(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
use.
(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
surface casing.
(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
upon request.
(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
depth.
(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.
(E) Casinghead.
(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
determined.
(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
recompleted.
(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 Cont'd... |