1320 Wet Gas Measurement.pdf

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Wet Gas MeasurementClass 1320

Philip A LawrenceDirector of Business DevelopmentCamerons Measurement Systems

14450 JFK BlvdHouston, Texas

USA.

Introduction

Wet gas measurement is becoming more prevalent in the modern oil and gas market place. The effect ofentrained liquid in gas and its impact on measurement systems is being researched world wide by variouslaboratories and JIP working groups.

The subject is quite large and encompasses many different concepts, meter types and opinions, with new ideasbeing brought to the fore each year that the subject is reviewed.

This paper will discuss the phenomenon of wet gas and the various types of meters that may be used for itsmeasurement, together with some of the current thinking and concepts associated with wet gas measurement, amention of some of the terms and mathematical concepts used to enable the reader to grasp a better

understanding of what this stuff is about! Proprietary algorithms to determine liquid loading will not be mentioned.

HistoryThe concept of entrained liquid effecting a gas meters performance was looked at many years ago a researchengineer at the NEL (National Engineering Laboratory UK) named J.W. Murdoch, he produced a document fromresearch showing the effect of liquid over-reading, the publication showing the data is available as written byMurdock and is entitled,

"Two-Phase Flow Measurement with Orifices", Journal of Basic Engineering, pp.419-433, 1962. Murdock,

J.W.

Other wet gas researchers have contributed to the development of the subject and a plethora of data and

correlations exist to suit different metering types concepts and installations, the major metering devices

being used are of a differential pressure type due to the robustness of the design.

The subject is hard to deal with because of the lack of test data available to the market place, this

sometimes results in data being kept in house and confidential, also the inability to produce a coherent test

condition in the laboratory that will match the in field location is also a big issue.

Recent laboratory data shows that even with a well managed laboratory offering various multi-product

fluids, at differing pressures, it may be impossible to match the in field condition which means that any

meter correlation, or correction algorithm formed from the data may be suspect.

This is not all doom and gloom it is possible to work with data sets that are not exactly ideal, but caution

must be taken and the metering system uncertainty or accuracy may need to be relaxed, to allow a

sensible operation in the field.

What is Wet Gas?

The term is used to denote a natural gas flow containing a relatively small amount of free liquid by volume,

usually this may be limited up to about 10%.

There are presently few techniques or methods available which can measure this type of fluid regime to a

reasonable degree of accuracy.

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Wet Gas may be considered to be a subset of two-phase flow!

The phenomenon of wet gas may occur in several ways.For example:

a) Over time as dry natural gas wells age, changes in flow conditions including a reduction in line pressure may

result in the heavier hydrocarbon gases condensing in flow-lines and transportation pipelines.

b)Production wells for gas condensate fields usually may have wet gas flow.c) The quantity of lift gas injected to increase production from many oil wells brings them to flow conditions that

can be termed as a wet gas stream.

Many gas wells worldwide are now approaching the latter stages of their production life making wet gas metering

more common and driving meter manufacturers and users to new ideas and methodology.

An ISO DIS (dissertation) 14532 Standard (terminology) also sights the following wet gas definition:

Wet Gas is defined as gas with inclusion of desirable or undesirable components like water vapour, free water

and / or liquid hydrocarbons in significantly greater amounts than those quoted for pipe line quality natural gas.Typically wet gas may consist of unprocessed, (well head) or partially processed natural gases,and may alsocontain condensed hydrocarbon, traces of carbonyl sulphide and, process fluid vapour such as methanol andglycol.

Wet Gas Measurement TermsThe Wet Gas measurement fraternity use a specific language and terms to describe wet gas flow and its effectson metering which can be sometimes difficult to grasp and sound complex.

The following terms are some of those commonly used today, not all of the terms are used in this paper, but theseare presented for the purpose of general knowledge and overview.

Superficial Gas Velocity (SGV)This term refers to the gas velocity in a pipeline system that would be present if there were no liquid present in

the gas stream, If liquid is however present in the system, the actual gas velocity will be higher due to thereduction in available pipe area caused by the liquid present taking space in the pipe.

Superficial Liquid Velocity (SLV)The term superficial liquid velocity refers to the liquid velocity that would be present if there were no gas presentin the gas stream and is related to the SGV.

Liquid Load (LL)Liquid load, or mass ratio, is a wet gas correlation term that is used to describe the amount of liquid present in theflowing gas stream. This term is usually defined as the ratio of the liquid mass flow-rate to the gas mass flow-rateand is commonly expressed and used in calculations as percentage value.

Gas Volume (void) Fraction (GVF.)

GVF, or gas volume fraction, is defined as the ratio of the gas volumetric flow-rate to the total volumetric flow-rate.The total volumetric flow-rate is the sum of the liquid volumetric rate and the gas volumetric flow-rate. Thesevolumetric flows are usually expressed in actual (not standardized )volumetric terms.

Liquid Volume Fraction (LVF).LVF, or liquid volume fraction, is defined as the ratio of the liquid volumetric flow-rate to the total volumetricflow-rate. The total volumetric flow-rate is the sum of the liquid volumetric flow-rate and the gas volumetric flow-rate.These volumetric flows are also usually expressed in actual (not standardized) volumetric terms.

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Lockhart & Martinelli Parameter (or dimensionless number).The term Lockhart Martinelli Number (X) isa dimensionless parameter that is used to correlate gas and liquid flowin a pipe. It was derived by two engineers Lockhart and Martnelli whom worked on steam flow measurementin the late 50s in the UK and has been put forward by wet gas researchers in wet gas calculations.Liquid Hold-up (Hold Up).Liquid Hold-up is described as being the area occupied by the liquid in a wet gas stream when viewed at aspecific location of the cross-section of the pipe, relative to the total cross sectional area of the pipe at the samelocation.

Measurement Over-Reading (or over-measurement error).When a flow measurement device operating in a wet gas environment and reports a higher flow-rate than itshould, it is considered to have what is termed over reading or over measurement error .

Under Reading (or under measurement error).When a flow measurement device reports a lower flow-rate than is actually occurring it is considered to haveproduced an under-reading or under-measurement error.

Froude Number.

The gas velocity may be also expressed as a dimensionless number, known usually as the Densiometric

Froude Number:

Multiphase Flow.This term describes two or more types of liquid components flowing in the gas stream at the same time, it isthen referred to as multiphase flow. Typical liquids include oil, condensate and water, sometimes solids may beentrained which can make the mixture harder to measure and more difficult to determine a mathematicalrepresentation of the said components flow-rates.

Some Mathematical Terms (US customary units).Gas Volume (or void) Fraction. (1) Liquid Volume Fraction (2)

Where:QG = Gas Volumetric Flow-rate at flowingconditions, in ft^3 /sec

QL = Liquid Volumetric Flow-rate at flowingconditions, in ft^3/sec

Where:QG = Gas Volumetric Flow-rate at flowing

conditions, in ft3/secQL = Liquid Volumetric Flow-rate at flowing

conditions, in ft3/sec

Superficial Gas VelocityA

WSGV

G

=

(3) Lockhart & Martninelli NoG

L

QG

QLX

= (4)

Where:WG = Gas Mass Flow-rate, lbm/sec = Density of Gas, lb/ft^3

A = Area of Pipe, ft^2

Liquid Loading %100xW

WLL

G

L= (5)

Where:

Where:

QL = Liquid Volumetric Flow-rate at Flowingconditions, f^t3/sec

QG = Gas Volumetric Flow-rate at Flowingconditions, f^t3/sec

L = Density of Liquid, lb/ft^3G = Density of Gas, lb/f^t3

Liquid Volume FractionQLQG

QLLVF

+= (6)

WL = Liquid Mass Flow-rate, lbm/secWG = Gas Mass Flow-rate, lbm/sec QG = Gas Volumetric Flow-rate at flowing

LiquidGas

Gas

VV

VGVF

+=

LiquidGas

Liquid

VV

VLVF

+=

Where:

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conditions, ft^3/secQL = Liquid Volumetric Flow-rate at flowing

conditions, ft^3

Liquid Volume Fraction(LVF) also = 1 --- GVF (7)Application Chart of Gas Versus Liquid Loading Quantities In Some Applications (Figure 1.0) :

Fig 1.0StandardsMeter performance requirements in the wet gas arena are not covered fully in current measurement standards

but an API recommended practice is available (No RP 85) describes the use of wet gas meters in an allocation

system.

Representation of the fluid velocities types , measured volumes, and mass have also not been exactly defined

and various regions of the world use different terminology to obtain a measurement result. This can add some

confusion and sometimes many discussions between interested parties ensue.

Current trends indicate approximate ranges of liquid/gas ratios found in most producing gas fields as having GVF> 90-93% or Lockhart-Martinelli parameters to a maximum of approx 0.35.

ASME have a wet gas standard underway ASME MFC Sub-Committee 19 (Wet Gas Metering)

The ISO TC193 WG-1SC3 white paper Allocation Metering in the Upstream Area makes an good effort to

detail some definitions to try to arrive at a common start point, and it also deals with wet gas issues and fluid

definitions thus :Fluid Definitions

Some definitions are given below for single-phase fluid streams (e.g. gas, water and liquid streams) and multi-phase fluid stream (e.g. wet gas streams and multiphase streams).

Unlike the downstream and transport and distribution businesses, for the upstream area it is not the case that allfluid streams are properly conditioned to one single-phase and indeed stay in one-phase over a large range ofpressures and temperatures.In the upstream area, the fluids are often un-stabilized, these fluids are what we experience in the wet gas arena,and any pressure and temperature change (even a p in a measurement device or over a valve) might cause aphase change and change a single-phase fluid into a multiphase fluid. Accordingly, all definitions below should be

referred to the operation ranges of temperature and pressure that occur in the system under consideration.Dry Gas (treated gas)

Clean dry gas (not necessarily only hydrocarbons but may contain other components such as CO2, N

2, etc.)

where no liquid condensation is expected over the expected normal operating temperatures and pressures at themetering point. As an example, gas with a dew-point of 5C measured under conditions between 5 and 10C.

Equilibrium Gas (separated at dew-point)

Equilibrium Gas is defined as separated gas that basically has no free liquids but may develop a small liquidcontent by changes in process conditions or meter/pipe-work interaction. Any process changes of the gas maycause a shift in the definition of the gas as wet or dry.

Application Bbl/MMSCF Mass Ratio

Dry gas 0 0

Gas from separator 0-1 .75%

Gas from slug catcher 0-5 3.7%

Wet gas production 0-20 13%

Liquid / Gas production >20 >13%

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These changes may affect the GOR, GCR, the Lockhart-Martinelli parameter and the gas and liquid properties.Close to critical conditions small changes may cause large variations in the liquid and gas fractions and in thefluid properties.

Care should be taken in meter selection so as not to cause additional impact on the line process conditions.The measurement devices that can be used for equilibrium gas are similar to the devices mentioned for dry gasapplication. However, in the design, care should be taken in that, as soon as liquids start to be formed (e.g. dueto pressure drop in the meter) the effect on the reading should be established.

Ultrasonic meters are increasingly being used for this service, and the following comments are relevant.

At present ultrasonic meters may not be suitable for measuring gas above 0.5% LVF (Liquid Volume Fraction) asthe units may produce unstable readings.

Care should be taken in systems subject to carry over or liquid entrainment when the ultrasonic meter has a poorlocation. If the meter is too close to bends, valves or other obstructions, the resulting swirl / turbulence canseriously affect the accuracy of the mathematical techniques used to find the velocity profile and therefore theflow-rate.

If the operating temperature is too high there may be a issues over the strength of the bonding material used inthe manufacture of some types of Ultrasonic transducers.

Testing has shown some transducers may fail at temperatures in excess of 150C or when there is a suddenpressure fluctuation (an occurrence that can be common in production pipelines).

Other installation parameters or concerns that need care are that some signals read by the meter may be verysusceptible to background noise from other components in, or close to the pipeline on some designs.

Work is however underway to develop ultrasonic meters for wet gas above current norms !

Wet Gas (two or three phase)

Any mixture of gas and up to about 10% by volume of liquid hydrocarbon and water. The mass ratio of gas toliquid varies significantly with pressure for a constant Gas Volume Fraction. A convenient parameter to indicatethe wetness of the gas is the Lockhart-Martinelli parameter.

Gassy Liquids (two or three phases)

Any mixture of hydrocarbon liquid and water at a pressure below its equilibrium pressure (bubble point) andwhere gas is present in the liquid mixture. This typically occurs inside a separator or where the liquid is exposedto a pressure reduction e.g.cavitation.

Gas-Oil (or Gas-Condensate) Ratio, GOR or GCR

The ratio of produced gas flow rate to the produced oil (condensate) flow rate. Generally the GOR or GCR is

measured in standard units, e.g. m3

/m3

or scf/bbl.

Gas-Liquid Ratio, GLR

The ratio of produced gas flow rate to the produced total liquid flow rate. Generally the GLR is measured in

standard units, e.g. m3

/ m3

or scf / bbl.

Gas and Liquid Behavior in a Closed Conduit

The behavior of the gas and liquid in a flowing pipe will exhibit various characteristics of flow depending on thepressure of the gas, velocity of the gas, and liquid content, as well as the piping orientation , (horizontal, verticalor sloping).

The liquid may be in the form of tiny droplets or, the pipe may be filled completely with liquid.

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Despite the complexity of the gas and liquid interactions, various attempts have been made to model thisbehavior.

These gas and liquid interactions are referred to as flow regimes or flow patterns. (Figs 2 and 3)

Flow regime maps are used to describe the way gasses and liquids interact based on various parameters.These maps and charts may also be used to try to predict the performance of a specific flow meter based onthe type of regime present.

Figure 2.0 Flow Pattern Map

Figure 3.0 Flow Regime Map (Horizontal Pipes)

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Flow Regimes

Annular Mist FlowAnnular mist flow occurs at high gas velocities. A thin film of liquid is present around the annulus of the pipe.Usually most of the liquid is entrained in the form of droplets in the gas core.Due to the result of gravity, there is usually a thicker film of liquid on the bottom of the pipe as opposed to thetop of the pipe or measurement device. (Figure 4.0)

Fig 4.0Stratified (Smooth) FlowStratified or stratified smooth flow exists when the gravitational separation is complete.The liquid flows along the bottom of the pipe as gas flows over the top. Liquid holdup in this regime can be largebut the gas velocities are usually low.

Stratified Wave FlowStratified wave flow is similar to stratified smooth flow, but with a higher gas velocity. The higher gas velocityproduces waves on the liquid surface. These waves may become large enough to break off liquid droplet at thepeaks of the waves and become entrained in the gas. These droplets are distributed further down the pipe.

Slug FlowIn the slug flow regime, large frothy waves of liquid form a slug that can fill the pipe completely. These slugs mayalso be in the form of a surge wave that exists upon a thick film of liquid on the bottom of the pipe.

Elongated Bubble FlowElongated bubble flow consists of a mostly liquid flow with elongated bubbles present closer to the top of the pipe.

Dispersed FlowAssume a pipe is completely filled with liquid with a small amount of entrained gas. The gas is in the form ofsmaller bubbles. These bubbles of gas have a tendency to reside in the top region of the pipe as gravity holds theliquid in the bottom of the pipe

Other Regime Issues

Wet Gas systems are prone to hydrate formation in certain instances and care must be taken in design ofsystems that may be inaccessible (sub-sea) also transmitter sensing line lengths and the position to thetransmitter must be reviewed.

Natural gas pockets between hydrate plugs in a pipe can cause safety concerns. If a pipeline is believed to bedepressurized and a gas pocket is present, safety issues arise. When the hydrate plug dissociates, the plug canturn into a high speed projectile driven by the pressure behind it causing catastrophic results. These movinghydrates can snap off thermo-wells off destroy orifice plates and cone devices.Care must be taken when thawing out hydrates

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Wet Gas Research

A large amount of research has been conducted to determine the effect that wet gas flow regimes have on flowmeasurement devices. This research has been used to help to develop devices that can measure the gas andliquid volumes.

Typical Wet Gas Testing LoopTo evaluate dry gas flow meters under wet gas conditions, a typical piping setup is commonly used.

The apparatus consists of a reference gas flow meter positioned in a dry gas stream. A metered liquid injectionpoint is positioned downstream of the dry gas measurement source. This is the point where liquid is introduced tothe dry gas stream.

The flow meter under test is positioned after the metered liquid injection point (Figure 5). Both the gas andliquid streams are measured individually before being combined.

Figure 5.0 Wet Gas Test Loop (Typical)

Meter Types used in Wet Gas

The main meter types being developed as wet natural gas meters are Ultrasonic and Differential Pressure Meters.These are dealt with next :

Ultrasonic MetersUltrasonic Meter manufacturers are currently researching the possibility of developing an Ultrasonic Meter into awet natural gas device but so far the published research has shown this to be an extremely difficult technicalchallenge as mentioned earlier.

Whereas for many dry gas applications the Ultrasonic Meter is an excellent choice of meter it is found howeverwhen using it for wet gas measurement a number of problems arise.

These include the chord flooding and therefore failing, liquid bridging the gap between transducer face and pipewall (causing loss of signal), the signal strength being reduced by absorption in the liquid phase, the signal beingdeflected away from the desired path by refraction through the liquid phase and the background noise of valvesetc. drowning out the signal. Most of the recent wet gas ultrasonic research done on stratified flow which can bedifficult to reproduce in the live field condition.

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Differential Pressure Meters

Orifice Plate Meter

Traditionally the Orifice Plate Meter was used to meter wet gas flows. In the last few years this has changedsince it is now known that the liquid is held up at the plate and the resulting flow is not steady. The liquid tends totravel through the orifice in slugs. The result is an unsteady DP reading. This can be seen from Orifice PlateMeter wet gas photographs taken at the South West Research Institution in 1997 (see fig 6.0)

Fig 6.0 :An Orifice Meter in a Wet Gas Flow.

Furthermore, Orifice Plates are susceptible to distortion if struck by a slug or pressure pulse and the plate tendsto act as a liquid trap that can gathers particulates in the downstream and upstream section.

Venturi Meter

The Venturi Meter is a popular wet gas meter. It does not suffer the same problems as an Orifice Plate Meter asit allows slugs and pressure pulses to pass through unobstructed due to the inlet being angled. (This feature alsoallows the Venturi to be self cleaning. Current Wet Gas Metering research Joint Industry Projects all include thismeter in their test programs and its performance is reasonably well documented.)

One main difference between the Wet Gas Venturi Meter and the Wet Gas Cone Type Meter is that the minimumflow area (i.e. the throat) of the Venturi is along the centerline and the Cone Meters minimum flow area is at theperiphery of the pipe which has some advantages.

This gives the cone meter an advantage in a wet gas flow as it does in single-phase flow , the meter cancondition the flow as it passes the cone.

The net result is a steady DP signal seen in cone type devices. Venturi meters do not condition the flow as

effectively as cone devices it also may tend to hold up liquid at the inlet and therefore small slugs created by theVenturi meters design periodically flow through the meter causing pressure spikes to be read at the DP ports.

Venturi Meter testing in industry has led to the publication of special correlations to correct for the liquid inducederror.

The Venturi Meters general performance is similar to a Cone Meters and correlations found are very similar toeach other , cone meters have a slight edge in operational stability.

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Entrained liquid in gas causes an over-reading in the gas flow rate determination (fig 7.0 )

Wet Gas Cone Meters

The Cone Meter is also a self cleaning device. The acceleration of the gas over the cone tends to remove anyliquid and particulates that come into contact with the meter.The Cone acts on the flow regime to redistribute it over the pipe area this is advantageous in tight installationspaces and downstream mixing takes place.

In 2002 NEL tested 6 0.55 and 0.75 beta ratio cone meters and the results and analysis were reported at the2002 NSFMW It was found that like other DP meters the Cone meter over-reads the gas flow-rate with a wet gasflow and can be a predictable device.

The scale of this positive error induced by an entrained liquids presence in a gas flow was found to bedependent on a)The Lockhart-Martinelli parameter (X), b)The pressure (or gas to liquid density ratio) and c)The

gas densiometric Froude number (gFr ).

The definition of the Lockhart - Martinelli parameter was mentioned earlier and is the square root of the ratio ofthe superficial liquid flow inertia force to the superficial gas flow inertia force. (equation (4))The definition of the gas Densiometric Froude number is: the square root of the ratio of gas inertia force to the

liquid gravitational force. It is calculated in equation ( 7) Note that in equation 7 the term sgU is the superficial gas

velocity which is calculated by equation (8).

gl

gsg

ggD

U

Fr

= (7) A

m

Ug

g

.

sg= (8)

Positive errors induced on any type of DP meter by an entrained liquids presence in the gas flow is commonly

presented in the form of the square root of the ratio of the actual read DP from the wet gas flow ( tpP ) and the

DP that would be expected to be read from that specific DP meter if the gas phase flowed alone through the

meter ( gP ).

1.00

1.05

1.10

1.15

1.20

1.25

0 50 100 150 200 250 300 350 400

LGR (m3 liquid/million normal m3 gas)

Gasflowo

verreading

Venturi

Orifice

Fi ure 7.0

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The over-reading is usually expressed by the term gtp PP . Alternatively the absolute percentage liquid

induced error for any DP meter can be approximated to be ( ) %100*1PP gtp .

It has been found from research that as the Lockhart-Martinelli parameter (X) increased for a set gas to liquiddensity ratio and gas densiometric Froude number (Frg),,, the over-reading increased.

If the gas to liquid density ratio increased for a set Lockhart-Martinelli parameter and gas Densiometric Froudenumber.the over-reading can reduce.

If the gas Densiometric Froude number increased say for a set Lockhart-Martinelli parameter and gas to liquiddensity ratio the over-reading can increase. (figure 9.0)

Determining Liquid Loading

A popular method for finding the liquid flow-rate in a wet natural gas flow is to use a tracer injection method. TheShell Oil Company developed technique is well documented , and it offers water and liquid hydrocarbon flow-rate

estimations to about 10%. Over the last few years the tracer injection technique has been applied with theVenturi meter and a Venturi meters wet gas flow correlation used to predict wet gas effect and liquid flow-rates.

Figure 9.0

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Tracer Methodology

A chemical tracer is injected upstream o f the DP meter into the wet gas stream at a known flow rate.Samples are taken downstream of the meter at around 150 diameters (may be shorter if mechanical mixing ispresent ) to enable mixing to talk placeThe samples fluorescent intensity is compared with that of the tracer Difference in the fluorescents together withthe rate of the tracer injection can be related to flow rate.10 samples are usually taken over 10 minute intervals,samples are analyzed after being allowed to stand

overnight and liquid rate for each sample determined.A flash factor for the condensate is applied. From this data a liquid load data set can be found and then appliedto the wet gas DP meter to correct the over-read .

ConclusionsWet Gas measurement is a complicated subject that requires forethought in using applications usually at thecutting edge of technology. As more work is done in this field ideas that were valid 10 years ago are now foundto be changed. The advent of metering applications were hydrate formation is possible must have a safetyreview incorporated to make sure that not only measurement issues are dealt with. Newer technologies areentering the market place each year however a uniform test method must be developed to offer the end user thechance for comparison between these devices.

Index of some terms

X The Lockhart-Martinelli Parameter

g

.

m The actual gas mass flow-rate

l

.

m The actual liquid mass flow-rate

( )tpg

.

m The over estimated gas mass flowrate using

the read wet gas differential pressure

g The gas density

l The liquid density

tpP The read wet gas (or two-phase) D.P.

gP The gas superficial differential pressure

dC The discharge coefficient

gFr The gas Densiometric Froude number

sgU The superficial gas velocityg The gravitational constant

D The meter inlet diameterA The meter inlet cross sectional areaM3 Cubic MetersE The DP meter Velocity of ApproachY The DP meter expansibility factorM The Murdock gradientMSCF Thousand standard cubic feet

SCFH Standard cubic feet per hour

ReferencesMurdock, J.W., Two-Phase Flow Measurement With Orifices, ASME Journal of Basic Engineering, Dec. 1962Hewitt G.F. , Measurement of Two Phase Flow Parameters, Academic Press, London, New York, S.F. 1978Ting V.C ., "Effects of Non-Standard Operating Conditions on the Accuracy of Orifice Meters", SPE 1993Ifft. S. and Mikkelsen. E.D ,Pipe Elbow Effects on the V-Cone Flow-meter, ASME Fluids Conference, 1993

Gas Processors Association, Engineering Data Book, Volume 1, Sections 1-16, Gas Processors SuppliersAssociation, Tulsa, OK, Revised Tenth Edition, 1994Ifft S Mccrometer Wet Gas Meter Testing NSFMW Kristiansand Norway 1997Van-Mannen. H.Cost Reduction - Wet-Gas Measmt Using the Tracer-Venturi Combination, NEL one day seminar, 1999De Leeuw. H (R), Liquid Correction of Venturi Meter Readings in Wet Gas Flow, NSFMW 1997

Stewart D., Hodges D., Steven R., Peters R., Wet Gas Metering with V-Cone Meters, NSFMW 2002

Kegel,T.M Wet Gas Measurement, 4th CIATEQ Semina r on Advanced Flow Measurement, Boca del Rio, 2003John Amdal, Harald Danielson, Eivind Dykesteen, Dag Fllo, Jens Grendstad, Hans Olav Hide, Hkon Moestue,Bernt Helge Torkildsen, Handbook of Multiphase MeteringThe Norwegian Society for Oil and Gas Measurement.Lawrence PA & Steven R Research Developments In Wet Gas Metering with V-Cone Meters NSFMW 2003Kinney J ISHM Class # 1320 Wet Gas Measurement ISHM O.K. USA 2006ISO TC 193 WG 1.0 Allocation Metering in the Upstream Area (white paper) 2006Steven R A Discussion on Horizontal Wet Gas D.P. Flow Meters St Andrews Scotland UK..NSFMW 2007

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1320 Wet Gas Measurement.pdf