APPENDIX B  Flowline Rulemaking  Docket No. 171200767         Amended Initial Draft of Proposed Rules  October 1531, 2017  FLOWLINE RULEMAKING INITIAL DRAFT OF PROPOSED RULES (Please note that the redline below may in some instances show current rule language as newly proposed language because it has been moved between sections.) DEFINITIONS (100 Series) BREAKOUT TANK means a tank used to either relieve surges in a liquid hydrocarbon pipeline system or receive and store liquid hydrocarbons transported by a pipeline for reinjection and continued transportation by pipeline. CRUDE OIL TRANSFER LINE means a pipe or piping system that is not regulated by the U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration pursuant to 49 C.F.R. § 195.2, and which transfers crude oil or condensate generated by more than one oil and gas facility to an offsite production or storage facility. DOMESTIC TAP means an individual gas service line directly connected to a flowline. FLOWLINES means a segment of pipe transferring oil, gas, or condensate between a wellhead and the point of delivery to a U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration or Colorado Public Utilities Commission regulated gathering line or a segment of pipe transferring produced water between a wellhead and the point of disposal, discharge, or loading. shall mean those segments of pipe from the wellhead downstream through the production facilities ending at: in the case of gas lines, the gas metering equipment; or in the case of oil lines the oil loading point or LACT unit; or in the case of water lines, the water loading point, the point of discharge to a pit, the injection wellhead, or the permitted surface water discharge point. The different types of flowlines are: Wellhead Line means a flowline that transmits well production fluids from an oil or gas well to process equipment (e.g., separator, production separator, tank, heater treater), not including pre-conditioning equipment such as sand traps and line heaters, that do not materially reduce line pressure. Production Piping means a segment of pipe that transfers well production fluids from a wellhead line or production equipment to a gathering line or storage vessel and includes the following: Production Line means a flowline connecting a separator to a meter, LACT, or gathering line; Dump Line means a flowline that transfers produced water, crude oil, or condensate to a storage tank, or process vessel and operates at atmospheric pressure at the flowline’s outlet; Manifold Piping means a flowline that transfers fluids from lines that have been joined together to comingle fluids into a piece of production facility equipment; and Process Piping means all other piping that is integral to oil and gas exploration and production related to an individual piece or a set of production facility equipment pieces. Peripheral Piping means a flowline transferring fluids between oil and gas facilities for lease use, that may include, but is not limited to, fuel gas, lift gas, instrument gas, and power fluids. Produced Water Flowline means a flowline used to transfer produced water for treatment, storage, discharge, injection or reuse for oil and gas operations. Page 1 of 20  APPENDIX B  Flowline Rulemaking  Docket No. 171200767         Amended Initial Draft of Proposed Rules  October 1531, 2017  Produced Water Transfer System means a pipe or piping system that transports produced water generated at more than one well. A segment of pipe transferring only freshwater is not a flowline. A line that would otherwise satisfy the above definition will not be considered a flowline if all of the following are satisfied: -the operator prospectively marks and tags the line as a support line; -the line is not integral to production; -the line is used infrequently to service or maintain production equipment; -the line does not hold a constant pressure, and -the line is isolated from a pressure source when not in use. This definition does not include gathering lines. GATHERING LINE means a gathering pipeline as defined by 4 C.C.R. § 723-4901 or a pipeline regulated by the U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration pursuant to 49 C.F.R. §§ 195.2 or 192.8shall mean a pipeline and equipment described below that transports gas from a production facility (ordinarily commencing downstream of the final production separator at the inlet flange of the custody transfer meter) to a natural gas processing plant or transmission line or main. The term “gathering line” includes valves, metering equipment, communication equipment, cathodic protection facilities, and pig launchers and receivers, but does not include dehydrators, treaters, tanks, separators, or compressors located downstream of the final production facilities and upstream of the natural gas processing plants, transmission lines, or main lines. GRADE 1 GAS LEAK means a leak that represents an existing or probable hazard to persons or property and requires immediate repair or continuous action until the conditions are no longer hazardous. LOCKOUT means installing a device, such as a blind plug, blank flange, or bolted slip blind, that prevents operation of an energy-isolating device, such as a valve, and ensures the equipment cannot be operated until the lockout device is removed. MAXIMUM ANTICIPATED OPERATING PRESSURE means the highest operational pressure expected to be applied to a flowline when in service. OFF-LOCATION FLOWLINE means a flowline from a well to a production facility that is not on the same oil and gas location as the well. PIPELINE means a flowline, crude oil transfer line or gathering line as defined in these Rules. RISER means the component of a flowline transitioning from below grade to above grade. TAGOUT means securely fastening a tagout device to an energy-isolating device, such as a valve, to indicate that the energy-isolating device and the equipment being controlled may not be operated until the tagout device is removed. TAGOUT DEVICE means a prominent warning device, such as a tag, that will not deteriorate or become illegible with exposure to weather conditions or wet and damp locations. The tagout device must: include an instruction to not operate the equipment; the date of the last successful integrity test; the reason for tagging out the equipment; and be color coded per ANSI/ASME A13.1. PIPELINE FLOWLINE REGULATIONS (1100 Series) Page 2 of 20  APPENDIX B  Flowline Rulemaking  Docket No. 171200767         Amended Initial Draft of Proposed Rules  October 1531, 2017  1101. Registration Requirements a. Registration of Off-Location Flowlines. An operator of an off-location flowline must submit a Flowline Form, Form 44, to the Director after completing construction and must include the following information: (1) GPS location points for the risers; (2) pipe and bedding materials used in construction; (3) flowline diameter; (4) fluids that will be transferred; (5) the maximum anticipated operating pressure and initial pressure test results; (6) a schematic drawing of the flowline, associated oil and gas locations, and existing and proposed pipelines related to the oil and gas locations; and (7) the COGCC Facility ID assigned to the associated oil and gas locations. b. Domestic Tap Registration. (1) Upon installation or discovery, operators must report to the Director the GPS location for the point of flowline connection and the address of the point of delivery of all domestic taps connected to an operator’s flowline. (2) For Domestic Taps installed after February 14, 2018, an operator must register the domestic tap pursuant to subpart (1) and ensure: A. The domestic tap is locatable by a tracer line or location device placed adjacent to or in the trench of the domestic tap to facilitate locating it; B. A licensed plumber properly installs: i. properly-sized regulators on the domestic tap at the point it connects to the operator’s flowline and at the point it delivers gas to the dwelling or structure where the gas is utilized; and ii. all necessary piping to accommodate appropriate odorization, and gas utilization metering equipment; C. All materials used for the domestic tap are designed for gas service and are installed using appropriate cover and bedding material in accordance with industry standards; D. Markers are installed and maintained at the point the domestic tap connects to the operator’s flowline and at the point it delivers gas to the dwelling or structure where the gas is utilized. Markers must include the language required by Rule 1102.f.(2); and E. Odorant is supplied at the time of installation until abandonment of the domestic tap. c. Crude Oil Transfer Line Registration. At least 30 days before beginning construction of a crude oil transfer line, an operator must submit a Form 12 to the Director that includes a schematic Page 3 of 20  APPENDIX B  Flowline Rulemaking  Docket No. 171200767         Amended Initial Draft of Proposed Rules  October 1531, 2017  showing the gathering line’s route, including its crossings of public by-ways, road crossings, sensitive wildlife habitats, sensitive areas and natural and manmade watercourses to the Director. 1102. FLOWLINE AND CRUDE OIL TRANSFER MAINTENANCE, AND REPAIR AND RECLAMATION LINE INSTALLATION, OPERATIONS, a. Material. Materials for pipe and pipe other components of pipelines shall must be: (1)A. Able to maintain the structural integrity of the pipeline flowline or crude oil transfer line under anticipated operating temperature, pressure, and other conditions that may be anticipated; and (2)B. Compatible with the substances to be transported. C. Locatable by a tracer line or location device placed adjacent to or in the trench of all buried nonmetallic pipelines to facilitate the location of such pipelines. b. Design and Installation. (1) Each component of a flowline or crude oil transfer line must meet one of the following standards appropriate for the component: A. American Society of Mechanical Engineers, Pipeline Transportation Systems for Liquids and Slurries, 2016 Edition (ASME B31.4-2016), and no later editions of the standard. ASME B31.4-2016 is available for public inspection during normal business hours from the Public Room Administrator at the office of the Commission, 1120 Lincoln Street, Suite 801, Denver, Colorado 80203. Additionally, ASME B31.4-2016 may be examined at any state publications depository library and is available to purchase from the ASME. The ASME can be contacted at Two Park Avenue, New York, NY 10016-5990, 1-800-843-2763; B. ASME Gas Transmission and Distribution Piping Systems, 2016 Edition (ASME B31.82016), and no later editions of the standard. ASME B31.8-2016 is available for public inspection during normal business hours from the Public Room Administrator at the office of the Commission, 1120 Lincoln Street, Suite 801, Denver, Colorado 80203. Additionally, ASME B31.8-2016 may be examined at any state publications depository library and is available to purchase from the ASME. The ASME can be contacted at Two Park Avenue, New York, NY 10016-5990, 1-800-843-2763; C. ASME Process Piping, 2016 Edition (ASME 31.3-2016), and no later editions of the standard. ASME 31.3-2016 is available for public inspection during normal business hours from the Public Room Administrator at the office of the Commission, 1120 Lincoln Street, Suite 801, Denver, Colorado 80203. Additionally, ASME 31.3-2016 may be examined at any state publications depository library and is available to purchase from the ASME. The ASME can be contacted at Two Park Avenue, New York, NY 10016-5990, 1-800-843-2763; or D. API Specification 15S, Spoolable Reinforced Plastic Line Pipe, Second Edition, March 2016 (API Specification 15S), and no later editions of the standard. API Specification 15S is available for public inspection during normal business hours from the Public Room Administrator at the office of the Commission, 1120 Lincoln Street, Suite 801, Denver, Colorado 80203. In addition, API Specification 15S may be examined at any state publications depository library and is available from API at 1220 L Street, NW Washington, DC 20005-4070, 1-202-682-8000. Page 4 of 20  APPENDIX B  Flowline Rulemaking  Docket No. 171200767         Amended Initial Draft of Proposed Rules  October 1531, 2017  (2) Each component of a pipeline flowline or crude oil transfer line mustshall be designed and installed to: A. prevent Prevent failure from internal or external corrosion and the effects of transported fluids; B. and to wWithstand maximum anticipated operating pressures and other internal loadings without impairment of its serviceability; C.. The pipe shallD. h Have sufficient wall thickness or be installed with adequate protection to Wwithstand anticipated external pressures and loads that will be imposed on the pipe after installation;and. D. Allow for line maintenance, periodic line cleaning, and integrity testing. c. Installation. (1) Installation crews must be trained in all flowline or crude oil transfer line installation practices for which they are tasked to perform. (2) No pipe or other component may be installed unless it has been visually inspected at the site of installation to ensure that it is not damaged. (3) Flowlines or crude oil transfer lines must be installed in a manner that minimizes interference with agriculture, road and utility construction, the introduction of secondary stresses, and the possibility of damage to the pipe. (4) The pipe must be handled in a manner that minimizes stress and avoids physical damage to the pipe during stringing, joining, or lowering in. During the lowering in process the pipe string must be properly supported so as not to induce excess stresses on the pipe or the pipe joints or cause weakening or damage to the outer surface of the pipe. (5) Flowlines or crude oil transfer lines that cross a municipality, county, or state graded road must be bored unless the responsible governing agency specifically permits the owner to open cut the road. (6) Unless the manufacturer’s installation procedures and practices direct otherwise: A. pipeline trenches must be constructed to allow the pipeline to rest on undisturbed native soil and provide continuous support along the length of the pipe; B. trench bottoms must be free of rocks greater than two inches in diameter, debris, trash, and other foreign material not required for pipeline installation; and C. over excavated trench bottoms must be backfilled with appropriate material and compacted prior to installation of the pipe to provide continuous support along the length of the pipe. (7) The width of the trench must provide adequate clearance on each side of the pipe. Trench walls must be excavated to ensure minimal sluffing of sidewall material into the trench. Subsoil from the excavated trench must be stockpiled separately from previously stripped topsoil. (8) A flowline or crude oil transfer line trench must be backfilled in a manner that provides firm Page 5 of 20  APPENDIX B  Flowline Rulemaking  Docket No. 171200767         Amended Initial Draft of Proposed Rules  October 1531, 2017  support under the pipe and prevents damage to the pipe and pipe coating from equipment or from the backfill material. Sufficient backfill material must be placed in the pipe springlift of the pipe to provide long-term support for the pipe. Backfill material that will be within two feet of the pipe must be free of rocks greater than two inches in diameter and foreign debris. Backfilling material must be compacted as appropriate during placement in a manner that provides support for the pipe and reduces the potential for damage to the pipe and pipe joints. (9) Flowlines and crude oil transfer lines must be installed as designed. (10) Flowlines and crude oil transfer lines that traverse sensitive wildlife habitats or sensitive areas, such as wetlands, streams, or other surface waterbodies, must be installed in a manner that minimizes impacts to these areas. c.d. Cover. (1) All installed pipelines flowlines mustshall have cover sufficient to protect them from damage. On crop land cropland, all pipelines flowlines shall must have a minimum cover of three (3) feet. (2) Where an underground structure, geologic, economic or other uncontrollable condition prevents pipelines a flowline from being installed with minimum cover, or when there is a written agreement between the surface owner and the operator, the a flowline line may be installed with less than minimum cover or above ground. (3) All installed crude oil transfer lines must have a minimum cover of three (3) feet. d.e. Excavation, backfill and reclamation. (1) When pipelines flowlines or crude oil transfer lines cross crop lands croplands, unless waived by the surface owner, the operator shall must segregate topsoil while trenching, and trenches shall be backfilled trenches so that the soils can shall must be returned to their original relative positions and contour. This requirement to segregate and backfill topsoil shall does not apply to trenches which are twelve (12) inches or less in width. Operator must make Rreasonable efforts shall be made to run pipelines flowlines or crude oil transfer lines parallel to crop irrigation rows on flood irrigated land. (2) On crop lands and non-crop lands, pipeline All trenches must shall be maintained in order to correct subsidence and reasonably minimize erosion. (1)(3) Interim and final reclamation, including revegetation, must shall be performed in accordance with the applicable 1000 Series rules. f. Marking. (1) In Designated Setback Locations, and where crossing public rights-of-way or utility easement, an operator must install and maintain a marker that identifies the location of pipelinesflowlines or crude oil transfer lines. (2) The marker must include the following language: "Warning", "Caution" or "Danger" followed by the words "gas (or name of natural gas or petroleum fluid transported) pipelineflowline (or crude oil transfer line)" along with the name of the operator and the telephone number where the operator can be reached at all times. The Page 6 of 20  APPENDIX B  Flowline Rulemaking  Docket No. 171200767         Amended Initial Draft of Proposed Rules  October 1531, 2017  letters must be legible, written on a background of sharply contrasting color and on each side with at least one (1) inch high with one-quarter (¼) inch stroke. g. Inspection. All newly constructed crude oil transfer lines must be inspected by third-party independent inspectors to ensure the crude oil transfer line is installed as prescribed by the manufacturer’s specifications and in accordance with the requirements of the 1100 series rules. An inspector must be trained, experienced and qualified in the phase of construction being inspected. A list of all third-party independent inspectors and a description of each independent inspector’s qualifications, certifications, experience, and specific training must be provided to the Director upon request pursuant to Rule 205. h. Maintenance. (1) Each operator must take reasonable precautions to prevent failures, leakage and corrosion of pipelinesflowlines and crude oil transfer lines. (2) Whenever an operator discovers any condition that could adversely affect the safe and proper operation of itsa pipelineflowline or crude oil transfer line, it must correct it within a reasonable time. However, if the condition presents an immediate hazard to persons or property, the operator may not operate the affected part of the system until the operator has corrected the condition. (3) Any flowline or crude oil transfer line not actively in use must have all valves locked or tagged out. g.i. Repair. (1) Each operator must, in repairing its pipelinesflowlines or crude oil transfer line, make repairs in a safe manner that prevents injury to persons and damage to equipment and property. (2) An operator may not use any pipe, valve, or fitting to repair a flowline or crude oil transfer line unless the components meet the installation requirements of the 1100 series rules. A flowline or crude oil transfer line installed prior to February 14, 2018, that undergoes a major modification or change in service after February 14, 2018, must satisfy all requirements of the 1100 series rules before an operator can place the flowline or crude oil transfer line in to service. (3) An operator may not use any pipe, valve, or fitting, for replacement or repair of a flowline, unless it is designed to the maximum anticipated operating pressure. (4) An operator must pressure test any repaired flowline or crude oil transfer line before returning it to service. j. Operating requirements. (1) No flowline or crude oil transfer line may be operated until it has demonstrated compliance with Rule 1103. (2) The maximum operating pressure for a flowline or crude oil transfer line may not exceed the manufacturer’s specifications of the pipe or the manufacturer’s specifications of any other component of it, whichever is less. A flowline or crude oil transfer line must be equipped with adequate controls and protective equipment to prevent it from operating above the maximum Page 7 of 20  APPENDIX B  Flowline Rulemaking  Docket No. 171200767         Amended Initial Draft of Proposed Rules  October 1531, 2017  operating pressure. k. Corrosion control. (1) All coated pipe must be electronically inspected prior to placement using coating deficiency (i.e. scratch, bubble, and “holiday”) detectors to check for any faults not observable by visual examination. The detector must operate in accordance with manufacturer's instructions and at a voltage level appropriate for the electrical characteristics of the pipeline being tested. During installation all joints, fittings, and tie-ins must be coated with materials compatible with the coatings on the pipe. Coating materials must: A. B. C. D. E. F. l. Be designed to mitigate corrosion of the buried pipeline; Have sufficient adhesion to the metal surface to prevent under film migration of moisture; Be sufficiently ductile to resist cracking; Have enough strength to resist damage due to handling and soil stress; Support any supplemental cathodic protection; and If the coating is an insulating type, have low moisture absorption and provide high electrical resistance. (2) Pipes must be locatable by a tracer line or location device placed adjacent to or in the trench of a buried nonmetallic flowline or crude oil transfer line. (3) Cathodic protection systems must meet or exceed the minimum criteria set forth in the National Association of Corrosion Engineers standard practice Control of External Corrosion on Underground or Submerged Metallic Piping Systems. (4) If internal corrosion is anticipated or detected, the flowline or crude oil transfer line operator must take prompt remedial action to correct any deficiencies, such as increased pigging, use of corrosion inhibitors, internal coating of the pipeline (e.g. an epoxy paint or other plastic liner), or a combination of these methods. Crude oil transfer line as built. For a crude oil transfer line placed into service after February 14, 2018, the operator must, within 30-days from the date of being placed into service, file with the Director a Form 44, and register with the Utility Notification Center of Colorado (UNCC). Operators must include the following information: (1) a schematic layout of the facility that shows the location of all associated above ground equipment and the pipeline centerline from the point of origin to the termination point; (2) a geographical information system layer utilizing North American datum 83 geographic coordinate system (GCS) in an environmental systems research institute (Esri) shape file format that has a completed attribute table containing the required data; and (3) an affidavit of completion that that states the operator designed and installed the crude oil transfer line in compliance with the 1100 Series rules and submitted the ERSI shape file to the UNCC. (4) the proposed pipe material (i.e., size, weight, grade, wall thickness, coating, and standard dimension ration); (5) the type of fluid to be transported; (6) the method for testing integrity; Page 8 of 20  APPENDIX B  Flowline Rulemaking  Docket No. 171200767         Amended Initial Draft of Proposed Rules  October 1531, 2017  (7) proposed burial depth of the crude oil transfer line; and (8) the location and construction method proposed for all public by-ways, road crossings, sensitive wildlife habitats, sensitive areas and natural and manmade watercourses (i.e., bored and cased or bored only). m. Record Keeping. An operator must keep records of flowline or crude oil transfer line size, route, materials, maximum anticipated operating pressure, pressure test results, and integrity management documentation for the life of the flowline. These records are available for inspection by the Director pursuant to Rule 205. h.n. One Call participation. As to any pipelines over which the Commission has jurisdiction, each Every operator shallmust become a Tier One member of the UNCC and participate in Colorado's One Call notification system, the requirements of which are established by §9-1.5-101., C.R.S. et seq. (1) An operator must include its UNCC member code when filing an Operator Registration, Form 1, Change of Operator, Form 10, Gas Facility Registration, Form 12, or Flowline Form, Form 44. (2) Upon completing an asset purchase, transfer, construction or relocation of a flowline or crude oil transfer line, an operator must update within 30-days its location information with the UNCC. (3) An operator’s registration with the Commission grants the Director permission to access information the operator submits to UNCC about its oil and gas facilities. o. Notification. The operator of a crude oil transfer line must submit a Form 42 notice of change to the Director identifying any crude oil transfer line or portion thereof that has been removed from service for more than one year. g. Pressure testing of flowlines. 11021103. OPERATIONS, MAINTENANCE, AND REPAIR INTEGRITY MANAGEMENT a. Notification. At least ten days before conducting an initial pressure test or an annual pressure  test,  an  operator  must  submit  a  Form  42  to  the  Director  to  allow  a  representative  of  the  Commission to witness the testing process and results.    b. Initial Pressure Test Requirements. After installation or being taken out of service and bBefore operating a segment of flowline or crude oil transfer line, an operator must test the flowline or crude oil transfer line it shall be tested to maximum anticipated operating pressure and demonstrate integrity. In conducting tests, each operator mustshall ensure that reasonable precautions are taken to protect its employees and the general public. The operator may conduct the test testing may be conducted using well head wellhead pressure sources and well bore fluids, including natural gas. Such pressure tests shall be repeated once each calendar year to maximum anticipated operating pressure, and operators shall maintain records of such testing for Commission inspection for at least three (3) years. c. Off-Location Flowlines. All off-location flowlines must be subject to one of the following integrity management programs: (1) Annual pressure test; Page 9 of 20  APPENDIX B  Flowline Rulemaking  Docket No. 171200767         Amended Initial Draft of Proposed Rules  October 1531, 2017  (2) Continuous pressure monitoring; or (3) For aboveground flowlines, annual visual inspection. d. Belowground Dump Lines. An operator must verify integrity of belowground dump lines by performing an annual static-head test. e. Aboveground Dump Lines and Small Diameter Peripheral Piping. An operator must verify integrity of aboveground dump lines or peripheral piping by performing an annual visual inspection. f. Integrity Management for All Other Flowlines. Any flowlines not subject to c. through e. above, must be subject to one of the following integrity management programs: (1) A pressure test every three years and annual visual inspection; or (2) Continuous pressure monitoring. g. Crude oil transfer lines. All crude oil transfer lines are subject to one of the following integrity management programs: (1) Annual pressure test; (2) Continuous pressure monitoring; or (3) Smart pigging conducted every three years. h. Leak protection, detection, and monitoring. (1) All crude oil transfer line operators must file with the Director any leak protection and monitoring plan prepared by the operator or required by the Director, pursuant to the Rule 205. All crude oil transfer line operators must develop and maintain a plan to share all inflow and outflow data. The data may include, but is not limited to, the flow and fluid properties of rate, volume, temperature, and pressure in order to perform a material balance computation. The plan must provide for data sharing between the production facility operator, the crude oil transfer line operator, and the operator at the point or points of disposal, storage, or sale. If a data discrepancy is observed, the party observing the data discrepancy is to notify all other parties and action must be taken to determine the cause. The crude oil transfer line operator is to retain a record of all data discrepancies. If requested, copies of such records must be filed with the Director pursuant to Rule 205. (2) i. Pressure Test Requirements. A pressure test must subject the flowline or crude oil transfer line to the maximum anticipated operating pressure and be conducted in accordance with one of the following: (1) API RP 1110, Recommended Practice for the Pressure Testing of Steel Pipelines for the Transportation of Gas, Petroleum Gas, Hazardous Liquids, Highly Volatile Liquids or Carbon Dioxide (6th Ed., February 1, 2013) (API RP 1110), and no later editions of the standard. API RP 1110 is available for public inspection during normal business hours from the Public Room Administrator at the office of the Commission, 1120 Lincoln Street, Suite 801, Denver, Colorado 80203. In addition, API RP 1110 may be examined at any state publications depository library and is available from API at 1220 L Street, NW Washington, DC 20005- Page 10 of 20  APPENDIX B  Flowline Rulemaking  Docket No. 171200767         Amended Initial Draft of Proposed Rules  October 1531, 2017  4070, 1-202-682-8000. (1) (2) The American Society for Testing and Materials Standard Practice for Field Leak Testing of Polyethylene (PE) and Crosslinked Polyethylene (PEX) Pressure Piping Systems Using Hydrostatic Pressure (ASTM F2164 – 13), and no later editions of the standard. ASTM F2164 – 13 is available for public inspection during normal business hours from the Public Room Administrator at the office of the Commission, 1120 Lincoln Street, Suite 801, Denver, Colorado 80203. In addition, ASTM F2164 – 13 may be examined at any state publications depository library and is available from ASTM at ASTM International, 100 Barr Harbor Drive, PO Box C700, West Conshohocken, PA, 19428-2959, 1-877-909-2786 j. Continuous Pressure Monitoring Requirements. An operator’s continuous pressure monitoring program must ensure: (1) Pressure data are monitored continuously, i.e., 24 hours, 7 days a week, and the monitoring is sufficiently sophisticated to identify integrity or pressure anomalies; (2) Systems are capable of being shut-in for repairs immediately upon discovery of an anomaly, either through automation or through a documented, manual process; (3) The operator documents the continuous monitoring program, including integrity anomalies and the documentation demonstrates how an operator will maintain and repair anomalies in flowlines or crude oil transfer lines; and (4) A map of the flowline or crude oil transfer line system is available in ESRI shapefile format. The shapefile must show the flowline or crude oil transfer line alignments, location of isolation valves, and pressure-monitoring points. k. Visual Inspection Requirements. An operator must perform a visual, aerial, or other survey of the entire flowline length to detect integrity failures, leaks, spills, or releases, or signs of a leak, spill, or release like stressed vegetation or soil discoloration. An operator may use audio, visual, or olfactory or other detection technology, like optical gas imaging or LASERs, to detect integrity failures. An operator must document the employee conducting the inspection, detection methodology, and date and time of the inspection. a. Flowline segments operating at less than fifteen (15) psig are excepted from pressure testing requirements. 11034. ABANDONMENT Each pipeline abandoned in place shall be disconnected from all sources and supplies of natural gas and petroleum, purged of liquid hydrocarbons, depleted to atmospheric pressure, and cut off three (3) feet below ground surface, or the depth of the pipeline, whichever is less and sealed at the ends. This requirement shall also apply to compressor or gas plant feeder pipelines upon decommissioning or closure of a portion or all of a compressor station or gas plant. Notice of such abandonment shall be filed with the Commission and with the local governmental designee or local government jurisdiction. a. A flowline or crude oil transfer line remains subject to all of the requirements in Rules 1101 through 1103 until the operator completes all abandonment requirements set forth below. b. For abandonment, operators must permanently remove a flowline or crude oil transfer line from service by physically separating it from all sources of fluids or pressure and comply with one of the following: (1) Abandonment in place. The operator must: Page 11 of 20  APPENDIX B  Flowline Rulemaking  Docket No. 171200767         Amended Initial Draft of Proposed Rules  October 1531, 2017  A. Purge the flowline or crude oil transfer line of any liquids; B. Deplete the flowline or crude oil transfer line to atmospheric pressure; C. Cut the flowline’s or crude oil transfer line’s risers to three (3) feet below grade or to the depth of the flowline or crude oil transfer line, whichever is shallower; D. Seal the ends of the flowline or crude oil transfer line below grade; and E. Remove cathodic protection and above-grade equipment associated with the riser. (2) Removal. The operator must remove the flowline or crude oil transfer line and risers, and cathodic protection and above-grade equipment associated with the riser. c. Once an operator removes a flowline or crude oil transfer line from service and is in the process of abandoning it, the operator must lockout and tagout the risers associated with the flowline or crude oil transfer line using appropriate devices. d. Within 10 days of an operator completing abandonment requirements for a flowline or crude oil transfer line, the operator must file a Notice of Flowline Abandonment, Form 44, with the Director. If the operator abandons an Off-Location Flowline and has not submitted GPS location points for the flowline’s risers, the Notice of Flowline Abandonment must include this information. e. The Director will provide the filed Notice of Flowline Abandonment, Form 44 to the appropriate Local Governmental Designee and UNCC. f. These abandonment requirements apply to compressor or gas plant feeder pipelines upon decommissioning or closure of a portion or all of a compressor station or gas plant. DRILLING, DEVELOPMENT, PRODUCTION AND ABANDONMENT (300 Series) 312. COGCC Form 10. CERTIFICATE OF CLEARANCE AND/OR CHANGE OF OPERATOR *** i. A completed Form 10 is shall be required for any change of operator for all oil and gas facilities, excluding except for produced water transfer systems, gas gathering systems, gas- processing plants, and underground gas storage facilities as those shall be changed with a Form 12, Gas Facility Registration/Change of Operator, which are governed by Rule 313B. 313A. COGCC Form 11. MONTHLY REPORT OF GASOLINE OR OTHER EXTRACTION PLANT All operators of gasoline or other extraction plants shall must make monthly reports to the Director on a Form 11. Such forms shall must contain all information required thereon and shall must be filed with the Director on or before the twenty-fifth (25th) day of each month covering the preceding month. 313B. COGCC Form 12. PRODUCED WATER TRANSFER SYSTEM, AND GAS FACILITY REGISTRATION/CHANGE OF OPERATOR a. An operator must submit a Form 12 to register a new produced water transfer system, gas gathering system, a new gas processing plant, or a new underground gas storage facility. The operator must attach a flowline layout drawing and a topographic map to the Form 12. Page 12 of 20  APPENDIX B  Flowline Rulemaking  Docket No. 171200767         Amended Initial Draft of Proposed Rules  October 1531, 2017  b. When an operator makes significant changes to an existing produced water transfer system, gas gathering system, gas processing plant, or underground gas storage facility, the operator must submit a Form 12 to update the Commission’s records regarding the facility. The operator must attach an updated flowline layout drawing and an updated topographic map to the Form 12. c. An operator must submit a Form 12 to change the operator of a produced water transfer system, gas gathering system, gas processing plant, or an underground gas storage facility. The operator must attach documentation confirming transfer of the asset(s) to the Form 12 for a change of operator. d. At least 30 days before beginning construction of a gas gathering line with segments subject to safety regulation by the Office of Pipeline Safety, U.S. Department of Transportation, an operator must submit a Form 12 to the Director. The operator must attach a schematic showing the gathering line’s route and its crossings of public by-ways and natural and manmade watercourses to the Form 12. 328. MEASUREMENT OF OIL *** d. Tank Gauging. Measurement by tank gauging shall must be completed in accordance with industry standards as specified in: i. The API Manual of Petroleum Measurement Standards, Chapter 3.1A Standard Practice for the Manual Gauging of Petroleum and Petroleum Products, (Second Edition, August 2005) and no later editions; ii. The API Manual of Petroleum Measurement Standards, Chapter 3.1B Standard Practice for the Manual Gauging of Petroleum and Petroleum Products, (Second Edition, June 2001) and no later editions; iii. The API Manual of Petroleum Measurement Standards, Chapter 3.1A Standard Practice for the Manual Gauging of Petroleum and Petroleum Products, (Second Edition, August 2005) and no later editions; iv. The API Manual of Petroleum Measurement Standards Chapter 18.1 - Custody Transfer Section 1-Measurement Procedures for Crude Oil Gathered from Small Tanks by Truck (Second Edition, April 1997) and no later editions, or v. The API Manual of Petroleum Measurement Standards Chapter 18.2, Custody Transfer of Crude Oil from Lease Tanks Using Alternative Measurement Methods, (First Edition, July 2016) and no later editions. The API Manuals identified in i. through v. above are available for public inspection during normal business hours from the Public Room Administrator at the office of the Commission, 1120 Lincoln Street, Suite 801, Denver, Colorado 80203. In addition, the API Manuals may be examined at any state publications depository library and is available from API at 1220 L Street, NW Washington, DC 20005-4070, 1-202-682-8000. *** SAFETY REGULATIONS (600 Series) Page 13 of 20  APPENDIX B  Flowline Rulemaking  Docket No. 171200767         Amended Initial Draft of Proposed Rules  October 1531, 2017  602. GENERAL The training and actions of an operator’s employees, as well as the proper location and operation of equipment, are essential to any safety program. a. Operators must familiarize their employees Employees shall be familiarized with these Rules as provided herein as they relate to their job functions. Each new employee should have his or her job outlined, explained and demonstrated. b. Employees shall must immediately report unsafe and potentially dangerous conditions to their supervisor and any such these conditions shall be remedied as soon as practicable. c. An operator must notify the Director of reportable safety events at an oil and gas facility. Reportable safety events include: (1) Any fire, explosion, accidental detonation, or uncontrolled release of pressure. (2) Any accident that involves a fatal injury. (3) Any accident involving a major or life-threating injury. (4) Any injury to the member of the general public that requires Medical Treatment. (5) Any natural event or accident that results in an actual or threatened safety event. d. Initial notification from the operator of a reportable safety event described in c. (1) -(7) above, must occur as soon as practicable, but no more than 24 hours after the safety event. An Accident Report, Form 22, must be submitted to the Director within 3-days of the accident. (1) At the Director’s request, the operator must submit a supplemental report that details the root cause analysis, information about any repairs, or other information related to the accident. (2) At the Director’s request, the operator must present its root cause analysis about the accident to the Commission or to an organization approved by the Director. e. Where unsafe or potentially dangerous conditions exist and first responders are on-site, the owner or operator must respond as directed by first responders (such as sheriff, fire district director, etc.) f. Vehicles of persons not involved in drilling, production, servicing, or seismic operations must shall be located a minimum distance of one hundred (100) feet from the wellbore, or a distance equal to the height of the derrick or mast, whichever is greater. Equivalent safety measures shall be taken where terrain, location or other conditions do not permit this minimum distance requirements.   g. Existing wells are exempt from the provisions of these regulations as they relate to the location of the well.   h.g. Existing producing facilities shall be are exempt from the provisions of these regulations with respect to minimum distance requirements and setbacks unless they are found by the Director to be unsafe. Page 14 of 20  APPENDIX B  Flowline Rulemaking  Docket No. 171200767         Amended Initial Draft of Proposed Rules  October 1531, 2017  h. Self-contained sanitary facilities shall be provided during drilling operations and at any other similarly staffed oil and gas operations facility 605. OIL AND GAS FACILITIES. 605.d. Mechanical Conditions. All valves, pipes and fittings shall must be securely fastened, inspected at regular intervals, and maintained in good mechanical condition. An operator must fully open and close all valves at least annually and repair or replace valves that are not fully operational. Any valve, flange, fitting or other component connected to a flowline must have a manufacturer’s rating that is equal to or greater than the flowline’s maximum anticipated operating pressure. (1) A valve must be installed at each of the following locations: A. On the suction end and the discharge end of a pump station in a manner that permits isolation of the pump station equipment in the event of an emergency; B. On each flowline entering or leaving a breakout tank in a manner that permits isolation of the breakout tank from other facilities; C. At locations along a flowline system that will minimize the likelihood or damage or pollution from accidental discharge of hydrocarbons or E&P Waste, as appropriate for the terrain in open country or for populated areas; D. On each flowline to allow integrity testing of the flowline without interrupting fluid flow of other connected pipelines; E. On each side of a flowline crossing a waterbody that is more than 100 feet (30 meters) wide from high-water mark to high-water mark; and F. On each side of a flowline crossing a reservoir holding water for human consumption. (2) Check Valves Required. A. Where an operator produces two or more wells through a common flowline, separator, or manifold, the operator must equip each flowline leading from a well to the common flowline, separator, or manifold with a check valve or other means of shut-off. The check valve or other means of shut-off must be in the flowline serving the well. The check valve must be located between the wellhead and the point where the flowline connects with any other fFlowline, common separator, or common manifold. i. For wells produced through a common flowline or separator, the operator must place the check valve or other means of shut-off in each flowline leading from a well as close to the wellhead connection as is practicable. ii. For wells produced through a common manifold, the operator may place the check valve or other means of shut-off in each flowline from a well near a point where the flowline enters the manifold or as close to the wellhead connection as practicable. B. The check valve or other means of shut-off must be installed to permit fluids moving from the well to the common flowline, separator, or manifold and to prevent any fluid from entering the well through the flowline. C. The operator must keep the check valve or other means of shut-off in good working order. Page 15 of 20  APPENDIX B  Flowline Rulemaking  Docket No. 171200767         Amended Initial Draft of Proposed Rules  October 1531, 2017  D. Upon the Director’s request, operators must test the operation of the check valve or other means of shut-off. *** FINANCIAL ASSURANCE AND OIL AND GAS CONSERVATION AND ENVIRONMENTAL RESPONSE FUND (700 Series) 711. Natural g Produced water transfer systems, gas gathering, natural gas processing and underground natural gas storage facilities. Operators of produced water transfer systems ,natural gas gathering, natural gas processing, or underground natural gas storage facilities shall must be required to provide statewide blanket financial assurance to ensure compliance with the 900 Series rules in the amount of fifty thousand dollars ($50,000), or in an amount voluntarily agreed to with the Director, or in an amount to be determined by order of the Commission. Operators of small systems gathering or processing less than five (5) MMSCFD may provide individual financial assurance in the amount of five thousand dollars ($5,000). E&P WASTE MANAGEMENT (900 Series) 906. SPILLS AND RELEASES *** b. Reporting spills or releases of E&P Waste or produced fluids. (1) Report to the Director. Operators shall report a spill or release of E&P Waste or produced fluids that meet any of the following criteria to the Director verbally or in writing as soon as practicable, but no more than twenty-four (24) hours after discovery (the “Initial Report”). A. A spills/release of any size that impacts or threatens to impact any waters of the state, a residence or occupied structure, livestock, or public byway; B. A spill/release in which one (1) barrel or more of E&P Waste or produced fluids is spilled or released outside of berms or other secondary containment; C. A spill/release of five (5) barrels or more regardless of whether the spill/release is completely contained within berms or other secondary containment. ; or D. Any Grade 1 Gas Leak. Operators reporting a Grade 1 Gas Leak must use a Form 44 to submit the Initial Report or subsequent information required by this section. The Initial Report to the Director shall include, at a minimum, the location of the spill/release and any information available to the Operator about the type and volume of waste involved. If the Initial Report was not made by submitting a COGCC Spill/Release Report, Form 19 the Operator must submit a Form 19 with the Initial Report information as soon as practicable but not later than 72 hours after discovery of the spill/release unless extended by the Director. Page 16 of 20  APPENDIX B  Flowline Rulemaking  Docket No. 171200767         Amended Initial Draft of Proposed Rules  October 1531, 2017  In addition to the Initial Report to the Director, the Operator shall make a supplemental report on Form 19 not more than 10 calendar days after the spill/release is discovered that includes an 8 1/2 x 11 inch topographic map showing the governmental section and location of the spill or an aerial photograph showing the location of the spill; all pertinent information about the spill/release known to the Operator that has not been reported previously; and information relating to the initial mitigation, site investigation, and remediation measures conducted by the Operator. The Director may require further supplemental reports or additional information. *** Page 17 of 20  APPENDIX B  Flowline Rulemaking  Docket No. 171200767         Amended Initial Draft of Proposed Rules  October 1531, 2017  CONFORMING CHANGES DEFINITIONS (100 Series) OIL AND GAS FACILITY shall means equipment or improvements used or installed at an oil and gas location for the exploration, production, withdrawal, gathering, treatment, or processing of crude oil, condensate, E&P waste, or natural gas. OIL AND GAS OPERATIONS means exploringration for oil and gas, including the conducting of seismic operations and the drilling of test bores; the siting, drilling, deepening, recompletiong, reworking, or abandonment abandoning of a welln oil and gas well, underground injection well, or gas storage well; producitiong operations related to any such well, including the installation ofing flowlines and gathering systems; the generationg, transportationtransporting, storagestoring, treatmenttreating, or disposal disposingof exploration and production wastes; and any constructiong, site preparationg, or reclaimingation activities associated with such operations. PLUGGING AND ABANDONMENT shall means the cementing of a well, the removal of its associated production facilities, the removal or abandonment in-place of its flowline(s), and the remediation and reclamation of the wellsite. PRODUCTION FACILITY shall means any storage, separation, treating, dehydration, artificial lift, power supply, compression, pumping, metering, monitoring, flowline, and other equipment directly associated with a well oil wells, gas wells, or injection wells. PRODUCTION PITS shall means those pits used after drilling operations and initial completion of a well, including pits related to produced water flowlines or associated with E&P waste fromat natural gas gathering, processing and storage facilities, which constitute: SKIMMING/SETTLING PITS used to provide retention time for settling of solids and separation of residual oil for the purposes of recovering the oil or fluid. PRODUCED WATER PITS used to temporarily store produced water prior to injection for enhanced recovery or disposal, off-site transport, or surface-water discharge. PERCOLATION PITS used to dispose of produced water by percolation and evaporation through the bottom or sides of the pits into surrounding soils. EVAPORATION PITS used to contain produced waters which evaporate into the atmosphere by natural thermal forces. SPECIAL PURPOSE PITS shall means those pits used in oil and gas operations, including pits related to produced water flowlines or associated with E&P waste at from natural gas gathering, processing and storage facilities, which constitute: BLOWDOWN PITS used to collect material resulting from, including but not limited to, the emptying or depressurizing of wells, vessels, or flowlines, or E&P waste from gas gathering systems. FLARE PITS used exclusively for flaring gas. EMERGENCY PITS used to contain liquids during an initial phase of emergency response operations related to a spill/release or process upset conditions. Page 18 of 20  APPENDIX B  Flowline Rulemaking  Docket No. 171200767         Amended Initial Draft of Proposed Rules  October 1531, 2017  BASIC SEDIMENT/TANK BOTTOM PITS used to temporarily store or treat the extraneous materials in crude oil which may settle to the bottoms of tanks or production vessels and which may contain residual oil. WORKOVER PITS used to contain liquids during the performance of remedial operations on a producing well in an effort to increase production. PLUGGING PITS used for containment of fluids encountered during the plugging process. DRILLING, DEVELOPMENT, PRODUCTION AND ABANDONMENT (300 Series) 303. REQUIREMENTS FOR FORM 2, APPLICATION FOR PERMIT-TO-DRILL, DEEPEN, RE-ENTER, OR RECOMPLETE, AND OPERATE; FORM 2A, OIL AND GAS LOCATION ASSESSMENT. *** 303.b. FORM 2A, OIL AND GAS LOCATION ASSESSMENT. *** (2) Exemptions. A new Form 2A shall not be required for the following: A. Surface disturbance, other than for purposes described in subsections 303.b.(1) B and C. above, at an existing Oil and Gas Location within the originally disturbed area, even if interim reclamation has been performed; B. For an Oil and Gas Location covered by an approved Comprehensive Drilling Plan and where such Comprehensive Drilling Plan contains information substantially equivalent to that which would be required for a Form 2A for the proposed Oil and Gas Location and the Comprehensive Drilling Plan has been subject to procedures substantially equivalent to those required for a Form 2A, including but not limited to consultation with Surface Owners, local governments, the Colorado Department of Public Health and Environment or Colorado Parks and Wildlife, where applicable, and public notice and opportunity to comment, and where the operator does not seek a variance from the Comprehensive Drilling Plan or a provision of these rules that is not addressed in the Plan; C. Gathering lines; DC. Seismic operations; ED. Pipelines for oil, gas, or water; or FE. Roads. *** 317B. PUBLIC WATER SYSTEM PROTECTION a. Definitions. For purposes of this Rule 317B: (1) Drilling, Completion, Production and Storage (“DCPS”) Operations shall means operations at (i) well sites for the drilling, completion, recompletion, workover, or stimulation of wells or chemical and production fluid storage, and (ii) any other oil and gas location at which production Page 19 of 20  APPENDIX B  Flowline Rulemaking  Docket No. 171200767         Amended Initial Draft of Proposed Rules  October 1531, 2017  facilities are operated. DCPS Operations shall excludes roads, gathering lines, pipelines, and routine operations and maintenance. (2) Existing Oil and Gas Location shall means an oil and gas location, excluding roads, pipelines, and gathering lines, permitted or constructed prior to the later of May 1, 2009 for federal land or April 1, 2009 for all other land or the date that the oil and gas location becomes subject to Rule 317B by virtue of its proximity to a Classified Water Supply Segment. (3) New Oil and Gas Location shall means an oil and gas location, excluding roads, pipelines, and gathering lines, that is not an existing oil and gas location. (4) New Surface Disturbance shall means surface disturbance that expands the area of surface covered by an oil and gas location beyond that initially disturbed in the construction of the oil and gas location. (5) Non-Exempt Linear Feature shall means a road, or gathering line, or pipeline that is not necessary to cross a stream or connect or access a well or a gathering line. *** E&P WASTE MANAGEMENT (900 Series) 907. MANAGEMENT OF E&P WASTE *** f. Other E&P Waste. Other E&P waste such as workover fluids, tank bottoms, pigging wastes from pipelines gathering and flow lines, and natural gas gathering, processing, and storage wastes may be treated or disposed of as follows: (1) Disposal at a commercial solid waste disposal facility; (2) Treatment at a centralized E&P waste management facility permitted in accordance with Rule 908; (3) Injection into a Class II injection well permitted in accordance with Rule 325; or (4) An alternative method proposed in a waste management plan in accordance with rule 907.a.(3) and approved by the Director. Page 20 of 20