Broadsword Corrosion Engineering Ltd.

Calgary, Canada

Broadsword Corrosion Engineering Ltd.

Calgary, Canada
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Teevens P.J.,Broadsword Corrosion Engineering Ltd. | Khera A.,Allied Engineers | Zhu Z.,Broadsword Corrosion Engineering Ltd.
ASME 2013 India Oil and Gas Pipeline Conference, IOGPC 2013 | Year: 2013

Contaminants such as CO2, H2S and O2 in water-wet liquid and gas pipelines create an aggressive environment conducive to facilitating internal corrosion. During pipeline operations, solids deposition, water accumulation, bacterial activities and improper chemical inhibition aggravate the internal corrosion attack. For assessing the threat of internal corrosion, the petroleum industry currently has only three integrity validation tools at its disposal. These are Pressure Testing, In-line Inspection (ILI) and Internal Corrosion Direct Assessment (ICDA). To enhance pipeline integrity for piggable and nonpiggable pipelines, NACE International has developed and published a variety of industry consensus Standard Practices for the ICDA protocols to predict time-dependent internal corrosion threats for various petroleum products in both offshore and onshore under sweet or sour environments. These NACE International ICDA Standards include: • SP0206-2006 "ICDA Methodology for Pipelines Carrying Normally Dry Natural Gas (DG-ICDA)" [1] • SP0208-2008 "ICDA Methodology for Liquid Petroleum Pipelines (LP-ICDA)" [2], • SP0110-2010 "Wet Gas ICDA Methodology for Pipelines (WG-ICDA)" [3] • Multiphase flow (MP-ICDA) is under development with TG-426 and will be released in 2013. • Process Piping (PP-ECDA, Above Ground) is in its early stages of development with the release not likely before 2015. • Process Piping (PP-ECDA, Buried) is in its early stages of development with the release not likely before 2015. • Process Piping (PP-ICDA) for various service environments is in its early stages of development with the release not likely before 2015. All ICDA protocols are a structured, iterative integrity assessment process, consisting of the following four steps: Preassessment, Indirect Inspection, Detailed Examination and Postassessment. Most importantly, unlike ILI and pressure testing, all the ICDA standards require a mandatory root cause analysis and a go forward mitigation plan to arrest the corrosion processes being encountered. This paper reviews the following case studies: LP-ICDA for a crude oil pipeline and WG-ICDA for a high pressure gas pipeline with free water and condensate. ICDA is applicable for dry gas systems too but due to limiting length of this paper, the dry gas case study is not detailed. This paper will be useful for the pipeline operators to provide guidance in identifying locations at which corrosion activity has occurred, is occurring, or may likely occur in the future under a series of pre-defined operating conditions. Copyright © 2013 by ASME.


Gonzalez C.M.,Petroamazonas EP | Arumugam S.,Broadsword Corrosion Engineering Ltd. | Teevens P.,Broadsword Corrosion Engineering Ltd.
NACE - International Corrosion Conference Series | Year: 2016

In 2010, mechanical integrity personnel started the application of the Direct Assessment (DA) and Inline Inspection Methodologies (ILI) to establish the integrity validation baseline assessments for a Pipeline Integrity Program (PIP) for the pipelines operated within Blocks 12 and 15 by Petroamazonas EP, in Ecuador. There were four preconditions which justified the implementation of these methodologies: Following the CFR Title 49, Part-195.6, the Blocks 12 and 15, are classified as Unusually Sensitive Areas (USA's). Pressure Testing had been the only Integrity Validation Technique applied to all the pipelines and was performed only after the construction of the line to verify the weldments installed but NOT any in-service defect detection. There are pipelines that have been operating for more than 20 years without any integrity assessment beyond the initial construction hydro test. There have been several internal corrosion failures of some pipelines at Blocks 12 and 15 resulting in significant and important economic losses to the operation. For the implementation of the DA and ILI methodologies the following NACE International and API (American Petroleum Institute) Standard Practices were used as guidelines: NACE SP-0502 for External Corrosion Direct Assessment, NACE SP-0102 and API-1163 for the Inline Inspection Program and NACE MP-ICDA (by the TG-426 and now being published for a late 2015 release) for Internal Corrosion Direct Assessment. © 2016 by NACE International.


Fardisi S.,Broadsword Corrosion Engineering Ltd. | Tajallipour N.,Broadsword Corrosion Engineering Ltd. | Teevens P.J.,Broadsword Corrosion Engineering Ltd.
NACE - International Corrosion Conference Series | Year: 2012

A mechanistic model was developed to predict uniform corrosion rates in sour liquid petroleum pipelines. The model incorporates the transient chemical reactions which occur in the bulk of the corrosive fluid, the transport of the active species to and away from the surface, and the electrochemical reactions occurring at the surface of the metal. In addition, the technical complications of coupling a scale growth model applicable to multiple scale types such as FeCO 3 and FeS, with a corrosion simulation were discussed in detail. It was proposed to remedy these issues by separating the scale growth and corrosion modeling procedures. The results of examining scale formation can be stored in a correlated database to be imported later into the corrosion simulation using the approach presented in this paper. This method helped to incorporate the effect of FeS film growth on the variation of the corrosion rate. All the assumptions and simplifications of the model are discussed and shown to be appropriate for solving this problem. Several simulations were performed, and the predictions were compared with available experimental data in different operating conditions. In general, results agreed well with the corresponding experimental values tending to justify the approach presented. ©2012 by NACE International.


Fardisi S.,Broadsword Corrosion Engineering Ltd. | Tajallipour N.,Broadsword Corrosion Engineering Ltd. | Teevens P.J.,Broadsword Corrosion Engineering Ltd.
NACE - International Corrosion Conference Series | Year: 2012

Flexible pipes are made of steel wires covered with a minimum of two polymer sheaths from inside (to protect the line from the bore flow) and outside (to protect the line from sea water). The space between the inner and outer polymer sheaths form an annular where corrosive species such as H 2S, CO 2, and H 2O can penetrate, condense and accumulate. Corrosion in such conditions features some unique characteristics that are very different from conventional production lines. The amount of the electrolyte is very limited in these applications. This causes the electrolyte to become saturated with the corrosion products and disturbs the chemical reactions that ultimately cause corrosion. Broadsword Corrosion Engineering decided to develop a comprehensive and up-to-date model suitable for these applications. The model incorporates the effect of transport processes, the chemical reactions occurring in the electrolyte, and the electrochemical and precipitation reactions that occur at the surface of the metal. The model was validated using the client's third-party laboratory testing and other experimental data. Several simulations were performed and the effects of pressure, temperature, and volume-to-surface-area were investigated and discussed in details. ©2012 by NACE International.


Brown D.C.,Broadsword Corrosion Engineering Ltd. | Johnston S.,Broadsword Corrosion Engineering Ltd. | Teevens P.,Broadsword Corrosion Engineering Ltd. | Turner R.J.,University of Calgary
NACE - International Corrosion Conference Series | Year: 2016

Microbially influenced corrosion (MIC) is a process whereby microbial cells living in an exopolymer matrix, known as a biofilm, induce corrosion of the associated surface. The risk of MIC within a system is usually assessed by measuring planktonic (free-floating) cells, which is assumed to approximate the biofilm-associated cells (sessile) cells. This work aimed to determine the accuracy of this industry-practiced approach of assessing MIC risk from planktonic cell counts. Planktonic and sessile cell counts of two single species cultures, one of an aerobe (Pseudomonas fluorescens) and one of an anaerobe (Geoalkalibacter subterraneus), both of which have been associated with MIC, were monitored in a growth curve test to determine how planktonic and sessile cell counts relate during the initial stages of biofilm formation. The results indicate two factors govern biofilm initiation of the tested species. Firstly, a minimum planktonic cell density is required and secondly, a minimum exposure time of the surface are both required prior to biofilm initiation and the onset of internal corrosion of carbon-steel pipelines. Both these factors affect biofilm formation in a species specific manner. © 2016 by NACE International.


Arumugam S.,Broadsword Corrosion Engineering Ltd. | Tajallipour N.,Broadsword Corrosion Engineering Ltd. | Teevens P.J.,Broadsword Corrosion Engineering Ltd.
NACE - International Corrosion Conference Series | Year: 2014

The sour corrosion product (i.e. iron sulphide) exhibits different morphologies under different operating conditions and possess different crystal structures and oxidation states. Developing a model to understand the growth mechanism of different forms of the sour corrosion product is essential in predicting corrosion rates and mitigating scale formation in sour environment. This paper presents a new approach wherein the nanocrystalline iron sulphide (mackinawite) scale formation is modeled by the nucleation and growth of the scale crystals. Ignoring any solid state reactions that could form iron sulphide in undersaturated solutions, the supersaturation level quantified the extent of nucleation followed by diffusion controlled crystal growth. The scale morphology in terms of the volumetric porosity and their influence on the predicted sour corrosion rates were studied under stagnant conditions. © 2014 by NACE International.


Arumugam S.,Broadsword Corrosion Engineering Ltd. | Tajallipour N.,Broadsword Corrosion Engineering Ltd. | Teevens P.J.,Broadsword Corrosion Engineering Ltd.
NACE - International Corrosion Conference Series | Year: 2014

This paper presents a new approach to model the growth mechanism of the sweet corrosion product (i.e. iron carbonate scale) and to study the influence of the corrosion product morphology on the uniform corrosion rates. Corrosion rates were defined as the iron ion flux rate leaving the metal surface which is governed by the thickness and volumetric porosity of the corrosion product (scale). Nucleation and crystal growth were treated as the two committed steps in forming the scale. The population number and the critical size of the iron carbonate nuclei were determined using the classical nucleation theory. Supersaturation level was quantified by the effusion of iron ions from the metal surface and infusion of carbonate ions from the bulk solution. Crystal growth, followed by nucleation and termination of the supersaturation condition, was modeled using a moving boundary approach solving Fick's diffusion equations in spherical coordinates. Under stagnant conditions, the formed scale layer thickness and the volumetric porosity were obtained based upon the crystal shape and size. Also, the time-dependent iron ion flux/corrosion rates were predicted. Further, the effects of operating parameters such as pressure and temperature on the competition between the nucleation rate and the growth rate of crystal nuclei were examined. © 2014 by NACE International.


Eggum T.,Broadsword Corrosion Engineering Ltd. | Arumugam S.,Broadsword Corrosion Engineering Ltd. | Tajallipour N.,Broadsword Corrosion Engineering Ltd. | Teevens P.,Broadsword Corrosion Engineering Ltd.
NACE - International Corrosion Conference Series | Year: 2015

Oxygen corrosion is a major threat to water injection systems, particularly when injecting seawater to maintain reservoir pressure. Utilizing and building on previously published approaches, mechanistic and semi-empirical modeling applications were developed for oxygen corrosion in aqueous environments. The goal of this work was to develop a comprehensive, multi-platform approach that can be applied to a variety of oilfield water applications (seawater and produced water) and conditions (oxygen concentrations, flow velocities, temperatures, etc.). The Oxygen Reduction Reaction rate (the principal cathodic reaction) was modeled as mixed-control with activation and diffusion components, usually but not universally dominated in oil and gas systems by diffusion processes. At high injection flow rates and when residuals of dissolved chlorine, normally injected upstream of the deaerator to control microbiological activity, is transported down the tubing string (due to shut-in or upset of the oxygen scavenger system), an erosion-corrosion approach is preferable to the above flow-dependent corrosion rate calculations. Having chlorine residuals in the injected water can be detrimental to the tubing string's integrity due to its contribution to the rate of internal erosion-corrosion. Based on available data (online dissolved oxygen measurements, flow rates, temperatures, and other operating parameters) cumulative damage from these mechanisms can be assessed and remaining life predictions made. The NACE Standard Practice for Corrosion Control and Monitoring in Seawater Injection Systems (SP0499-2012) recommends less than 50 ppb dissolved oxygen, less than 6 m/s flow velocity, and for carbon steel lines, predicts a five to seven year service life before repairs are needed. By understanding the interactions of the identified critical operating parameters, an analysis of this type will enable the operator to optimize operating conditions, inhibitor and biocide treatment protocols, and ultimately extend the service life of water injection installations. © 2015 by Nace International.


Arumugam S.,Broadsword Corrosion Engineering Ltd. | Tajallipour N.,Broadsword Corrosion Engineering Ltd. | Teevens P.J.,Broadsword Corrosion Engineering Ltd.
NACE - International Corrosion Conference Series | Year: 2015

CO2 sequestration requires the prediction of pressure-temperature-composition (P-T-X) data for CO2 and water mixtures at significantly high pressures and temperatures and these applications most commonly deal with subsurface water containing dissolved salts. In this study, a thermodynamic model was used to predict the solubility of supercritical CO2 in pure water and in the presence of chloride salts in the aqueous phase (i.e. brine solutions) for temperatures up to 100°C and pressures up to 60 MPa. The concentrations of the corrosion species in the aqueous phase was predicted and were compared with experimental data available from open literature. A mechanistic model is presented to predict the internal corrosion of carbon steel under such operating conditions of temperature, pressure and salt concentrations. © 2015 by Nace International.


Teevens P.,Broadsword Corrosion Engineering Ltd. | Tajallipou N.,Broadsword Corrosion Engineering Ltd.
Annual Conference of the Australasian Corrosion Association 2014: Corrosion and Prevention 2014 | Year: 2014

The pipeline industry in the developed world is increasingly experiencing more intense and protracted regulatory, public and environmental scrutiny than ever before. It has been likened to the intense public debate about 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 the public perception that pipeline operators are not proactively preventing corrosion-initiated releases.

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