Current through Register Vol. 47, No. 17, September 10, 2024
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.
