Current through Register Vol. 50, No. 9, September 20, 2024
A. Diverter System. A diverter system shall
be required when drilling surface hole in areas where drilling hazards are
known or anticipated to exist. The district manager may, at his discretion,
require the use of a diverter system on any well. In cases where it is
required, a diverter system consisting of a diverter sealing element, diverter
lines, and control systems must be designed, installed, used, maintained, and
tested to ensure proper diversion of gases, water, drilling fluids, and other
materials away from facilities and personnel. The diverter system shall be
designed to incorporate the following elements and characteristics:
1. dual diverter lines arranged to provide
for maximum diversion capability;
2. at least two diverter control stations.
One station shall be on the drilling floor. The other station shall be in a
readily accessible location away from the drilling floor;
3. remote-controlled valves in the diverter
lines. All valves in the diverter system shall be full-opening. Installation of
manual or butterfly valves in any part of the diverter system is
prohibited;
4. minimize the number
of turns in the diverter lines, maximize the radius of curvature of turns, and
minimize or eliminate all right angles and sharp turns;
5. anchor and support systems to prevent
whipping and vibration;
6. rigid
piping for diverter lines. The use of flexible hoses with integral end
couplings in lieu of rigid piping for diverter lines shall be approved by the
district manager.
B.
Diverter Testing Requirements
1. 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.
2.
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.
3. After nippling-up on
conductor casing, the diverter sealing element and diverter valves are to be
pressure tested to a minimum of 200 psig. Subsequent pressure tests are to be
conducted within seven days after the previous test.
4. Function tests and pressure tests shall be
alternated between control stations.
5. Recordkeeping Requirements
a. Pressure and function tests are to be
recorded in the driller's report and certified (signed and dated) by the
operator's representative.
b. The
control station used during a function or pressure test is to be recorded in
the driller's report.
c. Problems
or irregularities during the tests are to be recorded along with actions taken
to remedy same in the driller's report.
d. All reports pertaining to diverter
function and/or pressure tests are to be retained for inspection at the
wellsite for the duration of drilling operations.
C. BOP Systems. The operator shall
specify and insure that contractors design, install, use, maintain and test the
BOP system to ensure well control during drilling, workover and all other
appropriate operations. The surface BOP stack shall be installed before
drilling below surface casing. The BOP stack shall consist of the appropriate
number of ram-type preventers necessary to control the well under all potential
conditions that might occur during the operations being conducted. The pipe
rams shall be of proper size(s) to fit the drill pipe in use. The use of
annular-type preventers in conjunction with ram-type preventers is encouraged.
1. The requirements of LAC 43:XIX.111.C-I
shall not be applicable for wells drilled to or completed in the Nacatoch
Formation in the Caddo Pine Island field.
2. The commissioner of conservation,
following a public hearing, may grant exceptions to the requirements of LAC
43:XIX.111.C-I.
D. BOP
Working Pressure. The working pressure rating of any BOP component, excluding
annular-type preventers, shall exceed the maximum anticipated surface pressure
(MASP) to which it may be subjected.
E. BOP Auxiliary Equipment. All BOP systems
shall be equipped and provided with the following:
1. A hydraulically actuated accumulator
system which shall provide 1.5 times volume of fluid capacity to close and hold
closed all BOP components, with a minimum pressure of 200 psig above the
pre-charge pressure without assistance from a charging system.
2. A backup to the primary
accumulator-charging system, supplied by a power source independent from the
power source to the primary, which shall be sufficient to close all BOP
components and hold them closed.
3.
Accumulator regulators supplied by rig air without a secondary source of
pneumatic supply shall be equipped with manual overrides or other devices to
ensure capability of hydraulic operation if the rig air is lost.
4. At least one operable remote BOP control
station in addition to the one on the drilling floor. This control station
shall be in a readily accessible location away from the drilling floor. If a
BOP control station does not perform properly, operations shall be suspended
until that station is operable.
5.
A drilling spool with side outlets, if side outlets are not provided in the
body of the BOP stack, to provide for separate kill and choke lines.
6. Choke and kill lines each equipped with
two full-opening valves. At least one of the valves on the choke line and the
kill line shall be remotely controlled. In lieu of remotely controlled valves,
two readily-accessible manual valves may be installed provided that a check
valve is placed between the manual valves and the pump.
7. A valve installed below the swivel (upper
kelly cock), essentially full-opening, and a similar valve installed at the
bottom of the kelly (lower kelly cock). A wrench to fit each valve shall be
stored in a location readily accessible to the drilling crew.
8. An essentially full-opening drill-string
safety valve in the open position on the rig floor shall be available at all
times while drilling operations are being conducted. This valve shall be
maintained on the rig floor to fit all connections that are in the drill
string. A wrench to fit the drill-string safety valve shall be stored in a
location readily accessible to the drilling crew.
9. A safety valve shall be available on the
rig floor assembled with the proper connection to fit the casing string being
run in the hole.
10. Locking
devices installed on the ram-type preventers.
F. BOP Maintenance and Testing Requirements
1. The BOP system shall be visually inspected
on a daily basis.
2. Pressure tests
(low and high pressure) of the BOP system are to be conducted at the following
times and intervals:
a. during a shop test
prior to transport of the BOPs to the drilling location. Shop tests are not
required for equipment that is transported directly from one well location to
another;
b. immediately following
installation of the BOPs;
c. within
14 days of the previous BOP pressure test. Exceptions may be granted by the
district manager in cases where a trip is scheduled to occur within 2 days
after the 14-day testing deadline;
d. before drilling out each string of casing
or liner (The district manager may require that a conservation enforcement
specialist witness the test prior to drilling out each casing string or
liner);
e. Not more than 48 hours
before a well is drilled to a depth that is within 1000 feet of a hydrogen
sulfide zone (The district manager may require that a conservation enforcement
specialist witness the test prior to drilling to a depth that is within 1000
feet of a hydrogen sulfide zone);
f. when the BOP tests are postponed due to
well control problem(s), the BOP test is to be performed on the first trip out
of the hole, and reasons for postponing the testing are to be recorded in the
driller's report.
3. Low
pressure tests (200-300 psig) of the BOP system (choke manifold, kelly valves,
drill-string safety valves, etc.) are to be performed at the times and
intervals specified in LAC 43:XIX.111.F.2. in accordance with the following
provisions.
a. Test pressures are to be held
for a minimum of five minutes.
b.
Variable bore pipe rams are to be tested against the largest and smallest sizes
of pipe in use, excluding drill collars and bottom hole assembly.
c. Bonnet seals are to be tested before
running the casing when casing rams are installed in the BOP stack.
4. High pressure tests of the BOP
system are to be performed at the times and intervals specified in LAC
43:XIX.111.F.2 in accordance with the following provisions.
a. Test pressures are to be held for a
minimum of five minutes.
b.
Ram-type BOP's, choke manifolds, and associated equipment are to be tested to
the rated working pressure of the equipment or 500 psi greater than the
calculated MASP for the applicable section of the hole.
c. Annular-type BOPs are to be tested to 70%
of the rated working pressure of the equipment.
5. The annular and ram-type BOPs with the
exception of the blind-shear rams are to be function tested every seven days
between pressure tests. All BOP test records should be certified (signed and
dated) by the operator's representative.
a.
Blind-shear rams are to be tested at all casing points and at an interval not
to exceed 30 days.
G. BOP Record Keeping. The time, date and
results of pressure tests, function tests, and inspections of the BOP system
are to be recorded in the driller's report and are to be retained for
inspection at the wellsite for the duration of drilling operations.
H. BOP Well Control Drills. Weekly well
control drills with each drilling crew are to be conducted during a period of
activity that minimizes the risk to drilling operations. The drills must cover
a range of drilling operations, including drilling with a diverter (if
applicable), on-bottom drilling, and tripping. Each drill must be recorded in
the driller's report and is to include the time required to close the BOP
system, as well as, the total time to complete the entire drill.
I. Well Control Safety Training. In order to
ensure that all drilling personnel understand and can properly perform their
duties prior to drilling wells which are subject to the jurisdiction of the
Office of Conservation, the operator shall require that contract drilling
companies provide and/or implement the following:
1. periodic training for drilling contractor
employees which ensures that employees maintain an understanding of, and
competency in, well control practices;
2. procedures to verify adequate retention of
the knowledge and skills that the contract drilling employees need to perform
their assigned well control duties.
AUTHORITY NOTE:
Promulgated in accordance with
R.S.
30:4 et
seq.
