What must a small LPG operator do to implement this subpart?

§ 192.1015 What must a small LPG operator do to implement this subpart?#

(a)General. No later than August 2, 2011, a small LPG operator must develop and implement an IM program that includes a written IM plan as specified in paragraph#

(b)of this section. The IM program for these pipelines should reflect the relative simplicity of these types of pipelines.#

(b)Elements. A written integrity management plan must address, at a minimum, the following elements:#

(1)Knowledge. The operator must demonstrate knowledge of its pipeline, which, to the extent known, should include the approximate location and material of its pipeline. The operator must identify additional information needed and provide a plan for gaining knowledge over time through normal activities conducted on the pipeline (for example, design, construction, operations or maintenance activities).#

(2)Identify threats. The operator must consider, at minimum, the following categories of threats (existing and potential): corrosion (including atmospheric corrosion), natural forces, excavation damage, other outside force damage, material or weld failure, equipment failure, and incorrect operation.#

(3)Rank risks. The operator must evaluate the risks to its pipeline and estimate the relative importance of each identified threat.#

(4)Identify and implement measures to mitigate risks. The operator must determine and implement measures designed to reduce the risks from failure of its pipeline.#

(5)Measure performance, monitor results, and evaluate effectiveness. The operator must monitor, as a performance measure, the number of leaks eliminated or repaired on its pipeline and their causes.#

(6)Periodic evaluation and improvement. The operator must determine the appropriate period for conducting IM program evaluations based on the complexity of its pipeline and changes in factors affecting the risk of failure. An operator must re- evaluate its entire program at least every five years. The operator must consider the results of the performance monitoring in these evaluations.#

(c)Records. The operator must maintain, for a period of at least 10 years, the following records:#

(1)A written IM plan in accordance with this section, including superseded IM plans;#

(2)Documents supporting threat identification; and#

(3)Documents showing the location and material of all piping and appurtenances that are installed after the effective date of the IM program and, to the extent known, the location and material of all pipe and appurtenances that were existing on the effective date of the operator's program. APPENDIX A TO PART 192 - RESERVED APPENDIX B TO PART 192 - QUALIFICATION OF PIPE AND COMPONENTS I. List of Specifications A. Listed Pipe Specifications API Spec 5L-Steel pipe, "Line Pipe" (incorporated by reference, see § 192.7). ASTM A53/A53M-Steel pipe, "Standard Specification for Pipe, Steel Black and Hot- Dipped, Zinc-Coated, Welded and Seamless" (incorporated by reference, see § 192.7). ASTM A106/A-106M-Steel pipe, "Standard Specification for Seamless Carbon Steel Pipe for High Temperature Service" (incorporated by reference, see § 192.7). ASTM A333/A333M-Steel pipe, "Standard Specification for Seamless and Welded Steel Pipe for Low Temperature Service" (incorporated by reference, see § 192.7). ASTM A381-Steel pipe, "Standard Specification for Metal-Arc-Welded Steel Pipe for Use with High-Pressure Transmission Systems" (incorporated by reference, see § 192.7). ASTM A671/A671M-Steel pipe, "Standard Specification for Electric-Fusion-Welded Pipe for Atmospheric and Lower Temperatures" (incorporated by reference, see § 192.7). ASTM A672/A672M-09-Steel pipe, "Standard Specification for Electric-Fusion- Welded Steel Pipe for High-Pressure Service at Moderate Temperatures" (incorporated by reference, see § 192.7). ASTM A691/A691M-09-Steel pipe, "Standard Specification for Carbon and Alloy Steel Pipe, Electric-Fusion-Welded for High Pressure Service at High Temperatures" (incorporated by reference, see § 192.7). ASTM D2513 "Standard Specification for Polyethylene#

(PE)Gas Pressure Pipe, Tubing, and Fittings" (incorporated by reference, see § 192.7). ASTM D 2517-00-Thermosetting plastic pipe and tubing, "Standard Specification for Reinforced Epoxy Resin Gas Pressure Pipe and Fittings" (incorporated by reference, see § 192.7). ASTM F2785-12 "Standard Specification for Polyamide 12 Gas Pressure Pipe, Tubing, and Fittings" (PA-12) (incorporated by reference, see § 192.7). ASTM F2817-10 "Standard Specification for Poly (Vinyl Chloride)#

(PVC)Gas Pressure Pipe and Fittings for Maintenance or Repair" (incorporated by reference, see § 192.7). ASTM F2945-12a "Standard Specification for Polyamide 11 Gas Pressure Pipe, Tubing, and Fittings" (PA-11) (incorporated by reference, see § 192.7). B. Other Listed Specifications for Components ASME B16.40-2008 "Manually Operated Thermoplastic Gas Shutoffs and Valves in Gas Distribution Systems" (incorporated by reference, see § 192.7). ASTM D2513 "Standard Specification for Polyethylene#

(PE)Gas Pressure Pipe, Tubing, and Fittings" (incorporated by reference, see § 192.7). ASTM D 2517-00-Thermosetting plastic pipe and tubing, "Standard Specification for Reinforced Epoxy Resin Gas Pressure Pipe and Fittings" (incorporated by reference, see § 192.7). ASTM F2785-12 "Standard Specification for Polyamide 12 Gas Pressure Pipe, Tubing, and Fittings" (PA-12) (incorporated by reference, see § 192.7). ASTM F2945-12a "Standard Specification for Polyamide 11 Gas Pressure Pipe, Tubing, and Fittings" (PA-11) (incorporated by reference, see § 192.7). ASTM F1055-98#

(2006)"Standard Specification for Electrofusion Type Polyethylene Fittings for Outside Diameter Controlled Polyethylene Pipe and Tubing" (incorporated by reference, see § 192.7). ASTM F1924-12 "Standard Specification for Plastic Mechanical Fittings for Use on Outside Diameter Controlled Polyethylene Gas Distribution Pipe and Tubing" (incorporated by reference, see § 192.7). ASTM F1948-12 "Standard Specification for Metallic Mechanical Fittings for Use on Outside Diameter Controlled Thermoplastic Gas Distribution Pipe and Tubing" (incorporated by reference, see § 192.7). ASTM F1973-13 "Standard Specification for Factory Assembled Anodeless Risers and Transition Fittings in Polyethylene#

(PE)and Polyamide 11 (PA 11) and Polyamide 12 (PA 12) Fuel Gas Distribution Systems" (incorporated by reference, see § 192.7). ASTM F 2600-09 "Standard Specification for Electrofusion Type Polyamide-11 Fittings for Outside Diameter Controlled Polyamide-11 Pipe and Tubing" (incorporated by reference, see § 192.7). ASTM F2145-13 "Standard Specification for Polyamide 11 (PA 11) and Polyamide 12#

(PA12)Mechanical Fittings for Use on Outside Diameter Controlled Polyamide 11 and Polyamide 12 Pipe and Tubing" (incorporated by reference, see § 192.7). ASTM F2767-12 "Specification for Electrofusion Type Polyamide-12 Fittings for Outside Diameter Controlled Polyamide-12 Pipe and Tubing for Gas Distribution" (incorporated by reference, see § 192.7). ASTM F2817-10 "Standard Specification for Poly (Vinyl Chloride)#

(PVC)Gas Pressure Pipe and Fittings for Maintenance or Repair" (incorporated by reference, see § 192.7). APPENDIX C TO PART 192 - QUALIFICATION OF WELDERS FOR LOW STRESS LEVEL PIPE I. Basic Test The test is made on pipe 12 inches (305 millimeters) or less in diameter. The test weld must be made with the pipe in a horizontal fixed position so that the test weld includes at least one section of overhead position welding. The beveling, root opening and other details must conform to the specifications of the procedure under which the welder is being qualified. Upon completion, the test weld is cut into four coupons and subjected to a root bend test. If, as a result of this test, two or more of the four coupons develop a crack in the weld material or between the weld material and base metal, that is more than 1/8 inch (3.2 millimeters) long in any direction, the weld is unacceptable. Cracks that occur on the corner of the specimen during testing are not considered. A welder who successfully passes a butt-weld qualification test under this section shall be qualified to weld on all pipe diameters less than or equal to 12 inches. II. Additional Tests for Welders of Service Line Connections to Mains A service line connection fitting is welded to a pipe section with the same diameter as a typical main. The weld is made in the same position as it is made in the field. The weld is unacceptable if it shows a serious undercutting or if it has rolled edges. The weld is tested by attempting to break the fitting off the run pipe. The weld is unacceptable if it breaks and shows incomplete fusion, overlap, or poor penetration at the junction of the fitting and run pipe. III. Periodic Tests for Welders of Small Service Lines Two samples of the welder's work, each about 8 inches (203 millimeters) long with the weld located approximately in the center, are cut from steel service line and tested as follows:#

(1)One sample is centered in a guided bend testing machine and bent to the contour of the die for a distance of 2 inches (51 millimeters) on each side of the weld. If the sample shows any breaks or cracks after removal from the bending machine, it is unacceptable.#

(2)The ends of the second sample are flattened and the entire joint subjected to a tensile strength test. If failure occurs adjacent to or in the weld metal, the weld is unacceptable. If a tensile strength testing machine is not available, this sample must also pass the bending test prescribed in Subparagraph#

(1)of this paragraph. APPENDIX D TO PART 192 - CRITERIA FOR CATHODIC PROTECTION AND DETERMINATION OF MEASUREMENTS I. Criteria for Cathodic Protection A. Steel, cast iron, and ductile iron structures#

(1)A negative#

(cathodic)voltage of at least 0.85 volt, with reference to a saturated copper- copper sulfate half- cell. Determination of this voltage must be made with the protective current applied, and in accordance with Sections II and IV of this Appendix.#

(2)A negative#

(cathodic)voltage shift of at least 300 millivolts. Determination of this voltage shift must be made with the protective current applied, and in accordance with Sections II and IV of this A ppendix. This criterion of voltage shift applies to structures not in contact with metal of different anodic potentials.#

(3)A minimum negative#

(cathodic)polarization voltage shift of 100 millivolts. This polarization voltage shift must be determined in accordance with Sections III and IV of this Appendix.#

(4)A voltage at least as negative#

(cathodic)as that originally established at the beginning of the Tafel segment of the E-log-I curve. This voltage must be measured in accordance with Section IV of this appendix.#

(5)A net protective current from the electrolyte into the structure surface as measured by an earth current technique applied at predetermined current discharge#

(anodic)points of the structure. B. Aluminum structures#

(1)Except as provided in Subparagraphs#

(3)and#

(4)of this paragraph, a minimum negative#

(cathodic)voltage shift of 150 millivolts, produced by the application of protective current. The voltage shift must be determined in accordance with Sections II and IV of this Appendix.#

(2)Except as provided in Subparagraphs#

(3)and#

(4)of this paragraph, a minimum negative#

(cathodic)polarization voltage shift of 100 millivolts. This polarization voltage shift must be determined in accordance with Sections III and IV of this Appendix.#

(3)Notwithstanding the alternative minimum criteria in Subparagraphs#

(1)and#

(2)of this paragraph, aluminum, if cathodically protected at voltages in excess of 1.20 volts as measured with reference to a copper-copper sulfate half-cell, in accordance with Section IV of this appendix, and compensated for the voltage#

(IR)drops other than those across the structure-electrolyte boundary, may suffer corrosion resulting from the buildup of alkali on the metal surface. A voltage in excess of 1.20 volts may not be used unless previous test results indicate no appreciable corrosion will occur in the particular environment.#

(4)Since aluminum may suffer from corrosion under high pH conditions, and since application of cathodic protection tends to increase the pH at the metal surface, careful investigation or testing must be made before applying cathodic protection to stop pitting attack on aluminum structures in environments with a natural pH in excess of 8. C. Copper structures A minimum negative#

(cathodic)polarization voltage shift of 100 millivolts. This polarization voltage shift must be determined in accordance with Sections III and IV of this Appendix. D. Metals of different anodic potentials A negative#

(cathodic)voltage, measured in accordance with Section IV of this appendix, equal to that required for the most anodic metal in the system must be maintained. If amphoteric structures are involved that could be damaged by high alkalinity covered by Subparagraphs#

(3)and#

(4)of paragraph B of this section, they must be electrically isolated with insulating flanges, or the equivalent. II. Interpretation of Voltage Measurement Voltage#

(IR)drops other than those across the structure-electrolyte boundary must be considered for valid interpretation of the voltage measurement in paragraphs A(1) and#

(2)and paragraph B(1) of Section I of this appendix. III. Determination of Polarization Voltage Shift The polarization voltage shift must be determined by interrupting the protective current and measuring the polarization decay. When the current is initially interrupted, an immediate voltage shift occurs. The voltage reading after the immediate shift must be used as the base reading from which to measure polarization decay in paragraphs A(3), B(2), and C of Section I of this appendix. IV. Reference Half Cells A. Except as provided in paragraphs B and C of this section, negative#

(cathodic)voltage must be measured between the structure surface and a saturated copper-copper sulfate half cell contacting the electrolyte. B. Other standard reference half cells may be substituted for the saturated copper-copper sulfate half-cell. Two commonly used reference half cells are listed below along with their voltage equivalent to -0.85 volt as referred to a saturated copper- copper sulfate half cell:#

(1)Saturated KCl calomel half cell: -0.78 volt.#

(2)Silver-silver chloride half-cell used in sea water: -0.80 volt. C. In addition to the standard reference half cells, an alternate metallic material or structure may be used in place of the saturated copper sulfate half- cell if its potential stability is assured and if its voltage equivalent referred to a saturated copper-copper sulfate half- cell is established. APPENDIX E TO PART 192 - GUIDANCE ON DETERMINING HIGH CONSEQUENCE AREAS AND ON CARRYING OUT REQUIREMENTS IN THE INTEGRITY MANAGEMENT RULE I. Guidance on Determining a High Consequence Area To determine which segments of an operator's transmission pipeline system are covered for purposes of the integrity management program requirements, an operator must identify the high consequence areas. An operator must use method#

(1)or#

(2)from the definition in § 192.903 to identify a high consequence area. An operator may apply one method to its entire pipeline system, or an operator may apply one method to individual portions of the pipeline system. (Refer to figure E.1.A for a diagram of a high consequence area). Determining High Consequence Area School ABC Pipeline HCA Figure E.l.A II. Guidance on Assessment Methods and Additional Preventive and Mitigative Measures for Transmission Pipelines#

(a)Table E.11.1 gives guidance to help an operator implement requirements on additional preventive and mitigative measures for addressing time dependent and independent threats for a transmission pipeline operating below 30% SMYS not in an HCA (i.e. outside of potential impact circle) but located within a Class 3 or Class 4 Location.#

(b)Table E.11.2 gives guidance to help an operator implement requirements on assessment methods for addressing time dependent and independent threats for a transmission pipeline in an HCA.#

(c)Table E.11.3 gives guidance on preventative & mitigative measures addressing time dependent and independent threats for transmission pipelines that operate below 30% SMYS, in HCAs. Table E.II.1 Preventive and Mitigative Measures for Transmission Pipelines Operating Below 30% SMYS not in an HCA but in a Class 3 or Class 4 Location (Column 1) Threat Existing 192 Requirements (Column 4) Additional (to 192 requirements) Preventive and Mitigative External Corrosion…….. 455-(Gen. Post 1971), 457-(Gen. Pre-1971). 459-(Examination), 461-(Ext. coating). 463-(CP), 465-(Monitoring). 467-(Elect isolation), (469-Test stations). 471-(Test leads), 473- (Interference). 479-(Atmospheric), 481- (Atmospheric). 485-(Remedial), 705-(Patrol). 706-(Leak survey), 711 -(Repair-gen.) 717-(Repair-perm.) ……. 603 - (Gen Operation)…… 613 - (Surveillance)………… …………………………… ….. • For Cathodically Protected Transmission Pipeline: • Perform semi-annual leak surveys. • For Unprotected Transmission Pipelines or for Cathodically Protected Pipe where Electrical Surveys are Impractical: • Perform quarterly leak surveys Internal Corrosion 475-(Gen IC), 477-(IC monitoring). 485-(Remedial), 705-(Patrol). 706-(Leak survey), 711-(Repair- gen.). 717-(Repair - perm.). 53(a)-(Materials). 6 0 3 - ( G e n. O p e r ' n). 613-(Surveillance). • Perform quarterly leak surveys. Perform semi-annual leak surveys. 103-(Gen. Design), 111-(Design factor). •Participation in state one-call system, 317-(Hazard prot), 327-(Cover). 3rd Party Damage 614-(Dam. Prevent), 616-(Public education). 615 (Emerg. Plan) •Use of qualified operator employees and contractors to perform marking and locating of buried structures and in direct supervision of excavation work, AND 705-(Patrol), 707-(Line markers). 711 (Repair-gen.), 717-(Repair- perm.). •Either monitoring of excavations near operator's transmission pipelines, or bi-monthly patrol of transmission pipelines in class 3 and 4 locations. Any indications of unreported construction activity would require a follow up investigation to determine if mechanical damage occurred. Table E.II.2 Assessment Requirements for Transmission Pipelines in HCAs (Re-assessment intervals are maximum allowed) [table on next page] Re-Assessment Requirements (see Note 3) At or above 50% SMYS At or above 30% SMYS Below 30% SMYS Baseline Assessment Method Max Re-Assessment Interval Assessment Method (see Note 3) Max Re- Assessment Interval Assessment Method Max Re-Assessment Interval Assessment Method 7 CDA 7 CDA 10 Pressure Test or ILI or DA Ongoing Preventative & Mitigative (P&M) Measures (see Table E.II.3), (see Note 2) Pressure Testing 15 (see Note 1) Repeat inspection cycle every 10 years Pressure Test or ILI or DA (see Note 1) Repeat inspection cycle every 15 years 20 Pressure Test or ILI or DA Repeat inspection cycle every 20 years 7 CDA 7 CDA 10 ILI or DA or Pressure Test Ongoing Preventative & Mitigative (P&M) Measures (see Table E.II.3), (see Note 2) In-Line Inspection 15 (see Note 1) Repeat inspection cycle every 10 years ILI or DA or Pressure Test (see Note 1) Repeat inspection cycle every 15 years 20 ILI or DA or Pressure Test Repeat inspection cycle every 20 years 7 CDA 7 CDA Ongoing Preventative & Mitigative (P&M) Measures (see Table E.II.3), (see Note 2) 10 Direct DA or ILI or Pressure Test Assessment 15 (see Note 1) DA or ILI or Pressure Test (see Note 1) Repeat inspection cycle every 10 years Repeat inspection cycle every 15 years 20 DA or ILI or Pressure Test Repeat inspection cycle every 20 years Note 1: Operator may choose to utilize CDA at year 14, then utilize ILI, Pressure Test, or DA at year 15 as allowed under ASME B31.8S. Note 2: Operator may choose to utilize CDA at year 7 and 14 in lieu of P&M. Note 3: Operator may utilize "other technology that an operator demonstrates can provide an equivalent understanding of the condition of line pipe." Table E.II.3 Preventative & Mitigative Measures addressing Time Dependent and Independent Threats for Transmission Pipelines that Operate Below 30% SMYS, in HCAs Existing 192 Requirements Additional (to 192 requirements) Preventive & Threat Mitigative Measures Primary Secondary External Corrosion 455 - (Gen. Post 1971) 457 - (Gen. pre1971) 459 -#

(Examination)461 - (Ext. coating) 463 -#

(CP)465 -#

(Monitoring)467 - (Elect isolation) 603 - (Gen Oper) 613 -#

(Surveil)For Cathodically protected Trmn. Pipelines •Perform an electrical survey (i.e. indirect examination tool/method) at least every 7 years. Results are to be utilized as part of an overall evaluation of the CP system and corrosion threat for the covered segment. Evaluation shall include consideration of leak repair and ispection records, corrosion monitoring records, exposed pipe inspection records, and the pipeline environment. External Corrosion 469 - (Test stations) 471 - (Test leads) 473 -#

(Interference)479 -#

(Atmospheric)481 -#

(Atmospheric)485 -#

(Remedial)705 -#

(Patrol)706 - (Leak survey) 711 - (repair - gen.) 717 - (Repair perm.) For Unprotected Trmn. Pipelines or for Cathodically protected Pipe where Electrical Surveys are Impracticable •Conduct quarterly leak surveys AND •Every 1 1/2 years, determine areas of active corrosion by evaluation of leak repair and inspection records, corrosion monitoring records, exposed pipe inspection records, and the pipeline environment. Internal Corrosion 475 - (Gen IC) 477 - (IC monitoring) 485 -#

(Remedial)705 -#

(Patrol)706 - (Leak survey) 711 - (repair - gen.) 717 - (Repair perm.) 53#

(a)-#

(Materials)603 - (Gen Oper) 613 -#

(Surveil)•Obtain and review gas analysis data each calendar year for corrosive agents from transmission pipelines in HCAs, •Periodic testing of fluid removed from pipelines. Specifically, once each calendar year from each storage field that may affect transmission pipelines in HCAs, AND •At least every 7 years, integrate data obtained with applicable internal corrosion leak records, incident reports, safety related condition reports, repair records, patrol records, exposed pipe reports, and test records. •Participation in state one-call system, •Use of qualified operator employees and contractors to perform making and locating of buried structures and in direct supervision of excavation work, AND 615 - (Emerg Plan) 3rd Party Damage 103 - (Gen. Design) 111 - (Design factor) 317 - (Hazard prot) 327 -#

(cover)614 - (Dam. Prevent) 616 - (Public educat) 705 -#

(Patrol)707 - (Line markers) 711 - (repair - gen.) 717 - (Repair-perm.) •Either monitoring of excavations near operator's transmission pipelines, or bi-monthly patrol of transmission pipelines in HCAs or class 3 or 4 locations. Any indications of unreported construction activity would require a follow up investigation to determine if mechanical damage occurred. APPENDIX F TO PART 192 - CRITERIA FOR CONDUCTING INTEGRITY ASSESSMENTS USING GUIDED WAVE ULTRASONIC TESTING#

(GWUT)This appendix defines criteria which must be properly implemented for use of guided wave ultrasonic testing#

(GWUT)as an integrity assessment method. Any application of GWUT that does not conform to these criteria is considered "other technology" as described by §§ 192.710(c)(7), 192.921(a)(7), and 192.937(c)(7), for which OPS must be notified 90 days prior to use in accordance with §§ 192.921(a)(7) or 192.937(c)(7). GWUT in the "Go-No Go" mode means that all indications (wall loss anomalies) above the testing threshold (a maximum of 5% of cross-sectional area#

(CSA)sensitivity) be directly examined, in-line tool inspected, pressure tested, or replaced prior to completing the integrity assessment on the carrier pipe. I. Equipment and Software: Generation. The equipment and the computer software used are critical to the success of the inspection. Computer software for the inspection equipment must be reviewed and updated, as required, on an annual basis, with intervals not to exceed 15 months, to support sensors, enhance functionality, and resolve any technical or operational issues identified. II. Inspection Range. The inspection range and sensitivity are set by the signal to noise (S/N) ratio but must still keep the maximum threshold sensitivity at 5% cross sectional area (CSA). A signal that has an amplitude that is at least twice the noise level can be reliably interpreted. The greater the S/N ratio the easier it is to identify and interpret signals from small changes. The signal to noise ratio is dependent on several variables such as surface roughness, coating, coating condition, associated pipe fittings (T's, elbows, flanges), soil compaction, and environment. Each of these affects the propagation of sound waves and influences the range of the test. It may be necessary to inspect from both ends of the pipeline segment to achieve a full inspection. In general, the inspection range can approach 60 to 100 feet for a 5% CSA, depending on field conditions. III. Complete Pipe Inspection. To ensure that the entire pipeline segment is assessed there should be at least a 2 to 1 signal to noise ratio across the entire pipeline segment that is inspected. This may require multiple GWUT shots. Double-ended inspections are expected. These two inspections are to be overlaid to show the minimum 2 to 1 S/N ratio is met in the middle. If possible, show the same near or midpoint feature from both sides and show an approximate 5% distance overlap. IV. Sensitivity. The detection sensitivity threshold determines the ability to identify a cross-sectional change. The maximum threshold sensitivity cannot be greater than 5% of the cross-sectional area (CSA). The locations and estimated CSA of all metal loss features in excess of the detection threshold must be determined and documented. All defect indications in the "Go-No-Go" mode above the 5% testing threshold must be directly examined, in-line inspected, pressure tested, or replaced prior to completing the integrity assessment. V. Wave Frequency. Because a single wave frequency may not detect certain defects, a minimum of three frequencies must be run for each inspection to determine the best frequency for characterizing indications. The frequencies used for the inspections must be documented and must be in the range specified by the manufacturer of the equipment. VI. Signal or Wave Type: Torsional and Longitudinal. Both torsional and longitudinal waves must be used, and use must be documented. VII. Distance Amplitude Correction#

(DAC)Curve and Weld Calibration. The distance amplitude correction curve accounts for coating, pipe diameter, pipe wall and environmental conditions at the assessment location. The DAC curve must be set for each inspection as part of establishing the effective range of a GWUT inspection. DAC curves provide a means for evaluating the cross- sectional area change of reflections at various distances in the test range by assessing signal to noise ratio. A DAC curve is a means of taking apparent attenuation into account along the time base of a test signal. It is a line of equal sensitivity along the trace which allows the amplitudes of signals at different axial distances from the collar to be compared. VIII. Dead Zone. The dead zone is the area adjacent to the collar in which the transmitted signal blinds the received signal, making it impossible to obtain reliable results. Because the entire line must be inspected, inspection procedures must account for the dead zone by requiring the movement of the collar for additional inspections. An alternate method of obtaining valid readings in the dead zone is to use B- scan ultrasonic equipment and visual examination of the external surface. The length of the dead zone and the near field for each inspection must be documented. IX. Near Field Effects. The near field is the region beyond the dead zone where the receiving amplifiers are increasing in power, before the wave is properly established. Because the entire line must be inspected, inspection procedures must account for the near field by requiring the movement of the collar for additional inspections. An alternate method of obtaining valid readings in the near field is to use B- scan ultrasonic equipment and visual examination of the external surface. The length of the dead zone and the near field for each inspection must be documented. X. Coating Type. Coatings can have the effect of attenuating the signal. Their thickness and condition are the primary factors that affect the rate of signal attenuation. Due to their variability, coatings make it difficult to predict the effective inspection distance. Several coating types may affect the GWUT results to the point that they may reduce the expected inspection distance. For example, concrete coated pipe may be problematic when well bonded due to the attenuation effects. If an inspection is done and the required sensitivity is not achieved for the entire length of the pipe, then another type of assessment method must be utilized. XI. End Seal. When assessing cased carrier pipe with GWUT, operators must remove the end seal from the casing at each GWUT test location to facilitate visual inspection. Operators must remove debris and water from the casing at the end seals. Any corrosion material observed must be removed, collected and reviewed by the operator's corrosion technician. The end seal does not interfere with the accuracy of the GWUT inspection but may have a dampening effect on the range. XII. Weld Calibration to set DAC Curve. Accessible welds, along or outside the pipeline segment to be inspected, must be used to set the DAC curve. A weld or welds in the access hole (secondary area) may be used if welds along the pipeline segment are not accessible. In order to use these welds in the secondary area, sufficient distance must be allowed to account for the dead zone and near field. There must not be a weld between the transducer collar and the calibration weld. A conservative estimate of the predicted amplitude for the weld is 25% CSA (cross sectional area) and can be used if welds are not accessible. Calibrations (setting of the DAC curve) should be on pipe with similar properties such as wall thickness and coating. If the actual weld cap height is different from the assumed weld cap height, the estimated CSA may be inaccurate and adjustments to the DAC curve may be required. Alternative means of calibration can be used if justified by a documented engineering analysis and evaluation. XIII. Validation of Operator Training. Pipeline operators must require all guided wave service providers to have equipment-specific training and experience for all GWUT Equipment Operators which includes training for: • Equipment operation, • field data collection, and • data interpretation on cased and buried pipe. Only individuals who have been qualified by the manufacturer or an independently assessed evaluation procedure similar to ISO 9712 (Sections: 5 Responsibilities; 6 Levels of Qualification; 7 Eligibility; and 10 Certification), as specified above, may operate the equipment. A senior-level GWUT equipment operator with pipeline specific experience must provide onsite oversight of the inspection and approve the final reports. A senior-level GWUT equipment operator must have additional training and experience, including training specific to cased and buried pipe, with a quality control program which that conforms to Section 12 of ASME B31.8S (for availability, see § 192.7). XIV. Training and Experience Minimums for Senior Level GWUT Equipment Operators: • Equipment Manufacturer's minimum qualification for equipment operation and data collection with specific endorsements for casings and buried pipe • Training, qualification and experience in testing procedures and frequency determination • Training, qualification and experience in conversion of guided wave data into pipe features and estimated metal loss (estimated cross-sectional area loss and circumferential extent) • Equipment Manufacturer's minimum qualification with specific endorsements for data interpretation of anomaly features for pipe within casings and buried pipe. XV. Equipment: Traceable from vendor to inspection company. An operator must maintain documentation of the version of the GWUT software used and the serial number of the other equipment such as collars, cables, etc., in the report. XVI. Calibration Onsite. The GWUT equipment must be calibrated for performance in accordance with the manufacturer's requirements and specifications, including the frequency of calibrations. A diagnostic check and system check must be performed on-site each time the equipment is relocated to a different casing or pipeline segment. If on-site diagnostics show a discrepancy with the manufacturer's requirements and specifications, testing must cease until the equipment can be restored to manufacturer's specifications. XVII. Use on Shorted Casings (direct or electrolytic). GWUT may not be used to assess shorted casings. GWUT operators must have operations and maintenance procedures (see § 192.605) to address the effect of shorted casings on the GWUT signal. The equipment operator must clear any evidence of interference, other than some slight dampening of the GWUT signal from the shorted casing, according to their operating and maintenance procedures. All shorted casings found while conducting GWUT inspections must be addressed by the operator's standard operating procedures. XVIII. Direct examination of all indications above the detection sensitivity threshold. The use of GWUT in the "Go-No Go" mode requires that all indications (wall loss anomalies) above the testing threshold (5% of CSA sensitivity) be directly examined (or replaced) prior to completing the integrity assessment on the cased carrier pipe or other GWUT application. If this cannot be accomplished, then alternative methods of assessment (such as hydrostatic pressure tests or ILI) must be utilized. XIX. Timing of direct examination of all indications above the detection sensitivity threshold. Operators must either replace or conduct direct examinations of all indications identified above the detection sensitivity threshold according to the table below. Operators must conduct leak surveys and reduce operating pressure as specified until the pipe is replaced or direct examinations are completed. Required Response to GWUT Indications GWUT criterion Operating pressure less Operating pressure over Operating pressure over than or equal to 30 and less 50% SMYS 30% SMYS than or equal to 50 SMYS Over the detection sensitivity threshold (maximum of 5% CSA) Replace or direct examination within 12 months, and instrumented leak survey once every 30 calendar days Replace or direct examination within 6 months, instrumented leak survey once every 30 calendar days, and maintain MAOP below the operating pressure at time of discovery Replace or direct examination within 6 months, instrumented leak survey once every 30 calendar days, and reduce MAOP to 80% of operating pressure at time of discovery. PART 199 - DRUG AND ALCOHOL TESTING SUBPART A - GENERAL#