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Collaborating Authors
CORROSION 2014
The Effect of Buffering Capacity on HIC Behavior for FFP Evaluation
Mizuno, Daisuke (JFE Steel Corporation) | Ishikawa, Nobuyuki (JFE Steel Corporation) | Kobayashi, Kenji (Nippon Steel & Sumitomo Metal Corporation) | Hara, Takuya (Nippon Steel & Sumitomo Metal Corporation) | Tada, Eiji (Nippon Steel & Sumitomo Metal Corporation)
ABSTRACT Hydrogen Induced Cracking (HIC) is a major issue of line pipe steels exposed to sour environments. In general, 5.0 wt% NaCl and 0.5 wt% CH3COOH solution with 0.1 MPa H2S specified as solution A in NACE TM0284 is used to evaluate the resistance of steel plates and pipe products. However, in many cases, the test condition is too severe compared to the actual field conditions. Therefore, Fit-For-Purpose () evaluation method has been the subject of considerable investigations in recent years. The Iron and Steel Institute of Japan (ISIJ)(1) high-strength line pipe () Research Committee proposed the buffer solution which contained high concentration of acetic acid and sodium acetate for test including mildly sour conditions. In a previous study, it was shown that the newly proposed test solution had a strong pH buffering capacity in the range of pH 3.5 to 5.5 under 0.1 MPa H2S. In this paper, the influence of pH buffering capacity of the solution on behavior was investigated and crack area ratio was strongly affected by pH shift during test. In addition, pH buffering capacity of the solution under lower H2S partial pressure was evaluated for evaluations. The test solution which contained high concentration of acetic acid and sodium acetate showed an excellent pH buffering capacity compared with the conventional test solution.
- Asia > Japan (0.49)
- North America > Canada > Alberta (0.28)
- North America > United States > Texas > Harris County > Houston (0.17)
ABSTRACT Degradation of aged power transmission systems have become a serious problem in Japan. In the case of a transmission tower, inner corrosion of the steel pipe beam is one of the issues because internal corrosion assessment based on the external appearance of the pipe is difficult. In order to utilize practical inspection techniques, characterization of the corrosion properties of the pipe, especially of the internal surface, is required. In this study, several atmospheric corrosion () sensors were arranged at a regular interval inside steel pipes which were set up at a coastal testing field and the time dependence and corrosion rate distribution of the inner surface of the pipes from the end to the center were evaluated. Based on the study it was concluded that the corrosion behavior of the inner section of the steel pipe strongly depends on climatic conditions such as temperature, dew point, relative humidity, rainfall and wind direction. The corrosion rate tends to become less from the end to the center inside the steel pipe. The corrosion information acquired from sensors showed good agreement with the corrosion condition of the steel pipe sample, which indicates that the method used in this study is effective for monitoring the internal corrosion status of steel pipes.
- Asia > Japan (0.68)
- North America > United States > Texas (0.21)
- Materials > Metals & Mining > Steel (1.00)
- Energy > Power Industry (1.00)
ABSTRACT Phosphonate scale inhibitors (SIs) applied in downhole squeeze applications may be retained in the near-well formation through adsorption and/or precipitation mechanisms. In this paper, we focus on the properties of precipitated "mixed" calcium and magnesium phosphonate complexes formed by nine common phosphonate species. By "mixed", we mean anionic SI bound to both calcium and magnesium divalent cations, i.e. the complex SI_Can1_Mgn2 is formed where n1 and n2 are the stoichiometric coefficients for Ca and Mg, respectively. The stoichiometry (n1 and n2 or the Ca/P and Mg/P molar ratios) in various precipitates is established experimentally and the effect of solution pH on the molar ratios of Ca/P and Mg/P in the precipitate is determined. Static precipitation tests were carried out varying the amounts of Ca and Mg present in the system at test temperatures ranging from 20°C to 95°:C, at a fixed [SI] = 2,000ppm. The solution molar ratio of Mg/Ca was varied but the ionic strength of each test solution was kept constant. In addition, tests were also carried out with (i) only Ca and SI present, and (ii) only Mg2+ and SI present. The molar ratios of Ca2+/P and Mg2+/P in the solid precipitates were determined by assaying for Ca2+, Mg2+ and P in the supernatant liquid under each test condition by ICP spectroscopy (Cao, Mgo and Po are known, but they are also measured experimentally). We show experimentally that the molar ratios of precipitated Ca/P and Mg/P (or Ca/SI and Mg/SI) depends on the nature of the SI (i.e. how many M2+ binding sites there are per molecule); solution pH; the relative magnitude of the SI binding constants to Ca and Mg at the test pH; and the solution molar ratio of Mg2+/Ca2+; for all phosphonates tested. It is found that, as pH increases, the combined molar ratio of Ca/P+Mg/P, i.e. n1+n2 in the SI_Can1_Mgn2 complex increases up to a theoretical maximum, depending on the chemical structure of the phosphonate. Our findings are consistent with proposed phosphonate SI-Ca-complex structures which were presented and discussed in two SPE technical papers (SPE 155114, 2012 and SPE 164051, 2013).
- Asia > Middle East (0.28)
- North America > United States > Texas > Harris County > Houston (0.17)
- Materials > Chemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Constituents > Salts/Sulphates/Scales (0.72)
Minimizing Grounding Resistance of Cathodic Protection Anode Bed with Finite Element Method
Wuxi, Bi (PetroChina Pipeline R&D Center) | Chengwei, Xu (PetroChina Pipeline R&D Center) | Zhiyuan, Xue (PetroChina Pipeline R&D Center) | Hongyuan, Chen (PetroChina Pipeline R&D Center) | lingli, Liu (PetroChina Pipeline R&D Center)
Cathodic protection (CP) anode bed grounding resistance calculating formulae, given by CP standards, are reviewed firstly. Underground assumptions and limitations of these grounding calculating formulae are analyzed, which means formula method may encounter problems when designing anode beds in high soil resistivity area. Based on finite element analysis (FEA) method, a new grounding resistance calculation method is suggested, which is can be treated as more suitable and flexible for anode bed grounding resistance calculation in high soil resistivity condition. The main steps of FEA method, geometric model building, meshing, boundary condition and solver setting, and grounding resistance calculating according to Ohmic law, are clearly presented. In order to introduce the FEA method in detail, a realistic anode bed design program for Northwestern China area, where soil resistivity is always very high, is demonstrated. Based field soil resistivity survey data by Wenner 4‐pin method, the candidate anode bed site, named Station A, is regarded as optimal site, and Barnes' soil layer analysis method is used to predict soil resistivity distribution in depth direction. Both formula method and FEA method are used to calculate grounding resistance. The following comparison results show that formulae from COR‐GS‐023, GB21448‐2008, РД 153‐39.4‐039‐99
- Asia > China (0.68)
- Asia > Russia (0.47)
- North America > United States > Texas (0.18)
- Energy > Oil & Gas (1.00)
- Government > Regional Government > Asia Government (0.68)
The Laboratory Evaluation of Seawater Injection on H2S Production, Incorporating Several Different Treatment Strategies, Utilizing Fixed Film Upflow Bioreactors
Hoffmann, Heike (Intertek Production & Integrity Assurance) | Harris, Kevin (Intertek Production & Integrity Assurance) | Palmer, Jim (Intertek Production & Integrity Assurance)
ABSTRACT Reservoir Souring is the unplanned production of increased concentrations of hydrogen sulfide (H2S) in wellstream fluids from production wells that are subjected to water-injection. The consequences of souring with respect to safety, corrosion and environmental risk can be significant. This is typically associated with the activity of a specialized group, the Sulfate-reducing bacteria (). However, in recent years, various other micro-organisms are believed to be involved in souring, e.g. Sulfate reducing archaea (). In this study, fixed film up flow bioreactors () were utilized to assess the potential for H2S production or changes in such H2S production, when seawater is injected into a North Sea oil reservoir. The study has demonstrated how changes in fundamental parameters (e.g. bacterial nutrients, shut-in periods) can impact sulfide production and alter the microbial communities. The were soured to create a ‘worst case’ scenario and different nutrient additions or remediation treatments were applied to represent either near injection wellbore or deep field conditions. Typical oil field practice is to measure H2S in the gas phase. Partition modelling of H2S between water, oil and gas phase was applied to the measured sulfide data to give a real-world indication of the effect of H2S in gas when resuming production following a shut-in. The following parameters were measured during the testing period: sulfide generation, volatile fatty acid organic carbon sources (), iron, nitrate and nitrite concentrations. The microbiology of the system was evaluated both by traditional culture techniques and molecular methods, such as fluorescence in situ hybridization (FISH) analysis and other -based analysis. Results indicate that when sulfide generation had reached 1.5 mM, and the nutrient source was changed, almost complete cessation of sulfide generation resulted for a period of 7 days. Whereas, following shut-in period, sulfide generation recommenced after re-starting the flow and reached a concentration of 4.4 mM immediately and rose even higher to 5.0 mM over the first days of flow. However, sulfide concentrations returned to 2.0 mM again within 7 days after restart. However, the changes in the microbial community were found to be somewhat selective to certain SRB families. The various effects of the different treatments and conditional changes are discussed further in this paper.
- Europe > United Kingdom (0.89)
- North America > Canada > Alberta > Woodlands County (0.24)
- North America > United States > Texas > Harris County > Houston (0.16)
- Materials > Chemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Constituents > Bacteria (0.35)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.34)
A Mechanistic Erosion-Corrosion Model for Predicting Iron Carbonate (FeCO3) Scale Thickness in a CO2 Environment with Sand
Al-Aithan, G.H. (Saudi Aramco) | Al-Mutahar, F.M. (Saudi Aramco) | Shadley, J.R. (The University of Tulsa) | Shirazi, S.A. (The University of Tulsa) | Rybicki, E.F. (The University of Tulsa) | Roberts, K.P. (The University of Tulsa)
ABSTRACT CO2 (sweet) corrosion is one of the most dominant mechanisms of destruction of carbon steel equipment and piping used by the oil and gas industry. The presence of sand can accelerate the damage significantly. The combined effect of sand erosion and CO2 corrosion on carbon steel tubing and piping can greatly influence material selection for the design and affect operation of oil and gas production facilities. However, for some operational and environmental conditions, FeCO3 scale that is formed as a result of CO2 corrosion can provide some protection against the erosion-corrosion environment. Many investigators have conducted research to investigate the conditions for which iron carbonate scale forms and provides protection, but only a few have examined erosivity of FeCO3 scale. The erosion resistance of FeCO3 scale to solid particle erosion (erosivity) has been characterized in the current work under various environmental conditions in submerged, direct impingement flow loop experiments. A mechanistic model has been developed that includes the competition between the growth of FeCO3 scale through CO2 corrosion and the removal of scale by sand erosion. The model then predicts the corrosion rate for scale-forming conditions, when sand is produced. The effects of sand concentration, solution chemistry, temperature, and flow velocities on erosion-corrosion rates have been examined. A computer program has been developed, based on the mechanistic model, to predict erosion-corrosion rates.
- Asia > Middle East > Saudi Arabia (0.46)
- North America > United States > Texas > Harris County > Houston (0.17)
ABSTRACT Seawater injection into oil reservoirs for secondary oil recovery is frequently accompanied by souring (increased sulfide concentrations). Production of hydrogen sulfide causes various problems, such as microbiologically influenced corrosion (), deterioration of crude oil. Sulfate-reducing bacteria () are considered to be major players in souring. Volatile fatty acids (s) in oil field water are assumed to be produced by microbial degradation of crude oil. The objective of this research is to investigate mechanisms of souring from the view of production by the crude oil biodegradation. A microbial consortium collected from oil-water separator was suspended to seawater. Crude oil or liquid n-alkane mixture was added to the culture medium as sole carbon source. Anaerobic incubation was conducted for 190 days. Physicochemical analysis showed that preferable toluene degradation and sulfate reduction occurred concomitantly in crude oil amended condition. Sulfide concentration was much lower in alkane mixture amended condition than that of crude oil amended condition. These observations suggest that are related to toluene activation and consumption steps in crude oil degradation. Therefore, the electron donors for were not only , but a lot of crude oil components, especially toluene. Alkanes were also degraded by microorganisms, but did not so contribute to reservoir souring.
- Asia > Japan (0.95)
- North America > United States > Texas (0.19)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
A finite element model was developed to simulate distribution of local potential inside the defect. Results demonstrated that there is a non-uniform potential distribution at corrosion defects. The CP is shielded, at least partially, at the defect, especially at its bottom. This effect is enhanced with increasing depth and decreasing width of the defect. Empirical equations are derived to enable calculation of CP effectiveness at corrosion defects, providing industry recommendations for accurate assessment of further corrosion allowance and remaining life of pipelines in the field. Key words: Pipelines; Corrosion defects; Cathodic protection; Numerical assessment INTRODUCTION Corrosion is one of the primary mechanisms affecting negatively the safety and reliability of pipelines. Generally, corrosion can result in several types of defect on pipe surface, such as macroscopic holes due to general corrosion occurring over a large area, corrosion pits due to localized corrosion, and cracks generated by stress corrosion cracking (SCC).
ABSTRACT The wet CO2 corrosion is a complex process, especially when crude oil is contained in the corrosion system. In this paper, the corrosion behaviors of 3Cr alloy steel, L245 and 16Mn steel in oil-water mixture emulsion with 10%, 30%, 80% water cut under various temperature in a dynamic condition were investigated, respectively. The corrosion product scale was characterized by SEM and EDS. The results demonstrate that 3Cr steel exhibited the best corrosion resistance. At 10% and 30% water cut, the corrosion scales of the three steels were thin and compact, and dominated by FeCO3. At 80% water cut, a Cr-rich layer formed on surface of 3Cr steel, and the scale of L245 steel was compact internal but porous external, while the scale of 16Mn steel was compact but cracked and spalled. The corrosion rate of 3Cr steel decreased with increasing temperature at 80% water cut, but the corrosion rate of 16Mn steel increased sharply with increasing temperature due to the corrosion scale spalled. The corrosion rate of L245 steel exhibited a maximum value at 60 °C. Combined the morphologies of scales and the corrosion rate, it can be found that the corrosion rates of three steels increased obviously when the solution changed from water-in-oil to oil-in-water, but the Cr element caused a reduction of corrosion rate at high temperature and high water cut by forming Cr-containing layer. However, pitting corrosion formed under the thin and cracked Cr-containing layer.
ABSTRACT For a given production system, the corrosion mitigation philosophy is usually established based on the fluid properties and the operating parameters pre-identified within the Basis of Design (BOD). Information in the BOD comes from reservoir simulation, process/flow modeling, and thermodynamic/ compositional fluid analyses. These data have limited accuracy and a wide variability throughout the field life. Very often and due to capital expenditure (CapEx) constraints, most of production facilities primarily utilize carbon steel lines with corrosion mitigation provided by injection of chemical inhibitors. When using carbon steel and inhibition, a successful operation requires active corrosion monitoring to keep tabs on effectiveness of the chemical inhibition program. The monitoring program is a key to proactively identify new corrosion mechanisms surfacing during the field operation. Due to the wide variety of operating conditions, it is not practical to run laboratory corrosion tests simulating every production scenario. Most of the corrosion predictions rely heavily on the laboratory test results; however, the tests have limitations and may not precisely cover all of the corrosion mechanisms in predicting field performance. Depending on new mechanisms identified by the corrosion monitoring program, corrective actions are usually taken. These actions may include additional chemical treatments and mechanical systems such as pigging to bring the corrosion under control. This paper discusses some of the interesting corrosion mechanisms that have emerged in production systems due to changes in operating conditions during field operations. Corrosion monitoring data with fluid analyses, flow modeling, and additional laboratory testing have been effectively used to understand the corrosion mechanism and develop solutions for control. This work focuses on internal corrosion control of carbon steel in production and transportation lines with single or multiphase flow.
- 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)