Mirmorax is launching a new Oil in Water Analyzer!
The new analyzer is a portable desktop analyzer based on ultrasound technology with the weight of only 10 kilos.
The analyzer provides quick and accurate result analyzing your produced water or slop water. Multiple areas of use: Laboratory, Offshore, Onshore and even a by-pass solution for inline use is available. Mirmorax offers a flexible rental solution to fit our customers’ requirements.
All desktop OIW Analyzers are made in a transpotable Pelicase for easy transport and handle.
A digital touch operated screen makes the operation convenient and intuitive.
Our rental fees are all inclusive remote support, spare parts and even a replacement analyzer if deemed necessary.
Mirmorax offers a short term and a longer term rental.
Mirmorax is dedicated to make our customers satisfied. The Desktop Oil in Water Analyzer is a new product. Our first version, DT250, will be offered for rental only, to ensure optimal performance of all instruments in field. Mirmorax offer an introduction price valid with placing an order within end of 2016.
If you require more information about the DT250 feel free to get in touch by email of phone or simply use the live chat on the bottom of this page.
New Oil Era – New Challenges – Better Technology
MIRMORAX NOW HAS THE MOST ROBUST OIL IN WATER ANALYZER ON THE MARKET ACROSS ALL TYPES OF APPLICATIONS.
ROAD TO ROBUSTNESS
Whereas our Oil in water analyzers can be best described by evolution in technology our clients describe it as a revolution in results. So, why is that? Well, it starts and ends with making ourselves unaffected by the variables that the industry in general uses as excuses for not delivering results.
In 2010 Mirmorax started a journey through unknown territory with one single, ambitious goal set as the only known beacon: To create THE Oil in Water analyzer in the market, preferred across a variety of applications and by the vast majority of the market. At the time we had a technology that was developed to deliver accurate results under very stable condition and within a limited measurement range.
In contrast, our customers wanted to use the analyzers in more areas and different applications than before. This included a less stable environment, wider measurement range, changing process conditions, various chemicals and last but not least, measuring multiple oil types in the produced water.
FROM MEASURING DISCHARGE TO ENABLING REDUCTION
Through firstly a detailed technical analysis followed by a good soul searching exercise, we found that the path to making the most accurate Oil in Water analyzer on the market was less about measuring oil concentration more accurately and more about making sure we were unaffected by other factors. We already had the most accurate Oil in Water analyzer on the market for condensate applications and for low concentrations, we just needed to overcome the challenges other applications had.
We identified 5 challenges that we needed to overcome to get there:
- Measurement range increase from 0-1000 to 0-25 000 ppm
- Response time from measurement to data output from 15-30 min to 2 seconds
- Automatic compensation for changes in temperature, salinity and density
- Correct particle size measurements for high concentrations
- Automatic cleaning of the transducer
We managed to develop the expanded concentration range and the response and had several successful tests using this software. The way we did verification measurements also now enabled us to actually measure temperature, salinity and density of the water. And when we had these measurements, we could apply these to our models and maintain a stable concentration measurement regardless of changes in these three properties. Worth mentioning here was that chemicals such as MEG, corrosion inhibitors and other chemicals is only observed as a change in density of the water and therefore does not change oil concentration measurements.
AUTOMATIC CLEANING – MAINTENANCE FREE SYSTEM
Also, Mirmorax new automatic cleaning mechanism that ensures that the system can measure continuously across the whole measurement range and without any interruption in measurements. It is the only system that can provide uninterrupted measurement and clean sensor up to 400 bar operational pressure.
With these new features, an industrial software version was implemented offshore as a side-measurement and has proven to be a success. At a more challenging test, we found that an improvement needed to be made to get correct particle size at higher concentrations. What we had gained in faster response time, we had lost in particle size accuracy for the higher concentrations.
ACCURATE READINGS REGARDLESS OF PARTICLE SIZE OR API GRADE OR THE MIX OF THEM
By applying additional theoretical models that was developed in-house, we found a unique way to determine particle size, regardless of what concentration of oil that was in the water. This didn’t only solve the problem with reading correct concentrations and particle sizes, but also opened up a series of new opportunities. This testing, the iterative improvement and verification process was done closely with one of Mirmorax key customers who had very specific requirements on both ranges and accuracy.
As Mirmorax uses acoustics, the dominant property relevant for the acoustic response is the density of the oil. The density and corresponding viscosity of the oil will determine what particle size an oil concentration will have in a given part of the separation system. So, given that there are two different oil types with individual density in the same produced water, they will have different particle sizes.
For other measurement principles, such as fluorescence this represents a big problem since the ppm measurements is not a direct measurement, but a measurement of the aromatic oils, the dissolved oil and not the actual oil droplets. The aromatic response, fluorescence, is basically the surface area of the accumulated droplets as well as the density of the oil. So, if you have 4 particles, 1 with heavy oil and 3 with condensate they will measure about 150% wrong compared to if you had 2 particles with heavy oil and 2 with condensate. These are significant numbers, especially considering these numbers may be a bottleneck for production rates.
LAB PROVEN – FIELD PROVEN – RELEVANT
Mirmorax Oil in Water analyzer has been thorough testing with mixes of heavy oil and condensate now for about 18 months onshore and offshore.
The results can only be described as fantastic, and with the full range with variety of oil types and percentage of each oil, we are within +/-15% relative. The key for maintaining the accuracy is the measurement principle being insensitive to oil density changes and the accurate particle size measurement regardless of concentration. This means that Mirmorax can handle an unlimited number of different oil types and changing fractions of these in the same produced water stream.
This is in particular important in a market where production from various fields is done through tie-backs and share topside processing facilities, often build for one oil and having to separate a mix of several. On top of this, regulations and environmental awareness is higher than ever and as brown fields are producing more and more water, managing produced water becomes key for utilizing the existing capacity.
PRODUCED WATER – BOTTLENECK REDUCED
Mirmorax Oil in water analyzers are due to its measurement robustness an excellent and cost effective choice when trying to get more out of the existing processing capacity. By installing Mirmorax OiW, not only at the discharge for final verification, but further upstream, the operators has the opportunity to get capacity out of their produced water separation system. Based on case studies done by our clients, we have seen increases in an existing separation systems of more than 35% without other modifications than installing Mirmorax OiW to optimize each separation process. Mirmorax today has the expertise to deliver enabling technology from 1 stage separator to discharge and will be a knowledgeable partner.
~ TIE IN FIELDS – MIXES OF OIL – PRODUCED WATER CHALLENGES – SOLUTION DELIVERED ~
How can technology innovation improve?
Innovate or die.
Newer and better tech is always needed in the oil & gas industry – even when companies aren't exactly shouting to be first in line, OE asked:
Technology Advances in Subsea Sampling
BY EIVIND GRANSAETHER, CEO, MIRMORAX
While the last few years has seen a host of new subsea technology innovations, few technologies have developed quite as fast as that of subsea sampling.
Originally characterised as a manual-focused process with little consideration for flow dynamics and fluctuating reservoir conditions, today subsea sampling is providing operators with real-time information on oil, gas and water fractions as well as fluid properties and PVT data from closer to the wellhead than ever before.
The Importance of Subsea Sampling
There’s no doubt as to the importance of subsea sampling today. As operators look to generate a more complete picture of the reservoir, increase recovery rates and extend field life, subsea sampling is playing a crucial role – particularly in supporting multiphase meters.
Such meters can only operate to their full potential if they are precisely calibrated and sensitively aligned with the changing fluid, process conditions and flow rates of the reservoir. Such changing conditions might include an increased amount of liquid and water in the gas flow, growing water cuts, or varying well characteristics. And such calibration can only be achieved through the true volumetric sampling of oil, gas and water in the well.
Accurate PVT (Pressure, Volume, and Temperature) data is also vital. If operators can generate an accurate understanding of the PVT properties of their reservoir fluids and changes in fluid properties, such as density and viscosity (often as the reservoir is depleted), the more they will be able to predict reservoir behavior, ensure production optimisation and calibrate multiphase meters for maximum performance.
Such data is also particularly important as fields start to age, as is the case in many North Sea fields. In such cases, as figure 1 illustrates, the uncertainty of metering systems tend to increase and up to date volumetric sampling information is required to put the meters back on track. With the cost of purchasing and integrating just one multiphase or wet gas meter approximately US$400,000, subsea sampling can have a significant impact on the field’s economics as well.
Figure 1
Overcoming Technology Limitations
So given the importance of subsea sampling, what are the technology limitations preventing accurate and volumetric sampling?
The limitations of previous and even current sampling technologies include samples being taken randomly and topside; little consideration for flow dynamics; an inability to track and react to fluctuating reservoir conditions, such as high Gas Volume Fractions (GVF) and increased salinity; and a failure to maintain original pressure conditions in the laboratory.
The latter point is particularly important when it comes to water conductivity. While oil is relatively stable, water conductivity may change significantly during the time between the sample being taken and the results received by the laboratory. An inabilty to maintain the exact conditions subsea can jeopardise the validity of these results.
Furthermore, there are also the dangers of fluid contamination in cases where samples are exposed to oil-based drillling or other reservoir production fluids, for example, and the inevitable cost implications and risks surrounding subsea intervention.
The result is no volumetric representation in the samples, low repeatability and an incomplete and potentially inaccurate sample with a lack of PVT data and other information the operators require.
New Subsea Sampling Developments
It’s with these restrictions in mind that Norwegian-based Miromorax has committed to developing a subsea sampling system that delivers true volumetric sampling on oil, gas and water in the well - below the flowline, in controlled conditions and without interrupting production. In this way, the operator can accurately capture fluid properties, calibrate multiphase and wet gas meters, and ensure that the wells are performing at the peak of their production limits to deliver flow assurance
Mirmorax is delivering on this through a new Subsea Multiphase Sampling System (SMSS) that delivers accurate sampling through phase representative samples and in-situ analysis capabilities that are integrated to allow both fractional and salinity data.
At the centre of the new system is a permanently installed Analyzer system module that, mounted to the multiphase sampler, provides online, on-demand fractions of oil, gas, water, salinity and density without the need for subsea intervention.
The Analyzer uses a unique acoustic-based technology where online quantitative values can be obtained by just a push of a button and then made available through standard communications. Based on the functionalities of the in-line multiphase sampling system, the operator can then read the oil, gas and water fractions directly from the sampling bottles taken at a specific time window, providing a phase fractional set of data that can be directly compared to the metering data for the same time period.
By calibrating this fixed point at given pressure, temperature and volumetric fractions, the operator can provide the multiphase meter with a fixed point and increase the meter’s accuracy significantly in relation to the pressure and temperature conditions the sample was taken under.
Figure 2, for example, illustrates the correlation between variables in a multiphase meter. The landscape 3D plot illustrates the correlation curve between two core data inputs and the output value. The red point places the 3D plot of the meter in reference at a fixed point, with PVT data then needed to ensure that all values correlate.
Figure 2
The online fractional data generated through the Analyzer also provides crucial, high-value information to the operator when quality checking samples before they are extracted and transported to surface and can also help determine when a full PVT compositional analysis is required. Knowledge of the sample quality and representation before extracting and transporting for laboratory analysis also removes any risk of faulty samples and reduces transport and analysis costs.
Sometimes the knowledge generated through the system prior to extraction may even be enough to support EOR and other multiphase meter activities without the need for further laboratory analysis.
The System has also undergone rigorous testing at the Christian Michelsen Research Multiphase Flow Loop in Bergen.Here, the subsea sampling system delivered excellent Water Liquid Ratio (WLR) results with an absolute error of less than 1% within a 90% confidence interval; and GVF results that more than met expectations.
In addition, the system was able to accurately quantify the salinity of water. With salinity affecting water conductivity and adding uncertainty to the fraction measurements of the flow, such information is crucial to the operator in calibrating multiphase meters and optimising production.
It is the Miromorax Subsea Multiphase Sampling System’s ability to take measurements 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 that is revolutionising subsea sampling today. For the first time, operators, through just a push of a button, can generate online, on-demand fractions of oil, gas, water, salinity and density without subsea intervention.
Other Technology Innovations
Yet, it is not just in subsea sampling that Miromorax is making an impact subsea. The Mirmorax oil in water monitoring solution has also been taken subsea.
With increased water production and discharges in the North Sea, the growth in brownfields, and stricter environmental regulations, the detailed information on the size and amount of sand and oil in produced water – whether it be reinjection or discharged – is crucial for operators today. And it is with these issues in mind that Mirmorax has developed a highly effective, and robust oil in water monitoring solution.
The system is based on an ultrasonic measurement technique in which individual acoustic echoes from both solids and oil droplets are analysed. Recent new developments also include new temperature and salinity measurements; an auto calibration feature to compensate for scale build-up and that allows for several millimeters of scale and oil to grow on the ultrasound transducer without affecting accuracy; and self-cleaning mechanisms that prevent the danger of thick oil clogging the system.
Through developments such as this, the monitor can cover a wider measurement range and compensate for layers of scaling and possible contamination. Salinity measurement is also a valuable source of data when determining the origin of water coming from multiple wells. Information about the salinity and density mix also provides the operator with verification of how much of the separation capacity is being used for each of the fields.
Rising to the Challenge
With operators needing greater control and insight into their subsea operations than ever before, the spotlight has fallen on subsea technology development.
It is encouraging to see that companies, such as Mirmorax, are rising to the challenge.
Eivind Gransaether is CEO of Mirmorax AS, an industry leader in sampling, monitoring and processing solutions to the oil & gas industry which he founded in 2009. Prior to founding Mirmorax, Eivind had a number of roles at Roxar (now Emerson Process Management) including Commercialisaton Manager and Global Subsea Sales Manager. Eivind is a graduate of the Norwegian University of Science & Technology (NTNU)
Monitoring production
ACCURATE MEASUREMENT OF OIL IN WATER IS A CRITICAL ELEMENT OF OIL AND GAS OPERATIONS TODAY BECAUSE OF THE INCREASE IN PRODUCED WATER AS A BY-PRODUCT OF PRODUCTION.
Oil in Water Monitoring – A Key Element of Production Separation Technology Today
By Erlend Blanchard, Mirmorax
The accurate measurement of oil in water is a critical element of operations today for one main reason - the continued increase in produced water as a by-product of oil & gas operations.
With 70% of the world’s production coming from mature fields and with a renewed focus on enhanced recovery techniques, such as Produced Water Re-Injection (PWRI) and water flooding, the oil & gas industry today is producing more water than oil. The growing increase in water cuts, for example, is a direct result of water flooding techniques as injected water eventually reaches the production wells.
The total discharge of produced water on the Norwegian continental shelf during 2011, for example, was 131 million m3 with the Norwegian Petroleum Directorate (NPD) predicting that this number will increase in the period up until 2015. Looking worldwide and in 2010, produced water rates exceeded hydrocarbon globally by as much as 50% and on the UK Continental Shelf this figure reached over 130% between 2011 and 2012 (Source: Genesis).
So what does this mean for oil & gas operators and oil in water monitoring?
There are two key arguments for the case for accurate oil in water monitoring today – one economic and one environmental.
The Economic Case for Oil in Water Monitoring
From an economic perspective, accurate information on the size and amount of sand and oil in produced water – whether it is reinjection, discharged or processed water – means more optimal operations, particularly during the water and oil separation and treatment processes.
The greater the detail on the specific components, concentrations and respective size distributions, for example, the more likely there will be optimum production through the enhanced design and use of separators and filters throughout the separation process.
Having accurate information and being able to control water/oil content also improves oil recovery and oil quality as well as ensuring reliable oil production estimates and the long-term economic future of the field. Such information can also negate lost revenues through produced water discharge.
There also remains a real danger to production if produced water is not carefully monitored – not just during the separation phase but throughout production. Typical problems might include the plugging of disposal wells by solid particles and suspended oil droplets, and the plugging of lines, pumps and valves due to inorganic scales.
To this end, information on sand and oil size distributions and concentrations will minimize effects such as plugging and decline in formation permeability that can have a highly negative economic effect on the field, reducing reservoir pressure and injectivity in water flooding operations and negating PWRI’s effectiveness as a secondary recovery technique.
The Environmental Case
The environmental case for oil in water monitoring is strong today also. Today, there are a number of regulators and bodies ensuring minimal oil discharge.
These include the OSPAR (Oslo/Paris) Convention, the main legal instrument overseeing international cooperation on the protection of the marine environment of the North-East Atlantic through to federal regulations in the Gulf of Mexico and bodies, such as the Norwegian State Pollution Control Authority (SFT) and US Environmental Protection Agency (EPA).
OSPAR, for example, has already set a target of ‘zero harmful discharge’ from produced water by 2020 and today, the current OSPAR limit is 30 mg of dispersed oil per litre of produced water. In the United States, according to the Environmental Protection Agency (EPA), produced water discharges must not exceed an oil daily maximum limitation of 35 mg per litre of produced water (40 CFR 435.52(b)).
In addition, OSPAR has also recently set out a new risk-based approach for operators as a means of integrating the assessments of all substances in produced water and identifying those posing the greatest unacceptable risk.
According to OSPAR, “where unacceptable environmental risks have been identified, contracting parties should review management options, evaluate measures and develop and implement site-specific actions to reduce the risks to an acceptable level.” In such circumstances, oil in water monitoring will be even more important.
From international regulations through to a company’s reputation and the importance of protecting the marine environment, the environmental argument for oil in water monitoring and reducing the liability of environmental discharges is every bit as strong as the economic one.
Oil in Water Monitoring Technologies Today
So are today’s oil in water monitoring technologies providing operators with all the information they need to meet both the economic and environmental criteria?
Traditionally, oil in water monitoring was manual, with samples taken from the produced water discharge, acidified to a low PH and then extracted through chemicals. Infrared quantification would then take place with oil content determined by the infrared absorbance of the sample extract and the total methylene (CH2) present.
Manual sampling has its limitations, however. As well as the fact that it is a highly labour-intensive process, there can be inconsistencies in the results. For example, spot samples rather than continuous samples over time are taken at just one moment in time with operators not getting the full real-time picture.
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 recent emergence of online, inline oil in water monitoring technologies, however, has negated many of these limitations.
Online, inline monitoring can provide direct measurements at the dispersed and suspended phase and generate more detailed information on the size distribution and concentration of oil and sand in water. The fact that the monitoring is able to take place in real-time also provides a highly effective early warning system in terms of any production threats.
Real-time monitoring also optimizes the ongoing separation process. With any deviation, one can quickly step in so that production can continue. Separators, hydro cyclones and the type and regularity of chemical injection can all be run seamlessly with significant benefits to production.
Yet, even these technologies have their drawbacks – particularly in remote, offshore environments where there are often complex mixtures of produced water and dangers of scaling and possible contamination. In such circumstances, the accuracy and robustness of oil in water monitoring technologies are pushed to the limit.
The Rise in Acoustic-based Monitoring
It’s with these issues in mind that Mirmorax has developed an oil in water monitoring solution based on an ultrasonic measurement technique in which individual acoustic echoes from both solids and oil droplets are analyzed.
This is achieved through advanced signal processing that provides accurate information on size distribution and concentration. The amplitude of the scattered signals from each passing particle is used to characterize the produced water.
The way the system works is that 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. A large number of measurements are then performed to generate a distribution and from the distribution of these amplitudes, the particle size distribution and particle concentration can be calculated from accurate acoustic scattering models.
Furthermore, by being an ‘inline’ instrument, the monitor can provide direct measurements at the dispersed and suspended phase with more detailed information on the size distribution and concentration of oil and sand in water. The monitor caters for concentrations of 0 – 1000 + parts per million (ppm) and can provide complete size distributions ranging from two to three micrometers.
Meeting Scaling and Contamination Challenges
Many monitors, however, struggle to generate accurate measurements when there is scaling. To counteract this, the Mirmorax monitor is able to ‘sound penetrate’ material as opposed to optical based monitoring solutions that can’t. 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.
In addition, we have also introduced a new auto calibration feature to compensate for scale build-up and that allows for several millimeters of scale and oil to grow on the ultrasound transducer without affecting accuracy
Other recent developments include self-cleaning mechanisms that prevent the danger of thick oil clogging the system, and enhanced salinity detection, where salinity can be compensated for in the final measurements. Salinity measurement is a valuable source of data when determining the origin of water coming from multiple wells. Information about the salinity and density mix also provides the operator with verification of how much of the separation capacity is being used for each of the fields.
It is through developments such as these that the monitor can cover a wider measurement range and compensate for layers of scaling, possible contamination and salinity – issues that are particularly prevalent in offshore fields.
North Sea Installations
Last year, Mirmorax provided three of its oil-in-water monitoring units to Statoil’s Kristin Platform, where the ultrasonic pulse echo technology provides Statoil with highly accurate oil ppm measurements allowing them to monitor and optimize their produced water treatment process.
A number of other North Sea orders have also been recently signed and a trial is currently taking place in the Orkney Islands in partnership with leading operators. In another North Sea oil field, where three Oil in Water monitors were installed, the monitors managed to reduce the overall oil content in discharge water by more than 30%.
A ‘Must’ for Operators
With increased water production and discharges in the North Sea, the growth in brownfields, and stricter environmental regulations, the detailed information on the size and amount of sand and oil in produced water is an absolute ‘must’ for operators today. It’s encouraging to see that the latest in oil in water monitoring technologies are rising to the challenge.
Oil in water monitoring is a key to production seperation
ACCURATE MEASUREMENT OF OIL IN WATER IS A CRITICAL ELEMENT OF OIL AND GAS OPERATIONS TODAY BECAUSE OF THE INCREASE IN PRODUCED WATER AS A BY-PRODUCT OF PRODUCTION.
Oil in Water Monitoring – A Key Element of Production Separation Technology Today
By Erlend Blanchard, Mirmorax
The accurate measurement of oil in water is a critical element of operations today for one main reason - the continued increase in produced water as a by-product of oil & gas operations.
With 70% of the world’s production coming from mature fields and with a renewed focus on enhanced recovery techniques, such as Produced Water Re-Injection (PWRI) and water flooding, the oil & gas industry today is producing more water than oil. The growing increase in water cuts, for example, is a direct result of water flooding techniques as injected water eventually reaches the production wells.
The total discharge of produced water on the Norwegian continental shelf during 2011, for example, was 131 million m3 with the Norwegian Petroleum Directorate (NPD) predicting that this number will increase in the period up until 2015. Looking worldwide and in 2010, produced water rates exceeded hydrocarbon globally by as much as 50% and on the UK Continental Shelf this figure reached over 130% between 2011 and 2012 (Source: Genesis).
So what does this mean for oil & gas operators and oil in water monitoring?
There are two key arguments for the case for accurate oil in water monitoring today – one economic and one environmental.
The Economic Case for Oil in Water Monitoring
From an economic perspective, accurate information on the size and amount of sand and oil in produced water – whether it is reinjection, discharged or processed water – means more optimal operations, particularly during the water and oil separation and treatment processes.
The greater the detail on the specific components, concentrations and respective size distributions, for example, the more likely there will be optimum production through the enhanced design and use of separators and filters throughout the separation process.
Having accurate information and being able to control water/oil content also improves oil recovery and oil quality as well as ensuring reliable oil production estimates and the long-term economic future of the field. Such information can also negate lost revenues through produced water discharge.
There also remains a real danger to production if produced water is not carefully monitored – not just during the separation phase but throughout production. Typical problems might include the plugging of disposal wells by solid particles and suspended oil droplets, and the plugging of lines, pumps and valves due to inorganic scales.
To this end, information on sand and oil size distributions and concentrations will minimize effects such as plugging and decline in formation permeability that can have a highly negative economic effect on the field, reducing reservoir pressure and injectivity in water flooding operations and negating PWRI’s effectiveness as a secondary recovery technique.
The Environmental Case
The environmental case for oil in water monitoring is strong today also. Today, there are a number of regulators and bodies ensuring minimal oil discharge.
These include the OSPAR (Oslo/Paris) Convention, the main legal instrument overseeing international cooperation on the protection of the marine environment of the North-East Atlantic through to federal regulations in the Gulf of Mexico and bodies, such as the Norwegian State Pollution Control Authority (SFT) and US Environmental Protection Agency (EPA).
OSPAR, for example, has already set a target of ‘zero harmful discharge’ from produced water by 2020 and today, the current OSPAR limit is 30 mg of dispersed oil per litre of produced water. In the United States, according to the Environmental Protection Agency (EPA), produced water discharges must not exceed an oil daily maximum limitation of 35 mg per litre of produced water (40 CFR 435.52(b)).
In addition, OSPAR has also recently set out a new risk-based approach for operators as a means of integrating the assessments of all substances in produced water and identifying those posing the greatest unacceptable risk.
According to OSPAR, “where unacceptable environmental risks have been identified, contracting parties should review management options, evaluate measures and develop and implement site-specific actions to reduce the risks to an acceptable level.” In such circumstances, oil in water monitoring will be even more important.
From international regulations through to a company’s reputation and the importance of protecting the marine environment, the environmental argument for oil in water monitoring and reducing the liability of environmental discharges is every bit as strong as the economic one.
Oil in Water Monitoring Technologies Today
So are today’s oil in water monitoring technologies providing operators with all the information they need to meet both the economic and environmental criteria?
Traditionally, oil in water monitoring was manual, with samples taken from the produced water discharge, acidified to a low PH and then extracted through chemicals. Infrared quantification would then take place with oil content determined by the infrared absorbance of the sample extract and the total methylene (CH2) present.
Manual sampling has its limitations, however. As well as the fact that it is a highly labour-intensive process, there can be inconsistencies in the results. For example, spot samples rather than continuous samples over time are taken at just one moment in time with operators not getting the full real-time picture.
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 recent emergence of online, inline oil in water monitoring technologies, however, has negated many of these limitations.
Online, inline monitoring can provide direct measurements at the dispersed and suspended phase and generate more detailed information on the size distribution and concentration of oil and sand in water. The fact that the monitoring is able to take place in real-time also provides a highly effective early warning system in terms of any production threats.
Real-time monitoring also optimizes the ongoing separation process. With any deviation, one can quickly step in so that production can continue. Separators, hydro cyclones and the type and regularity of chemical injection can all be run seamlessly with significant benefits to production.
Yet, even these technologies have their drawbacks – particularly in remote, offshore environments where there are often complex mixtures of produced water and dangers of scaling and possible contamination. In such circumstances, the accuracy and robustness of oil in water monitoring technologies are pushed to the limit.
The Rise in Acoustic-based Monitoring
It’s with these issues in mind that Mirmorax has developed an oil in water monitoring solution based on an ultrasonic measurement technique in which individual acoustic echoes from both solids and oil droplets are analyzed.
This is achieved through advanced signal processing that provides accurate information on size distribution and concentration. The amplitude of the scattered signals from each passing particle is used to characterize the produced water.
The way the system works is that 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. A large number of measurements are then performed to generate a distribution and from the distribution of these amplitudes, the particle size distribution and particle concentration can be calculated from accurate acoustic scattering models.
Furthermore, by being an ‘inline’ instrument, the monitor can provide direct measurements at the dispersed and suspended phase with more detailed information on the size distribution and concentration of oil and sand in water. The monitor caters for concentrations of 0 – 1000 + parts per million (ppm) and can provide complete size distributions ranging from two to three micrometers.
Meeting Scaling and Contamination Challenges
Many monitors, however, struggle to generate accurate measurements when there is scaling. To counteract this, the Mirmorax monitor is able to ‘sound penetrate’ material as opposed to optical based monitoring solutions that can’t. 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.
In addition, we have also introduced a new auto calibration feature to compensate for scale build-up and that allows for several millimeters of scale and oil to grow on the ultrasound transducer without affecting accuracy
Other recent developments include self-cleaning mechanisms that prevent the danger of thick oil clogging the system, and enhanced salinity detection, where salinity can be compensated for in the final measurements. Salinity measurement is a valuable source of data when determining the origin of water coming from multiple wells. Information about the salinity and density mix also provides the operator with verification of how much of the separation capacity is being used for each of the fields.
It is through developments such as these that the monitor can cover a wider measurement range and compensate for layers of scaling, possible contamination and salinity – issues that are particularly prevalent in offshore fields.
North Sea Installations
Last year, Mirmorax provided three of its oil-in-water monitoring units to Statoil’s Kristin Platform, where the ultrasonic pulse echo technology provides Statoil with highly accurate oil ppm measurements allowing them to monitor and optimize their produced water treatment process.
A number of other North Sea orders have also been recently signed and a trial is currently taking place in the Orkney Islands in partnership with leading operators. In another North Sea oil field, where three Oil in Water monitors were installed, the monitors managed to reduce the overall oil content in discharge water by more than 30%.
A ‘Must’ for Operators
With increased water production and discharges in the North Sea, the growth in brownfields, and stricter environmental regulations, the detailed information on the size and amount of sand and oil in produced water is an absolute ‘must’ for operators today. It’s encouraging to see that the latest in oil in water monitoring technologies are rising to the challenge.
Mirmorax obtained full iso 9001:2008 certification
Mirmorax has as part of the continous improvements of quality and compliance decided to certify our existing quality system.
The puropse of this is to verify the quality of our processes, get external feedback and ensure our clients that our processes and product deliveries are subject to continous improvement on quality and safety.
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
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.
© Mirmorax AS – All rights reserved – For grants send an email to contactus@mirmorax.com
Use of Oil in Water monitor for understanding water treatment
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.
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.