Compliance

Saltwater Disposal and UIC Class II Injection Wells: Permits and Testing

Produced water has to go somewhere, and for most operations that means a disposal well: an injection well permitted under the federal Underground Injection Control (UIC) program, run by EPA or a state with primacy such as the Texas Railroad Commission. This guide covers what a disposal well permit requires and the testing that keeps it operating.

Why disposal wells exist

Produced water has to go somewhere. For most operations that means a disposal well: an injection well permitted under the federal Underground Injection Control (UIC) program, run by EPA or a state with primacy such as the Texas Railroad Commission.

Class II wells are the UIC class for oil and gas related injection: disposal of produced water, enhanced recovery injection, and hydrocarbon storage. They are regulated under 40 CFR Parts 144 and 146. On a frac job, the water that comes back starts as flowback and ends in the same place: a permitted disposal well or a reuse system.

Produced water is not a waste stream you can ignore. It is salty, often hot, and sometimes carries solids and hydrocarbons. It has to be handled, moved, and injected where the permit says. In most producing areas it cannot simply be dumped at the surface.

Disposal is the last stop in a chain that starts at the wellhead: separation, storage, trucking or piping, then injection. Each link has its own paperwork, and the disposal well is where the chain is proven safe.

Who runs the program

Most producing states have primacy and run the program themselves. In Texas the Railroad Commission permits injection and disposal wells and enforces the testing schedule.

Know who your regulator is. The regulator decides the permit forms, the test calendar, and the reporting that keeps your well legal. On a multi-state operation, the rules differ state by state. The disposal well in one state does not follow the rules of the other, and the crew that moves across state lines has to learn the new calendar.

Primacy means the state's rules carry the weight of the federal program. What EPA sets at the federal level, the state implements and enforces at the well, and the paperwork follows the state's format.

What a permit requires

A permit application documents the well construction (casing, cement, tubing, packer), the injection interval, the maximum authorized injection pressure, and the fluids to be injected. Injection only into the permitted interval is allowed.

The limits are written into the permit for a reason. The maximum authorized injection pressure protects the formation and the casing. The injection interval keeps the water in the zone it was permitted for. Operating outside either one means operating outside the permit.

Disposal operations also monitor injection pressure and volume, and tubing-casing annulus pressure where the permit requires it. Those readings go into the operating record, and they are the first evidence reviewed when something goes wrong.

The permit fixes the well's identity: what it may inject, how fast, and under what pressure. Any change to the operation, from a different fluid to a different interval, means the permit has to change first.

Mechanical integrity testing

Mechanical integrity testing (MIT) is the heart of the program. In Texas, Form H-5 documents each test. The rules of the test are specific, and the crew running the test has to know them cold.

Notify the district office at least 48 hours before the test. Test pressure is 500 psig or the maximum authorized injection pressure, whichever is less, but no less than 200 psig. The test runs a minimum of 30 minutes. The test passes when pressure stabilizes within 10% of the required pressure and holds for 30 minutes. File Form H-5 with the district office within 30 days after any pressure test, including failed tests.

Those numbers matter to the people running the test and the people paying for it. A test done wrong is a test that has to be done again, and the clock restarts. The 48-hour notice gives the district office a chance to witness the test, and the pressure limits keep the test meaningful without pushing the well past what the permit allows.

The test schedule

Testing frequency depends on protection. Wells with surface casing set and cemented through the entire usable-quality groundwater zone test every 5 years. Wells without that protection test more often, commonly annual.

The schedule is what keeps the well legal, and it does not manage itself. The 5-year interval is the maximum between tests for the best-protected wells, not a target to drift toward. Companies that run disposal fleets track the calendar the way they track dispatch. OpsFlo keeps the schedule and the paperwork in one place, so a test date does not slip because it lived in someone's inbox.

When a test fails

A failed test means the well is shut in, repaired, and retested. The Commission sends a letter requiring the repair and retest within a set period. The well stays shut in until the retest passes and the paperwork is on file.

Most failures trace to a leak: through casing, past the packer, or up the annulus. Finding the leak early is cheaper than a long shut-in, which is why the test calendar gets managed like any other field obligation. A well that cannot hold pressure cannot inject, and a well that cannot inject makes no money.

While the well is down, the rest of the operation backs up: tank batteries fill, trucks wait, and production slows. The repair and the retest are the fastest way back, and they start with the test data that found the problem.

Sources and further reading

• EPA: Class II Oil and Gas Related Injection Wells
• eCFR 40 CFR Part 144: Underground Injection Control Program
• Railroad Commission of Texas: Injection permit types
• Railroad Commission of Texas: Form H-5 testing procedure