Multiphase metering technology has advanced significantly in recent years, as has the acceptance and utilisation of such technology offshore. Dr David Stewart, NEL's multiphase flow services manager, reviews the current state of play and highlights the developments and challenges ahead.
Many new field developments are economically marginal and cannot sustain the financial implications of the traditional separatorbased technology. Multiphase meters can offer significant cost savings by eliminating the need for separators, or by allowing several fields to share common processing facilities.
In well management applications, multiphase meters offer continuous data output giving valuable information about the performance of wells. This enables problems or changes in well performance to be detected sooner, and subsequent decisions to be made earlier than would be possible with traditional processing technology.
The importance of multiphase metering is evident in the number of papers published on the subject and the time devoted to it at major flow measurement and oil and gas conferences. This was the case at October's North Sea Flow Measurement Workshop, a major event organised by NEL which attracted over 250 engineers from the oil and gas industry.
In-line multiphase meters
In-line multiphase meters rely on a number of fluid property measurements combined to give the flowrate of each of the three phases, oil, water, and gas. There are several techniques employed, although these can be grouped into two key areas - velocity or total flow measurement and phase fraction measurement.
Velocity/flow measurements are most commonly achieved using a differential pressure measurement or cross correlation of a particular signal, ie pressure or conductivity. Many meters also use slip models, which accounts for the fact that the gas generally travels faster than the liquid. Some in-line meters try to minimise slip by trying to homogenise the flow using a blind tee upstream of the meter with the meter installed in a vertical upwards flow direction.
The phase fractions can be determined from measurements of physical properties of the three-phase mixture from which the relative quantities of each individual phase can be deduced.
Gamma energy attenuation is a common method, where the oil, water and gas attenuate the gamma energy by different amounts. The gamma energy is emitted at two energy levels, as the high energy level is more sensitive to the gas/liquid ratio and the lower energy is more sensitive to the water/oil ratio in the liquid phase. Combined, the two energy attenuation measurements can be used to determine the phase fraction of all three phases. A third energy level can also be used to determine the salinity of the water phase.
The capacitance/conductance technique can be used to determine the water cut in the liquid phase. In oil continuous flow a capacitance sensor is used to measure the dielectric constant of the fluid and determine the water cut. In water continuous flow a conductance sensor is used. This approach can be good at high gas volume fractions. The disadvantages are that if the fluid is continually switching between oil continuous and water continuous the meter can find it difficult to track the changes.
Microwave attenuation can also be used to measure the water cut in the liquid phase. This has the benefit of being less sensitive to GVF and works in both oil and water continuous flows.
Many years of testing at NEL and in the field has shown that in-line meters can achieve accuracies of between 2.5% and 10% at best on each phase at certain conditions, although performance can vary significantly with GVF and water cut. Other parameters such as pressure, liquid viscosity and water salinity can also significantly affect the performance.
Separation based meters
Separation based meters or systems can employ various degrees of separation, but most use compact separators to achieve partial separation. This results in a predominantly liquid stream containing up to 30% gas by volume and a gas stream usually containing no more than 1% or 2% liquid by volume, but can in extreme cases, particularly in heavy slug flow, contain up to 10% liquid by volume.
Generally, compact cyclone separators are used for the separation, with the liquid level adjusted using flow control valves on the inlet and outlets. Most separation-based meters use a standard in-line multiphase meter on the predominantly liquid stream and a standard gas meter, such as a vortex or Coriolis meter, on the gas stream. If there is a high liquid content in the gas stream a wet gas meter that is capable of measuring both liquid and gas flowrates can be used.
Tests in recent years, again at NEL and in the field have shown that separation based systems can achieve better than 5% accuracy on each phase and are less affected by GVF than in-line meters. The main disadvantages are the size, weight and reliance on fast acting valves for level control in the separator. This can make them unsuitable for subsea applications.
Performance verification
The discussion regarding the most suitable means of verifying multiphase meter performance has continued for many years. The simplest option is to do nothing and hope the meter performs. Given the complexity of the instrumentation and software and, depending on the application, the potential financial implications of meter errors or failure, this approach is not recommended.
The next option is to rely on a basic functionality test carried out by the meter vendor. This could be as simple as confirming that the meter can recognise static samples of oil, water and gas, or could involve a more involved flow test using the vendor's flow facility. Many users are understandably reluctant to accept such tests as proof of performance due to the lack of independence.
Consequently, it is common to conduct a flow test at an independent test facility. NEL has carried out many such acceptance tests over recent years for many clients in its multiphase flow test facility. This facility was purpose built just over ten years ago for multiphase meter evaluation and testing. The advantage of a trusted independent facility is that the reference metering will be accurate and fully traceable and that the independent organisation has no affiliation to either the vendor or the end user.
There is also the debate over what type of test fluids to use. The use of 'dead' fluids where the gas does not dissolve in the oil and there is no phase change with pressure or temperature is the practice at NEL, with the advantage that it allows NEL to achieve low uncertainties on the reference flowrates. Some argue that the disadvantage is that the fluids do not replicate those in the field.
The use of 'live' crude oil and natural gas is more realistic but means that the gas is highly soluble in the oil, making reference metering difficult. If the test meter is at a different pressure and/or temperature from the reference meters then the gas can go into or come out of solution with the oil. This change in phase fraction within the test facility must be accounted for by either complex physical PVT analysis of the oil and gas, or by modelling the PVT behaviour if the fluid properties are known. Either way, the inevitable result is a higher uncertainty in the reference flowrates.
It is also common to verify a meter offshore against a three-phase test separator when such facility exists. This does have the advantage of testing the meter in its intended installation using the fluids it will be metering in practice. However, the significant disadvantage of this approach is the potentially high uncertainty in the reference flowrates. The separator performance can have a major effect on the metering accuracy. Liquid carry over or gas carry under, resulting from poor separation, can result in large errors in the liquid and gas flowrates, in addition to the added uncertainty of using live fluids.
These issues are discussed in a paper from the recent North Sea Flow Measurement Workshop, which describes the meter selection and verification process for three multiphase meters for Kerr-McGee North Sea (UK). In this one meter was verified at NEL and subsequently against the test separator offshore. The other two meters were tested using live fluids at ChevronTexaco's Humble facility with NEL acting as independent witnesses.
Multiphase meter challenges
The challenges for multiphase metering at present are several. Cost reduction is a key aim as some of the meters on the market are very expensive. Another paper from the North Sea Flow Measurement Workshop, presented by Shell, highlighted this fact, discussing the desire for a multiphase meter per well for improved well management. At present most multiphase meters are too expensive for this to be a real consideration, however the paper highlighted work that Shell has been doing in conjunction with a manufacturer of a low cost meter that could be considered for 'per well' metering.
A key aspect was this meter's lack of a nuclear source for density measurement. In many parts of the world such sources are either not allowed, or simply not desirable due to the risk of sabotage. An upcoming NEL research project, funded by the UK's DTI, will investigate the suitability of an ultrasonic based multiphase meter.
Improved accuracy is obviously another key aim, as an increasing number of applications will call for multiphase meters to be used for allocation purposes between different oil companies. In such cases the uncertainty in the oil phase, and possibly gas phase would be critical.
A slightly longer term challenge is the development of downhole meters. These meters would operate in the actual well and provide valuable information on which areas of the well are producing which fluids. This would enable improved well management and faster, more accurate decisions regarding well production. Several manufacturers are actively developing downhole meters at present. The key issue for such meters is reliability in an extreme environment.
Source: OilOnline.com - View Original Article
Many new field developments are economically marginal and cannot sustain the financial implications of the traditional separatorbased technology. Multiphase meters can offer significant cost savings by eliminating the need for separators, or by allowing several fields to share common processing facilities.
In well management applications, multiphase meters offer continuous data output giving valuable information about the performance of wells. This enables problems or changes in well performance to be detected sooner, and subsequent decisions to be made earlier than would be possible with traditional processing technology.
The importance of multiphase metering is evident in the number of papers published on the subject and the time devoted to it at major flow measurement and oil and gas conferences. This was the case at October's North Sea Flow Measurement Workshop, a major event organised by NEL which attracted over 250 engineers from the oil and gas industry.
In-line multiphase meters
In-line multiphase meters rely on a number of fluid property measurements combined to give the flowrate of each of the three phases, oil, water, and gas. There are several techniques employed, although these can be grouped into two key areas - velocity or total flow measurement and phase fraction measurement.
Velocity/flow measurements are most commonly achieved using a differential pressure measurement or cross correlation of a particular signal, ie pressure or conductivity. Many meters also use slip models, which accounts for the fact that the gas generally travels faster than the liquid. Some in-line meters try to minimise slip by trying to homogenise the flow using a blind tee upstream of the meter with the meter installed in a vertical upwards flow direction.
The phase fractions can be determined from measurements of physical properties of the three-phase mixture from which the relative quantities of each individual phase can be deduced.
Gamma energy attenuation is a common method, where the oil, water and gas attenuate the gamma energy by different amounts. The gamma energy is emitted at two energy levels, as the high energy level is more sensitive to the gas/liquid ratio and the lower energy is more sensitive to the water/oil ratio in the liquid phase. Combined, the two energy attenuation measurements can be used to determine the phase fraction of all three phases. A third energy level can also be used to determine the salinity of the water phase.
The capacitance/conductance technique can be used to determine the water cut in the liquid phase. In oil continuous flow a capacitance sensor is used to measure the dielectric constant of the fluid and determine the water cut. In water continuous flow a conductance sensor is used. This approach can be good at high gas volume fractions. The disadvantages are that if the fluid is continually switching between oil continuous and water continuous the meter can find it difficult to track the changes.
Microwave attenuation can also be used to measure the water cut in the liquid phase. This has the benefit of being less sensitive to GVF and works in both oil and water continuous flows.
Many years of testing at NEL and in the field has shown that in-line meters can achieve accuracies of between 2.5% and 10% at best on each phase at certain conditions, although performance can vary significantly with GVF and water cut. Other parameters such as pressure, liquid viscosity and water salinity can also significantly affect the performance.
Separation based meters
Separation based meters or systems can employ various degrees of separation, but most use compact separators to achieve partial separation. This results in a predominantly liquid stream containing up to 30% gas by volume and a gas stream usually containing no more than 1% or 2% liquid by volume, but can in extreme cases, particularly in heavy slug flow, contain up to 10% liquid by volume.
Generally, compact cyclone separators are used for the separation, with the liquid level adjusted using flow control valves on the inlet and outlets. Most separation-based meters use a standard in-line multiphase meter on the predominantly liquid stream and a standard gas meter, such as a vortex or Coriolis meter, on the gas stream. If there is a high liquid content in the gas stream a wet gas meter that is capable of measuring both liquid and gas flowrates can be used.
Tests in recent years, again at NEL and in the field have shown that separation based systems can achieve better than 5% accuracy on each phase and are less affected by GVF than in-line meters. The main disadvantages are the size, weight and reliance on fast acting valves for level control in the separator. This can make them unsuitable for subsea applications.
Performance verification
The discussion regarding the most suitable means of verifying multiphase meter performance has continued for many years. The simplest option is to do nothing and hope the meter performs. Given the complexity of the instrumentation and software and, depending on the application, the potential financial implications of meter errors or failure, this approach is not recommended.
The next option is to rely on a basic functionality test carried out by the meter vendor. This could be as simple as confirming that the meter can recognise static samples of oil, water and gas, or could involve a more involved flow test using the vendor's flow facility. Many users are understandably reluctant to accept such tests as proof of performance due to the lack of independence.
Consequently, it is common to conduct a flow test at an independent test facility. NEL has carried out many such acceptance tests over recent years for many clients in its multiphase flow test facility. This facility was purpose built just over ten years ago for multiphase meter evaluation and testing. The advantage of a trusted independent facility is that the reference metering will be accurate and fully traceable and that the independent organisation has no affiliation to either the vendor or the end user.
There is also the debate over what type of test fluids to use. The use of 'dead' fluids where the gas does not dissolve in the oil and there is no phase change with pressure or temperature is the practice at NEL, with the advantage that it allows NEL to achieve low uncertainties on the reference flowrates. Some argue that the disadvantage is that the fluids do not replicate those in the field.
The use of 'live' crude oil and natural gas is more realistic but means that the gas is highly soluble in the oil, making reference metering difficult. If the test meter is at a different pressure and/or temperature from the reference meters then the gas can go into or come out of solution with the oil. This change in phase fraction within the test facility must be accounted for by either complex physical PVT analysis of the oil and gas, or by modelling the PVT behaviour if the fluid properties are known. Either way, the inevitable result is a higher uncertainty in the reference flowrates.
It is also common to verify a meter offshore against a three-phase test separator when such facility exists. This does have the advantage of testing the meter in its intended installation using the fluids it will be metering in practice. However, the significant disadvantage of this approach is the potentially high uncertainty in the reference flowrates. The separator performance can have a major effect on the metering accuracy. Liquid carry over or gas carry under, resulting from poor separation, can result in large errors in the liquid and gas flowrates, in addition to the added uncertainty of using live fluids.
These issues are discussed in a paper from the recent North Sea Flow Measurement Workshop, which describes the meter selection and verification process for three multiphase meters for Kerr-McGee North Sea (UK). In this one meter was verified at NEL and subsequently against the test separator offshore. The other two meters were tested using live fluids at ChevronTexaco's Humble facility with NEL acting as independent witnesses.
Multiphase meter challenges
The challenges for multiphase metering at present are several. Cost reduction is a key aim as some of the meters on the market are very expensive. Another paper from the North Sea Flow Measurement Workshop, presented by Shell, highlighted this fact, discussing the desire for a multiphase meter per well for improved well management. At present most multiphase meters are too expensive for this to be a real consideration, however the paper highlighted work that Shell has been doing in conjunction with a manufacturer of a low cost meter that could be considered for 'per well' metering.
A key aspect was this meter's lack of a nuclear source for density measurement. In many parts of the world such sources are either not allowed, or simply not desirable due to the risk of sabotage. An upcoming NEL research project, funded by the UK's DTI, will investigate the suitability of an ultrasonic based multiphase meter.
Improved accuracy is obviously another key aim, as an increasing number of applications will call for multiphase meters to be used for allocation purposes between different oil companies. In such cases the uncertainty in the oil phase, and possibly gas phase would be critical.
A slightly longer term challenge is the development of downhole meters. These meters would operate in the actual well and provide valuable information on which areas of the well are producing which fluids. This would enable improved well management and faster, more accurate decisions regarding well production. Several manufacturers are actively developing downhole meters at present. The key issue for such meters is reliability in an extreme environment.
Source: OilOnline.com - View Original Article
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