美国联邦法律 交通运输部 49 cfr 195 F

Research and Special Programs Administration, DOT §195.401

(c) For aboveground breakout tanks built to API Standard 650 and first placed in service after October 2, 2000, hydrostatic and pneumatic testing must be in accordance with section 5.3 of API Standard 650.

(d) For aboveground atmospheric pressure breakout tanks constructed of carbon and low alloy steel, welded or riveted, and non-refrigerated and tanks built to API Standard 650 or its prede-cessor Standard 12C that are returned to service after October 2, 2000, the ne-cessity for the hydrostatic testing of repair, alteration, and reconstruction is covered in section 10.3 of API Stand-ard 653.

(e) For aboveground breakout tanks built to API Standard 2510 and first placed in service after October 2, 2000, pressure testing must be in accordance with ASME Boiler and Pressure Vessel Code, Section VIII, Division 1 or 2. [Amdt. 195–66, 64 FR 15936, Apr. 2, 1999]

§195.308Testing of tie-ins.

Pipe associated with tie-ins must be pressure tested, either with the section to be tied in or separately.

[Amdt. 195–22, 46 FR 38360, July 27, 1981, as amended by 195–51, 59 FR 29385, June 7, 1994] §195.310Records.

(a) A record must be made of each pressure test required by this subpart, and the record of the latest test must be retained as long as the facility test-ed is in use.

(b) The record required by paragraph

(a) of this section must include:

(1) The pressure recording charts;

(2) Test instrument calibration data;

(3) The name of the operator, the name of the person responsible for making the test, and the name of the test company used, if any;

(4) The date and time of the test;

(5) The minimum test pressure;

(6) The test medium;

(7) A description of the facility tested and the test apparatus;

(8) An explanation of any pressure discontinuities, including test failures, that appear on the pressure recording charts;

(9) Where elevation differences in the section under test exceed 100 feet (30 meters), a profile of the pipeline that shows the elevation and test sites over the entire length of the test section; and

(10) Temperature of the test medium or pipe during the test period.

[Amdt. 195–34, 50 FR 34474, Aug. 26, 1985, as amended by Amdt. 195–51, 59 FR 29385, June 7, 1994; Amdt. 195–63, 63 FR 37506, July 13, 1998; Amdt. 195–78, 68 FR 53528, Sept. 11, 2003] Subpart F—Operation and

Maintenance

§195.400Scope.

This subpart prescribes minimum re-quirements for operating and main-taining pipeline systems constructed with steel pipe.

§195.401General requirements.

(a) No operator may operate or main-tain its pipeline systems at a level of safety lower than that required by this subpart and the procedures it is re-quired to establish under §195.402(a) of this subpart.

(b) Whenever an operator discovers any condition that could adversely af-fect the safe operation of its pipeline system, it shall correct it within a rea-sonable time. However, if the condition is of such a nature that it presents an immediate hazard to persons or prop-erty, the operator may not operate the affected part of the system until it has corrected the unsafe condition.

(c) Except as provided in §195.5, no operator may operate any part of any of the following pipelines unless it was designed and constructed as required by this part:

(1) An interstate pipeline, other than

a low-stress pipeline, on which con-struction was begun after March 31, 1970, that transports hazardous liquid. (2) An interstate offshore gathering line, other than a low-stress pipeline, on which construction was begun after July 31, 1977, that transports hazardous liquid.

(3) An intrastate pipeline, other than

a low-stress pipeline, on which con-struction was begun after October 20, 1985, that transports hazardous liquid. (4) A pipeline on which construction was begun after July 11, 1991, that transports carbon dioxide.

49 CFR Ch. I (10–1–04 Edition) §195.402

(5) A low-stress pipeline on which construction was begun after August 10, 1994.

[Amdt. 195–22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195–33, 50 FR 15899, Apr. 23, 1985; Amdt. 195–33A, 50 FR 39008, Sept. 26, 1985; Amdt. 195–36, 51 FR 15008, Apr. 22, 1986; Amdt. 195–45, 56 FR 26926, June 12, 1991; Amdt. 195–53, 59 FR 35471, July 12, 1994]

§195.402Procedural manual for oper-ations, maintenance, and emer-

gencies.

(a) General. Each operator shall pre-pare and follow for each pipeline sys-tem a manual of written procedures for conducting normal operations and maintenance activities and handling abnormal operations and emergencies. This manual shall be reviewed at inter-vals not exceeding 15 months, but at least once each calendar year, and ap-propriate changes made as necessary to insure that the manual is effective. This manual shall be prepared before initial operations of a pipeline system commence, and appropriate parts shall be kept at locations where operations and maintenance activities are con-ducted.

(b) The Administrator or the State Agency that has submitted a current certification under the pipeline safety laws (49 U.S.C. 60101 et seq.) with re-spect to the pipeline facility governed by an operator’s plans and procedures may, after notice and opportunity for hearing as provided in 49 CFR 190.237 or the relevant State procedures, require the operator to amend its plans and procedures as necessary to provide a reasonable level of safety.

(c) Maintenance and normal operations. The manual required by paragraph (a) of this section must include procedures for the following to provide safety dur-ing maintenance and normal oper-ations:

(1) Making construction records, maps, and operating history available as necessary for safe operation and maintenance.

(2) Gathering of data needed for re-porting accidents under subpart B of this part in a timely and effective man-ner.

(3) Operating, maintaining, and re-pairing the pipeline system in accord-ance with each of the requirements of this subpart and subpart H of this part. (4) Determining which pipeline facili-ties are located in areas that would re-quire an immediate response by the op-erator to prevent hazards to the public

if the facilities failed or malfunctioned. (5) Analyzing pipeline accidents to determine their causes.

(6) Minimizing the potential for haz-ards identified under paragraph (c)(4) of this section and the possibility of re-currence of accidents analyzed under paragraph (c)(5) of this section.

(7) Starting up and shutting down any part of the pipeline system in a manner designed to assure operation within the limits prescribed by §195.406, consider the hazardous liquid or carbon dioxide in transportation, variations in altitude along the pipe-line, and pressure monitoring and con-trol devices.

(8) In the case of a pipeline that is not equipped to fail safe, monitoring from an attended location pipeline pressure during startup until steady state pressure and flow conditions are reached and during shut-in to assure operation within limits prescribed by §195.406.

(9) In the case of facilities not equipped to fail safe that are identified under paragraph 195.402(c)(4) or that control receipt and delivery of the haz-ardous liquid or carbon dioxide, detect-ing abnormal operating conditions by monitoring pressure, temperature, flow or other appropriate operational data and transmitting this data to an at-tended location.

(10) Abandoning pipeline facilities, including safe disconnection from an operating pipeline system, purging of combustibles, and sealing abandoned facilities left in place to minimize safe-

ty and environmental hazards. For each abandoned offshore pipeline facil-

ity or each abandoned onshore pipeline facility that crosses over, under or through commercially navigable wa-terways the last operator of that facil-

ity must file a report upon abandon-ment of that facility in accordance with §195.59 of this part.

(11) Minimizing the likelihood of ac-cidental ignition of vapors in areas near facilities identified under para-graph (c)(4) of this section where the

Research and Special Programs Administration, DOT §195.402

potential exists for the presence of flammable liquids or gases.

(12) Establishing and maintaining li-aison with fire, police, and other appro-priate public officials to learn the re-sponsibility and resources of each gov-ernment organization that may re-spond to a hazardous liquid or carbon dioxide pipeline emergency and ac-quaint the officials with the operator’s ability in respondinq to a hazardous liquid or carbon dioxide pipeline emer-gency and means of communication. (13) Periodically reviewing the work done by operator personnel to deter-mine the effectiveness of the proce-dures used in normal operation and maintenance and taking corrective ac-tion where deficiencies are found.

(14) Taking adequate precautions in excavated trenches to protect per-sonnel from the hazards of unsafe accu-mulations of vapor or gas, and making available when needed at the exca-vation, emergency rescue equipment, including a breathing apparatus and, a rescue harness and line.

(d) Abnormal operation. The manual required by paragraph (a) of this sec-tion must include procedures for the following to provide safety when oper-ating design limits have been exceeded: (1) Responding to, investigating, and correcting the cause of:

(i) Unintended closure of valves or shutdowns;

(ii) Increase or decrease in pressure or flow rate outside normal operating limits;

(iii) Loss of communications;

(iv) Operation of any safety device; (v) Any other malfunction of a com-ponent, deviation from normal oper-ation, or personnel error which could cause a hazard to persons or property.

(2) Checking variations from normal operation after abnormal operation has ended at sufficient critical locations in the system to determine continued in-tegrity and safe operation.

(3) Correcting variations from normal operation of pressure and flow equip-ment and controls.

(4) Notifying responsible operator personnel when notice of an abnormal operation is received.

(5) Periodically reviewing the re-sponse of operator personnel to deter-mine the effectiveness of the proce-dures controlling abnormal operation and taking corrective action where de-ficiencies are found.

(e) Emergencies. The manual required by paragraph (a) of this section must include procedures for the following to provide safety when an emergency con-dition occurs:

(1) Receiving, identifying, and classifying notices of events which need immediate response by the oper-ator or notice to fire, police, or other appropriate public officials and com-municating this information to appro-priate operator personnel for correc-tive action.

(2) Prompt and effective response to a notice of each type emergency, includ-

ing fire or explosion occurring near or directly involving a pipeline facility, accidental release of hazardous liquid or carbon dioxide from a pipeline facil-ity, operational failure causing a haz-ardous condition, and natural disaster affecting pipeline facilities.

(3) Having personnel, equipment, in-struments, tools, and material avail-able as needed at the scene of an emer-gency.

(4) Taking necessary action, such as emergency shutdown or pressure reduc-tion, to minimize the volume of haz-ardous liquid or carbon dioxide that is released from any section of a pipeline system in the event of a failure.

(5) Control of released hazardous liq-

uid or carbon dioxide at an accident scene to minimize the hazards, includ-

ing possible intentional ignition in the cases of flammable highly volatile liq-uid.

(6) Minimization of public exposure to injury and probability of accidental ignition by assisting with evacuation of residents and assisting with halting traffic on roads and railroads in the af-fected area, or taking other appro-priate action.

(7) Notifying fire, police, and other appropriate public officials of haz-ardous liquid or carbon dioxide pipeline emergencies and coordinating with them preplanned and actual responses during an emergency, including addi-tional precautions necessary for an emergency involving a pipeline system transporting a highly volatile liquid.

(8) In the case of failure of a pipeline system transporting a highly volatile

49 CFR Ch. I (10–1–04 Edition) §195.403

liquid, use of appropriate instruments to assess the extent and coverage of the vapor cloud and determine the haz-ardous areas.

(9) Providing for a post accident re-view of employee activities to deter-mine whether the procedures were ef-fective in each emergency and taking corrective action where deficiencies are found.

(f) Safety-related condition reports. The manual required by paragraph (a) of this section must include instructions enabling personnel who perform oper-ation and maintenance activities to recognize conditions that potentially may be safety-related conditions that are subject to the reporting require-ments of §195.55.

[Amdt. 195–22, 46 FR 38360, July 27, 1981; 47 FR 32721, July 29, 1982, as amended by Amdt. 195–24, 47 FR 46852, Oct. 21, 1982; Amdt. 195–39, 53 FR 24951, July 1, 1988; Amdt. 195–45, 56 FR 26926, June 12, 1991; Amdt. 195–46, 56 FR 31090, July 9, 1991; Amdt. 195–49, 59 FR 6585, Feb. 11, 1994; Amdt. 195–55, 61 FR 18518, Apr. 26, 1996; Amdt. 195–69, 65 FR 54444, Sept. 8, 2000; Amdt. 195–173, 66 FR 67004, Dec. 27, 2001]

§195.403Emergency response train-ing.

(a) Each operator shall establish and conduct a continuing training program to instruct emergency response per-sonnel to:

(1) Carry out the emergency proce-dures established under 195.402 that re-late to their assignments;

(2) Know the characteristics and haz-ards of the hazardous liquids or carbon dioxide transported, including, in case of flammable HVL, flammability of mixtures with air, odorless vapors, and water reactions;

(3) Recognize conditions that are likely to cause emergencies, predict the consequences of facility malfunc-tions or failures and hazardous liquids or carbon dioxide spills, and take ap-propriate corrective action;

(4) Take steps necessary to control any accidental release of hazardous liq-uid or carbon dioxide and to minimize the potential for fire, explosion, tox-icity, or environmental damage; and (5) Learn the potential causes, types, sizes, and consequences of fire and the appropriate use of portable fire extin-guishers and other on-site fire control equipment, involving, where feasible, a simulated pipeline emergency condi-tion.

(b) At the intervals not exceeding 15 months, but at least once each cal-endar year, each operator shall:

(1) Review with personnel their per-formance in meeting the objectives of the emergency response training pro-gram set forth in paragraph (a) of this section; and

(2) Make appropriate changes to the emergency response training program as necessary to ensure that it is effec-tive.

(c) Each operator shall require and verify that its supervisors maintain a thorough knowledge of that portion of the emergency response procedures es-tablished under 195.402 for which they are responsible to ensure compliance. [Amdt. 195–67, 64 FR 46866, Aug. 27, 1999, as amended at Amdt. 195–78, 68 FR 53528, Sept. 11, 2003]

§195.404Maps and records.

(a) Each operator shall maintain cur-rent maps and records of its pipeline systems that include at least the fol-lowing information:

(1) Location and identification of the following pipeline facilities:

(i) Breakout tanks;

(ii) Pump stations;

(iii) Scraper and sphere facilities; (iv) Pipeline valves;

(v) Facilities to which §195.402(c)(9) applies;

(vi) Rights-of-way; and

(vii) Safety devices to which §195.428 applies.

(2) All crossings of public roads, rail-roads, rivers, buried utilities, and for-eign pipelines.

(3) The maximum operating pressure of each pipeline.

(4) The diameter, grade, type, and nominal wall thickness of all pipe.

(b) Each operator shall maintain for at least 3 years daily operating records that indicate—

(1) The discharge pressure at each pump station; and

(2) Any emergency or abnormal oper-ation to which the procedures under §195.402 apply.

(c) Each operator shall maintain the following records for the periods speci-fied:

Research and Special Programs Administration, DOT §195.408

(1) The date, location, and descrip-

tion of each repair made to pipe shall

be maintained for the useful life of the pipe.

(2) The date, location, and descrip-

tion of each repair made to parts of the pipeline system other than pipe shall

be maintained for at least 1 year.

(3) A record of each inspection and test required by this subpart shall be maintained for at least 2 years or until

the next inspection or test is per-formed, whichever is longer.

[Amdt. 195–22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195–34, 50 FR 34474, Aug. 26, 1985; Amdt. 195–173, 66 FR 67004, Dec. 27, 2001]

§195.405Protection against ignitions and safe access/egress involving

floating roofs.

(a) After October 2, 2000, protection provided against ignitions arising out

of static electricity, lightning, and stray currents during operation and maintenance activities involving aboveground breakout tanks must be

in accordance with API Recommended Practice 2003, unless the operator notes

in the procedural manual (§195.402(c)) why compliance with all or certain pro-visions of API Recommended Practice 2003 is not necessary for the safety of a particular breakout tank.

(b) The hazards associated with ac-cess/egress onto floating roofs of in- service aboveground breakout tanks to perform inspection, service, mainte-nance or repair activities (other than specified general considerations, speci-

fied routine tasks or entering tanks re-moved from service for cleaning) are addressed in API Publication 2026. After October 2, 2000, the operator must review and consider the potentially hazardous conditions, safety practices and procedures in API Publication 2026

for inclusion in the procedure manual (§195.402(c)).

[Amdt. 195–66, 64 FR 15936, Apr. 2, 1999]

§195.406Maximum operating pres-sure.

(a) Except for surge pressures and other variations from normal oper-ations, no operator may operate a pipe-

line at a pressure that exceeds any of the following: (1) The internal design pressure of

the pipe determined in accordance with §195.106. However, for steel pipe in pipe-lines being converted under §195.5, if one or more factors of the design for-mula (§195.106) are unknown, one of the following pressures is to be used as de-sign pressure:

(i) Eighty percent of the first test pressure that produces yield under sec-tion N5.0 of appendix N of ASME B31.8, reduced by the appropriate factors in §§195.106 (a) and (e); or

(ii) If the pipe is 12 3?4inch (324 mm) or less outside diameter and is not tested to yield under this paragraph, 200 p.s.i. (1379 kPa) gage.

(2) The design pressure of any other component of the pipeline.

(3) Eighty percent of the test pres-sure for any part of the pipeline which has been pressure tested under subpart

E of this part.

(4) Eighty percent of the factory test pressure or of the prototype test pres-sure for any individually installed component which is excepted from testing under §195.305.

(5) For pipelines under §§195.302(b)(1) and (b)(2)(i) that have not been pres-sure tested under subpart E of this part, 80 percent of the test pressure or highest operating pressure to which the pipeline was subjected for 4 or more continuous hours that can be dem-onstrated by recording charts or logs made at the time the test or operations were conducted.

(b) No operator may permit the pres-sure in a pipeline during surges or other variations from normal oper-ations to exceed 110 percent of the op-erating pressure limit established under paragraph (a) of this section. Each operator must provide adequate controls and protective equipment to control the pressure within this limit. [Amdt. 195–22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195–33, 50 FR 15899, Apr. 23, 1985; 50 FR 38660, Sept. 24, 1985; Amdt. 195– 51, 59 FR 29385, June 7, 1994; Amdt. 195–52, 59 FR 33397, June 28, 1994; Amdt. 195–63, 63 FR 37506, July 13, 1998; Amdt. 195–65, 63 FR 59480, Nov. 4, 1998]

§195.408Communications.

(a) Each operator must have a com-munication system to provide for the transmission of information needed for

49 CFR Ch. I (10–1–04 Edition) §195.410

the safe operation of its pipeline sys-tem.

(b) The communication system re-quired by paragraph (a) of this section must, as a minimum, include means for:

(1) Monitoring operational data as re-quired by §195.402(c)(9);

(2) Receiving notices from operator personnel, the public, and public au-thorities of abnormal or emergency conditions and sending this informa-tion to appropriate personnel or gov-ernment agencies for corrective action;

(3) Conducting two-way vocal com-munication between a control center and the scene of abnormal operations and emergencies; and

(4) Providing communication with fire, police, and other appropriate pub-lic officials during emergency condi-tions, including a natural disaster.

§195.410Line markers.

(a) Except as provided in paragraph

(b) of this section, each operator shall place and maintain line markers over each buried pipeline in accordance with the following:

(1) Markers must be located at each public road crossing, at each railroad crossing, and in sufficient number along the remainder of each buried line so that its location is accurately known.

(2) The marker must state at least the following on a background of sharply contrasting color:

(i) The word ‘‘Warning,’’ ‘‘Caution,’’ or ‘‘Danger’’ followed by the words ‘‘Petro-leum (or the name of the hazardous liq-uid transported) Pipeline’’, or ‘‘Carbon Dioxide Pipeline,’’ all of which, except for markers in heavily developed urban areas, must be in letters at least 1 inch (25 millimeters) high with an approxi-mate stroke of 1?4inch (6.4 millime-ters).

(ii) The name of the operator and a telephone number (including area code) where the operator can be reached at all times.

(b) Line markers are not required for buried pipelines located—

(1) Offshore or at crossings of or under waterways and other bodies of water; or

(2) In heavily developed urban areas such as downtown business centers where—

(i) The placement of markers is im-practical and would not serve the pur-pose for which markers are intended; and

(ii) The local government maintains current substructure records.

(c) Each operator shall provide line marking at locations where the line is above ground in areas that are acces-sible to the public.

[Amdt. 195–22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195–27, 48 FR 25208, June 6, 1983; Amdt. 195–54, 60 FR 14650, Mar. 20, 1995; Amdt. 195–63, 63 FR 37506, July 13, 1998] §195.412Inspection of rights-of-way

and crossings under navigable wa-

ters.

(a) Each operator shall, at intervals not exceeding 3 weeks, but at least 26 times each calendar year, inspect the surface conditions on or adjacent to each pipeline right-of-way. Methods of inspection include walking, driving, flying or other appropriate means of traversing the right-of-way.

(b) Except for offshore pipelines, each operator shall, at intervals not exceed-ing 5 years, inspect each crossing under a navigable waterway to determine the condition of the crossing.

[Amdt. 195–22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195–24, 47 FR 46852, Oct. 21, 1982; Amdt. 195–52, 59 FR 33397, June 28, 1994]

§195.413Underwater inspection and reburial of pipelines in the Gulf of

Mexico and its inlets.

(a) Except for gathering lines of 41?2 inches (114mm) nominal outside diame-ter or smaller, each operator shall pre-pare and follow a procedure to identify its pipelines in the Gulf of Mexico and its inlets in waters less than 15 feet (4.6 meters) deep as measured from mean low water that are at risk of being an exposed underwater pipeline or a haz-ard to navigation. The procedures must be in effect August 10, 2005.

(b) Each operator shall conduct ap-propriate periodic underwater inspec-tions of its pipelines in the Gulf of Mexico and its inlets in waters less

Research and Special Programs Administration, DOT §195.424

than 15 feet (4.6 meters) deep as meas-ured from mean low water based on the identified risk.

(c) If an operator discovers that its pipeline is an exposed underwater pipe-line or poses a hazard to navigation, the operator shall—

(1) Promptly, but not later than 24 hours after discovery, notify the Na-tional Response Center, telephone: 1– 800–424–8802, of the location and, if available, the geographic coordinates of that pipeline.

(2) Promptly, but not later than 7 days after discovery, mark the location of the pipeline in accordance with 33 CFR Part 64 at the ends of the pipeline segment and at intervals of not over 500 yards (457 meters) long, except that a pipeline segment less than 200 yards (183 meters) long need only be marked at the center; and

(3) Within 6 months after discovery, or not later than November 1 of the fol-lowing year if the 6 month period is later than November 1 of the year of discovery, bury the pipeline so that the top of the pipe is 36 inches (914 milli-meters) below the underwater natural bottom (as determined by recognized and generally accepted practices) for normal excavation or 18 inches (457 millimeters) for rock excavation.

(i) An operator may employ engi-neered alternatives to burial that meet or exceed the level of protection pro-vided by burial.

(ii) If an operator cannot obtain re-quired state or Federal permits in time to comply with this section, it must notify OPS; specify whether the re-quired permit is State or Federal; and, justify the delay.

[Amdt. 195–82, 69 FR 48407, Aug. 10, 2004]

§§195.414–195.418[Reserved]

§195.420Valve maintenance.

(a) Each operator shall maintain each valve that is necessary for the safe operation of its pipeline systems in good working order at all times.

(b) Each operator shall, at intervals not exceeding 71?2months, but at least twice each calendar year, inspect each mainline valve to determine that it is functioning properly.

(c) Each operator shall provide pro-tection for each valve from unauthor-ized operation and from vandalism. [Amdt. 195–22, 46 FR 38360, July 27, 1981; 47 FR 32721, July 29, 1982, as amended by Amdt. 195–24, 47 FR 46852, Oct. 21, 1982]

§195.422Pipeline repairs.

(a) Each operator shall, in repairing its pipeline systems, insure that the re-pairs are made in a safe manner and are made so as to prevent damage to persons or property.

(b) No operator may use any pipe, valve, or fitting, for replacement in re-pairing pipeline facilities, unless it is designed and constructed as required by this part.

§195.424Pipe movement.

(a) No operator may move any line pipe, unless the pressure in the line section involved is reduced to not more than 50 percent of the maximum oper-ating pressure.

(b) No operator may move any pipe-line containing highly volatile liquids where materials in the line section in-volved are joined by welding unless— (1) Movement when the pipeline does not contain highly volatile liquids is impractical;

(2) The procedures of the operator under §195.402 contain precautions to protect the public against the hazard in moving pipelines containing highly volatile liquids, including the use of warnings, where necessary, to evacuate the area close to the pipeline; and

(3) The pressure in that line section is reduced to the lower of the fol-lowing:

(i) Fifty percent or less of the max-imum operating pressure; or

(ii) The lowest practical level that will maintain the highly volatile liquid in a liquid state with continuous flow, but not less than 50 p.s.i. (345 kPa) gage above the vapor pressure of the com-modity.

(c) No operator may move any pipe-line containing highly volatile liquids where materials in the line section in-volved are not joined by welding un-less—

(1) The operator complies with para-graphs (b) (1) and (2) of this section; and

49 CFR Ch. I (10–1–04 Edition) §195.426

(2) That line section is isolated to prevent the flow of highly volatile liq-uid.

[Amdt. 195–22, 46 FR 38360, July 27, 1981; 46 FR 38922, July 30, 1981, as amended by Amdt. 195–63, 63 FR 37506, July 13, 1998]

§195.426Scraper and sphere facilities. No operator may use a launcher or receiver that is not equipped with a re-lief device capable of safely relieving pressure in the barrel before insertion or removal of scrapers or spheres. The operator must use a suitable device to indicate that pressure has been re-lieved in the barrel or must provide a means to prevent insertion or removal of scrapers or spheres if pressure has not been relieved in the barrel.

[Amdt. 195–22, 46 FR 38360, July 27, 1981; 47 FR 32721, July 29, 1982]

§195.428Overpressure safety devices and overfill protection systems.

(a) Except as provided in paragraph

(b) of this section, each operator shall, at intervals not exceeding 15 months, but at least once each calendar year, or in the case of pipelines used to carry highly volatile liquids, at intervals not to exceed 71?2months, but at least twice each calendar year, inspect and test each pressure limiting device, relief valve, pressure regulator, or other item of pressure control equipment to deter-mine that it is functioning properly, is in good mechanical condition, and is adequate from the standpoint of capac-ity and reliability of operation for the service in which it is used.

(b) In the case of relief valves on pressure breakout tanks containing highly volatile liquids, each operator shall test each valve at intervals not exceeding 5 years.

(c) Aboveground breakout tanks that are constructed or significantly altered according to API Standard 2510 after October 2, 2000, must have an overfill protection system installed according to section 5.1.2 of API Standard 2510. Other aboveground breakout tanks with 600 gallons (2271 liters) or more of storage capacity that are constructed or significantly altered after October 2, 2000, must have an overfill protection system installed according to API Rec-ommended Practice 2350. However, op-erators need not comply with any part of API Recommended Practice 2350 for

a particular breakout tank if the oper-

ator notes in the manual required by

§195.402 why compliance with that part

is not necessary for safety of the tank.

(d) After October 2, 2000, the require-

ments of paragraphs (a) and (b) of this section for inspection and testing of pressure control equipment apply to

the inspection and testing of overfill protection systems.

[Amdt. 195–22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195–24, 47 FR 46852, Oct.

21, 1982; Amdt. 195–66, 64 FR 15936, Apr. 2, 1999]

§195.430Firefighting equipment.

Each operator shall maintain ade-

quate firefighting equipment at each pump station and breakout tank area.

The equipment must be—

(a) In proper operating condition at

all times;

(b) Plainly marked so that its iden-

tity as firefighting equipment is clear;

and

(c) Located so that it is easily acces-

sible during a fire.

§195.432Inspection of in-service breakout tanks.

(a) Except for breakout tanks in-spected under paragraphs (b) and (c) of

this section, each operator shall, at in-

tervals not exceeding 15 months, but at

least once each calendar year, inspect

each in-service breakout tank.

(b) Each operator shall inspect the physical integrity of in-service atmos-

pheric and low-pressure steel above-

ground breakout tanks according to section 4 of API Standard 653. However,

if structural conditions prevent access

to the tank bottom, the bottom integ-

rity may be assessed according to a

plan included in the operations and maintenance manual under §195.402(c)(3).

(c) Each operator shall inspect the physical integrity of in-service steel aboveground breakout tanks built to

API Standard 2510 according to section

6 of API 510.

(d) The intervals of inspection speci-

fied by documents referenced in para-

graphs (b) and (c) of this section begin

on May 3, 1999, or on the operator’s last

Research and Special Programs Administration, DOT §195.442

recorded date of the inspection, which-ever is earlier.

[Amdt. 195–66, 64 FR 15936, Apr. 2, 1999]

§195.434Signs.

Each operator must maintain signs visible to the public around each pump-ing station and breakout tank area. Each sign must contain the name of the operator and a telephone number (including area code) where the oper-ator can be reached at all times.

[Amdt. 195–78, 68 FR 53528, Sept. 11, 2003]

§195.436Security of facilities.

Each operator shall provide protec-tion for each pumping station and breakout tank area and other exposed facility (such as scraper traps) from vandalism and unauthorized entry.

§195.438Smoking or open flames.

Each operator shall prohibit smoking and open flames in each pump station area and each breakout tank area where there is a possibility of the leak-age of a flammable hazardous liquid or of the presence of flammable vapors.

§195.440Public education.

Each operator shall establish a con-tinuing educational program to enable the public, appropriate government or-ganizations and persons engaged in ex-cavation-related activities to recognize a hazardous liquid or a carbon dioxide pipeline emergency and to report it to the operator or the fire, police, or other appropriate public officials. The program must be conducted in English and in other languages commonly un-derstood by a significant number and concentration of non-English speaking population in the operator’s operating areas.

[Amdt. 195–45, 56 FR 26927, June 12, 1991]

§195.442Damage prevention program.

(a) Except as provided in paragraph (d) of this section, each operator of a buried pipeline must carry out, in ac-cordance with this section, a written program to prevent damage to that pipeline from excavation activities. For the purpose of this section, the term ‘‘excavation activities’’ includes excavation, blasting, boring, tunneling, backfilling, the removal of above-ground structures by either explosive or mechanical means, and other earthmoving operations.

(b) An operator may comply with any of the requirements of paragraph (c) of this section through participation in a public service program, such as a one- call system, but such participation does not relieve the operator of the re-sponsibility for compliance with this section. However, an operator must perform the duties of paragraph (c)(3) of this section through participation in a one-call system, if that one-call sys-tem is a qualified one-call system. In areas that are covered by more than one qualified one-call system, an oper-ator need only join one of the qualified one-call systems if there is a central telephone number for excavators to call for excavation activities, or if the one-call systems in those areas com-municate with one another. An opera-tor’s pipeline system must be covered by a qualified one-call system where there is one in place. For the purpose of this section, a one-call system is considered a ‘‘qualified one-call system’’

if it meets the requirements of section

(b)(1) or (b)(2) or this section.

(1) The state has adopted a one-call damage prevention program under §198.37 of this chapter; or

(2) The one-call system:

(i) Is operated in accordance with §198.39 of this chapter;

(ii) Provides a pipeline operator an opportunity similar to a voluntary par-ticipant to have a part in management responsibilities; and

(iii) Assesses a participating pipeline operator a fee that is proportionate to the costs of the one-call system’s cov-erage of the operator’s pipeline.

(c) The damage prevention program required by paragraph (a) of this sec-tion must, at a minimum:

(1) Include the identity, on a current basis, of persons who normally engage in excavation activities in the area in which the pipeline is located.

(2) Provides for notification of the public in the vicinity of the pipeline and actual notification of persons iden-tified in paragraph (c)(1) of this section of the following as often as needed to make them aware of the damage pre-vention program:

49 CFR Ch. I (10–1–04 Edition) §195.444

(i) The program’s existence and pur-pose; and

(ii) How to learn the location of un-derground pipelines before excavation activities are begun.

(3) Provide a means of receiving and recording notification of planned exca-vation activities.

(4) If the operator has buried pipe-lines in the area of excavation activity, provide for actual notification of per-sons who give notice of their intent to excavate of the type of temporary marking to be provided and how to identify the markings.

(5) Provide for temporary marking of buried pipelines in the area of exca-vation activity before, as far as prac-tical, the activity begins.

(6) Provide as follows for inspection of pipelines that an operator has rea-son to believe could be damaged by ex-cavation activities:

(i) The inspection must be done as frequently as necessary during and after the activities to verify the integ-rity of the pipeline; and

(ii) In the case of blasting, any in-spection must include leakage surveys.

(d) A damage prevention program under this section is not required for the following pipelines:

(1) Pipelines located offshore.

(2) Pipelines to which access is phys-ically controlled by the operator. [Amdt. 195–54, 60 FR 14651, Mar. 20, 1995, as amended by Amdt. 195–60, 62 FR 61699, Nov. 19, 1997]

§195.444CPM leak detection.

Each computational pipeline moni-toring (CPM) leak detection system in-stalled on a hazardous liquid pipeline transporting liquid in single phase (without gas in the liquid) must com-ply with API 1130 in operating, main-taining, testing, record keeping, and dispatcher training of the system. [Amdt. 195–62, 63 FR 36376, July 6, 1998]

H IGH C ONSEQUENCE A REAS

§195.450Definitions.

The following definitions apply to this section and §195.452:

Emergency flow restricting device or EFRD means a check valve or remote control valve as follows:

(1) Check valve means a valve that permits fluid to flow freely in one di-rection and contains a mechanism to automatically prevent flow in the other direction.

(2) Remote control valve or RCV means any valve that is operated from a loca-tion remote from where the valve is in-stalled. The RCV is usually operated by the supervisory control and data acqui-sition (SCADA) system. The linkage between the pipeline control center and the RCV may be by fiber optics, micro-wave, telephone lines, or satellite.

High consequence area means:

(1) A commercially navigable waterway, which means a waterway where a sub-stantial likelihood of commercial navi-gation exists;

(2) A high population area, which means an urbanized area, as defined and delineated by the Census Bureau, that contains 50,000 or more people and has a population density of at least 1,000 people per square mile;

(3) An other populated area, which means a place, as defined and delin-eated by the Census Bureau, that con-tains a concentrated population, such as an incorporated or unincorporated city, town, village, or other designated residential or commercial area;

(4) An unusually sensitive area, as de-fined in §195.6.

[Amdt. 195–70, 65 FR 75405, Dec. 1, 2000]

P IPELINE I NTEGRITY M ANAGEMENT

§195.452Pipeline integrity manage-ment in high consequence areas. (a) Which pipelines are covered by this section? This section applies to each hazardous liquid pipeline and carbon dioxide pipeline that could affect a high consequence area, including any pipeline located in a high consequence area unless the operator effectively demonstrates by risk assessment that the pipeline could not affect the area. (Appendix C of this part provides guid-ance on determining if a pipeline could affect a high consequence area.) Cov-ered pipelines are categorized as fol-lows:

(1) Category 1 includes pipelines ex-isting on May 29, 2001, that were owned or operated by an operator who owned or operated a total of 500 or more miles of pipeline subject to this part.

Research and Special Programs Administration, DOT

§195.452

(2) Category 2 includes pipelines ex-isting on May 29, 2001, that were owned or operated by an operator who owned or operated less than 500 miles of pipe-line subject to this part.

(3) Category 3 includes pipelines con-structed or converted after May 29, 2001.

(b) What program and practices must operators use to manage pipeline integ-rity? Each operator of a pipeline cov-ered by this section must:

(1) Develop a written integrity man-agement program that addresses the risks on each segment of pipeline in the first column of the following table not later than the date in the second column:

Pipeline Date

Category 1.............................March 31, 2002.

Category 2.............................February 18, 2003. Category 3............................. 1 year after the date the

pipeline begins operation.

(2) Include in the program an identi-fication of each pipeline or pipeline segment in the first column of the fol-lowing table not later than the date in the second column: Pipeline Date

Category 1.............................December 31, 2001. Category 2.............................November 18, 2002.

Category 3.............................Date the pipeline begins op-eration.

(3) Include in the program a plan to carry out baseline assessments of line pipe as required by paragraph (c) of this section. (4) Include in the program a frame-work that— (i) Addresses each element of the in-tegrity management program under

paragraph (f) of this section, including

continual integrity assessment and evaluation under paragraph (j) of this section; and

(ii) Initially indicates how decisions

will be made to implement each ele-ment.

(5) Implement and follow the pro-gram.

(6) Follow recognized industry prac-tices in carrying out this section, un-less— (i) This section specifies otherwise; or

(ii) The operator demonstrates that an alternative practice is supported by a reliable engineering evaluation and provides an equivalent level of public safety and environmental protection. (c) What must be in the baseline assess-ment plan? (1) An operator must include each of the following elements in its written baseline assessment plan:

(i) The methods selected to assess the integrity of the line pipe. An operator must assess the integrity of the line pipe by any of the following methods. The methods an operator selects to as-sess low frequency electric resistance welded pipe or lap welded pipe suscep-tible to longitudinal seam failure must be capable of assessing seam integrity and of detecting corrosion and defor-mation anomalies. (A) Internal inspection tool or tools

capable of detecting corrosion and de-formation anomalies including dents,

gouges and grooves; (B) Pressure test conducted in ac-cordance with subpart E of this part; or (C) Other technology that the oper-ator demonstrates can provide an

equivalent understanding of the condi-tion of the line pipe. An operator choosing this option must notify the Office of Pipeline Safety (OPS) 90 days

before conducting the assessment, by sending a notice to the address or fac-simile number specified in paragraph (m) of this section. (ii) A schedule for completing the in-tegrity assessment; (iii) An explanation of the assess-ment methods selected and evaluation

of risk factors considered in estab-lishing the assessment schedule.

(2) An operator must document, prior to implementing any changes to the plan, any modification to the plan, and

reasons for the modification. (d) When must operators complete base-line assessments? Operators must com-plete baseline assessments as follows: (1) Time periods. Complete assess-ments before the following deadlines:

49 CFR Ch. I (10–1–04 Edition)

§195.452

If the pipeline is:

Then complete baseline assessments not later than the following date according to a schedule that prioritizes assessments: And assess at least 50 percent of the line pipe on an expedited basis, beginning with

the highest risk pipe, not later than: Category 1................................March 31, 2008................................................September 30, 2004. Category 2................................February 17, 2009...........................................August 16, 2005. Category 3................................

Date the pipeline begins operation ..................

Not applicable.

(2) Prior assessment. To satisfy the re-quirements of paragraph (c)(1)(i) of this section for pipelines in the first col-umn of the following table, operators may use integrity assessments con-ducted after the date in the second col-umn, if the integrity assessment meth-od complies with this section. However, if an operator uses this prior assess-ment as its baseline assessment, the operator must reassess the line pipe ac-cording to paragraph (j)(3) of this sec-tion. The table follows:

Pipeline Date Category 1.............................January 1, 1996.

Category 2.............................February 15, 1997. (3) Newly-identified areas. (i) When in-formation is available from the infor-mation analysis (see paragraph (g) of

this section), or from Census Bureau

maps, that the population density around a pipeline segment has changed so as to fall within the definition in §195.450 of a high population area or other populated area, the operator must incorporate the area into its

baseline assessment plan as a high con-sequence area within one year from the date the area is identified. An operator must complete the baseline assessment of any line pipe that could affect the newly-identified high consequence area within five years from the date the area is identified. (ii) An operator must incorporate a new unusually sensitive area into its

baseline assessment plan within one

year from the date the area is identi-fied. An operator must complete the baseline assessment of any line pipe that could affect the newly-identified high consequence area within five years from the date the area is identi-fied.

(e) What are the risk factors for estab-lishing an assessment schedule (for both

the baseline and continual integrity as-sessments)? (1) An operator must estab-lish an integrity assessment schedule that prioritizes pipeline segments for assessment (see paragraphs (d)(1) and (j)(3) of this section). An operator must base the assessment schedule on all risk factors that reflect the risk condi-tions on the pipeline segment. The fac-tors an operator must consider include, but are not limited to:

(i) Results of the previous integrity assessment, defect type and size that the assessment method can detect, and defect growth rate;

(ii) Pipe size, material, manufac-turing information, coating type and

condition, and seam type;

(iii) Leak history, repair history and cathodic protection history;

(iv) Product transported;

(v) Operating stress level;

(vi) Existing or projected activities

in the area;

(vii) Local environmental factors that could affect the pipeline (e.g., corrosivity of soil, subsidence, cli-matic);

(viii) geo-technical hazards; and

(ix) Physical support of the segment such as by a cable suspension bridge. (2) Appendix C of this part provides further guidance on risk factors. (f) What are the elements of an integrity management program? An integrity management program begins with the initial framework. An operator must continually change the program to re-flect operating experience, conclusions drawn from results of the integrity as-sessments, and other maintenance and

surveillance data, and evaluation of consequences of a failure on the high consequence area. An operator must in-clude, at minimum, each of the fol-lowing elements in its written integ-rity management program: (1) A process for identifying which pipeline segments could affect a high consequence area;

(2) A baseline assessment plan meet-ing the requirements of paragraph (c) of this section;

Research and Special Programs Administration, DOT §195.452

(3) An analysis that integrates all available information about the integ-rity of the entire pipeline and the con-sequences of a failure (see paragraph

(g) of this section);

(4) Criteria for remedial actions to address integrity issues raised by the assessment methods and information analysis (see paragraph (h) of this sec-tion);

(5) A continual process of assessment and evaluation to maintain a pipeline’s integrity (see paragraph (j) of this sec-tion);

(6) Identification of preventive and mitigative measures to protect the high consequence area (see paragraph

(i) of this section);

(7) Methods to measure the program’s effectiveness (see paragraph (k) of this section);

(8) A process for review of integrity assessment results and information analysis by a person qualified to evalu-ate the results and information (see paragraph (h)(2) of this section).

(g) What is an information analysis? In periodically evaluating the integrity of each pipeline segment (paragraph (j) of this section), an operator must analyze all available information about the in-tegrity of the entire pipeline and the consequences of a failure. This infor-mation includes:

(1) Information critical to deter-mining the potential for, and pre-venting, damage due to excavation, in-cluding current and planned damage prevention activities, and development or planned development along the pipe-line segment;

(2) Data gathered through the integ-rity assessment required under this section;

(3) Data gathered in conjunction with other inspections, tests, surveillance and patrols required by this Part, in-cluding, corrosion control monitoring and cathodic protection surveys; and (4) Information about how a failure would affect the high consequence area, such as location of the water in-take.

(h) What actions must an operator take to address integrity issues?

(1) General requirements. An operator must take prompt action to address all anomalous conditions that the oper-ator discovers through the integrity assessment or information analysis. In addressing all conditions, an operator must evaluate all anomalous condi-tions and remediate those that could reduce a pipeline’s integrity. An oper-ator must be able to demonstrate that the remediation of the condition will ensure that the condition is unlikely to pose a threat to the long-term integ-rity of the pipeline. A reduction in op-erating pressure cannot exceed 365 days without an operator taking further re-medial action to ensure the safety of the pipeline. An operator must comply with §195.422 when making a repair.

(2) Discovery of condition. Discovery of

a condition occurs when an operator has adequate information about the condition to determine that the condi-tion presents a potential threat to the integrity of the pipeline. An operator must promptly, but no later than 180 days after an integrity assessment, ob-tain sufficient information about a condition to make that determination, unless the operator can demonstrate that the 180-day period is impracti-cable.

(3) Schedule for evaluation and remedi-ation. An operator must complete re-mediation of a condition according to a schedule that prioritizes the conditions for evaluation and remediation. If an operator cannot meet the schedule for any condition, the operator must jus-tify the reasons why it cannot meet the schedule and that the changed schedule will not jeopardize public safety or environmental protection. An operator must notify OPS if the oper-ator cannot meet the schedule and can-not provide safety through a tem-porary reduction in operating pressure. An operator must send the notice to the address specified in paragraph (m) of this section.

(4) Special requirements for scheduling remediation.(i) Immediate repair condi-tions. An operator’s evaluation and re-mediation schedule must provide for immediate repair conditions. To main-tain safety, an operator must tempo-rarily reduce operating pressure or shut down the pipeline until the oper-ator completes the repair of these con-ditions. An operator must calculate the temporary reduction in operating pres-sure using the formula in section 451.7 of ASME/ANSI B31.4 (incorportaed by

49 CFR Ch. I (10–1–04 Edition) §195.452

reference, see §195.3). An operator must treat the following conditions as im-mediate repair conditions:

(A) Metal loss greater than 80% of nominal wall regardless of dimensions.

(B) A calculation of the remaining strength of the pipe shows a predicted burst pressure less than the established maximum operating pressure at the lo-cation of the anomaly. Suitable re-maining strength calculation methods include, but are not limited to, ASME/ ANSI B31G (‘‘Manual for Determining the Remaining Strength of Corroded Pipelines’’ (1991) or AGA Pipeline Re-search Committee Project PR–3–805 (‘‘A Modified Criterion for Evaluating the Remaining Strength of Corroded Pipe’’ (December 1989)). These documents are incorporated by reference and are available at the addresses listed in §195.3.

(C) A dent located on the top of the pipeline (above the 4 and 8 o’clock posi-tions) that has any indication of metal loss, cracking or a stress riser.

(D) A dent located on the top of the pipeline (above the 4 and 8 o’clock posi-tions) with a depth greater than 6% of the nominal pipe diameter.

(E) An anomaly that in the judgment of the person designated by the oper-ator to evaluate the assessment results requires immediate action.

(ii) 60-day conditions. Except for con-ditions listed in paragraph (h)(4)(i) of this section, an operator must schedule evaluation and remediation of the fol-lowing conditions within 60 days of dis-covery of condition.

(A) A dent located on the top of the pipeline (above the 4 and 8 o’clock posi-tions) with a depth greater than 3% of the pipeline diameter (greater than 0.250 inches in depth for a pipeline di-ameter less than Nominal Pipe Size (NPS) 12).

(B) A dent located on the bottom of the pipeline that has any indication of metal loss, cracking or a stress riser. (iii) 180-day conditions. Except for conditions listed in paragraph (h)(4)(i) or (ii) of this section, an operator must schedule evaluation and remediation of the following within 180 days of dis-covery of the condition:

(A) A dent with a depth greater than 2% of the pipeline’s diameter (0.250 inches in depth for a pipeline diameter less than NPS 12) that affects pipe cur-vature at a girth weld or a longitudinal seam weld.

(B) A dent located on the top of the pipeline (above 4 and 8 o’clock posi-tion) with a depth greater than 2% of the pipeline’s diameter (0.250 inches in depth for a pipeline diameter less than NPS 12).

(C) A dent located on the bottom of the pipeline with a depth greater than 6% of the pipeline’s diameter.

(D) A calculation of the remaining strength of the pipe shows an operating pressure that is less than the current established maximum operating pres-sure at the location of the anomaly. Suitable remaining strength calcula-tion methods include, but are not lim-ited to, ASME/ANSI B31G (‘‘Manual for Determining the Remaining Strength of Corroded Pipelines’’ (1991)) or AGA Pipeline Research Committee Project PR–3–805 (‘‘A Modified Criterion for Evaluating the Remaining Strength of Corroded Pipe’’ (December 1989)). These documents are incorporated by ref-erence and are available at the address-es listed in §195.3.

(E) An area of general corrosion with a predicted metal loss greater than 50% of nominal wall.

(F) Predicted metal loss greater than 50% of nominal wall that is located at a crossing of another pipeline, or is in an area with widespread circumferen-tial corrosion, or is in an area that could affect a girth weld.

(G) A potential crack indication that when excavated is determined to be a crack.

(H) Corrosion of or along a longitu-dinal seam weld.

(I) A gouge or groove greater than

12.5% of nominal wall.

(iv) Other conditions. In addition to the conditions listed in paragraphs (h)(4)(i) through (iii) of this section, an operator must evaluate any condition identified by an integrity assessment or information analysis that could im-pair the integrity of the pipeline, and as appropriate, schedule the condition for remediation. Appendix C of this part contains guidance concerning other conditions that an operator should evaluate.

(i) What preventive and mitigative measures must an operator take to protect

Research and Special Programs Administration, DOT §195.452

the high consequence area? (1) General re-quirements. An operator must take measures to prevent and mitigate the consequences of a pipeline failure that could affect a high consequence area. These measures include conducting a risk analysis of the pipeline segment to identify additional actions to enhance public safety or environmental protec-tion. Such actions may include, but are not limited to, implementing damage prevention best practices, better moni-toring of cathodic protection where corrosion is a concern, establishing shorter inspection intervals, installing EFRDs on the pipeline segment, modi-fying the systems that monitor pres-sure and detect leaks, providing addi-tional training to personnel on re-sponse procedures, conducting drills with local emergency responders and adopting other management controls. (2) Risk analysis criteria. In identi-fying the need for additional preven-tive and mitigative measures, an oper-ator must evaluate the likelihood of a pipeline release occurring and how a release could affect the high con-sequence area. This determination must consider all relevant risk factors, including, but not limited to:

(i) Terrain surrounding the pipeline segment, including drainage systems such as small streams and other small-

er waterways that could act as a con-duit to the high consequence area;

(ii) Elevation profile;

(iii) Characteristics of the product transported;

(iv) Amount of product that could be released;

(v) Possibility of a spillage in a farm field following the drain tile into a wa-terway;

(vi) Ditches along side a roadway the pipeline crosses;

(vii) Physical support of the pipeline segment such as by a cable suspension bridge;

(viii) Exposure of the pipeline to op-erating pressure exceeding established maximum operating pressure.

(3) Leak detection. An operator must have a means to detect leaks on its pipeline system. An operator must evaluate the capability of its leak de-tection means and modify, as nec-essary, to protect the high consequence area. An operator’s evaluation must, at least, consider, the following factors— length and size of the pipeline, type of product carried, the pipeline’s prox-imity to the high consequence area, the swiftness of leak detection, loca-tion of nearest response personnel, leak history, and risk assessment results. (4) Emergency Flow Restricting Devices (EFRD). If an operator determines that an EFRD is needed on a pipeline seg-ment to protect a high consequence area in the event of a hazardous liquid pipeline release, an operator must in-stall the EFRD. In making this deter-mination, an operator must, at least, consider the following factors—the swiftness of leak detection and pipeline shutdown capabilities, the type of com-modity carried, the rate of potential leakage, the volume that can be re-leased, topography or pipeline profile, the potential for ignition, proximity to power sources, location of nearest re-sponse personnel, specific terrain be-tween the pipeline segment and the high consequence area, and benefits ex-pected by reducing the spill size.

(j) What is a continual process of eval-uation and assessment to maintain a pipe-line’s integrity? (1) General. After com-pleting the baseline integrity assess-ment, an operator must continue to as-sess the line pipe at specified intervals and periodically evaluate the integrity of each pipeline segment that could af-fect a high consequence area.

(2) Evaluation. An operator must con-duct a periodic evaluation as fre-quently as needed to assure pipeline in-tegrity. An operator must base the fre-quency of evaluation on risk factors specific to its pipeline, including the factors specified in paragraph (e) of this section. The evaluation must con-sider the results of the baseline and periodic integrity assessments, infor-mation analysis (paragraph (g) of this section), and decisions about remedi-ation, and preventive and mitigative actions (paragraphs (h) and (i) of this section).

(3) Assessment intervals. An operator must establish intervals not to exceed five (5) years for continually assessing the line pipe’s integrity. An operator must base the assessment intervals on the risk the line pipe poses to the high

49 CFR Ch. I (10–1–04 Edition) §195.452

consequence area to determine the pri-ority for assessing the pipeline seg-ments. An operator must establish the assessment intervals based on the fac-tors specified in paragraph (e) of this section, the analysis of the results from the last integrity assessment, and the information analysis required by paragraph (g) of this section.

(4) Variance from the 5-year intervals in limited situations—(i) Engineering basis. An operator may be able to justify an engineering basis for a longer assess-ment interval on a segment of line pipe. The justification must be sup-ported by a reliable engineering eval-uation combined with the use of other technology, such as external moni-toring technology, that provides an un-derstanding of the condition of the line pipe equivalent to that which can be obtained from the assessment methods allowed in paragraph (j)(5) of this sec-tion. An operator must notify OPS 270 days before the end of the five-year (or less) interval of the justification for a longer interval, and propose an alter-native interval. An operator must send the notice to the address specified in paragraph (m) of this section.

(ii) Unavailable technology. An oper-ator may require a longer assessment period for a segment of line pipe (for example, because sophisticated inter-nal inspection technology is not avail-able). An operator must justify the rea-sons why it cannot comply with the re-quired assessment period and must also demonstrate the actions it is taking to evaluate the integrity of the pipeline segment in the interim. An operator must notify OPS 180 days before the end of the five-year (or less) interval that the operator may require a longer assessment interval, and provide an es-timate of when the assessment can be completed. An operator must send a notice to the address specified in para-graph (m) of this section.

(5) Assessment methods. An operator must assess the integrity of the line pipe by any of the following methods. The methods an operator selects to as-sess low frequency electric resistance welded pipe or lap welded pipe suscep-tible to longitudinal seam failure must be capable of assessing seam integrity and of detecting corrosion and defor-mation anomalies.

(i) Internal inspection tool or tools

capable of detecting corrosion and de-

formation anomalies including dents,

gouges and grooves;

(ii) Pressure test conducted in ac-

cordance with subpart E of this part; or

(iii) Other technology that the oper-

ator demonstrates can provide an equivalent understanding of the condi-

tion of the line pipe. An operator

choosing this option must notify OPS

90 days before conducting the assess-

ment, by sending a notice to the ad-

dress or facsimile number specified in

paragraph (m) of this section.

(k) What methods to measure program effectiveness must be used? An operator’s

program must include methods to

measure whether the program is effec-

tive in assessing and evaluating the in-

tegrity of each pipeline segment and in

protecting the high consequence areas.

See Appendix C of this part for guid-

ance on methods that can be used to

evaluate a program’s effectiveness.

(l) What records must be kept? (1) An

operator must maintain for review dur-

ing an inspection:

(i) A written integrity management

program in accordance with paragraph

(b) of this section.

(ii) Documents to support the deci-

sions and analyses, including any modifications, justifications, variances, deviations and determina-

tions made, and actions taken, to im-

plement and evaluate each element of

the integrity management program

listed in paragraph (f) of this section.

(2) See Appendix C of this part for ex-

amples of records an operator would be

required to keep.

(m) Where does an operator send a noti-

fication? An operator must send any no-

tification required by this section to

the Information Resources Manager,

Office of Pipeline Safety, Research and

Special Programs Administration, U.S. Department of Transportation, Room

7128, 400 Seventh Street SW., Wash-

ington, DC 20590, or to the facsimile

number (202) 366–7128.

[Amdt. 195–70, 65 FR 75406, Dec. 1, 2000, as

amended by Amdt. 195–74, 67 FR 1660, 1661,

Jan. 14, 2002; Amdt. 195–76, 67 FR 2143, Jan.

16, 2002; 67 FR 46911, July 17, 2002]

交通运输工程建设法律法规清单

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展，为促进国民经济发展和改善人民生活提供运输保障。 县级以上地方人民政府应当优先发展公共汽车客运，对公共汽车客运发展、道路运输站（场）枢纽建设、交通物流发展等给予政策和资金扶持。 县级以上地方人民政府应当将道路运输管理所需经费纳入本级财政预算，并对抢险、救灾、战备等应急运输所需支出予以保障。 第四条县级以上地方人民政府交通运输主管部门负责组织领导本行政区域的道路运输管理工作，道路运输管理机构负责具体实施道路运输管理工作。 县级以上地方人民政府其他有关部门按照各自职责，共同做好道路运输管理的相关工作。 第五条县级以上地方人民政府交通运输主管部门应当会同有关部门，依法编制本行政区域的道路运输发展规划，拟定产业政策，报同级人民政府批准后组织实施。 编制道路运输发展规划应当依据国民经济和社会发展规划，与城乡规划和土地利用总体规划相衔接，并符合综合交通运输体系发展规划。 道路运输站（场）、公交站场、出租汽车服务中心、驾驶人培训教练场地等交通设施布局和建设应当纳入城乡规划，并在编制控制性详细规划时予以规划控制。 第六条道路运输管理遵循公开、公正、高效、便民的原则，保护正当竞争，制止非法经营。 从事道路运输以及相关业务经营活动，应当依法经营、诚实信用、公平竞争。任何单位和个人不得封锁或者垄断道路运输市场。 第七条鼓励道路运输以及相关业务经营者实行规模化、集约化、公司化经营，鼓励使用符合国家标准的节能和新能源汽车从事道路运输以及相关业务经营活动，鼓励发展甩挂运输、多式联运等运输方式。 第八条道路运输相关行业协会应当按照自愿自律的原则，根据行业协会章程，规范和指导会员经营行为，维护会员合法权益，促进道路运输业健康发展。 第二章一般规定 第九条从事道路运输以及相关业务经营活动，应当具备法律、法规和本条例规定的条件，依法取得道路运输许可，按照核定的期限、范围、种类、项目、区域和场所等许可事项从事经营活动。 用于客运、货运、机动车驾驶人培训、汽车租赁、交通物流经营的车辆，应当按照国家规定向车籍所在地县级以上道路运输管理机构申请配发道路运输证件，并随车携带。

浅析区域交通运输系统对于城市旅游产业发展的用途

浅析区域交通运输系统对于城市旅游产业发展的作用-人力 资源 浅析区域交通运输系统对于城市旅游产业发展的作用 李华赵泽梅云南大学旅游文化学院 摘要：过去20年，在经历了形成、快速成长和稳步发展三个阶段后，我国旅游产业已发展成为我国国民经济新的增长点和发展速度最快的产业之一。深入研究交通运输系统的发展对城市旅游产业发展的作用，不仅有助于城市围绕旅游产业合理配置相关资源，以提升旅游品质，还有利于是推动我国旅游业的持续优化，提升我国整体旅游水平。 关键词：区域交通系统旅游产业丽江 一、理论综述 1.国内外理论研究 区域交通运输系统是城市旅游经济发展的重要条件，国外学者针对交通对旅游作用及影响的研究，主要集中在交通对旅游需求、旅游目的地发展、旅游可持续发展、区域内旅游交通运输体系发展、旅游者影响的研究。国内关于交通对旅游影响的研究起步较晚，研究内容主要集中在交通与旅游的关系、交通对旅游业的影响、特定交通运输方式和具体交通设施对区域旅游的影响等。 2.城市旅游产业的基本特点 （1）城市旅游产业在国民经济中的地位不断提升。城市旅游产业在国民经济中的地位不断提升，成为了第三产业中的重点产业和支柱产业之一。 一方面，随着城市的经济发展水平不断提高，城市环境日益改善，现代旅游资源不断开发和丰富；另一方面由于旅游产业强大的综合性和产业关联性，

使得旅游产业的发展带动了城市交通、餐饮、住宿、商贸、金融、文化、信息等相关服务业和一、二产业的发展，也极大地带动了城市就业，因此发展旅游业成为了城市大力发展第三产业、优化产业结构的重要核心内容。 （2）城市旅游产业综合性较强。旅游产业的发展是以第一、第二产业的发展为基础的，是个综合性很强的产业。旅游产业关联性较强还体现在旅游产业内部，即旅游产业链的一荣俱荣、一损俱损。 （3）城市的旅游资源与交通运输条件构成了旅游产业的空间竞争力。城市旅游资源是旅游产业的根本价值，但是城市旅游产业的发展不仅取决于旅游资源的质与量，也取决于配套产业的发展情况。具体来看，旅游产业的发展不仅要凭借旅游资源，更重要的是要依托交通系统的发展，即城市是否拥有便捷的交通、发达的区际交通网络、较大的旅客区域内运输能力等。 二、完善的交通运输系统对城市旅游产业发展的作用 1.提高游客满意度，提升游客体验价值 在现代旅游产业中，交通运输系统的功能已发生本质的变化，其功能除为游客提供空间位移外，还包括满足旅游者体验、观光和娱乐需求等多重功能。交通运输系统已不仅仅是一种“出行工具”，更是一种无形的旅游产品，旅游地交通运输系统的有效性与感知质量，不仅决定旅游者的出游动机，同时会对旅游者的整体满意度、体验质量和重游意愿产生直接影响。 2.增加游客游玩的景点的数量与停留的时间 交通作为旅游活动中时间和金钱消耗的主要项目之一，其通达性、便捷性与舒适性等因素是旅游者目的地选择和日程安排的重要依据。在大多数情况下，游客在到达一个旅游城市后，在规划其出行计划，决定游玩景点的过程中，

道路运输管理工作规范

道路运输管理工作规范 第一节道路货物运输经营许可 一、道路货物运输经营许可事项及实施主体 县级道路运输管理机构负责实施本辖区内道路普通货运、道路货物专用运输、道路大型物件运输的行政许可。未设县级道路运输管理机构的，由上一级的道路运输管理机构负责实施本辖区内道路普通货运、道路货物专用运输、道路大型物件运输的行政许可。 二、道路货物运输经营许可条件 道路运输管理机构受理道路普通货运、道路货物专用运输、道路大型物件运输经营许可申请，应当审查申请人是否具备以下条件： （一）有与其经营业务相适应并经检测合格的运输车辆 1．车辆技术性能应当符合国家标准《营运车辆综合性能要求和检验方法》（GB 18565）的要求； 2．车辆外廓尺寸、轴荷和载质量应当符合国家标准《道路车辆外廓尺寸、轴荷及质量限值》（GB 1589）的要求； 3．从事大型物件运输经营的，应当具有与所运输大型物件相适应的超重型车组。超重型车组是指运输长度在14 米以上或宽度在3 . 5 米以上或高度在3 米以上的货物的车辆，或者运输重量在20 吨以上的单体货物或不可解体的成组（捆）货物的车辆； 4．从事冷藏保鲜、罐式容器等专用运输的，应当具有与运输货物相适应的专用车辆，专用容器、设备、设施应当固定在专用车辆上；

5．从事集装箱运输的，应当具有与运输集装箱相适应的车辆，车辆还应当有固定集装箱的转锁装置。 （二）有符合规定条件的驾驶人员 1．取得相应的机动车驾驶证； 2 ，年龄不超过60 周岁； 3．取得相应的从业资格证。 （三）有健全的安全生产管理制度 安全生产管理制度包括以下几个方面： 1．安全生产操作规程； 2．安全生产和岗位责任制； 3．安全生产监督检查制度； 4．从业人员安全管理制度； 5．安全例会制度； 6．安全培训和教育学习制度； 7．车辆、设施、设备安全管理制度； 8．事故处理应急预案等。 三、道路货物运输经营许可程序 （一）要求提交的申请材料 申请从事道路货物运输经营的，道路运输管理机构应当要求申请人提供以下材料：1．《道路货物运输经营申请表》； ．负责人身份证明，经办人的身份证明和委托书；2． 3．已购置车辆的，应提供机动车辆行驶证、机动车综合性能检测报告单和车辆

交通运输系统常识

1、系统：由若干相互区别、相互联系而又相互作用得要素组成，在一定得阶层结构形成中分布，在给定得环境约束下，为达到整体得目得而存在得有机集合体。 2、系统得共性：有序性、集合性、相关性与整体性。 3、系统得特性：目得性、环境适应性与环境改造性。 4、组成系统得三要素：物质、能量、信息 5、系统分析：就是从系统长远与整体最优出发，在选定系统目标与准则得基础上，分析构成系统得各个层次子系统得功能与相互关系，利用定量得方法提供可用得数据，借以制定可行方案，推断可能产生得效果，寻求子系统整体效益最大化得策略，以及系统与环境得相互影响。 6、系统分析得六要素：（1）目得（2）调查、收集资料（3）替代方案（4）费用与效益（5）模型与模拟（6）评价基础 7、系统分析得准则：（1）外部条件与内部条件相结合（2）当前利益与长远利益相结合（3）局部效益与整体效益相结合（4）定量分析与定性分析相结合8、系统分析得理论技术基础：运筹学、概率论与数理统计、控制论、信息论9、系统分析得方法论得特点：（1）研究方法上得整体化（2）技术应用上得综合化（3）管理得科学化 10、系统工程方法论：霍尔（Hall）三维结构方法论（知识维、时间维、逻辑维）、切克兰德软系统方法论 时间维：规划—拟定方案—研制—生产—安装—运行—更新 逻辑维：明确问题—系统指标设计—系统方案综合—系统分析（模型化）--系统选择（最优化）--决策—实施 霍尔（Hall）三维结构方法论与切克兰德软系统方法论得相同点：问题导向、注重程序及阶段。不同点：研究对象或应用领域、基本方法、核心内容或关键点。

11、交通运输系统得五个特征：（1）具有明确得目得性（2）就是一个整体，相互协调，适应运输任务得需要（3）层次性十分突出（4）诸子系统得“元、部件”彼此间相关（5）发展与建设必须与外部环境相适应。 12、交通运输系统得多功能、多目标表现为：它具有运输功能、生产功能、工业功能、经济循环功能、客运服务功能、国防功能、城市功能以及区域功能。 13、根据交通运输系统信息交换得方式与关联处理得方式可分为：（1）递接控制系统：对各子系统得控制作用就是按照一定优先与从属关系安排得决策单元来实现得。如铁路运输系统（2）分布式控制系统：由各子系统得控制单元就是按子系统得控制目标事先按一定方式分配给子系统得控制单元，她们之间可以有有限得信息交换。如海运港口系统得管理。（3）分散控制系统：每个子系统只能得到整个系统得一部分信息同时也只能对系统变量得某一子集进行操作与处理，各自都有独立得控制目标。如公路、内河得控制管理。 14、交通运输系统得独特特点：（1）交通运输系统就是一个连续性过程系统，它得连续性表现为运输生产过程得连续性与运输时间得连续性（2）交通运输系统生产得多环节、多功能、超区域得特点（3）交通运输系统生产具有网络性特点。 交通运输网就是由骨架（干线）线网、地方线路与厂矿支线、专用线网组成(4)交通运输系统就是一个动态系统。表现在①交通运输系统就是国民经济大系统得组成部分，国民经济大系统随着时间得变化而变化，从而使运输任务也随着时间得变化而变化。②交通运输系统本身得动态性，即交通运输系统中得人流、物流、车流、船流以及飞机流等本身就就是经常处在一个流动得状态。 15、交通运输系统得独特功能：生产功能、旅客运输功能、国民经济系统得循环功能、国防功能。 16、交通运输系统得结构包括交通运输系统运输方式结构、交通运输系统设备结构、交通运输系统运输网结构。 17、交通运输网：就是在一定空间范围（国家或地区）内由几种运输方式得线路与枢纽等固定技术装备组成得综合体。

道路货物运输管理规范.

菏泽市道路货物运输管理工作规范第一节道路货物运输经营许可 一、道路货物运输经营许可的受理及实施主体 县级或县级以上道路运输管理机构负责实施本辖区内道路普通货运、道路货物专用运输和道路大型物件运输的行政许可。 未设县级道路运输管理机构的,由上一级的道路运输管理机构负责实施本辖区内道路普通货运、道路货物专用运输、道路大型物件运输的行政许可。 二、道路货物运输经营许可条件 道路运输管理机构受理道路普通货运、道路货物专用运输、道路大型物件运输经营许可申请,应当审查申请人是否具备以下条件: (一有与其经营业务相适应并经检测合格的运输车辆 1.车辆技术性能应当符合国家标准《营运车辆综合性能要求和检验方法》 (GB18565的要求; 2. 车辆外廓尺寸、轴荷和载质量应当符合国家标准《道路车辆外廓尺寸、轴荷及质量限值》 (GB1589的要求; 3.从事大型物件运输经营的,应当具有与所运输大型物件相适应的超重型车组。超重型车组是指运输长度在 14 米以上或宽度在 3. 5米以上或高度在 3米以上的货物的车辆,或者运输重量在20吨以上的单体货物或不可解体的成组 (捆货物的车辆; 4.从事冷藏保鲜、罐式容器等专用运输的,应当具有与运输货物相适应的专用车辆,专用容器、设备、设施应当固定在专用车辆上; 5.从事集装箱运输的,应当具有与运输集装箱相适应的车辆,车辆还应当有固定集装箱的转锁装臵。 (二有符合规定条件的驾驶人员 1.取得与驾驶车辆相应的机动车驾驶证;

2.年龄不超过 60周岁; 3.取得与驾驶车辆相应的从业资格证。 (三有健全的安全生产管理制度 安全生产管理制度包括以下几个方面: 1.安全生产操作规程; 2.安全生产和岗位责任制; 3.安全生产监督检查制度; 4.从业人员安全管理制度; 5.安全例会制度; 6.安全培训和教育学习制度; 7.车辆、设施、设备安全管理制度; 8.事故处理应急预案等。 三、道路货物运输经营许可程序 (一要求提交的申请材料 申请从事道路货物运输经营的,道路运输管理机构应当要求申请人提供以下材料: 1. 《道路货物运输经营申请表》 ; 2. 拟设立企业提供《企业名称预先核准通知书》或工商行政管理机关办理的营业执照,个体经营者提供《居民身份证》 ;

新交通运输常用法规汇编

交通运输行政执法常用法规汇编 一、公路行政执法 1. 中华人民共和国公路法（1997 年7 月 3 日第八届全国人 民代表大会常务委员会第二十六次会议通过，2004 年8 月28 日第十届全国人民代表大会常务委员会第十一次会议第二次修正） 2. 公路安全保护条例（2011 年 2 月16 日中华人民共和国国 务院令第593 号公布） 3. 中华人民共和国收费公路管理条例（2004 年9 月13 日中 华人民共和国国务院令第417 号公布） 4. 路政管理规定（2003 年 1 月27 日交通部令第２号公布） 5. 超限运输车辆行驶公路管理规定（2000 年 2 月13 日交通 部令第 2 号公布） 6. 公路监督检查专用车辆管理办法（2002 年11 月16 日交 通部令第 6 号公布） 7. 关于在全国开展车辆超限超载治理工作的实施方案 （2004 年 4 月30 日交通部、公安部、发展改革委、质检总局、安全监管局、工商总局、法制办公布） 二、道路运政行政执法

1. 中华人民共和国道路运输条例（2004 年 4 月30 日中华人 民共和国国务院令第406 号） 2. 危险化学品安全管理条例（2002 年 3 月 2 日中华人民共 和国国务院令第591 号公布） 3. 外商投资道路运输业管理规定（2001 年12 月20 日对外 贸易经济合作部令交通部令第9 号公布） 4. 国际道路运输管理规定（2005 年 4 月13 日交通部令第 3 号公布） 5. 道路旅客运输及客运站管理规定（2005 年7 月12 日交通 部令第10 号公布，2009 年 4 月20 日交通运输部令第 4 号第二次修正） 6. 道路货物运输及站场管理规定（2005 年 6 月16 日交通部 令第 6 号公布，2009 年 4 月21 日交通运输部令第 3 号第二次修正） 7. 道路危险货物运输管理规定（2005 年7 月12 日交通部令 第9 号公布，2010 年10 月27 日交通运输部令第 5 号修订） 放射性物品道路运输管理规定（2010 年10 月27 日交通运输部令第 6 号公布） 8. 道路运输车辆维护管理规定（1998 年 3 月 4 日交通部令 第 2 号公布，2001 年8月20 日交通部令第4号修正） 9. 机动车维修管理规定（2005 年 6 月24 日交通部令第7

交通运输系统分析第1次作业

（注意：若有主观题目，请按照题目，离线完成，完成后纸质上交学习中心，记录成绩。在线只需提交客 观题答案。) 本次作业是本门课程本学期的第1次作业，注释如下： 一、单项选择题(只有一个选项正确，共28道小题) 1. （）的应用为系统思想提供了丰富的实践内容。 (A) 运筹学 (B) 辩证唯物主义 (C) 哲学 (D) 系统工程 正确答案：D 解答参考： 2. 按系统形态分类，人造系统可以分为（） (A) 自然系统和人工系统 (B) 实体系统和概念系统 (C) 静态系统和动态系统 (D) 反馈系统和封闭系统 正确答案：B 解答参考： 3. 切克兰德软系统方法论的核心是（） (A) 实现最优化 (B) 求得满意解 (C) 调查比较或学习 (D) 建立概念模型 你选择的答案：未选择 [错误] 正确答案：D 解答参考： 4. 从事系统分析时，除了用工程和数学方法进行科学预测和分析外，考虑到资料的不确定性和客观环境的发展变化，还常常要凭借（）进行判断和优选．

(A) 系统模型 (B) 运筹学 (C) 哲学理念 (D) 价值观念 正确答案：D 解答参考： 5. （）是进行系统分析的基础． (A) 建立模型 (B) 建立方案 (C) 明确目的 (D) 收集资料 你选择的答案：未选择 [错误] 正确答案：D 解答参考： 6. 交通运输枢纽是多种交通运输方式或多种交通运输设备构成的（）。（P121） (A) 地方 (B) 点 (C) 结合部 (D) 交叉点 你选择的答案：未选择 [错误] 正确答案：C 解答参考： 7. 为了综合考虑多个目标的统一评价或者将若干个小目标统一为一个较大的目标，这种工作称为（）． (A) 多目标评价 (B) 多目标分析 (C) 目标体系建构 (D) 目标体系评价 你选择的答案：未选择 [错误] 正确答案：B 解答参考：

交通运输法规

一、名词解释： 1、行政主体：是指代表国家实施行政管理权，能以自己的名义行使国家行政职权，并能独立承担因此产生的相应法律责任的组织。 2、交通运输行政管理行为：是指行政主体为实现交通运输行政管理的目的，在行使行政职权和履行行政职责过程中所实施的一切具有法律意义、产生法律效果的行为。 3、交通行政处罚：是指交通运输行政管理机关对违反交通运输行政管理法律规范的公民、法人和其他组织所给予的行政法律制裁。 4、交通行政复议：是指公民、法人和其他组织认为交通运输行政管理机关作出的行政行为为侵犯了其合法权益，在法定期限内向上一级机关或者法律规定的其他机关提出行政复议申请，上级行政机关或者法律、法规规定的其他机关受理后依法进行审理并作出行政复议决定的一种法律制度。 5、行政赔偿：是指行政主体违法行使职权，造成公民、法人或者其他组织合法权益的损害，由国家承担的赔偿责任。 6、交通运输管理法规：是指由国家权力机关或行政机关依法制定并颁布，体现国家的交通运输意志，维护交通秩序调整交通运输行政管理机关在对道路客货运输、汽车维修、搬运装卸、运输辅助服务等进行管理的过程中与行政相对人形成的社会关系，并通过国家强制力保证实施的法律规范总称。 7、多式联运合同：指由多式联运经营人以两种以上不同的运输方式将货物或旅客从起运地点运输到约定地点，托运人支付运输费用的合同。 二、简答： 1、交通运输法规调整的对象 答：1）在交通运输行政管理权力行使运用过程中，交通行政管理机关与相对一方的公民、法人或其他组织之间发生社会关系。2）交通运输行政管理权力实施监督过程只发生的社会关系。 2、交通运输法规的作用： 答：1）维护交通运输秩序2）监督行政权力主体、防止违法滥用行政职权3）保护公民、法人和其他组织的合法权利。 3、交通运输法规的基本原则： 答：1）合法原则2）合理原则3）程序公正原则4）权力制约原则 4、行政行为与其他行为相比具有的特征： 答：1）行政行为是交通运输行政管理主体所实施的行为2）行政行为是交通运输行政管理主体行使职权或履行职责的行为3）行政行为是能够产生法律效果的行为4）行政行为具有多种行为方式。 5、交通行政处罚一般程序：

道路运输法律法规政策汇编

道路运输法律法规政策汇编 一、【法规综合】 1.交通运输部关于认真做好2013年道路水路春运工作的通知 2.关于进一步加强和规范治理车辆非法超限运输工作的通知 3.关于进一步加强烟花爆竹安全监督管理工作的意见 4.公路水路交通运输“十二五”教育与培训发展规划 5.公路水路交通运输信息化“十二五”发展规划 6.公路水路交通运输节能减排“十二五”规划 7.国务院关于加强道路交通安全工

作的意见 8.国务院办公厅关于加强车辆超限超载治理工作的通知 9.交通运输突发事件应急管理规定 10.关于加强道路运输管理队伍建设的指导意见 11.交通运输行政执法评议考核规定 12.关于废止24件交通运输规章的决定 13.交通运输行政执法证件管理规定 14.关于认真做好2010年道路水路春运工作的通知 15.公路交通突发事件应急预案 16.关于进一步促进公路水路交通运输业平稳较快发展的指导意见

17.关于认真做好2009年春节运输工作的通知 18.国务院关于实施成品油价格和税费改革的通知 19.国务院安委会办公室关于进一步加强道路旅客运输企业安全生产管理工作的通知 20.公路、水路交通实施《中华人民共和国节约能源法》办法 21.关于做好北京奥运会火炬接力境内传递公路转场交通保障工作的紧急通知 22.关于加强涉及军车号牌及相关证件违法犯罪活动查处工作的意见23.关于废止47件交通规章的决定

24.印发关于在全国开展车辆外挂治理工作的实施方案的通知 25.关于进一步规范公路养路费征收管理工作的通知 26.关于做好2007年度防抗台风工作的通知 27.关于进一步加强交通行业节能减排工作的意见 28.关于开展向新时期知识型产业工人孔祥瑞同志学习活动的决定 29.关于深入开展“迎奥运、讲文明、树新风”活动的实施方案 30.关于开展交通行政许可监督检查的通知 31.2007年全国交通行业节能工作要

【行政许可项目名称】道路运输车辆营运证核发

【行政许可项目名称】道路运输车辆营运证核发 【法定实施主体】密云县交通局 【行政许可项目依据】《中华人民共和国道路运输条例》、《道路旅客运输及客运站管理规定》、《危险化学品安全管理条例》、《道路危险货物运输管理规定》、《道路货物运输及站场管理规定》 【行政许可收费依据】本项许可不收费 【行政许可审查总时限】8工作日 【一】道路货物运输车辆营运证件核发（企业设立增车） 【申办材料】 （1）《道路货物运输经营行政许可决定书》及复印件； （2）《车辆技术档案》（大件、专用车辆需附专用设施、设备或容器照片）；（3）《汽车综合性能检测报告单》；（出厂时间不满一年的新车不提供此项）（4）车辆为在用车时，提供在用车运管费缴费凭证证明； （5）《北京市道路货物（含危险品）运输业户车辆变更登记表》； （6）车辆行驶证及复印件； （7）工商营业执照复印件； （8）完成承诺聘用的驾驶员合同、从业资格证书及复印件。 一、申请 【申请条件】 （1）道路货物运输经营者取得合法、有效经营许可证； （2）车辆基本条件： ①车辆技术性能应当符合国家标准《营运车辆综合性能要求和检验方法》（GB18565）的要求；

②车辆外廓尺寸、轴荷和载质量应当符合国家标准《道路车辆外廓尺寸、轴荷及质量限值》（GB1589）的要求。 （3）大型物件运输车辆条件： 申请从事大型物件运输的，应当具有与所运输大型物件相适应的超重型车组。 ①一类大型物件运输：车辆装备具有装载整体大型物件实际能力在20吨以上100吨以下的超重型车组，包括牵引车和挂车，并有相应的配套附件。 ②二类大型物件运输：车辆装备具有装载整体大型物件实际能力在100吨及以上200吨以下的超重型车组，包括牵引车和挂车，并有相应的配套附件。 ③三类大型物件运输：车辆装备具有装载整体大型物件实际能力在 200吨及以上300吨以下的超重型车组，包括牵引车和挂车，并有相应的配套附件。 ④四类大型物件运输：车辆装备具有装载整体大型物件实际能力在300吨及以上的超重型车组，包括牵引车和挂车，并有相应的配套附件。 （4）专用运输车辆条件： ①申请从事集装箱运输的，应是符合国家标准的集装箱专用运输车，有固定集装箱的转锁装置。 ②申请从事冷藏保鲜运输的，应是符合国家标准的冷藏保温专用运输车，有专用的冷藏设施、设备，并固定在专用车辆上。 ③申请从事罐式运输的，应是符合国家标准的罐罐式专用运输车，有专用的容器、设施、设备，并固定在专用车辆上。 （5）持有有效的机动车行驶证件； （6）企业安全服务、考核合格； （7）属企业设立时已有车辆或完成承诺车辆的，驾驶人员与运输车辆比例至少达到1：1。

交通运输系统分析各种解释

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