In-Line Inspection (ILI) of pipelines is quickly becoming the industry-preferred method of integrity assessment. As the technology has matured, new frontiers have begun to be exploited by this technique which has traditionally found its primary application in onshore transmission pipeline systems. The translation of the application of this technique to the offshore environment is not without its pitfalls, both technological and economic.
This paper will discuss the limitations of attempting to use commonly applied onshore logistical activities in an offshore environment and the impact of unexpected problems that became greatly magnified in this environment. It will detail how such pipeline systems present unique obstacles to be overcome by both the pipeline operator and the ILI contractor. It will describe not only the complex field logistics, but also unique data analysis considerations as well. This paper will enumerate the lessons learned ? most of them the hard way. Finally, it will offer several points for offshore pipeline operators to ponder as they consider applying ILI technology to pipeline systems which are reaching farther out into deep and, some day soon, ultradeep waters.
INTRODUCTION
Marathon Ashland Pipe Line LLC(1) operates a 12-inch pipeline for a partnership of several offshore operating companies in the Gulf of Mexico off the western shore of the Mississippi River delta.
This pipeline has its origin in the South Pass Area and terminates onshore Louisiana near Venice (Figure 1). It gathers and transports crude oil and natural gas condensate production from eight offshore fields. This pipeline is referred to as the South Pass West Delta (SPWD) 12 pipeline system.
The strategic positioning of this pipeline makes it an attractive option for transporting liquid production from deepwater prospects in the Gulf of Mexico. Since this pipeline will be soon approaching its design life, the pipeline owners were interested in assuring the mechanical integrity of the trunkline portion of the system in order to market with confidence its available capacity.
Between June and July 1999 this pipeline system, approximately 47 miles (75 km), was inspected using geometry and high resolution metal loss tools. The initial metal loss inspection was unsuccessful. A rerun of this tool was performed in February 2001.
