Multiphase Flowmeter Experience From A Research Perspective
Author(s): m. m. m. Thant D. Sharma A. A. Zulkifli
Abstract/Introduction:
The worldwide growth of multiphase flowmeter (MPFM) installations is seen to be on a rising trend with uses onshore, offshore and even in subsea development. Data from SPE 74689 shows that the growth takes on an exponential direction with up to 210 installations on topside facilities in the year 2000 and therefore this can only mean in the year 2008, this number and also its application would be far greater in field operation and future field development by oil companies. Similarly in Malaysia, there has been a growth in MPFM usage and has been operational since 1999. This paper presents the importance of three-phase flow measurement, and an overview of the status of multiphase metering technology as well as discusses in detail the performance of the measurement technologies provided by current multiphase flowmeters installed across PETRONAS based on the experiences gained in operating those multiphase flowmeters. It also briefly discusses the limitations of current measurement technologies and identifies areas where more research work may be required to improve the current multiphase measuring technologies.
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Document ID:
9BB97474
Horizontally Installed Cone Differential Pressure Meter Wet Gas Flow Performance
Author(s): Richard Steven,
Abstract/Introduction:
Cone DP meters are widely used to meter wet natural gas flows. It is therefore important to fully understand the wet gas flow response of cone DP meters. One method of metering the gas flow rate of a wet natural gas flow is to estimate the liquid flow rate (usually a mixture of hydrocarbon liquid and water) from an independent source (such as a tracer dilution technique or test separator histories) and then use a wet gas correlation to correct for a meters liquid induced gas flow rate error. It is therefore important to have a reliable cone DP meter wet gas correlation for wet natural gas flows where the liquid component is a water and light hydrocarbon liquid1 mixture.
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Document ID:
8402AF78
Combination Of Venturi And Multi Energy Gamma Ray Breaks The Extra Heavy Oil Paradigm Beyond 20 Pa.s At Line Conditions
Author(s): Ana Marin, Onerazan Bornia And Bruno Pinguet
Abstract/Introduction:
The objective is to present accurately the performance of the combination of a Venturi and multi energy gamma ray in a case study in Venezuela. The focus is on practical information, knowledge sharing to overcome all classical problems due to fluid behaviour met by multiphase metering device in extra heavy oil including classical separator. Heavy and Extra-Heavy Oil represent more than 50% of the total oil in place in the world, and large efforts is spent to overcome difficulties related to this kind of oil production. Venezuela has pone of the largest reserve with more than currently 3.2 trillion of oil in place. Different set of technologies and methodologies have been used to overcome the technical production and monitoring challenges in these lifted or pumped wells. Petroleos de Venezuela (PDVSA) at the opposite of Canadian companies is currently using cold production techniques due to historical reasons. Recently, Orocual field in Monagas Northern (Venezuela) put in production a cluster with Extra Heavy Oil reaching gravity from 8.6 to 11 API and with a viscosity range from 6,000 cP to more than 20,000 cP at line conditions. As per fact, this new production cluster did not have any accurate production data, and PDVSA could only use conventional storage tanks to estimate the liquid flow rate and the gas was vented and not measured. In these production conditions, no separator was able to work. However, it was essential to PDVSA in this early phase of the development to review the field performance and get access to the oil, water, and gas flow rates. In these challenging conditions, and after trying other multiphase manufacturers claiming to work in Extra Heavy Oil, PDVSA found that the only solution was the combination of a Venturi and multi energy gamma ray. The Vx technology dedicated to Heavy Oil and Extra Heavy Oil broke the extra heavy oil paradigm related to multiphase technology to measure flow rates accurately and a comparative test demonstrates when it was possible f that the overall uncertainty of the entire system (Venturi-Tank) was better than 2-4%. This extended the new multiphase technology operating envelope for PDVSA from Gas to Extra Heavy Oil and provided a unique solution and the capability to monitor and optimize in real-time the field production.
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Document ID:
E38DF9B8
Calibration Of A Five Beam Ultrasonic Flowmeter For LNG At Cryogenic Temperatures
Author(s): Asaad Kenbar Peter Van Brakel Jeroen Van Klooster
Abstract/Introduction:
Liquefied Natural Gas (LNG) has traditionally been bought and sold on the basis of long term contracts, with the amount of energy transferred derived from measurements of tank volumes. However, as the contribution of LNG to global gas sales increases, it is likely that it will be increasingly traded on the basis of short-term (spot) prices in a similar way to crude oil. In such circumstances the use of flowmeters, the accepted method of measuring oil, becomes attractive for custody transfer measurement at receiving terminals. TUV NEL has conducted research to investigate the application of conventional flowmeters to LNG. This report forms part of this research work. The ultimate objective of this research work is to establish standards for cryogenic flow measurement, in particular for measurement of Liquefied Natural Gas (LNG). The aim of the work is to assist industry to establish a framework of measurement standards and capabilities. These will enable UK businesses and public authorities to make accurate flow measurements that will be accepted nationally and internationally. A comprehensive review covering LNG measurement technologies, calibrations and uncertainties has already been completed by TUV NEL 1. The review identified two types of flowmeters suitable for LNG flow measurement, namely Coriolis and ultrasonic flowmeters.
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Document ID:
73564727
The Effect Of Viscosity On Hydrocarbon Liquid Turbine Meter Measurements
Author(s): Thomas Kegel Gordon Stobie
Abstract/Introduction:
Flow measurement requires ancillary measurements to achieve uncertainty levels acceptable for custody transfer applications. Volume corrections require pressure and temperature measurements, gas volume corrections additionally require composition information. The ancillary measurements are also required to achieve the required uncertainty from the flowmeter. Gas measurement examples include the dependence of orifice meter discharge coefficient or turbine meter K Factor based on the Reynolds number. While small corrections are conventionally applied to correct liquid density for pressure (CPL) and temperature (CTL), liquid viscosity corrections are uncommon. This paper updates current understanding of the effect of viscosity on liquid measurements in four parts. The first part presents a review of viscosity fundamentals including measurement, traceability, and uncertainty. The second part presents a correlation of turbine meter performance with viscosity. The discussion begins with a methodology to identify and organize relevant variables. Calibration data are presented to illustrate the correlation and facilitate further discussion. In the third part of the paper, data of liquid viscosity are described. The discussion includes sensitivity to changes in pressure and temperature as well as the dependence on density (API gravity). Previously published, as well as new, data are included. The final part of the paper investigates the impact of viscosity on traditional calibration practices based on master meters or provers. If a meter is calibrated using product at flowing conditions the effects of viscosity are generally reduced, whilst calibration in a laboratory will generally use a different fluid. Because fluid viscosity is not generally addressed it is a parameter whose effect is often ignored.
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Document ID:
49409D58
Traceable Calibration Of Liquid Densitometers
Author(s): Norman Glen Douglas Griffin
Abstract/Introduction:
Density measurement is a key element of both mass and volume flowrate measurement in the oil industry and as such is fundamental to the commercial operation of facilities. The most widely implemented approach for mass flow measurement is to use a volumetric flowmeter and a densitometer. All flowmeters require periodic calibration traceability within the UK is provided through the National Flow Measurement Standards Facilities at TUV NEL, supported by the UK Department for Innovation, Universities and Skills (DIUS) under the Engineering and Flow Measurement Programme. All commercial densitometers also require periodic calibration and the UK regulator for petroleum measurement and allocation, part of the UKs Department of Energy and Climate Change (DECC) also identified a need for research into practical methods for in-situ calibration of densitometers, as well as a greater understanding of the effects on densitometer performance of variations in product density, pressure and temperature. This is particularly important as more and more operators are involved in smaller field developments tied back to other operators platforms, feeding third-party pipeline infrastructures. In addition, as more high-temperature, high-pressure fields come on stream, more densitometers will be operating at temperatures and pressures significantly different from those currently used as the reference conditions for calibration.
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Document ID:
B5110D79
Measurement Of Forward And Reverse Natural Gas Flows In Closed Conduits By Differential Pressure Cone Flow Meters And Ultrasonic Meters
Author(s): Larry Whitaker Philip A. Lawrence
Abstract/Introduction:
The use of differential pressure type meters to measure accurately a bi-directional gas flow in a pipeline can have major measurement uncertainty issues due to the geometric difference in the differential producer element shape when used in the reverse direction. Meter discharge coefficients may be different in these particular cases for geometric devices such as concentric,square edged and flange tapped orifice flow meters and Venturi meters. Current national and international measurement standards state that bi-directional flow measurement is not permitted using orifice plate type flow meters for a good measurement uncertainty and that meter runs dedicated for each direction must be used in this application. This paper details the recent experience and testing of differential pressure cone meters used to measure high pressure natural gas to custody transfer standards and as check meters for the CTM Gas Ultrasonic Meters (USMs) at a natural gas storage and transmission facility in New Mexico USA The cone meters mentioned in this paper were supplied for the field application, and were independently tested using High Pressure Natural Gas Product at a nationally certified test facility in the USA. The provisional testing and a feasibility study was done on smaller diameter meters with water to demonstrate and prove the application at an international certified independent laboratory in the far east. A user in-field data set comparison will be shown between the bi-directional cone meters and the bidirectional ultrasonic meters used for the custody transfer measurement on the site. The resulting test and installation data demonstrates that the use of cone meters in a bi-directional configuration works well and is a real world cost effective alternative method to an old issue. The paper will not mention any trade names and will only use generic names and terminology
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Document ID:
3DD59E03
Ultrasonic Meter Recalibration
Author(s): Gordon Stobie Angel Floyd
Abstract/Introduction:
There are a number of aspects that should be considered in the concept of USM Gas Meter Recalibration. Currently there are three schools of thought that appear to be considered in isolation of each other. These are: 1. Z Configuration, Duty - Check meter using trigger points to justify a meter recalibration. 2. A meter risk or value judgment to trigger a meter recalibration. 3. USM diagnostics to trigger a meter recalibration. Whilst the authors consider that each of the above topics have a valid basis, it is not believed that any one provides a sole basis upon which to justify a meter removal and (re)calibration, and that they should be used in combination to support (or otherwise) each other. The authors will discuss the three subjects and provide examples and an insight into the trigger points which could be adopted
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Document ID:
542482FF
Features Of Allocation Systems Incorporating Long Pipelines
Author(s): Phillip Stockton
Abstract/Introduction:
There are two main approaches to systems of allocation that include long pipelines. The first accounts for each users hydrocarbons within the pipeline itself. The second method ignores the transit time in the pipeline and allocates the metered quantities exiting the pipeline based on the metered quantities input into the pipeline on the same day using this approach parties will not be allocated precisely what they input to the pipeline on a day, but over a period of time there is an expectation that any daily gains and losses will even themselves out. This paper examines instances when this is not necessarily true depending on the allocation equations employed. It demonstrates, using simple models and results from a real allocation system, how parties can be systematically under and over allocated hydrocarbons due to the mathematics of the allocation agreement. It goes on to examine the reasons for this unexpected and subtle bias in the allocation system and presents methods to assess the stability of the equations and approaches to eliminate allocation bias. It also discusses the wider implications for allocation systems in general, particularly in terms of how the assumptions, equations and logic of a system should be tested at the conceptual development stage to prevent problems occurring. In Section 2 a simple model is used to describe an allocation system associated with a pipeline. This model illustrates the basic process and presents the main features of the allocation methodology. Data from an analogous real system is presented to highlight a problem with the allocation results of such a system. In Section 3 the model is then used to analyse the allocation system behaviour without the obfuscating effects of measurement uncertainty in the real data.
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Document ID:
0E5D8118
What Does Accuracy Mean To You?
Author(s): Raymond Kalivoda Peter Sims
Abstract/Introduction:
Accuracy! Now, more than ever accuracy is critically important to the petroleum industry. Crude oils and refined petroleum products are bought and sold on the worldwide market. They may be transported over thousands of miles and change ownership many times on their journey from the well head to the end user. Each time the product changes ownership, a custody transfer is completed and both buyer and seller expect the product to be accurately measured. In all transactions it is increasingly important to reduce measurement errors. This is especially true for large volume custody transfers by pipeline or ship where validating the degree of accuracy can be most difficult and costly. Accuracy is a seemingly easy concept but determining the precise volume measured, even with a high quality custody transfer meter, is challenging. In fact, the accuracy of a dynamic measurement can only be expressed quantitatively as an inaccuracy or uncertainly. The problem is the true value is unknown so a mathematically exact value is not possible. The measurement can only be determined as a probability within a specific range. Accuracy can be defined as the closeness in the agreement between the result of a measurement and the true value of the measurement. The quantitative expression of accuracy is in terms of uncertainty which is defined in statistical terms. The Guide to the Expression of Uncertainty in Measurement (GUM) is an international standard published by ISO that defines the quantitative aspects of accurate measurement. It allows the user to determine the degree of accuracy of a given measurement and how much each of the input factors influences it. Used in this manner, uncertainty analysis is a cost-effective way to evaluate and optimize a measurement system.
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Document ID:
06E9958C
An Investigation Into Multiphase Flow Streams Containing A Viscous Oil Component
Author(s): Christopher Mills Neil Barton, Richard Harvey, Amy Ross And Gary Miller, Andrew Parry, Cheng-Gang Xie And Bruno Pinguet
Abstract/Introduction:
Complex multiphase fluids, such as those containing viscous liquid components, arise in many industrial fields although it is within the upstream hydrocarbon production industry, in particular the growing heavy-oil sector, that most focus is being placed on their measurement. On a global basis, around seventy per-cent of the worlds remaining oil reserves are estimated to be in the heavy or extra-heavy category. That means that their density is below 22.3 API and their in-situ viscosity within the range 100 - 10000 cP. Tar sands and bitumen deposits have higher viscosities still. There is a growing need to properly quantify these high viscosity crudes, which in virtually all cases are produced and transported as complex multiphase flow streams containing gas, heavy-oil and water. In these heavier oil environments, traditional test separators can no longer provide a sufficient level of measurement accuracy, due to the higher densities and higher viscosities involved. Multiphase flow meters (MPFMs), on the other hand, have reached a level of technical development where they are regarded as acceptable alternatives to test separators in many hydrocarbon exploration and production applications and the challenge now exists to further extend their capabilities into higher-viscosity regimes. Multiphase flow meters (MPFMs) combine a number of primary sensors, which are used to measure physical parameters such as pressure, temperature, water-cut, density, and fluid velocity. For many such sensors, the output signals have a strong dependence on the structure of the flow (the flow regime), and models are required to decode and interpret the signals correctly. To date, most of the flow models used with commercial MPFMs have been developed for conventional crude-oil production applications, and hence are applicable for relatively lowviscosity liquid / gas flow regimes. As the liquid viscosity rises, the extent to which the classic flow patterns (stratified, slug, bubbly, annular etc.) change, and under what conditions, has yet to be firmly established. Consequently, the extent to which the flow models must also be adjusted or developed remains similarly unclear.
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Document ID:
4BB342A5
The Effects Of High Viscosity/Low Reynolds Number Flow Conditions On Multipath Ultrasonic Flow Meters
Author(s): Gregor J Brown, Terry Cousins, Donald R Augenstein, Herbert Estrada,
Abstract/Introduction:
With rising worldwide energy demands and depletion of existing conventional oil reserves the production of heavy oil is becoming increasingly common. The high viscosity of heavy oils presents measurement challenges for most types of flow meter. For example it limits the maximum flow of a PD meter, reduces the turndown of a turbine meter and can result in measurement errors in Coriolis meters. Ultrasonic meters can be used for measurement of high viscosity oils. However, in order to do so with high accuracy they have to cope with increased signal attenuation and changing velocity profiles through the transition from turbulent to laminar flow. This paper explains the technical challenges faced when using ultrasonic meters for high viscosity/low Reynolds number flows and shows how these conditions can adversely affect the performance of some designs of ultrasonic meter. Modelling using velocity profile data and analysis of meter diagnostic data is presented in order to illustrate the physical processes that are at work. Test data is presented to demonstrate the performance of conventional and improved ultrasonic meter designs. The improved ultrasonic meter design incorporates a reducing nozzle to flatten and stabilise the velocity profile in the transition region. The impact of this design feature on permanent pressure loss is evaluated.
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Document ID:
F0C09E77
Diagnosis And Evaluation Of Ultrasonic Clamp-On Measurements
Author(s): Mathias Panicke
Abstract/Introduction:
Ultrasonic clamp-on flow meters offer great flexibility of use, thanks to the fact that they are non-invasive and installed on the outside of the piping. They are used for a wide range of measuring tasks. The evaluation of the gathered measurement data, and its reliability, are as important as the measuring value itself. Ultrasonic flow meters inherently offer extensive selfdiagnostic possibilities, both during installation and for long-term monitoring. This article presents both device-supported procedures and measures that can be taken by the user to evaluate an application that has been or is to be implemented.
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Document ID:
C6118C87
The Benefits Of A Fully Self Diagnosing Gas Ultrasonic Meter
Author(s): John Lansing Koos Van Helden Volker Herrmann
Abstract/Introduction:
During the past several years the use of ultrasonic meters (USMs) has gained world-wide acceptance for fiscal applications. The many benefits of USMs have been documented in papers at virtually every major conference. As the cost of gas continues to increase, the significance of knowing that the ultrasonic meter is operating accurately has never been more important. The use of diagnostics to help identify metering issues has been discussed in several papers over the past few years Ref 1, 2 & 12. The traditional method of verifying whether the USM is operating accurately essentially requires using the USMs diagnostic information to help understand the meters health. This has often been referred to as Conditioned Based Maintenance, or CBM for short. Different USM meter designs require different analysis techniques, especially for the velocity profile analysis. For the field technician, it is often difficult to understand all the diagnostic features of each USM meter design. Through the years software has been developed to help determine if the meter is operating correctly or not. However, it is still very difficult to clearly define limits on some of the diagnostic parameters that translate into a quantifiable metering error. This paper will discuss two methods of providing a fully redundant self diagnosing meter. The first is a new CBM concept to assist in determining if the fiscal 4-path USM meter is operating accurately. Rather than relying entirely on the understanding and interpretation of the meters diagnostics, a meter designed with an additional built-in diagnostic path, has been developed. In this paper the meter design will be referred to as the CBM 2Plex 4+1 meter. The second is having a meter which monitors, on a real-time basis, all diagnostic parameters and then reports when one, or more, approach unacceptable values. Traditionally in the past the user would collect log files monthly and analyze them. The problem is that often the technician would overlook a problem and thus it could develop into a significant measurement error. Also, since inspections are often performed on a monthly basis, a problem can develop and it may take a month or more before the user would see this. By monitoring the diagnostics on a real-time basis, combined with the redundancy of an independent, second metering path of the CBM 2Plex 4+1 meter, all aspects of a meters health can be checked and validated without the need for monthly inspections. This not only significantly reduces operation and maintenance (O&M) expenditures, but lowers measurement uncertainty in the field.
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Document ID:
3C230966
Maintaining Measurement Accuracy Using Gas Ultrasonic Flow Meter Diagnostics
Author(s): Daniel J. Hackett
Abstract/Introduction:
Gas ultrasonic flow meter diagnostics have been used in the last several years to not only monitor the health of the flow meter but to indicate potential dynamic flow disturbances that left unchecked can slowly lead to increased measurement uncertainty. Understanding the diagnostics available is one key to providing user actionable recommendations to resolve alarms or alerts. However, there are additional steps a user should initially take to avoid potential problems from installation and to identify the magnitude of the shift in specific diagnostic parameters.
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Document ID:
9899C54A
Examination Of Ultrasonic Flow Meter In CO2-rich Applications
Author(s): Koos Van Helden Andreas Ehrlick Toralf Dietz Peter Tan
Abstract/Introduction:
Exploration of less conventional natural gas sources will lead to more diverse operation conditions and compositions for natural gas measurement. One significant challenge is increased levels of CO2 in the gas. While standard applications deal with levels well below 5 mole percent, this amount may be as high as 20 mole percent, or even higher at some installations. Additionally there are some applications where CO2 is the major gas component. Re-injection of CO2 into declining oilfields will require accurate and reliable flow measurement. Such applications contain up to 60% CO2 and require an accuracy level comparable to custody transfer for natural gas. While the flow measurement is currently being done primarily using ?p devices, such as orifice meters, it would be a significant improvement to use ultrasonic meters with their increased functionality, larger turn-down ratio reduced maintenance, and diagnostic capabilities. Applications such as CCS (Carbon capture and storage) with CO2 concentrations near 100% are even feasible today. Table 1 gives a short summary of various applications and the typical amount of carbon dioxide in the gas stream.
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Document ID:
AA73FA4C
The Challenge Of Well Testing On Old Test Separator
Author(s): D. Vijay Kumar,
Abstract/Introduction:
The well test data produced from old production wells through old Test Separators associated with pneumatic instrumentation was very challenging and difficult. As the well behaviour changes towards the end of the production phase with significant variations of Gas Void Fraction (GVF) and high variations in the water cuts, the old well test measurement limits the functionality thereby resulting in a higher degree of uncertainty /accuracy for reservoir management and production estimates. The well test is a health check for the well producing and for the reservoir good well test equipment will ensure reliable well test data. Accurate, timely and reliable well production data are very important for :- Operation control Reservoir management Production allocation Field development & optimization
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Document ID:
5F5A0205
Petroleum Development Oman Pdo() Experience In Well Testing At High Gvf And High Pressure Conditions
Author(s): Abdullah Al-Obaidani Salim Al-Sibani
Abstract/Introduction:
Continuous and accurate well testing data is one of the challenging aspects in well testing at high GVF and high pressure applications in Petroleum Development Oman. PDO has many promising fields where wells generally are at high GVFs and relatively high pressures. The need of reliable well testing data is becoming more important to realise improvements since the company is actively moving towards well & reservoir management (WRM). A metering project which was initiated in 2003 suggested installing different types of well testing equipment. After completion of this project in 2006, PDO realised improvements in well testing data and hydrocarbon reconciliation. However, fields with high GVFs achieved relatively less improvement and several attempts to improve the hydrocarbon reconciliation were carried out. A joint effort with the multiphase meter vendor to further improve measurements and hence field reconciliation has taken place in early 2008 where PDO has expressed more emphasis in achieving better reconciliation factors for particular fields. This effort has resulted in a significant improvement in hydrocarbon reconciliation and hence enabled better WRM. This paper addresses PDOs experience and measurement challenges in the joint effort in testing wells at the described conditions. It highlights different tools used and the specific improvements made. This includes using multiphase flow meters and mobile separators. In addition, this paper also highlights the methods used to back allocate hydrocarbon to the wells. Furthermore, it highlights the importance of accurate parameters to be configured in this equipment to deliver quality well testing data.
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Document ID:
89545976
Tomography Powered 3-phase Flow Metering In The Wet Gas Regime
Author(s): ystein Lund B, Arnstein Wee And Ingve Morten Skjldal,
Abstract/Introduction:
Multiphase meters were initially developed by several companies during the 1990 s and operating companies have gained about 10 - 15 years of operational experience by using them. The need for high performance meters has been expressed by the oil companies since quite many years back 1. The particular case where the gas fraction of a multiphase stream is in the high 90 percent level (typically above 95% gas) is denoted wet gas. As a matter of fact, the majority of gas producing wells contain small amounts of liquids and wet gas metering represents a growing interest for the gas field operators. Even in cases where the reservoir only produces gases, liquid condensation will usually occur in the flow lines because of the reduction in temperature and pressure causing wet gas conditions at the metering location.
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Document ID:
EB3325EA