This document discusses lessons learned in how not to implement drilling automation. It begins by defining drilling automation and providing examples of automated processes like maintaining downhole weight on bit and optimizing mechanical specific energy. It then outlines common mistakes made in automation projects like not including drillers, having insufficient data quality, and giving drillers too many or too few controls. The key lessons are that automation must improve performance, drillers must be central to the design and implementation, reliable data and controls are essential, and human factors like training and complacency must be addressed. Critical success factors for automation include deciding what to automate and implementing with consideration of both technical and people issues.
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 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.
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.
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.
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.
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.
Each year, companies use averaged well production (type wells) to support billion dollar expenditures to buy and develop oil and gas resources. These type wells often have unrepresentative rate-time profiles and recoveries over-stated by as much as 50%. These intolerable errors result from common, but incorrect, assumptions in constructing type well production profiles, and the selection and weighting of analog wells. Literature related to constructing type wells is sparse and incomplete. This lecture will fill that gap and lead participants to informed decisions for best practices in type well construction. Hind casting examples show that only small errors in recovery result when the type well construction combines historical and predicted production rates. This improvement results from using educated estimates (not intrinsic values) for months with no data to average, and from individual well forecast errors that offset one another. A Monte Carlo method incorporates risk and leads to better well selection and weighting factors, achieving more representative rate-time profiles. The recommended methodology incorporates aggregation and choosing different uncertain parameters. Parameter choice is important because it makes little sense to risk recovery (e.g., P90 for proved reserves) when the application demands a different parameter such as present value. Type well construction methods are common, but they have errors that are difficult to detect. Evaluators are likely using type wells for financial analysis, facility design, cash flow prediction, reserve estimation and debt financing without knowledge of the inaccuracies and options to improve accuracy.
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 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.
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.
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.
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.
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.
Each year, companies use averaged well production (type wells) to support billion dollar expenditures to buy and develop oil and gas resources. These type wells often have unrepresentative rate-time profiles and recoveries over-stated by as much as 50%. These intolerable errors result from common, but incorrect, assumptions in constructing type well production profiles, and the selection and weighting of analog wells. Literature related to constructing type wells is sparse and incomplete. This lecture will fill that gap and lead participants to informed decisions for best practices in type well construction. Hind casting examples show that only small errors in recovery result when the type well construction combines historical and predicted production rates. This improvement results from using educated estimates (not intrinsic values) for months with no data to average, and from individual well forecast errors that offset one another. A Monte Carlo method incorporates risk and leads to better well selection and weighting factors, achieving more representative rate-time profiles. The recommended methodology incorporates aggregation and choosing different uncertain parameters. Parameter choice is important because it makes little sense to risk recovery (e.g., P90 for proved reserves) when the application demands a different parameter such as present value. Type well construction methods are common, but they have errors that are difficult to detect. Evaluators are likely using type wells for financial analysis, facility design, cash flow prediction, reserve estimation and debt financing without knowledge of the inaccuracies and options to improve accuracy.
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.
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.
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.
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.
"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.
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.
Replacing a Stack Gas Flow Hardware Device with PEMSCTi Controltech
Presentation by President of CMC Solutions to PNWIS & AWMA (Pacific Northwest International Section of the Air & Waste Management Association)
CMC Solutions was retained to perform a demonstration of a statistical hybrid predictive emissions monitoring system (PEMS) under 40 CFR Part 75, Subpart E.
The PEMS was deployed in September of 2010 for stack gas flow and pollutant emissions. The demonstration confirmed that the PEMS passes all the statistical tests for the 720 hour demonstration period.
Summary
Statistical hybrid PEMS have been successful in meeting the requirements of the U.S. emission trading program
PEMS achieve very high accuracy levels
PEMS demonstrate superior reliability
PEMS are certified as an alternative to CEMS
PEMS are a cost effective alternative to a CEMS
Managed Pressure Drilling (MPD) was introduced in 2000 as an adative drilling technology for pricely controlling the pressure profile in the wellbore. Utilizing applied surface pressure, MPD provides an addition degree of freedom in the design and drilling of wells. MPD has been utilized successfully in drilling projects to mitigate or eliminate problems associated with conventional drilling operations. MPD has been used for early kick detection, driling through narrow pore pressure/fracture pressure windows, reduction of the probability of lost returns, identifying and eliminating issues of wellbore breathing (ballooning), and pore pressure/fracture gradient mapping. An area that has great potential, but has gainned little attention, is the ability to utilize MPD for dynamic influx control. MPD changes the primary barrier envelope to well control, allowing small influxes to be managed through the MPD system. This lecture describes the current state of dynamic influx control and its limitations. It shows how conventional well control practices actually increase the probability of secondary well control problems, and thus risk. The basis for and practical applications of dynamic influx control are presented. Conditions under which dynamic influx control is practicable, and when conventional well control should be invoked, are discussed. Adoption of Dynamic Influx Control eliminates many problems associated with the current conventional methods of well control, allowing the control of the well to be regained safer, quicker and with less risk of secondary problems, including underground blowouts, stuck pipe, lost returns and secondary kicks.
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.
A side by side comparison of various aspects of owning and applying a predictive emissions monitoring system vs. a continuous emissions monitoring system. Excerpted from CMC Solutions at http://cmcpems.com/pems-vs-cems/
How I failed to build a runbook automation systemTimothyBonci
How I tried and failed to build a runbook automation system and what I learned.
Our intentions can be good and the technical ability and time may be there and we’re going to build the thing to make work easier and more productive, allowing everyone to apply their labor to only the most valuable tasks – yet sometimes it’s still not enough. This is a post-mortem.
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.
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.
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.
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.
"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.
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.
Replacing a Stack Gas Flow Hardware Device with PEMSCTi Controltech
Presentation by President of CMC Solutions to PNWIS & AWMA (Pacific Northwest International Section of the Air & Waste Management Association)
CMC Solutions was retained to perform a demonstration of a statistical hybrid predictive emissions monitoring system (PEMS) under 40 CFR Part 75, Subpart E.
The PEMS was deployed in September of 2010 for stack gas flow and pollutant emissions. The demonstration confirmed that the PEMS passes all the statistical tests for the 720 hour demonstration period.
Summary
Statistical hybrid PEMS have been successful in meeting the requirements of the U.S. emission trading program
PEMS achieve very high accuracy levels
PEMS demonstrate superior reliability
PEMS are certified as an alternative to CEMS
PEMS are a cost effective alternative to a CEMS
Managed Pressure Drilling (MPD) was introduced in 2000 as an adative drilling technology for pricely controlling the pressure profile in the wellbore. Utilizing applied surface pressure, MPD provides an addition degree of freedom in the design and drilling of wells. MPD has been utilized successfully in drilling projects to mitigate or eliminate problems associated with conventional drilling operations. MPD has been used for early kick detection, driling through narrow pore pressure/fracture pressure windows, reduction of the probability of lost returns, identifying and eliminating issues of wellbore breathing (ballooning), and pore pressure/fracture gradient mapping. An area that has great potential, but has gainned little attention, is the ability to utilize MPD for dynamic influx control. MPD changes the primary barrier envelope to well control, allowing small influxes to be managed through the MPD system. This lecture describes the current state of dynamic influx control and its limitations. It shows how conventional well control practices actually increase the probability of secondary well control problems, and thus risk. The basis for and practical applications of dynamic influx control are presented. Conditions under which dynamic influx control is practicable, and when conventional well control should be invoked, are discussed. Adoption of Dynamic Influx Control eliminates many problems associated with the current conventional methods of well control, allowing the control of the well to be regained safer, quicker and with less risk of secondary problems, including underground blowouts, stuck pipe, lost returns and secondary kicks.
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.
A side by side comparison of various aspects of owning and applying a predictive emissions monitoring system vs. a continuous emissions monitoring system. Excerpted from CMC Solutions at http://cmcpems.com/pems-vs-cems/
How I failed to build a runbook automation systemTimothyBonci
How I tried and failed to build a runbook automation system and what I learned.
Our intentions can be good and the technical ability and time may be there and we’re going to build the thing to make work easier and more productive, allowing everyone to apply their labor to only the most valuable tasks – yet sometimes it’s still not enough. This is a post-mortem.
Modern business drivers are continually pushing to reduce the time it takes to get a product or service to market, reduce the risk and cost associated with that, and to improve quality.
In laboratories, delivering an analytical result that’s ‘right first time’ (RFT) is the answer. There is no reprocessing data or re-running injections and no out of specification (OOS) results or reporting/calculation errors.
Using chromatography data system tools for RFT analysis automatically gives high quality of results and confidence in results, lower cost of analysis, improved lab efficiency, and faster release to market and return on investment (ROI).
Modern business drivers are continually pushing to reduce the time it takes to get a product or service to market, reduce the risk and cost associated with that, and to improve quality.
In laboratories, delivering an analytical result that’s ‘right first time’ (RFT) is the answer. There is no reprocessing data or re-running injections and no out of specification (OOS) results or reporting/calculation errors.
Using chromatography data system tools for RFT analysis automatically gives high quality of results and confidence in results, lower cost of analysis, improved lab efficiency, and faster release to market and return on investment (ROI).
Lean Maintenance is gaining traction as a sound strategy to keep equipment running and productivity humming. The hardest part is getting started. On Thursday, March 20 at 1 p.m. CDT, Plant Engineering will present a Webcast that looks at the steps needed to implement a sound Lean Maintenance strategy on your plant floor and to begin to reap the benefits.
Learning objectives:
-The value of Lean Maintenance as a plant-floor strategy and the history of lean
-The steps and tools needed to get started down the road to Lean
-Getting plant-floor buy-in from line workers
-Incorporating technology into Lean maintenance
Modern business drivers are continually pushing to reduce the time it takes to get a product or service to market, reduce the risk and cost associated with that, and to improve quality.
In laboratories, delivering an analytical result that’s ‘right first time’ (RFT) is the answer. There is no reprocessing data or re-running injections and no out of specification (OOS) results or reporting/calculation errors.
Using chromatography data system tools for RFT analysis automatically gives high quality of results and confidence in results, lower cost of analysis, improved lab efficiency, and faster release to market and return on investment (ROI).
Critical Performance Metrics for DDR4 based SystemsBarbara Aichinger
Servers are critical to today's Cloud Computing and DDR memory is at the heart of all Cloud Computing Servers. Presented at DesignCon 2015 this presentation outlines new measurable performance metrics for DDR4 Memory Subsystems.
Grails has great performance characteristics but as with all full stack frameworks, attention must be paid to optimize performance. In this talk Lari will discuss common missteps that can easily be avoided and share tips and tricks which help profile and tune Grails applications.
Grails has great performance characteristics but as with all full stack frameworks, attention must be paid to optimize performance. In this talk Lari will discuss common missteps that can easily be avoided and share tips and tricks which help profile and tune Grails applications.
Slide deck used during the SPE Live broadcast on 19 August 2020 with guest Doug Peacock, 2010-11 SPE Distinguished Lecturer and currently a Technical Director for GaffneyCline.
WATCH VIDEO: https://youtu.be/ykJhFkNUXqc
TRAINING COURSE: http://go.spe.org/peacockSPELIVE
The unitization process has evolved over the years and is now well established throughout the world with many countries having legislation for unitization.
Although there are generic agreements, each unitization agreement is unique and requires a wide range of issues to be considered.
Learn More: www.spe.org/dl/schedule.php
With speakers from various disciplines and professions, the SPE Distinguished Lecturer program focuses on the hottest trends, tools, and technology in E&P around the globe. View the complete 2019-2020 Distinguished Lecturer schedule at www.spe.org/dl/schedule.php.
Shale development in the US has been ongoing for at least the last decade, and many lessons can be learned from the US experience to help prevent air emissions and aquifer contamination in future developments around the world. Media reports and films such as "Gasland" imply that shale development is widely polluting fresh water aquifers and the atmosphere, with a wide range of estimates of contamination. This lecture examines the risk of contamination of aquifers through wellbores, either by hydrocarbon migration or hydraulic fracturing operations, and is primarily based on a comprehensive three-year study funded by the US National Science Foundation examining nearly 18,000 wells drilled in the Wattenberg Field in Colorado, plus other relevant studies. In the midst of the Wattenberg field is heavy urban and agricultural development, with over 30,000 water wells interspersed with the oil and gas wells, resulting in a natural laboratory to measure aquifer contamination. Lessons learned have universal applications with clear relationships established between well construction methods in both conventional and unconventional wells and contamination risks.
Over the past few years, significant advancements have been made in completion and stimulation designs in horizontal wells in unconventional plays, with the primary driver being the improvement of fracture contact area in these very low permeability reservoirs, to improve production volumes and recoveries. Fracture contact area with plug-and-perf or sliding sleeve systems have been intensified by increasing the density of contact points in the formation as well as proppant amount with great success. While these parameters have been optimized, other important parameters such as fracture conductivity and connectivity have been largely neglected. In the journey to improving contact area, proppant conductivity is often sacrified to save costs, and fracture stimulation treatments are overflushed in order to maximize operational efficiencies on multi-well pads. This presentation will highlight the importance of all of these parameters, and provides steps that can be taken to further optimize and enhance well producitivity and economics in the shale plays.
Courier management system project report.pdfKamal Acharya
It is now-a-days very important for the people to send or receive articles like imported furniture, electronic items, gifts, business goods and the like. People depend vastly on different transport systems which mostly use the manual way of receiving and delivering the articles. There is no way to track the articles till they are received and there is no way to let the customer know what happened in transit, once he booked some articles. In such a situation, we need a system which completely computerizes the cargo activities including time to time tracking of the articles sent. This need is fulfilled by Courier Management System software which is online software for the cargo management people that enables them to receive the goods from a source and send them to a required destination and track their status from time to time.
COLLEGE BUS MANAGEMENT SYSTEM PROJECT REPORT.pdfKamal Acharya
The College Bus Management system is completely developed by Visual Basic .NET Version. The application is connect with most secured database language MS SQL Server. The application is develop by using best combination of front-end and back-end languages. The application is totally design like flat user interface. This flat user interface is more attractive user interface in 2017. The application is gives more important to the system functionality. The application is to manage the student’s details, driver’s details, bus details, bus route details, bus fees details and more. The application has only one unit for admin. The admin can manage the entire application. The admin can login into the application by using username and password of the admin. The application is develop for big and small colleges. It is more user friendly for non-computer person. Even they can easily learn how to manage the application within hours. The application is more secure by the admin. The system will give an effective output for the VB.Net and SQL Server given as input to the system. The compiled java program given as input to the system, after scanning the program will generate different reports. The application generates the report for users. The admin can view and download the report of the data. The application deliver the excel format reports. Because, excel formatted reports is very easy to understand the income and expense of the college bus. This application is mainly develop for windows operating system users. In 2017, 73% of people enterprises are using windows operating system. So the application will easily install for all the windows operating system users. The application-developed size is very low. The application consumes very low space in disk. Therefore, the user can allocate very minimum local disk space for this application.
About
Indigenized remote control interface card suitable for MAFI system CCR equipment. Compatible for IDM8000 CCR. Backplane mounted serial and TCP/Ethernet communication module for CCR remote access. IDM 8000 CCR remote control on serial and TCP protocol.
• Remote control: Parallel or serial interface.
• Compatible with MAFI CCR system.
• Compatible with IDM8000 CCR.
• Compatible with Backplane mount serial communication.
• Compatible with commercial and Defence aviation CCR system.
• Remote control system for accessing CCR and allied system over serial or TCP.
• Indigenized local Support/presence in India.
• Easy in configuration using DIP switches.
Technical Specifications
Indigenized remote control interface card suitable for MAFI system CCR equipment. Compatible for IDM8000 CCR. Backplane mounted serial and TCP/Ethernet communication module for CCR remote access. IDM 8000 CCR remote control on serial and TCP protocol.
Key Features
Indigenized remote control interface card suitable for MAFI system CCR equipment. Compatible for IDM8000 CCR. Backplane mounted serial and TCP/Ethernet communication module for CCR remote access. IDM 8000 CCR remote control on serial and TCP protocol.
• Remote control: Parallel or serial interface
• Compatible with MAFI CCR system
• Copatiable with IDM8000 CCR
• Compatible with Backplane mount serial communication.
• Compatible with commercial and Defence aviation CCR system.
• Remote control system for accessing CCR and allied system over serial or TCP.
• Indigenized local Support/presence in India.
Application
• Remote control: Parallel or serial interface.
• Compatible with MAFI CCR system.
• Compatible with IDM8000 CCR.
• Compatible with Backplane mount serial communication.
• Compatible with commercial and Defence aviation CCR system.
• Remote control system for accessing CCR and allied system over serial or TCP.
• Indigenized local Support/presence in India.
• Easy in configuration using DIP switches.
Event Management System Vb Net Project Report.pdfKamal Acharya
In present era, the scopes of information technology growing with a very fast .We do not see any are untouched from this industry. The scope of information technology has become wider includes: Business and industry. Household Business, Communication, Education, Entertainment, Science, Medicine, Engineering, Distance Learning, Weather Forecasting. Carrier Searching and so on.
My project named “Event Management System” is software that store and maintained all events coordinated in college. It also helpful to print related reports. My project will help to record the events coordinated by faculties with their Name, Event subject, date & details in an efficient & effective ways.
In my system we have to make a system by which a user can record all events coordinated by a particular faculty. In our proposed system some more featured are added which differs it from the existing system such as security.
Explore the innovative world of trenchless pipe repair with our comprehensive guide, "The Benefits and Techniques of Trenchless Pipe Repair." This document delves into the modern methods of repairing underground pipes without the need for extensive excavation, highlighting the numerous advantages and the latest techniques used in the industry.
Learn about the cost savings, reduced environmental impact, and minimal disruption associated with trenchless technology. Discover detailed explanations of popular techniques such as pipe bursting, cured-in-place pipe (CIPP) lining, and directional drilling. Understand how these methods can be applied to various types of infrastructure, from residential plumbing to large-scale municipal systems.
Ideal for homeowners, contractors, engineers, and anyone interested in modern plumbing solutions, this guide provides valuable insights into why trenchless pipe repair is becoming the preferred choice for pipe rehabilitation. Stay informed about the latest advancements and best practices in the field.
Forklift Classes Overview by Intella PartsIntella Parts
Discover the different forklift classes and their specific applications. Learn how to choose the right forklift for your needs to ensure safety, efficiency, and compliance in your operations.
For more technical information, visit our website https://intellaparts.com
Overview of the fundamental roles in Hydropower generation and the components involved in wider Electrical Engineering.
This paper presents the design and construction of hydroelectric dams from the hydrologist’s survey of the valley before construction, all aspects and involved disciplines, fluid dynamics, structural engineering, generation and mains frequency regulation to the very transmission of power through the network in the United Kingdom.
Author: Robbie Edward Sayers
Collaborators and co editors: Charlie Sims and Connor Healey.
(C) 2024 Robbie E. Sayers
TECHNICAL TRAINING MANUAL GENERAL FAMILIARIZATION COURSEDuvanRamosGarzon1
AIRCRAFT GENERAL
The Single Aisle is the most advanced family aircraft in service today, with fly-by-wire flight controls.
The A318, A319, A320 and A321 are twin-engine subsonic medium range aircraft.
The family offers a choice of engines
Saudi Arabia stands as a titan in the global energy landscape, renowned for its abundant oil and gas resources. It's the largest exporter of petroleum and holds some of the world's most significant reserves. Let's delve into the top 10 oil and gas projects shaping Saudi Arabia's energy future in 2024.
Democratizing Fuzzing at Scale by Abhishek Aryaabh.arya
Presented at NUS: Fuzzing and Software Security Summer School 2024
This keynote talks about the democratization of fuzzing at scale, highlighting the collaboration between open source communities, academia, and industry to advance the field of fuzzing. It delves into the history of fuzzing, the development of scalable fuzzing platforms, and the empowerment of community-driven research. The talk will further discuss recent advancements leveraging AI/ML and offer insights into the future evolution of the fuzzing landscape.
Industrial Training at Shahjalal Fertilizer Company Limited (SFCL)MdTanvirMahtab2
This presentation is about the working procedure of Shahjalal Fertilizer Company Limited (SFCL). A Govt. owned Company of Bangladesh Chemical Industries Corporation under Ministry of Industries.
Industrial Training at Shahjalal Fertilizer Company Limited (SFCL)
Lessons Learned: How NOT to Do Drilling Automation
1. Society of Petroleum Engineers
Distinguished Lecturer Program
www.spe.org/dl 1
Dr. William L. Koederitz, SPE, PE
Lessons Learned,
How NOT to Do Drilling Automation
2. Outline
• What is drilling
automation?
– Examples
– Pros and Cons
• How NOT to do drilling
automation
– A positive side will also be
shown!
• Conclusions
2
3. Drilling Automation
• The technique of operating or controlling
a process by highly automatic means,
reducing human intervention to a
minimum.
• Mechanization refers to the replacement
of human power with mechanical power of
some form.
3
4. The 10 Stages of Automation
4
Level Automation Description
10
The computer decides everything, acts autonomously, ignoring the
human.
9 Informs the human only if it, the computer, decides to
8 Informs the human only if asked, or
7 Executes automatically, then necessarily informs the human, and
6
Allows the human a restricted time to veto before automatic
execution, or
5 Executes that suggestion if the human approves, or
4 Suggests one alternative
3 Narrows the selection down to a few, or
2 The computer offers a complete set of decision/ action alternatives, or
1
The computer offers no assistance: human must take all decisions
and actions
IEEE Transactions on Systems, Man, and Cybernetics- Part A: Systems and Humans, Vol. 30, No. 3, May 2000
5. Example – DWOB Control
• DWOB = “Downhole Weight on Bit”
• SWOB = “Surface Weight on Bit”
• DWOB ≠ SWOB
• Constant DWOB provides better results
– Higher Rate of Penetration
– Better directional control
5
SurfaceWeight
W eig ht o n B it
NormalForce
6. Manual DWOB Control
• Control process by driller
– Read slow-speed DWOB
– Compare to desired DWOB
– Adjust SWOB setpoint in autodriller
• Holds DWOB “close” to desired
• Requires constant monitoring, adjusting
• If downhole conditions change, must react
rapidly
6
7. Automated DWOB Control
• Driller sets bounds on DWOB, SWOB
• Automated optimization process
– Analyze high-speed surface and downhole
drilling data
– Compute change in SWOB
– New SWOB sent direct to rig
• Driller now only has to monitor
• Holds DWOB very close to desired
• Reacts quickly to changes downhole
7
8. Example – MSE Optimization
• MSE = “Mechanical Specific Energy”
• MSE = energy in / volume of rock drilled
• Lower MSE more efficient drilling
8
9. Manual MSE Optimization
• Optimization process by driller
– Change Bit Weight and/or RPM
– MSE response dictates next change
• Performance improvement
– More as driller gains experience
• Requires constant monitoring, adjusting
9
10. Automated MSE Optimization
• Driller sets bounds on Bit Weight, RPM
• Automated optimization process
– Analyze recent drilling & MSE data
– Search technique selects Bit Weight, RPM
– New Bit Weight, RPM sent direct to rig
• Driller now only has to monitor
• Performance improved in most cases
– Can’t compete with dedicated expert driller
10
11. Why Automate?
• Efficiency
– Tasks that are repetitive and require
continuous monitoring can be done more
consistently with automation.
– Free up rig crew for other tasks
• Enhance Crew Capability
– Shortage of experienced individuals at the rig
• Improved Performance
– Do things that people can’t do (non-stop)
• Safety
11
12. Risks of Automation
• Complacency
• Loss of ownership
• Dependent on data & control
quality
• Maximum performance limited by
“smartness” of automation logic
– In the specific situation
• Automation can not innovate
– Only motivated people can do that
12
13. When & What to Automate
• Selection Methods
– Look for good automation applications
– Look for performance improvement
opportunities
• Define automated and non-automated options
• Decide based on your criteria
– Return on Investment
– Safety
13
14. Drilling Automation in SPE
• SPE DSATS
– Drilling Systems Automation Technical Section
– Purpose is to accelerate automation in drilling
– On SPE website, workshops, forums, …
– SPE/IADC-173010-MS “Drilling Systems Roadmap
– The Means to Accelerate Adoption”
• IADC ART
– Advanced Rig Technology Committee
– Focused on safety and efficiency of automation
14
15. How Not to …
“The office saw value and
wanted it, so the rig will too.”
•Performance-motivated rig
•Office often out of touch with actual
rig operations
– Rig crew sees the negatives and
focuses on them
•Solution
– Include driller from the start
– Change how people work
15
Aha!!!
16. How Not to …
“The office saw value and wanted it, so the rig
will too.”
•NOT a performance-motivated rig
•Solution
– Change to performance-motivated rig!
– If not willing to do that:
◦ Acceptance will be an issue
◦ Design in value that has meaning at rigsite
–Make their life easier
16
17. How Not to …
“Driller is no longer needed. ”
•Driller is the core of rig activity
•If he feels left out, automation will not work
– Even if no action is required on his part
•Solution
‒ Design system with driller at center and in
control
‒ Treat driller as most-critical automation enabler
17
18. How Not to …
“That rig’s data was good enough for drilling,
so it’ll be fine for automation.”
•Typical rig data is never good enough
– Often already insufficient (if you really look)
•Reliable, high-quality data is a must-have
•Solution
– Investigate rig data quality, upgrade as needed
– Continuous monitoring of data quality
18
19. How Not to …
“That rig’s controls were good enough for
drilling, so they’ll be fine for automation.”
•Reliable, sufficiently precise control of rig equipment
is a must-have
•Typical rig control is often not precise enough or is
not readily accessible
•Solution
– Evaluate rig control capability, resolve issues
– Continuous monitoring of control quality
19
20. How Not to …
“Since it’s automated, driller only needs to turn
it on, not understand how it works.”
•This reduces effective use (loss of value)
– Worst case, destroys rigsite acceptance
•Optimum use by rig maximum value
•Solution
– Design so driller is well informed of how it works
– Enhance comfort level (simulator exercises a +)
20
21. How Not to …
“This rig is a sister rig to the last one we
automated, so we are ready to go.”
21
• Every rig has some unique aspects
• Office records often aren’t perfect
• Solution
‒ Do a detailed rig survey
‒ Build configuration specific to rig
‒ Pre-test configuration in lab
22. How Not to …
“It’s a highly-automated system, so there
shouldn’t be any maintenance for the rig to
do.”
•Maintenance needed for optimum, safe
performance
•Changes in rig, sensors, drilling, …
•Solution
– Design for easy, minimal maintenance
◦ Automated diagnostics or remote monitoring
22
23. How Not to …
“Their only choice is on or off.”
“Let’s let them adjust everything.”
•There is an optimum level of interaction for
each driller and situation
•But too many levels are confusing
•Solution
– Analyze drillers, identify group(s)
– Design for some variation in drillers
◦ Basic vs advanced
23
24. How Not to …
“Automation seems to be going well, so
driller must be paying close attention.”
•Complacency is a risk
– The “better” the automation does its job, the
higher the risk
– A tough problem to solve
•Solution
– Human factors engineering, in some form
24
25. How Not to …
“Let’s make the system do everything (we
think) they need. They’ll sort it out.”
•The driller is over-loaded by this, resulting in
misuse or non-use
•Solution
– Design the system as a suite of tools
◦ Driller picks the right tool for the right job
– Key decision criteria are simplicity,
modularity, benefit/cost ratio
25
26. Conclusions
• Automation is a tool to improve
performance
– Pros and cons, per application
• Critical success factors
– Deciding if and what to automate
– Design and implementation
◦ People issues often > technical issues
◦ Do not leave the driller out!
26
27. Society of Petroleum Engineers
Distinguished Lecturer Program
www.spe.org/dl 27
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