October 13, 2021","volume":"83 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88997014","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}
Digital transformation is shifting the structure of work in nearly every industry and fundamentally changing the value proposition for customers. As part of PETRONAS’ overall digital transformation, Front End Engineering (FEE) has embarked on an ambitious program to digitalize and integrate the company's Front End project realization processes and applications into a single digital tool, referred to as Concept Factory. This paper reviews the journey to initiate, frame and deliver the Front End work process digitalization. The Concept Factory digital transformation program first focused on a strategy to identify the pain points within the traditional project realization work process and how this is impacting both quality and speed of delivery. Once the pain points were identified, assessment of how digitalization may eliminate the pain points and enhance the project realization process value was completed. This assessment also included an end-to-end review of where the current Front End work processes to identify barriers that challenged the ease of digitalization; these included highly manual and siloed work processes, data management and tools; insufficient leveraging off the extensive Company knowledge databases and analogue projects; and inefficient technical and cost benchmarking to assure robustness of Front End work. This resulted in a more significant Front End process transformation being needed to increase the potential value creation through the digital transformation. A stepwise, iterative approach using Agile project management techniques has been used to harness the full capabilities of digital integration and analytics to FEL-2 rather than merely digitalizing the existing manual workflow. This will be done by first automating and upgrading databases and discrete data hand-offs to be "digital ready", independently developing and digitalizing the full suite of Front End technical and cost analysis tools, then integrating these tools within a common Concept Factory analytics platform for both stand-alone Front End analysis and as a domain tool within the broader Field Development Planning digital framework. Several technical and organizational challenges were identified that need to be overcome from business case syndication to adoption. As the daily work routines of employees are being radically changed to adapt to the rapid change of digital technology, ongoing alignment was done to engage the Front End team and broader stakeholder groups in the process through demonstrations and feedback sessions. In addition, cascading technical needs through the digital team execution required ongoing alignment through daily Scrums, Sprint Planning and demonstration sessions. Fully integrated Front End process digitalization has rarely been attempted within E&P companies. However, this has the potential to disrupt the Front End work process from a manual, siloed generation of deliverables to an automated and integrated techno-commercial proc
{"title":"Front End Work Process Digital Transformation: Challenges and Opportunities","authors":"Grant Veroba, Nurul Aminah Mohd Azmi","doi":"10.2118/205606-ms","DOIUrl":"https://doi.org/10.2118/205606-ms","url":null,"abstract":"\u0000 Digital transformation is shifting the structure of work in nearly every industry and fundamentally changing the value proposition for customers. As part of PETRONAS’ overall digital transformation, Front End Engineering (FEE) has embarked on an ambitious program to digitalize and integrate the company's Front End project realization processes and applications into a single digital tool, referred to as Concept Factory. This paper reviews the journey to initiate, frame and deliver the Front End work process digitalization.\u0000 The Concept Factory digital transformation program first focused on a strategy to identify the pain points within the traditional project realization work process and how this is impacting both quality and speed of delivery. Once the pain points were identified, assessment of how digitalization may eliminate the pain points and enhance the project realization process value was completed. This assessment also included an end-to-end review of where the current Front End work processes to identify barriers that challenged the ease of digitalization; these included highly manual and siloed work processes, data management and tools; insufficient leveraging off the extensive Company knowledge databases and analogue projects; and inefficient technical and cost benchmarking to assure robustness of Front End work. This resulted in a more significant Front End process transformation being needed to increase the potential value creation through the digital transformation.\u0000 A stepwise, iterative approach using Agile project management techniques has been used to harness the full capabilities of digital integration and analytics to FEL-2 rather than merely digitalizing the existing manual workflow. This will be done by first automating and upgrading databases and discrete data hand-offs to be \"digital ready\", independently developing and digitalizing the full suite of Front End technical and cost analysis tools, then integrating these tools within a common Concept Factory analytics platform for both stand-alone Front End analysis and as a domain tool within the broader Field Development Planning digital framework.\u0000 Several technical and organizational challenges were identified that need to be overcome from business case syndication to adoption. As the daily work routines of employees are being radically changed to adapt to the rapid change of digital technology, ongoing alignment was done to engage the Front End team and broader stakeholder groups in the process through demonstrations and feedback sessions. In addition, cascading technical needs through the digital team execution required ongoing alignment through daily Scrums, Sprint Planning and demonstration sessions.\u0000 Fully integrated Front End process digitalization has rarely been attempted within E&P companies. However, this has the potential to disrupt the Front End work process from a manual, siloed generation of deliverables to an automated and integrated techno-commercial proc","PeriodicalId":11017,"journal":{"name":"Day 2 Wed, October 13, 2021","volume":"22 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87260226","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 oil and gas industry, a highly technical industry, involves a collaboration of various disciplines of science and technology from exploration to production and utilization of the products. Continuous research and technology developments have improved the success of the industry. Oil and Gas will continue to play important role in the total energy mix due to their affordability and easiness of use. The infrastructure and facilities viz, drilling rigs, pipeline, casing and tubular, platforms and chemical produced from other industries also contribute significant greenhouse gas (GHG) emission. Increased use of oil & gas is causing the emission of GHG in the atmosphere causing temperature rise of the earth which is a major cause for climate change. The increasing demand for natural gas is necessitating the development of giant contaminated gas fields which will further increase GHG production significantly. Natural gas would be the transition fuel from conventional to renewable energy sources. Climate science is understood, and experts are of the view that current and enhanced future emissions of GHG will have a catastrophic effect on the environment. It has to be controlled and produced contaminated gases need to be stored safely and utilized for humanity. Improvement in energy efficiency and environmental sustainability by reduction of greenhouse gas emissions from the industrial operations as well as from energy use by consumers is picking up. Carbon capture, separation, transportation, storage, and utilization has started at a small scale. There is an urgent need to improve yesterday’s performance and meet tomorrow’s challenge in CCUS in the petroleum industry. Fundamental research for capturing, utilization and storage of GHG has to be enhanced for improvising the processes. It is a fact that technology stimulates science, science stimulates technology, and both stimulate the efficiency of the process. Because of this, success mantra and objective for better performance, oil and gas companies are investing and pursuing research and development for controlling and managing the carbon capture utilization and storage (CCUS). This paper discusses the result of active Research and Development of CCUS which is being pursued for the last decades for fundamental issues of separation of carbon dioxide, transportation, subsurface storage physics & chemistry and utilization of the CO2 into usable products. Scientific results and findings of basic and applied research for better efficiency and cost-effectiveness of the products like precipitated calcium carbonate (PCC), alcohols and methane generation by Methanogenesis. Supercritical behavior of CO2 in subsurface, geomechanical and geochemical changes during and after storage, enhancing trapping mechanism, the effect of H2S on CO2 storage and understanding the science of contaminant separation and areas of improvement in methodologies will be presented and highlighted.
{"title":"Pitching Early for CCUS Research and Development in Oil & Gas Industry: A Well Thought Endeavor","authors":"R. Tewari, M. Sedaralit, B. Lal","doi":"10.2118/205809-ms","DOIUrl":"https://doi.org/10.2118/205809-ms","url":null,"abstract":"\u0000 The oil and gas industry, a highly technical industry, involves a collaboration of various disciplines of science and technology from exploration to production and utilization of the products. Continuous research and technology developments have improved the success of the industry. Oil and Gas will continue to play important role in the total energy mix due to their affordability and easiness of use. The infrastructure and facilities viz, drilling rigs, pipeline, casing and tubular, platforms and chemical produced from other industries also contribute significant greenhouse gas (GHG) emission. Increased use of oil & gas is causing the emission of GHG in the atmosphere causing temperature rise of the earth which is a major cause for climate change. The increasing demand for natural gas is necessitating the development of giant contaminated gas fields which will further increase GHG production significantly. Natural gas would be the transition fuel from conventional to renewable energy sources.\u0000 Climate science is understood, and experts are of the view that current and enhanced future emissions of GHG will have a catastrophic effect on the environment. It has to be controlled and produced contaminated gases need to be stored safely and utilized for humanity. Improvement in energy efficiency and environmental sustainability by reduction of greenhouse gas emissions from the industrial operations as well as from energy use by consumers is picking up. Carbon capture, separation, transportation, storage, and utilization has started at a small scale. There is an urgent need to improve yesterday’s performance and meet tomorrow’s challenge in CCUS in the petroleum industry.\u0000 Fundamental research for capturing, utilization and storage of GHG has to be enhanced for improvising the processes. It is a fact that technology stimulates science, science stimulates technology, and both stimulate the efficiency of the process. Because of this, success mantra and objective for better performance, oil and gas companies are investing and pursuing research and development for controlling and managing the carbon capture utilization and storage (CCUS).\u0000 This paper discusses the result of active Research and Development of CCUS which is being pursued for the last decades for fundamental issues of separation of carbon dioxide, transportation, subsurface storage physics & chemistry and utilization of the CO2 into usable products. Scientific results and findings of basic and applied research for better efficiency and cost-effectiveness of the products like precipitated calcium carbonate (PCC), alcohols and methane generation by Methanogenesis. Supercritical behavior of CO2 in subsurface, geomechanical and geochemical changes during and after storage, enhancing trapping mechanism, the effect of H2S on CO2 storage and understanding the science of contaminant separation and areas of improvement in methodologies will be presented and highlighted.","PeriodicalId":11017,"journal":{"name":"Day 2 Wed, October 13, 2021","volume":"68 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78956206","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}
Youngbin Shan, Hongjun Lu, Qingbo Jiang, Zhijun Li, Jianpeng Xue, Fengjun Tian, Yun-gong Wang, Li Luke, Chongdong Shi, Peiming Shi, Bin Yuan, Hangyu He
The objective of the paper is to introduce a new technology which secures long horizontal casing deployment by a reliable casing flotation technology. It is common nowadays to drill a slim hole and extends to long horizontal extension to pay zones in condensate and shale oil and gas reservoir. To assure a successful casing deployment into the horizontal section, a flotation collar is often installed to float the casing in horizontal to mitigate the friction and Torque & Drag. However, slim casing may encounter difficulty in circulation and subsequent cementing even after the collar is broken. A new proprietary technique proposed in this paper solved above contingencies and secured 100% success in casing deployment, This technique secures smoothly circulation and cementing by flotating air in horizontal casing interval and purging air out of hole to overcome Spring Effect before circulation and cementing. Often, the flotation collar is made of proprietary material that can break or explodes under certain hydraulic pressure. After breaking, the whole collar becomes a portion of casing with exact the same ID of casing or a very small difference that does not have any negative effect to subsequent Plug & Perf, frac, tools running through and fluid movement. For long horizontal length of small open hole and casing sizes, casing deployment may be difficult if the Torque & Drag and friction through the low sides can not be mitigated. This paper proposes a new technique to fill air full of horizontal interval along inside the casing and ensure a sufficient of air purging to overcome Spring Effect before circulation and cementing. So far twelve (12) wells have been successfully completed including Asian longest horizontal gas well with 7,388.18m measured depth and 4,118.18m horizontal length. All jobs are 100% successful and there is no difficulty in mud circulation and cementing. Even for the longest 4,118.18m horizontal length casing deployment, the hook weight on surface when casing reached the total depth still remained 20 MT. Before this technique was applied, operators were unable to deploy 4 ½" casing through a 6" bit hole beyond 1500m horizontal length. Most often the hook weight at surface were zero when casing extended to almost 1500m in horizontal length. This new technique brings a great value to operators to complete longer horizontal well to yield more production with less investment.
{"title":"Long Horizontal Well Completion via a New Flotation Technique","authors":"Youngbin Shan, Hongjun Lu, Qingbo Jiang, Zhijun Li, Jianpeng Xue, Fengjun Tian, Yun-gong Wang, Li Luke, Chongdong Shi, Peiming Shi, Bin Yuan, Hangyu He","doi":"10.2118/205594-ms","DOIUrl":"https://doi.org/10.2118/205594-ms","url":null,"abstract":"\u0000 The objective of the paper is to introduce a new technology which secures long horizontal casing deployment by a reliable casing flotation technology.\u0000 It is common nowadays to drill a slim hole and extends to long horizontal extension to pay zones in condensate and shale oil and gas reservoir.\u0000 To assure a successful casing deployment into the horizontal section, a flotation collar is often installed to float the casing in horizontal to mitigate the friction and Torque & Drag. However, slim casing may encounter difficulty in circulation and subsequent cementing even after the collar is broken.\u0000 A new proprietary technique proposed in this paper solved above contingencies and secured 100% success in casing deployment, This technique secures smoothly circulation and cementing by flotating air in horizontal casing interval and purging air out of hole to overcome Spring Effect before circulation and cementing.\u0000 Often, the flotation collar is made of proprietary material that can break or explodes under certain hydraulic pressure. After breaking, the whole collar becomes a portion of casing with exact the same ID of casing or a very small difference that does not have any negative effect to subsequent Plug & Perf, frac, tools running through and fluid movement.\u0000 For long horizontal length of small open hole and casing sizes, casing deployment may be difficult if the Torque & Drag and friction through the low sides can not be mitigated.\u0000 This paper proposes a new technique to fill air full of horizontal interval along inside the casing and ensure a sufficient of air purging to overcome Spring Effect before circulation and cementing.\u0000 So far twelve (12) wells have been successfully completed including Asian longest horizontal gas well with 7,388.18m measured depth and 4,118.18m horizontal length. All jobs are 100% successful and there is no difficulty in mud circulation and cementing. Even for the longest 4,118.18m horizontal length casing deployment, the hook weight on surface when casing reached the total depth still remained 20 MT.\u0000 Before this technique was applied, operators were unable to deploy 4 ½\" casing through a 6\" bit hole beyond 1500m horizontal length. Most often the hook weight at surface were zero when casing extended to almost 1500m in horizontal length.\u0000 This new technique brings a great value to operators to complete longer horizontal well to yield more production with less investment.","PeriodicalId":11017,"journal":{"name":"Day 2 Wed, October 13, 2021","volume":"51 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75627066","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}
A second stage of gravity settling with the addition of demulsifiers or clarifiers is commonly used in processing plants to further treat the separated produced water. In previous work, we demonstrated gravity settling lower efficiency in removing oil carryover from produced water compared to other processing techniques. Both centrifugation and filtration were found to significantly improve the separated water quality. In this work, we focus on centrifugation and further evaluate its efficiency in improving the quality of separated water for both water and chemical floods, specifically surfactant/polymer (SP) flooding. Samples were firstly prepared to imitate the separation plant projected feed and operations. Synthetic representative brines were prepared and used with dead crude oil to prepare the oil/water emulsions. Emulsion separation was conducted at different temperatures, as well as different concentrations of SP, and the demulsifier. The kinetics and efficiency of separation were thoroughly studied over two stages of separation: primary gravity settling and secondary centrifugation. We performed gravitational separation using bottle tests in order to firstly obtain the separated produced water for use in secondary water treatment studies and to secondly further investigate gravity settling kinetics and efficiency. Water quality, in terms of oil content, was then assessed through solvent extraction and UV analyses. Samples of the produced water separated by the primary gravity settling were then exposed to secondary centrifugation. Centrifugation was performed at different rotational speeds using a dispersion analyzer. Light transmission evolution in space and time was used to study kinetics, efficiency and mechanisms of secondary centrifugation. The results reconfirmed that a single-stage gravity settling is not sufficient to reduce oil carryover to acceptable levels for disposal and re-injection into oilfields. Secondary centrifugation yielded clear and significant improvement in water quality even in the presence of EOR chemicals. With centrifugation, the separation efficiency was a function of the rotational speed. Higher rotational speeds resulted in higher creaming velocities and faster separation. In addition, creaming velocities indicated that higher temperatures yield favorable effects on oil droplets migration and separation rates. This is possibly due to the lower density and larger bouncy at higher temperatures. Based on these results, we conclude that secondary centrifugation is very efficient and effective in improving the quality of separated water. In terms of the effects of investigated EOR formulations, SP addition caused minor but manageable reduction in separated water quality at a level that would not harm conventional disposal practices.
{"title":"Produced Water Quality: Uncovering the Effects of Centrifugation for Water and Chemical Floods Using a Dispersion Analyzer","authors":"J. Almorihil, A. Alsmaeil, Z. Kaidar, A. AlSofi","doi":"10.2118/205534-ms","DOIUrl":"https://doi.org/10.2118/205534-ms","url":null,"abstract":"\u0000 A second stage of gravity settling with the addition of demulsifiers or clarifiers is commonly used in processing plants to further treat the separated produced water. In previous work, we demonstrated gravity settling lower efficiency in removing oil carryover from produced water compared to other processing techniques. Both centrifugation and filtration were found to significantly improve the separated water quality. In this work, we focus on centrifugation and further evaluate its efficiency in improving the quality of separated water for both water and chemical floods, specifically surfactant/polymer (SP) flooding.\u0000 Samples were firstly prepared to imitate the separation plant projected feed and operations. Synthetic representative brines were prepared and used with dead crude oil to prepare the oil/water emulsions. Emulsion separation was conducted at different temperatures, as well as different concentrations of SP, and the demulsifier. The kinetics and efficiency of separation were thoroughly studied over two stages of separation: primary gravity settling and secondary centrifugation. We performed gravitational separation using bottle tests in order to firstly obtain the separated produced water for use in secondary water treatment studies and to secondly further investigate gravity settling kinetics and efficiency. Water quality, in terms of oil content, was then assessed through solvent extraction and UV analyses. Samples of the produced water separated by the primary gravity settling were then exposed to secondary centrifugation. Centrifugation was performed at different rotational speeds using a dispersion analyzer. Light transmission evolution in space and time was used to study kinetics, efficiency and mechanisms of secondary centrifugation.\u0000 The results reconfirmed that a single-stage gravity settling is not sufficient to reduce oil carryover to acceptable levels for disposal and re-injection into oilfields. Secondary centrifugation yielded clear and significant improvement in water quality even in the presence of EOR chemicals. With centrifugation, the separation efficiency was a function of the rotational speed. Higher rotational speeds resulted in higher creaming velocities and faster separation. In addition, creaming velocities indicated that higher temperatures yield favorable effects on oil droplets migration and separation rates. This is possibly due to the lower density and larger bouncy at higher temperatures.\u0000 Based on these results, we conclude that secondary centrifugation is very efficient and effective in improving the quality of separated water. In terms of the effects of investigated EOR formulations, SP addition caused minor but manageable reduction in separated water quality at a level that would not harm conventional disposal practices.","PeriodicalId":11017,"journal":{"name":"Day 2 Wed, October 13, 2021","volume":"20 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75561128","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}
京公网安备 11010802042870号
京ICP备2023020795号-1
扫码关注我们
求助内容：
应助结果提醒方式：