Pipeline Integrity Engineering, Designing, B

NORTHERN AREA WESTERN CONFERENCE –16TH - 19TH FEBRUARY 2004, VICTORIA, BC

NACE Northern Area Western Conference, Feb. 16 – 19, 2004, Victoria B.C. Session: Pipeline Integrity Engineering, Designing, Building, and Operating Pipelines to Comply With The Alberta Pipeline Act and Regulations and CSA Z662- Reflections From the Post-Mortem Analysis and AEUB Guide 66 (for System Integrity and Corrosion Control) Review Standpoints On Oversights, Shortcuts, and Shortcomings Existing in Industry and Regulatory Practices

Dennis R. Maki C&M Engineering Ltd. 2805 – 12 St, NE Calgary, Alberta, Canada T2E 7J2

Abstract The Conference Theme is “Reducing the Costs of Corrosion”, not “Slashing Budgeted Expenses for Corrosion Control”. Too often, in the course of developing and operating an oil or gas production system, accounting and budgeting principles supercede sound technical systems assessments as to what actual expenditures are necessary to design, build, operate and keep systems in top form throughout their life cycles to eventual decommissioning. In Alberta, all Pipeline Systems are required to be designed and operated in compliance with the Pipeline Act and Regulations; however both End User and Regulatory Body Gaps exist in ensuring compliance with these Statutes. This is to the overall detriment of safe and sound designs, construction, and the continuing operation of “corrosion under control” systems. The excellent short form resource information contained in the AEUB’s Guidelines such as Guide 66 should be consulted frequently - both to ensure that due diligence principles are followed with respect to the technical integrity of designs, and in the later safe and monitored operation of all designed and installed equipment.

1.0 Introduction

By way of offering a brief preface and introduction to all of those who may suffer confusion in separating natural laws in action versus financial planning wizardry and accounting groupthink, a few preliminary comments bear merit: -Corrosion is a natural reaction process that works on the unnatural; it will work 24 hours a day, 7 days a week on man-made materials, self propelled by the unnaturally high internal energy states placed within them from previous processing and manufacturing operations. Table 1 outlines the free energies of spontaneous formation of oxides from a number of industrially important metals, with the accompanying Table 2 listing the typical galvanic corrosion potential for the aqueous corrosion of the same metals. Under the conditions stated, gold is the only metal noted that does not tend to either oxidize or corrode but rather remain in the noble, metallic state. All of the others will environmentally degrade over time, and yield or give off energy in the process, with energy yields and degradation rates linked closely to the amount of energy that was originally needed to first reduce them from their original metallic ores. -Corrosion can never be eliminated, but through the application of scientific principles such as cathodic protection and well planned internal corrosion mitigation actions it can be reduced to economically low levels over the life of a system. -Cost reduction program pushes aimed at reducing ‘the costs of corrosion control programs’ will hit a target- but it will be the wrong target. As with all operations cost control efforts, overall objectives with respect to corrosion control costs must be to reduce but in conjunction with understanding regulations mandating the control of corrosion. The ‘reduced corrosion’ benefits, versus ‘outlay costs involved for corrosion control’ must be evaluated globally, and then carefully benchmarked and defined for all local situations. -The Laws of Nature pay no attention to accounting interpretations and budgeting cuts with respect to the degradation of man-made materials. In essence, Natural Law states, “You can’t win, and You can’t break even…(and further, …You can’t get out of the game)”. Understanding these facts is fundamental to developing effective corrosion control programs that will work properly throughout the life cycle of all man made and installed systems, and especially oil and gas pipeline systems. The following outline condenses frequently repeated personal observations and reflections concerning them from participating in some 100 to 150 component failure analyses per year over the last several years.

2.0 The Basics of Corrosion and Corrosion Control Corrosion of the iron within carbon steels follows a simple relationship; contacting the steel surface with water allows an ionic electrical current to set itself up, and completes a corrosion circuit; this results in the loss of iron at many localized points from the steel surface. In the absence of effective corrosion control systems, when water goes on, iron comes off- and once it has come off there is no economical, or practical, method of putting it back on again. External corrosion control mechanisms are successfully mitigated by ensuring the use of only high quality and tightly adhering coatings, careful field installation practices to minimize coating damage, and the design, installation, and proper operation of cathodic protection systems. They are well understood, and installation of the protection systems is typically Code mandated. Internal corrosion and corrosion mitigation processes are currently not well understood, and are only loosely referenced in current Codes. Wet gas is often shipped in dry design gas pipeline systems due to the customer service and revenue maximization objectives of producers and mainline pipeline companies. During their time of operation, many gathering and gas dehydration systems will upset from steady state operations and then deliver into dry gas transmission systems gases and liquids that do not conform to contract specifications, and short period gas quality relaxations are often granted to operators. However, short term water carryover problems can quickly give rise to long term gas quality nonconformances, and if no systematic corrosion detection, monitoring and mitigation programs are in operation, and capable of countering the effects of line upset conditions within lines that are supposedly “Dry”, internal corrosion in the systems can initiate and propagate rapidly. Of recent note in the USA, a major pipeline company believed that it was only shipping dry gas at a river crossing point in New Mexico and had a liquids collection unit installed upstream but did not have equipment installed downstream of the collection unit to check this assumption. Direct literature quotes are (1) “Board investigators found that the rupture was the result of severe internal corrosion”…”The investigation also revealed that the partial clogging of the drip upstream of the rupture location likely caused some liquids to bypass the drip”…and “At the rupture site, a bend in the pipe had created a low point in the pipeline where liquids and other residue accumulated and caused corrosion”…While the line was noted to be not amenable to pigging, the likely accumulation of liquids could have been foreseen and monitored by the installation of proper line bottom sampling equipment at a very low cost. Periodic checks would then have alerted the operators that the pipeline drip unit upstream was malfunctioning; not checking and correcting this situation at an early opportunity eventually resulted in a catastrophic incident.

Fundamental Point #1: Proper design control and corrosion management programs must be implemented prior to construction and early in the lives of systems in order to avoid system wastage and ruination. Latter day and spin management programs are not effective corrosion management programs and are easy to spot; they invariably involve extensive cost and economic analyses and recommend either major pipeline lining programs, partial or total system rebuilds, or both. Disaster control and spin management programs are not testaments to corrosion control but rather monuments to bad prior management, bad decision making, and a total failure to act to monitor and control corrosion at its initial, and most controllable, stages. 3.0 Engineering, Designing and Building Systems for Promotion of Corrosion Control When no provisions have been made upfront to install corrosion monitoring equipment as part of initial line construction and to initiate line monitoring as soon as fluids and gases are delivered into a line following line commissioning, internal corrosion of materials can and often will take place rapidly. Many production systems are overdesigned in size as a result of designers and eventual operators speculating that continuing or increased production volumes will later materialize. Conversely, pigging, chemical injection, and corrosion monitoring equipment locations are seldom included in the initial design concepts and built in due to cost pushbacks for items categorized as “frills”, and a general lack of awareness of the technical and operations necessity for the equipment (“it’s only corrosion, and we only want the system to produce for 5 years anyway”). Over time and with increased formation pressure drawdowns, all oil and gas production systems will produce more water. Maximizing and front-ending initial well productivity is often followed as an upfront cash flow technique with no consideration of the later substantial costs associated with excessive early volumes of associated produced waters. Rapid system deterioration and failure from the initiation and propagation of corrosion attack is a frequent consequence. Compounding the problem of inadequacies related to a lack of monitoring facilities installed in systems prior to system startup, are further and frequently observed (always preventable) construction approaches and oversights applied during the design process as weak attempts to postpone expected system deterioration, or to squeeze down initial capital investment costs: -

Adding section thickness to linepipe to ‘solve’ corrosion problems (real or perceived); this is not a substitute for a corrosion control program, and in most cases will not work to effectively control corrosion. Extremely fast acting corrosion mechanisms will often locally drill their way through the excess metal in thick walled pipe systems in only slightly more time than

for minimally designed thinner walled systems based on operating hoop stresses and pressure retention considerations alone. -

Lack of industry knowledge of what ‘Sour Service’ applications for sour liquids and sour gas system designs really are; ‘Sour Service’ is in fact a group of related services where components operate at varying stress levels and exposures to water in the presence of H2S within the fluids handled. Bulk hardness testing and documentation requirements such as ‘being below HRC 22 in hardness according to NACE’ are not satisfactory for many designs that use steels in continuous and aggressive exposures to H2S and water. Steel matrix cleanliness and quality requirements are not understood but are of critical importance for high H2S and highly stressed applications; simple hardness tests alone are meaningless for the acceptance and performance in sour service where failure may result from the presence of high quantities in general of small inclusions, or of only a few, but large, inclusions in the metal matrix (2).

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Decisions made to purchase materials for technically sophisticated designs (i.e. pressure containing components) based on the very lowest of Code requirements by non-technically knowledgeable and non-technically accredited members of Purchasing Departments; cost cuts made in these areas frequently result in the very cheapest of components being bought for an end use on the bases of price and delivery considerations alone.

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Unknown exact points of origin of offshore materials; an original plant of manufacture is often unknown or very difficult to determine, materials test reports may be scanty to non-existent, and procedures for the verification of component quality (through the manufacturing chain, up to and including the point of installation) similarly poor. Low specification and low cost steels, containing high levels of nonmetallics, are far more susceptible to aggressive forms of corrosion and degradation than materials obtained from known, quality manufacturers that have demonstrated a clear commitment to steel cleanliness.

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No Third Party Inspection of materials; Third Party Inspection in order to ensure conformance to an operator’s specification requirements has been virtually eliminated by Owner/Operator Companies a result of ongoing cost reduction efforts. Lack of intermediary inspection is a major quality shortcoming since many components used in commercial projects become treated as ‘off the shelf/stocked items’ and then sourced by distributors on price alone from manufacturers located in countries having no fundamental understanding of Canadian system designs and/or design requirements.

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Inadequate general fabrication procedures; few owner/operator companies that will run systems built by EPC Firms review for code

acceptability (or contract out for Third Party Review) all aspects of end fabricator submitted procedures in order to confirm their technical suitability. Fewer companies still then issue written engineering acceptances for the procedures prior to their actual use on sites during construction. -

Transition piece design and fabrication procedures are not well prepared or audited; the welding of thin walled linepipe or fittings to heavier walled riser or above ground piping sections is seldom engineered comprehensively and to the Code extent required. Stresses between thin and thick walled components should be moved away from sharp component to component thickness changes, not focused right at and over the weld zones. For complicated transition welds (where both different piping code materials and thicknesses are employed) detailed side-to-side weld hoop stress calculations are required in order to ensure that all the requirements of separate Codes meeting at a transition location are achieved.

Fundamental Point #2: Do it right the first time, and don’t scrimp - retrofitting systems for corrosion monitoring and control, and/or rebuilding them after a failure is very expensive, time consuming, and in most cases futile at such points in time since most of the cumulative system damage will have already taken place. If there is enough money in a corporate capital or operations budget to retrofit a system for corrosion control or to rebuild a system properly after an uncontrolled pressure incident, then there is enough money in the budget to think through a proper design and perform a proper installation in the first place. 4.0 Pipeline Operation and Maintenance Manuals For Corrosion Control and as Operations Quality Documents, and the Ongoing Use of AEUB Guide 66 as a Check on Adequacy The AEUB’s Draft Pipeline Regulation of 2003-04 (3), as per Clause 7(1) of this document, states: “The licensee shall prepare and maintain a manual or manuals of pipeline operating, corrosion control, maintenance, repair and integrity management procedures and shall submit a copy to the Board on request”. While this wording is somewhat different than the wording contained in the currently operable Pipeline Regulation, it indicates that a thorough engineering and documentation approach will shortly become a regulatory requirement in Alberta for the ongoing operation of oil and gas pipeline systems. Properly prepared and effective Operation and Maintenance Manuals and plans as referenced in the revised AEUB Pipeline Regulations should provide attention to and a full treatment of all of the points contained in AEUB Guide 66 (4) on Pipeline Inspection and Analysis of Pipeline Failures. Well written Operation and Maintenance Manuals are, by their very nature, good Quality, Quality Systems, and Documentation Control Sources. These Quality Systems will cost money -

but investments made in them will be returned many times over during the life of facilities through eliminating operations problems and incidents, lowering downtime and shut in time, avoiding imposed legal and regulatory actions, and maintaining systems and materials in prime condition for eventual reuse or resale. The above stated, the effective use of Pipeline Operation and Maintenance Manuals in Alberta has been observed to be limited at the current point in time by the following: -

It is doubtful that most Operators (there are over 1,000 recognized operations entities in Alberta alone) have prepared and have available on either a site specific or a generic basis - these Operation and Maintenance Manuals for use in and with the daily operation of their systems.

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Where Operators do have written plans and documentation of system operations, in many cases they have not evolved into Living, Current Documents that are read, understood, followed, and continuously improved on by Field Operations Staff. It is also unlikely that the stale dated documents and references that may be in use fully represent either current and existing equipment designs or the actual operations procedures for the systems that they initially documented.

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Although it is noted repeatedly when design advice is given by corrosion professionals and later in practice during corrosion failure analyses, the greenfield inclusion of proper and effective pigging facilities (launcher and receiver units containing barrels long enough to accommodate pig trains) as part of initial systems production designs is a rare occurrence. This is always a major design oversight when they are omitted as the installation of effective pigging facilities during initial system construction, combined with their scheduled and ongoing use after system commissioning, is the single most important internal corrosion control method for any system.

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Initial pipeline commissioning and final pipeline suspension operations are not effectively executed; if Manuals and procedures do not exist, the result is usually seen in the last minute telephone calls made to corrosion consultants with the questions “How do I start up this System?”, or “How do I suspend and mothball this System?”

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Procedures for Line Repairs will only be properly followed if they are detailed in written form within a Pipeline Operation and Maintenance Manual; these procedures are seldom included.

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Ensuring that the overestimation, overapplication, and wastage of chemicals is avoided will provide high cost control benefits to all operators;

detailed calculations, however, are seldom performed by operators to confirm all supplier cost estimates and to optimize the applications, let alone verify (through accurate ongoing monitoring techniques) that the chemical used produces the desired effect as to corrosion reduction. Many corrosion control programs involving the use of chemical corrosion inhibitor applications are not well thought out and/or are completely undocumented – when a drum (210 liters) of gasoline currently costs approximately $140.00 Cdn, net of container charges, versus blended corrosion inhibitor mixes in the range of $500.00/drum, and the neat inhibitor itself at about $800.00 Cdn per drum, avoiding wastage and overapplication of chemical will justify the extra administration and scorecard costs easily by itself. -

For companies that have in place Operation and Maintenance Manuals, the actual records keeping requirements and records filing instructions as outlined in the Manuals are often not administered or followed. Other than for accounting and royalty payment purposes, for many field operations areas overall records keeping can only at best be rated as poor to extremely poor.

Fundamental Point #3: Operating systems according to documented plans that are out of date is ‘somewhat’ better than operating to no plan whatsoever, but it is also similar to designing systems with specifications that are out of date. Neither using outdated specifications nor using outdated operating plans can be justified as being according to technically sound design or operations practices. Major efforts are required by most operators in order to put in place Pipeline Operation and Maintenance Manuals that can be audited and demonstrated to meet both requirements for their existence and actual tests of their ongoing effectiveness.

5.0 Existing Regulations, Regulatory Enforcement Shortcomings, and Areas Seen as Candidates for Continuous Improvement in Regulations and Enforcement Pipeline corrosion incidents in Alberta in 2001/2002 numbered 503, whereas in 2002 they numbered 563; this trend is not encouraging. (5) Past regulatory programs aimed towards deadlines for enforcement of governmental accounting, royalty revenue collection standards have been able to achieve virtually complete revenue compliance with their program requirements within a matter of months. Although this has been the case for revenue inflows, it has not been the case with respect to ensuring compliance with the Regulations for the design, construction and safe operation of the systems used to generate these revenues. Current enforcement inspections for pipeline matters in Alberta (Licensees operating pipelines in Alberta are responsible for complying with all

applicable Standards and AEUB Regulations) are conducted on the basis of operator track record, site inspection history, site sensitivity, and perceived risk as evaluated; there is no Regulatory Spot Audit Program for use by the Regulators to confirm the existence of Pipeline Operations and Maintenance Manuals, or to confirm (where they are available) that the procedures and programs contained within them are effective. Post mortem corrosion failure investigations must be conducted as noted in the AEUB’s Guide 66, but this is not a proactive quality process. Proactive quality processes emphasize the prevention of failures and bringing systems under control in a planned manner, rather than first efforts being directly tied to actual failures and the uncontrolled consequences that spring from them. Recommendation 21 of the 2003 AEUB Public Safety and Sour Gas Annual Progress Report (6) outlines an undertaking by the AEUB to review its requirements respecting older sour gas pipelines and the performance history of the pipelines to ensure that adequate attention is focused on the possibility of corrosion related or other types of leaks occurring. Unfortunately, actions for this Report Recommendation will again be prioritized based on the same criteria as for other evaluations; this is not encouraging, especially when leaks related to component failures of materials are concerned. These failures will likely happen in cases when the quality of the material in use is really not high enough for low temperature or sour service applications, or both, even though the materials may have met ‘the minimum requirements of the Code of the Day’. Of final and particular note with respect to corrosion and corrosion related failures for systems materials are unauthorized and non-design code materials substitutions; these DO occur, and are typically not noticed until after an actual failure (e.g. low quality/high temperature components substituted for components where high quality/low temperature specification items are mandated by Code). Complete site and end materials inspections prior to granting Licenses to Operate per AEUB Guide 66 for systems can catch many of these errors and ensure that they are rectified. Prior to undertaking further construction work in these situations it should then also be possible to also directly determine if proper engineering approval was sought and received in the course of the execution of the design change or materials substitution; actions should then be instigated (as a professional practice issue, and with a formal complaint directed to the appropriate professional registration body) if they were not. Fundamental Point #4: Bringing Regulations and procedures into effect with no clear and strong plans for their enforcement is a major Regulatory shortcoming. This is compounded by situations where there are no clear consequences outlined and enforced for cases where the Regulations or procedures are not followed.

6.0 Summary and Concluding Comments In the field of materials degradation, and in particular in those sub fields of materials degradation directly by and in direct conjunction with corrosion, it is important to remember that you can never win; the Laws of Nature cannot be reversed, and all man-made materials will eventually return fully to their natural states. A second impossibility is ‘breaking even’, since even the best, properly designed, engineered, and installed system will always be in worse than installation shape several years after commissioning. There are methods, however, to keep all systems ‘in the game’ and generating good net revenues long past their originally intended design lives; to ensure this (a very fine idea, since with corrosion and materials degradation ‘one can’t get out of the game anyway’) operators have to stay in the game as well- by applying effective corrosion mitigation programs and making the corresponding and appropriate expenditure outlays to ensure ongoing system serviceability and integrity. Codes such as CSA Z662 outline only minimum design and operations requirements for oil and gas systems in Canada, whereas Provincial Acts and Regulations often incorporate, modify, clarify and improve on these Codes. In addition to and as adjunct documents to Codes, Acts, and Regulations, useful documents such as the AEUB’s Guide 66 on Pipeline Inspection should be consulted and employed on a well thought out, documented, quality controlled, and rigorous basis to minimize the effects of problems springing from both human design oversights and the operation of the Laws of Nature that guarantee the ongoing degradation of materials. In the end analysis, only by invoking ongoing, technically suitable and auditable plans can design and operations shortcomings be identified and eliminated, and the natural tendency of all materials in systems to degrade be mitigated. Much progress in narrow technical areas aimed at limiting the actions of specific corrosion mechanisms has been made, but overall approaches to system management for the elimination of design faults and the mitigation of corrosion overall in systems are still too loosely tied together, inappropriately applied, and ineffectively monitored. To ensure that known problems will be caught and treated in a comprehensive manner, closing some remaining gaps in Regulations and Regulatory Enforcement are further required; only thereafter will overall objectives of reducing materials and corrosion failures, both on an ongoing and a yearly absolute and statistical basis, be met.

Table 1. – Free Energy of Formation of Metal Oxides (Per Oxygen Atom) at 227 Deg. C (500 Deg. K) in Kilocalories*

Metal in Metallic Form

Free Energy of Oxide Formation/Kcal.

Magnesium Aluminum Zinc Iron Nickel Copper Silver Gold

-130.8 -120.7 - 71.3 - 55.5 - 46.1 - 31.5 + 0.6 + 10.5

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* Brophy, Rose, and Wulff, The Structure and Properties of Materials, Volume II, Thermodynamics of Structure, (John Wiley and Sons, 1964), P. 147.

Table 2. – Galvanic Series of Metals in Seawaters, Measured With Respect To a Saturated Calomel Reference Electrode, Volts*

Metal in Metallic Form

Potential vs. SCE, Volts

Magnesium Aluminum Alloy 7072 Zinc Mild Steel Nickel Copper Silver Gold

- 1.65 - 0.88 - 1.03 - 0.61 - 0.10 - 0.36 - 0.10 +0.10

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* From Fontana and Greene, Corrosion Engineering, (McGraw-Hill, 1978) P. 274; Bolded information from John E. Hatch, Aluminium: Properties and Physical Metallurgy, (American Society for Metals, 1984), (Magnesium and Aluminum), P. 257; R. S. Treseder, NACE Corrosion Engineer’s Reference Book, (Houston, Tx: National Association of Corrosion Engineers, 1980) (Silver), P. 59; and Brush – Wellman Engineered Materials, Tech Briefs- A Guide to Galvanic Corrosion, (Brochure, 2003), (Gold).

References 1). M. V. Veazey, NTSB Reports Probable Cause of New Mexico Pipeline Rupture and Fire, Materials Performance, NACE, (April, 2003), P. 24 – 25. 2). Zhang, Thomas, and Wang, “Evaluation and Control of Steel Cleanliness – Review”, 85th Steelmaking Conference Proceedings, (ISS-AIME, Warrendale, PA, 2002) pp. 431-452. 3). “Draft Pipeline Regulation”, Alberta Energy and Utilities Board, Pipeline Regulation, May 2003. 4). “AEUB Guide 66, Pipeline Inspection Manual”, Alberta Energy and Utilities Board, November 2001. 5). “AEUB Field Surveillance Provincial Summary January – December 2002”, Alberta Energy and Utilities Board Statistical Series 57, May, 2003 6). “AEUB Public Safety and Sour Gas Annual Progress Report – April 2003”, Recommendation 21, P. 25