Texas Administrative Code
Title 16 - ECONOMIC REGULATION
Part 1 - RAILROAD COMMISSION OF TEXAS
Chapter 3 - OIL AND GAS DIVISION
Section 3.13 - Casing, Cementing, Drilling, Well Control, and Completion Requirements
Universal Citation: 16 TX Admin Code § 3.13
Current through Reg. 50, No. 13; March 28, 2025
(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, brine, 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, Brine, 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.
(vi) When using a Kelly
rig during drilling, the well shall be fitted with an upper Kelly cock in
proper working order to close in the drill string below hose and swivel, when
necessary for well control. A lower Kelly safety valve shall be installed so
that it can be run through the blowout preventer. When needed for well control,
the operator shall maintain at all times on the rig floor safety valves to
include:
(I) full-opening safety valve;
and
(II) inside blowout preventer
valve with wrenches, handling tools, and necessary subs for all drilling pipe
sizes in use.
(vii) All
control equipment shall be consistent with API Standard 53: Recommended
Practices for Blowout Prevention Equipment Systems for Drilling Wells. Control
equipment shall be certified in accordance with API Standard 53 as operable
under the product manufacturer's minimum operational specifications.
Certification shall include the proper operation of the closing unit valving,
the pressure gauges, and the manufacturer's recommended accumulator fluids.
Certification shall be obtained through an independent company that tests
blowout preventers, stacks and casings. Certification shall be performed every
five (5) years and the proof of certification shall be made available upon
request of the Commission.
(viii)
All well control equipment shall be in good working condition at all times. All
outlets, fittings, and connections on the casing, blowout preventers, choke
manifold, and auxiliary wellhead equipment that may be subjected to wellhead
pressure shall be of a material and construction to withstand or exceed the
anticipated pressure. The lines from outlets on or below the blowout preventers
shall be securely installed, anchored, and protected from damage.
(ix) In addition to the primary closing
system, including an accumulator system, the blowout preventers shall have a
secondary location for closure.
(x)
Testing of blowout prevention equipment.
(I)
Ram type blowout prevention equipment shall be tested to at least the maximum
anticipated surface pressure of the well, but not less than 1,500 psi, before
drilling the plug on the surface casing.
(II) Blowout prevention equipment shall be
tested upon installation, after the disconnection or repair of any pressure
containment seal in the blowout preventer stack, choke line, or choke manifold,
limited to the affected component, with testing to occur at least every 21
days. When requested, the district director shall be notified before the
commencement of a test.
(III) A
record of each test, including test pressures, times, failures, and each
mechanical test of the casings, blowout preventers, surface connections,
surface fittings, and auxiliary wellhead equipment shall be entered in the
logbook, signed by the person responsible for the test, and made available for
inspection by the Commission upon request.
(C) Drilling fluid program.
(i) The characteristics, use, and testing of
drilling fluid and conduct of related drilling procedures shall be designed to
prevent the blowout of any well. Adequate supplies of drilling fluid of
sufficient weight and other acceptable characteristics shall be maintained.
Drilling fluid tests shall be performed as needed to ensure well control.
Adequate drilling fluid testing equipment shall be kept on the drilling
location at all times. Sufficient drilling fluid shall be pumped and maintained
to ensure well control at all times, including when pulling drill pipe. Mud pit
levels shall be visually or mechanically monitored during the drilling process.
Mud-gas separation equipment shall be installed and operated as needed when
abnormally pressured gas-bearing formations may be encountered. The Commission
shall have access to the drilling fluid records and shall be allowed to conduct
any essential tests on the drilling fluid used in the drilling or recompletion
of a well. When the conditions and tests indicate a need for a change in the
drilling fluid program in order to insure control of the well, the operator
shall use due diligence in modifying the program.
(ii) Wells drilled with air shall maintain
well control using blowout preventer systems and/or diverter systems.
(iii) All hole intervals drilled prior to
reaching the base of protected water shall be drilled with air, fresh water or
a fresh water based drilling fluid. No oil-based drilling fluid may be used
until casing has been set and cemented to the protection
depth.
(D) Diverter
systems for bay and offshore wells. Any bay or offshore well that is drilled to
and/or through formations where the expected reservoir pressure exceeds the
hydrostatic pressure of the drilling fluid column shall be equipped to divert
any wellbore fluids away from the rig floor. 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. 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. After all connections have been made on the surface casing or
conductor casing, the diverter sealing element and diverter valves shall be
pressure tested to a minimum of 200 psig. Subsequent pressure tests shall be
conducted within seven days after the previous test. All diverter systems shall
be maintained in working condition. No operator shall continue drilling
operations if a test or other information indicates that the diverter system is
unable to function or operate as designed.
(E) Casinghead.
(i) Requirements. All land and bay wells
shall be equipped with casingheads of sufficient rated working pressure, with
adequate connections and valves accessible at the surface, to allow pumping of
fluid between any two strings of casing at the surface.
(ii) Casinghead test procedure. Any well
showing sustained pressure on the casinghead, or leaking gas or oil between the
surface casing and the next casing string, shall be tested in the following
manner. The well shall be killed with water or mud and pump pressure applied.
The casing shall be condemned if the pressure gauge on the casinghead reflects
the applied pressure. After completing corrective measures, the casing shall be
tested in the same manner. This method shall be used when the origin of the
pressure cannot otherwise be determined.
(F) Christmas tree.
(i) All completed non-pumping wells shall be
equipped with Christmas tree fittings and wellhead connections with a rated
working pressure equal to, or greater than, the surface shut-in pressure of the
well. The tubing shall be equipped with a master valve, but two master valves
shall be used on all wells with surface pressures in excess of 5,000 psi. All
wellhead connections shall be assembled and tested prior to installation by a
fluid pressure equal to the test pressure of the fitting employed.
(ii) The Christmas tree for completed bay and
offshore wells shall be equipped with either two master valves, one master
valve and one wing valve, or two wing valves. All bay and offshore wells shall
have at least five feet of spacing between the bottom of the Christmas tree and
the surface of the water at high tide, where applicable. Any newly completed
bay and offshore well or existing well on which the Christmas tree is being
replaced shall be equipped with a back pressure valve wellhead profile at the
flange where the tubing hangs on the Christmas tree.
(G) Storm choke and safety valve.
(i) Bay and offshore wells shall be equipped
with a storm choke and/or safety valve installed in the tubing.
(ii) An operator may request approval to use
a surface safety valve in lieu of a subsurface safety valve by filing with the
appropriate district director a written request for such approval providing all
pertinent information to support the exception.
(iii) The depth and type of the safety valve
shall be reported in the "remarks" section of the appropriate completion report
form required by §
3.16 of this title (relating to
Log and Completion or Plugging Report), after the well is completed or
recompleted.
(7) Additional requirements for wells on
which hydraulic fracturing treatments will be conducted.
(A) All casing strings or fracture tubing
installed in a well that will be subjected to hydraulic fracturing treatments
shall have a minimum internal yield pressure rating of at least 1.10 times the
maximum pressure to which the casing strings or fracture tubing may be
subjected.
(B) The operator shall
pressure test the casing (or fracture tubing) on which the pressure will be
exerted during hydraulic fracturing treatments to at least the maximum pressure
allowed by the completion method. Casing strings that include a pressure
actuated valve or sleeve shall be tested to 80 percent of actuation pressure
for a minimum time period of five (5) minutes. A surface pressure loss of
greater than 10 percent of the initial test pressure is considered a failed
test. The casing required to be pressure tested shall be from the wellhead to
at least the depth of the top of cement behind the casing being tested. The
district director shall be notified of a failed test within 24 hours of
completion of the test. In the event of a pressure test failure, no hydraulic
fracturing treatment may be conducted until the district director has approved
a remediation plan, and the operator has implemented the approved remediation
plan and successfully re-tested the casing (or fracture tubing).
(C) During hydraulic fracturing treatment
operations, the operator shall monitor all annuli. The operator shall
immediately suspend hydraulic fracturing treatment operations if the pressures
deviates above those anticipated increases caused by pressure or thermal
transfer and shall notify the appropriate district director within 24 hours of
such deviation. Further completion operations, including hydraulic fracturing
treatment operations, may not recommence until the district director approves a
remediation plan and the operator successfully implements the approved plan.
(D) The following conditions also
apply if the well is a minimum separation well, unless otherwise approved by
the director:
(i) Cementing of the production
casing in a minimum separation well shall be by the pump and plug method. The
production casing shall be cemented from the shoe up to a point at least 200
feet (measured depth) above the shoe of the next shallower casing string that
was set and cemented in the well (or to surface if the shoe is less than 200
feet from the surface).
(ii) The
operator shall pressure test the casing string on which the pressure will be
exerted during stimulation to the maximum pressure that will be exerted during
hydraulic fracturing treatment. The operator shall notify the district director
within 24 hours of a failed test. No hydraulic fracturing treatment may be
conducted until the district director has approved a remediation plan, and the
operator has implemented the approved remediation plan and successfully
re-tested the casing (or fracture tubing).
(iii) The production casing for any minimum
separation well shall not be disturbed for a minimum of eight hours after
cement is in place and casing is hung-off, and in no case shall the casing be
disturbed until the cement has reached a minimum compressive strength of 500
psi.
(iv) In addition to conducting
an evaluation of cementing records and annular pressure monitoring results, the
operator of a minimum separation well shall run a cement evaluation tool to
assess radial cement integrity and placement behind the production casing. If
the cement evaluation indicates insufficient isolation, completion operations
may not re-commence until the district director approves a remediation plan and
the operator successfully implements the approved plan.
(v) The operator of a minimum separation well
may request from the appropriate district director approval of an exemption
from the requirement to run a cement evaluation tool. Such request shall
include information demonstrating that the operator has:
(I) successfully set, cemented, and tested
the casing for which the exemption is requested in at least five minimum
separation wells by the same operator in the same operating field;
(II) obtained cement evaluation tool logs
that support the findings of cementing records, annular pressure monitoring
results or other tests demonstrating that successful cement placement was
achieved to isolate productive zones, potential flow zones, and/or zones with
corrosive formation fluids; and
(III) shown that the well for which the
exemption is requested will be constructed and cemented using the same or
similar techniques, methods, and cement formulation used in the five wells that
have had successful cement jobs.
(8) Pipeline shut-off valves for bay and
offshore wells. All bay and offshore gathering pipelines designed to transport
oil, gas, condensate, or other oil or geothermal resource field fluids from a
well or platform shall be equipped with automatically controlled shut-off
valves at critical points in the pipeline system. Other safety equipment shall
be in full working order as a safeguard against spillage from pipeline
ruptures.
(9) Training for bay and
offshore wells. All tool pushers, drilling superintendents, and operators'
representatives (when the operator is in control of the drilling) shall be
required to, upon request, furnish certification of satisfactory completion of
an American Petroleum Institute (API) training program, an International
Association of Drilling Contractors (IADC) training program, or other
equivalent nationally recognized training program on well control equipment and
procedures. The certification shall be renewed every two years by attending an
API- or IADC-approved refresher course or a refresher course approved by the
equivalent nationally recognized training program.
(10) Bottom-hole pressure surveys. The
Commission may require bottom-hole pressure surveys of the various fields at
such times as determined to be necessary. However, operators shall be required
to take bottom-hole pressures only in those wells that are not likely to suffer
damaging effects from the survey. Tubing and tubingheads shall be free from
obstructions in wells used for bottom-hole pressure test purposes.
(b) Casing and cementing requirements for land wells and bay wells.
(1) Surface casing requirements for land
wells and bay wells.
(A) Any proposal to set
surface casing to a depth of 3,500 feet or greater shall require prior approval
of the appropriate district director. A request for such approval shall be in
writing and shall specify how the operator plans to maintain well control
during drilling, and ensure successful circulation and adequate bonding of
cement, and, if necessary, prevent upward migration of deeper formation fluids
into protected water. The district director may grant approvals on an area
basis.
(B) Amount required.
(i) An operator shall set and cement
sufficient surface casing to protect all usable-quality water strata, as
defined by the Groundwater Advisory Unit of the Oil and Gas Division. Unless
surface casing requirements are specified in field rules approved prior to the
effective date of this rule, before drilling any well, an operator shall obtain
a letter from the Groundwater Advisory Unit of the Oil and Gas Division stating
the protection depth. In no case, however, is surface casing to be set deeper
than 200 feet below the specified depth without prior approval from the
district director. The district director may grant such approval on an area
basis.
(ii) Any well drilled to a
total depth of 1,000 feet or less below the ground surface may be drilled
without setting surface casing provided no shallow gas sands or abnormally high
pressures are known to exist at depths shallower than 1,000 feet below the
ground surface; and further, provided that production casing is cemented from
the shoe to the ground surface by the pump and plug method.
(C) Cementing. Cementing shall be
by the pump and plug method. Sufficient cement shall be used to fill the
annular space outside the casing from the shoe to the ground surface or to the
bottom of the cellar. If cement does not circulate to ground surface or the
bottom of the cellar, the operator or the operator's representative shall
obtain the approval of the district director for the procedures to be used to
perform additional cementing operations, if needed, to cement surface casing
from the top of the cement to the ground surface.
(D) Cement quality.
(i) Surface casing strings must be allowed to
stand under pressure until the cement has reached a compressive strength of at
least 500 psi in the zone of critical cement before drilling plug or initiating
a test. The cement mixture in the zone of critical cement shall have a 72-hour
compressive strength of at least 1,200 psi.
(ii) An operator may use cement with volume
extenders above the zone of critical cement to cement the casing from that
point to the ground surface, but in no case shall the cement have a compressive
strength of less than 100 psi at the time of drill out nor less than 250 psi 24
hours after being placed.
(iii) In
addition to the minimum compressive strength of the cement, the free water
content shall be minimized to the greatest extent practicable in the cement
slurry to be used in the zone of critical cement. In no event shall the free
water separation average more than two milliliters per 250 milliliters of
cement tested in accordance with the current API RP 10B-2: Recommended Practice
for Testing Well Cements, inside the zone of critical cement, or more than six
milliliters per 250 milliliters of cement tested outside the zone of critical
cement.
(iv) The Commission may
require a better quality of cement mixture to be used in any well or any area
if conditions indicate that a better quality of cement is necessary to prevent
pollution, isolate productive zones, potential flow zones, or zones with
corrosive formation fluids or prevent a safety issue in the well.
(E) Compressive strength tests.
Cement mixtures for which published performance data are not available must be
tested by the operator or service company. Tests shall be made on
representative samples of the basic mixture of cement and additives used, using
distilled water or potable tap water for preparing the slurry. The tests must
be conducted using the equipment and procedures in, or equipment and procedures
equivalent to those in, API RP 10B-2, Recommended Practice for Testing Well
Cements. Test data showing competency of a proposed cement mixture to meet the
above requirements must be furnished to the Commission prior to the cementing
operation. To determine that the minimum compressive strength has been
obtained, operators shall use the typical performance data for the particular
cement used in the well (containing all the additives, including any
accelerators used in the slurry) at the following temperatures and at
atmospheric pressure.
(i) For the cement in
the zone of critical cement, the test temperature shall be within 10 degrees
Fahrenheit of the formation equilibrium temperature at the top of the zone of
critical cement.
(ii) For the
filler cement, the test temperature shall be the temperature found 100 feet
below the ground surface level, or 60 degrees Fahrenheit, whichever is greater.
(F) Cementing report.
Within 30 days of completion of the well, or within 90 days of cessation of
drilling operations, whichever is earlier, a cementing report must be filed
with the Commission furnishing complete data concerning the cementing of
surface casing in the well as specified on a form furnished by the Commission.
The operator of the well or the operator's duly authorized agent having
personal knowledge of the facts, and representatives of the cementing company
performing the cementing job, must sign the form attesting to compliance with
the cementing requirements of the Commission.
(G) Centralizers. Surface casing shall be
centralized at the shoe, above and below a stage collar or diverting tool, if
run, and through usable-quality water zones. In nondeviated holes, pipe
centralization as follows is required: a centralizer shall be placed every
fourth joint from the cement shoe to the ground surface or to the bottom of the
cellar. All centralizers shall meet specifications in, or equivalent to, API
spec 10D Specifications for Bow-Spring Casing Centralizers; API Spec 10 TR4,
Technical Report on Considerations Regarding Selection of Centralizers for
Primary Cementing Operations; and API RP 10D-2, Recommended Practice for
Centralizer Placement and Stop Collar Testing.
(H) Alternative surface casing programs.
(i) An alternative method of fresh water
protection may be approved upon written application to the appropriate district
director. The operator shall state the reason for the alternative fresh water
protection method and outline the alternate program for casing and cementing
through the protection depth for strata containing usable-quality water.
Alternative programs for setting more than specified amounts of surface casing
for well control purposes may be requested on a field or area basis.
Alternative programs for setting less than specified amounts of surface casing
will be considered on an individual well basis only. The district director may
approve, modify, or reject the proposed program. The district director shall
deny the request if the operator has not demonstrated that the alternative
casing plan will achieve the intent of this rule as described in subsection
(a)(1) of this section. If the proposal is modified or rejected, the operator
may request a review by the deputy director of field operations. If the
proposal is not approved administratively, the operator may request a public
hearing. An operator shall obtain approval of any alternative program before
commencing operations.
(ii) Any
alternate casing program shall require the first string of casing set through
the protection depth to be cemented in a manner that will effectively prevent
the migration of any fluid to or from any stratum exposed to the wellbore
outside this string of casing. The casing shall be cemented from the shoe to
ground surface in a single stage, if feasible, or by a multi-stage process with
the stage tool set at least 100 feet below the protection depth.
(iii) Any alternate casing program shall
include pumping sufficient cement to fill the annular space from the shoe or
multi-stage tool to the ground surface. If cement is not circulated to the
ground surface or the bottom of the cellar, the operator shall run a
temperature survey or cement bond log. The appropriate district office shall be
notified prior to running the required temperature survey or bond log. After
the top of cement outside the casing is determined, the operator or the
operator's representative shall contact the appropriate district director and
obtain approval for the procedures to be used to perform any required
additional cementing operations. Upon completion of the well, a cementing
report shall be filed with the Commission on the prescribed form.
(iv) Before parallel (nonconcentric) strings
of pipe are cemented in a well, surface or intermediate casing must be set and
cemented through the protection depth.
(I) Mechanical integrity test of surface
casing after drillout.
(i) If the surface
casing is exposed to more than 360 rotating hours after reaching total depth or
the depth of the next casing string, the operator shall verify the integrity of
the surface casing by using a casing evaluation tool or conducting a mechanical
integrity test or equivalent Commission-approved casing evaluation method,
unless otherwise approved by the district director.
(ii) If a mechanical integrity test is
conducted, the appropriate district office shall be notified at least eight
hours before the test is conducted to give the district office an opportunity
to witness the test. 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 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 up to a
maximum of 1,500 psi for a minimum of 30 minutes. A pressure test demonstrating
less than a 10% pressure drop after 30 minutes constitutes confirmation of an
acceptable pressure test. The appropriate district office shall be notified
within 24 hours after a failed test. Completion operations may not re-commence
until the district director approves a remediation plan and the operator
successfully implements the approved plan, and successfully re-tests the
surface casing.
(2) Intermediate casing requirements for land
wells and bay wells.
(A) Cementing method.
Each intermediate string of casing shall be cemented from the shoe to a point
at least 600 feet (measured depth) above the shoe. If any productive zone,
potential flow zone, or zone with corrosive formation fluids is open to the
wellbore above the casing shoe, the casing shall be cemented;
(i) if the top of cement is determined
through calculation, from the shoe up to a point at least 600 feet (measured
depth) above the top of the shallowest productive zone, potential flow zone, or
zone with corrosive formation fluids;
(ii) if the top of cement is determined
through performance of a temperature survey, from the shoe up to a point at
least 250 feet (measured depth) above the top of the shallowest productive
zone, potential flow zone, or zone with corrosive formation fluids;
(iii) if the top of cement is determined
through performance of a cement evaluation log, from the shoe up to a point at
least 100 feet (measured depth) above the top of the shallowest productive
zone, potential flow zone, or zone with corrosive formation fluid; or
(iv) to a point at least 200 feet
(measured depth) above the shoe of the next shallower casing string that was
set and cemented in the well (or to surface if the shoe is less than 200 feet
from the surface); or
(v) as
otherwise approved by the district director.
(B) Top of cement. The calculated or measured
top of cement shall be indicated on the appropriate completion form required by
§
3.16 of this title (relating to
Log and Completion or Plugging Report).
(C) Alternate method. In the event 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 specified above, impossible or impractical, the multi-stage
process may be used to cement the casing in a manner that will effectively
isolate and seal the zones to prevent fluid migration to or from such strata
within the wellbore.
(3)
Production casing requirements for land wells and bay wells.
(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.
(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.
This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the agency's legal authority.
Disclaimer: These regulations may not be the most recent version. Texas may have more current or accurate information. We make no warranties or guarantees about the accuracy, completeness, or adequacy of the information contained on this site or the information linked to on the state site. Please check official sources.
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