Dp12b Flow Instruments

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CONTENTS Section

Page

1 SCOPE ....................................................................................................................................................... 4 2 REFERENCES............................................................................................................................................ 4 2.1

DESIGN PRACTICES .................................................................................................................... 4

2.2

GLOBAL PRACTICES ................................................................................................................... 4

2.3 INDUSTRY PRACTICES AND PUBLICATIONS............................................................................ 4 2.3.1 International Standards Organization (ISO).............................................................................. 4 2.3.2 American Gas Association ....................................................................................................... 4 2.4

OTHER PUBLICATIONS ............................................................................................................... 5

2.5

COMPANY TECHNICAL REPORTS.............................................................................................. 5

2.6

FLOW CALCULATION PROGRAMS ............................................................................................. 5

3 BACKGROUND.......................................................................................................................................... 5 4 FLOW MEASUREMENT ............................................................................................................................ 5 4.1

PRINCIPLES USED ....................................................................................................................... 5

4.2 METER SELECTION CRITERIA.................................................................................................... 6 4.2.1 Accuracy................................................................................................................................... 6 4.2.2 Rangeability.............................................................................................................................. 7 4.2.3 Discharge Coefficient (C) ......................................................................................................... 8 4.2.4 Reynolds Number..................................................................................................................... 9 4.2.5 Straight Run Requirements .................................................................................................... 14 4.2.6 Meter Selection Tables........................................................................................................... 14 5 FLOW MEASUREMENT DEVICES.......................................................................................................... 17 5.1 DIFFERENTIAL PRESSURE TYPE METERS ............................................................................. 17 5.1.1 Basic Flow Rate Equation ...................................................................................................... 17 5.1.2 Orifice Meters ......................................................................................................................... 18 5.1.3 Segmental Wedge Meter ........................................................................................................ 21 5.1.4 Venturi Tube ........................................................................................................................... 22 5.1.5 Lo Loss Tube or Dall Tube ..................................................................................................... 23 5.1.6 Flow Nozzle ............................................................................................................................ 24 5.1.7 Pitot Tube and Averaging Pitots ............................................................................................. 24 5.1.8 Pitot-Venturi Tube................................................................................................................... 25 5.2 NON-HEAD TYPE METERS........................................................................................................ 26 5.2.1 Turbine Meter ......................................................................................................................... 26 5.2.2 Positive Displacement Meter .................................................................................................. 27 5.2.3 Vortex Shedding Meter ........................................................................................................... 28 5.2.4 Magnetic Flow Meter .............................................................................................................. 29 5.2.5 Ultrasonic Flow Meter ............................................................................................................. 30 5.2.6 Variable Area Meter................................................................................................................ 31 5.2.7 Coriolis (Mass) Type............................................................................................................... 32 5.2.8 Thermal Meter ........................................................................................................................ 33 5.2.9 Multi-Phase............................................................................................................................. 34 5.3

TYPICAL PROBLEMS IN FLOW MEASUREMENT..................................................................... 34

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5.3.1 5.3.2 5.3.3 5.3.4 5.3.5 5.3.6 5.3.7

INSTRUMENTATION

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FLOW MEASUREMENT AND CONTROL

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2 of 38 July, 2007

Deviation from Design Conditions .......................................................................................... 34 Meter Range........................................................................................................................... 35 Required Turndown ................................................................................................................ 35 Liquid Bubble Point................................................................................................................. 35 Gas Law Deviation ................................................................................................................. 35 Viscosity ................................................................................................................................. 36 Contamination ........................................................................................................................ 36

5.4

CUSTODY TRANSFER METERING STATIONS......................................................................... 36

5.5

METER PROVERS ...................................................................................................................... 36

6 FLOW CONTROL APPLICATIONS ......................................................................................................... 37 6.1

CONTROL OF PUMPS ................................................................................................................ 37

6.2

CONTROL OF COMPRESSORS................................................................................................. 37

6.3

FLOW RATIO CONTROL ............................................................................................................ 37

TABLES Table 1 Fluid Properties Required................................................................................................................... 6 Table 2 Best Achievable Accuracy For Given Meter Installations ................................................................... 7 Table 3 Meter Suitability ................................................................................................................................ 15 Table 4 - Flow Meter Selection Criteria ......................................................................................................... 16 FIGURES Figure 1 Comparison Of Dp And Flow Rate For Differential Pressure Flow Element...................................... 8 Figure 2 laminar flow profile ............................................................................................................................ 9 Figure 3 Turbulent Flow Profile ..................................................................................................................... 10 Figure 4 Discharge Coefficients For Orifices And Nozzles In Viscous Service With Flange Taps................. 11 Figure 5 Unrecoverable Pressure Loss ......................................................................................................... 12 Figure 6 Overall Permanent Pressure Loss Through Various Primary Elements .......................................... 13 Figure 7 Concentric Sharp Edge Orifice ........................................................................................................ 18 Figure 8 Quadrant Edge Orifice..................................................................................................................... 19 Figure 9 Eccentric Orifice .............................................................................................................................. 20 Figure 10 Segmental Orifice.......................................................................................................................... 20 Figure 11 Integral Orifice Meters ................................................................................................................... 21 Figure 12 Elbow Meter .................................................................................................................................. 21 Figure 13 Segmental Wedge Meter............................................................................................................... 22 Figure 14 Venturi Meter................................................................................................................................. 23 Figure 15 Badger Lo-Loss™ Flow Tube ........................................................................................................ 23 Figure 16 Flow Nozzle................................................................................................................................... 24 Figure 17 Pitot Tube And Averaging Pitot ..................................................................................................... 25 Figure 18 Pitot-Venturi Tube ......................................................................................................................... 25 Figure 19 Typical Turbine Meter Assembly ................................................................................................... 26 This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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Figure 20 Selection Guide For Displacement And Turbine Meters................................................................ 27 Figure 21 Types Of Positive Displacement Meters........................................................................................ 28 Figure 22 Vortex Shedding Meter.................................................................................................................. 29 Figure 23 Magnetic Flowmeter Principle ....................................................................................................... 30 Figure 24 Ultrasonic Flowmeter Schematic ................................................................................................... 30 Figure 25 Variable Area Flowmeter ............................................................................................................... 32 Figure 26 Coriolis Flowmeter......................................................................................................................... 33 Figure 27 Process Flow Diagram Flow Ratio Control Stream B (controlled stream) ratioed to Stream A (wild stream) .......................................................................................................................................................... 37 Figure 28 Flow Ratio Control - Flow Rangeability With Normal Ratio Adjustment Limits (Usable flow limits taken as 30 and 95% of meter range) ........................................................................................................... 38

Revision Memo 07/07

General Revison. Minor text updates.

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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1

SCOPE

This section covers the aspects of flow measurement and control that are required for the development of a Process Design Specification. The discussions are generally limited to closed-conduit type flow meters in single-phase applications. For the meters that are covered, both theoretical and practical information is presented, in an attempt to provide a single design reference for process designers, as well as for new and practicing instrument engineers. 2 2.1

REFERENCES

DESIGN PRACTICES

DP X-A

Pumps - Pumping Service Design Procedures

DP XI-E

Compressors - Centrifugal Compressors

DP XIV-A

Fluid Flow - General

DP XIV-B

Fluid Flow - Single Phase Liquid Flow

DP XIV-C

Fluid Flow - Single Phase Gas Flow

2.2

GLOBAL PRACTICES

GP 3-6-1

Piping for Instruments

GP 15-4-1

Flow Instruments

GP 15-6-1

Electronic and Pneumatic Instruments

2.3

INDUSTRY PRACTICES AND PUBLICATIONS

American Petroleum Institute (API), Manual of Petroleum Measurement Standards Chapter 4

Proving Systems, Section 1 - Introduction

Chapter 4

Proving Systems, Section 2 - Conventional Pipe Provers

Chapter 4

Proving Systems, Section 6 - Pulse Interpolation

Chapter 5

Liquid Metering, Section 2 - Measurement of Hydrocarbons by Displacement Meters

Chapter 5

Liquid Metering, Section 3 - Measurement of Hydrocarbons by Turbine Meters

Chapter 5

Liquid Metering, Section 5 - Fidelity and Security of Flow Measurement Pulsed Data Transmission Systems

Chapter 12

Section 2 - Calculation of Petroleum Quantities Measured by Turbine or Displacement Meters

Chapter 14

Section 3 - Concentric, Square-edge Orifice Meters

Chapter 21

Section 1 - Flow Measurement Using Electronic Metering Systems

2.3.1

International Standards Organization (ISO)

ISO 5167

Measurement of Fluid Flow by Means of Orifice Plates, Nozzles, and Venturi Tubes Inserted in Circular Crosssection Conduits Running Full.

ISO 5168

Measurement of Fluid Flow - Estimation of Uncertainty of a Flow Rate Measurement.

ISO 10790

Measurement of Fluid Flow in Closed Conduits - Guidance to the Selection, Installation and Use of Coriolis Meters.

2.3.2 Report No 9

American Gas Association Measurement of Gas by Multipath Ultrasonic Meters

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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2.4

July, 2007

OTHER PUBLICATIONS

Miller, R. W., Flow Measurement Engineering Handbook The Foxboro Company, Fluid Meters, Their Theory and Application American Society of Mechanical Engineers, Shell Flow Meter Engineering Handbook, Royal Dutch/Shell Group. Dutch Shell Laboratory, Delft Report 1312M, Royal, Delft, Holland. Lipták, Béla G., Instrument Engineers Handbook, Chilton Publishers. 2.5

COMPANY TECHNICAL REPORTS

EMRE 001

EMRE Product Control Manual

EEEL.2E.81

ER&E Report Information Package on Meter Proving

EE.13E.86

ER&E Report Implementation Guidelines for Custody Transfer of Hydrocarbons

EE.46E.87

ER&E Report Fuel Gas Flow Measurement Implementation Guide

EE.68E.89

ER&E Report Implementation Guidelines for Custody Transfer of Gases

EE.2M.91

ER&E Report Master Meter Proving of Positive Displacement Meters

HMP

Hydrocarbon Measurement Practices (HMP-Refining)

2.6

FLOW CALCULATION PROGRAMS

Pegasys - ExxonMobil Standard Flow Meter Analysis / Sizing Program. Note: This program is now layered under the HSME environment and can be installed on the personal computer by approved users. 3

BACKGROUND

After temperature, flow is the most commonly measured variable in most refinery and chemical processes, whether the process is continuous, or batch in nature. Many processes are controlled by varying the flow of a fluid, be it reflux to a pipestill or fractionator column, heating medium to a reboiler, fuel to a fired heater, or the discharge rate from a separator. Accurate measurement and control of fluid flow is also critical from an economic point of view, since practically any fluid that flows through a plant has a price tag attached to it. In general, flow measurements can be grouped into four categories:

• • • •

Basic measurement for process monitoring and regulatory control Unit material balances Accounting information for custody transfer (product sales) Information required by State or Federal regulatory bodies for permitting

Control of flow is generally quite straightforward and easily accomplished, usually, the difficulty lies in selecting the proper measurement device. 4 4.1

FLOW MEASUREMENT

PRINCIPLES USED

There are many devices used to measure flow, many of which are inferential in nature. That is, they measure flow indirectly by measuring a related property such as a differential pressure across a flow restriction or a fluid velocity in a pipe. A number of different fundamental physical principles are used in flow measurement devices. The most common flow measurement principle is the head meter. These devices function by converting the kinetic energy in the flowing fluid into potential energy represented by a differential pressure measured across a flow restriction in the pipe. Other devices measure the fluid velocity in a variety of ways: the generation of a counter-emf in an electric field; Doppler radar reflections off particles or bubbles in the fluid; rotation of a turbine wheel; etc. The following is a discussion of each of the various types of flow meters. This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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The type of flow measurement device selected depends on a large number of parameters: flowing fluid and conditions, cost, accuracy requirements, and space available, to mention the major ones. IN ORDER TO PROPERLY DESIGN AND SIZE A FLOW METER FOR A GIVEN APPLICATION, IT IS IMPORTANT FOR THE PROCESS DESIGNER TO REALIZE THAT A MINIMUM OF PROCESS STREAM DATA MUST BE SUPPLIED AS PART OF THE PROCESS DESIGN SPECIFICATION. TABLE 1 LISTS THE MINIMUM STREAM DATA NEEDED FOR LIQUIDS, GASES (vapors), AND STEAM. Table 1 Fluid Properties Required LIQUIDS

GASES & VAPORS

STEAM

Internal Pipe ID

Internal Pipe ID

Internal Pipe ID

Operating Temperature

Operating Temperature

Operating Temperature

Operating Pressure

Operating Pressure

Operating Pressure

Viscosity

Viscosity

Viscosity (Opt)

Specific Gravity or Density

Mol. Wt. or Density

Density (Opt)

Flow Rate (Max/Nor/Min)

Flow Rate (Max/Nor/Min)

Flow Rate (Max/Nor/Min)

Heat Capacity Ratio (Cp/Cv) Compressibility Note:

Viscosity, compressibility (gases), and specific gravity (liquids) should be specified at operating temperature and pressure.

Please note that the minimum flow rate is NOT zero flow. The minimum flow is the lowest anticipated continuous flow rate that must be measured or controlled. For custody transfer and inventory applications, standard temperature and pressure should be stated since different countries have different standard temperature and pressure bases. 4.2

METER SELECTION CRITERIA

Although an orifice meter will most likely be selected for most applications, the proper selection of a flow meter for a particular application requires considerable evaluation of tradeoffs. It involves evaluating the total cost of ownership against many application considerations, which affect meter performance. The most important application factors, which require consideration, are fluid state, flowing conditions, Reynolds number, density, rangeability, mechanical installation constraints and accuracy requirements. In addition to the above, the designer must also decide on what basis the measurement will be made: Mass, Volume (operating or standard) or Energy. Once known, this dictates the level of instrumentation required to produce that measurement. For example, if standard volume is selected, the meter installation, in addition to its flow meter and transmitter, will also have to be provided with field transmitters for pressure and temperature, to compensate for process variations in these variables. In some instances, a specific gravity or density analyzer may also be needed to account for variability in stream composition. Economic considerations also come into play when selecting a meter. The initial equipment cost is not the only cost to consider. Thought should also be given to 1) total installed cost, 2) maintenance cost, and 3) operating cost. The following paragraphs discuss each of the factors required to be considered and their potential impact on the measurement. Costs must be carefully evaluated, particularly as meter size or operating pressure changes. For instance, a small sized venturi might be of comparable cost to an averaging pitot, but as the size increases the cost of the venturi rapidly exceeds that of the averaging pitot for a given pipe size. Increasing design pressure has the same effect. 4.2.1

Accuracy

Flow meter accuracy is defined as the closeness of agreement between the measured flow rate and the actual flow rate in a pipe. Accuracy can be considered to be made up of two components: precision and bias error. Precision is the metering device's ability to give the same flow readings for the same true value of flow. Precision is normally a function of the repeatability and stability of the system. Bias error is the difference (or offset) in the average flow value and the actual flow value. Bias error is usually caused by progressive aging and drift in the installed equipment.

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Plant applications can be classified into three categories:

• • •

Class I

Sales, Custody Transfer, and other applications requiring high accuracy

Class II

Material Balance, and Equipment Performance applications

Class III

General Purpose

The system accuracy achievable for typical meter types, as defined by EMRE 001 Product Control Manual, for each of the above Classes is shown in Table 2. Table 2 Best Achievable Accuracy For Given Meter Installations % UNCERTAINTY OF MEASURED VOLUMETRIC FLOW RATE METER TYPE CLASS I

CLASS II

CLASS III

Positive Displacement

0.2

0.2

0.5

Turbine

0.2

0.2

—

Orifice(1) Vortex Shedding

1.0(2)

2.0

5.0

Not recommended

0.75

1.5

0.2

0.2

0.5

Not recommended

1.0

1.4

Coriolis(3) Ultrasonic (4) Notes: (1)

4.2.2

Uncertainty of orifice meter is listed as "% of full scale".

(2)

HMP allows orifice meters to be used in Class I applications for steam and gases only.

(3)

Uncertainty of coriolis meter is listed as "% of mass flow rate".

(4)

Multipath Ultrasonic meters only.

Rangeability

Rangeability is a flow meter's ability to cover a range of flow rates within specified accuracy limits. It is usually defined as the ratio of the maximum to minimum flow rates and is also known as meter turndown. For differential pressure type flow meters, because of the square root relationship between flow rate and differential pressure, flow rangeability is usually severely limited without taking certain measures. As shown in Figure 1, for a change in differential pressure from 100% down to 10% of full scale (about the limit for reasonable accuracy with conventional transmitters), the change in flow rate is only from 100% to 30% of full scale. Therefore, in most differential pressure applications, the maximum usable rangeability of an orifice is about 100/30 or roughly 3 to 1 with a standard differential pressure transmitter. GP 15-4-1 states “The normal flow rate should be between 70% to 80% of the full scale flow provided that the anticipated minimum and maximum flow rates will be between 30% and 95% of the full scale flow". This limits the working rangeability to 950/30, or roughly 3 to 1. However, in certain cases, this rangeability may be extended up to 10 to 1 through the use of the new, high-accuracy, digital differential pressure transmitter, that have an accuracy better than 0.1% of the calibrated range provided that the minimum dP is greater than 0.1in. of water (25.4 mm of water). The reason for this is the calibrated range of the transmitter corresponding to the measured differential pressure at the minimum flow rate gets so small (less than 1 in. of water), the transmitter is unable to accurately distinguish between a true differential pressure change due to flow, versus pure process background noise in the pipe. If greater than 4 to 1 rangeability is required using conventional transmitters, multiple differential pressure transmitters may be installed in parallel across the same set of orifice taps. In this approach, each transmitter provides for a 3 to 1 rangeability and is designed to measure a specific flow range. Switching logic is then utilized in the process control system to select the correct transmitter. In most modern control systems, this switch is automatic. So, for example, if an orifice is supplied with two differential pressure transmitters, this equates to a rangeability of 9 to 1. In the practical sense, no more than 3 conventional d/p transmitters should be installed in parallel across an orifice plate. It should be noted that for multiple transmitters on one orifice plate, the pressure drop at the highest expected flow rate should be taken into account in hydraulic balances.

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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If high accuracy digital transmitters are used, three transmitters on the same set of taps would provide 1000:1 rangeability, adequate for any foreseeable application. CAUTION: In these wide rangeability applications, the pipe Reynolds Number should be calculated at the lowest flow rate to be measured to verify turbulent flow conditions still exist. For non-head type flow meters, the above problem with the square root relationship between flow rate and differential pressure does not exist. Non-head type flow meters can generally provide wider rangeability, usually on the order of 10:1. When greater than 10:1 is needed, parallel meter runs are usually employed. Figure 1 Comparison Of Dp And Flow Rate For Differential Pressure Flow Element

100

100

Δ P, % of Full Scale

80

90

70 60 50 40

80 70 60

30

Flow Rate, % of Full Scale

90

50 20

40

10 0

4.2.3

0

DP12BF01

Discharge Coefficient (C)

Every head type flow meter geometry has something called a discharge coefficient, (C). The discharge coefficient corrects the theoretical flow rate equation for the influence of velocity profile (Reynolds number). Specific discharge coefficients for various flow meter geometries have been determined by actual tests run by many different organizations (e.g., API, ASME) over the past 75 years. The discharge coefficient is a very important factor in defining the shape of the flow path. It is heavily influenced by factors such as: the size of the orifice bore, the size of the pipe, fluid velocity, fluid density, and fluid viscosity. The orifice to pipe diameter ratio, d/D, also called (beta ratio-β) in flow meter literature, is usually limited to a maximum of 0.7, because of the sensitivity of the discharge coefficient to such things as pipe diameter variation and wall roughness. However, for new designs it is best to limit β to 0.65. If the d/D ratio limit is exceeded, it can be reduced by increasing line size for the length of the meter run. A high d/D ratio is a sign of unusually high line velocity and the piping pressure drop calculations should be checked. On the opposite end, β is usually limited to a minimum of 0.25. Anything less than 0.25 would be suspicious, indicating oversized pipe; as the area of a 0.25 d/D orifice would be only 6 percent of the pipe area. Hence, for new meter designs, the beta ratio should be kept in the range of 0.25 to 0.70.

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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4.2.4

July, 2007

Reynolds Number

Reynolds number is a dimensionless number expressing the ratio of the dynamic forces to the drag forces of a fluid. Reynolds number is used as a way to correlate the variations in flow meter coefficient of discharge (C) with changes in the fluid's properties, flow rate, and meter geometry. In its simple form (from API Chapter 14, Section 3, Part 1), the Reynolds number can be expressed as:

Re =

N2 qm μD UNITS Customary Metric = Pipe Reynolds number

where: Re (dimensionless) N2

= 1.27324 = kg/hr = lbm/ft/s = ft

qm

μ fluid D Diameter

Unit Conversion Constant 353.6777 Mass Flow Rate lbm/s Absolute Viscosity of the cP Meter Tube Inside mm

Reynolds number can be expressed in two ways: Pipe Reynolds number or Throat Reynolds number. Do not confuse them, as they are not interchangeable. Pipe Reynolds number will always be lower than the throat Reynolds number. However, pipe Reynolds number is more convenient to use because in most cases, at the time of design, the orifice throat dimension is not usually known. Pipe Reynolds number does not represent the true performance of a flow element. It is for this reason that, whenever possible, a throat Reynolds number should be calculated. At low Reynolds numbers, the drag (viscous) forces dominate and flow is said to be laminar in nature (see Figure 2). As Reynolds number increases, the drag forces become less dominant and the flow is said to be turbulent in nature (see Figure 3). In order for most differential flow applications to provide reasonable results, the flow profile in the pipe should be turbulent or in a range where the pipe Reynolds number is 10,000 or greater. This assures operation over the flat or constant portion of a differential device's discharge coefficient (C) curve, and away from the sloped portion of the curve. See Figure 4. Figure 2 laminar flow profile

V Max = 2 v

DP12BF02

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Figure 3 Turbulent Flow Profile

V Max = 1.2 v

DP12BF03

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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Figure 4 Discharge Coefficients For Orifices And Nozzles In Viscous Service With Flange Taps

Typical Nozzle 1.0

0.8 Diam. Ratio 4

0.9

Discharge Coefficient Excluding Velocity of Approach, C = K

1

( dD )

0.75 0.7 0.8 0.5

0.65 0.6

0.7

0.2 Diam. Ratio

0.6

0.3

0.4

0.5

0.4

0.3

0.2

2 1

4

6 8

10

2

4

6 8

102

2

4

6 8

103

2

4

6 8 104

2

4

6 8

Throat Reynolds Number(1) Note: (1) This chart is based on Rd, the Reynolds number computed from throat diameter and velocity, all other references in this subsection are to RD, the Reynolds number computed from pipe diameter and velocity. DP12BF04

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PRESSURE DROP Pressure drop is a reflection of the energy lost when a fluid is passed through a flow meter. In most applications, pressure drop is a heavily weighted factor during the meter selection process due to energy costs. As shown in Figure 5, as fluid passes through a flow restriction in a pipe, the upstream static pressure decreases sharply and then recovers somewhat downstream of the restriction. This difference between the upstream static pressure and the final downstream static pressure is called the pressure drop or permanent (unrecoverable) pressure loss. Figure 6 shows the estimated permanent pressure loss for various differential pressure type flow meters. Figure 5 Unrecoverable Pressure Loss High Pressure Tap

Low Pressure Tap

Permanent Head Loss Measureable Head

e Pr

e ur ss

of Pr

ile

DP12BF05

During design, the unrecoverable pressure loss for differential type flow meters can usually be calculated as a percentage of the differential meter range selected. Historically, in refining and chemicals, standard meter differential ranges of 10, 20, 25, 50, 100, and 200 in. of water, (25, 50, 62.5, 125, 250, 500 mbar) are used. For specified flow rates, this resulted in non-standard orifice bore sizes which had to be bored to tolerances of 0.001 in. (0.025 mm). With today's calibration technology, the use of standard orifice sizes - typically increments of 0.25 or 0.125 in. (6 - 12 mm) - can be considered to facilitate ordering and stocking orifice plates. For new designs, a preliminary meter range of 100 in. (125 mbar) is preferred. This represents a good compromise between a sufficient differential pressure for accuracy and permanent pressure loss. For example, for most orifice plates, the permanent pressure loss is usually around 60 percent of the meter range. For a 100 in. (250 mbar) of water meter range, this equates approximately to 60 in. of water (150 mbar) or 2.0 psi (0.15 bar). Again, the normal flow rate (70 - 80% of full scale flow rate) will occur at 50 - 60% of these full scale pressure differentials. This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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DESIGN PRACTICES

July, 2007

Because the density of compressible fluids changes as it flows through the flow element, an “expansion factor (Y)" or density correction is normally included. For maximum accuracy, this change in density should be limited to 1.0 percent, when determining Y from an upstream static pressure measurement. This can be achieved by keeping the differential meter range to less than 1/40th of the upstream line pressure (absolute). In cases where it is known that the downstream static pressure is used in the flow calculation, the differential meter range should be less than 1/15th of the downstream line pressure (absolute) to achieve the same 1.0 percent density change limit, since the Y curves show a given change in differential pressure causes less variation in the value of Y2 under these conditions. Regardless of which location is used to determine the expansion factor (Y), the selected meter range in inches of water (mm) should not exceed 1.5 times the upstream static pressure value in psia (bara). If the minimum pressure of a liquid flowing through the differential producing device is below the bubble point of the liquid, flashing will cause multi-phase flow, resulting in severe loss of measurement accuracy. Figure 6 Overall Permanent Pressure Loss Through Various Primary Elements 100

90

80 Orifice

Pressure Loss, % of Flange Tap ΔP

70

60 Flow Nozzle 50

40

30 Venturi Tubes 20 Short Form

10 Dall Flow Tube 0 0 DP12BF06

0.2

0.3

0.4

0.5

0.6

0.7

0.8

Diameter Ratio

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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4.2.5

July, 2007

Straight Run Requirements

As the process fluid approaches the inlet of a flow meter, it is important that the fluid velocity profile be not only flat as explained before but also reasonably symmetrical about the longitudinal axis of the pipe. To obtain this desired characteristic, it is necessary to provide long straight pipe runs upstream of the meter which are free of any obstructions to the flow. These straight run requirements differ by flow meter type, and are heavily influenced by the piping geometry immediately ahead and preceding a meter. Typical minimum straight run requirements are provided in GP 3-6-1, Piping for Instruments. For more detailed information, the designer is referred to the Industry Practices listed in the reference section of this design practice. A general “rule of thumb" is 20 pipe diameters upstream, and 5 pipe diameters downstream. In many installations it is impossible to provide sufficient lengths of straight pipe to remove swirl and to restore an acceptable profile geometry. For this reason flow conditioners are used in combination with specified pipe lengths. Distortion and swirl can be caused by close-coupled elbows in different planes. Use of flow conditioners is the simplest and low cost option to eliminate the swirl and bring the profile into symmetry. AGA-ASME tube-bundle conditioners are widely used in the industry. Straight run requirements are lower for some of the non-head devices; in particular, the following: magnetic, coriolis and multiphase. No straight run piping is required for positive displacement meters. 4.2.6

Meter Selection Tables

For general flow measurement, the orifice meter is currently the first choice. This is primarily due to acceptable accuracy, wide industry acceptance, large published databases from reputable calibration laboratories, and ease of calibration. However, many companies are considering vortex meters as the meter of choice, because of its lower cost. The major drawback of orifice and vortex flowmeters is the inability to check the meter operation without a prover. Table 3 lists the flow meter types along with which services they are not suitable for. Table 4 lists the flow meter types and provides some indication of their advantages and disadvantages, as well as the applicable pipe sizes. Note that as design pressure or pipe size increases, the availability of large-size inline flow meters is reduced due to high costs thus favoring the use of insertion type flow meters. However, insertion type flow meters of any type sample only one point in the flow profile and the requirement for a flat, symmetrical and stable flow profile discussed earlier becomes even more critical.

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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July, 2007

Table 3 Meter Suitability

Large Pipe/Duct Sizes (> 24”)

Multi-Phase Flow

Custody Transfer

Low Flow Rates

(1)

Non-Conductive Fluids

Entrained Vapor (in liq.)

(1)

Entrained Liquid (in gases)

Entrained Particulates (in liq.)

Changing MW

Fouling Services

High Viscosity

Steam

Clean Liquid

Clean Gas

TYPE OF MEASUREMENT ELEMENT

Low Reynolds Nos.

SERVICE CONDITIONS

HEAD DEVICES (SQUARE ROOT) Concentric Orifice

Y

Y

Y

Quadrant Edge Orifice

Y

Y

Segmental Orifice Eccentric Orifice

Y

Integral Orifice

Y

Y

Elbow Meter

Y

Y

Y

Y

Wedge Meter

Y

Y

Y

Venturi

Y

Y

Y

Y

Y

Y

Y

(1)

(1)

Y

(1) (1)

Y

Y

Y

Y

Y

Y

Y

(1)

(1)

(1)

(1)

Y

(1)

(1)

Y

(1)

(1)

Y

(1)

Y

(1)

(1)

Y

(1)

Y

(1)

(1)

Y

(1)

Y

Y

Y

Y (1)

Y

Y Y

Y

Dall / Lo Loss Tube

Y

Y

Y

Flow Nozzle

Y

Y

Y

Pitot Tube

Y

Y

Y

Y

(1)

Y

Pitot-Venturi

Y

Y

Y

Y

(1)

Y

Annubar (Averaging Pitot)

Y

Y

Y

(1)

Y

Y

Y

Y

(1)

Y Y

Y

OPEN CHANNEL Flume

Y

Y

Y

Y

NON-HEAD DEVICES Turbine Meter

Y

Y

Variable Area

Y

Y

Positive Displacement

Y

Y

Magnetic

(1) Y

Y

Ultrasonic (liquid service)

(1)

Y

(4) Y

Y

Coriolis (Mass)

Y

Y

Thermal

Y

(1)

Y Y

(1)

Y

Y

Y

Y

Y

Y

(1)

Y

Y

Y

Y

Y

Multi-Phase

(1)

Y

Y

Y

Y

Vortex Shedding

(1)

Y

Y

Ultrasonic (gas service)

Y

Y

Y

Y Y

Y

Y

Y

Y

(1)

(1)

Y

Y

Y

(2)

Y

Y

Y

(1)

Y

Y

(1)

(1)

Y

(1)

Y

Y Y

Y

(1)

(1)

(1)

Y

Y

Y

Y

Y

(3)

Y (1)

Y

Notes: Not recommended for this condition. Y

Will not significantly affect measurement.

(1)

Depends on application, by exception.

(2)

Only in flare service for oil loss control.

(3)

Some types require conductive fluid.

(4) Some types depend on entrained particles or bubbles. This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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July, 2007

Table 4 - Flow Meter Selection Criteria TYPE OF MEASURING ELEMENT

APPLICABLE SERVICES

UNSUITABLE SERVICES

ADVANTAGES

DISADVANTAGES

APPLICABLE PIPE SIZES

HEAD DEVICES (SQUARE ROOT) Concentric Orifice

Most

Multi-Phase, dirty, high viscosity

Quadrant Edge Orifice

High viscosity

Segmental Orifice Eccentric Orifice Integral Orifice

Fouling services Entrained gas, Solids deposits Low flow rates

Elbow Meter

Control (repeatability)

Wedge Meter

Most

Venturi

Most

—

Dahl / Lo Loss Tube

Most

—

Low pressure loss, High accuracy Low pressure loss

Flow Nozzle

Most

—

Low pressure loss

Pitot Tube

Clean services

Dirty services

Low cost

Pitot-Venturi Averaging Pitot

Clean services Large sizes, Additions

Dirty services —

Flume

Large liquid volumes

Gases, Steam

High d/p produced Can be added thru hot-tap High capacity

Turbine Meter

Clean services

Dirty services, High viscosity

Variable Area

Clean services, Low flow rates —

Fouling services Dirty services

High accuracy

Non-Conductive fluids

Ultrasonic (transit time)

Conductive liquids, Fouling services, Slurries, Corrosive Flare metering, Variable MW

No pressure loss, Minimum run lengths No pressure loss

Ultrasonic (doppler)

Liquids

Clean services

Vortex shedding

High temperature

Fouling, Slurries, High viscosity

Coriolis (mass)

Most

Target

Suspended solids

Fouling services

Thermal

Clean gases

High temperature, Fouling

— — —

Widely used

High pressure loss

1/2 - 36 in. (12.7 - 914 mm) 2 - 14 in. (50 - 350 mm)

—

High pressure loss, High cost

— —

High pressure loss High pressure loss, Low accuracy Must be calibrated in laboratory

2 - 14 in. (50 - 350 mm) 2 - 14 in. (50 - 350 mm)

Low accuracy

2 in. and higher (50 mm) 1/2 - 12 in. (12.5 - 305 mm)

Fouling services

Small size

High accuracy, Low velocity Fouling services

Low cost Low rates

— High cost High cost, Removal difficult

1/2 in. (12.5 mm)

3 - 72 in. (100 mm - 1.8 m) 4 - 48 in. (100 mm - 1.2 m)

High cost, Removal difficult Removal difficult, Low d/p produced

4 - 48 in. (100 mm - 1.2 m) Very large

Cannot be removed Large sizes require support (vibration) Low accuracy

Very large 1 - 72 in. (25 mm - 1.8 m) Unlimited

—

3/16 - 24 in. (4.7 - 610 mm)

NON-HEAD DEVICES

Positive Displacement Magnetic

—

—

High accuracy —

No pressure loss, Non-Intrusive Range, Insensitivity to fluid type Mass measurement — Low pressure loss, Very low rates possible

Must be vertical

1/8 - 3 in. (3 - 75 mm)

High cost, High maintenance High cost

1 - 16 in. (25 - 400 mm) 0.1 - 96 in. (2.5 mm - 2.4 m)

High cost

1/8 - 120 in. (3.1 mm - 3 m)

High cost

1/2 - 72 in. (12.5 mm - 1.8 m) 1 - 8 in. (25 - 200 mm)

Must be proved to verify accuracy High cost, Space requirements

1/2 - 6 in. (12.7 - 150 mm)

Low accuracy

0.5 - 48 in. (12.5 mm - 1.2 m)

—

Most

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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Multi-Phase

July, 2007

Multiphase (liq/liq/gas)

Single phase

5

Saves cost of three-phase separator

VERY high cost

3 - 6 in. (75 - 150 mm)

FLOW MEASUREMENT DEVICES

There are several different types of flow measurement devices. The most common type of volumetric flow measurement device is “differential producers" which rely in inferring the flow rate from the square root of the measured differential produced across an engineered restriction in the pipe. Other types of volumetric flow measurement devices, rely on inferring the flow rate from the fluid velocity in the pipe. An additional type, which is a mass meter is the “Coriolis meter" which utilizes the coriolis effect to measure mass flow rates. The remaining types include open channel meters and positive displacement flowmeters. 5.1

DIFFERENTIAL PRESSURE TYPE METERS

The most widely-used flow meters in the petrochemical industry are d/p meters; generally using an orifice plate as the differential producer. 5.1.1

Basic Flow Rate Equation

It is not the intent of this section to derive the basic flow rate equation from Bernoulli's equation. If the reader is interested in this derivation, please refer to DP XIV - Fluid Flow. Pegasys - ExxonMobil Standard Flow Meter Analysis / Sizing Program is the recommended flow calculation program to be used. The true mass flow rate equation for both liquids and gases (vapors) can be represented as follows: qM = NMρ

C Y1 Fad2 1 − β4

h w ρf 1

UNITS

where:

qM NMρ C

= = =

Y1

=

Fa

=

d hw

= =

Mass flow rate Conversion factor for the units used Discharge Coefficient of a given flow meter geometry Gas Expansion Factor (for Vapors and Steam only) Thermal Expansion Factor correction for differential producers Bore of the differential producer Differential Pressure

β ρf1

= =

D

=

Customary lbm/hr

358.9268 for lb/hr dimensionless

Metric

kg/hr 162.8065 for kg/hr

dimensionless in./in. °F

mm/mm °C mm mm of water at 4°C, 1.03361 kg/cm2, and 9.8066 m/s2

Beta ratio (d/D) Density at flowing conditions

in. inches of water at 60°F, 14.696 psia, 32.174 ft/s2 dimensionless lbm/ft3

Internal Pipe Diameter of the line

in.

mm

kg/m3

This form of the equation originates from Foxboro's Flow Measurement Engineering Handbook by R. W. Miller, and is the basis for all orifice design calculations performed by the Pegasys - ExxonMobil flow meter analysis / sizing program. The Gas Expansion Factor, Y1, can be determined from equations in Miller's handbook or from Figure 5 in the Fluid Flow Design Practice, DP XIV-C.

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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5.1.2

July, 2007

Orifice Meters

The most widely used differential pressure flow meter is the orifice meter. ASME and API testing over the last 75 years has determined the empirical discharge coefficient to a high degree of certainty for a wide range of liquid, vapor and steam flow rates and flowing conditions. Orifice meter installations generally consist of a set of orifice flanges, two valved tap connections, interconnecting piping or tubing, a transmitter manifold, and a differential pressure sensor (transmitter). Concentric, Square Edge Orifice - The concentric, square edge orifice shown in Figure 7 is the most commonly used of all the orifice type flow meters for both liquid and vapor applications. It is by far the least expensive to fabricate (100 to 300 US dollars) and the easiest to install or change. If installed correctly, accuracies of ± 1.0 to 5.0 percent of full scale are possible. However, the designer must recognize that these devices have certain limitations.

The first limitation is Reynolds number. As shown earlier in Figure 4, below a Reynolds number of 10,000, the basic discharge coefficient changes markedly with Reynolds number, and hence with flow rate. For this reason, concentric, square edge orifices are not used in this region. Secondly, because of the square root relationship between flow rate and differential pressure, the flow rangeability of this device is severely limited without taking certain measures, like using high-accuracy digital (“Smart") or multiple differential pressure transmitters. There are some applications where the net pressure loss across an orifice (discussed earlier) is important. For all practical purposes, the permanent (unrecoverable) pressure loss across an orifice can be stated to be roughly about 60% of the selected full scale differential pressure transmitter range. For example, if a full scale differential pressure transmitter range of 100 in. of water (125 mbar) is selected, the permanent pressure loss would be roughly 60 in. of water (75 mbar) (100 times 0.60). If this unrecoverable pressure loss is too great, an alternate metering device should be evaluated for the application. Two types of orifice fittings have been designed to allow removing the orifice plate from the line without having to unbolt the orifice flanges and spring them apart. These are the Daniels Senior™ and the Junior™ fitting. The Junior fitting requires the pipeline to be depressured before removing the orifice plate; the Senior fitting allows removal of the plate with the line at flowing conditions. These fittings are convenient, but are quite expensive compared to a conventional pair of orifice flanges, and are used only where frequent plate changes are required to accommodate changing flow conditions or frequent plate inspection is required by contract. Senior fittings should be considered for Custody Transfer measurements. Figure 7 Concentric Sharp Edge Orifice

DP12BF07

Quadrant Edge Orifice - Unlike the square edge orifice, the upstream edge of quadrant edge orifice, is machined into a quarter circle or quadrant. This gives a flow characteristic between that of the sharp edged plate and a flow nozzle, and tests show the discharge coefficient to be quite constant down to a pipe Reynolds number of 1000. It is this phenomenon that makes the quadrant edge orifice useful in the viscous range below a pipe Reynolds number of 10,000 where the discharge coefficient (C) of a square edged orifice is known to change appreciably with either flow rate or viscosity. A quadrant edge orifice is shown in Figure 8.

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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The Global Practices (GPs) allow the quadrant edge orifice to be used in applications with Reynolds numbers below 10,000. It is often found in liquid fuel to furnace applications. Its usefulness is limited, since the required radius of the quadrant becomes quite large with increasing line size and d/D ratios, thus requiring a much thicker plate than normal and giving many of the disadvantages of the flow nozzle. The unrecoverable pressure loss across a quadrant edge is approximately the same as the square edge orifice. Figure 8 Quadrant Edge Orifice

DP12BF08

Eccentric Orifice - Eccentric orifices, unlike square edge orifices, do not have their flow opening (bore) in the center of the plate, but rather tangent to a circle whose diameter is equal to 98 percent of that of the pipe (see Figure 9). Eccentric orifices are often used to measure fluids that are in two phases, where the primary phase is considerably larger in quantity than the secondary phase. However, it is important to know which is the primary and secondary phase of the fluid, as this is required to define the position of the bore on the plate, either at the top or bottom.

For liquids with entrained vapors, the flow opening (bore) will be at the top of the plate, as shown in Figure 9A. This is done to allow the entrained vapor in the flowing liquid to pass through the orifice, and not get trapped on the upstream side of the plate which can influence the flow reading. For vapors with entrained liquids, or sediment bearing liquids, the bore will be at the bottom of the plate (see Figure 9B). Similar to the above, this is done to allow any condensate in the vapor or sediment in liquids to pass through the orifice, and not build up on the upstream side of the plate which can influence the flow reading. Due to the forced change in fluid pattern as it enters the orifice and the inherent distortion downstream, the accuracy of an eccentric orifice suffers. Eccentric orifice discharge coefficients (C) are only reliable to ± 2 percent. The unrecoverable pressure loss across an eccentric orifice is approximately the same as the square edge orifice.

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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Figure 9 Eccentric Orifice

A

B

DP12BF09

Segmental Orifice - Where there is a need to measure liquids containing solids, the segmental orifice is a low cost solution. This meter design, as shown in Figure 10, has a wide opening at the bottom of the plate to allow for free passage of the solids. Similar to the eccentric orifice, the segment is tangent to a circle whose diameter is equal to 98 percent of the pipe diameter. During field installation, it is important that the segment opening is well aligned and not covered by the inlet pipe or flange gasket.

The unrecoverable pressure loss across a segmental orifice is approximately the same as the square edge orifice. Figure 10 Segmental Orifice

DP12BF10

Integral Orifice - Integral orifices are normally used to measure very low flow rates. Typically, for liquid flow rates down to 0.04 gal/min. (0.015 l/m), and for gases as low as 0.9 standard cubic ft/hr (25 standard liters/hour). Accuracy is ± 2.0 percent of full scale.

Integral orifices come in standard pipe sizes of 0.5 in. (12.3 mm), 1.0 in. (25.4 mm), and 1.5 in. (37.7 mm). They also come in two different styles: a straight through design and a U-bend design (see Figure 11). For these meter sizes, the orifice bore can range from 0.010 in. (0.25 mm) to 1.184 in. (30.07 mm). Due to these very small clearances, the use of these devices in dirty services should be avoided and the use of strainers should be considered.

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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Figure 11 Integral Orifice Meters High Pressure Pf1

Low Pressure Pf2

Integral Orifice

High Pressure Pf1

Integral Orifice

Diaphragm Capsule Low Pressure Pf2

DP12BF11

U-Bend

Straight-Thru

Diaphragm Capsule

U-Bend

Elbow Meter - Flow measurement using elbow taps utilizes the differential pressure developed by centrifugal force as the direction of fluid flow is changed in a piping elbow (see Figure 12). Since most piping installations already have elbows, installation costs are minimal. Since a low differential pressure is developed, elbow meters are only suitable for high fluid velocities, typically greater than 5 ft/s (1.5 m/s). Because of the sensitivity to flow velocity distribution, long upstream lengths are required. A minimum of 25 diameters upstream and 10 diameters downstream are recommended. Accuracy is poor, with best achievable being around ± 4.25 %. However, repeatability is good, so elbow meters are usually found in flow control applications where absolute accuracy is unimportant. Figure 12 Elbow Meter

High Pressure Port

Low Pressure Port

DP12BF12

5.1.3

Segmental Wedge Meter

The Taylor segmental wedge flow element is similar in nature to the segmental orifice. The major difference being the Taylor wedge is fabricated as a spool piece pipe section which has a V-notch (segmental wedge) cut into the center. See Figure 13. Accuracy is quoted to be in the range of ± 0.5 to 5.0 percent. One of the advantages of the Wedge meter is its ability to maintain the square root flow relationship over a much lower value of Reynolds number than any other differential producing element. The Wedge meter's discharge coefficient is constant down to a Reynolds number of 300. This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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The segmental Wedge has been used in many h Exxon sites to handle difficult to measure fluids that fall into the categories of hot, viscous, corrosive, erosive, and liquids with solids (slurries). It can also handle fluids that tend to flash or solidify when dead ended in a typical flow transmitter. Compared to other differential flow elements, the segmental Wedge element will have a significantly higher initial cost. example, a 2 in. ABB Wedge meter costs around $2500 US dollars, and the cost increases linearly with pipe size.

For

Figure 13 Segmental Wedge Meter

High

Flow Direction

5.1.4

Low

Wedge Flow Element

Venturi Tube

As shown in Figure 14, a Venturi Tube is a contoured flow element which can be used in both liquid and gas applications. The inlet section of this flow element is typically angled to less than 21 degrees to reduce the chances of vapor bubbles forming in the throat section which will cause the meter to read incorrectly and can lead to cavitation. This design feature is the primary reason why Venturi tubes have the lowest permanent pressure loss of any differential producing flow element. However, most Venturi tube applications require Reynolds numbers of 75,000 or more, as this is the region where their discharge coefficient (C) is constant. The Venturi tube is the most expensive differential pressure device, but is sometimes justified when net pressure loss is expensive, such as the suction line to a cat cracker air blower. The net pressure loss of a properly designed venturi is about 10% of the gross differential pressure from inlet to throat. Venturi tubes are also sometimes found in applications with liquids containing solids (slurries), as its design provides for unobstructed flow through the element without any chance of solids buildup. Calibrated accuracy is in the range of ± 0.5 to 1.5 percent. In addition to the standard set of pressure taps (inlet, throat) for measuring the developed differential pressure across the tube, Venturi's can also be constructed with a system of pressure taps which project radially into the pipe and feed into a common chamber known as a piezometer ring. This arrangement provides for an average pressure measurement around the circumference of the stream, and is usually found in low pressure applications.

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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Figure 14 Venturi Meter Low Pressure Tap

High Pressure Tap

Permanent Head Loss re P ssu Pre le rofi

Measurable Head

DP12BF14

5.1.5

Lo Loss Tube or Dall Tube

Dall tubes and “Lo-Loss" flow tubes (see Figure 15) are somewhat shorter in length and less expensive than the classic Venturi, but not as inexpensive as an orifice plate. The “Lo-Loss" flow tube is a registered trademark of Badger Meter, Inc. These flow elements can be used in both liquid and gas applications. Calibrated accuracy is about ± 1.0 percent. These flow elements have exceptionally low permanent pressure loss compared to any other differential producer, as shown earlier in Figure 6. In flow applications where a significant pressure drop can not be tolerated, the Dall tube or “Lo-Loss" design should be evaluated. These flow elements require Reynolds numbers of 125,000 or more, as this is the region where their discharge coefficient (C) is constant. Outside of this region, the flow accuracy is reduced. Dall tubes and “Lo-Loss" flow tubes are also more sensitive than a Venturi to deposits left by dirty or solid containing streams. Unlike the Venturi, the pressure sensing taps on these devices are only in the order of 0.125 in. (3.18 mm) in diameter, and can be prone to plugging. Figure 15 Badger Lo-Loss™ Flow Tube High Pressure Connection Low Pressure Connection

Flow

DP12BF15

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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5.1.6

July, 2007

Flow Nozzle

A flow nozzle is usually used to measure steam flow, and particularly steam at high temperatures and pressures such as in a boiler outlet line. The elliptical design of its entrance cone (Figure 16) lends itself to steam applications which normally tend to wear away the sharp edge of an orifice plate, especially when the steam approaches its saturation point. Flow nozzles come in a variety of designs. They range from simple line insertable elements, like Figure 16, which are clamped between two pipe flanges to complete flanged spool piece pipe sections. From a maintenance standpoint, the flanged spool piece design is preferred as it provides for easy removal during element inspection. Similar to an orifice plate, the permanent pressure loss through a nozzle is relatively high. It is approximately 30 to 95 % of the differential pressure (meter DP range) developed across the element. Flow nozzles also have a higher initial cost. Calibrated accuracy is ± 1.0 percent at best. Figure 16 Flow Nozzle High Pressure Connection

Low Pressure Connection

Flow

DP12BF16

5.1.7

Pitot Tube and Averaging Pitots

The pitot tube and averaging pitot flow elements have the advantages of essentially no permanent pressure loss and relatively low initial cost. As shown in Figure 17, these are line insertable devices which can be installed into a flow stream through a tap in the wall of the pipe. An Annubar™ is one vendor's particular design of an averaging pitot tube and is widely used in the industry. These devices can be used to measure both liquids and gases. Pitot tubes and averaging pitots are typically found in applications requiring a flow measurement in large pipe sizes or rectangular ducts – 10 in. (250 mm) and larger – where conventional flow elements would be very expensive to fabricate, and may not be justifiable on cost. Also, a pitot tube or averaging pitot should not be used in an application where accuracy is important. These flow elements are highly dependent on velocity profile. Typical calibrated accuracy is ± 3 percent. If a pitot tube is used, it is recommended that a pipe traverse be made to determine the point of average velocity upon which to locate the pitot element. Pitot tubes and averaging pitots do not work well in dirty streams, or streams containing solids. Averaging pitots have pressure sensing ports equally spaced along the tube section inserted into the process line. These pressure ports and the pitot inlet are relatively small in diameter. Usually, in dirty stream applications, solids tend to plug these openings and reduce the accuracy and reliability of the flow reading.

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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Figure 17 Pitot Tube And Averaging Pitot PITOT TUBE

AVERAGING PITOT Flow

HP LP

DP12BF17

Another disadvantage of a pitot tube is they do not produce a significant differential flow signal in most large pipe or duct applications. Typically, the differential flow signal produced at full scale flow is on the order of 1 in. (25.4 mm) of water column or less. At this level, it is sometimes difficult to discriminate between an actual flow rate change and the background noise of the process itself. An averaging pitot is typically designed to generate pressure differentials in the same range as an orifice plate with a low permanent pressure loss. Note also that averaging pitot (Annubar™) on large size ducts require proper support on both ends. 5.1.8

Pitot-Venturi Tube

The Pitot-Venturi tube (Figure 18), is an outgrowth from the Pitot tube. It can be used to measure both liquids and gases. However, the advantage of this flow element is its ability to develop roughly fifteen times the differential flow signal of the standard Pitot tube. Accuracy is roughly ± 1.0 percent, if properly installed and calibrated. Figure 18 Pitot-Venturi Tube Low Pressure High Pressure

Impact Hole

Inner Venturi

Outer Venturi

Inner Throat DP12BF18

Outer Throat

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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5.2

5.2.1

July, 2007

NON-HEAD TYPE METERS

Turbine Meter

A turbine meter (Figure 19) derives its name from its operating principle. A turbine wheel (rotor) is set in the path of the flowing fluid. As the fluid enters the open volume between the blades of the rotor, it is deflected by the angle of the blades and imparts a force that causes the rotor to turn. The speed at which the rotor turns has a linear relationship to the flow rate over a specified range. Figure 19 Typical Turbine Meter Assembly Pickup Coil Housing

Meter Housing

Downstream Stator

Rotor Upstream Stator

Deflector Ring

DP12BF19

Several methods are used to transmit this motion to a readout device. In some older applications, a mechanical device conveyed this rotor motion directly to a register. In modern applications, however, the usual method is to use an electrical signal. A pickup coil containing a permanent magnet is usually mounted on the meter body. As each blade tip of the rotor passes the coil, it changes the magnetic flux and produces a pulse. Each pulse that is generated corresponds to a fixed quantity of volume which has passed through the meter. This ratio of pulses per unit volume is defined as the “meter factor" of the turbine meter. For applications requiring high accuracy, like custody transfer, multiple pickup coils are usually installed on a turbine meter to allow fidelity checks on the generated pulses to assure the flow signal is not getting corrupted. For further information on this concept, the designer is referred to the API Manual of Petroleum Measurement Standards, Chapter 5 - Liquid Metering, Section 5 - Fidelity and Security of Flow Measurement Pulsed Data Transmission Systems. The minimum requirement is Level B. Turbine meters are expensive, but do have excellent accuracy and good rangeability (roughly 10:1). They are usually limited to clean liquid applications, for obvious reasons. When properly designed and installed, they can achieve accuracies in the order of ± 0.2 percent of reading when calibrated against a suitable prover. Turbine meters, and their associated flow straighteners, typically have about 8 - 10 psi (55.2 - 69 kPa) pressure drop across them at normal rated flow. They are also used in gas applications, but the orifice plate is still the preferred choice for gas applications due to lower installed cost. Fluid viscosity and flow rate play a major role in the decision whether to use a turbine meter. Figure 20 presents guidelines for when to select between turbine meters and positive displacement meters. In general, turbine meters perform better with low viscosity liquids (such as propane, gasoline, kerosene, or diesel oil) and under fully developed turbulent flow (Reynolds number above 10,000). They also have a longer service life than do positive displacement meters.

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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Figure 20 Selection Guide For Displacement And Turbine Meters Viscosity, μ (Center of Pressure) >100 100 30 Displacement Best 10 3 Turbine Considered 1 0.3

Displacement Considered

Turbine Best

0.1 >0.1 3

10

DP12BF20

30

100

300

1,000

3,000 10,000 30,000 100,000

Flow Rate, Q (Gallons Per Minute)

Turbine meters should not be used on liquids that contain waxy components that may collect on the surfaces of the meter and effect its cross-sectional flow area. Precautions such as overspeeding protection and the installation of upstream strainers must be strictly followed for reliable performance. Additionally air eliminators must be used in the case of liquid service. If a turbine meter is selected for a specific application, facilities must also be provided to facilitate periodic calibration (i.e., proving). That is, verification of its meter factor. This is usually done in one of two ways: either inline proving (most common) or shop proving. In the case of inline proving, appropriate valving must be installed as part of the turbine meter station to allow the isolation and tie-in of a portable prover truck or equivalent. For shop proving, the meter is simply removed from the line and replaced by a similar meter in kind. The removed meter is then sent off site to a calibration facility for proving. 5.2.2

Positive Displacement Meter

Positive displacement (PD) meters measure volumetric flow by continuously separating (isolating) a flow stream into discrete volumetric segments, counting them, and then returning it to the flowing stream. Some of the more common PD meter types are shown in Figure 21. PD meters are very accurate, but are sensitive to viscosity as shown in Figure 20. They are predominantly found in liquid applications in most products sold at marketing terminals. They are slightly higher in cost than turbine meters, but with equal rangeability (10:1). PD meters typically have about 3 - 7 psi (20.7 - 48.3 kPa) pressure drop across them at normal rated flow. Like the turbine meter, PD meters contain electronic pickup coils that generate pulses corresponding to the fixed volume of product that has passed through the meter. This ratio of pulses per unit volume is defined as the “meter factor" of the PD meter. For high accuracy applications, like custody transfer, multiple pickups may be used for security reasons as discussed above under the turbine meter. Precautions are necessary, in liquid service meters, to prevent the passage of vapor or air. This is by including the installation of air eliminators. Strainers are a must for these meters to remove sediment. Two popular styles of PD meters are the Rotating vane design (Smith - FMC Measurement Solutions) and the Oval Gear design (Brooks - Emerson Process Management Division). The Rotating vane design has no fixed tolerances and can pass dirt unhindered. The Oval Gear design has fixed tolerances and will jam up when passing dirt like sand. When designed and installed properly, PD meters achieve accuracies in the order of ± 0.2 percent of reading. To maintain this accuracy, these meters require periodic calibration against a suitable prover to verify its meter factor. As discussed above under turbine meters, this proving may be done inline (most common), or off site at a calibration facility. If done inline, appropriate valving to allow the isolation and tie-in of a portable prover truck or equivalent must be provided as part of the PD meter station. This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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Figure 21 Types Of Positive Displacement Meters Six Common Positive-Displacement Meter Principles. Clockwise from Top Left: Rotating-Paddle, Bi-Rotor, Nutating Disc, Oval Gear, Sliding Vane, Oscillating Piston.

DP12BF21

5.2.3

Vortex Shedding Meter

The vortex flow meter measures liquids, gases, and steam flow rates using the principle of vortex shedding (Von Karman vortices). The transmitter produces either an electronic analog or pulse rate signal that is linearly proportional to the volumetric flow rate. The phenomenon of vortex shedding occurs whenever a non-streamlined obstruction (typically called a bluff body) is placed in a flowing stream. As fluid passes around this obstruction, the fluid stream cannot follow the sharp contours and becomes separated. High velocity liquid particles flow past the lower velocity (or stationary) particles in the vicinity of the body to form a shear layer. It is this shear layer that breaks down after some length of travel into well-defined vortices as shown in Figure 22. Vortices are rotational flow zones that form alternately on each side of the bluff body with a frequency proportional to the liquid flow rate. Differential pressure occurs as the vortices are formed and shed. This alternating pressure or force variation is used to actuate a sealed sensor such as a strain gauge or piezoelectric crystal to produce a frequency proportional to vortex shedding.

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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Figure 22 Vortex Shedding Meter

Vertical Bluff Body

Flow

DP12BF22

Vortex meters come in sizes from 1 - 48 in. (25.4 - 1200 mm). Initial costs are relatively high, but maintenance is low and the calibrated accuracy can be from ± 1.0 to 2 percent of reading. They also have a very high rangeability of 10:1, but with a permanent pressure loss about equal to an orifice plate. Vortex meters should not be used in pulsating flow service, as the flow-induced pressure pulsations are detected as vortex pressure pulsations, causing highly inaccurate readings. Also, they should not be used in liquids with entrained dirt because the dirt will become lodged in the bluff body. When sizing a vortex meter the Reynolds number should be calculated at both the upper and lower flow range to be sure that it falls in the operating range of the vortex meter. The same facilities specified for the calibration of a turbine meter (see above) are required for calibration of vortex flow meters. 5.2.4

Magnetic Flow Meter

The magnetic flow meter (Figure 23) measures flow according to Faraday's law of magnetic induction, which states that the voltage induced in a conductor moving through a magnetic field is proportional to the velocity of the conductor. In process applications, the “conductor" is the process fluid itself. The faster it flows, the greater the voltage induced across the electrodes of the meter. The magnetic flow meter can accommodate solids in suspension, as well as most corrosive fluids. Accuracy is ± 1.0 percent of full scale, where the output is linear with flow rate. One of the most important requirements when thinking of using a magnetic flow meter for an application is to assure the fluid to be measured is conductive. If not, the meter will not work. Most liquid hydrocarbons do not have sufficient conductivity for measurement by a magnetic meter. Magnetic meters are relatively expensive and are usually plagued by zero-offset problems (no-flow indication).

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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Figure 23 Magnetic Flowmeter Principle Electromagnet

Process Liquid

DP12BF23

Measuring Tube Electrodes

Because there is no obstruction in the flow path, these meters have no inherent permanent pressure loss. Since the flow tube of most magnetic flow meters are lined, it is very important that the correct liner be selected for compatibility with the process fluid to be measured. Polyurethane and PTFE are the two most common liner materials. Applications in h Exxon sites are rare but may include the measurement of sulfuric acid, and some waste water streams. 5.2.5

Ultrasonic Flow Meter

One feature of some ultrasonic flow meters is they are non-intrusive devices, meaning they mount external to the pipe. A typical clamp-on ultrasonic meter consists of two transducers mounted opposite each other on the pipe, and generally positioned so that the sound beams from the transducers cross at a 45 degree angle as shown in Figure 24. Accuracies range from ± 1 to 5 percent. Other, higher accuracy ultrasonic designs have transducers mounted through the wall of the pipe with the transmitter and receivers mounted flush with the inside pipe wall so as to not obstruct flow or to attract fouling. Figure 24 Ultrasonic Flowmeter Schematic Doppler Type

Flow

Transit Time Type

Flow

DP12BF24

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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There are basically two methods used to interpret velocity measurement using the acoustical approach, Doppler and time-of-flight. In the Doppler method, the sound waves are reflected off bubbles or entrained particles in the liquid. The difference in frequency of the transmitted signal and the reflected signal is a function of the fluid velocity (the Doppler effect). This type of meter is frequently installed external to the pipe, and is completely non-intrusive. This is especially convenient for spot checks of various flow streams not usually metered. The other method is differential time of flight which is nothing more than a measurement of the difference in transit time between two sound waves which are transmitted in opposite directions diagonally across the pipe. The difference in transit time (time-offlight) is a function of the fluid velocity. This meter has very wide turndown (better than 100:1), and provides mass flow rate, density, and volumetric flow rate. It is unfortunately, very expensive, but the cost is essentially independent of line size. When using external ultra-sonic flow meters there are some very important items to consider. First, it is imperative that the pipe surface where the transducers are to be mounted is clean and polished. If not, this will add attenuation to the transmitted acoustic signal. Second, in order to assure good transducer contact with the pipe, an acoustic coupler paste is usually used. Make sure the paste used is good for the operating temperature of the line, and will not degrade with temperature. Finally, make sure the transducers used are able to withstand the process operating temperature where the measurement is to be made. If the transducer is not rated for this temperature, you run the risk of burning up the transducer. Typical applications of external Doppler ultra-sonic flow meters in h Exxon sites include performance testing of heat exchangers, or in applications where an inline flow meter is considered suspect and a spot check measurement is desired. The most frequent use of the time-of-flight meter is in metering flare gas streams. The Multipath Ultrasonic meter is the recommended meter to be used. Ultrasonic meters on custody transfer systems have to maintain the targeted accuracy. To ensure this, regular operational checks and proving of the equipment's performance should be made. Details of the proving and calibrating intervals are in the HMP's. 5.2.6

Variable Area Meter

This design is sometimes called a Rotameter™. The basic design is shown in Figure 25. As fluid moves up the tube, the float rises in proportion to the flow rate. The tube is designed to give a constant drop across the float by varying its cross sectional area. The tube may be made of glass, with an armor shroud as the meter body for air, water, or nitrogen services. For process services, glass is prohibited so the tube is stainless steel, with the indicating mechanism operated by magnetic coupling to the float. Float selection is very important, as the float shape is used to compensate for viscosity effects.

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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Figure 25 Variable Area Flowmeter Outlet

Pressure Drop Across Float

Buoyant Force of Fluid Float

Weight of Float Metering Tube

DP12BF25

Inlet

Variable area meters come in sizes from 0.25 - 6 in. (6 - 150 mm), and are accurate to ± 2.0 percent. The smaller meters are usually called purge meters. These are used to regulate small flows for purging differential pressure transmitter sensing lines for flow and level applications, where solids and slurries are present. They are also found in analyzer applications to set the flow in sample loops. 5.2.7

Coriolis (Mass) Type

The Coriolis type flow meter (Figure 26) measures fluid mass and density based on the Coriolis effect, a natural phenomenon quantified in 1835 by Gaspard Gustave de Coriolis. It is the Coriolis effect which explains why objects moving freely over the surface of the earth appear to curve. The meter consists of one or two flow tubes enclosed in a sensor housing. These tubes are vibrated at their natural frequency by an electromagnetic drive coil located at the center of the bend in the tube. The vibration is similar to that of a tuning fork, completing a full cycle about 80 times each second.

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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Figure 26 Coriolis Flowmeter Fluid Force

Flow

Flow

Vibrating Flow Tube (Single Flow Tube Shown)

Fluid Force Fluid Forces Reacting to Vibration of Flow Tube Twist Angle

Twist Angle

End View of Flow Tube Showing Twist

DP12BF26

As fluid flows into the sensor tube, it is forced to take on the vertical momentum of the vibrating tube. When the tube is moving upward during half of its vibration cycle, the fluid flowing into the sensor resists being forced upward by pushing down on the tube. Having the tube's upward momentum as it travels around the tube bend, the fluid flowing out of the sensor resists having its vertical motion decreased by pushing up on the tube. All of this causes the tube(s) to twist. When the tube is moving downward during the second half of its vibration cycle, it twists in the opposite direction. This tube twisting characteristic is a result of the Coriolis effect. The amount of sensor tube twist is directly proportional to the mass flow rate of the fluid flowing through the tube. Coriolis type flow meters are typically found in applications desiring an accurate mass flow rate, without the need to measure and correct a volumetric flow rate by applying product temperature and density compensation to get to mass flow. Coriolis meter accuracy is on the order of ± 0.5 percent of rate. One of the big use of Coriolis mass flow meters is in LPG measurement. When using Coriolis flow meters, there are some very important items to consider. First, it is imperative to maintain its flow tubes full at all times. For liquid streams, it is recommended that the flow tubes be mounted vertically downward, so as to eliminate a potential vapor trap. However, for batch plants where flushing & draining are required between batches, this may not be possible. If the meter is located in a vertical line, fluid flow should be pumped up through the meter, and not down. Second, when installing the meter in the line, locate the meter upstream of control valves, and support only the process pipe not the meter. The meter should not be rigidly supported. Third, it is very important to select the correct materials of construction for the flow tubes. Secondary pressure containment is also a requirement to avoid product release to the atmosphere. Additionally, to maintain the targeted accuracy of the Coriolis meter that are used in Custody Transfer measurement, regular operational checks and proving of the equipment's performance should be made. Details of the proving and calibrating intervals are included in the HMP's. Coriolis meters are currently limited in size to 6 in. for liquid service, and generate a higher permanent pressure loss than other meters. For gases, application of Coriolis meters is limited by pressure, molecular weight and flow rate so an instrument specialist should be consulted to verify the feasibility of the use of a coriolis meter in the application. Again, pressure drop will be a major factor. 5.2.8

Thermal Meter

The thermal meter is a liquid or gas flow sensor which consists of three temperature elements (usually two matched RTDs and a low power heater) installed in the flow stream. The low power heater is used to preferentially heat one of the RTDs. This configuration creates a temperature differential between at least two of the temperature elements, and is greatest when there is a no flow condition. As flow rate increases, heat is dissipated from the flow sensor causing the temperature differential to decrease. This measurement of temperature differential is inversely related to flow rate. The thermal meter has a fairly wide rangeability, usually 100:1 or more. Typical accuracy is on the order of ± 2.0 percent of full scale reading. This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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5.2.9

July, 2007

Multi-Phase

In the early 1990s, working commercial multiphase meters were developed. Their application is primarily in the oil production industry, where their high cost is justified by eliminating the two- or three-phase wellstream test separators and their associated meters and controls. Several types of these meters exist. One type temporarily separates the gas and liquid phases, and uses a sampling technique to measure the oil and water utilizing a coriolis meter. The most common type uses a homogenizer to make a pseudo single-phase which is metered with a conventional venturi section, and two gamma-ray sources to calculate the oil and water fractions of the stream. Accuracies are ± 5% up to a gas volume fraction of 0.95. The third type is only suitable for plug flow, and utilizes a multi-electrode capacitance or conductance probe to measure the plug flow (assumed to be the gas velocity), the fraction of the tube in plug flow, and the liquid phase flow. All three of these devices depend on microprocessor-based electronics to perform the massive statistical calculations required. Being a very difficult measurement type, this usually is left to a specialist to design and implement. 5.3

TYPICAL PROBLEMS IN FLOW MEASUREMENT

A number of potential problem areas of flow measurement are listed below, many of which can be avoided by choice of correct pipe location. Not all of the problems will effect all types of meters. However, the problems listed tend to affect differential pressure flow meters more significantly than other types of meters. 5.3.1

Deviation from Design Conditions

Normally, process flows occur at relatively constant flowing temperature and pressure. However, when the process being designed does not assure constant flowing temperature and pressure, the process designer faces the issue of whether temperature and pressure compensation is required. ExxonMobil practice is to provide P, T compensation for any custody transfer applications. Because the most common flow meter utilized in the petrochemical industry, the orifice meter, is a square-root device, determining the effect on measured flow of deviation from design flowing conditions is frequently a confusing calculation. To assist the process designer in determining the effect of these deviations for temperature, pressure, molecular weight (density or specific gravity), and compressibility, the following equations are provided:

New Flowmeter Factor = Old Flowmeter Factor x Correction Factors (shown as C x below) Gases (Volumetric Flow)

Pressure

CP =

PNew POld

Temperature

CT =

TOld TNew

Molecular Weight

CMW =

MWOld MWNew

Specific Gravity

CSG =

SGOld SGNew

Compressibility

CZ =

Z New Z Old

P in absolute units

T in Degrees, Absolute

Must also correct for T and P

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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Liquids (Volumetric Flow)

C SG =

SG New SG Old

Specific Gravity

C SG =

SG New SG Old

Molecular Weight

C MW =

MWNew MWOld

Specific Gravity

Mass Flow (Gases & Liquids)

Meter Factor (formerly known as Pen Factor)

Meter factor is the number of flow units/unit of chart scale. For example, for a 0 - 10 sq rt chart, the Meter factor is 1/10 times the flow at full scale. To find new Meter factor when meter range only is changed New Meter Factor =

5.3.2

New Meter Range Old Meter Range

x Old Meter Factor

Meter Range

To find new meter range when Meter factor only is changed New Meter Reading =

⎛ New Meter Factor ⎞ ⎟⎟ ⎜⎜ ⎝ Old Meter Factor ⎠

2

x Old Meter Reading

Double the flow, increase differential (meter range) by 4. Half the flow, decrease differential (meter range) by 1/4. 5.3.3

Required Turndown

One of the most frequently encountered “problems" is over-specified turndown requirements. Until recently, the standard orifice meter/differential pressure transmitter combination was limited to a 3:1 turndown. The usable flow range was from 30% - 95%. This was typically true of any of the square-law differential producers. Modern electronic differential pressure transmitters can provide 10:1 turndown without exceeding the accuracy specifications. Any turndown requirements outside these limits require the installation of multiple transmitters with different differential pressure ranges, or in more extreme cases, multiple, parallel meter runs. These type installations are most common in Custody Transfer Metering applications. 5.3.4

Liquid Bubble Point

Accurately measuring two-phase flow with most conventional flow measurement devices is difficult, if not impossible. Therefore, care should be taken to locate liquid flow meters such that the pressure is high enough to preclude vapor passing through the meter. However, it has been established that a small amount of vaporization (one to two weight percent) as the liquid passes through the meter can be tolerated, and will not seriously affect accuracy. Where flashing is known to occur, locate the orifice meter in a vertical run of pipe, with flow upward to prevent vapor collection, and the subsequent loss of accuracy. 5.3.5

Gas Law Deviation

If the service conditions cause a gas to deviate from the ideal gas laws, it will be necessary to know the extent of the deviation. When a choice is available, it is preferable to locate the meter in a location where this problem does not exist. This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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Viscosity

The problems caused by high viscosity or low Reynolds number have already been covered. Quite often, selection of a higher temperature location, can eliminate this problem. 5.3.7

Contamination

Solids in Liquid Streams, Liquids in Gas Streams - For measuring slurries, or for situations where some solids can be expected, the eccentric orifice, segmental orifice, Wedge, or venturi flow meters offer some solution to the problem. Gases in Liquid Streams - The eccentric orifice, with tangent at the top, or an upflow vertical line will eliminate infrequent gas carried along in liquid lines. Purge and Blowback - These have been mentioned under the heading, “variable area meter". A purge, also called blowback, is used when, for some reason, the line material would cause problems if allowed to enter the differential sensing lines (tubing or pipe) from the orifice flange taps to the differential pressure transmitter. A prime example is cat plant service where dry catalyst or the solids part of a slurry must be kept out of the sensing lines. Another common example is in metering vacuum tower bottoms, in which case the high viscosity and coke particles of the line fluid could interfere with the flow differential pressure measurement.

When using variable area meters for this purpose, purge rates are very important. This is because 1) need to have enough sensing line purge velocity to keep the solids from entering the sensing lines, 2) need to keep the purge velocity low enough to prevent false differential pressures due to friction loss, and 3) the possible effect of the purge medium used on the process. Suggested purge rates are given in GP 3-6-1. 5.4

CUSTODY TRANSFER METERING STATIONS

All custody transfer metering stations shall be designed in accordance with the applicable control requirements for custody transfer, its associated Implementation Guidelines, and any specific legal requirements for the Country of installation. The HMP and EMRE 001 Product Control Manual can be used as guides for the Custody Transfer System. Orifice metering station designs shall utilize prefabricated meter runs to ensure measurement accuracy. These meter run assemblies are usually available from meter specialty manufacturers and comprise specially selected pipe lengths carefully machined and attached to the orifice flanges. Meter run size shall be a minimum diameter of 2 in. (50 mm). If small meter runs are necessary, either the pipe will be increased to 2 in. for the length of the meter run, or honed flow calibrated meter runs shall be employed. Use of flow conditioning equipment is recommended. 5.5

METER PROVERS

Petroleum measurement standards define meter proving as the practice of comparing the performance of a meter to a known certified standard. Meter provers are mainly affiliated with liquid applications. Four types of meter provers are internationally recognized and approved for calibrating meters, particularly those assigned to custody transfer service. These are:

• • • •

Stationary Pipe Provers - unidirectional and bi-directional Master Meter Provers - positive displacement and turbine Portable Small Volume Provers Volumetric Tank Provers

In selecting a meter prover type, the most important consideration is the ability to prove the meter over its full range of operating conditions – flow rates, viscosities, temperatures, and product vapor pressures. Other factors to also consider include – number of meters to be proved, their locations, accessibility, plot space available, product contamination aspects, frequency of meter provings, etc. Stationary Pipe Provers, whether unidirectional or bi-directional, are typically the preferred choice for high capacity meters having flow rates in excess of 7500 bbls/hr (1200 m3/hr) and requiring a minimum time (typ. 0.5 to 1 hour) to calibrate. When pipe provers are selected, they are usually furnished as part of a fully automated proving system. Pipe provers are also very expensive and maintenance prone if measuring dirty products. Master Meter Provers are considered to be the most cost effective and easiest method for meter proving. Master meter provers are typically the choice for applications involving flow rate capacities from a low 1900 bbls/hr (300 m3/hr) up to a medium high of 7500 bbls/hr (1200 m3/hr). This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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For more information and specific design details on meter provers, the designer is referred to the API, Manual of Petroleum Measurement Standards - Chapter 4. 6 6.1

FLOW CONTROL APPLICATIONS

CONTROL OF PUMPS

Refer to DP X-A, Pumps - Pumping Service Design Procedures for details. 6.2

CONTROL OF COMPRESSORS

Refer to DP XI-E, Compressors - Centrifugal Compressors for details. 6.3

FLOW RATIO CONTROL

In blending and treating operations, it is often necessary to hold two or more flow rates in a fixed ratio, with the rate of one of the streams (the “wild stream") being the basis for controlling the other stream(s) (the “controlled" streams). Figure 27 illustrates this situation. Stream A is the “wild" stream and Stream B is the “controlled" stream. The rate of Stream A is set outside the flow ratio arrangement; for example, by a level controller on an upstream unit or by a manual valve. It may also be flow controlled, as indicated by the dashed valve , with the set point manually set by the operator. The desired control ratio is entered either manually into the Ratio function block by the console operator through the process control system, or it may be set automatically from some advanced control application program. Figure 27 Process Flow Diagram Flow Ratio Control Stream B (controlled stream) ratioed to Stream A (wild stream) A

PV

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The flow rangeability limitations of flow meters discussed earlier are important in ratio applications, especially when the ratio is not held fixed and will be adjusted. Figure 28 illustrates the impact of ratio adjustment extremes on the rangeability of a flow meter. If the ratio is set at 1.0, both stream A and B are available over the normal range of 30% to 95%. If the Ratio is 0.5 (Stream B is one half the meter range of stream A), Stream A is limited to a range of 60% to 95% , while stream B is limited to a range of 30% to 47.5%. If the ratio is 1.7, Stream A is limited to a range of 30% to 55.9%, while Stream B is limited to a range of 51% to 95%.

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company

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Figure 28 Flow Ratio Control - Flow Rangeability With Normal Ratio Adjustment Limits (Usable flow limits taken as 30 and 95% of meter range) Ratio Adjustment = 1.0

Ratio Adjustment = 0.5

Ratio Adjustment = 1.7

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0 DP12BF29

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Stream B

This information is considered CONFIDENTIAL and shall not be released to or discussed with any persons except (a) employees of ExxonMobil Affiliates who have an appropriate research agreement with ExxonMobil Research and Engineering Company (EMRE), and (b) consultants, contractors, or employees of third parties with whom proper secrecy agreements have been executed with EMRE or such ExxonMobil Affiliates. ExxonMobil Research and Engineering Company