1 INTRODUCTION

Flare systems at offshore production platforms, refineries and chemical plants are primarily installed for safety purposes. The flare systems are mainly activated due to an unexpected shut-down or when it becomes necessary to suddenly dispose rapidly large amounts of gas. Going 20 years back, a common sign of an offshore production platform or process plant was the ever-burning flare, to be seen from far distances. The burning flare was in a way the mark of the oil production age. At that time, few, if any, regarded the burning flare as an unwanted proof of unprofitable production and gas emissions.

This has now changed, and there is an entirely different awareness amongst operators and oil companies about the effect of gas emission as both an environmental and an economical issue. In addition to the obvious safety purposes of a flare, national legislation in more and more countries requires control of the emission, and in some countries operators have to pay taxes for their CO2 emission. Since the Kyoto climate conference in December 1997 the focus on the global warming has increased, and the emission of CO2 has become an international responsibility.

This yields also for the flare gas emission, and oil production platforms are nowadays both designed and rebuilt for zero-flare operation. This change in operation of the flare systems has also influenced on the requirements of the flare gas metering systems. From a continuous, more or less steady flowing amount of flare gas, today's picture is more binary in nature, wit the gas flow either to be approximately zero, or at the specified maximum rate.

2 WHY MEASURE FLARE GAS?

From an operator's point of view, there is no reason to measure the flare gas unless it is of economical benefit or it is required by e.g. the national government for tax payment purposes. In order to achieve economical benefit of a flare gas measurement, the purpose of the measurement could be to identify points of leakage, to obtain better control with emission rates or mass balancing. These application areas for ultrasonic gas flow meters have added metering requirements beyond the direct flare gas metering requirements. Also, this has opened a new market within refineries and onshore process plants.

Irrespective of the application, the operator would not invest in a flare gas metering system, or any other system for that matter, unless the investment would be economically beneficial in the long term. In that respect the choice of technology for the metering application is of most importance. An evaluation of cost versus benefit should be made, and the basis for the evaluation would be parameters as investment, installation and maintenance costs, measurement uncertainty, repeatability, measurement range, reliability and non-intrusiveness of the measurement technology. The ultimate flow meter would of course be the best sum of all these parameters. With a very low selling price. However, as they say, you get what you pay for, so the general rule still applies; quality costs. Irrespective of this, more and more operators world wide have experienced that measurement of flare gas implies control of emission. And control pays off, so the investment in measurement technology is really an investment in increased profit.

As earlier stated, more focus have been put on the environmental and economical aspects of the gas flaring, and in some countries the operators have to pay taxes for their CO2 emissions. Accordingly, in order to fulfil the regularity requirements, the operators requirements regarding the flare gas metering systems have changed.

2.1 Governmental Legislation

In Norway, in 1993, regulations relating to measurement of fuel and flare gas for calculation of CO2 tax in the petroleum activities were resolved (1) the regulation was stipulated by the Norwegian Petroleum Directorate (NPD) by virtue of Section 5 of Act of 21 December 1990 relating to CO2 tax in the petroleum activities on the Norwegian continental shelf. The purpose of the regulation was to ensure that the calculation and reporting of CO2 tax was based on accurate measurements.

Inevitably, oil companies operating on the Norwegian continental shelf had to relate to this regulation. However, also manufacturers of flare gas metering systems operating in this market were forced confirm that their instrumentation did comply with these regulations.

According to (1), only three measurement methods were acknowledged for flare gas metering on the Norwegian continental shelf:

. Ultrasonic measurement,
. Insertion turbines with density measurement/density calculation,
. Thermal mass meters.

However, a new revision of (1) expected to be accepted this year, states an operational range of flare gas meters up to 100 m/s, which in terms only qualifies the ultrasonic time-of-flight flow meter technology. This is not only a clear indication of what the future flare gas metering technology is expected to be, but is states that it is, today, the only proven technology to be utilised for these demanding applications. The single requirement of ultrasonic flow meter for flare gas metering is also stated in NORSOK STANDARD I-104, Section 7.1.3.(2).

3 FLARE GAS METERING

With the change in the operation of the flare systems, an adaptation of the flare gas metering systems has been imperative. With flare systems being installed primarily for safety purposes, the flare gas metering systems must cope with dramatically changes in the flow velocity, gas composition and temperature over a very short time scale. Hence, the measurement challenges may vary a lot over a short time period.

Due to the nature of e.g. a process shut-down, when all of the process gas is flared, the flow velocity may exceed 100 m/s. As a result of this extremely high flow velocity, unwanted particles and components such as oil, water, salt and scale may be transported along the flare pipeline. Knowing this, it is quite evident that any instrumentation that intrudes into the flare pipeline might get influenced, or at the worst get damaged, during such a shut-down.
Accordingly, limitations of what metering systems that can be put in operation have arisen.

3.1 Flare Gas Measurement Methods

Traditionally, conventional metering systems were used for flare gas measurements. Typical meters that were utilised are:

. insertion turbines
. Thermal mass meters
. Annubars

A turbine meter utilises the principle that the gas is led through the meter rotor. The rotor is designed with a specific number of blades positioned at a precise angle to the flow stream.
The gas impinges on the rotor blades causing the rotor to rotate, with the angular velocity of the rotor being directly proportionally to the gas velocity. Clean fluids are required to prevent contamination of the bearings unless sealed bearings are used. Insertion type turbine meters cause negligible pressure drop, but due to the local velocity measurement, the measurement uncertainty is higher than for conventional full-bore turbine meters. Typical flow range for such meters is up to 30 m/s.

Thermal mass meters are typically based on two Thermowell-protected Resistance Temperature Detectors (RTDs). When placed in the process stream, one RTD is heated and the other is sensing the process temperature. The temperature difference between the two elements is related to the process flow as higher flow rates cause increased cooling of the heated RTD. Thus, the temperature difference between the two RTDs is reduced. As with the insertion turbine meter, the thermal mass meter causes negligible pressure drops. In addition, it has no mechanical parts, high temperature range and requires little installation space. Typical flow range for the thermal mass meters is 0.3 to 30 m/s.

Annubars have been used for years on flare applications. An annubar is a differential pressure device with the signal increasing proportional to the square of the flow. Annubars are good for high flow rate applications, but are not good for low flow applications due to the small pressure difference these flows represent. For mass flow applications, annubars require pressure and temperature compensation. The characteristics of the annubar are high measurement principle, it causes a pressure drop in the pipe as it intrudes with the process flow. This again implies potentially high maintenance costs. Typical turn down ratio is 10:1,
So that several annubars are required in order to cover a large flow range.
Other metering types, such as positive displacement meters, vortex meters, hot-wire anemometers, coriolis mass flow meters and sonic nozzles have too limited flow range to be considered for such metering applications. In addition, some of these metering types introduce an unwanted pressure drop in the pipe.

A metering technology that has gained more and more acceptance for flow measurements is the ultrasonic time-of-flight meters.

4 ULTRASONIC TIME-OF-FLIGHT FLOW METERS

The technique of transit-time flow metering is well known to the physicists dealing with flow-metering problems and was first used by the German engineer Rutten in measuring water and steam flows in large canals as found in power station practice (3).

The ultrasonic time-of-flight gas flow meter is based on measurement of contra propagating ultrasonic pulses, in which the transit time of the sonic signal is measured along one or more diagonal paths in both the upstream and downstream directions.


Obtain the average axial flow velocity, some order of correction to the measured flow velocity is required. One way to utilize this correction, K, is to use the Reynold's number as a measure of the flow profile, and adjust the measured axial flow velocity according to a function based on the Reynold's number estimated.

As can be seen from these equations, the flow velocity measured along the ultrasonic cord does not depend on pressure, temperature or any other process parameter. This is a very important characteristic of an ultrasonic flow meter, as it implies that no adjustment due to changes in e.g. gas composition is required. Accordingly, an ultrasonic flow meter should present valid measurements independent of the process conditions. Thai is, within the flow, pressure and temperature range specified for the meter in question.

In addition to the axial flow velocity, also the velocity of sound can be calculates on the basis of the time-of-flight measurements, see Equation (4.4). Once the velocity of sound, c, is known, the isentropic index, can be found using known equations from thermodynamics relating isentropic index and the density, of the gas with the state variables. Empirical formulae have been developed for finding the molecular weight and the density of the gas from the transit times (t12and t21). Accordingly, in addition to the volume flow rate, the Fluenta FGM 130 can also present the mass flow rate of the flare gas.

For more and more flare gas metering challenges, only ultrasonic transit-time meters are regarded to be applicable. This is, today, the only proven technology that can meet the extremely high turn-down ratios required for these applications. The NORSOK standard (2) claims an operating velocity range of 0.2 -100 m/s, giving a turn-down ratio of 500:1. One could of course discuss this requirement dependent on the installation, e.g. an LP (Low pressure) or Vent flare will generally not represent measurement challenges in this flow range. However, a flare system does usually comprise of a HP (High Pressure) flare, and potentially of an LP and/or a Vent flare. Experience has shown that the maximum specified flow range for these HP pipelines are likely to be in the 100 m/s area. From the operators'view, it is unquestionable preferable to utilize one metering instrument for all these applications, if only ultrasonic flare gas meter on the market able to operate up to three flare pipelines simultaneously with one Flow computer

Putting the specified upper flow velocity for flare gas meters in perspective; a hurricane is defined as wind speed of approximately 30-32. m/s. Thus, the required measurement range is more than three times the wind speed of a hurricane. Anyone having experienced a hurricane knows that both the carry along effect of voices in the wind and the general noise level is dramatic. Bearing this in mind, it is obvious that both the ultrasonic signal propagating along the measurement card and the signal processing system must be very robust in order to extract time-of-flight information under such conditions. At the same time, the meter must perform accurate measurements at the lowest flow velocities. Both the Norwegian CO2 tax regulations (1) and the NORSOK standard (2) state measurement uncertainty limits of ±5% of measured volume flow rate for flare gas meters. This applies for the entire measurement range. The measurement uncertainty of a meter for flare gas applications shall be verified by an uncertainty analysis within a 95% confidence level.

In order to meet these requirements, the Fluenta FGM 130 utilises broadband ultrasonic transducers and Chirp excitation to obtain a Signal-to-Noise ratio requisite at the higher flow velocities. By utilizing this t4echnique, the Fluenta FGM 130 has demonstrated flow measurements up to 120 m/s in a wind tunnel test (4).


As can be seen, a train of Chirp and CW signals are transmitted every 10 ms, implying 100 measurements every second. In one measurement period, 100 measurements are carried out for Chirp and CW, both upstream and downstream. This results in an updated flow measurement value every 4-5 seconds in the low flow range. At the higher flow rates, only Chirp measurements are utilised, giving an updated flow measurement value every 2-3 seconds. The measurement rate of 100 per second ensures a fast dynamic response to rapid changes in the flare stack. This is a situation likely to occur where zero-flaring is the general picture, followed by a process shut-down or a sudden disposal of large amounts of flare gas.


4.3 Features of Importance

What is a very important feature of a flare gas meter at these conditions, with flow velocities up to and above 100 m/s, is that no meter parts intrude into the pipe cross-section. If this were the case, particles and droplets may affect the metering performance not only at the time of depositing, but also on a permanent basis if the deposits are not removed from the metering parts. At worst, the metering parts can be damaged, resulting in malfunction and erroneous readings. Generally, ultrasonic flare gas meters utilize transducers are mounted with the front centre point flush with the inner pipe wall for all pipe sizes from 6" to 72", see Fig. 4.1. However, some ultrasonic meters utilize other transducer mounting configurations, with the transducer intruding up to ? D into the pipe cross section. Depending on the application and the pipe size, this may be favourable, but the sensors will be exposed to process debris.

New technology, more powerful signal-and microprocessors have increased the availability of measurement data from an ultrasonic gas flow meter. As more and more of the signal processing can be implemented in software, both raw data and processed data can be acquired and analysed. By having this information on a digital form, e.g. trough a serial communication line, no information is lost due to non-linearities, bit resolution and offset and gain errors found in digital-to-analogue and analogue-to-digital converters. By using e.g. RS-422 or RS-485 serial communication, data can be transmitted over long distances. Combined with the Modbus protocal, data can be transferred to and from a supervisory system with high data integrity. From the Fluenta FGM 130 Flow Computer over 100 parameters are continuously available for e.g. a supervisory system. This information can be utilised for monitoring the meter performance and trending over longer time periods.

In addition, the flare gas metering system itself, being "intelligent", can utilise the internal trend information for self-diagnostics, to improve the quality of the meter performance. All measured parameters, e.g. transit times up-and downstream, pressure and temperature, reflect the process condition in the flare stack. Disproportionate change in one of these parameters in proportion to the other measured parameters could indicate an erroneous measurement condition.

4.4 Automated Condition based Maintenance

Automated condition based maintenance implies that regular service intervals on e.g. a transmitter are omitted at the expense of service only demand. This maintenance scheme requires direct information of the transmitter status, so that an evaluation of the transmitter can be carried out. If the transmitter status itself is not sufficient to give information of the transmitter condition, a duplicated transmitter solution might represent the required solution.

The Fluenta FGM 130 has implemented an interface enabling up to twelve HART transmitters to be connected to one Flow Computer. For each of the maximum three measurement systems, up to two pressure and two temperature transmitters can be configured. The Flow Computer will continuously present both the measurement values and the communication status for each of the HART transmitters to the supervisory system through the modbus serial communication link. By utilizing duplicated transmitters, the supervisory system can compare the measurement values for each transmitter and give a warning if the measurement values are adrift or the transmitter status indicates an error.

Although the basic technology for injecting carbon dioxide (CO2) for enhancing oil production has not significantly changed in recent years, methods for monitoring and controlling injection are still being refined.

Operations in the Postle field, Texas County, Okla., show how an operator uses chromatographs and remote terminal units to monitor injection in a CO2 flood.

Operations
For many years, Mobil Exploration & Producing U.S. Inc. has used "water alternating gas" (WAG) techniques in its CO2 flooded fields. This concept relies on the premise that injected CO2 mixes with oil in the reservoir, creating a lighter, easier way to move fluid.

In the WAG process, CO2 is injected for a period of time. After CO2 injection is stopped, water injection commences.

Water pushes the lightened oil toward adjacent producing well bores. This CO2-laden crude oil is pumped to the surface and then piped to a central tank battery where oil, water, and gas are separated. After separation, the water goes to a facility for reinjection, the oil is sold, and the gas is piped to a treatment plant.

In the treatment plant, the gas is dehydrated and natural gas liquids may be separated for sale. The dehydrated CO2 stream is then compressed and returned for reinjection.

The WAG process may continue for many years until the oil in the reservoir is depleted.

During secondary recovery with water injection, Mobil's Postle field had a producing capacity of 23,000 b/d. The field became a candidate for tertiary CO2 recovery when production declined to about 2,000 b/d. With the CO2 WAG technique, production is expected to reach 12,000 b/d.

Postle receives CO2 from two sources. Virtually pure CO2 is delivered by pipeline from a CO2 source field in New Mexico, and the remaining CO2 is derived from recycled gas with a CO2 concentration as low as 85%. Typically, the two streams are combined to produce a mixture varying between 93 and 97% CO2.

Because of piping restrictions, pressures at the injection wellheads deviate by as much as 200 psi from the pipeline delivery point. Process temperatures will vary from 55° F. in the winter to 75° F. in the summer, but are relatively consistent throughout the system.

The operations require precise measurements. Partners are involved in the operating expense burden, so that accurate accounting for all parties is required.

In addition, optimum operations call for verification of pattern sweep efficiency, which is the economical use of CO2. This requires affordable methods for monitoring and control at the wellheads.

Flow computation
Flow rates can be calculated with fundamental principles of fluid mechanics, shown as a set of flow equations in the American Gas Association Report No. 3, Third Edition, 1990.

Mobil selected this method primarily because of the wide range of empirical data relating to differential-producing orifice flowmeters and the corresponding correlation to wedge meters.

The volumetric flow rate at base conditions as given by Report No. 3 is:

Qv = Nl Cd Ev Y d 2 (rt,pDP)1/2 /rb

where:
Qv = Volumetric flow rate at base (standard) conditions
Nl = Unit conversion factor
Cd = Orifice plate discharge coefficient
Ev = Velocity of approach factor
Y = Expansion factor
d = Orifice plate bore diameter calculated at flowing temperature
rt,p = Fluid density at flowing conditions (based on flowing temperature and pressure)
DP = Orifice differential pressure
rb = Fluid density at base conditions.

The most accurate application of the equation dictates the measurement of three variables:

1. Flowing pressure
2. Orifice differential pressure or delta pressure
3. Flowing temperature.

All three variables can be readily monitored with transducer technologies.

Density effect
A factor of particular interest is the mass per volume, or density (rt,p, rb) of the process. CO2 fluid-stream density is greatly affected by pressure, temperature, and component mixture. This fact can be intuitively deduced when one realizes that the fluid is typically somewhere between a liquid and a gaseous state.

Leaving all other variables the same and modifying only the component concentrations to 98% CO2, 0.67% C1, 0.67% C2, and 0.67% C3 causes density to change to 55.26 lb/cu ft. That is a difference of almost 10%.

The density of a more practical injection mix of 98.5% CO2, 1% C1, 0.4% C2, and 0.1% CO3 at 1,800 psia and 72° F. is 53.01 lb/cu ft. If the mix changes to 93% CO2, 3% C1, 3% C2, and 1% CO3, and pressure drops to 1,600 psia, the density decreases to 47.88 lb/cu ft. Once again, that is a difference on the order of 10%.

To translate this example into volumetric flow terms, the following conditions can be assumed:

* Orifice diameter = 3.5 in.
* Pipe diameter = 6.065 in.
* Base conditions = 60° F., 14.65 psia
* Delta pressure = 50 in. of H2O.

The flow rate of the first mixture is 30.2 MMscfd, compared to the second of 29.3 MMscfd. Therefore, a 3% error would occur if one did not consider density changes.

Automation
Density can be measured directly with an instrument appropriately named a densitometer. From perspectives of initial capital outlays as well as ongoing maintenance expenses, the drawback is the cost of installing densitometers at multiple locations.

Therefore, Mobil sought other methods for determining CO2 density in the Postle field.

In the initial configuration, the system consisted of an RTU located at two critical measurement points. One is the pipeline delivery point for the purchased CO2 and the other is downstream of injection sites, which have different partner participation than the sites in the remainder of the field.

This placement enables equitable distribution of process costs between different entities.

The RTUs execute a real-time program to monitor the pressure, temperature, and delta pressure occurring at an orifice or wedge device. Each RTU communicates via radio links to a central computer in the field office.

A gas chromatograph at the master meter site is similarly linked to the computer. The master computer program continually extracts the gas constituent information for subsequent relay to all RTUs.

Embedded firmware in the RTUs provide precise calculations of density and heat-capacity ratio, as well as a close estimate of viscosity. Heat-capacity ratio and viscosity influence the calculation of flow rate factors such as Y and C.

Applying the AGA No. 3 flow equation with these parameters results in an accurate CO2 volume accumulation.

The gas chromatograph is housed in two industrial-style enclosures mounted near an RTU site. For ease of maintenance and to eliminate potential corrosion of electronic components resulting from exposure to combinations of CO2 and water vapor, the analyzer is separated from the controller.

The unit is a single-stream device capable of furnishing a C5+ analysis. This range permits determination of the most common elements and compounds such as CO2, N (nitrogen), C1 (methane), C2 (ethane), C3 (propane), C4 (butane), and C5 (pentane). Results are updated via radio links about every 10 min.

A central server, or computer master station, transmits the mole fractions to individual RTUs. Each RTU performs flow rate calculations and volume accumulations.

Within an RTU, data including hourly average flowing and differential pressures, hourly average temperature, and hourly volume accumulation are maintained for a period of up to 35 days.

Should a user desire, the master station can obtain this historical information on demand. The central computer also offers an operator daily summaries for purposes of closeout.

To verify chromatograph determinations with laboratory results, the master software makes a provision for the download of a sample volume rate to an RTU. This quantity sets the volume interval by which the RTU triggers an external gas sampling mechanism.

The rate proportional sample can be subsequently analyzed monthly at an offsite facility. A user then decides whether to keep the existing chromatograph data, or to edit compositions directly.

If edited, the existing flow volumes are updated with newly calculated values. This gas sample feature permits system backup in case of chromatograph failure, and satisfies requirements for installations where a sample is necessary to adhere to field operations.

Field results
Prior to system commissioning, conventional flow computers provided volume values within ±8% of the figures supplied by densitometer-based CO2 provider companies. With the current system, the volumes are within ±0.6%.

In short, the volumes match sufficiently to deem the system accurate for stream measurement purposes and for field surveillance.

Wellhead application
With this approach proven in the initial configuration, Mobil is preparing to implement this system at the wellheads.

Because RTUs are already present in a monitoring capacity using wedge meters, and the chromatograph analysis is accessible by all RTUs, no additional equipment is required.

The incremental cost difference is limited to a firmware upgrade, which is inexpensive on a per-unit basis.

Notwithstanding the obvious initial installation advantage in the Postle field, the chromatograph technique offers distinct cost savings from a maintenance point of view.

Calibration and continued operational verification of densitometers is a time-consuming task that is difficult under field conditions. This time is increased by the travel required to reach widespread sites in a typical injection scheme.

Total maintenance time increases rapidly because of the multiple number of devices in place.

When a chromatograph is used, personnel need only work with one device at a single location, and the calibration process is straightforward. Therefore, implementation of these devices can be considered more cost effective compared to densitometers when multiple points along a common pipe system are involved.

Some Guidelines in Flowmeter Selection for Liquids
Flowmeter element	Recommended Service	Rangeability	Pressure Loss?	Typical Accuracy, percent	Required Upstream pipe, diameters	Effects from changing viscosity?
Coriolis mass Meter	Clean dirty viscous liquids some slurries	10 to 1	Low	±0.5 of rate	None	None
Elbow meter	Clean dirty liquids some slurries	2.5 to 1	Very low	±5 to ±10 of full scale	30	Low
Electromagnetic	Clean, dirty viscous con- ductive liquids and slurries	40 to 1	None	±0.5 of rate	5	None
Flow nozzle	Clean and dirty liquids	4 to 1	Medium	±1 to ±2 of full scale	10 to 30	High
Orifice	Clean, dirty liquids; some slurries	4 to 1	Some	±2 to ±4 of full scale	10 to 20	High
Pitot tube	Clean liquids	3 to 1	Very low	±3 to ±5 of full scale	20 to 30	Low
Positive Displacement	Clean viscous liquids	10 to 1	High	±0.5 of rate	None	High
Target meter	Clean dirty viscous liquids some slurries	8 to 1	Medium	±1 to ±5 of full scale	10 to 28	Medium
Thermal Mass	Clean dirty viscous liquids some slurries	10 to 1	Low	±1 of full scale	None	None
Turbine	Clean, viscous liquids	20 to 1	High	±0.25 of rate	5 to 10	High
Ultrasonic (Doppler)	Dirty, viscous liquids and slurries	10 to 1	None	±5 of full scale	5 to 30	None
Ultrasonic (Transit Time)	Clean, viscous liquids some dirty liquids(depending on brand)	40 to 1	None	±1 to 3 of full scale	10	None
Variable area	Clean dirty viscous liquids	10 to 1	Medium	±1 to ±10 of full scale	None	Medium
Venturi	Some slurrys but clean dirty and liquids with high viscosity	4 to 1	A little	±1 of full scale	5 to 18	High
Vortex	CLean, dirty liquids	10 to 1	Medium	±1 of rate	10 to 20	Medium
Wedge	Slurries and liquids with high viscosity	4 to 1	A little	±0.5 to ±2 of full scale	10 to 30	Low
Weir V-notch	Clean, dirty liquids	100 to 1	Very low	±2 to ±5 of full scale	None	Very Low

---

Dwyer J has submitted this flow article. Flowmeterdirectory in no way
claims the accuracy of the above chart nor will be held liable for the contents thereof.

Effective use of water for crop irrigation requires that flow rates and volumes be measured and expressed quantitatively. Measurement of flow rates in open channels is difficult because of nonuniform channel dimensions and variations in velocities across the channel. Weirs allow water to be routed through a structure of known dimensions, permitting flow rates to be measured as a function of depth of flow through the structure. Thus, one of the simplest and most accurate methods of measuring water flow in open channels is by the use of weirs.

In its simplest form, a weir consists of a bulkhead of timber, metal, or concrete with an opening of fixed dimensions cut in its top edge. This opening is called the weir notch; its bottom edge is the weir crest; and the depth of flow over the crest (measured at a specified distance upstream from the bulkhead) is called the head (H). The overflowing sheet of water is known as the nappe.


Types of Weirs

Two types of weirs exist: sharp-crested weirs and broad-crested weirs. Only sharp-crested weirs are described here because they are normally the only type used in the measurement of irrigation water. The sharp edge in the crest causes the water to spring clear of the crest, and thus accurate measurements can be made. Broad-crested weirs are commonly incorporated in hydraulic structures of various types and, although sometimes used to measure water flow, this is usually a secondary function. The components of a sharp-crested weir.

The weir selected should be that most adapted to the circumstances and conditions at the sites of measurement. Usually, the rate of flow expected can be roughly estimated in advance and used to select both the type of weir to be used and the dimensions of the weir. The following facts should be considered when a specific type of weir is selected for a given application.
The head should be no less than 0.2 feet and no greater than 2.0 feet for the expected rate of flow.

For the rectangular and Cipolletti weirs, the head should not exceed one-third of the weir length.

Weir length should be selected so that the head for design discharge will be near the maximum, subject to the limitations in 1 and 2.

Measurements made by means of a weir are accurate only when the weir is properly set, and when the head is read at a point some distance upstream from the crest, so that the reading will not be affected by the downward curve of the water. That distance should be at least 4H. The proper method of measuring H.

Rectangular-Notch Weir
The rectangular-notch weir is illustrated in Figure 3 . This is the oldest type of weir now in use. Its simple construction makes it the most popular. The discharge equation for the rectangular-notch weir is:

Equation 1 gives discharge values for rectangular-weir notch lengths of up to 4 feet and depths of flow or head of up to 1.5 feet.

The High Void-Fraction Multiphase Flowmeter developed out of the nuclear reactor safety expertise of its inventor, engineer James Fincke at the U.S. Department of Energy's Idaho National Engineering and Environmental Laboratory. The almost-maintenance-free wet gas flowmeter, which can measure the flow rate of gas and liquid from natural gas wellheads 5- to 10-times more accurately than conventional methods, in real time, and continuously, has been licensed by the Perry Equipment Corporation (PECO) in Texas and won Fincke and his PECO colleagues a 1999 R&D 100 Award.

FILLS VOID FOR HIGH-VOID FRACTION MEASUREMENTS
R&D Magazine presents one hundred of these awards yearly for the most important new products. Bulent Turan, a manager in PECO's Flow Measurement Division that is testing and marketing the flowmeter, said, "The award tells us we've been going down the right track in developing this technology. This device provides the accuracy the industry has long been looking for."
PECO is currently installing the meter on natural gas wellheads to demonstrate it works as well in the real world as it did in the lab. Doyle J. Gould, Vice President of Marketing and Business Development at PECO, expects the meter to fill a natural gas industry void. "There's not a piece of equipment out there like it," he said, "so we believe it will take off like gangbusters."

Natural gas producers drill about 6000 new wells every year, and over 320,000 are expected to be in use in the United States alone by the year 2001. The natural gas flowing from these wells is usually mingled with either valuable liquid hydrocarbon or a briney mix of hydrocarbon and salt water. Current equipment to measure the volume of flow, such as mechanical test separators, costs between $50,000 and $400,000 and may be off by 10-20 percent of the volume.

THAT'S HEAVY, DUDE
The difficulty in measuring wet gas arises from the fact that gas and liquid are both fluids with different properties. In a standard flowmeter, the measured pressure of a flowing fluid can be used to determine its velocity, from which its volumetric flow rate is calculated. If the fluid is all gas or all liquid, the differential pressure accurately reflects the flow rate. With a mixture, however, there are no distinctions between the two, which results in uncertain measurement of both fluids. To determine the individual flow rates, the ratio of gas to liquid must be known.

"If you know how much liquid is there," said INEEL's Fincke, "you can account for it. But that's like knowing the answer before asking the question."

The inaccurate reading is a result of the design of the standard flowmeter. The basic flowmeter consists of a pipe that is constricted on one end. The constriction causes the fluid flowing through the pipe to accelerate. Before and after the constriction, two pressure measurements of the accelerating liquid are taken and the difference in pressure is converted into a volumetric flow rate.

ONE PHASE, TWO PHASE . . .
If the fluid is single-phase, such as all gas, determining the volumetric flow rate is a simple, accurate calculation. In a gas-liquid mix, however, the denser fluid—liquid—accelerates much slower than the lighter one—gas. The differential pressure, then, is a skewed reading of the two fluids that overestimates the gas phase and underestimates the liquid phase.

LIGHT PHASE, DENSE PHASE
Fincke needed to determine how the equilibrated fluids behaved mathematically to calculate the correct flow rates in the wet gas flowmeter, and he did this using low-pressure air and water. "We developed a flowmeter geometry and some mathematical theory that relates the pressures to the flow rates," he said. "But then PECO wanted to do some testing with natural gas hydrocarbons at pressures similar to what you find at wellheads."

Using known amounts of separated natural gas and liquid hydrocarbon, the researchers mocked up a wellhead to gather data over a wide range of conditions and with different flowmeter geometries. The tests confirmed the validity of Fincke's mathematical models. INEEL's wet gas flowmeter is accurate with wet gas that contains up to 10% liquid. If natural gas is much wetter than that, Fincke said, the producers may have a problem that needs to be addressed in the field.

SEPARATION ANXIETY
The natural gas industry currently avoids the problem of taking multiphase measurements by using mechanical separators that allow the liquid and gas components to be measured independently. For small natural gas producers, these separators may be the best option, said Fincke. Natural gas flows into a tall, skinny tank, where the two components settle out—liquid is removed from the bottom and gas from the top to be measured. Even so, the measurement can be off by as much as 20% of the gas volume.

Large producers use portable test separators that they cart around on flatbed trucks to measure their individual wellheads a couple times a year. Test separators for small and large producers are expensive, require workers to operate and don't monitor the flow continuously. The wet gas flowmeter, on the other hand, costs between $12,000 and $20,000, has no moving parts and can operate automatically and continuously.

Fincke said the wet gas flowmeter will be useful for two wide-ranging applications: reservoir management and common pipeline usage. Since the flowmeter is inexpensive and small—about 3 feet long—it can be used on all natural gas reservoirs all the time and even on offshore rigs. "The gas well problem is an area that was sorely lacking an economical solution," said Fincke.


UNCOMMON SOLUTION FOR A COMMON PIPELINE

Sometimes a number of producers share a common pipeline from the same gas field. Since profits are based on the gas portion of the mixture, inaccurate metering can adversely affect producers' and distributors' compensation. The wet gas flowmeter will allow producers to determine how much gas their wellheads are contributing to common pipelines, and being within 2-4% of the volume is more acceptable than being off by 20%. "They need to know how much each is producing with accuracies that are agreeable to everyone sharing the pipeline," he said.

PECO is currently beta-testing the flowmeter on natural gas wellheads. "If a producer is interested," said Fincke, "PECO will size a meter for the well, bring it out, put it on the well long enough to convince the producer that it will work and do what we say it will do. And then the producer will buy it."

"We need to show the natural gas industry that the meter performs to meet their needs," said Fincke. "We hope it will become the accepted measurement solution."

Accurate gas and liquid measurement is best achieved with an optimized flow profile. All those involved with a custody transfer station benefit from flow profile standards of accuracy that far exceed those of the past 40 years. Well, standards have changed. By including flow conditioning in their latest metering station design standards, the American Petroleum Institute (API) and ISO have recognized a revolutionary new technology that insures an unparalleled degree of flow accuracy. This technology is an isolating flow conditioner-placed upstream of a flowmeter-which conditions the flow such that it enters the flowmeter with a uniform, fully developed profile. This happens regardless of the pipe configuration prior to the conditioner.

Another factor required in this industry is the ability to assess a measurement facility's full cost of ownership. This includes consideration of the initial capital, commissioning, training, spareparts , maintenance, and calibration costs for the equipment' s lifetime. What this means is that full ownership cost is actually several times initial capital investment, spread over time. Considering such costs gives a more realistic financial picture to use as a deciding factor in equipment selection. This, of course, leads also to isolating flow conditioning technology.

Two of the measurement chain's most significant parameters are proper installation and application of flowmeters in conjunction with flow conditioners ; yet, even though they influence the factor s mentioned above, they may be neglected in owners hip cost assessments . This could be a significant over sight, since flow conditioning's role is to ensure that a pipeline' s unpredictably variable flow environment when it enters the custody transfer station is stabilized so it resembles as closely as possible the actual flow of the gas under consideration. The closer this resemblance, the more reliable and fiscally sound the flow measurement.

Installation Effects
All inferential flowmeters (for example, orifice, ultrasonic, and turbine meters) are subject to the effects of velocity profile, swirl, and turbulence structure. The meter calibration factors or empirical discharge coefficients are valid only if geometric and dynamic similarity exists between the metering and calibration conditions or between the metering and empirical database conditions-in other words, under fully developed flow conditions. In fluid mechanics, this is commonly referred to as the Law of Similarity.

In the industrial environment, multiple piping configurations are assembled in series, generating complex problems for standards-writing organizations and flow metering engineers. The challenge is to minimize the difference between the actual flow conditions and the fully developed flow conditions in a pipe, in order to maintain minimum error associated with the selected metering device's performance.

Research programs in both Western Europe and North America have confirmed that many piping configurations and fittings generate disturbances with unknown characteristics. Even a single elbow can generate very different flow conditions-from "ideal" to "fully developed" flow-depending on its radius of curvature (that is, mitered or swept). In addition, the disturbance piping configurations generate is further influenced by the conditions prior to these disturbances.

In general, upstream piping elements may be grouped accordingly:
- Those that distort the mean velocity profile but produce little swirl.
- Those that both distort and generate bulk swirl.

As a result, today's measurement industry focus is to lower uncertainty levels associated with these distorted flow conditions.

Flow Conditioners
The problem, then, is to minimize the difference between real and distorted flow conditions on the selected metering device, thus maintaining the low uncertainty required for fiscal applications . For clarity, this will be referred to as "pseudo- fully developed" flow .

A method to circumvent the influence of the fluid dynamics on the meter 's performance is to install a flow conditioner in combination with straight lengths of pipe to "isolate" the meter from upstream piping disturbances . This isolation, however, is never perfect.

Pseudo-Fully Developed Flow
From a practical standpoint, we generally refer to fully developed flow in terms of swirl-free, axisymmetric, time average, velocity profile in accordance with the Power Law or Law of the Wall prediction.

To bridge the gap between research and industrial applications, the term pseudo-fully developed flow will be defined as follows:
"The slope of the orifice meter's discharge coefficient deviation or meter factor deviation that asymptotically approaches zero as the axial distance from the flowmeter to the upstream flow conditioner increases."

Isolating Flow Conditioner
To truly isolate flowmeters, the optimal flow conditioner, placed in sequence before the flowmeter, should achieve the following design objectives:
- Low permanent pressure loss (low head ratio).
- Low fouling rate.
- Rigorous mechanical design.
- Moderate cost of construction.
- Elimination of swirl [less than 2°-when the swirl angle is less than or equal to two (2) degrees, as conventionally measured using pitot tube devices, swirl is regarded as virtually eliminated].
- Independence of tap sensing location (for orifice meters).
- Pseudo-fully developed flow for both short and long straight lengths of pipe.

For turbine and ultrasonic meters, when the empirical meter factors for both short and long piping lengths are approximately +/- 0.10% for liquid applications, or approximately +/- 0.25% for gas applications, and if it is also shown to be independent of axial position, then it is assumed to be at a minimum and to be pseudo-fully developed.

For orifice meters, the term Cd deviation (%) refers to the percent deviation of the empirical coefficient of discharge or meter calibration factor from fully developed flow to the disturbed test conditions. Desirably, this deviation should be as near to zero as possible. As explained above, a minimal deviation is regarded as +/- 0.25% for gas applications.

Experimental Results
Several flow conditioners have been evaluated by the Gas Research Institute for comparison purposes as part of their Installation Effects Research Program. For these tests, the same test loop or apparatus was used, to provide consistency between experiments.

For the test loop, gas enters a stagnation bottle and flows to a straight section of pipe. The gas then enters a 90° elbow or tee followed by a meter tube and flowmeter. The flow conditioners tested are positioned at various upstream distances, X, from the orifice plate. To obtain dimensionless terms, the distance X was divided by the meter tube nominal diameter, D.

For the experiments, the selected flowmeter was a concentric, flange-tapped, square-edged orifice meter with Betas of 0.67 and 0.75. The internal diameter of the meter tube, IDp, was 102.29 mm (4.027 inches) and the length of the meter tube, L1, was 17 nominal pipe diameters (17D). For certain AGA tube bundle measurements, the length of the meter tube, L1, was increased to 45D and 100D lengths. The flow disturbance was created by either a 90° elbow or a tee installed at the inlet to the meter tube.

Analysis of Results
The results obtained for the AGA design, using meter tube lengths of 17D, 45D, and 100D,
indicate a minimal deviation when:
· L1 = 17D; and X/D = 12 - 15
· L1 = 45D; and X/D = 8 - 9
· L1 = 100D; and X/D = 8 - 9 or > 45

Tests on four flow conditioners in a 17D long test pipe with a tee were funded by GRI. The Beta for the orifice meter was 0.67 and the Reynolds number was approximately 900,000.

These results are not surprising in light of current understanding of pipe flows. The tube bundle-long relied upon to condition the disturbances present in gas flow-does an excellent job of eliminating swirl. However, the fixed diameter tubes generate an unstable turbulence structure that begins to redevelop rapidly. Also, the constant and high radial porosity does not offer a method to redistribute any asymmetric flow patterns.

A new breed of isolating flow conditioners produces pseudo-fully developed flow conditions for both short and long piping configurations. This is evidenced by the slope of the orifice meter's discharge coefficient deviation or meter factor deviation asymptotically approaching zero as the axial distance from the flowmeter to the upstream flow conditioner increases. The new breed of flow conditioners has also demonstrated an insensitivity to tap sensing location, confirming the presence of pseudo-fully developed flow.

Measurement Standards
Orifice Meters
The research programs have clearly indicated that the requirements specified in both orifice standards are erroneous and that minimum straight length specifications in the standards (ISO 5167 and AGA no. 3) are in urgent need of revision.

Present domestic and international measurement standards provide installation specifications for pipe length requirements and flow conditioners upstream of orifice meters (ANSI's 2530 and ISO's 5167). A significant revision with respect to piping configurations with and without flow conditioners is presently underway for both standards. Both standards are out for ballot in 1999.

With respect to installation effects and the near-term flow field, the correlating parameters that impact similarity vary with flowmeter type and design. However, it is generally accepted that the concentric, square-edged, flange-tapped orifice meter exhibits a high sensitivity to time average velocity profile, turbulence structure, and bulk swirl and tap location.

In North America, current design practices utilize short upstream piping lengths with a specific flow conditioner-AGA tube bundles-to provide pseudo-fully developed flow in accordance with the applicable measurement standard (ANSI 2530/A.G.A. 3/API MPMS 14.3). Most North American installations consist of 90° elbows or complex header configurations upstream of the orifice meter. Tube bundles in combination with piping lengths of 17 diameters (17D) have been installed to eliminate swirl and distorted velocity profiles. Ten diameters (10D) of straight pipe are required between the upstream piping fitting and the exit of the tube bundle, and 7 diameters (7D) of straight pipe are required between the exit of the tube bundle and the orifice meter.

Recent research indicates that the flow conditioning error is a function of time-averaged velocity profile, swirl angle, tap sensing location, and turbulence structure. As a result of these new findings, a significant improvement in flow conditioner performance has been achieved over other devices designed to tackle velocity and swirl alone.

Ultrasonic Meters
Ultrasonic meter technology is relatively new to fiscal applications. This technology shows tremendous potential for performance equal to or better than most world-class flow calibration laboratories.

Preliminary research in natural gas has indicated the need for flow conditioners to ensure compliance with the Law of Similarity and an uncertainty of +/- 0.25%.

Preliminary research in liquid has also indicated the need for flow conditioners that ensure compliance with the Law of Similarity and an uncertainty of +/- 0.1%.

Turbine Meters
For gas applications, AGA report no. 7 and ISO 9951 cover the requirements for their installation and performance.

For liquid applications, API MPMS chapters 5 and 6 cover the requirements for their installation and performance. Recent research in the laboratory and the field has indicated the sensitivity to velocity profiles approaching the turbine meter. Errors of as much as 1.0% were reported due to partially blocked strainers and/or provers located upstream of the meter runs.

Outlook
Designing and operating an accurate flowmeter application requires understanding of the fluid's physical properties. An envelope must be drawn around the process (or operating) conditions, and the identification of any special conditions. Understanding the physical principles upon which the selected flowmeter is based and comprehending its sensitivities to physical and process conditions is critical. Most important, designing and operating an accurate measurement facility requires compliance with the Law of Similarity, which is what the flow conditioner insures. Placing an isolated flow conditioner prior to the flowmeter will condition the disturbed fluid entering the conditioner so that it proceeds to the flowmeter with a virtually ideal bullet- shaped profile for extremely accurate measurement. Managers who examine these factors will discover their estimate of full cost of ownership is not only more accurate but will positively

1.1 Introduction

The McCrometer V-Cone Flowmeter is a patented technology that accurately measures flow over a wide range of Reynolds numbers, under all kinds of conditions and for a variety of fluids. It operates on the same physical principle as other differential pressure-type flowmeters, using the theorem of conservation of energy in fluid flow through a pipe. The V-Cone's remarkable performance characteristics, however, are the result of its unique design. It features a centrally-located cone inside the tube. The cone interacts with the fluid flow, reshaping the fluid's velocity profile and creating a region of lower pressure immediately downstream of itself. The pressure difference, exhibited between the static line pressure and the low pressure created downstream of the cone, can be measured via two pressure sensing taps. One tap is placed slightly upstream of the cone, the other is located in the downstream face of the cone itself. The pressure difference can then be incorporated into a derivation of the Bernoulli equation to determine the fluid flow rate. The cone's central position in the line optimizes the velocity profile of the flow at the point of measurement, assuring highly accurate, reliable flow measurement regardless of the condition of the flow upstream of the meter.

1.2 Principles of Operation
The V-Cone is a differential pressure type flowmeter. Basic theories behind differential pressure type flowmeters have existed for over a century. The principal theory among these is Bernoulli's theorem for the conservation of energy in a closed pipe. This says that for a constant flow, the pressure in a pipe is inversely proportional to the square of the velocity in the pipe. Simply, the pressure decreases as the velocity increases. For instance, as the fluid approaches the V-Cone meter, it will have a pressure of P1. As the fluid velocity increases at the constricted area of the V-Cone, the pressure drops to P2, as shown in Figure 1. Both P1 and P2 are measured at the V-Cone's taps using a variety of differential pressure transducers.

The Dp created by a V-Cone will increase and decrease exponentially with the flow velocity. As the constriction takes up more of the pipe cross-sectional area, more differential pressure will be created at the same flowrates. The beta ratio equals the flow area at the largest cross section of the cone (converted to an equivalent diameter) divided by the meter's inside diameter.

1.3 Reshaping the Velocity Profile
The V-Cone is similar to other differential pressure (Dp) meters in the equations of flow that it uses. V-Cone geometry, however, is quite different from traditional Dp meters. The V-Cone constricts the flow by positioning a cone in the center of the pipe.

This forces the flow in the center of the pipe to flow around the cone. This geometry presents many advantages over the traditional concentric Dp meter. The actual shape of the cone has been continuously evaluated and tested for over ten years to provide the best performance under differing circumstances.
One must understand the idea of a flow profile in a pipe to understand the performance of the V-Cone. If the flow in a long pipe is not subject to any obstructions or disturbances, it is well-developed flow. If a line passes across the diameter of this well-developed flow, the velocity at each point on that line would be different. The velocity would be zero at the wall of the pipe, maximum at the center of the pipe, and zero again at the opposite wall. This is due to friction at the pipe walls that slows the fluid as it passes. Since the cone is suspended in the center of the pipe, it interacts directly with the "high velocity core" of the flow. The cone forces the high velocity core to mix with the lower velocity flows closer to the pipe walls. Other Dp meters have centrally located openings and do not interact with this high velocity core. This is an important advantage to the V-Cone at lower flowrates. As the flowrate decreases,


the V-Cone continues to interact with the highest velocity in the pipe. Other Dp meters may lose their useful Dp signal at flows where the V-Cone can still produce one.

The pipe flow profile in actual installations is rarely ideal. There are many installations where a flowmeter exists in flow that is not well developed. Practically any changes to the piping, such as elbows, valves, reductions, expansions, pumps, and tees can disturb well-developed flow. Trying to measure disturbed flow can create a substantial problem for other flowmeter technologies. The V-Cone overcomes this by reshaping the velocity profile upstream of the cone. This is a benefit derived from the cone's contoured shape and position in the line. As the flow approaches the cone, the flow profile "flattens" toward the shape of a well-developed profile.

The V-Cone can flatten the flow profile under even extreme conditions, such as single elbows or double elbows out-of-plane positioned closely upstream of the meter. This means that as different flow profiles approach the cone, there will always be a predictable flow profile at the cone. This ensures accurate measurements even in non-ideal conditions.

2.1 High Accuracy
The V-Cone primary element can be accurate to ±0.5% of reading. The level of accuracy is dependent to a degree on application parameters and secondary instrumentation.

2.2 Repeatability
The V-Cone primary element exhibits excellent repeatability of ±0.1% or better.

2.3 Turndown
The turndown of the V-Cone can reach far beyond traditional Dp meters. A typical turndown for a V-Cone is 10 to 1. Greater turndowns are attainable. Flows with Reynolds numbers as low as 8000 will produce a linear signal. Lower Reynolds number ranges are measurable and are repeatable by applying a curve fit to the measured Dp.

2.4 Installation Requirements
Since the V-Cone can flatten the velocity profile, it can function much closer to upstream disturbances than other Dp meters. The recommended installation for the V-Cone is zero to three diameters of straight run upstream and zero to one diameters downstream. This can be a major benefit to users with larger, more expensive line sizes or users with small run lengths available. McCrometer conducted performance tests of the V-Cone downstream of a single 90° elbow and two close coupled 90° elbows out of plane. These tests show that the V-Cone can be installed adjacent to either single elbows or two elbows out of plane without sacrificing accuracy.

2.5 Long Term Performance
The contoured shape of the cone constricts the flow without impacting it against an abrupt surface. A boundary layer forms along the cone and directs the fluid away from the beta edge. This means the beta edge will not be as subject to the usual wear by unclean fluids. The beta ratio will then remain unchanged and the calibration of the meter will be accurate for a much longer time.

2.6 Signal Stability
Every Dp meter has a "signal bounce". This means that even in steady flow, the signal generated by the primary element will fluctuate a certain amount. On a typical orifice plate, the vortices that form just after the plate are long. These long vortices create a high amplitude, low frequency signal from the orifice plate. This could disturb the Dp readings from the meter. The V-Cone forms very short vortices as the flow passes the cone. These short vortices create a low amplitude, high frequency signal. This translates into a signal with high stability from the V-Cone. Representative signals from a V-Cone and from a typical orifice plate are shown in figure 6.



2.7 Low Permanent Pressure Loss
Without the impact of an abrupt surface, the permanent pressure loss is lower than a typical orifice plate meter. Also, the signal stability of the V-Cone allows the recommended full scale Dp signal to be lower for the V-Cone than other Dp meters. This will lower the permanent pressure loss.

2.8 Sizing
The unique geometry of the V-Cone allows for a wide range of beta ratios. Standard beta ratios range from 0.45, 0.55, 0.65, 0.75, and 0.85.

2.9 No Areas of Stagnation
The "swept through" design of the cone does not allow for areas of stagnation where debris, condensation or particles from the fluid could accumulate.

2.10 Mixing
The short vortices described above mix the fluid thoroughly just downstream of the cone. The V-Cone is currently in many applications as a static mixer where instant and complete mixing are necessary.

2.11 Three Models
McCrometer offers three types of V-Cone primary elements, the precision tube V-Cone, the Wafer-Cone? and the insertion top-plate V-Cone. Precision tube V-Cones range in line sizes from ?" to 72" and larger; Wafer-Cones range from 1/2" to 6"; and insertion top-plate V-Cones range in line size from 6" to 72" and larger.

3.1 Application Data
The customer must provide application parameters so that the appropriate V-Cone flowmeter may be selected. McCrometer has an extensive meter performance database of fluid properties which can be utilized for sizing purposes.

3.2 General Calculations


3.3 Calculations for Liquids


3.4 Calculations for Compressible Fluids (gases and vapors)


3.6 Application Sizing
Each V-Cone is tailored to its specific application. Before manufacturing, every V-Cone will have a "sizing" completed according to the physical parameters of the application. The computer generated sizing uses application data as a basis to predict the V-Cone's performance. Full scale DP (typically 50 inches of water at full scale), working flow range, expected accuracy, and predicted pressure loss are determined by the sizing. The sizing recommends the beta ratio that best meets the application requirements.

3.7 Calibrations
Precision tube and wafer flowmeters less than 18" diameter are calibrated in one or more of the following McCrometer calibration facilities:

McCrometer recommends that every V-Cone meter be calibrated. A calibration is required when the application requires the best accuracy. Insertion top-plate style flowmeters can be calibrated as an option. If an actual calibration is not requested, the coefficient for the meter can be estimated. Data collected over years of independent testing allows for an accurate estimate of the meter's Cf . For V-Cones intended for use in a compressible fluid with high accuracy requirements, McCrometer recommends calibration in a compressible fluid.


3.8 Materials of Construction
All materials used on V-Cone flowmeters are certified. Materials furnished to McCrometer include a certified material test report (CMTR) from the original material manufacturer. The test reports include material composition and applicable material grades. Upon request copies of the material test reports can be supplied to our customers.

3.9 Valve Manifolds
McCrometer recommends a three valve or five valve manifold as part of a V-Cone flow measurement system. Manifolds allow for in-line transmitter calibrations, isolation of the transmitter from the transmission lines without depressurizing the line and in-line purging of transmission lines.

3.10 Secondary and Tertiary Instrumentation
A differential pressure transmitter generally measures the differential pressure signal from the primary element. Once the signal is measured, the transmitter generates an electronic signal that is then interpreted by a flow monitor or other process control system. For compressible fluids, line pressure and temperature measurements are sometimes required. McCrometer offers the following flow measurement instrumentation: differential pressure transmitters, flow computers, and pressure and temperature sensors for mass flow measurement. All can be calibrated and programmed at the factory.