Current through Register Vol. 63, No. 12, December 1, 2024
(1)
Cementing of Casing. All casing strings must be cemented with a quantity of
cement sufficient to fill the annular space back to the surface.
(a) The intermediate casing string must be
cemented to fill the annular space back to the surface unless otherwise
approved by the department.
(b)
Casing must be:
(A) Cemented with a high
temperature resistant cement, unless waived by the department and must be
cemented in a manner necessary to exclude, isolate, or segregate overlying
formation fluids from the geothermal resources zone and to prevent the movement
of fluids into possible fresh water zones; and
(B) Cemented back to the surface or to the
top of the inner casing. A temperature or cement bond log may be required by
the department after setting and cementing the production casing and after all
primary cementing operations if an unsatisfactory cementing job is
indicated.
(c) Proposed
well cementing techniques differing from the requirements of this paragraph
will be considered by the department on an individual well basis.
(2) Pressure 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:
(A) A
pressure decline of 10 percent or less in 30 minutes is for the low pressure
test considered satisfactory prior to initiating the high-pressure
test;
(B) When performing the
low-pressure test, it is not acceptable to apply a higher pressure and bleed
down to the low test pressure;
(C)
The high-pressure test must be to the rated working pressure of the ram type
blowout prevention equipment and related equipment, or to the rated working
pressure of the wellhead on which the stack is installed, whichever is lower. A
pressure decline of 10 percent or less in 30 minutes is considered
satisfactory;
(D) Annular blowout
prevention equipment must be high-pressure tested to 50 percent of the rated
working pressure;
(E) Manual
adjustable chokes not designed for complete shut off (CSO) must be pressure
tested only to the extent of determining the integrity of the internal seating
components to maintain back pressure; and
(F) Hydraulic chokes designed for CSO 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. 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 prevention equipment
pressure testing, the casing must be isolated with a test plug set in the
wellhead and the appropriate valve 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 prevention equipment 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 prevention equipment, 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 prevention 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. The auxiliary control systems must be maintained in working order
and inspected daily to check the mechanical condition and effectiveness and to
insure personnel acquaintance with their operation. A blowout prevention
practice drill must be conducted weekly for each drilling crew and be recorded
on the driller's log.
(j) The
results of all blowout prevention 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.
(k) 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.
(l) The department may
require that any blowout prevention equipment test results submitted to the
department have a signed affidavit stating that the testing procedures of the
blowout prevention equipment and the passing results are accurate and complies
with OAR 632-010-0014.
(m) The
department may require that all blowout prevention equipment tests be conducted
and 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.
(n) In the event of
casing failure during the test, the casing must be repaired or recemented until
a satisfactory test is obtained. A pressure decline of 10 percent or less in 30
minutes is considered satisfactory. The department may require an affidavit
signed by the operator or contractor conducting the pressure test certifying
that a satisfactory pressure test has been obtained.
(o) Casing test results must be recorded in
the driller's log and reported to the department within 60 days after
completion. The casing and lap test reports must give a detailed description of
the test including mud and cement volumes, lapse of time between running and
cementing casing and testing, method of testing, and test results.
(3) Blowout Prevention Equipment
and Procedures. The operator must use all necessary precautions to keep all
wells under control and use trained and competent personnel and properly
maintained equipment and materials at all times. Blowout preventers and related
well control equipment must be installed, tested immediately after installation
using water, and maintained ready for use until drilling operations are
completed. Certain components, such as packing elements and ram rubbers, must
be of high-temperature resistant material as necessary. All kill lines,
blowdown lines, manifolds, and fittings must be steel and have a temperature
derated minimum working pressure rating equivalent to the maximum anticipated
wellhead surface pressure. Subject to subsections (a) and (b) of this section,
blowout prevention equipment must have hydraulic actuating systems and
accumulators of sufficient capacity to close all of the hydraulically operated
equipment and have a minimum pressure of 1,000 psi remaining on the
accumulator. The department may approve manually operated blowout preventers.
Dual control stations must be installed with a high-pressure backup system. One
control panel must be located on the ground at least 50 feet away from the
wellhead or rotary table. Air or other gaseous fluid drilling systems must have
blowout prevention assemblies. Such assemblies may include, but are not limited
to, a rotating head, a double ram blowout preventer or equivalent, a banjo-box
or an approved substitute thereof and a blind ram blowout preventer or gate
valve, below the banjo-box. Exceptions to the requirements of this paragraph
will be considered by the department on a case-by-case basis. Approved
exceptions may include certain geologic and well conditions, such as stable
surface areas with known low subsurface formation pressures and temperatures.
(a) Conductor Casing. In certain instances, a
remotely controlled hydraulically operated expansion type preventer or an
acceptable alternative, approved by the department, including a drilling spool
with side outlets or equivalent may be required by the department in areas
where shallow thermal zones are indicated.
(b) Surface, Intermediate, and Production
Casing. Before drilling below any of these strings, the blowout prevention
equipment must include a minimum of the following, unless otherwise approved by
the department:
(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) Install all blowout preventers, choke
lines, and choke manifolds above ground level. Casing heads and optional spools
may be installed below ground level, provided they are visible and
accessible;
(C) 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;
(D) All ram blowout
prevention equipment must be equipped with hydraulic locking devices and manual
locking devices with hand wheels extending outside of the rig's
substructure;
(E) Blowout
prevention equipment installed on the well must have a rated working pressure
equal to or higher than, the working pressure;
(F) Wells drilled while using tapered drill
strings must be equipped with 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;
(G) Blowout prevention equipment must consist
of at least one expansion-type preventer and a rotating head. Additional
blowout prevention equipment may be required by the department based on
site-specific well safety needs. Ram blowout prevention equipment or a drilling
spool must have side outlets with a minimum inside diameter of two inches on
the kill side, and three inches on the choke side to accommodate choke and kill
lines. Outlets on the casing head may not be used to attach the choke or kill
lines;
(H) Additional blowout
prevention equipment must include, 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;
(I) Choke manifold and
related equipment must consist 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;
(J) 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 prevention equipment or drilling spool
outlet;
(K) The choke line should
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;
(L) The accumulator must have sufficient
capacity to operate the blowout prevention 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 prevention equipment controls
may be located at the accumulator or on the rig floor; and
(M) The drilling fluids containment system
must have a functional mud pit horn.
(c) Testing and Maintenance.
(A) Ram type blowout preventers and auxiliary
equipment must be tested to a minimum of 1,000 psi, 1.5 psi per foot of casing,
or to the working pressure of the casing or assembly, whichever is the lesser.
Expansion type blowout preventers must be tested to 70 percent of the above
pressure testing requirements. The blowout prevention equipment must be
pressure tested:
(ii) Prior to drilling out plugs or casing
shoes or both; and
(iii) Following
repairs that require disconnecting a pressure seal in the assembly.
(B) During drilling operations,
blowout prevention equipment must be actuated to test proper functioning as
follows: once each trip for blind and pipe rams but not less than once each day
for pipe rams; and at least once each week on the drill pipe for expansion type
preventers.
(C) All flange bolts
must be inspected at least weekly and retightened as necessary during drilling
operations. The auxiliary control systems must be inspected daily to check the
mechanical condition and effectiveness and to ensure personnel's acquaintance
with the method of operation. Blowout prevention and auxiliary control
equipment must be cleaned, inspected, and repaired, if necessary, prior to
installation to ensure proper functioning. Blowout prevention controls must be
plainly labeled, and all crewmembers must be instructed on the function and
operation of the equipment. A blowout prevention drill must be conducted weekly
for each drilling crew. All blowout prevention tests and crew drills must be
recorded on the driller's log.
(4) Related Well Control Equipment. A full
opening drill string safety valve in the open position must be maintained on
the rig floor at all times while drilling operations are being conducted. A
kelly cock must be installed between the kelly and the swivel.
(5) Drilling Fluid. The properties, use, and
testing of drilling fluids and the conduct of related drilling procedures must
be sufficient to prevent the blowout of any well. Sufficient drilling fluid
materials to ensure well control must be maintained on site and readily
accessible for use at all times.
(6) Drilling Fluid Control. Before pulling
drill pipe, the drilling fluid must be properly conditioned or displaced. The
hole must be kept reasonably full at all times; however, in no event will the
annular mud level be deeper than 100 feet from the rotary table when coming out
of the hole with drill pipe. Mud cooling techniques must be utilized when
necessary to maintain mud characteristics for proper well control and hole
conditioning. The department may require the use of mud cooling
equipment.
(7) Drilling Fluid
Testing:
(a) Mud testing and treatment
consistent with good operating practice must be performed daily or more
frequently as conditions warrant. Mud testing equipment must be maintained on
the drilling rig at all times; and
(b) The following mud drilling fluid system
monitoring or recording devices must be installed and operated continuously
during drilling operations occurring below the shoe of the conductor casing. No
exceptions to these requirements will be allowed without the specific prior
approval of the department:
(A) High-low level
mud pit indicator including a visual and audio-warning device;
(B) Degassers, desilters, and
desanders;
(C) A mechanical,
electrical, or manual surface drilling fluid temperature monitoring device. The
temperature of the drilling fluid going into and coming out of the hole must be
monitored, read, and recorded on the driller's or mud log for a minimum of
every 30 feet of hole drilled below the conductor casing; and
(D) A hydrogen sulfide indicator and alarm
must be installed in areas suspected or known to contain hydrogen sulfide gas
that may reach levels considered dangerous to the health and safety of
personnel in the area.
(8) Well-head Equipment and Testing:
(a) Completions. All wellhead connections
must be fluid pressure tested to the API or ASA working pressure rating. Cold
water is required as the testing fluid, unless otherwise approved by the
department at the time of permitting. Welding of wellhead connections must be
performed by a certified welder using materials in conformance with ASTM
specifications; and
(b) Well-head
Equipment. All completed wells must be equipped with a minimum of one
casinghead with side outlets, one master valve, and one production valve,
unless otherwise approved by the department. All casingheads, Christmas trees,
fittings, and connections must have a temperature derated working pressure
equal to or greater than the surface shut-in pressure of the well at reservoir
temperature. Packing, sealing mediums and lubricants must consist of materials
or substances that function effectively at, and are resistant to, high
temperatures. Wellhead equipment, valves, flanges, and fittings must meet
minimum ASA standards or minimum API Standard 6A specifications. Casinghead
connections must be made such that fluid can be pumped between casing
strings.
(9)
Supervision. From the time drilling operations are initiated and until the well
is completed or decommissioned, a member of the drilling crew or the toolpusher
must monitor the rig floor at all times for surveillance purposes, unless the
well is secured with blowout preventers or cement plugs.
Stat. Auth.: ORS 522
Stats. Implemented: ORS
522.155 &
522.305