This white paper proposes a subsea separation system using cyclonic technology to improve the economic viability of developing tight, low reserve gas fields in the Southern North Sea. Computational fluid dynamics was used to verify that a cyclone unit could effectively separate solids from well fluids on the seabed. An accumulator would collect solid particles for removal by ROV, while a pipeline would transport separated gas to an offshore platform. Economic modeling indicated the proposed subsea system could reduce costs compared to conventional approaches, making marginal fields commercially feasible.
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.
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.
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.
Big Data is an emerging technology in Information Management that holds promising returns on investment, as it can provide advanced analytics capabilities. It is well suited for large enterprises, and when used properly, it can lead to breakthroughs in analytics, deriving information from data that was previously not possible. However, a Big Data project cannot be approached using traditional IT system design and methods. Its success relies on teamwork and collaboration among petroleum engineering subject matter experts, senior IT professionals, and data scientists. To ensure that Big Data initiatives do not deliver poor results or disappoint, Big Data projects require significant preparation, which dramatically increases the chances of success. This presentation provides practical information about how to get started and what to consider in your plan, and it gives useful tips and examples for planning and executing a Big Data project. At the end of the presentation, attendees will know what Big Data is, what it offers, how to plan such projects, what the roles and responsibilities are for the key project members, and how these projects should be implemented to benefit their organization. Big Data analytics offers enterprises a chance to move beyond simply gathering data to analyzing, mining, and correlating results for insights that translate into business solutions.
Collaborative Working helps assets to operate more efficiently and as one team, resulting in higher production, less cost, lower HSE exposure and higher morale. Shell has pursued the Digital Oilfield for the last fifteen years, under the heading of Smart Fields. Collaborative Work Environments (CWEs) were implemented in the majority of assets, live environments now cover over 60% of Shell’s production. The presentation will provide an overview of current Collaborative Work Environments. It will show examples of CWEs in different types of assets, and of the business value achieved. The large scale implementation was achieved through a structured deployment programme, taking assets and projects through a standard design, implementation and embedding approach. To embed and sustain the new ways of working, a focus on the people aspects and change management has been critical. Each project included process design, awareness and training sessions and establishing coaches, support and continuous improvement.
Frans van den Berg is currently an independent consultant in the design of Digital Oilfields and Collaborative Work Environments. He has worked 32 years in Shell, lastly in its global Smart Fields or Digital Oilfield program in the technology organisation in the Netherlands. There he led the global implementation of Collaborative Work Environments in Shell. He has held various positions as a petroleum engineer, head of petrohysics and asset development leader in operational roles and in global technology deployment. He worked ten years in Malaysia and Thailand. Frans has a PhD and a Master in Physics from Leiden University in the Netherlands. He has been involved in the organisation of the SPE Intelligent Energy and Digital Energy Conferences since 2008.
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.
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.
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.
Big Data is an emerging technology in Information Management that holds promising returns on investment, as it can provide advanced analytics capabilities. It is well suited for large enterprises, and when used properly, it can lead to breakthroughs in analytics, deriving information from data that was previously not possible. However, a Big Data project cannot be approached using traditional IT system design and methods. Its success relies on teamwork and collaboration among petroleum engineering subject matter experts, senior IT professionals, and data scientists. To ensure that Big Data initiatives do not deliver poor results or disappoint, Big Data projects require significant preparation, which dramatically increases the chances of success. This presentation provides practical information about how to get started and what to consider in your plan, and it gives useful tips and examples for planning and executing a Big Data project. At the end of the presentation, attendees will know what Big Data is, what it offers, how to plan such projects, what the roles and responsibilities are for the key project members, and how these projects should be implemented to benefit their organization. Big Data analytics offers enterprises a chance to move beyond simply gathering data to analyzing, mining, and correlating results for insights that translate into business solutions.
Collaborative Working helps assets to operate more efficiently and as one team, resulting in higher production, less cost, lower HSE exposure and higher morale. Shell has pursued the Digital Oilfield for the last fifteen years, under the heading of Smart Fields. Collaborative Work Environments (CWEs) were implemented in the majority of assets, live environments now cover over 60% of Shell’s production. The presentation will provide an overview of current Collaborative Work Environments. It will show examples of CWEs in different types of assets, and of the business value achieved. The large scale implementation was achieved through a structured deployment programme, taking assets and projects through a standard design, implementation and embedding approach. To embed and sustain the new ways of working, a focus on the people aspects and change management has been critical. Each project included process design, awareness and training sessions and establishing coaches, support and continuous improvement.
Frans van den Berg is currently an independent consultant in the design of Digital Oilfields and Collaborative Work Environments. He has worked 32 years in Shell, lastly in its global Smart Fields or Digital Oilfield program in the technology organisation in the Netherlands. There he led the global implementation of Collaborative Work Environments in Shell. He has held various positions as a petroleum engineer, head of petrohysics and asset development leader in operational roles and in global technology deployment. He worked ten years in Malaysia and Thailand. Frans has a PhD and a Master in Physics from Leiden University in the Netherlands. He has been involved in the organisation of the SPE Intelligent Energy and Digital Energy Conferences since 2008.
"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.
The Completion Engineer integrates the requirements of a number of other disciplines (Reservoir, Drilling, Production, etc) to maximize the value of a hydrocarbon resource. This almost always requires evaluating competing and conflicting factors to determine the 'best' option for a particular problem. This talk will demonstrate a decision making process that allows the stakeholders to compare various options in a fair and roboust way. Two real onshore or offshore examples will be reviewed depending on SPE chapter interest. Members will take away a new methodology on how to compare competing factors that influence a completion or well design.
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.
In these times of low oil and gas prices, the drive to provide 'more for less' has never been greater. One key component in achieving this is the ability to accurately monitor the production rates along a wellbore and across a reservoir. Ideally a range of different measurements should be available on-demand from all points in all wells. Clearly conventional sensors such as downhole pressure and temperature gauges, flow meters, geophone arrays and production logging tools can provide part of the solution but the cost of all these different sensors limits their widespread deployment. Fibre-optic Distributed Acoustic Sensing, or DAS for short, is changing that. Using an optical fibre deployed in a cable from surface to the toe of a well DAS, often in combination with fibre-optic Distributed Temperature Sensing (DTS), provides a means of acquiring high resolution seismic, acoustic and temperature data at all points in real-time. Since the first downhole demonstrations of DAS technology in 2009 there has been rapid progress in developing the technology and applications, to the point where today it is being used to monitor the efficiency of hydraulic fracture treatments, provides continuous flow profiling across the entire wellbore and is used as a uniquely capable tool for borehole seismic acquisition. With optical fibre installed in your wells and DAS acquiring data, there is now the ability to cost effectively and continuously monitor wells and reservoirs to manage them in real-time in order to optimise production.
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.
Drilling systems automation is the real-time reliance on digital technology in creating a wellbore. It encompasses downhole tools and systems, surface drilling equipment, remote monitoring and the use of models and simulations while drilling. While its scope is large, its potential benefits are impressive, among them: fewer workers exposed to rig-floor hazards, the ability to realize repeatable performance drilling, and lower drilling risk. While drilling systems automation includes new drilling technology, it is most importantly a collaborative infrastructure for performance drilling. In 2008, a small group of engineers and scientists attending an SPE conference noted that automation was becoming a key topic in drilling and they formed a technical section to investigate it further. By 2015, the group reached a membership of sixteen hundred as the technology rapidly gaining acceptance. Why so much interest? The benefits and promises of an automated approach to drilling address the safety and fundamental economics of drilling. What will it take? Among the answers are an open collaborative digital environment at the wellsite, an openness of mind to digital technologies, and modified or new business practices. What are the barriers? The primary barrier is a lack of understanding and a fear of automation. When will it happen? It is happening now. Digital technologies are transforming the infrastructure of the drilling industry. Drilling systems automation uses this infrastructure to deliver safety and performance, and address cost.
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.
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).
What are my 3P Reserves? Haas Petroleum Engineering Serviceshaasengineering
What is the best way to estimate your 3P reserves? President of Haas Petroleum Engineering Services Thad Toups gave this presentation on Haas' internal analytics and auditing methodology.
The oil and gas industry places great reliance on layers-of-defenses, or barrier thinking, to protect against process safety incidents. Human performance continues to be the single most widely relied on barrier: whether as a defense in its own right, or in implementing, inspecting, maintaining and supporting engineered defenses. Human error, in its many forms, also continues to be a significant threat to the reliability of engineered and organizational defenses. While approaches to developing and assuring layers of defenses strategies have become increasingly formalized and rigorous in recent years, many organizations struggle to know how to ensure the human defenses they rely on are as robust as they reasonably can be when those strategies are developed and implemented. Drawing on the 2005 explosion and fire at the Buncefield fuel storage site as a case study, the presentation considers issues associated with the independence and effectiveness of human defenses. The key idea SPE members should take away from the lecture is that organizations can improve the strength of their human defenses by being clearer about exactly what it is they expect and intend of human performance to protect against threats. The presentation sets out challenges organizations can use to ensure the human defenses they rely on are as robust and reliable as they reasonably can be.
Lean - Tight Oil Design & Construction
Eliminate Waste - simplify, streamline, continuous improvement
Value Add, Non Value Add, Waste
Value Stream Mapping Tight Oil
Lean Primary Development
Weekly Work Plan
Prototyping Water Treatment Example
Transition to Lean: Integrated, Last Planner System, Continuous Process, Continuous Improvement / Innovation
"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.
The Completion Engineer integrates the requirements of a number of other disciplines (Reservoir, Drilling, Production, etc) to maximize the value of a hydrocarbon resource. This almost always requires evaluating competing and conflicting factors to determine the 'best' option for a particular problem. This talk will demonstrate a decision making process that allows the stakeholders to compare various options in a fair and roboust way. Two real onshore or offshore examples will be reviewed depending on SPE chapter interest. Members will take away a new methodology on how to compare competing factors that influence a completion or well design.
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.
In these times of low oil and gas prices, the drive to provide 'more for less' has never been greater. One key component in achieving this is the ability to accurately monitor the production rates along a wellbore and across a reservoir. Ideally a range of different measurements should be available on-demand from all points in all wells. Clearly conventional sensors such as downhole pressure and temperature gauges, flow meters, geophone arrays and production logging tools can provide part of the solution but the cost of all these different sensors limits their widespread deployment. Fibre-optic Distributed Acoustic Sensing, or DAS for short, is changing that. Using an optical fibre deployed in a cable from surface to the toe of a well DAS, often in combination with fibre-optic Distributed Temperature Sensing (DTS), provides a means of acquiring high resolution seismic, acoustic and temperature data at all points in real-time. Since the first downhole demonstrations of DAS technology in 2009 there has been rapid progress in developing the technology and applications, to the point where today it is being used to monitor the efficiency of hydraulic fracture treatments, provides continuous flow profiling across the entire wellbore and is used as a uniquely capable tool for borehole seismic acquisition. With optical fibre installed in your wells and DAS acquiring data, there is now the ability to cost effectively and continuously monitor wells and reservoirs to manage them in real-time in order to optimise production.
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.
Drilling systems automation is the real-time reliance on digital technology in creating a wellbore. It encompasses downhole tools and systems, surface drilling equipment, remote monitoring and the use of models and simulations while drilling. While its scope is large, its potential benefits are impressive, among them: fewer workers exposed to rig-floor hazards, the ability to realize repeatable performance drilling, and lower drilling risk. While drilling systems automation includes new drilling technology, it is most importantly a collaborative infrastructure for performance drilling. In 2008, a small group of engineers and scientists attending an SPE conference noted that automation was becoming a key topic in drilling and they formed a technical section to investigate it further. By 2015, the group reached a membership of sixteen hundred as the technology rapidly gaining acceptance. Why so much interest? The benefits and promises of an automated approach to drilling address the safety and fundamental economics of drilling. What will it take? Among the answers are an open collaborative digital environment at the wellsite, an openness of mind to digital technologies, and modified or new business practices. What are the barriers? The primary barrier is a lack of understanding and a fear of automation. When will it happen? It is happening now. Digital technologies are transforming the infrastructure of the drilling industry. Drilling systems automation uses this infrastructure to deliver safety and performance, and address cost.
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.
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).
What are my 3P Reserves? Haas Petroleum Engineering Serviceshaasengineering
What is the best way to estimate your 3P reserves? President of Haas Petroleum Engineering Services Thad Toups gave this presentation on Haas' internal analytics and auditing methodology.
The oil and gas industry places great reliance on layers-of-defenses, or barrier thinking, to protect against process safety incidents. Human performance continues to be the single most widely relied on barrier: whether as a defense in its own right, or in implementing, inspecting, maintaining and supporting engineered defenses. Human error, in its many forms, also continues to be a significant threat to the reliability of engineered and organizational defenses. While approaches to developing and assuring layers of defenses strategies have become increasingly formalized and rigorous in recent years, many organizations struggle to know how to ensure the human defenses they rely on are as robust as they reasonably can be when those strategies are developed and implemented. Drawing on the 2005 explosion and fire at the Buncefield fuel storage site as a case study, the presentation considers issues associated with the independence and effectiveness of human defenses. The key idea SPE members should take away from the lecture is that organizations can improve the strength of their human defenses by being clearer about exactly what it is they expect and intend of human performance to protect against threats. The presentation sets out challenges organizations can use to ensure the human defenses they rely on are as robust and reliable as they reasonably can be.
Lean - Tight Oil Design & Construction
Eliminate Waste - simplify, streamline, continuous improvement
Value Add, Non Value Add, Waste
Value Stream Mapping Tight Oil
Lean Primary Development
Weekly Work Plan
Prototyping Water Treatment Example
Transition to Lean: Integrated, Last Planner System, Continuous Process, Continuous Improvement / Innovation
Te ofrecemos una guía gratuita sobre Mallorca (España) para que tengas a mano información tan necesaria al viajar allí como dónde comer, qué ver o los mejores lugares para salir de fiesta.
William J 'Bill' Le Gray;
a Broad Multi-functional, ongoing Team Builder for Better
Business- via Optimal Workplace Organizing & Product
Conditions. (United States Program Development).
@FRESH EYES VISIONING, CBLG Associates, Cedar MI.
Often times we wonder why our lives have taken so many unexpected twists and turns. If God is so good and cares for us so much, why does it seem like failures and disappointments tend to characterize our lives? As soon as the Israelites were set free from 400 years of captivity, they were thrown a curve ball. This message helps us understand why.
To help reaching the Sustainable Development Goals, CGIAR must tap into Big Data. Within the programme on Climate Change for Agriculture and Food Security (CCAFS), researchers have already applied Big Data analytics to agricultural and weather records in Colombia, revealing how climate variation impacts rice yields. After defining its Open Data-Open Access strategy, CGIAR has launched an internal call for proposals for big data analytics platforms that will provide services to the Agri-Food system programmes and parners, and will interconnect the CGIAR data to other multi-disciplinary big data. The seminar will present the pespectives of the envisioned platforms.
Top ten universities in uk for construction managementEden Brown
Here is a list of top universities of UK from Guardian Top University Guide 2013 for construction-related jobs. Take a look if you are looking forward to purse construction management.
Webinar: CCS major project development lessons from the ZeroGen experienceGlobal CCS Institute
The ZeroGen Integrated Gasification Combined Cycle (IGCC) with CCS project, was a first-of-a-kind, commercial-scale CCS project proposal in Australia. Lessons learnt from this project include real-life project management experience integrating the key elements of a large-scale CCS project, from the technical to the commercial to stakeholder management.
This webinar was presented by Professor Andrew Garnett, Director, Centre for Coal Seam Gas, The University of Queensland. The Q&A session also included Martin Oettinger, Deputy Director, Low Emissions Technology for ACALET. Martin's career includes 6 years in a senior technical leadership role with ZeroGen.
Optimizing completions in deviated and extended reach wells is a key to safe drilling and optimum
production, particularly in complex terrain and formations. This work summarizes the systematic methodology
and engineering process employed to identify and refine the highly effective completions solution used in ERW
completion system and install highly productive and robust hard wares in horizontal and Extended Reach Wells
for Oil and Gas. A case study of an offshore project was presented and discussed. The unique completion design,
pre-project evaluation and the integrated effort undertaken to firstly, minimize completion and formation damage.
Secondly, maximize gravel placement and sand control method .Thirdly, to maximize filter cake removal
efficiencies. The importance of completions technologies was identified and a robust tool was developed .More
importantly, the ways of deploying these tools to achieve optimal performance in ERW’s completions was done.
The application of the whole system will allow existing constraints to be challenged and overcome successfully;
these achievements was possible, by applying sound practical engineering principle and continuous optimization,
with respect to the rig and environmental limitation space and rig capacity.
Keywords: Well Completions , Deviated and Extended Rearch Wells , Optimization
This discussion paper on Energy Well Integrity focuses on typical onshore unconventional oil or gas wells, which are generally similar to wells used for conventional oil or coal bed methane production. The major topics covered in this paper are well design, construction, use and abandonment. Issues of cementing practices and gas migration pathways are given special emphasis because they are key aspects in establishing and understanding well integrity.
CarbonNet storage site characterisation and selection processGlobal CCS Institute
The CarbonNet Project has undertaken an extensive geoscience evaluation programme to identify, characterise and select prospective offshore storage sites in the nearshore Gippsland Basin, in south eastern Australia.
The process builds upon basin and regional assessments undertaken at the national level, and focuses upon leads and play fairs assessed using a vast amount of geological data available from 50 years of petroleum exploration and developments in the basin.
CarbonNet geoscience work has been subject to independent scientific peer reviews, and external assurance certification by Det Norske Veritas against the recommended practise for geological storage of carbon dioxide (CO2) J203.
CarbonNet now holds five greenhouse gas assessments permits providing exclusive rights to explore, appraisal and develop a portfolio of CO2 storage sites.
The project has identified a prioritised storage site capable of storing in excess of 125 Mt of CO2 for which a 'Declaration of Storage' has been prepared which demonstrates the 'fundamental determinants' and probability assessment of potential CO2 plume paths as required under Australian CCS legislation'.
This webinar will be presented by Dr Nick Hoffman, CarbonNet Geosequestration Advisor, and will provide an overview of CarbonNet geoscience evaluation programme, referencing the relevant knowledge share products available on the Global CCS Institute website.
CarbonNet storage site characterisation and selection process
Improving Efficiency Tight Gas
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WHITE PAPER:
IMPROVING EFFICIENCY AND
REDUCING COST WHILST GETTING TO
THE TARGET
Neil Harvey, Abdullah Khan, Sermsak Manalertsakul
OSL Consulting, Hull, November 2015
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TABLE OF CONTENTS
1. EXECUTIVE SUMMARY ..........................................................................................3
2. INTRODUCTION ....................................................................................................5
3. REDUCING COSTS WHILST TARGETING TIGHT GAS............................................6
4. THE CLEVER THINKING ®
APPROACH.................................................................10
5. THE SOLUTION....................................................................................................14
6. CONCLUSION ......................................................................................................18
7. REFERENCES .......................................................................................................20
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1. EXECUTIVE SUMMARY
Developing stranded tight gas reserves has become one of the key issues in recent years, as
more conventional fields become depleted. Directional drilling from a platform is used to
develop single and multiple well gas fields. However, this method has high cost implications
for single well and dual well developments and may not be economically viable for low
reserve fields. Finding ways of improving the economic viability of tight, low reserve gas fields
in the SNS is becoming more important.
Improving the economic viability of tight, low reserve gas fields in the SNS may be achieved
using seabed separation technology so that the well fluid can then be exported to a nearby
offshore platform. Sand handling and disposal management is a significant challenge for the
design of this subsea unit. This presents an opportunity to develop a simple and economical
solution for such a subsea unit in the SNS, possibly using cyclonic processing techniques.
A study was initiated to propose a suitable separation system and a solid management
solution. The objective of the study was to:
Identify a suitable solid particle separation technology and investigate using CFD
Develop an outline process scheme and size the key process equipment
Investigate a suitable solids removal and disposal system
Develop a design of a proposed subsea separation skid
Perform an economic evaluation to assess the commercial feasibility of the project.
All possible options for the challenge, including cyclonic technology was assessed using OSL’s
unique Clever Thinking®
methodology. This approach ensured that the most suitable sand
removal solution was identified for further development.
The subsea production system typically consists of subsea wellhead systems with Christmas
trees, process equipment, subsea manifolds, tie-in and flowline systems for multiple well
production, umbilical systems, control systems and the export pipeline system. For the
separator a single cyclonic unit was selected from the number of possible solutions. The key
benefit of using this subsea separation technology is that it is a simple construction with no
moving parts. An accumulator will be situated underneath the cyclone collecting separated
solid particles from the well stream. A spherical design was implemented in the design of the
unit to avoid any possible dead spaces which cause difficulties in solids removal from the
container. A fiscal flow meter will measure the flowrate of the export gas from the separator,
prior to being transferred to the host platform through the subsea pipeline.
The accumulator will be emptied using an ROV. Whilst isolated from the cyclone, to allow
pressure reduction, the solids will be fluidised with water to allow slurry fluid to be transferred
to a container on the ROV vessel. The slurry will be treated and disposed of onshore in a safe
manner.
The success of this undertaking was greatly influenced by the close partnership with an
operating company whilst carrying out this conceptual study. The collaboration meant that
the overall team, made up of both OSL and operational personnel were able to combine
knowledge and experience whilst investigating solutions for recovering gas from stranded
offshore gas fields before transporting it using subsea pipelines to an adjacent platform.
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The Clever Thinking®
practise employs techniques that are designed to drive the creative
thought process and break-away from established thought patterns, this method is proven to
release potential from the team with a wealth of untapped ideas.
The proposed solution satisfies the defined design aspects and has overcome the potential
operational difficulties, providing strong financial benefits for single well tight gas marginal
field development. The proposed solution has proven to be attractive as it is technically
feasible, constructible, maintainable and economic.
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2. INTRODUCTION
There are currently many challenges in the gas production and supply markets such as gas
price, ageing assets, shareholders’ expectations, maintaining safe operations, UK oil and gas
security of supply. Developing new reserves has become one of the key issues in recent
years, especially the exploration of stranded gas reserves as more conventional fields become
depleted. A number of technologies have been studied in order to create economic viability
for future exploration.
It is estimated that there are more than 100 assets in the Southern North Sea (SNS) that are
labelled as stranded fields. These are a collection of tight reservoirs with distant
infrastructure, possibly with small volumes, and inconsistent gas qualities. The main reasons
why these resources have not yet been developed are related to cost and technology, though
some of these stranded tight gas fields may be successfully developed with the use of a
subsea well, horizontal drilling, and fracturing.
Directional drilling from a platform is used to develop single and multiple well gas fields.
However, this method has high cost implications for single well and dual well developments
and may not be economically viable for low reserve fields. Finding ways of improving the
economic viability of tight, low reserve gas fields in the SNS is becoming more important.
This may be achieved using seabed separation technology so that the well fluid can then be
exported to a nearby offshore platform through a subsea pipeline for further production. This
process will reduce the total cost of such projects due to the reduction of drilling distance,
and negating the requirement for a costly topside production platform and associated
structure.
Solids handling and disposal management is a significant challenge for the design of this
subsea unit. Solid particles may cause clogging and erosion in pipelines, pipework and
rotating machinery which threaten pipeline and system operations. This study will propose a
solution to this problem, which complements the selected separation process.
OSL Consulting (OSL) and its partner operating company recognise an opportunity to develop
a simple and economical solution for such a subsea unit in the SNS, possibly using cyclonic
processing techniques. The seabed unit is intended to segregate sand particles and proppants
released as part of hydraulic fracturing (fracking) activities.
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3. REDUCING COSTS WHILST TARGETING TIGHT
GAS
3.1. Tight Gas Fields
Natural gas present in low permeability geological formations is referred to as Tight Gas.
Tight Gas is defined as natural gas from reservoirs with an average matrix permeability of
less than 0.1 millidarcy (mD) [Ref. 1], however recently the German Society for Petroleum
and Coal Science and Technology (DGMK) announced a new definition for tight gas
reservoirs elaborated by the German petroleum industry, which includes reservoirs with an
average effective gas permeability less than 0.6 mD. This gas source mainly produces dry
gas due to the tight porosity of the reservoir formations.
The exploration and exploitation of this ‘Unconventional’ source of natural gas has up until
recent years been avoided due to prohibitive field development costs. Because of this many
gas discoveries and fields have been left undeveloped. In the UK Continental Shelf (UKCS)
the opportunity size is estimated at approximately 4TCF for new field developments and it is
expected that the figure is greater than this for further developments of existing fields.
3.2. Barriers to Targeting Offshore Tight Gas
3.2.1. Technology
Execution thus far has been complicated by the lack of available stimulation equipment for
the SNS. Recently this appears to have become less of an issue, with several service
companies implementing and offering skid based or otherwise portable fracturing spreads
for deployment on to temporary platforms or suitable temporary boats.
Developments in horizontal drilling have made the development of tight gas reservoirs more
promising. The bores can intersect natural fissures and fractures that are present in the
formation and improve the production from these reservoirs significantly.
Progress in hydraulic fracturing (fracking) techniques in recent years, due to the US Shale
Gas boom have also made vast improvements in the possible recovery rates of these fields.
3.2.2. Fracking
The main purpose and value of hydraulic fracturing in a low permeability formation is to
accelerate production. Significant stimulation of the well hydraulic fracturing (fracking) is
required to ensure commercial flows. Because of this the solids handling of the returning
proppant material (sand or aluminium oxide) is required.
3.2.3. Economics
Currently challenging economics hinder the development of the Tight gas fields. With the high
costs associated with well development and well stimulation costs there is a concern that
much of the unconventional gas resource such as tight gas is uneconomic to exploit.
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Distinct from the costs of designing and building a suitable topside platform, there are
significant and often uncertain development costs involved with the drilling. The cost of
drilling is particularly high when drilled horizontally for long distances before initiating the
fracking process.
3.3. Problem History
There are many low-reserve, tight gas fields, which are currently disregarded due to their
uneconomic nature.
Solids production is part and parcel of gas exploration and extraction. With tight gas fields
this is more of an issue due to the hydraulic fracturing that is required to obtain a suitable
production flow rate of gas from the field. The proppants used in the fracturing process
return to the surface with the gas and flowback liquids. There are many options that have
been developed to remove the associated solids in the gas streams. Generally, this separation
takes place on a platform. However, it is not economically feasible at lower reserves to
develop such fields, at the normal costs associated with the installation of the required
infrastructure.
This issue has affected the development of low-reserve tight gas fields as the costs of
supplying suitable processing equipment. OSL Consulting Engineers (OSL) have partnered
with a large European gas supply operator to undertake a conceptual study in collaboration to
find the most efficient and economical solution for subsea separation, including solids
removal,
3.4. The Tight Gas Challenge
Exploration of stranded tight gas reserves has become a challenging topic in recent years. A
number of technologies have been studied in order to create economic viability for future
exploration. Directional drilling from a platform is used to develop single and multiple well gas
fields.. However, this method has high cost implications for single well and dual well
developments and may not be economically viable for low reserve fields.
Solids removal will represent the main challenge in designing this package. Except in cases of
recovering solids caused by drilling, it is anticipated that at the beginning of the extraction,
solids presence will be relatively small. However, it may be the case, that after some time in
operation, the well may start producing solids at a high rate. If not managed and treated
properly, this will give rise to potential pipeline erosion issues, which will make the asset
inoperable. Generally, the production facilities experience a maximum solids production rate
during early production phase. When the well is established, solid production will decrease
and stay constant at a low rate, and may finally increase again when the well is depleting.
The amount and timing of the solids arrival is not predictable so a system must be installed to
remove any solids from the gas stream throughout its lifetime.
The solution to this issue must be able to operate on one or two wells at a time. It must be
simple and have a small footprint, but economically favourable and must require minimum
maintenance and intervention.
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3.5. Idea
The project partners have discussed ways of improving the economic viability of tight, low
reserve gas fields in the Southern North Sea. The partners see an opportunity to provide a
simple and economical solution using cyclonic processing techniques for separation of the well
fluids, using conventional technology but applied in a new environment.
This can be achieved via the installation of a skid located on the seabed which will utilise a
cyclone unit modified for subsea use to segregate sand and proppants particles used as part
of or as a result of well fracturing. Well fluids will then be exported to a nearby offshore
platform via a subsea pipeline for further processing as normal. This scheme aims to reduce
the total cost of such projects due to lower associated costs of drilling, equipment and
structures.
Solids handling and disposal management is a significant issue for the design of this subsea
unit. Solid particles may cause clogging and erosion in pipelines, pipework and rotating
machinery (installed on downstream platform) which threaten pipeline and system operations.
This can potentially lead to requiring additional pigging. The intention of the study was to
propose a solid management solution to this problem which complements the selected
separation process.
As part of the study the partners firstly confirmed whether cyclone technology is the best
option and examine all possible modifications of cyclonic technology and cyclone configuration
schemes suitable for subsea separation.
An important feature of the study involved the research and development work OSL carried
out in collaboration with a local research partner. Use of Computational Fluid Dynamics (CFD),
would ensure that the final solution of the cyclone performance was suitably verified and
optimised to meet the set project criteria.
3.6. Approach
The objective of the study was to:
Identify a suitable solid particle separation technology and investigate the technical
feasibility of the selected separation technology using CFD
Develop an outline overall process scheme and determine the suitable size of key
process equipment items and the main piping systems
Investigate a suitable solids disposal and handling management system for the safe
disposal of the separated solids from the produced well fluids
Develop a design of a proposed subsea separation skid and determine mechanical and
structural requirements to satisfy the constructability of the package
Perform an economic evaluation to assess the commercial feasibility of the project
considering direct costs, indirect costs and sale revenues.
All possible options for the challenge, including cyclonic technology was assessed using OSL’s
unique Clever Thinking®
methodology. This approach ensures that the most suitable sand and
proppant removal solution is identified for further development.
Following on from the assessment the process design was progressed with a basis of design,
process drawings, a solids disposal and handling study and preliminary process design,
including equipment sizing and line sizing.
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An important feature of this work is the research and development work OSL carried out in
collaboration with a local research institute. Thorough assessment and verification of the
process mechanics, carrying out solids/liquids separation performance of the process using
Computational Fluid Dynamics (CFD), ensured that the final solution of the cyclone
performance was verified. Assessing sensitivity analysis on process parameters and inlet
particle distribution, the model was used to optimise the solution using various numerical
methods and algorithms, highlighting any further developments to improve the performance.
Further design development followed on with the team generating 3-D models of wellhead,
separation equipment and controls with a standard frame size.
A cost estimate followed on from the design estimating the total cost of the selected option
including pipeline costs and solids removal costs. This was then further developed into a high
level economic assessment of the overall project. This economic assessment consisted of a
high level cost analysis which incorporates drilling costs, gas reserves value, capital
expenditure (capex) and operational expenditure (opex)
This problem solving approach is a template deployable to other similar projects in the oil and
gas industries:
Assess the problem
Clever Thinking®
Proposed list of possible solutions
Identify best solution
Develop design
Verify design
Further design development
Cost and economic assessment.
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4. THE CLEVER THINKING ® APPROACH
4.1. What is Clever Thinking®
?
Clever Thinking®
is a unique method of addressing technical challenges. The Clever Thinking®
philosophy has been developed to describe the distinctive way in which OSL strives to
conduct business. It aims to provide a structured way of delivering maximum quality to our
customers. The ability to think creatively, unimpeded by orthodox constraints, without losing
sight of the goal.
The Clever Thinking®
strategy encourages and facilitates the thought processes that we, as
professional Engineers, undertake on a daily basis when faced with a technical challenge. It
encompasses the definition of problems and the generation and assessment of ideas that may
resolve them, without compromising safety.
Clever Thinking®
allows OSL to provide custom fit solutions for every problem, providing
maximum quality and adding value to our customers. The process is carried out during the
different design stages and at various project phases. Use of this practise ensures efficient
and focussed project solutions, Figure 4-1 illustrates the general work flow of the process.
Figure 4-1 - Clever Thinking® Process Flowchart
4.2. A Clever Thinking®
Culture
The culture of creating solutions by sharing ideas is an integral part of the working life at
OSL. This cultural philosophy benefits the working environment and improves the quality of
the solutions OSL produce.
Everyone’s ideas are of equal value, requires respect for each other’s views and ideas.
Support and encouragement will be required to help people engage in the Clever Thinking®
process
Define the
problem
Collate the
team
Communicate
the problem
Divergent
thinking
Convergent
thinking
Selecting
solutions
Close out and
actions
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There is strength in different perspectives, experiences and viewpoints. Clever Thinking®
is
about collaboration, not competition. The philosophy of the best idea may be someone else’s
is good way to promote teamwork. Conflicts may arise from time to time; the avoidance of
conflicts is not recommended, as the team may be able to capitalise on such conflicts as
conflicting views can create a productive environment for the team.
It is well documented that appreciation, acknowledgement and recognition are strong
motivators for a team to work harder and aim higher. By celebrating team members’
achievements in front of colleagues, it stimulates all concerned. By recognising individuals
input and effectiveness, you tap into the best way to motivate them and bring out their
hidden talents.
Attentive listening is empowering for all involved. Listening empowers people to take
responsibility, to be more productive, to influence their environment, and to increase their
own capabilities.
Finally, Clever Thinking®
techniques will not suit all situations and all people. It cannot be
forced, so encouragement of the concept should be ingrained into the fabric of the company
culture
4.3. The Clever Thinking® Methodology
4.3.1. Defining the Problem
The leader or team members should generate an appropriate problem statement which
summarises the work to be completed as concisely as is possible (i.e., in a paragraph). This
statement is to be recorded as the basis for the discussions and displayed prominently during
the meeting.
This statement should contain details of the problem that needs solving (i.e., Pipework
requires replacement or Investigate the feasibility of offshore compression). The elements of
the statement should only state facts and not mention or intimate at any possible solutions so
as to keep the team members’ minds free from any influences or clear of any contaminating
ideas. The statement should contain any relevant background information and will not pre-
judge the problem or infer any preconceived solution.
An engineer who either prepared the problem statement or someone who understands the
background to the challenge should introduce the problem to the team to fully ensure that
there is complete understanding of the issues involved and the background. This is to then be
followed by a discussion of the problem to set the boundaries for generation of possible
design solutions.
4.3.2. Generation of Ideas and Solutions
Essential to the success of the Clever Thinking®
philosophy is the ability of the user to get
into the correct frame of mind to generate the most creative solutions. It is useful to change
the environment (i.e. a particular room), the change in scenery will help alter the pattern of
thinking from the daily norm. Minimising the formality of the session makes a break from the
rigid structure of a normal meeting (i.e. strict agendas, formal meeting protocol, etc.), this
helps encourage creativity from the team members. Clever Thinking®
requires a positive and
unrushed environment.
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Along with the problem statement, the team should be given suitable questioning and idea-
steering guidewords, such as:
What? (In the simplest terms, what is the purpose of the work?)
Why? (What requirements are driving this work?)
Boundaries (Boundaries of the problem)
Information (What information is needed to solve the problem?)
Assumptions (What assumptions are we to make in the generation of solutions?).
For these guidewords the team will provide short statements for discussion. These could be
on post-it notes, written on a whiteboard or on a laptop
The meeting attendees should use ‘Provocation Operation’ [Ref. 1] and make a bold or
creative statement about the problem to move the thinking forward so that new ideas or
solutions may be found. Also consider using ‘Random Stimulation’ techniques in which team
members use creative and/or random words to promote creativity and ideas. Both of these
techniques are designed to drive the creative thought process and break-away from
established thought patterns.
It may be necessary to not pursue answers wholly within the set time-frame of the meeting,
but allow the team to generate the list of ideas over a reasonable longer period giving them
chance to ‘sleep on it’. Possibly make space on the whiteboard or post-it notes available for
people to write down ideas when they arise.
4.3.3. Assessing suitable solutions
Following the initial definition of the problem and the generation of possible solution ideas an
assessment of the feasible actions and areas for further investigation are proposed by the
team. It should be emphasised that all solutions and areas for investigation are recorded in
the appropriate manner. These then undergo a screening exercise to remove those that are
considered technically infeasible, not economically viable or not possible due to any other
reason. The reasons for not taking them forward are to be recorded to ensure full visibility.
The remaining areas for investigation are then to be agreed by the team as a set of
recommendations. The team should also consider what additional information is necessary for
the project to be completed.
4.4. Teamwork
Individuals have different viewpoints and ways of thinking, but to achieve the goals of the
exercise and identify solutions the group need to work and think as a team. Thinking up and
considering new ideas requires a change in cognitive reasoning. If you appraise the problem
from a range of viewpoints the team will have a more holistic perspective on the problem and
possible solutions.
One method of achieving cooperative group thought is to use the Six Thinking Hats®
[Ref. 3].
This is a simple, but powerful tool conceived by one of the foremost experts in the fields of
creativity and Lateral thinking, Edward De Bono, that defines a teamwork thinking tool
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involving six coloured hats. OSL have added a further coloured hat and thought process,
which is our seventh hat – connectivity. It is based on his principle of parallel thinking where
everyone in the group is thinking in the same direction, from the same perspective, at the
same time. It guides team members away from the confines of everyday inflexible viewpoints
and one-way thinking. This tool enables a group of individuals to look at things in a more
collaborative way, outside of normal perspectives.
Colour Direction Notes
White hat Facts information / data needs - what information is available?
what are the facts?
Red hat Feelings emotional / gut feeling - intuitive gut reaction or
statements of emotional feeling (without justification)
Yellow hat Benefits positives - identify advantages
Black hat Cautions negatives / risk - identifying reasons to be wary
Blue hat Process managing the thinking process - what is the subject?
what are we thinking about? what is the goal?
Green hat Creative ideas – though provocation and inquiry, following a train
of thought
Purple hat Connectivity OSL added the connection of all the other thoughts and
adding extra value to the process
Table 4-1 OSL’s Seven Thinking Hats
Managing group thinking requires a skilful facilitator to lead the proceedings. A strong and
independent temperament is important as well as being open to ideas and criticism from the
team members. The leader should encourage involvement from all team members by sharing
participation, also recognising the importance of individual contribution to the discussions.
Recognition of efforts is a way to encourage input and reduce disengagement. The leader
should also ensure regular summarising, keeping everyone informed of the thought processes
and helping to keep the group members committed to the task.
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5. THE SOLUTION
The production of solids containing sand and proppants following the fracking procedures can
happen at any stage of the field life, however it is most likely to occur at the beginning and
when the field has become more mature and its pressure has depleted. These solids can
threaten the mechanical integrity of the choke valves and the downstream system, due to
erosion and deposition, including the subsea export pipelines.
It is considered that the cost implications associated with eroded pipeline decommissioning,
new pipeline installation, periodic pipeline inspections and a risk of environmentally damaging
hydrocarbon spills would be excessively high. Pipeline leaks would be detrimental to the
company’s finances and reputation. Therefore, separation equipment that can achieve
satisfactory efficiency to reduce the risk of mechanical failure due to erosion issues is required
along with a removed solids accumulator.
5.1. Technology Selection
As part of the technology selection process, suitable criteria were defined. Suitable separation
technology must offer a wide range of operating conditions, process operations flexibility for
commissioning, start-up and shutdown, a minimal footprint and a light load for jack up
deployment and to eliminate the requirement for piling. The assessment included an appraisal
of trade-offs between separation efficiency and associated replacement costs of equipment
and eroded pipelines, along with an option to improve erosional resistance for pipeline
internals, e.g. protective coating and/or wall thickness increase.
An investigation of alternative novel technologies such as inline axial cyclone was a key
element of the decision along with potential concepts to satisfy solids disposal management.
Solids disposal options included the installation of a Solids Accumulator and the requirement
for the vessel to be depressurised prior to initiating solid removal activities. Solids removal
options involved either intervention using a remotely operated underwater vehicle (ROV) or
by diver intervention.
5.2. Subsea Cyclone System
A separation unit is required to be situated close to the wellhead, designed to remove these
solid particles from well fluids from early life to late life production. A self-contained subsea
separation unit is proposed to be installed by the rig on the well conductor without the need
for piling. The unit should also be capable of being handled and installed by a standard jack-
up rig and have a standard subsea tree guide frame. Moreover, the unit must be designed to
allow relocation as and when a new low reserve gas field needs to be decommissioned.
The package includes the wellhead, cyclonic separator, solids accumulator, flow metering
station and umbilical installations [Ref. 4]. Figure 5-1 depicts a simplified block diagram
showing the processes of the unit and their interactions.
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Figure 5-1 - Subsea Separation Block Diagram
For the separator a single cyclonic unit was selected from the number of possible solutions.
For the operation of this unit centrifugal force generated by the flow of the fluids and the
shape of the cyclone enables solid particles to be suspended in the swirling gas stream inside
the cyclone. This causes solid particles, which are denser than the well fluids, to be collected
on the cyclone wall and to travel downwards towards the bottom of the cyclone as shown in
Figure 5-2.
The particles therefore can be collected in an appropriate container and leave the cleaned
well fluids in in a reverse-flow direction through the gas outlet, commonly at the top of the
cyclone. Therefore, the single cyclone separator is typically called a reverse flow cyclone.
Figure 5-2 - Single Cyclone Mechanism [Ref. 5]
The benefits of using this subsea separation cyclone technology rather than any other is that
it is a simple construction with no moving parts, which makes it the most common technology
using centrifugal forces to separate solids particles from fluids. The equipment is made of few
parts so has small footprint and as it is easy to assemble a relatively low level of capital
investment is required. The single cyclone unit also has a relatively low operating pressure
drop compared with multiple cyclone units. A key advantage of this solution is that it uses
existing topsides technology redeployed with some design modifications.
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5.3. Tight Gas Solution
The subsea production system typically consists of subsea wellhead systems with Christmas
trees, process equipment, subsea manifolds, tie-in and flowline systems for multiple well
production, umbilical systems, control systems and the export pipeline system. The process
flow diagram (PFD) shown in Figure 5-3 depicts the equipment set up.
Figure 5-3 – Process Flow Diagram
5.3.1. The Process Equipment
The main process equipment consists of the cyclone (discussed in section 5.2) and a solids
accumulator vessel. The accumulator will be situated underneath the cyclone collecting
separated solid particles (such as sand and proppant), from the produced well stream. A
spherical design was implemented in the design of the separation package to avoid any
possible dead spaces which could result in difficulties in solids removal from the container.
The accumulator will be filled up with water and a suitable hydrate inhibitor. The quantity of
produced solids can then be monitored by a rise in liquid level using a level indicator located
within the storage vessel.
A fiscal flow meter will measure the flowrate of the export gas from the separator, prior to
being transferred to the host platform by way of the subsea pipeline.
Figure 5-4 shows the compact skid design of the subsea unit. Production piping connects the
wellhead tree directly to the cyclone separator, where the sand and proppants will be
segregated from the production stream and collected in the solid accumulator. The solid free
gas will be exported to end users through the pipeline. The production piping is fitted with a
series of actuated valves to control the flow of gas coming from the wellhead. Piping will be
supported within the framework to ensure operational stability. The steel superstructure of
the unit will provide adequate support for equipment items and suitable subsea protection.
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Figure 5-4 – Subsea Separation Unit
5.3.2. Solids Disposal Management
Once a suitable level is reached, the solids in the accumulator will be emptied using an ROV.
Prior to removing solids from the container, the Solids Accumulator shall be isolated from the
cyclone to allow pressure reduction. In order to empty the solids accumulator, the solids will
need to be fluidised with water through a water injection pump. Water distribution nozzles
may be required to aid this process to enable solids suspension as the replacement water
enters the solids accumulator. The injection pump has a sufficient pressure to allow slurry
fluid to be transferred via a temporary hose to a container on the ROV vessel. The slurry will
be treated and disposed of onshore in a safe manner.
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6. CONCLUSION
6.1. Contemporary Approach
The contemporary approach to the development of tight gas accumulations involves deep
horizontal drilling. These fields cannot be produced at economic flows without assistance from
stimulation treatments, i.e. fracking. This imparts the continual problem of solids handling
due to the release of sand and the fracturing proppants used to stimulate the well. These
solids then create downstream difficulties with erosion of equipment, especially choke valves,
and pipework along with the significant maintenance cost associated with this.
Directional drilling from a platform is used to develop single and multiple well gas fields. This
method has high cost implications for single well and dual well developments and may not be
economically viable for low reserve fields. Finding ways of improving the economic viability of
tight, low reserve gas fields in the SNS is becoming more important.
There is a growing industry approach to examine this issue from alternative perspectives. An
approach to find new ways of doing things, or reapply current methods in a new way is
required, so as to improve efficiency of the recovery system and reduce costs to ensure the
viability of these assets.
6.2. Collaboration: Client and Partners
The success of this undertaking was greatly influenced by the fact that OSL was able to work
in close partnership with an operating company to undertake this conceptual study. The
collaboration meant that the overall team, made up of both OSL and operational personnel
were able to combine knowledge and experience whilst investigating solutions for recovering
gas from stranded offshore gas fields and transporting it using subsea pipelines to an
adjacent offshore platform.
During the experience of the cooperation it became evident that working together generates
much more than working in isolation. The partner teams were able to pool resources, sharing
know-how and expertise such that the ideas and solutions output from the Clever Thinking®
meeting was more creative giving rise to comprehensive, practical and constructive results.
6.3. Clever Thinking®
: Solution Generation
OSL define Clever Thinking®
as the culture of creating solutions by sharing ideas. The
philosophy aims to utilise creative thinking techniques to improve the value of the solutions
that are provided. The approach provides the ability to think creatively, unimpeded by
orthodox constraints, without losing sight of the goal.
Clever Thinking®
sessions where a team is formed of personnel directly involved in the issue
at hand and also people independent from the project team to give as wide a range of
experience and opinions as possible. A facilitator guides the team through the process of first
identifying ideas, then reviewing and developing these, with the ultimate goal to produce a
list of possible solutions to the issue along with assigned actions for follow up work. During
the sessions the creative thinking toolbox may be employed as necessary
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This practise employs techniques that are designed to drive the creative thought process and
break-away from established thought patterns. One approach is used but this method is
proven to release potential from the team with a wealth of untapped ideas.
6.4. Tight Gas Development
Tight gas is a prospect which currently remains underexploited outside the US, but demands
on the gas market are bringing this to the fore. Tight gas is becoming an industry priority and
the development of these reserves in the SNS is starting to take off. In the overview of
activities from September 2015, the UK Oil and Gas Authority (OGA) focus on priorities
planning has SNS tight gas regional developments intended for the latter half of 2016. Tight
gas has the potential to facilitate and maximise the current upsurge of growth in the gas
industry.
Extracting value from tight gas reservoirs represents a challenge for the industry as it
necessitates the use of advanced technologies. Well costs are the most significant cost driver
in the economics of unconventional gas. If the costs of well exploitation are reduced, then
this makes tight gas a very viable prospect. The solution developed by this process for the
subsea extraction method and processing unit is poised to become an integral part of
reducing the costs and making tight gas recovery economically practicable.
The proposed solution for solids separation and solid removal approach will satisfy the
defined design aspects. It also has overcome the potential operational difficulties and
provides a strong financial benefit for single or dual well tight gas marginal field development.
The proposed solution has proven attractive for SNS operators as it is technically feasible,
constructible, maintainable and economic. This innovative technology has the potential to
become the leading solution in the production of marginal gas fields.
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7. REFERENCES
1. Law, B. E., and J. B. Curtis, 2002, Introduction to unconventional petroleum systems:
AAPG Bulletin, v. 86
2. The Mechanism of Mind (1969)
3. Six Thinking Hats - Edward de Bono (1985)
4. OS-0483-BAY-PRP-0006 - Conceptual Study for Subsea Separation: Summary Report,
Rev. A00 (April 2015)
5. Gas Condition and Processing Volume 2: The Equipment Modules, J.M. Campbell and
Company, 8th
Edition (2004)