Recent years have seen advances in controlling external corrosion for buried pipelines. Specialized equipment and methods for assessing cathodic protection effectiveness and AC corrosion threats, state-of-the art corrosion sensing equipment, remote monitoring dataloggers, and advanced modeling techniques offer operators technologically advanced means and methods for managing external corrosion risks. While proof of compliance continues to rely on long-established field tests and monitoring cycles, there are opportunities to improve external corrosion management programs to incorporate advanced technologies and methods. This paper presents a case study demonstrating the Enbridge Integrated External Corrosion Management (IECM) methodology for a 12-inch, 85-mile-long crude oil pipeline located in North America. Pipeline construction, external corrosion history, modeling, field validation assessment, and resulting IECM protocols are presented and discussed.
The Enbridge External Corrosion Prevention team (ECP) is developing an Integrated External Corrosion Management (IECM) process by which management of external corrosion control systems can be optimized while maintaining asset integrity and safety. IECM is intended to provide a methodology by which operators can move from a traditional reactive approach to a state-of-the-art proactive strategy commensurate with industry expertise and technology. Here we discuss a case study intended to demonstrate and assess the outcomes of IECM. The subject is a 12-inch diameter crude oil pipeline located in North America. Results of the process reveal opportunities for improvement and efficiencies in operation and maintenance (O&M).
The IECM procedure has been described in detail elsewhere and begins with development of a mechanistic model1. To obtain sufficient accuracy, data reflecting pipeline construction, tie-in points, bond points, anode bed locations, rectifier drain point locations, and environmental factors must be incorporated into the model. Some of those key aspects are discussed as follows:
The pipeline is 12 inches in diameter, approximately 85 miles in length, and consists of 3 physically distinct sections owed to phased construction. Physical characteristics of the pipeline construction are shown in Figures 1 through 3 below. The pipeline varies in age from 11 years (MP 28 through 40) to 60 years (MP 40 to end) and has wall thickness ranging from 0.22 to 0.36 inches. The pipeline is coated with either coal tar epoxy (CTE), fusion bonded epoxy (FBE), or two-layer polyethylene (2LPE) for most of its length.
