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
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
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
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
Plant operators have three levers for assuring plant
integrity against corrosion or erosion. These are inhibition,
metallurgy and monitoring, as shown in Fig. 1.
1. Factors affecting plant equipment
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
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.
2. Example of a continuous corrosion
3. Sensor arrays for continuous
corrosion monitoring can be installed in
remote places and powered by long-
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 sites 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 inspectors point of view, or changing the
role of limited resources (such as qualified inspectors) from
making measurements to analyzing the causes and mitigation of
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
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. 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
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
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.
7. A sensor array installed
circumferentially on a crude-heater transfer
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.
8. Sensor data support optimization
of a corrosion inhibitor dosing program.
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.
9. Continuous corrosion monitoring
systems have been used to optimize
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 mechanismeither
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.
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
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