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Energy
ABSTRACT: Premature tube leaks were encountered at a compressor after-stage cooler operating at 100-130°F (37.8-54.4°C) after three years in service due to under-deposit corrosion. The damage encountered was confirmed by visual, metallurgical examination and chemical analysis of corrosion products. The premature failure resulted from condensation of water containing dissolved carbon dioxide, hydrogen sulfide and possibly oxygen at the center bottom portion of the tube. Moreover, the presence of pitting in the liquid phase area indicates that the injection of the oil soluble water dispersible corrosion inhibitor was not effective. Chemical analysis of the deposits revealed that they comprised mainly of iron sulfide products. Metallurgical examination revealed no manufacturing defects. Corrective actions of similar failures are discussed in terms of design and inhibition. INTRODUCTION The compressor after stage cooler tubes failed prematurely after three year in service. Final inspection revealed that 41 tubes out of 360 had leaks subsequent to hydro-tests. An investigation team was assembled to investigate the failure. Three major analyses were conducted including: Failure analysis, process thermodynamic analysis, and field investigation in order to come up with all possible root causes that might lead to the failure. PROCESS OVERVIEW Figure 1 shows a simplified process flow diagram for NGL Plants. The main objective of these NGL plants is to liquefy the feed gas by compressing and cooling it. The NGL Plants receive the feed gas from spheroids, stabilizers at low pressure ~ 1.0 psig (6.9 kPa). The gas is compressed in the compression section to recover the NGL in the stripping section. The off gas from the stripping sections from all NGL Plants is sent to the de-ethanization section to recover more NGL. Figure 2 shows a simplified process flow diagram for an NGL compression system. This includes low pressure (LP) compressors and high pressure (HP) compressors driven by steam turbines. Associated equipment includes the feed gas separator drums, its bottom pump, the inter-stage coolers, the inter-stage separator drums, inter-stage pumps and the after coolers. Feed gas from the spheroids, stabilizers, enters the NGL compression system at about 1.0 psig (6.9 kPa) and passes through the feed gas separator drum, where entrained water is removed. Then, it is compressed to about 60 psig (413.7 kPa) in the low pressure (LP) compressor, cooled in the inter-stage cooler, and then flashed out in the inter-stage separator drum. Water is removed to the pressure sewer from the Inter-stage Separator boot, and hydrocarbon liquid is pumped to the stripper feed drum by the inter-stage pumps. The gas is then compressed to 430 psig (2.965 MPa) in the high pressure compressor, cooled in the after cooler and flashed out in the stripper feed drum. CORROSION OVERVIEW Corrosion Loops Material of construction for all equipment identified in the compression section is carbon steel. Equipment is grouped together according to similar process conditions and degradation mechanisms. Such groups are called Corrosion Loops. A total of four corrosion loops were identified in the compression sections.
- 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 > Processing Systems and Design > Compressors, engines and turbines (1.00)
- (2 more...)
Development Of A Test Protocol For The Evaluation Of Underdeposit Corrosion Inhibitors In Large Diameter Crude Oil Pipelines
Been, Jenny (Alberta Innovates Technology Futures) | Place, T.D. (Enbridge Pipelines Inc.) | Crozier, Brendan (Alberta Innovates Technology Futures) | Mosher, Michael (Alberta Innovates Technology Futures) | Ignacz, Tom (Baker Hughes) | Soderberg, Jeff (Brenntag Canada) | Cathrea, Colin (Champion Technologies Ltd) | Holm, Michael (GE Water and Process Technologies) | Archibald, Darin (Multi-chem Production Chemicals Co.)
INTRODUCTION ABSTRACT: Pipelines carrying heavy crude oil may be subject to corrosion caused by deposition of sediments, a sludge containing oil, water, and bacteria in a particulate matrix. A standard testing protocol was developed with the participation of five inhibitor vendors. The test protocol includes inhibitor evaluations based on (1) Filming Effectiveness, (2) Partitioning Studies, (3) Sludge Corrosivity and Inhibitor Tests, and (4) Bacterial Kill Studies. The results of the different tests and the relevance of each test with regard to the application are discussed. A successful bacterial kill test approach was established. Initial exposure tests of coupons covered with inhibited sludge in oil are most representative of the pipeline environment, but results were variable. Improvements to the test procedure are presented and explored. Crude oil transmission lines have enjoyed a long history without significant levels of internal corrosion due to the use of sediment and water tariff limits that render the bulk fluid non-corrosive. Velocities are generally sufficiently high to prevent accumulations of the remaining trace quantities of water. However, recent experience has indicated that with less than 0.5% sediment and water, accumulation of solids can occur through a combination of gravitational settling and fluid dynamic effects. The deposition of solids can lead to underdeposit corrosion at unexpected locations such as over bends. It has been suggested that the location, quantity, and character of the deposit may be different for large (>20 inch (50.8 cm)) versus small (<10 inch (25.4 cm)) diameter pipelines. Stratification of solids with different properties likely occurs in thick accumulations, but these are difficult to measure since the only practical pipeline sludge sampling method involves pigging, which thoroughly mixes the sludge. One transmission pipeline operator's internal corrosion management program includes pigging and chemical treatment to mitigate internal corrosion on an as-needed basis. These treatment protocols have largely been adapted from upstream pipeline experience where inhibitor vendors have provided successful chemical programs for several decades. Whereas upstream pipelines transport large percentages of corrosive water, transmission pipelines have very different operating conditions. This transmission pipeline operator's pigging and chemical treatment program is effective. However, there are uncertainties regarding the mechanism by which the inhibitors provide their benefit - specifically against the threat of underdeposit corrosion. Vendors are faced with the challenge to develop a chemistry that will penetrate the deposit and inhibit the underlying steel. Development of the right inhibitor chemistry requires an understanding of the nature of the deposits. Deposits consist of mixtures of hydrocarbons, sand, clays, corrosion by-products, biomass, salts, and water and are generally referred to as “sludge” or “schmoo”.1 The sludge chemistry can vary within a stratified sludge deposit, between different locations, and as a function of transported crude. The water content can be several percent and usually consists of an emulsion. However, a thin film has been observed surrounding grains of sand, where contact with other grains can lead to a water layer on the steel surface.2 Corrosion may be promoted by the presence of salts, organic acids, or bacteria.
- North America > Canada > Alberta (0.29)
- North America > United States > Texas (0.28)
Inhibition Of Co2 Corrosion Of 1030 Carbon Steel Beneath Sand-Deposits
Pandarinathan, Vedapriya (Corrosion Centre for Education, Research and Technology Department of Chemistry Curtin University) | Lepková, Katerina (Corrosion Centre for Education, Research and Technology Department of Chemistry Curtin University) | Gubner, Rolf (Corrosion Centre for Education, Research and Technology Department of Chemistry Curtin University)
ABSTRACT: The performance of three corrosion inhibitors was investigated at 1030 carbon steel surfaces in the presence and absence of a sand deposit. Potentiodynamic measurements showed that the inhibition efficiency to mitigate corrosion reactions decreases in the presence of sand deposit. In contrary, the inhibitor performance was found to increase with longer exposure time of the steel to the corrosive media, at sand deposited surfaces. The differences between the steels corroded with and without sand deposit in the presence of an inhibitor were confirmed using both potentiostatic polarisation technique and scanning electron microscopy. The inhibition activity of the studied compounds in mitigating under-deposit corrosion of carbon steel has been discussed. INTRODUCTION Investigation of CO2 corrosion processes of 1030 carbon steel surfaces has been widely researched by numerous authors1-7. The impact of solid particles produced during oil and gas operations on the corrosion inhibition of the system is a major concern for the oil and gas industry2,3. CO2 corrosion is enhanced in the presence of entrained sand particles in the pipelines leading to severe corrosion damage underneath the settled sand deposits4,5. It has been reported that under-deposit corrosion leads to localized corrosion and formation of pits on the metal surface6. In previous investigations, the mechanism of under-deposit corrosion has been related to a galvanic corrosion between surfaces with and without sand deposits 7-10. The control of under-deposit corrosion is currently being accomplished through methods such as pigging and the use of corrosion inhibitor chemicals. While the CO2 corrosion inhibition of mild steel surfaces has been largely investigated, only limited studies have been undertaken to evaluate the inhibition efficiency under a produced sand layer. Little attention has been paid to the principles of inhibition offered by the applied corrosion inhibitors under circumstances where sand deposits are formed, but pigging is not possible11,12. It has been shown that the sand particles can adsorb the corrosion inhibitors applied to the system thereby reducing the activity of the inhibitor13. The organic compounds such as imidazolines, quaternary ammonium compounds, thiols, pyrimidine based compounds, several mercaptans, phosphate esters etc. have been reported as potential CO2 corrosion inhibitors for industrial applications14-17. The aim of this study is to evaluate the performance of a range of corrosion inhibitors under sand deposited carbon steel surfaces in CO2 environment. Electrochemical investigations were conducted under potentiostatic and potentiodynamic conditions to determine the corrosion processes proceeding at the sand-deposited surfaces18,19. The estimated corrosion rates as a function of exposure time from the electrochemical test results and also from weight-loss immersion tests are presented. The surface morphology of the corroded structure plays an important role in determining the inhibition principles20,21. The surface characteristics of the corrosion scale formed in the presence and absence of sand deposits have been analysed using scanning electron microscopy. The influence of sand particles on the inhibition activity of the studied inhibitors has been discussed. EXPERIMENTAL PROCEDURE Test Materials The electrochemical corrosion tests were conducted using 1030 grade carbon steel electrodes embedded in epoxy resin.
- Oceania > Australia (0.68)
- North America > United States > Texas > Harris County > Houston (0.16)
- Materials > Metals & Mining > Steel (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (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)
Prediction of Uniform CO2 Corrosion of Mild Steel Under Inert Solid Deposits
Huang, Jin (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) | Choi, Yoon-Seok (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)
INTRODUCTION ABSTRACT The effect of an inert solid deposit on uniform CO2 corrosion of mild steel is modeled based on a mechanistic electrochemical CO2 corrosion model. Laboratory testing has shown that the dominant factors introduced by the inert solids deposit are related to surface coverage, where both anodic and cathodic reaction rates are decreased because of less active surface area being exposed. The inert solid deposits also create a mass transfer barrier for corrosive species which limits the rate of the cathodic reactions. An existing mechanistic electrochemical model was modified to account for these effects and was capable of capturing the main features of uniform CO2 corrosion of mild steel under inert solid deposits. Severe crevice and pitting corrosion problems can be found under solid deposits in oil and gas pipelines[1]. Localized corrosion can occur under these deposits as they can provide an environment which is chemically and physically different than the areas which are uncovered. Such heterogeneities may lead to formation of galvanic corrosion cells, affect inhibitor performance or harbor bacterial growth leading to MIC,[2],[3]. Underdeposit corrosion is more prevalent at the bottom of horizontal lines and where flow rates are lowest. However, there are very few studies to be found in the open literature related to the mechanisms of underdeposit CO2 corrosion[4]. Most of the available literature refers to the effect of deposits on corrosion inhibitor performance.[5] -[8] Since deposits have been reported as an important factor which may lead to severe CO2 corrosion, it's very important to understand first the mechanisms of uniform corrosion under solid deposits, before focusing on the effect they have on corrosion inhibitor performance. Real-life scenarios for under deposit CO2 corrosion found in oil/gas pipelines are very complex. An insitu deposit is likely to be neither pure nor inert. Rather it has complex composition and even some reactivity. Typical deposits consist of combinations of inorganic solids such as sand, scale and corrosion products, and organic matter such as wax and inhibitor residues. In addition, oxygen (O2), acetic acid (CH3CO2H), hydrogen sulfide (H2S) and bacteria were found in some deposits. Experiment set up EXPERIMENTAL PROCEDURE Experiments were conducted at atmospheric pressure in a three-electrode glass cell, Figure 1. The cell was filled with 2 liters of 1 wt% NaCl solution. CO2 was continuously bubbled through the cell. API# 5LX65 mild steel was used as the working electrode (WE) for electrochemical measurements. Platinum wire was used as a counter electrode (CE) and a KCl saturated silver-silver chloride (Ag/AgCl) reference electrode (RE) was connected to the cell externally via a Luggin capillary. A glass pH electrode was immersed in the electrolyte to monitor the pH during the experiment. Hydrochloric acid (HCl) or sodium bicarbonate (NaHCO3) was added to adjust the pH at the beginning of the test to desired value, which didn't change much throughout the duration of the test. The temperature was maintained within ± 1°C using a hot plate and a thermocouple with feedback control.
- 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 An under deposit corrosion test method has been developed where three carbon steel specimens are mounted together in an assembly. Two of the specimens are covered by sand or another deposit, while one specimen is not covered. The potential difference and galvanic current between sand covered and not covered specimens is measured. The corrosion rate of all three specimens is measured by linear polarization resistance measurements, while the galvanic current is measured by zero resistance ammetry. The paper summarizes the test method and presents experience in using the test method for both film-forming inhibitors and pH stabilization. INTRODUCTION The use of carbon steel in combination with CO2 corrosion inhibitors represents an economically favorable alternative for transportation of unprocessed oil and gas compared to the use of corrosion resistant materials. Corrosion inhibitors used for this application generally contain specifically designed surface active compounds. These compounds adsorb to surfaces and interfaces in the fluid, like solids, emulsions, droplets etc. 1-8 . The surfactant molecules also partition between phases (hydrocarbon or aqueous phase) according to their solubility in the respective phase 1 . Solid particles can consume a significant amount of corrosion inhibitor by adsorption when the surface area is large 2 . This can result in a reduction in inhibitor concentration to levels below the minimum effective concentration. If the entrapment of the inhibitor by solids is not properly accounted for this effect may lead to failure of the system 1-4 . Produced solids affect not only inhibitor performance but many other aspects of the petroleum production as well. Sand particles are known to cause erosion corrosion. They can also form sand beds in some part of the pipelines or in separators. Severe corrosion attack can occur under such deposits 3 . Little has been published about the inhibitor performance in the presence of solids. This paper presents a test method for laboratory testing of CO2 corrosion inhibitor performance in the presence of sand deposits and discusses the experience using this method. The test method was developed to assess the performance of corrosion inhibitors in presence of sand deposition on parts of the steel surface. The cases used as examples in this paper are based on inhibitor addition prior to sand deposition. This represents the case of sand deposition under conditions of continuous inhibition at levels which are sufficient for protection of bare surfaces. The presented test method may also contribute to the development of improved inhibitor products. The intention of the present work was not to compare inhibitors. The inhibitors were used as example products in the development of the test method and identification of critical parameters for the testing. GENERAL PROCEDURE FOR UNDER DEPOSIT CORROSION TESTING The test method described here can be performed in a standard 3 liter glass cell. A specially designed specimen holder and lid has been developed. A sketch of the cell design with the specimen holder is shown in Figure 1. The cell lid is equipped with connections for CO2 gas bubbling, solution replenishment, specimen holder, sand filling, solution sampling and temperature sensor.
- North America > United States > Texas (0.28)
- Europe (0.28)
- Water & Waste Management > Water Management > Water & Sanitation Products (1.00)
- Materials > Chemicals > Specialty Chemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- 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 This paper contains the discussion of a case history where corrosion attacks took place in a slightly sour waste water disposal pipeline. The exposure of the waste water to the air had taken place from an open pit, which may have generated elemental sulfur fine particles in the solution. When solids dropped out from the solution, localized attack was detected in the form of underdeposit corrosion. Details are also given on the laboratory testing results and development of a corrosion inhibition program for such an environment. In many onshore operations, the integrity of a waste water disposal pipeline can be extremely important since any failures of the pipeline may directly result in a shutdown of the entire upstream oil and water separation processes. The main water source to be disposed is generally the produced water after a series of surface facilities, such as, separators, filters, clarifier tanks, cone bottom storage tanks, etc. There are also many waste water sources which are much dirtier in terms of solid content to be transported in the waste line after commingling with the produced water. These waste waters can be from vacuum trucks, drains, scrubbers, soft water cogeneration units and generators and are first dumped into waste pits which could be directly opened to the air. After temporary solids settle out they are pumped into storage tanks and then go through a filtration process whenever the tanks get full. It is then easy to determine that these waste waters are generally full of solids collected from either reservoir or surface facilities. Unfortunately, the filtration process involved can be quite inadequate and ineffective sometimes to get rid of all the suspended solids, particularly the fine particles. The ratio of waste water and the produced water varies from system to system and therefore the quality of the water being sent down to the waste pipeline can differ from month to month, not to mention the variations from the variable field conditions. From a corrosion perspective, it is not hard to concede that the waste water could pose a high risk to the integrity of the carbon steel pipelines in terms of underdeposit corrosion (UDC) due to the presence of a significant amount of solids. The standard reduction potential for oxygen is 1.23 V for equation 1, implicating its strong electron removing capability when compared with other acidic species dissolved in the solution. The detrimental impact of the ingress of oxygen for oil and gas pipeline system had been observed and reported by many operators and researchers1-3. The most effective way to reduce the oxygen impact on the pipeline deterioration is the elimination of the oxygen sources, such as using gas blankets and preventing the leakage. The use of an oxygen scavenger, e.g. bisulfite, is also a typical option in the field. But its effectiveness can be largely limited when the oxygen concentration and location are the uncertain factors, as well as its potential deactivation by other chemicals in the water.
- Water & Waste Management > Water Management > Water Supplies & Services (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Energy > Oil & Gas > Midstream (1.00)
- 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 > Environment > Waste management (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)
INTRODUCTION ABSTRACT: The main purpose of the present study was to develop a comprehensive model that can predict the pitting corrosion rate of oil and gas pipelines containing CO2, H2S, and bacteria. Pitting corrosion has been described using a diffusion model in a unidirectional pit. The model considers 22 ionic species and the potential value inside the pit. The diffusion coefficient values of these ions, which strongly affect the corrosion rate, were found in the literature. This model predicts whether pitting will occur and the maximum corrosion rate at the time of the formation of a corrosion protective scale. The presence of H2S allows for the formation of FeS film, which has a suppressive effect on the CO2 corrosion rate. This suppressive effect on CO2 corrosion rate is more dramatic with increasing temperature and concentration of H2S. In the presence of bacteria, the concentration of sulfates at the bottom of the pit goes to zero when convergence occurs. The sulfate reducing bacteria reduces sulfate to sulfide and produces acetic acid at the bottom of the pit, which accelerates corrosion. These acetates also form complexes with iron, which increase the acidity of the pit. This comprehensive model provides information such as the corrosion rate in mils per year, if the system is CO2 or H2S dominated, and if the system is in a pitting or non-pitting condition. It was observed that the primary parameters that affect the model predictions are temperature, bulk pH, concentration of acetates, concentration of sodium chloride, concentration of hydrogen sulfide, concentration of sulfates, and metal wall thickness. According to Crolet and Bonis1,2, “In the absence of acetic acid there is no record of pitting corrosion in a producing well.” This suggests that pitting corrosion is being enhanced by the presence of acetic acid. At pH values greater than 5.5, there will be minimal CO2 corrosion due to the presence of protective iron carbonate scale. To make the bottom of the pit acetic in the case of CO2 corrosion of iron, complexes of acetates must form. Whichever scale forms first, provides the rate-limiting step of the corrosion reaction. Smith and Wright4 reported that the amount of H2S in the gas phase (H2S partial pressure) necessary to form FeS is dependent upon parameters such as pH, fugacity constant for H2S, equilibrium constants for H2S dissociation, and the solubility product for FeS precipitation. Determination of aqueous H2S activity can be calculated by Henry's law equilibrium constant for H2S. At low H2S concentrations, iron carbonate scale forms (CO2 dominant corrosion). At low concentrations of H2S, the mackinawite film will be unstable due to reaction kinetics. The FeS film dissolves faster than it forms at the mackinawite/solution boundary Ikeda et. al.5 showed that the presence of H2S in a CO2 containing environment had two conflicting effects. Their study observed the temperature effect on corrosion rate up to 250°C, at a constant pressure of CO2 (3.0 MPa) containing a small amount of H2S up to 330 ppm.
- North America > United States > Louisiana (0.28)
- North America > United States > Texas (0.28)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Constituents > Bacteria (0.35)
- 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 > Health > Noise, chemicals, and other workplace hazards (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Materials and corrosion (1.00)
A Mechanistic Model For Predicting Localized Pitting Corrosion In a Brine Water-CO2 System
Zhu, Zhenjin (MCIC Broadsword Corrosion Engineering, Ltd.) | Tajallipour, Nima (MCIC Broadsword Corrosion Engineering, Ltd.) | Teevens, Patrick J. (MCIC Broadsword Corrosion Engineering, Ltd.) | Xue, Huibin (Department of Mechanical and Manufacturing Engineering University of Calgary) | Cheng, Frank Y.F. (Department of Mechanical and Manufacturing Engineering University of Calgary)
ABSTRACT: This paper proposes a Finite-Element-Analysis-based mechanistic model to predict internal localized pitting corrosion rates of petroleum pipelines in sweet (CO2) production environments. In this model, the computational domain consisted of a hemispherical pit and a thin boundary layer of an electrolyte solution. The mesh was generated using quadratic triangular elements in the Cartesian coordinate system whereas a moving mesh method was utilized to track the dynamic pitting propagation. The flux rate of each participating chemical ionic species was computed by solving the Nernst-Planck equation. Specifically, the convection was obtained by solving the Navier-Stokes equations. The electric field in the electrolyte solution was computed based on the Poisson equation with electroneutrality whereas a Debye-Hückel approximation was applied to describe the variation of potential at the metal-solution interface by reason of the existence of the electrical double layer. The ionic concentration distribution was solved using Fick's Second Law. Consequently, the growth rate of a pre-existing pit was predicted. Meanwhile, laboratory tests were conducted to validate the proposed model, demonstrating that the developed model agrees well with experimental data. Furthermore, numerical studies were performed to characterize the effects of convection and chloride ion concentration on pitting corrosion rates. Hence, the model presented herein is able to predict localized pitting corrosion rates and incubation times for its onset in a given sweet system set of operating conditions as well as the onset of pit passivation incubation time. The technical benefits to be gained by the corrosion engineering community and pipeline operators include a better understanding of when to batch chemically treat a pipeline before pitting becomes autocatalytic and when it may be impossible to “turn-off” the pitting excursions due to operationally delaying proper corrosion inhibition practices. INTRODUCTION Localized pitting corrosion is an insidious degradation process of a metal. It primarily manifests as deep cavernous voids which when interconnected have a negative direct impact on the remaining fitness-for-service life of a pipeline. The localized defects can be induced by mechanical breakdown or chemical dissolution (e.g. mineral acids) damage. Pits can also be attributable to other effects of external stress during installation, solids impingement in operation, micro-structural phase heterogeneity during manufacturing, dissimilar expansion/shrinkage rates between scale and metal, as well as chloride anions attack. Upon initiation of the defect, a voltage difference (i.e. potential gradient) occurs between the uncorroded metal and the neighboring adjacent surface, leading to the establishment of an anode at the bottom of the defect but a cathode at the surrounding surface. The generated iron ions tend to effuse into the electrolyte solution. Due to a restricted confined volume inside the defect, ionic transportation (i.e. diffusion or more aptly, mass transfer) is retarded. As ferrous ions are accumulated, Fe²+ hydrolysis takes place under the catalysis by chloride ions, which produces hydrogen ions, depresses pH levels within the defect, and leads to a steep Tafel slope [1]. When an electrochemical reaction appears, a smaller anode dissipates the current as required for the reduction reaction at the cathode, elevating anodic current density.
- North America > United States > Texas (0.46)
- North America > Canada > Alberta (0.29)
- 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)
Pitting Initiation Of Austenitic And Duplex Stainless Steel In Laying Of Flowline In Deepwater
Wang, Jing (Corrosion and Protection Center, Key Laboratory for Environmental Fracture (MOE), University of Science and Technology Beijing) | Lu, Minxu (Corrosion and Protection Center, Key Laboratory for Environmental Fracture (MOE), University of Science and Technology Beijing) | Zhang, Lei (Corrosion and Protection Center, Key Laboratory for Environmental Fracture (MOE), University of Science and Technology Beijing) | Xu, Lining (Corrosion and Protection Center, Key Laboratory for Environmental Fracture (MOE), University of Science and Technology Beijing) | Chang, Wei (CNOOC Research Institue) | Guo, Hong (CNOOC Research Institue)
ABSTRACT: With development of oil and gas exploitation in deepwater, more and more stainless steels have been used in flowline. However, stainless steels may suffer from pitting in seawater. This research was based on corrosion risk in laying process of subsea flowline. The initiation time of stainless steels immersed in seawater is one of the dominate factor during materials screening, design and laying of flowline. In this work, pitting corrosion behaviors of austenitic and duplex stainless steel including initiation was investigated. Also the effects of temperature, dissolved oxygen, salinity on corrosion were discussed by morphologic characterization of localized corrosion associated with its shape and size description. Another assessment was cyclic potentiodynamic polarization. During cyclic potentiodynamic polarization, it was recorded versus a saturated calomel electrode. The results show that temperature, dissolved oxygen, and especially temperature were main factors which affect corrosion behavior of stainless steels in seawater. INTRODUCTION With more and more demand for oil and gas, oil and gas reservoirs had put visions to deeper waters, with water depth often greater than 1500 meters. Stainless steel had been widely used in seawater for flowline materials due to its excellent corrosion resistance and high fatigue properties. For subsea installation and commissioning there is a significant risk of raw seawater ingress during laying process of flowline in deepwater. Stainless steel and other duplex steels often used for flowline, will suffer quite rapid pitting if exposed to raw sea water for a period times. To determine the pitting susceptibility under different environment and how long the pitting will appear, cyclic potentiodynamic polarization and immersion experiments were carried out in this work. Many researchers had divided the step of pitting corrosion as initiation, metastable propagation and stable propagation of pits, with the passive film breakdown, it developed an aggressive local chemistry at the corroding site, next is the continued stable growth of the corroding area [2-5]. P, Ernst and R. C. Newman studied pit growth of 304SS foil, and it shows that pits grown in plate material and high alloy stainless steel have the same basic morphology [6]. Some researchers had found that the severity of pitting tends to increase with the logarithm of the chloride concentration [7]. H. P. Leckie found that corrosion potentials of AISI 304 SS increased with oxygen concentrations at high temperature in high-purity water[8,9,10]. W.-C researched different dissolved oxygen (DO) concentrations on low carbon steel, and the current increased when pitting appeared. Current reached highest when the dissolved oxygen was 8.5ppm at beginning of the reaction (DO=0.01ppm, 0.09ppm, 0.43ppm, 8.5ppm) [11]. J. H. Zheng did a research on the effects of dissolved oxygen on the potential of 316L stainless steel in hot lithium hydroxide solution, and they found that the corrosion potential will remain at around -850mV vs SCE if the dissolved oxygen in the solution is controlled at a level of less than 10ppb, however 316L stainless steel will become completely passivated when about 650ppb of oxygen exists in the solution [12].
- North America > United States (0.47)
- Asia > China (0.30)
- Materials > Metals & Mining > Steel (1.00)
- Energy > Oil & Gas > Upstream (1.00)
ABSTRACT: In order to assess the risk of pipeline failure due to a leak or burst, information about the current state of the pipeline must be combined with a corrosion rate that models how quickly the anomalies grow. Information about the current state of the pipeline can be inferred from inspections and is a critical ingredient in the integrity management decision making process. Inline inspection results are subject to various sources of uncertainty. This paper specifically addresses the effects of sizing uncertainties on integrity decisions. In-line inspection sizing accuracies are currently assumed to be independent of the actual feature size. This paper explores the practical consequences of this assumption through the rules of mathematical statistics. The paper highlights that - due to random sizing errors -the deepest feature call often represents an overestimate of the true feature depth and discusses some of the implications thereof on integrity management decisions such as excavation, repair or replacement. In many approaches that are proposed in the literature the time-averaged corrosion rates are computed without explicitly considering the effect of the sizing uncertainties. This paper highlights some of the effects of these uncertainties and the resulting biases that occur in the exceedance probability calculations based on these statistical corrosion rate models. The intent of this paper is to demonstrate the significant consequences when interpreting the largest anomalies in the ILI results under the current sizing error assumptions. It is the intent to bring this to the industry's attention and foster a constructive discussion about the adequacy of the current practice or the need for more detailed sizing uncertainty models. INTRODUCTION In order to assess the risk of pipeline failure due to a leak or burst, information about the current state of the pipeline must be combined with a corrosion rate that models how quickly the anomalies grow. Information about the current state of the pipeline can be inferred from inspections and is a critical ingredient in the integrity management decision making process. Inline inspection results are subject to various sources of uncertainty. This paper specifically addresses the effects of sizing uncertainties on integrity decisions. The analysis in this paper is based on rigorous application of the principles behind mathematical statistics. Traditionally, each feature reported by ILI is treated as a stand-alone measurement and is subject to uncertainty. The uncertainty distribution is often identical for all features. This paper advocates looking at the ensemble of all data points and making maximum use of the additional information this brings about. Aside from the current state of the pipeline, the corrosion rate is another critical component for integrity management. Corrosion rates can be estimated from standards and industry guidelines, correlation and regression models applied to similar service conditions, coupon losses, indirect measurements, or a comparison of the results of multiple inline inspections. This paper discusses accurate estimation of corrosion rates from the results of multiple inline inspections. The discussion in this paper is limited to the effects of the sizing uncertainty only.