Archive | Energy Management

279

6:14 pm
May 10, 2017
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Don’t Neglect Electrical Equipment Maintenance

Human error and improper maintenance, akin to operating a car and not checking the oil, can lead to catastrophic results to equipment and personnel involved.

Human error and improper maintenance, akin to operating a car and not checking the oil, can lead to catastrophic results to equipment and personnel involved.

Electrical equipment that is not properly maintained is notNFPA 70E compliant and, therefore, dangerous to personnel and business operations.

By James Godfrey, CESCP, Craft Electric & Maintenance

Since the release of the 2015 edition of NFPA 70E, “Standard for Electrical Safety in the Workplace,” there seems to be a tremendous push by companies to achieve compliance, and rightfully so. As noted in this standard, more than 2,000 people each year are admitted to burn centers with severe arc-flash burns.

NFPA 70E states that an arc-flash risk assessment shall be performed and shall determine if an arc-flash hazard exists. Arc flash is the result of an arcing fault that bridges the air gap between conductors such as phase to phase, phase to neutral, or phase to ground. In an article published in Safety and Health Magazine (August 2009) the most common cause of arc-flash accidents is human error. However, such things as the accumulation of conductive dust inside an enclosure and equipment failure, most likely the result of inadequate maintenance, can also cause these arc-flash events. In short, if electrical-equipment maintenance is neglected, something is going to blow. When that happens, it can be catastrophic.

OSHA CFR 1910.303(b)(1) states that electrical equipment shall be free from recognized hazards that are likely to cause death or serious physical harm to employees. Simply put, condition of maintenance must be considered. NFPA 70E states that electrical equipment shall be maintained in accordance with manufacturer instructions or industry-consensus standards to reduce the risk associated with failure.

The term “industry-consensus standards,” typically refers to a standard that has been accepted as recommended practice such as NFPA 70B, “Recommended Practice for Electrical Equipment Maintenance.” This standard addresses such things as development and implementation of an electrical preventive-maintenance (EPM) program, recommended intervals for maintenance, testing and test methods, reliability-centered maintenance (RCM), and acceptance testing.

When having an arc-flash risk assessment performed and not addressing the maintenance component of an electrical safety program, some assumptions must be made. These include, but are not limited to, equipment that is operating properly, equipment that has been properly maintained, and condition of maintenance, as well as opening times of over-current protective devices.

If an arc-flash risk assessment has been performed, then the amount of incident energy must be observed before removing equipment covers.

If an arc-flash risk assessment has been performed, then the amount of incident energy must be observed before removing equipment covers.

NFPA 70E states that over-current protective devices that have not been properly maintained can cause increased opening times, thus increasing the incident energy in the event of a fault in the electrical-distribution system. This creates a major safety concern for personnel and their interaction with energized electrical equipment, as well as lost revenue due to equipment failure. As a result, careful consideration must be given to the development and implementation of an effective electrical-safety program to maximize benefit and minimize cost. The arc-flash risk assessment can be a costly endeavor and the results obtained can be misleading or inaccurate because of improper or inadequate maintenance.

Surprisingly, a high percentage of facilities are not OSHA and NFPA compliant and have little knowledge of what it takes to be compliant in the area of electrical safety. Furthermore, some are doing very little in terms of electrical-equipment maintenance and are satisfied with having infrared scans done on the electrical panels because it has been recommended by their insurance company. Infrared thermography is very effective at identifying heat-related issues, but does not satisfy the requirement to maintain electrical equipment in accordance with manufacturer instructions or industry-consensus standards.

Infrared technology generally requires a direct line of sight to the target area, which raises another safety concern. Pursuant to the NFPA 70E requirements, the level of risk must be assessed before removing equipment covers and exposing energized conductors and circuit parts. To properly assess the risk, such things as available fault current and opening times of over-current protective devices must be considered.

Available fault current is the amount of current that may be present at any point in the electrical system as a result of a short or fault condition. If a fault were to occur in the electrical system as a result of equipment failure or human error, the equipment affected may not be rated to handle the fault current and this could be catastrophic. If an arc-flash risk assessment has been performed, then the amount of incident energy (typically expressed in calories/cm2) must be observed and personal-protective equipment selected and put on before removing equipment covers.

At this point, a decision must be made, based on personnel risk, to open or not open equipment and expose energized conductors and circuit parts. If it is determined that removing equipment covers could expose personnel to an unacceptable risk, the equipment should be de-energized before performing any type of preventive maintenance. An infrared scan would be ineffective in this case.

When doing any work on electrical systems, proper personal-protection equipment is essential.

When doing any work on electrical systems, proper personal-protection equipment is essential.

Maintenance considerations

An effective preventive- and proactive-maintenance program should take into consideration safety, the age of the equipment, operating environment, and the criticality of the asset. If infrared scanning is the only form of preventive-maintenance approach that’s been employed, equipment reliability and safety have been compromised. That type of situation should be of great concern to plant managers, maintenance managers, technicians, and other employees.

As outlined in NFPA 70B, several available maintenance and testing options are specific to the targeted equipment. Take, for example, low-voltage service-entrance equipment, often referred to as switchgear. Some of the maintenance recommendations outlined in NFPA 70B include energized/de-energized inspection and de-energized cleaning. While the equipment is in a de-energized state, all bolted connections and cable terminations should be torqued, in accordance with manufacturer specifications.

During de-energized maintenance, molded-case/insulated case circuit breakers should be exercised manually to keep the contacts clean and help the lubrication perform properly. This simple maintenance procedure is often overlooked, and breaker failure is a common result. In addition, breaker testing (primary and secondary injection) and protective relay testing are also recommended. These and other factors must be considered when determining what compliance means and developing an electrical-safety program that satisfies the OSHA and NFPA requirements.

We’ve heard that, “an ounce of prevention is worth a pound of cure.” This phrase should have significant meaning when management is struggling with how to comply with the latest regulations imposed by OSHA as it relates to safety in the workplace.

Among the several elements that make up an effective electrical-safety program, electrical-equipment maintenance is one that cannot be ignored. When the decision is made to have an arc-flash risk assessment performed, consider the condition of maintenance of the electrical equipment and the affect it will have on the results of the risk assessment. This will ensure that employees stay safe and assure management that money appropriated is well utilized. The result of a well-administered electrical-safety program will reduce life-safety risk, cut business interruptions, and extend the life of electrical equipment. MT

Jay Godfrey, CESCP, has more than 25 years of experience in the electrical-contracting industry and is a licensed electrical contractor in Georgia. Godfrey is OSHA trained, NFPA certified and, for the past eight years, has been working as a preventive-maintenance and electrical-safety consultant with Craft Electric & Maintenance, Atlanta.

292

8:12 pm
January 13, 2017
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Cooling Upgrade Increases Efficiency

QTS Realty Trust Inc. owns, operates, or manages data centers and supports more than 1,000 customers. Upgrading fans and controls at one facility through Vertiv (Emerson Network Power) improved efficiency and reduced operating costs.

QTS Realty Trust Inc. owns, operates, or manages data centers and supports more than 1,000 customers. Upgrading fans and controls at one facility through Vertiv (Emerson Network Power) improved efficiency and reduced operating costs.

Variable-speed technology and intelligent controls combine to reduce data-center operating expense.

There are several reasons to consider upgrading your data center’s thermal-management system, including improving capacity management, deferring capital costs, and promoting environmental responsibility. You may simply want to improve energy efficiency and reduce operating costs. In a typical data center, cooling accounts for approximately 38% of total energy consumption.

Regardless of your specific goal, if thermal-system upgrades are on your mind, you are not alone. A recent survey of information technology (IT), facilities, and data center managers in the United States and Canada found that 40% of data centers have been upgraded in the past five years. Twenty percent are in the process of upgrading, and more than 30% would be upgraded in the next 12 months.

Why the surge in thermal-upgrade projects? There is continuous pursuit for higher equipment reliability, greater energy efficiency, additional capacity, and greater insight into performance. What can’t be overlooked is the fast return on investment (ROI) achieved by those who have recently upgraded. One such company is QTS Realty Trust Inc., headquartered in Overland Park, KS. The company owns, operates, or manages 24 data centers and supports more than 1,000 customers with its data-center solutions.

QTS has experienced significant growth over the past 10 years, going from owning a single data center in 2005 to a coast-to-coast portfolio of 12 centers encompassing more than 4.7 million sq. ft. To ensure continued provision of leading-edge services and optimal performance from its newly acquired Sacramento, CA, facility, the company required improved cooling-system efficiency and greater visibility into system performance. An upgrade of fans and controls, using the latest in cooling technology, was warranted to maintain cooling stability, improve efficiency, and reduce costs.

The aim was to generate enough cost savings to yield a full ROI in 2 1/2 yr. At the same time, the company also wanted advanced monitoring capabilities to continue best-practice data-center management.

Solutions

The need for improved system visibility that would allow QTS to provide its customers with more uniform cooling, coupled with the desire for cost savings generated from improved energy efficiency, led the company to upgrade the Sacramento facility. Experiencing a very common energy-efficiency challenge in its data center, employees found that the legacy cooling systems were providing more airflow than was required in one area, while another had a deficit. Installing electrically commutated (EC) fan technology from Emerson Network Power, which is now known as Vertiv (Columbus, OH, vertivco.com) into 64 cooling units would allow cooling adjustments based on load requirements.

Management sought to partner with a company that could complete the project within a fixed five-week timeline with limited use of QTS resources and manpower. Another key challenge was that only a certain number of units could be off at any one time to maintain the level of redundancy required. This stipulation called for careful planning and coordination to ensure the project could be completed within the parameters specified. QTS also wanted to ensure their upgrade was performed by a service provider that had experience configuring the latest technology for business-critical data centers. As the original equipment manufacturer (OEM), Emerson Network Power’s Liebert Services, now part of Vertiv, was chosen to ensure high-quality parts and installation from factory-trained technicians.

Originally electing to only install EC plug fans, QTS management quickly realized it was missing the opportunity to optimize the cooling system for maximum efficiency benefits. Company leaders determined it could better achieve its stability and visibility goals through the addition of the Liebert iCOM control system, which enabled under-floor pressure control through building-management-system (BMS) integration. Wireless sensors were also installed to monitor cooling improvements.

This more holistic approach gave the company added flexibility through multiple configurations inherent to the controls that balance loading in the space. These configurations include control by wireless and remote temperature sensors, advanced supervisory control, or BMS control. QTS now has the option to coordinate fans, perform auto-tuning, and customize staging or sequencing whenever it is needed to further improve energy efficiency, availability, and flexibility.

System configurations include control by wireless and remote temperature sensors, advanced supervisory control, or BMS control. The project was performed within an operating data center and completed on time.

System configurations include control by wireless and remote temperature sensors, advanced supervisory control, or BMS control. The project was performed within an operating data center and completed on time.

Benefits

The entire thermal-system upgrade project, performed within an operating data center, was completed on time without any negative impact on the company or its customers. As a result of the upgrade, QTS earned a $150,000 rebate from the Sacramento Municipal Utility District and initially saved $12,000 a month in energy costs. Additional savings are expected from continued optimization.

In addition to the obvious financial benefits, QTS accomplished the following with its thermal-system upgrade:

• Reduced its carbon footprint with more than 75% immediate reduction in the energy consumption using Liebert thermal-management units

• Improved Power Usage Effectiveness (PUE) by 0.16

• Provided better intelligence to BMS for improved visibility

• Improved uniformity of under-floor static pressure, allowing adjustment of air flow to match equipment loads by changing floor tiles

• Eliminated air leakage through cooling units that were previously off or in standby using the control’s proprietary virtual damper

• Exceeded minimum ROI estimates by 40% and achieved targeted savings sooner than budgeted

• Maximized free cooling through improved unit airflow and cooling control.

According to QTS western region vice president Ken Elkington, the results of the upgrade far exceeded his expectations. “We took amp draw measurements on the existing fans. As soon as we placed the first new EC plug fan into a unit, even at 100 percent speed, the power consumption dropped 30 percent,” he said. “We were very excited to see that result, but then it got even better. By varying the fan speed to match the load in the zone, the power consumption dropped another 33 percent, and we are now experiencing higher-than-expected energy savings.” MT

For more information, visit vertivco.com.

88

5:49 pm
December 22, 2016
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Beware Dirty Power

randmWhether personnel refer to it as a surge, a sag, a spike, a transient, a fluctuation, an interruption, or noise, “dirty power” reflects an abnormality in the electricity that runs a facility.

According to insight from Vertiv, formerly Emerson Network Power (vertivco.com, Columbus, OH), dirty power originates outside of and within a facility. Sources include lightning, utility switching, capacitor switching, and faults on the utility’s distribution system, all of which can affect the quality of power before it even reaches the plant’s internal system.

Vertiv’s experts note that daily fluctuations from internal electrical equipment, such as devices that run in cycles or get turned on and off frequently, can cause cumulative and equally damaging power hazards. Even a small appliance can lead to problems with sensitive equipment that shares the same line. What’s worse, the more electrical equipment a site uses, the more transients accumulate. MT

— Jane Alexander, Managing Editor

screen-shot-2016-12-22-at-11-40-36-am

Click to enlarge.

Vertiv is the new name of the business formerly known as Emerson Network Power. For more information, visit vertivco.com.

397

7:34 pm
June 13, 2016
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Upgrading Legacy Power Systems

Upgrading to new equipment requires careful analysis and planning to avoid extended downtime.

Upgrading to new equipment requires careful analysis and planning to avoid extended downtime.

A Q & A with Danita Knox, GE Energy Connections.

When’s the best time to upgrade a power system? According to Danita Knox of GE Energy Connections, Atlanta, it can vary. Consider the following situations as ideal opportunities:

  • if a facility had or is planning a significant expansion that might affect overall power-system loading
  • if a recent arc-flash study revealed significant incident levels or danger of exposure for electrical workers or operators
  • if personnel are having difficulty locating replacement and spare parts for the site’s electrical system
  • if plant personnel desire better monitoring of the overall power system.

Once the decision has been made to move forward on an upgrade, what’s next? We asked Knox for some insight into what facilities can do to make these projects go smoothly.

MT: What trends in power-system upgrades are you seeing among older installations?

Knox: One trend involves customers replacing older electromechanical relays, meters, and trip units with newer digital “smart” equivalents. This provides a single, multi-function device that incorporates communications (local and network), event logging, and monitoring (graphical screens and remotely using web tools). Critical applications include upgrading to smart switchgear offerings that feature built-in monitoring, diagnostics, redundancy, and remote-control capabilities.

Facilities are also adding devices to their power systems that help locate workers further away from the equipment they operate. This is done, in some cases, by adding remote racking devices to existing breakers or using robot-type devices to operate equipment from a safe distance. We’re seeing more sites updating old fused devices, such as a load interrupter switch, with faster-operating vacuum breakers and relay equivalents that reduce arc-flash incident levels.

Finally, with limited budgets for large capital projects in many plants, it’s essential for them to find ways to extend the life of their existing equipment. To that end, facilities are often looking at retrofit options.

MT: What tips do you have for sites that are embarking on a power system upgrade?

Knox: Ideally, it helps to start with a comprehensive arc-flash study. This can provide remediation suggestions on how to reduce arc-flash exposure levels and improve personnel and equipment safety. To begin an arc flash study, an operation needs an accurate schematic or diagram of the facility. Plant personnel familiar with the electrical system can usually collect the information needed to build this diagram. An accurate schematic also provides critical information that can be a great tool to develop safe and proper LOTO (lock-out/tag-out) practices.

With a thorough arc-flash study, plant operators can then evaluate multiple options that help define steps to start upgrading a power system. Upgrade projects can be prioritized into smaller projects, depending on employee exposure, process needs, available outage periods and budget constraints.

If you’re going to replace old gear with new equipment, such as this ground and test device for Magne-Blast switchgear, be sure to test all critical components prior to the outage. Photo: GE

If you’re going to replace old gear with new equipment, such as this ground and test device for Magne-Blast switchgear, be sure to test all critical components prior to the outage. Photo: GE

MT: To get management buy-in, what’s the best way to estimate the return on investment (ROI) and benefits of an upgrade?

Knox: Often the need to upgrade is based on some failure or electrical incident that has caused downtime, equipment damage, or, worst-case scenario, employee injury.

When you look at the cost associated with downtime and/or injury, it’s fairly easy to calculate ROI if the project is done in a phased approach. Some trip unit, relay, and breaker upgrades can be done under the threshold of a maintenance budget.

MT: Are there any budget-friendly ways to upgrade a legacy system?

Knox: Yes, there are. It’s important to look at upgrade options that solve the most problems with minimal disruption to plant operations and equipment.

Consider, for example, if a single upstream breaker/relay combination in the facility can reduce arc-flash exposure for downstream feeder breakers without upgrading each breaker. Does the site have unused spare breakers that can be rotated out with a local service shop for upgrades that can later be installed during a short outage?

If a plant is updating old relays and meters, it should get new doors with new components prewired. This allows a shorter outage while equipment is being replaced. Also, “replacing the guts” in the existing compartment in a field outage can help reduce upgrade costs, assuming the new equipment has been pre-determined to fit the compartment and it can be easily wired. MT

Danita Knox is senior product manager for Power Delivery Services within GE Energy Connections, headquartered in Atlanta.

Steps to a Successful Power-System Upgrade

According to GE’s Danita Knox, as a site prepares for a power-system upgrade, it’s important to identify and select a reputable vendor that’s experienced, trained, and knowledgeable in designing this type of complex project. A power-system upgrade includes these steps:

  • Budgeting for hardware, software, and labor.
  • Development of a project schedule and careful outage planning for the upgrade.
  • Design of the system and procurement of all components prior to the outage.
  • Labor and logistics planning for the outage to ensure that work is completed on time.
  • Testing of all critical components prior to the outage.
  • Failure mode and effects analysis to plan for challenges during the outage and prepare solutions or workarounds.
  • Site safety and work policy that includes LOTO (lock-out/tag-out) training and documentation.

“During the upgrade,” Knox said, “an experienced project manager with a background in power systems is indispensable. Many facilities operate continuously with infrequent planned outages. Careful planning and execution is required to maximize work and re-energize systems in a timely manner.”

Knox advises creating a detailed schedule and work procedures early on, including planning types of labor and required skill-sets and procuring all materials well in advance. “Regarding procurement,” she cautioned, “be careful to consider smaller items, such as personal protective equipment and installation components. If these small details are missed in outage planning, they can create schedule slippage, safety risks, or technical errors while limiting the amount of work accomplished.”

367

3:39 am
April 11, 2016
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Loadability Studies Aid PRC-025-1 Compliance

Regulatory requirements governing Bulk Electric System (BES) power-generation owners and operators are expected to significantly increase the volume of work related to analyzing, implementing, and testing protective relays at sites.

Regulatory requirements governing Bulk Electric System (BES) power-generation owners and operators are expected to significantly increase the volume of work related to analyzing, implementing, and testing protective relays at sites.

While Bulk Electric System power-generation facilities have until 2019 to conform to the PRC-025-1 standard, early adopters can begin capturing a range of benefits now.

By Jane Alexander, Managing Editor

In August 2003, an electric power blackout across the northeast United States and Ontario, Canada, affected an estimated 50 million people. Analysis of this and other major disturbances over the past 25 years has revealed generators tripped for conditions that did not pose a direct risk to those units and associated equipment.

As a result, the North American Electric Reliability Corp. (NERC), Atlanta, created the PRC-025-1 Generator Relay Loadability Standard. According to Steve Nollette, supervising engineer for Emerson Network Power’s Electrical Reliability Services, Columbus, OH, the intent of the standard is to increase grid stability during system disturbances by reducing unnecessary tripping of generators or the number of “misoperations” caused by incorrect settings, logic, or design errors.

The Federal Energy Regulatory Commission (FERC), Washington, has launched a campaign designed to reduce misoperations by 25%, including implementation of standardized setting methodologies such as PRC-025-1, which is currently enforceable.

Bulk Electric System (BES) generation facilities, according to the NERC definition, are required to conform to PRC-025-1 by October 2019. Nollette explained that, while this seems like ample time, facilities should begin planning a loadability study now to reap the following benefits associated with early adoption and, thus, avoid the costly consequences of delay or noncompliance.

Better access to engineering resources. As regulatory requirements governing operations continue to change, single generation sites that operate with limited engineering resources may need assistance from external or outsourced resources such as contractors, who can perform the highly technical tasks needed to meet the new regulatory requirements. While multi-site generation entities often already utilize an engineering team specializing in matters pertaining to NERC compliance, they may also need assistance due to the volume of work related to analyzing, implementing, and testing all of their protective relays.

“The economic laws of supply and demand dictate that, as a deadline approaches and more generation plants rush to seek out contract assistance, the available supply of contractors and engineering firms will dwindle,” Nollette said. “This translates into higher costs and potentially lower quality. Early adopters will have access to greater engineering resources at lower costs.”

Less business interruption. For generation sites that have completed a system assessment and require changes to the load-sensitive protective relay settings, implementation and testing will need to be scheduled, requiring a maintenance outage. When a loadability study is performed earlier, there is a greater ability to schedule the implementation and testing during a planned outage rather than having to schedule a separate maintenance outage. Nollette explained that planned outages are typically part of a forecast and budget while unplanned maintenance outages typically incur additional unexpected costs and are disruptive to normal operations.

More time for special cases. In some instances, an existing relay system may not be capable of using the settings required by NERC PRC-025-1. In these special cases, the deadline for compliance is extended by two years to allow retrofit of the existing protective-relay system. As Nollette pointed out, this is a significant engineering effort that is best performed carefully, with sufficient time and resources. Early adopters will have the benefit of adequate time to plan, budget, engineer, remove, install, and test the new protective relays.

Planning, executing loadability studies

The complexity and amount of effort required to perform a generator loadability study, according to PRC-025-1, can vary widely depending upon system design, configuration, age, and documentation. Generation facilities should already be developing plans of action to meet the compliance deadline.

Start by determining if outside engineering help is needed. It’s likely that most generator owners (GOs) and generator operators (GOPs) already understand the make-up of their technical resources. Determining if external resources are needed to supplement compliance efforts could be as simple as not having enough staff for the number of facilities requiring assessment.

Determine the scope of your study. “Most engineers, facing PRC-025-1 compliance considerations for the first time, will need to exert significant time and effort to learn the new standard and how it applies to their site,” Nollette said. “To determine the scope of their efforts, GOs and GOPs need to evaluate which of their protective relays require analysis and how close they are to compliance.”

The first step in determining the scope is to gather generation-unit data, which will be used throughout the assessment process. Collecting this basic generation-unit information will provide a preview for the amount of work that will be needed. 

Nollette stated that required information can be found in the following documents: one-line drawings, three-line drawings, protective relay settings, relay test reports, and component nameplates.

1604floadability02d

Fig. 1. Typical synchronous generator protective-relay system. To help with determining how the standard applies to a given plant, the PRC-025-1 application guidelines illustrate a comprehensive protective relay scheme for a generation unit.

To help with determining how the standard applies to a given plant, the PRC-025-1 application guidelines illustrate a comprehensive protective-relay scheme for a generation unit. However, not all relays illustrated will necessarily exist in every system (see Fig. 1).

Once the generation system protective relays have been sorted into the appropriate options, as seen in Fig. 1, the remaining necessary information is gathered to assess each protective relay’s compliance. This information is also found within the documentation initially gathered for the generation unit data.

Table I. Comparison of Option A to Software Simulation

Table I. Comparison of Option A to Software Simulation

Understand the options available for compliance. NERC PRC-025-1 provides multiple options for setting load-responsive protective relays, as outlined in Attachment 1, Table I of the application guidelines. Each relay may have as many as three options available. Option A is the simplest to apply, but generally results in a less-accurate assessment. Software simulation, referred to as either Option B or Option C in the application guidelines, is more accurate because it models the machine’s reactive-power capability using field forcing simulations.

Compare nameplate data and relay settings with the PRC-025-1 standard to determine compliance. GOs must determine whether or not protective relays within the generation unit meet compliance requirements. The process of comparing as-found settings with the standard will require relay-specific information such as instrument transformer ratios and protective-relay pickup and/or tap values.

Start assessment process early and allot enough time for corrective actions. Whether determining the reactive power rating through conservative calculation (Option A) or through software simulation, corrective actions will likely need to be taken. Actions will include scheduling an outage for the implementation, testing, and documentation of the relay setting changes—all of which can take significant time to complete.

“No matter which compliance option is chosen, any changes to the existing settings should be carefully reviewed by the original-equipment manufacturer (OEM) and the protection engineers who are responsible for upstream coordination, prior to implementation,” Nollette said.

Compile all information to complete the demonstration report. A thorough report for generator loadability will contain all information that was gathered during the assessment phase, supportive calculations from PRC-025-1 application guidelines, results from the software simulations (if performed), and documentation of any corrective actions and testing.

According to Nollette, assimilating reporting characteristics that make the auditing process efficient will contribute to a successful audit with the Electrical Reliability Organization (ERO). Reporting methods that support a searchable document, a linked table of contents, bookmarking, and embedded links to supporting documentation should be an integral part of the demonstration report, Nollette explained.

Achieving NERC PRC-025-1 compliance requires a concerted effort. GOs or GOPs will need to rely heavily on either internal or external engineering
resources, especially when moving beyond the conservative calculations used in Option A to more-accurate software simulations. While these simulations take more time to execute, they ultimately require fewer setting changes for better protection. Nollette concluded that a well-executed compliance plan rewards generating entities with a protected and more stable system and grid.
MT

Steve Nollette is a supervising engineer for Emerson Network Power, Electrical Reliability Services, Columbus, OH. He has more than 20 years of experience performing and managing electrical testing, maintenance, and engineering services.

EDITOR’S NOTE: To help facilities streamline the loadability study process, Emerson’s Electrical Reliability Services team has created a tool that automates the process of comparing settings with standard requirements. Download it at http://bit.ly/1Xqo4I6. For additional assistance, email NERCcompliance@Emerson.com or visit emersonnetwork.com.

431

8:33 pm
January 12, 2016
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You Can’t Manage What You Don’t Measure

Fluids, compressed air, boilers, heat exchangers, and steam systems can waste significant energy in your plant if their performance isn’t constantly monitored and measured.

Fluids, compressed air, boilers, heat exchangers, and steam systems can waste significant energy in your plant if their performance isn’t constantly monitored and measured.

Just how much revenue can your process operations afford to lose?

Shakopee, MN-based Emerson Process Management (emersonprocess.com) has released an Engineer Insight Report to help industrial end-users better understand where and how energy can be saved in their operations. Entitled Top 5 Measurements for Energy Efficiency, it identifies priorities with equipment systems that “should be a concern for any plant-management team looking to gain better insight into process energy use.” The report also details some real-world successes and energy savings realized by other end-users and highlights the measurement technologies they leveraged.

Utility Fluids (metering flow and managing use)

Utility fluids, i.e., water, air, gas, and steam, are the lifeblood of a plant. A shortage of any one of them could lead to a shutdown. Emerson acknowledges that, while every plant is different, for most, it’s reasonable to say, that 5% to 15% of a site’s energy is wasted in the form of lost or misused utility fluids. Metering the flow and managing the use of utility fluids could be an opportunity to save between $1 million and $15 million annually.

Compressed Air (measuring flow to identify leaks and manage use)

Compressed-air systems in plants are major energy users and generally have many leaks and other issues leading to waste. Measuring flow in a compressed-air system helps identify areas of excessive use and ways to better manage overall air use. Measuring air use is best done with several points of flow measurement throughout the system, i.e., at each compressor, at headers, and at major branch lines. More measurement points allow tighter leak control and better management of system health.

Boilers (improving drum-level measurement)

In boilers, the water level in the steam drum must be precisely controlled to optimize steam production, maximize boiler efficiency, and maintain safety. If water levels are too low, there’s a risk of damage to the boiler—and a significant risk of costly boiler trips. If levels are too high, water could be carried with the steam, reducing heat-transfer effectiveness and possibly damaging  downstream turbines. Steam-system performance is most efficient when boiler operation is stable and costly shutdown, purge, and re-start cycles are avoided. According to Emerson experts, reliable drum-level measurements are important in achieving that desired condition.

Heat Exchangers (predicting and detecting fouling)

Process facilities may have hundreds of heat exchangers that can foul over time, directly affecting production capacity, maintenance costs, and energy use. Heat-exchanger fouling is accelerated by many factors, including sediment, corrosion, decomposition, and crystallization. Unfortunately, due to the difficulty and perceived high cost of real-time monitoring, many of these units may only be checked periodically, during field rounds. Operators using visual and manual measurement methods are often challenged to spot signs of contamination and, over time, build-up occurs—impeding heat transfer, reducing throughput, and driving up energy consumption. Energy costs rise when fouling requires additional heat for a needed temperature change.

Steam Systems (monitoring steam traps)

Most industrial plants use steam heat to provide the energy that drives processes. Boilers and steam-distribution lines are the obvious components of these systems. However, critical steam traps, i.e., mechanical valves that let condensed water out of the system while keeping the steam in, are frequently overlooked. A large plant can have thousands. They fail in one of two ways: open or closed. An open trap leaks steam, wasting energy. A closed trap lets condensed water build up in the steam pipe, creating reliability issues and causing “water-hammer” events that can damage the steam system and connected equipment. Steam traps have an average life expectancy of about five years. Regular replacement of failed traps is essential for proper steam-system operation.

Download the complete report, along with a free White Paper entitled Process Energy Efficiency: Measure, Monitor—Then Improve, at emr.sn/Mwn. MT

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