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Thursday, September 27, 2012

The Case of the Missing 200 Million Barrels of Oil

Source: George S. Mack of The Energy Report  (9/27/12)

Marshall J. Adkins Supply threats in the Middle East have governments around the world hoarding oil, largely in secret. But it didn't get past Raymond James Director for Energy Research Marshall Adkins, who noticed the 200 million-barrel discrepancy between what was pumped and reported global oil reserves. Where did the missing oil go, and why don't prices reflect this substantial surplus? More importantly, what happens once the reality of an oversupply sets in?—A tough six months, Adkins expects. Read on to find out where you can hide when prices plummet.


The Energy Report: You've written a provocative research report titled "Hello, We'd Like to Report a Missing 200 Million Barrels of Crude." It argues that the global oil inventory should have grown by over 200 million barrels (200 MMbbl) during the first six months of 2012. Where did this oil go? And a better question is, why hasn't this surplus shown up in pricing?

Marshall Adkins: When the U.S., the European Union and the United Nations imposed sanctions against Iran, the world responded by putting oil into storage. China rapidly began filling its strategic petroleum reserves. Saudi Arabia topped off its surface reserves. Iran put oil in the floating tankers.

TER: Why isn't this storage being reported? Is it normal for this oil to not go into the regular reporting channels?

MA: Yes. Unfortunately, it takes three or four months, and often six months, to get good data from the Organization for Economic Cooperation and Development (OECD). It's a lag, but at least you usually get the data. We estimate that OECD data accounts for about two-thirds of global oil inventory capacity. The other third, which is just an estimate, is off the radar. Few sources really track this non-OECD data. The International Energy Agency (IEA) does not track it either, because there's simply no reliable way of getting the information. China is probably the best example of that. It just does not tell us exactly how much it has.

TER: Could this result in dumping at some time in the future, potentially after the November election in the U.S.?

MA: It could. But even if they don't dump it, we think there is an even bigger structural problem. We are running out of places to put the growing supply of oil. Based on our supply-demand numbers, the world is poised to build significant inventories in early 2013. There is a very real possibility that if Saudi Arabia does not initiate production cuts sometime in early 2013, we will run out of places to put this oil around the world.

TER: Your particular specialty area is oilfield services. You maintain a U.S. rig-count table, which showed a 6% drop year-to-date as of August 31, 2012. Does this indicate that it's getting easier to get oil horizontally than it is to drill straight down?

MA: There is no question that the application of horizontal oil technology has completely changed the game for both oil and natural gas here in the U.S. Yes, it's just a much more efficient way of extracting oil and gas, particularly from formations that are very tight. This is a trend that's going to be here for a long time. It has led to an incredible increase in production per well.

TER: I noted dry gas rigs in your table are down 57% during that same one-year period. Even wet gas rigs are down 40%. How long can this go on before gas prices turn around?

MA: The decline in the overall rig count this year is mainly a function of the falling natural gas rig count, both wet and dry gas rigs. Early on, oil rig growth offset a lot of that gas decline, but the growth rate in oil has stagnated. So, low prices for natural gas are causing a meaningful decrease in gas drilling, but we think there will continue to be reasonable growth in gas supply from the oil wells in operation. That said, gas prices should gradually rebound as we build out infrastructure and consumers start to take greater advantage of extremely low gas prices in the U.S. Next year, we think the overall U.S. rig count will continue to deteriorate with lower oil prices. As that happens, overall gas production growth should flatten. That allows growing gas demand to offset stagnating supply growth. That should eventually drive U.S. natural gas prices higher. It will take a while, but we expect gas prices to improve steadily over the next several years.

TER: Natural gas prices were up about 35–40% before summer. Was this just a bounce, or could this be the beginning of a bull market in natural gas?

MA: I wouldn't call it a bull market in gas. Gas prices have certainly improved, but I think most people who are out there drilling for gas would say that $3 per thousand cubic feet ($3/Mcf) isn't exactly a bull market. They simply aren't making a whole lot of money at that price. That said, today's prices are much better than six months ago and things are looking better. We think natural gas prices will average closer to $3.25/mcf next year and $4/Mcf the year after. Yes, we think the gas price bottom that we saw earlier this year, $2/Mcf, is well behind us. Directionally, things should continue to improve.

TER: Should investors be bullish on any segment in energy right now? If so, which ones?

MA: In light of our relatively bearish overall stance on crude, we don't have any Strong Buy recommendations in our oil services universe. We're not recommending a whole lot of exploration and production (E&P) names at this stage either. The ones that we think do perform here are refiners that benefit from the price differential between West Texas Intermediate (WTI) and Brent crude. In addition, infrastructure companies such as master limited partnerships (MLPs) and companies that service either pipelines, refineries or other new infrastructure should outperform over the next several years.

TER: Any final thoughts?

MA: The bottom line is that we have a tough six months ahead of us for crude oil prices as inventories continue to build in Q1/13. Sometime in early 2013, oil prices should deteriorate as much as 30% from where we are today and hit bottom in mid-2013. At that point, we'll probably get a lot more constructive on oil services and E&P names.

TER: Thank you very much.

MA: Thank you for having me.

Marshall Adkins focuses on oilfield services and products, in addition to leading the Raymond James energy research team. He and his group have won a number of honors for stock-picking abilities over the past 15 years. Additionally, his group is well known for its deep insight into oil and gas fundamentals. Prior to joining Raymond James in 1995, Adkins spent 10 years in the oilfield services industry as a project manager, corporate financial analyst, sales manager, and engineer. He holds a Bachelor of Science degree in petroleum engineering and a Master of Business Administration from the University of Texas at Austin.


DISCLOSURE:
From time to time, Streetwise Reports LLC and its directors, officers, employees or members of their families, as well as persons interviewed for articles on the site, may have a long or short position in securities mentioned and may make purchases and/or sales of those securities in the open market or otherwise.

Liquid Flowmeters

An overview of types and capabilities, plus guidelines on selection, installation, and maintenance

INTRODUCTION

Measuring the flow of liquids is a critical need in many industrial plants. In some operations, the ability to conduct accurate flow measurements is so important that it can make the difference between making a profit or taking a loss. In other cases, inaccurate flow measurements or failure to take measurements can cause serious (or even disastrous) results.

With most liquid flow measurement instruments, the flow rate is determined inferentially by measuring the liquid's velocity or the change in kinetic energy. Velocity depends on the pressure differential that is forcing the liquid through a pipe or conduit. Because the pipe's cross-sectional area is known and remains constant, the average velocity is an indication of the flow rate. The basic relationship for determining the liquid's flow rate in such cases is:

Q = V x A

where

Q = liquid flow through the pipe

V = average velocity of the flow

A = cross-sectional area of the pipe

Other factors that affect liquid flow rate include the liquid's viscosity and density, and the friction of the liquid in contact with the pipe.

Direct measurements of liquid flows can be made with positive-displacement flowmeters. These units divide the liquid into specific increments and move it on. The total flow is an accumulation of the measured increments, which can be counted by mechanical or electronic techniques.

Reynolds Numbers

The performance of flowmeters is also influenced by a dimensionless unit called the Reynolds Number. It is defined as the ratio of the liquid's inertial forces to its drag forces.


Figure 1: Laminar and turbulent flow are two types normally encountered in liquid flow Measurement operations. Most applications involve turbulent flow, with R values above 3000. Viscous liquids usually exhibit laminar flow, with R values below 2000. The transition zone between the two levels may be either laminar or turbulent.

The equation is:

R = 3160 x Q x Gt
D x µ

where:

R = Reynolds number

Q = liquid's flow rate, gpm

Gt = liquid's specific gravity

D = inside pipe diameter, in.

µ = liquid's viscosity, cp

The flow rate and the specific gravity are inertia forces, and the pipe diameter and viscosity are drag forces. The pipe diameter and the specific gravity remain constant for most liquid applications. At very low velocities or high viscosities, R is low, and the liquid flows in smooth layers with the highest velocity at the center of the pipe and low velocities at the pipe wall where the viscous forces restrain it. This type of flow is called laminar flow. R values are below approximately 2000. A characteristic of laminar flow is the parabolic shape of its velocity profile, Fig. 1.

However, most applications involve turbulent flow, with R values above 3000. Turbulent flow occurs at high velocities or low viscosities. The flow breaks up into turbulent eddies that flow through the pipe with the same average velocity. Fluid velocity is less significant, and the velocity profile is much more uniform in shape. A transition zone exists between turbulent and laminar flows. Depending on the piping configuration and other installation conditions, the flow may be either turbulent or laminar in this zone.

FLOWMETER TYPES

Numerous types of flowmeters are available for closed-piping systems. In general, the equipment can be classified as differential pressure, positive displacement, velocity, and mass meters. Differential pressure devices (also known as head meters) include orifices, venturi tubes, flow tubes, flow nozzles, pitot tubes, elbow-tap meters, target meters, and variable-area meters, Fig. 2.

Positive displacement meters include piston, oval-gear, nutating-disk, and rotary-vane types. Velocity meters consist of turbine, vortex shedding, electromagnetic, and sonic designs. Mass meters include Coriolis and thermal types. The measurement of liquid flows in open channels generally involves weirs and flumes.

Space limitations prevent a detailed discussion of all the liquid flowmeters available today. However, summary characteristics of common devices are shown in Table 1. (Click here to see Table1) Brief descriptions follow.

Differential Pressure Meters

The use of differential pressure as an inferred measurement of a liquid's rate of flow is well known. Differential pressure flowmeters are, by far, the most common units in use today. Estimates are that over 50 percent of all liquid flow measurement applications use this type of unit.

The basic operating principle of differential pressure flowmeters is based on the premise that the pressure drop across the meter is proportional to the square of the flow rate. The flow rate is obtained by measuring the pressure differential and extracting the square root.

Differential pressure flowmeters, like most flowmeters, have a primary and secondary element. The primary element causes a change in kinetic energy, which creates the differential pressure in the pipe. The unit must be properly matched to the pipe size, flow conditions, and the liquid's properties. And, the measurement accuracy of the element must be good over a reasonable range. The secondary element measures the differential pressure and provides the signal or read-out that is converted to the actual flow value.

Orifices are the most popular liquid flowmeters in use today. An orifice is simply a flat piece of metal with a specific-sized hole bored in it. Most orifices are of the concentric type, but eccentric, conical (quadrant), and segmental designs are also available.

In practice, the orifice plate is installed in the pipe between two flanges. Acting as the primary device, the orifice constricts the flow of liquid to produce a differential pressure across the plate. Pressure taps on either side of the plate are used to detect the difference. Major advantages of orifices are that they have no moving parts and their cost does not increase significantly with pipe size.

Conical and quadrant orifices are relatively new. The units were developed primarily to measure liquids with low Reynolds numbers. Essentially constant flow coefficients can be maintained at R values below 5000. Conical orifice plates have an upstream bevel, the depth and angle of which must be calculated and machined for each application.

The segmental wedge is a variation of the segmental orifice. It is a restriction orifice primarily designed to measure the flow of liquids containing solids. The unit has the ability to measure flows at low Reynolds numbers and still maintain the desired square-root relationship. Its design is simple, and there is only one critical dimension the wedge gap. Pressure drop through the unit is only about half that of conventional orifices.

Integral wedge assemblies combine the wedge element and pressure taps into a one-piece pipe coupling bolted to a conventional pressure transmitter. No special piping or fittings are needed to install the device in a pipeline.

Metering accuracy of all orifice flowmeters depends on the installation conditions, the orifice area ratio, and the physical properties of the liquid being measured.

Venturi tubes have the advantage of being able to handle large flow volumes at low pressure drops. A venturi tube is essentially a section of pipe with a tapered entrance and a straight throat. As liquid passes through the throat, its velocity increases, causing a pressure differential between the inlet and outlet regions.

The flowmeters have no moving parts. They can be installed in large diameter pipes using flanged, welded or threaded-end fittings. Four or more pressure taps are usually installed with the unit to average the measured pressure. Venturi tubes can be used with most liquids, including those having a high solids content.

Flow tubes are somewhat similar to venturi tubes except that they do not have the entrance cone. They have a tapered throat, but the exit is elongated and smooth. The distance between the front face and the tip is approximately one-half the pipe diameter. Pressure taps are located about one-half pipe diameter downstream and one pipe diameter upstream.

Flow Nozzles, at high velocities, can handle approximately 60 percent greater liquid flow than orifice plates having the same pressure drop. Liquids with suspended solids can also be metered. However, use of the units is not recommended for highly viscous liquids or those containing large amounts of sticky solids.

Pitot tubes sense two pressures simultaneously, impact and static. The impact unit consists of a tube with one end bent at right angles toward the flow direction. The static tube's end is closed, but a small slot is located in the side of the unit. The tubes can be mounted separately in a pipe or combined in a single casing.

Pitot tubes are generally installed by welding a coupling on a pipe and inserting the probe through the coupling. Use of most pitot tubes is limited to single point measurements. The units are susceptible to plugging by foreign material in the liquid. Advantages of pitot tubes are low cost, absence of moving parts, easy installation, and minimum pressure drop.

Elbow meters operate on the principle that when liquid travels in a circular path, centrifugal force is exerted along the outer edges. Thus, when liquid flows through a pipe elbow, the force on the elbow's interior surface is proportional to the density of the liquid times the square of its velocity. In addition, the force is inversely proportional to the elbow's radius.

Any 90 deg. pipe elbow can serve as a liquid flowmeter. All that is required is the placement of two small holes in the elbow's midpoint (45 deg. point) for piezometer taps. Pressure-sensing lines can be attached to the taps by using any convenient method.

Target meters sense and measure forces caused by liquid impacting on a target or drag-disk suspended in the liquid stream. A direct indication of the liquid flow rate is achieved by measuring the force exerted on the target. In its simplest form, the meter consists only of a hinged, swinging plate that moves outward, along with the liquid stream. In such cases, the device serves as a flow indicator.

A more sophisticated version uses a precision, low-level force transducer sensing element. The force of the target caused by the liquid flow is sensed by a strain gage. The output signal from the gage is indicative of the flow rate. Target meters are useful for measuring flows of dirty or corrosive liquids.

Variable-area meters, often called rotameters, consist essentially of a tapered tube and a float, Fig. 3. Although classified as differential pressure units, they are, in reality, constant differential pressure devices. Flanged-end fittings provide an easy means for installing them in pipes. When there is no liquid flow, the float rests freely at the bottom of the tube. As liquid enters the bottom of the tube, the float begins to rise. The position of the float varies directly with the flow rate. Its exact position is at the point where the differential pressure between the upper and lower surfaces balance the weight of the float.

Because the flow rate can be read directly on a scale mounted next to the tube, no secondary flow-reading devices are necessary. However, if desired, automatic sensing devices can be used to sense the float's level and transmit a flow signal. Rotameter tubes are manufactured from glass, metal, or plastic. Tube diameters vary from 1/4 to greater than 6 in.

Positive-Displacement Meters

Operation of these units consists of separating liquids into accurately measured increments and moving them on. Each segment is counted by a connecting register. Because every increment represents a discrete volume, positive-displacement units are popular for automatic batching and accounting applications. Positive-displacement meters are good candidates for measuring the flows of viscous liquids or for use where a simple mechanical meter system is needed.

Reciprocating piston meters are of the single and multiple-piston types. The specific choice depends on the range of flow rates required in the particular application. Piston meters can be used to handle a wide variety of liquids. A magnetically driven, oscillating piston meter is shown in Fig. 4. Liquid never comes in contact with gears or other parts that might clog or corrode.

Oval-gear meters have two rotating, oval-shaped gears with synchronized, close fitting teeth. A fixed quantity of liquid passes through the meter for each revolution. Shaft rotation can be monitored to obtain specific flow rates.

Nutating-disk meters have a moveable disk mounted on a concentric sphere located in a spherical side-walled chamber. The pressure of the liquid passing through the measuring chamber causes the disk to rock in a circulating path without rotating about its own axis. It is the only moving part in the measuring chamber.

A pin extending perpendicularly from the disk is connected to a mechanical counter that monitors the disk's rocking motions. Each cycle is proportional to a specific quantity of flow. As is true with all positive-displacement meters, viscosity variations below a given threshold will affect measuring accuracies. Many sizes and capacities are available. The units can be made from a wide selection of construction materials.

Rotary-vane meters are available in several designs, but they all operate on the same principle. The basic unit consists of an equally divided, rotating impeller (containing two or more compartments) mounted inside the meter's housing. The impeller is in continuous contact with the casing. A fixed volume of liquid is swept to the meter's outlet from each compartment as the impeller rotates. The revolutions of the impeller are counted and registered in volumetric units.

Helix flowmeters consist of two radically pitched helical rotors geared together, with a small clearance between the rotors and the casing. The two rotors displace liquid axially from one end of the chamber to the other.

Velocity Meters

These instruments operate linearly with respect to the volume flow rate. Because there is no square-root relationship (as with differential pressure devices), their rangeability is greater. Velocity meters have minimum sensitivity to viscosity changes when used at Reynolds numbers above 10,000. Most velocity-type meter housings are equipped with flanges or fittings to permit them to be connected directly into pipelines.

Turbine meters have found widespread use for accurate liquid measurement applications. The unit consists of a multiple-bladed rotor mounted with a pipe, perpendicular to the liquid flow. The rotor spins as the liquid passes through the blades. The rotational speed is a direct function of flow rate and can be sensed by magnetic pick-up, photoelectric cell, or gears. Electrical pulses can be counted and totalized, Fig. 5.

The number of electrical pulses counted for a given period of time is directly proportional to flow volume. A tachometer can be added to measure the turbine's rotational speed and to determine the liquid flow rate. Turbine meters, when properly specified and installed, have good accuracy, particularly with low-viscosity liquids.

A major concern with turbine meters is bearing wear. A "bearingless" design has been developed to avoid this problem. Liquid entering the meter travels through the spiraling vanes of a stator that imparts rotation to the liquid stream. The stream acts on a sphere, causing it to orbit in the space between the first stator and a similarly spiraled second stator. The orbiting movement of the sphere is detected electronically. The frequency of the resulting pulse output is proportional to flow rate.

Vortex meters make use of a natural phenomenon that occurs when a liquid flows around a bluff object. Eddies or vortices are shed alternately downstream of the object. The frequency of the vortex shedding is directly proportional to the velocity of the liquid flowing through the meter, Fig. 6.

The three major components of the flowmeter are a bluff body strut-mounted across the flowmeter bore, a sensor to detect the presence of the vortex and to generate an electrical impulse, and a signal amplification and conditioning transmitter whose output is proportional to the flow rate, Fig. 7. The meter is equally suitable for flow rate or flow totalization measurements. Use for slurries or high viscosity liquids is not recommended.

Electromagnetic meters can handle most liquids and slurries, providing that the material being metered is electrically conductive. Major components are the flow tube (primary element), Fig. 8. The flow tube mounts directly in the pipe. Pressure drop across the meter is the same as it is through an equivalent length of pipe because there are no moving parts or obstructions to the flow. The voltmeter can be attached directly to the flow tube or can be mounted remotely and connected to it by a shielded cable.

Electromagnetic flowmeters operate on Faraday's law of electromagnetic induction that states that a voltage will be induced when a conductor moves through a magnetic field. The liquid serves as the conductor; the magnetic field is created by energized coils outside the flow tube, Fig. 9. The amount of voltage produced is directly proportional to the flow rate. Two electrodes mounted in the pipe wall detect the voltage, which is measured by the secondary element.

Electromagnetic flowmeters have major advantages: They can measure difficult and corrosive liquids and slurries; and they can measure forward as well as reverse flow with equal accuracy. Disadvantages of earlier designs were high power consumption, and the need to obtain a full pipe and no flow to initially set the meter to zero. Recent improvements have eliminated these problems. Pulse-type excitation techniques have reduced power consumption, because excitation occurs only half the time in the unit. Zero settings are no longer required.

Ultrasonic flowmeters can be divided into Doppler meters and time-of-travel (or transit) meters. Doppler meters measure the frequency shifts caused by liquid flow. Two transducers are mounted in a case attached to one side of the pipe. A signal of known frequency is sent into the liquid to be measured. Solids, bubbles, or any discontinuity in the liquid, cause the pulse to be reflected to the receiver element, Fig. 10. Because the liquid causing the reflection is moving, the frequency of the returned pulse is shifted. The frequency shift is proportional to the liquid's velocity.

A portable Doppler meter capable of being operated on AC power or from a rechargeable power pack has recently been developed. The sensing heads are simply clamped to the outside of the pipe, and the instrument is ready to be used. Total weight, including the case, is 22 lb. A set of 4 to 20 millampere output terminals permits the unit to be connected to a strip chart recorder or other remote device.

Time-of-travel meters have transducers mounted on each side of the pipe. The configuration is such that the sound waves traveling between the devices are at a 45 deg. angle to the direction of liquid flow. The speed of the signal traveling between the transducers increases or decreases with the direction of transmission and the velocity of the liquid being measured. A time-differential relationship proportional to the flow can be obtained by transmitting the signal alternately in both directions. A limitation of time-of-travel meters is that the liquids being measured must be relatively free of entrained gas or solids to minimize signal scattering and absorption.

Mass Flowmeters The continuing need for more accurate flow measurements in mass-related processes (chemical reactions, heat transfer, etc.) has resulted in the development of mass flowmeters. Various designs are available, but the one most commonly used for liquid flow applications is the Coriolis meter. Its operation is based on the natural phenomenon called the Coriolis force, hence the name.

Coriolis meters are true mass meters that measure the mass rate of flow directly as opposed to volumetric flow. Because mass does not change, the meter is linear without having to be adjusted for variations in liquid properties. It also eliminates the need to compensate for changing temperature and pressure conditions. The meter is especially useful for measuring liquids whose viscosity varies with velocity at given temperatures and pressures.

Coriolis meters are also available in various designs. A popular unit consists of a U-shaped flow tube enclosed in a sensor housing connected to an electronics unit. The sensing unit can be installed directly into any process. The electronics unit can be located up to 500 feet from the sensor.

Inside the sensor housing, the U-shaped flow tube is vibrated at its natural frequency by a magnetic device located at the bend of the tube. The vibration is similar to that of a tuning fork, covering less than 0.1 in. and completing a full cycle about 80 times/sec. As the liquid flows through the tube, it is forced to take on the vertical movement of the tube, Fig. 11. When the tube is moving upward during half of its cycle, the liquid flowing into the meter resists being forced up by pushing down on the tube.

Having been forced upward, the liquid flowing out of the meter resists having its vertical motion decreased by pushing up on the tube. This action causes the tube to twist. When the tube is moving downward during the second half of its vibration cycle, it twists in the opposite direction.

Having been forced upward, the liquid flowing out of the meter resists having its vertical motion decreased by pushing up on the tube. This action causes the tube to twist. When the tube is moving downward during the second half of its vibration cycle, it twists in the opposite direction. The ammount of twist is directly proportional to the mass flow rate of the liquid flowing through the tube. Magnetic sensors located on each side of the flow tube measure the tube velocities, which change as the tube twists. The sensors feed this information to the electronics unit, where it is processed and converted to a voltage proportional to mass flow rate. The meter has a wide range of applications from adhesives and coatings to liquid nitrogen.

Thermal-type mass flowmeters have traditionally been used for gas measurements, but designs for liquid flow measurements are available. These mass meters also operate independent of density, pressure, and viscosity. Thermal meters use a heated sensing element isolated from the fluid flow path. The flow stream conducts heat from the sensing element. The conducted heat is directly proportional to the mass flow rate. The sensor never comes into direct contact with the liquid, Fig. 12. The electronics package includes the flow analyzer, temperature compensator, and a signal conditioner that provides a linear output directly proportional to mass flow.

Open Channel Meters

The "open channel" refers to any conduit in which liquid flows with a free surface. Included are tunnels, nonpressurized sewers, partially filled pipes, canals, streams, and rivers. Of the many techniques available for monitoring open-channel flows, depth-related methods are the most common. These techniques presume that the instantaneous flow rate may be determined from a measurement of the water depth, or head. Weirs and flumes are the oldest and most widely used primary devices for measuring open-channel flows.

Weirs operate on the principle that an obstruction in a channel will cause water to back up, creating a high level (head) behind the barrier. The head is a function of flow velocity, and, therefore, the flow rate through the device. Weirs consist of vertical plates with sharp crests. The top of the plate can be straight or notched. Weirs are classified in accordance with the shape of the notch. The basic types are V-notch, rectangular, and trapezoidal.

Flumes are generally used when head loss must be kept to a minimum, or if the flowing liquid contains large amounts of suspended solids. Flumes are to open channels what venturi tubes are to closed pipes. Popular flumes are the Parshall and Palmer-Bowlus designs.

The Parshall flume consists of a converging upstream section, a throat, and a diverging downstream section. Flume walls are vertical and the floor of the throat is inclined downward. Head loss through Parshall flumes is lower than for other types of open-channel flow measuring devices. High flow velocities help make the flume self-cleaning. Flow can be measured accurately under a wide range of conditions.

Palmer-Bowlus flumes have a trapezoidal throat of uniform cross section and a length about equal to the diameter of the pipe in which it is installed. It is comparable to a Parshall flume in accuracy and in ability to pass debris without cleaning. A principal advantage is the comparative ease with which it can be installed in existing circular conduits, because a rectangular approach section is not required.

Discharge through weirs and flumes is a function of level, so level measurement techniques must be used with the equipment to determine flow rates. Staff gages and float-operated units are the simplest devices used for this purpose. Various electronic sensing, totalizing, and recording systems are also available.

A more recent development consists of using ultrasonic pulses to measure liquid levels. Measurements are made by sending sound pulses from a sensor to the surface of the liquid, and timing the echo return. Linearizing circuitry converts the height of the liquid into flow rate. A strip chart recorder logs the flow rate, and a digital totalizer registers the total gallons. Another recently introduced microprocessor-based system uses either ultrasonic or float sensors. A key-pad with an interactive liquid crystal display simplifies programming, control, and calibration tasks.

SELECTING A FLOWMETER

Experts claim that over 75 percent of the flowmeters installed in industry are not performing satisfactorily. And improper selection accounts for 90 percent of these problems. Obviously, flowmeter selection is no job for amateurs. The major steps involved in the selection process are shown in Fig. 13.

The most important requirement is knowing exactly what the instrument is supposed to do. Here are some questions to consider. Is the measurement for process control (where repeatability is the major concern), or for accounting or custody transfer (where high accuracy is important)? Is local indication or a remote signal required? If a remote output is required, is it to be a proportional signal, or a contact closure to start or stop another device? Is the liquid viscous, clean, or a slurry? Is it electrically conductive? What is its specific gravity or density? What flow rates are involved in the application? What are the processes' operating temperatures and pressures? Accuracy (see glossary), range, linearity, repeatability, and piping requirements must also be considered.

It is just as important to know what a flowmeter cannot do as well as what it can do before a final selection is made. Each instrument has advantages and disadvantages, and the degree of performance satisfaction is directly related to how well an instrument's capabilities and shortcomings are matched to the application's requirements. Often, users have expectations of a flowmeter's performance that are not consistent with what the supplier has provided. Most suppliers are anxious to help customers pick the right flowmeter for a particular job. Many provide questionnaires, checklists, and specification sheets designed to obtain the critical information necessary to match the correct flowmeter to the job.

Technological improvements of flowmeters must be considered also. For example, a common mistake is to select a design that was most popular for a given application some years ago and to assume that it is still the best instrument for the job. Many changes and innovations may have occurred in recent years in the development of flowmeters for that particular application, making the choice much broader.

A recent development is the availability of computer programs to perform the tedious calculations often necessary for selecting flowmeters. Calculations that used to take an hour can be performed in a matter of seconds (see accompanying section, "Selected Reference Material").

Click Here For Questions To Ask When Selecting A Flowmeter

Cost Considerations

There are a wide range of prices for flowmeters. Rotameters are usually the least expensive, with some small-sized units available for less than $100. Mass flowmeters cost the most. Prices start at about $3500. However, total system costs must always be considered when selecting flowmeters. For example, an orifice plate may cost only about $50. But the transmitter may add an additional $500 or $600, and sensing line fabrication and installation may cost even more.

Installation, operation, and maintenance costs are important economic factors too. Servicing can be expensive on some of the more complicated designs.

As with many other products, a plant engineer generally gets what he pays for when he purchases a flowmeter. But the satisfaction that he receives with the product will depend on the care that he uses in selecting and installing the instrument. And that gets back to knowing the process, the products, and the flow-metering requirements. "Overbuying" is not uncommon. Plant engineers should not buy a flowmeter more capable or complicated than they need.

WORKING WITH FLOWMETERS

Although suppliers are always ready to provide flowmeter installation service, estimates are that approximately 75 percent of the users install their own equipment. But installation mistakes are made. One of the most common is not allowing sufficient upstream and downstream straight-run piping for the flowmeter.

Every design has a certain amount of tolerance to nonstable velocity conditions in the pipe, but all units require proper piping configurations to operate efficiently. Proper piping provides a normal flow pattern for the device. Without it, accuracy and performance are adversely affected. Flowmeters are also installed backwards on occasion (especially true with orifice plates). Pressure-sensing lines may be reversed too.

With electrical components, intrinsic safety is an important consideration in hazardous areas. Most flowmeter suppliers offer intrinsically safe designs for such uses.

Stray magnetic fields exist in most industrial plants. Power lines, relays, solenoids, transformers, motors, and generators all contribute their share of interference. Users must ensure themselves that the flowmeter they have selected is immune to such interference. Problems occur primarily with the electronic components in secondary elements, which must be protected. Strict adherence to the manufacturer's recommended installation practices will usually prevent such problems.

Calibration

All flowmeters require an initial calibration. Most of the time, the instrument is calibrated by the manufacturer for the specified service conditions. However, if qualified personnel are available in the plant, the user can perform his own calibrations.

The need to recalibrate depends to a great extent on how well the meter fits the application. Some liquids passing through flowmeters tend to be abrasive, erosive, or corrosive. In time, portions of the device will deteriorate sufficiently to affect performance. Some designs are more susceptible to damage than others. For example, wear of individual turbine blades will cause performance changes. If the application is critical, flowmeter accuracy should be checked at frequent intervals. In other cases, recalibration may not be necessary for years because the application is noncritical, or nothing will change the meter's performance. Some flowmeters require special equipment for calibration. Most manufacturers will provide such service in their plant or in the user's facility, where they will bring the equipment for on-site calibration.

Maintenance

A number of factors influence maintenance requirements and the life expectancy of flowmeters. The major factor, of course, is matching the right instrument to the particular application. Poorly selected devices invariably will cause problems at an early date. Flowmeters with no moving parts usually will require less attention than units with moving parts. But all flowmeters eventually require some kind of maintenance.

Primary elements in differential pressure flowmeters require extensive piping, valves, and fittings when they are connected to their secondary elements, so maintenance may be a recurring effort in such installations. Impulse lines can plug or corrode and have to be cleaned or replaced. And, improper location of the secondary element can result in measurement errors. Relocating the element can be expensive.

Flowmeters with moving parts require periodic internal inspection, especially if the liquid being metered is dirty or viscous. Installing filters ahead of such units will help minimize fouling and wear. Obstructionless instruments, such as ultrasonic or electromagnetic meters, may develop problems with their secondary element's electronic components. Pressure sensors associated with secondary elements should be periodically removed and inspected.

Applications where coatings may occur are also potential problems for obstructionless instruments such as magnetic or ultrasonic units. If the coating is insulating, the operation of magnetic flowmeters will ultimately be impaired if the electrodes are insulated from the liquid. This condition will be prevented by periodic cleaning. With ultrasonic flowmeters, refraction angles may change and the sonic energy absorbed by the coating will cause the meter to become inoperative.

Reprinted with permission from Plant Engineering Magazine,November 21, 1984. © by Cahners Publishing Company.




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Wednesday, September 26, 2012

FUNDAMENTALS OF ORIFICE METERING

 

Bill Buckley


 

 Introduction


The purpose to this paper is to discuss the fundamental components used in orifice measurement.


Background


The general concepts of head meters, which include the orifice, have been known for centuries. The orifice has been in commercial use since the early 1900's. The device is used to create a differential pressure that relates to the velocity of the gas from which a flow rate can be calculated. As the following gas passes through the restriction in the line caused by the orifice plate, the difference in the upstream and downstream pressure can be measured at set points, called taps, and a flow rate at the point can be determined.

 

Figure 1. Head Meter


Standards and Importance


Orifice measurement is guided by the standards of several organizations. Primary among these is the American Gas Association and the American Petroleum Institute. The AGA #3 report is the standard that provides guidelines for the construction and installation of orifice meters. All orifice plates, holding devices, and meter tubes should be manufactured adhering to this standard in order to help ensure that the end product is an accurate measurement device.


Orifice Plates


The most fundamental component of orifice measurement is the orifice plate. This is typically a circular, flat device, which is held in the flowing stream by a holding device. Typically, it is made of a durable metal such as stainless steel. Orifice plates come in two types, the paddle plate and the universal plate. The paddle plate is held in place by flanges, while the universal plate fits into the various types of holding devices. AGA #3 standards spell out specific requirements for the orifice plates, including the concentricity of the orifice bore, the surface finish, flatness of the plate, and edge thickness. While the orifice plate is the least expensive of the components in orifice measurement, its importance should not be overlooked.


Figure 2. Orifice Plates


Orifice Devices


There are primarily three different types of devices used to help center an orifice plate in the flowing medium. The first and least expensive is the orifice flange union. This is a pair of flanges, which has been tapped to provide a differential reading. While it is the least expensive to purchase, it requires a higher maintenance level since the line must be bled down and the flanges spread apart in order to remove the plate.


The next device type is the single chamber orifice fitting. The single chamber device has an advantage over flanges in that it makes removal of the plate easier and safer due to the prevention of spillage that occurs when flanges are spread apart. Like flanges, however, the simplex device requires that the line pressure be bled off before the plate may be removed. The simplex device utilizes universal type orifice plates.



Figure 3. Orifice Flange Union Figure

4. Single Chamber Fitting

 

The third device is the dual chamber orifice fitting. This fitting allows for the removal of the universal orifice plate without first bleeding down line pressure. This is accomplished through the use of internal valves, which isolate the upper (non-pressure) chamber from the bottom (pressured) chamber. The senior type is the most expensive of the plate holding devices to purchase, but could be the most economical when compared to the overall cost of the installation, since isolation valving is not required to allow plate removal.


Figure 5. Dual Chamber Fitting

 

Meter Tubes


A meter tube basically consists of upstream tubing, the orifice fitting or flanges and downstream tubing. The purpose of tubing is to insure as smooth a flow profile, going into the orifice plate, as possible. The AGA #3 standard has very specific requirements for meter tube pipe, including the smoothness of the inside surface of the tubing and minimum lengths required under particular installations. If these standards are not met in the manufacture of the meter tube, then degradation in measurement could result.

 

Figure 6. Three-Section Meter Tube


Straightening Vanes and Flow Conditioners


Straightening vanes are bundles of small diameter tubing, which are placed inside the upstream section of a meter tube. They are commonly of two types, flanged and in-line. The flanged types are held in the line between a pair of flanges in the upstream. The in-line vane is held in place inside the tubing by setscrews. Their purpose is to facilitate the smoothing of flow going into the orifice plate while allowing for shorter upstream tubing lengths.

 

Figure 7. Straightening Vanes

 

The flow conditioners eliminate swirl like a straightening vane and, also, generate a near fully-developed flow profile. The conditioner also reduces the amount of required upstream tubing needed to meet AGA #3 requirements.


Figure 8. Flow Conditioner


Secondary Devices


The orifice fitting with its orifice plate is known as the primary devices in the orifice measurement package. There are other devices known as secondary devices, which translate the raw information from primary devices into more useable information. The most common of these are pneumatic chart recorders and flow computers.


The pneumatic chart recorder presents the information from the differential pressure, static pressure, and temperature transmitters in a graphical form, usually circular charts. The chart usually represents a 24-hour or 8-day period, which can be integrated later to provide volume figures.


Figure 9. Secondary Devices


Flow computers have increased in use in recent years due to the requirements for measurement information on a more "real time" basis. Flow computers, like the pneumatic chart, take the flow information from the differential pressure, static pressure, and the temperature transmitter and calculates flow volumes. Unlike the chart, flow computers do not have to go through an integration step to come up with these figures. There are several levels of sophistication available in flow computers. The battery-powered, solar charged devices have the best utility as field devices, which can store the flow information on site, do the volume calculations and then send that information on to a higher device such as a mainframe computer. The higher-level flow computers are usually AC or DC powered and provide not only the same calculations capability as the solar–powered units, but also have advanced flow control and alarm capabilities.


Conclusion


The latest AGA #3/API MPMS Chapter 14.3 measurement standard has greatly tightened the tolerances for the manufacture of orifice devices and meter tubes. It is very much in the best interest of the users of these devices to have sound maintenance programs in place to insure that the like-new quality of the tubes be maintained for as long as possible. The primary device, whether a fitting or flange, cannot be expected to provide accurate, reliable flow information if the orifice plate is bowed or otherwise degraded in some way. The vast body of data supporting orifice measurement over the years becomes meaningless if the guidelines for the design, manufacture, installation and maintenance of these devices are not followed.


Bill Buckley

Daniel Measurement and Control

P.O. Box 19097

Houston, Texas 77224


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