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

The skid mounted multiphase meter.

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

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

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

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

Meter application

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

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

Benefits

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

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

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

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

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

Description

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

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

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

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

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

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

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

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

Operational experience

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

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

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

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

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

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

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

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

Conclusion

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

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

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

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

References

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

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

 

Source :Offshore-Magazine

Commingled multiphase flows – the metering challenge

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

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

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

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

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

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

Multiphase metering – is it ready?

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

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

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

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

Developing technology

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

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

Improving reliability, packaging

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

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

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

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

Two-phase flow in Vertical Perspex Venturi.

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

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

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

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

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

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

Future challenges, opportunities

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

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

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

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

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

Readying the technology

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

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

Source: Offshore-Mag.com   -   View Original Article

Multiphase Metering in Challenging Environments

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

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

The heavy oil challenge

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

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

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

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

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

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

Sour service environments

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

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

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

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

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

Limited maintenance

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

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

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

The problem of scaling

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

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

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

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

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

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

Source: Offshore-Mag.com   - View Original Article

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