combi BOP, Oil & Gas Glossary

What Is a Combi BOP?

Combi BOP (also called a combination blowout preventer or CT BOP stack) is a compact, integrated well-control stack designed specifically for coiled tubing and wireline well intervention operations. It combines a hydraulic stripper packer — which maintains a dynamic pressure seal around moving coiled tubing or wireline — with one or more ram-type preventers, including blind/shear rams capable of severing the CT string in an emergency. The result is a single, lower-profile assembly that enables live-well intervention without shutting in the well prior to entry, providing continuous well control from the moment the CT enters the wellbore to the moment it is fully retrieved.

Key Takeaways

A combi BOP integrates a stripper packer (dynamic seal) and ram-type preventers (blind/shear rams) into one compact stack, typically 3-5 ft shorter than a full drilling BOP assembly.
Working pressure ratings range from 5,000 to 15,000 psi, and the selected unit must match or exceed the wellhead pressure rating for the specific intervention job.
Stripper elements are sized to the coiled tubing OD being run — common sizes are 1.75 in, 2-3/8 in, 2-7/8 in, and 3-1/2 in — and must be replaced when the CT OD changes.
Shear/blind rams can sever the CT string in an emergency and then close fully to provide wellbore isolation, making them the last line of defense before the wellhead.
API 16A governs the design, testing, and qualification of BOP components; pressure tests of the stripper and rams are required before each well entry to confirm seal integrity under operating conditions.

Combi BOP Components and How They Work Together

The combi BOP stack is typically made up of three functional elements arranged in series on top of the wellhead or lubricator. The hydraulic stripper packer sits at the top and forms the primary dynamic seal — a rubber element that grips the CT OD while still allowing the string to move up or down under injection pressure. This stripper must maintain a gas-tight seal at full wellhead pressure while the CT is moving at typical injection speeds of 30-100 ft/min. Below the stripper are pipe rams, which are closed around a stationary CT string to provide a positive static seal whenever CT movement is suspended — for example, during a tool exchange or a well-control hold. At the bottom of the stack sit the blind/shear rams, which can either close on a CT-free wellbore (blind mode) or shear through the CT string and seal simultaneously (shear mode), providing full wellbore isolation in a blowout scenario.

Hydraulic actuation lines run from each element to a dedicated BOP control panel — either a compact skid-mounted accumulator or the CT unit's existing BOP control system — allowing the operator to open and close each element independently. Interlock logic is typically programmed so that the shear rams cannot be activated while the stripper is still energized around a moving CT string, preventing premature severance. The stack height, weight, and footprint are substantially smaller than a conventional drilling BOP, allowing combi BOPs to be rigged up on single-mast CT units operating from light well intervention vessels, production platforms, or road-transportable packages on land.

The combi BOP is pressure-tested on the surface before each job by staging up to the rated working pressure with water, holding for 15 minutes, and confirming no pressure decay. Function testing — cycling each ram and the stripper packer through open and close — is performed at the same time. The test log must be signed off by the well-control supervisor before any CT enters the wellbore.

Fast Facts: Combi BOP

Working pressure range: 5,000-15,000 psi, matched to wellhead rating
Common CT OD sizes: 1.75 in, 2-3/8 in, 2-7/8 in, 3-1/2 in
Primary seal: Hydraulic stripper packer — dynamic, seals while CT is moving
Secondary seal: Pipe rams — static, closed around stationary CT
Emergency isolation: Blind/shear rams — sever CT and close wellbore
Governing standard: API 16A (BOP equipment design and testing)
Stack height advantage: 3-5 ft shorter than full drilling BOP stack
Test requirement: Full pressure test + function test before each well entry

Well Intervention Tip:

When swapping CT strings for a different OD job on the same wellsite, the stripper element must be changed out to match the new CT OD before any pressure test or well entry. Running a mismatched stripper — even 1/16 in undersize or oversize — will cause either immediate leakage past the element or excessive wear that fails midway through the job, both of which compromise well control. Always verify the element part number against the CT OD on the job ticket before rig-up.

Combi BOP is also referred to as:

combination BOP — full form of the abbreviation, used in engineering specifications and API documentation
CT BOP stack — emphasizes its coiled tubing-specific application, distinguishing it from drilling BOP stacks
wireline BOP — when the same style of integrated stack is configured for slickline or braided wireline rather than coiled tubing
intervention BOP — general term used in well services to describe any compact BOP stack used during post-completion intervention, not just CT

Frequently Asked Questions About Combi BOPs

Why is a combi BOP used instead of a full drilling BOP for CT operations?

A full drilling BOP stack is designed for large-OD drill pipe and casing strings and can weigh 20,000-80,000 lb or more. Coiled tubing units are compact, road-transportable, and often rigged up on platforms or wellheads with limited space and weight capacity. The combi BOP provides the well control functions specifically needed for CT — a dynamic stripper seal for moving pipe and shear capability for emergencies — at a fraction of the weight and height, making it practical for the intervention environment without the overhead of a drilling rig BOP.

What happens if the stripper packer fails during a live-well CT job?

If the stripper loses its dynamic seal and pressure is observed leaking past it, the operator immediately stops CT movement, closes the pipe rams around the stationary string to establish a static seal, and investigates. If the stripper cannot be repressurized or replaced with the CT in the hole, the well may need to be killed by pumping kill-weight fluid down the CT before retrieving the string. The pipe rams hold pressure while the kill operation is executed. This is why function-testing the entire stack before entry is mandatory — discovering a failed stripper element after entering a live well is a serious well-control event.

Can a combi BOP be used on high-pressure sour gas wells?

Yes, but the elastomer materials in the stripper packer and ram elements must be specified for H2S service (NACE MR0175 compliant), and the working pressure rating must match the maximum anticipated surface pressure. For high-pressure/high-temperature (HPHT) sour gas wells, specialized CT BOPs rated to 15,000 psi with H2S-resistant seals and metal-to-metal backup seating are available. The deployment plan requires explicit well-control risk assessment for sour service, including respiratory protection, H2S monitoring, and emergency disconnect procedures for the CT string.

Why Combi BOPs Matter in Oil and Gas

As mature fields require increasingly frequent well interventions to maintain production — cleanouts, scale removal, logging, perforation work, and gas lift — the combi BOP has become an essential piece of well-control infrastructure for the coiled tubing industry. Its compact form factor and integrated design make it possible to intervene in live wells safely on platforms, remote land locations, and subsea wellheads (via subsea CT stacks) without the cost and complexity of a full workover rig. The ability to sever the CT string and seal the well in seconds provides a meaningful last-resort safeguard against catastrophic blowout during intervention, making the combi BOP a cornerstone of modern well integrity management.

Combi BOP: Definition, Well Control Equipment, and Coiled Tubing Operations