H-5 - Pressure Testing Injection Wells FAQs
Frequently Asked Questions on Pressure Testing Injection Wells
Can the pressure test requirement be waived?
All injection and disposal wells must demonstrate mechanical integrity. The pressure test is usually the simplest and least expensive method available. Other methods of demonstrating mechanical integrity may be approved by UIC if they can reliably detect leaks at a level approximately equivalent to the pressure test. A Form H-5 should be used to document every mechanical integrity test performed on an injection/disposal well. In the case of an alternative test method, Form H-5 will serve to identify the well and describe the test conditions.
Why are some wells required to be tested annually and others every five years?
Wells completed with surface casing set and cemented through the entire zone of usable quality groundwater are required to be tested every five years. Wells without full surface casing protection for usable quality groundwater are required to be tested more frequently.
If the permit doesn't state a maximum authorized injection pressure, what test pressure should be applied?
All injection/disposal permits are issued based on the wellbore construction and operating conditions stated in the permit application. Thus, the pressure stated on the application is the permitted maximum. If an application is not readily available, the maximum test pressure of 500 psi. would be a safe choice.
What do you consider to be a successful pressure test?
The test pressure must STABILIZE FOR 30 MINUTES AT A PRESSURE WITHIN 10% OF THE STARTING PRESSURE to be considered a clear demonstration of mechanical integrity. In addition, the well must be in compliance with its permit and the test must be conducted in accordance with the instructions on Form H-5.
What if the pressure will not stabilize for 30 minutes, but stays within 10% of the test pressure?
Under most operating conditions, this would indicate a lack of adequate mechanical integrity and the well would have to be shut in, repaired, and retested. In rare cases in which a well operates at low injection pressures and volumes with full surface casing protection of usable quality groundwater, UIC may allow continued operation of the well subject to frequent retesting and monitoring.
May a well that fails a pressure test be converted to production or shut in under a 14(b)(2) extension?
Yes, as long as the casing string has mechanical integrity. The well must be repaired and retest, or plugged if it has a casing leak.
If the well is shut in under a 14(b)2 extension, or is currently producing, does it still have to be tested?
Once a well has been used for injection/disposal, it must demonstrate mechanical integrity periodically until the permit is canceled, regardless of whether it is currently equipped or used for injection/disposal. See question no. 15 for more information.
How do we test a well equipped with gas lift valves in the tubing?
Wells that inject liquids are required by rule to test with a liquid filled annulus. The two-part pressure test may be performed as described in the seminar manual. The use of a tubing plug may be necessary if the test pressure cannot be achieved due to low shut in tubing pressure or low injection pressure.Alternatively, UIC may approve the use of air pressure to test the tubing/casing annulus. In this case, the instructions on Form H-5 would still be followed, except that the test pressure would have to stabilize for at least 60 minutes.
What effect does shutting a well in, or converting it to production have on the an annual testing requirements?
A well that was converted to production after a successful pressure test will revert to the five year pressure test cycle while it is actively producing. A well that was shut in after a successful pressure test will continue to be scheduled for annual pressure tests unless the permit is canceled or voluntarily suspended. See question no. 15 for more information. In addition, tubing-casing annulus monitoring required by many permits, may be discontinued.
Who is authorized to perform the Mechanical integrity tests?
Anyone who is authorized by the well operator can perform the standard H-5 pressure test. There is no requirement to hire a service or testing company to perform the test.
Other methods of demonstrating mechanical integrity, such as radioactive tracer or differential temperature surveys, require specialized equipment and training not normally available to an operator.
How do I know if I need to perform an H-5 pressure test or an H-15 test on my shut in wells?
The H-15 mechanical integrity test is required for shut in production wells of various ages. The H-15 test does not apply to any well with an active injection of disposal permit. Injection and disposal wells are required to perform MITs based on Form H-5, which is a more thorough test than the H-15.
If you have received notice to perform an H-15 test on your injection or disposal well, it is probably a scheduling program error. We suggest you send the notice back to the Commission, to the attention of the Record Codification section (at the main Austin address), with a note to the effect that "This is an injection/disposal well that is subject to H-5 pressure testing. Please remove from the Form H-15 testing schedule." If you have any questions, you can call the Record Codification section at (512) 463-6905.
Recent amendments to Statewide Rule 14 complicated the issue slighly by requiring shut in wells to demonstrate mechanical integrity every 4 years. This requirement may require shut in injection wells to perform an injection well MIT (Form H-5) one year early to satisfy the SWR 14 requirement. Alternatively, a shut in production well MIT (Form H-15) can be performed, but it will only fulfil the SWR 14 requirement, and have no effect on the injection well MIT schedule.
My company periodically does "unofficial" pressure tests for various reasons. Is there any filing requirement on these?
Yes, the Form H-5 should be filed to document all mechanical integrity tests on injection wells, not just the "official" or "passed" ones.
The "failed" test that you file will notify the Commission that you have complied with the requirement to perform a pressure test. The Commission will generate a letter advising you to repair and retest the well in 60 days.
The "pass" test will "reset the clock". The pressure test schedule is based on the most recent pressure test, whether scheduled by the Commission, or performed after a workover, etc.
Can polymer gels, drilling mud, or other high viscosity fluids be used in the tubing-packer-casing annulus to help pass the pressure test?
The purpose of the mechanical integrity test is to prove the integrity of the tubing, packer and casing. The use of any packer fluid additive that interferes with the sensitivity, or reduces the effectiveness of the mechanical integrity test is expressly prohibited by Rules 9(12)(D)(vi) and 46(j)(4)(F)(ii).
Can a well be tested with gas instead of water?
Wells that inject only gases may be tested with a gas-filled annulus. The gas test pressure must stabilize for at least 60 minutes. Wells that inject water must be tested with a liquid filled annulus to represent the hydrostatic pressure of the water column. The liquid test pressure must stabilize for at least 30 minutes. Gas pressure (e.g. from a bottle of nitrogen) may be used to apply the test pressure on a liquid-filled annulus, for a 30 minute stabilized test.
The 1999 amendments to Rule 9 and 46 allow for something called Permit Suspension. How does that work?
Permit suspension has the same effect as permanent cancellation of the injection permit, except that the permit can be reactivated at a later date. Permit suspension allows long-term relief from injection well pressure testing and monitoring requirements. Note that the well must be pressure tested at the time the permit suspension is requested, and again at the time the permit re-activation is requested.
Can annulus monitoring be done with open tubing-casing pressure valves?
No. The purpose of having wellhead pressure observation valves is two-fold: First, it contains injected fluids inside the wellbore in the event of a tubing or packer leak; Second, it allows pressure to build up and be detected. Leaving pressure observation valves open will be cited as an operating violation (Rule 13(b)(1)(B)) and nullify any potential annulus monitoring credit.
Operating an injection well with open tubing-casing wellhead valves is an unsound practice because a tubing or packer failure will result in immediate surface and subsequent, groundwater pollution.