Boilers

Update and bump: The whitepaper, DCS Controller Loading Reduction for Sequence Logic - A Boiler Control Project Case Study, is now available.

Original post:

Let's close this week with a post about sequence control loading improvements in boiler operations. I managed to get my hands on a draft of a whitepaper from Emerson's Shawn Zadeh who is a Process Automation Engineer on the Process Systems and Solutions team.

For one particular boiler control project, Shawn and a colleague observed that the DeltaV controller processor Free Time statistic was very good on the two controllers being used. With everything being mostly the same on the project vs. other projects with respect to motor control modules (CMs), control loop CMs, and discrete input CMs; the only striking exception was the way they chose to complete sequences.

Sequential tasks are often handled using IEC 848 sequential function charts (SFCs). In the whitepaper, Shawn notes there have been previous project tradeoffs in SFC implementations with controller scan rates and controller free time. The logic can be intensive when following the ISA-88 (S88) model with phase modules running SFCs that are often used in equipment modules. Shawn describes the upside to SFCs that are easy to understand because they clearly and simply represent the steps of the process. SFCs also work well for high-level programming of control sequences. They are familiar to many people, because SFC is one of the languages specified in IEC 61131-3, and they are used frequently in programming PLCs. And SFCs are self-documenting and easy to troubleshoot and debug.

For those not familiar with SFCs, it consists of a series of steps linked by transitions. A step is essentially a state of the system, and can be active or inactive (idle); the initial step is always active at start-up. Some steps have actions associated with them (open a valve, close a gate, etc.) that will be performed only if the step is active. A transition is enabled when the step preceding it is active and the logical condition(s) for the transition are satisfied. When a transition is enabled the step preceding it becomes idle and the one following it becomes active.

What Shawn and team did was to develop a technique for programming DeltaV systems for boiler control that replaces SFCs with function blocks to align with standard boiler control conventions, but had the unanticipated effect of using a very low amount of controller processing time as well. Function blocks, defined by IEC 61499, cover a broad range of applications. They are used traditionally for continuous control, but work quite well for discrete control. Function blocks are easy to use, help reduce training requirements, allow reuse of programming elements, and can reduce processor loading compared to SFCs.

For the sequence control strategy, the control module was broken into two main sections: the Sequence Control Initiation area and the Control Sequence Operation and Shutdown area. They wanted to delineate where the sequence setpoint is determined and where the sequence actions and confirmations are in order to facilitate troubleshooting. Shawn shared that the combination of the two areas that can handle failure detection (through the use of interlock and permissive functions), using a standard interface, and the connection between the two areas and the sequence logic contained in a top-down format that's easy to read is unique.

Using this approach, the project controllers could perform complete unit operation control (i.e. sequence and continuous control) at a 200ms scan rate, which can satisfy nearly all non-SIS process and manufacturing control requirements. Operational runtime has proven this approach to be a robust method for the sequencing requirements found in these types of boiler project. Shawn sees reuse of this approach on modules that require fast scan times on multiple units/independent sequences running on a single controller.

I'll update the post once the whitepaper is finalized and available on the www.EmersonProcess.com website. DCS Controller Loading Reduction for Sequence Logic - A Boiler Control Project Case Study.

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I caught up last week with Emerson's Al Novak. You may recall Al from some of our alternative fuels-related posts. He mentioned that they had another Alternative Fuels and Energy Summit in Cambridge, Massachusetts. The focus of this summit was on using "biomass" feed stocks and using biochemical, thermochemical, or combustion technologies to convert the feedstocks into to fuel and energy. Nearly 50 people attended this event.

For those not familiar with the term biomass, I turn to Wikipedia, which defines it:

...a renewable energy source, is biological material derived from living, or recently living organisms, such as wood, waste, and alcohol fuels. Biomass is commonly plant matter grown to generate electricity or produce heat.

One of the presentations given was Biomass Energy Optimization by Emerson's Chip Rennie. I'll highlight some of the points he shared with the summit attendees. On the value in burning biomass, Chip noted that waste fuel substitution could reduce costs of manufacturing more than any other single change.

From a capacity standpoint, biomass power represents the largest source of renewable energy, surpassing hydro-based energy production. Biomass power plants divert wood waste from landfills, which reduces the production and atmospheric release of methane. According to the U.S. Environmental Protection Agency (EPA):

Methane is over 20 times more effective in trapping heat in the atmosphere than carbon dioxide (CO2) over a 100-year period...

Chip's final point on burning biomass is that it can result in zero net carbon dioxide emissions because any carbon dioxide released by burning biomass can be removed from the atmosphere by growing more biomass.

Chip shared some U.S. biomass statistics. In 2008, biomass accounted for about 1.4% of total U.S. power generation nearly equaling wind, solar, and geothermal power production combined. The use of biomass as a fuel source is expected to grow tenfold between 2008 and 2020.

Some of the challenges for process manufacturers and energy producers using biomass fuel are inconsistent calorie, moisture, and sludge content, difficulty in handling (feeder plugging, conveyor trips, etc.) and inconsistent material size. These challenges are offset by biomass fuel advantages in high caloric value, abundant supply, lower emissions, relative lower costs, and reduced carbon footprint compared with traditional fuel sources.

Chip shared some process control and optimization strategies for biomass multi-fuel boilers. These strategies involve the use of model predictive controllers with systems such as the DeltaV automation system for the unit BTU demand, bark constraint, and auxiliary fuel constraint. In addition, fuzzy logic blocks are used to calculate biomass heat release and biomass quality.

Biomass heat release is calculated from feeder speed, oxygen, steam flow, bark air, and pressure change rate. Biomass quality is calculated from feeder speed, oxygen, steam flow, opacity, and demand change rate. These algorithms help adjust the controls to the changing conditions of the biomass.

While the use of biomass as a fuel continue to grow, the summit attendees echoed that feedstock and legislative policy continue to be the major hurdle in successful projects. Emerson's James Stanley who also attended this summit relayed a quote from Dr. Tom Amidon from State University of New York College of Environmental Science and Forestry (ESF). He stated:

Feedstock is the tail that will wag your dog.

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Boilers remain a large source of energy consumption in most plants. Emerson's Bob Sabin, whom you may recall from many earlier energy management-related posts, has some great thoughts on a recent Plant Services magazine article.

The article Boiler inspection and maintenance by Stephen Kleva provides an overview and reminder of aspects of safe and economical boiler operation, and makes a number of good points. Building on this, it occurs to me that instrumentation and control technology can be leveraged to help accomplish the goals of maintaining safety and achieving lowest possible costs.

Boiler owners sometimes overlook the value of a fully functional automated control system and a computerized asset monitoring system. Mr. Kleva notes several things regarding how problems with a boiler process can occur:

It's important to remember that most problems don't occur suddenly. Instead, they develop slowly over a long period of time.

Boiler logs provide a continuous record of the boiler's operation, maintenance and testing. Because operating conditions change slowly over time, a log is the best way to detect significant changes that might otherwise go unnoticed.

"The success of any boiler log is determined by how vigilant the operator is in regularly updating it.

Most operations personnel would agree with the statements above, yet many sites do not have or do not fully maintain the equipment needed for complete monitoring and/or comprehensive performance logging. For example, it is all too common for boilers to be operated for long periods with known instrumentation problems. For a variety of reasons, these are not promptly addressed, but they certainly contribute to less than most economical operation, and sometimes play a part in a breakdown.

Today's computer technology allows monitoring of boiler process measurements to be done consistently and automatically every minute of the year, and further, today's tools provide alerts when a parameter trends out of normal range, changes too quickly, or exceeds a constraint. The unfortunate situation is that most sites have not implemented these asset-monitoring tools even though they are relatively inexpensive and not very complicated to apply.

Extending this, many sites have not taken advantage of computerized data logging and historical data management. Even at their best, paper logbooks provide only a minimal view of process performance. They are only one-value snapshots of process parameters at a one- or two-hour interval and they are subject to gaps in data when operations personnel are tied up with other tasks. Computer control and data historian systems monitor the process in the range of every half second, do not get interrupted, and provide a multitude of data analysis tools to observe trends, identify abnormalities, and provide the basis to drive improvement.

The article also mentions, "Optimal air-to-fuel ratio is important because a boiler requires just the right amount of oxygen to ensure efficient combustion." Mr. Kleva goes on to relate that a control system is the tool to use to achieve optimized combustion consistently over time.

A good control system will manage efficiency over the load range of the boiler, and will be designed to work with any other boilers that are present on the site. Many (if not most) industrial sites run more than one boiler to produce required steam. A modern control implementation will calculate the cost per steam in real time per boiler, and will manage load across all available boilers in order to provide the lowest cost steam in total within applicable constraints.

While instrumentation and controls may sometimes seem to be only a necessary evil for a boiler process, they have been repeatedly proven to be a technology and tool that improves performance by supporting safe operation and optimizing the economic outcome.

Bob, thanks for adding your perspectives on the role process automation can play to this boiler maintenance article!

I always like receiving goodies that I can pass along to the readers of this blog. This one, a boiler blowdown savings calculator, is from Emerson's Jim Thompson. Jim is a manager in the Rosemount Analytical Liquid business.

Jim probably knew that I'm definitely not a boiler blowdown expert, so he was kind enough to point me to a great Boiler Blowdown Fact Sheet developed by the North Carolina Division of Pollution Prevention and Environmental Assistance.

For those like me who may have heard the term but not have known what it really meant, the fact sheet sums it up:

To avoid boiler problems, water must be periodically discharged or "blown down" from the boiler to control the concentrations of suspended and total dissolved solids in the boiler. Surface water blowdown is often done continuously to reduce the level of dissolved solids, and bottom blowdown is performed periodically to remove sludge from the bottom of the boiler.

It makes good economic sense to perform these blowdowns. You can reduce fuel consumption, use less chemical treatments, and reduce heat loss in the steam you are producing. Automated boiler blowdown operations can:

...save about 2 percent of a facility's total energy use with an average simple payback of less than one year.

Jim pointed out that measurement of boiler feedwater conductivity is an indicator of the concentration of dissolved solids. Rosemount Analytical conductivity sensors, transmitters, and analyzers are used to measure for these dissolved solids. A blowdown system typically includes an automation system running the PID loop, a sample cooler and downstream conductivity sensor & transmitter as the loop input, and the blowdown control valve position as the loop output. Depending on the boiler application, conductivity, pH, dissolved oxygen and free chlorine may also be measured and controlled on the feedwater and makeup water lines.

The calculator uses the maximum recommended concentration limits according to the American Boiler Manufacturers Association (ABMA). Also, the American Society of Mechanical Engineers (ASME) has developed a best operating practices manual for boiler blowdown. The recommended practices are described in Sections VI and VII of the ASME Boiler and Pressure Vessel Code. The calculator helps you identify energy-saving opportunities by comparing your blowdown and makeup water treatment practices with the ASME practices.

If your process includes boilers, give the calculator a try to see if you have opportunities to improve efficiency and reduce ongoing maintenance costs.

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

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

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

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

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

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

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

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

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

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My colleague, Deb Franke, pointed me to a great article in her RSS feeds. The ChemicalProcessing.com article, Innovative Fixes for Saving Energy in Plants, describes some ideas to help reduce plant energy costs. Although energy costs have come down in recent weeks, they are still one of the largest controllable costs as I have mentioned in an earlier post.

The article points out innovative solutions including dual drive pumps, variable speed motors, water/glycol systems, automated blowdown systems, low BTU sweep gas and wireless sonic leak detectors. Give the article a read if you think some of these might apply in your plant processes.

I forwarded the article to Emerson's Lou Heavner, whom you may recall from earlier advanced process control application posts. I asked what new and innovative, energy saving ideas he might have to share.

Lou had a couple of ideas. But, being the modest sort, he added a caveat that they may not qualify as new or innovative. To me, if you're looking for ways to reduce your energy costs and you didn't consider one of these, it's definitely new.

Lou's first thought was on distillation processes. He writes:

In distillation, relative volatility and hence difficulty of separation tends to improve at lower pressure. When cooling water and/or air are used to condense the overheads, the pressure is often tightly controlled for stability in the face of changing ambient conditions and the extra cooling capacity available during nights or colder weather is not fully utilized. If pressure is allowed to "float" and as much condensing occurs as is possible, pressure will fall in the column and separation will normally improve. This means less heat is needed in the reboiler and hence energy savings when using steam or some other "costly" utility stream to provide reboil.

His second thought was around combustion processes burning fuel gases with changing compositions. Lou notes:

In heaters or boilers where the gaseous fuel consists of a hydrocarbon mixture of varying composition (like refinery fuel gas), a change in fuel can have an effect on the heat generated by combustion and on the excess air level in the flue gas for a given fuel flow rate. Sometimes, if variability of the flue gas justifies, companies will install fuel quality analyzers that measure composition or heating value. In many cases, the same thing can be achieved and better flow control at the same time, by using a Coriolis mass flow meter. It turns out that the mass flow of a hydrocarbon and the "btu" flow are directly related since both are related directly to MW.

You can't do this with PT compensated flow, because it knows nothing of MW. But Coriolis measures mass directly and can be used to reduce variability of "btu" feed to the burner. This can be dramatic where the fuel gas varies significantly. It is not a good solution if the "btu" content changes due to the presence of inerts (like N₂ or CO₂) or non-hydrocarbons (like H₂ or CO), since they do not exhibit a linear relationship between mass flow and "btu" flow. But if they are present in small quantities and don't vary much, the concept can still work.

On processes that degrade the "quality" of energy, Lou shares:

Saving energy can be as simple as minimizing thermodynamically irreversible operations. Mixing, heat transfer, and throttling of process flows are common examples of irreversible processes. In general, industry should avoid over-purifying/heating/cooling followed by mixing or blending to achieve the target composition/temperature. Process design should attempt to get as much work as possible out of utilities and recover as much heat as possible. Pinch technology is one approach to heat integration design used by process engineers. Of course, there are practical limitations like capital cost considerations, dynamic response and controllability, and availability/reliability of utilities, especially ambient cooling.

Also, control valves should be selected to minimize throttling losses and allocation and valve position should be used to minimize overall pressure drop in systems like utilities where resources are shared by different units or equipment. For example, if multiple reactors are cooled with a shared refrigeration unit, the coolant temperature setpoint can be raised (reducing the refrigeration required) until one of the user's demand exceeds the capability of its corresponding control valve to deliver.

Let's hope that something between the ChemicalProcessing.com article and Lou's thoughts provides you at least one idea that can help reduce your plant's energy bills.

Emerson's Doug White sent me his presentations from the recent AIChE spring meeting. Doug is a principal consultant and vice president for advanced process control (APC) services, and has many years of experience justifying, designing, installing and commissioning APC applications for process manufacturers.

Given rapid rising energy costs, his presentation, How to Save Energy through Advanced Automation, caught my attention. He starts by showing an upward trend in natural gas prices (in one word--ouch!) Doug makes the point that process energy usage is often the largest controllable cost in most plants.

Doug shows energy flows for process manufacturers in different industries including chemicals, pulp and paper and oil refining. He also gives some typical percentages of the energy flow inputs and outputs. For example, a typical refinery's sources of energy include 1% purchased steam, 25% purchased fuel, 64% raw materials consumed as fuel and 10% purchased power. This energy is used in steam production and central power production in the power plant. In the process and offsites areas, the energy is mainly consumed in the process-fired equipment, direct fuel usage and electric motor drives. Energy not consumed in the process is exported as steam, fuel and power.

Applying better automation and APC can help improve efficiencies around individual equipment like boilers, heaters and kilns (links are to earlier posts where equipment efficiency stories have been chronicled.) Savings can also be achieved at a unit, multi-unit and site level by finding opportunities in optimization, waste heat recovery, and off-spec/waste minimization.

As the earlier percentages indicate, you may have a control loop heavily involved in your plant's energy usage. It may well be worth improving the measurement, control valve performance and loop control performance to reduce variability and energy consumption. Also, your process may have bypasses around production equipment that may be compensating for poor control through the equipment. Optimized control can eliminate the need for these bypasses.

The presentation is loaded with specific examples including stem systems, combustion control, heaters, distillation controls, plant utility systems, facility optimizers, boiler load allocation and site energy balances. Some examples like power boilers include return on investment (ROI) calculations that may assist you in your project justification efforts.

I wanted to highlight some key points Doug makes around heater optimization. If there is resistance in improving heater controls because the damper control is are not reliable, then he recommends adding positioners to the dampers. Bring the feedback to the control system and then analyze and fix any controller problems. If the next objection is on-line analyzers don't exist or are not maintainable, Doug notes that analyzers are cheaper and more reliable, especially mass flow meters. With today's higher fuel costs, these analyzers should be well justified.

There are likely many areas to look for energy savings. Doug recommends a disciplined approach to evaluation and analysis to prioritize the opportunities. Given the increasing costs of energy and the fact that this is often the largest controllable cost in a process manufacturing plant, it may make sense to establish a program around saving energy and apply focused efforts in prioritized projects to reduce overall energy consumption.

The Automation.com list server has an interesting thread, Three Element Drum Level Control Problem. The question asked was:

We have a waste heat recovery boiler that is supplied by exhaust of a 20MW Gas Turbine. We've seen that at lower turbine loads (75% and below) the three element drum level controller cannot maintain the drum level at desired setpoint. As soon as the load on the Gas Turbine is increased to more than 75% of rated load, the stability keeps getting better. At rated load (20MW) the drum level is very stable and close to the setpoint.

There have been several responses discussing the tuning at various loads. I asked around to see what advice we might have to offer. Emerson's Jack Tippett, a variability management consultant noted that it is critical to know your process dynamics. His point:

If you don't know the process dynamics, control tuning is an art not a science and good control performance is an accident not a certainty.

Once you know your process dynamics, it is important to design your strategy to assist in achieving the process objectives in light of those dynamics. Jack noted a similar situation from his past where he tuned the levels in a 450-megawatt heat recovery steam generator (HRSG) system.

There were six boilers including two lines with high, medium and low-pressure drums. This power producer was unable to achieve a station ramp rate of 25 MW per minute necessary for automatic generation control (AGC) due to serious swings in the drum levels.

After measuring and determining the process dynamics, the process was re-tuned and they were able to achieve the ramp rate and achieve good level control at less than 70% load.

Jack also noted that they chose a single-element control strategy for the following reasons:

1. Feedwater flow control requires a working flow meter: the sense lines for the flow transmitter were outside and were subject to freezing. The Fisher valve had a DVC positioner and AMS software to monitor incipient valve non-linearities (which are the main reason for the second element.)
2. The open loop dynamics (changing the feedwater valve position manually and watching the response to level) on all six boilers showed very small dead times (1 to 6 seconds). This meant that the proportional-integral (PI) level tuning could be very aggressive. As a result, there was no value in the third element (steam flow feed forward)--the level control could be fast enough to respond the changes in level due to steam demand changes. The real need for the feed forward from steam is when the level dynamics are very slow (30 - 90 seconds dead time) so that the feedwater flow can anticipate the long-term level changes (due to steam demand) in spite of the shrink/swell effect.

By having good measurement in the flow, valve position, and valve characteristics and good understanding of the process dynamics across its operating range, Jack and the plant engineers were able to successfully implement a simple single-element control strategy.

Process manufacturers continue to seek ways to improve their energy efficiency, due to the high cost of energy. Corrosion and solids deposition in boilers, condensers, and steam turbines reduce the efficiency of this equipment and increase energy usage. This can also lead to unscheduled downtime if the conditions persist long enough to cause equipment failure.

One important way to minimize corrosion and the formation of solid particles is to have ongoing, accurate and reliable pH control in the boiler water, boiler feedwater and steam condensate, and main steam (carryover.)

The challenge is that these applications are often very low in conductivity. This is a challenge for continuous pH measurement due to the unavoidable formation of liquid junction potentials in the reference sensor. These cause offsets and instability in the pH measurement.

Emerson's Brian LaBelle, a power industry manager for Rosemount Analytical liquid analytical devices, explained these junction potentials are caused by spontaneous migration of ions from more concentrated to more dilute solution within a pH sensor electrode. What happens is a charge separation occurs among the various ions present. (At the word "ion", my mind raced back to those repressed memories of college chemistry lectures...)

Sometimes a severe junction potential occurs when there is an imbalance of negatively and positively charged ions across the liquid junction found in the basic reference electrode. The lower the porosity of the junction, the greater is the charge separation across this junction.

Sounds like we've gone a long way from the original problem of keep the equipment from corroding and being gummed up with solid particles.

Brian brought me to the solution by explaining that the technology team came up with the solution of replacing the diffusion junction with an open capillary (that's a hole for most of us.) Actually, this is not new or innovative, but what is innovative is that precise, laser drilling on a micro-scale of tens of microns is far more precise than what can be achieved with a twisting, mechanical bit. To minimize the junction potentials and provide more accurate measurement, the optimum capillary is laser-drilled at 25 microns in diameter. This capillary is also tapered outward to the outlet filter to help avoid clogging.

As we depart the micro world of ions and laser holes and return to our world of boilers, condensers, and steam turbines, the pH measurement with the Rosemount Analytical 3200HP pH sensor provides more accurate and reliable continuous measurement to ward off corrosion and solids formation. This means more reliable, efficient operations for this energy-consuming equipment.

Recently, a North American chemical manufacturer was having problems with their boilers tripping during startup and shutdown sequences. This problem was caused by a wide variation in the process' demand for steam. This situation caused lost production, which affected the overall plant efficiency.

Jim Dunbar, an Emerson variability management consultant was called in to provide emergency tuning services, to set the loops on the boilers to be able to handle the range in steam demand.

Jim's mission was to work with 2 boilers and about 10 loops controlling these boilers to resolve the situation.

The problem began when the plant installed a new steam-driven compressor that required a minimum steam pressure for operation. The team installed a backpressure controller to satisfy the steam requirements of the compressor. However, the boiler still had to ramp up very quickly to maintain the plant steam header pressure on process unit shutdowns. When the boiler firing-rate was increased too rapidly, the boiler would trip due to low feedwater level.

Jim worked with the plant staff to perform open loop bump tests on the feedwater flow and drum-level control loops. This data was collected in the PI historian and analyzed with the EnTech Tuner. Lambda tuning constants were calculated resulting in much faster and stable drum level control. Next, the boiler master controls were tuned to coordinate the speed of response with the level control. It was important that the firing response was fast enough to meet the requirements of the steam header, but not so fast as to cause an unrecoverable upset to the drum level resulting in a boiler trip.

Since his visit to the site, the manufacturer has not had a boiler trip in over four weeks, despite numerous simultaneous unit shutdowns.

Beyond the improved reliability of the process, Jim provided the operations staff some key insights on what to watch for if instability creeps back into the process.

You might think because I work for Emerson, that I know all the developments going on. Far from it... I try to create this illusion by subscribing to the personalized RSS search over at MyEmerson News, in addition to my RSS subscriptions to the growing number of bloggers in our world of process automation.

The news blurb said:

Vortex technology has traditionally been preferred for measuring flow in saturated steam applications, but users also want a compensated mass flow output. Emerson's new Rosemount MultiVariable Vortex Flowmeter combines the benefits of proven Rosemount vortex technology with a temperature-compensated mass flow output directly from the meter. Besides reducing process variability, the new flowmeter lowers total installed cost of temperature-compensated measurement points by 25%.

Eric described how a temperature compensated mass flow of a vortex meter for saturated steam typically required external sensors and a flow computer to do the calculations. This new multivariable flowmeter includes everything necessary to do the calculations within the flowmeter and send it back to the automation system via HART digital communications, pulse output, or conventional analog 4-20mA signals.

By eliminating these separate components the cost of installation and ongoing maintenance is reduced. Eric calculates the installation cost savings by what is eliminated from externally compensated saturated steam measurements. These include the thermowell, temperature sensor, temperature transmitter, wiring, commissioning, and either separate flow computer or calculations in the automation system.

On the maintenance front, the technology team did something unique by designing a non-wetted temperature sensor in the flowmeter which can be replaced without shutting the process down--always a good thing for plants seeking maximum manufacturing efficiency.

Trying to manage energy consumption and steam usage in a manufacturing process can be a tricky undertaking. The need to do it is ever increasing with higher fuel costs. A recent AEI Environment Policy Outlook study shows the gas and oil price trends over the past 25 years.

The variables operations staff typically must juggle include process load requirements, multiple fuel types, boiler/turbine availability and efficiency levels, and electric buy/sell prices to name a few. Of course, steady state operations are rarely possible because product mix and volumes being produced are normally in flux.

You may recall Bob Sabin, a consultant in Emerson's Industrial Energy Solutions organization, from an earlier post on Chemical Recovery Boilers. Bob discussed how the team of energy consultants works with process manufacturers to develop facility specific models and rule sets to continually determine the optimum operating setpoints for all the process units.

They have packaged their approach into a SmartProcess Energy application that is used to reduce the total cost of energy in a mill/plant by automating critical decision-making. The energy optimization process begins with a review of existing Powerhouse operations and recent operating data. The consultants use off-line modeling tools to evaluate improved operating methods and estimate the level of savings that can be achieved. The effort reviews the fuel alternatives, purchased versus produced power options and constraints, and the current decision making process for optimizing energy and steam production and usage.

Bob said that a key to Emerson's energy optimization approach is extensive data validation to help the application tolerate measurement errors and device failures. The decision making rules for optimum operation are implemented using mathematical models running within the automation system controller.

He pointed to two areas of savings. The first is identifying large opportunities for cost improvement such as changes in fuel type usage. Perhaps more important is the second area, which is the constant small adjustments being made to process setpoints in real-time. This helps move the total operation to its absolute best cost point based on current constraints. These are adjustments that could not easily be recognized by the operators.

The Industrial Energy Solutions team has documented typical annual savings of $500K to $2MM USD where the SmartProcess Energy application has been applied.

As process manufacturers grapple with high fuel costs to create the steam for their processes, they often look to increase the use of biomass and alternate fuels in their boilers.

The key measurement is typically the cost per pound of steam. This can be reduced by maximizing the use of cheaper fuels like wood, stoker coal, and other forms of biomass while minimizing the use of natural gas and oil.

I spoke with Chip Rennie in Emerson's Industrial Energy Solutions organization on the control challenges of operating boilers when running non-fossil fuels. These fuels can vary in moisture, consistency of particle size, BTU content, combustion air requirements, and boiler emissions performance limits.

From Chip and the consulting team, well operating multi-fuel boilers can often generate 90% of the plant's steam, operate in automatic control over 95% of the time, minimize carbon in ash, and maintain emissions to specified levels.

Chip stresses the key to optimizing the operation of these boilers begins with an assessment of the mechanical components and instruments. Optimum business results cannot be achieved if these underlying components greatly limit performance. Examples of issues to be resolved include include fuel conveyor changes, fuel bins and distribution equipment, overfire or undergrate air system modifications, fan upgrades, or damper improvements.

Chip and his team have bundled their expertise on multi-fuel boilers into a SmartProcess application and call it SmartProcess Boiler. This application provides complete automatic control of the boiler at all times including start-up, automatically adjusts for changing fuel BTU per volume, and the system allows a multi-fuel boiler to be used as a swing boiler while burning least cost fuels.

The application automates many functions that are often done manually and allows a higher percentage of steam to be generated with biomass or alternate fuels.

Projects are typically done as a turnkey including design, installation, commissioning, start-up and training of the operations staff to run the boiler using the newly optimized equipment, firing methods, and control tools. Given the high costs of fossil fuels today, payback on the entire project is typically 3 to 6 months.