The Life Cycle Cost Approach: The Effect of Power Uprates on Pumping Equipment

Issue 3 and Volume 4.

By Gerard van Loenhout, Technical Service Engineer, Flowserve Flow Solutions Group

Editor’s Note: This article is excerpted from a paper given at NUCLEAR POWER Europe in Milan, Italy, in June 2011. The complete paper is available at the Power Engineering magazine website,

Increasing the licensed power output of a commercial nuclear power plant is referred to as a power uprate. Uprates are an economical interesting way of producing more electricity, particularly with increasing energy prices around the globe and a situation likely to remain in the future.

Nuclear plant uprates for boiling and pressurized water reactor designs can be divided into three different categories, varying from small to large. These categories are:

  • Measurement Uncertainty Recapture (MUR)
  • Stretched Uprate (SPU)
  • Extended Power Uprate (EPU).

A MUR is a process whereby certain emergency core cooling systems assumptions are reduced regarding reactor power measurement to a specific value based on more accurate feed water flow measurements. This reduction can result in an increase in reactor licensed thermal power of 1.2 to 1.7 percent above the licensed thermal power.

A SPU is typically an uprate where the original plant design excess margins are used to increase reactor thermal power. Typically a SPU does not require extensive plant modifications as it uses existing margins in the plants equipment. The U.S. Nuclear

Regulatory Commission (NRC) has defined that a SPU is any uprate less than 7 percent of the originally licensed thermal power.

An EPU is a term used to describe a large increase in licensed reactor thermal power above the originally licensed thermal power. The NRC has defined that any uprate of 7 percent or higher to be an EPU.

Increasing electricity production at a nuclear power plant can be achieved in two ways:

1. Increase thermal power in primary loop (inside the nuclear reactor)
2. Improve thermal efficiency in the secondary loop (referred to as Balance of Plant), by replacing or refurbishing existing steam turbines, feed water heaters or a combination of these measures.

Increasing reactor thermal output can be achieved by increasing the amount of fissile Uranium-235 isotope in the fuel. This is also referred to as increasing the degree of enrichment. Alternatively, one can increase the density of the fuel. Another option to increase reactor thermal output is to optimize reactor operating conditions. Optimization of the fuel reload focuses on increasing the output from the fuel bundles using less power without affecting the high power bundles. It is also possible to increase core power by increasing the performance of the high power bundles.

In boiling water-type reactors, increased core power is achieved by either optimizing the control rod pattern or by increasing the reactor recirculation flow. The level of recirculation flow can be retained with larger steam voids in the core or the steam volumes can be held constant by increasing recirculation flows. A combination of both is also feasible. In pressurized water reactors, increased power output requires an increase in steam flow or in the coolant temperature difference across the core, or both. In all cases, steam production to the main turbines increases with increased electrical output being produced by the plants turbo-generators.

An increase in thermal reactor power directly influences the capacity of the secondary and tertiary loops, also referred to as steam and main cooling water circuits. The results are reflected in increased amounts of both main feed- and cooling water flows accommodating the transport and subsequent removal of a surplus of heat coming from the primary circuit. Such an increase in flow of the Balance of Plant (BOP) pumping equipment can be achieved by modifying or replacing existing equipment.

This article discusses a BOP example where the use of pump system assessment tools assist nuclear plant owners in developing a clear and exact scope on what type of pumping equipment modifications are needed to ensure the new, uprated operating conditions are met. Since pumps are not operating in isolation, a full system driven approach is to be applied, instead of a mere component driven approach. Meaningful and lasting pump system improvements can only be achieved by analyzing the system as a whole.

Within the current light water reactor technology applied, two major designs are distinguished, being the boiling water reactor and pressurized water reactor design. Their principles are shown in Figure 1.

The life cycle cost tool

Life cycle cost analysis (LCC) for pumping equipment provides key decision makers with an excellent tool that helps understanding all the components that make up the total cost of owning and operating a pumping system. Recognition of the potential opportunities to significantly reduce energy, operating and maintenance costs, provide any improvement project a solid basis for achieving success. In the Hydraulic Institute and Europump Pump Life Cycle Cost handbook, the equation which makes up the total LCC, has been defined as follows:

LCC = Cic + Cin + Ce + Co + Cm + Cs + Cenv + Cd, where
Cic = initial cost or purchase price
Cin = installation and commissioning costs
Ce = energy costs
Co = operating costs
Cm = maintenance costs
Cs = downtime (or loss of production)
Cenv = environmental costs
Cd = decommissioning

For most pump applications in continuous operation, lifetime energy- and maintenance costs dominate the total life cycle costs. High energy-type pumping systems in power stations, such as the condenser cooling or feed water systems, have a lifespan of many years. Thus some costs will be incurred at the start and others will be incurred at different times during the lifetime of the plant. This is why it is necessary to calculate a present or discounted value of the LCC. These include discount rate, interest rate, expected equipment life and expected price increase for each LCC factor over the estimated lifetime of the equipment. Figure 2 shows a typical LCC cost split for a standard pumping system.

As discussed before, uprating the BOP of an existing nuclear power station typically requires increasing feed water and condenser cooling water flows. With the inherent low system efficiency, condenser cooling water flow increase is usually significant compared to the original design flow. Particularly when conducting EPUs, cooling water flow increases of 10 to 20 percent may be required in obtaining the new planned station output level. In average one can say that nuclear power stations use 40 to 45 liters/second of cooling water per MWe output. (For fossil power stations this value is between 20 to 35 liters/second, depending on the vacuum required). As an example, for an EPU of 12 percent of an existing 1,000 MWe nuclear power station, the calculation shows that:

  • Existing cooling water flow would be: 1,000 x 45 x 3,600/1,000 = 162,000 m³/hour
  • New cooling water flow would be: 1,120 x 45 x 3,600/1,000 = 181,440 m³/hour

    Increasing the cooling water flow can be done in two different ways. The first way is to simply take out the existing pumps and replace them with new pumps. Usually, this requires making additional modifications to the plants civil structure as it was made tailor made to the existing pump units. Civil structural modifications can be, when compared to the investment cost of new pumps, 3 to 4 times higher than the cost for the new pumps and so these have to be added to the initial project costs.

    For high-flow pumps like vertical cooling water pumps, the combination of the pump design and water intake structure is crucial in assuring long term trouble free operation. Undisturbed inflow of the water into the pump.s impeller is required in order to avoid capacity and efficiency losses or damages due to potential vibration or cavitation. The so-called velocity distribution at impeller entry must be as uniform as possible and it is secured by a correct pump–intake chamber design. In case uniform inflow cannot be sustained, at some point local flow separation or even vortices may occur at the pump entry leading to unwanted hydraulic and mechanical behavior of the pump. While new selected pumps may meet the new conditions of service, usually additional investment costs are needed for civil structure improvements to correctly match pump and intake. Another critical aspect is the time it takes to implement such complex structural changes and risks associated with this.

    The second way is using the full capabilities of hydraulic engineering expertise of a pump supplier, providing power stations the possibility of increasing the pump flow by upgrading the existing cooling water pumps. One advantage is that the initial investment cost for such an upgraded solution is considerably lower than replacement by new units. Also, the additional cost needed for structural changes is typically less, as the pump’s new flow intake design can be optimized against the existing pit design. By applying a comprehensive technical assessment to review the existing pump system performance as well as the new conditions of service, users can have the assurance that the upgraded pumps will perform according expectation. Figure 3 shows the difference in LCC costs between modifying or replacing existing pumps.

    Plant Thermodynamics

    The net output of any steam-cycle power plant is determined by its thermal efficiency regardless of the heat source applied. Current Generation II nuclear power plants have a relatively low thermal efficiency (33 percent), whereas the latest ultra-supercritical fossil plants can reach 47 percent thermal efficiency. On average, one can say that for the older nuclear power plants, roughly two thirds of the energy is lost due to the intrinsic limitations of turning heat into mechanical energy. Steam conditions in nuclear power stations are limited by the need for the primary loop to operate well below the critical point. Superheating the steam is not feasible, a design limitation applied to avoid possible metal brittleness effects of the main components in the primary loop. Lower cycle efficiency in turn requires higher cooling water flow rates.

    In a power station, cooling water is used for two main purposes:

    1. Convey heat from the primary heat source to the steam turbines, steam cycle heat transfer. In a nuclear power station there’s an additional requirement, referred to as Residual Heat Removal and Emergency Core Cooling Systems.
    2. Condensing the steam and discharging the surplus of heat into the ultimate heat sink.

    The physics of thermodynamics define that the bigger the temperature difference between the internal heat source and the external environment where the surplus heat is absorbed, the more efficient the process becomes in achieving mechanical work. Figure 4 shows the classic Rankine steam cycle displaying the working principle of the thermodynamics.

    As the steam conditions in nuclear power stations are more or less fixed, another possibility of increasing the plant’s thermal efficiency is to improve the existing condenser performance, also referred to as lowering the condenser back pressure. Power plant condensers face many variables that define their ultimate performance. Some of these variables are: flow rates, variations of cooling water inlet temperatures, variable heat loads from the steam system, tube sheet macro fouling, deposits, air ingress and poor air removal pump conditions, decreasing tube speeds, silt build up and so on.

    One solution successfully applied in recent EPU’s conducted in Scandinavia has been to increase the cooling water flow by upgrading existing main cooling water pumps. Usually, an increase in cooling water flow is combined with a modification of the low-pressure section of the plant’s steam turbine, as any increase in turbine output is a function of back-end loading and condenser back pressure. All steam turbines are primarily dependent upon the heat rejection capability of the condenser cooling water flow. Low back pressures typically occur during winter time, while higher back pressures occur during summer time. This explains why most power plants have a higher net output in winter than summer, as differences in cooling water temperature may vary considerably.

    Also, in the case where no steam turbine modifications are undertaken, conducting a careful review of the condenser’s heat rejection system may already yield a substantial gain in net output delivered to the grid by mere adjustment of the cooling water flow, specifically during the warmer summer months. Figure 5 displays an existing relationship between a station net electrical output versus the cooling water flow inlet temperature of a PWR plant located in the northwestern part of Europe. Of course, plants taking in cooling water from shallow supply sources may benefit more from a flow increase as surface water temperatures tend to vary more over the year. Reducing the average condenser temperature by 0.5 C during spring, summer and autumn (6 to 7 months per year), may bring 0.5 to 2 MWe as a gain, depending on the size of the power plant.

    The System Assessment Approach

    Making changes in an existing condenser heat rejection system requires a thorough understanding of the system and its limitations. As the cooling water flows used are considerable in quantity, it is often challenging to perform accurate flow measurements. It is why such a flow measurement is best embedded in a full system assessment conducted by experienced engineers focusing on energy and hydraulic optimization.

    The technical assessment process consists of the following steps:

    1. Retrieving plant information; performing a forensic audit of current process parameters, maintenance history and new operational demands
    2. Collecting data; implementing a testing methodology using data collection to generate actionable data
    3. Analyses of collected data; validating pumping performance by scaled model test and develop a new hydraulic solution
    4. Reporting; generate detailed reporting with recommendations, including supporting LCC, for implementation of the new pumping solution
    5. Securing and verification of pump and pump system performance after implementation of the modifications under new conditions of service.

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