A REVIEW OF STEAM FLOWMETERING · PDF filea review of steam flowmetering technology ... 3.7 rotary-shunt meters ... 6 uncertainty in steam flowmeter measurements

A REVIEW OF STEAM FLOWMETERING TECHNOLOGY

A Report for

National Measurement System Directorate Department of Trade & Industry 151 Buckingham Palace Road

London, SW1W 9SS

Project No:FEUS04 Report No: 2004/69 Date: October 2004

The work described in this report was carried out under contract to the Department of Trade & Industry (‘the Department’) as part of the National Measurement System’s 2002-2005 Flow Programme. The Department has a free licence to copy, circulate and use the contents of this report within any United Kingdom Government Department, and to issue or copy the contents of the report to a supplier or potential supplier to the United Kingdom Government for a contract for the services of the Crown. For all other use, the prior written consent of TUV NEL Ltd shall be obtained before reproducing all or any part of this report. Applications for permission to publish should be made to: Contracts Manager TUV NEL Ltd Scottish Enterprise Technology Park East Kilbride G75 0QU E-mail: [email protected] Tel: +44 (0) 1355-272096 © TUV NEL Ltd 2004

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Project No: FEUS04 Page 1 of 55 Report No: 2004/69

NEL East Kilbride

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Tel: 01355 220222 Fax: 01355 272999

A REVIEW OF STEAM FLOWMETERING TECHNOLOGY

A Report for

National Measurement System Directorate Department of Trade & Industry 151 Buckingham Palace Road

London, SW1W 9SS

Prepared by: N Barton

Approved by: D Boam Date: October 2004 for Mr M Valente Managing Director

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Summary This report was prepared as part of the DTI NMSD 2002-2005 Flow Programme. It describes the results of a review into the use of flowmeters to measure steam flows in the UK. This review was based on an extensive search of published literature and the internet and on discussions with meter manufacturers and meter users. A brief overview of steam systems is given followed by a review of the main types of meter currently used to meter steam. The report also discusses the use of flow measurements and issues associated with calibrating steam flowmeters. Steam is a very efficient energy-transport medium that is used in a wide range of applications, including power generation, chemical processing and industrial-scale space heating. The diversity of steam metering applications makes generalization difficult. In this review it has been found that in the Power Generation sector the use of steam meters is well understood and usually based on internationally recognized standards. In the Process Sector and other sectors, metering practices are somewhat more variable. One of the primary issues that has been identified, which has a major influence on attitudes to flowmetering, is that the high value of steam is not appreciated by many steam users. Differential-pressure meters, in particular orifice plates, are by far the most popular meters used in steam in the UK. This is primarily because they are familiar to many users and also because they can be used without the need for calibration. Spring-Loaded Variable-Area (SLVA) meters and vortex meters are becoming increasingly established alternatives to differential-pressure meters, particularly when higher levels of accuracy at high turndown ratios are required. Ultrasonic meters and Coriolis meters are also likely to take an increasing share of the steam market in the next few years. The primary source of metering error in steam systems is probably the use of meters without accounting for the variation of density as steam pressure and temperature vary. Wetness is also likely to be a major source of error in saturated steam systems. No operational steam flow calibration facilities have been identified in this review although some work is ongoing to look into the feasibility of developing a portable steam calibration rig. Currently, meter users must rely on calibration in alternative fluids.

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CONTENTS SUMMARY……………………………………………………………………. 2 . 1 INTRODUCTION……………………………………………….…………...... 4 2 OVERVIEW OF STEAM DISTRIBUTION SYSTEMS 2.1 Flow Through Steam Mains……………………………….……………….… 5 2.2 Steam Flow Metering Applications……………………….………………… 11 2.3 The Value of Steam……………………………………….……………….… 12 3 STEAM FLOWMETERING TECHNOLOGY……………….……………... 12 3.1 Differential-Pressure Flowmeters…………………………….…………….. 13 3.2 Variable-Area Meters…………………………………………….…………... 22 3.3 Vortex Meters………………………………………………………………… 27 3.4 Ultrasonic Flowmeters………………………………………………………. 29 3.5 Coriolis Meters…………………………………………………………..…... 33 3.6 Turbine Meters…………………………………………………………..…... 35 3.7 Rotary-Shunt Meters……………………………………………….………... 36 4 MEASUREMENTS ASSOCIATED WITH STEAM FLOWMETERING 4.1 Pressure and Differential-Pressure Measurement……………………..... 36 4.2 Temperature Measurement……………………………………….….…….. 39 4.3 Measurement of Steam Quality and Steam Quality Issues……..………. 39 4.4 Boiler Feed and Condensate Return Measurement……………….…….. 40 5 CALIBRATION OF STEAM FLOWMETERS…………………….……….. 41 6 UNCERTAINTY IN STEAM FLOWMETER MEASUREMENTS……….. 43 7 CONCLUSION………………………………………………………………. 44 8 REFERENCES………………………………………………………………. 47 APPENDIX ..………………………………………………………….………………. 50

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1 INTRODUCTION Steam is extensively used as an energy-transport medium, distributing heat and power in many industrial applications. Table 1 provides an indication of the flexibility of steam systems and the range of industries that use steam. The amount of money spent generating steam is very large. For example, 45% of the fuel burnt by US manufacturers (about $18 billion dollars worth in 1997) is used to raise steam [2]. Steam is also commonly used for district heating, particularly in continental Europe and Asia. 60% of homes in Denmark are heated by steam in district heating schemes [3]. It has been estimated that steam flowmeters make up about 10% of the global flowmeter market [4].

Table 1. Uses of steam [1]

The effective use of flowmeters can lead to significant cost savings in most steam distribution systems. The Energy Efficiency Good Practice Guide GPG18 [5] suggests that installation of a flow metering system can result in fuel cost savings of 5 to 10%. However, flowmeters are not always installed in steam systems and many steam meters are not well used. Therefore there is still considerable scope for cost saving within the UK and elsewhere by improving steam flow metering practices. This report was prepared as part of the DTI NMSD 2002-2005 Flow Programme. It describes the results of a review into the use of flowmeters to measure steam flows in the UK. This review was based on an extensive search of published literature and the internet and on discussions with meter manufacturers and meter users. The report provides an overview of the current use of steam flowmeters in UK industry with an emphasis on technical issues associated with measuring the flow of steam. A basic introduction to steam distribution systems and the use of steam meters in these systems is given in Section 2. Sections 3 and 4 describe different steam metering technologies and associate measurements. Section 5 discusses issues associated with calibrating flowmeters for use in steam. Factor affecting the uncertainty of steam flow metering are discussed in Section 6. Conclusions are drawn in Section 7.

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2 OVERVIEW OF STEAM DISTRIBUTION SYSTEMS 2.1 Flow through Steam Mains This section gives a brief overview of steam distribution systems and their operation. A more detailed introduction to the subject of Steam Engineering is given in the Spirax Sarco Learning Centre website [1]. Figure 1 illustrates the behaviour of a fixed mass of water as it is heated and changes into steam. The x axis on the graph, entropy, is a measure of the energy stored in the steam. The red line describes the behaviour of the steam at atmospheric conditions. As heat is added to the water its temperature increases up to 100oC. The heat content of the water at this point is known as the sensible heat. At 1 bar (absolute) the sensible heat is about 419 kJ/kg. Adding further heat causes the water to boil and the quality of the steam (the mass fraction of vapour, x) increases. Steam whose quality is less than 1 is known as saturated steam. Adding heat to saturated steam increases the quality of the steam, but it does not change its temperature. Therefore if the pressure of saturated steam is known its temperature is also known. As pressure is easy to control the temperature of saturated steam can also easily be controlled.

Figure 1. A temperature-entropy diagram showing the phase-change

behaviour of steam If sufficient heat is added to saturated steam the quality increases to 1, and with further heating it becomes superheated steam. The energy required to change water at 100oC and 1 bar to superheated steam at 100oC and 1 bar is about 2257 kJ/kg and is known as the latent heat. Superheated steam can be regarded as a dry gas. Unlike saturated steam, adding heat at a fixed pressure will cause an increase in temperature. Superheated steam is used in steam turbine generators and in steam main systems to avoid condensate problems. However it is less efficient in heat transfer applications and consequently most steam systems operate predominantly with saturated steam.

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Increasing the steam pressure increases the amount of energy required to boil the water (the sensible heat) and reduces the latent heat.

Figure 2. Simplified diagram of a boiler

Steam distribution systems typically comprise a boiler and a steam main with a series of pipes teeing off to different processes. The flow rate, temperature and pressure at various points are adjusted via control valves. The flow conditions in steam pipework are highly dependent on the capacity and control of the boiler generating steam for the system. Figure 2 shows a simplified diagram of a boiler. Essentially boilers comprise a pressurized vessel, partially filled with water, which is heated by burners. At start-up, the control valve downstream of the boiler is closed and as the burners heat the water it boils, steam fills the steam space and the pressure in the boiler increases up to the desired pressure. At this point the control valve is opened to let steam flow into the steam main system. The cold steam main is likely to contain condensate and further condensate will be generated when the steam condenses on the cold pipe walls. Suddenly opening the control valve can cause slugs of condensate to be carried at high velocity through the steam pipework. Slugs impacting on fixtures such as valves or bends cause a phenomenon known as waterhammer. This can be very damaging. To avoid water hammer and problems with thermal loading, the boiler control valve is opened slowly, in a controlled manner. In some systems, line pressure may have to exceed a certain value before condensate return lines remove condensate efficiently. This can exacerbate condensate build-up at system start-up. Once the steam distribution system is up to temperature, the boiler pressure is controlled by adjusting the control valve and burners. Level sensors are used to adjust the boiler water feed flow rate and hence the water level in the boiler. Some liquid droplets, generated by splashing at the water-steam interface, are carried into the steam flow. A modern boiler will typically produce steam in the quality range

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between 0.94 and 0.97. If superheated steam is required, this is generally achieved by installing a heat exchanger on the boiler outlet. Separators are also sometimes installed immediately downstream of the boiler to improve the steam quality. In a poorly controlled or badly sized boiler an increased demand for steam can cause a significant drop in boiler pressure. This increases the bubble size and splashing at the water surface and the mass of water that leaves the boiler in the form of droplets increases. A poorly specified or operated boiler is therefore likely to produce poor quality steam, particularly in a system in which demand varies considerably over the day. The flow regime in steam pipelines depends on the amount of condensate present and the velocity of the vapour phase, as illustrated in Figure 3. At low steam velocities condensate runs along the bottom of the pipe. As the steam velocity increases, waves on the liquid surface increase in height and, if enough condensate is present, they can bridge across the pipe to cause a slug and hence waterhammer problems.

Figure 3. The development of slug flow as steam velocity increases in a steam main

Figure 4. Annular flow in a horizontal pipe

At higher steam flow rate, an annular flow regime can occur in which condensate is carried in a liquid film on the pipe walls with a high-velocity core of vapour and droplets (see Figure 4). To avoid waterhammer and droplet erosion problems, most saturated-steam pipes are sized to limit the steam velocity to less than 35 m/s and hence minimize condensate pick-up. Poorly designed pipework can cause condensate to build up and hence increase the chances of waterhammer problems, as shown in Figure 5. Most steam pipework systems use inclined pipes and condensate pockets to collect liquid and tees are arranged at the top of pipes to prevent condensate entering process plant off the

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steam main (see Figure 6). These methods are effective at removing the bulk of the condensate provided steam traps are drained on a regular basis. However, where a high degree of dryness is required (e.g. in the flow entering a flowmeter), steam separators should be used. A well specified separator can increase steam quality to 0.98 or more [1].

Figure 5. Pipework installations that promote condensate build-up [6]

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a) Inclined pipe

b) Condensate pocket c) Steam main branch

Figure 6. Pipework arrangements to promote condensate removal [6]

Figure 7 shows the operating conditions experienced by different flowmeters, taken from various sources. In most power-generation applications and in many refinery operations, steam is superheated and no condensate will be present, except at start-up. As waterhammer and erosion are not considered to be a problem in superheated systems, flow velocities of between 50 and 70 m/s are normal. In most applications, heat transfer is the primary consideration and there is little perceived advantage in using extra energy and plant to superheat steam. Consequently most steam systems operate with saturated steam. The wetness of saturated steam is rarely measured and information on typical steam wetness values varies somewhat. It is generally assumed that most of the condensate is produced by the boiler and steam quality is in the 0.9 to 1 range. However, in poorly maintained and operated systems, steam can be significantly wetter than this [7]. In geothermal and nuclear applications, steam quality is often less than 0.9.

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Figure 7. Operating conditions of selected steam systemsSteam Flow Metering Applications

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The required performance of a steam flow meter is highly dependent on its purpose. Ideally a flowmeter will have a low uncertainty and a high repeatability and sensitivity over a wide range of operating conditions. However, in many applications not all of these parameters are essential. The steam flow measurement sector is fairly sharply divided into two distinct markets. In power-generation and custody-transfer applications, steam is usually superheated and the measurement priorities are low uncertainty and low pressure loss. In smaller steam-main applications, steam is usually saturated and the priority is to get a good meter turndown ratio. Flow measurements made for steam custody-transfer purposes are becoming important as, increasingly, one company will generate steam and sell it to another company on a neighbouring site. In large chemical production sites with numerous processing units, the supply of steam is now tending to be handled by third party companies, often from local combined heat and power (CHP) plant. In this case, agreements between the vendor and the customer typically require mass flow uncertainty to be less than 1%. The Climate Change Levy (CCL) paid by CHP plant operators can be reduced depending on the amount of steam supplied to third parties and steam export meters may therefore be subject to similar levels of scrutiny as fiscal oil and gas metering systems. Similarly, “pseudo-custody-transfer” applications are becoming more frequent in which utilities and other plant units are treated as separate business entities to evaluate performance. In both cases, a low uncertainty and high repeatability are required. When steam flow is used as a measure of energy consumption, the amount of energy returned to the boiler in the form of condensate should be metered and accounted for. In steam-turbine generator plant, the flow of superheated steam to the turbine inlet is measured and used as an input into the calculated turbine efficiency. Contracts between the plant manufacturer and operator usually use this efficiency measurement to determine large financial bonuses and penalties and consequently it is important that this inflow measurement has a low uncertainty. Typically, nozzles are used in this application and all measurements are made to appropriate ASME, ISO or DIN standards. In chemical plant, flowmeters are frequently used to aid process control. Typical applications include measurements of feed flow to reactors, flow into and out of separators or distillation columns, flow through heat exchangers and flow into and out of tanks and jacketed steam flows. The primary aim of process-control flow measurements is to ensure the optimal composition of process products and the optimal efficiency of the process. In most processes, good repeatability is essential but low uncertainty is less important. Most steam flow measurements in process plant are made for monitoring purposes. Measurements are used to identify problems, to detect leaks, to allocate costs, to calculate energy efficiency, to monitor steam balances and to identify maintenance requirements. In this case, only high repeatability is required. Implementation of Monitoring and Targeting (M&T) systems consistently results in cost savings and should be considered by any operator spending more than £30,000 a year on fuel to raise steam [5]. In general, flowmeter manufacturers have reported an increased interest in steam flowmetering owing to the introduction of the Integrated Pollution Prevention and

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Control (IPPC) Directive (96/61/EC). However, this has not been dramatic and some manufacturers report that this increased level of interest in now tailing off. Case studies in the Appendix [5] give a feel for typical applications of steam meters in a range of industries. 2.2 The Value of Steam One of the primary reasons for metering steam is to determine the energy usage and ultimately the cost of various processes. In making this calculation, it is important to be able to determine the value of the steam. There are well-defined methods of assessing the economics of steam systems [8, 9]. Table 2 provides some feel for typical costs associated with generating steam, however the value of steam depends heavily on whether it is being generated for a specific purpose or whether it is a by-product of some other process. For example, a study carried out by a large plant operator about ten years ago concluded that the value of the steam they produced varied from 50p/tonne to £20/tonne depending on its source and ultimate use. Steam has traditionally been perceived as being a “free” resource in the Process Sector, despite its high value. The variable perceptions of the value of steam have a significant impact on the perceived benefit of installing a steam metering system.

Table 2. The cost of raising steam (based on 2001 prices) [1]

3 STEAM FLOWMETERING TECHNOLOGY No one type of meter is ideal for metering steam in all applications. This section gives an overview of the main methods currently used to meter steam and some additional techniques that are likely to become more popular in the medium term. It aims to give a feel for the advantages of some meters over others. Ideally a flowmeter will be accurate, reliable, robust, and easy to use and install. In steam systems, the following qualities are particularly desirable: 1. The ability to operate at high temperatures and pressures

Obviously the flowmeter must be able to operate at the steam flow conditions or else methods must be available to insulate it from the steam

2. Good accuracy over a large turndown The inherent variability of flow and pressure in steam systems makes a high turndown ratio important in many steam applications. Equally, insensitivity to pressure variations is helpful.

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3. A mass flow output Nearly all steam metering applications require a mass flow measurement. This can be achieved either by a direct mass-flow output or a volumetric output combined with a steam density measurement

4. An ability to resist the effects of condensate The ability to cope with waterhammer and droplet erosion is important in most steam meters. Even in superheated steam applications, meters are likely encounter condensate at start-up. Insensitivity of flow measurements to wetness is particularly important in saturated-steam flow measurement. Corrections for wetness depend on knowing the steam quality and this is difficult to measure. Upstream separation is usually the only viable option.

5. Reduced calibration requirements It is more difficult to perform an accurate calibration of a flowmeter in steam than in most other fluids. Any metering method that eliminates the need for calibration (e.g. a standards-based method) is at an advantage over flowmeters that require calibration at operational conditions.

6. Low pressure loss and flow disturbance In many steam systems, a high pressure is required to operate the boiler correctly and the pressure loss through the flowmeter will not impact significantly on operating costs. However, in other systems an increased pressure loss through any component will increase boiler fuel consumption significantly. Depending on the operating conditions, flowmeters that cause a significant blockage in the flow may therefore have a significant financial impact in the long term. It has been suggested by on meter supplier that blockages may also help to entrain and break up condensate droplets in saturated steam. This may have an impact on downstream processes that require dry steam.

7. Flexible ranging It is generally recognized that most steam pipework is over-sized. Consequently, many flow meters are oversized and so operate at the lower end of their range. In these cases it is advantageous to use a flowmeter whose design allows the use of restricted measuring sections or whose measuring range can be re-ranged in a flexible manner to accommodate this. The alternative is to install a meter with a high turndown ratio.

3.1 Differential-Pressure Flowmeters Differential-pressure meters, and in particular orifice plates, are by far the most common flowmeters used in steam. Differential-pressure flowmeters comprise a partial blockage in the pipeline (the primary element) and a method to measure the pressure difference across that blockage. Differential pressure across the primary element increases with flow and the measured differential pressure is used, in conjunction with a meter-specific discharge coefficient and a fluid density value, to calculate the mass flow rate through the meter. The performance of differential-pressure meters depends on the primary element and the associated differential-pressure and temperature measurements. This section discusses the application of the most popular designs of primary element. Section 5.1 and 5.2 discuss issues associated with pressure, differential-pressure and temperature measurement.

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The use and manufacture of orifice plates, Venturi tubes and nozzles is described in the ISO 5167 standard [10]. This makes them attractive in that they measure to a well defined uncertainty without the need for calibration. As they are used in many other flow measurement applications, personnel are likely to be familiar with them and, depending on the design used, they can be a relatively cheap option. Their mode of operation also makes them relatively insensitive to pressure fluctuations when compared with some alternative metering methods [11]. Differential-pressure meters are affected by thermal expansion and, when low uncertainty of measurement is required, suitable corrections need to be applied. Orifice Plates Approximately 80% of industrial gas and steam flow applications in the process sector use differential-pressure meters [11] and in steam applications the vast majority of these meters are orifice plates. Some older power stations use orifice plates to meter steam entering steam generator sets, but owing to their high pressure losses these meters have tended to be replaced over the years. Orifice plates comprise a flat plate with a machined central hole and pressure tappings on either side, as shown in Figure 8. A number of propriety design variations are available with different flanging arrangements, tappings arrangements and extra features such as drain holes. Multivariable orifice-plate flowmeters, which output flow rate, temperature, line pressure and differential pressure, are also available. Probably the primary advantage of orifice plates (and ISA 1932 nozzles and Venturis which are discussed below, is that they are fully described in the ISO 5167 [10]. If an orifice plate is manufactured and installed to specifications given in ISO 5167, its uncertainty associated with the primary device will be 0.5% (for the most commonly used beta ratio plates). Additional uncertainty, associated with secondary instrumentation such as differential-pressure transmitters and temperature measurements, can be calculated relatively easily to provide a reliable metering uncertainty with a reduced requirement for an initial meter calibration. This is a significant benefit in steam flow systems as it is highly unlikely that calibration at representative conditions is an option. However, it should be recognized that these meters should be recalibrated periodically to account for such factors as primary element wear and long-term transducer drift.

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Figure 8. An orifice plate flowmeter [12]

Further advantages of orifice plates include their low cost, relative ease of installations and the fact that they are very robust in many applications. They are also popular because of their familiarity and proven track record. The primary disadvantage of orifice plates is that they have a low rangeability (typically 4:1, up to 10:1 with a modern differential-pressure transmitter) and they cause a relatively high pressure loss across the meter. This is particularly problematical in those steam systems in which flow usually varies considerably. It is reasonably well established that steam pipework tends to be oversized for its application and anecdotal evidence suggests that many orifice plate flowmeters are poorly sized and operate below their designed flow range. Orifice plates require relatively long upstream straight sections (up to 100 diameters) and they are sensitive to upstream pipe roughness. Ideally they should be installed in customized flow tubes with flow conditioners. However, this is rarely the case, and many orifice-plate steam meters are in error owing to poor installation. Ideally, orifice plates should be inspected and cleaned on a regular basis. However, this is rarely done in steam systems and it is not uncommon for meters to be installed for decades without being removed. Condensate can have severe effects on orifice plates in steam applications. Water hammer can cause plate buckling and droplet (and rust particle) erosion damages the sharp edge of the orifice. Both of these problems can result in flow measurement errors of the order of a few percent. Orifice plates can act as dams collecting condensate running along the bottom of the pipe. To avoid this problem a small drain hole is often drilled at the bottom of the orifice plate. Occasionally flow will be diverted around an orifice plate installation during system start-up to avoid damage by waterhammer and erosion.

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Figure 9. Wet steam correction factor for a 2” β=0.75 orifice plate [13]

Mottram et al [6] provide a good overview of the effects of wet steam in differential-pressure flowmeters and other common steam meters. It should be noted that the effect of condensate on differential-pressure steam meters depends on a number of factors, including the saturated-steam density, and the meter orientation and geometry. An example of the effects of wet steam on orifice plates is provided by Hussein and Owen [13]. They tested a 2” β=0.75 orifice plate meter in wet steam flow at 4 and 6 bar for dryness mass fractions down to 0.84 at flow rates between 306 and 486 kg/hour. Results (see Figure 9) were plotted in terms of a correction factor, F:

+=

metermeter

refl,refg,

.Qmm

Fρ Equation 1

Figure 9 shows that an over-measurement of about 10% occurred when the steam quality was 90%, demonstrating that very significant errors can occur in orifice plates in wet steam. A large amount of work has been done on correcting orifice plates in wet steam flows, but this has tended to concentrate on the high wetness fractions that occur in nuclear and geothermal applications [14, 15, 16]. Hussein and Owen found that the correlations of James [14] and Murdock [15] best fitted their test data.

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Venturi Tubes Venturis are essentially a reduced-bore section of pipework comprising a reducer section (known as the convergent section), throat section and a divergent section (see Figure 10). Differential pressure is measured between a tapping upstream of the convergent section and a tapping at the throat.

Figure 10. A classical Venturi tube

When compared with orifice plates, Venturis are highly resistant to water hammer, erosion and build up of dirt. Their streamlined shape also reduces the pressure loss across the meter considerably. They are more expensive to purchase and, as they are relatively long, more radical pipework modifications are required to install a Venturi. Like orifice plates, their use is described in ISO5167 [10] and consequently they tend to be used in steam systems in which it is perceived that orifice plates would be easily damaged, or when energy losses cannot be tolerated in the system. However, they are more difficult to remove, inspect and clean than orifice plates. The uncertainty of Venturis is slightly higher than that of orifice plates being up to 1% as defined in ISO 5167 with a similar rangeability (about 4:1). The latter is a disadvantage in steam systems. They are less sensitive to flow disturbances caused by upstream pipework and pipe roughness, but they should still be installed in metering tubes and possibly with a flow conditioner. A range of correlations have been developed, based on experimental tests, that model the effects of steam-water mixtures in Venturis, most notably by Murdock [15] and Chisholm [16] and, more recently, in wet gas by de Leeuw [17] and Steven [18]. In a typical steam system, a Venturi will be less sensitive to wetness effects than an orifice plate and is likely to be in error by a few percent. Figure 10 (which is based on data from tests performed at NEL on Venturis in wet-gas mixtures [19]) gives a feel for the likely behaviour of a Venturi in wet steam.

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Figure 11. The effect of quality on mass flow measurements of a Venturi tube in a wet-gas mixture

Nozzles ISA 1932 nozzles and ASME nozzles are the third main type of differential-pressure flowmeter defined in ISO 5167 [10] and, in many respects, they can be regarded as a compromise between orifice plates and Venturis. For general applications, they are more popular in the US than in the UK. In the UK they are primarily used in power generation applications, particularly for the measurement of steam entering HP turbines in steam generator sets. They have a number of features that make them more suitable for steam use than orifice plates and consequently they are more common in steam systems than other metering applications. They are primarily used for Reynolds numbers above 10000 in high-velocity high-temperature applications. In steam systems in the UK they are probably more common than Venturis but considerably less common than orifice plates.

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Figure 12. ISA 1932 nozzles in alternative installations

Figure 12 shows ISA 1932 nozzles in alternative installations. They function in a similar way to orifice plates, but their more streamlined shape reduces the pressure loss across the device. They are more resistant to droplet erosion and waterhammer. They are more difficult to manufacture than orifice plates and their price tends to be intermediate between orifice plates and Venturis. In addition, they are more difficult to remove than orifice plates, making cleaning and inspection more of an issue. Nozzles can be installed between flanges and their sensitivity to upstream pipework is similar to that of Venturis. Ideally they should be installed in a metering tube, possibly with a flow conditioner. Power-station-performance measurement installations are nearly always governed by relevant standards (e.g. ISO 5167 or ASME PTC6 [20]) and consequently they are generally well designed. In addition, as the steam being measured is superheated, errors owing to wetness are effectively eliminated. Outside the power sector, the quality of installation and operation of nozzles is more variable. However, in general and as with Venturis, their selection over orifice plates implies a specific metering requirement and an appreciation of metering issues and, as a result, nozzle installations tend to be better than those for orifice plates. The uncertainty of nozzles is similar to that of Venturis and orifice plates, as is their turndown, and consequently they are not well suited to systems with large fluctuations in flow. Figure 13 compares the performance of an orifice plate and a nozzle in wet gas [21]. In this graph the two-phase multiplier value Φg is the ratio of measured flow rate to the gas flow rate. Figure 13 suggests that nozzles are more sensitive to wetness effects than orifice plates.

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Figure 13. Effect of wetness in nozzles and orifice plates [21]

Multiport averaging Pitot tubes Multiport averaging Pitot tubes consist of a tube that spans the pipe with upstream-orientated tappings that measure the mean stagnation pressure of the flow (see Figure 14). The difference between the stagnation pressure (high-pressure) tappings and a downstream static-pressure tapping is used to calculate the flow rate through the meter.

Figure 14. A multiport averaging Pitot tube Multiport averaging Pitot tubes are often used as an alternative to orifice plates and nozzles in power station steam applications. Although available in spool form, they are principally used as insertion meters and this makes them easy to install. They also present little blockage to the flow and consequently cause low pressure losses. This has made them a popular choice in the process sector. A range of proprietary designs are available, including multivariable meters that provide a measure of mass flow, pressure, temperature and density. The main disadvantage of averaging Pitot tubes is that the pressure differential is small. This is not a major issue in high-velocity flows and these meters are well

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suited to many power generation and the superheated-steam applications. However, in smaller scale, saturated-steam, applications the low pressure differential limits their turndown ratio and this can be a serious disadvantage. As with any insertion meter, the pipe cross-sectional area is used in the calculation of flow. The standards for steam pipework allow variations of up to 5% in cross-sectional area, which will translate into a 5% volumetric flow measurement uncertainty in any insertion meter installed into a pipe that has not been measured. Similarly, if the tube is not installed precisely across the diameter of the pipe or if it is not inserted to the correct depth, measurement errors will occur. Some modern designs make installation and adjustment easier in this respect. Multiport averaging Pitot tubes are also highly sensitive to flow disturbance by upstream pipework components, such as bends and valves, and to rough upstream pipework. Consequently they should be installed in metering runs. However, this is rare as it somewhat negates the purpose of an insertion meter. Some manufacturers have indicated that non-condensable gas can build up in Pitot tubes and that this causes their measurements to drift significantly over time. Theoretically, uncertainties of 1% are achievable over a 5:1 turndown, although in practice it is rarely possible to reduce uncertainty below about 5% for an insertion tube. In particular their accuracy reduces at low flow rates and this limits their use in steam systems with highly variable flow rates. In newer designs, turndown ratios have been improved by designing the bar to increase differential pressure and by the use of better differential-pressure transmitters. Very little information is available on multiport Pitot tubes in wet steam. Tappings may be blocked by condensate, particularly the bottom-most tappings when condensate is running along the bottom of the pipe, and ideally they should be installed in an inclined or vertical pipe to eliminate this possibility. Some modern tubes are specifically designed to reduce the chances of hole blockage. In general, multiport Pitot tubes are thought to be insensitive to minor erosion. Their resistance to water hammer will vary depending on design: thin-stemmed insertion meters are likely to be damaged by slugs of water. Other Differential-Pressure Devices A range of alternative differential-pressure devices exist that are occasionally used in steam flow metering applications, some of which are illustrated in Figure 15. Most of the design variants allow the flow of condensate to pass unimpeded along the bottom of the pipe. None of these meters are recognized in international standards, although the V-cone is recognized by Measurement Canada for natural-gas custody-transfer applications [22]. The V-cone is probably the most popular proprietary differential-pressure meter and is known to perform comparatively well in wet-gas (and consequently wet-steam) flows [19]. Although very popular for steam flow measurement in North America, the V-cone meter is uncommon in the UK. Information on the performance of other differential-pressure meters in steam is very limited.

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a) V Cone b) Eccentric Orifice Plate

c) Segmental orifice plate d) Wedge meter

Figure 15. Alternative differential-pressure meters

3.2 Variable Area Meters Cone-and-Float Variable-Area Meters An illustration of a cone-and-float-type meter, the most well-known of which is the Rotameter, is shown in Figure 16. Increasing flow caused the float to rise and its position in the tapered tube gives a measure of the flow rate through the meter. In steam applications, the tube is typically stainless steel and the float position is measured by means of a magnetic transducer. This type of meter is cheap, relatively accurate (with a typical uncertainty of 1.5% over a 10:1 turndown) and easy to install provided a vertical pipe section is available. However, it is limited in size and mostly used for low flow applications. No information has been found on the performance of these meters in wet steam applications; however Mottram et al [6] suggest a possible correction method. As these meters are only suitable to measure low flow rates, erosion and waterhammer problems are unlikely to be an issue.

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Figure 16. Cone-and-float variable-area meter

Spring-Loaded Variable-Area Meters (SLVA) Figure 17 shows the principle of the spring-loaded variable-area meter. It comprises a spring-opposed cone that is arranged to increase the flow area through a fixed orifice as the flow rate increases. The differential pressure is measured across the orifice and meters are typically designed such that volumetric flow rate varies linearly with differential pressure. More-modern SLVA meters llinearize their measurements electronically.

Figure 17. Spring-loaded variable area meter

The performance of variable-area meters varies between designs. The most popular and well-known SLVA steam meter is the Gilflo meter [23], shown in Figure 18. The primary advantage of Gilflo meters (and other SLVAs) in steam applications is their ability to maintain a low uncertainty (about 1%) over a high turndown (claimed to be up to 100:1). In addition to this, they require few upstream and downstream straight lengths (6D diameters upstream and 3 diameters downstream) and some designs allow installation between flanges. The main disadvantage is they have a relatively high pressure loss (similar to or greater than that of an orifice plate depending on the

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flowrate). These meters are usually calibrated before use and ideally should be recalibrated periodically, although in practice this is rarely done. The fact that they have moving parts would appear to be a disadvantage, although these meters are well-proven in steam applications. Figure 19 shows a comparison between the measurements made by an orifice plate meter and other meters (including a Gilflo meter) made by Hardy et al [24] in a two-inch steam main with nominally superheated steam. Agreement between the orifice plate and the Gilflo meter was found to be within ±1.6% of the upper range value (URV), except at lower flows when the difference approached ±2-3% URV. Given the uncertainty of the orifice-plate reference (especially at low flow rates), this suggests that the Gilflo meter performed within its 1% uncertainty specification, although the turndown ratio was found to be 50:1 instead of the claimed 100:1. When the meter was recalibrated in air after about 18 months of continuous service no degradation in performance was found. The work reported by Hardy et al [24] was carried out in the early 1980s and may not reflect the performance of modern meters.

Figure 18. Gilflo SLVA meter [1]

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Figure 19. Measured mass flow rate plotted against mean measured flow

rate of all four meters for Eastech and Yewflo vortex meters, an orifice plate and a Gilflo meter [24].

A development of the Gilflo meter, the DIVA meter [25], uses deflection of the cone as a measure of flow rate. In saturated steam, the DIVA meter uses an integral temperature sensor to calculate the steam mass flow. Neither the Gilflo nor the DIVA meter is intended for use in wet steam, although the latter is marketed specifically for use in saturated steam. No information is available on their resistance to droplet erosion or waterhammer, although their popularity implies a reasonable degree of robustness. Hussein and Owen [13] calibrated a 2” Spirax Sarco Spiraflo SLVA flowmeter meter in wet steam (see Figure 20 and 21). This meter had a spring-loaded flap that closed against the flow and its deflection was taken as a measure of flow (Note that this design of meter has since been superseded by the Gilflo and DIVA meters). Figure 21 shows that errors of the order of 10% could be realistically expected in the measurements of an uncorrected meter in wet steam flows. No data is available on the performance of newer meters in wet steam.

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Figure 20. Spirax Sarco Spiraflow SLVA meter tested by Hussein & Owen

[13]

Figure 21. Wet-steam correction factor for an SLVA meter [13]

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3.3 Vortex Meters Figure 22 shows the principle of operation of a vortex meter. A bluff body, in the form of a shedder bar across the diameter of the meter spool, causes a series of alternating vortices to be shed in its wake. The frequency of this vortex shedding is measured and used in Equation 2, below, to determine the mean flow velocity and hence the volumetric flow through the meter:

Figure 22. Principle of a vortex meter [26]

StAdfQ ..

= Equation 2

In which: Q is the volumetric flow rate (m3/s) f is the measured frequency (Hz) d is the bluff body width (m) A is the pipe cross sectional area (m2) St is the flow Strouhal number For a wide range of Reynolds numbers, the Strouhal number remains constant and hence the flow velocity is proportional to the shedding frequency over a large range of fluid densities and viscosities. Shedding detection methods vary between manufacturers and include thermal sensors, ultrasonic sensors, pressure sensors and the detection of the slight movement of the bluff body by means of a piezoelectric sensor in the bluff body support spindle. Vortex meters are becoming increasingly popular in steam flowmetering applications. Although they are still not extensively used [28], they have a greater prevalence in new installations and they are often used to replace older meters, such as orifice plates. Vortex meter performance varies from model to model, but typical uncertainty values range between 0.5% to 1.5% with a claimed turndown of between 10:1 and 50:1. Their high turndown ratio, coupled with a fairly low pressure loss and a tolerance of high temperatures has made them desirable for many steam applications. However,

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they are not described in standards, limiting their use in fiscal and custody-transfer applications. Because of the high cost of large vortex meters, most meters in service are 6” or smaller. Historically, vortex meters have had problems owing to sensor failure, coating and clogging of components and vibration. The former two issues have largely been addressed by improved meter design. Vibration problems have also largely been solved over the last few years by improved signal processing, making them more suitable for noisy environments [27]. Mass balancing techniques can be used to reduce the meter’s amplitude of vibration [28]. One of the disadvantages of vortex meters is that, unlike many flowmeters, below a certain flow rate they cease to register any flow. In a well-sized meter, this threshold will correspond to about 7% of the maximum flow. However, in a poorly sized meter, this threshold may correspond to 20% of the maximum flow, and consequently the meter turndown will be significantly reduced. To avoid this problem and to maintain a good turndown ratio, vortex meters are often installed in pipe reductions to elevate the flow velocity in the meter, typically to 75 m/s. Indeed, some modern spools have integral reduction sections. This is does not cause significant problems in superheated steam, but it will cause droplet entrainment in saturated systems. It will also cause an increased pressure loss through the meter. Vortex meters are sensitive to upstream flow disturbances and should be installed in a metering tube with a flow conditioner if appropriate. Typically, manufacturers recommend similar installation requirements to those defined in ISO 5167-1 [10] for orifice plates. Two of the attractive features of vortex meters are that they have a roughly linear response with increasing volumetric flow rate and they produce a direct electrical output. Multi-variable meters are available that provide a mass flow measurement based on a temperature sensor and pressure- and temperature-compensated multi-variable meters will be on the market soon. Many modern vortex meters include diagnostics systems that allow meter health checks to be carried out; however anecdotal evidence from meter manufacturers suggests that this facility is rarely used by their customers. Hardy et al [24] tested Eastech VORT-X-CEL 3050 and Yewflo YF105 vortex meters in a 2” superheated steam main. Over an eighteen-month period, both performed (almost) to their specification without any significant problems (see Figure 19). Both meters agreed with an orifice-plate reference meter to ±1.4% URV within their operating range. The Yewflo specification suggested an operating range down to 120 kg/hour, however a lower limit of 140 kg/hour was found to be more appropriate. As noted earlier, the work report by Hardy et al [24] was carried out in the early 1980s and may not reflect the performance of modern instruments. In general, vortex meters are perceived to be very rugged, although manufacturers do not receive a large amount of feedback on the performance of their meters. This suggests either that meter failure is rare or that when a meter fails it is not replaced or it is replaced with a meter from another manufacturer. Opinions on the sensitivity of these meters to erosion differ. Some sources suggest that vortex meters are reasonable insensitive to wear [5], whilst others suggest that they are quite rugged, but sensitive to erosion [29]. Some manufacturers claim that round-edged bluff body shapes minimize erosion effects. Tests have been performed for one of the meter manufacturers that suggest an error of 1 or 2% can be expected in a badly eroded meter [28].

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Hussein and Owen [13] tested a 2” vortex meter in wet steam flow at 4 and 6 bar over a 0.84 to 1 quality range at flow rates between 540 and 929 kg/hour (Figure 23). The vortex meter consistently over-read and the error increased with liquid mass fraction, probably because the increased liquid fraction causes the steam to accelerate, thus increasing the gas velocity detected by the sensor. Figure 23 suggests that errors of the order of 10% could be expected in a vortex meter in a typical wet-steam system. Wet-gas tests at NEL [19] on a 4” Fisher Rosemount 8800A vortex meter agreed reasonably well with Hussein and Owen’s results.

Figure 23. Wet-steam correction factor for a vortex-shedding meter [13]

3.4 Ultrasonic Flowmeters Most modern ultrasonic flowmeters use the transit-time method to measure the mean fluid velocity. In this method a pulse of ultrasound is sent from one ultrasonic transducer to another angled across the meter’s flow tube (Figure 24). The transit time of the pulse is proportional to the mean fluid velocity along the path of the pulse. By measuring the transit time both in the direction of the flow and against it, the volumetric flow rate through the meter can be determined. In general, ultrasonic flowmeters are produced with a range of single and multiple path arrangements. In steam applications, most meters use a single diametric path, as shown in Figure 24. Dual-path designs are occasionally used as shown in Figure 25. In general applications most ultrasonic meters are “wetted transducer” designs with the transducers mounted in a spool and directly in contact with the process fluid as

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shown in Figure 26. Currently in steam all ultrasonic flowmeters use this arrangement. For lower temperature steam installations the transducers are usually in direct contact with the steam. For higher temperatures a thermal buffer material (terminologies include “fibre-acoustic bundles” and “buffer wave-guide technology”) can be used to insulate the transducers from the steam, allowing the use of ultrasonic meters at temperatures up to 500oC. Adequate insulation is essential for ultrasonic meters in steam applications as their measurements are affected by the build-up of condensate in the transducer pockets. For this reason, transducers are always mounted horizontally to facilitate drainage.

Figure 24. Single 45o diametric ultrasonic path configuration

Figure 25. Dual 45o diametric ultrasonic path configuration

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Figure 26. A wetted transducer ultrasonic flowmeter

Clamp-on ultrasonic flowmeters have been available for a number of years for liquid flows. In this type of flowmeter the transducers are mounted in solid blocks that are clamped, or otherwise fixed, onto the outside of the pipe (as shown in Figure 27). This is a very flexible system as it allows flowmeters to be placed in convenient positions (or even moved) without the need to penetrate the pipe. However, clamp-on meters are usually less accurate than equivalent wetted-transducer designs. Recently, a clamp-on meter for use in gas has become commercially available and one manufacturer has carried out limited steam tests on several university district-heating systems in the United States. They have stated that: “The success of a clamp-on steam flow measurement will depend upon a number of factors e.g. steam quality number, pipe size, pipe condition etc. It is essentially possible and proven, but not in all cases.” They also suggest that, at present, the system should be commissioned by the manufacturer.

Figure 27. A clamp-on ultrasonic flowmeter

A third generic variant of the ultrasonic flowmeter is the hot-tap design. In this, the ultrasonic transducers are mounted on a stem that is inserted into a boss-and-valve arrangement mounted on the outside of the pipe. Once installed the transducers are wetted and typically protrude into the flow. This arrangement allows installation of a flowmeter into a pipe without the need for breaking the pipe or shutting down the flow. Hot-tap ultrasonic flowmeters are a very new development in steam. One manufacturer has installed 13 hot-tap steam installations in the UK but no other examples have been identified in this review. Ultrasonic steam flowmeters are reasonably well established as energy meters in domestic district-heating systems [3]. However, they are relatively new to the high-pressure and high-temperature requirements of the industrial market. The first use of ultrasonic flowmeters in a refinery was in the Netherlands in 1995 and they are still

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considerably less common than differential-pressure meters in heavy-duty applications. However, they are likely to become more popular in steam flows, probably primarily in superheated applications where high accuracy, large volume flow measurements are required. Based on the sales of one ultrasonic meter supplier, it is estimated that there are currently in excess of 2000 ultrasonic steam installations world-wide. In general applications, ultrasonic flowmeters have proved to be reliable and accurate. Their performance depends on their design, but manufacturers have stated that uncertainties of between 1% and 2% are achievable for spool-type meters in steam flows. In gas flows, turndowns of 150:1 turndown are achievable and, in steam, high turndowns can be expected. No information was available for the accuracy of clamp-on meters in steam, but, based on liquid flow data, an uncertainty of between 5% and 10 % would be expected in a reasonably good installation. The uncertainty of hot-tap installations would be expected to be intermediate between the spool and clamp-on meters, again depending on the installation. No international standards currently exist for ultrasonic flowmeters. However, the American Gas Association has produced the AGA 9 guideline [33] and ISO and British Standards are currently in draft awaiting public comment (ISO 17089 and BS 7965). Currently, the relative cost of ultrasonic flowmeters compared with other flowmeters is very high in small sizes, but it becomes quite competitive as pipe size increases. In common with vortex meters, ultrasonic meters have an electronic output and some models have diagnostic capabilities and multi-variable output options. One of the disadvantages of ultrasonic meters is that they are sensitive to flow disturbances caused by upstream pipework. The sensitivity of meters varies from design to design. However, as a rule of thumb, the more paths a meter has the less sensitive it is. For example, a single-path meter installed a few diameters from a bend may be in error by 10% or more. As single-path meters are common in steam applications, care must therefore be taken to ensure that they are installed with a sufficient length of straight pipework upstream: the normal recommendation from manufacturers is for at least 20 pipe diameters. Spool-type ultrasonic meters are non-intrusive and they therefore cause a negligible pressure loss; this is one of the primary marketing points for these meters. However, it should be realized that this is only an advantage in some steam applications. As they present little resistance to the flow, they are also unlikely to suffer erosion or waterhammer damage. The resistance and durability of intrusive hot-tap designs will depend on individual designs. No published information has been found on the performance of ultrasonic meters in wet steam, although it is known that they can tolerate some condensate. Tests performed at NEL on ultrasonic flowmeters in wet gas [34] suggest that in wet steam an ultrasonic flowmeter is likely to over-read, but to a lesser extent than a differential-pressure flowmeter. If the ultrasonic paths are interrupted by a continuous stream of liquid (e.g. if the transducer ports clog with condensate), the meter error is likely to be very large.

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3.5 Coriolis Meters Coriolis flowmeters operate on the principle that inertia forces are generated whenever a particle in a rotating body moves relative to that body in a direction toward or away from the centre of rotation. A practical implementation based on this principle was developed following the realization that the radial acceleration that has to be applied to the flowing fluid could be produced by a rotation alternating in opposite directions. This was achieved by using a vibrating or oscillatory motion rather than a rotating system and led to the production of the first commercial Coriolis meter. The vibrating tube may be straight or looped and can take many different forms. To date, U-tube designs and their variants have been most popular. A U-tube design is illustrated in Figure 28.

F

F2Flow

Flow

F1

Figure 28 A schematic diagram of a U-tube Coriolis meter [35] The driving force required to keep the tube in constant vibration is minimized when the frequency of vibration is at, or close to, a natural frequency of the fluid-filled tube. In most meters, the vibrating tube is anchored at two points and the driving force is applied at a position usually midway between two anchor points (point F in Figure 28). The flow then gives rise to oscillatory deflections acting in opposite directions in the two halves of the tube. Using transducers situated at appropriate points (F1 and F2 in Figure 28) the deflections can be detected. When the fluid is at rest, the deflections at the sensing points are in-phase. When flow is present, Coriolis forces act to produce a secondary deflection, resulting in a phase difference in the transducer signals. This phase difference, ∆Φ, is directly proportional to mass flow rate, i.e.

φ∆= kM& Equation 4 where k is a constant that is dependent on the mechanical characteristics of the system. Many commercial meters employ a double-tube configuration with the driving and sensing transducers connected between the conduits. The tubes are then made to vibrate in opposite directions and the sensors detect the relative movement. This removes noise in the form of common-mode vibration input from the environment.

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Straight-tube designs are also available for circumstances when U-tubes are problematical. As the tubes are driven at resonance, a measurement of density can be made by determining the resonant frequency. Furthermore, temperature transducers are generally incorporated to allow compensation for changes in the elastic modulus of the tube material. Coriolis meters are microprocessor based, and can provide signal information as well as output signals based on various combinations of the mass flow, density and temperature measurements. Coriolis meters were originally developed for liquid metering applications, but they are now well established in gas [33] with over 20,000 gas applications world-wide. Steam applications are common for gas Coriolis meters although, as they are a new technology, they are still relatively rare in the UK compared with differential-pressure meters, vortex meters and variable-area devices. As Coriolis meters are mass flowmeters, no additional pressure or temperature measurements are required for density compensation. Indeed, density and pressure measurements are usually standard meter outputs. They are accurate over a large flow range with typical uncertainties of 0.35% over a 50:1 turndown and 1% over a 100:1 turndown being quoted [33]. It is also claimed that they can be calibrated in water and used in gas without any increase in uncertainty although, in the case of steam flow, this would assume that integral temperature corrections produce no additional error. They require no straight pipework upstream and have a relatively low pressure drop. AGA, API, Measurement Canada, PTB and NMi are all developing standards for Coriolis meters [33] and consequently they are likely to become increasingly acceptable for fiscal and custody-transfer purposes. They are limited in size to about 6 to 8 inches (or less if high turndown is required). In the past Coriolis meters have suffered from being overly sensitive to external vibration and noise. Although modern meters have improved in this respect, care should still be taken to minimize these effects. They are relatively expensive, although, as with other low pressure drop meters, the gains in reduced energy losses should be considered when comparing these meters against alternative technologies. Coriolis meters are affected by erosion and wet steam and they are usually recommended for use in dry steam. Exposure to wetness does not affect the meter calibration but it is likely to reduce metering accuracy. No data have been found on the performance of Coriolis meters in wet steam. However, wet-gas tests were performed at NEL [20] on a 100mm Endress and Hausser Promass 63F. Figure 29 shows typical results from these tests. Increasing liquid fraction caused an over-measurement and the results suggest that errors of the order of -10% to -15% could be expected in a typical saturated-steam system owing to wetness effects.

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1

1.1

1.2

1.3

1.4

1.5

1.6

1.7

0.4 0.5 0.6 0.7 0.8 0.9 1

Gas Quality, x

Cor

rect

ion

Fact

or, F

Figure 29. Wet-gas tests of a Coriolis meter at 30 barg.

3.6 Turbine Meters

Figure 30. A turbine flowmeter Turbine meters consist of a free-spinning rotor mounted in a spool, often with an integral stator/flow straightener upstream (see Figure 30). The rate of rotation of the rotor is measured via a magnetic coil or optical pickup and is used as a measure of the flow. At high velocities and with a well designed meter, the pulse rate will be very nearly proportional to the volumetric flow rate. At lower velocities, the bearing friction may cause a significant deviation from linear performance, and a calibration curve is usually used to correct for this effect. Bearing wear will affect the calibration of turbine meters and consequently they can require a relatively high amount of maintenance and recalibration over time. They also vulnerable to bearing damage if flow velocities are beyond their operating specification. Well-maintained turbine meters are quite accurate, having a typical uncertainty of better than 0.5% over a 10:1 turndown. They are quite sensitive to installation errors. They give a volumetric flow rate measurement, so additional measurements are

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required to provide mass flow information. Wet-gas tests [19] suggest that under-measurements of the order of 1% would be expected in typical wet-steam systems. However, as they prone to damage by water hammer and droplet erosion, they are only suitable for metering superheated steam flows and they are rarely used in practice. Some American manufacturers claim that turbine meters are suitable for use in steam, but none of the UK manufacturers do. 3.7 Rotary-Shunt Meters Rotary-shunt meters take the form of an orifice, partially blocking the flow from a steam main and a turbine meter that measures the flow through a pipe loop bypassing the orifice. Rotary-shunt meters are more common in older steam systems as they tend to be less accurate than newer technologies. They are only available from OVAL Corporation in Japan. The mechanical version of the rotary-shunt meter has the advantage of not requiring an electrical supply anid is therefore useful in remote locations. 4. MEASUREMENTS ASSOCIATED WITH STEAM FLOWMETERING 4.1 Pressure and Differential-Pressure Measurement Differential-pressure measurements are intrinsic to differential-pressure flowmeters. In superheated steam, static pressure and temperature measurements are required to calculate steam mass flow rates (unless a mass flowmeter is being used). In saturated steam, either pressure or temperature measurements can be used to determine the steam density, and hence the mass flow. In steam systems, both pressure and differential-pressure transmitters must be installed in such a way as to avoid damage by high temperatures and to ensure that condensate does not affect the measurement being made. This is usually achieved by designing the impulse lines such that they are filled with condensate at all times. This is usually achieved by a siphon arrangement or by including a low point in the impulse lines in which the condensate collects, insulating the pressure transmitter from the steam. Often seal pots (also known as condensate pots) are included in the arrangement and there is usually provision for venting or flushing the lines and filling with water. Isolation valves should also be included in the impulse lines to allow recalibration of the dP transmitters and zero checks. Figure 31 shows some common arrangements for pressure tappings in horizontal and vertical pipes. Ideally, impulse lines should be insulated and trace heated if there is a risk of freezing in cold weather; glycol is sometimes added to the condensate in the impulse lines for this purpose. Gas bubbles in the impulse lines can cause a sluggish response from the pressure transmitters and the impulse lines should be blown through to ensure that no air is trapped in them. It is not uncommon for impulse lines in an exposed position to be accidentally damaged or bent. This can change the depth of condensate in the impulse line causing an offset in the pressure or differential-pressure measurement being made. Correct ranging of differential-pressure transmitters is a major issue in steam metering systems. Differential-pressure flowmeters are often oversized and will then have transmitters that operate outside their intended operating range: as a result measurement accuracy will suffer. To a large extent the turndown of the differential-pressure device will determine the turndown of the differential-pressure flowmeter.

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Typically differential-pressure flowmeters have a turndown of 5:1, but this can be extended to 10:1 by using modern transmitters [11]. Higher turndown ratios are also achieved by using a high-range and low-range transmitter in parallel. Multivariable transmitters are available that measure both pressure and differential-pressure. These transmitters will also accept an input from a temperature transmitter and calculate mass flow rates internally. The primary advantage of multivariable transmitters is that they allow a differential-pressure device to be connected back to a flow computer or data acquisition system via one cable instead of three. Although flowmeters are rarely recalibrated in steam systems, it is common for some maintenance to be performed on pressure and temperature transmitters. This will typically entail zero checks and in-situ recalibration of transmitters. This is typically done on an annual basis, although some manufacturers claim that modern transmitters can be stable for up to 10 years [28].

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Figure 31. Various impulse-line arrangements for steam flow [6, 34]

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4.2 Temperature Measurement Poor temperature measurement can be the primary source of error in dry steam systems [6]. Although thermal-resistive temperature sensors, such as Platinum Resistance Thermometers (PRTs), are quite accurate, having uncertainties of 0.1% or less, their measurements can be highly dependent on their installation. In unlagged steam pipework, there can be a temperature difference of up to 5oC between the pipe wall and the pipe axis. The pressure recovery at the flow stagnation point on the temperature probe can also result in an over-measurement of up to 0.5oC. In some installations, the temperature measurement is taken some distance downstream of the flowmeter and consequently an under-measurement can result. Ideally, sheathed temperature transducers should be installed near the meter in an insulated pipe section. The probe should be inserted such that the centreline temperature is measured and by angling the probe downstream stagnation point errors can be minimized. 4.3 Measurement of Steam Quality and Steam Quality Issues Although steam quality has a significant effect on flowmeter accuracy, it is rarely measured in practice. Quality measurement is usually done by sampling the steam through a multiport sampling tube and measuring chemical concentrations in a condensed sample or passing the sample through a calorimeter [6]. However, it can be difficult to extract a representative sample from the flow and this procedure is generally regarded as being restricted to laboratory applications [35]. At least one alternative steam-quality metering method has been developed [36]. Based on the use of twin slotted orifice plates, this meter is quite specialized and, although marketed as a steam meter, it is not yet in common use.

Figure 32. A good steam metering installation [9]

As will be apparent from Section 3, nearly all flowmeters are adversely affected by condensate and any reasonably accurate saturated-steam metering system should include a separator, as shown in Figure 32. A good separator system will increase steam quality to about 98%. Most flowmeter manufacturers suggest that their

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flowmeter should be used in dry steam, but few explicitly state that their meter must be used with a separator. This is because any flowmeter that explicitly requires a separator will be perceived as being expensive or difficult to install. As steam flowmeter accuracies are usually stated for dry steam, the accuracy gains caused by installing a separator are rarely apparent to the meter user. Systems are available that compensate for steam wetness electronically, but, as wetness is often unknown and is difficult to measure, the value at these systems is open to question. Given that a separator has the added benefit of enhancing a flowmeter’s durability, upstream separation is nearly always preferable to wetness compensation. Some attempts have been made to develop metering systems that can measure both the mass flow rate of and quality of wet steam. The system developed by Hussein et al [36] extended the work of Hussein and Owen [13]. Their meter consisted of a variable-area meter in line with a separator. The separator was tested to determine the relationship between the condensate collection rate and the steam quality. The flowmeter was then calibrated in wet steam to allow correction of its measurements for a known steam quality. Hence the flowmeter could be corrected using the condensate flow measurement from the separator and then the condensate flow rate was added to the corrected steam flow rate to provide a total mass flow rate. In laboratory tests this metering system measured steam quality to within 0.22% and steam mass flow rate to about 1.05% of the reference measurement system. Texaco in Houston have developed a metering system known as the Orifice-choke flowmeter [37]. This is used to measure steam flow in a dispersed network of steamflood injection wells. It uses differential-pressure measurements through a critical-flow choke and an orifice plate in series to determine the steam mass flow rate and the steam quality. The latter is measured to within about 10% over a range of 20 to 100%. 4.4 Boiler Feed and Condensate Return Measurement A relatively popular alternative to measuring steam flow directly is to measure the flow rate of water into the steam system (the boiler feed) and the flow of condensate collected from the steam process and steam traps. Single-phase water flow rates can be measured accurately, typically using a counter on a mechanical pump or occasionally an electromagnetic flowmeter. It is normal practice when operating a boiler to “blow down” periodically to purge accumulations of unwanted substances in the boiler water. Any boiler-feed measurement must account for the steam lost during this process as well as water carried over into the pipework in the form of droplets and any leakage from the system. Condensate return measurements are usually made as a measure of the efficiency of individual processes [35]. This is done on a one-off basis by collecting condensate and flash steam in a weighed container filled with cold water or on a continual basis with a metering pump.

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5 CALIBRATION OF STEAM FLOWMETERS During the course of this project no readily available operational steam flowmeter calibration rigs have been identified in the UK or Europe. As there is a lack of any direct calibration method for flowmeters in steam, meter users must consider alternative techniques if high accuracy is required. This section gives an overview of the issues associated with steam-meter calibration and it discusses the practicalities of calibrating meters in steam and alternative fluids. The aim of flowmeter calibration is to characterize and (if possible) reduce the uncertainty of a flowmeter. This can be done by removing the meter and calibrating or recalibrating it in steam or an alternative fluid or by calibrating it in-situ against a more accurate reference system. In some flowmeters diagnostic or “dry calibration” capabilities may be used to identify problems with the transducers or electronic, although they do not calibrate the meter in the true sense of the word.

Source of Error Dry Steam Lab

Calibration

Gas or Water Lab Calibration

In-Situ Calibration

Meter Diagnostics

Manufacturing defects in the meter

√ √ √ x

Damaged or worn components

√ √ √ ?

Degradation of transducers over time

√ √ √ ?

Electronic or display failure

√ √ √ √

Poor installation

x x √ x

Wetness effects

x x √ ?

Poorly ranged meter or transducers

? x √ x

Inaccurate or no steam density correction

√ x √ x

Inaccurate or no temperature correction

√ x √ x

Incorrect information used in the flow calculation

√ √ √ x

Table 3. Sources of error in a steam flowmetering installation

Table 3 summarizes the primary reasons why a steam flowmeter will be in error and identifies whether these causes of error would be identified by alternative calibration techniques. A dry-steam calibration facility, if one were available, would characterize a flowmeter fairly well, but it would not allow for wetness effects and installation effects that the meter experienced when it was being used. A wet-steam calibration facility would be more representative of saturated operational conditions but it would only be useful if the steam wetness was known, which it rarely is in saturated systems. Most steam flowmeters are calibrated in water or air flows. This tests the ability to meter volumetric flow at low temperatures, but it does not provide information on the high-temperature performance of the meter, its density correction or sensitivity to wetness effects. In water flows it is also difficult to achieve Reynolds

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numbers representative of steam flow. In principle, a sophisticated in-situ calibration of a steam flowmeter is the ideal option. However, the practicalities of in-situ calibration limit its viability in many applications. Four modern steam flowmeter calibration facilities have been identified in this work, of which only one is known still to be in use. Spirax Sarco operate an in-house facility that can be used to calibrate small flowmeters, or larger meters at relatively low flowrates. This facility has been used to calibrate a range of common steam meters. The University of Iowa [38] and Texas A & M University [36] have both built steam flow calibration facilities for specific metering projects; however, the current status of these facilities is unknown. Texaco had an experimental steam flow facility in Houston, which was used for development of steam metering techniques, primarily aimed at managing a steamflood injection well network [39]. Liverpool University also developed a steam flow facility for testing flowmeters in wet and dry steam, as shown in Figure 33 [13]. This test rig comprised a 2-inch test section with superheated steam passing through a steam meter under test. Steam was condensed and the condensate was passed to a weigh-tank to act as a reference. The uncertainty of the reference system was estimated as being 0.6% and the rig had a flow range of 800 to 1250 kg/hour, operating at between 4 and 10 barg. For wet-steam tests, a water spray was injected into the test line at a measured rate and tests were performed for steam qualities varying from 0.84 to 1.

Figure 33. Steam flowmeter calibration rig at Liverpool University [13]

The use of a condenser and weigh tank provides a simple, flexible and accurate reference system, but it has the disadvantage that steam cannot be reused for other processes. Consequently a rig of this type may be expensive on a commercial basis, particularly as high flow rate calibrations are likely to be of most interest to the calibration market. An alternative approach is to set up a steam flowmeter calibration facility that extracts steam from a main and returns it back to the main once it has been used. This is a cheaper option as steam can be effectively resold to the supplier and hence costs can be reduced. However, suitable separation and control equipment will be required to provide adequate control of the flow rate and quality. An accurate

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reference meter or metering system would have to operate in dry steam: this could be achieved by the use of separators or by metering downstream of a pressure-reducing component in superheated steam. Some work is being undertaken to assess the technical and commercial viability of a portable steam flowmeter calibration rig [40]. This test rig is likely to be restricted to small- and medium-bore pipework (up to 6 inches) and will be designed to tee off on a bypass line in series with the meter under test. Conceptual designs for this rig have been developed but no operational prototype has been demonstrated to date. Given the difficulties associated with calibrating steam meters at representative conditions and the current lack of facilities, the popularity of ISO 5167 differential-pressure meters, which do not require calibration, is understandable. However, this does engender a culture in which flowmeter calibration is not routine and consequently meter degradation is not readily detected. The introduction of portable calibration facilities may have some impact on metering techniques in this respect. 6 UNCERTAINTY IN STEAM FLOWMETER MEASUREMENTS In this section a number of potential sources of significant flowmetering error are identified and, based on information gathered in this review, tentative estimates of their relative importance are suggested. The influence of different effects will vary from installation to installation and from meter type to meter type, making accurate generic estimates of uncertainty impractical. However, most meters have a similar order-of-magnitude response to non-ideal conditions. The aim of this section is, therefore, to highlight the scale of problems caused by different phenomena rather than to provide definitive values for use in specific uncertainty analyses. a) Compensation for Steam Density In many current installations, steam density is not measured. Instead, an assumed density is used in the mass-flow-rate calculation. The error caused by this approximation will depend on the stability of the steam pressure and temperature, but errors of 30% or more can be expected if density compensation is not used [1]. Steam meters for use in saturated steam often use a temperature or pressure measurement to compensate for steam-density changes. In a poorly insulated meter with the temperature measurement point near the wall, this may result in significant errors as there will be a discrepancy between the measured and mean steam temperature. However, in most cases, a mass-flow uncertainty of about 1% or 2% would be expected. If superheated steam is being metered, both temperature and pressure must be measured, and Spirax Sarco [1] have estimated that with as little as 10°C of superheat a vortex meter can be in error by 14% if the density compensation is based on pressure alone. Errors associated with extrapolation of steam tables within the flowmeter or in a flow computer are unlikely to be significant compared with other sources of error. b) Poor Upstream Installation During this study, poor meter installation has been cited as being common in many steam meter applications. Many meters are positioned immediately downstream of elbows, partially closed valves or other flow disturbances, usually because of lack of space. No steam-specific information on installation effects has been found.

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However, more general information on installation errors suggest that errors in the 2% to 4% range are typical and errors of up to 20% are possible in some types of meter. c) Wetness Effects Over the range of steam qualities typically experienced in saturated steam systems and when no separator is in place, flowmetering errors caused by condensate are likely to be in the 0% to 10% range. The measurements from any meter installed in a position where condensate can build up are likely to be highly dubious. d) Wear Many flowmeters in steam systems experience droplet erosion and waterhammer damage. The implications of this damage will be very dependent on the type of meter. However, as an example, an orifice plate with a rounded edge, but no significant increase in hole bore, is likely to under-read by between 5% and 30%. Any differential-pressure device is likely to be highly sensitive to small increases in the effective flow area, with the meter error matchiung the percentage change in flow area. In contrast, some vortex meter manufacturers claim that even quite bad erosion results in errors of only 1% to 2% [28]. Based on the list above, it is reasonable to expect that uncertainties approaching 1% can be achieved in the best metering systems in superheat steam. A good metering system in saturated steam is likely to have an uncertainty of between 5 % and 10% and a poor system could be in error by 50% or more. 7 CONCLUSIONS Steam is a very flexible energy-transfer medium and there are many widely recognized advantages of steam systems. Consequently, the steam flowmeter market in the UK is quite diverse, ranging from high-accuracy custody-transfer metering applications to small, cheap meters used in local heating applications. Steam is an expensive fluid and it has been well demonstrated that effective use of flow measurements consistently reduces fuel consumption in steam systems. If better metering practices were widely used, UK industry could save a very large amount of money by reducing wasted energy. Unfortunately the value of steam is not always appreciated and so the uptake of good metering practice has been slow in some sectors. The use of good metering practices is slowly increasing but it is far from widespread. The drive towards improving process efficiency has resulted in more interest in flow metering in the process sector, as has the trend towards purchase of steam from third-party operators of CHP or boiler plant. Legislation and taxation measures, such the IPPC and CCL, seem to have had a limited effect but this does not seem to have been sustained. In the Power Sector, flowmetering has always been regarded as being an important measure of power generation efficiency and consequently metering methods are well-established and usually based on standards. Nearly all steam meters are flowmeters developed for gas applications with adaptations for high pressures and temperatures and they are used to measure the mass flow of dry stream. In addition to high temperatures and pressure, steam meters should ideally be able to cope with highly variable flows and condensate.

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Low pressure loss can be important in many steam systems and often steam pipes are oversized. The latter can make appropriate sizing and ranging of steam meters an issue. The diversity of the steam market makes it difficult to discuss the relative merits of different types of meter, as these will vary from application to application. All of the meters discussed in this report will be optimum in specific scenarios. Differential-pressure meters are likely to remain common for a long time, although their market share will probably reduce as newer technologies are adopted. Ultrasonic meters and Coriolis meters will become more common, as they have in other general gas and liquid flow measurements. Clamp-on ultrasonic steam meters, when they become commercially available, are likely to find a niche market. Spring-loaded variable-area meters and vortex meters are also likely to increase in market share in applications where higher accuracy is important. In general, few users report problems with steam meters. However, as flow measurement errors are not always apparent to the meter user, this does not necessarily indicate that most steam meters are measuring accurately. Market pressures are continuing to drive new technological developments. There is a slow but steady improvement in meter design in the established meters and very rapid development in the newer metering methods. The issues with steam metering are well recognized by meter vendors and, on the whole, they do provide good advice to their customers. However in some circumstances it may not be commercially sensible for vendors to emphasize the difficulties of metering steam. For example, nearly all steam meters benefit from the use of a separator upstream. One meter vendor is unlikely to require the use of a separator with their meter when no such requirement is stated for a competing meter, as this puts their product at an apparent, but false, disadvantage. Selection of a steam meter requires a good understanding of the required function of the meter and how it is to be used in the steam system. Some important points to consider are: • What is the purpose of the meter and how are its measurements going to be

used? • What are the uncertainty requirements and are they realistic? • Is low uncertainty required or is good repeatability sufficient? • High turndown is often useful in steam systems, but is it necessary in this

application? • How will density compensation be achieved? • Is pressure loss through the meter important, or is excess pressure available? • How robust does the meter have to be? • Is upstream separation practical? Some training resources are available for meter users. Many of the larger meter vendors will offer some form of in-house training and some information is available on the internet, although this is quite scattered. The primary problems with steam metering systems appear to be associated with a lack of appreciation of metering issues. The fact that a lot of literature on steam metering extols the virtues of density compensation implies that something as simple as density compensation is not routine for many users. This is probably the main source of metering error in small- and medium-sized steam systems. Poor installation, with meters installed close to bends or other upstream flow disturbances,

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has also been identified as a major source or metering error. Trends towards reduced system maintenance have resulted in an overall increase in steam wetness and hence increased metering errors. None of the common metering methods measure accurately in wet steam; typical errors in wet steam can be expected to be of the order of 5 to 10%. There may be a niche market for a good wet-steam meter but, in general, wetness is dealt with by separation, which is usually easier than in hydrocarbon systems. A great deal of care is required to manage fiscal and custody-transfer metering systems. Many of the larger organizations have the technical expertise to specify and manage custody-transfer and fiscal systems, but smaller companies often do not. Calibration of meters in steam is difficult and no facilities have been identified that calibrate steam meters at their operating conditions. Given the numerous metering problems inherent in many steam metering systems, it is unlikely that there would be a large market for the calibration of steam meters for general purpose use. However there may be some requirement for calibration of meters for fiscal and custody-transfer or other high-accuracy applications. The economics of performing an accurate steam calibration will probably dictate that calibration in gases or by a portable on-site reference system is the only viable method of achieving this.

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7 REFERENCES

1. Spirax Sarco Learning Centre http://www.spiraxsarco.com/learn/default.asp?redirect=home.asp

2. US Department of Energy Industrial Technologies Program http://www.oit.doe.gov/bestpractices/steam/

3. Yoder, J.L. Ultrasonics reverberate through flowmeter market.

http://www.flowresearch.com/articles/InTech%207_21_00.pdf

4. Yoder, J.L. When will the vortex flowmeter market pick up steam? http://www.flowresearch.com/hothottopics/September_2003/Vortex_Flowmeters.htm

5. Energy Efficiency Good Practice Guide 18, Reducing energy consumption

costs by steam metering. http://www.actionenergy.org.uk/downloads/GPG018.pdf

6. Mottram, R.C., Owen, I. & Turner, J.T., Wet steam/wet gas flow measurement. Flow Measurement and Instrumentation Consortium Report No 13, May 1991.

7. Personal communication with Colin Stephenson, Spirax Sarco Ltd.

8. Steam Generation Costs ECG066 Energy Consumption Guide

http://www.actionenergy.org.uk/downloads/ECG066.pdf

9. How to calculate the true cost of steam, US DOE Best Practices Steam Technical Brief

http://www.oit.doe.gov/bestpractices/steam/pdfs/tech_brief_true_cost.pdf 10. International Organization for Standardization. Measurement of fluid flow by

means of orifice plates, nozzles and Venturi tubes inserted in circular cross-section conduits running full. ISO 5167-1:2003. International Organization for Standardization, Geneva, 2003.

11. Menzies, M. & Graber, W., Measurement best practices for improving

chemical plant safety, availability and efficiency (DP flow gas and steam examples). Chem Show 99, New York, 1999.

12. Seiko Flow Control

http://www.seiko-flowcontrol.com

13. Hussein, I.B. and Owen, I., “Calibration of flowmeters in superheated and wet steam”, Flow Measurement and Instrumentation, Vol. 2, October 1991.

14. James, R., Metering of steam-water two-phase flow by sharp-edged orifices.

Proc. Inst. Mech. Engrs. 180 (1965-1966) 549-566.

15. Murdock, J.W., Two-phase flow measurement with orifices. Trans. ASME J. Basic Engng. (December 1962) 419-433.

16. Chisholm, D., 1977, “Research Note: Two-Phase Flow through Sharp-Edged

Orifices”, Journal of Mechanical Engineering Science, 19, No. 3.

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17. De Leeuw, H., “Liquid Correction of Venturi Meter Readings in Wet Gas

Flow”, Paper 21 presented at the 1997 North Sea Flow Measurement Workshop, October 1997.

18. Steven, R., “Wet Gas Metering”, Ph.D. Thesis, University of Strathclyde,

Glasgow, April 2001.

19. Stewart, D., The evaluation of dry gas meters in wet gas conditions. DTI NMSD Flow Programme 1999-2002, NEL Report No 2002-100, November 2002.

20. ASME PTC 6 – 1996 Steam Turbines, 1996, ISBN: 0791823725.

21. Chisholm, D. & Leisham, J. M., Metering of wet steam. Chemical and Process

Engineering, July 1969.

22. McCrometer’s V-Cone flowmeter receives Canadian custody transfer approval http://www.mccrometer.com/newsroom/press021.htm

23. Gilflo flowmeters for steam, liquids and gas.

http://www.spiraxsarco.com/assets/uploads/PDFs/sb/S41_18.PDF

24. Hardy, J.E., Hylton, J.O. & Moore, R.L.. Steam flow measurements. US DOE Report DE-AC05-840R21400, reprinted by Gervase Instruments Ltd, 1984.

25. DIVA flowmeter for saturated steam measurement

http://www.spiraxsarco.com/us/assets/uploads/PDFs/sb/Diva.pdf

26. Nonlinear data analysis for vortex flow meters, University of Freiberg, http://www.fdm.uni-freiburg.de/groups/timeseries/vortexflow/index.php

27. Yoder, J.L. When will the vortex flowmeter market pick up steam?

http://www.flowresearch.com/hothottopics/September_2003/Vortex_Flowmeters.htm

28. Personal communication with Neil Jackson, Emerson Process, Stirling.

29. Personal communication with Roger Bancroft, Flowquip Ltd.

30. Instromet Inc., CheckSonic Ultrasonic Gas Flowmeter

http://www.instrometinc.com/BrochurePDFs/UltrasonicCheckSonic.pdf

31. American Gas Association (AGA) Report No. 9, Measurement of gas by multipath ultrasonic flowmeters, 1998.

32. Zanker, K.J. & Brown, G.J., The performance of a multi-path ultrasonic meter

with wet gas. 18th North Sea Flow Measurement Workshop, Gleneagles, Scotland, 2000.

33. Patten, T., Dunphy, K., Parson, F. & Skewers, P. Using Coriolis meters for

gas measurement: An update on AGA11, 2001. http://www.emersonprocess.com/micromotion/solutions/PDF/Using+Coriolis+Meters+for+Gas+Measurement+Texas+AM.pdf

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34. ISO TR 12767:1998. Measurement of fluid flow by means of pressure

differential devices – Guidelines to the effect of departure from the specifications and operating conditions given in ISO 5167-1. (Also BS ISO TR 12767:1998)

35. Personal communication with Colin Stephenson, Spirax Sarco Ltd. 36. Morrison, G.L., Hall, K.R. and Flores, A.E.. Slotted orifice based two phase

flow meter. Texas A&M University http://www.flowlinemeters.com/Dr%20Morrison%Paper.pdf.

37. Hussein, I.B., Owen, I. & Amini, A.M., Energy metering system for high quality

saturated steam. Flow Measurement and Instrumentation, Vol. 3, No. 4, 1992. 38. Lloyd, K.E., Guthrie, B.D. & Peters, R.J.W.. A flowmeter calibration facility

developed at the University of Iowa to evaluate custody transfer steam flowmeters with a cone differential pressure mater used as the metering standard. ISA 2002 – PMCD – Process Measurement & Control, 2002.

39. Sims, J.C. Texaco’s steam research facility. Proc 7th UNITAR Conference on

Heavy Crude and Tar Sands, Paper 1998.161, 1998 http://www.oildrop.org/Info/Centre/Lib/7thConf/19980161.pdf?id=jwssa

40. Personal contact with Alan Sumpter, Tekniflo Ltd.

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APPENDIX

CASE STUDIES

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The following case studies of steam flowmetering applications are taken from the Energy Efficiency Good Practice Guide 18, Reducing energy consumption costs by steam metering [4] Case History 1: Chemical Company (Yorkshire) System Design The site spends approximately £500,000/year on oil purchases for its three boilers. The steam produced is for process use and the system is controlled via a Trend Energy Management System. The metering system was designed to monitor the 12 main production areas and it also provides the basis for Trend pIc's control of the boilers. Thirteen meters have been installed. Detailed Design The steam supplied to the site is saturated and the load in individual production areas can vary. Vortex meters were chosen for installation on grounds of cost, performance (turndown ratio) and previous experience with this type of meter. Steam separators were also installed to knock out entrained water droplets. The approximate consumption in each individual area was known, so meters were sized on the basis of information from charts supplied by the manufacturer. The manufacturer also advised on the location and installation of the meters and this advice was followed. The meters are monitored continuously by the Trend system, data being archived to file and tape streamed. Hard copy is produced both daily and weekly for accounting purposes, for the calculation of savings, and for inputting to a fledgling M&T system. Maintenance Meters are recalibrated annually. The recalibration does not involve a dimensional check on the vortex-shedding bar. Because of their design, vortex meters require no periodic maintenance. Conclusions The steam meters were installed as part of an Energy Management System and are used both for monitoring and for controlling steam usage in individual areas of the site. A lot of information is being produced on both a daily and a weekly basis but, until recently, the company did not have the management structures to take full advantage of the system. The current implementation of M&T should give more positive results in the future. Few cross-checks are built into the system, so it is difficult for the user to assess the accuracy of individual meters. The M&T system will, however, help to highlight any inaccuracies that may exist. Vortex meters, unlike differential-pressure meters, have no means by which the transmitter can be isolated from the vortex bar. The zero point of the meter can, therefore, only be checked by isolating it from the flow. This will require a bypass arrangement if the flow is not to be interrupted.

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Case History 2: Educational Establishment System Design Boiler fuel for the site costs approximately £300,000/year. Steam is supplied at low pressure and is used primarily for space heating in the buildings on the site. The metering system was designed to measure consumption in individual buildings, thereby providing information on which energy conservation measures might be based. Twenty six meters have been installed, the majority supplied by Spirax-Sarco and the remainder by Gervase and Kent. Detailed Design Saturated steam is supplied to calorifiers located around the site, and the load variation can be significant. Variable-area meters were selected because of their high turndown ratios. In order to size the meters correctly, an energy consultant was employed: temporary meters were installed at the various relevant locations and profiles of steam demand were established. Most of the meters fitted were 50 mm. The manufacturer provided installation instructions and the local representative suggested where the meters should be located. Meters are read daily and on demand, since they are wired directly to a central computer. However, meter accuracy is offset by the slow sampling rate of the computer, a difficulty overcome on later meter models by the incorporation of a pulsed output. Maintenance The meters installed have a low maintenance requirement and during the two years since installation have neither been recalibrated nor had their primary dimensions checked. Recalibration would involve returning the meters to the manufacturer. Conclusions The site is difficult to monitor accurately and cheaply. The load is predominantly space heating and is spread over a large number of individual buildings. This means that significant load variations will occur and necessitates a large number of meters. The variable-area type of meter is the best choice for such an application. The large number of buildings varying in both age and construction would have made calculation of heat losses from first principles impractical. The use of temporary metering to size the individual meters was, therefore, both sensible and practical. Because the steam supply system is adequately steam trapped, the use of upstream separators was considered unnecessary. A few meters do have wire-mesh screens installed upstream to collect solid debris. From the start, the system was designed to be directly wired back to a central computer. The area over which the meters are spread would make manual meter reading uneconomic.

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Case History 3: Paper Mill System Design The site spends approximately £1 million/year on coal for its boilers. Annual steam production totals 292000 tonnes. Steam is generated at high pressure, expanded through turbines to generate electricity and then supplied to the paper-making machines to heat the drying rollers. There is no space-heating requirement. The metering system was designed to measure consumption in individual parts of the process as well as around the electricity generation plant. Twenty six orifice-plate meters have been installed. Detailed Design The steam supplied around the site is saturated, and the load to individual areas varies very little. Company policy resulted in all meters being purchased from Kent. Steam consumption was determined from the rate of paper production, the paper type and the degree of drying required. This information was passed to Kent, which supplied the appropriate meters. Because of their extensive experience with this type of meter, the company engineers were able to install and commission the meters themselves. At present, the meters are read daily: the readings being used both for energy accounting and for inputting to an M&T scheme. A recent site survey has resulted in changes being proposed, and these may involve an expansion of the metering system. Maintenance meters are recalibrated during the annual shutdown and whenever problems occur. Recalibration involves only the transmitters, the view being that the orifice plate itself is unlikely to be the cause of problems. The company employs an outside contractor to service the meters, although instrument engineering capability is available on-site. Conclusions The limited load variation on this site during the year means that the meters installed do not require high turndown ratios. Orifice plates are best suited to this type of application. After calibration, the accuracy of the orifice plate can be 0.75% or better, together with a repeatability of 0.25%. The meters can be used for both energy accounting and M&T.

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Case History 4: Rubber Manufacturing Company System Design The site has an annual energy bill of £550,000, of which £300,000 is used for purchasing coal and gas for steam production. The steam is used for both space and process heating. The metering system was designed to monitor the steam consumption of the major production centres. Five variable-area (Gilflo) meters were installed within the production system to augment the existing steam orifice-plate meter at the boilerhouse. Detailed Design Saturated steam is supplied to the site and, because the load to individual areas varies considerably, variable-area meters were selected for their high turndown ratio. Rotary-shunt meters were also considered but were rejected on the grounds of their limited turndown capabilities. The meters were supplied with a pulsed output and readings are relayed back to the Engineering Manager's office. The site provided the manufacturer (Gervase) with basic information on pressure, temperature, and maximum and mean consumptions. The manufacturer specified the meter sizes and supervised the installation. The aim of the installation was to provide basic information on which energy conservation measures could be based. The system is programmed so that meters are read on a weekly basis. There are no plans to install additional meters, and current concern is focused on integrating the meter readings into the site's M&T system. Maintenance The Gervase meters have a low maintenance requirement and, during the three years since installation, have neither been recalibrated nor had the primary elements checked. The impulse lines to the DPCs are not readily accessible and so are not blown through at regular intervals. Conclusions Variable-area meters are best suited to this application, where steam is required for both space and process heating and where load variations can be significant. Only the key production areas are sub-metered, the system covering 80% of site steam usage. The benefits to be obtained from any additional metering were outweighed by the cost of its installation. The considerable amount of information produced by the system is used both for energy accounting and for consumption monitoring. Until recently, no appropriate management structure existed to allow the information to be used to target consumption or to permit action to be taken on the basis of a regular assessment of steam usage. With the current implementation of an M&T system, more positive results are expected. Few cross-checks are built into the system. Boiler plant steam production can be checked via the feed-water flow and this has shown the boiler-plant export meter to be suspect.

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Case History 5: Chemical Company (Cheshire) System Design The site has an annual energy bill of £2.5 million, of which £1.2 million is spent on coal to fire high-pressure boilers. Steam is used to generate electricity and is then sold to the various production centres as a heat supply. The metering system was designed to measure usage in each individual area. This necessitated the installation of 20 meters on the distribution system. A further 20 meters were installed within the production areas for use as checks and to subdivide usage within those areas. Detailed Design The provision of superheated steam around the site avoids many of the problems common to steam metering. The load is fairly constant at 32,000 ±7,000 kg/h, so most of the meters used are orifice plates with a variety of DPCs and transmitters. The site has extensive experience of orifice plates and was able to design and specify the sizes of plate required. Steam consumption was estimated by the Technical Department and the meters were sized to give 70% of FSD at full flow. If this proves to be inadequate, the transmitters can be re-ranged. Under current procedures, the meters are read daily and the information is used for monitoring consumption levels. Total Quality Management is being introduced and it is thought that targeting of energy use will become increasingly important. Maintenance Meters are recalibrated on demand rather than to any pre-set schedule. However, if a meter has not been recalibrated for two years, it is scheduled for recalibration. Primary elements are rarely checked as this involves shutting down the steam main. A glycol mixture is used to minimize the risk of impulse lines freezing. Conclusions By deliberately oversizing the meters, their effective turndown ratio is reduced. A good orifice plate can have a turndown ratio of 5:1 after calibration, but this can be reduced to 3.5:1 by oversizing. In this particular application, such a reduction is not important as the range of steam flows expected does not exceed 2:1. The use of glycol in the impulse lines deserves further comment. Depending on the strength of the mixture, glycol can provide protection down to -10°C, which should be more than adequate for most locations in the UK. Two problems can, however, arise:

• if the steam is to come into direct contact with foodstuffs, the use of glycol will be prohibited;

• care will be needed when blowing through the impulse lines in order to ensure that the mixture strength is equalized on both sides of the DPC.

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