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FIGURE 19 Single stage double suction reactor feed pump, 12,000 horsepower (8950 KW) (Flowserve Corporation)

More detailed information on other nuclear power plant pumping services is given in Subsection 9.14.1.

High-Speed, High-Pressure Boiler Feed Pumps As steam pressures rose to 3000— and even to 4500 lb/in2 (200 to 310 bar)—the total head that was required to be developed by the pump rose from around 4000 ft (1220 m) to as high as 7000 and 12,000 ft (2140 and 3660 m). The only means available of achieving these higher heads at 3600 rpm (2-pole motor speed at 60 Hz) was to increase impeller diameter and the number of stages. The pumps had to have longer and longer shafts to accommodate the larger number of stages. This threatened to interfere with the long uninterrupted life between overhauls to which steam power plant operators were beginning to become accustomed. The logical solution was to reduce the shaft span by reducing the number of stages.

In the 1970s, stage pressures rose from around 800 ft/stage to 3000 ft/stage and higher. Several single, 65,000 horsepower (48,500 kW) boiler feed pumps were constructed to support 1300 MW fossil plants (Figure 20). The higher head requirements were achieved by increasing the speed of rotation instead of increasing impeller diameter or stage number. As a result, boiler feed pumps in large central stations today generally operate at speeds from 5000 to 9000 rpm.

Boiler-Feed Pump Drives The majority of boiler-feed pumps in small and medium-size steam plants are driven by electric motors. It was the practice to install steam-turbine driven standby pumps as a protection against the interruption of electric power, but this practice has disappeared in central steam stations.

Central stations have trended away from electric motor drives, including those equipped with hydraulic couplings, fluid, and variable frequency drives, to steam turbines for units in excess of 200 MW because

1. The use of an independent steam turbine increases plant capability by eliminating the auxiliary power required for boiler feeding.

2. Proper utilization of the exhaust steam in the feedwater heaters can improve cycle efficiency.

3. In many cases, the elimination of the boiler-feed pump motors may permit a reduction in the station auxiliary voltage.

4. Driver speed can be matched ideally to the pump optimum speed.

5. A steam turbine provides variable-speed operation and better flow compliance to varying plant load and flow demands without an additional component, such as a hydraulic coupling.

Many combined cycle plants are constructed utilizing motor-driven boiler feed pumps to facilitate flexibility in start-up and varying load demands.

Application of variable frequency drive (VFD) motors continues as equipment costs drop. The VFD technology provides variable motor speeds by controlling the frequency input.

Operation of Boiler-Feed Pumps at Reduced Flows Operation of centrifugal pumps at shutoff or even at certain reduced flows can lead to very undesirable results. This subject is covered in detail in Subsections 2.3.1 to 2.3.4, Section 8.1, and Chapter 12, where methods for calculating minimum permissible flows and means for providing the necessary protection against operation below these flows are discussed.

Recent experiences have clearly defined the need to understand hydraulic instability, cavitation, and separation as they relate to off-design flow operation.

As deregulation and economic constraints dictate plant load cycling to match electricity demands and operating costs, the large central station boiler feed pumps experience significantly low operating flow. The low flow operation, high impeller suction specific speed, and high inlet tip speeds result in mismatched flow angles, backflow recirculation, and severe suction impeller inlet cavitation damage. This low flow hydraulic instability will also result in damage to pump volute cutwaters and diffuser

FIGURE 21 Diffuser inlet vane erosion damage (Flowserve Corporation)
FIGURE 22 Unsteady vapor cavity behavior, feed pump at low flow (Flowserve Corporation)

vanes (Figure 21). Suction impellers where the suction specific speed exceeds 10,000 and eyebore inlet tip speeds exceed 200 ft/sec. are highly susceptible to this low flow instability and component damage. The series of photos in Figure 22 show a condition typical for many high-energy pumps operating at flows below design levels. They demonstrate how serious low-flow instability can be when it is coupled with two-phase flow activity.

The severity of cavitation erosion is highly dependent on the inlet tip speed of the suction stage impeller, the NPSHA, and the thermodynamic properties of the fluid being pumped. The erosion seen in Figure 23 was caused by the collapse of discrete cavitation

FIGURE 23 Impeller inlet vane cavitation erosion damage (Flowserve Corporation)
FIGURE 24 Cavitation vapor bubbles on suction surface of the impeller inlet vane (Flowserve Corporation)

vapor bubbles. Cavitation forms around an impeller blade because of local static pressure falling below the vapor pressure of the liquid being pumped. The vapor cavity shown in Figure 24 is an example of this phenomenon.

With decreasing flow rates (due to operating at off-design conditions), the fluid approaches the impeller blade with larger and larger angles of incidence altering the velocity and pressure fields inside the impeller.

Pumps that are cycled between minimum-flow and flows in excess of the best efficiency point (BEP) create conditions at the impeller in excess of what "fixed geometry" machines can effectively tolerate. Impeller geometry has been shown to influence the degree and severity of cavitation problems experienced with high-energy pumps.

Through the 1980s, attempts were made to pursue "non-traditional" designs of impeller blading. These efforts took the form of profiling the inlet blade in a way that rapidly increased and then decreased the blade thickness.

A new impeller blade design approach, referred to as a "biased-wedge" design, has been found to provide a manufacturable configuration that enables cavitation bubble-free operation over a wide fluid flow range. This design approach is a result of extensive flow visualization test work and computational fluid flow analysis of many impeller geometries. It successfully advances the performance of high-energy pump suction stages to levels not achievable with conventional designs. Dramatic reduction in cavitation activity on the impeller was recorded as seen in the photo (Figure 25) of the suction surface of the final impeller taken at identical positions in the suction inlet and at the same operating conditions (baseload and minimum flow) as Figure 24. The inlet vane air foil shape has proven successful in facilitating feed pump flow rangeability.

Fundamentals for Successful Operating Life—Efficiency/Reliability Best practices for extended successful operating life of pumps are outlined in Chapter 12. Essential fundamentals to emphasize for boiler feed pumps are proper pump warm-up, standby warming, and shaft (fixed bushing) seal drain temperature control. These characteristics have become more critical as central station plants are cycled and large feed pumps are operated with varying loads and in standby modes. Current designs of multistage pumps (Figure 17) installed in combined cycle plants are less sensitive to thermal transients and wide swings in load (pump flow).

Pre-warming of the pump and maintaining warm-up flow to an idle pump to assure dimensional thermal uniformity is essential to maintenance of internal clearances, pump efficiency, and long life. This process is critical for multistage pumps to minimize thermal

FIGURE 25 Operation at same flow as Figure 24, improved inlet vane shape-(Flowserve Corporation)

;—dramatic vapor bubble reduction

FIGURE 25 Operation at same flow as Figure 24, improved inlet vane shape-(Flowserve Corporation)

;—dramatic vapor bubble reduction

FIGURE 26 Thermal distortion of feed pump casing and shaft, due to improper warm-up and thermal stratification

stratification within the pump. The distortion, including shaft bowing (Figure 26), will cause the following potential failure modes:

1. Flashing

2. Internal rubbing

3. Increased wear ring clearances

4. Pump seizure

5. Worn seal bushing clearance and excessive leakage

6. Loss of pump performance and efficiency

7. High pump vibration

8. Worn bearings/bearing clearances

Installation features and operating practices that extend pump life, efficiency, and reliability are

1. Proper pump insulation (Figure 27) at the casing and discharge head

2. Warm-up orifice, piped around the discharge check valve. Preference is to inject warm-up flow to the bottom of the pump casing to minimize short-circuiting of the hot feed-water and potential thermal stratification within the casing.

3. Maintaining shaft seal leakage drain temperature (Figure 28) between 150 and 170°F (65 and 77°C); utilize an electro-pneumatic temperature control system.

4. Installation of thermocouples or other temperature-detecting instruments (Figure 29) in the pump casing and discharge head to confirm temperature differences within 50°F (28°C) across the pump and relative to the feedwater temperature.

5. Assurance of proper functioning of the pump casing "pin" and "key" block to allow uniform thermal growth. Confirm that the hold-down bolts for the outboard casing feet are not over-torqued, preventing uniform axial thermal growth as the pump is heated.

6. Assurance of proper location and functioning of critical pipe hangers to minimize pipe strain on the pump suction and discharge nozzles.

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