ABSTRACT
Oil and gas transmission pipelines susceptible to corrosion are regulated by governing authorities all over the world. Cathodic Protection (CP) is the most common technique used to protect buried pipelines. When pipelines are installed inside casing pipe (casing) beneath roadways, railroads and other locations, the CP is ineffective for the cased section of carrier pipe. Furthermore, when the end seals on the casing are compromised, the corrosion threat is increased on the cased section of carrier pipe either due to metallic short or due to electrolytic coupling between the carrier pipe and casing. Pipeline operators in U.S. are mandated to comply with 49 CFR Part 192, Subpart O, to protect the cased carrier pipe from corrosion in High Consequence Areas (HCAs). One common approach used by pipeline operators is to fill the annulus space between casing and carrier pipe with a dielectric fill such as wax. It is assumed that wax fill process pushes out contaminated water, leaving annulus with the wax, however this is not always possible. During the wax fill process, contaminated water gets trapped in air pockets and around spacers, consequently increasing corrosion risk on the carrier pipe. Existing indirect assessment techniques, for pipeline integrity monitoring, cannot be applied to the wax filled casings due to shielding effects. NACE standard SP0200 recognizes multiphase vapor corrosion inhibitors as one of the viable options for corrosion mitigation of carrier pipes in the casing annulus space. Vapor Corrosion Inhibitors (VCIs) are water-based gel-like solutions that are injected in the casing annulus space. This paper explores effect of VCI gels in diverting the CP current to the holidays on the carrier pipe inside a casing and VCIs effect on indirect assessment techniques used for pipeline integrity of cased pipelines.
INTRODUCTION
Oil and gas transmission pipelines susceptible to corrosion are regulated to protect the environment and ensure public safety. Cathodic Protection (CP) is the most common technique used to mitigate corrosion and is one of the regulatory requirements in the United States. When pipelines are installed beneath roadways, railroads and other locations, a larger pipe is used to encase the main pipe, i.e., carrier pipe. This arrangement is generally referred as casing. The two pipes in a casing are separated with airgap in-between and end seals are installed to prevent water/soil ingress into the annulus space. When the end seals on the casing are compromised, the threat of corrosion is increased on the cased section of carrier pipe due to ingress of contaminants; CP is ineffective for the cased section of carrier pipe either due to metallic short or due to electrolytic coupling between the carrier pipe and casing. Pipeline operators in the US are mandated to comply with 49 CFR Part 192, Subpart O, to protect the cased carrier pipe from corrosion in High Consequence Areas (HCAs). Specifically, the operators are required to assess the integrity of the carrier pipe using either recommended methods such as pressure testing, direct assessments, and inline inspection or a method acceptable to either state or federal regulators. Complying with the integrity assessment requirement inside a casing has proven challenging for operators, especially oil and gas distribution system operators that operate lines classified as transmission pipelines. In many cases, transmission pipelines were not designed to be “piggable.” Pressure testing is generally not preferred because it disrupts service and introduces water. Direct assessment is problematic because the casing shields many of the indirect inspection techniques used to identify direct examination locations, and it is difficult to expose the carrier pipe for direct examination without excavating and removing the casing pipe.
