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

The economics of subsea sampling in Oil Industry

The role of subsea sampling in securing maximum effectiveness from multiphase meters is reviewed here by Mirmorax chief executive Eivind Gransaether. He discusses how subsea sampling is addressing other crucial production management issues offshore, such as injection water, water breakthrough, chemical analysis and EOR, and the major impact it is having on today’s field economics.

With test lines for subsea well testing costing as much as $60 million and the accompanying logistical challenges involved, the installation of permanent subsea multiphase meters, as an alternative to well testing and as a means of increasing recovery, has become a priority for many operators today.

The figures also bear this out: Gioia Falcone from Texas A&M University and Bob Harrison of Soluzioni Idrocarburi estimate that, as of 2010, over 3300 multiphase meters were installed worldwide.

Yet, the focus on multiphase meters – however important – overlooks the crucial role of subsea multiphase sampling in offshore fields today. Multiphase meters can only be truly effective and accurate if they are precisely calibrated and are subject to high quality, volumetric sampling and reliable reservoir simulations over the field’s lifetime.

For all their current effectiveness, multiphase meters face a number of offshore challenges today. These include the wide range of conditions and fluctuating flow rates in many offshore fields. Many wet gas fields, for example, produce over a wider range of process conditions than previously with an increased amount of liquid and water in the gas flow.

In addition, remote field locations, growing water cuts and fast changing reservoir and well characteristics are becoming increasingly common in reservoirs today, putting more pressure on multiphase meters.

The last few years have also seen a growth in subsea tiebacks and longer horizontal production pipelines, as operators look to tie in smaller fields to existing infrastructure and better manage costs. This growth has exacerbated the importance of real-time, subsea monitoring of the transferred fluids for both flow assurance and production allocation purposes.

With longer tiebacks and potential delays to detecting water breakthrough, for example, the need to track threats to pipeline and production integrity and accurately measure production and fiscal allocation is crucial.

Under such circumstances, metering systems today are facing huge pressure to accurately track multiphase and wet gas flows and overcome any potential threats to accuracy, such as changes in oil characteristics and varied flow conditions outside their calibration ranges. This is where subsea sampling comes in.

Subsea sampling and processing can play a key role in generating the fractional data on oil, gas, water, salinity, PvT (Pressure, Volume, and Temperature) and other information that today’s multiphase meters need to be calibrated for. In that way, such meters can operate to maximum effectiveness.

Despite their clear importance however, many subsea sampling systems have been relatively crude in the past, failing to generate a truly volumetric representative sample that contains fluids from all the phases.

Such sampling techniques include the hot stab method, used to move fluid from one device to another; extraction by differential pressure; or flowing the well to a surface test facility that then captures samples.

The weaknesses of these techniquesare that they are used just topside and are manually-driven; samples are taken randomly without taking note of the flow dynamics of the fluids being sampled; and the original conditions in the field, such as pressures, are overlooked. The result is an incomplete sample with the differential pressures used to sample and then transport the samples a main source of inaccuracy. So how can we address these limitations?

In designing a new subsea sampling system, a key criterion was that it must be deployed subsea close to the wellhead, where more accurate fluid properties can be generated and where multiphase meters are deployed.

What was also vital was to maintain the sample at its original pressure conditon from extraction to delivery to the surface and then transportation to the laboratory facility. Maintaining the pressure condition and the true representation of the process is crucial in providing accurate PVT analyses.

This has been achieved through an ROV-based subsea sampling system with a number of key elements. Via the ROV, the subsea sampling system extracts and transports samples into sampling bottles under isobaric conditions and then transports them to the surface. This is achieved through an ROV-operated docking sampling unit (DSU), consisting of a docking unit, a hydraulic sample extraction system and sampling bottles.

The ROV transports the sampling device from the surface vessel and docks onto a stationary subsea sampling interface (SSI) through a standard hydraulics and manipulator system. The two parts are then connected with a robust connector and barriers which are then tested to verify pressure integrity. Figure 1 illustrates the system in sampling mode, after the DSU has been docked onto the SSI.

This operation is then repeated multiple times on the same well in order to secure a set number of samples over a certain time period. The result is a sampling system subsea and close to the wellhead and a seamless process from sample collection to final analysis topside.

Applications today

It has already been stressed how accurate subsea sampling can play a key role in effectively calibrating multiphase meters. This is particularly the case as fields age with the uncertainty of metering systems tending to grow over time (see Figure 2) and confidence in real-time production data diminishing as field conditions change and the verification of input data becomes more cumbersome to obtain.

In such circumstances, effective volumetric subsea sampling can play a key role in sustaining production and having a positive effect on the bottom line and financial returns from the field.

Aside from multiphase meters, effective subsea sampling can also add value to other areas of offshore production management today, helping to provide enhanced returns.

 

Take, for example, chemical analysis. With operators facing increased threats to flow assurance from hydrates, the injection of chemical inhibitors, such as methanol and ethylene glycol (MEG) and low dose hydrate inhibitors (LDHIs), is particularly popular today. Such inhibitors are playing a key role in combating scaling and corrosion, with chemicals often used to break up surface tension and facilitate the oil and gas flow.

At the same time, however, operators also need to establish greater control over the measuring and injection of hydrate inhibitors to ensure the correct inhibitor amounts are injected and that injection rates are changed when conditions change.

For thermodynamic inhibitors, such as MEG, which tend to require higher injection rates and concentrations, injection rates must be adjusted if operating parameters, such as high sub cooling or high water cuts, vary.

Having information on how these chemicals propagate from an injection well into other wells will provide operators with a better understanding of their reservoirs, enable them to optimize their chemical injection programs, and ensure better economics for the reservoir.

Effective subsea sampling is able to achieve this, generating accurate volumetric samples that can then be subjected to chemical analysis and help determine future chemical injection programs. With EOR-based chemical injection programmes, subsea sampling can track the flow of injection fluid into the well, measure its effects, and provide an accurate sample where chemical content can be extracted.

The rise of produced water re-injection (PWRI) programmes has also led to a growing need for detailed information on the size and amount of sand and oil in produced water – whether it is reinjection, discharged or processed. Again subsea sampling can play an important role in monitoring the reinjection process, generating greater detail on the specific components of produced water, and optimizing enhanced oil recovery programmes.

The financials

So what effect is subsea sampling having on the economics of reservoir management? Let’s take a look at how it supports multiphase meters as an alternative to well testing. While, it’s difficult to utilize specific numbers, it’s clear that the costs of well test lines can have a highly negative effect on the economics of a reservoir.

For example, subsea well intervention can be a labour-intensive and costly activity with rig costs running at up to $1 million a day. Aligned to this is the lost production as a result of the shutdown and the testing and reconnection of the well. For a well producing say 15,000b/d of oil, where the crude will be sold for around $95 a barrel, and where the well will lose production for 12 hours, the lost revenue is already over $700,000.

Furthermore, while the use of multiphase meters to generate real-time data, can pre-empt these costs, if these meters are inaccurate and unable to adapt to changing flow conditions, the impact on flow assurance and field economics is likely to be significant.

Alternatively, for a development that can enjoy the benefits of fixed data points for later reservoir simulation and effective multiphase subsea sampling, the cost savings and positive impact on flow assurance are likely to be substantial.

Whether it is multiphase meter calibration, enhanced oil recovery, chemical injection or subsea tiebacks, it’s crucial for today’s operators to have effective subsea sampling and monitoring capabilities in place.

Encouragingly, it now seems that the technologies are now rising to this challenge and delivering significant financial benefits to the reservoir. OE

By: Eivind Gransaether
Issue: February 2012

Eivind Gransaether is CEO of Mirmorax, the company he founded in 2009. He previously served as subsea engineering manager at Norway’s Roxar (now part of the Emerson group). While with Roxar, he was development manager for that company’s Subsea Retrievable Multiphase meter (SRC) and was also responsible for three other product developments.

Source: OilOnline.com  - View original Article