— Baldor-Reliance® explosion proof motors Certified safe solutions
When you specify a Baldor-Reliance explosion proof motor, you can trust it’s the right solution for hazardous locations. We are committed to making reliable motors that are readily available and perform efficiently throughout their entire lifecycle, without ever compromising safety. Reliable. Flexible. Performance.
Baldor-Reliance® explosion proof motors Corrosion resistant permanently attached stainless steel nameplate. Frame optimized for maximum cooling, efficiency, noise and safety Laced and varnished stator winding to prevent movement of wires and extend motor life Robust Super-E premium efficiency designs to maximize energy savings in industrial applications Rotor coated to prevent corrosion and increase reliability
Variety of seal and flame path designs provide a safe, and reliable custom solution to meet most applications
Wide variety of shaft grounding solutions available to increase bearing life
Potted leads permanently seal the frame and connections for safety and contaminants Multiple lead outlet solutions available for convenient and safe access to auxiliary leads
Inverter Duty ratings allow for flexible operation in demanding applications and meet NEMA MG1 Part 31.4.4.2
Oversize conduit box for easier connection and UL certified for safety Dual mounting holes provide flexible installation. Making motor change out easy and efficient
UL Listed drains are standard on motors going into high humidity applications
Chicago, IL
soon
Shelby, NC Gainesville, GA Athens, GA Atlanta, GA Columbus, MS Westville, OK
Ozark, AR
Fort Smith, AR
Manufacturing locations: Fort Smith, AR; Ozark, AR; Athens, GA; Gainesville, GA; Columbus MS; Shelby, NC; Westville, OK Modex centers: Fort Smith, AR; Atlanta, GA; Chicago, IL
479-646-4711 baldor.abb.com
Standard heavy duty cast iron designs for optimal performance. Lighter steel band designs available to help reduce weight and better suit the application
Engineering is personal.
So is the way you use information.
CFE Media delivers a world of knowledge to you.
Personally.
To do your job better each day, you need a trusted source of information: CFE Media — Content for Engineers CFE Media is home to four of the most trusted names in the business:
delivers a wide array of strategies and solutions to help control system designers create a more efficient process.
Visit www.controleng.com serves engineering professionals in the oil and gas industry with expert content on new technology, products and processes. provides the latest knowledge on commercial and institutional facility construction and management.
Visit www.csemag.com
Visit www.oilandgaseng.com
delivers a plant-floor knowledge and expertise to help manufacturers operate smarter, safer and more efficiently.
Visit www.plantengineering.com
Plantwide Condition Monitoring Proactive. Powerful. Secure. We understand oil & gas operations. With 60 years of experience and proven customer successes, the unique challenges of oil & gas technologies are clear to us. Clarity is something we also bring to our oil & gas customers, spanning refineries, LNG and Offshore operations. Our connected condition monitoring platform, System 1 is the operational backbone that proactively monitors asset health, allowing our customers to achieve smarter uptime and unparalleled clarity while mitigating risk. System 1 can be paired with the industry’s first intrinsically cybersecure, next gen condition monitoring system, Orbit 60, which provides more channels and more processing power in half the size, ideally-suited for space constrained applications.
At Bently Nevada, our mission is helping oil and gas companies intelligently accelerate their digital transformation journey.
Contact us at www.bently.com
CONNECT Establish unified platform Mitigate risks + vulnerabilities ANALYZE Integrate performance insights Leverage expertise VISUALIZE Remove blind spots Achieve holistic view
Offering CLASS 150 CLASS 300 AND
FLANGES to the ASTM A961 Standard
Weldy says:
This is what REAL normalization looks like. weldbend.com
COMMENT
3010 HIGHLAND PARKWAY, STE. 325 DOWNERS GROVE, IL 60515 630-571-4070, FAX 630-214-4504
CONTENT SPECIALISTS/EDITORIAL KEVIN PARKER, Editor 630-890-9682, KParker@CFEMedia.com KATIE SPAIN NAREL, Art Director KSpain@CFEMedia.com
PUBLICATION SERVICES JIM LANGHENRY, Co-Founder & Publisher JLanghenry@CFEMedia.com STEVE ROURKE, Co-Founder SRourke@CFEMedia.com AMANDA PELLICCIONE, Director of Research APelliccione@CFEMedia.com PAUL BROUCH, Director of Operations PBrouch@CFEMedia.com CHRIS VAVRA, Production Editor CVavra@CFEMedia.com MICHAEL ROTZ, Print Production Manager 717-766-0211, Fax: 717-506-7238 mike.rotz@frycomm.com MARIA BARTELL, Account Director, Infogroup Targeting Solutions 847-378-2275, maria.bartell@infogroup.com RICK ELLIS, Oil & Gas Engineering Project Manager, Audience Management Director 303-246-1250, REllis@CFEMedia.com LETTERS TO THE EDITOR Please e-mail your opinions to KParker@CFEMedia.com INFORMATION For a Media Kit or Editorial Calendar, e-mail Susie Bak at SBak@CFEMedia.com REPRINTS For custom reprints or electronic usage, contact: Shelby Pelton, Wright’s Media 281-419-5725 x138, cfemedia@wrightsmedia.com MAILING ADDRESS CHANGES Please e-mail your changes to customerservice@CFEMedia.com
PUBLICATION SALES JUDY PINSEL, National Sales 3010 Highland Parkway, Ste. 325 Downers Grove, IL 60515
JPinsel@CFEMedia.com 847-624-8418 Fax 630-214-4504
4 • APRIL 2020 OIL&GAS ENGINEERING
Notes on HTE-based corrosion inhibition
H
igh throughput experimentation (HTE) allows execution of large numbers of experiments to be conducted in parallel. It is widely used in the pharmaceutical industry for drug discovery. In 2019, Clariant, a Swiss specialty chemicals company, opened its HTE laboratory in Houston, Texas to advance oil & gas research and application development for the oil & gas industry. The lab is part of a Clariant initiative to expand HTE capabilities globally. The technique’s efficacy relies on automated instrumentation and robots, specialized software tools, miniaturization, intelligent design and enhanced analytics. Clariant believes its use of HTE in formulating custom corrosion control solutions is unique.
Considerations involved Well operators make choices when controlling corrosion. Most often, low-grade carbon steel pipes transport fluids and gases rather than expensive alloys. Inhibitors prevent corrosive acid attack caused by the presence of dissolved CO2 and H2S gases in hydrocarbon or produced water flow. Corrosion inhibitors are formulated from precise ratios of from three to seven ingredients. Small formulation changes result in large changes in inhibitor application effectiveness. The recipe of a corrosion inhibitor likewise varies depending on specific conditions of temperature, pressure, salinity and composition of the produced water and hydrocarbon. The HTE lab’s purpose is to rapidly and accurately screen the most effective inhibitor formulations for the application. It’s necessary to understand the prevalent system conditions and to mimic in the laboratory the corrosion environment found in the field. This includes metallurgy involved, temperatures and pressures the hydrocarbons travel at and even pipe-run lengths. Design of experiments moderates the testing required. Automation executes many experiments simultaneously. Miniaturization enables smaller sample sizes, improves
KEVIN PARKER EDITOR
sustainability efforts during test phases and proves useful when pre-production samples are in short supply. A broad spectrum of potential treatments is looked at, since it’s not always possible to change the inhibitor’s chemical formulation. Data replaces intuition Classical corrosion testing is done manually and serially, grounded in industry derived standards. Based on experience, corrosion industry veterans specified formulation ranges as a place to start. Clariant takes this to the next level, digitalizing formulation efforts while institutionalizing this data, enabling instant access to the know-how. Clariant’s HTE lab has two aspects: 1) robotic formulation is concerned with basic chemistry and uses fundamental physical properties as a proxy for corrosion. 2) Through detailed application testing, performed in accordance with industry standards, the HTE method takes these formulations and conducts electro-chemical and gravimetric testing. In a nutshell, the HTE lab automates choosing a formulation range. Then, using autoclaves or other means, the exact, best formulation is specified. While product performance is important, it’s relative to the production environment. For deep subsea, best-in-class product performance is critical. HTE identifies the best of the best corrosion inhibitor. Oil production in the Permian basin operates under different parameters. Budget and formulation must be balanced between costs and performance level required. The HTE platform is flexible to pinpoint best-in-class cost-performance. Now, more than ever, innovation, agility, and cutting-edge technology are vital levers to ensuring oil & gas industry viability. OG
I NSIDE
Cover image courtesy: Clariant
EDITOR’S COMMENT 4
Notes on HTE-based corrosion inhibition 8
FEATURES 6
The role of the engineer in troubled times Survey results indicate concern, contingency planning
8
Flanges recall puts U.S. pipelines integrity in doubt Unanimous verdict returned in favor of the plaintiffs
10
Technology provides greater insight into produced water Multiphase fraction and conductivity meter offers a commercially viable alternative to well testing
12
12
Eliminate arc flash hazards upfront Safe work practices and PPE significantly decreased U.S. workplace electrical fatalities
16
Intelligent edge computing at the wellhead improves performance The digital wellhead promises efficiency and productivity increases for hundreds of thousands of wells across the U.S.
19
The impact of digitalization on the oil & gas industry An interview with Bently Nevada’s Terry Knight
16 OIL&GAS ENGINEERING APRIL 2020 • 5
CORONAVIRUS PANDEMIC
The role of the engineer in troubled times Survey results indicate concern, contingency planning By Kevin Parker
T
he most general definition of “engineer” in Webster’s dictionary is “a person who carries through an enterprise through skillful or artful contrivance.” It has been suggested that engineers have an important role to play in defeating the Coronavirus pandemic. Think about it. If this were Gilligan’s Island, it would be to the professor and not the skipper that we would turn to for guidance. For a better, and less facetious, model of what must happen we can look at World War II. The historian Paul Kennedy’s book, “Engineers of Victory,” examines five case studies that illuminate how skillful, artful contrivance was used to solve specific challenges related to defeating the Axis powers. “The book’s potential transferability to large nonmilitary organizations will seem obvious,” says Kennedy. Instead, on our Google News pages, we read stories about the Chinese building hospitals in days and the south Koreans use 3-D printing to crank out respirators. Closer to home, the story is about pinpointing where in the supply chain that shipment of personal protective equipment is stranded. The takeaway must be that manufacturing must come back to the United States, which can’t remain captive to global supply chains. Oil & gas specific For the oil & gas industry, the Coronavirus is a double whammy. Not only are steep demand drops anticipated, but the demand loss is being manipulated to attack the viability of shale-based oil & gas production. Events are moving fast, but include the following. The White House promised to bolster oil prices by filling up the Strategic Petroleum Preserve. Doing so would cost $2.6 billion. The International Energy Agency (IEA) on March 16 said that decline in transport, industrial and commercial activity points to a drop in global oil demand of as much as 2.5 million barrels a day for the first quarter, compared to the same quarter last year. On the morning of March 17, Brent crude oil was trading at $29.91 a barrel. U.S. shale producers need a price of at least $45 a barrel to remain viable.
6 • APRIL 2020 OIL&GAS ENGINEERING
Russia and Saudi Arabia refuse to cut production. Russia says it can maintain operations at $30 per barrel for a decade. The IEA says developing countries dependent on oil production will see a 50% to 85% fall in petroleum revenues. In the last industry bust, Texas lost more than 103,000 jobs and only 36,000 came back in the period from 2016 to 2019. So far, at least seven U.S. independent producers have announced spending cuts. What engineers think Oil & Gas Engineering is published by CFE Media & Technology, which also publishes Plant Engineering and Control Engineering. CFE is an acronym for “content for engineers.” CFE Media is surveying its readership to gauge the more immediate impacts of the new environment. Top actions being taken by the respondents’ companies because of coronavirus include the following. • Eliminating travel • Delaying or eliminating hiring • Adding supply chain contingencies, including secondary sources • Delaying or eliminating investments • Mandating work from home • Adding new manufacturing capabilities to fill supply chain gaps • Increasing production of relevant products to meet increased demand. About half of respondents said their company is having supply chain problems. Eight percent said they were having severe problems and 40% minor problems. Finally, respondents were asked, what strategies should the U.S. government review to help address this type of situation in the future? Top responses included incentivizing re-shoring of key manufacturing segments back to the U.S. and doing more to promote manufacturing automation where production can be completed with minimum operator involvement. OG Kevin Parker is the editor for Oil & Gas Engineering.
INHERENT FR PROTECTION. MEETS UNRIVALED COMFORT. A groundbreaking introduction from the leaders in FR fabric, Westex Synergy® Pro delivers maximum comfort from inherent FR protection. Exceptionally soft with superior color uniformity, this aramid is designed to maintain its remarkably professional appearance even after repeated washes. So when it comes to keeping your crew confident and entirely focused on the job at hand, you can trust Westex Synergy® Pro won’t compromise. // NFPA® 2112 Certified // 4.5 oz/yd2 - 34.16% Body Burn // 6.0oz/yd2 - 20.76% Body Burn // NFPA 70E® Cat 1 Compliant // Superior Color Uniformity // Exceptionally Soft // Guaranteed FR for the Life of the Garment
Learn more about how Westex Synergy® Pro delivers best-in-class comfort and protection against thermal hazards.
WESTEX.COM/OG
| 864.571.2110
Westex®, Milliken® and Synergy® Pro are registered trademarks of Milliken & Co. NFPA® 2112 and NFPA 70E® are registered trademarks of the National Fire Protection Association.
METALLURGY & THE MIDSTREAM
Flanges recall puts U.S. pipelines’ integrity in doubt Unanimous verdict returned in favor of the plaintiffs By Kevin Parker
I
n the culmination of a lengthy period of litigation, in February, Judge Andrew S. Hanen of the United States District Court for the Southern District of Texas, issued a permanent injunction and ordered a recall of flanges made by the Spanish company, Ulma Forja and its U.S. subsidiary, Ulma Piping. The Court found that Ulma, which furnishes flanges for use in American pipelines, refineries and chemical plants, “intended to deceive customers by mislabeling the flanges.” The ruling followed a jury verdict in favor of two American flange manufacturers, Boltex and Weldbend, which in 2017 had filed a lawsuit alleging that Ulma falsely claimed that it normalized its flanges in accordance with ASTM A105 standards. The question now is what, if anything, happens to the over 3.7 million flanges sold in the U.S. by the defendants since about 1998? The lawsuit filed by Boltex and Weldbend alleged Ulma deliberately stamped these flanges “A105N,” issued documentation with each flange stating they had undergone the normalization process specified by the ASTM and shipped the flanges into the U.S. for use in pipelines — all when testing showed the flanges were not normalized. The verdict delivered In late September 2019, the Texas federal jury, after deliberating for less than a day, returned with a unanimous verdict in favor of plaintiffs. They also found that Ulma Piping owed roughly $31 million to the American pipe makers for undercutting their business by falsely advertising its oil pipeline parts as being strengthened by heat treatment. “American companies like Weldbend and Boltex can compete with anyone in the world on a fair and level playing field,” said James Coulas Jr., president of Weldbend. Flanges are a key part of pipeline systems, and defects in them can lead to catastrophic
8 • APRIL 2020 OIL&GAS ENGINEERING
failure. The normalizing heat treatment at issue makes a metal more ductile and tough following its subjection to thermal or mechanical hardening processes. The process of heating, followed by slow cooling, alters the metal’s microstructure, which in turn reduces hardness while increasing ductility. Ductility is the ability of a material to deform plastically without fracturing. Carbon steel can be normalized after it is cold rolled to reduce the brittleness caused by work hardening. While reducing the total amount of damages owed in the suit, in ordering the permanent injunction, Judge Hanen stated that “an injunction would greatly benefit the public,” and that “mislabeling the qualities and characteristics of a product like the flanges in question, which are used throughout the petroleum industry, is a dangerous practice.” He added that the “public deserves truthful product information especially on products as critical as these flanges potentially are.” What’s at risk? The ruling also ordered Ulma to “recall any product which purports to be normalized,” which has not been normalized per ASTM international standards. “Ulma’s intentional acts and cover-up regarding their substandard flanges were outrageous,” Coulas said. “We remain extremely concerned about the more than 3.7 million substandard flanges — valued over $100 million — that Ulma sold into the United States. Engineers design refineries, pipelines, pressure vessels and other piping systems based on the product fully complying with the standard.” Judge Hanen’s order permanently enjoins Ulma from manufacturing, selling or otherwise distributing, directly or indirectly through distributors, any flange that is marked, engraved, advertised or labeled as complying with ATSM A105 and ATSM
A105N or as being normalized, that does not comply with ASTM standards. Furthermore, according to the court’s ruling, Ulma distributors should recall any product that purports to be normalized or to be ASTM A105 or ASTM A105N compliant that has not been normalized according to ASTM A961 or ASTM A941. Recalling those flanges may be avoided if they relabel/rebrand or otherwise redesignate by some means that is either actually on the flange or accompanies the flange in question so they accurately reflect that they have not been normalized or are not compliant with the standards set out in ASTM A105. The U.S. market is the world’s largest for oil & gas industry materials. Many foreign companies looking to enter these markets almost invariably do so by pricing themselves below already competitive domestic prices. The question must always be, what steps were taken, or not taken, to allow them to profitably do so? OG
Figure 1: Flanges are a key part of pipeline sys-
Kevin Parker is the editor of Oil & Gas Engineering.
tems. The normalizing heat treatment makes a metal more ductile and tough following its subjection to thermal or mechanical hardening processes. Image courtesy: CFE Media
We Make Valve Automation Easy!
FireChek
®
FM Fire-Safe Series
Dedicated Thermal Shutdown for Manual Valves
Adds Thermal Shutdown Function to Any Spring Return Actuator
Find Out More at:
ESD Series
Actuated Valves with Integral FireChek Thermal Shutdown
Or Call Us at:
1-800-899-0553
PRODUCED WATER MANAGEMENT
Technology provides greater insight into produced water Multiphase fraction and conductivity meter offers a commercially viable alternative to traditional well testing By Finn Erik Mohn Berge
Figure 1: By providing full fraction measurements of different well phases, the high-frequency magnetic field technique is the equivalent of a multi-phase fraction meter. All figures courtesy: Hammertech
R
ising water cuts and a broad range of well and field conditions are becoming increasingly prevalent in oil & gas operations today, particularly with older fields. As is well known, water cut is the ratio of water produced to total fluid produced. For example, a well that makes 50 barrels of oil per day and 150 barrels of water a day has a water cut of 150/50+150 = 75%. According to research analysts, IFP Energies Nouvelles (IFPEN), 300 million barrels of water a day are expected to be produced by 2020, an increase of 20% from 2008. Produced water, however, can be a major inconvenience and cost to operators, reducing pressure in the reservoir as well as production facility capacity. Operators must dispose of the water by discharging it into the environment or by re-injecting into the reservoir. There is increased pressure on operators to measure water production and water salinity in real-time. This can play a vital role in ensuring that water doesn’t gather in pipelines and inhibit oil production, that re-injected water is used to its full potential, and that threats to production from water salinity are pre-empted. Yet, managing water production is complex, involving many disciplines and highly trained and specialized engineers. Furthermore, identifying the source of the water production, the well, and ultimately the specific water producing zone in the well, can be time consuming.
10 • APRIL 2020 OIL&GAS ENGINEERING
When it comes to choosing a technology that can trend water behavior and deliver on water production and water salinity, operators often face two different but unsatisfying choices. One option is using low-cost water cut meters that come with significant data gaps in that they only provide information in water and oil rather than in the multiphase flow. The other is use of more complex multiphase meters. While providing comprehensive multiphase flow information and accurately characterizing flow regimes, such meters are often cumbersome, expensive, and require considerable maintenance with the need to input pressure, temperature and volume (PVT) information. It is economically infeasible to deploy one multiphase meter on each well. In short, there seems to be a significant gap when it comes to accurately measuring real-time water content and salinity in multiphase flow. That is changing. Full fraction measurements Hammertech recently introduced a multiphase fraction and conductivity meter that provides direct, robust and cost-efficient multiphase fraction (% water, oil & gas) and water conductivity detection. The meter has gone through a series of testing and installations, demonstrating uncertainty specifications of water fraction and waterin-liquid (WLR) at ± 3% absolute, and conductivity (salinity) at ± 0.5 Siemens/meter. The meter provides full fraction measurements of the different phases of the well, including water fraction (hold-up), water-in-liquid ratio (WLR) and gas fraction measurement, as well as salinity measurement. In this way, the meter becomes a multiphase fraction meter as per figure 1. The detection principle around the meter is called high-frequency magnetic field technique (HFMFT), a unique variant of the eddy current measurement technique where an eddy current creates a magnetic field that opposes the change in the magnetic field that created it (see figure 2).
The eddy currents then react back on the source of the magnetic field (Lenz’s law). When a conductor — in this case the water — is exposed to a varying magnetic field, eddy currents will be induced in the water. These eddy currents induce a magnetic field which opposes the original field and power is lost due to the currents. The loss of power is proportional to the water content, with large amounts of water resulting in large amounts of energy loss and small amounts of water resulting in small amounts of energy loss. The conductivity (salinity) of the water will also affect energy loss. The meter then measures via dedicated probes the conductivity (and temperature) of the water to differentiate between energy loss caused by the amount of water and energy loss caused by levels of conductivity. Conductivity is then calculated for the water in multiphase flow based on the measured complex permittivity of the water. Complete overview What are the benefits of the new meter and what gap is being addressed in the market? For operators the key benefit is a complete overview of the field through the online trending of water content in multiphase flow. By measuring water fractions, the operator can trend the water level, and if there are no changes (or a slight steady increase), the well is stable and producing as expected. In such cases, expensive well testing crews aren’t required. As soon as there is a change in the water level, however (as detected by the meter), the operator can dispatch a well testing crew to investigate, pinpointing problematic wells (such as when there is excessive water production from the wellhead) and instigating remedial action. Furthermore, since the salinity of the water is detected, the operator can identify if the water production is a result of too hard water injection. Reduced CAPEX and OPEX Another benefit is reduced capital expenditure (CAPEX) and operating expenditure (OPEX) with the costs of the meter equal to just two to three well tests, allowing the operator to access online measurements from each production well. Well test savings combined with increased oil production due to reduced water production can result in $29 million in added value, based on a field of 200 wells with an average production of 500 bbl/d, and a conservative oil price of $55 a barrel.
The meter is also cost-effective compared to more complex multiphase meter deployments. According to our estimates, replacing a multiphase meter per well on a five-well configuration, installing each well with the new technology meter and then having just a multiphase meter on the manifold can lead to savings of up to $500,000. For a typical field with 50 wells, the savings are thus more than $5 million. There is also low OPEX with the small, lightweight (27 kg) meter. It is a simple, non-intrusive “plug-and-play” solution with no installation support required, besides being easy to integrate with existing production operations. There are also low power requirements (ca 10 W vs 20+ W for a multi-phase flow meter), and no sensors in contact with the process, which otherwise might lead to potential contamination and inaccurate measurements. We also conservatively estimate an increase of 0.5% in production following from use of the meter. One final benefit of the meter relates to PVT data. Multiphase meters rely on the accurate input of PVT data and other fluid parameters to achieve the specifications provided by vendors. This can be a challenging process, especially as such variables are likely to change significantly over the lifetime of the reservoir as fluid and process conditions change. With the multiphase fraction and conductivity meter, however, there is no complicated set up or configurations and no reliance on PVT data.
Figure 2: Using a highfrequency magnetic field technique, an eddy current creates a magnetic field that opposes the change in the magnetic field that created it.
A Viable alternative As operators continue to wrestle with the challenges of produced water, the multiphase fraction and conductivity meter has come along at just the right time — offering a commercially viable alternative to traditional well testing, water cut and multiphase meter operations, and generating real-time water content and water conductivity measurements. OG Finn Erik Mohn Berge is a company vice president with Hammertech AS. OIL&GAS ENGINEERING APRIL 2020 • 11
SAFETY & TRAINING
Eliminate arc flash hazards upfront Safe work practices and PPE have significantly decreased U.S. workplace electrical fatalities
By Tim Howd
Figure 1: An arc flash (AF) is a release of incident (thermal) energy from an electric fault. Source: NFPA 70E Handbook, Exhibit 100.4. All graphics courtesy: Burns McDonnell
W
orking in the oil & gas industry is inherently hazardous. Whether dealing with crude oil, natural gas liquids (NGLs), refined products or electricity, safety must be the priority. Increased awareness of arc flash requires a new focus on prevention. In the past, safety management for electrical workers focused primarily on electric shock, electrocution and fire from electrical systems. Over the past two decades, however, the emphasis has expanded to include hazards associated with electrical arc flashes. As electrical systems become larger and more complex, there has been a dramatic increase in exposure to electrical and arc-flash hazards. Greater awareness of these hazards has led to the development of better tools and technologies to quantify and mitigate them. In addition, NFPA 70E: Standard for Electrical Safety in the Workplace provides guidelines for performing risk assessments to determine the severity of the hazard and identify the proper work practices and personal protective equipment (PPE) required for interacting with electrical equipment. This focus on mitigating the impacts of arc flash events using safe work practices and PPE has significantly decreased the number of workplace electrical fatalities in the United States. Nonetheless, the fatality rate from electrical contact or electrical discharge remains 3.8 times higher in the U.S. than in the United Kingdom (Floyd & Floyd, “Bringing Attention to Residual Risk: Psychology of Warning, Administrative Controls and PPE,” p. 96). The lower rate in the U.K. is likely due to decades of emphasis on risk assessments and prevention through design by applying the hierarchy of controls. Today, we need to adopt a similar approach — one that focuses on
12 • APRIL 2020 OIL&GAS ENGINEERING
eliminating or reducing the severity of the arc flash hazard itself, rather than simply mitigating its impacts on personnel. Integrating arc flash prevention from the earliest stages of project design is the solution. What is an arc flash? An arc flash is a release of incident, or thermal, energy from an electric arc fault. It occurs when electric current flows through an air gap between conductors. It is most often caused by accidental contact between tools and electrified surfaces. The probability of an arc flash also depends on numerous variables that differ from installation to installation, including equipment condition, contaminants in the air and exposure to moisture or animals. Though arc flash incidents are less common than many other incidents — both electrical and nonelectrical — they are much more likely to cause severe injury or even death. An arc flash typically lasts for a short duration but may generate temperatures as high as 35,000°F and a blast with a force of up to 1,000 pounds. The intense heat of an arc flash can cause severe burns, while the arc blast may knock the victim backward, destroy the electrical box or other equipment, and send shrapnel flying. According to Electrical Safety Foundation International (ESFI), in 2016 there were 154 electrical fatalities and 1,640 nonfatal electrical injuries in the workplace, with most occurring in construction. Statistics also indicate workers are more likely to be injured if they are less experienced or are working long hours, due to the human performance factor. Even so, current risk assessment factors require human interaction to mitigate the hazard. Risk assessment While it isn’t always possible to eliminate all electrical hazards or even substitute a lesser hazard, engineering controls that do not require human interaction can be used to bring the hazards to an acceptable level of risk. We all engage in risk assessment every day, and everyone’s risk tolerance is different.
Whether we’re making decisions about driving a car, skydiving or visiting another country, we weigh the severity and probability of the risk against the outcome. If the risk is too high, it must be reduced to an acceptable level. For example, speed limits and seat belt laws were introduced to help reduce the overall risk of car travel, and they have been largely successful. According to the National Highway Traffic Safety Administration (NHTSA), the annual rate of traffic fatalities has declined for decades. It’s important to note that these safety practices reduce the hazard by decreasing the severity of a potential accident, but do not prevent the accident in the first place. These practices, which are considered lower-order controls, also require human action to put on the seat belt or obey the speed limit. In the auto industry, new higher-order engineering controls — like blind spot monitoring, adaptive cruise control, lane departure warnings, automatic braking and applications that prevent texting while driving — are being introduced. Rather than simply reducing the severity of accidents, these engineering controls help prevent accidents from occurring. They are much more effective at reducing overall risk, and they don’t require human action to implement. An increase in the application of such higher order controls is needed in the oil & gas industry as well.
Elimination, substitution and engineering controls are considered higher-order controls and are most effective at reducing arc flash risk. They are implemented during the design phase and do not require human intervention during work tasks. The remaining lower-order controls have been found to be far less effective, in large part because they require real-time knowledge, consistent attention and decisive action from both supervisors and workers. Since ANSI Z10 was published in 2005, safety management experts have encouraged the disciplined application of higher-order controls to reduce electrical hazards. But adoption of this approach has been inconsistent. With publication of NFPA 70E 2018, which added sections referencing ANSI Z10 and hierarchy of controls, this is beginning to change. As the oil & gas industry has started paying closer attention to the efficacy of various controls, it has become apparent that although work practices and PPE are good tools, they are subject to human error. The better option is prevention through design.
Mitigating risk Every terminal and pipeline project should include a risk assessment, or process hazard analysis (PHA). The PHA will: • Identify who or what may be at risk and the potential cost of that risk • Determine if existing risk reduction measures are adequate or if more needs to be done • Prioritize risk reduction activities based on the hierarchy of controls • Address risk over time.
Prevention by design Too often, oil & gas projects are designed and built before arc flash prevention is considered. This is understandable, since accurate, final incident energy (arc flash hazard) calculations require detailed and precise information that often is available only at the end of a project’s design or even after construction. However, this is not the most effective approach. Systems created in this way frequently may require significant modification to equipment or operating limitations to address the arc flash hazard. Unfortunately, the ability to positively impact the system currently is very limited. From both a cost and effectiveness standpoint, it is far better to implement arc flash hazard preventions during the design phase of the project. Each project and facility has unique components that contribute to the risk associated
Once a hazard is identified, the owner must determine what level of risk is tolerable. If the risk is acceptable, no action is required. If it is unacceptable, either the probability or the severity, or both, must be reduced using the hierarchy of controls.
Figure 2: The hierarchy of controls. Source: ANSI Z10: Occupational Health and Management Systems
OIL&GAS ENGINEERING APRIL 2020 • 13
SAFETY & TRAINING with electrical equipment, but all projects benefit from considering arc flash prevention during the design phase. Figure 3 illustrates how the different systems play a role in hazard prevention or mitigation. First, every electrical system is designed to operate within a range. A basic electrical protection system is designed to keep the system operating within that range through overload and short-circuit protection. As the system begins to age, preventative maintenance is needed both to keep the system operating as designed and to prevent contaminants, such as dust or deteriorating insulation, from increasing the likelihood of an electrical system incident. Active safety protection systems also can be used to prevent the hazard from becoming more severe, but they aren’t present in every electrical system. (Preventative maintenance and active safety protection systems are pieces that are missing far too often.) Other protective layers do not prevent electrical incidents, but simply mitigate the hazard. For example, arc-resistant equipment does not prevent the arc, but contains most of the energy and redirects it to a safe location. Similarly, PPE, safe work practices and emergency response reduce the impact of an incident, but do not decrease the chances of an event occurring. Optimizing safety The severity of an arc flash hazard depends on numerous variables, but short-circuit current, distance and time play an outsize role. When prevention starts during design, engineers can implement engineering controls to optimize the relationship between these factors. The short-circuit current for a given power system is dependent on system impedances and source fault currents. These values can only be influenced during the design process, when you’re identifying your sources, selecting your distribution equipment and sizing the transformers and cables. Early planning allows you to optimize these values and ultimately leads to hazard prevention. The distance between a worker and a hazard is a key variable in the calculation of the hazard’s severity, but it cannot easily be changed. Such distances are based on industry standards and equipment construction. However, engineering controls can be implemented to 14 • APRIL 2020 OIL&GAS ENGINEERING
keep workers away from equipment while still allowing them to perform many of their daily tasks. These include remote operation of breakers and switches, remote racking, remote diagnostic capability and sensors to identify issues or improve preventative maintenance. The severity of an arc flash hazard decreases when the exposure time is reduced. Exposure time is directly related to the clearing time of the protective devices, and this is where you can have the biggest impact on preventing the hazards of arc flash. Technologies such as differential relaying, zone-selective interlocking and active arc flash detection can drastically reduce the time it takes to recognize and clear a fault. The use of arc-resistant equipment also can reduce the severity of a hazard. Other measures The technologies described above can drastically reduce the risk of arc flash incidents. Yet even standard fuses, breakers or relaying can be optimized to minimize risk, if properly designed. For example, most arc flashes start as single line-to-ground faults. Therefore, the introduction of an impedance grounded system can eliminate arc flashes from ground faults, drastically reducing the probability of the event ever occurring. The probability of arc flash also can be reduced by allowing only qualified electrical workers to perform the work and by implementing a comprehensive preventative maintenance program. Most of these technologies are not new; still, because there is not always one technology that meets the needs of a given project, it is essential to identify and incorporate an effective solution early in the project. Final words Arc flash hazards have been a known problem in the oil & gas industry for years, and numerous strategies have been undertaken to mitigate the impacts of arc flash events. More recently, NFPA 70E 2018 has put new emphasis on eliminating arc flash hazards altogether using the hierarchy of controls. Effective arc flash prevention requires addressing the risk early, during the design stage of terminal and pipeline projects. The earlier preventative concepts are introduced into the project life cycle, the more effective they will be from both a safety and cost perspective.
A qualified partner should recognize that safe work cannot be performed if the initial design is unsafe. The qualified partner should have experience in design, construction and, most importantly, safety management systems. By bringing all types of arc hazard prevention experience under one roof, a qualified engineerprocure-construct (EPC) company allows oil and gas companies to eliminate the complications of working with multiple vendors. A cohesive team also efficiently integrates safety systems and anticipates potential errors, thereby enabling projects to be completed faster and on budget. Professional engineers can utilize their experience to incorporate sound engineering practices and engineering controls to minimize arc flash hazards and implement prevention through design. OG
mentation systems for liquid storage and distribution facilities in the oil & gas industry. Tim has a Bachelor of Science in electrical engineering from the University of Missouri-Columbia.
Figure 3: Layers of protection.
Tim Howd, PE, is an electrical and instrumentation engineer at Burns & McDonnell specializing in the design and analysis of electrical and instru-
EXPANSION JOINTS AND CHECK VALVES
Complete line of products suitable for a vast number of industries
WATER/WASTE WATER
MARINE
THE EXPANSION JOINT AND CHECK VALVE PEOPLE 209-943-6088 | procoproducts.com
HVAC
POWER GENERATION
OIL & GAS
Find our complete range of products at procoproducts.com
DIGITAL OILFIELD
Intelligent edge computing at the wellhead improves performance The digital wellhead promises efficiency and productivity increases for hundreds of thousands of wells across the U.S. By Jane Ren
T
ake any flight from Texas to California and you will fly over West Texas and New Mexico. A glance out the window will reveal a land pockmarked with a seemingly boundless patchwork of square sandy areas. What the eyes won’t discern from that height is that each one of those squares contains an oil wellhead. Welcome to the Permian Basin that supplies almost a third of the U.S. domestic crude oil. The oil fields in the basin contain tens of thousands of wells, and the number is growing every year. Over the past five years, more than 5,000 wells have been added to the inventory. Aside from the wells themselves there is little else in the region as far as infrastructure goes. Each of these wells is unmanned, and often, located in areas difficult to access. Despite these challenges, the wells need to be inspected for gas leaks and any structural damage, which can be a costly and time-consuming operation. Aside from the need to avoid falling foul of compliance or health and safety regulations, there is the matter of data. In modern oil production, data is vital for planning and assessment, and wellheads are a significant and abundant source of data that at present is mostly untapped. Although some of the newer wellheads may have smart digital sensors with built-in wireless communications, the vast majority are legacy installations with analog gauges. Even the new smart sensors require a technician to be near the site to download data to a handheld device. What is a digital wellhead? Operators are trying to digitalize these fields and wells so that they can detect all the important production parameters from a remote location. The answer is a digital wellhead that provides integrated functionality at
16 • APRIL 2020 OIL&GAS ENGINEERING
the edge. This will allow real-time and predictive analytics of wellhead integrity, well performance and environmental risk. The idea of the digital wellhead is to give it a brain, or more accurately, an edge computing device. The plan is to bring everything onto a level playing field. Whether the well instrumentation is analog or digital, we would like all the wellhead information to be available on the same platform even though it comes from different devices and vendors. That is the ultimate vision, but the most important thing is to achieve a digital wellhead regardless of whether it has remote connectivity, because there must be multipurpose computer intelligence on site. This will have a positive impact on three areas. The first is automation, the second is precision, and the third is prediction. These are the three big advantages that were not able to be achieved before we added edge intelligence. Delivering wellhead automation A typical example of efficacious use of automation is gas leak detection. This is a significant concern at wellheads, and even for abandoned wells where the operator is still liable for any leak from the structures. The challenge around gas detection without automation is that it always requires people to visit the site. These inspection teams will attend to the wellhead site with infrared sensors or cameras, move around the area and try and detect any possible gas leaks. These wellheads are remote. Travel is involved and inspections are infrequent. When the wellheads are visited, there is added risk related to health and safety. The idea behind having automation and intelligence at the wellhead is to be able to put gas sensors at the wellhead that can constantly monitor for any gas in the area. With
an automated drive and the sensor located on a rotating mount, it can turn in various directions controlled by the edge computer to remotely monitor conditions. This reduces the need for people to visit the site. There are a range of philosophies when it comes to digitalizing the wellhead, either through a device strategy or an edge strategy. One option would be to replace the dumb, analog sensor with a smart sensor that has embedded computing and communications capabilities. This can be expensive and often only delivers a point-to-point solution with the individual device providing its information in isolation. Aside from that lack of integration, this method can also be challenging to scale. Edge-based digitalization is about being open to the low-level sensors. The sensor can be dumb, but it is given intelligence by the edge computing device. You are adding intelligence to sensors via one computing device that can include gas detection, pressure or flow monitoring and even structural monitoring. Precision and prediction Precision at the digital wellhead is another benefit of edge computing. There are two ways you can detect any issues such as leaks or corrosion. One is to use a threshold-based anomaly such as pressure changes. With edge computing, detection can be more precise. On the market now are relatively low-cost gas detection sensors that can be attached to seams or seals between the flanges. These can detect even small leaks; however, it requires data processing at a high level to filter out the noise of the baseline fluctuation. The software needs to be able to look at trends and continuously compare the anomalies before it can confirm a leak. It is not a single point detection, and when you have edge computing resources there, that makes it much more feasible to do at the wellhead.
Another area is prediction, which encompasses two separate things. The first is incidents, whether there are a leak or pressure issues in the well. The second is risk factors. There being a risk factor does not mean there will be an incident. For example, there may be some structural changes at the flanges that are not bad enough to create an incident yet, or there may be heavy corrosion around the wellhead structure that could lead to a future leak. The prediction is derived by using the risk factor monitored to be able to derive the probability of a wellhead incident so the maintenance and inspection visits can be targeted, and condition based. So why would prediction require edge processing? One of the newer ways of monitoring corrosion or erosion of the wellhead is by using advanced, AI-based image analytics. It continuously monitors the changing patches of color on the pipes in a well structure as corrosion and erosion advance., Then it is able to integrate humidity and temperature at the well as part of an evaluation of risk. With all of the risk factors monitored and combined with their predictions, the algo-
The digital wellhead allows real-time and predictive analytics of wellhead integrity, well performance and environmental risk. Graphic courtesy: Atomiton
OIL&GAS ENGINEERING APRIL 2020 • 17
DIGITAL OILFIELD rithm determines which well could be more exposed to incidents or quality issues. This sort of prediction profile requires edge computing and is not something that can be done by a single sensor or device. Risk assessment with predictive analytics creates digital wellheads. Additional benefits There are two types of resources that cost money at the wellhead. The first is people, including the wellhead maintenance crews that visit the well sites. Then there is the cost of any regulatory infractions. By using intelligence at the wellhead these visits can be dramatically reduced, not down to zero, but they would become condition-based as opposed to schedule-based. Every well is different and can be exposed to various risk factors, so optimizing the schedule for individual well visits reduces the cost of inspections. There is also an additional, secondary effect of the digital wellhead, and that is the
increased data capturing and integrated processing. The reality is that there is more data generated at a wellhead than there is data data processed. Wellhead data is very valuable in monitoring and diagnosing the health of the well, the productivity of the well and quality of the well. You have to aggregate and analyze multiple wellhead data sources together in context, to be able to make better conclusions about the reservoir. Most of the digitalization efforts at wellheads are currently centered on creating digital data without being able to integrate this information to undertake analytics. By putting computing power at the wellhead, you are not only putting it at the edge but aggregating multiple edge devices into a center that can create more valuable intelligence on the reservoir and its longterm health and productivity. OG Jane Ren is the CEO and co-founder of Atomiton. Atomiton, founded in 2013 and headquartered in Santa Clara, CA., is an enterprise IoT software company.
SP5000X Series
Sunlight Readable Outdoor HMI for eXtreme Conditions Class 1 Div 2
800-289-9266 | PROFACE AMERICA.COM
IIoT in O&G
The impact of digitalization on the Oil & Gas industry An interview with Bently Nevada’s Terry Knight
T
erry Knight is president and CEO of Bently Nevada Corp., a Baker Hughes business, known for its condition monitoring software and associated hardware. As such, the company is deeply involved in the ongoing digitalization of the oil & gas industry. We recently caught up with Knight to get his perspectives on his company’s and the industry’s progress. Oil & Gas Engineering: How is digitalization impacting the oil and gas industry? Knight: As I meet with some of my key customers in the oil & gas industry, it’s clear that cash and cashflow have become more important in their investment decisions. This is where digitalization can have a big play. Whether upstream, midstream, or downstream, more and more plant operators are looking to implement digital technology which can help them manage their assets more efficiently and improve productivity and reliability in the long run. Now they are looking into technologies that can give them more plant visibility, more flexibility and quicker insight on how to manage their machines. This is where Bently Nevada, a Baker Hughes business, comes in. Bently Nevada is a world leader in condition monitoring and asset protection solutions, with more than 60 years of innovation. The technology we provide can give customers insights in to how their machines are operating. This then allows them to make smart decisions to optimize performance and diagnose problems quickly and efficiently and of course we can augment their own operators with our global services team. With Bently Nevada, we can enable customers to move from traditional practices of timebased maintenance to predictive maintenance. None of us want to see failures, so with the right solution being able to see or predict something is going to happen, it allows for a
safe shutdown versus a plant trip worse case or allows for detailed planning if not such an immediate concern. OGE: What are the benefits of edge computing and what does it mean for the industry? Knight: Today we already provide a complete solution with high-speed processing to give machinery protection, coupled with System 1 that can provide customers with analytics to make smart decisions. Orbit 60 takes it to the next level. First, Orbit 60 brings in the very latest technology and even faster processing which enables us to couple many systems together so customers really can have true synchronization of assets for the ability to make better fleet decisions. There are times when cloud-based analytics are fast enough to make fleet-wide decisions, but if a customer has a problem that is difficult to diagnose for a given asset and needs real-time analytics, Orbit 60 brings the ability for our customers to write their own code, download to Orbit 60 in our “Sandbox” and run their own diagnostics. OGE: Many automation and process-control suppliers embracing IIoT are learning that they must offer higher levels of services in support of their solutions — to educate the users on what the technology can do and how to use it. Has this been the case with Bently Nevada? Knight: Bently Nevada has been around for just over 60 years (hence the “60” in the name “Orbit 60”). We have been a trusted partner with many customers for many years, so we’ve been on a journey together as technology has improved. For me this is just the next step in the journey. It is a critical and potentially a more dramatic step than some, but our deep domain expertise and our customers’ knowledge of how their plant and equipment works means we can work OIL&GAS ENGINEERING APRIL 2020 • 19
IIoT in O&G together and utilize the Industrial Internet to obtain even better insights, especially at the enterprise level with customers who may have many plants globally. OGE: How will best practices for asset protection and management evolve, with future advances in sensor technology, connectivity and analytics? Terry Knight is president and CEO of Bently Nevada, a Baker Hughes business and provider of condition monitoring solutions.
Knight: Future advances in sensor technology, connectivity and analytics will heighten the need for increased flexibility and visibility, and our newest products are excellent examples of how we are preparing for it. Orbit 60 series is our next-generation machinery protection and edge computing platform that is built on a fully distributable architecture and has the flexibility for future expansion. For customers who want to manage their assets at the plant-wide level, Orbit 60 series can help them create proactive maintenance and fleet management programs for maximum productivity and cost reduction. System 1 is the software platform that connects to Orbit 60 series and other Bently Nevada equipment to give full visibility of the plant — giving customers the complete picture of their plant and making it easier for them to make the right decision.
www.mrshims.com
Belt/Sheave Laser Alignment System New Green laser delivers these important benefits: ● Reduces Vibration ● Eliminates downtime and productions ● At an affordable price ● Visible indoors and Outdoors ● Brightness great for long distances
Mr. Shims
your answer to better alignment for rotating machinery
1-800-72-SHIMS (1-800-727-4467)
OGE: What’s unique about System 1 diagnostic software? Knight: For me this is simple. We first take the domain expertise we’ve developed over many years; we couple it with the learnings we find in working and helping our customers solve problems and build it in to System 1. We are always learning, so we release a couple of versions of System 1 each year to capture that new knowledge we’ve developed. Many customers I visit talk about an aging workforce and the lack of skills, so we see that customers with large dispersed fleets have adopted centralized monitoring centers so they can harness the skillsets they need in one location to support multiple sites. This fits right in our wheelhouse and our replication solution enables them to centralize. OGE: What makes vibration a key parameter in determining machine health? What type of advances are being made here? 20 • APRIL 2020 OIL&GAS ENGINEERING
Knight: Vibration is a key indicator in predictive maintenance, especially for rotating equipment, because early signs of machine failure can be detected through vibration. Other signs like smoke, heat, noise, and pressure changes come as the faults progress. Continuously monitoring vibration information against historic data gives customers confidence in the reliability and productivity of their machines. At Bently Nevada, we are always innovating and finding new ways to maximize value for our customers. This includes our sensor technology as well. We are researching ways to not only refine the detectability but also looking for alternative parameters we can measure with new technology — to give customers greater visibility and understanding of their machines. OGE: Will Baker Hughes’ joint venture with C3.ai eventually contribute to Bently Nevada’s use of that machine learning capability in its solutions? Knight: The Baker Hughes-C3.ai joint venture alliance is a huge milestone for the company, with more oil and gas operators looking for artificial intelligence and deep learning solutions to improve their productivity. At Bently Nevada, we are already actively leveraging decision support algorithms and an extensive collection of machine data to analyze and diagnose machine problems. With the integration of a powerful machine learning technology, we will be able to expand our capability to monitor and diagnose and to think more creatively about asset management for all of Baker Hughes’ customers. OGE: Of all the concepts and technologies being introduced into industrial enterprises, which interests you the most personally? Knight: We are certainly coming into an age where processing power, edge technology and cloud-based solutions mean we are entering into an exciting time for our industry. Bringing these different facets of advanced technology together helps customers solve complex problems, drive greater efficiency, and increase productivity. This is what excites me and the whole team at Bently Nevada and Baker Hughes. OG
High Throughput Experimentation
A FIRST FOR THE OIL & GAS INDUSTRY
Introducing High Throughput Experimentation (HTE), while used widely in other industries for years, we are the first company to adopt a dedicated, in-house HTE service for the Oil and Gas industry. Through differentiation and innovation, this new state-of-the-art fast response unit offers oil production customers optimized formulations, in a fast timeframe to meet their unique treatment requirements while providing new and sophisticated solutions. Developed to help reduce time to market for new products, our advanced HTE laboratory uses automated instrumentation, specialized software WWW.CLARIANT.COM/OIL
tools, and alternative research techniques to provide accelerated synthesis, formulation, application and testing unique to the Oil and Gas Industry. Using standardized flexibility, the HTE methodology is able to identify the right solution, whether it is a best-in-class product performance or a best-inclass cost performance, depending on the operating environment. Learn more about Clariant’s unique approach in using HTE for application development.
We understand how you need to reduce complexities at your plant.
CLEAN PROCESS + CLEAR CLEAN PROGRESS PROCESS + CLEAR PROGRESS We understand how you need to reduce complexities at your plant.
You strengthen your plant’s safety, productivity and availability with innovations and resources.
You strengthen your plant‘s safety, productivity and availability with innovations and resources.
Prosonic Flow G 300 – Ultrasonic flowmeter redefines gas measurement • For raw and processed natural gas, coal seam gas, shale gas, gas mixtures, wet biogas and digester gas • Powerful process control thanks to pressure and temperaturecompensated values measured in real time • Advanced gas analysis functions for calculation of additional process variables, customer-specific gases or gas mixtures • Maximum reliability and robustness independent of the gas moisture
Do you want to learn more? www.us.endress.com/prosonic-flow-g300