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PEH:Liquid and Gas Measurement

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Publication Information

Vol3FCECover.png

Petroleum Engineering Handbook

Larry W. Lake, Editor-in-Chief

Volume III – Facilities and Construction Engineering

Kenneth E. Arnold, Editor

Chapter 11 – Liquid and Gas Measurement

Marsha Yon Daniel, Measurement & Controls Inc., Kevin L. Warner and Tom Mooney, Daniel Industries Inc.

Pgs. 439-460

ISBN 978-1-55563-118-5
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Liquid Meters—Marsha Yon

Introduction

Flow measurement begins with a properly operating flowmeter; however, measurement procedures and correct flow calculations equally contribute to good overall system performance. Guidelines for liquid hydrocarbon measurement are detailed in the American Petroleum Institute’s (API’s) Manual of Petroleum Measurement Standards (MPMS), a comprehensive, ongoing publication in which chapters are periodically revised and then released. Commonly referenced standards include: Chap. 4 "Proving Systems," Chap. 5 "Metering," Chap. 7 "Temperature Determination," Chap. 9 "Density Determination," Chap. 11 "Physical Properties Data," Chap. 12 "Calculation of Petroleum Quantities," Chap. 13 "Statistical Aspects of Measuring and Sampling," Chap. 14 "Natural Gas Fluids Measurement," and Chap. 21 "Flow Measurement Using Electronic Metering Systems."

The information in this chapter covers the characteristics of three types of flowmeters that are commonly used for the measurement of liquid hydrocarbons: the selection criteria for a flowmeter, the basics of field meter proving, and specifics on the design and operation of a lease automated custody transfer (LACT) system.

Liquid flowmeters can be classified in two general areas: (1) a positive displacement meter that continuously divides the flowing stream into known volumetric segments, isolating the segments momentarily and returning it to the flowing stream while counting the number of displacements; and (2) an inference meter that "infers" flow by measuring some dynamic property of the flowing stream. Typical inference meters are turbine meters that infer flow by monitoring impeller speed, orifice meters that monitor pressure differential, and the Coriolis meter, which senses the Coriolis force on vibrating tubes to infer flow rate.

Positive Displacement Meters

Positive displacement (PD) liquid meters have long been the standard of measurement for liquid hydrocarbons such as crude oil. Over the years, numerous design improvements have resulted in an expanded product line that now serves industrial as well as petroleum applications.

Theory of Operation of PD Meters. A liquid meter is, in essence, a hydraulic motor with high volumetric efficiency that absorbs a small amount of energy from the flowing stream. This energy is used to overcome internal friction in driving the meter and its accessories and is reflected as a pressure drop across the meter. Pressure drop is regarded as a necessary evil that must be minimized. Pressure drop across the internals of a PD meter actually creates a hydraulically unbalanced rotor, which causes rotation. A PD meter can be broken down into three basic components. These are the external housing, the measuring unit, and the counter drive train. See Fig. 11A.1.


The external housing is the pressure vessel that contains the product being metered. It can be a single- or double-case construction. A single-case meter has the housing and the measuring chamber walls as one integral unit. In double-case construction, the external housing is separate from the measuring unit and serves only as a pressure vessel. This type of construction has two major advantages: (1) the measuring chamber walls only sense the delta pressure across the meter inlet and outlet, which allows for thinner chamber walls with less distortion, and (2) system piping stresses that are absorbed in the external housing are not transmitted to the precision measuring element.

The measuring unit is a precision metering element and is made up of the measuring chamber and the displacement mechanism. The six PD designs most commonly used are the piston, sliding vane, oval, trirotor, birotor, and disc. See Fig. 11A.2.


The counter drive train is used to transmit the internal motion of the measuring unit into a usable output signal. Many PD meters use a mechanical gear train, which requires a rotary shaft seal or packing gland where the shaft penetrates the external housing. Other meters may use magnetic drive couplings, reed switch outputs (contact closure), and differential inductance (DL) pickoffs. These last three offer the advantages of lower driving torque and no seals that could leak the product.

Design Considerations for PD Meters. Most hydrocarbons are metered using a capillary seal PD meter. In this design meter, the capillary action of the metered product forms a liquid seal between moving and stationary parts. This type of meter requires very close clearance dimensions and is sensitive to differential pressure.

Product slippage is the most crucial problem affecting the accuracy of a capillary seal PD meter. All capillary seal PD meters have some clearance between moving and stationary parts and some differential pressure across these clearances. For this reason, there will always be some product that is allowed to bypass the measuring chamber by "slippage" through these clearances. If slippage were constant at all operating conditions, it could be corrected by the counter drive train gearing and would cause no inaccuracy. However, it is not constant and does vary with flow rate, pressure drop, temperature, viscosity, and clearance dimensions.

Turbine Flowmeters

Turbine flowmeters are an effective means of accurate measurement of liquid/gas products in many industries. Because of the turbine meter’s versatility and flexibility in product metering applications, it is one of the most widely used technologies in flow measurement.

Turbine meters were invented in the 18th century by Reinhard Woltman, and at that time were used for water-flow measurement. In the 1950s, turbine meters were first used for hydrocarbon measurement for aeronautical applications within aircraft. In 1970, the API recognized the turbine meter in MPMS Chap. 5 Sec. 3, "Measurement of Liquid Hydrocarbons by Turbine Meters."[1] With these published standards, the turbine meter gained recognition as a custody-transfer metering technology acceptable for use in liquid-petroleum-products metering systems. These systems include crude-oil production and pipelines, petroleum product pipelines, refinery applications, tanker loading and unloading, crude-oil terminals, and refined-product loading-rack terminals. For additional information about turbine meters and their use in gas measurement, see Sec. 11B.3 of this chapter.

Theory of Operation of Turbine Meters. Turbine meters are inferential measurement devices. They infer the volumetric flow rate based on the mechanical properties of the meter and the physical properties of the measured fluid. Turbine meters are a combination of a mechanical assembly and electronic components to measure volumetric flow rates. See Fig. 11A.3.


The turbine meter consists of a rotor with multiple blades mounted on a free-running bearing system. Fluid flow through the meter impinges on the turbine blades, causing the rotor to rotate on its axis along the centerline of the turbine-meter housing. The angular velocity to the turbine rotor is directly proportional to the fluid’s linear velocity through the meter housing. Given the fixed cross-sectional area of the meter housing and the linear velocity of the fluid through this area, the volumetric flow rate can be calculated.

A voltage pulse signal is produced as the rotor blade passes a magnetic pickup coil mounted externally on the meter housing. Each pulse represents a discrete volume of liquid. The number of pulses per unit volume is called the meter’s K-factor. The K-factor is determined during flow calibration and is unique to each and every meter. In smaller meter sizes, the unit of volume is typically given in gallons or liters. In larger meters, the unit of volume is typically given in barrels or cubic meters.

Coriolis Flowmeters

A meter utilizing the Coriolis force to measure mass flow rate was first patented in 1978. Most Coriolis meters can measure the density of the fluid in addition to the mass flow rate. Therefore, because volume flow rate is equal to mass flow rate divided by density, the associated electronics package can be programmed to output the volume flow rate. At this point, Coriolis meters become volume flow rate meters and can provide an output similar to such other meters as positive displacement and turbine meters. For additional information about Coriolis meters and their use in gas measurement, see Sec. 11B.5 of this chapter.

Theory of Operation of Coriolis Meters. The Coriolis force as first identified in 1835 refers to the deflection relative to the Earth’s surface of any object moving about the Earth. This force can also be produced on a vibrating tube(s). When a fluid moves through the vibrating tube(s), the Coriolis force causes the tube(s) to distort slightly. The degree of distortion is directly proportional to the mass flow rate of the fluid. Coriolis manufacturers use various proprietary techniques to monitor the magnitude of the distortion and process the measured signals into useable measurement information. As mass flow rate through the vibrating tube(s) increases, the offset in position or distortion monitored between the upstream and downstream portions of the tube(s) increases. See Fig. 11A.4 for a typical Coriolis meter design. In addition to measuring the Coriolis force, most meters are capable of utilizing the frequency of vibration of the tube(s) to measure density.


Coriolis Sensor Considerations. Most manufacturers offer a comprehensive sizing program that provides information regarding accuracy, flow rate, pressure drop, and velocity with any given fluid and process condition.

Coriolis meters offer the advantage of a large turndown ratio—more than twice the turndown of a turbine meter. Flow velocity through a Coriolis meter is generally high. Velocity should always be considered when sizing a meter for an erosive fluid with high solids content and when considering piping limitations including pressure drop. The pressure drop across the meter should be known in order to select the proper size sensor. For example, a 4-in. meter can handle a rate of 2,500 bbl/hr but has a pressure drop at this rate of 13 psi (with a viscosity of 1 cp). Pressure drop should always be considered with any flowmeter that is operating near a fluid’s equilibrium vapor pressure so that the fluid does not cavitate or flash at the metering point. Air or gas slugs do not damage the meter; however, Coriolis meters are not intended to meter multiphase fluids.

Coriolis Transmitter Considerations. Coriolis meters are electronic. They require power and some associated device that interprets the signals from the meter and provides useable digital, analog, or serial outputs. Most meters today have a separate device or transmitter, but advances in technology have produced meters that produce an output directly from the sensor. Whether in a separate housing or located on the meter, there is a central processing unit (CPU) that is programmed to provide the output required. The CPU is programmed with the meter’s calibration coefficients and is programmed to output in the required units of measurement. Because there is no movement or mechanical action in the meter that can be utilized to produce a pulse, the CPU is also programmed to produce the pulse required for proving and for totalization.

Given the capabilities of electronics today, additional features such as alarm and control outputs, averaging, and calculation of relative density are easily a part of a Coriolis transmitter. Because the Coriolis meter is programmable, the means of configuring the meter should be understood in addition to the security of the device after installation in the field.

Metering System Design

Certain basic installation requirements are needed for proper operation of a positive displacement meter or a turbine meter. As a minimum, strainers, adequate upstream and downstream straight pipe, flow conditioning, and a downstream control valve are required. These meters operate best with clean fluid streams. Debris in the flow stream that is allowed to pass through the meter limits the life of the meter. A strainer or filter upstream of the meter should be utilized. A properly sized strainer that captures the destructive debris and keeps pressure drop to a minimum is a vital piece of equipment in a metering system.

Positive displacement and turbine meters are susceptible to disturbances in the flow stream. Flow disturbances can be caused by any upstream piping configuration that results in distortion of the fluid flow profile. Elbows and bends in the pipe upstream of the meter can produce a bulk swirl in the flowing fluid, which, if left uncorrected, could result in very unreliable measurements. For this reason, it is recommended that the meter be installed in a properly-sized run of pipe (or specially manufactured meter tube for greater accuracy) with a minimum of 10 diameters of straight unobstructed pipe upstream of the meter and 5 diameters downstream. It is important that all flanged connections in the upstream section to the turbine meter, as well as the downstream section, be properly aligned. Proper alignment throughout the metering section eliminates offsets, steps, and gaskets protruding into the bore, all of which can disturb the flow pattern. Dowel pinning of flanges can also aid in proper alignment of the metering section.

The historical method of flow conditioning utilizes straightening vanes or tube bundles. While this method is adequate for eliminating the swirl component of the flowing fluid, it does nothing for the velocity flow profile. Several manufacturers can provide isolation flow conditioners that eliminate the swirl and form a uniform velocity flow profile of the fluid before the flowmeter.

Proving connections downstream of the meter should be provided to facilitate proving of the meter, with a properly calibrated proving meter or "prover," under conditions as close to the normal operating conditions as practical. See API MPMS Chap. 4 for further description of a prover. The proving connections consist of two tees separated by a block and bleed valve in the run of pipe downstream of the meter. Block valves are installed on the outlet of each tee to allow the prover to be attached and flow to be directed to it in series with the meter being "proved."

Following the proving connections, another essential component for proper operation of the metering system is a control valve. The control valve is important because it helps to maintain a minimum backpressure on the meter to prevent meter cavitations and product flashing.

Unlike meters with moving parts, the Coriolis meter can handle typical pipeline solids without damage to the meter; however, a strainer upstream of the meter is recommended to protect the meter prover. No straightening vanes or flow conditioning is required for a Coriolis meter; therefore, no straight pipe sections upstream or downstream of the meter are necessary. This makes a Coriolis meter ideal for tight locations, as are typical on offshore platforms and for bidirectional metering systems. Consideration should be given to the location of the meter electronics that generate the pulse output so that the proving connections and the transmitter are located in close proximity.

Valves to stop flow through the Coriolis meter are required. Verification that the meter registers zero flow in a nonflowing condition is required on initial installation. The zeroing procedure requires, as a minimum, a block and bleed valve downstream of the meter, and it is preferable to have a shutoff valve upstream to block the meter in during zeroing.

The Coriolis meter acts as a densitometer in addition to measuring flow. There is a considerable cost savings for metering systems that require both the measurement of flow and the measurement of density or gravity when the measurement can be made with a single instrument. Finally, the large turndown of a Coriolis meter can eliminate the use of a bank of several different size meters to cover the rates, again providing a cost savings for the metering system.

Flowmeter Performance

Manufacturers typically state performance characteristics for flowmeters based on a factory calibration utilizing water or other stable fluid. "Accuracy" is the measure of how close to true or actual flow the meter indication may be. It is expressed as a percent of true volume for a specific flow range.

Linearity. Linearity is defined as the deviation of measurement from the meter’s minimum flow rate specification to the maximum flow rate specification. It is generally expressed as a percentage. For example, a meter with a linearity statement of +/–0.25% means the meter factor for a given meter will not deviate more than 0.5% from the minimum to maximum flow rate.

Repeatability. Repeatability is the meter’s ability to indicate the same reading under the same flow conditions. For custody transfer applications, a meter’s repeatability is usually specified to be at least 0.05%.

Resolution. Resolution is another key parameter in a meter’s performance criteria. Resolution is a measure of the smallest increment of total flow that can be individually recognized by the meter.

Turndown. Turndown is the meter’s flow range capability. The flow range of the meter is the ratio of maximum flow to minimum flow over which the specified accuracy or linearity is maintained. For example, a meter with a minimum flow rate of 100 bbl/hr and a maximum flow of 1,000 bbl/hr is said to have a 10:1 turndown. For positive-displacement meters, excessively low rates tend to under-register flow as slippage increases. At excessively high flow rates, there is an increase in wear. A meter should operate optimally around the midpoint of its rated flow range.

Flowmeter Selection

Fluid properties often dictate proper meter selection in a liquid application. Liquids such as anhydrous ammonia, refined hydrocarbons like gasoline or diesel, crude oil, and liquefied petroleum gas (LPG) have differing fluid properties such as density, viscosity, pour point, flash point, flowing temperature, and flowing pressure. All of these factors are important when specifying the requirements for the flowmeter. Fig. 11A.5 is a flowmeter application guide based on fluid properties.


Pressure drop through a meter is the amount of permanent pressure loss that is a result of the liquid passing through the meter. Meter manufacturers can provide data to compute expected pressure drop for a variety of liquids. As the viscosity and/or flow rate of the measured product increases, so does the amount of pressure drop. The specified design pressure of the system and the minimum and maximum operating pressures should be provided to the manufacturer. The maximum pressure is used to ensure that the mechanical rating of the meter is sufficient. The minimum pressure is needed to ensure that adequate pressure is available in the system to allow for pressure drop through the meter while maintaining the fluid in a liquid state—in other words, to prevent the product from flashing or changing to a gaseous state. Control valves or backpressure valves are often recommended to maintain sufficient pressure on the fluid as it is metered.

Fluid temperature and ambient temperature are factors to consider. If the product is very cold or very hot, it could well exceed the manufacturer’s temperature limits for the electronics, as well as exceed the standard materials temperature range for the meter body or internal parts.

Flowmeters that have internal moving parts may be affected by changes in liquid density and viscosity. For light hydrocarbons, the minimum flow rate capability of the meter may need to be increased to maintain specified linearity and repeatability. Viscosity can also affect the low end of the meter’s flow range. The actual viscosity of the fluid at operating or flowing temperature is what is relevant. A crude oil may have a viscosity of 50 cSt at 60°F; however, the temperature of the crude at flowing conditions may be 80°F, which would significantly reduce the viscosity and increase the actual flow rate range of a given meter.

Chemical compatibility must be considered in the material selection of all internal wetted surfaces. Dry, abrasive products may require special lubricating systems that isolate bearings and gears from the product. Entrained solids are not readily passed by most flowmeters and should be removed by an appropriately meshed strainer upstream of the meter.

Most meters yield gross measurement inaccuracies with a product that contains either free or entrained air. Removal of this air with an appropriately sized air eliminator is essential. Large volumes of free air not only impair accuracy but can also overspeed and destroy a meter with moving parts.

As with all metering systems, the choice of flowmeter technology should be based on cost of ownership. Cost of one type of meter relative to another varies by size and manufacturer. The initial cost, however, is only one of several costs that should be considered. For example:
  • Accuracy: consider a 16-in. pipeline meter flowing at 12,000 bbl/hr. With oil priced at $22/bbl, an improved accuracy of only .05% could result in a savings of U.S. $132 for every hour of operation.
  • Maintenance: recurring costs in maintaining a meter can be a significant factor in overall meter cost.


Meter Proving

Meter proving is the physical testing of the performance of a liquid meter in a liquid service. The main purpose of the test is to assure accuracy. The basic principles of proving a liquid meter are the same whether it is a Coriolis meter, turbine meter, or a positive displacement meter. Each type of meter has its own characteristics when being proved, but the basic principles are the same:

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When proving a meter, the process-fluid conditions must be as stable as possible throughout the proving process. This includes temperature, pressure, flow rate, and density. Before starting a meter proving, let the liquid flow through the meter and prover long enough so that the conditions stabilize. Check for leaks or fluid bypassing around the prover or meter. The only way to obtain a reliable meter factor is to have all the liquid that is measured by the meter also measured by the prover.

When in the field, a meter’s performance may change because of installation effects from piping, mechanical wear of the meter, and changes in the physical properties of the metered fluid. Therefore, the meter is proved to adjust for these changes, and the meter factor is applied when calculating the total net volume.

Meters are proved on a periodic basis determined contractually by the buyer and seller or by company policy. Some meters are proved for every batch transaction, which could be several times a day, while other meters may be proved as little as once a quarter. Regular proving ensures that the metering system is providing accurate flow data and confirms the integrity of the metering system.

LACT Units

LACT units are designed for unattended custody transfer of crude oil from a seller to a buyer. Flow rate, operating pressure, gravity, and temperature of the oil determine the LACT design. Minimum pressure drop through the piping and components is desirable.

LACT units have traditionally been fitted with positive-displacement meters, but a turbine meter can be used with certain types of fluid. New units being built today utilize Coriolis meters because they have no moving parts and can offer a lower cost. See Fig. 11A.4.

Positive displacement meters require certain accessories to read throughput. Large numeral counters equipped with a switch to operate a sample solenoid or provide a meter-failure circuit are common. Right-angle drives and photoelectric transmitters provide a pulse output for proving the meter. Positive-displacement meters must be equipped with some type of mechanical temperature-compensating device or an electronic temperature averager.

Coriolis and turbine meters are available with electronic transmitters that provide a local display, temperature averaging, a sample solenoid switch, and a high-frequency pulse for proving. Coriolis meters also provide an online measurement of observed gravity and calculate corrected gravity.

LACT Design Considerations. Centrifugal pumps are commonly used as charge pumps for LACT units, which typically operate at low enough pressures to allow the use of 150 series American Natl. Standards Inst. (ANSI) flanges. This type of pump provides a smooth flow without pulsation and does not require pressure relief protection. LACT units need a strainer before the pump to trap sediments. Failure to remove these sediments can cause damage to the pump and/or internal parts of the meter. The LACT unit should also have an air eliminator on a rise between the pump and meter to eliminate air or vapors from pumped liquids. Often, the strainer and air eliminator are contained in a single unit. (See Fig. 11A.6.)


LACT units are equipped with sediment and water (S&W) monitors that test the oil for the presence of water. The S&W probes are typically internally coated capacitance type for continuous monitoring. The monitor is used to detect unmerchantable oil, generally 0.5% water or more. The monitor sends a signal to an alarm panel that actuates a three-way divert valve that diverts the flow back to the tank to be treated again before it passes through the meter.

The sampling system is very important to the operation of an LACT. Sampler and S&W monitor locations are critical. They are normally installed in a vertical run of pipe downstream of an ell, where the flow is thoroughly mixed so that the probe and sampler "see" a representative sample. The sample probe can be placed downstream of a static mixer. Samplers should be paced by the meter and inject a common sample of 1.5 cm3 per stroke into the sample container. The size of a sample container is determined by the throughput of the LACT. The sample line from sampler to the sample container must be sloped downward toward the sample container with no high or low points in the line.

Downstream of the meter is a proving manifold. This manifold consists of three valves. The block and bleed is the inline valve and must be a double block and bleed type so it can be checked for leakage. Proving requires no leakage through this valve. The two bypass valves divert the flow through the prover and back into the line for full flow.

A backpressure valve should be installed downstream of the proving manifold to maintain a constant backpressure on the centrifugal charge pump, meter, and prover and assure constant flow rate through the LACT. A check valve is also needed downstream of the backpressure valve on an LACT unit so fluid cannot flow back from the pipeline and be metered twice.

Pressure gauges are needed on the pump discharge, at the air eliminator/strainer, and at the meter to check for normal operation. These gauges indicate if the strainer needs cleaning or if meter problems exist.

An electrical panel on the LACT controls the function of the unit. The control panel can be mounted on the skid in an explosion-proof enclosure or placed off skid. Newer units are being built with programmable controllers, thus eliminating relays and allowing better control of flow rate, pressure, and sampling.

LACT Operation and Maintenance Considerations.
  • The meter and valve drains and all flanges must be checked for leaks.
  • The strainer must be cleaned periodically to maintain normal flow rate.
  • The S&W monitor should be recalibrated monthly or when a delivery is completed.
  • PD meters require periodic maintenance of the gear train, packing gland, the counter, or right-angle drive.
  • The block-and-bleed valve should be inspected at each proving for leakage. If a leak is detected, a proving should not be performed until the valve is repaired.
  • The charge pump must be checked for excessive vibration or leaking seals. A drop in flow rate may occur if the impeller is partially plugged.


Flow Calculations and Overall System Performance

Most flowmeters output a pulse that represents gross volume (volume at flowing conditions). Gross volume is then converted to net volume (volume at contract conditions) with the appropriate corrections for temperature, pressure, S&W, and meter factor. With custody transfer, line integrity, or allocation based on net volumes, it is critical to accurately measure all variables and to maintain all measurement equipment.

PLCs, SCADA equipment, and flow computers offer a huge benefit for real-time monitoring of measurement stations. They offer the advantage of being able to act in a timely manner upon information that can save thousands of dollars in revenue.

Gas Meters—Kevin L. Warner and Tom Mooney

Introduction

It is widely accepted that global natural gas demand will continue to grow for the foreseeable future, possibly doubling every decade. Major new upstream developments, together with midstream transportation systems and downstream feedstock projects, are already progressing in all world areas. As this gas revolution evolves, there will be a dramatic rise in the requirement for high-accuracy measurement at every point in the gas value chain (Fig.11B.1).


This value chain can be subdivided into four major categories within which metering is carried out: gas production, gas transmission, gas storage, and gas distribution. Within these categories, there is a huge array of different gas-metering applications and a similar number of potential solutions. This can lead to confusion when selecting the optimum solution for the application.

Two of the traditional approaches have been to use orifice plates or turbine meters. Over the last few years, however, newer technologies, in particular ultrasonic and Coriolis meters, are being used more frequently. Since these are new technologies, many practitioners are unaware of how they compare with the traditional technologies, such as orifice and turbine meters. In particular, it can be difficult to know what flowmeter is most appropriate for a particular project, application, or specific set of circumstances. The aim of this chapter is to address this issue and hopefully provide some pointers to assist engineers with flowmeter selection within the four major categories.

Orifice Meters

International Standards. As a result of its longevity and widespread usage in the industry, the orifice plate is an extremely well documented and regulated measurement device. There are two main standards for orifice metering: ISO Standard 5167[2] and AGA Standard 3. [3] This chapter is based around the requirements and guidance of ISO Standard 5167. [2]

Orifice Flowmeter Overview. The orifice flowmeter consists of a thin, flat plate sandwiched between flanges or installed in a dedicated fitting. The plate has a precise, sharp-edged orifice, bored concentric with the pipe axis. The flow pattern contracts as it approaches the orifice—the contraction continuing to a distance of approximately one orifice diameter downstream. This point of minimum cross section is called the vena contracta. Thereafter, the jet diverges to the full-pipe section.

A mathematical model, generated from experimental data, of the conditions in the meter stream must be applied to calculate the flow. Refining this mathematical model is a continual process. The uncertainty in the flow-rate measurement can be predicted in accordance with ISO Standard 5167. [2]

There are many ways of locating an orifice plate within a pipeline. These range from a simple orifice flange to a more specialized fitting, such as the long standing Daniel Senior Fitting, which permits removal of the plate under pressure (Fig. 11B.2). It should be noted that other manufacturers offer orifice fittings with the similar design objectives.


There are also guidelines as to how the orifice flowmeter should be mounted in the pipeline. Because the orifice flowmeter is particularly sensitive to flow profile distortions, care should be taken to ensure fully developed flow. ISO Standard 5167[2] provides details on meter tube design. Fig. 11B.3 provides a representation of the "catch all" meter tube.


This tube incorporates a 2-diameter straightening vane within the 44-diameter upstream meter tube. Shorter meter-tube configurations may be achieved by using flow conditioners other than simple vanes. These devices may include shorter tube bundles in combination with a perforated "flow conditioning plate" or a thicker perforated plate as a standalone device.

Theory of Operation. The installation of the orifice plate causes a static pressure difference between the upstream side and the throat or downstream side of the plate (Fig. 11B.4). The rate of flow can be determined from the measured value of this pressure difference and from knowledge of the flowing gas properties, upstream or downstream pressure, and gas temperature, as well as the circumstances under which the device is being used. There are modifications to generally accepted equations for flow rate calculations because of frictional pressure losses, expansibility factors, and other empirically derived coefficients. Various internationally recognized equations may be applied and normally take the form of a discharge coefficient and an expansibility factor. A full analysis may be found in ISO TR 5168, Annex E. [4]


Advantages and Disadvantages. All meter types have advantages and disadvantages. Table 11B.1 summarizes them for orifice flowmeters.


Sizing. Orifice meter size is determined largely by the range of differential pressures that are deemed acceptable to measure. For example, a user who is willing to operate at differential pressures of 200 in. of water column would be able to flow more than 40% more gas through an identical device than a user who limits the differential pressure to 100 in. of water column. Similarly, the choice of beta ratio (the ratio of the outer diameter of the orifice plate and the diameter of the plate opening) will also impact the range of measurement. Typical sizing is accomplished by limiting beta ratios to values no larger than 0.65 and differential pressures between 10 and 100 in. of water column.

Gas Turbine Meter

International Standards. There are two main standards for turbine meters: ISO Standard 9951, Measurement of Gas Flow in Closed Conduits: Turbine Meters[5] and OIML R32, Rotary Piston Gas and Turbine Gas Meters. [6]

Turbine Meter Overview. A basic turbine meter consists of pressure-containing meter housing with end flanges; a set of internals, incorporating the turbine wheel and gearing mechanisms; and a means of counting the turbine wheel revolutions. A typical turbine meter has additional components such as flow conditioning devices, bearing lubrication mechanisms, and sophisticated mechanical and electrical counter systems. An exploded view of a turbine meter is given in Fig. 11B.5. For additional information about turbine meters and their use in liquid measurement, see Sec. 11A.3 of this chapter.


Like orifice meters, turbine meters should be mounted within a meter tube (Fig. 11B.6). Most modern turbine meters have integral flow conditioners. These conditioners help to remove swirl and much of the distortion from the flow profile, and hence, the overall straight length requirement upstream of the meter can be relatively small. A typical requirement is 5 diameters.


Theory of Operation. The operation of a turbine meter is based on the measurement of the velocity of gas. The flowing gas is accelerated and conditioned by the meter’s straightening section. The integrated straightening vanes prepare the gas flow profile by removing undesirable swirl and asymmetry before the gas flows over the freely rotating turbine wheel. The dynamic forces of the flowing gas cause the rotor to rotate. The turbine wheel is mounted on the main shaft, with high-precision, low-friction ball bearings. The turbine wheel has helical blades that have a known angle relative to the gas flow. The gas flow drives the turbine wheel at an angular velocity, which, in the linear range of a well-designed meter, is proportional with the gas velocity. Using a gearing mechanism, the rotating turbine wheel drives the mechanical counter. In addition, the rotating blade can also be used to generate pulses via a proximity sensor. Each pulse detected is equivalent to a discrete volume of gas at actual conditions (i.e., the total number of pulses collected in any period of time represents the gross observed volume during that period). For each meter, a calibration characteristic (K factor) is required. This factor is expressed in pulses per volume and is given by the manufacturer.

The K factor is determined by means of a flow calibration. This flow calibration should be carried out over the entire operating range of the meter because the K factor may vary with flow. This variation with flow is the turbine meter’s linearity. Once the K factor has been defined, the flow through the meter can be calculated because the two quantities are proportional.

Advantages and Disadvantages. The advantages and disadvantages for turbine meters are given in Table 11B.2.


Sizing. Gas turbine meter sizing varies from one manufacturer to the next; however, the variables to be considered are consistent. Gas turbine meters are velocity meters, and the upper velocity limit is essentially unchanged by pressure. Thus, a given size turbine meter will have an associated upper uncorrected flow rate limit. The range of the measurement is affected at the low end by the amount of mass flow through the meter. Thus, the range of a turbine meter is enhanced by increasing line pressure. For example, a 3-in. gas turbine meter might have a range of 30:1 at 200 psi but more than 60:1 at 500 psi.

Ultrasonic Meters

International Standards. The situation with ultrasonic flowmeters and international standards is quite straightforward—there is none. There is, however, an ISO committee currently working to produce a standard: ISO Standard TC30/SC5/WG1. [7] In the meantime, there are several best practice guidance documents—the first to be released in 1998 was AGA Report 9, Measurement of Gas by Multipath Ultrasonic Meters, [8] and then, in 2000, BSI 7965, The Selection, Installation, Operation and Calibration of Diagonal Path Transit Time Ultrasonic Flowmeters for Industrial Gas Applications. [9] Both of these documents are under review at the moment, and it is anticipated that a new revision will be issued in the near future.

Ultrasonic Meter Overview. A multipath transit time ultrasonic meter (USM) is basically a device that consists of three main components: the meter body (cylindrical pipe spool), transducer pairs (mounted in the pipe spool), and an electronic module (Fig. 11B.7).


USMs derive the volume flow of the gas by measuring the transit times of high-frequency sound waves. Transit times are measured for pulses propagating up and downstream across the gas stream at an angle with respect to the pipe axis. These transit times, together with the meter geometry, are used to calculate the average gas velocity on a particular chord. Multiple paths are used within ultrasonic meters to maximize accuracy in the overall average velocity measurement. These multiple paths also provide a certain degree of immunity to flow profile effects, such as asymmetry and swirl. The level of immunity offered by the multipath USM varies from one design to another, as shown by Grimley. [10] Despite the fact that the USM offers some immunity to flow profile distortions, they still require upstream straight lengths of pipe. A typical meter tube layout for a USM is shown in Fig. 11B.8.


Theory of Operation. As previously stated, USMs measure the transit times of high-frequency sound pulses. The transducers are mounted on the meter body at defined locations. Fig. 11B.9. [9] shows a schematic arrangement for a single path. The dimensions X and L are precisely determined during the meter manufacture. These measurements, together with the electronic characteristics of each transducer pair, characterize the ultrasonic flowmeter. The transit time for a signal, traveling with the flow, is less than that for a signal traveling against the flow. The difference in these times determines flow velocity.


It is also important to consider any additional uncertainty associated with the through-life stability of the USM. There are several influencing factors, one of which is wall roughness. It has been shown by Zanker[11] that changes in wall roughness can cause significant drift in USM meters that incorporate a center path bouncing configuration to determine gas velocity. With such chord configurations, the USM measures the velocity at the center of the pipe (i.e., the maximum velocity). To arrive at an average velocity, a correction factor based on the Reynolds number and wall roughness is used. Over time, the wall roughness changes, so the correction factor becomes more and more erroneous. This results in serious meter drift. This is just one influencing factor—to quantify all influences relies on a significant passing of time together with data gathering, so responsibility has to be placed on the manufacturer to demonstrate the meter’s through-life stability.

Advantages and Disadvantages. There are a host of benefits offered by ultrasonic technology when compared with traditional measurement techniques such as the orifice or the turbine meter. The main benefits for ultrasonic flowmeters are shown in Table 11B.3.


Sizing. Ultrasonic meters operate over a specified velocity range, which is independent of gas temperature, pressure, or composition. Although limits vary from one manufacturer to another, typical guidelines limit the velocity range from about 3 ft/sec to about 70 ft/sec. Pressure ranges may impact the configuration of the meter because special ultrasonic transducers are sometimes specified for either high or low pressures. Caution should also be given to applications with carbon dioxide levels in excess of about 25% because CO2 may absorb the ultrasonic signals.

Coriolis Flowmeters

International Standards. Recent advances in the development and performances of Coriolis meters have meant that the measurement of the mass flow rate of gases, such as natural gas for custody transfer applications, is now a reality. This has been reflected by the large acceptance of this technology within the natural gas industry. As an example, Micormotion has supplied 5,000 Coriolis meters for natural gas applications in the last 3 years. This industrial acceptance motivated ISO to develop a standard through the ISO Technical Committee—ISO Standard TC30/SC12. [12] In addition to this ISO standard, there is also an engineering technical report prepared by AGA entitled Coriolis Flow Measurement for Natural Gas Applications.[13] For additional information on Coriolis meters and their use in liquid service, see Sec. 11A.4 of this chapter.

Although there is no ISO standard for natural gas measurement using Coriolis measurement, some countries have issued type-approval certificates for natural gas measurement using Coriolis meters. These countries include: The Netherlands (Netherlands Inst. for Metrology and Technology), Germany (Physickalisch-Technische Burdessarstalt), Canada (Measurement Canada), and Russia (Gosstandard).

Coriolis Meter Overview. A Coriolis meter comprises two main parts: a sensor (primary element) and a transmitter (secondary element). See Fig. 11B.10. With this design, the gas flows through a U-shaped tube. The tube is made to vibrate in a perpendicular direction to the flow. Gas flow through the tube generates a Coriolis force, which interacts with the vibration, causing the tube to twist. The greater the angle is twisted, the more the flow increases. The sensing coils, located on the inlet and outlet, oscillate in proportion to the sinusoidal vibration. During the flow, the vibrating tubes and gas mass flow couple together because of the Coriolis force, causing a phase shift between the vibrating sensing coils. The phase shift, which is measured by the Coriolis meter transmitter, is directly proportional to the mass flow rate. The vibration frequency is proportional to the flowing density of the flow. However, the density measurement from the Coriolis meter is not normally used as part of the gas measurement station. Like other meters, the Coriolis is usually mounted in a meter tube. Because the device is insensitive to flow disturbances, there is no requirement for any form of flow conditioning, straight lengths, or meter tube.


Theory of Operation. Coriolis meters operate on the principle that if a particle inside a rotating body moves in a direction toward or away from the center of rotation, the particle generates inertial forces that act on the body. Coriolis meters create a rotating motion by vibrating a tube or tubes carrying the flow, and the inertial force (Coriolis force) that results is proportional to the mass flow rate. By measuring the amount of inertial force or deflection, it is possible to infer the mass flow rate. It is this phenomenon that is harnessed within the Coriolis flowmeter.

It is also important to consider any additional uncertainty associated with the through-life stability of the Coriolis meter. There are two main influencing factors: the change in flow-tube structural characteristics caused by erosion of the tube wall by abrasive particles and the coating of the flow tube by debris. Abrasion of the flow tubes by abrasive particles can directly affect the flow calibration of the meter. Coating of the flow tubes by debris is only a concern at low fluid flow velocities when the meter is not self-cleaning. This influence does not affect the meter’s calibration and only affects the meter’s zero. It can be corrected by regular zero checks for drift and zeroing, if required. Both of these influences can be identified as occurring under flowing conditions by monitoring the drift in flowing density over time.

Advantages and Disadvantages. The advantages and disadvantages for Coriolis meters are shown in Table 11B.4.


Sizing. Gas Coriolis meters, like all Coriolis meters, are mass devices. The sensitivity of the meter to measure small amounts of mass flow determines the low end of the metering range. The upper end of the measurement range is most often determined by the largest acceptable pressure loss. The pressure loss across the meter increases with flow rate and the corresponding velocity through the meter. Velocities through the meter can be a substantial fraction of the speed of sound but clearly should not exceed about 0.5 Mach.

References


  1. Measurement of Liquid Hydrocarbons by Turbine Meters. 2000. In Manual of Petroleum Measurement Standards, fourth edition, Ch. 5, Sec. 3. Washington, DC: API.
  2. 2.0 2.1 2.2 2.3 Standard 5167, Measurement of Fluid Flow by Means of Pressure Differential Devices—Part 1: Orifice Plates, Nozzles and Venturi Tubes Inserted in Circular Cross-Section Conduits Running Full, ISO, Geneva, Switzerland (1991).
  3. Orifice Metering of Natural Gas and Other Related Hydrocarbon Fluids, Report No. 3. 2000. Washington, DC: AGA.
  4. Orifice Metering of Natural Gas and Other Related Hydrocarbon Fluids, Report No. 3. 2000. Washington, DC: AGA.
  5. ISO 9951:1994, Standard 9951, Measurement of Gas Flow in Closed Conduits: Turbine Meters. 1994. Geneva, Switzerland: ISO.
  6. R 32, Rotary Piston Gas Meters and Turbine Gas Meters. 1989. Paris, France: OIML.
  7. ISO Standard TC30/SC5/WG1, Measurement of Gas Flow in Closed Conduits—Ultrasonic Meters. Geneva, Switzerland: ISO.
  8. Measurement of Gas by Multipath Ultrasonic Meters," Report No. 9. 1998. Washington, DC: AGA.
  9. 9.0 9.1 BSI 7965:2000, The Selection, Installation, Operation and Calibration of Diagonal Path Transit Time Ultrasonic Flowmeters for Industrial Gas Applications. 2000. London: BSI.
  10. Grimley, T. 2000. Ultrasonic Meter Installation Configuration Testing. Paper presented at the 2000 AGA Operations Conference, Denver, 7–9 May.
  11. Zanker, K. 1999. The Effects of Reynolds Number, Wall Roughness and Profile Asymmetry on Single and Multipath Ultrasonic Meters. Paper presented at the 1999 North Sea Flow Measurement Workshop, Gardermoen, Norway, 25–28 October.
  12. ISO Standard TC30/SC12, Measurement of Fluid Flow in Closed Conduits—Mass Methods. Geneva, Switzerland: ISO.
  13. Coriolis Flow Measurement for Natural Gas Applications, technical report. Washington, DC: AGA.

SI Metric Conversion Factors


bbl × 1.589 873 E – 01 = m3
cp × 1.0* E – 03 = Pa•s
cSt × 1.0* E – 06 = m2/s
°F (°F – 32)/1.8 = °C
ft × 3.048* E – 01 = m
in. × 2.54* E + 00 = cm
in.3 × 1.638 706 E + 01 = cm3
psi × 6.894 757 E + 01 = kPa


*

Conversion factor is exact.