GOOD PRACTICE GUIDE AN INTRODUCTION TO WET-GAS FLOW METERING

Transcription

1 GOOD PRACTICE GUIDE AN INTRODUCTION TO WET-GAS FLOW METERING

2 Good Practice Guide This guide provides an introduction to wet-gas metering which is aimed at people who have little experience in this area. It covers the basic concepts of characterisation and flow regimes before progressing onto the various metering options available to measure the gas and liquid components. This includes single-, two- and three-phase metering, measurement of liquid content, metering challenges and terminology used by industry. Contents Foreword 2 1. What is a wet gas? Steam flows Hydrocarbon flows 4 2 Wet gas flow patterns Horizontal flow patterns Vertical flow patterns 6 3 Measuring wet-gas flows Single phase metering options Two and three-phase metering options 7 4 Differential pressure meters Different types of differential pressure meters Correcting the response of the meter Commonly used corrections 11 for differential pressure meters 4.4 How to calculate the gas flow rate using 12 a differential pressure meter 4.5 Practical considerations Installations and effects Pressure tappings 14 5 Non-differential pressure flow meters 15 6 Measurement of liquid content Test separator Sampling Tracer method Microwave technology Pressure loss ratio method 18 using differential pressure meters 6.6 Advanced signal processing 20 7 Two and three-phase wet-gas meters 20 8 Issues and challenges with wet-gas metering 22 9 Summary References 24 Annex 1: Understanding the terminology used in 24 wet-gas flow measurement Annex 2: Nomenclature and definitions 26 1

3 An Introduction to Wet Gas Flow Metering Foreword This good practise guide is aimed at people who are inexperienced in the flow measurement of wet gases but who would like to advance their knowledge and understanding. For those not familiar with wet gases it can be rather daunting to first approach the subject because much of the available literature is normally aimed at people with some experience. Wet-gas flow measurement can be more difficult to comprehend due to the complexities of a combined flow of a compressible fluid (gas) and a non-compressible fluid (liquid). This makes the subject slightly more difficult to grasp than the measurement of single phase flows of just liquid or gas. The guide provides initial direction and help on what you need to consider and where to start when first faced with the prospect of wet-gas metering. It should enable the reader to be more confident and equipped to understand the terminology used along with the metering principles that are commonly encountered, before moving on to more advanced information. Common examples of wet-gas flows that are metered are in the extraction of natural gas (in the oil and gas industry) and saturated steam lines - which are commonly encountered in a wide variety of industries. It is important to be able to measure wet-gas flows to quantify products, reduce costs and optimise the management of systems and resources. An understanding of wet-gas metering principles can help enable this. Reading this guide should enable the reader to: understand the terminology used in the area understand some of the wet-gas metering principles identify what metering technology is needed for their application make informed decisions on wet-gas metering deal with suppliers of wet-gas metering technology Although the document is written for those who have some basic understanding and experience with flow metering, this is not totally necessary as this document links in with other introductory guides to flow metering to cover the necessary background. As this is an introductory guide some of the more complex terminology used in wet-gas flow measurement has not been fully covered. However, for reference a section has been included at the end of this guide which contains explanations and definitions of the terminology commonly encountered in this area. The reader should feel more comfortable and equipped to move on to more in-depth information on wet-gas flows after reading this document, while the reference section provided will be beneficial to understand more advanced information. 2

4 Good Practice Guide 1. What is a wet gas? This at first may seem a straight forward question but in fact there has been some debate as to its actual definition [1]. In simple terms it can be described as a gas with a small amount of liquid present. In most cases people are mainly interested in knowing the amount of gas flowing rather than liquid. This depends though on the potential monetary value represented by the type of liquid present, e.g. gas condensate. There is no quantitative definition of a wet gas flow that is universally accepted. People have interpreted the definition ranging from a humid gas (i.e. gas saturated with liquid vapour) to multiphase flows with a gas volume fraction (volume of gas to the total volume of gas+liquid) of 90% or higher. However, since the gas volume fraction is based on the volumetric flow rates of the liquid and gas phases at actual conditions, no account has been made of the gas and liquid densities. Liquids are considered as incompressible fluids and so the density does not tend to change with a change in pressure. Gas on the other hand is a compressible fluid and the density changes significantly with pressure. If the pressure of a system increases, the gas density increases but the liquid density will not change. The fluid densities are an important consideration in flow measurement as they relate to the actual mass quantities of the fluids present. To account for both the flow rates and densities of the liquid and gas phases it is common practice to define the wetness or liquid loading of the gas using the Lockhart-Martinelli parameter, referred to as X. This parameter can be calculated from the mass or volumetric flow rates and the density of the fluids as follows [1]: 3

5 An Introduction to Wet Gas Flow Metering 1. What is a wet gas? cont. The Lockhart-Martinelli parameter can also be expressed in terms of the gas and liquid densiometric Froude number; this is a dimensionless number used to express the liquid or gas phase velocity. It is common (and sometimes confusing) to find different expressions of the Lockhart-Martinelli parameter in different publications. Care should be taken as some older publications use different definitions for the Lockhart-Martinelli parameter. Reference [1] provides information on the definitions for wet-gas flow. The Lockhart-Martinelli parameter is used to define a wet-gas flow with the value of X between zero (i.e. completely dry gas) and about 0.3. Flows with a Lockhart-Martinelli parameter above 0.3 are usually referred to as multiphase flows. 1.1 Steam flows Steam, when it is saturated and has water present as a liquid, can be defined as a wet gas. In this case the gas component is steam and the liquid is very hot water. Huge amounts of steam are routinely produced by industry in general and it has been estimated that approximately 50% of the energy consumed by industry is for the generation of steam. Therefore, the ability to accurately measure the amount of steam can be extremely important to account for costs. For this reason a comprehensive review of steam flow metering technology has been conducted separately and is available from TUV NEL. 1.2 Hydrocarbon flows Within the oil and gas industry wet-gas flows are commonly encountered, for example, when gas is extracted from reservoirs where it can contain some liquid, or when extracted dry gas undergoes a change in pressure and temperature, say across a choke valve, and liquid subsequently condenses out. This is only one example but there are many other situations where the measurement of wet gas is important. Within this industry the liquid component can be any combination of water and liquid hydrocarbon. The liquid fraction of the total hydrocarbon flow is typically a low molecular weight hydrocarbon referred to as the gas condensate. 2 SI after the French le Systēm International d Unitės, or the International System. A system based on a particular choice of metric units from which all others can be derived. 4

6 Good Practice Guide 1.2 Hydrocarbon flows cont. The hydrocarbon present in the liquid phase depends on the local temperature and pressure conditions. The system conditions could either change or be such as to enable condensation of liquid from its vapour hydrocarbon form. As the temperature and/or the pressure changes, then liquid may form from the gas phase. The presence of the liquid can cause problems and errors in the ability to accurately meter the gas phase flow rate. Changes in the system conditions are common, for example, when a gas is transported from a reservoir at high temperature and pressure to where it is brought ashore. It is common practice to define the amount of water in the liquid phase as a percentage known as the water cut. This liquid phase may have a water cut anywhere between 0% and 100%. 2. Gas flow pattern To accurately meter wet-gas flows, it is advisable to understand how the liquid and gas phases are distributed within a pipe as this can affect the response of the measuring equipment. For example, the liquid can be flowing along the bottom of the pipe or be dispersed as droplets in the gas phase. The distribution of the liquid and gas phases within a system are classified by so-called flow patterns ; these are illustrated below. 2.1 Horizontal flow patterns In horizontal pipes several flow patterns are observed: Stratified flow here the liquid flows along the bottom of the pipe and the less dense gas occupies the upper part of the pipe. Stratified-Wavy this is basically stratified flow with a wavy gas-liquid interface as shown below. Transitional this is the flow pattern observed when the gas velocity increases and begins to lift liquid from the stratified layer into the gas stream. This pattern occurs as a transition between the stratified-wavy flow and annular flow pattern, which is described below. Annular - the liquid flows as a film on the pipe walls with the gas flowing inside the liquid forming a central core. In horizontal pipes, the effect of gravity will tend to ensure that more liquid is at the bottom of the pipe than at the top. 5

7 An Introduction to Wet Gas Flow Metering 2.1 Horizontal flow patterns cont. Annular-mist this pattern occurs as the gas velocity increases and picks up some of the liquid into the gas core as droplets or mist. 2.2 Vertical flow patterns In vertical pipes the main flow patterns observed are annular flow and annular-mist flow for wet-gas conditions. 3. Measuring wet-gas flows Flow direction Knowing what measurements you want will help dictate the type of metering technology that is required. What measurements are needed or important? Gas flow rate only? Gas + liquid flow rate? Gas + liquid hydrocarbon + water flow rates? Single-phase meter } Wet gas metering options Two-phase meter Which one? Three-phase meter 6

8 Good Practice Guide 3.1 Single-phase metering options This option allows for the measurement of the gas flow rate only, but the effect of the liquid on the meter response should be accounted for. The required uncertainty of measurement can be a significant factor when determining whether or not to correct for the liquid presence. It may be that the low liquid content and/or low financial value of the liquid means that only the gas measurement is important. Single-phase meters can generally be divided into those using differential pressure techniques and non-differential pressure techniques. 3.2 Two- and three-phase metering options Two- and three-phase meters provide information on the gas and total liquid flow rates or the gas, liquid hydrocarbon and water flow rates. The metering principles of these types of meters are covered in Section Differential pressure (DP) meters Differential pressure (DP) meters are one of the most commonly used single-phase meter types available for wet-gas flow measurement. If you are unfamiliar with differential pressure meters then it may be advisable to first read the introductory guide to differential pressure meters so that you can fully understand their use in single-phase conditions. This guide is available from TUV NEL. When a differential pressure flowmeter is used in wet-gas conditions the meter tends to over-read the amount of gas passing through it. This means that the estimated quantity of gas determined by the flow meter is higher than the actual amount passing through it. Therefore the meter response must be corrected to provide the actual gas mass flow rate. The over-reading is defined as the uncorrected gas mass flow rate measured in wet-gas conditions, divided by the actual gas mass flow rate that would be obtained if the gas flowed alone in the pipe. Over-reading = gas mass flowrate measured in wet -gas conditions gas mass flowrate measured in dry -gas conditions When using the equation to calculate the gas mass flow rate the over-reading simplifies down to approximately the root of the differential pressure measured in wet-gas conditions divided by that measured in dry-gas conditions. 7

9 An Introduction to Wet Gas Flow Metering 4.1 Different types of differential pressure meters Meters commonly used are: Venturi tubes V-cones or cone-type meters Orifice plates Information on using differential pressure meters is available from the introductory guide to differential pressure meters by TUV NEL. Venturi tube V-cone meter Orifice plate fitted into pipe 8

10 Good Practice Guide 4.1 Different types of differential-pressure meters cont. The amount of liquid present can have a different effect on the over-reading response of different differential-pressure meters; for example the over-reading response for a V-cone may be different to that for a Venturi meter with the same amount of liquid present at identical flow conditions. 4.2 Correcting the response of the meter The response of each meter must be corrected for the presence of the liquid otherwise significant errors in the measurement of the gas flow rate can occur. For example, errors of up to 60% and more can occur in the gas flow rate depending on the meter type used, local flow conditions and liquid content. Serious mis-measurement issues can result from inadequate corrections for the presence of liquids. The response of differential-pressure meters are usually presented as a graph showing the over-reading as a function of the liquid content expressed as the Lockhart-Martinelli parameter, X. The graph below shows what the over-reading for a differential-pressure meter could look like. It can be seen that the meter over-reading increases with increasing liquid content. Illustration of the over-reading response for a differential pressure meter in wet-gas conditions, the liquid content is expressed by the Lockhart-Martinelli parameter. It should be noted that the shape of the response can be non-linear and is generally different for each type of meter. The over-reading response of a flow meter is dependent on the wet-gas flow conditions and can be affected by the: gas velocity (via the gas densiometric Froude number) flow meter diameter ratio or beta value 1 gas density gas-liquid density ratio liquid phase properties (e.g. density, interfacial tension and viscosity) 9 1 The diameter ratio (sometimes called beta or beta ratio) is the ratio between the minimum cross section at the restriction, d, and the pipe diameter, D..

11 An Introduction to Wet Gas Flow Metering 4.2 Correcting the response of the meter cont. As an example the graph below shows the actual over-reading response for a Venturi tube of beta 0.4. In this example the over-reading decreases with an increase in the gas pressure from 15 bar gauge up to 60 bar gauge. It is worth remembering that the gas density is directly related to the pressure, therefore as the pressure increases then the gas density is also increased. OR vs X (HP) barg 30 barg 15 barg Venturi Meter Over-Reading (-) Lockhart-Martinelli Parameter (-) Venturi meter (β = 0.4) over-reading as a function of the Lockhart-Martinelli parameter (expresses the liquid fraction) at gas pressures of 15, 30 and 60 barg. This example illustrates the effect that the flow conditions can have on the response of the meter. For example, if the response of the meter (i.e. the differential pressure measurement) is not corrected to account for the presence of the liquid this can cause an error in the gas flow measurement of ~60% at a pressure of 15 bar and Lockhart-Martinelli parameter of approximately 0.3. This highlights the importance of correcting for the presence of the liquid. The reader should be aware that the measurements from differential pressure meters can be affected by a number of parameters such as: Geometry Gas velocity Flow pattern Pressure Temperature Liquid viscosity (gas viscosity not that important) Liquid surface tension 10

12 Good Practice Guide 4.3 Commonly used corrections for differential pressure meters Corrections or correlations that account for the presence of liquid for Venturi tubes and orifice plates are widely available. The correlations are used to determine the meter over-reading (via knowledge of X) and then determine the actual gas mass flow rate. The corrections that have been commonly used by industry are: Murdock equation [2,3] Chisholm equation [4] } Orifice plates de Leeuw correlation (modified Chisholm correlation) [5] Venturi tubes Correlations have been published and are available for V-cone meters but as these were proprietary flow meters there has been less independent research performed and no standards are available as to their use, even in single phase conditions. In general the over-reading response of V-cones in wet-gas conditions is usually less than that observed for Venturi tubes; because of this property V-cone meters have proved very popular for wet-gas metering. Previous research performed on the effect of Venturi tubes and V-cones in wet gas conditions are available from TUV NEL. A report titled The evaluation of dry gas meters in wet gas conditions provides in-depth information on the performance of these meters. Care should always be taken when using a correlation. If it is applied outside the range over which it was obtained then large measurement errors can occur. For example, the de Leeuw correlation was derived from data using a 4-inch Venturi tube with a beta of 0.4, however it is now known that beta affects the over-reading in wet gas conditions [6]. Errors of up to 12% in the gas mass flow rate are known to occur if applying this correlation to larger beta ratios [7]. However, even knowing this there may have been no other choice available to industry but to use the available correlations and increase the uncertainty of the value of the gas mass flow rate. TUV NEL have recently derived a new correlation for Venturi tubes that takes into account a greater range of parameters than have been available up to now [7]. This new correlation covers the following: nominal pipe diameters from 2-inch to 10-inch (50 mm to 250 mm) beta 0.4 to 0.75 gas phases of o steam o hydrocarbon liquid phases of o hydrocarbon o water o very hot water, i.e. from steam (different surface tension from cold water this appears to have an effect on the meter response) Wet-gas correlations used to correct the gas flow to account for the error induced by the presence of liquid provide an uncertainty of approximately ± 2% for the gas flow using orifices plates and approximately ± 3% for the gas flow using a Venturi tube. A modified Chisholm correlation is available for orifice plates in wet gas flows [8]. 11

13 An Introduction to Wet Gas Flow Metering 4.4 How to calculate the gas flow rate using a differential pressure meter Once you have your differential pressure measurement taken in wet-gas flow conditions you will then need a measurement of the liquid flow rate. Techniques to measure the liquid flow rate are summarised in Section 6. First, calculate the Lockhart-Martinelli parameter, this requires information on the: gas flow rate (can estimate at first from the wet-gas differential pressure measurement) liquid flow rate liquid density gas density Then use an appropriate wet-gas correlation to relate the Lockhart-Martinelli parameter to the over-reading in the differential pressure. The over-reading is used to calculate the mass flow of the gas as if it was dry. An estimated value of the dry gas flow rate is first used and then an iterative calculation procedure is applied until the estimated input value of the dry gas flow rate (used to calculate the Lockhart-Martinelli parameter) is within an acceptable convergence range with the output value. Usually the computation method is programmed into a flow computer to automatically calculate the actual dry-gas flow rate. The liquid flow rate, gas and liquid densities are usually entered into the computer. Gas and liquid densities can be determined from sampling the flows and subsequent analysis of the fluids. Iterative procedure to calculate the actual gas flow rate in wet-gas conditions 12

14 Good Practice Guide 4.5 Practical considerations to wet-gas metering using differential pressure devices Venturi tubes are commonly selected instead of orifice plates to meter wet-gas flows as they are considered to be much more durable, more resistant to erosion and can withstand higher differential pressures without incurring damage to the device. Orifice plates, when used for wet-gas flow measurement, should ideally be easily accessible and checked regularly for damage or erosion as this affects the accuracy of the flow measurement. Orifice plates are mainly used for topside metering applications. Upstream face of orifice plate Downstream face of orifice plate Orifice plates can be damaged by slugs of liquid impacting on their surface and bending the plate, and this can affect the flow measurement. It should be noted that the use of thicker orifice plates can withstand higher differential pressures and the impact force from liquid slugs. The maximum plate thickness permitted by the standard ISO is 0.05 times the pipe diameter, this is a plate thickness of 5 mm for a nominal four-inch pipe. For pipe diameters between 50 mm and 64 mm a plate thickness of up to 3.2 mm is allowed Installation effects It is recommended to install Venturi tubes and orifice plates in a horizontal position as any liquids which collect in the impulse lines from Verturi tubes installed in a vertical orientation can affect the flow measurement. 2 ISO to 4 is the international standard covering the Measurement of fluid flow by means of pressure differential devices inserted in circular cross-section conduits running full. This document provides 13 information on how the flow in full pipes should be measured to ensure measurement consistency across industries. It includes information on orifice plates and Venturi tubes to meter single phase flows of liquid and gas, such as equations to calculate the flow, tolerance of manufacture of the meter, uncertainty of flow measurement and installation requirement etc.

15 An Introduction to Wet Gas Flow Metering Installation effects cont. The straight pipe length upstream of the meter is recommended to be as long as possible to minimise the flow measurement uncertainty. For more information on installation effects in single-phase metering please refer to the introductory guide on installation effects (available from TUV NEL). The reduced pipe lengths that have been recommended for dry gases are not recommended for wet gas conditions. This is to ensure the fluids have settled into their natural flow regime at the meter. Correlations to correct for the meter overreading have assumed no flow disturbances upstream of the meter to change the flow regime Pressure tappings The pressure tappings are the holes machined through the pipe wall, flange or meter that allow the pressure to be measured by a suitable sensor (see the diagram below). The tube connecting the pressure tapping to the pressure sensor is referred to as the impulse line. A report on impulse lines for differential pressure flowmeters is available from TUV NEL. Pressure tapping and impulse line connection to a pressure sensor to measure the pressure within the pipe Some general guidance and good practice on how to obtain differential pressure measurements in wet-gas conditions are summarised below. The quality of your flow measurement is very much dependent on the quality of the differential pressure measurement. Natural gas flows The pressure tappings should be at the top of the pipe to ensure that liquids trapped in the impulse line can drain back into the pipe. The temperature of the gas will tend towards ambient once it leaves the main pipe the drop in temperature can cause condensation of the gas to liquid. The impulse lines should be kept as short as possible to limit temperature drop. 14

16 Good Practice Guide Pressure tappings cont. Trace heating can be applied to the impulse lines to prevent hydrate formation 3 in natural gas pipelines as the drop in temperature of the gas as it moves away from the main pipe can cause hydrates to form and block the impulse line, thus providing inaccurate pressure measurements. The heating can also limit the formation of liquid in the impulse line. Trace heating or insulation can be used around the pipe walls to prevent hydrate formation and reduce or eliminate the potential condensation of liquids from a reduction in temperature. This may even be sufficient in some cases to eliminate the need for wet-gas flow measurement entirely if the temperature is maintained such that no condensation occurs and the fluid is completely in the gas phase. Pipework upstream of differential pressure meters should be designed such that bends or other installations upstream of the meter encourage any stratified or flowing liquid to flow at the bottom of the pipe. This is recommended as the correlations available to correct the meter over-reading were derived from the fluids flowing in a stratified flow regime. Steam flows For the metering of steam the pressure tapping should be horizontal and the impulse line should be sloping downwards. This arrangement is to encourage condensation of the fluid in the impulse line so that the pressure sensor is exposed to colder water as high temperature steam can damage the pressure sensors. The impulse lines can be filled with water prior to exposure to line conditions to ensure no damage to the sensors by the steam. 5. Non-differential pressure flow meters Although differential pressure flow meters are commonly selected for wet-gas measurement there are other metering options available. In some cases a meter may have been installed to meter dry gas but for various reasons there is some liquid present within the gas flow. Therefore knowledge of the effect of the liquid presence on the meter is required. A brief summary of the known effects on other single phase meters exposed to wet-gas conditions is provided below. Turbine meters should ideally never be used to meter wet gas as the meter can be damaged and the meter response is unpredictable Hydrates are solid crystalline structures which can form in natural gas and water mixtures under certain pressure and temperature combinations. This is covered in Section 8.1.

17 An Introduction to Wet Gas Flow Metering 5. Non-differential pressure flow meters cont. d Ultrasonic meters will always over-read the gas flow rate and the presence of the liquid can affect the proper functioning of the meter by blocking transducers etc. Have been successful when the presence of liquid is very low [9]. Sound pulses are passed back and forth between the transducers one upstream and one downstream. A sound pulse travelling against the flow direction takes longer to travel the intervening distance than a sound pulse travelling in the direction of flow. The difference in the time taken is proportional to the flow velocity. Vortex meters will always over-read the gas flow rate and the liquid present can affect the function of the meter, depending on the design. The principle of operation of a vortex meter: as the fluid flows past a block or obstruction in the flow, vortices are generated at a frequency proportional to the fluid velocity. Coriolis meters can have an unpredictable behaviour in wet gas conditions but there is current research into their use in this area [10]. With a Coriolis meter the fluid is directed through a vibrating flow tube, Coriolis forces exerted by the moving fluid cause the tube to twist. The amplitude of the twist is related directly to the mass flow rate. More information on the effect of wet-gas conditions on single phase meters can be obtained from the TUV NEL report The evaluation of dry gas meters in wet gas conditions. 16

18 Good Practice Guide 6. Measurement of the liquid content Separate liquid measurement is important and necessary for use with single-phase meters to correct for the presence of the liquid. There are a number of techniques available for measuring the liquid content, these include: Test separator Sampling Tracer Microwave technology (water specific) Overall pressure loss across differential pressure meters Infrared Advanced signal processing In the majority of these methods it is usually assumed that the liquid flow rate is constant between consecutive measurements, the timing of which can vary by months. Each method is briefly explained below. 6.1 Test separator This is the conventional approach to determine the individual phase flow rates and involves the physical separation of the liquid from the gas, with each phase then metered separately. This method provides flow rate information on all phases present and can be used to check the performance of a wet-gas flow meter. Validation of a wet-gas meter using a test separator The pressure and temperature of the fluids at the test separator may be different to that at the flow meter. If this is true then the gas and liquid flow rates must be corrected to the conditions at the meter to account for possible phase changes and/or mass transfer between the liquid and gas phases. Another issue to consider is that the separation will very likely not be 100% efficient and there may be liquid carry-over into the gas stream and gas carry-under into the liquid stream(s). 17

19 An Introduction to Wet Gas Flow Metering 6.2 Sampling Sampling is where a physical wet-gas sample is removed from the pipeline for analysis. There are various commercial wetgas sampling systems available. Challenges with this technique: ensuring a sample is collected that is representative of both the gas and liquid phase fractions ensuring no mass transfer occurs between the liquid and gas during sampling. Schematic of flow sampling 6.3 Tracer method This technique involves the injection of tracer dyes into the flow and then a sample is taken at a specified distance downstream of the injection point to measure the dilution of the tracer(s). The concentration/dilution of the tracer in the liquid phase is used to calculate the liquid flow rate. Tracers are selective to oil and water phases and the samples do not have to be representative of the actual volume fractions of the various phases existing in the main pipeline. The technique itself can be rather cumbersome to perform and it can be difficult to get to the right point to conduct the test, access issues etc. 6.4 Microwave technology Microwave techniques can be used to detect the overall water fraction (in both the liquid and gas phases). The technique exploits the much higher permittivity of water than hydrocarbons. As the technique only detects and measures the water component then the liquid hydrocarbon fraction must be determined by another method, usually by Pressure-Volume-Temperature (PVT) calculations, which calculate the fraction of the hydrocarbon present in both the gas and liquid phases. Several manufacturers of wet-gas meters have incorporated microwave technology into their meters. 6.5 Pressure-loss ratio method using differential pressure meters The pressure drop across the primary measurement section of a Venturi tube is partly recovered downstream of the meter. In dry gas conditions the recovery is around 80% to 95%, however in wet gas conditions the liquid presence produces a smaller pressure recovery and this difference can be exploited to provide a measure of the liquid fraction. The method involves using an additional pressure tapping downstream of the Venturi tube to provide a measure of the overall pressure loss, Δp2, as shown in the schematic below. 18

20 Good Practice Guide 6.5 Pressure-loss ratio method using differential pressure meters cont. Venturi tube illustrating overall pressure loss (Δp2) and the differential pressure (Δp1) used to calculate the pressure loss ratio (Δp2/Δp1) The pressure loss ratio (Δp2/Δp1) correlates with the liquid content and is most sensitive at low liquid loading (i.e. low values of Lockhart-Martinelli parameter) At low liquid loading the pressure loss ratio method can be used with orifice plates and Venturi tubes to calculate the Lockhart-Martinelli parameter. Its use is limited to calculating values of the Lockhart-Martinelli parameter up to maximum values of approximately It should be noted that the method is known to be affected by the system pressure (gasliquid density ratio), gas velocity and beta value. The graph below illustrates the relationship between the pressure loss ratio and the Lockhart-Martinelli parameter. PLR vs X (LP) Pressure Loss Ratio (-) gas pressure 15 barg 0.1 gas pressure 50 barg Lockhart-Martinelli Parameter (-) TUV NEL has derived equations to use the pressure loss ratio with Venturi tubes to calculate the Lockhart-Martinelli parameter [7]. 19

21 An Introduction to Wet Gas Flow Metering 6.5 Pressure-loss ratio method using differential pressure meters cont. The pressure loss ratio is used within some commercial wet-gas meters to calculate the liquid content at low liquid loading. The method is particularly useful to monitor changes in the liquid fraction when using a flow meter and can be used to detect if liquid is present within a gas stream. 6.6 Advanced signal processing This is basically where the liquid has an effect on the measured variables, for example, pressure fluctuations in the differential pressure measurement of DP meters, or the shift in the speed-of-sound in ultrasonic meters. Complex analysis and recognition of patterns has been used in various wet-gas flow meters to provide extra information and to help in determining the liquid and gas flow rates. 7. Two and three-phase commercial wet-gas meters There are various meters marketed specifically for wet-gas flow measurement to meter both the liquid and the gas flow rates directly. Most of the available meters use some sort of differential pressure device and may incorporate additional metering techniques and other technologies to determine the water and liquid hydrocarbon fractions. Some of the operating principles of wet-gas meters are summarised here to provide a basic understanding of how they determine the gas and liquid flow rates. One of the principles used to measure both the liquid and gas flows is to use two differential pressure devices in series, which provide the same flow rate for dry gas but each device has a different over-reading response when liquid is present. The difference in over-reading response is exploited and correlations are then applied to the data to determine both the gas and liquid flow rates. 20

22 Good Practice Guide 7. Two and three-phase commercial wet-gas meters cont. Some wet-gas meters use one differential pressure device in series with another non-differential pressure meter (e.g. a clamp-on sonar-based meter) and use the difference in the meter responses to the local wet-gas flow conditions to estimate the individual phase flow rates. Other meters use partial separation systems to meter the separate streams of liquid and gas. These types of meter are generally based around existing multiphase meter designs and are larger, more expensive and more complex systems. Pressure loss measurements are used in some of the meters to determine the liquid content at low liquid loadings. Once the liquid and gas fractions have been determined via the various metering technologies, many wet-gas meters then use Pressure-Volume-Temperature (PVT) models to calculate the total fraction of hydrocarbons present in both the gas and liquid phases. Using the above the water-liquid ratio of the liquid phase can then be determined. It should be noted that while many of the single-phase meters used for measuring wet-gas flows are recommended to be installed in a horizontal position, the majority of the two and three-phase wet gas flow meters are recommended to be installed in a vertical position. This is to force the multiphase flow into a more symmetrical flow pattern type such that the ability of the particular metering technology in use is enhanced. Horizontal installation is recommended for differential pressure meters to ensure the impulse lines do not fill with liquids. Other techniques incorporated into commercial wet-gas flow meters used to calculate the water fraction are: Microwave technology Gamma ray Infrared technology Other wet gas metering principles used include: advanced signal processing neutral network interpretation - meter trained to predict individual phase flow rates 3D broadband radio frequency systems to image the flow sonar sensors to measure the speed of turbulent eddies generated in the wet-gas flow vortex meter in combination with a differential pressure device 21

23 An Introduction to Wet Gas Flow Metering 8. Issues and challenges with wet-gas metering A useful paper which covers the real world practicalities of wet-gas metering was provided by Stobie [9] at a previous TUV NEL Wet Gas Flow Measurement Seminar. This included information on different commercial meters available as well as useful advice on the issues likely to be encountered. 8.1 Hydrates Hydrates are solid crystalline structures which can form in natural gas and water mixtures under certain pressure and temperature combinations. The formation and build-up of hydrates within pipes can cause measurement errors, damage equipment or even block an entire pipeline (see image below). Operators of natural gas systems are very keen to detect if water is present so that they can prevent the formation of hydrates before any problems can occur. Hydrate inhibitors such as methanol can be added to prevent their formation. Hydrate blockage in a section of pipe [11] 8.2 Flow conditioners Flow conditioners are commonly used upstream of gas and liquid flow meters to correct asymmetrical flow profiles, reduce swirl and to reduce the recommended upstream pipe length before a flow meter while maintaining flow measurement accuracy. However, the use of flow conditioners is not recommended for wet-gas conditions. Hydrates can form in these flow conditions and block them. Also liquids can build up in front of flow conditioners and result in a skewed flow profile, which can affect the flow measurement. Zanker flow conditioner plate 22

24 Good Practice Guide 9. Summary Wet-gas flow measurement is significantly more complicated than measuring the single phase flow of dry gas. The presence of the liquid changes the response of dry-gas flow meters. Therefore the meter response must be corrected to provide the actual dry-gas flow rate. Separate measurement of the liquid flow rate is necessary to calculate the actual dry-gas flow rate. Differential pressure meters are the most commonly used single-phase meter type to measure wet gas flow. The DP meter will over-read in wet gas conditions. Use a wet-gas correlation to correct the meter response and obtain the actual dry-gas flow rate. Knowledge of the liquid flow rate is required for the correlation. Over-reading response (no units) Over-reading Specific commercial wet-gas flow meters are available to. Simultaneously measure both the gas and liquid flow rates or Measure the gas flow rate, water flow rate and hydrocarbon liquid flow rate in the stream. G a s L iq u id L iq u id h y d r o c a r b o n W a te r You may find the list of definitions at the end of this document particularly helpful in understanding the terminology commonly used in wet-gas flow measurement 23

25 Good Practice Guide 10. References [1] Hall, A.,Griffin, D., Steven, R. A discussion on wet gas flow parameter definitions, In Proc. of 25th North Sea Flow Measurement Workshop, October [2] Murdock, J. W. Two-Phase Flow Measurements with Orifices, Journal of Basic Engineering, Vol 84, pp , [3] Chisholm, D. Flow of Incompressible Two-Phase Mixtures through Sharp-Edged Orifices, Journal of Mechanical Engineering Science, Vol 9, No. 1, [4] Chisholm, D. Research Note: Two-Phase Flow through Sharp-Edged Orifices, Journal of Mechanical Engineering Science, Vol 19, No. 3, [5] De Leeuw, R. Liquid Correction of Venturi Meter Readings in Wet-Gas Flow, in Proc. of 15th North Sea Flow Measurement Workshop, Norway, paper 21, October [6] Stewart, D. G. Application of Differential Pressure Meters to Wet Gas Flow, in Proc. of 2nd South East Asia Hydrocarbon Flow Measurement Workshop, March [7] Reader-Harris, M. J., Graham, E. M. An improved model for Venturi-tube over-reading in wet gas, in Proc. of 27th North Sea Flow Measurement Workshop, October [8] Steven, R., Stobie, G., Hall, A. Further evaluation of the performance of horizontally installed orifice plate and cone differential pressure meters with wet gas flows in Proc. of 7th South East Asia Hydrocarbon Flow Measurement Workshop, March [9] Stobie, G. J. The Conocophillips perspective on wet gas metering, In Proc. of NEL Wet Gas Flow Measurement Seminar, September [10] Lansangan, R., Skinner, J., Reese, M., Toro, A. D., Tombs, M., Duta, M., Zhou, F., Henry, M. Coriolis mass flow metering for wet gas, Measurement and Control, Vol 41/7, September 2008 [11] ASME MFC-19G-2008 Technical Report, Wet gas flowmetering guidelines Annex 1: Understanding the terminology used in wet-gas flow measurement Basic Definitions Fluid - A substance readily assuming the shape of the container in which it is placed. Gas - Hydrocarbons in the gaseous state at ambient temperature and pressure. Oil - Hydrocarbons in the liquid state at ambient temperature and pressure. Phase - Within the bounds of wet gas or multiphase flow, the term refers to either oil, gas or water flows in a mixture of any number of the three. Multiphase flow - Two or more phases flowing simultaneously in a conduit. Emulsion - Colloidal mixture of two immiscible flows; one fluid dispersed in the form of droplets (dispersed phase) within the other (continuous) phase. 24

26 An Introduction to Wet Gas Flow Metering Annex 1: Understanding the terminology used in wet-gas flow measurement cont. Classifications for Wet Gas Flow Flow regime - The physical geometry exhibited by a wet gas or multiphase flow in a conduit, for example, stratified water/ gas flow liquid flowing at the bottom of the conduit with the gas flowing above it (not usually at the same actual velocity). Homogeneous flow - A wet gas or multiphase flow in which all the phases are evenly distributed over the cross-section of a closed conduit. Note: the composition is the same at all points. Measurable Quantities Mass flow rate - The mass of fluid flowing through a cross-section of a conduit per unit time. Volume flow rate - The volume of fluid flowing through a cross-section of a conduit per unit time. Phase flow rate - The amount of one phase of a multiphase flow flowing through a cross-section of a conduit per unit time. Note the phase flow rate may be specified as being either mass or volume flow rate. Multiphase flow rate - The total amount of the two or three phases of a multiphase flow flowing through a cross-section of a conduit per unit time. Note: this may be specified as being either mass or volume flow rate. Phase velocity - The velocity of one phase of a multiphase flow at a cross-section of a conduit. Multiphase velocity - The flow velocity of a multiphase flow at a cross-section of a conduit. Superficial phase velocity - The flow velocity a single phase of a multiphase flow would have, assuming that it occupies the whole conduit itself. Slip - Term used to describe the flow conditions that exist when the phases have different velocities at a cross-section of a conduit. Slip ratio - The ratio between two phase velocities. Slip velocity - The phase velocity difference between two phases. Velocity profile - The mean velocity distribution of a fluid at a cross-section of a conduit. Phase area fraction - The cross-sectional area locally occupied by one of the phases of a multiphase flow, relative to the cross-sectional area of the conduit at the same local position. Note: this may be also referred to as hold-up. (hold-up generally applies to liquid area fraction only) Phase mass fraction - The mass flow rate of one of the phases of a multiphase flow, relative to the total multiphase mass flow rate. Phase volume fraction - The volume flow rate of one of the phases of a multiphase flow, relative to the total multiphase volume flow rate. Void fraction - The cross-sectional area locally occupied by the gaseous phase of a multiphase flow, relative to the crosssectional area of the conduit at the same local position. Gas-liquid ratio (GLR) - The gas volume flow rate, relative to the total liquid volume flow rate at standard temperature and pressure (s.t.p). Gas-oil ratio (GOR) - The gas volume flow rate, relative to the oil volume flow rate at s.t.p. Gas volume fraction (GVF) - The gas volume flow rate, relative to the total multiphase volume flow rate, at the local temperature and pressure. Note: this is normally expressed as a percentage. Water cut (WC) - The water volume flow rate, relative to the total liquid volume flow rate at s.t.p. Note: this is normally expressed as a percentage. Water-in-liquid ratio (WLR) - The water volume flow rate, relative to the total liquid volume flow rate at local temperature and pressure.. Note: this is normally expressed as a percentage. 25

27 Good Practice Guide Annex 2: Nomenclature and definitions m g Gas Mass Flow rate [kg/s] m l Liquid Mass Flow rate [kg/s] ρ g Gas Density [kg/m 3 ] ρ l Liquid Density [kg/m 3 ] v g v v l Superficial Gas Velocity [m/s] The velocity that the gas phase from a two phase flow would have if it travelled alone and completely fill the pipe. Superficial Liquid Velocity [m/s] The velocity that the liquid phase from a two phase flow would have if it travelled alone and completely fill the pipe. GVF Gas Volume Fraction [-] The ratio of gas volumetric flow rate to total volumetric flow rate. α g Void Fraction [-] The fraction of the pipe area at a given cross-section that is occupied by the gas phase. Note: this can differ significantly from the GVF if the gas and liquid velocities are different (slip flow). g Gravitational Acceleration [m/s 2 ] D Upstream Pipe Diameter [m] C d Discharge Coefficient (Venturi or other DP meter) K = g C ml X = m g d E ε ρ ρ g l Dry Gas Flow Coefficient (Venturi or other DP meter) Modified Lockhart-Martinelli parameter [-] A dimensionless number used to express liquid fraction. Fr x l g = ml = m + m g v g g D l ρ l ρ g ρ g Gas Densiometric Froude Number [-] A dimensionless number used to express gas velocity. Mass fraction of liquid in gas [-] 26

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