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Continuous corrosion monitoring enhances operational decisions

03.01.2014  |  Clarke, K.,  Permasense, UK

Operators with permanently-installed continuous corrosion monitoring systems have better understanding of the corrosion and erosion rates occurring within their facility.

Keywords: [corrosion] [erosion] [inhibitor] [coupons] [inspection] [steel] [pipes] [vessels]

A major problem for the hydrocarbon processing industry (HPI) is the effective monitoring of asset integrity while minimizing the exposure of personnel to difficult and potentially hazardous working environments. The application of permanently installed ultrasonic wall-thickness monitoring equipment and wirelessly transmitted data can provide continuous information on the rate of metal loss, even in the most severe environments and at extreme temperatures.

Asset and integrity managers are utilizing these systems as a critical component of safety, integrity and risk management programs to monitor the potential loss of containment due to corrosion and erosion. The data is also increasingly being used to drive risk-based operational decision-making in areas such as determining the consequences of processing more aggressive feedstocks, optimizing process conditions, applying corrosion inhibitor strategies, choosing metallurgy for plant upgrading and extending run lengths between turnarounds. This article will review key drivers and possible benefits related to continuous corrosion monitoring.

Understanding the causes of corrosion

Steel pipework and vessels are always at risk of corrosion or erosion, depending on the metallurgy of the equipment, aggressiveness of the process fluids, and operating conditions. Unless managed carefully, there is a potential risk of failure. Such events could result in a release of hydrocarbons, with a possible consequential impact on the environment and/or personnel, apart from the financial costs of equipment repairs and unplanned operational interruptions or damaged reputations.

There are various well-established, manual techniques for the periodic assessment of equipment integrity. The drivers of corrosion and erosion include: process conditions, feedstock constituents and the presence of abrasive solids. The chemical inhibitors to mitigate corrosion rates are familiar to the HPI. The present situation, such as operating aging/older plants and equipment; greater fluid corrosiveness and erosiveness; tighter health, safety and environmental (HSE) regulations; the environmental and reputational costs from leak/release events; and the growing shortage of skilled inspection staff are hurdles confronting traditional plant integrity monitoring processes.

ACTION PLANS

Plant operators have three levers for assuring plant integrity against corrosion or erosion. These are inhibition, metallurgy and monitoring, as shown in Fig. 1.

 
  Fig. 1.  Factors affecting plant equipment
  integrity assessments.



Metallurgy

Equipment metallurgy can be upgraded, often at substantial capital expense (CAPEX). An alternative option is to adopt a combination of corrosion monitoring and inhibition; this action plan is an operating expense (OPEX). Thus, the choice of strategy often evolves as tension between available CAPEX vs. the drive to minimize OPEX. In capital-constrained situations, the monitoring/inhibition strategy is very popular.

However, in this case, the widely adopted approach of periodic manual inspections does not capture the often intermittent, and sometimes accelerated and nonlinear nature of corrosion. It is, therefore, very difficult to use this data to correlate directly with either corrosion drivers or inhibitor applications to enable an understanding of the effects of feedstock and process decisions and the use of inhibitors on plant integrity. Manual ultrasonic wall-thickness measurement is also subject to repeatability and reproducibility errors, from inspectors, different ultrasound test sets and small differences in measurement locations, which is not the case with permanently mounted systems.

Permanent corrosion monitoring can represent progress in enabling effective use of corrosion inhibitors and in providing asset and integrity managers with a real-time picture of how the infrastructure is coping with the demands placed upon it.

Ultrasonic sensors

At the core of the permanent continuous corrosion monitoring systems is an ultrasonic sensor mounted on stainless-steel waveguides. The waveguides isolate the sensor electronics from high process temperatures and guide the ultrasonic signal to the pipe wall and back, as illustrated in Fig. 2. The sensors are powered by long-life batteries, and transmit their data by wireless transmitter. As a result, cabling to monitoring locations is not required, thus substantially reducing the cost of installation. It enables rapid deployment in difficult to access and remote areas, as shown in Fig. 3. 

 
  Fig. 2.  Example of a continuous corrosion monitoring system.

 
  Fig. 3.  Sensor arrays for continuous
  corrosion monitoring can be installed in
  remote places and powered by long-
  lasting batteries.

Wall-thickness data can be retrieved from sensors that are operating in extreme temperatures and environments. Automatic classification of data by corrosion rate allows quick and easy determination of where significant corrosion activity is occurring across the facility, enabling prioritization of the site’s inspection resources.

OPTINIZATION OF PREVENTION AND MITIGATION STRATEGIES

Direct, accurate and sufficiently frequent measurements of pipework thickness to accurately identify trends are rarely practically feasible with manual inspection methods when coupled with the problems of accessibility and mitigating safety risks to personnel.

Conversely, permanently installed sensor systems deliver continuous high-quality data. Installed on pipes and vessels operating at up to 600°C (1,100°F), these sensors have been certified as intrinsically safe for use in hazardous environments. They have been proven in operation for a number of years in refinery environments, along with onshore and offshore upstream facilities.

Fig. 4 shows the range of drivers that are motivating plant operators to invest in permanently installed corrosion monitoring systems. Typical investment decisions are justified by safety and operational risk mitigation factors including assuring plant integrity, improving equipment availability, determining better accessibility of measurement points from an inspector’s point of view, or changing the role of limited resources (such as qualified inspectors) from making measurements to analyzing the causes and mitigation of corrosion.

 
  Fig. 4.  Drivers for installing continuous
  corrosion monitoring systems.

However, once installed, these systems are highlighting where corrosion is taking place and whether it is intermittent or continuous. This information is proving particularly valuable in informing the production planning and operations decision-making processes, to drive the plant to improved profitability.

Personnel safety and equipment service life

The permanent corrosion monitoring sensors were installed on cast carbon steel u-bends with a wall thickness of approximately 25 mm (1 in.), operating at 380°C (720°F) at the Gelsenkirchen refinery operated by BP. The corrosion/erosion rates at these locations were a critical determinant for the timing of the next turnaround. High temperatures would have exposed inspectors to a significant hazard if manual methods had been used. The sensor data enabled the refinery management to manage operations with confidence until the turnaround. The system has been delivering reliable measurement data for over four years (Fig. 5).

 
  Fig. 5.  A continuous corrosion monitoring
  sensor is installed at a refinery.


Improved insight on feedstock decisions

Continuous corrosion monitoring is also being used to support more strategic decision-making processes such as feedstock selection and diversification. One refiner carried out a month-long trial of a crude that it had not previously processed, to gain a better understanding of the potential integrity impacts. The crude was processed at 20%–25% of the total slate during the test period. The sensors installed on the kerosine draw-off from the crude tower showed a marked increase in the corrosion rate (Fig. 6). The test-run data provided a valuable insight; the refiner used the information to develop operational guidelines and inhibitor strategy for future processing of the crude on an ongoing basis.

 
  Fig. 6.  Corrosion data provided by a
  continuous corrosion monitoring on a
  kerosine draw-off for a crude tower.

Processing of high-acid “opportunity” crudes is a key profit improvement strategy for many refiners in the Western Hemisphere. While naphthenic acid corrosion tends to be quite localized, refiners are deploying arrays of sensors. The sensors enable making a series of point measurements to highlight where a significant increase in corrosion activity is being observed. This approach also enables an understanding of the effectiveness of inhibitor chemical injections in at-risk locations.

Fig. 7 is an example of such sensor arrays. The sensors are installed circumferentially across five locations along a crude or vacuum heater transfer line. Data from the sensor system can give the refiner confidence to gradually increase the acidity of the crude oil processed while closely monitoring “known-risk” areas for an increase in corrosion activity.

 
  Fig. 7.  A sensor array installed
  circumferentially on a crude-heater transfer line.


Optimization of corrosion inhibitor injection

A key weapon in the fight to control corrosion is an inhibitor chemical. The sensor trend, as shown in Fig. 8, illustrates how an operator systematically adjusted the inhibitor dose over a one-month period, until the sensor data showed that the corrosion rate was stabilized.

 
  Fig. 8.  Sensor data support optimization
  of a corrosion inhibitor dosing program.


Process optimization

The data shown in Fig. 9 is from the overhead system of a sour-water stripper. For this system, the corrosion rate was moderate, but steady. The refiner used the sensor data to alter the process conditions of the tower until the corrosion rate stabilized from October forward.

 
  Fig. 9.  Continuous corrosion monitoring
  systems have been used to optimize
  operating conditions.


Material selection

Another refiner installed the continuous-corrosion monitoring sensors 18 months before a major turnaround so that it could track corrosion over a one-year period through the crude tower and associated pipework. The objective was to better understand the dominant corrosion mechanism—either uniform thinning corrosion from sulfidation or localized attack from naphthenic acids. The output would inform their decision-making process to determine the preferred metallurgy to be used in upgrading the equipment.

The sensor data demonstrated that localized corrosion from naphthenic acid attack was the dominant mechanism. As a result, the refinery selected the appropriate metallurgy to be installed in the upcoming shutdown.

Cost-effectiveness and safety

The installation of permanently installed sensors eliminates the cost of repeat measurements; for example, the cost in building scaffolding to access measurement points. There is no personnel exposure to high-risk locations or adverse ambient conditions. In extreme environments, such as offshore oil and gas production facilities, the technology is being used to systematically limit the amount of inspector time required on the platform, to reduce costs of transferring staff from shore by helicopter and to add flexibility within constraints on the total numbers of staff offshore at any one time.

In Northern Alberta, Canada, and on the North Slope in Alaska, permanently installed sensors are being used to deliver a reliable picture of piping condition. In Canada, the key driver is the rapid turnover of inspectors due to the harsh working environment, with associated uncertainty of reliability of measurements. In Alaska, sensor deployment is being driven by limitations on accommodations for inspectors, due to environmental constraints preventing an expansion of local living facilities.

In Europe, refiners are installing sensors at high-risk locations in HF alkylation units to significantly reduce the time that inspectors must spend working within the unit, wearing full chemical suits and breathing apparatus. In parallel with the obvious safety benefits, the refiner was able to reduce the cost of having a large number of inspection staff trained and qualified for working within the alkylation unit. The simplicity of installation is also a significant advantage when being installed in these process units, avoiding the need for multiple personnel to fit cables and mechanical hardware over an extended period.

Technology advancement

Operators using permanently installed continuous corrosion monitoring systems have a more accurate and timely understanding of the corrosion and erosion rates occurring within their facility. While often installed as part of safety or operational risk management programs, the data from such systems is providing plant operators with valuable insight into the effect of changing operations on corrosion/erosion rates, and supporting more effective risk-based decision-making around issues such as feedstock cost reduction, chemical inhibition strategy, shutdown timing, and the selection of metallurgy for plant upgrades. Permanently installed systems are also enhancing inspection strategies in locations where access is costly, dangerous or physically restricted, while the availability of wireless transmission of data significantly reduces the time needed to install such equipment in these tough environments. HP

The author
Kevin Clarke is the sales director for Permasense. He has over 27 years of experience in the downstream and oil and gas sector. Previously, he was a lead partner and director at KBC Advanced Technologies plc, with a specific focus on developing Russian and Eastern European client accounts, and overseeing delivery of consultancy projects. Mr. Clarke also held various executive vice president positions. Earlier in his career, he worked at the Elf Oil Refinery in Milford Haven, UK, where his various roles included operations superintendent and operational planning superintendent. Mr. Clarke holds an MBA and a BE degree in chemical engineering from Imperial College. He is a chartered member of the Institution of Chemical Engineers. 


 



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Antonio Martinez Niembro
06.17.2014

Very good article. A way forward would be to design such sensors for cathodically protected pipelines underground and offshore.

LARRY RUBIAN
06.16.2014

very educational indeed

Fahad
03.19.2014

thank u for your answers,
is the silicone water or oil baced?
thx
Fahad

Fahad
03.18.2014

thank u for your answers,
is the silicone water or oil baces?
thx
Fahad

Kevin Clarke
03.18.2014

Sensors are attached in two ways - either welding a pair of stainless steel stud bolts, or by using a clamped assembly. We recommend drawn arc method, but customers have used capacitive discharge, TIG and friction welding. Clamps are suitable for lower temperature applications (<150 degC); studs for all temperatures from -150 degC to +600 degC.
We have installed sensors on most commonly found metallurgies in refineries, petrochemical plants, offshore oil and gas production, including P5/5 Chrome, P9/9 Chrome, 1% Cr (5130),
Duplex, P265GH (430-161), 1.4571 (316Ti), P295GH (17Mn4), Monel, HR120, Inconel, Incoloy, Hastelloy

Kevin Clarke
03.18.2014

The measurements are localised to the sensor - about 2 cm squared below the tip, so it doesn't need to consider fittings, etc.

Coating would need to be removed just under the tip - a very small area - to ensure good metal-to-metal contact. We provide a silicone tip seal to protect the exposed area and mitigate any possibility of external corrosion.

There is no interaction with CP system.

Kevin Clarke
03.18.2014

The Permasense technology provides wall thickness measurements accurate to +/- 0.1mm, which is in in-line with manual ultrasonic testing. However, being permanently mounted in location, there are no repeatability/reproducibility issues that you get with manual measurements because of slight differences in probe location, different UT set, different operator.

Kevin Clarke
03.18.2014

Anyone with specific questions can contact us via our website www.permasense.com

IQBAL MAJID SHEIKH
03.12.2014

Keep me updating really interesting one.

K. Laxma Reddy
03.11.2014

Good article asset integrity preservation.

KNPC, corrosion specialist

Fahad
03.11.2014

Is longitudinal waves system of UT able to measure thicknesses accurately?
Is it design to consider wall variations or geometrical shapes of the monitored lines or systems?
(such as fittings, reinforcement, maintenance patches etc )

Fahad

Fahad
03.10.2014

Would this system interact with existing cathodic protection ststem.
Do we have to remove pipeline coating (fpe) to install the sensors. (localized removal)
thanks
Fahad

Hector Trujillo, P.E.
03.10.2014

Is there a way to remotely measure steel corrosion underwater (ocean)?

fahad
03.09.2014

what method used to attach sensors to the main run pipe.?
what if we use high alloy steel , for acidic comodity?

thaks
fahad .

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