As we have seen with the advent of the shale oil revolution in the United States, the development of new technology plays an important role in the oil and gas industry. It’s an enabler in reducing capital costs, simplifying production and increasing capacity of new or existing facilities. It can make a marginal project into a profitable development.
Progressing technology, while dealing with significant risk, is a challenge that can be overcome through a technology qualification process. A Technology Qualification Program (TQP) provides a means to identifying the risks and taking the correct steps to mitigate it; not avoid it.
This lecture summarizes the required steps involved in qualifying technology and how to keep track of technology development through the Technology Readiness Level (TRL) ranking system. In addition, some of the pitfalls in executing a TQP program are identified and discussed with emphasis on both component and system testing. Examples are given to illustrate the danger in taking shortcuts when executing the qualification plan.
Data from a recent subsea separation qualification program is presented comparing test results between CFDs, model fluid and actual crude testing at operating conditions. Knowing the limitations of the tools and testing system selected is an important step in closing the gaps identified in the TQP program.
The TRL has evolved at a faster pace and has become more acceptable in the oil and gas industry then the TQP. Nonetheless, continued standardization of both the TQP and TRL is still necessary in order to reduce overall cost of developing technology and allow faster implementation.
The weakness of reservoir simulations is the lack of quantity and quality of the required input; their strength is the ability to vary one parameter at a time. Therefore, reservoir simulations are an appropriate tool to evaluate relative uncertainty but absolute forecasts can be misleading, leading to poor business decisions. As recovery processes increase in complexity, the impact of such decisions may have a major impact on the project viability. A responsible use of reservoir simulations is discussed, addressing both technical users and decision makers. The danger of creating a false confidence in forecasts and the value of simulating complex processes are demonstrated with examples. This is a call for the return of the reservoir engineer who is in control of the simulations and not controlled by them, and the decision maker who appreciates a black & white graph of a forecast with realistic uncertainties over a 3-D hologram in colour.
Reservoir simulation is a sophisticated technique of forecasting future recoverable volumes and production rates that is becoming commonplace in the management and development of oil and gas reservoirs, small and large. Calculation and estimation of reserves continues to be a necessary process to properly assess the value and manage the development of an oil and gas producer’s assets. These methods of analysis, while generally done for different purposes, require knowledge and expertise by the analyst (typically a reservoir engineer) to arrive at meaningful and reliable results. Increasingly, the simulation tool is being incorporated into the reserves process. However, as with any reservoir engineering technique, certain precautions must be taken when relying on reservoir simulation as the means for estimating reserves. This discussion highlights some of the important facets one should consider when applying numerical simulation methods to use for, or augment, reserves estimates. The main take away will be an appreciation for the areas to focus on to arrive at meaningful and defendable estimates of reserves that are based on reservoir models.
Unconventional development propelled the United States to produce more oil than it imports for the first time in 20 years. Increased production of domestic oil and gas profoundly impacted economic growth and job creation for the U.S. During this evolution, there was a need to address environmental regulations and infrastructure requirements in order to access the sheer volume of resources. Combined with today’s horizontal drilling and hydraulic fracturing technology, a strategic development plan can be constructed for any country to create an unconventional energy opportunity. In this lecture, the experience from U.S development is utilized to provide a fully-integrated workflow for developing shale oil and gas reservoirs from exploitation to production. Starting at the nano-scale, we will zoom into the pore structure to understand the storage and flow paths. Transitioning to the reservoir-scale, well testing and microseismic are utilized to define the flow capacity and estimate the stimulated volume. Learnings from this subsurface characterization is used to guide well completion, flowback, and production operations. The diagnostic methodology specific to each operation can be applied to identify geologically favorable areas and the best completion practice. As development progresses, opportunities to improve recovery can be magnified through optimum well spacing and refracturing. As a final step in the development, determining an appropriate enhanced recovery method is essential to access the remaining resources. Finally, example development scenarios are provided to demonstrate how a technically driven strategy is more effective to maximize value and make the unconventional revolution a global one.
The lifecycle of developed fields, onshore and offshore will go through different stages of production up to the decline into late field life. Effective reservoir engineering management will lead to prolonging the life of field if a cost effective processing surface facilities strategy is put in place. Factors that lead to the decline in oil production or increase in OPEX may include increased water production, solids handling and the need for relatively higher compression requirements for gas lift. In order to maintain productivity and profitability, an effective holistic engineering approach to optimizing the process surface facilities must be utilized. The challenges of Optimizing Mature Field Production are: 1. Reservoir understanding with potential definition of additional reserves 2. Complete re-appraisal of the operability issues in the production facilities 3. Develop confidence to invest to optimize the process handling capabilities and capacity 4. Low CAPEX simplification of the surface facilities infrastructure to meet challenges 5. An implementation plan that recognizes the ‘Brownfield’ complexities 6. Selection of suitable optimum technology, configuration and training 7. Optimum upgrade plan of the facilities with minimum production losses Successful operation of mature fields and their surface facilities requires successful change management to the new operating strategy. Using a holistic approach can maximize the full potential of mature processing facilities at a manageable CAPEX and OPEX.
Dr. Wally Georgie Dr. Wally Georgie has a B.Sc degree in Chemistry, M.Sc in Polymer Technology, M.Sc in Safety Engineering and PhD in Applied Chemistry with training courses in oil and gas process engineering, production, reservoir and corrosion engineering. He has worked for over 37 years in different areas of oil and gas production facilities, including corrosion control, flow assurance, fluid separation, separator design, gas handling and produced water. He started his career in oil and gas services sector in 1978 based in the UK and working globally with different production issues then joined Statoil as senior staff engineer and later as technical advisor in the Norwegian sector of the North Sea. Working as part of operation team on oil and gas production facilities key focus areas included optimization, operation trouble-shooting, de-bottlenecking, oil water separation, slug handling, process verification, and myriad other fluid and gas handling issues. He then started working in March 1999 as a consultant globally both offshore and onshore, conventional and unconventional in the area of separation trouble shooting, operation assurance, produced water management, gas handling problems, flow assurance, system integrities and production chemistry, with emphasis in dealing with mature facilities worldwide.
We are all familiar with the production systems through which reservoir fluids flow to reach our processing facilities. This is a journey characterized by complex multiphase flow phenomena that govern pressure and temperature changes along the way. A monumental amount of research and development work has been invested towards better understanding multiphase flow behavior over the past fifty years. Yet, many challenges remain as we strive to optimize ever more complex production systems fraught with difficult flow assurance issues. Just how good is the science? And more importantly, how does this impact our bottom line? This lecture will discuss key concepts of multiphase flow leading to the current “state-of-the-art” models used today. Looking towards the future, the science must be advanced to address areas of greatest uncertainty and align with trends in field development strategies. Recommendations will be presented covering the top 5 areas of research necessary for these purposes. The economic impact of multiphase operations will be illustrated using two examples that provide insight towards maximizing asset value.
Mack Shippen is a Principal Engineer with Schlumberger in Houston, where he is responsible for the global business of the PIPESIM multiphase flow simulation software. He has extensive experience in well and network simulation studies, ranging from flow assurance to dynamic coupling of reservoir and surface simulation models. He has served on a number of SPE committees and chaired the SPE Reprint Series on Offshore Multiphase Production Operations. He holds BS and MS degrees in Petroleum Engineering from Texas A&M University, where his research focused on multiphase flow modelling.
"Drilling" often refers to all aspects of well construction, including drilling, completions, facilities, construction, the asset team, and other groups. Good performance measures drive performance and reduce conflict between these groups, while bad performance measures mislead and confuse. The first key to success is how to communicate drilling performance in terms that answer the questions of executives and managers, which requires a business-focused cross-functional process. The second key to success is to drive operational performance improvement, which requires a different set of measures with sufficient granularity to define actions. Over the past 10 years, a very workable system has evolved through various approaches used in drilling more than 16,000 wells in the US, South America, and the Middle East. The system has delivered best-in-class performance. It has proven that an effective performance measurement system which addresses both executive requirements and operational requirements can both deliver outstanding results, and also communicate those results, with remarkable value to the organization. The basic principles are widely applicable to areas other than drilling.
In low oil-price environments, it is customary to cut expenses, reduce staff, and postpone most, if not all, capital investments. While this strategy may be financially sound in the short term, it is ineffective in the long run, particularly for companies with the need to sustain production levels or to replace reserves through drilling, production or reservoir projects. Heavy oil projects are usually more challenging, as production costs are higher and the oil price is even lower.
This presentation addresses the dilemma of controlling cost and at the same time sustaining production and increasing recovery. A balance can be struck by focusing on the quality of decisions, such as when and where to invest, and ensuring that projects are delivered on- budget, a common issue in the E&P industry. The central idea in this presentation is that, in the most complex and financially challenging case of Enhanced Oil Recovery (EOR) projects, the combination of quality decision making and the implementation of “fit-for-purpose” technology offers the most promising middle-point. By providing eight examples of innovative technologies to help reduce uncertainty, cost and time for delivering commercial EOR oil, and three successful case studies, the audience will gain confidence in the proposition that it is perfectly viable to double recoveries for many of our fields in the next 15 years, even in the current price scenario.
Finally, EOR is a business, and as such it needs to compete favorably with other businesses in a company’s E&P portfolio - challenging in low oil price environments. The lecture will close by presenting a strategy, illustrated with an example, on how to divert from the traditional engineering approach in favor of a managerial decision approach, that will help engineers to justify viable recovery projects.
Oil and gas are essential parts of a sustainable future. Though these are finite energy resources and sources of greenhouse gas emissions, the world continues to require their production. For this reason, it is imperative that we consider improved industry practices.
To begin, the audience will be presented with the most basic principles of sustainability pertaining to oil and gas operations, including SPE’s position on this matter. When oil is discovered at a location, decisions and guarantees cannot be made without considering the project’s life cycle. Our commitments must be demonstrated consistently along each stage of a project in direct consideration of a sustainable future.
Next, several case studies relating to sustainability, integrating the realities of the social license to operate and operations will be presented to the audience, detailing the required steps for the successful execution of any project facing challenging conditions.
The presentation will conclude by underlining that the inclusion of internal and external stakeholders will only enrich the project and, therefore, pave the road to success. It is our responsibility to create a culture of operational professionalism and reliability through active participation. In order to counterbalance the world’s energy demand, we must produce oil and gas while considering that the more efficiently the energy is produced, the more affordable the energy will be. The oil industry is not only committed to its own sustainability but also to the sustainability of our planet.
The weakness of reservoir simulations is the lack of quantity and quality of the required input; their strength is the ability to vary one parameter at a time. Therefore, reservoir simulations are an appropriate tool to evaluate relative uncertainty but absolute forecasts can be misleading, leading to poor business decisions. As recovery processes increase in complexity, the impact of such decisions may have a major impact on the project viability. A responsible use of reservoir simulations is discussed, addressing both technical users and decision makers. The danger of creating a false confidence in forecasts and the value of simulating complex processes are demonstrated with examples. This is a call for the return of the reservoir engineer who is in control of the simulations and not controlled by them, and the decision maker who appreciates a black & white graph of a forecast with realistic uncertainties over a 3-D hologram in colour.
Reservoir simulation is a sophisticated technique of forecasting future recoverable volumes and production rates that is becoming commonplace in the management and development of oil and gas reservoirs, small and large. Calculation and estimation of reserves continues to be a necessary process to properly assess the value and manage the development of an oil and gas producer’s assets. These methods of analysis, while generally done for different purposes, require knowledge and expertise by the analyst (typically a reservoir engineer) to arrive at meaningful and reliable results. Increasingly, the simulation tool is being incorporated into the reserves process. However, as with any reservoir engineering technique, certain precautions must be taken when relying on reservoir simulation as the means for estimating reserves. This discussion highlights some of the important facets one should consider when applying numerical simulation methods to use for, or augment, reserves estimates. The main take away will be an appreciation for the areas to focus on to arrive at meaningful and defendable estimates of reserves that are based on reservoir models.
Unconventional development propelled the United States to produce more oil than it imports for the first time in 20 years. Increased production of domestic oil and gas profoundly impacted economic growth and job creation for the U.S. During this evolution, there was a need to address environmental regulations and infrastructure requirements in order to access the sheer volume of resources. Combined with today’s horizontal drilling and hydraulic fracturing technology, a strategic development plan can be constructed for any country to create an unconventional energy opportunity. In this lecture, the experience from U.S development is utilized to provide a fully-integrated workflow for developing shale oil and gas reservoirs from exploitation to production. Starting at the nano-scale, we will zoom into the pore structure to understand the storage and flow paths. Transitioning to the reservoir-scale, well testing and microseismic are utilized to define the flow capacity and estimate the stimulated volume. Learnings from this subsurface characterization is used to guide well completion, flowback, and production operations. The diagnostic methodology specific to each operation can be applied to identify geologically favorable areas and the best completion practice. As development progresses, opportunities to improve recovery can be magnified through optimum well spacing and refracturing. As a final step in the development, determining an appropriate enhanced recovery method is essential to access the remaining resources. Finally, example development scenarios are provided to demonstrate how a technically driven strategy is more effective to maximize value and make the unconventional revolution a global one.
The lifecycle of developed fields, onshore and offshore will go through different stages of production up to the decline into late field life. Effective reservoir engineering management will lead to prolonging the life of field if a cost effective processing surface facilities strategy is put in place. Factors that lead to the decline in oil production or increase in OPEX may include increased water production, solids handling and the need for relatively higher compression requirements for gas lift. In order to maintain productivity and profitability, an effective holistic engineering approach to optimizing the process surface facilities must be utilized. The challenges of Optimizing Mature Field Production are: 1. Reservoir understanding with potential definition of additional reserves 2. Complete re-appraisal of the operability issues in the production facilities 3. Develop confidence to invest to optimize the process handling capabilities and capacity 4. Low CAPEX simplification of the surface facilities infrastructure to meet challenges 5. An implementation plan that recognizes the ‘Brownfield’ complexities 6. Selection of suitable optimum technology, configuration and training 7. Optimum upgrade plan of the facilities with minimum production losses Successful operation of mature fields and their surface facilities requires successful change management to the new operating strategy. Using a holistic approach can maximize the full potential of mature processing facilities at a manageable CAPEX and OPEX.
Dr. Wally Georgie Dr. Wally Georgie has a B.Sc degree in Chemistry, M.Sc in Polymer Technology, M.Sc in Safety Engineering and PhD in Applied Chemistry with training courses in oil and gas process engineering, production, reservoir and corrosion engineering. He has worked for over 37 years in different areas of oil and gas production facilities, including corrosion control, flow assurance, fluid separation, separator design, gas handling and produced water. He started his career in oil and gas services sector in 1978 based in the UK and working globally with different production issues then joined Statoil as senior staff engineer and later as technical advisor in the Norwegian sector of the North Sea. Working as part of operation team on oil and gas production facilities key focus areas included optimization, operation trouble-shooting, de-bottlenecking, oil water separation, slug handling, process verification, and myriad other fluid and gas handling issues. He then started working in March 1999 as a consultant globally both offshore and onshore, conventional and unconventional in the area of separation trouble shooting, operation assurance, produced water management, gas handling problems, flow assurance, system integrities and production chemistry, with emphasis in dealing with mature facilities worldwide.
We are all familiar with the production systems through which reservoir fluids flow to reach our processing facilities. This is a journey characterized by complex multiphase flow phenomena that govern pressure and temperature changes along the way. A monumental amount of research and development work has been invested towards better understanding multiphase flow behavior over the past fifty years. Yet, many challenges remain as we strive to optimize ever more complex production systems fraught with difficult flow assurance issues. Just how good is the science? And more importantly, how does this impact our bottom line? This lecture will discuss key concepts of multiphase flow leading to the current “state-of-the-art” models used today. Looking towards the future, the science must be advanced to address areas of greatest uncertainty and align with trends in field development strategies. Recommendations will be presented covering the top 5 areas of research necessary for these purposes. The economic impact of multiphase operations will be illustrated using two examples that provide insight towards maximizing asset value.
Mack Shippen is a Principal Engineer with Schlumberger in Houston, where he is responsible for the global business of the PIPESIM multiphase flow simulation software. He has extensive experience in well and network simulation studies, ranging from flow assurance to dynamic coupling of reservoir and surface simulation models. He has served on a number of SPE committees and chaired the SPE Reprint Series on Offshore Multiphase Production Operations. He holds BS and MS degrees in Petroleum Engineering from Texas A&M University, where his research focused on multiphase flow modelling.
"Drilling" often refers to all aspects of well construction, including drilling, completions, facilities, construction, the asset team, and other groups. Good performance measures drive performance and reduce conflict between these groups, while bad performance measures mislead and confuse. The first key to success is how to communicate drilling performance in terms that answer the questions of executives and managers, which requires a business-focused cross-functional process. The second key to success is to drive operational performance improvement, which requires a different set of measures with sufficient granularity to define actions. Over the past 10 years, a very workable system has evolved through various approaches used in drilling more than 16,000 wells in the US, South America, and the Middle East. The system has delivered best-in-class performance. It has proven that an effective performance measurement system which addresses both executive requirements and operational requirements can both deliver outstanding results, and also communicate those results, with remarkable value to the organization. The basic principles are widely applicable to areas other than drilling.
In low oil-price environments, it is customary to cut expenses, reduce staff, and postpone most, if not all, capital investments. While this strategy may be financially sound in the short term, it is ineffective in the long run, particularly for companies with the need to sustain production levels or to replace reserves through drilling, production or reservoir projects. Heavy oil projects are usually more challenging, as production costs are higher and the oil price is even lower.
This presentation addresses the dilemma of controlling cost and at the same time sustaining production and increasing recovery. A balance can be struck by focusing on the quality of decisions, such as when and where to invest, and ensuring that projects are delivered on- budget, a common issue in the E&P industry. The central idea in this presentation is that, in the most complex and financially challenging case of Enhanced Oil Recovery (EOR) projects, the combination of quality decision making and the implementation of “fit-for-purpose” technology offers the most promising middle-point. By providing eight examples of innovative technologies to help reduce uncertainty, cost and time for delivering commercial EOR oil, and three successful case studies, the audience will gain confidence in the proposition that it is perfectly viable to double recoveries for many of our fields in the next 15 years, even in the current price scenario.
Finally, EOR is a business, and as such it needs to compete favorably with other businesses in a company’s E&P portfolio - challenging in low oil price environments. The lecture will close by presenting a strategy, illustrated with an example, on how to divert from the traditional engineering approach in favor of a managerial decision approach, that will help engineers to justify viable recovery projects.
Oil and gas are essential parts of a sustainable future. Though these are finite energy resources and sources of greenhouse gas emissions, the world continues to require their production. For this reason, it is imperative that we consider improved industry practices.
To begin, the audience will be presented with the most basic principles of sustainability pertaining to oil and gas operations, including SPE’s position on this matter. When oil is discovered at a location, decisions and guarantees cannot be made without considering the project’s life cycle. Our commitments must be demonstrated consistently along each stage of a project in direct consideration of a sustainable future.
Next, several case studies relating to sustainability, integrating the realities of the social license to operate and operations will be presented to the audience, detailing the required steps for the successful execution of any project facing challenging conditions.
The presentation will conclude by underlining that the inclusion of internal and external stakeholders will only enrich the project and, therefore, pave the road to success. It is our responsibility to create a culture of operational professionalism and reliability through active participation. In order to counterbalance the world’s energy demand, we must produce oil and gas while considering that the more efficiently the energy is produced, the more affordable the energy will be. The oil industry is not only committed to its own sustainability but also to the sustainability of our planet.
Increasing interest by governments worldwide on reducing CO2 released into the atmosphere form a nexus of of opportunity with enhanced oil recovery which could benefit mature oil fields in nearly every country. Overall approximately two-thirds of original oil in place (OOIP) in mature conventional oil fields remains after primary or primary/secondary recovery efforts have taken place. CO2 enhanced oil recovery (CO2 EOR) has an excellent record of revitalizing these mature plays and can dramatically increase ultimate recovery. Since the first CO2 EOR project was initiated in 1972, more than 154 additional projects have been put into operation around the world and about two-thirds are located in the Permian basin and Gulf coast regions of the United States. While these regions have favorable geologic and reservoir conditions for CO2 EOR, they are also located near large natural sources of CO2.
In recent years an increasing number of projects have been developed in areas without natural supplies, and have instead utilized captured CO2 from a variety of anthropogenic sources including gas processing plants, ethanol plants, cement plants, and fertilizer plants. Today approximately 36% of active CO2 EOR projects utilize gas that would otherwise be vented to the atmosphere. Interest world-wide has increased, including projects in Canada, Brazil, Norway, Turkey, Trinidad, and more recently, and perhaps most significantly, in Saudi Arabia and Qatar. About 80% of all energy used in the world comes from fossil fuels, and many industrial and manufacturing processes generate CO2 that can be captured and used for EOR. In this 30 minute presentation a brief history of CO2 EOR is provided, implications for utilizing captured carbon are discussed, and a demonstration project is introduced with an overview of characterization, modeling, simulation, and monitoring actvities taking place during injection of more than a million metric tons (~19 Bcf) of anthropogenic CO2 into a mature waterflood.
Longer versions of the presentation can be requested and can cover details of geologic and seimic characterization, simulation studies, time-lapse monitoring, tracer studies, or other CO2 monitoring technologies.
UntitledExcessive Water Production Diagnostic and Control - Case Study Jake O...Mohanned Mahjoup
For mature fields, Excessive water production is a complex subject in the oil and gas industries and has a serious economic and environmental impact. Some argue that oil industry is effectively water industry producing oil as a secondary output. Therefore, it is important to realize the different mechanisms that causing water production to better evaluate existing situation and design the optimum solution for the problem. This paper presents the water production and management situation in Jake oilfield in the southeast of Sudan; a cumulative of 14 MMBbl of water was produced till the end of 2014, without actual plan for water management in the field, only conventional shut-off methods have been tested with no success. Based on field production data and the previously applied techniques, this work identified the sources of water problems and attempts to initialize a strategy for controlling the excessive water production in the field. The production data were analyzed and a series of diagnostic plots were presented and compared with Chan’s standard diagnostic plot. As a result, distinction between channeling and conning for each well was identified; the work shows that channeling is the main reason for water production in wells with high permeability sandstone zone while conning appears only in two wells. Finally, the wells were classified according to a risk factor and selections of the candidate wells for water shut off were presented.
Adoption of the applied surface-backpressure types of managed pressure drilling (MPD) technologies in deepwater have mainly involved the use of a rotating control device (RCD). The RCD creates a closed drilling system in which the flow out of the well is diverted towards an automated MPD choke manifold (with a high-resolution mass flow meter) that aside from regulating backpressure also increases sensitivity and reduces reaction time to kicks, losses, and other unwanted drilling events. This integration of MPD equipment into floating drilling rigs to provide them with MPD capabilities, including the capacity to perform pressurized mud cap drilling (PMCD) and riser gas mitigation (RGM), has produced improvements not only in drillability and efficiency, but most importantly in process safety. Case histories on how MPD has performed will be presented on the following: • allowed drilling to reach target depth in rank wildcat deepwater wells that have formations prone to severe circulation losses and narrow mud weight windows; • increased drilling efficiency by minimizing non-productive time associated with downhole pressure-related problems and by allowing for the setting of deeper casing seats; • enhanced operational and process safety by allowing for immediate detection of kicks, losses and other critical downhole events. • provided riser gas mitigation capabilities that can detect a gas influx once it enters the drilling fluid stream, and not after it has already broken out above the rig blow-out preventers (BOPs).
Reservoir engineers cannot capture full value from waterflood projects on their own. Cross-functional participation from earth sciences, production, drilling, completions, and facility engineering, and operational groups is required to get full value from waterfloods. Waterflood design and operational case histories of cross-functional collaboration are provided that have improved life cycle costs and increased recovery for onshore and offshore waterfloods. The role that water quality, surveillance, reservoir processing rates, and layered reservoir management has on waterflood oil recovery and life cycle costs will be clarified. Techniques to get better performance out of your waterflood will be shared.
With speakers from various disciplines and professions, the SPE Distinguished Lecturer program focuses on the hottest trends, tools, and technology in E&P around the globe. View the complete 2018-2019 Distinguished Lecturer schedule at www.spe.org/dl/schedule.php.
This is an in-depth course that is designed to provide the participants with a solid understanding of reservoir engineering and associated modern theories in order to manage and maximize hydrocarbon recovery. Hands-on examples and exercises are used throughout the course to help participants with understanding key performance concepts. Participants are encouraged to bring their own laptop computer to class.
Microfracturing is an excellent method of obtaining direct stress measurements, not only in shales, but in conventional reservoirs as well. Recent advances have shown that microfracturing can help improve reservoir management by guiding well placement, completion design, and perforation strategy. Microfracturing consists of isolating small test intervals in a well between inflatable packers, increasing the pressure until a small fracture forms and then by conducting a few injection and shut-in cycles, extend the fracture beyond the influence of the wellbore. Results show that direct stress measurements can be successfully acquired at multiple intervals in a few hours and the vertical scale nearly corresponds to electric log resolution. Therefore, microfracture testing (generally performed in a pilot / vertical well) is an appropriate choice for calibrating log derived geomechanical models and obtaining a complete, accurate, and precise vertical stress profile. This talk describes the microfracturing process and presents several examples that led to increased hydrocarbon recovery by efficient stimulation and/or completion design. Case studies presented range from optimizing hydraulic fracturing in unconventionals, determining safe waterflood injection rates in brownfields, and improving perforation placement in ultra deepwater reservoirs.
Mayank Malik is the Global Formation Testing Expert in Chevron's Energy Technology Company and is a champion for advancing research on microfracturing. He holds a B.S. in Mechanical Engineering from Delhi College of Engineering (India), MS in Mechanical Engineering from University of Toronto (Canada), and Ph.D. in Petroleum Engineering from The University of Texas at Austin (USA). Malik has authored numerous papers on petrophysics, formation testing, and microfracturing. He is currently serving on the SPE ATCE Formation Evaluation committee and is also the Chairman for SPWLA Formation Testing Special Interest Group.
As we have seen with the advent of the shale oil revolution in the United States, the development of new technology plays an important role in the oil and gas industry. It’s an enabler in reducing capital costs, simplifying production and increasing capacity of new or existing facilities. It can make a marginal project into a profitable development.
Progressing technology, while dealing with significant risk, is a challenge that can be overcome through a technology qualification process. A Technology Qualification Program (TQP) provides a means to identifying the risks and taking the correct steps to mitigate it; not avoid it.
This lecture summarizes the required steps involved in qualifying technology and how to keep track of technology development through the Technology Readiness Level (TRL) ranking system. In addition, some of the pitfalls in executing a TQP program are identified and discussed with emphasis on both component and system testing. Examples are given to illustrate the danger in taking shortcuts when executing the qualification plan.
Data from a recent subsea separation qualification program is presented comparing test results between CFDs, model fluid and actual crude testing at operating conditions. Knowing the limitations of the tools and testing system selected is an important step in closing the gaps identified in the TQP program.
The TRL has evolved at a faster pace and has become more acceptable in the oil and gas industry then the TQP. Nonetheless, continued standardization of both the TQP and TRL is still necessary in order to reduce overall cost of developing technology and allow faster implementation.
Increasing interest by governments worldwide on reducing CO2 released into the atmosphere form a nexus of of opportunity with enhanced oil recovery which could benefit mature oil fields in nearly every country. Overall approximately two-thirds of original oil in place (OOIP) in mature conventional oil fields remains after primary or primary/secondary recovery efforts have taken place. CO2 enhanced oil recovery (CO2 EOR) has an excellent record of revitalizing these mature plays and can dramatically increase ultimate recovery. Since the first CO2 EOR project was initiated in 1972, more than 154 additional projects have been put into operation around the world and about two-thirds are located in the Permian basin and Gulf coast regions of the United States. While these regions have favorable geologic and reservoir conditions for CO2 EOR, they are also located near large natural sources of CO2.
In recent years an increasing number of projects have been developed in areas without natural supplies, and have instead utilized captured CO2 from a variety of anthropogenic sources including gas processing plants, ethanol plants, cement plants, and fertilizer plants. Today approximately 36% of active CO2 EOR projects utilize gas that would otherwise be vented to the atmosphere. Interest world-wide has increased, including projects in Canada, Brazil, Norway, Turkey, Trinidad, and more recently, and perhaps most significantly, in Saudi Arabia and Qatar. About 80% of all energy used in the world comes from fossil fuels, and many industrial and manufacturing processes generate CO2 that can be captured and used for EOR. In this 30 minute presentation a brief history of CO2 EOR is provided, implications for utilizing captured carbon are discussed, and a demonstration project is introduced with an overview of characterization, modeling, simulation, and monitoring actvities taking place during injection of more than a million metric tons (~19 Bcf) of anthropogenic CO2 into a mature waterflood.
Longer versions of the presentation can be requested and can cover details of geologic and seimic characterization, simulation studies, time-lapse monitoring, tracer studies, or other CO2 monitoring technologies.
UntitledExcessive Water Production Diagnostic and Control - Case Study Jake O...Mohanned Mahjoup
For mature fields, Excessive water production is a complex subject in the oil and gas industries and has a serious economic and environmental impact. Some argue that oil industry is effectively water industry producing oil as a secondary output. Therefore, it is important to realize the different mechanisms that causing water production to better evaluate existing situation and design the optimum solution for the problem. This paper presents the water production and management situation in Jake oilfield in the southeast of Sudan; a cumulative of 14 MMBbl of water was produced till the end of 2014, without actual plan for water management in the field, only conventional shut-off methods have been tested with no success. Based on field production data and the previously applied techniques, this work identified the sources of water problems and attempts to initialize a strategy for controlling the excessive water production in the field. The production data were analyzed and a series of diagnostic plots were presented and compared with Chan’s standard diagnostic plot. As a result, distinction between channeling and conning for each well was identified; the work shows that channeling is the main reason for water production in wells with high permeability sandstone zone while conning appears only in two wells. Finally, the wells were classified according to a risk factor and selections of the candidate wells for water shut off were presented.
Adoption of the applied surface-backpressure types of managed pressure drilling (MPD) technologies in deepwater have mainly involved the use of a rotating control device (RCD). The RCD creates a closed drilling system in which the flow out of the well is diverted towards an automated MPD choke manifold (with a high-resolution mass flow meter) that aside from regulating backpressure also increases sensitivity and reduces reaction time to kicks, losses, and other unwanted drilling events. This integration of MPD equipment into floating drilling rigs to provide them with MPD capabilities, including the capacity to perform pressurized mud cap drilling (PMCD) and riser gas mitigation (RGM), has produced improvements not only in drillability and efficiency, but most importantly in process safety. Case histories on how MPD has performed will be presented on the following: • allowed drilling to reach target depth in rank wildcat deepwater wells that have formations prone to severe circulation losses and narrow mud weight windows; • increased drilling efficiency by minimizing non-productive time associated with downhole pressure-related problems and by allowing for the setting of deeper casing seats; • enhanced operational and process safety by allowing for immediate detection of kicks, losses and other critical downhole events. • provided riser gas mitigation capabilities that can detect a gas influx once it enters the drilling fluid stream, and not after it has already broken out above the rig blow-out preventers (BOPs).
Reservoir engineers cannot capture full value from waterflood projects on their own. Cross-functional participation from earth sciences, production, drilling, completions, and facility engineering, and operational groups is required to get full value from waterfloods. Waterflood design and operational case histories of cross-functional collaboration are provided that have improved life cycle costs and increased recovery for onshore and offshore waterfloods. The role that water quality, surveillance, reservoir processing rates, and layered reservoir management has on waterflood oil recovery and life cycle costs will be clarified. Techniques to get better performance out of your waterflood will be shared.
With speakers from various disciplines and professions, the SPE Distinguished Lecturer program focuses on the hottest trends, tools, and technology in E&P around the globe. View the complete 2018-2019 Distinguished Lecturer schedule at www.spe.org/dl/schedule.php.
This is an in-depth course that is designed to provide the participants with a solid understanding of reservoir engineering and associated modern theories in order to manage and maximize hydrocarbon recovery. Hands-on examples and exercises are used throughout the course to help participants with understanding key performance concepts. Participants are encouraged to bring their own laptop computer to class.
Microfracturing is an excellent method of obtaining direct stress measurements, not only in shales, but in conventional reservoirs as well. Recent advances have shown that microfracturing can help improve reservoir management by guiding well placement, completion design, and perforation strategy. Microfracturing consists of isolating small test intervals in a well between inflatable packers, increasing the pressure until a small fracture forms and then by conducting a few injection and shut-in cycles, extend the fracture beyond the influence of the wellbore. Results show that direct stress measurements can be successfully acquired at multiple intervals in a few hours and the vertical scale nearly corresponds to electric log resolution. Therefore, microfracture testing (generally performed in a pilot / vertical well) is an appropriate choice for calibrating log derived geomechanical models and obtaining a complete, accurate, and precise vertical stress profile. This talk describes the microfracturing process and presents several examples that led to increased hydrocarbon recovery by efficient stimulation and/or completion design. Case studies presented range from optimizing hydraulic fracturing in unconventionals, determining safe waterflood injection rates in brownfields, and improving perforation placement in ultra deepwater reservoirs.
Mayank Malik is the Global Formation Testing Expert in Chevron's Energy Technology Company and is a champion for advancing research on microfracturing. He holds a B.S. in Mechanical Engineering from Delhi College of Engineering (India), MS in Mechanical Engineering from University of Toronto (Canada), and Ph.D. in Petroleum Engineering from The University of Texas at Austin (USA). Malik has authored numerous papers on petrophysics, formation testing, and microfracturing. He is currently serving on the SPE ATCE Formation Evaluation committee and is also the Chairman for SPWLA Formation Testing Special Interest Group.
As we have seen with the advent of the shale oil revolution in the United States, the development of new technology plays an important role in the oil and gas industry. It’s an enabler in reducing capital costs, simplifying production and increasing capacity of new or existing facilities. It can make a marginal project into a profitable development.
Progressing technology, while dealing with significant risk, is a challenge that can be overcome through a technology qualification process. A Technology Qualification Program (TQP) provides a means to identifying the risks and taking the correct steps to mitigate it; not avoid it.
This lecture summarizes the required steps involved in qualifying technology and how to keep track of technology development through the Technology Readiness Level (TRL) ranking system. In addition, some of the pitfalls in executing a TQP program are identified and discussed with emphasis on both component and system testing. Examples are given to illustrate the danger in taking shortcuts when executing the qualification plan.
Data from a recent subsea separation qualification program is presented comparing test results between CFDs, model fluid and actual crude testing at operating conditions. Knowing the limitations of the tools and testing system selected is an important step in closing the gaps identified in the TQP program.
The TRL has evolved at a faster pace and has become more acceptable in the oil and gas industry then the TQP. Nonetheless, continued standardization of both the TQP and TRL is still necessary in order to reduce overall cost of developing technology and allow faster implementation.
The weakness of reservoir simulations is the lack of quantity and quality of the required input; their strength is the ability to vary one parameter at a time. Therefore, reservoir simulations are an appropriate tool to evaluate relative uncertainty but absolute forecasts can be misleading, leading to poor business decisions. As recovery processes increase in complexity, the impact of such decisions may have a major impact on the project viability. A responsible use of reservoir simulations is discussed, addressing both technical users and decision makers. The danger of creating a false confidence in forecasts and the value of simulating complex processes are demonstrated with examples. This is a call for the return of the reservoir engineer who is in control of the simulations and not controlled by them, and the decision maker who appreciates a black & white graph of a forecast with realistic uncertainties over a 3-D hologram in colour.
Safe Hose Assemble: From Factory to FieldDesign World
Jim Reilly of The United Distribution Group, GHX Industrial, LLC, and Rick Pitman of PSC will discuss the proper use of hydraulic hose, from fabrication and assembly to industry drivers and field usage. They will also explain NAHAD’s role in improving hose standards and what engineering personnel need to know.
isiMix Technology - Simulation of Mixing Processes
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Improving Operational Performance With Smarter, Cost-Effective Training ProgramsGSE Systems, Inc.
This webinar, presented in conjunction with Hydrocarbon Processing magazine, introduces a simulation-based training strategy that helps plant owners:
- Avoid risk and decrease cost
- Protect revenue
- Increase workforce agility
- Spend less while getting better results
- Get 80% of the learning at 20% of the cost
For more information, please visit www.envision-training.com.
Slide deck used during the SPE Live broadcast on 19 August 2020 with guest Doug Peacock, 2010-11 SPE Distinguished Lecturer and currently a Technical Director for GaffneyCline.
WATCH VIDEO: https://youtu.be/ykJhFkNUXqc
TRAINING COURSE: http://go.spe.org/peacockSPELIVE
The unitization process has evolved over the years and is now well established throughout the world with many countries having legislation for unitization.
Although there are generic agreements, each unitization agreement is unique and requires a wide range of issues to be considered.
Learn More: www.spe.org/dl/schedule.php
With speakers from various disciplines and professions, the SPE Distinguished Lecturer program focuses on the hottest trends, tools, and technology in E&P around the globe. View the complete 2019-2020 Distinguished Lecturer schedule at www.spe.org/dl/schedule.php.
Shale development in the US has been ongoing for at least the last decade, and many lessons can be learned from the US experience to help prevent air emissions and aquifer contamination in future developments around the world. Media reports and films such as "Gasland" imply that shale development is widely polluting fresh water aquifers and the atmosphere, with a wide range of estimates of contamination. This lecture examines the risk of contamination of aquifers through wellbores, either by hydrocarbon migration or hydraulic fracturing operations, and is primarily based on a comprehensive three-year study funded by the US National Science Foundation examining nearly 18,000 wells drilled in the Wattenberg Field in Colorado, plus other relevant studies. In the midst of the Wattenberg field is heavy urban and agricultural development, with over 30,000 water wells interspersed with the oil and gas wells, resulting in a natural laboratory to measure aquifer contamination. Lessons learned have universal applications with clear relationships established between well construction methods in both conventional and unconventional wells and contamination risks.
Over the past few years, significant advancements have been made in completion and stimulation designs in horizontal wells in unconventional plays, with the primary driver being the improvement of fracture contact area in these very low permeability reservoirs, to improve production volumes and recoveries. Fracture contact area with plug-and-perf or sliding sleeve systems have been intensified by increasing the density of contact points in the formation as well as proppant amount with great success. While these parameters have been optimized, other important parameters such as fracture conductivity and connectivity have been largely neglected. In the journey to improving contact area, proppant conductivity is often sacrified to save costs, and fracture stimulation treatments are overflushed in order to maximize operational efficiencies on multi-well pads. This presentation will highlight the importance of all of these parameters, and provides steps that can be taken to further optimize and enhance well producitivity and economics in the shale plays.
In order to determine a field’s hydrocarbon in place it is necessary to model the distribution of fluids throughout the reservoir. A water saturation vs. height (Swh) function provides this for the reservoir model. A good Swh function ensures the three independent sources of fluid distribution data are consistent. These being the core, formation pressure and electrical log data. The Swh function must be simple to apply, especially in reservoirs where it is difficult to map permeability or where there appears to be multiple contacts. It must accurately upscale the log and core derived water saturations to the reservoir model cell sizes.
This presentation clarifies the often misunderstood definitions for the free-water-level, transition zone and irreducible water saturation. Using capillary pressure theory and the concept of fractals, a practical Swh function is derived. Logs and core data from eleven fields, with very different porosity and permeability characteristics, depositional environments and geological age are compared. This study demonstrated how this Swh function is independent of permeability and litho-facies type and accurately describes the reservoir fluid distribution.
The shape of the Swh function shows that of the transition zone is related more to pore geometry rather than porosity or permeability alone. Consequently, this Swh function gives insights into a reservoir’s quality as determined by its pore architecture. A number of case studies are presented showing the excellent match between the function and well data. The function makes an accurate prediction of water saturations even in wells where the resistivity log was not run due to well conditions. The function defines the free water level, the hydrocarbon to water contact, net reservoir and the irreducible water saturation for the reservoir model. The fractal function provides a simple way to quality control electrical log and core data and justifies using core plug sized samples to model water saturations on the reservoir scale.
Extended-reach wells present difficult drilling challenges, which if inadequately understood and addressed can yield significant downside risks and extensive non-productive time (NPT). These challenges are mainly due to complex well designs that combine high-deviation and extended-reach wellbores with difficult geology and hostile environments. Understanding the challenges and developing solutions are important to deliver the well with the proper casing specifications for production purposes.
Geomechanically, due to their long reaches and high deviations, borehole instability and lost circulations are particularly dominant in the overburden shale sections of extended-reach and horizontal wells. However, a good understanding of the rock failure mechanisms and an innovative use of the wellbore strengthening techniques can mitigate these geomechanical challenges through integration with good drilling practices such as efficient equivalent circulating density (ECD) management and effective hole-cleaning strategies. In addition, the long open-hole exposure typically experienced in these wells can cause chemical, thermal and/or fluid penetration issues that can further complicate the difficult drilling conditions. These secondary influences further stress the importance of incorporating geomechanical understanding in drilling fluids formulation.
This presentation focuses on the geomechanical challenges of drilling extended-reach wells. It highlights the need to integrate geomechanical solutions with appropriate drilling practices, particularly solutions based on good understanding of the intricate relationship between borehole stability, lost circulation, ECD, hole cleaning and bottom-hole assembly (BHA) optimizations in overcoming the drilling performance limiters. A case history will be presented as an example.
Coiled tubing is a unique fluid and tool conveyance means used to intervene throughout the entire well lifetime. Its flexibility of use is certainly one of the largest in the oil-and-gas industry, ranging from logging to stimulation to cleanout and even drilling. However, for the longest time, it was only seen as a rudimentary fluid conveyance system, despite its capability to service any well deviation.
With the development of instrumented tools for downhole point measurements and the use of fiber optics for distributed sensing, the recent advent of coiled tubing real-time monitoring has completely transformed this image. The access to live wellbore information—such as pressure, temperature, or flow—along with accurate depth control thanks to casing collar locator and gamma ray sensors have greatly enhanced fluid placement. Meanwhile, the ability to monitor the load, torque, and accelerations the bottomhole assembly is subjected to significantly improves the performance and possibility to use and manipulate downhole tools. Thanks to real-time monitoring, a whole new realm of optimization possibility was discovered.
This lecture describes the various real-time measurements that are available today during coiled tubing interventions and how they can be used to provide the industry with faster, safer, and more efficient operations while maximizing return on investment. A wide range of applications and examples will be discussed. Through them, one will be able to appreciate how coiled tubing has now entered a new era where the limits of operational optimization still have not been reached.
Hybrid optimization of pumped hydro system and solar- Engr. Abdul-Azeez.pdffxintegritypublishin
Advancements in technology unveil a myriad of electrical and electronic breakthroughs geared towards efficiently harnessing limited resources to meet human energy demands. The optimization of hybrid solar PV panels and pumped hydro energy supply systems plays a pivotal role in utilizing natural resources effectively. This initiative not only benefits humanity but also fosters environmental sustainability. The study investigated the design optimization of these hybrid systems, focusing on understanding solar radiation patterns, identifying geographical influences on solar radiation, formulating a mathematical model for system optimization, and determining the optimal configuration of PV panels and pumped hydro storage. Through a comparative analysis approach and eight weeks of data collection, the study addressed key research questions related to solar radiation patterns and optimal system design. The findings highlighted regions with heightened solar radiation levels, showcasing substantial potential for power generation and emphasizing the system's efficiency. Optimizing system design significantly boosted power generation, promoted renewable energy utilization, and enhanced energy storage capacity. The study underscored the benefits of optimizing hybrid solar PV panels and pumped hydro energy supply systems for sustainable energy usage. Optimizing the design of solar PV panels and pumped hydro energy supply systems as examined across diverse climatic conditions in a developing country, not only enhances power generation but also improves the integration of renewable energy sources and boosts energy storage capacities, particularly beneficial for less economically prosperous regions. Additionally, the study provides valuable insights for advancing energy research in economically viable areas. Recommendations included conducting site-specific assessments, utilizing advanced modeling tools, implementing regular maintenance protocols, and enhancing communication among system components.
Industrial Training at Shahjalal Fertilizer Company Limited (SFCL)MdTanvirMahtab2
This presentation is about the working procedure of Shahjalal Fertilizer Company Limited (SFCL). A Govt. owned Company of Bangladesh Chemical Industries Corporation under Ministry of Industries.
Final project report on grocery store management system..pdfKamal Acharya
In today’s fast-changing business environment, it’s extremely important to be able to respond to client needs in the most effective and timely manner. If your customers wish to see your business online and have instant access to your products or services.
Online Grocery Store is an e-commerce website, which retails various grocery products. This project allows viewing various products available enables registered users to purchase desired products instantly using Paytm, UPI payment processor (Instant Pay) and also can place order by using Cash on Delivery (Pay Later) option. This project provides an easy access to Administrators and Managers to view orders placed using Pay Later and Instant Pay options.
In order to develop an e-commerce website, a number of Technologies must be studied and understood. These include multi-tiered architecture, server and client-side scripting techniques, implementation technologies, programming language (such as PHP, HTML, CSS, JavaScript) and MySQL relational databases. This is a project with the objective to develop a basic website where a consumer is provided with a shopping cart website and also to know about the technologies used to develop such a website.
This document will discuss each of the underlying technologies to create and implement an e- commerce website.
Explore the innovative world of trenchless pipe repair with our comprehensive guide, "The Benefits and Techniques of Trenchless Pipe Repair." This document delves into the modern methods of repairing underground pipes without the need for extensive excavation, highlighting the numerous advantages and the latest techniques used in the industry.
Learn about the cost savings, reduced environmental impact, and minimal disruption associated with trenchless technology. Discover detailed explanations of popular techniques such as pipe bursting, cured-in-place pipe (CIPP) lining, and directional drilling. Understand how these methods can be applied to various types of infrastructure, from residential plumbing to large-scale municipal systems.
Ideal for homeowners, contractors, engineers, and anyone interested in modern plumbing solutions, this guide provides valuable insights into why trenchless pipe repair is becoming the preferred choice for pipe rehabilitation. Stay informed about the latest advancements and best practices in the field.
Water scarcity is the lack of fresh water resources to meet the standard water demand. There are two type of water scarcity. One is physical. The other is economic water scarcity.
CFD Simulation of By-pass Flow in a HRSG module by R&R Consult.pptxR&R Consult
CFD analysis is incredibly effective at solving mysteries and improving the performance of complex systems!
Here's a great example: At a large natural gas-fired power plant, where they use waste heat to generate steam and energy, they were puzzled that their boiler wasn't producing as much steam as expected.
R&R and Tetra Engineering Group Inc. were asked to solve the issue with reduced steam production.
An inspection had shown that a significant amount of hot flue gas was bypassing the boiler tubes, where the heat was supposed to be transferred.
R&R Consult conducted a CFD analysis, which revealed that 6.3% of the flue gas was bypassing the boiler tubes without transferring heat. The analysis also showed that the flue gas was instead being directed along the sides of the boiler and between the modules that were supposed to capture the heat. This was the cause of the reduced performance.
Based on our results, Tetra Engineering installed covering plates to reduce the bypass flow. This improved the boiler's performance and increased electricity production.
It is always satisfying when we can help solve complex challenges like this. Do your systems also need a check-up or optimization? Give us a call!
Work done in cooperation with James Malloy and David Moelling from Tetra Engineering.
More examples of our work https://www.r-r-consult.dk/en/cases-en/
About
Indigenized remote control interface card suitable for MAFI system CCR equipment. Compatible for IDM8000 CCR. Backplane mounted serial and TCP/Ethernet communication module for CCR remote access. IDM 8000 CCR remote control on serial and TCP protocol.
• Remote control: Parallel or serial interface.
• Compatible with MAFI CCR system.
• Compatible with IDM8000 CCR.
• Compatible with Backplane mount serial communication.
• Compatible with commercial and Defence aviation CCR system.
• Remote control system for accessing CCR and allied system over serial or TCP.
• Indigenized local Support/presence in India.
• Easy in configuration using DIP switches.
Technical Specifications
Indigenized remote control interface card suitable for MAFI system CCR equipment. Compatible for IDM8000 CCR. Backplane mounted serial and TCP/Ethernet communication module for CCR remote access. IDM 8000 CCR remote control on serial and TCP protocol.
Key Features
Indigenized remote control interface card suitable for MAFI system CCR equipment. Compatible for IDM8000 CCR. Backplane mounted serial and TCP/Ethernet communication module for CCR remote access. IDM 8000 CCR remote control on serial and TCP protocol.
• Remote control: Parallel or serial interface
• Compatible with MAFI CCR system
• Copatiable with IDM8000 CCR
• Compatible with Backplane mount serial communication.
• Compatible with commercial and Defence aviation CCR system.
• Remote control system for accessing CCR and allied system over serial or TCP.
• Indigenized local Support/presence in India.
Application
• Remote control: Parallel or serial interface.
• Compatible with MAFI CCR system.
• Compatible with IDM8000 CCR.
• Compatible with Backplane mount serial communication.
• Compatible with commercial and Defence aviation CCR system.
• Remote control system for accessing CCR and allied system over serial or TCP.
• Indigenized local Support/presence in India.
• Easy in configuration using DIP switches.
Hierarchical Digital Twin of a Naval Power SystemKerry Sado
A hierarchical digital twin of a Naval DC power system has been developed and experimentally verified. Similar to other state-of-the-art digital twins, this technology creates a digital replica of the physical system executed in real-time or faster, which can modify hardware controls. However, its advantage stems from distributing computational efforts by utilizing a hierarchical structure composed of lower-level digital twin blocks and a higher-level system digital twin. Each digital twin block is associated with a physical subsystem of the hardware and communicates with a singular system digital twin, which creates a system-level response. By extracting information from each level of the hierarchy, power system controls of the hardware were reconfigured autonomously. This hierarchical digital twin development offers several advantages over other digital twins, particularly in the field of naval power systems. The hierarchical structure allows for greater computational efficiency and scalability while the ability to autonomously reconfigure hardware controls offers increased flexibility and responsiveness. The hierarchical decomposition and models utilized were well aligned with the physical twin, as indicated by the maximum deviations between the developed digital twin hierarchy and the hardware.
Verifying Performance and Capability of New Technology for Surface and Subsurface Facilities
1. Society of Petroleum Engineers
Distinguished Lecturer Program
www.spe.org/dl
1
Ed Grave
Verifying Performance and Capability
of New Technology for Surface and
Subsea Facilities
2. Presentation Outline
• Why Qualify?
• Technology Qualifying Program (TQP)
• Technical Readiness Level (TRL)
• TQP Pitfalls
• Subsea Separation Qualification Example
• Summary
2
3. Why Qualify?
• Enables new technology implementation
– Reduces capital costs
– Increases production/efficiency
– Improves reliability
• Identifies and reduces risks that can be
managed
• Confirmation that a technology will
function with confidence
3
4. Qualification Program
• Is a process that identifies & reduces
uncertainties that are manageable
• Two very useful documents for subsea:
– Det Norske Veritas (DNV-RP-A203)
– American Petroleum Institute (API-RP-17N)
• Most companies have their own
customized qualification programs
4
5. Qualification Program
Technology qualification
steps
5
Steps Description
1 Qualification Basis Facts & objective identified
2 Technology Assessment Novelty, challenges, gaps
3 Threat Assessment Identifies failure modes & risks
4 Technology Qualification
Plan (TQP)
Strategy to manage risks
5 Execution Plan Execution of TQP (tests, analysis)
6 Performance Assessment Review of collected evidence
Reference: Horpestad, Eirik; “Technology Qualification of
Equipment in Subsea Production Systems”, Master Thesis,
NTNU University 2012
6. API17N TRL Interpretation
Specific for Subsea Production System
6
TRL Stage Description
0 Unproven Concept No Analysis
1 Analytically Proven Experimental Research
2 Physically Proven Lab Tested
3 Prototype Tested Pilot Test-Robust & Reliable
4 Environment Tested Commercial Demonstration
5 System Tested System Integration
6 System Installed Full Scale System Test
7 Field Proven Proving Operation Over Time
1
2
3
Gate Reviews – assessment at different phases…
7. API17N TRC/TRL
Interpretation
7
Significant development required/unachievable during project timeline
Work required before the next stage of the project
Ready for use
Some additional required- achievable during project
TRL
Field
Proven
System
Installed
System
Tested
Environment
Tested
Prototype
Tested
Physically
Proven
Proven
Concept
Unproven
Concept
Technical Risk Category (TRC) TRC 7 6 5 4 3 2 1 0
Very High Technical Risk/
Unacceptable Reliability
A
<20%
High Technical Risk/
Low Reliability
B
20-80%
Medium Technical Risk/
Moderate Reliability
C
80-95%
Low Technical Risk/
Acceptable Reliability
D
>95%
Reducing Risk/Increasing Reliability
8. TQP Pit Falls
• Too much focus on engineering
and little on the process
• Many teams do not understand
what they are trying to do
• Too much focus on component
tests and not on the system
• More analytical models are needed
• TQP should not be an addendum
8
Reference: Markussen, Christian; “Experience with Technology
Qualification and Subsea Processing”, SPE Subsea Processing
Workshop, Stresa Italy 2012
9. TQP Pit Falls
• One member is driving the show
• No representation by either research,
project or operations
• No involvement from supplier
• Insufficient stakeholders support
• Short cuts due to project pressure
• Insufficient expertise and experience
– Leads to incorrect assumptions
– Poor Execution Plan
9
10. Pit Fall Example
10
Performance
Difference
between N2
and NG
Reference: Austrheim, Trond; “Re-entrainment Correlations for
Demisting Cyclones at Elevated Pressures on a Range of Fluids”,
Energy & Fuels, May 2009
Verlaan Demisting Cyclones
High Pressure Separation – Not testing device/system at
expected operating conditions
11. Qualifying subsea separation for shallow
water applications <1500m of water depth
11
• Flexible to a wide range of fluid
and operating conditions
Example – Subsea Separation
Inlet nozzles with Inlet Vane Diffusers
Perforated
baffles
Sand removal devices
Dome with
demisting cyclones
Reference: “Qualification of a Subsea Separator…”, M.R. Anderson
& E.J. Grave, OTC 25367-MS, May 2014
12. Compact Separation for Deep
Water (<1500m)
2009 From Concept to Deployment 2014
Conceptual Design
• Robust, flexible design
• Wide API Gravity
• Sand handling system
• Integrated Degassing
High Pressure
System Testing
• Half scale testing
• Real crudes, natural
gas
• Simulated operating
conditions
Proof of Concept
• CFD analysis, Dynamic
modeling
• Low pressure testing w/
model oils, brine, sand
12
TRL 0-1 TRL 2-3 TRL 4-5 TRL 6-7
13. Example – Subsea Separation
• CFD Simulations – screened a number of
designs, improved feed inlet, flow profile, etc.
• Model Fluid Tests – validate CFD models
– Test Matrix cover range of fluid properties
– Appropriate scale to minimize geometry effects
– Attention to sampling points, repeatability…
• High Pressure Tests
– Crude oil, synthesized water, methane gas
– Similar test matrix & fluid properties
– Same scale with the same internals
13
14. • Data & visual observations used to validate CFD models
• Provides ability to see fluid flow patterns
• Further improvements made and tested prior to high pressure test
14
Model Fluid Testing
15. • CFD models correctly predicted biased flow
patterns in the inlet and settling sections
• CFD does not predict effect on emulsion and
foam due to pressure drop across baffles
Splashing
through baffles
15
CFD & Models Validation
16. • Tests are most representative of field applications
• Tests performed at different flow rates,
temperatures, & water cuts using three different
crudes, saline water & methane gas at 45 bar-g
16
Separator is the same
diameter, length and
with the same
internals as tested
with model oils
High Pressure Testing With
Crude Oil and Natural Gas
17. • Although the physical properties (density, viscosity,
surface tension) are similar, chemical interactions
and emulsion stability are not the same
• For this case, model oil performed poorly
17
High Pressure Testing With Crude Oil
and Natural Gas
Model Oil 50 C⁰
Total Flowrate, (m3/hr)
Crude Oil at
Pressure 50 C⁰
Oil in Water (OIW) vs Total Flow Rate; API 35⁰
10000
8000
2000
6000
4000
0
Oil in Water (OIW) vs Total Flow Rate; API 35⁰
20%WC
40%WC
70%WC
18. • …but the oil quality was worse during the high pressure
tests compared to the model oil at the same interface
level
18
High Pressure Testing With Crude Oil
and Natural Gas
Model Oil 50⁰C
Total Flowrate, (m3/hr)
Crude Oil 50⁰C
Water in Oil (WiO) vs Total Flow Rate; API35⁰Water in Oil (WiO) vs Total Flow Rate;
API35⁰
Total Flowrate, (m3/hr)
20%WC
40%WC
70%WC
35%
30%
25%
20%
15%
10%
5%
0%
WIOOut
19. Summary
• Technology Qualification is an enabler!!
– Mitigates risks
– Implements technology
• Existing industry standards are a good
starting point
• Not all TQPs are equal…leads to confusion
• Careful selection of the Qualification team
• Standardized tests will lead to savings
• Don’t cheat!!
19
20. Society of Petroleum Engineers
Distinguished Lecturer Program
www.spe.org/dl 20
Your Feedback is Important
Enter your section in the DL Evaluation Contest by
completing the evaluation form for this presentation
Visit SPE.org/dl
22. COMPUTATIONAL FLUID DYNAMICS (CFD)
• Evaluate original separator design
• Optimized inlet piping, feed
arrangement, and perforated baffle
design
• Comparison between full and
small-scale geometries
• Fixed separator design used
during model fluid tests and high-
pressure, “live” crude tests
22
Original
Design
Improved
Example – Subsea Separation
23. • Computational Fluid Dynamics (CFD) is a
good tool to inexpensively vet or improve
technology
• CFDs must be validated with model fluids
resembling expected field conditions
• Model fluids emulsion and foaming tendencies
do not reflect real crudes
• For the examples presented model oil testing
alone would have resulted in an incorrect
design
23
Summary
24. Technical Readiness Level
• Developed by NASA (1970’s)
– Risk management tool
– Communication tool between
technologists & managers
– Keeps track of technology
development stage
– Reinforces the Qualification
Process
24
Reference: Warwick, Alistair; “Meeting The Challenge of
Deepwater Development”, Offshore Magazine, Feb 2011
$