126.01.09 Ark. Code R. 001
Current through Register Vol. 49, No. 10, October, 2024
This subpart prescribes minimum requirements for the protection of metallic pipelines from external, internal, and atmospheric corrosion.
The corrosion control procedures required by § 192.605(b)(2), including those for design, installation, operation and maintenance of cathodic protection systems, must be carried out by, or under the direction of, a person qualified by experience and training in pipeline corrosion control methods.
Whenever an operator has knowledge that any portion of a buried pipeline is exposed, the exposed portion, if bare or the coating is deteriorated, must be examined for evidence of external corrosion. If external corrosion requiring remedial action under §§ 192.483 through 192.489 is found, the operator shall investigate circumferentially and longitudinally beyond the exposed portion (by visual examination, indirect method, or both) to determine whether additional corrosion requiring remedial action exists in the vicinity of the exposed portion.
Each pipeline under cathodic protection required by this subpart must have sufficient test stations or other contact points for electrical measurement to determine the adequacy of cathodic protection.
!f corrosive gas is being transported, coupons or other suitable means must be used to determine the effectiveness of the steps taken to minimize internal corrosion. Each coupon or other means of monitoring internal corrosion must be checked two times each calendar year, but with intervals not exceeding 71/2 months.
If the pipeline is located...... | Then the frequency of inspections is: |
Onshore | At least once every 3 calendar years, but with intervals not exceeding 39 months. |
Offshore | At least once each calendar year, but with intervals not exceeding 15 months. |
Each operator that uses direct assessment as defined in § 192.903 on an onshore transmission line made primarily of steel or iron to evaluate the effects of a threat in the first column must carry out the direct assessment according to the standard listed in the second column. These standards do not apply to methods associated with direct assessment, such as close interval surveys, voltage gradient surveys, or examination of exposed pipelines, when used separately from the direct assessment process.
Threat | Standard1 |
External corrosion | § 192.9252 |
Internal corrosion in pipelines that transport dry gas | § 192.927 |
Stress corrosion cracking | § 192.929 |
This subpart prescribes minimum leak-test and strength-test requirements for pipelines.
Class location | Maximum hoop stress allowed as percentage of SMYS | |
Natural Gas | Air or inert gas | |
1...................... | 80 | 80 |
2...................... | 30 | 75 |
3...................... | 30 | 50 |
4...................... | 30 | 40 |
Except for service lines and plastic pipelines, each segment of a pipeline that is to be operated at a hoop stress less than 30 percent of SMYS and at or above 100 p.s.i. (689 kPa) gage must be tested in accordance with the following:
Except for service lines and plastic pipelines, each segment of a pipeline that is to be operated below 100 p.s.i.g.. must be leak tested in accordance with the following:
This subpart prescribes minimum requirements for increasing maximum allowable operating pressures (uprating) for pipelines.
Pipe Size Inches (millimeters) | ALLOWANCE Inches (millimeters) Cast Iron Pipe | ||
Cast Iron Pipe | Ductile iron pipe | ||
Pit Cast Pipe | Centrifugally Cast Pipe | ||
3-8 (76-203) | 0.075(1.91) | 0.065(1.65) | 0.065(1.65) |
10-12 (254 to 305) | 0.08(2.03) | 0.07(1.78) | 0.07(1.78) |
14-24 (356 to 610) | 0.08(2.03) | 0.08(2.03) | 0.075(1.91) |
30-42 (762 to 1067) | 0.09(2.29) | 0.09(2.29) | 0.075(1.91) |
48 (1219) | 0.09(2.29) | 0.09(2.29) | 0.08(2.03) |
54-60 (1372 to 1524) | 0.09(2.29) | ____ | ____ |
This subpart prescribes minimum requirements for the operation of pipeline facilities.
Whenever an increase in population density indicates a change in class location for a segment of an existing steel pipeline operating at hoop stress that is more than 40 percent of SMYS, or indicates that the hoop stress corresponding to the established maximum allowable operating pressure for a segment of existing pipeline is not commensurate with the present class location, the operator shall immediately make a study to determine:
Each operator shall establish procedures for analyzing accidents and failures, including the selection of samples of the failed facility or equipment for laboratory examination, where appropriate, for the purpose of determining the causes of the failure and minimizing the possibility of a recurrence.
Class location | Factors Segment- | ||
Installed before (Nov.12, 1970) | Installed after (Nov. 11, 1970) | Converted under §192.14 | |
1....................... | 1.1 | 1.1 | 1.25 |
2....................... | 1.25 | 1.25 | 1.25 |
3....................... | 1.4 | 1.5 | 1.5 |
4....................... | 1.4 | 1.5 | 1.5 |
Pipeline segment | Pressure date | Test date |
-Onshore gathering line that first became subject to this part (other than § 192.612) after April 13, 2006. -Onshore transmission line that was a gathering line not subject to this part before March 15, 2006. | March 15, 2006, or date line becomes subject to this part, whichever is later. | 5 years preceding applicable date in second column. |
Offshore gathering lines .......... | July 1, 1976 | July 1, 1971 |
All other pipelines............... | July 1, 1970 | July 1, 1965 |
Each tap made on a pipeline under pressure must be performed by a crew qualified to make hot taps.
This subpart prescribes minimum requirements for maintenance of pipeline facilities.
Maximum interval between patrols | ||
Class location of line | At highway and railroad crossings | At all other places |
1, 2...................... | 7 1/2 months, but at least twice each calendar year. | 15 months, but at least once each calendar year. |
3......................... | 4 1/2 months, but at least four times each calendar year. | 7 1/2 months, but at least twice each calendar year. |
4......................... | 4 1/2 months, but at least four times each calendar year. | 4 1/2 months, but at least four times each calendar year. |
Leakage surveys of a transmission line must be conducted at intervals not exceeding 15 months, but at least once each calendar year. However, in the case of a transmission line which transports gas in conformity with § 192.625 without an odor or odorant, leakage surveys using leak detector equipment must be conducted:
Each operator shall maintain the following records for transmission lines for the periods specified:
Each weld that is unacceptable under § 192.241(c) must be repaired as follows:
Each permanent field repair of a leak on a transmission line must be made by-
NOTE: Test duration must be of sufficient length to detect leakage, and the following should be considered:
Volume under test and the time for the test medium to become temperature stabilized.
If the MAOP produces a hoop stress that is: | Then the pressure limit is: |
Greater than 72 percent of SMYS | MAOP plus 4 percent |
Unknown as a precentage of SMYS | A pressure that will prevent unsafe operation of the pipeline considering its operating and maintenance history and MAOP |
Each operator shall take steps to minimize the danger of accidental ignition of gas in any structure or area where the presence of gas constitutes a hazard of fire or explosion, including the following:
When an operator has knowledge that the support for a segment of a buried cast iron pipeline is disturbed:
Abnormal operating condition means a condition identified by the operator that may indicate a malfunction of a component or deviation from normal operations that may:
Evaluation means a process, established and documented by the operator, to determine an individual's ability to perform a covered task by any of the following:
Qualified means that an individual has been evaluated and can:
Each operator shall have and follow a written qualification program. The program shall include provisions to:
Each operator shall maintain records that demonstrate compliance with this subpart.
This subpart prescribes minimum requirements for an integrity management program on any gas transmission pipeline covered under this part. For gas transmission pipelines constructed of plastic, only the requirements in §§ 192.917,192.921, 192.935 and 192.937 apply.
The following definitions apply to this subpart.
Assessment is the use of testing techniques as allowed in this subpart to ascertain the condition of a covered pipeline segment.
Confirmatory direct assessment is an integrity assessment method using more focused application of the principles and techniques of direct assessment to identify internal and external corrosion in a covered transmission pipeline segment.
Covered segment or covered pipeline segment means a segment of gas transmission pipeline located in a high consequence area. The terms gas and transmission line are defined in the Definitions section.
Direct assessment is an integrity assessment method that utilizes a process to evaluate certain threats (i.e., external corrosion, internal corrosion and stress corrosion cracking) to a covered pipeline segment's integrity. The process includes the gathering and integration of risk factor data, indirect examination or analysis to identify areas of suspected corrosion, direct examination of the pipeline in these areas, and post assessment evaluation.
High consequence area means an area established by one of the methods described in paragraphs (1) or (2) as follows:
Identified site means each of the following areas:
Potential impact circle is a circle of radius equal to the potential impact radius (PIR).
Potential impact radius (PIR) means the radius of a circle within which the potential failure of a pipeline could have significant impact on people or property. PIR is determined by the formula r = 0.69 * (square root of (p*d2)), where 'r' is the radius of a circular area in feet surrounding the point of failure, 'p' is the maximum allowable operating pressure (MAOP) in the pipeline segment in pounds per square inch and 'd' is the nominal diameter of the pipeline in inches.
Note: 0.69 is the factor for natural gas. This number will vary for other gases depending upon their heat of combustion. An operator transporting gas other than natural gas must use section 3.2 of ASME/ANSI B31.8S-2001 (Supplement to ASME B31.8; (incorporated by reference, see § 192.7)) to calculate the impact radius formula.
Remediation is a repair or mitigation activity an operator takes on a covered segment to limit or reduce the probability of an undesired event occurring or the expected consequences from the event.
An operator's initial integrity management program begins with a framework (see § 192.907) and evolves into a more detailed and comprehensive integrity management program, as information is gained and incorporated into the program. An operator must make continual improvements to its program. The initial program framework and subsequent program must, at minimum, contain the following elements. (When indicated, refer to ASME/ANSI B31.8S (incorporated by reference, see § 192.7) for more detailed information on the listed element.)
An operator must include each of the following elements in its written baseline assessment plan:
An operator using the confirmatory direct assessment (CDA) method as allowed in § 192.937 must have a plan that meets the requirements of this section and of § 192.925 (ECDA) and § 192.927 (ICDA).
An operator must comply with the following requirements in establishing the reassessment interval for the operator's covered pipeline segments.
Maximum Reassessment Interval | |||
Assessment Method | Pipeline operating at or above 50% SMYS | Pipeline operating at or above 30% SMYS, up to 50% SMYS | Pipeline operating below 30% SMYS |
Internal Inspection Tool, Pressure Test or Direct Assessment | 10 years(*)------------ | 15 years(*)----------- | 20 years.(**) |
Confirmatory Direct Assessment | 7 years----------------- | 7 years---------------- | 7 years. |
Low stress Reassessment | Not applicable--------- | Not applicable------- | 7 years + ongoing actions specified in §192.941. |
(*) A Confirmatory direct assessment as described in § 192.931 must be conducted by year 7 in a 10-year interval and years 7 and 14 of a 15-year interval.
(**) A low stress reassessment or Confirmatory direct assessment must be conducted by years 7 and 14 of the interval.
An operator must maintain, for the useful life of the pipeline, records that demonstrate compliance with the requirements of this subpart. At minimum, an operator must maintain the following records for review during an inspection.
An operator must provide any notification required by this subpart by -
An operator must send any performance report required by this subpart to the Information Resources Manager-
APPENDIX A TO PART 192 - RESERVED
APPENDIX B TO PART 192 - QUALIFICATION OF PIPE
API 5L-Steel Pipe, "API Specification for Line Pipe" (incorporated by reference, see § 192.7).
ASTM A53/A53M-SteeI Pipe, "Standard Specification for Pipe, Steel Black and Hot-Dipped, Zinc-Coated, Welded and Seamless" (incorporated by reference, see § 192.7).
ASTM A106-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-Steel pipe, "Standard Specification for Electric-Fusion-Welded Pipe for Atmospheric and Lower Temperatures" (incorporated by reference, see § 192.7).
ASTM A672-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-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-Thermoplastic pipe and tubing, "Standard Specification for Thermoplastic Gas Pressure Pipe, Tubing, and Fittings" (incorporated by reference, see § 192.7).
ASTM D2517-Thermosetting plastic pipe and tubing, "Standard Specification Reinforced Epoxy Resin Gas Pressure Pipe and Fittings" (incorporated by reference, see § 192.7).
Number of Tensile Tests - All Sizes
10 lengths or less | 1 set of tests for each length. |
11 to 100 lengths | 1 set of tests for each 5 lengths, but not less than 10 tests. |
Over 100 lengths | 1 set of tests for each 10 lengths, but not less than 20 tests. |
If the yield-tensile ratio, based on the properties determined by those tests, exceeds 0.85, the pipe may be used only as provided in § 192.55 (c).
Steel pipe manufactured before November 12,1970, in accordance with a specification of which a later edition is listed in Section I of this appendix, is qualified for use under this part if the following requirements are met:
APPENDIX C TO PART 192 - QUALIFICATION OF WELDERS FOR LOW STRESS LEVEL PIPE
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.
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.
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:
APPENDIX D TO PART 192 - CRITERIA FOR CATHODIC PROTECTION AND DETERMINATION OF MEASUREMENTS
APPENDIX E TO PART 192 - GUIDANCE ON DETERMINING HIGH CONSEQUENCE AREAS AND ON CARRYING OUT REQUIREMENTS IN THE INTEGRITY MANAGEMENT RULE
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.I.A for a diagram of a high consequence area).
Determining High Consequence Area
Figure E.I.A
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
Table E.II.2
Assessment Requirements for Transmission Pipelines in HCAs (Re-assessment intervals are maximum allowed)
Table E.II.3
Preventative & Mitigative Measures addressing Time Dependent and independent Threats for Transmission Pipelines that Operate Below 30% SMYS, in HCAs
As used in this part:
Administrator means the Administrator, Pipeline and Hazardous Materials Safety Administration or his or her delegate.
Ambient vaporizer means a vaporizer which derives heat from naturally occurring heat sources, such as the atmosphere, sea water, surface waters, or geothermal waters.
Cargo transfer system means a component, or system of components functioning as a unit, used exclusively for transferring hazardous fluids in bulk between a tank car, tank truck, or marine vessel and a storage tank.
Component means any part, or system of parts functioning as a unit, including, but not limited to, piping, processing equipment, containers, control devices, impounding systems, lighting, security devices, fire control equipment, and communication equipment, whose integrity or reliability is necessary to maintain safety in controlling, processing, or containing a hazardous fluid.
Container means a component other than piping that contains a hazardous fluid.
Control system means a component, or system of components functioning as a unit, including control valves and sensing, warning, relief, shutdown, and other control devices, which is activated either manually or automatically to establish or maintain the performance of another component.
Controllable emergency means an emergency where reasonable and prudent action can prevent harm to people or property.
Design pressure means the pressure used in the design of components for the purpose of determining the minimum permissible thickness or physical characteristics of its various parts. When applicable, static head shall be included in the design pressure to determine the thickness of any specific part.
Determine means make an appropriate investigation using scientific methods, reach a decision based on sound engineering judgment, and be able to demonstrate the basis of the decision.
Dike means the perimeter of an impounding space forming a barrier to prevent liquid from flowing in an unintended direction.
Emergency means a deviation from normal operation, a structural failure, or severe environmental conditions that probably would cause harm to people or property.
Exclusion zone means an area surrounding an LNG facility in which an operator or government agency legally controls all activities in accordance with § 193.2057 and § 193.2059 for as long as the facility is in operation.
Fail-safe means a design feature which will maintain or result in a safe condition in the event of malfunction or failure of a power supply, component, or control device.
g means the standard acceleration of gravity of 9.806 meters per second2 (32.17 feet per second)2.
Gas, except when designated as inert, means natural gas, other flammable gas, or gas which is toxic or corrosive.
Hazardous fluid means gas or hazardous liquid.
Hazardous liquid means LNG or a liquid that is flammable or toxic.
Heated vaporizer means a vaporizer which derives heat from other than naturally occurring heat sources.
impounding space means a volume of space formed by dikes and floors which is designed to confine a spill of hazardous liquid.
Impounding system includes an impounding space, including dikes and floors for conducting the flow of spilled hazardous liquids to an impounding space.
Liquefied natural gas or LNG means natural gas or synthetic gas having methane (CH4) as its major constituent which has been changed to a liquid.
LNG facility means a pipeline facility that is used for liquefying natural gas or synthetic gas or transferring, storing, or vaporizing liquefied natural gas.
LNG plant means an LNG facility or system of LNG facilities functioning as a unit.
m3 means a volumetric unit which is one cubic meter, 6.2898 barrels, 35.3147 ft.3, or 264.1720 U.S. gallons, each volume being considered as equal to the other.
Maximum allowable working pressure means the maximum gage pressure permissible at the top of the equipment, containers or pressure vessels while operating at design temperature.
Normal operation means functioning within ranges of pressure, temperature, flow, or other operating criteria required by this part.
Operator means a person who owns or operates an LNG facility.
Person means any individual, firm, joint venture, partnership, corporation, association, state, municipality, cooperative association, or joint stock association and includes any trustee, receiver, assignee, or personal representative thereof.
Pipeline facility means new and existing piping, rights-of-way, and any equipment, facility, or building used in the transportation of gas or in the treatment of gas during the course of transportation.
Piping means pipe, tubing, hoses, fittings, valves, pumps, connections, safety devices or related components for containing the flow of hazardous fluids.
Storage tank means a container for storing a hazardous fluid.
Transfer piping means a system of permanent and temporary piping used for transferring hazardous fluids between any of the following: Liquefaction process facilities, storage tanks, vaporizers, compressors, cargo transfer systems, and facilities other than pipeline facilities.
Transfer system includes transfer piping and cargo transfer system.
Vaporization means an addition of thermal energy changing a liquid to a vapor or gaseous state.
Vaporizer means a heat transfer facility designed to introduce thermal energy in a controlled manner for changing a liquid to a vapor or gaseous state.
Waterfront LNG plant means an LNG plant with docks, wharves, piers, or other structures in, on, or Immediately adjacent to the navigable waters of the United States or Puerto Rico and any shore area immediately adjacent to those waters to which vessels may be secured and at which LNG cargo operations may be conducted.
Leaks and spills of LNG must be reported in accordance with the requirements of Part 191 of this chapter.
http://www.archives.gov/federal_register/code_of_federaI_regulations/lBR locations.html.
Documents incorporated by reference are available from the publishers as follows:
Source and name of referenced material | 49 CFR reference |
A. American Gas Association (AGA): | |
(1) "Purging Principles and Practices," (3rd edition, 2001).. | §§ 193.2513; 193.2517; 193.2615. |
B. American Society of Civil Engineers (ASCE): | |
(1) SEI/ASCE 7-02 "Minimum Design Loads for Buildings and Other Structures," (2002 edition). | § 193.2067. |
C. ASME International (ASME): | |
(1) ASME Boiler and Pressure Vessel Code, Section VIII, Division 1, "Rules for Construction of Pressure Vessels," (2004 edition, including addenda through July 1, 2005). | § 193.2321 |
(2) ASME Boiler and Pressure Vessel Code, Section VIII, Division 2, "Rules for Construction of Pressure Vessels-Alternative Rules,: (2004 edition, including addenda through July 1,2005). | §193.2321. |
D. Gas Technology Institute (GTI): | |
(1) GRI-89/0176 "LNGFlRE" A Thermal Radiation Model for LNG Fires," (June 29,1990)........................... | § 193.2057. |
(2) GTI-04/0049 (April 2004) "LNG Vapor Dispersion Prediction with the DEGADIS 2.1: Dense Gas Dispersion Model for LNG Vapor Dispersion". | § 193.2059. |
(3) GRl-96/0396.5 "Evaluation of Mitigation Methods for Accidental LNG Releases, Volume 5: Using FEM3A for LNG Accident Consequence Analyses," (April 1997). | § 193.2059 |
E. National Fire Protection Association (NFPA): | |
(1) NFPA 59A (2001) "Standard for the Production, Storage, and Handling of Liquefied Natural Gas (LNG)." | §§ 193.2019; 193.2051; 193.2057; 193.2059; 193.2101; 193.2301; 193.2303; 193.2401; 193.2521; 193.2639; 193.2801. |
Each LNG facility designed, constructed, replaced, relocated or significantly altered after March 31, 2000 must be provided with siting requirements in accordance with the requirements of this part and of NFPA 59A (incorporated by reference, see § 193.2013). In the event of a conflict between this part and NFPA 59A, this part prevails.
Each LNG container and LNG transfer system must have a thermal exclusion zone in accordance with section 2.2.3.2 of NFPA 59A (incorporated by reference, see § 193.2013) with the following exceptions:
Each LNG container and LNG transfer system must have a dispersion exclusion zone in accordance with sections 2.2.3.3 and 2.2.3.4 of NFPA 59A (incorporated by reference, see § 193.2013) with the following exceptions:
Each LNG facility designed after March 31, 2000 must comply with requirements of this part and of NFPA 59A (incorporated by reference, see § 193.2013). In the event of a conflict between this part and NFPA 59A, this part prevails.
Materials
Each operator shall keep a record of all materials for components, buildings, foundations, and support systems, as necessary to verify that material properties meet the requirements of this part. These records must be maintained for the life of the item concerned.
Design of Components and Buildings
Impoundment Design and Capacity
An outer wall of a component served by an impounding system may not be used as a dike unless the outer wall is constructed of concrete.
A covered impounding system is prohibited except for concrete wall designed tanks where the concrete wall is an outer wall serving as a dike.
Each impounding system serving an LNG storage tank must have a minimum volumetric liquid impoundment capacity of:
LNG Storage Tanks
A flammable nonmetallic membrane liner may not be used as an inner container in a storage tank.
Each LNG facility constructed after March 31, 2000 must comply with requirements of this part and of NFPA 59A (incorporated by reference, see § 193.2013). In the event of a conflict between this part and NFPA 59A, this part prevails.
No person may place in service any component until it passes all applicable inspections and tests prescribed by this subpart and NFPA 59A (incorporated by reference, see § 193.2013).
The butt welds in metal shells of storage tanks with internal design pressure above 15 p.s.i.g. must be radiographically tested in accordance with the ASME Boiler and Pressure Vessel Code (Section VIII Division 1), except that hydraulic load bearing shells with curved surfaces that are subject to cryogenic temperatures, 100 percent of both longitudinal (or meridional) and circumferential (or latitudinal) welds must be radiographically tested.
After March 31, 2000, each new, replaced, relocated or significantly altered vaporization equipment, liquefaction equipment, and control systems must be designed, fabricated, and installed in accordance with requirements of this part and of NFPA 59A (incorporated by reference, see § 193.2013). In the event of a conflict between this part and NFPA 59A, this part prevails.
VAPORIZATION EQUIPMENT
Each LNG plant must have a control center from which operations and warning devices are monitored as required by this part. A control center must have the following capabilities and characteristics:
This subpart prescribes requirements for the operation of LNG facilities
Each operator shall follow one or more manuals of written procedures to provide safety in normal operation and in responding to an abnormal operation that would affect safety. The procedures must include provisions for:
Each component in operation or building in which a hazard to persons or property could exist must be monitored to detect fire or any malfunction or flammable fluid that could cause a hazardous condition. Monitoring must be accomplished by watching or listening from an attended control center for warning alarms, such as gas, temperature, pressure, vacuum, and flow alarms, or by conducting an inspection or test at intervals specified in the operating procedures.
When necessary for safety, components that could accumulate significant amounts of combustible mixtures must be purged in accordance with a procedure which meets the provisions of the AGA "Purging Principles and Practice" after being taken out of service and before being returned to service.
Each operator shall maintain a record of results of each inspection, test and investigation required by this subpart. For each LNG facility that is designed and constructed after March 31, 2000 the operator shall also maintain related inspection, testing, and investigation records that NFPA 59A (incorporated by reference, see § 193.2013) requires. Such records, whether required by this part or NFPA 59A, must be kept for a period of not less than five years.
This subpart prescribes requirements for maintaining components at LNG plants.
Each support system or foundation of each component must be inspected for any detrimental change that could impair support.
Each auxiliary power source must be tested monthly to check its operational capability and tested annually for capacity. The capacity test must take into account the power needed to start up and simultaneously operate equipment that would have to be served by that power source in an emergency.
Hoses used in LNG or flammable refrigerant transfer systems must be:
Each LNG storage tank must be inspected or tested to verify that each of the following conditions does not impair the structural integrity or safety of the tank:
Each exposed component that is subject to atmospheric corrosive attack must be protected from atmospheric corrosion by:
Each component that is subject to internal corrosive attack must be protected from internal corrosion by:
Corrosion protection provided as required by this subpart must be periodically monitored to give early recognition of ineffective corrosion protection, including the following, as applicable:
Prompt corrective or remedial action must be taken whenever an operator learns by inspection or otherwise that atmospheric, external, or internal corrosion is not controlled as required by this subpart.
This subpart prescribes requirements for personnel qualifications and training.
For the design and fabrication of components, each operator shall use-
Personnel having security duties must be qualified to perform their assigned duties by successful completion of the training required under § 193.2715.
Each operator shall follow a written plan to verify that personnel assigned operating, maintenance, security, or fire protection duties at the LNG plant do not have any physical condition that would impair performance of their assigned duties. The plan must be designed to detect both readily observable disorders, such as physical handicaps or injury, and conditions requiring professional examination for discovery.
Each operator must provide and maintain fire protection at LNG plants according to sections 9.1 through 9.7 and section 9.9 of NFPA 59A (incorporated by reference, see § 193.2013). However, LNG plants existing on March 31, 2000, need not comply with provisions on emergency shutdown systems, water delivery systems, detection systems, and personnel qualification and training until September 12, 2005.
This subpart prescribes requirements for security at LNG plants. However, the requirements do not apply to existing LNG plants that do not contain LNG.
Each operator shall prepare and follow one or more manuals of written procedures to provide security for each LNG plant. The procedures must be available at the plant in accordance with § 193.2017 and include at least:
The protective enclosure may be one or more separate enclosures surrounding a single facility or multiple facilities.
A means must be provided for:
Where security warning systems are not provided for security monitoring under § 193.2913, the area around the facilities listed under § 193.2905(a) and each protective enclosure must be illuminated with a minimum in service lighting intensity of not less than 2.2 lux (0.2 ftc) between sunset and sunrise.
Each protective enclosure and the area around each facility listed in § 193.2905(a) must be monitored for the presence of unauthorized persons. Monitoring must be by visual observation in accordance with the schedule in the security procedures under § 193.2903(a) or by security warning systems that continuously transmit data to an attended location. At an LNG plant with less than 40,000 m3 (250,000 bbl) of storage capacity, only the protective enclosure must be monitored.
An alternative source of power that meets the requirements of § 193.2445 must be provided for security lighting and security monitoring and warning systems required under §§ 193.2911 and 193.2913.
As used in this part
"Accident" means an incident reportable under Part 191 involving gas pipeline facilities or LNG facilities.
"Administrator" means the Administrator, Pipeline and Hazardous Materials Safety Administration or his or her delegate.
"Covered employee, employee, or individual to be tested" means a person who performs a covered function, including persons employed by operators, contractors engaged by operators, and persons employed by such contractors.
"Covered function" means an operations, maintenance, or emergency-response function regulated by part 192,193, or 195 of this chapter that is performed on a pipeline or on an LNG facility.
"DOT Procedures" means the Procedures for Transportation Workplace Drug and Alcohol Testing Programs published by the Office of the Secretary of Transportation in part 40 of this title.
"Fail a drug test" means that the confirmation test result shows positive evidence of the presence under DOT Procedures of a prohibited drug in an employee's system.
"Operator" means a person who owns or operates pipeline facilities subject to Part 192.
"Pass a drug test" means that initial testing or confirmation testing under DOT Procedures does not show evidence of the presence of a prohibited drug in a person's system.
"Performs a covered function" includes actually performing, ready to perform, or immediately available to perform a covered function.
"Positive rate for random drug testing" means the number of verified positive results for random drug tests conducted under this part plus the number of refusals of random drug tests required by this part, divided by the total number of random drug tests results (i.e., positives, negatives, and refusals) under this part.
"Prohibited drug" means any of the following substances specified in Schedule I or Schedule II of the Controlled Substances Act (21 U.S.C. 812) : marijuana, cocaine, opiates, amphetamines, and phencyclidine (PCP).
"Refuse to submit, refuse, or refuse to take" means behavior consistent with DOT Procedures concerning refusal to take a drug test or refusal to take an alcohol test.
"State agency" means an agency of any of the several states, the District of Columbia, or Puerto Rico that participates under the pipeline safety laws (49 U.S.C. 60101et seq.).
The anti-drug and alcohol programs required by this part must be conducted according to the requirements of this part and DOT Procedures. Terms and concepts used in this part have the same meaning as in DOT Procedures. Violations of DOT Procedures with respect to anti-drug and alcohol programs required by this part are violations of this part.
The purpose of this subpart is to establish programs designed to help prevent accidents and injuries resulting from the use of prohibited drugs by employees who perform covered functions for operators of certain pipeline facilities subject to part 192,193. or 195 of this chapter.
Each operator shall conduct the following drug tests for the presence of a prohibited drug:
Within this 365-day period, the employee or the employee's representative, the operator, the Administrator, or, if the operator is subject to the jurisdiction of a state agency, the state agency may request that the laboratory retain the sample for an additional period. I f, within the 365-day period, the laboratory has not received a proper written request to retain the sample for a further reasonable period specified in the request, the sample may be discarded following the end of the 365-day period.
With respect to those employees who are contractors or employed by a contractor, an operator may provide by contract that the drug testing, education, and training required by this subpart be carried out by the contractor provided:
The purpose of this subpart is to establish programs designed to help prevent accidents and injuries resulting from the misuse of alcohol by employees who perform covered functions for operators of certain pipeline facilities subject to part 192 of this code.
Each operator must maintain and follow a written alcohol misuse plan that conforms to the requirements of this part and DOT Procedures concerning alcohol testing programs. The plan shall contain methods and procedures for compliance with all the requirements of this subpart, including required testing, record keeping, reporting, education and training elements.
Before performing an alcohol test under this subpart, each operator shall notify a covered employee that the alcohol test Is required by this subpart. No operator shall falsely represent that a test is administered under this subpart.
Each operator shall prohibit a covered employee from reporting for duty or remaining on duty requiring the performance of covered functions while having an alcohol concentration of 0.04 or greater. No operator having actual knowledge that a covered employee has an alcohol concentration of 0.04 or greater shall permit the employee to perform or continue to perform covered functions.
Each operator shall prohibit a covered employee from using alcohol while performing covered functions. No operator having actual knowledge that a covered employee is using alcohol while performing covered functions shall permit the employee to perform or continue to perform covered functions.
Each operator shall prohibit a covered employee from using alcohol within four hours prior to performing covered functions, or, if an employee is called to duty to respond to an emergency, within the time period after the employee has been notified to report for duty. No operator having actual knowledge that a covered employee has used alcohol within four hours prior to performing covered functions or within the time period after the employee has been notified to report for duty shall permit that covered employee to perform or continue to perform covered functions.
Each operator shall prohibit a covered employee who has actual knowledge of an accident in which his or her performance of covered functions has not been discounted by the operator as a contributing factor to the accident from using alcohol for eight hours following the accident, unless he or she has been given a post-accident test under § 199.225(a), or the operator has determined that the employee's performance could not have contributed to the accident.
Each operator shall require a covered employee to submit to a post-accident alcohol test required under § 199.225(a), a reasonable suspicion alcohol test required under § 199.225(b), or a follow-up alcohol test required under § 199.225(d). No operator shall permit an employee who refuses to submit to such a test to perform or continue to perform covered functions.
Each operator shall conduct the following types of alcohol tests for the presence of alcohol:
Except as provided in §§ 199.239 through 199.243, no operator shall permit any covered employee to perform covered functions if the employee has engaged in conduct prohibited by §§ 199.215 through 199.223 or an alcohol misuse rule of another DOT agency.
No operator shall permit a covered employee who has engaged in conduct prohibited by §§ 199.215 through 199.223 to perform covered functions unless the employee has met the requirements of § 199.243.
Each operator shall ensure that persons designated to determine whether reasonable suspicion exists to require a covered employee to undergo alcohol testing under § 199.225(b) receive at least 60 minutes of training on the physical, behavioral, speech, and performance indicators of probable alcohol misuse.
126.01.09 Ark. Code R. 001