Select Committee on Trade and Industry Written Evidence

APPENDIX 4

Response from Derek Mortimore to ECGD submission

BP—BTC PIPELINE PROJECT

ECGD REPORT TO TRADE & INDUSTRY COMMITTEE RE BTC

Response from Derek Mortimore

  A copy of this report has been given to me by the committee for my review. I do not propose to comment on the financial aspects of the workings of ECGD but their document contains a technical report on the field joint coating from Worley Parsons(WP), carried out for ECGD, which contains many inaccuracies and in which they make personal statements about me and try to refute comments I had made when I reviewed the field joint coating specification in November 2002 at the request of BP.

  I find it extraordinary that the introductory paragraphs of WP's report refer to my relationship with BP in a derogatory manner and try to impung both my character and my professionalism. Anyone reading this report would have to ask the question:

"If Worley Parsons were working for ECGD and no other party, how could they obtain erroneous information regarding Mortimore's involvement with BP and why would they feel it necessary to put such inaccurate comments into a technical audit document?"

  They state:

"After he issued his comments he asked to be paid for his effort."

  Totally untrue.

  This refers to my review of the field joint coating specification that was given to me in BP's offices in Baku in October 2002. They make no reference to the documentary reviews I had been carrying out from May 2002 thru October 2002 or the other instructions I had accepted from BP up to that point. Why not? Obviously they were not aware of them neither could they have had any details of any of the activities I had undertaken in accordance with such instructions. In other words, their informant in BP had only given them the information he wanted to in order that they would gain a false impression of my involvement.

  They further state:

"Since a BP employee had asked Mr Mortimore to review the documents, BP issued Mr Mortimore a contract to cover the work he did."

  This is an appalling travesty of the truth.

  In February 2002 1 was contacted by BP's ACG (Offshore) group and asked to undertake a very urgent assignment to secure the establishment of a new pipe coating facility in Azerbaijan. I accepted instructions and was working in Baku 72 hours later. During this engagement and in a social environment, an old friend in BP's BTC group asked for some advice which I willingly gave.

  Present at that meeting was my employer in the ACG group and he suggested to Paul Stretch—the BP man from the BTC group that he make use of me as I was the only BP pipe coating expert in Azerbaijan. Subsequently, Stretch asked me to review one short document and give him an opinion. This document was in connection with the field joint coating. I was so concerned by what I read that I informed Paul Stretch that the writer, Trevor Osborne, was wrong and that BP needed to assess properly all available technologies for the field joint coating because at that stage this had clearly not been done and if they proceeded on the basis of the very limited research outlined in the first document, then they would come to the wrong conclusion and make a very serious mistake.

  You should note that even today, all the available technologies have never been looked at by the project team and their specification was written on the basis of a pre determined conclusion.

  My comments to BP led to me being asked to review other documents and later to undertake various tasks all at the same day rate that had been agreed with the offshore group.

  For the record, I was previously involved in the BTC project in 2001 at the pre-engineering stage at the direct request of Bob Schofield, a long time friend, who was then the project manager for BTC. At his suggestion, I attended his offices and gave a film show and talk to his staff on the philosophy that needed to be developed for the life time protection of the BTC pipeline and the benefits of three layer HDPE for the primary protection. I made a very strong recommendation for this system and I answered many questions from his team regarding both factory and field joint coating. You should note that at that time, the consultants were recommending a different factory applied coating but Bob Schofield agreed with me that three layer HDPE was their best option.

  I gave a full day of my time and no fee or even travel expenses were sought.

  WP have chosen to question the fact that I had made comments on "non-technical issues, ie contractual, costs, contractor capabilities, trade laws, insurance and contractor claims"—of course I did, that was my duty to my client. All of these matters had been discussed in BP's Baku office and I had been specifically asked to comment on them but clearly their informant in BP was not aware of the instructions from BP Baku.

  WP did not contact me at any time and clearly did not verify facts.

  The way WP worded their introduction is no more than an attempt at a cheap smear, it is based on false information provided by somebody within the project who clearly bore malice towards me, I have no problem with personal malicious attacks from people who know that they are in the wrong but I cannot understand why a company of WP's standing allowed themselves to be used as a conduit for this particularly pernicious attack. To have made these comments in their report demonstrates a clear bias and in my opinion compromises the document's worth to the point of invalidity.

  It is noteworthy that they comment only on parts of one document I had written (they must not have been given any of the many others) and amazingly they print what purports to be BP/BTC comments on my report. You should note that these "BP/BTC" comments have never been made at any time previously!

  If these are BP comments then this is the first time that BP have responded in writing to any comments I have made. It has only taken from 12 November 2002 until this report dated 15 July 2004 for BP to respond to issues that required urgent attention two years ago!

  In order to assist the committee through this "comment/counter comment" cycle I attach herewith following documents to help you:

—  My response to Worley Parsons document.

—  Copy of my letter to CEO—Worley Parsons.

—  BP Field Joint Coating Specification given to me in November 2002.

—  My original critique of this specification made in November 2002.

—  An explanation of science involved, prepared by Dr John Leeds, a leading authority in the field.

  I hope this documentation will help and both myself and Dr Leeds remain ready to appear in person if required.

BP—BTC PIPELINE

DEREK MORTIMORE'S RESPONSE TO WORLEYPARSONS DOCUMENT

  WP's words are printed thus:  This desktop study . . .

  My words are printed thus:  This desktop study . . .

 PAGE 2, ITEM 1. INTRODUCTION

Para 4—Also, the polyethylene and adhesive layers are cut back an additional 50 mm leaving a fusion bonded epoxy (FBE) toe on the steel.

  Not so. This may have been the original intent but was not achieved in practice. Many of the "toes" were incomplete and many were contaminated with PE adhesive. To explain this in simple language, the toes referred to are at the end of the pipe coating which is "cut back" from the end of each pipe as the welding process in the field would damage the coating. BP specified to the factory pipe coater that they must cut back the PE to expose a 50 mm toe of FBE, the primer layer, sticking out around the full circumference of the pipe end. The reason for this was that the specification writers knew that the SPC material did not take up good adhesion to the PE and therefore a seal would be effected between the liquid coating and the FBE coating at either side of the joint. As this seal is paramount to the performance of the joint coating it is fair to say that the in-service performance of every joint was predicated on this FBE toe being present in a full and secure condition.

  Nowhere in the WP document is it stated that any joint without this must fail. But that is the reality.

  They do not mention the configuration of the end cut to the PE. This was supposed to be feathered, that is chamfered to a gentle slope to eliminate any sharp edges, but in many cases was left square cut. This means that the square cut ends of the PE coating acted as a "crack inducer" to the joint coating material. These are failures in BP's quality assurance programme which directly led to many of the early failures. This gives the lie to the repeated assertions in the WP document that all of the failures were the fault of the application sub-contractor, the British company PIH Ltd, but of much more concern to me is the absolute certainty of future failures in service.

Para 5—"We have not independently verified that this information is comprehensive, complete, accurate or up to date".

  I understood that WP acted for ECGD to audit the technical specifications on which the pipeline was to be built. This statement that they did not verify any documents, statements from BP etc is absolutely astounding and clearly invalidates the whole report.

PAGE 3, ITEM 2—EXECUTIVE SUMMARY

"BP (AGT Pipelines Project) completed a detailed large diameter pipeline field joint coating evaluation, testing and selection process prior to selection of Speciality 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 . . ."

  This is not true. The majority of available systems were not considered.

  I listed all the available systems to BP in Baku in June 2002, these are:

—  Liquid systems—epoxies, urethanes or hybrids such as phenolic epoxies, urethane ureas, epoxy urethanes etc.

—  Footprint systems—tape plus ie well-known anti-corrosion tapes with the addition of overwraps, rockshields etc or shrink sleeves, of which there are many different types.

—  Mimic systems—FBE + PE adhesive + PE top coat with the top coat applied by one of the following methods:

1.  Flame spray.

2.  Post fused tape.

3.  Post fused sheet.

4.  Injection moulding.

  Such systems are well known, at least to those of us active in all types of pipelines in all areas of the world, but clearly not to the group of people who had resolved no matter what, that one product only would be used.

  In July 2002 I arranged a demonstration of all of these technologies as clearly they had not been evaluated before. I arranged PE coated pipe with prepared field joints, together with laboratory and test facilities at the premises of a major pipe coater. The system suppliers were to come to the site in Northern France to carry out demonstrations at their own cost, these suppliers were coming from UK, Italy, USA and Germany. The idea was for BP to see all of the available technologies and then draw up a short list of systems to be fully evaluated.

  When I had completed these arrangements I informed BP Baku of this and the following day was instructed by BP Baku to cancel the whole thing as BP London's mind was already made up.

  This demonstrates very clearly a desire on the part of some people within BP London that the best systems were not even to be demonstrated as their superiority over the ludicrous coat of paint already decided on, would be apparent to all.

  You may wish to question the motivation of these people.

  The words used by WP "detailed evaluation . . .very thorough . . . etc" are not valid, the "evaluation" was only of a very limited selection of systems and they did not even look at "21st century" options. Unbelievably they then referred to the "step change" they were effecting in the industry! As I wrote at the time, it was a step change—a backward step!

  WP then list a number of documents they were given by BP/SPC.

  You will note that only the first document, The Advantica Report, was issued prior to the issuing of the specification.

  This is crucial. Any investigation of this matter requires the investigator to draw the time line through all actions by all parties up to the preparation and issuing of the specification as this document was included in the bid package and construction started with this specification as a contractual obligation. From the documents available, the investigator will easily identify a clear "push" for one product only to be considered. All of the documents issued since and all subsequent changes made to this specification arise out of the fact that the specification was and is, inappropriate. It was in my words "under developed and should never had been issued".

  They ignored the advice given in my November 2002 document but since then, and mainly because of serious failures, we have seen a flurry of reports, the sum total of which is a cobbling together of answers to questions which should not have had to be asked and would not have been asked if the matter had been engineered properly at the outset. You should also note that BP have in their possession a number of reports which specifically show that the SPC material could not meet relevant international standards and therefore should not have been used. These reports were not given to WP.

  It is of particular interest to me that their comments on pages 14 to 19 are all about the specification review document I submitted to BP in November 2002, yet they do not declare having received this document in their list on page 3. Why not?

PAGE 3—LAST PARAGRAPH

"At the request of Pipeline Induction Heat etc   . . . "

  It was not at the request of the applicator. I have checked with PIH. A pity that WP did not verify any facts before submitting their document.

  You will note that the SPC cold room report is listed by WP dated September 2003. My document dated 12 November 2002 advised BP that they needed to know all about the curing and performance behaviour of the epoxy and therefore needed to carry out a significant cold weather evaluation in order that they could instruct the contractor—PRIOR TO THE COMMENCEMENT OF THE WORKS—This did not happen.

  Again, I have checked with PIH,

PAGE 4—"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"

  Seventeen months after they had issued their specification they finally found out how to cure the epoxy. This finding did not prove the viability of the field joint, only how to cure the paint. So if they previously did not know how to cure the paint, how could they have proven the viability of the field joint coating specification?

  This simple question is key to the whole problem—they did not prove the viability of the field joint coating before issuing the specification. This is beyond question.

  How could such a serious mistake be made, was it a simple abrogation of responsibility, an error made in ignorance, a stupid act by an incompetent person or was it something else, something that should make you question the motivation of the people concerned.

PAGE 5—"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 THREE LAYER PE SYSTEM COATED LINE PIPE"

  This statement about confidence would be very funny if the situation was not so serious. The reality is that the world has no confidence in using liquid epoxy paint on field joints on polyethylene-coated pipe to the point that nobody in the world uses it, yet BP are saying that they have no confidence in what the whole of the rest of the world is doing!

  Three layer PE had been in use for 30 years at this time so they are saying that all owners of three layer coated pipelines had been doing it wrong for all of this time! Did they talk to these owners?

  Tapes and shrink sleeves have served the industry very well but more importantly, 21st century technology three layer "mimic" field joint systems had been in use for some years. Why did they ignore them in favour of technology that had been rejected by the rest of the world?

  There are many points I could address here but for most of them I would be repeating myself. I will only comment on one more before addressing all of the comments made against me personally.

PAGE 10—ITEM 3.7

"Limited adhesion of field joint coatings to 3 layer HDPE equally applies to all other HDPE field joint coating systems"

  Absolute rubbish. The systems I refer to as "mimic" systems employ HDPE in molten form as their top coat. This melts into the HDPE at the sides of the joint and forms a cohesive mass, there is no adhesion. Clearly the BP/BTC team did not investigate this but it is appalling that the WP team who carried out the technical audit did not even know of such systems.

RESPONSE TO PERSONAL ATTACK

PAGE 14—ITEM 4.1

  1 have addressed all items in my introductory remarks

You should note that all of the following remarks by WP and BP/BTC refer to my original response when i first read the Field Joint Coating Specification in November 2002. The BP/BTC Comments are extraordinary as they have never been made before, they did not respond to my critique at any time and you must remember that when i made my remarks, i was acting for BP, trying to help them.

PAGE 14—ITEM 4.2

"BP/BTC Response—The BTC pipeline will operate at 50 degrees C so this is not an issue . . . "

  Operational temperatures of the pipeline had been discussed in BP's Baku office on the day I was given the specification in 2002. 1 was informed that the pipeline could well run at over 70 degrees C. Now they are saying that it will run at a maximum of 50 degrees. I do not know what temperature the pipeline will run at, do they?

"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"

  This incredibly crass statement is made in response to my pointing out that this would be the first time that liquid epoxy paint had been used for field joints on polyolefin coated pipe. My statement to them was true and confirmed as such by BP themselves in their published article entitled "CASPIAN CONNECTIONS" (Frontiers Magazine, BP's in-house magazine, August 2003, available from BP web site) in which they state in relation to the field joint coating:

  "As far as we know, this is the first time that such a system has been employed", this statement confirms the fact that BP knew they were using this pipeline for "guinea pig" engineering and defeats totally the many comments in the WP report regarding track record of the SPC material.

  Their comment re coal tar and asphalt enamel should be viewed in the light of the fact that the vast majority of North Sea pipelines are coated with asphalt enamel, this is still the current practice including by BP themselves and their comment re FBE and 3-layer should be viewed in the light of the fact that there have been many failures of all pipe coating systems, including FBE and three layer polyethylenes. I do not say this to denigrate them, I have worked with every type of pipe coating for over forty years and I recognise reality. We develop our thinking regarding their use through our experiences, both good and bad, and our understanding evolves through this process. We do not guess—we know. We do not hope—we prove.

  They try to imply that I am some sort of backwoodsman when in fact I have been at the forefront of coating technology for years. Typically, with regard to field joint coating I have developed with various people many innovations and the offshore pipeline joint coating system we developed in 1972, for BP, is used throughout the offshore pipeline construction industry to the extent that it was applied to its 8th million joint last year.

  Multi billion dollar pipelines can not be used as guinea pigs for an individuals ideas, needs or wants, they must be built to known standards with proven technology. This project ignores this principle and therefor cannot be proved as "fit for purpose" for its design life and the insurance implications are obvious.

  The WP comments are even worse. They try to draw a distinction between adhesion and bond. Their statement that SP2888 cures in place is true, just as it is when you buy white emulsion paint from your local DIY store and apply it to your lounge ceiling. All paints cure in place. What we are interested in is the permanence of the adhesion (bond) to the substrate(the surface to which it is applied)

  Their attempt to say that the adhesion of the specified material is superior to all others is pathetic as well as being totally untrue. The adhesion of liquid epoxies to grit blasted steel is generally good, the problem here is the adhesion to polyethylene. In the specification, this failure is recognised by BP as they state the adhesion test result is to be considered a pass when "the coating peels in large pieces from the substrate". This is of course a failure in every international standard and every specification in the global pipeline industry. Only the BTC specification allows what is a clear failure, to be considered a pass and this is just another example of certain peoples determination to use one product only to the exclusion of all others, even falsifying a pass result with obvious consequences to the long term integrity of the pipeline to achieve their objective.

  We need to look at three aspects of the physics of adhesion in this case where the paint is applied over the polyethylene at either side of the joint:

—  POLAR ADHESION—as the polyethylene is a non-polar material with very low surface energy, there is no polar adhesion.

—  CHEMICAL ADHESION—normally defined as the process whereby the applied coating changes the surface chemistry of the substrate, this does not happen when liquid epoxy is applied to polyethylene.

—  MECHANICAL ADHESION—in simple terms this means surface wetting translated into surface tension thereby forming adhesion to the substrate. When the substrate is grit blasted prior to application, this expands the available surface to be wetted thereby increasing the adhesion, but with polyethylene, it cannot be blasted aggressively for this purpose but can only be lightly abraded. The expansion of available surface for wetting is therefore only marginal. Additionally, the polyethylene has very low surface energy and the problem of obtaining adhesion, particularly by high energy paints, to polyethylene is well known in the paint and plastics industries.

  Compare the above with the use of hot melt polyethylene joint material which melts into the overlap areas and forms a cohesive mass, but then BP very pointedly would not even look at such systems even when the demonstration programme had been set up. WHY NOT?

  Page 16. "There is a known way to remake the cutback on 3 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".

  They are right, the "Hancox" rotating knife system was used to re cut ends on the Thamama pipeline. I should know, I was a consultant to one of the coating contractors! The following factors should be taken into account:

—  The work was done in very hot desert conditions

—  The pipe was a much smaller diameter

—  There was a substantial thickness of FBE

  But what is most important is that the design and construction management contractor had looked at liquid paint systems and rejected them. He could not identify a commercially available system which would meet the service requirement of the pipeline and was forced into developing his own field joint coating system. This system, subsequently known as "DAWPA" was based on a three layer mimic system using a pre-cut sheet of polypropylene as the external layer. This was seam welded and fillet welded at the sides of the joint using polypropylene wire welding.

  This resulted in homogenous "End to End" polyolefin protection, exactly as I recommended to BP and which they very vigorously avoided looking at!

  So here we have BP/BTC using this joint as a reference and yet they avoided even looking at it for BTC. You have to ask—WHY?

  The pipeline operator's corrosion engineer in Abu Dhabi has recently confirmed the good performance of this system on a pipeline operating at higher temperature than BTC and in very bad ground conditions.

  You should also note that where joints have failed on BTC and are being blasted off and the SPC material being re-applied, no re-cutting of the ends of the PE is being done so one would have to conclude that BP have accepted that these repaired joints will fail.

PAGE 16—"THE CONTRACTOR WILL BE PROVIDED WITH COMPREHENSIVE DATA IN RESPECT OF THE IMPACT OF TEMPERATURE ON CURING RATES"

  No—he was not.

  Otherwise there could not have been the cracking problem.

PAGE 16—"ROLLERS WERE USED . . . "

  My comment was very clear, they did not do any testing of roller applied material in the original Advantica test, they then specified it in the formal specification.

PAGE 17—"THE COATING MAY OR MAY NOT BE DAMAGED IN COLD WEATHER, BUT IT WILL CERTAINLY NOT SUFFER THE SAME DAMAGE FROM SOIL STRESSING AS THE ALTERNATIVES AVAILABLE"

  I cannot believe the crassness of these statements. They are saying that they did not know if the joint coating would be damaged, or not, during backfilling—absolutely astounding! But then of course they could always find out "on the job", another example of the "guinea pig" engineering culture.

  Then they say definitively that it will not suffer soil stressing as badly as alternatives—when they did not test any of these alternatives. This is the judgement of the crystal ball! It is certainly not an engineering judgement. The fact is that had the joint been coated with a mimic three layer system employing injection moulded PE top coat, the field joint would actually have had superior soil stressing resistance to that of the factory applied coating—a dramatic advance in field joint coating technology.

  Little or no reference is made in the WP report with regard to in-ground performance of the epoxy yet this is fundamental to the coatings ability to protect the pipe in the long term.

  Oil and gas pipelines are not passive, inert items, they are live, dynamic structures that move due to ground movement and most importantly, pressure changes within the pipe. Movement can be lateral, linear and concentric. The coating has to accommodate such movement. The operating temperature will fluctuate with pressure changes and should the pipeline be shut down for any time, the pipe temperature will drop down to the in-ground ambient—estimated by BP to be å5º to +50º C in the worst case (Caspian Connections article, BP's Frontier Magazine, August 2003). This means a temperature range of -5º to +50ºC. How will this affect the performance of the coating particularly at the PE/epoxy interface with significant differences in the expansion/contraction rates of the materials? This question has been discussed throughout the whole pipeline industry and I am yet to hear any individual say—"it will be OK, the system is fully proven"

PAGE 17—"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 APPLICATION, WHICH IS DIFFERENT THAN THE PIPELINE OPERATING COMPANY GOAL TO USE A PIPELINE COATING SYSTEM THAT PROVIDES LONG TERM CORROSION PROTECTION FOR THE PIPELINE".

  The principle that the industry works to, is to first establish the necessary performance criteria for the field joint coating, this obviously may be limited to certain generic systems. And then to allow the contractor to exercise his commercial right to negotiate with potential suppliers and then crucially, for the contractor to prove the viability of his favoured system to the client, PRIOR to commencement of the works. Because the contractor has to certify his work as being fit for purpose, it is in his interest that the field joint material is correct.

  What we saw was the client instructing the contractor to use a material which was not proven, was unsuitable and which failed. In specification terms, they chose the material and then set the performance criteria to suit the very limited capability of the chosen product—a complete reversal of best practice.

  At this point you should be aware that the specification issued for contract bid was a revised version, the original had specified three named paints, the final document nominated only the SPC material. The contractors bidding for the field joint coating contract reported to me (remember I was working for BP) that they were being offered the now disqualified paints for six dollars per litre delivered and the SPC material at 18 dollars per litre. This discrepancy is greater than any I have ever seen in 43 years of dealing with pipeline coatings and cannot be explained in normal commercial or technical terms.

  Essentially, BP paid three times as much, for a material that failed.

  Apart from the unexplained cost, you should be aware that the companies who bid to carry out subcontract field joint coating as well as the main construction contract bidders all queried the sole source specification and expressed their disquiet when instructed by BP that the specification was written in stone, ie, no alternatives would be considered.

PAGE 18—"THERE IS NO BEST INDUSTRY PRACTICE FOR FIELD JOINT COATING . . . "

  This is the excuse for using a process that is clearly wrong? Is not knowing best practice a reason to use worst practice?

"Materials used on previous projects have been shown to be inferior to the selected material"

  Totally untrue. A statement made without a shred of proof.

  I refer you to both BP and my own comments on Thamama C&F.

  Did they talk to RuhrGas in Germany, they have over 200,000 kilometers of PE coated pipe in the ground. Not one single field joint of which is coated with a liquid epoxy paint and they are totally satisfied with their field joint coating system which was one I recommended to BP to look at but which was rejected unseen.

PAGE 18—"THE SPECIFICATION IS FAR MORE DEVELOPED THAN MANY PREPARED FOR SIMILAR PROJECTS AND MOREOVER IS SUPPORTED BY THE RESULTS FROM A DETAILED TEST PROGRAMME"

  Totally untrue, in my critique of the specification in November 2002 I concluded that it was under developed and should not have been issued. I have discussed the matter with many in our industry and can say that the general opinion is incredulity that the specification was ever issued.

  The test programme referred to was the original Advantica testing where they tested the SPC material applied over a primer, they then specified it without primer thereby nullifying the findings of the Advantica report on which their whole support for the specification rested.

  You should note that the "best practice" advocated by SPC, who after all, formulated and manufacture the product, is as follows:

  "THE CONCERN WITH THE EPOXY TO POLYETHYLENE BOND HAS BEEN ADDRESSED BY FLAME TREATING THE POLYETHYLENE AND APPLYING AN EPOXY PRIMER"

  The above is an extract from a paper entitled "Liquid epoxy coatings for today's pipeline coating challenges" written and presented by Mr J Banach—Technical Director of SPC, the paper was given at the British Hydraulic Research Group's PIPELINE PROTECTION CONFERENCE at Aachen, Germany in October 2003. This conference is the leading forum in the pipeline protection industry and the paper was given to 160 delegates from 21 different countries.

  This paper was not provided to WP by BP.

  My written opinion in 2002 was that the original test results bore as much relevance to the project as the results of the then recent Eurovision Song Contest.

  (I was reprimanded for this comment.)

PAGE 19—"IT IS HARD TO BELIEVE THAT IT (THE SPC MATERIAL) DID NOT MEET BTC HSE REQUIREMENTS"

  I had raised the fact in my November 2002 document that the material contained high levels of Bisphenol A, a known endochrine disruptor and I asked that we (BP) check that it was allowable both under the company's HSE policy and the specific project policy as we were crossing thousands of open waterways and shallow aquafers. This was a perfectly proper comment for me to make.

  As the first priority on a project is health and safety, I find the expression—"hard to believe it did not meet etc" to be a clear indication that WP had not checked and did not know.

PAGE 19—"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"

  I have made clear the sort of homogenity that I was looking for and which was readily available to them. Shrink sleeves take up adhesion through a variety of different adhesives but none of them could be considered to provide homogenous PE protection. Shrink sleeves were one of the seven systems I asked them to look at. They tested one out of a possible 30 different sorts of shrink sleeves and condemned the technology outright even though it is serving the industry very well.

  Of particular interest is the Trans Canada Company's specification for the use of liquid epoxy paints as a rehabilitation coating for polyethylene coated pipe. This is where an operating pipeline may be exposed and sections of the original coating removed to facilitate some mechanical repairs. They specify that the liquid coating (SP-2888 is approved and used) must only be applied to steel surfaces, in transition areas ie, where the rehab coating overlaps onto the PE, the liquid must stop short of the PE and a shrink sleeve be used for the transition. This specification was written after Trans Canada carried out a test programme with liquid epoxies onto PE which failed them as a joint coating.

  A copy of the Trans Canada report was given to BP in August 2002, it is one of many documents which could have been made available to WP but which was denied by BP.

  Clearly WP did not know of the three layer systems I referred to BP in 2002 but somehow knew of the three layer system used in Abu Dhabi in 1994!

  They were told that the coating at the pipe ends was re-cut in Abu Dhabi but not told that this was not being done to the cracked field joints on BTC.

PAGES 19 THRU 24

  Much of this refers specifically to the cracking problem. What has not been recognised is that this is not THE PROBLEM. The cracking is no more than a physical manifestation of the inappropriateness of the chemistry employed.

  BP and WP refer to a number of reports that support the use of a liquid epoxy paint for field joint protection on a polyethylene coated pipe. BP do not refer to any of a number of documents in their possession that clearly condemn this concept.

  To disclose that 26% of the joints coated in Georgia were cracked is both extraordinary and unforgiveable. Then to try to ascribe the blame to the applicator as the sole guilty party is an act of cowardice and frankly, stupidity, the like of which I have never seen before.

  The client, BP, is responsible for the construction of the pipeline. All specifications and instructions in the implementation of them are the responsibility of the client. The construction proceeds only when the client has agreed all of the contractors and their sub-contractors, quality plans which are then incorporated into the project quality plan.

  To have 26% of the coated joints cracked is a terrible failure of quality assurance but it is no more than a graphic illustration of the key failure which was to employ an unproven and inadequately tested coating system in the first place, that is the essential failure of quality assurance.

  As you read the pages of the WP report you see a clear picture emerging of inadequate attention to matters of paramount importance. Almost all of the referenced documents were only prepared after the problems came to light. They also reveal that more and one assumes, proper inspection personnel were placed on the project from JANUARY 2004, six months after construction started. If these people were necessary in January 2004 then they were necessary in July 2003. No wonder that BP's quality assurance failed.

  Reference is made to DCVG and temporary cathodic protection. These passages of the report are risible. They demonstrate a minimal understanding of the technology, I refer you to Dr Leeds' explanation of the science.

  The significance of the field joint coating cracking problem has been under estimated by BP and their response in physically dealing with it amounts to the worst gross negligence I have ever seen in the pipeline industry.

  These cracks take three basic forms:

—  Full or almost full, circumferencial cracks at the edge of the factory coating or over the girth weld.

—  Shorter lengths at these locations.

—  Tensile cracks in crescent shapes around the circumference.

  BP and WP state clearly that the cause of the cracking was:

"due to thermal cycling of the pipe while the coating was not adequately cured (limited flexibility)"

  This is the only explanation advanced and all their comments are focused on the failings of the applicator but then we read on page 22:

"They indicated that the small cracks that were found were caused by other reasons"

  What other reasons? Here we have a statement with no explanation and we are left hanging in the wind.

  Cracks of six inches or less are not being repaired, Why? Are we to assume that because BP do not know what is causing them, it is OK to leave them?

  It is not OK.

  Assumptions have been made that the area of exposed steel at any crack will be protected by the cathodic protection (CP) and that the crack itself and the steel it exposes, will not change during the next 40 years. Both assumptions are totally wrong.

  Firstly the cathodic protection, for the above to be true, BP have assumed that the CP system will give an even spread of current to the whole pipe surface, thereby achieving the necessary level of pipe to soil potential level that we know provides protection. How that will be achieved using remote ground beds in rock conditions (high resistance) or in wet salt-laden soils (low resistance) is beyond me and all the CP experts who have debated this. BP's assumption is unsupportable. In addition, as the corrosion process develops at a crack, the surrounding coating will lift and the most serious corrosion will occur under the disbonded coating, where the CP is totally ineffective.

  Secondly, the cracks themselves. These will lengthen over time and in some cases, also widen due to the dynamics of the hydraulic operation of the pipeline. As corrosion occurs, the "lifting" process as described above will take place.

  The corrosion engineer has two main weapons in the fight against corrosion on cross-country pipelines. The barrier coating is always considered the primary system with the cathodic protection considered as a complementary system. Where serious cracking of the coating has occurred on BTC and then been ignored by the corrosion engineer, no power on earth can guarantee the CP will protect at every location yet here we have BP making the CP their only form of protection. I do not know of a single professional corrosion engineer working in the pipeline industry who would support that.

  The most frightening thing of all is that short cracks at the edge of the PE, through to the steel, will provide the perfect initiation point for the formation of stress corrosion cracking (SCC). This phenomena is considered the greatest scourge of the modern high pressure pipeline industry. I am not aware that BP conducted a specific programme at the design stage of the project to ensure the conditions known to cause SCC were recognised and eliminated but I will state categorically that to leave perfect "nesting sites" in the coating is the height of folly and frankly, is beyond belief.

CONCLUSION

  I have been engaged in protecting pipelines for over 40 years. I have worked on a number of BP projects and served the company in a number of different capacities, directly or indirectly, over that time. I am not anti-BP. Everything I have done with regard to this project is out of my desire to help them. That is still my position today.

  What has gone on in the BTC project is appalling. It is essential for the committee to consider the actions of the individual consultant and the BP personnel in the period leading to the writing and issuing of the field joint coating specification. The lies, half-truths and deliberate misleading that went on led the client to issue a specification that was inappropriate, underdeveloped and clearly, when implemented could not prove the necessary "fitness for purpose" to sustain beyond question, the structural integrity of the pipeline for its design life.

  As corrosion engineers, we know that we cannot defeat the laws of nature, the best we can do is hold back nature for a definable period of time.

  BP have a number of reports which they purport, validates their specification. They also have a number of reports that does the exact opposite. The best you can say is that their fundamental decision to use the unproven system was a guess.

  The principle that we work on is the holistic principle, ie:

  WHOLE PIPE—WHOLE LIFE

  Essentially this means that we design the corrosion protection system so that all elements are proven to provide the protective service, in all ground conditions, for the design life plus, of the pipeline.

  This principle has been ignored in this case.

  There is nothing in the WorleyParsons report that proves their case; the fact is that the WP report, if anything, proves the opposite. I refer you to my detailed comments and the explanation of the science prepared by Dr John Leeds.

  WorleyParsons says:

—  We have not independently verified that this information is comprehensive, complete, accurate or up to date.

  So what was the objective of their report? It does not provide any of the verification one would expect to see, on which ECGD could base their financial decision.

  The WorleyParsons report is one of the most extraordinary I have ever read. It has been rewritten, dated only four days before ECGD submitted it to the committee, and dedicates 25% of its content to attacking me. Can anyone believe that this attack was in their original report; of course not, it has been prepared together with an individual in BP, in an attempt to assassinate both my character and my ability.

  The report does not deal with the events leading up to the issuing of the specification. This is the period that is most critical in the whole sorry saga. Had the requirements of the project been recognised and dealt with properly and professionally at that time, then no failures would have occurred and the pipeline's structural integrity would have been assured. As it is, the structural integrity of this pipeline is not assured, joint coatings will fail in service and the subsequent corrosion will be uncontrollable.

  The truth appears sporadically from the miasma of half-truth, untruth and obfuscation.

  The reality is that there was a consistent and shameless promotion for the use of one product and this clouded the judgement of people who should have known better.

  Others have made direct allegations regarding the potential criminal conduct of some of the personnel involved during that critical period, particularly with regard to the material selection process, and clearly the only way to resolve the truth of the situation is for a proper forensic investigation to be conducted by the police into all the individuals' actions. I will of course provide the investigating authority with all the relevant documentation, including reports written by some of those involved, to BP, containing half-truths and deliberately misleading statements.

  Such investigations can reveal any connection between those involved in writing the specifications and the company whose product was nominated. (At three times the cost of its competitors)

  Information regarding this was given to BP along with many other documents in an evidence file in August 2002. BP subsequently held an internal audit. The auditors contacted me and I told them of the existence of this evidence file. They seemed very excited and immediately asked me for it, I responded that the file was in the hands of one of BP's managers in Baku but that the file belonged to me. They told me that they had just been in Baku and were not made aware of this file. They appeared desperate to obtain it, so feeling that an audit would reveal the truth I told them I would phone Baku and advise the manager concerned that he could hand the file over to them. This I did and they went to Baku within 48 hours to pick the file up. Of course, copies of this file are in both Baku and UK although the original one that they picked up seems to have disappeared.

  FACT—when they issued the specification they had one report only, the seriously flawed Advantica report, that supported the use of the SPC product. The evidence file contained seven reports that condemned it, Three of these written by Advantica.

  The circumstances in which I received documents dealing with the relationship of the man who promoted the SPC material and wrote the specification for BP, to the SPC company were explained to the auditors and the name, telephone number and location of the individual who gave me the documents and who had asked me to confirm to the BP auditors that he would have a statement notarised if necessary was also given to them. The individual concerned is one of the most respected, leading professionals in the industry, his character is unimpeachable and he had no interest in the project at that time.

  It did not surprise me that the auditors did not contact him, not at that time or at any time since. This fact may surprise you.

  This is the audit that the Sunday Times became aware of and asked for the report, which was of course denied by BP.

  In this critical period in 2002 there was a concerted effort to avoid the truth, to avoid any and every doubt expressed regarding their pre-determined decision to use an unsuitable product. I was not the only person expressing doubts, remember, I had been approached for help by senior BP managers.

  I was warned before Christmas 2002 that I was to be removed from the project and my involvement was terminated at the end of January 2003 even though I was engaged in tasks at that time instructed by BP Baku. During 2002 I had written much on the field joint protection concept and specification. Not one single point I had raised was ever responded to during this period or later, up to the writing of the WP report where a few comments from "BP/BTC" are quoted.

  After my termination I contacted the project compliance manager for BP Mr David Winter to express my deep concern that the company was making a terrible mistake and asked for a meeting. He eventually agreed and I met him at the end of March 2003. Present for part of that meeting was David Fairhurst, the BP corrosion engineer.

  Mr Winter greeted me with the words "thank you for coming Mr Mortimore but I must tell you that nothing you say will change our minds" at which point I realised that I was wasting my time. However, I had prepared properly for this meeting and decided that I would proceed with my plan which was to give him the historical background of the use of PE and epoxies, establish the fact that their testing had been utterly inadequate, criticise the issued specification in an unanswerable way and try to get them to realise that they must review the whole situation. The meeting lasted over five hours but I failed to get any change in their attitude, which remained—this may not be right but we are going to do it anyway.

  One of the instructions I had had from the project management in Baku was to procure some of the SPC product for evaluation by them not by the London office of BP. I had obtained the material from Canada and had made some free film samples at my home. I showed these to Winter and bent them in front of him to demonstrate the lack of flexibility, the samples shattered when bent but he would still not accept that the material was unsuitable due to its lack of flexibility. I reminded him of the Advantica flexibility test report that I had included in the evidence file, that showed the SPC material failing dismally when tested to a recognised international standard (Transco CW6) and he would not accept this evidence either.

  Mr Winter informed me at the end that I would not be re-hired on the project, I would never work for BP again and that if I stood up and opposed BP, he would ensure that I was made bankrupt. This pathetic threat was treated with the contempt it deserved.

  After the Sunday Times published their devastating article in February, I wrote to Lord Browne, the CEO of BP. I used the expression "last desperate plea" in this letter. I was at my wits end in my worries over the project and the company's future. Five weeks later I received a letter from the MD of the BTC Pipeline Company in Baku, denying me a meeting on the grounds that "nothing could be gained". You can make up your own mind as to whether or not they could have gained something useful from such meeting.

  During the first two months of this year I was placed under severe pressure over this matter, I had as many as seven investigators trying to get me to whistle blow, this included phone calls, knocks on the door even feet in the door. Having been strong, fit and healthy for all of my sixty years I was shocked to suffer a heart attack at this time. This has resulted in some damage for which I am scheduled to have surgery later this year. The cardiologist's opinion was as all tests to find a background cause were negative, the attack was almost certainly caused through stress. The only stress I was feeling at that time was my worry over BP and my own deep sense of guilt that I had failed them.

  I am now retired from the oil and gas business, only partly through health, but primarily though the realisation that my sort of corrosion engineering is not wanted anymore, by a company like BP. Respect for the laws of nature, employment of basic engineering principles, the establishment of performance parameters before undertaking any form of engineering research etc seem to have gone out of the window to be replaced by the—this will do, lets make a few quid, we can make it up as we go along—culture, which I consider to be totally unprofessional, completely unethical and which will eventually result in the greatest disasters that the oil and gas industries have ever seen.

  I have spent a lot of time dealing with the integrity problems of existing pipelines. I have probably looked at as many as 400 pipelines spread over all six continents where serious corrosion problems have occurred. The golden thread running through all of these is that the coating has failed. The failure mechanism is usually identifiable and we can conclude that a mistake has been made and can define rehabilitation strategy. It is also a fact that at least 90% of these pipelines were cathodically protected.

  The BTC pipeline is unique in my experience in that the failure mechanism has been designed into the pipeline.

  In my original submission I gave you some of the historical background to the use of epoxy paints and polyethylene coating in the oil and gas industries. You may be interested to know that there maybe as many as 350 paint manufacturers in the UK with many of them making epoxy paints.

  Not one of these companies markets its epoxy paint as a joint coating for polyethylene coated pipes. WHY—because they know it would not work.

  As I intend that this shall be the last document I ever write on the subject of BTC, I would like to finish with these words from that most perspicacious of American writers, Walt Whitman

  The earth does not argue,

It is not pathetic, has no arrangements, does not scream,

Haste, persuede, threaten, promise,

Makes no discriminations, has no conceivable failures,

Closes nothing, refuses nothing, shuts none out

  Whitman was right, only man can conceive of failure, our duty is to prevent it.

  I will make myself available to the committee, if required, anytime after 22 September.

26 August 2004

BP—BTC Pipeline Project

1.  BP FIELD JOINT COATING SPECIFICATION

2.  ORIGINAL REVIEW DATED NOVEMBER 2002 WRITTEN BY DEREK MORTIMORE

PROJECT NAME: AGT PIPELINES PROJECT

DOCUMENT TITLE: SPECIFICATION FOR FIELD JOINT COATING

DOCUMENT NO: 410088/00/L/MW/SP/015

CONTENTS

  1.  INTRODUCTION

  1.1  GENERAL

  1.2  SCOPE   

  1.3  DEFINITIONS

  1.4  REFERENCE CODES AND STANDARDS

  1.5  MATERIAL APPROVAL AND CONTROL

  2.  CONTRACTOR'S SCOPE OF WORK

  2.1  GENERAL   

  2.2  HEALTH, SAFETY AND ENVIRONMENT (HSE)   

  2.3  QUALITY SYSTEMS   

  2.4  CERTIFICATION AND TEST REPORTS   

  2.5  FIELD JOINT IDENTIFICATION   

  2.6  PRE-QUALIFICATION ACCEPTANCE TESTS   

  3.  SURFACE PREPARATION   

  3.1  PRELIMINARY CLEANING   

  3.2  BLAST CLEANING AND PREPARATION   

  3.3  POWER TOOL CLEANING

  3.4  AIR QUALITY

  3.5  AMBIENT CONDITIONS

  4.  APPLICATION AND REPAIR OF COATINGS

  4.1  GENERAL

  4.2  CONDITION OF COATING MATERIALS   

  4.3  PREPARATION OF COATING MATERIALS      

  4.4  COATING APPLICATION   

  4.5  THICKNESS TOLERANCE   

  4.6  REPAIR OF COATINGS   

  5.  INSPECTION AND TESTING BY CONTRACTOR   

  5.1  ENVIRONMENTAL CONDITIONS   

  5.2  VISUAL INSPECTION   

  5.3  HOLIDAY TESTING   

  5.4  THICKNESS TESTING   

  5.5  IMPACT RESISTANCE   

  5.6  ADHESION STRENGTH   

  5.7  PENETRATION INDENTATION TEST

  5.8  HARDNESS

  5.9  CATHODIC DISBONDMENT TESTING

  TABLE 1—APPROXIMATE DESIGN ENVIRONMENTAL DATA   

  ANNEX A  INSPECTION/TESTING SUMMARY, PREQUALIFICATION   

  ANNEX B  INSPECTION/TESTING SUMMARY, PRODUCTION   

1.  INTRODUCTION

1.1  General

  1.1.2  The cross-country pipelines for the AGT pipelines project will be buried and will be protected against external corrosion by external coating and Cathodic Protection systems. The external coatings shall be suitable for the operating conditions to which they are subjected and shall have proven good resistance to cathodic disbondment.

  1.1.3  Approximate pipeline design and environmental criteria are typically as given in Table 1.

1.2  Scope

  1.2.1  This document and related specifications cover the minimum requirements for the field joint coating of linepipe coated with three Layer High Density Polyethylene (3LHDPE). The 3LHDPE coating system will be supplied in accordance with project specification 410088-00-L-MW-SP-006, Specification for Three Layer Polyethylene Coating of Linepipe.

  1.2.2  Field joints shall be coated using a liquid applied system as described in Section 4.1 of this specification.

1.3  Definitions

—  For the terms "COMPANY" and "CONTRACTOR" refer to General Conditions of Contract.

—  The term "MANUFACTURER" shall mean the particular company responsible for manufacture and supply of the coating materials.

1.4  Reference Codes and Standards

  1.4.1  This Specification references the following Codes and Standards—see Section 1.4.2 to 1.4.3 below. Where an edition date is not specified the latest edition at the time of contract award shall be used unless otherwise agreed with COMPANY.

  1.4.2  ASTM Standards

ASTM D 2240-91	Standard test method for rubber property (durometer hardness).
ASTM D 5402-93 (1999)	Standard practice for assessing the solvent resistance of organic coatings using solvent rubs.
ASTM G 8-96	Standard test methods for cathodic disbonding of pipeline coatings.
ASTM G 14-96	Standard test method for impact resistance of pipeline coating (falling weight test).
ASTM G 17-96	Standard test method for penetration resistance of pipeline coatings (blunt rod).
ASTM G 42-96	Standard test method for cathodic disbonding of pipeline coatings subjected to elevated temperatures.

  1.4.3  British Standards/International Standards Organisation (ISO)

BS EN ISO 9001	Quality Systems—Model For Quality Assurance In Design, Development, Production, Installation and Servicing (1994).
BS EN ISO 9002	Quality Systems—Model For Quality Assurance In Production, Installation And Servicing (1994).
BS 7079 Part Al	Preparation of steel substrates before application of paints and related products. Visual assessment of surface cleanliness. Specification for rust grades and preparation grades of un-coated steel substrates and of steel substrates after overall removal of previous coatings. (1994). [Identical with ISO 8501-1].
BS EN ISO 8501-1	Preparation of steel substrates before application of paints and related products—Visual assessment of surface cleanliness.
BS EN ISO 8503-2	Preparation of steel surfaces before application of paints and related products. Method for the grading of surface profile of abrasively blast cleaned steel using a comparator (1995).

  1.4.4  Canadian Standards Association

CAN/CSA Z245.20-M92	External fusion bond epoxy coating for steel pipe (1992).

  1.4.5  NACE Standards

RP 0274/93	Standard recommended practice for high voltage electrical inspection of pipeline coatings prior to installation.

  1.4.6  The SUPPLIER shall make these standards available to all personnel engaged on the work and shall ensure any sub-contractor follows the same requirements.

1.5  Material Approval and Control

  COMPANY shall approve MANUFACTURER(s) and coating materials to be used. Coating work shall not commence until all relevant documents, the Quality/Inspection plan and supporting procedures have been approved by COMPANY.

  CONTRACTOR shall submit to COMPANY certified copies of the results of tests made by MANUFACTURER covering the physical, chemical and performance characteristics of all materials to be used in the work, plus detailed specifications and instructions for handling and application.

  Coating shall be applied, inspected, tested and repaired in accordance with procedures as approved by COMPANY. The work shall be under the supervision of CONTRACTOR'S specialist coating personnel as approved by COMPANY. All coating inspectors shall be suitably experienced and qualified, eg to NACE Coating Inspectors Certificate, and career details shall be provided for COMPANY approval.

  During the work, the following actions shall also be subject to approval by COMPANY:

  —  Time lapse for application to prepared steel surfaces.

  —  Use of power tool cleaning.

  —  Use of thinners for coating materials.

  —  Treatment of defective and damaged coatings.

2.  CONTRACTOR'S SCOPE OF WORK

2.1  General

  CONTRACTOR shall provide testing and inspection equipment, all properly calibrated, for use by COMPANY during testing and inspection. CONTRACTOR shall be responsible for continuous supervision and inspection of the work.

  CONTRACTOR shall supply, and maintain in good working order, all labour, transport, supervision, consumables, materials, plant, tools, equipment, lighting, spare parts, inspection and holiday detection apparatus, safety equipment, protective clothing, site cabins, weatherproof enclosures with humidity control for blast cleaning and coating, stores with temperature controls, transport, well drained stockpile area, and all other items needed to perform the work described and specified herein.

  CONTRACTOR is responsible for ensuring that all work is performed to the standard of quality required by the approved project Specification. COMPANY may request the provision of coating material samples, and prepared and coated test panels. CONTRACTOR shall demonstrate production of the specified surface cleanliness and roughness for site preparation.

  Coating and abrasive materials shall be clearly identified with type, manufacturer's name, batch number, expiry date, pot life, etc details.

2.2  Health, Safety and Environment (HSE)

  The CONTRACTOR shall fully comply with the HSE requirements of the CONTRACT. CONTRACTOR shall ensure that all work and storage is performed in accordance with all applicable laws affecting health and safety at work and follow recommendations of MANUFACTURER.

2.3  Quality Systems

  The CONTRACTOR shall operate a Quality Management System in compliance with BS EN ISO 9001: 1994 or BS EN ISO 9002: 1994 as appropriate. A Quality Plan shall be submitted within 4-weeks from contract award, for acceptance by the Company. This Plan shall ensure compliance with the requirements of the contract or purchase order and any statutory authority requirements that may apply and include all activities to be undertaken by the CONTRACTOR to meet the Scope of Work.

  COMPANY shall be allowed access to inspect all items and phases of the work. Where field joint coating procedure acceptance tests have been agreed, COMPANY will witness these tests.

2.4  Certification and Test Reports

  CONTRACTOR shall establish a full reporting and recording system and shall produce daily reports, and submit a full documentation package at the end of the work, including, where applicable:

—  Items prepared, method of preparation, abrasive type and grade, standard of cleanliness and profile achieved

—  Coating material type, name, colours, application method, thickness measured, etc

—  Application and inspection personnel

—  Ambient temperature and humidity conditions

—  Outstanding areas for coating/repair, repair results

—  Certificate of conformity

—  Certified copies of test results made by MANUFACTURER covering the physical, chemical and performance characteristics of his products, data sheets, including cathodic disbondment results.

  CONTRACTOR shall provide the following procedures where applicable:

—  Field joint preparation and induction heating

—  Coating procedure

—  Coating materials, storage, application and repair, curing

—  Measures to be adopted during periods of adverse weather

—  Inspection and testing, including acceptance criteria, and frequencies, coating thickness

—  Preservation, packing, shipping and storage: to include methods, materials and any requirement for periodic inspection

—  Quality Plan

  CONTRACTOR shall supply data sheets and details of coating materials to establish the suitability of the proposed coating for the given use of the coated item. All coating materials shall conform to the specified composition. MANUFACTURER shall confirm in writing that the coating systems meet the requirements of this Specification and can be applied successfully to the relevant substrate.

2.5  Field Joint Identification

  Details of field joint number and coating type/date shall be generated and recorded by CONTRACTOR's tracking system and all data shall be provided to COMPANY in an agreed format.

2.6  Pre-Qualification Acceptance Tests

  Pre-qualification tests for the field joint anti-corrosion coating shall be carried out by CONTRACTOR. These tests shall prove that CONTRACTOR can provide an applied coating which meets all the specified properties.

  Before field application of field joint coating materials the CONTRACTOR shall pre-qualify his materials, process and application procedure. Two full field joints shall be prepared and coated under conditions that replicate those expected in the field; one joint shall be coated by spray method and the other by hand using a brush or roller. When the coating is fully cured the tests in Appendix A shall be conducted.

3.  SURFACE PREPARATION

3.1  Preliminary Cleaning

  Weld splatter, sharp edges, etc shall be removed. The surface shall be decontaminated of hydrocarbon deposits and moisture, using a solvent wipe if necessary, in accordance with SSPC-SP1 (BS 5493, Clause 14.2). The surface shall be allowed to dry out before proceeding to the next stage of the work. After cleaning, unless otherwise approved, the field joint shall be uniformly heated to 80ºC to remove all moisture and to preclude any condensation of moisture on the surface after blast cleaning. Also, if environmental conditions require it, the steel substrate shall be preheated to a maximum of 80ºC by induction method immediately before application.

  The shop applied linepipe coating, adjacent to field joints shall be decontaminated as above.

  If salt contamination of the steel surface is suspected, tests shall be made for the presence of corrosion promoting salts. Testing shall be with potassium fern-cyanide test papers to BS 5493, Appendix G or approved alternative. Salts shall be removed and surfaces re-tested until no corrosion promoting salts remain. Salt contamination shall be removed with a solution of bio-degradable detergent in water.

3.2  Blast Cleaning and Preparation

  The blast cleaning standard shall be ISO 8501-1, Sa 2% unless specified otherwise. The amplitude of the profile of the blast cleaned surface shall be tested and shall be in the range 75 to 100m unless specified otherwise for a particular coating. All rust, scale, dirt and other contaminants shall be removed.

  Abrasive material shall be of the expendable type. Abrasive shall be stored under shelter and in sealed packing before use. Abrasive shall be of the correct particle size to achieve the specified profile and shall not leave any residue embedded in the profile of the blast cleaned surface. Sand shall not be used for blast cleaning.

  Expendable abrasives shall not be recycled and shall be free of contaminants, such as chlorides and other soluble salts, metallic copper and not more than 2% by weight of copper oxide.

  All dust, abrasive, debris and accumulations shall be removed from the blast cleaned surfaces before coating begins by vacuum cleaning, blowing with clean and dry compressed air, or with clean brushes.

  Nozzles for blast cleaning shall be of Venturi design and shall be discarded when wear reaches 30% of the original bore.

  All nozzles for blast cleaning shall be provided with remote control of the blast stream. The remote control mechanism shall be kept in good working condition and shall only be kept in the "on" position by the operator's hand during blast cleaning.

  Blast cleaning and preparation of the shop applied linepipe coating, adjacent to field joints shall be carried out in accordance with the approved procedures for the selected field joint coating material. The FBE landing and adjacent PE parent coating shall be sweep blasted to provide a key for the liquid applied field joint coating system. Hand abrading of the exposed FBE may be used as an alternative to sweep blasting (under no circumstances shall the FBE toe be completely removed during blast cleaning the intention is that the surface shall be roughened by the bias, process only). The PE coating shall be sweep blast cleaned for a minimum distance of 75mm from the edge of the field joint area to provide a key for the field joint coating.

  Where specified flame treatment shall be applied as a preparation treatment for the HDPE coating for a distance of 75mm from the edge, in accordance with an approved procedure. Flame treatment shall be applied on pipeline sections that are to be installed using horizontal directional drilling or thrust bore and on pipeline sections designated as having an operating temperature above 50ºC.

3.3  Power Tool Cleaning

  Power tool cleaning shall not be permitted as a general alternative to blast cleaning for field joint surface preparation. The use of power tools for localised areas may be permitted subject to approval by COMPANY of the relevant procedure.

3.4  Air Quality

  Compressed air for surface preparation (or coating application) shall be free of oil and condensed water. These shall be determined daily with a blotter test. If necessary, after-coolers shall be provided to reduce the water content to an acceptable level. Traps, filters and separators shall be regularly emptied and cleaned.

3.5  Ambient Conditions

  No final surface preparation shall be carried out when the following conditions exist, or are likely to occur in the near future:

—  temperature of the steel surface is less than 3ºC above the dew point of the surrounding air

—  temperature is outside the limits set by the manufacturer

—  air temperature is below 5ºC

—  wind is raising dust (unless work is being carried out under cover)

—  during rain (unless work is being carried out under cover).

  MANUFACTURER's recommendations for maximum allowable relative humidity shall be observed. In all cases, the required surface cleanliness grade shall be evident on the surface of the steel at time of coating application.

4.  APPLICATION AND REPAIR OF COATINGS

4.1  General

  A liquid applied field joint coating procedure shall be developed by the CONTRACTOR to ensure consistent quality specifically with regard to cure, film thickness, adhesion and low temperature flexibility characteristics.

  The coating system shall be urethane modified epoxy, SPC 2888 RG (manufactured by Speciality Polymer Coatings Inc.)

  All coating materials shall be mixed, applied and cured in accordance with this Specification and MANUFACTURER'S written instructions and datasheets.

  The coating shall not show a tendency to "curtain" when applied to a vertical surface. It shall possess good flow characteristics and give a smooth continuous film of uniform appearance. The applied coating shall have adequate adhesion, to steel and polyethylene, as proven by the adhesion test.

  The coating application process and repair technique shall comply with the established written procedure, which shall define all relevant details including: coating name, data sheets, pipe cleaning, blast cleaning medium and technique, surface quality, dust removal, coating application, curing procedure and coat stripping technique. The application procedure used during the pre-qualification testing once qualified shall be strictly applied and monitored to ensure consistent application quality.

  The shop applied linepipe coating, adjacent to field joints shall be decontaminated as described in 3.1 above. The surfaces of the FBE landing and adjacent PE parent coating shall be prepared strictly in accordance with the MANUFACTURER's instructions and the approved coating procedure. The PE coating shall be cleaned and prepared as stated in Section 3.2 of this specification. . All post application testing shall extend over the whole field joint area and the 75mm liquid coating overlap.

  Inspection and testing during production shall be as detailed in Appendix B of this Specification

  The coating materials shall be stored and applied by CONTRACTOR in accordance with MANUFACTURER's recommendations. An adequate proportion of the field joint coating material shall be provided in small packs. The coating system applied to a particular item or group of surfaces shall be the product of one MANUFACTURER.

  All coatings shall comply with proposed UK Department of the Environment regulations for Volatile Organic Compounds (VOC) content for year 2000.

4.2  Condition of Coating Materials

  Coating materials shall be delivered in their original, sealed, undamaged containers with name of MANUFACTURER, product reference, batch numbers, shelf life and storage requirements clearly marked. Containers shall remain unopened until required for use.

  Coating materials shall be stored in a safe, dry enclosure or building in accordance with local laws, MANUFACTURER's printed recommendations and Contract safety regulations. The storage location shall be adequately ventilated and containers shall not be exposed to direct sunlight during storage. With local high ambient temperatures, temperatures within enclosures/buildings shall be maintained in the range as recommended by MANUFACTURER. Materials shall be handled in such a manner to prevent damage or contamination that would make them unsuitable for use. Any material, which exhibits evidence of contamination or deterioration, shall be rejected.

  Field joint material products shall be used in chronological order of the date of manufacture. Coating materials whose shelf life has expired shall not be used. Coating materials, which have deteriorated during storage, shall not be used. In all cases where deterioration is suspected, the MANUFACTURER's guidance shall be obtained.

4.3  Preparation of Coating Materials

  Individual components of two-part (or more) coating materials shall be mixed strictly in accordance with MANUFACTURER'S requirements and the approved procedure.

  Particular attention shall be paid to adequate mixing to ensure that all components are fully dispersed in the medium prior to application. Materials shall not become fouled or contaminated, or allowed to thicken unduly from evaporation.

  The pot life of coating materials shall be noted and monitored. Any mixed coating material, which has exceeded its pot life, shall be discarded regardless of the apparent condition.

4.4  Coating Application

  Field joints shall be prepared and coated only after the joint has been radiographed, visually inspected and accepted by COMPANY.

  Coatings shall be applied to surfaces that are free of dust, moisture, oil and grease, residues of welding, salt, mud, rust staining and any other form of contamination.

  Immediately after the surface preparation to the required standard, the coating shall be applied in a single coat to a thickness in accordance with section 4.5 of this document and the MANUFACTURER's recommendations. The coating shall extend over the prepared "toe" of FBE and the prepared 75mm of PE at each side of the joint. A uniform coat shall be applied.

  The coating system shall be hand applied using a roller, although spray application may be used. Spray application, however, shall not be used on pipeline sections designated as having an operating temperature above 50ºC.

4.5  Thickness Tolerance

  The dry film thickness of the coating shall be a minimum of 750 microns and a maximum of 1,250 microns. While the thickness of the coating in some areas may exceed the stated maximum limit, any which exceeds the MANUFACTURER'S recommended maximum shall be grounds for removal; and reinstatement of the coating. CONTRACTOR's procedures for thickness measurement shall include proper calibration of equipment and for the use of suitably qualified personnel.

4.6  Repair of Coatings

  Repairs to coatings shall be carried out in accordance with the approved procedure. Repaired areas shall match the properties of the main coating. All repairs shall be holiday tested.

  Defective and damaged coatings shall be removed by scraping, abrasive disking or sweep blast cleaning until a surface suitable for repair coating is obtained. Overall preparation shall be used if it is not possible to identify local areas of damage.

  Areas of damage exposing the substrate shall be prepared by spot blast cleaning and then coated again fully. Areas of damage not exposing the substrate shall be washed down, allowed to dry, the edges chamfered (without damaging underlying coating layers) and the coating repair system applied.

  The first 25mm of intact coating surrounding the damage shall be feathered to a fine edge by sanding or disking taking care not to damage underlying coatings.

  At cathodic protection cable connection points made at field joints (minimum distance between circumferential weld and cable connection point shall be 75mm), the damaged coating shall be repaired with a liquid applied repair grade material in accordance with an approved procedure and holiday tested. The coating shall extend over the connection point and onto the cable insulation.

5.  INSPECTION AND TESTING BY CONTRACTOR

  The inspection and testing requirements are as described below and as summarised in Annex A for prequalification testing and Annex B for production field joints.

5.1  Environmental Conditions

  The following shall be measured and recorded at least four times a day, including once at the start of each shift, and shall relate the values to the requirements of this Specification:

—  dry bulb temperature (hygrometer)

—  wet bulb temperature (hygrometer)

—  dew point

—  relative humidity

—  substrate surface temperature.

5.2  Visual Inspection

  Each field joint shall be visually inspected after application of the coating. The field joint coating shall consist of a uniform film that is free of runs, sags, misses, dry spray, blisters, pinholes, poor bonding, laminations, porosity, air entrapment at welds and is uniform in colour and properties when cured. There shall be no visible runs, sags or bubbles. The examination shall include checks for soft spots.

5.3  Holiday Testing

  After application of the coating, field joints shall be 100% holiday tested generally in accordance with NACE RP0274. All post application testing shall extend over the whole field joint area and 200mm onto the parent coating. The holiday test shall be carried out at 4 KV, using a portable instrument. A fine wire metallic brush electrode shall be used with a travel rate of 300mm per second. Equipment shall be earthed as recommended. CONTRACTOR's procedures for holiday testing shall include details of calibration techniques. The maximum number of acceptable holidays per field joint or coated item is four. If two consecutive pipe joints show more than two holidays, the cause shall be investigated immediately. If four consecutive pipe joints fail, the coating process shall be stopped until the cause is determined. Pipe joints with more than four holidays shall be stripped and re-coated. All holidays shall be repaired and re-tested.

5.4  Thickness Testing

  The coating thickness over bare steel at every field joint shall be measured at five equidistant locations and recorded. Every reading shall be in accordance with Section 4.5. The coating thickness instrument shall be calibrated hourly.

5.5  Impact Resistance

  Once fully cured, the impact resistance of the coating applied over bare steel shall be tested to ASTM G14 and shall withstand an impact of at least 1.5J without a holiday being caused (J = 9.81 * impact height (m) * impact weight (kg). Frequency of testing shall be four locations 50mm apart on the crown of the pipe every 100 joints. Test will fail if a holiday is found at any impact test site. Holiday test to be carried out as defined in 5.3 above. If impact resistance is found to be below the required value then further tests shall be carried out to determine the reason for failure and the coating process modified to conform to the requirements of this document. All affected items or field joints between the failed item or field joint and the last acceptable test location shall be stripped and re-coated.

5.6  Adhesion Strength

  The adhesion of the field joint coating shall be determined at all three interfaces at ambient temperature at two locations by the "St Andrews Cross" method. Using a sharp knife two straight incisions shall be made in the coating through to the steel, the FBE or the PE, as appropriate. The incisions shall intersect at an angle of 30º/150º The coating shall resist disbondment when attempts are made to lift it from the 30º angle with the point of a sharp knife. Tests shall be carried out at the frequencies required in Annex A and B.

  Adhesion of the field joint coating shall also be determined after hot fresh water soak at 50ºC for 21-28 days.

 

Ranking	Result
Fails adhesively as a complete	0
Pees in large pieces adhesively from substrate	1
peels in small pieces adhesively from substrate	2
Peel cohesively in large pieces	3
Refuses to peel or peels cohesively in small pieces	4

  The coating shall be considered a pass if the adhesion strength determined from the above table is met as follows.

  Over PE- Minimum result: =/> 1

  Over Steel and FBE, Minimum result: =/> 3

5.7  Penetration Indentation Test

  Three samples shall be cut from three separate field joints, and tested for resistance to indentations in accordance with ASTM G 17. The test shall be performed at design temperature of 23ºC and 74ºC. Maximum penetration depth exhibited after testing shall not exceed 5% of the coating thickness. The test result at 74ºC is for information only.

5.8  Hardness

  The hardness of the coating layer shall be measured according to ASTM D-2240-91. The minimum value shall be 80 Shore D. The test shall be carried out on the fully cured coating.

5.9  Cathodic Disbondment Testing

  Pre-qualification cathodic disbondment testing shall be performed for 28 days at an electrolyte temperature of 23ºC and 74ºC (~ 2ºC). Electrolyte shall be 3% NaCl in ionised water. The Holiday size shall be 6 mm. The acceptance criteria shall be 6 and 8 mm respectively average radial disbondment from the edge of the predrilled hole. The test shall be performed in accordance with CSA-Z245.20-M92. The test result at 74ºC is for information only.

  The Contractor may propose alternative cathodic disbondment test standards (eg ASTM G42) and methods, providing the essential requirements of this Specification are retained. Any such alternatives shall be submitted to COMPANY for review and approval.

Table 1 APPROXIMATE DESIGN ENVIRONMENTAL DATA

Design life	40 years
Pipeline material	API 5L, longitudinal seam or spiral welded linepipe
Pipeline wall thickness	12.7 to 23.8 mm approx
Pipeline design temperature	Maximum service temperature 74ºC
Pipeline construction method	Laying in open trench with subsequent backfilling (some HDD and thrust boring possible)
Concrete weight coating (special crossings)	Applied by mould or compression coat process
Protection potential range of steel ("instant off" value), versus Cu/CuSO4	more negative than minus 850mV to of the order minus 1,200mV
Coating defect surveys (full pipeline)	holiday testing at mill and prior to laying. Direct current voltage gradient after laying. Coating defects to be repaired.
Soil temperature, 1m depth	0ºC to +35ºC
Soil types	typically wet, with clay and gypsum possible (wet/dry cycles possible) some areas stony and rocky
Soil resistivity	Can be below 10ohm.m (severely corrosive)
Water table	1m assumed
Temperature in shade (air), in direct sunlight	-26ºC to +43ºC, +78ºC max
Elevation, m	up to 3,000 above MSL
Relative humidity	100% max
Environment air quality	exposed—corrosive to non-polluted—non corrosive wind borne salt and sand very fine clay-like dust

Annex A

INSPECTION/TESTING SUMMARY, PREQUALIFICATION

LIQUID FIELD JOINTING MATERIAL

Property	Relevant Clause	Acceptable Values	Number of Tests*
Before Cleaning
Pipe condition	3.1	No weld spatter, sharp edges, surface clean	Full surface each joint
Chlorides	3.1	No chlorides	2 locations each joint
Oil contamination	3.1	No indications of oil contamination	Full surface
After Cleaning
Cleanliness	3.2	Sa 2	2 locations each joint
Profile	3.2	75-100 m	4 locations each joint
Chloride	3.1	No chlorides	2 locations each joint
Dust, Oil & other contamination	3.2	No indications of dust, oil or other contamination	Full surface each joint
AFTER COATING
Visual Examination
Field joint coating	4.1	Test for cure ASTM D5402.	Random each joint
Visual Examination
Field joint coating	5.2	Free of runs, sags, misses, dry spray blisters, pinholes, soft spots etc.	Full surface each joint
Coating Thickness
Field joint coating	4.5	750m-1,250m	5 locations each joint
Holidays
Field joint coating and over	5.3	No holidays (4 KV)	Full surface each joint PE
Adhesion Strength
Over PE	5.6	Refusal to lift, no separation of layers	2 locations each joint
Over Steel	5.6	Cohesive, no lifting	1 location each joint
Adhesion Strength/Hot Water Soak Test
Over PE	5.6	Refer to section 5 . . .	1 location each joint
Over . . . Steel	5.6		1 location each joint
Impact Resistance
Over Steel	5.5	. . . (minimum) ASTM G14 and to failure, report impact values	4 locations each joint
Penetration (indentation)
Field joint coating	5.7	5% of coating thickness maximum, at 23ºC  and 74ºC	1 location each joint
Hardness
Field joint	5.8	Minimum value: 80 Shore D	1 location each joint
Cathodic Disbondment
Field joint coating	5.9	28 day test—Average radius of disbondment <8 mm @ 74ºC and <6 mm at 23ºC	1 location each joint
DESTRUCTIVE TESTS
Flexibility Bend Test
Field joint coating	4.1	At ambient and at minus 30ºC. No cracking/disbondment or pinholes	1 location each joint

* Number of Tests can be increased at the sole discretion of the COMPANY. Surplus pipe shall be ordered to allow for losses due to testing.

Annex B

INSPECTION/TESTING SUMMARY, PRODUCTION

LIQUID FIELD JOINTING MATERIAL

Property	Relevant Clause	Acceptable Values	Minimum Frequency*
Before Cleaning
Pipe general condition	3.1	No dents, scabs, slivers, burrs, gouges etc	Each field joint
Chloride	3.1	None	1 per 10 pipes at 3 locations
Oil	3.1	No indication of oil contamination	1 per 10 pipes
Blast Cleaning
Grit type and size	3.2		Random
Pipe condition	3.2	Conditions AandB of ISO 8501-I	Each field joint
Surface profile	3.2	SA2.5 with anchor pattern 75 to 100µm	Each field joint
Relative humidity	3.5	<85% unless pipe is heated above DP	Each field joint
Elapsed time	3.5	Relative to Humidity	Each field joint
After Cleaning
Cleanliness	3.2	Sa 2.5	Each field joint
Profile	3.2	75-100 µm	Each field joint
Chloride	3.1	No chlorides	1 per 10 pipes
Dust, Oil and other contamination	3.2	No indications of dust, oil or other contamination	1 per 10 pipes
COATING PROCESS
Pipe pre-heating	4.1	Max pre-heat 80ºC (pre-heat dependent upon environmental conditions)	As required to promote cure
AFTER COATING
Visual Examination
Appearance of coating	4.1 and 5.2	No surface defects or soft spots	Each field joint
Longitudinal Welds		No air entrapment	Each field joint
Coating Thickness
Field joint coating	4.5	750m -1,250m	Each field joint. 5 locations
Holidays	5.3	No holidays (4 KV)	Full surface each field joint
Adhesion
Over PF Over steel	5.6		1 per 100 joints, 3 locations, one over steel and 2 over PE, ie one each side of welded joint
Impact Resistance
Over Steel	5.5	...-J (minimum) ASTM G14	1 per 100 joints

* COMPANY reserves the rights to increase inspection and testing frequency if warranted by the circumstances.

BP CASPIAN DEVELOPMENTS

AGT PIPELINES PROJECT

REVIEW OF FIELD JOINT COATING SPECIFICATION No. 410088/00/L/MW/SP/015 (issue 02.10.02)

  All comments made in this document reflect the fact that BP have named the coating product to be used, with no alternatives to the contractor.

  1.1.2  "The external coatings shall be suitable for the operating conditions to which they are subjected and shall have proven good resistance to cathodic disbondment".

  BP must therefore have clear, incontrovertible proof that the named product will meet this clause. 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, and of course its suitability must be validated for the design life of the pipeline, namely 40 years PLUS.

  2.2  "The contractor shall fully comply with the HSE requirements of the contract. Contractor shall ensure that all work and storage is performed in accordance with all applicable laws affecting health and safety at work and follow recommendations of manufacturer".

  BP must have already subjected the named product to detailed chemical analysis and COSHE risk assessment and be satisfied that there are no health and safety risks to personnel in the use of this material and no risk to environment particularly as the epoxy will be mixed and applied on open site where the pipeline crosses waterways and over shallow aquafers. More than 500,000 litres of the liquid epoxy will be imported if all the joints are coated this way. It will all be transported by truck to point of use. Accidents will happen. Spillages will occur.

  2.4  "Contractor shall provide the following procedure where applicable: Coating materials, storage, application and repair, . . . Measures to be adopted during periods of adverse weather".

  BP are specifying, by name with no alternative, the coating material. The construction work will take place in ambient temperatures from +40 to -20 degrees C. BP must know therefore how this material behaves in this temperature range.

  The contractor by definition is a pipeline builder not a paint technologist. He must be instructed in the proper use of the nominated product.

  The reality is that epoxies do not normally cure at 5ºC or below and amine materials crystallise at 0ºC and cannot be reconstituted.

  What is "adverse weather"—rain, snow, high wind, low temperatures, high temperatures?

  Company is nominating the product to be used but not now to use it, is this because the company does not know how to use it in "adverse" conditions? The contractor who will never even heard of this material before, certainly will not know how to use it and will be within his rights to ask for instruction.

  NOTE—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.

  It therefore cannot be considered as "best industry practice" or even "normal industry practice" so how can contractor be expected to produce definitive procedures and how will company be able to agree validity of procedures if it does not know how to use the material anyway?

  2.6  "Two full field joints shall be prepared and coated under conditions that replicate those expected in the field; one joint shall be coated by spray method and the other by hand using a brush or roller".

  BP tested the product applied by spray and brush. No testing was carried out at Advantica on roller applied material.

  3.1  "After cleaning, unless otherwise approved, the field joint shall be uniformly heated to 80ºC to remove all moisture and to preclude any condensation of moisture on the surface after blast cleaning. Also if environmental conditions require it, the steel substrate shall be preheated to a maximum of 80ºC by induction method immediately before application".

  Will this heating procedure remove all moisture from undercut areas? Has it been tested? How are we defining the requirements of "environmental conditions"?

  Heat, cold, wind, rain, snow? When is secondary preheat required? The contractor cannot be expected to know, he must be instructed.

  3.2  "The FBE landing shall be sweep blasted to provide a key for the liquid applied field joint coating system. Hand abrading of the exposed FEE may be used as an alternative to sweep blasting (under no circumstances shall the FBE toe be completely removed during blast cleaning the intention is that the surface shall be roughened by the blast process only). The PE coating shall be blast cleaned for a minimum distance of 75mm from the edge of the field joint area to provide a key for the field joint coating."

  Leaving an exposed toe of FBE at the cut back on three layer coated pipe has been a standard practice for some pipe coaters for some time. Eupec have provided this on the BP ACG Group offshore pipeline, of their own volition. They refer to it as the "WEATHERING TOE", its use has arisen out of undercut problems being experienced at the cut back areas on three layer coated pipe when stored for some time before use. However, the toe that they offer is between 15-50mm long with no guarantee on thickness. Bredero and PPSC are installing the same end cut equipment at the Kuantan plants.

  The FBE toe provided to BP will vary in length and very significantly in thickness. Some toes will only have a few microns of FBE over the original blast profile and some will have significant traces of PE copolymer left on. Clearly this specification does not recognise this. An assumption has been made that the toe will be present in a definably secure condition on every one of 500,000 pipe ends, it will not. No provision has been made for anything else. What action should be taken if the toe is not present? 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. Who pays?

  This last question is easy, BP pays. Why? Because experience over many years has shown us what happens to FBE coating cut backs and the contractor would be right in assuming that BP know how the exposed FBE will behave when pipe is stored. The reality is that BP do not know.

  Where the FBE has been "skimmed" so that only 0-100 microns is left on the pipe, then there is too little FBE left OVER the blast profile. This weak structure will take up moisture, corrosion will be initiated UNDER the FBE. When the field joint crew "dry out" the joint, as specified, this friable material will "fly" when blasted or abraded. Where corrosion deposits have formed beneath the FBE then it must be removed anyway! What should the contractor do in this circumstance? Obvious, ask for clients instructions, and any subsequent actions will be at the clients cost.

  Where the FBE is full thickness but with traces of copolymer evident, what action should the contractor take? You cannot peel the PE off, it is molecularly hooked to the FEE, to remove it you have to remove part of the FEE. What happens if, when wire brushing, all of the FBE is removed from part of the circumference? Does contractor re-cut end? How? Who pays?

  With regard to blasting the PE, this can only be done very lightly as the PE will "fly" if blasted vigorously.

  3.2 cont.  "Where specified flame treatment shall be applied as a preparation treatment for a distance of 75mm from the edge. in accordance with an approved procedure."

  What flame treatment and why?

  No testing was carried out at Advantica on flame treated ends.

  Experimentation has been carried out on heat treatment of PE by a number of authorities including this author who has tried radiant heating, selected spectrum IR heating and propane torching. Result—no discernable difference in adhesion of liquid urethanes and epoxies to PE. Why—because the root causes of the adhesion problem are not addressed in any way by flaming the PE, rather, the low energy aspect is made worse by flaming, not better!

  No change can be made to the non-polar nature of the PE, the epoxy exerts no chemical change at the interface so that only leaves the possibility of mechanical treatment of the overlap area as a means of improving adhesion. Why was this not tested/specified? Experiments have been conducted on all types of scarification, the information is available—but was not sought.

  "Flame treatment shall be applied on pipeline sections that are to be installed using horizontal directional drilling or thrust bore and on pipeline sections designated as having an operating temperature above 50ºC"

  Why? Adhesion, which is paramount for thrusts, is not changed by flaming, Flaming cannot improve performance regarding in-service temperature at all.

  The reality is that the epoxy will have very poor adhesion to PE at overlap areas and when pipe is thrust bored in cold weather the epoxy will come off.

  The "hot" areas will present a different but equally damning problem, thermal cycling testing has shown that the epoxy will crack circumfrencially at the transition area of original coating/steel. The reasons for this are clearly apparent but appear to have been disregarded.

  3.5  "No final surface preparation shall be carried out when the following conditions exist or are likely to occur in the near future; temperature is outside the limits set by manufacturer. Air temperature is below 5ºC".

  <5ºC will be experienced throughout the winter period. Should construction shut down for four months just because of the paint?

  Obviously the low temperature problem is a macro one. Can the work proceed if a local micro condition can be established at appropriate temperature? If so, why do we not say so?

  4 . . . "The coating application process an repair technique shall comply with the established written procedure, which shall define all relevant details including . . . , curing procedure and coating stripping technique . .  . "

  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? What work has been done to prove a stripping technique?

  4.4  "The coating system shall be hand applied using a roller, although spray application may be used. Spray application, however, shall not be used on pipeline sections designated as having an operating temperature above 50ºC."

  For the second time the spec calls for roller application when this was never at any time tested prior to issue of spec.

  When may spraying be done? Whose decision is it? What technique will be allowed? Manual or auto?  

  Spraying will cause some atomised emissions, has BP had this product and process subjected to COSHE risk assessment? If not, then how could this spec have been issued to contractors, we are in contravention of our own HSE rules.

  Why can't spraying be done on the "hot" pipes? It makes no sense.

  Lastly the product comes in two totally different forms for hand and spray application (see Advantica report) whichever the contractor buys then he can only use one application process. If he buys both—then mix up will occur.

4.5  "The dry film thickness of the coating shall be a minimum of 750 microns and a maximum of 1250 microns"

  Applying an amine cured epoxy in these thicknesses in one pass is totally outwith normal paint industry practice. The material is described as a "URETHANE MODIFIED EPOXY" but the HSE data sheet issued by manufacturer shows no iso-cyanate or other urethane components in the formulation. Applying epoxy to this thickness will render the cured film brittle. Flexibility is a primary requirement of all pipe coatings, lack of this quality will reveal itself when "snaking" pipe into the ditch in cold weather. Thermal cycling and strain polarisation tests over the coating/steel transition area reveal this materials lack of flexibility graphically. Test reports are in BP possession.

5.5  Impact Resistance

  The spec calls for this test to be carried out on the coating applied to the steel only. 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.

  Experience has shown this to be the case.

  The reality is that the brittle epoxy over a flexible PE will be cracked on impact In cold weather.

5.6  Adhesion Strength

  "The adhesion of the field joint coating shall be determined at all three Interfaces at ambient temperature at two locations by the `St Andrews Cross' method.

Adhesion of the field joint coating shall also be determined after hot water soak at 53 degrees C for 21-28 days".

  The St Andrews Cross test is a simple "watershed" test ie, pass or fail. The ranking system of result is on a scale of 1-5 or in this spec, 0-4.

  This spec states that a result of 1 on PE (Peels in large pieces adhesively from substrate) is a pass. It is not, it is a failure. It is clearly a failure in any other spec and to any recognised standard. Most of all, it is a failure if common sense is applied. No coating that peels off the substrate in large pieces can possibly be acceptable. What this spec recognises is the inability of the nominated material to adhere properly to PE. The acceptable result on steel is stated as 3. This is the minimum acceptable on PE.

  The evidence of this clause is clear regarding item 5.5 above.

  With regard to the hot water soak, do we test after 21 or 28 days or both?

5.7  Penetration Indentation Test

  "Test shall be performed at design temperatures of 23 degrees C and 74 degrees C. Test result at 74 degrees C is for information only".

  Pipeline will run close to 70 degrees C in places and the design life is 40 years PLUS.

  If test fails at 74 degrees it is a FAIL result.

5.9  Cathodic Disbondment Testing

  As above, spec says results at 74 degrees C are for information only.

  Pipeline is designed to run dose to this temperature for over 15,000 days!

  Failure to meet test criteria at operating temperature (or very close to it) can only be considered as a FAILURE.

CONCLUSION

  There are three elements to my conclusion:

1.  Implications of the form of the specification

2.  Potential contractual impact

3.  Final comment

  1.  It is clearly a serious mistake for BP to nominate one material only.

  We remove the contractors normal commercial negotiating ability with his suppliers. We assume responsibility for performance of the material. Comment is made above regarding the serious problems of transportation, storage, mixing and cure.

  In my opinion we are in contravention of European law with regard to restraint of trade. We must hope that no supplier of FJC materials takes this up.

  It is not normal BP practice to specify in this way.

  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.

  2.  There are many openings for the contractor to justify extraover costs. Clearly the use of the named material is going to lead to a serious problem, particularly during the colder months, with curing the applied paint. The joint areas are going to need cover and heat during preparation, application and curing. Storage at site will need to be in temperature controlled conditions. Freezing will render the material unusable.

  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.

  The performance of the epoxy is contingent on the 2" FBE toe being present. It wont be. Are we going to instruct contractor that if he removes any of the toe during blasting that he will have to re-cut the end of the coating? Because he will be removing some or all of this toe on many of the joints and it will not be his fault. He will be able to prove this very simply. Re-preparation of ends will be at our cost and we will have to instruct re process.

  Impact of backfill in cold weather will damage epoxy, particularly on overlap areas. Post lay overline survey will reveal damages through to steel. Who pays for repair? The contractor will be able to prove the weakness of the system in cold conditions. Costs for repairs could be astronomical.

3.  FINAL COMMENT

  I am at a loss to understand why this specification has been issued.

  Purely as a coating specification it is under developed and incomplete. As a field joint coating specification on a major pipeline it is utterly inappropriate as it does not confirm a protective system that can be successfully applied in all the conditions under which this pipeline will be constructed, nor does it confirm the integrity of the protection for the design life of the pipeline.

  It is by no means the cheapest option.

  The potential for claims against the company is open ended.

  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?

  Company needs to initiate action immediately in order to avoid a serious problem.

  Lastly I draw your attention to my comments re clauses 5.5, 5.6, 5.7 and 5.9. The wording of the specification is a tacit admission that the system cannot meet specific requirements of the pipeline. Have you considered the insurance implications of this?

Copy of letter from Derek Mortimore to the CEO—WorleyParsons

  I am in receipt of your company's report titled:

DESKTOP STUDY FINAL REPORT FIELD JOINT COATING REVIEW REDACTED VERSION

  This report is embedded in an Export Credit Guarantee Department (ECGD)—a division of the Department of Trade & Industry, UK Government, report on their lending to this project. Their report has been submitted to the Parliamentary Select Committee on Trade & Industry to the instruction of that committee who are currently investigating various matters. The committee have passed the documentation to me for comment.

  I understand that ECGD commissioned your company to carry out an audit of the engineering specifications on which the construction is based. Your re-written report is 24 pages long with six of those pages dedicated to attacking me. You have spent 25% of a so-called technical audit document attacking a man on the basis of inaccurate information from someone within BP and one document out of many I prepared for BP when working to their instruction. This is incredible. You did not contact me at any time, nor asked for any clarifications from me.

  Needless to say your uninformed comments are dealt with in uncompromising terms in my response to the committee as are your technical comments, both by me and also by a leading authority in the field.

  I enclose a copy of page 14 of your report and under item 4.1 you will see that you have made a number of comments about me.

  I highlight only two although I have dealt with them all in my formal response:

  You state "After he issued his comments he asked to be paid for his effort"—this is totally untrue.

  You state "Mr Mortimore's comments were fairly general with a lack of specific technical details or references"—they were not, they were very specific but as my document of November 2002 is now in the committee's hands, it is for them to decide the validity.

  You criticise me for making comments on non-technical issues. That was my duty. Your informant neglected to tell you that all of these issues had been discussed in BP's Baku office and I was specifically asked by my client to cover them in my review.

  Over the six pages of your report that you dedicate to me, you set out BP comments which were never made before in response to my original specification review. This is the first time that any of us have seen these comments. Clearly your informant had not bothered to tell you that but you then go on to make a number of your own comments. I will not detail further here but inform you that every single comment is responded to in my review document to the parliamentary select committee.

  I must state that I am appalled that a company of your standing has allowed itself to be used as the conduit for somebody's malice towards me.

  Your report clearly states that you did not verify any of the documents you were given neither did you verify the accuracy of any of the statements made to you by BP personnel, in view of this I would be pleased to receive an explanation of your actions.

  I hope you are aware that the committee sits in September and after they reach a conclusion in the first matter they are investigating, they then publish all the submitted documents on the UK Government website so our whole industry can read your uncalled for comments about me and my very detailed response and total rejection of your report.

  A copy of this letter is included in my submission to the select committee.

Derek N Mortimore

26 August 2004

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Prepared 4 May 2005