Select Committee on Trade and Industry Written Evidence


APPENDIX 2

Desktop Study Final Report Field Joint Coating Review (Redacted Version) by WorleyParsons Energy Services


1.
INTRODUCTION
2.EXECUTIVE SUMMARY
3.JOINT COATING EVALUATION, TESTING AND SELECTION
3.1Introduction
3.2Main Line Joint Coating Product Evaluation and Testing
3.3Peer Assist Review
3.4Pipeline Coatings/Trench Backfill System Optimization Study
3.5Intercoat Adhesion Investigation
3.6SPC SP-2888 RG Joint Coating Material Field Demonstration
3.7Field Joint Coating Technical Risk Assurance Process
3.8Coating Manufacturing Plant Visit
3.9SP-2888 Flexibility and Impact Resistance Testing
3.10SP-2888 Cold Room Application Tests
3.11Pre-Heat and Post-Cure Heating Laboratory Study
3.12Field Application and Testing Program
4.D. MORTIMORE COMMENTS
4.1General
4.2Comments and Responses
5.FIELD JOINT COATING CRACKING
5.1Introduction
5.2Georgia
5.3Azerbaijan
6.CORRECTIVE ACTIONS
7.PROJECT COST AND SCHEDULE IMPACT
7.1Cost Impact
7.2Schedule Impact


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:
CountryTotal number of Coated Joints (to February 2004) Approximate Number of Problem Coated Joints % Problem Rate
Azerbaijan11,386300 2.6%
Georgia4,8901,260 26%


  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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