Incomplete Combustion Burns Money
Those plant managers continuously seeking ways to increase profits could benefit by visiting the boiler house. (It's that building tucked near the back of the property with the big coal piles around it). Once there they need to ask one question: "What has been the average percentage of O2 in each boiler's stack over the past 24 hours?"Burning coal (or natural gas, fuel oil, wood, or gar...
Those plant managers continuously seeking ways to increase profits could benefit by visiting the boiler house. (It’s that building tucked near the back of the property with the big coal piles around it). Once there they need to ask one question: ‘What has been the average percentage of O 2 in each boiler’s stack over the past 24 hours?’
Burning coal (or natural gas, fuel oil, wood, or garbage) promotes a chemical chain reaction. When the fuel is heated to high enough temperature in the presence of air, the carbon in the coal combines with the oxygen in the air to form either carbon dioxide (CO2) or carbon monoxide (CO) gases. Which gas is formed depends on the quantity of oxygen present. The more CO present, the more incomplete the combustion and the less efficient the boiler is (see Typical Boiler Efficiency diagram).
Since the goal is to obtain as much CO 2 as possible, why not supply more air to the fuel as it is burning? Too much air supplies more oxygen than is actually needed to combine with the carbon resulting in excess oxygen. Not only does the excess oxygen play no part in combustion, it reduces boiler efficiency by absorbing heat that would otherwise be used to turn water into steam. Ideally the control system should supply the exact amount of air to ensure complete combustion of the coal. Unfortunately this is easier said than done. It turns out that combustion of coal is a complex physical and chemical process. Typically it takes about 17 pounds of air to burn one pound of coal, but impurities, moisture, ash handling, particle size, and numerous other factors can change combustion efficiency from minute to minute. That is one of the reasons most boilers operate with excess oxygen and why monitoring and controlling the amount of excess oxygen can dramatically influence operating cost and profits.
Small adjustment, huge savings
Jack Schilling, application consultant with Honeywell IAC (Fort Washington, Pa.) explains it like this, ‘The fuel savings between operating with 5% excess oxygen and 8% excess oxygen can be hundreds of thousands of dollars per year. For example, a natural gas fired boiler operating with 8% excess oxygen is usually about 76% efficient. Reducing the excess air to 5% improves the boiler efficiency to nearly 80%. To calculate the fuel savings divide 76% by 80% and subtract from 1.0. The result (5%) is the savings to be gained by reducing the excess oxygen.
A plant with an average hourly steam production demand of 250,000 lb/hr, a boiler heat pickup of 1,000 BTU/lb, and an assumed boiler efficiency of 76% requires about 2,880,000 MBTU/yr (M = 1,000) of fuel annually. If natural gas costs $2 per MBTU, the annual boiler fuel bill is approximately $5.7 million. A 5% fuel reduction would save about $280,000 per year.’
Being able to operate a boiler with lower excess oxygen requires more than posting a memo that boilers are to be operated at 5% excess oxygen. Boiler experts report the most common reasons for operating with excess oxygen are:
Older boilers using mechanical linkages for fuel-to-air ratio control are frequently calibrated for high excess air operation and mechanical linkages are unable to compensate for physical and chemical variations in fuels;
Oxygen analyzers don’t exist, are not working, are inaccurate, unreliable, improperly installed, or not connected to the control system; and/or
Operators feel more comfortable when a boiler operates in a fuel-rich condition.
When mechanical fuel-to-air linkages are replaced with control-system-based fuel-to-air ratio controls, and accurate, reliable oxygen measurements are integrated into the control system, fuel-to-air ratios can be automatically trimmed and excess oxygen can routinely be maintained at a 5% level.
Any efforts to improve a boiler’s performance will eventually result in an examination of the current control strategies. Many of the combustion control strategies used today evolved from control strategies developed 20 or 30 years ago. These strategies may be executing in a new controller platform, but many boilers are using essentially the same strategies they started with two decades ago. It’s been common practice for any new control techniques, addition of online measurements, or changes in control platforms fit within the framework of the existing control strategy (see Typical Gas Fired Combustion Control with Oxygen Correction diagram). Often the justification to add to or modify existing control strategies, rather than seek a new strategy, has been the result of skepticism and resistance to change.
In the case of skepticism, steam production is so critical to manufacturing that long-standing mandates exist requiring any new ‘ideas’ must be implemented in such a way that operations can easily return to the ‘old way’ just in case the new idea doesn’t work.
Resistance to change frequently enters the picture frequently where one operator is responsible for the operation of multiple boilers. In such situations operators understandably want operational consistency from boiler to boiler.
Both justifications have some validity, but stubbornly clinging to tradition can limit the opportunities to improve boiler efficiency and in a worst case scenario, unnecessarily require adding a new boiler to meet growing steam production requirements.
Alternative control strategies
Before the perfection of ‘industrial strength’ variable speed drives, the common method to control air flow to a boiler was to operate the force draft (F.D.) fan at constant speed and manipulate the F.D. fan inlet vanes (damper) to maintain the correct airflow to the boiler (see Typical Gas-Fired Boiler diagram). The design of F.D. inlet vanes introduces non-linearity into the control equation requiring physical or software characterization to linearize the air control loop.
Today many boiler F.D. fans are being retrofitted with variable speed drives, resulting in two advantages.
First, the thermodynamic fan law defines that rotational fan speed is linear to volumetric fan airflow. The linear relationship of fan speed to fan airflow can eliminate the need to characterize the control loop and simplifies combustion control.
Second, the use of a variable speed drive can provide a substantial reduction in fan horsepower when used at partial loads.
Robert Benz, president of Benz Air Engineering (Hermosa Beach, Calif.) explains, ‘A boiler requiring 218 hp to power a fan at 100% load will consume 27 hp at 50% load and a mere 0.22 hp at 10% load. Depending on how often and for how long the boiler operates at less than 100% load, the savings can be significant.
Del Monte Foods (Modesto, Calif.) has a very seasonal production cycle, they were able to save over $7,000 per month in electrical cost during their eight month nonmanufacturing season.’
Mr. Benz adds, ‘When those responsible for operating a boiler are willing to accept new ideas, like using variable speed drives, the sophistication of microprocessor based control systems can actually deliver simpler control strategies and improved performance.’
In 1996 Del Monte decided it was time to replace the pneumatic panelboard control system on their two 150,000 lb/hr natural gas fired boilers. Because of the seasonal nature of Del Monte’s production and their California location, two key requirements for a new control system were the ability to achieve a minimum of 10:1 boiler turndown and significant reduction in nitric oxide (NOx).
Ed Conner, Del Monte’s utilities manager, explains, ‘We found there are plenty of control systems that provide good performance under steady-state conditions, but cooking tomatoes is a batch process. We needed the control system to respond very quickly to production demands and retain tight boiler control. Eventually we selected the Compu-NOx system from Benz Air Engineering and have been quite satisfied with its performance. For example, in 1995 we used 18.69 therms per ton of tomatoes. After installing the Compu-NOx system in 1997 we reduced the therms per ton of tomatoes to 16.3 (a 12.8% savings).’
As stated earlier, the best way to save fuel is to improve boiler efficiency. Del Monte has been able to tune their boilers to consistently operate between 0.8% and 1.4% O2 and that has saved them over $100,000 per year in natural gas cost. At the same time, NOx levels are consistently below air district requirements, a truly remarkable accomplishment especially considering Del Monte boilers are using the burners delivered with their 1967 and 1977 boilers.
When asked about skepticism’s converting from a pneumatic panelboard system to a computer-based system, Mr. Conner laughed and said, ‘The operators and I were very skeptical. We bought and installed several back-up instruments anticipating reliability problems, but after initial training and hands-on use of the system, attitudes have completely flip-flopped. We removed the back-up instruments and operators would fight rather than switch back.’
Del Monte’s seasonal production was a driver for the 10:1 boiler turndown requirement, but Mr. Conner reports they routinely achieve a 15:1 boiler turndown while maintaining tight, responsive boiler control.
Many boilers continue to use traditional (evolutionary) control strategies, but apparently some new thinking can produce remarkable results. Regardless of your preference and philosophy about the best boiler control strategy, perhaps it’s time to take a walk to the boiler house and reexamine how it’s being controlled and operated. It just might save a lot of money and increase profits.
New Burner Management Standards near Approval
New and emerging performance-based standards- issued by American National Standards Institute (ANSI, Washington, D.C.), Instrument Society of America (ISA, Research Triangle Park, N.C.), and International Electrotechnical Committee (IEC, Geneva, Switzerland)-provide support to companies that use safety instrumented systems (SISs) to properly manage and reduce process risk to manageable levels.
The ANSI/ISA S84.01, IEC 61508, and IEC d61511 standards provide flexibility and allow for implementing practical and cost-effective solutions. They don’t mandate the ‘how to,’ but do provide a framework to use alternative protection solutions that improve safety and make business sense.
IEC 61508 is an umbrella safety standard and serves as the basis for developing IEC d61511 to specifically cover SISs used throughout the process industry, including combustion control. IEC d61511 has recently become available for review and initial indications are it will require some language changes to satisfy the S84.01 supporters, but everyone agrees it’s in the best interest of everyone to have one global governing standard.
Working in tandem with the ISA and IEC safety standards, Factory Mutual Research (FMR, Norwood, Mass.) developed complimentary approval standard 7605, ‘Programmable Logic Control (PLC) Based Burner Management Systems.’ When released in late 1999, standard 7605 will be used to evaluate, test, and certify SIS devices are suitable for deployment in industries and applications covered by IEC 61508.
According to Paris Stavrianidis, FMR’s director of risk engineering, the philosophy of 7605 follows the life-cycle philosophy contained in ANSI/ISA S84.01 and IEC 61508, including requirements to establish a Safety Integrity Level (SIL). Manufacturers of programmable microprocessor-based burner management systems must use relevant codes and standards in the design of the SIS devices and declare the safety integrity level (typically SIL 2) the system is designed to meet when the system is submitted to FMR for approval.
FMR approval is based upon evaluation of the safety controls and is granted at the device (i.e., sensor or PLC) level. Evaluation and testing includes verification that the device operates as required-for a PLC that means the hardware and software meet IEC 61508 requirements-including if it properly deals with upsets and faults in a safe manner, and operates consistently under extreme conditions of ambient temperature and operating voltage. Additional testing includes flame failure response, trial for ignition, purge timings, dielectric withstand, and the ability to operate for at least 100,000 cycles.
The harmonization and development of international standards benefit users and manufacturers by encouraging the development, certification, adoption, and deployment of a single solution regardless of world area. Nowhere is this more important than in safety and protection systems.
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Factory Mutual Research
Using Model-based Control Optimizes Boiler Efficiency
Faced with a need to improve operational efficiency and increase production at its Sim Gideon (Bastrop, Tex.) plant, the Lower Colorado River Authority (LCRA, Austin, Tex.) teamed with the Foxboro Company (Foxboro, Mass.) to implement an experimental process optimization model on Unit 3, a 340 megawatt, natural gas-fired, load-following boiler with a maximum ramp rate of 40 megawatts per minute.
The goal of the optimization modeling project was to explore the feasibility of utilizing advanced control to improve unit efficiency, reduce emissions of NOx and other greenhouse gasses, and do it without impacting the unit’s fast ramp rate.
Working with LCRA personnel, a team of advanced control consultants from Foxboro (Foxboro, Mass.) and Simulation Sciences (Brea, Calif) utilized Foxboro’s Connoisseur software to collect and analyze data and then construct a model-based, multivariable controller. Implemented on a separate computer the multivariable controller interfaces to the existing Foxboro IA process control systems loops (see Unit Optimizer diagram).
Initial multivariable controller tuning and testing was conducted in open loop operation over four days. Final tuning was achieved during two ten-hour verification tests using a pre-programmed load profile with the optimization modeling system operating in both off- and on-line mode.
Verification test data revealed efficiency improvements for the entire unit (boiler, generator, etc.) of 0.65%, NOx reductions of 12.3%, and estimated CO2 reductions of 51,500 tons per year, all achieved without any degradation in unit ramp rate.
LCRA personnel have determined that improvements will pay for the project in less than one year and are encouraged by data indicating further NOx reductions might be achievable with slight modifications to the controller model.
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