Mirmorax, Author at Mirmorax

Use of Mirmorax Oil In Water monitors to increase capacity and increase revenue

This paper discusses the benefits of using Mirmorax Oil in Water monitors for optimizing water treatment capacity, either for handling tie-in fields increased requirement for capacity or turning a traditional expense into a source for increased revenue.

Use of Oil in Water monitor for understanding water treatment

by Mirmorax

Use of oil in water monitor for understanding water treatment

USING THE MIRMORAX OIL IN WATER MONITOR TO BETTER UNDERSTAND WATER TREATMENT.

Mirmorax Oil in Water Monitors Reduce the Overall Oil Content in Discharge Water by More Than 30% on North Sea Field. Oil in Water Monitors Lower Oil Levels on Discharge Water to Increase Revenues.

Produced water has become the subject of an increasing operator focus in a number oil & gas applications today, as the output and results effect the environment, injection wells and the well’s production capabilities.

There is also an increased focus on water production today in oil sands and shale gas fields (in addition to more conventional fields) as water is becoming a scarce resource and recycling the water requires cost efficient and effective treatment systems.

Cost efficient treatment systems are key to allowing produced water to be discharged and regulatory requirements are set as to what content of oil particles are allowed. However, having control of your oil particle measurements is not only a matter of compliance, but is also strongly linked to water treatment capacity and loss of produced oil.

THE MIRMORAX OIL IN WATER MONITORS - INCREASING TREATMENT CAPACITY

Mirmorax is optimizing the oil and water separation process by applying its Mirmorax Oil in Water monitors. By installing monitors upstream and downstream of the separator train, Mirmorax can develop operational procedures capable of increasing the water treatment capacity significantly without adding more treatment systems.

In a North Sea oilfield, for example, Mirmorax installed three Oil in Water monitors. Due to the optimizing of the separation process, the monitors managed to reduce the overall oil content in discharge water by more than 30%. As part of this project, expensive, service-intensive separation systems were removed and operational procedures with existing robust separation equipment were developed.

INCREASING OIL REVENUES

Another additional but less well understood motivation for optimizing production by applying the Mirmorax Oil in Water monitors is increased revenues. For example, the annual increased oil revenue for lowering oil ppm levels from 30 ppm to 20 ppm on discharge water for a large oil field producing 100,000 barrels of produced water a day will be 38,000 USD. This alone will pay for the investment in the Oil in Water monitors over just a few years of operation. The Mirmorax Oil in Water monitors measure between 0-2500 ppm and have extremely high accuracy, even at lower ranges.

HANDING INCREASED WATER PRODUCTION CAPACITY

As many new wells are being tied into existing fields, the need for increased capacity in water treatment is a natural consequence. Using optimized separation techniques and operational procedures may very well be the most cost effective solution for handling the additional produced water, due to the increase in producing wells. Again, the Mirmorax Oil in Water is the answer.

The Mirmorax oil in water monitor also distinguishes between sand particles and oil particles. This ensures that there is no danger of counting sand as oil and allows the operator to identify the right particles to be removed, with others materials , such as sand and gas, then discharged without penalties.

ALLOWING FOR FIELD VARIATIONS

Oil separation and water treatment is not suited to a laboratory with highly accurate instrumentation. It’s about measuring real produced water under non-ideal conditions. This also includes allowing for changes in salinity and methanol present in the water without affecting measurements. Mirmorax Oil in Water monitors measure salinity, temperature and density accurately and hence compensate fully for any effects these substances may have on measurements. This is a new feature and ensures a stable ppm reading, regardless of field variations.

Salinity measurement is also a valuable source of data when determining the origin of water coming from multiple wells, and tie-ins. Information about salinity and density mix provides the operator with a good core measurement or verification of how much of the separation capacity is being used for each of the fields and, in addition, serves as a back-up verification of water break through.

WITHSTANDING CONTAMINATION

Furthermore, in real process conditions, Oil in Water monitors also must withstand a certain level of contamination. Mirmorax’s new auto calibration feature allows for several millimeters of scale and oil to grow on the ultrasound transducer without affecting the accuracy. In addition, most Mirmorax Oil in Water applications do not need an active cleaning mechanism that can generate sound contamination and is also vulnerable to long-term damage.

LISTENING TO OUR CUSTOMERS

Mirmorax’s new developments within our Oil in Water monitor technology are the result of customer input and are highly relevant for today’s operators. Our understanding of the water treatment process is not only based on years of field experience, but also is the result of working closely with customers to solve challenges and provide better solutions. T
The results are solutions, such as the Mirmorax Oil in Water monitors, that are meeting today’s oil and water separation challenges head-on.

Use of Oil in Water monitor for understanding water treatment

by Mirmorax

Oilfield Technology (April 2012) - Fighting PVT Inaccuracy

GENERATING ACCURATE PVT DATA THROUGH THE LATEST SUBSEA SAMPLING TECHNOLOGIES

BY EIVIND GRANSAETHER, CEO, MIRMORAX

The Importance of PVT and the Dangers of Inaccuracy

One of the most important sources for evaluating fluid properties and predicting reservoir performance today is PVT (Pressure, Volume, and Temperature) data.

If operators are able to generate an accurate understanding of the PVT properties of their reservoir fluids, then this crucial information will form the cornerstone of all field development decisions going forward – from reservoir simulation and recovery estimates through to production and optimization strategies. In addition, samples also need to be of PVT quality to be truly effective and accurate.

Traditionally, conventional test separators have played a crucial role in measuring PVT data with separator tests conducted to determine the changes in volumetric behavior of the reservoir fluid as it passes through the separator or separators. Samples are then reconstituted to produce a representative live sample by recombining the fluids with separator gas to match the wellhead gas/oil ratio (GOR).

However, PVT data is only effective if it is accurate. A SPE paper as far back as 1997 from Adel M Elsharkawy at Kuwait University (SPE 37441), for example, highlights the dangers of inaccurate PVT data and assumptions.

In this study, a PVT simulator was used to study the changes in reservoir gas gravity and produced gas gravity during pressure depletion in a Middle Eastern reservoir where simulation studies showed that the reservoir gas and average produced gas gravity changed by as much as 50% during the pressure depletion of the black oil reservoir.

In the absence of further PVT studies, the initial separator gas gravity was assumed to represent reservoir gas and produced gas and used to calculate crude oil and gas properties. The result was a significant underestimation of the solution gas-oil ratio and oil formation volume factor, and an overestimating of crude oil viscosity.

Using separator gas to represent both reservoir gas and average produced gas in calculating gas and oil PVT properties resulted in underestimating ultimate oil recovery by a staggering 40%.

While this is perhaps an extreme example, it’s clear that the more accurate your representation of PVT data, the more you will be able to predict reservoir behavior and ensure production optimization.

This article will examine the importance of PVT data, particularly in relation to multiphase and how subsea sampling can play such an important role in ensuring PVT and flow meter accuracy.

The Continued Growth of Flow Meters

With test lines for subsea well testing costing as much as US$60 million and the accompanying logistical challenges, the installation of subsea multiphase meters, as an alternative to well testing and as a means of optimizing recovery, have become commonplace for many operators today. Current predictions are that there are 3,300 multiphase meters installed worldwide as of 2010.

Such meters today, however, can only operate to their full potential if they are precisely calibrated and benefit from high quality volumetric sampling that reflect the changing fluid and process conditions of the reservoir. This might include an increased amount of liquid and water in the gas flow, growing water cuts, or fast changing reservoir and well characteristics.

Other factors that are also likely to result in significant variations in PVT properties might include comingled well streams from subsea tie backs; changes in water properties from sea or fresh water flooded wells; and differences in salinity between injected and reservoir water.

Furthermore, as a field starts to age, so the uncertainty of metering systems tend to increase as figure 1 illustrates.

uncertainty of metering systems

Figure 1

The Crucial Role of PVT Data

In such circumstances, effective volumetric subsea sampling and accurate PVT data and PVT quality samples can have an enormously positive effect on both the meters’ performance and field-wide production strategies.

By tracking composition changes, such as changes in fluid properties like density and viscosity (often as the reservoir is depleted), PVT data can play a key role in supporting production and fiscal allocation. Much of the inaccuracies found in all forms of allocation methods today, for example, come from operators not keeping updated PVT descriptions.

Furthermore, PVT descriptions are also vital in generating accurate reservoir models which can ultimately lead to improved reservoir recovery.

And as for meters, it is the fractional data on oil, gas, water, salinity and PVT (Pressure, Volume, and Temperature) which is crucial for calibrating multiphase meters and ensuring that they operate at their maximum potential. All multiphase meters using a gamma source must be configured with the fluid properties of oil, water and gas and ideally must reflect the changing PVT data over time.

Generating Accurate PVT Data

So how can we generate more accurate PVT data and what are the limitations of today’s current technologies?

There’s no doubt that subsea sampling, processing and the use of separators can play a key role in capturing PVT data today.

There are a number of weaknesses in using a separator, however, particularly where longer pipelines and lower pressures decrease PVT accuracy. Furthermore, using a test separator to run well tests one well at a time can also have a negative impact on the economics of the field with production having to be shut down on occasion. Figure 2 explains the steps needed to conduct a well test and provides average detail on the time when production is lost and thus profit reduced.

Stages in well-testing:	Time taken/average (hours):	Time affecting production (hours):

Connecting well-test equipment	2-4/3	3
Building up pressure/flow	2-4/2	1.5
Testing	2-4/2	0
Deconnecting well-test equip.	2-4/3	3
Building up pressure/flow	2-4/2	1.5
Other lost time	3	3

Total:	9-17/12	12

Figure 2

The alternative to well testing - subsea sampling, however, has also come with certain limitations in the past.

Many subsea sampling systems, for example, have previously been relatively crude, failing to generate a truly volumetric representative sample that contains fluids from all the phases.

Conventional PVT analysis can also taken weeks to be delivered to the customer with analysis often based on a limited number of samples retrieved either through wireline sampling or flow tests. While oil is relatively stable, water conductivity may change significantly during the time between the sample being taken and results received by the laboratory, therefore having a major potential impact on well stimulation operations, for example.

There is also the danger of fluid contamination where samples are sometime exposed to oil-based drillling or other reservoir production fluids.

Furthermore, subsea sampling normally takes place topside with samples taken randomly without taking note of the flow dynamics of the fluids being sampled and the original conditions in the field, such as pressures, overlooked. The result is an incomplete sample and a lack of accurate PVT data.

There are also challenges when collecting PVT data, especially in remote offshore locations, such as high pressure/high temperature environments as well as sour service fields.

A More Effective Means of Collecting PVT Data

It’s with these key drivers and challenges in mind that we have developed a more robust approach to subsea sampling and the collection of PVT data where the sample is maintained at its original pressure conditon from extraction to delivery to the surface and then transportation to the laboratory facility. Maintaining this pressure condition and the true representation of the process is crucial in providing accurate PVT analyses.

We have achieved this through an ROV (Remotely Operated Vehicle)-based subsea sampling system. While using an ROV for sporadic sampling could well be an expensive process, a complete supply sampling unit is much more cost effective.

Here’s how it works. Via the ROV, 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. Figure 3 illustrates the system in sampling mode, after the DSU has been docked onto the SSI.

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.

In this way, many of the traditional limitations of operating topside, lengthy delays, and sample contamination are addressed. Instead, measurements are taken directly from the flowline under measurable and controlled conditions with fluid properties and PVT data taken closer to real-time and closer to the wellhead.

The Rise of Virtual Flow Meters

Accurate PVT data will also play a key role as the industry sees the growth in virtual flow meters which will see, according to the research institute, NEL, the employing of “software that combines distributed measurements to calculate the flow rate. For example, the pressure drop across a choke, the wellhead temperature, and the downhole pressure could be used as inputs.”

In such circumstances, PVT quality samples and PVT data will be crucial.

Accurate Sampling and Accurate PVT Data

From reservoir modelling and reservoir simulation through to comprehensive field development strategies, the accurate generation of PVT data and PVT quality samples is crucial to understanding reservoir performance today. An accurate sampling system is a highly effective means of achieving this.

View published article

by Mirmorax

Mirmorax will have delegates at OTC in Houston 29. april to 4. may

Mirmorax is seeing an increased interest in their Oil in Water Monitoring and Multiphase Sampling Systems products and will be in Houston at the Offshore Technology Conference (OTC) in Houston, held 30th of April to 3rd of May.

We will not have a stand this year, but dedicate our availability for clients who are interested in products presentations and meetings. Please feel free to contact us to book an appointment in Houston these days, as we will be present at the exhibition the whole week. For booking or questions: mirmorax.com/contact

by Mirmorax

Offshore Engineer (February 2012)

THE ECONOMICS OF SUBSEA SAMPLING

BY EIVIND GRANSAETHER, CEO, MIRMORAX

With test lines for subsea well testing costing as much as US$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 with Gioia Falcone from Texas A&M University and Bob Harrison of Soluzioni Idrocarburi Srl estimating that, as of 2010, there were over 3,300 multiphase meters 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.

This article will look at the role of subsea sampling in securing maximum effectiveness from multiphase meters and how subsea sampling is addressing other crucial production management issues offshore, such as injection water, water breakthrough, chemical analysis, and EOR. The results are having a major impact on the economics of the field today.

Securing Optimum Performance from Multiphase Meters

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 tie-backs 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 the 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.

The Role of Subsea Sampling in Offshore Fields Today

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 techniques, however, is 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 criteria 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 to us 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.

We achieved this through an ROV (Remotely Operated Vehicle)-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 for Subsea Sampling Today

We have already 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.

Sampling mode systems

Figure 1

uncertainty of metering systems

Figure 2

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, chemical analysis, for example. 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 particular 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 & 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 US $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 15,000 Barrels of Oil per Day (BOPD), where the crude will be sold for around US$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 tie-backs, 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.

View published article

by Mirmorax

Oilfield Technology (June 2011)

ESTABLISHING SUBSEA ENGINEERING PRINCIPLES IN SUBSEA SAMPLING AND OIL IN WATER MONITORING OPERATIONS

BY EIVIND GRANSAETHER, CEO, MIRMORAX

Subsea Sampling and Oil in Water Monitoring

The increased challenges operators are facing as they look to maximize production, squeeze more oil & gas from their older fields, and meet environmental requirements, are seeing a renewed focus on two vital but often under-reported technologies – subsea sampling and oil in water monitoring.

While tending to focus on different elements of the reservoir – in the case of subsea sampling below the reservoir surface and in the case of oil in water monitoring normally on an offshore platform – both technologies share one key challenge.

That is the need to introduce greater intelligence, automation and subsea engineering principles into their operations and move away from the manual focus that has too often dominated both technologies in the past.

Let’s take a look at subsea sampling and oil in water monitoring in greater detail.

The Rise in Subsea Sampling

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 can provide early warning signs if there is water breakthrough, for example.

Aligned to this and just as important, however, is the process of subsea sampling. It is accurate subsea sampling that leads to the precise calibration, accuracy over time, and effectiveness of these metering systems. By adding a subsea process sampling system, for example, operators can generate fractional data on oil, gas, water, salinity, PvT (Pressure, Volume, and Temperature) and other information that the meters need to be calibrated for.

Subsea sampling, that can provide high quality, accurate volumetric sampling for the lifetime of the field, support such multiphase meters in the areas of reservoir simulation, field economics, system integrity, revenue allocation, and production optimization – to name just a few. In summary, subsea sampling is central to reservoir management and the monitoring of reservoir operations.

Yet is subsea sampling rising to the challenge?

Subsea sampling techniques on the market today include the hot stab method, extracting the samples by differential pressure, or flowing the well to a surface test facility that captures samples.

All these techniques, however, share a number of limitations. Firstly, the techniques are often used topside and are manual-driven; samples are taken randomly without due consideration to the flow dynamics of the fluids being sampled; and the original pressure conditions are not maintained during the fluid sample’s journey to the laboratory.

The focus on the manual and the risk of human error means that there is therefore little way of achieving a truly volumetric representative sample or being assured that the sample contains fluids from all the phases. The result is low quality samples, no volumetric representation, and low repeatability.

Oil in Water Monitoring

As with subsea sampling, oil in water monitoring is an equally important technique where the technologies don’t seem to keeping up.

The last few years have seen a significant increase in global water production. One of the main reasons for this is the growth of brownfields and Produced Water Re-Injection (PWRI) to ensure higher recovery rates and a longer lifetime for existing oil fields.

This increase in produced water has 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 water. Effective monitoring and control over the reinjection process will optimize the water flooding of the reservoir and ensure maximum production performance.

There are a number of other drivers behind the increased focus on oil in water monitoring.

There is the lost revenue due to oil being lost through produced water discharge; greater detail on the specific components of produced water can help optimize the separation of oil and water, taking place in separation process facilities; and there are real dangers to production optimization if produced water is not carefully monitored.

This is 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.

And then there are environmental regulations. 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. Within this context, it is essential that E&P operators can demonstrate to regulators and governments the effective monitoring of oil in water.

So are oil in water monitoring technologies doing better than their subsea sampling counterparts in meeting these increased operator demands?

Again, there are a number of flaws to traditional techniques.

Traditionally, oil in water monitoring tends to be manual, with samples taken from the produced water discharge, acidified to a low PH and then extracted with a chemical known as tetrachloroethylene.

Once the solvent is extracted, infrared quantification then takes place with oil content determined by the infrared absorbance of the sample extract and the total methylene (CH₂) that is present. 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.

There is also potential confusion as to what constitutes ‘dissolved’ and ‘dispersed’ oil with both extracted by the extracting solvent. 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 environmental requirements.

The result is inconsistent ways of analyzing the spot samples with varying results and, in terms of employee productivity, a highly labour intensive process.

A Focus on Subsea Engineering - Subsea Sampling and Oil in Water Monitoring

Against this backdrop, we at Mirmorax are focusing on providing operators with a more automated and intelligent subsea sampling and oil in water monitoring system built on strong subsea engineering principles.

Taking subsea sampling first, we have developed an ROV-based subsea sampling system that collects samples subsea. It is only through sampling at or near the wellhead that samples, representative of the fluid flowing through the meter, can be generated, yielding more accurate fluid properties and more accurate multiphase measurements.

The sampling system via its ROV extracts and transports the sample into sampling bottles under isobaric conditions and then transports them to the surface. Key components of the new system is an ROV operated docking sampling unit (DSU), consisting of a docking unit, a hydraulic sample extraction system and sampling bottles. The sampling unit itself is based on standard subsea engineering principles and is a combination of field proven technologies, such as the hydraulic actuator, collet connector and system for testing sealing integrity.

The second key element - essential in taking samples subsea and isolating the sample from the process – is a stationary subsea sampling interface (SSI). The ROV transports the sampling device from the surface vessel and docks onto the stationary SSI through a standard hydraulics and manipulator system. The two parts are then connected with a robust connector and barriers which are 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. This ensures accuracy on the sample in case of unstable flow and provides the accumulated volume needed to perform analysis topside.

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. And all this takes place while maintaining the sample at its original pressure conditon all the way through to the lab.

In oil in water monitoring, we have recently acquired the Oil-in-water (OiW) product line, an online and inline oil-in-water monitor for topside oil and gas applications, from Roxar Flow Measurement, a division of Emerson Process Management.

As part of the acquisition, Mirmorax has also signed an agreement to secure all Intellectual Property (IP) rights for the product with Dutch technology company TNO Science and Industry. TNO was part of the original Joint Industry Project (JIP) with Roxar in developing the monitor along with Statoil, Eni SpA, and Shell and Petroleum Development Oman (PDO).

The Oil-in-water monitor and its ultrasonic pulse-echo technology provide accurate, real-time information on the amount of sand and oil dispersed in water and is an important alternative to previous manual-dominated operations.

The monitor is based on an ultrasonic measurement principle. Through the insertion of an ultrasonic transducer directly into the produced water flow, ultrasonic technology takes individual acoustic pulse-echo measurements from solids, oil droplets and gas. Each detected echo is analyzed and classified as coming from an oil droplet, a sand particle or a gas bubble. Concentration levels can then be calculated based on the size distribution.

The monitor caters for concentrations of about 1000 parts per million (ppm) and by separating and analyzing individual acoustic pulse-echo measurements, the monitor can provide complete size distributions ranging from two to three micrometers. Calculations can be made simultaneously for oil and sand.

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.

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). Furthermore, by using advanced auto diagnostics functionality, the monitor is also able to overcome challenges, such as equipment degradation, scaling and temperature or chemical changes.

We have plans to develop the monitor for subsea applications, allowing for water characterization at an earlier stage of the process and enabling the monitor to become an important tool in subsea processing.

In this way, the acquisition will help us come closer to attaining our goal of delivering innovative, high quality subsea processing solutions that help operators optimize flow assurance, meet environmental requirements, and generate the best possible returns from their reservoir assets.

Together, with our subsea sampling system, we are injecting much-needed subsea engineering principles into subsea processing operations, ensuring that operators are finally able to meet their production optimization and environmental challenges.

The manual-focus of the past is now very much behind us!

by Mirmorax

Oil Review Africa (March 2011)

March Subsea Systems – Oil Review Africa

THE GROWTH OF SUBSEA SAMPLING IN AFRICA

BY EIVIND GRANSAETHER, MIRMORAX

The Growth of Deepwater Fields

There’s no doubt that offshore exploration in Africa continues to be one of the industry’s true growth areas. Along with the Gulf of Mexico and offshore Brazil, Africa will account for 85% of global deepwater expenditure between now and the end of 2012, according to analysts, Douglas-Westwood, with annual expenditures worldwide likely to reach over US $24.6 billion by 2012.

Douglas-Westwood also estimates that overall capital expenditure for the period 2008-2012 is expected to total $38.2 billion, 47% of which will be accounted for by Africa. As of 17^th January 2011, the World Oil Deepwater Report also found that there were 26 deepwater prospects where drilling activity was underway offshore West Africa.

And it’s not just offshore West Africa which is the focus of activities. In August 2010, the first deepwater oil was discovered offshore East Africa in Mozambique’s Rovuma Basin.

Yet, just as offshore expenditure continues to grow, so do the challenges in ensuring maximum production rates from the reservoir to the refinery once the fields come on stream.

One area of subsea production, that doesn’t gain the same attention as production trees, wellheads, and jumper equipment, for example, is that of subsea sampling.

Subsea sampling today provides crucial input to a key element of flow assurance on many of Africa’s offshore fields – multiphase and wet gas meters.

Such meters provide important real-time information on flow conditions in the reservoir. They can be used to determine maximum oil production and gas handling capacity and can provide early warning signs if there is water breakthrough, for example. Today, many of Africa’s most high profile fields have multiphase meters installed including Total’s Pazflor and Akpo’s fields; ExxonMobil’s Marimba and Kizomba C fields; and ENI’s Mondo field.

Furthermore, with increasingly challenging ownership structures in many of these offshore fields with complex commingled streams and royalty allocations, multiphase meters today are also playing an important role in production and fiscal allocation.

So what is the link with subsea sampling?

It is accurate subsea sampling that leads to the precise calibration, accuracy over time, and effectiveness of these metering systems. It also support these meter’s roles in areas, such as reservoir simulation and field economics, system integrity, the allocation of revenue from tied in fields, and production optimization.

By adding a subsea process sampling system, for example, operators can generate fractional data on oil, gas, water, salinity, PvT (Pressure, Volume, and Temperature) and other information that the meters need to be calibrated for.

And accuracy over time is probably the most important element subsea sampling can provide to multiphase meters today. It is subsea sampling and the calibration of meters that can ensure that a meter installed on a well at the start-up of production is providing accurate estimates of oil, gas and water ten years later - even when the produced fluids in the field have changed.

Yet are today’s subsea sampling systems meeting the requirements of today’s multiphase meters?

Unfortunately, the answer, in many cases, seems to be no.

The US Department of Energy said as much in 2006 when they established the Research Partnership to Secure Energy for America (RPSEA) with one of the key goals being ‘the development and standardization of deepwater sampling’.

There are a number of subsea sampling techniques on the market today, the most popular being the hot stab method and others including the extraction of the samples by differential pressure, or flowing the well to a surface test facility that captures samples.

All these techniques, however, share a number of limitations. Firstly, the techniques are often used topside; samples are often taken randomly without due consideration to the flow dynamics of the fluids being sampled; and the original pressure conditions are not maintained during the fluid sample’s journey to the laboratory.

The result is that there is little way of achieving a volumetric representative sample or being assured that the sample contains fluids from all the phases. The result is low quality samples, no volumetric representation, and low repeatability.

It’s clear that multiphase meters play a crucial role in flow assurance today. It’s up to subsea sampling methods to ensure that they perform to their very optimum ability. Subsea sampling, that can deliver true volumetric sampling on oil, gas and water in the well without interrupting production, can enable the operator to accurately capture fluid properties throughout the lifetime of the field, conduct comprehensive PVT and chemical analysis, calibrate multiphase and wet gas meters, and increase oil & gas recovery from the reservoir.

It was against this backdrop that we have developed a subsea sampling system that overcomes many of the limitations above.

There were a number of key criteria to the system we developed – going subsea and being ROV-operated, a seamless process from collection to analysis; no interruption to production, and being robust.

Firstly, the system needed to be installed subsea. It’s only through sampling at or near the wellhead that samples that are representative of the fluid flowing through the meter can be generated. Another driver for this is the limitation of platform space on many African platforms as well as the increase in subsea tiebacks, with the Pazflor field being one such example.

Having made this decision, the next logical step was to design an ROV-operated system taking the recommendations from the RPSEA partnership described earlier in the article. As well as recognizing that deepwater measurement is a critical need in the development of reserves, RPSEA also set a goal of installing measurement systems on deepwater wells via ROV.

The system we developed also needed to represent 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. It was the differential pressures used to transport the samples which were the main source of inaccuracy with previous sampling techniques.

The final criteria two were that we did not interrupt production, potentially costing the operator hundreds of thousands of dollars, and we wanted to ensure that the system was robust and able to operate in the challenging and HP/HT environments of offshore Africa.

The solution, that we developed, is therefore built around an ROV operated docking sampling unit (DSU), consisting of a docking unit, a hydraulic sample extraction system and sampling bottles.

The ROV tool then extracts and transports the sample or samples into sampling bottles under isobaric conditions and then transports the samples to the surface. The sampling unit consists of a hydraulic actuator, collet connector and system for testing sealing integrity.

The second main element is a stationary subsea sampling interface (SSI). The ROV transports the sampling device from the surface vessel and docks onto the stationary SSI through a standard hydraulics and manipulator system. Figure 1 illustrates the system in sampling mode, after the DSU has been docked onto the SSI

Sampling mode systems

Figure 1

The operation then takes place a number of times on the same well with the operator able to obtain multiple sample points on one single ROV operation in order to obtain a fully representative sample over a set time period and to provide the accumulated volume needed to perform analysis topside. And all these samples can be taken without interrupting production.

Another key challenges for offshore operations in Africa is the high pressures and high temperatures in the deepwater fields. For example, ENI’s deepest well in West Africa – the Oberon 2, off the coast of Angola – contains pressures of up to 10,800 PSI and temperatures of 157 °C.

To meet these challenges, the new system can operate comfortably with HP/HT applications of up to 1000 bar/15,000 PSI and 180 °C / 350°F and has design depth of 3,500 meters.

Testing has also shown the system to be in compliance with design codes even when it is tested at up to 22,500 PSI. The new system is currently undergoing qualification testing.

It’s clear that subsea sampling in Africa’s offshore fields is going to become more and more important over the next few years in guaranteeing flow assurance and accurate production allocation. It’s encouraging to see that some of the limitations of the past are now being overcome and that subsea sampling can take its rightful place as a key element of subsea production systems.

by Mirmorax

Institute Of Engineers (August 2007)

This article was published in the Indian Institution of Engineers Magazine in August 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

Global water production is on the increase - so much so that today we are producing more water than oil.

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.

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)[1].

In the illustration, the y-axis is standard cubic meters in millions with the graph showing the current and estimated amount of produced water being discharged into the sea. With the current average oil-in-water content for all the installations on the Norwegian Continental Shelf, this translates into approximately 3000 tons of oil.

Taking a Closer Look at the Water

The increase in produced water, whether it is reinjection, discharged or processed water, has also led to a growing need from the operator for a better monitoring of produced water.

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

Optimising Production

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

There is the increase in revenue by separating the oil from the produced water. According to energy industry analysts Douglas-Westwood, 2.1 million barrels of oil are lost every day due to oil being lost through produced water discharge[2].

There are also other potential problems during the production phase that can be alleviated through produced water monitoring. 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.

Careful monitoring and quick preventative action can save quite literally millions of dollars.

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 also 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.

There are real dangers to production if produced water is not carefully monitored – not just during the separation phase but throughout production. 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[3] - 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 – especially produced water re-injection (PWRI) which is utilised to ensure pressures are sustained and to increase recovery rates.

It is essential that all oil and solid particles in the produced water re-injection 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.

Addressing the Environmental Challenge

Another key market driver in the development of reliable and accurate oil-in-water monitoring is the tightening 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[4] and a number of environmental regulations have emerged over the last few years to ensure the accurate measurement of oil in produced water.

Leading this is the 2000/2001 Oslo/Paris Convention (OSPAR) - also known as the Convention for the Protection of the Marine Environment of the North-East Atlantic.

OSPAR covers all the oil-producing coastal states of Western Europe with its goal being to ‘…prevent and eliminate pollution by oil and other substances caused by discharges of produced water into the sea.’ The key requirement 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.’

OSPAR means that operators must now demonstrate to regulators and government the effective monitoring of oil in water. As well as avoiding any financial penalties, accurate monitoring can also open up opportunities for participating in emission trading schemes.

The Weaknesses of Manual Sampling

So, with there being a clear demand from operators, are today’s oil in water monitoring technologies rising to the challenge in offshore production?

If this question had been posed a few years ago, the answer would have had to be ‘No’. That was when manual sampling was the predominant tool for oil in water monitoring.

According to what was previously the OSPAR defined reference method, manual sampling 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 methylene (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 tons 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, the IR method measured 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).’

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 analysing the spot samples with varying results.

Staff Productivity

The final, perhaps most obvious downside of manual sampling, is the labour intensive nature of the process and the negative impact on staff productivity which makes it unpopular with operators. A more automated form of monitoring would have a significant impact on freeing up resources and improving staff productivity.

The Emergence of Online Monitoring

Online, inline, real-time monitoring of oil in water, however, meets many of the requirements of today’s operator, providing 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 labour intensive sampling; and an avoidance of exposure to solvents, such as tetrachloroethylene.

In being an inline monitor with no need for sidestreams or sample extractions, the monitor acts as a flow instrument providing direct measurements at the dispersed and suspended phase. Here the monitor design is essentially like a flow instrument similar to a multiphase meter.

Online, inline monitoring also includes more detailed information on the size distribution and concentration of oil and sand in water. 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.

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 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?

Previous obstacles to online monitoring have included doubts as to its inability to effectively characterise complex water mixtures through to concerns about the accuracy, maintenance, calibration and its robustness in harsh environments.

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

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.

Through the insertion of an ultrasonic transducer directly into the produced water flow, ultrasonic technology takes individual acoustic pulse-echo measurements from solids, oil droplets and gas. These are then separated and analysed to provide accurate information to the operator on size distribution and concentration for oil and sand. The Roxar Oil-in-water monitor caters for concentrations of about 1000 parts per million (ppm).

An added benefit is that the technology can ‘sound penetrate’ material. If there is an issue of oil film or scaling, the ultrasonic technology can work just as effectively and accurately because the ultrasonic energy will penetrate the layer and still transmit a signal into the produced water flow. This is not the case with the majority of today’s oil-in-water monitors which are reliant on optical technology.

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

Through the ultrasonic technology, 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.

There is also 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.

The net result is increased accuracy and a positive impact on both optimising production and meeting environmental requirements.

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.

Changing the Way Oil in Water is Monitored

Today’s technologies are changing the way oil in water is being monitored, providing the operator with greater detail and accuracy in their water characterisation information as well as greater reliability and robustness. With the need to optimise production, meet environmental requirements and maximise returns from brownfields, the timing couldn’t have been better.

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.

Case Study - Statoil

The Roxar Oil-in-water monitor was installed at Statoil’s Sleipner A platform on May 16^th 2006. Sleipner A is a fixed platform located in the North Sea in block 15/9, approximately 240 kilometers west of Stavanger, Norway and serving the Sleipner East, Sleipner West and Sigyn gas and condensate fields. The installation produces gas/condensate from different wells and the concentration and oil droplet size range is expected to be relatively low.

Statoil will use the Roxar Oil-in-water monitor to measure overboard water discharge from the platform and ensure that it meets environmental requirements for limited or zero oil emissions into seawater. The monitor will also act as an early warning detection system in the water treatment facility and will play a vital role in helping Statoil efficiently monitor the separation process.

Since installation, several tests have been completed to demonstrate the performance of the monitor. Data analyses clearly show that both in terms of accuracy and sensitivity, the monitor performs according to specifications. There is, as expected, a clear correlation between measured oil in water concentration and changes in the water level in the gravity separators.

The Statoil pilot to date has confirmed the Roxar Oil-in-water monitor’s ability to provide accurate information to Statoil on the size distribution and concentration of oil and is already playing a key role in monitoring Statoil’s overboard discharge and separation process.

[1] Oljedirektoratet, Norway

[2] Douglas Westwood, September 2005.

[3] World Energy Organisation, 2002

[4] Source: Statoil

by Mirmorax

Hart's E&P (April 2007)

This article was published in Hart’s E&P Magazine in April 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