Norflow seminar, 9^th June 1999

High Performance Multiphase Metering - A Personal Perspective

Mr A.W. Jamieson, Shell U.K. Exploration and Production

Summary

Multiphase meter development over the last twenty years has produced a variety of commercially available meters that have already brought large savings to the oil industry. In high production cost areas such as the North Sea, the potential applications call for meters with a significantly higher performance. This need for higher performance is set in the context of the value of the measurements to the user for managing complex allocation systems, and the difficulties inherent in developing and implementing such multiphase metering systems successfully

1. Introduction

Multiphase meters have been seen by many engineers as key components in reducing the capital and operational costs of oil and gas production facilities. The development has been targeted essentially at improving well testing - replace a large and expensive test separator by a compact cheap multiphase meter with equivalent performance and you have obvious savings. For subsea applications the savings are even larger - subsea multiphase meters mounted at the wellheads save long test lines. Yet despite the potential benefits oil companies are only slowly deploying multiphase meters. Indeed, with the recent fall in oil price and the subsequent cut backs, there has been a large reduction in funds for development of multiphase meters.

I have argued that the greatest savings from using multiphase meters will come when their performance is sufficiently good for them to be used for third party allocation and when they are deployed subsea. This is especially true for a high cost production area such as the North Sea. One can then run multiphase pipelines from subsea satellites to the most convenient host facility where the hydrocarbons can be processed in common separation facilities. Thus one avoids the problem of how one juggles the production to the separators one has available to allow reasonably accurate allocation to be made.

I do not think it is exaggerated to say that without high performance multiphase metering, it will simply not be economically worth while for oil companies to develop he small accumulations of hydrocarbons left to be developed in the North Sea. Of course, they could agree to exchange or sell acreage, or agree to lower quality metering, and get around the problem, but this approach has not been popular to date. I would add that in my view knowing what one is doing is crucial for the successful exploitation of marginal fields. Cost effective measurements are not 'nice to have’; they are essential if one wishes to minimise the hassle inherent in taking on these developments, and in optimising the production.

How realistic is my claim that high performance multiphase metering is not only practicable, but can be achieved in reasonable time scales, say 5 - 10 years? My answer is that in some special cases, such as wet gas metering, we have already achieved that kind of performance. I also say that in several cases where we have operated multiphase meters in series with test or production separator metering, the multiphase meters have shown that he separator metering is mostly not as good as we would like to believe. The logic is simple; if you are happy with traditional separator metering, you should also be prepared to be happy with the multiphase metering. The laboratory tests that have been carried out on multiphase meters show that there are clear ways to improve the performances of the meters, but also show up deficiencies in the test facilities. It is easy to bemoan the fact that multiphase meters, after some twenty years of development, are not yet widely in use. On the contrary, I think it is a great tribute to all involved that we have meters that can be deployed, can in their present state of development compete with traditional metering systems, and have already brought savings to the oil and gas industry that easily exceed the total cost of development to date. I see no good technical reasons why the performance of multiphase meters should not improve, and in my opinion to near fiscal quality.

Multiphase metering in its present state of development offers the industry a wide range of choices for field development or upgrading of facilities, but choices that are poorly tested and that cannot be proved except on operating facilities. In its current approach to reducing costs, the industry would like to have the benefits but is unwilling to invest the money to ensure satisfactory implementation of multiphase metering. The oil and gas producers appear to hope that multiphase metering has become sufficiently mature that their support need only be indirect.

In the paper I discuss first how to approach multiphase metering applications. I review the needs for multiphase metering, which I consider have not really changed over that time and discuss the application areas with the emphasis on high performance. I consider the difficulties of implementation and discuss the future of multiphase metering, with the emphasis on high performance.

2. Multiphase Fluids

Many of the measurements required in oil and gas production, flow, level, temperature, and pressure have traditionally been treated separately, and mostly without regard to the interactions with other parts of the production process. The development of multiphase technologies to transport and meter unseparated hydrocarbon streams allows and indeed forces one to take a more integrated view of the whole production process. Furthermore, when multiphase meters have been deployed, they have confirmed the shortcomings that have long been suspected in conventional measurements made using test and production separators.

The 'Multiphase Composition Triangle' shown in Figure 1 can be used to indicate conditions under which any measurement in the oil and gas production processes is made. We find single-phase oil, water and gas at the vertices of the triangle; two-phase fluids, oil/gas, water/gas and oil/water along the sides of the triangle, and the vast range of three phase fluids occupy the interior of the triangle. I have also shown a transition region, where the liquid part of the multiphase mixture may be either water-in-oil or oil-in water, making measurements difficult for instruments using electrical properties of the fluid.

We can now see that any oil and gas production process takes a particular multiphase mixture and performs a sufficiently good separation into marketable oil and gas streams and a waste water stream. How well these streams approximate to single phase flow depends on the process and how it reflects the specification of the oil and gas in the supply contracts and the environmental constraints for the waste water stream.

It is easy to use the triangle to show why multiphase metering is complex. If we have difficulty with the single phases, which are so obviously different from each other, we can expect measurement to be at least as difficult for any multiphase composition in the triangle. We have to add to that the complexity from the flow regimes. Flow regime maps have been determined by subjective observation in laboratory testloops, almost always for two-phase mixtures, say oil-gas or water-gas. These maps vary for temperature, pressure, viscosity and pipe orientation. There have been only a few attempts to make three phase flow regime maps, and these are very complex.

This means that it is not practical to predict the performance of multiphase meters from first principles and that detailed empirical testing will be needed. Obviously, the higher the performance demanded from the meter, the better the test facilities need to be. In time, when enough applications have been examined we should be able to see generalities, but for the next few years at least each application will need to be treated on its own merits.

Thus the Multiphase Composition Triangle is also useful in indicating where we have inadequate measurements and where we should direct our attention in developing new instruments.

3. Overview of Multiphase Metering

The outcome of the work done around the world over the last twenty years, at a cost of about £70 million, is that there are several commercial multiphase meters available, and a variety of approaches under development. These meters give the gas, oil, and water volume flowrates at line conditions. (At present there is a strong preference for volume rather than mass flowrates, but this preference may change.) These are the measurements that are in principle obtainable from a test separator, the oldest type of multiphase meter.

I have been associated directly and indirectly with multiphase metering over that period, and have given my perception of that period in the appendix to this paper. It is not an exhaustive history of multiphase metering, but I thought it would be useful to show a little of how we have arrived at the present situation.

Today I would identify four general approaches to multiphase metering, all of which are being actively developed and are being applied in the field. I further believe that any multiphase meter can be fitted without much difficulty into one of these four categories or a combination of them. Not all of these approaches are suitable, in my opinion, to lead to high performance multiphase meters.

3.1 Compact separation systems

These devices perform a rough separation of the well flow into liquid and gas streams. These are then metered using meters that can tolerate small amounts of the other phase. The liquid must be further split up into oil and water. These systems are being applied world-wide, but are bulky and do not bring the full benefits of multiphase metering with them. Typical cost £100 - 200k. I do not think these systems can be developed much beyond well testing capability. To get high performance the gas tolerant liquid meters and the liquid tolerant gas meters must be high performance multiphase meters in their own right, and I would then expect the cost of the system would then be prohibitive.

3.2 Phase fraction and velocity measurement

These meters attempt to identify the fractions of oil, water and gas and measure the phase velocities, which are not usually the same. In practice manufacturers try to condition the flow so that the phase velocities are similar, and the differences in velocity are corrected using multiphase and slip models. Most of the multiphase meters deployed in the North Sea are of this type. Typical cost £100 - 200k surface, £200 - 400k subsea. I believe that some of these meters can be developed into high performance meters. However, most of the multiphase fluid models in these systems use quite long averages of the measured parameters. Multiphase flow is a complex, turbulent, highly non-linear process. It is my opinion that attempts to measure it based on fluid models using averages of parameters over times much longer than those of the fluctuations in the flow cannot give high accuracy.

3.3 Tracers

Multiphase flow is measured by injecting at known rates tracers (e.g. fluorescent dyes) that mix with the individual phases. By analysing a sample of the multiphase fluid taken sufficiently far downstream of the injection point, and combining this with the injection rate, the individual flows can be determined. Currently tracers are only available for oil and water. The technique is particularly suited for wet gas measurement where the liquid to gas ratio varies slowly with time. Costs are closely related to day rate for work and hire of equipment, say £1500 per day. I would like to believe that tracer techniques can be developed to the extent that they could be used to calibrate or verify multiphase meters in situ. However, the conventional tracer technique applied to fluctuating flows gives inaccurate results. Sampling times need to be shorter than the fluctuations in the flow. Nonetheless, one can choose the tracers, and one can choose the means of detecting and measuring their concentration. Therefore it appears to me that it is reasonable to expect it is possible to develop practical high performance tracer techniques.

3.4 Pattern recognition

These systems are characterised by their use of simple sensors combined with complex signal processing. I believe that these systems have the potential to offer the cheapest hardware combined with the highest metering performance. A major benefit from this approach will be targeting low cost solutions for specific applications. Cost is more variable, but within the range £20 - 60k, depending on the number and type of sensors used.

The pattern recognition approach is the least familiar and most mysterious approach to multiphase metering for most people. Yet the operator who puts his ear to a pipe to listen to the flow, or who feels the temperature of a pipe to judge whether there is a flow inside it is practising a crude form of flow measurement by pattern recognition. It is therefore worthwhile pointing out some of the general features of this approach that distinguish it from the other approaches to multiphase metering. As an example, the ESMER pattern recognition meter uses differential pressure, pressure, capacitance and conductance sensors to sense relatively fast (approx. 25 - 500Hz) fluctuations in the multiphase flow. The signals from sensors used in most metering applications are damped to reduce noise and give a good average value of the measured parameter. In the pattern recognition approach the fluctuations are what is important, and the average value may not be used at all. An analysis is carried out of the amplitude and frequency fluctuations of the sensor signals and a large number of “features” are calculated. These characterise various aspects of the signal. Thus each sensor, instead of generating only one parameter, can generate perhaps thirty “features”.

In principle we can write an equation for each “feature” in terms of the unknown oil, water and gas flow rates. This means that for the meter referred to above which has five sensors, we can write perhaps 150 independent simultaneous equations in terms of the oil, water and gas flow rates. In an ideal world one could hope to find a feature that responded only to oil, another to water and a third to gas. So far, nature does not appear to be so kind and practical methods have to be used to solve this complicated mathematical problem. In the meter above a feature saliency test is used to find the most significant features and then neural networks are used to calculate the oil, water and gas flowrates. Other mathematical techniques could have been used, however. The essential point is that the fast fluctuations in multiphase flow carry most of the information. By using heavily damped sensors the fine detail is lost with the consequence that multiphase meters using heavily damped sensors are unlikely to achieve high accuracies. Using fast sensors and pattern recognition signal processing, virtually unlimited accuracy should be possible, but one is faced with the difficulty of providing highly accurate calibration data for the meter. I believe that it is practical to achieve relative accuracies per phase of 5% by 2005, and 1 - 2%, near fiscal quality, in certain applications by 2010.

4. The Needs

Why do we really need multiphase meters? A responsible oil and gas producer will begin the answer by saying that one needs to know what is happening in producing wells to a sufficient extent that one can tell what is happening in the reservoir. This allows the producer to optimise production to satisfy day to day commercial constraints and also satisfy long term recovery from the reservoir. The producer is also interested in what goes on in the production process. Where several fields are processed on the same facility the operator is required by co-venturers to make adequate measurements to allocate the production and hence the revenue to the correct field. These needs have been present since the oil industry started, and are likely to remain until its end. They have been satisfied to a greater or less extent by wellhead sampling, test and production separator metering, and by high accuracy gas and oil export metering into extensive oil and gas pipeline systems. These hardware systems and the associated allocation models have not been thought of as 'multiphase meters' but I would claim that that is what they are.

So the response to the original question is, "We don't really need multiphase meters, but we do need the information described above to run our facilities." Multiphase meters, essentially collections of sensors and algorithms, and deployed at judicious locations in the hydrocarbon producing processes, simply allow the measurements indicated above to be made in ways that allow the overall production process to be simplified. The more that can be done by the multiphase meter, the greater the simplification that can be made. However, the benefits of simplification of the facilities usually appear in the capital expenditure budget for the facilities and are forgotten once the facilities are handed over to operations. Operational expenditure budgets are usually worked out assuming that the savings have been made, so the holder of that budget views any extra expenditure as a direct cost, and not as a (hopefully small) reduction in the savings. Unless the information provided is accepted as being as good or better than that obtained previously, the multiphase meter cannot be claimed to be giving any operational benefit.

How much hassle are we prepared as oil companies to accept from a multiphase meter? And how much effort are we willing to put in to make them work consistently well? In the current downturn, the answer is fairly clearly, “Not a lot”.

Thus we can summarise the needs for a multiphase meter as follows. It must provide high quality information for a variety of routine operational tasks, from reservoir management to production allocation. It must do this complying with existing ways of working. It should be easy to install, commission and operate. It should operate reliably and require virtually no maintenance.

It is obvious that there is considerable conflict between the above and the present state of development of multiphase meters, particularly in terms of high performance. Clearly, the main justification for applying multiphase meters is in the value of the data provided by them, and equally clearly, that value must be significantly greater than the cost of providing the data, whether from a multiphase meter or otherwise. I think that in evaluating the benefits of a multiphase meter, we have focused on the capital expenditure savings as they are relatively easy to estimate, but I now consider that these savings are of secondary importance. However, I have found it virtually impossible to get figures that are accepted for the value of being able to make any measurements in the oil and gas production processes, not just those by multiphase meters. In the current business environment it is increasingly important to be able to show what the real benefits are from new technology. Consequently, I think we have to try harder to estimate the real value of the data. It may then be easier to get approval for development of high performance multiphase meters. On the other hand, if no one is prepared to put a value on the information, then there would appear to be no real need for the technology and we should stop pretending there is.

5. Applications

Let us now return to the Multiphase Triangle and consider some multiphase metering applications that lie in different regions. Discussion of these in turn shows how we can build on experience from one application to tackle a more difficult one, and why it is wise not to try to install a multiphase meter in too difficult an application.

Applications 1-3 illustrate the progression of wet gas metering from 1% to about 10% liquid, or 90% Gas Volume Fraction (GVF). Compact separators are also practical in high GVF applications, albeit not in Shell Expro’s circumstances. Moreover, the phase fraction and velocity measurement approach, which was originally targeted at 50-60% GVF, has been extended to GVFs of over 90% in special circumstances, so that I think it is now best to treat wet gas metering simply as an important subset of multiphase metering.

Application 4 will have natural drive throughout its life, so the reservoir engineers expect hardly any water. For such an application we only have to measure two phase flow, and be able to detect water breakthrough should it happen.

Application 5 is unusual in that it is to measure the water/gas mixture produced in the depressurising of a reservoir. The accuracy required for this two-phase measurement is about 10%, but equipment must be low cost.

Applications 6 and 8 are satellite fields with water injection, tied back to a production installation. The trajectories followed by these wells across the multiphase triangle show how the small reservoirs being developed in the North Sea today decline rapidly to water. This type of application is the most common in Expro for application of multiphase meters, and the most difficult, as the metering must cope with a wide range of flowrates for the individual phases and a wide range of watercuts.

Application 7 is on an old field, where there is no test separator and well testing had to be done by deferring about £800,000 worth of production each year. If one can reduce this deferment, it is evident that this will help in delaying abandonment.

I have also included two other fairly general areas of application on the multiphase triangle. Firstly, in Oman, there are many low-pressure wells with no gas at wellhead conditions, and so are two phase oil-water mixtures. These are tested using Coriolis meters, with the density measurement used to determine the oil and water flowrates.

Secondly, well engineers are considering downhole multiphase metering, especially for multilateral wells where there is a need for a meter in each branch of the well. To me, the main advantage in metering downhole is to suppress the gas fraction and reduce the measurement to an oil/water measurement. I would expect the GVF to be low for this area of application, and the meters need to be designed accordingly. I believe that downhole meters are practical for many wells, but that it will take even longer to develop and prove them than it is taking for surface and subsea multiphase meters. Flowmeters installed with the tubing are unlikely to be acceptable for critical metering applications because of the difficulty of retrieving them for repair. It will be difficult to design satisfactory wireline retrievable flow elements. Any kind of high performance downhole flow meter will require locally mounted, fairly complex signal processing electronics which will have to operate at high temperatures.

It is clear that these application areas are significantly different. Thus each application really has to be treated on its own merits. In Shell Expro, and I believe for the North Sea, the bulk of applications demand high performance metering. One way to tackle this would be to try to prove equipment first on applications where lower performance is needed, and then apply it to more difficult applications. This would require a clear strategy for developing fields that could absorb the long periods of waiting to establish techniques before starting the next project. Unfortunately, when Expro’s small prospects were being developed before the 1998 downturn, they were all fast track and super fast track projects, with little time for developing multiphase meters specifically for the applications. If and when prospect development starts again, it is most unlikely that it will be done in a leisurely way. Many will remain uneconomic without appropriate multiphase metering solutions.

6. Implementation - The Difficulties

It has been my experience that implementing new measurement techniques successfully in the oil and gas industry is in practice fraught with difficulty. Let us assume that the early hurdles of turning a good idea into a working prototype instrument have been successfully overcome. Several years will have passed, and perhaps some £250,000 or more will have been invested. Let us further assume that there has been at least active interest by an oil company and an equipment manufacturer so that the prototype equipment is compatible with oilfield installation requirements. Nevertheless, a field evaluation of a new instrument will probably cost more than the whole development to date, and may take over a year to organise.

In my experience if a field evaluation is to give useful data, the staff on the installation on which the evaluation is to be carried out must be able to see direct benefit to them if the evaluation is successful. In these days of minimal manning, if there is no direct benefit to the people who have to support the evaluation, they are unlikely to devote adequate time, especially when things go wrong. A further consequence of minimal manning is that for field evaluations today, it is almost essential to provide means of getting the data onshore so that the evaluation can be monitored remotely.

After satisfactory field evaluation, one is then faced by the difficulties of turning working prototypes into fully commercial instruments. In the case of multiphase meters, one really requires considerable feed back from instruments operating in the field to confirm that the instrument performs correctly. Conditions in the field are quite different to those one can simulate in a test loop. It is often stated that operating platforms are not places on which to conduct R&D projects. However, if one wants to gain the benefits that better measurements can undoubtedly bring, one cannot exclude operating facilities from the R&D process.

This is not making excuses for why we do not yet have a wide range of satisfactory multiphase metering systems. However, groups of people, namely, academics, industrial researchers, representatives from government departments, manufacturers, engineers and operators from oil companies and their contractors must somehow form extended teams for about ten years if successful conclusions are to be reached. In my experience, such teams are not put together. They simply happen because those who decide to be members recognise that they need to be involved. I continue to be surprised at how effective such extended teams can be at getting things done while they can work together. It is at the implementation stage, when large amounts of money must be spent, that these extended teams are most likely to break up. If there is no longer a clear need expressed by a keen prospective user and that user's active involvement, there is virtually no incentive to continue. Development languishes until another potential user expresses enthusiasm, and all one can do is hope that earlier work has not been wasted.

7. The Future of Multiphase Metering

We in the countries around the North Sea like to think we are leading the development of multiphase meters. We have set challenging targets for multiphase meter performance, but it is evident that the North Sea market for multiphase meters is not big enough for manufacturers on their own to develop, say, multiphase meters for third party allocation. For Shell Expro, if the performance of multiphase meters stops at “well testing” standard, we will not require many multiphase meters topsides or subsea, but neither will we get the benefits from using them. Clearly for the North Sea operators there is a major challenge to improve the performance of multiphase meters significantly over, say, a five-year period.

There is little appreciation of the time it takes to develop and test multiphase meters. About a year and a half ago year I made what was intended to be an upbeat presentation to colleagues working on new developments, and told them that we could reasonably expect to develop multiphase meters for third party allocation by 2005. Their response was that they already needed that quality of performance for projects they were working on and that they could not wait for that length of time.

From the testing we have done on multiphase meters offshore, and what I have seen done by other companies, I believe that it is impractical to verify the performance of multiphase meters offshore to high standards except in very exceptional circumstances. Valves on test separators or on production manifolds frequently pass sufficiently to make detailed verifications impossible. It is often difficult to maintain stable operation of separators to allow detailed comparison.

Without exception, however, the multiphase meters have shown up deficiencies in traditional separator measurements. From evaluations carried out in test labs and offshore, I think it is fair to say that several multiphase meters perform as well as traditional test separators. Indeed, one can go further and ask under what conditions can production separator metering realistically achieve the high accuracies called for in third party allocation agreements.

If high performance multiphase meters are to perform a significant role for small North Sea prospects, high quality test facilities are required that can accurately simulate conditions in real operational circumstances. This is to reduce as far as practicable the doubts that the meter is not doing what it is supposed to do. Some of the existing test facilities on operational locations could possibly be upgraded to fulfil such a role. The value of the data from multiphase meters must therefore be perceived as being sufficient to justify the upgrading or construction of these facilities and the expense of running them. It is unlikely that meter manufacturers would be able to justify such costs. It would therefore fall to oil companies to meet such costs, as they would stand to gain the largest share of the benefits.

Multiphase meter development was started some twenty years ago with the conviction that these devices could simplify oil field development and reduce operational costs. Today, after an expenditure of some £70 million, I believe that conviction has been more than justified in terms of the savings already made through their deployment. However, although it is as clear now as it was then that multiphase meters can bring large savings, there does not appear to be the same conviction to make the technology work. It is not the case that a ‘final push’ will deliver high quality multiphase metering. It will require sustained, consistent effort for many years. If one thinks of installing multiphase meters on a significant fraction of the million or so wells in the world, it would be naive to think otherwise. In high cost areas such as the North Sea simple satellites producing to third party processing facilities are key to reducing costs. Higher performance multiphase meters are then essential to provide good enough data to manage the resulting complex allocation systems.

8. Conclusions

Multiphase metering is at the stage of development where oil companies can deploy them to bring large benefits, reducing the costs of facilities and allowing operators and reservoir engineers to optimise production.

Existing multiphase meters or indeed any multiphase meter likely to be developed can be fitted into one or a combination of the four approaches currently used in multiphase metering. These approaches offer different levels of technical complexity and require different levels of understanding. Operating companies can therefore choose a multiphase metering system suited to their specific needs.

Enough development and testing has now been done to show that high performance multiphase meters for third party allocation and for near fiscal measurement are practical, and that their realisation need not be too far off. In this respect the pattern recognition approach, on its own or in combination with the hardware from the other approaches is most relevant.

The potential market world wide for multiphase metering systems is very large. No single type of meter or metering approach can hope to cover all applications. Although we can expect that some manufacturers will withdraw, others may enter the market. There is clearly room for several suppliers.

However:

• Multiphase metering systems are most certainly not “fit and forget” equipment in their present state of development. They should only be deployed where there are clear financial benefits and where there is real commitment to making them work.

• Widespread implementation of multiphase metering cannot take place until expertise is spread more widely throughout the oil industry. Specialists in oil companies, developers and manufacturers hold most of the expertise in multiphase metering. Metering consultants and facility design houses are slowly beginning to build their expertise.

• Multiphase metering is a complex subject. It is important to develop ways to explain the complexities in a readily understandable way. The Multiphase Triangle approach appears to be a useful tool.

• The market situation in the North Sea is different to the rest of the world. The technical requirements for most likely applications are really beyond the capabilities of the products that manufacturers can reasonably supply at present. The North Sea market for multiphase meters on its own is unlikely to bring sufficient return on investment for manufacturers to develop the higher performance meters required in the North Sea.

• If North Sea operating companies wish to gain the very large benefits of multiphase metering, they will have to provide the financial backing to support the development of higher performance meters.

References

This paper, as stated in the title, is my personal view of developments in multiphase metering in general, and with special emphasis to the needs of the North Sea. It refers to work carried out by colleagues in Shell, work done by JIPs or in association with other companies. Much of this work is described in reports that are not generally available. Accordingly, I have not attempted to give a list of references. I do draw attention to the paper I gave at the 1998 North Sea Flow Measurement Workshop, “Multiphase Metering - The Challenge of Implementation”, on which this paper is based and which I hope it complements.

APPENDIX

Multiphase Metering Over The Last 20 Years

I have been associated directly and indirectly with multiphase metering since the early 1980s and I thought it was worth giving my view of how multiphase metering has grown and changed over that time. This is not an exhaustive review of multiphase metering, but simply a personal account of how and where I have been involved. Obviously this story will be biased heavily towards a view from within the Shell Group of companies, and to the needs of Shell Expire in the North Sea. To get a balanced view of how we have got to where we are in the development of multiphase metering, I would encourage others to set down their accounts of this time.

Since the downturn in the oil industry from mid-1998, many new field developments have been shelved, and with them the prospects of deploying multiphase meters. Within Shell Expire, and within the Shell Group as a whole, there is a large reduction in the effort to develop and implement multiphase metering. I see the same happening in other oil companies. In combination with the mergers and take-overs of oil companies, the numbers of specialist staff in metering are being reduced significantly. I think the perception is that manufacturers, design contractors and specialist metering consultants can readily supply these services. I believe that with appropriate commitment and encouragement from the oil companies such a system can be made to work, but it will not just happen by itself. Others may then be able to set that experience alongside their own, and hopefully may be able to take a better approach, or at least avoid repeating unsuccessful approaches.

Coriolis multiphase meter

I spent most of the 1980's in the Production Measurements group at KSEPL, the then Shell E&P laboratory in Holland. When I arrived in 1980, some scouting studies had been made on the feasibility of multiphase metering, and the favoured approach at the time, was to attempt to develop a straight multiphase Coriolis meter. Coriolis meters come in various shapes, usually to get round patent difficulties or to increase the available signal, but for a meter to be installed near the well head a straight unobstructed flow path has obvious advantages. In terms of the multiphase composition triangle, we believed that the route to multiphase metering was first to develop an oil/water mass flow meter, to be able to meter along the bottom line of the triangle, and then gradually increase the gas content, moving upwards through the triangle until it was possible to measure everywhere. The laboratory prototype could work with up to about 15% of gas. In practice, however, Coriolis meters can really only handle liquids or gases, and thus cannot be used over most of the multiphase triangle.

Harwell nucleonic tracer meter

In the early 1980s AEA Harwell proposed an elegant method of measuring multiphase flow. By injecting intense beams of neutrons into a multiphase flow, the nuclei of the various atoms present in the stream would be excited, and in decaying from the excited states would emit almost immediately gamma rays of different energies depending on which atoms were present. By monitoring the intensities of the emitted gamma rays at the different energies, the composition of the multiphase fluid could be determined. Some atoms could also be transformed into other isotopes or excited stated with a reasonably long half life, say a few tenths of a second, and which then decayed with emission of gamma rays with specific energies. If suitable atoms could be found in trace compounds specific to the oil, water and gas components, the velocities of these could in principle be measured. Combining this with the composition, the flow rates of oil, water and gas could in principle be determined. A JIP with BP and the then Britoil investigated this approach. The attractions were that it would be completely non-intrusive. Both injection of the neutrons and measurement of emitted gamma rays could be made through even thick walled pipe. The system could in principle be mounted on a saddle and lowered over a subsea pipeline, making recovery straightforward. The source of neutrons, a high intensity neutron flash tube, was harmless when switched off but quite dangerous if switched on in air. Water is an excellent absorber of neutrons, so the approach was suited for subsea installation but not topsides. In practice the composition measurements could be made, but apart from oxygen, there were no atoms that could be excited with suitable half-lives to give velocities. This meant that one could measure the velocity of water in the multiphase fluid, and at a pinch the velocity of the gas by the oxygen in the carbon dioxide component. To get the flowrates of oil, water and gas one would have to resort to homogenising the flow, or injecting suitable compounds to provide the necessary tracer atoms. The rapidly increasing complexity of the system combined with the relatively short lifetime of the neutron flash tube meant that the system was not viable, but gave a useful background for some of the later work with tracers.

Field measurement requirements

Throughout the 1980s much of the work of the Production Measurements group was directed to improving well testing, and it was then that we began to consider production separators, and more especially test separators, as simply being large, expensive, and really quite complex multiphase flowmeters. Detailed evaluations of the performance of different types of test separator at different watercuts were made. It proved to be difficult to give simple expressions for the expected performance of a separator for any given field situation: indeed it is only really recently that one can do this reasonably simply using Monte Carlo simulation techniques. This work was incorporated in a Field Measurements report for the guidance of Shell operating companies. The advice was given that each application should be considered on it own merits, but that generally equipment should be installed to allow the flowrate of each phase of a producing well to be known to 10% relative uncertainty. This was not saying that the measurements of oil, water and gas from a test separator should be made to 10%, as well testing by test separator is an intermittent operation, and difficult estimates of flowrate changes with time have also to be included. This early attempt to give a simple single number guide figure has had many shortcomings, but is still widely used and tacitly accepted in production operations in the absence of something easier to understand.

Monitoring other developments

We monitored quite intensively other multiphase meter developments. In the mid-80s oil companies were effectively competing to support multiphase metering development projects, and I saw the proposals for extending the Christian Michelsen developed water-in-oil monitor to what has now become the Fluenta multiphase flowmeter. We also had a small input into the CSIRO developed dual energy gamma absorption multiphase meter, now commercialised by Kvaerner. Shell Australia asked our advice on whether the original proposal was worth supporting. At the time I had replied that it was, but it was only several years later, when the field trials of the prototype were being reported at the North Sea Flow Measurement Workshops, that I realised that that proposal had turned into something real.

The development of multiphase meters has in practice been through two routes. Firstly, the development of two phase (oil and gas) meters, initially around 60-70% gas volume fraction and then increasing the gas volume fraction and watercut. Operating in the transition zone and at high water cuts has proved particularly difficult. Secondly, the development of wet gas meters and gradually increasing the liquid content. Both approaches have now overlapped, and in my opinion it does not make too much sense any longer to maintain wet gas meters as an entirely separate category of meters.

Venturi wet gas metering and tracer techniques

In the second half of the 1980s much work was done on wet gas measurement. NAM in Holland wanted to allocate gas from a production system run in conjunction with another operator. They did not want to have test separators. Extensive testing showed that fluorescent tracers could give the liquid to gas ration of the producing wells sufficiently accurately to give a gas allocation to about 3%. The tracer technique was also sensitive enough to detect if there was a change to produced rather than condensed water in the liquid. In Expro we have applied the wet gas venturi technique on Schooner and Ketch. We have applied the tracer technique separately to determine liquid content of gas wells, but also to determine oil in high watercut oil wells.

MultiCapacitance Flowmeter

One day, a colleague came to the head of the section and myself with a proposal for a multiphase meter. He operated the multiphase test loop, which had transparent sections, and had seen the multiphase flow patterns, mostly slug flow, repeat time after time. We had been developing a segmented capacitance probe for improved measurement of level in separators.

"Why not make a short level sensor with two sets of capacitance sensors, the first set to measure the height of the liquid/gas interface, and the second set to give the velocities of the liquid and gas by cross correlation. That will give a two phase flow meter. The water cut of the liquid fraction can be determined from the capacitance sensors immersed in the liquid - and so we can have a multiphase meter in which many of the parameters are geometrical".

We were sceptical, but couldn't think of a good enough reason to say no. Over the next couple of years or so, by using technical college students doing their period of industrial experience, the proposal moved forward to a working prototype that showed that good performance could be obtained in slug flow. Kongsberg Offshore Systems were selected to commercialise the system, and during the early 1990s after I had returned to Expro commercial prototypes were built and extensively field tested. The attractions of the approach were that the meter used simple hardware, and could therefore be made reasonably cheaply. It did not use radioactive sources, which meant that it could be used anywhere in the world. However, with its design of electronics, it could only operate in the slug flow regime. Although this is probably the most common flow regime for oil wells, many wells will cross flow regime boundaries in their lifetimes. This is the case for many Expro applications, and it is impractical to consider changing out a multiphase meter at a fairly indeterminate date in the future when the flow regime changes. Another problem was that it had difficulty in measuring in high watercut flows. Kongsberg intended to solve these problems by operating at much higher frequencies, but bad experience in Shell field tests, and in tests in the high pressure test loop at Porsgrunn in Norway led to Kongsberg withdrawing from the multiphase market.

Personally, I was very disappointed when the MCF development stopped. There was a wealth of information available from the many sensors in the instrument that could have been used to make the meter work in other flow regimes and at high water cuts. It was one of the few approaches that offered low costs. The demise of this approach simply underlines the fact that when potential users and a manufacturer start to lose confidence in a particular technique, it is very difficult to recover the situation.

Production surveillance monitor

The Production Surveillance Monitor (PSM) was developed by Shell Oil in the 1970s as a simple well head production monitor. It was essentially a microphone with a built in gain control. The more noise from the well, the greater the production. Unfortunately, this was only true for some wells. In the mid 80s the instrument was tested extensively and for some wells, particularly those in slug flow and for gas lifted wells, the device could give good results.

Ultrasonic cross correlation

The question then arose as to whether it was possible to improve the PSM. Experiments were made with two ultrasonic sensors mounted a short distance apart. By cross correlating the noise and applying neural network techniques it was possible fairly easily to get measurements of liquid and gas to about 10%. This approach was abandoned as it was not easy to incorporate water cut measurements and calibration appeared difficult.

ESMER

Shortly after I returned to Expro we received a request from Imperial College to support a pattern recognition approach to multiphase metering. Given the background with the PSM and the ultrasonic cross correlation, I was very interested in this approach. We have since deployed a prototype system on Auk, which has, been operating for over a year. I believe that this approach, using cheap sensors and complex signal processing is one of the keys to developing high performance multiphase meters.

Expro support to multiphase meter development in the 1990s

On my return to Expro in 1989, it was very clear that if multiphase meters were only suitable for well testing, there were a very limited range of applications. For new developments there was often little incentive to replace the test separator. As a general-purpose vessel it could be used in many ways, and it was not difficult to defend its inclusion. Once you have a test separator, more aptly named a general-purpose vessel with metering capabilities, it is very difficult to argue for multiphase meters as well. For prospects that were to be developed as remote, unmanned facilities or subsea facilities, there were few that only required multiphase meters with well testing capability only. However, if it was possible to allocate production with multiphase meters, then there were many applications. Consequently I have tried to promote the view that high performance meters are needed together with the means of calibrating them and verifying their performance in the field.

Through the 1990s Expro involvement has been to work largely through JIPs, recognising that no one manufacturer or oil company is going to solve multiphase metering by itself. Many of these JIPs have been with NEL, the sampling separator approach of the early 1980s, the Multiflow JIPs to test commercial or near commercial meters and wet gas JIPs. Others have been JIPs with the Norwegian multiphase meter manufacturers, Framo, Multifluid in conjunction with Norske Shell and the research group RTS in Rijswijk, or in JIPs to test multiphase meters at Norske Hydro’s Porsgunn facility.

An important joint industry sponsored study in the early 1990s was that carried out at Imperial College under the direction of Prof. Geoff Hewitt. This strongly advocated the use of the nucleonic techniques that feature today in many of the commercially available multiphase meters. We participated in the Multiphase Forum comprising several oil companies keen to pool their experience. We have actively supported the general Shell Group developments in improving gamma absorption meters and the MCF development with Kongsberg Offshore, and have been the major industrial sponsor of the ESMER development.

Expro’s implementation of multiphase meters

I have been involved in the deployment of all of Expro’s multiphase metering systems. Venturi wet gas metering on Schooner and Ketch has been a success, but there have been problems with the metering electronics. These facilities are not normally manned, and these difficulties underline the need to provide metering solutions that are overall reliable. To the user of the data it is no good saying that the new, technically difficult bit works, and that it’s the old ordinary bits that don’t.

A Fluenta multiphase meter was deployed on Anasuria for well testing. This meter has given problems throughout its service life, but to be fair these cannot all be attributed to the meter. It has been rebuilt twice, first because of water ingress in the insulation layer over the capacitance sensors, and the second time because of water leakage behind the sensor assembly. While it was working, it showed up deficiencies in the production separator measurements on Anasuria. It is recognised that a working multiphase meter on Anasuria is important if third party fields are to be processed on Anasuria.

Two Multifluid International meters have been installed on Gannet. These meters have been considered a success, largely I think because extensive operational tests to establish the suitability of the meters showed up deficiencies in the Gannet test separator metering. However, as on Anasuria, it has been very difficult to verify these meters in normal operations. After water breakthrough occurred, and as watercuts have continued to rise, the production programmers are no longer confident in the data from the meter, but we have not been able to clarify this.

A prototype ESMER pattern recognition meter has been operating on a single well on Auk for almost eighteen months, giving good trend data from the well. It is to be moved to a separator manifold where it can be used to test a number of wells. Auk has no test separator. The multiphase meter will allow wells to be tested without deferring production.

From the foregoing, I hope that it is clear that multiphase meter development has not followed a straight, direct path. There have been many ideas that appeared to be good, but in practice had major drawbacks, others are good, but simply did not come to fruition, and there are good ideas around that have not been given a chance. For example, many of you may remember Dr Kuturiov’s presentation of the approach he is trying in Russia at the last Norflow seminar in 1997. It is a regret for me that in the general reorganisation of many of our companies, and in the general downturn of the oil industry that we have been unable to evaluate this approach in more detail.

Related Article: Multiphase Metering - the Challenge of Implentation

Laser Instruments and Instrumentation

Go to Specific Subject: Laser Level Instrumentation and Measurement |

Laser Radar Instrumentation depends on knowing the speed of light, approximately 0.3 meters per nanosecond. Using that constant it is calculated how far a returning light photon has travelled to and from an object: Distance= (Speed of Light x Time of Flight) / 2. It works as follows;

1. Laser generates an optical pulse.
2. Pulse is reflected off an object and returns to the system receiver.
3. High-speed counter measures the time of flight from the start pulse to the return pulse.
4. Time measurement is converted to a distance by using the formula above

Laser Technology is utilised in accurate Laser Instruments for Industrial Level and Measurement Applications.

Reflectivity of the Object

Measurements are not generally affected by the reflectivity of the Object . Highly reflective objects may saturate some laser detectors, while the return signal from low-reflectivity objects may occasionally be too weak to register as valid.

Day or Night

Laser radar is an "active illumination" technique that, unlike photography, does not depend on ambient illumination. It works during the day or at night.

Sunlight and Reflections/Angle of Measurement

A strong sunlight reflection off a highly reflective target may "saturate" a receiver, producing an invalid or less accurate reading. However, laser measurements are not usually affected by other reflections.

Dust and Vapour

Laser measurements can be weakened by interacting with dust and vapour particles, which scatter the laser beam and the signal returning from the target. However, using last-pulse measurements can reduce or eliminate this interference.

Target's Angle of Repose

Laser measurements can be made to targets at any angle.

Background Noise and Radiation

Laser Measurement is not affected by background noise. Instrumentation generally determines baseline radiation levels to ensure that it does not interfere with measurements.

Temperature and Temperature Variations

Laser measurements are based on the speed of light and are unaffected by temperature variations.

Vessel Pressure and Off-Gas Layers

Laser Measurement is unaffected by pressure or vacuum variations, or off-gas layers.

Thanks to OPTEK for the above information.

 

Laser Level Instrumentation and Measurement

Introduction to Laser Instruments and Applications - When the laser was invented in 1960, it was amazingly, a solution looking for a problem. While the laser's weapons potential was clear, most of the uses of lasers that have changed the World were not foreseen even by the so-called experts of the time. In this chapter, we touch on perhaps one tenth of one percent of those where lasers are now indispensable, or at least have the potential to be in the future - from repairfaq.

Lasers come to Level Measurement - Laser-level technology is expanding options in sensor applications and this article covers the good and bad points of this new measurement technique.From David W. Spitzer and ControlGlobal.com

Laser Level Measurement - David W. Spitzer - The basics, a short description - Part 1 and Part 2 - from appliedmc.

The Lowdown on Radar Level Measurement - Free-Air or Guided-Wave - Which Do You Use When? - Walt Boyes - Radar level measurement is basically divided into two groups, free-air and guided-wave - from the excellent Control Global.

Application Considerations for Continuous Level and Inventory Monitoring of Powder and Bulk Solids - Continuous level measurement is about one thing, e.g. answering the question “how much stuff do I have”. There are many applications where you need to know how much material is in a bin, silo or other vessel type. Usually the desired engineering unit is expressed in terms of volume or weight. “Measuring” volume or weight is not always the most practical approach, sometimes it isn’t even viable. Take those silos you have, how do you weigh the ingredients if the silos weren’t installed with load systems? Not an easy or inexpensive question to answer. So what do we do? This is where continuous level measurement sensors and systems come into play and offer a viable and cost effective approach.The purpose of this white paper is to discuss and inform about the application considerations when you need to measure the level of material continuously or simply determine on a continuous basis how much stuff you have in your vessels - whilst this document is about many of the technologies available it does have a section on Laser level - from Blue Level Technologies.

A Dozen Ways to Measure Fluid Level - How They Work - This article from ABB covers most level measurement techniques, however there is a small section on Laser Instrumentation for the Process Industry on page 6. 

Multiphase Flow Metering

Multiphase Metering - the Challenge of Implementation

High-Performance Multiphase Metering - a Personal Perspective

Good Practice Guide - An Introduction to Multiphase Flow Measurement - This guide provides an introduction to multiphase flow measurement. Firstly, the document covers key definitions associated with multiphase flow before moving on to multiphase flow patterns and properties. Multiphase flow measurement technologies are introduced, along with installation and flow assurance issues - from tuvnel.

The Influence of Liquid Viscosity on Multiphase Flow Meters - from tuvnel.

16^th North Sea Flow Measurement Workshop 1998

Multiphase Metering - The Challenge of Implementation

Mr A.W. Jamieson, Shell U.K. Exploration and Production

1. Introduction

“Multiphase flow measurement” is a term that has been increasingly heard since about 1980 amongst operators in oil companies and designers of oilfield facilities. For some, it promised measurement capabilities under new and trying conditions. They saw a need to simplify the design and improve the control of production facilities. They considered that, unless multiphase measurement techniques were improved, it would be virtually impossible to know what was happening in the advanced subsea systems or on the unmanned satellite platforms that were being planned. In addition they could not see how future enhanced oil recovery systems could be operated effectively without these measurements. For others, multiphase flow measurement was less appealing. They envisaged even more intricate measuring systems, which would be difficult to maintain, and which would only complicate the design and operation of the facilities - without producing a single extra barrel of oil.

It is now clear that the first view is being confirmed. After a long gestation period, reflecting the technical difficulties involved, meters with adequate performance for selected applications are now commercially available. Oil companies are keen to deploy them. At present Shell Expro has operational multiphase meters on four facilities in the North Sea and can show savings in capital expenditure of about £40 million through their use. The second view must not be ignored however. As multiphase meters are deployed in our operations unexpected difficulties will appear, as with any new technology. If these are not addressed promptly and effectively, multiphase metering will get a bad name, operator confidence will be lost and full implementation of the technology could easily be delayed for, say, five to ten years.

Multiphase flow measurement is not new. Indeed, such measurements are made routinely at most production facilities: a test separator combined with its instrumentation in fact forms a multiphase flowmeter. What is new is the changed attitude towards these measurements. Oil companies have decided on detailed requirements for such measurements, and together with scientific and industrial instrumentation specialists are working towards satisfactory multi-disciplinary solutions for specific applications. The long-term aim is a low cost multiphase meter per well.

Shell Expro has been proactive in the development of this technology, supporting development at Shell laboratories, Universities, and in Joint Industry Projects. The areas of application are varied and include wet gas metering, well testing, optimising production to delay abandonment, and allocation metering. The biggest savings come when it is possible to deploy subsea meters and performance is good enough to allocate production to third parties. By 2010 Capex savings totalling £180-280 million should have been made. Large savings in operating costs over field lifetimes should also be achieved.

None of this will happen by itself. Currently expertise in multiphase flow measurement resides in a few specialists in oil companies, manufacturers and testing laboratories. Know-how must be transferred to project teams, metering consultants; design contractors and operating staff before this technique can realise its full potential.

In this paper, I will outline the types of multiphase meters now available to the oil industry and consider a variety of applications. I think that this is the best way of illustrating the challenges that face the oil industry in implementing multiphase metering in a reasonable time scale, and also of illustrating the opportunities that multiphase metering will continue to open up for well into the new millennium.

2. Overview of Multiphase metering

The oil industry began to take a serious interest in developing multiphase meters around 1980. The problem is simple to state: we want to obtain the gas, oil, and water volume flowrates at line conditions. (At present there is a strong preference for volume rather than mass flowrates, but this preference may change.) These are the measurements that are in principle obtainable from a test separator, the oldest type of multiphase meter. Today I would identify four general approaches to multiphase metering, all of which are being actively developed and are being applied in the field.

Compact separation systems

These devices perform a rough separation of the well flow into liquid and gas streams. These are then metered using meters that can tolerate small amounts of the other phase. The liquid must be further split up into oil and water. These systems are being applied worldwide, but are bulky and do not bring the full benefits of multiphase metering with them. Typical cost £100 - 200k.

Phase fraction and velocity measurement

These meters attempt to identify the fractions of oil, water and gas and measure the phase velocities, which are not usually the same. In practice manufacturers try to condition the flow so that the phase velocities are similar, and the differences in velocity are corrected using multiphase and slip models. Most of the multiphase meters deployed in the North Sea are of this type. Typical cost £100 - 200k surface, £200 - 400k subsea.

Tracers

Multiphase flow is measured by injecting at known rates tracers (e.g. fluorescent dyes) that mix with the individual phases. By analysing a sample of the multiphase fluid taken sufficiently far downstream of the injection point, and combining this with the injection rate, the individual flows can be determined. Currently tracers are only available for oil and water. The technique is particularly suited for wet gas measurement. Costs are closely related to day rate for work and hire of equipment, say £1500 per day.

Pattern recognition

These systems are characterised by their use of simple sensors combined with complex signal processing. Potentially they offer the cheapest hardware combined with the highest metering performance. A major benefit from this approach will be targeting low cost solutions for specific applications. Cost is more variable, but within the range £20 - 60k, depending on the number and type of sensors used.

I believe that any multiphase meter can be fitted without much difficulty into one of these four categories or a combination of them. This is not to say that multiphase metering is now a mature technology and that there will only be minor improvements. Quite the reverse. I think a useful comparison can be made with the development of the motor car. The modern car is clearly similar to cars of 100 years ago. There were no fundamental breakthroughs in knowledge required to transform the car of then to what we have now, but unquestionably there has been enormous development and improvement.

The pattern recognition approach is the least familiar and most mysterious approach to multiphase metering for most people. Yet the operator who puts his ear to a pipe to listen to the flow, or who feels the temperature of a pipe to judge whether there is a flow inside it is practising a crude form of flow measurement by pattern recognition. It is therefore worthwhile pointing out some of the general features of this approach that distinguish it from the other approaches to multiphase metering. As an example, the pattern recognition meter described in the paper by Toral et al [1] presented at this workshop uses differential pressure, pressure, capacitance and conductance sensors to sense relatively fast (approx. 25 - 500Hz) fluctuations in the multiphase flow. The signals from sensors used in most metering applications are damped to reduce noise and give a good average value of the measured parameter. In the pattern recognition approach the fluctuations are what is important, and the average value may not be used at all. An analysis is carried out of the amplitude and frequency fluctuations of the sensor signals and a large number of “features” are calculated. These characterise various aspects of the signal. Thus each sensor, instead of generating only one parameter, can generate perhaps thirty “features”.

In principle we can write an equation for each “feature” in terms of the unknown oil, water and gas flow rates. This means that for the meter referred to above which has five sensors, we can write perhaps 150 independent simultaneous equations in terms of the oil, water and gas flow rates. In an ideal world one could hope to find a feature that responded only to oil, another to water and a third to gas. So far, nature does not appear to be so kind and practical methods have to be used to solve this complicated mathematical problem. In the meter above a feature saliency test is used to find the most significant features and then neural networks are used to calculate the oil, water and gas flowrates. Other mathematical techniques could have been used, however. The essential point is that the fast fluctuations in multiphase flow carry most of the information. By using heavily damped sensors the fine detail is lost with the consequence that multiphase meters using heavily damped sensors are unlikely to achieve high accuracies. Using fast sensors and pattern recognition signal processing, virtually unlimited accuracy should be possible, but one is faced with the difficulty of providing highly accurate calibration data for the meter. I believe that it is practical to achieve relative accuracies per phase of 5% by 2005, and 1 - 2%, near fiscal quality, in certain applications by 2010.

3. The multiphase triangle

The biggest obstacle to the successful implementation of multiphase metering is the general lack of understanding of what it is about. It is difficult to explain simply why multiphase metering is so complex. When discussing multiphase metering with colleagues working on prospect development, the general expectation they seem to have is that there can be a universal multiphase meter that can measure all three phases to high accuracy simultaneously over a wide range of flowrates, different for each phase. They tend to assume that measurements from test or production separators are of relatively high quality, because measurements have been made that way for a long time.

Various ways have been proposed to show how the multiphase flow characteristics of a well or a field change with time, and to show the operating envelopes of multiphase meters. The most useful I have found are the plots of application multiphase flow and meter envelopes on a two phase plot of liquid flowrate against gas flowrate, Fig. 1, and a plot of application watercut against gas volume fraction, Fig. 2 [2,3,4].

Such plots are essential when planning to install a multiphase meter, but they do not give the uninitiated person a grasp of how a specific application fits into the whole multiphase picture.

I have found that in explaining multiphase flow, the “Multiphase Triangle”, Fig. 3, is more useful and more readily understood than Fig. 2 above. It is an approach commonly used in other disciplines for displaying properties of three component mixtures.

The vertices of the triangle represent single-phase gas, oil and water, while the sides represent two phase mixtures and any point within the triangle represents a unique three-phase mixture. The transition region indicates where the liquid fraction changes from water-in-oil to oil-in-water. The ranges of common multiphase flow regimes, which are affected by temperature, pressure, viscosity and flowline orientation, are indicated at the side of the triangle.

Most of the work over the last two decades has concentrated on developing two-phase meters i.e. oil/gas. New advances in measuring three-phase flow allow us to operate over a larger fraction of the triangle.

A former colleague, Rob Smeenk, proposed this approach in the early 1980’s. At that time the triangle was quite bare. We could only measure single-phase flow of oil, water and gas; we could also measure part of the way along the oil-water line. A real indicator of the progress that has been made since then is the detail that has been added to the triangle.

It is easy to use the triangle to show why multiphase metering is complex. If we have difficulty with the single phases, which are so obviously different from each other, we can expect measurement to be at least as difficult for any multiphase composition in the triangle. We have to add to that the complexity from the flow regimes. Flow regime maps have been determined by subjective observation in laboratory testloops, almost always for two-phase mixtures, say oil-gas or water-gas. These maps vary for temperature, pressure, viscosity, pipe orientation. There have been only a few attempts to make three phase flow regime maps, and these are very complex.

This means that it is not practical to predict the performance of multiphase meters from first principles and that detailed empirical testing will be needed. Obviously, the higher the performance demanded from the meter, the better the test facilities need to be. In time, when enough applications have been examined we should be able to see generalities, but for the next few years at least each application will need to be treated on its own merits.

4. Applications

I have shown applications that lie in different regions of the triangle. Discussion of these in turn shows how we can build on experience from one application to tackle a more difficult one, and why it is wise not to try to install a multiphase meter in too difficult an application.

Application 1 in Fig. 3 is topsides wet gas metering, using venturi meters, with about 1% by volume of liquid at operating conditions. The corrections to gas flow because of the liquid are derived from a test separator. This is a high quality measurement: the accuracy claimed is about 1.5%.

Application 2 is a gas condensate field with about 2% by volume of liquid, so it is similar to Application 1. To be economically viable, it will probably be developed as a subsea installation. This precludes the use of a test separator. Initially metering is required for well testing for reservoir management, but later in field life may need to be used for third party allocation. Subsea tracer injection to determine the liquid/gas ratio is a possibility, or using the fact that pressure recovery of a venturi meter is related to the liquid/gas ratio. Pattern recognition techniques are also likely to be suitable. In any case, special studies will be required for the initial application, and even more for third party allocation.

Application 3 is another gas condensate field, with about 10% by volume of liquid. Again, to be economically viable, this field will probably have to be developed subsea. It is obviously more difficult to use wet gas metering, but limited studies to date indicate this is probably feasible. Again, the initial application will be reservoir management, but there may be need to meter for third party allocation later in field life.

These three applications illustrate the progression of wet gas metering from dry gas to about 10% liquid, or 90% Gas Volume Fraction (GVF). Compact separators are also practical in high GVF applications, albeit not in Shell Expro’s circumstances. Moreover, the phase fraction and velocity measurement approach, which was originally targeted at 50-60% GVF, has been extended to GVFs of over 90% in special circumstances, so that I think it is now best to treat wet gas metering simply as an important subset of multiphase metering.

Application 4 is a very long subsea tieback, with a multiphase meter required for well testing and reservoir management. The well will be natural drive throughout its life, so the reservoir engineers expect hardly any water. This will most likely be Shell Expro’s first subsea multiphase meter, and from the multiphase triangle it is easy to see why this is an ideal first application. We only have to measure two phase flow, and have the capability of detecting water breakthrough should it happen. We could do that ten years ago, so from the measurement point of view we can be confident that we can make that measurement subsea. The stiffer challenge is in getting the operational aspects of the installation right to minimise the need for expensive maintenance.

Application 5 is unusual in that it is to measure the water/gas mixture produced in the depressurising of a reservoir. The accuracy required for this two-phase measurement is about 10%, but equipment must be low cost. Again, we know that this measurement can be done by a variety of equipment. As with all multiphase metering, it is not a trivial matter to get it right.

Applications 6 and 8 are subsea tiebacks to a floating production installation where there is a multiphase meter for well testing instead of a test separator. The trajectories followed by these wells across the multiphase triangle show how the small reservoirs being developed in the North Sea today decline rapidly to water.

Application 7 is on an old field, where there is no test separator and well testing had to be done by deferring about £800,000 worth of production each year. If one can reduce this deferment, it is evident that this will help in delaying abandonment. The measurement had to be low cost, and a pattern recognition approach is being evaluated.

I have also included two other fairly general areas of application. In Oman, there are many low-pressure wells with no gas at wellhead conditions, and so are two phase oil-water mixtures. These are tested using Coriolis meters, with the density measurement used to determine the oil and water flowrates.

Well engineers are considering downhole multiphase metering, especially for multilateral wells where there is a need for a meter in each branch of the well. To me, the main advantage in metering downhole is to suppress the gas fraction and reduce the measurement to an oil/water measurement. I would expect the GVF to be low for this area of application, and the meters need to be designed accordingly.

In Shell Expro, apart from the high accuracy wet gas meters, we have found it very difficult to make direct comparisons of the several multiphase meters we have installed with other metering, usually test or production separators. Without exception, however, the multiphase meters have shown up deficiencies in traditional separator measurements. From evaluations carried out in test labs and offshore, I think it is fair to say that several multiphase meters perform as well as traditional test separators.

5. The Market

With this review of multiphase meter applications I think it is clear that there can be no single multiphase meter that can satisfy all requirements. This is good news for multiphase meter manufacturers and developers. Through much of the last two decades, manufacturers and oil companies have chosen a particular approach and have concentrated on that to the exclusion of other approaches, hoping that their approach would be “the winner”.

Table 1 Wells World Wide

(source KOP)

LOCATION	NUMBER	AVERAGE PRODUCTION BBL/DAY
USA	572,000	11
Venezuela	15,000	191
Argentina	13,000	57
Canada	47,000	29
Western Europe	6,420	990
Rest of World	251,000	188

The best way to use multiphase meters is to have one per well. Table 1 shows the number of wells in different regions of the world. There are about one million. Many of these have very low production rates by North Sea standards, but I suggest that a modest target would be for the oil industry to install multiphase meters on 1% of the wells by 2010. That means 10,000 meters, or about 900 a year between now and 2010. I think most of these wells are on land, and that the meters would be used for well testing. Thus with a relatively modest improvement in performance multiphase meters can be deployed widely. At an average cost per meter of £100,000 that is a market of £I Billion. I think there is room for a few winners in that market.

For the North Sea the picture is different. There are about 1000 wells in the North Sea, and I suggest that a reasonable target is about 100 multiphase meters by 2010. Most of these would be subsea for well testing or third party allocation, and will therefore cost more, say an average of £200,000, giving a market of only some £20 Million, less than £2 Million a year between now and 2010.

6. The future of multiphase metering

We in the countries around the North Sea like to think we are leading the development of multiphase meters. We have set challenging targets for multiphase meter performance, but it is evident that the North Sea market for multiphase meters is not big enough for manufacturers on their own to develop, say, multiphase meters for third party allocation. For Shell Expro, if the performance of multiphase meters stops at “well testing” standard, we will not require many multiphase meters topsides or subsea, but neither will we get the benefits from using them. Clearly for the North Sea operators there is a major challenge to improve the performance of multiphase meters significantly over, say, a five-year period.

There is little appreciation of the time it takes to develop and test multiphase meters. Last year I made what was intended to be an upbeat presentation to colleagues working on new developments, and told them that we could reasonably expect to develop multiphase meters for third party allocation by 2005. Their response was that they already needed that quality of performance for projects they were working on and that they could not wait for that length of time.

From the testing we have done on multiphase meters offshore, and what I have seen done by other companies, I believe that it is impractical to verify the performance of multiphase meters offshore to high standards except in very exceptional circumstances. Valves on test separators or on production manifolds frequently pass sufficiently to make detailed verifications impossible. It is often difficult to maintain stable operation of separators to allow detailed comparison. To put it simply, if we have the facilities to carry out such verification, we probably don’t need to install a multiphase meter.

The consequences of this are that most of the testing to show that a multiphase meter has a high performance will have to be done at special test facilities that can simulate realistic operational conditions. There are one or two facilities that may be suitable, but they are unlikely to be able to cover the likely range of flow conditions. It is unlikely that tests done on current laboratory test loops will be sufficiently convincing.

7. Conclusions

Multiphase metering is at the stage of development where oil companies can deploy them to bring large benefits:

Multiphase meters are now being applied successfully by a number of companies. Apart from the obvious financial benefits, they allow operators and reservoir engineers to monitor oil and gas production in ways not possible before, thus aiding production optimisation. In the long term, this will probably be the biggest benefit from the use of multiphase metering.

Existing multiphase meters or indeed any multiphase meter likely to be developed can be fitted into one or a combination of the four approaches currently used in multiphase metering. These approaches offer different levels of technical complexity and require different levels of understanding. Operating companies can therefore choose a multiphase metering system suited to their specific needs.

Enough development and testing has now been done to show that high performance multiphase meters for third party allocation and for near fiscal measurement are practical, and that their realisation need not be too far off. In this respect the pattern recognition approach, on its own or in combination with the hardware from the other approaches is most relevant.

The potential market world wide for multiphase metering systems is very large. No single type of meter or metering approach can hope to cover all applications. Although we can expect that some manufacturers will withdraw, others may enter the market. There is clearly room for several suppliers.

However:

• Multiphase metering systems are most certainly not “fit and forget” equipment in their present state of development. They should only be deployed where there are clear financial benefits and where there is real commitment to making them work.

• Widespread implementation of multiphase metering cannot take place until expertise is spread more widely throughout the oil industry. Most of the expertise in multiphase metering is held by specialists in oil companies, by developers and by manufacturers. Metering consultants and facility design houses are slowly beginning to build their expertise.

• Multiphase metering is a complex subject. It is important to develop ways to explain the complexities in a readily understandable way. The Multiphase Triangle approach appears to be a useful tool.

• The market situation in the North Sea is different to the rest of the world. The technical requirements for most likely applications are really beyond the capabilities of the products that manufacturers can reasonably supply at present. The North Sea market for multiphase meters on its own is unlikely to bring sufficient return on investment for manufacturers to develop the higher performance meters required in the North Sea.

• If North Sea operating companies wish to gain the very large benefits of multiphase metering, they will have to provide the financial backing to support the development of higher performance meters.

8. References

1. H. Toral, S. Cai, E. Akartuna, K. Stothard, A.W. Jamieson, Field Tests of the ESMER Multiphase Flowmeter, 1998, North Sea Flow Measurement Workshop, Gleneagles, Scotland.
2. C.J.M. Wolff. Required operating envelope of multiphase flow meters for oil well production, 1993, North Sea Flow Measurement Workshop, Bergen, Norway.
3. Handbook of Multiphase Metering, Norwegian Society of Oil and Gas Measurement.
4. W. Slijkerman, A.W. Jamieson, W.J. Priddy, O. Okland, H. Moestue, Oil companies needs in multiphase flow metering, 1995, North Sea Flow Measurement Workshop, Lillehammer, Norway.

Optical Fibre Technologies in Instruments

Fibre optics are certainly part of the new and emerging technologies themes.

Leak detection in pipelines - here are several very interesting articles from Future Fibre Technologies.

FFT FOPSS LDS IntroPaper.pdf

FFT Pipeline Integrity Paper.pdf

Fibre Optic Sensors for Measurement of Flow, Level, Pressure, Stain, Temperature and Vibration.

Super information from Davison Instruments, to get their papers click here.

Shutdown and Blowdown Valves - Partial Closing Techniques

For some years now there have been systems available to check and report on the operation of shutdown and blowdown valves by partially closing and validating the results.

There are various schools of thought on the technique, and whilst it does not fully validate the integrity of the valve, the partial closing does give the valve some exercise and monitor such things as break out torque and parameters over the 10-20% operation. This must improve the chances of operation during a true demand on the system and hence enhance integrity.

Also, of course, there usually are trips during operation, when this occurs a window of opportunity arises to capture all the valve status information across both the opening and closing stokes of the valve. This is usually achieved by a comparison against the "new footprint" or signature of the valve. Thus faults will be sensed by Torque changes, slower speed of operation etc. Data such as this is captured either by propriety software or Asset Management Systems. Hence the software can predict that the valve is going to fail and schedule in appropriate maintenance at an appropriate moment (rather than have a unplanned and rather expensive shutdown).