Although the drilling industry is slowly moving toward a higher degree of automation, casing running is still left out of this equation. Until now. Due to the more delicate handling that is required to handle casing, the task is often handed over to dedicated casing running service companies. This year, a new rig is build that performs the task of casing running, including making and monitoring the connection, fully automated and 100% hands off: "just press start sequence". To enable full-automated casing running, it is required to have a dedicated handler with high precision handling and measuring systems. To reach the maximum safety level, the goal is set to have no people in the red zone on the floor for any assistance. An integrated (scada) control system needs to combine data as casing length, positioning, amount of turns to spin in and make up torque into one system. It also needs to communicate to the other rig equipment as drawworks and topdrive to enable smooth fully hands off operations. The above is this year integrated in an HM100 mobile rig and will be deployed in the oilfield in Q3 2020 for a mayor operator. The equipment is capable of handling casing up to 13 3/8" in full automated sequences at a speed of ∼ 1300 ft/hr, more then 300% faster then manual operations. At a traditional catwalk machine, casing is pushed over the pipe slide. For this reason the thread needs to stay protected by thread caps, until the pipe is in wellcentre. Here usally 2-3 people are present to guide the casing and apply dope etc. To make sure that no people need to work in the red zone on the floor, it is chosen to develop a pipe handler that lifts the casing from pipe bed to wellcentre in one movement, while keeping the thread clear: a massive safety improvement. The sequence is completed by an automated hand over to the casing running tool on the topdrive. As final step, while making the connection, the integrated torque turn graph system controls and monitors the connection and stores this combined with the length in the auto-tally system. Fast save operations, with data readily available. This is the industry first mobile rig with full automated casing running capabilities, an important step in the ongoing field automation. With a consistent speed of over 30 casings / hour the time per well is reduced significantly, while there is no need to have separate crews and tools available on location. Casing running will now be predictable in time and duration, with real time results immediately available on the OPC-UA server for the client.
{"title":"Full Automated Casing Running: The Next Step Completed in Field Automation","authors":"Arthur de Mul","doi":"10.2118/202812-ms","DOIUrl":"https://doi.org/10.2118/202812-ms","url":null,"abstract":"\u0000 \u0000 \u0000 Although the drilling industry is slowly moving toward a higher degree of automation, casing running is still left out of this equation. Until now. Due to the more delicate handling that is required to handle casing, the task is often handed over to dedicated casing running service companies. This year, a new rig is build that performs the task of casing running, including making and monitoring the connection, fully automated and 100% hands off: \"just press start sequence\".\u0000 \u0000 \u0000 \u0000 To enable full-automated casing running, it is required to have a dedicated handler with high precision handling and measuring systems. To reach the maximum safety level, the goal is set to have no people in the red zone on the floor for any assistance.\u0000 An integrated (scada) control system needs to combine data as casing length, positioning, amount of turns to spin in and make up torque into one system. It also needs to communicate to the other rig equipment as drawworks and topdrive to enable smooth fully hands off operations.\u0000 \u0000 \u0000 \u0000 The above is this year integrated in an HM100 mobile rig and will be deployed in the oilfield in Q3 2020 for a mayor operator. The equipment is capable of handling casing up to 13 3/8\" in full automated sequences at a speed of ∼ 1300 ft/hr, more then 300% faster then manual operations.\u0000 At a traditional catwalk machine, casing is pushed over the pipe slide. For this reason the thread needs to stay protected by thread caps, until the pipe is in wellcentre. Here usally 2-3 people are present to guide the casing and apply dope etc. To make sure that no people need to work in the red zone on the floor, it is chosen to develop a pipe handler that lifts the casing from pipe bed to wellcentre in one movement, while keeping the thread clear: a massive safety improvement.\u0000 The sequence is completed by an automated hand over to the casing running tool on the topdrive.\u0000 As final step, while making the connection, the integrated torque turn graph system controls and monitors the connection and stores this combined with the length in the auto-tally system.\u0000 Fast save operations, with data readily available.\u0000 \u0000 \u0000 \u0000 This is the industry first mobile rig with full automated casing running capabilities, an important step in the ongoing field automation. With a consistent speed of over 30 casings / hour the time per well is reduced significantly, while there is no need to have separate crews and tools available on location. Casing running will now be predictable in time and duration, with real time results immediately available on the OPC-UA server for the client.\u0000","PeriodicalId":186916,"journal":{"name":"Day 3 Wed, November 11, 2020","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2020-11-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124333583","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. Ghassan, M. Fernandes, Onood Al Ali, N. Kaczorowski
This paper describes how the reservoir team at ADNOC Sour Gas developed the ability to dynamically adjust and manage their production strategy based on plant product output and market requirements, driving profitability and maximizing value of the sour gas assets of the UAE. The reservoir team developed and successfully implemented an extensive data acquisition program, enabling adequate characterization of a giant ultra-sour gas carbonate reservoir in the Late Jurassic Arab Formation in the western area of Abu Dhabi. The field is located in the southern part of UAE, in the Liwa province, and covers an area of 57 km2. It consists of four main reservoir zones: Arab A, Arab B, Arab C, and Arab D. Current development is focused on the central part of the field with most of the wells dedicated to Arab C. Future development plans will focus on the southern and northern areas of the field. Early during the appraisal stage, the data suggested the existence of an areal gradient in composition across the reservoir. As such, a clear understanding of this areal distribution in addition to the usual reservoir gas composition, properties and behavior was essential in optimizing field production and maximizing value. Over the course of field development, reservoir fluids from different well locations were sampled and analyzed. Various issues were encountered during this process including H2S stripping in down hole samples, contamination from stimulation fluids and quality assurance and quality control concerns in lab measurements. Resolving these issues allowed a coherent understanding of the compositional variation in the Arab Formations. To properly model the compositional variation, an innovative methodology was implemented by the team to initialize the dynamic model. The methodology consisted of two major steps. Firstly, PVT data was analyzed and correlations between H2S and other components were developed. Secondly, through PETREL, compositional maps were created. Ultimately, each grid block was assigned a unique composition honoring the areal variation in composition across each reservoir zone. In addition, empirical correlations between fluid components and plant product streams were developed through material balance analysis. Using product models, these correlations were input into the dynamic model which allowed estimated plant products to be output directly from simulation runs. Simulation forecasts of estimated plant products were later verified by actual plant yields, giving confidence in the methodology implemented. Further, this method allowed a quick turnaround in production planning and optimization thereby reducing the reliance on a fully-fledged plant simulator for short term gains and quick wins.
{"title":"Production Optimization and Value Maximization of a Giant Ultra-Sour Gas Carbonate Reservoir, Onshore Abu Dhabi","authors":"M. Ghassan, M. Fernandes, Onood Al Ali, N. Kaczorowski","doi":"10.2118/203223-ms","DOIUrl":"https://doi.org/10.2118/203223-ms","url":null,"abstract":"\u0000 This paper describes how the reservoir team at ADNOC Sour Gas developed the ability to dynamically adjust and manage their production strategy based on plant product output and market requirements, driving profitability and maximizing value of the sour gas assets of the UAE.\u0000 The reservoir team developed and successfully implemented an extensive data acquisition program, enabling adequate characterization of a giant ultra-sour gas carbonate reservoir in the Late Jurassic Arab Formation in the western area of Abu Dhabi.\u0000 The field is located in the southern part of UAE, in the Liwa province, and covers an area of 57 km2. It consists of four main reservoir zones: Arab A, Arab B, Arab C, and Arab D. Current development is focused on the central part of the field with most of the wells dedicated to Arab C. Future development plans will focus on the southern and northern areas of the field.\u0000 Early during the appraisal stage, the data suggested the existence of an areal gradient in composition across the reservoir. As such, a clear understanding of this areal distribution in addition to the usual reservoir gas composition, properties and behavior was essential in optimizing field production and maximizing value.\u0000 Over the course of field development, reservoir fluids from different well locations were sampled and analyzed. Various issues were encountered during this process including H2S stripping in down hole samples, contamination from stimulation fluids and quality assurance and quality control concerns in lab measurements. Resolving these issues allowed a coherent understanding of the compositional variation in the Arab Formations.\u0000 To properly model the compositional variation, an innovative methodology was implemented by the team to initialize the dynamic model. The methodology consisted of two major steps. Firstly, PVT data was analyzed and correlations between H2S and other components were developed. Secondly, through PETREL, compositional maps were created. Ultimately, each grid block was assigned a unique composition honoring the areal variation in composition across each reservoir zone.\u0000 In addition, empirical correlations between fluid components and plant product streams were developed through material balance analysis. Using product models, these correlations were input into the dynamic model which allowed estimated plant products to be output directly from simulation runs. Simulation forecasts of estimated plant products were later verified by actual plant yields, giving confidence in the methodology implemented. Further, this method allowed a quick turnaround in production planning and optimization thereby reducing the reliance on a fully-fledged plant simulator for short term gains and quick wins.","PeriodicalId":186916,"journal":{"name":"Day 3 Wed, November 11, 2020","volume":"24 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2020-11-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"115095516","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}
H. Saradva, Siddharth Jain, Christna Golaco, S. Su, A. Amtereg, H. Mustapha
Sharjah National Oil Corporation (SNOC) operates three onshore reservoirs in the Emirate of Sharjah. The reservoir simulation models use compositional modelling to capture the fluid dynamics in mature, low porosity highly fractured gas condensate fields. The scope of this project was to improve the reservoir characterization by investigating and overcoming lack of water production in compositional models for effective EOR and gas storage strategies. Water cut of 30%+ comprised of a combination of produced and condensed water in a reservoir with no active aquifer, thus posing a modelling challenge combined with a lack of comprehensive historical PVT data. All existing PVT reports in the database were retrieved and a comprehensive quality check was performed. The best possible PVT results for each field were short-listed and taken as reference datasets for validating the compositional EoS in a depleted field. A new EOS was generated for these fields based on legacy PVT data combined with 38+ years of production data. A shortfall of this new EOS was the inability to produce condensed water as observed in the field with Chloride counts less than 1500 ppm. To rectify this low water production mismatch, a blind test was conducted introducing water as a component in the EoS in the simulation model to see the effect. Moreover, extensive scale problems in any of the wells of 30-year-old mature assets leading to regular interventions never occurred in the asset's operational history. As expected, mobility of the fluids in the system had changed and low salinity condensed water was seen to have a good match. Liberated water was traced at the surface to confirm water production rate of the same order of magnitude as observed in production data. Due to overwhelming water production rates from the trial test, SNOC decided to perform a comprehensive extended PVT study. The naturally fractured carbonates were subjected to geological and material balance study and the data indicated an absence of active aquifers, which made it difficult to match observed water production in simulation models. To effectively plan future EOR projects like gas storage, it was necessary to model the effects of water and its interaction with injected fluids in the reservoir while honouring low water movement in the subsurface. The paper provides a novel workflow for generation of the compositional equation of state with water as a component in retrograde condensate fields. The workflow followed the lumping of hydrocarbon components to minimise runtime and capture maximum possible fluid dynamics in the reservoir without compromising the fluid properties observed in the PVT lab. It was also vital for the simulation model to honour the production history spanning over three decades. It also highlights the ability and importance of including water as an EOS component to effectively capture the condensed water in the reservoirs that many works of literature and simulators are unable t
{"title":"Introducing Water Component in a Compositional Equation of State Model for Condensed Water Production Modelling in a Mature Rich Gas Condensate Reservoir","authors":"H. Saradva, Siddharth Jain, Christna Golaco, S. Su, A. Amtereg, H. Mustapha","doi":"10.2118/203196-ms","DOIUrl":"https://doi.org/10.2118/203196-ms","url":null,"abstract":"\u0000 Sharjah National Oil Corporation (SNOC) operates three onshore reservoirs in the Emirate of Sharjah. The reservoir simulation models use compositional modelling to capture the fluid dynamics in mature, low porosity highly fractured gas condensate fields. The scope of this project was to improve the reservoir characterization by investigating and overcoming lack of water production in compositional models for effective EOR and gas storage strategies. Water cut of 30%+ comprised of a combination of produced and condensed water in a reservoir with no active aquifer, thus posing a modelling challenge combined with a lack of comprehensive historical PVT data.\u0000 All existing PVT reports in the database were retrieved and a comprehensive quality check was performed. The best possible PVT results for each field were short-listed and taken as reference datasets for validating the compositional EoS in a depleted field. A new EOS was generated for these fields based on legacy PVT data combined with 38+ years of production data. A shortfall of this new EOS was the inability to produce condensed water as observed in the field with Chloride counts less than 1500 ppm. To rectify this low water production mismatch, a blind test was conducted introducing water as a component in the EoS in the simulation model to see the effect. Moreover, extensive scale problems in any of the wells of 30-year-old mature assets leading to regular interventions never occurred in the asset's operational history.\u0000 As expected, mobility of the fluids in the system had changed and low salinity condensed water was seen to have a good match. Liberated water was traced at the surface to confirm water production rate of the same order of magnitude as observed in production data. Due to overwhelming water production rates from the trial test, SNOC decided to perform a comprehensive extended PVT study. The naturally fractured carbonates were subjected to geological and material balance study and the data indicated an absence of active aquifers, which made it difficult to match observed water production in simulation models. To effectively plan future EOR projects like gas storage, it was necessary to model the effects of water and its interaction with injected fluids in the reservoir while honouring low water movement in the subsurface.\u0000 The paper provides a novel workflow for generation of the compositional equation of state with water as a component in retrograde condensate fields. The workflow followed the lumping of hydrocarbon components to minimise runtime and capture maximum possible fluid dynamics in the reservoir without compromising the fluid properties observed in the PVT lab. It was also vital for the simulation model to honour the production history spanning over three decades. It also highlights the ability and importance of including water as an EOS component to effectively capture the condensed water in the reservoirs that many works of literature and simulators are unable t","PeriodicalId":186916,"journal":{"name":"Day 3 Wed, November 11, 2020","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2020-11-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"115786969","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}
Han Haochen, Huang Yongjian, Zhang Yong, Sun Qi, Chengqin Sun, Zhimeng Fang, Haoweu Chen
Well depth is one of the most valuable parameters in drilling engineering. Commonly well depth is calculated by the absolute difference in height based on the revolution of drawwork sensor, which is a pulse encoder or incremental optical encoder. Both encoders have complicated calibration process, and the measurement is easily disturbed. Different from the traditional indirect measurement from the drawwork sensor, the direct measurement provided by laser distance device can simplify the process and decrease the systemic error. The principle of the measurement is to calculate the distance by the product of the atmospheric refraction coefficient and the speed of light. In our design, we fixed the laser distance device on the hook and placed the reflector under the crown to measure the height variant. Modern industrial laser distance device with high accuracy can finish multiple measurements per unit time and calculate the average to reduce the measurement error effectively. The well depth measurement system software based on laser distance measuring device can shorten and simplify the calibration process or even realize automatic calibration. The laser distance measuring device can be used effectively in the severe weather, such as strong winds, and minimize the error caused by manual operation. We completed the optimization of laser distance sensor and selected Sick DL 100 as the main laser sensor, as well as a laser measurement prototype in lab. After thousands of trials and errors, it turns out to be applicable. In order to be compatible with the new well depth measurement system, we developed a corresponding software by .Net Framework and WPF. With the help of .Net framework and WPF, UI and core codes of the software are separated in physical isolation, which can improve the development efficiency and make preparation for further extension and optimization. The software supports portal communication and ethernet, which can connect with the laser distance device conveniently. By the well depth measurement system software based on laser distance measuring device, we simplified the well depth measurement calibration, reduced the system error and improved the accuracy of measurement. The application of this system contributes to the drilling operation and shortens the drilling period.
{"title":"Well Depth Monitor Software Design Based On Laser Distance Measuring Device","authors":"Han Haochen, Huang Yongjian, Zhang Yong, Sun Qi, Chengqin Sun, Zhimeng Fang, Haoweu Chen","doi":"10.2118/203349-ms","DOIUrl":"https://doi.org/10.2118/203349-ms","url":null,"abstract":"\u0000 Well depth is one of the most valuable parameters in drilling engineering. Commonly well depth is calculated by the absolute difference in height based on the revolution of drawwork sensor, which is a pulse encoder or incremental optical encoder. Both encoders have complicated calibration process, and the measurement is easily disturbed.\u0000 Different from the traditional indirect measurement from the drawwork sensor, the direct measurement provided by laser distance device can simplify the process and decrease the systemic error. The principle of the measurement is to calculate the distance by the product of the atmospheric refraction coefficient and the speed of light. In our design, we fixed the laser distance device on the hook and placed the reflector under the crown to measure the height variant. Modern industrial laser distance device with high accuracy can finish multiple measurements per unit time and calculate the average to reduce the measurement error effectively.\u0000 The well depth measurement system software based on laser distance measuring device can shorten and simplify the calibration process or even realize automatic calibration. The laser distance measuring device can be used effectively in the severe weather, such as strong winds, and minimize the error caused by manual operation. We completed the optimization of laser distance sensor and selected Sick DL 100 as the main laser sensor, as well as a laser measurement prototype in lab. After thousands of trials and errors, it turns out to be applicable. In order to be compatible with the new well depth measurement system, we developed a corresponding software by .Net Framework and WPF. With the help of .Net framework and WPF, UI and core codes of the software are separated in physical isolation, which can improve the development efficiency and make preparation for further extension and optimization. The software supports portal communication and ethernet, which can connect with the laser distance device conveniently.\u0000 By the well depth measurement system software based on laser distance measuring device, we simplified the well depth measurement calibration, reduced the system error and improved the accuracy of measurement. The application of this system contributes to the drilling operation and shortens the drilling period.","PeriodicalId":186916,"journal":{"name":"Day 3 Wed, November 11, 2020","volume":"15 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2020-11-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"117295569","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}
Sunil Chitre, Hammad Mustafa, A. Anurag, A. Bazuhair, M. Kuliyev, Khalid Javid, Usman Anjum, Neil Sookram, Latifa AlHaji, Z. Al-Kindi, Baraka Said Afeefi, George Jabour
This paper describes optimal field development and appraisal in complex reservoirs and challenging environments in field ‘ABC’. Most of the wells are laterals with ICD (lower) completions across heterogeneous carbonate reservoirs. Highly corrosive environments i.e. up to 20% H2S present an added risk, particularly in the event of water encroachment. Optimal development needs a multi-disciplinary surveillance approach involving an integration of input form stakeholders, including geoscience and petroleum engineering, to ensure productivity optimization during the whole life of the field. Field ABC is an offshore field with extremely heterogeneous carbonate reservoirs and acid stimulation is usually done to improve production. The wells in the field are mostly horizontal, oil producers with ICD lower completions. The upper completion uses carbon steel L80 and for corrosion mitigation, inhibitors are injected through chemical injection valves. In this paper, a pilot well is reviewed where a methodical approach was used for evaluation. Baseline production logging and reservoir saturation monitoring were done in the lower completion and a corrosion log was acquired in both the upper and lower completions. Data acquired was integrated and observations show that the measurements correlate well with each other. This case study integrates and correlates downhole zonal contribution, phase holdups, pressure and temperature data from production logging with metal loss data from a high-resolution multi-finger caliper tool. Well trajectory shows a depression across the heel of the well which is incidentally between the EOT and the topmost ICD. Although there is no water production at surface, a static water sump is observed across this depression on the production logs. This static water is possibly completion fluid or unremoved fluid from the acid job. Minor localized corrosion is also observed across the same depression on the corrosion logs, also confirming presence of some water. The H2S production and the presence of water is an added risk to completion integrity as it creates a corrosive environment. Therefore, in such cases it will be necessary to monitor the production and corrosion at regular intervals of time. This case study shows that by applying a multi-disciplinary approach and integrating various measurements, well conditions can be viewed not just as pieces of a puzzle but as a complete picture to improve the understanding of the well behavior. Time-lapse monitoring of production and corrosion along with reservoir saturation is also necessary to prevent surprises and help in making informed decisions towards better field development.
{"title":"Looking at the Bigger Picture - Better Understanding of Well Behavior through Integration of Petrophysical, Production Logging and Corrosion Evaluation Data in a Challenging Environment, Ensuring Maximum Well Life and Overall Productivity","authors":"Sunil Chitre, Hammad Mustafa, A. Anurag, A. Bazuhair, M. Kuliyev, Khalid Javid, Usman Anjum, Neil Sookram, Latifa AlHaji, Z. Al-Kindi, Baraka Said Afeefi, George Jabour","doi":"10.2118/203144-ms","DOIUrl":"https://doi.org/10.2118/203144-ms","url":null,"abstract":"\u0000 This paper describes optimal field development and appraisal in complex reservoirs and challenging environments in field ‘ABC’. Most of the wells are laterals with ICD (lower) completions across heterogeneous carbonate reservoirs. Highly corrosive environments i.e. up to 20% H2S present an added risk, particularly in the event of water encroachment. Optimal development needs a multi-disciplinary surveillance approach involving an integration of input form stakeholders, including geoscience and petroleum engineering, to ensure productivity optimization during the whole life of the field.\u0000 Field ABC is an offshore field with extremely heterogeneous carbonate reservoirs and acid stimulation is usually done to improve production. The wells in the field are mostly horizontal, oil producers with ICD lower completions. The upper completion uses carbon steel L80 and for corrosion mitigation, inhibitors are injected through chemical injection valves. In this paper, a pilot well is reviewed where a methodical approach was used for evaluation. Baseline production logging and reservoir saturation monitoring were done in the lower completion and a corrosion log was acquired in both the upper and lower completions. Data acquired was integrated and observations show that the measurements correlate well with each other.\u0000 This case study integrates and correlates downhole zonal contribution, phase holdups, pressure and temperature data from production logging with metal loss data from a high-resolution multi-finger caliper tool. Well trajectory shows a depression across the heel of the well which is incidentally between the EOT and the topmost ICD. Although there is no water production at surface, a static water sump is observed across this depression on the production logs. This static water is possibly completion fluid or unremoved fluid from the acid job. Minor localized corrosion is also observed across the same depression on the corrosion logs, also confirming presence of some water. The H2S production and the presence of water is an added risk to completion integrity as it creates a corrosive environment. Therefore, in such cases it will be necessary to monitor the production and corrosion at regular intervals of time.\u0000 This case study shows that by applying a multi-disciplinary approach and integrating various measurements, well conditions can be viewed not just as pieces of a puzzle but as a complete picture to improve the understanding of the well behavior. Time-lapse monitoring of production and corrosion along with reservoir saturation is also necessary to prevent surprises and help in making informed decisions towards better field development.","PeriodicalId":186916,"journal":{"name":"Day 3 Wed, November 11, 2020","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2020-11-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"115907940","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}
Manar Alahmari, M. Bataweel, A. Al-Humam, A. Almajed
Sand production from poorly consolidated reservoir formations has been a persistent problem in the petroleum industry. Sand production can cause erosion and corrosion to downhole and surface equipment's and loss of production. Several technologies are used to reduce sand production effects and subsequently maintain well production and safe operations. Such techniques include completion techniques, and in-situ chemical consolidation methods. The enzyme urease induced carbonate precipitation (EICP) is a reversible and environmentally friendly technique that can be used for sand consolidation. In EICP, urease enzyme catalyses the hydrolysis of urea in an aqueous solution, which results in ammonia and carbonic acid production. In the presence of calcium ions, the carbonate ions precipitate as calcium carbonate. It has been reported that urease enzyme starts losing its activity above 65 °C and thus this technology can only be applied in reservoirs with temperatures up to 65 °C. This study addresses an improved EICP method where protein is added and the technique can be applicable at high temperature reservoirs. Two EICP solutions were prepared, EICP control solution (solution 1) which contains urease enzyme, calcium chloride and urea and modified EICP solution (solution 2) which consists of urease enzyme, calcium chloride, urea and protein. Test specimens were made by mixing sand with EICP solution and allowed to cure at different temperatures ranging from 25°C to 130 °C. Additionally, XRD analysis was performed to identify the type of calcium carbonate polymorph. SEM imaging was carried out to visualize the morphology of the calcium carbonate precipitation in the sand specimens. Specimens treated with the solution containing protein (solution 2) had a high consolidation strength. As the temperature increases the strength of consolidation decreases in specimens treated with solution 2 and 1. However, the strength of consolidation of specimens treated with solution 2 that contains protein was considerably greater at all temperatures (up to 130 °C), than the strength of specimens treated with solution 1. Moreover, XRD analysis revealed that 70% of the calcium carbonate polymorph in solution 2 was calcite (which is the most stable polymorph). SEM images show that in the specimens treated with solution 2 the calcium carbonate precipitates at inter-particle contacts. The impact of these results include the use of the EICP protein technique as a downhole sand consolidation method in high temperature reservoirs. Furthermore, the addition of protein in the EICP solution can lead to a reduction in the concentration of substrate and enzyme required to achieve sand consolidation, and subsequently reduction in undesirable ammonium chloride. These advantages enhance the potential use of the EICP protein system for sand consolidation in high temperature reservoirs.
{"title":"Sand Consolidation by Enzyme Mediated Calcium Carbonate Precipitation","authors":"Manar Alahmari, M. Bataweel, A. Al-Humam, A. Almajed","doi":"10.2118/203192-ms","DOIUrl":"https://doi.org/10.2118/203192-ms","url":null,"abstract":"\u0000 Sand production from poorly consolidated reservoir formations has been a persistent problem in the petroleum industry. Sand production can cause erosion and corrosion to downhole and surface equipment's and loss of production. Several technologies are used to reduce sand production effects and subsequently maintain well production and safe operations. Such techniques include completion techniques, and in-situ chemical consolidation methods. The enzyme urease induced carbonate precipitation (EICP) is a reversible and environmentally friendly technique that can be used for sand consolidation. In EICP, urease enzyme catalyses the hydrolysis of urea in an aqueous solution, which results in ammonia and carbonic acid production. In the presence of calcium ions, the carbonate ions precipitate as calcium carbonate. It has been reported that urease enzyme starts losing its activity above 65 °C and thus this technology can only be applied in reservoirs with temperatures up to 65 °C. This study addresses an improved EICP method where protein is added and the technique can be applicable at high temperature reservoirs.\u0000 Two EICP solutions were prepared, EICP control solution (solution 1) which contains urease enzyme, calcium chloride and urea and modified EICP solution (solution 2) which consists of urease enzyme, calcium chloride, urea and protein. Test specimens were made by mixing sand with EICP solution and allowed to cure at different temperatures ranging from 25°C to 130 °C. Additionally, XRD analysis was performed to identify the type of calcium carbonate polymorph. SEM imaging was carried out to visualize the morphology of the calcium carbonate precipitation in the sand specimens.\u0000 Specimens treated with the solution containing protein (solution 2) had a high consolidation strength. As the temperature increases the strength of consolidation decreases in specimens treated with solution 2 and 1. However, the strength of consolidation of specimens treated with solution 2 that contains protein was considerably greater at all temperatures (up to 130 °C), than the strength of specimens treated with solution 1. Moreover, XRD analysis revealed that 70% of the calcium carbonate polymorph in solution 2 was calcite (which is the most stable polymorph). SEM images show that in the specimens treated with solution 2 the calcium carbonate precipitates at inter-particle contacts.\u0000 The impact of these results include the use of the EICP protein technique as a downhole sand consolidation method in high temperature reservoirs. Furthermore, the addition of protein in the EICP solution can lead to a reduction in the concentration of substrate and enzyme required to achieve sand consolidation, and subsequently reduction in undesirable ammonium chloride. These advantages enhance the potential use of the EICP protein system for sand consolidation in high temperature reservoirs.","PeriodicalId":186916,"journal":{"name":"Day 3 Wed, November 11, 2020","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2020-11-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125953144","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}
Offshore natural gas fields are normally developed based on multiphase flow. One of the key challenges for such flow lines may be the risk of gas hydrate formation. This risk can be mitigated by injecting Mono Ethylene Glycol (MEG) into the flow line as a thermodynamic hydrate inhibitor. Due to the large volumes of costly glycol required and the desire to minimise the environmental footprint, the glycol is regenerated on topside or onshore facilities. Presence of salts in the MEG systems make it more challenging to operate them and having full control over the chemistry within the MEG system is key to have successful operation. Today chemistry control within MEG system is largely done by manual sampling and lab analysis as online analysers are either not available or not qualified for the service. Having robust online analysers that can measure water, MEG, pH stabiliser and dissolved salts will minimize these challenges and enable remote operations of the MEG systems. A Digitalization platform enabling condition monitoring and remote operations system to optimise performance and maintenance efforts on the MEG Regeneration and Reclamation Systems is being developed. The system collects digital input from sensors, analysers, instruments and controllers on the onshore or offshore assets to monitor system behaviour. The uniqueness of the approach to remote operations is our unparalleled process and chemistry expertise in combination with our in-house data science team to produce a system-wide view of the MEG Regeneration and Reclamation system. Current and historical data from MEG Regeneration system are ingested into the data platform, and through custom algorithms, provides full visualisation of the system performance and condition monitoring of critical components within the system. The operating conditions are characterized to reduce downtime and operating costs and maximise production. Online monitoring of the composition of rich- and lean MEG and formation water breakthrough can improve predictability of the scaling tendency and operation of the MEG plant. This can be achieved by having a qualified set of online analysers that can measure MEG, water and ionic composition online. With this enhanced visibility of the performance and predictive analysis, the need for site visits and troubleshooting efforts can be reduced and repeat failures and unplanned downtime can be prevented. The digitalization platform and work approach has already been successfully implemented on Sulphate Removal Units/Water Injection Technologies but are new to MEG systems. Qualification programs of critical parameters such as MEG content, chloride and divalent cation ion measurements are being carried out in parallel as part of the digitization efforts. Selected results from testing of online analysers and the key features from the digitalization platform are presented in this paper. An online analyser has been tested for simultaneously measuring MEG, water, organi
{"title":"Digitalized Next Generation Mono Ethylene Glycol Regeneration Systems","authors":"Salim Deshmukh, Tore Larsen, Shanta Seereeram","doi":"10.2523/iptc-19927-ms","DOIUrl":"https://doi.org/10.2523/iptc-19927-ms","url":null,"abstract":"\u0000 Offshore natural gas fields are normally developed based on multiphase flow. One of the key challenges for such flow lines may be the risk of gas hydrate formation. This risk can be mitigated by injecting Mono Ethylene Glycol (MEG) into the flow line as a thermodynamic hydrate inhibitor. Due to the large volumes of costly glycol required and the desire to minimise the environmental footprint, the glycol is regenerated on topside or onshore facilities. Presence of salts in the MEG systems make it more challenging to operate them and having full control over the chemistry within the MEG system is key to have successful operation. Today chemistry control within MEG system is largely done by manual sampling and lab analysis as online analysers are either not available or not qualified for the service. Having robust online analysers that can measure water, MEG, pH stabiliser and dissolved salts will minimize these challenges and enable remote operations of the MEG systems.\u0000 A Digitalization platform enabling condition monitoring and remote operations system to optimise performance and maintenance efforts on the MEG Regeneration and Reclamation Systems is being developed. The system collects digital input from sensors, analysers, instruments and controllers on the onshore or offshore assets to monitor system behaviour. The uniqueness of the approach to remote operations is our unparalleled process and chemistry expertise in combination with our in-house data science team to produce a system-wide view of the MEG Regeneration and Reclamation system. Current and historical data from MEG Regeneration system are ingested into the data platform, and through custom algorithms, provides full visualisation of the system performance and condition monitoring of critical components within the system. The operating conditions are characterized to reduce downtime and operating costs and maximise production.\u0000 Online monitoring of the composition of rich- and lean MEG and formation water breakthrough can improve predictability of the scaling tendency and operation of the MEG plant. This can be achieved by having a qualified set of online analysers that can measure MEG, water and ionic composition online. With this enhanced visibility of the performance and predictive analysis, the need for site visits and troubleshooting efforts can be reduced and repeat failures and unplanned downtime can be prevented.\u0000 The digitalization platform and work approach has already been successfully implemented on Sulphate Removal Units/Water Injection Technologies but are new to MEG systems. Qualification programs of critical parameters such as MEG content, chloride and divalent cation ion measurements are being carried out in parallel as part of the digitization efforts.\u0000 Selected results from testing of online analysers and the key features from the digitalization platform are presented in this paper.\u0000 An online analyser has been tested for simultaneously measuring MEG, water, organi","PeriodicalId":186916,"journal":{"name":"Day 3 Wed, November 11, 2020","volume":"100 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2020-01-13","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"121466458","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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