Applying Non-Traditional ILI Technology To Challenging Pipeline .

Applying Nontraditional ILI Technology to Challenging Pipeline Segments for Transmission Integrity ManagementAmerican Gas Association Operations Conference & Biennial Exhibition May 19-22, 2015 Grapevine, TexasFor pipelines less than 10” in OD, there are fewer robotic tools presently available 1, therefore free-swimmingtraditional MFL tools are often utilized. The use of free-swimming ILI tools allows for the option of cleaning thetarget inspection area which has the added benefit of removing excess liquids and sediment, potentiallyenhancing the data quality of theinspection. However, projectsutilizing free-swimming ILI tools tendto have increased costs associatedwith additional construction such aswelding temporary launchers andreceivers and added time for pipelinecleaning.Entry points for ILI tools atwaterways must be evaluated basedFigure 3: Profile of a concrete-lined canal crossing under a roadwayupon the most economical andfeasible options and take into account the environmental sensitivity of the area, permitting duration andrequirements, pipeline depth, and overall impact to the surrounding area. These locations also tend to be lowpoints in the pipeline making them susceptible to liquids accumulation which must be taken into account duringthe project planning and ILI tool selection process. If significant liquids are encountered, it can impact the abilityof many robotic ILI tools to successfully complete the inspection and potentially result in a tool’s electronics beingdamaged or the tool becoming stranded in the pipeline.CASED SPANSAbove-grade cased spans can pose aunique challenge for assessing pipelinesegments with Direct Assessmentmethods. Standard casing inspectionscannot be conducted due to the fact thepipe is not buried, and visual inspection ofthe carrier pipe cannot be conductedsince it is enclosed within a casing 2. In2014 PG&E conducted two inspections ofabove-grade cased spans.Figure 4: 10” carrier inside 16” OD casing located inside a bridge structure crossing a majorOne project inspected approximatelyriver1,000’ of a 10” OD pipeline inside a 16”OD casing that was contained within the structure of a two-lane bridge spanning a major river crossing. A nontethered robotic MFL tool was chosen to conduct this inspection. This allowed the tool entry point to be located1Technologies are under development and newly available within this size range that offer additional robotic ILI tool optionsfor future projects.2Mini robotic technologies are emerging to conduct visual and in some cases ultrasonic spot testing within the annular spacebetween casing and carrier pipe, although attaining 100% visual inspection remains problematic with this technique given thepresence of spacers and sometimes debris within the annular space.5 Page

Applying Nontraditional ILI Technology to Challenging Pipeline Segments for Transmission Integrity ManagementAmerican Gas Association Operations Conference & Biennial Exhibition May 19-22, 2015 Grapevine, Texasin a field, and a safe distance away from the main road, roughly 180’ from the onset of the casing. This entrypoint allowed for safe staging and work areas required minimal permitting and land owner agreements and didnot impact the bridge traffic. This project was also executed without taking an outage which minimized theimpact to gas system operations and staff.The second project inspected an 8” OD pipelineinside a 12” OD casing, which was attached tothe outside of a bridge via pipe hangers andspanning a river some 239’. An 8” tetheredMFL tool was selected for this project in partbecause a convenient location and abovegrade access was available at the end of thecased span to launch the tool, and because fullcoverage of the span including metal loss datacould be obtained. This tool was inserted atone end of the bridge and propelled to theopposite side by compressed air. Once the toolFigure 5: 8" carrier inside a 12" casing attached to a bridgereached the end of the casing, a winch wasused to pull the tool back to the starting point.After the tool run, the ILI vendor determined that the last 2’of the cased span was not inspected since the ILItool could not pass further into the bend at the end of the casing. The project team was able to remove the endof the casing not inspected by the ILI tool and perform a Direct Examination in order to complete the inspection.CONSTRUCTABILITYFive non-traditional ILI projects have been conducteddue to construction-driven challenges at locationsoriginally planned for Direct Assessment excavations.In all cases the cost and challenges associated witheach method were evaluated and the non-traditionalILI option was executed after it was determined tohave either a lower cost and/or greater likelihood ofsuccess than the excavation option.One project was a 30” OD pipeline approximately1,500’ up a mountainside in an environmentallysensitive area. Excavating the Direct Assessmentrequired dig locations at this location would haverequired transporting all equipment up difficultterrain by hand, and manual digging in rocky soil. Thelocation was also at high risk of not being completedin time due to an upcoming deadline. The nontraditional ILI was ultimately executed with atethered MFL tool and coordinated in conjunction6 PageInspection LocationFigure 6: 30" OD pipeline on mountainside in an environmentallysensitive area

Applying Nontraditional ILI Technology to Challenging Pipeline Segments for Transmission Integrity ManagementAmerican Gas Association Operations Conference & Biennial Exhibition May 19-22, 2015 Grapevine, Texaswith the planned shutdown of the pipeline for a nearby replacement project. The entire non-traditional ILIproject was completed 18 days after project initiation.A 12” OD inspection project was conducted via tetherless robotic MFL while the pipeline system remained inoperation in order to inspect three low points for internal corrosion. This inspection was utilized to provide theTransmission Integrity Management engineering team with additional data from which to evaluate the overallinternal corrosion threat within the pipeline.An additional 12” OD inspection project was initiated due to a challenging Direct Assessment location which waslocated in unstable soil conditions and adjacent to a structural foundation. The project was also conducted viatetherless robotic MFL while the pipeline system remained in operation. The scope was expanded to 3,400’,which was the maximum feasible from a single entry point based on the specific tool utilized. Doing so allowedthe engineering team to satisfy the original project objective of inspecting the pipe at the unstable soil location,while also inspecting nearby locations identified by the Indirect Inspection Tool (IIT) results previously conductedas part of the ECDA (External Corrosion Direct Assessment) program with minimal added cost.One 30” OD inspection project was conducted at a location in which construction was underway as an ECDAcasing inspection, but was shut down prior to completion of the assessment when a traffic control-related disputeerupted between the two permitting agencies. The timeframe to resolve the dispute between the two agenciesand the eventual restrictions placed on construction hours made meeting the rapidly approaching compliancedeadline doubtful. A cross functional project team of PG&E ILI Engineering and GTS Project Managerscoordinated with a nearby replacement project for shared resources and a planned pipeline outage, allowing forsuccessful project execution in six days from project inception to ILI execution.The other of these projects was on a 24” OD pipeline requiring an internal corrosion inspection at a low point thattraversed underneath a 60” diameter sewer line adjacent to a major freeway. A tethered robotic EMAT tool wasidentified for this inspection along with another nearby inspection of a creek crossing on the same pipeline.These locations were known to have liquids present, and because the EMAT tool requires a clean pipeline, achemical cleaning program requiring a launcher and receiver was designed and implemented. This addedmeasure ensured the pipeline at the two targeted low points was sufficiently clean to allow the tool to obtainquality data.DETAILED INSPECTION PROFILE: 20” OD CREEK CROSSING WITH PIPETEL EXPLORER 20/26PROJECT INTRODUCTIONAs part of PG&E’s 2013 Direct Assessment Program, an internal corrosion inspection on a 20” OD pipeline at a lowpoint in a creek crossing was required to be completed prior to the end of 2013. The inspection needed toencompass the entire creek bottom, the downstream sag elbow and the adjacent downstream pipe for a totalinspection length of 48’. The pipeline at the crossing was installed in 1960, had a wall thickness of 0.312”, andincluded a 45 1.5D sag elbow with a wall thickness of 0.500”. The method originally identified to conduct theinspection was to excavate and perform direct examination of the subject pipe and fitting. However, because ofthe extensive permits required, the project was at-risk to be completed prior to its required completion date. As acontingency the permitting for the originally planned direct examination process proceeded, but in parallel the7 Page

Applying Nontraditional ILI Technology to Challenging Pipeline Segments for Transmission Integrity ManagementAmerican Gas Association Operations Conference & Biennial Exhibition May 19-22, 2015 Grapevine, Texasproject team began gathering the necessary data andperforming an analysis to determine if a nontraditional ILI project would be a viable option.SCOPING PROCESSThe project team gathered and analyzed the availablepipeline records including the pipeline features list(PFL) and as-built drawings to determine criticalproject parameters including pipeline diameter andfeature characteristics important to non-traditional ILItool navigability. Additionally, the team reviewedaerial imagery and conducted a site visit to determine Figure 7: Dry creek crossing to be inspected for internal corrosionviable locations to gain access for ILI tool insertion.Gas planning and operations staff were contacted todetermine the practicality of conducting a pipeline shutdown within the target timeframe, and to solicitinformation regarding the expected level of liquids and general pipeline cleanliness at the crossing.Based on the scoping analysis, three key challenges were identified:Inspection of ElbowBased on engineeringanalysis, the 45 sagelbow on thedownstream side of thecreek was determinedto be the likely point forliquids to gather if present inthe pipeline. It was alsodetermined that this was the primarylocation where internal corrosion wouldoccur, and therefore, the central focal pointof the inspection. Based on PG&E’s procedure, thebottom 180 of the fitting was to be inspected forinternal corrosion.PrimaryInspectionTargetFigure 8: Profile of creek crossingThis requirement posed a challenge for the non-traditional ILI project team to identify a tool capable of collectingdata inside the fitting. Many ILI tools experience sensor liftoff inside elbows resulting in decreased resolution inbends, and some are unable to gather any information at all at these types of fittings.8 Page

Applying Nontraditional ILI Technology to Challenging Pipeline Segments for Transmission Integrity ManagementAmerican Gas Association Operations Conference & Biennial Exhibition May 19-22, 2015 Grapevine, TexasLong Lead PermittingThe location of the key sag bend resides within a creek bottom which would be subject to a Streambed AlterationAgreement permit from the California Department of Fish & Wildlife, as well as a permit from the Regional WaterQuality Control Board. As a contingency the permitting for the originally planned direct examination processproceeded in parallel with the non-traditional ILI project scoping process. Although these permits were ultimatelyobtained in September, the specific construction and mitigation requirements related to those permits made theexecution of a Direct Examination (dig) of the elbow within the creek bed infeasible prior to the deadline. Thenon-traditional ILI project had to ensure the ILI tool entry point was a sufficient distance from the creek toeliminate the need for any long-lead permitting.Problematic ShutdownAfter a hydraulic analysis was performed by transmission system planning and the project was discussed with gassystem operations staff, it was determined that taking the pipeline at the creek crossing out of service would haveplaced a significant strain on operational resources. Although the project team could have pursued this option,doing so would have required moving resources away from a number of other impacted projects in the area.Additionally, Compressed Natural Gas (CNG) would have been required in order to supply customers withuninterrupted service.Multiple options were investigated for implementing a temporary pipeline bypass around the creek; however allwere determined infeasible within the project timeframe due to permitting constraints and significant community& property owner impact.SOLUTION DETERMINEDIn order to overcome the scheduling challenge, the team was able to identify multiple viable options for nontraditional ILI tool entry points near the inspection point but located far enough away from the creek bank toeliminate the need for any long-lead permits. Locations upstream and downstream were identified that couldaccommodate both robotic tools as well the installation of a launcher and receiver for free-swimming tools.Figure 9: Hot-tap launch schematic9 PageThe issue of theoperationally infeasiblepipeline shutdown wasovercome by use of thePiptel Explorer roboticMFL tool with its “hottap” launch & retrieve ability. This method allows for theuntethered battery-powered robotic tool to be launched,conduct an inspection, and exit the pipeline via a pressurecontrol fitting (PCF) without requiring a system shutdown.This method would allow the pipeline to remain in-serviceunder normal operating pressure (NOP) for the durationof the inspection while requiring only minimal supportfrom gas operations staff during project execution, and

Applying Nontraditional ILI Technology to Challenging Pipeline Segments for Transmission Integrity ManagementAmerican Gas Association Operations Conference & Biennial Exhibition May 19-22, 2015 Grapevine, Texaseliminating the need for CNG resources.The last remaining key issue was theinspection of the target elbow. In order tominimize the potential of damage to theMFL sensor, Pipetel typically retracts thesensor when passing through fittings. Thismethod would not be acceptable forconducting this inspection because of theassessment requirement to inspect thebottom 180 of the elbow. After conductingan engineering evaluation, Pipeteldetermined a solution based on the factFigure 10: 12 o'clock position at top ofthat each of the Explorer tool’s MFL sensorsag bend most at-risk for tool damageblocks can be deployed and/or retractedindividually. The evaluation showed that greatest threat of tool damage was present at the top (12 o’clockposition) of the sag bend. Pipetel determined that by deploying only the sensor blocks covering the bottom 270 of the pipeline circumference, the risk of tool damage could be minimized while also fully magnetizing andobtaining the required data for the bottom 180 of the fitting. This technique would allow the key inspectioncriteria to be satisfied while also minimizing the risk of tool damage during inspection of the fitting.KEY PROJECT PLANNING CONSIDERATIONSOnce the solutions to the key challenges of the project had been determined, the non-traditional ILI project waspresented to the project sponsors. The project was authorized to proceed and the project team moved forwardwith the detailed project planning and preparations. A temporary construction easement with the land owneradjacent to the excavation location was obtained and engineered construction drawings were then prepared.Construction activities such as excavation, welding, hot-tapping, and pipe fitting were planned, scheduled andcoordinated by the Project Management team. Gas system operations staff worked with Pipetel to develop avalve operations plan, and community outreach efforts were conducted to ensure all local authorities andsurrounding land owners were made aware of the pr

The use of non-traditional in-line inspection (non-traditional-ILI) methods and tools has become increasingly valuable in managing the integrity of gas transmission pipeline systems. From late 2012 through December of 2014, Pacific Gas & Electric Co. (PG&E) conducted 15 non-traditional ILI projects for Transmission Integrity Management purposes.