Oil & Gas

One of the largest offshore oil & gas industry events, the ONS 2010 (Offshore Northern Seas) Conference, will be happening August 24 through 27 in Stavanger, Norway. During this conference, a number of Emerson folks will be presenting on the application of technologies in offshore oil & gas production. These presentations include:

• Asset Management Overview: Asset management of instrument, valves, rotating, and process equipment, including online, offline, and wireless
• Daniel: Recent Innovations in Ultrasonic Measurement including new transducer releases and advanced diagnostics
• The DeltaV process automation system: Electronic Marshalling and I/O on Demand
• Emerson Valve Automation Overview
• Intelligent Well: Downhole Monitoring and Control - Investigate the benefits of measuring closer to the reservoir
• Micro Motion Coriolis Overview: mass flow measurement for metering, high flows, and meter verification
• Rosemount: Instrument measurement diagnostics in practice
• Roxar Subsea Flow Assurance: Covering the ROV retrieval tool and chemical injection valves
• Wireless Cost and Time Savings: The tool to cut down cost and implementation time

I received an advanced copy of the Emerson Valve Automation overview, which will be given by Ronald de Jong. The Valve Automation business is responsible for the Emerson valve and actuator brands including: Bettis, El-O-Matic, Shafer, Hytork, Dantorque, FieldQ, and EIM.

Together, these brands provide ¼-turn (rotary) actuators and linear (rising stem) actuators that are pneumatic and hydraulic, gas-hydraulic, multi- and ¼-turn electric driven. The Valve Automation team provides additional controls, accessories, valve procurement, packaging, and testing services. Offshore oil & gas production has it unique challenges and require engineered solutions such as:

• Gas/hydraulic actuators for block valves or main line isolation valves
• Direct gas actuators for block valves or main line isolation valves
• Pressure guard for emergency shutdown (ESD) application when no external power source is available
• Multiport flow selectors for test well selecting application
• Actuators for high vibration applications
• Actuators for surface safety valves
• Hydraulic power units
• Subsea actuators
• SIL-PAC for ESD applications
• Smart actuators

Ronald closes his presentation by describing the actuators commonly used in Floating Production Storage and Offloading (FPSO), Floating Storage and Offloading (FSO), and Single Point Mooring (SPM) applications--for the turret (Shafer), topside (Bettis), and subsea (Dantorque) areas of these vessels.

If you'll be at the ONS conference, check out Ronald's and the others' presentations and tell them hi from me.

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I received a question a few days ago about flow measurement and wet gas. Here is a paraphrased version of the question:

The meter would be used to measure gas in and out of storage. The gas may be wet--depending on pressure and temperature. I do not know yet how wet it can be. Ultrasonic meters have been tried in the past and sometime have issues if there is too much water in the gas. How much is too much and is there a general guideline for gas wetness that applies to these meters?

I turned to Emerson's Karl Stappert who has experience with a number of flow measurement technologies ranging from Ultrasonic to Coriolis effect. I thought his answer was the makings of a great blog post so I thought I'd share it with you.

The "wet" is of course liquids of varying levels that tend to collect on the walls of the piping at any velocity. The problem is that regardless of liquid loading levels, they will build up in low-level areas of the piping at low flow velocities and they get swept out and whipped-up back into the flow stream when high velocity flows are reintroduced. Liquids can collect in the USM [ultrasonic meter] transducer ports bridging the space between the transducer and USM meter body causing the ultrasonic transducer to fail. USMs such as the Daniel JuniorSonic, which has its transducers located at the top of the meter pointing down, will mostly eliminate the liquid bridging on the transducers.

This design mostly eliminates the liquid bridging concern, but there still exists the potential for intermittent failures when the flow transitions from low velocity to high and sweeps liquids up that have collected during the low velocity timeframe. Liquids that are entrained into the gas stream will cause refraction of the ultrasonic sound wave and may degrade signal quality causing some ultrasonic sound shots to fail in a batch of shots. However, failure of all shots in a batch is a rare occurrence and likely only intermittent if ever. It is not possible to totally alleviate these intermittent conditions regardless of liquid load in the flow stream. This is due to the liquid collection issue at low velocities and potential piping configuration issues.

A meter and meter tube inspection and cleaning program should be employed to ensure the accuracy of the meter over time. Also, with the increasing flow capacity of Coriolis flow measurement, this technology can be considered for these slightly wet gas conditions.

Changing wetness conditions is a challenge in gas flow measurement. Both Ultrasonic and Coriolis measurement can be successfully applied. It's important that any piping issues be addressed to avoid liquid collection areas upstream of the flow meter and that that the maintenance program monitors for wet conditions.

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Emerson's Alan Baird shared a great story I wanted to pass along. The story begins with a Middle East oil & gas producer. The production field used steam injection to help lift the hydrocarbons to the surface for further processing. For those of you in other industries, here's a brief description of the steam injection process:

Steam injection is an increasingly common method of extracting heavy oil. It is considered an enhanced oil recovery (EOR) method and is the main type of thermal stimulation of oil reservoirs. There are several different forms of the technology, with the two main ones being Cyclic Steam Stimulation and Steam Flooding. Both are most commonly applied to oil reservoirs which are relatively shallow and which contain crude oils which are very viscous at the temperature of the native underground formation.

The traditional method to monitor the steam injection wellheads includes solar panels plus battery backup for power, remote terminal units (RTUs), radio communication units, explosion-proof junction boxes, dynamic flow computers, pressure and temperature instrumentation, and the associated cables, cable trays, tray supports, etc. required in wiring it all up.

Alan and team looked at what equipment would be required if the measurements were performed and transmitted via IEC 62591 WirelessHART devices. They used the AMS Wireless Snap-On software in the AMS Device Manager application to develop the design. One design consideration was where to do the totalization calculations. The one-minute updates from wireless devices led to the decision to bring the signals back to the SCADA system and do the flow calculations on the receiving end.

They did some pilot wells to test the design and compare the wireless approach with the wired steam injection wellheads. For the flat terrain of the production field, they discovered the wireless devices could communicate over 300 meters. The wireless differential pressure (DP) flow, pressure, and temperature transmitters caused no interference with the existing radios on the wired wellheads.

Each wellhead had one differential pressure (DP) flow, two pressure, and one temperature transmitter. For the pilot, these were installed in the same impulse lines they had and the DP lines across the V-Cone element. The flow calculations between the wired and wireless approach were within 0.1% of one another. They were also able to get diagnostic alerts from the wireless devices back to the AMS Device Manager software.

The pilot proved not only the wireless approach was a cost-effective alternative; it was also much faster to install and commission. The oil & gas producer has a constant need to bring new steam injection wells on-line to maintain production rates. They can now wirelessly instrument and do totalization calculations on one steam injection wellhead per day.

The results were significant enough to call the pilot a success and roll out across this and other production sites.

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The DeltaV team has been hard at work creating two new whitepapers detailing an I/O on Demand cost analysis and Electronic Marshalling. These technologies are available in the latest DeltaV release.

Emerson's Oil and Gas sales and marketing director, David Newman developed the I/O on Demand Cost Study whitepaper. He presents a study:

...from an existing offshore manned platform was analyzed to compare the different combinations of capital cost of the as built wired / Foundation fieldbus versus Electronic Marshalling technology. The results show cost savings of between 7% and 26% which equates to $0.3M to $1.25M, depending on the options chosen, with additional value of saving of up to 30 tonnes in weight and up to 43 m2 of deck space in cabling, cable tray, junction boxes and cabinets.

The scope of the study includes materials and labor for a manned, offshore platform and its process automation system and associated cabling, cable tray, marshalling cabinets, system cabinets, controller I/O cards, and control room space requirements. David describes the layout:

The Control Room is situated at one end of the Platform, such that the average cable length on the cable tray is about 90 metres. In that room are System Cabinets containing controllers and I/O cards. From there, the cabling continues to Marshalling Cabinets, then onto cable tray which runs out onto the platform. At various positions on the platform, cabling exits the cable tray to local Junction Boxes. From the Junction Boxes, there is an average of 10 metres of cable to each field device, and in the case of a Fieldbus loop an average of 5 metres between the junction box and megablock and the megablock and the field device.

The cost analysis first considers the number of I/O that could be wireless I/O, based on the speed of the control loop or monitoring application. Based on the platform topology 30 wireless I/O can be connected per wireless network.

The whitepaper compares these scenarios:

• Conventional wired with Fieldbus (separate power) - as built
• Conventional wired, Control Room Electronic Marshalling with Fieldbus (separate power)
• Conventional wired, Field Electronic Marshalling with Fieldbus (separate power)
• Conventional wired, Field Electronic Marshalling with Fieldbus (integrated power)
• Conventional wired, Field Electronic Marshalling, Fieldbus (integrated power) and wireless devices

Pages 8-10 of the whitepaper show the I/O mixes used in the calculations. The savings, presented on page 12, range from 6.8% to 25.6% for the 1874 total number of points considered.

David has developed a calculator that an Emerson local business partner or sales office can apply to your application to how these I/O on Demand technologies can impact the financial costs of your project.

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I saw in my Sound Off blog RSS feed that Dan Hackett, part of Emerson's Daniel Measurement and Control business, did a podcast interview with Walt Boyes. The 25-minute podcast is on some new Daniel Ultrasonic flow measurement technology being introduced at the upcoming Emerson Exchange.

Dan starts by describing how these critical ultrasonic flow measurements work. I thought Dan's explanation was more understandable than my Guadalupe River rafting analogy in an earlier post. If there's no flow, the time it takes the ultrasonic pulse to travel across the pipe from one side upstream to the other side downstream and back is the same. As the flow increases, the time difference between the travel across the pipe each way increases--since one way the pulse goes with the flow and the other way it goes against the flow.

Dan described how some of the Daniel liquid and gas ultrasonic flow meters have 4 measurement paths to get different measurements at different points to integrate an average flow. The average axial velocity multiplied by the area of the pipe gives the uncorrected volume flow rate through the ultrasonic flow meter.

He described how these critical meters are used primarily in custody transfer applications. For those not familiar with the term, custody transfer is like the cash register where the possession of feedstocks, intermediates, and finished products changes hands between companies, governments, or countries. The measurements must be highly accurate and agreed to by both parties.

As Walt pointed out in one of his questions, ultrasonic flow measurement, because of low-pressure drop and high turndown capability, can handle a wide range of applications from very high temperatures to very high pressures. Dan described an application in gas measurement where this technology was being applied. Offshore and onshore gas production measure high-pressure natural gas--usually at the custody transfer point with the gas distribution pipelines. High volume consumers of natural gas, such as power plants and aluminum producers will meter the incoming natural gas. Also, many municipal districts measure the incoming natural gas before it goes into their distribution systems for the area businesses and residences.

For liquid custody transfer, crude oil production and processing are typical applications for ultrasonic flow measurement. Dan mentioned that right now it's mainly used in the feedstock and finished products areas of refineries, and less so in the process itself, where other flow measurement technologies are typically applied. In a refinery, the custody transfer surrounding the incoming crude and the refined products such as gasoline, diesel fuel, and kerosene are good applications for ultrasonic flow measurement. A final application Dan notes was liquefied natural gas (LNG) facilities where the incoming natural gas is measured and also in regasifiers where the liquid is converted back to high pressure gas for final distribution.

The new ultrasonic flow meter transducer being shown at the Emerson Exchange extends the temperature and viscosity range to address more applications like the heavy crudes found in the oil sands and oil shales. Typically, conditioning processes were required to reduce viscosity and or temperature, which add operational costs to the custody transfer measurement process.

One of the big enhancements Dan mentioned was on the software side, where diagnostics now embedded expert knowledge to identify conditions such liquid fractions in gas and pipeline deposit layer buildup. In oil & gas applications, the first case helps spot expensive liquid condensate giveaway. Accumulated buildup inside of pipes impacts the integrity of the custody transfer measurements. When these diagnostics are connected to the Daniel CUI 5 or AMS Device Manager software, operators and maintenance personnel are notified of a problem immediately and offered suggestions for corrective action. The CUI 5 baseline viewer provides a consolidated view for monitoring performance within pre-set ranges.

I found the podcast to be 25 minutes well spent as well as the recent email newsletter in getting up to speed on the latest developments in ultrasonic flow measurement and good application fits.

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In the news a while back was Emerson and Flow-Cal, maker of the leading natural gas accounting software. They introduced Coriolis-specific data integration to the FLOWCAL software. The purpose is:

...to enable direct interface of API Ch. 21.1-compliant Micro Motion Coriolis data with Flow-Cal accounting software for natural gas production and transmission data management.

The API Ch. 21.1 standard refers to the electronic gas measurement portion of Chapter 21, Flow Measurement Using Electronic Metering Systems. It encompasses the flow computer as well as the gauge/impulse lines; cabling/wiring; peripheral devices including counters, pulse generators, on-line analyzers, densitometers and gravitometers; calibration equipment; and measurement software.

I turned to Emerson's Marc Buttler, a manager in the Micro Motion division to get the story for how this integration was made possible. He described the typical natural gas accounting path. It starts with the flow meter measurement on the gas production line. The flow meter feeds a transmitter or flow computer, also known as electronic flow measurement (EFM). A SCADA system typically polls this information, and sends it to the enterprise management accounting software.

The American Petroleum Institute (API) and American Gas Association (AGA) have very strict requirements for this data required by the natural gas accounting software. The data must include the measurement, associated configuration, and the event logs around the measurement.

Marc shared with me that the Remote Automation Solutions business within Emerson has had a longstanding relationship with the Flow-Cal organization. The Micro Motion team also has had a longstanding relationship with their parent company, Coastal Flow. The engineers at Micro Motion and Remote Automation Solutions teamed with the Flow-Cal engineers to complete the path from the Micro Motion flow meters, with a FloBoss 107 or a ROC809 as the flow controller, and ROCLink software used in place of SCADA polling software.

Technically what happens is that the ROCLink software delivers the flow meter data in the Flow-Cal specified .CFX file format for Coriolis natural gas flow measurement required for AGA 11 (Measurement of Natural Gas by Coriolis Meter) and API Ch 21.1 compliance.

By automating this flow of information through this collaborative R&D effort, energy producers can increase the reliability of their natural gas measurements and production accounting, while reducing the maintenance and capital costs. Much of these improvements come from the accuracy and reliability of Coriolis measurement. It measures gas volume without additional temperature or pressure measurements, which reduces the components to purchase and maintain.

As Coriolis measurement continues to move into the mainstream of natural gas flow metering, Marc sees more SCADA polling suppliers developing and providing the connection from the electronic flow measurement device to the Flow-Cal software to provide the end-to-end natural gas production and transmission management.

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Emerson's DeltaV SIS product manager, Mike Boudreaux, whom I've featured in several process safety-related posts, manages two great sources of information on safety instrumented systems (subscribe) and process safety (subscribe). These Friendfeed rooms are excellent places to both capture and comment on stories as one finds them.

My subscription to the safety instrumented systems room pointed me to a great article by Murphy Oil's William Taggart. The article, which originally appeared in Intech magazine, is entitled Process safety systems in the Gulf of Mexico.

Mike's capture of the article's opening paragraph drew my attention:

Process safety systems for the offshore oil/gas industry in the Gulf of Mexico have taken a very different path than those of their onshore brethren. Monthly and quarterly testing of safety devices in an online mode, a prescriptive safety standard written more than 40 years ago, and a governmental agency looking over their shoulder make up what could have been a recipe for disaster, but instead it has been a recipe for an exemplary process safety record coupled with high uptimes. The differences lie in API RP 14C and ISA84 and the results to facilities in the Gulf of Mexico and onshore facilities. The differences are also why their system has worked.

I'm not sure about 40 years ago, but what the author describes is exactly how it worked more than 20 years ago when I worked as a systems engineer on offshore oil & gas platforms.

The American Petroleum Institute's Recommended Practice 14C (API RP 14C) was indeed very prescriptive for what safety shutdowns were required for each piece of the processing equipment from the wellheads to the custody transfer skids where the production was metered and ownership transferred to the pipeline companies.

The author wrote:

API RP 14C provides a simple standard you can easily apply to offshore oil and gas facilities where the process design is the same basic type that has seen use for years. It errs on the conservative side by requiring safety devices, which might be excluded under ISA84, IEC 61511, or IEC 61508 analysis. It does not address the implementation of the safety system, rather focusing on the required functions.

Based on the platform's processing equipment, the safety instrumented functions were very clear. And, monthly testing of the safety instrumented function inputs and safety valves was required by the U.S. Department of the Interior's Minerals Management Service. The operators worked hard to make sure the platforms they were responsible for had no MMS citations. The author notes a change over the years with the advent of reliable electronic transmitters that the safety function inputs could be tested quarterly instead of monthly.

Another key difference with other process industries is that RP 14C has philosophy to shut everything down on a safety trip:

...an event on a single vessel will affect the entire facility, especially if it is a process critical vessel like a flare scrubber or process sump tank. On a typical offshore oil/gas facility, 20 safety devices will shut in the entire facility. Also, 200-400 safety devices will shut in their specific piece of equipment or a section of the process train depending on the size and complexity of the facility.

The combination of a conservative, prescriptive approach to safety instrumented functions, federally-mandated rigorous testing, and a "shut it all down" philosophy has produced an impressive safety track record where there has been no process safety-related fatalities in more than 9 years in the Gulf of Mexico.

In his safety instrumented system room, Mike had also flagged an October 2008 ControlGlobal.com story on Murphy Oil's use of the DeltaV and DeltaV SIS systems on some of their offshore platforms and the reasons for taking this approach.

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I had a chance to meet Emerson's Philip Schwarz a few years back in a multi-divisional marketing meeting. He had a slot on the agenda to discuss the trends in the oil & gas industry. He leads these efforts for Emerson Process Management's Rosemount measurement products. He was one, dynamic presenter, if you ever have a chance to hear one of his talks. Maybe I'll capture some video and post it in YouTube the next time I catch him presenting.

I saw an email from Philip where he mentioned that the oil & gas producers have been big adopters of wireless field device communications technologies. Philip noted around 9 in 10 of these oil and gas wireless applications were in onshore oil & gas fields. A big driver of this technology adoption has been for gross oil production flow monitoring applications.

The traditional way to measure gross oil production has been to use portable meter skids. These skids measure the oil, gas, and water content for each producing well on a site--when hooked up one by one. Since many fields are geographically dispersed, these measurements may be done one per month up to twice per year. After a well is tested, its production rate is assumed to be the last-tested measurement. It's important to note that these measurements are not to control the wellhead, but to monitor the production rates for each well.

Now, if five months have passed, this last-tested measurement might not be very accurate. And problems may have occurred in the subsurface well formation causing a production drop.

The main reason these wells have not been fully instrumented and been communicating continuously is the labor and installation costs of measurement devices, cabling, remote terminal units (RTUs), batteries, radios, etc. In many areas, these wells typically don't have the high production rates of offshore production wells. Hence, the traditional solution of a portable skid and schedule to conduct the flow measurements has been employed.

Wireless measurement devices and self-organizing WirelessHART networks have changed the economics by significantly reducing the infrastructure costs. To do the gross oil production measurements, these onshore sites install Rosemount 3051S wireless pressure transmitters and 648 wireless temperature transmitters. Instead of once per month or twice per year, each well can be measured on the order of seconds.

Communications between wireless devices can extend up to half a mile as the transmitters from surrounding wellheads self-organize to form a network with the wireless gateway devices. None of the cabling, cable trays, etc. is required, which significantly reduces the installation cost barrier.

Philip shared a 2005 Society of Petroleum Engineers (SPE) paper with me written by engineers with one of the major U.S. oil producers. It shared a vision of the digital oil field that provides real-time monitoring, analysis, and control for optimum field management. This vision included making the oil field more like a factory where there is a higher level of measurement and control to improve efficiency.

Technologies like WirelessHART self-organizing network communications and wireless-enabled field devices here in 2008 make possible many of the visions that were not economically justifiable when this paper was written.

Next time, a nice video of Philip talking about this will save around 550 words!

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I've known Emerson's Patrick Deruytter for many years. He's now the general manager for the Emerson Process Management office in South Korea. As his career has advanced, he's lived in many places--Minnesota and Texas in the U.S., Belgium and the U.K. in Europe, Australia, Singapore, and China. His experiences have included projects, project management, product marketing, lifecycle support, and general management.

He was in Austin last week and we had a chance to catch up. I found out he recently spoke at the Asia Pacific FPSO Summit with a presentation, Enabling Operational Excellence in FPSO. For those not versed in FPSOs, the acronym stands for Floating Production Storage and Offloading. When I worked in the offshore oil and gas industry in the mid-to-late 1980s, the overwhelming majority of offshore production came from fixed-leg platforms that set on the ocean floor.

Patrick highlighted some of the challenges and global trends for FPSOs. The first is the ever-increasing sophistication and complexity of the vessels and the onboard processing facilities. Oil and gas producers are building and modernizing FPSOs to meet the global needs for hydrocarbon-based energy.

Increasingly, FPSO owners want all of their systems integrated--navigation and propulsion systems, integrated automation systems (IAS), custody transfer systems (CTS), etc. Given the fast track nature of FPSO projects, equipment deliveries and skilled project engineers are critical for on time, on-budget performance. Once commissioned, the systems need to be highly reliable and easy to maintain, given the marine environment in which they operate.

Integrated systems provide a single window into the oil & gas production processes, subsea control processes, management of onboard assets, safety instrumented systems, and vessel automation processes (ballast control, offloading, power management, tank washing, etc.)

The design of the processing facilities on FPSOs is becoming extremely modular. This helps with the construction phase while the vessel is in the shipyard, and makes engineering, installation, and commissioning more manageable. The major processes like separation, gas dehydration, gas injection, oil metering, seawater treatment, power generation and distribution, custody transfer, etc. are pre-built, instrumented, and set on the deck of the vessel for integration with the automation and safety systems.

The modular trend extends to the wiring. FPSOs are moving away from large central control rooms toward remote I/O and control stations distributed among the production modules. This reduces the size of the total control room footprint, which is quite expensive on these ships. It also reduces cable runs, which reduces overall weight. And the modular design lends itself to modular pre-assembly and pre-testing which reduces overall commissioning time. Typically, the earlier you find problems, the easier and less expensive they are to resolve.

Patrick listed products across Emerson Process Management and alliance partners used in large marine projects like FPSOs and FLNG (floating liquefied natural gas) vessels. The list included DeltaV automation systems, DeltaV SIS safety systems, AMS suite software, Scanjet tank cleaning, Wärtsilä power distribution / engines / drives / vessel automation / propulsion systems, Rosemount tank radar level gauging and measurement, Fisher valves and regulators, Daniel metering and custody transfer, Micro Motion flow meters, and Valve Automation offshore valve systems.

These technologies have been applied in some of the world's largest FPSOs including ExxonMobil Kizomba A & B, BP Angola, Pemex, and Total, to name a few.

Patrick closed his presentation on WirelessHART wireless devices and how they are being incorporated in applications like wellhead annular pressure and heat exchanger pressure monitoring. This additional monitoring helps more quickly spot abnormal situations and reduces the manual clipboard and keyboard entry work processes.

The level of sophistication and technologies applied to these marine applications has come a long way from my days back in offshore oil production two decades ago!

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Emerson's Fisher division recently announced a new three-way, temperature-control valve and actuator system. The release highlighted its potential use by process manufacturers:

The new GX 3-way has the ability to accurately control the temperature of water, oils, steam, and other industrial fluids. Applications include heat exchangers and lubricating skids.

For those not well versed with three-way valves, you'll find use for them in both flow mixing (converging) and flow splitting (diverging) applications.

I caught up with Brad Smith, the global GX control valve product manager, about some potential applications for this valve. Brad began by sharing the development objectives for this valve. Typically, when a process manufacturer cannot achieve the required control, they must reassess process-piping arrangements, often going to a 2-valve arrangement. This GX 3-Way valve provides the level of control to avoid re-piping and 2-valve arrangements.

Brad shared with me that the biggest application focus for this 3-way valve is in temperature control around heat exchangers. It was designed for high-capacity applications and precise linear characteristics required for accurate temperature control. Brad cited a specific heat exchanger application in beer brewing where the wort temperature is maintained with a glycol coolant.

Another common application for this 3-way valve is pH control on feedwater to a boiler. When the pH of the feedwater rises beyond a predetermined level, a three-way valve adds fresh make up water to reduce the pH back to target levels.

A third application Brad discussed was for test separator manifolds. Test separators are mainly used in oil & gas production facilities to measure the amounts of oil, gas, and water from the well. The manifold contains three-way valves coming from each wellhead that uses the test separator. Some installations use the three-way valves while others prefer globe valves.

A final application Brad shared was in the steel industry. Rod mills require good temperature water box control.

Most process manufacturers have temperature control applications requiring mixing flow streams or splitting flow streams. This three-way valve might have the flow characteristics and properties your application requires.

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A great presentation at the recent Emerson Exchange was one that discussed the results of applying model predictive control (MPC) in a challenging gas plant process. Model predictive control has been available for decades and used in very large applications such as refinery process units, but its use in smaller applications found in the oil and gas sector is relatively new.

This plant was limited by its field compression capability, and throughput could be increased if they could reduce the differential pressure (DP)--mainly by lowering the inlet pressure to the gas plant. Swings in gas flows were introducing disturbances to downstream equipment such as carbon dioxide removal trains, causing them to trip. This caused further disturbances and in turn caused the operators to run these CO₂ removal trains very conservatively to minimize the risk of cascading train trips. The result was that overall throughput was reduced--directly impacting the bottom line financial performance of the plant.

Sarah Perkins and Andrew Taylor of ProSys Engineering, based in Australia, were called in to work with the gas plant's engineering staff to develop control strategies to maximize throughput while minimizing upset conditions and their cascading effect on other process units.

They saw three areas where advanced process control, specifically MPC, could be applied to meet the overall objective of maximizing plant throughput capacity. These included minimizing the differential pressure across the CO₂ removal trains, minimizing the liquid recovery plant (LRP) inlet pressure (to reduce overall plant inlet pressure), and using the plant's incoming pipeline as a surge vessel to eliminate spikes in inlet pressure which might trip the reciprocating compressors.

Let's dig in a little deeper in one of these areas--CO₂ removal trains. This gas plant had a number of these trains in parallel. The objective of the model predictive control strategy was to maximize the flow through the train either to a specified high limit or to valve saturation--whichever constraint was active first. Satisfying this objective effectively minimizes the differential pressure across each CO₂ removal train.

For each train, they designed and implemented a dedicated DeltaV PredictPro MPC control block running in their DeltaV controllers. To minimize the differential pressure, the goal was to maximize the butterfly valve opening coupled with the need to quickly cut back the flow in case another CO₂ removal train trips. With this MPC-based flow controller, the butterfly valves were linearized where the output was expressed as a % of flow capacity, instead of a % of valve position. Each butterfly valve had different flow characteristics, so each MPC flow controller was individually characterized.

The feed gas flow was the manipulated variable; the constraints were setpoint (SP) minus process variable (PV) error, and an operator-entered maximum flow rate. These constraints help to detect trip conditions and honor process limits like flow rates at which foaming begins to occur. In abnormal situations, the maximum flow rates are set to current flow rates to allow the operators a chance to make decisions about redistributing the flow rates.

The team made custom graphics for the operators to see the CO₂ removal trains on a single view, to quickly recognize patterns of abnormal situations and to take manual corrective action.

The payback on increased throughput was less than two months and even more throughput will occur when all of the reciprocating compressors are reconfigured for the reduced operating discharge pressure.

With MPC available at the DCS controller level, it can be applied to many smaller and mid-size applications in oil & gas and other industries. Engineers like Andrew and Sarah are helping process manufacturers solve challenging problems like these that also deliver fast financial results.

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On several occasions, I've discussed the subject of flow measurement and custody transfer. My WatchThatPage email spy service alerted me to a great new article by Emerson's N.K. Chaudhary. He's a member of the flow group based in Singapore.

His article, Improving Custody Transfer, describes the role of Coriolis direct mass flow measurement and some tips when using them in a custody transfer application. In describing the importance of good measurement in custody transfer, I'll borrow N.K.'s words:

Whenever liquid product such as refined petroleum changes custody from one supplier or distributor to the next, it must be accurately measured and scrupulously accounted for.

There are many types of flow technologies. The article describes the three basic categories including inferential volumetric flow, direct volumetric flow and direct mass flow. Each has advantages and disadvantages. Inferential flow measurement devices include magnetic, ultrasonic, differential pressure and turbine-based flow meters. Positive displacement (PD) technology fits in the direct volumetric flow category.

The bulk of the article describes direct mass flow measurement. The best examples of these are Micro Motion Coriolis flowmeters. N.K. describes how these meters arrive at a volumetric flow rate:

To determine a volumetric flow rate, a mass flow meter must also know the density of the fluid, which is accomplished by measuring the natural frequency of tube vibration. The fluid's flowing density is proportional to the square of the period of vibration of the flow tubes (inversely proportional to the frequency squared).

Coriolis flowmeters were approved by the American Petroleum Institute (API) in custody transfer applications in 2002 (API MPMS 5.6). N.K. cites a number of reasons that Coriolis technology has been widely accepted in custody transfer flow measurement:

...longstanding high accuracy and repeatability, versatility, reliability, tolerance of solid particles, and more recently low pressure drop and high performance.

N.K. offers some installation guidelines such as to avoid installing the Coriolis sensor at the highest point in the pipe. This is where gas is most likely to separate out. As I mentioned in an earlier entrained gas post, digital signal processing can filter out signal disturbance caused by slug flow conditions.

Unlike many of the other flow measurement technologies, Coriolis meters can be installed without long, straight pipe runs upstream and downstream which can simplify the installation. In applications with very high flow rates, it may make sense to install multiple Coriolis flowmeters in parallel. The total flow measured is the sum each output.

The article also describes OIML approval standards and proving methods to meet regulatory requirements. If you are considering alternatives for flow measurement in custody transfer applications, this article might help in your analysis.

Recently, one of my RSS feeds alerted me to a new Micro Motion 2400S transmitter packaged in stainless steel for the ELITE Coriolis flow and density meter line. This 316L stainless steel packaging is:

Rated to IP66 and IP67, the corrosion resistant stainless steel housing is ideal for applications where instruments are subjected to regular caustic wash-downs, which are typically found in the food, beverage and life science industries. The 316L construction is also ideally suited for marine and offshore environments.

I caught up with Emerson's John Martin, a Food & Beverage industry manager for the Micro Motion family of products. I wanted to get the story behind the design of this product.

For those that have never been inside a food & beverage or pharmaceutical manufacturing process, John shared how you'll be struck by the bright, shiny silver look you see around the process. Hygienic standards are paramount in these industries and a mild caustic (e.g. sodium hydroxide) is often used to wash down the processing equipment. Standard painted-aluminum transmitter housings do not do well in this caustic environment. This new 316L stainless steel housing allows the transmitter to be integrally mounted with the Coriolis meter and provides a local display at the measurement point for the operations personnel.

John noted that normally, transmitters with aluminum and painted-aluminum housings had to be mounted remotely, in stainless steel enclosures or control rooms, to avoid the corrosive environment. This installation method meant more engineering and installation costs.

This 2400S transmitter supports DeviceNet and Profibus DP communications. These are common digital bus communication protocols used by PLCs and other automation systems like Emerson's DeltaV system. Across two wires, these transmitters communicate process and diagnostic information back to the controllers. From the press release:

The result is that one instrument can provide flow, density and temperature measurements, eliminating the need for multiple sensors and the wiring/configuration costs associated with them. In addition, digital communications unlock instrument diagnostic information, such as drive gain, meter verification and other alarms.

John also shared with me that other industries like offshore oil and gas and other marine environments have corrosive environments caused by saltwater and salt in the air, making them good candidates for this stainless steel transmitter housing.

I do know from my days back as an engineer working on offshore Gulf of Mexico oil and gas platforms, that we put the instruments with painted aluminum housing inside 316 stainless steel junction boxes to protect them from the corrosive, salt-air environment. This packaging option might have reduced the size/number of junction boxes required.

Update: I just saw a Twitter "tweet" from @timalosi who reminds me:

there is more to hygenic than stainless. draining is much more important. the Housing is just for looks

Tim, point taken and all in 140 characters or less!

I know that sometimes these posts can get fairly deep technically. Being Friday, here's one I hope you won't find so deep. It's about an email I received from one of our very senior SureService engineers, Randy Pratt, who was recently out working with an offshore oil and gas producer. These stories are especially near and dear since this is the industry I worked in as a systems engineer to begin my career.

For those that have never been out to an offshore platform, it's a whole 'nother world of steel, pipes and equipment. Typically, you whisk in and whisk out on a helicopter to take care of the business that needs tending to. For Randy, that meant doing a Premier Service visit where he spent several days with the systems engineers and technicians looking at all maintenance aspects of their DeltaV system. This visit also provided the opportunity for Randy to answer questions and share his experience gained over the years.

Now after a few days out on the platform, Randy was ready to head back. Unfortunately, the expected "whisk out" part was not possible. A hydraulic pump on the helicopter failed during the pre-flight checks. The good news is that it was discovered while the helicopter was on the helipad and not while in flight back to the main island, a trip of 80 kilometers or 50 miles.

Randy got to experience the other way to get off of an offshore platform, via boat. Back when I did this in the mid 1980s in the Gulf of Mexico, we typically used a rope swing from the platform's boat landing out to the crew boat. When there were swells in the Gulf, you had to be pretty good at timing your swing to make sure the boat was on the way up. It was a little tricky to go from a stationary platform to a moving landing target.

It's gotten a little more high-tech in the decades that have passed. Randy got to be "frogged" which means being lowered in a personnel transfer capsule by crane down to the boat below.

Randy concluded his adventure with a three-hour boat ride back to mainland, followed by more conventional means of transportation back to Austin.

I just wanted to share this interesting working slice of life for those of you not in the industry.

Update: I just received an email letting me know that the pictures which I upload to Flickr were being blocked by this person's IT organization... *&%$#&*. I like using Flickr because it thumbnails the photos, allows me to tag them, and creates the HTML code for me to paste into these posts.

Please let me know whether these pictures are being blocked at your site. Here's the three pictures:

I'm also curious if any other social media sites are being blocked (YouTube, LinkedIn, FaceBook, Del.icio.us, Twitter, etc.)

Update 2: At ControlGlobal.com, Walt Boyes picks up on business uses for social media sites like YouTube and Flickr. See his example of the U.S. Chemical Safety Board's YouTube Channel, if you can.

If you can't see this channel which shows video analysis of plant safety incidents, you now have a great argument on the need for your IT organization to unblock this site.

Update 3: Thank you Gary Mintchell for adding visibility to the plight of process manufacturers with "Mordoch, The Preventer of IT Service" departments who are blocking YouTube and other social media sites. Let's get a Groundswell going here!

Recently my Emerson RSS news Feed alerted me to a wireless application on a North Sea oil and gas platform. I sent a note to the team involved with this project asking about their perspectives.

I received great notes back from Jeremy Fearn, a Smart Wireless Specialist based in the United Kingdom and Rolf Jenssen, a manager in our Norwegian Asset Optimization organization.

The overall challenge this oil and gas producer faced was the desire to measure annular pressure of the wells remotely by replacing the local pressure gauges. These measurements monitor the integrity of the tubing and annulus in the area between the production tubing and well casing.

Now, from my days on oil and gas platforms in the Gulf of Mexico, I recall that adding pressure measurement around the wellheads can be difficult and cost prohibitive. As Jeremy points out, this requires cable tray, cables, installation, drawings, man-hours, transportation and accommodation of the team to do all this. Also, the areas around the wellheads are classified as hazardous areas.

The team found the easiest and least disruptive way to replace the existing local pressure gauges was to use a gauge adapter with the Rosemount wireless pressure transmitters. This provided a direct replacement of the manual gauges with the wireless devices.

Another challenge was the distance between the wireless gateway and the room with the automation systems and AMS Device Manager software. Jeremy described their solution to use the fiber optic option for an Ethernet connection to the gateway. A short length of fiber optic cable was used to connect from the wireless gateway to a nearby cabinet room. This room contained spare optical fibers, which allowed the team to connect through to the process Ethernet backbone.

The platform already had AMS Device Manager software used for on-line diagnostics of 125 valves equipped with HART DVC controllers. AMS Device Manager also included an AMS OPC server. This software pulled in all the wireless pressure readings from the wireless gateway. From here, the data was passed to an OPC client on the host automation system. The AMS software also tagged all the parameters in the wireless HART transmitters, making it easy to select a parameter showing the overall quality of the measurement. This meant the quality of the measurement also could be transferred to the operators on the automation system. For detailed information about the status, configuration and health of the wireless transmitters, AMS Device Manager with EDDL files is used, clearly showing any failures.

Rolf also noted that the automation system's OPC client during the set up uploaded all of the values and parameters available from the AMS OPC Server, taken from all the platform HART devices including the wireless devices. After the selection of the pressure, temperature and the overall quality value, the team deleted the whole upload, but the selected values for the OPC links were now updated continuously to the operators, included the annular pressure measurements.

Initially, the staff engineers thought that two wireless gateways would be required, due to the density of the platform and production equipment. It turned out that only one gateway was required. All devices were able to communicate with the gateway. In fact, the device mounted furthest from the gateway still found a direct path! As more devices are added in the future, the strength the self-organizing network will be increased from additional wireless signal pathways.

The team took two days less than expected to complete the installation, and the oil and gas producer's staff has performed similar installations on other platforms without help from Jeremy or the other wireless consultants.

The real benefit is that the annular pressured is monitored continuously by the operations staff rather than twice a day through manual readings. Pressure drop in the annulus might indicate a problem with the well. These continuous measurements provide operators an opportunity to take corrective action much earlier to help avoid well rework and lost production.

I'm catching the session, Realized Benefits from Foundation Fieldbus at the ISA Expo 2007. ARC Advisory Group's Larry O'Brien moderated the session.

The first part of the session looked at BP's use of Foundation Fieldbus (FF) in an onshore oil & gas production SCADA application in the U.S. state of Wyoming. They tested various suppliers systems and field devices in the harsh Canadian winter environment to compare the robustness of the various FF offerings. At each well site of eight wells, control was run in the FF devices, which in turn were connected, into their remote terminal units (RTUs). They saw immediate project savings in the wiring/installation labor/physical footprint savings. A key benefit they saw was remote diagnostics into these devices from a central location.

Next Suncor Firebag shared their Foundation fieldbus experiences. Suncor has standardized on Foundation fieldbus for all capital projects. Firebag has 9-10 billion barrels of reserves using today's extraction technologies. The extraction efficiency is expected to increase over time and these known reserves will increase. Suncor documented commissioning savings of Foundation fieldbus versus conventional devices of one sixth of the time. The benefits cited included faster time to first oil, and instrumentation maintenance practices moved from preventive to predictive. This helps eliminate unnecessary maintenance and avoid unplanned shutdowns.

They are currently looking at applying the statistical processing from the high-speed history in the FF devices to detect flame flutter on furnace and boiler flames. Another application they are investigating again with this high-speed sampled data is early detection of water hammer conditions in piping. This condition can cause millions of dollars in damage to the pipes if it is unchecked.

Emerson's Marcos Peluso gave a quick overview of the case for control in the field and robustness as measured by mean-time-between-failure. The key is the communications path is shorter when the control loop executes between a sensor and final control element than when it is between a sensor, automation system controller, and final control element. The loop can also execute with more certainty with the execution times of the fieldbus segment. Marcos indicated that the application should determine whether control is run in the automation system controller or in the FF device. There are strengths to each approach.

EnCana next presented how they could get gas compressor stations up and running more quickly with Foundation fieldbus devices than with conventional field devices. For their installations, all control was run in the field devices. This designed proved helpful in avoiding lost production when batteries did not hold their charge from solar panels. The remote terminal units and wireless network transmitters dropped out when the battery voltage dropped, but the FF devices kept running. Operators drove to site after they lost communications but found the compressors continuing to run with the loops fully in control. Overall, they we able to reduce operating expenses by linking together their remote compressor stations by centralizing the operators window into their decentralized control. Troubleshooting could be done remotely which reduced downtime.

Finally, Shell briefly shared their Foundation fieldbus experiences. While they agreed with the project savings others had experienced, they saw the biggest value in moving from preventive to proactive maintenance. They recommended this is where process manufacturers should spend the bulk of their planning efforts. This process often involves a cultural change so it takes time and quite a bit of planning and execution. Their approach is to have focused resources continually reviewing the diagnostics from intelligent field devices and performing maintenance based on this information. They cited savings in the millions of dollars from shifting to this approach.

As more people discover various posts over the past year and a half, I receive a number of great questions. Here is a recent one. The specific operating parameter details have been omitted, but I wanted to share the flavor of the question and the answer.

We have a customer that uses a turbine flowmeter for natural gas metering. Based on the furnace-cycle time demand, cubic gas volume demand, no-flow shutdown time, our supply pressure at the metering station, and piping distances between metering station and furnace, we´d like to calculate the Dynamic Response Error due to the shutdown time in this system.

Jorge Gomez is an application manager in Emerson's Remote Automation Solutions business and is located in Brazil. He also provides support for Daniel flow products. Jorge worked many years in Brazil's national flow lab and has quite a number of contacts with flow technicians in TÜV SÜD's NEL, Germany's Physikalisch-Technische Bundesanstalt (PTB) and the US National Institute of Standards and Technology (NIST).

Jorge provides the following guidance:

Measurement of gas flow with turbines in a cyclic flow rate as you are asking is always a big problem--the main reason is that the turbine meter has a natural inertia in the rotor that cause a overmetering when the flow rate stops (the rotor keeps turning a time after the flowrate stops.) Usually this overmetering is not totally compensated by the rotor inertia when it starts to move when the flowrate returns. In other words, a turbine meters tends to show a positive error in a cyclic flowrate.

The estimation of this error is not easy, because it depends on the dynamic response of the meter that is variable depending on the model, design of the blades, mass of the rotor, wear of bearings and even the flow profile and how the flowrate changes (suddenly, slowly, pulsating, etc.)

There is a good study presented in ISO TR 3313 standard (measurement of fluid flow in closed conduits-guidelines of the effects of flow pulsations on flow measurement instruments). Despite this standard's focus on orifice plates, there are sections covering turbines (6.2) and vortex (6.3)--these are meters especially susceptible to unsteady flow.

This standard presents a theoretical approach, but the main question is estimates the dynamic response parameter, that is strictly empiric (obtained from experiments). This standard suggests this parameter for turbines from 2" up to 6" for gas and liquid flow, but the suggested parameters can be always questioned. You can also obtain this parameter from experiments on a calibration bench, although I don't know if this is possible in your case.

The standard also presents a very comprehensive bibliography, and you can purchase and download it from the ISO site.

From a practical point of view, maybe the best solution, especially if this is a custody transfer measurement--as it seems to be--is thinking about use of a flow sensing technology less affected by unsteady flow, like ultrasonic, Coriolis or even differential pressure measured across orifice plates.

Earlier I mentioned Emerson's Dean Taggart's work with complex sequences in safety instrumented systems, based on an ongoing oil sands gasification project. John Kingston, from Emerson local business partner Spartan Controls, is presenting on this topic along with Emerson's Chuck Miller at the upcoming ISA Expo 2007.

I received a copy of the submitted paper that, among other things, explores the separation between basic process control systems (BPCS) and safety instrumented systems (SIS). Historically, the SIS was a separate entity, but with technological advances, this has begun to change. The authors note that the IEC 61508 international safety standard does not provide a definition of separation. It does mention physical separation as a highly effective technique. Given that the standard is much more performance-based than prescriptive-based, they note that there are few statements defining separation.

The paper refers to a few specific clauses in 61508-1 such as 7.5.2.4, where when the control system places a demand on one of the safety-related systems, then it "...shall be separate and independent" from the safety-related systems. In order to satisfy this clause the control system must be proven sufficiently independent from the SIS. Certification agencies like the various TÜV organizations and other third-party testing labs help provide this proof for SIS suppliers per the IEC 61508 performance standards.

61508-1 Clause 7.6.2.7 addresses common cause failures by requiring functional diversity, technology diversity, diverse parts, services, and support, and that the BPCS and SIS not share common operational, maintenance, or test procedures, and that they be physically separated. Safety instrumented systems like DeltaV SIS address these in the authors' words:

Those factors [governing independence] include diversity, which essentially means that the BPCS and SIS should have different components, operating systems, chip sets, central processing units, etc. When looking at sharing parts, services, and support systems, once must ensure that the BPCS and SIS have different power sources, and that a safety network dedicated to safety related communications is used. They should not share test procedures, which means that if you are testing either the BPCS or the SIS, that those tests should be able to be run completely independently of each other. Finally, physical separation applies to how the architecture of the system is laid out, and how cabinetry is designed; in essence, this is where one would look at separating DCS cabinets from SIS cabinets, and perhaps maintaining the SIS from a different workstation than the one used for the BPCS.

A final clause that is discussed, 61508-2 Clause 7.4.2.3 explores how non-safety functions implemented in an SIS need to be treated as safety-related unless it can be shown it is sufficiently independent (that the failure of any non-safety-related functions does not cause a dangerous failure of the safety-related functions.) This implies that control and safety functions can exist within the same system as long as sufficient care is taken in design and throughout the IEC 61511 safety lifecycle.

The authors summarize the implications of separation well:

Essentially, everything all boils down to good engineering designs and practices. One must consider the standards carefully, and understand the implications before going down a certain path. One cannot simply look at a system and know if it satisfies these requirements, because almost every system has a different level of independence. One must look at the specific details of a system to verify that it satisfies the requirements.

Dean summed up how these applied to the asphaltene gasification project:

The complexity of the process led to a need for integration as well as separation. Integration brings the benefits of integrated development and operating environments, less training cost, simpler architectures, faster and more reliable communications, reduced integration time, better handling of status information, and improved fault handling. The safety requirements of gasification focus on preventing damage to the burner, reactor, and syngas cooler, as well as operator safety. The process itself leads to the need for an intricate startup, as well as multiple methods of shutting down the process depending on the current state. An integrated but separate solution can provide several advantages while still providing the required amount of separation.

One of the challenges in converting the Northern Alberta oil sands into usable energy is the tremendous amounts of natural gas consumed in the process. The supply and cost of this resource is a major cost factor for Oil Sands producers.

OPTI Canada and Nexen are the first to introduce large-scale gasification into the bitumen upgrading process in the Long Lake project. This process uses the Shell Gasification Process (SGP) processes which takes the liquid asphaltenes from OPTI's OrCrude process and produces hydrogen for the distillate hydrocracking process, synthetic gas for the bitumen recovery process and fuel for power and steam generation.

The economic benefit of this process is well described in a 2004 paper, Gasification in the Canadian Oil Sands: The Long Lake Integrated Upgrading Project:

The energy balance of the project... demonstrates the elimination of virtually all of the natural gas cost exposure, which results in an operating cost advantage of about 50% over currently-configured operations.

Stephen Krause, a specialist in Emerson's Hydrocarbon and Energy Industry center based in Calgary is involved in the project engineering on this large, complex first-of-its-kind project. Much like processes found in other industries like refining, Stephen told me that gasification is an extremely complex process that requires extensive safety design to mitigate risks. I highlighted some of these safety design challenges in an earlier post. Some of the goals with respect to safety, automation and modular aspects of this project are described here.

Other Oil Sands producers are watching this project unfold as they consider including gasification as part of their upgrader project. And, the experience gained by Stephen and the Emerson project team will greatly help these producers as the future projects unfold.

For complex processes like gasification units in the Oil Sands region of Northern Alberta, Canada, how do you handle the integration of complex sequences which involve both the safety instrumented system (SIS) and control system (BPCS--basic process control system in safety-speak)?

This was the subject of a recent paper given by Dean Taggart, a professional engineer and certified functional safety expert (CFSE) in Emerson's Calgary-based Hydrocarbon and Energy Industry Center. Dean gave this paper along with members from Spartan Controls and the oil and gas producer, OPTI Canada.

The team gave the paper, Integration of Complex Sequences using DeltaV (presentation), at the 2007 AIChE Spring National meeting. Dean and the team quite comprehensively covered the areas of process and safety requirements and their technical concerns, and applying an implementation framework to this project.

With this post, I'll zero in on the decisions of what should be within the span of the SIS and BPCS. As the team states, it's clear what initially goes into the SIS:

Normally the process is designed in a Front End Engineering Design (FEED) phase, where vessels, pumps, piping, and instrumentation are proposed. The process goes through a HAZOP process, with the intent of identifying hazards. As these are considered, either through a PHA, LOPA, or Risk Analysis, SIL targets are determined and requirements for SIS are established [hyperlinks added to help with acronyms].

For complex processes, the SIS may be involved in the startup or stopping sequences, like in the burner management system on a gasification reactor. Normally the process of burner management involves closing off the feeds and the burner goes off. But for a gasification reactor, under high pressure and temperature, the vessel must evacuate the asphaltene quickly or it will harden and plug up the feed lines. A shutdown sequence is required to depressurize and cool down in a non-damaging way.

The choice the project team faced was either to perform all of the startup and shutdown sequences in the SIS or split them between the SIS and BPCS. The issue with splitting the sequence is increased configuration complexity, data mapping, communications diagnostics and handshaking logic required. And some common methods for this communication like MODBUS/serial communications and OPC, the communications throughput has to be carefully designed and tested. A bigger concerned stated in the paper:

In order to work properly, the BPCS and SIS would have to have "parallel" sequences which would need to be synchronized very tightly with each other. In the event that communications was lost during a startup or shutdown, each would have to execute separate and parallel actions. Since the actions may need to be modified based on process conditions, this adds even more complexity.

For this project, the team used the DeltaV system and DeltaV SIS and ran the sequence in the DeltaV SIS. The paper describes a simpler approach:

Under normal circumstances, the SIS runs the sequence, can override the BPCS when required, and can examine the health of the BPCS. The BPCS only performs process control, listens to the SIS for overrides, and can examine the health of the SIS. If communications is lost, the SIS can take the appropriate action (perhaps abort a startup, execute a shutdown, or may do nothing at all if in normal operation). In this case, the BPCS may continue to execute process control on some loops, and for others they may automatically be set to override or manual mode. The flexibility is there, and there is little concern over loss of communication.

If you have a project with hazardous areas with control system and SIS requirements, this paper is an excellent resource for an approach to think through the design process.

Here at the Emerson Exchange we're now into the workshops where process automation professionals, Emerson technologists, and Emerson industry, project, and application professionals share some of their experiences.

Dave Horan, has 17 years with Emerson's Rosemount division. Dave works with many of the engineering contractors on large projects on their instrumentation requirement. His presentation is on a shallow-water offshore project off the coast of Venezuela.

The project had a floating storage offloading, central processing facility and wellhead platform. The central process facility (CPF) basically cleans up and separates the produced fluids from the wellhead platform. Produced water and some gas is re-injected to the reservoir to help keep the production flowing.

The largest problem in this project was 40 skids coming from 23 vendors located on 2 continents. The number of possible permutation in types of instruments is huge given so many skid suppliers. This would create a real training and maintenance headache to support these once the CPF was started up. The challenge was to manage the skid vendors to standardize on a set of instrumentation to reduce the permutations.

For the Rosemount transmitters, up front planning was done with the oil producer's engineering team to pre-select appropriate instruments that could be used by all the skid vendors. For this project, all skid vendors had the same project manager in Emerson's Rosemount organization, to specify and purchase the transmitters. Standardization was enforced for model numbers, materials, mounting brackets, and local indicators to name a few instrument selection parameters.

The project management group provides project managers, engineers, project documentation, quotations, data entry, logistics and other functions/deliverables required to achieve the project milestones.

The goal to reduce the variations of instrumentation was achieved meeting the project objectives of an on-time project and minimizing training and ongoing maintenance.

Many process manufacturers have flow metering stations where ownership of incoming raw materials, intermediates, and/or outgoing products change. This custody transfer process is common with oil and gas producers, refiners, and chemical/petrochemical manufacturers.

Accuracy is critical since these measurements impact the bottom lines for both the seller and buyer. And, with the introduction in the U. S. of the Sarbanes-Oxley (SOX) Act of 2002, companies are required to put the controls in place to prove the accuracy of these measurements. Other countries have similar regulations requiring these documented proof-of-accuracy processes.

Robert Fallwell, a regional manager in Emerson's Metco Services business, has written an excellent article, Sarbanes-Oxley audits: coming soon in the July issue of Control Engineering magazine.

Robert shares his expertise on how process manufacturers need to prepare for the SOX auditors. He boils it down to:

...they ask for proof that flow measurements are accurate, that you have procedures to ensure measurement accuracy, and that the plant's operators, engineers, and production accountants have been trained in the correct procedures for the measurement control process.

If your business is impacted by SOX or similar regulations, you'll want to incorporate some of the ideas presented in this article.

Many industries such as oil and gas production, gas distribution, and LNG processing have the need to communicate over long distances without having readily available communications infrastructure. These manufacturers require voice, data, and/or video communications to operate reliably all day, every day.

I caught up with Gavin Jacobs who manages the telecommunications and network technologies project team for Emerson's Hydrocarbon and Energy industry organization.

Gavin's team works with the process manufacturer by starting with a conceptual design which analyzes and defines the requirements for the project. From this point, the architecture and technologies are recommended along with a project plan and schedule. The key to the design is to use the latest, proven technologies, and build upon the group's best practices standards.

In putting together the plan, the team draws upon their individual experts in local area networks (LANs), wide area networks (WANs) and the methods of transport including radio, satellite, microwave, telephone leased lines, fiber, spread spectrum, and traditional copper cable. They also work with the various LAN/WAN and data acquisition protocols required including TCP/IP, UDP, MODBUS, BSAP, and DNP3. And the group works closely with the suppliers of switches, routers, wireless, cables and other equipment required for the communications networks.

Beyond the upfront consultation and planning, Gavin's team performs detailed engineering, and follows it through with the implementation, integration, installation, and commissioning. One of the most common causes of LAN communications issues is improper cable installations. This is a critical part of the design, and it should be well documented to minimize installation issues. Also, having equipment and cables rated for their operating environments is critical to reliable and safe operations.

The commissioning process involves validating the communications throughput, monitoring and trending the physical layer, validating packet routing, validating security, and monitoring the protocols to eliminate sources of potential service disruptions. Some of this diagnostic information is often integrated with the manufacturer's maintenance management system to provide a central area for managing any issues with the network.

Gavin's team often provides ongoing operational support to help these manufacturers take advantage of communications improvements and cost reductions in these technologies.

As more and more process manufacturers incorporate digital busses into their automation architectures, debates often occur whether to limit the plant to a single bus or to incorporate multiple busses.

You can see both sides of this argument on a Foundation fieldbus forum in a Mixing fieldbuses thread. The original question posed:

In a new plant scenario, lets say an 800 point I/O count with about a 50-50 mix of analog and discretes. I think it's a no-brainer to go FF [Foundation fieldbus] where applicable for the analog control/monitoring. The question is, the remaining 400 or so points where we need shut-off valves, motor controls etc. what do we do?

Multiple buses should not be mixed in a system, not because it can't be done, because it can be done using most control systems in the market today, but because the system gets messy and expensive to operate and maintain.

Emerson's position in this debate differed greatly and was well articulated by Dewey Kuchle in our Hydrocarbon and Energy Industry Center in Calgary.

His key points in this forum thread include:
1. Remember the objective is to have projects on budget, on schedule, and operate efficiently. The selected technology is a means to this end.
2. No one digital bus technology is best for all the types of transmitters, actuators, motors, analyzers and other process instrumentation. Each technology and how it is implemented in the various process automation systems has its strengths and weaknesses. Pick the right one for the job.
3. Nothing beats "hands on" to compare the various systems and how they implement these digital busses like Foundation Fieldbus, Profibus DP, DeviceNet, and AS-bus. This is a great way to see what it takes to engineer, install, commission, operate and maintain them.

Digital busses like Foundation fieldbus are great for much of the process measurement and actuator instrumentation. It can be used, but is not as good a fit for motor control centers as DeviceNet or Profibus DP. The ideal situation is to have a single architecture that can support all of the most common busses and integrates them seamlessly, like our DeltaV system.

Conversely, these more discrete-oriented busses cannot pass back to the engineers, operators, and maintenance personnel the predictive diagnostics that intelligent measurement and actuator instrumentation contain that help run the process more efficiently and with fewer upsets.

Most of the reasons for the differences are the analog or discrete starting points of the technologies. Without delving into longer explanations, I will point to PlantWeb University's Engineering School which goes into the choices and tradeoffs in the "Choosing the right bus" section.