Flexibility in the range of crudes that can be accepted by a refinery is paramount for maximizing profitability, and, in some regions, is key for the ongoing survival of the facility itself. Many of the lower cost crudes on the market – the so called “Opportunity Crudes” – are priced at a discount against the marker crudes because of their difficult processing properties – most notably, their corrosiveness, measured by the TAN (Total Acid Number), which is the laboratory test method used to characterize crudes that are prone to causing naphthenic acid corrosion.
Oil and gas facility operators the world over are proactively deploying permanently installed, continuous wall thickness monitoring systems at scale 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 optimization 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.
Many of the world’s existing refineries were designed to process crudes with a TAN of 0.3 mgKOH/g or less, while the total volume of almost 3 percent of global production has been/is being added which has a TAN of 1 mgKOH/g or more. These crudes are often discounted by several $/bbl against the normal marker crudes, like Brent or WTI. A 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.
High TAN crudes bring naphthenic acid corrosion, which is a particularly aggressive and often localized corrosion mechanism, characterized by the ‘orange peel’ effect, shown in the photograph above.
While the majority of the issue is centred on the crude and vacuum distillation units, gas oil and residue products fed to downstream conversion and hydroprocessing units can also exhibit TAN levels that are problematic in feed section equipment fabricated from carbon steel.
The aggressiveness of naphthenic acid corrosion is a function of four key parameters within the plant: temperature, metallurgy, velocity and crude oil sulphur content.
Refiners have two principal mitigation strategies for naphthenic acid corrosion – they can upgrade the metallurgy of many/all of the susceptible areas of the unit(s), or they can use chemical inhibitors. In both cases, these strategies should be combined with tighter corrosion monitoring at critical locations to verify the inhibitor distribution and/or 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 optimization of the inhibitors and the installation of integrity monitoring systems can be carried out on-the-run without the need for a plant shutdown.
There are several types of instruments that have traditionally been used for monitoring corro-sion in oil refineries. Two of the most common are corrosion probes and manual ultrasound.
Intrusive 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, that sits in the process fluid and is (normally) made from the same grade of 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.
Intrusive corrosion probes suffer from a number of disadvantages:
• Indirect measurement: The corrosion of the probe is used to infer the corrosion that is experienced by the equipment itself – often, the two are not the same due to differences in material and the shear velocity effects described previously.
• The tip often corrodes away after two-to-three-or-four 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 avoid any 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 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 special mounting flanges to be bored and welded to the piping.
• The intrusive probe creates a disturbance in the flow of the fluid that can potentially 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 and non-continuous information supply.
Ultrasound has been applied in the oil and gas industry for the past 50+ years and is a well-established technique. 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 back wall. 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 (often called Thickness Measurement Location, or TMLs) is very time consuming and labor intensive, such that the wall thickness at an individual low-to-medium risk point may only be measured every 5+ 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 using the same equipment. 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 as each measurement has been made. From such data, it could be inferred that the accuracy of manual ultrasound is ±0.5 mm to 1 mm (±20 though to 40 thou).
• Susceptibility to internal metal surface roughness, for example, localized pitting – it is a limitation of ultrasonic physics that very small defects on the inside surface of the metal will scatter the ultrasound and create a distortion in the reflected signal. This can manifest itself as an apparent increase in the metal wall thickness compared to an earlier reading which is, of course, impossible. Human nature will often discard this measurement, and the operator would shift the probe slightly to one side or another until a ‘normal’ reading was obtained (i.e. the same or less than the previous reading). Thus, this limitation of ultrasound could result in very valuable information about the onset of roughening of the internal surface, as an indication of the presence of corrosion activity, being missed.
• Equipment/technician damage at high temperatures – temperatures above approximately 100 °C (212 °F) can permanently damage the electronics of the transducer. In addition, for temperatures in excess of this level and certainly for the types of temperatures at which naphthenic acid would be prevalent, it is not safe for inspectors to be working in close proximity of the hot metalwork, even wearing protective equipment.
• Requirement for physical access – the technician 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, with consequential costs and energy losses.
There are several modern and well-proven corrosion measurement technologies available now that seek to overcome the disadvantages of both intrusive probes and manual ultrasound. These technologies fall into two main categories:
• Permanently installed, local/point measurement
• Permanently installed, area measurement
Area measurement methods provide a valuable way of determining that there is corrosion activity going on within a given system, and the approximate extent of that total metal loss. However, an increase in measurement area carries an associated reduction in resolution or sensitivity of those measurements. If these instruments indicate a 1% loss of metal volume across the entire measurement area, it requires very skilled and highly trained specialists to interpret whether this is a uniform loss of metal across the entire area, or the loss of metal from a single pit, which could be almost through the entire wall thickness. In practice, area measurement tools are most useful for screening. Data collected by these systems is often sent away periodically for interpretation by specialists for processing and return at a later time, with an additional data processing cost and delay. Very often this equipment is complex in structure, with sophisticated metal surface wired couplings, making it expensive to buy and install and easy to damage in an industrial environment. Many of these type of systems require the inspector to go into the field to retrieve the data, so requiring physical access to the equipment. Once deployed, these systems cannot be re-located in the event of subsequent equipment replacement.
Many of the point measurement monitoring methods available today suffer from the disadvantages described earlier:
• Unsuitable for high-temperature applications due to sensitivity of the transducers or electronics.
• Distortion of the ultrasonic reflection from rough internal surfaces resulting in confusing wall thickness trends.
• Inherent lack of field robustness and high installation costs due to cabling between various components of the monitoring system, e.g., between transducers and associated electronics/data loggers, resulting in poor quality data or high system maintenance costs.
• Poor quality data overload: large quantities of poor quality data are collected, creating resource-intensive data interpretation before any value can be derived.
Waveguide corrosion and erosion monitoring products have overcome the limitations above, making it the ideal monitoring solution for naphthenic acid corrosion monitoring – having both sensitivity to small changes in wall thickness and robustness to extreme plant conditions, while being simple and cost-effective to install at scale.
The effectiveness of patented waveguide technology is to protect electronics from high temperatures.
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). It is the only point measurement technology currently available on the market that can operate at these elevated 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.
By analyzing over 10,000 sensors deployed throughout the oil & gas industry since 2008 (collecting over 13 million wall thickness measurements from live plant), the need to overcome physical limitations associated with standard ultrasonic wall thickness measurements with a rough or pitted internal surface was identified.
The solution to this issue is the proprietary and patented AXC (Adaptive Cross Correlation) ultrasonic signal processing method, introduced in 2015. Instead of scanning for the peak of the first ultrasound reflection from the internal surface, AXC makes use of the previous waveform structures to improve the reliability of detection of the first echo, even in the presence of distortion from a rough internal surface. 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 color bar.
For more information, contact RFQ.RMD-RCC@Emerson.com. This article was excerpted from Crude Slate Flexibility Through Online Corrosion Monitoring, A Corrosion Monitoring Solution Guide from Emerson Automation Solutions.
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