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Overview

This section discusses the characteristics of available metering and the required infrastructure to collect and store data.

Outlined in the following is an approach to guide the end-user toward implementing a metering and measurement system, bearing in mind the following key questions:

  • Do I need any additional meters to manage energy use?
  • How do I decide where to install meters?
  • What meters should I use?
  • How do I link these meters to my monitoring systems?
  • Can I afford them? If not, what are the priorities?
  • What are the practical and other issues I need to know about?

A structured approach to developing a measurement plan is illustrated in Figure 37.

Figure 37. Measurement plan – A structured approach

9.1 Introduction

Metering and measurement represent a key component of the overall EMIS. Timely measurement of utility consumption, ambient conditions and process variables allow your plant or facility to

  • provide cost-centre accounting
  • identify problem areas before they become out of control
  • verify utility billing
  • assist in energy purchasing
  • assist in maintenance and troubleshooting
  • aid in identifying and monitoring energy projects
  • offer meaningful data toward sizing and design for capital installations and improvements

It must be emphasized that whatever is being measured, the output data will not in itself reveal why something happened. At this point, the end-user is encouraged to note changes and deviations in the data's patterns and look for possible causes. On another cautionary note, the difficulty in measuring everything at once makes it necessary for the end-user to select a few key areas and monitor these with particular attention to the sudden change or unusual event and other warning signals. Having acquired the data, the end-user may be guided by the following when interpreting the measured results:

  • Since measurements do not "stand alone," use comparisons to determine if a result is under or over budget, better or worse than the last similar time period, above or below the industry average, or better or worse than one product or another, to name only a few considerations. Perform benchmarking according to internal and external comparisons.
  • When making comparisons, words can be too vague to be useful; use numbers (e.g., "100 kg of product/MWh is an improvement over 85 kg/MWh" is more specific than "we are better than we used to be").
  • Normalize the data in order to ensure realistic comparisons. Account for seasonal difference changes in use and occupancy or process (e.g., m3 natural gas vs. m3 natural gas heating degree-day).

9.2 The Need for Metering

An energy management plan or strategy should be developed before contemplating the expansion of metering capability and selecting sensors, meters and other monitoring instruments. This plan will provide a foundation for considering the intended purpose of installing meters beyond the utility's revenue metering. Reliance on main utility meters, except in the cases of small plants or facilities, is inadequate for determining utility consumption profiles in these areas. The end-user must clearly understand whether the metering is being installed strictly for savings verification and whether the installation is to be permanent or temporary. Sub-metering allows for energy use accountability to be introduced at the level of the end-user, who has the greatest influence on driving operating costs downward, unlike plant or facility utility personnel.

Forecasting for utility purchase contracts is another driver for increased metering and measurement capability. In some regions, retail power rates have become more time-sensitive, and the average price will change over time and use. Load profile shapes will influence pricing in this situation, with flatter profiles usually resulting in a lower average cost.

Energy marketers may offer simplified rates that level out these time-based variations, but this may not necessarily offer the best deal. Variable rates may provide the lowest average price when selected in conjunction with strategies that reduce, level or shift peak demand. Knowing the shape of your aggregate typical daily load profile and that of your major sub-metered loads could reveal opportunities to reduce present and future price and thus total cost. Increased knowledge of your energy use will help your energy supplier offer the most optimum and secure pricing.

The same rationale in the foregoing may be applied to natural gas fuel forecasting and purchasing. From the point of view of producers, transporters and suppliers, a level load throughout the day and year is most desirable. As a result, variations in demand tend to increase these costs significantly. Having a detailed knowledge about gas use, enhanced by sub-metering, will allow the purchaser to determine the amount of base-load firm and interruptible gas requirements for contracted purchases.

In summary, energy purchase contracts may be sensitive to peak use that exceeds maximum levels specified in the purchase contract, making close monitoring and control of plant or facility loads necessary. Lack of knowledge about an organization's consumption or usage peak profiles will be detrimental to negotiating the best available purchase contract in an open market.

Be sure to know the following:

  • when the energy is consumed (time of day and seasonal use)
  • what loads can be controlled (shifted, levelled and/or reduced)

9.3 Deciding Where to Locate Meters and Sensors

Having established the need for metering and measurement, the next step is to develop a measurement plan that outlines a road map for installing monitoring equipment. This plan should identify

  • all monitoring points
  • types of sensors and their locations
  • signal cable routes and wireless communications
  • necessary documentation

The measurement plan precedes the preparation of a data acquisition plan and subsequent analysis. The end-user must ultimately define the frequency of measurements (e.g., 15 minutes, hourly, etc.) and whether monitoring will be for a short or long term.

9.3.1 Step 1: Review Existing Site Plans

If up-to-date site plans are available, single-line diagrams should illustrate natural gas and electrical distribution to major loads. The electrical schematics will illustrate the power distribution to transformers, motor control centres and major loads. The schematics, having revealed the configuration of the energy distribution and metering, will provide valuable insight as to whether the existing distribution systems readily lend themselves to metering for cost allocation purposes.

In many instances, many of the main gas metering points or motor control centres could supply loads in different plant or facility cost centres. Installing additional metering for all these loads would likely be cost-prohibitive or at odds with the site's budgetary constraints. The steps listed in the following will help rationalize the decision as to the number and location of meters that will strike a balance between the site's objectives and budgetary constraints.

9.3.2 Step 2: Develop a Meter List

A list of meters that will be included in the overall cost allocation strategy should be developed. A simple example of such a metering list is illustrated in Table 7.

Table 7. Metering list
Metering Point Metered Load
CA 1 No. 1, No. 2 air compressors
E 1 115 kV sub
E 2 Administration building
W 1 Municipal water service
NG 1 Main site entrance
NG 2 Dryers
E 3 Parking lot car block heaters and lighting
W 2 No. 1, No. 2, No. 3 service water pumps
S 1 Utility boilers No. 1, No. 2
E 4 HVAC units No. 1, No. 2, No. 3

9.3.3 Step 3: Assign Energy Accountability Centres

After completing the metering list, energy accountability centres can be assigned in accordance with the plant or facility's business units. Table 8 illustrates an example as to how the energy accountability centres may be configured in accordance with the metering list presented in Table 7.

Table 8. Energy accountability centres
Business Unit Energy Accountability Centre Performance Variable Metered Load
Site services Administration Tonne of product E 2
Site services Parking lot Tonne of product E 3
Site services Building heating Outdoor air temperature NG 1 – NG 2
Site services Air conditioning Outdoor air temperature E 4 – Calculated Factor
Site services Domestic water Tonne of product W 1
Process Materials handling and production Tonne of product E 1 – (E 2 + E 3 + E 4)
Process Process heating Tonne of product NG 2
Process Compressed air Tonne of product CA 1
Process Process water Tonne of product W 2
Process Process steam Tonne of product S 1

9.3.4 Step 4: Decide on Additional Metering or Measurement

Adopting a systematic approach to tabulate a metering list and energy accountability centres reveals areas where metering and measurement can be improved.

For example, major process loads such as pumps, motor drives, etc. could be electrically sub-metered to gain more knowledge on usage rather than having to rely on a coarse measurement from meter subtraction for process, as illustrated in Tables 7 and 8.

Also, there is a gap in potential useful information to be gained from the compressed-air system, which is not power metered according to the metering list. At the moment, compressed-air flow (m3/sec) can be "ratioed" against total production (tonne of product). Electrically sub-metering the bank of air compressors (No. 1 and No. 2) would enable the performance of the air compressor equipment to be tracked – (m3/sec)/kW – yielding valuable diagnostic information. If Metering Point E 5 were added in this regard, the energy accountability centre tabulation would be amended with the following addition:

Business Unit Energy Accountability Centre Performance Variable Metered Load
Process Compressed air Total airflow E5

9.4 Deciding on What Types of Metering to Use and Practical Considerations

9.4.1 Electrical Metering

In many cases, power quality and feed protection issues represent the driving force for sub-metering electrical power instead of energy management considerations. In moving to an energy management and cost control justification for installing additional metering capability, the following should be considered when reviewing the types of commercially available metering equipment and subsequent selection.

As a start, existing utility revenue metering should be utilized to the fullest possible extent, particularly to gain an appreciation of a site's total electrical load profile or for billing verification. Special concerns related to using existing revenue metering include the following:

  • Because the revenue meter is the property of the utility and is a regulated device, utility personnel should make any modifications.
  • Modifications typically include retrofit with a pulse initiator or installation of a pulse splitter on an existing pulse initiator.
  • It is key that the pulse value is obtained from the meter or the utility.
  • When existing facility panel meters cannot be refitted with pulse initiators or when voltage levels prohibit cost-effective installation of new meters, new 5-amp current transformers could be installed on the secondary side of existing meter current transformers, which would in turn be connected to new metering equipment. This metering approach is not as accurate as direct metering because measurements based on secondary current introduce a second measurement error.

Power meters owned by the site for monitoring total power to a major load centre would typically be located at the point of delivery (sub-station) and monitor the watts and Q-pulse from the utility revenue meters. Total kVA, kW and kVAR readings would then be calculated from these signals. A typical digital power meter for this application would offer a digital readout display and a maximum sampling rate of 128 Hz. A standard version may allow for a maximum of four channels. In comparison, a premium, more advanced version of this power meter would include most of the same features but have a video display terminal and allow for a maximum of 42 channels. The premium version is generally more suited to revenue grade metering and would offer power quality analysis, event-triggered data storage and logging.

An economical power measurement unit for sub-metering could typically offer a digital readout display and a maximum sampling rate of 32 Hz. Typical power measurement would include apparent power (VA), reactive power (VAR) and power factor (PF), as in the more premium models previously referred to. This unit would typically be ideal for use as a power transducer for DCS, EMS, SCADA and PLC systems.

A deregulated power market application may impose certain metering requirements. The following Web sites are included for reference, representing power-metering products that are deemed to conform to the requirements of some open markets:

End-users are encouraged to research the particular requirements that apply to the region in which their plant or facility is located.

9.4.2 Natural Gas Metering

In most cases, natural gas sub-meters with dial indicators are used. Although equipped with pulse output capability, this feature is rarely used, largely due to perceived cost considerations. Larger areas of natural gas consumption may have meters that make use of the utility's pulse signal.

Natural gas meters range in size and capacity from 2-in. (50-mm) flanged connections at 800 CFH (22.6 m3/hr.) capacity to 56 000 CFH (1600 m3/hr.) rating. For small commercial loads of up to 15 psig (1 bar), compact line-mounted meters with a dial-face or odometer-type index can be purchased. For higher-volume industrial loads, a full range of meters that are rated for working pressures of up to 300 psig (24 bar) are available.

Many site-owned meters remain uncorrected for temperature and pressure, bringing the accuracy of many site-metered volumes into question. Compensation for temperature effects can be accomplished by a mechanical computer with a spiral bi-metallic thermocouple probe, positioned at the meter inlet within a sealed temperature well. Natural gas volume readings may be corrected to a 60°F (15°C) basis to yield readouts in standard cubic feet (SCF) or normal cubic metres (Nm3) between flowing temperatures of 220°F to 120°F (229°C to 49°C).

Pressure correction factors may be calculated according to the following formula:

(Utility delivery pressure + Site atmospheric pressure) / Atmospheric pressure at sea level

For example, if the utility delivery pressure is 50 psig (345 kPa), estimated site atmospheric pressure is 14.6 psi (100.66 kPa) and atmospheric pressure at sea level is 14.73 psi (101.56 kPa), then the pressure correction factor would be

(50 + 14.6) / 14.73 = 4.39

As such, the metered volume would be multiplied by 4.39 to obtain a "true" reading in this case.

Temperature- and pressure-compensated meters are commercially available from major vendors. Some meters are available with battery-powered microprocessor-based correction for temperature and pressure effects. The corrector may be integrally mounted within the body of the meter or externally mounted on a wall, pipework or standard instrument drive.

Thermal-dispersion-type flow meters offer relative simplicity of measurement through a single-pipe penetration, thus eliminating temperature and pressure transmitters and density compensation calculations required by differential pressure, vortex and turbine type metering. As such, less hardware is needed for a metering system, and this flow meter offers an alternative and accurate means of gas-flow measurement. Communication between the flow meter and signal processor assembly is over two-wire pair. Linear output signals of 0-5 V DC or 4-20 mA can interface with either RS 232 or RS 485 communication.

It must be remembered that because gas service entrances and meters are usually located outdoors, a $1,000 metering point can incur a final cost of $10,000 when the costs of trenching, buried conduit and structural penetrations through buildings for pipework are considered. In these cases, wireless data communications may present a viable alternative.

Much like electrical meters, a pulse initiator could be installed on existing natural gas meters by the utility to provide shared signals. For cases where a pulse initiator is already present on the meter, a pulse splitter may be installed. Important points to consider in using shared signals for natural gas metering include

  • allocate enough coordination time with the utility
  • obtain from the utility the correct scale factor for the meter
  • temperature and pressure compensation of the output from the pulse initiator

It should be emphasized that although sharing signals with utility meters can be cost-effective, sharing signals with existing facility meters can entail unforeseen calibration and repair expenses. Related concerns include

  • all the inaccuracies of the existing metering system are assumed
  • existing facility meters could potentially be improperly sized
  • calibration documentation could be limited or unavailable
  • impracticality of removing meters from a live system could leave no alternative but field calibration, with its associated approximations

9.4.3 Steam Metering

Orifice plate meters are in common use throughout plants. Calibration data would have to be obtained either from the facility's calibration records or from a meter's nameplate data. Steam flow is proportional to the square root of the pressure difference across the measuring orifice plate. At low flows, significant changes in flow may not generate significant changes in differential pressure, leading to measurement error. This is a concern if steam generation falls below the turndown ratio for rated accuracy of the orifice plate measuring device, leading to inaccurate data logging.

Another caution regarding the use of orifice plate steam flow meters relates to when steam pressure is lowered. Steam flow readings extracted by differential pressure orifice plate devices are usually affected when steam pressure is lowered due to a corresponding reduction in steam density. This in turn results in a greater pressure drop at the orifice plate for a given flow, yielding a proportionally higher steam flow reading. Calculated mass flow correction factors must be applied to steam flow readings in this case to obtain a true reading. Discussions with site personnel reveal that automatic pressure compensation is rarely applied. 

An example of mass flow correction as applied to orifice plates for saturated steam is outlined as follows:

Given a flow reading of 13 607 kg/hr. of saturated steam, an operating pressure of 690 kPa and an orifice plate design pressure of 862 kPa, what is the actual corrected mass flow?

The correction formula is: Cm=√(dD/dA) × (dA/dD)

Where dA = steam density at actual pressure
dD = steam density at design pressure
Cm = mass flow correction factor

From steam tables: dB = (1/specific volume) = 1/0.201 = 4.976 kg/m3
dA = (1/specific volume ) = 1/0.243 = 4.120 kg/m3
Cm=√(4.976/4.120) × (4.120/4.976) =0.9098

Therefore, the actual steam flow is 0.9098 × 13,607 = 12,380 kg/hr.

Differential pressure is usually measured by a differential pressure transmitter and conditioned into a 4-20 mA or other industry standard signal to an energy management and control system.

Vortex flow meters, although more costly, offer greater accuracy compared with orifice plate flow meters and have over three times the "rangeability." Another alternative to flow measurement by orifice plate is offered by annubars, which consist of diamond-shaped sensors that are inserted in the flow stream. Annubar flow sensors generate lower permanent pressure loss due to reduced flow restriction and require less labour to install. As an example, an annubar installed on an 8-inch (200-mm) pipe requires only 4 linear inches (20 cm) of welding compared with an orifice plate, which requires 50 inches (125 cm) of welding for the same pipe. Installed cost savings range from 25 percent on smaller pipes to 70 percent on larger pipes. As in the case for orifice plates, manufacturer's data must be consulted to determine the appropriate temperature and pressure compensation factors. Rangeability will be similar to orifice plates. 

9.4.4 Water and Condensate Metering

Unless a meter is very old, existing turbine, rotating disc, vortex and magnetic flow meters can usually be retrofitted with a pulse head. Final confirmation of this should be made with the meter manufacturer. Although rarely calibrated, most of these flow meters probably have reasonable accuracy if the meters are in serviceable condition. Be aware that the costs of meter removal, replacement of worn parts and recalibration could often equal the cost of a new meter. It is suggested that any pulse-head retrofit should be accompanied by the installation of a local register to provide a check reading.

If the metering pipework includes a check valve to stop the flow of condensate or water through the meter, and if the check valve fails, the flow may be correctly metered on the local register but metered multiple times by the pulse head.

Numerous types of venturi, annubar and orifice plate meters that use differential pressure transmitters will be encountered in the field. These are susceptible to numerous operational and calibration issues.

Non-intrusive type flow meters offer a means of performing spot checks for liquid flow measurement. These include magnetic, transit time and doppler-type sonic flow meters. The main advantage of this metering equipment is that it offers portability of measurement and unobstructed flow with no pressure drop in the pipework. Important points to consider in selecting non-intrusive meters include

  • magnetic flow meters are relatively expensive but offer high rangeability (30:1) and are suitable for dirty fluids and bi-directional flow measurement
  • transit-time-based sonic flow meters offer high accuracy for relatively clean flows but are adversely affected by bubbles or particles in the flow stream and internal deposition on pipe walls, and require full pipe flow with moderate turbulence
  • the accuracy of doppler-type sonic flow meters depends on the presence of suspended particles or bubbles in the liquid flow stream

9.4.5 Compressed-Air Metering

Although widely used, orifice plates are inappropriate for compressed-air systems because they offer limited turndown capability (3:1), and they generate relatively high differential pressures. It is suggested that Pitot-tube-based instruments offer improved turndown and relatively negligible differential pressure. Selection of a Pitot-tube-based measurement should include temperature and pressure compensation in order to produce true flow readings. Both the Pitot tube and Type J thermocouple should be installed in an undisturbed section of the compressed-air line from each compressor.

Lack of pressure gauges or uncalibrated gauges in the system restrict measurement of differential pressures on critical components such as filters, coolers and separators. Installation of test taps at selected locations would enable the use of one calibrated precision instrument to obtain reliable pressure readings and avoid maintaining and calibrating a number of gauges.

9.4.6 Data Loggers

In situations where access is cumbersome (e.g., motor and fan housings, electrical junction boxes, air vents, etc.), data related to temperature, relative humidity, voltage, amperage, pressure and CO2 can be monitored by data loggers. Since they are stand-alone devices, they can also be re-used for other assignments. Relative cost is low compared with more permanent data-acquisition systems.

Most data loggers can interface with a PC. Some have external input capabilities that may be wired to existing gauges and sensors that are equipped with voltage output terminals, also enabling these devices to be monitored and recorded.

Data loggers offer an alternative measurement application for opportunities where a small number of simple retrofit measures (e.g., lighting) are replicated in great quantity and only a representative sample requires metering. Knowing the operational profile of a motor or lighting system that has a flat amperage-draw profile enables energy consumption to be readily computed.

9.5 Linking Meters to Monitoring Systems

Following the selection of metering equipment, the architecture of the system that links the data collected in real time from various remote electronic meters (natural gas, power, compressed air, steam and water) to the EMIS software must be configured.

Currently, most meters have analogue output options (4-20 mA), serial digital interface options (direct RS 232) and network bus communication interface capability, for example, Ethernet, Modbus remote terminal unit (RTU), etc. As such, although most meters can be initially used on a stand-alone basis, these can be integrated within a complete plant or facility-wide system for monitoring and control through a common communication link, offered through open architecture. 

Figure 38 illustrates a commonly used system that utilizes RTUs mounted in the field to monitor energy use in various areas of a plant or facility. The RTUs are interconnected via a local area network (LAN) to a main EMIS computer.

Figure 38. Common EMIS configuration

9.6 Cost Considerations

Cost is always a prime consideration, and having planned for measuring and data acquisition, a decision must be made as to whether the existing metering infrastructure should be used or whether new metering equipment should be purchased. It should be cautioned that the avoided cost of using an existing meter can be offset by the costs of converting to meet new metering requirements, in addition to inspection, repair and calibration costs. Other considerations include technical requirements of the project, whether the meter still has to fulfil its original duty and whether a permanent installation is required.

The cost-effectiveness of metering depends highly on the economies of scale of the end-use. For example, metering of a 200-hp motor is comparable to a 20-hp motor, but the 200-hp motor has the potential for yielding 10 times the savings for similar cost.

Costing is difficult to estimate for the purposes of this handbook in the absence of detailed engineering and the susceptibility of costs to market conditions.

9.7 Concluding Remarks

The expectation of absolute precision for all of a site's measurements and the difficulty of achieving this is often perceived as a barrier to implementing improved metering capability. This should not deter the site from upgrading metering systems before it implements an EMIS. Staged implementation applied within budgetary constraints is a practical way to get started. At this point it is important to realize that, in practice, measurements will not be perfect.

Action to achieve improvements is best ensured by an organizational culture that encourages rewards and sustains utility cost-reduction initiatives. The EMIS is intended to supply useful information and data about the site's utility consumption patterns. Effectively communicating, encouraging participation and involving personnel across all levels of the site requires people skills. Motivation will be sustained when a team experiences early success with proven results, as validated by the EMIS. Credibility will also enhance motivation and buy-in from all personnel. Methods of rewarding good performance should be developed with an organization's human resources group. This may involve giving recognition through publicity (e.g., testimonial posters, company publications such as newsletters, non-monetary awards at company events, etc.) or a modest cash award. Motivation will also be enhanced when staff is assured that help is available from the team to correct poor performance.

Although procedures and standards such as ISO serve a useful purpose, beware of overreliance on these as a driver for improving energy use efficiency. For example, ISO 14000 is widely regarded as a proven international standard for effective and comprehensive environmental management. Although it is broad enough to encompass energy use efficiency, this broad focus may miss some unique aspects of energy management. For example, strategic energy purchasing is a complex and key requirement when operating within a deregulated environment. The key focus of ISO 14000 is on environmental conformance and compliance. As such, this standard offers no guidance on energy purchasing because purchasing is not normally related to conformance compliance. Undeniably, there is a direct link between energy and the environment, and an EMIS can serve as a useful complementary tool to environmental issues.

Another area that can be a problem is relying too much on a single energy champion. Many organizations have been in situations in which information could not be found because "only a certain person knew" or because that person was absent. An effective EMIS will capture the collective knowledge of a site's energy use and make it broadly available. In addition, by reducing data-collection time, personnel can devote more time to developing solutions.