Wet Gas Measurement

Philip A LawrenceChairman ISO TC193 SC3

ISO-NEN (Upstream Natural Gas Measurement)

Kingwood Texas

IntroductionWet gas measurement is becoming more prevalent in the modern oil and gas marketplace. The effect of entrained liquid in gas and its impact on measurement systemsis being researched world wide by various laboratories and JIP working groups. Theimpact can be very significant financially.

The subject is quite large and encompasses many different concepts, meter types andopinions, with many new ideas being brought to the forefront each year as moreresearch is done.

This paper will discuss and describe the phenomenon of wet gas and some of thevarious types of meters that are and may be used for this type of measurement,together with some recent thinking and concepts associated with wet gas measurement,The writer will mention some of the terms and mathematical concepts used to enablethe reader to grasp a better understanding of what this stuff is about!

Only public domain algorithms to determine liquid loading be mentioned.

History The concept of entrained liquid effecting a gas meters performance was looked atmany years ago an American research engineer Dr J.W. Murdoch, he produced adocument from research showing “the effect of liquid over-reading”, the publicationshowing the data is available as written by Murdock 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 aplethora of data and correlations exist to suit different metering type’s conceptsand installations, the major metering devices being used are of a differentialpressure type due to the robustness of the design.

The subject is hard to deal with because of the lack of test data available to themarket 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 willmatch the in field location is also a big issue.

Recent laboratory data shows that even with a well managed laboratory facilityoffering various multi-product fluids, at differing pressures and density rations ,it may be impossible to match the” in field condition” which means that any metercorrelation, or correction algorithm formed from the data may be suspect in otherfield conditions.

This is not all doom and gloom it is possible to work with data sets that are notexactly ideal, but caution must be taken and the metering system uncertainty oraccuracy 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 amountof free liquid by volume, usually this may be limited up to about 10%. The ASMEMFC19 Wet Gas Technical Report/Guide offers some guidance although it is circa 300pages long ! and requires a lot of study.

There are presently few techniques or methods available which can measure this typeof fluid regime with a reasonable degree of accuracy.

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 areduction in line pressure may result in the heavier hydrocarbon gases condensing in flow-lines andtransportation 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 wellsbrings 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 productionlife making wet gas metering more common and driving meter manufacturers and usersto new ideas and methodology. An ISO DIS (dissertation) 14532 Standard (terminology) also sights the following wetgas definition:Wet Gas is defined as gas with inclusion of desirable or undesirable components likewater vapour, free water and / or liquid hydrocarbons in significantly greateramounts than those quoted for pipe line quality natural gas. Typically wet gas may consist of unprocessed, (well head) or partially processednatural gases,and may also contain condensed hydrocarbon, traces of carbonylsulphide and, process fluid vapour such as methanol and glycol.The ISO TC 193 WG no 1 Technical report also refers to wet gas in the same way asthe14532 dissertation.

Wet Gas Measurement TermsThe Wet Gas measurement fraternity use a specific language and terms to describe wetgas flow and its effects on metering which can be sometimes difficult to grasp andsound complex.

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

Superficial Gas Velocity (SGV)This term refers to the gas velocity in a pipeline system that would be present ifthere were no liquid present inthe gas stream, If liquid is however present in the system, the actual gas velocitywill be higher due to the reduction in available pipe area caused by the liquidpresent taking space in the pipe.

Superficial Liquid Velocity (SLV)The term superficial liquid velocity refers to the liquid velocity that would bepresent 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 describethe amount of liquid present in the flowing gas stream. This term is usually definedas the ratio of the liquid mass flow-rate to the gas mass flow-rate and iscommonly 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-rateto the total volumetric flow-rate.The total volumetric flow-rate is the sum of the liquid volumetric rate and the gasvolumetric flow-rate. These volumetric flows are usually expressed in actual (notstandardized )volumetric terms.

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

Lockhart & Martinelli Parameter (or dimensionless number) very important to review !The term Lockhart Martinelli Number (X) isa dimensionless parameter that is used tocorrelate gas and liquid flowin a pipe. It was derived by two engineers Lockhart and Martnelli whom workedon steam flow measurement in the late 50’s in the UK and has been put forward bywet 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 gasstream when viewed at a specific location of the cross-section of the pipe, relativeto the total cross sectional area of the pipe at the same location.

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

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

Froude Number. The gas velocity may be also expressed as a dimensionless number, known usually asthe Densiometric Froude Number:

Multiphase Flow. This term describes two or more types of liquid components flowing in the gasstream at the same time, it is then referred to as multiphase flow. Typical liquidsinclude oil, condensate and water, sometimes solids may be entrained which can makethe 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) LiquidVolume Fraction (2)

Where: QG = Gas Volumetric Flow-rate at flowing conditions, in ft^3 /secQL = Liquid Volumetric Flow-rate at flowing conditions, in ft^3/sec

Where: QG = Gas Volumetric Flow-rate atflowing conditions, in ft3/sec QL = Liquid Volumetric Flow-rate at flowing conditions, in ft3/sec

Superficial Gas Velocity (3) Lockhart &

Martninelli No (4)

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

A = Area of Pipe, ft^2

Liquid Loading

(5) Where:Where:QL = Liquid Volumetric Flow-rate at Flowing

conditions, f^t3/secQG = Gas Volumetric Flow-rate at Flowing conditions, f^t3/secρL = Density of Liquid, lb/ft^3ρG = Density of Gas, lb/f^t3

Liquid Volume Fraction

(6)

WL = Liquid Mass Flow-rate, lbm/sec WG = Gas Mass Flow-rate, lbm/sec

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

Where:

Liquid Volume Fraction (LVF) also = 1 – GVF (7)

Basic Application Chart of Liquid Loading Showing Quantities/Ratios Some Gasapplications. (Figure 1.0)

Fig 1.0Standards

Meter performance requirements in the wet gas arena are not covered fully incurrent measurement standards but an API recommended practice is available (API-RP85) describes the use of wet gas meters in an allocation system which was developedfor a certain field condition in the G.O.M.

Representation of the fluid velocities, types, measured volumes, and mass have in thepast not been exactly defined or agreed and various regions of the world usedifferent terminology to obtain a measurement result.

This can add some confusion and sometimes many tough discussions between interestedparties ensue.

Current trends indicate approximate ranges of liquid/gas ratios found in mostproducing gas fields as having GVF > 90-93% or Lockhart-Martinelli parameters to amaximum of approx 0.3

ASME have a wet gas report completed and published - ASME MFC Sub-Committee 19 (WetGas Metering)

The ISO TC193 WG-1 SC3 white paper “Allocation Metering in the Upstream Area”makes an good effort to detail some definitions to try to arrive at a common startpoint, and it also deals with ‘wet gas’ issues and fluid definitions thus .

TC193 also is about to publish a wet gas technical report under SC3 WG 2 “wet gasmeasurement in the upstream area” Fluid Definitions

Some definitions are given below for single-phase fluid streams (e.g. gas, water andliquid streams) and multi-phase fluid stream (e.g. wet gas streams and multiphasestreams). Unlike the downstream and transport and distribution businesses, for the upstreamarea it is not the case that all fluid streams are properly conditioned to onesingle-phase and indeed stay in one-phase over a large range of pressures andtemperatures.In the upstream area, the fluids are often un-stabilized, these fluids are what weexperience in the wet gas arena, and any pressure and temperature change (even a Δpin a measurement device or over a valve) might cause a phase change and change asingle-phase fluid into a multiphase fluid. Accordingly, all definitions below shouldbe referred to the operation ranges of temperature and pressure that occur in thesystem under consideration. Dry Gas (treated gas) Clean dry gas (not necessarily only hydrocarbons but may contain other componentssuch as CO2, N2, etc.) where no liquid condensation is expected over the expectednormal operating temperatures and pressures at the metering point. As an example, gaswith a dew-point of –5°C measured under conditions between 5 and 10°C.

Equilibrium Gas (separated at dew-point) Equilibrium Gas is defined as separated gas that basically has no free liquids butmay develop a small liquid content by changes in process conditions or meter/pipe-work interaction. Any process changes of the gas may cause a shift in the definitionof the gas as wet or dry. These changes may affect the GOR, GCR, the Lockhart-Martinelli parameter and the gasand liquid properties. Close to critical conditions small changes may cause largevariations in the liquid and gas fractions and in the fluid properties. Care should be taken in meter selection so as not to cause additional impact on theline process conditions.The measurement devices that can be used for equilibrium gas are similar to thedevices mentioned for dry gas application. However, in the design, care should betaken in that, as soon as liquids start to be formed (e.g. due to pressure drop inthe meter) the effect on the reading should be established.

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

At present ultrasonic meters may not be suitable for measuring gas above 0.5% LVF(Liquid Volume Fraction) as the units may produce unstable readings and research onthese devices

Care should be taken in systems subject to carry over or liquid entrainment when theultrasonic meter has a poor location. If the meter is too close to bends, valves orother obstructions, the resulting swirl / turbulence can seriously affect the

accuracy of the mathematical techniques used to find the velocity profile andtherefore the flow-rate.

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

Testing has shown some transducers may fail at temperatures in excess of 150°C orwhen there is a sudden pressure fluctuation (an occurrence that can be common inproduction pipelines).

Other installation parameters or concerns that need care are that some signals readby the meter may be very susceptible 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 currentnorms! 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 to liquid varies significantly with pressure for a constant GasVolume Fraction. A convenient parameter to indicate the wetness of the gas is theLockhart-Martinelli parameter. Gassy Liquids (two or three phases) Any mixture of hydrocarbon liquid and water at a pressure below its equilibriumpressure (bubble point) and where gas is present in the liquid mixture. Thistypically occurs inside a separator or where the liquid is exposed to a pressurereduction 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.GenerallyGLR 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 variouscharacteristics of flow depending on the pressure of the gas, velocity of the gas,and liquid content, as well as the piping orientation , (horizontal, vertical orsloping). The liquid may be in the form of tiny droplets or, the pipe may be filled completelywith liquid.

Despite the complexity of the gas and liquid interactions, various attempts have beenmade to model this behavior.

These gas and liquid interactions are referred to as “flow regimes” or “flowpatterns”,(Figs 2 and 3)

Flow regime maps are used to describe the way gas and liquids interact based onvarious parameters.

These maps and charts may also be used to try to predict the performance of aspecific flow meter based on the type of regime present.

Figure 2.0 Flow Pattern Map-(CEESI Colorado)

Figure 3.0 Flow Regime Map (Horizontal Pipes) (ISO-ASME)

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 bottomof the pipe as opposed to the top of the pipe or measurement device (Figure 4.0 is anextreme case)

Figure 4.0

Stratified (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 large but 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 may

Also 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 presentcloser 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 Flow Regime Issues

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

Natural gas pockets between hydrate plugs in a pipe can cause safety concerns. If apipeline is believed to be depressurized and a gas pocket is present, safety issuesarise. When the hydrate plug dissociates, the plug can turn into a high speedprojectile driven by the pressure behind it causing catastrophic results.

These moving hydrates can snap off thermo-wells off destroy orifice plates and conedevices valves ,Venturi meters etc.

Wet Gas Research

An amount of research has been conducted to determine the effect that wet gas flowregimes have on flow measurement devices. This research has been used to help todevelop devices that can measure the gas and liquid volumes.

Typical Wet Gas Testing Loop

To evaluate dry gas flow meters under wet gas conditions, a typical piping setup iscommonly used.

The apparatus consists of a reference gas flow meter positioned in a dry gas stream.A metered liquid injection point is positioned downstream of the dry gas measurementsource. This is the point where liquid is introduced to the dry gas stream.

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

Figure 5.0 “Wet Gas TestLoop”(Typical CEESI)

Meter Types used in Wet Gas

The main meter types being developed as wet natural gas meters are Ultrasonic andDifferential Pressure Meters. These are dealt with in the paper next:-

Differential Pressure Meters

Orifice Plate Meter

Traditionally the Orifice Plate Meter was used to meter wet gas flows. In the lastfew years this has changed since it is now known that the liquid is held up at theplate and the resulting flow is not steady. The liquid tends to travel through theorifice in slugs. The result is an unsteady DP reading. This can be seen from OrificePlate Meter wet gas photographs taken at the South West Research Institute in 1997.(See fig 6.0)

Fig 6.0-An Orifice Meter in a Wet Gas Flow-(SWRI San Antonio TX)

Furthermore, Orifice Plates can be susceptible to distortion if struck by a slug orpressure pulse and the plate tends to act as a liquid trap that can gathersparticulates in the downstream and upstream section (Figure 6.0)

Venturi Type Meter

The Venturi meter is a more popular wet gas meter. It does not suffer the sameproblems as an Orifice Plate Meter as it allows slugs and pressure pulses to passthrough unobstructed due to the inlet being angled. (This feature also allows theVenturi to be self cleaning. Current Wet Gas Metering Research Joint IndustryProjects all include this meter in their test programs and its performance isreasonably well documented.)

One main difference between the Wet Gas Venturi Meter and the Wet Gas Cone Type Meteris that the minimum flow area (i.e. the “throat”) of the Venturi is along the centerline and the Cone Meters minimum flow area is at the periphery of the pipe which hassome advantages in regards to certain flow regimes.

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

The net result is a steady DP signal seen in cone type devices. Venturi meters donot condition the flow as effectively as cone devices it also may tend to hold upliquid at the inlet and therefore small slugs created by the Venturi meters designperiodically flow through the meter causing pressure spikes to be read at the DPports.

Venturi Meter testing in industry has led to the publication of special correlationsto correct for the liquid induced error.

The Venturi Meters general performance is similar to a Cone Meters and correlationsfound are very similar to each other cone meters have a slight edge in operationalstability and turndown. Entrained liquid in gas causes an over-reading in the gas flow rate determination(Figure 7.0)

Cone Type Meter

The Cone Meter is also a self cleaning device. The acceleration of the gas over thecone tends to remove any liquid and particulates that come into contact with themeter.

The Cone acts on the flow regime to redistribute it over the pipe area this isadvantageous in tight installation spaces and downstream mixing takes place. For gasand wet gas the static and DP taps are usually on the top of the meter. (The drawing fig 8.0is for illustrative purposes only)

1.00

1.05

1.10

1.15

1.20

1.25

0 50 100 150 200 250 300 350 400

LG R (m 3 liquid/m illion norm al m 3 gas)

Gas flow overreading Ventur

Orifi

Figure 7.0

Figure 8.0 Typical Cone Meter (cut away) Wet Gas Preferred Beta Ratio @ 0.75(Courtesy Cameron Valve and Measurement Inc)

Cone Meter Wet Gas Research

In 2002 NEL tested 6” 0.55 and 0.75 beta ratio cone meters and the results andanalysis were reported at the 2002 NSFMW It was found that like other DP meters theCone meter over-reads the gas flow-rate with a wet gas flow and can be a predictabledevice.

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

The definition of the Lockhart - Martinelli parameter was mentioned earlier and isthe square root of the ratio of the superficial liquid flow inertia force to thesuperficial gas flow inertia force. (equation (4))

The definition of the gas Densiometric Froude number is: the square root of the ratioof 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

gsgg gD

UFr

(7)

AmUg

g.

sg (8)

Positive errors induced on any type of DP meter by an entrained liquids presence inthe gas flow is commonly presented in the form of the square root of the ratio ofthe actual read DP from the wet gas flow ( tpP ) and the DP that would be expected tobe read from that specific DP meter if the gas phase flowed alone through the meter( gP ).

The over-reading is usually expressed by the term gtp PP . Alternatively theabsolute 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 liquid density ratio and gas Densiometric Froude number(Frg)….. the over-reading increased.

If the gas to liquid density ratio increased for a set Lockhart-Martinelli parameterand gas Densiometric Froude number …… the over-reading may reduce.

If the gas Densiometric Froude number increased say for a set Lockhart-Martinelliparameter and gas to liquid density 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 usea tracer injection method. The Shell Oil Company developed technique is welldocumented, 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 gaseffect and liquid flow-rates. As shown below in Figure 10 next

Figure 10

Tracer Methodology (Widely Used)

A special chemical tracer is injected upstream o f the DP meter into the wet gasstream at a known flow rate.Samples are taken downstream of the meter at around 150 diameters (may be shorter ifmechanical mixing is present) to enable mixing to talk place

The samples fluorescent intensity is compared with that of the tracer Difference inthe fluorescents together with the rate of the tracer injection can be related toflow rate. 10 samples are usually taken over 10 minute intervals, samples are

DP Meter v

Figure 9.0 (Courtesy of Cameron Valve and Measurement Inc-O.R. / XLM Plot)

analyzed after being allowed to stand overnight and liquid rate for each sampledetermined.

A flash factor for the condensate is applied. From this data a liquid load data setcan be found and then applied to the wet gas DP meter to correct the over-read .

Downstream Recovery Pressure Method

This method uses the relationship that the recovery pressure measured downstream ofany differential pressure meters varies as the liquid loading changes within certainparameters of density ratio and pressure.

This phenomenon has been detailed by various laboratories and researchers usingvarious D.P. meters Venturi Cone types and Orifice Plates where trash is notprevalent in the line.

The concept of measuring a liquid is a pipe by using just a pressure transmitterafter the meter has a real appeal to the problem of liquid determination.

Caution must be taken to see if the density ratios, pressures and flow rates fallinto the generic wet gas research release data in 2007 by CEESI of Nunn Colorado.

The recovery pressure is read at 4 D’s from the rear face of the cone meter the datacollected can be used to develop algorithms that will allow under certain conditionsand density ratios to predict liquid loading to a certain uncertainty.

The levels of uncertainty for the liquid measurement is not low but usually thesetypes of measurement application have no liquid base line to work from for correctionanyhow. “Stevens” records that the following equations used sensibly approximatesthe liquid value and outputs a gas correction for a simple wet gas meter thatdetermines liquid load using the pressure loss ratio dry to wet.

Other Electronic Non DP Devices

Care must be taken when using energy additive (electronic meters) to measure wet gasbecause there is reduced research available on these types of meters due to certainissues that prevent repeatable measurement and also the devices may only work well inrestrictive liquid /gas flow regimes or for that particular set of conditions.

Ultrasonic Meters

Whilst they are very good for dry gas applications the uncertainty for these devicesdepends on many factors when used in wet gas flow regimes. Research has been done onstratified flow with certain devices.

Issues

The chord flooding and failing and liquid bridging the gap between transducer faceand pipe wall (causing loss of signal).The signal strength being reduced byabsorption in the liquid phase, the signal being deflected away from the desired pathby refraction through the liquid phase and the background noise of valves etc.

The signal may be drowned out by the liquid at the transducer location and can makethis type of meter fail to perform properly

Data released in 2007 shows that for certain types of ultrasonic meter the Lockhart &Martineli numbers must be kept low to obtain a useable result.( Figs 11 and 11 a)

Some ultrasonic meter manufacturers are currently researching the possibility ofdeveloping an Ultrasonic Meter into a wet natural gas device but so far the publishedresearch has shown this to be an extremely difficult technical challenge.

Wet Gas Testing Data (Typical Ultrasonic Meter Test Spool and Data Set Fig 11 and 11 a)

Courtesy CEESI Wet Gas Data Release 2007 Figure11.0a.

Coriolis Type Meter Wet Gas Test Data (Two Types Shown A&B).

Meters were tested at the CEESI wet gas loop and both types seem to operate withpredictability only at low LM numbers. This can be seen in the data sets providedmeter a to LM 0.18 and meter B to LM 0.035.

Meter Type A Meter Type B

Both Data Sets Courtesy of CEESI Wet Gas Data Release 2007

Conclusions

Wet Gas measurement is a complicated subject that requires fore-thought inmeasurement applications ,it is usually at the cutting edge of technology. As morework is done in this field ideas that were valid 10 years ago are now found to bechanged slightly.

The advent of metering applications were hydrate formation is possible musthave a safety review incorporated to make sure that not only measurement butsafety issues are dealt with.

Newer technologies are entering the market place each year however a uniform testmethod must be formulated to offer the user the chance of comparison between wetgas metering devices in use and entering the marketplace.

Test Limit B 0.035 LM.

Test Limit B 0.035 LM.Amplified

Index of Some Terms

X The Lockhart-MartinelliParameter

The actual gas mass flow-

rate

The actual liquid mass

flow-rate

The overestimated gas mass flow-

rate using the read wet gasdifferential pressure.g The gas densityl The liquid density

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

The gas superficialdifferential pressure

The dischargecoefficient

The Gas DensiometricFroude number

The superficial gasvelocity g The gravitationalconstant

D The meter inletdiameterA The meter inlet crosssectional areaM3 Cubic Meters E The DP meter Velocityof ApproachY The DP meterexpansibility factorM The Murdock gradientMSCF Thousand standard cubicfeetSCFH Standard cubic feet perhour

References.

Murdock, J.W., “Two-Phase Flow Measurement with Orifices”, ASME Journal of Basic Engineering,Dec. 1962

Ting V.C , "Effects of Non-Standard Operating Conditions on the Accuracy of Orifice Meters",SPE 1993

Ifft. 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,

1994

Ifft S Mccrometer Wet Gas Meter Testing NSFMW Kristiansand Norway 1997

Van-Mannen. H.Cost Reduction - Wet-Gas Measm’t Using the Tracer-Venturi Combination”, NEL oneday seminar, 1999

De 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 delRio, 2003John Amdal, Harald Danielson, Eivind Dykesteen, Dag Flølo, Jens Grendstad, Hans Olav Hide, Håkon Moestue,

Bernt Helge Torkildsen, “Handbook of Multiphase Metering”The Norwegian Society for Oil and Gas Measurement.

Lawrence PA & Steven R “Research Developments In Wet Gas Metering with V-Cone Meters” NSFMW 2003

Kinney J ISHM Class # 1320 Wet Gas Measurement ISHM O.K. USA 2006

ISO TC 193 WG 1.0 Allocation Metering in the Upstream Area (white paper) 2006

Steven R A Discussion on Horizontal Wet Gas D.P.Flow Meters St Andrews Scotland UK…..NSFMW 2007

Lawrence PA Wet gas Measurement ISHM Class 2007 #1320 2007

Wet Gas Data Release Estes Park Colorado (CEESI - Wet Gas Laboratory Nunn CO). 2007

Wet Gas test data on a 2 inch cone meter courtesy - Cameron Houston Inc - Lawrence 2009