MPFM_多相流量计手册2005

HANDBOOK OF MULTIPHASE FLOW METERING

Revision 2, March 2005

Handbook

of

Multiphase Flow Metering

(Copyright)

Revision 2, March 2005

Produced for

The Norwegian Society for Oil and Gas Measurement

The Norwegian Society of Chartered Technical and Scientific Professionals by:

(in alphabetical order)

Corneliussen, Sidsel: BP Norway

Couput, Jean-Paul: TOTAL

Dahl, Eivind: Christian Michelsen Research

Dykesteen, Eivind: Roxar Flow Measurement

Fr?ysa, Kjell-Eivind: Christian Michelsen Research

Malde, Erik: ConocoPhillips

Moestue, H?kon: Norsk Hydro

Moksnes, Paul Ove: Framo and Schlumberger

Scheers, Lex: Shell GS International

Tunheim, Hallvard: Norsk Hydro

The work was co-ordinated by Eivind Dahl, Christian Michelsen Research AS.

The NFOGM takes no responsibility for any personal injury, loss or damage to property howsoever caused, arising from the use or abuse of any part of this Handbook.

Norwegian Society for Oil and Gas Measurement

(NFOGM)The Norwegian Society of Chartered Technical and Scientific Professionals (Tekna)

www.nfogm.no Secretariat: The Norwegian Society of Chartered Technical and Scientific Professionals,

P.O. Box 2312 Solli, N-0201 OSLO

Phone: (+47) 2294 7548 / 61

www.tekna.no Postboks 2312 Solli, N-0201 Oslo Phone: (+47) 2294 7500

Preface

Multiphase metering, and a handbook for providing the users, manufacturers and others some form of guidelines for handling multiphase flow measurement has been

wanted by the industry from the start. The Norwegian Society for Oil and Gas Measurement (NFOGM) first developed a handbook to serve as a guideline and provide a common basis for the in-line multiphase measurement system. With help

from the manufacturers and the users the first revision of the handbook was published in 1995.

The development and use of the meters has increased since then, and NFOGM contacted Christian Michelsen Research (CMR) to investigate the need for an updated handbook.

In 2003 it was decided to start the work, and a revision to include comments from

users and get a more detailed and up to date handbook was initiated by NFOGM.

The work was financed by NFOGM and The Norwegian Society of Chartered Technical and Scientific Professionals (Tekna).

A project was established at Christian Michelsen Research in order to coordinate an

international workgroup to carry out this task. The workgroup consisted of ten participants who contributed on a voluntary basis with a broad and varied skills and

experience from oil and gas flow measurement. The participants were each assigned

main responsibility for the revision of one or more chapters, and they have contributed by writing of texts and in discussions at a total of 8 workgroup meetings

in the period from October 2003 until March 2005.

We wish to express our thanks to all the workgroup participants (listed on the previous page) and the project leader at CMR, Eivind Dahl, for their contributions to

this Handbook.

March 2005

Norwegian Society for Oil and Gas Measurement

Chairman

Svein Neumann

TABLE OF CONTENTS

1.INTRODUCTION (4)

1.1A BOUT THE NEW REVISION (5)

1.2O THER RELEVANT WORK (6)

2.SCOPE (7)

https://www.wendangku.net/doc/807926226.html,RMATIVE REFERENCES (8)

4.DEFINITIONS (9)

4.1T ERMS RELATED TO MULTIPHASE FLOW METERING (9)

4.2T ERMS RELATED TO METROLOGY (14)

4.3S UBSCRIPTS AND SYMBOLS (17)

5.MULTIPHASE FLOW METERING PHILOSOPHY (18)

5.1S INGLE WELL SURVEILLANCE OR MONITORING (20)

5.2W ELL TESTING (22)

5.3P RODUCTION ALLOCATION METERING (26)

5.4F ISCAL OR CUSTODY TRANSFER MEASUREMENT (28)

5.5S UMMARY OF FEATURES OF MPFM S (28)

6.MULTIPHASE FLOW (29)

6.1M ULTIPHASE FLOW REGIME MAPS (30)

6.2S LIP EFFECTS (33)

6.3C LASSIFICATION OF MULTIPHASE FLOWS (35)

7.TECHNOLOGY (36)

7.1M ETER CATEGORIES (36)

7.2M EASUREMENT PRINCIPLES (44)

7.3S ELECTION OF TECHNOLOGY AND MAINTENANCE REQUIREMENTS (53)

8.PERFORMANCE SPECIFICATION (56)

8.1T ECHNICAL DESCRIPTION (57)

8.2S PECIFICATION OF INDIVIDUAL SENSORS AND PRIMARY DEVICES (57)

8.3S PECIFICATION OF OUTPUT DATA AND FORMATS (58)

8.4M EASURING RANGE, RATED OPERATING CONDITIONS AND LIMITING CONDITIONS (58)

8.5M EASUREMENT UNCERTAINTY (59)

8.6G UIDELINE ON MPFM PERFORMANCE SPECIFICATION (62)

9.DESIGN GUIDELINES (67)

9.1P RODUCTION ENVELOPE (67)

9.2MPFM MEASURING ENVELOPE (70)

9.3U SING THE FLOW MAPS DURING TESTING (72)

9.4T HE CUMULATIVE PERFORMANCE PLOT (73)

9.5O THER CONSIDERATIONS (74)

10.TESTING, CALIBRATION AND ADJUSTMENT (76)

10.1F ACTORY A CCEPTANCE T ESTING (FAT) (77)

10.2C ALIBRATION OF MPFM S (78)

10.3A DJUSTMENT OF MPFM S (90)

11.FIELD INSTALLATION AND COMMISSIONING (91)

11.1I NSTALLATION CONSIDERATIONS (91)

11.2I NSTALLATION AND SITE INTEGRATION (92)

11.3C OMMISSIONING (95)

11.4S TART-UP (96)

12.VERIFICATION DURING OPERATION (99)

12.1B ASELINE MONITORING (99)

12.2S ELF CHECKING / SELF DIAGNOSTICS CAPABILITIES / REDUNDANCY (100)

12.3T WO METERS IN SERIES (101)

12.4M OBILE TEST UNITS (102)

12.5T RACER TECHNOLOGY (102)

12.6I NJECTION (102)

12.7S AMPLING (103)

12.8R ECONCILIATION FACTOR (103)

12.9G EO-CHEMICAL FINGERPRINTING (105)

12.10S UBSEA SYSTEMS VERIFICATION (105)

13.BIBLIOGRAPHY (106)

A NUCLEAR GAUGE EMPLOYMENT (108)

B USER MANUAL FOR THE EXCEL PROGRAM FOR GENERATION OF FLOW MAPS (111)

1. INTRODUCTION

The need for multiphase flow measurement in the oil and gas production industry has

been evident for many years. A number of such meters have been developed since

the early eighties by research organizations, meter manufacturers, oil and gas production companies and others. Different technologies and various combinations

of technologies have been employed, and prototypes have been quite dissimilar in

design and function. Some lines of development have been abandoned, whereas a

number of meters have become commercially available, and the number of applications and users is rapidly increasing.

Since the first Handbook of multiphase metering (hereafter simply called the Handbook) was published in 1995, multiphase flow measurement has further matured and is now being considered a separate discipline in the oil and gas flow

measurement society. New applications of multiphase flow meters (MPFMs) have

emerged, from simply being a replacement of the conventional test separator shared

by a number of wells, towards more compact and low cost meters with application

on a one-per-well basis and installations both topside and subsea.

Meters from different manufacturers will always differ in their design, function and

capabilities. In order to promote mutual understanding of MPFMs and their applications among users, manufacturers and others, some form of guidelines or user

manual seemed appropriate and was the reason for publishing the first Handbook in

1995 (Dykesteen, 1995). The Handbook was written to serve that purpose and to

help provide a common basis for the field of in-line multiphase flow measurement

systems. It was not the intention at that stage that this document should be regarded

as a final report. Rather, it was hoped that it would initiate more international work

in which the issues and topics raised here can be further developed.

Since the multiphase flow metering technologies and applications have developed

significantly since 1995, the Norwegian Society for Oil and Gas Measurement (NFOGM) therefore in 2003 decided to update the Handbook to reflect these improvements and to make it the main guide for state-of-the-art multiphase flow measurement.

1.1 About the new revision

The revision of this Handbook has been carried out over the years 2003 – 2005. In

this Section the major updates of the present version of the Handbook are briefly described as well as other work of particular relevance. The chapters logically follow

the course from an introduction to multiphase flow measurement philosophy and multiphase flows in general, via selection of technology, performance specifications,

design considerations to field installation and commissioning and finally the operation of MPFMs.

Chapter 3 is new and includes informative references to provide the reader with some references to relevant standards and literature regarding multiphase flow measurement. The definitions in Chapter 4 have been extended and split into definitions relating to multiphase flows and definitions relating to metrology in general.

The chapter previously called “Applications of multiphase metering” has been renamed to “Multiphase flow metering philosophy” (Chapter 5). As the change in

heading indicates, the chapter has been extended to include more of the general and

overall reasoning for selection, installation and operation of multiphase flow metering systems in various applications.

Chapter 6 provides the reader with a general introduction to multiphase flows. This

chapter has been updated and includes extended descriptions of flow regimes and slip effects in multiphase flows. A new classification of multiphase flows linked to

the gas volume fraction has also been introduced, and it is emphasised that wet gas

meters and their applications have now been included in the Handbook, since wet

gas is considered as a subset of multiphase flows.

MPFMs are still classified into categories in terms of technology (Chapter 7), and

brief descriptions of the most commonly used measurement principles in MPFMs currently available on the market have also been included. Guidance on selection of

technology and maintenance requirements is also provided.

There is a need for more standardised performance specification of MPFMs, both for

comparison of measuring ranges and measurement uncertainties but also for more efficient selection of technology. This chapter has therefore been updated and extended to serve this purpose (Chapter 8).

Chapter 9 presents new guidelines for designing MPFM installations. As an aid in

“composition map”. These two maps provide convenient ways of first plotting the

predicted well production which is due to be measured in a specific application. The

measuring range of a MPFM may then be plotted in the same maps, overlying the

estimated well trajectories (estimated production over the field life time). This

method for design of MPFM installations is described in more detail in this chapter.

In addition a Microsoft Excel program has been developed to provide the users with

a software tool for generating these plots.

The last chapters of the Handbook have been reorganised significantly compared to

the previous version, where Chapter 10 now covers all aspects concerning testing,

calibration and adjustment of MPFMs. Testing, calibration and adjustment can take

place at different locations and for different purposes in the course from manufacturing to commissioning on site. This chapter covers some of the alternatives and highlights particular issues for each alternative.

Chapter 11 covers field installation and commissioning, and provides recommended

procedures and practices for field installation and commissioning of MPFMs.

Although MPFMs cannot easily be sent to a calibration facility for recalibration,

there is a need for regular calibration to verify the meter performance. The purpose

of Chapter 12 is to provide some guidelines on how to verify meter performance in

the field during operation, assuming no test separator is readily available.

The appendices include a short introduction to important aspects concerning nuclear

gauge employment and also a brief user manual for the Excel program for generation

of the flow maps described in Chapter 9.

1.2 Other relevant work

Parallel to the work by the NFOGM workgroup, an API Upstream Allocation Task

Group has been at work to develop an API Recommended Practise RP 86 Measurement of Multiphase Flow. Their remit has been to consider and evaluate all

methods which are used today to estimate flow rates in a multiphase environment. A

close cooperation was established between the two groups in order to harmonise the

documents in terms of terminology, methodology and content and to make them

consistent. The API RP 86 Measurement of Multiphase Flow is due for ballot in mid

2005. Other relevant publications are the Guidance Notes for Petroleum Measurement published by the UK Department of Trade and Industry (DTI).

2. SCOPE

This document is intended to serve as a guide for users and manufacturers of MPFMs. Its purpose is to provide a common basis for, and assistance in, the classification of applications and meters, as well as guidance and recommendations

for the implementation and use of such meters.

The document may also serve as an introduction to newcomers in the field of multiphase flow measurement, with definition of terms and a description of multiphase flow in closed conduits being included.

The so-called in-line MPFMs that directly measure the oil, water and gas flow rates

without any conditioning, as well as the partial- and full separation MPFMs are the

main focus of the Handbook. Conventional two- or three-phase separators are not included here. It should be emphasized however that in contrast to the previous Handbook, this version also covers wet gas meters and their applications, since wet

gas is considered as a subset of multiphase flows.

Even if the individual flow rates of each constituent are of primary interest, often

their ratios (Water-in-Liquid Ratio, Gas/Oil Ratio, etc) are useful as operational parameters. Constituents other than oil, gas and water flow rates or ratios of these

are not dealt with here.

The performance of a multiphase flow meter in terms of uncertainty, repeatability,

range, etc. is of great importance, as this enables the user to compare different meters

and evaluate their suitability for use in specific applications. Section 8 covers this

issue in detail and proposes standard methods to describe performance .

The testing and qualification of the meters is also related to performance. Guidance

is provided to help optimise the outcome of such activities. Since MPFMs measure at

line conditions, the primary output is individual flow rates and fractions at actual conditions (e.g. at the operating pressure and temperature). Conversion of these actual flow rates to flow rates at standard conditions, requires knowledge of composition and mass transfer between the liquid and the gas phases and may involve multiphase sampling. The conversion from actual conditions to standard conditions is not included here.

3. INFORMATIVE

REFERENCES

In single-phase flow measurement there exists normative standards; this is not the case for multiphase flow metering. The following literature is recommended as informative references for multiphase flow metering.

ISO-Guide

(The abbreviation “GUM” is often used) International Organization for Standardization (1995):

Guide to the expression of uncertainty in measurement, ISBN-92-67-10188-9.

When reporting the result of a measurement of a physical quantity, some quantitative indication of the result has to be given to assess its reliability and to allow comparisons to be made. The Guide to the expression of uncertainty in measurement establishes general rules for evaluating and expressing uncertainty in measurement that can be followed at many levels of accuracy and across many fields.

ISO-11631:1998International Organization for Standardization (1998):

Measuring of fluid flow.

Methods of specifying flow meter performances.

API TP 2566 American Petroleum Institute (2004):

State of the art Multiphase Flow Metering.

API RP-85 American Petroleum Institute (2005):

Use of Subsea Wet gas Flow meters in Allocation Measurement Systems.

Recommended Practice 85 discusses how liquid hydrocarbon

measurement is accomplished by using available sampling information

to determine the well's water volume fraction and gas-oil ratio (GOR).

This RP presents a recommended allocation methodology that is

technically defensible and mathematically optimised to best fit the

application, and that equitably accommodates variances in the

uncertainty level between meters within the system.

ISO/TR 7066-1:1997 International Organization for Standardization (1997):

Measurement of fluid flows in general.

Assessment of uncertainty in calibration and use of flow measurement

devices - Part 1: Linear calibration relationships.

DTI, Issue 7, December 2003 UK Department of Trade and Industry (DTI) (2003):

Guidance Notes for Petroleum Measurement, Issue 7.

State of Alaska, Alaska Oil and Gas Conservation Commission (2004): Guidelines for qualification of multiphase metering systems for well testing.

4. DEFINITIONS

Two categories of terms are defined below. The first section defines terms that are

commonly used to characterise multiphase fluid flow in a closed conduit. The second

section defines metrological terms that may be useful in characterising the performance of a multiphase flow meter.

4.1 Terms related to multiphase flow metering

Actual conditions The actual or operating conditions (pressure and temperature) at which

fluid properties or volume flow rates are expressed.

Adjustment (See important notice at the end of this Section) Operation of bringing a measuring instrument into a state of performance suitable for its use (ISO-VIM, 1993).

NOTE: A tuning of the measuring instrument or measuring system in order to operate according to a reference or standard. The

tuning may include software, mechanical and/or electrical

modifications.

Calibration (See important notice at the end of this Section) Set of operations that establish, under specified conditions, the relationship between values of quantities indicated by a measuring instrument or measuring system, or values represented by a material measure or certified reference material, and the corresponding values realised by standards (ISO-VIM, 1993).

NOTE 1: The result of the calibration may indicate a need for adjustment of the measuring instrument or measuring system

in order to operate according to a reference or standard.

NOTE 2: The result of a calibration permits either the assignment of values of measurands to the indications or the determination of

corrections with respect to indications.

NOTE 3: A calibration may also determine other metrological properties such as the effect of influence quantities.

NOTE 4: The result of a calibration may be recorded in a document, sometimes called a calibration certificate or a calibration

report.

Capacitance In a capacitor or system of conductors and dielectrics, the property that permits the storage of electrically separated charges when potential

differences exist between the conductors. Capacitance is related to charge

and voltage as follows: C = Q/V, where C is the capacitance in farads, Q is

the charge in coulombs, and V is the voltage in volts.

Certified Reference Material (CRM) Reference material, accompanied by a certificate, one or more of whose property values are certified by a procedure which establishes traceability to an accurate realization of the unit in which the property values are expressed, and for which each certified values is accompanied by an uncertainty at a stated level of confidence (ISO-VIM, 1993).

Compression factor Z and Z0The compression factor Z is the quotient of the actual (real) volume of an arbitrary mass of gas, at a specified pressure and temperature, and the volume of the same gas, under the same conditions, as calculated from the ideal gas law. The compression factor at standard conditions is Z0.

Conductivity The ability of a material to conduct electrical current. In isotropic material the reciprocal of resistivity. Sometimes called specific conductance. Units

are Siemens/m or S/m.

Dielectric constant See the definition of permittivity.

Dispersed flow Dispersed flow is characterised by a uniform phase distribution in both the

radial and axial directions. Examples of such flows are bubble flow and

mist flow.

Dissolved water Water in solution in petroleum and petroleum products.

Dry Gas Gas flows not containing any liquids under the actual operating conditions,

however with further processing e.g. temperature and pressure changes

liquids again might fall out

Emulsion Colloidal mixture of two immiscible fluids, one being dispersed in the other

in the form of fine droplets, in multiphase fluids discrimination should be

made between oil-in-water emulsion and water-in-oil emulsion. Both

respond differently to permittivity measurements.

Entrained water Water suspended in oil. Entrained water includes emulsions but does not include dissolved and free water.

Equation of State Equations that relate the composition of a hydrocarbon mixture, pressure and temperature of gases and liquids to one another.

Fiscal Fiscal refers to a meter’s service and does not imply any standard of performance. A “fiscal” measurement (or custody transfer measurement) is

basis for money transfer, either between company and government or

between companies.

Flow regime The physical geometry exhibited by a multiphase flow in a conduit; for example, in two-phase oil/water, free water occupying the bottom of the

conduit with oil or oil/water mixture flowing above.

Fluid A substance readily assuming the shape of the container in which it is placed; e.g. oil, gas, water or mixtures of these.

Froude numbers Froude number (F r) is the ratio of inertial force and gravitational force for a

particular phase; in other words, the ratio of kinetic to potential energy of

the gas or the liquid.

Gamma rays Electromagnetic waves of the highest frequencies known, originally discovered as an emission of radioactive substances and created by

transition of a nucleus to lower energy states.

Gas Hydrocarbons in the gaseous state at the prevailing temperature and pressure.

Gas-Liquid-Ratio (GLR) The ratio of gas volume flow rate and the total liquid (oil and water) volume flow rate, both volume flow rates should be converted to the same pressure and temperature (generally at the standard conditions). Expressed in volume per volume, e.g. m3/m3.

Gas-Oil-Ratio (GOR) The ratio of gas volume flow rate and the oil volume flow rate; both volume flow rates should be converted to the same pressure and temperature (generally at standard conditions). Expressed in a volume per volume, e.g. scft/bbl or m3/m3.

Gas Volume Fraction (GVF) The gas volume flow rate, relative to the multiphase volume flow rate, at the pressure and temperature prevailing in that section. The GVF is normally expressed as a fraction or percentage.

Homogeneous Multiphase Flow A multiphase flow in which all phases are evenly distributed over the cross-section of a closed conduit; i.e. the composition is the same at all points in the cross section and there the liquid and gas velocities are the same (no-slip). Note that bubbly multiphase flow regimes are probably the best approximation for homogeneous multiphase flow (v Mixture = vs Gas + vs Liquid).

Homogeneous oil/water flow A two-phase oil/water flow in which both phases are evenly distributed over the cross-section of a closed conduit; i.e. the composition is the same

Intermittent flow Intermittent flow is characterised by being non-continuous in the axial direction, and therefore exhibits locally unsteady behaviour. Examples of

such flows are elongated bubble, churn and slug flow (Figure 5.4). The

flow regimes are all hydrodynamic two-phase gas-liquid flow regimes.

Liquid-Gas-Ratio (LGR) The ratio of liquid volume flow rate and the total gas volume flow rate. Both rates should be converted to the same pressure and temperature (generally at the standard conditions). Expressed in volume per volume, e.g. m3/m3.

Liquid Hold-up The ratio of the cross-sectional area in a conduit occupied by the liquid phase and the cross-sectional area of the conduit, expressed as a percentage.

Liquid Volume Fraction (LVF) The ratio of liquid volume flow rate and the total fluid (oil, water and gas) flow rate, both volume flow rates should be converted to the same pressure and temperature. Expressed as a fraction or percentage.

Lockhart-Martinelli parameter Lockhart-Martinelli parameter (LM or X) is defined as the ratio of the liquid Froude number and the gas Froude number or in other words the ratio of the pressure gradient for the liquid to the pressure gradient for the gas in a pipe under equilibrium flow conditions (an increasing LM parameter means an increasing liquid content or wetness of the flow).

Mass flow rate The mass of fluid flowing through the cross-section of a conduit in unit time.

Measuring envelope The area's in the two-phase flow map and the composition map in which the MPFM performs according to its specifications.

Microwave Electromagnetic radiation having a wavelength from 300 mm to 10 mm (1 GHz to 30 GHz).

Multiphase flow Two or more phases flowing simultaneously in a closed conduit; this document deals in particular with multiphase flows of oil, water and gas in

the entire region of 0-100% GVF and 0-100% Water Cut.

Multiphase flow meter (MPFM) A device for measuring the individual oil, water and gas flow rates in a multiphase flow. The total package of measurement devices for composition and velocity, including possible conditioning unit, should be considered as an integral part of the meter. Note that under this definition also a conventional two- or three-phase test separator is a multiphase meter.

Multiphase flow velocity The ratio of the multiphase volume flow rate and the cross sectional area of the conduit. Note that this is fictive velocity, only in homogeneous and slip free multiphase flow this velocity has be meaningful value. Multiphase flow velocity is the sum of gas superficial and liquid superficial velocity.

Multiphase fraction meter A device for measuring the phase area fractions of oil, gas and water of a multiphase flow through a cross-section of a conduit.

Multiphase volume flow rate The total (oil, water and gas) volume flowing through the cross-sectional area of a conduit per unit time.

Oil Hydrocarbons in the liquid state at the prevailing temperature and pressure conditions.

Oil (water or gas) volume fraction The ratio of oil (water or gas) volume flow rate and the total fluid (oil, water and gas) flow rate, both volume flow rates should be converted to the same pressure and temperature (generally at the standard conditions). Expressed in a fraction or percentage.

Oil-continuous two-phase flow A two-phase flow of oil/water characterised in that the water is distributed as water droplets surrounded by oil. Electrically, the mixture acts as an insulator.

Slip velocity The phase velocity difference between two phases. See Section 6.2.

Standard or Reference conditions A set of standard (or reference) conditions, in terms of pressure and temperature, at which fluid properties or volume flow rates are expressed, e.g. 101.325 kPa and 15 °C.

Superficial phase velocity The flow velocity of one phase of a multiphase flow, assuming that the phase occupies the whole conduit by itself. It may also be defined by the relationship (Phase volume flow rate) / (Pipe cross-section).

Composition map Graph with Gas Volume Fraction (GVF) and Water Cut (WC) or Water in Liquid ratio (WLR) along the x- and y-axis, respectively. Both the GVF

and Water Cut or WLR should be at actual conditions.

Two-phase flow map Graph with superficial velocity of gas and liquid along the x- and y-axis, respectively e.g. the Mandhane (1974) flow map for horizontal multiphase

flow. Alternatively the actual gas volume and actual liquid volume flow

rates can be used.

Void fraction The ratio of the cross-sectional area in a conduit occupied by the gas phase and the cross-sectional area of the conduit, expressed as a percentage. Volume flow rate The volume of fluid flowing through the cross-section of a conduit in unit time at the pressure and temperature prevailing in that section.

Water-continuous two-phase flow A two-phase flow of oil/water characterised in that the oil is distributed as oil droplets surrounded by water. Electrically, the mixture acts as a conductor.

Water Cut (WC): The water volume flow rate, relative to the total liquid volume flow rate (oil

and water), both converted to volumes at standard pressure and

temperature. The WC is normally expressed as a percentage.

Water Fraction Meter (WFM) A device for measuring the phase area fractions of oil and water of a two-phase oil/water flow through a cross-section of a conduit expressed as a percentage.

Water-in-liquid ratio (WLR) The water volume flow rate, relative to the total liquid volume flow rate (oil and water), at the pressure and temperature prevailing in that section.

Well trajectory The trajectory of a well over time in a two-phase flow map and composition

map.

Wet gas Gas that contains liquids, generally wet gas is defined as gas/liquid systems

with a Lockhart-Martinelli parameter smaller than approximately 0.3.

Hydrocarbon gasses that contain heavy components that will condensate

during further processing (but at a particular p and T behaves as a pure gas)

are not considered to be a wet gas from a measurement point of view.

X-rays X-rays are electromagnetic radiation of a similar nature to light, but with an

extremely short wavelength. It is produced by bombarding a metallic target

with fast electrons in vacuum or by transition of atoms to lower energy

states. Its properties include ionising a gas upon passage through it,

penetrating certain thickness of all solids and causing fluorescence.

IMPORTANT NOTICE

It is important to note that the ISO definitions (ISO-VIM, 2003) of the terms “Calibration” and “Adjustment”, which are used in this Handbook, are fundamentally different from the definitions of these terms in the API RP 86 Measurement of Multiphase Flow. The API RP 86 uses definitions consistent with the API Manual of Petroleum Measurement Standards (MPMS).

According to the MPMS, the term “Calibration” prescribes an adjustment to the meter should it be found out of range, whereas the ISO definition does not permit such an adjustment. ISO identifies “Adjustment” as a separate activity and not part of a “Calibration”.

4.2 Terms related to metrology

The uncertainty of MPFMs should be specified by terms that are in conformance with "The international vocabulary of basic and general terms in metrology" (VIM) issued by ISO (1993). Other standards based on the above document may also be used, e.g. BS 5233 (1986): "Glossary of terms used in metrology". Some of the definitions of BS 5233, which may be particularly relevant to multiphase flow measurement, are quoted below (or form part of the definitions).

Accuracy of measurement Closeness of the agreement between the result of a measurement and the value of the measurand (ISO-VIM, 2003).

NOTE 1:The value of the measurand may refer to an accepted reference value 1.

NOTE 2: “Accuracy” is a qualitative concept, and it should not be used quantitatively. The expression of this concept by

numbers should be associated with (standard) uncertainty.

Corrected results Result of a measurement after correction for systematic error (ISO-VIM,

2003).

Error of measurement Error of measurement is the result of a measurement minus the value of the measurand (ISO-VIM, 2003).

In general, the error is unknown because the value of the measurand is unknown. Therefore, the uncertainty of the measurement results should be evaluated and used in specification and documentation of test results.

Influence quantity Quantity that is not the measurand, but that affects the result of the

measurement (ISO-VIM, 2003).

Limiting conditions Extreme conditions that a measuring instrument is required to withstand

without damage, and without degradation of specified metrological

characteristics when is subsequently operated under its rated operating

conditions (ISO-VIM, 2003).

Measurand Particular quantities subject to measurement (ISO-VIM, 2003).

Measuring range Set of values of measurands for which the error of a measuring instrument

is intended to lie within specified limits (ISO-VIM, 2003).

Random error The result of a measurement minus the mean that would result from an

infinite number of measurements of the same measurand carried out under

repeatable conditions.

NOTE:Because only a finite number of measurements can be made,

it is possible to determine only an estimate of the random

error. Since it generally arises from stochastic variations of

influence quantities, the effect of such variations is referred to

as random effects in the ISO-Guide (1995).

Rated operating conditions Conditions of use for which specified metrological characteristics of a measuring instrument are intended to lie within given limits (ISO-VIM, 2003).

1In some documents it also points to the “true value” or “conventional true value”. However,

Reference conditions Conditions of use prescribed for testing the performance of a measuring

instrument or for intercomparison of results of measurements (ISO-VIM,

2003).

NOTE:The reference conditions generally include reference values

or reference ranges for the influence quantities affecting the

measuring instrument.

Repeatability Closeness of the agreement between the results of successive measurements of the same measurand carried out under the same conditions of measurement (ISO-VIM, 2003).

NOTE 1:These conditions are called repeatability conditions

NOTE 2:Repeatability conditions include:

- the same measurement procedure

- the same observer

- the same measuring instrument, used under the same

conditions

- repetition over a short period of time

NOTE 3: Repeatability may be expressed quantitatively in terms of the dispersion characteristics of the results.

Reproducibility Closeness of the agreement between the results of measurements of the same measurand carried out under changed conditions of measurement (ISO-VIM, 2003).

NOTE 1: A valid statement of reproducibility requires specification of the conditions changed

NOTE 2:The changed conditions may include:

- principle of measurement

- method of measurement

-

observer

- measuring instrument

- reference standard

-

location

- conditions of use

-

time

NOTE 3: Reproducibility may be expressed quantitatively in terms of the dispersion characteristics of the results.

NOTE 4: Results are here usually understood to be corrected results.

Result of a measurement Value attributed to a measurand, obtained by measurement. It is an estimated value of the measurand (ISO-VIM, 2003).

Span The algebraic difference between the upper and lower values specified as

limiting the range of operation of a measuring instrument, i.e. it

corresponds to the maximum variation in the measured quantity of

interest2.

Example: A thermometer intended to measure over the range -40 0C +

60 0C has a span of 100 0C.

Systematic error The mean value that would result from an infinite number of measurements of the same measurand carried out under repeatability conditions minus a

true value of the measurand (ISO-VIM, 2003).

Uncertainty of measurement Parameter associated with the result of a measurement, characterising the dispersion of the values that could reasonably be attributed to the measurand (ISO-VIM, 2003).

NOTE 1:The parameter may be, for example, a standard deviation (or

a given multiple of it), or the half-width of an interval having

a stated level of confidence.

NOTE 2: Uncertainty of measurement comprises, in general, many components. Some of these components may be evaluated

from statistical distribution of the results of series of

measurements and can be characterised by experimental

standard deviations. The other components, which can also

be characterised by standard deviations, are evaluated from

assumed probability distributions based on experience or

other information.

NOTE 3: It is understood that the result of the measurement is the best estimate of the value of the measurand, and that all

components of uncertainty, including those arising from

systematic effects, such as components associated with

corrections and reference standards, contribute to the

dispersion.

4.3 Subscripts and symbols

Table 4.1 includes a list of the main subscripts used in the equations in the

Handbook, while colours and symbols used in the schematic drawings are included

below.

Table 4.1 Subscripts used in the equations in the Handbook.

Symbol Quantity Value / SI Units

C Capacitance F

εo Permittivity of free space 8.854?10-12 F/m

v s,gas Superficial gas velocity m/s

v s,liquid Superficial liquid velocity m/s

v m Multiphase mixture velocity (v m = v gas + v liquid) m/s

q gas Gas volume flow rate m3/s

A Area (e.g. cross-sectional area of pipe) m2

λliquid Liquid hold-up

λgas Gas void fraction

αliquid Liquid volume fraction

αgas Gas volume fraction

t Time s μLinear attenuation coefficient 1/m

I Count rate

X Lockhart-Martinelli parameter (see Section 7.1.3.2)

ρg Gas density kg/m3

ρl Liquid density kg/m3

D Internal pipe diameter m

g Gravitational constant ~9.81 m/s2

F r Froude number (see Section 7.1.3.2)

Key to colours and symbols:

5. MULTIPHASE FLOW METERING PHILOSOPHY

Conventional single-phase metering systems require the constituents or "phases" of

the well streams to be fully separated upstream of the point of measurement. For

production metering this requirement is usually met automatically at the outlet of a

conventional process plant, since the main purpose of such a plant is to receive the

sum of well streams in one end and to deliver (stabilized) single phases ready for

transport (and hence also measurement) in the other end. Single-phase metering

systems normally provide high-performance measurements of hydrocarbon production.

The need for multiphase flow metering arises when it is necessary or desirable to

meter well stream(s) upstream of inlet separation and/or commingling. Multiphase

flow measurement technology may be an attractive alternative since it enables

measurement of unprocessed well streams very close to the well. The use of MPFMs

may lead to cost savings in the initial installation. However, due to increased

measurement uncertainty, a cost-benefit analysis should be performed over the life

cycle of the project to justify its application.

MPFMs can provide continuous monitoring of well performance and thereby better

reservoir exploitation/drainage. However this technology is complex and has its

limitations; therefore care must be exercised when planning installations that include

one or more MPFMs. One of the limitations of the multiphase measurement

technology is the uncertainty of the measurement. The main source for these higher

measurement uncertainties of MPFMs in comparison to single-phase metering

systems (for example) is the fact that they measure unprocessed and far more

complex flows than what is measured by single-phase measurement systems.

A second limitation in a multiphase application is the possibility to extract

representative samples. Whereas samples of the different fluids are readily captured

from, for example, the single-phase outlets of a test separator, no standard or simple

method for multiphase fluid sampling is yet available. Since most MPFMs on the

market need some kind of a priori information about the properties being measured

(like densities, oil permittivity and/or water conductivity/salinity), this information

must be made available and be updated on a regular basis.

A number of different MPFMs are available on the market, employing a great

diversity of measurement principles and solutions (Cf. chapter 7 and 8). Some

MPFMs work better in certain applications than others. Hence a careful comparison

and selection process is required to work out the optimal MPFM installation for each