Growth of Multiphase Meters and the Key Challenges they are Addressing

By - Vincent Vieugue,
Emerson Process Management

The Multiphase Meter Market Today

There is no doubt that the market for multiphase meters within the oil and gas industry is continuing to grow.

Douglas Westwood, for example, predicts that there will be one thousand additional subsea multiphase meters deployed by 2015 and many operators are continuing the rapid deployment of such meters – both subsea and topside. Examples include Petrobras, who have indicated that they would like to see a multiphase meter on each of their subsea wells and trees; and Statoil, one of the first users of the technology, which today has more than 150 multiphase and wet gas meters in operation.

Multiphase meters are today a vital component of operators’ development and field production plans. They can be used for production monitoring, individual well testing, production allocation and reservoir monitoring and they provide the operator with critical information on a well’s capabilities – information such as water saturation and break through, gas coning, permeability and flow characteristics.

Yet, there is plenty more room for growth. According to Rystad Energy Global, just 12% of global oil & gas production is currently facilitated by multiphase meters.

From 1st to 3rd Generation

In order to understand the current adoption of multiphase meters and their future potential, it is necessary to examine how they have developed. Multiphase meters have undergone a significant evolution since they first came on the market in the early 1990’s. The first commercial Roxar topside multiphase meter, for example, (launched in 1992) was based on microwave technology, operated on a single velocity basis, and assumed that homogenous flow and liquid and gas were travelling at the same speed.

In the early 2000’s, the second generation multiphase meters came to market (figure 1 shows a subsea version of the Roxar second generation meter). The meter allowed, for the first time, measurement of both liquid and gas velocities. The meter incorporated a Dual Velocity™ method with calculated phase fractions based on capacitance and conductivity measurements. The meter also came in combination with a single energy gamma densitometer and venturi section.

Other highlights of the second generation meter included parts designed to withstand more than 30 years of operating in harsh environments, power consumption at less than four times that of the first generation meter, and for subsea meters, a retrievable canister.

By this stage, the benefits to the operator were also clear. This included no separation requirements; no need for costly test separators; the instantaneous and continuous measurement of three phase rates – not just at a discrete point in time and not just for one well; and limited maintenance requirements. The result was substantial CAPEX/OPEX savings, increased well control, and enhanced production from the fields.

Changing Operator Needs

However, as multiphase meters continue to increase their market penetration, so do the challenges increase. Many oil & gas fields, for example, are more geologically complex, remote and heterogeneous than ever before. There is an even greater need for multiphase meters to generate accurate and reliable, real-time data from the wells to help diagnose and optimize the well’s performance and fend off flow assurance threats.

Such a need can’t necessarily be met by the second generation multiphase meter’s measurement principle which provides a simplification of complex flow patterns and is dependent on the reservoir being relatively homogeneous.

Secondly, the last few years have seen a growth in smaller fields (on average 200 to 300 million bbl) as well as brownfields. Only recently, Statoil announced that it is to focus further on brownfields to sustain production on the Norwegian Continental Shelf (NCS) at current levels.

Multiphase meters have an important role to play in brownfield developments in improving well testing in environments characterized by often complex interdependencies between aging and new technologies. There is also a subsequent need for an even simpler and compact meter design, which helps widen the operating envelope, increase flexibility, and lower the cost per meter.

Finally, there is the need to meet environmental and HSE requirements, particularly where the use of nucleonic sources is unacceptable, due to legislation or company policy. The ability for operators to forgo the nucleonic source within multiphase meters without forgoing accuracy remains a continuing challenge.

In summary, while second generation meters continue to be successful and effective, there is an increased onus on multiphase meters for even greater accuracy and a measurement principle that enables the operator to better handle complex, flow regimes and achieve maximum production rates.

There is also a need for multiphase meters to take on board environmental implications, widen the operating envelope, and operate at lower costs and in previously inaccessible locations.

The Third Generation Multiphase Meter

So how can the third generation multiphase meter (see figure 2) address these challenges?

The development of a new electrode geometry sensor for the meter, for example, can allow for measurements in separate sectors in addition to the full cross sectional area. This results in more combinations and more accurate fraction measurements and velocities for each segment.

Rather than being able to perform cross sectional measurements, the new measurement principle will allow the meter to perform both rotational near wall measurements and cross-volume measurements, thereby providing a comprehensive mapping of the flow regimes. Asymmetrical flow and less-than-perfect mixtures of the gas and dispersed phase can also be handled in a manner that was impossible with previous meters. The measurement principle is shown below in figures 3a and 3b (red indicates high sensitivity, blue indicates low sensitivity).

In this way, the operator can benefit from an accurate understanding of flow regimes, mixing effects and velocity profiles, and can detect rapid changes in compositon, thereby making the measurements more accurate and consistent than with other available technology.

There is also the potential for widening the operating envelope with the next generation of multiphase meters. This can be achieved through reduced height and weight, opening up substantial potential cost savings in terms of installation, maintenance and deck space.

Field Replaceable Insert Venturis also allow for extended service life and operating range, and can remove uncertainties in sizing meters based on uncertain production forecasts.

A meter with several Field Replaceable Insert Venturi sizes, for example, means that the optimal size can be selected for early life and replaced later with a different size in late production life. In this way, optimal performance from the venturi can be achieved.

Finally, there is the challenge of alleviating environmental concerns. To counteract concerns over nucleonic sources, non-radioactive meters can today cover the full operating range 0 -100% watercut and 0 – 95% GVF (gas volume fraction).

However, for those operators who are concerned with the limitations over the maximum GVF range or the slightly higher uncertainty than the gamma version, developments are underway in Emerson’s case to develop a densitometer based on X-rays as an alternative to the nucleonic gauge.

The X-ray based densitometer, known as FluorX and developed in conjunction with PANalytica, utilizes attenuation measurements of the same photon energies as a low energy gamma-ray source, and provides the same measurement accuracy. Adding a FluorX system to the non-gamma meter version means that the meter can be used in the full 0-100% GVF range and also ensures improved accuracy, as our tests have shown.

Much More to Come!

With the market for multiphase meters continuing to grow and the need for accurate flow measurement and a wider operating envelope as important as ever, it is imperative that today’s multiphase meters are able to meet operator challenges.

A new measurement principle, new electrode geometry and near wall measurements are ensuring that multiphase meters continue to evolve to meet such demands.

Such technical developments, as well as meeting environmental concerns through developments, such as the x-ray based densitometer, will ensure that multiphase metering becomes ever more prevalent – not just in well testing but in reservoir monitoring, flow assurance calculations, and production optimization.

Vincent Vieugue is Vice President of Sales & Marketing at Roxar Flow Measurement, part of Emerson Process Management.

Source - ROGTEC-Magazine   -   View Original Article

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

Commingled multiphase flows – the metering challenge

Metering and allocation of the oil and gas industry is more complicated than ever. Production flows are no longer straightforward. Instead, various streams made up of differing mixes of oil, water, and gas from different fields belonging to different operators and sometimes even under different tax regimes, are being commingled as an increasing number of marginal fields enter production.

A new approach to metering is required and “per-well” multiphase meters appear to be the best way. But, is the technology ready? Meter manufacturers believe so, but TUV NEL, which has performed independent testing of multiphase meters over the past 20 years, believes more testing and verification is required to give field operators the confidence and experience to meet their commitment to partners and regulatory bodies.

Most offshore fields developed 20 or 30 years ago were designed to cope with flow from a single field. While it always has been important to monitor individual well production, it generally has not been essential to know which well every single barrel of oil came from when it all belonged to one operator. However, when you add the complexities of multiple flows belonging to different operators, each with varying oil/water/gas mixes, things become much more complex.

The traditional approach to offshore multiphase flow metering has been to use a test separator and separate oil and gas flowmeters, with periodic testing of flows from each well. This is adequate to provide regular information about what each well is producing in terms of oil, water, and gas, but in terms of allocation, when every drop of oil counts, its suitability and applicability is questioned.

On a typical platform with 10 - 20 producing wells feeding into a single production separator, changes to a specific well’s production could remain unnoticed for weeks, even months, until the well flow takes its turn in the test separator. As more established offshore assets become production hubs for multiple fields, any undetected changes to flow rates, water, and gas content can have cost implications. For example, a sudden water breakthrough in a well which previously produced several thousand barrels per day could reduce revenues for all of the stakeholders and fiscal bodies, as well as financially affecting the operator of the facility.

What is really required is continuous, individual “per well” flow metering. Separation systems are costly, large, and heavy. It is not practical in terms of deck space or cost to have individual separation for each well, so multiphase metering has to be the way forward. However, uncertainty remains about the application, suitability, and performance of multiphase meters.

Multiphase metering – is it ready?

Multiphase flow measurement has been developing in the oil and gas industry over the last 20 years. When multiphase metering was first introduced, unrealistic claims led to great expectations and ultimately disappointment when the technology failed to meet its initial promise. However, in recent years the technology has developed to a point where multiphase metering is considered as a key enabler in development of many marginal fields.

The technology’s accuracy certainly has improved and it is fair to say that many of the meters being marketed today are more than capable of meeting the levels of accuracy required for operations such as well testing, i.e. up to 20% uncertainty, where approximate performance and repeatability of measurement are the main requirement. However, for allocation and fiscal measurement with required uncertainties of less than 10%, or in some cases below 5%, there is still a challenge.

There are a handful of multiphase meters currently available that can meet the accuracy required for allocation under specific conditions, but so far no multiphase meters are available commercially with less than 5% uncertainty over the full range of conditions.

With more than 1 million production wells around the world, the “per well” market for flowmeters is attractive for meter manufacturers and they are working to improve technology. However, with multiple stakeholders in terms of allocation and fiscal reporting, independent verification of meter accuracy is essential. Furthermore, the current cost of multiphase meters is prohibitive for “per well” metering to become common.

Developing technology

There are a number of factors multiphase meter manufacturers need to research. These include:

• Transparency of accuracy through independent testing
• Uncertainty less than 5%
• More gas volume fraction (GVF) capabilities
• Higher water cut capability
• Lower cost.

Improving reliability, packaging

Accuracy of multiphase flowmeters has been tested by independent specialists TUV NEL over a number of years via joint industry projects (JIPs) funded by a wide range of oil companies including most of the major international operators and meter manufacturers.

There are two keys to accuracy claims that require independent verification: the hardware and the software. Manufacturers claim significant accuracy advances for hardware with improved sensor technology in meters such as nuclear gamma ray detectors and dielectric sensors. In terms of software, manufacturers have worked to refine algorithms to interpret the measured signals and to correct for flow regime effects.

Complete multiphase metering systems need independent verification across a full range of well conditions with varying levels of water cut and GVF. This can be done at a specialist multiphase testing laboratory such as TUV NEL’s facility in East Kilbride, Scotland, which combines a full scale three-phase test separator with single-phase reference meters to provide real time comparisons with multiphase meters on test. (This facility forms part of the UK National Standards for flow measurement).

The TUV NEL facility can operate at flow rates up to 16,000 b/d, water cuts from 0 -- 100%, gas fractions up to 98%, line pressures of 10 bar, and at operating temperatures of 20º-0º C (68º-32º F). This allows the physical testing of multiphase meter systems over a range of well conditions and can lead to increased confidence in the reliability of their measurements. However, in addition to the performance of a meter itself, the ultimate accuracy of the system depends on the PVT (pressure, volume, temperature) modeling software used as part of the overall metering package.

Two-phase flow in Vertical Perspex Venturi.

Multiphase meters measure the flowrates of each phase at line conditions, often at elevated pressures. These measurements must then be converted to standard conditions using a PVT model. This conversion adds to the uncertainty of the measurement when converted to standard or any other conditions.

The PVT model requires physical property or composition input data for the oil, water, and gas phases. It is used to determine the change in both densities of the phases and, more significantly, the amount of phase transfer between the phases from line conditions to standard conditions. The phase transfer is almost exclusively between the oil and gas hydrocarbon phases, with a reduction in pressure causing some of the lighter liquid hydrocarbon components to evaporate or “flash off” into the gas phase. This is commonly referred to as “oil shrinkage.”

Despite the almost universal use of PVT models in multiphase meters, there is little information on how these calculations are performed, and indeed how one manufacturer’s model compares with another. There is also little, if any, information on the sensitivity of these models to errors in the input physical property or composition data. In discussion, regulators say this as an area of concern. The UK regulator, for example, has experienced serious errors in allocation measurement due to poor PVT information.

Given the potential financial impact of PVT calculations, there is a clear need to evaluate independently the performance of the PVT models used in different multiphase meters to determine the consistency between models and the sensitivity to input variations.

Analysis of multiphase technology helps identify areas where manufacturers can focus development efforts. For example, as increasingly marginal wells become viable with high oil prices, multiphase meters will need to handle ever higher water cuts. In late-life fields, viable water cuts of over 90% are common and in the future it is possible that flows with even the smallest oil content may be economic.

Multiphase meters also need to be able to cope with GVFs ranging from less than 10% to more than 98% at various flow rates.

Future challenges, opportunities

With so many variables, multiphase metering development is a complex process. However, meter manufacturers are making headway with the issues and further independent testing will highlight the general progress of the technology.

Although multiphase meters are still cost prohibitive as a widespread alternative where pre-existing test separator capacity exists, they are cost effective for new developments where test separators are not available because they offer both lower capex and opex.

Multiphase meters probably will play an important role in unlocking the potential of heavy oil, much of which will be produced with the aid of steam, creating a multiphase mixture of evaporated hydrocarbons, oil, solids, and water.

In addition to metering production, multiphase meters also promise other benefits. Multiphase meters can optimize gas lift by providing real-time data. In a recent project by an oilfield services company in Brazil, gas lift was optimized in old wells by applying of a conventional single-phase meter to monitor gas injection flows, while simultaneously monitoring production with a commercially available multiphase meter. Test result analyses found that in most of the wells tested, increased gas injection benefited production, although in the case of one well, optimization required a reduction in the volume of gas injected.

In high water cut wells, multiphase meters may determine accurately when production becomes non-viable by providing real-time information about what is being produced.

Readying the technology

With so many variables, multiphase metering is a complex business, but it is clearly the way for operators to maximize asset values, develop marginal fields, or manage challenging wells.

“Per well” multiphase flowmeters will become the long-term norm for most new developments and for many existing wells. The technology is developing quickly and with increasing understanding of accuracy, capability, and application needs, greater trust of multiphase meters will grow quickly to increase demand and reducing meter cost.

Source: Offshore-Mag.com   -   View Original Article

Multiphase Metering in Challenging Environments

Many operators see multiphase metering as an important factor in increasing production rates. Industry analysts Douglas-Westwood Ltd and OTM Consulting, for example, predict that more than 1,000 additional multiphase meters will be deployed by 2015. According to Rystad Energy Global, 12% of global oil & gas production today, for instance, is facilitated by Roxar multiphase meters.

With the increased market penetration of multiphase meters come challenges – particularly in environments such as deepwater operations where scaling is prevalent, and other environments such as heavy oil and sour gas fields.

The heavy oil challenge

According to the United States Geological Survey, heavy oil is known to occur in 127 basins throughout the world with 3,424 Bbbl of “in place” heavy oil.

A major difficulty with heavy oil is its high viscosity and associated weak flow, which makes it difficult to extract. Technologies that work with light and medium oil grades often fail with heavy oil due to the different process conditions such as low gas rates, low density contrast among liquids, unpredictable emulsion properties, viscous fluids, and the presence of wax.

The fact that there is no need to separate phases in multiphase meters, as opposed to standard test separators, benefits multiphase meters. Fluids may separate poorly in heavy oil fields due to the small differences in densities among the phases. Well dynamics in heavy oil wells also can cause carry over and carry under, leading to inaccurate test separator measurements.

Multiphase meters must, however, deal with large variations in oil densities and viscosities in heavy oil fields. This can be counteracted with direct-phase slip measurements. In the case of Roxar’s meters, for example, for phase velocity determination, cross correlation and dual cross correlation is used below 90% gas void fraction (GVF). The cross correlation algorithms are not dependent on viscosity, and dual cross correlation enables direct-phase slip measurements.

Venturi mass flow measurement also is used in multiphase meters, with such venturi models able to cater for large variations in oil densities and viscosities. The three velocity measurement method ensures that the system has a built-in redundancy and self-verification.

Highly viscous fluids often have wax, raising concerns about clogging the process impulse tubing (sense lines). To counteract this threat, multiphase metering should include self-draining impulse tubing. Such impulse tubing is more sensitive and guarantees a higher turndown, leading to higher sensitivity and accuracy of the meter/measurements, compared to alternative solutions such as remote seals.

Sour service environments

Sour service environments also pose challenges to the reliability of multiphase equipment.

There is the challenge of measuring flow rates of oil, water, and gas reliably and accurately under the presence of high and fluctuating H2S concentrations, and there are the HSE implications for a multiphase meter of producing a potentially hazardous gas.

A robust measurement principle for multiphase flow is essential in sour service. Meters which apply fractional measurements using electrical impedance measurements, in combination with either non-gamma software or single, high-energy gamma for density measurements, are robust against H2S concentration variations.

The electrical impendence measurements calculate the mixed conductivity and permittivity to determine the phase fractions and it is highly unlikely that the oil permittivity and water conductivity will change significantly in the presence of H2S gas and sulphur atoms.

When dealing with wellstreams containing hazardous sour gases, it is important to consider the safety and environmental implications that the cleaning and interruption of the well flow have.

Limited maintenance

In this case, remote and limited maintenance requirements are important. The normal maintenance schedule of the meter will be a yearly empty-pipe calibration of the gamma system and a check-up of the meter’s electronics and transmitters to ensure there is no drift. All maintenance actions can be done remotely from the service console.

Remote monitoring also allows operators and service engineers to control the multiphase meters from a safe, remote location -- of great importance when the meters are to be installed at unmanned locations. One example is the Kasaghan project in the Caspian Sea (23% mol H2S), an area of over 5,500 sq km (2,124 sq mi) and where there is a potential for 50 to 200 multiphase meters to be installed on unmanned platforms.

Roxar has supplied a number of projects with multiphase meters around the world where process conditions indicate high concentrations of H2S. In 2003, Roxar supplied multiphase meters to a field in Qatar with v/v 2% H2S. The meters monitor the well rates and input data to update the production model. In 2004, Roxar delivered 19 meters to a major operator in Kazakhstan. This field is known for extreme high H2S levels, up to 16 mol%. These meters have shown consistently good measurements.

The problem of scaling

Scaling – the term used to describe a deposit inside a pipeline, borehole, or reservoir which forms after a chemical reaction – represents one of the most significant production and well integrity challenges in oil and gas production today.

Scaling can plug both production and injection wells as well lines, pumps, and valves. It can lead to inaccurate multiphase measurements, if the scale forms a layer on the inside a meter’s sensors.

The materials that make up the surface that forms the inside of the capacitance/inductive sensor is important. A PEEK (Polyetheretherketone) surface, for example, is more resistant to scale build-up than steel or metallic components.

Another preventative measure in applications with known scaling potential is to inject scale inhibitor upstream of the meters – at the trees, for example. This should be done as an early preventative measure before scale problems occur.

In cases where scale build-up does have the potential to influence meter readings, it is important for the multiphase meters to detect and solve such scaling problems through both preventative and corrective actions.

There are other remedial measures -- the use of a scale inhibitor to prevent the formation of scale and to increase oil and gas flow, for example, and the direct removal of the scale with the use of a manual brush when access to the meter inner wall is possible.

Source: Offshore-Mag.com   - View Original Article