Optimizing CAPEX and OPEX for High CO2 and H2S Field by Using Mechanistic Corrosion Modelling Approach

The gas contaminants especially CO2 and H2S from the well is a major threat to oil and gas production facilities and pipeline. Developing this type of reservoir cost enormous CAPEX and OPEX due the need for expensive materials or the need of continuous chemical injection. This paper outlines the opportunity of cost optimization for future field development and operational through mechanistic corrosion modelling approach. This method was embedded to an in-house corrosion prediction model that was first developed by collaboration with Ohio University in 2008 with capability to predict corrosion rate for partial pressure more than 20bar of CO2 and up to 1bar of H2S. The model validation was performed based on actual field production operated at 55°C and 22 bar of CO2 partial pressure followed the methodology as outlined in NACE paper C2012-0001449. Upon successful validation, the model has been deployed to assist an Operator of an offshore pipeline in Southeast Asia, operating at 97°C and 17 bar of CO2 partial pressure, to ascertain the risk due to CO2 corrosion and review the original pipeline design adequacy. Subsequently, the model has been utilized for an Operator of onshore facilities in Middle East to address specific issue encountered during the final stage of development for one of the wellpad in which the wells are expected to experience increase of H2S from 100ppm in original design to more than 1000ppm during actual production. This process changes raised a serious concern on the integrity of the materials as potential corrosion issue and the need for corrosion mitigation such as H2S Scavenger injection was not originally considered during early stage of engineering. The corrosion rate from the model has been validated against the intelligent pigging (IP) data and proven to be able to predict corrosion rate with +20% accuracy and more than 99% confidence level for CO2 partial pressure up to 25 bar with the presence of H2S. Based on deployment and utilization of the model, the high confidence in the model ability to accurately predict the corrosion rate will lead to potential CAPEX and OPEX optimization for the field development and during operational stage.

Mitigating CO2 Corrosion of Natural Gas Steel Pipelines by Thermal Spray Aluminum Coatings

Internal pipeline corrosion due to CO2 is a major challenge facing the oil and gas industry. To protect the pipelines and equipment from the ravages of CO2 corrosion, novel sacrificial coatings can be used. The objective of this study was to investigate the corrosion behavior of Al-based alloys as sacrificial coatings to protect pipelines in a CO2-saturated aqueous electrolyte (3.5 wt.% NaCl) at 4 bar CO2 partial pressure (3 barg) and 40 oC. The corrosion resistance of Al-based alloys and thermal spray coatings was evaluated in an electrochemical reaction autoclave using electrochemical methods (potentiodynamic polarization, linear polarization resistance, and electrochemical impedance spectroscopy). Post-corrosion surface characterization was performed by scanning electron microscopy equipped with energy dispersive X-ray spectroscopy. The obtained data show Al-based alloys demonstrated promising protection against CO2 corrosion with no breakaway degradation issues.

Pitting and CO2 corrosion behavior of oil and gas pipeline welds

A finite element (FE) model is presented in this work that is used to analyze the effect of pitting corrosion on the CO2 corrosion behavior of oil and gas pipeline welds. The FE model contains two parts, i. e., stress calculation of the welded joint using Abaqus software, and of the chemical reaction at the welded joint using COMSOL Multiphysics® software. The effect of transportation pressure, pit depth and welding material on the CO2 corrosion behavior of weld metal was investigated using the FE model. It turned out that the FE model is helpful to instruct the management and to assess the remaining service life prediction of pipelines in the oil and gas industry.

Galvanic Interactions between Fe Electrodes in CO<sub>2 Saturated Solutions with Different pH

Localized CO2 corrosion is a very common problem in the oil and gas industry. Severe damage of the surface is attributed to the formation, and breakdown, of protective iron carbonate (FeCO3) scales. When the corrosion layer is compromised, the difference between the open circuit potential of the FeCO3-covered and non-covered regions act as the driving force for a galvanic interaction. Depending on the area ratio of the anodic and cathodic areas, the surface could suffer severe localized damage. The present study was focused on the galvanic interactions between iron samples in solutions with different pH. CO2 saturated 1% NaCl solutions with bulk pH of between 6 and 8 and temperature ranging from 20°C and 80°C were studied. A split cell allowed for customization of different environments in each of the half cells, along with simultaneous monitoring of the galvanic current and driving force as indicated by the difference in open circuit potential. Corrosion product layers were characterized using scanning electron microscopy, energy-dispersive X-ray spectroscopy and X-ray photoelectron spectroscopy. The results indicated that the pH of the bulk solution plays a major role in the formation of protective FeCO3 scales. Fe exhibited passive-like behavior when immersed in a solution at 80°C with pH adjusted to 8. After reaching a passive-like behavior, Fe samples were cathodic when coupled to samples immersed in a solution with lower pH. The galvanic current decreased with increasing temperature and pH gradient.