Recent Experience on Implementation of New Techniques of Gas Metering

Andrew W. Jamieson, Shell U.K. Exploration and Production

1. Summary

Gas metering in the oil and gas industry is changing rapidly with the steady introduction of new metering techniques, which will supplant or co-exist alongside traditional methods. Gas metering fits readily into a concept in which any oil and gas industry metering application is a special application of multiphase metering. Recent experience in applying new metering techniques is discussed for ultrasonic meters onshore and offshore, Coriolis meters offshore and Venturi meters for wet gas service. The constraints affecting the various parties involved in implementing new metering techniques are discussed and conclusions drawn for the kind of guidelines that the industry requires.

2. Introduction

As with all areas of metering, gas metering in the oil and gas industry is going through a revolution. Techniques developed over the last two decades are now being applied widely, supplanting traditional orifice metering. Old techniques, such as Venturi meters, are making a comeback. Application of powerful data processing techniques means that complex metering systems can be operated and interrogated remotely. However, with these significant advances comes the difficulty for metering specialists of being able to acquire a sufficiently wide and deep knowledge of the large variety of systems to be able to manage the metering systems of the future. It is self evident that without a sound technical foundation, the most elaborate metering management system is useless.

In this paper, I first set gas metering in an overall metering context using the ‘Multiphase triangle’. I then consider several recent gas metering applications using ultrasonic, Coriolis and Venturi meters. I discuss the role of standards and the positive and negative effects of the current drive to reduce operating costs, especially in the North Sea. This leads naturally to indications of how gas metering may develop over the next few years.

3. Gas metering and the multiphase triangle

Over the last two years I have strongly promoted the use of the ‘Multiphase triangle’ in discussing all measurement problems in the upstream oil and gas industry. The triangle (Fig 1) gives the composition of an unprocessed crude oil stream in terms of fractions of oil, gas and water. The vertices of the triangle represent 100% oil, gas and water; the sides represent two-phase oil-gas, water-gas and oil-water. (Strictly speaking, the oil and water ‘components’ together form the liquid ‘phase’, but in multiphase metering it is usual to blur the distinction between ‘component’ and ‘phase’ and consider oil and water as separate phases.) In the middle of the triangle we have the enormous variation of three-phase flows.

Already one can see that each application is unique. Are we processing the fluid onshore, in the jungle, in the desert, or in the Arctic? Are we processing the fluid offshore, on a platform or subsea? Are we considering processing downhole? Each of these locations brings its own design problems and implementation difficulties. Then we have to consider the fluid properties, namely flowrate, temperature, pressure, viscosity; then the economics of processing and how much “impurity” we can afford to leave in the processed streams. These latter considerations are especially important in sales gas metering.

Figure 1 Multiphase Triangle

The traditional view was that metering was essentially a matter of measuring single phase fluids, and that one had to adapt the methods to cope with the contaminants, such as liquids in gas streams. I consider a better view is to treat all oil and gas metering applications as multiphase metering, and that one chooses from the variety of components and techniques available to build a system to measure the composition and flowrate of that multiphase flow.

One might ask, “Is this really necessary for gas metering, and especially sales gas metering, where we are obviously dealing with a single phase fluid?”

If we look at typical sales gas metering system, we usually analyse the gas for about ten components, eight of which are hydrocarbon, plus nitrogen and carbon dioxide. The composition and flowrate are probably fed into an allocation system, which, if it is to work properly, will be based on component mass flowrates. Given that in multiphase metering we blur the distinction between ‘component’ and ‘phase’ it is evident that a sales gas metering system is nothing other than a multiphase metering system giving the mass flow of each component. Current multiphase metering systems give the volume flowrate for each phase; I believe that multiphase allocation systems will need to work in mass terms, and as such, the sales gas allocation systems provide the ideal model of what is required.

The gas metering applications I will discuss occupy the very tip of the multiphase triangle. In volume terms, the liquid content will be less than about 1-2%. In mass terms, however, the liquid may then make up some 25% of the mass, and as the price of oil and gas is roughly the same in mass terms, the liquid content will then be very valuable.

4. Recent applications

I will discuss my involvement over the last few years with new technology gas metering systems: gas ultrasonic meters offshore on separators and onshore for sales gas, Coriolis meters used for metering unusual fluids, and Venturi meters used on wet gas service. A recurrent theme will be the effort needed to get such systems working, the effort required to keep them working and deal with the novel issues that seem to turn up with each new application, and then how the hard gained information is fed back within one’s own company, to partners and other operators, to designers, system builders, and manufacturers.

4.1 Ultrasonic meters on separators

I have been involved with a number of projects where ultrasonic meters have been installed to meter gas off separators. On many of these applications the ultrasonic meters have not worked, and often have not even had a chance of working. It is too simplistic to blame the meters; I have also seen many conventional orifice meters on separators that could never work, but still produce “metering” information that is used by optimists in hydrocarbon management systems.

Let us consider what happens to a multipath ultrasonic meter from when it leaves the factory, with glistening paint outside and shiny smooth inside, until it goes into service perhaps eighteen months later. First, there is the trip to the calibration station. The transducers may be installed on the meter, or they may be kept separate from the body. The transducers comprise relatively light sensor parts mounted on heavy flanges, especially those intended for high pressure service. They tend to be fragile, and the first unhappy event in the meter’s life may be a delay in calibration because a transducer has broken in transit. The calibration itself offers opportunities for interesting things to happen. The manufacturer may have coated the internal surface with a waxy preservative; unless this is removed a significant calibration error will result. Upstream and downstream pipework may not match the meter bore; again a significant calibration error may occur.

Once calibrated, the meter has to be cared for. If another transducer gets damaged, and there may be up to twelve of these for a meter, one has to consider what to do to maintain the calibration. In principle, all one should have to do is replace the transducer with another as it should be possible to manufacture transducers to be nearly identical. In practice this is not yet so. Transducers tend to come as matched pairs, so is it possible just to replace a pair with another pair, without having to recalibrate the meter? Some manufacturers claim this can be done very repeatably, but as there are many variants of transducers it is difficult for the user to be sure that this is indeed the case for the meter and transducers for his application. Should one then hold a complete set of transducers, calibrated for the meter? But then one is faced with the problem of how to look after these as well as the meter.

Let us suppose the meter has arrived on site for installation. It may be that the construction engineers have decided to keep it in safe, dry storage until the metering station has been fabricated, cleaned and about to be put into service. In this case, the meter will have a dull life for several months, but don’t feel too sorry for it, it may yet have fun during its commissioning, as we shall see shortly. But instead the meter may be destined to see everything that goes on at the fabrication yard. It will be left out in all weathers, be used as a pup-piece in the construction, will have the fabrication debris flushed through it and will be pressure tested with the associated pipework. Its local electronics box will be opened several times, and get filled with rain on snow.

Remember that the meter was for service on a separator on an offshore platform. We have now got offshore, and are about to put the meter into service. The separator is brought to pressure; the precommissioned meter is switched on and shortly after stops working. Everything about the meter is suspect; either the transducers or the electronics may have failed, or both. Working on the electronics is difficult; the platform is of the open module construction and it is a rare day that one can open electronic boxes without rain or salt spray getting inside. Because ultrasonic meters are considered to be low maintenance items, isolation valves were not installed to permit them to be removed relatively easily. We have to wait until there is a scheduled production shutdown before the meter can be removed.

Not unreasonably, the operating company wants to be sure that whatever meter goes back in, it will work. No-one can give such an assurance for the ultrasonic meter, but in reality they cannot give that assurance for any other meter, as the complex mixture of problems revealed when the ultrasonic meter is removed defies easy explanation. It is impossible to say whether the failure resulted from flaws in design or manufacture, or from mishandling during the time in the fabrication yards, or from failure in the short period in actual service.

My view is that metering on separator offtakes is far more difficult than is generally believed. This type of metering is becoming steadily more important in allocation schemes and consequently it is important to have good gas meters. I believe that ultrasonic metering is the best technique for this application, but current meters, essentially the same as those for the stable conditions of onshore sales gas metering, need to be better adapted to the offshore environment.

4.2 Ultrasonic meters onshore

Let us now consider a meter that was looked after carefully before it was put into operation. Whereas the meter described in the separator application did not really get a chance to give useful information, this meter from the same manufacturer has strongly vindicated the view that ultrasonic meters give a new way of looking at gas flows, and give much useful diagnostic information.

The meter was intended for an important sales gas metering station, which comprised two streams fed from an inlet header. The system vendors had been asked to design the inlet pipework configuration to minimise the transmission of ultrasonic noise from upstream and to ensure that the swirl at the meters would not degrade the accuracy of the meters significantly. During commissioning, the meter vendors noticed that the flow profile at the meter in the right hand stream was dramatically different from that at the meter in the left hand stream. (Right and left are defined with respect to the direction of flow of the gas.) The right hand 4-path meter was showing velocities on the two inner chords some 10-15% lower than the two outer chords over the whole flow range tested, whereas the left hand one showed the normal pattern with the velocities on the two inner chords higher than on the outer chords. Note that 4-path meters measure the average velocity over the whole length of the chords, thus a wide range of flow profiles can give the same chord velocities.

Initially swirl was discounted, as the manufacturer usually associated swirl with unstable velocity readings. The meter readings were very stable on all chords, and the velocity pattern indicated very symmetrical flow conditions in the pipe. The two outer chords showed virtually identical velocities, as did the two inner chords. We were forced to consider that there might be something in the line, something that would have to be large and fairly close to the meter to give the observed velocity pattern, but had difficulty in believing this given the care that had been taken during construction to keep the pipework clear of debris. The upstream pipework was opened up and the pipework was clear of obstructions to beyond the inlet header.

An intense discussion with NEL gave the almost certain cause of the problem. The major difficulty was in explaining the difference between the right and left hand streams. Our metering station was mirror-symmetrical for two valves and four bends upstream of the metering. The fifth bend was to the underground feed line to the station. It appeared evident that the combinations of out-of-plane bends were generating swirl that was increased in the right hand stream and partially cancelled in the left hand stream. There was a relatively long length (22D) of upstream straight pipework which would allow any contra-rotating vortices to dissipate and leave a strong steady swirl in the right hand stream. As the only mechanism for removing this swirl is friction with the pipewall, it can persist for very long distances.

The vendors had quoted work done by Grimley at SwRI in the USA [1] as justification for saying that the swirl levels induced by the header configuration would not lead to significant degradation in accuracy of the meters. Unfortunately, Grimley’s work only considered the effect of two bends upstream of the meter, as does ISO 5167, the main guide in gas metering to requirements for upstream pipework. It is evident that the ultrasonic meter has shown that for our installation at least it is not sufficient to consider only the first two upstream bends or fittings when designing swirl free piping configurations.

We had already considered the possible need to install a thick plate flow conditioner if swirl levels were found to be higher than those described by Grimley, and are now making the necessary modifications for its installation. Work carried out by NEL in a JIP on header configurations upstream of an orifice several years ago gives us the supporting evidence that thick plate conditioners will remove the levels of swirl we believe to be present in the right hand stream and make a flow profile acceptable for the 4-path meter.

4.3 Coriolis metering of “funny” gas

I was asked to advise on a proposal by a Shell operating company to meter “gas” and “condensate” on an offshore facility for export into a gas pipeline. The reason for using inverted commas is that the “gas” has a density of about 300 kg/m³ and the “condensate” has a density of about 500 kg/m3 at metering conditions. The wellstream is fed into a 3-phase separator to remove water from the crude stream. The condensate and gas streams are then compressed to give the two supercritical (neither gas nor liquid) fluids described above. These are metered separately into the gas export line where they remain in the gas phase provided the other input streams to the export line have a sufficiently low average molecular weight.

The problem was to decide how best to meter these supercritical fluids. The metering specialist on the project had sought advice widely and had decided that the best way was to use Coriolis meters. The quantities were relatively low, falling within the range of 1½” or 3” meters. A master meter would be used to check both the “gas” and “condensate” meters periodically.

At first I was sceptical. I had no difficulty in accepting Coriolis meters for metering real liquids, and was in the process of being convinced that they were also suitable for metering real gas. I had shortly before agreed to using one for metering fuel gas at one of our installations, but was not so happy for their use in a more critical gas application. My concerns went back some years when we at the Shell E&P Research laboratory tried to develop a multiphase meter based on the Coriolis metering principle. We thought that a Coriolis meter could already handle two-phase oil and water mixtures, and that the way ahead would be to make a Coriolis meter that could tolerate increasing quantities of gas. However, as is now well known, Coriolis meters cannot tolerate more than a few percent of gas unless it is completely entrained in the liquid. Essentially the coupling of the vibrating tube to the fluid ceases and the meter stops working. For single phase gas, the Coriolis principle should work, especially at high pressures. Evidently it had taken some years for manufacturers to develop reliable products for real gas, but how would these perform on these supercritical fluids? I suspected that the coupling between the fluid and the vibrating tube would be degraded, and the calibrations performed with real gas and real liquid might not be meaningful.

I thought that the most comparable fluid would be supercritical ethylene, and learned that there was only one very special rig in the world for calibrating the turbine meters used for that application. I also learned that a JIP was testing Coriolis meters for that service and were showing good results.

By this time I had realised that there was not a more practical approach for offshore application. My remaining reservations now centred on the more practical aspects of ensuring the mounting of the meters followed the manufacturer’s best practices, and whether it would be practical to carry out an in-situ calibration of the master meter using a compact prover and a turbine meter as a transfer standard. From data inspected at a factory acceptance test, it was evident that the “proving” of a Coriolis meter by this method is still in development. To get a mass flowrate, the volume flowrate of the turbine meter must be multiplied by the density of the calibration fluid, and master meter rigs do not usually have on-line density measurement. Another complication is that the turbine meter may be calibrated accurately with the compact prover, but that free gas may appear when the turbine meter is used to calibrate the Coriolis meter. In that case the turbine meter will over-read, leading to an under-calibration of the Coriolis meter.

By the end of summer, we should know whether this novel approach to metering “funny” gas works as well as it deserves to.

4.4 Venturi wet gas metering

I give a short discussion on Venturi wet gas metering to emphasise the point that in general we do not get enough feedback from operational facilities to feed forward into new developments. Shell Expro now has two facilities using wet gas metering essentially for sales gas metering. The drive to use wet gas metering was to eliminate the bulk processing facilities that would have been necessary if conventional metering techniques were used. At the time when the development decisions were being made, the cost of these production facilities would have made the projects uneconomic.

On both facilities, the liquid content is less than 1%. The over-reading of the Venturi meters because of the entrained liquid is corrected using a variant of Murdock's equation. The liquid content is determined (in principle) from periodic well tests. On one facility the ultrasonic meter in the test separator gas outlet has several failed transducers which cannot be replaced as they are deemed obsolete by the manufacturer.

At the design stage, we had hoped that the data from the well testing would build up a picture of how the wells were changing with time, and that this could be used to guide the development of other fields where it would not be practical to have a test separator. Currently we have a project where the fluids are slightly wetter than those described above, and wet gas metering is an attractive option. Even more critical is the need to determine the onset of water breakthrough, and although there are several ways in principle of doing that, none have been fully demonstrated to date. For the project to move forward, the risk of choosing a low cost option using techniques that are promising but not fully demonstrated must be judged against a high cost traditional option using techniques that are known to give problems.

5. Constraints

Good implementation of new technology gas metering systems requires favourable circumstances. Firstly, the technology must be sufficiently mature that it can be considered for application. This means that the measurement principles are theoretically sound, and that they have been incorporated in a practical manner into working, commercially available equipment. This in turn means that there is a manufacturer keen to support the new metering approach, and who can foresee an adequate commercial return for his efforts in developing and marketing the new equipment.

Second, the ideas underlying the new technology have to have circulated long enough in the metering community that there is a general expectation that the new technique can work in a oil and gas environment. Often the ideas will have been generated in oil and gas company laboratories or in Universities, and before practical equipment can be developed there has to be close interaction between inventor and manufacturer.

Third, suitable pilot applications are required, and these must be at locations where the potential user of the new metering technique sees clear commercial advantages from its use. This means it can give significantly enhanced performance for the same cost, or, more usually, the same performance, or even a lower performance, at a significantly lower cost. This means, inevitably, that the new technology system will be installed on a “difficult” application, and those responsible for the installation cannot expect things to be easy.

Fourth, a reasonably tolerant user is essential. Neither the inventor nor the manufacturer will have been able to anticipate all of the circumstances of the installation; often the new technology metering will be the first means of making an assessment. Traditional views may have to make way for ones based on more accurate and reliable measurements, and that process does not happen easily.

Fifth, even after successful pilot applications, there comes the slow, difficult process of establishing the new metering technique as a general method to be applied by projects through design houses, main contractors and metering system suppliers. Current practice is to use a single contractor on a lump sum basis. Sub-contractors make their bids on fixed prices. This approach does not, in my experience, lead directly to successful implementation of new technology systems. In practice, each application will be somewhat different to the pilot schemes; precautions considered essential by those carrying out pilot schemes may appear unnecessary to project teams; nagging doubts over the actual flow conditions may suddenly crystallise into unwelcome hard facts that cannot be ignored. At the end of the day the new technology metering system may have been installed for a much lower cost than a traditional system, but the metering specialist is unlikely to receive much praise from a project manager who had reckoned on getting all of the savings, and finds he is over-budget because of the work required to get the system working properly.

Sixth, operators and users of the new systems need to learn how they work, and indeed discover what extra information the new systems can give them that will enhance their operations. In these days where staff numbers are being reduced dramatically, it is unlikely that the learning process will be easy. One must rather expect that in the immediate period after a new technology system is put into operation that more resources will be required, rather than less, to ensure that any problems are dealt with promptly and the associated lessons learnt and circulated to other users.

Seventh, a balance has to be struck between the view that development work cannot be carried out on operational facilities and opposing view that unless new systems can be developed in real conditions, there is no chance of realising the benefits that can come from their use. How such a balance is struck depends on the value the industry puts on the availability of the new techniques.

6. Conclusions

Implementation of new techniques for gas metering has clearly led to improvements in gas metering performance, lower installed costs, and better understanding of what actually happens in gas flows. This better understanding raises questions on installation requirements in current metering standards, and suggests that it would be unwise for the industry to draw up rigid standards that could be shown to be invalid in a relatively short time. I consider it would be preferable to have guidelines for a general approach to metering, with each specific application considered on its own merits and the proposed solution submitted for some sort of peer review to judge its suitability. I would suggest that this is more or less what happens in practice.

Gas metering clearly fits into a general treatment of any oil and gas metering application as being a special case of multiphase flow metering. Indeed, as the industry blurs the distinction between “phases” and “components”, sales gas metering systems which measure the flowrates of perhaps ten components form an ideal model for future multiphase allocation metering systems.

The major difficulty with new technology gas metering is still in the quality of the implementation. Too much is expected from the new systems too soon in terms of reduced operating and maintenance costs. All sections of the industry, developers, manufacturers, project teams, design houses, contractors, government agencies, gas shippers, facility operators and gas transportation controllers all require an appreciation of the other parties’ problems. For the increasingly sophisticated gas measurement systems required in the 21st century, a sound technical basis, reliable equipment, sound project management, workable contracts, practical operating procedures, sensible regulation are all essential.

Reference

1. GRIMLEY, T.A. The influence of velocity profile on ultrasonic meter performance,
A.G.A. 1998 Operations Conference, Seattle, Washington.

INSTRUMENT SOCIETY OF AMERICA OIL AND GAS CONFERENCE MARACAIBO, VENEZUELA
22-25 SEPTEMBER 1998

Implementation of new technology metering

by A.W. Jamieson, Shell U.K. Exploration and Production

Summary

Flow measurement in the Oil and Gas industry is undergoing a revolution, and this is particularly evident in the North Sea. Novel techniques such as wet gas metering, ultrasonic metering are being applied for gas, while clamp-on ultrasonic metering and radar tank gauging are being tried out for oil. Multiphase metering is making slow but steady progress, and meters are now being installed that really give added value to field developments. Within operating companies, technical expertise in these techniques is limited, and is even more limited within manufacturers and engineering design houses. The major challenge is the building up of expertise across the industry to allow these techniques to be implemented successfully and to realise the large savings in capital and operational costs that are made possible through the application of new metering techniques.

Introduction

Over the last decade the efforts to drive down the costs of producing oil and gas has resulted in the development of new metering techniques that are now beginning to be applied. A decade ago high accuracy oil metering was done using PD meters or turbine meters with meter provers. High accuracy gas metering was done with orifice meters or turbine meters. The only multiphase meters we had were test separators or first stage production separators. Subsea metering was none existent. The situation for current producing fields is not that much different. Although the new techniques are more or less available, operating companies are justifiably wary of applying them. Experience with the new techniques remains almost completely with the developers of the individual techniques and their immediate sponsors in the oil companies. Operational experience is scarce. Obviously we have a chicken and egg situation: one cannot gain experience with a new technique until one has committed to use it, and project teams do not want to commit to a new technique without the availability of operational experience.

Almost all of Shell Expro's projects are keen to apply new metering technology as it is evident that large capital and operational savings can be made. My advice is straightforward: if there is no clear benefit from applying a new metering technique, don't. There are too many examples of new technology being applied as a 'nice to have'. Unfortunately, when it is switched on, doesn't work, and operational staff aren't really interested in it working, it isn't at all a 'nice to have'. Any confidence that there was in the new technique is lost, and it takes a very long time to restore that confidence. However, when a metering technique is developed to the stage where it is practical to implement it and there is a clear benefit of applying it in a project, I promote it vigorously.

The decision to apply a new metering technology should not be taken lightly, as if it cannot be made to work satisfactorily there may be no other option but to replace it with something else. There needs to be a large contingency budget for the things that will almost inevitably go wrong. This may appear to give a negative view of applying new technology. However, where we have applied new techniques and have kept a tight watch on the design, installation and commissioning, we have had fewer problems than with conventional systems, where everything is supposed to be fully understood.

In the rest of the paper I will first take a look into the future to 2010 to see what techniques are most likely to be in use. Then I'll discuss these techniques in more detail. Finally, I'll look at what needs to be put in place to allow the projection to 2010 to come true.

A look into the future

In 2010 there will be a much wider range of metering equipment in use than there is today. This simply reflects the fact that there will be a wider range of types of facilities for producing oil and gas. Thus we will have the old conventional facilities, simplified unmanned facilities, floating production systems, subsea production systems all coexisting together and feeding into multi-user pipelines. With advances in well technology we may even have subsurface metering on multilateral wells draining different accumulations. Added to this there will be much more automation than there is today.

There will be a number of the conventional turbine meter plus meter prover stations for oil export metering. Similarly for gas export there will be a number of conventional orifice metering stations. These systems have defined the accuracies the oil and gas metering industry accepts as reasonable. There is no drive to demand higher accuracy, but there is a strong drive to maintain these accuracies for critical systems but at a lower cost. However, every metering system will be looked at in its own context for cost effectiveness, with accuracy and cost being traded against overall financial exposure. The range of options can extend from no metering at all to full fiscal quality metering. If today’s conventional systems continue to provide cost effective solutions for the applications in which they are installed, they should continue to be used.

For most applications new techniques will be preferred. It is clear that in 2010 ultrasonic metering will be preferred for high accuracy gas metering. Ultrasonic meters, either clamp-on or multi-path appear to be the likely choice for crude oil transfer from floating production systems, but in both cases turbine meters are strong competitors. With facilities near the end of their useful lives there will be special requirements. Deferring abandonment as long as possible is worth a great deal to the industry, and having means to meter produced fluids to be sure of optimum performance is essential. By 2010 multiphase metering in its widest meaning will be widely used and it should be clear which of the techniques currently under development are most cost effective. Metering unprocessed streams will be common, with a strong preference for meters to be installed in individual flowlines. The best systems will be capable of near fiscal accuracy, and it will be practical to consider installing such high accuracy systems subsea.

The savings produced by using new metering techniques, especially multiphase metering, are large. Eliminating bulk separation facilities saves $15 - 20 Million per facility; a subsea test line costs typically $25 - 40 Million. In a company such as Shell Expro such savings over a five year period can easily be $150 Million.

From this brief look at the world in which the metering technology we are developing today will be used, we now look in more detail at the specific areas of technology.

Oil

The use of floating production systems has led to the need for cheaper oil export metering. Clamp on ultrasonic meters allow metering on the large diameter discharge lines from the floating production system to the shuttle tankers. This means that higher flow rates are possible, reducing loading times and the likelihood of having to disconnect in bad weather. Using duplicate meters overall accuracies are claimed to be of the order of 0.5 to 1%, but there still remains the problem of how to verify the performance of these meters on crude oil at very high throughputs. Large diameter multipath ultrasonic meters are also suitable for this application, and offer higher accuracy and better stability. For lines of about 20 inches diameter and larger there are very few facilities that can provide a calibration using crude oil, and a water calibration is not ideal.

Large diameter, high quality turbine meters could also be used for this application. They are very competitive in price with ultrasonic meters, and if used in pairs for checking each other will give the same indication of discrepancies as ultrasonic meters. Indeed, some meter types have been used for several decades and their performance is well established. Manufacturers of large turbines meters do not appear to want to compete in what is likely to be a fairly large market, and hence ultrasonic meters are getting an opportunity to dominate this market.

Radar tank gauging on the oil tanks of storage tankers is also being applied, but the movement of the vessel when on station degrades the overall accuracy significantly from that which can be achieved in calm conditions in harbour. It is likely to be too difficult to improve the corrections for movement sufficiently for this approach to become fully acceptable.

For oil metering in smaller line sizes Coriolis meters are becoming common. In Shell Expro we still have concerns over the use of thin walled vibrating pipes in main oil flowlines, especially for those above 4" diameter. However, better quality control in manufacture and a wider choice of materials means that we are using more of these meters. From a metering point of view we are pleased with the performance, but there are still significant issues to be resolved in mounting Coriolis meters to overcome errors due to vibration. This still seems to be somewhat of a black art.

Gas

High accuracy (dry) gas metering in gas producing companies will probably be done in the future using ultrasonic meters, for export and for allocation. Shell Expro has installed three Instromet 5-path Q-Sonic meters at St Fergus for fiscal metering of the gas supplied to the power station at Peterhead operated by Scottish Hydro Electric. This was the first application in the UK where ultrasonic meters were used as the primary fiscal measurement, and probably in the world. Where fields need to increase the capacity of the metering stations, ultrasonic meters are first choice. Our new developments are using ultrasonic meters in their base cases. It is unlikely that Expro will install any more conventional orifice metering stations for fiscal duty. Indeed, on one current project where orifice metering will be installed, a thick plate flow conditioner will be used to reduce the overall length of the metering system.

The advantages of an ultrasonic metering station over an orifice metering station are lower overall cost of about 30 % and size of 50%. Maintenance is significantly reduced and the inbuilt diagnostics tell when things are beginning to go wrong. Currently ultrasonic meters need to be calibrated at a high quality test facility. We have seen a sensitivity of the meter calibration to the surface finish of the meter interior of the order of 0.5% from clean to dusty. The reasons for such shifts are not at all clear, but we suspect that they do not only occur with ultrasonic meters, but affect all gas meters. The shifts observed are usually considerably smaller than the +/- 0.6% which is the basic uncertainty for an orifice plate discharge coefficient.

For gas transportation companies the situation is somewhat different. In continental Europe gas transporting companies have long experience of using gas turbine meters at large export stations and as sales meters to large users. They will continue to use these, and are increasingly using two meters of two different types in series to give warning of discrepancies. Thus ultrasonic meters are being used as back up meters for turbine meters.

Ultrasonic meters are also very suitable for production metering from separators. We have also installed a Daniels 4-path ultrasonic meter on Schooner on the test separator gas outlet. The near fiscal metering on Schooner is by wet gas venturis; the ultrasonic meter is used, among other things, to provide a check on the venturi meters calibration. Metering of wet gas will be dealt with under multiphase metering.

Multiphase

Multiphase metering is slowly coming of age. Development of multiphase meters began seriously in the early 1980s, thus we have somewhat in excess of 15 years effort, and a investment across the industry of at least $80 Million. Much of this investment has gone into setting up an infrastructure in which multiphase metering has become recognised as a viable technique. Multiphase meters are now commercially available and can be installed topsides to give clear added value to field developments. For subsea costs are much higher and installation more difficult. Nevertheless it is now evident that for Shell Expro, the largest benefits from multiphase metering will come when subsea meters can be used to allocate third party production.

In 1995 a forum consisting of Shell, BP, Statoil, Hydro and Saga presented a paper at the North Sea Flow Metering Workshop entitled "Oil companies needs in multiphase flow metering". This paper is still quite up to date, the main requirements on accuracy being 5 - 10% relative uncertainty for liquid and gas flow rates, and 2% absolute uncertainty for watercut.

Multiphase meters are not yet at the stage where they are meeting these target accuracies. Thus they should only be installed where there are means of checking their performance. As with any new technology it is important with the early installations not to lose the confidence of the operators. We must be able to stand very firmly by what the meter is telling us, this means being very critical in the assessment of any test data and not becoming too attached to a particular technique. The range of possible multiphase meter applications is enormous. It is unreasonable to expect that one type of meter will be able to satisfy all applications. As an operator we also want to have a choice of manufacturer to ensure that prices are not over-inflated.

Shell Expro are pursuing multiphase metering very actively. The following gives the status at present.

Operational meters:

Schooner - venturi wet gas metering (From October 1996)

Anasuria - Fluenta multiphase meter for well testing (from October 1996)

Auk, Gannet, Southern Field Unit - Tracers (from about mid 1995)

Gannet - 2 MFI multiphase meters for internal allocation (from July 1997)

Auk - ESMER for well testing (from December 1997)

Applications:

Every project is now considering multiphase metering at the conceptual design stage. We are looking very hard for a suitable subsea application.

Meter development:

We support Shell Group work in developing multiphase meters. We have also been supporting the development of the ESMER pattern recognition multiphase meter, originally at Imperial College, but now with PSL (Petroleum Software Ltd) and Daniel Europe. This promises to give a versatile and relatively cheap multiphase meter.

In Shell Expro we assess the suitability of a multiphase meter for a particular application, matching the meter performance envelope to the well or field production profile, as described in the above mentioned paper. We also translate the results of tests or manufacturers' data into a format that we want to use rather than the numerous formats used by manufacturers to try to enhance the apparent performance of their meters.

From evaluation of test data to date and our limited operational experience the following points can be made:

Accurate measurement of water cut at all gas volume fractions range is most important, and particularly at the higher water cuts. The multiphase meters that are commercially available are fairly reasonable two phase meters and are approaching the target accuracies for liquid and gas. They still do not provide good enough watercut measurement.

There is a need to be able to calibrate multiphase meters in situ. It may be possible to extend the present tracer techniques, but at present it is difficult to accept the validity of calibrations made in laboratory test loops at conditions very different from those in the field.

However, whenever we have compared multiphase meters with current conventional separator measurements, there have always been significant problems in doing so.

This leads on to the need for test facilities that can more closely simulate field conditions. Obviously such facilities will be expensive, but only a small fraction of the potential savings multiphase metering can achieve.

Needs to achieve the above

As I stated at the beginning of the paper, a revolution is taking place in metering. There is concern within Expro and by our co-venturers that where new metering technology is being applied and there is no recognised pertinent standard, there is a risk that meter selection and meter station facilities may be inappropriate for the required duty.

Almost all of our projects are applying novel, cost saving techniques in metering. To recap, examples are clamp on ultrasonic meters for export from floating production systems, wet gas metering using venturis, fiscal ultrasonic meters, thick plate flow conditioners for gas, Coriolis meters, possible wet gas ultrasonic, then all the multiphase applications. There are no standards existing for these techniques, although there are committees of interested parties producing early drafts. It is a widely held view across the industry that it is too soon to be drawing up definitive standards in these areas. Shell Expro, in common with other operating companies, is seeking to use industry wide standards where possible, and reduce the number of internal standards to a minimum.

Within Shell Expro we consider that the best approach is that followed by the United Kingdom DTI, and which is embodied in their latest guidelines for metering systems. Each application is considered in the light of its particular circumstances, and appropriate techniques agreed between the relevant operators, manufacturers and the DTI as conforming with good oil field practice. This puts the emphasis on getting a good functional specification agreed by all parties. The basis for that specification can be standards, special test results, expert opinion from appropriate resources, and so on. There need be no risk that meter selection and meter station facilities may be inappropriate if care is taken at this stage. Indeed, this approach is fully auditable and forces one to consider all the relevant issues. We think this is a much more practical approach than trying to draw up new standards that cannot yet accurately reflect real operating requirements.

Given the variation in requirements across applications and the wide range of techniques, it is essential that facilities designers, engineering contractors and meter vendors have an open dialogue with the users of the metering information, for example reservoir and petroleum engineers or the commercial departments responsible for the sales contracts. Further, a metering system specification must take into account the expected changes in flow rate over the expected service life. Consultants, contractors and their clients must realise, in turn, the substantial investment of time and effort needed by the vendor to tender a proper quotation for a system using new technology, especially if it is for a multiphase metering system. Co-operation will be necessary to allow vendors, intermediaries and end users to properly assess and qualify the metering system.

Conclusions

The new metering techniques that have been in development over the last decade are beginning to be applied. In the UK this has facilitated by the view shared by operators and the DTI that the metering techniques used on a particular application should be cost effective.

By the year 2010 a much wider range of metering techniques will be in use than at present. Multiphase metering especially will play a large role.

Government departments, operators, design contractors manufacturers and consultants will have to co-operate to ensure that expertise is built up to achieve the cost saving benefits possible with new metering technology.

Related Article: Recent Experience on Implementation of new Techniques of Gas Metering, also by Andy Jamieson.

Orifice Plates

Orifice Plate - An orifice plate is a device used for measuring flow rate, for reducing pressure or for restricting flow (in the latter two cases it is often called a restriction plate). Either a volumetric or mass flow rate may be determined, depending on the calculation associated with the orifice plate. It uses the same principle as a Venturi nozzle, namely Bernoulli's principle which states that there is a relationship between the pressure of the fluid and the velocity of the fluid. When the velocity increases, the pressure decreases and vice versa. This technical information from Wikipedia, the free encyclopedia gives a good overview.

Good Practice Guide an Introduction to Differential Pressure Flow Meters - This introductory guide to differential-pressure (Δp) flow meters has been produced for people who are relatively inexperienced in using this type of meter or who would just like to learn more about the subject. The guide provides useful information on the maintenance of existing meters and for purchasing a new metering system. The introduction covers the basic theory of how differential-pressure flow meters work and fundamental background information. Some of the most common types of meters are described together with their advantages and disadvantages. This includes orifice plates, Venturi tubes, cone meters, nozzles, variable area meters and averaging pitots. Practical information and guidance are provided on the use of differential-pressure meters including important considerations for the selection and ongoing maintenance of a suitable meter. A useful table on the advantages and disadvantages of a more extensive range of differential-pressure meters is provided in the summary. By reading this guide you will not become an expert in differential-pressure meters, but it will give you some useful and practical information on their use - from the National Measurement System.

Orifice Plates - The Engineering Toolbox has a a useful range of technical pages on many aspects of Orifice Plates.

Differential Pressure Orifice - The most commonly used flowmeter is the orifice meter. The orifice meter consists of two parts. These are the measurement orifice plate, which is installed in the process line, and the differential pressure transmitter, which measures the pressure developed across the orifice plate. There has been extensive research to determine the operating characteristics of orifice meters. The physical phenomenon of the orifice meter is described by the Continuity equation and the Bernoulli equation - from Gilson Eng.

Fundamentals of Orifice Metering - Throughout the oil and gas industry, there stems the need for accurate, economical measurement of process fluids. Orifice metering satisfies most flow measurement applications and is the most common flow meter in use today. The orifice meter, sometimes called the head loss flow meter, is chosen most frequently because of its long history of use in many applications, versatility, and low cost, as compared to other flow meter available - from the Acadiana Flow Measurement Society.

Conditioning Orifice Plate Technology; Taking the Standard to a New Level of Capability - A very interesting article from Emerson Process Management which highlights the advantages of this innovative design which enables multiple benefits without compromising performance.

Fundamentals of Orifice Meter Measurement - An orifice meter is a conduit and a restriction to create a pressure drop. An hour glass is a form of orifice. A nozzle, venturi or thin sharp edged orifice can be used as the flow restriction. In order to use any of these devices for measurement it is necessary to empirically calibrate them. That is, pass a known volume through the meter and note the reading in order to provide a standard for measuring other quantities. Due to the ease of duplicating and the simple construction, the thin sharp edged orifice has been adopted as a standard and extensive calibration work has been done so that it is widely accepted as a standard means of measuring fluids - from Emerson Process Management.

Application of the Orifice Meter for Accurate Gas Flow Measurement - The most common device used in gas flow measurement is the orifice flow meter. It is capable of very accurate measurement provided it is properly applied, designed, installed, maintained and interpreted. It is the intention of this article to cover these aspects of the orifice meter so that the use of the device can be evaluated and a proper decision made on application - from Emerson Process Management.

Orifice Plates, Orifice Flanges, Metering Runs and Venturi Tubes – This very useful engineering document from ABB covers Orifice Plates, their Maintenance, Inspection, Assemblies, Metering Runs and more.

Orifice Flowmeter Calculator - A fluid passing though an orifice constriction will experience a drop in pressure across the orifice. This change can be used to measure the flowrate of the fluid. To calculate the flowrate of a fluid passing through an orifice plate, enter the parameters into the table. (The default calculation involves air passing through a medium-sized orifice in a 4" pipe, with answers rounded to 3 significant figures.) - from efunda.

Sizing Orifice Plates - Meeting Modern Expectations - Allan G. Kern - Orifice plates with differential pressure (DP) transmitters remain the workhorses of fluid flow measurement in the process industries, due to their proven robustness, ease of use, adaptability to a broad spectrum of applications, familiarity, and economy. The weak side of orifice plates, where otherwise properly applied and installed, is limited turndown, with a nonlinear loss of accuracy at lower flow rates due to the square-root nature of the flow/DP relationship.When sizing orifice plates, some new rules of thumb can be applied to significantly improve orifice plate turndown and accuracy, while gaining extended measurement range, in most applications. This can be accomplished for the cost and effort of revising the calculation, buying a new orifice plate, and re-configuring the transmitter, activities that are routinely carried out in any case - from InTech and the ISA.

Development of Orifice Meter Standards - This paper is for the purpose of reviewing how we have arrived at the orifice meter standards, what is their value and what we can expect in the future. It is of value to review this background since respect for the orifice standards (and other standards) has diminished. This can lead to real chaos for the gas industry. The last way you want to solve your measurement problems is based on personal opinions – this is the purpose of the standards, because it represents consensus data with legal standing - from Emerson Process Management.

Orifice Plates for Flow Measurement & Flow Restriction - This document covers the basics of orifice plates - from wermac.org.

Theoretical Uncertainty of Orifice Flow Measurement - Orifice meters are the most common meters used for fluid flow measurement, especially for measuring hydrocarbons. Meters are rugged, mechanically simple, and well suited for field use under extreme weather conditions. In 1779, an Italian physicist named Giovanni B. Venturi (1746-1822) performed the first recorded work that used orifices for the measurement of fluid flow. Many years of field experience with wide range of meter sizes, variety of fluids, and numerous investigative tests have identified all major contributing factors of measurement uncertainty of orifice flowmeters. Because of their long history of use and dominance in the fluid flow measurement, their designs, installation requirements, and equations for flow rate calculation have been standardized by different organizations in the United States and internationally [Ref 1-7]. These standards provide the guideline for the users to achieve accurate flow measurement and minimize measurement uncertainty. This paper discusses different factors that contribute to the measurement inaccuracy and provide an awareness to minimize or eliminate these errors - from Emerson Process Management.

Orifice Meter Station Operation & Maintenance – A video giving the basics.

VIDEO - Back to Basics: DP Flow Measurement - Walt Boyes - Part One-- Differential Pressure Flow Measurement.

The following information from the CEESI technical library whilst being old covers many fundamentals very well.

• Effects Of Abnormal Conditions Of Orifice Meters - Zaki D. Husain - The orifice meter has been a standard in the gas industry for years. With proper operation and maintenance, the orifice meter has proven to be an accurate method to measure natural gas. The orifice meter is one of the most basic devices ever invented for measurement However, it also has associated problems as a result of its simplicity. With the increasing demand and prices of natural gas minimizing error in measurement has become essential.
• Effects of Abnormal Conditions on the Accuracy of Orifice Measurement - Bill Johansen - The effects of abnormal conditions on orifice plate based flow measurement is a broad topic. The research on abnormal effects has typically focused on issues such as the effects of bent plates, plate eccentricity, dulled orifice bore leading edge, the presence of water and liquified hydrocarbons, and many other conditions found in pipeline orifice meters. This paper discusses potential problems in four areas of orifice based flow measurement: calculation of discharge coefficients, calculation of expansion factors, flow conditioning, and gas sampling.
• Effects of Entrained Liquid on Orifice Measurement- Bill Johansen - Natural gas often has some liquid content. The liquid may be water, hydrocarbons, or compressor oil. As this gas flows through an orifice meter is the gas being measured correctly? This paper discusses four test programs that were conducted to examine the effects of entrained liquids on orifice meter performance.
• The Effects of Oil Coating on the Measurement of Gas Flow Using Sharp Edged Orifice Flowmeters - Bill Johansen and Tom Kegel - Orifice plates are known to be sensitive to a variety of effects due to dimensional variations and flowing fluid conditions. A number of studies have been performed to determine the specific effects of water entrainment and two phase flow on orifices, but the results were not well documented and were limited in scope. This paper describes an investigation funded by the Gas Research Institute (GRI) to determine the effects of a coating of compressor oil on the flowmetering performance of orifice plates. A viscous oil is used to coat only the plate or both the plate and upstream piping. The effect of this coating on orifices having different diameter ratios (B) in several different line sizes is evaluated by statistically comparing the discharge coefficient for the wetted orifice to the discharge coefficient when dry.
• Effect of Liquid Entrainment on the Accuracy of Orifice Meters for Gas Flow Measurement - V.C. Ting and G. P. Corpron - This paper presents the results of a study to show that a small amount of liquid entrainment in an orifice meter can affect the accuracy of gas flow measurement.
• The Orifice Expansion Correction for a 50 mm Line Size at Various Diameter Ratios - Walt Seidl - The expansion coeffiecient or factor for a compressible flowmeter corrects for the change in pressure and density as the fluid is accelerated through the flowmeter. This paper describes the results of a test program to determine the expansion factors for flange-tapped sharp-edged orifices with diameter ratios between 0.242 and 0.726 in a nominal 50 mm (2 inch) line.
• Effects of Abnormal Conditions on the Accuracy of Orifice Measurements - Steve Caldwell - The orifice meter is one of the most widely utilized measurement devices and is one of he oldest, next to the bucket. The orifice meter is one of the most basic devices ever invented for measurement and has many advantages because of its simplicity and also has many associated problems as a result of its simplicity.
• Effects of Abnormal Conditions on the Accuracy of Orifice Measurements - Taft Snowdon - The orifice meter remains the foremost measurement device used on the industry for hydrocarbon flow. The primary element of the orifice meter is the orifice plate and orifice meter tube consisting of the orifice fitting, or flanged pressure taps, adjacent piping and the flow conditioner or straightening vanes. The complete system also includes the temperature and pressure measuring devices used often called the secondary element and the pressure lines from the taps to the pressure instruments. The American National Standard Institute/American Petroleum Institute Standard 2530 (ANSI/API 2530) also called the AGA-3, provides specific recommendations for the manufacture, inspection and installation of an orifice meter. In order to ensure accuracy, with minimum uncertainty, these guidelines and inspection procedure should be established by taking relatively fundamental measurements of the primary element components.
• New Data for the Quadrant Edged Orifice - Charles Britton and Steve Stark - New experimental data is presented for both quadrant-edge and sharp-edge orifice plates used in low Reynolds number applications - from starkassoc.com.
• Effects of Abnormal Conditions on the Accuracy of Orifice Measurements - Steve Caldwell.

Orifice Plate Standards

ISO 5167-2:2003 - Measurement of fluid flow by means of pressure differential devices inserted in circular cross-section conduits running full - Part 2: Orifice plates.

AGA 3.1 Orifice Metering of Natural Gas and Other Related Hydrocarbon Fluids Part 1-General Equations and Uncertainty Guidelines - This standard provides a single reference for engineering equations, uncertainty estimations, construction and installation requirements, and standardized implementation recommendations for the calculation of flow rate through concentric, square-edged, flange-tapped orifice meters. Both U.S. customary (IP) and International System of Units (SI) units are included - from Law Resource.Com.

Flow Measurement User Manual - This manual discusses gas flow measurement based on philosophies expressed in AGA (American Gas Association) and API (American Petroleum Institute) guidelines. It has some useful information on Orifice Plates and the relevant standards - - from Emerson Process Management.

Multiphase Flow Metering

Multiphase Metering - the Challenge of Implementation

High-Performance Multiphase Metering - a Personal Perspective

Good Practice Guide - An Introduction to Multiphase Flow Measurement - This guide provides an introduction to multiphase flow measurement. Firstly, the document covers key definitions associated with multiphase flow before moving on to multiphase flow patterns and properties. Multiphase flow measurement technologies are introduced, along with installation and flow assurance issues - from tuvnel.

The Influence of Liquid Viscosity on Multiphase Flow Meters - from tuvnel.

New Developments in Metering technology

Implementation of New Technology Metering

Recent Experience on implementation of new techniques of gas metering

Kindly provided by Andy Jamieson

Coriolis Flowmeters

The following technical papers are from Emerson Process Management

Coriolis Tutorial - TUTOR is where you can explore the basics of Coriolis theory to understand the capabilities only Micro Motion Coriolis technology offers your process.

Coriolis Technology Creates Superior Meters - Chuck Stack, Micro Motion Inc.

The Coriolis Revolution - Gene Perkins Micro Motion Inc.

Mass Flow Measurement Accuracy in Process Industries - John Dolenc, Emerson Process Management.

Explaining how two-phase flow affects mass flowmeters - Micro Motion Inc.

Traceability and Uncertainty Analysis for Flowmeter Calibration Process with Coriolis Flowmeters as Reference - R. DeBoom, M.Buttler, A.Koblbeck, A Pruysen - Micro Motion Inc.

Understanding the Challenges of Two-Phase Flow - Tim Patten - Micro Motion Inc.

Load Cells Versus Coriolis Mass Flowmeters In Batch Applications - Franki Parson.

ISO 17025 Accreditation and the Application to Using Coriolis Flowmeters as Reference Standards - M.Lee, D.Standiford -Micro Motion Inc and A.Pruysen - Emerson Process Management.

Entrained Gas Handling in Micro Motion^® Coriolis Flowmeters - Tim Patten - This white paper discusses the measurement problems caused by process fluids that contain bubbles of air or other gas, and describes how Micro Motion® sensor and transmitter technology can be used to overcome those problems. It also presents suggestions for minimising measurement problems by improving application design.

Accurate Flow Measurement Improves Profit - Two-wire Coriolis Flowmeter for Loop Powered Applications - Rough Economic Seas - The current economic climate means that many managers are taking a keen interest in the selection of their flow-measuring devices. Today’s decision makers understand the benefits of different flow technologies and accept that when migrating to higher performing technologies, there may be cost implications resulting from, for example, increased wiring and associated installation costs. In a new installation, these extra costs can usually be minimized through good engineering practices.

Other Technical Paper Links

Coriolis Mass Flowmeters - Donald Ginesi - Thanks to Caldon.

When Do You Measure Mass Flow? - Walt Boyes and thanks to M. R. Franceschini, Inc.

What is the Coriolis Principle? - Thanks to the flowmeterdirectory.com.

Coriolis Mass Flowmeters Take Center Stage for Bulk Measurement in Oil & Gas Industry - Andre Verdone - Accurate measurement of liquids is important for all oil and gas production or consumption sites. This is especially true for bulk-transfer devices where large volumes of products are being moved and must be monitored, including crude oil depots, gasoline and jet fuel tank farms, refineries, and even cruise line terminals. In the past, mass transfer was measured in batches with weigh scales or load cells. However, installation, calibration and maintenance of a scale or load cell are costly, difficult to do, time consuming, and don’t work for continuous processes. For these processes, such methods as orifice plates and magnetic flow tubes can measure volumetric flow, but additional instruments are needed to measure temperature and pressure to compensate for fluid density changes. Introducing additional instruments also introduces errors, which can result in an overall measurement error rate as high as 3 percent. Now several measurement standards are moving toward use of Coriolis mass flowmeters, which can measure mass flow directly at the same time as they measure temperature and density. What’s more, transfer measurement by mass is the most accurate method, since mass is independent of, and unaffected by, changing process fluid characteristics, including pressure, temperature, viscosity, conductivity, and gravity - from Flow Control.

Flow Measurement information Notes.

Static Properties, not in motion

Static pressure, the pressure exerted by fluids at rest.

Density

Density is a measurement of the proximity of molecules that make up a substance. Density is Mass per Unit of Volume ( r = m / V ), where: r = Density, m = Mass, and V = Volume.

Effects of Temperature and Pressure on Density

Heating causes a substance to expand, increasing its volume, and decreasing its density. Cooling causes a substance to contract, decreasing its volume, and increasing its density. More pressure causes a substance to compress, decreasing its volume, and increasing its density. Less pressure causes a substance to expand, increasing its volume, and decreasing its density.

Specific Gravity

Specific Gravity is the ratio comparing the density of a fluid to the density of water or air while at standard conditions.

Specific Gravity = Density of a liquid / Density of water.

Specific Gravity = Density of a liquid / Density of air.

The Specific Gravity of Liquids and Gases will decrease as temperature increases.

Dynamic Properties, in motion flowing

Dynamic pressure, the pressure above static pressure caused by movement of fluids.

Flow

In laminar flow, the fluid particles move along parallel paths. If laminar flow could be observed, it would appear as several streams of liquid flowing smoothly alongside each other.

Turbulent flow is agitated and disturbed. Turbulent flow appears to have small, high frequency fluctuations that travel in all directions forming eddies.

Transitional flow exhibits characteristics of both laminar and turbulent patterns. In some cases, transitional flow will oscillate between laminar and turbulent flow.

Viscosity

Viscosity is the property that determines how freely fluids flow. Viscosity can be further described as the property of a fluid that contributes to laminar or turbulent flow characteristics. If the molecules slide easily over one another, the substance has a relatively low viscosity. A substance with a higher viscosity has a higher resistance to flow.

Effect of Temperature on Viscosity

Small changes in temperature may produce significant changes in a fluid's viscosity. As the Temperature of a fluid decreases, its viscosity will increase.

Temperature of a fluid increases, its viscosity will decrease.

Reynolds Number

Flow is often measured in terms of velocity. Therefore, when different portions of the flow are moving at different velocities, measurement accuracy will be affected. The flow profile depends on a combination of factors, including the forces that act to keep flow moving at a constant rate. The relationship between these forces is expressed by the Reynolds number ( RD ). It is a ratio of internal to viscous forces specific to flow conditions where RD = Inertial forces / Viscous forces.

When the Reynolds number is less than 2000, flow is in the laminar region. When the Reynolds number is greater than 4000, flow is considered to be in the turbulent region. When the Reynolds number is in the range of 2000 to 4000, flow is transitional. Viscosity is the factor which most affects the value of the Reynolds number.

The Measurement

Flow Rate

The measurement unit to express the rate of flow actually refers to the velocity of the flow, or how rapidly the substance moves. A flow rate is a measure of the distance a particle of a substance moves in a given period of time. Feet per second is a unit commonly used to measure flow rate.

Volumetric Flow Rate

The method of measurement used to indicate the volume of fluid that passes a point over a period of time is volumetric flow rate. Volumetric flow rate is usually expressed in gallons per minute (GPM) or cubic feet per second.

Mass Flow Rate

Mass flow rate determines the amount of mass that passes a specific point over a period of time. Mass flow rate applications determine the weight or mass of the substance flowing through the system.

Differential Pressure

The rate of flow using a head flowmeter device is determined by measuring the pressure drop across a constriction. Differential pressure is measured and flow rate is inferred from the measured difference in the two related pressures.

Bernoulli's Law

Head-flow type flow measurement is based on the principle that energy cannot be created or destroyed. Consequently, in a pipe, with fluid flowing, the same volume of fluid will pass by two different points over the same period of time. However, if the fluid flow passes through a constriction, the flow velocity must increase if the flow rate is to remain constant,. Therefore, to maintain the flow rate between the two different points the total energy of the fluid must also remain constant.

All head-type differential pressure flowmeters operate on the conservation of energy principle. The primary sensing element creates a differential pressure by constricting the fluid flow, while a secondary element measures this differential pressure. The relationship between differential pressure and flow is:

Q = CA times the square root of ( 2 gh )

where:

Q = flow

C = orifice coefficients

A= cross-sectional area of the restriction

g = gravitational constant

h = head or differential pressure

This square root or "square law" relationship of flow to differential pressure makes some disadvantages of head-type flowmeters apparent. Measurement of flows of less than 30 percent of maximum may be less accurate than a measurement at a higher percent of maximum flow. The square root relationship also makes integrating or totalizing of flows cumbersome and the accuracy of totalized flow somewhat questionable. In addition, this relationship represents a nonlinear effect on loop gain in flow control systems, requiring controller readjustment at different rates of flow. The nonlinear effect results in loss of accuracy below 50 percent of the measurement span.

Orifice Plate

The most common and the simplest differential producer is the orifice plate. An orifice plate is usually composed of stainless steel. An opening of a predetermined size and shape is machined into the plate according to strict tolerances. Then, the orifice plate is inserted perpendicular to the process flow. This abruptly reduces the stream size, creating a head-producing constriction. Differential pressure is then measured at pressure taps installed upstream and downstream from the orifice plate.

The most common type of orifice plate is the concentric bore where the hole will be in the center of the pipe. An eccentric bore plate is used to minimize measurement inaccuracies that can be caused by solids settling out of the liquid. The eccentric bore is positioned so that the bottom of the hole is even with the inside wall of the pipe.

Venturi Tubes

The venturi tube places a constriction in the flow path that acts on the same principle as that of the orifice plate. In basic forms, the venturi tube consists of a converging conical inlet, a cylindrical throat, and a diverging recovery cone. Venturi tubes are better suited for the measurement of dirty fluids and slurries which would tend to build up in front of, or clog an orifice plate.

Flow Nozzles

Flow nozzles are a restriction consisting of an elliptical contoured inlet and a cylindrical throat section. Flow nozzles are well suited for measurement of steam flow and other high velocity fluid flows where erosion may be a problem.

Elbow - Tap Flowmeters

Elbow-tap flowmeters operate on the principle that when a fluid moves around a curved path, the acceleration of the fluid around the curved path creates a centrifugal force. The centrifugal force results in a higher pressure on the outside of the elbow than on the inside of the elbow. A major advantage is the ease with which they can be installed, however they are less accurate than other head-type measurement devices.

Pitot Tubes

Consists of two pressure taps in a flow stream. The low pressure tap is perpendicular to the flow path and measures the static head. The high pressure tap is inserted into the flow stream and faces directly into the flow path. By measuring the differential pressure created by the Pitot tube, flow rate can be calculated. Pitot tubes causes negligible pressure loss in the flowing stream, however they are difficult to position properly in the flow stream and are subject to plugging in slurry applications.

Other types

Magnetic Flowmeters

Magnetic flowmeters are widely used to measure the flow rate of conductive liquids in process applications. In general, magnetic flowmeters are accurate, reliable, measurement devices that do not intrude into the system.

Principle of Operation

Magnetic flowmeters operate on the principle of Faraday's Law of Electromagnetic Induction, an electrical voltage is induced in a conductor that is moving through a magnetic field and at right angles to the field. The faster the conductor moves through the magnetic field, the greater the voltage induced in the conductor.

AC Magnetic Flowmeters

Alternating current (AC) magnetic flowmeters excite the electromagnetic field with AC current. Noise may be produced within the meter or within the process. The zero must be adjusted when the flowmeter is full of process fluid at zero flow. Sensitivity of electrodes may be reduced if the electrodes become coated with a non-conductive material.

DC Magnetic Flowmeters

Direct current (DC) magnetic flowmeters excite the eletro-magnetic field with a DC current. DC magnetic flowmeters are not subject to inaccuracies due to the coating of electrodes.

Thermal Flowmeters

In a thermal flowmeter, flow rate is measured either by monitoring the cooling action of the flow on a heated element placed in the flow or by the transfer of heat energy between two points along the flow path.

Hot Wire Anemometers

Hot wire anemometers have probes inserted into the process flow. These probes are usually connected in a typical bridge circuit. One of two probes is heated to a specific temperature. The second probe measures the temperature of the fluid. As the flow increases, it causes a heat loss in the heated probe. Consequently, more current is required to maintain the probe at the correct temperature. The increase in current flow reflects the energy necessary to compensate for the heat loss from the probe that was caused by the changing fluid flow. This change in current flow can be measured and used to calculate mass flow rate.

Calorimetric Flowmeters

Calorimetric flowmeters work on the principle of heat transfer by the flow of fluid. Typically, calorimetric flowmeters are comprised of elements arranged consecutively along the direction of the flow. A heating element is placed in the flow. A sensor is positioned to measure the temperature upstream of the device; a second measuring device reads the temperature of the flow downstream from the heater. The rate of flow is determined by the difference in the two temperatures.

Ultrasonic Flowmeters

Ultrasonic flow instruments measure the velocity of sound as it passes through the fluid flowing in the pipe. Some designs allow measurements to be made external to the pipe, while others require that the sensor be in contact with the flowstream. Thus, the sensor may be clamped onto the pipe or may be mounted in a section of pipe which is installed in the system.

Mass

In some industrial processes, accurate measurement of mass flow is required. Mass is defined as a measure of the quantity of matter in a body. Mass is one of the three fundamental quantities, the others being length and time, upon which all physical measurements are based. Often mass is thought of as weight, but these quantities are dissimilar. Weight is the measure of the effect of earth's gravity on mass and varies over the earth's surface.

Angular Momentum Mass Flowmeter

The angular momentum mass flowmeter is a true mass flowmeter since the reaction of the primary element is proportional to the momentum of the flow stream. In this type of device fluid passes through an impeller and a turbine mounted in series in a pipeline. The impeller is driven at a constant speed by a small motor. As it is rotated, it causes the fluid entering the impeller to take on its rotational velocity. The fluid then enters a turbine that is restrained by a calibrated spring and does not rotate. The torque produced by the turbine on the calibrated spring is directly proportional to the mass flow.

Coriolis Flowmeters

The Coriolis flowmeter is a true mass flowmeter which operates on the physical principle of the effects of the earth's rotation on a mass. This effect is referred to as the Coriolis acceleration and produces a Coriolis force. Since torque is equal to mass multiplied by acceleration, a measurement of the Coriolis force provides the means for a direct determination of mass flow.

One type of Coriolis mass flowmeter consists of an impeller with radial vanes. The meter is positioned so the vanes are in line with the flow. The impeller, powered by a small motor turns at a constant rate. The vanes direct the flow in a direction that is radial and perpendicular to the axis of rotation., this results in a Coriolis acceleration which then exerts a force on the vanes. Force-sensing devices measure the torque produced, and, since the amount of torque is directly proportional to the mass flow rate, the value can be used to calculate the rate directly.

The vibrating U-tube is another type of mass flowmeter that uses the principle of Coriolis acceleration of a fluid. The U-tube offers no obstruction to the flowpath allowing it to measure liquids with varying physical properties. In addition, this type of flowmeter may be used with liquids containing solids. The flowmeter consists of a vibrating U-tube in which the Coriolis acceleration is created and measured. An oscillator vibrates the tube rapidly along the axis formed between its open ends. Because of this alternation, the fluid in one arm of the tube flows away from the axis of rotation while in the other half, the same amount of fluid flows towards the axis of rotation. These opposing Coriolis accelerations result in forces in the opposite directions, which produce a twisting motion in the tube which is directly proportional to the mass flow through the U-tube, is detected by a sensing device.

Hydraulic Wheatstone Bridges

The hydraulic Wheatstone bridge mass flowmeter is a true mass flowmeter which uses differential pressure to measure the mass flow. Four identical orifice plates are placed in a Wheatstone bridge arrangement. A portion of the flow is pumped at a constant rate from one segment of the fluid loop to another segment of the loop. A Differential pressure transmitter is then used to sense the flow signal.

Positive Displacement

Positive Displacement Flowmeters

In many applications, positive displacement flowmeters provide significant advantages over meters of other classes. They are accurate, precise, have a wide flow range and are ideal for measuring low rates of flow. In addition, their operation requires no external power supply and they usually require only simple maintenance. Positive displacement flowmeters operate by trapping a known quantity of fluid, and transferring the fluid from the inlet to the outlet connections. Then the number of trapped volumes that pass through the meter is counted to measure the flow.

Nutating Disc Flowmeter

The meter consists of a housing containing a disc which is allowed to wobble, or nutate. As fluid enters the inlet port of the meter, its movement in the chamber causes the disc to turn or nutate. As the disc turns, it transfers a fixed quantity of fluid from the inlet to the outlet.

Helical Gear Positive Displacement Flowmeter

In this type of positive displacement flowmeter, two radically-pitched helical gears are used to continually trap liquid as it passes through the flowmeter. A sensing system, typically magnetic or optical, senses a pulse each time a portion of a revolution occurs. Flow through the flowmeter is proportional to the rotational speed of the gears.

Oscillating Piston Positive Displacement Flowmeters

When a quantity of fluid enters the chamber it causes a piston to rotate on its shaft. As it does so, a specific volume of fluid is moved through the meter and discharged at the outlet port. Each revolution of the piston corresponds to the movement of a fixed volume of fluid through the meter. A sensing system, typically magnetic or optical, senses a pulse each time a portion of a revolution occurs.

Rotary Vane Flowmeters

As fluid enters the meter, vanes are moved causing the rotor to turn. The vanes are spring loaded and able to slide freely in the rotor body as it turns, When the fluid enters the inlet port, the vanes extend against the housing wall to enclose the measuring chamber, they retract at the outlet to discharge the fluid into the system. Each complete revolution of the rotor moves several fixed volumes of fluid through the meter from inlet to outlet.

Lobed Impeller and Oval Gear Flowmeters

Two lobed impellers (rotors) are mounted on parallel shafts and are geared-synchronized to keep them correctly positioned in relation to each other. These lobes rotate in opposite directions, so as fluid enters the meter and causes the impellers to rotate, a measuring chamber is formed.

The oval gear flowmeter is a variation of the lobed impeller flowmeter. The lobed impellers are replaced by a pair of meshed oval gears.

Axial Turbine Flowmeters

In current-type meters, a discrete volume of fluid is not actually captured and transferred from inlet to outlet to measure flow rate as it is in a positive displacement meter. Rather, the total quantity of flow is inferred from the reaction of the turbine caused by the fluid flow.

Rotameters

The rotameter consists of a tapered glass tube which is incorporated into the piping system. The tube is positioned so its greatest diameter is uppermost and contains a float which moves up and down freely as the flow within the tube changes. Since the upward and downward forces on the float are in equilibrium, the float assumes a definite position at a given flow rate.

Shedders

Vortex shedders are a type of oscillatory flowmeter. Such flowmeters employ a physical phenomena that cause discrete changes in some parameter that is a function of the flow through the flowmeter.

Theory of Operation

Vortex shedding can occur whenever a blunt or flat-faced body, called a bluff body, is positioned in a flowing stream of gas or liquid. As fluid passes a bluff body at low velocity, the flow is able to follow the irregular contour. However, as the velocity increases, the fluid tends to separate into layers and swirl around the body to form vortices downstream of it. When a vortex on one side of the bluff body breaks away from the body, it is followed by a new one on the opposite side of the body. That in turn also breaks away, followed by a new vortex on the opposite side. This alternating pattern of vortices is called a Von Karman vortex trail. The alternate shedding of vortices is the basis of meter operation. It is this increase and decrease of pressure across the bluff body which is measured to determine a frequency of vortex formation. The frequency of the vortex generation is directly proportional to the fluid velocity.

Design

Vortex shedding flowmeters are generally comprised of three basic parts: a shedder, or bluff body, which generates the vortices; a sensor to sense the frequency of the vortices and produce a signal that can be measured; and, a transmitter to amplify and condition the signal.

Vortex Precession Flowmeter

This type of meter also operates by detecting vortices. However, in this device, the fluid is forced into a swirl condition by swirl-producing vanes, or swirl blades. The center of the vortex becomes displaced from the meter centerline and follows a helical path (precession) as it moves downstream through an enlargement. This precession causes fluctuations in fluid pressure and velocity. A sensor placed downstream from the swirl blades detects and measures the frequency of the precession. This frequency is linearly proportional to flow rate.

Flow & Level Calibration Notes

Differential Pressure Transmitter Calibration

Introduction

In the Differential Pressure Transmitter, as flow increases, the differential pressure increases, and when flow decreases the differential pressure decreases. For example, an orifice plate is placed in a pipe to restrict the fluid flow. This restriction creates a pressure drop that can be converted to flow rate. The differential pressure transmitter measures the pressure drop created, by measuring pressure at two different points, upstream and downstream. Differential pressure, then is the difference between the higher pressure or upstream reading and the lower pressure or downstream reading. Differential Pressure = High Pressure - Low Pressure.

Input and Output Measurement Standards

Differential pressure is usually measured in inches of water.

Use a low pressure calibrator to both furnish and measure the input pressure.

A milliammeter is an appropriate output standard to measure the transmitter's output.

Differential Pressure Transmitter Connections

Connect the transmitter to the pressure calibrator as shown in the manufacturer's instructions for the calibrator. The air supply requirements for the calibrator are also found in the manufacturer's instructions. Connect the output from the pressure calibrator to the high pressure port on the transmitter to provide signal pressure. Vent the transmitter's low pressure port to atmosphere to provide a reference point for the differential pressure measurement. To measure the transmitter output, connect a milliammeter to the transmitter. Then connect a 24-volt power supply in series with the transmitter and milliammeter.

Differential Pressure Transmitter Five-Point Check

Typically, inputs at 10%, 30%, 50%, 70% and 90% of span are used as test points.

Check for Hysteresis. Hysteresis is the tendency of an instrument to give a different output for a given input, depending on whether the input resulted from an increase or decrease from the previous value.

Often the data from an instrument test is recorded on a calibration data sheet to help identify instrument errors.

Adjusting for Error Correction

Adjust the zero first, since span error is corrected only after an accurate zero is established. Zero is properly set when a 10% input produces a 10% output.

Adjust the span at 90%. Since zero and span frequently interact, after one of these errors has been corrected, the other may require readjustment.

Square Root Extractor

Flow rate which may be represented by Q, is the square root of the calculated pressure drop across a restriction. Q = square root of the Differential Pressure. Differential pressure transmitters may include an integral square root extractor, which provides a linear output signal. However, if a square root extractor is not part of the transmitter circuitry in the process, a separate square root extractor may be installed in the output signal loop.

Input and Output Measurement Standards

In a loop, a 4-20 mA output from a differential pressure transmitter provides an input to the square root extractor. So, in the calibration, a milliamp source would provide an appropriate input standard. The output measurement standard is also a milliammeter. To complete the setup, connect a power supply in series with a square root extractor and milliammeter. Manufacturer's instructions specify the input values and expected outputs.

The square root of the input determines the output.

Magnetic Flowmeter Calibration

Introduction

In measurement and control loops where the process flow is a conductive liquid, magnetic flowmeters can be used to measure flow. As fluid passes through the meter's magnetic field, the fluid acts as a conductor. The change in potential varies directly with the fluid velocity.

Input and Output Standards

Disconnect the flow tube from the transmitter. A magnetic flowmeter calibrator simulates the signal provided by the electrodes in the flow tube. The operating voltage and frequency range of the calibrator must match those of the magnetic flowmeter. Select the maximum output signal using the calibrator range switch. The signal options include 5,10, or 30 mV AC. The magnetic flowmeter calibrator has predetermined test point, so the percent output knob is used to set each output for a five-point check. Since output is in milliamps, a milliammeter is the appropriate output measurement standard for this calibration setup.

Five-Point Check

To begin the calibration of a magnetic flowmeter, calculate the input signal value. The input signal is equal to the upper range multiplied by the calibration factor and by the phase band factor. These values are indicated on the instrument's data plate.

Input Signal = Upper Range x Calibration Factor x Phase Band Factor

Record the output values at each test point, and from this data determine if the instrument is within manufacturer's specifications. The following formula tells if the range of error is within manufacturer's specifications:

Accuracy = (Deviation / Span ) * 100

Deviation = Expected Value - Actual Value

Adjust zero at the lowest point in the instrument's range by turning the zero adjust screw until the output reading is correct. Then adjust span, and , since zero and span often interact, verify both until no further adjustment is necessary.

To conclude the calibration, recheck the upscale and downscale readings to verify that the instrument is properly calibrated.

Vortex Shedding Flowmeter Calibration

Introduction

In the process line, flowing fluid strikes the bluff body and vortices are shed alternately on each side of the bluff body. The flow velocity determines the frequency at which the vortices are shed. The shedding of the vortices induces a resonance in the bluff body that is detected by the sensor. From the sensor, pulses are sent to the transmitter where the appropriate loop output is developed.

Input and Output Measurement Standards

Calibration of a vortex shedding flowmeter's transmitter requires an input standard that can simulate the electrical pulses counted by the transmitter. A frequency generator provides this input. For a more detailed explanation of a specific frequency generator's features, see the manufacturer's literature.

A milliammeter will display the output signal.

Settings and Connections

Before making the connections, determine the vortex shedding frequency. The vortex shedding frequency is usually provided by the manufacturer, but if it is not listed in the manufacturer's literature, calculate the frequencies using this formula:

Vortex Shedding Frequency = RF x CF x ( URV/TIME)

where:

The vortex shedding frequency is represented in pulses per second or PPS.

PPS = represents the alternate shedding of vortices on either side of the bluff body

RF = stands for reference factor which can be found on the transmitter's data plate and is usually represented in pulses per US gallon

CF = is the conversion factor, and is a number found in the manufacturer's conversion table, the CF converts the RF to actual volume or mass flow rate units

URV = is the upper range value in US gallons per minute

TIME = is related to the increment in which the flow is measured

Are span jumpers required to calibrate this transmitter? Refer to the manufacturer's instructions for the appropriate setting for the coarse span jumpers.

Once the PPS has been determined and span jumpers set in their proper positions, the frequency generator can be connected to the input terminals of the transmitter. The output side of the calibration loop is connected in series. After all the connections are made, set the fine span.

Adjustments and Accuracy

To set the fine span, the frequency generator is set to the upper range value of the transmitter. Adjust the fine span screw until 100% output is indicated on the milliammeter. Once the fine span adjustment has been completed, as indicated by a 20 mA reading on the output standard, adjust the zero.

Disconnect the frequency generator and connect the signal lead to the shield of the coaxial cable.

Zero is adjusted at the low range value so the generator must be set to the appropriate setting following the fine span adjustment.

The zero is adjusted until the output signal matches the input signal at the lowest input value.

The span and zero should be adjusted and readjusted until both are correct.

Perform the Five-Point check to verify the instrument's range accuracy.

Mass Flowmeter Calibration

Introduction

A mass flowmeter measures flow rate in weight per unit time rather than volume. This measurement is independent of temperature and pressure.

Input and Output Measurement Standards

Although an input and an output standard are needed, smart mass flowmeters are digital instruments, so they also require a special communication device. This device, called an interface device or communicator, is used for configuration and calibration.

The interface device must be connected to the mass flowmeter. It can be connected at any point in the loop as long as it is in parallel with the signal lines.

When the device is turned on, a self-diagnostic program is performed. After the self-test is complete, press the process variable key to display current readings from the transmitter.

Keys have the following functions:

HELP = gives an explanation of the current display and the function keys

RESTART = initiates communication with the smart transmitter

PREVIOUS FUNCTION = returns user to last decision level

ALPHANUMERIC KEYS = enter information into the interface

Configuring Mass Flowmeters

Configuration defines the parameters of the transmitter's operation. To begin on-line configuration, press the "config" key on the interface device. Then enter information to identify the instrument.

The instrument parameters are checked and displayed by the interface device. Make any corrections to these displays by following the prompts on the interface device display. With the changes made, press the restart key to download the data to the transmitter. This completes the configuration. Now verify span and zero.

Correcting Errors

To establish the zero and span values, the flow tube must be full of process liquid with no flow. Because actual process fluid is used, this procedure is typically done on an installed transmitter.

Press the "format" key followed by the "proceed" key. Then press the "autozero" key.

The autozero automatically establishes zero to the properties of the process fluid.

The resulting display will indicate that the mass flowmeter is properly calibrated.

Hydrostatic Level Calibration

Introduction

A level sensing device locates the interface between a liquid and a vapor or between two liquids. Then it transmits a signal representing this value to process measurement and control instruments. As the level in the tank changes, the output reading changes proportionally. Hydrostatic head pressure is used to measure fluid level. To determine the height or level of a liquid the head pressure is measured and by knowing the specific gravity of the liquid the height can be calculated. Hydrostatic level gaging often use a differential pressure transmitter to compensate for the atmospheric pressure on the liquid. The high pressure port senses the atmospheric pressure on the fluid in the tank. The high side also senses hydrostatic head pressure. The difference between the pressures can be converted to level. The low pressure port senses only atmosphere.

In dip pipe applications, gas flows through a pipe that is submerged in the tank's liquid. A differential pressure transmitter measures the back pressure on the tube caused by an increase in the tank level. The high pressure port senses the pressure increase caused by the back pressure in the dip pipe. The low pressure port is vented to atmosphere.

The same calibration procedure applies for any differential pressure level measuring system.

Input and Output Measurement Standards and Connections

A low pressure calibrator is the input measurement standard. It provides and measures low pressure values as required for calibrating hydrostatic level systems. A low pressure calibrator contains a pressure readout and pressure regulator.

A milliammeter measures the transmitter's output. The milliammeter, power supply, and transmitter should be connected in series. For best calibration results, mount the transmitter in the same position as it is installed in the process. At the transmitter connect the source of pressure to the high pressure port and vent to atmosphere the low pressure port.

Five-Point Check

Determine the instrument's range and test points for calibration.

For the lower range value measured in inches of water, divide the minimum height of the liquid in inches by the liquid's specific gravity. The upper range value is the maximum height of the liquid in inches of water divided by its specific gravity. The span then, is the difference between these values. Perform the five-point upscale and downscale check.

Correct the zero at 10% of input span, adjusting zero until the output produced is 10% of the output span. Next, correct the span error, applying 90% input and adjusting the span until 90% output is produced.

Closed Tank Level Gauging

The procedure used in open tank applications is also used for closed tank applications. Closed tank applications must compensate for the static pressure in the vapor above the liquid. To accurately measure the head pressure of the liquid alone a reference leg is used. The reference leg is a pipe connecting the vapor space to the low side of the differential pressure transmitter. The reference leg must be either completely dry or completely filled with liquid.

Dry Reference Leg

The low pressure port receives the pressure of the vapor space. The high side receives vapor pressure in addition to the pressure from the liquid. The value measured by the transmitter represents only the pressure of the liquid because vapor pressure is applied to both the high and low sides of the transmitter. Calibrate with pressure to the transmitter's high pressure port, and vent the low pressure port to atmosphere. Adjust the transmitter's span for the specific gravity of the liquid in the tank. The low range is equal to the minimum level in inches, and the upper range value is equal to the maximum level in inches.

Wet Reference Leg

Often it is necessary to use a reference leg filled with liquid for gaging the level in closed tanks that contain volatile fluid. The column of fluid in the reference leg imposes additional hydrostatic pressure on the pressure side of the transmitter. This additional pressure must be compensated for to correctly gage level.

To determine the additional pressure that the reference leg will apply, take the height of the wet leg in inches and multiply it by the specific gravity of the fluid. The reference leg fill liquid may be different from the tank contents. Connect the low pressure calibrator to both ports of the transmitter. A regulator is used to add the hydrostatic pressure of the wet leg to the low side. Then, zero the output until 4 mA of output is produced. After zero is adjusted, perform a five-point check to the high side using a second regulator. In systems where the transmitter is mounted below the minimum measuring level, compensate for the additional static pressure by lowering the zero value. In systems where the transmitter is mounted above the minimum measuring level, compensate for the decreased static pressure by raising the zero value.

Calibrate the transmitter span first before compensating zero for transmitter height location.

Displacement Level Calibration

Introduction

Buoyant force acts on a displacer that is submerged in a liquid. The displacer is reduced in weight by the weight of the amount of fluid it displaces. This movement of the displacer is typically translated and converted to an instrument signal.

Input and Output Measurement Standards

One method is to use actual liquid level as the input for calibrating a displacement level transmitter. The most appropriate liquid for replicating process conditions is a safe liquid with the same specific gravity as the process fluid.

Connect a milliammeter as the output standard and a 24 V DC power supply in a series circuit with the transmitter.

Determine the setting for the calibration dial by multiplying the specific gravity of the liquid by the correction factor. Then, set the pointer to the compensated value.

Displacement level transmitters are classified as direct or reverse acting. With direct action, an increase in level, increases the output signal, and a decrease in level decreases the output signal. With reverse action, an increase in level, decreases the output signal, and a decrease in level increase the output signal.

Calibration

When the chamber is empty, the corresponding output should be 4 mA. If the milliammeter displays a value that is greater than or less than 4 mA, adjust the zero.

To correct span, fill the chamber to the upper range value, and turn the span adjustment until 20 mA is produced.

Linearity is not always adjustable on this type of transmitter, check to manufacturers specifications.

Adjust both zero and span until transmitter performs within specifications.

Liquid-Liquid Interface

This same sensing principle used to measure liquid vapor interface, can be used to locate the interface between two liquids.

The heavier of the two liquids exerts more buoyant force, so as the lower phase rises or falls, the displacer travels with it.

To create calibration conditions that replace the process, use liquids that have the same specific gravity as the process fluids. Fill the chamber with the lighter phase to check and adjust the zero. Check zero by filling the chamber to 100% with the lighter fluid.

Check span by filling the chamber 100% full of the heavier phase. Adjust span until 20 mA output is produced.

Check mid-range output and recheck zero and span.

V-Cone Flowmeters

Go to Specific Subject: V-Cone Engineering Design | V-Cone Flowmeter Applications | V-Cone Oil and Gas Applications | V- Cone Chemical Applications | V-Cone Defence Applications | V-Cone Metals and Mining Applications | V-Cone Nuclear Applications | V- Cone Paper Industry Applications | V-Cone Power Industry Applications | V-Cone Sugar Industry Applications | V-Cone Transport Industry Applications | V-Cone Water and Wastewater Industry Applications | Miscellaneous V-Cone Applications | V-Cone^® Suggested Specifications

The following links are from McCrometer.

 

V-Cone Engineering Design

V-Cone Technical Brief - English - Spanish - Russian - 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. This technical brief gives a comprehensive overview of the technology.

An Overview of the McCrometer V-Cone Meter - Dr. RJW Peters and Dr. R. Steven - The V-Cone meter is a differential pressure (DP) type meter patented by McCrometer Inc. The V-Cone meter is in many respects a classical DP meter using the physical laws of the conservation of mass and energy as its principle of operation. However, there are important differences between the V-Cone meter design and other DP meter types. These differences give the V-Cone meter important performance advantages. These advantages include the ability of the V-Cone meter to operate with very short upstream and downstream straight pipe lengths, to create a low total pressure (or “head loss”), to create a very stable DP, to give a large turn down, to create relatively low signal noise and to cope well with liquid and particulates in the gas stream. The aim of this paper is to discuss the design of the V-Cone meter and explain why this design gives these advantages over traditional DP meters - from the American School of Gas Measurement Technology.

10 Things You Probably Don’t Know About Cone Meters - (But Really Should Find Out) - Nick Voss - This article details some interesting facts about Cone Meters.

Flow Calculations for the V-Cone^® and Wafer-Cone^® Flowmeters.

Wet Gas Metering with V-Cone - Dr. Richard Steven and Dr. RJW Peters - With the industrial requirement to meter wet gas flows increasing worldwide McCrometer has tested the performance of the single phase V-Cone meter (a Differential Pressure (DP) type meter) in wet gas flows in both the NEL and CEESI wet gas loops. These tests have shown how the V-Cone meter responds to different amounts of liquid entrained in a gas flow and have enabled correction factors to be developed.

API 22.2 Revised from API 5.7 - A Summary by Dr R.J.W. (Bob) Peters - McCrometer V-Cone Meters Tested in Accordance with API 5.7 "Testing Protocol for Differential Pressure Flow Measurement Devices" and Subsequently Further Tested to meet the Additional Requirements of API 22 "Testing Protocol" Section 2 - "Differential Pressure Flow Measurement Devices" (a Revision of API 5.7 ).

V-Cone Installation Guide #1 - Upstream and Downstream Minimum Straight Pipe Run Requirements for Liquid Metering and Gases at a Reynolds Number (Re) Value Less Than or Equal To 200,000.

V-Cone Installation Guide #2 - Upstream and Downstream Minimum Straight Pipe Run Requirements for Gas Metering at a Reynolds Number (Re) Value > 200,000.

Pipe Elbow Effects on the V-Cone Flowmeter - Stephen A. Ifft and Eric D. Mikkelsen - Installation effects of upstream disturbances on flowmeters are important in today’s marketplace. Lengthy upstream piping required by many types of flowmeters can substantially increase the cost of flowmeter installations. This is especially true when flowmeters are added to existing systems. Obviously, interest is building about the effects of common installation problems. One common disturbance found in piping configurations is the single 900 elbow and close coupled double 900 elbows out-of-plane. The National Institute of Standards and Technology (N.I.S.T.) in Gaithersburg, Maryland is studying installation effects on several flowmeter technologies as part of a government/industry consortium. The McCrometer Division of Ketema Inc. is conducting installation effects tests on the V-Cone flowmeter at the McCrometer water test laboratory in Hemet, California. Since 1986, McCrometer has replicated the N.I.S.T. tests performed on a typical orifice plate flowmeter. Both N.I.S.T. and McCrometer tests incorporated a wide range of beta ratios from 0.363 to 0.750 and used relative positions of the meter to the elbows from 0 to 190 diameters. McCrometer tests indicate that the V-Cone is less susceptible to the presence of upstream single elbows and double elbows out-of-plane than a typical orifice plate flowmeter. Depending on beta ratio and the type of elbow upstream, it appears an orifice meter can require as much as fifty diameters of upstream pipe run. McCrometer’s tests indicate that within the tested beta ratio range, the V-Cone meter can be installed close - even close coupled - to either single or double elbows out of- plane without affecting the stated accuracy of the meter more than 0.3%.

An Update on V-Cone Wet Gas Metering Research - Dr. Richard Steven - Multiphase Development Manager, McCrometer, Charles Britton and Tom Kegel CEESI.

Partially Closed Valve Effects on the V-Cone Flowmeter - Stephen A. Ifft - Research conducted indicates that the V-Cone flowmeter is less susceptible to upstream flow disturbances than traditional flowmeters. This testing has placed various flow disturbances upstream of the V-Cone including single elbows, double elbows out-of-plane, valves, and swirl generators. In an effort to further quantify the effects of partially closed valves on the V-Cone, McCrometer has completed the first in a series of valve installation effects tests.

Permanent Pressure Loss Comparison Among Various Flowmeter Technologies - Stephen A. Ifft - This paper explores the issue of permanent pressure loss through various types of flow metering technologies. Of particular interest is the V-Cone. The V-Cone flowmeter is a differential pressure device produced by McCrometer, Hemet, California, USA. By design, the V-Cone measures differential pressure created by a cone positioned in the center of the pipe. The open area through which the fluid passes is stretched over the edge of the cone. This annular space appears to constrict flow dramatically compared to other metering technologies. This paper compares the permanent pressure loss among meters in a typical application.

Signal Noise Ratio Comparison for V-Cone and Orifice Plate Flowmeter - Stephen A. Ifft - This paper discusses and compares the relative signal noise between the V-Cone differential pressure flowmeter and a typical orifice plate differential pressure flowmeter.

The VM V-Cone System Flow Meter - Measurement Simplified - This bulletin covers Performance, Accuracy, Self-conditions flow, Maximum installation flexibility, Maintenance and Features and Benefits of V-Cone Meters.

A Performance Study of a V-Cone Flowmeter in Swirling Flow - This report describes a test to evaluate the measurement accuracy of three 150 mm (6 inch) V Cone meters of different beta ratios in swirling flow.

New Method for Accurate High Reynolds Metering uses Water Calibration for Significant Cost Savings - Jonathan Hollist and Nick Voss - Cone meters have been shown to be an accurate measuring device for various flow applications. In order to maintain accuracy, Cone meters need to be calibrated to determine the discharge coefficient (Cd). The Cd often changes with Reynolds number. The same meter can have a different Cd for gas applications (high Reynolds numbers) than for liquid applications (low Reynolds numbers). Therefore a Cone meter needs to be calibrated over the entire range of Reynolds numbers for its specific application. In order to reach the high Reynolds numbers in most gas applications calibration need to be done in a gas lab. This often is verily costly and time consuming. To save time and money, accuracy is often sacrificed and a Cone meter slated for a gas application is calibrated in the manufacturer’s water facility. McCrometer has developed a method that can predict the Cd at high Reynolds numbers based on a water calibration at small Reynolds numbers. This paper discusses the accuracy of this method.

Don’t Let Valves Come Between You and Accurate Flow Measurement - Jim Panek - Getting valves and flow meters to work together is sometimes a challenging task within industrial water and wastewater applications. Valves tend to create the kind of irregular media flow patterns in pipelines that make it a real challenge to achieve accurate flow measurement of liquids, gas or steam. That’s why many types of popular liquid flow meters require straight pipe runs. Unfortunately, the nature of the process or the kind of space required for long straight runs of pipe is often an impossible luxury in many of today’s plants.

The following papers are made available thanks to Dr Bob Peters of McCrometer:

New Compact Wet Gas Meter Based on a Microwave Water Detection Technique and Differential Pressure Flow Measurement - Dr Øystein Lund Bø and Dr Ebbe Nyfors, Roxar Flow Measurement, Dr Tore Løland, Statoil and Dr Jean Paul Couput, TotalFinaElf.

Testing the Wafer V-Cone Flowmeters in accordance with API 5.7 “Testing Protocol for Differential Pressure Flow Measurement Devices” in the CEESI Colorado Test Facility - Dr R.J.W.Peters - Flow Measurement Technology Manager, McCrometer,Dr Richard Steven - Multiphase Meter Development Manager, McCrometer, Steve Caldwell - Vice President, CEESI, Bill Johansen - Engineering Manager, CEESI.

Tests of the V-Cone Flow Meter at Southwest Research Institute^® and Utah State University in Accordance with the New API Chapter 5.7 Test Protocol - Dr. Darin L. George - Senior Research Engineer, Southwest Research Institute, Mr. Edgar B. Bowles - Fluid Systems Engineering Manager, Southwest Research Institute, Ms. Marybeth Nored - Research Engineer, Southwest Research Institute, Dr. R.J.W. Peters - Flow Measurement Technology Manager, McCrometer, Dr. Richard Steven - Multiphase Development Manager, McCrometer.

The Use of a V-Cone Fuel Flow Meter to Measure the Coke Oven Gas and Natural Gas Flow in a Combined Heat and Power Plant - Ann McIver and Dr. R.J.W. Peters.

Other Links

Flow Disturbance Cone Meter Testing - Gordon Stobie, Richard Steven, Kim Lewis, Bob Peebles - Cone meters have grown in popularity due to their claimed immunity to flow disturbances. Cone meters are said to require no flow conditioning and little upstream and downstream straight pipe lengths. If this is true, cone meters can be installed in many locations where no other flow meter could operate satisfactorily. A meter that is immune to flow disturbances is of significant importance to industry. Hence, independent proof of cone meter resistance to flow disturbances is important. However, there is little literature in the public domain discussing cone meter performance in disturbed flows - - The Norwegian Society for Oil and Gas Measurement.

 

V-Cone Flowmeter Applications

 

V-Cone Oil and Gas Applications

Proven Flow Measurement Solutions for the Oil and Gas Industry - The V-Cone^® flow meter is an advanced technology that takes differential pressure flow measurement to a new level. The V-Cone flow meter has proven its performance in the oil and gas industry in some of the harshest operating conditions and for the widest variety of fluid types. In these applications, the V-Cone flow meter consistently outperforms traditional dP devices and other major flow technologies.

Field Experiences with V-Cone Technology - Philip A. Lawrence - This paper describes the principles and field use of the V-cone D.P. flowmeter used in the role of wellhead metering, injection measurement allocation metering / custody transfer both topside and sub-sea in on-offshore oil and gas production applications.

Crude Pumping Station Flow Measurement

Pipeline Crude Pumping Station Solves Flow Measurement Problem with V-Cone Meter - Nick Voss - A regional light crude pipeline operator in the mountain states of the U.S. was looking for an economical, accurate method to measure crude inventory flow within its pumping stations. The pipeline operator specializes in transporting partially processed crude to other lines or main terminals. Accurate flow measurement is essential to the cost-effective operation of pipelines. While highly precise, and often expensive, flow meters are required to perform custody-transfer measurements for payment purposes, there are also intermediate process measurement points within pumping stations, for example, that can be served with less expensive technology.

Crude Oil Production Gas Lift

V-Cone Flow Meter Improves Efficiency and Reduces Costs in Gas Lift Applications (Ideal for Low Pressure Oil / Gas Production Sites) - Nick Voss - Process engineers responsible for crude oil production from wells that employ gas lift systems to increase oil production will find that the rugged, highly accurate V-Cone^® Flow Meter from McCrometer features a wide turndown, small footprint and virtually no maintenance, which reduces total installed costs and operating life cycle costs while improving crude oil production efficiency.

Compressor Surge Control Flow Measurement

V-Cone Flowmeter Solves Compressor Control Problems for the Oil & Gas Industry - To prevent a compressor from surging, a ?ow metering device is placed in the compressor piping to monitor the gas ?ow through the compressor. One of the advantages of using McCrometer’s V-Cone^® Flowmeter is due to its unique design. The patented ?owmeter offers an advanced, differential pressure ?ow technology that acts as its own flow conditioner, fully conditioning and mixing the flow prior to measurement.

Custody Transfer Measurement

Custody Transfer Measurement with the V-Cone Flowmeter - Stephen A. Ifft - This paper discusses the approval of the McCrometer V-Cone flowmeter for custody transfer measurement in Canada.

Custody Transfer Flow Measurement with New Technologies - Stephen A. Ifft - New technologies can often bring advances to the operational processes within many industries. These advances can improve the overall production of a facility with better performance, better reliability, and lower costs. Obstacles exist, however, to the introduction and use of these new technologies. The natural gas industry has such obstacles, particularly with the use of new technology for custody transfer flow measurement. Paper standards from international organizations like the International Organization for Standardization, the American Petroleum Institute and the American Gas Association are examples of these obstacles. While these paper standards serve to protect and guide companies in their use of technology, they prevent the introduction of new and often better technology. A reform is underway in the natural gas industry to allow companies to take advantage of newer technologies that were not accessible before. This will hopefully redefine the phrase “approved for custody transfer measurement.” This phrase has been used incorrectly around the world for decades since none of the organizations listed above actually approve meters for custody transfer measurement. If companies are to reap the benefits of newer and better technology, the industry must continue to reform the existing paper standards that exclude every technology but those that are decades old. As new technologies become available, the industry must have procedures ready for evaluating their possible benefits and detriments. Without these procedures, the advances of the modern world will be overlooked. McCrometer Inc. is a manufacturer of flow measurement devices, including the V-Cone differential pressure flowmeter. McCrometer has first-hand knowledge of the obstacles to bringing a new technology to the natural gas market. This paper explains how one new technology has been used successfully in custody transfer flow measurement applications even without “custody transfer approval”.

Enhanced Oil Recovery

Steam Custody Transfer - The oil field operator injects the steam into the ground to heat the heavy (API gravity 6-15 typically) oil. Once heated the oil can be retrieved via traditional pumping methods. The operator pays for the steam by the BTU at the negotiated point of custody transfer.

FPSO Vessel Flow Measurement

Liquid & Gas Flow Measurement for Oil/Gas FPSO Vessels - Marcus Davis - The ability to eliminate long required straight pipe runs for flow meter technologies while meeting necessary technical specifications reduces installation real estate and allows for flexible layouts while cutting overall pipe weight, material and installation costs. McCrometer’s uniquely designed differential pressure V-Cone^® Flow Meter is now frequently utilised by the industry’s major FPSO Vessel builders and operators.

FPSO Flow Meter Fits Just Right - Space-Saving Flow Meter Gets Engineers Out Of Tight Spots In Offshore Applications: Ideal for Measuring Wet Gas, Condensate and Dirty or Abrasive Flows.

Gas Injection System Flow Measurement

Water Alternating Gas Injection System Requires Compact Flow Measurement Solution - Nick Voss - The oil/gas process engineers initially considered using a differential pressure (dP) technology orifice plate flow meter, but there was a problem. The installation area for the meter was already crowded with equipment, and the orifice plate flow meter required a long pipe straight-run to ensure accurate measurement. There simply wasn’t enough room to accommodate the orifice plate flow meter. The flow specialist at McCrometer recommended installing a VCone^® Flow Meter with its built-in flow condition technology, which reduces the typical pipe straight-runs required both upstream and downstream from the meter for accurate measurement.

LNG Flow Measurement

Self-Conditioning Flow Meter Solves Measurement Challenges for LNG Processing and Distribution - Nick Voss - The Challenge - Converting natural gas to its liquefied LNG state reduces its volume by 600 percent. This reduction in volume facilitates transport by ship, export and distribution. The natural gas is first cooled to -260?F (-162.2?C), which condenses the fluid into the liquefied state. Flow is then measured again several times during transportation, storage, regasification and distribution through pipelines to the end users. The liquefaction process takes place in hazardous, space-constrained facilities. LNG processing, transportation, storage and distribution require a flow meter that is rugged, dependable, simple to install and suitable for use in potentially explosive environments. Flow meter technologies with moving parts or those requiring complex installation, or frequent recalibration and other maintenance represent potential safety issues, accuracy problems and added operating costs that burden production and refinery operations.

Miscellaneous Oil and Gas Flow

Oil & Gas Industry: Hot Air Application in an Oil Refinery - Shell Refinery had the need to measure hot air in 2 locations with a low pressure drop. The problem was that the hot air was blown through square ducts with a dimension of 1400 x 502 mm and 1200 x 451 mm. There were was a split off from a larger duct in two legs and where the flowmeter was to be placed there was literally no straight pipe runs. The total straight section available was 1800 mm; for all ducts the same.

Subsea Flow Measurement

Subsea Flow Measurement - Nicholas Voss - With depths as deep as 10,000ft (3,000m) - Flow measurement in subsea oil and gas production systems represents a challenge. In addition to normal considerations for selecting a flow meter such as accuracy and repeatability, subsea module manufacturers face demanding space constraints and must plan for transportation and implementation on the ocean floor. There is only so much space available within subsea modules. The ability to eliminate the required straight pipe runs for flow meters while meeting or exceeding the necessary technical specifications reduces/shrinks installation real estate and allows for flexible layouts while cutting overall pipe weight, material, and installation costs.

Test Separator Gas Flow Measurement

V-Cone Meter - Gas Measurement for the Real World - Maron J. Dahlstrøm - This paper describes the performance of the V-Cone meters used for Embla test separator gas measurement. The advantages and disadvantages for use of this technology on the partially processed gas at an offshore platform is discussed. It has been shown in tests that the V-Cone meter functions well with wet gas conditions. The long term repeatability of the meter is documented. Also the low influence from upstream disturbance is confirmed. It is shown that calibration curve fit to ISO5167-1 based equations, can give dry gas accuracy inside the fiscal requirements for gas at Reynolds number above 1 million. The experience from Embla shows that the V-Cone meter tolerates rough operation: The V-Cone meter dimensions certified at six month intervals identifies no changes to the meter. Also the flow calibrations carried out at the same time intervals presents no significant changes, the results match close to the accuracy of the equipment used in the flow calibrations.

Test Separator Using Offshore Metering - Philip A. Lawrence - This paper highlights the advantages of using V-Cone Meters on Test Separators.

V-Cone Flowmeter Solves Test Separator Problems for the Oil & Gas Industry - In the gas metering section of a test separator, liquid “carry over” is a well-known problem, especially when new wells are put on stream. Occasionally, when the well stream ?ow exceeds the capacity of the test separator, water, oil, agitated solids and other debris are carried over into the metering devices. As a result of this harsh treatment, ori?ce and conventional turbine meters have sometimes been found buckled or damaged-even when relocated somewhere downstream of the process. A V-Cone ?owmeter provides outstanding performance without the long lengths of upstream or downstream pipe runs usually required by other types of ?owmeters. This requirement for reduced straight pipe run results in signi?cant space savings, especially on offshore platforms.

Wellhead Metering

Wellhead Metering Using V-Cone^® Technology - This paper describes the McCrometer V-cone D.P. meter as currently used by the Oil and Gas industry in the role of wellhead injection and allocation metering in on-shore, topside and sub-sea production applications.

Wet Gas Metering

V-Cone^®, An Alternative to Orifice Meter in Wet Gas Applications - Stephen A. Ifft - This paper will discuss the use of the V-Cone differential pressure flowmeter to measure the flow of wet gas. Wet gas flow measurement is gaining considerable attention due to its importance in the oil and gas industry. Separator and well-head flow lines are two examples where wet gas can occur in a production system. Orifice plates have long been used for these applications. While orifice plates offer good measurement in clean gas applications, an alternative is needed that will provide better performance in the harsh environment of wet gas flow.

Wet Gas Metering with V-Cone - Dr. Richard Steven and Dr. RJW Peters - With the industrial requirement to meter wet gas flows increasing worldwide McCrometer has tested the performance of the single phase V-Cone meter (a Differential Pressure (DP) type meter) in wet gas flows in both the NEL and CEESI wet gas loops. These tests have shown how the V-Cone meter responds to different amounts of liquid entrained in a gas flow and have enabled correction factors to be developed.

Research Developments in Wet Gas Metering with V-Cone Meters - Philip A. Lawrence, and Richard Steven - This paper briefly summarises the V-Cone meter technology and then discusses the results of repeat wet gas flow tests at NEL in May 2003 (at nominally 15 and 60 Bar) for the 0.75 beta ratio V-Cone meter, to show the repeatability of the meter with wet gas flows and the reliability of the previously published wet gas flow correlation within the NEL parameter range.

Wet Gas Testing with V-Cone - This paper details a series of tests conducted on Wet Gas applications.

 

V-Cone Chemical Applications

Chemical Industry: Saturated Steam - Steam measurement is always a challenge, as the traditional Pitot Tubes and Orifices are of low accuracy, low rangeability, plus the ID of the process tube is usually unknown and the straight pipe requirements are difficult to meet. Steam is almost always a non-homogenous fluid, with cavitation, shocks and other irregularities. The flow conditioning and mixing effect of a V-Cone eliminates the usual measurement problems.

Chemical & Petrochemical Processing: Crude Oil Refining to Saleable Products Production of Petrochemicals - V-Cone flowmeters can be used in refineries and petrochemical plants to save physical space, reduce upstream and downstream pipe runs, and increase accuracies when used in areas where traditional forms of flow measurement were not possible.

Chemical Industry: Manufacture of Chemical Products Components from Air - Continuous/batch processes needed a method to measure flows of chemical components and products from skid mounted units installed at various types of industries worldwide. They were required to reduce space and weight, and increase accuracy.

Chemical Industry/Power Generation: Steam, Condensate and Feedwater Measurement - Condensate is a very difficult fluid to measure because it is never just water. Condensate contains steam bubbles which cause shocks and cavitation which typically destroy other types of flowmeters.

 

V-Cone Defence Applications

U.S. Navy Adopts V-Cone Flow Meter for EMALS Duty on Next-Generation Carriers - Nick Voss - Defense contractor General Atomics (GA) is developing the next generation of aircraft catapult launch systems for United States Navy’s new Gerald R. Ford-class aircraft carriers. The Electromagnetic Aircraft Launch System, or EMALS, utilizes a breakthrough linear motor technology instead of conventional steam pistons.The Challenge - Accelerating a fully loaded strike aircraft to its launch end speed using linear motor technology generates heat in both the power system and the motors, which must then be dissipated by a cooling system. The cooling water in the system needs to be actively monitored and controlled to ensure proper cooling of these systems, which requires an accurate and dependable flow meter. GA reviewed the available flow meter technologies on the market in terms of their measurement accuracy, dependability and installation space requirements.

 

V-Cone Metals and Mining Applications

Metals & Mining Industry: Steel Mill Exhaust Gas Measurement - Mefos “The Foundation for Metallurgical Research” is a research company for the Swedish steel industry which is one of the dominant industries in Sweden. In one of their projects assigned to them it was important for to measure flow for efficiency and environmental reasons. The flow meter was required to operate on hot exhaust gas from the AOD furnace with some contaminants at a temperature ranging from + 300 to + 800 ° C in a pipe line of 1000 mm.

 

V-Cone Nuclear Applications

V-Cone Flow Meters Solves Nuclear Lab Underwater Measurement Problem - Willem Smith - NRG Lab faced a problem when the old vortex flow meter was wearing out and they found that model was no longer in production. The Lab plant managers needed a new flow metering solution with specific capabilities, including, electronics with a long life, low maintenance costs and a technology that performs well underwater and can withstand the effects of nuclear radiation.

 

V-Cone Paper Industry Applications

The Economic and Technical Justification for changing from a Nozzle Flow Meter to a V-Cone Flow Meter on the outlet of a Steam Recovery Boiler in a Paper Plant - A very large integrated Paper Plant desired to improve productivity of paper production utilizing the existing equipment. The technical paper describes the reasons why the Paper Plant considered the replacement of a flow meter on the steam outlet of a Recovery Boiler.

 

V-Cone Power Industry Applications

Pacific Klamath Energy Utilizes V-Cone Flow Meter to Solve Problem in Co-Generation Plant - Bruce Willard - Providing accurate and reliable steam flow measurement to the steam host is a very important aspect in generating revenue for the co-generation facility. The existing annubar flow measurement system could not measure the low end of the steam flow requirements without major changes to the piping and purchasing a new annubar. To eliminate this problem, Klamath Pacific Energy contacted McCrometer and asked them about the V-Cone Flow Meter, which relies on differential pressure (DP) technology. It was then decided to replace the annubar system based on the expected accuracy of the V-Cone Flow Meter and its space-saving installation features that required only minimal changes to the piping layout.

Advanced Flow Meter Technology To The Rescue: V-Cone Reduces Installation Costs For Aging Power Plant - Markku Metsarinne - Metso Power Oy, located in Finland, began a new project in 2002 to design and build a new flue gas treatment operation within the new power plant for client, Kotkan Energia Oy, located in Kotka, Finland. Metso Power had to design the flue gas treatment plant to fit into the section of the new plant, which was pre-determined by Kotkan Energia. The fact that the location of the flue gas treatment plant was selected in advance, added to the complexity of the project. It was necessary to fit the equipment into a limited space.

Use of V-Cone Fuel Flow Meter to Measure Coke Oven Gas & Natural Gas Flow in a Combined Heat and Power Plant - Ann McIver and Dr. R.J.W. Peters - This paper describes key aspects of the Citizens Thermal Energy district energy system in Indianapolis. It will present the requirements imposed, through the continuous emissions monitoring rules established by the Environmental Protection Agency (EPA), as delineated in 40 CFR 75. The reason for the choice of the V-Cone, which is not a fuel flow metering technology specifically addressed in the regulations, will be presented and the tests required by the EPA to enable the V-Cone to be accepted. The results of the flow tests in an independent laboratory before and after a period in service will be given.

Geothermal Steam Flow Measurement - This application involved measuring steam before it enters the turbine. Two measurements were required for each turbine, one on the high pressure side and one on the low pressure side.

Digester Gas Flow to Co-Gen Plant - This application was to measure the digester gas consumption of the power generation boilers. Measurement Challenge/Difficulty: Digester gas is usually corrosive and can be wet. It is difficult and impractical to measure with any meter other than the V-Cone. The short pipe run required for the V-Cone makes it extremely practical to install.

Exhaust Gas Flow Measurement - This application involves the Flow measurement of heavily contaminated gases in an energy experimental station.

Power Generation Industry: Exhaust Gas Flow Measurement - This application was measuring non-condensable gas into a Lo Cat scrubber before discharge to atmosphere. This is a compliance measurement. The considerable amount of H2S makes it a safety issue as well.

 

V-Cone Sugar Industry Applications

Accurate Flow Meter Helps Sugar Mill Measure Steam Consumption of Distillery Plant Producing Bio-Ethanol - Nick Voss - The process engineers at the sugar mill in Latin America needed a new flow meter for steam custody transfer purposes. They were required to measure the steam transferred via a 16-inch line from the sugar mill to its sister company bio-ethanol plant for cost accounting purposes. The mill’s process engineers were looking for a reliable and accurate steam flow measurement solution without routine maintenance requirements for operation in a high-heat, high-humidity dirty plant environment. Choosing a new flow meter can be a complex and time-consuming process. There are numerous flow meter measurement technologies, and not all of them are equally suitable for measuring all fluids: steam, gas or liquids.

 

V-Cone Transport Industry Applications

Honda Cars Philippines Ensures Quality Manufacturing with Advanced Gas Measurement Solution - Nick Voss - Providing accurate and reliable liquefied petroleum gas (LPG) consumption data for Honda’s oven burners is necessary to ensure accurate production cost and billing as well. Unfortunately, the planned thermal flow metering system could not measure the low end of the LPG flow scale without major changes to the piping system and purchasing a new insert probe. With the plant’s piping space constraints a McCrometer V-Cone Flow Meter was recommended, which due to its compact configuration, required minimal changes to the existing piping system.

 

V-Cone Water and Wastewater Industry Applications

Flowmeter Smoothes City's Troubled Waters - An application note for the water industry.

Water & Wastewater Industry: Digester Gas Measurement - Measure Digester Gas at a water treatment plant.

Natural Gas Measurement - Measure Natural Gas Flow to a Standby Generator.

Reservoir Raw Water Measurement - Accurately measure raw water flow out of a reservoir outlet structure. A space length of 42” was available in a 42” line to insert a flow meter. Connection lines feeding into the main header were located 1/2, 3 and 5 pipeline diameters upstream from the meter and were inducing considerable turbulence into the flow approaching the meter.

Water Treatment Plant - Measure the effluent flow in a 4-inch line from a Water Treatment Plant high service pump with extremely limited straight piping available.

Water Well Measurement Effluent Measurement - Measure Flow from Water Wells in a Desert Community - Well water is very turbulent and is filled with sand and debris. The turbulence is significant due to the typically short pipe runs. The sand and debris cause damage to the flow elements and create a need for lots of costly field maintenance. The customer was experiencing significant maintenance problems with the mechanical meters on the wells. These problems were caused by a combination of turbulence and short pipe runs, sand and debris.

 

Miscellaneous V-Cone Applications

Aerospace Industry: High-Pressure Helium Measurement - High pressure Helium custody transfer point - Remote measurement requires high turndowns. Traditional orifice measurement requires three meter runs to cover the intended range of operation.

Analytical Instruments Industry: Air Flow Measurement - Precisely Monitor Plant Air Flow.

Food & Beverage Industry: Grain Alcohol Measurement - Alcohol (grain) is difficult to measure due to its solvent characteristics (It plays havoc with turbine bearings). Alcohol also has a relatively low vapor pressure making traditional differential pressure measurement over the specified range difficult. This was an existing plant with minimal straight pipe available for proper flow measurement.

Food & Beverage Industry: Steam & Specialty Gases Measurement in Breweries - Steam being used in breweries had always been overlooked as a source or “reusable” or “capturable” energy. Averaging Pitot tubes typically used were not only inaccurate, but still required costly pipe runs along with very regular and expensive maintenance and replacement. In generating steam, thermal mass meters had been used but presented some of the same problems. Brewers looking to improve their efficiencies needed a new method to obtain and measure a thermal mass balance around the plant for steam generation and usage.

Gas/Steam Turbine Manufacturing: Gas Flow Measurement - Gas in Serpentine Piping System - A solution to a measure gas during the commissioning of gas turbines where almost no strait pipe runs were available.

HVAC/Institutional Facility: Chilled Water & Steam Measurement - Measurement of Chilled Water & Steam - In most instances the use of V-Cones associated with chillers for chilled water in large institutional users is a matter of space, accuracy, and turndown. The V-Cone needs very little upstream and downstream piping requirements, allowing it to be used in spaces where other meters cannot be used, or to replace existing flowmeters that never proved accurate because of space limitations. In many large universities and other facilities, such as hospitals and airports, across the U.S., the reason for initial interest and subsequent purchases of V-Cones to measure Chilled Water was to fit within the confines of the existing and new buildings that were being used to house the chillers. Additionally, the second most important reason was the delivered accuracy. In the past, most usage had been ignored, but with the rising costs associated with cooling, each individual building must be accountable for individual use.

V-Cone Coke Oven Gas Case Study - Flow monitoring of coke-oven gas is difficult due to solids build up on interior surfaces. Heavy accumulation often renders venturis, orifice and segmental orifice plates incapable of accurate flow measurement. In addition, the pressure-sensing ports of venturi or orifice plate flowmeters become plugged, making the readings of these primary differential pressure devices difficult, if not impossible. A 150mm diameter V-cone Differential Pressure Flowmeter with a full-scale range of 110mm water column was selected for evaluation by Svenskt Stal Oxelosund. Mr. Lekberg, Instrument Engineer for SSAB, was responsible for the installation and evaluation of the V-cone. After one month of continuous flow, Mr. Lekberg reported, “We had the meter installed for one month and then inspected it together with ANSKO (the local McCrometer representative), and to our surprise, the meter was clean and had no obvious wear on the cone. The performance of the meter was also excellent and to our full satisfaction”.

Flow Meter Research for APS Beam-Lines - Jeff T. Collins & Brian Batzka - Many critical APS beam-line components, such as the photon shutters and fixed masks, utilise porous media for heat transfer enhancement and consequently rely on steady operation at design flow rates to ensure that the proper levels of heat transfer enhancement are maintained. it is therefore necessary to ensure that the flow metering system, which the component is interlocked on, has a high degree of reliability.

 

V-Cone^® Suggested Specifications

V-Cone Primary Element Specification

V-Cone Primary Element Specification for Air Applications

V-Cone Primary Element Specification for Gas Applications

V-Cone Primary Element Specification for Steam Applications

V-Cone Primary Element Specification for Water Applications

Differential Pressure Flowmeter Specification (non-proprietary)

Specification of Wet Gas Measurement Equipment for Fiscal Allocation - Dr Max Rowe, Rod Bisset, Anthony Alexander - Item 2 on the index of papers - When a new field is to be accepted by a host, it is necessary to define a functional specification for the measurement equipment. This is usually documented as part of the allocation agreement. The question that needs to be addressed is: “What is an acceptable measurement specification?”. The ultimate answer will be one which meets standards set by relevant Government authorities and is acceptable to all parties who approve the allocation agreement. One approach, often used, is to apply standard guidelines derived from industry best practice, e.g. 1% uncertainty for a gas fiscal flow measurement. This approach has the advantage of being simple to apply, but may involve some measurements being made with an unnecessary degree of accuracy. Another approach is to undertake modelling of uncertainty in the measurement system to establish the criticality of each measurement. Scheers and Wolff point out the need to consider the whole measurement system through to allocated revenue and propose that the optimum uncertainty of each measurement should be established by evaluating the trade-off between measurement costs and the losses and risks of uncertainty in the measurement. In this paper an extension of these approaches is applied in which uncertainty modelling was applied to the propagation of uncertainty through the whole measurement and allocation system and was used to establish the impact on each company or field’s revenue stream - The Norwegian Society for Oil and Gas Measurement.

Further published articles and independent reports are available on the McCrometer website.

Ultrasonic Flow Metering

Go to Specific Subject: Ultrasonic Flow Meters | Clamp On Ultrasonic Flow Meters | Ultrasonic Flowmeters Recalibration Intervals | Ultrasonic Flowmeters for Custody Transfer | Ultrasonic Flowmeter Diagnostics | Leak Detection and Prevention using UltrasonicFlowmeters | Ultrasonic Flare Flow Meters | Other Ultrasonic Flowmeter Links.

An Ultrasonic Flowmeter is a device which measures volumetric flow and is non intrusive. It measures the average velocity along the path of an emitted beam of ultrasound. This it does by averaging the difference in measured transit time between pulses of ultrasound into and against the direction of the flow. There are two physical designs one which is based on a spool installed between flanges in a process line, the second is "clamp on ultrasonic meters" where the ultrasonic transmitter and sensors are installed on the exterior of the pipe. Both Ultrasonic Flow Meters designs are relatively maintenance free, however the clamp on technology has advantages in that they can be retrofitted to existing lines without costly piping modifications.

The following papers are from Zedflo Australia. 

 

Ultrasonic Flow Meters

WideBeam™, Cavity-Free™ Ultrasonic Flowmeters Achieve Process and Natural Gas Custody Transfer Accuracy and Performance - WideBeam™, Cavity-Free™ ultrasonic flowmeters have been proven to meet the recently released API standards for liquid custody transfer. This same Cavity- Free technology is now available for gas applications and will meet AGA-9 standards for custody transfer. The two major types of ultrasonic flowmeters available for gas custody transfer measurement are conventional ‘insert’ type meters and Controlotron’s unique WideBeam™, ‘Cavity-Free’ design.

Lightning Protection of Ultrasonic Flow Meters - This document outlines important recommendations for all installations requiring protection from lightning damage-Eli Spalten Senior Applications Engineer, Controlotron.

How Can the Guesswork be Taken Out of Flow Measurement? - Clamp-on Ultrasonic Flow Technology offers several advantages over other flow measurement methods, number one being the utilization of external sensors. They are quickly and easily mounted on the outside of the pipe, making them the perfect choice for retrofit applications and applications where corrosive, toxic or high pressure liquids and gases rule out the option of cutting the pipe. With the use of the WideBeam technology, clamp-on flowmeters have proven their superiority in both the field and the lab. They offer several benefits:

(a) Measurement of practically any liquid and gas.

(b) Performance unaffected by viscosity, flow rate, pipe size, solids and aeration content.

(c) High accuracy and repeatability through automatic temperature compensation and zero drift correction.

(d) Installation flexibility on pipe sizes up to DN 9140 (360”).

Reflexor™ Doppler Technology - The Technology - from Controlotron - Doppler flowmeters inject sound into the liquid by a transmit transducer at a known angle and reflects off a moving particle or bubble. The frequency is shifted proportional to velocity of the particle or bubble. The reflected signal is captured by the receive transducer and demodulated by the electronics.

Flowmeters for Water & Wastewater Applications - Unfortunately, there are many preconceptions and misconceptions about the use of ultrasonic flowmeters within a wastewater treatment plant. This Industry Note will provide a clear insight into the proper selection and use of the two types of ultrasonic flowmeters; transit-time and Doppler - From Controlotron.

The Effect of Temperature Gradients on Ultrasonic Flow Measurement - Claus Nygaard Rasmussen - It has been established that ultrasonic flow meters are influenced by thermal conditions, this technical paper addresses this - from Siemens Flow Instruments.

The Case for Widebeam Ultrasonic Flow Measurement - Matt Bird - The most commonly used method of flow measurement is Transit Time Ultrasonic Flow measurement. Two types available, externally mounted Diametral and insertion type Chordal, have different advantages and disadvantages. This article examines the pros and cons of the Diametral and Chordal Measurement systems, and offers a third solution - from Siemens Flow Instruments.

Videos

Theory of Operation: Ultrasonic Doppler Flow Meter - This video details how a Doppler Flow Meter works - from Instruments Direct.

Theory of Operation: Ultrasonic Transit Time Flow Meter - This video details how a Transit Time flow Meter Works - from Instruments Direct.

 

Clamp On Ultrasonic Flow Meters

The following papers are from Zedflo Australia.

Cost-EfficientOn-SiteCheck Metering Made Easy - Brian Roughan - When a flowmeter in operation has to be verified, it usually must be uninstalled and transported to a facility for the necessary verification or check-metering. With an on-site verification device, though, this task is made much faster, easier and at a fraction of the cost. When using the right meter, the result can even be as accurate as any off-site verification.

Comparative Advantages of Clamp-on Transit-time Ultrasonic Flowmeters over Conventional Intrusive Flowmeters - Recent developments have enabled today’s clamp-on transit-time ultrasonic flowmeter technology to reach a level of applicability, functionality, economy and performance which establishes this instrument as the prime candidate to replace most, if not all, the conventional intrusive flowmeters in most of their niche applications. This paper describes the advances that have taken place and how users of conventional intrusive flowmeters may evaluate for themselves the advantages available to them by use of the clamp-on transit-time ultrasonic flowmeter in place of any of their prior intrusive flowmeter types - Joseph Baumoel, President, Controlotron.

The Ultimate Flowmeter, High Precision - Low Cost - Joe Baumoel, President,Controlotron Corporation - High precision and low cost are usually incompatible concepts. Providing precision is usually the thing that leads to high cost in a flowmeter. However, start with a high cost-high precision clamp-on ultrasonic flowmeter and take out the costly functions and features that are not needed for most applications and you have a non-intrusive high precision-low cost flow meter!

Clamp on Ultrasonic Flowmeters - Your Questions Answered - Thanks to Zedflo Australia.

Suggested Permanent Multifunction Clamp-On Dual Channel/PathTransit-Time Ultrasonic Flowmeter Specification - A useful typical specification from Controlotron.

Clamp-On Ultrasonic Meter Applications - William E. Frasier - I have applied the Siemens clamp-on meter in many configurations in the field and will describe purposes and findings on the way to precise meter certainty. The clamp-on system provides an effective new tool for insight into the flowing regime within a pipe - from the American School of Gas Measurement Technology.

The following articles are from Siemens:

• Clamp-on Ultrasonic Flowmeters - How they Measure Up - Clamp-on ultrasonic flowmeters - portable or permanent - are valuable tools for helping district energy providers, building owners and managers and others measure and manage their system performance in a number of ways. These units provide the baseline and load profile information needed to effectively optimize system efficiency and reduce energy consumption - and costs.
• How Can Clamp-On Ultrasonic Flow Meters Identify what Product is Flowing from Outside the Pipe? - John Accardo - Many petroleum pipelines flow multiple products such as diesel fuel, gasoline and jet fuel. Between each of these products lies an interface where the flow stream transitions from one product to another. Pipeline operating companies depend on instrumentation to indicate what fluid is in the pipe and when an interface occurs in order to manage the pipeline’s operations. For example, flow arriving at a terminal is stored by product type in specific storage tanks. By knowing when an interface arrives, a valve can be switched to route the new fluid to its respective tank. Certain additives (e.g., Drag Reduction Agent “DRA”) may only be injected for specific fluids. So, you can see that knowing what fluid is presently in the pipe is critical to proper operation of the pipeline. Using a non-intrusive instrument for this purpose adds another level of benefits, including low cost installation, no loss of pressure, no interruption of the DRA, and the ability to allow pig passage through the measurement point.
• Are there Differences between Clamp-On Ultrasonic Meters Used for Onshore Purposes and Those Used for Offshore Projects? - Leslie Bottoms - While the basic technology used is the same for onshore and offshore projects, there are some differences between clamp-on ultrasonic meters in these applications. Offshore environmental conditions require a higher level of protection from the elements. The main concern with instrumentation when used offshore is the constant exposure to salt air and sea spray. This combination can easily corrode housings and cables which are exposed to the elements all day, everyday. A typical onshore application may involve temperature swings from 20 to 110 degrees F, but in most cases, the instruments used in these locations are generally protected from the sun and rain by sheds or some form of additional shelter. However, when located offshore, protection is limited to the instrument enclosure, due to size and weight limitations. In addition, temperatures are often exceeded at both ends of the scale.
• Knowing What’s Inside from the OUTSIDE - Clamp-On Ultrasonic Flowmeters Leveraged for Sophisticated Interface Measurements - John Accardo - Many petroleum pipeline companies transport multiple hydrocarbon liquids (e.g., diesel fuel, gasoline, and jet fuel) through a single common pipe. Between each liquid sits an interface where the flowstream transitions from one product to another. Pipeline operating companies depend on instrumentation to indicate which fluid is flowing through their pipe at any given time and when an interface occurs—information that is vital for proper management of pipeline operations.
• Reliable Flow Monitoring of Primary and Secondary Sewage Treatment - Achieve Better Performance in Even the Most Challenging Applications - Monitoring the flow of liquid is a vital component of any wastewater application. Flow data is used to make important decisions that ensure various processes operate at maximum efficiency, which is why plant managers must be able to trust that the flowmeters installed throughout a facility are providing consistently accurate information. However, certain operating conditions may make it extremely difficult to achieve the necessary level of precision in flow measurement.

Applications in Liquid Measurement Using Clamp-On Ultrasonic Technology - Sid Douglass - Ultrasonic meters are typically used to measure flow and clamp-on ultrasonic meters are no exception. One will find these meters installed in most aspects of the petroleum industry. This white paper details some of these applications - from CRT services.

Ultrasonic Clamp On Flow Meter Application Reports - A series of reports on Clamp On Ultrasonic Flow Meter applications across a wide range of industries - from TOKYO KEIKI INC .

Videos

Siemens SITRANS FUS1010 Clamp-On Flowmeter Installation Guideline - Learn how to get started with the FUS1010 clamp-on ultrasonic flowmeter, including identifying and selecting sensors, choosing a mounting location and programming the meter. SITRANS FUS1010 is the most versatile clamp-on meter on the market today, with maintenance-free external sensors that eliminate the need to cut the pipe or stop the flow.

Validating SITRANS F US Clamp-on Flowmeter Performance - Learn how to use several simple diagnostic tools on any SITRANS F US clamp-on ultrasonic flowmeter to ensure that the flowmeter is operating properly and the readings are as accurate as possible. The SITRANS F US flowmeter line from Siemens provides precise measurement of liquids and gases and features maintenance-free external sensors that eliminate the need to cut the pipe or stop the flow.

 

Other Useful Clamp on Ultrasonic Flow Meter Links

Fundamental Principles of Clamp on Ultrasonic Flow Meters - Overview of selection, Installation, Operation and maintenance of clamp-on meters - William E. Frasier Jr - This paper is aimed at ultrasonic natural gas meters that use transit time across the gas pipe as the measurement variable. Custody transfer meters using sensors wetted with gas are the more familiar meter format. Clamp-on meters are quite similar - from the American School of Gas Measurement Technology.

Clamp-on Ultrasonic Flowmeter Improvements - Ultrasonic flow measurement technology offers a low-cost method to measure flow. The advantage of clamp-on ultrasonic flow sensors is installation without stopping a process to put a hole in a pipe to insert a conventional sensor. From InTech and the ISA.

A Clamp-On Ultrasonic Flowmeter for Gases - Michael J. Scelzo - Despite the industrial success of clamp-on ultrasonic flowmeters for liquid measurement, it has long been accepted as if it were a fundamental limit imposed by nature, that this technology could not be used to measure the flow of gases in metal pipes. The incorrect conclusion, that clamp-on gas flow metering is impossible, developed because the acoustic impedance of gases, even at pressure, is much less than the acoustic impedance of metals - from GE Measurement & Control Systems.

Full Steam Ahead - Clamp-on Flow Measurement no Longer just for Liquids - Daryl Belock - When plant engineers look for a non-intrusive flow measurement solution, clamp-on ultrasonic flowmeters are typically the first technology considered. Users traditionally have considered clamp-on technology only for liquid applications. For years flowmeter manufacturers have been asked,“Do you have a clamp-on solution for steam?” Until recently the answer has been no, but new technology now makes clamp-on steam flow measurement a reality for many common types of steam flows - from GE Measurement & Control Systems.

Water System Standardises on Clamp-On Ultrasonic Flowmeters - Daryl Belock & Phil McDonald - from GE Measurement & Control Systems.

Strength in Numbers - Matching Lamb Wave Sensors to the Resonant Frequency of a Pipe Wall - James Doorhy - Clamp-on ultrasonic flowmeter technology offers several major advantages over other methods of flow measurement when it comes to accounting for what, and how much, is flowing through a pipe. These benefits are derived primarily from one very important feature of clamp-on ultrasonic meters — i.e., their external sensors. Unlike traditional insert sensors, external sensors do not require pipes to be cut or operations to be halted in order to complete the installation process. Instead, the sensors are mounted on the exterior of the pipe and measure flow by transmitting acoustic signals into the pipe wall before entering the fluid - from Siemens.

 

Ultrasonic Flowmeters Recalibration Intervals

The following papers are from the excellent CEESI Flow Measurement Technical Library - A superb resource!.

• Ultrasonic Meter Recalibration Intervals - Thomas Kegel - Covers data, discusses analytical results and presents a mathematical model that relates recalibration shift, meter size, velocity, and recalibration time interval. The results can be applied as a tool to assist in determining an appropriate recalibration interval for an ultrasonic meter. The database supporting this project is a result of twelve years of history in the operation of an ultrasonic gas flow calibration facility. The database includes 95 recalibration events, recalibration time intervals from less than one year to nine years, meter sizes from DN100 to DN500, and gas velocities between 3 and 30 m/s.
• Ultrasonic Meter Repeatability and Reproducibility - T.M. Kegel - The high flow system of the Iowa natural gas facility has been in place for 14 years. A number of programs are maintained to monitor the random effects. Traditional control chart techniques have been adapted for the measurements of pressure, temperature, gas composition and flowrate. Turbine meter calibration standards have traditionally been monitored using ultrasonic check meters. A new low flow system has recently been installed that makes use of ultrasonic meters as both calibration standards and check meters. This paper will describe the development and interpretation of some monitoring techniques for the various flowrate standards.

Flow Calibrating Ultrasonic Gas Meters - Joel Clancy - The primary method for custody transfer measurement has traditionally been orifice metering. While this method has been a good form of measurement, technology has driven the demand for a new, more effective form of fiscal measurement. Ultrasonic flowmeters have gained popularity in recent years and have become the standard for large volume custody transfer applications for a variety of reasons. Most users require flow calibrations to improve meter performance and overall measurement uncertainty. The latest revision of AGA Report No. 9, Measurement of Gas by Multipath Ultrasonic Meters, Second Addition [Ref 1], now requires flow calibration for ultrasonic flow meters when being used for custody transfer applications. What considerations then, should be taken when choosing to flow calibrate an ultrasonic flowmeter? What are the benefits to the user? What should a user expect from a flow calibration? What kind of performance should the customer expect or accept from an ultrasonic meter? What are the diagnostic capabilities inherent in an ultrasonic meter? These areas, as well as others will be explored and considered - from CRT Services.

 

Ultrasonic Flowmeters for Custody Transfer

The following papers are from the American School of Gas Measurement Technology:

• Fundamentals of Multipath Ultrasonic Flow Meters for Gas Measurement - Eric Thompson - This paper outlines the operating principles and application of ultrasonic gas flow metering for custody transfer. Basic principles and underlying equations are discussed, as are considerations for applying ultrasonic flow meter technology to station design, installation, and operation.
• Ultrasonic Meter Flow Calibrations - Considerations and Benefits - Joel Clancy - The primary method for custody transfer measurement has traditionally been orifice metering. While this method has been a good form of measurement, technology has driven the demand for a new, more effective form of fiscal measurement. Ultrasonic flowmeters have gained popularity in recent years and have become the standard for large volume custody transfer applications for a variety of reasons.
• Ultrasonic Gas Flow Meters For Custody Transfer Measurement - Jim Micklos - This paper outlines the operating principals and application of ultrasonic gas flow metering for custody transfer. Basic principles and underlying equations are discussed, as are considerations for applying ultrasonic flow meter technology to station design, installation, and operation.
• Ultrasonic Flow Meter Calibration Considerations And Benefits - Wayne Haner - The increased use of natural gas as the primary source of energy internationally, combined with the increased market price is driving the expansion and modernization of gas transportation infrastructure and is encouraging more accurate measurements of gas flows. To ensure the fair transaction at custody transfer locations, gas pipeline companies are demanding credibility and excellence of meter calibration as a main parameter in ensuring accountability for the gas invoiced.

 

Ultrasonic Flowmeter Diagnostics

Guidance Note - Application of Ultrasonic Flow Meter Diagnostics - Improvements in digital signal processing techniques have enabled large amounts of data to be processed and stored in real time. Manufacturers of modern flow meter devices such as ultrasonic meters (USMs) have taken advantage of these improvements and are now using diagnostic parameters to perform a ‘health-check’ of the meter when in operation. This can help the diagnosis of potential problems with the measured fluid or the measurement system - from NEL.

 

Leak Detection and Prevention using Ultrasonic Flowmeters

Clamp-on Leak Detection Solution for Enhanced Pipeline Management - When a pipeline leak occurs, it causes a sudden decrease in pressure at the leak origin. This pressure transient radiates both upstream and downstream from the line breach and decreases the density of the liquid, which results in a sudden drop in the liquid‘s sonic propagation velocity (Vs). The change in Vs is detected at each site station and time stamped with the arrival of the pressure wave‘s leading edge. As a result, the highly accurate FUS-LDS can locate a leak event within ±150 meters - from Siemens.

Leak Detection & Pipeline Management Solutions - SCADA based leak detection systems depend on data from existing Turbine or PD Flowmeters, and pressure and temperature instruments originally installed by others. These instruments were not originally specified to provide the extraordinarily high accuracy and calibration stability needed for leak detection. Therefore, system performance cannot be assured by the SCADA system supplier. No single party can be held responsible for SCADA based leak detection system performance. All elements of the LD system are provided by Controlotron to assure the specified leak detection accuracy. Controlotron takes responsibility for system installation, start-up, optimization and maintenance. In addition, the LD system’s compensated volume balance principle provides continuous leak detection, not the “one shot” leak detection provided by pressure based SCADA systems.

Leak Detection and Prevention - Joseph Baumoel, Controlotron, USA, Provides an overview of the ongoing problem of pipeline spills and evaluates the technologies available for the identification and control of pipeline leaks.

Technical Review of Leak Detection Technologies - Volume I - Crude Oil Transmission Pipelines - Analysis of recent data from the U.S. Department of Transportation Office of Pipeline Safety (DOT-OPS) indicates that, despite stricter regulations and enforcement, the rate at which pipeline accidents occurs has not significantly changed over the last two decades (Hovey and Farmer, 1999). The statistics suggest that short pipelines will have at least one reportable accident during a 20-year lifetime and longer pipelines (800 or more miles of line pipe) can expect a reportable incident every year. Research indicates that the best opportunities to mitigate pipeline accidents and subsequent leaks are through prevention measures such as aggressive controller training and strict enforcement of safety and maintenance programs (Hovey and Farmer, 1999; Borener and Patterson, 1995). The next most productive enhancement comes from implementing better pipeline monitoring and leak detection equipment and practices. Early detection of a leak and, if possible, identification of the location using the best available technology allows time for safe shutdown and rapid dispatch of assessment and cleanup crews. An effective and appropriately implemented leak detection program can easily pay for itself through reduced spill volume and an increase in public confidence - from Alaska Department of Environmental Conservation.

 

Ultrasonic Flare Flow Meters

How can you Measure the Flare Gas in Your Storage Tank? - Lonnie Barker - A way to use an ultrasonic flow clamp-on unit that would help accurately and reliably measure the gas in this challenging application - from Siemens.

How do you Measure Flare Gas Effectively with Clamp-On Ultrasonic Flow Meters? - Martin Dingman - If you flare-off gas rather than use a vapor recovery unit (VRU), or even flare-off the exposed gas after using the VRU, then you may have already experienced your share of challenges - particularly when it comes to measuring the gas you’re flaring. Challenges can arise from a number of external agents. In particular, inaccurate and unreliable measurements of flare gas applications running under low (and extremely low) pressures in steel pipes. Whether you are venting into the atmosphere or into a VRU, the biggest challenge in measuring low pressure flare gas in steel pipes is the conflict in their acoustic impedances that isn’t suitable for clamp-on ultrasonic flow meter measurement. This blog discusses a solution - from Siemens.

How much Do You Flare? - How to Measure Flare Flow Rates Reliably and Accurately - Ultrasonic Flowmeters help compliance with Environmental Emission Requirements, reduce Leaks and Understand their Process Losses - from GE Measurement & Control Systems.

 

Other Ultrasonic Flowmeter Links

Ultrasonic Flowmeters - By David W. Spitzer - Parts 1 to 4 - The flowmeters to be discussed use ultrasonic energy or correlation as their primary flow measurement technique. Therefore, a common class of "ultrasonic flowmeters" comprised of an open channel flowmeter (such as a flume or weir) that incorporates an ultrasonic level measurement is specifically excluded from this discussion. Ultrasonic flowmeters use sensors to generate ultrasonic waves and direct them into the flowing stream. Information from the remnants of these sound waves is used to determine the flow of fluid passing through the flowmeter. Ultrasonic flowmeters have no moving parts.

Ultrasonic Flowmeters Move Into the Mainstream - Walt Boyes, Editor in Chief -Thanks to ControlGlobal.com.

Ultrasonic Flow Measurement - Technology - From www.sensorland.com.

Are Ultrasonic Flowmeters Right for You? - From Automation World.

Ultrasonic Doppler Flowmeters - Flow reference from Omega.

Effluent Flow with Suspended Solids - Facing Rising Treatment Costs, Paper Mill Reconsiders Flowmeter Installation - This article describes some solutions to this issue - David W. Spitzer, P.E. - Thanks to flowcontrolnetwork.com.

University Chilled Water Plant Plays it Cool with Ultrasonic Flowmeters - An application article - From InTech and the ISA.

Total Life Cycle Investment: Changing how we think about Well Head Gas Flow Meters - Tim Hayes - Operations Engineer, Spring Gully - In a time when large capital ventures are realising the need to consider total life cycle operational costs, reviewing lower maintenance flow meter technology may see a decrease in the expected operational expenditure on large Coal Seam Gas (CSG) projects - thanks to the Origin Energy Talent Search Team.

The following excellent Ultrasonic Flowmeter Papers are from Cameron-Caldon:

• General Principles of LEFM Time-of-Flight Ultrasonic Flow Measurements - Herb Estrada - A time-of-flight ultrasonic flow measurement system projects acoustic energy along one or more diagonal paths through the pipe in which flow is to be measured, this paper explains these principles.
• Identifying and Bounding the Uncertainties in LEFM Flow Measurements - Herb Estrada - It is appropriate to ask how the errors of individual elements, biases and time varying random errors, should be combined. In the treatment of uncertainties in LEFM flow measurements, it has been Caldon’s practice to follow the guidance of ASMEstandard for heat balance testing, with respect to estimating and combining potential errors from various sources in the measurement system.
• Theory of Ultrasonic Flow Measurement, Gases & Liquids - Herb Estrada - Ultrasonic flow measurement systems (UFMs) are being applied with increasing frequency to hydrocarbon flow measurements. Most of these UFM s are transit time (also called time-of-flight) systems—they measure the transit time of ultrasonic energy pulses traveling with and against the direction of flow. This paper will outline the principles of three kinds of transit time UFMs.
• Installation Effects and Diagnostics Interpretation using Caldon Ultrasonic Flow Meter - H. Estrada/ T. Cousins/D. Augenstein - This is a comprehensive review of Installation and diagnostics.
• Proving Liquid Ultrasonic Flow Meters - Don Augenstein - This paper’s objective is to provide UFM users with relevant information necessary to understand how UFMs operate particularly with respect to measurement variability and its effect upon proving along with investigating potential factors that influence UFM statistics and repeatability.
• Proving of Multi-Path Liquid Ultrasonic Flowmeters - T. Cousins, D. Augenstein - This paper identifies the factors affecting the provability of multi-path chordal ultrasonic meters. It also presents proving data for such meters, for a range of meter sizes, at several independent certified hydraulic laboratories around the world, as well as data from meters at various field installations. These data show that repeatability is predictable and generally is controlled by hydraulic/turbulence statistics. The statistics are zero biased and subject to the flow conditions at the site. The understanding of the proving characteristics gained by this analysis leads to proving procedures whereby a specified calibration accuracy, such as the ±0.027% of the API Standards, can be achieved. The paper describes this process and demonstrates its application using field data.

Proving Liquid Ultrasonic Meters - Christopher B. Laird - Proving is the process that determines the accuracy of a meter. A prover is a device with detector switches that define a precise, known volume. The prover is connected in series with the meter being proved so that as flow passes through the meter, the same flow, and only that flow must pass through the prover. The flow moves the displacer in the prover until it touches the first detector switch, the pulses coming from the meter start being counted by a prover counter. When the displacer touches the second detector switch, the pulses from the meter stop being counted. In this way, the exact number of pulses generated by the meter for an exact amount of flow is determined and the actual volume registration of the meter can be compared to the known volume of the prover. The ratio of the volume of the prover to the volume registered by the meter is called the Meter Factor. The proving process involves taking the average of several tests (comparisons) of the above mentioned ratio and checking the consistency of the tests. For example, if 5 tests or proving runs are made, the ratios must agree within 0.05%. If they do, then statistically, the uncertainty of the average Meter Factor will be within 0.027% and will meet industry requirements - from CRT Services.

The following papers are from the American School of Gas Measurement Technology:

• Principles Of Operation For Ultrasonic Gas Flow Meters - John Lansing - This paper discusses fundamental issues relative to ultrasonic gas flow meters used for measurement of natural gas. A basic review of an ultrasonic meter’s operation is presented to understand the typical operation of today’s Ultrasonic Gas Flow Meter (USM). The USM’s diagnostic data, in conjunction with gas composition, pressure and temperature, will be reviewed to show how this technology provides diagnostic benefits beyond that of other primary measurement devices. The basic requirements for obtaining good meter performance, when installed in the field, will be discussed with test results. Finally, recommendations for installation will be provided, including an example of a good piping design.
• Ultrasonic Meters for Residential and Commercial Applications - Paul Honchar - An ultrasonic meter falls into the classification of inferential meters. Unlike positive displacement meters that capture volume to totalize volume, inferential meters measure flowing gas velocity to totalize volume. Orifice meters use pressure drop to measure velocity to infer volume and turbine meters use the speed of the rotor to measure velocity to infer volume, while ultrasonic meters use sound waves to measure flowing gas velocity to infer volume. Ultrasonic meters have been around for many years in primarily liquid measurement. However, their application in the measurement of natural gas is relatively new, and has become more commercialized over the last decade - from the American School of Gas Measurement Technology.
• Continuous Monitoring of Ultrasonic Meters - Randy Miller - Utilizing electronic flow computers and SCADA systems to collect and analyze ultrasonic meter data can provide many benefits for a Natural Gas Pipeline Company. The Natural Gas Pipeline industry has seen tremendous changes in the past 20 years including a smaller multi skilled workforce. In fact, a Measurement Technician on a facility may be responsible for a wide range of tasks and skills necessary for operating and maintaining a pipeline. Much of their measurement work is performed with less frequency, and on more complex equipment than ever before. Gaining the proficiency needed to recognise and troubleshoot ultrasonic meter problems, let alone subtle changes that can provide an eye into potential measurement inaccuracies, requires time and experience to learn. By bringing the meters diagnostic data in via SCADA, we can provide alarms and trending capabilities that are not dependent on the frequency at which a Technician can visit a measurement facility. It is also not dependent on whether a Technician has necessary expertise to recognise potential meter problems - from the American School of Gas Measurement Technology.

The following Technical Papers are from Emerson Process Management:

• Operation of Ultrasonic Flow Meters at Conditions Different Than Their Calibration - Mr William Freund, Daniel Measurement and Control/ Mr Klaus Zanker, Daniel Measurement and Control/ Mr Dale Goodson, Daniel Measurement and Control /Dr James E. Hall, Letton-Hall Group/ Mr Andrew W. Jamieson, 4C Measurement. Currently, calibration of an ultrasonic flow meter for natural gas measurement is conducted under the conditions available at the flow calibration facility. Since almost all of these facilities utilize natural gas flowing in a pipeline, it is usually not possible to vary parameters such astemperature, pressure and gas composition, each of which affect the speed of sound. When the ultrasonic meters are then used in applications where these parameters are different from their calibration values, does the calibration still apply? Thanks also to NEL.
• Energy Measurement using Ultrasonic Flow Measurement and Chromatography - The Technician’s Perspective-Charles W. Derr and Charles F. Cook, Daniel Measurement and Control.
• A Powerful New Diagnostic Tool for Transit Time Ultrasonic Meters - Mr. W. R. Freund, Jr & Mr. K. J. Zanker - Ultrasonic flow meters produce a wealth of information that can be used to evaluate meter performance. Users can monitor this information to determine if any maintenance is required thus eliminating the need for routine maintenance and recalibration. Unfortunately this usually means rather heavy user involvement to track and analyze the information produced by the ultrasonic meter. This paper presents a new diagnostic indicator which, together with a few other indicators, confirm correct meter operation. Most of the diagnostics are null indicators or can be configured as null indicators, i.e. the indicated values are near zero when the meter is operating normally. These indicators are focused on the time measurement and therefore do not necessarily give information on bad flow conditions such as a half open valve immediately upstream of the meter.
• An Overview and Update of AGA Report No.9 - This paper reviews some of history behind the development of AGA Report No. 9 (often referred to as AGA 9), key contents and includes information on meter performance requirements, design features, testing procedures, and installation criteria.
• Gas Ultrasonic Flow Meter Station Design - This paper highlights some of the considerations that differentiate USM stations from conventional meter station practices. It is the subtle details that yield the big rewards. Consideration checklists are detailed and the prime importance items discussed. There is more design detail than many people realise and all items are important to a successful station.
• Ultrasonic Meter Station Design Considerations Technical White Paper - This paper addresses several issues that an engineer should consider when designing ultrasonic meter installations
• Diagnostic Ability of the Four Path Ultrasonic Flow Meter - Klaus J. Zanker - The primary function of the ultrasonic meter is to measure the actual volume flow rate. The process involves measuring four velocities on chords located in four different radial positions and in two different vertical planes. The eight transducers are fired about 50 times per second and the transit times to traverse each chord in both directions are measured. This vast array of data can be processed to yield useful diagnostic information, which forms the subject of this paper and shows that the four-path ultrasonic meter does much more than just measure the flow rate. It has sufficient diagnostic ability to confirm the authenticity of the measurement, and develop the source for conditional based maintenance and re-calibration.
• How Today's Ultrasonic Meter Diagnostics Solve Metering Problems - This paper discusses both basic and advanced diagnostic features of gas ultrasonic meters (USM), and how capabilities built into today’s electronics can identify problems that often may not have been identified in the past. It primarily discusses fiscal-quality, multi-path USMs and does not cover issues that may be different with non-fiscal meters. Although USMs basically work the same, the diagnostics for each manufacturer does vary. All brands provide basic features as discussed in AGA 9. However, some provide advanced features that can be used to help identify issues such as blocked flow conditioners and gas compositional errors.