The challenges of monitoring and maintaining pipeline integrity become even more daunting when the pipeline is in a hostile environment.
The difficulties of monitoring, assessing, inspecting, and remediating pipeline integrity are exacerbated when the pipeline is offshore-especially in deep waters-or in arctic conditions.
Offshore concerns
The catastrophic damage inflicted upon the Gulf of Mexico pipeline infrastructure by Hurricanes Katrina and Rita in 2005 is a grim reminder to industry of the special difficulties involved in maintaining pipeline integrity offshore.
Zach Barrett, program development senior engineer with the US Pipeline & Hazardous Materials Safety Administration, notes that while “the industry is up to the challenge, conducting assessments and making associated repairs in offshore environments have a component of increased complexity.
“Obtaining space for launchers and receivers may be difficult to manage. Branch lines connecting to the main trunk line could cause additional difficulties for inline inspection.
“This, coupled with the recent and potential for future hurricanes in the gulf, results in additional challenges for effecting repairs and scheduling assessments.”
At the core of those challenges is a better understanding of the environmental loads on offshore pipelines and incorporating that knowledge in their design and construction, according to Neal Prescott, director, subsea/deepwater technology for Fluor Corp.’s Upstream SBL, Energy & Chemicals Group, based in Sugar Land, Tex.
“Recent storm damage in the Gulf of Mexico points to the acceptance of higher loads than have been anticipated or used in the past,” he says.
Even with that challenge ahead, pipeline operators already have been struggling to find ways to extend asset life with an aging offshore pipeline infrastructure, notes Steve Schroder, general manager of Baker Hughes Pipeline Management Group, Houston.
“Many systems were not designed for the passage of inline inspection tools, and those that were have very limited space on offshore platforms to perform pigging operations.”
Schroder also cited as another area of concern the question of how to monitor the performance of offshore cathodic protection (CP) systems: “Most systems employ galvanic CP systems, and many are at the end of the design life of the sacrificial anodes. To date, no cost-effective method exists to evaluate the performance of these systems.”
Also needed are advances in marker systems to support effective location of pipewall anomalies offshore, says Phillip Morrison, vice-president, pipeline integrity products and services, T.D. Williamson Inc., Tulsa.
Deepwater challenges
Sustaining the integrity of pipelines in deep waters carries its own unique techinical difficulties.
And those hurdles are magnified by a boom in demand for the specialized services and equipment needed for the ongoing surge in global deepwater oil and gas development.
“Deep water continues to present challenges for integrity management”, says Claudi Santiago, president of Florence, Italy-based GE Oil & Gas, which has a pipeline integrity and inspection services unit. “We’ve found that every project we’ve contributed to presents its own unique challenges and almost always requires us to step up and take our technology to the next level.”
Deepwater development will result in long pipelines tying into existing pipeline infrastructure, impacting design and construction in two ways relative to integrity management and effective asset life planning, says John Stearns, vice-president, marine pipeline systems for Houston-based Intec Engineering.
“First, the nominal diameter of the pipeline might change several times from deepwater to shallow water, or even to shore,” he says. “This variance in pipeline diameter, and the long distances involved, impacts the design, manufacture, and selection of an internal inspection pig and any associated equipment and processes.
“For instance, designers must consider how best to mitigate the risk of a stuck inspection pig. A lot of significant development and testing effort, combined with judicious design and construction, is required to avert unnecessary or extended production shutdowns for maintenance and repair.
“Second, successful navigation of an inspection pig from deep water to shallow water, and through subsea wyes at pipeline intersection locations, requires rigorous development and testing of the pig to facilitate a safe, reliable interface between the inspection equipment and the pipeline system.
Such issues dramatically affect design and construction parameters, project schedules, and, ultimately, efficient operations, says Stearns. “As industry continues to expand the range of multidiameter pigging for deepwater…pipelines, its need for experienced, seasoned pipeliners and advanced technology development also will increase.”
Regulators currently are demonstrating a high reliance on hydrostatic pressure testing of deepwater pipelines as a test to prove pipeline integrity, although such conventional pipeline integrity testing could prove problematic for deepwater systems.
“Deepwater pipelines, however, are exposed to external collapse as well as large axial and lateral forces and movements acting on the pipeline during construction and during operation,” Stearns notes. “Some industry experts believe that better methods, other than hydrotests, exist for proving deepwater pipeline integrity.”
One possible alternative, he says, would be a comprehensive quality assessment/quality control (QA/QC) effort in tandem with a pipe mill pressure-test program, along with similar rigorous and comprehensive QA/QC programs at other key component manufacturing, fabrication, and installation locations.
This could provide an equal or greater benefit and level of safety, Stearns contends: “This argument is particularly strong for deepwater gas pipelines.”
Stearns also expressed concern about equipment reliability and subsea inspection frequency regarding the recent use of subsea high-integrity pressure protection systems to facilitate pipeline design-particularly long-distance tiebacks.
Arctic offshore challenges
The new frontier in testing the limits of industry’s ability to ensure pipeline integrity is the offshore Arctic.
Even the open-water season in the Arctic poses huge logistical and logistical challenges for pipeline installation. But the difficulties grow after freeze-up.
Seabed ice scour from ridges, strudel scour, ice loading, ice gouging, subgouge soil deformations, and ice-soil-pipe interactions all factor into integrity design considerations.
Stearns notes that the Shtockman pipeline project in the Barents Sea off Russia is currently pushing the envelope for industry’s technical capabilities in hostile environments.
Intec’s own abilities to design an offshore arctic pipeline are being put to the test with the planned installation of a production flowline in the Beaufort Sea off Alaska.
Part of the Oooguruk oil field development project under way by Pioneer Natural Resources Co., Irving, Tex., the flowline will represent the first application of pipe-in-pipe (PIP) flowline technology off Alaska. Intec also designed the first offshore arctic subsea pipeline as part of BP PLC’s Northstar development in the Beaufort Sea off Alaska.
The Oooguruk subsea system is a buried pipeline bundle extending 5.7 miles from an offshore gravel island in 5 ft of water to shore, to link with a 2.3-mile onshore system built on vertical supports. The offshore system comprises an open bundle with individual lines strapped together to hold down costs of developing the field, expected to peak with output at 15,000-20,000 b/d of oil by 2010. The bundle consists of four pipelines, separated by spacers along every 20 ft of the pipelines: a 16-in. OD multiphase PIP line for oil, gas, and water; a 6-in. gas line; an 8-in. water line; and a 2-in. diesel line.
The inner and outer pipe of the PIP flowline are designed with high-frequency induction welded pipe. All of the flowlines are grade X-52 or higher to handle potentially higher operating strains.
Pioneer will excavate a 9-ft trench for installing the pipeline bundle and bury the line at least 6 ft to the top of the pipe. It plans to install a fiber optic monitoring system along the subsea flowline to detect possible seabed erosion from studel scour.
