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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)
Role Of Acetates On Pitting Corrosion In A CO2 System
Garber, James D. (Corrosion Research Center University of Louisiana at Lafayette) | Knierim, Kathleen (Corrosion Research Center University of Louisiana at Lafayette) | Patil, Vinayak B. (Corrosion Research Center University of Louisiana at Lafayette) | Hebert, Mr.Jared (Coastal Chemicals Inc.)
INTRODUCTION ABSTRACT A pitting model has been developed which provides an explanation of why acetates affect CO2 pitting corrosion. The pitting diffusion model is based on the diffusion of iron ions from the bottom to the top of the pit. To maintain electro-neutrality, negatively charged ions must migrate into the pit. For the pit to continue propagating, it must be more acidic at its bottom than at the top. The model has shown how acetates allow this to happen. The new model can be used to predict if CO2 pitting corrosion will occur provided parameters such as temperature, salt concentration, in-situ pH and acetate concentration are known. A method is presented which allow for the calculation of in-situ pH from laboratory information. The first published data on the presence of organic acids in oilfield waters appears to have been reported by Rogers (1917). There was no further mention of the effect of these acids until Menaul (1944) addressed the problem of corrosion of tubing in gas condensate wells where there appeared to be no appreciable difference in CO2 content. Some wells corroded extremely rapidly while others showed no appreciable amount of corrosion. He was able to identify a second corrosive agent, organic acids. In view of this problem, the NGAA Committee was formed in 1944 to study corrosion in gas condensate wells. Greco and Griffin (1946) found that when laboratory samples of oilfield water containing organic acids were heated in the laboratory to as much as 200 ºF, there was about a 1.0 pH unit drop in the reported laboratory pH. Hackerman and Shock (1947) observed that the presence of acetic acid resulted in severe pitting attack along the direction of flow. Locht (1949) was the first to describe an analytical procedure for the detection of individual organic acids in gas condensate wells. Shock and Subdury performed experiments which showed that the addition of acetic acid caused the corrosion of steel in a CO2 environment to increase by 45 %. There was a prolonged period without any work done in this area until Crolet and Bonis (1983) resurrected the topic by pointing out that acetates were contributing to the alkalinity of the water as well as increasing the CO2 corrosion rate. In their 1989 paper8, they make the classic statement that “there is no record of CO2 corrosion in a producing well in the absence of acetic acid”. Their explanation was that acetates confer a strong acid buffering power, thus preventing rapid neutralization due to the generation of bicarbonate. They noted that at a pH around 5.5 to 5.6 the amount of CO2 corrosion was slight. A similar observation was made by Carlson (1949) who described the upper pH limit of CO2 corrosion as 5.4. Alapati showed a plot of CO2 corrosion rate versus pH using field data and the result was that at a pH of 5.5 the corrosion rate became zero. Alapati also showed that for 18 Gulf Coast gas condensate wells.
- 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 A mathematical approach was taken in order to describe the pitting process in CO2 corrosion. The hypothesis established was based on a unidirectional pit model which involved nineteen species, one of them (Fe2) being diffused from the bottom of the pit. Using numerical methods, a prediction of corrosion rates in the pit, concentrations of the species in the pit and pH profile were determined. The average corrosion pitting rate from CO2 was found by calculating the corrosion rate at various pit depths. Sulfate reducing bacteria (SRB) on carbon steel has been studied by determining the role of bacteria in conjunction with localized CO2 corrosion. The influence of temperature, pH, sodium chloride, acetates and sulfates has been analyzed and modeled in a program that calculates CO2pitting corrosion rates including the reduction from sulfate to sulfide due to SRB. This bacteria metabolism produces acetate and hydrogen ions which increases the CO2 pitting corrosion rates. The increased corrosion rate from the bacteria is expressed as a percent enhancement above the CO2 corrosion model value. INTRODUCTION Pitting is a localized form of corrosion on a metal surface that results in relatively rapid penetration in small discrete areas. Pitting is more destructive than uniform corrosion, and it is unpredictable and difficult to detect and prevent. This type of corrosion depends on the metallurgy of the alloy, temperature, pressure, amount of carbon dioxide, pH and shape of the pit. Pits may be shallow, elliptical, deep, undercut or subsurface and may follow metallurgical features. Other factors include thickness of the metal, presence of fatty acids, and the chemical composition of the water. When a metal corrodes by pitting, the dissolved metal ions generate a positive charge in an environment with low pH. This generated positive ion is balanced, to maintain electro-neutrality, by negative charges in the form of anions migrating into the pit. Additionally, many species inside the pit are experiencing equilibrium with the various ions. This phenomenon will produce many reactions which can cause an increase or decrease in the concentration of hydrogen ions and hence an alteration in the pH value which will or will not allow propagation of the pit. Since the concentration of ions involved in the pit are difficult to establish experimentally, mechanistic models of pitting corrosion have been studied to predict the environment in the pit, which is related to the corrosion rate 1,2,3,4. The main purpose of the present study is to develop a new pitting model in CO2 corrosion, taking as a basis the unidirectional pitting model presented by Galvele5,6,7 . This model would describe the rate of pit propagation by the diffusion of Fe ions from the pit into the moving liquid film. Figure 1 shows the unidirectional pit used in this study. Once developed, the model can then be used to determine the effect of sulfate reducing bacteria inside the pit. PITTING MODEL The Corrosion Research Center of the University of Louisiana at Lafayette8,9 has developed a theoretical pitting rate model for CO2 corrosion.