Encouraging Innovation in Locating and Characterizing Underground Utilities (2009)

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38C H A P T E R 5 Utility Characterization TechnologiesIntroduction “Utility characterization” is the determination of a utility’s characteristics other than its location. These characteristics include the type of utility, the type of material it is made of, owner, size, age, pressure, voltage, capacity, condition, and usage status, which is to say whether it is inactive, abandoned, out of service, or active. A utility’s condition can be further subdivided into its cathodic state for metallic utilities, its pipe- wall thickness, its internal and external corrosion, its wrapping and coating integrity, and its physical condition, including breaks, tears, and gouges. Within the locating industry there is no standard governing the collection of this type of data, nor is there a standard among, or within, various utility agencies. For transportation agencies trying to identify existing and poten- tial utility problems for routine management purposes or for new-project planning, this means that the characterization data that is sought should be clearly detailed in any scope of work to ensure that the appropriate data is, in fact, collected. Currently, the greatest advances in characterization technology and analysis probably have to do with oil and gas pipelines, which must be regularly inspected, and for which the Pipeline and Hazardous Materials Safety Administration (PHMSA) or related agencies have established reporting standards to avoid pipeline failures and to implement effective life-cycle manage- ment practices. Existing records are the easiest and probably the most accu- rate way to determine much of the basic information about a utility. With the exception of information on a utility’s cur- rent condition and use, most of its characteristics may be included in the original utility record. The record may then be amended as utility sections are replaced, moved, repaired, or abandoned. Even the utility’s current condition could poten- tially be inferred from repair, maintenance, age, or material- type records. Existing records may reveal a utility’s age, although forensic techniques that analyze manufacturing vari- ations and property data may also establish a utility’s origin andage. In short, because records may be lost, unavailable, or trans- lated to a different medium or may exclude appropriate char- acterization data, other methods must be available to augment records in determining the characteristics for utilities. A description of some of these methods follows. An exposed utility offers direct access to determine many of the utility’s characteristics. The utility type, material type, encasement type, size, condition, voltage, pipe-wall thickness, and number of wires or conduits can all be directly observed, inferred, or measured with appropriate instruments. Instru- mentation may be used to infer whether the utility is inactive, abandoned, or out of service, but usually the utility owner must definitively confirm this through a physical inspection, such as by tapping on the pipe. Internal inspections, such as in-line inspection, can also be useful for determining some pipeline characteristics, such as pipe material, pipe geometry, pipe wall condition, leakage areas, and obstructions to flow. Inside the utility, cameras can be used for visual observation, lasers for interior pipe-wall sur- face distance measurements, and a variety of internal geophys- ical methods for determining pipe-wall thickness, corrosion, and exterior surface condition. Although external inspection of an exposed utility allows these determinations to be made, internal inspection allows for a continuous, less-intrusive means of characterizing many aspects of the utility. Internal inspection requires access from one or both ends of a utility section. The pipe’s size and condition, the presence of bends, a lack of access, and health issues may preclude internal inspec- tion using some or all of the available methods. However, an internal inspection’s most important feature is that it can be part of an unobtrusive and ongoing utility asset management practice that tracks utility performance and condition data. Such data, when effectively used, minimizes unexpected fail- ures and allows for the most cost-effective life-cycle manage- ment decisions to be made about the timing and extent of utility repair and replacement. Effective decisions about whether to repair or replace utilities can be made during the

39planning and design process for new transportation projects when such data is available and being used. Surface geophysical methods, many similar to or the same as those described in chapter 4, may be effective for some characterizations. In some cases, utility type, material, and some aspects of condition can be inferred using these meth- ods, although the conditions under which such inferences can be made from surface-based surveys are limited and specific. What follows are details on some surface geophysical char- acterization methods that may be used, either through the utility’s direct exposure or through internal inspection. Determining Characteristics from Physical Inspection General Characteristics Ownership Ownership cannot generally be inferred directly from a physi- cal inspection unless an ownership tagging or identification system was used during construction or repair. Examples of such systems include colored pipes or colored markers for dif- ferent utility systems (a standard color scheme is now in wide- spread use) or physically imprinted markings along the pipe system at selected intervals or at various appurtenances. Older piping systems often are less easily identifiable. There is also the possibility that ownership or some other aspect of the system has changed since a physical marker was installed. Ownership of a site-identified utility is typically determined through a comparison with utility map records or through detective work to identify the utility and contact potential utility companies for a positive identification. From a surface survey, only the newer types of utility-marking systems, such as marker balls and radio frequency identification (RFID) tagging, offer the desired information quality. Type of Utility When a previously undetected pipe or cable is discovered on site, it is important to determine its purpose to help identify its owner and the potential risks of working around it. For some pipes or cables, the pipe’s color coding, markings, or material will help in identifying its purpose. For example, a clay pipe is principally for sanitary sewer or drainage purposes. For pipes made from steel, cast iron, or other material, or for unmarked cables or cable ducts, additional investigation may be required to determine whether the pipe carries water, gas, or oil or whether the cable carries electricity, data signals, or optical fiber transmissions. Some determinations are fairly easily made in the field once the pipe or cable is exposed. For instance, a live electric conductor can be identified by its electromagnetic (EM) field; the absence of metal in a cable would indicate afiber optic cable with no metal sheathing. A gas pipe may have detectable leakage from pipe joints or other defects. If a pipe can be traced to an identifiable appurtenance, such as a valve or hydrant, then the nature of the pipe can be established. There is no consistent means to identify the utility type from a surface survey without the use of utility-marking systems, except in the case of electric cables. If it is urgent that a previ- ously unknown pipe be identified, then a small hole may be drilled into the pipe to determine the type of fluid or gas car- ried. It is more difficult to identify abandoned or temporarily unused utilities. Usage Status Determining whether a utility is in use, inactive, out of service, or abandoned follows steps similar to those used to determine the utility type or owner, as previously discussed. An active EM field created by a live conductor or the presence of noise or vibrations caused by a flowing liquid within a pipe may indi- cate that the utility is live. Determining whether a utility is abandoned, out of service, or simply inactive, however, may be impossible. Thus, to ensure safety, utilities should be con- sidered live until proven otherwise. In most cases, it is neces- sary to identify the utility owner to confirm a utility’s usage status because surface surveys may give incorrect usage status information. For instance, a field marker may not have been updated to reflect a change in the utility’s status. Physical Characteristics Utility Size and Material A utility’s size and materials may be readily determined once the pipe or cable has been physically exposed. In some cases, inferences about pipe size and material may be made using some of the utility locating approaches described in the previ- ous chapter. However, precise size measurements and differ- ences between relatively similar materials, such as steel and cast iron or clay and unreinforced concrete, are not possible using the locating equipment currently available. Remember that many utilities are not consistent in the types of material used along its length, that sections may be replaced with different materials, and that repairs may alter the utility’s local diameter and other characteristics. Flow Characteristics It is generally important to ascertain the flow characteristics of a buried utility to assess construction risk or design for any planned relocation. Flow characteristics for electrical conduc- tors mean the cable’s voltage, whether there is alternating or direct current, and the number of phases used. For piping

40systems, this means the pipe’s operating pressure, any expected pressure fluctuations, and the pipe’s flow capacity and veloc- ity. For gravity systems, the pipe gradient is critical, and it is important to know whether the system is likely to be sur- charged at intervals (that is, operate temporarily under pres- sure). Among the pipe characteristics, it is important to know the pipe’s maximum allowable operating pressure (MAOP) adjusted to the pipe’s current structural condition. The char- acteristics of electrical conductors are more easily measured in the field than those of other utility types, especially if the elec- trical conductor can be encircled. If the pipe is fully exposed, water flow can be measured nondestructively using special equipment. For instance, to determine fluid or gas pressure, pipe tapping can be used. In general, however, external inspec- tion or surface survey cannot determine a utility’s actual-flow and design-flow characteristics. The utility owner must be con- tacted for this information. The availability of utility failure statistics, such as water-line breaks, and past-condition survey information may be important to establish the adequacy of a line that is to be buried beneath a new roadway. Such infor- mation could also be incorporated into updatable electronic- marking systems, such as the RFID tagging discussed earlier. Age and Condition Although a pipe’s or cable’s approximate age may be established by looking at the particular characteristics of its materials or the method of its installation, in general, utility records must be used to establish age. Some aspects of a utility’s condition may be established visually through an external inspection of an exposed pipe section. For instance, a visual inspection may detect a utility’s cathodic state, any damage to the cable jackets or pipe coatings, any pipe breaks, splits, or gouges, any exter- nal corrosion and pitting, or any delamination. However, hid- den damage or deterioration, such as corrosion within a pipe or a fault within a cable, may be impossible to visually deter- mine. Technologies for determining some aspects of a pipe or cable condition remotely or without involving destruction are described in the next section. For cables, most techniques involve fault-tracing techniques that isolate sections of cable for integrity testing. For buried pipes, most techniques involve internal inspection systems, with confirmation through local- ized excavation and inspection. When a pipe is exposed, some of the same techniques used to examine a pipe from within can be used to examine it from the outside, looking inward through the pipe wall. A particular disadvantage of the exter- nal inspection process is that it is either localized to the test-pit points at which the pipe is exposed, or else entire pipeline sec- tions must be exposed to gain complete coverage. Because deterioration is often not uniform along a pipe’s length, local- ized observation provides only part of the picture of a pipe’s condition.Some aspects of pipe continuity (for example, deteriorated joints in conductive pipes) may be able to be determined using EM tracing surveys, as discussed in chapter 4. However, surface-based surveys in general can provide very little infor- mation that is helpful in determining the age and condition of buried utilities. Inspection of Oil and Gas Pipelines Increasingly, public-safety concerns regarding oil and gas pipelines have encouraged or required the development of improved integrity management programs. These programs aim to prevent structural integrity problems, especially those that damage public safety, business operations, or the envi- ronment. To operate such a program, the physical condition of a pipeline must be evaluated using various combinations of internal inspection, hydrostatic pressure testing, and direct assessment. Because of the risk to the public and the cost of the pipelines, inspection techniques for oil and gas pipelines are well advanced and are the subject of continuing research. For the most part, the techniques apply to larger diameter steel pipelines with a minimum of bends, but they present a good starting point for the review of general pipeline inspection technologies. Internal Inspection In an in-line inspection, a high-tech device known as a smart or intelligent pig is inserted into the pipeline and is propelled by the flowing medium. This smart pig records certain physical data about the pipeline, such as locations of reduced pipe wall thickness, dents, and so forth, as it moves through the pipeline. The ability of smart pigs to find corrosion flaws larger than a certain size makes them extremely valuable for finding flaws before they become critical and cause pipeline failure, either through leak or rupture. Baseline surveys, which are run imme- diately after pipeline installation, not only identify problems associated with the installation but also serve as reference points for comparison with later surveys to project the pipeline’s dete- rioration over time as a result of factors such as corrosion. Since their invention in 1964, smart pigs have undergone several generations of technological advancement. There are now four types of specialized pigs that focus on metal loss inspection, crack inspection, geometry inspection, and map- ping, respectively. Metal Loss Inspections Metal loss in a pipe wall is generally caused by internal or external corrosion, which can be detected through magnetic flux leakage and ultrasonic techniques.

41MAGNETIC FLUX LEAKAGE. The magnetic flux leakage (MFL) tool induces a magnetic field in the pipe and records magnetic flux anomalies as it travels along the pipeline. The recorded mag- netic flux anomalies are converted to information concerning metal loss, including its length and maximum pit depth, which allows for subsequent calculations, using American Society of Mechanical Engineers (ASME) guidelines (1), to determine the pipe’s remaining strength. The technique is popular because it is relatively inexpensive and is well understood. There are two types of these tools, high-resolution MFL and standard-resolution MFL. The main difference between the two is in the number of sensors and the level of resolution. The high-resolution MFL tool is typically capable of readily detect- ing corrosion pits with a diameter greater than three times the wall thickness. Once pits are detected, these tools can typically assess the depth of the corrosion within ±10% of the wall thickness with an 80% level of confidence. Transverse magnetic flux leakage tools have been devel- oped to detect longitudinally long and narrow flaws, such as selective seam corrosions and axial gouges. This kind of tool is similar to the longitudinal MFL tool mentioned earlier; however, the induced magnetic field is in a transverse direc- tion, perpendicular to the longitudinal axis of the pipeline. ULTRASONIC TOOLS. Ultrasonic transducers, also called “UT tools,” use large arrays of ultrasonic transducers to send and receive sound waves that travel through the wall thickness, permitting a detailed mapping of the pipe wall. UT tools can indicate whether the wall loss is internal or external. The typ- ical resolution of a UT tool is ±10% of the pipe wall thickness with an 80% level of confidence. UT tools are typically used in liquid pipelines, such as those carrying crude oil or gasoline, because the liquid in the pipeline acts as the required coupling medium for the ultra- sonic sensors. In gas lines, the tool can be run within a batch of liquid sent through the pipeline. Crack Detection Tools Crack detection is the most challenging task among internal inspection technologies. In the past, no tools were available for this task; hence, the available tools are fairly new and rep- resent still-developing technologies. ULTRASONIC CRACK DETECTION TOOLS. In contrast to the ultra- sonic metal loss inspection, in which compression waves propagate straight through the wall, the ultrasonic crack detection tool is based on a 45° shear wave generated by the angular incidence of ultrasonic pulses through the liquid cou- pling medium (such as crude oil). A dense array of sensors is the key to providing high resolution with good discrimina- tion during inspection.The tool’s limitation for gas pipelines is the coupling medium required for the ultrasonic sensors. To improve the performance and cost-effectiveness of the ultrasonic tool, the Gas Technology Institute is developing gas-coupled ultra- sonics as an accurate, commercially available gas-pipeline inspection method. ELASTIC WAVE TOOLS. The elastic wave tool uses a liquid-filled wheel to inject ultrasound in a circumferential direction to detect and measure cracks and stress corrosion cracking (SCC) in the gas pipeline. It can detect cracks deeper than 25% of the wall thickness and more than 2-in. long. It has also proven useful in detecting coating disbondment. Although the elastic wave vehicle finds SCC occurrences, it also presents too many false positives. ELECTROMAGNETIC ACOUSTIC TRANSDUCER TOOLS. Electro- magnetic acoustic transducer (EMAT) tools generate ultra- sonic waves within the pipe wall but do not need to contact the pipe wall to do so. EMAT pigs send the ultrasonic waves around the circumference of the pipe to detect and size cracks. False positives may also be a problem with EMAT inspections. Geometry Inspection Geometric inspections gather information about the physical shape, or geometry, of a pipeline. These tools identify any pos- sible obstructions in the pipe and confirm a free passage for any other tool. They are primarily used to find “outside force damage,” or dents, in the pipeline. Dents or other geometric compromises of the pipeline shape may be due to physical contact, stress, or deformation induced by improper installa- tion, erosion, or shifting of the substrate. Dents can affect the strength and performance of the pipeline and may result in damage to critical interior or exterior protective coatings. The two main types of geometry tools available use the same principle. The simplest geometry inspection tool, called a caliper tool, uses a set of mechanical fingers or arms that ride against the internal surface of the pipe or that use electro- magnetic methods to detect variations in pipe diameter. Advanced deformation tools operate in the same manner as a caliper tool, but they also use gyroscopes to provide the o’clock position of the pipe’s dent or deformation. These tools can also generally provide a detailed 3-D geometric survey of the pipeline alignment, which allows the interior curvature to be mapped to help analyze stress. Mapping Tools A mapping tool incorporates an inertial navigation system, similar to that used to guide missiles, to determine horizon- tal position and altitude of the tool along its trajectory. Actual

42geographic coordinates of pipeline’s route are calculated by establishing GPS control points along the pipeline and then tying the inertial data to these points. This tool can be used in conjunction with the other tools described earlier to more accurately find anomalies in metal loss, cracks, and geometry inspection. Without an inertial nav- igation system, inspection pigs rely on an odometer mounted on them, which is usually accurate to within 2.64 ft/mile of pipe traveled. Some location systems use simple electromagnetic transmissions sent to handheld receivers aboveground. While specialized inspection technologies for metal loss, crack detection, cross-section geometry, and pipeline map- ping are individually well developed, using some or all of them together can compensate for the weaknesses of any one method. Such combinations offer the greatest potential when inspecting pipelines for anomalies, which can be identified and sized using more than one method. Using tools in combination is also a better solution for pipeline operators because it pro- vides complete pipeline integrity data at optimum cost. Hydrostatic Testing The hydrostatic test establishes the pressure-carrying capac- ity of a pipeline, and it may help identify significant defects that could approach critical size at operational pressures. The pipeline must be pressured to at least 125% of the MAOP to provide an adequate margin between the test pressure and the operating pressure. If there is a near-critical defect at or below MAOP, that defect will cause a pipeline failure when pressur- ized above the MAOP. Hydrostatic testing is used to commission a pipeline for initial service and as a criterion for qualifying a pipeline for return to service. Hydrostatic tests are also the preferred integrity assessment method when the pipeline is not capable of being internally inspected, or if defects are suspected that may not be detectable by internal inspections. Axial flaws such as stress corrosion cracking, longitudinal seam cracking, selective seam corrosion, long narrow axial (channel) corro- sion, and axial gouges are difficult to detect with internal inspection and are better detected with a hydrostatic test. If hydrostatic testing is used as the primary defense against pipeline failure, it is essential to establish a proper hydrostatic test interval. The interval must be equal to the time required for a defect to grow from a size that just passes the hydrostatic test (125% of MAOP) to a size that is critical at operating pressure. However, hydrostatic testing cannot provide information about the extent or severity of the remaining damage. Further- more, hydrostatic testing requires the acquisition of large quantities of test water, which in some areas may be difficult. Once used, the test water may contain trace quantities of petro- leum products, requiring that the water be treated before it is disposed of or discharged. Finally, hydrostatic testing requiresthat the pipeline be out of service for a period of time, thus potentially curtailing the availability of gasoline, jet fuel, diesel fuel, crude oil, or home-heating oil at the delivery point. Direct Assessment (External) Current internal inspection technologies or hydrostatic testing may not be suitable, or cost-effective, on certain transmission systems. For example, some pipelines cannot be inspected by smart pigs or cannot be removed from service for hydrostatic testing. Direct assessment techniques can be used for such pipelines because the techniques do not impede pipeline operation. Direct assessment is a structured process. It uses various aboveground surveys and prior experience to predict where corrosion will or may occur, and then field measurements and monitoring are undertaken to determine the condition of the pipe at these sites. Often, a dig program is used for ver- ifying the condition of the coating and the pipe. Based on the field verifications, additional feedback is received to tune var- ious assessment approaches for the pipeline, to further pre- dict where similar conditions may exist that are conducive to such corrosion, and to perform additional field verification. Direct assessment has been developed for oil and gas trans- mission pipelines to deal with certain types of general external corrosion direct assessment (ECDA), internal corrosion direct assessment (ICDA), and a very specialized external corrosion called stress corrosion cracking direct assessment (SCCDA). External Corrosion Direct Assessment External corrosion direct assessment (ECDA) addresses gen- eral external corrosion caused by a lack of protective coating, usually from certain types of holes in the external coating of pipelines. These holes are normally associated with coating penetrations from rocks, poor pipe installation quality, coating deterioration with time, and many types of third-party dam- age, such as excavations. Coating disbonding, resulting from loss of adhesion between the external coating and the outer pipe wall surface, is rarely detected through ECDA, because the nonconductive coating shields the passing current. Coating disbonding cre- ates gaps where the cathodic protective current cannot reach the pipe surface, and reactants may accumulate and foster corrosion. Internal Corrosion Direct Assessment Internal corrosion direct assessment (ICDA) attempts to address internal corrosion on gas transmission pipelines that normally operate as a dry-gas service, and it assumes that the presence of an electrolyte (water) serves as the driving mecha-

43nism for this general internal corrosion. ICDA rests on the principle that the electrolyte settles out, or drains, on the inner lower surface of a pipe whenever a certain critical angle of inclination is exceeded for a specific gas flow velocity. In determining the critical angle of inclination, the model defined in GRI Report 02-0057, “Internal Corrosion Direct Assessment of Gas Transmission Pipelines—Methodology,” or a demon- strated equivalent model could be used (2). However, the use of ICDA does not exclude wet-gas oper- ations that can generate higher risks of failure from internal corrosion (especially for pipelines that don’t use an effective cleaning pig/analysis program). Stress Corrosion Cracking Direct Assessment Stress corrosion cracking (SCC) is a selective external corro- sion attack resulting from a combination of disbonded coat- ing, tensile stress, and certain environmental factors. There are two types of SCC on the outer surface of a pipeline, “high pH” and “near neutral.” Industry-recommended practices for stress corrosion cracking direct assessment (SCCDA) are under development as the current B31.8S largely focuses on high pH SCC factors and recommends hydrostatic testing if SCC has gone to failure. The aboveground tools used in direct assessment are intro- duced in the paragraphs that follow. These tools are expected to have functions such as measurement of the insulation char- acteristics of coatings, survey of the level of cathodic potential (CP), location of a coating defect, and evaluation of the area of a coating defect (typically referred to as a “holiday”). The following are types of SCCDA surveys: • Close-Interval Surveys: Close-interval surveys are typically used to determine CP levels along a pipeline, shorts to other structures, and stray current areas. However, they are lim- ited in detecting small coating holidays. • AC Current Attenuation Surveys: These surveys are typically used to assess coating quality and to detect and compare discrete coating anomalies. This technique does not require electrical contact with the soil and can often be used to gather information through magnetically transparent cov- ers, such as soil, ice, water, and concrete. • Direct Current or Alternating Current Voltage Gradient Sur- veys: Direct current or alternating current voltage gradient (DCVG or ACVG) surveys are typically used to detect small to large holidays. They are sometimes used to determine whether a region is anodic or cathodic, but they cannot determine CP levels. Small, isolated coating holidays asso- ciated with corrosion or third-party damage can some- times be found when survey crews are specifically asked to investigate small indications that ordinarily are considered inconsequential.• Pearson Surveys: These surveys are typically used to detect various coating holidays, but they cannot differentiate the size of each holiday. The technique employs an AC signal injected onto the pipeline and compares the potential gra- dient along the pipeline between two mobile earth con- tacts. At coating defects, voltage-gradient increases occur, which are noted and recorded on record sheets as the sur- vey progresses. Generally, two or more tools are recommended in imple- menting a direct assessment program. In a dig program, metal loss or cracks in the pipe can be found by such ordinary nondestructive evaluation techniques as ultrasonic, magnetic powders, and so forth. The guided wave method is also a choice to inspect defects in the pipe over a limited length. Summary for Oil and Gas Pipelines The current state of the art in oil- and gas-pipeline inspection technology has provided much of the information and data necessary to develop a rational, cost-effective strategy for pipeline integrity management. Currently, a wide range of tools have been designed and are well developed for internal inspection, direct assessment, and hydrostatic testing. The features of each method should be considered in conducting an assessment program, depending on the condition of the actual pipeline in question. The selection of appropriate yet cost-effective methods is still widely considered more art than science. Nondestructive Inspection Tools for Utility Piping As discussed in the introduction to this chapter, nondestruc- tive inspection tools for buried pipes are principally deployed within the buried pipes, since only localized excavations are practical to allow for external inspection. Many of the tech- niques described, however, can be adapted for use on an exposed pipe’s exterior. Cable inspection systems are only briefly described because fault location and condition assess- ment are carried out by the utility owner, who taps into the conductor at various points and propagates signals along indi- vidual cables or fibers. The discussions that follow on nonde- structive pipe inspection tools are not applicable to all types of underground piping systems. As also mentioned in the intro- duction to this chapter, pipe material, access limitations, pipe bends, and pipe internal diameter limit the techniques that may be used. An overarching issue is matching the level and frequency of inspection to the risk posed by the utility type and the value derived from regularly knowing the utility’s con- dition. In more direct terms, the techniques appropriate for determining the condition of a long, relatively straight, large-

44diameter steel pipeline carrying high-pressure natural gas may have little in common with the techniques and equipment appropriate for monitoring small-diameter water distribu- tion piping or sewer collection piping. The available finan- cial resources, the risks posed by potential failure, and the pipe materials or configurations make each application quite distinct. Visual Inspection Closed-Circuit Television There is a wide variety of camera systems for the visual inspec- tion of the interior of pipes or pipelines—ranging from very small-diameter pipes in a boiler heat exchanger to person- entry-size pipes in areas inaccessible for direct inspection. These systems have been in use for many years and can gather data on pipe integrity, size changes, and material changes. The main improvements and innovations in recent years have been in the quality of the images that can be produced through better lighting and high-resolution, digital color imaging; the use of digital video files rather than cumbersome videotapes; and the ability to combine TV inspections with other types of data collection. Photographic or Laser-Based Scanning Devices Several manufacturers offer devices that will produce high- resolution images of a pipe wall that can be unwrapped to present the full internal surface of the pipe as a flat surface. From these images, defects can be identified, crack lengths and widths measured, and statistics created about the propor- tion of defects. From these statistics, or from a simple glance at the visual image, a rapid understanding of the condition of a length of pipe can be gathered. Systems may use a side- scanning laser, or they may simply scan the photographic image collected by a fish-eye lens. A drawback is that the still image does not give as much information about water leak- age in a pipe, for example, as a video image, such as closed- circuit television (CCTV), would give. For this reason, in recent systems, still images and CCTV are often combined. Zoom Cameras To avoid the time and expense of inserting a CCTV camera system into a drainage pipe, it is sometimes adequate to use a camera that is lowered into the manhole and oriented along the pipe to be inspected. Focused lighting and a high-powered zoom lens provide a quick visual survey of straight sections of pipe that are accessible from the manhole. Debris within the pipe, collapsed sections, protruding lateral taps, and so forth are the types of problems that can be quickly determined.Pipe Usage Status Acoustic emission may determine active versus empty water pipes by a nearby means of direct access to the system, such as a fire hydrant. This technique almost always employs res- onant sonics and is used mostly to differentiate water systems when more than one water system may be present in an area. This is a very specific application without broad applicability. For the use of acoustic emission in locating water pipes, see the discussion in chapter 4. For acoustic and ultrasonic leak detection, see the section later in this chapter. Internal Pipe Geometric Measurements For pipes principally under internal pressure, cross-section changes are usually undetectable from pipe-scanning mea- surements prior to the pipe’s failure. For gravity pipes such as brick sewers that fail principally from external soil loads, visi- ble signs of failure can often be seen as sharp distortions, or major cracks occur, bricks fall out, and so forth. For flexible pipes that are resisting external soil loads, however, the fail- ure generally occurs through a progressive deformation or the “ovaling” of the pipe. When this reaches a critical level, the pipe may suddenly buckle and fail. The extent of ovaling is important to determine the design of pipe-lining systems to rehabilitate the pipe. Laser-Based Geometric Measurements Visual inspection is poor at determining such gradual deflec- tions or determining the quantitative amount of ovality in the pipe. For this reason, a number of techniques for assessing the geometry of the pipe’s internal surface have been developed. These include rotating laser systems, ring laser systems, and laser point cloud systems. Such systems are typically mounted on the same types of pipe tractor robots as a CCTV system and may be operated on a sequential basis with a CCTV pipe inspection. Despite some potential difficulties with these systems, they do provide the ability to track the gradual deformation of a pipe over time. In this regard, a major difficulty is ensuring that subse- quent passes with the measurement system, perhaps one or two years later, can be accurately registered to the same cross section so that changes over time at that cross section can be determined. Sonar Inspection Sonar inspection devices can be used in water-filled pipes in a manner similar to the sonar soundings in lakes and rivers and the ultrasonic inspection methods for a pipe wall. The instrument is immersed in the water, providing it with a good

45coupling for the sonar signal. The internal shape of the water- filled pipe or the presence of internal debris below the water level may be measured from the reflected signal’s time of travel. When the pipe is partially filled, the instrument is typ- ically floated on the water surface, and only the portion of the pipe that is under water can be inspected. External Pipe Bedding Conditions Once pipes have been installed in the soil, they are typically constrained to move and settle with the soil or to deform. Ground-induced bending in a pipe may amplify stresses caused by internal pressure or external ground pressure. Like- wise, both flexible pipes and rigid pipes can be affected by poor bedding conditions outside of the pipe or by the presence of soil voids over a portion of the perimeter of the pipe. In the case of a flexible pipe, a void or soft bedding on one side of the pipe will cause uneven stress and deformation of the pipe wall. In the case of a rigid pipe, if the pipe fractures, fine soil may wash away or wash into the pipe, creating soil voids. Over time these voids allow sections of fractured pipe to move relative to each other, causing collapse. The voids get larger until a sink- hole occurs when the road surface above the pipe collapses. Such sinkholes are, in fact, a frequent occurrence across the United States. Thus, an important part of determining the condition of a buried pipe is often also determining the condition of the soil surrounding it and detecting any voids that may have developed. Some of the surface geophysical techniques discussed in chapter 4 may potentially find reasonably sized soil voids adjacent to pipes. They also have the potential to differenti- ate pipe backfill in trenches from the natural soil surround- ing the trench. When using surface techniques, it is difficult to find small soil voids or weak zones of backfill that are likely to lead to progressive deterioration but that are not distinct enough to be imaged from the surface. Internal pipe scanning systems, such as ground-penetrating radar (GPR) and ultra-wideband (UWB) pulsed radar systems, can make such determinations, but they are not yet in regular commercial use. Mechanical Damage to Pipelines A significant proportion of damage to buried pipelines comes from external mechanical damage caused by inadvertent and often unauthorized excavation in the vicinity of a pipeline. Because of the safety implications of immediate or delayed failures of oil or gas pipelines from this cause, this has been an active area of research funding by the Office of Pipeline Safety (OPS)/PHMSA, both in terms of detecting real-time encroachment and detecting mechanical damage in pipelinesurveys. Encroachment detection is not directly of interest to the current report, but the detection of existing mechanical damage can be an important part of utility characterization. Techniques used for the mechanical-damage detection of pipelines were discussed in the previous section on oil and gas pipeline inspection. Some of the techniques discussed in the next section can also be applied to pipe-wall measurements to determine loss of wall thickness due to corrosion. Pipe-Wall Measurements Pipe-wall measurement techniques can typically be divided into EM methods that must be applied differently in metallic and nonmetallic pipelines and ultrasonic methods that can be applied to either. Only the techniques that were not discussed for oil and gas pipelines are highlighted here. Nonlinear Harmonics The nonlinear harmonics (NLH) method consists of impress- ing an alternating magnetic field onto magnetic material, such as steel, and sensing the amount of magnetism produced. To do this, a transformer is used to cause a magnetic field to pass through two electrical coils and into the pipe wall. One of the coils is connected to a source of electric current that oscillates thousands of times per second. Because of the nature of the pipe-wall material, the magnetism in the pipe wall does not oscillate with the same pure waveform provided by the elec- trical source. Instead, its oscillation pattern is distorted so that it contains frequencies that are several times higher than the frequency of the electrical source. The NLH method takes advantage of these higher frequency oscillations, sometimes called the “harmonics of the excitation frequency.” A second- ary electrical winding on the transformer core responds to the oscillating magnetism and produces an electrical signal that can be filtered to remove the source frequency and retain the harmonics. The amplitudes of these remaining harmonics are considered to be related to the level of stress and strain in the steel pipe wall (3). Magnetic Inductance Pipe-wall thickness can be measured by pulsing a magnetic inductance coil that is positioned close to the wall and measur- ing the inductance of the pulsed coil. The distance of the coil from the wall is accurately determined so that the inductance is a measure of the wall thickness. The apparatus may include the combination of an ultrasonic transducer mounted in a fixed position relative to the magnetic pulse coil and arranged so that ultrasonic energy pulses are directed toward the wall. In this manner, reflected ultrasonic pulses will provide a measure of the distance (U.S. Patent 4,418,574).

46X-Ray Inspection Where direct access is limited, X-ray techniques have been applied to measure pipe-wall thickness for pipes covered with insulation. The pipe is exposed to radiation from an X-ray or gamma-ray source. The transmitted radiation is detected by film, or more recently, an imaging plate (4). This technique could conceivably be applied internally to a larger diameter pipe, but normally the technique would be applied to an exposed section of pipe. Ultrasonic Inspection Ultrasonic thickness gauges use sound waves to measure wall thickness. Different types of materials have different inherent acoustic velocities. For example, the acoustic velocity of steel is 0.2330 in./microsecond and that of aluminum is 0.2500 in./ microsecond. Typically, a sample of the material to be tested is required for high-accuracy measurements, although tables exist for common materials. Good coupling of the transmitted and reflected acoustic signal into the measurement device is necessary for good quality measurements. This is difficult to achieve for remote internal pipe inspections in an empty pipe—especially in pipes that are in poor condition or that have internal buildup or debris. Other Pipe-Scanning Techniques Ground-Penetrating Radar Some use has been made of GPR systems in internal pipe inspections. This is only applicable to nonconductive pipes that will allow the signal to propagate through the pipe wall into the surrounding soil. As for the surface-based GPR surveys discussed in chapter 4, differences in materials or the presence of voids will reflect an emitted signal back to a receiver. Con- tinuous wave signals or pulsed signals may be used. The draw- back to continuous wave signals is that pipe geometry and other pipe or backfill features can produce signals that are dif- ficult to interpret. Pulsed wave signals tend to produce more easily interpreted signals. However, for both continuous wave and pulsed wave signals, high frequencies or very short wave- length pulses are required to resolve variations in pipe-wall thickness. Fortunately, the necessary high-frequency signals can be used from within a pipe, because the area of interest is within the pipe wall or immediately outside the pipe wall, and signal attenuation is less of a problem. In 2002, the limitations on the power levels versus the frequency spectrum permitted by the FCC for GPR and UWB applications were eased; hence, methods based on the new spectrum limitations are evolving. There are examples of field studies that use within-pipe GPR (5, 6), and a UWB-based pulsed-signal approach is in labora- tory testing at Louisiana Tech University (7). More methodsare generally available for examining steel- or other conductive- walled pipes; thus, GPR approaches for nonconductive pipes are an important area of development. Surface-based surveys that use GPR may provide generic information about a pipe’s or conduit’s relative size or shape— depending, of course, on depth and surrounding conditions. Determining material type and other characteristics is usually not possible. Infrared Measurements Infrared techniques can be effective for some aspects of utility characterization. The uneven heating or cooling of a pipe wall or a pipe liner can indicate variations in pipe-wall thickness, the bonding of a liner to the pipe wall, the presence of soil voids outside the pipe, and so forth. For differences to be visible, it is necessary have a temperature difference between the inside of the pipe and the surrounding ground. For thick-walled pipe inspection, it may be necessary to first heat or cool the pipes over an extended period of time to get measurable results. However, for thin pipe liners in relatively small pipes, differ- ences in liner bonding can be noted almost immediately using a light bulb as a heat source. The approach can also be applied to steam systems. Steam pipes are almost always insulated, and one aspect of operational efficiency is to gauge the effectiveness of that insulation. External inspection can be done during operation by looking for hot spots along the external surface of the insulation. Internal scans would require draining the sys- tem and would look for thermal differences between intact areas of insulation and damaged areas. Pipe Leakage and Integrity Testing Smoke Testing Smoke testing is applied to sections of storm- or sanitary- drainage systems to find leakage points. Sections of the drainage pipe network are isolated and smoke is introduced into the pipe system using fans and a smoke generator. The smoke will exit the pipe network through faulty joints and other leaking or damaged areas and, in many cases, can be observed at the ground surface, indicating the presence and approximate location of a leak. The technique is relatively inexpensive, but it can have a poor success rate, even under good application conditions. The method cannot be used when the water table is above the pipe level. Typically, it is used as a preliminary survey technique to determine major leakage areas in sewers. Dye and Tracer Testing Dyes or other tracer elements can be used in pipe networks to trace the connectivity of different pipe sections. Such

47tracer elements can also be used, under the right conditions, to track leakage out of or into a pipe network. The use of trac- ers is typically more labor intensive than smoke testing but gives better and more verifiable results. The ability to inject the tracer element at one point or several and observe or measure its arrival at another point or many points in the system is needed. Pressure Testing A key aspect of the acceptance process for most pressure pipe systems is some form of pressure testing of the overall system or a segment-by-segment testing protocol. Such pressure test- ing is also used to gauge the integrity of nonpressure pipe sys- tems, such as storm and sanitary sewer pipe networks. At low pressures and for small-diameter pipes, air pressure can be used for testing, but for large-diameter pipes and for high pres- sures, a nearly incompressible fluid such as water is used for safety reasons. To find leaks more effectively, the pipe network is typically tested section by section by isolating the section under test from the rest of the pipe network and subjecting it to internal pressure. Depending on the pipe’s use, the accept- ability criterion may be that it resists pressure at a certain level higher than the maximum allowable operating pressure, or that it has less than a specified pressure drop over a specified period of time. The drawbacks to pressure testing are the length of time required for testing and the need to trace and find leaks if they are present within the section tested. For large-diameter pipes, the volume of water needed for pressure testing also may present challenges. In some cases, localized testing and sealing operations can be carried out from within a pipeline, such as in grouting operations for gravity sanitary sewer lines. In this case, inflatable packers seal off a small sec- tion of a pipe, the pressure integrity is checked, and, if it is found lacking, a grout is pumped into the sealed section so that it exits the pipe through the leaking zones and forms a seal around the exterior of the pipe. Acoustic and Ultrasonic Leak Detection Both nonaudible and audible methods can be used for leak detection. The methods involve listening for the noise or vibrations that are emitted when a fluid inside a pipe leaks through the pipe wall. Detection can be as simple as using a receiver on the surface to find the maximum amplitude of the signal, which is assumed to be directly over the leak. When two or more measurements are made for a section of pipe, in- pipe methods can estimate the approximate location of the leak. When a traveling receiver is used, in-pipe methods can pinpoint the source of the leak. Systems are also available that use an ultrasonic transmitter inside the pipe and a detector outside.Pipe-Wall Conductivity Scanning A relatively new inspection approach known as the focused electrode leak location (FELL) method (8, 9) can be used to look for leakage areas in nonconductive pipes. The principle of the technique is that a water leakage path through the pipe wall will greatly increase the conductance between an electrode inside the pipe and a buried electrode outside the pipe. The internal pipe electrode is shielded so that it only responds to leakage points directly opposite the internal electrode position. In a gravity pipe system, the pipe is temporarily filled during passage of the inspection system so that any potential leaks are made active. Gas Detection Leaks in gas pipelines can be detected by chemical sensors tra- versed across the ground surface or, for significant leaks, sim- ply by the odor introduced into the gas. The precise location of such leaks is difficult to determine, however, and more than 500,000 leaks on buried gas distribution piping are incorrectly pinpointed each year, according to the American Water Works Association Research Foundation (AWWARF) (10). In 2006, a digital leak-detection research project was funded by AWWARF (Project #4041). A pre-prototype detection unit has been developed and tested by natural-gas and steam- utility crews. Initial trials indicate that detection has improved within a 4-ft excavation window from 66% using existing technology to 100% using the new equipment. Cable Fault Detection Systems It is important to know the condition of buried electrical and communication cables and to be able to precisely locate faults in the cable. A number of techniques are available, including those for electrical cables (11): Murray loop test, fall of poten- tial test, DC charge and discharge test, induction test, impulse wave echo test, and time domain reflectometry test. For optical cables, the quality of fiber-optic cable perfor- mance depends on attenuation or optical loss and on defects (including faults) that cause reflections or scattering and for which the location can be measured using optical time domain reflectometry. Combined Inspection Systems During the passage of an inspection device through a pipe, it can be attractive to make multiple measurements for pipe characterization and condition assessment. The advantages include making the most of the same site mobilization, gain- ing more information on pipe condition than a single method usually allows, and providing redundant measurements to increase the confidence of the condition assessment. The

48drawbacks include the increasing complexity and cost of the equipment, which limit the range of contractors available to bid on the work and which require larger-scale jobs to be cost- effective, and whether the range of information that can be collected will in fact be used or needed for effective condition assessment. These issues must be determined on a case-by- case basis, but it is expected that multiplatform inspection systems will become more common as the sensor integration becomes more effective and the costs of such systems drop. Examples of multisensor systems currently available include the following: • “Smart pigs” used by oil and gas pipeline operators. These may include a variety of sensing devices, depending on the purpose of the survey. The high risks and costs from leaks, government regulation, and the geometry conditions related to many pipelines make smart pigs an attractive inspection option. • CCTV visual inspection combined with sonar below-water inspection in partially filled pipes can be used when pipes cannot be emptied during inspection. • CCTV visual inspection combined with laser-based internal pipe geometry measurements make it easier to gauge the continued deformation of pipes under external soil load that is a precursor of collapse problems. • Multisensor systems that encompass a wide variety of sen- sors and measurement systems, of which only a few com- mercial examples exist. Data- and Asset-Management Systems Important advances in recent years have been made in the management of utility system data. These advances have been made possible by improvements in computer technology, database and operations management software, GIS software, precise GPS equipment, and wireless cellular or satellite data acquisition systems. These advances have important implications for the inter- action of utility systems with transportation projects because of improvements in utility mapping, recordkeeping, condition assessment, and life-cycle asset management. Some key areas related to condition assessment are men- tioned in the following paragraphs. Data Management and Display Most cities and utilities have introduced GISs within their orga- nizations for the management of a wide range of physical and management data. These systems interface with supervi- sory control and data acquisition (SCADA) systems and wire- less monitoring systems, with generalized asset managementand maintenance management systems, and with specialized pipeline-inspection data collection software and condition assessment software. When fully implemented, the integration of the systems means that complete maps of a utility system are available in the office or in the field coupled with a full his- tory of maintenance work on a section of a utility and the cur- rently assigned condition of the utility segment. Work orders for repair or maintenance can also be generated directly from the software. The problems with fully employing the software to define utility locations and conditions are twofold: the pedigree of the data entered into the system is often unknown and it may be inaccurate or incomplete; and there is often a lack of con- sistency in how physical data is recorded and physical con- ditions are assessed across work crews from one agency to another. Nevertheless, these changes represent huge advances in technological capability, and they also provide a platform whereby the accuracy of location and pedigree of information can be readily updated in the future. Guidelines for inspection training and consistent condition assessment also have been developed by several agencies (for example, NASSCO) (12). Prediction of Risk of Failure and Need for Rehabilitation or Replacement When good records of a utility’s characteristics and perfor- mance over time are available, it is possible to effectively plan for proactive maintenance, rehabilitation, and replacement that will lower life-cycle costs for the utility. This same infor- mation and analysis can guide the decisions that need to be made when a utility is to be left in place beneath a transporta- tion renewal project. Typical factors involved in such decisions include the utility’s • Age; • Failure history; • Correlation to location or soil type; • Correlation among pipes with similar characteristics; • Condition assessment ratings over time; • Specific pipe condition attributes over time; • Cathodic protection level for metal pipelines; • Risk assessment rating using predictive models; and • Periodic hydrostatic testing to failure of pipe sections. Guidelines, Standards, and Regulations for Pipe Inspection and Condition Assessment Outside the pipeline industry, there are surprisingly few com- prehensive guidelines and standards for the inspection, data management, and condition assessment for buried utilities.

49Testing and inspection of buried pipelines is discussed in Pip- ing Systems and Pipeline ASME Code Simplified (13). Proce- dures and acceptance criteria for various inspection methods can be found in the Boiler and Pressure Vessel Code. Codes are also available for other aspects of piping design, analysis, and management, including the following: • B31.1 Power piping • B31.3 Process piping • B31.4 Pipeline transportation systems for liquid hydro- carbons and other liquids • B31.5 Refrigeration piping and heat transfer components • B31.8 Gas transmission and distribution piping systems • B31.8S Managing system integrity of gas pipelines • B31.9 Building services piping • B31.11 Slurry transportation piping systems • B31G Manual for determining the remaining strength of corroded pipelines In the municipal sewer sector, there has been a concerted effort over the past several years to standardize the way in which sewer defects are catalogued in condition databases (14), and similar efforts have been developed in other utility sectors. Without consistent data collection and interpretation, much of the potential value of condition data in managing maintenance and rehabilitation and making comparisons among systems is lost. Government regulations also have had some impact out- side the pipeline industry. For example, in the sewer sector, the U.S. Environmental Protection Agency developed guidelines for municipalities on how to manage their sewer systems’ capacity, management, operations, and maintenance, and the Government Accounting Standards Board developed finan- cial guidelines for updating the asset value of buried infra- structure based on the condition of that infrastructure (15). Summary There are currently very few aspects of utility characterization data that can be reliably determined from a surface-based util- ity location or characterization survey. This could change sub- stantially, however, with the introduction of smart marking and tagging systems for utilities. Over time, new utilities would be identified with programmable and updatable electronic markers, and existing utilities could be marked as they are exposed for maintenance or during other excavation activities. Without the use of smart tags, most characterization data must be obtained from utility records or by physically expos- ing the utility through access pits or test holes. Utility records may be of variable quality in terms of the accuracy of original information and consistent updating of changes. Even theinformation that can be attained in a nondestructive manner when the utility is physically exposed is quite limited both in type of data and in extent of the data applicability along the pipeline from a limited exposure. The most active area of utility-characterization data advances has been in the internal inspection techniques available for pipelines, the development of consistent terminology for pipe defects and pipe condition assessment, and the use of asset management approaches to manage the buried utilities effec- tively over their life cycles. There has been an equivalent improvement of technology and procedures for the manage- ment of electrical and communication cables. Many utilities have readily embraced asset-management approaches and are in a better position to answer questions about utility condition today than they were a decade ago. One could argue that it is incumbent on utility providers who have been given the right to use the space beneath the public right-of-way to know where their utilities are and to know the characteristics and condition of their utilities so that intelligent decisions can be made about replacement or reha- bilitation during transportation renewal projects. While gaps will continue to exist for out-of-service or abandoned utilities, the combination of smart tagging systems and the ongoing asset-management approaches by utilities offer the prospect for a substantial improvement in utility management beneath rights-of-way in the future. References 1. Manual for Determining the Remaining Strength of Corroded Pipelines, a Supplement to ASME B31 Code for Pressure Piping. American Society Mechanical Engineers Standards, B31G, New York, N.Y., June 1991. 2. Moghissi, O., L. Norris, P. Dusek, B. Cookingham, and N. Sridhar. Internal Corrosion Direct Assessment of Gas Transmission Pipelines— Methodology. GRI-02/0057, Gas Research Institute, Des Plaines, Ill., 2002, p. 39. 3. Crouch, A., and G. Chell. Making the “Smart Pig” Smarter. Tech- nology Today, Southwest Research Institute, San Antonio, Tex., Fall 2002. 4. Vengrinovich, V. L., Y. Denkevich, S. Zolotarev, A. Kuntsevich, and S. Emelyanenkov. New Technique for Pipes Wall Thickness Assess- ment Considering Scattering Effect. Proc., Presented at the 8th ECNDT (European Conference on Nondestructive Testing), Barcelona, Spain, June 2002. 5. Guy, E. D., J. J. Daniels, and Z. Daniels. Cross-Hole Radar Effec- tiveness for Coal Mine-Related Subsidence Investigations: Studies Near Discontinuities Imaged Using High-Resolution Seismic Reflection. Proc., NASTT NO-DIG 2003 Conference, Las Vegas, Nev., March–April 2003, p. 15. 6. Ariaratnam, S. T., and N. Guercio. In-Pipe Ground Penetrating Radar for Non-Destructive Evaluation of PVC Lined Concrete Pipe. Solid Mechanics and Its Applications: Advances in Engineering Structures, Mechanics & Construction, Vol. 140, 2006, pp. 763–772.

507. Jaganathan, A., E. N. Allouche, and N. Simicevic. Pipeline Scan- ning: Novel Technology for Detection of Voids and Internal Defects in Non-Conductive Buried Pipes. Proc., ISTT 2006 No-Dig Conference, Oct. 29–Nov. 11, 2006, Brisbane, Australia. 8. Harris, R. J., and J. Tasello. Sewer Leak Detection—Electro-Scan Adds a New Dimension. Case Study: City of Redding, CA. Proc., Pipelines 2004 International Conference, San Diego, Calif., Aug. 2004. 9. Dayananda, D., C. G. Wilmut, and B. J. Dsouza, Effective Identifi- cation of Service Line Defects with Electro-Scan Technology. Proc., Water 2007 Conference, San Antonio, Tex., March 2007. 10. Development of a Digital Leak Detector. Project #4041, until June 2008. American Water Works Association Research Foundation, 2007. http://www.awwarf.org/research.11. Pabla, A. S. Electric Power Distribution. McGraw-Hill Professional, 2005, p. 878. 12. Pipeline Assessment & Certification Program (PACP) Reference Man- ual. National Association of Sewer Service Companies, Owings Mills, Md., 2001, p. 257. 13. Ellenberger, J. P. Piping Systems and Pipeline. ASME Code Simpli- fied, McGraw-Hill, 2005, p. 268. 14. Pipeline Assessment and Certification Program (PACP) Standard Database. National Association of Sewer Service Companies, Owings Mills, Md., 2004. 15. Government Accounting Standards Board. Statement 34 Resource Center at http://1172.3.167.244/repmodel/other_pubs&resources. html.