(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
Cont'd...