B. Dow, Suzett Urbano, Freddy Rojas Rodriguez, Chiradeep Gupta
It is clear the global energy shift toward sustainability is underway. Sentiment is demanding low-carbon energy pursuit at a rate that will require significant investment of infrastructure metamorphosis, while opening new environmental risks that have yet to be determined. For example, electricity storage and transport on the scale required for full conversion away from hydrocarbons would require raw materials sourced in manners that remain ecologically challenging. The oil and gas industry is executing a transformation toward sustainably sourced energy in preparation for this shift. These efforts vary across industry stakeholders, but they are focused on visibly transformative change. However, there remains opportunity to participate in the classic energy supply with a better view toward sustainability by applying technologies that deliver these outcomes. The first important step, however, is to apply the correct key performance objectives (KPOs) and begin measuring the impact of executing with sustainability in mind. This paper will focus in on one drilling technique, managed pressure drilling (MPD), and outline sustainability KPOs applied on case study projects around the world. Classic drilling focuses on performance metrics of time and cost. These metrics, in and of themselves, represent "sustainability" in a sense, but typically are not viewed in that light. Application of MPD, consequently, is weighed with the same. Suppose, however, MPD was evaluated not only on performance KPOs, but also sustainability KPOs. MPD is capable of containment of reservoir fluid and pressure, reduction of drilling fluids and weighting materials, reduction of human energy through applied automation and remote operations, and extension of fields and drilling assets. Packaging and deployment technologies can also reduce emissions during mobilization, execution and demobilization. The work will present a means of defining and measuring the sustainability impact against conventional drilling applications and serve as a roadmap to start the conversation on how the oil and gas industry can make better use of technologies readily available to sustainably deliver oil and gas to the world throughout the energy transition. The primary consumer of energy, the automobile industry, focus significant efforts on fuel efficiency as a KPO. The drilling industry can facilitate a similar shift.
{"title":"Sustainability Metrics for Managed Pressure Drilling","authors":"B. Dow, Suzett Urbano, Freddy Rojas Rodriguez, Chiradeep Gupta","doi":"10.2523/iptc-21986-ms","DOIUrl":"https://doi.org/10.2523/iptc-21986-ms","url":null,"abstract":"\u0000 It is clear the global energy shift toward sustainability is underway. Sentiment is demanding low-carbon energy pursuit at a rate that will require significant investment of infrastructure metamorphosis, while opening new environmental risks that have yet to be determined. For example, electricity storage and transport on the scale required for full conversion away from hydrocarbons would require raw materials sourced in manners that remain ecologically challenging. The oil and gas industry is executing a transformation toward sustainably sourced energy in preparation for this shift. These efforts vary across industry stakeholders, but they are focused on visibly transformative change. However, there remains opportunity to participate in the classic energy supply with a better view toward sustainability by applying technologies that deliver these outcomes. The first important step, however, is to apply the correct key performance objectives (KPOs) and begin measuring the impact of executing with sustainability in mind. This paper will focus in on one drilling technique, managed pressure drilling (MPD), and outline sustainability KPOs applied on case study projects around the world. Classic drilling focuses on performance metrics of time and cost. These metrics, in and of themselves, represent \"sustainability\" in a sense, but typically are not viewed in that light. Application of MPD, consequently, is weighed with the same. Suppose, however, MPD was evaluated not only on performance KPOs, but also sustainability KPOs. MPD is capable of containment of reservoir fluid and pressure, reduction of drilling fluids and weighting materials, reduction of human energy through applied automation and remote operations, and extension of fields and drilling assets. Packaging and deployment technologies can also reduce emissions during mobilization, execution and demobilization.\u0000 The work will present a means of defining and measuring the sustainability impact against conventional drilling applications and serve as a roadmap to start the conversation on how the oil and gas industry can make better use of technologies readily available to sustainably deliver oil and gas to the world throughout the energy transition.\u0000 The primary consumer of energy, the automobile industry, focus significant efforts on fuel efficiency as a KPO. The drilling industry can facilitate a similar shift.","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80210971","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. Sarma, J. Rafiee, F. Gutiérrez, C. Calad, Ryan Hilliard, Sebastian Plotno, E. Mamani, O. Angulo, Gabriel Quintero
As the oil and gas industry embarks on the path to energy transition, pressure from government regulators, investors, and the public in general demand that companies have clear and transparent net-zero goals and that their operational initiatives and plans support such transition efforts. Mature fields present an opportunity to increase production through operational optimization, which at the same time, can also lead to greenhouse gas (GHG) emissions efficiency. This paper presents the application of a novel modeling and optimization technique in a mature waterflood environment. Data Physics is the amalgamation of the state-of-the-art in machine learning and the same underlying physics present in reservoir simulators. These models can be created as efficiently as machine learning models, integrate all kinds of data, and can be evaluated orders of magnitude faster than full scale simulation models, and since they include similar underlying physics as simulators, they have good long term predictive capacity and can even be used to predict performance of new wells without any historical data. The technology was applied to a mature field in the Neuquen basin in Argentina to effectively reduce the amount of water injected into the reservoir with no negative impact on the production. Additionally, a new Carbon Intensity (CI) modeling tool was used to compare the emissions intensity before and after optimization showing a significant improvement in CI achieving three objectives in one single decision: 1) obtain significant water injection reduction with its corresponding impact in injection and water treatment costs; 2) maintaining production compared to the initial decline of the field, improving the top line; and 3) improving the GHG emissions intensity hence the long term benefit to the environment. The paper deals more with the implementation of the technologies than the technologies themselves, assuming that readers unfamiliar with both Data Physics and Carbon Intensity tools will refer to the references section to gain familiarity with these.
{"title":"Optimizing a Waterflood Using a Combination of Machine Learning and Reservoir Physics. A Field Application for Reducing Fresh Water Injection with no Impact on Oil Production and Improved Carbon Intensity","authors":"P. Sarma, J. Rafiee, F. Gutiérrez, C. Calad, Ryan Hilliard, Sebastian Plotno, E. Mamani, O. Angulo, Gabriel Quintero","doi":"10.2523/iptc-22406-ea","DOIUrl":"https://doi.org/10.2523/iptc-22406-ea","url":null,"abstract":"\u0000 As the oil and gas industry embarks on the path to energy transition, pressure from government regulators, investors, and the public in general demand that companies have clear and transparent net-zero goals and that their operational initiatives and plans support such transition efforts. Mature fields present an opportunity to increase production through operational optimization, which at the same time, can also lead to greenhouse gas (GHG) emissions efficiency.\u0000 This paper presents the application of a novel modeling and optimization technique in a mature waterflood environment. Data Physics is the amalgamation of the state-of-the-art in machine learning and the same underlying physics present in reservoir simulators. These models can be created as efficiently as machine learning models, integrate all kinds of data, and can be evaluated orders of magnitude faster than full scale simulation models, and since they include similar underlying physics as simulators, they have good long term predictive capacity and can even be used to predict performance of new wells without any historical data. The technology was applied to a mature field in the Neuquen basin in Argentina to effectively reduce the amount of water injected into the reservoir with no negative impact on the production. Additionally, a new Carbon Intensity (CI) modeling tool was used to compare the emissions intensity before and after optimization showing a significant improvement in CI achieving three objectives in one single decision: 1) obtain significant water injection reduction with its corresponding impact in injection and water treatment costs; 2) maintaining production compared to the initial decline of the field, improving the top line; and 3) improving the GHG emissions intensity hence the long term benefit to the environment.\u0000 The paper deals more with the implementation of the technologies than the technologies themselves, assuming that readers unfamiliar with both Data Physics and Carbon Intensity tools will refer to the references section to gain familiarity with these.","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79613093","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. Alzain, Ali Abu Qurain, A. Al-Jaafari, Jason Hall
This paper aims to detail key success factors in understanding the effective principles of managing the health and well-being of the contractor workforce during and post pandemics, specifically for organizations in the oil, gas and energy industry. Furthermore, it shall provide insights and guidance on how to maintain and enhance contractor workforce experience, particularly during and post the COVID-19 pandemic; detailing the benefits of having well-established health management programs designed specifically for the contractor workforce. The social determinants of health (SDH) can be defined as the social and economic conditions in which people are born, grow, live, learn, work and age. They are nonmedical factors that influence a vast range of health conditions; affecting individuals' overall quality-of-life. Economic policies, social norms and political systems are all examples of forces and factors that shape daily life conditions and affect human health (ODPHP, n.d.; WHO, n.d.a). SDH also encompasses education, employment, socioeconomic status, access to health care, social support as well as neighborhood and physical environment (Artiga and Hinton, 2018). SDH have a crucial influence on health disparities and inequities – "the unfair and avoidable differences in health status seen within and between countries" (CDC, 2020). A well-known key factor in the emergence and perpetuation of health disparities is housing. Several researchers from a diverse array of disciplines explored the various aspects of the association between housing, health and well-being. They endeavored to comprehensively elucidate the major pathways through which housing conditions can negatively impact health equity, with a focus on the broad spectrum of hazardous exposures, their accumulated impact and their historical production. As reported by Rolfe et al. (2020), there is compelling evidence of poor physical health consequences of toxins within homes, damp and mold, cold indoor temperatures, overcrowding, and safety factors. Beyond the aforementioned impacts of physical aspects of housing on physical health, poor housing conditions have also been linked with high risks of poor mental health and well-being (Pevalin et al., 2017).
{"title":"The Use of Health Management Programs for the Contractors Workforce","authors":"H. Alzain, Ali Abu Qurain, A. Al-Jaafari, Jason Hall","doi":"10.2523/iptc-22122-ms","DOIUrl":"https://doi.org/10.2523/iptc-22122-ms","url":null,"abstract":"\u0000 This paper aims to detail key success factors in understanding the effective principles of managing the health and well-being of the contractor workforce during and post pandemics, specifically for organizations in the oil, gas and energy industry. Furthermore, it shall provide insights and guidance on how to maintain and enhance contractor workforce experience, particularly during and post the COVID-19 pandemic; detailing the benefits of having well-established health management programs designed specifically for the contractor workforce.\u0000 The social determinants of health (SDH) can be defined as the social and economic conditions in which people are born, grow, live, learn, work and age. They are nonmedical factors that influence a vast range of health conditions; affecting individuals' overall quality-of-life. Economic policies, social norms and political systems are all examples of forces and factors that shape daily life conditions and affect human health (ODPHP, n.d.; WHO, n.d.a). SDH also encompasses education, employment, socioeconomic status, access to health care, social support as well as neighborhood and physical environment (Artiga and Hinton, 2018). SDH have a crucial influence on health disparities and inequities – \"the unfair and avoidable differences in health status seen within and between countries\" (CDC, 2020).\u0000 A well-known key factor in the emergence and perpetuation of health disparities is housing. Several researchers from a diverse array of disciplines explored the various aspects of the association between housing, health and well-being. They endeavored to comprehensively elucidate the major pathways through which housing conditions can negatively impact health equity, with a focus on the broad spectrum of hazardous exposures, their accumulated impact and their historical production. As reported by Rolfe et al. (2020), there is compelling evidence of poor physical health consequences of toxins within homes, damp and mold, cold indoor temperatures, overcrowding, and safety factors. Beyond the aforementioned impacts of physical aspects of housing on physical health, poor housing conditions have also been linked with high risks of poor mental health and well-being (Pevalin et al., 2017).","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77615209","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}
Y. Bashir, Nordiana MOHD MUZTAZA, Amir Abbas Babasafari, Muhammad Khan, M. Mahgoub, S.Y. Moussavi Alashloo, A. H. Abdul Latiff
Seismic Imaging for the small-scale feature in complex subsurface geology such as Carbonate is not easy to capture because of propagated waves affected by heterogeneous properties of objects in the subsurface. The initial step for machine learning (ML) is to provide enough data which can make our learning algorithm updated and mature. If one has not provided the multiple shapes of diffraction data, then your prediction of ML will be not accurate or even ML not able to detect the pattern of diffraction in the data. After the learning, our machine, the detection of the target is the crucial part that compares with the target and searches the specific signature in the given data. In this paper, we feed it with data in the form of the image and feature. Which can pass through the learning algorithm to predict the target. The idea of ML is to get the difference between your prediction and the target as closely as much possible. Which leads to the better preservation of diffractions amplitude in laterally varying velocity conditions. ML destruction is used for diffraction data separation as the conventional filtering techniques mix the diffraction amplitudes when there are a single or series of diffractions.
{"title":"Machine Learning Application on Seismic Diffraction Detection and Preservation for High Resolution Imaging","authors":"Y. Bashir, Nordiana MOHD MUZTAZA, Amir Abbas Babasafari, Muhammad Khan, M. Mahgoub, S.Y. Moussavi Alashloo, A. H. Abdul Latiff","doi":"10.2523/iptc-21926-ea","DOIUrl":"https://doi.org/10.2523/iptc-21926-ea","url":null,"abstract":"\u0000 Seismic Imaging for the small-scale feature in complex subsurface geology such as Carbonate is not easy to capture because of propagated waves affected by heterogeneous properties of objects in the subsurface. The initial step for machine learning (ML) is to provide enough data which can make our learning algorithm updated and mature. If one has not provided the multiple shapes of diffraction data, then your prediction of ML will be not accurate or even ML not able to detect the pattern of diffraction in the data. After the learning, our machine, the detection of the target is the crucial part that compares with the target and searches the specific signature in the given data. In this paper, we feed it with data in the form of the image and feature. Which can pass through the learning algorithm to predict the target. The idea of ML is to get the difference between your prediction and the target as closely as much possible. Which leads to the better preservation of diffractions amplitude in laterally varying velocity conditions. ML destruction is used for diffraction data separation as the conventional filtering techniques mix the diffraction amplitudes when there are a single or series of diffractions.","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90566813","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}
S. Khan, U. Allauddin, Syed Muhammad Fakhir Hasani, R. Khan, M. Arsalan
Vortex tube that splits a single compressed gas stream into two separate hot and cold streams had been successfully used for spot cooling, and refrigeration. Significant temperature gradient exists between hot and cold stream ends that could be utilized for power generation using thermo-electric generators. Distance between hot and cold ends could be vital for small inaccessible down-hole well locations which may require the use of curved vortex tubes. Efficiency of vortex tube depends on temperature difference between hot and cold ends. In this work, effects of tube curvature on temperature separation efficiency are investigated through numerical simulations. Numerical models of straight and curved vortex tubes are developed in a commercial computational fluid dynamics package Ansys-fluent®. For the curved tube, multiple curvature angles are used to analyze the effects of curvature on velocity and temperature fields inside the vortex tube. The standard κ − ε turbulence model is used to model three-dimensional turbulence. The cold stream mass fraction is varied by controlling hot exit pressure. The numerical results for 110° curved vortex tube are validated through published experimental data and are found to be in good agreement. It is found that the curvature has affirmative results on temperature separation efficiency as compared to straight tube. This is mainly due to the energy separation phenomenon governed by the multi-circulation loop extension and multiple vortex formation in curved vortex tubes. Curvature angles of 180° and 270° have similar effects on the vortex tube where the maximum ΔTc obtained is 15.7 K which is about 5.3% higher than the straight vortex tube. The temperature separation ΔThc values for curved tubes are comparable with straight tube, the maximum being 25.2 K for the 150° curved vortex tube which is about 0.8 per higher than the straight tube. The temperature separation efficiency for curved vortex tubes with curvature angles larger than 150° is found to be higher than straigt tube, the maximum value being 8.7% for the 270° curved tube. A profound investigation of the effects of curvature on energy separation phenomenon in a vortex tube had been lacking and this research attempts to fill that gap. This novel work is expected to provide insight into the energy separation mechanisms in vortex tubes and lead the way to their use in thermo-electric power generation.
{"title":"The Effect of Tube Curvature on Temperature Separation Efficiency of Ranque-Hilsch Vortex Tube","authors":"S. Khan, U. Allauddin, Syed Muhammad Fakhir Hasani, R. Khan, M. Arsalan","doi":"10.2523/iptc-22414-ms","DOIUrl":"https://doi.org/10.2523/iptc-22414-ms","url":null,"abstract":"\u0000 Vortex tube that splits a single compressed gas stream into two separate hot and cold streams had been successfully used for spot cooling, and refrigeration. Significant temperature gradient exists between hot and cold stream ends that could be utilized for power generation using thermo-electric generators. Distance between hot and cold ends could be vital for small inaccessible down-hole well locations which may require the use of curved vortex tubes. Efficiency of vortex tube depends on temperature difference between hot and cold ends. In this work, effects of tube curvature on temperature separation efficiency are investigated through numerical simulations. Numerical models of straight and curved vortex tubes are developed in a commercial computational fluid dynamics package Ansys-fluent®. For the curved tube, multiple curvature angles are used to analyze the effects of curvature on velocity and temperature fields inside the vortex tube. The standard κ − ε turbulence model is used to model three-dimensional turbulence. The cold stream mass fraction is varied by controlling hot exit pressure. The numerical results for 110° curved vortex tube are validated through published experimental data and are found to be in good agreement. It is found that the curvature has affirmative results on temperature separation efficiency as compared to straight tube. This is mainly due to the energy separation phenomenon governed by the multi-circulation loop extension and multiple vortex formation in curved vortex tubes. Curvature angles of 180° and 270° have similar effects on the vortex tube where the maximum ΔTc obtained is 15.7 K which is about 5.3% higher than the straight vortex tube. The temperature separation ΔThc values for curved tubes are comparable with straight tube, the maximum being 25.2 K for the 150° curved vortex tube which is about 0.8 per higher than the straight tube. The temperature separation efficiency for curved vortex tubes with curvature angles larger than 150° is found to be higher than straigt tube, the maximum value being 8.7% for the 270° curved tube. A profound investigation of the effects of curvature on energy separation phenomenon in a vortex tube had been lacking and this research attempts to fill that gap. This novel work is expected to provide insight into the energy separation mechanisms in vortex tubes and lead the way to their use in thermo-electric power generation.","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86019855","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}
Alexandre Javay, Ahmed I. Elbatran, Sunil Sharma, Nata M. Franco, Mauricio Corona, Ahmed A. Alismail
In a deep gas drilling project, the 22-in section across shallow fractured carbonates is drilled using an unweighted clay-water system incorporating up to 50-lbm/bbl bentonite. The main challenges comprise lost circulation, tight hole, and low penetration rates due to high clay content and lack of inhibition, resulting in geological complications and affecting the well delivery time. To seal off the large fractures in the lower-cretaceous limestones, the new drilling fluid was engineered with high thixotropic characteristics presenting a flat, shear-thinning rheological profile with low plastic viscosity, high yield point and flat gel strengths. The selection of candidate wells was supported by offset wells analysis considering drilling performance, penetration rate and footage achieved, and the likelihood of encountering losses. Fine-tuning of the fluid rheology was performed to effectively account for the probability of losses on each well and a fit-for-purpose drilling fluid formulation was designed. This innovative technology combining mixed-metal oxide with premium bentonite was run in a series of wells as a substitute to the previously used system. Due to its superior viscosity at low shear rates the fluid successfully prevented losses by gelling up in the interstices of the highly fractured limestone intervals. In addition, the fluid delivered higher drilling performance across the abrasive sandstone-clay intercalations and the hard carbonates toward the bottom of the section. By maintaining full circulation all way through and therefore avoiding the expenses associated with blind drilling and pumping mud cap, the initiative resulted in considerably lowering the fluid cost in this section. Significant operation time savings were also achieved by drilling the section faster to the intended casing point in a minimum number of runs. Enhanced wellbore condition that allowed the drill string to trip out on elevators instead of back-reaming also contributed to saving rig time. The casing could be run to bottom and cemented trouble free in one stage with cement returns to surface thus precluding the cost of stage collar tool in most of the wells. This paper unveils the facets of this versatile water-base fluid that was introduced as a solution to prevent losses and address poor drilling performance.
{"title":"Use of Mixed-Metal Oxide Water-Based Drilling Fluid System Increased Drilling Performance and Eliminated Mud Losses","authors":"Alexandre Javay, Ahmed I. Elbatran, Sunil Sharma, Nata M. Franco, Mauricio Corona, Ahmed A. Alismail","doi":"10.2523/iptc-21961-ms","DOIUrl":"https://doi.org/10.2523/iptc-21961-ms","url":null,"abstract":"\u0000 In a deep gas drilling project, the 22-in section across shallow fractured carbonates is drilled using an unweighted clay-water system incorporating up to 50-lbm/bbl bentonite. The main challenges comprise lost circulation, tight hole, and low penetration rates due to high clay content and lack of inhibition, resulting in geological complications and affecting the well delivery time.\u0000 To seal off the large fractures in the lower-cretaceous limestones, the new drilling fluid was engineered with high thixotropic characteristics presenting a flat, shear-thinning rheological profile with low plastic viscosity, high yield point and flat gel strengths. The selection of candidate wells was supported by offset wells analysis considering drilling performance, penetration rate and footage achieved, and the likelihood of encountering losses. Fine-tuning of the fluid rheology was performed to effectively account for the probability of losses on each well and a fit-for-purpose drilling fluid formulation was designed.\u0000 This innovative technology combining mixed-metal oxide with premium bentonite was run in a series of wells as a substitute to the previously used system. Due to its superior viscosity at low shear rates the fluid successfully prevented losses by gelling up in the interstices of the highly fractured limestone intervals. In addition, the fluid delivered higher drilling performance across the abrasive sandstone-clay intercalations and the hard carbonates toward the bottom of the section.\u0000 By maintaining full circulation all way through and therefore avoiding the expenses associated with blind drilling and pumping mud cap, the initiative resulted in considerably lowering the fluid cost in this section. Significant operation time savings were also achieved by drilling the section faster to the intended casing point in a minimum number of runs. Enhanced wellbore condition that allowed the drill string to trip out on elevators instead of back-reaming also contributed to saving rig time. The casing could be run to bottom and cemented trouble free in one stage with cement returns to surface thus precluding the cost of stage collar tool in most of the wells. This paper unveils the facets of this versatile water-base fluid that was introduced as a solution to prevent losses and address poor drilling performance.","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90928153","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}
Jorge Vasquez, Anibal Flores, Rama Anggarawinata, Victor Hung Jie Thien, Lakmun Chan, Nur Izzah Haji Yaakub
Drilling and cementing across permeable, naturally fractured, and depleted formations have become some of the most common challenges across the world. A major operator in Offshore Brunei was facing similar challenges across such formations. The primary objective of the cementing job across this difficult formation was to isolate shallow hydrocarbon zones. Achieving desired top of cement (TOC) without inducing losses was the major design challenge. Drilling across such formation generally leads to loss circulation scenarios. This makes subsequent cementing operation more challenging. In order to minimize losses during the cement job, an innovative tailored spacer system was designed and pumped immediately before the cement slurry. This tailored spacer system not only helped in mud removal and wellbore cleaning but also helped to mitigate losses during cementing. Spacer and cement slurry density and rheology was optimized with the help of an advanced hydraulic simulator and industry leading computational fluid dynamics (CFD) software. To check the effectiveness of the spacer system, several laboratory tests were conducted to determine the spacer system's ability to plug a porous medium. Specialized particle suspension analysis was conducted to assure that the spacer design can maintain the fluid system's solid transport stability under both dynamic and shutdown periods. This helped to avoid plugging off restrictions such as critical flow paths in float equipment and the liner hanger. To validate the spacer design, several field jobs were executed for surface, intermediate and production casing scenarios. For each job the spacer design was tailored for the wellbore condition based on the severity of losses. For such jobs, initial purely hydraulic simulations predicted the possibility of losses. No losses or substantially reduced losses were noted for the cement jobs where this tailored spacer system was used. These results validated that the tailored spacer helped to mitigate the loss potential from the hydrostatic pressure. Top of cement was also validated based on fluids returns to surface and final displacement pressure. The first cement job using this innovative spacer system was executed for a 13-3/8inch surface casing job in Q3-2020. 100 bbls of an 11 ppg spacer was pumped across a permeable formation ahead of the cement slurry. Cement returns were observed at surface. Since the first job, 14 cement jobs using this innovative spacer system have been successfully executed in offshore Brunei for various casing sizes.
{"title":"Innovative Spacer Solution to Control Losses While Cementing in Permeable and Depleted Formations","authors":"Jorge Vasquez, Anibal Flores, Rama Anggarawinata, Victor Hung Jie Thien, Lakmun Chan, Nur Izzah Haji Yaakub","doi":"10.2523/iptc-22630-ms","DOIUrl":"https://doi.org/10.2523/iptc-22630-ms","url":null,"abstract":"\u0000 Drilling and cementing across permeable, naturally fractured, and depleted formations have become some of the most common challenges across the world. A major operator in Offshore Brunei was facing similar challenges across such formations. The primary objective of the cementing job across this difficult formation was to isolate shallow hydrocarbon zones. Achieving desired top of cement (TOC) without inducing losses was the major design challenge.\u0000 Drilling across such formation generally leads to loss circulation scenarios. This makes subsequent cementing operation more challenging. In order to minimize losses during the cement job, an innovative tailored spacer system was designed and pumped immediately before the cement slurry. This tailored spacer system not only helped in mud removal and wellbore cleaning but also helped to mitigate losses during cementing. Spacer and cement slurry density and rheology was optimized with the help of an advanced hydraulic simulator and industry leading computational fluid dynamics (CFD) software.\u0000 To check the effectiveness of the spacer system, several laboratory tests were conducted to determine the spacer system's ability to plug a porous medium. Specialized particle suspension analysis was conducted to assure that the spacer design can maintain the fluid system's solid transport stability under both dynamic and shutdown periods. This helped to avoid plugging off restrictions such as critical flow paths in float equipment and the liner hanger. To validate the spacer design, several field jobs were executed for surface, intermediate and production casing scenarios. For each job the spacer design was tailored for the wellbore condition based on the severity of losses. For such jobs, initial purely hydraulic simulations predicted the possibility of losses. No losses or substantially reduced losses were noted for the cement jobs where this tailored spacer system was used. These results validated that the tailored spacer helped to mitigate the loss potential from the hydrostatic pressure. Top of cement was also validated based on fluids returns to surface and final displacement pressure.\u0000 The first cement job using this innovative spacer system was executed for a 13-3/8inch surface casing job in Q3-2020. 100 bbls of an 11 ppg spacer was pumped across a permeable formation ahead of the cement slurry. Cement returns were observed at surface. Since the first job, 14 cement jobs using this innovative spacer system have been successfully executed in offshore Brunei for various casing sizes.","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85732806","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}
Managing carbon emissions has become a major responsibility for the oil and gas industry in a drive to ensure sustainable energy and create a clean environment. Therefore, governments, research centers, IOC’s and NOC’s are actively adopting new guidelines and inventing new technologies to safely circulate carbons. In this paper, the process of modeling CO2 sequestration in a deep saline aquifer will be discussed. Carbon dioxide can be safely stored indefinitely in subsurface geological formations by four trapping mechanisms; structural, residual, soluble, and mineral trapping. These four trapping mechanisms can take hundreds or thousands of years to happen. Furthermore, the oil and gas industry standard recommend that any technology used to store CO2 needs to demonstrate a storage capacity of 1000 years with less than 0.1 per-cent leakage potential per year. Therefore, modelling such process should capture any existing trapping mechanism, even if it happens after several hundreds of years, to ensure long-term secure storage of the CO2. Using our in-house simulator "GigaPOWERS", many sequestration scenarios were conducted to come up with a recommended guideline to maximize the volume of CO2 trapped in deep saline aquifers. This study used a giant synthetic anticline model with a variation in geological properties. The residual and soluble trapping mechanisms were captured through relative permeability hysteresis and extended water PVT tables respectively. Injecting CO2 into water aquifers is a dynamic process where drainage and imbibition cycles are likely to happen. Such processes cause the CO2 to be trapped in the middle of the pores as an immobile phase, which can be a favorable phenomenon maximizing the security of CO2 sequestration. Since CO2 is soluble in water, when it contacts the water phase it will form a carbonated water that is denser than water itself and migrates downward in a phenomenon known as "CO2 fingering". The CO2 solubility in water depends mainly on the salinity and temperature which both need to be accurately captured in the simulation model. Depending on the long-term objective of the sequestration project, the development strategy can be altered to maximize the outcome using the detailed simulation model. In this paper, the simulation best practices for modeling CO2 sequestration for maximum secure long-term storage (1000+ years) are suggested. Carbon dioxide, CO2, sequestration in deep saline aquifers is a well-known method to reduce carbon emissions. However, there is very little published literature on the simulation best practices for modeling the CO2 sequestration process. Therefore, this paper will be a pioneer to guide the industry for accurate simulation of such process.
{"title":"Modeling CO2 Sequestration in Deep Saline Aquifers – Best Practices","authors":"Hassan Alzayer, Tareq Zahrani, A. Shubbar","doi":"10.2523/iptc-22423-ea","DOIUrl":"https://doi.org/10.2523/iptc-22423-ea","url":null,"abstract":"\u0000 Managing carbon emissions has become a major responsibility for the oil and gas industry in a drive to ensure sustainable energy and create a clean environment. Therefore, governments, research centers, IOC’s and NOC’s are actively adopting new guidelines and inventing new technologies to safely circulate carbons. In this paper, the process of modeling CO2 sequestration in a deep saline aquifer will be discussed.\u0000 Carbon dioxide can be safely stored indefinitely in subsurface geological formations by four trapping mechanisms; structural, residual, soluble, and mineral trapping. These four trapping mechanisms can take hundreds or thousands of years to happen. Furthermore, the oil and gas industry standard recommend that any technology used to store CO2 needs to demonstrate a storage capacity of 1000 years with less than 0.1 per-cent leakage potential per year. Therefore, modelling such process should capture any existing trapping mechanism, even if it happens after several hundreds of years, to ensure long-term secure storage of the CO2. Using our in-house simulator \"GigaPOWERS\", many sequestration scenarios were conducted to come up with a recommended guideline to maximize the volume of CO2 trapped in deep saline aquifers.\u0000 This study used a giant synthetic anticline model with a variation in geological properties. The residual and soluble trapping mechanisms were captured through relative permeability hysteresis and extended water PVT tables respectively. Injecting CO2 into water aquifers is a dynamic process where drainage and imbibition cycles are likely to happen. Such processes cause the CO2 to be trapped in the middle of the pores as an immobile phase, which can be a favorable phenomenon maximizing the security of CO2 sequestration. Since CO2 is soluble in water, when it contacts the water phase it will form a carbonated water that is denser than water itself and migrates downward in a phenomenon known as \"CO2 fingering\". The CO2 solubility in water depends mainly on the salinity and temperature which both need to be accurately captured in the simulation model. Depending on the long-term objective of the sequestration project, the development strategy can be altered to maximize the outcome using the detailed simulation model. In this paper, the simulation best practices for modeling CO2 sequestration for maximum secure long-term storage (1000+ years) are suggested.\u0000 Carbon dioxide, CO2, sequestration in deep saline aquifers is a well-known method to reduce carbon emissions. However, there is very little published literature on the simulation best practices for modeling the CO2 sequestration process. Therefore, this paper will be a pioneer to guide the industry for accurate simulation of such process.","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86200415","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}
Multiphase fluids are mixtures of oil, water, and gas. Roughly six out of every ten wells contain multiphase fluids with variations in the fluid makeup, rheology, and viscosity. They may also include small amounts of sand, paraffin, hydrates, and drilling cuttings. This necessitates local separation at the well site, which can require a significant footprint of process equipment infrastructure at or near each well site. Ever since oil production began, produced fluids have been transferred from the well to the storage or processing facility using reservoir pressures. This means the bottom hole pressures needed to be sufficient to not only get the fluid to the surface but also move it some distance on the surface through flow lines. In cases where reservoirs are either low energy or are characterized by rapid pressure depletion curves as is common in a number of unconventional plays, this can be problematic. In wells that are artificially produced with a down hole pump or other artificial lift equipment the pump must have sufficient pressure capability to bring the fluids to the surface and then move them some distance on the surface through a flow line. Additional pressure may also be required for the separation equipment at the end of the flow line.
{"title":"Multiphase Pumping with Progressive Cavity Pumps","authors":"M. Hester","doi":"10.2523/iptc-22277-ea","DOIUrl":"https://doi.org/10.2523/iptc-22277-ea","url":null,"abstract":"\u0000 Multiphase fluids are mixtures of oil, water, and gas. Roughly six out of every ten wells contain multiphase fluids with variations in the fluid makeup, rheology, and viscosity. They may also include small amounts of sand, paraffin, hydrates, and drilling cuttings. This necessitates local separation at the well site, which can require a significant footprint of process equipment infrastructure at or near each well site.\u0000 Ever since oil production began, produced fluids have been transferred from the well to the storage or processing facility using reservoir pressures. This means the bottom hole pressures needed to be sufficient to not only get the fluid to the surface but also move it some distance on the surface through flow lines. In cases where reservoirs are either low energy or are characterized by rapid pressure depletion curves as is common in a number of unconventional plays, this can be problematic.\u0000 In wells that are artificially produced with a down hole pump or other artificial lift equipment the pump must have sufficient pressure capability to bring the fluids to the surface and then move them some distance on the surface through a flow line. Additional pressure may also be required for the separation equipment at the end of the flow line.","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86423030","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}
S. Al-Sabea, A. Abu-Eida, M. Patra, M. AlEidi, G. Ambrosi, Nakul Khandelwal, Rishi Gaur, Khaled M. Matar, Abdulatif Al wazzan, J. Vasquez
Acid systems are widely recognized by the oil and gas industry as an attractive class of fluids for the efficient stimulation of carbonate reservoirs. One of the major challenges in carbonate acidizing treatments is adjusting the convective transport of acid deep into the reservoir while achieving a minimum rock face dissolution. Conventional emulsified acids are hindered by several limitations; low stability at high temperatures, a high viscosity that limits pumping rate due to frictional losses, the potential of formation damage, and the difficulty to achieve homogenous field-scale mixing. This paper highlights the successful application of an engineered low-viscosity retarded acid system without the need for gelation by a polymer or surfactant or emulsification by diesel. An acid stimulation job using a new innovative retarded acid system has been performed in a West Kuwait field well. The proposed acid system combines the use of a strong mineral acid (i.e. hydrochloric acid "HCl") with a non-damaging retarding agent that allows deeper penetration of the live HCl acid into the formation, resulting in a more effective stimulation treatment. The retardation behavior testing includes dissolution experiments, compatibility testing, coreflood study, and corrosion rate testing (conducted at 200°F). The on-job implementation included the use of a packer to pinpoint fluid pumping (pre-flush) at the point of interest, followed by the customized novel retarded acid system for improving conductivity at perforations and effective reservoir stimulation. This acid system is characterized by having a low-viscosity and high thermal stability system that can be mixed on the fly. This approach addresses the main challenges of emulsified acid systems and offers a cost-effective solution to cover a wide range of applications in matrix acid stimulation and high-temperature conditions that require a chemically retarded acid system. The application of this novel acid retarded system is a fit-for-purpose solution to optimize the return on investment by maximizing the well production and extending the lifetime of the treatment effect. This new system also offers excellent scale inhibition and iron control properties which eliminates the need for any acid remedial work, making it an economical approach over other conventional acid systems. The paper presents results obtained after stimulating the carbonate reservoir and describes the lessons learned from the job planning and execution phases, which can be considered as a best practice for application in similar challenges in other fields. Proper candidate selection, best available placement technique, and lab-tested formulation of novel retarded acid system resulted in achieving 1700 BOPD of oil production (27% higher than expected).
{"title":"Low Viscosity Polymer Free Acid Retarded System, a Novel Alternative to Emulsified Acid: Successful Application in West Kuwait Field","authors":"S. Al-Sabea, A. Abu-Eida, M. Patra, M. AlEidi, G. Ambrosi, Nakul Khandelwal, Rishi Gaur, Khaled M. Matar, Abdulatif Al wazzan, J. Vasquez","doi":"10.2523/iptc-22665-ms","DOIUrl":"https://doi.org/10.2523/iptc-22665-ms","url":null,"abstract":"\u0000 Acid systems are widely recognized by the oil and gas industry as an attractive class of fluids for the efficient stimulation of carbonate reservoirs. One of the major challenges in carbonate acidizing treatments is adjusting the convective transport of acid deep into the reservoir while achieving a minimum rock face dissolution. Conventional emulsified acids are hindered by several limitations; low stability at high temperatures, a high viscosity that limits pumping rate due to frictional losses, the potential of formation damage, and the difficulty to achieve homogenous field-scale mixing. This paper highlights the successful application of an engineered low-viscosity retarded acid system without the need for gelation by a polymer or surfactant or emulsification by diesel.\u0000 An acid stimulation job using a new innovative retarded acid system has been performed in a West Kuwait field well. The proposed acid system combines the use of a strong mineral acid (i.e. hydrochloric acid \"HCl\") with a non-damaging retarding agent that allows deeper penetration of the live HCl acid into the formation, resulting in a more effective stimulation treatment. The retardation behavior testing includes dissolution experiments, compatibility testing, coreflood study, and corrosion rate testing (conducted at 200°F).\u0000 The on-job implementation included the use of a packer to pinpoint fluid pumping (pre-flush) at the point of interest, followed by the customized novel retarded acid system for improving conductivity at perforations and effective reservoir stimulation. This acid system is characterized by having a low-viscosity and high thermal stability system that can be mixed on the fly. This approach addresses the main challenges of emulsified acid systems and offers a cost-effective solution to cover a wide range of applications in matrix acid stimulation and high-temperature conditions that require a chemically retarded acid system.\u0000 The application of this novel acid retarded system is a fit-for-purpose solution to optimize the return on investment by maximizing the well production and extending the lifetime of the treatment effect. This new system also offers excellent scale inhibition and iron control properties which eliminates the need for any acid remedial work, making it an economical approach over other conventional acid systems.\u0000 The paper presents results obtained after stimulating the carbonate reservoir and describes the lessons learned from the job planning and execution phases, which can be considered as a best practice for application in similar challenges in other fields. Proper candidate selection, best available placement technique, and lab-tested formulation of novel retarded acid system resulted in achieving 1700 BOPD of oil production (27% higher than expected).","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86458150","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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