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Results
Predicting Localized CO2 Corrosion In Carbon Steel Pipelines
Li, Hui (Institute for Corrosion and Multiphase Technology Department of Chemical & Biomolecular Engineering Ohio University) | Brown, Bruce (Institute for Corrosion and Multiphase Technology Department of Chemical & Biomolecular Engineering Ohio University) | Nešic, Srdjan (Institute for Corrosion and Multiphase Technology Department of Chemical & Biomolecular Engineering Ohio University)
ABSTRACT: A mechanistic model is being developed with the aim of predicting localized CO2 corrosion in carbon steel pipelines. The model is built based on a galvanic coupling mechanism proposed to be responsible for pit propagation of carbon steel in a CO2 environment. Various phenomena associated with the localized corrosion process, such as electrochemical reactions, chemical reactions, mass transfer, FeCO3 film formation, passivation, depassivation and repassivation are taken into account in the model to generate a complete and realistic simulation of field conditions. Both uniform and localized corrosion rates can be predicted depending on how corrosion conditions evolve with time. The model calculates the change of corrosion condition at each time step to determine if a uniform or localized corrosion model should be used. In addition, this model provides users with other valuable information, such as local water chemistry, fluxes of species, and film morphology to help users understand the corrosion process. A parametrical study shows the effect of a variety of factors on the corrosion process which is in agreement with common knowledge about localized corrosion. INTRODUCTION Localized corrosion is considered one of the most destructive forms of corrosion in the oil and gas industry. Although normally occurs over a limited surface area, it can lead to failure of pipelines and equipment in a relatively short period of time due to its high propagation rate. Consequently, localized corrosion is a major concern in the oil and gas industry as its normal operation is heavily dependent on the integrity of low cost carbon steel pipelines, normally passing over thousands of miles over land, underground and subsea. Significant efforts have been made towards understanding corrosion mechanisms over the past few decades. Today, researchers have reached a sufficient level of knowledge that enables them to propose theoretically sound mechanisms for uniform corrosion of carbon steel which are supported by empirical data.1 Except for a few minor aspects, uniform corrosion of carbon steel can be said to be well understood. However, what happens in localized corrosion for carbon steel remains far less clear. Despite extensive past research, the mechanistic understanding of localized corrosion remains far from adequate. This is partly because water chemistry, particularly surface water chemistry, in the very small area of a pit is normally inaccessible by conventional equipment and differs substantially from the bulk solution. The complexity of localized corrosion is aggravated by the fact that initiation of pitting corrosion appears to be a (semi) random process in terms of when and where pits happen. Intuitively, one can say that pit initiation is also associated with the physical and chemical environment in close proximity to the metal surface. Therefore, it is critical to find a way to determine conditions near the steel surface, such as water chemistry and electrochemical phenomena, in order to understand what happens in localized corrosion. Unfortunately, up to now, few experimental methods have been found that can reliably detect localized corrosion or local water chemistry 2 , making it one of the biggest challenges for corrosion research.
- 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 aim of this work is to analyze hydrogen damage and possible prevention in the oil refineries. Hydrogen damage failures are differentiated into two groups based on two mechanisms: electrochemical processes (mainly at low temperature, up to ~100°C) arising from acid corrosion or cathodic protection, and high temperature (between 200 and 900°C) arising from the presence of hydrogen gas at high pressures. Examples of hydrogen damages and their analysis are given for the various units of oil refineries. The aim of this work is to analyze typical hydrogen damages and possible prevention at the oil refineries' units. Hydrogen gas occupies an essential place in the processes in the oil refining industry: hydrodesulfurizers, hydrocrackers, and catalytic reformers. In addition to these processes proceeding at high temperatures (>200°C), there are some sources of hydrogen gas arising from electrochemicalcorrosion of carbon steel equipment in contact with aqueous solutions of acids, such as H2S (sour water), HCl, HCN, H2SO4, and HF at low temperatures (20 to 100°C) and chemical corrosion by organic acids (naphthenic acids among them) at 101 - 360°C. Many names of hydrogen damages representing physico-chemical phenomenon appeared in books and encyclopedias1-8 using by many generations of chemical engineers, chemists, corrosion engineers, scientists and materials engineers. In one monograph9, hydrogen damages were divided into two groups based on two mechanisms: electrochemical processes (mainly at low temperature, up to ~100oC) arising from acid corrosion and cathodic protection (when water molecules can be reduced to hydrogen atoms at certain potentials), and high temperature (between 200 and 900°C) arising from the presence of hydrogen gas at high pressures (4 - 30 MPa). We suggest differentiating special case of appearing of hydrogen gas on carbon steel surface because of chemical corrosion by organic acids (naphthenic acids among them) at 101 - 360°C10, 11. Low temperature (<100°C) hydrogen damage takes place with the participation of hydrogen ions (H+) which are reduced to hydrogen atoms (Ho) and penetrate into steel. This type of hydrogen damages can occur in the overhead of atmospheric and vacuum distillation columns, amine, isomerization, fluid catalytic cracking, and alkylation units. In cathodic protection at potentials below -0.72 V vs Cu/CuSO4 electrode, water can be reduced with release of hydrogen gas which can penetrate into steel and cause hydrogen embrittlement. Chemical attack by organic acids (naphthenic acids among them) which are present in crude oils and petroleum distillates results in formation of hydrogen gas on carbon steel surface and its penetration inside. Different monitoring methods were developed for detection of possible hydrogen damages. We can differentiate them into two groups: detection of hydrogen gas and detection of physical discontinuities (fissures, cracks, blisters) in metals resulting in changes of their mechanical properties. Hydrogen gas can be detected either in intrusive or non-intrusive devices called hydrogen probes. Hydrogen that penetrates through a metallic wall can be detected by manometric (hydrogen pressure) or vacuum method, electrochemically (hydrogen ionization from H atoms into H+ ions), heat conduction (gas chromatography), vacuum extraction at 400°C, or hydrogen effusion.
- Geology > Geological Subdiscipline (0.34)
- Geology > Mineral (0.32)
- Energy > Oil & Gas > Downstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.67)
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Reservoir Description and Dynamics (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)
ABSTRACT: AC-induced corrosion continues to be a controversial subject and a full agreement on influencing parameters and mechanism has not yet been achieved. The influence of AC-induced interference on the localized corrosion resistance of passive metals is discussed on the basis of laboratory test results. Tests were performed on stainless steel with different chemical composition (PREN 18 and 25) in soilsimulating solution and on carbon steel in alkaline solution (under cathodic protection of carbon steel, the local pH at the soil-steel interface is higher than 10, so carbon steel is in passive condition). Potentiodynamic tests were also carried out to analyse the effects of AC stationary interference on passivity current density. Applied AC was in the range of 10 A/m2 to 100 A/m2. Results allow to evaluate the effect of AC on: time-to-corrosion, AC critical current density and corrosion morphology. INTRODUCTION In the last 25 years, AC-interference, due to the parallelism between pipelines and AC power lines, have caused problems of electrical safety, corrosion and management of cathodic protection (CP) systems. While for DC induced corrosion on buried metal structures there is large agreement on criteria to be used for corrosion mitigation and international standards are available since many years 1-2, in the case of AC interference different approaches are proposed and different opinions still exist. To define AC corrosion risk, the primary parameters are AC density and AC voltage. Nevertheless, from field and laboratory experiences, AC density appears to be the most accurate parameter. Instead, AC voltage, measured as remote earth voltage, seems to be a less accurate parameter because this value is the product of two parameters, that is AC current and environment resistance, so that no absolute threshold value can be adopted. Other AC corrosion risk related parameters are 3-4: cathodic polarization (in the case of metal structures in cathodic protection conditions), coating defect surface area, electrolyte composition and resistivity. Recently, a European Technical Specification, UNI CEN/TS 15280-20075, has been published, but doubts still remain on the identification of the most influencing parameters (i.e., AC voltage or AC density) and above all the threshold values of critical parameters and the corrosion mechanism in the presence of AC. The European Technical Specification 5 and NACE reports 6-7 suggest critical values as regard the maximum allowable AC voltage to remote earth in order to control AC-related corrosion. Thought this parameter is of easy measurements, it is not directly linked to the interfering AC density. Because AC density is claimed as the most critical parameter, coated structures are more susceptible of AC-induced corrosion since high AC density can be reached at coating pin-holes or coating small defects. Based on experimental results 8-12, no significant increase of corrosion rate, in both aerobic and anaerobic conditions, being measured on carbon and low alloy steels in freely corroding condition at AC density lower than 30 A/m2. In this paper, the effect of AC-induced interference on the corrosion resistance of passive metals is studied and discussed on the basis of laboratory test results.
- Europe > Italy (0.29)
- North America > United States > Texas > Harris County > Houston (0.15)
- Research Report > New Finding (0.34)
- Research Report > Experimental Study (0.34)
- 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)
Water/Hydrocarbon Co-Condensation And The Influence On Top-Of-The-Line Corrosion
Pojtanabuntoeng, Thunyaluk (Institute for Corrosion and Multiphase Technology Ohio University) | Singer, Marc (Institute for Corrosion and Multiphase Technology Ohio University) | Nesic, Srdjan (Institute for Corrosion and Multiphase Technology Ohio University)
ABSTRACT: Top of the line corrosion (TLC) is a great concern in wet gas transportation where temperature gradient between the internals of the pipeline and the outside environment leads to the condensation of water vapor and a lighter fraction of hydrocarbons. Liquid water from the condensation is greatly corrosive as it is saturated with the acid gases; e.g. CO2, H2S, HAc, etc. Extensive work has been previously focused primarily on the hydrocarbon-free systems. In reality, the presence of condensable hydrocarbons affects the overall condensation process as two immiscible liquids with different wettability will form on the steel surface. As a result, less corrosion would be expected if hydrocarbons condense on the steel surface together with water. This work investigates the influence of hydrocarbon co-condensation (n-heptane) on top of the line corrosion. The wettability of water and n-heptane on carbon steel (X65) was determined and corrosion tests under co-condensation were conducted. The results show that following condensation water has higher affinity towards carbon steel than n-heptane in all cases. In a hydrocarbon-free system, corrosion rate increased with the water condensation rate whereas the presence of n-heptane provides some degree of protection in the co-condensation scenario. Under the condition tested where the steel temperature was relatively low (less than 30°C), iron carbonate scale was detected in a co-condensation system but not in a pure water system, suggesting different chemistry in the water condensate phase. INTRODUCTION In stratified wet gas transportation, lighter hydrocarbons fractions may co-condense along with water vapor. The condensate is then composed of two immiscible liquid phases water and hydrocarbon, having different abilities to wet the steel surface. Corrosive gases dissolve into the condensed water formed on the upper surface of the pipe resulting in Top-of-the-Line Corrosion (TLC). Extensive research has been conducted and key parameters influencing TLC have been investigated (e.g., temperature, pressure of acid gases, total pressure, acetic acid, etc.) [1-4]. However, those earlier studies focused on hydrocarbon-free systems whereas in reality the co-condensation of hydrocarbons is also present. The presence of hydrocarbons can affect TLC either by changing the wetting of the steel surface or by influencing the water chemistry of the system. Since the hydrocarbons act as a nonelectrolyte, it is expected that they will generally lower the CO2 corrosion rate. It has been established [5- 8] that crude oil provides protection to the steel if it displaces water from the steel surface at the bottom of the line. Lower interfacial tension indicated weak interaction between water and hydrocarbon interface. Thus, water phase was easily entrained into small droplets and maintained in the bulk oil phase. However, the hydrocarbon fraction that co-condenses with water at the top of the line, differs from that at the bottom, and is fairly light - may range from pentane to nonane. It was thought that such light condensate fractions do not give much protection to the steel from CO2 corrosion [5], [6]. Yet, it should be pointed out that this referred primarily to the bottom of the line corrosion.
ABSTRACT: Based on laboratory and field data, the presence of acetic acid (HAc) in oilfield brines has been found to enhance both the occurrence and the rate of localized CO2 Top-of-Line Corrosion (TLC). However, the fundamental role of this organic compound in CO2 corrosion is still a controversial topic, particularly concerning its electroactive participation in the overall cathodic mechanism. In an attempt to assess this issue, the effect of HAc on the kinetic behaviour of carbon steel was addressed in this study by means of both electrochemical measurements and electron microscopy examinations. Whether HAc acts as a specific cathodic reactant or just as a proton source or both was the central idea of the present work. The results are further discussed in terms of repercussions on TLC corrosion. INTRODUCTION In the petroleum industry, internal CO2 corrosion of carbon steel pipelines for transportation of crude or semi-processed hydrocarbons is often associated with the presence of some other acidic gases or volatile organic acids. Acetic acid (HAc) appears to be one of the most prevalent organic compounds that are usually found in oil and gas reservoirs with concentrations ranging from a few hundreds up to thousands of ppm in the co-produced aqueous phase. Results reported from both field observations and laboratory investigations have shown that the presence of HAc may induce a detrimental effect on the overall corrosion rate and the pitting morphology in sweet systems 1 , 2 . This is particularly relevant in the case of top of line corrosion (TLC). Indeed, field experience shows that HAc is a key factor in the localized TLC attacks. For this reason, the role of organic acids in general and HAc in particular has increasingly caught up the attention of the major actors in oil and gas industry over the last few years. The effect of HAc on the corrosion rate of carbon steel in CO2-containing media has been extensively addressed in a number of independent studies over a wide range of operating conditions as discussed and summarized in recent literature reviews 3 , 4 . The fundamental role of acetic acid in CO2 corrosion of carbon steel has however been the subject of apparent controversies thus far, particularly in which concerns the eventual electroactive participation of this compound in the cathodic mechanism. The effect of HAc on the overall kinetic behaviour of carbon steel and corrosion scaling was addressed by means of electrochemical measurements and SEM examinations. Whether HAc acts as a specific cathodic reactant or just as a proton source is the central idea of the present work. EXPERIMENTAL PROCEDURE Electrochemical measurements were performed at room temperature in a conventional three-electrode cell on coupons machined from API 5L X 65 pipeline steel. The elemental composition of the steel is given in Table 1 . A coiled titanium wire was used as a counter-electrode. Surface and cross-sectional examinations were performed using a scanning electron microscopy (SEM) equipped with an energy dispersive spectroscopy (EDS). Iron (II) content was determined by spectrophotometry at 508 nm as ortho-phenanthrolin complex.
- Europe (0.28)
- North America > United States (0.28)
ABSTRACT: Pitting corrosion has been observed in the internal of a tank after only one year of service in a petrochemical plant. The tank was protected by sacrificial magnesium anodes suspended from the roof. The corrosion occurred as a result of the failure of internal Cathodic Protection (CP) through the fast consumption and self corrosion of the magnesium anodes. The analysis of the tank content indicated an alkaline electrolyte with pH 10.5 at 60 0C and high conductivity. The main objective of this paper is to study the magnesium anode corrosion behavior in the same solution as the tank by examining polarization behavior of the magnesium anode in the same solution and by simulating the entire CP system using the commercial boundary element analysis software. The possibility of using aluminum anodes in the tank solution was also investigated. The High conductivity of the solution and relatively high temperature accelerate the self dissolution of magnesium anodes. Aluminum anodes are recommended as replacement for the magnesium anodes. INTRODUCTION Cathodic Protection (CP) is one of the corrosion control techniques that is used widely in industry to decelerate corrosion rates. It works through out the metal structure by acting as cathode for an electrochemical cell. There are two types of CP systems impress current CP and sacrificial CP. Sacrificial CP occurs when a metal is coupled to a more reactive anodic metal; this connection is referred to as a galvanic couple. In order to effectively transfer corrosion from the metal structure to the anodic metal, the anode material must have a large enough natural voltage difference to produce an electrical current flow. The most commonly used sacrificial anodes are magnesium anodes for media with low conductivity because magnesium has high derivation current. Zinc and aluminum alloys are also used as galvanic anodes. Modeling techniques have been applied in the CP field since the 1980's. There are a lot of structures that have been modeled such as offshore platforms1, ships 2 3 and Pipelines. 4 Numerical methods applied to corrosion problems have included the finite different method (FDM), finite element method (FEM) 5 and Boundary element method (BEM). The BEM has superiority over the FDM and FEM in the following advantages 6: § The meshes are only on the surface, so mesh generation can be used with confidence, and a CP model can be constructed quickly and inexpensively. § BEM methods are very effective and accurate for modeling infinite domains as is the case for long pipelines. EXPERIMENTAL PROCEDURE An electrochemical test was conducted for the magnesium and aluminum alloy. The VersaSTAT4 (1) potentiostat with VersaStudio (1) software package was used to generate the open circuit potential (OCP) measurements, along with potentiodynamic polarization tests. The tests were carried out by a traditional three-electrode glass cell. Magnesium and aluminum alloy were used as solid electrodes with 1 cm2 exposed area while the counter electrode was graphite bar. The reference electrode was Standard Calomel Electrode (SCE) and all the electrodes were immersed in high alkaline electrolyte (Table 2).
- North America > United States > Texas (0.16)
- North America > Canada > British Columbia (0.15)
- 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)
ABSTRACT: Positive Material Identification (PMI) has become an important inspection protocol at petroleum refineries and power plants around the world to help prevent catastrophic failures of piping systems. Many of these failures are caused by accelerated corrosion resulting from the chemical makeup of the pipes. Three corrosion mechanisms will be discussed, which include Residual Elements in HF Alkylation Units, Sulfidation, and Flow Accelerated Corrosion (FAC). Traditionally, chemical analysis of carbon steel piping has been performed by laboratory analysis of filings, or more recently, by the use of spark-based optical emission spectroscopy (OES) instrumentation. Handheld x-ray fluorescence technology, with its dramatically improved detection limits, ease of transport, reduced sample preparation, and nondestructive analysis, has now become a valid and industry-accepted method for PMI. Details of recent advancements in handheld XRF technology are provided, and how it can be used as a tool to prevent failures due to accelerated corrosion. INTRODUCTION Today's inspectors and maintenance personnel in petroleum refineries and power plants have access to powerful new testing tools that change the way that positive material identification (PMI) is performed. They can test miles of pipeline, piping systems, vessels, and their associated refinery alloys during a single turnaround, helping to avoid the potential dangers caused by material mix-ups. These instruments can detect and measure trace elements for FAC modeling as well s analyze components for residual elements in HF alkylation and low Si sulfidation systems. RESIDUAL ELEMENTS (RE) Residual element concentrations in carbon steel pipe can be a critical indicator of the expected life and performance of finished components in petrochemical applications. Particular elements of interest include chromium (Cr), copper (Cu), and nickel (Ni), as well as molybdenum (Mo), tin (Sn), vanadium (V), antimony (Sb), arsenic (As), and lead (Pb). As the manufacturing of carbon steel becomes more dependent on recycled product, residual element concentrations in finished materials increase. Further, residual elements are difficult to remove or lower using simple metallurgical techniques during the melting process. Because residual levels can be strong indicators and affecters of material properties, including corrosion resistance, residual element analysis is increasingly a major concern in both installed and newly purchased materials. The greatest area of concern related to residual element analysis in petroleum refineries is in hydrofluoric acid (HF) alkylation units where increasing levels of RE can result in a significant increase in preferential non-uniform corrosion. RE Prevention Through Elemental Analysis A guideline found in API RP-571,1 which focuses on damage mechanisms affecting fixed refinery equipment, says that corrosion can be minimized based on the carbon content and the sum of residual elements Cr, Ni, and Cu. The optimum conditions for non-uniform corrosion in a carbon steel piping system calls for a carbon content of <0.18%, and a sum of the RE to be <0.15%. A case study cited in the September 2004 issue of Hydrocarbon Processing2showed that HF alkylation units can be subject to selective corrosion in a unique manner resulting from elevated levels of residual Cr, Cu, and Ni.
The Influence Of Flow Rate And Inhibitor On The Protective Layer Under Erosion-Corrosion Conditions Using Rotating Cylinder Electrode
Akbar, Abdulmuhsen (Institute of Engineering Thermofluids, Surfaces and Interfaces, School of Mechanical Engineering, University of Leeds) | Hu, Xinming (Institute of Engineering Thermofluids, Surfaces and Interfaces, School of Mechanical Engineering, University of Leeds) | Neville, Anne (Institute of Engineering Thermofluids, Surfaces and Interfaces, School of Mechanical Engineering, University of Leeds) | Wang, Chun (Institute of Engineering Thermofluids, Surfaces and Interfaces, School of Mechanical Engineering, University of Leeds)
INTRODUCTION ABSTRACT: This paper reports findings from an investigation into the effect of flow rate and organic inhibitor on the material performance, film thickness and hardness of protective scales formed on X65 carbon steel surface in a rotating cylinder electrode (RCE) system. The experiments were conducted at a temperature of 70 °C, pH of 5.9 and 4.5 g/cm.s² wall shear stress (tw) using both uninhibited and inhibited Forties brine with 25 ppm of inhibitor saturated with carbon dioxide (CO2) containing 0.1% HST60 PSA silica sand, which can be described as semi-spherical with sharp edges. Weight gain/loss was measured for: as-received X65 specimens and specimens before and after removing corrosion scales in both uninhibited and inhibited systems. In addition, the hardness of the surface specimens and scales was measured using a nano-indenter. This was supported by post-test analysis of samples using scanning electron microscopy (SEM), focus ion beam SEM (FIBSEM), energy dispersive X-ray spectroscopy (EDX) to assess the nature, the thickness, the elemental composition and the possible salts forming these protective films. It was found that the weight loss of as-received surfaces was reduced by more than 43% when 25 ppm of inhibitor was introduced. Nevertheless, inhibitor was found not to be effective in reducing weight loss of pre-scaled surfaces. Sweet corrosion is a significant and costly issue in the oil and gas industry 1-5; 12.5% of failures in the oil and gas industry related to the phenomenon. Pipelines transporting hydrocarbons and produced water/seawater injected are in some cases made of carbon steel. Failure of such pipelines results in their shut down and hence costs million of dollars 6-7. The mechanism of carbon dioxide corrosion is a complicated process. It is influenced by different factors and conditions, such as carbon dioxide partial pressure and temperature which affect the corrosion rate, pH value which influences anodic mechanisms for iron dissolution in CO2 solutions 8 and velocity in which turbulence pushes a sweet system into a higher corrosive regime. Corrosion inhibitors are used to prevent or reduce material degradation due to corrosion for carbon steel pipelines. They are widely evaluated under stagnant or low flow rate (<1 m/s), in addition some work has been done to assess the performance of them in multiphase flow 9. However, there is still a need to evaluate the performance of these inhibitors under high shear conditions and especially in erosion-corrosion where sand present. Some investigators 10-16 attempted to study the influence of flow intensity and inhibitor concentration on initiation of flow-induced localized corrosion (FILC) and mechanical properties of corrosion scale products. On the other hand, some other investigators noticed that cracking and spalling of corrosion scales was primarily because of the intrinsic stresses ¹². Fracture toughness is used as a measurement of cracking resistance of the corrosion scale. Gao et al. observed that the fracture toughness changed considerably with flow rate and the scale produced at velocity of 0.5 m/s showed the lowest fracture toughness of 0.64 MPa ¹³.
ABSTRACT: The Inline Inspection (ILI) data indicated that corrosion has taken place inside the pipeline transporting the wet natural gas containing CO2 at very high temperature. The corrosion inhibitor at the injection rate of 0.47 Liter per MMSCFT (One Pint per MMSCFT) was injected into the pipeline to protect carbon steel from corrosion. The corrosion modeling results showed very high corrosion rate under the operating conditions. The severity of corrosion inside the pipeline detected by ILI was much lower than the corrosion prediction modeling results. The finding in this study showed the passivation film formed under the operating conditions at very high temperature reduced the general corrosion rate. However, addition of the corrosion inhibitor to the testing autoclaves reduced its protection, and increased corrosion rate. A corrosion inhibitor that is compatible with the passivation film is required to protect the pipeline. This study demonstrated how the laboratory data have supported the corrosion mitigation program for a field operation through exploring the mechanism of high temperature CO2 corrosion of carbon steel in a low total dissolved solids (TDS) brine. INTRODUCTION High temperature CO2 corrosion of carbon steel is one of the most challenging areas in the oil and gas industry. High temperature wet natural gas, in conjunction with a high production rate, affects the kinetic balance of formation and deterioration of the protective passivation layer. The very significant effect of protective iron carbonate films, especially at high temperature1, presents one of the greatest difficulties in the prediction of CO2 corrosion of carbon steel. It was also reported that corrosion prediction models lack supporting laboratory data at high temperature and high pressure.2 Schmitt, et al.,3 studied the effect of flow on localized corrosion in the presence of scale. Many papers reported using laboratory tools to select corrosion inhibitor.4-6 This study was initially intended to solve a corrosion issue for an operations team in Indonesia. The field produces large amount condensate and wet natural gas containing at least 5-mole % CO2 at high pressure and temperature. The high gas production rate generates a very high flow gas flow velocity inside the pipelines. The combination of these conditions results in a very corrosive environment inside the pipelines. The existing well flow lines were designed to use carbon steel material and apply the corrosion inhibition program to control internal corrosion to enable the pipeline to be operated safely within its design life. A recent inline inspection of the existing pipeline, using the intelligent pig technique, showed the areas inside pipeline affected by internal corrosion. The suitability of carbon steel pipeline was called into question, along with the requirements for an effective corrosion inhibitor. Although it is very challenging, it is critical for corrosion engineers to evaluate the existing corrosion inhibition program and develop a long term corrosion mitigation strategy plan, including selecting a suitable corrosion inhibitor and determining appropriate injection rates. This purpose of this study is to understand the corrosion phenomena of pipelines that transport condensate and wet natural gas containing CO2.
- North America > United States (0.47)
- Asia > Indonesia (0.36)
- 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: Deposits can play an important role in the corrosion rate and morphology of carbon steel in a production environment as well as affect the efficacy of an inhibitor. A test method has been developed to investigate the corrosion characteristics of carbon steel in a stratified flow regime where deposits of solids accumulate in the bottom of a pipeline. This test method is used to investigate the difference in under deposit corrosion of API X-65 carbon steel when the deposit consists of either sand or iron sulfide (FeS) with and without the presence of mill scale on the steel. In the case of bare API X-65 carbon steel, the average corrosion rate of the coupons in the FeS deposit is significantly higher than those in the sand deposit, with metal thinning above the deposit and pitting at the solid / liquid interface. In the case of the carbon steel with mill scale, the average corrosion rate and the thickness loss of the coupons were relatively the same for the two deposits. Pitting occurred on the samples with mill scale in the sand deposit, though not in the FeS deposit. Under deposit corrosion can occur in a variety of stratified flow environments and can come in a variety of forms from sand and clays to corrosion products to biofilms to basic sediment and water (BS&W). Deposit composition affects the corrosion mechanism uniquely, so the expected deposit should be included in testing, especially for inhibitor effectiveness. This paper investigates the difference in under deposit corrosion when using sand versus iron sulfide (FeS). Stratified flow is a type of flow regime in which the different phases separate, usually in horizontal pipe, with the lighter fluids moving across the top, and the heavier fluids and solids moving along the bottom. Because of the lack of turbulence, water separation and solids dropout occurs. Sand deposits cause the formation of differential concentration cells, promoting corrosion in a similar manner to crevice corrosion.1 The sand itself does not interact with the metal surface. Iron sulfide, however, not only promotes the differential concentration cell, it is also electrochemically active, with a potential much more noble than bare carbon steel, the level of which is dependent upon the pH2, creating a galvanic couple between the covered steel and the exposed steel. Test Materials EXPERIMENTAL PROCEDURE The test coupons were rectangular API 5L X65 coupons, diagrammed in Figure 1. Table 1 gives the chemical composition of the material. Just prior to testing, one set of coupons was heated to 1100°F (593.3°C) for approximately 3 hours to form a mill scale. The coupons remained in the oven during the heating and cooling process. Test Environment ASTM D 1141 substitute seawater, the composition of which is given in Table 1, was used for the testing. The temperature was 100°F (37.8°C), and the solution was saturated with 20 psig (0.14 MPa) of 50% H2S / 50% N2. The pH after saturation was 6.08.
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)