Emerson Process Experts

I received an email from Anand Iyer. He's a certified project management professional (PMP) and a project manager in Emerson's engineering center in Pune, India. His project experience covers the gamut from pharmaceuticals, bulk drugs and intermediates to oil, gas and petrochemicals.

He's sent me a paper he's written entitled, Collaborative Measurement Control System Engineering. It describes how measurements close to one another in the process can collaborate with one another to verify their operation. He describes an example around a distillation column:

Now let us take two temperatures (bottom temperatures) in a distillation column and a level measurement. When the level is normal, the two temperatures are same or have a fixed relationship between them. TI1 is placed at a lower level in the column (near bottom) and TC2 is at a higher level (and used for Temp. control). Now TC2 is generally used for control. We can safely say that if Level is normal, and TC2 is under maintenance, TI1 can be used for control (with a minor adjustment to Setpoint if required). Thus Level and Thermocouple TI1 put together can "collaborate" the measurement of Temperature-measurement TC2.

Anand contrasts the traditional approach to a failure with how collaborative measurement strategies can be used in control strategies to avoid outages or process disturbances. In the traditional approach:

…the first thing done if an element were to fail was to swap the elements (either during the shutdown caused by the failure) or by a planned outage or having the loop in manual and doing the swap. At times, we have also used our ingenuity and just swapped the wires at the analog inputs and tuned control setpoints to have the plant up and running in a very short time. And hopefully, in all that chaos, someone had the presence of mind to record the swap on the wiring diagrams.

Using a collaborative measurement strategy:

…says that if level is not low and TC2 is not available then TI1 can be a valid measurement. We alarm the operator that TC2 is not available, fine tune the setpoint if required… All this occurs automatically and there is no outage or disturbance that could result in quality issues.

He extends the thought to Foundation fieldbus devices where the final control elements themselves can perform the logical evaluations and select the available primary or collaborated measurement, increasing the overall robustness of the control strategy. Anand also extends his thinking to wireless devices and how they could be used in a collaborative measurement environment—not as a primary measurement, but as a collaborative measurement to check on other devices nearby.

I hope you'll give Anand's paper a read and add your thoughts.

Tags: collaborative measurement | project management professional | PMP | Foundation fieldbus | distillation column | measurement strategy | control strategy |

March 12, 2008 in Control Strategies, in Distillation Column, in Foundation Fieldbus, in Measurement, in Project Services, in Wireless | Comments (0)

My RSS feeds pointed me to a great ChemicalProcessing.com article on batch manufacturing alarms. The article, Rethink batch-manufacturing alarm systems, was written by Joseph Alford.

He opens with provocative questions:

Do operators sing the praises of your plant's alarm system? No? Well, do they at least agree that generated alarms represent real abnormal situations requiring a response and that the automation/control system presents alarms in a timely, accurate and reliable way? No again? Well why not? Aren't operators the primary customers of your alarm system? Perhaps it's time for an alarm remediation project.

Many with continuous processes would agree that their alarm strategies implemented inside their automation systems need work. The complexity is amplified in batch processes because unique operating conditions are created within all of the numerous steps along the way.

The article boils down the crucial steps to take:

The key considerations in achieving effective alarm systems include defining objectives early in a project's life (i.e., in a plant's alarm philosophy or a system's functional requirements), adhering to the definition of an alarm, and implementing alarm-management best practices.

I ran this article by Todd Ham, a senior principal engineer in Emerson's Life Sciences industry organization. You may recall Todd from earlier posts.

Todd agrees completely that a successful alarm strategy begins in the functional requirements stage of a project. The project teams work with pharmaceutical and biotechnology manufacturers early on in a project to document their alarm requirements.

Todd stressed that a good strategy examines not only what conditions require an alarm—typically an adverse effect to personnel, product, or equipment—but also what is the desired response. Is alarm annunciation sufficient? Does this require a device interlock? Should this put the batch in hold? Does quality assurance (QA) need to be notified? This is called exception handling.

In a batch process, the requirements may differ based on the process step. For example, the alarm may be critical during processing, but not important during cleaning. Further, the alarm may only need to be monitored once the process is at steady state. In these scenarios, the control strategy developed by the project team will selectively enable/disable alarms at the appropriate point in the sequence.

Todd cautions that this is not a "one size fits all" exercise. The project team and manufacturer's staff must step through each process unit/system and ask a series of questions to arrive at a solution where alarms are both appropriate for a particular operating state and relevant for alerting operators to abnormal situations.

Todd agrees with the author that this work must be done up front, or the alarm flood, nuisance alarm scenario described in the article will be the result. You can't wait until the end of the project to think about alarm management. When you come right down to it, it's just as important as defining the control requirements for the project.

Tags: batch process | batch alarm | functional requirements | alarm management | alarm strategy |

February 29, 2008 in Abnormal Situation Prevention, in Alarm Management, in Project Services | Comments (0)

Emerson's Chuck Miller is one passionately guy when it comes to process safety and the international safety standards, IEC 61508 and IEC 61511. He is on a mission to put the focus of functional safety management where he believes it belongs—on the competency of safety professionals involved in the safety lifecycle.

Chuck noted a panel discussion he sat in on at last fall's ISA Expo in Houston. The panel discussed various approaches to process manufacturing risk mitigation. These included combining control and safety in the same control system platform, the standalone safety instrumented system (SIS) approach, and the separate-yet-integrated safety system approach.

An end user on the panel discussed the common platform approach. He emphasized that his company's internal policies and procedures for risk assessment, implementation, operations and maintenance were well understood and consistently applied. These factors drove the decision to implement systems in this manner.

A safety instrumented system supplier discussed the standalone SIS approach and one of Chuck's colleagues discussed the separate yet integrated approach that is represented by safety instrumented systems like DeltaV SIS. Using several advanced technology examples including advancements in diagnostic coverage; common programming environments and global databases the presenter illustrated how such technologies, when appropriately applied, provided measurable savings throughout the safety lifecycle without compromising the SIS's ability to conform to international safety standards, such as IEC 61511.

Chuck's revelation was that the real issue is not so much the philosophy, the approach, the architecture, or even the platform selected. What really drives a successful SIS implementation is competency. Each of the presenters was passionate about their approach being the best solution because their individual competency was based on that particular philosophy and approach.

His bottom line—functional safety management must be implemented around the requirements of a technology and supported by competent safety professionals that always ensure that the SIS solution is defined, designed, installed, operated and maintained in a way that meets its defined functional safety requirements throughout its lifecycle.

As this group of panelists demonstrated in their exchanges with the audience—there are several philosophies, architectures and platforms to mitigate process manufacturers' safety risks. It takes competent safety professionals to work with these throughout the safety lifecycle.

Tags: functional safety | process safety | IEC 61508 | IEC 61511 | ISA Expo | safety instrumented system | SIS |

January 29, 2008 in Project Services, in Safety | Comments (0)

I'm returning back to the U.S. from a week of meetings in Thailand. I'm struck by the sheer number of large greenfield projects being implemented and being planned across the Asia-Pacific region.

Over the past several years, Emerson project teams from this region have executed and are executing many of the mega-sized projects. Some examples from prior press releases include: Shanghai SECCO Petrochemical ethylene complex, Fujian LNG-import terminal, and Reliance Life Sciences therapeutic proteins manufacturing.

These projects are executed on a global scale with participation from project engineers from many countries in many world areas. Advances in communications and what can be done across the internet make global project collaboration and management possible.

While in other world areas we see a lot of experienced automation professionals retiring, in this world area a new generation of automation professionals is coming on the scene. They are learning the automation craft as these projects are executed and the new plants are operated.

Working on greenfield projects mean these new automation professionals get to use the lastest technologies like digital busses, controller-based advanced control, and enterprise connectivity to build plants that are more efficient than what is possible with prior technologies.

With my visit and new connections made, I hope to bring more stories of Emerson experts from this bustling region of the world.

Tags: greenfield project | automation projects | global project execution |

January 18, 2008 in Enterprise Integration, in Project Services | Comments (0)

A colleague recently pointed me to a Manufacturing Business Technology article, Red alert: Increase in process automation heightens need for safety-related systems. The article points to a recent Frost & Sullivan study which predicts the market for safety-related systems used by process manufacturers will more than double from 2006.

Quoting from the account of this research report:

It says users will welcome systems that address the underlying challenge of minimizing the trade off between process uptime and process safety. In addition, users will favor vendors that have significant technical experience in installing complex integrated safety solutions that monitor safety and non-safety functions while reducing the costly channels of diversified communication.

Over the past several years of blogging, I've discussed safety instrumented systems and the associated global standards, IEC 61508 and IEC 61511 on numerous occasions. Newer architectures like Emerson's smart SIS incorporate digital communications so that the complete safety instrumented function (SIF) can be continuously diagnosed to help the function perform when it should and not when it shouldn't.

Rather than being prescriptive and instructing process manufacturers what to do, the safety standards are performance-based. IEC 61511 allows you to investigate the alternative solutions for the right safety instrumented function for the safety integrity level (SIL). This means that more engineering work may be required to investigate these alternatives to find the best solution.

I think this where the "technical experience" part of the quote from above comes in. Emerson's Len Laskowski said it best in an earlier post:

This is great news for the engineering community because they get to do the engineering. However the bad news is they must do the engineering.

As process manufacturers address their risk-mitigation strategies and comply with the IEC 61511 standard, they will continue to work closely with those that can provide the technical expertise required throughout the safety lifecycle, from front end engineering and design to ongoing system maintenance.

Tags: IEC 61511 | IEC 61508 | SIS | safety instrumented system | FEED | front end engineering design |

January 7, 2008 in Project Services, in Regulatory Compliance, in Safety | Comments (0)

Engineers being the problem solvers that they are, typically enjoy a project in full execution mode. Problems must be quickly confronted and solved to keep everything moving forward. As we've mentioned in earlier posts, the part they typically like least is the upfront justification to get the projects approved in the first place.

Emerson's Pete Sharpe, a principal consultant in the Advanced Automation Services organization, shared his thoughts on automation investment justification with the readers of Automation World magazine. The article, Strengthen Company, Minimize Risk, pointed to areas of opportunity for project justification.

Pete's guidance is to look at the economic buckets your efforts in automation can influence, which boils down to increasing profits and minimizing risk. Simply put:

To increase profits, "you must either increase revenues or lower costs," he emphasizes. Revenue is a bucket on the positive side of the formula that is affected by things like throughput, yields, recoveries or product price. That means "you have to shift production toward the more valuable products, or increase yield, reduce off-spec, product losses and downgrades of product," Sharpe states. Cost-lowering considerations could involve maintenance, labor, energy, utilities or raw materials, among other areas.

Pete cites an example of looking at quality. Poor quality can lead to customer rejection, off spec and rework. Providing better quality than is specified in the contract is called "quality giveaway". It likely means additional costs are being incurred without receiving additional price for this quality. This is particularly relevant to commodity markets such as gasoline and diesel. Other potential sources of justification are in intangible costs like safety and environmental compliance.

Minimizing risk is about reducing the probability that something bad will occur in the plant's operation. These projects focus on improving reliability, safety, environmental liability, and dealing with abnormal situations. Risk can be evaluated based on the frequency and severity of historical incidents. Then appropriate application of technology and programs designed to mitigate the highest risk areas by applying such things as predictive maintenance, operator training systems or abnormal situation prevention technologies.

The key is to look for how your project will affect the throughput, production costs and total production value on an on-going basis. Ultimately, the expected financial return of the project will determine whether the project goes forward or not. The article sums this up:

...the ultimate metric for justifying investments is ROI. He notes that it includes the time value of money, and calculation of returns based on expected future cash flows from the investment.

In most companies, the management team evaluates potential projects based on the expected return and the risk associated with the investment. The projects with the highest rate of return and lowest perceived risk are those that will likely be funded. In almost all cases, the project return must exceed the manufacturer's cost of capital, which varies depending on company. Pete notes that there are exceptions where a low return, discretionary project is approved. This could be a "stay-in-business" investment decision, which ultimately is about reducing overall business risk.

Tags: project justification | quality giveaway | safety compliance | environmental compliance |

January 2, 2008 in Education, in Modernization, in Project Services | Comments (0)

In the process of moving hydrocarbon through the supply chain from producer to consumer, terminals play an important role. They receive liquids and gases from many sources including ship, rail and pipeline. These gas and liquid hydrocarbons are stored in tanks or vessels until required to move via other methods of transportation including barge, truck and pipeline.

I had the chance to view an upcoming article featuring Emerson's Cor Vermeijs. He's based in the Netherlands. The article explored ways for terminal operators to use automation to optimize the inventory management and operational efficiency of their terminals. The goal is to improve the quality, productivity and availability of the terminal and help the owner of the terminal lower the costs of operations and maintenance, improve environmental and safety compliance, and reduce energy usage.

He notes that many terminals today are manually operated from planning all the way to manually operated valves and pumps. This limits the availability of real-time information to make the most efficient schedules. These delays affect the throughput of the terminal, which directly affects its profitability.

In the article, Cor stresses the starting point should be to study the current operational processes. The key is to look for areas of inefficiency that can be automated. The study typically includes a cross-section of the organization from operations, sales and management. The output of this study is:

…a plan to optimize these processes, to automate them, and to implement them wherever necessary. The results of this site audit are issued in a report that gives the solution for the concept, a cost-benefit analysis, the payback period and a performance guarantee. It's all based on the best possible use of the storage tanks, the pumps, the pipelines and the jetties. The objective is as many product movements as possible without running the risk of product contamination or tank overfills.

Architecturally, when manual processes are automated, the information is collected in a single system. This information becomes the basis for a route planner. The system takes the recommended route with the corresponding pipeline segments, valves and pumps and links it to the data from the work order. This information can include the time when the route/transfer can be started, how long it will take, which ship or train will deliver the volume, and who is the owner. Cor sums this up:

…all information is available not only to the operator in the control room, but also to the man on the jetty, the planner and perhaps even to the captain of the unloading or receiving vessel. And it all takes place in real time, with immediate feedback of events such as a delay along the line, so that you can adjust your planning while the work goes on without interruption, thus increasing your terminal's efficiency.

Terminal management includes a number of processes including custody transfer accounting, inventory tracking, security management, loader or driver verification, load requests and initiation, permissives management, ticket generation, custom reports, remote dock monitoring, event logging, and system integrity management.

Tags: terminal management | oil movements | terminal operator | terminal inventory |

December 3, 2007 in Data Management, in Project Services, in Terminal | Comments (0)

Successfully executing a project with safety instrumented systems requires trained and competent project team members. They must be versed in the safety lifecycle as required by international safety standards—primarily IEC 61508 and IEC 61511 (ISA 84.01 in the U.S.) for the process industries.

To address this safety expertise requirement, TÜV and exida along with the support of other global safety experts created the Certified Functional Safety Expert (CFSE) concept. Its mission is:

…to ensure that personnel performing SIS lifecycle activities are competent as required by the IEC 61508, 61511, and 62061 [machinery safety] standards.

Currently there are two levels of certification, CFSE and CFSP (Certified Functional Safety Professional). The difference is mainly in practicing experience—ten years for CFSEs versus two years for CFSPs. The CFSE.ORG website describes the difference:

The CFSE is the higher level certification and is aimed at professionals who actively lead, coordinate and review the more complex and demanding activities in the Safety Lifecycle in leadership positions including SIL selection and SIL verification.

The CFSP is targeted at professionals who need a thorough understanding of the Safety Lifecycle activities at the execution level without necessarily leading, coordinating or reviewing the more complex and demanding activities.

CFSE.ORG reports that there are currently over 200 CFSEs and CFSPs in practice worldwide. The certification process is not easy. Those trying to take the test are warned:

…the certificate exams are extremely rigorous and often demand significant preparation in order to achieve the 80% passing grade for both exams. With this in mind, the Governance Board strongly recommends that all candidates develop an in-depth study plan to properly prepare for the examinations. The topics covered in the different exams and sample Process Applications Exam questions provided in the Specialties and General Information pull-down menus may be helpful in developing an effective study plan.

In view of the comprehensive nature of the exams, the Governance Board recommends that candidates put in at least 40 self study hours as part of their preparation for the CFSE/CFSP exams.

I bring all this up because I received a note from one of my colleagues in Calgary in our Hydrocarbon and Energy industry center. The news is that they have three newly minted CFSEs—David Goerzen, Prasad Goteti, and Ajmal Siddiq. Congratulations on your achievement!

I went out to the CFSE.ORG site and did a search on the 15 pages of CFSEs/CFSPs. As of today, November 27, 2007, I counted 38 Emerson CFSEs and 8 CFSPs. This is more than 20% of all the certified safety professionals in the world. The percentage is higher if you exclude the machinery safety professionals.

The organizational roles of these safety professionals run the gamut including projects, support, technology, sales and marketing. These organizations work with process manufacturers at various stages of the safety lifecycle to help meet their risk reduction goals.

Tags: IEC 61511 | IEC 61508 | CFSE | CFSP | functional safety | safety instrumented system | safety lifecycle | ISA-84 | S84 |

November 27, 2007 in Project Services, in Safety, in Support Services | Comments (0)

There may be reasons why you need to consider something beyond your automation system that has been running in your plant for years and years. It might be the need to more tightly control energy usage to reduce energy costs. It might be to improve quality and consistency to stay ahead of your competitors. It might even be that you are losing peoples' expertise to retirement to maintain this automation system.

The vernacular for this process varies—modernization, migration, or upgrade—but planning is an essential component. I caught up with Laurie Ben, who directs a team of modernization consultants in Emerson's Process Systems and Solutions business. They have expertise in Emerson systems and systems from other automation suppliers. They also have methods and tools to design a migration solution.

This migration process can range from a simple connection between systems all the way to a "rip and replace" project, depending on the business drivers prompting the change. Some plants have existing pneumatic and panel-mount controls. Downtime and reliability concerns often provide the justification required to transition these to the current digital communications-based systems.

These digital technologies provide ways to do hot cutovers to keep the process running while the automation is migrated from pneumatic to digital. An example of how this works is a Fisher Foundation fieldbus-based DVC6000f digital valve controller. Its pressure control functionality connects to a DeltaV system while also sending a pressure signal to the existing actuator or pneumatic positioner. Once these pressures are balanced within the system, control is transferred to the digital valve controller. During this phase, AMS Device Manager helps finalize the cutover by helping the team to communicate locally with the valve to monitor exactly what is happening during the process of mounting, adjusting, stroking, and calibrating the valve.

Laurie mentioned that operator consoles typically have the shortest life span of all the automation system components. It is often the first consideration for migration to a modern automation system. Newer operator workstations keep the look and feel of the operator graphics and faceplates and connect to the existing automation system. Over time, I/O and controller hardware and software can be migrated. The business drivers help dictate the pace of migration.

For instance, if energy cost reduction is the business driver, it may make sense to modernize the controller and I/O to get embedded advanced control capabilities. Units like lime kilns, fired heaters, boilers, etc. can be run more efficiently as a unit with model predicted control than as a collection of interdependent loops.

It really begins with your business drivers and developing a plan to move forward to modernize your automation. The hardest path is to justify it based on obsolescence since the calculation of ROI based on problem avoidance. The best path is to find cost reduction or efficiency-improving opportunities. These numbers are the basis for your financial justification calculations.

Tags: energy costs | system migration | system modernization | system upgrade |

November 16, 2007 in Modernization, in Project Services | Comments (0)

You may have seen quite a bit of news coverage (here, here) on wireless technology as it applies to plant instrumentation. At the recent Emerson Exchange, Emerson also announced some wireless news.

If you are an automation engineer, you might have thought about some applications where you would like to try this technology.

Your best course is to start with a simple business case. Perhaps the operators perform rounds to get readings from gauges and instruments not connected to the automation system. Having this information and associated diagnostics coming from wireless devices could possibly make your plant's instrument technicians more efficient.

I caught up with Mark Sagstetter in Emerson's Rosemount Measurement business. He recently went to a refinery along with John Biscone, a service technician in Emerson's Instrument & Valve Services business. Operator and instrument technician efficiency was the very business case this refinery was pursuing. Mark and John were contracted to provide their expertise to help plan the network and installation process of the wireless instruments and gateways. Much like the early days of digital bus technologies, this expertise can help automation engineers establish best practices for planning and executing future wireless installations.

In the course of a two-day site visit, they worked with the plant engineers and identified five process units including four tank farm locations that met the criteria for increasing operator and instrument technician efficiency.

My understanding when talking with Mark is that there are basically two overall best practices to follow when implementing a wireless field network. The first is planning the wireless network and the second one is the network installation.

When executing the best practice of planning the Self-Organizing wireless networks, Mark and John like to have scaled site drawings. Unfortunately, in this case, scaled drawings were not readily available. Necessity being the mother of invention prompted the team's great idea to use Google Earth to generate site maps. They used the printouts during the walk-through of these process units to help envision device locations, gateway locations, plot anticipated communications, and to help identify possible impenetrable situations.

As part of the best practice of planning the network, it is a good idea to plot at least two paths of anticipated good communications for each instrument. Using a color-coding scheme, with one color to mark anticipated good communications paths and another color to mark potentially interrupted paths of communication, John and Mark were able to use this process to help understand how the network may function when installed. It also helped to understand, plan for, and possibly eliminate possible pinch points and/or possible impenetrable situations before the actual installation.

With every Self-Organizing wireless instrument being capable of being a router (sending and receiving messages from other instruments), possible pinch points and impenetrables are easily overcome. This is accomplished with the addition of measured points or instruments that act as routers or range extenders.

During the installation-planning portion of the site visit, Mark and John recommended the plant engineers follow the wireless installation best practices. To do this, the plant engineers would need to power and commission the gateway first. Then install, power, and commission the instruments, starting with the instrument closest to the gateway and continue working outward from the gateway. The instruments' connectivity to the gateway should be verified each time after installing, powering and commissioning the instrument.

One thing I noted in my conversation with Mark is that the instruments mount with standard process connections. Engineers have been using these standard connections for years. The actual mounting location for the instruments and gateways were determined by providing a forearm's length (a measurement device every instrument technician has with them at all times) of space between the antennas and any wall or metal structures to avoid signal attenuation.

Installation would continue by powering, installing, and commissioning instruments outward from the gateway, until all the devices have been brought on-line. By installing the instruments in this fashion, the actual formation and connectivity of the wireless Self-Organizing network can be compared with what was expected during the best practice of planning the network.

Beyond the immediate need to help the plant engineers plan a smooth installation at this refinery, Mark and John helped them establish best practices to aid in future wireless projects/installations.

Tags: wireless field network | self organizing | wireless site planning | site drawings | wireless best practices |

October 25, 2007 in Measurement, in Project Services, in Wireless | Comments (2)

Jack Murray, a member of Emerson's Metals, Mining, and Minerals industry team, shared a paper he had co-written with an Alcan Gove bauxite mine and alumina refinery staff member and Emerson fieldbus consultant, Sudhir Jain. Alcan was recently purchased by Rio Tinto.

Their paper, Fieldbus Technology on a Large Scale Mineral Project, describes Alcan's path from the 4-20mA analog world to a digital bus communications world. Alcan's investigation of the benefits of moving from analog to digital began in 1999. They had seen possible ways to reduce their project costs and improve operations by using digital busses.

Their first step, like most when undertaking something new, was a small step. They chose to implement Foundation fieldbus in a non-critical area of an existing facility. Their initial installation consisted of 20 I/O. They chose fieldbus devices from a number of automation suppliers to obtain a greater breadth of experience. They also chose Profibus DP for their motor control centers and variable speed drives.

This experience proved beneficial when the decision was made in 2004 to nearly double refinery capacity to meet growing demand. The project consisted of 5,000 field devices and 15,000 total I/O including motors and drives. They used a DeltaV system and the two digital busses, Foundation fieldbus and Profibus DP, for which they gained experience to connect the majority of this I/O. A key part of their decision was to work with Sudhir during the front end engineering design (FEED) process to assist in the segment design, training of key personnel, and to establish wiring best practices and standards.

Sudhir related to me how they developed new hazard analysis procedures (CHAZOP, short for control HAZOP) to ensure that failure of any bus segment would not leave a critical part of the plant unmonitored or uncontrolled. Segment segregation practices were developed to address the findings from this analysis. They also had a 3D model of the plant site, so that questions of distance and pathways could be quickly addressed to help rapidly advance the engineering effort.

They chose a modular construction approach using pre-assembled modules (PAMs). These modules were assembled and fitted off-site and fully pre-commissioned before they were delivered to the plant site. These PAMs were self-contained units and included process vessels, piping, pumps, instrumentation and valves, all fully wired and tested.

The digital busses fit into this modular approach with test procedures developed and a portable DeltaV system used to test field devices and fieldbus segments within the PAMs. Once delivered to the plant site, it was much faster to hook up fully tested segments than to individually terminate and retest devices as had to be done on their analog-based projects.

The project team followed elements of the Construction Industry Institute (CII) PepC model. The paper describes this model:

In the new model procurement transactions for the most critical elements of the project (indicated by capital P) happen first and to a large extent define the next step, the main body of the engineering effort for the rest of the project (Capital E). This is followed by procurement of the materials for the rest of the project (small p), followed by the actual construction (capital C).

This model helped Alcan take advantage of the expertise of the suppliers involved in the project and aligned with their globally distributed engineering and procurement practices. It also supported their modular approach and the use of PAMs.

As with most every bus-based project, they documented savings in cabinet space, installation and commissioning. The real value was in the accelerated project timeline. In five fiscal quarters, 95% of the engineering, 76% of the PAM fabrication, and 54% of the on-site construction was completed. Alcan was able to meet their aggressive project schedules and get production on-line sooner.

Update: Welcome readers of Carl Henning's PTO PROFIblog. I'm not sure about the "voice of reason" part, but like Carl, I certainly agree that the benefits from the digital bus technologies outweigh the change in status quo from the analog world.

Read the Crossing the Chasm article to which Carl refers and judge for yourself. Feel free to let me know what you think.

Tags: fieldbus | digital bus | segment design | HAZOP | FEED | front end engineering design | CII | Constuction Industry Institute | PepC |

October 23, 2007 in Metals, Mining, Minerals, in Profibus, in Project Services | Comments (0)

While at the recent ISA Expo 2007, I had the chance to listen to Emerson's Jonas Berge's presentation on software for automation. Jonas is an active member in the ISA SP104 committee. This committee is responsible for advancing the Electronic Device Description Language (EDDL) standard.

A few years back he wrote a book, Software for Automation: Architecture, Integration, and Security. His presentation covered some of the ideas from the book. Specifically, he discussed these key points:

• Select technologies for software architecture
• Justify investment to management
• Where and how to deploy DCOM vs. Web
• Where each OPC flavor is used and how
• Integrate with business and coexist with legacy
• Troubleshoot DCOM and OPC
• Apply software and make the PC rugged
• Engineer and document software
• Backup, administer, and optimize
• Make it robust, safe, secure, and 21 CFR Part 11 compliant

The body of knowledge that an automation professional must understand to perform their job effectively continues to expand. As Jonas describes, the software architecture is as important to design as the hardware architecture. Information flows from devices connected from digital busses all the way through the automation systems to enterprise-level software applications.

Security concerns must be addressed and be part of this design. Cyber-security is an area of specialization unto itself and you can follow many of the issues and advancements at the Digital Bond and Unfettered blogs.

Jonas describes setup of networks and OPC, ODBC, and web services communications across networks and tips for troubleshooting these. One everything is functioning properly, methods of management and administration including backup and restore procedures are covered.

Jonas highlights the fact that this is a lot to plan and get right. If you find yourself overwhelmed and too busy to become an expert in this area, you are not alone. Many process manufacturers are working with their automation suppliers versed in this level of expertise to help on the project front-end and to help maintain these software packages and integration methods through their useful lifecycle. One example is Emerson's SureService support services.

Tags: ISA104 | SP104 | EDDL | automation software | OPC |

October 17, 2007 in Cyber-Security, in Interoperability, in Project Services, in Support Services | Comments (0)

Emerson's Mike Schmidt, a principal safety consultant in the Refining and Chemical industry center, presented Beyond 2oo3: Multi-sensor Architecture in SIF Design at the Emerson Exchange. You may recall Mike from an earlier post.

Mike discussed several cases and applications where more than three sensors are used in safety shutdown applications. Redundancy was his first example where more than one sensor is being used for the exact same purpose. An example is separate temperature sensors installed on the inlets to multiple reactors, perhaps because of fears of common cause failure. In fact, all three of these sensors measure the same thing. The inlet temperature is coming from the same header, so it is the same for all three new sensors.

Separate hazards are those serving unrelated purposes or are at independent points in the process. There is no redundancy here. The only possible architecture for the sensors is to have three separate instances of one-out-of-one (1oo1) voting.

Mike built the case of three tanks with three inlet temperatures sensors coming off a common header and said it could be argued that the three could be considered redundant. However, three sensors on the tank outlets could not be considered redundant since they are monitoring for separate hazards.

When evaluating fault tolerances, it is important to consider the number of success paths. Parallel paths provide redundancy where serial paths with multiple elements have single points of failure. If you have three identical temperature sensors in parallel, it is like having a path with three in parallel in series with common cause failure. Using different types of sensors greatly reduces this common cause failure to provide much lower probabilities of failure on demand (PFD_AVG).

Mike discussed the case of a packed-bed reactor. These may be instrumented with ten or more temperature sensors to provide a temperature profile. The safety trip will be based on an abnormal profile. With advanced logic solvers, it is possible to perform the calculations necessary to reduce several measurements to profile parameters that can be used to trip a safety instrumented function (SIF). The profile is 1oo1 voting, but a rule might be that 8 out of 10 temperature sensors must be working to be considered a valid profile, so the PFD_AVG is based on 8oo10 fault tolerance.

A separate issue to consider from a safety mitigation standpoint is multiple sensors for localized problems, like hot spots or leaks. Considering packed bed reactor hot spots, it sounds right to say we do not want to trip the reactor based on a single temperature sensor fault. Although this may sound right, Mike explored the math behind determining the PFD_AVG. The example here is for an array of sensors installed to detect a hot spot within the packed bed, but it could just as easily be an array of analyzers around the outside of a piece of equipment installed to detect a leak of flammable or toxic gases.

He discussed the concept of the temperature sensors located next to the failed one. The sensors are primary for their respective zones and secondary for their neighboring zones. The key is to set up a separate safety instrumented function for each zone, which contains the primary sensor and the neighboring secondary sensors. This allow the reactor not be treated as a single SIF where any one sensor failure can trip it.

The math works out that no matter how many transmitters, and surrounding zones, the PFD_AVG calculations are based on primary and one secondary, even in the case of multiple secondary zones. The voting is one out the number of surrounding zones plus the one primary zone, and the PFD_AVG is always based on 1oo2 fault tolerance. No credit is taken for any of the additional secondary sensors in the PFD_AVG calculations.

Mike summarizes these concepts by saying the number of sensors required for a SIF can be optimized to achieve the necessary coverage and the required redundancy. Using more than three sensors for redundancy does not really help. It may be necessary for coverage based on the geometry of the vessel, but not for increased redundancy.

Tags: safety shutdown | process safety | redundancy | fault tolerance | common cause failure | safety instrumented function | SIF | logic solver | sensor |

September 26, 2007 in Emerson Exchange, in Project Services, in Safety | Comments (0)

The ever-increasing global demand for energy requires tremendous daily global movements of crude and refined products. Offsite operations play a vital role in the hydrocarbon supply chain. These offsite operations provide the receiving, shipping and storage facilities for handling bulk liquid or gas products. These sites typically include tank farms, blenders and terminals for handling truck, rail, and marine transport.

Tank farms and terminals are found at various stages along the production process from oil & gas collection terminals to refinery terminals and depots, to primary depots where refined products are loaded and transported to your local gas station.

I caught up with Patrick Truesdale, a senior consultant, in Emerson's advanced automation services team. Patrick will be co-presenting with Emerson's Gerrie Benjert at the upcoming Emerson Exchange. Their topic is developing a business case for tank farm and terminal automation.

The biggest business challenge Patrick finds from his work with offsite operators is the lack of spare capacity throughout the global distribution system. Capacity utilization is at a maximum and assets in many of the established markets like North America and Western Europe are aging. This increases the chances for unplanned shutdowns. These facilities often lack flexibility to deal with changes in market demand.

Other challenges include increasing safety and environmental requirements and increasing compliance reporting. In addition, new regulatory mandates for ultra low sulphur fuels, biofuels and other additives increase the number of products to manage through the distribution chain.

Overcoming these challenges is the basis for the business case that Patrick helps offsite operators build. If the case for improvement justifies capital investment, an important step will be reviewing the key components in an offsite automation system. These components include automatic tank gauging and inventory management, goods movement automation and control, blend control and optimization, and terminal management systems.

The more these components are integrated, the better the efficiency of the offsite operations can be. Automated data collection, correlation, and reporting help streamline the regulatory reporting challenge and provide a better data to make process improvements. In addition, custody transfer of the liquids and gas can be more accurately measured, accounted, and billed.

In his presentation, Patrick and Gerrie will discuss some of the quantified benefits that some offsite operations have been able to achieve. It is important to establish a continuous improvement loop to collect data before and after these offsite automation system components are added or modernized. This is so the data can be analyzed and used to generate additional projects to further integrate and streamline operations, based upon quantified results.

Tags: offsites | terminal management | tank gauging | inventory management | blend control | tank farm | terminal automation | refinery |

August 13, 2007 in Modernization, in Offsites, in Project Services | Comments (0)

Recently the DeltaV News RSS feed announced a video case study for Australia's Arrow Energy at their Tipton Gas plant.

I discovered that Bob Gale, an AIChE fellow and Sr. Technical/Safety Consultant in Emerson's Refining and Chemical industry center was involved in this project. You may recall Bob from an earlier post about achieving IEC 61511 compliance.

Like more and more projects, a global team from Emerson was assembled to execute this project. Bob's role was to do the safety integrity level (SIL) verifications for the project. Bob noted that a part of the IEC 61511 Safety Life Cycle for DeltaV SIS projects is to have an Emerson Certified SIS Consultant verify that the safety instrumented functions (SIF), as they were designed, meet the safety integrity level that is specified in the project.

Bob's task was to ensure them that each SIF provided the risk reduction that was required to make things safe. One example he described was determining that this plant needed to divide one large SIF that encompassed the fire detection equipment on all the compressors into a single SIF for each compressor. This change allowed each of the smaller SIFs to provide the necessary risk reduction required. Each SIF is designed to shutdown the compressor in the event of a fire.

By working methodically through all of process equipment that required risk reduction, Bob played a key role for the project team in the plant's IEC 61511 safety lifecycle efforts.

Tags: safety instrumented system | safety instrumented function | IEC 61511 | SIL | safety integrity level | safety lifecycle |

August 9, 2007 in Project Services, in Safety | Comments (0)

Standards play an important role in fostering technological progress—both in the willingness of consumers to adopt the technologies and suppliers in developing products to meet the standards.

In our world of process automation, standards have continued to advance from base-level digital communications protocols to higher-level data communications standards for process manufacturers. The ISA-95 (S95) or IEC/ISO 62264 family of standards as they are globally known are an example of a set of data standards for the interface between enterprise planning systems and automation systems.

I had a chance to get a preview of a whitepaper that Emerson's Shenling Yang is developing around S95 and the XML-based implementation of this standard called Business To Manufacturing Markup Language (B2MML). You may recall Shenling from an earlier post on project timelines. She is now a data integration specialist in the Life Sciences industry center.

As stated in an ISA press release this past January on B2MML improvements:

B2MML was developed by the WBF's XML Working Group to provide manufacturing companies with a freely available XML Schema implementation of the ISA-95 Enterprise - Control System Integration Standard.

You can get a sense for just how detailed and comprehensive these standards are by viewing some of the schema documents available on the World Batch Forum's B2MML web page. Beyond the common schema organized around the S95 data model, other schemas exist for equipment, extensions, maintenance, materials, personnel, process segments, product definitions, production capabilities, production performance, and production schedules. Warning, these schema documents are not light reading!

On projects requiring workflow improvements and/or paperless operations, Shenling and the team follow B2MML data definitions to be consistent with the S95 standard. Because leading enterprise resource planning (ERP) systems like SAP support B2MML, Shenling finds that it simplifies connectivity and reduces the overall engineering effort for integration between the ERP and manufacturing execution systems like Compliance Suite. Ongoing maintenance is also reduced since the information exchanged between applications follows well-defined data definitions.

An example is an order coming down from SAP in an XML-formatted document complying with the B2MML Production Performance schema. The project team used transaction templates, along with the Compliance Suite support component and the process order XML from SAP to generate the actual transaction documents to be passed from the ERP to Compliance Suite. The automated parts are handled by the DeltaV Batch system and other parts of the process like materials management, laboratory information, and proof of personnel training are sent to their respective workflow processes.

The results of these workflows and batch data from the automation system are consolidated in an electronic batch record, which is a critical piece in reducing the overall cycle time on the way to releasing the product for sale.

Update: Gary Mintchell reports on his Feed Forward blog today that the World Batch Forum has announced version 4 of the B2MML standard and some of the additions to this standard. Here's the announcement from the WBF.

Tags: ISA-95 | s95 | IEC 62264 | ISO 62264 | B2MML | World Batch Forum | WBF | Life Sciences |

July 3, 2007 in Data Management, in Interoperability, in Life Sciences, in Project Services | 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)

Recently, a press release announced Emerson's selection on a $2.6 billion (USD) oil sands project in Northern Alberta, Canada.

The project team includes Emerson's Hydrocarbon and Energy Industry Center and Emerson's local business partner, Spartan Controls, both based in Calgary. Spartan Controls also has an office closer to the oil sands region in Edmonton. This team will supply engineering and project management, automation commissioning, and ongoing support services. Over the past several years, they have had experience with several other oil sands projects.

These Canadian oil sands (a.k.a. tar sands) hold known oil reserves second only to Saudi Arabia. Unlike those reserves, it is quite a bit more difficult to process bitumen, a molasses-like viscous oil into feedstocks for refineries to turn into gasoline, diesel and other sources of usable energy. With this project and many others, total Canadian oil production is projected to double from 2.5 million barrels per day (MBPD) to 4.9 MBPD by 2020

The process revolves around an upgrader, which changes the bitumen into synthetic crude oil. The Oil Sands Discover Centre describes the process well in this Upgrading Fact Sheet. It opens with this nice summary:

Upgrading is the process that changes bitumen into synthetic crude oil. Bitumen, like crude oil, is a very complex mixture of chemicals (a hydrocarbon with chains in excess of 2,000 molecules). It also has a lot of carbon in relation to hydrogen. Some upgrading processes remove carbon, while others add hydrogen or change molecular structures. Upgrading also involves sorting bitumen into its component parts and then using them to produce a range of additional products and byproducts.

The large oil sands projects require quite a team effort among the energy companies, Engineering, Procurement and Construction (EPC) contractors, automation suppliers and their local sales and service organizations to execute these large projects as efficiently as possible. And, in the words the energy company's president a "consistent and durable process" is the goal once the upgrader process is in full operation. This is especially important in the cold, harsh winter climate of Northern Alberta. For this project, the upgrader has a total processing capability of 231,000 BPD and construction expected to begin after regulatory approval this fall.

With higher crude oil prices, more projects like these become economically viable to do, to help the supply catch up with the global demand.

There is plenty of work to be done and many career opportunities in Calgary, Alberta if you want to join in all this fun!

Tags: oil sands | tar sands | upgrader | bitumen | EPC | main automation contractor |

June 7, 2007 in Project Services, in Upgrader | 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)

People from across the world come up this blog and get some great questions from time to time. The most recent example is questions about safety instrumented systems (SIS) and the IEC 61511 standards. I thought I'd run them by two experienced Emerson safety experts, Len Laskowski in the Refining and Chemical industry center and Stephane Boily in the Hydrocarbon and Energy industry center.

As safety professionals incorporate these performance-based international safety standards, I thought sharing their answers with you might help your safety planning efforts. Len answers the four questions and Stephane adds his thoughts looking at the SIS installation components.

What are the standards that define the best rules for installation of field equipment of a SIF/SIS, on site?

IEC 61511 or ISA-S84-2003 (which is really the same thing, plus a grandfather clause) are intended for application in the process industry. They do the best job of defining what one needs to be concerned with for field instruments. The guidance may be considered somewhat minimal but the critical safety issues are there. Whatever would make a good installation for the basic process control system (BPCS) is a good installation for the SIS also. However, some different issues need to be recognized. First, the instruments need to be reliable. One measurement, referred to as "proven in use" means reliability data must be available for safety integrity level (SIL) calculations. If not then SIL-rated instruments are an option. Next one must consider fault tolerance requirements for the Safety Instrumented Function (SIF). This is a function of the SIL level for each SIF in the SIS. There will of course always be the need to make sure the instruments are calibrated routinely and tested per the proof test requirement. If this is online then the engineer needs to make sure that those facilities plus the ability to do maintenance is designed into the project. Typically sensors need their own root valve and final control elements may need bypasses or means for partial stroke testing.

The routing of the individual cables of transmitter that is in a 2oo3 voting system--the same route, different routes?

Some reliability engineers would want to try to convince you that a different route is required. While everyone would like a diverse routing from a common mode point of view, (a fire, dropped crane load, chemical spill could destroy all the cables in the same tray, etc.) it is many times impractical to route differently. One deciding factor is availability. If high availability is require diverse routine is a good idea, but again not mandatory. Some companies may have internal standards on this subject. The other factor is whether or not the SIS fails safe. If a loss of a cable, causes the System to have a spurious safe trip the system is safe, but you have to deal with the cost of the spurious trip. If the SIF is energized-to-trip, one needs to look at separate routing. Also, end of line monitoring etc.

Can I install the three field devices in battery or in different places to avoid, common failure, e.g., vibration, risk of fire?

Field instruments are designed for the outdoor industrial environment. Utilize them correctly for their application. If it is a bad installation for the BPCS it is bad for the SIS also. While many SIS logic solvers have been industrially hardened to operate in a broad range of environmental conditions with numerous successful applications, it just stands to reason that putting them in environmentally controlled areas will improve potential reliability plus the ability to do maintenance.

Yes one must always be careful with respect to common mode. Common mode can wiped out the reliability gains of redundancy. That is why it is required to do SIL Calculations to verify that the common mode effect is not so strong that it renders the SIF ineffective.

Must I use the normal practices of engineering or do rules or recommendation exist for the installation of field equipment for the SIF/SIS?

One has to ask whose normal practices?? If we mean industry best normal practices the answer is yes again but one needs to follow the entire IEC-61511 Life Cycle to determine what that really means for each project. What is an acceptable solution for one plant may not work for another. The questions you ask really points out that to safely design a plant, the project needs to execute the IEC61511 Safety Life Cycle. Hazards are identified early in the project and solutions are designed around those hazards. The questions you asked should all be covered in the Safety Requirements Specification (SRS). There are 27 questions that cover the topics you have asked and more, much more. Inexperienced engineers may not be aware of this list of questions that define an IEC61511 SRS. This is why you should work with experienced organizations. A study done by the Health and Safety Executive in the UK has shown that the majority of problems with SIS systems today are actually specified into the project. (Or shall we say not specified into the project, one does not know what one does not know.) Failure to execute the life cycle activities early and properly can have serious safety, schedule and cost implications on a project.

Stephane adds these thoughts on the installation components:

Sensor-To reduce common mode each sensor should have a separate process connection. There have been some good arguments made with regards to using different technologies in order to reduce common mode but one must look at practicality vs. benefits and risk reduction. Also, although the use of diverse technologies can reduce common cause it will not eliminate it completely.

Transmitters-For sensors integrated (or separate) with the transmitter, the geographical locations of the voted transmitters should be away from each other to the extent possible (so that in the event of a fire--all transmitters are not affected--as an example!)

Junction Boxes-Separate JBs for each transmitter / 2 core cable is preferred.

Multicore Cables-If separate JBs not possible, run each transmitter pair in separate multicore cables to the control room.

Cable Trays-Run the multicore cables in separate trays which have separate routes to the control room when practical. Availability would be the determining factor.

Safety Logic Solver-Each transmitter signal could be connected to separate SLS, on separate carriers. This would slightly compromise on the PFD value however and could also make the SIF configuration more complicated, but reduces common cause. SLS installed in two different cabinets in different control rooms would be even better! However common sense needs to be used and practicality. Same logic could be used for the output signals.

The extent to which one would go in segregating will depend on ALARP - As low as reasonably practicable (here 'low' refers to the risks involved). The Risk Reduction Factor (RRF) of the SIF and how much of the risk is the engineer / company ready to absorb, will dictate the decision. The common cause calculator (based on such segregation) is given in IEC 61508-6, Table D.5.

Tags: IEC 61511 | IEC 61508 | ISA-84 | S84 | safety instrumented system | SIS | SIL | safety integrity level | SIF | safety instrumented function | ALARP |

May 9, 2007 in Project Services, in Safety | Comments (0)

At the recent Interphex Pharmaceutical Manufacturing Conference, Emerson's Todd Ham presented on the subject of automating fermentation. Todd acknowledged that Christie Deitz, whom we've featured in several other posts, had a large hand in the development of this presentation and work on the project discussed.

The presentation discussed a recent project done on a large-scale, multi-product biopharmaceutical complex. This project was so successful it recently won the Facility of the Year Award Winner in Project Execution. One of the keys to success was a clear design philosophy established up front. Elements of this philosophy included:

• Fully automated
• Paperless, dock-to-dock using electronic records, operator handheld devices, and barcode scanning
• Consistency for operators based on industry standards like ISA-88 (S88), ISA-95 (S95), and digital bus technologies
• Focus on fermentation as a key process area for the project

A key to success in the project was the close working relationship between the manufacturer and the Emerson Life Sciences project team on the up front requirements and design, and the subsequent module-level and integration-level testing.

The upfront design considered not only the fermentation and recovery processes, but also the full automation required for paperless operations. This design included recipe-level batch control, warehouse management, electronic signatures, and a complete electronic batch record, including the manual processes. These manufacturing processes included material management, container management, filter management and sampling.

The project team applied the S88 standard to control modules looking to identify the common modules and instances for things like motors and valves. At the S88 equipment module level, the team created project wide module templates, area specific module templates, and unique, one-time use equipment modules.

The sampling system and sparger control are examples of project-wide templates. Fermentation agitator control and dissolved oxygen control are examples of area-specific equipment modules. Transfer panels and valve assemblies are examples of unique equipment modules.

At the S88 unit level, the team designed classes and instances based on physical similarity and phases that they use such as batch media, inoculate, ferment, etc. This led to various unit classes for fermentation vessels including seed fermenters, production fermenters, and feed vessels.

From a recipe standpoint, the design grouped phases into operations, then grouped operations into unit procedures, and finally grouped unit procedures into procedures, all again following the S88 standard.

Todd shared some lessons learned from the team. With regard to the modular design approach, the team learned to keep process units the same as much as possible. With similar units, it is also important to make sure the operations are also as uniform as possible. The team cautioned about the overuse of aliases, which reference pieces of physical equipment like valves and motors, in phase logic. By not overusing aliases, but rather relying on equipment modules to handle physical differences, the phase logic could be generically written to handle multiple pieces of similar equipment like process tanks.

Other lessons learned were to plan for the extra documentation required for high levels of modularity and dock-to-dock automation. Like other members of the Life Sciences team have counseled in earlier posts, time spent upfront in planning and testing saves a lot of project backend effort.

The benefits of a complete electronic batch record vs. a paper-based process in terms of faster release of products are pretty clear. It's important to assemble the project team and begin the planning and design early to prepare for the additional effort commensurate with the increased automation required for a successful project.

Tags: ISA-88 | S88 | ISA-95 | S95 | fermentation | biopharm | electronic batch record |

May 2, 2007 in Fermentation, in Life Sciences, in Project Services | Comments (0)

Do you ever feel that pressure when things just aren't right? Things like increasing production costs, growing raw material and/or finished product inventories, inconsistent quality and inflexible production to meet changing customer needs. According to John Dolenc, a principal consulting engineer for Emerson's Advanced Applied Technology team, these are potential business drivers to consider modernizing your process automation.

Other potential drivers include unreliable operations caused by false trips and excessive plant alarms, poor-to-nonexistent production data, time wasting manual data entry and checking, and time consuming regulatory compliance and documentation. Each of these drivers has a cost associated with it that can be used to develop a business case for improvement.

John helps process manufacturers understand and quantify these opportunities for improvement in Process Automation Feasibility studies. The study begins with gathering the background information found in process flow diagrams, P&IDs, operating procedures, operator log sheets, plant history data, production costs and trends, quality reports, and current control strategies.

Usually a team forms with members from plant management, plant engineering, operations, maintenance, quality assurance, and even corporate engineering and management depending on the level of potential improvement. John and other advanced applied technology consultants bring expertise in production processes, plant operations, and the impact control strategies have on the process to help develop an improvement plan. They are experienced in providing a methodology based on past experiences and bring an outside perspective to facilitate discussion and have the freedom to challenge the rational behind past practices to get at the underlying issues.

The methodology examines the process unit performance first from a financial perspective. Key performance indicators (KPIs) are identified and the performance versus these KPIs is analyzed. Base line performance is established, potential improvements are identified, and financial gains are calculated. An automation plan to achieve the financial benefits is developed based on examining the production process; looking at process constraints, process disturbances, and limitations in equipment or other areas of the operation.

The cost to implement the automation plan is estimated and a financial analysis is done to determine if the projected benefits justify an automation project. For smaller units this process can take four weeks to perform the feasibility study, while larger units or plant-wide studies may take several months.

The real fun happens when projects get funded and quantified improvements get made. It goes a long way to relieve that pressure!

Tags: feasibility study | modernization project | key performance indicators | KPI |

January 22, 2007 in Process Optimization, in Project Services | Comments (2)

Todd Ham and Dan Lorenzo from Emerson’s Life Sciences Industry center presented a workshop entitled, Large Project Execution. The focus is on sharing best practices for successfully executing large projects.

They define a large project as 10 or more engineers with more that 5000 engineering hours. The project schedule is typically measured in years and tends to have high visibility with upper management.

Far and away the most important aspect to success is the team leadership. Team leaders should possess technical expertise,