| (vi) When using a Kelly rig during drilling, the well
shall be fitted with an upper Kelly cock in proper working order to
close in the drill string below hose and swivel, when necessary for
well control. A lower Kelly safety valve shall be installed so that
it can be run through the blowout preventer. When needed for well
control, the operator shall maintain at all times on the rig floor
safety valves to include:
(I) full-opening safety valve; and
(II) inside blowout preventer valve with wrenches,
handling tools, and necessary subs for all drilling pipe sizes in
(vii) All control equipment shall be consistent with
API Standard 53: Recommended Practices for Blowout Prevention Equipment
Systems for Drilling Wells. Control equipment shall be certified in
accordance with API Standard 53 as operable under the product manufacturer's
minimum operational specifications. Certification shall include the
proper operation of the closing unit valving, the pressure gauges,
and the manufacturer's recommended accumulator fluids. Certification
shall be obtained through an independent company that tests blowout
preventers, stacks and casings. Certification shall be performed every
five (5) years and the proof of certification shall be made available
upon request of the Commission.
(viii) All well control equipment shall be in good
working condition at all times. All outlets, fittings, and connections
on the casing, blowout preventers, choke manifold, and auxiliary wellhead
equipment that may be subjected to wellhead pressure shall be of a
material and construction to withstand or exceed the anticipated pressure.
The lines from outlets on or below the blowout preventers shall be
securely installed, anchored, and protected from damage.
(ix) In addition to the primary closing system, including
an accumulator system, the blowout preventers shall have a secondary
location for closure.
(x) Testing of blowout prevention equipment.
(I) Ram type blowout prevention equipment shall be
tested to at least the maximum anticipated surface pressure of the
well, but not less than 1,500 psi, before drilling the plug on the
(II) Blowout prevention equipment shall be tested upon
installation, after the disconnection or repair of any pressure containment
seal in the blowout preventer stack, choke line, or choke manifold,
limited to the affected component, with testing to occur at least
every 21 days. When requested, the district director shall be notified
before the commencement of a test.
(III) A record of each test, including test pressures,
times, failures, and each mechanical test of the casings, blowout
preventers, surface connections, surface fittings, and auxiliary wellhead
equipment shall be entered in the logbook, signed by the person responsible
for the test, and made available for inspection by the Commission
(C) Drilling fluid program.
(i) The characteristics, use, and testing of drilling
fluid and conduct of related drilling procedures shall be designed
to prevent the blowout of any well. Adequate supplies of drilling
fluid of sufficient weight and other acceptable characteristics shall
be maintained. Drilling fluid tests shall be performed as needed to
ensure well control. Adequate drilling fluid testing equipment shall
be kept on the drilling location at all times. Sufficient drilling
fluid shall be pumped and maintained to ensure well control at all
times, including when pulling drill pipe. Mud pit levels shall be
visually or mechanically monitored during the drilling process. Mud-gas
separation equipment shall be installed and operated as needed when
abnormally pressured gas-bearing formations may be encountered. The
Commission shall have access to the drilling fluid records and shall
be allowed to conduct any essential tests on the drilling fluid used
in the drilling or recompletion of a well. When the conditions and
tests indicate a need for a change in the drilling fluid program in
order to insure control of the well, the operator shall use due diligence
in modifying the program.
(ii) Wells drilled with air shall maintain well control
using blowout preventer systems and/or diverter systems.
(iii) All hole intervals drilled prior to reaching
the base of protected water shall be drilled with air, fresh water
or a fresh water based drilling fluid. No oil-based drilling fluid
may be used until casing has been set and cemented to the protection
(D) Diverter systems for bay and offshore wells. Any
bay or offshore well that is drilled to and/or through formations
where the expected reservoir pressure exceeds the hydrostatic pressure
of the drilling fluid column shall be equipped to divert any wellbore
fluids away from the rig floor. When the diverter system is installed,
the diverter components including the sealing element, diverter valves,
control systems, stations and vent lines shall be function and pressure
tested. For drilling operations with a surface wellhead configuration,
the system shall be function tested at least once every 24-hour period
after the initial test. After all connections have been made on the
surface casing or conductor casing, the diverter sealing element and
diverter valves shall be pressure tested to a minimum of 200 psig.
Subsequent pressure tests shall be conducted within seven days after
the previous test. All diverter systems shall be maintained in working
condition. No operator shall continue drilling operations if a test
or other information indicates that the diverter system is unable
to function or operate as designed.
(i) Requirements. All land and bay wells shall be equipped
with casingheads of sufficient rated working pressure, with adequate
connections and valves accessible at the surface, to allow pumping
of fluid between any two strings of casing at the surface.
(ii) Casinghead test procedure. Any well showing sustained
pressure on the casinghead, or leaking gas or oil between the surface
casing and the next casing string, shall be tested in the following
manner. The well shall be killed with water or mud and pump pressure
applied. The casing shall be condemned if the pressure gauge on the
casinghead reflects the applied pressure. After completing corrective
measures, the casing shall be tested in the same manner. This method
shall be used when the origin of the pressure cannot otherwise be
(F) Christmas tree.
(i) All completed non-pumping wells shall be equipped
with Christmas tree fittings and wellhead connections with a rated
working pressure equal to, or greater than, the surface shut-in pressure
of the well. The tubing shall be equipped with a master valve, but
two master valves shall be used on all wells with surface pressures
in excess of 5,000 psi. All wellhead connections shall be assembled
and tested prior to installation by a fluid pressure equal to the
test pressure of the fitting employed.
(ii) The Christmas tree for completed bay and offshore
wells shall be equipped with either two master valves, one master
valve and one wing valve, or two wing valves. All bay and offshore
wells shall have at least five feet of spacing between the bottom
of the Christmas tree and the surface of the water at high tide, where
applicable. Any newly completed bay and offshore well or existing
well on which the Christmas tree is being replaced shall be equipped
with a back pressure valve wellhead profile at the flange where the
tubing hangs on the Christmas tree.
(G) Storm choke and safety valve.
(i) Bay and offshore wells shall be equipped with a
storm choke and/or safety valve installed in the tubing.
(ii) An operator may request approval to use a surface
safety valve in lieu of a subsurface safety valve by filing with the
appropriate district director a written request for such approval
providing all pertinent information to support the exception.
(iii) The depth and type of the safety valve shall
be reported in the "remarks" section of the appropriate completion
report form required by §3.16 of this title (relating to Log
and Completion or Plugging Report), after the well is completed or
(7) Additional requirements for wells on which hydraulic
fracturing treatments will be conducted.
(A) All casing strings or fracture tubing installed
in a well that will be subjected to hydraulic fracturing treatments
shall have a minimum internal yield pressure rating of at least 1.10
times the maximum pressure to which the casing strings or fracture
tubing may be subjected.
(B) The operator shall pressure test the casing (or
fracture tubing) on which the pressure will be exerted during hydraulic
fracturing treatments to at least the maximum pressure allowed by
the completion method. Casing strings that include a pressure actuated
valve or sleeve shall be tested to 80 percent of actuation pressure
for a minimum time period of five (5) minutes. A surface pressure
loss of greater than 10 percent of the initial test pressure is considered
a failed test. The casing required to be pressure tested shall be
from the wellhead to at least the depth of the top of cement behind
the casing being tested. The district director shall be notified of
a failed test within 24 hours of completion of the test. In the event
of a pressure test failure, no hydraulic fracturing treatment may
be conducted until the district director has approved a remediation
plan, and the operator has implemented the approved remediation plan
and successfully re-tested the casing (or fracture tubing).
(C) During hydraulic fracturing treatment operations,
the operator shall monitor all annuli. The operator shall immediately
suspend hydraulic fracturing treatment operations if the pressures
deviates above those anticipated increases caused by pressure or thermal
transfer and shall notify the appropriate district director within
24 hours of such deviation. Further completion operations, including
hydraulic fracturing treatment operations, may not recommence until
the district director approves a remediation plan and the operator
successfully implements the approved plan.
(D) The following conditions also apply if the well
is a minimum separation well, unless otherwise approved by the director:
(i) Cementing of the production casing in a minimum
separation well shall be by the pump and plug method. The production
casing shall be cemented from the shoe up to a point at least 200
feet (measured depth) above the shoe of the next shallower casing
string that was set and cemented in the well (or to surface if the
shoe is less than 200 feet from the surface).
(ii) The operator shall pressure test the casing string
on which the pressure will be exerted during stimulation to the maximum
pressure that will be exerted during hydraulic fracturing treatment.
The operator shall notify the district director within 24 hours of
a failed test. No hydraulic fracturing treatment may be conducted
until the district director has approved a remediation plan, and the
operator has implemented the approved remediation plan and successfully
re-tested the casing (or fracture tubing).
(iii) The production casing for any minimum separation
well shall not be disturbed for a minimum of eight hours after cement
is in place and casing is hung-off, and in no case shall the casing
be disturbed until the cement has reached a minimum compressive strength
of 500 psi.
(iv) In addition to conducting an evaluation of cementing
records and annular pressure monitoring results, the operator of a
minimum separation well shall run a cement evaluation tool to assess
radial cement integrity and placement behind the production casing.
If the cement evaluation indicates insufficient isolation, completion
operations may not re-commence until the district director approves
a remediation plan and the operator successfully implements the approved
(v) The operator of a minimum separation well may request
from the appropriate district director approval of an exemption from
the requirement to run a cement evaluation tool. Such request shall
include information demonstrating that the operator has:
(I) successfully set, cemented, and tested the casing
for which the exemption is requested in at least five minimum separation
wells by the same operator in the same operating field;
(II) obtained cement evaluation tool logs that support
the findings of cementing records, annular pressure monitoring results
or other tests demonstrating that successful cement placement was
achieved to isolate productive zones, potential flow zones, and/or
zones with corrosive formation fluids; and
(III) shown that the well for which the exemption is
requested will be constructed and cemented using the same or similar
techniques, methods, and cement formulation used in the five wells
that have had successful cement jobs.
(8) Pipeline shut-off valves for bay and offshore wells.
All bay and offshore gathering pipelines designed to transport oil,
gas, condensate, or other oil or geothermal resource field fluids
from a well or platform shall be equipped with automatically controlled
shut-off valves at critical points in the pipeline system. Other safety
equipment shall be in full working order as a safeguard against spillage
from pipeline ruptures.