Balance of Plant Control System

Swapan Basu , Ajay Kumar Debnath , in Power Plant Instrumentation and Control Handbook (Second Edition), 2019

2.1 General

When large pumps run, they create a great deal of heat from the churning effect of the impellers. So when the pump runs it is necessary to cool the pump impellers. During a higher load operation, fluid flowing through the pump acts as a coolant. When the pump just starts and/or when the pump is running at very low load, normal fluid flow quantity may not be sufficient to cool the impellers. Therefore a minimum quantity of fluid needs to flow through the pump, thus balance fluid is returned to the source. This is achieved by recirculation flow of the fluid through the pump. Recirculation is defined as returning the pump discharge flow to the point where the pump has suction so that a minimum flow requirement of the pump is ensured through the pump (even when there is low/no load demand to the system from the pump). For recirculation flow of a BFP (the pump has its suction from the deaerator), the pump entire/partial flow water from the BFP is returned to the deaerator during startup and at low load. Generally, the BFP handles the high flow at high differential pressure (DP); the pump sizes are large so even for small units such recirculation flow is necessary. The loop discussed here is applicable for each pump, so only one loop is illustrated.

2.1.1 Objective

The purpose of the BFP recirculation control loop is to ensure minimum flow through the BFP at all times.

2.1.2 Discussion

The BFP recirculation line is taken from the pump discharge ahead of the discharge valve and returned through the recirculation valve to a deaerator where the BFP has suction (Figs. 3.17 and 3.18). There are various BFP sizes, types, and unit sizes, and variations in controls. Generally, in power plants up to 200 MW (there are modulating types of controls for unit size <   200 MW) an ON/OFF type of recirculation control is deployed. BFP recirculation control loops for unit sizes ≥   500 MW are generally the modulating type. For smaller units a simple flow switch may be used to operate BFP recirculation control (Fig. 11.1A ), whereas in 120 MW/200/210 MW units the suction flow of the BFP is measured and this signal is used to OPEN/CLOSE the BFP recirculation control valve (Fig. 11.1B). There will variations of temperature, so it is recommended to compensate the flow with feed water (FW) temperature at BFP suction.

Fig. 11.1

Fig. 11.1. BFP recirculation control.

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Balance of Plant Control System

Swapan Basu , Ajay Kumar Debnath , in Power Plant Instrumentation and Control Handbook, 2015

2.0.2 Discussion

The BFP recirculation line is taken from the pump discharge ahead of the discharge valve and returned through the recirculation valve to a deaerator where the BFP has suction (see Figure III/6.2-1 and III/6.2-2). There are various BFP sizes, types, and unit sizes, as well as variations in controls. Generally, in power plants up to 200 MW (there are modulating types of controls for unit size <200 MW) an ON/OFF type of recirculation control is deployed. BFP recirculation control loops for unit sizes ≥500 MW are generally the modulating type. For smaller units a simple flow switch may be used to operate BFP recirculation control (see Figure XI/2.1-1a), whereas in 120 MW/200/210 MW units the suction flow of the BFP is measured and this signal is used to OPEN/CLOSE the BFP recirculation control valve (see Figure XI/2.1-1b). Since there will variations of temperature so, it is recommended to compensate the flow with feed water (FW) temperature at BFP suction.

FIGURE XI/2.1-1. BFP recirculation control.

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The steam turbine

British Electricity International, in Turbines, Generators and Associated Plant (Third Edition), 1991

4.3.2 Feed pump duty, margins, and the need for variable speed

The duty of the boiler feed pump as determined by the boiler and turbine pressure flow conditions, is given by Fig 1.71. Shown on the diagram are the boiler feed-pump characteristics, i.e., the relationships between the head produced by the boiler feed pump corresponding to the particular value of feed flow pumped, and the boiler feed pump speed. Various head/flow characteristics corresponding to the operating range of pump speeds are indicated. The curve denoted as 'system resistance' is the relationship between feedwater flow and the head that has to be produced by the boiler feed pump to pump the feedwater into the boiler. Also shown in the diagram are the design values of feedwater flow for the turbine plant, boiler plant and the feed pump itself.

FIG. 1.71. Boiler feed pump and system characteristics

It is normal practice to design the boiler to produce a higher rate of steam generation than that appropriate to the value used in the turbine-generator design. This margin is normally about 5% and is intended to cover application variations (e.g., site conditions such as available cooling water) at the time that the boiler is designed, and also to allow for a deterioration of plant capability in service. In addition to the effect of the boiler margin, the boiler feed pump is designed to produce a rather higher feedwater flow than that needed by the normal boiler design condition. This is intended to cope with pump wear and transient conditions, and to act as an operational margin.

At the value of feed flow corresponding to the turbine design quantity, the head produced by the pump is in excess of that required to pump the water to the boiler. This excess pressure can be minimised if the pump can be driven at reduced speed: if this is not possible the excess pressure has to be broken down across the feedwater regulating valve. As can be seen from Fig 1.71, at low values of feed flow, the excess of head produced by the pump over the system resistance head is considerable. On typical British sets of 500 MW and over, variable-speed drive is always adopted because the cost of providing it is much less than the operational and financial losses that would be incurred by this breakdown of pressure. In addition to this, all conventional plant is required to be capable of two-shift operation, i.e., to be shutdown overnight and started in the morning. During an overnight shutdown the boiler pressure falls significantly, such that during the start-up period next morning, the boiler feed pump is only required to deliver some 100-200 bar instead of the approximate 230 bar closed-valve full-speed pressure of the pump. For this reason, the pump that is used during the start-up period should have a speed range down to approximately 70% full speed to avoid excessive wear on the feedwater regulating valve.

As the power requirement of a boiler feed pump for a typical 500 MW unit is approximately 10 MW, it can be seen that the choice of an economic and technically acceptable variable-speed boiler feed pump drive is a decision of major importance. The possible types of boiler feed pump variable-speed drives which have been considered by the CEGB for use on large generating units are:

•

Fixed-speed electric motor with variable-speed coupling.

•

Converter-fed variable-speed (electric) motor (VSM).

•

Back pressure steam turbine.

•

Condensing steam turbine.

In addition to these choices, the option of slipring induction motor, regulated by resistance in the rotor circuit, has been considered and used in the past. This relatively cheap and simple solution, using large liquid rheostats with mechanically-movable tapping points, has proved unreliable in practice, with a high maintenance burden.

Variable-speed electric motors and condensing steam turbines have only recently become viable options (for future units over 900 MW) due to the trend to slower (6000 r/min or less) 'International Class' boiler feed pumps, to limit erosion and cavitation in the pump, to the NPSH required and de-aerator height, etc. These two types of drive are not feasible for use with the higher speed 'Advanced Class' pumps used on 500 and 660 MW units so far, due to converter size limitations and blade vibration and stressing difficulties.

A technical description of electric motor drives (variable-speed, induction, synchronous, etc.) for feed pumps is given in Volume D. A description of the use of steam turbines for driving feed pumps can be found in Section 9 of this chapter.

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Condensers, pumps and cooling water plant

British Electricity International, in Turbines, Generators and Associated Plant (Third Edition), 1991

14.1 Introduction

The design and arrangement of boiler feed pumps has a significant impact on overall unit availability. In determining the optimum arrangement of feed-pumping plant, the economic assessment needs to take account of capital costs, capitalised running costs, repair and maintenance costs, and the likely effects of loss of availability. Other constraints which should be considered are:

•

The need to ensure that failure of a single pumpset does not impair the start-up of the main unit or affect output capability. Standby capacity equivalent to the largest duty pumpset is indicated with a rapid start-up capability, sufficient to prevent the loss of boiler drum level and consequent unit trip.

•

The need to ensure that the plant is able to operate satisfactorily during and after a large load rejection by the turbine-generator unit. This requires that the drives for the duty pumps and their power supplies must be suitable for this operating condition. Alternatively, a suitable rapid start/ standby pumpset is necessary.

•

The need to provide adequate NPSH margins, taking into account that the pumps are supplied from a direct contact heater (de-aerator), which can be subject to pressure decay following a reduction in turbine load.

•

There should be at least two pumpsets capable of starting the unit. If a turbine drive is to fulfil this function, then a steam supply independent of the main boiler (i.e., an auxiliary boiler) is required.

•

If two or more pumps are required to operate in parallel, then the pumpsets should be able to accommodate run-out duties following loss of an operating pump.

•

The provision of sufficient pumping capacity to meet flow requirements under all operational circumstances. It is normal practice to include a flow margin to accommodate additional demand by the turbine above its design rating during transient flow disturbances. A margin on pump generated head is also appropriate to cover for deterioration resulting from internal wear during periods between overhaul. In the interests of keeping pumpset sizes and powers to a reasonable minimum, consistent with maintaining the pump best efficiency close to the duty point operation, these margins have been optimised as 5% on flow and 3% on generated head.

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Evaluation of Hazard and Risk Analysis

Swapan Basu , in Plant Hazard Analysis and Safety Instrumentation Systems, 2017

List of Abbreviations

ALARP As low as reasonably practicable
BFP Boiler feed pump
CCPS Center for chemical process safety
CEI Chemical exposure index
COP Critical operating parameter
DOW FEI Dow Fire and Explosion Index
EC&I Electrical, control, and instrumentation
ETA Event tree analysis
FCV Feed control valve
FEED Front end engineering design
FMEA Failure mode and effect analysis
FSA Formal safety assessment
FTA Fault tree analysis
HAZID Hazard identification
HAZOP Hazard and operability study
HC Hydrocarbon
HRA Human reliability analysis
HW Hardware
IPLs Independent protection layers
LOPA Layer of protection analysis
MEA Major accidental event
MF Material factor
MHF Major hazard facility
MHI Material hazard index
MOC Management of change
NOPSEMA National Offshore Petroleum Safety and Environmental Management Authority
O&M Operation and maintenance
OPGGS Offshore Petroleum and Greenhouse Gas Storage (Safety) Regulation (Commonwealth)
OSHA Occupational Safety and Safety Administration (USA)
P&ID Piping (process) and instrumentation diagram
PFD Process flow diagram
PHA Plant hazard analysis/preliminary hazard analysis
PSF Performance shaping factor
PSM Process safety management
QRA Quantitative risk analysis
SFARP/SFAIRP So far as is reasonably practicable
SHI Substance hazard index
SMS Safety management system
SW Software

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Main Equipment

Swapan Basu , Ajay Kumar Debnath , in Power Plant Instrumentation and Control Handbook (Second Edition), 2019

1.4 Boiler Feed Pumps

The outlet of the deaerator is connected to the BFP suction and from there the working fluid is called "feed water (FW)" and reaches the boiler proper with the help of boiler feed pumps. It impels the FW with requisite pressure dictating the operating point of steam generation. BFPs are always supplied in a redundant configuration to avert interruption of operation.

Normally one motor-driven BFP is kept for start-up and emergency situations and one or two turbine-driven BFPs (may also be motor) are kept for operating up to a full load.

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Mechanical Seals

Heinz P. Bloch , in Petrochemical Machinery Insights, 2017

Conversion Cost and Savings

This case history involved converting eight multistage boiler feed pumps from the traditional soft packing gland to a plan 23 mechanical seal arrangement (plan 23 was illustrated in Chapter 21.4). As the reader no doubt knows, whenever packing is used, one must reduce rubbing friction and damage to shaft and packing. The packing gland follower must be adjusted, and some leakage must be allowed. One aims for a drip rate of one drop per second to assist in cooling and lubricating the shaft contact region. As packing and shaft wear, periodic adjustment will be needed, and a competent workforce is needed to strike a balance between excessive tightness (too many repairs) and too much gland leakage. Ask yourself what this labor component would cost.

In any event, the boiler feed pumps incorporated packing glands at both drive and nondrive ends. Although installed at a power generation facility, this arrangement is typical of many applications around the world at chemical works and refineries. Most of the feedwater pumps installed in this time frame had been fitted with packed glands, and many continue to run today using this outdated approach. Leakage from the packed glands will be a pure loss to the operation. In this example, the boiler feed was at 121°C, and losses through the packed gland had to be made up with water from the treatment plant. The calculation of the energy loss is based on the energy required to take the makeup water from 10°C to a feedwater temperature of 121°C. The steam generators were gas-fired, and the heat energy requirement could be translated into a net CO2 contribution. Because plant manpower had been reduced, gland follower adjustments were only made when the leakage was severe. As a result, the average leakage rate from the pumps was about 1   L/min per gland.

With eight boiler feedwater pumps and 16 glands leaking on average one quart (roughly 1   L) per minute per gland, energy loss was calculated at 124   kW. The plant operates 24   h per day, 365 days per year, causing an annual energy loss of 1,086,240   kWh. These energy savings are purely based on heating requirements and do not include energy costs for water treatment, deaeration, and pumping. It is worth noting that these energy savings do not include possible pump power reductions. The stated energy savings refer to the combustion process and boiler operation costs only.

Site personnel determined that the combustion process emitted 0.0282   kg of CO2 per liter of water heated. With losses of 1   L per minute per gland, the calculated savings amounted to 237   tons of CO2 per year. Just to compare, an average European high-efficiency diesel-fueled vehicle covering 20,000   km (12,500   miles) per year would emit 3.2   tons per year. The savings equate to removing about 80 automobiles from the roads. In some parts of the world, very substantial carbon tax payments are eliminated by intelligent sealing pursuits.

Aside from any tax issues, the curtailment of gland leakage would require employing trained craftspeople who do the gland adjusting day in, day out. Training, rewarding, and retaining these crafts has become an insurmountable challenge for most facilities. Reliability-focused engineers will make a compelling case for using mechanical seals with flushing in accordance with plan 23.

Reliability-focused engineers and managers will make it their obligation to understand water management systems that keep pace with 21st century thinking. Some such systems go well beyond API flush plan 23, and special opportunities abound in the power generation, mining, and pulp and paper industries. Substantial profitability and reliability gains are possible by making a competent seal manufacturer your technology resource. Some old and unprofitable sealing arrangements (read packing) may benefit from redesigned seal housings; see Fig. 21.8.1.

Fig. 21.8.1. Designing and reconfiguring a new mechanical seal environment is being discussed here.

 Courtesy Hydro Inc., Chicago, IL, http://www.hydroinc.com.

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Main Equipment

Swapan Basu , Ajay Kumar Debnath , in Power Plant Instrumentation and Control Handbook, 2015

1.4 Boiler Feed Pumps

The outlet of a deaerator is connected to the boiler feed pump (BFP) suction and from there to the popular term of the working fluid—feedwater—to reach the boiler proper. It impels the FW with requisite pressure that dictates the working or operating point of steam generation. BFPs are always supplied in a redundant configuration to avoid interruption of operation. Normally, one motor-driven BFP is kept for startup and emergency situations and one or two turbine-driven BFPs (maybe a motor as well) are kept for operating up to a full load.

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Double-Case Pumps

Erik B. Fiske , in Centrifugal Pumps (Second Edition), 1992

Throttle Bushings.

The most reliable shaft sealing system for large boiler-feed pumps consists of throttle bushings with a custom designed, cold (90° – 120°F) condensate injection system. Pumps have operated for 40 years or more with their original throttle bushings.

The throttle bushing bore, the shaft under the bushing, or both should be grooved. To obtain the desired effect, the following design parameters are varied: the groove cross section, the number of groove starts, the "hand" of the grooves, and the length of the grooved section. The grooves reduce leakage for a given running clearance and increase tolerance to solid particles in the feedwater. They also reduce the possibility of seizureif the pump is subjected to severe operating transients, such as flashing. Shaft sleeves under the throttle bushings are undesirable. They reduce the ability to resist seizure during severe temperature transients.

There are at least five types of condensate injection control systems [2]. The type of control is normally recommended by the pump manufacturer based on the purchaser's feedwater system design. A simple pressure-controlled system is shown in Figure 12-9. Temperature-controlled systems are morecommon. A drain-temperature control system is shown in Figure 12-10.

Figure 12-9. Pressure-controlled throttle bushing injection system

 (from Ashton [2])

Figure 12-10. Drain-temperature controlled throttle bushing injection system.

 (from Ashton [2])

Two waterflood pumps such as the one shown in Figure 12-11 operate in series. The downstreampump has 4,000 psi suction pressure and 8,000 psi discharge pressure. Mechanical seals would not be practical for these pressures. Therefore the pumps are fitted with long throttle bushings that discharge into collection chambers with suitable drain connections. The cold leakage is expendable, and no re-injection system is needed.

Figure 12-11. Double-case waterflood pump for 4,000 psi suction pressure

 (courtesy BW/IP International, Inc. Pump Division, manufacturer of Byron Jackson/United™ Pumps)

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Automatic Control

Dipak K. Sarkar , in Thermal Power Plant, 2015

10.5.5 Pump minimum flow recirculation control (Figure 10.35)

To ensure the safety of large pumps, e.g., boiler feed pump (BFP), condensate extraction pump (CEP), etc., it is essential to maintain a minimum flow through the pump at all modes of operation. This control valve is located on a separate line tapped from either the individual pump discharge or the common discharge header of pumps.

The minimum flow through a pump is maintained by using a pump minimum flow recirculation control valve, circulating fluid from the associated pump discharge line back to its source, i.e., the deaerator feedwater storage tank/condenser hotwell, etc. As long as the fluid flow to the process is at or below the safe minimum limit this control remains in service. When the fluid flow exceeds the safe limit, the pump minimum flow recirculation control valve is closed.

Figure 10.35. Pump minimum flow control.

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