Emerson Process Experts

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!

Tags: oil&gas | offshore platform | production platform | personnel transfer capsule | YouTube | Flickr | Groundswell |

March 28, 2008 in Oil & Gas, in Support Services | Comments (0)

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.

Tags: wellhead | annulus pressure | annulur pressure | EDDL | OPC server | self organizing network |

March 11, 2008 in Asset Optimization, in Measurement, in Oil & Gas, in Wireless | Comments (0)

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.

Tags: Foundation fieldbus | capital projects | preventive maintenance | proactive maintenance |

October 4, 2007 in Foundation Fieldbus, in Oil & Gas, in Refining | Comments (0)

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.

Tags: flow measurement | turbine meter | natural gas metering | dynamic response error | cyclic flow |

August 27, 2007 in Measurement, in Oil & Gas | Comments (0)

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.

Tags: IEC 61511 | IEC 61508 | safety instrumented system | SIS | BPCS | asphaltene | gasification |

August 24, 2007 in Gasification, in Oil & Gas, in Safety, in Technologies | Comments (0)

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.

Tags: oil sands | tar sands | gasification | upgrader | bitumen |

June 27, 2007 in Gasification, in Oil & Gas, in Project Services | Comments (0)

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.

Tags: IEC 61511 | safety instrumented system | SIS | HAZOP | PHA | LOPA | SIL | basic process control system | BPCS | complex sequence | oil sands | gasification | AIChE |

May 21, 2007 in Oil & Gas, in Project Services, in Safety | Comments (0)

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.

Tags: Emerson Exchange | project management | project services | instrumentation |

October 3, 2006 in Emerson Exchange, in Oil & Gas, in Project Services | Comments (0) | Trackback (0)

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.

Tags: Sarbanes-Oxley | custody transfer | regulatory compliance | flow measurement |

August 8, 2006 in Chemical, in Custody Transfer, in Measurement, in Oil & Gas, in Refining, in Regulatory Compliance | Comments (0) | Trackback (0)

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.

Tags: telecommunications | LAN engineering | WAN engineering | oil and gas |

June 21, 2006 in Miscellaneous, in Oil & Gas | Comments (0) | Trackback (0)

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.

Tags: Foundation fieldbus | digital busses | Profibus | DeviceNet | As-i bus |

March 7, 2006 in Digital Busses, in Oil & Gas | Comments (0) | Trackback (0)