Energy Management

A recent Wall Street Journal article, U.S. Expects Steady Climb in Energy Prices opens:

Energy prices are undergoing a long, slow march higher as major economies shake off the effects of last year's recession, the U.S. Energy Information Administration said Tuesday in its monthly outlook.

This outlook has many process manufacturers in energy-intensive industries again looking for opportunities to increase their energy efficiency. Emerson's Dr. Douglas C. White has written a great article, Save Energy through Automation, in the January 2010 edition of AIChE's Chemical Engineering Progress magazine.

Doug takes a reference Olefin plant with a naphtha feed that produces 500K tons/year of ethylene, total energy usage of 30MMBtu/ton ethylene, and total steam usage of 11MMBtu/ton ethylene. You can see the other process parameters on page 2 of the article.

He provides very specific energy saving examples and business result quantification based on the reference plant. I'll highlight only a few specific examples but you'll want to read the full 8-page article if energy efficiency improvements are part of your 2010 plans. Doug notes:

Advanced control and optimization systems can have a large impact on energy usage. However, their general functionality and energy impacts have been covered previously [Nasi, M. et al Experience with ethylene plant computer control, Hydrocarbon Processing, V62, N6, June, 1983, p. 74] and will not be discussed further here.

It's important to make sure the key plant variables are being measured accurately, "in terms of location, frequency, accuracy, and number." Deadtime can be introduced if the measurement device is physically located some distance away from a more appropriate location. Doug shares that this deadtime reduction can have a greater impact on loop performance than any tuning or algorithm change.

Many petrochemical plants measure fuel gas by volume instead of mass and density. If a plant has variations in fuel gas composition, flowmeters which measure mass and gas density will reduce the variability in cracking furnace combustion control. He cites an example naphtha plant:

...this improvement might be 0.2% in furnace efficiency, which is worth approximately $200,000/yr...

Market conditions, feedstock availability, furnace decoking, and process equipment availability impacts the load/throughput at which a plant operates. Effective anti-surge control on the cracked gas and refrigeration compressors is important since these units are major energy consumers within the plant. Doug writes:

The recycle valve needs to open very quickly and accurately to recirculate gas from the stage discharge to the suction. The ability to stably and safely operate the compressor closer to the surge limit saves energy, and the required operating constraint margin depends on the response characteristics of the anti-surge valve.

These anti-surge recycle valves can go from open to close and close to open in under two seconds. Doug quantifies:

If the plant is in low-throughput conditions 25% of the time, the value of the reduced recycle would be $125,000/yr for the reference plant.

Other energy saving examples Doug describes include stack gas CO measurements for improved combustion efficiency, key control loop dynamic analysis and tuning, and energy management and information systems (EMIS).

He closes the article with the importance of having a, "...structured program to assess, implement, and sustain energy savings achieved through automation..." This includes and energy study block diagram showing this structured approach to identify the top priorities.

There is a wealth of wisdom of practical ways that you can reduce the energy consumption of your process operations. Give the article a read if this imperative is part of your 2010 plans.

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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!

Reconciling Mass and Energy Balances in an Ethylene Complex is the name of a presentation recently given by Emerson's Patrick Truesdale. The venue was the 2009 AIChE annual meeting in Nashville, Tennessee. Patrick is a senior consultant on the Industry Solutions team and has a wealth of experience in the refining and petrochemical industries.

Patrick began his presentation by identifying some of the challenges ethylene producers face, especially in mature plants found in North America, Latin America, and Europe. Plants (brownfield) built decades ago were typically sized around 300 KTA (kilo tons per annum). Today's newer, greenfield plants found mostly in the Asia Pacific, Middle East, and Africa world areas are typically larger than 1000 KTA.

With the run up in energy prices over the last several years, the older, brownfield plants were not instrumented with mass measurements to do mass and energy balances. Ethylene plants have also been focusing their capital expenditures to meet higher quality specifications, increase capacity, address new regulatory compliance, and process cheaper feedstocks. For many ethylene producers, the plant staff has been stretched and unable to focus on improving energy efficiency.

Patrick described one of the common key performance indicators (KPIs), loss opportunities. He defined the gain/loss as open inventory plus receipts minus shipments minus closing inventory. Receipts include the fuel consumed in the production process and shipments include the fuel produced by the process. These gains and losses can be accountable and unaccountable. Examples of accountable losses include what is flared and coke produced. Examples of unaccountable losses include leaks and theft.

Process energy usage is the largest controllable cost in most ethylene plants and requires a focused effort to improve this gain/loss KPI. Patrick outlined a process that begins with defining the process boundaries. It starts with the feeds, steam, and fuel gas to the fired heater as well as the distillation tower feeds, tops, and bottoms. Next, look at the cracked gas compressor turbo machinery, cryogenic distillation, and hydrogenation reactor. Temperature and pressure measurements around these boundaries provide the inputs for mass and energy balance calculations.

The second step is to identify custody transfer boundaries, which includes the raw material production and supply at the load port, the unload port at the ethylene complex, the load port for ethylene at the complex, and finally the unload port at the customer site. The bill of lading (BOL) combined with the custody transfer metering equipment measure transportation losses from each load to unload handoff.

The third step is to design mass and energy balances to account for losses and consumption in the production process. This includes measurements at the inventory holding tanks, tank-to-tank transfers, tank to unit transfers, and process nodes, as well as incoming receipts and outgoing shipments. Also, measurements need to be in place for any intercompany transfers of materials and energy.

The fourth is to survey the existing measurement systems. From Patrick's experience KPIs associated with mass loss are directly based on the quality of instrumentation and procedures: poor results--1.5-2.5% mass losses, average results--0.7-1.5% mass losses, good results--less than 0.5% mass losses, and pacesetters--less than 0.2% mass losses. Patrick notes there are a wide variety of flow measurement technologies from which to choose including Coriolis, differential pressure, magmeter, positive displacement, turbine, ultrasonic, and vortex. They each have strengths and weaknesses with respect to pressure drop, accuracy, required maintenance, slurry flow tolerance, viscosity tolerance, fluid conductivity, and process intrusiveness. In slides 18-22, Patrick provides some selection considerations.

Once the measurements are in place, the fifth step is to develop mass and energy balance models. Measurements should be validated, with errors detected and corrected to fix gross and bias errors. Random errors are reconciled through a simultaneous solution of the equations for:

• flows, inventories, and material transfers mass and volume balancing
• flows, inventories simple and multi-phase component balancing
• enthalpy, power, heat exchanger, and steam energy balancing

Patrick's final step is to define the business process to identify KPI reporting, the KPI dashboard, and the processes to implement continuous improvement. Having the metrics for when the plant is both operating smoothly and having problems helps provide the feedback to solve the operational issues more quickly and return to more energy efficient, smooth operations.

The KPIs for optimized energy usage and loss reduction are interrelated and the need to address grows with global competitive pressures, higher energy costs, and increasing regulations.

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Last week I was on the phone with Emerson's Bob Sabin, a consulting engineer on the Industrial Energy Solutions team. You may recall Bob from some earlier energy efficiency-related posts. As I'm prone to do this time year after our annual Emerson Exchange meeting, I asked Bob if he did an Emerson Exchange presentation. He did in fact present, A Structured Optimization Plan for Leveraging Control Technology to Reduce Energy Costs and Improve Overall Plant/Mill Profitability.

Bob discussed the increasing focus on energy due to its cost and increasing emissions regulatory climate across the globe. It's a case where greater energy efficiency is both the "green" thing to do by reducing emissions and it lowers operational costs by reducing one of the largest controllable costs. Energy usage improvement is an aspect of overall production optimization and savings go directly to the bottom line.

Bob cited an ARC Advisory Group study, Best Practices in Energy Management, which categorizes leaders, competitors, and followers in the reduction of energy usage. Half of the leaders reduced energy consumption by 10-15% each year, while over half the followers made no progress or did not know if they had made any progress.

He outlined a typical site energy-flow perspective, beginning with the sources of energy: purchased steam, purchased fuel, raw materials consumed as fuel, and purchased power. The fuel and raw material fuel are converted to steam and electrical power and consumed by the process in steam and electric drives, process heating and cooling, fired equipment such as fired heaters and dehydration units, and direct-fueled equipment and processes. The site may also export steam, fuel and power. Bob and the consulting team work with process manufacturers to assess these areas for ways to minimize (energy inputs), improve efficiency, optimize, and maximize (energy outputs).

Bob described the energy improvement process that begins with survey and measurement, followed by actions to fix field devices and loops, followed by equipment repair, followed by unit process optimization, followed by site coordination to drive the entire operation to the best cost point within constraints. Although the process is never ending, the savings are cumulative with each pass through the improvement cycle.

In the survey and measurement phase where measurements don't currently exist, Bob recommends considering wireless devices to monitor steam flows, condensate returns, water and warm water usage, air flows, and air pressures. Wireless measurements can be implemented at a fraction of the cost of traditional wired devices. The survey and measurement phase is where benchmarks are established to monitor performance over time and compare current operations with known industry standards to establish the economic case to justify investment.

Many plants have opportunities to fix leaks, maintain steam traps and improve insulation on their steam, air, and water systems. Other areas to fix the basics include measurement device calibration and final control element inspection for linearity and repeatability. These loops are often in manual when the devices are not performing correctly. Variable frequency drives for fans, pumps, and other cyclical load devices can be more efficient than processes with recirculation loops and throttled flow.

Once these basics are addressed in a bottom up approach and the process is returned to automatic control, units can be optimized. The highest benefit is typically only sustainable if a holistic approach is taken starting with the basics. Bob recommends a "single knob" strategy where a single operator input establishes the process rate. It incorporates equipment and process constraints, coordinated rate/load changes, and bumpless, balanceless manual/auto transfer. The regulatory control can then be enhanced with advanced process control that incorporates process specific techniques and expertise. To gain the desired improvements in energy efficiency, the design targets the process controls to be in automatic mode more than 95% of the time.

Bob gives examples of simple utility operations with and without multiple fuel sources to more complex operations. No matter the complexity, the road to lower emissions and lower energy usage begins by measuring it, fixing it from the bottom up, getting on automatic control, incorporating process expertise into the control strategies, and layering models for area/site optimization. It's also the way to move profitably from follower to leader.

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Emerson's Joel Lemke presented You Can't Manage What You Don't Measure: Getting a Handle on Plant Energy Usage at the 2009 Emerson Exchange. The presentation's abstract is:

User cases will be presented demonstrating how new flow metering installations enabled users to reduce their overall cost of steam, compressed air and other utilities. Until meters are in place, it is impossible to prioritize improvement projects or quantify benefits of existing improvement projects. A metering system should be easy to install and inexpensive to operate to ensure net benefits.

Energy costs remain a large part of operating a plant for many process manufacturers. Joel notes that knowledge is required of the utility fluids of where the energy is flowing and how much is consumed. It needs to be granular to know who is using what at a sub-unit level. Good measurement is required to get the information to make the decisions required to optimize energy usage.

Joel showed a steam system showing three boilers feeding a steam header connected to multiple units throughout the process. This pulp and paper mill began to apply a concerted, energy reduction program when oil exceeded $100 (USD) per barrel. The goal was to compare their usage to industry benchmarks in steam, compressed air, process water, and electricity.

The quality of the installation of differential pressure (DP) flow measurement is key to the accuracy and ongoing reliability of this flow measurement. He shared some best practices. The first is ways to eliminate impulse lines. Consider direct mount installations, which eliminates inaccuracies, provides consistent installations, reduces complexity, reduces leak points, and ends leak testing. Leaks are wastes in energy, put personnel at risks, and increase maintenance costs to troubleshoot and repair.

A new best practice, Joel mentions is to mount the DP meter above the pipe as long as the steam is below 400 degF. There is no imbalance between the upstream and downstream side of the pressure measurements across the orifice.

Another energy saving area is to minimize pressure lost from leaks. By auditing the compressed air systems to eliminate leaks, you can reduce compressor horsepower requirements from the source pressure to the pressure at the destination. Annualize over a year, this can result in large energy savings.

Joel discussed self-organizing wireless networks. The cost per point using wireless was much lower because of the lower installation costs. The mill has added temperature measurement in addition to the DP flow measurement. The WirelessHART measurements enabled much more complete monitoring of plant utilities for the given budget.

I managed to get my hands on a great paper, Olefin Plant Energy Savings through Enhanced Automation, written by Emerson's Dr. Douglas C. White, whom you may recall from earlier posts. Doug is a principal consultant who leads the Process Improvement and Optimization Consulting team.

He presented this paper at the AIChE Spring National Meeting as part of the Ethylene Plant Technology - Energy Consumption and Optimization track. The abstract:

Energy is the single largest controllable cost for olefin plants and the recent rise in prices has caused most plants to look even more closely at their usage. Automation and advanced automation can significantly reduce usage across all areas of the plant. Some of these savings can be achieved with no investment, only changes in normal operating procedures. In other cases improvements to on-line analyses, measurements and control action are justified but generally require relatively modest investments. The management of the utilities at a major olefin site can be difficult with many daily operating decisions that must balance competing economic and production issues. Real time modeling of process and utility equipment and monitoring of the energy usage in plants permits allocation decisions to be made much more frequently and accurately, often resulting in substantial savings.

Doug describes the economics that Olefin producers face:

Olefin plants are large energy consumers with energy the largest variable operating cost after feedstocks. Using energy efficiently has been and remains a primary goal for olefin producers.

Natural gas is the marginal fuel consumed and its price has been a source of volatility over the past several years. Doug describes surveys where there is at least a 40% spread in energy usage between the most and least efficient plants. The source of this variation is due to the age and efficiency of the equipment and the heat integration.

Doug provides an energy investment opportunity matrix of high, medium, and low potential energy savings versus capital cost/time to implement. An example of a potentially high energy saving opportunity, but coming at a high capital cost is and integrated turbine. At the other end (low savings / low investment) are things like increased insulation and heat exchanger maintenance.

He describes two ways to reduce energy costs--either by reducing supply costs or reducing process energy demand. On the supply-cost side, the focus is to increase internal utility production efficiency and reduce external purchase costs. Advanced control and optimization on the furnaces, quench/fractionators, compressors, and distillation columns are a few examples cited on the process energy demand reduction side.

The paper describes areas to find energy savings. These include: control loop performance improvements, more accurate measurement of process variables, measurement additions via WirelessHART technology, valve performance improvements to handle the various olefin plant load conditions, loop dynamic analysis and tuning, and steam system management and control. The paper provides further thoughts in each of these areas.

Doug recommends developing an automation energy savings program and beginning with a full assessment of current operating conditions. This not only helps with the justification, but also provides the benchmark to compare improvements against to provide return on investment. He counsels that a part of this assessment is to identify the control and advanced control loops that have a major impact on energy usage. He has another matrix of energy loss consequences versus historical frequency for monitoring and maintenance. This analysis helps prioritize financial impact and focus the justification efforts.

Whether or not you're an Olefins producer, you'll gain some insight in how to find and plan a path to energy savings.

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For many industrial plants and mills, energy costs can be 10 to 20% of their overall business costs. Given these significant costs, leaders in the industrial process industries establish and maintain continuous energy optimization programs to minimize energy cost impact. According to an ARC Report, Best Practices for Energy Management:

Energy can be the largest component of a manufacturer's cost structure. Despite a recent drop in energy prices, costs are still trending upward over the long term...

I caught up with Emerson's Bob Sabin, whom you may recall from earlier posts. Bob is an industrial energy consulting engineer who helps process manufacturers establish this continuous improvement process. It starts and carries on with measuring how much energy is being purchased, produced, and used throughout the plant/mill site. It's important to establish a baseline for steam, electricity, fresh water, air, and process water usage. The perspective should be how much is being consumed by each site area/process. As time goes on, the baseline can be monitored for changes due to equipment issues, energy use can be compared to known industry benchmarks, and projects to improve energy performance can be justified with hard data.

After the survey and measurement phase, it's important to complete basic tasks such as fixing steam devices, maintaining measurement and final control devices, and addressing control loops that contribute to process variability. This variability directly correlates with higher energy consumption. From there, owners are in position to move on to unit process energy optimization and unit coordination for energy savings.

Often key measurements required to monitor energy consumption are not in place because of capital cost barriers. These barriers have been made higher in the past due to the difficulties in running cable infrastructure to the wired instruments. Bob shared how some industrial manufacturers are using WirelessHART measurement devices to significantly reduce the capital cost barriers associated with installation. Bob noted that energy measurement projects today could be completed at one-third the cost as compared to traditional implementations.

He shared an example where one mill added about 70 wireless transmitters measuring steam flows, condensate returns, water and warm water flows, airflows, and air pressures. Given the old adage, "You can't control what you can't measure", these measurements helped identify inefficiencies in the process and give a true energy usage picture to properly assign the costs. Having this energy monitoring information can also help make better profitability decisions by helping to determine product or grade costs during peak and off-peak hours.

Bob described a case where the site's steam use had spiked at a heat exchanger during a condensate flood. This helped the operations team more quickly resolve the situation and save considerable energy waste. Another example is how these wireless measuring devices helped spot air, steam, and water leaks that were not being quickly noticed during maintenance rounds.

I got fired up when Bob closed his thoughts to me with a Vince Lombardi quote, "If you don't keep score [measure], you're only practicing." Game, on!

Update: Podcast added.

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Last week at the ISA Expo in Houston, I sat in on a great session featuring Emerson's Ed Bailey, as well as folks from Siemens, Ametek and a private consultant with years of experience with Dow Corning. The session was entitled, Energy Management Issues for Process Optimization, and it had the following description:

Subjects open for discussion in this session include nearly anything relevant to this topic, not just process control and instrumentation. Expect discussions regarding process maintenance, process modifications, maybe whole new processes that were less cost effective under the old energy cost structure but now are more cost effective.

Ed leads the technology development efforts for the Rosemount Analytical Gas measurement products. He kicked off the panel discussion showing the forecasted growth of energy production. From an ExxonMobil outlook study, most of the world's growing energy needs will continue to be met by the combustion of oil, gas, and coal.

To help manage the carbon emissions, to deal with the increases in fuel costs over their historical averages, and to operate in an environment with increasing governmental regulations, process manufacturers have an ever-increasing need for improved combustion flue gas analysis. The best way to minimize carbon dioxide (CO₂) emissions is to operate existing combustion processes at their maximum efficiency.

Ed described some of the existing industry practices like averaging the output of a few analyzers as not providing enough insight to diagnose and optimize the burners. Burner differences and stratification are normal conditions that this averaging strategy does not well address. Instead, Ed recommended a mix of oxygen (O₂) and carbon monoxide (CO) measurements be used combined with neural network strategies that enable more complex models to be created to maximize efficiency versus the load/fuel variations--and to minimize mono-nitrogen oxide compounds (NO_x). The key point is that more discrete measurement points, which in turn feed more sophisticated control algorithms, will drive efficiency.

One of the discussion points during the session was the use of zirconium oxide (ZrO₂) oxygen analyzers to measure the residual oxygen remaining in the flue gases from any combustion process. Ed mentioned the Rosemount Analytical in-situ oxygen transmitter as an example of a zirconium oxide oxygen analyzer to help provide data to better control and optimize the combustion process.

An interesting question came into the panel about the safety considerations of running the combustion process right on the edge at its most efficient but potentially dangerous point. The panel had good thoughts that you need to separate the control aspects from the safety instrumented system burner management aspects. Like any process with safety risks, a risk analysis and risk mitigation strategy per the IEC 61511 international safety standard is critical.

MP3 | iTunes | My Podcast Alley feed! {pca-d211b332524855a78944048f9c70f6e7}

I've been catching up on some of my automation and industry RSS feeds, and saw an interesting post, Energy Costs: Why is Industry So Slooooooow to React?, from the Energy Pathfinder blog.

The post describes process manufacturers struggling with high energy costs. They tend to pursue lower energy prices first, but cutting waste is a much slower process. The fourth bullet point caught my attention:

To make energy improvements, a facility must accommodate change. Meaningful energy solutions require some combination of changes to technology, procedures, and practices. Change poses challenges--even threats--to people whose livelihood is connected to long-standing procedures and priorities. Change requires front line energy managers to practice a certain amount of salesmanship. Sadly, this kind of communication is often not the strength of most powerhouse superintendents or maintenance directors. Many good energy-saving proposals never get off the ground for this reason.

I sent a link to the article to Emerson's Bob Sabin, whom you may recall from earlier posts. Bob is an energy-management consulting engineer and I wanted to see if his experiences were similar or different.

Bob wrote back:

It is curious why North American industry has been slow to react to energy costs, but then we have seen the same deliberate, measured response to other competitive pressures. Energy improvement projects compete with all other potential maintenance or improvement projects for the scarce capital dollar.

The way many organizations are structured, it does typically take a person acting as a project champion to raise an energy improvement idea for consideration. It takes a lot of effort to deliver the documentation regarding payback, to convince business management that there is low risk, and then to work with line operations to convince them that the project is in their interest, also. These champions most often emerge from operations or engineering middle management.

Unfortunately, middle management in many plants/mills suffers from existing day-to-day challenges and the lack of resources and training. They are often not in a position to make necessary changes to entrenched work processes. We see this every day in the instrumentation and control business.

With PCs on every desk, handhelds by the dozens, the Internet, wireless, and other technologies, a large percentage of plants/mills still struggle with basic process measurement and automatic control. There is still quite a bit of opportunity to apply basic process control technology to reduce energy consumption and improve other production performance measures.

The potential savings from lower energy costs can help place focus on education, leadership, and training which in turn will improve energy performance and other business metrics.

I agree with Bob's assessment that progress begins with economic justification and the focus of an organizational champion to drive the process forward. With many North American facilities designed in an era of inexpensive energy, folks like Bob can work with plants and mills to develop the justification to make their production process more energy efficient.

As reported by the Automation Gear blog, a big breakthrough has come to Micro Motion Coriolis flow meters. They can now be powered with two wires. These same wires carry the process variable and digitally communicate other process variables back to the process automation system via HART.

I did some reading and learned that that ultra-low power technology in the transmitter coupled with an optimized Coriolis sensor design made it possible to power these flow and density meters on a 4-20mA HART signal. Process manufacturers should continue use the 4-wire design for the real demanding applications like fiscal metering and custody transfer, meter verification and ones with entrained air.

Outside of these demanding applications, many mass flow, volume flow, density and temperature applications are well suited for the 2-wire Coriolis meter.

I caught up with Tom O'Banion, who leads the chemical industry efforts in Emerson's Micro Motion division. He noted that Coriolis technology has increasingly been used to measure liquids and gases because of its accuracy and reliability compared with other flow measurement technologies.

With units typically spread over great distances, installation costs have been one limiting factor in the use of Coriolis technology. Tom noted one refiner's estimate of $15 per foot plus labor for the cost of pulling the additional power wires needed for the 4-wire transmitter. This can add up quickly in tank farm or hydrogen metering applications that are typically long distances from the rack room.

Many natural gas metering stations on individual units were installed when natural gas was inexpensive--$1/Mscf. With prices now closer to $8/Mscf, chemical manufacturers and refiners want to track natural gas usage much more closely to optimize their operating costs. A typical small ethylene cracker may consume $200-$300 million in natural gas per year. Instead of differential pressure across orifice plates or turbine meters, a two-wire Coriolis meter can more accurately measure natural gas consumption and provide the flow, density and temperature measurements via HART back to the automation system for tighter control.

Another application Tom mentioned is hydrogen metering. It is usually located along the perimeter of the refinery. It's very expensive and quite difficult to measure with conventional technologies. Using the existing wiring, the 2-wire Coriolis meter provides more accuracy and less maintenance.

Tom also noted that installation costs with the additional wires sometimes prevented the use of Coriolis technology in applications for which it was better suited--especially if the analysis had been based on installed costs rather than lifecycle costs (which favors Coriolis technology with no moving parts.) The two-wire version shrinks the installed cost difference.

It's great that technology continues to advance to create more opportunities to optimize and save energy. I'll continue to pass along applications as I come across them.

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.

Let's close the week with a short post about energy saving opportunities. The pain of higher energy costs is fresh on my mind with an unexpected trip by car from Austin to Houston and back with gasoline prices now just shy of $4/gallon USD.

Back in May, I wrote about an AIChE paper Emerson's Doug White presented, How to Save Energy through Advanced Automation. 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.

If you didn't get a chance to hear Doug present this at the AIChE Spring meeting, or read the PDF of the presentation, you may have a chance to see him live in your area to get your energy-saving questions answered. He's teaming with Scott Pettigrew, an Emerson senior energy consultant.

This seminar series will begin in the Houston area, in La Porte, and will be jointly hosted by Emerson and its local business partner, Puffer Sweiven.

From the seminar flyer, here's what it covers:

Survey the root causes of excessive plant energy usage and how automation can reduce consumption. Review a systematic approach to identifying potentially high payback improvement areas and solutions. Opportunities can originate in the process, measurement devices, valves, or controllers. Learn basic principles and key concepts to understand the nature of challenges and options. Actual plant case studies will be presented. Specific operational improvements in the following areas due to enhanced automation performance will be addressed: reduced fuel costs, reduced electricity usage, reduced steam costs, increased equipment availability, reduced compressor costs, improved boiler efficiency.

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The date is August 21^st from 7:30 to 1pm U.S. Central time at the Puffer Sweiven La Porte office. Send an email to RSVP a spot.

Rumor has it that they'll be another session further East along the Gulf Coast, and possibly other locations. I'll update this post as I hear more.

If you have interest in your area, send me an email and I'll pass it on to Doug, Scott and the team.

I was catching up on some of my industry-based RSS feeds and came upon an Energy Pathfinder blog post, Taming Energy Costs While Going Green: An Open Letter to Corporate America. The blog's author, Christopher Russell, asks and answers:

Energy cost control... Green marketing... Can you be successful at both? The answer is "yes," but you should be prepared to manage both in a combined effort.

What caught my eye was his fourth point:

Harvest more value from your existing process control systems. Companies everywhere are relying on information systems to manage their core production processes. It's a small effort to amend those same systems to accommodate energy performance monitoring. Energy savings can increase the returns on existing control systems.

I ran this post by Emerson's Bob Sabin, an energy management specialist. You may recall Bob from earlier posts on boilers and energy management. With the rapid escalation in energy prices, you might imagine that the energy management team is pretty busy--and you'd be right.

I asked Bob for his thoughts on this fourth point, and he had a great response:

I believe it is true that many existing process control systems can be amended or enhanced to provide additional value in energy performance improvement. In the simplest case, the energy performance of most any process equipment can be closely monitored for efficiency of energy use. Trends of energy efficiency can be examined over time, and when degradation is seen, the root cause can be quickly identified and remedied. Monitoring of efficiency can be done locally at the plant/mill site, or it can be handled remotely by a central team or service provider.

In addition, processes can often be run with less variability such that they can be pushed nearer to their constraints. Being nearer to process constraints frequently brings the benefit of improved energy efficiency. Enhancing controls will drive reduced variability by allowing full automatic operation for a higher percentage of time and/or providing calculations that compensate for incoming variability.

Further, for sites that have complexity in operation that affects energy use, it can be beneficial to provide enhanced information systems capability that will support profitable operations decision making.

Often, energy needs, energy prices, and operating scenarios change so quickly and with so many permutations that it is virtually impossible for operations personnel to determine the single most profitable operating scenario at any given time. An Energy Management Information System (EMIS) can deliver this information in real time every day, all day.

An EMIS consists of a model of the processes involved that is automatically fed process data and gathers or takes user entered cost data. The EMIS model arrives at the most profitable operating scenario based on current production needs, actual costs in play, and the constraints that are in place for process operation. Emerson supports process manufacturers with various types of performance monitoring, variability reduction, and EMIS implementations.

As with most things we do, focus can produce results. In this case, energy savings can be achieved by leveraging and amending the existing process control and information systems. Depending on your plant or mill's energy consumption, it may be worth the development of models to compare actual operating conditions against the ideal case for optimum profitability.

Emerson's Mark Coughran has been busy sharing his process control expertise lately. His latest article, Improve Batch Reactor temperature control, appears in the June issue of Chemical Processing magazine.

Mark describes three batch reactor temperature control cases with split-range control configurations. The first case involves control valves to hot and cold headers on the reactor jacket. The second case involves control valves to steam and chilled-water heat exchangers and the final case involves a control valve on the chilled fluid and variable electric heater.

You'll see common advice in the posts where Mark is featured. In this article, he summarizes this advice into five recommended steps on how you should approach loop tuning:

1. Make the process dynamics as linear as possible.
2. Minimize dead time.
3. Measure the process dynamics.
4. Choose the right controller algorithm to compensate for the process dynamics.
5. Tune for the speed required, without oscillation.

Proper selection and sizing of control valves and minimizing non-linearities in control strategies such as dead zones in split-range control help to address the first point. For a batch reactor, the jacket heating and cooling responses may be very different. One way to mitigate this difference is to use a controller, which supports gain scheduling to provide separate tuning parameters for the cooling and heating steps.

Dead time (the time delay from an output change to a change in the process variable) can occur in the transport delay of heating/cooling media from the control valve into the jacket. Circulating pumps and jacket-temperature sensor location can help reduce this cause of dead time. Also, filters applied to the temperature transmitters will appear as dead time to the control loop. Mark counsels that you allow one overshoot on the jacket-temperature setpoint response to get the fastest linear response and to minimize dead time.

For measuring the process dynamics for integrating (those that ramp at various slopes on a change in output), processes like reactor temperatures are easily determined from step tests with the loop in manual mode. The proportional + integral + derivative (PID) controller compensates for these process dynamics. Proportional action is mainly used for integrating processes. Some derivative action may be needed on the reactor temperature controller but usually not for the jacket controller.

Mark recommends the Lambda tuning method to tune for the speed required without oscillation. Start with the jacket (slave) control loop first. It must be faster than the reactor (master) control loop per the rule of cascade tuning. For processes with significant nonlinearities, fuzzy logic control might work better.

As he concludes in the article, the benefits of getting this tuning right is improved product quality, reduced batch cycle time and reduced energy usage and waste.

I read the on-line version of the Wall Street Journal early each morning as I get my coffee fix. This morning there was an interesting article, Stung by Soaring Transport Costs, Factories Bring Jobs Home Again. It's about how the economics of manufacturing plant location around the world is quickly changing with the rapid spike in energy costs. From a U.S. shipping cost perspective:

...cost of shipping a standard, 40-foot container from Asia to the East Coast has already tripled since 2000 and will double again as oil prices head toward $200 a barrel...

The article quotes Emerson's Chief Operating Officer, Ed Monser:

...logistics costs, which include all the expenses associated with moving goods, became a worry about a year ago.

"That's when it became a dominant part of the discussion," he says, adding that oil then was less than $100 a barrel. "So with oil now at $130, it's even more serious." Mr. Monser says Emerson's larger strategy is to regionalize manufacturing, producing as much as possible within the part of the world where its sold.

Energy costs play a huge role in most process manufacturing industries. As I mentioned in a prior post on ways to save energy, there are things you can do to reduce your energy consumption and run your plant more efficiently. These are shorter-term solutions to help mitigate the pain of soaring energy costs.

Longer term, it may well mean more process manufacturing plants geographically dispersed where their manufactured products are sold. This trend has been going on for many years, but the spike in energy costs may accelerate it further and bring back manufacturing to regions where it departed.

This would mean that even more new plants added to the drawing board than are already in the works. It also means that we'll need a lot more smart minds joining the process automation and process manufacturing ranks. And for you boomers recently retired or soon to retire, it means that you can probably contract out your expertise until you're ready to fully "put your feet up."

It's all food for thought as we adjust personally and professionally to reality of these higher energy costs.

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.

High energy costs continue to prompt process manufacturers to seek ways to increase their energy efficiency. A colleague pointed a great post to me, The Seven Steps to Successful Industrial Energy Management, on the Energy Pathfinder blog.

My take away was that the culture for becoming more energy efficient starts at the top and developing metrics, incentives, and disincentives to change organizational behavior are keys to success.

I thought I'd share this post with Bob Sabin, a consultant in Emerson's Industrial Energy Solutions organization. You may recall Bob from earlier posts.

Bob believes improving the operation of the Industrial Powerhouse can be a large factor in improving overall energy management at process manufacturing sites. The carbon footprint of the powerhouse can be reduced, the reliability and responsiveness of the operation can be increased, and the cost of energy can be reduced--all at the same time.

With this focus (and not to be out done by the seven steps), Bob offers his ten steps to successful Industrial Powerhouse improvement:

1. Obtain top management commitment to improving the carbon footprint, reliability, and cost of operation of the Powerhouse.
2. Benchmark current operations in terms of efficiency, reliability, cost, and emissions.
3. Survey current process equipment, control technology, and operating methods. Create a matrix of factors that are impacting or limiting operating performance.
4. Examine potential process equipment repairs and upgrades that could deliver benefit, rank these in terms of return for investment, and complete repairs and upgrades that will deliver good immediate benefit.
5. Focus on process parameter measurement devices and actuators. Especially for combustion air and fuel flows, ensure that repeatable measurement and control capability exists.
6. Implement full automatic control that is robust and reliable. Even the best operating crews cannot optimize Powerhouse performance every minute of the day for every day of the year.
7. Install optimized control functionality as appropriate to optimize efficiency, prioritize lowest cost fuels, load equipment based on cost, and make economic operating decisions automatically.
8. Change Standard Operating Procedures for the Powerhouse to ensure that process units are run in automatic using the optimized control functions. Make focus of operations identifying and troubleshooting process issues rather than manual process operating adjustments.
9. Regularly benchmark operation in terms of efficiency, reliability, cost, and emissions, repeat steps above when results are not satisfactory.
10. Investigate and consider re-powering the industrial site with lower cost fuels and/or technologies.

Bob and the Industrial Energy Solutions consultants have helped process manufacturers achieve ongoing savings from improved energy efficiency by putting these steps into practice. If your energy costs are higher than they could be, give these ten steps a try or contact the industrial energy team for help.

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.

A great question came in on the Operating Fired Heaters More Efficiently and Reliably blog post:

Jim I work with natural draft heaters on a daily basis and have initiated several efficiency tests with improved burner internals. I am looking for an opportunity to optimize dual firetube treater by first off improving the combustion efficiency to 80% in each tube and then staggering the temperature controls so that one tube runs 90 to 100% of the time and the other tube only fire during high load requirements.

I sent the comment around our advanced automation consultants for any comments that they might have and I received a great reply from Lou Heavner whom you may recall from earlier posts. Lou describes how to approach optimizing these heaters:

Heater efficiency is calculated using heat loss or input/output method. Input/Output method is difficult because you have to account for lags and delays between fuel firing rate changes and the measurement of process heat absorption changes and in the specific case where there is incomplete phase change on the process side (e.g. partial vaporization) you cannot easily solve with reasonable instrumentation. The heat loss method measures heat loss in the flue gas and assumes any other losses are negligible and constant. If not, they need to be measured and added as well.

Heat loss requires knowledge of the supply air (and fuel) temperatures and the flue gas exhaust temperature as well as the composition of the fuel and flue gas, just like with a boiler. In perfect combustion, there would be no unburned fuel in the flue gas and no sensible heat losses. But due to practical considerations, there are sensible heat losses and to calculate them, you need to know the delta T between the exhaust and ambient and how much excess oxygen remains in the exhaust. Efficiency calculations made using this technique can be pretty accurate in a natural draft heater, but if there is air leakage after the combustion zone, tramp air will show up as lower efficiency due to increased O2. And there is usually an optimum cost operation where the trade-off between sensible heat losses and unburned fuel losses require some level of unburned or incompletely burned fuel leaving in the flue.

When you are ready to control, the goal is to minimize excess O2 while not allowing excessive fuel to go unconsumed. CO analyzers are often used to detect incompletely burned fuel and the goal is usually to keep it below 150 ppm or some lower target. O2 is controlled to stay as low as possible without exceeding the CO limit, which is usually 2% O2 or less for the fluegas.

You can do this with simple feedback control, but feed forward control can help do better. Information on fuel quality, if it varies, and process side temperatures and flows (the heater load demand) can be used to adjust the fuel and air for combustion to meet the heating demand at maximum efficiency. Fuel and air cross limits are often used to maintain fuel and air ratio without getting into a fuel rich condition in the firebox during load changes. But airflow is usually difficult to measure. Therefore, it is often inferred from damper position.

When evaluating an application, we would want to know what instrumentation already exists and what the process variability looks like. What efficiency are they currently obtaining? Then we would look at the control valves and any other contributors to variability to see if they warrant repair or replacement. We would similarly evaluate the instrumentation and analyzers to see if they need anything there.

Then we could evaluate the control strategy and performance and recommend reconfiguration or tuning as appropriate, which may include advanced process control (APC). The person evaluating the controls would have to weigh the cost against the improvement from better loop tuning, valve repair/replacement, CO analyzer, etc. to come up with the best solution. Dampers are often the weak link in fine control of a natural draft heater.

As my colleague Doug Simmers in Emerson's Rosemount Analytical business noted, "The commenter is probably correct with the strategy to fire one heater full out, and bring the second unit on only when needed. Running at full fire develops the best turbulence for fuel/air mixing, and the excess O2 can be kept lower." This is a load allocation problem when two heaters are firing simultaneously. If we can model heater efficiency for each heater as a function of load, then we could optimize the load allocation across both heaters when both must be fired. Actual testing would identify the models, uncover the best strategy, and verify or disprove this assumption."

He may also be interested in the efficiency calculator, developed by Doug's team.

Join the conversation and add a comment if you have experience to share.

In an earlier post about fired heater efficiency and reliability, I had spoken with Emerson operations consultant, Chris Forland, on the opportunities for refiners to optimize this energy intensive unit.

Working with engineers in the Rosemount Analytical Gas division, Chris has developed a spreadsheet with fired heater efficiency economic calculations which allows refiners to get a rough estimate of the potential value in applying efficiency solutions like the SmartProcess Heater Optimizer.

You can enter data in the cells with blue text for each fired heater in your plant to get a quick assessment. Chris has filled in typical values from a cross section of refineries in case you don't have exact data. This will let you get a feeling for the overall improvement opportunity and if there is enough return on investment to warrant a closer look.

If you have fired heater units in your manufacturing process, give this calculator a try and let us know what you think by adding a comment or contacting us.

A continuing theme to several of these blog posts is how process manufacturers are looking for ways to improve energy efficiency in these times of high energy costs. One way to do this is to optimize the steam required for a distillation process.

I caught up with Pete Sharpe whom you may recall from an earlier post on reducing costs of APC projects using pre-engineered applications. Pete has recently completed some work for a specialty chemical manufacturer that wanted to improve the performance of the distillation columns by decreasing the steam required and decreasing the reflux flows to the columns.

Pete worked with the process engineers to apply model predictive control (MPC) technology found in the SmartProcess Distillation Optimizer. This application is one of the pre-engineered SmartProcess applications Pete described in the earlier post.

The distillation process is a classic multivariable problem with control variables, manipulated variables and constraint variables.

Using model predictive control, the column can be controlled and operated as a unit instead of a collection of loops.

In addition to reduced operator load, the process engineer identified 400 lb/hour savings in steam on one of the columns and close to 900 lb/hr on the first column where the Distillation Optimizer application was implemented. With a cost for 135 psi steam of $5 per klb, this translates into energy savings of more than $50,000 USD for these particular columns. This savings adds up as all of the distillation columns on site are converted over from multi-loop control to MPC-based control. Steam reductions are a result of lower reflux flows that have been reduced by about 20%. While this change increases the average overhead impurities as is expected, it is well within specifications.

Now that the Distillation Optimizer has demonstrated stable results on two of the columns, Pete is working with the process engineers to implement it on the remaining columns over time. Beyond better performance and increased efficiency, the best measure of the success to date has been operators leaving the MPC control on more than 90% of the time. This is one of the true tests according to Pete and the Advanced Automation Services team.

We discussed improvement of multi-fuel boilers in an earlier post. Similarly, pulp and paper manufacturers often wrestle with chemical recovery boilers because of the complexity of the combustion process. This complexity is largely driven by the variability in the "fuel" (black liquor) and often by swings in production rate.

The variation in the BTU content of the incoming black liquor can cause difficulty in meeting the emissions restrictions, can lead to fouling of the boiler, may impact boiler efficiency, and can limit liquor throughput. Safety is also a major concern around a recovery boiler process.

Bob Sabin, a consultant in Emerson's Industrial Energy Solutions organization described the challenge as maximizing liquor throughput while minimizing the fouling of the upper boiler and maintaining optimal unit thermal efficiency. This can be done if the boiler combustion controls are configured to compensate for liquor BTU changes.

The process Bob and the team follow with pulp and paper manufacturers typically begins with an analysis where they measure the mills operating performance and compare it with world class performance. Some benchmarks include: maintaining excess oxygen at 1.5% to maximize unit efficiency, maximizing liquor throughput to either permit or steaming limits, minimize fouling to require one water wash per year, and running the recovery boiler in fully automatic mode more than 95% of the time.

Through this benchmarking process deficiencies and mechanical design limits can be identified and corrected. The economic benefits of process improvements can also be calculated.

Next a detailed field audit of valves, instrumentation, wiring, and control system performance is performed to find areas requiring attention.

With this assessment completed a complete cost estimate and return on investment calculation and justification can be developed to improve the performance of the recovery boiler. The expertise of the team has been packaged into a SmartProcess Recovery boiler solution which encompasses design, installation, commissioning, start-up, and operations personnel training.

Pulp and paper manufacturers typically experience project payback in three to six months through increased liquor throughput, better thermal efficiency, water wash reductions, and reduced variability in green liquor reduction.

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.

Building on my prior mentioned rising energy costs post, manufacturers are looking beyond optimizing their throughput, quality, and plant availability at how they can optimize the use of energy, since this directly impacts their bottom line.

Changing process conditions causes changes to the plant utility system which impacts: power demand, steam demand, fuel balance, emission targets, and the dynamics of the operation. Effectively managing utility system operations must consider the competing economic and production issues in a timely manner to improve the profitability of the production process.

I spoke with Peter Stanley, an Energy Management consultant in the Performance Monitoring and Optimization business unit of Emerson's Asset Optimization division. Steve and the team typically see opportunities for a 2-5% reduction in annual fuel bills by applying an Energy Management application to optimize the utility system. This can translate into as much as 25% of utility annual fuel spend.

The first step is to look at the major areas of energy usage. The first area is in the steam balance which is the steam required to provide heat across the site. Units may be importers or exporters of steam, and the amount of steam produced or consumed changes with throughput and operating mode.

The next area is power balance, again by looking at the importers and exporters of electricity. Many plants have on site generation in addition to what they purchase from the local utility, and can export excess power back to the utility grid.

Fuel balance looks at the mix of fuel gas and waste or by products which have little or no value. The objective is to consume in the lowest cost manner that raises the maximum energy for the process units.

Environmental constraints look at NOx and SOx levels and avoiding the maximum limits based upon the regulatory statutes and availability of emissions trading practices.

In addition to changing process conditions based upon what is being produced, the prices of fuel and power changes. Contractual arrangements for the import or export of electricity, fuel, or steam also impact the optimization.

A final area of consideration is the performance of the existing equipment including the boilers, gas & steam turbines, recovery steam generators, etc.

Building a solution with Emerson energy management experts and the AMS Optimizer, it is possible to continually deter the set of operating setpoints that will allow the utility operations to continually run at its economic optimum based upon all these factors and constraints.

Peter describes the approach where Emerson partners with its customers to deliver a guaranteed level of benefits typically within six months for a completed system. Payment for services and software is not due until the end of the project when the guaranteed level of benefits has been achieved.

Peter stressed that all projects have paybacks within 12 months and Internal Rate of Returns greater than 200%. Support of the optimizer solution is provided with a long term support contract.

It sounds like in an era of high energy costs and a solution with performance guarantees, that this is definitely an area to consider if your manufacturing process consumes lots of energy.

You don't have to look too hard to find news stories (here, here, here) of rising oil prices and their impact on process manufacturers around the globe.

Refineries and petrochemical manufacturing processes can especially require vast amounts of energy to process the feedstocks into intermediate or final products.

I spoke recently with Doug White, who leads our advanced automation services consultants for Emerson Process Management. Some of the folks I've written about like James, Eric, and Lou are senior consultants in Doug's organization.

Doug mentioned that one of the units at which refiners and petrochemical manufacturers should take a close look is the fired heater which provides the required heat for the distillation process. In many plants, these units were built 10-15 years ago or more. Most were built in times when natural gas was extremely inexpensive. There was little need for energy efficient designs--so even today they consume energy at higher rates than they could.

He sees these units as a quick way for manufacturers to save costs and improve their bottom lines.

Doug described these opportunities and gives very practical advice on how to get the project assessed, implemented, and sustained in an Oil & Gas Journal article entitled: Advanced automation technology reduces refinery energy costs. Some steps Doug recommends from the assessment phase:

1. Data gathering. Compile information about existing systems.
2. Interviews with plant staff. Find current energy-use problem areas, understand current operational procedures, and stimulate ideas on possible changes.
3. Evaluation of plant energy economics. Understand what are the major users and their costs of operation.

If you are one of the manufacturers struggling with higher energy costs, this article is well worth the read to develop a plan to reduce these high energy costs.

Update: Repaired broken hyperlinks.