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 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 combination of phosphorus and zinc is mainly used as the carbon steel corrosion inhibitor for cooling water systems in the industrial plants such as petroleum refining or petrochemical plants. Moreover, treatments with high-concentration phosphorous and zinc are also applied to inhibit initial corrosions when the industrial plants are started up. Recently in some countries such as China, using phosphorous is prohibited by the wastewater regulation because of increasing conscious for environment. Therefore, non-phosphorus treatments for cooling water systems are highly required. In this presentation, new developed non-phosphorus treatments (initial and maintenance treatments) are introduced based on the laboratory and field tests. (1) Initial treatment: The combination of a specific organic acid and zinc showed the same inhibition ability as that of high-concentration phosphorus and zinc treatments. (2) Maintenance treatment: The combination of low-molecular weight polymers and zinc showed the same inhibition ability as that of phosphorus and zinc treatments. It was assumed that the polymers improve the corrosion inhibition abilities by dispersing zinc effectively. Introduction For cooling water treatment chemicals, environmentally friendly chemicals should be developed continuously because huge amount of industrial water are used for cooling water systems and it is necessary to concern effect for environment. As carbon steel corrosion inhibitors for cooling water systems in the industrial plants such as petroleum refining or petrochemical plants, chromates treatments were prohibited. The combination of phosphorus and zinc is mainly used because the enforcement of various regulations limit the applicable chemical compositions. 1 Now it is necessary to develop non-phosphorus treatments because regulations of phosphorus discharge from cooling water is expanding globally to prevent ecosystem in environmental water from eutrophication. Especially, China and several parts of USA strictly regulate phosphorus discharge. Therefore, the using phosphorus for cooling water treatment is limited in these areas. Aside from regulations, using phosphorous for corrosion inhibitor in cooling water systems causes undesired issues such as the formation of calcium phosphate scales, increasing cyanobacteria and algae. 1 By using phosphorous as corrosion inhibitors, it is necessary to use scale and slim inhibitors.

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 To obtain heat affected zone (HAZ) hardness levels below maximums specified in the current (2015) edition of NACE (1) MR0175/ISO (2) 15156-3 for sour service use, welded super martensitic stainless steels (SMSS) need post weld heat treatment (PWHT). PWHT is mainly done by stress relieving or tempering post welding as re-austenitizing, quenching, and tempering is not practical in many applications. Double stress relief thermal cycles may be needed so that any martensite which forms due to transformation during the first stress relief cycle is tempered by the second stress relief cycle. Overall, design of PWHT can be challenging to ensure not only meeting maximum hardness requirements but also ensuring meeting minimum design yield strength. This study investigates the austenite start and finish (A 1 and A 3 ) phase transformation temperatures as a function of heating rate and reports the martensite start and finish temperatures (M S and M F ). Phase transformation temperatures in 13Cr-5Ni-2Mo (UNS S41426) alloy are measured using a resistance heating physical simulator coupled with dilatometry. Dilatometry-based phase transformation temperatures are compared with HAZ hardness results in 13Cr-5Ni-2Mo SMSS welds after PWHT. Mechanical properties associated with the different PWHT temperatures are measured to understand the effect of PWHT on design mechanical properties like yield strength. Overview Supermartensitic stainless steels (SMSS) are an important class of engineered alloys for oil and gas applications in which intermediate corrosion resistance is required with high yield strength such as 95 – 110 ksi Minimum Yield (MY) strength in the quenched and tempered condition. 1 Possessing less than 0.03 wt% carbon for improved weldability, 2,3 11.5-13.5 wt% Cr, 4.5-6 wt% Ni, and 1.5-3 % Mo for improved corrosion resistance, 1 SMSS display a good balance of corrosion resistance, 4-6 yield strength above 95 ksi, 1,4 and good weldability, 2,3 but with lower cost than alloys like duplex stainless steels. 1 However, in welded downhole tubing applications that are required to meet current (2015) edition of NACE MR0175/ISO 15156-3, 7 as-welded heat affected zone hardness (HAZ) is limited to 27 HRC (nominal 280 HV per ASTM (3) E140-12b conversion 8 ) for qualification of welded UNS S41426 components by hardness survey for sour service. 7 As-welded HAZ hardness in SMSS grades exceeds 300 HV, 2,3 above the maximum hardness allowed for sour service, 7 and therefore requires application of post weld heat treatment (PWHT) to reduce the as-welded HAZ hardness and reduce likelihood of in service failures. 9 For many applications, re-austenitizing, quenching, and tempering is not a practical PWHT method for control of HAZ hardness, and PWHT is therefore mainly carried out with one 2,3 or two 2 stress relieving or tempering thermal cycles at an appropriate temperature after welding. However, nickel additions to SMSS, required to stabilize the gamma loop and enable martensite formation, 1 also lower the A 1 temperature into the range typically targeted for PWHT. 2,3 PWHT via stress relieving or tempering of these alloys to meet the sour service hardness limits can therefore be challenging. 2,3,10 Development of economical, reliable PWHT procedures is therefore a critical step to deploy SMSS successfully into oil and gas applications where welding is needed.

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 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 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 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.

Abstract Vapor corrosion inhibitors (VCI) are volatile chemistries and eventually they diminish at the source to provide the necessary protection on valuable assets. Shipping and Storage Covers with vapor corrosion inhibitors are used to protect military equipment, wind energy assets and other high value industrial goods. This paper provides gas chromatography-mass spectrometry (GC-MS) testing and data on corrosion inhibitors. New and used protective covers with corrosion inhibitors; were tested to answer the end users concerns; if the VCIs last as long as the covers do; or do they deplete before the covers need replacement? Introduction Military equipment must be mission ready at all times. These military assets may include military ground vehicles, weapon systems, support equipment and other deck equipment on naval ships. Metal parts contained in such equipment are subject to the effects of corrosion, a natural process. 1 To mitigate corrosion damage on this equipment and meet readiness requirement, significant amount of efforts have been put by the armed forces. According to United States Government Accountability Office (GAO) report GAO-19-513 in May 2019; the cost impact of corrosion to Department of Defense (DoD) assets in fiscal year 2016 was $20.6 billion. 2 Some of the traditional corrosion mitigation methods for these assets may include general-purpose warehouses, shed storage facilities, controlled humidity preservation (CHP) storage facilities, or heavy-duty tarps. However, they have their limitations in terms of accessibility and day-to-day use. Warehouses and storage facilities are not always available and accessible in every location. To build one requires a lot of capital and sometimes it is not even practical considering the size of the equipment. Heavy-duty tarps may be applicable on some cases, but custom fitted covers may be better suited on complex items. Corrosion control covers have been used in all branches of the U.S. Armed Forces including, USMC, Army, Navy, Airforce and National Guard, in various climates. In 2000, the US Navy started a small business innovation research (SBIR) funding to study and develop "Flexible Corrosion Preventative Coverings". The first-generation of protective covers with VCI technology was patented as US 6,444,595 in 2002. 3 According to a United States Airforce (USAF) report published in 2008, after a year-long study of different corrosion protection methods, the first-generation advanced protective covers with VCI could provide up to 10 times better asset protection comparing with the traditional protective methods. 4 Naval Sea System Command (NAVSEA) approved the use of these protective covers for a variety of equipment ranging from weapon systems to deck equipment in 2003. 5 With the rapid technology developing in this field, a new generation of VCI covers emerged as providing more breathability, flexibility and durability against rough surfaces of military equipment in 2012. Two US patents, US 8,883,284 and US 8,828,487, were granted on this new technology. 6 According to a paper on this new technology presented at Fleet Maintenance & Modernization Symposium (FMMS) in 2016; 7 the US Navy was the first to use these protective covers and demand has steadily increased across the other military branches.

Abstract EIS (Electrochemical Impedance Spectroscopy) technique has been used in many areas such as biosensors, battery development, fuel cell development etc. Many efforts have also been made to apply this technique to paint/coating evaluations. The epoxy industrial coatings containing fillers or ceramic beads are commonly used in chemical processing, Mining/Mineral & Ore processing, Oil/gas, Power (fossil, hydroelectric, and nuclear), water/waste water, etc. These coatings provide excellent corrosion and erosion resistance for metal and concrete surfaces. EIS is a useful tool to investigate corrosion/erosion resistance of these protective coatings under various environment conditions. EIS can measure impedance of coatings and phase angle of imposed AC voltage/current. The changes in impedance and phase angle can be used as indicators of coating structure changes caused by corrosion, erosion, water penetrations, etc. There are various ways to analyze EIS data to correlate the data with the performance of paint/coating products but these methods all have limitations when used to evaluate high performance protective coatings. In this presentation, we discussed the limitations of commonly used EIS data analysis methods. A modified CPE model is proposed to evaluate high performance protective coatings on water/chemical penetrations and/or surface deteriorations due to corrosion and/or erosion. Introduction EIS data fitting models are composed of resistors, capacitors, and other electronic components. These electronic elements can be used to simulate coating films, defects or damages of coating samples. In many models, a perfect coating film is considered as a capacitor. Resistors and Capacitors in EIS Data Fitting Model Resistors are electronic components which have constant electrical resistance. In both DC (direct current) and AC (alternating current) circuits, the impedance of a resistor can be calculated by (inline-equation). Resistors always have constant impedance which are independent of frequency of AC voltage in AC circuits. Capacitors are different from resistors. In a DC circuit, current flow stops when a capacitor is fully charged, so the impedance is infinite. In an AC circuit, the impedance (also called reactance) of a capacitor can be calculated by equation: (inline-equation), where C is the capacitance of the capacitor, f is frequency, ω is angular frequency by radians. From this equation, the impedance of a capacitor is inversely proportional to the frequency of the AC power supply: (inline-equation). At extreme high frequency, the impedance equals 0. At extreme low frequency (an AC circuit), the impedance is infinite, which means that there is no current flow through the capacitor.

Abstract Many Oil & Gas fields are sour with H 2 S partial pressures above 0.05 psi. For such situations, it is critical to employ OCTG qualified for sour service, resistant to SSC. As corrosion processes in acidic environments with dissolved H 2 S make the testing solution to drift, some standardized test solutions are highly buffered with the acid-base couple acetic acid / acetate. Another method for limiting the pH drift consists by frequent additions of strong acid during the test. The objective of this work is to compare NACE TM0177 Solution B, EFC 16 solution with and without pH adjustment and HLP solution. Thermodynamic calculations for predicting the saturation pH, hydrogen permeation tests, corrosion rates and fine characterizations of iron sulfide scales were performed for being correlated to SSC test results and for understanding the impact on the hydrogen uptake and the protectiveness of corrosion products. Introduction Enhanced metallurgies must be selected for OCTG for preventing catastrophic failures due to SSC in sour gas and oil wells. According to the Annex B of the NACE MR0175/ISO 15156-2 document, 1 a material is identified as SSC resistant when it has a threshold stress higher than 80% AYS with uniaxial tensile test in the sour brine NACE TM0177 Solution A saturated by 1 bar H 2 S. 2 Since a couple of decades, the increase of the mechanical properties of OCTG was motivated to access hydrocarbons in deeper reservoirs. For example, 125 ksi SMYS materials resistant to SSC were developed but for limited range of range of pH and P H2S , so-called fit-for-purpose (FFP) environments. 3-5 NACE TM0177 Solution A, as defined in the 70's, is acknowledged as a very severe sour Quality Control (QC) condition. Consequently, the pH drift during the corrosion test and resulting from corrosion processes is not a matter of concern. On the contrary, for materials qualified in FFP environments, it is important to keep constant the sour severity level by limiting the pH drift as much as possible. Several strategies are employed to fulfill that objective; either by increasing the buffer capacity of the test solution, which is predominantly done thanks to the acid-base couple acetic acid/acetate, 6 or by the regular addition of a strong acid during the test duration. 7 Up to now, few information is available on the impact of pH control and more globally of the test solution composition on SSC. Even though regions of environmental severity for SSC in NACE MR0175 / ISO 15156-2 are defined only through pH and P H2S , it is now well established that the gas composition modifies the risk of SSC occurrence by affecting H 2 S gas fugacity and consequently aqueous H 2 S activity. This fact has motivated the addition of a technical circular inside ISO 15156 document. 8 Some works provided evidences that the composition of the solution itself is susceptible to impact directly the risk of SSC on low alloyed steels. Case et al. observed an increase of the threshold stress intensity factor on C110 when increasing salt concentration, which impacts the aqueous H 2 S activity and also likely adsorbed H 2 S coverage on steel surface. 9 Duvall Deffo Ayagou and co-authors investigated the influence of the acetic acid / acetate buffering on the corrosion rate and the hydrogen uptake of X65 linepipe. 10 Corrosion rates markedly increase with the buffer capacity of the test solution and hydrogen permeation fluxes as well.

Abstract This paper introduces permeation-based models used for the prediction of the unique environments of the flexible pipe annulus where the armour wires are placed in the flexible pipe structure. Test results are presented for SSC behavior of the armour wires in high pressure autoclaves simulating one to one the conditions of a flexible pipe annulus. The results are compared with tests executed at ambient pressure with both a partial pressure approach and with an approach based on H 2 S fugacity. The difference in results are discussed in the context of the potential improvements possible with using fugacity for qualification of armour wires exposed to H 2 S related degradational mechanisms. Introduction The recent suggestion of the H 2 S fugacity as the governing parameter in Sulfide Stress Cracking (SSC) and/or Hydrogen Induced Cracking (HIC) is a change from the conventional use of partial pressure as the governing parameter. 1-4 Whereas the is still no general industry consensus on this approach the use of fugacity is already being introduced in testing programs for armour wires used in unbonded flexible pipes. Traditionally, qualification testing for carbon steels is in accordance with NACE TM-0177 executed at ambient pressure, replicating the H 2 S partial pressure from the high-pressure operation condition into the ambient pressure test condition. 5 When using a fugacity approach, it is the calculated H 2 S fugacity from the high-pressure condition which is replicated in the ambient pressure testing. The use of H 2 S fugacity in qualification may potentially reduce the overall conservatism related to qualification testing; thus, requiring validation before it can be applied. The Flexible Pipe Unbonded flexible pipes are constructed from concentric layers of polymeric and steel material. In order to preserve the flexibility of the pipe construction, the layers are not bonded together hence the phrasing unbonded flexible pipe. Figure 1 shows a typical cross section of an unbonded flexible pipe illustrating typical layers. Various types of unbonded flexible pipes may omit some of the layers. Below is a description of each of the main layers.

Abstract Recently, a power company identified their current procedures for corrosion protection with industrial coatings of pipe cable sections as an opportunity for process improvement. The power company sought to decrease the difficulty of maintaining coatings on these assets, increase the service life of the coating systems, and decrease life cycle cost. This presentation will provide a narrative of the steps taken during the process improvement, i.e., evaluation of the current paradigm, development of improved procedures and identification of better materials afforded through advances in coatings technology, implementation of the improvements, and lessons learned. Introduction Recently, a power company was not satisfied with the performance of the coatings they were applying to pipe cables. The pipe cables are steel protective covering for conductors transmitting as much as 140,000 volts. The pipe cables are filled with pressurized oil or nitrogen to prevent internal corrosion and short circuiting. The pipe cables are buried with exception of intermittent concrete underground concrete chambers. For oil filled pipe cables the chambers provide for access to valves for sampling and inspecting the oil. Manholes provide access to the chambers. The chambers frequently fill with stormwater and the pipe cables are immersed. This environment and set of circumstance pose many challenges for external corrosion protection of the pipe cables with coatings including limited access, confined space, immersion, high humidity, and poor visibility. Coatings were failing prematurely, and the company engaged a corrosion and coatings consulting company to develop process improvement to increase coatings service life and decrease life cycle cost. Experimental Procedure Premature coating failures are typically caused by inadequate surface preparation, faulty application, or improper material selection. To identify the cause and recommend process improvement the consultant used a two-step technical approach – (1) Review of Background Information, and (2) Existing Coatings Condition Assessment. Review of Background Information The Consultant interviewed the client, reviewed current client specifications, QA/QC practices, and previous inspection reports. The consultant learned through discussions with the client performed by a contracted asset maintenance firm. The spot repair maintenance painting tasks are completed by personnel without specific coatings training responsible for other maintenance activities. Comprehensive specifications are not used however, the surface preparation and coating products requirements are included in the task orders in a general standard, table format. The utility had been using mostly bitumastic as the standard coating system and in some instances used a silicone coating for spot repairs. Review of QA/QC practices revealed critical inspections were not being conducted, e.g., monitoring of ambient conditions, soluble salt testing, by the maintenance personnel. Lastly, third party inspection had not been used.

Abstract Organic corrosion inhibitors (CIs) are widely employed in the oil and gas industry to protect carbon steel pipelines against internal corrosion. Inhibitor selection by corrosion engineers frequently relies on long testing procedures and protocols, which requires significant time and expenditure. This study aims at providing a simpler and more reliable methodology for inhibitor characterization, which can contribute to inhibitor selection in the oil and gas industry. Two model compounds, tetradecyl phosphate ester (TPE) and tetradecyl tetrahydropyrimidinium (TTHP), were chosen for this methodology development in an aqueous environment of 5 wt.% NaCl (pH = 4.5) at 25° C . Linear polarization resistance (LPR) measurements were conducted to determine the corrosion rate (CR) over a wide range of CI concentrations, from which surface saturation concentration and surface coverage (?) values were extracted. Kinetic parameters for adsorption (k A , k D , and K AD ) were obtained by means of Langmuir adsorption isotherm and non-linear regression analysis. Potentiodynamic polarizations were executed to analyze the inhibition behaviors. It is concluded that both TPE and TTHP could retard anodic and cathodic reactions with no change in limiting current. Introduction Corrosion inhibitors (CIs) are widely used in the oil and gas industry to protect carbon steel tubulars against internal corrosion. CIs can be injected continuously into a corrosive environment at very low concentrations to decrease the corrosion rate of the exposed metallic material and maintain effective corrosion protection 1 . CO 2 corrosion inhibitors typically consist of amphiphilic, surface-active molecules with alkyl tails typically in the range of C12 to C18 2 . Such molecules have a strong tendency to adsorb onto the steel surface and form self-assembled structures 3,4 . However, the performance of these surfactant-type CIs is influenced by operating conditions, such as temperature, pressure, pH, and flow. If a corrosion inhibitor is added without considering these factors, its efficiency could be decreased and sometimes lost, which may result in unpredictable behavior and corrosion-related failures 5-7 . Generally, operators in the field find it very hard to predict CIs performance in advance, if there is any change in the operating condition. Consequently, an effective corrosion prediction tool would be indeed of great value. The long term objective of this work is to develop such an inhibition prediction tool, using, as a starting point, the inhibition model proposed by Dominguez Olivo 8,9 . For now, the goal of this study is to develop a methodology for CI characterization valid in a wide range of conditions, which can be used for CI selection and dosing strategy. So far, the practice of corrosion inhibitor selection for corrosion engineers in the oil and gas industry usually relies on long testing procedures and protocols 6 . This practice requires excess time, which could be shortened with the development of methodology for CI characterization.

Abstract Lining the floor bottoms and vapor space within an Aboveground Storage Tanks (AST) is a well-proven method to mitigate internal corrosion of the carbon steel substrate. An AST is usually scheduled for out-of-service inspection at least 10 years after its initial in-service date; sometimes the out-of-service schedule could be even longer (e.g., over 20 years) depending on the local regulations and engineering assessments. Therefore, the selection of an appropriate tank lining system and its application are critical for long term performance in maintaining the integrity of the assets. API Recommended Practice (RP) 652 [1] provides recommendations on the application process of lining materials and a guideline for lining system selection. The same practice lists the general benefits and limitations of thin and thick film linings and provides items that should be considered when selecting a liner; however, API RP 652 does not provide a testing protocol for lining selection and qualification. This paper presents a qualification test protocol for selecting lining for storage tank bottoms and vapor spaces exposed to hydrocarbon products. The protocol includes, but is not limited to, standard atlas cell, pressurized atlas cell, and autoclave testing. In addition, the paper discusses best practices for application of these systems on large diameter (> 50 m) tanks in crude oil service based on extensive field experiences. Introduction Internal corrosion within an aboveground storage tank (AST) or breakout tank may be attributed to water within the crude oil to contact the carbon steel surface. Hydrocarbon products will contain small fractions of basic sediment and water (BS&W) content within crude oil transmission pipeline. The BS&W of hydrocarbon products from Canada are restricted by tariffs to typically not exceed 0.5 percent by volume, while most U.S. tariffs restrict the content to less than 1.0 percent [2]. This water is primarily present as a stable emulsion, maintaining an oil-wet pipe, protecting the internal surface of the pipeline from corrosion [3].