|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
Big data analytics is a big deal right now in the oil and gas industry. This emerging trend is on track to become an industry best practice for good reason: It improves exploration and production efficiency. With the help of sensors, massive amounts of data already are being extracted from exploration, drilling, and production operations, as well as being leveraged to shed light on sophisticated engineering problems. So, why shouldn't a similar approach be applied when it comes to worker health and safety; especially when it's the norm across a wide variety of other industries? While the International Association of Oil and Gas Producers came out with a safety performance report that showed fatalities and injuries for the industry were down in 2019, the US Occupational Safety and Health Administration (OSHA) says that the oil and gas industry's fatality rate is 7 times higher than all other industries in the US.
The oil and gas industry has picked up on the benefits of digitization and artificial intelligence (AI) in its day-to-day activities, and the health, safety, and environment (HSE) sector is no exception. While AI brings clear benefits, the risks that come with those benefits remain unclear. While touting the advances of technology in HSE at SPE's Virtual Annual Technical Conference and Exhibition (ATCE), Olav Skar, director of health, safety, security, and wells at the International Association of Oil and Gas Producers (IOGP), said, "I also see risks, and I remain concerned that we do not truly understand them." Skar spoke at ATCE on a panel that included Mohamed Kermoud, Schlumberger's global vice president for HSE, and Philippe Herve, the vice president of energy solutions at SparkCognition. The panel was moderated by Josh Etkind, Shell's Gulf of Mexico digital transformation manager.
After years of low oil prices, the focus is on adding a lot of value for a little cost. SPE's technical directors are talking about adding value to everything from a petroleum engineering degree to a wellbore. A failure to do so can mean a degree that does not prepare a student to contribute after graduation, or a well whose production fades early. Those working as petroleum engineers have a generation's worth of challenges to address due to the push into unconventional development. Those results will determine how much value can be coaxed from these ultra- tight rocks. For those designing projects that will get built, it pays to think small. A standardized, modular design can deliver value at a cost that is lower, and more likely to come in within the budget. Doing more with less in drilling means there are fewer drilling rigs in the world, and the job of many engineers still working will be to identify the best available technology to continue to reduce the number of rigs required.
The American Society of Safety Professionals (ASSP) Foundation released a fatigue-research report that shows the value of wearable technology in the workplace. The 3-year study was led by Lora Cavuoto at the University at Buffalo and Fadel Megahed at the Farmer School of Business at Miami University of Ohio. The project also involved researchers from Auburn University and the University of Dayton. The study, which ended in December, demonstrated how to capture a worker's safety performance and translate the data into personal fatigue levels. It is the first step in creating a comprehensive framework that can identify research-supported interventions that protect workers from injuries caused by being tired on the job.
Prior to 2007, the U.S. Department of Energy (DOE) upstream oil and gas research program focused primarily on onshore applications. In 2000, the DOE published the
Discussion focuses on key research findings from the DOE ultra-deepwater research portfolio of 2007-2013. Then the paper describes the current offshore research portfolio 2014 – 2019. Finally, the paper describes the outcomes and insights from key discussions with industry, academia, research and non-government and government stakeholders that could become a frame for a technology research roadmap for the entire Outer Continental Shelf.
DOE research investments in public-private partnerships with industry, academia, research labs, and others have made an important contribution to the current state-of-the-art in offshore technology---contributions that most people may not realize are tied to previous research investments by DOE. Tracing these contributions, tracking them back to the
The information in this paper will both inform and inspire new frontiers of research for the OCS. As the USA moves forward with onshore development of unconventional resources, there are features of the DOE onshore research portfolio that may have merit in the OCS. For example, the DOE Field Laboratory program is focused on basin-specific research strategies where new technology can be applied to operating oilfields and evaluated via the scientific method. Then the data captured can potentially become part of further research by the DOE National Laboratories including geophysical, geomechanical, geochemical, and data analytics such as machine learning. This DOE program has been very successful onshore, and perhaps there is a place for a comparable multi-disciplinary, multi-partner approach in the OCS.
Abstract Well Integrity engineers are commonly challenged with using limited resources, and even more limited data, when trying to identify which wells amongst their diverse well inventory may be prone to damage and failure, the mechanisms and influential factors responsible for the potential damage and failures, and the reason why certain wells may pose the greatest risk. Furthermore, these integrity engineers are often uncertain as to the parameters that should be tracked; what inspection methods should be conducted, in which wells and at what frequency measures should be taken; and how the asset risks can be adequately determined and relayed to management to prioritize near-term and future financial investments into well integrity and decommissioning cost centres. In this paper, an approach and workflow are described on how the application of a combination of reliability and risk methods, parameter-based damage models and available field data can be used to develop a tool used by asset integrity and operations personnel to risk-rank wells by the probability of failure and associated consequences. Additionally, this paper illustrates how the approach and models developed are adaptable to both the damage mechanisms specific to the application and to the data and parameters that are currently being measured or readily obtained, or other related variables that can used as suitable proxy parameters. As experience and history build (adding to the understanding and prioritization of damage mechanisms and key parameters), and to improve estimated values of the associated probability of failure due to these mechanisms, the knowledge is fed back into the model to improve its predictive capabilities. This paper also describes how the methodology was applied by a commercial SAGD operator to develop a subsurface isolation risk assessment tool that was tailored to their wells, their application conditions and the parameters that they measure. The types of static and dynamic parameters that this tool considers, including geologic, well design, construction and operational data, are also illustrated, as well as how the tool is being used to prioritize injection and production wells by relative risk. Illustrative examples of how well, pad and asset risks are being identified, rolled-up across the asset and summarized are presented, and how well integrity and risk metrics are being communicated within the company. Ongoing activities to continue to update and advance the risk-ranking model are also noted; in particular, potential opportunities to develop improved mechanistic and data-driven models and predictions of damage and failure likelihoods, based on pooled reliability data and information across the broader thermal recovery sector.
Abstract Since the Industrial Internet of Things (IIoT) became its own domain, in parallel with consumer-oriented IoT, various industries have been successfully deploying such systems – initially as pilot projects, and more recently at scale. Meanwhile, the O&G industry, hurt by the price of oil, postponed investments in new technologies. Nevertheless, there are now multiple successful case studies of IIoT in O&G. This paper contains a high-level review of several such IIoT projects in O&G and aims to help the reader gauge the results achieved in this area. By examining these cases and looking at the similarities and differences with applications in other industrial sectors (transportation, water management, utilities…), the O&G industry can derive guidance in its adoption of IIoT, in particular by identifying the "lowest-hanging fruit" to improve operations and reduce human and equipment costs. While there is still confusion in terms of standards, choice of technologies, and myriad actors of all sizes, this is neither new in our industry nor unexpected in an emerging field; these challenges should therefore not prevent others from moving forward.
Abstract OSHA has reported in 2016 that the upstream industry has one of the highest rates of severe injuries, in some measures, it actually has the highest. Therefore, imagine a world where these accidents, injuries and diseases could be predicted before they actually happened. Such a system has been developed and tested that will redefine the HSE industry thinking. The Human Sensory Predictive Personal Protective Equipment (PPPE) system which is founded on a plurality of machine, predictive methods, and supervisory safety alert system was developed by the efactory (Saudi Aramco: Innovation lab). This game-changing system measures human sensory central and peripheral signals, via human – machine interface - namely brain signals measured by electroencephalography (EEG), and biometrics (heart rate, stress response, temperature, body position and location) measured by specialized sensors built into personal protective equipment (e.g. hard hats, safety glasses, gloves, and belts). The real time outputs from the PPPE could produce anticipated alerts and supervisory instructions to workers and worksite personnel. This innovative system predictively determines risk and alert levels associated to worksite tasks involving, personnel, equipment, and the environment. This system redefines the industry's current thinking through five core value propositions: situational awareness, knowledge and skill retention, biofeedback loops, predictive analytics, and safety alert system. Firstly, it is capable of identifying human awareness states (e.g. disengaged, boredom, fatigue, sleep deprivation) from a collection of brain signals, which is further validated by biometrics. These biological measurements are associated to an adaptive biofeedback system to the worker. The predictive analytics system contributes through a knowledge proposition of the potential of gathering sensory information based on ‘predictive opportunities'. In one work shift there are a total of 86,400 seconds of predictive power/employee that until now, have been left undiscovered. This further challenges and contributes to the well-known safety industry paradigms such as the Henrich - accident triangle. This biofeedback system leverages human machine interface collecting both the brain signals and biometrics. Currently, HSE alert systems do not provide methods and models to utilize awareness through the human computer interface (HCI). This intelligent human sensory system rises to the challenge in developing an innovative platform that could be capable of providing early detection and indication of any hazardous scenario in O&G operations.
After years of low oil prices, the focus is on adding a lot of value for a little cost. SPE’s technical directors are talking about adding value to everything from a petroleum engineering degree to a wellbore.
A failure to do so can mean a degree that does not prepare a student to con-tribute after graduation, or a well whose production fades early.
Those working as petroleum engineers have a generation’s worth of challenges to address due to the push into unconventional development. Those results will determine how much value can be coaxed from these ultra-tight rocks.
For those designing projects that will get built, it pays to think small. A standardized, modular design can deliver value at a cost that is lower, and more likely to come in within the budget.
Doing more with less in drilling means there are fewer drilling rigs in the world, and the job of many engineers still working will be to identify the best available technology to continue to reduce the number of rigs required.
Leaders need to be aware of the value that can be destroyed by mistakes made by humans interacting with complex systems.
And SPE needs to identify and support successful efforts to address health, safety, and environmental challenges, to help spread good ideas and show the difficult challenges the industry can and does address. The value of those efforts is often hard to measure, but it can be big.
Ramona Graves, Academia
The value of a petroleum engineering degree varies widely, depending on where it was earned. In many universities in the developing world, where hiring local workers is essential, the petroleum engineering graduates are far from ready to begin contributing, said Ramona Graves, the director representing academia.
Jeff Moss, Drilling
Drilling engineers are looking ahead to more years of managing jarring change. Jeff Moss, technical director for drilling, said the rapid increase in drilling productivity in recent years is a prelude to more of the same as drilling engineers sift through a flood of digitally controlled offerings promising even greater efficiency.
Hisham Saadawi, Production and Facilities
It is not the time to be thinking big in oil and gas facilities. Hisham Saadawi, technical director for production and facilities, said the focus has shifted from megaprojects to smaller projects where the investment management challenges and risks are all lower. Often companies are “looking at existing facilities to maximize return on the investment made,” he said.
Tom Blasingame, Reservoir
Reservoir engineers have a lot of promises to fulfill. “We were promised big data would save us. That more simulation would save us. And we were promised that we could understand flow regimes at scales we have not been using for the past 100 years,” said Tom Blasingame, technical director for reservoir.
Jennifer Miskimins, Completions
A keyword for completion engineers is interactions. For Jennifer Miskimins, technical director for completions, those range from production-altering pressure surges from well to well during fracturing to collaborations with drillers and reservoir engineers to build more productive wells.
Johana Dunlop, Health, Safety, and Environment
Recognition of industry success is on the growing list of things to do for the new technical director for health, safety, and environment (HSE), Johana Dunlop.
J.C. Cunha, Management and Information
Offshore drilling involves “an amazing set of equipment and high technology … run by human beings.” That sort of human interaction with complex systems has been on the mind of J.C. Cunha, whose term as technical director for management and information ended this fall. He is thinking more needs to be done to “reduce human error in complex systems.”
More than 8,300 professionals from 60 countries attended the 2017 SPE Annual Technical Conference and Exhibition, which was held in October in San Antonio, Texas. Conference panels and technical sessions examined best practices and emerging technologies throughout the oil and gas industry, including discussions on the role of data analytics, contemporary research and development initiatives, sustainability, automation, and recent innovations. Here are highlights from this year's conference. A panel on starting companies selling disruptive drilling technology began with the advice, "If you remember anything today, remember it is not about technology--it is about money." The advice from Tom Bates, an energy investor from Fort Worth, Texas, began a discussion put on by the Drilling Systems Automation Technical Section (DSATS) about starting successful companies that sell digitally controlled drilling tools. When discussing money, the panelists kept coming back to the critical, sometimes maddening role people play in deciding who gets money and profits in the end. "Most profitable companies do not want things that disrupt" the status quo, said David Blacklaw, Shell global drilling automation lead. For change to happen, it may well require upper management to promote changes that have benefits that are not obvious to those in operations.