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Pipeline Pigging and Integrity Management Conference

NiSource 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 ASSESSMENT

Current integrity management regulations for transmission pipelines permit four inspection methods for pipelines:

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. This method is often only considered due to the potentially high cost of a retrofit for smart pigging, the lack of sufficient pipeline pressure or flow to run a smart pig, or the “single feed” of supply that this pipeline may provide such that it cannot be taken out of service for a pressure test or wireline assessment. DA can be the shining star as an assessment method for the aforementioned scenarios. An operator is in business to move product, and the explanation to their customers that they need to take a section out of service, while required, 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 for Direct Assessment of Gas and Hazardous Liquid Pipelines:

SUMMARY: Under current regulations governing integrity management of gas transmission lines, if an operator uses direct assessment to evaluate corrosion risks, it must carry out the direct assessment according to PHMSA standards. In response to a statutory directive, this Final Rule prescribes similar

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standards operators must meet when they use direct assessment on certain other onshore gas, hazardous liquid, and carbon dioxide pipelines. PHMSA believes broader application of direct assessment standards will 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 Standard RP0502-2002 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 external corrosion, 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. Operators use direct assessment not only to find existing corrosion defects but also to prevent future corrosion problems.

Congress recognized the advantages of using direct assessment on U.S. Department of Transportation (DOT) regulated gas, hazardous liquid, and carbon dioxide pipeline facilities. Section 14 of the Pipeline Safety Improvement Act of 2002 (Pub. L. 107-355; Dec. 17, 2002) directs DOT to issue regulations on using internal inspection, pressure testing, and direct assessment to manage the risks to gas pipeline facilities in high consequence areas. In addition, Section 23 directs DOT to issue regulations prescribing standards for inspecting pipeline facilities by direct assessment.

In response to the first statutory directive, Section 14, DOT's Research and Special Programs Administration (RSPA)1 published regulations in 49 CFR part 192, subpart O, that require operators to follow detailed programs to manage the integrity of gas transmission line segments in high consequence areas. Subpart O also requires an operator electing to use direct assessment in its integrity management program, to carry out the direct assessment according to §§ 192.925, 192.927, and 192.929, as appropriate.2

Sections 192.925, 192.927, and 192.929 cross-reference the American Society of Mechanical Engineers' (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 gas pipeline risks. In addition, §192.925 cross-references a NACE International (NACE) standard, NACE Standard RP0502-2002, “Pipeline External Corrosion Direct Assessment Methodology.'' NACE Standard RP0502-2002 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 ensure operators 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) reorganized RSPA into two new DOT administrations: the Pipeline and Hazardous Materials Safety Administration (PHMSA) and the Research and Innovative Technology Administration. RSPA's regulatory authority over pipeline and hazardous materials safety was transferred to PHMSA. 2 The standard on external corrosion direct assessment § 192.925) requires operators to integrate data on physical characteristics and operating history, conduct indirect aboveground inspections, directly examine pipe surfaces, and evaluate the effectiveness of the assessment process. Under the standard for direct assessment of internal corrosion (§ 192.927), operators must predict locations where electrolytes may accumulate in normally dry-gas pipelines, examine those locations, and validate the assessment process. The standard for direct assessment of stress corrosion cracking (§ 192.929) involves collecting data relevant to stress corrosion cracking, assessing the risk of pipeline segments, and examining and evaluating segments at risk.

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DA is currently the only proactive method of pipeline integrity assessment, as it looks at the environment surrounding the pipeline and identifies the locations where corrosion activity, past, present, and future, is probable. The other assessment methods address similar as well as additional threats but only identify what has already occurred on the pipe, providing a snapshot of current conditions without consideration for conditions surrounding the pipe. Without acquiring data typically associated with DA activities, it is difficult, if not impossible, to have enough appropriate information to make sound root cause and preventive and mitigative decisions.

In this paper we will be concentrating on the External Corrosion Direct Assessment (ECDA) method which effectively 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 coating penetrations from rocks, poor pipe installation, coating deterioration with time, and from many types of third party damage. The case study presented herein will demonstrate how the acquisition, integration and verification of data to continually improve an operator’s GIS system are instrumental in each step of the process.

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 steps

Each step has intensive data management requirements associated with it and invalid assumptions and ineffective data quality control methods can lead to incorrect or inappropriate results which propagate throughout the entire process. The purpose of integrity management is to know as much as is necessary about a pipeline to manage and operate it safely and reliably. That knowledge is gained through effective and continual mining, management and validation of data. Defendable integrity decisions are based on documentable, complete data, and conversely unsubstantiated decisions are based on incomplete and undocumented 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 the course to meet the infamous December 17, 2012 date for pipeline integrity industry compliance. It is important to emphasize that all the way through the DA process NiSource has strived to continuously validate their decision to utilize DA and as well compare what is in the GIS to what is really found in the ground. This validation of the DA process and the updating of the GIS have led to a growing confidence in the use of DA as an assessment method and an increased knowledge of the pipeline segments being investigated.

Case Study: Uncoated (bare) Pipe vs. Coated Pipe

The mining of data for any project can be an enlightening and educational process that allows an operator to do a gut check of their GIS database. This project was no different and had a positive upside for NiSource in validating data. Field verification and in depth document research led to substantial determination that the majority of the scheduled HCA’s would remain in the DA program while some others would be removed. The HCA’s that were field verified as being uncoated were placed by NiSource into their capital budget “pipe replacement” program as a prudent operator. The reality is that DA is not a

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silver bullet for every non-piggable segment and the decision to use DA needs to be questioned and reevaluated 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 what the overall integrity threat may be. During the initial building of the GIS database for the NiSource piping systems, several areas of unknown mainline coatings occurred. It was established that as a “worst” case scenario, the unknown coating types would be classified as “Bare” uncoated piping. As this methodology works sufficiently for industry required monitoring practices, applying ECDA to these areas proves to be complicated due to the unknowns.

Please see Table 1 for a brief timeline of how the team continued to research the HCA’s to ensure that NiSource 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 with some HCA’s being rather short in length and if they proved to be bare – NiSource determined that a potential 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, specific tools, procedures, and data evaluation techniques were developed in order for preparation of the indirect inspections on the uncoated portions of piping within the various HCA’s. The exact extents of the uncoated 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 inspection tools utilized for coated piping and those utilized for uncoated piping. Data interpretation of the indirect inspection tool results within the overlap areas would have resulted in the possibility of unnecessary or missed excavations due to this uncertainty.

Approximated costs of $25,000 to $50,000 dollars per excavation can occur, dependent on the areas being excavated and the amount to of corrosion discovered on the piping. With the large estimated investment in excavations and analysis on the uncoated pipe segments, it was determined that NiSource needed visual evidence of the mainline coating types and their extents within each of the HCA’s classified as having portions 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, for the purpose of locating, inspecting, or to performing repairs, maintenance, and installation of utility facilities with the use of specialized tools. See Illustration 1 for an example of the process. Keyhole technology allows utilities and their contractors to cost-effectively expose and perform repair and maintenance work on their underground pipe and other facilities without resorting to more costly and disruptive conventional excavation methods. Conventional practices—usually performed using several large pieces of equipment (backhoes, dump trucks, pavement breakers, etc.)—can account for a significant amount of time and labor relating to a repair job. The Keyhole excavations and inspections that occurred thereafter, actually verified that several of the HCA’s classified as uncoated had various types of mainline coatings 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 inspection tools were feasible in evaluating the various HCA’s from an ECDA standpoint. If during the keyhole excavation it was determined that uncoated piping existed, those pipe segments were taken out of the ECDA program and were selected for sections of pipe replacement within an upcoming NiSource capital budget project. The sites that did remain in the ECDA program were updated in the Facility database with the correct coating type and further validated the ECDA process and the full life cycle of the company’s GIS 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

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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 Sources

A common method for detecting the polarized potential of a buried pipe which is cathodically protected by rectified alternating current impressed upon the pipe is to have each rectified protection current periodically pulsed to an off state for a precise pulse duration and pulse period which are integral multiples of the period of the alternating current. The potential between the pipe and a reference electrode at the test site is sampled and analyzed to detect the polarized potential. It is analyzed to find the area under the portion of the waveform during which no off pulses are present and to use that area to detect the on potential. The area within the off pulses, after reactive spikes are eliminated, is subtracted from the on potential area to determine the IR drop potential. The IR drop potential is then subtracted from the on potential and the difference is displayed as the polarized potential.

A CLOSE-INTERVAL SURVEY (CIS) is a series of structure-to-electrolyte direct current (dc) potential measurements performed at regular intervals for assessing the level of cathodic protection (CP) on pipelines and other buried or submerged metallic structures (Illustration 2). Within the industry, the terms close-interval survey (CIS) and close-interval potential survey (CIPS) are used interchangeably. Types of CIS include: 1) On survey, data collection with the CP systems in operation 2) Interrupted or on/off survey, a survey with the CP current sources synchronously interrupted 3) Asynchronously interrupted survey, a close-interval survey with the CP current sources interrupted asynchronously, using the waveform analyzer technique 4) Depolarized survey, a close-interval survey with the CP current sources turned off for some time to allow the structure to depolarize 5) Native-state survey, data collection prior to application of CP Hybrid surveys, close-interval surveys incorporating additional measurements such as lateral potentials, side-drain gradient measurements (intensive measurement surveys), or gradient measurements along the pipeline The term CIS (or CIPS) does not refer to surveys such as cell-to-cell techniques used to evaluate 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-cycle interrupted survey combined with a depolarized survey to evaluate a minimum of 100 mV of cathodic polarization and a slow-cycle interrupted survey. Close-interval survey is used to assess the performance and operation of a CP system in accordance with established industry criteria for CP such as those in NACE International Standard RP0169. The -850 mV criteria are indicated in Illustration 2. Close-interval survey 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 interpretation provides 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 pickup and discharge; identifying possible shorted casings; locating defective electrical isolation devices; detecting unintentional contact with other metallic structures; testing current demand and current distribution along a pipeline.

There are three criteria recognized by NACE International RP0169-96 for corrosion control of buried or submerged structures. (1) Those are (a) the -850 mV (Cu/CuSO4) potential criterion with correction for IR drops, (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 the most widely used for corrosion control of buried and immersed structures. There are many reasons for their popularity. Among them are the relative ease of measurement and attainment, especially on structures with good anti-corrosion coatings. However, as the structures to which these criteria are being applied age and coatings degrade, increased current demand makes attaining either of these criteria more difficult because of the cost of additional cathodic protection and monitoring. For the purposes of the NiSource ECDA program 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 the indirect inspections occurring. Documentation of the influencing current sources are pertinent as it allows for data analyses to occur from a corrosion prevention cathodic protection standpoint of how much direct current polarization has occurred with CP systems when energized. Not knowing the exact locations of all

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the CP current sources resulted in performing close interval survey (CIS) indirect inspections with all current sources “On” and uninterrupted (which typically allows one to measure instant “Off” pipe to soil potential measurements).

Several of the HCA’s on two of the pipeline segments were said to have had 14 known current sources affecting 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. Several weeks of additional troubleshooting occurred on other various NiSource CP systems as well as other foreign pipeline operator systems.

Utilizing NiSource’s field gathered GPS coordinates of existing CP rectifier assets and foreign line crossings overlaid into satellite imagery mapping programs a visual estimation was made of what possible CP 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 to determine their potential for producing current sources influencing the HCA’s. One by one the additional individual current sources were tested for influence. Of these an additional 7 were found to have in fact produced currents affecting the surveys along the HCA’s, all of which were assets owned and operated by NiSource on various piping systems.

Knowing for certain what current sources affect the CP systems on pipeline segments proves to be invaluable when utilizing ECDA as an integrity assessment. The CP influencing testing results has been updated into the NiSource databases. If the CP assets had been incorporated into the existing GIS database prior to the indirect inspections, a simple query could have been ran to find out how many CP current source assets were within the ~25 mile diameter circumference. The information discovered during the influence testing could have been uploaded into the existing GIS database and utilized during any such future 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 Program

The pipeline workforce has a disparity between generations, spanning the entire industry, based on age of the infrastructure and the many acquisitions and mergers that have taken place in the last 20 years. This is a key piece of information when looking for validation of what a company has in their GIS database and what 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 1 research. DA is a fundamentally straight forward process to follow and easily defended when applied properly. 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 operational arena 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 the HCA’s that was to be addressed. Following procedure and made the appropriate site visits were made but no evidence indicated the presence of a casing other than the information in the GIS Database. The location of the casing, based on the inventory stations, was in a grassy area between a public road and a paved parking lot. It was determined by NiSource to continue with the Direct Assessment method but upon our Step 3 investigations, we would excavate and make the final determination regarding the existence of a casing. It was conceivable that a casing could have been installed due to the close proximity to a road but no vent pipes or marking that are typical of a cased crossing existed. Some old construction notes were

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discovered that showed a casing installed at a sewer line crossing and local Operations personnel said that they 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 a validation dig was required. The opportunity to select that “exact” location did not occur but we did fall within roughly 60’ of the dig site and the casing. The excavation of the dig site proved to be spot on and the GIS Database proved to be correct. A casing existed and was roughly measured 7 feet 3 inches, which is indicative of a reroute of the existing road with the pipeline no longer under the road. The casing length was not accurate in the GIS Database but the location was identified and the casing was removed, and the mainline pipe inspected, blasted and recoated.

Illustrations 3 – 6 provide some more interesting aspects that we experienced in the field activities. It was determined 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 addressed in the GIS Database as part of the “As-Built” process. This back and forth of information between the project and the database is essential to taking advantage of the information discovered during an assessment project.

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 Inspection

A GIS Database is as accurate as an operator’s documentation to track or validate the information. The focus of a company’s GIS Database was significantly focused on the “XY” or GPS location of the pipeline for many years and is significantly shifting to the “data” or what is under the ground as opposed to the exact location of where the attribute exists in the world. This project addressed a fragment of each of these efforts.

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 for NiSource and has currently adjusted roughly 8 of their pipelines in 17 locations. This process will continue as 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 on information 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 4 recommendations.

In summary, there has never been a time when pipeline safety and reliability has received so much public and regulatory scrutiny, and the need for efficient, effective and verified information management for compliance is greater than ever. The purpose of all assessment activities associated with pipeline integrity is simply the means to acquire enough information to allow operators to make sound, well-informed decisions regarding the ongoing safe and reliable operations of their pipeline assets.

Reliable and defendable decisions are based on reliable, complete data, and conversely deficient decisions are based on incomplete or inadequate data. No matter the assessment method that an operator selects, the GIS data is the key to benchmarking and moving forward to future assessments. The effort to improve the data that an operator has in their Facility/GIS database is a byproduct or bonus that should be taken advantage of and updated as the final step to each post assessment process.

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

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Table 1 Information from NiSource GIS Database and Field Verification

Date Number of HCAs

Uncoated (bare) Segments # of Casings # of Regions Number of Digs

2/14/2011 42 8 14 64 228 2/21/2011 43 9 14 66 236 4/11/2011 35 9 14 58 204 7/6/2011 36 7 24 67 220 12/19/2011 48 5 7 60 226

Regions = 4 digs Casings Regions = 2 digs

HCA's + # Casings + # Bare = # Regions (HCA's + Uncoated * 4)+(Casings*2) = Digs

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Illustration 1 Step 1: Keyhole Excavation Example

Illustration 2

Step 1: Close-Interval Survey

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Illustration 3

Step 3: Discovery of Casing – 20” casing – 12” pipeline

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

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Illustration 5 Step 3: Casing measured at 7 ft 3 in

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Illustration 6 Step 3: Casing removed, blasted and recoated

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

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