1 Permasense Ltd, Century House, 100 Station Road, Horsham, RH13 5UZ, UK www.permasense.com [email protected]+44 20 3002 3672 1. Introduction Present high levels of production and the ease of availability of light tight oils (so called LTOs) are driving US refiners to enhance their processing flexibility to take advantage of the significantly higher margins that can be achieved from processing of these oils. While considerable focus is being placed on the ability of the crude and vacuum distillation towers to cope with a marked change in yield slate from these crudes from a tower loading and fractionation standpoint, these LTOs also exhibit unique processing issues from a corrosion point of view. The production of LTOs relies on the use of (so called) fracking fluids, a cocktail of chemicals to stimulate oil to flow from the field. In many instances, these chemicals can end up in the crude oil as feedstock to the refinery. In addition, the transportation of light tight oils by railcar requires the addition of H 2 S passivator chemicals that can introduce other corrosion-related problems to refineries. These amine-based compounds can deposit as salts in the top section of crude towers, around the top pumparound and draw trays, with the resulting possibility of under deposit corrosion. To counter these issues, many operators are adding acidic chemicals to their desalter wash water to neutralise the amines. However, without careful monitoring and control, this operation in itself opens up the potential for increased corrosion over a wider area of the crude distillation unit. As well as LTOs, many operators are exploring a wider crude slate basket and testing new crudes, with the possibility for introduction of other corrosive species, such as organic acids (chlorides) into the crude unit, which are usually residues from chemicals used for well stimulation in the upstream oil production process. While dew point corrosion in the crude overhead systems is well documented, the processing of LTOs at a refinery can increase the risk to plant integrity from elevated corrosion across a wider area of the crude overheads system. This can result in unplanned shutdowns driven by unacceptably high corrosion activity. However, if unnoticed and unmitigated, this increased corrosion rate could lead to a hydrocarbon leak and, in the worst case, result in an explosion or fire, which may cause human tragedy, extended business interruption, loss of customers, the cost of extensive rebuilding of equipment, as well as the impact on the company's brand reputation, and future enhanced regulatory scrutiny. Unplanned outages in a critical process unit, such as the crude distillation, will often cancel out the profit gained from processing a price-advantaged crude diet, so refiners have to walk the narrow tightrope between maximising profit and managing plant on-stream availability. Compound this with Continuous corrosion, monitoring of crude overhead systems
Transcript
1 Permasense Ltd, Century House, 100 Station Road, Horsham, RH13 5UZ, UK www.permasense.com [email protected] +44 20 3002 3672
1. Introduction
Present high levels of production and the ease of availability of light tight oils (so called LTOs) are driving US refiners to enhance their processing flexibility to take advantage of the significantly higher margins that can be achieved from processing of these oils. While considerable focus is being placed on the ability of the crude and vacuum distillation towers to cope with a marked change in yield slate from these crudes from a tower loading and fractionation standpoint, these LTOs also exhibit unique processing issues from a corrosion point of view.
The production of LTOs relies on the use of (so called) fracking fluids, a cocktail of chemicals to stimulate oil to flow from the field. In many instances, these chemicals can end up in the crude oil as feedstock to the refinery. In addition, the transportation of light tight oils by railcar requires the addition of H2S passivator chemicals that can introduce other corrosion-related problems to refineries. These amine-based compounds can deposit as salts in the top section of crude towers, around the top pumparound and draw trays, with the resulting possibility of under deposit corrosion. To counter these issues, many operators are adding acidic chemicals to their desalter wash water to neutralise the amines. However, without careful monitoring and control, this operation in itself opens up the potential for increased corrosion over a wider area of the crude distillation unit. As well as LTOs, many operators are exploring a wider crude slate basket and testing new crudes, with the possibility for introduction of other corrosive species, such as organic acids (chlorides) into the crude unit, which are usually residues from chemicals used for well stimulation in the upstream oil production process.
While dew point corrosion in the crude overhead systems is well documented, the processing of LTOs at a refinery can increase the risk to plant integrity from elevated corrosion across a wider area of the crude overheads system. This can result in unplanned shutdowns driven by unacceptably high corrosion activity. However, if unnoticed and unmitigated, this increased corrosion rate could lead to a hydrocarbon leak and, in the worst case, result in an explosion or fire, which may cause human tragedy, extended business interruption, loss of customers, the cost of extensive rebuilding of equipment, as well as the impact on the company's brand reputation, and future enhanced regulatory scrutiny.
Unplanned outages in a critical process unit, such as the crude distillation, will often cancel out the profit gained from processing a price-advantaged crude diet, so refiners have to walk the narrow tightrope between maximising profit and managing plant on-stream availability. Compound this with
Continuous corrosion, monitoring of crude overhead systems
2 Permasense Ltd, Century House, 100 Station Road, Horsham, RH13 5UZ, UK www.permasense.com [email protected] +44 20 3002 3672
pressure to reduce costs, most notably through reduced headcount and contractor use, often including inspection department resources, and the ability of a refiner to maintain an appropriate level of surveillance of plant integrity is further challenged.
Oil and gas facility operators the world over are solving this puzzle by proactively deploying at scale, permanently installed, continuous wall thickness monitors to track corrosion in critical locations. Not only does tighter monitoring enable cost-effective tracking of corrosion in areas of concern, but it enables a refiner to pinpoint specific feedstocks or process operations that result in accelerated corrosion rates - thereby facilitating optimisation of corrosion mitigation strategies online and validation of the effectiveness of these mitigation strategies, so that timely, evidence-based, integrity management decisions can be made.
2. The need for crude processing flexibility
Figure 1: US light tight oil production (EIA)
Recent data, shown in Figure 1, published by EIA, shows the rapid growth in production of US domestic light tight oil. These crudes are discounted by several $/bbl against the normal marker crudes, like Brent or WTI and refineries located in the vicinity of the major light tight oil formations have an even higher margin advantage. A conservative discount of just $0.5/bbl from the standard crude slate for an opportunity crude could raise the profitability of a typical 200 kbpd refinery by $35 Million/year; far in excess of the cost of incremental chemical inhibition and monitoring, meaning that the payback time on the implementation of an inhibition/monitoring program can often be measured in terms of a few months.
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3. Crude tower overhead corrosion Crude tower overhead corrosion has been well studied and documented over many years. The aggressiveness of the corrosive attack in the overhead system is a function of the amount of chloride present in the system, which in turn is a function of the effectiveness of the desalter. Inadequate desalter performance results in high (salt) chloride content in the crude oil at the desalter outlet - the chloride ions hydrolyse in the crude furnace and form hydrogen chloride which is condensed in the crude overhead system. The highest risk location for failure occurs at the point where the first droplet of hydrochloric acid condenses, because this has a very low pH, known as the dew point. If ammonia and amine-based salts are present in the overhead system, and the operating conditions favour salt formation, these compounds can create a protective layer over the condensed hydrochloric acid and allow it to corrode away at the underlying metal without interruption. The hydrochloric acid dewpoint can move around within the overhead system, driven by changes to operating temperature and pressure and flowing velocity, which makes it difficult to monitor.
Crude overhead system shell-and-tube condensers are traditionally designed with the overhead material on the shell side. The hydrochloric acid attack therefore occurs on the outside of the tubes - a localised leak results in crude oil (which is usually used as the cooling medium) leaking into the overhead (naphtha) product. If unchecked, this contaminated naphtha can have a significant impact on the performance and catalyst life of downstream hydrotreaters. Examples of localised dew point corrosion are shown in the photographs (Figure 2) below.
Figure 2: Crude overhead hydrochloric acid dew point corrosion [Courtesy of Nalco Champion]
Light tight oil processing introduces another corrosion problem for refiners - the use of amine-based H2S passivators can result in salt formation in the top section of the crude tower, on the inside of the tower walls on the trays, around the top pumparound circuit and in the product draw-offs. As described previously, these salts can form a protective layer over the hydrochloric acid with the result that very aggressive and localised corrosion can occur. In order to neutralise these amines, refiners are moving towards new treatment programs involving acidifying the desalter - if applied without care, this can also introduce acid-based corrosion around the desalter wash water system and in the desalter itself.
Most refiners utilise a chemical treatment program for their crude overhead system, in addition to close desalter performance monitoring. Common treatments utilise two elements:
1. Neutraliser - often an amine-based compound, or ammonia, this acts to raise the pH in the overheads system and to react with any hydrochloric acid present, producing an inert amine chloride-type compound.
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2. Filmer - this is also often an amine-based compound, which is injected to cover the surfaces inside the overhead system, thereby providing a barrier to prevent the hydrochloric acid from coming into contact with the metal.
In order to dilute hydrochloric acid formed in the overhead system, many crude units also employ a continuous water wash - often control systems on these water wash facilities are basic, with no guarantee of uniformity of water distribution across the exchanger banks. This can result in operators having a false sense of security.
4. Crude overhead dew point corrosion management Refiners have two principal mitigation strategies for crude overhead acid corrosion - they can upgrade the metallurgy of many/all of the susceptible areas of the unit(s), often to high grade, expensive alloys such as hastelloy, monel or titanium or they can use chemical treatment. In both cases, these strategies should be combined with tighter corrosion monitoring at critical locations to verify the inhibitor distribution and the effectiveness of the metallurgy upgrade. The choice between these options is usually a question of capital budget availability - in the current climate, where capital budgets are being cut, many operators are choosing chemical inhibition and monitoring over metallurgical upgrading, especially since the optimisation of the inhibitors and the installation of integrity monitoring systems can be carried out on-the-run without the need for a plant shutdown.
Figure 3: The choice between metallurgical upgrading and chemical treatment for crude overhead dewpoint corrosion mitigation
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5. High risk areas for acid dewpoint attack in crude tower overheads
The diagram below shows the areas of a typical crude unit that are at high risk from acid dewpoint attack:
Figure 4: Crude tower overheads - high risk locations for acid dewpoint attack
6. Commonly applied technology for corrosion monitoring
There are several types of instrument that have traditionally been used for monitoring corrosion in oil refineries. Two of the most common are corrosion probes and manual ultrasonic inspection.
Corrosion probes have been in use since the 1960s and are a very well established technology. They rely on an intrusive element with a sacrificial tip, which sits in the process fluid and is (normally) made from the same material as the surrounding equipment. As the sacrificial tip corrodes, its electrical resistivity changes, which is recorded externally (usually on a locally mounted data logger) but these are also increasingly available wirelessly connected. The corrosion of the sacrificial tip is used to infer the level of corrosion being experienced by the surrounding equipment. While being simple to use, corrosion probes suffer from a number of disadvantages:
The centre‐line measured corrosion may not be the same as the corrosion rate at the wall,
due to the shear velocity effects described previously.
The tip often corrodes away after two to three years (or even less with "high sensitivity"
applications), while many refineries are now operating 5+ years between major
turnarounds. Thus, the corrosion probe tip will usually need to be replaced on‐the‐run.
Very careful safety procedures and intensive technician training are required to reduce
danger to personnel. In spite of this, there have been several well documented safety
incidents caused by probes being ejected at high velocity under residual pressure. Several
international oil companies have banned removal of intrusive probes while the plant is
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running, with the result that they operate 'blind', from a corrosion standpoint, for the final,
and most critical, one or two years of the cycle between turnarounds.
The intrusive nature of these probes means that they cannot be installed during normal
operations, since they require specialist mounting flanges to be bored and welded to the
piping.
The intrusive probe creates a disturbance in the flow of the fluid that can induce corrosion
to occur further downstream.
Many of the older type, data logger based probes require an engineer to visit the equipment
to download data. They therefore require physical access to the probe location and have an
inherently low acquisition rate. This latter point is an important issue for crude overhead
systems, such as the overhead line itself, as these are often physically remote ‐ the probe
data connection then has to be cabled to a nearby platform, increasing installation costs and
opening the possibility for the cable to be damaged.
6.2. Manual ultrasonic inspection
Ultrasound has been applied in the oil and gas industry for the past 50 years and is a well-established technique for measuring metal wall thickness. The technique involves the generation of ultrasound from a transducer that is placed directly onto the metal surface. The ultrasound is transmitted through the metal until it is reflected off the inside metal surface (backwall). The reflected ultrasound signal (or A-scan) is recorded and the time difference (the 'time-of-flight') between the sending and reflected signals provides the measurement of the wall thickness. While the technique can be reliable, completion of a full set of measurements for a medium-sized refinery with 80,000+ corrosion measurement points is very time consuming and labour intensive, such that the wall thickness at an individual low- to medium-risk point may only be measured every 2-3 years. It is therefore very difficult to take measurements in key locations with enough frequency to measure corrosion rates with any confidence, or to link periods of high wall loss to specific feedstocks or process operations (which require measurements on the time scale of days to be useful).
In addition, while being relatively simple, manual ultrasound methods have the following disadvantages:
Repeatability and reproducibility errors ‐ it is highly unlikely that consecutive measurements
will be taken in precisely the same location by the same NDE technician. In addition, the
equipment used and the skill level of the NDE technician can vary between measurements,
introducing high variability to the measurements. The chart below shows manual
measurements at a single (nominal) location over time from 1984 to 2013. It is clear that
different conclusions regarding wall thickness and corrosion rate can be drawn over time.
From such data, it could be inferred that the accuracy of manual ultrasound is +/‐ 0.5 to 1
mm (+/‐ 20‐40 thou).
7 Permasense Ltd, Century House, 100 Station Road, Horsham, RH13 5UZ, UK www.permasense.com [email protected] +44 20 3002 3672
Figure 5: Manual ultrasound measurements at a fixed location over time [courtesy of
Chevron]
High temperatures ‐ temperatures above only 100˚C (212˚F) can permanently damage the
electronics of the transducer.
Physical access ‐ the inspector needs to be able to have access to the equipment at the
measurement location of interest, therefore requiring scaffolding (possibly permanently
installed) and stripping of insulation to expose the metal work to make the manual
measurements.
7. Overview of the Permasense technology
Permasense permanently installed, ultrasonic, wireless, wall thickness monitoring sensors are ideal for crude overhead dewpoint corrosion monitoring - having sensitivity to small changes in wall thickness, robustness to extreme plant conditions, extended battery life (enabling reliable operation over the entire cycle between turnarounds) while being simple and cost effective to install at scale.
7.1 Resilience to high temperature
The design of the sensor incorporates a unique and patented 'waveguide' design as shown on the following page. The waveguides are made from stainless steel, which is a poor conductor of heat, and so the electronics are kept safely away from the hot metal surface (up to 600˚C (1100˚F)).
8 Permasense Ltd, Century House, 100 Station Road, Horsham, RH13 5UZ, UK www.permasense.com [email protected] +44 20 3002 3672
Figure 6: Effectiveness of Permasense patented waveguide technology to protect electronics from high temperatures
The ultrasound is transmitted from the 'sending' transducer, down one waveguide and the reflection is transmitted up the other waveguide to the 'receiving' transducer. As with manual ultrasound, the 'time-of-flight' difference between the 'surface wave' signal and the first reflection from the internal metal surface provides the wall thickness measurement, as shown in the diagram below.
Figure 7: Signal and wavepath of the Permasense ultrasonic sensor
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7.2 Resolution of roughness effects
Permasense have recently announced the availability in Data Manager v5 of a major advance to their technology with the arrival of the proprietary AXC (Adaptive Cross Correlation) ultrasonic signal processing method.
AXC makes use of the previous recorded waveform to improve the resilience of the measurement when the internal metal surface morphology is very rough, where normal ultrasonic wall thickness measurements can break down. In addition, AXC further enhances the repeatability of the measurements, meaning that even smaller levels of corrosion or erosion can be detected in a matter of days. AXC enables the separation of the wall thickness measurement from the onset of roughening of the internal surface - however, the presence of roughness is now captured separately as a colour bar, known as the Permasense Shape Indicator, or PSI. This improved processing method makes the interpretation of the data much easier and quicker.
8. Local measurements/area coverage
The Permasense system is designed to have a low cost of installation, through use of wireless communications and battery power-packs, avoiding any need for cabling with the resultant armouring and cable tray installation. This simplicity of installation makes these sensors ideal for use in remote locations which are only accessible during turnarounds.
Each sensor has a measurement footprint of an area of approximately 1 cm2, which is similar to manual ultrasound inspection. Thus, the probability of detection of localised dewpoint corrosion attack using a single sensor, would be small. In order to increase the probability of detection, sensors are installed as multi-point arrays, at the highest risk locations based on understanding of the dew point temperature, metallurgy and the equipment geometry. The number of sensors needed for each array is driven by historical inspection records, or by the proportion of the area being monitored that is expected to be affected by corrosion - the smaller the affected area as a proportion of the whole equipment being monitored, the more sensors that are required to achieve 90% confidence in detecting the onset of that localised corrosion activity.
Figure 8: Variation of number of sensors with area of corrosion and probability of detection
0.80
0.85
0.90
0.95
1.00
5 10 15 20 25 30
Co
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den
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det
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No. of sensors
10% of areamonitored exhibiting
corrosion activity
15%20%25%
10 Permasense Ltd, Century House, 100 Station Road, Horsham, RH13 5UZ, UK www.permasense.com [email protected] +44 20 3002 3672
Figure 8 shows the result of mathematical analysis carried out the Department of Non-Destructive Engineering at Imperial College in London, showing the relationship between the numbers of sensors deployed in an area, the area of the corrosion activity as a proportion of the total area being monitored and the resultant probability of detection. Only a modest number of sensors are required in an area to achieve an excellent probability of detection.
9. Point measurement resolution and the effect of process temperature variations
All ultrasound-based measurements are affected by process temperature variations, due to the change in speed of sound through the metal.
Figure 9: Variation of wall thickness measurement with process temperature
Figure 9 shows the variation of wall thickness, measured using permanently installed ultrasonic sensor. When zoomed in, as shown, the variation is of the order of 0.05 mm (2 thou), for process temperature fluctuations of 20˚C (40˚F). This level of variation is not ideal for determination of short term changes in corrosion rates, despite being orders of magnitude less than achievable with manual inspection. The latest generation of Permasense sensors (WT210) make use of an integrated thermocouple to measure the metal surface temperature, and can automatically compensate the wall thickness data for process temperature variations, as demonstrated in Figure 10 for the same data shown in Figure 9.
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Figure 10: Temperature compensated wall thickness measurement
The temperature compensated data shows variation of less than 10 micrometres (0.2 thou). This degree of precision enables detection of much smaller, shorter term corrosion rates, with confidence. However, as importantly, the corrected data shows that corrosion was not continuous at this location and there are two discrete corrosion events, which were masked by measurement noise in the original data. The precision achievable with the latest sensor models and automated data processing is comparable to that of high sensitivity intrusive probes, but without their inherent safety problems and high installation costs.
10. Permasense monitoring solution for crude tower overhead systems
Figure 11 shows an example of a monitoring system for a crude tower overhead system using the Permasense technology.
A typical overhead monitoring system would consist of 20-30 measurement locations, with between 2 and 5 sensors per location - so a total of 40 to 150 sensors, depending on the system configuration, metallurgy and operating conditions.
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Figure 11: Key monitoring locations for crude tower overheads system using Permasense technology
11. Case studies
11.1. Chemical treatment optimisation
'Real-time' corrosion data from Permasense sensors installed in the crude overheads system can provide an effective understanding of the effectiveness of the overhead chemical treatment program. A European refiner used a network of Permasense sensors, installed across the overhead system, to adjust the treatment chemical dosage to stabilise corrosion.
Figure 12: Crude tower overheads system monitoring trend using Permasense technology
Prior to optimisation of the overhead treatment chemicals, corrosion rates were very high - 1.2 mm/year (48 mpy). Over a month long period, the refiner increased the neutraliser dosage in steps,
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tracking the effect on the corrosion trend provided by the Permasense sensors - once the chemical dose was optimised, the sensor data showed that the corrosion trend had been stabilised.
Figure 13: Crude tower overhead line - Permasense installation
11.2. Optimisation of overhead process conditions
As was described earlier, the location and severity of hydrochloric acid dewpoint attack can be affected by several process parameters, such as the crude overhead cutpoint or the volume of stripping steam injected into the tower (and, hence, the volume of water condensed in the overhead system).
Figure 14 shows a corrosion rate trend from Permasense sensors, correlated against the calculated volume of water condensed in the overhead exchangers. The volume of water is a function of the overhead cutpoint and other operating parameters - these are changed on a seasonal basis. The Permasense data demonstrates that when there is a sufficient volume of water condensed in the overhead exchangers, the higher the dilution of any acid droplets that condense - resulting in a higher, and less corrosive, pH. The chart also shows that the reverse is true - lower volumes of condensed water result in highly concentrated acid droplets at the dewpoint, and higher corrosion rate.
Water Condensed in Overhead Shell and Tube Exchangers Vs. Permasense Data
Water Condensed Nov 12 ‐ Jul 13 Water Condensed Aug '13 ‐Now
Thickness E2102A Nov 12 ‐ Jun 13 Thickness E2102A Aug 13 ‐Now
Outlet Temperature < Dew Point, bulk water condensation
Outlet Temperature > Dew Point, localised water condensation
Large amount of condensed water
Little/no condensed water
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11.3. Treatment chemical mal-distribution
One refiner noted significantly higher corrosion rates from Permasense sensors installed on the shell of one bank of exchangers from a series of banks of overhead shell-and-tube exchanger shells. This was investigated and determined to be due to an uneven distribution of the treatment chemicals. As a result, the operator prepared a small project to install a dedicated treatment chemical injection point for that exchanger bank in the next turnaround.
11.4. Turnaround workscope preparation
A failure of an overhead exchanger bundle is a major problem for refiners - requiring an extended shutdown. In many cases, refiners keep spare overhead exchanger bundles on hand in case of a failure during normal operations, to avoid an extended delay in provisioning a new bundle from suppliers at short notice (and resulting high cost). In Case study 3 above, as a result of the high corrosion rates observed on the Permasense sensors installed on the shell of the exchanger described above, the operator was able to anticipate the need to replace the tube bundle in the work scope of a forthcoming turnaround. The equipment was ordered well in advance, with the result that this could be procured at an acceptable cost.
11.5. Tracking overhead system organic chloride corrosion
A North American customer was able to monitor corrosion rates in the overhead system attributable to specific batches of crude using Permasense sensor data. Figure 15 shows the wall thickness trend over a six month period. The period marked by the red dot showed markedly higher corrosion rates than normal, although the crude type was not unusual and had been processed previously. During this period, there were no unusual process measurements to indicate any kind of unexpected issue with processing of this crude - apart from the high corrosion rate trend shown by the Permasense sensor data. As a result, the refiner sent samples of the crude oil to a laboratory for more advanced analysis. This showed a high (and unusual) level of organic chloride in the crude oil - most probably due to the use of well stimulant chemicals in the upstream oil production process. As a result of this experience, this refiner now routinely tests every import of crude for organic acids to pre-empt any corrosion problems.
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11.6. Desalter wash water system corrosion
A North American customer installed a Permasense sensor system to track corrosion in the desalter wash water system. This was due to the fresh wash water being fed from a nearby lake and being highly oxygenated (and hence corrosive). This application is similar in most respects to that required for effective corrosion monitoring of the desalter wash water circuit after acidification to neutralise amine passivators when processing light tight oils.
12. Conclusions
Market conditions are driving refiners to seek new ways to raise profitability. This includes
processing more variable quality crude oils, such as the US light tight oils (LTOs). In doing so,
the risk of a corrosion‐driven failure is increasing, in a cost‐constrained environment where
inspection headcount and contract resource can be limited.
The growing availability of light tight oils, which have their own integrity‐related processing
issues, is resulting in a choice between upgrading of metallurgy and chemical
inhibition/corrosion monitoring. With tight budgetary constraints in place, many oil
companies are opting for chemical inhibition and tighter monitoring. Payback times from an
inhibition/enhanced monitoring strategy can often be measured in the order of a few
months.
Acid dew point attack is a localised phenomenon that occurs in the crude tower overheads.
Effective monitoring requires a technology that can operate in remote locations, is able to
detect small changes in internal roughness and wall loss and is simple and cost‐effective to
install at scale.
Intrusive corrosion probes have the required sensitivity and responsiveness, but are complex
to install and maintain and suffer from potential safety problems when changing sacrificial
probes. They represent a single point measurement that infers the impact of the
corrosiveness of the process fluid on the equipment wall. Manual ultrasound suffers from
repeatability/reproducibility issues due to variations between measurements in
measurement location, operator and equipment. However, manual ultrasound also requires
that an inspector can gain access to the location, which is not often feasible with crude
tower overhead systems.
Permasense technology, installed in arrays, provides both the local resolution accuracy and
the required area coverage to be the perfect solution for dew point monitoring. The latest
generation Permasense sensors are able to provide equivalent accuracy to 'high sensitivity'
intrusive probes, by using automated temperature compensation, enabling measurement of
short‐term changes in corrosion rates with confidence, making them ideal for tracking
corrosion from short crude processing campaigns.
Installed at more than 70 refineries world‐wide that are owned by international oil
companies, independents as well as national oil companies, Permasense sensors have
automatically delivered more than 10 million on‐line measurements over the past 5 years to
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those personnel who need the data to make better informed operational and asset integrity
management decisions.
Contact: For further information, about Permasense continuous corrosion and erosion monitoring solutions please contact us by email at [email protected] or by telephone to our UK offices at +44 20 3002 3672 and +44 1224 628 258 or Houston office at +1 281 724 3774 or our Kuala Lumpur office at +60 3 6200 0788
