Utilities charged with verifying 450,000 miles of transmission line in six months.
The North American Electric Reliability Corp. (NERC) recently had an epiphany. It discovered there can be significant discrepancies between the transmission line designs from the engineering department and what is actually built in the field. Interestingly, this discovery is not a surprise to anyone involved with the construction portion of the utility industry.
Heat, beat and fit in the field is a way of life in the construction world. That is why utilities have as-built drawings, but many times this information does not get back to the office, much less get reviewed or lead to revised file drawings. We live in a world where we are all doing more with less, which all too often means scrambling just to keep up with the next assignment before putting the last assignment to bed.
The Tree Did It
What brought all this to light (or dark) was an event that took place in August 2007. Duke Energy had a 230-kV transmission line lockout due to a flashover between the line's conductor and vegetation located within the right-of-way. It was pretty clear vegetation caused the line trip, but as the root-cause investigation unfolded, NERC received a surprise.
The investigation indicated the conductor-to-ground clearance was less than expected. Instead of the required minimum clearance, the design criteria called for 15 ft (4.6 m); in this case, there was roughly 2 ft to 7 ft (0.6 m to 2.1 m) of clearance available. Evidence pointed to inconsistencies between the actual field conditions and the design dimensions of the transmission line.
Duke proposed an assessment of its 230-kV and 345-kV transmission systems using aerial light detection and ranging (LiDAR) and Power Line Systems' computer-aided design and drafting (PLS-CADD) technologies. Duke believed LiDAR surveying would provide a fast response with accurate data points locating existing structures, conductor sags and ground profiles.
NERC approved the proposal, and Duke went to work. The first phase of the survey encompassed 642 miles (1,033 km) and 3,966 spans. Of those spans, 67 (or 1.7% of 3,966) were identified as having conductor-to-ground clearance issues. The second phase covered 552 miles (888 km) and 3,340 spans, of which 55 spans (or 1.6% of 3,340), were identified as having conductor-to-ground clearance issues.
In a paper published by NERC on April 21, 2010, the agency reported, “The results from phases one and two validated Duke's assertion that the new technologies would provide enhanced reliability by developing a precise 3-D model to confirm conductor-to-ground clearance issues throughout the entire right-of-way of the system.”
LiDAR and PLS-CADD had been used successfully to model about 1194 miles (1,922 km) and 7,306 spans of transmission, and identify 122 ground clearance issues. These clearance issues were about 1.67% of the overall line, which is an amazingly small percentage. Even more amazing, by using LiDAR-based technologies, Duke was able to do a complex assessment in a relatively short time frame.
Intertwined NERC Standards
The success of Duke's investigation caused some alarm within the agency as it became concerned that, nationally, other utilities and transmission line owners, referred to by NERC as entities, might have similar situations. Consequently, NERC issued a recommendation to the industry, published in a press release as “Consideration of Actual Field Conditions in Determination of Facility Ratings.”
This press release has become known in the industry as the “NERC alert of Oct. 7, 2010.” Basically, it tells entities they need to determine if their rating methodology takes into account this difference between design criteria and actual field conditions, and verify that facility ratings are consistent with the methodology.
The NERC alert goes on to say, “Fortunately, new technologies such as LiDAR and PLS-CADD allow entities to more easily assess their lines.”
In the NERC alert, entities were given a very aggressive schedule to meet. They had roughly six months — until April 7, 2011 — to identify any and all rating discrepancies. The remediation schedule was aggressive, too; entities were given until Oct. 7, 2012, to correct everything.
This is not an insignificant effort even with the new LiDAR-based technologies. Just scanning, modeling and reporting on one transmission line is a huge amount of work for a utility. The alert reported that NERC had identified approximately 450,000 miles (724,000 km) of transmission lines above 100 kV for investigation. In addition, much of North America would be covered by snow during the assessment period.
On Second Thought
The entities became very vocal about the impact the alert would cause them and their systems. On Nov. 30, 2010, Gerald Cauley, president and CEO of NERC, issued a letter to the industry's CEOs saying, “I have heard you; let me share my thoughts on the importance of this activity and clarify expectations for responding to the alert.”
Cauley acknowledged the difficulty in meeting the schedule and amended the six-month assessment time to provide a three-year period for the investigation. The new schedule gives entities until Dec. 31, 2011, to identify high-priority facilities and conduct an assessment of them. Medium-priority facilities have to be identified and assessed by Dec. 31, 2012. Low-priority facility assessments can occur until Dec. 31, 2013.
“There has been a tremendous surge in business because of the NERC requirements, and it isn't just for Aerotec. It's a frenzy across the industry,” reports Jim Dow, CEO of Aerotec, reports. As a result of all this activity, many new companies have entered the LiDAR surveying business. “The buyer really has to be careful and have good specifications defining the type of surveying and the deliverables,” continues Dow.
Transmission owners were given the autonomy to develop the rating methodology for their transmission lines. The challenge is determining if the existing transmission line's design criteria matched the as-built field conditions.
Alastair Jenkins, president and CEO of GeoDigital, points out, “It is more than verifying that the initial design criteria and as-built field conditions agree. The owner is expected to prove that, over the life of the line, real-world conditions have not compromised the line's rating. If storm restorations took place, they have to match initial designs. If encroachments are found, they cannot cause a clearance issue. If under-built construction has been added, it has to be within acceptable parameters. Properly executed LiDAR-based technology can do that.”
Assuming 450,000 miles of transmission line is accurate, scanning that amount of geography can be a logistical nightmare. On a good day, LiDAR providers conservatively estimate they typically gather data for 50 miles to 70 miles (80 km to 113 km) of transmission line. This figure varies with weather conditions, width of scan on either side of the right-of-way, equipment and terrain.
“It takes a good deal longer to obtain good data in an urban environment than rural,” says Paul Richardson, technical director for service provider Network Mapping. Richardson points out, “In an urban setting, the power lines have a lot more turns, often at tight angles as the routes follow roads and other urban corridors. Also, challenging terrain along the right-of-way means the line routing is likely to involve more changes of direction than across a relatively flat landscape. The type of terrain can therefore lead to data gathering being harder. In those cases, the number of miles captured would typically reduce.”
Even with the speed of aerial LiDAR, gathering data for 450,000 miles is a great deal of work, but that is only about 20% to 25% of the effort. Once LiDAR data is recorded, it normally takes several weeks to process the raw point-cloud data into usable plans and profiles, or 3-D models. This is followed by several more weeks of work to produce the final report identifying all the problem areas and showing the remediation necessary to meet NERC requirements.
So utilities are looking at an average of a couple of months for each transmission line to be scanned, modeled and assessed. Then the transmission owner takes over, first reading the report and then verifying the model. Assuming no glitches, the owner develops a mediation plan and gets it approved, which can take several more months. There also are approvals, permits, budgets and scheduling of the work force, adding even more time. Multiply that effort by each transmission line comprising the 450,000 miles NERC identified, and the enormity of the undertaking begins to take shape.
It is estimated the cost to evaluate the transmission lines identified by NERC will range between $650 million and $1.8 billion. Typically, LiDAR costs can run between $1,500/mile and $4,000/mile, but is that really an issue? The industry is spending roughly $2 billion to $3 billion a year on vegetation management now. A large percentage of that is for aerial LiDAR-based technologies, which has to include portions of the 450,000 miles identified as transmission lines of interest.
Jim Koop, managing director for W.I.R.E. Services, says, “The nice thing about collecting LiDAR data is that once you have it, you have it.” Koop goes on to explain, “The gathered data can be used for many purposes. If the line is flown for vegetation management, later that data can be processed to identify clearance issues, be used for asset inventory or for verification of construction (as-built). The utility can have it reprocessed for any deliverable needed.”
The Early Results
In the six months following the NERC alert, the agency has been receiving assessment plans. On May 11, 2011, NERC issued a statement of its preliminary findings, reporting, “The majority of assessment plans reviewed so far are good examples of what NERC considers to be the appropriate level of content and detail.” However, the statement went to say that NERC reviewers have identified some problem areas with the assessments.
Reviewers noted that in some of the early assessments, the entities did not prioritize their transmission lines as directed. Or, if they did, they did not provide the rationale behind the way they did their line prioritization. There also were returns that did not provide the methodology details of how entities compared initial transmission line design criteria with the actual field construction to arrive at the line's ratings.
Adam Rousselle, president and CEO of Utility Risk Management Corp., puts it this way, “The utilities know their system requirements the best, but there is a problem that should be addressed. The true high-priority issue may actually be the interconnects between utilities. Little information is available about the transition point where utilities intersect with each other. Two utilities may have different opinions of priorities for a shared circuit. It is much like driving a road that crosses county boundaries. One side is potholed and the other newly paved.”
Technology Trumps Inconsistencies
As a result of the early analysis, NERC believes the entities need a little more guidance with their responses. Transmission owners do not always agree on the applications of standards, so it is not surprising there are issues with rating methodologies. Even neighboring utilities do not always agree on all the assumptions or criteria used in line designs, much less ratings.
The preliminary findings caused NERC to recommend that entities provide more details for their assessment plans. Initially, NERC required the owner to provide the methodology. The agency is now recommending the methodology includes conductor-to-conductor distances and conductor distance to objects (including ground clearance) occupying rights-of-way. In addition, the owner is expected to show how the conductor meets minimum clearance requirements.
The blackout of 2003 introduced a lot of utilities to LiDAR-based technologies with NERC's FAC-003 vegetation management standard. The Oct. 7 alert joins that standard with the FAC-008 facility rating methodology and FAC-009 establish facility ratings standards, and it is expected that more of the industry will see LiDAR-based technologies as one of the solutions to the latest vegetation-based threat to the integrity of the grid.
Fortunately, computer manufacturers, software developers and hardware suppliers have been improving their product during this time. Computer memory has gotten cheaper, and the machines are more powerful. Software was once the bottleneck, but now all the CADD platforms are LiDAR viewers.
Hardware wise, there are new classes of sensors available to take advantage of improvements in waveform digitizing technology. Spatial resolution and accuracy continues to improve as manufacturers release updated systems using multiple channels with multiple lasers and wavelengths in the red, green, infrared and short infrared spectrums, for example. There is even one system using a single laser with beam-splitting technology.
Of course, verifying and remediating problems will provide challenges as the industry moves forward. It should not be surprising that initial reports indicate there are some inconsistencies with a portion of the transmission owners' assessment plans or that some entities are not in agreement on line rating assumptions. This is a big effort, and it is easier for larger entities to establish their procedures while the smaller transmission owners are still trying to get a handle on the techniques available.
Keep in mind that procedural revisions are not a show-stopper for entities using LiDAR-based technology. Once the data has been collected, it can be manipulated, organized and arranged to meet any requirements set forth by government agencies. LiDAR-based technologies truly have no limitation as to how the data can be used once it has been collected. The limitation is with users. They must decide the criteria to be used and the deliverable to be supplied.
Network Mapping www.network-mapping.com
Power Line Systems Inc. www.powline.com
Utility Risk Management Corp. www.utilityrisk.com
W.I.R.E. Services www.wireservices.ca