Using Venturi Meters Installed In Vertical Orientation For Wet-Gas Flow Measurement
Author(s): G. Chinello, E. Graham, m. Reader-Harris, S. Clark, A. Collins
Abstract/Introduction:
New data has been collected byTV-SDNational Engineering Laboratory (NEL)on the performance of Venturi meters installed in a vertical orientation which shows errors of over four times that from using the current ISO technical reports. This paper presents possible corrections for using Venturis for vertical installations to reduce the error and provide the basis for extending the standards. Venturi tubes are one of the most common types of device used for wet-gas flow measurement as they are a simple, robust and cost-effective flow meter. They also form the main component in the majority of commercial wet-gas and multiphase flow meters. Major oil and gas operators acknowledge that more accurate measurement of wet-gas and multiphase flows can be used to optimise reservoir conditions and increase production, hence there is a drive to improve the accuracy and increase the use of this technology. The presence of the liquid in the gas phase causes an increase in the measured differential pressure and results in the Venturi tube over-reading the actual amount of gas passing through the meter. This over-reading is usually corrected using available correlations derived from experimental data to determine the actual gas mass flowrate.
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Document ID:
14F823D9
Gas Quality Parameters Where Gas Composition Cannot Be Measured Online
Author(s): Eivind Nag Mosland, Camilla Stre, Askjell-Eivind Frysa
Abstract/Introduction:
At metering stations for custody transfer of natural gas, gas quality parameters such as molar mass, density at line and reference conditions and calorific value are found by calculations based on gas composition as measured by an online gas chromatograph. In metering stations upstream the custody transfer point it may not be cost-efficient to install gas chromatographs(GCs). In such situations, alternative means for determination of quality parameters must be considered. Furthermore, for possible future subsea custody transfer metering stations, use of gas chromatographs may not be technically possible. Finally, back-up solutions for a gas chromatograph can be beneficial, in particular for un-manned platforms.
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Document ID:
F5039760
Coriolis Density Error Targeting- Ambient Temperature Fluctuation And The Development Of A New Temperature Compensation Model
Author(s): Gordon S. Lindsay
Abstract/Introduction:
This paper details the experimentation, results and output of a 4-year doctorate research project, the objective of which was to develop new ambient air temperature compensation techniques for calculating fluid density on a Coriolis flow meter. The primary driver for this research topic is the recent increase in interest from end users with regards to utilising the density value from Coriolis meters for applications such as fuel bunkering, condition based monitoring and live fluid property determination. A targeted experimentation protocol was developed with input from manufacturers and end users, resulting in a facility build which allowed for realistic ambient temperature variations in the surrounding environment of the meter to be simulated at flowing conditions. As a result of this research it was discovered that the error imparted on the density calculation by ambient temperature can be live corrected by repurposing existing diagnostic measurements on the device transmitter. Therefore, using the high-resolution data sets obtained during testing,a new correction model was developed and validated by way of blind testing. The new model is shown to work on both ageing Coriolis devices currently installed in the field as well as new generation devices currently in the prototype stage.
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Document ID:
72A77220
Evaluation Of New Mixing Method For Pipeline Sampling At NEL Flow Facility
Author(s): E. Verloop, P. Verloop, J. Dods, B. Pinguet, E. Sveinsvoll, S. vreb
Abstract/Introduction:
Correct measurements of the water content and crude oil composition are essential for an accurate yield allocation. Especially in the cases of maturing production fields or locations where sand in combination with high water contents can be present, unreliable measurements on the quantity of oil being produced can occur resulting in significant measurement errors. Furthermore, with offshore locations commonly having constrained in electrical power, pipework configurations, and footprint size available, this can be a big issue and challenge. A new mixing method for pipeline sampling was found to cope with these limitations. The new mixing technology, e-Jetmixing, made use of the eductor principle and was tested with the support of Aker BP at the NEL low-pressure multiphase facility. A comparison was made between the e-Jetmixer and traditional jet mixing designs. Tests were performed on oil/water flows up to 65 % water cut by volume. The new and traditional mixing technologies were compared for both horizontal and vertical pipeline configurations. Test results showed that the traditional jetmixer required a high amount of power/energy to reach a homogeneous oil/water mixture and showed the unexpected layering of oil/water at low flowrate regimes. The new e-jetmixing design (with eductor), was tested under the same conditions and reached a homogeneous oil/water mixture with a substantially lower amount of required energy. Furthermore, it was found that the new e-jetmixing design showed a more consistent performance irrespective of the flow conditions, indicating an improvement of the overall measurement uncertainty. We can conclude that the new e-jetmixing design (with eductor) tested at the NEL facility has proven that a substantial reduction in power required and footprint can be achieved, together with more consistent performance. This paper will detail the advancements on the technology, the test work completed at an independent National Measurement Institute facility and describe the benefits it can offer end users.
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Document ID:
6A18EB09
The Generic Way To Establish The True Statement About The Uncertainty Of Facilities For MPFM/WGFM Validation
Author(s): Dr. Bruno Pinguet,Terri Leonard
Abstract/Introduction:
Over the years, multiphase and wet gas flowmetering technologies (MPFM/WGFM) have been improving in terms of reliability and compactness. Lately,with a significant cost reduction, they are planned to be deployed on each wellhead over the coming years. Furthermore, some significant improvements to the measurement uncertainties have been achieved. It is not unusual to now see claims within a few percent on gas or liquid or hydrocarbon flowrate measurements.This significant effort,based on understanding the fluid mechanics, sensor technologies, and modelling,should be recognized. An immediate consequence is the need to ensure that the claimed performances are correct, fair and can be checked against very high-quality references (i.e.,low uncertainty). Today with 100million BOPD with a value of 6Bn per day, an error of 0.1% leads to more than 2Bn revenue per year,which can be a gain or loss during the trading among the partners.At this date, the best way to verify multiphase and wet gas metering technologies is by testing at multiphase and wetgas reference facilities,where the standard states that the overall facility uncertainty should be 3 to 4 times better than the MPFM/WGFM (i.e.,within 0.5% to 1%). Establishing the overall facility uncertainty should be straight forward as soon as the procedures to identify the entire chain of errors are well understood and considered and evaluated in a fair manner. In case of doubt, the highest uncertainty value should be systematically considered (most pessimistic case until proper evaluation and proven justification have been made). Additionally, the overall uncertainty of the third-party ones,which are technically independent and impartial,should be publicly available for review to all the stakeholders testing or validating MPFM/WGFM performance for a proper understanding of the challenges,and not hidden as it is today. The purpose of this paper is to show that the process to establishing the overall facility uncertainty should be identical because all these facilities are based on the same principle with a separator, single-phase pumping process through some reference flowmeters, and after mixing them and passing through the MPFM/WGFM, back to the separator. Additionally, the calculation from line to standard conditions should be following the same generic way from reference measurement to multiphase flowmeter conditions and then to standard conditions.
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Document ID:
0D798C5B
Validity And Consistency Of Mpfm Data Through A Machine Learning Based System
Author(s): T. Barbariol, E. Feltresi, G.A. Susto,
Abstract/Introduction:
Despite the increased interest on Multiphase Flow Meters (MPFM) in the last decades1, the overall trust in the MPFM is still quite small, as the matter of fact less than a few percent of the oil fields worldwide employs MPFM to monitor the production2. However, monitoring the well flow and its composition has become very important as fields become economically marginal and reservoirs deplete3. Traditional methods, like oil separators, continue to be adopted despite their obvious disadvantages: they are expensive, bulky and do not allow continuous monitoring of the well performances. The reason behind this choice mainly relies on the lack of confidence in the MPFM. The separator is a conceptually simple instrument that does not require an act of faith to be trusted. On the contrary the MPFM is a complex system made up of different sensor modules that return their measurements to a flow model. The flow model processes the input data and gives back the estimated individual flow rates. Both these two stages can be prone to errors and malfunctions, but the sensor level is the most crucial and delicate. In order to overcome this mistrust, the MPFM manufacturer has to guarantee the customer the highest reliability.
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Document ID:
536D7889
Challenges And Opportunities For Subsea Multiphase Meters In The Brazilian Pre-Salt
Author(s): Luiz Octavio, Richard Streeton
Abstract/Introduction:
The Brazilian pre-salt discoveries are among the most important made in the world over the last decade. This province comprises large accumulations of high commercial value light oil-a reality that puts Brazil in a strategic position to meet the ever increasing global demand for energy. Based on conservative estimates, and only considering the portion already discovered, the pre-alt could double the countrys oil reserves to 31 billion barrels. Multiphase flow meters (MPFM) have been in development since the 1980s. However, it was not until recentlythat the technology has matured sufficiently to be used in subsea allocation applications. For operators, the use of subsea multiphase meters may bring important cost savings in CAPEX via the simplification of subsea field layouts as well as in OPEX as they provide continuous real-time reservoir and production monitoring capabilities. In Brazil, the National Agency of Petroleum, Natural Gas and Biofuels (ANP) adopted resolution No.44/20151 in October 2015 covering the use of multiphase meters for production allocation. In recent ANP auctions, interest in the pre-salt has been high among International Oil Companies (IOCs). With a continued relatively low oil price, a premium must be placed on technologies that can reduce CAPEX and OPEX on the cost side and/or contribute to improved reservoir and production management on the revenue side. Multiphase metering is a technology that is able do both and can thereby have a significant impact on the overall viability of pre-saltfield developments.The paper outlines how the deployment of multiphase meters can facilitate a wider range of possible subsea layouts-potentially more cost effective that a single-riser philosophy. This is important in Brazil as most fields-and particularly the pre-salt, lie in ultra-deep water. The paper summarizes the significant points of the ANP resolution that impact subsea field layouts. Finally and most importantly, the specific measurement challenges for multiphase metering in the pre-salt will be outlined.
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Document ID:
1B0AFDE5
Parallel Calibration Of Multiphase Flow Meters Vs Separator
Author(s): Stig Harald Hammer Gustavsen, Torbjrn Selanger, Therese Renstrm
Abstract/Introduction:
In recent years, the number of marginal oil fields put into production has increased. The typical scenario is that these small fields are tied back to an existing installation that acts as host. This way of arranging production of oil and gas in a production hub makes the development of marginal fields economically viable. One challenge with this type of arrangement is that as the owner structure gets more complex, the complexity in the allocation system also increases. It is essential for a viable long-term collaboration that the produced oil and gas revenue is accurately split according to owner fraction in a transparent and robust manner.Tying the production from small surrounding fields, often called 3rdparty fields, to a host installation usually requires modifications of the process at the host installation. To achieve accurate allocation measurements, the production from each license should ideally be processed and measured isolated from the other licenses. This would require enormous investments and is not realistic. Another approach is to have a dedicated inlet separator for each license. This method provides good accuracy of production volumes, but still requires relatively large investments in addition to space and weight reserves on the host installation. The cheapest, smallest and lightest solution usually involves using Multiphase flow meters (MPFM) for allocation.The individual mass flow of the oil, gas and water phases of the production fluids from each separate field is measured by a dedicated MPFM, and allocation can be performed based on these measurements. Production from different fields can then be processed with minimum modifications of the hosts processing systems.The downside of using MPFMs for allocation is a reduction in measurement accuracy. MPFMs have been shown to drift with varying flow conditions1. To reduce the uncertainty in the MPFM measurements and ensure that the measurements are representative for the present conditions, periodic calibrations of the meters is necessary.
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Document ID:
C441A7ED
Composition Measurement Of Multiphase Flow
Author(s): Carl Nilsson
Abstract/Introduction:
The successful operation of most types of multiphase meters hinges among other things on accurate PVT properties at the operating conditions1,2. As pressure and temperature change, the gas and oil properties also change according to the total wellstream composition.Over the lifetime of a reservoir the wellstream composition will gradually change and thus the composition or stored PVT tables used in the MPFM flow-computer needs to be updated. Traditionally the total wellstream composition found by sampling gasand oil from a test separator.Bottom hole sampling (BHS)can also be used as long as the reservoir conditions allow this. Otherwise gas and oil or condensate must be sampled from a multiphase wellstream, usually close to the MPFM or WGM location. Thiscreates two challenges: 1.Obtaining high quality PVT gas and oil samples from multiphase flows is considerably more error prone than sampling from a separator.2.The recombination factor for the gas and oil compositions needed to find the wellstream composition are derived from the measured gas and oil flow rates (or GOR)measured by the MPFM. Regarding point 2 one will easily realise that if the MPFM measurements are very inaccurate for some reason, the updated wellstream composition could be worse than the old one.
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Document ID:
39AF8AE6
Getting Rid Of The Prover, By Using A New Multipath Ultrasonic Flow Meter
Author(s): Dag Fllo, Equinor Pico Brand, Peter Van Brakel, Frode Endresen
Abstract/Introduction:
Metering systems with ball-provers are commonly used for loading/offloading of oil tankers. Such metering systems have significant cost, size, weight, and a considerable number of components. In this project, Equinor and KROHNE have cooperated on the testing of a new design multipath ultrasonic flow meter which is suitable for metering systems with master meter rather than ball-prover. The aims of this technology development project was to develop a master-meter system that: ?Has an uncertainty estimate which is about the same as that of a system with ball-prover ?Has considerably lower costs, size, and weight than a system with ball-prover To reach that goal, it was required to define a flow-metering run that would make the new ultrasonic meter independent of flow profile disturbances from upstream piping. Multiple tests were performed with different metering runs and different upstream pipe configurations. Following these flow profile disturbance tests, the flowmeter installed in the optimal metering run was calibrated and adjusted at one laboratory and verified by calibration on multiple liquids at 3 independent accredited laboratories.
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Document ID:
2B8C7631
Wet Gas Performance Of Coriolis Meters: Laboratory And The Field Evaluation
Author(s): J. Hollingsworth1, D. Morett1
Abstract/Introduction:
The rapid growth in unconventional gas production has brought with it increased demand for a method of measuring flow rates of both gas and liquid at the wellhead that is more cost effective and reliable than traditional methods (i.e. separator and/or compensated differential pressure), while remaining reasonably accurate. This paper describes research efforts to determine to what degree a single Coriolis meter is capable of measuring gas and liquid flow rates in wet gas processes, without compositional fluid analysis or other inputs beyond readily available process measurements. This paper will also discuss some of the potential impacts of meter design and best practices for installation and use in the field. This research builds on more than 10 years of development in Coriolis multiphase performance, although previous work has largely focused on small amounts of gas in a liquid process. Coriolis meters have the ability to measure multiple relevant variables: mass flow, density, temperature, tube damping (an indicator of phase fraction conditions), and time. By combining these variables with readily available process variables, such as density of liquid and gas, it is possible to make corrections to errors in Coriolis measurements due to multiphase process conditions and calculate the phase fraction, to apportion the overall mass flow to gas and liquid components.
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Document ID:
8CBFBBFA
Subsea Multiphase Fluid Analyzer Mufa() A- New Concept To Provide Accurate Fluid Parameter Input To Multiphase Flow Meters
Author(s): Kjetil Folger, Jan Kocbach, Kjetil Haukalid, Anders Hallanger, Marie Bueie Holstad, Eirik bro, Audun Faanes, Asbjrn Erdal
Abstract/Introduction:
Multiphase flow meters (MPFMs) rely on accurate knowledge of fluid parameters such as densities and dielectric parameters in order to calculate flow rates with good accuracy. Uncertainties and variations over time in the composition can lead to large uncertainty in the estimated fluid parameters. Uncertainty in fluid parameters is a main contributor to the overall uncertainty of multiphase flow measurements.In this paper we present a new concept for a subsea multiphase fluid analyzer (MuFA), in whichthe fluid parameters are measured directly at operating conditions using an add-on module to the MPFM. Thus, accurate input parameters are provided that will increase the reliability and accuracy of MPFMs. The functionality of the MuFA concept is to sample the multiphase flow into a subsea chamber, let the fluids separate within the chamber, and measure the fluid parameters of the three phases directly at operating conditions. The fluids are released into the multiphase flow after characterization. The concept has been verified by multiphase flow loop experiments over a broad range of flow conditions applying electromagnetic sensors and a gamma densitometer. A control system for automated sampling and analysis of the three fluid phases has been implemented and tested.
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Document ID:
F0326458
Metering Computer Systems-What Next?
Author(s): Tommy Leach, Mike Rawlings
Abstract/Introduction:
The flow computer metering system typically comprising of both flow computers and a metering supervisory computer(MSC)is the cash till for any oil andgas Operator. We have seen major economic and technological changes inside and outside of our industry, with respect to the former, the oil price crash of 2014 was damaging. The oil price has always been somewhat cyclical,hence the issues that we have faced in recent years have happened before and could happen again. Given the length of the low prices, companies were forced to adapt, or they simply wouldnt survive. The political landscape on previous crashes were maybe more collaborative whereas OPEC and the emergence of non-OPEC oil production coupled with a drop in global demand through a stuttering global economy led to a sharp sustained drop. Although we seem to be approaching a more stable price, it is difficult to predict when the next steep drop will occur. We are all still feeling the effects of 2014, it has shaped the approach of operator investments from prospective drilling through to production and has changed how all suppliers in the oil and gas industry operate too. This has and continues to have a bearing on the technological advancements we strive for, the goalposts for what we are trying to achieve may not have changed,but the means to which we get there has.
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Document ID:
C291FEEB
Hybrid
Author(s): Richard Steven, Ray Kutty
Abstract/Introduction:
Flow metering technology has never been so sophisticated and diverse. Advances in electromechanical devices, with their various parameters controlled, operated, and read by ever improving computers have revolutionized flow metering. The last five decades has seen different flow metering physical principles, previously theoretically understood but originally beyond practical application, becoming viable and attractive options for flow meter design. This revolution has produced various robust, reliable, now common place meter types such as Coriolis, transit time ultrasonic, and vortex meters etc. Furthermore, these advances have also facilitated respective real-time verification systems. Nevertheless, all modern flow meter types still have their limitations, signifiacant pros and cons, and industry would benefit from further technical advances.
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Document ID:
24A9DF2C
On Estimation Of Water Cut Changes And Pvt Calculation Approaches In Virtual Flow Metering
Author(s): Mohamed Ibrahim, Dag Ljungquist
Abstract/Introduction:
Virtual flow metering (VFM) is playing a significant role in surveillance independently and in conjunction with multiphase measurement instrumentation. Many production wells do not have physical metering installed and count solely on VFM. Even when wells are complemented with thorough measurement instrumentation, VFM still adds value as a backup when sensors fail.An accurate approach for calculating thermodynamic and transport properties (for the rest of the article, PVT) is a key element for a successful VFM software. This is due to the fact that multiphase flow equations count on these properties as part of the closure. For example, the friction correlation requires viscosity as input.The fluids in production vary significantly in composition and consequently in properties and behaviour.Usually, a fluid sample is taken to specialized labs to analyze composition and provide experimental measurementsfor the behaviour of the fluid. However, the experimental data are discrete in nature and local.Therefore, a generic and a more continuous solution is desirable, hence, relying on modeling.There are several approaches to predict PVT. One of them is to use empirically fitted models, but these models always have poor extendibility and generality outside the fitted range and composition. Moreover, they are not thermodynamically consistent over phases. A more appropriate and physically grounded approach is the use of equations of state (EoSs). There are various categories of EoSs.Cubic EoSs like Soave-Redlich-Kwong (SRK) 1, SRK with Huron Vidal mixing rules (SRK-HV) 2 and Peng-Robinson (PR) 3 are amongst the lightest in computations.Consequently, they are the most widely used in industry. Among the heaviest in computation time are the multi-parameters EoSs, which are at least one order of magnitude higher than Cubic EoSin computation time 4.Span-Wagner 5 for pureCO2 and GERG (Groupe Europeen de Recherches Gazieres) 6 for mixtures are examples of multi-parameters EoSs. The Cubic-Plus-Association (CPA) is one of the state-of-the-art approaches which has been a good compromise between accuracy and computation time.
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Document ID:
BF52899C
The Impact Of Regular Well Testing On The Accuracy Of Allocation Calculations
Author(s): Mahdi Sadri, Seyed m. Shariatipour, And Masoud Ahmadinia
Abstract/Introduction:
Although the interest in using multi-phase flow meters in the oil and gas industry has recently increased, there remain some oil and gas fields in which the flow rate of their individual wells is measured by occasional well tests. In such fields, the commingled production streams from all the wells are transferred to the separation unit and the total production rates are subsequently measured by single phase flow meters. As a consequence, although continuous flow measurement data of the total production is available for the whole field, the production data of the individual wells within it is intermittent. In the absence of measured data between two well tests, well flow rates are estimated by allocation factors which are calculated based on the well test data. While allocation factors are normally assumed to be constant between two consequent well tests, fluctuations in the well production typically change values over time. Long time intervals between well tests can therefore create large uncertainties in the allocation results. In this research, the effect of increasing the regularity of well tests on the uncertainty in the allocation process has been studied. Fluctuations in the production of three actual wells have been statistically analysed and quantified using their relative standard deviation. The same fluctuations have then been applied to the production streams of a simulated oil field with 36 wells to generate three different cases. Allocation and hydrocarbon accounting calculations have subsequently been undertaken for one to four well tests conducted per month. The pattern of fluctuations has been generated using a Matlab code. Each calculation has been repeated 100 times with different patterns and the results have been subsequently averaged and reported. The results show that increasing the regularity of flow tests can considerably reduce the allocation error. The most significant reductions were observed when the number of flow tests was increased from one to two per month. In this case, the average allocation error of the three investigated cases was reduced by 0.43%, 0.45%, and 1.11% which is equivalent to an 18.2M (Million), 18.9M, and 46.6M decrease, respectively,in the cost of allocation uncertainty for the three cases based on hydrocarbon accounting calculations. The results of the case studies suggest that the cost of allocation uncertainty can be reduced by 27.1M, 29M, and 80.1M, respectively, for the three cases if well tests are undertaken weekly instead of monthly.
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Document ID:
BE2EEABD
Wet-Gas Metering Implications- Of Changing Well Conditions On Long-Term Flow Measurement
Author(s): Sakethraman Mahalingam, Muhammad Arsalan, Jairo Leal Jauregui
Abstract/Introduction:
As the Oil and Gas industry slowly adapts to the Digitization paradigm, more data, however poor in quality, is considered better than none at all. Digitization relies on analyzing Big Data coming from across the oil and gas infrastructure and is viewed through a lens of the 4V model -Volume, Veracity, Velocity and Variety 1. A fifth V for Value is sometimes considered as well 2 -implying that some information is more valuable than others. The problem in the Oil and Gas industry seems to be mainly variety in and veracity of the data.Wet-gas meters have an important role to play in enabling the Digitization of the industry especially because unlike measurements got from production logging or well testing, the meters are permanently installed and constantly providing data.Within the metering industry, wet-gas metering is often considered less challenging than liquid-dominant multiphase flow metering.Perhaps because of this perception, most wet-gas meters today are based on simple differential pressure devices.There is a trust deficit between the wet-gas meters and reservoir management as the meters are known to provide a Volume of data but their Veracity and hence their Value may be limited.
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Document ID:
38255E2D
From Tie Back To Allocation Business: A Prerequisite Is To Understand The Different Methods And Their Impacts For Fair Trade
Author(s): Dr. Bruno Pinguet, Anna Pieper
Abstract/Introduction:
Flowrate measurements are essential to the oil and gas industry for quantifying and optimizing the production but also for taxation, custody transfer, allocation, reservoir management, well testing, environmental reporting purpose. A given flowrate measurement is entirely and correctly defined if, and only if, it is accompanied by its associated uncertainty. The uncertainty is the degree of doubt about measurement,and it is related toa confidence interval to represent the likelihood that the real value of the measurement is within a specified interval. A reported measurement should specify these 3 quantities: the reading, the associated uncertainty, and the confidence level,but this is far to be the standard practice in the oil and gas industry. Today with roughly 100million BOPD,this is a business value of roughly 6Bn per day, and an error of 0.1% leads to more than 2Bn revenue per year,which can be a gain or loss during the trading among the partners.To trade successfully,companies must have a regulatory framework based on measurement confidence or uncertainty,but examples often are forgetting that allocation is also versus the quality of the produced fluids and final mixed product. A 30API and 45API oil have not the same value for a given volume,and this needs to be considered.The paper is proposing thru simple examples to show the impact of the allocation for a given hypothetical field either based on proportional based allocation, uncertainty-based allocation, and by value adjustment.When the uncertainty in a measurement is adequately assessed and stated, the fitness for the measurement can be proven and judged, and the allocation process should reflect such effort in obtaining the lowest uncertainty value. These scenarii will show how the production reconciliation can be drastically different for the different end-users and how important this should be understood clearly and applied adequately for fairness in business.
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Document ID:
A70996BF
When By-Difference Allocation Is The Best Choice
Author(s): Astrid Marie Skalvik, Ranveig Nygaard Bjrk, Eivind Nag Mosland
Abstract/Introduction:
It is often assumed that pro rata allocation is always superior to by-difference allocation in terms of uncertainty. In this paper, it is shown that for some combinations of production and gas lift rates, by-difference allocation may result in uncertainties significantly lower than pro rata allocation. The objective of this work is to show how the total economic risk obtained by different allocation methods heavily depend on the production profiles. It is focused upon the importance of gas lift and gas production rates. The aim is to establish some useful rules of thumb to identify cases where the uncertainty of an input parameter/measurement is amplified (through the sensitivity coefficients) to such an extent that the calculations would have been more accurate if the measurement had been omitted. Such measurements will increase the allocation uncertainty and thus the financial risk of loss related to misallocation, even when the cost of collecting the information is not included.Analytic equations, which may be used to estimate the allocation uncertainty and thus the economic risk for different allocation principles and production profiles, are presented. Based upon the analytical equations, it is demonstrated how different allocation principles (pro rata vs by-difference) may be optimal for different sets of realistic production profiles.
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Document ID:
BCF01925
Assessment Of Allocation Systems: Combining Data Validation & Reconciliation Scheme And Pvt Simulations
Author(s): Dennis Van Putten, Lennart Van Luijk , Izwan S A Wahab, Siti F B Johari
Abstract/Introduction:
Allocation methods are applied in the oil and gas industry to compensate for the imbalance in measurement systems. Reconciliation of the measured values is possible if redundancy in the measurements is present. Different approaches to resolve this imbalance are designed 1and the choice of the allocation method depends on the agreement between the stakeholders. The need for more fair allocation methodologies is increasing nowadays due to the fact that accurate metering at every relevant element of a production facility is either very expensive or physically (near to) impossible, taking into account recent trends such as deep-water field development, use of subsea production systems, enhanced oil recovery and tie-backs of pipelines from satellite fields. This leads to the sharing of production or transport facilities and meters for different wells, which in turn leads to more complex allocation systems 5. The industry is driving towards more efficient operation which leads to more small field tie-ins in existing allocation systems. The same cost efficiency may lead to the choice of the operator to omit metering or use alternatives like virtual flow metering 4. Also, more small-size operating companies are buying (depleting) fields from larger operating companies, leading to more stakeholders in an allocation system. Change in the allocation procedure, the number of stakeholders or the operating conditions in an allocation system, requires an assessment on the procedures in place to critically evaluate the impact on the stakeholders such as Finance, Operations, Facilities Engineers and Reservoir Engineers. For increasingly complex production systems, the traditional allocation processes appear to be less suitable and an alternative methodology is required.
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Document ID:
AF5C771C
Data Reconciliation In Microcosm Reducing- DP Meter Uncertainty
Author(s): Allan Wilson, Phil Stockton, Richard Steven
Abstract/Introduction:
The hydrocarbon production industry runs large complex pipework systems with numerous and varied equipment such as multiple valves, pressure and temperature sensors, flow meters etc. However, due to the inherent uncertainty in each equipment setting and instrumentation output, the resulting massed raw data can be somewhat inconsistent. As such industry applies Data reconciliation techniques on the macro overall pipe system. Such techniques involve mathematical procedures that combine a pipeworks multiple instrumentation readings, equipment settings, associated uncertainties, and governing physical laws, to automatically validate data and reconcile measurements such that the whole makes physical sense. The technique can improve best estimates of not just measured system variables but even unmeasured variables. The technique transforms raw and sometimes inconsistent data sets into a single consistent data set representing the most likely truth.In this paper,the technique often applied on this macro scale,is introduced to the micro scale of an individual meter system. In the macro scale data reconciliation, the flow meter system is treated like any other instrument output, i.e. as a single node, a single point measurement. There has not been any attempt to take a flow meter designs sub-systems and develop mathematical techniques specifically tailored to the internal operation of that specific metering system for the purpose of improving that the individual flow meters performance, for all the advantages that would entail.
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Document ID:
E7C4DEC3
An Intercomparison Between Primary High-Pressure Gas Flow Standards With Sub-Permille Uncertainties
Author(s): Jos G.M. Van Der Grinten, Arnthor Gunnarsson, Mijndert Van Der Beek, Bodo Mickan
Abstract/Introduction:
Currently, state-of-the-art commercial calibrations of high-pressure gas flowmeters are performed with uncertainties that range between 0.13% and 0.25%, depending on pressure and flowrate.These measurement capabilities are traceable to primary standards using several steps in which the flowrate range and pressures are increased. For the primary high-pressure calibration facilities in Western Europe these traceability chains are described in 1. In France a pVTt tank is used, in The Netherlands, Germany and Denmark piston provers are used. The National Metrology Institutes and Designated Institutes of these countries cooperate with the high-pressure calibration laboratories in the EuReGa consortium (European References for Gas). Every three years, after recalibration of the participants high-pressure gas flow laboratories, EuReGa organises an intercomparison at the level where commercial calibrations are performed. These results are used to average the traceability chains of the laboratories, which also results in lower uncertainties. This process is called harmonisation and the procedure and data processing is described in 2.The results of the harmonisation exercises are reported by EuReGa 3. In the past 20 years of harmonisation the differences between the laboratories have diminished and the uncertainties have improved 2.After the success of20 years of intercomparisons, EuReGa extends the intercomparisons to the level of the primary standards. These are operated with sub-permille uncertainties, i.e. with expanded uncertainties (??2) better than 0,1%. Unfortunately, the French colleagues cannot participate. Their primary pVTt tank operatesat variable pressure. For the pVTt tank critical flow Venturi nozzles (sonic nozzles) are suitable as intercomparison devices as their mass flowrate does not depend on the downstream pressure. An intercomparison between LNE-LADG, PTB, NIM and NIST using sonic nozzles4, demonstrated the equivalence of the French and the German primary standards.The two DN100 turbine gas meters used in this comparison have been used in previous EuReGa intercomparisons. The last time in 2017 -20183. In this paper these results will be compared with the present results utilising piston provers.
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Document ID:
C481431B
Production Optimisation For Improved Field Management By Continuous Well Monitoring
Author(s): Andrew W. Jamieson, Ukedirin J. Abamwa
Abstract/Introduction:
This paper aims to promote better management of oil wells and oil fields. Monitoring and measurement of oil well production has always been challenging. Reasonable estimates of well production are essential for day-to-day reporting and production programming. Reservoir engineers need them for many aspects of field management, for example, updating reserve estimates, planning field extensions and deciding when to apply enhanced recovery processes. Well flowrates are required by production chemists to set the correct concentration of injected chemicals such as corrosion or hydrate inhibitors, demulsifiers, among others. These flowrates are also required for effective sand management.However, when confronted by volatile oil prices, demands to cut operating costs, changes in ownership of assets and, indeed, short-sightedness by management in the face of these demands, appropriate monitoring of well production is often neglected. Every now and then spectacular examples of the consequences of such neglect hit the headlines. In 2004 Shell admitted to overestimating its reserves by some 20%, leading to a sharp fall in its share price and litigation entailing huge fines, costs and compensation claims that lasted for years afterward. In the 2010 Deepwater Horizon oil spill in the Gulf of Mexico, initial flowrate estimates varied from the BP figures of 1000-5000 bbl/day to the Flow Rate Technical Groups figure of 62,000 bbl/day. It is evident that not knowing the flowrate was significant in the litigation and costs that followed. But there are far more mundane examples where poor production measurements lead to large revenue losses that are not really noticed.We discuss conventional well test methods and illustrate that they often cannot give accurate estimates of well production. We point out that continuous well monitoring is more and more being recognised as a better alternative. We give examples of the demonstrable benefits such as optimised production, predictive well maintenance and increased revenues.Sadly we concede that despite the clear evidence that continuous monitoring gives significant benefits, there is little apparent active interest from the industry worldwide. We ask why is there such an inconsistency, but we are unable to give good explanations.
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Document ID:
D6EA096D