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

Current through Reg. 49, No. 28; July 12, 2024
(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.
(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.