ISO/TR 12748:2015
(Main)Natural Gas — Wet gas flow measurement in natural gas operations
Natural Gas — Wet gas flow measurement in natural gas operations
ISO/TR 12748:2015 describes production flow measurement of wet natural gas streams with WGFMs in surface and subsea facilities. Wet natural gas streams are gas-dominated flows with liquids like water and/or hydrocarbon liquids. ISO/TR 12748:2015 defines terms/symbols, explains the various concepts, and describes best practices of wet gas flow meter design and operation. It addresses metering techniques, testing, installation, commissioning, and operation practices such as maintenance, calibration, and verification. It also provides a theoretical background of this comprehensive, challenging and still evolving measurement technology.
Gaz naturel — Mesurage du débit de gaz humide dans les opérations de gaz naturel
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Standards Content (Sample)
TECHNICAL ISO/TR
REPORT 12748
First edition
2015-10-15
Natural Gas — Wet gas flow
measurement in natural gas operations
Gaz naturel — Mesurage du débit de gaz humide dans les opérations
de gaz naturel
Reference number
©
ISO 2015
© ISO 2015, Published in Switzerland
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ii © ISO 2015 – All rights reserved
Contents Page
Foreword .vi
Introduction .vii
1 Scope . 1
2 Terms and Definitions . 1
3 Symbols .10
4 Objectives of wet gas flow measurement .13
4.1 Common production scenarios .14
4.2 Production allocation .15
4.3 Flow assurance aspects .16
4.4 WGFM considerations .16
4.5 Reliability in remote WGFM installations .16
5 Flow regimes .17
5.1 Horizontal wet gas flow regimes .17
5.1.1 Stratified flow .18
5.1.2 Slug flow .18
5.1.3 Annular mist flow . . .18
5.2 Vertical up wet gas flow regimes .18
5.2.1 Churn flow .18
5.2.2 Annular mist flow . . .19
5.3 Vertical down wet gas flow regimes .19
5.4 Inclined flow.19
5.5 Examples of wet gas flow regimes .19
5.6 Flow regime maps .20
5.7 Different wet gas flow parameters.21
5.8 Water in wet gas flow .21
6 Wet gas flow metering principles .22
6.1 General .22
6.2 In-Line wet gas flow meters .23
6.2.1 Single-phase gas flow meter with correction factor .23
6.2.2 Two-phase wet gas flow meter .24
6.2.3 Multiphase wet gas flow meter .24
6.3 Single-phase gas differential pressure meters with wet gas flow .24
6.3.1 DP Meter design influence on wet gas over-reading .25
6.3.2 Lockhart-Martinelli parameter influence on DP meter wet gas
flow over-reading .25
6.3.3 Gas to liquid density ratio influence on DP meter wet gas flow over-reading .25
6.3.4 Gas densiometric Froude number influence on DP meter wet gas
flow over-reading .26
6.3.5 DP meter orientation influence on DP meter wet gas flow over-reading .26
6.3.6 Influence of β on DP meter wet gas flow over-reading .28
6.3.7 Fluid property influence on DP meter wet gas flow over-reading.28
6.3.8 Meter size/diameter influence on DP meter wet gas flow over-reading .28
6.3.9 Applying DP meter wet gas flow correlations .28
6.4 General discussion on DP meter wet gas correlations .29
6.4.1 Wet gas flow performance characterization vs. published wet gas correlations .29
6.4.2 Horizontally-installed orifice plate meter .29
6.4.3 Horizontally-installed Venturi meter .31
6.4.4 Horizontally-installed cone meter .32
6.5 Generic two-phase wet gas meter designs .33
6.5.1 Multiple single-phase meters in series .33
6.5.2 Differential pressure meter classical DP/permanent pressure loss wet
gas meters .35
6.5.3 Fast response sensor system .36
6.6 Multiphase wet gas flow meters .37
6.6.1 Trace water metering with multiphase wet gas flow meters .38
6.6.2 Multiphase wet gas flow meter subsystems .38
6.6.3 Phase fraction device choices .39
6.6.4 Gas volume fraction vs. gas void fraction measurement .41
6.6.5 Semi-empirical multiphase flow calculation — Slip model .41
6.6.6 PVT (pressure volume temperature) models .42
6.6.7 Multiphase wet gas flow meter required fluid property inputs .42
6.6.8 Multiphase wet gas flow meter phase fraction measurement .42
6.6.9 Measurement of water salinity .43
6.6.10 Multiphase wet gas flow meter redundant subsystems and diagnostics.43
6.6.11 Selection of multiphase wet gas flow meter technologies .44
6.7 Wet gas flow meter performance testing .44
6.8 Virtual metering system (VMS) .45
7 DP Meter Wet Gas Correlation Practical Issues .45
7.1 DP meter wet gas flow installation issues .46
7.1.1 Liquid flow rate estimation techniques .46
7.1.2 Monitoring wet gas liquid loading with a DP meter downstream port .47
8 Design and Installation Considerations .49
8.1 Design considerations.49
8.1.1 Meter orientation and fluid flow .49
8.1.2 Meter location relative to other piping components .50
8.1.3 Use of two-phase flow rate and composition maps .50
8.1.4 Fluid sampling.52
8.1.5 Redundancy and external environmental considerations .52
8.1.6 Security .53
8.1.7 Cost and project schedule implications .54
8.2 Performance specifications .54
8.3 Wet gas flow measurement uncertainty .55
8.3.1 Uncertainty evaluation methodologies .55
8.3.2 Additional factors affecting wet gas flow measurement uncertainty .55
8.3.3 Expressing uncertainty of wet gas flow rates .56
9 Testing, Verification and Calibration .56
9.1 Meter orientation .56
9.2 Comments on flow regimes and mixers .57
9.3 Installation requirements .57
9.4 Wet gas flow characterization tests — Single-phase DP meter baselines .57
9.5 Wet gas flow facility operational considerations .58
9.5.1 Test facility operational issues — Achieving thermodynamic equilibrium .58
9.5.2 Test facility operational issues — Phase flow rate stability .60
9.5.3 Test facility operational issues — Witnessing of tests .61
9.6 Meter testing in a wet gas flow facility .62
10 Operational and Field Verification Issues .65
10.1 Laboratory reference vs. field hydrocarbon flow composition estimates .66
10.2 Laboratory reference vs. field calibration of phase fractions .66
10.3 Comparisons of multiphase wet gas flow meter and single-phase meter requirements .66
10.3.1 The challenge of supplying multiphase wet gas flow fluid properties .66
10.3.2 Confidential slip models .67
10.4 The importance of correct fluid property predictions .67
10.4.1 The importance of gas properties when metering small liquid flow rates .70
10.4.2 Preparation for fluid property variations during meter service .71
10.4.3 Fluid property sensitivity investigation.71
10.5 The benefit of an initial wet gas flow facility test . .73
10.6 Line size limitations for some multiphase meters .73
10.7 In situ wet gas flow meter verification .73
iv © ISO 2015 – All rights reserved
10.7.1 Reconciliation factors and meter output confidence .74
10.8 Operation and maintenance .74
10.8.1 System redundancy and diagnostics .74
10.8.2 Operating WGFM diagnostics .75
10.9 Miscellaneous operational issues .76
10.9.1 Wet gas flow and DP transmitters .76
10.9.2 Software and fluid property update procedures .77
10.9.3 Long term trending comparisons with test facility/factory characterization .77
11 Common Field Issues .77
11.1 Inefficient separator systems .77
11.2 Separator systems — An adverse environment for single-phase meters .78
11.2.1 Separator Outlet deployment .79
11.2.2 Gas Measurement at the separator outlet .79
11.2.3 Liquid Turbine Meter .80
11.2.4 Practical limitations of wet gas flow metering with separator technology .80
11.3 Wet gas flow meter practical problems .81
11.3.1 Considerations for wet gas flow metering .81
11.3.2 The adverse effects of contamination, hydrates, scale, and salts .82
11.3.3 Theoretical, laboratory and actual wet gas flow conditions .84
11.3.4 Undisclosed WGFM calculation procedures .84
11.3.5 Differential pressure measurement and wet gas flows .85
11.3.6 Problems due to lack of long time operating experience of WGFMs .86
Annex A (informative) WGFM design checklist.87
Annex B (informative) Wet gas parameters equations .89
Bibliography .90
Foreword
ISO (the International Organization for Standardization) is a worldwide federation of national standards
bodies (ISO member bodies). The work of preparing International Standards is normally carried out
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electrotechnical standardization.
The procedures used to develop this document and those intended for its further maintenance are
described in the ISO/IEC Directives, Part 1. In particular the different approval criteria needed for the
different types of ISO documents should be noted. This document was drafted in accordance with the
editorial rules of the ISO/IEC Directives, Part 2 (see www.iso.org/directives).
Attention is drawn to the possibility that some of the elements of this document may be the subject of
patent rights. ISO shall not be held responsible for identifying any or all such patent rights. Details of
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on the ISO list of patent declarations received (see www.iso.org/patents).
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For an explanation on the meaning of ISO specific terms and expressions related to conformity
assessment, as well as information about ISO’s adherence to the WTO principles in the Technical
Barriers to Trade (TBT), see the following URL: Foreword — Supplementary information.
The committee responsible for this document is ISO/TC 193, Natural Gas, Subcommitte SC 3,
Upstream Area.
vi © ISO 2015 – All rights reserved
Introduction
Oil and gas companies started developing Wet Gas Flow Meters (WGFMs) and Multiphase Flow Meters
(MPFMs) through extensive R&D activities in the late 1980s. During this period, WGFMs and MPFMs
were typically perceived as two distinct technologies for different applications: MPFMs were designed
for liquid continuous flow conditions and WGFMs were designed for gas continuous flow conditions.
In recent years, however, the operating range of these two technologies has increasingly overlapped,
blurring the distinction between a WGFM and MPFM. As wet gas flow is presently considered a subset
of multiphase flow, a WGFM is an MPFM that specializes in gas-dominant multiphase flow conditions. In
this Technical Report, such technologies will be referred to as WGFMs.
There are many factors that contributed in the decision to replace a separator with a WGFM, with each
application warranting careful consideration. A well-designed and maintained separator working
within an appropriate flow condition range should produce accurate flow measurements. A primary
concern for oil and gas companies was to reduce costs by replacing complex and bulky test separators,
as well as to further simplify the upstream infrastructure, in particular for offshore and subsea
1) 2)
projects. WGFMs typically require lower capital and operational expenditures than fully equipped
test separators. More savings in CapEx may be achieved by omitting dedicated test lines in satellite
developments. In addition, there is a significant benefit for offshore developments, in terms of weight
and space conservation, by using the much smaller footprint of WGFMs.
Due to various operational problems, a conventional test separator does not continuously provide
accurate and reliable well test data, giving only relevant information when the well is switched to the
test separator. With the use of WGFMs testing well production more frequently or even continuously
becomes possible. WGFM developments and extensive testing over the last two decades have resulted in
WGFM technology that is a viable alternative to a test separator. Modern WGFMs now offer continuous
well monitoring (per installation on individual wells).
WGFM technology is an attractive option for multiphase wet gas flow measurement. Over the last two
decades, some WGFMs have been developed from prototypes into very mature, robust, advanced, and
field-proven measurement devices, increasing their application scope. Although originally intended for
use mainly in reservoir and well production allocations, WGFMs have evolved into a technology that
spans even fiscal product allocation. In the latter case, the output of a WGFM is used to determine money
transactions between operating companies or between an operating company and a host government.
This Technical Report focuses on the measurement of wet gas flow, i.e. terminology, models, and
principles, and the design, implementation, testing, and operation of WGFMs.
1) Capital expenditure (CapEx) or costs for purchasing and installing a WGFM/MPFM includes all hardware to
operate the WGFM (data transmission, verification facilities, sampling arrangements, etc.)
2) Operating expenditure (OpEx) or costs to operate a WGFM/MPFM (maintenance, verification processes,
sampling for fluid properties, etc.)
TECHNICAL REPORT ISO/TR 12748:2015(E)
Natural Gas — Wet gas flow measurement in natural gas
operations
1 Scope
This Technical Report describes production flow measurement of wet natural gas streams with WGFMs
in surface and subsea facilities. Wet natural gas streams are gas-dominated flows with liquids like
3)
water and/or hydrocarbon liquids (see 2.67 for a detailed definition). This Technical Report defines
terms/symbols, explains the various concepts, and describes best practices of wet gas flow meter design
and operation. It addresses metering techniques, testing, installation, commissioning, and operation
practices such as maintenance, calibration, and verification. It also provides a theoretical background
of this comprehensive, challenging and still evolving measurement technology.
There are four general methods in measuring wet natural gas flow. Each approach is detailed below.
— Single-phase gas flow meter with correction factor: Uses a single-phase gas flow meter (often
a conventional gas flow metering device) with a correction factor for the effect of liquid on the
metering system. In these cases, the liquid flow rate required to determine the correction factor,
should be estimated from an external source.
— Two-phase WGFM: The gas and liquid (both water and hydrocarbon liquid combined) flow rates
are predicted with no additional external information regarding the liquid flow rate required.
This is generally known as a two-phase WGFM and will be referred to in this Technical Report
simply as WGFM.
— WGFM: A flow meter that measures the gas and liquid flow rates, and also the gas, water and
hydrocarbon liquid ratios (or “phase fractions”) with no external information required regarding
the liquid flow rate.
— Phase separation/Measurement after phase separation: This traditional and conventional method
of wet gas flow metering uses a two- or three-phase separator with single-phase flow meters
measuring the outgoing single-phase flows.
The first three of these methods, which emerged in the last two decades, may be described as in-line
wet gas flow metering, i.e. wet gas flow measurement is executed with WGFMs without separating
the gas and liquid phases. This Technical Report discusses in detail these first three methods. Several
best practice documents have already been issued to describe, among other topics, wet gas flow
[9][10][11][12]
measurement .
The last method is more conventional and describes wet gas flow measurement after the gas and liquid
phases have been separated. Wet gas meters can be used in multiphase flow metering systems that
utilize partial separation technologies. This method is only briefly discussed in this Technical Report.
2 Terms and Definitions
For the purposes of this document, the following terms and definitions apply.
2.1
adjustment
act of altering an instrument’s performance in any way, e.g. software, mechanical or electrical
modifications, in order for the instrument’s indication to match the reference values indicated by a test
stand
3) In this Technical Report, the term hydrocarbon liquid includes both oil and condensed hydrocarbons.
2.2
calibration
set procedure under specified conditions where the output/performance of an instrument is checked
against a reference, usually a test stand
Note 1 to entry: The result of calibration determines the deviation between the instrument indication and the
references. This deviation can assign an uncertainty value to the measurand and could indicate a requirement
for an adjustment.
2.3
capacitance
the ability of a body to store an electrical charge
Note 1 to entry: Any object that can be electrically charged exhibits capacitance (e.g. a parallel-plate capacitor).
2.4
composition map
map with water liquid ratio or WLR (2.63) along the horizontal axis (0 % ≤ WLR ≤ 100 %) and gas volume
fraction or GVF (2.22) along the vertical axis (0 % ≤ GVF ≤ 100 %); used to show WGFM operating
envelopes and/or well trajectories (2.65)
Note 1 to entry: The combination of a two-phase flow rate map (2.59) and a composition map is beneficial to
evaluate WGFM applications. See 8.1.3.
2.5
conductivity
ability of a material to conduct electrical current
Note 1 to entry: In isotropic material, conductivity is also the reciprocal of resistivity, sometimes called
specific conductance.
2.6
density ratio
DR
ratio of gas density to liquid density at line conditions, or
DR=ρρ
gl
Note 1 to entry: In multiphase wet gas flows, the liquid density is typically considered to be the density of a
homogenous mix of liquid components. See Formula (6).
2.7
dry gas
fluid that is solely in a gaseous phase
Note 1 to entry: The mix of fluid components flowing may cause the gas to have a finite relative humidity but the
flow at the flow meter is only in a gaseous phase.
2.8
emulsion
colloid substance consisting of water and hydrocarbon liquid mixes
Note 1 to entry: Emulsions can be water continuous or hydrocarbon liquid continuous, as these have different
characteristics.
2.9
equation of state
EoS
equations that relate the properties of a given substance to its thermodynamic condition
2 © ISO 2015 – All rights reserved
2.10
film thickness
thickness of the liquid film in annular flow
2.11
flow regime
flow pattern
physical dispersion of phases of a two-phase flow (either wet gas or multiphase) in a conduit
Note 1 to entry: For a particular case of wet gas flow, the flow regime descriptions usually discuss gas and liquid
interaction only, with no individual mention of water and hydrocarbon liquid.
2.12
flow quality
dryness fraction
gas mass fraction
GMF
x
ratio of the gas mass flow rate to the total mass flow rate, or
.
m
g
x==GMF
..
mm+
gl
Note 1 to entry: In multiphase wet gas flows, the liquid flow rate is typically considered to be the sum of the
liquid components (for example, hydrocarbon liquids, water and liquid chemical inhibitors).
2.13
flow regime (pattern) map
graph describing the wet gas flow regime across a range of flow conditions
Note 1 to entry: There is no agreed form for flow regime maps, and different maps can use different parameters
on the graph axes. Gas and liquid superficial velocities are common choices. Flow regime maps are almost always
created from experimental observation, and sometimes include theoretical considerations.
Note 2 to entry: to entry : Flow regime transitional boundaries/regions should be taken as approximations.
2.14
fluid
any substance that continuously deforms under a continuous infinitesimal sheer force.
2.15
foams
mixture of gas and liquids, where the gas is held in a liquid structure
Note 1 to entry: With wet gas, this tends to be more prevalent with gas/water flows than gas/liquid hydrocarbon
flows due to the higher interfacial tension of water compared with that of liquid hydrocarbons.
2.16
free liquid
liquid components in a wet gas flow that are in a liquid form, not including evaporated liquid held as
vapour state with the gaseous component of flow.
2.17
gamma rays
electromagnetic radiation of a kind arising from the radioactive decay of an atomic nucleus
2.18
gas
gaseous component of a wet gas flow, which includes any liquid vapour with relative humid gases
2.19
gas densiometric Froude number
square root of the ratio of the gas flow inertia (if it were to flow alone) to the liquid’s weight, or
U ρ m
Superficial Gas Inertia Force 1
sg g g
Fr == =
g
Liquid Gravity Force ρρ− ρρ()−ρ
gDD AgD
lg gl g
2.20
gas expansion factor
term used to indicate the volume change in gas between two different conditions, which may include
standard conditions
2.21
gas to oil ratio
GOR
ratio of gas to hydrocarbon liquid volume flow rate
3 3
Note 1 to entry: GORs are stated at standard conditions, but may commonly use different units (e.g. sm /sm or
MMscf/bbls) resulting in different numerical values.
2.22
gas volume fraction
GVF
ratio of gas to total fluid volume flow rate at actual flow conditions, or
Q
g
GVF=
..
QQ+
gl
Note 1 to entry: The GVF is a dynamic measurement of volume flow rates that inherently accounts for slip (2.52)
between the gas (Q ) and liquid (Q ) phases. The liquid volume flow rate consists of the sum of the liquid flow
g l
rates, e.g. hydrocarbon liquids, water, and liquid chemical inhibitors. This is not to be confused with gas void
fraction (2.23). GVF may be expressed as a ratio or a percentage.
2.23
gas void fraction
α
g
ratio of gas cross sectional area to total pipe cross sectional area, or
A
g
α =
g
A
Note 1 to entry: Gas void fraction is a static measurement at a moment in time and it does not account for slip
(2.52) between the gas and liquid phases. The existence of slip between the phases differentiates GVF from gas
void fraction.
Note 2 to entry: Phase fraction devices in WGFM designs tend to measure the gas void fraction in the system’s
line-of-sight, not the GVF. The WGFM slip model then derives the GVF from inputs including the gas void fraction
and other subsystem measurements.
2.24
homogeneous hydrocarbon liquid/water flow
flow of water and hydrocarbon liquid where the phases are evenly distributed throughout the fluid mix
and there is no slip between the water and the hydrocarbon liquid
Note 1 to entry: The composition of a homogeneous water and hydrocarbon liquid mix is constant throughout the
conduit. However, homogeneous distribution of the phases is rare.
4 © ISO 2015 – All rights reserved
2.25
infrared
electromagnetic radiation with longer wavelengths than visible light
2.26
intermittent flow
unsteady flow, where the GVF varies with time, e.g. slug flow
2.27
line conditions (actual, process, or operating conditions)
thermodynamic conditions of the fluid passing through the meter, i.e. the fluid conditions at line
(metering device) pressure and temperature
2.28
liquid densiometric Froude number
square root of the ratio of the liquid flow inertia (if it were to flow alone) to the liquid’s weight, or
__
ρ m
Superficial Liquid Inertia Force U 1
sl
l l
Fr == =
l
Liquid Gravity Force ρρ− ρρ()−ρ
gD AgD
lg ll g
2.29
liquid hold up
α
l
ratio of liquid cross sectional area to total pipe cross sectional area, or
A
l
αα=−1 =
lg
A
Note 1 to entry: The liquid hold up gives effectively the same information as the gas void fraction (2.23).
Note 2 to entry: The liquid hold up is a static measurement at a moment in time and it does not account for slip
between the gas and liquid phases. That is the liquid hold-up gas and liquid volume fraction (2.31) differ due to the
existence of slip between the phases.
Note 3 to entry: With multiphase wet gas flow the liquid hold up can be split into its constituent liquid components.
For example, with a gas, condensate and water flow where hydrocarbon liquid hold-up (α ) and water hold up
hcl
(α ) are:
water
A
hcl
α =
hcl
A
A
water
α =
water
A
αα=+αα+= 1
∑ gwater hcl
2.30
liquid loading
qualitative description of the relative amount of liquid in a wet gas flow
2.31
liquid volume fraction
LVF
ratio of liquid to total fluid volume flow rate at actual flow conditions, or
.
Q
l
LVFG=−1 VF=
..
QQ+
lg
Note 1 to entry: The LVF is a dynamic measurement of volume flow rates that inherently accounts for slip
between the gas (Q ) and liquid (Q ) phases. The liquid volume flow rate consists of the sum of the liquid flow
g l
rates (for example, hydrocarbon liquids, water, and liquid chemical inhibitors). This is not to be confused with
liquid hold up (2.29). LVF may be expressed as a ratio or a percentage.
2.32
Lockhart-Martinelli parameter
square root of the ratio of the liquid inertia to gas inertia if the phases flowed alone at line conditions, or
Inertia of Liquid Flowing Alone
X =
LM
Inertia of Gas Flowing AAlone
that is:
.
.
ρ
Fr ρ ρ
m Q 1−GVF
l g
l l l l
X == ==
LM
. .
Fr ρ ρ GVF ρ
g l g g
m Q
g
g
Note 1 to entry: The Lockhart-Martinelli Parameter has a long complicated history. There are several different
definitions for this parameter, and they are not equivalent. This includes the original definition by Lockhart-
Martinelli which is different from the stated definition here. The definition supplied in this Technical Report
is now commonly used. Nevertheless, this issue continues to cause confusion in the industry. The different
[12] [13]
definitions are described in detail with historical context in References and.
Note 2 to entry: In the second formula above, the relationship of the Lockhart-Martinelli number and the GVF is a
function of the density ratio.
2.33
mass flow rate
mass of fluid flowing through a conduit per unit time
2.34
measurand
particular quantities subject to measurement
2.35
meter operating envelope
areas in the two-phase flow rate map (2.59) and/or composition map (2.4) in which a WGFM is to
perform/or stated to be capable of performing
Note 1 to entry: This envelope may vary with changing operating condition and fluid properties.
2.36
microwave
electromagnetic radiation, typically in the frequency range 0,3 GHz to 300 GHz
2.37
multiphase flow
flow of gas, water, and hydrocarbon liquid phases
Note 1 to entry: Each of these three components is designated as a separate “phase”. Multiphase flows may also
have other “phases” such as salinity of water or chemical injection phases. A multiphase flow is a subset of a two-
phase flow where the liquid consists of two or more components, typically water and hydrocarbon liquid. There
is no limit to the relative quantity of liquids in a multiphase flow, i.e. the GVF range is 0 % < GVF < 100 %.
2.38
multiphase flow meter
MPFM
device that measures the oil, water and gas flow rates in a multiphase flow
6 © ISO 2015 – All rights reserved
2.39
multiphase/phase fraction device
device that measures the phase area fractions of the individual phases of a multiphase flow
Note 1 to entry: These devices tend to measure the area occupied by a particular phase across a given cross-
sectional area. This is not the same information as the phase volume flow rate ratios due to the existence of
a slip (2.52).
2.40
oil continuous liquid
oil external emulsion
liquid flow consisting of the two “phases”, hydrocarbon liquid and water, where the hydrocarbon liquid
phase encases the water phase suspended in water droplets in the hydrocarbon liquid phase
2.41
operating envelope
see 2.35
2.42
over-reading
ratio of a single-phase gas flow meter’s erroneous gas mass flow rate prediction (i.e. the “apparent gas
mass flow rate”) to the actual dry gas mass flow rate
Note 1 to entry: In the case of DP devices, this is often approximated to the square root of the wet gas to dry
gas DP ratio.
2.43
permittivity
measure of the ability of a dielectric medium to be electrically polarized when exposed to an electric field
2.44
phase
used in WGFM applications to describe each of the three components gas, water and hydrocarbon liquid.
Other components such as glycol and methanol can also be referred to as “phases”
2.45
phase flow rate
amount (in mass or volume) of a specific phase passing a referenced point in the conduit per unit time
2.46
phase mass fraction
ratio of the mass flow rate of one phase to the total mass flow rate
2.47
production envelope
collection of possible well production trajectories (gas flow rates and liquid flow rates) over time in the
two-phase flow rate map (2.59), see Figure 23
2.48
relative humidity
ratio of water liquid vapour present in a gaseous fluid relative to the maximum (or saturated) amount
of water liquid vapour possible for that given gaseous fluid to hold at a given thermodynamic condition
2.49
Reynolds number
Re
ratio of the inertial to viscous forces, or
ρUD. 4m
Re==
μπμ.D
Note 1 to entry: The Reynolds number is important in many single-phase meter calibrations or characterizations.
In the common event of dry gas meters being used for wet gas flow measurement the Reynolds number term can
be important. Note that there is no consensus on how to define Reynolds number for a multiphase flow
2.50
salinity
quantification of any dissolved salts in water, expressed as either a percentage or a concentration
2.51
shrinkage
volume change in liquids between two different thermodynamic operating conditions (may include
standard conditions); comprises shrinkage due to pressure, temperature, and mass transfer between
phases (e.g. gas coming out of solution)
2.52
slip
qualitative term used to describe differences in velocity between different phases in a wet gas or
multiphase flow
Note 1 to entry: Typically, gas and liquid phases do not travel at the same velocity. The existence of slip
significantly complicates wet gas and multiphase flow metering techniques.
2.53
slip ratio
S
R
ratio of average velocities of any two phases in a wet gas or multiphase flow, or
−
U
g
S =
R
−
U
l
Note 1 to entry: For example, the slip ratio between gases and liquids, hence making the GV
...
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