A choke manifold is an assembly of valves, chokes, gauges and piping that controls flow and pressure coming out of a well. Fluid is forced through a restriction called a choke, which drops the pressure and sets the flow rate while holding backpressure on the well. Gate or plug valves route the flow through one choke or another.
You will find choke manifolds in two places: on a drilling rig as part of the well control system, and in a flowback or well testing spread between the wellhead and the separator. The hardware looks similar, but the job is different, and so is the way you rig it up and run it.
What does a choke manifold do?
A choke is a deliberate restriction. Forcing fluid through a small opening drops its pressure, and the size of the opening decides how much gets through. Upstream of the choke, the well sees backpressure. Downstream, the separator, flare line or mud-gas separator sees a lower, workable pressure.
In drilling, the job is backpressure: holding enough pressure on the well while a kick is circulated out that no more formation fluid comes in. In flowback and well testing, the job is rate: bringing the well on under control, cleaning it up without damaging the surface equipment, and holding steady flow so the separator can measure what the well makes. The valves let the crew flow through one choke while the other is isolated, so worn parts can be changed without shutting the well in.
What are the parts of a choke manifold?
Configurations vary by service and pressure rating, but most manifolds use the same pieces.
| Part | What it does |
|---|---|
| Inlet connection | Ties the manifold to the choke line from the BOP stack (drilling) or the flow line from the wellhead and plug catcher (flowback). |
| Gate or plug valves | Isolate each leg. Run fully open or fully closed, never used to throttle. |
| Adjustable choke | A variable opening, set by handwheel or hydraulic actuator, used to change rate or pressure while the well flows. |
| Positive (fixed) choke | Holds a replaceable bean with a fixed orifice for steady, repeatable flow. |
| Bypass line | A full-opening path around the chokes when no restriction is wanted. |
| Gauges and data ports | Read pressure upstream and downstream of the chokes and give access for sampling or chemical injection. |
| Bleed valves | Bleed an isolated leg to zero before it is opened. |
| Crosses, tees and outlet | Join the legs and send flow on to the next piece of equipment. |
Choke manifold diagram: the flow path
A common flowback and well test layout has two choke legs, one adjustable and one positive, with a gate valve on each side of each choke. From the well to the outlet:
- The flow line enters at the inlet, where a gauge reads wellhead pressure.
- The inlet cross splits flow toward the adjustable leg, the positive leg and, on some units, a bypass.
- On the active leg, both gate valves are open and flow passes through the choke, where the pressure drop happens. On the standby leg, both gates are closed.
- The legs rejoin at the outlet cross, a downstream gauge reads the reduced pressure, and flow leaves for the next piece of the spread.
Spec sheets often call these 5-valve or 9-valve manifolds, counting the isolation valves. More valves mean more ways to route flow and isolate a leg.
What is the difference between a positive and an adjustable choke?
A positive choke uses a bean, a hardened insert with a fixed orifice. Bean sizes are given in 64ths of an inch, so a 32/64 bean has a half-inch opening. Changing the rate means isolating the leg, bleeding it down and swapping the bean. Positive chokes are simple and hold a steady rate, which is why many well tests settle onto one once flow stabilizes.
An adjustable choke changes its opening while the well flows, and an indicator shows the equivalent opening. It is the choke you use while bringing a well on, during cleanup and whenever conditions are changing. The tradeoff is wear: sand cuts the trim, and the indicator drifts away from the true opening as it erodes. Chokes turn up away from the manifold too. Tiger’s sand traps, for example, carry 3 in 10K adjustable chokes on their dump lines.
How is a drilling choke manifold different from a flowback choke manifold?
Drilling choke manifold and the choke and kill system
On a drilling rig, the choke manifold connects to the BOP stack through the choke line. When the well takes a kick, the crew shuts in on the BOPs, then circulates the influx out through the choke manifold, adjusting the choke to hold bottomhole pressure constant. Returns go to the mud-gas separator and gas goes to the flare line. The kill line and kill manifold let the crew pump into the well when it cannot be pumped down the drill string. Together they make up the choke and kill system, covered by API Specification 16C, Choke and Kill Equipment.
Flowback and well test choke manifold
In a flowback or well testing spread, the manifold sits after the wellhead and plug catcher and drops wellhead pressure to something the sand trap, separator and lines downstream can handle. It runs for days or weeks of continuous flow, often with sand in the stream, so erosion matters more than on most drilling manifolds. Chokes are listed in the scope of API Specification 6A, the specification for wellhead and tree equipment, and flowback manifolds are commonly built and documented to it. Which specification a job requires comes from the operator’s program. Our guide to what is in a flowback spread shows where the manifold fits.
What is a hydraulic choke manifold?
A hydraulic choke manifold has at least one choke driven by a hydraulic actuator instead of a handwheel. The actuator is run from a remote panel, often called a hydraulic choke operator or choke console, which shows choke position and the pressures the operator works to. On a rig, that panel lets the choke operator run a kill from the rig floor. On flowback, it lets the crew adjust the choke from a safe distance instead of standing next to high-pressure iron. Manual chokes are simpler and cost less, so many manifolds carry one of each, with the manual choke as the backup.
How do you set up a choke manifold?
- Spot and level the skid where the inlet and outlet lines make up without strain, with clear access to the valves, gauges and chokes.
- Check ratings before anything is connected. Read the working pressure on the manifold, every valve, the iron and every union. The system is only rated as high as its lowest-rated piece.
- Make up the iron. Match every hammer union figure to its mate, and restrain temporary lines as the operator’s program requires.
- Pressure test before the well is opened. Test with water to the pressure in the operator’s program, which can never exceed the working pressure of the lowest-rated component. Many programs call for a low-pressure test before the high test. Test valves one at a time by closing each, pressuring against it and confirming it holds. Keep people clear.
- Walk the valve line-up. Active leg open, standby leg closed, bleeds closed, choke at its starting setting, and a clear path to the separator or flare. A closed valve downstream when the well opens means trapped pressure.
How do you operate a choke manifold during flowback and well testing?
Bring the well on through the adjustable choke at a small opening and open in steps, letting pressures settle between changes. Log choke size, upstream and downstream pressure, and rates at every step. That log is how you spot trouble early.
Once the well is clean and steady, many crews move flow to the positive leg. To change a bean: move flow to the other leg and set its choke, close the gate valves on both sides of the leg being serviced, bleed it to zero and confirm zero on the gauge, leave the bleed open, and only then break the choke cap.
Watch for erosion. Sand at high velocity cuts beans, seats and needles, and the tees and elbows just downstream of the choke. A choke is washing out when upstream pressure falls and rate climbs at the same setting, or when an adjustable choke has to be pinched in again and again to hold pressure. Treat a sudden change as a washout until you prove otherwise.
That is the main reason to take sand out early. In many spreads the sand trap sits downstream of the choke, but when sand comes back hard, a sand separator rated for full wellhead pressure goes upstream of the manifold. Tiger’s 10,000 PSI cyclonic sand trap (24 in x 120 in) and 15,000 PSI sand trap are rented for that job, staged at the wellhead as the first line of defense. Our article on cyclonic sand separators covers how they work.
Also watch for freezing. The pressure drop across a choke chills gas, and a big enough drop can form hydrates that plug the choke or the line behind it. Spreads that expect this add heat or chemical injection near the choke.
What safety rules apply to choke manifolds?
- Never exceed the working pressure of the lowest-rated component in the manifold, the iron or the equipment downstream.
- Never throttle with a gate valve. Partly open gates wash out and then will not seal.
- Bleed to zero and verify on a gauge before breaking a connection, opening a choke body or hammering a union. Never hammer on a union holding pressure.
- Hammer unions of different figures can look alike and partly make up, then separate under pressure. Match figure numbers and ratings on every connection.
- Restrain temporary iron and keep people out of the line of fire during testing and flow.
- On a sour well, monitor for H2S against the H2S exposure limits before anyone opens the system.
Frequently asked questions
What is the function of a choke manifold in oil and gas?
It controls flow rate and pressure from the well by forcing flow through a choke. In drilling it holds backpressure while a kick is circulated out. In flowback and well testing it brings the well on at a controlled rate and protects the equipment downstream.
What is a choke and kill manifold?
The drilling well control setup that pairs the choke manifold, which bleeds flow off the well, with the kill manifold, which pumps fluid into it. Both connect to the BOP stack.
How are choke sizes measured?
In 64ths of an inch. A 16/64 bean has a quarter-inch orifice and a 32/64 bean a half-inch orifice.
Where does the sand trap go relative to the choke manifold?
Usually downstream of the choke. On high-pressure, high-sand flowback, a sand separator rated for full wellhead pressure goes upstream to protect the chokes.
Is a hydraulic choke better than a manual choke?
Not always. A hydraulic choke gives finer remote control and keeps the operator away from the iron. A manual choke is simpler and makes a good backup.
Rent the equipment that works with your choke manifold
Tiger Safety Rentals rents the well testing equipment around a choke manifold: cyclonic sand traps rated to 10,000 PSI, a 15,000 PSI sand trap, flow iron, well test separators and flare trailers, dispatched from Broussard, Midland, Dilley and Hobbs. See our well testing and production rentals or call 888-365-5220 for 24/7 dispatch.
