th
Proceedings
Proceedingsof
ofthe
the8th
8 International Pipeline Conference
IPC2010
September
September 27-October
27-October 1,
1, 2010,
2010, Calgary,
Calgary, Alberta, Canada
IPC2010-0
IPC2010-31060
KOC’S INTEGRITY MANAGEMENT PROGRAM FOR NON-PIGGABLE PIPELINES- A
CASE STUDY
Ashish Khera
Allied Engineers
213 New Delhi House,
27 Barakhamba Road,
New Delhi-110001,India
Phone: +91-11-23314928
akhera@alliedengineer.com
Abdul Wahab Al-Mithin
Kuwait Oil Company- Inspection & Corrosion
P.O. Box 9758, Ahmadi
610008, Kuwait
Phone: +965-23981304
amithin@kockw.com
James E. Marr
TransCanada Pipeline Ltd.
st
450- 1 Street S.W.,
Calgary, Alberta
T2P 5H1, Canada
Phone: +403-920-5410
jim_marr@transcanada.com
Shabbir T. Safri
Kuwait Oil Company-Inspection & Corrosion
P.O. Box 9758, Ahmadi
610008, Kuwait
Phone: +955-23861527
ssafri@kockw.com
Saleh Al-Sulaiman
Kuwait Oil Company- Inspection & Corrosion
P.O. Box 9758, Ahmadi
610008, Kuwait
Phone: +965-23984392
ssulaima@kockw.com
ABSTRACT
More than half of the world's oil and gas pipelines are
classified as non-piggable1. Pipeline operators are becoming
aware there are increased business and legislative pressures to
ensure that appropriate integrity management techniques are
developed, implemented and monitored for the safe and reliable
operation of their pipeline asset.
The Kuwait Oil Company (KOC) has an ongoing
“Total Pipeline Integrity Management System (TPIMS)”
program encompassing their entire pipeline network. In the
development of this program it became apparent that not all
existing integrity management techniques could be utilized or
applied to each pipeline within the system. KOC, upon the
completion of a risk assessment analysis, simply separated the
pipelines into two categories consisting of piggable and nonpiggable lines. The risk analysis indicated KOC‟s pipeline
network contains more than 200 non-piggable pipelines,
representing more than 60% of their entire pipeline system.
These non-piggable pipelines were to be assessed by
utilizing External Corrosion Direct Assessment (ECDA) for
the threat of external corrosion. Following the risk analysis,
a baseline external corrosion integrity assessment was
completed for each pipeline.
The four-step, iterative External Corrosion Direct
Assessment (ECDA) process requires the integration of data
from available line histories, multiple indirect field surveys,
direct examination and the subsequent post assessment of the
documented results. This case study will describe the available
correlation results following the four steps of the DA process
for specific non-piggable lines. The results of the DA program
will assist KOC in the systematic evaluation of each individual
non-piggable pipeline within their system.
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INTRODUCTION
Kuwait Oil Company (KOC) pipeline network is a
very diverse system consisting of 420 transmission pipelines.
The pipeline diameter ranges from 76.2 mm (3”) to 1422.4 mm
(56”). The length of each of these lines varies from less than
100 meters (330 feet) to several kilometers. These lines are of
various vintages with the oldest line commissioned in 1948 and
the newest in 2010.
In March 2005, the „Total Pipeline Integrity
Management System‟ study was implemented by KOC for their
entire pipeline system. This included the DGPS mapping of all
the lines followed by a baseline, quantitative risk assessment.
The lines were subsequently prioritized for the threat of external
corrosion. Following the risk and external corrosion threat
assessment the pipeline system was subsequently divided into
piggable and non-piggable pipelines. A total of 62% of the
KOC pipeline system, representing 261 lines, were designated
as non-piggable.
These lines were subsequently selected for the
application of the National Association of Corrosion Engineers
(NACE) International - External Corrosion Direct Assessment
(ECDA) Standard2. The ECDA standard outlines a process to
assess the integrity of a pipeline subject to the threat of external
corrosion (EC). The ECDA process can be applied for both
piggable and non-piggable pipelines as stated under section
1.1.6 in NACE ECDA standard2. Table 1 categorizes the
pipelines based on transported products within the KOC system
which were initially selected for ECDA.
Table 1: Summary of KOC Pipeline System
Pipeline ID
Condensate (CO)
Crude (CR)
Fuel Gas (FG)
High Pressure (HP)
Low Pressure (LP)
Total Number of Pipelines-
ECDA Applicable Pipelines
43
84
42
62
30
261
Since an internal inspection tool could not be run through these
lines these lines were categorized as non-piggable . This may be
due to simply no available launcher/ receiver facility or
operational and design constraints which may not allow the
passage for an internal inspection tool.
DIRECT ASSESSMENT PROCESS
The initial application of ECDA requires more stringent
conditions to implement DA as an integrity management tool.
The ECDA NACE standard2 was used as a guide and a
company specific ECDA procedure was developed for nonpiggable pipelines within the KOC system. The four prescribed
stages of the ECDA program are:
1. Pre Assessment (PrA)
2. Indirect Inspection (IDI)
3. Direct Examination (DEx)
4. Post Assessment (PoA)
PREASSESSMENT (PrA)
This is the first stage of the process wherein the main
objective is to assess the applicability of the ECDA program to
the KOC pipelines. If deemed feasible to proceed, available
historic and current data on a per pipeline basis were collected
and assessed to define the unique, but preliminary ECDA
regions. This analysis becomes the base and rational for the
development and implementation of the sequential indirect
(IDI) surveys and direct examination (DEx) components of the
DA process.
PrA on KOC system
To initiate the PrA, the initial data collection source was
the KOC Inspection & Corrosion department. Available records
consisted of construction and maintenance data, corrosion
protection information, and investigative excavation results for
some of the lines. For many lines, minimal data was available
either due to being destroyed during the Gulf War or because of
the very old heritage of some lines. Most of the data was only
available in hard copy. Also, most of the lines were operated
under separate asset heads compounding the compilation of
information to complete the pre-assessment. A series of
discussions and interviews with KOC personnel resulted in an
initial working knowledge of the pipeline system.
Concurrently to the PrA, above ground differential global
positioning system (DGPS) mapping was performed for each of
the pipelines within the KOC system. Information on all above
ground features, crossings, proximity to other lines and any
unique right of way observations were identified and
documented. This data was plotted on the most recent GIS
imagery of the system. A centerline for each of the pipelines
was generated as displayed in Fig 1.
NOMENCLATURE
CIPS:
Close Interval Potential Survey
DCVG:
Direct Current Voltage Gradient
DGPS:
Differential Global Positioning System
ECDA:
External Corrosion Direct Assessment
ICDA:
Internal Corrosion Direct Assessment
SCCDA:
Stress Corrosion Cracking Direct Assessment
2
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Figure 1: A section of KOC pipeline system
c. Known data sources and past repairs – known from pipeline
records and also provides a method to evaluate pipelines
ECDA feasibility relative to each individual line.
d. Unknown and/or insufficient data – determined from
analysis and lack of available pipeline data.
After performing the baseline risk assessment, DGPS
mapping and baseline mapping, data integration and the initial
PrA, many technical discussions were held between all involved
parties regarding the application of NACE standard and
selection of IDI tools. Some conservative assumptions were
made and had to be made, regarding the coating type and the
material information for each line. As per section 3.5 of ECDA
standard2, it was decided to treat the lines as one single region
(one preliminary ECDA region). Two complimentary indirect
inspection (IDI) techniques were subsequently selected. These
were a Close Interval Potential Surveys (CIPS) and Direct
Current Voltage Gradient (DCVG). These techniques were
approved by KOC and are considered as “traditional” IDI
surveys.
Through this exercise, it confirmed that the KOC
pipeline system was a “spider web network” and omissions of
information related to individual lines were confirmed but the
ECDA process was deemed applicable to the system. The
developing baseline DGPS survey was required for line
locating, as there were many lines intersecting each other or
within a common right of way. None of the hundreds of above
ground flowlines were included in this program. Some areas
were defined as inaccessible due to oil lakes being present; here
the centerline position had to be extrapolated from the nearest
two accessible end points.
To deal with such a large number of pipelines and
various data elements, a state of the art GIS enabled database
was used. The database needed to be flexible enough to allow
dynamic data integration as new data was constantly integrated
from various PrA and day to day pipeline activities. Following
evaluation, not all the data collected needed to be electronically
saved but conversely, various levels and iterations of data
integration and layering was required to assess the KOC system.
To assist the PrA data collection process, both NACE
and PRCI3 have provided data collection guides which were
applied to all pipelines. Summarized below is the initial
prioritization criteria utilized in this preliminary PrA ECDA
process applied to all non piggable lines:
a. Business critical pipeline (determined by KOC)
b. Past failures – known from pipeline records
INDIRECT INSPECTION (IDI)
The second stage of ECDA is the above ground
indirect inspection. At least two above ground inspection
techniques are required within each DA region to locate
potential external corrosion areas. A severity criterion was also
established to prioritize these areas for further action and
inspection.
IDI on KOC system
This implementation, QAQC and reporting was the
responsibility of another KOC contractor. The DCVG and CIPS
were performed on each of the pipelines considered for the
initial program. The DCVG survey was completed with sub
decimeter GPS measurements to locate, detect position, and
size the coating defect indications. Simultaneously, CIPS
measured the ON and OFF voltage potentials which were
synchronized with GPS controlled current interrupters. Based
on the discussions between KOC and the IDI contractor a
classification index and a priority class were created as
displayed in Appendix A, Table 2.
As a result each surveyed pipeline was categorized into
areas where immediate (I), scheduled (S), monitored (M) and
no further action was required by KOC.
DIRECT EXAMINATION (DEx)
The third stage of the ECDA process involves the
excavation, evaluation and documentation of the pipe
conditions at an investigative excavation. The site selection was
based primarily on the IDI results. The DEx was performed to
assess the actual corrosion found on the pipe body and the
results were correlated to the IDI findings.
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DEx on KOC system
Based on the PrA and IDI results, multiple site
locations were selected on each of the program pipelines. These
sites were not only the areas where immediate action was
required but also consisted of scheduled and monitored action
locations. For each pipeline a unique null site location was also
examined, where no IDI indications existed. A null location is
required for validating the ECDA process. All DEx sites were
more than a joint length long (approx. 15m) and contained at
least one girth weld. This decision enabled a proper
classification of both the girth weld and pipe coating and
allowed for an overall increased inspection sample size.
It was found that the KOC pipeline network has
pipelines with many types of external coating systems such as
Coal Tar Enamel, Asphalt, Polyethylene Tape, Shrink Sleeves, 3
Layer Polyethylene, Fusion Bond Epoxy etc. or a combination
of multiple coatings on a single pipeline.
Standardized field procedure for direct examination
related to the assessment and documentation of investigative
sites for ECDA were used. The deliverables upon applying
these procedures for each DEx investigation were:
- Sub meter GPS coordinates of weld locations along with
start and end of excavations.
- Correlation of the IDI indication to coating faults etc.
- The description and documentation of terrain conditions;
- Assessment and documentation of the pipeline coating
conditions;
- The identification and documentation of pipeline corrosion
deposits;
- The documentation of pH values for electrolyte found
beneath the disbonded coating;
- When possible, and if required, the collection of corrosion
deposit, microbial, and electrolyte samples;
- Measuring the pipe-to-soil potential at pipe depth, soil
resistivity, soil pH etc.;
- The documentation of all defects;
- If necessary, external corrosion defect mapping
- Engineering analysis as per standards and company accepted
procedures
- Photographs for all of the above
- Individual site reports followed by a consolidated report for
the individual pipeline
DEx fell within the existing centerline generated during
mapping.
ii)
Soils: Soils can enhance coating disbondment over
time since pipeline construction. Most of the investigative sites
were located in areas of fluvial sands or calechie (i.e. hard pan)
similar soils. Many of the locations had both these soils present
often stratified from the ground surface to the bottom of the
excavation. The drainage at these sites was mostly characterized
as imperfect to well drained. The topography for most of the
sites was level to inclined areas. Some investigative locations
had oil contaminated soils. Interestingly, there was no unusual
or accelerated coating deterioration due to oil contaminated
soils.
Soils measurements of resistivity and pH were also
obtained at each investigative site. Based on the above soil
characteristics, a quantitative score for soil corrosivity4 was
obtained for each investigation.
While performing the coating assessment, the majority
of the lines investigated correlated to the higher soil corrosivity
plus having a greater coating disbondment. In most of the lines
a direct correlation was found between soil corrosivity and the
number of external corrosion anomalies. Both these correlations
are displayed below in Table 3.
Summary of DEx results
a)
CTE Coated Lines: The pipelines inspected during this
program had a field applied coal tar enamel coating and were
commissioned between 1952 and 1968. The coating was over
the ditch for these lines. As coal tar ages, under specific
conditions it can become brittle and this may affect its physical
protective properties and cathodic compatibility. At most of the
sites the outer wrap (applied to hold the molten coal tar in
place) appeared to be bonded as displayed in Fig 2 with the coal
tar coating underneath disbonded and poorly adhered to the
pipe surface as illustrated in Fig 3.
Listed below is an overview of the DEx results.
i)
Centerline: Based on the sub-meter GPS reading
collected during DEx, the centerline for each pipeline was
regenerated. In some cases, a centerline offset of greater than 1
meter was observed. This was mainly caused by incorrect GPS
readings completed during the mapping due to several lines
crisscrossing each other in congested pipeline corridors. This
was the case in 12% of lines where DEx was performed. For
the remainder of the lines the GPS coordinates collected during
Table 3: Correlating Soils Corrosivity to Coating Disbonment &
Anomalies
Number of lines where DEx was performed
Higher coating
Higher external
disbonment with
corrosion anomalies
higher soil corrosivity
with higher soil
corrosivity
Coal
tar
67%
89%
coated lines
PE
Tape
90%
75%
coated lines
iii)
Coating Condition: For assessment purposes, the KOC
system can be divided into two types of systems; coal tar and
tape type coating systems. From the investigative locations,
65% of the DEx sites contained coal tar enamel (CTE) coated
lines and the rest were polyethylene (PE) tape coated lines.
4
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Figure 2: Initial appearance of CTE coating
performing DEx the coating type was ascertained for these
lines. A major concern with tape coating systems is they are not
cathodically compatible. If the coating disbonds, the CP‟s
ability to protect the pipe surface from external corrosion is
severely limited. In most of the locations the polyethylene tape
coating visually appeared to be intact as displayed in Fig 5.
Upon further inspection it was found that the PE tape coating
was disbonded and poorly adhered to the pipe surface as
displayed in Fig 6. Extensive corrosion deposits were found
under disbonded coating.
Figure 5: Initial appearance of PE Tape coating
Figure 3: Intact though disbonded CTE coating
It was found that the coal tar coating was cohesive but
in many cases poorly adhered to the pipe surface. The
percentage of disbonded coating was correlated to the IDI
severity classification accepted by KOC. This is displayed in
Appendix A Fig 4, where a correlation was identified between
the IDI priority class and disbonded coating. Based on this
correlation, the most severe disbonding was found in immediate
action required sites. As the coating condition improved, the
severity of the IDI classification was justified for this particular
coating type.
b)
PE Tape Coated Lines: The pipelines inspected during
this program had field applied, single wrap polyethylene tape
coating and were commissioned between 1970 and 1973. After
5
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Figure 6: Intact though completely disbodned PE Tape coating
Similar to the coal tar coatings, the extent of disbonded PE tape
coating was correlated to the IDI severity classification. These
results are illustrated in Appendix A Fig 7, where no correlation
was found between IDI classification classes and disbonded
coating. In many cases the Immediate locations had better
coating than the lower prioritized Scheduled, Monitored or Null
sites.
iv)
External Corrosion: Under the disbonded coating, the
corrosion deposits of Iron oxide/hydroxide (FeO/OH)
commonly known as rust to a DEx technician were consistently
found. In many areas, deposits of Calcium carbonate (CaCO3)
indicative of a functioning cathodic protection system and Iron
carbonate (FeCO3) associated with anaerobic conditions leading
to external corrosion were also found.
Pitting corrosion was commonly found under the FeO
and FeCO3 corrosion deposits. The corrosion was both
localized, general wall loss with associated pitting and isolated
pits. Appendix A Fig 8 and 9 categorizes the external corrosion
anomalies detected for both coal tar and polyethylene tape
systems respectively based on the severity of IDI indications. A
correlation was found between the number and severity of
anomalies associated with the coal tar coatings and the existing
IDI classification. Whereas for polyethylene tape coating there
was no correlation found between the number and severity of
external corrosion anomalies found and the existing IDI
classification.
The defect engineering assessment was completed as
per ASME B31G, Modified B31G and Effective Areas Method.
A Pass/ Fail classification was given to each anomaly based on
ASME B31G. An engineering schematic was generated for each
investigative site, displaying the correlation of IDI indications,
disbonded coating and color coded anomalies based on Pass/
Fail classification. Graphical representation along with detailed
calculations for Failed anomalies were also generated. Besides
external corrosion other anomalies found during DEx were
documented such as gouges, dents, pins, arc burns,
microbiologically influenced corrosion etc.
POST ASSESSMENT (PoA)
On completion of the above three ECDA stages, KOC
Inspection & Corrosion group performed the PoA and continues
to perform an iterative review based on the ECDA program on a
line by line basis. The ECDA program forms a portion of the
overall KOC integrity management program, and led to the
following actions:
- Line being declared unfit for service.
- Immediate repairs and the development of future repair
plans
- Complete line coating rehabilitation
- Performing mechanical modifications to make the line
piggable for further inspection
- Performing a hydrotest
- Revising and re-rating the operating pressure
- Determination of the next ECDA program for these lines in
this program and future lines
- Data integration based on the ECDA steps and
improvement of system wide integrity management practices
- Rerunning risk assessment and re ranking the lines
- Developing pipeline performance metrics
SOME LESSONS LEARNED
This was the first time an ECDA program was
performed on the KOC system and initially there were many
startup problems. Based on the learning from the initial ECDA
program some revisions are recommended for future
implementation of ECDA programs. These include:
-
-
-
-
-
6
A single entity to have the accountability and
responsibility for all the four stages of ECDA. This would
improve data acquisition and related QAQC, data
integration and post assessment processing to tie in all the
stages of ECDA.
Since the commencement of this program and initial
application of ECDA, a lot more data is available now and
integrated. The ECDA program could be implemented on
a per line basis rather than in stages over time with
multiple contractors across the complete system.
Pipelines should be further sub divided into unique ECDA
regions based on common physical, pipe, operational and
risk characteristics.
Customized or non traditional IDI techniques for each
ECDA region should be implemented. These should also
be able to tackle the congested right of way areas, oil
lakes, and poor access areas.
Based on initial results, the IDI severity criteria needs to
be more dynamic and customized for the system
depending on the coating type.
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-
Implementing other complimentary inspection programs
along with ECDA such as SCCDA or ICDA when
applicable.
ACKNOWLEDGMENTS
- KOC Inspection & Corrosion Department (Client)
- NDT Systems & Services (Main Contractor)
- Allied Engineers Inspection Team References
(ECDA Sub Contractor)
- Marr Associates (Partners with Sub Contractor)
(1)
Beugen P.V. “Bidirectional MFL Inspection Of NonPiggable Pipelines”
„Pipeline & Gas Journal‟ March 2008
(2)
Standard Practice ANSI/NACE SP0502-2008 “Pipeline
External Corrosion Direct Assessment Methodology”
NACE International
(3)
PRCI- Pipeline Research Council International ECDA
Standards
(4)
A.W. Peabody “Peabody‟s Control of Pipeline Corrosion”
Second Edition
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Table 2: Priority Classes based on IDI surveys
SV- Severe Indication
MD- Moderate Indication
MN- Minor Indication
N/NI- No Indication
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Figure 4: Coating Disbondment for CTE Coating Systems
100%
90%
Coating Disbondment
80%
70%
60%
50%
40%
30%
20%
10%
0%
I
S
Null
CR029
I
S
Null
CR030
I
Null
I
CR031
S
CR046
Null
I
Null
I
S
Null
I
Null
CR085
HP009* (CTE +
Tape)
HP012
I
Null
HP033
I
Null
LP020
DEx Sites classified as perAction required for various KOC Pipelines
Based on IDI results:
Trends:
(I) Immediate Action
(S) Scheduled Action
As Expected
Null Location
Unexpected
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Figure 7: Coating Disbondment for PE Tape Coating Systems
100%
90%
Coating Disbondment
80%
70%
60%
50%
40%
30%
20%
10%
0%
S
M Null
CO019
I
S
HP028
Null
I
S
N
S
HP050
M
Null
LP012
I
S
Null
CR021
I
S
Null
I
LP014
S
Null
I
S
M
LP006
Null
HP039
DEx Sites classified as per Action required for various KOC Pipelines
Based on IDI results:
Trends:
(I) Immediate Action
(S) Scheduled Action
As Expected
(M) Monitored Action
Null Location
Unexpected
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Figure 8: External Corrosion Anomalies for CTE Coating System
90
Number of External Corrosion Anomalies
80
70
>50%
60
20 to 50%
10 to 20%
Pipe
Through
wall
50
40
30
Trends:
20
As Expected
10
Unexpected
0
I
S
CR029
Null
I
S
CR030
Null
I
Null
CR031
I
S
CR046
Null
I
Null
CR085
I
S
Null
HP009* (CTE +
Tape)
I
Null
HP012
I
Null
HP033
I
Null
LP020
DEx sites classified as per Action required for various KOC pipelines
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Figure 9: External Corrosion Anomalies for PE Tape System
20
18
Number of External Corrosion Anomalies
16
14
>50%
20 to 50%
12
10 to 20%
Pipe
Through
wall
10
8
6
Trends:
4
As Expected
2
Unexpected
0
S
M Null
CO019
I
S
HP028
Null
I
S
HP050
N
S
M
LP012
Null
I
S
CR021
Null
I
S
LP014
Null
I
S
LP006
Null
I
S
M
Null
HP039
DEx sites classified as per Action required for various KOC pipelines
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