RESERVOIR MONITORING: Multiphase meter on unmanned wellhead platform replaces test separators

The skid mounted multiphase meter.

At the beginning of the 1990s, a major research and development project to extend the capabilities of multiphase export was launched. This program included the simultaneous development of multiphase flow modeling, multiphase technology (qualification of multiphase pumps, development of multiphase meters, and subsea separation), and a new process to fight fluid-related effects such as hydrates, waxes, and others.

The initial aim was to simplify surface topside facilities, and to avoid installation of separators, pumps, compressors, and safety/flaring systems. In a second stage, this technology could be subsea deployed. The development of these different disciplines would help to avoid duplicate processing and huge infrastructures, and would ease remote controlled operation of unmanned platforms. The multiphase meter was one component of this global approach.

From 1991 to 1996, TotalFinaElf supported and tested multiphase meter prototypes. These were qualified on onshore fields. The application of an integrated multiphase approach to develop a Middle East offshore field reduced the investments and operating costs drastically.

In such a development, the multiphase meter found its place by eliminating the need for a dedicated testing flowline or a test separator and flaring system. Therefore, in 1997, their first multiphase meter on an offshore-unmanned wellhead platform was installed.

Meter application

The decision to use a multiphase meter was made in 1994-1995. Very few fields relied on a multiphase meter for well testing, without it being backed up by a test separator. The field layout comprises wells that are clustered on a wellhead platform. The production is sent to shore through a 40 km line. After separation, the oil is metered before custody transfer, which yields an excellent reference measurement.

The platform is unmanned. It has minimum facilities - production manifold, test manifold, and multiphase flowmeter (MPFM) 1900VI. The local operator interface of the meter is housed in the electrical room. The readings from the meter are also available onshore, through a low baud rate communication that carries all the control signals for the platform. The valves of the test manifold are not equipped with actuators.

Benefits

The field comprises several wells that are clustered on a wellhead platform. The production is sent on shore by a 40 km pipeline.

Monitoring of the multiphase flow at the wellhead eliminates the need for dedicated test lines from remote wellhead completions, as well as the need for a dedicated test separator at the processing facility. The meter replaces a test separator in its functionality.

A MPFM at the wellhead allows improved well control, hence better reservoir monitoring and well performance management. It is clear that extra information could be gained from the instantaneous feature of the measurement. For example, water slugs and gas slugs appear clearly in the readings of the remote wells. Continuous readings, instead of accumulated quantities given by test separator, will allow diagnostics of well behavior, and total recovery would probably be increased.

The capital expenditure savings have been estimated at US$800,000, compared to a test separator solution. In this application, the main savings came from the fact that the device saved the cost of the flare. The platform has no vessels to blow down.

This device helps in cutting operating expenditures as well. Despite the manually operated valves of the manifolds, it is possible to have each well tested monthly with only one visit per week. During a one-day visit, the production operator can test 2-3 wells, thanks to the short stabilization time of the meter. When leaving, the operator launches a 'long' test that will last until the next visit. A remote display allows for further analysis of the behavior of a given well. From a maintenance point of view, the meter is a low maintenance cost item, compared to a test separator.

Description

The multiphase meter is basically an instrumented pipe section, approximately 1.4 meters long, and consists of a capacitance sensor, an inductive sensor, a gamma densitometer, and a venturimeter. In addition, there is a flow computer and a service console.

The multiphase meter used for this application is basically an instrumented pipe section, approximately 1.4 meters long, and with an internal diameter of 3 in. No separation and mixing is involved. The meter has been supplied as skid mounted, complete with inlet and return piping, with drain, vent, and drip tray for ease of calibration.

In order to limit any potential for clogging by wax and other materials within the meter itself, or in the pressure and differential pressure impulse lines, the complete instrumented pipe section has been heat-traced and lagged.

The multiphase meter is a Fluenta MPFM 1900VI, and consists of a capacitance sensor, an inductive sensor, a gamma densitometer, a venturimeter and a flow computer. The measurement principle is first to measure the density of the flow using a gamma densitometer. In oil-continuous flow (up to 60-70% water cut), the density measurement is combined with a measurement of the dielectric constant of the flow using the non-intrusive, surface plate, and capacitance sensor. Together, these two measurements provide the instantaneous composition of the flow at the measurement location.

At higher water cut, when water is the continuous liquid phase, the mixture conductivity is measured using an inductive type sensor. This then replaces the capacitance measurement in the composition calculation.

The velocity of the flow is determined by cross-correlation between different electrode pairs in the capacitance sensor. The cross correlation velocity may also be combined with the venturi meter, which extends the range of the multiphase meter to cover single phase liquid and annular flow, and also add redundancy to the velocity measurement in the intermediate range of gas volume fraction (GVF).

By combining both the compositional and the velocity information of the flow, the actual flow rates of oil, gas and water are determined by mathematical models hosted in the flow computer. The interphasial slip between liquid and gas is handled using the Dual Velocitytrademark method. This method is capable of handling complex flow regimes, including severe slugging, in-homogeneous phase distribution, and interphasial slip.

The non-intrusive design, together with the Dual Velocity method for handling phase slip, means the Fluenta multiphase meters do not require mixers to homogenize the flow, or a separator to split the flow, before measurement. This gives the meter a wide operating range, which is not limited by the efficiency of the upstream flow conditioner or splitter. Due to the limited interaction with the flow, pressure drop, erosion, and creation of emulsions that may otherwise affect the downstream process, are avoided.

Operational experience

The MPFM 1900VI was offshore commissioned in early 1997. Fluenta carried out this job with assistance from in-house specialists, especially for fluid parameters (oil and water density) determination. The duration of the commissioning/startup phase was about 10 days including training for the operators.

No test separator was available on the offshore platform for testing and verification. A static calibration procedure has been defined and implemented. This has been successfully applied to the meter to check the meter and make diagnostics. The procedure involves isolating the meter, emptying it and filling it with air, oil, and seawater. Since the fluid properties are known, this makes it possible to check the static response and calibration of the capacitance sensors, inductance sensor and gamma meter.

The MPFM is continuously in operation. During the weekly visit, wells to be tested are switched through the meter. A well test takes about one hour, and all the tests are validated before being entered into the database. In between weekly visits, the MPFM is left under flowing conditions with one well producing through the meter.

The man machine interface allows simple operation of the system. No systematic maintenance is carried out under normal operation. Verification of performance is done through regular follow up and comparison between well figures and total production.

The manufacturer has been called out once a year for calibration, and once for replacement of a display monitor and an electronic card on the inductive sensor. In four years, three interventions have been carried out by the manufacturer, mainly for capacitance and inductance sensors calibration.

The system has been operating successfully during four years without any problems. No failure has been recorded on sensors. The availability has been 100% since startup. The meter has been used during a short period of time only for liquid and gas measurements, due to a bias in the water cut measurement generated by incorrect water cut setting.

This indicates that care must be taken when calibrating MPFM with field measurements, which are not necessarily representative. This also indicates that even in such a case, the system still continues to provide data before reconfiguration or recalibration of some sensors.

The meter has been used for continuous recording of flow rates, gas fraction, and water hold up of wells for well behavior monitoring or for individual well test for reservoir management. Accuracy of the meter has been checked by both daily and monthly comparison with terminal figures. MPFM figures for oil and water have been in good agreement (average of less than +/-5% for oil, and +/-10% relative for water) with fiscal figures. Yearly figures show a difference of less than 1% between reference figures and multiphase meter figures.

Conclusion

The decision to install a multiphase flow meter instead of a test separator was governed by the low cost of such a development compared to alternative solutions. We have to recognize that the qualification was still in its final phase when the decision was made. The deployment of this equipment has allowed the unmanned operation of this platform. This technology has allowed a step-by-step approach. Today, additional multiphase flow meters have been ordered in the frame of an extension of the development.

Compared to the results we are accustomed to getting from a test separator, the figures, which are delivered by this equipment, are in the same range of accuracy. Furthermore, the detailed analysis of the gas/water/oil fraction distribution allows better knowledge of the flow conditions in the gathering system and in the flowlines. During transient operations (mainly startup operations), the increase of the water cut allows us to improve our understanding of the well near the well bore.

On this field, the deployment of a multiphase meter has contributed in improving the economy of the full project and improving our understanding of the hydrodynamics of the reservoir near the wellbore.

This experience demonstrates that the MPFM can be a very reliable solution for well testing and well monitoring; nevertheless success requires involvement of all people (project people, specialists, users) from design studies to operations. Also, support of manufacturers and a mutual understanding are key issues. Four years life time without failure shows that multiphase metering is now compatible with very demanding subsea and high water depths applications (sequences, tests, long term checks, cost impact).

References

Leggett B. et. al, "Multiphase Flow Meter Successfully Measures Three-Phase Flow at Extremely High Gas Volume Fractions - Gulf of Suez, Egypt," SPE 36837.
Caetano, E., Pinheiro, J., Moreira, C., Farestvedt, R., "MMS 1200 - Cooperation on a Subsea Multiphase Meter Application," OTC 8506.
Slater, S., Paterson, A., Marshall, M., "The development and use of a subsea multiphase flowmeter on the South Scott Field," OTC 8549.
Razali I., "Multiphase metering in Malaysia - Current and Future," 4th Annual International Conference - The future of multiphase metering.
Perry, D., Mitchell, M., Halvorsen, M., "Application of the First Multiphase Flow Meter in the Gulf of Mexico," SPE 49118.
Dykesteen, E., "Comparison of experiences from Multiphase Metering in different operations," IBC 1999.
Egner, E., Kalsaas, O., "Operational experience with multiphase meters at Vigdis," North Sea Flow Measurement Workshop, 1999.
Caetano, E., Dykesteen, E., "Operational experience with subsea multiphase meter," North Sea Flow Measurement Workshop, 2000.

Editor's Note: This is an updated and summarized version of OTC 13220, presented at the Offshore Technology Conference in Houston, Texas, May 2001.

 

Source :Offshore-Magazine

Present Status of MultiPhase Metering in Oil and Gas Industry

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

Meters, sampling critical for effective multiphase flow management

Understanding measurement methods is necessary for good design

Flow assurance is recognized as hugely important for the transportation of hydrocarbon fluids, since failures can be extremely costly to fix and can cause safety issues. In particular, flow assurance is vital for multiphase flows of oil, gas, and water mixtures.

The industry is trending towards the use of multiphase meters to measure these types of flow. Multiphase meters bring advantages such as lower capital and operational expenditure, increased capability to monitor individual wells in real time, reduced need for test separators and associated maintenance, and minimal loss of production through well shutdowns during tests.

For subsea activities, installing multiphase meters can provide further benefits such as a reduction in required piping infrastructure, and the capability to install meters on each well to continually monitor production. It also allows different operators to share pipeline systems, reducing cost and disruption, as individual well production can be metered before commingling.

In the majority of cases, multiphase meters' performance and accuracy depend on the accuracy of the fluid properties data employed for flow calculations. Pipeline fluid sampling of multiphase flows has become essential to ensure these data are accurate. Inaccurate mismeasurements can lead to large financial losses, misallocation of fluids, and exposure to increased flow assurance risks. Ideally, the industry would prefer multiphase flow measurement technology to be less sensitive to fluid properties.

NEL's flow measurement facility in East Kilbride, UK.

Sampling is used to determine the composition of pipeline fluids and fluid properties for multiphase metering, and can identify the presence of components that could cause flow assurance issues such as build-up of deposits of scales and waxes in the line. Subsea sampling systems are now being developed, even though each subsea sample can cost as much as £500,000 (nearly $765,800). The reason is that the pay-offs can be worthwhile.

While early identification of flow assurance issues is crucial, cost and time associated with obtaining fluid samples can be significant too. Subsea sampling systems are being installed because the fluids obtained are representative of what is passing through the meter; whereas collecting fluid samples topside may not be. One reason is that organic components such as paraffins and asphaltenes may be deposited along the pipeline before the topside sampling position. Also, inhibitors may be injected after the meter, affecting the fluid properties in the collected sample; topside, the samples will be collected under different conditions, such as temperature and pressure.

Looking into the causes

Numerous factors need to be considered for multiphase and wet gas flow metering, including blocked impulse lines and deposits of solid material. Meters with moving parts can also become damaged by deposits and hydrate crystals.

For multiphase flows, issues include formation of waxes, hydrates, scales; restrictions and blockage of pipes; damage of equipment; and corrosion/erosion of pipe and equipment.

The design, modeling, and testing of subsea multiphase sampling systems has been crucial to eliminate the risk of failure to collect a sample. This failure can itself be caused by flow assurance problems such as blockages or formation of waxes and hydrates caused by temperature and pressure changes.

Hydrates are solid crystalline structures which are problematic because they can damage equipment and even block the whole pipeline. Hydrates forming in flow conditioners in gas pipelines can also affect the flow profile and the meter performance. Additionally, some oils contain wax molecules, which can in turn form wax particles at low temperatures, leading to deposition on the pipe wall or inside the meter. And, wax build-up can affect electrical detection of fluids; for example, if wax coats the electrodes in a multiphase meter.

Any type of deposit can lead to blockages in the pipe. If the multiphase flow meter has a Venturi tube (usually the case), this can also alter its dimensions, leading to errors and blocking of the line.

Scales are formed from inorganic chemicals present in the flow. While these can be treated using inhibitors, they are difficult to dislodge, and strong acids may be needed to remove them.

Blocked impulse lines for differential pressure type meters can be caused by hydrates, waxes and scales. Trace heating can be applied around impulse lines to limit the formation of hydrates and waxes, and many subsea meters use diaphragms at tappings to prevent build-up of solids. Operating temperature, pressure, and multiphase composition of the flow will determine whether asphaltenes also form, but unlike hydrates and waxes, these do not melt when heated.

Sand is undesirable in all types of flow, since it erodes pipe work, meters, valves, and other components. Unfortunately, there is no cure to combat such erosion, and once a component has become worn, the only option is to replace it.

While deposits of solid material can cause restriction of pipes and within flow meters, inhibitors injected into pipelines to mitigate flow assurance issues can also change the fluid properties and affect the meter response, if it relies on accurate fluid property data. Ideally, fluid sampling should be performed close to the meter to ensure the sample is representative of the fluid passing through it.

All this underlines importance of understanding the challenges of measuring individual components of multiphase fluids, as implementation is much more complex than metering the single phase components of just oil or water or gas.

Potential applications

Multiphase flow meters (MPFMs) can be applied to help predict flow assurance issues, production upsets, and changes. They principally operate by measuring the bulk flow rate of the multiphase mixture and calculating the individual phase fractions. These are then used to determine the flow rates of the individual streams within the mixture. Understanding the measurement techniques employed in a meter will help predict how it will be affected by flow assurance issues or changes in the fluid properties.

The following measurement techniques are commonly used in MPFMs.

Differential pressure meter

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Differential pressure (DP) meters can be used either to calculate the flowrate of the multiphase mixture or to calculate the density of the mixture. DP meters are extensively employed to meter wet gases, either by applying corrections to adjust for the presence of liquids or as part of a wet gas meter system.

Example of cross-correlation.

 Cross-correlation is where two sets of sensors look for correlated signals caused by flow disturbances such as slugs and bubbles. This does not work well in homogenous flow or where there is an emulsion, as by definition there is nothing to cross-correlate.

Electrical property measurements of the electrical impedance across the pipe can determine the electric properties of the multiphase mixture such as capacitance and conductance. Capacitance sensors work best in oil-continuous flow, while conductivity sensors work best in water-continuous flow. The results of these tests can then be used to determine the phase factions of the multiphase mixture.

Microwaves can be used in two ways to measure multiphase mixtures – resonance and absorption. Like electrical capacitance, microwaves exploit the difference in permittivity of the multiphase components to determine the individual phase fractions of the mixture.

Gamma ray attenuation.

Gamma ray attenuation is another option. The most common nuclear sources used are Barium 133, Caesium 137, and Americium 241. The number of gamma rays passing throughout the pipe depends on the composition of the multiphase mixture inside the pipe and therefore indicates the composition of the flow. For example, gas is a weak absorber of gamma rays, while water is a stronger absorber.

Partial separation combines the elements of MPFMs with separation techniques, and is particularly useful when the multiphase mixture has a high gas volume fraction greater than 95%. Partial separators employ a device that separates the gas and liquid streams to be measured.

Future hydrocarbon management

Flow assurance will continue to be important in hydrocarbon management, especially for multiphase flows. Use of MPFMs to monitor production and for allocation is set to continue due to the advantages and cost reductions that they deliver. However the complexity of these technologies also increases the cost of the meter, so meter longevity becomes critical, especially taking into account the additional cost of subsea meters and the associated issue of meter accessibility. There is a vicious circle, because while multiphase flow meters can be affected by existing flow assurance issues, they can also be used to identify potential flow assurance problems. Regular and representative fluid sampling is therefore essential for identifying flow assurance issues that may impact their reliability.

Source: Offshore-Mag.Com   -    View Original Article