tr-112230

EPRI • 3412 Hillview Avenue, Palo Alto, California 94304 • PO Box 10412, Palo Alto, California 94303 USA800.313.3774 • 650.855.2121 • [email protected] • www.epri.com

Survey of Instrumentation andControl Practices in the ProcessIndustries for Application to thePower Utilities

TR-112230

Final Report, April 1999

EPRI Project ManagerR. Torok

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Raytheon Engineers & Constructors, Inc.

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CITATIONS

This report was prepared by

Raytheon Engineers & Constructors, Inc.100 Corporate ParkwayBirmingham, AL

Principal InvestigatorJ. M. Mendel

This report describes research sponsored by EPRI.

The report is a corporate document that should be cited in the literature in the followingmanner:

Survey of Instrumentation and Control Practices in the Process Industries for Application to thePower Utilities; EPRI, Palo Alto, CA: 1999. TR-112230.

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REPORT SUMMARY

With impending deregulation and ever-tightening environmental constraints, utilitiesare increasing their emphasis on maximizing operating efficiency and reducingmaintenance and operational costs. It is likely that utilities can use the capabilities ofmodern control and information management systems more effectively than theycurrently do. This report documents lessons learned over many years by experts in theprocess industries that might benefit the utility industry as it transitions to acompetitive, deregulated environment.

BackgroundThe number of new distributed control systems and instrumentation is on the rise.Acceptance of these advancements in the utility market, however, has been muchslower and less widespread than in other process industries that have similarinstrumentation and control (I&C). For example, the petrochemical, pulp and paper,and metal processing industries commonly automate process plants and use distributedcontrol systems, “smart” sensors, advanced control algorithms, and integrated datacollection and mining. Potential benefits of modernizing I&C systems in fossil plantsinclude closer regulation of process variables such as steam temperatures andpressures, fuel flow, excess oxygen and pulverizer operation to improve efficiency andreduce emissions. In addition, savings in labor may be achieved by reducing the needfor calibration and maintenance. The amount of plant data collected and analyzed alsocan dramatically increase, enabling optimization of operations on a broader scale thanhas traditionally been possible. An evaluation of specific technologies in use and thebenefits realized in the process industries will provide valuable guidance to the utilityindustry.

ObjectivesTo develop an understanding of which modern I&C technologies and approaches usedin process industries might be particularly beneficial to the utility industry as ittransitions to an unregulated, competitive environment.

ApproachAnalysts interviewed ten I&C experts with broad experience in upgrading controlsystems in the process industries. The purpose of the interviews was to discover

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practices that have proven beneficial in process industries and assess their usefulness tofossil generating stations.

ResultsThe report is a compendium of responses to survey questions in four areas: Planningand Justification of Automation and Control System Upgrades; Digital Control SystemArchitecture; Digital Control System Vendors; and, Implementation Procedures. Itincludes comments, discussion, conclusions, and recommendations from a panel of tenI&C experts, each with more than twenty years experience upgrading process industrysystems. Interviewee responses are either paraphrased or given verbatim, asappropriate. In some cases, interviewees ranked control system upgrade issues in orderof importance. This report will help utilities benefit from the experiences of processindustries as they modernize plants and adjust to a competitive environment. Based onthis timely information, utilities will be able to better prioritize, justify, and plan I&Cmodernization efforts at their plants.

EPRI PerspectiveThe utility industry should pay careful attention to process industry approaches andlearn from their experiences. While utilities are only now learning to operate ascompetitive businesses, process industries have been doing this for many years.Presumably, their decisions to update their I&C and information management systemshave been motivated by the need to maintain a competitive edge. Cost justification ofI&C upgrades has proven particularly problematic for utilities. It should, therefore, beinstructive for the utility industry to study the technologies and upgrade approachesthat have been adopted by these traditionally competitive industries.

TR-112230

KeywordsControlsPlant retrofitsInstrumentation and controlAutomation

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ABSTRACT

To develop an understanding of modern instrumentation and control (I&C)technologies that might benefit the utility industry, analysts interviewed ten I&Cexperts with broad experience in upgrading control systems in the process industries.The interviews were conducted to discover practices that have proven beneficial inprocess industries and assess their usefulness to fossil generating stations. This report isa compendium of those interview responses and is divided into four categories:Planning and Justification of Automation and Control System Upgrades; DigitalControl System Architecture; Digital Control System Vendors; and, ImplementationProcedures. Information here will help utilities benefit from the experiences of processindustries as they modernize plants and adjust to a competitive environment. Based onthis timely data, utilities will be able to better prioritize, justify, and plan their I&Cmodernization efforts. Cost justification of I&C upgrades has typically provenproblematic for utilities. It should, therefore, be instructive for the utility industry tostudy the technologies and upgrade approaches that have been adopted by thesetraditionally competitive industries.

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ACKNOWLEDGMENTS

The authors and EPRI would like to acknowledge the following experts ininstrumentation and control who made this study possible by contributing their timeand expertise as interviewees.

Mr. Robert W. Barber Champion International Corporation

Mr. Murray A. Champion Yokogawa Industrial Automation

Mr. Jay D. Colclazier Fisher-Rosemount Systems, Inc.

Mr. Don Frerichs Elsag Bailey Process Automation

Mr. Dan D. Glossner Amoco Chemicals, Decatur Plant

Mr. William J. Harding The Foxboro Company

Mr. Paul S. Inglish Honeywell Industrial Automation and Control

Mr. David J. Latour Union Camp Corporation

Mr. Chris E. Rogers Boise Cascade Corporation

Mr. Fred Y. Thomasson Union Camp Corporation

We also thank the following people who reviewed drafts of the report and providedcomments and recommendations that were used to improve the final version.

Ms. Teresa Taylor Tri-State G&T Association, Inc.

Mr. John N. Sorge Southern Company Services

Mr. Dale P. Evely Southern Company Services

Mr. Cyrus Taft EPRI I&C Center

And finally, we would like to acknowledge the staff of the EPRI I&C Center, whoadvised the author on the important fossil plant issues.

Mr. Duane Bozarth

Mr. Robert Frank

Mr. Cyrus Taft

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CONTENTS

1 INTRODUCTION............................................................................................................. 1-1

2 PLANNING AND JUSTIFICATION OF DIGITAL CONTROL SYSTEM UPGRADES ..... 2-1

2.1 Initial Cost Factors Associated With a Digital Systems Upgrade................................... 2-2

2.1.1 Purchased Equipment ........................................................................................... 2-3

2.1.2 Site Preparation..................................................................................................... 2-3

2.1.3 Preparation of Control Requirements Documentation ............................................ 2-4

2.1.4 Configuration of System ........................................................................................ 2-5

2.1.5 Verification and Staging of System ........................................................................ 2-5

2.1.6 Input/Output (I/O) Checkout................................................................................... 2-6

2.1.7 Operator and Maintenance Technician Training .................................................... 2-6

2.1.8 Startup................................................................................................................... 2-7

2.2 Continuing Expense Factors Associated with Digital Systems...................................... 2-8

2.3 General Categories of Benefits of Digital Control Systems........................................... 2-9

2.3.1 Smaller Process Variation and Operating Closer to the Optimum DuringNormal Operations ........................................................................................................ 2-10

2.3.2 Fewer Process Upsets and Faster Recovery After an Upset ............................... 2-11

2.3.3 Operator Manpower Savings ............................................................................... 2-12

2.3.4 Control Room Floor Space Reductions................................................................ 2-12

2.3.5 Maintenance “Savings” ........................................................................................ 2-13

2.3.6 Safety and/or Environmental Benefits Due to Use of Logs................................... 2-14

2.4 Benefits of Specific Advanced Control Loop Logic Algorithms.................................... 2-15

2.4.1 Simple PID with Feed Forward ............................................................................ 2-15

2.4.2 Loop decoupling using process mathematical model, e.g. Dynamic MatrixControl or Inferential Model Control. .............................................................................. 2-16

2.4.3 Compensation for a measurable upset using a mathematical process model. ..... 2-16

2.4.4 Adaptive control of PID tuning constants. ............................................................ 2-17

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2.4.5 Neural Net. .......................................................................................................... 2-17

2.4.6 Fuzzy Logic. ........................................................................................................ 2-17

2.4.7 Statistical Process Control. .................................................................................. 2-18

2.5 Benefits of Batch or Sequence Controls, Including Group Starts ................................ 2-19

2.6 Benefits of Integration of Digital Control Systems with Information Processing (IP)Systems ............................................................................................................................ 2-20

2.7 Value of Post Installation Audits ................................................................................. 2-22

3 DIGITAL CONTROL SYSTEM ARCHITECTURE ........................................................... 3-1

3.1 DCS-Only vs. DCS/PLC Hybrid..................................................................................... 3-1

3.2 Operator Interface Decisions........................................................................................ 3-3

3.2.1 Console Computer Operating System ................................................................... 3-3

3.2.2 Operator Console Graphics ................................................................................... 3-5

3.2.3 Quantity of Operator Console Screens Required and Span of OperatorControl............................................................................................................................. 3-6

3.3 Use of “Smart” Field Elements and Field Element Networks ........................................ 3-7

3.3.1 “Smart” Field Elements – Standalone or Networked .............................................. 3-8

3.3.2 Field Element Data Communications Networks and Instrumentation AssetManagement Systems..................................................................................................... 3-8

3.3.3 Fieldbus (Foundation or Others) ............................................................................ 3-9

4 DIGITAL CONTROL SYSTEMS SPECIFICATIONS AND VENDORS............................ 4-1

4.1 Digital Control Systems Specification ........................................................................... 4-1

4.2 Vendor Qualification ..................................................................................................... 4-2

4.3 Scope of Vendor Responsibilities ................................................................................. 4-3

5 IMPLEMENTATION PROCEDURES .............................................................................. 5-1

5.1 Process I/O and Logic Requirements Documentation and Verification ......................... 5-1

5.2 Logic Configuration Specification and Verification ........................................................ 5-2

5.3 Staging......................................................................................................................... 5-3

5.4 Operator and Maintenance Technician Training ........................................................... 5-4

5.5 Operator Interface Problems ........................................................................................ 5-6

6 CONCLUSIONS.............................................................................................................. 6-1

6.1 Planning and Justification of Digital Control System Upgrades...................................... 6-1

6.2 Digital Control System Architecture ............................................................................... 6-2

6.3 Digital Control System Specifications and Vendors ....................................................... 6-2

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6.4 Implementation Procedures........................................................................................... 6-3

A SURVEY INTERVIEWEES..............................................................................................A-1

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1 INTRODUCTION

A survey of instrumentation and controls practices in the processes industries wascompleted during October-November, 1998. The information gathered in the survey isintended to benefit EPRI members as they make plant process control equipmentdecisions for a fossil utility industry in transition to an unregulated businessenvironment. The purpose of the survey is to: 1.) identify, and 2.) assess applicability tothe utility industry of, instrumentation and control practices that have proven beneficialin the competitive, de-regulated, process industries.

The topics of the survey were developed based on input from the EPRI Instrumentationand Control Center in Harriman, Tennessee. These topics focused on the primaryissues related to the replacement of analog panel-mounted process controlinstrumentation with digital control systems. The topics are organized under thefollowing major headings:

• Planning and Justification of Automation and Control System Upgrades

• Digital Control System Architecture

• Digital Control System Vendors

• Implementation Procedures

The interviewees for the survey were representative of those people who have dealtwith these issues. A listing of the interviewees, with their organizations, titles, andexperience is shown in Appendix A. Note that these people each have 20-30+ yearsexperience in digital control systems during the period when these systems weredisplacing panel-mounted, analog, control systems in the process industries.

The following are the typographic conventions used in this document. Direct interviewcomments, paraphrased by the investigator, have been italicized. In a few cases, whereinterviewees responded in writing, the comments are italicized and shown withindouble quotation marks (“ “) to indicate that the comments have been repeatedverbatim. The investigator’s conclusions and recommendations, based on all of theinterviews, are shown in boldface.

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2 PLANNING AND JUSTIFICATION OF DIGITAL

CONTROL SYSTEM UPGRADES

In the process industries beginning in the late 1970’s, Distributed Control Systems(DCS’s) began replacing panel-mounted single loop controllers (pneumatic, analogelectronic, and digital electronic). In parallel with the regulatory instrumentation looplogic shifting to DCS’s, motor start/stop (interlock) logic, implemented with hardwiredrelay panels, migrated either to Programmable Logic Controllers (PLC’s) or to the DCS.The cost/benefit analysis and justification of digital control systems was a popular topicin process industry technical journals of the early to mid 1980’s. Cost factors, such as:controls equipment prices, wiring, floor space, control room/rack room HVAC,operational manpower requirements, maintenance requirements, etc. were estimatedand compared between panel-mounted and DCS architectures. Process operationalincentives (benefits) due to such effects as: production variation reductions, rawmaterial usage reductions, control system reliability improvements, integrationcapability with plant information systems, etc. were also estimated and comparedbetween architectures.

Although the digital technology has changed, the procedures for making decisionsabout control renovations to processing plants has remained constant: As a first step,management still insists on a feasibility study or cost/benefit analysis of a proposedproject. Not only must costs and benefits be estimated, but the proponents of therenovations must understand the risks embodied in these estimates. What has beenlearned in the process industries in the many repetitions of this exercise by theinterviewees? This section of the report will examine the following topics in thiscategory:

1. Initial Cost Factors Associated with a Digital Systems Upgrade,

2. Continuing Expense Factors Associated with Digital Systems,

3. General Categories of Benefits of Digital Control Systems,

4. Benefits of Specific Advanced Control Loop Logic Algorithms,

5. Benefits of Batch or Sequence Controls,

Planning and Justification of Digital Control System Upgrades

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6. Benefits of Integration of Digital Control Systems with Information ProcessingSystems, and

7. Value of Post Installation Audits.

2.1 Initial Cost Factors Associated With a Digital Systems Upgrade

In order to estimate costs, one must first define the scope of the renovation, and thendefine the equipment and tasks required. The cost estimate can be no better than thescope and requirements definitions that it is based upon. The following requirementsdefinitions were reviewed in this survey to determine their potential impact, as costfactors, on a cost/benefit analysis:

1. Equipment, including system level firmware/software,

2. Site preparation, including: rack room/control room renovation (e.g. lighting,furniture, etc.), AC power supply, power & instrumentation wiring/cabling,grounding, HVAC & air filtration,

3. Preparation of process control requirements documentation,

4. Configuration of system,

5. Verification and staging of system,

6. Input/Output (I/O) checkout,

7. Operator and maintenance technician training, and

8. Startup.

The “impact” of a cost factor on the cost/benefit analysis was conceptually defined tobe the product of the magnitude of the expected cost, times the expected variability ofthe estimate. That is, costs that are relatively large and are relatively difficult toestimate precisely, can have a relatively large impact on an analysis. Costs that arerelatively small and can be precisely estimated will have relatively little impact on ananalysis.

Interviewees were asked to review the list for missing and/or superfluous items andthen to rank the list in order of impact.

There were no cost factors added to the list. One interviewee recommended deletingsystem staging from the list, as a required activity.


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2.1.1 Purchased Equipment

Comments on the cost of purchased equipment , as a cost factor, were:

• Significant but one of least difficult to estimate. Accurate I/O count will lead to an accurateequipment cost.

• Rank No. 1 (highest out of 8) in analysis impact.

• Extremely important to project. Costs highly sensitive to estimation errors, particularlyselecting and estimating the proper system functionality.

• Significant and highly dependent on getting an accurate I/O count and agreement on thescope of the operator interface.

• Costs are significant, but easy to define. Actual cost typically comes close to estimate.

• Equipment costs are sometimes an issue, but not a major one.

• Costs are large but definable, and generally estimated accurately.

• Costs will be accurate, provided I/O count is accurate.

There was almost complete concurrence on this topic. Purchased equipment is asignificant cost component, but it can be estimated accurately if the systemrequirements are carefully developed.

2.1.2 Site Preparation

This is was the cost factor considered to have the greatest impact. Some of thecomments:

• Typically retrofit must install new equipment while old equipment is still in place andrunning. Installation must be carefully planned to be able to remove old equipment afternew is started up, e.g. new cable should not be laid over the old.

• This is a difficult and expensive exercise.

• Typically the largest impact. Cost of operating while constructing and demolishing oldequipment requires detailed planning, and is usually underestimated.

• Rank No. 1(Tie with Preparation of Control Requirements Documentation for highest) inanalysis impact. We’ve gotten “burned” on several problems over the years: We have hadproblems getting the old equipment out after the new was installed. Grounding was usuallyunderestimated. The cost of air filtration to remove dust and air-lock double doors to the


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control and rack rooms was underestimated. There was also the cost of providing backuppower; we have gone to emergency generators to hold power after battery backup unitsexpire.

• Rank No. 2 (out of 8, 1 highest) in analysis impact. Primary problem is having to work in anoperating control room, where the operating organization may not be as dedicated to the cut-over schedule as the engineering/construction organization. Often hidden problems willcome to light after the project has begun: e.g. lead paint on columns to be removed, newlighting requirements, existing HVAC problems, etc.

• This is generally underestimated, due to a lack of understanding, by the estimator, of the siteorganization and the condition of the site equipment.

Site preparation should be diligently planned, defined, and estimated byexperienced people. Once the plan is approved, both construction and operationsmust commit to the plan to avoid cost overruns.

2.1.3 Preparation of Control Requirements Documentation

Most of the interviewees gave this topic a medium ranking on cost/benefits analysisimpact, as can be concluded from the following responses:

• Significance depends on availability and validity of existing documents, e.g. may decide torun entirely new field cables if documentation is poor. Typically the cost is not relativelysignificant unless there is a supervisory system included, such as an IBM 1800.

• Rank No. 6 (out of 8, 1 highest) in analysis impact.

• This is a time consuming effort.

• Rank No. 4 (out of 8, 1 highest) – it tends to be underestimated in cost and time.

• Projects that go well will have DCS users taking an active role in this activity andunderstanding exactly what they are asking for.

One interviewee disagreed with the above and stated -- Cost has low sensitivity toestimation error, because this is a routine, straight forward, procedure for an upgrade.

However, the investigator suggests that the following two responses deserve attentionfor their insight into the importance of this factor:

• Rank No. 1 (Highest, Tie with Site Preparation) in analysis impact. We originallyperformed a loop-by-loop swap to the DCS, and got a very low cost for this. In fact, thiseffort should have had a much larger scope, with a larger cost, and it is a worthwhileinvestment to get more out of the DCS.


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• Rank No. 1 (out of 8, 1 highest) in analysis impact. This takes a lot of time, particularlyfrom the people with the least amount of time available. Getting their input is important.

To get the maximum value from a DCS replacement, more than just the DCSimplementation of the same control loops is necessary. As we will emphasize later inthis report, when benefits are discussed, advanced control techniques will requireprocess review, analyses, model building, and model validation with process data.

2.1.4 Configuration of System

This cost factor drew a wide range of responses:

• Configuration typically not relatively significant, unless adding upper level or advancedregulatory functions.


• Costs have medium sensitivity to estimation error.

• Cost are relatively easy to estimate with operator input.

• Typically not a problem for us.

• This is sometimes a problem, we would rank it as No. 3(out of 8, 1 highest).

• This can be easily subject to cost over-runs, particularly if the contractor offered a low bidprice and is losing money on the job.

However, one interviewee probably identified the root cause of the diverse responsewith his comment: Easy to perform, once the logic has been identified and documented

If the logic and interface requirements are clearly defined in the control requirementsdocumentation, configuration will not be a cost or schedule issue.

2.1.5 Verification and Staging of System

All but one of the interviewees gave this topic a medium-to-high ranking on analysisimpact, as can be concluded from the following responses:

• Verification of the hardware at the vendor’s site is straightforward and not difficult toestimate. Verification of the configuration is a lot more difficult and therefore difficult toestimate. A test plan should be written. Many customers require simulation using loop backto verify each loop.


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• This is a time consuming effort, but it is a must. This is the last chance to see how thesystem will work and re-do.

• Rank No. 2 (out of 8, 1 highest) – tends to be underestimated in time and complexity to dothe job completely. About ½ of the problems are due to inadequate review of ControlRequirements Documentation before the configuration was begun, and about ½ due to short-sighted project managers arbitrarily setting a short duration time on this activity.

• We do a complete hardware staging using a simulator. We check the configuration and thegraphics at the staging. This pays by eliminating startup “surprises”.

• Rank No. 4 (out of 8, 1 highest). This is important to project success.

• A simulator is best for verification of logic, if the job can afford it.

One interviewee stated that staging was unnecessary -- Recommend deletion of this item.Staging is unnecessary. A major oil refiner is doing zero staging.

Staging is costly, particularly if logic verification cannot be accomplished as aprevious, separate, step. It also requires a spot in a tight schedule where there istemptation to shorten duration. It does eliminate startup “surprises”. An experiencedteam, implementing well defined logic on a seasoned DCS architecture, could solveany problem, that would be found at staging, in the field at startup. Typically,however, staging is a good insurance policy.

2.1.6 Input/Output (I/O) Checkout

Interviewees were in agreement on this topic, as typified by the following:

• Definitely do it. Not difficult to estimate.

• This is usually a well defined problem. Sometimes there is problem communicating therequirements to the construction company, leading to a cost estimation problem.

• We have this exercise “nailed down” now.

I/O checkout is not a serious cost factor; however, it should be defined in detail to theconstruction contractor.

2.1.7 Operator and Maintenance Technician Training

Comments on this topic were the most diverse of any cost factor:


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• High fidelity simulation is not worthwhile if the operators know the process and are beingtrained on the control system. Teach the process with a low-level simulator to keep costs ofsimulator low and certain.


• Cost has low sensitivity to typical estimation errors, once the number and types of people tobe trained is decided.

• Costs here are difficult to estimate and have a big impact.

• Rank No. 3 (out of 8, 1 highest) – typically always underestimated.

• This has not been an analysis problem. We spend more with the DCS than we used to.

• This is easy to define but difficult to implement. Operating managers will make thecommitment to training, on the dates that it is scheduled and available from the DCS vendor,but if anything else comes up, they will tend to sacrifice training.

• The importance of training is the most under-estimated factor in the long term success of aproject.

Training, particularly with a simulator, is a significant cost factor. It is difficult toschedule and prioritize. Training simulators vary greatly in process fidelity and incapability of tracking changes to the logic and graphics in the “real” control system.Training objectives should be defined early, and training plans should be developedconcurrently with the control requirements documents.

2.1.8 Startup

Comments on Startup as a cost factor were fairly well in agreement:

• Not significant if the other steps are done correctly, particularly Verification and Staging. Amajor chemical company will not do a startup until the logic has been simulated.

• Not significant.

• High sensitivity to estimation error due to uncontrollable events, e.g. weather.

• Costs here should be low, if everything listed above has been accomplished.

• I’ve been “blessed” with good startups. I attribute that to diligence to Verification andStaging.

• No problem.


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• Startup costs may be greatly impacted by events external to DCS design/constructionplanning and control. Often mill operations will over-ride the schedule in order to meet aproduction objective.

The main purpose of the Verification and Staging step is to insure a trouble freestartup, and this will indeed be the case, if that preparatory step is diligentlyexecuted. Job cost accounting systems should be capable of identifying the propersource of cost variance, should meeting other objectives increase the control systemstartup cost.

2.2 Continuing Expense Factors Associated with Digital Systems

There is an annual, continuing, cost associated with ownership of a digital controlsystem, which must be included in the cost/benefit analysis. As the comments belowshow, there are two schools of thought on maintaining a digital system – freezing thesystem design at the time of design implementation, or keeping the system current withthe system vendor’s latest versions:

• Continuing costs will depend on which of two typical strategies is chosen: Freeze systemarchitecture, or keep architecture up-to-date. Freezing will lead to low annual costs untilentire system is scrapped and replaced. Keeping up-to-date with software releases, newconsole hardware, etc. may be expected to cost about 10% of the system cost per year.

• I recommend freezing system architecture for life of system. If you don’t need it, don’t buyit.

• For a DCS, continuing hardware costs are minor, just the replacement of failed components.Software upgrades and enhancements can be expected to cost 5% of the initial cost per year.Keeping people up to date on system is important and can be expected to cost 2% per year.

• Continuing costs should be low, because initial software should be used for several yearswithout upgrading. Training costs will depend on other factors, e.g. employee job changes.

• Count on events such as software upgrades, Y2K, etc. We get a preliminary quote from theVendor and put that number into the plan. The 5% of the initial cost per year (suggested byanother interviewee) is probably pretty accurate.

• We spend about $50-70,000 per year per control room/rack room to replace spares. We alsohave the cost of software licensing and support. Our DCS vendor warehouses spares here, sowe only replace what we use. Training costs are definitely higher than with panel-mountedinstrumentation. We send each new person on DCS maintenance to the DCS vendor’sschool for 3 weeks.


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• Software upgrades for our DCS probably average 10% of the initial cost per year. 2% ofinitial cost per year for training is probably about right. We have a problem identifying theright people to train. In several cases the people trained do not develop the overall diagnosticskills and motivation necessary to make a good DCS technician.

• Software and hardware maintenance should be 3-5% of initial cost, if the right DCS vendoris selected. Some people do incur continuing DCS vendor costs greater than 10%.

To get the full benefits of the digital system upgrade, assume in the analysis that thesystem will be kept up to date at an annual cost of 5-10% of the initial cost per year.Also include 2% of the initial cost per year for training.

2.3 General Categories of Benefits of Digital Control Systems

The interviewees were first asked to comment on the following classification scheme fordigital control system benefits that are relevant to fossil utility units:

1. Energy and materials savings (and effective capacity increases) from operatingcloser to constrained optimum due to decreased process variation during normalequipment operation. The decrease in process variation can be enabled by any ofthe digital system characteristics to be discussed.

2. Energy and materials savings (and effective capacity increases) from fewer processupsets and/or decreased recovery time. The decrease in process upsets can beenabled by any of the digital system characteristics to be discussed. Decrease inprocess upsets can also be enabled by higher system reliability related to fewerelectronic components and faster mean time to repair.

3. Operator manpower savings from 1.) the concentration of control stations on CRTdisplays and 2.) the use of digital systems alarm management and operator promptfunctions.

4. Control room floor space reductions.

5. Maintenance savings from fewer electronic components and faster mean time torepair. (Note: Maintenance savings should be netted against any increases in plantor general office personnel required due to digital systems support.) Maintenancesavings on control loop modifications requiring only reconfiguration.

6. Safety and/or environmental benefits, due to post-accident sequence analysis from arecorded historian/event log

There was general agreement on the classification scheme; however, it was noted thatthe distinction between Category No. 1 and Category No. 2 is really dependent only on


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the magnitude of a change necessary to define it as an “upset”. A pulverizer trippingout is definitely an upset and any benefits of a digital system in responding belongs inCategory No. 2. Normal fluctuations in fuel heating value are not considered upsets,and any benefits of a digital system in responding to these fluctuations belongs inCategory No. 1.

2.3.1 Smaller Process Variation and Operating Closer to the Optimum DuringNormal Operations

The comments were unanimously positive:

• This is the No. 1 (out of 6) ranked incentive expected, e.g. operating at the optimum steamtemperature, excess air, etc.

• This is probably the No. 1 (out of 6) ranked incentive expected. Also, often the constraintswill change in the direction of the optimum once historical data is collected. This hashappened on boilers with excess air constraints.

• Cost savings in the process industries have been very large, in terms of production increasesand/or cost savings at constant production. For instance, refinery savings due to DCSaverage about $.12/bbl (6% of total production costs).

• This is the No. 1 (out of 6) ranked incentive expected.

• Boiler jobs (that we have done on DCS) have achieved significant savings in energy, e.g.excess oxygen prior to DCS averaged 6-8%; every DCS job achieves 2% or lower.

• This has been significant for our boiler control – excess air is now much less variable. Wehave changed from O2 control to O2 with CO trim.

• We have experienced on a utility boiler DCS upgrade: 1.) a heat rate improvement of 1.5%,of which 25-50% is directly the result of the DCS itself, and 2.) a reduction of 200 kW inauxiliary power, through the elimination of relays and other control equipment, and throughmore efficient operation of ID/FD fans.

One interviewee did sound a note of caution --For about 75% of the DCS applications wewill indeed achieve decreased process variation. This will often be primarily due to the increasedvisibility of the performance of the field elements of the loop and their subsequent repair orreplacement. For about 25% of the DCS applications we will often get worse loop performance.This is often due to misusing the vast, available, library of DCS logic structures withoutunderstanding the basic principals of control loop design. He added that this problem getscorrected in the field, and with experience, becomes avoidable through the ControlsRequirements Documentation.


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Experiences with digital control systems show significant energy and materialsavings and/or effective capacity increases, resulting from operating a fossil unit (or aclosely equivalent process) with less variation, and closer to the optimum, duringnormal operations.

2.3.2 Fewer Process Upsets and Faster Recovery After an Upset

The comments here again were unanimously positive:

• This is the No. 2 (out of 6) ranked incentive expected. Although very few upsets arepreventable via the control system, a digital system can significantly lower those that arepreventable with a control system.

• This is the No. 3 (out of 6) ranked incentive expected. The number of boiler trips has beendemonstrated to decrease significantly.

• Abnormal Situation Management (ASM) group of oil/chemical industry projects that onethird of all upsets are preventable with a digital control system, if the required software isincluded. Software includes ordinary control point alarms, plus programs that look forhistorical failure patterns across several process variables.


• The DCS has been of great benefit in post-upset diagnostics, particularly for analyzing thecauses of boiler trips and changing procedures. This has led to a 60-70% decrease in drumlevel trips, identifying and using “Best Practice” and then configuring “smart” alarm limits,based on the real likelihood that drum level is out of control. We have also identified thefastest, safest boiler startups and shutdowns, and use Help screens to coach every operatorthrough the “Best Practice”.

• This has been an important benefit of the DCS, particularly in minimizing the magnitude ofthe effects of any upset. For instance, we use on-line help screens to give the operatorguidance on recovering from an upset.

• This has been a significant benefit. Bark boilers routinely experience upsets in bark feed.Using advanced control techniques, at one of our mills, has virtually eliminated drum leveltrips.

• With the DCS logic capability, the impact of load change upsets on a hard coal burningutility boiler was reduced by a factor of 2. This translated into a benefit of speeding up loadchange rate on the unit from 5 MW/min to 10 MW/min. Oil used to fire this boiler duringstartup was also reduced by 30%, due to getting up to coal firing temperature 10-12 hourssooner. Faster startups were attributed mainly to the operators having graphic displays ofmotor interlock and startup sequencing information. Boiler trips have been reduced from anaverage of 10 per year to 1 or 2.


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These are impressive benefits. It should be pointed out that they were not achievedby simply replacing all the analog loops with the equivalent digital algorithms.Process models and transfer functions were developed. Model parameters wereestimated from data gathered on the system. Advanced control algorithms wereconfigured, tested, tuned, and re-tuned.

2.3.3 Operator Manpower Savings

The interviewees were asked to focus on their experience with benefits strictly due tocontrol automation. The following were the comments:



• Manpower savings should not be a DCS incentive. Manpower shifts to higher levelfunctions should be expected. Retraining to accomplish this should be planned.


• At a mill where we converted 5 boilers, there was one operator per boiler. After theconversion, 2 operators ran all 5.

• We have not reduced manpower as a result of a DCS conversion.

• We have not reduced manpower as a result of a DCS conversion. However, we weretypically running very lean on operators prior to the conversions.

There is little doubt that the DCS has the capability to achieve high levels ofautomation. Again, it will not happen by simply replacing the analog loops with theequivalent digitally implemented loops and operator interfaces, and then using thesame operational procedures. Success here requires motivation for change from allinvolved organizations. The system must be developed to allow the operator to“manage by exception”.

2.3.4 Control Room Floor Space Reductions

The digital system footprint is significantly smaller than the equivalent analog system.Can this be translated into a benefit after a renovation?

• This should be ranked last as an incentive. The requirement for operating during most of thetransition will mean very little space reduction actually realized.

• Benefits here are not significant.


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• Control rooms are becoming manpower centers, including maintenance and lab personnel.Space will not go down.


• No real benefits have been derived from the extra space. Typically left as rack space.

• No benefit here.

• We have put the created space, due to a DCS conversion, to good use at one mill. We used itfor control racks for new equipment, which, otherwise, would have required building a newrack room.

The only tangible benefit identified was associated with the avoided cost of a newrack room for a process expansion in the same area. The operator/technicianinteractions resulting from creating a manpower center can be considered as anintangible benefit.

2.3.5 Maintenance “Savings”

Interviewees were asked about the benefits of a digital system on the maintenancefunction, keeping in mind that the direct cost of maintenance may increase, but thattotal savings due to more “cost effective” maintenance could also increase.


• This is the No. 4 (out of 6) ranked incentive expected. Repair parts cost more, but fasterrepair makes a digital system more cost effective. For instance, when sootblower systemswere controlled by relays, heat rate penalties (during the typically longer repair times after arelay failure) were significantly higher than with a PLC.

• Maintenance savings can be expected to be 50% and greater after a DCS conversion (if theconversion includes fieldbus).


• No maintenance savings are produced; however, DCS operator action log makes themaintenance dept. a lot more efficient, due to faster and more specific identification ofproblems. Also there is a lot less hiding of operation errors under the category of“mysterious problems with the system”. More maintenance training, PCs for maintenance,Internet access, etc. are now required, costing more, but the increased efficiency more thanmakes up for it.

• We have not experienced savings here. The cost of a single repair of a DCS component isactually higher than with panel-mounted instrumentation, but you do fewer repairs.


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• Maintenance is significantly improved with the DCS due to the increased visibility of loopperformance. We’ve had process control engineers offsite observing loop performance,identifying valve problems, and initiating maintenance. This was not possible without theDCS.

• For a station with 2 units, there was a savings of $100,000 per year on recorder paper, due toinstalling the DCS. This was typical of many small cost reductions.

Digital control systems do not lower the direct cost of maintenance of the logicelements of control loops, they typically increase it. However, they provide theopportunity for dramatically improving the effectiveness of total control loopmaintenance, which shows up on the “bottom line” as an improvement in overallplant efficiency.

2.3.6 Safety and/or Environmental Benefits Due to Use of Logs

The interviewees noted benefits in this category, but the benefits are intangible anddifficult to quantify, relative to those in the other categories.

• This is the No. 3 (out of 6, 1 highest) ranked incentive expected. One of the biggest benefitsgained from a DCS conversion is the collection of historical data used to determine the rootcause of problems.

• Savings here are real, but intangible.

• DCS can produce OSHA compliant logs on everything that happened. The historical datacan be used to diagnose problems and get back on line faster. For instance, in one case areactor exploded. All process conditions and operator actions were reviewed from the DCShistorical data. The analysis showed a metallurgy failure as the cause.

• This is the No. 5 (out of 6, 1 highest) ranked incentive expected.

• The documentation (DCS logs) produced after a safety or environmental event are invaluablein dealing with organizations outside the mill. Having coordinated, time-stamped eventlogs, showing exactly what happened, helps meet several objectives very quickly.

• The ability to go back and diagnose problems from the DCS log has been helpful.

• One of the biggest benefits we see is the use of advanced control techniques to get the mostout of boilers while staying within environmental (Opacity, NOx) constraints.

A digital control system is capable of storing, retrieving, and reporting process eventdata with inherently higher reliability and validity than a manual log system. Thevalue of the benefits achieved will be highly site and situation specific.


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2.4 Benefits of Specific Advanced Control Loop Logic Algorithms

A number of the benefits noted above were due to the implementation of advancedcontrol algorithms. There are several alternatives to choose from. Some are built in ,and others are part of proprietary “add on” packages to the digital control system. Theinterviewees were asked to comment on their experiences with the followingalgorithms:

1. Interactive control loop decoupling using PID with feedforward control algorithm.

2. Interactive control loop decoupling using process mathematical model, e.g. DynamicMatrix Control or Inferential Model Control.

3. Control loop compensation for a measurable upset using a mathematical processmodel.

4. Adaptive control of PID tuning constants. (The turndown requirement for fossilpower plants may lead to normal operation at a wide range of power outputs.)

5. Use of “neural net” control algorithms.

6. Use of “fuzzy logic” control algorithms.

7. Use of statistical process control.

2.4.1 Simple PID with Feed Forward

• This advanced control technique gives the most “bang for the buck” because it is includedwith the DCS and is relatively easy to set up.

• Seven-element feed water (drum level) control is becoming the standard becauseconfiguration and tuning are easier with a digital system.

• Feed forward is routinely implemented. We typically use 5-element drum level control.

• We are doing this more with the DCS then we did in the past; but, it is not a substantialdifference.

• One of the real advantages of a DCS. This will definitely enable minimizing processvariability.

• “This should be a real advantage for boiler operation in a dynamic process environment. Notas important in base loaded installations.”


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2.4.2 Loop decoupling using process mathematical model, e.g. Dynamic MatrixControl or Inferential Model Control

• In the right applications this can be beneficial. Analyze problem requirements first beforeselecting a tool to use.

• Process industries make significant use of multivariable control.

• Multivariable control, using mathematical models for decoupling, has become the state-of-the-art with digital systems.

• This is less important than No. 1 (Simple PID with Feedforward) above.

• On our fuel/air controls on combination boilers using bark, we need the heating value of barkin the calculation. We use a mathematical model to calculate this based on several processvariables.

• The use of model reference control algorithms has increased significantly with the DCS. Weuse the historical data acquired through the DCS to update the models. A typical model isreaction kinetics for air oxidation.

• “I am not aware of DMC in Power, but it is widely used in the Refinery Business. Arefinery I was involved with (my role was small), stated that the whole capital cost of theDCS & Advanced Control was paid for by the advanced control (multi-million). The mainrole for the DCS in this case was to give reliable repeatable control.”

• “Don’t see this as a big advantage in boiler operations.”

2.4.3 Compensation for a measurable upset using a mathematical processmodel

• This is used. Also, mathematical process models are commonly used for data reconciliation,i.e. determining when a process variable is in error and determining the correct value fromthe remaining measurements.

• We’re getting a big benefit from calculating drum level alarm and trip points dynamically,because shrink/swell effects vary so much with production level.

• We use mass and heat balance models to determine upsets and then compensate in ourcontrollers.

• “Having the ability to change loop performance during upsets versus normal load variationis a significant advantage in operations with dynamic operating modes.”


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2.4.4 Adaptive control of PID tuning constants

• This will definitely be beneficial to power plants. It is included with DCS and is easy tosetup.

• This will have the biggest impact on the typical power plant.

• This is used by power plants with a more conservative approach; those not willing to usemultivariable control.

• We don’t typically do this; we typically don’t have wide operating ranges.

• We handle this with self tuning control loops.

• Several control loops are set up with adaptive tuning constants. Drum level controls and pHcontrol loops are examples.

• “Being able to handle non-linear process dynamics through the operating range is a realvalue for plants with variations in operating modes.”

2.4.5 Neural Net

• There has been a lot of success with this in predictive modeling, e.g. CEMS prediction orNOX prediction.

• This technique has been proven to be robust and reliable in the process industries. For apower plant a typical application would be the NOX/Heat rate/Production optimizationcontrol. (For a given NOX and Production constraint, control steam generation to thelowest heat rate). Also, scrubbers and ammonia injectors both have non linear transferfunctions, and they are tough to model using first principles. Neural nets handle theseproblems with ease.

• This technique has been used for analytical variables that are difficult and/or expensive tomeasure, e.g. the color of fuel oil is controlled by its correlation with temperature, pressure,and flowrate, rather than with a possibly problematic color spectra-photometer.

• We are using this for emissions monitoring, implemented as a DCS add-on package.

• “True NN control is very difficult to achieve. Not sure if would be worth the efforts forpowerhouse operations. Dynamics are pretty well understood.”

2.4.6 Fuzzy Logic

• There have been some limited successes with this technique. A superheater temperaturecontrol loop preventing overshoot is an example.


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• Fuzzy controllers, in general, offer little improvement over traditional PID's, and none overmodel based controllers like the Smith Predictor. However, they do seem to do well whenthere is a large deviation from setpoint (like when a large setpoint change is made) ANDwhen the process has long time delays and dead times. This is due to the inherent non linearcontrol action of the fuzzy controller. Again, a PID can be made to behave this way byadaptive tuning or even simply squaring the input error signal.

• Not typically used in final control element loop, but can be used in problem diagnosis.

• We’ve tried this, but have not gotten anything productive out of it.

• We are using this technique, combined with predictive models, extensively for optimizationin our energy management supervisory systems. One mill is using it to continuouslyoptimize the make/buy power decision. The system is credited with savings of $50,000 permonth. Another mill is using it as the plant master over 4 power boilers feeding the sameheader.

• “Fuzzy logic would be of definite benefit. Vary performance expectations based on operatingconditions.”

2.4.7 Statistical Process Control

• This is an early warning technique for identifying process upsets, prior to individual pointalarms and should be seriously considered.

• This technique is not popular now. It was big for a while.

• We use this for on-line variability analysis of process variables. This identifies loopsperforming abnormally.

• We are using the DCS vendor package for this.

• This is being used by others for control loop performance measurement, but we are not usingit.

• “Not as relevant for specific process parameters but worthwhile for overall key measures likeefficiency, daily operating rates, downtime tracking and analysis.”

Advanced control algorithms are definitely a key factor in achieving the benefitscited for a digital control system. There are several choices available that overlap onthe objectives that they will meet. There are advanced algorithms that are built intothe typical DCS, and there are add on packages (software, hardware, or both)available for others. The interviewees all concurred that it is best to first define thecontrol objective, and second evaluate, select, and test the advanced tool to achieve it.


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2.5 Benefits of Batch or Sequence Controls, Including Group Starts

Interviewees were asked to identify possible applications of batch controls for a fossilutility plant. The following suggestions were made:

• If the definition includes low-level sequence controls, then sootblowing sequencing is theprobably the most beneficial on digital systems, due to the capability of optimizing the steamusage to the determinable heat transfer coefficient. Most classical batch controls are notbeneficial to power plants because of the infrequency of equipment startups and shutdowns.It is not worthwhile to develop a batch program unless the procedure is performed at least ona weekly frequency.

• Benefits are real in terms of attaining fast, reliable, startups. Startups of pulverizers, boilerwater feed pumps, and turbines are candidates.

• One button equipment startups in the oil/petrochemical plant are commonplace. A majorrefinery will bring a distillation column on line completely under batch control.

• This is used on power plant control systems in the middle east, but not typically in the U.S.

• I would recommend batch controls for: Ash removal, conveyor systems, boiler startups andshutdowns. Even if operator manually executes each step, putting up “Best Practice”prompt messages will improve operations.

• We have achieved some major benefits from batch controls; however, there is a commonproblem that must be overcome – defining the procedure in standardized program. Werecommend using IEC 1131-3 to define the logic.

• “Utility processes aren’t recipe driven. One button startups eventually impact operatorskills. More value in help screens for startups. Conveyors and fuel handling processes couldbe opportunities”

There is divergent opinion on the benefit of automating batch operations performedinfrequently. If the benefit is perceived only as relieving the operator of manualtasks, then the average frequency of operator performance is highly relevant. On theother hand, if the benefit is perceived as achieving “best practice” for all operatorsfor a startup, shutdown, or product transfer of a process unit, then operations usedwith less frequency may indeed be worth automating.

The interviewees were asked to recall any experiences where the benefits of batchcontrols were quantified, and the following was offered by one interviewee: Benefits arequantified in terms of the value of speed, safety, and material savings. Any operation performedmonthly or more frequently is a candidate for batch control. A major oil refiner cut thetransition time on a distillation column product change from 2 days to 4 hours by automatingthe changeover.


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2.6 Benefits of Integration of Digital Control Systems with InformationProcessing (IP) Systems

The interviewees were asked to describe the impact on overall business decisionmaking observed from the integration of digital control systems with informationprocessing systems. They were asked particularly for examples that are relevant to afossil utility plant. The following comments were offered:

• This has had a significant impact for chemical plants, particularly on troubleshooting fromhistorical data. At a major chemical company, a certain reactor startup requires 8 hours.The cost of any problem that trips out a reactor is very high. Trips are analyzed andmeasures are taken to avoid future trips from the same problem class. The use ofmathematical programming on computers to minimize production costs is also of significantimpact.

• Processing plant raw material inventories have been reduced significantly through the use ofbusiness information processing systems tied to DCSs. Maintenance on valves can bescheduled based on accumulated valve travel distance, rather than time. This is morecorrelated with packing wear and saves significant money. For fossil units, the actual,realtime, heat rates of the units, rather than assumed heat rates, should lead to betterdispatch.

• Major impacts have been 1.) Increased availability of plant process data throughout theorganization, 2.) Increased reliability of numbers in the historical data bases, and 3.)Increased speed and frequency of reporting allows more timely actions. On line productionscheduling in oil refineries has led to about a 4% improvement in operational efficiency

• Availability of realtime plant process data in the system for various economic analyses lead to1-2 % reductions in operating costs.

• Variability analysis is used for preventive maintenance scheduling. Safety andenvironmental reports are run on the IP system. Best practice is documented.

• We have not integrated our DCS with a separate information processing system. Boilerhouse management is implemented on the DCS vendor package. Historicizing of data iswithin the DCS.

• All of our mills have either (OSI Software) PI or (AspenTech) CIM/21 and it is usedextensively. Process control engineers at Corporate Engineering routinely log on to thesesystems to monitor control performance.

• “Managers are used to MS applications such as Word, Excel etc. They demand that plantdata is available to them in this format. Trip analysis and other plant information is alsoimportant.”


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• “Real time cost data to the operators. True dynamic costs to the decision makers. Accurateperformance tracking. Uptime analysis and troubleshooting. The potential for system wideoptimization in real time.”

The next subject on this topic dealt with the extent that realtime plant data is used byplant and general office management. Comments:

• Terminal access of process data by a chemical plant manager is rare. Definitely used by plantprocess engineers, maintenance engineers and supervisors, and plant business managers.

• In the oil/petrochemical industry, the use goes all the way to the top of the company. Thepresident of a major oil company has a PC on his credenza and typically monitors totalamount of production instantaneously online.

• Plant managers may use the system to monitor over all performance. Direct observation ofprocess data by corporate officers above this level is extremely rare.

• Mill managers are definitely monitoring key process variables around the mill. V.P.responsible for corporate energy use is constantly comparing boiler operations across similarboilers in the company. Poor performance gets attention very quickly.

• Higher level process people responsible for each production unit access process data inscreens and reports implemented on the DCS.

• Operations management typically monitor trend graphics on key variables in their areas.Unit managers will generate reports on the previous day’s process data logs. The millmanager will typically monitor trends on key variables for the entire mill.

• “Real time process data is used by production engineers to help optimize processes. Millmanagement looks at key operating info to track plant performance. E.g. Steaming rates orminimum cost fuel flows. General office folks have yet to understand the value.”

Finally, under the topic of integration of process control systems with IP, theinterviewees were asked about experience with a process industry equivalent of powerutility “real time dispatch” (i.e. setting of plant output directly from a remote centraloffice)

• It’s being done. A major supplier of nitrogen controls nitrogen/air liquefaction and supplyfor hundreds of “over-the-fence” plants from a single control room in New York State. ThePlant Master controller in a multiple boiler facility is also analogous.

• Production rate from off shore oil wells is typically “dispatched” from a central office.Several utilities use real time dispatch for fossil plants, e.g. Baltimore.


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• Paper mills have fairly frequent upsets in steam demand, e.g. due to a “break” on a papermachine. Depending on the power plant configuration, a number of loops will be insupervisory control mode to a “plant master” which will make adjustments to set pointsimmediately when a break occurs to minimize venting steam.

• We are using energy management supervisory systems external to the regulatory controlsystems in the control rooms. One mill is using it to continuously optimize the make/buypower decision. The system is credited with savings of $50,000 per month. Another mill isusing it as the “plant master” over 4 power boilers feeding the same header.

The paper mill “plant master” examples are realtime and remote supervisory; however,the remote aspect does not include common carrier telephone connections.

The integration of digital process control systems with information processingsystems is just about universal in the process industries. Some plants try to stretchthe DCS to be both a process control system and an information processing system,but this is definitely not the trend. Making the process variables visible beyond thecontrol system in realtime has definite value in almost all business decision makingfunctions. The example given of the use of external energy management systems tooptimize power plant setpoints is also becoming the norm.

2.7 Value of Post Installation Audits

This section of the report has now examined the major issues of planning and justifyinga digital control system, as experienced by the interviewees. As a closing topic for thissection, the interviewees were asked about post installation audits. Comparing realizedcosts to planned or budgeted costs is routine for every project. Comparing plannedbenefits to realized benefits is another matter entirely. The following comments arenoteworthy:

• This is probably a good idea, but most people don’t do it.

• This doesn’t happen, companies can’t afford the time that it takes.

• Most companies will do an audit after the first two or three major DCS conversion projects.The results usually are that the savings are much bigger than used to justify the project.Then they don’t bother with audits any more.

• My company audits every project, and every DCS conversion project has met objectives andproduced the returns necessary to justify. Justifying a DCS conversion project today on aboiler is “really grabbing the low-hanging fruit”. The only negatives have been unfaircriticism of inefficient operation of the boiler, prior to the DCS, e.g. why were you operatingso inefficiently for so long?


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• We have now converted all of our 8 control rooms to DCS. After the first few we did audits.Then the need for audits disappeared.

• When we converted a Kamyr (continuous pulp mill) digester to DCS, it was justified on pulpyield variation improvements and on production increases. This was confirmed with anaudit.

Post installation audits of benefits are not routine. Where they have been performed,realized benefits have met or exceeded the plan.

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3 DIGITAL CONTROL SYSTEM ARCHITECTURE

The primary issues in the following three topical areas on digital control systemarchitecture were discussed with the interviewees:

1. Pure DCS vs. DCS/PLC Hybrid

2. Operator Interfaces

3. Use of “Smart” Field Elements and Field Device Networks

3.1 DCS-Only vs. DCS/PLC Hybrid

The best architecture for integration of regulatory instrumentation loop logic withmotor start/stop logic continues as an issue despite years of experience and debate.Some facilities use DCS I/O for the control of discrete devices such as motor controlcenters, solenoid valves, and field switches. Other facilities use PLC’s for the control ofdiscrete devices, with one or more communications between the DCS and the PLC’s.Interviewees were asked for comments on their approaches to an analysis of thedecision:

• Decision driven primarily by cost, i.e. PLC I/O is cheaper than DCS I/O; however, cost ofsystem integration hardware and software will negate some or all of the savings.

• Plant labor organization may require separation of discrete devices from instrumentationloops. Although PLC may appear less expensive, other factors may over-ride, e.g. DCS hasbetter diagnostics, PLC’s are not redundant, and two sets of tools and training are requiredfor the hybrid.

• This will soon not be an issue. New systems will be true hybrids with instrumentationcontrollers and discrete logic controllers on the same networks.

• Cost often drives the decision on discrete logic to a PLC; however, the hidden cost of theDCS/PLC gateway (hardware and software) will negate the savings.

Digital Control System Architecture

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• The weak point of the DCS/PLC hybrid is the interface – initial cost, programming cost,operation -- How do you update the software on one side of the interface without updatingthe other side? The strong point of the hybrid is the range of PLC solutions available.

• Major factors are: Maintenance troubleshooting capability, best fit with skills/experience ofthe engineers who will be implementing the system, best fit with process controlrequirements of equipment , e.g. safety system may require a level of redundancy notrequired on other DCS loops, and the discrete I/O capability and cost on the DCS.

• Electrical technicians typically do not want to troubleshoot from boolean logic; they preferladder diagrams. Some applications require the high speed of a PLC, e.g. counting sheets ofpulp coming from a cutter/layboy. Specialized systems, e.g. safety systems, burnermanagement, are often much more efficient on a PLC.

• Some of the issues are: User preference, availability of redundancy, cost, maintenance logicdocumentation requirements, configuration skills available, loop isolation requirements, andavailability of interface to third party equipment.

• “For process systems we want digital and analog information as closely coupled as possible,including safety, interlock, and process information to the operators. Therefore, a DCS, withdiscrete capability integral, is recommended. For processes that are discrete only andinterrelated information is not needed, PLC’s are recommended. Common configurationskills and common maintenance technicians for a pure DCS system is a plus.”

When asked what the decisions had been for the installations they had been involvedin, the comments were consistent – they had indeed gone both ways, depending on thespecific installation.

The interviewees were then asked for their advice for a specific type of installation, afossil utility plant.

• Consider three factors: 1.) Degree of integration, 2.) Speed of discrete device processingrequired, and 3.) Relative number of discrete to analog I/O points. With a low degree ofintegration, high speed required for discrete logic, and a relatively large ratio of discrete toanalog, then put in PLC. Otherwise, put discretes in the DCS.

• Put all discrete I/O in the DCS for a fossil plant.

• Consider control networks, such as Foundation Fieldbus and Control Net, with flexibility tohandle any mix of I/O types and logic functions.

• I recommend DCS only.

• Try to use DCS only, but don’t make it a bigger issue than it is.


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• Consider two factors: 1.) Capability and job definition (per union contract) of maintenanceand engineers, and 2.) the level of information about the discrete I/O necessary to display tothe operators.

• For the typical discrete device requirements on a boiler, we would recommend using the DCSto do all logic except the burner management system.

• DCS only to …”Minimize the number of systems, interfaces, suppliers, configurationlanguages, communication networks, standards, etc.”

For a fossil utility plant, unless there is a labor contract issue betweeninstrumentation and electrical maintenance, there is general concurrence to use theDCS-only architecture.

3.2 Operator Interface Decisions

The operator interface is the high visibility component of the DCS. It is also a high costcomponent with a high likelihood of rapid obsolescence. Obsolescence is not controlledby the DCS vendor; it is driven by the rapid pace of technology change in the computerand data communications network markets. There are always a number of specialfeatures to consider, such as, touchscreen, custom keyboards, and variations in pointingdevices. The method of designing and developing graphics and the number of screensdedicated to each operator are also typically issues.

3.2.1 Console Computer Operating System

The first question posed concerned the factors considered in deciding between variousconsole computer operating systems, such as VMS, Unix, or Microsoft NT. Several DCSvendors offer a choice.

• Entire industry is moving to NT, driven by customers and costs.

• Customers want PC based hardware platforms, but are typically not concerned about theunderlying operating system.

• NT will soon be the only choice.

• Vendor capability with the software is the primary factor. Select vendor first and then usehis best console software option for the job.

• The overwhelming preference for NT is driven by the desire for interconnectability and thecost/lack of satisfaction with proprietary operator interface solutions. The only negative isthe occasional screen lockup problem.


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• Cost is a big factor. DCS proprietary control stations were costing $50,000-100,000 each(list). The use of commercial, PC-based hardware has lowered this to less than $15,000.Operators also like using 21” CRT screens.

• “Most of the decisions have been vendor driven. Lots of attempts to try alternativeapproaches like Wonderware. Again, stick with one vendor. Drive them to cheaper, morescreens, easy configuration, transferable configurations between generations of op stations,better alarm management, a structured revision change process, screen redundancy, etc.”

When asked what the recent decisions had been for the installations they had beeninvolved in, the comments were somewhat varied, primarily due to the representedvendor organizations in the survey:

• NT

• Demand for touchscreen is declining. Demand for console furniture is declining. Customerswant the lower cost and flexibility of ordinary PCs on a desktop with a simple pointingdevice.

• NT, because it reduces training and support time.

• UNIX , because the system was Westinghouse.

• The decision for our company is NT. Microsoft has the motivation to fix the lockup problemwith Release 5, and we expect that they will.

• Considering the factors, we typically stay with the vendor’s standard console models, in hisproprietary design.

• We are now purchasing only 100% Windows NT.

• The market is driving all consoles toward Windows NT workstations.

The interviewees were then asked for their advice for a decision made now for a fossilutility plant:

• Select NT, but use enough operator stations to allow for software failures.

• Define the functional requirements of the console system before selecting a networkarchitecture: 1.) Required alarm handling rates are critical, a boiler feed water pump trip canput 500 tags into alarm. 2.) Screen call up time and refresh time is important during anabnormal event. 3.) Redundancy, in terms of the number of screens affected by a singlecomponent failure, is also a factor.

• Select NT and include a systems administrator in the staffing plan.


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• Select according to DCS vendor.

• Go with NT.

• Use NT.

• “Use commercial boxes, redundant screens to assure operator visibility, cheap per screencosts, networked views. Use NT. Unix is on the way down. NT reliability at the operatorlevel is acceptable. More understanding by on site resources, common boxes and operatingsystems.”

Select NT. If the DCS vendor does not offer an NT solution, consider carefully theneed for future modifications to the system and the future availability of spare parts.To increase flexibility, use standard desktop NT workstations.

3.2.2 Operator Console Graphics

The next issue for the interviewees was on the design and development of graphics --who should do it, how to proceed, and to what degree to standardize.

• There should be an evolutionary approach. The operators should have the major input. Theyshould be allowed to evolve the graphics into what works best for them. Typically they willevolve to very complex screens with a large number of update points and navigation keys to alot of other screens.

• Start early by having the operators review the vendor’s “Wedding Book” of screens from hispast fossil plant jobs. It is important to setup a controlled procedure that develops peerreview of operator screen suggestions and incorporates the best ones.

• Operators should design the graphics with strong guidance from human factors specialists.There is a lot of research on ergonomic factors in graphics design and navigation.

• Use a project team consisting of operators, engineers, computer programmers, technicians,and plant management, to develop graphics.

• Find willing operator, remove from normal duties, send him/her to DCS school, and thenteam with maintenance and DCS configuration engineer to develop all graphics. Thisachieves the best buy-in by the operators.

• Use a tremendous amount of operator input for layout, particularly from the operationsforemen. Our operators typically control from process graphics. We maintain plantgraphics standards for color coding, line styles, etc.


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• Systems integrator should make his recommendations based on previous jobs, then operatorsshould make suggestions and changes. We recommend the use of site standards for graphics.If site has no current standard, start with the ISA standard.

• “I can say without qualification that the best graphics have been developed by operators.The best system I have seen is that one or two operators are taken from shift and designatedas operator trainers. They are then responsible for all operator interfaces, including design,implementation, maintenance and the creation of the standards. There are many standardsfor graphics, but I have found that this is always a contentious issue, so site standards aredeveloped. The important thing is that the operators develop a sense of ownership of theoperator interface.”

• “Spend some time here. This is a key for the future. Engineers don’t do this well. Need togive operators a better view of the whole process. This is the disadvantage of DCS over theold control panel if it’s not done well. Put in one big screen in the control room. Getinnovative.”

Operators, particularly operators in a leadership role, must be integral to the designand development of the graphics. But to get the full automation benefits from theDCS, the operators will need to understand the capabilities of the DCS and how to“manage by exception”. Identify the lead operators, train them fully on the DCS,convert them to proponents of change, and then have them approve all graphics.

3.2.3 Quantity of Operator Console Screens Required and Span of OperatorControl

The following two questions were posed to the interviewees: In a typical control roomDCS console (grouping of displays, keyboards, annunciator panels, etc. for oneoperator) how many CRT displays are typically included? How many instrument loopsand discrete devices are typically controlled by one operator?

• Each operator needs 4 CRTs. One operator can be assigned 500 control loops + 500 discretepoints.

• Each operator needs 5 CRTs, 4 for process equipment control and 1 dedicated to the alarmsummary. One operator can control 2 fossil units, with 12,000 console tags per unit. This ishappening now at Arizona Public Service.

• Each operator needs a maximum of 3 CRTs. One operator can be assigned 200-500 controlloops.

• For fossil plants, operators typically do not rely on screen navigation and expect 11 screens –10 for process equipment control and 1 dedicated to the alarm summary. For equivalentequipment in the pulp and paper industry the same operator would have twice the equipment


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responsibility and half the CRT screens, but this would not be acceptable in the utilityindustry.

• You need a minimum of 2 screens per operator; however, for one boiler controlled by oneoperator, you need 3 screens. One operator can easily control 400-500 loops + associateddiscrete devices. We have control rooms where one operator is controlling 1200 loops.

• Our boiler house system has 6 screens for 4 boilers. Typically 1 screen is dedicated to acustom overview display and 1 screen is dedicated to area trends. We have one boardoperator and 3 rovers. There are about 500-700 loops in the boiler house.

• Each operator needs 3-4 screens. One operator can control 4 power boilers, 300-400 loops.

• “Typically for a single Unit, (say 300-600 MW), there would be three or four sets of operatorstations, with stacked CRT’s, i.e. two CRT’s on top of each other. One operator can onlyhandle two sets, the others are for assistance when there is a plant upset. Normally oneoperator would handle one Unit, with a supervisor that can help in a plant upset. Forsmaller Units, one operator may handle two Units. Usually each Unit would be on aseparate communication system so that there can be no inadvertent operation, or a failure inthe communication system will only affect one Unit.”

• “The process area and process dynamics are the key, not a loop count. One operator can runmany processes when the plant is running well. Key issue is startup and upsets. Controlscreens should not be a limiting factor. They are, or at least should be, cheap now. 4 screensminimum.”

Each control room operator requires 3-4 screens and can handle approximately 400instrumentation loops plus associated discrete devices. If these guidelines aresignificantly different from perceived requirements, then other factors should bereviewed, such as the “Help” screens, navigation scheme, alarm managementconfiguration, level of automation, particularly for preventing and recovering fromupsets, and level of operator training.

3.3 Use of “Smart” Field Elements and Field Element Networks

The field elements of an instrumentation control loop include sensors, transmitters, I/Pconverters, positioners, and control valves. Communication has traditionally beenaccomplished with analog DC current loops; however, digital data communicationsusing “smart” elements and field bus networks is an emerging technology. Initially, thedigital data communications applications were limited to calibration andtroubleshooting of smart transmitters, with the control loop communication remainingas analog DC. Interviewees experiences with the extensions of the use of thistechnology (beyond remote calibration and troubleshooting of smart transmitters) werereviewed.


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3.3.1 “Smart” Field Elements – Standalone or Networked

Interviewees were asked about the applications of “smart” field elements.

• For a typical installation today, 75% of transmitters are purchased as “Smart”. The benefitsof ease and speed of setup more than justify the $40 per instrument increase in cost.

• All transmitters today are purchased as “smart”. Smart valve positioners are far lessprevalent.

• Plan on all “Smart”

• “Wherever possible smart transmitters are applied due to the benefits of: accuracy, can belocated in areas which are not easily accessible to instrument technicians, can performdiagnostics and calibrated from a central location (either PC or DCS consoles).”

• We are typically putting in all “smarts”, transmitters and valves. Maintenance is drivingthis decision, and they feel that it is justified.

• For our typical installation, 80% of transmitters and 50% of valves are “smart”. Not all ofthe transmitter types we use are available from our vendor as “Smart”.

• Our company standard is all Rosemount “smart” transmitters. We do not use “smart”valves yet. We use the Entech valve standard and want to make sure that the “smart” valvesavailable will also meet the Entech standard.

• Use “smart” transmitters, except where communications time affects loop response.

• “Be careful of aliasing and process dynamics issues when selecting smart transmitters.Smart valves on all key process loops. Very little cost difference with smart sensors anymore.Easier to use one transmitter to spare multiple locations. Can do press./ temp compensationat the transmitter.”

Smart transmitters are prevalent. Smart valves are in the process of being accepted,and they offer major benefits in communicating valve condition and position history.

3.3.2 Field Element Data Communications Networks and Instrumentation AssetManagement Systems

Interviewees were asked about their experiences with the implementation of fieldelement data communications networks and/or overall instrumentation assetmanagement software for centralized calibration and maintenance.

• “Have applied Smart Transmitters on a Pulp & Paper application where the DCS andtransmitter manufacturer were the same. The transmitter data was available on the DCS and


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could recalibrate from the DCS console. A separate asset management PC was not required.Had the DCS not been capable of direct access to the transmitters, a separate PC with assetmanagement software would have been applied due to the benefits of smart transmitters.”

• We have implemented networks of Foxboro smart instruments.

• We have implemented networks of Honeywell smart instruments.

• We have implemented the Loveland (Honeywell) network at two mills. Both are pleased withthe benefits.

• “We have implemented asset management software. It’s still in the developing potentialstage. However, to get maximum control performance and therefore optimum processperformance the valves and sensors must be performing well. A predictive maintenanceapproach is needed.”

Centralized calibration and troubleshooting of smart instruments via a datacommunications network is an available technology that is achieving the benefitspromised. The applications cited are all proprietary, with limited interoperability.(See Conclusion of following section.)

3.3.3 Fieldbus (Foundation or Others)

Interviewees were asked if they have implemented (or are planning to implement) anydata communications networks (e.g. Foundation Fieldbus) completely replacing singleloop signal wiring. (Only comments listed below are by individuals presently affiliatedwith companies that are not a member of Fieldbus Foundation.)

• “Have not implemented Fieldbus technology nor do I have near term projects that I can applyit to. However, I do believe Fieldbus technology will be implemented in the near term and Iwill follow-up on its application.”

• We have only put in one Foundation Fieldbus system. It is on a lime kiln, 25 loops, andinstalled about 3 months ago. It is performing well. We would consider Fieldbus for a boiler,but it would be a very careful consideration.

• Our corporation is presently studying fieldbus. We don’t think they will commit to it at thisstage of its development.

• This is coming, but we will not be using for the next 2 years, while the initial “bugs” areworked out. We don’t see any advantage if using existing field instruments and existingfield wiring.

• “We have not and may not soon. However, in thinking about a control retrofit, especiallyfrom a pneumatic system, this should be closely considered.”


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Foundation Fieldbus is finally a reality and will likely replace all 4-20 ma wiringbetween smart field elements and the DCS controllers, in the near future, for newinstallations. Few DCS vendors have complete, field proven, fieldbus ready systemsright now. It is a little too early in the technology for application to fossil utilityboilers, but this could change quickly. Even if the technology is not a concern, aretrofit of an analog instrumented boiler with fieldbus is probably not justifiable.

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4 DIGITAL CONTROL SYSTEMS SPECIFICATIONS AND

VENDORS

The typical procedure for acquiring a digital control system is to develop a specificationand qualify vendors who can reliably provide the equipment and services that meetthat specification. After qualification, cost becomes a decision factor, but certainly notthe only factor.

The scope of DCS vendor responsibility can range from “Hardware and SystemSoftware Only” through “Full Turnkey Implementation”. Other vendors, consultants,and contractors may be involved.

The only comments listed in this section are by individuals presently affiliated withcompanies that are not DCS vendors.

4.1 Digital Control Systems Specification

The interviewees were asked if their company used a DCS specification. And if so, towhat level of detail is it developed, functional or including detailed designrequirements.

• We use a specification. It is mainly functional.

• Our corporation uses a fairly detailed DCS specification.

• We would only use a specification if we were choosing between several DCS vendors. Once aDCS vendor is selected for a site or company, the specification is a waste. The specification,if used, should only state functional requirements. Where the DCS vendor has been selected,we typically issue a document defining: 1.) the choices of DCS options, 2.) system blockdiagram, 3.) I/O count, and 4.) Quantities of other equipment.

• “No. We have selected our DCS at each operating location. Once that is done, we work withthe supplier on all new projects to develop the required system architecture as well as anymigration planning for the installed base.”

Digital Control Systems Specifications and Vendors

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Specifications, stating functional requirements, are used when selecting betweenvendors. Once a vendor is selected for a site, only specific job scope requirementsare specified.

4.2 Vendor Qualification

The following questions were asked: On what basis are DCS and PLC vendorsqualified? Is this done only when making a major purchasing decision or undercontinual scrutiny?

• Our company qualifies DCS and PLC vendors at the corporate level on the basis of productquality, price, and service. All sites either use one of the vendors qualified by corporate orjustifies their decision.

• Experience in our process area.

• Each site makes a decision on the DCS vendor (or vendors) with the best combination ofprice, delivery, and service, and sets up a purchase agreement with that vendor. There is acorporate agreement on PLCs – Allen-Bradley is the standard.

• “Almost all of the systems can do the job. Many of the decision points should be in what youexpect from your vendor after you buy. Engineering support, process optimization support,maintenance, spares management and inventory, etc.”

Qualification is similar to other vendors, with the added complication that thecustomer is typically heavily dependent on the vendor for support throughout thelife cycle of the product. This makes honesty, trust, track record, and experience inthe specific industry extremely important components of quality and service.

Interviewees were asked if they standardize on a single vendor for each (DCS, PLC) persite. Per all sites?

• No. Corporation has qualified 3 DCS vendors and 2 PLC vendors. All models by a vendorare considered qualified once a vendor is qualified.

• Yes, Corporation has one preferred DCS vendor and one preferred PLC vendor for alllocations. Not using the preferred vendors requires a detailed explanation.

• Typically one DCS vendor per site, but a few sites have 2.

• We standardize at each site; however I would recommend that you standardize for all sites.“To much synergy lost if you don’t. Common configurations, procedures, hardware,engineers, etc.”


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4.3 Scope of Vendor Responsibilities

Under this topic the first question asked was: What factors are considered whendefining DCS vendor responsibility?

• Process expertise is the main factor. We also consider success with advanced control schemesand staging capability.

• Consider the resources (people and dollars) that you have available and the capabilities thatthe DCS vendor and the A/E firm have to offer. We have used about all combinations, andgotten good results with all. Best combination is for Owner to purchase DCS, A/E firminstall and wire, and Owner configure DCS in-house.

• Service is very important.

• The skills that are needed and you don’t have or don’t want to keep on staff. Project needsversus system maintenance and optimization needs. Turnkey projects versus EPC.Proximity of your sites; shared inventories or vendor managed inventories. Competencies ofthe vendors.

The next question asked under this topic was: Have you ever given a DCS vendorcomplete, turnkey, full implementation responsibility for a retrofit to a panel-mountedcontrol room? What was your evaluation of their performance?

• Yes, if the vendor is qualified. We did it with Foxboro one of our mills and the job wentextremely well.

• Yes, and the project worked out O.K.

• We have given Bailey complete responsibility. The people assigned the job were not asexperienced as A/E engineers assigned to the same work.

• “Yes. Generalizations are never very good, but they don’t have good project managementskill sets in general. Their expertise is in their systems. If you do it, pay close attention to thespecific people assigned to your project.”

The last question asked under this topic was: What services do other vendors,consultants, in-house employees, and contractors provide, and how are these servicesdefined, scheduled, and coordinated?

• The following services are often performed by a specialized third party or consultant: Safetyaudit, graphics building assistance, information system interfacing, startup/checkoutassistance, and advanced controls.

• We use 3rd party specialist sometimes for advanced control logic development.


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• For major jobs we use the A/E for configuration, if the right people can be assigned;otherwise, we will use a system integrator for configuration. For small jobs the mill will dothe configuration.

• “There are specific functions required for the scoping, design, installation, checkout, startup,optimization, maintenance and management of any system. Who you assign responsibilityfor those functions depends on many factors; cost, time, skills, focus, priorities, preferences,career development, labor contracts, etc.. You must analyze each individually and within theconstraints of the current situation.”

The key phrase in the above comments is “…if the right people can be assigned,”.Implementers of digital control systems in the process industries have learned howto recognize qualified people. The vendor’s responsibility, or any otherorganization’s responsibility, will be dependent on depth of available, qualified,people.

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5 IMPLEMENTATION PROCEDURES

The success of a digital control system upgrade will depend on how completely,accurately, and clearly the process I/O and logic requirements are defined. After thedigital control system is configured, the system must be verified.

The success of a digital control system upgrade will also depend on the trainingprovided to the operators and technicians. Training is also a key to operator andmaintenance “buy-in” and ownership of the system.

5.1 Process I/O and Logic Requirements Documentation and Verification

The interviewees were first asked to define the documentation that would be prepared(or recommended) in their organizations if they were retrofitting a single loop panel-mounted instrumentation system to a DCS/PLC digital control system, assumingexisting documentation is incomplete. The comments were typically specific lists ofdocuments of use to construction, maintenance, or both:

• Loop sheets, motor elementaries, wiring lists, and some mechanism for documenting controlstrategy, e.g. SAMAs or IEC-1131 documents.

• “I/O database list for DCS vendor to configure, logic diagrams, graphic sketches, andconnection diagrams.”

• P&IDs with interlock notes, loop sheets, wiring schematics, motor elementaries, SAMAs onall complex loops, and logic narratives.

• P&ID’s, instrument tag database, loop sheets, motor elementaries/wiring schematics,SAMA’s with DCS-specific blocks, and logic narratives. We put the logic narratives onoperator help screens.

• Loop sheets, motor elementaries. We prefer to use the DCS vendor’s equivalent of the SAMAlogic diagram.

• “Much would depend on the scope of the effort. Assuming a fairly major retrofit, a detailedproject scope. P&ID’s. Instrument database. Instrument install specs. Valve specs.Preferred vendors list. Panel and termination wiring diagrams. DCS architecture

Implementation Procedures

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drawings. DCS equipment layouts. Control room and rack room drawings includingcutover plans. SAMA diagrams. Loop sheets. Loop narratives. Interlock diagrams.Configuration standards if none existed. Configuration drawings. Operator screen layouts.Failure mode logic.”

There was one comment in disagreement with the others:

• No specific documents are recommended. Survey the site with controls experts and let themrecommend the documentation requirements.

Next was asked – How would the documents be verified?

• Field check as much as possible.

• Users should verify any “as is” field documentation developed by the site survey team.

• “The connection diagrams would be field verified and the logic diagrams would be reviewedwith operations”.

• Review with operations and maintenance. Sometimes discrepancies are found during latersimulation, which is the same as a review.

• We do a 100% field verify for a replacement system. We do a 100% logic walkthrough.

• Review by corporate engineering and by mill operations and maintenance.

• Field check of existing wiring. Individual drawing checks by the designer. “Yellow line”check of all drawings against each other. DCS I/O check. DCS configurations tests. Prestart up inspection.

Implementers of digital control systems have typically developed field provendocument formats that define design and construction requirements. The samedocuments are updated during startup as “As Builts” and used by operations andmaintenance thereafter. Structured, detailed, review of these documents, at everyproject phase, by every affected person on the implementation team, is one of theearmarks of a successful project.

5.2 Logic Configuration Specification and Verification

After the controls requirements documentation has been used to configure the digitalcontrol system, the next step for implementation is the verification. The intervieweeswere asked how the configuration of the DCS/PLC is specified and verified in theirorganizations. Also, if they use, or plan on using, computer process simulation as partof this process.


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• Many DCS users require loop back type simulation to verify the DCS implementation of thelogic.

• Simulation is required only if the logic is intricate or different. For ordinary loops it is notrequired.

• A factory acceptance test is performed at the DCS vendor’s facility. Every I/O is simulated.The test is witnessed by plant operations to confirm that configured logic matches operatingconditions. This is the final review prior to start-up.

• Simulation is predominantly used. We use Gensym G2 and Simons IDEAS.

• We do not use simulation at all to verify configuration. We check logic when the system iswired to the real equipment and field instrumentation.

• We prefer to verify with simulation within the DCS. For Honeywell, we typically have thepeople doing the configuration write the simulation in CL [Honeywell Control Language].

• Yes we use a simulator, but we also check each I/O point and the internal logic via externaltest inputs.

There is no concurrence on the best method for verification of configured logic. Mostare using some level of simulation, but without specific testing procedures.

5.3 Staging

On the subject of staging, the interviewees were asked: Do you stage a DCS, either atthe vendor’s facility or at the site, prior to installing and connecting field wiring? Withone exception, the interviewees were in agreement:

• Stage hardware only.

• “Staging at factory.”

• Yes, complete staging at the vendor’s facility.

• Yes, we do a 100% staging at the vendor’s facility.

• Yes, we do a complete staging at the vendor’s facility.

• Yes. Factory test to see that it powers up and works OK. On site tests to verify I/O,interfaces, and configuration.

The dissenting comment:


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• Definitely do not stage a system. It is a waste of time and money for today’s DCSarchitectures.

Staging is a worthwhile exercise to confirm performance of the integrated system.Verification of logic configuration should be a separate, previous, step.

And finally: Do you perform a loop-by-loop checkout [a field verification that eachinstrument and discrete device is properly installed and wired to the DCS] prior toprocess equipment startup on the DCS/PLC?

• Loop checkout is absolutely a must.

• Yes, check loop hardware and software integration in the field prior to startup.

• “Loop checks are done prior to start-up.”

• Yes, complete loop check signed off for every loop.

• Yes, we do a 100% loop check on site.

• Yes, complete loop checkout.

• “Absolutely”.

Loop checkout is a must to validate construction.

5.4 Operator and Maintenance Technician Training

The first question under this topic was: Do you use a simulator for operator training?

• Yes, the use of a simulator for operating training is typical for a chemical process.

• Yes, most DCS users do.

• Yes.

• “A simulator is the preferred method of training.”

• Yes, we use a simulator in a separate computer linked to the DCS. The simulator is designedto automatically adapt to any changes in DCS logic and graphics so that it will remain up todate as the DCS is changed.

• We have completed development of a training simulator for one of our processes, and we aredeveloping simulators for some others.


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• Yes, we do this for about ½ of all major projects. There is pressure to drop this because of thecost.

• Yes.

• “Yes, especially if they have not used a DCS before.”

The next question under training was: Do you use self-directed training? With testing?

• No, not unless you are trying to teach the process, rather than teach the control system tooperators who already know the process.

• Yes.

• “Self directed training is not recommended, detailed training courses by an instructor arerecommended.”

• We tried this and didn’t like it.

• Yes, and the training exercises do include tests.

• Yes. Operator solve upset scenarios on the simulator and are timed on how quickly theysolve the problem. Simulator has to be fairly close to the process to make this work – samegraphics, same tags, approximately same process response.

• “It varies with the project and individual operations management interest. Mostly thetraining is formal. Sometimes testing.”

And finally on training: What is the most effective method of training operators?Training technicians?

• Process simulator on the DCS or interfaced to the DCS is the best way to train operators.Training technicians is very difficult, but very important. This is often overlooked.

• Process simulator on the DCS or interfaced to the DCS is typical. A further enhancementbeing used in oil/petrochemical is to set up the simulator to track a real process andautomatically adapt its behavior to the real process.

• “Training on the actual operator consoles is the most effective rather than generic trainingconsoles in the factory. Factory training is more effective for maintenance technicians.”

• Operator “buy-in” is important. They participate in the design (P&ID reviews, graphicsdevelopment). They go to the vendor schools. And, they train on the DCS simulator.

• For operators: we take them off the board, give them class room instruction, as well as timefor the self directed exercises on the simulator. For technicians: we typically send them off


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site to the vendor’s facility. There the equipment can be “bugged” and the student canpractice diagnostic skills.

• We use the simulator problem solving scores to qualify operators at 2 mills, i.e., if they can’tpass the simulator test, they can’t become an operator.

• Train to use DCS first on simple loops and a few motors, so that the operator can adjust froma panel to a CRT/keyboard environment. Then train on the complete process using the DCS.

• “Operators write the training manuals. Train on a simulator. Involved in PSI (pre startupinspection).” For technicians: “Just train those folks who will be working directly on thesystems immediately after the training. Bring suppliers to the site and train on actualequipment. Do it concurrently with configuration checkout, communication interfacechecks, I/O testing and operator training.”

•

Operator training on the same model DCS console and same graphics to be installedis recommended. Simulation must be used to take the place of real boiler and realI/O. There was no concurrence on the simulator requirements. Maintenancetechnician training is best handled offsite at the DCS vendor’s training facility.

5.5 Operator Interface Problems

The following question was of interest: Have you seen any problems with informationoverload, where the operators were getting so much information where they wereconfused and were in fact hindered in their ability to quickly diagnose problems? If so,what was the solution?

• Yes, this is associated with poor alarm management, either within the DCS capability orresulting from poorly conceived setup of alarm functions.

• Yes, this definitely can happen. It is often due to poor screen navigation design and/or topoor assignment of alarm groups/filters. Alarm priorities and filters need to be very carefullyconsidered.

• Yes, there are 2 solutions to be considered. 1.) Artificial intelligence (expert systems) toassist the operators, and 2.) Rethink the alarming scheme, particularly alarm cascading anddynamic filtering. Our facility uses an alarming design criteria whereby not more than 3alarms can cascade from a single abnormal event.

• “A considerable amount of time has to be allowed for training because each operator must becomfortable with his ability to absorb data at his comprehension level and speed, the plantcannot afford to have the operator be overwhelmed because of time constraints.”


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• This is due to poor system design, particularly graphics and alarm management. Need toreview both, if this is a problem.

• This is due to creating too many alarms and setting the alarm limits too tight. Operatorswill then inhibit or disable alarms, which creates a problem later. We require operations toprint out a list of inhibited alarms at the end of each shift.

• Alarm overloads occur when you are not careful in setting alarm limits and creating alarmstates. Where retrofitting a control room with annuciator panel alarms, we will leave thepanel alarms installed and hardwire the supercritical alarms to the panel alarm.

• Yes, the solution is careful design of the operator interface and the use of simulators fortraining.

• “Yes. First, make sure they know their process. Then develop and implement an alarmmanagement plan. Install help screens to diagnose and solve problems. Present operatorswith knowledge on the screen, not just data. Train well up front. Make navigation betweenscreens intuitive.”

And finally: Have you seen any problems with mode confusion, where the operatorswere not sure of which control mode they were in and how to quickly get back to afamiliar mode? If so, what was the solution?

• Yes, this problem is best solved by color coding control stations so that the normal mode ofcontrol is a specific color.

• Yes, this problem is best solved by training the operators in console procedures.

• Typically not a problem, but it would be solved by using color graphics to alert the operatorthat the control mode was abnormal.

• Sometimes operator problems are not exactly what the problem is at first defined to be. E.g.,we’ve had color blind operators, operators who can’t read, and operators who needed bifocals.

• Our DCS has a normal mode switch on the keyboard that will put all loops in their normalmode.

• We use a mode control text graphic of loops, clearly differentiating the loops not in theirnormal mode.

• I haven’t seen this problem nearly as much as “over-produced graphical displays”.

• “Yes. This is pretty much just a training issue.”

Several suggestions, including color coding of control mode and text listings of out-of-normal mode stations, were offered for solving these two problems.

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6 CONCLUSIONS

In the body of this report the investigator’s conclusions and recommendations wereshown in boldface, immediately following the interviewee comments for each topic.This section of the report summarizes these conclusions and recommendations for thefour major topic headings.

6.1 Planning and Justification of Digital Control System Upgrades

Conversion to DCS-based digital control systems, which has been ongoing in theprocess industries over the past 20+ years, is now virtually complete. Even without thissurvey, we can conclude that these upgrades were overwhelmingly justified. To denythis would require denying the economic Darwinism that we know is taking place, dueto the globalization of these industries.

Under this heading we reviewed several topics concerning how digital control systemsupgrades were justified in the process industries – What were the benefits expected,were the benefits realized, what were the critical tasks, were costs within budget, whatwas learned from a project manager’s perspective?

There were significant energy and material savings and/or effective capacity increasesdue to operating process equipment closer to the economic optimum during normaloperations. There were fewer process upsets and faster recovery after an upset. Therewere operating manpower savings due to automation. Total loop maintenance wasmore cost effective, even considering higher on-going DCS maintenance costs. Theinformation storage, retrieval, and reporting capabilities of the DCS were beneficial inanalyzing ( and preventing the repetition of) safety and environmental incidents.Examples of all of the above are shown in the report.

It should be stressed that the DCS was an “enabler” of the benefits cited; the benefitswere not achieved by simply “replacement in kind” of the DCS equivalent logic.Advanced control algorithms, built-in to the DCS or available as add-ons, were a keyfactor in attaining benefits. Analysis and automation of batch operations has led toachieving “best practice” for startups, shutdowns, and product transfers. Theintegration of process control systems with production level information processingsystems is another important source of benefits. Making process variables visible

Conclusions

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beyond the control system in realtime has had definite value in almost all businessdecision making functions.

The tasks required to upgrade to a DCS-based digital system, and the costs and risksassociated with each task were examined. There was nearly unanimous concurrence onthe order of march: Equipment must be purchased, the site must be prepared, andcontrol requirements must be documented. The new DCS must be configured withlogic verified, staged, wired, and checked out. The operators and maintenancetechnicians must be trained. Although equipment purchase is a relatively high costitem, it can be estimated accurately for an upgrade. Site preparation and conversioncoordination for an operating facility was identified as a critical task. Logicrequirements analysis, operator interface design, and modifications to the operator’sbasic approach to control were also identified as critical to achieving positive benefits.

6.2 Digital Control System Architecture

As stated in the body of the report, the best architecture for integration of regulatoryinstrument loop logic with motor start/stop logic continues as an issue despite years ofexperience and debate. The issues here were reviewed, and the interviewee consensuswas that, for a fossil utility type of installation, the DCS-only architecture, rather thanthe DCS/PLC hybrid, be recommended.

The recommended architecture for the operator interface of the DCS was Microsoft NTclient/server. Also, operators must be placed in a leadership and approval role duringthe design of graphics and the operator interface. This was typically a costly, but highlyworthwhile, decision to achieve the long term automation benefits, within the capabilityof the DCS.

“Smart” transmitters were reported as prevalent; smart valves were seen as being in theprocess of being accepted. Centralized calibration and troubleshooting of smartinstruments via a data communications network was identified as implemented onproprietary, non-interoperable, systems. Interviewees’ organizations were tryingFoundation Fieldbus on pilot projects, but did not think technology was mature enoughfor site critical processes such as boilers.

6.3 Digital Control System Specifications and Vendors

Interviewees recommended that specifications should be restricted to statement offunctional requirements and used to select between vendors. Once a vendor is selected,only the specific job scope requirements are documented. Interviewee’s organizationstend to standardize on a DCS vendor, at least at each site, in order to build almost apartnership relationship. Skilled people with both the specific process and specific DCS

Conclusions

6-3

configuration experience are a rare commodity, and are typically drawn from severalalternative sources to ensure job success.

6.4 Implementation Procedures

Implementers of digital control systems stated that they have typically developed fieldproven document formats that define design and construction requirements. The samedocuments are updated during startup as “As Builts” and used by operations andmaintenance thereafter. Structured, detailed, review of these documents, at everyproject phase, by every affected person on the implementation team, was reported asone of the earmarks of a successful project.

Although all agreed that verification of DCS logic is critical, there was no concurrenceon the value of simulation as an aid. Almost all agreed that a system staging wasworthwhile, and all agreed on the necessity of a loop-by-loop field wiring checkout.

Operator training on the same model DCS console and same graphics to be installedwas recommended. Simulation must be used to take the place of real boiler and realI/O; however, there was no concurrence on the simulator fidelity requirements.Maintenance technician training was recommended as best handled offsite at the DCSvendor’s training facility.

A-1

A SURVEY INTERVIEWEES

Name PresentCompany

Present Title(time with

presentcompany)

Previous Titles,Companies

Most Relevant Experience

Robert W.Barber

ChampionInternationalCorporation

SeniorControlsEngineer (8yrs)

Process controlengineer withInternationalPaper (20 yrs)

Converted 2 power boilers and 2recovery boilers from Foxboro panel-mounted to ABB Mod 300 DCS.

Murray A.Champion

YokogawaIndustrialAutomation

InternationalPowerBusinessDevelopment Manager

Trained operators and managed DCSimplementation projects in a broadcross section of industries

Jay D.Colclazier

Fisher-RosemountSystems, Inc.

Sr. IndustryConsultant (7yrs)

Processengineer withMonsanto andCelanese (14yrs)

Justified a number of retrofits withHoechst-Celanese – Chemical Batch onFisher-Provox. One of two advancedcontrol consultants with Fisher-Rosemount

Don Frerichs Elsag BaileyProcessAutomation

Director ofApplicationsResearch (35yrs)

ChiefApplicationsEngineer forPulp & Paper,Iron&Steel

Retrofited numerous panel-mountedsystems to DCS

Dan D.Glossner

AmocoChemicals,DecaturPlant

MaintenanceSupervisor(20 yrs)

Process controlengineer,projectengineer, sameplant

Has been converting Decatur plantequipment to Honeywell DCS since1985.

Survey Interviewees

A-2

Name PresentCompany

Present Title(time with

presentcompany)

Previous Titles,Companies

Most Relevant Experience

William J.Harding

TheFoxboroCompany

IndustryConsultant –PowerApplications(Recent hirefrom ParsonsEngineering)

Assistant ChiefInstrumentationand ControlsEngineer,Parsons PowerGroup (20 yrs)

Converted 6 utility plant panel-mounted instrumentation systems todigital.

Paul S.Inglish

HoneywellIndustrialAutomationand Control

BusinessDevelopmentConsultant(20 yrs)

Process ControlEngineer to Sr.BusinessAnalyst withExxon (8 yrs)

Developed major automation forrefineries.

Developed advanced regulatory controltechniques.

Developed information infra-structurefor refineries and chemical plants.

David J.Latour

UnionCampCorporation

SeniorProjectEngineer (20yrs)

Newtron Inc.,InstrumentTechnician

Managed several DCS installations.

Chris E.Rogers

BoiseCascadeCorporation

Manager ofElectrical andProcessControl ( 13years)

ITT Rayonier(10 years)

Managed several major equipmentrebuilds and installations.

Fred Y.Thomasson

UnionCampCorporation

SeniorApplicationsEngineer (21yrs)

Babcock &Wilcox, SeniorProcess ControlEngineer

Has implemented 3 energymanagement systems and has beeninvolved in several DCS projects.

tr-112230

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