(a) When drilling in areas where high
pressures are likely to exist, as determined by the department, all proper and
necessary precautions must be taken for keeping the well under control,
including, but not limited to, the use of blowout preventers and high-pressure
fittings attached to casing strings properly anchored and cemented:
(A) The Blowout Prevention Equipment
schematic diagram must indicate the minimum size and pressure rating of all
components of the wellhead and blowout preventer assembly;
(B) The department, on a site-specific basis,
may require the use of blowout preventers or other methods of controlling
shallow coal bed methane wells;
(C)
All blowout preventers, choke lines, and choke manifolds must be installed
above ground level. Casing heads and optional spools may be installed below
ground level provided they are visible and accessible;
(D) Blowout preventer equipment and related
casing heads and spools must have a vertical bore no smaller than the inside
diameter of the casing to which they are attached;
(E) All ram blowout preventers must be
equipped with hydraulic locking devices and manual locking devices with hand
wheels extending outside of the rig's substructure;
(F) Blowout prevention equipment installed on
the well must have a rated expected formation pressure higher than the working
pressure;
(G) In addition to the
minimum blowout preventer requirements outlined in this section, wells drilled
while using tapered drill strings must use either a variable bore pipe ram
preventer or additional ram type blowout preventers to provide a minimum of one
set of pipe rams for each size of drill pipe in use, and one set of blind
rams.
(b) Unless
otherwise approved by the department, the blowout prevention equipment must
include a minimum of at least one annular blowout preventer and one double-gate
preventer with pipe and blind rams or two single-ram type preventers; one
equipped with pipe rams and the other with blind rams. Ram preventers or a
drilling spool must have side outlets with a minimum inside diameter of 2
inches on the kill side, and 3 inches on the choke side to accommodate choke
and kill lines. Outlets on the casing head may not be used to attach choke or
kill lines;
(A) Additional blowout preventer
equipment includes, but is not limited to, one upper kelly cock, and one drill
pipe safety valve with subs to fit all drill string connections in
use;
(B) Choke manifold and related
equipment consists of one kill line valve, one check valve, two choke line
valves, choke line, two manual adjustable chokes (each with one valve located
upstream of the choke), one bleed line valve, and one mud service pressure
gauge with a valve upstream of the gauge;
(C) All choke manifold valves, choke and kill
line valves, and the choke line must be full bore. Choke line valves, choke
line, and bleed line valves must have an inside diameter equal to or greater
than the minimum requirement for the blowout preventer or drilling spool
outlet;
(D) The choke line must be
as straight as possible, and any required turns must be made with flow targets
at all bends and on block tees. All connections exposed to well bore pressure
must be welded, flanged, or clamped. Choke hoses with flanged connections
designed for that purpose will be accepted in lieu of a steel choke line. The
choke line must be securely anchored;
(E) The accumulator must have sufficient
capacity to operate the blowout preventer equipment as outlined in this
section, and have two independently powered pump systems connected to start
automatically after a 200 psi drop in accumulator pressure, or one
independently powered pump system connected to start automatically after a 200
psi drop in accumulator pressure and an emergency nitrogen back-up system
connected to the accumulator manifold. Blowout preventer controls may be
located at the accumulator or on the rig floor;
(F) A hydraulically operated accumulator;
and
(c) Minimum requirements for
blowout preventer equipment testing:
(A) All
blowout preventers and related equipment that may be exposed to well pressure
must be tested first to a low pressure and then to a high pressure;
(i) A stable low of 200-300 psi must be
maintained for at least 30 minutes prior to initiating the high-pressure
test;
(ii) The high-pressure test
must be to the rated working pressure of the ram type blowout preventer
equipment and related equipment, or to the rated working pressure of the
wellhead on which the stack is installed, whichever is lower. A stable
high-pressure test must be maintained for 30 minutes;
(iii) Annular blowout preventer must be
high-pressure tested to 50 percent of the rated working pressure and maintain a
stable pressure for 30 minutes; and
(iv) Manual adjustable chokes not designed
for complete shutoff must be pressure tested only to the extent of determining
the integrity of the internal seating components to maintain back pressure.
Hydraulic chokes designed for complete shutoff must be pressure tested to 50
percent of the rated working pressure.
(B) All casing below the conductor pipe must
be pressure tested to 0.22 psi per foot or 1,500 psi, whichever is greater, but
not to exceed 70 percent of the minimum internal yield strength of the casing.
A stable pressure must be maintained for 30 minutes. Higher pressures, using a
test plug in the casing head, may be required by the department on a
case-by-case basis;
(C) During
blowout preventer pressure testing the casing must be isolated with a test plug
set in the wellhead, and the appropriate valve must be opened below the test
plug to detect any leakage that may occur due to failure of the test
plug;
(D) The choke and kill line
valves, choke manifold valves, upper and lower kelly cocks, drill pipe safety
valves, and inside blowout preventer must be tested with pressure applied from
the wellbore side. All valves, including check valves, located downstream of
the valve being pressure tested, will be in the open position;
(E) Manually operated valves and chokes on
the blowout preventer stack, choke and kill lines, or choke manifold must be
equipped with a handle provided by the manufacturer, or a functionally
equivalent fabricated handle, and be lubricated and maintained to permit
operation of the valves without the use of additional wrenches or
levers;
(F) All operational
components of the blowout preventer equipment must be function tested at least
once a week to verify the components' intended operations;
(G) The blowout prevention equipment must be
pressure tested when installed, prior to drilling out casing shoes, and
following repairs or reassembly of the preventers that require disconnecting a
pressure seal in the assembly;
(H)
During drilling operations, blowout prevention equipment must be actuated to
test proper functioning once each trip, or once each week, whichever is more
frequent;
(I) All flange bolts must
be inspected at least weekly and retightened as necessary during drilling
operations;
(J) The auxiliary
control systems must be maintained in working order and be inspected daily to
check the mechanical condition and effectiveness and to ensure personnel at the
site are familiar with their operation;
(K) A blowout prevention practice drill must
be conducted weekly for each drilling crew, and be recorded on the driller's
log;
(L) The results of all blowout
preventer equipment pressure tests and function tests must be recorded on the
tour sheet and include the type of test, testing sequence, low and high
pressures, duration of each test, and results of each test;
(M) All blowout preventer equipment test
results submitted to the department must have a signed certification stating
that the testing procedures of the blowout preventer equipment and the passing
results are accurate and comply with OAR 632-010-0014;
(N) The department may require any blowout
preventer equipment test to be conducted or witnessed by an independent third
party that will report all test results to the department for review and
approval prior to commencement of drilling operations;
(O) All tool pushers, drilling
superintendents, and permittees' representatives (when the permittee is in
control of the drilling) are required to have completed an API, IADC, or
similar governing body sanction well control certification program and furnish
the certification of satisfactory of completion to the department prior to the
start of any drilling operations. The certification must be renewed every two
years.