- casing, cementing, drilling, and completion requirements,
- cathodic protection wells, and
- seismic holes and core holes (16 Tex. Admin. Code §§ 3.13, 3.99, and 3.100 respectively).
Important provisions include:
- “Potential flow zone” is a new term which refers to “a zone designated by the director or identified by the operator…that needs to be isolated to prevent sustained pressurization of the surface case, 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 other subsurface resources, or sufficient to cause the fluids in the annulus to maintain a static fluid level at or less than 250 vertical feet below the protection depth.”
- The diameter of the wellbore in which surface casing will be set and cemented must be at least 1.5 inches greater than the nominal outside diameter of the casing. For subsequent casing strings, the diameter of each section of the wellbore for which casing will be set and cemented must be at least 1 inch greater than the nominal outside diameter of the casing to be installed.
- All casing cemented in any well must 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.
- Casing must be cemented across and above all formations permitted for injection under § 3.9 (Disposal Wells) or § 3.46 (Fluid Injection into Productive Reservoirs) within 1/4 mile radius of the well to be drilled.
- Casing must be cemented across and above all productive zones, potential flow zones, and zones with corrosive formation fluids.
- Notice must be given to and approved by the district director before setting casing to a depth of 3,500 feet or greater.
- All casing installed in a well that will be subjected to hydraulic fracturing treatments shall have a minimum internal yield pressure rating of at least 1.15 times the maximum pressure to which the casing may be subjected.
- The operator must pressure test the casing (or fracture tubing) on which the pressure will be exerted during hydraulic fracturing treatments to at least the maximum anticipated pressure. The district director must be advised of a failed test within 24 hours of completion of the test.
- During hydraulic fracturing operations, the operator must monitor all annuli. All operations must be suspended if the pressure deviates above anticipated increases caused by pressure or thermal transfer. The district director must be notified within 24 hours of that deviation and must give his approval before operations can recommence.
- A blowout preventer system or control head and other connections must be installed as soon as surface casing is set.
- Ram type blowout prevention equipment must 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 and before encountering any high-pressure formations.
- Blowout prevention equipment must be tested upon installation, after the disconnection or repair of any pressure containment seal in the blowout preventer stack, choke line, or choke manifold, with testing to occur at least every 21 days.
This post was prepared by Barclay Nicholson (email@example.com or 713 651 3662) from Fulbright's Energy Practice.