2 Colo. Code Regs. § 404-1-603

Current through Register Vol. 47, No. 19, October 10, 2024

Section 2 CCR 404-1-603 - OPERATIONAL AND SAFETY REQUIREMENTS

a.Blowout Prevention Equipment ("BOPE"). The Operator will take all necessary precautions for keeping a Well under control during drilling, deepening, re-entering, recompleting, workovers, or plugging. The Operator will indicate the BOPE, if any, on the Form 2, Application for Permit to Drill, as well as any known subsurface conditions (e.g., under- or over-pressured formations). The Operator will ensure the working pressure of any BOPE exceeds the anticipated surface pressure to which it may be subjected, assuming a partially evacuated hole with a pressure gradient of 0.22 pounds per square inch ("psi") per foot.

(1) The Commission may designate specific areas, Fields, or formations as requiring certain BOPE. Any such proposed designation will occur by notice describing the area, Field, or formation in question and will be given to all Operators of record within such area or Field and by publication. The proposed designation, if no protest is timely filed, will be placed on the Commission consent agenda for its next regularly scheduled meeting. The matter will be approved or heard by the Commission pursuant to Rule 519. Such designation will be effective immediately upon approval by the Commission, except as to any previously approved Form 2. If a protest is timely filed, the designation will be heard by the Commission pursuant to the Commission's 500 Series Rules.

(2) Pursuant to this Rule 603.a, the Director may condition the approval of any Form 2 by requiring BOPE which the Director determines to be necessary for keeping the Well under control. Should the Operator object to such condition of approval, the Commission will hear the matter at the next regularly scheduled meeting of the Commission, subject to the notice requirements of Rule 504.

b.Rig Floor Safety Valve Requirements. During drilling or Well servicing operations there will be on the rig floor a safety valve with connections suitable for use with each size and type of tool joint or coupling being used on the job.

c.Well Servicing Operations.

(1)Pressure Check Requirements. Prior to commencing Well servicing operations, the Well will be checked for pressure and steps taken to remove pressure or to ensure that operations may be safely conducted under pressure.

(2)BOPE.

A. Adequate BOPE equipment will be used on all Well servicing operations.

B. Backup stabbing valves will be required on Well servicing operations during reverse circulation. Valves will be pressure tested before each Well servicing operation using low-pressure air or Fluid or high-pressure Fluid.

(3) All Well servicing operations will be conducted in accordance with American Petroleum Institute ("API") Recommended Practice ("RP") 54, Occupational Safety and Health for Oil and Gas Well Drilling and Servicing Operations, Third Edition Reaffirmed, January 2013. Only the Third Edition of API's RP 54 applies to this Rule; later amendments do not apply. All materials incorporated by reference in this Rule 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, CO 80203. In addition, these materials are available from API, 1220 L Street, NW, Washington, DC 20005-4070.

(4) An Operator will:

A. Design drilling Fluid in conjunction with operating procedures and surface equipment to prevent the blowout of any Well until the Well has been placed into production;

B. Maintain adequate supplies of drilling Fluid of sufficient weight and other acceptable characteristics;

C. Perform drilling Fluid tests as necessary to ensure Well control;

D. Maintain adequate drilling Fluid testing equipment on the location at all times;

E. Monitor wellbore Fluid levels to ensure Well control at all times, including when running or pulling pipe;

F. Monitor mud Pit levels visually or mechanically during the drilling process; and

G. Install and operate mud-gas separation equipment as necessary.

(5) The Director will have access to the drilling Fluid records related to the Fluid's properties used to control the Well (Fluid type, density, viscosity, Fluid loss control, and other rheological properties), and will be allowed to request or conduct any essential tests on the drilling Fluid used in the drilling or recompletion of a Well. The Operator will retain all records for a period of 5 years.

(6) When the conditions and tests indicate a need for a change in the drilling Fluid program in order to ensure control of the Well, the Operator will use due diligence in modifying the program.

(7) An Operator will maintain Well control using BOPE systems and/or diverter systems for Wells drilled with air, nitrogen, or foam.

(8) The Operator will install BOPE when there is any indication that a Well will flow, either through prior records, present Well conditions, or the planned Well work, or special orders of the Commission.

(9) When required, BOPE will be in accordance with API Standard 53: "Well Control Equipment Systems for Drilling Wells," 5th Edition (December 2018). Only the 5th Edition of API Standard 53 applies to this Rule; later amendments do not apply. All materials incorporated by reference in this Rule 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, CO 80203. In addition, these materials are available from API, 1220 L Street, NW, Washington, DC 20005-4070.

(10) Drilling after setting the surface casing will not proceed until BOPE is tested and found to be serviceable. Low pressure and high pressure tests will be performed. Test pressure, test duration, and test frequency will be in accordance with API Standard 53: "Well Control Equipment Systems for Drilling Wells," 5th Edition (December 2018), as incorporated by reference in Rule 603.c.(9), except that the minimum low pressure for a low pressure test will be 250 psi. Test pressure loss will be less than or equal to 10% of the initial stabilized surface pressure at the end of the test when testing with rig pumps against casing. When a test plug is used to isolate the casing from the BOPE being tested, then there will be no unexplainable pressure loss at the end of the test.

(11) While in service, BOPE will be inspected daily and a preventer operating test will be performed on each round trip, but not more than once every 24 hour period. Notation of operating tests will be made on the daily report.

(12) All pipe fittings, valves, and unions placed on or connected with BOPE, well casing, wellhead, drill pipe, or tubing will have a working pressure rating suitable for the maximum anticipated surface pressure and will be in good working condition as per generally accepted industry standards. The Operator will equip wellhead assemblies to monitor pressure-containing annuli at surface, unless exempted by the Director.

(13) BOPE will include pipe rams, blind rams, annular preventer, or other equipment that enable closure on the pipe being used. The choke line(s) and kill line(s) will be anchored, tied, or otherwise secured to prevent whipping resulting from pressure surges.

(14) The Operator will inspect and service the wellhead, tree, and related surface control equipment to maintain pressure control throughout the life of the Well.

(15) The Operator will conduct pressure testing of the casing string pursuant to Rule 408.

(16) An Operator will complete a formation integrity test ("FIT") after drilling out below the surface casing shoe and any intermediate casing shoes for a minimum of 1 Well on each Oil and Gas Location if:

A. The fracture gradient of the formation at the casing shoe is unknown; or

B. The test is necessary to demonstrate:

i. The casing shoe integrity is sufficient to contain the anticipated wellbore pressures of the penetrated formations;

ii. Flow paths to the formations above the casing shoe do not exist; or

iii. The casing shoe is competent to handle an influx of formation Fluid or gas.

C. An Operator will submit a plan to the Director for approval if the FIT does not demonstrate the requirements of Rule 603.c.(16).B.

D. The Operator will perform the FIT before drilling 20 feet or less of new hole, unless otherwise ordered by the Commission.

(17) If the blind rams are closed for any purpose except operational testing, the valves on the choke lines or relief lines below the blind rams should be opened prior to opening the rams to bleed off any pressure.

(18) BOPE for drilling operations will consist of (at a minimum):

A.Rig with Kelly. Double ram with blind ram and pipe ram; annular preventer or a rotating head.

B.Rig Without Kelly. Double ram with blind ram and pipe ram.

C.Trained Personnel.

i. During drilling operations there will be at least 2 persons at the Well Site that have successfully completed an International Association of Drilling Contractors certified Well control training, or have completed a Director-approved BOPE training.

ii. All rig employees will have adequate understanding of and be able to operate the BOPE system. New employees will be trained in the operation of BOPE systems.

(19)BOPE Testing for Drilling Operations. Upon initial rig-up and at least once every 30 days during drilling operations thereafter, pressure testing of the casing string and each component of the BOPE including flange connections will be performed to 70% of working pressure or 70% of the internal yield of casing, whichever is less. Pressure testing will be conducted and the documented results will be retained by the Operator for inspection by the Director for a period of 1 year. Activation of the pipe rams for function testing will be conducted on a daily basis when practicable.

d.Well Consolidation. Where necessary and reasonable, Operators will consolidate new Wells to create multi-Well pads, including shared locations with other Operators to protect and minimize adverse impacts to public health, safety, welfare, the environment, and wildlife resources.

e.Development from Existing Oil and Gas Locations. Where possible, Operators will develop multiple reservoirs by drilling from existing Oil and Gas Locations or by multiple completions or commingling in existing wellbores.

f.Pit Level Indicators. Pit level indicators will be used for mud Tanks and Drilling Pits.

g.Drill Stem Tests. Closed chamber drill stem tests will be allowed. All other drill stem tests require Director approval.

h.Fencing Requirements. Unless otherwise requested by the Surface Owner, Oil and Gas Locations or Oil and Gas Facilities will be adequately fenced to restrict access by unauthorized persons, if determined necessary by the Director. However, all pumps and Pits will be adequately fenced to prevent access by unauthorized persons.

i.Loadlines. All loadlines will be bullplugged or capped.

j.Guy Line Anchors. All guy line anchors left buried for future use will be identified by a marker of bright color not less than 4 feet in height and not greater than 1 foot east of the guy line anchor.

k.Tank Specifications. All newly installed or replaced crude oil and condensate storage Tanks will be designed, constructed, and maintained pursuant to the National Fire Protection Association ("NFPA") Code 30, Flammable and Combustible Liquids Code (2018 version). The Operator will maintain written records verifying proper design, construction, and maintenance, and will make these records available for inspection by the Director. Only the 2018 version of NFPA Code 30 applies to this Rule; later amendments do not apply. All materials incorporated by reference in this Rule are available for public inspections during normal business hours from the Public Room Administrator at the office of the Commission, 1120 Lincoln Street, Suite 801, Denver, CO 80203. In addition, these materials are available from the NFPA, 1 Batterymarch Park, Quincy, MA, 02169-7471.

l.Access Roads. At the time of construction, all leasehold roads will be constructed to accommodate all weather access by local emergency vehicles, and will be maintained in a stable condition.

m.Well Site Cleared. Within 90 days after a Well is Plugged and Abandoned, the Well Site will be cleared of all non-essential equipment, trash, and debris. For good cause shown, a reasonable extension of time may be granted by the Director. The Operator will request prior approval for this extension on a Form 4, Sundry Notice.

n.Identification of Plugged and Abandoned Wells. The Operator will identify the location of the wellbore with a permanent monument pursuant to Rule 434.a.(5).

o.Secondary Containment. Operators will design, construct, and maintain secondary containment devices around new and significantly modified crude oil, condensate, and produced water storage Tanks.

(1) Operators will design secondary containment structures to be sufficiently sized to contain at least 150% of the volume of the largest single Tank within the containment.

(2) Operators will construct secondary containment of steel, or other engineered material, designed and installed to prevent leakage and resist degradation from erosion or routine operation.

(3) To prevent leakage, Operators will line secondary containment areas with an impervious synthetic or engineered liner that underlays all primary containment vessels including partially buried vessels. The liner will be sufficiently impervious so that any discharge from a primary containment system will not escape containment before cleanup occurs. The liner will be attached to secondary containment and any equipment penetrating the liner will have a sealed connection.

(4) Secondary containment will prevent Spills or Releases from primary containment vessels, process vessels, or pipelines from migrating horizontally or vertically prior to clean-up.

(5) For locations within 500 feet and upgradient of a surface water body or wetland, tertiary containment, such as a compacted earthen berm, is required around Production Facilities.

(6) No potential ignition sources, aside from fired vessels ("FV"), will be installed inside the secondary containment area. Any electrical equipment installations inside the bermed area will comply with API RP 500, Recommended Practice for Classification of Locations for Electrical Installations at Petroleum Facilities classified as Class I, Division I and Division 2, 3rd Edition (including January 2014 errata), and the current national electrical code as adopted by the State of Colorado. Only the 3rd edition (including January 2014 errata) of API RP 500 applies to this Rule; later amendments do not apply. The materials incorporated by reference in this Rule 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, CO 80203. In addition, these materials are available from API, 1220 L Street NW, Washington, DC 20005-4070, and from the Department of Regulatory Agencies, Colorado Electrical Board, 1560 Broadway, Suite 110, Denver, CO 80202.

2 CCR 404-1-603

37 CR 16, August 25, 2014, effective 9/30/2014

38 CR 01, January 10, 2015, effective 2/14/2015

38 CR 03, February 10, 2015, effective 3/2/2015

38 CR 07, April 10, 2015, effective 4/30/2015

38 CR 16, August 25, 2015, effective 9/14/2015

39 CR 04, February 25, 2016, effective 3/16/2016

41 CR 05, March 10, 2018, effective 4/1/2018

41 CR 06, March 25, 2018, effective 5/1/2018

41 CR 23, December 10, 2018, effective 12/30/2018

42 CR 02, January 25, 2019, effective 2/14/2019

42 CR 17, September 10, 2019, effective 9/30/2019

42 CR 24, December 25, 2019, effective 1/14/2020

43 CR 17, September 10, 2020, effective 9/30/2020

43 CR 13, July 10, 2020, effective 11/2/2020

43 CR 24, December 25, 2020, effective 1/15/2021

45 CR 07, April 10, 2022, effective 4/30/2022

45 CR 09, May 10, 2022, effective 5/30/2022

45 CR 13, July 10, 2022, effective 7/30/2022