Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
Results
Understanding The Stress Corrosion Cracking Of X-65 Pipeline Steel In Fuel-Grade Ethanol
Lou, Xiaoyuan (School of Materials Science and Engineering Georgia Institute of Technology) | Goodman, Lindsey R. (School of Materials Science and Engineering Georgia Institute of Technology) | Singh, Preet M. (School of Materials Science and Engineering Georgia Institute of Technology) | Yang, Di (The George W.Woodruff School of Mechanical Engineering Georgia Institute of Technology)
INTRODUCTION ABSTRACT One of the major reasons why fuel-grade ethanol (FGE) is not currently transported by pipeline is its contribution to stress corrosion cracking (SCC) of carbon steel. Collaborative efforts have been made by several research groups to understand the mechanism of this SCC and to devise methods of protecting carbon steel from this environmentally assisted cracking. The focus of this paper is to discuss the effects of ethanol chemistry on SCC of carbon steel and to provide a mechanistic picture of crack initiation and growth in simulated fuel-grade ethanol (SFGE). Chloride content, water content, and pHe (pH value defined in ethanol-based solvent) of the ethanol are critical for SCC in this system. It was also found that film-related anodic dissolution controls the cracking dynamics in SFGE during the slow strain rate test (SSRT). Bio-ethanol is one of the major alternative liquid fuels used to replace conventional fossil fuels for motor vehicles. Currently, in the United States (US), 10% by volume fuel-grade ethanol is blended into gasoline. Increasing the availability and reducing the cost of bio-ethanol are critical to its future applications. One of the most efficient ways of transporting liquid fuels is via pipeline. However bio-ethanol is still shipped mainly by tanker trucks, which is more costly and demands more energy than pipeline transport. Concerns about stress corrosion cracking of the existing carbon steel pipelines due to fuel-grade ethanol are the major hindrance to the use of pipeline for ethanol products [1, 2]. Stress corrosion cracking in ethanolic environments has been reported and investigated since the early 1980s. [1, 3-6] Recent studies have shown that SCC is the main failure mode of pipeline steel exposed to fuel-grade ethanol. [1, 7] Chemical impurities and dissolved oxygen are factors that have been reported to influence SCC in fuel-grade ethanol. Laboratory studies on simulated fuel-grade ethanol showed that pipeline steels usually exhibited a type of SCC with a mixed mode (mostly intergranular) [1]. However, transgranular SCC has also been reported in SFGE [8]. Inconsistency in these experimental findings requires a systematic study to address the cracking mechanism in ethanolic environments. In this study, we report our work towards understanding the SCC mechanism of X-65 carbon steel in SFGE as well as the effects of variations in ethanol chemistry. Effects of changes in chloride content, pHe and water content were examined. Film-related anodic dissolution was experimentally found to be a major driving force for crack initiation and growth. It is believed that the competition between film growth and breakdown controls the crack propagation during SSRT. EXPERIMENTAL PROCEDURES 1) Materials and environments The testing specimens were cut from a new in-service X-65 pipe in as-received condition. The chemical composition and mechanical properties of this X-65 pipeline steel are shown in Table 1. (Table in full paper) Two different kinds of tensile samples (smooth and notched) were made based on the ASTM standard G 129 for slow strain rate testing [9].
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Renewable > Biofuel > Ethanol (1.00)
Corrosivity Of Anhydrous Ethanol, Hydrated Ethanol And Fuel E25 (25% Ethanol/75% Gasoline)
Moreira, Anna Ramus (IPT Institute for Technological Research) | Panossian, Zehbour (IPT Institute for Technological Research) | L.Santos, Célia A. (IPT Institute for Technological Research) | Bragagnolo, Gislaine M. (IPT Institute for Technological Research) | Gandur, Marcelo C. (Corrosion Protection Products - Building Safety Solutions - 3M Brazil) | de Souza, Emerson Monteiro (Corrosion Protection Products - Building Safety Solutions - 3M Brazil)
INTRODUCTION ABSTRACT The objective of the work was to study the corrosion of API 5LX 46 and API 5LX 65 alloys, used for pipelines, in anhydrous ethanol, hydrated ethanol and fuel E25 through laboratory immersion tests, NACE TM-0172 tests and dynamic tests (corrosion loops). Based on the results of this study, it was concluded that it is advisable that the internal surface of hydrated ethanol storage tanks be painted in order to avoid the corrosion of the internal walls which, despite being incipient, determines color changes which is unacceptable in the market. Furthermore, in pipelines used only for ethanol transportation, the painting of the internal walls of the tubes is not necessary because both the anhydrous ethanol and the hydrated ethanol are not aggressive to the steel, as long as the relative movement of the liquid is guaranteed. Finally, in pipelines used for ethanol and for petroleum derivatives transportation, it is advisable that the internal surfaces of these pipes be painted in order to avoid the contamination of the ethanol (anhydrous or hydrated) which makes the ethanol aggressive to the steel and changes its color (unacceptable in the market). The research project conducted had as a goal the study of the corrosion of API 5LX 46 and API 5LX 65 alloys, which are used as construction materials for pipelines, in anhydrous ethanol, in hydrated ethanol and in E25 through laboratory immersion tests, NACE TM-0172 tests and corrosion loop tests. Immersion tests EXPERIMENTAL PROCEDURE AND RESULTS As very few corrosion test methods for ethanol are available, in the present study specific test methods, both in stagnant and in nonstagnant conditions, were developed. The stagnant condition tests were conducted pretending to reproduce a storage tank condition (immersion tests) and the nonstagnant ones pretending to reproduce the ethanol transportation through pipelines (NACE TM-0172 tests with adjustments in order to make it suitable for ethanol evaluation and corrosion loop tests). Before the construction of the corrosion cell, some preliminary tests were conducted in order to identify the test conditions that influence the obtained results. One of the most important observations was that when an intake of water from the local atmosphere takes place, it determines the increase of the water content of the medium test. In order to avoid the absorption of water from the atmospheric air, a special test cell was developed (Figure 1). This cell consisted of a borosilicate glass test vessel and its cover. The cover was provided with three faucets made of glass and polytetrafluoroethylene (PTFE), with plastic connections, which were used to introduce gases and to contribute to the isolation of the test solution from the atmosphere. In the interior of the vessel, a polytetrafluoroethylene (PTFE)-made test coupon holder was inserted. This holder permitted testing three metal samples simultaneously without any contact among them. Between the test vessel and its cover, a brand of synthetic rubber and fluoropolymer elastomer seal ring was inserted in order to isolate the test solution from the local atmosphere.
- South America > Brazil (0.31)
- North America > United States (0.28)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Renewable > Biofuel > Ethanol (1.00)
On Development Of Accelerated Testing Methods For Evaluating Organic Coating Performance Above 100 °C
Shukla, Pavan K. (Southwest Research Institute®) | Pabalan, Roberto (Southwest Research Institute®) | Yang, Lietai (Southwest Research Institute®) | Smith, Mark A. (3M Company Corrosion Protection Products Division)
ABSTRACT Organic coatings are applied to protect underground and aboveground pipelines and other objects from corrosion. Hot-water soak and cathodic disbondment tests are routinely used in the coating industry to evaluate the performance of organic coatings that protect metal pipes in offshore (seawater) and onshore (aboveground or underground) applications. Numerous technical standards, which specify the operating conditions and test parameters, are available. The technical standards are applicable when the operating temperature is below 100 °C. However, the organic coatings could be subjected to temperatures above 100 °C when a pipeline is carrying hot fluids. Several attempts have been made to improve the existing test methods for evaluating coating performance above 100 °C. In this paper, we provide a critical review of published literature on coating performance evaluation above 100 °C. In addition, we discuss the test conditions that must be considered in developing accelerated coating evaluation methods above 100 °C. INTRODUCTION Hot-water soak and cathodic disbondment tests are routinely used in the coating industry to evaluate the long-term performance of organic coatings. There are numerous ASTM and international standards that outline procedures for conducting these tests below 100 °C. Both coating suppliers and consumers use standard procedures to evaluate performance of organic coatings. These standard procedures are also used to evaluate comparative performance of organic coatings. The coatings will be subjected to elevated temperatures when a pipeline is carrying hot fluid. Such situations may arise when a pipeline is transmitting oil sand and heavy oil, which have viscosity on the order of 103 To the authors' best knowledge, no technical standard is available that specifies test procedures for conducting hot-water soak and cathodic-disbondment tests above 100 °C. A literature search was conducted to determine whether any attempts have been made to develop test procedures for evaluating coating performance above 100 °C. In this paper, we critically review published literature on coating performance evaluation above 100 °C. We also discuss the test conditions that must be considered in developing accelerated coating evaluation methods above 100 °C.BACKGROUNDThe literature information revealed that no standard test methods exist for evaluating coating performance above 100 °C. This observation is confirmed through statements published by Kirkpatrick, et al.and Papavinasam and Revie.2Kirkpatrick, et al.1 stated that test methods to predict the long-term coating performance of fusion-bonded epoxy coatings at elevated temperatures need to be developed. Papavinasam and Revie2kg/m/sec at 25 °C. The viscosity of oil sand and heavy oil is about a million times higher than conventional crude oil. The viscosity of oil sand and heavy oil decreases with increasing temperature and equals that of crude oil when the temperature is raised to 200 °C. For this reason, oil sand and heavy oil are transmitted through an existing pipeline infrastructure at 200 °C. At such temperature, a transmission pipeline coating may experience temperatures exceeding 100 °C.
- Europe (0.68)
- North America > United States > Texas (0.50)
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)
INTRODUCTION ABSTRACT The toxicity of most synthetic corrosion inhibitors as well as recent environmental awareness provides sufficient motivation for the evaluation of natural products as potential alternatives. In response to this, the present paper presents the results of a series of studies in our laboratory on the inhibitive effect of selected plant extracts on the acid corrosion of mild steel using different electrochemical and non electrochemical techniques. The results indicate that all the extracts inhibited the corrosion process by virtue of adsorption of their phytochemical constituents on the corroding steel surface and inhibition efficiency improved with concentration of the active constituents. Synergistic effects increased the inhibition efficiency in the presence of halide additives. Inhibition mechanisms showed no generalized correlations, but our observed inhibition efficiencies, in excess of 95% in many instances, is adequate indication that some of these extracts are suitable candidate materials for the formulation of effective non toxic and environmentally friendly corrosion inhibiting additives. One of the most practical methods for corrosion protection of metallic structures deployed in service in aqueous aggressive environments is the use of organic inhibitors to protect the metal surface from the action of the corrodent [1-14]. Recently, due to increasing concerns about the environment and stricter environmental regulations, low inhibitor toxicity is an important requirement for practical applications of corrosion inhibitors. Consequently the current focus in corrosion inhibitor research is to identify and develop new classes of non toxic, environmentally friendly and inexpensive alternatives. In this regard, there has been increasing interest in investigating natural products of plant origin for corrosion inhibiting efficacy. Such studies are justified by the fact that plant parts contain several phytochemical compounds whose molecular and electronic structures bear close similarities with those of conventional organic inhibitor molecules. In addition, plant products are low-cost, readily available and renewable sources of materials. Despite the great availability and varieties of plant materials, only relatively few have been thoroughly investigated. The present report continues to focus on the broadening application of plant extracts for metallic corrosion control and collates some of the findings in our laboratory on the inhibiting effect of some plant materials including leaf extracts of Occimum viridis (OV), Telferiaoccidentalis (TO), Azadirachta indica (AI) and Hibiscus sabdariffa (HS), Mimosa pudica (MP), Moringaoleifera (MO) as well as extracts from the seeds of Garcinia kola (GK) on mild steel corrosion in acidic solutions. The studies have dual purpose; first to further establish the effectiveness of plant extracts as corrosion inhibitors and next to attempt deduction of the inhibition mechanism and possible adsorption modes of the extract active components vis-à-vis a number of experimental and theoretical observations. Materials EXPERIMENTAL The experiments were performed on mild steel sheets with weight percentage composition as follows; C - 0.05, Mn - 0.6 P - 0.36, Si - 0.3 and thickness 0.14cm. The metal specimens were degreased with absolute ethanol and dried with acetone. Investigated plant materials: Azadirachta indica (AI) leaves Garcinia kola (GK) seeds Hibiscus sabdariffa (HS) leaves Mimosa pudica (MP) leaves Moringa oleifera (MO) leaves
- Health & Medicine > Pharmaceuticals & Biotechnology (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.86)
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Health, Safety, Environment & Sustainability (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)
Development Of Low Corrosive Environmental Friendly Calcium Carboante Scale Dissolver For HTHP Wells
Chen, Tao (Champion Technologies Peterseat Drive) | Chen, Ping (Champion Technologies Peterseat Drive) | Montgomerie, Harry (Champion Technologies Peterseat Drive) | Hagen, Thomas (Champion Technologies Peterseat Drive) | Juliussen, Bjorn (Champion Technologies) | Haaland, Torstein (Champion Technologies)
INTRODUCTION ABSTRACT Calcium carbonate is one of the most common scales found in oilfields. Scale inhibitor treatment is a traditional method to control the calcium carbonate deposition. Scale acid treatment is another common way to remove/dissolve carbonate scale. However, high corrosion rate of scale dissolvers at high temperature and the environmental requirement for scale dissolvers have been two major challenges in the development of scale dissolvers and applications under HTHP conditions. In this paper, a low corrosive environmental friendly calcium carbonate scale dissolver has been developed to provide a treatment to remove calcium carbonate scale formed in HTHP wells. The characteristics of this product are as following: Yellow Y1 environmentally acceptable chemical in Norway. Both the aged (170°C) and non-aged samples showed similar CaCO3 dissolving capacity. A high dissolving rate in the initial stages of scale dissolution. No re-precipitation risk after cooling. · Low corrosiveness at temperatures up to 170°C. General corrosion is low and no pitting corrosion observed.In addition, a winterized version of this dissolver has been developed. The performance tests have been carried out and reported as well. Calcium carbonate, CaCO3, is one of the most common scale depositions found in oilfield production wells and surface facilities. It can be deposited all along the water paths from injectors through the reservoir to the surface equipment, especially in high temperature and high pressure (HTHP) wells, where temperature is up to 250C and pressure is up to 20000psi. Calcium carbonate scale forms when the solution is supersaturated with respect to Ca ions and HCO3 -ions. The two major factors causing CaCO3 deposition in the oil and gas industry are reduction in pressure and high temperature during production. Pressure drop leads to the loss of carbon dioxide (CO2) from aqueous solution. This causes an increase of pH and an associated increase of supersaturation. High temperature is another driving force causing CaCO3 self-deposition. The solubility of calcium carbonate decreases with temperature increase, hence CaCO3 crystallization frequently occurs at high temperature. In addition, the kinetics of calcium carbonate scale formation is a function of temperature, i.e. slow kinetics at low temperature. As the temperature increases, the formation of calcium carbonate will accelerates and precipitation may occur at an earlier stage. Carbonate scale formation can impair production by blockage of tubing and flowlines, fouling of equipment and concealment of corrosion. The effects of carbonate scale can be dramatic and costs can be enormous. Effective techniques are needed to solve the scale deposition and keep producing wells healthy. In most cases, scale prevention through chemical inhibition is the preferred method of maintaining well productivity. In order to minimize the formation of scale deposits, scale inhibitors treatment with polycarboxylates or phosphorous containing compounds (such as phosphonates or phosphate esters) are common practice in oil industry. However, while the most polymer scale inhibitors showed a good thermal stability, some phosphonate inhibitors had a limited usage for being applied at temperatures over 170C.
- Europe > United Kingdom (0.47)
- North America > United States > Texas (0.29)
- Europe > Norway > Norwegian Sea (0.24)
- Materials > Chemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Constituents > Salts/Sulphates/Scales (0.75)
Sulfide Stress Cracking (Ssc) Resistance Limits For A 125 Ksi Grade High Strength Low Alloy Steel Octg Developed For Mildly Sour Service
Omura, Tomohiko (Sumitomo Metal Industries, Ltd. Corporate Research & Development Laboratories) | Ohe, Taro (Sumitomo Metal Industries, Ltd. Pipe & Tube Company) | Abe, Toshiharu (Sumitomo Metal Industries, Ltd. Pipe & Tube Company) | Ueda, Masakatsu (Sumitomo Metal Industries, Ltd. Pipe & Tube Company) | Nice, Perry Ian (StatoilHydro) | Martin, John W. (BP Exploration)
INTRODUCTION ABSTRACT A 125 ksi grade high strength low alloy steel OCTG has been developed for mildly sour environments. This has been used for a “Fit For Purpose” production casing material in high pressure / high temperature wells. In this paper, the prevention of oxygen ingress and pH stabilization during testing have been investigated for obtaining accurate SSC test results by NACE TM0177-2005 Method A in mildly sour conditions. Testing techniques have been developed in which the test equipment is contained within a nitrogen chamber and the test pH is stabilized by using an acetic acid / sodium acetate buffering system. The SSC resistance of 125 ksi grade high strength low alloy steel has been evaluated using the above mentioned testing techniques under various H2S partial pressure and pH conditions. The SSC resistance limits are discussed in the relationship between H2S partial pressure and pH. 125 ksi grade high strength low alloy steel OCTG has been developed recently for mildly sour services. This grade has been used for a “Fit For Purpose” production casing material in high pressure / high temperature wells. The first investigations were based on the characterization of conventional C110 steels tempered to 125 ksi grade. At the next stage, new materials with superior SSC resistance were developed for a new 125 ksi grade by the microstructural optimization through Research & Development. Improved SSC resistance was achieved using a decrease in dislocation density by high temperature tempering, better control of the size and the distribution of carbides by the modification of the chemical compositions, adding alloying elements such as Nb and V for the microstructural refining and improved casting process. SSC resistance limits for this new grade had to be clarified, since the high strength grade does not pass SSC tests in conventional NACE-A solution saturated with 0.1 MPa H2S. NACE MR0175 / ISO 15156 specified SSC resistance limits for steels as a function of pH and partial pressure of H2S (pH2S). Figure 1 shows the pH-pH2S diagram in the NACE MR0175 / ISO 15156 standard. Four regions of severity are defined based on the SSC susceptibility. Region 0 corresponds to the non sour service, at pH2S less than 0.0003 MPa, where no precautions are usually required for the selection of steels for resistance to SSC. Regions 1, 2 and 3 respectively define domains of SSC susceptibility. The environmental severity in terms of SSC increases from region 1 to region 3, passing through the transitional region 2. Several works have tried to show the SSC resistance limits for 125 ksi grade OCTG according to the pH-pH2S diagram. The targeted environmental condition for the 125 ksi grade application is 0.003 MPa H2S - pH 3.5. However, the detailed SSC resistance limits have to be more defined. Additionally, it is important to establish appropriate SSC testing procedures in mildly sour conditions because the SSC test results are sensitive to several testing parameters, especially under lower pH2S levels.
INTRODUCTION ABSTRACT Testing of heavy wall longitudinal submerged arch welded (LSAW) large-diameter pipes of grade X65 to X80 for resistance to HIC (Hydrogen Induced Cracking) has been performed at test conditions representing less severe duty compared to NACE TM0284-2003 standard test conditions. The fitness of the material for intended applications (Fitness-For-Service) should be assured for in-field environmental conditions when the extent of HIC cracking is below specified limits. Test gases consisting of defined amounts of H2S in CO2 or N2 representing partial pressures from 0.003 to 1 bar H2S have been used in NACE TM0284 solution A and EFC publication no. 16 solution in a pH range from 3.0 to 6.0 for HIC testing. Pre-mixed commercially available as well as in-situ mixed test gases were utilized for the tests. Both methods of test gas generation showed comparable results. Also the effects of pH (constant and drifting) and test duration (96 h vs. 720 h) were investigated. The test specimens were evaluated by ultrasonic technique and by metallographic investigation according to NACE TM0284. The test results have been compared to SSC severity regions according to NACE MR0175 / ISO 15156-2 to define severely sour, mildly sour and non-sour test regions for the investigated steels. Steel pipelines used for the transport of media containing wet Hydrogen Sulphide (H2S) are faced with the danger of sudden and severe cracking. In sour environments containing water and H2S, hydrogen atoms, originating from the anodic dissolution of the material, can diffuse into the steel. Different forms of cracking may occur, such as Hydrogen Induced Cracking (HIC), Sulphide Stress Cracking (SSC) or Stress Oriented Hydrogen Induced Cracking (SOHIC) . The presence of liquid water necessary for initiation of these mechanisms can even be achieved when the gas temperature in the pipeline is above the water dew point, if the water vapour condenses on the colder pipe walls. Due to the sudden and unforeseeable appearance of these failure mechanisms it is necessary to use HIC resistant pipeline steel for sour applications. The standard laboratory HIC resistance test is given in the NACE standard TM0284, which was last revised in 2003 , or EFC publication no.16 . The test method consists of exposing test specimens to a sour test solution saturated with H2S gas at a partial pressure of 1 bar. After 96 h test duration the specimens are removed and evaluated. The test is not intended to reproduce service conditions, but to provide reproducible test environments to determine the HIC susceptibility at very severe conditions within a short time. The main factors for HIC test severity are the pH and the partial pressure of H2S during the test. Testing with regard to these parameters at less severe test conditions compared to standard testing is frequently called “Fit-For-Service” or Fit-For-Purpose” testing. A classification of line pipe steels regarding regions of severity can be found in NACE MR0175 / ISO 15156-2 .
- Materials > Metals & Mining (1.00)
- Energy > Oil & Gas > Upstream (1.00)
INTRODUCTION ABSTRACT A variety of electrochemical techniques has been used for the evaluation of protective performance of coated steel. For example, one of them is electrochemical impedance spectroscopy. (EIS) Each method has its own characteristic and is suitable to determine some kinds of anti-corrosive mechanisms of coating film. We developed a new evaluation method of protective coatings using current interrupter technique. Generally the equivalent circuit of coated steel is simplified as a connection of the resistance of test solution. the impedance of paint film and impedance of mild steel surface in series. When the time constant of the paint film is much smaller and very different from that of the metal substrate as coated steel in general, the two equivalent circuits can be separated from each other. Thus the polarization resistance of metal substrate was determined by separating the measured paint film impedance from the metal substrate impedance. Electrochemical parameters can be measured by using current interrupter technique. Results of protective coating performance obtained by some experiment were discussed. Corrosion protection by organic coatings is a popular and an important technology. High performance organic coatings have been developed for the protection of steel structures so far. So the evaluation method for these protective paints has been required because of the reduction of developing time for high performance coatings. Several methods of AC method such as EIS, DC method such as CI (current-interrupter technique) and RV(relaxation voltammetry) can be listed as electrochemical techniques. EIS technique is based on from low frequency to high. Current interrupter technique for coated steel was developed which enables to measure protective performances in short measuring time. The measurement starts with applying small current to coated steel at first. Generally the equivalent circuits of coated steel are simplified as a connection of the resistance of test solution, the equivalent circuit of paint film and the equivalent circuit of metal surface under paint film in series. When the time constant of the equivalent circuit corresponding to paint film is much smaller and very different from that of the metal substrate under paint film. the two equivalent circuits can be separated from each other. Thus the polarization resistance of metal substrate was determined by separating the metal substrate impedance from paint film impedance. So current interrupter method allows to obtain electrochemical parameters such as film resistance, film capacitance, polarization resistance, double layer capacitance and natural potential. Simplified circuit for measurement Principle of measurement using current interrupter technique The circuit for the measurement of five electrochemical parameters of coated steel is shown in Fig.1. Small current is applied to coated steel from the potential change of 10 mV to 50 mV by current pulse generator and then current is turned off. A potential decay curve was detected and plotted for obtaining five electrochemical parameters. (Figure in full paper) technique The principle of measurement on electrochemical parameters by current interrupter The current interrupter method is the way that the transitional polarization behavior of coated steel is measured to obtain polarization resistance.
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)