The Benefits Of Multiphase Metering For Production Monitoring And Reservoir Optimization
Author(s): Juan Carlos Perez, Cesar Rivera, And Roger Bello, Edelwis Goncalves, Bruno Pinguet, And Carlos Cumbe, Schlumberger
Abstract/Introduction:
Since the beginning of the well testing service around the world in early 1920s, it was only until the introduction of Multiphase Flow Metering technology in the early 90s that the oil industry faced a step change in the way the Well Testing is performed for production allocation and reservoir monitoring. With much better accuracy and excellent dynamic response plus the light, compact and safety advantage inherent to the multiphase units, the multiphase solution proposed nowadays in Well Testing Production Market bring incremental value to the knowledge and understanding of the reservoir. The processes involved in the dynamic reservoir evaluation are changing as well with the deployment of multiphase metering technology. Information related to field and well production history is normally input to reservoir models, and combined with other additional measurements in the wellbore like downhole pressure and temperature. New simulations are carried out and verified through a history-matching process in comparison with actual production measurements and well conditions (pressure and temperature monitoring). The reservoir fluid behavior and their interactions with completion and production systems can be properly understood in order to increase recovery factors through the life of the wells.
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Document ID:
39012917
Considerations Of Ultrasonic Flow Metering For The Oil & Gas Industry
Author(s): James Doorhy
Abstract/Introduction:
Ultrasonic flow meters have been employed in the Oil & Gas industries for many years. Since their inception in the early seventies many advancements in the technology have been made with regard to available configurations, electronics offered and sensor design. Today ultrasonic meters have proven to be reliable, versatile and capable of meeting the demands of the Oil & Gas markets. It is clear, however, that various ultrasonic flow meter technologies have different advantages with regards to design and application use that ultimately makes one or more appropriate than the other. Frequently, these differences can lead to misapplication and/or limited satisfaction by the end users. This paper will describe and outline the various technologies available in todays market and review each advantage / disadvantage along with the benefits of each type of design and technology. Basically, there are two forms of ultrasonic flow measurement, transit-time and Doppler. For the purposes of this paper, transit-time will be explored simply because almost all technology advancements have been focused on the transit-time technology and because it is the primary technology of choice used in the Oil & Gas industry.
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Document ID:
C6C388A3
Fiber-Optic Flowmeter At Bp Mahogany, Offshore Trinidad
Author(s): . H. nalmis, A. Vera, S. Mathias, E. S. Johansen, R. Chun
Abstract/Introduction:
In March, 2002, a downhole fiber-optic flowmeter was successfully installed in BPs Mahogany A-15 well, offshore Trinidad. The fiber-optic monitoring system also includes downhole pressure and temperature sensors and reports the real-time oil, water, and gas flow rates to the supervisory control and data acquisition (SCADA) system. The optical flowmeter is based on measurement of the flow velocity and the speed of sound which yield the flow rate and gas volume fraction, respectively. The Mahogany A-15 well is a single-zone producer with a long horizontal gravel-packed producing zone. The reservoir has a thin oil rim between a large gas cap and aquifer. Initially, in March of 2002, the well produced mostly oil with a low, but rapidly increasing gas rate. In 2003, the wellhead choke was opened fully and the total production rate increased which resulted in coning a large amount of gas. The flowmeter demonstrated excellent performance over flow conditions ranging from low gas fraction liquids, to severe slugging, and on to wetgas. Currently, the well is producing in excess of 50 mmscfd of gas and about 800 bpd of oil and condensate with a downhole GVF well above 95%. The optical flowmeter system continues to give gas and liquid rates in good agreement with the test separator proving the longevity of optical sensing and the robustness of the measurement methodology. In large gas reservoirs, the trend is towards drilling fewer wells per platform (in some cases 3 or less) with large diameter producing lines and very high flow rates (100s of mmscfd per well). At such large gas rates, it is often cost and size prohibitive to use conventional separators topside for metering the flow rates. Furthermore, losing measurement of these wells impacts a large percentage of the total production. The full bore downhole optical flowmeter has demonstrated measurement robustness, a wide measurement range with no practical upper flow rate limit, and performance that has been proven in both field installations and flow labs including CEESI, NEL, Hydro, and SwRI.
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Document ID:
6E309FAB
Flow Conditioning And Effects On Accuracy For Fluid Flow Measurement
Author(s): Blaine Sawchuk, Rick Rans, Marvin Weiss
Abstract/Introduction:
Inferential meters, such as orifice, turbine and ultrasonic meters, infer fluid flow based on an observed meter output combined with a number of fluid flow assumptions. Optimal flow conditions lead to optimal meter performance and in some cases fully developed turbulent pipeline flow is used to describe these optimal flow conditions. Unfortunately the length of long/straight/uniform/clean pipe required to produce fully developed pipeline flow often exceeds practical installation constraints. Although flow conditioning has been successfully used to create optimal flow conditions and reduce meter run lengths, problems can still exist if they are incorrectly applied. This overview presents material available from the literature which describes some of the installation effects that need to be managed.
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Document ID:
3219B578
The Influence Of Fluid Properties On Allocation Accuracy
Author(s): Jim Mcnaught, Norman Glen, Andy Johns, Carrie-Anne Irvine
Abstract/Introduction:
In the North Sea and elsewhere, many oil companies make use of shared pipeline systems to transport oil from the wells to shore. Each operator measures the volumetric flow rate of oil from their well to the shared pipeline. To enable correct allocation of oil to each operator once it reaches the refinery, it is necessary to know the effects of temperature and pressure on the volume of oil, i.e. the variation of density as a function of temperature and pressure. Current practice is based on measuring the density of the oil at process conditions, using a densitometer, and then using generic crude oil expansion coefficients to correct fluid densities to other conditions. However, there are concerns about the calibration procedures for densitometers and the applicability of current crude oil volume correction procedures. TUV NEL is currently running a Joint Industry Project aimed at addressing issues associated with the characterisation and traceable calibration of densitometers used in the North Sea oil industry. However, even with perfect densitometer operation, errors will be introduced by the use of inappropriate coefficients to correct the density at densitometer conditions to that at base conditions and then to that at meter conditions, as expansion coefficients for North Sea crude oils have never been adequately defined. The validity of using generic expansion coefficients on crude oils containing substantial amounts of water or natural gas liquids is highly questionable since the tables and procedures were developed for dry, stock tank crude oils.
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Document ID:
212036BF
Master Meter Proving Of Liquid Of Ultrasonic Flow Meters For Custody Transfer Measurement
Author(s): Peter Sims, Raymond Kalivoda
Abstract/Introduction:
Liquid Ultrasonic Flow Meters (LUFMs) continue to gain popularity in petroleum measurement with the promise of high accuracy and low maintenance. These are favorable features, but because of the high volume and value of petroleum products buyers and sellers must have a high level of confidence in the measurement. This assurance in Custody Transfer measurement is gained by adhering to the two basic requirements for all custody transfer meters: 1.) Tracing the measurement to a standard recognized by the International Organization of Legal Metrology (OIML) and 2.) Validating (proving) the meter at operating conditions. In large-volume liquid petroleum measurement applications this is normally accomplished by in-situ proving using a displacement prover.
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Document ID:
9C55503F
Development Of A Large-Capacity High-Pressure Natural Gas Calibration Facility In China
Author(s): Guo Ming-Chang, Ding Jianlin, Wang Jin-Song, Steve Caldwell, Thomas Kegel, Jiunn-Haur Shaw, Fong-Ruey Yang
Abstract/Introduction:
This paper presents the development of a world class calibration facility constructed in conjunction with the PetroChina West-East Natural Gas Transmission Pipeline project (WEGP). The paper will discuss the need for the facility, the basis of measurement, the traceability developed and plans for the continued development. The system is anticipated to be fully operational by mid 2008. Measurement uncertainty goals (at 95% confidence level) are 0.10% for a primary standard, 0.20% for a set of secondary standards, 0.25% for a set of working standards, and 0.35% for a mobile prover. To meet the ever-stringent environmental concerns of cleaner energy for the industries and household sectors, China, as a world economic contributor, has devoted its efforts in constructing a cross-country 4000 kilo-meters natural gas transmission pipeline. Along the way, major gas measurement stations have been built for accurate control and custody transfer. Thus, a large-scale calibration station with mobile prover is needed for the dissemination of measurement standard. The facility provides calibration of DN400 gas flow meters under maximum operating pressure of 9.6 MPa with actual flow range from 8 m3/h to 12,000 m3/h. Based on a flowthrough principle, natural gas is drawn from a 1016mm, 10 MPa trunk line and regulated through the standard and test sections. A primary standard, made by a 1000 kg capacity gyroscopic weighing scale, a secondary working standard, made by a bank of sonic nozzles and a set of reference turbine meters, complete the self-traceable measurement standard. To provide constant control check, three sets of ultrasonic meter are also installed. The system is fully automated with secured human machine interface and validated numerical calculation procedures. A mobile prover, developed by Instromet Company in Belgium, consists of two turbine meters and an ultrasonic meter, will be circulated among the gas measurement stations, and this will provide field verification of meter performance. A quality assurance program based on ISO 17025 and uncertainty evaluation is underway through the consultancy assistance from CEESI. A preliminary uncertainty analysis is briefly described. The discussion includes test data obtained to support Type A estimates for several components. An informal inter laboratory comparison test was completed in December 2007, the testing and results are discussed. The results indicated good agreement with CEESI and PTB.
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Document ID:
ABE7BF32
Statfjord Late Life Project Flow Measurement From Study To Start Up
Author(s): Jean Monnet, Liv Marit Henne, Trond Hjorteland
Abstract/Introduction:
The Statfjord late life project is intended to improve oil/gas recovery from this StatoilHydrooperated North Sea field, with the intention of keeping it on-stream until 2018-20. Statfjord A, B and C have been subject to substantial challenging modifications in order to produce more gas. These modifications have been carried out while all three platforms were in full operation. Gas production from Statfjord A, B & C is exported via a new pipeline called Tampen Link to the FLAGS transport system, which runs from Britains Brent field near Statfjord to St. Fergus in Scotland. In order to increase export capacity to the UK, a new metering system had to be installed on the Statfjord B. The final solution for a fiscal flow measurement skid containing two parallel runs based on Ultrasonic Meters (USM) plus a new analyser system has been subject to evaluation from the conceptual studies to the Detail Engineering. The main objective was to comply with the Gas Sales Agreement and Regulatory requirements. For Statfjord A & C the existing orifice plate skids are re-used with upgrade of the control systems and analysers systems. Existing gas analysis measurement equipment for the Statfjord A & C Platforms have been required to be upgraded from single to redundant systems.
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Document ID:
1F6874EA
Statfjord Late Life Project Flow Measurement From Study To Start Up
Author(s): Jean Monnet, Liv Marit Henne, Trond Hjorteland
Abstract/Introduction:
The Statfjord late life project is intended to improve oil/gas recovery from this StatoilHydrooperated North Sea field, with the intention of keeping it on-stream until 2018-20. Statfjord A, B and C have been subject to substantial challenging modifications in order to produce more gas. These modifications have been carried out while all three platforms were in full operation. Gas production from Statfjord A, B & C is exported via a new pipeline called Tampen Link to the FLAGS transport system, which runs from Britains Brent field near Statfjord to St. Fergus in Scotland. In order to increase export capacity to the UK, a new metering system had to be installed on the Statfjord B. The final solution for a fiscal flow measurement skid containing two parallel runs based on Ultrasonic Meters (USM) plus a new analyser system has been subject to evaluation from the conceptual studies to the Detail Engineering. The main objective was to comply with the Gas Sales Agreement and Regulatory requirements. For Statfjord A & C the existing orifice plate skids are re-used with upgrade of the control systems and analysers systems. Existing gas analysis measurement equipment for the Statfjord A & C Platforms have been required to be upgraded from single to redundant systems. Close collaboration between Oil Company, Engineering contractor and Metering/Analyser skid supplier has contributed to successfully completing a challenging Project.
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Document ID:
F9C0F8A7
Important Considerations For Traceable Calibration Of Liquid Ultrasonic Meters
Author(s): Gregor Brown,Terry Cousins,Don Augenstein
Abstract/Introduction:
Unlike the gas custody transfers, oil flow metering has long relied upon the use of use of volumetric provers to verify the performance of flow meters in operational conditions. There are now various situations, growing in number, where use of a prover is not the most practical method of checking the meter performance. This is particularly true of large diameter meters, such as used for FPSO offloading, and the measurement of liquefied gases, where conventional proving is not viable. This paper discusses the pros and cons of central (or laboratory) calibration of liquid ultrasonic meters versus use of volumetric provers for calibration in-situ.
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Document ID:
44CD61E4
Experience With The Latest Developments In Ultrasonic Transducer Technology
Author(s): Skule Smrgrav, Atle K. Abrahamsen, Kare Kleppe
Abstract/Introduction:
As ultrasonic gas flow meters are being used in more and more applications across the oil and gas industry certain applications have resulted in damaged transducers and failing measurements. Such applications include wet gas, after 1st or 2nd stage separation, high gas condensate fields, corrosive environments such as high H2S sites (more predominant in the later life of many sites). The advances in electronics and signal processing have made possible certain developments on ultrasonic transducers. Limitations due to material exposure to such corrosive environments are removed with the application of titanium as the only wetted part of USM transducers. Even though the definition of wet gas is difficult, and we will not try to do so here either, - for the purpose of this paper we consider liquid volume contents from 0,01% to 5% as wet gas. The obvious reason for calling it wet gas is of course the fact that it is by far mostly gas (more than 95%) and a little liquid (less than 5%). This means that the meter will basically operate like in gas measurement, but with the added difficulties caused by the presence of liquid.
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Document ID:
7A2C3352
The Application Of Multiphase Flow Meters In The Development Of Oil With Emulsion Forming Tendency
Author(s): Nick Paris, Gary Miller
Abstract/Introduction:
The Pyrenees Development is located offshore Western Australia and involves the combined subsea development of the Ravensworth, Crosby and Stickle oil fields in approximately 200 meters. Reservoir depths are approximately 1100m TVDSS and the Ravensworth and Stickle fields contain have small gas caps. The Pyrenees crude has undergone some in-situ biodegradation resulting in a near saturated medium black oil with a specific gravity of 19 API, gas-oil ratio (GOR) of 150 to 187scf/stb and in-situ viscosity from 8 to 11cP at 60C. The oil has a high emulsion forming tendency when mixed with produced water and these emulsions may be stabilised by the formation of naphthenate soap scale. The fields will be developed with seventeen subsea wells, comprising 13 horizontal producers, 3 vertical water disposal wells and one vertical gas disposal well.
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Document ID:
C369BA65
Further Evaluation Of The Performance Of Horizontally Installed Orifice Plate And Cone Differential Pressure Meters With Wet Gas Flows
Author(s): Richard Steven, Gordon Stobie & Andrew Hall
Abstract/Introduction:
Orifice meters have been studied for many years and their performance in single phase flows is well documented in the standards 1. Between 1967 and 1977 Chisholm 2,3 researched the response of orifice meters to two phase flow. No further research on the behaviour of orifice meters in wet gas flows was released until 2007, when Hall et al 4 and Steven et al 5,6,7 showed data from CEESI that indicated Chisholms equation 3 was appropriate for predicting the over-reading of an orifice meter in wet gas flow conditions, across a significant range of the flow conditions tested. Only at very low or high gas velocities (or gas densimetric Froude number) did Chisholms equation become inaccurate. In 2005 Steven 8 summarized the research into cone meters in wet gas flow. Stewart et al 9 had shown that cone meters had a performance in wet gas flow that was sensitive to the beta ratio, where this has been found to not be a very significant issue with orifice meters, as shown by Steven 5. Since most available cone meter data is for a 0.75 beta ratio, the wet gas over-reading correlation for the cone meter, Steven 8, is specific to this beta ratio. At the 2007 North Sea Flow Measurement Workshop, two papers, Evans et al 10 and Steven 11, showed that the published 0.75 beta ratio cone meter correlation was seen to diverge and become inaccurate on extrapolation to higher gas velocities than the data set for which the correlation was derived.
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Document ID:
BC51C4D4
An Innovative Solution Towards The Detection Of Wax And Asphaltenes In Production Fluids And To Ensure High Quality Measurements With Multiphase Metering In Such Challenging Conditions
Author(s): Bruno Pinguet, Carlos Cumbe
Abstract/Introduction:
Flow assurance and production optimization represents a cornerstone in current oil industry with regards to increasing recovery factor of the reservoir. One of the main challenges faced during the oil production is the presence of precipitates and/or deposits of asphaltene, wax, scale or any other elements that has the potential to alter the fluid production and transportation. The presence of deposit has a detrimental effect on the quality and performance of flow rates metering devices for production allocation. Conventional equipment failed to produce reliable solution to the flow rates measurement needs in such environment and in many cases additional equipments are required to improve performance of the separator i.e. upstream heating device, injection of inhibitors, etc in order to either remove or prevent or attenuate the precipitation severity. This is not cost effective and increases the operational time and risk. In this paper we present the experience of using permanent multiphase units for continuous monitoring of fluid effluent with high asphaltene content and also we describe how this experience was implemented for production allocation with multiphase mobile testing units for a field in East Venezuela. The challenges were to achieve the most accurate flow rate measurements in order to reduce the uncertainty in the allocation factor with fluid containing nearly 7% asphaltene. With better production allocation per well, the reservoir team will ensure a better reservoir management using continuous monitoring. With increased frequency in monitoring of production wells through the use of accurate and reliable multiphase testing units it enables the acquisition and availability of high quality data per well in order to allow a correct selection for well interventions or to prioritize the wells selected for intervention
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Document ID:
DEE51A78
The Application Of Multiphase Flow Meters In The Development Of Oil With Emulsion Forming Tendency
Author(s): Nick Paris, Gary Miller
Abstract/Introduction:
The Pyrenees Development is located offshore Western Australia and involves the combined subsea development of the Ravensworth, Crosby and Stickle oil fields in approximately 200 meters. Reservoir depths are approximately 1100m TVDSS and the Ravensworth and Stickle fields contain have small gas caps. The Pyrenees crude has undergone some in-situ biodegradation resulting in a near saturated medium black oil with a specific gravity of 19 API, gas-oil ratio (GOR) of 150 to 187scf/stb and in-situ viscosity from 8 to 11cP at 60C. The oil has a high emulsion forming tendency when mixed with produced water and these emulsions may be stabilised by the formation of naphthenate soap scale. The fields will be developed with seventeen subsea wells, comprising 13 horizontal producers, 3 vertical water disposal wells and one vertical gas disposal well.
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Document ID:
66B0CA44
Verification Of Tank Calibration Volumes
Author(s): James C. Hassell
Abstract/Introduction:
Accurate and defensible measurement forms a critical basis for sustainable relationships in the worldwide trading of chemicals, petroleum products and liquefied gases. In storage tanks, accurate and defensible fiscal measurement requires determining a transferred volume from the containment system to a high level of accuracy. To meet this high level of accuracy, the petroleum industry goes to great efforts in accurately measuring the liquid levels of its fiscal tank systems. Unfortunately, even the best gauging system or accurate manual measurement is compromised if the equivalent volumes are extracted from inaccurate calibration tables or measurements are defended with poor records. Adding to the problem of inaccurate calibrations is the fact that once an error has been integrated into a capacity table, it will act in a single direction until its discovery. The effect of any capacity table error is compounded by the number of transfers made. Clearly with these factors at play, even a small error can appreciate into a large sum of money.
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Document ID:
D5DAACEA
Measurement Of Produced Water Discharges - Regulatory Requirements And Recent Progress
Author(s): Alick Macgillivray, Ming Yang, Richard Paton
Abstract/Introduction:
Until recently, produced water was considered to be a waste stream for which metering was not a critical issue. As a result, little attention had been paid to the subject of metering this stream. However, in 2001 OSPAR (Oslo - Paris Commission) recommended a 15% reduction in the oil discharged via produced water by 2006 1, in relation to the year 2000. This meant that there was a need to accurately measure both the concentration of oil in produced water and the volume of water being discharged. In the UK, new Regulations, called OPPC (Offshore Pollution Prevention and Control) 2 were introduced in 2005, which require the measurement of produced water volume to an uncertainty of 10% 3. This paper is divided into two parts. The first part (Part A) will provide a summary of the regulatory requirements related to the discharge of produced water in the North Sea and in UK in particular. It will examine the measurement issues raised by the introduction of the new legislation, including the best methods of achieving the performance targets. The second part (Part B) illustrates the importance of reporting produced water volumes at standard conditions of temperature and pressure (15C and 1.01325 bar absolute). Equations that can be used to calculate the density, and hence the expansion factors of produced water are proposed. These apply across the wide range of temperatures and salinities found in practice.
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Document ID:
E03BDD8D
Impact Of Regulator Noise On Ultrasonic Flow Meters In Natural Gas
Author(s): Koos Van Helden, Toralf Dietz, Volker Herrmann
Abstract/Introduction:
Pressure regulators are a major source of noise in gas pipelines. In recent years, continuous optimization of the regulator design has led to a noticeable noise reduction, in particular in the audible range. However, the amount of noise generated at frequencies above the audible range may be problematic for ultrasonic gas flow meters. The reliability and accuracy of the signal transit time detected and thus the quality of the measured value provided by an ultrasonic gas meter are defined by the minimum signal level differential required between the sensor sound pulse to be analyzed and the signal interfering with the sound pulse (the signalto- noise ratio). The spectral distribution of noise and its dependence on the pressure difference and flow rate at the regulator are of particular interest in this paper. Fig. 1 is a general presentation of the situation.
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Document ID:
8E1A73AD
Smart Ultrasonic Meter
Author(s): Angela Floyd, Klaus Zanker, Mike Whelan
Abstract/Introduction:
As more multi-path ultrasonic meters are being incorporated into systems designed for the custody transfer of natural gas, the scrutiny of their performance capabilities has increased. As the meters have no moving parts, are fully electronic and require a power source to work, the ability to quantify and identify causes and extent of inaccuracy have been dependent of the manufacturers development of electronic diagnostic software. In addition, the majority of the meters are 8 and above and were built with the thought that no recalibration would be necessary. They are therefore expensive to remove from the line for inspection and sending to an independent lab for re-calibration. Manufacturers have been more sensitive to these needs in recent years and have developed sophisticated diagnostic parameters which, with extensive training, the field should be able to identify system or meter problems via a modem or Ethernet connection. As each manufacturer invests in a competitive edge, the extent and complexity of these diagnostics has increased. Therefore, field use of more than one model of meter requires extensive training and knowledge for the field technician or the office measurement engineer who may be challenged with the quest of understanding what the reams of diagnostic data really means. It was with this task and the unanimous agreement from the industry users that a PRCI project was proposed and supported. The title of SMART meter indicated the ultimate goal that the diagnostic data would in fact indicate whether the meter was working correctly or if the system was affecting the meter and to what extent the accuracy was affected. It also charged the resultant diagnostics with identifying which facet of the meter or the related installation was affecting the measurement accuracy.
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Document ID:
040680CC
A Discussion On Vortex Meter Technologies With Wet Gas Flows
Author(s): Andrew Hall, Richard Steven
Abstract/Introduction:
It is commonly believed that vortex flow meters can be used by the hydrocarbon production industry in adverse flow conditions as they have a reputation for being robust. One such application would be metering the gas offtake from a separator where the meter may occasionally encounter wet gas flow conditions. Extending this operation into the metering of unprocessed wet natural gas flow streams should be possible, although to date there has been only limited published research into vortex meter performance with wet gas flows. This paper presents the results of two vortex shedding flow meter research projects. The first was a single phase flow project, the second a wet gas flow project. Both are based on the investigation of the permanent pressure loss across the vortex meters bluff body as an extra variable to increase the capability of the metering system.
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Document ID:
AEDE4D21
Measurement Of Flow In Viscous Fluids
Author(s): Gary Miller, Robert Belshaw
Abstract/Introduction:
Worldwide reserves of heavy hydrocarbons (oils and tars) are now estimated to significantly outweigh those of conventional light crudes. Extraction of these viscous deposits is growing rapidly, supported by high oil prices and the increasing demand for security of energy supply. The recovery and transport challenges now arising and the enormous monetary value of the end product make accurate flow measurement vital. Unfortunately, when applied to viscous fluids, the accuracy achievable with many conventional liquid flowmeters remains relatively poorly known although it has long been recognised that higher viscosity conditions introduce additional technical challenges to the meter designer and end-user. These include increased friction at solid surfaces, larger pressure losses across internal bends and restrictions, the possibility of extreme or varying velocity profiles, and the greater susceptibility of the viscous fluids to entrain secondary components such as solids or gas. It is reasonable to predict that different meter designs will be affected in different ways, but at the present time the most appropriate technologies for viscous flow measurement have yet to be fully established. To improve upon this situation, an NMS (National Measurement System) programme of research work has been launched in the UK to investigate the performance of a series of conventional liquid flowmeters at elevated viscosity conditions. This paper reports on preliminary investigations made into the performance of sonar, Coriolis and Ultrasonic devices when operated under such conditions and on an associated upgrade of the UK National Standards Oil Flow Facility at TUV NEL that was undertaken to provide test fluids (with traceable reference metering) at viscosities up to 300 cSt in the initial stage.
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Document ID:
B74BCD67
The Subsea Multiphase Meter - Meeting Operator Design Requirements
Author(s): Ottar Vikingstad And Karl Herman Frantzen
Abstract/Introduction:
More than a decade after the first multiphase meters were installed on the seabed, subsea multiphase metering is finally gathering full momentum. No major subsea fields are being developed today without multiphase meters being employed in some way or another. Along with the maturing of the market, the technology behind the subsea multiphase meters has also matured. This paper discusses how the Roxar subsea Multiphase meter has developed from the early years, while building on experience and adapting to industry standards and client requirements. Roxar started to supply topside multiphase meters on a commercial basis in 1994. The company was then known as Multi-Fluid or MFI (Multi-Fluid International), and the meter - based on microwave technology - was known as the MFI MultiPhase Meter. The first subsea multiphase meters were supplied in 1996. These meters - based on the same technology as the topside meters - are referred to as the first generation meters in this paper. The big breakthrough for subsea multiphase meters came in November 1996, when Roxar received a milestone order for a total of 30 subsea multiphase meters for a major North Sea field development. At the time of this order, very few subsea multiphase meters had actually been submerged and put into operation. Had it not been for the pioneers who decided to equip every well with a subsea multiphase meter back then when this was still a very immature technology, subsea multiphase metering would not likely have advanced as quickly to the level it has today.
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Document ID:
66041D6C
North Belut Dualstream II Advanced Wet Gas Meter - Flow Testing At CEESI
Author(s): Warih Kundono, Malcolm Brown, Gordon Stobie, Mark Tudge, Alan Downing, Alistair Collins, Richard Steven And Thomas Kegel
Abstract/Introduction:
An 8 Solartron ISA Dualstream II Advanced wet gas meter for North Belut, Indonesia has been dry gas tested in natural gas (at Bishop Auckland, UK) and wet gas flow tested at CEESI with air and kerosene/water mixes. This paper discusses the selection and proposed use of this meter, the validity of testing wet natural gas meters with air flows and describes the new CEESI wet gas facility for testing large diameter, high flow rate wet gas meters. The CEESI facilities commissioning runs with a 4 orifice plate meter are described and the results compared to existing CEESI and NEL wet gas orifice meter data. With a validated test system the Dualstream II wet gas meter data will be analysed The operational principles of the meter will be reviewed and the performance of the meter with the wet gas flow with water cuts will be discussed.
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Document ID:
2E25AE54
Euroloop: Unique Oil And Gas Calibration Facilities
Author(s): Wim Volmer
Abstract/Introduction:
NMi is building two calibration facilities, one for Natural Gas and one for liquid Oil and Oil products. Both facilities are unique in the world when it comes to their combination of flow-, viscosity ranges and measurement uncertainties. Services provided will cover ranges that significantly surpass the current capabilities of available traceable Measurement Standards. As such these impartial, independent and accessible facilities will provide a wide range of opportunities for traceable calibration, Research & Development and hands-on training for the entire Hydrocarbon sector and all those related to it. In this paper and in the presentation NMi intends to outline how international traceability will be provided for liquid flows ranging from 10 to 5,000 m3/h, line sizes from 4 to 24 over viscosities up to 100 cSt. Using two intelligent, roughly 40 m long, bi-directional Piston Provers, the overall measurement uncertainty will typically be 0.05%, not exceeding 0.07%, for the whole set of ranges stated above. For Natural Gas, the flow ranges will be from 5 to 30,000 m3/h at operating pressure, 1,800,000 m3/h at standard conditions, pressures from 1 to 65 bar, line sizes from 2 to 30 and an overall measurement uncertainty better than 0.20% for all these conditions. The system is designed to facilitate R&D, calibrations and activities under legal metrological control, such as Type Approval, Initial Verification and such. Therefore the facilties design is partly derived from requirements in OIML Recommendations R117-1 1 and R137-1 2 and some ISO Standards. Apart from the facilities design, there is also another relation between EuroLoop activities and legal requirements, being periodic re-calibration, which is also highlighted in this paper. Both paper and presentation focus particularly on the implications of legal metrological requirements on technical design aspects of the EuroLoop facilities.
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Document ID:
8D4E88A5