Liquid Ultrasonic Meter: Three Years On ... Learning & Experience
Author(s): Abdullah Obaidani, Salim Al-Sibani
Abstract/Introduction:
The purpose of this paper is to present the background on the implementation and use of liquid Ultrasonic Meter for hydrocarbon allocation and reconciliation in Petroleum Development Oman. The option of using Liquid Ultrasonic meter was proposed as a solution based on successful implementation of this type of meter in Southern Field of Nimr in Oman, where numerous attempts at using PD and Orifice meter to measure the Central Production facilities output to the required accuracy was unsuccessful. The Liquid Ultrasonic meter used was the Krohne Ultrasonic V for viscosity of 200 cP which based on the line size and flow rate directly characterized the flow in the lamina range. The decision to adopt the liquid ultrasonic meter for the reconciliation application stemmed from the successful results from the Krohne meter. Fundamentally the line size of 24 inch and requirement for a maintenance free operation directed the decision for opting for the ultrasonic meter solution. The paper will discuss the use of liquid clamp on ultrasonic meter in hydrocarbon reconciliation, and issues encountered. In addition it will explore the use of online remote monitoring facility that was implemented on the meters. Also it will address the effect of the seasonal temperature changes. The drive to implement the proposed system was primarily to improve operational efficiency and availability and hydrocarbon reconciliation.
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Document ID:
261BB723
Proving Liquid Ultrasonic Flow Meters For Custody Transfer Measurement
Author(s): 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 adherence to the standards, procedures and methods that define the measurement process. There are two fundamental ways that petroleum products are measured - statically or dynamically. The measured volume determined by either method must be validated at operating conditions and traced to a fundamental standard. In a static system the product is transferred to a tank or similar container. After the transaction is completed the volume can be measured and validated by a suitable method. In a dynamic system PD, turbine or ultrasonic meters provide instantaneous information on the rate and volume of the transfer. As with static methods the measurement results must be validated by a suitable method. A key difference between a static and dynamic measurement is time. A static measurement is similar to a bank transaction, where the cash draw can be pulled and verified at any time. When a static transaction is complete there is time to review the measured volume, and if an error is suspected the volume can be re-measured. With a dynamic system the measurement must be right the first time there is no means to re-measure the volume. The proving system and process are essential in either static or dynamic measurement systems to validate the accuracy of volume measured. There are various worldwide standards and regulations that define the measurement system requirements, but they are fundamentally the same. Each is traceable to a national standard which in turn is traceable to the international standard. In dynamic measurement systems this link is the prover volume. There are gravimetric and volumetric methods where the prover volume is traceable the International Bureau of Legal Metrology (BIML). The technical arm of the bureau is OIML (International Organization for Legal Metrology). This is an intergovernmental organization that deals with all aspects of legal metrology. It has 59 Member States and 50 Corresponding Members. In this way all the countries are tied to the same weights and measurement standards, which facilitates world trade. The various measurement standards either directly or indirectly define the accuracy requirements over a range of operating conditions which include: flow rate, viscosity, temperature, pressure, piping configurations, etc. It is therefore important in the proving process to define both the operating conditions and the accuracy requirements because they are interdependent. A change in operating conditions can affect the meters accuracy. As a general rule the meter must be proven at operating conditions to validate its accuracy with the highest degree of confidence. The greater the change in operating conditions, the more uncertainty is introduced into the measurement. The object of all Custody Transfer meters is the same, highly accurate measurement, but the procedures to achieve the results may vary with the different meter technologies. This paper will focus on the standards, procedures and methods used to prove ultrasonic meters.
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Document ID:
7480D467
The Effect Of Flow Conditions On Ultrasonic Meters In Low Velocity OIL/WATER Flows
Author(s): Gregor Brown, Terry Cousins, Don Augenstein, Mike Almeida
Abstract/Introduction:
Multipath ultrasonic flowmeters are now capable of achieving the accuracies required in custody transfer applications. However, it must be recognised that all technologies have limitations and that optimum performance can not be achieved in every application. Previous papers have shown that the performance of liquid ultrasonic meters can be adversely affected by the presence of water in oil 1 - 3. It has also been shown that the behaviour of the meters is a complex function of the meter design, the flow regime, and the oil/water distribution 2, 3. This paper describes the performance of a 4-path ultrasonic meter in oil/water flows at low velocities over a wide range of water-cut. These tests were performed as an acceptance test for the meter prior to deployment in the North Sea on an allocation duty, measuring oil from a first stage separator. The tests were performed on a 4-inch Caldon LEFM 240C ultrasonic flow meter in the multiphase flow laboratory at TUV NEL. The tests covered low flow velocities in the range of 0.15 to 2.5 m/s. Tests were performed at 3, 5, 7, 10, 15, 20, 50 and 75% water-cut. Prior to the tests Caldon estimated the measurement uncertainty based on experience from previous oil/water laboratory tests at Ohio University 3. The meter performance was evaluated by comparison with the TUV NEL reference meters, and ultrasonic meter diagnostics were logged at 5 second intervals during the tests. This paper presents the performance data from the tests and compares these results with the uncertainties estimated by Caldon prior to the tests. An earlier paper presented the results grouped by water-cut and plotted as a function of flowrate 4. This paper presents the same data grouped by velocity and plotted as a function of water-cut. Diagnostic data is also presented in order to show the interactions between the flow regime and the measurements on individual paths.
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Document ID:
8741331B
Experiences With The Master Metering Principle And Ultrasonic Flowmeters At Offshore Locations Fpsos()
Author(s): John Thorogood
Abstract/Introduction:
This paper looks at the operating experiences when using multi path liquid ultrasonic meters for custody transfer duties offshore. The performance of the duty meters have been checked with a master meter, which has either been proved in situ or returned to a flow test laboratory. Results presented in this paper demonstrate the long term stability and high confidence in the measurement results.
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Document ID:
8B2396E6
Experienced Based Overview Flow Monitoring Technology In Mature Field
Author(s): J Tim Ong
Abstract/Introduction:
[Abstract Not Available]
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Document ID:
F1DAA168
A Case Study On Multiphase Flow Meter
Author(s): D.R. Vaidheeswaran, Rizal B Saluki
Abstract/Introduction:
Well testing is a complex phenomenon and can be performed on onshore as well as offshore wells. In an offshore platform, each well or group of wells can behave independently, the reservoir characteristics in the form of production/pressure profile being different. Sometimes, the well testing becomes significant due to contractual obligations between partners who share the same reservoir. The well-bore assessment in combination with shut-in data and test results data can be used to prevent damage to the well bore activity 1. The purpose of Multiphase Flow Meter (MPFM) is to determine the oil, water and gas volumes and mass flow rates from the multiphase stream produced by the wells in a typical offshore platform. A conventional method would be to use a test separator vessel, which by virtue of its design, separates the three phases each of which is individually metered at the outlets.
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Document ID:
08DFB412
Test Of A 1 Inch Roxar Watercut Meter On Light Condensate With Very Low Water Content
Author(s): Georg Johnsen
Abstract/Introduction:
The Oil industry is rapidly moving towards more difficult crude products, as more and more of the easy produce able crude oil will be finished. This leads to new challenges for the whole industry, finding better equipment to coupe with these challenges. One such trend is in the oil business is moving towards lighter oils or condensates. These will have to be processed and transported under high pressure, to stay liquid. The residue water, more or less saline, in condensates can cause serious corrosion problems in the downstream process equipment and pipelines. The Roxar Watercut meter have undergone a test on light condensate, with standard density of about 625 kg/m3, to establish how good the meter is for measuring the very low water content in such products. The ordinary process conditions were 0-650 ppm volume water, while the maximum range was 0-1650 ppm. The test took place offshore on a real condensate line, and was conducted by a large oil company. A standard Watercut meter was optimized during the installation process for optimization to these process conditions. Also the different contributions to the total measurement uncertainty from the different sensors (microwave, temperature and density) were evaluated, to see if such an installation was possible in the first place. In-line calibration is crucial on such installations, because it basically will compensate for any biased uncertainty in the measurement system. Establishing the dry oil permittivity under such circumstances is crucial for correct determination of the water content in the meter. Also, sampling several times, then averaging the samples, gives a very good correspondence, better than 50ppm under fairly stable process conditions.
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Document ID:
D080D665
Venturi-Tube Performance In Wet Gas: Computation And Experiment
Author(s): Michael Reader-Harris, David Hodges, Jeff Gibson
Abstract/Introduction:
Various one-off tests performed on wet-gas flowmeters appeared to show that changing the test fluids could affect the meter performance. It was believed that fluid properties, such as liquid surface tension and viscosity could play a major role however, no data existed that quantified the effects in a systematic manner. Quantifying the effect is important given the increasing use of wet-gas meters for gas and liquid allocation measurement. Knowledge of the extent of any change in meter performance is significant because current wet-gas correlations which correct for the liquid presence are not able to account for large changes in fluid properties. Many correlations in existence were developed on test facilities that utilize only a single pair of test fluids. Consequently, the use of such correlations on meters exposed to different fluids from those of the original test facility may well introduce systematic errors in the estimates of the individual-phase flowrates. In order to investigate this, TUV NEL carried out wet-gas testing of diameter ratio, , 0.6 and 0.75 Venturi tubes using three gas-liquid combinations (nitrogen-kerosene, argon-kerosene and nitrogen-water) and at two gas-liquid density ratios. These data were presented in 1 and 2. The results showed that changing the gas type had little measurable effect on the Venturi-tube performance with the largest deviations in over-reading relative to the nitrogenkerosene data not exceeding a range of -0.023 to 0.02, suggesting no effect of argon compared with nitrogen.
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Document ID:
3E228C28
Re-Evaluation Of Axioms Regarding Orifice Meter Wet Gas Flow Performance
Author(s): Richard Steven, Frank Ting, Gordon Stobie
Abstract/Introduction:
New wet gas flow data with 3 and 4 orifice meters suggests that orifice meters can be used like other differential pressure (DP) meters to meter wet gas flows. Liquid hold up due to the presence of the orifice plate was not found to cause pipe flow or metering problems. The wet gas flow readings from orifice meters are repeatable and predictable and for given wet gas flow conditions, the liquid induced error in the gas rate prediction is less than for equivalent cone and venturi type DP meters. Chisholms correlation has been shown to correct the liquid induced gas meter errors satisfactorily for most wet gas flows when the liquid flow rate can be estimated by independent means and DPs are kept below 500WC.
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Document ID:
4CE33EF2
Mpfm Experience In Malaysia
Author(s): Zakiah Zakaria
Abstract/Introduction:
Malaysia have been involved in multiphase flow metering (MPFM) for about a decade, with 28 meters currently in the operation. These meters are installed topside and solely used for reservoir management and production monitoring purpose. The importance of well testing and the pro and cons of conducting the test in both conventional and MPFM means are discussed in this paper. The test separator philosophy is simple, easily understood and operated by the operation personnel. However the limitations of this device incorporate both the accuracy, practicality and the safety issues. On the other hand, since majority of the fields are considered as marginal and having minimum facilities, MPFM is more desirable both economically and practically due to its compact configuration and operation easiness. However it has some drawbacks in terms of reliability, conceptual complexity and sensitivity to input data and parameters. MPFM has benefit us is many ways, including significant reduction in facilitys space and dimension, lower costs and online data availability. However, we have also encountered some constraints and limitations through out our involvement. The problems are occurring in the operation stage and further highlighted during the analysis phase by the reservoir expertise. These problems are inclusive of the human factor, improper design of the meter, changes in the reservoirs behaviour and the reliability of the technology itself. We have resolved majority of these issues with both assistant and commitment from the suppliers and operators, but this interference is not favourable and disturbs the operation activities. In spite of drawbacks of MPFM in our experience, reverting back to the conventional test separator is neither the best solution. In the current and future application, MPFM remain as a better option provided that the expected accuracy in well testing as part of production monitoring and reservoir management is satisfied and the economics for the overall field development over the entire life cycle is encouraging. Nevertheless, conventional test separator still deems to be the alternative whenever there is no suitability for an MPFM installation.
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Document ID:
AD485AE5
Outstanding Performance In Heavy Oil Application With Vx Technology Part( 1: Flow Loop Validation)
Author(s): Bruno Pinguet, Elsie Guerra, Hudson Lemes, Wilmar Angulo, Moussa Kane
Abstract/Introduction:
The objective of this paper is to present accurately the performance of the Vx Technology from modelization to flow loop tests in Heavy Oil Environment. The focus will be on practical information, and knowledge sharing to overcome all classical challenges met by multiphase flow meter. Why should we use a multiphase flow meter more than a separator? The main issue today is the production and productivity of the reservoir in Heavy Oil. All agree that well testing operations in heavy oil wells are very complex and most of conventional surface well testing equipment is very difficult to use in those operations to get reasonable accuracy. It is complex to run a test separator and its measurements are not reliable at all due to the vessel instability, foaming or separation issues. The main challenge is basically that the oil density is very close to the water density and therefore the process of gravity separation in the conventional separator is not anymore working properly. Added to this that most of the heavy oil is very viscous this should lead to have higher retention time. Another associated phenomenon is that the droplets of gas trapped inside the fluid cannot anymore flow freely inside the liquid and stay in gas phase but trapped inside the liquid. This is obviously leading to large overestimation of some of the liquid flow rate and by consequence then underestimate gas rate. Finally, it should be mentioned that phenomena of emulsion are appalling working conditions for any separators without any injected diluent or desemulsifier.
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Document ID:
884B8EFD
High Gas Mpfm An Operators Experience
Author(s): Wisnu Purwanto, Lukman Hakim Ramli, Oi-Mee Voon
Abstract/Introduction:
Brunei Shell Petroleum (BSP) Co. Sdn. Bhd.s activity is primarily exploring and producing crude oil and natural gas from onshore and offshore fields with production level of 210,000 barrel per day. Today, 90 percent of its oil and all its commercial gas come from seven offshore fields north of Borneo. This paper looks into design and operational aspects of High Gas Multiphase Flow Meter (HG-MPFM) BSP went through when developing two new oil-and gas fields offshore Brunei. The two fields Champion West (CWDP01) and Egret (EGDP01) are special from a metering point of view. The CWDP01 initially produces oil, and then further developed to produce gas whereas the EGDP01 produces gas in the early stage then developed to produce oil. In both cases, oil and gas fields are commingled into the same well testing facility. In addition to elaborations around the special design criterias, the paper also explores the dynamic flow tests and the meter commissioning undertaken in project phases. From there it goes into detailing the operating phase in an attempt to highlight meter performance towards well behavior.
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Document ID:
70F18335
Sonar-Based Gas Void Fraction Measurement Improves Coriolis And Turbine Flowmeter Performance In Multiphase Flows (0-10% Gvf)
Author(s): Ed Otto
Abstract/Introduction:
Crude oil production flow regimes are inherently multi-phase, with a significant operating cost directed toward accurately measuring and allocating produced hydrocarbons. Unfortunately, the presence of gas phase in liquid flow impairs accurate measurement by single phase flowmeters. Turbine and Coriolis meters deployed on the outlets of test separators can, if operated under multiphase flow conditions, introduce significant measurement error. These errors influence back allocation and well production allocation factors. In addition, test separator measurement errors, distort the reservoir engineers understanding of production performance and impact associated production models. Therefore, a SONAR-based system to measure the gas void fraction (GVF) next to turbine and Coriolis meters is proposed as a method to correct for the influence of secondary phase gas on flowmeter performance. A series of tests were conducted at Southwest Research Institute (SwRI) to validate this concept. The tests were as designed to simulate separator liquid outflow conditions and to assess the ability of gas void fraction (GVF) measurement to correct for errors introduced by entrained gas in liquid, i.e. gas carry-under, on turbine and Coriolis flowmeter technologies. Test data confirms that turbine and Coriolis meters over-report volumetric flow rate in proportion to the amount of entrained gas. Using the GVF measurement of the SONARbased system provides a simple correction to the primary measurement of both flowmeter types to within 1% of the reference liquid flow rate for 0-10% GVF range.
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Document ID:
AC93F97D
Application Of Wet Gas Metering Technology In Shell Malaysia Ep
Author(s): Ngu Kee King, Rick De Leeuw
Abstract/Introduction:
This paper seeks to present Shell Malaysias experience in the application of wet gas metering technology. The Companys involvement in wet gas metering dates back to the 80s where individual well flowlines were operationally metered using orifice plates and a reconciliation factor which was determined empirically through well tests. Chisholm formula was used for newer installations in the 90s and wet gas figures were verified using the well test by difference method. From the late 90s until today, over 20 Venturi-based wet gas metering systems have been installed, the majority of them with dual-dP tappings and provisions for online application of tracer dilution measurement and wet gas fluid sampling. A variety of implementation problems were experienced as well as successes achieved. The general lessons learnt is that for continued good performance, wet gas metering requires greater attention in design, installation and maintenance than traditional dry gas systems. However, with the experience gained, it is now a normal practice in the Company to employ wet gas metering technology instead of test separators for new installations unless specific cases dictate otherwise. We have yet to utilise this technology in Allocation metering systems but the acceptance of such systems can be expected in future.
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Document ID:
C0E9DEF0
New Data For The Correction Of Orifice Plate Measurements In Wet Gas Flow Conditions
Author(s): Andrew Hall, Richard Steven
Abstract/Introduction:
The orifice plate meter is a common flow meter in the oil and gas industry. This single phase gas flow meter is often used to meter unprocessed natural gas production flows which may in reality be wet gas flows. That is, the orifice meter is often used to meter the gas flowrate of a wet gas flow. As with all other differential pressure (DP) type meter designs used with wet gas flows, the orifice meter has a liquid induced error in its gas flowrate prediction output. The size of this error is stated in the literature to be dependent on the Lockhart-Martinelli parameter and the gas to liquid density ratio 1,2,3. However more recent wet gas research on other DP meter designs has shown liquid-induced errors in their gas flowrate prediction that are not only dependent on these two variables, but also the gas densimetric Froude number 4,5 and liquid properties 6,7,8,9. These particular phenomena have not yet been specifically investigated for wet gas flow through orifice meters. Also it is currently unknown whether changing the pipe diameter has any effect on the wet gas response of any DP meter, although there is some suspicion that this variable may have an affect 7,10. This paper shows new wet gas orifice meter data from tests conducted for BP at Colorado Engineering Experiment Station Inc. (CEESI) in 2006. The first set of data is for a 4 inch, 0.68 beta orifice meter at a nominal pressure of 60 bara with natural gas and the single liquid hydrocarbon component, Stoddard Solvent (which is a hydrocarbon mix that is predominately C10 to C12). The second set of data is for a 2 inch, 0.515 beta orifice meter at different pressures with natural gas and a liquid phase made up of various mixes of fresh water and Stoddard Solvent. This paper discusses the analysis of the 4 inch orifice meter wet gas data set and relates the results to the literature. The 2 inch orifice meter wet gas data set is analysed to offer some insight into the liquid property effect. Finally, the possibility of orifice meters having a wet gas flow diameter effect is discussed.
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Document ID:
08425EF1
Operational Value Of Flow Calibration Generated Data For Field Monitoring Of Ultrasonic Gas Meter Performance
Author(s): Garnet Grudeski, Wayne Haner, Jairo Mantilla
Abstract/Introduction:
Although calibration is an important step for enhancing the accuracy of all measurement technologies, in ultrasonic metering this activity plays an even more prominent role. The extended flow ranges capability of ultrasonic technology, although capacity adventitious, can magnify measurement error if not corrected through proper calibration. For ultrasonic metering, high-pressure calibration not only provides immediate performance value through measurement correction cleaning the meter of intrinsic uncertainty and offering traceable accurate readings at the laboratory it provides on-going operational field value through the definition of a meter specific performance baseline for continual qualification of meter health once operational in the field.
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Document ID:
39554C5D
Investigations On An 8-PATH Ultrasonic Meter - What Sensitivity To Upstream Disturbances Remain?
Author(s): Volker Herrmann, John Lansing, Toralf Dietz
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 several papers at virtually every major conference. As the cost of gas continues to rise, the benefits of accurate measurement become even more important. For this reason many users are installing flow conditioners in an attempt to create the same profile as the meter was subjected to during flow calibration. The newest release of AGA Report No. 9 Ref. 1 has a section that discusses a recommended installation for the USM which includes a flow conditioner. However, in many applications, using a flow conditioner is not preferred due to the increased piping length, added differential pressure, and higher installed cost. This paper will discuss testing an 8-path ultrasonic meter to identify what uncertainties remain from installation effects. Data on installations with and without a flow conditioner, including corresponding accuracy results, will be presented. This data helps identify the magnitude of uncertainties that may be present in field installations, and thus may help the user make a decision as to whether or not a flow conditioner is required.
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Document ID:
A9808056
How Often Do I Need To Recalibrate My Ultrasonic Meters A Series Of Life Cycle Studies
Author(s): Nguyen Van Nghia, Keith Roberts, Tom Kegel
Abstract/Introduction:
The installed base of multi-path natural gas ultrasonic meters continues to age, some of the oldest meters have been installed for over six years. As time goes on discussions within the industry increasingly focus on the issue of re-calibration. What is the long term stability of a typical meter? How sensitive is the stability to various fi eld conditions? Can diagnostic parameters be monitored to help identify the need for re-calibration? To support such questions this paper presents life cycle studies of various ultrasonic meters. These studies are based on long term performance data from fi rst calibration through operation and re-calibration. Additional value is realized when the data are obtained from both fi eld and laboratory. The fi rst several case studies provide a Southeast Asian perspective. They concern meters that have been initially calibrated, installed in the fi eld and then recalibrated. The analyses integrate fi eld and laboratory data. The cases cover the effects of low pressure operation, temperature variation, cleaning and electronics replacement. Additional case studies involve several different sized meters in use as check standards in a calibration facility. The calibration histories of these meters include tens of thousands of data points. In general the meters are operating under ideal conditions the analyses of the data indicate the stability under ideal conditions. The check standard history includes some data based on non-ideal conditions. These conditions include variable inlet profi les, variable pressure, and very low velocity. Additional value is realized when these data are included in the analyses.
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Document ID:
91F7ABBC
Dual Venturi Flowmeter For Downhole Multiphase Flow Measurement
Author(s): J Tim Ong
Abstract/Introduction:
Flow measurement has become an integral part of well monitoring in the oil and gas industry. The advent of more complex completions which includes multi-zone and mutli-laterals means that downhole monitoring is needed to be able to accurately determine the production from the separate zones. There are many downhole flow meter (DHFM) technologies available that will accurately determine flow rates for a production of either liquid or gas. However, when these standard flow metering technologies are used in a mixture of liquid and gas, measurement error increases due to the effects of poor density quantification, slip between fluid phases and also compression of gas phase. This is typical for a venturi based DHFM. The general idea of a DHFM is the suppression of gas production by operating above the bubble point (BPt) pressure. This is not often possible in mature fields and also in high GOR crude production. Therefore as field matures the probability of multiphase flow occurring downhole increases. The increase in mature fields in the global production dictates a technology that would be able to tackle this problem. The development of the dual venturi flow meter is aimed at stretching the envelope of downhole measurement to encompass multiphase flow 1. The design was put together in 2001 with one installation performed in the Captain field in the North Sea. The specification is based on flow measurement of all three phases of oil, water and gas produced in the well.
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Document ID:
27456A83
Testing Of The Red Eye Near-Infrared Water Cut Monitor In High Gvf Multiphase Flow Conditions
Author(s): Andrew Hall, John Lievois, Babajide Adejuyigbe
Abstract/Introduction:
successfully applied to measurement of small quantities of water in a variety of media, such as paper, methanol, tobacco, etc. The Red Eye 2G water cut monitor was developed to exploit the very characteristic attenuation of infra-red light by water as a means to measure the water cut in mixtures of oil and water. The water cut monitor uses four specific NIR wavelengths to provide a capability for water cut measurement across the full range from 0% to 100%. The monitor was known to operate reliably in the presence of a small quantity of free gas (up to 20%) from previous tests, and the purpose of this new test programme was to evaluate the capability of the instrument to operate in much higher gas volume fraction environments. This paper presents new data obtained in three test campaigns at the TUV NEL multiphase flow facility. The tests spanned the full range of water cuts from 0% to 100%, at a range of fluid mixture velocities, and with gas volume fractions in the 60% to 95% range. Most tests were for meters in a horizontal orientation, but some additional tests were included in vertical flow. The results exceeded expectations of water cut measurement uncertainty at these high gas fraction conditions, with very little dependence of the uncertainty on GVF.
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Document ID:
6ECEE90B
Analysis Of A Full Gamma Ray Spectrum In Combination With A Venturi To Monitor Salinity & Sand
Author(s): Bruno Pinguet, Gilles Roux, Alex Brocoletti, Nadege Hopman
Abstract/Introduction:
Using multiphase flowmeters in field operations has now become a widely accepted practice. A three phase flow measurement requires a minimum of five measurements split as 3 velocity measurements and 2 fractions knowing that the sum of the three holdups is equal to one. Numerous techniques exist to try to obtain these five measurements but as any other measurement system there is no universal metering solution and multiphase flow meters are limited versus the technology or the physical principle used at either High GVF, Low GVF, or due to sensitivity to phase dispersion or composition change to name the most common one raised by customers or scientists. Facing and recognizing this type of issue will lead manufacturers to propose some add-on devices to take into account this sensitivity. Meanwhile, adding equipment is leading to complexify the meter with more electronics, introducing some possible problems of reliability, or the worst one making several measurements at different P, T conditions and having difficulty to reinterpret these measurements in a consistent model due to the chaotic behavior of multiphase flow and the decoupling effect that exist among the numerous measurements. For example, the utilization of Dual Energy Gamma is the simplest device to use in a multiphase flowmeter and the most accurate to get the fraction measurement. Meanwhile the sensitivity of the nuclear attenuations to some heavy atoms can lead to added uncertainties of the fraction measurement if the composition of one of the phases drastically change versus time and that such variation is not taken in consideration in real time. However, any nuclear fraction measurement having more than 2 energy levels has the potential to overcome this type of problem and ensuring a proper measurement of concentration at the same area, at same time and at high frequency thanks to the use of entire spectrum information.
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Document ID:
1255435A
ISO Flow Measurement Standards - Report On The ISO Tc 30 Meeting In November 2006
Author(s): Michael Reader-Harris
Abstract/Introduction:
It has been recognised for some time that standards are an important enabler of innovation and international technology transfer. They have an important role in national and international trade and in wealth creation. Standards contributed to about 13 per cent of the growth in labour productivity in the UK over the period 1948-20021, and contribute u2.5 billion annually to the UK economy. Many other national economies must have benefited similarly. By developing and adopting standards, barriers to trade are lowered, transaction costs are reduced and the operation of markets is improved through the smooth flow of goods and services. Standards enable compliance to be demonstrated, provide confidence in product performance, and help to eliminate or reduce disputes between companies and across borders. They help smaller firms by transferring technology from larger ones. Poorer countries may benefit similarly. Flow measurement is an important area of standardization. For example UK natural gas demand averages around u10 billion annually, and most of this is measured (generally more than once) using ISO 5167. Avoidance of both inaccuracy through inadequate specification and excessive cost through over-specification is absolutely vital. Accuracy in taxation is of great importance to Government. Standards produced largely in one sector but used in others enable technology to be transferred from one sector to another. Work done for the upstream or gas transmission sectors is valuable to refineries, aerospace and the chemical industries, and indeed more widely. Participation in standards-making is an opportunity not only to share knowledge but also to gain it. Standardization is not only important for economic reasons. Accurate measurement of discharges, of produced water, for instance, is important to ensure a cleaner environment. The author of this paper is the Chairman of ISO TC 30, but the views expressed here are his own.
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Document ID:
65CD9BEE
Swirling Flow Through Venturi Tubes
Author(s): Jeff Gibson, Michael Reader-Harris
Abstract/Introduction:
There is an increasing desire to use Venturi tubes for wet gas measurement, but to ensure accuracy in wet gas, their behaviour in dry gas must also be understood. Work carried out at TUV NEL reported by Jamieson et al 1, data reported by van der Weers et al 2, and further work have shown that the performance of Venturi tubes in gas at high Reynolds number is very different from that in water due to the static-hole error effect. Some discharge coefficients in gas are greater than would have been expected by 3 per cent, or even more. Another factor which has an effect on how a Venturi tube performs is its internal shape, and work has shown that, of the designs evaluated, the optimum design was one with a convergent angle of 10.5 and sharp corners 3,4. It exhibited more predictable behaviour than the design recommended in ISO 5167 5,6. Differential-pressure flowmeters are known to be affected by upstream disturbances such as valves and bends, and the next stage in evaluating the suitability of the new design for industrial gas flow measurement was to investigate its installation requirements. Computational Fluid Dynamics (CFD) was used to compute the effect of upstream bends on Venturi tubes with convergent angles of 10.5 and 21 for comparison with experimental data. Two cases were modelled: a single bend and an out-of-plane double bend. The results of the single bend models have been reported previously in Reader-Harris et al 7 and TUV NEL report 2005/225 8. The focus of this paper is on the results of the double-bend and further examination of the effect of swirl on discharge coefficient, C, using the axisymmetric approximation comparison is drawn between the results of single- and double-bend cases where appropriate.
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Document ID:
DD051D8F
Field Experience With Orifice Custody Metering Systems At Saudi Aramco
Author(s): Maatoug Al-Maatoug
Abstract/Introduction:
This paper focuses on Saudi Aramcos experience with orifice-based custody gas metering systems. It presents our guidelines and practices in engineering, operating, maintaining and auditing our gas metering systems. It also highlights our training practices. In addition, it focuses on two key challenges we face with orifice-based systems black powder and dual chamber orifice fittings. The paper concludes with a brief look at Saudi Aramcos future custody gas metering improvement plans. With 259 billion barrels of proven crude oil reserves, 224.4 trillion SCF of gas reserves and 1.7 million barrels/day refining capacity 1, Saudi Aramco stands as the largest Oil Company worldwide. Saudi Aramco crude oil production goes through 43 Gas/Oil Separation Plants (GOSPs). There are five different crude grades produced and the majority of the crude is exported. The crude oil is stabilized and sweetened at four locations. An extensive pipeline network totalling 17,169 km 1 distributes the crude oil to local refineries and export terminals. Figure 1. Saudi Aramcos Basic Operations The production process starts with oil production from each of the many hydrocarbon reservoirs located both on-shore and in the Arabian Gulf (Figure 1). The crude oil first flows to the many GOSPs, where it is stabilized at the crude stabilization facilities.
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Document ID:
5FB9D75B
Large Capacity Gas Orifice Measurement Skid
Author(s): Steve Baldwin, Trilochan Gupta
Abstract/Introduction:
Natural Gas volumes passing through an orifice meter are commonly calculated following the standards dictated in API Manual of Petroleum Measurement Standards (MPMS) Chapter 14.3. The standard has specific installation requirements for many piping configurations. For the use of high performance flow conditioning devices, the standard allows these to be used as long as the manufacturer has data to show that their devices comply with the performance criterion of the standard. The configuration of the metering skid is such that upstream and downstream of the meter tubes, there are 4 elbows out-of-plane including splitting the flow to the meters by a header that seemed to be under-sized. API MPMS 14.3. Part 2 Appendix 2-D defines minimum upstream length for orifice meter with pipefitting of two 90 degree elbows out-of plane. There is no test data for 4 elbows out-of-plane and restrictive headers upstream of the orifice fittings. The combination of undersized headers and no public domain test data lead to the need of flow calibrating the whole metering skid. Therefore, it was likely that the combined measurement uncertainty of the complete system, including the secondary instrumentation could not possibly achieve the uncertainty limits of 1% In order to achieve the measurement uncertainty of less than or equal to 1%, the options defined in API 14.3 Part 2 Appendix 2 C and 2 D would have to be followed. The standard requires, if possible, the designed flow metering system with all upstream and downstream piping configurations be flow calibrated preferably at operating conditions to achieve improved measurement accuracy. A test matrix was developed that would allow the metering skid to be sufficiently calibrated to meet the intent of the standard. This test matrix and the testing results will be presented showing the difference in volumetric calculation using the standard API MPMS RHG equation and the actual volume.
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Document ID:
B0DF1AD7
Field Data Of An E-Rttm Based Leak Detection System
Author(s): Hilko Den Hollander, Berthold Bollermann, Gerhard Geiger
Abstract/Introduction:
Numerous pipeline leak detection and localisation systems are available today, varying from low-end volume balance to high-end RTTM (Real Time Transient Modelling). Despite that pipeline leak detection plays an important role in safe pipeline operation, legislation and methods to compare the different systems are still limited. In Germany pipeline leak detection is goverend by law in the TRFL (Technical Rules for Pipelines). The American Petroleum Institutes API 1130 describes Computational Pipeline Monitoring for Liquid Pipelines and API 1155 provides a method to compare the various systems. To get a better understanding of the capabilities of modern leak detection systems, this document describes two case studies. One study refers to a gas pipeline and focuses on leak detection under transient conditions and subsequent detection times. The second study refers to a (multi-product) liquid pipeline and focuses on leak localisation and leak rate calculation. KROHNEs PipePatrol E-RTTM (Extended Real Time Transient Modelling) has been installed on both pipelines and the systems were tested by leak trials which are described in the case studies. The paper starts with a brief introduction into E-RTTM based leak detection system, which forms the basis for the case studies.
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Document ID:
7EA94242
Ultrasonic Meter Condition Based Monitoring - A New And Simplified Solution
Author(s): John Lansing
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 several papers at virtually every major conference. As the cost of gas continues to increase, the importance 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. The traditional method of verifying whether the USM is operating accurately essentially requires using the USMs diagnostic information to help understand the meters health. 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 a new concept in understanding 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 4+1 meter.
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Document ID:
200AC02C
Diagnostics And Long Term Stability Of Gas Ultrasonic Meters
Author(s): Martin Schlebach, Tom Mooney
Abstract/Introduction:
Multi-path Gas Ultrasonic Meters (GUSM) have been used for over a decade in custody transfer applications, over the years many methods of verifying a meters performance and the overall integrity of the metering installation have been used. There have been a number of different terms used to describe these diagnostics capabilities, most recently Condition Based Monitoring (CBM) was used by Daniel and has been coined by other manufacturers as a generic term covering all aspects of GUSM diagnostics. What you call the diagnostics is insignificant, the information that is made available and its interpretations is whats important. In this paper we will look at CBM data taken before, during and after meter re-calibrations, from this data well evaluate the value of diagnostic data offered by multi-path GUSMs.
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Document ID:
735DB94E
Ultrasonic Metering Of Liquefied Natural Gas For Allocation And Custody Transfer
Author(s): Gregor Brown, Herb Estrada, Don Augenstein, Terry Cousins
Abstract/Introduction:
This paper describes multipath ultrasonic meters designed for the measurement of LNG and addresses the issues that could arise as a result of the challenging application conditions. The paper describes the design and calibration methodology developed at Caldon Ultrasonics for use with 4-path and 8-path chordal ultrasonic meters. The accuracy of the chordal design is compared with the relatively limited capabilities of 2-path configurations. It is demonstrated that the chordal meter calibration retains its applicability in varying installation conditions and at high Reynolds number conditions that cannot be replicated in a calibration facility. The benefit of using a swirl compensating 8-path arrangement is also highlighted.
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Document ID:
5206DD5C
The Expanding Use Of LNG From Natural Gas To Satisfy World Energy Demand Can Use Technologically Superior Ultrasonic Cryogenic Liquid Flow Metering, And Ultrasonic Gas Metering For Process And Custody Transfer Operations
Author(s): Jacob Freeke, James Matson, Michael Scelzo
Abstract/Introduction:
Transit-time Ultrasonic Flowmeters are now firmly established as an acceptable technology for gas and liquid flow measurement in the global Oil & Gas Industry. The technology has not only proven to be extremely accurate, exceeding legal metrology requirements, but also able to yield considerable savings for operators due to the effective absence of both pressure drop and maintenance requirements. This paper discusses how two advanced flowmeter designs, one for liquid LNG, and one for Natural Gas can help financially offset the impact of the anticipated increase in flowmeter numbers within the industry. A patented Bundle Waveguide Technology (BWT) system, using a unique design of a thermal buffer enables ultrasonic transducers, and hence flow meters, to be employed, complete with possible removal without affecting line integrity or safety, for liquid cryogenic LNG flow measurement. The paper will cite numerous installations on cryogenic LNG flow measurement applications that have been operating successfully for several years at LNG liquefaction and regasification facilities. Transit-time ultrasonic technology can accommodate the largest LNG pipeline encountered so far, significantly in excess of the largest pipe size accommodated by alternate technologies, without pressure loss and with lower capital outlay. BWT technology theory, design and a case study are discussed.
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Document ID:
9A527DFC