White Paper Available from the PPIM Conference: Pipeline Regulation and Direct Assessment

Pipeline Pigging and Integrity Management ConferenceNiSource and Willbros Engineering Utilize GIS during each Phase of the Direct Assessment Process: A Current DA Program in Place that takes full advantage of an Operator’s Database and a robust Algorithm for Assessment and then brings it on home for the next assessment period to the Company’s GIS. February 6 – 9, 2012 Ed Nicholson Integrity Engineer NiSource Gas Transmission and Storage Charleston, West Virginia (304) 357-2421 enicholson@nisource.com Amy Jo McKean Project Manager Willbros Engineering Kansas City, Missouri 816-398-4532 AmyJo.McKean@willbros.com Brad Leonard Senior Manager – Corrosion Services Willbros Engineering Pittsburgh, PA (412) 432-6882 brad.leonard@willbros.com PIPELINE REGULATION AND OVERVIEW OF DIRECT ASSESSMENTCurrent integrity management regulations for transmission pipelines permit four inspection methods forpipelines: 1) Pressure Testing 2) Internal Inspection 3) Direct Assessment for external, internal or SCC corrosion 4) Other Technology - Other technology usually requires that the method provide an equivalent understanding of the condition of the pipe and approval from PHMSA.Direct Assessment (DA) has been considered an operators “last resort” to integrity assessment. Thismethod is often only considered due to the potentially high cost of a retrofit for smart pigging, the lack ofsufficient pipeline pressure or flow to run a smart pig, or the “single feed” of supply that this pipeline mayprovide such that it cannot be taken out of service for a pressure test or wireline assessment. DA can be theshining star as an assessment method for the aforementioned scenarios. An operator is in business to moveproduct, and the explanation to their customers that they need to take a section out of service, whilerequired, still has a wide spectrum of potential ramifications to their end user.According to DOT, Pipeline and Hazardous Materials Safety Administration, 49 CFR Parts 192 and 195,[docket No. RSPA-04-16855;Amdt. 192-101 and 195-85] RIN 2137-AD97, Pipeline Safety: Standards forDirect Assessment of Gas and Hazardous Liquid Pipelines:SUMMARY: Under current regulations governing integrity management of gas transmission lines, if anoperator uses direct assessment to evaluate corrosion risks, it must carry out the direct assessmentaccording to PHMSA standards. In response to a statutory directive, this Final Rule prescribes similar Page 1 of 17

standards operators must meet when they use direct assessment on certain other onshore gas, hazardousliquid, and carbon dioxide pipelines. PHMSA believes broader application of direct assessment standardswill enhance public confidence in the use of direct assessment to assure pipeline safety.DATES: This Final Rule takes effect November 25, 2005. Incorporation by reference of NACE StandardRP0502-2002 in this rule is approved by the Director of the Federal Register as of November 25, 2005.SUPPLEMENTARY INFORMATION:Background This Final Rule concerns direct assessment, a process of managing the effects of externalcorrosion, internal corrosion, or stress corrosion cracking on pipelines made primarily of steel or iron.The process involves data collection, indirect inspection, direct examination, and evaluation. Operatorsuse direct assessment not only to find existing corrosion defects but also to prevent future corrosionproblems. Congress recognized the advantages of using direct assessment on U.S. Department ofTransportation (DOT) regulated gas, hazardous liquid, and carbon dioxide pipeline facilities. Section 14 ofthe Pipeline Safety Improvement Act of 2002 (Pub. L. 107-355; Dec. 17, 2002) directs DOT to issueregulations on using internal inspection, pressure testing, and direct assessment to manage the risks to gaspipeline facilities in high consequence areas. In addition, Section 23 directs DOT to issue regulationsprescribing standards for inspecting pipeline facilities by direct assessment. In response to the first statutory directive, Section 14, DOTs Research and Special ProgramsAdministration (RSPA)1 published regulations in 49 CFR part 192, subpart O, that require operators tofollow detailed programs to manage the integrity of gas transmission line segments in high consequenceareas. Subpart O also requires an operator electing to use direct assessment in its integrity managementprogram, to carry out the direct assessment according to §§ 192.925, 192.927, and 192.929, asappropriate.2 Sections 192.925, 192.927, and 192.929 cross-reference the American Society of MechanicalEngineers (ASME), ASME B31.8S-2001, “Managing System Integrity of Gas Pipelines. ASME B31.8S-2001 describes a comprehensive process to assess and mitigate the likelihood and consequences of gaspipeline risks. In addition, §192.925 cross-references a NACE International (NACE) standard, NACEStandard RP0502-2002, “Pipeline External Corrosion Direct Assessment Methodology. NACE StandardRP0502-2002 describes a step-by-step process for identifying and addressing external corrosion activity,repairing defects, and taking remedial action. Other parts of §§ 192.925, 192.927, and 192.929 ensureoperators use appropriate criteria in making direct assessment decisions.1 The Norman Y. Mineta Research and Special Programs Improvement Act (Pub. L. 108-426, 118; November 30, 2004) reorganizedRSPA into two new DOT administrations: the Pipeline and Hazardous Materials Safety Administration (PHMSA) and the Researchand Innovative Technology Administration. RSPAs regulatory authority over pipeline and hazardous materials safety was transferredto PHMSA.2 The standard on external corrosion direct assessment § 192.925) requires operators to integrate data on physical characteristics andoperating history, conduct indirect aboveground inspections, directly examine pipe surfaces, and evaluate the effectiveness of theassessment process. Under the standard for direct assessment of internal corrosion (§ 192.927), operators must predict locations whereelectrolytes may accumulate in normally dry-gas pipelines, examine those locations, and validate the assessment process. The standardfor direct assessment of stress corrosion cracking (§ 192.929) involves collecting data relevant to stress corrosion cracking, assessingthe risk of pipeline segments, and examining and evaluating segments at risk. Page 2 of 17

DA is currently the only proactive method of pipeline integrity assessment, as it looks at the environmentsurrounding the pipeline and identifies the locations where corrosion activity, past, present, and future, isprobable. The other assessment methods address similar as well as additional threats but only identify whathas already occurred on the pipe, providing a snapshot of current conditions without consideration forconditions surrounding the pipe. Without acquiring data typically associated with DA activities, it isdifficult, if not impossible, to have enough appropriate information to make sound root cause andpreventive and mitigative decisions.In this paper we will be concentrating on the External Corrosion Direct Assessment (ECDA) method whicheffectively addresses external corrosion caused by the absence of, or voids in, coating on the pipeline.These “voids” in continuous coating that are present on the pipeline can be associated with coatingpenetrations from rocks, poor pipe installation, coating deterioration with time, and from many types ofthird party damage. The case study presented herein will demonstrate how the acquisition, integration andverification of data to continually improve an operator’s GIS system are instrumental in each step of theprocess.ECDA is a methodology that is defined as a four step Process: 1) Pre-Assessment: incorporates various field and operation data gathering, data integration, and analysis 2) Indirect Inspection: combination of above ground tools and calculations to flag possible corrosion sites (calls), based on the evaluation or extrapolation of the data acquired during Pre-Assessment 3) Direct Examination: excavation and direct assessment to confirm corrosion at the identified sites, and remediation as defined in regulation 4) Post Assessment: determine if direct assessment sites are representative of the conditions of the pipeline, and what activities the operator needs to conduct moving forward based on the findings from the previous stepsEach step has intensive data management requirements associated with it and invalid assumptions andineffective data quality control methods can lead to incorrect or inappropriate results which propagatethroughout the entire process. The purpose of integrity management is to know as much as is necessaryabout a pipeline to manage and operate it safely and reliably. That knowledge is gained through effectiveand continual mining, management and validation of data. Defendable integrity decisions are based ondocumentable, complete data, and conversely unsubstantiated decisions are based on incomplete andundocumented data. 1) The pre-assessment step is the foundation for which all threat, risk assessment, prioritization and necessary assessment methodology decisions are made. Problems arise when data sources are questionable and numerous gaps exist leading to inappropriately conservative or incorrect assumptions. This is especially problematic at this early stage of the process. A structure built on a weak foundation can have disastrous results, and a DA program founded on weak or nonexistent data is no different.This project encountered data validation discrepancies and questions along the way as the team outlined thecourse to meet the infamous December 17, 2012 date for pipeline integrity industry compliance. It isimportant to emphasize that all the way through the DA process NiSource has strived to continuouslyvalidate their decision to utilize DA and as well compare what is in the GIS to what is really found in theground. This validation of the DA process and the updating of the GIS have led to a growing confidence inthe use of DA as an assessment method and an increased knowledge of the pipeline segments beinginvestigated.Case Study: Uncoated (bare) Pipe vs. Coated PipeThe mining of data for any project can be an enlightening and educational process that allows an operatorto do a gut check of their GIS database. This project was no different and had a positive upside forNiSource in validating data. Field verification and in depth document research led to substantialdetermination that the majority of the scheduled HCA’s would remain in the DA program while someothers would be removed. The HCA’s that were field verified as being uncoated were placed by NiSourceinto their capital budget “pipe replacement” program as a prudent operator. The reality is that DA is not a Page 3 of 17

silver bullet for every non-piggable segment and the decision to use DA needs to be questioned andreevaluated during each step of the process. The bare pipe criterion consists of a more stringent program,rightfully so, requiring a more aggressive or frequent reassessment period.As part of NiSource’s internal threat matrix assessments, coating types along pipe segments determine whatthe overall integrity threat may be. During the initial building of the GIS database for the NiSource pipingsystems, several areas of unknown mainline coatings occurred. It was established that as a “worst” casescenario, the unknown coating types would be classified as “Bare” uncoated piping. As this methodologyworks sufficiently for industry required monitoring practices, applying ECDA to these areas proves to becomplicated due to the unknowns.Please see Table 1 for a brief timeline of how the team continued to research the HCA’s to ensure thatNiSource was making the correct assessment method for long term and economical decisions.The numbers of excavations can dramatically increase the cost of the assessment for an HCA and withsome HCA’s being rather short in length and if they proved to be bare – NiSource determined that apotential stopple and replacement section would be the better method for a long term strategy.Due to pipeline integrity regulations and the amount of HCA’s occurring as uncoated pipe in GIS, specifictools, procedures, and data evaluation techniques were developed in order for preparation of the indirectinspections on the uncoated portions of piping within the various HCA’s. The exact extents of theuncoated portions of pipe segments were not exactly known prior to any indirect inspections occurring.This further complicated the process as the resultant would have to be an overlap in the indirect inspectiontools utilized for coated piping and those utilized for uncoated piping. Data interpretation of the indirectinspection tool results within the overlap areas would have resulted in the possibility of unnecessary ormissed excavations due to this uncertainty.Approximated costs of $25,000 to $50,000 dollars per excavation can occur, dependent on the areas beingexcavated and the amount to of corrosion discovered on the piping. With the large estimated investment inexcavations and analysis on the uncoated pipe segments, it was determined that NiSource needed visualevidence of the mainline coating types and their extents within each of the HCA’s classified as havingportions of uncoated piping. NiSource conducted Keyhole (Vac Truck) excavations along these HCA’s."Keyholing" is the process of making a small, precisely controlled excavation to access buried utilities, forthe purpose of locating, inspecting, or to performing repairs, maintenance, and installation of utilityfacilities with the use of specialized tools. See Illustration 1 for an example of the process. Keyholetechnology allows utilities and their contractors to cost-effectively expose and perform repair andmaintenance work on their underground pipe and other facilities without resorting to more costly anddisruptive conventional excavation methods. Conventional practices—usually performed using severallarge pieces of equipment (backhoes, dump trucks, pavement breakers, etc.)—can account for a significantamount of time and labor relating to a repair job. The Keyhole excavations and inspections that occurredthereafter, actually verified that several of the HCA’s classified as uncoated had various types of mainlinecoatings intact such as coal tar, fusion bond epoxy, asphalt enamel, and extruded polyethelene.By determining that several of the areas in fact did contain mainline coatings, traditional indirect inspectiontools were feasible in evaluating the various HCA’s from an ECDA standpoint. If during the keyholeexcavation it was determined that uncoated piping existed, those pipe segments were taken out of theECDA program and were selected for sections of pipe replacement within an upcoming NiSource capitalbudget project. The sites that did remain in the ECDA program were updated in the Facility database withthe correct coating type and further validated the ECDA process and the full life cycle of the company’sGIS database. 2) The indirect inspection step is the overall result of threat and risk assessment output from the respective models. From these outputs the pipeline is dynamically segmented into corrosion regions, appropriate tools are selected for field surveys, data gaps that can be eliminated through field acquisition are identified, the prioritized schedule is set, and the field logistics are addressed. This step is typically very heavily dependent on use of a GIS Database and the quality of data contained therein, as it is usually the means relied upon to get crews out to the correct locations to be assessed. It is also critical to provide “as expected” conditions so that comparison can be validated with “as-found” conditions, as a means of continuous improvement of data, lending itself to better decision-making through the remainder of the Page 4 of 17

process. Impact on threat and risk assessment may also need to be re-visited based on differences identified between field verified and records related data used prior to this step. All of this information determines tools and severity matrices to be utilized during the data analysis of the indirect inspection results.Case Study: Known Cathodic Protection Current SourcesA common method for detecting the polarized potential of a buried pipe which is cathodically protected byrectified alternating current impressed upon the pipe is to have each rectified protection current periodicallypulsed to an off state for a precise pulse duration and pulse period which are integral multiples of the periodof the alternating current. The potential between the pipe and a reference electrode at the test site issampled and analyzed to detect the polarized potential. It is analyzed to find the area under the portion ofthe waveform during which no off pulses are present and to use that area to detect the on potential. The areawithin the off pulses, after reactive spikes are eliminated, is subtracted from the on potential area todetermine the IR drop potential. The IR drop potential is then subtracted from the on potential and thedifference is displayed as the polarized potential.A CLOSE-INTERVAL SURVEY (CIS) is a series of structure-to-electrolyte direct current (dc) potentialmeasurements performed at regular intervals for assessing the level of cathodic protection (CP) onpipelines and other buried or submerged metallic structures (Illustration 2). Within the industry, the termsclose-interval survey (CIS) and close-interval potential survey (CIPS) are used interchangeably. Types ofCIS include: 1) On survey, data collection with the CP systems in operation 2) Interrupted or on/offsurvey, a survey with the CP current sources synchronously interrupted 3) Asynchronously interruptedsurvey, a close-interval survey with the CP current sources interrupted asynchronously, using the waveformanalyzer technique 4) Depolarized survey, a close-interval survey with the CP current sources turned offfor some time to allow the structure to depolarize 5) Native-state survey, data collection prior to applicationof CP Hybrid surveys, close-interval surveys incorporating additional measurements such as lateralpotentials, side-drain gradient measurements (intensive measurement surveys), or gradient measurementsalong the pipeline The term CIS (or CIPS) does not refer to surveys such as cell-to-cell techniques used toevaluate the direction of current (hot-spot surveys, side-drain surveys) or the effectiveness of the coating(traditional direct current voltage gradient, DCVG). Typical CIS graphs are shown for a fast-cycleinterrupted survey combined with a depolarized survey to evaluate a minimum of 100 mV of cathodicpolarization and a slow-cycle interrupted survey. Close-interval survey is used to assess the performanceand operation of a CP system in accordance with established industry criteria for CP such as those inNACE International Standard RP0169. The -850 mV criteria are indicated in Illustration 2. Close-intervalsurvey is one of the most versatile tools in the CP toolbox and, with new integrity assessment procedures,has become an integral part of the pipeline integrity program. Close-interval survey data interpretationprovides additional benefits, including: Identifying areas of inadequate CP or excessive polarization:locating medium-to-large defects in coatings on existing pipelines; locating areas of stray-current pickupand discharge; identifying possible shorted casings; locating defective electrical isolation devices; detectingunintentional contact with other metallic structures; testing current demand and current distribution along apipeline.There are three criteria recognized by NACE International RP0169-96 for corrosion control of buried orsubmerged structures. (1) Those are (a) the -850 mV (Cu/CuSO4) potential criterion with correction for IRdrops, (b) the -850 mV (Cu/CuSO4) polarized potential criterion, and (c) the 100 mV polarization criterion.Of those three, the -850 mV polarized potential and the -850 mV IR corrected potential are presently themost widely used for corrosion control of buried and immersed structures. There are many reasons for theirpopularity. Among them are the relative ease of measurement and attainment, especially on structures withgood anti-corrosion coatings. However, as the structures to which these criteria are being applied age andcoatings degrade, increased current demand makes attaining either of these criteria more difficult becauseof the cost of additional cathodic protection and monitoring. For the purposes of the NiSource ECDAprogram indirect inspections and data analysis the -850mV polarized potential criteria was utilized.Existing GIS and other data sets along with subject matter expert questionnaires revealed that the (CP)current sources affecting several pipelines within the ECDA program were not all known prior to theindirect inspections occurring. Documentation of the influencing current sources are pertinent as it allowsfor data analyses to occur from a corrosion prevention cathodic protection standpoint of how much directcurrent polarization has occurred with CP systems when energized. Not knowing the exact locations of all Page 5 of 17

the CP current sources resulted in performing close interval survey (CIS) indirect inspections with allcurrent sources “On” and uninterrupted (which typically allows one to measure instant “Off” pipe to soilpotential measurements).Several of the HCA’s on two of the pipeline segments were said to have had 14 known current sourcesaffecting the areas to be evaluated via the ECDA process. Once the indirect inspection CIS surveys began,it was obvious additional current sources were affecting the pipeline segments being surveyed. Severalweeks of additional troubleshooting occurred on other various NiSource CP systems as well as otherforeign pipeline operator systems.Utilizing NiSource’s field gathered GPS coordinates of existing CP rectifier assets and foreign linecrossings overlaid into satellite imagery mapping programs a visual estimation was made of what possibleCP current sources were affecting the indirect inspection CIS surveys within an ~ 25 mile circumference.Approximately 40 additional current sources were then identified and a testing program developed todetermine their potential for producing current sources influencing the HCA’s. One by one the additionalindividual current sources were tested for influence. Of these an additional 7 were found to have in factproduced currents affecting the surveys along the HCA’s, all of which were assets owned and operated byNiSource on various piping systems.Knowing for certain what current sources affect the CP systems on pipeline segments proves to beinvaluable when utilizing ECDA as an integrity assessment. The CP influencing testing results has beenupdated into the NiSource databases. If the CP assets had been incorporated into the existing GIS databaseprior to the indirect inspections, a simple query could have been ran to find out how many CP currentsource assets were within the ~25 mile diameter circumference. The information discovered during theinfluence testing could have been uploaded into the existing GIS database and utilized during any suchfuture CIS assessments. 3) The direct examination step is based on the findings, characterizations and prioritizations associated with the indirect inspection step. A very detailed, technically sound process algorithm must be developed, applied, and continually refined in order to identify locations to be inspected based on highest probability of corrosion damage occurring (or having occurred in the past), as well as identifying areas that need to be addressed to prevent corrosion occurring in the future. It is critical that the data acquired during this step be compared with the “as-expected” data provided through the previous steps and the anomaly classifications and prioritizations re-evaluated based on actual severity discovered. If there are significant differences, or unexpected findings, then the accuracy of the algorithm used for original classification and prioritization must be challenged and adjusted accordingly. Never blindly accept that a “black box” approach meets the unique conditions for each specific pipeline segment being assessed.Case Study: Casing in the GIS Database but not identified in the ProgramThe pipeline workforce has a disparity between generations, spanning the entire industry, based on age ofthe infrastructure and the many acquisitions and mergers that have taken place in the last 20 years. This isa key piece of information when looking for validation of what a company has in their GIS database andwhat a company has in the way of practical/operational validation of the data.In Direct Assessment, Step 3 takes it direction from Step 2 and Step 2 tools are determined based on Step 1research. DA is a fundamentally straight forward process to follow and easily defended when appliedproperly. So when Willbros and NiSource began the research process of Step 1 and utilizing the SME(Subject Matter Expert) information, there were areas of interest that did not show up in the operationalarena but did exist in the GIS Database.The GIS Database called out a 20” casing from 1323+64 to 1323+84 (roughly 18’) within one of theHCA’s that was to be addressed. Following procedure and made the appropriate site visits were made butno evidence indicated the presence of a casing other than the information in the GIS Database. Thelocation of the casing, based on the inventory stations, was in a grassy area between a public road and apaved parking lot. It was determined by NiSource to continue with the Direct Assessment method but uponour Step 3 investigations, we would excavate and make the final determination regarding the existence of acasing. It was conceivable that a casing could have been installed due to the close proximity to a road butno vent pipes or marking that are typical of a cased crossing existed. Some old construction notes were Page 6 of 17

discovered that showed a casing installed at a sewer line crossing and local Operations personnel said thatthey had heard that this was a practice in this area when this pipeline was built.In the “Dig” Selection process of Step 2, Willbros noted this was an area that we would look to select if avalidation dig was required. The opportunity to select that “exact” location did not occur but we did fallwithin roughly 60’ of the dig site and the casing. The excavation of the dig site proved to be spot on andthe GIS Database proved to be correct. A casing existed and was roughly measured 7 feet 3 inches, whichis indicative of a reroute of the existing road with the pipeline no longer under the road. The casing lengthwas not accurate in the GIS Database but the location was identified and the casing was removed, and themainline pipe inspected, blasted and recoated.Illustrations 3 – 6 provide some more interesting aspects that we experienced in the field activities. It wasdetermined that the “spacers” for the casing were bricks that are depicted in accompanying photos.As part of the final product delivered to NiSource, the retirement and removal of the casing was addressedin the GIS Database as part of the “As-Built” process. This back and forth of information between theproject and the database is essential to taking advantage of the information discovered during an assessmentproject. 4) The post assessment step is the culmination of all findings and analyses associated with the three previous steps. All verification and validation efforts, reviews, and quality control measures, if conducted thoroughly, should contribute to make this a very straightforward step in the process. A final “common-sense” review must occur considering the entirety of the project, so that the proper path forward can be established and defended with confidence and assurance of integrity related conditions. If remaining data gaps are identified, the mechanism for addressing them must be established prior to completion of this step. Major assumptions should be largely unnecessary at this point, especially with respect to any data elements considered critical to the integrity decision-making and monitoring processes. Effective integration of the data contained within the GIS, while arguably extremely critical in the previous three steps, is absolutely essential at this point. All final analyses and decisions affecting life of pipe integrity depend on the quality and accuracy of the data.Case Study: Adjustment of the NiSource Centerline based on the Step 2 PCM Indirect InspectionA GIS Database is as accurate as an operator’s documentation to track or validate the information. Thefocus of a company’s GIS Database was significantly focused on the “XY” or GPS location of the pipelinefor many years and is significantly shifting to the “data” or what is under the ground as opposed to theexact location of where the attribute exists in the world. This project addressed a fragment of each of theseefforts.The location for NiSource’s pipelines is continually being refined based on more accurate information.This was no exception in this effort as it related to the Step 2 results obtained from the PCM surveys.Willbros currently has reviewed the PCM information as it relates to the adjustment of the centerline forNiSource and has currently adjusted roughly 8 of their pipelines in 17 locations. This process will continueas Willbros completes additional HCA’s as outline in NiSource’s DA program.In Illustrations 7 and 8, Willbros provides examples of NiSource’s system that were adjusted based oninformation collected in Step 2 from the PCM information and can affect the Step 4 analysis for the HCA’s.The discovery along all the steps in DA will ultimately influence and be a final factor to the Step 4recommendations.In summary, there has never been a time when pipeline safety and reliability has received so much publicand regulatory scrutiny, and the need for efficient, effective and verified information management forcompliance is greater than ever. The purpose of all assessment activities associated with pipeline integrityis simply the means to acquire enough information to allow operators to make sound, well-informeddecisions regarding the ongoing safe and reliable operations of their pipeline assets.Reliable and defendable decisions are based on reliable, complete data, and conversely deficient decisionsare based on incomplete or inadequate data. No matter the assessment method that an operator selects, theGIS data is the key to benchmarking and moving forward to future assessments. The effort to improve thedata that an operator has in their Facility/GIS database is a byproduct or bonus that should be takenadvantage of and updated as the final step to each post assessment process. Page 7 of 17

A stitch in time….an effort that all operators are realizing the value in this mending of information todocumentable and fact based data that an operator can point back to a common thread of traceable history. Page 8 of 17

Table 1Information from NiSource GIS Database and Field Verification Uncoated (bare)Date Number of HCAs Segments # of Casings # of Regions Number of Digs2/14/2011 42 8 14 64 2282/21/2011 43 9 14 66 2364/11/2011 35 9 14 58 2047/6/2011 36 7 24 67 22012/19/2011 48 5 7 60 226Regions = 4 digsCasings Regions = 2 digsHCAs + # Casings + # Bare = # Regions(HCAs + Uncoated * 4)+(Casings*2) = Digs Page 9 of 17

Illustration 1Step 1: Keyhole Excavation ExampleIllustration 2Step 1: Close-Interval Survey Page 10 of 17

Illustration 3Step 3: Discovery of Casing – 20” casing – 12” pipeline Page 11 of 17

Illustration 4Step 3: Uncovering of the casing – Bricks utilized spacers Page 12 of 17

Illustration 5Step 3: Casing measured at 7 ft 3 in Page 13 of 17

Illustration 6Step 3: Casing removed, blasted and recoated Page 14 of 17

Illustration 7Step 4: Centerline adjustment – Blue is where the centerline was moved based on Step 2surveys and the Red line is where the original centerline existed from the digitizationprocess from the maps. The largest adjust length was measured to be roughly 35 feetfrom the original centerline. Page 16 of 17

Illustration 8Step 4: Centerline adjustment – Blue is where the centerline was moved based on Step 2surveys and the Red line is where the original centerline existed from the digitizationprocess from the maps. The heavy set blue line is attributed to the PCM survey and wasutilized to further adjust the extends of the pipeline segment. Page 17 of 17

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