| (v) as otherwise approved by the district director.
(D) Casing shall be cemented across and above all productive
zones, potential flow zones, and/or zones with corrosive formation
fluids, as follows:
(i) if the top of cement is determined through calculation,
across and extending at least 600 feet (measured depth) above the
zones;
(ii) if the top of cement is determined through the
performance of a temperature survey, across and extending 250 feet
(measured depth) above the zones;
(iii) if the top of cement is determined through the
performance of a cement evaluation log, across and extending 100 feet
(measured depth) above the zones;
(iv) across and extending at least 200 feet into the
previous casing shoe (or to the surface if the shoe is less than 200
feet from the surface); or
(v) as otherwise approved by the district director.
(E) Where necessary, the cement slurry shall be designed
to control annular gas migration consistent with, or equivalent to,
the standards in API Standard 65-Part 2: Isolating Potential Flow
Zones During Well Construction.
(5) Casing testing before drillout. For surface and
intermediate strings of casing, before drilling the cement plug, the
operator shall test the casing at a pump pressure in pounds per square
inch (psi) calculated by multiplying the length of the true vertical
depth in feet of the casing string by a factor of 0.5 psi per foot.
The maximum test pressure required, however, unless otherwise ordered
by the Commission, need not exceed 1,500 psi. If, at the end of 30
minutes, the pressure shows a drop of 10% or more from the original
test pressure, the casing shall be condemned until the leak is corrected.
A pressure test demonstrating less than a 10% pressure drop after
30 minutes constitutes confirmation that the condition has been corrected.
The operator shall notify the district director of a failed test.
In the event of a pressure test failure, completion operations may
not re-commence until the district director approves a remediation
plan, the operator successfully implements the plan, and the operator
conducts a successful pressure test.
(6) Well control.
(A) Wellhead assemblies. After setting the conductor
pipe on offshore wells or surface casing on land or bay wells, wellhead
assemblies shall be used on wells to maintain surface control of the
well at all times. Each component of the wellhead shall have a pressure
rating equal to or greater than the anticipated pressure to which
that particular component might be exposed during the course of drilling,
testing, or producing the well.
(B) Well control equipment.
(i) An operator shall install a blowout preventer system
or control head and other connections to keep the well under control
at all times as soon as surface casing is set. When conductor casing
is set and/or shallow gas is anticipated to be encountered, operators
shall install a diverter system on the conductor casing. For bay and
offshore wells, at a minimum, such systems shall include a double
ram blowout preventer, including pipe and blind rams, an annular-type
blowout preventer or other equivalent control system, and a shear
ram.
(ii) For wells in areas with hydrogen sulfide, the
operator shall comply with §3.36 of this title (relating to Oil,
Gas, or Geothermal Resource Operation in Hydrogen Sulfide Areas).
(iii) Ram type blowout prevention equipment shall have
a rated working pressure that equals or exceeds the maximum anticipated
surface pressure of the well. Blowout preventer rams shall be of a
proper size for the drill pipe being used or production casing being
run in the well or shall be variable-type rams that are in the appropriate
size range. Alternatively, an annular preventer may be used in lieu
of casing/pipe rams or variable bore rams when running production
casing provided the expected shut-in surface pressures would not exceed
the tested pressure rating of the annular preventer.
(iv) Operators shall install a drill pipe safety valve
to prevent backflow of water, oil, gas, or other formation fluids
into the drill string.
(v) Operators shall install a choke line of sufficient
size and working pressure.
(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.
Cont'd... |
