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The major problems of corrosion in oil and gas production is particularly found in oil production materials as tubing and casing are more exposed to carbon dioxide (CO2) pressure environments in deep water environment.
Usually, oil field materials used for oil and gas production are manufactured in carbon steels as pipelines, casing and production...
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Context 1
... Figure 1 Corrosion fundamental mechanism attack ...................................................................... 13 Figure 2 : Carbon dioxide chemical mechanism with water. .......................................................... 15 Figure 3: Pressure and temperature diagram phase of carbon dioxide ......................................... 20 Figure 4: Carbon steel corrosion experimental process ................................................................. 22 Figure 5: Experimental vessels ..................................................................................................... 23 Figure 6: Carbon steel specimen experimental details (SEM and EDS) before exposure to Carbon dioxide pressure. (A): Polish Carbon steel at t=0h and (B): carbon steel spectrum before exposed to carbon dioxide partial pressure. ................................................................................................ 26 Figure 7: De Waad corrosion prediction model and modify model (Ossai, C. I. (2012)) ................. 29 Figure 8: Carbon dioxide migration through an abandon well. (Connell L., et. al (2012)). .............. 35 Figure 9: Effect of carbon dioxide injection. (RUDYK S., et. al. (2009). ......................................... 36 Figure 10: Corrosion and cement bond log ................................................................................... 41 Figure 11: Wellbore corrosion logging wire-line ............................................................................. 42 Figure 12: Ultrasonic tools using pipeline engineering (Ultrasonic testing [online].) ....................... 43 Figure 13: Downhole corrosion log tools (Arbuzov, 2012) ............................................................. 44 Figure 14: MDI long sensor log (Arbuzov, 2012) ........................................................................... 45 Figure 15: MDI tubing corrosion log (Arbuzov, 2012) .................................................................... 45 Figure 16: Carbon dioxide experimental process (AutoCAD 2D draft) ........................................... ...
Context 2
... damage in oil field; in fact one of many solutions to carry out corrosion attack is carbon dioxide partial pressure and pH function with exposure time. Since carbon dioxide (CO 2 ) variations from gaseous phase to liquid phase and to reach a supercritical phase (Figure 3) with increasing a partial pressure, carbon dioxide will change it phase by interactions with de- ionised water or pure water, carbon dioxide dissolving through aqueous solution will not shadow Henry’s rule in carbon dioxide multiple phase (liquid, gas and supercritical) conditions, this carbon dioxide phase changing affect considerably the water chemistry. From the time when the solubility of de- ionised water mixed with carbon dioxide (CO 2 ) is correlated as aqueous solution corrosion formation to attack carbon steel , the solubility of carbon dioxide (CO 2 ) and de- ionised water will exchange or associate they chemical elements as ions or electrons to be a key matter in carbon steel ...
Similar publications
Deep water oil production tubing materials are exposed to high carbon dioxide (CO2) pressure and temperature conditions that can affect the corrosion performance of such materials. The present study evaluated the corrosion behavior of carbon steel exposed to supercritical CO2/oil/brine mixtures at different water cuts (0, 30, 50, 70, and 100%), CO2...
Citations
... Corrosion caused by carbon dioxide (CO 2 ) is a serious issue in oil and gas production [16]. It is the most effective corrosion that is noticed on pulled tubing string in Rumaila oil field as shown in Fig. 2. The presence of carbon dioxide in the produced fluids of the oil wells can lead to the sweet corrosion. ...
To diagnose the corrosion reasons in the most suffered oil wells, this study gathered an integrated field database for the oil wells operated with electrical submersible pumps (ESP) and had significant corrosion problems. In this database, 255 workover operations with rig conducted in super giant oilfield, located southern of Iraq, were evaluated and detailed for the production status of the target wells prior to the workover process and after the workover operation during the period (2015–2017). The gathered database helped to address the main causes of the corrosion in the workover wells and clearly explained the effect of corrosion on the failure of ESP wells in the field. The statistical analysis for the gathered database showed there is a strong correlation between the corrosion rate and the increasing water cut from the Main Pay wells. In addition, high-rate oil wells are observed to have the quickest corrosion failures. However, the plots of the statistic corrosion map do not seem to indicate a specific area or reservoir section but rather a field wide challenge. Interestingly, the CO2 corrosion due to the turbulent flow regime right above the ESP was the main reason for the failure of ESP wells caused by the induced holes in the tubing string. This study found that such corrosion issues can be mitigated before they occur in more producing oil wells by installing 13% Chrome metallurgy (CR-L80) tubing string in all Main Pay wells instead of using L80 alloy steel tubing string. Thus, such practice will reduce the cost, time and number of workover operations. Based on the scale of this constructed field database, this investigation also showed that the extra cost due to purchasing the 13% CR-L80 tubing would be offset if the tubing failure is mitigated in only 2 ESP wells.
Graphical Abstract
ESP corrosion damage during (2015–2017) reported by the inspection process of pulled tubings
... The quantity of oxygen released by wetland plants may be measured by connecting root oxygen release to the wetland surface area based on relevant field data if the number of active roots, their active lengths, and the radial oxygen loss (ROL) are known. [8][9][10][11] 566 conditioners and interface inhibitors [12]. The corrosion rate of a mineral M subjected to a corrosive medium (electrolyte) is depending on the electrochemical reaction kinetics. ...
This article proposes the effects of temperature on corrosion inhibition of hydrochloric acid (HCl) solution for low carbon steel with a weight loss process. The corrosion process was tested at temperatures of 25, 35, 45, 55, and 65oC, the inhibitor bulrush was used with concentrations of 0, 0.2, and 0.5 g/L, and hydrochloric acid was used as a solution. The experiment suggests that increasing inhibitor concentration leads to a decrease in corrosion rate in HCl solution due to diffusivity and oxygen solubility. Also, corrosion rate increases as temperature increment and bulrush inhibition efficiency increase with increasing inhibitor concentration up to a maximum of 97.73% at 25 oC and 0.5 g/L concentration. These results revealed that bulrush inhibitor is the best result due to creating a thicker and stronger adjacent layer on the metal surface to prevent dissolved oxygen to reach the metal surface. In the same matter, limited current density increased with increasing temperature and decrease with increasing inhibitor concentration.
