Pressure test your BOP at installation, after any pressure-containing seal is broken or repaired, and on a fixed calendar (every 14 days offshore under BSEE rules, with function tests every 7 days), and get every test chart signed. Keep an IBOP and a full opening safety valve in the open position on the rig floor for every connection size in the string, and drill your crew on stabbing the safety valve first. Before you rent either tool, confirm the pressure rating, connection match, and recent test documentation.
BOP testing and maintenance is the routine work that proves your blowout preventer will actually close when a well kicks. It's easy to treat as paperwork until you remember what happens when a stack fails. According to Business Insurance's coverage of the U.S. Chemical Safety Board report, the Deepwater Horizon BOP had miswired control systems, and the 2010 Macondo blowout killed 11 men and released more than 4 million barrels of oil into the Gulf. Below are straight answers to the questions drilling supervisors and company men ask most about test schedules, maintenance, IBOPs, and the valves that back them up on the rig floor.
BOP testing and maintenance is the combination of pressure tests, function tests, inspections, and repairs that keep a blowout preventer ready to seal the well. Testing proves the equipment works today, and maintenance keeps it working next week.
A blowout preventer (BOP) is a stack of large hydraulic valves mounted on the wellhead that can close around the drill pipe, close off the open hole, or shear the pipe to shut in a well during a kick. Two kinds of tests keep it honest:
The paperwork matters too. 30 CFR 250.746 requires test pressures to be recorded on charts or digital recorders, with the operator's representative, the rig contractor's representative, and the pump operator all signing off. Offshore wells follow BSEE's rules, which build on API Standard 53. Onshore wells answer to the BLM or the state.
Offshore BOPs in U.S. federal waters must be pressure tested at least every 14 days and function tested every 7 days between pressure tests. Blind shear rams get a longer 30-day pressure test window, and shear rams are function tested every 14 days. Onshore schedules depend on the state or federal agency in charge.
Offshore operators used to test weekly. The Minerals Management Service moved the requirement to 14 days in 1998 after a study found no statistical difference in failure rates between BOPs tested on 0-to-7-day intervals and 8-to-14-day intervals. The agency estimated the change would save industry $35 to $46 million a year.
Onshore rules look different. North Dakota's blowout prevention rule requires a pressure test at installation, after any equipment modification, and every 30 days after that. It also requires pipe rams to be functioned at least once every 24 hours and blind rams on each trip out of the hole.
| Test type | How often it's required | What it proves |
|---|---|---|
| Full BOP pressure test (offshore federal) | BSEE requires a new pressure test before 14 days have passed since the last one. | It proves each component holds both a low-pressure and a high-pressure test without leaking. |
| Blind shear ram pressure test | BSEE allows up to 30 days between blind shear ram pressure tests. | It proves the rams that close the open hole and cut pipe still seal under pressure. |
| Annular and pipe ram function test | BSEE requires a function test every 7 days between pressure tests. | It proves the annular and pipe rams open and close when the control system tells them to. |
| Shear ram function test | BSEE requires it every 14 days, or every 21 days if BSEE approves a longer test cycle. | It proves the shear rams actuate and the control system can fire them. |
| Onshore pressure test (North Dakota example) | The state requires it at installation, after modifications, and every 30 days. | It shows state rules can allow longer pressure test intervals while demanding daily ram function checks. |
A BOP retest is triggered by any event that could compromise a seal: installing the stack, breaking or repairing a pressure-containing connection, or drilling a new hole section that needs higher test pressures. The calendar is only one trigger.
BSEE requires operators to pressure test the affected components after the disconnection or repair of any well-pressure containment seal in the wellhead or BOP stack. You can skip the test after a casing run only if the stack stayed in place, the next hole section's test pressures aren't higher than the last test, and you're still inside the 14-day window, per the same 30 CFR 250.737 rule.
Common retest triggers on a working rig include:
Procedure counts too. In BSEE Safety Bulletin 016, inspectors cited an operator for failing to alternate control stations between consecutive pressure tests and for missing the 7-day function test. Neither involved a leak, and both still earned citations.
Routine BOP maintenance means daily visual checks, replacing wear parts on schedule, keeping the accumulator and control system healthy, and a major teardown inspection at least every five years. Under 30 CFR 250.739, offshore operators must visually inspect a surface BOP system every day and a subsea BOP system at least once every 3 days when weather allows. A major, detailed inspection of the well control system is required every 5 years, and an independent third party must review the results. Maintenance, inspection, and repair records have to stay on the rig for 2 years, and schematics and records must be kept onshore for the life of the equipment.
Day-to-day maintenance usually looks like this:
An experienced field service supervisor watching tool condition and paperwork catches small problems before they turn into a failed test at 3 a.m.
Skipped BOP maintenance shows up in three ways: failed tests that stop the rig, regulatory citations, and, in the worst case, a stack that won't seal during a kick.
Downtime comes first. A failed pressure test means the rig sits while the crew tracks down the leak, replaces an element or seal, and tests again. On a surface stack that might be hours. On a subsea stack, pulling the BOP to the surface can turn a single bad seal into days of lost rig time.
Compliance trouble comes next. BSEE inspectors review test charts and maintenance records, and missed tests or incomplete records lead to Incidents of Noncompliance (INCs). Those can shut down specific operations until the problem is fixed.
Well control failure is the outcome nobody wants to talk about. The Deepwater Horizon investigation is the clearest example: investigators found miswired control systems on a stack that was supposed to be the last line of defense. Consistent BOP testing and maintenance is what keeps a planned stop on your schedule instead of the well's.
An inside blowout preventer (IBOP) is a check valve that installs in the drill string to stop well fluids from flowing up the inside of the pipe, while still letting the crew pump down through it. A surface BOP seals the annulus and the open hole, so if a kick comes up the inside of the drill string, closing the rams won't stop it. That's the IBOP's job.
The most common rig floor style is the stab-in IBOP (often called a Gray valve), which is a spring-loaded check valve that's held open by a removable release tool so the crew can stab it, then pull the tool to let the check close. On top drive rigs, "IBOP" also refers to the upper and lower kelly-type ball valves built into the top drive.
An IBOP seals the inside of the drill pipe and allows one-way flow, while a surface BOP seals the annulus and the open hole and is operated hydraulically from a remote panel.
| Feature | Surface BOP | IBOP |
|---|---|---|
| Where it sits | The surface BOP is bolted to the wellhead below the rig floor. | The IBOP is made up into the drill string at the rig floor. |
| What it seals | It seals the annulus around the pipe, closes the open hole, or shears the pipe. | It seals the bore of the drill pipe and blocks flow coming up the string. |
| Flow direction | Once closed, it blocks flow in both directions. | It lets the crew pump down through the string but blocks flow coming up. |
| How it's operated | It's closed hydraulically from a remote control panel powered by an accumulator. | It's stabbed and made up by hand by the drill crew. |
Crews use an IBOP when they need to shut in the drill string and still pump through it or strip pipe back into the hole. Typical situations include:
30 CFR 250.736 requires an IBOP in the open position on the rig floor during operations, and the crew must be able to install one for each connection size in the string.
IBOPs and TIW valves work as a pair: the crew stabs and closes the full opening safety valve first to stop flow up the pipe, then makes up the IBOP on top so they can strip or pump through the string.
A full opening safety valve (FOSV), commonly called a TIW valve, is a manually operated ball valve with a full bore that can be stabbed into the drill string and closed with a wrench. Our guide to TIW valves and their role in drilling safety covers the history, and our explainer on what a full opening safety valve is covers how it's built.
The FOSV goes on first because an open, full-bore valve lets flow pass straight through while it's being stabbed, so the crew isn't fighting the well. A typical sequence looks like this:
Here's the catch: both valves have to fit the pipe in the hole. If the string has mixed connections, you need a valve for each size or a crossover sub that matches the connections. BSEE also requires a wrench for each manual valve within easy reach of the drill crew.
Before renting IBOPs, safety valves, or other well control tools, confirm the pressure rating, the connection match, the test documentation, and how fast the supplier can get a backup to location.
Ask your supplier these questions before anything ships:
Superior Performance rents inside BOPs in 1 1/4" through 5 1/2" connections and full opening safety valves in 2 3/8" through 5 1/2" connections, both rated to 10,000 and 15,000 psi, with additional sizes available by special order. Every rental tool is inspected and maintained before it goes out.
The well control lineup on our rental tools page also includes integral pump-in subs from 1 1/4" to 6 5/8" with top and side entry and 2-inch 1502 Weco connections, plus crossover subs from 2 3/8" to 20". For the full picture, see our overview of oilfield rental tools and services from Superior Performance.
Superior is headquartered in Broussard, Louisiana, with locations in Midland/Odessa and Oklahoma.
Your BOP testing and maintenance program is only as good as the backup valves on the floor. Head to the Superior Performance contact page and send: