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4 • FEBRUARY 2018
Not invented in Houston
T
he abrupt upturn in the fortunes of the U.S. oil & gas industry in recent months is being helped along by an innovation wave emanating from companies outside the oil & gas industry itself, whether they be makers of pumps, power systems, instrumentation, or IT-based automation. “It’s an exciting time in the oil & gas industry. The oil companies have streamlined their approach to be profitable despite higher costs and lower product prices. Best practices are being put in place and our work is part of that,” said Mark Thomas, oil & gas industry manager, Endress+Hauser. Endress+Hauser, Greenwood, Ind., began U.S. operations in 1970 and is one of the largest instrumentation companies in the country, specializing in flow, level, temperature, and analytical instrument production. The company recently announced partnerships with Angus Measurement Services, TechnipFMC, and Vector Controls to furnish solutions and services that support oil & gas industry digitization. Details are found in the news section of the issue. All the participants already work in oil & gas, but together they now are looking at, in the upstream, the whole production side of the wellpad, to tackle challenges the oil & gas companies bring to them. Take a step back For example, flow measurement in the separation process must accommodate crude oil, condensates, produced water, and natural or associated gas. In the hydrocarbon leg of the separator, the Coriolis flowmeter is replacing traditional mechanical type flowmeters. The Coriolis meter lacks moving parts and is easy to maintain. Coriolis meters can provide multiple parameters, including flow, density, and temperature, or even Net Oil, API gross, and net volume calculations, viscosity, and Reynolds number trending.
OIL&GAS ENGINEERING
KEVIN PARKER SENIOR CONTRIBUTING EDITOR
These features allow operators a better understanding of oil quality out of the separator, makes for a more efficient separator, and improves royalty owner allocation. The big picture is to think about all the industrial companies in the U.S. Northeast, Midwest, and on the West Coast that stand ready to contribute even more to the oil & gas industry’s ongoing success. Support is at hand for challenges that may be specific to a sedimentary basin such as the Permian or that may require automating some state-specific regulatory fine point. That’s a significant advantage compared to working offshore or in an exotic global region. Immense resources Besides being equipped with an industrial base capable of winning the last two world wars, the U.S. has Silicon Valley. It makes available to the oil & gas industry all its technologies, developed based on the immense resources provided by global consumer markets. A story in this month’s issue of Oil & Gas Engineering by veteran technology journalist Sidney Hill Jr. includes anecdotal evidence of growing analytics use in oil & gas fields. Several producers—including Anadarko Petroleum and Apache Corp.—shared their stories at the TIBCO Energy Forum. At Apache, analytics is one part of an IT infrastructure developed following some corporate soul searching in the wake of the industry downturn. “After the market shakeout, we had a new leadership team, and we looked at what we needed to do to come out of the downturn as a stronger company,” said Travis Osborne, Apache’s director of information management. OG
I NSIDE
Cover image courtesy: Endress+Hauser
FEATURES 6
6
Focus on power systems complements the bottom line Power factors, harmonics, fluctuations, and outages examined
9
Edge computing comes to the oil & gas industry
Image courtesy: Burns McDonnell
Forum bolsters producer’s confidence in technology-powered future
12
How slow-roll runout works in electric motors Vibration measurement a requirement in API motors
16
Prevent process safety incidents from occurring See what you inspect, and not what you expect
17
Hybrid cloud services support integration of operations
12 Image courtesy: Baldor
Secure, cloud-based solutions leverage on-demand scalability
NEWS 18
Alliance formed for provision of digital oilfield technology 18 Image courtesy: Roxar OIL&GAS ENGINEERING FEBRUARY 2018 • 5
ElEctrical powEr & procEss production
Focus on power systems complements the bottom line Power factors, harmonics, fluctuations, and outages examined By Mike Zakar
T
he reliability, resiliency, and near universal availability of electrical power is one of the United States’ greatest engineering achievements. Reports from the U.S. Department of Energy, the National Electric Reliability Corp. (NERC), and others typically place nationwide reliability at 99.97%. Nevertheless, economists estimate that loss of service averaging even 0.03% still costs the U.S. economy more than $100 billion annually. In refining and petrochemicals, electrical systems are the unsung heroes of plant profitability and operational efficiency. Telltale warning signs like poor power factors, voltage fluctuations, or harmonics distortions are often ignored. Until these systems verge on catastrophic failure, they attract scant capital investment. Service disruptions and failures “behind the meter,” i.e., within the industrial facility itself, cause a disproportionate share of economic losses. Plant downtime costs due to electrical system failures can be staggering when factoring in the costs of idle and non-productive staff in addition to lost production. Being without power for an entire day could mean the difference between profit and loss for an entire month. Facing a critical upgrade Kansas City, MO. based Burns & McDonnell recently completed an electrical system upgrade project for a major manufacturer of nylon intermediates. These intermediates are critical to production of high-end carpets. Plant output also includes nylon fiber, resins, and other specialty products. The 50-plus-year-old facility was productive and profitable, yet, in recent years, experienced increasing power system issues. The problems culminated in a major outage and extended shutdown resulting in millions of dollars of lost production. This incident convinced management it was time to invest.
6 • FEBRUARY 2018
OIL&GAS ENGINEERING
A team from Burns & McDonnell Power Distribution & Controls (PDC) had studied the facility prior to the outage. A master plan pinpointed needed system improvements to address reliability, safety, and maintenance over the next 20 years. An action plan was brought to bear. Top priority was upgrading the primary 138 kV transmission line with improved protection and a fault-isolation system. Backup power supplies were found near the plant, but it remained vulnerable to outage from a single event. Both primary and backup sources shared the same relatively short transmission line, which operated with normally closed secondary tie-breakers. In other words, though power came to the plant from multiple sources, it risked power loss because power flowed through a single transmission line to a switchyard inside plant boundaries. The 138 kV transmission line was modified. A new switchyard/substation allowed independent connections to the primary and two backup power sources. As important, a redundant fiber optic network was installed, connecting all sites. The enhanced network allowed each power source to be controlled by its own substation transformer, for isolation and greater protection in the event of a fault. The fiber network allowed microprocessorbased protection for current differentials. Additional coordination signals sent to protection systems identify faults and minimize affected areas. Microprocessor relays and protection equipment installed on the 138 kV power line work together to allow advanced fault recording. A communications network allowed monitoring all sites within the plant using supervisory control and data acquisition (SCADA). In the event of a fiber optic cable cut or equipment fault, network traffic can reverse around the completely redundant fiber network. This reduces recovery time to seconds rather than hours or days.
The planning process revealed the causes and costs of power-quality issues. It’s important to know, for example, that barely perceptible power sags can cause big problems in industries that have highly sensitive process parameters. Four important parameters A power system master plan typically focuses on four power quality issues: power factor, harmonics, voltage fluctuations, and outages. Power factor is the ratio of real power—the energy that runs motors, illuminates lights, and drives computers—to the apparent power coming into the circuit. The difference between real and apparent power is called reactive power. When electrical engineers calculate reactive power, it is expressed as a value ranging between 0 and 1, with 0 indicating more reactive power and 1 less reactive power. On a circuit with higher levels of real power, the value is closer to one. However, while it therefore might be assumed that maximum efficiency would be a circuit with no reactive power— meaning all electricity is doing work—some reactive power is needed to stabilize the circuit. The goal is to achieve the correct ratio between the points of too much reactive power (system is inefficient) and too little (system is unstable). Poor power factors also cause equipment degradation due to heat on wires and transformers; therefore, improving power factor (decreasing amount of reactive power) boosts power to the facility without overloading or overheating equipment. Inductive loads such as motors and drives are a primary cause of poor power factor. Nearly all manufacturing facilities are highly dependent on motors that kick on or off depending on production demands. Poor power factor can be corrected by installing capacitors either at the motor or on the network. One solution is a voltage source converter (VSC) that compensates for dynamic power factor caused by unbalanced loads. Non-linear load draws Harmonics are the wave fluctuations that occur when a non-linear load draws a current out of phase with the normal current. Anything that runs on 60 hertz ac current, which includes nearly everything found in homes or businesses, can create minor distortions in pulling current out of phase. In industrial
facilities, non-linear loads such as electric arc furnaces, welding machines, and other specialized equipment draw high loads and exert pull, to draw power out of phase. Poor harmonics can cause: • Overheated transformers • Tripped breakers and blown fuses • Control equipment malfunction • Disturbances to nearby equipment • Communications interference • Data loss.
Backup power supplies were found near the plant, but it remained vulnerable to outage from a single event. A new switchyard/substation allowed independent connections to the primary and two backup power sources. All images courtesy: Burns & McDonnell
Solving harmonics issues often involves installing harmonic filters that measure the distortion at the supply side—where power enters the system, often at the breaker/transformer— and sends out a corrective waveform that cancels or minimizes network distortions. Voltage fluctuations happen when power flow dips or rises unexpectedly. These fluctuations can occur either behind or in front of the meter. Within the facility, they can be caused by motors starting. Outside, weather events or the overloading of a section of the local distribution grid can come into play. Voltage fluctuations are particularly problematic for electromechanical relays. A large industrial plant may have thousands of installed relays, and a large voltage fluctuation can cause them to trip off in a cascade effect. Too little reactive power can cause voltage fluctuations—a small margin is always needed. Reactive power control devices compensate for voltage instabilities by improving power factor. A flexible alternating current transmission system (FACTS) device can act as a source or OIL&GAS ENGINEERING FEBRUARY 2018 • 7
ElEctrical powEr & procEss production a sink for reactive power, keeping it within the correct ratio. FACTS are based on voltage source converter technology and often can be a good solution when normal reactive power provided by generators or capacitor banks is too slow for sudden load changes.
Power quality issues at the petrochemical plant project were resolved by replacing an outdated system with smart controls. Detecting problems is easier, as is solving them.
8 • FEBRUARY 2018
Transient voltage spikes Outages are an obvious problem, caused by transient voltage spikes or surges. Outages are most often caused by problems on the distribution grid, such as storms and accidents. However, poor grounding, switching of inductive loads, or electrostatic discharge within the plant can cause a portion or even all of the system to go out. Even small electromagnetic discharges can cause problems and often are the reason for failure of a piece of electronic equipment or controller board. The solution is to install an uninterruptible power supply (UPS) to condition incoming power. The traditional solution is to install a resistor-capacitor which acts as a circuit inside a transformer, which acts as a layer of protection. The UPS must be carefully coordinated with the correct current limiting fuses. In a recent incident at a client’s refinery, a UPS distribution circuit with a 10-amp fuse mis-coordinated with the upstream UPS, causing the protective devices to shut down the entire coker unit. The UPS distribution at the 120V level, if not carefully coordinated with the correct current limiting fuses, can cause the UPS power to fluctuate, which may cause a dip in voltage and/or miscoordination of the protective devices, resulting in a widespread shutdown. Energy storage options following from advanced battery technologies are becoming one solution for UPS, particularly at datacenters, which cannot tolerate even minor power fluctuations. Batteries can be used in coordination with backup power supplies for seamless transition, or to slowly bring down critical systems.
OIL&GAS ENGINEERING
Microgrids are the solution many industrial plants are turning to for protection from external power disruptions. How to share power Power quality issues at the petrochemical plant project were resolved by replacing an outdated system with more sophisticated, smart controls. Detecting problems is easier, as is solving them. Once its systems were protected with redundant power feeds, the controls were prioritized in terms of 1) those that needed to start up first and 2) those essential to health and safety. Other upgrades were targeted as necessary for long-term growth. As in most industrial projects, cost was a factor. The studies looked to economize on equipment inventories. What can be mothballed or is no longer needed onsite? Are there central storage options for multiple affiliated plants where all wouldn’t be needing space for the same parts and equipment? Do repair schedules require keeping equipment onsite or can a delay in transport be managed? The answers to these types of valueengineering questions guided the engineering and construction staff, in conjunction with the plant’s operations and maintenance personnel, to optimize the costs and benefits of each solution identified. Modeling and analysis are invaluable tools. They can lend support to management decisions on setting budgets and calculating return on investment (ROI) to help prioritize upgrades or renovations. The goal is to demonstrate that power systems can’t be overlooked when setting capital budgets for overall plant process improvements. Whatever a plant’s refining or petrochemical product, prudent investment in power distribution systems can be the means to long-term competitiveness and profitability. Finding an engineering partner with an integrated team of all disciplines, including construction professionals is a first step. OG Mike Zakar is Substation Department Manager for Burns & McDonnell’s Houston-based transmission & distribution group. In his 22-plus years in the industry, Zakar has worked with North America’s largest utility, renewable energy, and industrial companies on a range of complex power delivery projects. He is a licensed electrical engineer with certifications in five states.
AnAlytics in the upstreAm
Edge computing comes to the oil & gas industry Forum bolsters producers’ confidence in technology-powered future By sidney hill Jr.
T
he watchword was optimism as several hundred individuals, all interested in the confluence of digitization in the upstream oil & gas industry, gathered in Houston in December 2017 for the TIBCO Energy Forum. This annual event is hosted by TIBCO Software, a company that specializes in helping corporations organize and analyze data for strategic business purposes. The prevailing story line at the event was that oil & gas producers finally have figured out how to remain profitable, even if prices never return to the highs seen in the early 2000s. The answer, according to most forum attendees, is to use information technology to create business models that can withstand shifting market dynamics. There also seemed to be a consensus that analytics—which is sometimes equated with Big Data—is the ideal technology for building these new oil & gas business models. It’s not surprising that a collection of TIBCO users would see analytics as the foundation on which to build structurally sound business models, since most of them already have chosen that path. There is evidence, however, that intelligent use of analytics can, in fact, make almost any business—oil & gas companies included—more efficient, which generally translates into higher profits.
It’s not how much you spend In his opening remarks at the Energy Forum, TIBCO Software CEO Murray Rode referred to a study recently published in the Harvard Business Review that discovered companies experiencing the following results after investing in analytics: • Revenue growth five times better than their peers • Profit growth eight times higher than their peers
• Return to shareholders two times higher than their peers. Even more interesting, Rode said, is the study found almost no difference in how much is invested by companies deemed leaders in analytics in comparison to those considered industry laggards. The leaders, on average, spend 2.5% of their revenue on analytics while the laggards spend 2.3% of revenue. “The difference is not in how much you spend, but in how you spend those dollars,” Rode said. Throughout the forum, both TIBCO executives and customers shared stories of how individual oil & gas companies are spending their dollars on analytics, and the benefits they’re reaping from those investments. Examples ranged from companies using well sensor data to optimize maintenance schedules to other companies changing drilling paths in real time in response to anomalies spotted on an analytics dashboard. There also were examples of companies developing completely new business models with analytics at the core, as well companies managing what could be considered Industrial Internet of Things (IIoT) platforms. Shawn Rogers, TIBCO’s senior director of analytic strategy, argues that there is no reason for a company to invest in IIoT technology without a plan to connect it to an analytics platform. “Simply collecting data has no inherent value,” Rogers said. “Analyzing data and taking action based on that analysis is where the payoff comes.” Analytics can add value to an oil company’s IIoT infrastructure, according to Rogers, by quickly filtering through all the data collected by sensors and identifying the few specific data points that are signaling potential problems. He also said TIBCO offers solutions OIL&GAS ENGINEERING FEBRUARY 2018 • 9
AnAlytics in the upstreAm
‘
Oil & gas companies are spending
that allow for doing two types of analysis, both of which are important to helping oil and gas companies thrive in increasingly volatile markets.
on analytics in
Which fluctuations are significant? pursuit of unique Analytics platforms have always allowed for bringing sensor data business models to a central platform, where the and reported 50% data can be assessed for historical trends that can help in adjusting reductions in the processes to prevent future problems. Recently, however, time it takes to drill Rogers said the company has wells in response to developed tools that allow for taking analytics “to the edge” where ubiquitous sensing operators can take readings from capability. individual devices in the field. In those scenarios, operators can spot potential problems, and adjust to avoid them, in real-time. “Analytics at the device determine which fluctuations in the data are significant,” Rogers said. “If I can analyze data at the edge, and know that I’m only looking at the important data points, that’s a huge payoff.” Michael O’Connell, TIBCO’s chief analytics officer, said ConocoPhillips is one of many companies who have used TIBCO’s Spotfire analytics platform in this fashion. ConocoPhillips reported a 50% reduction in the time it takes to drill wells after linking the Spotfire platform to the hundreds of sensors it has attached to wells in the Eagle Ford shale basin in South Texas. Spotfire constantly runs comparisons on data from all those sensors. It will automatically adjust settings—such as the weight being placed on a drill bit or the speed at which the bit is moving—if a well starts pumping at a lower rate than other wells that have not shown changes in such settings. Industry titans like ConocoPhillips are not the only oil & gas producers reaping big benefits from analytics. Several smaller producers—including Anadarko Petroleum and Apache Corp.— shared their stories at the TIBCO Energy Forum. These companies also offered examples of how analytics can support new business models.
’
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OIL&GAS ENGINEERING
At Apache, analytics is one part of an entire information technology infrastructure the company developed following some corporate soul searching in the wake of the industry downturn that started in 2014. “After the market shakeout, we had a new leadership team, and we looked at what we needed to do to come out of the downturn as a stronger company,” said Travis Osborne, Apache’s director of information management. Five key systems From an IT perspective, Osborne said, Apache determined it needed easier ways of getting data to people who make decisions in the field. To accomplish that, Osborne’s group undertook a project that involved first developing a smooth process for managing and moving data across the enterprise. That led to the purchase of a TIBCO product called BusinessWorks, which provides a visual environment for developing business processes, along with a messaging system for packaging and transporting data that support those processes. “Using BusinessWorks, we were able to build an architecture that allows us to follow data from where it originates to where it lands,” Osborne said. “That gave everyone a good insight into how processes were working, and whether any of them needed changing.” Osborne said it took roughly 90 days to build this architecture, which also helped Apache identify five key systems that were most critical to business operations. The next step was using the TIBCO Enterprise Messaging System (EMS) to build a backbone for seamlessly moving data between those five systems. That took roughly 15 months, which also involved connecting the messaging backbone to the TIBCO Spotfire analytics platform, where data can be viewed and analyzed. “We already had Spotfire in place, but it had been used primarily as a tool for engineers, allowing them to do some selfgenerated analytics,” Osborne said. “You might call it a bit of early data science.” As part of Apache’s new information architecture, Spotfire has become a mainstream analytical tool available to everyone in the enterprise. “We’ve gone from it being a tool
exclusively for engineers and people solving scientific problems to accountants, field foremen, and pumpers at the well-site all having access to Spotfire content,” Osborne said. “We’ve pushed it out to the pumper foreman level, so the guys on the front line making production management decisions can get more information on how we manage assets, as well as how we spend money,” he said. Making that data widely available allowed Apache to implement what Osborne referred to as a “ground up” approach to financial management. “We want everyone looking at the same data—from the people in the field to regional vice presidents and executive vice presidents at the corporate office. The visibility of that data is valuable because people in the field see things first. To see how their actions either increase revenue or lower cost is golden.” Teaming engineers with data scientists Anadarko took a slightly different approach to pushing analytical data to the field. It hired a group of data scientists and matched each of them with a petroleum engineer to create two-person teams that began exploring ways of using data to improve operations. These teams are part of what Anadarko calls its advanced analytics and emerging technologies group. One of the teams—consisting of Chad Loesel, a staff drilling engineer and Dingzhou Cao, a staff data scientist—gave a presentation at the TIBCO Energy Forum. The teams were charged with finding ways of getting data from the field to the corporate office, where it could be analyzed to produce meaningful information that could then be relayed back to the field in quick fashion. “We always had access to real-time drilling data,” Loesel said. “But historically by the time that data reached the office, it was old and static. We wanted to combine realtime drilling data with advanced analytics to see what we could gain in terms of a competitive advantage.” As they examined that question, the teams were all given one mandate: to move
quickly in deciding whether a project had the potential to generate a real return on investment. “We were looking for rapid proof of concept that we could make work, or we were moving on,” Loesel said. Roughly a year later, Anadarko has a fullblown real-time data analytics system in place, with four modules already in use and three others in the pipeline. The modules currently in use are: • Rule-based drilling activity recognition, which constantly monitors drilling activity and provides useful information to the remaining analytics modules • Sliding drilling guidance system • Key drilling performance indicators • Torque and drag • Trajectory and recognition. A rotational drilling guidance system was set for deployment at the time of the forum event, and modules for analyzing hydraulic models and wellbore trajectory were under development, according to Loesel. A TIBCO product called Streambase is the backbone of Anadarko’s real-time data analytics system. Streambase is programmed to move the data users request into the Sportfire platform, where it’s analyzed and pushed back to Streambase for delivery to the appropriate users via the Spotfire analytics dashboard. Cao, the data scientist, said Anadarko was able create the first prototype of an analytic application in three months, largely because the TIBCO tools are built on an open platform that allows for making quick connections between systems that need to share data. Now Anadarko users have full, real-time visibility of field data. “We have taken computing power to the edge,” Loesel said. “We can identify problems and get rigs back on track immediately.” Having ready access to this type of technology is why oil & gas producers are more confident about their ability to prosper, even if prices within the industry remain volatile. OG Sidney Hill Jr. is a graduate of the Medill School of Journalism at Northwestern University. He has been writing about the convergence of business and technology for more than 20 years. OIL&GAS ENGINEERING FEBRUARY 2018 • 11
Oil industry asset management
How slow roll runout works in electric motors Vibration measurement a requirement on API motors By Papa diouf, Pe and Bryan K. Oakes
V
ibration measurement of the radial shaft movement in rotating components is critical to electric motor monitoring and diagnostic testing. However, high shaft runout can lead to inaccurate vibration readings, because so-called slow roll runout, caused by mechanical and electromagnetic defects in the shaft probe track, is independent of the shaft vibration. Thus, the vibration measured during operations includes the shaft runout, which could increase or reduce the recorded vibration. If the vibration reading is higher than the true machine vibration, then unnecessary alarm or shut-off conditions can be triggered. On the other hand, if the vibration reading is lower than the true machine vibration, then premature failure can occur. Measurement of slow roll runout is a standard requirement on American Petroleum Institute (API) motors when non-contacting probes are specified. The API 541 covers the minimum requirements for special-purpose, form-wound squirrel-cage induction motors, 500 hp and larger, for use in petrochemical applications. Unless otherwise specified, oil film bearings are by default used in API motors. In this specification, all hydrodynamic bearing motors intended to operate at speed greater or equal to 1200 rpm, shall be equipped or have provision for non-contacting vibration and phase reference probes. When vibration probes are supplied or provision for probes is required, a probe track area must be supplied and treated so that the total combined mechanical and electrical runout does not exceed a certain limit. How it’s done Such testing typically is done using noncontacting proximity probes, such as eddy
12 • FEBRUARY 2018
OIL&GAS ENGINEERING
current proximity probes. The probes measure a varying gap voltage between a shaft and probe tip. Variation is mostly due to vibration, but also reflects the impact of slow roll runout. Let’s look at some different runout types, measurement methods and instruments used, acceptable levels according to API standards, contributing factors to high runout, and its impact on vibration measurement. The non-contacting proximity probe used is part of a transducer system that also includes an extension cable and proximitor. As noted, the system measures the gap voltage variation between probe tip and probe track on the rotating element. This gap continuously changes, mostly due to the shaft vibration, but also reflects any probe track out-of-roundness, concentricity between the probe track and bearing journal, surface defects on the probe track area, shaft misalignment, shaft bending, or variations in the electromagnetic properties of the shaft material near the circumference of the probe track area. All these non-vibration-dependent changes of the gap between shaft and probe tip define total indicator runout (TIR), or simply, runout. Runout will appear in the vibration readings and can lead to measurement errors. That’s why understanding runout is crucial to rotating machinery monitoring and diagnostics. Definitions and details Slow roll, as defined in API 541 5th Edition Section 6.3.3.3, is a condition in oil-film bearing motors or generators in which the rotor moves between 200 to 300 rpm. At this speed the dynamic effects are minimized. Vibration is almost nonexistent. In this state, proximity probe readings should be sensitive to probe
track mechanical defects, including out of roundness, or those related to surface finish, lack of concentricity between the bearing journal and track area, non-straight shafts, or electromagnetic defects in the shaft material. A slow-roll condition can be measured: 1) in the assembled machine; 2) on the rotating assembly positioned in v-blocks on the bearing half shells; or 3) in a lathe. Slow roll runout has two aspects: mechanical and electrical. Mechanical runout (MRO) is a measure of the shaft cylindrical surface deviation from a perfectly round surface, concentric with the bearing centers. Deviations include: surface out-of-roundness; mechanical defects on the surface, e.g., surface finish or scratches; or lack of concentricity between the surface and the bearing journal centers. MRO is measured with a dial indicator or a contacting probe. Electrical runout (ERO) is a measure of shaft surface electrical conductivity and magnetic permeability variation. Nonuniform shaft electromagnetic properties interfere with the magnetic field of the proximity probe, thus causing a change in the processed signal as a gap voltage variation. Note that ensuring transducer system operation requires the components to be matched sets. If these components are not matched properly, measured vibration amplitudes will not be accurate. Proximity probes are, as a default, calibrated to AISI 4140 steel. If the steel is significantly different, it could impact measurement accuracy. Proximity probes can be calibrated to other materials if necessary. How it’s done To measure slow roll: 1. The inductive coil is excited with alternating current, which creates an alternating magnetic field. 2. When a changing magnetic field interacts with a conductive material (such as the shaft), small currents, called eddy currents, are induced in the material. 3. The eddy currents, in turn, create an opposing magnetic field, resisting to the original magnetic field.
4. Interaction between the two magnetic fields is dependent on the distance between probe tip and target material. As distance varies, changes in the interaction between the two magnetic fields is converted into voltage output. 5. Voltage output is then converted into vibration units of displacement in mils or microns.
Figure 1: The eddy-current, non-contacting proximity probe used is part of a transducer system that also includes an extension cable and proximitor. As noted, the system measures the gap voltage variation between probe tip and probe track on the rotating element. All graphics courtesy: Baldor
One common mounting configuration consists of two eddy current proximity probes mounted on the bearing housing and located at 90 deg apart and at 45 deg from the vertical shaft centerline. Probes can be mounted inboard or outboard of the bearing journal depending on motor design. Probes are placed over the shaft in an area specially machined and adjacent to the bearing journal. This shaft area, called the probe track zone, is machined to minimize mechanical and electrical runout. Track zone width is dependent on probe tip size. A minimum width of 1.5 times the diameter of the probe tip is recommended for the track zone. This ensures the induced magnetic field from the probe tip fully penetrates the machined area. API 541 requires that the slow roll runout be measured during coast-down when the rotor speed is between 200 to 300 rpm. At this speed range, probe-recorded displacement is almost purely runout without any vibration. On non-API motors, slow roll runout can be OIL&GAS ENGINEERING FEBRUARY 2018 • 13
Oil industry asset management still exceed limits after motor assembly. Contributing factors include misalignment caused by cocked bearings, non-concentric frame bracket fits, a rotor bent during assembly, damaged probe track area, or other significant challenges. Some motor manufacturers go further and self-impose a combined mechanical and electrical runout limit that is much lower (less than 0.25 mils) on the shaft bearing journal and probe areas. This avoids finding issues arising later in the manufacturing process. Figure 2: Probes are mounted inboard or outboard of the bearing journal depending on motor design and placed over the shaft in an area specially machined and adjacent to the bearing journal. This shaft area, called the probe track zone, is machined to minimize mechanical and electrical runout. A minimum width of 1.5 times the diameter of the probe tip is recommended for the track zone.
14 • FEBRUARY 2018
recorded at approximately 10% to 15% of the operating speed. Total runout recorded must meet the required limit set forth by the motor specification. Acceptable levels Electric motor manufacturers refer to customer specifications to determine the acceptable levels of slow roll runout. API 541 limits the slow roll runout to 30% of the allowable unfiltered vibration peak to peak (1.5 mils), or 0.45 mils for induction motors. This limit applies to an assembled motor. If the runout limit is not met during manufacturing or initial testing, the motor will be disassembled and the shaft reworked. This process can be time consuming and costly. Usually, to save time, motor manufacturers partially assemble the motor (see Figure 3) and perform a quick test to check slow roll runout and bearing alignment and temperature. If the slow roll is within the limit, then the motor will be finish assembled before the complete testing is started. For this reason, API 541 standards has set a runout limit on the rotating assembly (rotor and shaft assembled) while supported in V-blocks. With this method, the allowable combined mechanical and electrical runout limit is 25% of the unfiltered allowable vibration limit, peak to peak (1.5 mils), or 0.375 mils. Keeping the runout within 0.375 mils increases the chances of achieving the desired limit with the motor assembled. However, a rotating assembly can have a very low runout on the V-block and yet
OIL&GAS ENGINEERING
Impact on vibration In the past, simple arithmetic subtraction was used to compensate vibration levels from slow roll runout. If the vibration amplitude was 1.6 mils peak to peak and the slow roll runout was known, for example, to be 0.45 mils, then (1.6 - 0.45) = 1.15 mils was considered the true vibration. This is incorrect because both the vibration and slow roll runout are waveforms and cannot simply be added or subtracted without filtering them. The unfiltered vibration contains all the frequency components that are in the incoming signal. When a vibration signal is filtered at a particular frequency at running speed, for example, it is expressed in an amplitude and phase angle that can be described as a vibration vector. As a vector, the filtered vibration at a given frequency, such as 1 times or 2 times, can be compensated with the filtered slow roll at the same frequency as a vector addition. Per API 541, the compensated vibration displacement filtered at running speed frequency shall not exceed 80% of the unfiltered limit. Compensation is not used in general by motor manufacturers, but can be useful in certain situations. Compensation could also increase the vibration depending on the angular position of the vectors. What impacts runout Mechanical runout is the measure of shaft deviation from a perfectly cylindrical
surface. It is mainly impacted by the manufacturing and assembly process and changes over time during motor operation. Improper selection of cutting tools or machining parameters can lead to higher surface roughness. Mechanical damages, such as scratches, scoring, and dings on the bearing journal or probe track will affect the mechanical runout. Since runout is measured in reference to the bearing journal, a non-concentric probe track to the bearing journal will result in high maintenace, repair, and overhaul costs. It is also impacted by the following: • A straight shaft pressed into a bowed rotor • A bent shaft pressed into a straight rotor • A misaligned shaft caused by improper fit between the motor frame and the bearing cartridges • A sagged or bowed rotor due to thermal instability in the rotor. Electrical runout is the measure of shaft material non-uniformity. When electrical runout is measured using non-contacting eddy current probes, the interaction between the emitted magnetic field and the induced magnetic field is converted into distance. Any phenomenon that can change the magnetic interaction between the probe tip and the shaft will affect the runout. These include non-uniform material grain structures, non-uniform electro-magnetic properties, or magnetized shaft. Manufacturing of the shaft, whether the result of a forging or hot-rolled steel process, can affect the metallurgical properties of the material and consequently the ERO.
runout is measured on a rotating shaft at slow speed between 200 and 300 rpm, according to API. Since runout impacts the vibration readings and can lead to measurement errors, it is important to understand its various sources and how to mitigate it. Monitoring runout level during the manufacturing process helps avoid having to disassemble the machine and return the rotor to the lathe or grinder for rework. Not meeting the slow roll runout limit after the machine is assembled can be costly to both manufacturers and customers. OG Senior mechanical design engineer Papa M. Diouf (IEEE Member, 2013) graduated from Purdue University in Indiana with a MSME in 2007. He has been with Baldor Electric since 2006. He is a registered engineer in South Carolina. Manager of the large ac design and mechanical engineering groups, Bryan K. Oakes (Senior IEEE Member) has been with Baldor Electric since 1989. He is member of the API 541 and API 547 subcommittees, and an author of multiple IEEE papers.
Figure 3: The API 541 standard has set a runout limit on the rotating assembly (rotor and shaft assembled) while supported in V-blocks.
Final words Slow roll runout for electric motors and generators is a condition in which the combined electrical and mechanical OIL&GAS ENGINEERING FEBRUARY 2018 • 15
Security & Safety
Prevent process safety incidents from occurring See what you inspect, and not what you expect By Gregory Hale
P
rocess safety events are bad enough within the confines of any facility, but it can lead to tragic incidents outside the fence. “These incidents are why we will never be complacent,” said Lynne Lachenmyer, vice president safety, security, health, environment, and corporate board at ExxonMobil during her keynote address at the Mary Kay O’Connor Safety Center 2017 International Symposium in College Station, Texas. “An instant is all it takes to leave an indelible impression on an entire industry.” A safety incident can be misleading as it is often a series of small incidents or shortcuts that lead to a bigger event. “Incidents are always preventable,” Lachenmyer said. “Major process incidents don’t just happen, they are a breakdown in the process safety systems. We must verify there has been no backsliding and we don’t hear ‘it can’t happen here’.” Lachenmyer recalled an explosion and fire in 1987 at a refinery in Torrence, Calif., which shut down the refinery. There were minor injuries in the blast. She said the incident shaped her life. “I was in a vanpool going home when it happened. When I came in the next day, the silence was deafening when you are used to the loud noises from the machines,” she said. She saw the debris field from the explosion and was struck by the shrapnel area’s potential impact. It is understood the oil & gas industry is relatively dangerous and the risk of fire and explosion or release of toxic chemicals is always present. She said smart process safety and reviewing policies and procedures is the only way to go.
Industrial incidents The industry is fraught with infamous incidents like Texas City, Pasadena, Deepwater Horizon, and the Valdez oil spill. How a company overcomes those incidents and learns from them is paramount. “As a result of Valdez, we overhauled our safety based on our risk management position,” Lachenmyer said. “We created a framework to be of one mind when it comes to safety and risk management. We speak the same language.” 16 • FEBRUARY 2018
OIL&GAS ENGINEERING
Thanks to the framework, she said, process safety performance is improving, but the company is not yet what it wants to be. “It is imperative for us to raise the bar,” she said. “It is a continuous journey.” Process safety is improved, Lachenmyer said, but the company went back to revisit the issue and see what it could do better. To do that, management had to look at the issue broadly, be humble, and listen. “We learned things we did well, but recognized things we can do better,” she said. “Equipping our people to execute process safety practices, we have seen an improvement in all segments.” Lachenmyer said the company has a roadmap on how to accomplish process safety improvements to show as part of a continuous process. “We are increasing process safety expectations. Everybody’s job involves risk management. Everyone needs to understand hazards and assess the risks and how to mitigate the risks.” That means workers need to understand the situational environment before entering it, and if something goes wrong, have a firm idea of their role in fixing it. All too human “We are all human and we know humans make mistakes,” she said. “Our goal is to enable operators to get safety critical tasks done correctly every time. Process safety systems should be executed flawlessly.” About 70% of incidents of consequence are related to actions taken, or not taken, by humans, she said. That is why they’ve made a concerted effort in making sure processes are understood and executed. “You get what you inspect, not what you expect,” Lachenmyer said. “We know what gets measured gets managed.” OG Gregory Hale is the editor and founder of Industrial Safety and Security Source (ISSSource.com), a news and information website covering safety and security issues in the manufacturing automation sector. This content originally appeared on ISSSource.com. ISSSource is a CFE Media content partner.
The many flavors of cloud compuTing
Hybrid cloud services support integration of operations Secure, cloud-based solutions leverage on-demand scalability
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By dante orsini
loud computing has joined the mainstream due to its ability to guard against cyber threats, human error, and natural disasters while maintaining industry compliance and lowering costs. Unfortunately, industries that stand to gain the most from cloud technologies often suffer from slower adoption rates due to concerns over data security. The good news is that in traditionally conservative sectors such as oil & gas, companies are realizing the agility, cost savings, and security benefits of hybrid cloud services. A recent forecast from the U.K.-based Oil and Gas Council encourages the shift. It states the industry can leverage cloud computing to provide powerful processing capabilities while facilitating links between multiple sites across the world.
Cost of entry considerations Oil & gas companies require powerful processing for large data files and high utilization rates of expensive human resources. For these organizations, the logical solution is to maintain powerful workstations under the operational control of specialists who need them while integrating software with a cloud system for all other functions. This results in a true hybrid solution with two systems that appear to operate as one. The cost-of-entry to the cloud is low and is typically based on a pay-as-you-go arrangement with charges directly related to specific compute and storage requirements. Oil & gas companies, especially smaller independents and service companies, can benefit from access to sophisticated, scalable, and secure IT infrastructures for very little outlay. They also benefit from transparent operational monthly costs and less overall impact on the balance sheet. Navigator Gas, which specializes in the gas transportation sector, is one example. The company, owner of liquefied petroleum gas (LPG) vessels, embraced hybrid cloud services and has experienced significant growth in recent years. Its compute and storage requirements had exceeded available on-premises capacity.
Navigator Gas now has a secure cloud-based solution to leverage the on-demand scalability of the cloud to achieve IT resiliency. One interesting aspect of its solution is that it leverages secure cloud hosting such as information-as-a-service (IaaS) with cloud-to-cloud disaster recovery and disaster-recovery-as-a-service (DRaaS) for on-premises servers. Professional services Any organization that migrates services to the cloud benefits from the availability of professional host cloud systems with dedicated and centralized support. Hardware upgrades, software upgrades, increased compute and capacity requirements, and technical support can enable companies to quickly respond to operational developments. Provision of third-party services frees organizations from being at the mercy of on-the-ground IT consultants and their busy schedules. Tangible business benefits realized from moving to a secure cloud platform include: • The avoidance of additional capital expenditure (CAPEX) investment while retaining use of existing on-premises servers. • A flexible, scalable, and secure cloud environment that is no longer dependent on a fixed server environment. • All workloads—cloud and on premises—are now protected by a hybrid cloud DRaaS solution. Previously it had no disaster recovery (DR) strategy in place. • Vulnerability scanning that meets application security requirements. Companies considering a hybrid cloud solution will discover the security, cost, and scalability capabilities to meet IT needs today and in the future. OG Dante Orsini is SVP business development, iland Internet Solutions. OIL&GAS ENGINEERING FEBRUARY 2018 • 17
OIL & GAS INDUSTRY NEWS Award recognizes development of liquid alkylation technology Honeywell announced its Honeywell UOP business and Chevron U.S.A. Inc., a subsidiary of Chevron Corp., received the 2017 Platts breakthrough solution of the year award in recognition for the development of the ISOALKY process, the first liquid alkylation technology to be introduced in 75 years. The technology, initially developed by Chevron, uses an ionic liquid catalyst to produce highoctane motor fuels. Chevron licensed the technology to Honeywell UOP, which offers it as an alternative to traditional technologies that use hydrofluoric or sulfuric acids as a liquid alkylation catalyst. Jim Rekoske, VP and chief technology officer for Honeywell UOP, said: “The ionic liquids technology is economically compelling, and far easier to handle than conventional liquid acid technologies, while delivering the same yields and high levels of octane.” Chevron proved the ISOALKY technology over a five-year period in a demonstration unit at its Salt Lake City refinery. The company broke ground on a retrofit project to convert its hydrofluoric (HF) acid alkylation unit at that refinery to ISOALKY technology. The completed unit will be operational in 2020, at which time the Honeywell UOP and Chevron USA received the 2017 refinery’s HF equipment and its inventory of HF acid will be removed. Platts breakthrough solution of the year award for ISOALKY technology uses a non-aqueous liquid salt—or ionic liqdevelopment of the ISOALKY process. Image courtesy: uid—at temperatures below 100ºC to convert a stream from a fluid Honeywell UOP catalytic cracker into a high-octane blending component that produces a cleaner-burning gasoline product. The process can be used in new refineries, and under most circumstances, in existing facilities undergoing capital expansion. The ionic liquid has strong acid properties, enabling it to perform catalysis, but without the volatility of conventional acids. It can produce alkylate from a wider range of feedstocks than conventional acid technologies while using a lower volume of catalyst. The ionic liquid catalyst has a very low vapor pressure and can be regenerated on-site, giving it a favorable environmental footprint compared to other technologies. OG
Downhole sensor system deployed offshore Norway Emerson’s Roxar downhole sensor system has been deployed on the Maria field in offshore Norway, providing the field’s operator, Wintershall, with improved well integrity monitoring and offshore safety. The latest deployment of the system provides crucial integrity data and measures online and realtime pressure and temperature information—from behind the casing in subsea production wells—to offshore operators. This leads to better insight into the status of well barriers and casing. The pressure and temperature monitoring system allows Wintershall personnel to verify that the predicted pressure buildup falls within the design criteria, and an alarm trigger point is implemented in case pressures that are potentially outside the system design are reached. The downhole sensor system also encompasses advances that enable operators to access online displays and trending of previously unreachable temperature and pressure subsurface data behind the well casing and achieve online integrity verification without any impact on production. The added knowledge on pressure and temperature dynamics in previously unreachable parts of the completion is delivered by the downhole sensor system’s highly accurate quartz gauges. It has also led to a better understanding and confidence in operators’ well integrity strategies. The system helps ensure wells meet integrity monitoring standards, such as API RP90 and NORSOK D-010. OG
18 • FEBRUARY 2018
OIL&GAS ENGINEERING
The downhole sensor system enables operators to access previously unreachable temperature and pressure subsurface data. Image courtesy: Roxar
Alliance formed for provision of digital oilfield technology
With the reinvigoration of the oil & gas industry, Endress+Hauser, Angus Measurement, and others are partnering to meet demand for oil-field digitization. Image courtesy: Endress+Hauser
Endress+Hauser announced partnerships with Angus Measurement Services, TechnipFMC, and its sales and service representative, Vector Controls. The automation companies will collaborate to bring added value to the oil & gas industry. The partnership alignment between the automation companies is to inform and better prepare the oil & gas industry and customers for continuing digitization. Each partner will contribute focused areas of expertise, including products and services: • Endress+Hauser’s intelligent field instruments and digital communication expertise captures and transmits product quality, quantity, and value. • Angus’ systems fabrication and technology consultants help customers optimize the performance of gas, oil, and water assets. • TechnipFMC’s oil & gas measurement technology and design capabilities deploy best-in-class technology and develop modularized systems. • Vector’s expertise in gas analytics, measurement, and control provides the opportunity to deploy best-in-class solutions. With this partnership, the members believe they can deliver industry expertise and systems capabilities that can digitalize the oilfield of the future. OG
Operational excellence use rising, but workplace culture remains a challenge Survey findings from Petrotechnics reveal operational excellence remains central to firms’ enterprise-wide strategies and is now delivering tangible results. For 16% of respondents, operational excellence initiatives are already delivering a return on investment (ROI) and, for 10%, it is embedded in the way they work. Nearly all (95%) respondents agree operational excellence requires everyone, “from the boardroom to the frontline, to consistently make the most effective operational decisions.” Around 60% of respondents said operational excellence has become more important in the last 12 months, compared to 80% in the previous year. Scott Lehmann, vice president of product management, Petrotechnics, said, “The last year was a significant phase in operational excellence’s evolution as it proved its worth in volatile times. The turbulent oil price put operations to the test and many companies, to their own surprise, weathered the storm and managed to maintain a margin. Now the price has stabilized, firms can focus on applying the same measures more widely and to even greater effect. As a result, operational excellence has emerged from the confines of narrow departments to become the new enterprise-wide norm.” While industry leaders are delivering ROI, there remains a huge opportunity for many more firms to follow suit. Nearly half of respondents (44%) say operational excellence is a priority and should be the way they run their business while 20% remain even further behind, stating, “Much more needs to be done to achieve operational excellence.” Workplace culture is the single biggest challenge according to 60% of respondents, followed by leadership and management (40%) when it comes to implementing operational excellence initiatives. Lehmann said, “Excellence initiatives require major change across the entire enterprise, affecting numerous roles and the way many individuals work. Inevitably, there will be resistance to change so management has a vital part to play in leading teams through the transition.” On the plus side, nearly half of respondents say their senior leadership team is the most engaged with operational excellence initiatives in their organization. Last year, 92% agreed, “Technology is an enabler for delivering sustainable operational excellence in the hazardous industries.” That sentiment continues this year, with 73% agreeing, “Digitization is helping accelerate our ability to deliver sustainable operational excellence.” Lehmann concluded, “The digital leaders have paved the way for the rest of the industry to follow. They have proved the value of operational excellence endeavors and shown the power of technology In the oil & gas industry, operational excelin achieving ROI. As lence is allowing reduced costs for production technology becomes processes. Image courtesy: Petrotechnics more readily available, many more firms can now adopt it to enhance their operational-excellence frameworks and deliver similar and long-term rewards.” OG OIL&GAS ENGINEERING FEBRUARY 2018 • 19
OIL & GAS INDUSTRY NEWS Well diagnostics breakthrough announced TGT Oilfield Services, provider of through-barrier diagnostic systems, announced the successful validation of its electromagnetic (EM) EmPulse well inspection system in high chromium tubulars. In three Middle East deployments—one an operator witnessed yard test and the other in two live wells—TGT engineers demonstrated that the system can quantitatively determine the individual tubular thickness of up to four concentric barriers, even when there are high amounts of chrome in the tubulars. “Increasing chromium content helps to protect well completions from highly-corrosive fluids, such as carbon dioxide, hydrogen sulphide, and chloride—but high-chrome can cause serious problems for ordinary EM pipe inspection systems,” said Ken Feather, TGT’s chief marketing officer. “It’s essential that operators can access integrity inspection systems that work reliably and accurately.” The increase in chrome and the resulting decrease in ferrous content causes EM signals to decay too quickly for ordinary EM inspection systems. EmPulse combines ultra-fast sensor technology with “time-domain” measurement techniques to capture EM signals rapidly and accurately in a wide range of pipe materials, including those with high-chrome content. This enables operators to evaluate pipe thickness and metal loss in multiple casing strings simultaneously, ensuring longterm well performance even in the most challenging production environments. “The ability of the technology to make measurements when facing specialized materials in certain well tubulars marks a significant breakthrough,” said Simon Sparke, TGT integrity expert and coordinator of the high-chrome testing program. “We anticipate that EmPulse will be particularly applicable for the Middle East operators, and also some fields in the Gulf of Mexico, the North Sea, and offshore Brazil.” The technology adds considerably to the integrity security of a well by providing barrier-by-barrier visualization of the well operating envelope at the time of logging. The time-based measurements, enabling the system to quantify metal loss in up to four barriers independently and deliver highly sensitive and fast response measurements, brings with it significant advantages over frequency-based measurements offered by other systems. The Middle East operator witnessed yard test consisted of a 28% chrome pipe with built-in mechanical defects where the high-speed EM sensor technology confirmed and correctly identified the man-made problems in a controlled environment. The second operation took place in two live Middle East wells in a very high hydrogen sulphide gas production scenario with 28% chrome tubulars. In this case, the system again functioned as planned, and recorded the status of three well barriers. Additionally, a multi-finger caliper recording confirmed the EM results for the condition of the inner pipe. OG
Fluor awarded contract for North Sea project
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Fluor Corp. announced that the company was awarded a contract by Shell for the engineering, procurement, and fabrication of Shell’s Penguins floating production storage and offloading (FPSO) vessel in the North Sea. Fluor booked the undisclosed contract value in the fourth quarter of 2017. “We are pleased to partner with Shell in the UK as they make this significant investment in their North Sea operations,” said Jim Brittain, president of Fluor’s energy and chemicals business. “We leveraged Fluor’s full range of integrated solutions to drive down the project’s costs and our fabrication capabilities were a clear differentiator. This award demonstrates Fluor’s ability to design, fabricate, and deliver high-quality, capital-efficient offshore facilities globally.” Fluor has full responsibility for the design, fabrication, and delivery of Belt/Sheave the pre-commissioned FPSO to the North Sea. The FPSO will have a producLaser Alignment System tion capacity of 45,000 barrels of oil equivalent per day, and can store up to New Green laser delivers these 400,000 barrels. The FPSO will be designed to operate continuously for 20 important benefits: ● Reduces Vibration years without dry docking and will help extend the life of the Penguins oil & ● Eliminates downtime and productions gas fields. ● At an affordable price ● Visible indoors and Outdoors The project will be led by Fluor’s Manila, Philippines, office and fol● Brightness great for long distances lows Fluor’s successful delivery of the Malampaya Phase 3 project in the Philippines. OG 20 • FEBRUARY 2018
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