Program Schedule

Click on the presentation speaker and titles below to read the abstract.

Tuesday, February 24th
8:00 - 8:30 AM Keynote Speaker - Hennie Prinsloo - Passing the Baton
Track 1 - Cathodic Protection Track 2 - Corrosion Mechanisms
8:45 - 9:15 AM
Daniel Fingas - Seasonal Variation of Cathodic Protection Potentials

To assess the effectiveness of cathodic protection, pipeline operators typically measure pipe-to-soil potentials. These pipe-to-soil potentials are compared against known criteria, possibly with additional consideration for soil resistivity, microbial action, etc. One consideration which has not received widespread attention in the literature is the seasonal variation in pipe-to-soil potentials widely observed in the Canadian prairie regions. In some cases, potentials measured during the spring may show a pipeline is fully protected, while measurements at the same location during the summer would show sub-criterion potentials.

The process of determining protection status is critical to successfully applying the External Corrosion Direct Assessment (ECDA) methodology to a pipeline. A set of data consisting of monthly ON, instant-OFF, and depolarized potentials was measured on a distribution pipeline in central Canada. This dataset, supplemented by information about local weather conditions and rectifier operating conditions, was used to develop appropriate guidelines for considering the impact of seasonal variations on an ECDA on a nearby pipeline. It is expected that these guidelines may be extended in order to more accurately assess protection levels throughout the year based on a limited set of data.

8:45 - 9:15 AM
Scott Pavelich – Corrosion of Aluminum Alloy Aeration Tanks in Modular Wastewater Treatment Plants

Severe internal corrosion was identified in aluminum alloy aeration tanks (biological reactors open to atmosphere) located within modular wastewater treatment plant designs. After 1.5 years of intermittent service, the corrosion in the tanks led to nearly 45% wall loss, which was significantly shorter than life expectancy. Visual inspections, as well as detailed laboratory testing was performed in order to identify the cause(s) of the corrosion damage. This presentation will focus on the visual inspection and laboratory results of various structural components within the aeration tanks with the objective of identifying the corrosion mechanism(s).

The morphology of corrosion damage varied from location to location within the tank. On the walls hard yellowish-white tubercles were observed, often over tooling scratches, with pitting damage underneath. The floor and floor components, such as pipe stands and brackets, were covered with large sludge deposits, under which extensive pitting damage was observed. Internal structural components of the aeration tanks also exhibited significant pitting damage with complete wall loss near dissimilar metals – in these instances solid deposits were not as prevalent. In all cases the corrosion damage was non-uniform. A number of methods were used on collected samples to assess the metallurgy, chemical composition of the alloys, and the pitting damage. Optical microscopy (OM), metallography, scanning electron microscopy (SEM), energy dispersive x-ray spectroscopy (EDX), Fourier-transform infrared spectroscopy (FTIR), xray diffraction (XRD), and microhardness testing were all characterization techniques employed to assist in the investigation.

Based on the results of the laboratory testing and visual inspections, it was believed that the corrosion phenomena observed was largely due to under-deposit corrosion on the tank floor and walls, with mitigating factors at play in different physical locations. Other internal components suffered localized corrosion, which was exacerbated by galvanic corrosion and the distance effect. The possibility of microbial influenced corrosion (MIC) will also be discussed.

9:15 - 9:45 AM
Cecil Gordon & Case Muskens - An Introduction to the HVDC Guide addressing the Influence of High Voltage DC Power Lines on Metallic Pipelines

Whereas the interaction between AC power lines and metallic pipelines is the subject of national standards and guidelines that together cover both analysis and mitigation issues, when new HVDC power lines were proposed in Alberta, namely the EATL (Eastern Alberta Transmission Line) and the WATL (Western Alberta Transmission Line), it was determined that similar guidance was not available. The power transmission companies working with a committee representing oil and gas companies, pipeline companies, communication companies and power distribution companies responded and produced a guide for use in screening to identify those situations requiring further analysis and possible mitigation.

While the same electrical coupling mechanisms apply to both AC and HVDC lines, there are also significant response differences between them and by understanding steady state and fault phenomena that can arise within HVDC systems a proper approach to their analysis in the context of electrical coordination with metallic pipelines can be carried out. The purpose of the guide was to introduce HVDC systems with particular focus upon lines being built in Alberta, provide sufficient background information, and to provide users of the guide a systematic approach in dealing with analysis and mitigation aspects of HVDC system influences upon metallic pipelines. Both similarities and differences with AC lines are emphasized within the guide.

The paper will provide an overview of the guide and present examples of actual user-issued results.

9:15 - 9:45 AM
John Baron - Corrosion Mechanism Considerations in Relation to Use of Non-metallic Coatings/Linings for Equipment and Pipelines

Often when operators utilize non-metallic coatings and linings for oil and gas production equipment, corrosion of the substrate is considered to be of little concern. Usually this is the case in that effective coatings and linings should protect the underlying metal and prevent corrosion mechanisms from initiating.

However in some cases corrosion of the substrate should be considered, monitoring and inspection of coated and lined facilities is necessary.

This presentation addresses some of those situations in terms of corrosion mechanisms to consider and provides some examples where corrosion has occurred in coated or lined equipment and piping. It also places emphasis on considerations for operators with regards to inspection and monitoring of coated or lined facilities.

Morning Break (9:45 - 10:30 AM)
10:30 - 11:00 AM
Wolfgang Fieltsch - CP Considerations for Pipelines Subjected to AC Interference

The presence of AC voltage and current on buried pipelines requires special considerations in the design, operation, and evaluation of cathodic protection (CP) systems. Both sacrificial and impressed current CP systems can be affected by AC interference on the pipeline. The presence of AC can present a shock hazard at CP test stations and can damage rectifiers and other CP equipment. Typical ON/OFF potentials measurements can be affected when using dedicated grounding connected to the pipeline via DC decoupling devices. AC can influence the driving voltage of the CP system and the overall CP system life. Cathodic protection criteria also need to be re-assessed with an understanding for the risk of AC corrosion. Special considerations must be made from the sizing of the cables, AC filtering and over-voltage protection on rectifiers, to DC decoupling devices for the protection of isolation flanges. As AC interference and mitigation becomes more prevalent due to shared pipeline/utility corridors, CP professionals require an improved understanding of how to deal with AC/CP system interactions.

10:30 - 11:00AM
Sridhar Arumugam - Scale Formation and Internal Corrosion Prediction in Water Pipeline in the Presence of Dissolved Oxygen

In this study, the role of dissolved oxygen (DO) in internal corrosion and coloured water formation in a water injection system is presented. The presence of dissolved oxygen in the water injection pipelines favored corrosion scale formation. Iron release from corroded pipelines was observed to be the principal cause of coloured water formation in the entire water injection system.

The iron released from corroded pipelines were primarily in the form of ferrous/Iron(II). Colored water was formed when the Iron(II) ions oxidises to form ferric/Iron(III) ions. Corrosion of the pipeline releasing Iron(II) ions and subsequent oxidation of Iron(II) to Iron(III) ions were thermodynamically feasible in the water injection pipelines due to the presence of dissolved oxygen in the water.

The amount of dissolved oxygen contributing to corrosion reactions at the metal surface and the amounts of dissolved oxygen utilized during oxidation of the corrosion scales were predicted. It was concluded that increased oxygen content in the system doesn't necessarily translate into an increased corrosion rate as a part of which will be utilized in oxidizing the ferrous compounds in the corrosion scale.

11:00 - 11:30 AM
Len Krissa - Development and Application of a New Solution for Mitigation of Carrier Pipe Corrosion inside Cased Pipeline Crossings

Increasing emphasis is being placed upon control of carrier pipe corrosion inside cased pipeline crossings from both an operator and regulatory perspective. Inline inspection associated with pipeline integrity management programs has identified external carrier pipe corrosion inside casings. Many factors contribute to this corrosion concern. Systems designed to proactively mitigate corrosion inside cased crossings were not readily available. The desire for a proactive carrier pipe corrosion control system led a pipeline operator and a company expert in the manufacture and application of volatile corrosion inhibitor (VCI) chemistry to consider a new corrosion mitigation solution. This effort resulted in the development of a unique product designed to fill the annular space of a casing with a gelatinous product that proactively controls carrier pipe corrosion and prevents intrusion of water, etc. into the annular space. The gel filler has been applied inside cased crossings since late 2011. Electrical resistance (ER) probes have been installed through the casing vents and submerged in the filler to the carrier pipe surface. The probes are monitored remotely with automated technology. The corrosion rate data validates the effectiveness of the VCI filler. This new corrosion control solution produces an excellent opportunity to enhance the integrity of pipelines inside cased crossings.

11:00 - 11:30AM
Tom Jack - Molecular Methods and MIC – Where are we?

In recent years the availability of relatively fast, inexpensive DNA sequencing methods has enabled researchers to gain new insights into the nature and mechanisms of microbially influenced corrosion in a rapidly developing area. Some of these insights are already challenging conventional wisdom. This talk will review what these techniques deliver now and what they could deliver in the future for oil and gas operations.

Track 1 - Chemical Inhibition Track 2 - Asset Integrity and Facilities
1:00 - 1:30 PM
Joe Bojes - Corrosion Inhibitor Development Strategies for High Temperature Applications: Shale Plays and Thermal Recovery Operations

Corrosion inhibitors have been successfully used to mitigate corrosion in oil and gas wells and pipelines for more than 60 years. Historically, the maximum temperatures associated with deep, hot wells typically ranged from 120 to 150°C. These temperatures, along with the acid gases present (i.e. CO2 and/or H2S), often limit the number of inhibitors that can be used for such applications.

The technological advances in fracturing have led to the development of shale gas reservoirs where downhole temperatures as high as 200°C are not uncommon. Produced gas from shale gas reservoirs can contain CO2 levels approaching 20 mole%. In addition, corrosion issues have been identified in some stages of the thermal recovery of oil sands and heavy oil (e.g. SAGD production), originally considered to have few high temperature corrosion issues. The gas associated with these steam recovery methods also contains high concentrations of CO2 and often significant levels of H2S.

The number of corrosion inhibitors that are stable at temperatures of 200°C or more and provide effective protection in CO2/H2S environments is even more limited. Consequently, Baker Hughes initiated a structured product development strategy to identify materials that can be used to formulate “next generation” corrosion inhibitors for these high temperature applications.

This paper details the systematic process that was implemented to identify corrosion inhibitor intermediates that are thermally stable at temperatures exceeding 200°C, which can then be formulated into products that provide effective corrosion protection in these severe production environments.

1:00 - 1:30 PM
Daryl Foley - Risk Management for SAGD Facilities from Design to Operation

SAGD operations present unique risks that differ from traditional upstream oil and gas facilities. Identifying and managing these risks can begin from development of the Design Base Memorandum through to commissioning. Opportunities exist to utilize project staff and corrosion and materials experts in the early stages of a major project. The right involvement of personnel, processes and information extraction mandates can assist in defining equipment risks and appropriate mitigation and monitoring prior to operating equipment. Identification of equipment in scope, regulatory requirements and development of equipment integrity manuals support the live repository of risk management strategies on a system level. Piping circuits can be developed at the P&ID stage and assembled in maintenance management and inspection management databases. This process leverages the development of Integrity Operating Windows (IOW’s) that can be established in the DCS and setup in data management software. Competency requirements can be setup in management systems align the right skills to critical tasks. The right involvement early in design can reduce cost and increase the effectiveness of overall integrity management programs.

1:30 - 2:00 PM
Jody Hoshowski - Effect of Batch Carrier and Carrier Ratio on Corrosion Inhibitor Filming Efficiency

Batch corrosion inhibitors have a long application history of protecting gas and emulsion pipe lines. Along with the chemical composition of the pipe line contents, factors affecting corrosivity can include, but are not limited to, temperature, pressure, and fluid dynamics. Preparing the pipe line surface with cleaning pigs and applying the inhibitor within a chemical pill between application pigs is typically the most effective method. An often overlooked factor is the selection of the carrier, when required. The chemical composition, physical characteristics, and ratio (concentration) can influence the ability of the mixture to film the internal pipe surface. A carrier is considered a liquid that provides a means of inhibitor transport to the surface. Iit also aids in providing a pill size that achieves the recommended contact time. Carriers often include one of the following; diesel, crude oil, condensate, methanol, amongst others. In this paper, the term diluent is not used synonymously with carrier as a carrier is considered to provide both a solvent for and/or dispersion with the inhibitor.

Corrosion inhibitor products for the Canadian market usually consider properties, such as, viscosity, flash point, and thermal stability. Filming efficiency is the primary objective when formulating an inhibitor product, however, the cost and the hazards associated with the components are very important factors. The cost and the availability of the carrier can also be a factor to consider. The applicability of a carrier was determined through physical compatibility and corrosion performance testing. This paper describes the effect of the carrier and ratio on some of M-I SWACO’s batch corrosion inhibitor products. It was found that the effect is not insignificant and, in some cases, yielded results that influenced the selection of products, carriers, or ratios.

1:30 - 2:00 PM
Sankara Papavinasam - Aim Corrosion Management: Perfect Key Performance Indicators

Asset integrity management (AIM) is a process that ensures the assets perform effectively and efficiently for the entire duration of their designed life. In order to effectively implement an AIM process, all risks to the asset must be understood and kept to a low level. One of the risks to oil and gas infrastructure is corrosion. Therefore, corrosion management is a key component of AIM process.

In order to ensure that the corrosion risk is minimum, several key performance indicators (KPIs) must be established and tracked throughout the life of the asset, i.e., during design, construction, operation, and abandonment stages. Some KPIs are leading indicators (e.g., online monitoring) and some are trailing indicators (e.g., inspection).

This paper presents KPIs used to manage corrosion in oil and gas production environments. It explains why some KPIs are effective while others are not. It then discusses the opportunities and challenges in implementing KPI. The KPIs described in this paper are based on industry surveys and on more than 25 failure analysis reports.

Afternoon Break (2:00 - 2:45 PM)
2:45 - 3:15 PM
David Shong - Validating the Efficacy of an Integral Active Inhibiting Chemical Package Contained in Domestic Aggregate Pre-Forms to Combat Corrosion Under Insulation (CUI)

Several recent trends being promulgated in the industrial community are helping designers, owners and insulation contractors become more proactive in preventing CUI. One of these trends is to ensure metal jacketing installed over the insulation is properly detailed to create a predictable, weatherproof first line defense against moisture infiltration. Hydrophobicity of certain types of insulation has also been widely promoted as a means of preventing CUI through implication that decreased water absorption automatically translates into better corrosion inhibition. In the field, hasty installation, inadequate sealant maintenance and in-situ physical damage due to compression of certain insulations can create flaws in the jacketing that will eventually allow moisture ingress into the system. This paper identifies an integral active inhibiting chemical package in wide use since 2002 that relies on liquid water infiltration as a catalyst and thereby provides an additional factor of safety in the battle against CUI for the life of the insulation. It explains at a molecular level how this time-tested package integral to domestic calcium silicate and expanded perlite insulations engages a two-pronged defense against CUI (physical coating and pH buffering). It will also quantify recent third-party test results that compare the corrosion performance of several common industrial insulations as evidenced by their actual Mass Loss Corrosion Rates (MLCR) when tested in accordance with the latest ASTM consensus method adopted by all insulation manufacturers in 2005.

2:45 - 3:15 PM
Nick Marx - Tackling Competency "or" A High Level Approach to Tackling Competency in Facility Integrity

The presentation is designed as a high level approach that can be applied to any industry or skill set. It will cover:

  • how to determine the various competencies needed,
  • establishing the criteria for each,
  • setting up matrices by which to measure individuals' compliance to the applicable matrix,
  • documenting the findings of the measurements and
  • determining potential go forward steps.

It covers both the advantages and pitfalls of developing an appropriate competency matrix and program for any given organization.

3:15 - 3:45 PM
Melanie Reid - A Corrosion Micelle Detection Method for Optimizing Corrosion Inhibitor Field Dosage Rates

Film forming corrosion inhibitors play an important role in managing corrosion in oil and gas production systems. Here we describe a novel method for measuring their function-related dosage. The approach relies on exploiting the phenomenon of these inhibitors’ inclination for single molecules to aggregate into “micelles” in solution when present above a certain concentration and temperature, and the relationship between the aggregation state and molecular function.

Translated to the oilfield environment, we have used the detection of micelles as the basis of a diagnostic tool for understanding whether a film forming corrosion inhibitor is available in solution at optimum concentration or not. Following review of the theoretical basis, case studies will be presented covering production and injection fluids, oil and condensate.

3:15 - 3:45 PM
Eric Kubian - Application of an Integrated Data Management System for Monitoring the on-going suitability of Pipeline INTEGRITY management PROGRAMS

Implementation of an effective pipeline integrity management (PIM) program requires on-going monitoring of the current risk status based on the level of adherence to prescribed tolerances for mitigation, monitoring, inspection and operational parameters. This paper outlines how integration of data sources in a central database for attribute information relating to pipeline integrity enables on-going monitoring of operating limits, along with the ability to track the level of compliance to the PIM program.

The paper describes how changes in the conditions being monitored affect the overall risk score, and can be used to flag unmitigated conditions that require attention. Essential pipeline attributes are assigned limits which define the operating envelope applicable to the initial risk score. The operating envelopes are determined for each pipeline segment during the initial risk assessment, where the unmitigated susceptibility to all deterioration mechanisms (internal and external corrosion/cracking, geo-technical hazards, the potential for overpressure, and/or third party damage) is evaluated based on physical attributes and current operating conditions.

A central platform with a GIS interface allows for direct connection of production volume sources to individual pipelines. Flow rate, pressure, temperature and chemistry information from each linked data source is then apportioned to determine flow conditions throughout the network. On-going updates of the source information to the risk model allows for flagging of operating conditions which exceed the operating limits set in the original assessment. Excursions outside the envelope may invoke a change in the risk score, depending on the weighting index for the attribute.

In addition to operating limits for production, monitoring of on-going compliance to the recommended integrity management program can be achieved by centralising the pipeline database as the gathering point for on-going results from operational activities (such as pigging, application of batch or injected corrosion inhibitors, corrosion rate monitoring, inspections, cathodic protection system maintenance and right-of-way surveillance results). Conditions outside of the operating limits, and non-compliance to the implementation of the prescribed maintenance activities can therefore be tracked, and triggers can be set to alert for conditions which may contribute to an elevated risk score.

Examples will be given of how a centralised pipeline integrity management database, integrated with required data sources, can be utilised to prevent pipeline damage/failure occurrences, along with providing the analysis tools required for optimisation of integrity management program components.

Wednesday, February 25th
Track 1 - Material Selection Track 2 - Asset Integrity and Pipelines
8:00 - 8:45 AM
Daryl Foley - Thermal Industry Materials Selection Challenges and Opportunities

Thermal operations present many challenges with respect to materials selection largely due to the unique nature of the process in combination with temperature. All thermal operators seek to design the lowest cost facilities but sacrifice operability, reliability and maintainability in the process. Once in operation capital cost cutting reveals itself in the form of high operating costs and higher risk of equipment failure and limited resources to identify and mitigate. Idealized solutions with respect to material can hit obstacles with availability and cost. Opportunities exist but fabricators are slow to adapt and operators un-unified in their approach to evolve and request materials for similar applications.

This presentation discusses some of the challenges and opportunities with respect to materials and relates it to processes in a typical thermal facility.

8:00 - 8:45 AM
Caroline Carsted - CAPP Best Management Practices for Pipeline Integrity and Incident Analysis – Present and Future

The objective of this paper is to illustrate how the Canadian Association of Petroleum Producers (CAPP), through its longstanding Pipeline Technical Committee, develop and update Best Management Practices to address gaps that are identified by our annual Pipeline Incident Analysis.

In addition, the paper will also provide a line of sight on CAPP’s future plans with regards to Best Management Practices and Guidelines, particularly on the management of pipelines in High Consequence Areas, and how the harmonization of pipeline performance measurement in Canadian jurisdictions.

8:45 - 9:15 AM
Dilip Kumar - Designing for Refinery Sour Water Corrosion

Sour water is among the most corrosive fluids in refineries causing failures due to fouling, plugging, corrosion and localized thinning. Proper material selection is critical to avoid failures and ensure safety as well as integrity of the concerned units in a plant for the expected design life. There were instances in the past where designers had selected materials of construction without enough process stream details being provided. The results were significant corrosion and early failures.

In a few typical examples of equipment design, e.g. reactor effluent coolers (REAC) and sour water strippers (SWS), undertaken by Jacobs Engineering for different confidential clients, detailed analyses of process and operating conditions were performed. These included reviewing values of Piehl Corrosivity Factor, dissociation constants for both NH4HS and NH4CI, content of NH4HS and the amount of chlorides along with other stream properties. The analyses revealed that carbon steel material was inappropriate in general for the applications. This was further supported by corrosion rate estimates that showed high rate of metal loss for carbon steel for the prevalent conditions. Next, the choice of duplex stainless steel was also examined. Formation of NH4CI deposit was very likely in one example. Corrosion due to wet NH4CI could be severe in this case. This mandated using materials with high Pitting Resistance number (PREN). Immunity against chloride stress corrosion cracking (SCC) was also required. Based on this analysis, duplex stainless steel too was not suitable for this application. This had been substantiated by SCC failure of several duplex stainless steel air coolers. The suitable materials could be alloy 625 or alloy C-276 as both of them have PREN greater than 40 providing excellent pitting resistance and contain more than 40% Nickel imparting immunity to chloride SCC. If measures such as minimizing/removing NH4CI deposits by proper wash water system design, water quality control, control of NH3 and chlorides, etc. could be implemented, Alloy 825 and super duplex stainless steel 2507 could be considered as compromises; alloy 825 being a preferred choice due to its immunity against chloride SCC. Several success/failure cases were considered for the above material choices along with their service life expectancies. Final decision was taken in favour of the alloy 625 for the first example case (a REAC) after careful consideration of potential risks and costs.

In the second example case (SWS), there was a risk of corrosion by NH4CI deposits in the upper section of the tower and the overhead vapour stream. Hence the top section and the overhead stream including the overhead air cooler was designed with carbon steel + inconel 625 overlay or solid alloy 625 material.

In a third example (a SWS), the risk of corrosion by NH4CI was absent. However, high level of NH4HS was present in the sour water, calling for duplex stainless steel 2205 in the overhead stream of the stripper.

This paper describes the important considerations for designing pressure equipment and piping in refinery sour water service and discusses the example cases in detail.

8:45 - 9:15 AM
Hong Lu - Developing Pipeline CAPEX Budget Based on Risk Assessment

Risk assessment has been part of pipeline integrity management program in the industry. Penn West has developed an economic pipeline risk assessment method to prioritize pipeline mitigation strategy and repair decisions. The risk assessment method uses quantitative method to address failure probability, and economic term to address consequence.

In the implementation of pipeline risk assessment, more challenges or opportunities have been identified when pipeline CAPEX budget is developed. Major components such as regulatory compliance, pipeline risk, and mitigation strategy need to be incorporated in the budget program consistently among all fields. In a large pipeline system, this may not be straightforward, as a mitigation program in a large pipeline system is often based on operation field instead of individual pipeline. A universal standard or process for pipelines in all operation fields is needed to incorporate regulatory requirement, pipeline risk, and mitigation strategy into CAPEX budget. Economic pipeline risk assessment makes it possible to meet this challenge.

This presentation demonstrates Penn West’s concept and process to integrate pipeline risk, budget, mitigation efficiency, regulatory compliance, and mitigation strategy in developing CAPEX budget. The strengths of this method are that [1] it aligns with production so that it can be identified if the budget can be justified; [2] it shows the overview of all the major components about budget distribution; and [3] it aligns with corporate decision making and corporate goal.

9:15 - 9:45 AM
Gobind Khiani & Jordan Grove - Conflict Metals and Compositions

Conflict Minerals are certain minerals that have been linked to their derivates i.e. Columbite-tantalite (Coltan) it is a metal from which TANTALUM is extracted. Tantalum uses include electronic components, alloy making carbide tools and jet engine components. Other metals such as TIN, GOLD, TUNGSTEN and any other mineral or its derivates that the Secretary of State’s determines to be conflict.

In our industry we use Carbon Steel as a common metal in structural steel, vessels, piping, valves, plates, and many more equipment/s. The chemical composition of metal used and its grades can play a major role in performance of the equipment and process conditions.

Materials fail in service, however when metals crack suddenly during routine pressure testing or operation it is imperative to know what raw material has been used to produce the equipment, where is the ORIGIN of raw materials.

9:15 - 9:45 AM
Winston Mosher - Methodology for the Evaluation of Cleaning Pigs on Sludge Deposits from Corrosion Pits

For decades pipelines have been operated in remote and environmentally sensitive areas with as well as within populated locations. The occurrence of spill incidences is an indicator of the current state of integrity management of the pipeline industry, and plays major role in the declining public perception of pipeline safety.

Proper maintenance of pipelines can prevent internal corrosion of pipelines to a remarkable degree. The methods employed are primarily mechanical cleaning (pigging) and chemical treatment (corrosion inhibitors, biocides), often used in combination. It has been demonstrated that carbon steel pipe will not corrode to a significant degree if the surface is protected by a continuous oil or hydrophobic phase. Problems arise in areas of the pipeline where this phase is compromised, typically under localized areas containing sediments. These sediments tend to be an agglomeration of solids, waxes and water which can create an environment conducive to the growth of bacteria. These bacteria have been largely to blame for creating highly corrosive surroundings leading to pitting corrosion. The resulting pits then become ideal locations for sediment and water to gather and create deep and dirty localized pitting that cannot be protected through chemical treatment alone.

In an effort to increase the knowledge of the cleaning efficiency of typical pig designs at removing sludge debris from pre-existing corrosion pits, a novel test setup has been devised.

An oil flow loop has been constructed with the capabilities of launching a 4” (10 cm) diameter cleaning pig. The pig passes through a test apparatus, which houses flush mounted coupons with variously sized pits packed with mock sediment (sludge) comprised of silt, oil and water. Following pigging, the coupons can be removed and analysed via laser scanning techniques to measure sludge volume loss and maximum depth of cleaning. The pigs cleaning abilities will be compared based on both metrics and information will be gathered based on the profile of the sludge’s surface post pigging.

Morning Break (9:45 - 10:30 AM)
10:30 - 11:00 AM
Haralampos Tsaprailis - Understanding the Advantages and Limitations of Duplex Stainless Steels for Oil and Gas Applications

Proper selection of materials for the oil and gas industry is still the main concern for suppliers and operators. Ideally, a material should perform for the entire duration of the project within the limits of design and under the applicable environment. However, the environmental conditions for most assets change as a function of time (typically becoming more aggressive).

Duplex Stainless Steels (DSS) are one of the most common Corrosion Resistant Materials (CRAs) used in the oil and gas industry. DSS are normally used in environments where the traditional austenitic steels cannot withstand the aggressive environments or where the risk for failure is greater. They are preferred over more corrosion resistant materials (Ni, Co and Ti alloys), mainly because of their low cost, mechanical properties, weldability and availability.

The objective of this presentation is to present recent research and development regarding DSS. This presentation will include information on the development of new DSS alloys with the addition of new alloying elements that aim at improving their performance in the field. Additionally, the presentation will include case studies where the application of DSS in extreme environments was beneficial (including cladding). Finally, the authors will show some commercially available software and its application for the materials selection.

10:30 - 11:00AM
Pat Teevens - Petroleum Pipeline Integrity under the Public “Microscope”: The Essential Role of Internal Corrosion Direct Assessment (ICDA)

The pipeline industry in the developed world is increasingly realizing more intense and protracted regulatory, public and environmental scrutiny than ever before. It has been likened to the intense public debate of the nuclear energy industry of the 1990’s. Pipeline failures, leaks, ruptures, environmental pollution from releases, greenhouse gas emissions and the unfortunate loss of human lives have all culminated in a growing and sensationalized, media-promoted public distrust of pipeline operators in general. Focal to the argument against pipeline proliferation and associated system expansions, is the widening perception that pipeline operators have inconsistent and ineffective pipeline integrity management programs. Since most upstream production pipelines and a significant percentage of midstream transmission lines fail due to internal corrosion, it is absolutely necessary that technical competency in corrosion engineering and corrosion management systems including the personnel charged with implementing them, are non-negotiable attributes with respect to regulatory program expectations. This paper discusses the benefits and successes attained by methodically defining internal pipeline corrosion susceptibility through the 4-step internal corrosion direct assessment (ICDA) process for wet gas and multiphase fluids. The advantages gained from following the new and pending NACE International Standard Practices for DA, regardless of whether the line is piggable or not, result in the operator being confidently able to define the root-cause of their problem, the degradation rate or severity of internal corrosion and the implementation of an appropriate verifiable mitigation plan. This process results in elevating pipeline reliability, safety and operator confidence which can be translated into reducing public skepticism that pipeline operators are not proactively preventing corrosion-initiated releases.

11:00 - 11:30 AM
Jeffrey Xie - Duplex Stainless Steels as Metallurgy Upgrade for Heat Exchangers

Some of the heat exchangers at NOVA Chemicals facilities have experienced severe corrosion either at the cooling water side or at both the cooling water and the process sides. The life expectancy can be as short as 2 – 3 years due to corrosion. The corrosion issue not only negatively impacts the reliable operations of the plants, but also induces significant financial penalty due to shut down and replacement. There is an urgent need to mitigate the corrosion issue occurred on heat exchangers. Improvement on the water treatment is a very important approach and has been the focus of the mitigation program. Metallurgy upgrade is also being seriously evaluated as one option for the corrosion mitigation.

To assess the applicability of duplex stainless steels in the particular process conditions in the company, two duplex stainless steels grade 2205 and 2507, compared with carbon steel, brass alloy, austenitic stainless steels (SS304L and SS316L), are evaluated in cooling water, process water and simulated high corrosivity water (mimicking the corrosive environment of the process or under the deposit). The performance of the metals is investigated using electrochemical techniques and immersion test. Duplex stainless steels are confirmed to have hundreds times better corrosion resistance than carbon steel or brass in the corrosive environments, especially in the environment with high concentration of chloride and low pH. The evaluation provides solid basis for material selection process, and application of duplex stainless steels is initiated at the manufacturing facilities.

11:00 - 11:30AM
Weixing Chen - An overview of stress cracking of pipeline steels in near-neutral pH environments

Stress cracking of pipeline steels in near-neutral pH has remained a virile integrity risk for oil and gas pipelines. Although it was termed as stress corrosion cracking, crack growth has never been observed under a static loading condition. It was determined later that the cracking is driven by corrosion-fatigue mechanisms with some uniqueness. First, the loading frequencies are typically well below 10xE-3 Hz, which is beyond the scope of most fatigue investigations. Second, the rate of corrosion is typically well below 0.1 mm/year at which a premature failure solely by corrosion would occur much longer than that actually found in the field. Third, hydrogen, a by-production of corrosion, can be generated to a level at which hydrogen embrittlement may occur only under special conditions. This overview will discuss details on how the above factors are synergistically interacted to cause failures of pipeline steels in the field. Based on the understanding of the cracking mechanisms, strategies to mitigate field crack initiation and propagation will be introduced.

11:30 - 12:00 AM NACE International Update
Track 1 - Non Metallics Track 2 - Heavy Oil and Bitumen Facilities
1:00 - 1:30 PM
Afolabi Egbewande - The Case for Quantifying the Performance of Butt Fusion Welded HDPE Pipe Joints Using Toughness as the Quality Criterion

High Density Polyethylene (HDPE) piping materials are finding an increasing application in the oil and gas, water, power utilities, and mining industries. With wider use comes the need for more stringent control on the integrity of engineering piping made from HDPE. This paper will focus on the trifecta of challenges facing the HDPE pipeline industry: welding, non-destructive testing, and mechanical testing. With the goal of maximizing the integrity of HDPE pipelines throughout their design life (and potentially beyond it), design and fabrication elements of the governing codes will be critically assessed. Facing increasing government and public scrutiny, all new pipeline construction in North America, including HDPE materials, have additional challenges. The harsh climate of regions such as Canada, with wide temperature variations and seasonal ground movement, necessitates a stringent approach to HDPE pipe construction.

Hence, in Canada, unlike in most other jurisdictions around the world, design codes for metallic structures are toughness-based rather than strength-based. This unique approach developed from lessons learned over decades of dealing with integrity issues resulting from the harsh (cold) weather service environments for many engineering facilities in the country. However, this consideration has not been applied to design/construction requirements for HDPE and other polymer materials. For example, whereas CSA Z662 has very strict quantitative or semi-quantitative toughness requirements for steel structures, the code only requires tensile and bend testing for HDPE materials. CSA Z662-2011 makes no attempt to address this issue although there is a simple solution to this. Bend testing, either for fusion procedure qualification or production fusion joints, does not address the toughness issue either.

This communication reviews the shortcomings of current testing requirements, appraises their sensitivity to defect types that pose very significant integrity concerns and considers the integrity gains that could be potentially derived from including quantitative toughness testing requirements in the design code. The cost implication of such additional design/construction testing requirements will also be discussed. This exercise will help identify the key components of current welding, NDE, and mechanical tests that affect the integrity of HDPE pipes and propose future modifications to code requirements in North America in order ensure socially-responsible and safe pipelines.

1:00 - 1:30 PM
Ryan Wilkes - Heat Exchanger Failure Case Study: Understanding the Total Cost of a Corrosion Issue in the Oil and Gas Industry

The total cost of corrosion in the oil and gas industry is an often overlooked subject when evaluating the impact of an upset or failure due to corrosion. Costly issues can arise when as little as a single piece of equipment is not designed to properly mitigate corrosion. Not only is there a need to replace the failed piece of equipment but there are many other costs to consider, including, but not limited to: environmental and cleanup costs, safety related costs, unnecessary corrosion inhibition costs, and costs associated with potential future failures at other projects that have utilized similar designs and processes.

In this case study, Husky’s Tucker Lake SAGD facility is examined as it experienced two very similar failures in heat exchanger tubes within 2 years of each other due to a boiler feed water (BFW) tank without a nitrogen blanket and a low flow condition. High amounts of oxygen were able to dissolve into the BFW, which led to several problems downstream of the BFW tank, particularly in the tubes of the heat exchangers. The low flow conditions present in the system led to a buildup of deposits, which also aided in an accelerated corrosion rate.

1:30 - 2:00 PM
Blair Mack - Fiberglass Pipe / Glass Reinforced Epoxy (GRE) / Fiberglass Reinforced Plastic (FRP)

Steel pipe is an accepted tradition in oilfield piping applications. We must discuss the long term corrosion resistance and flow benefits of fiberglass pipe, versus common corrosion prevention methods associated with steel piping products, including initial construction costs compared to long term operational costs.

Common oilfield corrosion includes: Sweet Gas Corrosion (CO2), Sour Gas Corrosion (H2S), Oxygen Corrosion (O2), Hydrogen Penetration (HIC, SOHIC, Embrittlement), Erosion Corrosion, Galvanic Corrosion, Differential Aeration and Microbial Corrosion. Fiberglass pipe is also commonly used in extremely corrosive chemical and industrial applications where Acids, Caustics, Salts, Solvents, Chemical Process Solutions, etc. are found.

We will discuss fiberglass pipe as a proven alternative for oil, emulsion, produced water disposal pipelines, as well as downhole tubing, tank vapor collection piping, and facility process piping.

We will differentiate thermoplastic corrosion resistant alternatives such as PVC and HDPE, “spoolable” products and fiberglass pipe; which have similar corrosion resistant properties but differing physical properties.

Our goal is to outline the challenges relating to non-traditional materials like fiberglass pipe, specifically installation procedures / practices and engineering requirements. We will also cover methods of training, support and ancillary material supply.

We will point out fiberglass product options, based on varying resin systems for specific temperature and chemical services.

We will relate fiberlass pipe to common industry codes and practices; how piping standard codes apply to fiberglass pipe and the most common differences between fiberglass pipe and other materials as it relates to Quality Control, Engineering and Design Data, Product Data, Installation Manuals and Certifications and Approvals.

1:30 - 2:00 PM
Qiang (John) Liu - Mystery of SAGD produced gas corrosivity and corrosion mitigation strategy

In the steam-assisted gravity drainage (SAGD) process, casing gas from the producer consists of approximately 90% steam and 10% produced gas. The produced gas (PG) contains approximately 15% CO2 and 0.8% H2S with temperatures up to 180ºC. CO2 corrosion modelling predicts a corrosion rate of 600 mpy (15 mm/y). Mackinawite modelling predicts 270 mpy (6.75 mm/y). The prediction from both corrosion models indicates PG has very severe corrosivity at these conditions. However, results from corrosion coupon/probe monitoring in the associated pipeline indicated much lower corrosion rate (< 0.25 mm/y) at these high temperatures but a higher corrosion rate at cooler temperatures. Corrosion product analysis supported that a passivation film of pyyrhotite and magnetite was forming at temperatures above 90ºC. The new passivation mechanism is discussed through theoretical approach in this paper.

In addition to the corrosion caused by PG, methanol that was injected to the casing gas laterals for preventing dead legs from freezing also aggravated the corrosivity. A corrosion mitigation program was implemented that included the pigging, both slug and batch corrosion inhibitors, chemistry analysis, corrosion rate (CR) monitoring and non-destructive tests. The program was effective in reducing the corrosion rate to 3 mpy (0.075 mm/y) and the operational reliability of the pipeline was maintained.

Afternoon Break (2:00 - 2:45 PM)
2:45 - 3:15 PM
Brian Gray - General Quality Assurance and Non-Destructive Microwave Inspection of Thermal Butt Fusion Welds in High Density Polyethylene

There are currently tens of thousands of kilometers of installed HDPE pipelines in North America, and the use of the material on its own, and as a liner material to extend the usefulness of existing metallic lines, is growing steadily. HDPE provides a unique set of material benefits such as corrosion resistance, mechanical abrasion resistance and low hydraulic resistance, and is commonly used for fresh and produced water transmission as well as low pressure gas transmission applications.

Currently, HDPE pipelines are joined primarily by Thermal Butt Fusion in North America, with Electrofusion jointing popular in space limited areas and applications. Butt fusions are created by simply heating the pipe ends to melting temperatures and then pressed together under specific pressure conditions, then cooled under the correct geometry until the plastic can re-crystallize. The process is simple on the surface, but because of the complex nature of the crystallization of the material it is often a problematic process. HDPE pipelines are mandated through the CSA and ASTM standards to be tested through selectively destroying fusions and analyzing the results, as well as visually examining the weld beads created during the fusion process.

The principle objectives of this presentation are to offer a novel method with which to non-destructively detect and characterize the common defect modes in butt fusion welds, as well as to offer an alternative method to the currently accepted bend back testing which is used to destructively examine the fusions. Currently there are several ultrasonic techniques that have been proposed, which are only capable of detecting contaminants or large scale mechanical damage. Using the Evisive standing microwave technique, it is possible to detect changes in the index of refraction of the material, which is in turn caused by changes in the degree of crystallinity due to the fusion process. The Evisive microwave technique exploits the fact that the degree of crystallinity in a proper fusion is different than that of a poor quality fusion, even without the presence of actual defects, which are also detectable through the method.

In addition, this presentation proposes a field-level tensile test to replace the bend back testing for destructive HDPE examination. Tensile testing has multiple advantages over bend back testing, notably the fact that tensile testing in the lab is the only accepted method of qualifying new procedures, and a field tensile is capable of providing meaningful quantitative data that cannot be gleaned from a bend back test. In addition, tensile testing allows an appropriate examination of the fracture surface which allows for an investigation as to failure causes.

2:45 - 3:15 PM
Ankit Vajpayee and David Russell - Detection of Corrosion Under Insulation (CUI) using Advanced Pipe Inspection Technology

Corrosion under Insulation (CUI) is one of the most expensive issues our industry is facing today. For a reliability specialist in a hydrocarbon processing environment, this issue has the potential to be catastrophic. For example: refinery’s steel piping is subject to temperature fluctuations. Thermal insulation applied to the pipe or vessel mitigates the effects, but the presence of seams, gaps or other discontinuities in the insulation layer makes them susceptible to infiltration by outside moisture or from the process environment. The result of infiltration is moisture held in contact with the pipe – resulting in CUI.

Its occurrence can be unpredictable and undetectable based on visual examination. Traditional methods of addressing this issue involve selective removal of insulation for visual inspection, radiography or spot thickness measurements with PEC (Pulsed Eddy Current).

This presentation discusses the development and deployment of an Advanced Electromagnetic Rapid Inspection Technique for detection of CUI without the need to remove the insulation.

3:15 - 3:45 PM
Dr. Avi C. Gadkari - High Performance Polymers for Harsh and Demanding Industrial Applications Focus On Polyamide 12 Pipe Liners for Pipeline Integrity Management

With oilfield operating conditions becoming increasingly harsh and demanding, High Performance Polymers [HPP], such as Polyamide 12 and PEEK, based systems can provide effective and reliable solutions for corrosion control, safety enhancement, environmental risk reduction, cost savings, ease of operation and other benefits.

This paper will focus on Polyamide 12 [PA12] pipe liners for the pipeline integrity management. PA12 liners are composed of a relatively thin-walled plastic pipe that is installed inside a pipeline to be a barrier between the flowing pipeline contents and the host pipeline. PA12 liners can be installed in new pipelines as well as for rehabilitation of previously operating pipelines. Polyamide 12 is a well-known, established, engineering polymer with a long safe and successful track record of operation under harsh conditions in Oil & Gas and Automotive industries. A special grade of PA12 is developed for pipe liner applications. Compared to the most common liner material, polyethylene [PE], PA12 has a much greater resistance to absorption, softening, and swelling by multiphase fluids in the pipelines. As a liner it can be used at higher temperatures than PE with significantly reduced risk of damage due to fluid absorption and permeation. This high performance liner material is suitable for pipelines transporting hot, sour, multiphase, and abrasive fluids and can offer significant cost advantages over corrosion inhibitor programs. This seminar is intended to describe PA12 liner design, installation, operating range and the enhanced pipeline lifetime it can offer.

3:15 - 3:45 PM
Mike Rogers and Dave Rose - A comparative Review of Boiler Water Treatment for Drum Boilers on High Purity Water and OTSG's on Produced Water

The current increase in the use of OTSG's for producing steam from produced water has brought many new personnel to have responsibility for boiler water treatment in these units. The authors feel that a review of what the differences are in the boiler water treatment to prevent fouling, scaling and corrosion in these units when compared to drum boilers would be useful. The review will cover the differences in monitoring, use of chemicals, control limits, when to clean as well as the techniques for undertaking failure analysis.

Thursday, February 26th
Track 1 - Protective Coatings Track 2 - Monitoring & Inspection in Pipelines
8:00 - 8:45 AM
Norman Spence - Failure of Rubber Linings and Coatings in Water Treatment Wessels within the SAGD Industry

The SAGD industry is a relatively new technique to withdraw bitumen from the oil sands. This presentation is to demonstrate that the past rubber lining and coatings that have been applied into these water treatment vessels is not working and failure of the linings is a very serious issue in the SAGD plant sites. I would like to discuss the following:

  • Past history of the linings within these vessels.
  • Failures of the rubber linings and liquid coatings within these vessels
  • Service conditions and how they drastically affect the type of lining to be applied within these vessels.
  • The process and costs to reline these vessels
  • New technology and the correct type of rubber lining for these vessels and service conditions

8:00 - 8:45 AM
Jana Johnson - Case Study: Downhole Tubing Inspection Data Comparison and Verification

This paper describes a case study of severe downhole corrosion in six different wells in the same formation with high H2S and CO2 partial pressures along with 5000m depth, high chloride water and elemental sulphur. After providing an overview of the well conditions and history of downhole corrosion in the field, the paper describes third party assessments that were completed based on past inspection history to determine a “risk of pit rupture” and “risk of collapse” for tubing in each well. Then the paper continues to describe a tubing replacement project for one well where there were significant concerns of tubing collapse.

Discussion then focuses on a data validation project that was completed for the one well. Previous downhole inspection results are compared to results from about 15 joints of tubing that were inspected in a test well. Data analysis methods are described and compared by showing a significant difference in results for a single inspection due to the type of analysis completed.

The reader is then shown a comparison of results obtained from physical measurements of the corroded tubing versus inspection results for those joints. Three distinct sections of data accuracy are discussed and pictures are included to show pit morphology seen in this tubing.

The paper concludes by recommending an inspection and analysis method while identifying limitations of the results of all inspection methods and physical measurements. Recommendations include tips on preparation of the tubing for inspection, consideration of pit morphologies that may be seen depending on well conditions and recommended analysis methods that should be used.

8:45 - 9:15 AM
Jane Hall - Application of Instrumental Techniques to Coating Failure Analysis

Before protective coatings are applied in the field, the coatings will be tested and qualified against laboratory and field criteria. The coating application process is normally strictly monitored according to coating application standards and manufacturer product data sheets. However, coating failure still happens due to unexpected factors. Sometimes coating failure could be a mystery which would be solved with the information obtained from instrumental analysis.

In this paper, a few instrumental analysis methods were used to elucidate coating failure cases. Normally the first question arising for coating failure analysis is: “Was the correct coating applied?” The easiest way to identify the coating system is Fourier Transform Infrared Spectroscopy (FTIR) analysis. However, this paper will demonstrate a case in which the two coating systems had exactly the same FTIR spectra, but demonstrated different performance in the field. The difference originated from the discrepancy in microstructures proved by Scanning Electron Microscope (SEM) images. For some metal coating systems, SEM won’t be able to differentiate one coating system from another. This paper describes how to use X-ray Photoelectron Spectroscopy (XPS) to disclose the “secret” recipe of one coating system which contained Zinc, making it a better coating than another very similar coating system. This paper also introduces a dispute on off-ratio issue by combustion analysis technique. Another case in this paper covers a pipeline coating failure analysis which included analyzing the top coat microstructure by SEM and high power optical microscope, analyzing chemical components of underlay by FTIR, and analyzing the contamination in soil samples with Gas Chromatography (GC), etc.

8:45 - 9:15 AM
Xavier Ortiz - Use of Piezoelectric and MsS Guided Wave Ultrasonic Monitoring Technologies on Underground Piping

Guided wave ultrasonic technology has been used for more than 20 years to assess the integrity condition of aboveground and underground structures. There are two basic technologies to generate guided waves. The first one uses a belt of piezo-electric sensors in direct contact with the piping surface. Longitudinal and torsional mode waves can be generated with the piezo-electric technology. The second basic technology uses a magneto-strictive (MsS) sensor to couple the waves into piping. The magneto-strictive sensor is a cobalt alloy-steel ribbon which is wrapped around the outer piping surface. The MsS technology generates torsional mode waves.

Stantec conducted integrity verification of underground piping using both technologies in different facilities. The piezo-electric technology was used in 2007 to inspect a combined 2.2 km of NPS3 and larger underground piping in 115 segments. The MsS technology was used in 2014 to inspect a combined 0.8 km of NPS6 and larger underground piping in 12 segments.

While guided wave ultrasonic has been used by the industry for many years, there is still a lack of information related to its performance when inspecting underground piping. The intent of this paper is to document the experience and results of using both piezo-electric and MsS technologies for integrity verification of underground piping while at the same time providing information regarding the effect of field-related variables such as coating, temperature, bends, and soil-to-air interfaces among others.

9:15 - 9:45 AM
Da Kuang and Frank Cheng - Synergistic Effect of Alternating Current and Cathodic Protection on Disbondment of Pipeline Coating

External corrosion of pipelines is prevented by coating and cathodic protection (CP). Various coating defects, such as holidays, can be generated during manufacturing, application, transportation and construction. Upon exposure to ground water, the steel at the defect base can be protected from corrosion attack by CP. However, the CP would also result in coating disbonding from the holiday due to locally elevated alkalinity.

Pipelines parallel to high-voltage electricity transmission lines can experience enhanced corrosion due to alternating current (AC) interference. The applied CP on the pipeline can be shifted from the standard potential, thus affecting corrosion protection and coating disbondment starting at the holiday. To date, there has been no work conducted to investigate the synergistic effect of AC and CP on coating disbonding at a holiday. Without this knowledge, the operator would not be able to effectively manage integrity of pipelines, especially when they are adjacent to power transmission lines.

In this work, a crevice cell was designed and built to investigate disbonding behavior of a fusion bonded epoxy (FBE) coating at a holiday and corrosion of X65 steel under the simultaneous application of various values of AC and CP in a simulated ground water solution. Results demonstrate that the AC contributes to coating disbondment due to generation of hydroxyl ions and hydrogen bubbles, both of which weakening the adhesion of FBE to the steel. At the same time, the AC enhances the CP permeation into the disbondment due to increased solution conductivity at small AC current densities such as 0.01 A/cm2. As the AC current density increases to 0.03 A/cm2, the generated hydrogen bubbles and corrosion product block the CP permeation, and localized corrosion occurs at the bottom of the disbondment. This work provides meaningful results for an improved safe design of pipelines under the AC interference.

9:15 - 9:45 AM
Frank Gareau and Alex Tatarov – ERW SEAMS: THE GOOD, THE BAD AND THE UGLY

Line pipe longitudinal weld seams may contain anomalies due to the manufacturing process. These anomalies often relate to the specific welding process that is characterized by the era of pipe manufacturing. Specific regulations in the United States and general regulation requirements in Canada require integrity assessments to be made to address potential seamdefect problems, particularly in low-frequency-welded ERW (electric-resistance-welded) pipe materials. This presentation will discuss the benefits of laboratory characterization of such anomalies to complement inspection and monitoring of these ERW seams. The characterization of such anomalies into good, bad and unacceptable (ugly) categories can be the basis for the assessment of integrity of these weld seams.

Morning Break (9:45 - 10:30 AM)
10:30 - 11:00 AM
Eugene Medvedovski - Corrosion Resistant Thermal Diffusion Coatings for Enhancement of Equipment Performance in Heavy Oil Production

The challenges facing heavy oil production equipment in terms of corrosion or wear and corrosion related issues are considered. The causes of the failure and the degradation mechanisms of steels and alloys used for production and processing equipment components are analyzed. These problems can be minimized by the appropriate surface engineering. The options of surface engineering solutions towards the protection of the processing equipment components and piping systems for heavy oil production with extension of their service cycle and enhancement of performance of the engineering materials are proposed and analyzed.

In order to improve corrosion and wear resistance of the production components, which also have to serve at elevated temperatures, the compounds based on the metals of IVb - VIb and VIII groups and the non-metallic elements of IIIa – Va groups with strong covalent bonds and high thermodynamic potential should be considered. Among different options of the surface engineering solutions to improve performance of structural components of heavy oil processing, such as production tubing strings, artificial lift systems and others, thermal diffusion coatings are successfully applied for their corrosion and wear protection. The principles of the thermal diffusion process, as one of the most successful routes for the mass-production, are formulated. In particular, in the case of steels and ferrous alloys widely used for oil production equipment, iron boride-based coatings with dense micro-crystalline uniform structures are formed. As opposed to cold and thermal spray coatings, electroplating, PVD, painting and other mechanically or chemically applied methods, the thermal diffusion technology successfully applied by ETI provides high integrity of finished products without spalling and delamination on the entire working surface of components. This technical solution provides significant extension of the component service life (typically from 3 to 10 times depending on the well production conditions) in harsh corrosion or corrosion-abrasion environments. The ETI boride-based coatings successfully withstand the actions of water steam with a presence of H2S, CO+CO2, chlorides, hydrocarbons in simulating oil field conditions tested in the autoclave and in the Atlas cell, as well as in strong acidic environments. Case studies of the successful application and industrial service of the ETI surface engineering solutions, e.g. for the joints with the inner protective coatings with the length up to 12 m, and the corrosion test data will be presented.

10:30 - 11:00AM
Frank Gareau - Inspection and Monitoring in the 21st Century

There is “gold” in the inspection and monitoring data that is available upstream of oil and gas processing facilities. A thorough understanding of the upstream infrastructure and operating conditions can be efficiently and effectively put to use to optimize operation of oil and gas production systems. Examples related to the maintenance tasks required to adequately address operational excellence and integrity management in our facilities will be addressed in the presentation. More specifically, integrity and emergency response challenges related to producing and processing H2S-containing process streams will be addressed.

11:00 - 11:30 AM
Rick Dunlap - Thermal Sprayed Aluminum for Industrial Coatings Needs

We will provide an overview from the contractor’s perspective for TSA that will include the basic theory and history of metallizing, TSA in particular. We would provide some scenarios where TSA is appropriate and perhaps not so appropriate. This would be some very basic history as well as some basic chemistry. Additionally we would illustrate the 2 methods utilized both flame spray and arc-spray and the scenarios and details on the method choice. We would discuss TSA’s use for offshore, process industries, and some key focus areas we see it used in today such as CUI and a few specific corrosion challenge areas it works well in such as External Floating Roof tanks and flare booms on platforms. We would discuss the economics and value of TSA / metal coatings versus conventional liquid coating systems, some barriers to industry acceptance, and the cost of ownership per year versus liquid coatings.

11:00 - 11:30AM
Bob Prieston - Post-ILI Monitoring of Upstream Oil and Gas Pipelines

This paper describes a case study of severe downhole corrosion in six different wells in the same formation with high H2S and CO2 partial pressures along with 5000m depth, high chloride water and elemental sulphur. After providing an overview of the well conditions and history of downhole corrosion in the field, the paper describes third party assessments that were completed based on past inspection history to determine a “risk of pit rupture” and “risk of collapse” for tubing in each well. Then the paper continues to describe a tubing replacement project for one well where there were significant concerns of tubing collapse.

Discussion then focuses on a data validation project that was completed for the one well. Previous downhole inspection results are compared to results from about 15 joints of tubing that were inspected in a test well. Data analysis methods are described and compared by showing a significant difference in results for a single inspection due to the type of analysis completed.

The reader is then shown a comparison of results obtained from physical measurements of the corroded tubing versus inspection results for those joints. Three distinct sections of data accuracy are discussed and pictures are included to show pit morphology seen in this tubing.

The paper concludes by recommending an inspection and analysis method while identifying limitations of the results of all inspection methods and physical measurements. Recommendations include tips on preparation of the tubing for inspection, consideration of pit morphologies that may be seen depending on well conditions and recommended analysis methods that should be used.

1:00 - 1:30 PM
Michael Magerstaedt - Field experience with highly erosion and corrosion resistant elastomer pipe coatings and linings

Analysis of multi-year erosion and corrosion protection experience with high performance polyurethane elastomer linings in Alberta oil sands shows that these materials significantly extend design life of steel pipes in hydrotransport as well as tailings lines. Similar results were obtained from phosphate slurry transport and from sea water / sand mixtures in enhanced oil recovery and dredging applications. At last year’s NAWC conference, evidence was shown that such liners even outlast expensive chromium carbide overlays (CCO) in situation where erosion-corrosion is likely to occur. This finding was confirmed in the long term, data will be presented here. A method for stripping of worn liner and re-lining of used steel pipes has been developed. Given a local or regional stripping and relining facility, this option can further reduce maintenance cost of slurry line operators. An excursion into field experience with exterior pipe coatings made from related high performance elastomers will be given. Not only long-term corrosion protection, but also protection from external pipe damage in thrust boring situations can be achieved with these materials. Field examples will be presented.

1:00 - 1:30 PM
Priyesh Menon, Dr. Gerrit Voordouw - Is there microbially-influenced corrosion in diluent transporting pipelines?

Pipeline corrosion is caused by physical, chemical and microbiological factors. Factors important for microbially-influenced corrosion (MIC) of pipelines transporting liquid hydrocarbons include the type of hydrocarbon being transported, the presence of water and nutrients needed for microbial growth. Low molecular weight hydrocarbons mixtures (including diluent) are toxic to microorganisms in undiluted form, and water is typically present at only 0 to 1% in diluent-transporting pipelines. To understand MIC under these conditions pigging solids, either loosely or tightly associated with a diluent-transporting pipe, were analyzed. A sample of encrusted nodules (EN), which were tightly associated with the pipe surface, showed the highest counts of acid-producing bacteria (APB). This sample was also the only one, which retained activity of hydrogen-utilizing methanogens, which can contribute to MIC. The EN sample also had the highest weight loss corrosion rate. Microbial community composition analysis of all samples indicated the presence of methanogens in many, including in the EN sample, while confirming the absence of SRB. Overall this work confirmed the presence of potentially MIC-causing microbes in tightly-associated solids from a diluent-transporting pipeline. These survive best in encrusted nodules, where they may be protected from the harsh conditions, which prevail in these lines, and where they may contribute to MIC.

1:30 - 4:00 PM Regulatory Forum - Dave Grzyb (AER), Bushra Waheed (BCOGC) and Robin Antoniuk (ABSA)