Clamp on Liquid Flow Meters for certain Well Test Applications

Clamp on Liquid Flow  Meters for certain Well Test Applications
New technological breakthroughs have enabled measurements of oil and water mixtures with some gas bubbles or infrequent gas pockets that have traditionally caused  damage to  other types of inline mechanically driven flow meters. The inline meter may be subject to  sand, grit, stones (up to 0.25″ diameter), solids  and suspensions that could stop and damage other meters. This damage can be caused by close clearances,  rotating seals, and  stuffing boxes or sensor fouling , depending on the type of intrusive device implemented in the field. Continued or even brief exposure to these elements require removal of the flow meter from the line in question. In an effort minimize downtime, maintenance costs and overall cost of ownership, several oil enterprises have been implementing new technology dual mode clamp on ultrasonic flow meters in these very applications. High speed processors, advanced filtering software and intelligent sensor design have paved the way for a new generation of flow measuring devices currently implemented in oil fields around the world.

Although more durable designs and more cost-effective inline meters are being produced  to work with dirty process fluid or  where the risk of overspeeding is a potential problem, there are reasons that have persuaded certain groups of users to lean towards using newer digital based clamp on technology. The main criteria being the total cost of ownership. Although the initial costs of  other  inline devices are more attractive in the initial stages, there are long term and immediate expenses which have to be accounted for. Some of the problems associated with traditional methods are:
1. Continual re-calibration of flow devices due to mechanical wear and tear
2. Direct Damage to flow elements due to gas pockets , grit or other materials causing calibration deviations or complete failures within days, weeks or months.
3. Cost of installations , re-installations and  manpower
4. Remote locations of these devices are a major source of frustration due to the distance involved and the  need for continual maintenance and checking

Advantages of a clamp on design are evidenced by
1. Lower cost of ownership (no maintenance required, no moving parts)
2. Non-intrusive designs considerably speed up installation time
3. Re-calibration is not a continual requirement and does not require removal of elements from the line
4. Clamp on Flowmeters are immune to gas pockets , sand and grit since there is no contact with the process media
5. Reynolds compensation factors can be implemented in the software design to improve accuracy on liquids with fixed kinematic viscosities.

The following shows typical flow data gathered on a 10 inch crude oil line in the liquid phase with a fixed kinematic viscosity and density. It is important for the user to input viscosity and density parameters so that the change of state from laminar to turbulent flow can be predicted . The accuracies normally achieved are withing 1% of rate if pipe conditions are acceptable and correct process and pipe data are entered into the flow computer. Like many other types of meters, clamp on flowmeters require fully formed axially symmetric flow profiles, so reasonable lengths of straight pipe are required for more accurate flow measurements. Below is typical data gathered from the crude oil measurement over several hours

In this case, Transit Time methods are being used since Doppler methods cannot measure accurately at low flow rates due to limitations on the dependency of particles or gas bubbles in the line which may not even be present

Transit time meters work on the principal that the time of flight from the downstream transducer to the upstream during flow will always be greater than the upstream to downstream time. This is measured in milliseconds and can be correlated to flow velocities

Successful measurements require the user to input the pipe wall thickness, outer diameter, liquid kinematic viscosity and density if the fluid is an unkown type. This information can normally be obtained from an experienced laboratory or from previous analytical data.

DIFFICULT APPLICATIONS

The following is a typical case study on a difficult application where economics played a major role in technology consideration . We can consider this application as a “worst case” implementation where the meters were operating on their technological limits. Test locations where the flow was always in a liquid state have not presented problems for the technology with steady readings and accurate data measurements and clamp on flowmeters are accepted as an alternative means to accurate flow measurements.

EESIFLO does not claim to measure three phase flow regimes but the data gathered by the devices in these applications have proved useful to oil well  planners. Some level of accuracy is achievable depending on pipe and liquid conditions. This application is of interest to users who cannot justify the purchase of full blown inline multiphase flowmeters that claim to accurately measure oil , liquid and gas ratios. In this instance, it was important for the client to obtain non-intrusive information from a well and from subsequent other wells. It was known that the flow maintained a liquid state for the most part but previous inline devices suffered continual damage and another solution was of most importance.

It was the intention of EESiFlo to work cooperatively with X  oil company to solve the flow measurement problems experienced at various oil well locations which were predominantly oil based liquids containing mixtures of water for the most with intervals of  high aeration and GVF at particular times of the day. Although it was impossible to measure the gas phases, the meters produced results that gave operators important information on the production of their wells which enabled them to plan for further courses of action

For the remainder of this data set, data appeared very accurate in three or four hour groups, at the end of which some undefined interference caused flow data to become erratic, and eventually the signal was lost. This loss of signal appears below on repetitive 3 to 4 hour cycles.

Loss of Signal
In addition to recording flow velocity (shown red below) the EESiFlo “Series” product line are capable of recording the signal strength of each data transmission. This signal strength is represented by a black line in the graph below. Note that prior to the loss both flow values and signal strength remain acceptable. As signal strength values dropped considerably, the flow values became erratic. Once signal strength returned to an acceptable level, flow values also became valid.

In addition to flow volume and signal strength, EESiFlo “Series” products are capable of measuring and recording the changing Speed of Sound of the medium, which is represented below by a blue line. Again, when flow data appeared normal, the signal strength and speed of sound all appeared normal. However, when the physical properties of the medium changed, all three signals became erratic until both speed of sound and flow values where finally lost. As soon as the properties returned to normal values, both speed of sound and flow rates returned to normal.

Experience indicates that some physical property of the flow is changing on a 3 to 4 hour cycle at the oil well. This may be entrapped air (gas) or increased particulate count (suspended particles) but most likely gas fractions. Although it is not possible to measure the void fractions or even measure their flow rates with the clamp on devices at this present time, the data gathered has been deemed useful diagnostic information

Float Blockage detection

The Problem:

Rotameter RAMC is often used in critical applications where safety is paramount. RAMC has the option of low flow alarm outputs. A low flow contact is set and an alarm is activated if flow drops below the minimum level. But what happens if the float is mechanically blocked? The meter works wrong and the blocked float cannot be seen through the solid S.S. tube !!

Under normal flow conditions the guided float tumbles round its center of gravity. This generates small movements of the pick up magnet. This fluctuation is measured by the Microprocessor. Below are typical fluctuations

The mechanically blocked float does not generate small movements of the pick up magnet. These Zero -fluctuations are measured by the Microprocessor. If these are under a certain level, the alarm current is set. The level is determined during an Autozero adjustment.
The Zero-fluctuations are recorded under no flow condition when the float is at the rest point (Autozero). A level for minimum fluctuations including a safety factor is generated.

Ultrasonic Medical Gas Flow Meter

Gill Instruments Ltd, the world leader in the design and production of ultrasonic meteorological anemometers, has now successfully applied the same technology to the demanding medical fields of anaesthesia and ventilation monitoring. The Spirocell uses proven ultrasonic techniques to measure gas flow reliably and accurately with no moving parts. Compared with existing technology the Spirocell provides extended functionality, reduced lifetime costs and improved reliability. It can measure from extremely low flow rates up to its maximum with no change in its configuration. Together with its high sample rate this gives the speed of response and accuracy to produce detailed information on very small changes in the gas flow. Unlike other measurement devices the Spirocell retains its accuracy despite the presence of moisture and the rapid changes in temperature and humidity that are found in patient respiration. This robustness of operation also means that the user is not required to perform any calibration on the unit. Along with these benefits the Spirocell is also easy to use. It is simple to install, has output via a serial link and requires no regular maintenance. Safety is a key factor in the design of the Spirocell so the unit has extensive error checking and diagnostic routines to ensure that only reliable data is collected. The ultrasonic sensors can be easily detached from the unit to allow sterilisation. The unit complies with all relevant US FDA recommendations. Gill Instruments Ltd is very experienced in designing and manufacturing products to the highest standards and can provide expert support to allow easy integration into other systems.

PRINCIPLE OF OPERATION
The Spirocell uses ultrasound to measure the velocity of gas travelling through the device. Bursts of ultrasound are transmitted upstream and downstream in the gas flow between the two sensors. The time of flight in both directions is measured and the distance between the sensors is known. Therefore, by using the equation opposite, the flow rate of the gas can be calculated. The tube in which the gas is flowing has a known cross sectional area, so for a given period of time the volume of the gas flow can also be measured. The speed of sound in a gas is dependent on factors such as temperature, pressure, humidity and composition. As can be seen, by using the difference in the times of flight, the equation used to calculate the flow rate becomes independent of the speed of sound. This means the measurement is unaffected by changes in these factors. This makes the Spirocell simple to use and removes the need for any time consuming calibration procedures to correct for environmental changes.

The Spirocell uses extensive self diagnostic routines which ensure a higher data integrity than any other technology. The results from these tests along with the flow data is output on the RS232 serial link. For example, if the unit fails any of its start up tests then no data will be transmitted and an error message will be sent. The Spirocell disassembles easily to allow the appropriate components to be sterilised. The unit is compatible with chemical and steam sterilisation for 15 to 30 min at 121°C.

Measuring Draft Beer

Introduction

The Auper flow meter was originally design specifically to be used in draft beer.  Three years of R&D were necessary to originally design this flow meter which has remained unchanged (and copied) since its release on the market in 1985. Auper was the first company to manufacture such a flow meter in North America. Tens of thousands are in use all over the world in all kinds of draft beer dispensers. It is used to monitor other products too, such as soft drink, juice, coffee, oil, water etc… We use standard Hex nut, washers and draft beer tailpieces to adapt to all plastic beverage tubing. The internal diameter of the tubing may vary from 3/16″ (4.7mm) to 1/2″ (13 mm). Tailpieces are available in chrome plated brass or stainless steel.

Operation

Liquid flowing into the flow meter (turbine) causes the propeller located inside the flow meter to spin. The internal diameter of the turbine and the design of the passageway allows a liquid to circulate normally, without cavitations or blockage. A flow meter is selected according to its typical flow rate specifications. At equal pressure, a liquid with a low viscosity (beer, water) flows more easily and at a faster rate within the same line than a thick viscose liquid like syrup.  We are never concerned with the type of liquid we are measuring but by the speed at which it is dispensed. The Auper flow meter is made of Delrin for its durability, its low friction properties (close to Teflon) and extremely low absorption. It is covered with rubber to protect it from moisture and water. The flow meter does not require any power from the electronics it is connected too. An accidental short-circuit would not damage it. The signal generated by this flow meter is totally independent from the type of product it is measuring; viscosity or dark products would not block the passage of an infra-red beam for instance.

The Auper flow meter model 50-316 has an operating curve which was designed for standard draft beer dispensers. This model operates very well on beer lines with an internal diameter between 3/16″ (4.76mm) and 3/8″ (9.25mm) with an average flow rate between 1 and 2.5 oz/sec (1.5 and 4 l/min). Some products such as the Guinness beer or carbonated water are often running at slower speed and will require a model with a slower typical flow rate (50-018). Ask you Auper representative for guidance before you order.

Model	Application	Pulse/oz	ml/pulse	Typical flow rate
50-018	Guinness/Soft drink/Soda	30	1	1 Oz/sec	30 ml/sec
50-316	Draft beer/Wine/Soda	15	2	2 Oz/sec	60 ml/sec
50-332	Alcohol/Syrups	45	0.6	< 0.5 Oz/sec	< 15 ml/sec
50-114	Fast flow applications	7	4.25	4 Oz/sec	120 ml/min

Installation

The flow meters are usually mounted in the storage room above the keg, on top of the wall bracket. It is inserted in the rigid tubing and secured to the wall using a plastic bracket when necessary. If FOB detectors (also called empty keg detectors) are used, the flow meter should be installed after this device. The FOB will prevent the flow meter from ever being in contact with foam or air rushing up the line.Each product line has to have a flow meter. Each flow meter is wired out of the storage room to either one of the Auper electronic controllers. Each flow meter is identified by line number, brand name and destination.

Beer Line Cleaning

The norms for beer line cleaning will vary from one country to another. Most beer line cleaners use a caustic solution (bleach) to clean and disinfect the lines and then rinse using soft water. The turbine should remain connected to the line in order to benefit from the line cleaning. When ever lines are cleaned, the meters should be read before and after or the system could be disabled by the manager. In certain countries, norms require that a sponge be used during the procedure. The turbine would have to be removed from the line since it will block the passage to the sponge or the sponge would block the flow meter. The company responsible for the line cleaning must be warned that flow meters have been installed in the beer lines and you must request that they use chemicals instead of sponges. Beer line cleaning should take place at least every 4 to 6 weeks.

Trouble shooting foamy draft beer

Draught beer is a sensitive product which requires a certain number of parameters to be just right :Temperature, pressure, propellant and good beer system design. The Auper flow meter (turbine) is guaranteed not to make beer foam. However, the installation of flow meters into your beer lines will not solve the foaming problems. It would only tell you how much is wasted. Before you proceed with the installation of the flow meters, take a good look at the dispenser itself and ask a few questions. Test the system in the morning before the bartenders start using it.

1. Does the serving temperature correspond to the brewers norms ?

North America: 38F(3.3C) & 42 F(5.5C)
Europe: 43F(6C) & 48F(9C)

Pour a glass and insert a thermometer immediately in the freshly poured beer. If the temperature in the glass is outside these norms, it is quite possible that your refrigeration system is defective or needs adjustment. Too high a temperature will increase the risk of excessive foaming. If too cold, the beer is not foamy enough and bartenders usually serve more in each glass. In either case, you should be concerned that the pour cost will probably be too high.

2. Is the flow rate between 2.5 and 3.5 l/min (Aprox: 2 oz/sec) ?

If the flow rate is too slow, it is probably due to a lack of pressure in the system. The C02 gas can separate from the beer while in the line causing the beer to foam at the tap. The color of the beer will change a few seconds after the tap is opened, passing from a clear and golden color to white. A gas leak will have the same effects.

3. Check the propellant ! Is the beer flat or over carbonated ?

Any beer system with a distance between the kegs and the faucet greater than 10 feet (3 meters) should be pressurized using a mixture of air or nitrogen (70 %) and CO2 (30 %). Straight CO2 can be used for direct draw systems and very short runs (less than 10 feet or 3 M). Clean straight air can be used if the sales volume per day is very high. Otherwise, it will either contaminate the beer (think of where the air is pumped from) or it will make the beer flat. The wrong choice of propellant will either make the beer foam, make it flat or change the taste. In either case you will be wasting product thus increasing your pour cost . Get a qualified technician to look at the problem !

Non-refrigerated kegs (Europe)

Temperature is one of the elements that will affect draft beer along with pressure, the type of gas, the line design and the product itself. When kegs are stored in a non-refrigerated room, an increase in the store room temperature will have an effect on the way the product pours at the faucet. The higher the storage temperature is, the more gas pressure will be required to dispense the beer properly. When kegs are kept in a cooler, the external temperature will not have an effect on the draft beer since everything is under a controlled environment. With this type of installation, pressure settings are often kept to a minimum. The smallest change in temperature will have an effect and may cause foaming. Before you proceed with the installation of the flow meter, check if you can dispense draft beer for 15 seconds with the beer retaining its golden color when coming out of the faucet. If after a moment, it turns white, the pressure is too low. Inserting a flow meter will only make things worse. Increase the pressure by 2 PSI (14 KPa) and try again. Repeat this procedure until you can pour beer properly for at least 15 seconds. When inserting a flow meter in the beer line, the additional friction may have to be compensated by increasing the pressure settings. Once the flow meter is in place, do the same test and follow the same procedure.

Soft drink and Juice

Pre-Mix
Whether it is wine, juice, or soft drink, if it’s ready to serve it’s Pre-Mix. As with draught beer, one flow meter per line will be necessary.

Post-Mix
For Post-Mix dispensers you have the choice of measuring the syrups or the carbonated water. If you are only interested in the total amount of soft drink dispensed , you will only need one flow meter connected to the carbonated water line (soda).

1. Measuring carbonated water

The ratio of the mixture (or “Brix”) is usually the same or very close for all the syrups (5:1). By installing the flow meter in the carbonated water (soda) line you will register the total amount of soft drink served through the dispenser. Since one carbonator unit can feed multiple dispensers, it is possible to install the flow meter closer to the carbonator just before the line splits to each dispenser, to monitor the total soft drink dispensed . If you want to monitor each dispenser separately, then the one flow meter per dispenser is installed, after the split, closer to the dispenser.

2. Measuring syrups.

If you want to know the quantity of each flavor served, you will need to install a turbine on each of the syrup lines. For this application it is necessary to use the turbine with model number 50-032 (slower flow rate).

Why and How to measure flare gas

1 INTRODUCTION

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

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

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

2 WHY MEASURE FLARE GAS?

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

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

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

2.1 Governmental Legislation

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

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

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

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

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

3 FLARE GAS METERING

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

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

3.1 Flare Gas Measurement Methods

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

. insertion turbines
. Thermal mass meters
. Annubars

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

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

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

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

4 ULTRASONIC TIME-OF-FLIGHT FLOW METERS

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

The ultrasonic time-of-flight gas flow meter is based on measurement of contra propagating ultrasonic pulses, in which the transit time of the sonic signal is measured along one or more diagonal paths in both the upstream and downstream directions. The flow of gas causes the time for the pulse traveling in the downstream direction to be shorter than for the upstream direction, and this time difference is a measure for the rate of the gas flow, see Fig. 4.1. By utilizing Equations (4.1) - (4.3), the gas volume flow rate can be calculated. In Equation (4.1), the axial flow velocity along the acoustic cord is calculated, and (4.2) gives the average flow velocity along the pipe axis. A single path ultrasonic flow meter measures the axial flow velocity along a single cord. Dependent on the flow velocity, the flow profile of the flowing gas will be some degree of a fully developed turbulent profile. In order to compensate for the flow profile to
Obtain the average axial flow velocity, some order of correction to the measured flow velocity is required. One way to utilize this correction, K, is to use the Reynold’s number as a measure of the flow profile, and adjust the measured axial flow velocity according to a function based on the Reynold’s number estimated. The volume flow rate at reference conditions is calculated from Equation (4.3), where the input of line pressure and temperature are required.
As can be seen from these equations, the flow velocity measured along the ultrasonic cord does not depend on pressure, temperature or any other process parameter. This is a very important characteristic of an ultrasonic flow meter, as it implies that no adjustment due to changes in e.g. gas composition is required. Accordingly, an ultrasonic flow meter should present valid measurements independent of the process conditions. Thai is, within the flow, pressure and temperature range specified for the meter in question.

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

4.2 CW-Chirp Measurements

Using continuous-wave (CW) signals and phase detection at the receiver, the transit time of ultrasonic signals can be determined in order to calculate the axial flow velocity. However, at higher flow velocities, the time-of-flight measurements may become ambiguous as the

Associated change in time-of-flight become larger than one CW signal period. To eliminate this ambiguity, a Chirp signal is utilised.The whole number of CW periods, n chirp’ is measured using the Chirp signal, and added to the time obtained from phase measurements using the CW signal, tcw.
This technique ensures time-of-flight measurements with 100 ns resolution, giving a flow velocity measurement resolution of 0.01 m/s (36″ pipe). With the changing operation of flare stacks, with zero-flaring becoming a common situation, it is very important to continuously present accurate measurement also in the lowest flow range.

4.3 Features of Importance

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

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

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

4.4 Automated Condition based Maintenance

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

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

Incorporating the possibility for automated condition based maintenance, the Fluenta FGM 130 is aligned to the NORSOK standard (2), which states normative requirements in this respect.

CHROMATOGRAPH, RTU SYSTEM MONITORS CO2 INJECTION

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

All three variables can be readily monitored with transducer technologies.

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

Holding the pressure at 1,000 psia and allowing the temperature to rise to 70° F. yields a density of 49.59 lb/cu ft, or a deviation of almost 6.5%.

When components common to the CO2 process are added, variations become more pronounced.
Leaving all other variables the same and modifying only the component concentrations to 98% CO2, 0.67% C1, 0.67% C2, and 0.67% C3 causes density to change to 55.26 lb/cu ft. That is a difference of almost 10%.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Weirs for Open-Channel Flow Measurement

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

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

Types of Weirs

Two types of weirs exist: sharp-crested weirs and broad-crested weirs. Only sharp-crested weirs are described here because they are normally the only type used in the measurement of irrigation water. The sharp edge in the crest causes the water to spring clear of the crest, and thus accurate measurements can be made. Broad-crested weirs are commonly incorporated in hydraulic structures of various types and, although sometimes used to measure water flow, this is usually a secondary function. The components of a sharp-crested weir.
The most common types of sharp-crested weirs are rectangular, trapezoidal (Cipolletti), and 90? V-notch weirs.
The weir selected should be that most adapted to the circumstances and conditions at the sites of measurement. Usually, the rate of flow expected can be roughly estimated in advance and used to select both the type of weir to be used and the dimensions of the weir. The following facts should be considered when a specific type of weir is selected for a given application.
The head should be no less than 0.2 feet and no greater than 2.0 feet for the expected rate of flow.

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

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

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

Cipolletti Weir

The Cipolletti weir, illustrated in Figure 4 , is trapezoidal in shape. The slope of the sides, inclined outwardly from the crest, should be one horizontal to four vertical.

The formula generally accepted for computing the discharge through Cipolletti weirs is:
equation (2) where parameters are as defined in equation (1) . The selected length of notch (L) should be at least 3H and preferably 4H or longer.

90 ° V-Notch Weir

The 90 ° V-notch weir, Figure 5 , is most accurate when measuring discharges of less than 500 gpm. The maximum discharge that can be accurately measured is approximately 5,000 gpm. The sides of the notch are inclined outwardly at 45 ° from the vertical.
The basic formula for discharge through the 90 ° V-notch weir is:
equation (3) where H = vertical distance (ft) between the elevation of the vertex (lowest part of the notch) and the water surface at least 4H upstream from the weir, and other parameters are as previously defined. Table 3 gives discharge values for 90 ° V-notch weirs for heads up to 1.5 feet.

Construction and Placement
The following general rules should be observed in the construction and installation of weirs.
A weir should be set at right angles to the direction of flow in a channel that is straight for a distance upstream from the weir at least ten times the length of the weir crest.

The crest and sides of the weir should be straight and sharp-edged. The crest of the rectangular and Cipolletti weirs should be level and the sides should be constructed at exactly the proper angle with the crest. Each side of the V-notch weir should make a 45 ° angle with a vertical line through the vertex of the notch.

The channel upstream should be large enough to allow the water to approach the weir in a smooth stream, free from eddies, and with a mean velocity not exceeding 0.3 foot per second.

Avoid restrictions in the channel below the weir that would cause submergence. The crest must be placed higher than the maximum downstream water surface to allow air to enter below the nappe.

Isolating Flow Conditioners Bring Unparalleled Accuracy to Metering Stations

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Advanced Differential Pressure Flowmeter Technology

1.1 Introduction

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

1.2 Principles of Operation

The V-Cone is a differential pressure type flowmeter. Basic theories behind differential pressure type flowmeters have existed for over a century. The principal theory among these is Bernoulli’s theorem for the conservation of energy in a closed pipe. This says that for a constant flow, the pressure in a pipe is inversely proportional to the square of the velocity in the pipe. Simply, the pressure decreases as the velocity increases. For instance, as the fluid approaches the V-Cone meter, it will have a pressure of P1. As the fluid velocity increases at the constricted area of the V-Cone, the pressure drops to P2, as shown in Figure 1. Both P1 and P2 are measured at the V-Cone’s taps using a variety of differential pressure transducers.
The Dp created by a V-Cone will increase and decrease exponentially with the flow velocity. As the constriction takes up more of the pipe cross-sectional area, more differential pressure will be created at the same flowrates. The beta ratio equals the flow area at the largest cross section of the cone (converted to an equivalent diameter) divided by the meter’s inside diameter.

1.3 Reshaping the Velocity Profile

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

This forces the flow in the center of the pipe to flow around the cone. This geometry presents many advantages over the traditional concentric Dp meter. The actual shape of the cone has been continuously evaluated and tested for over ten years to provide the best performance under differing circumstances.

One must understand the idea of a flow profile in a pipe to understand the performance of the V-Cone. If the flow in a long pipe is not subject to any obstructions or disturbances, it is well-developed flow. If a line passes across the diameter of this well-developed flow, the velocity at each point on that line would be different. The velocity would be zero at the wall of the pipe, maximum at the center of the pipe, and zero again at the opposite wall. This is due to friction at the pipe walls that slows the fluid as it passes. Since the cone is suspended in the center of the pipe, it interacts directly with the “high velocity core” of the flow. The cone forces the high velocity core to mix with the lower velocity flows closer to the pipe walls. Other Dp meters have centrally located openings and do not interact with this high velocity core. This is an important advantage to the V-Cone at lower flowrates. As the flowrate decreases,
the V-Cone continues to interact with the highest velocity in the pipe. Other Dp meters may lose their useful Dp signal at flows where the V-Cone can still produce one.

The pipe flow profile in actual installations is rarely ideal. There are many installations where a flowmeter exists in flow that is not well developed. Practically any changes to the piping, such as elbows, valves, reductions, expansions, pumps, and tees can disturb well-developed flow. Trying to measure disturbed flow can create a substantial problem for other flowmeter technologies. The V-Cone overcomes this by reshaping the velocity profile upstream of the cone. This is a benefit derived from the cone’s contoured shape and position in the line. As the flow approaches the cone, the flow profile “flattens” toward the shape of a well-developed profile.
The V-Cone can flatten the flow profile under even extreme conditions, such as single elbows or double elbows out-of-plane positioned closely upstream of the meter. This means that as different flow profiles approach the cone, there will always be a predictable flow profile at the cone. This ensures accurate measurements even in non-ideal conditions.

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

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

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

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

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

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

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

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

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

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

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

A NOVEL ULTRASONIC FLOWMETER CONCEPT

ABSTRACT

Ultrasonic flowmeters have been the center of attention within the natural gas industry for the last several years. To date, current commercial devices have been developed using Gaussian or proprietary integration techniques to measure the velocity of the flowing stream to eliminate the sensitivity to piping induced installation effects. When these proprietary integration techniques are applied, the ultrasonic meter is required to determine the swirl and asymmetry of the flowing stream. Published research has indicated both integration techniques are limited in their sensitivities to installation effects.

This paper presents a novel ultrasonic flowmeter concept, proposed by the author, that combines0.25 percent under field piping configurations for natural gas applications. This performance has not been demonstrated by any commercial or scientific design to date. The novel concept accomplishes this performance with fewer transducers and chordal paths resulting in considerable savings in manufacturing costs.

Combining these technologies into a flowmeter has created a method to measure the ‘real time’ health of the flowmeter.

To determine the validity of the invention, experiments were conducted in natural gas using a two-path ultrasonic flowmeter. Perturbation tests were conducted under the following fluid dynamic conditions:

* fully developed flow
* swirling flow
* non-symmetric, non-swirling flow

The results for the experiments demonstrate the validity of the concept and the performance of this novel approach.

FLOWMETERS

Flowmeters are generally classified as either energy additive or energy extractive. Energy additive meters introduce energy into the flowing stream to determine flowrate. Common examples of energy additive meters are magnetic meters and ultrasonic meters. Energy extractive meters require energy from the flowing stream, usually in the form of pressure drop, to determine the fluid’s flowrate. Examples of energy extractive meters are PD meters, turbine meters, vortex meters and head meters (orifice, pitot, venturi, etc.).

Further subclasses of flowmeters are based on determining if the meter is discrete or inferential.

Discrete meters determine the flowrate by continuously separating a flow stream into discrete segments and counting them. Inference meters infer flowrate by measuring some dynamic property of the flowing stream.

ULTRASONIC FLOWMETERS

Ultrasonic flowmeters have been the center of attention within the natural gas industry for the last decade. To date, current commercial devices have been developed using Gaussian or proprietary integration techniques. When the proprietary integration technique is applied, the ultrasonic meter is required to determine the swirl and asymmetry of the flowing stream. Published research has indicated both integration techniques are limited in their sensitivities to installation effects and have demonstrated additional bias uncertainties due to piping configurations.

Acoustic flow measurements are well known. They involve determining the average chordal velocity of the flowing stream from the difference in transit time of acoustic pulses transmitted in the downstream and upstream directions respectively between acoustic transducers. These acoustic pulses are transmitted along a chordal path, and a measure of the chordal velocity is determined from the measured transit times. The fluid can be gas or liquid.

The transit times depend on the mean velocity of the chordal path, the flow profile and the turbulence structure of the flowing stream. The reliability of the measured chordal velocity depend on the path length, the configuration and radial position of the acoustic path, the transmitted acoustic pulse form, the electronic timing and gating performance and the calculations involved in reducing the measured parameters to the mean chordal velocity.

The acoustic transducers may be mounted in an invasive or non-invasive manner. An invasive mount invades the channel’s containment structure through an aperture. An invasive mount does not transmit acoustic pulses through the containment structure, sometimes referred to as ‘wetted’ transducers. A non-invasive mount transmits the acoustic pulses through all or part of the channel’s containment structure, sometimes referred to as ‘non-wetted’ transducers.

The invasive mount is further classified as intrusive or non-intrusive. The intrusive term relates to a part or all of the transducer intruding into the flowing medium. The nonintrusive term defines the transducer mounting as not intruding into the flowing stream.

The acoustic paths may be arranged in a reflective, non-reflective or hybrid geometry.

A reflective path is arranged in a geometric manner to reflect one or more times off the containment structure or a reflective body installed inside the channel.

A non-reflective path is arranged in a geometric manner that does not reflect off the containment structure or a reflective body inside the channel.

A hybrid design employs any combination of both reflective and non-reflective paths and/or invasive and non-invasive configurations.

The number of paths and their placement in the channel vary among commercial and scientific designs.

STATE-OF-THE-ART

The state-of-the-art for ultrasonic flowmeters employs one of three integration methods to determine the average flowing velocity in a circular duct. The first two methods are commercially available. The third method is under development by the scientific community.

The first commercial method, known as Gaussian integration, is based on a fixed number of paths whose fixed locations and weighting factors are based on the numerical Gaussian method selected by the designer. Several Gaussian methods are available from publications (Jacobi & Gauss, Pannell & Evans, etceteras). The advantages of this approach are clear. No additional information of the flow profile is required for calculating the average flowing velocity. The weighting factors are fixed in advance as a result of the number of paths and the Gaussian method selected by the designer. The minimum number of paths is four regardless of the Gaussian method selected.

The second commercial method, which is a proprietary method, determines the swirl and/or asymmetry of the flowing stream by transmitting acoustic pulses along two or more paths having different degrees of sensitivity to swirl and to symmetry. The proprietary method uses a ‘trade secret’ matrix to determine the weighting factors for the chordal velocities based on the measured swirl and asymmetry. The recommended number of paths is five for the proprietary method.

The third scientific method, now under development by the National Institute of Standards and Technology (NIST) is an eleven-path arrangement. The unit, termed the advanced ultrasonic flowmeter (AUFM), is based on computer modeling of pipe flow fields and simulations of their corresponding ultrasonic signatures. The sensor arrangement for the AUFM will have enhanced velocity profile diagnostic capabilities for deviations from non-ideal pipe flows. Interpreting the signals produced by the ultrasonic sensors will be a pattern recognition system capable of classifying the approaching unknown flow among one of a number of typical flows contained in its electronic onboard library. This library will be created using results from computational fluid dynamics simulations. Both commercial methods perform well in the laboratory environment of ‘fully developed’ pipe flow.

In the industrial environment, multiple piping configurations are assembled in series generating complex problems for flow metering engineers. The challenge is to minimize the difference between the actual or “real” flow conditions and the “fully developed” flow conditions in a pipe to maintain a minimum error associated with the selected metering device’s performance. The two state-of-the-art commercial methods attempt to accomplish this objective.

With respect to installation effects and the near term flow field, the correlating parameters that impact similarity vary with meter type and design. However, it is generally accepted that the level of sensitivity to time-averaged velocity profile, turbulence structure, and bulk swirl is dependent on the metering technology and the specific design of that meter.

Significant research from the European Gas Research Group (GERG) and the Gas Research Institute (GRI) has attempted to quantify the additional uncertainties associated with installation effects. The first commercial method has an additional bias uncertainty of ±0.0 to 3.0 percent due to various piping configurations. The second commercial method has an additional bias uncertainty of ± 0.0 to 1.0 percent due to various piping configurations. Obviously both methods have clear disadvantages in ‘real’ performance to the user community.

THE ARTEFACT PACKAGE

A novel ultrasonic flowmeter concept combines the strengths of acoustic and isolating flow conditioner technologies to determine the flow velocity and/or throughput in a channel. The performance of this novel concept exceeds the current technology performance by an order of four to twelve times and has significant savings in manufacturing costs. The novel approach allows for creation of a method to measure the ‘real time’ health of the flowmeter.

The isolating flow conditioner eliminates swirl (less than 2° of swirl) and provides an axisymmetric velocity profile (±5 percent between parallel chords) upstream of the acoustic path(s). Acoustic pulses are transmitted along a chordal path, and a measure of the chordal velocity is determined from the measured transit times. An individual chordal weighting factor is applied to the chordal velocity to obtain the average flow velocity and/or throughput of the medium. An individual calibration factor for the chord, based on laboratory testing, may be applied in lieu of the weighting factor or in addition to the weighting factor.

The flowmeter uses a fixed weighting factor based on the position of the acoustic path(s) and the turbulence level of the flowing medium. For two-path or more designs, the weighting factor may be correlated on the chordal position, a relaxation term related to the profile development and the turbulence level of the flowing medium.

Combining these technologies into a flowmeter has created a method to measure the ‘real time’ health of the flowmeter. A one-path design provides a low-level ‘real time’ health of the flowmeter. A two or more path design provides a high-level ‘real time’ health of the flowmeter.

In the industrial environment, a flowmeter with these built-in diagnostic capabilities is referred to as a ’smart’ or ‘intelligent’ flowmeter.

EXPERIMENTAL APPARATUS

To determine the validity of the single and multi-path ultrasonic designs, experiments were conducted in natural gas at the Gas Research Institute’s Meter Research Facility under the auspices of Southwest Research Institute. Independent research has been conducted extensively on 200mm meters with both single path and multi-path ultrasonic designs. The pipe velocity was varied from 1.5 to 21.3 mps (5 to 70 fps) resulting in pipe Reynolds numbers from approximately 600,000 to 7,500,000.

Perturbation tests were conducted under the following fluid dynamic conditions:

* fully developed flow
* swirling flow
* non-symmetric, non-swirling flow

Fully developed flow was established with the use of an isolating flow conditioner, a minimum of forty diameters (40D) of straight pipe, a tee mounted in the same plane and approximately eighty diameters (80D) of straight pipe prior to the test section.

Non-symmetric, non-swirling flow was established with the use of an isolating flow conditioner, a minimum of forty diameters (40D) of straight pipe, and a tee mounted in the same plane prior to the test section. Swirling flow was established with the use of an isolating flow conditioner, a minimum of forty diameters (40D) of straight pipe, followed by a ninety-degree (90°) elbow and a tee out of plane prior to the test section. This combination has been known to generate swirl angles of fifteen to twenty degrees (15° to 20°)

SINGLE PATH OR MORE RESULTS The experiments demonstrated the validity of the novel concept. The single-path approach demonstrated an uncertainty of ±0.50 percent of actual flowrate in both perturbed and ‘good’ flow conditions for velocities greater than 3 mps (10 fps). While this performance equals the five-path proprietary design discussed previously, it achieves this performance with one-fifth of the transducers and chordal paths.

To determine the validity of the two-path or more invention, experiments were conducted in natural gas using a two-path and a threepath invention.

Again, the experiments demonstrated the validity of the novel concept. The two-path designs demonstrated an uncertainty of ±0.25 percent or better of actual flowrate in both perturbed and fully developed flow conditions for velocities greater than 3 mps (10 fps). While this performance exceeds the five-path proprietary design or the four-path Gaussian designs by an order of two to six times, it accomplishes this performance with at least one-half of the transducers and chordal paths.

The three-path design demonstrated a performance of ±0.15 percent of actual flowrate in both perturbed and fully developed flow conditions for velocities greater than 3 mps (10 fps). This performance exceeds the five-path proprietary design or the four-path Gaussian designs by an order of four to twelve times. This performance has not been demonstrated by any commercial or scientific design to date. The novel concept accomplishes this performance with fewer transducers and chordal paths resulting in considerable savings in manufacturing costs.

A four or more path design is predicted to have a performance of ±0.10 percent or better of actual flowrate in both perturbed and fully developed flow conditions for velocities greater than 3 mps (10 fps). Of course, it is important to note that the claimed uncertainty for state-of-the-art worldclass flow laboratories is approximately onefourth of one percent (±0.25%) using natural gas or air as the flowing medium.

SMART’ OR ‘INTELLIGENT’ FLOWMETER

Combining these technologies into a flowmeter has created a method to measure the ‘real time’ health of the flowmeter. A onepath design provides a low-level ‘real time’ health of the flowmeter. A two or more path design provides a high-level ‘real time’ health of the flowmeter. In the industrial environment, a flowmeter with these built-in diagnostic capabilities is referred to as a ’smart’ or ‘intelligent’ flowmeter.

Due to the brevity of the paper, it is not possible to explore the ‘real time’ health monitoring of the flowmeter.

However, the following is the VOS residual analysis for all meter designs for the complete experimental pattern.

STATISTICAL ANALYSIS

The following statistical results indicate the level of confidence in the stated performance for the various path designs.

The statistical results as a function of mean pipe velocity for the path designs are as

The statistical results as a function of fully developed flow or perturbed flow for the path designs are as follows
Notes:
(1) Statistics are for greater than 6 fps.

Residuals’ Plots

Due to the abbreviated length of the paper, we will present the compete set of the residuals’ graphs for the two-path designs only.

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