"Motivation is the catalysing ingredient for every successful innovation." Clayton Christensen. One of the pillars of project management is motivation. The success of any organisation rests on the ability of a leader to identify the motivation factors of a team and to encourage everyone to maintain positive thoughts and behaviour to achieve challenging targets successfully. This paper explains the practices implemented in the project that increased the motivation level of the team during the difficult and uncertain times of the oil downturn. This method consisted of three main phases. First, to conduct an initial survey to understand the motivation level of the team and identify the areas of improvement. Based on the results of the first phase, a master plan was created it to tackle the areas of improvement and lead the team to achieve the organisations annual objectives. To create the plan, it was necessary to identify the unique strengths and passions of every member of the team, address the need for recognition and strengthen the sense of belonging. After executing the master plan, a final survey was conducted to measure the success of the implementation. The results were outstanding in several areas. With the results of the final survey, it confirmed that the team's motivation level improved by 12%, and in some areas, such as recognition and belonging in 34%. Besides the statistics, the improvement in the motivation level resulted in a more creative team that was able to develop more than thirty operational initiatives that brought significant savings to the customer. All the challenging key performance objectives were achieved contributing to the company's business success. In conclusion, it was proven that even during the uncertain and challenging times of the oil industry, if we can keep our team motivated by reducing the weaknesses and building on top of the team's strengths, recognizing people's contribution to the company and showing them that their work clearly contributes to the business, and will always be possible to achieve even the most challenging targets. The approach is innovative in the sense that goes away from traditional financial incentive plans based on monetary rewards and looks at a deeper and more meaningful aspect of the human been regarding motivation. The methodology is based on Maslow's pyramid and Ikigai concept applied during the most challenging times in the oil industry; resulted in a boost in team motivation and overachievement of challenging key performance objectives.
{"title":"Project Management: Team Motivation, the Eye of the Storm","authors":"Cecilia Malagon Uribe, A. Ruzhnikov","doi":"10.2118/193039-MS","DOIUrl":"https://doi.org/10.2118/193039-MS","url":null,"abstract":"\u0000 \"Motivation is the catalysing ingredient for every successful innovation.\" Clayton Christensen.\u0000 One of the pillars of project management is motivation. The success of any organisation rests on the ability of a leader to identify the motivation factors of a team and to encourage everyone to maintain positive thoughts and behaviour to achieve challenging targets successfully.\u0000 This paper explains the practices implemented in the project that increased the motivation level of the team during the difficult and uncertain times of the oil downturn.\u0000 This method consisted of three main phases. First, to conduct an initial survey to understand the motivation level of the team and identify the areas of improvement. Based on the results of the first phase, a master plan was created it to tackle the areas of improvement and lead the team to achieve the organisations annual objectives. To create the plan, it was necessary to identify the unique strengths and passions of every member of the team, address the need for recognition and strengthen the sense of belonging.\u0000 After executing the master plan, a final survey was conducted to measure the success of the implementation.\u0000 The results were outstanding in several areas. With the results of the final survey, it confirmed that the team's motivation level improved by 12%, and in some areas, such as recognition and belonging in 34%. Besides the statistics, the improvement in the motivation level resulted in a more creative team that was able to develop more than thirty operational initiatives that brought significant savings to the customer. All the challenging key performance objectives were achieved contributing to the company's business success.\u0000 In conclusion, it was proven that even during the uncertain and challenging times of the oil industry, if we can keep our team motivated by reducing the weaknesses and building on top of the team's strengths, recognizing people's contribution to the company and showing them that their work clearly contributes to the business, and will always be possible to achieve even the most challenging targets.\u0000 The approach is innovative in the sense that goes away from traditional financial incentive plans based on monetary rewards and looks at a deeper and more meaningful aspect of the human been regarding motivation. The methodology is based on Maslow's pyramid and Ikigai concept applied during the most challenging times in the oil industry; resulted in a boost in team motivation and overachievement of challenging key performance objectives.","PeriodicalId":11014,"journal":{"name":"Day 1 Mon, November 12, 2018","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82083778","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}
Rudists are a group of strange shaped marine bivalves lived in the Tethys Ocean from the Late Jurassic to the Late Cretaceous. The rudist-bearing carbonates form a lot of oil and gas reservoirs in the Middle East. Therefore, the taxonomy, morphology, paleo-ecology of rudists is important to understand the rudist-bearing carbonate reservoir features for oil exploration and development. However, it is difficult to understand these characters of rudists because we can't collect whole rudist samples from the underground oil and gas reservoirs through core sample. X-ray CT is a useful method to visualize three dimensional rudist images with non-destruction of the core. Hence, X-ray CT has a potential to obtain the information of the taxonomy, morphology and depositional environment of rudists from core information. We conducted the X-ray CT scan to the reservoir formation (Formation A) of the Cenomanian age using core slab samples of Well #A and Well #B in the Abu Dhabi oil field. The some rudist fossils were observed on the cutting surfaces of slab cores in the both wells. However, the three dimensional morphology of rudists were not identified inside of the slab core. On the CT images, some autochthonous rudists were identified and it made the colony in Well #A. This rudist is standing position and suggesting original position of depositional environment from Cestari and Sartorio (1995). We demonstrated to be able to obtain the morphology from the slab cores with non-destruction using X-ray CT scan in this paper. Now we are challenging to make the high resolution 3D image modeling of rudists based on this X-ray CT result. This paper is summarized that usage method of the X-ray CT result to understand taxonomy/morphology and depositional environment from three dimensional position of rudists In addition, in the future technique, this paper suggested that combined technique between X-ray CT of core and FMI may reveal more comprehensive depositional setting such as direction of paleo ocean current and paleo wind in the future.
{"title":"Evaluation of Rudist Depositional Environment using X-ray CT Scan Late Cretaceous Cenomanian in Offshore Abu Dhabi","authors":"M. Yamanaka, Takashi Nanjo, T. Taniwaki","doi":"10.2118/192923-MS","DOIUrl":"https://doi.org/10.2118/192923-MS","url":null,"abstract":"\u0000 Rudists are a group of strange shaped marine bivalves lived in the Tethys Ocean from the Late Jurassic to the Late Cretaceous. The rudist-bearing carbonates form a lot of oil and gas reservoirs in the Middle East. Therefore, the taxonomy, morphology, paleo-ecology of rudists is important to understand the rudist-bearing carbonate reservoir features for oil exploration and development. However, it is difficult to understand these characters of rudists because we can't collect whole rudist samples from the underground oil and gas reservoirs through core sample. X-ray CT is a useful method to visualize three dimensional rudist images with non-destruction of the core. Hence, X-ray CT has a potential to obtain the information of the taxonomy, morphology and depositional environment of rudists from core information. We conducted the X-ray CT scan to the reservoir formation (Formation A) of the Cenomanian age using core slab samples of Well #A and Well #B in the Abu Dhabi oil field. The some rudist fossils were observed on the cutting surfaces of slab cores in the both wells. However, the three dimensional morphology of rudists were not identified inside of the slab core. On the CT images, some autochthonous rudists were identified and it made the colony in Well #A. This rudist is standing position and suggesting original position of depositional environment from Cestari and Sartorio (1995). We demonstrated to be able to obtain the morphology from the slab cores with non-destruction using X-ray CT scan in this paper. Now we are challenging to make the high resolution 3D image modeling of rudists based on this X-ray CT result. This paper is summarized that usage method of the X-ray CT result to understand taxonomy/morphology and depositional environment from three dimensional position of rudists In addition, in the future technique, this paper suggested that combined technique between X-ray CT of core and FMI may reveal more comprehensive depositional setting such as direction of paleo ocean current and paleo wind in the future.","PeriodicalId":11014,"journal":{"name":"Day 1 Mon, November 12, 2018","volume":"14 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87792447","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}
G. Chochua, A. Rudic, Amrendra Kumar, Aurélien Mainy, G. Woiceshyn
Horizontal wells are considered superior to vertical and deviated wells because they increase reservoir contact; however, they can cone unwanted fluids (gas, water) causing reduced oil recovery and early well abandonment. Inflow Control Devices (ICDs) are typically installed along the completion string to delay coning and restrict water/gas influx. Once the coning occurs, conventional ICDs, such as channels and orifices, were found to be inadequate in choking back the unwanted fluids. Thus, new types of "autonomous" ICDs, or AICDs, were developed that choke back unwanted fluids more than conventional ICDs. Conversely, such AICDs have limitations related to bulkiness, moving parts, wellsite adjustability, flow performance predictability, and erosion. To overcome these limitations, a new AICD, operating on a principle of a cyclone, was developed by a synergy of the latest numerical technologies, such as Computational Fluid Dynamics (CFD) utilizing a high-fidelity Large Eddy Simulation (LES) turbulence model, and Design of Experiments (DOE) techniques. This CFD-driven design optimization involved utilization of high-performance computing (HPC) coupled with experimental validation. A DOE matrix of CFD analyses runs was performed to identify a geometry that would generate significantly higher pressure drop for water and gas than for oil. Early multiphase testing on a prototype device validated the concept, and CFD was used to improve the understanding of the operating principle and hence the design. CFD was further used to extrapolate the flow performance to a wider range of operating conditions. An expanded flow performance map and the use of non-dimensional parameters led to the development of a mechanistic AICD performance model which further enhanced our understanding of AICDs and allowed reservoir software programs to evaluate the production performance of wells with AICDs versus wells with conventional ICDs or no inflow control. The overall result is the new cyclonic AICD presented herein which is: 1) relatively compact, 2) without moving parts, 3) erosion resistant, 4) superior in multiphase performance, 5) easily adjustable at the wellsite with many settings, 6) accurately modeled with CFD, and 7) easy to incorporate into state-of-the-art reservoir simulation models.
{"title":"Cyclone Type Autonomous Inflow Control Device for Water and Gas Control: Simulation-Driven Design","authors":"G. Chochua, A. Rudic, Amrendra Kumar, Aurélien Mainy, G. Woiceshyn","doi":"10.2118/192723-MS","DOIUrl":"https://doi.org/10.2118/192723-MS","url":null,"abstract":"\u0000 Horizontal wells are considered superior to vertical and deviated wells because they increase reservoir contact; however, they can cone unwanted fluids (gas, water) causing reduced oil recovery and early well abandonment. Inflow Control Devices (ICDs) are typically installed along the completion string to delay coning and restrict water/gas influx. Once the coning occurs, conventional ICDs, such as channels and orifices, were found to be inadequate in choking back the unwanted fluids. Thus, new types of \"autonomous\" ICDs, or AICDs, were developed that choke back unwanted fluids more than conventional ICDs. Conversely, such AICDs have limitations related to bulkiness, moving parts, wellsite adjustability, flow performance predictability, and erosion.\u0000 To overcome these limitations, a new AICD, operating on a principle of a cyclone, was developed by a synergy of the latest numerical technologies, such as Computational Fluid Dynamics (CFD) utilizing a high-fidelity Large Eddy Simulation (LES) turbulence model, and Design of Experiments (DOE) techniques. This CFD-driven design optimization involved utilization of high-performance computing (HPC) coupled with experimental validation. A DOE matrix of CFD analyses runs was performed to identify a geometry that would generate significantly higher pressure drop for water and gas than for oil.\u0000 Early multiphase testing on a prototype device validated the concept, and CFD was used to improve the understanding of the operating principle and hence the design. CFD was further used to extrapolate the flow performance to a wider range of operating conditions. An expanded flow performance map and the use of non-dimensional parameters led to the development of a mechanistic AICD performance model which further enhanced our understanding of AICDs and allowed reservoir software programs to evaluate the production performance of wells with AICDs versus wells with conventional ICDs or no inflow control. The overall result is the new cyclonic AICD presented herein which is: 1) relatively compact, 2) without moving parts, 3) erosion resistant, 4) superior in multiphase performance, 5) easily adjustable at the wellsite with many settings, 6) accurately modeled with CFD, and 7) easy to incorporate into state-of-the-art reservoir simulation models.","PeriodicalId":11014,"journal":{"name":"Day 1 Mon, November 12, 2018","volume":"13 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88055066","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. Abdel-hakim, Mohamed Abdel Azeem, F. Bransby, H. Low, Romain Clavaud, Bryan Bergkamp, Janardanan Kizhikkilod
The objective of this paper is to demonstrate the potential benefit of using site- and project-specific pipe-soil interaction (PSI) inputs in HTHP pipeline design. The paper first explains the overall approach used to generate site-specific PSI inputs to pipelines. This includes showing the importance of site investigation (geophysics, in situ testing and sampling) and onshore lab testing which should be integrated to select appropriate seabed parameter ranges for the derivation of site-specific PSI inputs. Then, the importance of using geotechnical calculation methods which consider the unique properties of carbonate soils to calculate pipeline friction factors is discussed. Finally, the paper demonstrates, for a regional case study, how the provided PSI inputs changed pipeline design and reduced project costs.
{"title":"Cost Savings for Subsea Pipelines Using Enhanced Pipe-Soil Interaction Assessment","authors":"M. Abdel-hakim, Mohamed Abdel Azeem, F. Bransby, H. Low, Romain Clavaud, Bryan Bergkamp, Janardanan Kizhikkilod","doi":"10.2118/192997-MS","DOIUrl":"https://doi.org/10.2118/192997-MS","url":null,"abstract":"\u0000 The objective of this paper is to demonstrate the potential benefit of using site- and project-specific pipe-soil interaction (PSI) inputs in HTHP pipeline design. The paper first explains the overall approach used to generate site-specific PSI inputs to pipelines. This includes showing the importance of site investigation (geophysics, in situ testing and sampling) and onshore lab testing which should be integrated to select appropriate seabed parameter ranges for the derivation of site-specific PSI inputs. Then, the importance of using geotechnical calculation methods which consider the unique properties of carbonate soils to calculate pipeline friction factors is discussed. Finally, the paper demonstrates, for a regional case study, how the provided PSI inputs changed pipeline design and reduced project costs.","PeriodicalId":11014,"journal":{"name":"Day 1 Mon, November 12, 2018","volume":"45 1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82722570","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}
P. Dhote, M. Al-Bahar, A. Cole, A. Al-Sane, A. Bora, Ashique Sreenivasan
Residual Oil Zones (ROZs) are an area of incrasing attention from hydrocarbon E&P industry with ever depleting reserves in known oil accumulations and advent of Carbon Dioxide (CO2) Capture and Storage needs and technology. ROZ can serve as viable solution to both the future problems as a possible vast new oil resource and a prospect for reducing carbon emission. ROZs can be defined as thick pile of low-quality reservoir rock below traditional oil-water contact with about residual oil saturations of mainly irreducible oil resulting from the natural flushing of reservoir due to buoying forces and aquifer action in geological past in earlier oil-filled part of reservoir. The production of oil from ROZs from such reservoirs is technically and economicaly feasible through application of enhanced oil recovery techniques - largely through missible CO2 flooding/injection in the zone because of the nature of fluid and reservoir rock. The depostional and tectonic regime in the Kuwait Petroliferous Basins is investigated to demonstrate the occurrence of and independently assess ROZ potential. The understanding of Kuwait Petroliferous Basin indicates that ROZs might be developed by hydrodynamic actions associated with tectonic regime. The degradation of oil by water action and related increase of sulfur content of crude oil can be used as workable proxy for identification ROZ potential of the rerservoir. The regional mapping, understanding of tectionic history and regional systhesis of crude oil composition shows an extensive stratigraphic and lateral existence of ROZ potential across the Kuwait Petroliferous Basin. This study aims to provide strategic roadmap and detail data acquisition program that will reveal ROZ production potential in Kuwait for Kuwait Oil Company (KOC).
{"title":"Producing from Residual Oil Zone ROZ: Concept and Strategy for Kuwait","authors":"P. Dhote, M. Al-Bahar, A. Cole, A. Al-Sane, A. Bora, Ashique Sreenivasan","doi":"10.2118/193001-MS","DOIUrl":"https://doi.org/10.2118/193001-MS","url":null,"abstract":"\u0000 Residual Oil Zones (ROZs) are an area of incrasing attention from hydrocarbon E&P industry with ever depleting reserves in known oil accumulations and advent of Carbon Dioxide (CO2) Capture and Storage needs and technology. ROZ can serve as viable solution to both the future problems as a possible vast new oil resource and a prospect for reducing carbon emission. ROZs can be defined as thick pile of low-quality reservoir rock below traditional oil-water contact with about residual oil saturations of mainly irreducible oil resulting from the natural flushing of reservoir due to buoying forces and aquifer action in geological past in earlier oil-filled part of reservoir. The production of oil from ROZs from such reservoirs is technically and economicaly feasible through application of enhanced oil recovery techniques - largely through missible CO2 flooding/injection in the zone because of the nature of fluid and reservoir rock. The depostional and tectonic regime in the Kuwait Petroliferous Basins is investigated to demonstrate the occurrence of and independently assess ROZ potential. The understanding of Kuwait Petroliferous Basin indicates that ROZs might be developed by hydrodynamic actions associated with tectonic regime. The degradation of oil by water action and related increase of sulfur content of crude oil can be used as workable proxy for identification ROZ potential of the rerservoir. The regional mapping, understanding of tectionic history and regional systhesis of crude oil composition shows an extensive stratigraphic and lateral existence of ROZ potential across the Kuwait Petroliferous Basin.\u0000 This study aims to provide strategic roadmap and detail data acquisition program that will reveal ROZ production potential in Kuwait for Kuwait Oil Company (KOC).","PeriodicalId":11014,"journal":{"name":"Day 1 Mon, November 12, 2018","volume":"15 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90347331","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}
EPCC for the Suhar Refinery Improvement Project in Oman The Suhar Refinery Improvement Project is one of the largest oil and gas projects ever awarded in Oman. Valued at US$ 2.1 billion, this was truly a ‘mega project in region’ and was executed by Petrofac in Joint Venture with Daelim and successfully completed in 2017. Petrofac and Daelim provided a turnkey Engineering, Procurement and Construction and Commissioning (EPCC) solution, which involved upgrades and improvements at the existing facility as well as the addition of new refining units. Delivered through a lump-sum turnkey model, Petrofac leveraged more than three decades of EPC expertise in Oman to shape its local delivery and reduce supply chain costs. Petrofac formed an integrated team with its partner Daelim, the client and JV partners to create a seamless approach, this included a focus group initiative toward flawless start-up as well as the utilisation of common systems, procedures and processes. On completion Sohar's existing output increased by more than 70% to exceed 185,000 barrels per day as well as significantly improving environmental performance. The project's safety performance was exemplary, achieving more than 53 million man-hours without a lost time incident, with a peak project manpower of 14,000. The creation of In-Country Value (ICV) was a guiding principle throughout, involving the training and development of Omani nationals and the support of local supply chains. The Suhar Refinery Improvement Project was on the winning nomination list that aided ORPIC to win the ICV Strategy Award in 2016. Resourcing was a critical component of the project both in terms of manpower levels required and the drive towards ICV. This paper aims to showcase the ability of major contractors to work in unison, sharing knowledge and capabilities, to reduce the challenges faced in the execution of mega projects; as well as the role of local content in successful implementation of major projects enabling the development of a capable local workforce.
{"title":"Challenges of Gas and Oil Mega-Projects: Suhar Refinery","authors":"S. Kalyanam","doi":"10.2118/192768-MS","DOIUrl":"https://doi.org/10.2118/192768-MS","url":null,"abstract":"\u0000 EPCC for the Suhar Refinery Improvement Project in Oman\u0000 \u0000 \u0000 The Suhar Refinery Improvement Project is one of the largest oil and gas projects ever awarded in Oman. Valued at US$ 2.1 billion, this was truly a ‘mega project in region’ and was executed by Petrofac in Joint Venture with Daelim and successfully completed in 2017.\u0000 \u0000 \u0000 \u0000 Petrofac and Daelim provided a turnkey Engineering, Procurement and Construction and Commissioning (EPCC) solution, which involved upgrades and improvements at the existing facility as well as the addition of new refining units. Delivered through a lump-sum turnkey model, Petrofac leveraged more than three decades of EPC expertise in Oman to shape its local delivery and reduce supply chain costs. Petrofac formed an integrated team with its partner Daelim, the client and JV partners to create a seamless approach, this included a focus group initiative toward flawless start-up as well as the utilisation of common systems, procedures and processes.\u0000 \u0000 \u0000 \u0000 On completion Sohar's existing output increased by more than 70% to exceed 185,000 barrels per day as well as significantly improving environmental performance. The project's safety performance was exemplary, achieving more than 53 million man-hours without a lost time incident, with a peak project manpower of 14,000.\u0000 The creation of In-Country Value (ICV) was a guiding principle throughout, involving the training and development of Omani nationals and the support of local supply chains. The Suhar Refinery Improvement Project was on the winning nomination list that aided ORPIC to win the ICV Strategy Award in 2016. Resourcing was a critical component of the project both in terms of manpower levels required and the drive towards ICV.\u0000 \u0000 \u0000 \u0000 This paper aims to showcase the ability of major contractors to work in unison, sharing knowledge and capabilities, to reduce the challenges faced in the execution of mega projects; as well as the role of local content in successful implementation of major projects enabling the development of a capable local workforce.\u0000","PeriodicalId":11014,"journal":{"name":"Day 1 Mon, November 12, 2018","volume":"80 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83051586","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}
As more oil and gas companies develop Internet of Things (IoT) strategies and beginning their digital transformation to Industry 4.0 or Smart Manufacturing, they face challenges in adopting technologies due to regulatory restrictions for highly combustible atmospheres such as exist in some of the world's largest and most critical industries - oil & gas, chemical, pharmaceutical, energy and others. In Zone 1 classified hazardous areas worldwide, up to 15% of personnel do not have access to mobile computing devices unless they are certified "intrinsically safe," or incapable of causing a spark that could ignite a combustible environment. Thus, the human "sensor" in hazardous area operations, who could conceivably detect perceived anomalies or problems in the maintenance, workflow, process or function of these operations, is relegated to recording observations with pencil and paper and then entering data manually into ERP systems hours or days later. Such lack of real-time communication and data management results in inefficiency, increased costs and elevated safety and asset risk, causing potential down-time and even loss of life in extreme cases. By deploying new IoT technologies that allow people to use technology inside Zone 1 hazardous areas, humans can actively interact with machines in real time to dramatically improve productivity, safety and the bottom line in hazardous operations. A new style of IoT platform built especially for oil & gas hazardous area operations, would need to include various and affordable types of sensors to cover vast spaces, real-time communications, cloud computing, machine learning, rights management, security, big data storage, analytics and user-friendly visualization, all functioning in highly explosive conditions. This paper considers the advantages for productivity and safety of an IoT Platform for Hazardous Locations, based on hands-on research conducted by AegexTechnologies, Verizon, Nokia and multiple technology partners that tested various edge technologies with first responders in realistic disaster scenarios during two annual events, Operation Convergent Response 2017 (#OCR2017) and Operation Convergent Response 2018 (#OCR2018 – to take place 5-8 November 2018)). The events provide unparalleled opportunities to test IoTunder extreme conditions with real people, such as a staged refinery collapse caused by an earthquake. #OCR2017 and #OCR2018 showed how enabling real-time communications and data management via cutting-edge technologies, such as intrinsically safe tablets and IoT sensors, can strategically assist first responders to better handle emergencies. The studies’ results give insight into the need for continued collaboration on IoT capabilities that can better manage not only emergency response, but everyday operations in hazardous industries such as oil and gas. Equipping oil and gas facilities with pervasive, smart IoT data-sensing capabilities, and equipping oil and g
{"title":"Enabling the Best by Preparing for the Worst: Lessons from Disaster Response for Industrial IoT in Oil and Gas","authors":"Thomas P. Ventulett, Leigh M. Villegas","doi":"10.2118/192614-MS","DOIUrl":"https://doi.org/10.2118/192614-MS","url":null,"abstract":"\u0000 \u0000 \u0000 As more oil and gas companies develop Internet of Things (IoT) strategies and beginning their digital transformation to Industry 4.0 or Smart Manufacturing, they face challenges in adopting technologies due to regulatory restrictions for highly combustible atmospheres such as exist in some of the world's largest and most critical industries - oil & gas, chemical, pharmaceutical, energy and others. In Zone 1 classified hazardous areas worldwide, up to 15% of personnel do not have access to mobile computing devices unless they are certified \"intrinsically safe,\" or incapable of causing a spark that could ignite a combustible environment. Thus, the human \"sensor\" in hazardous area operations, who could conceivably detect perceived anomalies or problems in the maintenance, workflow, process or function of these operations, is relegated to recording observations with pencil and paper and then entering data manually into ERP systems hours or days later. Such lack of real-time communication and data management results in inefficiency, increased costs and elevated safety and asset risk, causing potential down-time and even loss of life in extreme cases.\u0000 \u0000 \u0000 \u0000 By deploying new IoT technologies that allow people to use technology inside Zone 1 hazardous areas, humans can actively interact with machines in real time to dramatically improve productivity, safety and the bottom line in hazardous operations. A new style of IoT platform built especially for oil & gas hazardous area operations, would need to include various and affordable types of sensors to cover vast spaces, real-time communications, cloud computing, machine learning, rights management, security, big data storage, analytics and user-friendly visualization, all functioning in highly explosive conditions. This paper considers the advantages for productivity and safety of an IoT Platform for Hazardous Locations, based on hands-on research conducted by AegexTechnologies, Verizon, Nokia and multiple technology partners that tested various edge technologies with first responders in realistic disaster scenarios during two annual events, Operation Convergent Response 2017 (#OCR2017) and Operation Convergent Response 2018 (#OCR2018 – to take place 5-8 November 2018)). The events provide unparalleled opportunities to test IoTunder extreme conditions with real people, such as a staged refinery collapse caused by an earthquake.\u0000 \u0000 \u0000 \u0000 #OCR2017 and #OCR2018 showed how enabling real-time communications and data management via cutting-edge technologies, such as intrinsically safe tablets and IoT sensors, can strategically assist first responders to better handle emergencies. The studies’ results give insight into the need for continued collaboration on IoT capabilities that can better manage not only emergency response, but everyday operations in hazardous industries such as oil and gas.\u0000 \u0000 \u0000 \u0000 Equipping oil and gas facilities with pervasive, smart IoT data-sensing capabilities, and equipping oil and g","PeriodicalId":11014,"journal":{"name":"Day 1 Mon, November 12, 2018","volume":"31 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83096788","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}
Khalfan Al-Dhanhani, Sudhesh .K. Govindavilas, J. C. Palmer, Hisham Al-Mukhmari, Mahdi Mohamed Al-Marzooqi, T. Al-Sayed
ADNOC Offshore operates more than 1300+ numbers of oil, gas and water offshore wells of age 59 years on wards, at 300+ well head platforms located in shallow to intermediate water depth of 7m-34m for various fields. Well conductors being outer pipes of the well construction, its functionality is to resist various combined axial and bending forces acting on it. Also, conductors to be effective in transferring loads through the cement bond / skin friction to the surrounding soil/rock layers with sufficient factor of safety. Offshore well conductors were originally installed as bare steel without coating. Therefore, splash zone and atmospheric zone of the conductor is directly exposed corrosion. Fully submerged and buried part of conductor the is protected from external corrosion from jacket cathodic protection system. Some conductor's annuli are without proper cement top-up or poor cement (above sea-bed to top X-mas tree flange). Seventy percent of them have exceeded the original design life of 30 years and require life extension for extra 50+ years, since oil and gas reservoirs will be having active production potential. Methods, Procedures, Process: Above water baseline visual inspection of all well conductors were conducted to compile as-built data, coating, corrosion, inspection / breathing windows status by setting up the anomaly acceptance criteria. After the assessment of baseline inspection data, scheduled the detailed inspection plans were prioritized using NDT- ultrasonic testing (UT) or Advanced NDT technique. Structural assessment of the well conductor is carried out for axial load, internal bending moment due to internal casing and external bending moment due to environmental load. Minimum Required Thickness (MRT) is worked out to resist the combined axial and bending moment. Using MRT, Current Average Thickness (CAT) and Corrosion Rate (CR), current risk, the remaining life and mitigation plan were communicated through conductor passport Results, Observations, Conclusions: Systematic inspection criteria and strategy was set up to prioritize the inspection of all well conductors. Sixty percent of well conductors are found with open inspection windows on the conductor's surface or on the conductor flange, to monitor the internal cement level during drilling of the wells. The resulting moisture and air entry into the conductor annulus caused internal pitted corrosion in the atmospheric zone of the conductor. The local area thinning of the conductor reduced its axial, bending, buckling strength and will lead to collapse of the conductor. From HSE considerations, the affected well conductor require immediate intervention and this will involve major repair cost, production loss due to unplanned shut down of the well head tower. Novel/Additive Information: Detailed inspections of critical 126 well conductors were carried out using magnetic crawler mounted Saturated Low Frequency Eddy Current (SLOFEC) and Magnetic Eddy Current (MEC) meth
{"title":"Aging Offshore well Conductors Structural Integrity Issues and Challenges in their Life Extension","authors":"Khalfan Al-Dhanhani, Sudhesh .K. Govindavilas, J. C. Palmer, Hisham Al-Mukhmari, Mahdi Mohamed Al-Marzooqi, T. Al-Sayed","doi":"10.2118/192795-MS","DOIUrl":"https://doi.org/10.2118/192795-MS","url":null,"abstract":"\u0000 ADNOC Offshore operates more than 1300+ numbers of oil, gas and water offshore wells of age 59 years on wards, at 300+ well head platforms located in shallow to intermediate water depth of 7m-34m for various fields. Well conductors being outer pipes of the well construction, its functionality is to resist various combined axial and bending forces acting on it. Also, conductors to be effective in transferring loads through the cement bond / skin friction to the surrounding soil/rock layers with sufficient factor of safety. Offshore well conductors were originally installed as bare steel without coating. Therefore, splash zone and atmospheric zone of the conductor is directly exposed corrosion. Fully submerged and buried part of conductor the is protected from external corrosion from jacket cathodic protection system. Some conductor's annuli are without proper cement top-up or poor cement (above sea-bed to top X-mas tree flange). Seventy percent of them have exceeded the original design life of 30 years and require life extension for extra 50+ years, since oil and gas reservoirs will be having active production potential.\u0000 Methods, Procedures, Process: Above water baseline visual inspection of all well conductors were conducted to compile as-built data, coating, corrosion, inspection / breathing windows status by setting up the anomaly acceptance criteria. After the assessment of baseline inspection data, scheduled the detailed inspection plans were prioritized using NDT- ultrasonic testing (UT) or Advanced NDT technique. Structural assessment of the well conductor is carried out for axial load, internal bending moment due to internal casing and external bending moment due to environmental load. Minimum Required Thickness (MRT) is worked out to resist the combined axial and bending moment. Using MRT, Current Average Thickness (CAT) and Corrosion Rate (CR), current risk, the remaining life and mitigation plan were communicated through conductor passport\u0000 Results, Observations, Conclusions: Systematic inspection criteria and strategy was set up to prioritize the inspection of all well conductors. Sixty percent of well conductors are found with open inspection windows on the conductor's surface or on the conductor flange, to monitor the internal cement level during drilling of the wells. The resulting moisture and air entry into the conductor annulus caused internal pitted corrosion in the atmospheric zone of the conductor. The local area thinning of the conductor reduced its axial, bending, buckling strength and will lead to collapse of the conductor. From HSE considerations, the affected well conductor require immediate intervention and this will involve major repair cost, production loss due to unplanned shut down of the well head tower.\u0000 Novel/Additive Information: Detailed inspections of critical 126 well conductors were carried out using magnetic crawler mounted Saturated Low Frequency Eddy Current (SLOFEC) and Magnetic Eddy Current (MEC) meth","PeriodicalId":11014,"journal":{"name":"Day 1 Mon, November 12, 2018","volume":"8 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91257126","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}
Geomechanical modeling of hydraulic fracturing in deep gas reservoirs in Oman is complicated by high uncertainties in key parameters. This study aims to adopt a physics-based data analytics technique to model geomechanical behavior of rocks. The paper also presents the methodology of linking geomechanics with well performance. Finally, the integration of the results into a decision support system is discussed. The majority of deep gas reservoirs in Oman are tight. The permeabilities are in the sub-millidarcy range. Hydraulic fracturing helps to unlock the reserves. Meanwhile, proper hydrofracture design is required to optimize the development of these complex reservoirs. Due to high stresses, unclear processes governing hydrofracture propagation, and complex depositional and diagenetic histories, the applicability of standard hydrofracture modeling techniques becomes questionable. Proper surveillance design and in-depth analysis of the monitoring data assist in testing the range of applicability of the modeling tools. The analysis also aids in characterizing the influence of the processes not captured within the models. Recently the development of deep gas reservoirs in Oman started to benefit from horizontal well technology. Similarly to other horizontal developments, the question of proper well architechture and stimulation design was raised. In this study, the data pertaining to historical vertical wells was collated to understand the processes governing hydrofracture placement. The data indicated the presence of strong fracture barriers and of highly stressed zones which affect the ability to create sufficient fracture conductivity. Further, geomechanical models were calibrated to allow for realistic estimate of the contact area between the fracture and reservoir. Analysis of the production data indicated that productivity was often limited by the factors not captured in the models (e.g., suboptimal cleanup). For proper planning, risk factors may be chosen to reflect the loss of productivity. In the next step, the learnings from the vertical wells served for characterizing hydrofracturing in horizontals. Analysis of the data indicated that due to near-wellbore complexity and choking effect the productivity of an individual fracture in a horizontal well was only a fraction of that in a vertical well. As a final step all the data along with their interpretation are being incorporated into the library of hydrofracture scenarios. Future development will rely on searching for the analogs and selecting a design fitting all applicable scenarios. The paper presents an overview of the surveillance data analysis. The results of the analysis allow for creating a library of the development scenarios, which serve as a basis for a decision support system aimed at streamlining hydrofracture and well planning design.
{"title":"Integrating Geomechanical Modeling and Production Data for Decision Support in Deep Gas Reservoirs in Oman","authors":"A. Dobroskok, Ruqaiya Al Zadjali","doi":"10.2118/193235-MS","DOIUrl":"https://doi.org/10.2118/193235-MS","url":null,"abstract":"\u0000 Geomechanical modeling of hydraulic fracturing in deep gas reservoirs in Oman is complicated by high uncertainties in key parameters. This study aims to adopt a physics-based data analytics technique to model geomechanical behavior of rocks. The paper also presents the methodology of linking geomechanics with well performance. Finally, the integration of the results into a decision support system is discussed.\u0000 The majority of deep gas reservoirs in Oman are tight. The permeabilities are in the sub-millidarcy range. Hydraulic fracturing helps to unlock the reserves. Meanwhile, proper hydrofracture design is required to optimize the development of these complex reservoirs. Due to high stresses, unclear processes governing hydrofracture propagation, and complex depositional and diagenetic histories, the applicability of standard hydrofracture modeling techniques becomes questionable. Proper surveillance design and in-depth analysis of the monitoring data assist in testing the range of applicability of the modeling tools. The analysis also aids in characterizing the influence of the processes not captured within the models.\u0000 Recently the development of deep gas reservoirs in Oman started to benefit from horizontal well technology. Similarly to other horizontal developments, the question of proper well architechture and stimulation design was raised. In this study, the data pertaining to historical vertical wells was collated to understand the processes governing hydrofracture placement. The data indicated the presence of strong fracture barriers and of highly stressed zones which affect the ability to create sufficient fracture conductivity. Further, geomechanical models were calibrated to allow for realistic estimate of the contact area between the fracture and reservoir. Analysis of the production data indicated that productivity was often limited by the factors not captured in the models (e.g., suboptimal cleanup). For proper planning, risk factors may be chosen to reflect the loss of productivity. In the next step, the learnings from the vertical wells served for characterizing hydrofracturing in horizontals. Analysis of the data indicated that due to near-wellbore complexity and choking effect the productivity of an individual fracture in a horizontal well was only a fraction of that in a vertical well. As a final step all the data along with their interpretation are being incorporated into the library of hydrofracture scenarios. Future development will rely on searching for the analogs and selecting a design fitting all applicable scenarios. The paper presents an overview of the surveillance data analysis. The results of the analysis allow for creating a library of the development scenarios, which serve as a basis for a decision support system aimed at streamlining hydrofracture and well planning design.","PeriodicalId":11014,"journal":{"name":"Day 1 Mon, November 12, 2018","volume":"176 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76654096","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}
R. Heidorn, H. Salem, Salim Shuaili, A. Khattak, C. Pentland
The Eastern Flank part of the South Oman Salt Basin of the Sultanate of Oman is an important area for Oman's overall oil production. The fields are largely controlled by deep seated reactivated Neoproterozoic faults and halokinesis of the Infra-Cambrian Ara Group responsible for rich varieties of complex structural styles which have direct impact on field performance and development. The fidelity of newer seismic, the ever increasing information from wells and better integration of various data sets of different disciplines allow new insights into the unlocking of remaining hydrocarbons within existing fields and within near field exploration opportunities. The South Oman Salt Basin is subdivided into four NE-trending salt-related structural domains based on the type of salt withdrawal minibasins present. The Eastern Flank is located within structural domain I. Domain I represents the area where evaporites have been initially present, but have been subsequently removed by salt-dissolution and salt evacuation. The dominant structure style is the ‘mini turtle back structure', which shows a diverse structural architecture and is systematically classified based on structure- and fault architecture. Domain II is the zone of the large inverted salt withdrawal minibasin or turtle back structure which is located at the salt edge of the basin with evaporite presence in the subsurface. The structural style of a large turtle back structure shows complexities within the core of the structure and within the surrounding rim related to inversion and truncation of the Carboniferous and Permian reservoirs. This is reflected by the various development scenarios related to simple and complex cores as well as to simple and complex rims. Fault compartmentalization has a strong impact on field performance within domain I and II, thus several types of faults are established based on fault architecture and location within the structure. The systematic classification of structural styles and faults allow the establishment of analogues, which are in particular valuable for seismically poorly imaged areas. A new tool captures and centralizes the structural data, as well as a large range of other data sets within the production and geoscience environment from over 60 fields with the aim to make more consistent and better as well as quicker decisions related to field development planning.
{"title":"Recent Advances in the Understanding of the Salt Tectonic Evolution of the Eastern Flank at Regional and Field Scale and its Relationship to the South Oman Salt Basin of the Sultanate of Oman","authors":"R. Heidorn, H. Salem, Salim Shuaili, A. Khattak, C. Pentland","doi":"10.2118/192611-MS","DOIUrl":"https://doi.org/10.2118/192611-MS","url":null,"abstract":"\u0000 The Eastern Flank part of the South Oman Salt Basin of the Sultanate of Oman is an important area for Oman's overall oil production. The fields are largely controlled by deep seated reactivated Neoproterozoic faults and halokinesis of the Infra-Cambrian Ara Group responsible for rich varieties of complex structural styles which have direct impact on field performance and development. The fidelity of newer seismic, the ever increasing information from wells and better integration of various data sets of different disciplines allow new insights into the unlocking of remaining hydrocarbons within existing fields and within near field exploration opportunities.\u0000 The South Oman Salt Basin is subdivided into four NE-trending salt-related structural domains based on the type of salt withdrawal minibasins present. The Eastern Flank is located within structural domain I. Domain I represents the area where evaporites have been initially present, but have been subsequently removed by salt-dissolution and salt evacuation. The dominant structure style is the ‘mini turtle back structure', which shows a diverse structural architecture and is systematically classified based on structure- and fault architecture. Domain II is the zone of the large inverted salt withdrawal minibasin or turtle back structure which is located at the salt edge of the basin with evaporite presence in the subsurface. The structural style of a large turtle back structure shows complexities within the core of the structure and within the surrounding rim related to inversion and truncation of the Carboniferous and Permian reservoirs. This is reflected by the various development scenarios related to simple and complex cores as well as to simple and complex rims. Fault compartmentalization has a strong impact on field performance within domain I and II, thus several types of faults are established based on fault architecture and location within the structure. The systematic classification of structural styles and faults allow the establishment of analogues, which are in particular valuable for seismically poorly imaged areas. A new tool captures and centralizes the structural data, as well as a large range of other data sets within the production and geoscience environment from over 60 fields with the aim to make more consistent and better as well as quicker decisions related to field development planning.","PeriodicalId":11014,"journal":{"name":"Day 1 Mon, November 12, 2018","volume":"22 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78053783","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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