Mirmorax

Drilling & Exploration World (Dew) Journal (December 2011)

This article was published in Drilling & Exploration World (DEW) Journal in December 2011

LATEST DEVELOPMENTS IN SUBSEA SAMPLING & MONITORING

    BY EIVIND GRANSAETHER, CEO, MIRMORAX

As oil & gas demand continues to outstrip supply and as operators focus on managing costs and bolstering production, the effective subsea sampling and monitoring of oil & gas reservoirs has rarely been more important.

There are a number of reasons behind this renewed focus on sampling and monitoring relating to the following areas: multiphase meters and the need for these meters to operate at their full potential; the increased use of subsea tie-backs; the growth in brownfields and Enhanced Oil Recovery (EOR) programmes; and the rise in chemical inhibitors.

This article will examine these challenges in greater detail and examine how the latest developments in subsea sampling and monitoring (particularly oil in water monitoring) are addressing them.

The Growth & Importance of Multiphase Meters

One of the key means of generating accurate and reliable information from oil & gas wells is through multiphase and wet gas meters.

Such meters provide crucial real-time information on flow conditions in the reservoir. They can be used to determine maximum oil production and gas handling capacity and provide early warnings if there is water breakthrough, for example. As well as being valuable to day-to-day operations, the meters are also a key element of long-term field development plans ensuring improved ultimate recovery over the lifetime of the field.

It comes as no surprise therefore that as of 2010, there were 3,314 multiphase meters and wet gas meters installed worldwide, according to Gioia Falcone of Texas A&M University and Bob Harrison from Soluzioni Idrocarburi Srl. The same authors estimate that this number will double over the next 10 years.

One of the biggest challenges with multiphase meters today, however, is ensuring that they continue to operate at peak performance as flow and field conditions change and as the verification of input data becomes both cumbersome to obtain and unreliable.

Here, 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 the meters need to be calibrated for, in order that they can work at their full effectiveness.

The Growth in Subsea Tie-Backs

Another key driver today in subsea sampling and monitoring is the growth in subsea tie-backs.

The last few years have seen a growth in subsea tie-backs as operators look to tie in smaller fields to existing infrastructure and also manage costs. Some tie-backs today are as long as 150 kilometres and are prevalent in regions, such as the North Sea and Gulf of Mexico.

In the North Sea, for example, according to the UK trade association, the Energy Industries Council (EIC), 90% of all UK Continental Shelf offshore pipeline projects involve subsea tie-backs. Current North Sea tie-back examples include the Laggan to Shetland gas pipeline; the Sea Marten, Bright and Polecat oil & gas fields in the Central North Sea Block 20/3; and in Norway, the future Ormen Lange Phase 11 expansion project and the active Gjøa Oil & Gas field.

This growth of such tie-backs and longer horizontal production pipelines, however, brings with them a number of new challenges. The risk of longer tiebacks, for example, is that it takes longer to detect a water breakthrough in the well, which could lead to severe consequences and pipeline damage, before corrective action can be taken. The increase in carbon steel pipelines for cost saving purposes and their vulnerability to saline formation water has only increased the importance of real-time monitoring.

In such circumstances, real-time, subsea monitoring and sampling is crucial to track the fluids that are being transferred to support flow assurance and any threats to pipeline and production integrity. Potential threats to accuracy include changes in oil characteristics and varied flow conditions outside the calibration range.

Brownfields & EOR Programmes

According to the World Energy Organisation, 70% of the world’s oil and gas production comes from fields over 30 years old. This growth in brownfields has led to significant requirements in regard to subsea sampling and monitoring.

As opposed to newer fields, brownfields tend to have more flow assurance implications, with the increased danger of water and gas breakthrough in the wells – factors which can impact production capabilities significantly. The accompanying pipelines are also highly vulnerable to saline and unchecked water

The increase in brownfields has also seen an increase in enhanced oil recovery (EOR) programmes, such as the use of reinjection water to maintain field pressures. This has led to a corresponding increase in the need for water volumes to be treated in process facilities;  and the growth in chemical injection programmes.

The rise of Produced Water Re-Injection (PWRI) programmes, for example, has led to a rising  need for detailed information on the size and amount of sand and oil in produced water – whether it is reinjection, discharged or processed. The effective monitoring and control over the reinjection process can also help optimise the water flooding of the reservoir and ensure maximum production performance.

In addition, greater detail on the specific components of produced water can help improve the separation of oil and water taking place in separation process facilities, with there being real dangers to production optimisation if produced water is not carefully monitored.

Potential problems – during the separation process and production – can include the plugging of disposal wells by solid particles and suspended oil droplets, the plugging of lines, pumps and valves due to inorganic scales, and corrosion due to the electrochemical reactions of the water with piping walls.

Furthermore, in the case of chemical injection programmes, operators are looking for subsea sampling and monitoring information on how the chemicals propagate from an injection well into other wells. In this way, they can have a better understanding of their reservoirs and optimise their injection programs.

Chemical Inhibitors

Finally there is the rise in chemical inhibitors. 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), has never been more widely used. Such inhibitors are playing an important role in combating scaling and corrosion, with chemicals often used to break up surface tension and facilitate the oil & 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. Subsea sampling can play a key role in guaranteeing this control.

The Rise in Subsea Sampling

We have seen some of the challenges that necessitate effective subsea sampling and monitoring, yet are today’s technologies rising to the challenge? The rest of the article will address this question – firstly, subsea sampling.

There are a wide variety of subsea sampling techniques on the market today. These include the hot stab method, extracting the samples by differential pressure, or flowing the well to a surface test facility that captures samples.

Such techniques, however, share a number of limitations. They are often used just topside and are manual-driven; samples are taken randomly without consideration to the flow dynamics of the fluids being sampled; and the original pressure conditions are rarely maintained.

The result is an inability to generate a truly volumetric representative sample that contains fluids from all the phases and that can play a key role in areas such as multiphase meter calibration, tracking the injection of chemical hydrate inhibitors, and monitoring subsea tie-backs.

It’s against this backdrop that the Mirmorax Subsea Process Sampling System (SPSS) delivers true volumetric sampling of oil, gas and water in the well as well as high quality PVT analysis, salinity and chemical content.

Via its ROV (Remotely Operated Vehicle), the subsea sampling system extracts and transports the sample into sampling bottles under isobaric conditions and then transports them to the surface.  Key components of the new system are 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.

The operation described is repeated multiple times on the same well in order to secure a number of samples over a certain time period. The result is a seamless process from sample collection to final analysis topside - from extracting a representative sample, taking to the surface and then storing and transporting to the laboratory facility.

As well as the true volumetric representation it generates, the subsea sampling system is the ideal solution for measuring fluid composition within subsea tie-backs over the lifetime of the field, negating the high costs of subsea interventions and periodic fluid sampling.

The system also supports EOR programmes, such as chemical injection, by tracking the flow of injection fluid into the well, measuring its effects, and providing an accurate sample where chemical content can be extracted.

Finally, the validation of reservoir models and reservoir simulations depend on accurate sources of field information being generated over the lifetime of field. The subsea sampling system generates this data, irrespective of production rates or how long the field has been in production.

Oil in Water Monitoring

Again, like subsea sampling, traditional oil in water monitoring techniques have their limitations. They have tended to be manual and highly labour intensive and reliant on spot data to calculate a continuous flow, with the results often varied and inconsistent.

The Mirmorax Oil-in-water (OiW) monitor, however, counteracts this by being a highly effective processing and monitoring solution that can track water production and ensure that both production and separation facilities are performing optimally.

Traditionally designed to operate topside, we are currently developing a subsea application of the meter, which can allow for water characterisation at an earlier stage of the process and enable the monitor to become an important tool in subsea monitoring and processing.

The monitor is based on an ultrasonic measurement technique in which individual acoustic echoes from both solids and oil droplets are analysed. Each detected echo is analysed and classified as coming from an oil droplet, a sand particle or a gas bubble and concentration levels can then be calculated based on the size distribution. The monitor caters for concentrations of up to 1000 parts per million (ppm) and can provide complete size distributions ranging from two to three micrometers.

The information the monitor provides on the specific components of produced water brings with it a number of benefits.

The accurate monitoring of water during production, for example, prevents obstacles to production and plays a key role in production optimisation with ensuring maximum production performance.

For example, the monitor can detect oil and solid particles in produced water re-injection (PWRI), preventing surface sludge formation and oil saturation, facilitating wastewater disposal, and ensuring that pressures are maintained for enhanced oil recovery.

The information the monitor generates on sand and oil size distributions and concentrations will also minimise effects such as plugging and any decline in formation permeability which can reduce reservoir pressure and injectivity in water flooding operations. In addition, too much oil lost in production and a combination of fine sands and small oil droplets can also clog injection wells.

Finally, the monitor can also result in the

Rising to the Challenge

Whether it is multiphase meter calibration, enhanced oil recovery, chemical injection or subsea tie-backs, what this article has demonstrated is how crucial it is for operators today to have effective subsea sampling and monitoring capabilities in place.

While the challenges and demands are continuing to increase, it’s encouraging to see that a number of technologies are now keeping up.

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by Mirmorax

Chemical engineer (Dec 2007)

This article was published in the Chemical Engineer in December 2007 by the previous owners of the Oil-in-water product line, Roxar. Mirmorax acquired the Oil-in-water (OiW) product line from Roxar in March 2011.

THE GROWING IMPORTANCE OF OIL-IN-WATER MONITORING

                  BY GEIR AANENSEN, ROXAR

The Rise in Produced Water

The last few years have seen a significant increase in global water production in the oil and gas industry.

Whereas today current oil production is 80 million of barrels per day approximately, current estimates of global water production are 250 million barrels per day – a three to one ratio. Today, the average water cut globally[1] is 75 per cent – a five per cent increase on water cuts ten years ago.

The increase in produced water is being seen on the Norwegian Continental Shelf where water/oil ratios have increased from 0.93 in 2005 to 1.13 in 2005 and annual emissions of oil into the sea are estimated at 3000 tons of oil (see figure 1)[2].

Taking a Closer Look at the Water

With the increase in produced water has come the increased need from E&P (Exploration & Production) operators for detailed information on the size and amount of sand and oil in produced water – whether it is reinjection, discharged or processed water.

There are a number of drivers for this – some economic, some environmental and some both.

Optimising Production 

There are a number of means in which increased oil in water monitoring can help optimise production.

Firstly, there is lost revenue due to oil being lost through produced water discharge. According to energy industry analysts Douglas-Westwood, 2.1 million barrels of oil are lost every day through water discharge[3].

Secondly, greater detail on the specific components of produced water can help optimise the separation of oil and water which takes place in separation process facilities and which has increased over the last few years with the maturing of fields.

The information on sand and oil size distributions and concentration will help the operator optimise the separation process and ensure that all separation equipment is designed to and working within its operating range with respect to particle size.

Accurate oil in water monitoring has a vital role to play in efficiently monitoring separators, hydro cyclones and chemical injection and accurate knowledge on size distributions will also aid the operator in optimising production through the enhanced design and use of separators and filters.

Finally, there are real dangers to production if produced water is not carefully monitored – not just during the separation phase but throughout production. Potential problems can include the plugging of disposal wells by solid particles and suspended oil droplets, the plugging of lines, pumps and valves due to inorganic scales, and corrosion due to the electrochemical reactions of the water with piping walls.

Real-time monitoring will enable the operator to make knowledge based decisions when it comes to water treatment facilities.

The Brownfield Challenge 

Linked to the challenge of optimising production through more effective oil in water monitoring is the growing challenge of brownfields.

Today more than 70 per cent of the world’s oil and gas production comes from fields that are over 30 years old[4] - fields which may well have started off producing very little water but are producing large volumes of water and increased water cuts today. In these cases, the ability to efficiently and economically dispose of this water is critical to success.

Another inevitable result in the growth of brownfields and the need to increase recovery rates (which currently tend to be between 35 and 40 per cent) is reinjection water to ensure pressures are sustained.

In this case, it is essential that all oil and solid particles in the produced water re-injection (PWRI) are detected to ensure higher recovery rates and longer lifetimes for existing oil fields. If not, surface sludge formation and oil saturation can cause significant problems.

Information on sand and oil size distributions and concentration will also minimise effects such as plugging and decline in formation permeability which can reduce reservoir pressure and injectivity in water flooding operations.

Effective monitoring and control over the reinjection process will optimise the water flooding of the reservoir and ensure maximum production performance.

The Environmental Challenge 

We have discussed some of the economic advantages of effective oil in water monitoring but probably the single biggest driver today in accurate oil in water monitoring is the environmental driver - the need to meet environmental requirements on produced water discharge.

Today, oil in produced water accounts for about 90 per cent of the total amount of oil discharged into the North Sea by the oil and gas industry[5].

Measurement of oil in produced water is now required by law. Regulations include the 2000/2001 Oslo/Paris Convention (OSPAR)  - also known as the Convention for the Protection of the Marine Environment of the North-East Atlantic; the UK’s Dispersed Oil in Produced Water Trading Scheme and The Norwegian State Pollution Control Authority (SFT)’s regulations, which call for zero harmful discharge into the sea.

OSPAR is the international regulation with its goal being to ‘…prevent and eliminate pollution by oil and other substances caused by discharges of produced water into the sea.’ 

The required performance for OSPAR in 2007 is that ‘no individual offshore installation should exceed a performance standard for dispersed oil of 30 mg/l for produced water discharged into the sea.’ 

Within this context, it is essential that E&P operators can demonstrate to regulators and government the effective monitoring of oil in water. And the need to adhere to legal requirements and avoid financial penalties is not the only driver.

An effective monitoring of discharges and attempts to reduce such discharges through accurate monitoring can open up opportunities for participating in emission trading schemes.

Manual Sampling and Its Flaws 

So what technologies are available for oil in water monitoring today?

Traditionally, oil in water monitoring consisted of manual sampling. According to what was previously the OSPAR defined reference method, this would consist of taking one litre samples from the produced water discharge, acidifying to a low PH and then extracting with tetrachloroethylene (also known as perchloroethylene, perc, PCE, and tetrachloroethene).

Once the solvent is extracted, infrared quantification would then take place with oil content determined by the infrared absorbance of the sample extract and the total -CH₂   that is present (as defined in the OSPAR Agreement 1997-16).

According to OSPAR regulations, at least 16 samples must be taken each month for installations that discharge more than two tonnes of dispersed oil per year.

There are a number of down-sides to manual sampling, however.

Firstly, as they are spot samples and as the concentration of the oil in water often vary over time, operators are not getting the full, accurate picture. The use of spot data to calculate a continuous flow is only valid if the measured component is consistent with time. Figure 2 provides a good illustration of the dangers of manual sampling.

There is also potential confusion as to what constitutes ‘dissolved’ and ‘dispersed’ oil with both extracted by the extracting solvent. Whereas dispersed oil tends to refer to small droplets in produced water (containing aliphatics, some aromatics (PAHs) and acids), dissolved oil can also take the form of soluble hydrocarbon compounds, such as benzene, ethyl benzene, toluene, and xylene (BTEX) which are only partially soluble in water.

When the calibration takes place after solvent extraction, it is the total absorbance of -CH₂ measured that is plotted against the known concentration of the crude oil (total hydrocarbons) in the solvent.

As a result what is measured using the IR method are the total hydrocarbons including both the dispersed and dissolved oil. The result is that dissolved oil is often included in the dispersed oil content, making it more difficult for operators to effectively and accurately meet the OSPAR target of ‘dispersed oil not exceeding “30 milligrams per litre (mg/l).’ (italix)

Health & Safety 

There are also concerns about the health and safety implications of tetrachloroethylene – so much so that OSPAR today recommends a new reference method involving Gas Chromatography and Flame Ionisation Detection (modified ISO 9377-2 GC-FID).

While this is to be applauded, there is a real danger that this will lead to even greater inconsistencies in manual sampling due to the inherent differences between ISO 9377-2 GC-FID and the previous method of infrared quantification.

Whereas in countries, such as the Netherlands, there is no legal requirement to avoid tetrachloroethylene, in countries, such as Norway and Denmark, an alternative method has become a priority. In the UK, the new OSPAR reference method as detailed above came into force on 1 January 2007, although in the words of the Department of Trade & Industry ‘it is anticipated that some offshore facilities will continue to use the IR method.’ 

The result is inconsistent ways of analyzing the spot samples with varying results.

Staff Productivity 

And the final, perhaps most obvious downside of manual sampling, is the labour intensive nature of the process. A more automated form of monitoring would have a significant impact on freeing up resources and improving staff productivity.

The Need to Monitor the Separation Process 

Another weak link in oil in water monitoring is during the separation process where chemicals, such as biocides, emulsion breakers or corrosion inhibitors, are often used to improve oil/water separation.

How the chemicals are used can influence the final result. If, however, you have information on the amount of oil in water, and especially the droplet size distribution during different stages of the separation process, you have more empirical information to go on when introducing the chemicals. The oil droplet size distribution found at different stages in the process may influence your separation efficiency significantly.

The Emergence of Online Monitoring 

A constant theme throughout this article is the gap in information available to the operator. While the latest in multiphase metering technology is enabling operators to have accurate, real-time information on flow rates, water and sand in the well stream, the same doesn’t appear to be the case for oil in water monitoring.

The situation is changing, however, with the emergence of online, inline oil in water monitoring technologies. The move towards ‘inline’ monitors, where there is no need for sidestreams or sample extractions and where the monitor design is essentially like a flow instrument similar to a multiphase meter, is an important development.

Online, inline monitoring and its ability to provide direct measurements at the dispersed and suspended phase provides clear benefits to the operator with more detailed information on the size distribution and concentration of oil and sand in water and, as a result, more accurate discharge figures; a reduction in labor intensive sampling; and an avoidance of exposure to solvents, such as tetrachloroethylene.

The fact that the monitoring is able to take place in real-time also provides a highly effective early warning system. When the water sample analysis comes back from the laboratory showing that something is wrong, the damage may already be done. With online monitoring, if something happens, such as the identification of a process upset, you know about it and can react accordingly (as a result reducing oil pollution).

Real-time monitoring also optimises the entire ongoing separation process. With any deviation, one can quickly step in so that production can continue and be optimised. Separators, hydro cyclones and the type and regularity of chemical injection can all be run accordingly. The environmental and economic impact is obvious.

Remote Management 

And with the rise in remotely managed operations and increase in subsea tiebacks, online, inline oil in water monitoring provides effective knowledge-based maintenance for remote operations with information distributed and assessed by both offshore and onshore personnel.

Ultrasonic Pulse Echo Technology 

Yet, if online monitoring offers such clear benefits over manual analysis, why isn’t it more prevalent and a regulatory requirement today?

There have been a number of previous obstacles to online monitoring from the complex mixture of produced water through to concerns about the accuracy, maintenance, calibration and its robustness in harsh environments.

The result has been that, in the past, the furthest online monitoring has developed is as a tool for process monitoring rather than for regulatory compliance monitoring.

Today’s technologies and in particular ultrasonic pulse echo technology, however, are overcoming these concerns.

Ultrasonic pulse echo technology provides enhanced robustness in produced water environments. Exploiting the full range of properties of a propagating scalar wave field (diffraction, attenuation, time-of-flight, etc), ultrasonic measurement techniques are commonly found in a wide range of industrial applications such as medical ultrasound, non-destructive material testing and oil and gas.

The Roxar Oil-in-water monitor (see Figure 3), which is based on a patented solution with TNO Science and Industry, is built on an advanced ultrasonic pulse-echo technology.

A highly focused ultrasonic transducer is inserted directly into the produced water flow, enabling direct measurements on the suspended particles and dispersed oil phase. In the transducer focus, particles passing through the measurement volume will scatter the transducer beam and generate reflected waves or acoustic echoes. These acoustic signatures contain particle specific information.

The peak amplitude of the scattered signals from each passing particle is then used to characterise the suspension.  A large number of peak amplitude measurements are performed to generate a distribution of peak amplitudes.  From the distribution of these peak amplitudes, the particle size distribution and particle concentration can be calculated from accurate acoustic scattering models.

Higher Concentrations and Simultaneous Results 

With an increasing focus on oil in water monitoring at higher pressures, there is also a need for oil in water monitors to operate at higher concentrations.

And to optimise separation and water treatment processes, there is also a need to distinguish between gas, oil and sand and evaluate different particles simultaneously.  For re-injection applications in particular, the sand is a major concern when it comes to water flooding of the reservoir.

The Roxar Oil-in-water monitor can cater for concentrations of about 1000 parts per million (ppm). And by separating and analysing individual acoustic pulse-echo measurements, the monitor can provide complete size distributions ranging from the extremely low two to three micrometers.

Simultaneous calculations can be made using the generalised scattering model where scattering curves for oil and sand respectively are implemented in the model, and using feature extraction and classification of echoes, the correct forward model is used for each individual response.

One of the additional benefits of ultrasonic technology over more traditional technology is that it can ‘sound penetrate’ material. If there is an issue of oil film or scaling, the ultrasonic technology can work just as effectively and accurately simply because the ultrasonic energy will penetrate the layer and still transmit a signal into the produced water flow.

There is no need for detergents or other, separate cleaning mechanisms. And with a reference signal being continuously extracted from the system, the operator can make knowledge based decisions when it comes to maintenance intervals.

Online Monitoring – Taking on the Concerns 

A number of other traditional concerns on online monitoring are also being allayed. Take calibration and recalibration, for example, which is often required when chemical compositions change. Since the measurements are performed directly on the dispersed phase, this reduces the need for recalibration when the chemical composition changes.

The challenge surrounding reliability and robustness are also met head-on. With many of today’s oil in water monitors unable to work properly over long periods in harsh environments, the Roxar Oil-in-water monitor has been designed to be reliable, easy to maintain and have a long lifespan with the ultrasonic technology enhancing robustness.

By using advanced auto diagnostics functionality, the Oil-in-water monitor is also able to detect and overcome challenges, such as equipment degradation, scaling and temperature or salinity changes. In addition, the monitor has a ‘one size fits all’ that can be fitted on all pipe dimensions and is suitable for installation in hazardous conditions.

Meeting Expectations

With the increasing focus on subsea and downhole processing, the increase in water volumes and upstream separation and the rise in remote operations, as well as, of course, the growing environmental pressures, there is a real need in today’s oil and gas industry for accurate, online, inline monitoring of oil in water.

With the development of truly inline monitors for permanent installation, ultrasonic technology for enhanced robustness, sizing and classification capabilities and the ability to provide knowledge based maintenance for remote operations, oil in water monitoring technologies are now finally beginning to meet the E&P industry’s expectations.

Geir Aanensen is Business Unit Manager, Oil-in-water at Roxar Flow Measurement and can be contacted at Geir.Aanensen@roxar.com. Roxar is a leading international technology solutions provider to the upstream oil and gas industry.

 

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by Mirmorax