Abstract The new NACE Standard SP21424-2018 1 provides a set of simple criteria for assessing the risk of AC corrosion on existing collocations between powerlines and cathodically protected pipelines. However, the task of developing design criteria for new collocations is left to the pipeline operators. This paper covers a number of challenges related both to developing design criteria for new collocations and applying the new Standard to existing collocations. Topics like selection of the AC current density limit for mitigating AC corrosion on a new pipeline, recording AC and DC currents on 1 cm 2 coupons and dealing with high AC and DC average current densities at low AC voltages are discussed in detail in this paper. Introduction The new NACE Standard SP21424-2018 provides a set of simple criteria for assessing the risk of AC corrosion on existing collocations between powerlines and cathodically protected pipelines. Specifically, the AC current density should not exceed a time-weighted average of 30 A/m 2 if the DC current density exceeds 1 A/m 2 or 100 A/m 2 if the DC current density is less than 1 A/m 2 . This paper covers a number of challenges related to converting risk assessment criteria to design limits, receiving accurate recording data from installed AC coupons and finally dealing with unexpected high AC and DC average current densities at low AC voltages. Challenge 1. Developing Design Criteria Aligned With the New SP21424-2018 When a new AC interference study is conducted for a proposed pipeline running in a common right-of-way with an existing powerline, the accepted technical approach is to collect powerline, pipeline and soil resistivity data, to use dedicated software to predict the pipeline voltages and then to calculate predicted AC current densities based on predicted voltages and measured soil resistivities at selected locations. Finally, mitigation shall be designed to ensure that the average AC and DC current densities or alternatively the average corrosion rate to be recorded during and after commissioning will satisfy the new NACE criteria.

Abstract This paper explores the advances in remote monitoring technology and the enhancements that can be made to ensure that pipeline integrity is maximized while operational efficiencies are optimized. Specifically focusing on the data that is generated by cathodic protection and pipeline integrity monitoring devices (e.g. rectifier monitoring), this paper explores how data analytics techniques, such as artificial intelligence and machine learning algorithms, can shine a light on historically ‘dark’ data, improving pipeline integrity operations and the safety of workers and the broader public. Examples of artificial intelligence and machine learning work, such as applying intelligent algorithms to data analysis streams, will be presented as means of reducing data overload while providing automated predictive failure analysis and optimization of cathodic protection systems. Introduction Collecting large amounts of data is not a new idea in the cathodic protection industry. A myriad of data points are collected and stored each year for regulatory compliance purposes and for tracking operating performance. While the quality and quantity of data has improved over the years, influenced by increasingly automated data collection using remote monitoring devices, most data collected remains ‘dark’ – stored away in a unrelatable database for reference only if a specific need arises. 1 Monitoring Alarms Even some data that is not dark, has become a problem. Since the introduction of remote monitoring technologies onto cathodic protection assets almost 20-years ago, operators have worked with technology vendors to develop alarms, often simple notifications via email or SMS that are triggered if a threshold has been breached on a pre-configured limit. Alarms have been a wonderful invention for the industry, ensuring that the right people are notified as soon as data, indicative of a potential problem, exists. Alarms have revolutionized how pipeline operators monitor their CP systems and have saved time and resources in the process. Alarms, however, are not perfect. If an alarm limit is poorly configured, it can become the root cause of a very challenging, and sometimes dangerous condition – alarm fatigue.

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 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 Due to their low ratio of cost versus performances, quenched and tempered (Q&T) high strength low alloyed steels are widely used as tubular goods. For several decades, steel suppliers and academics are investigating the mechanisms of sour corrosion of these materials. Several publications highlighted the different parameters influencing the K ISSC of Q&T high strength low alloyed steels like the prior austenitic grain size, the dislocation density or the precipitation state. Niobium is known to have an impact on these 3 parameters, but authors often looked at its impact separately. Additionally, complete data relating the Niobium content and the K ISSC are extremely rare in the open literature. The present study focuses on the impact of Nb on the Prior Austenite Grain Size (PAGS) refinement for several quenching and tempering cycles and additionally on the role of Nb on the critical stress intensity factor for sulfide stress cracking (K ISSC ). A common Cr-Mo high strength OCTG steel alloyed with three different Nb contents ranging from 300 to 1000 ppm is used. It was found that Nb addition allows the use of higher strength material without compromising the resistance to crack propagation (K ISSC ). The results are discussed in terms of microstructure, hydrogen pick-up and precipitation state. Introduction The use of Oil Country Tubular Goods (OCTG) material in harsher environments (deeper wells, higher H2S concentrations and/or higher pressure and temperature) is pushing suppliers to design new steel grades with higher strength and better SSC resistance. This is extremely challenging since it is well known that the SSC resistance of a given material decreases with increasing its strength. Since the late 80's, people have been studying the metallurgical factors of low alloyed steels playing a role on the SSC resistance [1]–[3]. Quenched and tempered (Q&T) steels progressively became the reference since this processing allows to meet a high yield to tensile ratio answering the hardness limit imposed by successive API standards.

Abstract UNS N08935 is a new versatile austenitic alloy with the composition 35Ni-30Fe-27Cr-6.5Mo-0.28N and a PREN of 52. It has an extreme pitting resistance which makes the grade a good candidate for O&G applications. The alloy is available in several strength levels with good ductility: seamless tubes with 62 ksi, 140 ksi and 180 ksi. It is an austenitic grade that is worked to strength which results in an alloy with very high resistance to hydrogen effects. According to NACE MR0175 / ISO 15156 the grade will be a Type 4c material. For the 62 ksi material the resistance against Hydrogen Induced Stress Cracking (HISC) has been demonstrated by constant load testing of specimens polarized to -1050 mV SCE . For the cold worked material Slow Strain Rate Testing (SSRT) at Test Level VI in NACE MR0175 / ISO 15156, a condition within Type 4d is discussed. With its high mechanical strength and pitting resistance as well as being not prone for HISC, UNS N8935 is an interesting candidate for subsea applications. Further, UNS N08935 is interesting as tubing for HPHT-wells due to its very high strength. Introduction UNS N08935 is a newly developed 6% Mo grade that has a high Pitting Resistance Equivalent Number (PREN) of 52. Earlier data has been presented for heat exchanger tubing where extreme pitting resistance was shown. In addition general corrosion results in Hydrochloric Acid and Sulfuric Acid have been reported. 1 For solution annealed tubes from the same heats as used in this work, a Critical Pitting Temperature, CPT, at 100.8°C and 102.5°C in modified ASTM (1) G150 1 with 3M MgCl 2 , Magnesium Chloride, was reported. 2 Those investigations were made on annealed material. A mean CPT in ASTM G48E 3 of 70°C for butt welded tubes with Alloy 59 as filler metal was reported. 4 UNS N08935 is a structurally stable austenitic alloy where high pitting resistance and mechanical strength have been combined. This has been achieved by alloying with nitrogen while keeping the nickel content high. With such high nickel content as 35% the material is very structure stable and not prone to form intermetallic phases. Another aspect is that the material is fully austenitic which indicates that the alloy is not prone to hydrogen embrittlement. Some failures have occurred on precipitation hardened Ni-base alloys due to hydrogen embrittlement. 5 It should be noted that UNS N08935 is cold worked to strength and not precipitation hardened. The nitrogen content around 0.28% can be dissolved in the austenite and hence no chromium nitrides are formed. The high nickel content together with 6.5 % molybdenum and 26-27% chromium indicates that UNS N08935 should have good resistance against Stress Corrosion Cracking (SCC) in H 2 S environments.

ABSTRACT Alloy UNS (1) N08825 is a titanium-stabilized fully austenitic nickel-iron-chromium alloy with addition of copper and molybdenum. The alloy was designed for applications in the chemical process industry and was later applied in the oil and gas industry. Because of its high nickel content, UNS N08825 shows an outstanding resistance to stress corrosion cracking in aqueous and acidic chloride-containing solutions. However, the molybdenum content of 2.5 to 3.5 wt.% limits its resistance to pitting and crevice corrosion in highly concentrated chloride-containing environments. To address this weak point, a new advanced alloy with increased molybdenum content, which will be called Alloy 825 CTP, was developed. Previous corrosion tests showed an increased critical pitting temperature measured on the new alloy 1 and based on these data further corrosion tests were performed. Alloy 825 CTP has been tested according to ASTM G48 in solution-annealed and in PWHT condition to study the pitting and crevice corrosion resistance. In addition, corrosion tests were performed to study its corrosion resistance considering different mechanisms of environmental cracking. Sulfide stress cracking (SSC) and galvanically induced hydrogen stress cracking (GHSC) tests were performed according to NACE (2) TM0177-2016 Method A. Stress corrosion cracking (SCC) resistance was investigated using C-ring tests according to NACE TM0177 Method C at Level VI for 3 months and Level VII for 1 month. Slow strain rate (SSR) tests under cathodic polarization were performed to study the resistance to hydrogen embrittlement (HE). In terms of resistance to (localized) corrosion and hydrogen embrittlement, the newly developed Alloy 825 CTP was found to perform equally well or even better than the conventional material. INTRODUCTION Alloy UNS N08825 is a titanium-stabilized fully austenitic nickel-iron-chromium alloy with addition of copper and molybdenum 2 , which is resistant to corrosion in acids and alkalis under both oxidizing and reducing conditions. Thus, it is used for a great variety of applications including (petro)chemical industries, oil and gas production and processing and maritime applications. The high nickel content grants excellent protection against stress corrosion cracking in aqueous and acidic chloride-containing environments. However, alloy UNS N08825 has only a limited resistance to chloride-induced localized corrosion, which is a common corrosion type in the oil and gas production. 3

ABSTRACT INTRODUCTION LABORATORY TECHNIQUES FOR EVALUATION OF COATINGS ON STEEL Macroscopic examination. Microscopic examination – optical and scanning electron microscopy. Physical testing - thickness testing, pinhole testing, adhesion testing, and determination of the plane of delamination, hardness testing, and surface roughness (profile) testing. Chemical analysis - Fourier transform infrared spectroscopy for organic functional group analysis, gas chromatography – mass spectrometry for organic compound separation, identification and quantification, differential scanning calorimetry for melt range and thermal properties, scanning electron microscopy with associated energy dispersive x-ray spectroscopy for elemental analysis, and x-ray photoelectron spectroscopy for surface elemental analysis. Accelerated environmental exposure tests - salt spray (fog) tests, humidity tests, and ultraviolet light (QUV).

ABSTRACT In High Pressure High Temperature “HPHT” wells (pressure above 690bar, temperature above 150°C) which contain CO 2 and H 2 S, operators need to select corrosive resistant materials. High strength grades are usually required to meet collapse and burst properties. The aim of the end users is to get the specific grade which can resist to corrosion while minimizing the cost. The API 5CRA standard defines corrosion resistant alloy (CRA) grades for casings and tubings, from group 1 named “Super 13Cr 13 -5-2” (suitable up to 180°C), to group 2 “Duplex” grades 22-5-3 (232°C) or “Super Duplex” 25-7-4 (250°C) and higher grades. Therefore, when the well temperature is above 180°C, duplex grades or higher are commonly selected. A new proprietary grade chemistry was developed to provide good corrosion performances up to 230°C, 125ksi (862MPa) grade material and high impact toughness. From a metallurgical standpoint, achieving targeted mechanical and corrosion performances has ended up in a multi-phases material. Final properties are obtained by control of chemical analysis, phases balance and heat treatment. This process is thus more cost effective compared to cold hardened CRAs. Stress corrosion cracking performances were assessed and compared to Super 13Cr and Super Duplex materials showing significant benefice of chromium under high temperature. Potentiodynamic electrochemical measurements in H 2 S environment were performed to evaluate pitting performance and assess risk of sulfide stress corrosion cracking, confirming higher sulfide stress corrosion performance compared to 13-5-2 materials. X-ray Photoelectron Spectroscopy (XPS) characterizations provide deep knowledge about its passive film compositions underlining the beneficial effect of high chromium. This solution offers to Oil and Gas operators a cost effective designed seamless tubes for ultra-high temperature well reservoir condition as alternative to duplex materials. INTRODUCTION The combination of targeted performances of the new alloy: – 110 or 125ksi High Yield strengths – higher corrosion resistance performances than 13-5-2/supermartensitic materials – reduce manufacturing cost compare to Duplex materials lead to manufacture the seamless pipe in Mannesmann rolling followed by quench and temper heat treatment. High yield strengths (110 or 125ksi) are reached with a lower manufacturing cost without using the cold drawn process.

ABSTRACT Duplex Stainless steel 22Cr (DSS) is one of the corrosion resistant alloys (CRA) that is used extensively in oil and gas industry for critical applications such as wet gas production flow lines and pipelines. A number of new sour oil & gas projects in the company with high salinity (exceeding 200000 ppm NaCl) will be developed in the coming years. So far 22Cr DSS material is qualified up to 10 mbar partial pressure of H 2 S (ppH 2 S) in 160,000ppm chloride levels. The operating conditions of these new projects are outside these current material operating limits of 22Cr DSS defined within the company standards. The objective of the study was to enable wider use of 22Cr grades in higher sour projects in high chloride environments and qualify as lower cost alternative to more expensive CRA materials like 25Cr super duplex, alloy 825 or alloy 625. Pitting, crevice and stress corrosion cracking (SCC) and sulphide stress corrosion cracking (SSC) tests were conducted on both parent material and representative welds in high ppH 2 S and in high chloride environments using four-point bend test method (FPBT). The results established the new threshold sour service limits of DSS material which resulted in significant cost savings for various projects. This paper will present the test results and discuss the opportunities for 22Cr DSS application. INTRODUCTION The application of 22Cr DSS has rapidly expanded in the oil & gas industry over the last decade. 22Cr DSS material is used extensively in critical applications such as pipelines, piping, pumps, coolers and heat exchangers etc. 1 22Cr DSS are well known for their unique combination of corrosion resistance and mechanical properties. 22Cr DSS microstructure consists both face-centered cubic austenite phase and body-centered cubic ferrite phase, approximately 50% of austenite (?) phase and 50% of ferrite (a). 2 The applicability of 22Cr DSS in H 2 S containing environment is limited by H 2 S partial pressure, chloride content, temperature and pH. In the presence of H 2 S and chloride, 22Cr DSS can suffer from general corrosion, localized corrosion (pitting) and Environmentally Assisted Cracking (EAC) such as Sulphide Stress Cracking (SSC) and Stress Corrosion Cracking (SCC). ISO15156-3/NACE MR0175 3(1) is generally used as one of the standards in the material selection with SSC and SCC resistance in H 2 S environment. Based on extensive in-house test data and literature results for 22Cr DSS and 25Cr super duplex stains steel (SDSS), company has adopted the policy of not accepting unlimited environmental parameters (e.g. Cl- levels and pH), such as stated in ISO15156-3 Table A.24. 3 Many of the limits in ISO15156-3 have been grandfathered into it in early editions based on common consent and common experience, not necessarily based on formal testing. Also, the environmental limit in ISO15156-3 is applicable to cracking resistance of the material in the presence of H 2 S and does not consider the threat of corrosion particularly pitting. Pitting of 22Cr DSS under the influence of high chloride concentration and H 2 S is a considerable risk to our operation and has experienced it within these limits. Variations in material properties caused by welding also have a strong influence on cracking and pitting resistance and these are noted to be wide ranging depending on source of supply, product forms etc.

ABSTRACT Polythionic Acid Stress Corrosion Cracking (PTA SCC) of conventional austenitic stainless steel is a serious problem in refinery desulfurization units. Stabilization treatment after welding, Nitrogen blanketing and/or neutralization treatment using an alkaline solution are required during each turn around to prevent PTA SCC according to NACE (1) SP0170-2012. It has been known that proprietary S34751 has superior PTA SCC resistance compared with S34700 or S32100 even without Post Weld Heat Treatment (PWHT) and neutralization treatment during turn around. However, the difference of of PTA SCC resistance between proprietary S34751 and generic S34751 within extra low Carbon (C) content less than 0.02 wt% has not been reported. Therefore, the relationship between C content and PTA SCC resistance for generic S34751 was investigated by using long term aged samples with simulated welding Heat Affected Zone. INTRODUCTION Stabilized austenitic stainless steels such as UNS S32100 or UNS S34700 are widely used in hydro-treating or hydro-cracking processes in a complex refinery. However, S32100 or S34700 are susceptible to Stress Corrosion Cracking (SCC) due to the formation of Polythionic acid (PTA) (H 2 SxO 6 , x = 3 - 6) which causes cracking in the coarsened Heat Affected Zones (HAZ) because of sensitization, due to the formation of a Chromium (Cr) depleted zone by the precipitation of Cr based M 23 C 6 carbides along grain boundaries which occurs during actual operation. 1 To prevent PTA SCC, Stabilization Post Weld Heat Treatment (PWHT) at the temperature range of 843 °C to 900 °C for 2 to 4 hours is required for S32100 and S34700 to tie up free Carbon as TiC and NbC in the coarsened HAZ. Furthermore, several kinds of PTA SCC shutdown mitigation methods are listed in NACE SP0170 such as nitrogen purging to exclude oxygen, alkaline washing of equipment surfaces, and dry air to prevent liquid water formation. 2 Stabilization PWHT and/or these PTA SCC mitigation methods affect not only the fabrication cost but also the cost and schedule during maintenance opportunities. Hence, a stabilized austenitic stainless steel with excellent resistance for sensitization to prevent PTA SCC without the above mitigation methods would be ideal for hydro-treating and hydro-cracking processes in a complex refinery.

ABSTRACT CuNi90/10 has been used for many decades as a corrosion resistant alloy for seawater applications. Its corrosion resistance mainly results from the formation of a stable, thin and very adhesive protective layer that forms in contact with seawater. The formation of this protective layer can take up to several weeks depending on environmental influences such as temperature, oxygen content or pH value. There is a delay in the formation of a natural protective layer particularly in the case of brackish water. During this time the material is susceptible to corrosion. For this reason, efforts are made to accelerate the process of protective film formation. A typical method is to introduce inhibition with Sodium Diethyl Dithiocarbamate (SDD). Due to its environmentally damaging impact, this method of inhibition and the resulting disposal obligations is a very expensive process. Therefore the formation of a protective layer under naturally occurring conditions and the conditions under inhibition using SDD is being investigated. The goal was to compare both types of protective film formation and estimate whether inhibition with SDD has advantages in corrosion resistance of CuNi90/10 compared to a natural protective film in water from the Weser river. INTRODUCTION CuNi90/10 has been a proven material for seawater applications for decades. It is mainly used in the area of seawater coolant lines between sea chests and heat exchangers. However, CuNi90/10 has also been successfully implemented in bilge systems, fire extinguisher lines, in desalination plants or on offshore platforms. In addition to its excellent general corrosion resistance in seawater, CuNi90/10 also has excellent resistance to biofouling. There are numerous standardised materials under the term CuNi90/10. A comparison of the most used CuNi90/10 materials is shown in Table1. CuNi90/10 owes its excellent corrosion resistance to the formation of a natural protective layer under wetted conditions. This protective layer is particularly stable in clean, oxygen-rich seawater with pH values larger than 6.5. Figure 1 shows the structure of the protective layer. The formation of this protective layer requires a certain amount of time. A first layer of Cu 2 O forms due to the anodic dissolution of copper. A subsequent cathodic precipitation of Cu ions leads to a second layer of Cu 2 O/CuO. Finally Cu bonds with the components of seawater and if treated with ferrous sulphate, the outer layer also contains significant iron. 1

ABSTRACT Low alloy steels are one of the most commonly used material systems in oil and gas fields as they can be heat treated to appropriate strength levels, including higher strengths such as 758 MPa (110 ksi) and 862 MPa (125 ksi) minimum yield strength, while providing economical solutions for various oilfield conditions. Higher hardenability of low alloy steels is an important factor to ensure proper heat treatment to higher strength levels and this is typically achieved by addition of elements such as Chromium (Cr), Molybdenum (Mo), Nickel (Ni), etc. in the alloy chemistry. It is also essential to ensure adequate toughness in these high strength steels to reduce risk of brittle fracture. Increasing Ni content in the chemistry of low alloy steel can provide increased hardenability while maintaining good toughness when heat treated to high strengths. However, the guidelines of NACE MR0175/ISO 15156-2 currently restrict the maximum Ni content to 1% mass fraction and in general recommend use of Cr-Mo type low alloy steels such as 41XX series in sour (H 2 S) service. 1 This has generally led to exclusion of low alloy steels containing higher Ni such as 43XX series in sour service. In this paper, an effort is made to evaluate the sulfide stress cracking (SSC) resistance of common grades of Cr-Mo and Ni-Cr-Mo steels heat treated to high strength using NACE TM0177 Method A testing. 2 This would also assist when comparing the cracking resistance of high strength, low alloy steels with greater than 1% mass fraction Ni content to those which are within this limit. INTRODUCTION There is an increasing demand for use of high-strength low alloy steels for operating in many oil and gas production environment to meet design requirements. Many applications for downhole completion and test tools require heavy-wall cross-sections such as 38 mm (1.5) inches or thicker for manufacturing. Hardenability is a key factor in determining heat treatability of low alloy steels used for thick wall cross-sections. Higher hardenable low alloy steel grades are capable of providing better uniform through wall hardness when heat treated to higher strength while maintaining adequate ductility and toughness. Since, some these production environments could have H 2 S; the Sulfide Stress Cracking (SSC) resistance of these steels would be an important factor in consideration of their use.

ABSTRACT A previously developed modeling framework has been extended to predict the general and localized corrosion of various corrosion resistant alloys (CRAs), including alloys 2507, 2535, 28, 29, S13Cr, S15Cr, and S17Cr in complex aqueous systems relevant to oil and gas production and aggressive process environments. For this purpose, the model calculates the corrosion rates, corrosion potential and repassivation potential as a function of temperature, alkalinity, pH, partial pressure of gases (including H 2 S), and concentrations of various aggressive species. The corrosion rates and potential are computed using the mixed-potential theory by considering the main anodic and cathodic reactions coupled with a rigorous thermodynamic model to account for speciation by solving phase and chemical equilibria. The repassivation potential is calculated from a model that simulates the phenomena at the interface of the alloy and the occluded solution environment. To enhance the predictive capabilities of the model, the parameters of the repassivation potential model have been generalized as a function of alloy composition, environment composition and temperature. The results show that the model reasonably reproduces experimental data and predicts the repassivation potential and corrosion rates. INTRODUCTION Corrosion phenomena in the petroleum industry are one of the major issues that affect the integrity of production, process, and transportation facilities. The problem is more severe when oil, gas or gas condensates are produced from deep wells where temperature, pressure, and pH can exceed the resistance thresholds of materials that are typically used in the operations. 1, 2 In particular, presence of aggressive species such as chlorides, CO 2 , and H 2 S at high concentrations can lead to substantial general and localized corrosion, particularly when large amounts of formation and/or injection water are produced. 3-5 The use of corrosion-resistant alloys (CRAs) in oilfield operations has been increasing due to the need for improving equipment reliability and safety in environments where considerable amounts of corrosive fluids are produced. 5 Although CRAs are much more resistant to general corrosion compared to carbon steel or low alloy steels, they can be susceptible to localized corrosion and environmentally assisted cracking (EAC) in harsh sour environments. The majority of EAC cases in the presence of H 2 S include sulfide stress cracking (SSC) and stress corrosion cracking (SCC). 3, 5 SSC is a kind of hydrogen embrittlement that will lead to cracking through a bulk phenomenon. Aggressive pH and chloride content of the aqueous environment control the SSC process through their impact on the stability of the passive film. 5 Similar to SSC, SCC is also sensitive to the pH and chloride contents of the system. However, it significantly depends on the chemistry of the bulk solution and the local chemistry in the occluded environment as well as on the stability of the passive film. Moreover, SCC can occur at higher temperatures and at higher pH values compared to SSC. The SCC threshold conditions and consequently the application limits of CRAs are strongly affected by the presence of H 2 S.

ABSTRACT Precipitation Hardened (PH) nickel alloys have been used extensively and successfully in the Oil & Gas Industry for many years. These materials offer high strength and outstanding corrosion resistance in many aggressive environments and they are a common selection for high-strength equipment for downhole, wellhead, subsea and Christmas tree applications. However, several high-profile failures have occurred, including tubing hangers, cross-overs and subsea bolts with alloys such as UNS N07718, UNS N07716 and UNS N07725. In all these cases, the mechanism identified was Hydrogen Assisted Cracking (HAC) as a result of embrittlement from atomic hydrogen absorbed by the alloy in specific operating environments. PH nickel alloys exhibit complex microstructures with multiple potential secondary and tertiary phases. They require carefully controlled thermomechanical processing and heat treatment to deliver performance that is adequate for the intended applications If processed improperly (particularly during hot working and heat treatment), the resultant microstructure may adversely affect the material properties and suitability for the intended service. Despite the number of scientific and technical contributions produced over the last years, the interaction between these complex microstructural features, the service environment and atomic hydrogen is still not well established. This is further complicated by variations in testing approach used to study and simulate hydrogen charging conditions. The present paper provides insights on the HAC failure mechanism for API 6ACRA PH nickel alloys comparing findings from numerous studies. In addition, implications for currently adopted standards and emerging specifications are also presented and discussed. INTRODUCTION UNS a N07718 has been employed by the aerospace industry for hot turbine sections since the 1960’s. This material was adopted by the oil and gas industry in the 60’s and 70’s to deliver a high strength material option for increasingly hot and high pressure wells. The adoption while largely successful, did have early failures between the late 90’s and the early 00’s due to Hydrogen Assisted Cracking (HAC). Lessons learned from such failures, which will be reviewed in the following sections, resulted in manufacturers and operators coming together to create API b Specification 6A718 5 which better ensured HAC-resistance by close control of microstructure and all influencing process steps. For example, chemistry is restricted to make the most likely deleterious phase (d phase) less likely, and metallographic assessment assures that the phases present (including d phase) are not distributed deleteriously (by avoiding continuous, or semi-continuous grain boundary networks and avoiding the most damaging form of delta phase - acicular platelets).

ABSTRACT Alloy 35Mo is a new structurally stable high PRE austenitic alloy with the composition: 27 Cr - 35 Ni -6,5 Mo - 0,28 N. The alloy can be successfully welded with Alloy 59 as filler. The grade is a combination of Ni-base and high PRE super austenitic grade, which results in interesting properties for the alloy. It has a high PRE value of 52, which results in a CPT above 100°C in ASTM G150 with 3 M MgCl 2 . The CPT is considerably higher than for conventional 6 Mo alloys which have a CPT of about 65°C and also higher than most Ni-base alloys. A consequence of the high nitrogen content in Alloy 35Mo is good ductility and a high yield strength of more than 470 MPa for tested heat exchanger tubing in the solution annealed condition. This is higher than conventional 6 Mo alloys. Alloy 35Mo is a versatile alloy for applications in, for instance, the oil & gas, chemical and petrochemical industries, which is demonstrated by corrosion testing. INTRODUCTION Seamless stainless steel tubing is used in among other applications, heat exchangers in the refinery and chemical industry. Depending on the often demanding service conditions, alloys such as 6Mo super austenitic grades, hyper duplex and Ni-based alloys are used. In more severe acid corrosion conditions Ni-rich austenitic grades such as Alloy 28 are used but these have less pitting resistance than the 6Mo super austenitic grades. If high mechanical strength and high pitting resistance is required hyper duplex is an option. However, hyper duplex is limited by service temperature and resistance to corrosion in acids. If more severe service conditions are encountered Ni-base alloys such as Alloy 625 are often used. Alloy 35Mo is a newly developed 6%Mo grade. The grade is a combination of the alloying with Mo and N from the 6Mo super austenitic grades and Cr and Ni from the Ni-rich austenitic grades. This resulted in a 27 Cr - 35 Ni - 6,5 Mo - 0,28 N alloy. It has a PRE according to NACE MR0175/ISO (1) 15156-3, %Cr + 3.3% × Mo + 16 × %N, of 52 indicating extreme chloride pitting resistance. 1 Being processed as a stainless steel and having a high Ni-content results in that the alloy’s structure is stable and is not prone to precipitate intermetallic phases. Furthermore, the nitrogen content also contributes to the mechanical strength. As indicated by the PRE, Cr, Mo and N contribute to the pitting resistance and Ni contributes to the corrosions resistance in acid. For welding of Alloy 35Mo, Alloy 59 is used as filler metal. The aim of this work is to demonstrate the pitting resistance and mechanical strength and preliminary results also indicate the corrosion resistance in acid demonstrates that Alloy 35Mo increases the service window for austenitic stainless steels used as heat exchanger tubing.

Abstract Mitigation Model Monitoring Maintenance Management Introduction 5-M Methodology 1,2 External Corrosion Direct Assessment (ECDA) 3 Stress-Corrosion Cracking Direct Assessment (SCCDA) 4 Inline inspection 5 Above-ground monitoring techniques 6-8 Canadian Energy Pipeline Association’s (CEPA) Stress-corrosion cracking (SCC) recommended practices 9 5-M Methodology

ABSTRACT In oil and gas production and transportation dissimilar materials are frequently combined for technical and economic reasons. However, the combination of dissimilar metals can result in corrosion due to galvanic or bimetallic effects. The driving force for this kind of corrosion is the difference in corrosion potentials of the individual materials in the given environment which causes galvanic currents the magnitude of which depends on the sum of all system resistances (Ohmic Law). Any assessment of the corrosion rates at bimetallic couplings needs information on the free corrosion potentials (rest potentials) of the bimetallic partners in the relevant medium. Due to the lack of consistent literature data, a practical galvanic series was established in this work for standard oil country tubular goods (OCTG) steels, corrosion resistant alloys (CRA) as well as graphite (as gasket material) in a model sweet upstream environment. From polarization resistance measurements, information was obtained on the corrosion rate of the carbon steels in the absence of bimetallic coupling. Furthermore, the corrosion rates encountered at the partners of bimetallic couples were quantified via mass loss measurements. The results of this work allow better assessment of the severity of bimetallic corrosion and hence a more appropriate selection of materials which prevents corrosion failures, increases the integrity of assets, and saves costs. INTRODUCTION The combination of dissimilar metals can result in corrosion due to galvanic effects. This is caused by differences in corrosion potentials which are the driving force for galvanic or “bimetallic” corrosion 1 in this macro-element. The potential difference drives a galvanic current between these metals, the magnitude of which depends on the sum of all system resistances (Ohmic Law). The metal with the more negative corrosion potential will become the local anode and the metal with the more positive corrosion potential acts as the local cathode. In a bimetallic couple, the local anode will corrode faster than in the absence of a bimetallic partner, while the local cathode corrodes less than in the absence of a bimetallic partner and experiences cathodic protection. Any assessment of the corrosion rate for a bimetallic coupling needs the information about the corrosion potential of both bimetallic partners in the relevant medium.

ABSTRACT This paper describes the development of novel next generation fluoropolymer-based coatings for preventing fouling from a variety of inorganic and organic foulants. These coatings have demonstrated improved rapid decompression resistance and physical properties. Testing protocols included autoclave, acid resistance, scaling, abrasion and impact testing. In addition, several in-field case studies will be presented which highlight the capability of these exceptional coatings under various process conditions. INTRODUCTION A frequent problem in the oil and gas industry is the precipitation of organic and inorganic materials onto tubing surfaces when process stream undergoes pressure and/or temperature changes. For example, this can occur in downhole tubulars and in refinery heat exchangers. The resultant deposition of these materials onto the tube surface can be as benign as a nuisance to a major problem involving both production output/delays and operational safety. A potential solution to this problem is to apply a coating with “nonstick” properties to prevent scaling and organic fouling where sweet or sour conditions prevail. Fluoropolymers are a class of materials that have excellent chemical resistance and release properties and can function at relatively elevated temperatures. Often the process streams that produce fouling are also exacerbated by their corrosive nature. This typically will require moving away from carbon steel tubing to tubing made of corrosion resistant alloy combinations. This in turn can greatly increase the capital cost of a downhole string or heat exchanger. A common solution to providing corrosion protection is to use an epoxy based coating. However, these coatings do not provide antifouling protection and under process streams containing high H 2 S levels are not suitable. Utilizing a protective coating that can supply both corrosion resistance and antifouling provides a novel solution. Our work in this area 1 was previously described at a NACE conference 10 years ago. The object of this paper is to describe coating improvements and some examples where these coatings have excelled during the last decade.

ABSTRACT Super martensitic stainless steels are widely used in oil & gas production environments) for mitigation of general corrosion due to the presence of CO 2 in the produced fluids providing a cost-effective alternative to more expensive corrosion resistant alloys (CRA. However, there is little agreement on service limits when exposed in environments that contain H 2 S, particularly in relation to the susceptibility to sulfide stress cracking (SSC). This paper presents a review of published literature regardingsusceptibility to SSC of super martensitic stainless steels in production environments, with the aim to evaluate the service limits of these materials from both the empirical and mechanistic approaches. The conclusion of this review is that an adequate assessment of the susceptibility to SSC can only be accomplished using testing methods that account for both the role of the passive layer and the formation of metastable pits and their propagation in H 2 S-containing environments. This paper recommends the characterization of the passive layer resistance in super martensitic stainless steels using point defect modeling techniques to identify the role of critical variables on pit induction time distribution to describe the susceptibility to SSC. These critical variables include material conditions such as stress and environmental conditions such as temperature. The methodology is described in detail and a recommended path for investigation is discussed. INTRODUCTION The oil & gas industry is challenged with producing from formations that are increasingly sour, either as produced natural gas or associated gas [1]. Additionally, producing wells may reach up to 150°C and 500 bar of pressure with associated formation water containing up to 250.000 ppm Cl - . These conditions define a highly aggressive production scenario. The wide-ranging environmental conditions associated with this demanding service necessitate appropriate and cost-effective materials selection to optimize the capital expenditures. Typical carbon steel oil country tubular goods (OCTG) are used for well completions and also for associated surface facilities. However, in demanding service condtions, these materials can experience very high corrosion rates as well other forms of damage such as pitting [2-6].