Corrosion control is required when the calculated general corrosion rate cannot be accommodated by reasonable corrosion allowances for carbon steel, as listed in the attached table. For example, if the predicted corrosion rate is 10 mils per year (mpy) for a heat exchanger shell with a 20 year design life, a corrosion allowance of 0.20 inches would be required. This result is considered unreasonable. In this case, corrosion would have to be controlled by at least one of the following methods:
• Alter the environment, such as by removing the water from the production stream.
• Use cathodic protection.
• Deaerate water systems to less than 20 ppb oxygen. (The production environment from the well is usually oxygen free.)
• Use chemicals by batch or continuous treatment to inhibit corrosion of the carbon steel.
• Consider thin-filmed coatings, thick-filmed coatings such as glass-flake fiberglass linings, or laminate fiberglass-reinforced-plastic (FRP) linings
• Consider solid-wall nonmetallic alternatives such as pipe made of PVC, HDPE, or FRP. These are generally used for water systems; however, FRP and HDPE have instances of being used for low-pressure production in flowlines.
• Clad the equipment internally with CRAs by weld overlay, strip cladding, or other techniques.
• Substitute solid-wall CRAs. When using solid-wall CRAs, consider the risk of external chloride stress-corrosion cracking in offshore or coastal onshore plants.
Corrosion Inhibition Chemicals:
The most commonly used methods for corrosion control are chemical inhibition complemented with thin-filmed coatings. Chemical inhibition is a reliable alternative to CRAs, particularly for pipelines. However, chemical inhibitors have significant limitations. Most inhibitors are limited by temperature and mixture velocities. Consult the corrosion inhibitor chemical supplier to ascertain the allowable conditions for temperature and mix velocities. Extreme conditions of temperature and velocity require planning and evaluation on a case-to-case basis. Sometimes inhibitors are not a viable control method because offshore facilities do not have adequate space for storage and injection equipment.
In some cases remote and unmanned sites may make it impractical to use corrosion inhibition chemicals.
When use of inhibitors is not justified, or practical, consider Corrosion-Resistant Alloys (CRAs).
It is important to note that the type of inhibitor, inhibitor dosage, and inhibitor distribution are a function of temperature, velocity, two-phase flow regime, and shear stresses of the production flow.
Equipment Design Life: Basis of Selecting CRAs over Carbon Steel:
The attachment lists typical design lives and corrosion allowances for carbon steel and CRAs as they apply to specific equipment. A corrosion allowance is defined as excess material not required for the design thickness according to the appropriate design code. The engineer is responsible for choosing the correct corrosion allowance. Design codes do not set corrosion allowances.
Design life for surface facilities is set by inspection capabilities balanced with operating constraints such as the cost of opening equipment for inspection and the feasibility of replacing equipment at the plant site. Therefore, offshore facilities will have more conservative design lives than onshore facilities. Unlike surface facilities, completion equipment and production tubing have no corrosion allowances. Therefore, corrosion control is critical. If predicted corrosion rates are unacceptable for the design life of the carbon steel completion, then CRAs, nonmetallic materials, coatings, or chemicals are required.
I hope that process engineers in the upstream oil and gas industry who want to have some idea of corrosion will find this blog entry useful. Looking forward to comments from the members of "Cheresources" community