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ABSTRACT Glass cell experiments were conducted to investigate the mechanism and kinetics of mild steel corrosion in H2S environments which is accompanied by iron sulfide scale formation. By using the weight change method, the rates of corrosion and scale formation were found. It was also concluded that mackinawite is the predominant type of iron sulfide that formed on the steel surface under the test conditions studied, probably by a direct reaction of H2S with the underlying steel. Based on the experimental results, a mechanistic model of uniform H2S corrosion of mild steel is presented that is able to predict the rate of corrosion with time. In the model, the corrosion rate of mild steel in H2S corrosion is a function of H2S gas concentration, temperature, velocity, and the protectiveness of the mackinawite scale. The amount of scale retained on the steel surface depends on the scale formation rate as well as the scale damage rate. The scale formation may occur by corrosion and/or precipitation, while the scale damage can be by mechanical or chemical means. INTRODUCTION Internal CO2 corrosion of mild steel in the presence of hydrogen sulfide (H2S) represents a significant problem for the oil and gas industry. Surface scale formation is one of the important factors governing the corrosion rate. The scale growth depends primarily on the kinetics of the scale formation. As a part of a larger project focusing on the formation of both iron carbonate and iron sulfides in CO2 /H2S corrosion, the kinetics of iron carbonate has been quantified and reported in a recent publication. In contrast to relatively straightforward iron carbonate precipitation in pure CO2 corrosion, in an H2S environment, many types of iron sulfides may form such as amorphous ferrous sulfide, mackinawite, cubic ferrous sulfide, smythite, greigite, pyrrhotite, troilite, and pyrite, among which mackinawite is considered to form first on the steel surface by a direct surface reaction. The unknown mechanisms of H2S corrosion makes it difficult to quantify the kinetics of iron sulfide scale formation. Therefore, in this study, the mechanism of H2S corrosion as well as iron sulfide formation is investigated and a model of the overall process is proposed in this paper. EXPERIMENTAL PROCEDURE The experiments which served as a basis for the development of the model were already described in the previous publication. Here, only the most important features of the experimental program will be mentioned to facilitate following of the text below. The experiments were performed at atmospheric pressure in glass cells filled with a 1 wt.% NaCl aqueous solution continuously purged with a mixture N2 (>99.9 vol%) and H2S gases (H2S concentrations in the gas inlet: 0.0075 vol% to 10 vol%). The H2S concentrations in both the gas phase (in ppmw and Pa) and the liquid phase (in mol/l) under different test conditions are shown in Table 2. Rectangular and cylindrical specimens made from X65 pipeline steel were exposed for 1-24h at 25-80 ° C.
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- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (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)
ABSTRACT ABSTRACT A proposed method for Liquid Petroleum Pipeline Internal Corrosion Direct Assessment (LP-ICDA) has been developed that is consistent with the general principles of other Direct Assessment (DA) methods. The scope of LP-ICDA complements those of dry gas ICDA (DG-ICDA) and wet gas ICDA (WGICDA). LP-ICDA (as with other DA methods) is intended to serve as an integrity verification tool, playing the same role within pipeline integrity management as in-line inspection (ILI) and hydrotesting (either as a replacement or as a complement). The method relies on 1) identifying a mechanism for corrosion susceptibility, 2) detecting a property associated with this mechanism through an indirect measurement, 3) performing a direct observation of the pipe (e.g., by excavation), and 4) correcting for any discrepancies between the predictions and observations. The underlying basis of the proposed approach is simple; corrosion in liquid petroleum pipelines is most likely where water and/or solids accumulate. Secondary factors affecting the distribution of corrosion between locations of water and solids accumulation are also considered. INTRODUCTION Liquid product transmission pipelines are defined as pipelines that are fully packed with a liquid phase (i.e., no significant gas phase). Water content in crude oil is typically specified by "basic (or bottom) sediment and water" (BS&W) of less than 1% (sometimes 0.5 or 0.35%), and refined product or hydrocarbon condensate specifications are typically more stringent. Direct assessment methodology (DA) has been developed for the purpose of performing pipeline integrity verifications, especially for pipelines that are not able to accept inline-inspection (ILI) tools. DA development was initially driven by a need to meet pending changes to U.S. natural gas transmission pipeline regulations. DA also has applicability to the pipelines carrying other products. External corrosion DA (ECDA) and Stress corrosion cracking DA (SCCDA) have been developed for the buried pipelines. The prediction applicability of ECDA and SCCDA does not depend upon the product being transported, except that pressure fluctuations can differ between liquid and gas systems, and SCC susceptibility can be affected. The basis of DA is that 1) a mechanism for susceptibility is identified (i.e., preassessment), 2) a property associated with this mechanism is used as a basis for detecting susceptibility (indirect inspections), 3) direct observations are made to verify the correlation between the property and mechanism (direct examinations), and 4) corrections are made for any discrepancies (i.e., postassessment). Internal Corrosion Direct Assessment (ICDA) is a process that can be used to assess pipeline integrity, based on identifying areas along the pipeline where internal corrosion is most likely to exist. The process identifies the potential for internal corrosion caused by microorganisms, fluid with CO2, O2, H2S or other contaminants present in the carrying fluid. The ICDA methodology is a four-step process requiring integration of pre-assessment and indirect inspection data, with detailed examinations of the internal pipeline surface. A method to assess internal corrosion in normally dry natural gas systems has been developed and termed Dry Gas Internal Corrosion Direct Assessment (DG-ICDA).