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].

Abstract Double-Loop Electrochemical Potentiodynamic Reactivation (DLEPR) is a useful technique to measure the degree of sensitization (DoS) in austenitic stainless steels, as it is fast, nondestructive, and accurate in identifying low to medium DoS. While its use has been well-established for wrought austenitic stainless steels, the same is not true for their cast equivalents. A modified version, with more aggressive conditions in order to more selectively cause reactivation in regions that had residual ferrite from solidification, was tested with cast austenitic stainless steel spanning both UNS J92500 and J92600 compositions. Testing included microstructural evaluation of polished surfaces after the electrochemical tests and DoS measurements. The modified DLEPR consistently measured higher DoS values, but the trends in the data were the same for both versions of the test. Microscopy was more difficult with the modified DLEPR, as the surfaces were more severely corroded, somewhat masking smaller features such as inclusions and twin boundaries. Introduction Stainless steels are susceptible to sensitization in the temperature range of 500-900°C. 1-3 This is caused by the formation of Cr-rich M 23 C 6 (carbide) particles on the grain boundaries (GBs), resulting in a local depletion of Cr in the surrounding area, leaving it vulnerable to corrosive attack in the form of intergranular corrosion (IGC). 4-9 Electrochemical potentiodynamic reactivation (EPR) is a common method to evaluate the susceptibility of stainless steels to IGC caused by sensitization. ASTM (1) G108 is a standard method of EPR for use with wrought austenitic stainless steels, but it requires a 1μm surface finish to give reliable results and is strongly affected by the grain size of the sample. 10, 11 A more robust EPR method is the Double-Loop EPR (DLEPR) test and is insensitive to surface finish and only slightly sensitive to grain size. 10, 12 These methods are stated to only apply to wrought austenitic stainless steels, such as UNS S30400 (304) and S30403 (304L). 10-12 In the literature, a modified DLEPR method exists for the cast equivalents of 304 and 304L, UNS J92600 (CF-8) and J92500 (CF-3) respectively. It is more aggressive in both its electrolyte and test parameters in order to compensate for the variations in microstructure that occur from casting. 13 The cast materials often have residual ferrite due to the sequence of solidification, and no cold- or hot-working is done to homogenize the structure to pure austenite. 14-17 As a result of the presence of ferrite, which contains higher Cr concentrations than austenite, the cast materials can passivate more strongly, necessitating the use of more aggressive corrosion tests. 13

Abstract In response to new Pipeline & Hazardous Material Safety Administration (PHMSA) and Department of Transportation (DOT) regulations asking owner/operators to be more diligent in 'monitoring' their assets due to internal and external pipeline corrosion. Many operators are using both wired and wireless ultrasonic sensors for both buried and above ground assets between regularly scheduled in-line inspections (ILI). By doing so, operators are able glean important wall thickness data, which they otherwise wouldn't have without incurring significant costs from excavation, mass screenings such as ILI, etc. In addition, these operators can now use this data to map corrosion rates based on operational activity, mechanical activities, cleanings, chemical inhibitor utilization, etc. All of which help to paint the asset integrity and health of the asset under consideration which can extend its life of keep from leaks, spills, or other events. The ease of deployment coupled with the durability and flexibility of the different sensor platforms is allowing single point, multi-point, or area monitoring of critical asset locations to be monitored to allow operators to maintain their normal inspection intervals. Sensors are being deployed predominately for two different scenarios: New Construction: For areas which have been identified as low spots or potential troublesome locations during pipeline plotting. Asset Integrity Monitoring: For areas which have been identified by smart pigs or ILI. If a section has leaked or is in need of fix, sleeve, or repair, sensors are installed in the area where the asset failed previously. For pitting or 'low spots' which have been identified by the mass screening, sensors are placed on the areas which are marked to monitor the anomaly. This allows the asset owner to keep regularly scheduled ILIs as they are monitoring these low spots between inspections. Effectiveness of Mechanical or Chemical Cleaning: Using readily available corrosion data to confirm the presence/mitigation of corrosion activity at different locations along the asset. Essentially saving time and money by confirming, "Am I cleaning too much, or not enough?" or "Am I using enough (or the proper) chemical inhibitor, or too little?" In any of the above examples, these sensors can provide critical data around episodic or gradual ware of the asset due to microbiologically induced corrosion, chemical inhibitor effectiveness, and frequency of required cleaning.This paper will cover the sensor technology, deployment, and case studies around how the technology has helped owner/operators better protect their critical midstream assets.

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 ATI has developed ATI 642 ™† alloy, a new Ni-Cr-Mo corrosion-resistant alloy that displays significant resistance to sensitization from the effects of hot-clad bonding and welding operations. The new alloy is unique because of its substantial Fe content, which gives it a significant cost advantage over Ni-based alloys of similar performance, while still containing enough Ni to provide SCC resistance superior to 6Mo stainless steels. It has a PREN value in excess of 40, which provides useful resistance to chloride environments such as seawater. This paper will present the results of chloride stress-corrosion cracking (SCC), intergranular attack (IGA), and critical pitting temperature (CPT) corrosion tests, as well as results of tensile tests and Charpy impact energy tests. Testing was conducted in both the solution-annealed condition and following a sensitizing heat treatment that simulates typical exposure during the hot-clad bonding fabrication process. The microstructures of the new alloy in the solution-annealed, sensitization-heat-treated, and welded conditions will also be shown and discussed. The test results and microstructures will be compared to those of other alloys traditionally used by the oil and gas and chemical processing industries. Introduction UNS (1) N06625 (alloy 625) is one of the most commonly used materials in the oil and gas (O&G) and chemical processing industries (CPI) because of its excellent corrosion resistance and its long history of reliable service. However, alloy 625 is relatively expensive because its chemical composition was designed to be suitable for a wide range of end uses in both high-temperature and aqueous corrosion-resistant applications. When less corrosion resistance is required, N08825 (alloy 825) is often used for similar applications. Although alloy 825 is less expensive than alloy 625, there are several environments where it is not a suitable replacement, such as in aqueous environments with high chloride contents at elevated temperatures. This is because alloy 825 is more prone to pitting and crevice corrosion, and to stress corrosion cracking (SCC) under those conditions.

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 Proper maintenance of pipelines reduces the occurrences of failures due to internal corrosion to a remarkable degree. Primarily, the two methods employed in maintaining a pipeline are mechanical cleaning (pigging) and chemical treatment, (corrosion inhibitors & biocides) often used in combination. The technique known as batch filming uses a "pill" of concentrated chemical contained between two pipeline pigs; a lead pig and a filming pig (referred to as a pig "train"). In theory, the filming pig allows a small volume of chemical to continuously bypass the rear of the filming pig as the train moves down the pipe. This method is intended to coat the inner surface of the pipeline in a uniform layer of protective corrosion inhibitor. In practice it is very difficult for operators to determine the consistency of the coverage, and the thickness of the film deposited by a batch filming procedure. It is also very challenging to determine how long the chemical film can remain effective after it has been applied, especially if subsequent cleaning pigs are used as part of the maintenance schedule. To replicate the batch filming process at a pilot scale, a flow loop was modified with the capabilities of launching multiple 4" (10 cm) diameter pipeline pigs. The discussed methodology enabled researchers to batch film a pipe and analyze the thickness/coverage of the coating while varying specific parameters (contact time, pig design, chemical type and dilution ratio). The method also allowed for the observation of the effect of various cleaning pigs on the integrity of the applied film. The test scheme may provide valuable information to pipeline operators and chemical vendors about the use of batch filming and its reliability, as well as providing design insight to pig manufacturers. Introduction In previous studies, InnoTech Alberta has explored the effectiveness of various cleaning pig designs through a devised test method involving the use of a flow loop. 5 Following successful development and application of the test method, more challenges involving pigging practices were explored. As stated in previous works, 5 maintenance pigging and inhibitor application are the two main methods to prevent internal corrosion of pipelines. Inhibitor application typically comes in one of two forms: continuous injection, and batch filming. 6 With continuous injection, the chemical is dosed at a controlled rate into the pipeline and travels downstream with the fluid. This method is sometimes used when bottom of the pipe corrosion is the main issue. In this case the chemical should be denser than the carrier fluid, allowing it to flow along the bottom of the pipe, reaching the problematic areas.

Abstract Corrosion is a major concern in transmission pipelines that transport captured CO 2 . While dry CO 2 is noncorrosive, significant corrosion has been reported in dense phase CO 2 with trace amounts of water and impurities such as O 2 , H 2 S, SO x , and NO x . The aim of this work is to improve our understanding of the physicochemical aspects on the corrosion of carbon steels in the high-pressure environments associated with CO 2 transmissions pipelines. The effect of flow on the corrosion of X65 carbon steel was investigated in a series of autoclave tests with different combinations of impurity concentrations in supercritical CO 2 condition (8 MPa and 35°C). The corrosion rate of samples was determined by weight loss measurements. The surface morphology and the composition of the corrosion product layers were analyzed by using surface analytical techniques (SEM and EDS). Localized corrosion was measured via surface profilometry after corrosion products were removed. Results showed that no corrosion was observed in the supercritical CO 2 with 650 ppm of water, 50 ppm SO 2 , and 100 ppm NO, but corrosion occurred when SO 2 concentration was increased to 4500 ppm and 40,000 ppm of O 2 was added to the system. The presence of flow significantly accelerated the corrosion of carbon steel. Furthermore, localized corrosion was observed in the presence of both O 2 and flow. Introduction It is well known that dry CO 2 does not corrode carbon steels, and negligible corrosion occurred at water-unsaturated conditions (below solubility level) in dense phase CO 2 (liquid and supercritical). 1-5 However, it has been reported that noticeable, and potentially severe, corrosion occurs at water-unsaturated conditions in dense phase CO 2 with the presence of impurities, such as O 2 , H 2 S, SO 2 , NO 2 , etc. due to synergisms between chemical species. 6-14 Hua, et al. , 8 reported that general corrosion rates ranged from 0 to 0.012 mm/y with water contents varying from 300 ppm to 2800 ppm in the supercritical CO 2 with 1000 ppm O 2 . They also found that the general corrosion rates of X65 steel increased from 0.01 mm/y to 0.06 mm/y with water concentration increasing from 300 ppm to 1770 ppm with 100 ppm SO 2 and 20 ppm O 2 at 35°C and 80 bar. 9 Xu, et al. , 10 reported that the general corrosion rates of X70 steel varied from 0.03 mm/y to 1.78 mm/y at relative humidities ranging from 45% to 100% at 10 MPa CO 2 and 50°C with 2% SO 2 and 1% O 2 . Dugstad, et al. , 11 investigated the corrosion behavior of carbon steel exposed to liquid CO 2 flow for 10 days at 10 MPa and 25°C. The results showed that there was no corrosion in the liquid CO 2 flow with 500 ppm w H 2 O, while adding 500 ppmw SO 2 induced corrosion at a rate of 0.02 mm/year, and adding 500 ppm w NO 2 caused severe corrosion with rates reaching 1.6 mm/year. Choi, et al. , 11 investigated the effect of H 2 S on the corrosion behavior of pipeline steels in high pressure CO 2 systems. It was found that the general corrosion rates of the carbon steel and 1Cr steel tested were below 0.01 mm/year with the presence of 100 ppm H 2 O and 200 ppm H 2 S in the liquid (25°C, 12 MPa) and supercritical (80°C, 12 MPa) CO 2 phases.

Abstract The comparison of the pitting resistance of alloys with high corrosion resistance can be challenging, as CPT-values (critical pitting temperatures) are often above the boiling point of the test solutions. For high-nickel alloys, the use of potentiostatic electrochemical methods at increasing temperatures can also be questionable, as this alloy type often shows high or continuously increasing current densities with increasing temperature, rather than the desired distinct current peak at pitting. The applied electrochemical potential must also be proven to be below the transpassive potentials of the tested alloys. A new electrochemical method has been developed in which CPT-values could be determined of alloys UNS N08935, UNS N06625, UNS N06455 and UNS N06985. The electrochemical potential used is shown to be below transpassive potentials. The current density versus temperature curves were analyzed and showed low passive current densities up to temperatures where pitting started. CPT-values of the tested alloys were around 90°C for UNS N08935, UNS N06625 and UNS N06455 and 55°C for UNS N06985. Introduction Laboratory CPT-tests often have the benefit of being quick and easy to perform and can give important information of the pitting resistance of different alloys. Tests of pitting resistance are also frequently used for delivery testing, as a reduction in the CPT-value can identify defects in the materials. In this case a pass or fail-test at one temperature is typically done, instead of determining a CPT-value. Additionally, CPT-values can be used to differentiate between the pitting resistance of different alloys. This can be valuable at materials selection and may assist in evaluating life-time cost related to properties. The actual conditions at the place of intended use must be well known, as for instance the pH-value or contaminants may influence the corrosion resistance. Comparing CPT-values of different alloys Some problems may be encountered when attempting to determine CPT-values for certain alloys or using specific methods. It may, for instance, be difficult to find CPT-values for alloys with very high pitting resistance, as pitting may initiate only above the boiling points of test solutions. ASTM (1) G48 was developed using a maximum temperature of 85°C. 1 Changed test conditions at increased temperatures have been reported, especially of the pH-value, the potential and formation of deposits on sample surfaces. 2,3,4 Another standardized method, ASTM (1) G150, uses an applied electrochemical potential of 700 mV SCE (SCE: saturated calomel electrode) and a critical current density for CPT of 0.1 mA/cm 2 . 5 It has the advantage of being quick, as CPT is determined without iterative procedure and each test typically has a duration of a few hours. On the other hand, the test was developed for stainless steels and its use for nickel alloys is questionable, primarily due to their often lower transpassive potentials and potentially higher passive current densities. The 1M NaCl-solution used in ASTM (1) G150 is also too weak for highly pitting resistant alloys to obtain pitting.

Abstract Over the past decades, several corrosion prediction models have been developed for Upstream Oil and Gas process conditions. These models provide the unmitigated corrosion rates in typical sweet or sour conditions. However, the practice of field operations is typically based on the mitigated corrosion rate. Therefore, the predicted unmitigated corrosion rates cannot directly be used to understand real-life situation unless the effect of mitigation is effectively considered. Currently, the mitigated corrosion rate is typically quantified via a very simplified method (e.g. corrosion inhibitor availability). Corrosion prediction is designed to look forward and, ideally, should also be part of corrosion and asset integrity management. For this purpose, a robust analysis of the mitigation practices and methods is essential. This paper provides an overview of aspects to be considered when predicting mitigated corrosion rate for the case of continuous corrosion inhibitor (CI) injection as the mitigation barrier. It is proposed to use a combination of models to calculate the mitigated corrosion rate in a practical and reliable way. It is recognized that partitioning of the CI among different phases is a key aspect in relation to the field application of inhibitors. Therefore, guidance is provided to incorporate this as part of the corrosion mitigation and its prediction. Introduction Due to the potential impact of corrosion in oil and gas production, the phenomena of CO 2 corrosionH 2 S corrosion and organic acid corrosion are heavily studied. For materials selection as well as asset integrity and corrosion management, the threat of corrosion needs to be identified and evaluated, before mitigation strategies can be defined [1,2] . For this purpose, a wide range of corrosion prediction models have been developed [3-30]. The following type of models can be distinguished: - The earliest models, typically empirical and semi-empirical models for CO 2 corrosion [3-7] - Mechanistic models for corrosion tests-methods [9] and later to real process flowing conditions [10,11] and electrochemical models [12] . - Inclusion of a wider range of relevant corrosion mechanisms [8,14,19,20] first inclusion of organic acids [8] and more recently H 2 S corrosion [15-17] - Including specific phenomena like top of line corrosion [24-30] and oil-wetting [31,32] .

Abstract As part of the Feedstock Conversion Interface Consortium four samples of pine chips (all combinations of low and high moisture and ash content) were collected and processed for fast pyrolysis. The prepared biomass samples were liquefied at the National Renewable Energy Laboratory (NREL) using the fast pyrolysis process. Following some characterization of the bio-oils at NREL, the bio-oils were shipped to Oak Ridge National Laboratory (ORNL) for corrosion testing and further characterization. The content and composition of ash in each bio-oil was determined. Corrosion testing consisted of exposing selected metallic and elastomer samples for 1000 hr at 50°C and for longer times at room temperature as well as electrochemical impedance spectroscopy measurements to assess relative corrosivity of the bio-oils. Chemical characterization was conducted to identify the corrosive component of the bio-oils as well as to define the chemical differences among the oils. It was hypothesized that there could be a catalytic effect from the higher ash content in two of the biomass sources. Results of these characterization and corrosion studies will be reported. Introduction Use of liquid fuels produced from biomass is an attractive option for significantly reducing production of greenhouse gases compared to combustion of fossil-derived fuels. Thermochemical approaches to bio-oil production, including fast pyrolysis, hydrothermal liquefaction and catalytic fast pyrolysis, are being studied extensively and show great potential. However, the significant oxygen content of biomass results in the bio-oils being quite acidic. This manuscript has been authored by UT-Battelle, LLC under Contract No. DE-AC05-00OR22725 with the U.S. Department of Energy. The United States Government retains and the publisher, by accepting the article for publication, acknowledges that the United States Government retains a non-exclusive, paid-up, irrevocable, world-wide license to publish or reproduce the published form of this manuscript, or allow other to do so, for United States Government purposes. The Department of Energy will provide public access to these results of federally sponsored research in accordance with the DOE Public Access Plan (http://energy.gov/downloads/doe-public-access-plan) .

Abstract In the oil and gas industry, the management of the integrity of all pipelines and associated equipment ensures safe operation and availability for production during their intended life. Pipeline integrity assessment is usually executed in three separate steps: 1. threats (e.g., corrosion) analysis including effectiveness and efficiency of mitigation; 2. verification by monitoring and inspection; 3. fitness for service analysis to determine integrity status, estimate remaining life, and identify required follow up actions. Typically, in-line inspection by intelligent pigs is used to inspect for corrosion covering the entire pipeline. However, this approach is not always practical for more remote non-piggable pipelines, where verification can be a challenge and monitoring at topsides is often not sufficient to provide reliable data on the corrosion threat and effective mitigation of the full pipeline length. Therefore, alternative approaches are sometimes necessary. This paper describes a practical engineering approach that leverages the available expertise, consisting of the following steps. 1. This method starts with the corrosion analysis to determine a worst-case scenario of maximum expected wall loss. The analysis uses corrosion prediction software (that includes multiphase flow model, a verified oil-water wetting model) as well as an analysis of the mitigation measures by operations (including corrosion inhibitor injection availability) and the data available that supports the corrosion inhibitor performance. This analysis results in a flow and corrosion profile and identification and prioritization of critical locations for local area inspection. Wall loss at a different scenario with different confidence is also estimated based on both model and data limitations. 2. An inspection plan, including identification of the minimum required scope and inspection method, is developed and implemented. Fitness for purpose analysis is performed based on different limit states. 3. Local inspection results are extrapolated to the whole system using different statistical methods to give an updated corrosion profile. The confidence of the overall integrity assessment is established based on both corrosion confidence and inspection confidence. 4. The inspection results are analyzed, resulting in a pipeline integrity status determination, which includes remaining life/extension and next inspection due date.

Abstract Sucker rod pumps are widely used in artificial lift technology of Oil & Gas production. Corrosion, fatigue and corrosion-fatigue are common failure modes that limit life of the sucker rods that drive these pumps. Of these, corrosion fatigue is probably the most common. The initiation site for corrosion fatigue is typically a corrosion pit. The factors that contribute to the formation of corrosion pits were investigated. Four different sucker rod materials were evaluated with respect to (1) chemistry, (2) non-metallic inclusion content and (3) microstructural investigation including banding severity. It was concluded that microstructural banding has a negative influence on the general corrosion rates. The higher values of quantitively measured banding lead to increased general corrosion rates. The electrochemical potential differences between the light and dark bands is proposed as the cause of locally accelerated corrosion resulting in pits. The dark bands in the less corrosion resistant samples were lower bainite and these were presented as being more anodic. Introduction Sucker rods pumps are downhole artificial lift equipment that are widely used in the Oil and Gas industry as the part of onshore wells production. This artificial lift technology maintains or increases well production. With sucker rods pumps, the risk is related to aggressive production environmental conditions that may contain carbon dioxide (CO 2 ) and hydrogen sulfide (H 2 S) with other factors such as temperature, chlorides, and water cuts that cause materials corrosion and degradation. The cyclic up-and-down rod stroke movement lead to tension-tension and tension-compression stress conditions that provoke fatigue. The corrosion and fatigue synergy make corrosion-fatigue mode a predominant failure mechanism of sucker rods. 1 There are several known manufacturing approaches that have the potential to increase rods operational life by their influence on fatigue or corrosion resistance properties individually and synergistically. These approaches include (1) material selection, (2) surface treatments, (3) coatings, and (4) design.

Abstract In a recent modular construction project, severe corrosion of the gasket contact surfaces of flange faces was found to have occurred after the flanges had been tightened. 1 Root-cause analysis indicated that there is a greater chance of water ingress in tightened flanges in modular construction than in stick-built construction and that the longer construction period in the former can result in the severe corrosion of flange faces observed. Therefore, in order to mitigate or prevent such corrosion in modular construction, countermeasures should be taken. In this paper, two means of mitigating or preventing flange face corrosion in tightened flanges (i.e., a rust preventive coating and a special spiral wound gasket) were tested, and these tests confirmed their effectiveness. Introduction It has generally been thought that as long as flanges are properly tightened, no particular corrosion of the flange faces would occur during plant construction. However, in a recent plant construction project in which modular construction methods were used, severe corrosion of gasket contact surfaces in tightened flanges was found at the plant construction site. The plant was partially constructed in module fabrication yards, far from the plant site, and the modules were transported to the plant site by sea. Despite the flanges having been tightened at the module fabrication yards, severe corrosion of the flange faces, including the gasket contact surfaces, was found at the plant site (Figure 1). Root-cause analysis indicated that there is a greater chance of water ingress in tightened flanges in modular construction than in stick-built construction. Also, the period from flange tightening in the module yard to start-up of the plant is much longer than in stick-built construction. They, combined with the fact that both, the module fabrication yards and the plant site, were in tropical regions, resulted in the severe corrosion observed. In order to mitigate or prevent corrosion of flange faces in such projects, countermeasures should be taken, and considering the huge number of flanges, those measures should be simple and practical to apply. In this study, two such measures were tested on tightened flanges: one was a rust preventive coating applied by an aerosol spray and the other was a special spiral-wound gasket (SWG). 2