Abstract The corrosion resistance of metallic materials in natural seawater is arousing more and more interest from engineering companies and Oil & Gas end-users. Indeed, hydrotesting and flooding operations are very often conducted to check the quality of the vessels and piping systems. In this case, seawater may cause pitting corrosion and crevice corrosion. Seawater is a very complex and corrosive environment due to its high amount of chlorides, and to the presence of algae, bacteria and many other components that may lead to the formation of a biofilm on the surface of the steel. In addition, during an hydrotest, the temperature of the steel can dramatically increase under the effect of sun and reach relatively high temperatures. This paper provides an update on the resistance of various corrosion resistant alloys in natural seawater at 30°C (86°F) and 75°C (167°F). Three materials are investigated: UNS N08904, N08825 and N06625. They are today commonly used in the Oil & Gas industry, especially in the upstream part. UNS N08825 and N06625 are often cladded to carbon steel to get a cost-efficient metallic solution for piping systems. Introduction Seawater is involved in many industrial applications. For instance, it can be used for heat exchangers and as a cooling medium. It is also commonly used for hydrotesting of piping systems. This environment is very aggressive, especially when considering the complexity of seawater composition combined with the process temperature and sometimes acidic conditions. Choosing an inappropriate material may induce severe corrosion, leading to the leakage of the equipment. The risk of pitting corrosion must be taken into account for selecting the right Corrosion Resistant Alloy (CRA). Alloying elements such as chromium, molybdenum, tungsten and nitrogen have a beneficial influence on the pitting corrosion resistance of CRA materials. The Pitting Resistance Equivalent Number (PREN) is a useful empirical tool that can be used to get a ranking of stainless steels behavior in a chloride-containing environment.

Abstract Acid stimulation is a frequently used technology to enhance the production rate of hydrocarbons from a reservoir. Severe iron carbonate deposition has been observed recently during acid stimulation in sweet carbonate gas wells, especially for high-temperature high-pressure (HTHP) wells. It offsets the performance of acid stimulation, causes severe flow assurance issues, such as formation damage and tubing blockage. To study iron carbonate formation during acid stimulation, corrosion coupon tests were conducted to collect data of the corrosion rate and iron released from tubing during the acid injection stage of acidizing treatment. To simulate iron carbonate depositing in the near-wellbore region, scale prediction software (ScaleSoftPitzer) was applied to simulate the scaling tendency and potential mass deposition. This allows an insight into the iron carbonate precipitation. Results show iron carbonate deposition during acid stimulation is a corrosion induced scale issue. A high concentration of iron can release from tubular due to severe corrosion during acid injection, especially for the high-temperature reservoir. Minor iron carbonate could deposit at the initial stage of acid injection due to low the pH of spent acid. However, sever iron carbonate can precipitate when spent acid with pH ~3.8 mixes with formation water. A large amount of iron carbonate could deposit in the near-wellbore region or tubing, which potentially causes severe flow assurance issues and offsets the performance of acid stimulation. This paper presents a fundamental study to understand the mechanisms of iron carbonate deposition during acid stimulation in sweet carbonate reservoirs. It will benefit defining a proper strategy to control iron carbonate deposition in downhole tubing and near-wellbore matrix. Appropriate mitigation strategies are recommended. Introduction The formation of mineral scale is a flow assurance problem during oil and gas production. Scale deposition on the surface facilities, downhole tubing and near wellbore region in the reservoirs may create many problems including pipe or valve blockage, unscheduled equipment shutdown, and even more importantly production reduction. 1-5 Over the past few decades, great efforts have been made to understand the conventional oilfield scale formation and inhibition, such as CaCO 3 , BaSO 4 and CaSO 4 . Compared to these conventional mineral scale deposits, iron carbonate, an exotic scale, has received fewer attentions.

Abstract In Oil and Gas (O&G) facilities, it is estimated until a 40% of failures are due to corrosion induced by microorganisms (MIC). These microorganisms remain in planktonic or sessile form and a high diversity of metabolisms can be found. In the present study, planktonic and sessile microbial consortia were isolated and characterized from production waters of unconventional and conventional process. The water production showed major presence of the genus Halanaerobium (94.2%) and Arcobacter (73.6%) in sample of unconventional and conventional processes respectively. In the culture media formulated, Halanaerobium (68%) and genera Desulfovibrio (33.8%), Geotoga (33.3%), Proteiniphilum (30.89%) were found in a higher proportion for unconventional and conventional processes respectively. All these microbial genera have been reported as related to MIC. On the other hand, the biofilm formation was characterized by SEM-EDS and electrochemical techniques, using its ability of MIC in carbon steel; showing that the unconventional microbial consortium slightly higher corrosion capacity (2.35 mm/y) than the conventional microbial consortium (1.25 mm/y). These results represent the synergy of the different metabolisms that interact in the MIC-related communities, such as thiosulfate and sulfate reduction, iron oxidation/reduction and acid production microorganisms in unconventional and conventional processes. Introduction Corrosion causes an annual financial loss of US$4 trillion worldwide, half of that cost is in corrosion prevention and control, the other half in damages and lost productivity 1 . It is estimated that 20% to 40% of the failures caused by corrosion is produced by MIC 2-4 . MIC is a type of localized corrosion caused by microbial activities. This includes a variety of processes by which microbes contribute to corrosion directly or indirectly and severely affect the integrity of facilities in various industrial sectors, especially in the O&G industry 2,5,6 . Biofilms are widely believed to be responsible for MIC, in most cases 7,8 . This corrosion mechanism can occur in aqueous environment and is a common problem in O&G facilities due to the ubiquitous nature of microorganisms and corrosives in the pipes. Some facilities that can suffer MIC are water injection lines, storage tanks, sewage treatment systems, filtration systems, pipes, reverse osmosis membranes, and potable water distribution systems 4 . Secondary recovery processes in mature fields have water cuts greater than 90%, which creates the right conditions for the development of microbial populations due to of their abundant sources of carbon and energy 9,10 . MIC has also been reported on crude oil and refined products 7

Abstract In accordance with Annex A of ANSI (1) /NACE (2) MR0175/ISO (3) 15156-2, low-alloy steel (LAS) components for oil and gas (O&G) are acceptable if they contain less than 1 wt.% Ni. As an alloying element in steels, nickel improves low-temperature toughness and hardenability and does not promote the formation of carbides that could retain hydrogen into the steels. In this work, a set of five steels with different nickel content was specially fabricated to study the effect of that element on the sulfide stress cracking (SSC) resistance. Quenching and tempering (Q&T) heat treatments were customized to each chemical composition to obtain a tempered martensite microstructure with a hardness level below but near the 22 HRC threshold. The effect of nickel content on the anodic and cathodic behavior of those steels was evaluated by electrochemical polarization tests in substituted NACE TM0177 A test solution, where H2S bubbling was replaced by thiosulfate additions (i.e., Tsujikawa Method). Hydrogen permeation tests were conducted in a Devanathan-Stachurski cell, to evaluate the effect of nickel on the hydrogen diffusion. Additionally, slow strain rate tests (SSRTs) were performed at the open circuit potential (OCP) to assess the role of nickel on the SSC resistance. Introduction The first reported failures of oil and gas (O&G) steel components due to sulfide stress cracking (SSC) occurred in Canada, France, and the United States in the early 1950s. 1 Since then, several combinations of chemical composition and microstructure for different grades of steels were thoroughly evaluated. Fraser, Treseder and Eldredge studied the metallurgical factors affecting SSC resistance among 104 low-alloy steels (LASs). 2,3 In a following investigation by Treseder and Swanson, when comparing steels with the same hardness level, the SSC susceptibility increased if the nickel content was higher than 1 wt.%. 4 Considering the metallurgical advantages of adding Ni to steels, such as the increase in hardenability and the decrease of the ductile-to-brittle transition temperature, this limit has been discussed since the late 1960s. 5-7 Snape pointed out the possible presence of deleterious phases, i.e., retained austenite and untempered martensite, in the final microstructure of the steels studied by Treseder and Swanson. 4,7 Nickel stabilizes the austenitic phase at lower temperatures due to its effect on the lower critical temperature (A 1 ). If A 1 is exceeded during tempering, untempered martensite can be present in the final microstructure, which greatly reduces SSC resistance. 4,7 Snape proposes that steels with an adequate quenched and tempered (Q&T) microstructure can be resistant to SSC even at Ni contents beyond 1 wt.%. 7 However, a maximum limit for nickel as an alloying element was incorporated in the requirements for SSC resistant LASs as detailed in Annex A of ANSI (1) /NACE (2) MR0175/ISO (3) 15156-2 standard. 8 The standard sets a maximum hardness level of 248 HV (22 HRC) and a nickel content below 1 wt.%, and it excludes free-machining steels and those in the cold-worked state. 8 On the other hand, LASs that do not comply with those guidelines should be extensively qualified for SSC according to the test methods required by Annex B of ANSI/NACE MR0175/ISO 15156-2 and described in the NACE TM0177 standard. 8 Nonetheless, many authors suggest that microstructure, rather than the content of a given alloying element, is in charge of determining SSC resistance. 7,9,10 Another important factor to be considered is the steel cleanliness to avoid undesired effects between the alloying and residual elements. 9

Abstract The oil and gas industry is plagued with various flow assurance challenges including the formation of inorganic scale on component surfaces. Much research into scaling and inhibition is now being directed towards surface deposition as fouling on surfaces often causes operational problems and the rates cannot be predicted by consideration of bulk precipitation processes. However, achieving a mechanistic understanding of surface kinetics requires laboratory techniques that offer the ability to control thermodynamic parameters. A novel once-through capillary flow rig design based on the conventional tube blocking methodology was used to evaluate the surface formation of CaCO 3 under dynamic flowing conditions; an important attribute of this set-up is that saturation ratio (SR) remains constant in the capillary cell due to the short residence time of the flowing brine, and conditions can be such that there is no bulk (pre-precipitated) crystals in the solution when it flows through the cell. This allows the decoupling of bulk and surface scaling, enabling the reliable assessment of the kinetics of scale deposits present in the capillaries and provides an improved mechanistic understanding of mineral scaling on surfaces. CaCO 3 surface scaling kinetics was investigated by evaluating the induction times and gravimetric measurements of mass gain in the capillary cell. Scale precipitation tests were carried out on as-received (plain) and functionalized stainless steel substrates at three saturation ratios and flow rates ranging from 10-30 ml/min. Analyses of the induction times and deposition of scale show the significant influence of flow velocity and surface wettability on heterogeneous crystallization processes, and that scale growth on surfaces is not necessarily due to the deposition of bulk precipitated crystals. Introduction The formation of scale and oil & gas go hand in hand, it is a natural consequence of handling water associated with crude oil production. 1 Scales can build-up anywhere from clogging wellbore area to surface facilities such as production tubings, valves (subsurface control valves, SSCV), fouling pumps (electrical submersible pumps, EPSs) amongst many others; thereby restricting fluid flow and posing significant operational costs. 2 Dealing with damage as a result of inorganic scale formation is one of the major oil and gas industry challenges costing hundreds of millions of dollars per year in lost production in emergency shutdown, equipment failures or maintenance costs, and reduction in production. 1, 3 The inability to properly predict the severity ensures the industry spends millions of dollars in preventing and removing scale formation. 4, 5 There are various studies on the precipitation and deposition of inorganic scales, particularly calcium carbonate (CaCO 3 ). Most of these past studies on scale deposition and predictive models are mainly focused on the thermodynamic parameters in the bulk with little attention paid to scaling on surfaces, hence there is little reconciliation between bulk precipitation and surface deposition.

Abstract Mineral scale formation is one of the most common deleterious challenges in oil and gas production, restricting the steady flow of fluids. It poses major safety & operational issues and results in significant costs due to loss of production and remediation when not properly managed. Recent studies have shown that scaling processes on the surface are not necessarily a result of precipitation of crystals in the bulk solution and that they do not often share the same trends with regards to crystal growth kinetics and inhibition. Most of the past studies on scale deposition have focused on the static bulk data, some attention has been paid to surface conditions and hydrodynamic parameters. However, there is still no reconciliation between bulk precipitation and surface deposition. This study investigates the kinetics of CaCO 3 fouling by assessing the interplay between surface feature/condition and scale growth during heterogeneous nucleation processes, to better understand what characteristics of a surface promotes or reduces the likelihood of scale formation. To study the effect of surface "history" on fouling kinetics, scaling tests were performed on pre-scaled samples using brines of two saturation ratios (SR) at a flow rate of 10ml/min up to a previously determined induction time. Surface wettability effects were investigated by the application of silane on stainless steel to increase hydrophobicity, at three SR values and flow rates ranging from 10-30 ml/min at 70°C. CaCO 3 surface scaling kinetics was assessed from differential pressure change in a novel capillary flow rig designed to study heterogeneous scale formation under hydrodynamic conditions by keeping SR constant and ensuring that there is no bulk precipitate in the solution. The results show a non-water wet surface having improved scale performance by delaying the onset of nucleation and reducing the amount of surface fouling, while pre-scaled surfaces enable faster scale growth in comparison to non-seeded surfaces.

Abstract This paper discusses case studies of high voltage direct current (HVDC) & high voltage alternating current (HVAC) crossing Pipelines right of way (RoW) showcasing the effects of alternating current (AC) interference with respect to AC corrosion and Safety Hazards while running parallel and crossing at different angles to the same pipeline at multiple locations in a short span of length and restricting the AC current & safe voltage within maximum tolerable limits through deployment of mitigation measures as per industry code of practice, globally. The paper discusses effects of both powerline fault conditions as well as induced steady state on underground pipelines, AC interference modelling for enhancing effectiveness of Cathodic protection and analysis of AC interference mitigation measures. A comprehensive technical analysis involving collection of baseline information on both the pipeline and powerline and determining powerline fault current effects adjacent to each tower, on the pipe wall, the pipe coating, and the resulting safety hazard for pipeline personnel. Introduction When a pipeline is parallel to a high voltage power line for a significant distance, voltages can be transferred to the pipeline under both normal power line operating conditions and short-circuit conditions on the power line. These voltages can result in electrical shock hazard for maintenance personnel; they can also be detrimental to the integrity of cathodic protection equipment, the pipeline coating, and the pipeline steel, particularly during short-circuit conditions. The challenge is to identify the extent of AC interference on underground pipelines and mitigate these effects for the protection of pipelines. Problem Statement There are three modes of AC interference that can cause damage to pipeline systems and present an electrical shock hazard to pipeline personnel, namely; inductive coupling, resistive (conductive) coupling and capacitive (electrostatic) coupling. INDUCTIVE COUPLING: Inductive coupling occurs both under steady-state (normal operation) and fault conditions and the magnitude of the induced AC voltage depends on the phase current, phase wire configuration, layout and distance between pipeline and transmission line. The induced voltages reach the maximum values at discontinuities and reduces subsequently along the pipeline.

Abstract The use of 0.05 psi H 2 S partial pressure as the threshold determining when sulfide stress cracking (SSC) resistant materials are needed was codified in NACE MR 0175 (1975) nearly a half century ago and has served the industry well since implementation. The origins of this pressure are empirical and largely forgotten but there is significant history showing that it is a safe, conservative limit. As the oil and gas industry continues to innovate and mature, it is imperative to maintain knowledge of the basis of the sour limit and how it may be applied. Introduction For the past 70 years, H 2 S and its associated cracking mechanisms have been investigated, limits developed, and material properties identified. Prior to 1975 there were no standards, but there were standardized requirements outlined in various NACE (1) regional and national documents, in particular NACE 1F163 and 1F166, which were the precursors to NACE MR0175 (Wellheads and Trees). Some materials properties, notably the 22 HRC hardness limit had been notionally recommended in these early reports but were not formally standardized until NACE MR 0175 was issued in 1975. 1-3 When NACE MR 0175 (1975) was issued, the materials requirement focused on acceptable material properties for wellhead and tree materials since they involved the largest perceived safety risks. Setting a threshold when an environment should be considered sour or not was not included in NACE MR 0175 (1975) but was under prior industry consideration based on Texas Statewide Rule No. 36 which used 100 ppm H 2 S in the flow stream as a limit. API (2) 14E (1975) noted a limit as 0.05 psia H 2 S partial pressure or greater than 15 ppm (mg/L) H 2 S in the aqueous solution as a sour/non-sour threshold. 4 The table from API RP 14E (1975) with this information is provided in Table 1. The 0.05 psia (0.345 kPa) H 2 S partial pressure was adopted by NACE MR 0175 in the 1978 edition as the sour/non-sour threshold. The 15 mg/L H 2 S limit was not carried forward in MR 0175 and is considered more permissive for H 2 S content as 0.05 psia (0.345 kPa) H 2 S would translate into approximately 10 mg/L H 2 S at ambient pressure in a low salinity aqueous phase; higher pressures or salinity would result in even less dissolved H 2 S.

Abstract A 2018 case study (C2018-10909) required a rapid quantitative assessment of the external corrosion rate (CR) that buried station piping was subject to when equipped with an underperforming Cathodic Protection (CP) system in a high electrolyte resistivity environment. Originally installed multi-function instrumented probes provided initial operating data indicating acceptable CRs despite sub-criterion and speculative CP data. Operating this monitoring system in a multifaceted electrolyte, with confounding electrolyte variables, warranted further investigation when intriguing data was recorded. This follow-up case study presents findings post installation and operation of a revised soil side electrical resistance (ER) probe and coupon monitoring system following originally installed 100 µm probe failures. Utilizing monitoring hardware from multiple manufacturers and datasets beyond CP helped to shed light on the real driver of the original accelerated probe failures. Soil composition at pipe burial depth, installation practices, ER probe data, and CP data all combined to facilitate assessment of the corrosion mechanism through a wider lens. Introduction Operating a Cathodic Protection (CP) system at a remote pump station in a high soil resistivity environment (soil resistivity up to 50,000 ohm-cm) came with its initial challenges. Post original CP system installation it was evident that, at the time, non-traditional monitoring provisions were required to evaluate the CP system performance, and the overall corrosion prevention system effectiveness. Upon installation of the non-traditional monitoring provisions, intriguing data in the form of an elevated Corrosion Rate (CR) were observed over a longer-term period as the system reported data. Background The original installed CP system, designed to electrically isolate unintended below grade metallic infrastructure from the below grade product carrying piping, was impacted from piping installation deficiencies rendering the original CP design objective unachievable. 1 Inconclusive CP data was obtained from CP monitoring devices, which included test stations equipped with CP coupons, installed during pump station construction. A prompt project decision was made to install soil side Electrical Resistance (ER) probes to quantify the corrosion rates observed on probe element surfaces. Detailed in previous paper (C2018-10909), the ER probes initially operated as envisioned, and depicted acceptable corrosion rates given the inconclusive CP data and high electrolyte resistivity.

Abstract Many production chemicals are complex mixtures of surfactants yet are described by a single partition characteristic such oil soluble or water soluble. This paper presents a simple model of multi-component surfactant mixture partitioning based on the work of Zhu and Free. The model is extended to show how the composition of the production chemical changes as the oil/water ratio changes. The results show that the composition of the original production chemical in either the oil or water phases is rarely the same as the neat product on injection and can vary substantially as the water-cut changes over the production life and through the production system. Introduction Production chemicals used in the oil and gas industry are often multi-component surfactants which will partition between the oil and water often with different partition coefficients. As a consequence of the different partition coefficients, the proportion of each component in either the oil phase or the water phase will change as the water cut changes. A simple model has been developed to illustrate the compositional changes in the oil and water phase over the water-cut range. The model is an extension of the work of Zhu and Free, and clearly shows how the ratio of the components in either the oil or water phases rarely matches the composition ratio in the neat product. 1 As a result, if the performance of a production chemical is tested in a single phase e.g. corrosion inhibitor testing in brine only, the composition ratio of the components is unlikely to reflect what will be found under field application.

Abstract The high productivity of pre-salt exploratory wells led to a re-evaluation of Petrobras' model of offshore oil production and exploration. We present here the study that allowed the conversion of exploratory wells into producers, based on the corrosion resistance of carbon steel in different scenarios of pre-salt field production. The aim of the test program was to evaluate the influence of the produced water content (BSW), CO 2 partial pressure and oil characteristics on the carbon steel corrosion resistance. General corrosion analysis showed that for brine content below 40% corrosion rates ca. 0.05 mm/year for 28-day tests. Higher CO 2 partial pressure did not lead to increased corrosiveness, unlike shear stress. There was localized corrosion in most of the evaluated test conditions, confirming the importance of using laboratory techniques that allow such analysis. Localized as well as generalized corrosion kinetics decrease over time, confirming that laboratory tests, even when replicating field conditions, are more conservative as the operation time of the production columns will be extremely longer than laboratory test times. Based on results of this test program it was possible to extend the operation of exploratory wells adopting as safety criteria for well abandonment the produced water content (i.e. BS&W content) and additionally monitoring the internal pressure of production tubing. Introduction The production tubing of PETROBRAS exploratory wells is usually completed in carbon steel or low alloy steel as they operate for a short period, unlike columns in the production wells, which are completed with CRAs and designed for approximately 30 years. Due to high productivity of the pre-salt exploratory wells the idea of converting them into producing wells was considered, however it was necessary to establish safety criteria and operating limits since carbon steel is susceptible to CO 2 corrosion on referred field conditions. It is known that the water content in the oil directly influences the corrosiveness of the medium, but it is complex to estimate, based on existing knowledge, the corrosion rate only as a function of BSW (percentage of water and sediment), since each oil may have different characteristics, which are not incorporated in corrosion rate simulation softwares 1-3 .

Abstract Microstructure and strength affect hydrogen embrittlement (HE) susceptibility of martensitic steels. In order to understand their respective roles, two martensitic steels with the same chemical composition, but different strength (and or hardness) levels were selected. Incremental step load (ISL) technique was used to evaluate the environmental hydrogen embrittlement susceptibilities (EHE) of the materials by in-situ charging of hydrogen at a cathodic potential of −1.2V SCE . Microstructural characterization was performed using TEM. Stress and hydrogen concentration distributions at the time of failure were estimated from a stress coupled hydrogen diffusion finite element analysis (FEA). It was primarily observed that microstructure controlling strength has a more significant effect on HE failure, as compared to microstructure affecting hydrogen diffusion in case of EHE. This observation was further corroborated with fractographic analyses and qualitative discussion based on linear elastic fracture mechanics (LEFM). Introduction Quench and tempered (Q & T) martensitic steels are widely used to manufacture fasteners. These frames, bridges and other structural components. However, premature failures of these fastener components due to hydrogen embrittlement (HE) can lead to total loss of structural integrity and catastrophic failures. For instance, the HE cracking of high strength anchor rods and structural bolts in the San Francisco–Oakland Bay Bridge is a notable incident. 1 However, HE in martensitic steels is a complex phenomenon and has been a topic of research for decades. 2,3 The identification of the factors responsible for HE, involves fundamental considerations implicating the entire fastener supply chain, starting from the steel mill, the fastener manufacturer, the coater, all the way to the end user. The selection of heat treatment process could be considered as a decisive factor towards the prevention of HE failure of threaded fasteners. In general, fastener specifications place broad restrictions on material selection, without any mandate on the selection of a particular grade of steel. As a result, it is necessary to develop a better understanding on the susceptibility of these materials to HE. Based on the sources of hydrogen ingress into the steel structure, there are two broad categories of HE: a) internal hydrogen embrittlement (IHE) which is a delayed failure, caused by residual hydrogen from steelmaking, surface cleaning, electroplating in particular. 4,5 And, b) environmental hydrogen embrittlement (EHE), which occurs due to the introduction of hydrogen by sacrificial corrosion during service such as subsea applications. It is also generally accepted that strength (and or hardness) have a first-order effect on HE susceptibility in high-strength martensitic steels, with an increase in hardness and/or yield strength leading to a decrease in resistance to HE failures. 6–8 However, the underlying mechanism(s) that make strength a significant factor in influencing HE susceptibility needs further understanding.

Abstract There are two well recognized international standards to evaluate offshore atmospheric coatings. One is ISO-12944-9 (historically referenced as ISO 20340) and the other one is NACE TM 0404 (new construction)/TM 0304 (maintenance) with acceptance criteria referenced in NACE SP 0108. The major differences between the ISO and the NACE standards are the cyclic test method and the test duration for the rust creepage test. The ISO requires a 25-week cyclic test duration and NACE standard requires 12 weeks only. Furthermore, the NACE standard requires other coating properties - edge coverage (retention), thermal cycling and coating flexibility to be evaluated. In this experimental program, ten coatings (zinc rich epoxy and non-zinc rich epoxy) systems are evaluated using both test standards. The coatings were applied on grit blasted new steel panels to SP-10 surface cleanliness. The rust creepage test results reveal both standards can differentiate the same good and bad coating systems. In a comparative coating performance evaluation, the NACE method provides an efficient and holistic approach towards reliable coating system selection for offshore platforms. Introduction ISO 12944 (& ISO 9223) has six different corrosivity categories and assigns offshore environment CX (previously C5-M) the highest corrosion category In such a corrosive offshore environment, combined with imperfect application and risk of damage, the offshore platform coating service life can be short (<8 years) resulting in large scale maintenance programs. The price per square foot of maintenance programs are typically an order of magnitude higher than the new construction/erection costs. The maintenance costs can vary but is high and depends on ease of execution, type of maintenance and other factors influencing execution. Therefore, it is desirable for facility owners to select long service life offshore coatings and optimize the total expenditure related to maintenance. There are two well recognized international standards to evaluate offshore atmospheric coatings. One is ISO-12944-9 1 (historically referenced as ISO 20340 2 ) and the other one is NACE TM 0404 3 (new construction)/TM 0304 4 (maintenance) with acceptance criteria referenced in NACE SP 0108 5 . The differences of these two standards are listed in Table 1.

Abstract Well integrity is becoming one of the most relevant issues in Oil & Gas industries, requiring the integration of multidisciplinary teams in areas of subsoil operation, corrosion engineering, maintenance, and production to define and apply the integrity management strategy. Until 2013, the reference in well integrity had been the NORSOK D010 standard, which describes the minimum requirements for operation and performance of the well integrity barriers in the whole life cycle of the asset. On the other hand, operating companies have generated better management practices that were consolidated in the ISO 16530 standard issued in 2017. It was promoted after the Macondo well tragedy in the Gulf of Mexico and became the mainstay of well integrity management. This work does a descriptive review of corrosion, materials, and risk papers within the well integrity management with two objectives. Firstly, to be a tool for the advancement of knowledge, dimensioning the barriers of the implementation of strategy, and describing some available gear. Secondly, to establish requirements for risk assessment and management with generic guidelines to allow the quantification of risk and mitigation actions, and so help the continuous improvement of the well integrity according to the conditions of design, construction and operation. Introduction Well integrity management is based on the fundamental principle of the continuous search for technical, operational, and organizational solutions, aimed at reducing the risk of uncontrolled fluid discharges throughout the life of the well. The normative base is contained in the Norsok D-010 1 and ISO 16530 2,3 standards. Well integrity management started its regulatory process with the NORSOK D10 standard, which is still in force. This standard clearly describes the concept of barriers and the trees of possible events, avoiding the presence of an uncontrolled discharge. This standard was developed by the Norwegian oil industry, although it was scarcely implemented by the oil and gas industry until 2010, the date of BP's Macondo failure.

Abstract Surface erosion and erosion-corrosion are among major degradations in the hydrocarbon industries and are driven by the attributes of process streams and materials of construction for process equipment(s)/piping. Despite significant corrosion and wear resistance, the performance of Ni-P coatings is inhibited due to fracture and cracking by the impact of erosive particles in the process streams. This study involves the preparation of graphene incorporated Ni-P coatings by adding various concentrations of graphene in Ni-P plating bath under stirring conditions. The solid particle erosion behavior of Ni-P coatings was studied under two different erodent velocities of 35 ms −1 and 52 ms −1 and three different incident angles as 45°, 60°, and 90°. Indent size and morphologies were characterized using the microscopic examination. The electrochemical behavior of ternary Ni-P coatings was studied using Potentiodynamic Polarization testing against 3.5 wt.% NaCl solution. Graphene addition improved the electrochemical and wear behavior by the reduction of porosities and improved hardness, respectively. Introduction Pipelines, process equipment for hydrocarbon production and refining industries are prone to numerous degradation mechanisms arising from service conditions namely temperature, pressure, corrosivity, flow velocity etc. Among numerous damage mechanisms, erosion damage from high velocity fluids and abrasive particles is quite prevalent. Various types of erosion damage(s) reported so far are liquid droplet erosion, vapor bubble erosion, cavitation, abrasive particle erosion, and erosion-corrosion etc. 1 The extent of erosion is influenced by many attributes of erodent such as shape (i.e., asperity), hardness, density, impingement angle etc. Moreover, the process conditions and substrate properties (hardness, toughness, surface smoothness) also determine susceptibility to erosion damages. Certain applications in the refining industry require the fluidization of powdered catalysts via steam or air pressure which renders the material of process equipment (reactor, regenerator etc.) susceptible to erosion. Furthermore, the turbulent zones in piping systems (e.g., bends, reducers etc.) have high propensity of erosion damage. Erosion damage from steam impingement in boiler's piping system leads to a more complex and irreparable corrosion namely boiler water condensate corrosion. 2 The corrosion products in the form of debris and chips can sometimes act as erodent thereby aggravating the material loss from erosion-corrosion damage. In addition, higher velocities of the process streams may damage the protective films, thereby accelerating the metal loss rate.

Abstract Additive manufacturing of alloy 718 (UNS N07718) has been largely accepted into many industries and is steadily gaining a foothold in oil and gas applications, primarily in applications involving limited loading conditions in non-corrosive environments. Wrought UNS N07718, a nickel alloy known for its high strength and purpose-built corrosion resistance, has an impressive record of field performance in very demanding oil and gas applications including directional drilling. A broader applicability for additively manufactured UNS N07718 in corrosion applications is currently conditioned by characterization efforts limited to baseline corrosion testing. Additionally, testing has focused on machined surfaces, which are not representative of the surface resulting from additive manufacturing processes. The lack of information regarding corrosion behavior in the as-printed surface condition for this alloy produced using additive manufacturing continues to limit its applicability to the machined surface condition, thus negating benefits gained during the manufacturing process. In this study, the pitting and stress corrosion cracking behavior of additively manufactured UNS N07718 under a variety of surface conditions is investigated. These conditions included machined, as-printed, shot peened, and treated by a micro-machining process. Results from electrochemical and slow strain rate testing in a 2.25 M chloride-containing environment at elevated temperatures are presented and discussed with regards to the influence of surface quality and microstructural peculiarities determined with surface characterization and advanced microscopy on the corrosion resistance of additively manufactured UNS N07718. Experimental results have shown that as-printed surfaces are clearly more susceptible to corrosion and require adequate post-processing surface treatments to restore the expected corrosion resistance of UNS N07718. Introduction Additive manufacturing (AM) - a layerwise manufacturing technique in which a base material is consolidated using heat or force to produce a solid, three-dimensional object - has been successfully implemented in many industries, not only as a prototyping technology, but as a serious production technology. 1 This has been primarily demonstrated in the aerospace industry, but recent years have shown the slow adoption of AM processes into the oil & gas (O&G) industry. One of the most widely used AM processes, selective laser melting (SLM), utilizes a focused high-energy laser beam to fully melt metal powder particles together in a layerwise manner to result in a near-fully dense metal component based on an existing 3D computer-aided design (CAD) model. 2 Utilizing SLM, it is possible to process a wide variety of metal alloys, depending on the weldability of the alloy. One of the most studied alloys processed via SLM is precipitation-hardenable nickel (Ni) alloy 718 (UNS N07718), an alloy which has a long-standing tradition of utilization in demanding oilfield applications such as drilling equipment due to its high strength, good ductility, non-magnetic austenitic microstructure, and excellent resistance to environmentally assisted cracking (EAC). 3

Abstract The effect of NaCl concentration (non-ideality) was investigated on the solubility of FeCO 3 layer. After a layer of FeCO 3 was formed on a gold coated crystal, NaCl was incrementally added into the solution and the mass change of the FeCO 3 layer was measured with an Electrochemical Quartz Crystal Microbalance (EQCM). It was found that the mass of the precipitated FeCO 3 layer did not change with increasing NaCl concentration even though the saturation value of FeCO 3 ( S FeCO 3 .) was far below 1 and dissolution of FeCO 3 was expected. It was hypothesized that the calculation of S FeCO 3 was incorrect due to inaccurate equations for dissociation equilibrium constants or solubility product constant ( K sp ). Therefore, the equations for dissociation equilibrium constants taken from Oddo & Tomson 1982 and the K sp equation borrowed from Sun et al. 2009 were revisited. New equations were proposed for carbonic acid first dissociation equilibrium constant ( K ca ) and K sp . (equation) The predicted pH and S FeCO 3 values at low pressures over a temperature range of 30°C to 80°C and anionic strength range of 0 to 4.95 M were in good agreement with the experimental results. The new equations could justify the observations for the effect of NaCl concentration on FeCO 3 solubility. Introduction Iron carbonate (FeCO 3 ) formed on the internal surface of oil and gas pipelines plays an important role in protecting these pipelines from further corrosion. Whether precipitation of FeCO 3 is thermodynamically favorable is determined by a parameter called saturation of FeCO 3 , S FeCO 3 . In CO 2 corrosion, ferrous ions, coming from the dissolution of the steel matrix, combine with carbonate ions to form FeCO 3 . Precipitation of FeCO 3 occurs when S FeCO 3 is larger than one. If the precipitated FeCO 3 covers the steel surface evenly, it can form a compact and protective layer. This acts as a diffusion barrier hindering the mass transfer of corrosive species to the surface, which enhances the resistance of mild steel to further uniform CO 2 corrosion. S FeCO 3 is inversely proportional to the FeCO 3 solubility limit constant, K sp . Therefore, it is important to be able to calculate K sp accurately, which is a function of temperature and ionic strength. There are several studies that investigated the effect of temperature 1–3 and ionic strength 4 on K sp . When Sun, et al. 5 reviewed literature associated with FeCO 3 solubility, they found studies of K sp at room temperature and very low ionic strength, studies of solubility limit dependence on temperature, as well as studies of solubility limit dependence on ionic strength. Sun et al. combined the equations from Greenberg and Tomson 2 for temperature † and Silva et al. 4 for ionic strength ‡ to obtain a new equation for calculating the iron carbonate solubility product constant as a function of both temperature and ionic strength as follows: (equation) Where T K is temperature in Kelvin and I is ionic strength in mol/L.

Abstract It is important to monitor the corrosion rates of steel in electrolyte environments such as aqueous solution as well as soil in order to evaluate the integrity of the members of facilities. As a nondestructive monitoring method, CIPE (Current Interrupted Polarizing Extrapolation) method was developed. By the CIPE method the corrosion rate is calculated by the Tafel equation obtained from the polarization curve of in-situ measurement. It was found that the CIPE method was useful to monitor corrosion rates of steel in concrete as well as in neutral aqueous solution as presented in the conferences of CORROSION 2018 and 2019. In this paper, results of corrosion rates of carbon steel in sand containing sea water, which were measured by the CIPE method were discussed. As a result, it was confirmed that the CIPE method was also useful to monitor corrosion rates of carbon steel in soil. Furthermore, it was considered that when dissolved oxygen decreased the corrosion rate became negligible and the test piece behaved as a reference electrode without corroding. Introduction It is important to monitor the corrosion rates of steel in electrolyte environments such as aqueous solution as well as soil in order to evaluate the integrity of the members of facilities. As a nondestructive monitoring method, CIPE ( C urrent I nterrupted P olarizing E xtrapolation) method was developed. 1 This method is called CIPE for the abbreviation of the name in this paper. By CIPE method the corrosion rate is calculated by the Tafel equation obtained from the polarization curves of in-situ measurement. This "Tafel extrapolation method" has been used to determine the corrosion rate of steel in solutions since 1950's. 2 However, this method has several problems as follows; (1) Accurate polarization curve can't be obtained due to IR drops which are generated by the polarizing current and resistance of solution between the tip of the reference electrode and the steel surface. (2) Polarization curves are distorted due to changes of the steel surface state, which are caused by the accumulation of ions such as Fe 2+ , H + and OH − during the polarizing process. (3) Deciding the Tafel line from the polarization curve is difficult because it is not clear where the Tafel line starts from.

Abstract In alkaline water electrolyzers many parts are made of expensive nickel-based alloys, which in some cases may be an overly conservative option. Careful evaluation of the operating conditions and new research are required to determine to which extent nickel-based alloys may be replaced by less expensive materials in parts of the system. Electrochemical investigations have been carried out to get a deeper understanding of corrosion and film formation occurring on typical alloys used in alkaline electrolyzers. Potentiodynamic sweeps were performed on carbon steel (UNS K03014) and austenitic stainless steel (UNS S31603) in 25 wt% KOH under O 2 , N 2 and H 2 at atmospheric pressure from room temperature up to 80 °C. The gases represent the anode side, start-up/shut-in and the cathode side, respectively. Differences between the two materials and their response at the different conditions are discussed. Introduction The global renewable energy market is fast growing with a focus on solar and wind. These are intermittent energy sources that are subject to both seasonal and hourly variations, generating significant amounts of excess energy (several TWh/year worldwide) that will have to be stored before utilization. Power-to-Gas technologies, such as water electrolysis, are expected to play a major role in future energy storage systems. Hydrogen production by water electrolysis is highly appropriate for storage of large amounts of intermittent renewable energy. 1 Although polymer electrolyte membrane (PEM) electrolyzers have the best performance for water electrolysis, the complexity of the system with its high pressure operation and the high cost – mainly due to the use of noble metal catalysts – have prevented commercialization thus far. 2,3 An established alternative is alkaline water electrolysis. These operate at lower current densities, but are less expensive and thereby suitable for large-scale hydrogen production. 4 Current R&D typically aim to increase efficiency and decrease operational expenses (OPEX). One strategy is to decrease the cell voltage, which can potentially be achieved by zero-gap systems, 4 or increasing the current density and operating pressure. 3

Abstract Vapor corrosion inhibitors can be more volatile during elevated processing temperatures. It is critical that amount of VCI mass loss is engineered into the final product design. This paper focuses on a study where different vapor corrosion inhibitors are tested for mass-loss at different temperatures by use of TGA; and how this may affect corrosion inhibition level of the end-product. The paper also provides some critical considerations for manufacturing steps to improve application processes and final product quality. Introduction Engineering metals are all unstable on the earth in the environment of oxygen, water, and warm temperatures, because they tend to form more stable compounds to lower their energy by spontaneously reacting with the surrounding environmental species. 1 The damage or deterioration of metal due to this reaction is called corrosion. Additional accelerating factors to this process may include rain, snow, wind, dirt, UV, heat, etc. 2 According to the 2016 NACE IMPACT study, the global cost of corrosion is ~ US$2.5 trillion in 2013. However, 15%~30% of the corrosion cost could be saved by utilizing nowadays available corrosion control technologies, which means US$375 ~ US$875 billion could be saved globally. 3 One of the traditional corrosion protection methods for metals during transport and storage is to use coating or oils. But it has its disadvantages and limitations. The oily coating on metal surfaces needs to be removed before painting or welding, which is an extra step for end-users, rather time-consuming, and raising the cost. There are also some hard to reach spaces such as crevices and surfaces of complex-shaped articles that are difficult to apply coatings. 4 Additionally, coating systems could fail from prolonged environmental exposure and deterioration through UV radiation, moisture, chemical or biological agents, abrasion, water freezing and thaw cycle, etc. 5 New technologies that involve volatile corrosion inhibitors (VCIs) packaging materials keep evolving over the past decades to meet these challenges.