Process Sensing from top to bottom TEMPERATURE
LEVEL
ProSense family of temperature sensing components includes:
Flowline non-contact ultrasonic liquid level sensors use proven technology that won’t fail because of dirty, sticky or scaling liquids.
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• Continuous level measurement, switching and level control • Automatic temperature compensation for accurate measurement • Output options include current, voltage, frequency and relay • Pushbutton configured models, or PC configured models using free software
• Compact temperature switches • Thermocouple and RTD probes and sensors
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• Transmitters with integral sensors, thermocouple or RTD input • Thermowells and fittings • Thermocouple and RTD extension wire
FLOW The ProSense FSD Series flow switches and new FSA Series flow transmitters monitor liquid media and provide reliable flow detection for industrial applications. • NEW! FSA Series flow transmitters with a 4-20 mA analog output and 0 to 27 GPM measuring range • FSD Series flow switches offered in two flow rates up to 26.4 GPM and include an LED output status indicator • Fast response time (<10ms for FSA model) • Integrated check valve prevents back flow in horizontal or vertical mounting • IP65 / IP67 Starting at:
$10.50
• ProSense float level switches provide a low-cost general purpose solution for single point monitoring of liquid level in a variety of applications. Starting at:
$299.00 • ProSense SLT series submersible level sensors provide continuous liquid level measurement using the hydrostatic pressure exerted by the liquid above the sensor • 4-20 mA output signal compatible with PLCs, panel meters, data loggers, and other electronic equipment • Intrinsically safe with a +/-0.25% accuracy standard
PRESSURE ProSense pressure switches and sensors monitor hydraulic, pneumatic and other process applications reliably and accurately. A wide selection of models are available:
Starting at:
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• Mechanical or electronic pressure switches for low-cost indication and switching
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• Gauge and vacuum pressure transmitters with ceramic or stainless steel sensing elements • Digital pressure switches/transmitters with integral LCD display • Air differential sensors also available
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the #1 value in automation
A class by itself Multi-level fuse blocks with the highest standard of approvals for use in hazardous locations
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I NSIDE OG6
COVER STORY Big data: Challenge and opportunity Understanding how big data affects the oil and gas industry, and where companies are finding most success.
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IT OT HARMONIZATION OT to IT: Creating a circle of improvement Linking operations technology (OT) systems, such as SCADA and sensors to IT-level big data analytics is possible, but begs for the right asset-centric and event-driven view of OT-level trends so the IT-level analytics can find relevant patterns. This article demonstrates that an improvement cycle can be applied to key operational concerns, including equipment health and drilling optimization.
OG13 OG18
BIG CREW CHANGE Thirty years later, the industry is losing its best and brightest, again In the 1980s, the oil and gas industry was going through the same crew change as it is now. Highly educated workers were laid off and the cycle is repeating itself. Will the industry learn its lesson this time?
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FUTURE TECHNOLOGY IoT and the oilfield We are living in an increasingly connected world and this connectivity poses the
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question: “How will it affect the oilfield?” The implications from this are profound and will affect all industries over the next few years.
OG25 OG25
INDUSTRY FOCUS
Scratch out a shale-play living Part 3: Producers are struggling with depressed oil prices, but at least they’re producing. Drilling, conversely, has slowed to a minimal pace.
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PRODUCTS
A selection of useful oil- and gas-related products for engineers.
OG2 • AUGUST 2015
OIL&GAS ENGINEERING
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Big crew change and digital changeover
T
he oil and gas industry has reached a point between operational technologies (OT) and informational technology (IT). Digital systems are replacing the knobs, valves, levers and mechanical parts we have all grown to love. As this happens, how are these two systems working together? Is there harmony or disunity? It’s a slow process to switch out all the moving parts for digital controllers and actuators, which leads to the creation of a hybrid system. Contributing editor Roberto Michel delves deep into the challenge with his piece, “OT to IT: Creating a circle of improvement.” Complementing the IT side of the system, Karen Field’s cover story begins her five-part series on the big data drilldown with, “Big data: challenge and opportunity.” Looking at the IT theme from a wider angle, Frank Braswell, electrical engineer, puts perspective on the Internet of Things (IoT) in the oil and gas industry with, “IoT and the oilfield.” Paris-based oil and gas markets journalist Pierre Bertrand notes the cyclical nature of the “big crew change” and
implies that the industry has not learned from its past mistakes in, “Thirty years later, the industry is losing its best and brightest, again.” Content Specialist Peter Welander finishes his series on return on investment in the oil and gas industry with his look into the unconventional oil and gas market with “Scratch out a shale-play living.” Looking over this issue’s contents brings the question of where the industry is headed. With a decreasing oil price and Iran poised to unload an extra million barrels of oil per day onto the market, it seems that to stay ahead, the industry is going to have to use big data to save where it can and hold on until prices stabilize. The big crew change and the digital switchover are major factors contributing to a scary future. The industry is cyclical, and it seems we are reaching the nadir of the cycle. I think now the only place to go is on an upward trajectory. -Eric R. Eissler, Editor-in-Chief EEissler@CFEMedia.com
OIL&GAS ENGINEERING AUGUST 2015 • OG3
Migrate legacy systems with minimal disruption Another way Siemens is fueling efficiency.
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Annual returns on an investment in modernized automation can be as much as 30%, which would pay for the upgrade in no time at all. This enables your oil and gas operations to be more efficient, profitable and competitive for years to come. Visit usa.siemens.com/oilgas-migration-ce to learn more about migration advancements.
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Advertorial
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ike most process industries, oil and gas operations may be using outdated control systems with components nearing end-of-life. While this can be an opportunity to upgrade to the latest automation technologies, especially to boost efficiencies and operating margins, the risk of disruption and downtime can forestall the needed steps to move ahead. But operators can minimize that risk with careful planning and consideration of the steps outlined in this white paper. Three specific scenarios illustrate how oil and gas operators can migrate and upgrade to newer systems with minimum, if any, disruption. Annual returns on an investment in modernized automation can be as much as 30 percent, paying for the upgrade in a very short time while positioning an oil and gas facility’s operation to be more efficient, profitable and competitive for years to come. The three scenarios this white paper will cover are: • Scenario 1: Replace HMI systems • Scenario 2: Overlay legacy systems (or expand) with new systems • Scenario 3: Replace entire system The core of any control system migration is the PLC. Today’s oil and gas operators can invest in advanced PLC technologies that can truly transform their operations in many ways. Among those: • Open yet common architecture for plug-and-play interoperability • Framework engineering • Real time and remote diagnostics • Highly scalable, high-speed communications • Multilayered security Separately or together, these capabilities can make oil and gas facilities much more efficient, profitable and competitive. Instead of asking if they should migrate their legacy systems, operators should ask how to best upgrade and when to do it.
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• Topic Paper: Rethinking Automation: A Revolution in the Oil and Gas Industry.
OIL&GAS ENGINEERING AUGUST 2015 • OG5
BIG DATA DRILLDOWN
Big data: Challenge and opportunity Understanding how big data affects the oil and gas industry, and where companies are finding most success. By Karen Field
T
here is no better time for oil and gas companies to embrace the concept of big data analytics. But whether the industry, which some say is already spewing out data like oil gushing from a broken well, can realize the full benefit depends a lot on whether it can change. Steve Van Fleet, CEO of MAST (a subsidiary of Micromem), has been to quite a few customer meetings over the past few years. But there’s one in particular that he vividly remembers: “A woman PROBLEM: Despite huge adstood up. She was furivancements in the technologies ous, arms crossed, red and tools, the oil and gas industry faced,” he said. “Then has had a mixed track record when she launched into this it comes to realizing the full benbig tirade about data: efits of big data. ‘We collect terabytes of data now, and we don’t SOLUTION: The most important do a damn thing with it. So don’t talk to me step for companies is to underabout data without tellstand their own manual engineering me how it’s going to ing processes inside and out help me!’” before embarking on a big data That interruption project. stopped Van Fleet midway through a disACTIONS TO TAKE: cussion about his com• Study your manual engineering pany’s MEMS sensor processes and look for opportechnologies. MEMS is tunities to increase efficiency an acronym for microelectromechanical sysin your operations. tems. Developed out • Start with a small-use case of its core expertise in and be prepared to iterate as magnetic sensing, these you learn. tiny biosensors are used • Make sure you have an end-toin oil and gas applicaend solution. tions, such as detecting wear contaminants in
OG6 • AUGUST 2015
OIL&GAS ENGINEERING
lubricating fluids, and identifying the location of hydraulic fractures caused by fracking. “At that moment, I realized our future oil and gas customers were not looking for a technology solution or a data collection solution,” said Van Fleet, a former controls engineer who knows what it’s like to be on the customer side. “Maybe they didn’t actually articulate it that way, but what they were asking for was an end-to-end, big data solution that delivers actionable information and solves business problems.” The big data problem How exactly is it that many in the oil and gas industry wound up trying for big data, but got a big problem with data instead? Mark Lochmann, a consultant who spent 40 years of his career in the oil and gas industry focusing on information technology solutions, has a theory: “The data explosion in oil and gas is happening because we are instrumenting more operations,” he said. “Concurrently, we are able to capture and archive all that information pretty cheaply. Unfortunately, it is not growing in a very well-orchestrated fashion.” That’s because for most companies, the manager of almost every asset makes his or her own decisions about what to do and how to do it. “Sure, there’s a corporate structure that they generally adhere to,” Lochmann said. “But because almost all of the work processes are manual, each engineer said, ‘Well, I have a problem, and I will solve it my way.’” Lochmann said that the one exception is the exploration space, which has made great strides with big data because it tends to be a corporate process.
Figure 1: The oil and gas industry may be lagging behind other industries, but with more and more big data technologies and tools proven and available, and more successful use cases documented, companies have a huge opportunity to get improve the efficiency of their operations. Image courtesy: Datameer
Some industry observers say that more oil and gas companies are now clamoring for end-to-end technologies—presumably to prevent collecting even more data they don’t know what to do with. An end-to-end technology, in the case of big data, is essentially a package of managed services: The deployment of sensors, data collection and storage, delivery of that data back to the customer in the required format, and just about everything in between—sold as a subscription service akin to a monthly phone bill. The level of interest in managed services today has surged since the days when oil was $110 per barrel. “The majors and supermajors were totally against the idea,” said Dave Lafferty, an oil and gas industry consultant. Formerly, with the BP chief technology office, he worked on some of the earliest digital oilfield initiatives. “The tier three onshore oil and gas operators were the ones that first gravitated toward a services model because time-to-market was more critical to them than corporate ego, and they most definitely weren’t interested in building up massive IT departments.” It’s been a different story since oil dropped to $50 per barrel. Now much of Lafferty’s consulting work with top tier companies centers on helping them to use big data more effectively. The returns can be astounding. He points to one example involving a client that had been spending $100,000 annually to monitor just one oil well using a 1980s-era distributed control system. “The company was spending most of its time just manipulating the data,” Lafferty said. “Its cost-perwell dropped after they switched to a subscription service.”
‘
But those wins don’t always come easily. “There are literally hundreds of stories I could tell you about the millions of dollars spent by companies trying to get their heads around big data,” said Lafferty. “Often, it starts out as a simple request for corrosion or temperature measurement. Then, two years and a million dollars later they still haven’t gotten anywhere. That’s because they are so highly siloed. When they think they’ve solved this problem, they discover they have a whole new set of issues and need to involve other departments. It just grows and grows.” Controls engineers, who have typically operated in a bubble, are beginning to grasp this problem first hand. Historically, they’ve been given a list of requirements
Big data is evolving and will continue to evolve in the oil and gas industry. Which specific technologies and approaches will ultimately gain the most traction is still
’
debatable, but Lochmann likes to point out that the industry has been here before.
OIL&GAS ENGINEERING AUGUST 2015 • OG7
BIG DATA DRILLDOWN Six StepS to big data SucceSS 1. Make sure you understand the specific process that you are dealing with. 2. Find the business drivers that will capture the attention of senior management. 3. Decouple monitoring from control in big data applications. 4. Focus on the business problem. 5. Build a strong business case. 6. Give other departments that have a stake in the project a seat at the table. and they build a system that meets those specific requirements, in many cases perhaps not even sharing that information with the controls engineers sitting right next to them. “What we are finding now is that these guys must ensure that their designs are not just meeting the low-lying technical specifications, but that the designs are meeting the requirements across the organization,” said Jerry Hines, North American oil and gas manager for NI’s Energy Segment. NI sells both hardware and software to the industry. Hines said that controls engineers must take a higher-level view and focus on the business problem. “We’re seeing more engineers inviting IT and operations to have a seat at the table, making sure that that their needs are considered as well,” he said. “And that’s a good thing.” Now or never for big data The reality is that there has simply been no better time for big data. Most of the basic technology building blocks of big data are proven and available. Figure 2: Reprinted with permission of Spe: authors Velasquez, g., Kain, J., Villamizar, M., Yong, Z., dhar, J., carvajal M, g. a., … alJasmi, a. K. (2013, March 5). eSp “Smart Flow” integrates Quality and control data for diagnostics and optimization in Real time. Society of petroleum engineers. doi:10.2118/163809-MS. OG8 • AUGUST 2015
OIL&GAS ENGINEERING
Some technologies, such as drones, have been adapted from the military with no modifications required. And more technology vendors, such as large automation companies and providers of drones and sensors, are gravitating toward some kind of a managed services business model. “I would say that at this point in the 21st century, there is a technology out there to resolve any issue you could possibly encounter,” said Mohamed Jradi, automation team lead at JMP Engineering, which provides integrated automation and engineering services for a variety of industries. Jradi oversees the company’s oil- and gas-related projects. That’s both good and bad, from his perspective. “As new technologies become available, people tend to lose sight of what it is they are really trying to achieve,” Jradi said. “I think there’s a tendency for people to want to go with the latest thing. They read about cloud-based analytics and they think that’s the answer to their problems, when in reality they don’t even know what they don’t know or—worse yet, what they are trying to do, which makes it kind of impossible to write specifications.” Before embarking on any new project, Jradi believes that every engineer must ask the question: “Do I understand the specific process that I am dealing with?” And be prepared to answer it. Other industry observers agree that both legacy processes and thinking are impediments to big data success. “Companies
You certainly can’t be there all the time.
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BIG DATA DRILLDOWN Automated workflows require the same attention to detail.” To counter that, Lafferty advised not biting off too much at the start of a big data project. “It may seem counterintuitive, but companies must decouple monitoring and control,” he said. “Capture the monitoring prize first; there is a huge amount of health and safety gains to be made in monitoring applications. You can always move into control applications later.”
Figure 3: Swimming in data: While helping to select and implement a new technology for mobile operator rounds for refinery units in BP North America, analysts first studied the existing paper-based operations. Operators had spent years meticulously collecting data on every shift and placing the completed sheets in the “inbox.” Where did all that data go? Into banker boxes without anyone ever looking at the data. Image courtesy: Dave Lafferty, Scientific Technical Services
OG10 • AUGUST 2015
have the data they need, they have the applications and technology that they need, so why is it they aren’t able to do more?” said Lochmann. He said that many companies have retained their manual engineering processes, rather than studying those processes to understand whether resources are being used to their full potential. “The sad truth is the engineering function has grown up as an autonomous island around each asset, and the attitude is one of: ‘Whatever is required, my operators and engineers will figure it out,’ and they have.” Of course, one reason that companies cling to old methods is that it’s hard to change from manual to automated work processes, and there may be little impetus. “No question about it,” said Lochmann. “In the early 1980s, we started to get these basic PCs, and we had role-playing games. The game placed you in the middle of a field and you had to explore the virtual space by telling the computer what you wanted it to do. It took people a long time to reduce their normal activities to a set of complete, granular commands that the game could process.
OIL&GAS ENGINEERING
Back to the future Big data is evolving and will continue to evolve in the oil and gas industry. Which specific technologies and approaches will ultimately gain the most traction is still debatable, but Lochmann likes to point out that the industry has been here before. “In the mid-1980s, oil and gas exploration groups were going through the same transformation,” Lochmann said. “At the time, the primary valuation of an oil company depended on the ability to find and replace reserves, and most of the exploration work at the time was done with maps and pencils, hanging sections up on the wall. Suddenly, we had computers, which replaced paper and gave you the computational power, which led to 3D imaging, which reduced the probability of dry holes.” Because we now have shales with a large available reserve capacity, Lochmann said that finding and replacing reserves is still important but no longer the top priority it once was. “Oil and gas companies are going to be judged much more than they used to be on how efficiently they can take a reserve and turn it into cash they can use to fund exploration, drilling, and the other activities,” he said. “And there’s the big opportunity for big data.” Coming up: The latest advancements and applications of advanced sensors and data collection technologies for big data. OG Karen Field is a former mechanical design engineer, she has more than two decades of experience covering the electronics and automation industries.
AutomationDirect is a distributor of thousands of industrial automation products including Programmable Logic Controllers (PLCs), Programmable Automation Controllers (PACs), AC drives/motors, operator interface panels/HMI, power supplies, DC motors, sensors, push buttons, NEMA enclosures, pneumatic supplies, and much more. In business since 1994, the company headquarters is located just north of Atlanta, Georgia. Our prices are low. Our prices are well below the list price of more traditional automation companies because with our business model and focus on efficiency, AutomationDirect has the lowest overhead in the industry. We make ordering easy and our service is exceptional. Shop online with our exhaustive product listings or browse our online catalog; fax or phone us – you’ll get friendly, efficient service from the most helpful sales team in the business. Independent surveys completed by readers of Control Design magazine placed us at the top of the list for service 13 years in a row in their Readers’ Choice awards. Other surveys by magazines such as Control Engineering and Control have echoed the results. We ship super fast (and FREE 2-day transit on orders over $49). The majority of our products are stocked for same-day shipping. Orders placed by 6 p.m. EST will ship the same day with approved company credit or credit card. LTL items require 5 p.m. order cutoff and some limitations apply as 2-day transit time does not apply for LTL shipping of heavy itmes. See Terms and Conditions online for full details. We guarantee it. We want you to be pleased with every order. That’s why we offer a 30-day money-back guarantee on almost every stock product we sell, including our software (see Terms and Conditions for certain exclusions).
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Intuitive and personalized Ease of use defines Phoenix Contact’s website When you visit www.phoenixcontact.com/, you’ll get a personalized experience, easy navigation, clear product categories, and an intuitive search feature. The Homepage Our homepage highlights new products, upcoming events, and a range of information and links about the company, its products, and services. The improved search field suggests matching results as soon as you begin typing your request. Numerous filter items allow you to further refine your results. Finding what you want Phoenix Contact’s product catalog consists of more than 60,000 part numbers, and we’ve built-in several ways to find the product you need on the website. An easy-to-follow navigation menu makes it simple to find product information by including common industry terms. You can choose an A-to-Z product list, which features all of our product categories, along with common synonyms. This is available from any page on the site. If you’re more accustomed to Phoenix Contact’s product lines, you’ll like our Products tab, which includes links to the traditional catalog names. Our products in detail Specific product pages contain all the important details, such as technical data, approvals, and accessories related to the product. The website is designed so that you can select products you’re interested in and get a side-by-side comparison. You can also check product availability at a local distributor. Helpful downloads are made available, such as software and technical documents, directly through the product page or through the Service and Support tab. Solutions and resources Explore the “Solutions” section to learn how Phoenix Contact plays a role in key industries, including automotive, oil and gas, solar, transportation, water management, and wind power. Our “Resource Center” gives you an in-depth look at our products and technologies, including downloads of white papers, real-world case studies, and more. Other features include: • A Wish List: Submit inquiries about products
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IT OT HARMONIZATION
OT to IT: Creating a circle of improvement Linking operations technology (OT) systems, such as SCADA and sensors to IT-level big data analytics is possible, but begs for the right asset-centric and event-driven view of OT-level trends so the IT-level analytics can find relevant patterns. This article demonstrates that an improvement cycle can be applied to key operational concerns, including equipment health and drilling optimization. By Roberto Michel
T
he meeting of OT and IT systems is starting to take shape. OT-level systems are effective at what they do: tactical control over industrial processes and equipment assets. For their part, IT-level systems, including big data analytics, are effective at mining data to find patterns. But for the two to work together, there is a need to not only move data between the levels, but to provide context so that appropriate actions can be taken at the OT level. In a sense, the two are not merging so much as working in concert, with data from OT systems and Internet-connected sensors feeding higher-level analytics, where outputs then must be acted upon. It’s a virtuous circle in the making, with the goals spanning
issues, such as equipment reliability and uptime, and continuous improvement of operations, such as better rate of penetration (ROP) in drilling. Technology that can help this improvement cycle include big data analytics and enterprise historian software with associated asset-centric data models and analytical tools. In the opinion of some observers, what’s really needed is a better way to aggregate OT-level trends in one place and apply analytics without saddling engineers to manually gather data from point systems, including multiple SCADA systems. “Many of our clients have engineers spending 60 to 80% of their time just gathering data—dealing with exports from SCADA systems, reports, or spreadsheets—
Figure 1: OT to IT convergence to improve asset performance is aided by a context infrastructure layer with an asset-centric data model. Image courtesy: OSIsoft OIL&GAS ENGINEERING AUGUST 2015 • OG13
IT OT HARMONIZATION PROBLEM: Operations technology (OT) system spew out vast volumes of data on a continuous basis, but how do you harness this data for operational improvement in areas such as equipment health? SOLUTION: Oil and gas companies should consider enterprise historians and big data analytics software that function on an IT/ enterprise level to overlay assetcentric context over OT level data source, apply modeling and analysis, and recommend adjustments to OT level systems. ACTIONS TO TAKE: • Consider asset-centric data models so that OT level trends can be analyzed by asset types and attributes rather than tag names. • Apply modeling and analytics to look for hard to spot inefficiencies in performance or subtle precursors of equipment failure. • Look to create a continuous circle of improvement around equipment health or operational metrics by aggregating OT level trends into analytical software, and then apply modeling and rules techniques to arrive at actions to take back at the OT level. • Big data technology such as Hadoop can be leveraged to provide a single source of truth over OT-level data, and enable analytics that can help improve operations such as drilling performance.
OG14 • AUGUST 2015
OIL&GAS ENGINEERING
to even get to the point of analysis,” said Kemell Kassim, a vice president with Gray Matter Systems. “So by the time they’ve identified something to take action on, the data they are looking at might be weeks or months old, and meanwhile, the equipment and processes have been running inefficiently during that time.” Enterprise historians and associated analytics can help companies quickly gather data from OT-level systems, spot trends, and recommend adjustments, according to Kassim. This class of solution can also keep highresolution data intact. “When data is gathered manually, it tends to get dumbed down, meaning you end up looking at averages, or minimums and maximums, which makes it hard to draw accurate conclusions,” Kassim said. “You want to maintain high resolution on the underlying data, and also be able to apply some modeling to spot trends that require action.” Asset-centered analysis For OT and IT to work together, some technology providers see the need for software that acts as a context layer. Craig Harclerode, an oil and gas industry principal with OSIsoft, said that a context infrastructure for OT to IT interoperation should provide a metadata layer
for an asset-centric view of tag data, and be able to single out events that can be examined by analytics. “The context infrastructure’s metadata is an object model that abstracts process-level data so that it can be searched and analyzed by asset names and relationships instead of by tag names,” said Harclerode. “In this way, users can more easily compare the performance of similar types of equipment, such as compressors, or pumps that have similar sensor, performance calculations, and operating envelopes rather than trying to find information by tag names. “Because of the explosion in the number of data points or tags, the tags are becoming so numerous that you can’t really be effective at finding information and analyzing performance of like assets unless you move to an asset-based structure,” said Harclerode. The benefit of an OT-level-context infrastructure goes beyond data integration to this idea of circle of improvement between the OT and IT levels. Harclerode referred to this last, crucial phase as “operationalizing” the results of big data analytics. Oil and gas industry clients have been able to use context infrastructure capability with the company’s historian to aggregate and pass data to enterprise-level analytics in the proper asset-based model, and bring insights back into the historian for an operational benefit. Marathon Oil is a good example of using this technology, as the company has used the system and other analytics to improve drilling operations. Marathon is using the system for drilling performance analytics, using it to aggregate and move OT level data to systems such as Tibco Spotfire for further analytics, then displaying results and recommendations for adjustments back to drill rig operators using the system. As Ken Startz, senior business analyst with Marathon Oil, said in a presentation at OSISoft’s 2014 European user conference, “We see the transition from using PI as a tactical historian ... to more of an infrastructure around all of our data.” The PI system serves as OT infrastructure for Marathon’s MaraDrill system, a customized corporate system used for drilling performance management for
approximately 30 leased drilling rigs across three shale-gas plays in North America: Eagle Ford, Bakken, and Woodford. The system feeds data into analytics, including Spotfire, which is used to provide depth-based drilling performance insights to enhance the time-based drilling performance trends available through the system. An XML data export function within the system is used to export a slice of time-based drilling data to Spotfire, where it can be analyzed to give a depth-based understanding of drilling performance, such as weight on bit (WOB) over a given depth. By analyzing performance across both time and depth, MaraDrill provides insights to help avoid problems such as “stick slip,” a vibration phenomenon detrimental to efficient drilling. MaraDrill also runs models that generate recommended setpoints that drilling operators use to adjust WOB, torque, and other parameters in the drilling control system to avoid problems like stick slip and maximize ROP. According to Startz, about 50% of the benefit of MaraDrill comes from operators following these recommended setpoints, while the other half of the benefit comes from collecting data in PI and being able to perform analyses on the wells that were drilled. MaraDrill’s system has helped Marathon Oil improve on ROP for drilling versus peer group averages, with Marathon’s ROP at 1,450 ft/day, while peers averaged 1,050 ft/ day. “That is a pretty strong statistic that by using these advanced tools, we can drill faster and better,” said Startz. Equipment health Many oil and gas companies are trying to improve either process performance or equipment health by bringing data from the OT world into enterprise-level analytics. To do that more effectively, it helps to have an asset-centric view of OT-level data within asset monitoring solutions, according to Bart Winters, business manager of asset management solutions for Honeywell Process Solutions (HPS). “A key challenge is organizing data in the context of assets, so that you’re dealing with the data in terms of the attributes associated with a piece of equipment,
rather than cryptic underling tag names,” said Winters. “For example, it’s easier to troubleshoot pumps or heat exchangers if an engineer or support person can drill down into an asset hierarchy, beginning at the rig or well level, moving down to asset type, such as a pump, and then looking at the attributes of interest, such as inlet pressure. This requires the analytics
Halliburton’s big data expert on why Hadoop can help OT-level performance
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pen source big data technologies, including Hadoop and Storm, should be seen as complementary to traditional systems used at the OT level for monitoring and analysis. These big data technologies will help oil and gas companies get a complete picture of diverse data and complex relationships, which influence issues like drilling performance, according to Dr. Satyam Priyadarshy, chief data scientist at Halliburton’s Landmark division. Hadoop can be thought of as a way to store large amounts of complex data of any type without losing its resolution or data model, according to Priyadarshy. “This is because unlike traditional data warehouse technology based on an extraction, transformation, and loading paradigm, Hadoop is used to ingest data in native format and the transformative step is performed during the computing phase to discover value from big data,” he said. The result is that many types of data, from flat-file sensor data, tag data from historians, work order data from maintenance systems, geology data, or even video or scans of handwritten notes, can be stored and used within a Hadoop system. “What it provides you, at a base level, is a single source of truth,” Priyadarshy said. In some instances, big data must be analyzed in near real time, which is where big data technologies like Storm and Spark come into play because they are able to perform stream processing of data. “Halliburton Landmark’s software is able integrate to these big data technologies,” Priyadarshy said, “so that users can look at every available data source to find out which factors or subtle causal relationships between factors lead to lower than expected performance around issues such as ROP in drilling operations. Internally, Halliburton has begun to employ big data engines such as Hadoop to optimize operations by being able to consider the full range of data that might influence performance.” “Big data analytics is all about looking at the total picture and can be combined with industry applications that have specific domain knowledge or data cleansing algorithms,” said Priyadarshy. “Big data is about all the data relevant to a business. So whether the data comes from operational technology systems, or the data is from IT or business systems, you want to look at the whole picture. Traditional analytics that people have done have mostly been done in silos, and when you do things in silos, you can only get so much value from it.” OIL&GAS ENGINEERING AUGUST 2015 • OG15
IT OT HARMONIZATION
Figure 2: Using analytics for continuous process performance and equipment health monitoring can not only help spot precursors of major failures, it also can flag smaller but more frequent deviations from ideal process efficiencies. Image courtesy: Honeywell Process Solutions
software to have an abstraction layer that organizes data around asset types and attributes, but can still access tag-level data.” An effective analytics solution for taking action on OT-level trends should also be able to do rapid calculations on process or equipment performance data to see what the current operating efficiency is compared to expected performance to monitor for deviations from goals, according to Winters. “Besides these first principle calculations, asset monitoring solutions also need rules engines to kick off workflows,” he said. Asset analytics also should have data cleansing logic to automatically compensate for corrupt or missing data, as well as the ability to consider data other than tag-level process data, such as lab samples, work order data, vibration monitoring data, or oil analysis data. The sum of these capabilities, according to Winters, is what allows end-user organizations to glean OT-level data for the trends that require action. “You need the ability to bring multiple data sources in, cleanse and analyze the data, and do exceptionbased notifications and workflows when conditions or trends are not matching the expected model,” he said. input #104 at www.controleng.com/information
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Many oil and gas companies are trying to improve either process performance
use of monitoring and analysis solutions is to reduce the frequency and impact of unplanned capacity loss,” said Winters. “You might avoid a more catastrophic event in some cases, but it’s also about monitoring for efficiency.” OG
Roberto Michel is a freelance writer and editor with more than 20 years of experience with business-to-business publications.
or equipment health by bringing data from the
STATE-OF-THE-ART SOLUTIONS FOR DEMANDING APPLICATIONS
OT world into enterpriselevel analytics.
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Shell uses HPS’ asset monitoring and analysis software for performance and asset health improvement for its deepwater Gulf of Mexico operations, according to Winters. The system supports what Shell calls its exceptionbased surveillance or (EBS) program for the region. The EBS program is able to take in multiple sources of OT-level data and perform data cleansing to adjust for noisy and incomplete data so that valid alerts are triggered. Shell sees the EBS workflows as a higher-level, more multifaceted form of dealing with exceptions, rather than the type of operational alarming that occurs in OT-level systems when a single tag crosses a threshold. The EBS’s workflows also differ from OT-level alarming in that they escalate to the engineers responsible for long-term operational or asset health improvements, rather than operators who need to concentrate on short-term adjustments. The aim of asset monitoring and analytics is to consider various sources of OT-level data, and then apply data cleansing, rules engines, and workflow capabilities to elevate crucial issues for engineers. This helps identify both subtle precursors to equipment failure that might go unnoticed in traditional OT-level systems, as well as spot inefficiencies, such as primary and backup pumps running in parallel. “The basic goal in the OIL&GAS ENGINEERING AUGUST 2015 • OG17
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BIG CREW CHANGE
Thirty years later, the industry is losing its best and brightest, again In the 1980s, the oil and gas industry was going through the same crew change as it is now. Highly educated workers were laid off and the cycle is repeating itself. Will the industry learn its lesson this time? By Pierre Bertrand
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hen Javier Olivero received his pink slip from Schlumberger in May 2015, he became one of the 20,000 people from the global oilfield service company to lose his job due to low oil prices. Olivero, 48, was hired in 2012 for the third time at the company. He started working in the oil and gas industry in 1989. By 2015, he had worked as a petroleum and reservoir engineer, he had experience in economics, decision analysis, and portfolio management. His accumulated experience made him a valuable asset. Before being laid off, Olivero was part of a team developing Schlumberger software for economic and capital planning, reserves accounting, and portfolio management. That was until his entire department was outsourced to India to pare back the company’s payroll. Olivero’s story is not simply one of tough economic realities, cyclical PROBLEM: The industry is facing commodity fluctuations, a shortage of skilled engineers and industry shortretiring or being laid off. termism. In the latter half of his career, Olivero is one of thousands of SOLUTION: Oil and gas compadeparting experienced nies need to invest in their emoil industry professionployees, instead of laying them off. als—either forced out by low oil prices, or on the ACTION TO TAKE: verge of retirement—who • Have older workers mentor will be taking his accuyounger employees to ensure mulated experience and knowledge with him. His experience and gained knowlforced departure exacedge remains in the company. erbates a demographic crisis, an across-the-board
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OIL&GAS ENGINEERING
changing of the gray guard, dubbed the “big crew change.” The big crew change first began in the 1980s. Faced with a crunch in the price of oil that lasted throughout the mid-1990s, companies drastically scaled back on hiring new employees and laid off older, more experienced, but expensive professionals, mentioned Dr. Ramanan Krishnamoorti, professor of petroleum engineering at the University of Houston. “There was no place for companies to hire and place people. The only people who were kept were those capable of monetizing existing resources,” Krishnamoorti said. An estimated 600,000 jobs in the oil and gas industry were cut. What the industry unwittingly did in the 1980’s was plant the seed for a future demographic bubble that, 35 years later, is now bursting. The current generation of experienced senior petro-technical professionals (PTPs)— those with at least 25 years of experience and who are about to retire—is the same group that lived through the layoffs of the 1980s and 1990s. With insufficient hiring and grooming of young professionals into oil and gas at that time, the industry failed to create a new generation of experienced PTPs who would now be 32 to 50 years old and entering their mid-to-late careers. “There is a gap now in that age profile,” Krishnamoorti said. “That is what is biting the industry today.” Crunching the numbers: Hard truths Within seven years, as many as 50% of senior experienced PTPs, those currently between 47 and 57 years old with at least 25 years of work experience will be retiring. That number represents as many as 20% of
the entire oil and gas workforce in the U.S., said Kevin Lacy, executive vice president of technical staff at PetroSkills Alliance. The alliance was formed in 2001 by Shell, BP, and Ophiuchus Consulting Group, a Toronto-based corporate development consulting firm, to provide competency training to those who work in the oil and gas industry. The alliance’s 33 members represent 40% of the world’s oil and gas production. Between 2009 and 2015, the percentage of global PTPs with at least 25 years of experience fell from 38% to 26%, according to Lacy. But while the industry faces large retirement numbers, and a trough in mid-career professionals, with oil prices hovering a bit $53.35 per barrel on July 28, 2015, companies are again scaling back staff, and cutting training and development. “I’ll be a bit blunt. Companies when they enter a down turn like this on oil prices, they do stupid stuff,” Lacy said. “I would say 80% have cut their training programs in half, and that leaves very few who are trying to stay the course, which is actually the smart thing because they still have numbers of people that need training.” Since January 1, 2015, as many as 150,000 jobs, both directly and indirectly tied to the oil industry in the U.S., have been cut due to low oil prices. The big four oilfield service companies—Halliburton, Schlumberger, Baker Hughes, and Weatherford—plan as many as 49,500 cumulative job layoffs this year. Schlumberger’s 20,000 layoffs accounts for 15% of its total worldwide workforce. And the cuts are likely to continue. The U.S. Bureau of Labor Statistics reported in June a loss of 500 additional jobs in oil and gas extraction with a further 16,900 ancillary supporting jobs. According to Schlumberger’s 2013 Oil and Gas HR Benchmark, released in July 2014, which records and anticipates trends in technical staffing within the oil and gas industry, the projected global number of desired experienced PTPs in the oil and gas industry by 2018 will total 108,000. The 2018 projected global supply, however, is estimated at 75,300. Moreover, this information was obtained before the downturn in the industry.
Short-sighted remedies, Krishnamoorti suggested, such as layoffs during commodity downturns risk dissuading incoming college students from entering the oil and gas industry, further hampering the industry’s ability to recruit and retain a new generation of workers. What the industry faces for the foreseeable future is a lopsided distribution in the age of oil and gas workers. The numbers of young professionals hired in the past 15 years make up a larger percentage than those older and more experienced professionals whom younger employees depend on for training and mentorship. “If I were to bet today, and look four years down the road, I’d say we’ll need a lot of petroleum engineers,” said Krishnamoorti. “Enroll as a petroleum engineer today because we are going to need you.” According to Schlumberger’s HR report, relatively inexperienced PTPs who are 25 to 29 years old in 2005 roughly represented 13% of the global workforce. By 2018, they’ll represent as much as 24%. During this same time, mid-career professionals 40 to 44 years old in 2005 made up roughly 16%. By 2018, they’re expected to drop to almost 10%. Ghosts from the past are today’s problem Faced with low oil prices, sizeable layoffs, and with a seemingly new demographic bulge in the making, one would be forgiven for thinking the oil and gas industry was in the grips of a self-repeating cycle, that it is committing the same mistake today it did in the 1980s. While there are certainly echoes of yesteryear, “a big difference between now and the 1980s is that training and hiring activities have not stopped,” said J. Ford Brett, CEO of PetroSkills. “The biggest thing will be how many new hires will these large companies have over the next few months?” The American Petroleum Institute (API), the largest industry trade association in the U.S., predicts as many as 1.2 million jobs will be created in oil and gas by 2030. A vast majority of those jobs are anticipated in the Gulf Coast region of the U.S., where hydraulic fracturing of shale resource plays has prompted a renaissance of on-shore production. Reid Porter, API
current ‘ The generation of experienced senior petrotechnical professionals (PTPs)—those with at least 25 years of experience and who are about to retire—is the same group that lived through the layoffs of the 1980s and
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1990s.
OIL&GAS ENGINEERING AUGUST 2015 • OG19
BIG CREW CHANGE
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Faced with low oil prices, sizeable layoffs, and with a seemingly new demographic bulge in the making, one would be forgiven for thinking the oil and gas industry was in the grips of a self-repeating cycle, that it is committing the same mistake today it did in
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the 1980s.
spokesman, said that the job numbers include all job categories and skill sets. Measuring exactly how many people enter the oil and gas industry meanwhile is tricky. Who’s in, who’s out Companies view workforce supply and demand as proprietary information, Samantha Sipowicz, a spokeswoman for the Society of Petroleum Engineers (SPE), said in a written statement to Oil & Gas Engineering. SPE, however, publishes its own membership demographics, which is a useful barometer to assess the industry’s global workforce. By year-end 2014, SPE reported having 92,965 professional members from 147 countries. Of that number, 27,854 of them were 35 years old and younger, and 7,011 were at least 65 years old. The average age of the SPE’s professional membership was 45 years old as of year-end 2014. Student membership in the SPE equaled 50,997 for the same period—a 13,290 increase from the previous year. If companies stay the course over the next five to eight years and continue hiring and training employees, the oil and gas industry stands a good chance of recuperating from the demographic gap caused by the 1980 downturn, Brett said. But that could depend largely on the price of oil. “The demographic health of the industry will be a lot better 30 years from now. I suppose it is possible if the price of oil falls to $20 or $30 per barrel, that people will do something that will be harmful,” Brett said. Invest in quality staff Courtney Stephens, CEO of QED Energy Associates, which provides training programs for incoming oil and gas industry technicians, said that while companies are still hiring, the layoffs from commodity pricing have made it harder to find a job. Whereas companies’ hiring processes a year ago may have taken two to three weeks, with the abundance of laid-off technical staff this year, companies may take 2 to 3 months to hire a candidate, she said. Companies may also be using the drop in commodity pricing to their advantage by using it as an opportunity to reassess their hiring projections by reducing the amount of
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anticipated staggered retirements, according to Stephens. “When we talk about the big crew change, HR departments are struggling with the fact that they are going to have people retiring over the next five years, and they are all going to be retiring at different times,” said Stephens. “I think HR departments within oil companies have taken advantage of the fact that we have a commodity price crunch, and they are using this to get rid of anybody that’s within a couple of years of retirement.” Stephens said she has been receiving 25 resumes a week since the beginning of 2015 from close friends and contacts recently laid off; all of them within years of retirement and still hoping to find work. “They are engineers I know who have worked at oil companies for 25 years and are qualified experts,” Stephens said. “They are very good at business development, structuring acquisitions and divestitures, they have intellectual capital stuck in their heads that no one else at their company can possibly have, their performance is outstanding.” If company leadership is not prepared for staff transitions, the laying off of its more experienced PTPs could cost them more than their initial payroll savings by either failing to aggregate or altogether losing the intellectual capital of departing staff. This is where companies face the real challenge to address the big crew change. In the same way medical students do in-house residencies to learn how to apply their years of studies, so too do many college graduates entering the oil and gas industry. Schlumberger’s 2011 HR Assessment report said that PTPs could take as many as 11 years to acquire the necessary skills to make nonstandard, original technical decisions when working for national and international oil companies. Faced with more relatively inexperienced PTPs and a deepening deficit of senior experienced PTPs, industry leaders are asking themselves how to efficiently dedicate time and resources to narrowing the experience gap within their ranks. One solution could come in the form of technological applications to facilitate
knowledge transfer, said Kandy Lukats, CEO of 3GiG, a knowledge capture software company based in Houston. Lukats, 51, said companies are better able to use technology in ways that can create a corporate memory of how employees, technicians, and their leadership carry on large capital decision making projects. By integrating a knowledge capture software application within a company’s daily routine, companies could be better prepared for the brain drain of leaving retirees, or those senior professionals recently laid off.” Lukats, whose company’s clients include Hess, BP, and W&T Offshore, said there is growing interest within the industry for these types of software applications, but their adoption remains limited despite the decades companies have been tackling the big crew change. “Everyone talks about it, but what we’ve found is unless you target tangible solutions specific to the way people work every day, companies won’t adopt technology, because they can’t prove any value,” Lukats said. “Their ability to be agile and to react is way more efficient now, but the problem you have is, if you’ve lived through the 1980s, you were a young upstart and you wouldn’t have been in
a management role to understand the impact on the business during that time. Therefore, companies are almost relearning what their predecessors already went through.” For Olivero, that is precisely his concern. He said that he was not surprised to have been laid off from Schlumberger. Having lived through previous price fluctuations, he knew what to expect, but he did not anticipate being let go before the software program he was working on was finished. “Because they laid off a bunch of people from my area globally, how will they transfer that knowledge to younger people?” Olivero said. “How will they transfer the knowledge of how to use the software itself, its testing, and development to the new people in India?” Today, Olivero is attempting to start his own business by taking advantage of his experience and the low oil prices to enter into acquisitions and divestitures of oil and gas assets. On a final note, he said when he was let go from Schlumberger, he was not mentoring anyone. OG
Who is going to be working it the future? If the skilled engineers are retiring now, who is going to train the new generation. Image courtesy: CFE Media
Pierre Bertrand is an oil and gas markets journalist. He worked for two years in Kuwait and Oman as well as in the U.S. analyzing oil and gas markets. OIL&GAS ENGINEERING AUGUST 2015 • OG21
FUTURE TECHNOLOGY
IoT and the oilfield We are living in an increasingly connected world and this connectivity poses the question: “How will it affect the oilfield?” The implications from this are profound and will affect all industries over the next few years.
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magine a pumper at a wellsite with a cell phone or radio as a connected device. As the pumper moves around the site, a great deal of visual, auditory, and thermal data can be collected and reported. Not only can the pumper gather data, but an analysis of site conditions can be processed, and the results reported via the communication device. Ideally, around-the-clock site coverage is desired. However, having someone on-site 24/7 is cost prohibitive, as is the idea of heavily instrumenting a wellsite. This will begin to change with the application of IoT technologies to oil and gas production. IoT will touch key areas that operators are concerned about: productivity, safety, compliance, asset protection, and environmental stewardship. Several technology advances make IoT possible: small and inexpensive components, greater functionality, sensor technology, high-speed wireless communications, new Internet services, greater computing speeds, and high-density storage technologies. As these areas PROBLEM: Systems for getting improve, IoT will prolifertimely and actionable informaate into more aspects of tion remotely from the oilfield are oil production and expand costly and difficult to deploy. to smaller producers. Another consideration SOLUTION: IoT technology has is that smartphones will the potential to make the benefits become an integral part of remote oilfield monitoring cost of the IoT experience. Getting actionable data effective and feasible, even for needed for site operation small producers. will no longer be tied to a desktop computer. For ACTION TO TAKE: this to happen, installation • Keep a close eye on IoT techof IoT systems must be nologies and concepts as it is simple and system operaincreasingly deployed in varition must be easy to comous industries. prehend and use. Relating that to smartphone usage,
By Frank Braswell
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the device is extremely complex, but the interaction is made simple with the use of icons, color, shapes, and movement on the screen. Interaction with IoT systems will be visual and intuitive, also based on interaction with mobile devices. Productivity Before anything else, an IoT system must increase productivity before owner/operators will even consider it. For most, monitoring tank levels is at the top of the list, especially for crude oil. If the tanks are remotely monitored, there are a number of immediate benefits, as numerous manual steps are eliminated to get data from the field to the office. This makes it much easier to generate royalty reports and manage production rates. Reporting in real time or near real time allows operators to respond to production problems much faster, saving time and money. Another benefit is displaying production data automatically on a smartphone (see Figure 1). This allows field and office personnel to view wellsite information together and take appropriate actions. This also shows the effectiveness of a modern visual user interface. Productivity enhancement can also be achieved by monitoring vibration and heat from bearings and motors to detect fault conditions and predict maintenance needs. Thus, IoT can enhance productivity with the deployment of various sensors throughout the wellsite, along with the display of actionable data and real-time messaging. Safety Oilfields are hazardous by nature due to high pressures, moving machinery, high voltage, and toxic liquids and gasses. In addition to worker safety, consider thievery and copper theft as workplace risks. IoT technology has the potential to reduce the risk of injury.
Monitoring and reporting of toxic gasses, such as hydrogen sulfide, carbon dioxide, and methane at the wellsite give workers warning of hazardous conditions. Wind speed and direction reporting are also helpful as workers approach the site. Sensors monitoring pressure, temperature, levels, flows, and other critical parameters can be programmed to indicate readings that are out-of-bounds and dangerous, so workers can be aware of hazards as they approach the wellsite. Warnings can be communicated via text messages and special screen displays on mobile devices. Unauthorized personnel can be indicated by vehicle detection sensors, visual surveillance cameras, and audio monitoring, alerting operators to potential problems. Mobile devices can be programmed to track workers’ locations and movements. Unusual movement, or lack thereof may indicate problems. Workers can also use mobile devices to send for help. On the downside, tracking workers’ movements will immediately bring up privacy concerns. This is an issue across the board for all users of this new mobile technology, and beyond the scope of this article. Some workers may welcome the additional protection, while others will object. Regulatory compliance Many of the aforementioned remote measurements will be related to proof of regulatory compliance. Tank levels and images taken by remote monitoring systems can serve as proof that monthly, semi-annual, and annual reporting requirements are met because the data are time stamped. The data can be retrieved from the system and incorporated into the required reports. If a spill occurs, damage can be quantified by knowing exactly when the spill occurred, and the quantity lost. Without monitoring, there is no way to know how long the condition has been critical.
be taken by the system, such as activating lights, sounding alarms, or activating cameras. Text messages can be sent to operators if sensors detect a problem. Big data With additional sensors, more data are collected, which will have benefits beyond simply monitoring more single points of operation at the wellsite. For example, maintenance histories can now be tracked and correlated across individual and multiple wellsites. As IoT systems are deployed, they may start with sensors for only the most important measurements, such as tank levels. IoT systems are designed to easily add sensors, covering more operational parameters. However, as more data are collected, information management becomes an issue. It’s no longer possible to interpret results with a single spreadsheet or graph. The sheer quantity of data makes the display of data problematic. Looking at graphs and numbers isn’t enough anymore. To ensure proper data analysis and usefulness, two things must happen. First, the data must be analyzed in such a way that it
Figure 1: Pumper’s friend iPhone software. Image courtesy: Systems of Merritt, Inc.
Figure 2: IoT in the oilfield. Image courtesy: Frank Braswell
Asset protection Remote monitoring can signal a breach of property, unusual drops in crude oil levels, electrical outages, or other conditions signaling problems at the site. Measures can OIL&GAS ENGINEERING AUGUST 2015 • OG23
FUTURE TECHNOLOGY yields useful and actionable information. Second, the results must be presented in a more visual way so that information can be easily grasped. Data analysis needs to go beyond the obvious curves and numbers. Deep inside multiple data streams is
hidden information about production efficiencies. It can be found only by cross-correlating data. For example, temperature, vibration, and pressure at the wellhead can indicate pump inefficiency or seal wear. The data taken over time can predict when mainte-
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Oilfields are hazardous by nature due to high pressures, moving machinery, high voltage, and toxic liquids and
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nance is needed. Data can also be analyzed across a group of wellsites to predict reservoir performance.
input #106 at www.controleng.com/information
What will the future bring? IoT systems have the capability to bring in data from every important area of the oilfield that affects performance. That data has the ability to improve efficiency, protect workers, monitor assets, and allow for better environmental stewardship. As prices for sensors and electronics continue to decrease, devices become smaller, communication improves, and cloud services mature, IoT systems will proliferate in the oilfield. Maintenance costs for older, wired SCADA systems will eventually drive larger producers to IoT systems that feature lower installation and maintenance costs, and yield better information. IoT systems aren’t just about deploying many fancy wireless sensors. It’s about using those sensors to generate useful and actionable information in real time from the wellsite to provide significant operational benefits. Keep an eye on IoT, because it will be coming to the oilfield, and coming to smartphones in the near future. OG Frank Braswell has authored the Pumper’s Friend software for oilfield data collection and has recently worked with WellMark on remote tank level sensing hardware and software. OG24 • AUGUST 2015
OIL&GAS ENGINEERING
INDUSTRY FOCUS
Scratch out a shale-play living Part 3: Producers are struggling with depressed oil prices, but at least they’re producing. Drilling, conversely, has slowed to a minimal pace. By Peter Welander
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From 2010 through 2014, investment in exploration and drilling increased by 80%, but that trend has reversed. Areas where jobs couldn’t be filled fast enough are now seeing major declines.
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o far, this article series has examined refining and the oil industry as a whole. This installment concentrates on land-based operations and includes the actual oil plays and production sites where oil, natural gas, and water are separated and prepared for refining. The nature of this section of the industry has changed enormously over the past few years with the advent of large-scale hydraulic fracturing for oil and gas production. For a while, producers couldn’t drill fast enough in areas such as Marcellus, Bakken, and Eagle Ford plays, but those advances stalled as the price of West Texas Intermediate roughly halved during 2014. Much has been written on the causes for this change, but for now, the effects will be considered, concentrating on unconventional drilling. From 2010 through 2014, investment in exploration and drilling increased by 80%, but that trend has reversed. Areas where jobs couldn’t be filled fast enough are now seeing major declines. But how does this macroeconomic picture affect life for companies trying to make a living by producing crude oil? Traditionally, the upstream portion of the industry had generally been regarded as the high-profit part of the business with refining plodding along, trying to keep its head above water. That picture reversed and companies that only operate refineries are glad to be doing just that. Oil still flows The industry consensus is most of the conventional oil and gas in North America and much of the world has been found and extracted. The next barrels of oil will either come from unconventional plays or involve expensive extraction methods, in some cases both. Fracking is more expensive than traditional methods, and oil prices below $60 per barrel make those unsustainable. However,
once the wells are drilled and producing, it’s important to keep it flowing. “One thing that’s keeping the oil prices low is that everything that has already been developed is producing at maximum or close to maximum,” said Randy Miller, vertical marketing director for gas at Honeywell Process Solutions. “If the initial drilling investment has already been made, it’s almost always the best decision to produce at the highest level. If you strip away the cost of capital, the operating costs of shale wells are not all expensive. The sunk cost and the cost of capital is the biggest component, so there is not much incentive to shut the well down because you still have to service the debt, maintain leases, and other associated costs. There are fixed costs you can’t avoid whether the asset is producing or not.” Miller added that in some situations producers ended up halting work in new fields, completing wells but stopping short of doing the final connections. The wells remain untapped, waiting for prices to recover. James Crafton, consultant with Performance Sciences, considers the rate of return on investment the key element as companies look at their situation. “Only the leveraged small production operators are in a bad way,” he said. “The rest just aren’t making as much money as they would like. However, based on my analysis and that of a few others, those companies where the primary cash flow stems from drilling are in trouble. This is because production alone does not cover their operating costs. It has been reported that in several shale plays, few, if any of the wells will actually pay out.” According to Crafton, the resulting management strategies to mitigate this challenge are diverse to say the least, and include: • Reducing nontechnical staffing and terminating consulting staff • Minimizing capital expenditures: no compression and no surface facilities OIL&GAS ENGINEERING AUGUST 2015 • OG25
INDUSTRY FOCUS in this series pointed out, just because there might be a clear business case for making some sort of improvement, companies are not necessarily ready to leap at such an opportunity. There are other considerations at work. “Whenever an industry retracts, we have a surplus of many things, so the aspects that focus on efficiency are not usually the ones that are employed first,” Miller said. Many projects are proceeding, particularly those related to compliance issues, but overall Honeywell has been surprised Image courtesy: CFE Media at the extent to which producers have delayed or cancelled other automation projects, still the expecta• Reducing drilling or drilling to hold acretion is that discretionary automation projects age, set pipe to satisfy the contract, and related to efficiency increases they will come move to the next lease back as soon as the price of oil shows more • Not bringing wells online, which saves on sustained upward movement, according to lease operating expenses and automation Miller. Companies with a little foresight might costs. want to get ahead of the curve and work on Not a great situation, but production comprojects now, during the lull, so they can be panies are pushing ahead in areas where ahead when prices recover. production is already underway. Other com“When resources become tight and expenpanies look at this situation with a sense of sive, automation can make those resources history and know the industry has survived more efficient,” said Miller. “Under those boom and bust cycles many times before. conditions, automation has more value. But This is just one more. “I’ve seen some projnow we have people and resources availects that are tied to the bigger picture,” said able to develop assets, even if they’re less Virgis Vaiciulis, senior consulting technical efficient. If we get back to where we were professional at Wood Group Mustang’s autoa year ago and resources get tight, then mation and controls team. “Those compaautomation makes more sense. Automation nies say, ‘We know times are tough, but we projects related to safety and regulatory comstill have to execute this project because it pliance are always going on, but the ones affects other areas of our fields.’ Everything related to improving efficiency will not lead is tied together, and if you change one piece, the resurgence of this industry. It will lag it affects other pieces, and if you upgrade somewhat depending on the company and one site, you need to upgrade other sites specific situation.” too, because you can’t just do it halfway.” Automation to the rescue? Conventional wisdom states, “When the going gets tough, the tough automate.” Well, perhaps, but it isn’t always so simple. Automation requires investment and when times are tough, there might not be a lot of extra money available. As the first article OG26 • AUGUST 2015
OIL&GAS ENGINEERING
From cap-ex to op-ex When capital for investment projects dries up, companies move their activity to smaller-scale operational projects, where they hope to realize higher production and lower costs. Such has been the case during this downturn. “In the general
business environment, we have seen a move from cap-ex to op-ex focus,” said Darren Doige, director of onshore oil and gas marketing and business development for Emerson Process Management. “A year or 18 months ago, the primary driver was to bring new wells online as fast as possible and get them connected to the market. That urgency has completely gone away, at least in North America. The Middle East is still going strong, but in the U.S. there is a move to op-ex focus. Operating engineers are now focused on existing wells and maximizing the production from them. They’re also looking for ways to keep production costs and lifting costs as low as possible to maintain the profitability of the limited revenue stream. Operators are willing to listen or complete automation projects when they have immediate impact toward increasing production or decreasing operating costs.” Overall, the oil and gas industry is famous, or perhaps notorious, for being slow to adopt new technologies. Fracking was an exception because it was adopted almost overnight, but more mundane technologies can take a long time. Production companies and their investors are looking at projects very carefully trying to see beyond the current situation–aware low prices could persist. That makes for a tricky analysis. When prices recover While nobody can predict the price of oil over the next couple years, the consensus is we have seen the bottom of the curve. It may not shoot back up right away, but it shouldn’t go down any further. Maybe that’s wishful thinking, but many seem to be subscribing to the idea. If oil does begin to creep back to $70 or $80 per barrel, what is likely to happen? Automation projects should begin to move again, and they may look different than they did in 2013 or earlier. Operating companies have learned lessons about standardization that they will use going forward. “The automation industry, across the board, is trying to make everything simpler,” said Vaiciulis. “In oil production, they try to reduce the engineering cost by standardizing Ethernet-based technology and by putting the remote I/O
on the equipment skid. It must be plug-andplay. If a customer asks, ‘We’re putting in a 16-well test manifold, and we’re buying two test separators and one production separator, what PLC equipment do I need?’ I can say, ‘You need a well-test enclosure, two test separator enclosures, and one production enclosure.’ That’s it. I just place the order and buy it. The vendor already has the design. It really becomes cookie cutter.” Operating companies have also realized that unconventional wells act differently and need different systems than in years past. Doige said that systems on older wells might be reconfigured over their life, but the schedule moves much faster now. “One thing that has caught the industry is the rapid decline curve with unconventional wells,” he said. “A traditional well starts off free-flowing, then you put it on gas lift, and later on an electrical submersible pump (ESP). When it’s really low, you put it on a sucker-rod pump. Traditionally, that might take 10 or 15 years. But in some unconventional fields like Eagle Ford, that’s happening within 12 to 18 months. That’s a lot of change to a well site in a short amount of time. A single remote terminal unit can now handle all of those conditions so you may need only one over the life of the well. The instrumentation can remain constant rather than having to change everything when you move from gas lift to ESP.” As producers consider a world after the oil slump when prices stabilize above $75 per barrel, resources will get tighter and cash will start flowing again. When that happens, investments in automation will return. As Honeywell’s Miller pointed out, “Automation plays a role in keeping operating costs low. Automating a well head means fewer trips by an operator. Companies that have such a philosophy will continue, but they will be selective. The resurgence of automation will likely lag in overall development, but it will play a stronger role as resources get tight and the move to make them more efficient, safer, and more flexible as those aspects are more highly valued, as they were just a year ago.” OG
industry ‘ The consensus is most of the conventional oil and gas in North America and much of the world has been found and
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extracted.
Peter Welander is a contributing content specialist for Oil & Gas Engineering. OIL&GAS ENGINEERING AUGUST 2015 • OG27
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