This type of corrosion can only be inspected through video.
Doing repairs is also an option, but only for the small areas, as this would also require extensive shutdown and cost.
Based on all these factors, the refinery has decided to retire
The fitness-for-service (FFS) assessment can be used also
to evaluate the structure integrity of in-service reactors. If
inspection reveals issues with a reactor’s mechanical integrity and the reactor is not retired, you can use API 579
guidelines to make assessments on its suitability for continued service. API 579 was developed for equipment in the
refining industry for quantitative engineering evaluations on
structural integrity. It also can be applied to make run, repair, and replacement decisions.
Is your reactor still safe in service today? The FFS assessment can be used for projecting the remaining life of the
equipment. It also can be applied for certain damages like
general localized corrosion and the presence of cracks or
creep and fire damages, as well the other items on the list.
If the FFS assessment results show the reactor is still
suitable for current operating conditions, an appropriate
monitoring and inspection program will still need to be in
place to ensure its mechanical integrity in service. If the assessment result shows that it is not suitable for service, you
could consider rerating the equipment if you do not want to
retire the reactor; or, you could consider retiring the reactor.
What kind of reactor failures have we seen in the industry? We have seen hydrotreaters, hydrocrackers, and even a
pyrolysis gasoline (pygas) hydrotreater’s reactor fail where a
reactor was damaged with a hole. Many times, reactor failure
was caused by a temperature excursion where the reactor
was operated above the designed temperature. There are also
other types of failures that are caused by corrosion, such as
high-temperature hydrogen attack or cracking when reactors
are exposed to too low a temperature while still under pressure. The reactor failure can also be caused by hydrogen embrittlement when the reactors are cooled down too quickly
and the hydrogen dissolved into the reactor wall could not
get out right away. Temper embrittlement was affected mostly on primarily 2.25Cr-1Mo material. Failures were also observed due to poor toughness of the material and mechanical or thermal fatigue.
The inspection techniques commonly used for reactor inspection are the nondestructive examinations (NDEs). Some
of them have already been mentioned by Derek for their plant
use, including UT, magnetic particle, penetrant, and radiographic. The infrared thermometry was actually used mostly
for the cold-wall reactor design. There are also advanced nondestructive examinations such as automatic ultrasonic testing, advanced ultrasonic backscattering technique, time-of-flight diffraction, and angle beam spectral analysis for walls.
Some of the tests have required a sample be extracted into a
boat or scoop for the test.
The inspection frequency normally is determined by the
calculated each minute as a moving weighted average and
incorporates the value each second by adding one sixtieth
of the latest value to the weighted average over the previous
If that rate of change is 50° F. or above in 1 min, then
I am wondering if you have any specific recommendations on the type of instrumentation for thermometry
inside the reactors, both from the hydrotreating and hydrocracking standpoints.
There are differences, but we have had good experience with high-temperature, high-pressure thermometry provided by both of the vendors represented and showing exhibits here today.
What are your criteria for retiring a hydroprocessing reactor? What kind of failures have you seen? What are the
inspection techniques you use and your frequency of inspection?
This is a complicated question. In general, there is no
need to retire a reactor unless there is an active degradation
mechanism identified. So if there is one identified, inspection plans need to be in place to verify the degree of degradation and identify the mechanisms in the corrosion review
At Shell, we use a risk-based inspection technology to establish the required extent for inspection and frequency of
the inspection, as well as the assessment of the reactor’s remaining life.
Here is one example. There is a soon-to-be retired reactor
in naphtha hydrotreating service that was made in 1958, so
it is quite old. The reactor was made of C-½ moly material
with stainless-steel 304 overlays. There are two corrosion
concerns with this reactor. One is the high-temperature hydrogen attack which has been managed through the inspection program and Ensure Safe Production (ESP) practices
with regard to operating temperature and hydrogen partial
pressure. With the recent industry experience on high-temperature hydrogen attack and the expected new API curves
for this type of metal service, it is possible the Shell inspection program and the ESP practices may not be acceptable
for this type of service. As a result, the refinery is considering replacing the reactor.
The second corrosion concern on this reactor is the sulfidation. Because if the stainless-steel 304 is detached from
the reactor wall, there will be a concern of sulfidation corrosion. The corrosion rate can be as high as 10-15 mils/year.