Visitors come to Alaska for many reasons: camping, wildlife, scenery. And more than 90,000 people from around the world come each year to tour the Trans Alaska Pipeline System, commonly known as TAPS. This 800-mile engineering marvel passes through three mountain ranges, over three faults and across 800 rivers and streams in its mission to connect oil fields in northern Alaska to the seaport at Valdez, where the oil is shipped to the lower 48 states for refining. Since its completion nearly 30 years ago, the pipeline has transported more than 15 billion barrels of oil.
Named after the Aleut word Alyeska, meaning “mainland,” the Alyeska Pipeline Service Company headquartered in Anchorage, Alaska, was established in 1970 to design, construct, operate and maintain TAPS. At the time, construction of TAPS was the largest privately financed construction project ever attempted, and cost more than $8 billion when completed. To ensure that the pipeline is stable and well maintained, surveyors have regularly monitored TAPS since its initial construction. Today they are using 3D scanning technology to ensure that the pipeline is correctly maintained.
Pipeline ConstructionAlyeska supervised five years of surveying and geological sampling before beginning TAPS construction in March 1975. The construction of TAPS took two years to complete and employed more than 70,000 workers, many of whom often worked under extreme conditions.
The pipeline is principally made up of a single 48-inch diameter pipe constructed in six sections. Alaska's harsh environment and permafrost (frozen soil) meant that more than half the pipeline had to be elevated rather than buried to prevent permafrost from melting and shifting due to the heat of the oil. Thawing frozen soils could have made the ground unstable and possibly caused ecological damage. By elevating the pipe on vertical support members (VSMs) these soils can remain frozen and the pipe can move in case of expansion and contraction due to temperature variations. In permafrost areas, the supports, which consist of two vertical supports and a connecting crossbeam, or horizontal support member (HSM), contain thermal devices carrying heat up through the pipes. The remainder of the pipeline was buried in a deep ditch, insulated with gravel padding and covered with dirt.
Ongoing MaintenanceAs with any engineering project of this magnitude, the pipeline requires continual monitoring. Monitoring slope stability is one of the important activities Alyeska has regularly performed since startup. Normal geological activity could potentially damage the pipeline. Every year, Alyeska conducts slope stability surveys at six key locations on the pipeline from about 35 miles south of Glenallen to 75 miles north of Fairbanks. Most of these sites are located on southern hillsides where sun exposure is greatest. These sites are located in areas known for ice lenses below the pile supports. These lenses can melt, causing hillsides to migrate downslope as much as 0.2 inches per year.
Historically, the horizontal and vertical monitoring of the six sites took five crew members about 21 days using optical surveying instruments and methods. These methods entailed separate horizontal and vertical surveys. In 2005, Anchorage-based CMSI-Bell J.V. developed a plan to reduce the hours of labor required to complete the survey. CMSI-Bell J.V. is a joint venture between Chugach Alaska Corporation, an Alaska Native Corporation, and F. Robert Bell and Associates, an Alaskan civil engineering and surveying firm. CMSI-Bell proposed using 3D scanning technology to complete the original scope of work as well as to potentially provide additional data that could be used in monitoring these sites.
One of the first steps in setting up the surveys was to visit each location to determine if 3D scanning was practicable. The sites range from 700 to 5,000 feet horizontally and 300 to 950 feet vertically. “A specific business problem we faced was to reduce, or at a minimum keep the same, the total man hours for the project while at the same time providing additional data,” says CMSI-Bell’s Chris Burt, CE. Burt had been involved with similar jobs using 3D scanning for Hyundai in Korea as well as for BP at Prudhoe Bay Oil Field along Alaska’s Northern Shoreline. “We also needed to be able to repeat the monitoring easily since the locations had to be surveyed on an annual basis.”
Establishing GPS ControlCMSI-Bell combined the use of GPS with 3D scanning technologies to produce a single point monitoring system and a point cloud-based surface mesh-3D model monitoring system. The firm had previously completed a three-year project to gain vertical bench marks along the entire pipeline with an 800-mile static survey using GPS. The bench marks were also referenced with state plane coordinates, and CMSI-Bell used this control for the scanning project. CMSI-Bell needed to establish optimal scanner base positions for each setup, which meant finding locations that would maximize visible VSM bases, spaced about 60 feet apart. In addition, CMSI-Bell's crew set rebars to serve as intermediate control points between each of the setup locations. These rebar sets assisted in the registration process, as well as tying the final scan data into state plane coordinates. Since these intermediate rebar sets were located on moving slopes, they were tied into vertical bench marks with known state plane coordinates.
Bench marks located outside the monitored areas were referenced to ensure that stable points were used. A Trimble (Sunnyvale, Calif.) GPS base unit was set on one of these bench marks and a Trimble R8 GPS rover was used to capture grid coordinates for the rebars serving as intermediate control points. Elevations were measured referencing the 1999 Alaska Geoid. Parameters set in a Trimble TSCe controller to meet accuracies of 0.05' horizontal and 0.07' vertical for a minimum occupation time of three minutes with at least six visible satellites. At least one additional control point, or vertical bench mark, was also measured and checked against recorded coordinates at each site. Because the intermediate control is migrating downhill along with the pipeline, it has to be re-shot each year using GPS and the stable control points.
Setting Up the ScansCMSI-Bell determined and accurately documented the optimal locations for the scanner base setups, point cloud registration spheres, monitor point targets and ground scanning. CMSI-Bell used a Trimble GS200 3D Scanner, which is capable of measuring up to 5,000 points per second to ranges of 350 meters. Scanning and processing involved a two-person field crew identifying and establishing these locations. They then scanned and processed the data and extracted the deliverables from the point cloud. The field crew used a generator to power the scanner.
The parameters for the actual scanning were accomplished by setting up the desired scan areas, using Trimble PointScape field software, to scan the ground at a 1" to 2Â½" grid and the support steel at a Â¼" to Â½" grid. By using this approach, the surveyors were able to scan between 500 and 600 linear feet of pipeline, and associated monitor points per set up. By establishing these grids, CMSI-Bell was able to efficiently scan all the desired objects and monitor points in the allotted time frame.
To accomplish the actual monitor point data collection, CMSI-Bell created a flat target with a magnetic backing, and then punched a hole in the target's center. Once the crew members found the best line-of-sight location to the scanner, they placed the target onto the VSM and used a steel punch to create the monitor point on the VSM's steel. They used paint pens to outline the target and punch marks so that it will be easy to find the locations next year. Once all the targets visible from the current scanner location had been scanned, they moved the targets to the next set of VSMs.
While scanning the pipeline, CMSI-Bell also picked up the ground surface and as much of the pipeline support steel as possible so the engineer could monitor the ground for sinkholes or other signs of failure. This was done to potentially eliminate additional monitoring trips for purposes of assessing pile tilt or drainage issues.
Comparing New Data With OldComparison of the historical data to the scanned data was accomplished by locating the historical monitor points, which were located horizontally and vertically in separate locations on the pipeline support structure. The scanned data was cross-referenced to historical data that had been collected with optical instrumentation and procedures. During the first scanning pass, the surveyors had to set up targets at both of these locations as well as the new single monitor point location. This step was taken to ensure a smooth transition from the old to the new data, and so that any previous reports and studies could be directly related to the new monitor points as well.
"The problem was how to ensure that monitor point data was from the exact same point on the VSMs every year," Burt says, "and then adjust scan clouds to a datum, which is determined by historically stable control points. By using the Trimble 3D scanner and flat targets we were able to create one monitor point on each VSM and record the X, Y and Z components of that mark with one survey."
Combining and registering this number of scans has traditionally been a time-consuming task, with the longest site taking 16 setups and the shortest site taking three setups. The scans were registered in groups of four, and it typically took about an hour per scanner to set up so that scan clouds were properly registered together. "We then used Trimble RealWorks Survey software to geo-reference the registered scans to GPS control data," Burt says. "The information we gathered was invaluable, plus we learned lessons for future projects of this nature."
Facing ChallengesThere were many challenges inherent to a project of this scope, including the remoteness of the sites, which were only accessible via pipeline maintenance roads. Safety was another concern since the sites were remote. The field crew was lifting and carrying gear and transporting supplies to and from the pipeline every day, including two gel-cell 12V batteries for the scanner and a backup generator. All this work was done on relatively steep slopes. For this reason, footing and stability of both the surveyors and equipment were also important safety concerns. The two-person survey crew was often multitasking and also had to avoid fatigue.
And, of course, weather was a major factor. Fall weather in Alaska is unpredictable and survey efforts were often complicated by wind and rain that hampered data collection. The CMSI-Bell surveyors used a small yard umbrella and a bipod setup to shield the scanner from rain. The scanned data was relatively unaffected by rain unless the surface being scanned had a significant amount of water on it. Occasionally, the targets over the monitor point punch marks had to be wiped off just prior to scanning them in order to collect accurate data. Gathering accurate data the first time was critical since the remote locations made it difficult and expensive to repeat the process.
Lessons LearnedIn addition to concerns about safety and weather, the work was further complicated by unstable ground surfaces beneath the scan bases. "Soft, sloped ground frequently made it difficult to keep the scan base stable so we fabricated steel plates for support," Burt says. "The other problem caused by steep terrain was target acquisition since slope steepness made it difficult to use the camera's zoom feature to find spherical targets." The scanning results were able to be easily combined with historical points, which meant that the standardized monitoring reports and databases did not need to be redesigned when incorporating new data. This permits a direct "apples-to-apples" comparison when looking at the slope stability data over the lifetime of the project.
Finally, the ground surface mesh for future monitoring meant that pipeline engineers could now compare the surface annually at these sites to help study the problems in more detail. "We found additional uses of scanned data, including determining the skew or tilt of the vertical support members without making another site visit," Burt says. "We also reduced the overall cost of the project by 23 percent."
Using these methods, CMSI-Bell believes that it has developed a precise, accurate annual monitoring service that requires fewer hours of labor while providing combined vertical and horizontal monitoring points as well as an annual ground monitoring comparison for enhanced quality control. Its application of scanning technology should help to ensure the safe and continuing transportation of oil from the northern fields of Alaska to the rest of the United States.