| (A) Centralizers. In deviated and horizontal holes,
the operator shall provide centralization as necessary to ensure zonal
isolation between the top of the interval to be completed and the
shallower zones that require isolation.
(B) Cementing method. The production string of casing
shall be cemented by the pump and plug method, or another method approved
by the Commission, with sufficient cement to fill the annular space
back of the casing to the surface or to a point at least 600 feet
above the shoe. If any productive zone, potential flow zone and/or
zone with corrosive formation fluids is open to the wellbore above
the casing shoe, the casing shall be cemented in a manner that effectively
seals off all such zones by one of the methods specified for intermediate
casing in paragraph (2) of this subsection. A float collar or other
means to stop the cement plug shall be inserted in the casing string
above the shoe. Cement shall be allowed to stand under pressure for
a minimum of eight hours before drilling the plug or initiating casing
pressure tests. In the event that the distance from the casing shoe
to the top of the shallowest productive zone, potential flow zone
and/or zone with corrosive formation fluids make cementing, as required
above, impossible or impractical, the multi-stage process may be used
to cement the casing in a manner that will effectively seal off all
such zones, and prevent fluid migration to or from such zones within
the wellbore. Uncemented casing is allowable within a producing reservoir
provided the production casing is cemented in such a manner to effectively
isolate and seal off that zone from all other productive zones in
the wellbore as required by §3.7 of this title (relating to Strata
To Be Sealed Off).
(C) Reporting of top of cement. Calculated or measured
top of cement shall be indicated on the appropriate completion form
required by §3.16 of this title.
(D) Isolation of gas/oil contact zones. The position
of the gas-oil contact shall be determined by coring, electric log,
or testing. The producing string shall be landed and cemented below
the gas-oil contact, or set completely through and perforated in the
oil-saturated portion of the reservoir below the gas-oil contact.
(4) Tubing requirements for land wells and bay wells.
(A) Tubing requirements for oil wells. All flowing
oil wells shall be equipped with and produced through tubing. When
tubing is run inside casing in any flowing oil well, the bottom of
the tubing shall be at a point not higher than 100 feet (vertical
depth) above the top of the producing interval nor more than 50 feet
(vertical depth) above the top of the liner, if a liner is used, or
100 feet (vertical depth) above the kickoff point in a deviated or
horizontal well. In a multiple zone structure, however, when an operator
elects to equip a well in such a manner that small through-the-tubing
type tools may be used to perforate, complete, plug back, or recomplete
without the necessity of removing the installed tubing, the bottom
of the tubing may be set at a distance up to, but not exceeding, 1,000
feet (vertical depth) above the top of the perforated or open-hole
interval actually open for production into the wellbore.
(B) Alternate tubing requirements. Alternate programs
requesting a temporary exception pursuant to subsection (d) of this
section to omit tubing from a flowing oil well may be authorized on
an individual well basis by the appropriate district director. The
district director shall deny the request if the operator has not demonstrated
that the alternative tubing plan will achieve the intent as described
in subsection (a)(1) of this section. If the proposal is rejected,
the operator may request a review by the director of field operations.
If the proposal is not approved administratively, the operator may
request a hearing. An operator shall obtain approval of any alternative
program before commencing operations.
(c) Casing, cementing, drilling, and completion requirements
for offshore wells.
(1) Casing. An offshore well shall be cased with at
least three strings of pipe, in addition to such drive pipe as the
operator may desire, which shall be set in accordance with the following
program.
(A) Conductor casing. A string of new pipe, or reconditioned
pipe with substantially the same characteristics as new pipe, shall
be set and cemented at a depth of not less than 300 feet TVD (true
vertical depth) nor more than 800 feet TVD below the mud line. Sufficient
cement shall be used to fill the annular space back of the pipe to
the mud line; however, cement may be washed out or displaced to a
maximum depth of 50 feet below the mud line to facilitate pipe removal
on abandonment. Casing shall be set and cemented in all cases prior
to penetration of known shallow oil and gas formations, or upon encountering
such formations.
(B) Surface casing. All surface casing shall be a string
of new pipe with a mill test of at least 1,100 pounds per square inch
(psi) or reconditioned pipe that has been tested to an equal pressure.
Sufficient cement shall be used to fill the annular space behind the
pipe to the mud line; however, cement may be washed out or displaced
to a maximum depth of 50 feet below the mud line to facilitate pipe
removal on abandonment. Surface casing shall be set and cemented in
all cases prior to penetration of known shallow oil and gas formations,
or upon encountering such formations. In all cases, surface casing
shall be set prior to drilling below 3,500 feet TVD. Minimum depths
for surface casing are as follows.
(i) Surface Casing Depth Table.
Attached Graphic
(ii) Surface Casing test.
(I) Cement shall be allowed to stand under pressure
for a minimum of eight hours before drilling plug or initiating tests.
Casing shall be tested by pump pressure to at least 1,000 psi. If,
at the end of 30 minutes, the pressure shows a drop of 100 psi or
more, the casing shall be condemned until the leak is corrected. A
pressure test demonstrating a drop of less than 100 psi after 30 minutes
constitutes confirmation that the condition has been corrected.
(II) After drillout, if the surface casing is exposed
to more than 360 rotating hours, the operator shall verify the integrity
of the casing using a casing evaluation tool, a mechanical integrity
test, or an equivalent Commission-approved alternate casing evaluation
methodology, unless otherwise approved by the district director.
(III) If a mechanical integrity test of the surface
casing is conducted, the appropriate district office shall be notified
a minimum of eight (8) hours before the test is conducted. The operator
shall use a chart of acceptable range (20% - 80% of full scale) or
an electronic equivalent approved by the district director, and the
surface casing shall be tested at a minimum test pressure of 0.5 psi
per foot multiplied by the true vertical depth of the surface casing
up to a maximum of 1,500 psi for a minimum of 30 minutes. A pressure
test demonstrating less than a 10% drop in pressure after 30 minutes
constitutes confirmation of an acceptable pressure test. The operator
shall notify the appropriate district office within 24 hours of a
failed test. Operations may not re-commence until the district director
approves a remediation plan and the operator implements the approved
plan, and the operator successfully re-tests the surface casing.
(C) Production casing or oil string.
(i) The production casing or oil string shall be new
or reconditioned pipe with a mill test of at least 2,000 psi that
has been tested to an equal pressure.
(ii) After cementing, the production casing shall be
tested by pump pressure to at least 1,500 psi. If, at the end of 30
minutes, the pressure shows a drop of 150 psi or more, the casing
shall be condemned. After corrective operations, the casing shall
again be tested in the same manner.
(iii) Cementing of the production casing shall be by
the pump and plug method. Sufficient cement shall be used to fill
the calculated annular space above the shoe to isolate any productive
zones, potential flow zones, or zones with corrosive formation fluids
and to a depth that isolates abnormal pressure from normal pressure
(0.465 psi per vertical foot of gradient). A float collar or other
means to stop the cement plug shall be inserted in the casing string
above the shoe. Cement shall be allowed to stand under pressure for
a minimum of eight hours before drilling the plug or initiating tests.
(2) Operators shall comply with the well control requirements
of subsection (a)(6) of this section.
(d) Exceptions or alternate programs. The director
may administratively grant an exception or approve an alternate casing/tubing
program required by this section provided that the alternate casing/tubing
program will achieve the intent of the rule as described in subsection
(a)(1) of this section and the following requirements are met:
(1) The request for an exception or alternate casing/tubing
program shall be accompanied by the fee required by §3.78(b)(5)
of this title (relating to Fees and Financial Security Requirements).
(2) An administrative exception for tubing shall not
exceed a period of 180 days. A request for an exception for tubing
beyond 180 days shall require a Commission order.
|
| Source Note: The provisions of this §3.13 adopted to be effective January 1, 1976; amended to be effective April 8, 1980, 5 TexReg 1152; amended to be effective October 3, 1980, 5 TexReg 3794; amended to be effective January 1, 1983, 7 TexReg 3982; amended to be effective March 10, 1986, 11 TexReg 901; amended to be effective January 11, 1991, 16 TexReg 39; amended to be effective August 13, 1991, 16 TexReg 4153; amended to be effective August 25, 2003, 28 TexReg 6816; amended to be effective January 1, 2014, 38 TexReg 3542 |
