Corrosion Control in the Oil and Gas Industry Using Nodal Analysis and Two-Phase Flow Modeling Techniques
- Carlos A. Palacios (Corpoven S.A.) | Valoy Chaudary (Universidad Central de Venezuela)
- Document ID
- Society of Petroleum Engineers
- SPE Latin America/Caribbean Petroleum Engineering Conference, 23-26 April, Port-of-Spain, Trinidad
- Publication Date
- Document Type
- Conference Paper
- 1996. Society of Petroleum Engineers
- 5.2 Fluid Characterization, 4.1.2 Separation and Treating, 4.2.3 Materials and Corrosion, 4.3.4 Scale, 4.5 Offshore Facilities and Subsea Systems, 4.1.4 Gas Processing, 2.4.3 Sand/Solids Control, 3.1 Artificial Lift Systems, 5.4 Enhanced Recovery, 4.2 Pipelines, Flowlines and Risers, 5.2.1 Phase Behavior and PVT Measurements, 5.3.2 Multiphase Flow, 4.1.5 Processing Equipment, 5.4.2 Gas Injection Methods, 4.1.1 Process Simulation, 3 Production and Well Operations, 5.2.2 Fluid Modeling, Equations of State
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Corrosion Control in the Oil and Gas Industry Using Nodal Analysis and Two-Phase Flow Modeling Techniques.
Characterization of corrosion in the oil and gas industry is becoming of increasing importance for safety reasons as well as for the conservation of the production facilities; therefore preventing down time and damage to the environment. This article presents the methodology used by our company to characterize the corrosion behavior of the whole production facilities, taking into consideration the hydrodynamic and thermodynamic conditions of the produced fluids (flow velocities, flow pattern. liquid holdup, pressure, temperature, etc.) as they flow from the reservoir through the surface installations (flowlines, gas/oil gathering and transmission lines, gas processing plants, artificial lift systems, etc.). The methodology uses Nodal System Analysis (NSA) and Two-Phase modeling techniques to: 1) optimize the entire production system to obtain the most efficient objective flow rate taking into consideration the corrosive/erosive nature of the produced fluid and 2) characterize the corrosive nature of the produced fluid as they flow through the above mentioned installations. The NSA and Two-phase modeling was performed using commercially available simulators and CO2 corrosion rates were determined using well known published correlations. For H2S corrosion, NACE MR0175 criteria is applied. The application of this methodology has allowed for corrosion control strategies, protection and monitoring criteria, inhibitor optimization and to increase the effectiveness of already existing corrosion control systems.
Velocity enhanced corrosion problems in oil and gas production equipment are common. These often occur when produced fluids are accompanied by carbon dioxide (sweet corrosion) and/or hydrogen sulfide (sour corrosion). In recent years the presence of carbon dioxide in the produced fluids is encountered more frequently due to the use of enhanced oil recovery techniques involving CO2 injection into reservoirs, due to the occurrence of sweet/sour gas production from deeper wells, and increased exploitation of heavy crudes with higher H2S and CO2 content. The effect of flow velocities on corrosion are more severe and more frequently encountered in multiphase flows and in many cases corrosion rates depend on the flow patterns. These are enhanced in the presence of sand inducing the phenomenon called erosion/corrosion.
Carbon dioxide dissolves in the presence of a water phase forming a weak acid (carbonic acid) which ionizes, thus reducing the pH and corroding carbon steel pipes. As the carbon steel corrodes, it forms a corrosion product scale (ferrous carbonate, FeCO3) which provides a degree of protection of the steel from further corrosion. The protectiveness of the scale depends on environmental factors and the characteristics of the steel. The environmental factors are those that define the medium in which the steel is corroding such as temperature, CO2 partial pressure, solution chemistry, fluid velocity, single-phase or multi-phase flows, flow pattern, pipe geometry, solution pH, and the ratio CO2/H2S. Steel characteristics include chemical composition and heat treatment, which determines the microstructure of the steel. As the partial pressure of CO2 increases, the pH decreases, thus making the environment more corrosive. Temperature directly influences the solubility of the FeCO3 scale; as it increases, corrosion rate decreases because of the formation of a more tenacious scale. P. 501
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