APPENDIX 2
Desktop Study Final Report Field Joint
Coating Review (Redacted Version) by WorleyParsons Energy Services
1. | INTRODUCTION
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| 2. | EXECUTIVE SUMMARY |
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| 3. | JOINT COATING EVALUATION, TESTING AND SELECTION
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| 3.1 | Introduction |
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| 3.2 | Main Line Joint Coating Product Evaluation and Testing
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| 3.3 | Peer Assist Review |
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| 3.4 | Pipeline Coatings/Trench Backfill System Optimization Study
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| 3.5 | Intercoat Adhesion Investigation
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| 3.6 | SPC SP-2888 RG Joint Coating Material Field Demonstration
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| 3.7 | Field Joint Coating Technical Risk Assurance Process
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| 3.8 | Coating Manufacturing Plant Visit
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| 3.9 | SP-2888 Flexibility and Impact Resistance Testing
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| 3.10 | SP-2888 Cold Room Application Tests
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| 3.11 | Pre-Heat and Post-Cure Heating Laboratory Study
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| 3.12 | Field Application and Testing Program
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| 4. | D. MORTIMORE COMMENTS |
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| 4.1 | General |
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| 4.2 | Comments and Responses
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| 5. | FIELD JOINT COATING CRACKING
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| 5.1 | Introduction |
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| 5.2 | Georgia |
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| 5.3 | Azerbaijan |
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| 6. | CORRECTIVE ACTIONS |
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| 7. | PROJECT COST AND SCHEDULE IMPACT
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| 7.1 | Cost Impact |
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| 7.2 | Schedule Impact |
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1. INTRODUCTION
WorleyParsons Energy Services (WorleyParsons), BTC Finance
Parties' Independent Midstream Facilities Engineer, was requested
to complete a BTC Field Joint Coating Review Desktop Study (Azerbaijan
and Georgia). This request was initiated after the 15 February
2004 London Sunday Times article concerning BTC's field joint
coating in Azerbaijan and Georgia.
This Desktop Study Report was prepared utilizing documents
and information furnished by BP/BTC. As a result of our request
for information for our Field Joint Coating Review BP/BTC provided
314 individual documents. BP/BTC also requested that Specialty
Polymer Coatings (SPC) provide WorleyParsons any required assistance
and information on their SP-2888 field joint coating product.
WorleyParsons prepared this report using the documents provided
by BP/BTC (who were very responsive to our request), information
from SPC and answers to our questions by BP/BTC. This report covers
only the evaluation, testing, selection and application of BTC's
main line field joint coating in Azerbaijan and Georgia. The Desktop
Study did not address Turkey since BOTAS under their Lump Sum
Turnkey contract is using Protogol instead of SP-2888 as their
field joint coating material.
BTC selected a 3-layer polyethylene (first layer is fusion
bonded epoxy, second layer is an adhesive and the third layer
is polyethylene) shop applied coating for its main line pipe coating
system in Azerbaijan and Georgia. Each pipe section is coated
with this 3-layer polyethylene coating except for an approximately
100 mm segment of bare steel at each end to allow pipe sections
to be welded. Also, the polyethylene and adhesive layers are cut
back an additional 50 mm leaving a 50 mm fusion bonded epoxy (FBE)
toe on the steel. This keeps the polyethylene layer from melting
during welding and allows the SP-2888 field joint coating to bond
to the FBE toe. After two pipe sections are welded together, the
bare metal and weld is cleaned and coated with field applied SP-2888
liquid coating.
The findings set forth in this report are based on our review
of information received from sources outside WorleyParsons Energy
Services. We have not independently verified that this information
is comprehensive, complete, accurate or up to date. The findings
contained in this report are based on our evaluation of the available
information in light of our current knowledge and experience of
international pipeline industry practices. WorleyParsons Energy
Services assumes no liability for any errors and omissions contained
in the report resulting from errors and omissions in the information
upon which the report is based, nor any liability for any decision
made or action taken in reliance of such information, or for any
resulting consequential, special or similar damages.
2. EXECUTIVE SUMMARY
Based on a desire to use larger backfill (22 mm) and a lack
of confidence in the field joint coatings used to date on 3-layer
polyethylene (PE) coated line pipe, especially with respect to
large diameter pipe (greater than 36" O.D.), BP (AGT Pipelines
Project) completed a detailed large diameter pipeline field joint
coating evaluation, testing and selection process prior to selection
of Specialty Polymer Coatings (SPC) SP-2888 liquid field joint
coating for the BTC and SCP pipeline projects. The evaluation,
testing and selection process was very thorough and included the
following testing, studies and evaluation:
— Advantica Field Joint Coating Selection Testing
Program—Report issued July 2002
— PEER Assist Review-Meeting in September 2002,
Observations and Recommendations issued February 2003 (after Algerian
demonstrations where BP had a 34", 3-layer PE coated, pipeline
under construction)
— Advantica Pipeline Coatings/Trench Backfill System
Optimization Study—Phase 2 Field Joint Coatings—Report
issued January 2003
— Advantica Intercoat Adhesion Investigation—Report
issued January 2003
— SPC SP-2888 RG Joint Coating Algerian Field Demonstration—Project
Document issued February 2003
— Field Joint Coating Technical Risk Assurance Process
(TRAP)—Conducted in January 2003 with follow-up meeting
in May 2003 with reports issued
— Advantica SP-2888 Flexibility and Impact Resistance
Testing—Report issued June 2003
— SPC SP-2888 Cold Room Application Tests—Report
issued September 2003
— SPC/Carter Coating Pre-Heat and Post-Cure Heating
Laboratory Study—Report issued October 2003
The latest liquid epoxy coating systems combine fast curing,
high adhesion, flexibility and toughness with volatile organic
compound (VOC) free formulations for improved environmental friendliness.
The liquid epoxy coatings high build, single coat, applications
are also cost effective. These liquid epoxy coating systems are
becoming an industry standard for pipeline coating refurbishment/repair,
field joint coating and bored/directional drilled crossing pipe
coating.
The field joint coating selected by BTC, Specialty Polymer
Coatings (SPC) SP-2888, is an amine cured, 100% solid, two-component
liquid epoxy urethane coating. Developed for today's environmentally
sensitive workplace, the coating is free of VOCs and isocyanates
and has excellent adhesion and chemical abrasion/impact resistance.
The "urethane" portion of the cured coating polymer
adds to the abrasion and impact resistance of the epoxy base and
lowers the required cure temperature and/or cure time.
At the request of the Pipeline Induction Heat LTD (PIH),
the field joint coating subcontractor for both the Azerbaijan
and Georgian pipeline construction contractors, SPC completed
the low ambient temperature application tests/study. Based on
these studies, the parameters required for the successful application
and cure of the SP-2888 field joint coating at low ambient temperatures
were developed and the equipment necessary to achieve the required
post application cure temperatures were identified.
Between the start of production field joint coating in August
2003 to early November 2003 BP/BTC indicated that no problems
with the application or integrity of the SP-2888 field joint coating
were reported.
As the weather turned colder in early to mid November 2003,
cracking of the field joint coating was reported in both Azerbaijan
and Georgia. BP/BTC assembled a team to investigate the cracking
of the field joint coating material. The initial findings of the
investigation team concluded that cracking of the coating was
due to thermal cycling of the pipe while the coating was not adequately
cured and had limited flexibility. The inadequate curing was attributed
to minimal pre-heating of the field joints prior to coating, no
post heating and ambient temperatures below 10ºC. Previously
testing had determined that to apply the specified field joint
coating at low ambient temperatures (below 10ºC) conditions
both pre-heat and post heating were required because the coating
curing rate was severely diminished when the temperature fell
below 10ºC. The subject of pre-heat and post heating during
winter work had been openly discussed and all parties were aware
of the requirements. In conjunction with SPC and BTC, PIH had
developed a prototype induction coil, specifically for post curing
but it had rarely, if ever, been used. BP/BTC also indicated that
the field joint coating subcontractor had not followed his own
approved field joint coating method statement and application
procedures or the Field Joint Coating Manufacturer's standard
data sheets and recommendations.
In early December 2003, BP/BTC completed a field test program
verifying the pre-heat/post heat temperatures and time required
to successfully cure the SP-2888 field joint coating material.
BTC then issued BTC Project Procedure AGT002-2004-EN-PRO-00002—Field
Joint Coating using Preheat and Post Heating, Rev. U-02 (dated
9 February 2004) for application and repair of SP-2888 field joint
coating at low ambient temperatures. BP/BTC indicated that there
has been no cracking of the field joint coatings since implementation
of this procedure.
BP/BTC determined that the major cause of the cracking of
the field joint coating was the coating subcontractor continuing
to coat the field joints at low ambient temperatures using his
standard procedure, which was not adequate for low ambient temperature
application. Special procedures are required to apply any field
joint coating material, including heat shrink sleeves, at low
ambient temperatures. A significant amount of Canadian pipeline
construction is accomplished during the winter months but the
contractors accept that it requires extra effort and special equipment
and/or shelters. The Azerbaijan and Georgian pipeline contractors
and their coating subcontractor (especially in Georgia) continued
to work at low ambient temperatures but did not change their work
procedures to accommodate the pre-heat and post heating (curing)
requirements.
The inaction of the BTC construction management/inspection
team to enforce the project requirements allowed the problem to
become greater than necessary. If the BTC IPMT (Integrated Project
Management Team) had taken immediate steps to ensure that the
contractors followed their procedures and method statements then
the number of coated field joints with cracks would have been
significantly less in Georgia. Instead, it seems that they only
reacted when the cracks in the field joint coatings were discovered.
Since most of the problem joints are in Georgia where there
were delays in the pipeline backend (lowering in, backfilling
and clean-up) work the problem joints have not been backfilled.
This significantly reduces the problem since the cracked field
joint coatings can be removed and the field joints recoated with
a minimum amount of extra work.
On its planned routine site visit in May 2004, WorleyParsons
will discuss current field joint coating procedures with BTC's
IPMT (Integrated Project Management Team) and will try to review
the ongoing field joint coating practices for each pipeline spread
in Azerbaijan and Georgia including discussing the issue with
each BTC spread field joint coating inspector.
Since this problem arose, BTC has implemented several corrective
actions to prevent the reoccurrence of this problem.
3. JOINT COATING
EVALUATION, TESTING
AND SELECTION
3.1 Introduction
BP (AGT Pipelines Project) completed an extensive field joint
coating evaluation and testing program prior to selection of SPC's
SP-2888 as the field joint coating product for the AGT Pipelines
(BTC and SCP). At the request of Pipeline Induction Heat LTD (PIH),
the field joint coating subcontractor in both Azerbaijan and Georgia,
BP/BTC and SPC completed an evaluation and testing program to
show that the field joint coating product could be applied during
winter weather using pre-heat and post-heating to assist curing
of the Azerbaijan and Georgia main line field joint coating.
3.2 Main Line Joint Coating Product Evaluation and Testing
In April/May 2001, BP, as part of its Pipeline Cost Reduction
Initiative, decided to perform a main line field joint coating
product evaluation. An additional driver for performing a pipe
field joint coating evaluation was BP and its engineering contractors
lack of confidence in the field joint coatings used to date on
3-layer PE system coated line pipe, especially with respect to
large diameter pipe (greater than 36" O.D.). Since the goal
of the initiative was to be able to utilize larger than normal
backfill material, a detailed technical review and testing for
performance of field joint coating materials to ascertain their
ability to resist penetration, abrasion and impact and to provide
good adhesion and good cathodic disbondment resistance was needed.
In July 2001, BP (AGT Pipelines Project—BTC crude oil
pipeline and SCP [Shad Deniz] gas pipeline) contracted John Brown
Hydrocarbons (JBH) to develop a testing program scope of work
(this test program addressed both the SCP and BTC pipelines).
Also, BP (AGT Pipelines Project) had JBH prepare and issue AGT
Pipelines Project (BTC & SCP) Project Specification 410088/00/L/MW/SP/015—Specification
for Field Joint Coating: Revision B1 (ITC) on 12 September 2001;
Revision C1 (Client Comment) on 20 September 2001; and Revision
D1 (AFD) on 19 October 2001.
BP specialists and the project team then selected three readily
available field joint liquid coating systems (spray grade and
hand-applied) and a field joint heat shrink sleeve to be tested
and evaluated. In November 2001, the selected field joint coating
suppliers were then asked to provide the selected products for
independent testing at a laboratory to be selected by BP (AGT
Pipelines Project).
In December 2001, BP (AGT Pipelines Project) contracted a
coating company to coat three. joints of 36" O.D. line pipe
with 3-layer PE to AGT Pipelines Project Specification 410088/00/L/MW/SP/006—Specification
for 3-Layer Polyethylene Coating of Line Pipe, Revision D1 (AFD)
dated 19 October 2001. They also requested bids from two field
joint coating contractors to provide workspace and equipment,
prepare the pipe and apply the selected field joint coatings (or
provide facilities for the manufacturers own technicians to apply
the coatings). Pipeline Induction Heat LTD (PIH), a well-known
pipeline coating contractor, was the successful bidder. The product
suppliers were invited to attend and apply or witness the application
of their field joint coating product (all suppliers were represented
either directly, through an agent or by PIH).
Advantica Technology (Advantica) test laboratory was contracted
by BP (AGT Pipelines Project) to carry out the field joint coating
testing of the applied coatings in accordance with the scope of
work prepared by JBH and approved by BP (AGT Pipelines Project).
JBH issued AGT Pipelines Project Document 410088/00/L/MW/SC/003—Pipeline
Field Joint Coating Study-Scope of Work, Revision D1 (AFD) dated
7 March 2002, which provided a detailed test program for Advantica.
Advantica completed a rigorous testing program, established
a weighted acceptance criterion and evaluated the test results.
In July 2002 Advantica issued Report R 5426—BP Pipeline
Field Joint Coating Study: Support to Shah Deniz Export Project.
The report stated the following:
— "In order to simplify the selection process,
each test has been weighted in terms of its relevance to the conditions
that are likely to prevail during the construction, commissioning
and service of the Shah Deniz pipeline. Only the liquid coatings
were included in this ranking exercise as they were considered
to be suitable, not only for the girth welds, but also for fittings
and adhoc sections of pipe on which heat shrink sleeves (heat
shrink sleeve/wrap/tube are heat shrinkable products to provide
corrosion protection) to the field joint would be inappropriate.
The decision not to include the sleeves in the ranking exercise
was supported by their variable adhesion around the circumference
of the test pipe and their poor performance on penetration, indentation,
abrasion and gouging tests, particularly at elevated temperature."
— "The SPC hand and spray applied materials
were ranked 1st and 2nd overall. The SPC materials (SP-2888 spray
and hand grades) gave the best overall performance due to their
excellent adhesion to the steel and FBE substrates. These materials
also exhibited good resistance to abrasion, indentation, penetration,
gouging and cathodic disbondment."
— "The heat shrink sleeves, despite having
been applied by the material supplier, exhibited variable levels
of adhesion, some areas peeling from the epoxy primer with little
resistance. Although the sleeves performed well on cathodic disbondment
tests and displayed good impact resistance, they were very susceptible
to penetration and indentation and were easily damaged during
abrasion and gouging tests. Due to the thermoplastic nature of
these materials, their mechanical properties (indentation, penetration,
abrasion and gouging resistance) deteriorated even further at
elevated temperature."
In July 2002, BP (AGT Pipelines Project) selected SPC SP-2888
field joint coating for the BTC and SCP pipelines. JBH issued
AGT Pipelines Project Specification 410088/00/L/MW/SP/015—Specification
for Field Joint Coating, Revision D2 (reissued approved for design)
dated 3 July 2002 specifying SPC as the single source field joint
coating supplier for the AGT Pipelines Project.
3.3 Peer Assist Review
In August 2002, BP (AGT Pipelines Project) requested that
its UTG (Upstream Technology Group) Technical Integrity group
conduct a BTC Line Pipe and Field Joint Coating PEER Assist review
to independently evaluate the processes followed in selection
of the field joint coating for the project. Particular attention
was focused on the selected field coating application, urethane
modified epoxy, which was a relatively new process, especially
on 3-layer PE coated pipe. The final version of the BTC Line Pipe
and Field Joint Coating PEER Assist Observations and Recommendations
Report BTC/001/2 was issued after the Algerian demonstrations
on 27 February 2003. The PEER Assist meeting was held on 5 September
2002. The PEER Assist Review summary stated the following:
— "The project has performed an extensive evaluation
of the various field joint-coating systems that can be applied
to 3-layer coated PE pipe, covering technical performance and
ability to cope with larger backfill material. This included a
number of standard 3-layer field joint coating systems and the
proposed liquid system normally used on FBE coated pipe. The results
clearly indicate that the selected liquid field joint coating
system represents a step change in present industry practice,
both technically and commercially."
— "BP TRAP procedure would be a good mechanism
to close this out."
In October 2002, following receipt of the PEER Assist comments,
JBH issued AGT Pipelines Project Specification 410088/00/L/MW/SP/015—Specification
for Field Joint Coating, Revision 0 (AFC) dated 2 October 2002
and the field joint coating supplier SPC was invited to attend
a meeting in London with the PEER Assist team, UTG, Bechtel, JBH
and other project team personnel to discuss joint coating product
availability, HSE, field operations assistances, training, etc.
3.4 Pipeline coatings/trench backfill system optimization
study
In January 2003, Advantica was contracted by BP (AGT Pipelines
Project) to undertake a Pipeline Coatings/Trench Backfill System
Optimization Study-Phase 2 Field Joint Coatings. This study included
a small-scale laboratory test program to assess the resistance
of the field joint coatings to penetration, impact and abrasion
and a large-scale program to assess the resistance of field joint
coatings to penetration, impact and abrasion when subjected to
freshly crushed and screened, clean, 20 mm igneous aggregate.
The tests were performed on two liquid (each hand applied and
spray applied) and one heat shrink sleeve joint coating products.
Advantica issued Report 5777 on January 2003. Advantica study
conclusions included the following:
— "The field joint coating systems evaluated
in this test programme all resisted penetration, impact and abrasions
in large-scale tests performed using freshly crushed and screened
20 mm igneous aggregate."
— "Based on the small-scale tests results,
significant deterioration in the mechanical properties of the
field joint coating materials occurs at 50ºC. With the exception
of the SP-2888 coatings, all others will require bedding and padding
in aggregate significantly less than the 20 mm used in the large-scale
tests to ensure long-term corrosion protection."
3.5 Intercoat Adhesion Investigation
In January 2003, Advantica was contracted by BP (AGT Pipelines
Project) to undertake an investigation of the Intercoat Adhesion
between the SPC Coating (SP-2888) and a 3-Layer PE Mainline Coating.
The testing program included:
— "Initial adhesion; the as-applied bond strength
was determined prior to testing."
— "Thermal cycling; the cycle comprised of
two 12-hour consecutive periods of immersion in baths of fresh
water maintained at a constant 650ºC and 30ºC respectively.
The cycle was repeated 10 times and the bond strength assessed
within one hour of the panels being removed from the baths."
— "Water Soak; this involved immersing the
test panels for 10 days in a heated bath of fresh water maintained
at a constant 50ºC. The bond strength was assessed within
30 minutes of the panels being removed from the bath."
— "The bond strengths were assessed using the
`cross-cut and peel' and the dolly pull-off tests."
Advantica issued Report 5863 on January 2003 with the following
conclusions:
— "Grit blasting the PE surface provided a
significant improvement in the Intercoat adhesion of the SP-2888
material. However, application of the SPC-1889 primer proved to
be detrimental, unless applied in combination with flame treatment."
— "Adhesion of the SP-2888 to the FBE tail
and the grit blasted steel was considered to be excellent prior
to and subsequent to the thermal cycling test."
3.6 SPC SP-2888 RG Joint Coating Material Field Demonstration
In February 2003, as recommended by the PEER Assist Team,
a field demonstration of the application of SPC SP-2888 RG field
joint coating material was performed in Algeria (where BP had
a 34" OD, 3-layer PE coated, pipeline under construction)
by a specialist coating applicator (PIH) using In Salah Project
3-layer PE coated (without an FBE toe), 34" OD, line pipe.
The demonstration included spray application using automatic rotating
equipment and hand application by roller and brush. BP (AGT Pipelines
Project) and SPC personnel witnessed the field demonstration.
AGT Pipelines Project Document AGT005-000-EN-REP-00008-Field Joint
Coated Site Demonstration for BTC Pipeline, Revision U01 dated
26 February 2003 was issued for information and implementation.
This document noted the following key points and project recommendations:
— Key Point: "There were no concerns on site
about the chemical and mechanical properties of applied and cured
SP-2888 RG."
— Key Point: "At low ambient temperatures cure
over the PE overlap may be slower than over steel and some post
application cure may be required."
— Project Recommendation: "Means of post curing
coating over the PE overlap may be required when ambient conditions
are below 10ºC even after preheat by induction coil."
3.7 Coating Technical Risk Assurance Process
As recommended by Peer Assist Team, the project team commission
BP UTG to conduct a Technical Risk Assurance Process (TRAP) on
the Field Joint Coating System. The TRAP was conducted on 16 January
2003 with a follow-up meeting on 14 May 2003. Reports were issued
for both the original TRAP and the follow-up meeting. The original
TRAP report included the following comments:
— "2 part epoxy solvent-less field joint coating
with very small amount of reacted urethane produces slightly tougher
performance over normal epoxy. Coating has been in use for at
least seven years. Good corrosion prevention performance: as good
as or better than any other epoxy system available."
— "Limited adhesion of field joint coating
to 3-layer HDPE equally applies to all other HDPE field joint
coating systems. The field joint coating system selected, SP-2888,
gives the best performance on steel from the Advantica test program
especially when considering compatibility with 22 mm backfill."
— "The resistance of this coating to penetration
and indentation, and to cathodic disbondment were amongst the
key properties influencing selection of this material."
— "Product used in North America since 1996
and in generic form for close on 20 years."
— The TRAP report references the following from
an Advantica Report R 4583—Pipeline Coating/Trench Backfill
System Optimisation Study-Extension to Small-Scale Laboratory
Test Programme: "The SP-2888 material applied as a two coat
system provides a more mechanically resistant girth weld coating
than the heat shrink sleeve previously tested, particularly at
elevated temperatures."
The follow-up meeting TRAP report included the following
comments:
— "Potential for slow curing of field joint
coating over PE at low ambient temperatures is acknowledged. Further
data on time to optimum cure versus temperature is to be provided
by SPC. PIH are currently developing a post heating method to
accelerate cure of the field joint coating at the PE overlap at
low ambient temperatures, but have still to make a detailed proposal."
— "The Algeria demonstration field joints were
located and inspected and there was no evidence of cracking of
the SP-2888. Temperatures at that location currently fluctuate
between 3 and 35ºC."
3.8 Coating Manufacturing Plant Visit
A BP/AGT Pipelines Project team visited a SPC's coating manufacturing
plant in Canada. The purpose of the visit was to review first
hand the quality systems in place at the manufacturing stage of
the SP-2888 RG field joint coating material and witness SPC's
manufacturing procedures and capabilities. Items discussed were
their manufacturing quality assurance/control program, production
rate and installation personnel training.
3.9 SP-2888 Flexibility and Impact Resistance Testing
Following accusations from a third party consultant with
respect to the selected field joint coating's (SP-2888) impact
resistance and flexibility, Advantica was contracted by BTC Pipeline
Company to undertake further evaluation tests on the flexibility
and impact resistance of the SP-2888 field joint coating. This
was probably the least significant testing effort of the extensive
study and testing program completed by BP (AGT Pipelines Project).
The testing indicated that fully cured SP-2888 coated joints met
the required impact resistance. Even though the flexibility testing
was not performed on coated pipe, the testing did indicate that
the application temperature and curing time impacted the flexibility
of the coating. The Advantica BTC Program consisted of a series
of large-scale impact tests employing coated pipe samples prepared
in conjunction with the Shah Deniz and related BP projects and
a series of small-scale impact resistance and flexibility tests
which were performed on freshly prepared test panels. Advantica
Report 6259 issued June 2003 stated the following:
— "The small-scale tests were able to quantify
the minimum height at which the SP-2888 coating would start to
exhibit coating damage when impacted with 22 mm aggregate. The
spray and brushing grades of SP-2888 when applied over 3-layer
PE exhibited slight damage, although not through-film, once the
drop height reached 450 cm and 500 cm respectively. This was in
reasonable agreement with the results of the large-scale tests
in which only surface roughening occurred when 20 mm aggregate
was dropped from a height of 300 cm."
— "Coating flexibility was influenced by the
state of cure of the material, which in turn was dictated by the
conditions prevailing during coating application and curing. Coatings
applied at ambient temperature (~20ºC) and cured for short
periods, eg 24 hours, did not achieve as high a strain to failure
as those applied at higher temperatures and/or cured for longer
periods, eg 72 hours. Raising the temperature of the coating components
and/or the substrate, during coating application, appeared to
`kick-start' the chemical reaction. This allowed the coating to
reach a more advanced state of cure, within a shorter period of
time and hence to achieve its ultimate mechanical properties more
quickly."
3.10 SP-2888 Cold Room Application Tests
In order to evaluate the effectiveness of this post-cure
of the SP-2888® RG epoxy on polyethylene during winter conditions,
tests were conducted in a "cold room" by Specialty Polymer
Coatings, Inc. GC Lab Services, Inc. provided third party services
for documentation of coating application parameters under simulated
winter conditions and follow-up testing to evaluate the cure of
the coating. Tests were conducted on 26 August 2003. Three meters
of 42" diameter pipe coated with 3-layer polyethylene, supplied
by BP, were used for this evaluation. Post-curing of the epoxy
was accomplished using a hot air generator connected to a clam
shell that was fitted around the pipe at the area to be heated.
Preheating to 80ºC (approximately two minutes required) was
accomplished by using an induction coil supplied by Commercial
Coating Services. Specialty Polymer Coatings Report—Evaluation
of a Method to Cure SP-2888 RG Girth Weld Coating on HDPE at -10ºC
dated 10 September 2003 contained the following `Conclusion'":
— "Post-heating is required to cure the SP-2888®RG
on the HDPE at temperatures below 5ºC. The clam shell hot-air
apparatus provides, sufficient heat during post-cure to ensure
curing of the epoxy on the HDPE overlap during winter conditions.
With a pipe and ambient temperature of -10ºC, 20 minutes
or less of post cure at 80ºC was required to sufficiently
cure the SP-2888®RG as determined by bend tests."
3.11 Pre-Heat and Post-Cure Heating Laboratory Study
Specialty Polymer Coatings engaged Charter Coating Service
(2000) Ltd (Calgary, Alberta Canada) to conduct a laboratory study
to determine the optimum pre-heat and post heating cure temperatures
and heating durations required for application of the two components
liquid epoxy coating SP-2888®R.G. Spray Grade on 3-layer HDPE
coated pipe at a temperature of -10ºC/14ºF. The objectives
of the study was to optimize the application conditions under
cold field conditions of -10ºC/14ºF, determine the ability
to bend without cracking at -10ºC/14ºF and determine
the relationship between coating hardness and the percentage (%)
of cure. Carter Coating Service Report 0154-03-10 concluded that
the "flexibility data, hardness and DSC (differential scanning
calorimetry) results showed a clear correlation with post-heat
curing rates and duration". The report's recommendations
on application at cold field conditions of -10ºC/14ºF
included the following:
— Pre-heat the steel surface to 70ºC/158ºF.
— Pre-heat the coating components mix and apply
in accordance with SPC recommendations.
— Post-cure the SP-2888®RG Spray Grade coating
for two (2) minutes at 80ºC/176ºF.
3.12 Field Application and Testing Program
Following the discovery of cracking in coated field joint
in Georgia, a two-phase program of field application and testing
was carried out at Kilometer 110 in Georgia from 3 December through
8 December 2003. The objective was to define the parameters required
to promote cure and to prevent cracking of the field joint coating
during periods of low ambient temperatures.
In Phase 1, six joints were coated as follows:
— The first joint was coated under the Contractor's
standard blast preheat regime, without any involvement of the
team, apart from detailed observation and measurement.
— The subsequent five joints were torch heated to
drive off moisture before blasting and then preheated to 40ºC,
50ºC, 60ºC, 70ºC and 80ºC respectively, after
blasting and immediately prior to coating.
— The joints were then left to cure naturally at
ambient conditions.
In Phase 2 an additional six joints were preheated and coated
in an identical manner to the five joints in Phase 1, but were
then post heated. Post heating involved raising the pipe temperature
to 80ºC after coating application (time to reach required
temperature was variable from four to five minutes) using the
PIH prototype enclosed coil. After reaching the required temperature
of 80ºC the enclosed coil was left in place for a further
10 minutes before removal. The post heating temperature and heating
duration were identical for each of the six Phase 2 joint coatings.
The 12 completed field joint coatings were tested in accordance
with the field joint coating specification. The Phase 1 field
joint coatings failed on "crosscut" and "impact"
tests. All Phase 2 field joint coatings passed the tests.
Following the initial testing the joints coated under both
Phase 1 and Phase 2 were regularly visually inspected for the
appearance of cracks, both at the butt welds and the steel to
PE interface (from 4 December to 12 December 2003). During this
time period temperatures cycled from an estimated low of -10ºC
during the night and a recorded high of 12ºC during the day.
Cracking was observed on the south side of the Phase 1 field joint
coatings (both west and east end), which were not post heated.
No cracking was observed on the Phase 2 field joint coatings,
which were both preheated and post heated. Based on these results,
the team concluded that correctly prepared and processed field
joint coatings did not exhibit cracking within the period from
application through observation and that flexibility and resistance
to cracking are dependent upon correct curing of the field joint
coating at times when the weather cycles through positive and
negative temperatures (degrees centigrade).
4. D MORTIMORE COMMENTS
4.1 General
It is our understanding that Mr Mortimore, a friend of a
BP employee, reviewed the project's Field Joint Coating Specification
410088/00/LM/ASP-015, Revision 0 dated 24 September 2002 as a
favour. After he issued his comments he asked to be paid for his
effort. Since a BP employee had asked Mr Mortimore to review the
documents, BP issued Mr. Mortimore a contract to cover the work
he did.
As indicated in Section 4 above, BP (AGT Pipelines Project)
completed a significant program of review, evaluation and testing
of field joint coatings, especially SP-2888, prior to and after
receipt of Mr Mortimore's comments.
Mr Mortimore's comments were fairly general with a lack of
specific technical details or references. The comments he made
concerning winter work would also apply to all other available
field joint coating materials, including heat shrink sleeves.
Several of his comments addressed non-technical issues, ie contractual,
costs, contractor capabilities, trade laws, insurance and contractor
claims.
WorleyParsons provided additional responses under "Independent
Engineer" to provide additional clarity and/or information.
4.2 Comments and Responses
This section details some of Mr Mortimore's comments with
BP/BTC and/or Independent Engineer responses.
Comment:
"Probably the worst case condition for an epoxy is immediately
downstream of early main pumping stations where the coating will
be running hot, maybe up to 70ºC in fully immersed state
at different times of the year."
BTC/BP Response:
"The BTC pipeline will operate at 50ºC so this
50ºC is not an issue. The SPC pipeline will run hotter for
approximately 5 km down stream of Sangachal, there is only one
compressor. The compressor shuts in at 72ºC and is expected
to operate well below 70ºC."
Comment:
"no pipeline owner has been identified who specifies
this product, for this exact purpose, anywhere in the world. It
has limited use as field joint coating on FBE coated pipe in Canada
but not on PE coated pipe."
BTC/BP Response:
"If we adopted the same negative attitude to the selection
of line pipe coatings we would still be applying coal tar and
asphalt enamel to wire brushed steel surfaces rather than benefiting
from the superior performance we get from FBE and three layer
FBE-polyolefin coatings."
Independent Engineer Response:
Even though the SPC coating material SP-2888 may not have
been used on projects with 3-layer PE coated line pipe it has
been used on a significant number of projects in the Canada and
United States. Our cathodic protection specialist considers coating
of field joints of 3-layer PE coated line pipe to be very important
and believes that liquid coating materials, including the selected
product, are a positive step change, which seem to be confirmed
by BP (AGT Pipelines Project) evaluation and testing program.
The outermost layer of the "3 layer, polyethylene (PE)"
pipeline coating system (used on the BTC pipeline) is polyethylene,
a very slick material. Because of its physical characteristics,
it is held in place by the second layer of the coating system—an
adhesive. Field joint coating systems for use on 3-layer PE coated
pipelines have generally been some form of a "tape wrap"
and adhesive system. There is no real bond between the polyethylene
of the pipeline coating and the joint coating other than the adhesive
therefore making the field joint coating design life dependent
on the stability of the adhesive. If the adhesive fails, the tape
wrap can disbond as a sheet allowing moisture underneath the wrap
material and shield the underlying bare metal from the cathodic
protection current. Liquid field joint coating systems such as
SP-2888 cure in place, which allows them to mechanically bond
with the prepared surfaces underneath, whether metal, fusion bonded
epoxy or polyethylene. This mechanical bond should provide an
extended design life over an adhesive bond.
Comment:
"If new toe has to be made by end cutting the PE—how
is this to be done? There is no known way to accurately recut
the coating end by hand."
BTC/BP Response:
"There is a known way to remake the cutback on three
layer FBE-polypropylene in the field and this was used successfully
on the ADCO Thamama C and F Project in Habshan, UAE. In 1994—on
every field joint. This procedure could be employed on three layer
FBE-polyethylene with minor changes to the procedure."
Comment:
"<5ºC will be experienced throughout the winter
period. Should construction shut down for four months just because
of the paint?"
Independent Engineer Response:
The application of any field joint coating, including heat
shrink sleeves (wraps), requires special procedures and/or equipment
during cold weather. SP-2888 coating has been installed in the
winter in the United States and Canada (where it gets pretty cold).
Comment:
"The contractor cannot know how to cure the applied
epoxy in all conditions and will ask for instruction from BP.
Do we know how to cure it?"
BTC/BP Response:
"The contractor will be provided with comprehensive
data in respect of the impact of temperature on curing rates."
Independent Engineer Response:
In fact, the selected field joint coating subcontractor for
both the Azerbaijan and Georgian pipeline construction contractors
was involved in the BP/BTC testing program.
Comment:
"For the second time the spec calls for roller application
when this was never at any time tested prior to issue of spec."
BTC/BP Response:
"Rollers were used. Roller application has been used
widely on other projects and is the recommended method of hand
application."
Comment:
"It is an absolute requirement that the coating applied
over the PE has sufficient impact resistance to resist backfill
impact as if it shatters the resulting cracks will transmit into
the coating on the steel."
BTC/BP Response:
"The coating may or may not be damaged by impact in
cold weather, but it will certainly not suffer the same damage
from soil stressing as the alternatives available."
Independent Engineer Response:
BP/BTC completed an extensive impact test program on the
SP-2888 coating along with other liquid coatings and heat shrink
sleeves.
Comment:
"As above, spec says results at 74ºC are for information
only. Pipeline is designed to run close to this temperature for
over 15,000 days!"
BTC/BP Response:
"How does 700 km of pipeline maintain 74ºC from
one compressor located at one end? The temperature profile shows
that the temperature decays below 50ºC within 5 km. Once
again BTC runs at 50ºC max down stream of the pump stations
and SCP compressors are designed to shut in at 72ºC a situation
which operations are unlikely to allow."
Independent Engineer Response:
Even though this comment is not totally correct it does not
apply to BTC because the discharge temperature at the pump stations
is a maximum of 50ºC.
Comment:
"It is clearly a serious mistake for BP to nominate
one material only. We remove the contractors normal commercial
negotiating ability with his suppliers."
Independent Engineer Response:
We disagree with this comment. Since field joint coating
is important, especially in the case of 3-layer PE coated pipe,
we do not believe it is acceptable to let the pipeline contractor
select the field joint coating material to be used. The pipeline
contractor will be inclined to select a coating based on price
and ease of installation, which is different than the pipeline
operating company goal to use a pipeline coating system that provides
long-term corrosion protection for the pipeline.
Comment:
"We are specifying material and application that is
not `best industry practice' or even `normal industry practice'
we are in fact completely out on a limb, we cannot identify any
pipeline owner who uses this epoxy by this application on PE field
joints anywhere in the world."
BTC/BP Response:
"There is no best industry practice for field joint
coating on three-layer polyethylene, the industry is still learning.
Materials used on previous projects have been shown to be inferior
to the selected material.
The specification is far more developed than many prepared
for similar projects and moreover is supported by the results
from a detailed test programme.
Not true. There is no industry standard field joint coating
system, which meets all of the requirements of this project. While
there may be conceptual field joint coating systems which provide
a seamless PE protection system (eg flame sprayed polyethylene),
they are far from fully developed, without a track record and
require a much greater level of applicator skill than the product
specified for BTC."
Comment:
"In use, the material is a known irritant and though
the safety data sheet states `Reproductive toxicity—None
known', it contains 5-15% Bisphenol A which is a known endochrine
disruptor. It is not possible for the company to issue this specification
to the contractors unless we have confirmed it fits with our HSE
policy totally, if it does not fit, spec should be withdrawn immediately."
Independent Engineer Response:
The contractors' Method Statements covered HSE issues. The
field joint coating subcontractor (the pipeline contractors in
both Azerbaijan and Georgia used the same specialist coating subcontractor)
issued a Field Joint Coating Environmental Impact Assessment.
Also, the manufacturer's data sheets provided handling and storage
requirements for the product. The project specification required
the field joint coating contractor to transport, handle and store
the coating product in accordance with the manufacture's requirements.
Since this product has been used on hundreds of projects in Canada
and the United States (strong indication that the product is safe
if handled, stored and applied correctly) it is hard to believe
it did not meet BTC HSE requirements.
Comment:
"There are available industry-standard FJC systems that
meet all of the requirements of this pipeline, these systems provide
seamless, end-to-end homogenus PE protection which remove all
of the uncertaincies of this specification. They are even specified
by BP on three layer coated pipelines! Were they not considered
here? And if not, why not?"
BTC/BP Response:
"Is the author referring to heat shrink sleeves in his
use of `end-to-end homogenous PE protection' If so these did not
meet the requirements of the testing regime.
Strongly disagree, there are no standard FJ coating systems
which provide a seamless end to end homogeneous PE protection."
5. FIELD JOINT
COATING CRACKING
5.1 Introduction
Prior to the commencement of construction field joint coating,
the pipeline contractors in Azerbaijan and Georgia developed and
approved field joint coating procedures and method statements.
These procedures and method statements included a "Hold"
on winter application pending resolution of pre-heating and post
heating temperature parameters.
Despite a hold being placed upon winter working procedures
and method statements, pre-qualification testing (PQT) was allowed
to commence to permit construction start-up. During July and August
2003, PQTs were carried out in Azerbaijan and Georgia by the coating
sub-contractor PIH and witnessed by BTC/SCP technical representatives.
Following successful PQTs, production field joint coating was
allowed to proceed.
From August 2003 to November 2003 no problems were reported
concerning application or integrity of the field joint coating
product SP-2888.
At the onset of colder ambient weather conditions in early
to mid-November 2003, cracking of the field joint coating material
was reported in both countries (field joint coating production
was shut down towards end November). BTC indicated that field
joint coating activities were suspended once it was determined
that the cracks were the result of improper application at low
ambient temperatures.
A team of representatives from the product supplier SPC,
BTC project team and BP UTG (Upstream Technology Group) corrosion
specialists was assembled to investigate the cracking of the field
joint coating. The investigation team carried out an examination
of records, many visual inspections and selected a representative
sample of field-coated joints for testing in order to quantify
the extent of the problem. The following table summarises the
results:
| Country | Total number of Coated Joints (to February 2004)
| Approximate Number of Problem Coated Joints
| % Problem Rate |
| Azerbaijan | 11,386 | 300
| 2.6% |
| Georgia | 4,890 | 1,260
| 26% |
| | |
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The initial findings of the investigation team concluded
that cracking of the coating was due to thermal cycling of the
pipe while the coating was not adequately cured and had limited
flexibility.
5.2 Georgia
It was discovered that cracking had occurred on many of the
coated field joints on the pipeline from KP 110 to KP 126 where
the field joints had been coated from 6 November to 29 November
2003. The investigation team concluded that the cracking was due
to thermal cycling of the pipe while the coating was not adequately
cured (limited flexibility). The inadequate curing was attributed
to minimal pre-heating of the field joints prior to coating, no
post heating and ambient temperatures below 10ºC.
The Contractor had not followed the Field Joint Coating Manufacturer's
standard data sheets and recommendations with regard to the minimum
temperature for application and curing. The Contractor also had
not followed his own field joint coating method statement and
application procedures.
Previous testing had determined that application of the specified
field joint coating at low ambient temperature (below 10ºC)
conditions required both pre-heating and post heating because
the coating cure rate was severely diminished when the temperature
fell below 10ºC. The subject of pre-heating and post heating
during winter work had been openly discussed and all parties were
aware of the requirements. In conjunction with SPC and BTC, PIH
had developed a prototype induction coil specifically for post
heating but it had rarely, if ever, been used.
PIH, the field joint coating subcontractor in Georgia, had
a induction coil (for pre-heat) mounted on a truck but it was
not available all of the time since the truck was used to transport
men and material between work sites. The failure to pre-heat the
field joints using this induction coil immediately prior to application
field joint coating when there was moisture on the pipe and at
lower ambient temperatures violated their own method statement.
For the coated field joints inspected during the site visit
it was evident that the cracking was predominantly on the south
side of the pipe and within the polyethylene chamfer. The conclusion
from this was that the most likely cause of the cracking was the
wide difference between the coefficient of thermal expansion of
polyethylene and that of steel and the temperature extremes seen
by that part of the pipe, which is exposed to the full glare of
the sun during the day.
Under winter working conditions, where temperatures regularly
fluctuate from sub-zero during night and early morning to the
low teens at midday and early afternoon, pre-heat without post
heating was insufficient to adequately cure the field joint coating.
Therefore, the joint coating sits in a state of partial cure and
was cycled between the prevailing ambient temperature extremes
over long periods (typically up to 1 month). Any forces imposed
upon the coating during this period (thermal, mechanical, etc.)
were likely to promote cracking at points of high stress as the
coating has not attained its required mechanical properties.
5.3 Azerbaijan
The following provides a chronological record of the pre-heat
and post-heating regimes used during the coating of the 261 field
joints that BTC surveyed:
— 7 November-24 December 2003—No pre-heat,
except for that required to remove moisture prior to blast cleaning.
Post-heating to 65ºC using an open induction coil, which
was removed immediately upon reaching the target temperature.
The field joints were allowed to cool to ambient temperature.
Ambient daylight temperatures recorded over this period ranged
from 5ºC to 20ºC.
— 25-26 December 2003—No pre-heat. Insulating
blankets reportedly used for the first time at SB 110 following
post-heating, but is not clear if these were used on the field
joint coatings at SB 130 and 131 (coated during this period) where
the contractor reported cracking.
— 27 December 2003-11 January 2004—Pre-heat
to 80ºC immediately prior to coating application, post-heating
to 80ºC using an enclosed coil and the coil left in place
(or the coil replaced by insulating blankets) for an additional
10 minutes after the target temperature of 80ºC had been
reached.
— 10 January 2004—14 field joints were coated
for trial purposes using a pre-heat temperature of 54ºC to
63ºC and a post-heating temperature of 80ºC, with insulating
blankets applied to the field joint and left on for 10 minutes
after post-heating.
— No cracks in excess of 6" long were observed
in the coated field joints that were coated from 27 December 2003
to 11 January 2004. During this period the Contractor had adopted
a field joint coating procedure that included both pre-heating
of the field joints to a temperature in excess of 54ºC and
post heating to 80ºC and maintaining the post-heat temperature
for a further 10 minutes by either leaving the enclosed coil in
place or using insulating blankets. BTC indicated that no cracks
were found that were associated with application of the field
joint coating following these procedures. They indicated that
the small cracks that were found were caused by other reasons.
6. CORRECTIVE ACTIONS
The following correction actions have been taken:
— BP (AGT Pipelines Project) issued Project Procedure
AGT002-2004-EN-PRO-00002—Application Procedure for Field
Joint Coating using Preheat and Post Heating, Revision U-02 dated
9 February 2004. This procedure incorporates successful pre-heating
and post heating parameters for application and curing at low
ambient temperatures (developed and successfully proved by field
testing). This procedure also provides field joint coating repair
procedures at low ambient temperatures.
— Starting in January 2004, BTC provided full time
coating inspectors, on back-to-back basis, in Azerbaijan and Georgia
(previously field joint coating inspectors were not full time
and had other responsibilities). Senior pipeline inspectors and
BP/BTC corrosion specialists are being used to supplement the
coating inspectors. It is WorleyParsons opinion that the use of
full time field joint coating inspectors provides valuable insurance.
— BP/BTC increased their emphasis on field joint
coating HSE issues indicating that the pipeline contractor and
field joint coating subcontractor were not meeting all of their
HSE requirements, ie clean-up, handling, etc.
— The Pipeline Construction Contractor also increased
its number of inspection personnel.
— SPC provided a coating specialist from 8 January
to 1 February 2004 to assist the coating subcontractor to solve
application issues, assist the coating inspection team and provide
training to the field joint coating inspectors.
— In Azerbaijan, the contractor repaired/replaced
the crack field joint coatings and continue work using the correct
procedures. In Georgia, the contractor moved his work to near
the Azerbaijan border (at a much lower elevation) and continued
working using the correct procedures.
In addition to these correction actions, BP/BTC plans to
take the following actions:
— Remove and recoat all of the cracked field joints
in Georgia when the weather improves (no access due to snow at
the higher elevations where the cracked coated field joints are
located).
— Monitor the temporary cathodic protection system.
— Engage an independent company to carry out a survey
of the buried pipe using either the DCVG or Pearson methods starting
in a few weeks. BTC's February 2004 Lenders Progress report indicates
that they will be running a DCVG (direct current voltage gradient)
survey on the buried portion of the pipeline. The DCVG survey
method measures the flow and direction of current along the pipeline
and will indicate major and some minor flaws in the pipeline coating
(3-layer PE) and field joint coating (SP-2888). It is a fairly
common practice to perform this type of cathodic protection survey
immediately after pipeline construction. Normally, major coating
flaws indicated by the survey are excavated and repaired but it
is not necessary to repair all coating flaws, especially minor
ones, since there will be an impressed current cathodic protection
system to protect the steel where there are minor coating flaws
(holidays).
Also, the BTC Pipeline cathodic protection system provides
temporary corrosion protection during construction and permanent
corrosion protection during the operational life for the line
pipe and facilities. According to NACE (National Association of
Corrosion Engineers) International cathodic protection is "a
technique to reduce the corrosion of a metal surface by making
that surface the cathode of an electrochemical cell". When
electrical current flows from a metal surface (the pipeline) into
an electrolyte (the surrounding soil), metal ions are also carried
along—resulting in metal loss. When a pipeline is cathodically
protected, the ground around the pipeline is "charged"
such that electrical current "trickles" to the pipeline
over its entire length. Because the pipeline coating acts as a
shield to the metal the electric current flow seeks out minor
flaws in the coating and "protects" the pipe by flowing
to the pipe rather than away from the pipe. Since no current leaves
the pipeline anywhere, no metal loss occurs.
7. PROJECT COST
AND SCHEDULE
IMPACT
7.1 Cost Impact
The London Sunday Times article stated that Consultants
had indicated that it could cost up to >500 million to dig
up the pipeline and recoat the joints. This cost is significantly
more than the total pipeline installation cost for both Azerbaijan
and Georgia. Since it is believed that most, if not all, of the
problem joints have not been backfilled, any cost impact to BTC
should be fairly small. There is no indication of field joint
coating cracking prior to ambient temperatures below 10ºC
so the only joints with concerns are the ones completed during
period after the ambient temperature went below 10ºC (early
to mid November for Georgia).
BP/BTC indicated that the technical issues had been resolved
but that CCIC (pipeline contractor in Azerbaijan) and SPJV (pipeline
contractor in Georgia) still had contractual and construction
warranty concerns regarding field joint coating. BTC indicated
they were still pursuing these issues with the contactors. BTC
also indicated that they are still negotiating with the pipeline
contractors so any cost to BTC for the recoating effort will only
be available when the final change orders are approved.
7.2 Schedule Impact
Soon after the problem with cracking of the field joint coating
was discovered field joint coating activities were shut down.
In Georgia, the section of pipeline with most of the coated field
joints with cracks is in a high elevation area that has not been
accessible since the coating effort was shut down. BP/BTC indicated
that the backend (lowering in, backfilling and clean-up) pipeline
construction work in Georgia had been behind, which is reason
that so many completed coated field joints were not backfilled.
Therefore the only schedule impact in Georgia will result from
the short period when field joint coating was stopped (once the
pre-heat and post heating procedure was developed the contractor
started coating field joints close to the Azerbaijan border, which
has a similar terrain as Azerbaijan) and the removal and re-coating
of the all of the field joints that have coating cracks. We would
expect the Pipeline Contractor and its field joint coating subcontractor
to plan their 2004 work activities to accommodate this extra work
effort (in fact the February Lenders Progress Report indicated
that the contractor had an extra crew working on replacing the
cracked coated field joints).
In Azerbaijan, the cracking problem was discovered fairly
early resulting in a fairly small number of coated field joints
with cracks. The field joint coating effort was shutdown only
for the short period during which pre-heat and post heat parameters
were developed and tested in the field. Once these parameters
proved successful, the Pipeline Contractor in Azerbaijan incorporated
them in to his field joint coating procedures and resume coating
of the field joints. Therefore, the impact on the pipeline installation
schedule in Azerbaijan should be minimum.
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