https://emersonexchange365.com/emerson-exchange/The Peer-to-Peer Online Emerson Global Users Exchange Communityen-USTelligent Community 13https://emersonexchange365.com/emerson-exchange/f/event-announcements/7561/how-to-downgrade-from-windows-10-pro-iot-to-windows-7-proSat, 10 Nov 2018 06:56:00 GMTcd40bb2b-3d49-4868-939d-417119b40291:4de1f609-2dda-41aa-bc9b-a8479051a6a7Suresh ThomasDo not have the downgrade DVD for windows 7, is there any steps to follow or need to get the windows 7 DVD from Emerson. please help!!! We haven't received the DVD as it mentioned in the catalogue, the build version as the below Part # : SE2613C01 Compatible DeltaV ™ Revision =12.3.1DeltaVhttps://emersonexchange365.com/emerson-exchange/m/mediagallery/5374Fri, 11 May 2018 09:13:00 GMTcd40bb2b-3d49-4868-939d-417119b40291:93f2893f-eede-4b12-ba39-b623fc3a3856Rami MahjoubaHello! I am an EE student working for the first time on a project using DeltaV 13. Whenever I try to download the workstation, I get this error message popping up: "AB-20180410 DO NOT DOWNLOAD THIS WORKSTATION. Doing so will cause this workstation to become un-configured. This workstation is not running a Remote Client operating system or the Terminal Service is not installed. Delete the Remote Client Sessions on this workstation, uncheck the Enable Remote Client Functionality on this workstation's property dialog and read the DeltaV Remote Client Overview section in DeltaV Books Online." I also had many other problems like commissioning a controller or opening the DeltaV Operate Configure, but I think most of them are caused by the first problem. Can anyone tell me how to fix it? Thanks :)https://emersonexchange365.com/emerson-exchange/b/weblog/posts/video-recap-from-day-4-at-emerson-exchange-1178782779Fri, 28 Oct 2016 13:06:00 GMTcd40bb2b-3d49-4868-939d-417119b40291:f78e2556-589c-446f-af1d-3eb07c4ca471Jim CahillHere are video recaps of days 1 and 2 and day 3 The post Video Recap from Day 4 at Emerson Exchange appeared first on the Emerson Automation Experts blog.Emerson Exchangeeventemrex2016https://emersonexchange365.com/emerson-exchange/b/weblog/posts/video-recap-from-day-4-at-emerson-exchange-2137929916Fri, 28 Oct 2016 13:06:00 GMTcd40bb2b-3d49-4868-939d-417119b40291:a3208550-844b-48e6-98f0-1f1d7f523153Jim CahillHere are video recaps of days 1 and 2 and day 3 Related Posts Wireless for High Temperature Electric Arc Furnace Control At the Emerson Exchange-Physically or Virtually Emerson Exchange Conference Video Highlights from Day 1 and Day Video Recap from Day 3 at Emerson Exchange Renewable Energy Powering Gas Wells and Pipelines Driving Maintenance Workflows with Condition Monitoring The post Video Recap from Day 4 at Emerson Exchange appeared first on the Emerson Automation Experts blog.Emerson Exchangeemrex2016https://emersonexchange365.com/emerson-exchange/b/weblog/posts/video-recap-from-day-4-at-emerson-exchangeFri, 28 Oct 2016 13:06:00 GMTcd40bb2b-3d49-4868-939d-417119b40291:864026ef-a0ba-4650-be47-3c9564d6c425Jim CahillHere are video recaps of days 1 and 2 and day 3 Related Posts Wireless for High Temperature Electric Arc Furnace Control At the Emerson Exchange-Physically or Virtually Emerson Exchange Conference Video Highlights from Day 1 and Day Video Recap from Day 3 at Emerson Exchange Renewable Energy Powering Gas Wells and Pipelines Driving Maintenance Workflows with Condition Monitoring The post Video Recap from Day 4 at Emerson Exchange appeared first on the Emerson Process Experts blog.Emerson Exchangeemrex2016https://emersonexchange365.com/emerson-exchange/b/weblog/posts/best-in-conference-award-winners-namedFri, 28 Oct 2016 02:32:00 GMTcd40bb2b-3d49-4868-939d-417119b40291:f0b640f5-18bb-4f1e-8575-41cf4fe36ae9Emerson Exchange Newsby Jim Montague One of the unfailing highlights of Emerson Global Users Exchange are the Best in Conference Awards for its very finest conference sessions, and the winning presentations for 2016 were no exception. Five teams won awards in the conference's main categories, and accepted their crystal plaques at lunch on the event's fourth day this week in Austin. Texas. The record-breaking 800 session proposals received earlier this year by the Emerson Exchange Board of Directors were narrowed down by the board and its conference subcommittee into the 320 sessions presented this week, and just five were chosen as best in conference. "We look for presentations that tell a good story, define a significant problem, and detail its solution," said Robert Sentz, vice chairman of the 2016 Emerson Global Users Exchange, and instrumentation and controls engineers, 3M Materials Resource Division. He will serve as chairman next year. "We also want to know the how the solution benefited its users." Solve & Support "Fighting Irish Tackle Alarm Management—Implementing an Alarm Management Program @ UND Power Plant" by Thomas Cole, UND Power Plant, Bill Farmer, Novaspect, and Todd Stauffer, exida UND Power Plant, Novaspect and exida improved the plant's DeltaV alarm system by creating an alarm philosophy document (APD) that could drive consistency and create a common understanding. The alarm configuration was loaded into SILAlarm software, and alarm rationalization was performed. After rationalization, the alarm configuration was imported back into DeltaV to update settings and to populate Alarm Help software. Measure & Analyze "A Wireless Odyssey—from Resistance to Enthusiasm" by Alan Weldon, Hunt Refining, and Donna McClung and Steve Moore, both of Emerson After some initial resistance about wireless, Hunt Refining Co. accepted it for maintenance, added it to other monitoring applications, and has been a leading user of Emerson’s wireless technology for close to a decade, though there were some bumps along the way. In 2007, there was a need to monitor temperature in a hot asphalt tank, so Hunt and Emerson navigated challenges and collaborated to implement wireless safety relief valve monitoring that saved Hunt $170,000. This increased confidence, and since then, Hunt’s network has grown to include many pervasive sensing applications that address safety, environmental, reliability and process needs across the refinery. Implementation of Emerson's AMS and Wireless Snap-On settled any concerns of network reliability and system integration. Operate & Manage "Intelligent Solvent Tank Farm Management" by Matt Rauschke of 3M and Kyle Nystrom and Colin Singer, both of Novaspect 3M and Emerson collaborated to improve 3M’s existing solvent delivery system. The system was migrated from an energy-intensive, pressure-based system to an on-demand system with intelligent monitoring and bookkeeping. The solution was developed through the use of an inventory management system/DeltaV interface, better flow measurement, smart VFD flow calculations, and wireless limit switches. The new system reduced accounting discrepancies, eliminated rail car unloading errors, and provided real-time verification of the piping network integrity using a software-based leak detection system. No transfer errors have occurred since the system was installed, and the solution reduced cost for repurchasing new solvent and disposition of mixed solvents. Final Control & Regulate "Natural Gas Pipeline System Integrity Improvements—Reducing Operational and Financial Risks through Pressure Control Station Reinforcement" by Niko Boskovic and Andrew Loge, both of FortisBC, and Reese Dawes, Spartan Controls Natural gas distributor FortisBC runs a distribution pipeline serving more than 600,000 customers, which is supplied by its large Huntingdon pressure-control station using six parallel 16-in. Fisher V250 control valves. However, its single-station design was identified as being a reliability concern as a single point of failure, so FortisBC and Spartan Controls used Fisher 24-in. V260 control valves, Bettis Gas Hydraulic actuators and ControlWave telemetry to provide complete redundancy, including over-pressure protection, true failsafe, low bleed, remote and local operation, and control performance requirements. The solution met all of the unique project requirements and was tested, installed and commission on-time and on budget. The result is a massive risk reduction for FortisBC. Business Management & Career Development "Better Listening, Better Life—Learn to Listen Like a Pro" by Nikki Bishop and Bruce Smith, both of Emerson This workshop taught attendees simple techniques to learn to listen like pros by focusing on listening and better understanding spoken words. Participants had the opportunity try out new techniques during the session.emrexSolve & Supportbest in conferencehttps://emersonexchange365.com/emerson-exchange/b/weblog/posts/severe-service-isolation-valve-provides-solution-to-leak-through-problem-at-buck-combined-cycleFri, 28 Oct 2016 02:26:00 GMTcd40bb2b-3d49-4868-939d-417119b40291:42204e66-e17e-4e69-b175-f243724ba1cfEmerson Exchange Newsby Paul Studebaker Duke Energy’s Buck Combined Cycle Plant in Rowan County, North Carolina, is a 630-MW facility that burns gas in two combustion turbines and uses their exhaust to generate steam for additional turbine generators. Ever since its startup in 2011, the safety isolation valve on the spray attemperator has been a bad actor. “We replaced it three times between 2011 and 2014, each time at a cost of $10,000,” said Jim Webb, account manager, R.E. Mason, which assisted Duke with the problem. Together with Mark Nymeyer, global marketing communications manager for Fisher flow controls, Emerson Automation Solutions. Webb presented the session, “Emerson Isolation Solution at Buck Combined Cycle,” at Emerson Global Users Exchange in Austin, Texas. “The valve cost $6,000, and installation cost $4,000,” Webb said. Worse, “when leaking, the valves were costing $2,000 per month in thermal performance degradation.” The spray attemperator adds water to high-pressure (HP) steam to cool it to the right temperature to feed it to the turbines. The problem valve is on the line that supplies boiler feedwater to the attemperator, which operates at 350 °F and 3,500 psi. The isolation valve cycles several times each day when the unit is going in or out of load and was failing by destruction of its internal trim parts. Together with Duke Energy, Buck Combined Cycle and Emerson specified and supplied a replacement valve that appears to be solving the problem. The replacement is based on the Fisher Z500 two-piece floating ball valve, which meets leak test criteria of standard AP 598 under both high and low pressure and is available in ½- to 36-in sizes with full or reduced bores in classes 150-4500 (also limited classes). Forged materials are standard. The specified Z500 Severe Service replacement valve includes Inconel 718 internal components, spray-and-fused overlay coating and a double-d shaft. “A pressed-in primary seat was chosen, despite its potential for a leak path because the specifiers wanted it to be able to expand and shrink with temperature without fretting the other internal parts,” said Nymeyer. With a blowout-proof shaft and graphoil packing rings, it is capable of API 598 shutoff in the primary flow direction, and Class 5 under reverse flow. The valve is fitted with a Bettis G Series actuator with two sealed single-pole, double-throw (SPDT) GO proximity switches. The actuator is rated to 176 °F. “It’s heavy and requires some extra support,” Webb said. The new valve was installed on Nov. 1, 2014. As of Jan. 13, it showed a count of 3,166 cycles and no sign of leak-through. “At an ambient temperature of 28 °F, I measured the pipe temperature as 30 °F. That’s complete shutoff,” Webb said. The cumulative cycle count indicates an average of seven cycles per day. “I was shocked that it was still working when it cycles so much.” Along with saving $24,000 per year in thermal performance, the new valve promises to save the plant $10,000 per year in replacement costs. “We have reliable, tight, metal-sealed shutoff,” Webb added. “Emerson provided a quality solution with improved thermal performance that saved a lot of money for the plant.”Final Control & RegulateemrexFisherisolation valveshttps://emersonexchange365.com/emerson-exchange/b/weblog/posts/vision-to-reality-a-roadmap-to-iiotFri, 28 Oct 2016 02:25:00 GMTcd40bb2b-3d49-4868-939d-417119b40291:5de92445-94a8-42b8-8d0d-59c3c75ad2f1Emerson Exchange Newsby Paul Studebaker “The Shell Prelude floating liquefied natural gas (FLNG) is the largest floating thing in the world, six times the size of an aircraft carrier, but it has only 100 people on board caring for it. How can they do this?” asked Jonas Berge, director, applied technology, Emerson Automation Solutions. “A team in Perth, Australia—1,100 miles away—watches over equipment and advises them. Along with the travel, cost and danger savings, those people in Perth get to go home at the end of the day and see their families. What’s that worth?” Berge was speaking to a room packed with attendees of his session, “Modernize Your Plant with IIoT at Your Own Pace,” at the Emerson Global Users Group Exchange 2016 this week in Austin, Texas. “You’ve heard a lot about what people call the Industrial Internet of Things (IIoT),” he said. “Some plants are already benefitting. A classic example is the Shell Malampaya offshore platform in the west Philippine Sea, where smart positioners allow valves to be monitored from onshore. The information also goes to the company intranet, so Shell personnel around the world can log on, see it and help the platform personnel. Remote coal seam gas fields in Australia have gas chromatographs that need to be working and in calibration. “Each day one is not can cost up to $100,000,” Berge said. To check one takes a one- to three-day trip, and they’re usually OK. “Now, with IIoT, we can dial into the chromatographs, check their diagnostics and see which are fine and which need calibration.” That’s worth about $6,000 per saved trip. Emerson also is monitoring chemical plants from a center in Singapore. “Wireless monitors allow us to advise a Denka chemical plant within a couple of days if a steam trap needs service,” Berge said. “In the past, a trap could be leaking steam for a year before they discovered the problem. The program has reduced steam consumption by 7%.” Berge defined six steps to put a plant on the IIoT: 1. Define or install plant-wide digital sensor networks 2. Instrument the assets 3. Deploy predictive analytics software on-premises 4. Review work processes 5. Enable a private internet of things 6. Introduce IIoT business models Pervasive sensing calls for digital networks throughout the plant. “Using 4-20 mA for hundreds or thousands of additional sensors is impractical,” Berge said. “If you have fieldbus already in place, you can use it to add sensors. If not, consider WirelessHART to get additional measurements for reliability, energy efficiency and other uses. Replace manual data entry by automating data collection for applications like vibration, corrosion and power.” Instrument the assets. Consider applications to improve results in reliability (maintenance), efficiency (energy and loss control), operations (productivity), and environmental, health and safety (EHS). “Operations and EHS will mostly be for on-premise consumption,” Berge said. “Reliability and efficiency are candidates for IIoT, where putting it in the cloud makes it possible to involve outside expertise.” You want to install technology with a purpose, not indiscriminately deploy thousands of sensors. “So we conduct a plant modernization audit: Sit down with all the relevant departments and find out what they need,” Berge said. “This is not a site walkdown, just a meeting and interview. Based on that, we can figure out roughly how many sensors, and the network size.” Deploy software applications. Much of the data needs no interpretation, just to be displayed to operators or supervisors. Some needs multiple measurements over time to be combined and calculated, such as a heat exchanger where flow, temperatures and differential pressures are used to determine heat transfer coefficients. “Turn existing equipment into smart, connected assets,” Berge said. “For example, instrument a pump for pressure, flow, seal pressure, motor temperature, power, etc.” Change standard operating procedures. “People have to change their behavior or it’s all no good,” Berge said. The same as you now Google, check Yelp and use a GPS before you set off to find a restaurant, you need to “Google your pump” before you go into the field. Equipment generates alarms--you need alarm management for maintenance similar to what you use for controls. “Set priorities and make alarms actionable, so they tell you what to do,” Berge said. Enable a private intranet of things. Companies can put in centers of excellence to monitor equipment at multiple sites so they don’t need as many experts at each site. A single center can handle sites around the world, and the information is accessed only by company employees. Use an Internet of Things. Outsource to experts such as Emerson and vendors of different types of equipment. “Emerson can now go beyond just giving you a report—we can go there and fix it,” Berge said. “We look only at the equipment information, not process data, so you’re not revealing any process secrets.” There are multiple ways to do the necessary information technology/operations technology (IT/OT) integration—the connection between the instrumentation and the internet. “Generally, both areas of expertise are involved, but there are ways of working around that,” Berge said. IIoT can be independent of the control system, so there is no connection, “like we do with the steam trap monitors at Denka,” Berge said. “It’s completely separate. They didn’t even buy any hardware—not a single screw. We provide the service on a per-point, per-month basis.” In other cases, “We can send historian data directly to the cloud, or we can send up the DCS data,” Berge said. Either way, “We can use ‘data diodes’ so only the desired data leaves, and nothing comes in.” It can all be done on a three-year plan. “If you haven’t already, try wireless, and have us help you do a modernization audit,” Berge said. “Make sure your solution is compatible with your existing equipment—there’s no need to bulldoze your historian or replace what you already have. And get started.”WirelessemrexOperate & ManageIIoTIndustrial Internet of Thingshttps://emersonexchange365.com/emerson-exchange/b/weblog/posts/natural-gas-pipeline-reduces-operation-risk-by-3-4-millionFri, 28 Oct 2016 01:38:00 GMTcd40bb2b-3d49-4868-939d-417119b40291:77a71657-29f7-462f-91f0-6fa7116c8ed7Emerson Exchange Newsby Mike Bacidore FortisBC serves more than one million customers with natural gas and electricity in British Columbia. Almost two-thirds of FortisBC’s customer base is located in the greater Vancouver area and on Vancouver Island. “We wanted to show how important [failuer risks] are to the organization, so we created a risk analysis of our transmission assets and prioritized our work,” Loge said. “Risk is the probability of failure multiplied by the consequence of that failure. Because of a lack of redundancy in the pipe, it was a high consequence.” Ensuring the security of supply was top priority. “We wanted to remove any single point of failure in the station,” Andrew Loge, Manager of Engineerring at FortisBC, explained. “We wanted remote operation and wanted to meet the current design standards for seismic requirements. The station was orginally built in the 1950s and ’60s, but has been upgraded throughout the years.” Numerous stakeholders, including the operations group, engineering and asset management, gathered together and brainstormed how to meet the objectives, which yielded four viable options. “First, we looked at operations and maintenance changes—manning the station to monitor operations and increase response times, inspect existing pipe condition and recoat pipe to industry best practices to deter external corrosion,” said Loge. “But, if we found a flaw on a nonredundant piece of pipe, how do we fix it without disrupting service?” The second option was making station modifications, such as installing new pipe and four new block valves. It still left a small section of inlet piping as a single point of failure. The third option, an internal station bypass, would remove all single-point-of-failure pipe and valves from the complex. “The bypass would be decoupled from the facility, and it would cost about $8.6 million,” explained Loge. An external station bypass, the fourth option, would locate a new control station and pipeline externally for 100% redundancy and system resiliency. “It would be completely decoupled and the cost estimate was well above $40 million,” said Loge. “Options 3 and 4 met all of the objectives we had,” Loge explained. “Then we did a financial analysis. We looked at the project cost and the risk analysis. These two options both had more than 99% reduction in risk, so we decided on the internal station bypass because the cost was $32 million less. Then we went back to our engineering group and explained project objectives.” At this point Spartan Controls, an Emerson local business partner, was brought in to assist the engineering group with design and execution of the project. “The process needed performance over a wide range of flows,” said Reese Dawes, account manager at Spartan. “Noise was also a consideration because there are local residents and wildlife around the station. Emission standards are becoming very stringent, so environmental concerns needed to be addressed, too.” One objective was to optimize the real estate. “There was space around the station, but there wasn’t a lot of room to expand,” explained Dawes. “Any solution from a control-valve standpoint needed to be a small envelope. We needed to keep it in a single-valve train. Overpressure protection was critical. FortisBC wanted fail-safe and continued operation, so we needed to go through all the modes.” The gas supply that feeds into the station from the transmission line is unodorized gas, so at that point it’s all odorized for leak detection. “We needed accurate control from varying inlet pressures and flows,” said Dawes. “We looked at 30-year projected flow. We also wanted to reduce the differential pressure in the wide-open position across the system.” For environmental considerations, Fisher low-bleed current-to-pressure transducers and pneumatic positioners were used. “It also became important when we talked about overpressurization strategies,” explained Dawes. “These are large pipelines and releasing into the atmosphere is not safe. We landed on a monitoring device for overpressure protection. The monitor measures the downstream pressure.” The project team then identified all of the failure methods for components, including loss of instrument air, power, PLC and RTU, instrumentation failure and main valve failure. “We included a redundant power gas backup for loss of air,” Dawes said. “For loss of power, PLC or RTU communication, the centralized gas control center can manipulate these. If any of those were lost, we do have the ability to do local control, which is why we used pneumatic positioners, so we could manually load the system and control it without any electronics.” The project was completed on time and on budget in December 2015. Single-point-of-failure operation risk was reduced by an estimated $3.4 million/year.pipelinesemrexOperate & ManagegasFortisBCutilitieshttps://emersonexchange365.com/emerson-exchange/b/weblog/posts/spam-be-gone-monsanto-tames-nuisance-alertsFri, 28 Oct 2016 00:59:00 GMTcd40bb2b-3d49-4868-939d-417119b40291:eb078cbd-633d-4483-af6a-133ea53460dcEmerson Exchange Newsby Dave Perkon "Sometimes, taking advantage of status and diagnostics in intelligent devices can inundate you,” began Joel Holmes, site electrical reliability engineer at Monsanto’s manufacturing facility in Muscatine, Iowa. “A single instrument failure can result in six or more alerts. So, instead of sorting through a mountain of nuisance alerts, use AMS Device Manager to rid your system of spam information so you can focus your attention on more important decisions." Holmes, employed by Monsanto for more than 23 years, also supports the enterprise globally with respect to Emerson’s AMS solution. In the context of a workshop focused on taming nuisance alerts this week at the Emerson Global Users Exchange in Austin, Texas, he discussed the use of Alert Monitor, which he described as the predictive component within Emerson's AMS Device Manager software application. He also discussed solutions provided in AMS Device Manager v13.1.1 upgrade and gave actual results of a pilot program underway at the Monsanto plant. He also discussed optimization and enhancements discovered along the way. Monsanto Muscatine, located in southeast Iowa along the Mississippi river, primarily manufacturers and packages Roundup herbicide at its 150-acre, 450-employee facility. This 24/7/365 operation produces 70% of North America's Roundup herbicide. The AMS Device Manager at the Monsanto plant is a distributed application that encompasses multiple DeltaV domains and a legacy PROVOX system. AMS is integrated with its distributed control systems and includes more than 1,700 HART protocol tags and more than 125 FOUNDATION fieldbus tags. There are multiple device family clusters spread throughout the facility. "Imagine the amount of information that is coming in to our Alert Monitor, including status and diagnostic information," said Holmes. "The data is flooding our system. It's not just one area, it's the entire plant." What Is a Device Nuisance Alert? "Manufacturers provide a multitude of information from intelligent devices right out of the box which is great," said Holmes. "Unfortunately, much of the information does not add value, often is redundant to the root cause, or it's cryptic,” Holmes said. “We had a mountain of information coming in to our system—well over 100 device alerts a day." Monsanto needed to be able to make reasonable use of the data coming into its systems. To highlight a nuisance alert, Holmes provided an example of a dual element, hot backup temperature sensor. "An alert was simulated by lifting a wire," explained Holmes. "As a result, with v12 and v13 of Device Manager, a total of six device alerts occurred due to this single instance. After the upgrade, with the new v13.1.1 of Device Manager, you get just the information that adds value: sensor open and hot backup active. This results in an 83% reduction in actual generated alerts for this one incident." Optimization and Enhancements By optimizing the device toolkit installations, more usable information is available to act on. "There is less noise in your system that you will need to deal with, enabling you to get to the core issues your plant is experiencing," said Holmes. "It's all about usable information instead of too much information—which is often ignored." Optimization of the device install toolkits is a major portion of the upgrade. It eliminates the noise and spam in the data that the manufacturers originally provided with their intelligent devices. "A quick snapshot of our pilot system showed a small number of devices were generating a large amount of spam in the system," said Holmes. "A dozen device types were generating over 90% of our alerts. Additionally, we had only 10 individual devices that were causing more than 40% of those alerts. The top 20 accounted for 80% of all the alerts we saw. We were able to eliminate more than 50% of those instances because they were redundant or did not add information of value." One key objective of the AMS Device Manager V13.1.1 upgrade was to make it as efficient and simple as possible to get up and running at users’ sites. Over 120 device descriptor files were upgraded. Other additions include an auto-sorting feature to help set up the Alert Monitor configuration, and a default capability to simplify configuration. The results of the Monsanto pilot project are impressive. "Through our initial testing, we predicted we could achieve a 60% reduction of device alerts within Alert Monitor," said Holmes. "The actual results were well beyond that. We actually realized an 82% reduction in device nuisance alerts and a 71% reduction of device tags that were part of those issues. It made me more efficient at my job, and more improvements are planned for the future."AlarmsAMSMonsantoemrexOperate & ManageDeltaVhttps://emersonexchange365.com/emerson-exchange/b/weblog/posts/exxonmobil-rotterdam-expansion-saves-with-emersonFri, 28 Oct 2016 00:40:00 GMTcd40bb2b-3d49-4868-939d-417119b40291:77422182-34b0-4877-a223-bff624ab7b13Emerson Exchange Newsby Jim Montague It's good to get your ducks in a row, but, if you happen to be expanding ExxonMobil's Rotterdam Advanced Hydrocracker (RAHC), that's about a million ducks, so it might be good to get some help. To streamline its project management and procurement process to help to mitigate risk and accelerate deployment on the $1.2-billion brownfield project, ExxonMobil is using an innovative main instrument vendor (MIV) approach. This program relies on Emerson Automation Solutions to go well beyond the typical supplier role and participate in a global framework agreement with standardized parts and models, pre-fixed pricing structures, coordinated specification and procurement and verified testing and commissioning. The MIV also works closely with Fluor, which is the project's engineering and procurement construction (EPC) company. It handles engineer documents, loop diagrams and other essential tasks. The RAHC expansion is presently in the detail engineering stage, and it is expected to begin construction late in 2017. It will expand Rotterdam's hydrocracker to upgrade heavier byproducts to lighter, higher-value products, such as EHC Group II base stacks and ultra-low-sulfur diesel. This expansion builds on recent, similar projects at ExxonMobil's facilities in Baytown, Texas, and Singapore, which produce EHC Group II. Amit Verma, instrument group lead, safety and automated systems, ExxonMobil Research & Engineering, and Steve Newton, global account manager, Rosemount, Emerson Automation Solutions, presented "Top 10 ways ExxonMobil mitigated project risks on Rotterdam hydrocracker project" at the Emerson Global Users Exchange in Austin, Texas. Instrumentation project risks Before developing its MIV program, ExxonMobil faced an array of issues and risks that threatened to complicate and delay its RAHC project. Verma reported these include accelerated project schedule, coordinating multiple instrument vendors, project management/vendor stewardship, resource limits, quality control, cost controls, process data quality, getting specification right the first time, managing change orders and construction and commissioning. "It can be a struggle to get the right people on projects, but we and the EPC were also facing accelerated and compressed schedules, interfacing with many vendors," said Verma. "There are just a lot of challenges on this project and additional risks caused by its accelerated schedule. These include added manpower needed for developing multiple specifications, increased engineering burden on the EPC and ExxonMobil, managing procurement and lead times and speeding up bid evaluations. However, the resources for coordinating and completing all these tasks are limited, and the risk is something may slip somewhere, increasing costs and delaying the schedule." Traditionally, ExxonMobil and its EPC used multiple vendors, which multiplied their project management, project execution and procurement interfaces. This made them all more complex; increased administrative liability for procurement, expediters and engineers; led to ineffective order tracking; and required stewardship by multiple field contractors. "The more vendors we had, the thinner the resources we had to cover them, but we had to ensure adequate resources for us and the EPC without jeopardizing product quality and the schedule," explained Verma. "So, we developed a technical readiness process and a global framework agreement, which standardizes equipment parts and models on an approved manufacturer list (AML), and sets up a pre-agreed/fixed pricing structure. We're also striving to get more process performance data for devices right the first time to minimize change orders and costs." Settling on one MIV To simplify supplier support with one-stop shopping, reduce configuration and calibration errors and manage multiple remaining vendors, ExxonMobil also appointed Emerson as its MIV, lead project manager and single point of contact for the RAHC expansion project. Consequently, Newton reported that Emerson hired its own dedicated project manager for the Rotterdam project, added offices at ExxonMobil, embedded more staff with its client and made sure its valve selection tool matched ExxonMobil's tool. Besides project management, Emerson supplies not only its own products, but also brings in third-party devices in accordance with a predefined list from ExxonMobil. "Being an MIV allows us to embed more experts with our EPC team and ExxonMobil, and so everyone was able to collaborate more quickly under one roof," said Newton. "This enabled more efficient project stewardship, and let us cut six or seven months off our schedule by combining instrumentation requirements into one package and removing former requirements for competitive bidding, which translated to more dollar savings," added Verma. "This also allowed us to focus resources on technical selection, rather than bid evaluations, and reduce vendor interfaces, meetings and the EPC's administrative project management burden. This was much easier than all the phone calls and emails we had before.” "Besides coordinating testing documentation and logistics, having an MIV enabled more focused review meetings on process data with Intergraph's SmartPlant Instrumentation (SPI) software for QA reviews," added Verma. "It also allows deep dives by the MIV into control valve data and review cycles. This let us make sure process data was right, so the correct valves were selected before PO placement, and allow standardization across all valve orders. We also achieved standardization and approval during front-end engineering design (FEED) and further minimized change orders. "Using the MIV format really took our relationship with Emerson one step further, and bringing Emerson's project management expertise onboard further extended our efficiencies,” said Verma. “We'll refine this model as we go forward, but we're definitely going to do more of it in the future."ExxonMobilemrexSolve & SupportFlourMIVProject Managementhttps://emersonexchange365.com/emerson-exchange/b/weblog/posts/mexican-energy-company-resurrects-oil-platform-with-increased-productionThu, 27 Oct 2016 21:10:00 GMTcd40bb2b-3d49-4868-939d-417119b40291:c7819f78-2e46-4bd1-a72a-9a56b662aaffEmerson Exchange NewsBy Mike Bacidore When the Abkatun-A permanent platform exploded and collapsed in April 2015, the operator, Mexican state energy company Pemex, couldn’t get it back into production quickly enough. “Abkatun-A platform was built in the Gulf of Mexico in the early 1980s,” explained Ana Matute Portillo, Emerson marketing communications manager in the region. “The oil complex of six integrated platforms is 80 km off the coast of Carmen in Campeche. The production capacity is 380,000 bbl/day of light oil and 250,000 bbl/day of heavy oil, along with 630 million standard cubic feet/day of sour gas.” Mexico is the world’s tenth largest oil producer, and when the Abkatun-A platform went dark, Pemex deferred 220,000 bbl/day of oil. “Stopped production has a cost of $8 million/day, or $240 million/month,” explained Portillo at the Emerson Global Users Exchange this week in Austin, Texas. “Around this complex, there are many field productions,” explained Fernando Mirafuentes, solutions manager, Emerson. “A lot of pipelines converge to the complex. The production is collected at the linking platform and sent to the temporary platform and then to the permanent platform where there’s a separation of oil and gas. This platform is capable of pumping 750,000 bbl/day of oil. The challenge to rebuild the platform was incredible.” Pemex needed to get the platform back in production and targeted December 2015 as the date, but it also wanted to increase production with the rebuild. “Pemex had two different concerns—to restart production and to increase production. And July 2015 was when the bidding process started.” The operator wanted to restart the entire platform at the same time and not receive single parts of the solution at different times. “The scope included supply, installation and startup,” explained Mirafuentes. “They preferred one company to supply the whole solution for automation, system and safety in one package. The challenge was not easy.” Two competitors had an installed base in the complex. “They had three companies participating in the bidding—Invensys, Emerson Automation Solutions and Rockwell Automation,” said Portillo. “Pemex was looking not only for product, but for a supplier that could work with them in a super-short period of time. They were looking for a company with experience.” Emerson was assigned the automation and given just three months to execute. “We provided and executed the entire project,” explained Portillo. “When restarting the platform, we also established the basis for increasing production.” In the first phase of the project, the instrumentation was integrated in the factory. “The scope was to supply systems, supply DCS instrumentation, supply fire & gas instrumentation, supply emergency shutdown (ESD) instrumentation and install, commission and start up,” explained Mirafuentes. “The second phase was an extension of project. The real challenge was the installation in the field.” This solution was only for the permanent platform. But in Phase III Pemex wanted to replicate the system on all platforms in the Abkatun Complex. “We were able to restart operations in 70 days, even though the schedule was for 90,” said Portillo. “The investment was paid off in a few hours. As a result of the rehabilitation, they implemented a new separator and Pemex was able to increase production to 30,000 bbl/day.”OffshorePEMEXoil and gasemrexOperate & Managehttps://emersonexchange365.com/emerson-exchange/b/weblog/posts/prevent-downtime-and-ensure-safety-with-isolated-instrument-groundsThu, 27 Oct 2016 19:15:00 GMTcd40bb2b-3d49-4868-939d-417119b40291:bf41e011-cee9-4c12-99fc-2c271f204fe4Emerson Exchange Newsby Paul Studebaker From the days of Westinghouse and Edison, when “power distribution” was by a single, naked copper wire strung through trees and around glass knobs, to today’s civilization, which would not be possible without computers and tablets, people have struggled and died to provide adequate grounding systems. “The electrical intersection of man and machine has resulted in injuries and deaths,” said Terry Colleran, international expert, DCS, instrumentation and process control, Air Liquide. Improper grounding also leads to early demise of many control system components. Together with Jesse Godwin, service specialist, Control Southern, Colleran presented the session, “Grounding vs Grounding: What’s the Difference?” at the Emerson Global Users Exchange 2016, this week in Austin, Texas. Today’s automation systems use transistors and integrated circuits, components whose lives can be reduced or ended by capacitive discharge, overvoltage and power supply AC ripple. A capacitive or static electricity discharge that jumps a ¼-in gap at less than 60% relative humidity is 10,000 volts. “Wires store electrons. The amount depends mainly on the length of the wire, just like a capacitor,” Colleran said. When the capacitance is exceeded, the voltage discharges. Surges and arcs are caused by motor starts and stops, RF transmitters, proximity to wires carrying more than 50 VAC, and of course, lightning. “Unless constantly drained away to ground, electrons gather in wires until the capacitance is exceeded,” he said. Beware AC ripple on DC power—“sour power, we call it,” Colleran said. You’ll have more or less, depending on the rectification and power quality. “Capacitor filters prevent problems, but they deteriorate. Replace them every five to seven years.” Three volts of ripple means the 24 VDC electronics will see only 21 VDC, and will draw higher current. “Higher current means more heat, more resistance, and more current draw—a vicious cycle,” he said. Protective vs Instrument Grounds A proper plan requires two separate grounds, a protective earth (PE) ground for power, and an isolated ground for instrumentation. “Both must be at the same potential to protect man—a technician might touch both ground bars in a cabinet—so the National Electrical Code requires ‘at least one connection,’ but they are not the same thing,” Colleran said. Provide PE grounds in the form of a triad—a set of three rods spaced so the Hall-effect areas intersect to maximize current capacity. Use a separate, star point ground, and connect all the instrument grounds to it. “Then provide only one connection between the star point and the triad. Do not connect the power and instrument grounds in the cabinets. If you do, you don’t have a separate instrument ground.” “You think electricity takes the path of least resistance, but it doesn’t. It takes all the paths. So in a lighting strike, it burns through everything. Wires, steel structure, the voltage in everything goes high, then over time, it dissipates,” Colleran said. “You want the lighting to go to ground first and mainly through the triad, so keep instruments isolated.” The effectiveness of ground depends on the quality of the substrate—the soil beneath and around the facility in contact with ground rods. The conductivity of many substrates is bad and varies with time, seasons and weather. “When the plant is built, they take one sample at one time, 30 inches down,” Colleran said. “Sandy soils resist taking a charge.” Plants built on sandy soil, chert (flint) and loam, like many in the southeast and southern U.S., experience increased instrument failures during dry seasons and droughts when soil water content is low. Electrical events can cause sealed controls—contacts don’t open, safety systems actuate, equipment operates “in an uncontrolled manner, causing destruction of machinery and property, and sometimes loss of life,” Colleran said. “What’s the cost of a tripped process? The estimated cost of a life is more than $10 million, a good triad and star point cost about $3,000.”GroundingSolve & SupportAir LiquidePowerhttps://emersonexchange365.com/emerson-exchange/b/weblog/posts/steam-management-and-optimization-1258674579Thu, 27 Oct 2016 16:55:00 GMTcd40bb2b-3d49-4868-939d-417119b40291:2676dd04-a8f4-49de-9dd1-4e797d350e10Jim CahillAt the Emerson Exchange conference in Austin, Emerson’s Jim Dunbar presented Steam Management and Optimization. His abstract: Sipchem facility includes utility plant supplying steam to seven downstream production plants. Utility plant was struggling with reliability issues that had caused a ripple effect throughout the entire facility causing significant production loss. SipChem consulted Emerson and based on recommendations; SmartProcess Header solution was implemented along with improved control strategy and conceptual design for steam load shedding solution. Project was implemented online with no disturbance to plant operation and has delivered a robust and reliable plant wide master header control. Jim opened describing the project. Centralized utilities produce steam and power for the complex. It includes 5 boilers and the goal was to enhance plant master responsiveness to plant upsets and improve combustion air controls. The project was done in two phases with 2 boilers in phase 1 and 3 boilers in phase 2. What was happening is if they had a large upset or trip in the facility the steam headers from the boilers would fight each other and not smoothly handle the upset. The unit trips could ultimately lead to boiler trips. The goal was to improve stability, reliability and availability and make the plant more agile to changes. By optimizing the controls, fuel usage would be reduced and controls simplified for the operators. The project was done while the plant was running. The first step of the project was to create a medium fidelity simulation of the steam headers and boilers. This allowed scenarios to be performed to see how the control strategy would react to various unit upsets. This work was done on virtual machines including the simulation of the DeltaV control system. Jim noted that he could work on the control strategy while traveling to the site on the plane on his laptop. A detailed implementation plan was developed and presented to the petrochemical producer staff for review and approval. The control strategy takes the demand requirements of the plant to a main net energy controller which talks to each boiler control master. Ultimately the demand gets divided to each of the boilers on a proportional basis. The plant master provides total net energy demand for all boilers and the net energy controller allocates and balances total net energy demand between boilers. It considers all boiler limits, ramping capability and efficiency. Here’s the architecture of the solution: The solution includes boiler net energy optimization, total boiler net energy control and net energy limiting. The was a dashboard for the operators showing the optimum operating range for each boiler based on current plant steam demand. You can connect and interact with other optimization experts in the Improve & Modernize group in the Emerson Exchange 365 community. The post Steam Management and Optimization appeared first on the Emerson Automation Experts blog.Services, Consulting & TrainingJim DunbarSolve & SupportEnergyemrex2016Improve & Modernizehttps://emersonexchange365.com/emerson-exchange/b/weblog/posts/steam-management-and-optimization-367905030Thu, 27 Oct 2016 16:55:00 GMTcd40bb2b-3d49-4868-939d-417119b40291:4348a875-3fae-446a-9b1a-3ab2e5c8e80eJim CahillAt the Emerson Exchange conference in Austin, Emerson’s Jim Dunbar presented Steam Management and Optimization. His abstract: Sipchem facility includes utility plant supplying steam to seven downstream production plants. Utility plant was struggling with reliability issues that had caused a ripple effect throughout the entire facility causing significant production loss. SipChem consulted Emerson and based on recommendations; SmartProcess Header solution was implemented along with improved control strategy and conceptual design for steam load shedding solution. Project was implemented online with no disturbance to plant operation and has delivered a robust and reliable plant wide master header control. Jim opened describing the project. Centralized utilities produce steam and power for the complex. It includes 5 boilers and the goal was to enhance plant master responsiveness to plant upsets and improve combustion air controls. The project was done in two phases with 2 boilers in phase 1 and 3 boilers in phase 2. What was happening is if they had a large upset or trip in the facility the steam headers from the boilers would fight each other and not smoothly handle the upset. The unit trips could ultimately lead to boiler trips. The goal was to improve stability, reliability and availability and make the plant more agile to changes. By optimizing the controls, fuel usage would be reduced and controls simplified for the operators. The project was done while the plant was running. The first step of the project was to create a medium fidelity simulation of the steam headers and boilers. This allowed scenarios to be performed to see how the control strategy would react to various unit upsets. This work was done on virtual machines including the simulation of the DeltaV control system. Jim noted that he could work on the control strategy while traveling to the site on the plane on his laptop. A detailed implementation plan was developed and presented to the petrochemical producer staff for review and approval. The control strategy takes the demand requirements of the plant to a main net energy controller which talks to each boiler control master. Ultimately the demand gets divided to each of the boilers on a proportional basis. The plant master provides total net energy demand for all boilers and the net energy controller allocates and balances total net energy demand between boilers. It considers all boiler limits, ramping capability and efficiency. Here’s the architecture of the solution: The solution includes boiler net energy optimization, total boiler net energy control and net energy limiting. The was a dashboard for the operators showing the optimum operating range for each boiler based on current plant steam demand. You can connect and interact with other optimization experts in the Improve & Modernize group in the Emerson Exchange 365 community. The post Steam Management and Optimization appeared first on the Emerson Automation Experts blog.Industrial Energy & Onsite UtilitiesServices, Consulting & TrainingJim DunbarSolve & Supportemrex2016Improve & Modernizehttps://emersonexchange365.com/emerson-exchange/b/weblog/posts/steam-management-and-optimizationThu, 27 Oct 2016 16:55:00 GMTcd40bb2b-3d49-4868-939d-417119b40291:a433f443-e1c7-4c45-945b-96ac4cb6d09eJim CahillAt the Emerson Exchange conference in Austin, Emerson’s Jim Dunbar presented Steam Management and Optimization. His abstract: Sipchem facility includes utility plant supplying steam to seven downstream production plants. Utility plant was struggling with reliability issues that had caused a ripple effect throughout the entire facility causing significant production loss. SipChem consulted Emerson and based on recommendations; SmartProcess Header solution was implemented along with improved control strategy and conceptual design for steam load shedding solution. Project was implemented online with no disturbance to plant operation and has delivered a robust and reliable plant wide master header control. Jim opened describing the project. Centralized utilities produce steam and power for the complex. It includes 5 boilers and the goal was to enhance plant master responsiveness to plant upsets and improve combustion air controls. The project was done in two phases with 2 boilers in phase 1 and 3 boilers in phase 2. What was happening is if they had a large upset or trip in the facility the steam headers from the boilers would fight each other and not smoothly handle the upset. The unit trips could ultimately lead to boiler trips. The goal was to improve stability, reliability and availability and make the plant more agile to changes. By optimizing the controls, fuel usage would be reduced and controls simplified for the operators. The project was done while the plant was running. The first step of the project was to create a medium fidelity simulation of the steam headers and boilers. This allowed scenarios to be performed to see how the control strategy would react to various unit upsets. This work was done on virtual machines including the simulation of the DeltaV control system. Jim noted that he could work on the control strategy while traveling to the site on the plane on his laptop. A detailed implementation plan was developed and presented to the petrochemical producer staff for review and approval. The control strategy takes the demand requirements of the plant to a main net energy controller which talks to each boiler control master. Ultimately the demand gets divided to each of the boilers on a proportional basis. The plant master provides total net energy demand for all boilers and the net energy controller allocates and balances total net energy demand between boilers. It considers all boiler limits, ramping capability and efficiency. Here’s the architecture of the solution: The solution includes boiler net energy optimization, total boiler net energy control and net energy limiting. The was a dashboard for the operators showing the optimum operating range for each boiler based on current plant steam demand. You can connect and interact with other optimization experts in the Improve & Modernize group in the Emerson Exchange 365 community. Related Posts Optimizing Sugar Mill Boiler Performance Model Predictive Control Tips & Techniques Preview What is Operational Certainty? Business Results Optimizing Delayed Coker Operations Achieving Operational Excellence through Automation Inputs for Developing Control System Migration Strategies The post Steam Management and Optimization appeared first on the Emerson Process Experts blog.Process OptimizationJim DunbarSolve & SupportEnergyemrex2016Improve & Modernizehttps://emersonexchange365.com/emerson-exchange/b/weblog/posts/steam-management-and-optimization-1941628784Thu, 27 Oct 2016 16:55:00 GMTcd40bb2b-3d49-4868-939d-417119b40291:9c8ff5b3-1220-4b82-8b31-aadd8243e026Jim CahillAt the Emerson Exchange conference in Austin, Emerson’s Jim Dunbar presented Steam Management and Optimization. His abstract: Sipchem facility includes utility plant supplying steam to seven downstream production plants. Utility plant was struggling with reliability issues that had caused a ripple effect throughout the entire facility causing significant production loss. SipChem consulted Emerson and based on recommendations; SmartProcess Header solution was implemented along with improved control strategy and conceptual design for steam load shedding solution. Project was implemented online with no disturbance to plant operation and has delivered a robust and reliable plant wide master header control. Jim opened describing the project. Centralized utilities produce steam and power for the complex. It includes 5 boilers and the goal was to enhance plant master responsiveness to plant upsets and improve combustion air controls. The project was done in two phases with 2 boilers in phase 1 and 3 boilers in phase 2. What was happening is if they had a large upset or trip in the facility the steam headers from the boilers would fight each other and not smoothly handle the upset. The unit trips could ultimately lead to boiler trips. The goal was to improve stability, reliability and availability and make the plant more agile to changes. By optimizing the controls, fuel usage would be reduced and controls simplified for the operators. The project was done while the plant was running. The first step of the project was to create a medium fidelity simulation of the steam headers and boilers. This allowed scenarios to be performed to see how the control strategy would react to various unit upsets. This work was done on virtual machines including the simulation of the DeltaV control system. Jim noted that he could work on the control strategy while traveling to the site on the plane on his laptop. A detailed implementation plan was developed and presented to the petrochemical producer staff for review and approval. The control strategy takes the demand requirements of the plant to a main net energy controller which talks to each boiler control master. Ultimately the demand gets divided to each of the boilers on a proportional basis. The plant master provides total net energy demand for all boilers and the net energy controller allocates and balances total net energy demand between boilers. It considers all boiler limits, ramping capability and efficiency. Here’s the architecture of the solution: The solution includes boiler net energy optimization, total boiler net energy control and net energy limiting. The was a dashboard for the operators showing the optimum operating range for each boiler based on current plant steam demand. You can connect and interact with other optimization experts in the Improve & Modernize group in the Emerson Exchange 365 community. Related Posts Optimizing Sugar Mill Boiler Performance Model Predictive Control Tips & Techniques Preview 5 Questions for Process Control Consultant Mark Coughran Improving Coalescer, Separator and Reactor Control Performance What is Operational Certainty? Business Results Optimizing Delayed Coker Operations The post Steam Management and Optimization appeared first on the Emerson Automation Experts blog.Process OptimizationJim DunbarSolve & SupportEnergyemrex2016Improve & Modernizehttps://emersonexchange365.com/emerson-exchange/b/weblog/posts/ethanol-greenfield-awarded-reliability-program-of-the-yearThu, 27 Oct 2016 16:00:00 GMTcd40bb2b-3d49-4868-939d-417119b40291:02306eeb-2c10-4c96-9a7d-8ddd0a98cf61Emerson Exchange NewsBy Dave Perkon At the Ethanol Greenfield plant in Varennes, Quebec, production increased by 80%, yield improved by 11%, and even though production almost doubled in 10 years, there was only a 14% increase in maintenance cost. All of this couldn't have been achieved without a successful reliability program, and for its efforts the facility won the 2016 Emerson Reliability Program of the Year. "Since 2010, unplanned plant downtime is less than 1% per year; the percent of overtime was reduced by one-third; and schedule compliance increased by 10% to nearly 90% per year," said Frédéric Thivierge, operations manager at Ethanol Greenfield. "The Greenfield reliability program has also been under budget for the past five years, and the annual planned shutdowns have been stretched to once every 18 months, adding four or five days of production per year." Also, over the past 10 years, Greenfield reduced energy costs by 26%. Ethanol Greenfield was one of three finalists that presented at the Emerson Global Users Exchange in Austin, Texas. It competed through three rounds, which were not easy. To start, the participants had to fill out lengthy questionnaires about their reliability programs, host an Emerson consultant for a site visit and then prepare and deliver the reliability presentation twice at the Emerson Global Users Exchange event. Emerson experts moderated, and an experienced group, with literally billions of dollars of reliability experience, comprised the judging panel. The two runners-up were Bristol-Myers Squibb in Devens, Massachusetts, and CMC Steel in South Carolina. During the session, the three companies with best-in-class reliability programs presented their reliability programs, highlighting the effective use of reliability-based technologies, effective work processes, integrated maintenance best practices, leadership commitment and return on investment. Michael Andrews, senior reliability engineer at Bristol-Myers Squibb, discussed the reliability program at this global bio-pharmaceutical company with $17 billion in sales, of which $4 billion is invested in R&D. Even though the site has fully integrated computerized systems for the lab and process areas, such as DeltaV process automation, Syncade manufacturing execution system and a fully integrated AMS Suite, Andrews pointed out that it isn’t just about the technology and how you do reliability, but it's about "who" is reliability at a site. Reliability is more than just a maintenance department; it needs to be a part of your whole organization from the CEO through operations to the technicians—a culture of reliability. Greg Evans, reliability engineer at CMC Steel, discussed how the five steel mills of this 100-year-old company, with 100% of what it manufacturers made from recycled steel, aim to be low-cost producers and how CMC’s reliability program is helping them to get there. Evans related how CMC Steel has very good processes in place in the hot, dusty and dirty environment of the plant and how they’ve improve the overall equipment effectiveness (OEE) in the melt shop and rolling mill. One of many improvements, its billet welder increased yield by 15,000 tons/year ($6 million/year). The winner, Ethanol Greenfield, created a great reliability program. Starting operation in 2007, it is the largest Canadian ethanol producer, producing 185 million gal/year. About 50 million gal/year is fuel-grade ethanol, and, as byproducts, it produces distillers grains, carbon dioxide and corn oil. Three years ago, Greenfield merged maintenance and production departments under the same roof, creating synergy and better teamwork. It molded its reliability plan to reality and got people engaged, said Mathieu Fyfe-Leblanc, project leader, maintenance and reliability, at Ethanol Greenfield. "Reliability has to be part of the DNA of the plant,” he explained. “All personnel should be engaged in reliability because it is not a one-person job." Any reliability program also requires a strategy, continued Fyfe-Leblanc. Assets must be available when needed, reaching the performance they’re designed for or better in a cost-effective manner. “We like to call it a never-ending journey,” said Fyfe-Leblanc. “Take a step back, and be sure there are no cracks in the foundation.” Greenfield's reliability program included many pieces, such as kitting, visual indicators, skills development, training and work procedures. The 54 kitting locations ensured all the materials to accomplish each job were present. Visual indicators replaced the subjective reading of gauges with objective reading. Skill development, training and work procedures were also a big help in improving reliability. Avoidable maintenance team meetings ensured the failures or corrective actions were not repeated. Use of predictive maintenance was extensive and included vibration analysis, oil analysis, ultrasound motor greasing, motor condition and electrical signature analysis, ultrasonic wall thickness measurement and thermography. Significant use of wireless technology aided this program. Failure codes were also used and analyzed to determine the best area to work for the best payback. “Reliability is not a goal,” said Thivierge. “It’s a way to be, to think, to act.”reliabilityemrexSolve & Supporthttps://emersonexchange365.com/emerson-exchange/b/weblog/posts/implementing-an-effective-alarm-management-program-2136388521Thu, 27 Oct 2016 14:05:00 GMTcd40bb2b-3d49-4868-939d-417119b40291:e8b9123b-4f92-4c71-a038-1446b7ca40e8Jim CahillAt the Emerson Exchange conference in Austin Emerson’s Kim Van Camp and exida’s Todd Stauffer presented Seven Steps to a Peaceful Control Room: How to Implement an Effective Alarm Management Program for your DeltaV System. Their abstract: Has the alarm horn become the nemesis of your operators? This presentation describes how to create (build) an effective and sustainable program using ISA-18.2’s alarm management lifecycle (the blueprint) and DeltaV’s alarm management capabilities (the tools). It shows how following the program will allow you to address common alarm management issues (alarm overload, nuisance alarms, alarm floods, incorrectly prioritized alarms) and create a control room environment that maximizes operator performance, improves process safety, and drives operational discipline. Todd opened showing an operator screen overflowing with alarms. So many, that it would be difficult for an operator to know what actions to take. The purpose of an alarm is to make operators aware of abnormal situations in order to take corrective action before unplanned shutdowns or slowdowns occur. He shared a pump leak example where a high level nuisance alarm for a sump pump caused the operators to ignore the alarm when a leak occurred. The leak was not detected until inspection rounds were performed. Todd discussed the I SA 18.2 alarm standard that describes what to do, but not how to do it. A series of ISA 18.2 technical reports share some of the “how to do” recommendations. The standard defines an alarm that notifies the operator of an abnormal situation which requires a timely response. If it doesn’t require a response, it is not an alarm. Notifications including alerts and prompts should be put into different categories and displayed differently that the alarms and not be in the alarm summary page. So how do you create and effect alarm program? Here are the steps: Benchmark initial performance Create an alarm philosophy Rationalize the alarms Implement rationalization results/create alarm response procedure Implement alarm suppression Measure performance (monthly) Audit Kim shared some alarm performance key performance indicators such as average alarms per day, alarm rates, peak alarms in 10-minute time windows, etc. DeltaV Analyze takes the alarm log to generate these KPIs. The KPIs can also be provide as service from the Emerson Lifecycle Services team. Todd discussed some of the content in an alarm philosophy per the ISA-18.2-2016 update. Additions were made in the recent standard update to include an alarm system management audit, alarm shelving and more. All alarms should meet the criteria of if the alarm really should be an alarm based on the alarm philosophy. If it doesn’t meet the criteria, it should be reclassified to some other level of notification. Alarms should be prioritized based on the consequences of what would happen if the operator does not respond to it. A matrix should be developed to classify the alarms into priority levels. Priority levels above a threshold should be the ones that appear in the alarm summary. Todd noted one of the game changers to managing alarms during operations is alarm suppression, shelving and out of service. Examples of situations where the alarms should be put into one of these states include non-commissioned devices, transmitters malfunctioning, out of services. Todd noted that shelving is like hitting the snooze button on a wake up alarm. There is a time and place to shelve alarms based on a condition, such as a chattering alarm where the alarm is not at a critical alarm. The standard mandated that all distributed control systems have this shelving capability. Exida’s SILAlarm works with the DeltaV system to help guide the alarm rationalization process. The information collected can be pushed back into DeltaV to offer recommendations on actions to take in response to alarms. Kim described DeltaV Alarm Mosaic to help manage alarm floods via alarm flood suppression. It graphically shows causality. The good news is that this workshop is being filmed and will appear in the Emerson Exchange 365 community in the DeltaV group . If you haven’t already joined , please do and you’ll receive a notification when the video is posted. The post Implementing an Effective Alarm Management Program appeared first on the Emerson Automation Experts blog.Kim Van CampANSI/ISA 18.2Control & Safety SystemsOperate & Manageeventalarm managementemrex2016https://emersonexchange365.com/emerson-exchange/b/weblog/posts/implementing-an-effective-alarm-management-programThu, 27 Oct 2016 14:05:00 GMTcd40bb2b-3d49-4868-939d-417119b40291:dddc6f54-555a-4925-979f-57991f857e77Jim CahillAt the Emerson Exchange conference in Austin Emerson’s Kim Van Camp and exida’s Todd Stauffer presented Seven Steps to a Peaceful Control Room: How to Implement an Effective Alarm Management Program for your DeltaV System. Their abstract: Has the alarm horn become the nemesis of your operators? This presentation describes how to create (build) an effective and sustainable program using ISA-18.2’s alarm management lifecycle (the blueprint) and DeltaV’s alarm management capabilities (the tools). It shows how following the program will allow you to address common alarm management issues (alarm overload, nuisance alarms, alarm floods, incorrectly prioritized alarms) and create a control room environment that maximizes operator performance, improves process safety, and drives operational discipline. Todd opened showing an operator screen overflowing with alarms. So many, that it would be difficult for an operator to know what actions to take. The purpose of an alarm is to make operators aware of abnormal situations in order to take corrective action before unplanned shutdowns or slowdowns occur. He shared a pump leak example where a high level nuisance alarm for a sump pump caused the operators to ignore the alarm when a leak occurred. The leak was not detected until inspection rounds were performed. Todd discussed the I SA 18.2 alarm standard that describes what to do, but not how to do it. A series of ISA 18.2 technical reports share some of the “how to do” recommendations. The standard defines an alarm that notifies the operator of an abnormal situation which requires a timely response. If it doesn’t require a response, it is not an alarm. Notifications including alerts and prompts should be put into different categories and displayed differently that the alarms and not be in the alarm summary page. So how do you create and effect alarm program? Here are the steps: Benchmark initial performance Create an alarm philosophy Rationalize the alarms Implement rationalization results/create alarm response procedure Implement alarm suppression Measure performance (monthly) Audit Kim shared some alarm performance key performance indicators such as average alarms per day, alarm rates, peak alarms in 10-minute time windows, etc. DeltaV Analyze takes the alarm log to generate these KPIs. The KPIs can also be provide as service from the Emerson Lifecycle Services team. Todd discussed some of the content in an alarm philosophy per the ISA-18.2-2016 update. Additions were made in the recent standard update to include an alarm system management audit, alarm shelving and more. All alarms should meet the criteria of if the alarm really should be an alarm based on the alarm philosophy. If it doesn’t meet the criteria, it should be reclassified to some other level of notification. Alarms should be prioritized based on the consequences of what would happen if the operator does not respond to it. A matrix should be developed to classify the alarms into priority levels. Priority levels above a threshold should be the ones that appear in the alarm summary. Todd noted one of the game changers to managing alarms during operations is alarm suppression, shelving and out of service. Examples of situations where the alarms should be put into one of these states include non-commissioned devices, transmitters malfunctioning, out of services. Todd noted that shelving is like hitting the snooze button on a wake up alarm. There is a time and place to shelve alarms based on a condition, such as a chattering alarm where the alarm is not at a critical alarm. The standard mandated that all distributed control systems have this shelving capability. Exida’s SILAlarm works with the DeltaV system to help guide the alarm rationalization process. The information collected can be pushed back into DeltaV to offer recommendations on actions to take in response to alarms. Kim described DeltaV Alarm Mosaic to help manage alarm floods via alarm flood suppression. It graphically shows causality. The good news is that this workshop is being filmed and will appear in the Emerson Exchange 365 community in the DeltaV group . If you haven’t already joined , please do and you’ll receive a notification when the video is posted. Related Posts Plant Alarm Management and Analysis Alarm Management Live Q&A Highlights Rationalizing Plant Alarms Intelligent Field Device Diagnostic Alarm Management Improving Refinery Performance through Alarm Management Improve Safety Proof Test Capabilities with Intelligent Instrumentation The post Implementing an Effective Alarm Management Program appeared first on the Emerson Process Experts blog.Kim Van CampISA 18.2Emerson Exchangealarm managementemrex2016DeltaV