Troubleshooting boiler operation
Keeping an eye on boiler operations can lead to efficiency gains.
Gary Wamsley, PE, CEM, JoGar Energy and Utility Services Inc.
While visiting a large industrial facility in the Southeast, I became involved in a technical issue that could perhaps be referred to as part of a Boiler Feed Pump Operations Session 101.
As a staff technical leader in the corporate utilities group for a pulp and paper company, I had been scheduled to visit one of the tissue mills to conduct combustion efficiency testing on two 130,000 PPH steam boilers.
The facility was located in an ambient air quality non-attainment region for ozone, CO, and NOX. We had developed a plan to conduct field combustion emission testing to determine if burners and controls could be modified to reduce stack emissions and bring the boilers into compliance with the recently promulgated stricter air emissions requirements.
The boilers (installed in the 1970s) had initially fired No. 6 fuel oil and natural gas. However, the No. 6 oil systems were removed in the late 1980s due to particulate and SOX regulation changes.
Pump issue identification
During a preliminary inspection of the boilers and auxiliary systems (prior to conducting the emissions testing regimen), I noticed that both of the 100 hp boiler feed water pumps were running. That was not normal. These two boilers were installed as a 100% redundant system. Mill steam load averaged 70,000 to 90,000 PPH summer to winter. One boiler generally was in service, and the second unit was in warm stand-by using a continuous blowdown heat recovery concept to keep it hot at line pressure.
Since I had visited the facility frequently in the past, I knew that the feedwater pumps (BFPs) were also 100% redundant. At a steam load of 90,000 PPH there should have been no reason for two pumps to be operating. Both pumps seemed to be running OK. I went to the control room to further check out the DCS data and have a discussion with the shift utilities crew.
After a brief update about recent activities, one operator informed me that both BFPs had been in service for the past several months. I then recalled my visit about a year prior when the maintenance foreman had approached me about performance issues with these pumps. We had inspected the pumps and I suggested that, due to their age, he consider a minor overhaul.
The pumps were two-stage, horizontal, split-case, double-suction design. I indicated to him that it was an easy, straightforward repair procedure: Remove the casing upper half; check the impeller eye, the wear rings, and the casing cut-water for erosion; and then repack the glands if everything looked normal.
So I asked the boiler operator if maintenance had overhauled the pumps. “Yes, last summer,” he said, “during the annual outage.” They found nothing abnormal other than worn packing.
The plant steam pressure was 215 to 225 psig and feedwater pressure was normally 340 to 360 psig with one pump in service. Each pump was rated for 290 gpm at 720 feet. The deaerator operated at 7 psig (233 F); however, it was installed on the roof of the boiler building with a pump elevation head of 30 ft. There was no way cavitation should be an issue with these pumps (40-plus ft of suction head).
I then asked the operator why they needed to run both pumps. “One pump could not maintain boiler drum level and header pressure during sudden steam load changes,” he replied. Two pumps in parallel could double the feedwater flow or increase the pressure to near a maximum shut-off head of 360 psig at 50% flow rate, I thought.
My next action was to conduct another inspection and gather more data. In the MCC room, both pumps were pulling 82 to 85 amps (about 75% motor load). Here’s the pump power data calculation:
- Pp = (Q × H × s.g.) ÷ (3,960 × ηpump)
Motor kW = (V × A × PF × MEff. × 1.732) ÷ 1,000
Pp = [220 gpm x (770 - 40) ft x 0.96) ÷ (3,960 x 0.53) = 73 hp each = 85 amps at 460 V
The feedwater flow certainly appeared high. Bottom blowdown valves were closed and cold, as were the bottom header drain valves. We seemed to have a combined FW flow of about 440 gpm for a steam load of 90,000 PPH. Each pump (at 220 gpm) was about 53% efficient and using a combined 148 hp.
From previous experience at other similar steam plant installations, I decided to check out the minimum flow recirculation lines. Each pump has a 1-in. line (before the discharge check valve) that returns to the storage section of the deaerator. These lines provide a minimum continuous flow of 10% (about 30 gpm in this case) to assure against a “no flow” condition inside the pump when the steam drum level control valve goes automatically closed.
Since the feedwater is 233 F, these lines are fully insulated and difficult to discern by an unseasoned operator. It took me a few minutes to locate the “orifice-plate” assembly about 3 ft above the pump casing. The aluminum jacketed lines were about 3-in. diameter and some of the insulation appeared to be new. I retrieved a screwdriver from my combustion analyzer toolkit to conduct a quick flow-velocity sound test.
With the pointed end against the recirculation line pipe and the handle end against my ear, it was quite apparent that the flow velocity noise was much higher than reasonable. Upon returning to the control room for further discussion with the operator, I learned both lines had developed leaks (at 90-deg elbow fittings) over the past year. He understood that they were minimum flow lines to protect the pumps from seizure, but knew nothing about location of the restrictive orifice that sets the proper flow rate.
It was time for me to speak with a staff engineer. It took a while to find the pumps’ file and dig out the piping schematics. The 1-in. lines indicated a stainless orifice plate between flanges with an orifice diameter of 0.135 in. Remember that feedwater pressure is about 340 psig. A severely eroded orifice plate (as I then expected) could easily flow well over 120 gpm back to the DA tank.
After some further discussion and a few calculations, I got his agreement that two pumps were operating very inefficiently. So, I proposed a quick field trial:
- We asked the boiler operator to temporarily close the 1-in. isolation valves in the recirculation line on both pumps (valves located before the orifice flange assembly at each pump). Immediately the load on both motors changed from 82 to 46 amps.
- After a few minutes of steady-state flow, we shut down pump No. 2. The amps on pump motor No. 1 increased from 46 to 73, about normal for a one-pump operation at 70% boiler load.
- Next, we switched to pump No. 2 and experienced similar results.
- Finally, opening the minimum flow line on pump No. 2 increased motor load to 86 amps.
- There was no question that the orifice plates were eroded away. After all, these boilers were 30 years old. The boiler operator then reminded us that a sudden steam load change (from a broke pulper heating cycle) could cause the boiler to trip. So, back to two pumps!
Having experienced this plate erosion condition at other similar boiler plants, I offered a replacement orifice pipe design for the recirculation lines:
- Use a 6-in. length of 1-¼-in. diameter cold rolled steel bar stock.
- Drill a 9/64-in. size hole through the center of the bar.
- Then tap both ends of the nozzle for 1-in. size NPT threads.
- The recirculation line is Schedule 80. A tight threaded joint (using Teflon tape) is effective.
This robust design will last indefinitely.
You might ask: “Why not use a commercial automatic recirculation control (ARC) valve?” We prefer not to use these expensive control valves on low- and medium-pressure boilers with feed pumps at 100 hp and smaller.
Generally orifice pipes are more reliable and economical. At a boiler load below 25% to 40%, the feedwater pump will be operating on the “flat part of the curve.” An ARC valve is simply not accurate enough to detect a minimum pressure differential change of possibly 1 to 2 psig when the “drum level-control-valve” closes. Note the flat head curve near shutoff:
Converting the ARC valve to an electronic controller (using motor amps) does not work reliably either. The amperage change is also very difficult to discern at low feedwater flow rates. Failure of the valve to open (and establish minimum flow) is a recipe for pump cavitation and becoming steam bound. If the boiler trips on low water, plant production is affected immediately—not a situation that production management appreciates.
Repeatedly tripping two tissue machines offline due to a boiler feedwater pump mechanical issue is not good for your career path.
Now, for larger boilers with high-capacity, high-horsepower feed pumps, the ARC valve often becomes an energy conservation issue. Not continuously pumping 10% of the feedwater back to the deaerator reduces a lot of motor kWh over a year, especially so in regions of the country where power costs are 8¢ to 12¢ per kWh. Just be very cautious about dry-running a $50,000, multistage, stainless-trimmed feedwater pump. Talk about having an upset boss. It is not recommended.
Mill engineering and maintenance later replaced the orifice plates in the recirculation lines with robust orifice pipe nozzles. The boiler plant returned to single feedwater pump operation with no subsequent troubles. Earlier, a single pump was fully loaded due to the eroded orifice plate. They went from two pumps consuming 148 hp to one consuming 65 hp, saving approximately $100 per day in electrical power.
If your low-pressure or medium-pressure boiler plant has experienced a puzzling feed pump performance issue, be sure to include the minimum flow recirculation line in your problem analysis critique. Get some advice from a utilities guru if needed; there are several experts on Google.
Wamsley is a mechanical engineer with 40 years of technical management and operational experience in plant and staff engineering at large and small facilities for the tire, aerospace, and tissue/paper industries. Currently, Wamsley is president of JoGar Energy and Utility Services, Inc., located in Alpharetta, Ga. JoGar Energy Services offers “on-site” energy reviews, boiler efficiency testing services, technical assessments of specific utility systems, and training seminars on these topics. Wamsley can be reached at www.jogarenergy.com or 678-977-1508.
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