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Decoding discrepancies

Two 70,000-pph gas-fired boilers were using fuel amounts well above company standards. (The benchmark was cubic feet of gas per pound of steam.) The units had different steam pressures, geographical locations, feedwater conditions, and heat-recovery packages. Ten- and 15-percent flow-rate discrepancies between the feed-water and steam meters were identified. Both meters had significant mechanical-installation anomalies. By testing and documenting combustion efficiency, re-establishing new viable benchmark standards, and correcting meter discrepancies, the client was able to improve efficiency by 1.5 percent — a savings of $80,000 per year based on a fuel cost of $7.20 per million British thermal units of fuel energy value and 24/7/350 operation.

Plug the holes

A northern facility with two 85,000-pph field-erected gas-fired boilers had experienced a major curtailment in production. Summer steam load had dropped to 15,000 to 20,000 pph, and efficiency was poor. Thirty percent of the nozzles in one unit's burner ring were plugged and air-fuel controls were recharacterized to permit 3-percent excess O₂ and good efficiency at 18,000 pph.

Inspectors need access

An older 150,000-pph “A” frame package unit (with a new low-NOx burner) was experiencing NOx and carbon-monoxide (CO) emission levels well above permit limits. Additionally, fuel usage was high because the environmental manager required excess-air dilution. After several combustion-system modifications, the burner supplier disavowed further responsibility. A thorough inspection identified refractory deterioration and short-circuiting of furnace gases into the outlet breeching. The unit had been cycling “on- and offline” for years, and difficult access had decreased inspection and repair of the refractory in the front sections of the furnace walls.

Being too conservative

A commercial facility was operating three 40,000-pph dual-fuel (natural gas and methane) boilers at 5- to 6-percent excess O₂ while experiencing high exit-gas temperatures. The problem was caused by overly conservative combustion characterization during times of low natural-gas costs. Recharacterization to lower excess-O₂ levels resulted in a natural-gas cost savings of $80,000 per year (an average 3-percent savings per unit based on a fuel cost of $9.50 per million British thermal units of fuel energy value over 180, 205, and 210 days of operation).

Control is critical

In a facility with several large gas-fired boilers of various sizes and configurations, four boilers were operating in the 30- to 50-percent load range as standard procedure. System-pressure control was crucial. Older boiler controls could not maintain header pressure and drum level with fewer units operating at higher load. Heat-recovery equipment was producing good efficiency; however, excess-O² levels were high (5 to 6 percent). Recharacterization of air-fuel controls for optimization at 50-percent load resulted in an overall 1.5-percent boiler-efficiency improvement at lower loads and a fuel-cost savings of $240,000.

Bad conditions mean big expenses

Thermal imaging at a large manufacturing plant revealed numerous sections of uninsulated steam lines, dozens of large (8- to 16-in.) uninsulated valves, many “open-blowing” traps, and three large steam-coil air-heater units in a significant state of disrepair. These conditions equated to more than 4,000 pph of steam loss at a cost of $270,000 per year. (Steam cost $8.05 per 1,000 lb.) Every identified item had a repair-cost return on investment of less than two years.

RECOMMENDATIONS

Several general recommendations can help reduce steam-plant operating costs significantly, including:

• Efficiency testing

  Regular “heat-loss” efficiency testing should be conducted. ASME boiler-efficiency-objectives charts can be used to document unit operation (tables 1 and 2).

• Fuel usage

  Nominal fuel usage should be developed, posted, and documented for all boilers. Boilers should fall within three basic guidelines: 0.75 to 0.80 lb of steam per cubic foot of natural gas, 110 to 115 lb of steam per gallon of No. 2 fuel oil, or 115 to 125 lb of steam per gallon of No. 6 fuel oil.

  Changes in performance should trigger pre-determined actions by operating and maintenance crews.

• Meter accuracy

  Feedwater and steam meters should correlate within 1 percent. Because steam and fuel meters often are inaccurate, consequences of the discrepancies should be quantified. Good meters should produce input/output efficiency and ASME heat-loss-efficiency results within ±2 percent. A combustion-efficiency test can be a 2-hr procedure for systems without meters. Each boiler should achieve efficiency levels of at least 82 to 85 percent.

• Total system losses

  The percentage of total condensate-return and steam-distribution-system losses should be determined. If total losses (thermal energy) exceed 5 percent of steam produced, an economic assessment should be made, issues prioritized, and anomalies corrected.

• Get help

  If you do not have the time or resources to document boiler performance and steam-system losses and implement corrective measures, then get help. A two- or three-day review by a boiler-systems consultant should cost about $6,000.

CONCLUSION

Routine fuel-usage and auxiliary-equipment optimization in many large, mature steam plants (as well as smaller unattended operations) throughout North America can produce significant fuel- and maintenance-cost savings and salable carbon credits.

Many boiler-service companies can evaluate steam-plant conditions for a nominal fee. An experienced boiler consultant can identify and quantify anomalies that could be costing thousands of dollars per month. A boiler-efficiency improvement of 1 to 2 percent and a steam-distribution-system-efficiency improvement of 2 to 3 percent (in mature facilities) normally can be attained without significant capital expenditures. Therefore, calculating 4 percent of a boiler's annual fuel cost can help determine if action is warranted.

Lack of time or resources should not be the cause of boiler and steam-system performance problems. Ongoing awareness of basic operational standards and fuel costs should be a priority for any facility spending more than $500,000 on fuel per year. If serious operational issues are recognized, safety anomalies cannot be far behind.

President of JoGar Energy Services and a member of HPAC Engineering's Editorial Advisory Board, Gary Wamsley, PE, CEM, is a mechanical engineer with 40 years of technical management and operational experience in plant and staff engineering. He has developed and presents training programs on the energy optimization of boiler operations, water and steam treatment, industrial energy management, and combustion, compressed-air, centrifugal-pump, and thermal-process systems. He can be reached at gary.wamsley@comcast.net.