By Fred Maner, Jacksonville Electric Authority
JEA Trims Condenser Air In-Leakage and Realizes Significant Savings
Jacksonville Electric Authority’s Northside Generating Station has two operating gas/oil-fired steam units. Unit 1 is a 275 MW unit with a General Electric steam turbine and a Westinghouse steam condenser. Unit 3 is 520 MW unit with a Westinghouse steam turbine and a De Laval steam condenser. The units were placed in service in 1965 and 1979, respectively. [Unit 2, similar to Unit 1, is currently undergoing repowering.]
JEA implemented its TargetSmart Program at the Northside Generating Station to improve overall plant process performance. The program was designed to improve the plant heat rate and increase the time between forced outages. By eliminating excessive condenser air in-leakage, a common problem in power plant operations, JEA could meet both objectives. JEA approved the Air In-Leakage Reduction Project at Northside in January 2001 due to its high impact on unit performance and the availability of project resources.
Before the project began, the air in-leakage flow for Northside Unit 3 condenser was operating above its upper limit of 15 scfm, out of specification compliance by 25 scfm at full load. The annual cost of this deviation was more than $200,000.
JEA’s goal for the air in-leakage reduction project, therefore, was to reduce Northside Unit #3 condenser air in-leakage flow by 90 percent and make the process capable at full load by July 2001. Notably, the condenser air in-leak flow could not exceed the flow capacity of the condenser air removal system or it could adversely affect the turbine backpressure.
JEA’s project plan consisted of viewing the condenser air removal process as an equation, Y= f (x), and applying an M.A.I.C. Strategy (Measure, Analyze, Improve and Control). The project team developed a process map (Figure 1) to visualize the process flow for the condenser air removal system. The chart begins with the air in-leakage sources at the vacuum boundary. Air leaks into the system and is collected in the air removal section of the condenser. The air is pumped out of the condenser by the Nash vacuum pump. The air in-leak flow is measured in the air removal suction header before it reaches the vacuum pump, which discharges the air to atmosphere.
All the process steps are value added. The process map reveals several important points:
- All sources of air in-leakage must be identified and repaired.
- Good flow measurement is required.
- Pump capacity is critical to the process.
To narrow the analytical focus and learn more about the critical variables, JEA used two tools, the XY Matrix and PFMEA (process failure mode and effects analysis). These tools help prioritize the work effort and provide a sound method to incorporate both tribal knowledge and system experience into the problem analysis. Based on the XY Matrix (Figure 2), which categorizes and tallies equipment events according to defect modes, JEA selected air in-leakage sources into the condenser as the project focus.
Based on the PFMEA, which relates critical variables to potential failure modes within the process, the project team found that the current process control measurement was inadequate. While turbine backpressure was the historical process control measurement, changes in its value were actually only detectable to the operator in increments of 0.3 inch Hg absolute or greater. Since a change in turbine backpressure of 0.1 inch Hg absolute from the design point is worth $511/day, JEA needed to develop a better primary metric.
Primary and Secondary Metrics
JEA selected air in-leakage flow rate as the primary metric. During the fall of 2000, Intek Inc. agreed to donate a new air in-leakage flow meter system called the Sentry System to JEA. This would be the first Sentry System placed in-service in the world. In turn, JEA agreed to provide Intek Inc. with plant data concerning the condenser performance and air in-leakage on Unit 3. JEA installed the Sentry System in January 2001.
The air in-leak flow is measured in the air removal header upstream of the Nash vacuum pump. In January 2001 the high load air in-leakage flow baseline was established at 40 scfm. During low load operation, air in-leak flows above 100 scfm were common.
Helium leak detection test results and information from the PFMEA helped set the scope of work to reduce the number of air in-leak sources. The work scope included the following items:
- Replace water traps with a new receiver tank design. The water traps on the boiler feed pumps, feedwater booster pumps, and the steam packing exhauster could be replaced with one receiver tank, eliminating five water traps and providing a superior liquid seal between the condenser and the atmosphere.
- Repair LP turbine rupture disks.
- Repair turbine-to-condenser expansion joint.
- Repair LP turbine steam seals and housings. The seals needed to be replaced because the seal clearances had increased. Also, the housings needed to be checked for damage due to thermal distortion.
Resources made available for this project enabled JEA to complete all these items except for item 4, which will require a major outage. As shown in Figure 3, by the end of March 2001, the air in-leakage had dropped below the upper specification limit. The remedies established new baselines: approximately 13 scfm at high load and below 25 scfm at low load.
Northside expects to further reduce the air in-leakage and meet or exceed the 5.2 scfm target value when the LP turbine steam seal and turbine steam seal supply system is completely repaired.
To provide a second metric for gauging condenser performance, JEA selected the original metric, turbine backpressure. Accurate turbine backpressure measurement is dependent upon primary probe placement in the condenser neck and calibrated instrumentation. Gage validation was accomplished through instrumentation calibration. It is important to note that river water inlet temperature to the condenser (non-controllable parameter) must be held constant in order to accurately compare turbine backpressure data over time. Figure 4 shows a time series trend for turbine backpressure before and after process improvements. The figure shows data collected from two probes, one on each side of the condenser. Overall, Northside realized a 0.33 inch Hg absolute reduction in mean turbine backpressure.
JEA’s control plan incorporates three control measures: the Xbar/s (mean/standard deviation) chart, the Daily Water Chemistry Report, and a Plant Information Process Book (PI-ProcessBook). Data for the Xbar/s chart is collected during each month at both high and/or low load conditions (depending on unit availability). The unit should be operating at a constant load when the data is collected. The Xbar/s chart shown in Figure 5 is an example, using high load data. Note that the Xbar and the s charts both show one unique special cause event. It is believed that a change in the turbine steam seal header pressure is the special cause for both events (high and low). The LP turbine steam seal repair, mentioned above, and the Turbine Steam Seal System Project, will limit this pressure variation and benefit the overall performance of the condenser air removal process.
The Daily Water Report is an indication of the unit’s overall health. This report is monitored daily for significant changes in operating limit compliance for each of the chart elements.
The PI-ProcessBook is a time series data trending tool that is used to identify and troubleshoot system problems. It is a valuable tool for process trend analysis. The chart also shows the flexibility of the power production process.
JEA used Minitab to conduct a statistical analysis of test data collected from the Plant Information Data System (PI). The samples consisted of high load data taken before and after improvements. Both the air in-leakage and the turbine backpressure data showed a statistical difference before and after improvements. In both cases the null hypothesis was rejected (P value <0.05); thus, there is a statistical difference between the means in both data sets.
As noted above, the air in-leakage baseline flow dropped from 40 scfm to 13 scfm, an improvement of 67.5 percent. The overall turbine backpressure decreased by 0.33 inch Hg absolute, an improvement of 13.4 percent.
The annual saving for this process improvement is calculated below:
(Unit kW) x (Hours of Operation) x (Delta Btu/kWh) x ($/MMBtu oil/gas) x (Load Factor)
A change in Unit 3 turbine backpressure of 1.0 inch Hg absolute = 116.5 Btu/kWh
Therefore, 0.33 inch Hg absolute = 38.45 Btu/kWh
(520,000 kW) x (6400 hours) x (38.45 Btu/kWh) x ($3.50/MMBtu oil) x (0.461)
Annual Savings = $206,466
Northside Generating Station also realized several intangible savings from this project related to improvements in boiler cleanliness and reliability. Boiler chemical cleanings range in cost from $300,000 to $500,000, depending on unit specific requirements. A reduction in air in-leakage means less corrosion product is carried over to the boiler. Therefore, it is possible to realize some savings by increasing the mean time between cleanings. Also, if just one furnace tube failure event is eliminated during a peak demand period due to a reduction in air in-leakage, significant savings are possible:
(Unit MW) x (Cost of Replacement Power) x (Outage Period)
(520 MW) x ($60/MWh) x (72 hours)
Cost savings per typical event = $2,246,400
The original goal of this project was to reduce the excessive air in-leakage and improve turbine backpressure on Unit 3 by July 2001. The project successfully accomplished the goal three months ahead of the project schedule and the process is now capable.
Fred Maner is a Plant Engineer at Jacksonville Electric Authority’s Northside Generating Station. He has 19 years’ experience at JEA as a performance and plant engineer. Maner is a certified Six Sigma Green Belt and holds a bachelor’s degree in industrial technology from the University of North Florida.