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Corrosion/Erosion Management Strategy in the North Slope: Use of Corrosion Rate as Key Performance Indicator (KPI)

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Corrosion/erosion management for an operation is the systematic application of policies, practices, and resources to control corrosion/erosion and provide reliable safeguards against unexpected failures and leaks that can jeopardize mechanical integrity, operation, health, safety and environment (HSE). This paper highlights the use of a single key performance indicator in tracking monitoring strategy, mitigation strategy, and pipeline integrity for aboveground pipelines in the North Slope. The approach enables the integration of corrosion/erosion control, process monitoring, inspection, mitigation, environmental control, and materials management into a comprehensive management strategy. In this instance, external corrosion and stress corrosion cracking are effectively controlled; consequently, internal corrosion becomes the sole time-dependent failure type. Internal corrosion rate, like any KPI, enables the organization to operate with greater efficiency, reliability and control. The approach underscores a strategy that ensures that the facility remains fit for purpose during its design life. It satisfies the need to proactively control corrosion from growing to a size that could affect the structural integrity of components so that the facility remains sound and capable of safely performing the tasks for which it was designed and is compliant with the applicable regulations and standards governing design, operation, and maintenance.
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Corrosion/Erosion Management Strategy in the North Slope:
Use of Corrosion Rate as Key Performance Indicator (KPI)
Olagoke Olabisi, PhD
NACE Chemical Treatment Specialist
Director, Internal Corrosion Engineering
Corrpro Companies, Inc.
7000 Hollister (Building B)
Houston, Texas 77040
oolabisi@corrpro.com;
ABSTRACT
Corrosion/erosion management for an operation is the systematic application of policies,
practices, and resources to control corrosion/erosion and provide reliable safeguards against
unexpected failures and leaks that can jeopardize mechanical integrity, operation, health,
safety and environment (HSE). This paper highlights the use of a single key performance
indicator in tracking monitoring strategy, mitigation strategy, and pipeline integrity for
aboveground pipelines in the North Slope. The approach enables the integration of
corrosion/erosion control, process monitoring, inspection, mitigation, environmental control,
and materials management into a comprehensive management strategy. In this instance,
external corrosion and stress corrosion cracking are effectively controlled; consequently,
internal corrosion becomes the sole time-dependent failure type. Internal corrosion rate, like
any KPI, enables the organization to operate with greater efficiency, reliability and control. The
approach underscores a strategy that ensures that the facility remains fit for purpose during its
design life. It satisfies the need to proactively control corrosion from growing to a size that
could affect the structural integrity of components so that the facility remains sound and
capable of safely performing the tasks for which it was designed and is compliant with the
applicable regulations and standards governing design, operation, and maintenance.
Key words: Key Performance Indicator (KPI), Corrosion/Erosion Control Metrics, Aboveground
Pipelines, Pipeline Integrity, North Slope.
©2012 by NACE International. Requests for permission to publish this manuscript in any form, in part or in whole, must be in writing to NACE International,
Publications Division, 1440 South Creek Drive, Houston, Texas 77084. The material presented and the views expressed in this paper are solely those of the
author(s) and are not necessarily endorsed by the Association.
C2012-0001180
INTRODUCTION
Inspection and monitoring are the two key processes by which the onset of internal corrosion,
external corrosion and stress corrosion cracking can be detected. If external corrosion and
stress corrosion cracking are effectively controlled, internal corrosion monitoring, whether
through electronic probes or coupons, is able to detect corrosion significantly quicker than
inspection techniques. This “early detection” of the onset of corrosion enables a quick
response to the changing operational environment, and, when appropriate, an increase in the
quantity of treatment chemicals applied to the process fluids, thereby enhancing protection.
Thus, internal corrosion monitoring helps to minimize the extent of damage to the base
materials, and maintain the structural integrity of the production systems. That is, early
detection assists risk-criticality assessment, helps ensure reliability of production and enables
the avoidance of losses from equipment replacement and operational disruptions.
A key performance indicator (KPI) is a key corrosion/erosion control metric that can be used to
measure the efficiency of the prevailing corrosion/erosion risk management strategy, namely,
the integration of corrosion, erosion, process monitoring, inspection, mitigation, environmental
control, and materials management. KPI is a primary tool that can be used to proactively
control corrosion/erosion from growing to a size that could affect the structural integrity of
components so that the system remains sound and capable of safely performing the tasks for
which it was designed and is compliant with applicable regulations and standards governing
design, operation, and maintenance. KPI provides a reliable alert system against unexpected
failures and leaks, which could jeopardize mechanical integrity, operation, health, safety and
environment (HSE).
CORROSION IN PRODUCING OPERATIONS IN THE NORTH SLOPE
The preeminent parameter in the North Slope is the harsh arctic environment. All materials
corrode at ambient temperatures. The degree of corrosion on a structure is directly related to
the environment that the structure is located in. Higher temperatures usually result in higher
corrosion rates; lower temperatures result in lower corrosion rates. In the case of extremely
cold temperatures, the corrosion rate slows considerably. Therefore, structures that are
exposed to extremely low temperatures, as in the arctic environment of the North Slope, are
exposed to an essentially noncorrosive environment. In the summer, however, the situation is
different even in the arctic. The different types of corrosion that can occur on facility structures
in the summer include: corrosion under wet insulation particularly at the weld packs of above
ground pipelines, underground external corrosion, sub-merged external corrosion, and internal
corrosion.
A significant percentage of pipelines in the North Slope are held above ground with specially
designed vertical support members (VSM) embedded in the ground to support the
aboveground pipe in areas of thaw-unstable permafrost. In areas where heat might cause
undesirable thawing of the permafrost, the supports contain heat pipes to remove heat and
keep the ground frozen. Heat pipes contain anhydrous ammonia, which vaporizes
belowground, rises and condenses aboveground, removing ground heat whenever the air
temperature is 5°F to 10°F (2.78°C to 5.56°C) cooler than the ground temperature at the base
of the heat pipe. Heat is transferred through the walls of the heat pipes to aluminum radiators
on top of the pipes.
©2012 by NACE International. Requests for permission to publish this manuscript in any form, in part or in whole, must be in writing to NACE International,
Publications Division, 1440 South Creek Drive, Houston, Texas 77084. The material presented and the views expressed in this paper are solely those of the
author(s) and are not necessarily endorsed by the Association.
For aboveground pipelines, if external corrosion and stress corrosion cracking are effectively
controlled, internal corrosion becomes the preeminent time-dependent failure type1 in
determining the overall integrity of aboveground pipelines. Factors affecting internal
corrosion/erosion include a variety of variables, namely: presence of multiphase flow, presence
of particles and/or sand, water cut, high total pressure resulting in high H2S and CO2 partial
pressures, condensation of water resulting in un-buffered electrolyte pH, conductivity,
presence of mineral acid, elemental sulfur, brine chemistry, oxygen concentration, microbes,
flow velocity, etc. In certain formations in the North Slope, sand production with the produced
fluids can be as much as 2% by volume and water production could be greater than 50%.
Consequently, internal corrosion and sand erosion usually go hand in hand. Controlling
internal corrosion/erosion entails monitoring in combination with appropriate and timely
mitigation. The typical internal corrosion/erosion management documentation includes:
Sand management strategy,
Corrosion management Manual
Hydrotest and preservation procedures
Chemical management strategy
Risk management strategy
Corrosion monitoring strategy
Inspection procedures
The corrosion/erosion control implementation normally commences from the beginning of
operation with subsequent feedback of operational data into the company integrity
management system. Great implementation requires the correct execution of monitoring,
inspection, and mitigation strategies to ensure that the facility remains fit for purpose.
Examples of vital activities include corrosion rate monitoring, process monitoring, inspection,
data collection, analyses, reporting and corrective action. In addition, KPIs are used to track
the efficiency of the prevailing corrosion/erosion risk management strategy, namely, the
integration of corrosion, erosion, process monitoring, inspection, mitigation, environmental
control, and materials management.
CORROSION/EROSION CONTROL METRICS
Corrosion/erosion risk management for an operation is the systematic application of policies,
practices, and resources to control risk and provide reliable safeguards against unexpected
failures and leaks, occasioned by corrosion/erosion, which can jeopardize mechanical integrity,
operation, health, safety and environment (HSE). A corrosion/erosion control metric is a
performance measure that can be used to assess the efficiency of the prevailing
corrosion/erosion risk management strategy. A selected list of corrosion/erosion control
metrics is presented in Table 1
Corrosion Rate as Corrosion Control Metric.
According to NACE RP0775-20052, corrosion severity classification is in terms of corrosion
rates as illustrated in Table 2. Based on NACE classification, a letter grade system was
developed as a tool for summarizing corrosion coupon results. Table 3 illustrates the letter
©2012 by NACE International. Requests for permission to publish this manuscript in any form, in part or in whole, must be in writing to NACE International,
Publications Division, 1440 South Creek Drive, Houston, Texas 77084. The material presented and the views expressed in this paper are solely those of the
author(s) and are not necessarily endorsed by the Association.
grade system, for both general corrosion and pitting corrosion, used by several major oil
companies to categorize corrosion rates. Table 1
A Selected List of Corrosion/Erosion Control Metrics
Metric Description Review
Frequency
System Measures
Total number of spills Quarterly
Number of spills by cause Quarterly
Total Number of leaks Quarterly
Total number of defects found before they become leaks Quarterly
Number of leaks by cause Quarterly
Leak awareness training/improvement sessions Annually
Coupon and Probe Corrosion/Erosion Rates
Total number of locations with Grade “A” corrosion/erosion rate Quarterly
Total number of locations with Grade “B” corrosion/erosion rate Quarterly
Total number of locations with Grade “C” corrosion/erosion rate Quarterly
Total number of locations with Grade “D” corrosion/erosion rate Quarterly
Total number of locations with Grade “F” corrosion/erosion rate Quarterly
Fluid Sampling and Cleaning Pigging
Mileage of maintenance cleaning pigging Quarterly
Frequency of fluid for microbial analysis Quarterly
Frequency of fluid sampling for corrosion products (dissolved or
suspended) Quarterly
Frequency of fluid sampling for corrosion solids Quarterly
Internal/External Corrosion Inspection
Percent of thickness measurement locations (TMLs) inspected Quarterly
Frequency of isolation flange inspections Quarterly
Frequency of cathodic protection survey Annually
Percent of weld packs inspected Quarterly
Recur frequency for corrosion under insulation Quarterly
Chemical Optimization Activities (Mitigation)
Inventory and upgrade of monitoring devices Quarterly
Inventory and upgrade of treatment chemical Quarterly
Adjustment frequency of treatment chemicals Quarterly
Verification & validation of treatment chemicals performance (treatment
results) Quarterly
Qualification & validation of promising new treatment chemicals Quarterly
Repair or Replacement
Average repair indications per mile Annually
Average replacements indications per mile Annually
Number of repairs by cause Annually
Number of replacements by cause Annually
Leak/Repair ratio Quarterly
©2012 by NACE International. Requests for permission to publish this manuscript in any form, in part or in whole, must be in writing to NACE International,
Publications Division, 1440 South Creek Drive, Houston, Texas 77084. The material presented and the views expressed in this paper are solely those of the
author(s) and are not necessarily endorsed by the Association.
Corrosion is ranked as A, B, C, D, and F based on the mils per year (mpy) or mm/y: “A”
corresponding to lowest wall loss, “F” corresponding to maximum permissible wall loss. The
letter grade system is widely used as the management tool for reporting and summarizing
corrosion results. The system makes it easier for engineers and management to focus
attention on problem areas. Corrosion severity therefore constitutes an authentic corrosion
control metric; the concept is equally applicable to erosion or erosion-corrosion.
Table 2
Classification of General and Pitting Corrosion Rates2, (1 mpy = 0.0254 mm/y)
General Corrosion Pitting Corrosion
Low < 1.0 mpy Low < 5.0 mpy
Moderate 1.0 – 4.9 mpy Moderate 5.0 – 7.9 mpy
High 5 – 10 mpy High 8 – 15 mpy
Severe > 10 mpy Severe > 15 mpy
Table 3
Coupons: A Letter Grade System (1 mpy = 0.0254 mm/y)
In the evaluation of individual coupon, general corrosion rate and pitting corrosion rate are
determined and recorded along with the corresponding letter grades. A coupon could receive
an “A” for general corrosion, but a “D” for a deep, but narrow pit (with minimal mass loss). The
overall rating of any individual coupon corresponds to the worse (lower) of the two grades for
general and pitting corrosion rate.
Sand Probe as Erosion Control Metric.
Sand detection probe (SP) is used for short-term erosion trending. Sand monitoring (SM)
devices (externally strapped-on), are used for on-line monitoring of pipe-wall loss due to
erosion. For pipeline containing sand, the sand monitoring probes may be located at the 9
o’clock, 3 o’clock, or 12 o’clock positions because of the tendency of sand to plug the
monitoring system if placed at the 6 o’clock. Longer holders are used to place the probes in the
desired flow area. This assumes that flow intensity does not destroy or bend the whole
assembly away from the desired flow area. For the worst case scenario, sand probes are
located at the inlet to, and outlet from, de-sanding hydrocyclone, as well as the inlet to, and
outlet from, de-oiling hydrocyclone. A clamp-on sonic sand detector may be installed on the
Grade General Corrosion (mpy) Pitting Corrosion (mpy)
A 0.0 –< 1.0 0 –< 2
B 1.0 –< 2.0 2 –< 5
C 2.0 –< 5.0 5 –< 10
D 5.0 –< 10.0 10 –< 25
F > 10.0 > 25
©2012 by NACE International. Requests for permission to publish this manuscript in any form, in part or in whole, must be in writing to NACE International,
Publications Division, 1440 South Creek Drive, Houston, Texas 77084. The material presented and the views expressed in this paper are solely those of the
author(s) and are not necessarily endorsed by the Association.
overflow line to the de-oiling hydrocyclones to alert operators about sand carryover with the
overflow.
Treatment Chemical Residual as Corrosion Control Metric.
Treatment chemical content is the concentration, in parts per million (ppm), of residual
treatment chemical. Residuals analyses are the measurement and quantification of the
concentration of a treatment chemical within the process fluids. The primary reason for
measuring the residual concentration in a water sample is:
To ensure that the treatment chemical partitions to the water phase (and not the
hydrocarbon phase) and
To ensure that the treatment chemical reaches the end of a pipeline system and
did not simply accumulate upstream
For example, if 100 parts per million of corrosion inhibitor is injected into a pipeline, fluid
samples collected at the far end of the pipeline should be analyzed to determine whether the
product had been totally consumed or not. This would provide one measure of the
effectiveness of such treatment program.
Residuals analyses, whether the measurement of scale inhibitor residuals, de-foamer
residuals, de-emulsifier residuals, corrosion inhibitor residuals, etc., provide the corrosion
engineer with useful information and trends, which might identify potential corrosion problems.
Nonetheless, the results should only be interpreted in conjunction with results from other
corrosion monitoring techniques.
Electrolyte Content as Corrosion Control Metric.
The presence of electrolytes at any location in the system may be an indication of potential
corrosion problems in the area. Because of their corrosive effects, electrolyte concentrations
represent authentic corrosion control metrics. Consider, for example, a system, which has
been experiencing increased corrosion over a period of time. If the trend of increasing
corrosion rate versus time (see, for example, Figure 1) is compared to a plot of all electrolytes
present over that same period of time, it may be possible to ascribe the source of increased
corrosion to some electrolytes. Such electrolytes could be water, dissolved oxygen, dissolved
carbon dioxide, dissolved hydrogen sulfide, chloride anions, pH, iron cation, manganese
cation, dissolved anionic divalent compound such as sulfate, total dissolved bicarbonates,
organic acids, etc.
CORROSION/EROSION KEY PERFORMANCE INDICATORS (KPIs)
A corrosion/erosion KPI is a key metric that can be used to measure the efficiency of the
prevailing corrosion/erosion risk management3 strategy, namely, the integration of corrosion,
erosion, process monitoring, inspection, mitigation, environmental control, and materials
management. The KPI is a primary tool that can be used to proactively control
corrosion/erosion from growing to a size that could affect the structural integrity of components
so that the system remains sound and capable of safely performing the tasks for which it was
designed and is compliant with applicable regulations and standards governing design,
operation, and maintenance. That is, the KPI provides a reliable alert system against
©2012 by NACE International. Requests for permission to publish this manuscript in any form, in part or in whole, must be in writing to NACE International,
Publications Division, 1440 South Creek Drive, Houston, Texas 77084. The material presented and the views expressed in this paper are solely those of the
author(s) and are not necessarily endorsed by the Association.
unexpected failures and leaks, occasioned by corrosion/erosion, which could jeopardize
mechanical integrity, operation, health, safety and environment (HSE).
There are several corrosion/erosion matrices. To qualify as a KPI, a metric need to be able to
play a significant role in focusing attention on the corrosion/erosion trends in the operating
system, enabling decision-making and the necessary planning for targeting the required
corrosion/erosion mitigating measures. This enables the organization to operate with greater
efficiency, reliability and control of production and avoidance of losses from equipment
replacement and operational disruptions.
Table 4 depicts five KPIs as well as the corresponding compliance target normally used in
North Slope operations. In what follows, a situation is presented in which the use of corrosion
rate, measured with corrosion coupons, constitutes the primary KPI for a producing operation.
This lone KPI is used in tracking monitoring strategy, mitigation strategy, and pipeline integrity.
It is an example that underscores a typical corrosion management strategy that enables the
facility to remain fit for purpose during its design life
Table 4
Corrosion/Erosion Key Performance Indicators (KPI)
Performance measure System Compliance target value
1 Corrosion coupons/ER Probes for
general corrosion All locations of
probes/coupons 2 mpy (0.0508 mm/y)
2 Corrosion coupons for pitting
corrosion All locations of
coupons 5 mpy (0.127 mm/y)
3 Sand Probes/erosion coupons All locations of
probes/coupons 5 mpy (0.127 mm/y)
4 Cumulative thickness loss pipelines Corrosion allowance
5 Treatment chemical residual Pipelines Manufacturer’s
recommendation
FIELD DATA
Presented here are the actual field data, from the North Slope, that are analyzed using a single
KPI namely, corrosion rate rates measured with weight loss corrosion coupons. The weight
loss corrosion coupons were installed inside six pipelines and periodic corrosion
measurements were recorded for 616 days. The field data was used to calculate corrosion
rates for the six pipelines. Table 5 presents the calculated data and Figure 1 illustrates the
corrosion rate as a function of time overlaid with the target compliance level.
When interpreted in terms of the corrosion severity classification given in Table 2 as well as
the letter grades depicted in Table 3, the data suggest that pipelines 1, 2, 4, and 5 are in the
Grade “A” category throughout the period of corrosion rates measurements. On the other
©2012 by NACE International. Requests for permission to publish this manuscript in any form, in part or in whole, must be in writing to NACE International,
Publications Division, 1440 South Creek Drive, Houston, Texas 77084. The material presented and the views expressed in this paper are solely those of the
author(s) and are not necessarily endorsed by the Association.
hand, pipelines 3, and 6 fall in the Grade “A”, “C”, “D” and “F” categories during the period of
corrosion rates measurements.)
Table 5
Corrosion Rate (CR in mpy) of Pipelines as a Function of Time (1 mpy = 0.0254 mm/y)
Time
(Days) CR for P/L
#1 CR for P/L
#2 CR for P/L
#3 CR for P/L
#4 CR for P/L
#5 CR for P/L
#6
142 0.03 0.01 0.16 0.02 0.02 9.45
246 0.12 0.08 3.07 0.05 0.11 5.68
333 0.22 0.06 8.44 0.04 0.09 5.14
443 0.06 0.05 34.13 0.02 0.07 5.76
504 0.04 0.03 22.57 0.02 0.02 22.64
616 0.03 0.13 73.51 0.00 0.05 6.27
SELECTION OF CORROSION RATE AS A KPI
If external corrosion and stress corrosion cracking are effectively controlled for aboveground
pipelines, internal corrosion becomes the preeminent time-dependent failure type1 in
determining the overall pipeline integrity. On account of such crucial role, internal corrosion
rate is chosen as the single most important parameter and used as the key performance
indicator. This selection is hinged on the following key assumptions:
Coupon corrosion is a viable surrogate for pipeline internal corrosion.
Internal corrosion information obtained from corrosion coupons is representative of the
entire pipeline internal environment
For the aboveground pipelines under consideration, external corrosion and stress
corrosion cracking are effectively controlled and internal corrosion is the preeminent
time-dependent failure type1 in determining the overall pipeline integrity
It should be understood, however, that in rating pipeline conditions based on coupon results,
the information obtained from corrosion coupons are site-specific and may not be
representative of the entire pipeline environment. Given the above considerations, internal
corrosion rate was selected as the lone KPI for tracking monitoring strategy, mitigation
strategy, and pipeline integrity.
USE OF SELECTED KPI TO TRACK INTERNAL CORROSION TREND
Internal corrosion of a pipeline is critical and must be tracked by any operating company.
Figure 1 presents the plots of internal corrosion rate as a function of time for all six pipelines
whose data are presented in Table 5. The plots are overlaid with the target corrosion rate
compliance level of 2.0 mpy (0.0508 mm/y) (0.0508 mm/y). The series of graphs illustrate that
pipelines #1, #2, #4 and #5 are in compliance with the company target of 2.0 mpy (0.0508
mm/y) throughout the 616 days of the coupon insertion. On the other hand, pipelines #3 and
#6 are not in compliance with the company target level of 2.0 mpy (0.0508 mm/y).
©2012 by NACE International. Requests for permission to publish this manuscript in any form, in part or in whole, must be in writing to NACE International,
Publications Division, 1440 South Creek Drive, Houston, Texas 77084. The material presented and the views expressed in this paper are solely those of the
author(s) and are not necessarily endorsed by the Association.
USE OF SELECTED KPI TO DRIVE CHANGES IN CHEMICAL TREATMENT
Table 6 illustrates the methodology for using the selected KPI to “drive” changes in mitigation
action in terms of the company chemical treatment program.
Figure 1: Internal Corrosion Rate as a Function of Time overlaid with Compliance Level
Table 6
Increment in Chemical Treatment Level as Driven By KPI Target Rate of Corrosion
Chemical Treatment Coupon Results Chemical Treatment Serial
No. If current treatment
level, in ppm, is Coupon CR compared with
KPI target rate Then, increase chemical
treatment level to
1 25 If CR> 2.0 mpy (0.0508 mm/y) Increase to 50 ppm
2 50 If CR> 2.0 mpy (0.0508 mm/y) Increase to 75 ppm
3 75 If CR> 2.0 mpy (0.0508 mm/y) Increase to 100 ppm
4 100 If CR> 2.0 mpy (0.0508 mm/y) Increase to 125 ppm(1)
5 125 If CR> 2.0 mpy (0.0508 mm/y) Increase to 150 ppm(1)
6 150 If CR> 2.0 mpy (0.0508 mm/y) Increase to 175 ppm(1)
(1) The treatment chemical is not effective and may be replaced
©2012 by NACE International. Requests for permission to publish this manuscript in any form, in part or in whole, must be in writing to NACE International,
Publications Division, 1440 South Creek Drive, Houston, Texas 77084. The material presented and the views expressed in this paper are solely those of the
author(s) and are not necessarily endorsed by the Association.
This approach calls for a periodic (at least quarterly) review of KPI. If target corrosion level of
2.0 mpy (0.0508 mm/y) is exceeded, the review provides a mandate for the corrosion engineer
to appropriately modify the inhibition treatment in accordance with the indicated increment in
chemical treatment level presented on Table 6. Corrosion inhibitor level may be maintained
above recommended concentration but the inhibitor dosage should always be increased when
the corrosion rate indicates that any situation is outside the operating KPI target envelop.
USE OF SELECTED KPI TO TRACK REMAINING LIFE
For aboveground pipelines, if external corrosion and stress corrosion cracking are effectively
controlled, internal corrosion becomes the preeminent time-dependent failure type1. The
remaining life of a pipeline, occasioned by internal corrosion, is critical and must be tracked by
any operating company. By definition, the remaining life is the time it takes for the most severe
remaining corrosion anomaly to grow to leakage or failure. If no corrosion defects are found,
the remaining life can be taken as the same as for a new pipeline, namely, the design life. If
corrosion defects are found, the maximum remaining flaw size can be taken as the same as
the most severe indication. The growth rate used for calculating remaining life should be based
on the actual corrosion rate data applicable for the particular pipeline.
For a company in operation for about 5 years (1,825 days) whose pipeline design life is 20
years, the remaining life of its pipeline can be taken as 20 years if no corrosion defects are
found. For the six pipelines for which corrosion rate data are available, the remaining life
projections, presented in Table 7, are estimated based on the cumulative thickness loss of a
series of corrosion coupons placed at specific locations for the cumulative duration of 616
days.
In what follows, it should be noted that all calculations are based only on the overall weight
loss of the corrosion coupons that is primarily due to general corrosion. The corrosion pit
density, pit type, maximum pit diameter and depth were not determined. Consequently, the
pitting corrosion rates or severity could not be assessed.
Using pipeline #6 as an example, its cumulative thickness loss is 0.0140 inches (0.3556 mm)
for the cumulative duration of 616 days exposure. Assuming that the corrosion rates are
approximately the same for 5 years, the corrosion coupon thickness loss is estimated as:
Corrosion coupon thickness loss for 5 years (1,825 days) = (0.0140)*(1,825)/620 = 0.0412 inch
(1.04648 mm).
However, two sides of the corrosion coupon are exposed to the fluid inside the pipeline. For a
pipeline, only one surface, the inner surface of the pipeline, is exposed to the fluid. Hence, the
projected loss from the pipeline would be half of the coupon, which is 0.0206 inch:
Projected pipeline thickness loss for 5 years (1,825 days) = 0.0412/2 inch = 0.0206 inch
(0.52324 mm).
This value is less than the corrosion allowance, which is 0.0625 inch (1.5875 mm)
©2012 by NACE International. Requests for permission to publish this manuscript in any form, in part or in whole, must be in writing to NACE International,
Publications Division, 1440 South Creek Drive, Houston, Texas 77084. The material presented and the views expressed in this paper are solely those of the
author(s) and are not necessarily endorsed by the Association.
The nominal wall thickness of the pipeline is 0.237 inch (6.0198 mm; hence, the wall thickness
after 5 years is approximately equal to (0.237-0.0206) inch = 0.2164 inch (5.49656 mm)
That is, the projected pipeline thickness wall thickness after 5 years (1,825 days) is 0.2164
inch (5.49656 mm)
If, in the pipeline environment of reference, the design life for a pipe with a nominal wall
thickness of 0.237 inch (6.0198 mm) is 20 years, then the remaining life of the pipeline after 5
years of operation is estimated as follows:
Projected remaining life of the pipeline after 5 years (1,825 days) = (0.2164/0.237)*20 years
= (18.26 years).
The projected remaining life for the six pipelines is summarized on Table 7. It should be noted
that none of the pipelines exceeded its corrosion allowance. However, immediate and
aggressive action was initiated to control the corrosive environment of pipelines 3, and 6 to
preempt possible leakage at a future time.
Table 7
Projected Remaining Life of Pipelines
Projected Remaining Life Based on Cumulative Thickness Loss of Corrosion Coupons
Pipeline Nominal
Thickness Corrosion
Allowance Cumulative
Coupon
thickness
Loss
Estimated
pipeline
thickness Loss
in 5 years
Projected
Remaining Life
(years)
1 0.594 inch
(15.09 mm) 0.125 inch
(3.18 mm) 0.0001 inch
(0.0025 mm) 0.00015 inch
(0.00381 mm) 19.99
2 0.337 inch
(8.56 mm) 0.125 inch
(3.18 mm) 0.0001 inch
(0.0025 mm) 0.00015 inch
(0.00381 mm) 19.99
3 0.50 inch
(12.7 mm) 0.125 inch
(3.18 mm) 0.0396 inch
(1.0058 mm) 0.05865 inch
(1.48971 mm) 17.65
4 0.562 inch
(14.275 mm) 0.050 inch
(1.27 mm) 0.00 inch
(0.00 mm) 0.00 inch
(0.00 mm) 20.00
5 0.322 inch
(8.179 mm) 0.0625 inch
(1.5875 mm) 0.0001 inch
(0.0025 mm) 0.00015 inch
(0.00381 mm) 19.99
6 0.237 inch
(6.02 mm) 0.0625 inch
(1.5875 mm) 0.014 inch
(0.3556 mm) 0.0206 inch
(0.52324 mm) 18.26
©2012 by NACE International. Requests for permission to publish this manuscript in any form, in part or in whole, must be in writing to NACE International,
Publications Division, 1440 South Creek Drive, Houston, Texas 77084. The material presented and the views expressed in this paper are solely those of the
author(s) and are not necessarily endorsed by the Association.
CONCLUSION
This paper demonstrates the many attributes of internal corrosion rate, measured with weight
loss coupon, as a key performance indicator for aboveground pipelines, where external
corrosion and stress corrosion cracking are effectively controlled:
Internal corrosion rate is the key corrosion control metric that could proactively control
corrosion from growing to a size that could affect the structural integrity of pipelines
It can be used to track the remaining life of a pipeline
It can be used to “drive” changes in mitigation action
It provides a measure of efficiency of the prevailing corrosion risk management
strategy
It enables the integration of corrosion, erosion, process monitoring, inspection,
mitigation, environmental control, and materials management
It provides a reliable alert system against unexpected failures and leaks, that could be
occasioned by corrosion/erosion, which could jeopardize mechanical integrity,
operation, health, safety and environment (HSE)
ACKNOWLEDGEMENT
This paper is based on an on-going project, the support of which is hereby acknowledged.
REFERENCES
1. Managing System Integrity of Gas Pipelines, ASME B31.8S-2004.
2. Preparation, Installation, Analysis, and Interpretation of Corrosion Coupons in Oilfield
Operations, NACE International, NACE RP0775-2005.
3. A. Morshed, “Improving Asset Corrosion Management Using KPIs ”. Material
Performance. May 2008
©2012 by NACE International. Requests for permission to publish this manuscript in any form, in part or in whole, must be in writing to NACE International,
Publications Division, 1440 South Creek Drive, Houston, Texas 77084. The material presented and the views expressed in this paper are solely those of the
author(s) and are not necessarily endorsed by the Association.
... Corrosion risk management for an operation is the systematic application of policies, practices, and resources to control risk and provide reliable safeguards against unexpected failures and leaks, occasioned by corrosion, which can jeopardize mechanical integrity, operation, health, safety and environment (HSE). A corrosion control metric is a performance measure that can be used to assess the efficiency of the prevailing corrosion risk management strategy 4 . For bacteria population to be used as a corrosion control metrics, some empirical correlation is required, however tenuous, that could relate bacteria population to corrosion. ...
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Installation, Analysis, and Interpretation of Corrosion Coupons in Oilfield Operations
Preparation, Installation, Analysis, and Interpretation of Corrosion Coupons in Oilfield Operations, NACE International, NACE RP0775-2005.