Carbon dioxide systems are one of the most common environments in the oil field industry where corrosion occurs. Carbon dioxide forms a weak acid known as carbonic acid (H2CO3) in water, a relatively slow reaction. However, CO2 corrosion rates are greater than the effect of carbonic acid alone. Cathodic depolarization may occur, and other attack mechanisms may also be at work. The presence of salts is relatively unimportant.
Corrosion rates in a CO2 system can reach very high levels (thousands of mils per year), but it can be effectively inhibited. Velocity effects are very important in the CO2 system; turbulence is often a critical factor in pushing a sweet system into a corrosive regime. This is because it either prevents formation or removes a protective iron carbonate (siderite) scale.
The maximum concentration of dissolved CO2 in water is 800 ppm. When CO2 is present, the most common forms of corrosion include uniform corrosion, pitting corrosion, wormhole attack, galvanic ringworm corrosion, heat affected corrosion, mesa attack, raindrop corrosion, erosion corrosion, and corrosion fatigue. The presence of carbon dioxide usually means no H2 Embrittlement. CO2 corrosion products include iron carbonate (siderite, FeCO3), Iron oxide, and magnetite. Corrosion product colors may be green, tan, or brown to black.
where it found?
As stated before, CO2 corrosion is one of the most common environments where corrosion occurs, and exists almost everywhere.
Areas where CO2 corrosion is most common include flowing wells, gas condensate wells, areas where water condenses, tanks filled with CO2, saturated produced water and flowlines, which are generally corroded at a slower rate because of lower temperatures and pressures.
CO2 corrosion is enhanced in the presence of both oxygen and organic acids, which can act to dissolve iron carbonate scale and prevent further scaling.
Prevention / Mitigation
To reduce or prevent corrosion in an CO2 environment:
- Drilling – pH control with caustic soda
- Producing wells – corrosion inhibitors
- Flowlines – continuous corrosion inhibitor injection
Prediction of Corrosion
In sweet gas wells with a pH of 7 or less,
- CO2 partial pressure of 30 psi usually indicates corrosion.
- CO2 partial pressure of 7 – 30 psi may indicate corrosion.
- CO2 partial pressure of 7 psi is usually considered non-corrosive.
API literature states that steel equipment is susceptible to carbon dioxide corrosion when the partial pressure of carbon dioxide is greater than 7 psi. This partial pressure of carbon dioxide is calculated by multiplying the operating pressure by the mol % of carbon dioxide in the system and dividing by 100. For instance, in a well with 1000 psi pressure and 0.5 mol % carbon dioxide, the carbon dioxide partial pressure would be 1000 x 0.5 = 500 / 100 = 5 psi carbon dioxide.
The topography of carbon dioxide corrosion pits includes the following characteristics:
- sharp edges
- smooth sidewalls
- smooth bottoms
- pits tend to run into each other
The main corrosion by-product that indicates carbon dioxide corrosion is taking place is siderite (FeCO3). Magnetite (Fe3O4) and hematite (Fe2O3), both iron oxides, could indicate that carbon dioxide corrosion is occurring. The main mechanism occurring is indicated by the following equation:
2Fe + 2CO2 + O2 → 2FeCO3
Note that in the above equation, oxygen is required to form siderite. Another indication that carbon dioxide corrosion is occurring is the amount of carbonates present in the deposits. If the deposits contain over 3% carbonates, then most likely carbon dioxide is present in the system.
Carbon dioxide corrosion is usually controlled with the addition of a corrosion inhibitor to the system. A corrosion inhibitor effective in a carbon dioxide environment should be specified. Note that the selection of a particular corrosion inhibitor should be based on compatibility, cost, and other pertinent factors. Corrosion resistant alloys (CRAs) can also be added to help prevent carbon dioxide corrosion.