| (a) General. Operators shall comply with this section
for any wells that will be spudded on or after January 1, 2014.
(1) Intent. The operator is responsible for compliance
with this section during all operations at the well. It is the intent
of all provisions of this section that casing be securely anchored
in the hole in order to effectively control the well at all times,
all usable-quality water zones be isolated and sealed off to effectively
prevent contamination or harm, and all productive zones, potential
flow zones, and zones with corrosive formation fluids be isolated
and sealed off to prevent vertical migration of fluids, including
gases, behind the casing. When the section does not detail specific
methods to achieve these objectives, the responsible party shall make
every effort to follow the intent of the section, using good engineering
practices and the best currently available technology. In accordance
with §3.17 of this title (relating to Pressure on Bradenhead),
operators must notify the Commission of bradenhead pressure. The Commission
will evaluate notices of bradenhead pressure on a case-by-case basis
to determine further action and will provide guidance to assist operators
in wellbore evaluation.
(2) Definitions. The following words and terms, when
used in this section, shall have the following meanings, unless the
context clearly indicates otherwise.
(A) Stand under pressure--To leave the hydrostatic
column pressure in the well acting as the natural force without adding
any external pump pressure. The provisions are complied with if a
float collar and/or float shoe is used and found to be holding at
the completion of the cement job.
(B) Zone of critical cement--
(i) For surface casing strings, the bottom 20% of the
casing string, but no more than 1,000 feet nor less than 300 feet.
The zone of critical cement extends to the land surface for surface
casing strings of 300 feet or less.
(ii) For intermediate or production casing strings,
the bottom 20% of the casing string or 300 vertical feet above the
casing shoe or top of the highest proposed productive zone, whichever
is less.
(C) Protection depth--Depth to which usable-quality
water must be protected, as determined by the Groundwater Advisory
Unit of the Oil and Gas Division, which may include zones that contain
brackish or saltwater if such zones are correlative and/or hydrologically
connected to zones that contain usable-quality water.
(D) Productive zone--Any stratum known to contain oil,
gas, or geothermal resources in commercial quantities in the area.
(E) Gas/oil contact zone--A zone in an oil well in
which natural gas, commonly known as gas cap gas, overlies and is
in contact with crude oil in a reservoir.
(F) Bay well--Any well under the jurisdiction of the
Commission as defined in §3.78(a)(5) of this chapter.
(G) Deputy director of Field Operations--The deputy
director of Field Operations of the Oil and Gas Division or the deputy
director's delegate.
(H) Director--The director of the Oil and Gas Division
of the Railroad Commission of Texas or the director's delegate.
(I) District director--The Director of a Railroad Commission
district office or the district director's delegate.
(J) Hydraulic fracturing treatment--A completion process
involving treatment of a well by the application of hydraulic fracturing
fluid under pressure for the express purpose of initiating or propagating
fractures in a target geologic formation to enhance production of
oil and/or natural gas. The term does not include acid treatment,
perforation, or other non-fracture treatment completion activities.
(K) Land well--Any well subject to Commission jurisdiction
as defined in §3.78(a)(6) of this chapter.
(L) Minimum separation well--A well in which hydraulic
fracturing treatments will be conducted and for which:
(i) the vertical distance between the base of usable
quality water and the top of the formation to be stimulated is less
than 1,000 vertical feet;
(ii) the director has determined contains inadequate
separation between the base of usable quality water and the top of
the formation in which hydraulic fracturing treatments will be conducted;
or
(iii) the director has determined is in a structurally
complex geologic setting.
(M) Offshore well--Any well subject to Commission jurisdiction
as defined by §3.78(a)(7).
(N) Potential flow zone--A zone designated by the director
or identified by the operator using available data that needs to be
isolated to prevent sustained pressurization of the surface casing/intermediate
casing or production casing annulus sufficient to cause damage to
casing and/or cement in a well such that it presents a threat to subsurface
water or oil, gas, or geothermal resources. The Commission will maintain
a list of known zones by district and county that are considered potential
flow zones and make this information available to all operators. The
Commission will revise this list as necessary based on information
provided, or otherwise made available, to the Commission.
(O) Zone with corrosive formation fluids--Any zone
designated by the director or identified by the operator using available
data containing formation fluids that are capable of negatively impacting
the integrity of casing and/or cement or have a demonstrated trend
of failure for similar casing and cement design in the field. The
Commission will maintain a list of known zones by district and county
that are considered zones with corrosive formation fluids, and make
this information available to all operators. The Commission will revise
this list as necessary based on information provided, or otherwise
made available, to the Commission.
(P) Usable quality water--Water as defined in §3.30(e)(7)(B)(i)
of this title (relating to Memorandum of Understanding between the
Railroad Commission of Texas (RRC) and the Texas Commission on Environmental
Quality (TCEQ)).
(3) Wellbore diameters.
(A) The diameter of the wellbore in which surface casing
will be set and cemented shall be at least one and one-half (1.50)
inches greater than the nominal outside diameter of casing to be installed,
unless otherwise approved by the district director.
(B) For subsequent casing strings, the diameter of
each section of the wellbore for which casing will be set and cemented
shall be at least one (1) inch greater than the nominal outside diameter
of the casing to be installed, unless otherwise approved by the district
director. The district director may grant such approvals on an area
basis.
(C) The casing diameter requirements in subparagraphs
(A) and (B) of this paragraph do not apply to reentries, liners, and
expandable casing.
(D) All float equipment, centralizers, packers, cement
baskets, and all other equipment run into the wellbore on casing shall
be consistent with the manufacturer's recommendations.
(4) Casing and cementing.
(A) All casing cemented in any well shall be steel
casing that has been hydrostatically pressure tested with an applied
pressure at least equal to the maximum pressure to which the pipe
will be subjected in the well. For new pipe, the mill test pressure
may be used to fulfill this requirement. As an alternative to hydrostatic
testing, a casing evaluation tool may be employed. Casing meeting
the performance standards set forth in API Specification 5CT: Specification
for Casing and Tubing (or a Commission-approved equivalent standard)
shall be used through the protection depth.
(B) The base cement shall meet the standards set forth
in API Specification 10A: Specification for Cement and Material for
Well Cementing or the American Society for Testing and Materials (ASTM)
Specification C150/C150M, Standard Specification for Portland Cement
(or a Commission-approved equivalent standard).
(C) Casing shall be cemented across and above all formations
permitted for injection under §3.9 of this title (relating to
Disposal Wells) at the time the well is completed, or cemented immediately
above all formations permitted for injection under §3.46 of this
title (relating to Fluid Injection into Productive Reservoirs) at
the time the well is completed, in a well within one-quarter mile
of the proposed well location, as follows:
(i) if the top of cement is determined through calculation,
at least 600 feet (measured depth) above the permitted formations;
(ii) if the top of cement is determined through the
performance of a temperature survey conducted immediately after cementing,
250 feet (measured depth) above the permitted formations;
(iii) if the top of cement is determined through the
performance of a cement evaluation log, 100 feet (measured depth)
above the permitted formations;
(iv) at least 200 feet into the previous casing shoe
(or to surface if the shoe is less than 200 feet from the surface);
or
(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.
Cont'd... |
