INSPECTIONEERING JOURNAL
Challenging Baseline Inspection Paradigms for Oil &
Gas Upstream Equipment
By George C. Williamson, VP of Integrity, Risk Management & Litigation Support at Integrity & Emission
Reduction Partners, LLC, and Dr. Bill Hedges, Independent Consultant. This article appears in the
July/August 2022 issue of Inspectioneering Journal.
Introduction
Conventional wisdom holds that baseline inspections must be done for all
piping and other static mechanical pressure equipment [1-3]. An investigation
was conducted to challenge this paradigm and the potential risk of changes to
it. This article introduces a new approach to baselining practices that were
developed for and implemented by one upstream operator. One substantial
change was the elimination of baseline inspections for production and facility
piping. Alterations were also made in baselining practices for pressure vessels
with the objective of enhancing non-intrusive inspection (NII) programs.
Baseline Inspection Overview
Determining the purpose of performing baseline inspections is the principal
consideration for a practitioner. Baselining is done for different purposes and
can be classified in the three following categories:
1. Quality Control (QC)
2. Quality Assurance (QA)
3. Determination of future in-service corrosion rates by adding condition
monitoring locations (CMLs)
(API 570 Piping Inspection Code definition designates areas on piping systems
where periodic examinations are conducted. API 510 Pressure Vessel
Inspection Code definition designates areas on pressure vessels where periodic
external examinations are conducted in order to directly assess the condition of
the vessel.)
What is necessary and fit for purpose for each of the objectives can vary
significantly. Another factor to consider is when to perform baseline
inspections and depending on the objective, the optimal time will vary. The
scope of baseline inspection activities can include any of the following:
Verification of materials of construction
Visual testing (VT) or inspection to verify installations and evaluate
general equipment condition (e.g., material quality, coatings, insulation,
absence of mechanical or other forms of damage)
Verification of installed wall thickness versus design requirements
Although the definitions of QC and QA are different, the activities are
interrelated and often overlap. Given the context of this article, QC is the
implementation of procedures used to ensure that facilities are constructed to
meet the design specifications. QC typically works best when done early-on
during the construction phase with the intent of correcting problems
proactively and to ensure mistakes are not repeated. QA is a larger part of the
overall quality management system that is applied throughout different project
stages and sometimes on into the operational phase.
This article questions what baseline inspections are needed for determining inservice corrosion rates on upstream equipment. It also assesses when and how
they should be done.
Background and Investigation
The operator’s general baselining practice was to perform wall thickness
measurements on all static mechanical pressure equipment along with visual
inspections prior to placing the equipment in service. The approach was to
perform all these activities as part of an integrated program, (i.e., QC, QA, and
wall thickness measurement for in-service corrosion rate determination) during
the construction to pre-commissioning phases. Several issues arose from this
practice which drove a reevaluation of the approach. One problem was that the
requirements for adding CMLs were more arduous than needed for QC and QA
wall thickness verifications. The result was a delay of construction activities.
Additionally, the qualifications of personnel needed to implement the CML
program exceeded what was necessary for the basic wall thickness verification
work. Both factors were driving cost overruns and affecting optimal resource
allocation.
The investigation pivoted to what was needed for determining in-service
corrosion rates. The primary focus was on ultrasonic testing (UT) and wall
thickness measurement. The objective was to optimize the approach and ensure
a fit for purpose program. The investigation utilized information collected over
many years from the following three data sources:
Damage mechanism reviews (DMRs)
Equipment degradation patterns
Failure analyses
The effort was multidisciplinary and included a broad range of subject matter
experts (SMEs):
Inspection engineers
Corrosion engineers
Materials engineers
Mechanical engineers
Operations and maintenance
Projects
After analyzing the data, it was concluded that, for upstream equipment, no
credible thinning damage mechanism would be defined as general corrosion.
The Association for Materials Protection and Performance (AMPP) describes
“general corrosion" or "uniform corrosion" as proceeding more or less
uniformly over an exposed surface without appreciable localization [7]. The
specific credible damage mechanisms for thinning, of course, vary with specific
service conditions (e.g., deadlegs, high flow areas, production composition,
etc.), but some of the more prevalent upstream damage mechanisms are as
follows:
CO2 corrosion
H2S corrosion
Erosion
Microbiologically influenced corrosion (MIC)
Preferential weld corrosion (PWC)
Oxygen corrosion (often downstream of tank batteries or in some parts of
seawater handling systems)
The reviews confirmed that damage ranged from highly isolated (pitting) to
areas of relatively large wastage. However, it was determined that damage did
not result fully over a component or entire portion of equipment. This included
production piping, facility process piping, pressure vessels, and pipelines. In all
cases, it was determined that undamaged areas on a component (fitting, pipe
joint, shell plate, etc.) were always available to measure wall thickness for
comparative purposes and corrosion rate determination. A few examples of
Upstream equipment damage are illustrated in Figures 1-3.
Figure 1. Radiograph of carbon dioxide (CO2) corrosion on
well site piping. Some areas of deeper isolated damage are
illustrated by the red notations. Photograph courtesy of
Integrity Emission Reduction Partners (IERP) LLC.
Figure 2. Radiograph of erosion-corrosion on piping in
produced water service with entrained solids. Photograph
courtesy of Integrity Emission Reduction Partners (IERP)
LLC.
Figure 3. Gathering line failure caused by to top-of-line
(TOL) corrosion. Although a relatively large area of
corrosion damage was observed there were several locations
on the pipe joint with no damage. These locations were used
to calculate a long-term corrosion rate. Photograph courtesy
of Integrity Emission Reduction Partners (IERP) LLC.
Before deciding to change baselining practices, it was essential to further
analyze the ramifications of a potential change and align the organization. A
critical discipline to get agreement from was corrosion engineering, where it
was a strongly held cultural view, that baselining must always be done.
However, after reviewing data and the collective body of experience across the
organization, it was agreed that a change might be acceptable.
The accuracy of manual UT wall measurement and the potential effects on
corrosion rates were included as part of the investigation. Publications cite that
there are several variables and significant errors or variations in UT wall
thickness measurements [4, 5]. Minimum thicknesses reported in UT
qualification testing showed differences from the “true” thickness of +/- 25.0
mils (0.025 inches) within two standard deviations [4]. Another study
illustrated that depending on the specific instrument and transducer type that
the measurement error at mean thickness varied from +/- 19.0 to 44.0 mils
(0.019 to 0.044 inches) from the true material thickness [5].
The operators’ inspection programs required a threshold value of greater than
or equal to 0.020 inches of change before trusting a real reduction in thickness.
We are aware of one other operator similarly using a threshold value as high as
0.030 inches. It was decided to do a corrosion rate sensitivity analysis on
potential measurement errors of 0.020, 0.030, and 0.040 inches. Table 1
shows the maximum variability in corrosion rates that could result from the
different wall thickness measurement errors.
Table 1. Potential Maximum Deviation in Corrosion Rate Due to Wall
Thickness Measurement Error (mils per year).
Inspection Frequency
(Months)
Measurement Error (Inches)
0.020
0.030
0.040
24
10.0
15.0
20.0
36
6.7
10.0
13.3
48
5.0
7.5
10.0
60
4.0
6.0
8.0
72
3.3
5.0
6.7
(Corrosion rates were calculated and converted to mils per year using the
maximum potential measurement errors for each of the inspection frequencies
listed in the table.)
In every scenario, there is a possibility that the actual corrosion rate could be
zero. The potential errors in corrosion rate for the different scenarios ranged
from 3.3 up to 20 mils per year. The impact of these potential errors on
corrosion control mitigation decisions and recurring inspection frequencies can
be significant. In consideration of most corrosion control programs, corrosion
rates above 2.0 mils per year (mpy) would be considered non-optimal and
typically drive mitigation actions.
The sensitivity analysis demonstrated that there was a considerable amount of
uncertainty in actual corrosion rates even when applying past practices that
included pre-operational baseline inspections. This challenged the paradigm
that reliable and highly accurate corrosion rates were always applied. While
these errors are significant, they are not as high as if a program were to simply
use nominal wall thicknesses for the baseline wall thickness. Nominal pipe wall
thickness varies significantly - commonly up to 12.5%. Specific values depend
upon manufacturing method, size, and material standard [6]. It was concluded
that using nominal wall thickness would not be acceptable for determining
corrosion rates.
Elevated risk or critical piping that could also be subject to high corrosion rates
was a past justification or mandatory driver of baselining. After considering
measurement errors, practicable inspection frequencies, and existing
technologies; subject matter experts agreed that real-time permanently
installed monitoring sensors (PIMS) and mitigation were more appropriate
integrity management tactics in these situations. The overall view was that
reliance on the historical practice was no longer necessary or adequate in these
situations.
Baselining Approach
Following this work, it was concluded that the old paradigm should be shifted
to a default position of no baselining for piping unless there was a valid
technical justification (e.g., using and leaving poor quality hydrotest water in
the equipment). The view was that there would be either no cases or extremely
limited cases that the exception might apply. As previously discussed, if piping
was so critical due to consequence of failure or extremely high corrosion or
erosion rates; the solution would likely be PIMS and not the application of
periodic manual UT.
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It was recommended to stop the approach of performing all the baselining
activities as part of one program. The decision was made to only perform QC
and QA baselining during construction and through pre-commissioning. The
practices were simplified in general along with different personnel
requirements for these activities. The operator put a well-documented and
robust control process in place. They also made a firm decision to rely on this
information and not repeat any such activities afterwards (e.g., in
commissioning or operational life cycle phases). The view was that new
facilities should not be started up unless these activities were reliably done in
the first place.
A summary of the key principles of the innovative approach for baselining are
the following:
Activities for corrosion rate determination would be separated from other
baselining activities for QC and QA purposes.
The default position was that baselining wall thickness measurements
would not be done on any equipment before in-service operation for
corrosion rate determination purposes.
A damage mechanism review and risk assessment would determine if any
exceptions to the default position were necessary.
The frequency and timing for initial inspections would be set based upon
risk-based inspection (RBI) methodology.
Corrosion rates would be calculated after the initial in-service
inspection by comparing wall thickness measurements at CMLs
and undamaged wall on the component.
Results from QC and QA baselining activities (verification of
materials of construction, installation requirements, and
general conditions) performed during construction and precommissioning will be relied upon and not repeated as a
separate baseline activities in the operations life cycle. Note that
baselining is not to be confused with on-going visual inspections /
surveillance done during operational rounds or as part of regular inservice inspection programs. These ongoing activities will continue as part
of the overall in-service integrity programs.)
The investigation did identify activities in current practices done during QC or
QA baselining that should be continued or even expanded. Specifically, some of
the baselining activities done on pressure vessels. As an example, during the
operational phase, the operator was using non-intrusive inspection (NII) to
endorse the integrity of pressure vessels without vessel entry. The NII program
was delivering huge value and reducing health, safety, and environmental
(HSE) risk. Information from the pre-service baselines on pressure vessels was
an important enabler of the NII program.
Challenges with implementing NII programs can arise when damage is present
on vessel components from fabrication or construction. Internal surface
anomalies or irregularities on vessel shell plates and head components caused
by grinding or formation (e.g., rolling or forging) can be misidentified as inservice deterioration. Misinterpretation of these anomalies as in-service
damage can drive unnecessary inspections and other spurious activities. Having
a good understanding of the pre-service internal surface condition of the
components is essential for optimizing the NII program.
The standard approach for pre-service baseline inspection of pressure vessels
included the following:
Visual inspection and photographic documentation of the internal shell
surface conditions, other internal equipment, and coating if applicable.
Spot wall thickness measurements at select locations on shell plates and
heads.
The visual inspections and photographic documentation from pre-service
baselining was viewed as value adding and an enabler of NII. The collection of
spot UT wall thickness data was not. It was considered whether there would be
a benefit of applying automated UT for wall thickness mapping over large
surface areas to expand baselining data collection. It was decided that there
were better and lower cost alternatives.
The optimal baselining practice to support the NII program was determined to
be the following:
Continue the internal visual inspections and photographic documentation
of internal surface conditions and other internals.
Adding 3D laser scanning of internal surface anomalies that are identified
by visual inspections.
Specific criteria regarding surface anomaly patterns and depth thresholds were
included in the operator’s new baselining practice to determine when to apply
the 3D laser scanning.
Benefits
Several benefits have come out of the operator’s modification of their practices.
Separation of the programs has clarified roles and responsibilities. It has
allowed a focus on specific program objectives with better allocation of
resources. For example, after eliminating the corrosion rate determination
baselining activities on major projects, reducing redundancies, and aligning
competency requirements with job tasks, costs were reduced by over 50%.
The technical subject matter experts (SMEs) agreed that the clarifications and
additions made to pre-service baseline requirements for pressure vessels would
deliver value. Specifically, by reducing uncertainty from vessel inspection
results as part of the in-service NII program. Data from the enhanced
baselining practices will help eliminate the need for supplemental inspections
and spurious mitigation actions.
Potential Challenges and Limitations
Given that pre-service UT baselines will not be done, corrosion rates will be
calculated using wall thickness comparisons between measurements at a CML
and a different location on a component. All measurements will be taken at the
time of first in-service inspection. There are factors that must be considered
when selecting the comparative locations. Production conditions, component
type, manufacturing method, damage mechanism, and damage morphology
must all be considered.
In most cases, it is optimal to select undamaged wall adjacent to the CML as the
comparative location. Ideally the closer the comparative location to the CML,
the less likely there will be any variation in wall thickness from manufacturing
processes. However, depending upon specific CML patterns and damage
mechanisms, there is a possibility that damage might extend beyond the CML.
This could result in an error that underestimates corrosion rates.
Upstream inspection programs sometimes use radiographic testing (RT) on
piping for screening using the double wall single image (DWSI) technique
(Figure 4). This is done to detect damage, identify corrosion patterns, and the
extent of damage. The RT is followed up by UT for quantitative wall thickness
determinations. Typically, the RT inspections cover the entire CML pattern
designated for UT measurement and extend well beyond it. This procedure can
be used to ensure an appropriate comparative location with undamaged wall is
selected. Another way to provide assurance is to require UT scanning patterns
that extend beyond the CML to find undamaged areas.
Figure 4. Illustration of Double Wall Single Image (DWSI)
RT technique with Iridium 192 source and digital detector
array.
Given situations where components are not expected to have significant wall
thickness variations due to manufacturing methods (e.g., rolled pipe) and
depending upon damage mechanisms and production conditions, it may be
preferred to select comparative locations that are not close to CMLs. An
example of this would be a situation where corrosion is only credible at water
wet locations and not in the gas phase. In this case, the comparative readings
for the first corrosion rate calculation could be selected on a component in the
gas phase.
It should be noted that the practice of using the comparative location is only
used for the first corrosion rate determination. Subsequently, all corrosion
rate calculations will be made as in conventional programs by comparing
previous readings at a CML.
Conclusion
After completion of a review of the approach and long-held paradigms
regarding baseline inspection practices for upstream equipment, a decision was
made to make some significant changes.
The operator’s prior practice was to combine baselining activities with multiple
objectives all into one program done during construction and precommissioning. Several problems resulted such as redundancy, misalignment of
needs and personnel competency requirements, project delays, and excessive
costs. In order to improve overall effectiveness and reduce costs, a decision was
made to segment programs by only performing baselining activities needed to
support quality control and quality assurance objectives prior to operations. It
was also decided to trust, rely on, and not repeat these activities in the
operation’s life cycle.
A review of UT wall thickness measurement errors and the expected accuracy of
subsequent corrosion rate calculations showed potential variability in
predicated corrosion rates. This exposed gaps in past assumptions about the
effectiveness of conventional practices. It made clear that the risks associated
with change might be tolerable or within current limits. Furthermore, after
considering measurement errors, practicable inspection frequencies, and
existing technologies, it was decided that real-time permanently installed
monitoring sensors (PIMS) and mitigation were more appropriate integrity
management tactics in situations requiring highly accurate corrosion rates.
As part of the in-service integrity management program, significant changes
were made to baselining practices associated with how and when to take wall
thickness measurements for the purpose of corrosion rate determinations. One
substantial change in baselining inspection practices was the elimination of preservice UT wall thickness measurements for production and facility piping. This
conclusion was enabled by analysis of damage mechanism reviews (DMRs) and
operating experience with equipment degradation patterns. The findings
demonstrated that upstream damage mechanisms are not general and that
comparative locations on a component could be selected for corrosion rate
determination. Moreover, wall thickness measurements at CMLs and
comparative locations could be done at the same time during the first in-service
inspection interval. It should be noted that several considerations were
identified with the selection of comparative locations.
The operator made changes to the pre-service baselining activities for pressure
vessels. This was done to enhance the NII programs. Optimal baselining was
determined to continue with internal visual inspections and photographic
documentation of internal surface conditions and internals with the addition of
3D laser scanning of some internal surface anomalies. Specific criteria
regarding surface anomaly patterns and depth variation thresholds were
included in the operator’s new baselining practice. The operator decided to
discontinue wall thickness measurements during the construction phase unless
information was provided to change this.
Although modifications to baselining practices were predicated on a solid
foundation of experience and analysis, they do incorporate major changes and
so these programs are carefully monitored.
References
1. Anwer, A., 2018, “The Importance of Baseline Inspections,”
Inspectioneering Journal, 24(5), pp. 46-47.
2. API 510, 2014, “Pressure Vessel Inspection Code: In-Service Inspection,
Rating, Repair, and Alteration,” Tenth Edition, American Petroleum
Institute.
3. API 570, 2016, “Piping Inspection Code: In-Service Inspection, Rating,
Repair, and Alteration of Piping Systems,” Fourth Edition, American
Petroleum Institute.
4. Weire, D.R., Pardini, A.F., 2007, “Evaluation of UT Wall Thickness
Measurements and Measurement Methodology,” Prepared for U.S.
Department of Energy.
5. Lebowitz, C. A., Brown, L. M., 1993, “Ultrasonic Measurement of Pipe
Thickness,” Review of Progress in Quantitative Nondestructive Evaluation,
Vol. 12, Plenum Press, New York.
6. API RP 574, 2016, “Inspection Practices for Piping System Components,”
Fourth Edition, American Petroleum Institute.
7. AMPP, “What is Corrosion?” Association for Materials Protection and
Performance, https://www.ampp.org/resources/what-is-corrosion
Did you find this article helpful?
About the Authors
George C. Williamson, VP of Integrity, Risk Management & Litigation
Support at Integrity & Emission Reduction Partners, LLC
George Williamson, P.E. is VP of Integrity, Risk Management & Litigation Support at Integrity
Emission Reduction Partners (IERP), LLC in Houston, Texas. George has over 30 years of integrity
management, operations, and maintenance experience as a major asset owner with ARCO and BP.
His roles have included managing global oil and gas production facilities, pipelines, and subsea
systems in... Read more »
Dr. Bill Hedges, Independent Consultant
Bill is an independent consultant with over 35 years experience in integrity management in the oil
and gas industry working for international oil companies. He has led large integrity teams in
operational assets as well as central engineering teams. His specialist area is developing risk-based
corrosion management programs and troubleshooting operational integrity problems. ... Read more
»
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