SPE-177837-MS
Corrosion Management Challenges of Non-Piggable Pipelines, Sections &
Dead Legs
Rajdeep Dutta and Ibrahim Mohamed Al Suwaidi, Dolphin Energy Limited
Copyright 2015, Society of Petroleum Engineers
This paper was prepared for presentation at the Abu Dhabi International Petroleum Exhibition and Conference held in Abu Dhabi, UAE, 9 –12 November 2015.
This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents
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Abstract
Most operating oil and gas companies possess pipeline assets and In-line Inspections (ILI) are the most
effective ways to assess the integrity of a pipeline. However to carry out ILI the pipeline should be
piggable. Asset integrity audits have identified that while main pipelines are piggable most inter
connectors, branches and by-passes are not in the pig’s path. Some sections while no longer in use, are
still connected with the live system. These sections may be used rarely and therefore not an operational
priority. However these ‘weak links’ pose a major threat to overall system integrity.
Many of these non-piggable pipelines do not have a corrosion control strategy and the technical
integrity of most is unknown. This has been identified as a high integrity risk to operating companies with
respect to loss of production, high cost of failure/degradation and high failure safety risk. As part of the
technical integrity drive and risk management strategy, a need was identified to develop the strategy to
assure the integrity of non-piggable pipelines / sections.
A thorough technical analysis made with advantages and limitations of available integrity assessment
methods for non-piggable pipelines, such as: Hydrostatic Pressure Testing, External MFL Survey, Long
Range Ultrasonic Thickness (LRUT) and Corrosion Direct Assessment (CDA). Based on the analysis, the
most effective and techno-economic solutions were recommended and adopted by Dolphin Energy for its
on-shore pipeline network in the UAE namely LRUT.
Dolphin Energy operates approximately 750 Km of gas transmission and successfully completed an
LRUT inspection project - Phase-1 in 2012 comprising 9 locations and Phase-2 in 2014 - comprising 52
locations throughout the UAE. Post project assessment was made where LRUT inspection and corrosion
direct assessment results were analyzed together. Post assessment specifically addressed the effectiveness
of methods used, corrosion root cause analysis, a corrective action plan, remaining life calculations and
determination of re-assessment interval of each non-piggable pipeline.
This paper addresses the new strategy developed and successfully implemented by Dolphin Energy to
address the challenges associated with these non-piggable pipelines, sections and dead legs. Through this
paper other operating companies who face similar challenges will benefit from the experiences of Dolphin
Energy.
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SPE-177837-MS
Pipeline Network of Dolphin Energy in U.A.E
Dolphin Energy Limited is a major natural gas operating company in Middle East and its background is
given below from company website [4]:
⬙In 1999, the government of Abu Dhabi established Dolphin Energy Limited to implement the Dolphin
Gas Project. This unique strategic energy initiative began gas production in July 2007. The Project
involves production and processing of natural gas from Qatar’s offshore North Field and transportation of
the processed gas by subsea pipeline to the UAE and Oman.⬙
⬙In addition, the company undertook other important energy-related developments such as the Al Ain
– Fujairah Gas Pipeline. This 182 Km pipeline was completed in December 2003 and commissioned in
January 2004. This created the first ever cross-border refined natural gas transmission in the history of the
GCC.⬙
⬙Then in December 2010, Dolphin Energy commissioned the 244 Km Taweelah – Fujairah Pipeline.
Today, it is transporting vital gas supply to the eastern region of the UAE. The overall investment in wells,
sea lines, processing plant, export pipeline, receiving facilities and distribution network has made this one
of the largest energy-related ventures ever undertaken in the Middle East.⬙
⬙Dolphin Energy’s Downstream Operations is responsible for operations, maintenance and managing
the UAE Gas Network - comprising the Taweelah Receiving Facility (TRF), the Eastern Gas Distribution
System (EGDS), the Al Ain-Fujairah Pipeline (AFP) and the Taweelah-Fujairah Pipeline (TFP). These
assets ensure the receipt and distribution of natural gas from Dolphin Energy’s gas processing plant in Ras
Laffan, Qatar to its customers across the UAE and Oman, in a safe and reliable manner.⬙
⬙Once gas arrives at Taweelah, the majority is supplied to other parts of the UAE using Dolphin
Energy’s EGDS. The EGDS is also used to transport natural gas to Oman, using a connection with a
pipeline on the Omani border. This connection was put in place in October 2008 thus completing the
tri-nations gas grid.⬙
⬙The EGDS was upgraded by Dolphin Energy between 2006 and 2007 as part of a long-term lease
agreement with Abu Dhabi National Oil Company (ADNOC). This involved the refurbishment and
recoating of existing pipelines and the addition of fiber optic cables for communications purposes.⬙
Major on-shore pipelines of Dolphin Energy in UAE are summarized as below:
Pipeline Description
30⬙
36⬙
48⬙
24⬙
24⬙
48⬙
36⬙
48⬙
MAQTA - AL AIN
MAQTA - TAWEELA
MAQTA - JEBEL ALI
AL AIN - FUJAIRAH
AL AIN - OMAN Border
TAWEELAH – TIE IN
MAQTA - UMM AL NAAR
TAWEELAH - FUJAIRAH
Pipeline Code
Length
Year Commissioned
MAP
MTP
MJP
AFP
AOP
TRF Tie-in
MUAN
TFP
149.3 Km
49.6 Km
112 Km
174 Km
25.3 Km
9.6 Km
4.5 Km
244 Km
1992
1995
2001
2004
2004
2006
2008
2010
Non-piggable Pipelines & Sections
The Asset Integrity team established a comprehensive Pipeline Integrity Management System (PIMS) and
all pipelines as built and inspection data were uploaded to PIMS [5]. During this process of implementation it was identified that, all main pipeline inspection data are available, however there are several
non-piggable sections which are not included in PIMS.
In response Asset Integrity team in U.A.E. conducted a thorough site audit to identify such nonpiggable sections and found that:
SPE-177837-MS
3
1. Even though the main pipeline is piggable, most of the inter connectors, branches, by-passes were
not in pig’s path, and hence would be missed during ILI
2. Some sections are no longer in use, but connected with live system and had become dead legs
3. These sections are used rarely and not an operational priority. However, they are ‘weak’ links and
pose a major threat to overall system integrity
The non-piggable pipeline sections identified for baseline inspection by the Asset Integrity team are
listed below:
1. 24⬙ MAP KP127 – Al Ain Station
2. 12⬙ RAK Tie-in
3. 36’’ Delivery Line TRF - CRS
4. 12’’ CRS - Taweelah A Power Station
5. 30’’ CRS – Taweelah B Power Station
6. 12’’ CRS – Taweelah B Power Station Extension
7. 18’’ CRS - Taweelah A2 Power Station
8. 18’’ CRS - Taweelah IWPP Power Station
9. 24’’ CRS - Taweelah A1 Power Station
10. 2 X 18⬙ Crossover Lines from 24⬙ & 36⬙ MTP to 48⬙ MJP
11. 24’’ DEL Station - Oman Border
12. 12’’ Jump Over Line at TRF Tie-in
13. 36’’ Umm Al Naar Header (6 Road Crossings)
14. 10’’ Umm Al Naar East – Power Station (2 Road Crossings)
15. 2 X 36’’ Delivery Lines to DUSUP at JGRS
16. 8’’ Branch Line MAP KP35 – Military City
17. 24⬙ Delivery Line AFP - QIDFA at FRS
18. 4’’ Branch Line to GASCO PRS at MJP KP47
19. 2 X 12’’ Bypass Line at MTP SV2
20. 10’’ Flair Line at MAP SV1
One 1.2 Km pipeline 40-inch FRS-F2 was originally non-piggable, but a project was taken up to
upgrade it to a piggable pipeline by installing pig traps and associated facilities.
Integrity Assessment Methods of Non-piggable Pipelines
The Asset Integrity team carried out detailed research about industry practices used to establish the
integrity of non-piggable pipelines. The following methods were shortlisted for further detailed analysis:
1. Hydrostatic Pressure Testing
2. External Magnetic Flux Leakage (MFL) Survey
3. Long Range Ultrasonic Thickness (LRUT) Inspection
4. Corrosion Direct Assessment
The analyses of each method are given in the following sections.
Hydrostatic Pressure Testing
Hydrostatic pressure testing was one of the traditional methods used in the pipeline industry to check
fitness for service. ASME B 31.8 [2] specifies the hydrostatic test pressure for various pipeline class
locations and associated limits.
The main disadvantages of hydrostatic pressure testing methods are:
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SPE-177837-MS
a. The pipeline must be taken out of service for testing, which is not preferred for an operating
pipeline
b. The pipeline cannot be hydrotested when connected to live gas flow line
c. A large volume of water must be used and then disposed of in accordance with environmental
regulations
d. Introduction of water into the pipelines creates a corrosion risk; the pipeline must be dried before
it can be returned to service
e. Pressure testing is destructive and it may enhance severity of existing cracks or flaws
f. Only the critical flaws leading to failure at the time of testing are identified; sub-critical flaws are
not identified
External MFL Survey
Magnetic Flux Leakage (MFL) technology is well established in the industry and mostly followed for
In-Line Inspections (ILI) or Intellight Pigging. Considering the fact that, same tool can not be used for
non-piggable pipelines, a different type tool is developed used same MFL technology. The difference is
this tool access the pipeline from external side, like a movable ring. Sensors, data gathering and data
analysis of this ‘External MFL’ tool is similar to ILI tool.
Limitations of the External MFL technique are:
a. This method could not be applied economically for buried pipelines, due to costs involved in
excavating the pipe
b. Only above ground pipelines and sections can be inspected
c. Following sections of even above ground pipelines could not be inspected:
X Pipe supports
X Any underground road crossing
X Section below a sleeve / clamp
d. It is time consuming and labor intensive
Long Range Ultrasonic Thickness (LRUT) Inspection
Long Rage Ultrasonic Thickness (LRUT) inspection is primarily a Non Destructive Test (NDT) where
low frequency ultrasonic waves are used to detect defects and imperfections some distance away from the
ultrasonic source in a range of components.
A typical application of LRUT is the detection of corrosion and metal loss in pipes and pipelines. A
set of piezoelectric transducers sends the ultrasonic waves in both directions along the length of the pipe.
The same transducers detect the return signal and identify how far along the pipe the imperfections lay.
This scope of work details the inspection requirements in completing Long Range Ultrasonic inspection and follow up Ultrasonic Testing for anomalies found in the above ground station piping with buried
sections and below ground non-piggable pipelines.
The objective of LRUT inspection is to obtain a detailed inspection report on the status and the
structural condition of the non-piggable pipeline or sections. The LRUT inspection scope of work
normally covers the following:
1. A review of the supplied drawings and/or a complete site visit at each location to determine areas
that require excavation for inspection access and coating removal requirements.
2. A simulation test in the calibration block with artificial defect size of 3% to 9% wall loss of the
pipe section to be scanned in order to validate the test equipment and procedure
3. An inspection tool capable of achieving 100% inspection coverage of the pipelines. The inspection
tool specifications, its accuracy, resolution capabilities, data system, etc shall be in compliance
with ASTM E-2775-11 [1]
SPE-177837-MS
5
4. All test equipment shall have current and valid calibration certificates establishing following
parameters:
●
●
●
●
●
Equipment / System Sensitivity requirement
Reliable detection of at least 5% metal loss flaws
Discrimination between flaws and pipe features; e.g, welds, bends, supports, etc.
Longitudinal accuracy better than ⫾100mm
Test Range shall be ⫾30m (typical) and ⫾180m (ideal)
5. Inspection coverage shall include corrosion and defects on the piping at the supports, on the piping
under the road crossings and 100% coverage at the expansion loops and other inaccessible
locations
6. Detect and differentiate between internal and external erosion/corrosion and defects
7. Detect, classify and size weld fabrication defects not meeting the acceptance standard of the
construction code
8. Accurately report the pipe wall thicknesses throughout the pipelines and ensures that clear and
concise digital inspection reports are compiled on the condition and status of the pipeline
Indications identified on LRUT scan plots, are evaluated on the basis of:
e. The signal amplitude
f. The directionality of the focused response
This takes into account that large amplitude responses will be from a large cross-sectional area defect.
Small defects cannot produce large amplitude reflections. However, the converse is not always true; A
small amplitude response does not necessarily mean that the defect is small, as the response may be
affected by a number of factors.
In order to provide a means of identifying defects which are potentially significant in terms of the
integrity of the pipe it is also necessary to examine how localized the response is in terms of the pipe
circumference. This may be obtained from the focused tests and is plotted on a polar response chart.
Corrosion Direct Assessment
Direct assessment is an integrity assessment method that can be applied to buried pipelines for the
evaluation of time dependent threats, such as internal corrosion, external corrosion and stress corrosion
cracking. It shall only be used if situations where ILI is not technically feasible (e.g., non-piggable
pipelines) or are prohibitively expensive (e.g., operational parameters do not allow ILI, say, very high
pressure, high temperature, etc.) for the particular pipeline segment concerned.
External Corrosion Direct Assessment (ECDA) was developed by NACE for buried pipelines, as an
alternative to hydrostatic testing or pigging. Where it is intended that a direct assessment approach should
be used, it must comply with the stringent requirements set out in ANSI/NACE SP0502-2008 [8]. These
require an assessment of its applicability to the candidate pipeline segment and incorporate steps
necessary to validate its performance; such steps include the direct examination of the pipe surface and
typically involve using a combination of non-destructive testing methods and visual inspections.
The ECDA process as per ANSI/NACE SP0502-2008 has the following four components:
a. Pre-assessment
b. Indirect examinations (typically a combination of above ground surveys)
c. Direct examinations (local examination using NDT & visual inspections)
d. Post-assessment
The main techniques within this category are above ground surveys for locating buried pipeline
segments. They may be used on their own or as part of a ECDA programme. Indirect Examination
techniques Include:
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SPE-177837-MS
●
●
●
Cathodic Protection Pipe-to-Soil Potential (PSP) Survey
Close Interval Potential Survey (to determine CP levels, shorts, stray currents) [13]
Direct Current Voltage Gradient (DCVG) Survey (to detect. coating holidays) [13]
A direct examination of a pipeline segment refers to non-destructive testing (NDT) methods. including
visual inspection, followed by appropriate evaluation and remediation, in order to establish pipeline
integrity.
Where Direct Examination is used independently of a ECDA programme, physical access to the
pipeline must be sufficient to permit the entire surface area of the pipeline segment to be inspected.
Acceptable Direct Examination techniques include;
●
●
●
●
●
Visual inspection (for coating damage, metal loss)
Manual or automated UT (metal loss, cracking, weld defects)
External MFL (metal loss)
Magnetic particle examination (for surface cracks)
Long Range / Guided Wave UT (for metal loss detection and quantification) [1]
All pipelines in the UAE under Dolphin Energy network are onshore dry gas pipelines. As such internal
corrosion is historically less than 1% of the total reported corrosion. Therefore Internal Corrosion Direct
Assessment (ICDA) was not applied. However in case internal corrosion is encountered in future, ICDA
will be applied as per NACE SP0208-2008 [9].
Baseline Inspection of Non-piggable Pipelines
On completing detailed analysis of all the available integrity assessment methods, it was concluded that
LRUT would be the most techno-economic baseline inspection method for non-piggable pipelines in the
UAE. This method was used to complete the LRUT inspection project which consisted of Phase-1 in 2012
(9 locations) and Phase-2 in 2014 (52 locations) covering the UAE.
Pipe Excavation for LRUT Inspection
The buried sections of non-piggable pipelines were exposed as per the following scope:
1. Mark the inspection locations as per the scope and data provided
2. At each buried location marked for LRUT inspection, a bell hole shall be excavated
3. In each bell hole, 3 meter lengths of the buried pipe section shall be exposed
4. Excavation of a bell hole will be required where the length of the buried section of the pipe is more
than 30 meters
5. Should any pipe section measure less than 30 meters and one or both ends of pipe section is
accessible above ground, no bell hole excavation is required and LRUT inspection can be done
from part of the pipe aboveground
6. For all buried locations, positively confirm the pipeline location by trial pit. The trial pit must be
made by hand digging. No mechanical excavation equipment is permitted.
7. After locating the pipe by means of a trial pit, 3 meter length of pipe crown should be exposed (top
side only)
8. Should a weld joint be found during crown opening, move the bell hole so that the nearest end of
excavation is minimum 1 meter away from the weld joint
9. Full circumference of the pipe to be exposed and there shall be a minimum of 0.5 metres clearance
around the pipe. Whereas one side of the pipe shall have 1 meter working space inside the bell hole
10. The sides of the excavation are sloped or supported/shored to prevent caving in protect the field
workers. There are at least two proper safe entry/exit points in each excavation
11. Initial dewatering and continuous dewatering (if required) shall be carried out prior to all surface
SPE-177837-MS
7
preparation and LRUT inspection works inside the bell hole
12. Manual UT measurement of pipe wall thickness shall be taken at the centre of the bell hole. If
necessary for UT measurement a small window can be cut on the existing coating
Pipe Surface Preparation for LRUT Inspection
The exposed pipe surfaces were prepared as per the following scope:
1. Removal of existing protective coating may be completed manually (scrapping, brushing) or by
abrasive blasting. At each location 2.5 meters of full circumference pipe coating shall be removed
for LRUT Inspection
2. The surface preparation and cleaning shall meet St-2 standard. If abrasive blasting is utilized, it
shall be completed as per Dolphin Energy’s procedure [6] for surface preparation for the protective
coating
3. Any condensation builds up on the pipeline surface after abrasive blasting shall be addressed. The
dew points and pipeline surface preparation condition shall be tested, inspected and meet the
requirements of the product manufacturer as a minimum prior to coating application [10]
4. LRUT inspection shall be carried out within few hours of pipe surface preparation
5. Under no circumstances the prepared surface shall be left open for more than 24 hours in an open
atmosphere
LRUT Inspection Results Summary
The results of LRUT inspection is summarized below:
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SPE-177837-MS
Post Inspection Recoating
All pipe surfaces prepared for inspection were recoated as per the following scope:
1. Immediately after LRUT Inspection the exposed pipe surface shall be recoated [11]. The time gap
between LRUT and recoating shall not exceed 24 hours
2. Application of the protective coating shall be carried out as per Asset Integrity approved
procedures [6] using pre-qualified products
3. All newly applied coating, including existing exposed coating at the interface, shall be holiday
tested [12]
4. If any holiday (coating defect) is detected, that shall be rectified as per approved in-situ repair
procedure [7]. Repeat holiday test to be carried out to confirm that the repair is successful
5. Details of all holiday tests, results and in-situ repair (if any) shall be recorded
Backfilling and Site Restoration
All excavations were backfilled and the site was restored as per following scope:
1. Ensure that the backfilling of the trench is done in accordance with best practices after the LRUT
inspection and coating repairs are concluded
2. The site cleanup activities shall be conducted in such away to restore the area to its original
condition
3. Backfilling shall not be completed using the original excavated materials unless the following
criteria are met:
a. The pipeline shall be padded with a minimum 300 mm thick fine new sweet sand. No
backfilling material shall be used in this case
b. Backfill material shall be free from refuse, stones or rocks larger than 75mm, or any other
material which might prevent proper compaction or cause the compacted fill or embankment
to perform inadequately
c. Backfill material shall consist of granular soils with at least 80% of the material smaller that
13mm in size
d. All material used as backfill shall have a maximum salt content at 1% and a maximum sulphate
content of 5%
e. The pipeline ⬙Bund⬙ (if any) shall be re-constructed to its original contour and matched to the
existing undisturbed bund. Original excavated material can be used in this case
f. The backfill bund shall be capped with a compacted gatch cap of not less than 20 cm
4. Backfill shall be placed symmetrically to prevent eccentric loading upon or against the pipeline
5. After backfill permanent marker posts shall be installed at all LRUT inspected locations under the
scope. Marker plate shall be embossed with ⬙LRUT Loc. 2014⬙. Height of the marker post outside
the station area shall 1 m height, whereas within the station area it should not exceed 0.5 m from
ground level
6. The marker posts will help to identify exact location for future LRUT inspections
Post Assessment & Analysis
All results from the baseline inspection were evaluated to determine if the inspection or monitoring
activity was been executed according to plan and quality requirements. The results were recorded in PIMS
for future reference.
Inspection results were reviewed by the Asset Integrity team to determine whether any mitigation
action is necessary. The action may be to repair or rectify a condition that has been discovered, or to
modify the preventive and mitigation measure controlling the integrity threat that caused the condition
discovered by inspection or monitoring.
SPE-177837-MS
9
All defects were found to be below the threshold value of 10% of pipe wall thickness. As such no
further action was deemed necessary. However all metal loss indications are recorded in PIMS for
comparison with future inspections, to establish whether there is any indication for growth of corrosion
defects.
It was decided that LRUT inspections for all locations would take place every 5 years.
Conclusions
Pipeline operating companies around the world face challenges with non-piggable pipelines, that do not
have a corrosion control strategy and where the technical integrity of most is unknown. This has been
identified as providing a high integrity risk to operating companies with respect to loss of production, high
cost of failure/degradation and high failure safety risk.
As part of the technical integrity drive and risk management strategy, a need was identified to develop
the strategy to assure the integrity of non-piggable pipelines. Accordingly Dolphin Energy has taken up
this initiative to bring all non-piggable pipelines under comprehensive PIMS already established for
piggable pipelines.
This paper has explained Asset Integrity initiatives taken by Dolphin Energy for bringing all nonpiggable pipelines under PIMS. The methodology of baseline inspection of all non-piggable pipelines has
been developed and successfully implemented in the UAE. Through this paper other operating companies
will benefit from the experiences of Dolphin Energy, who face similar challenges.
Abbreviation
The following abbreviations are used in this paper:
A/G
Aboveground
ADNOC Abu Dhabi National Oil Company
ADWEC Abu Dhabi Water & Electricity Company
AFP
Al Ain-Fujairah Pipeline
ANSI
American National Standards Institute
ASME
American Society of Mechanical Engineers
ASTM
American Society for Testing and Materials
CDA
Corrosion Direct Assessment
CIPS
Close Interval Potential Survey
CP
Cathodic Protection
CRS
Central Receiving Station
DCVG
Direct Current Voltage Gradient
DEL
Dolphin Energy Limited
Dia.
Diameter
DNV
Det Norske Veritas
DUSUP Dubai Supply Authority
ECDA
External Corrosion Direct Assessment
EGDS
Eastern Gas Distribution System
FRS
Fujairah Receiving Station
GASCO Abu Dhabi Gas Industries Ltd.
GCC
Gulf Cooperation Council
GIS
Geographical Information System
ICDA
Internal Corrosion Direct Assessment
JGRS
Jabel Ali Gas Receiving Station
Km
Kilometer
KP
Kilometer Point
10
SPE-177837-MS
LRUT
M/m
MAP
MAOP
MOP
MFL
MJP
MTP
NACE
NDT
PHMSA
PIMS
PRS
PSP
RAK
SMYS
SSC
SV
TFP
TRF
U/G
UAE
UT
WT
Long Range Ultrasonic Thickness
Meter
Maqta – Al Ain Pipeline
Maximum Allowable Operating Pressure
Maximum Operating Pressure
Magnetic Flux Leakage
Maqta – Jabel Ali Pipeline
Maqta – Taweelah Pipeline
National Association of Corrosion Engineers
Non Destructive Test
Pipeline and Hazardous Material Safety Administration
Pipeline Integrity Management System
Pressure Reduction Station
Pipe-to-Soil Potential
Ras Al Khaimah
Specified Maximum Yield Strength
Stress Corrosion Cracking
Valve Station
Taweeleh - Fujairah Pipeline
Taweelah Receiving Facility
Underground
United Arab Emirates
Ultrasonic Thickness
Wall Thickness
References
The following documents are referred in this paper:
1. ASTM E2775-11, Standard Practice for Guided Wave Testing of Above Ground Steel Pipework
Using Piezoelectric Effect Transduction, ASTM International, www.astm.org
2. ASME B31.8S-2010, Managing System Integrity of Gas Pipelines, American Society of Mechanical Engineers, www.asme.org
3. DNV RP-F 101-2004, Recommended Practice of Corroded Pipelines, Det Norske Veritas,
www.dnvgl.com
4. Dolphin Energy Limited, Company website: www.dolphinenergy.com
5. UTS-ENG-MS-00001 (A05) 2011, Asset Integrity Management System, Dolphin Energy Limited, www.dolphinenergy.com
6. UTS-ENG-PR-00023 (A04) 2013, Coating and Painting Procedure, Dolphin Energy Limited,
www.dolphinenergy.com
7. UTS-ENG-PR-00019 (A04) 2011, Pipeline Defects Assessment and Repair Procedure, Dolphin
Energy Limited, www.dolphinenergy.com
8. ANSI/NACE SP0502-2008, External Corrosion Direct Assessment, NACE International,
www.nace.org
9. ANSI/NACE SP0208-2008, Internal Corrosion Direct Assessment, NACE International,
www.nace.org
10. NACE RP0105-2005, Liquid-Epoxy Coatings for External Repair, Rehabilitation, and Weld
Joints on Buried Steel Pipelines, NACE International, www.nace.org
SPE-177837-MS
11
11. NACE SP0109-2009, Field Application of Bonded Tape Coatings for External Repair, Rehabilitation, and Weld Joints on Buried Metal Pipelines, NACE International, www.nace.org
12. NACE SP0188-2006, Discontinuity (Holiday) Testing of New Protective Coatings on Conductive
Substrates, NACE International, www.nace.org
13. NACE SP0207-2007, Performing Close-Interval Potential Surveys and DC Surface Potential
Gradient Surveys on Buried or Submerged Metallic Pipelines, NACE International, www.nace.org