Drilling guides › Kick warning signs, flow checks and shut-in data
Kick warning signs, flow checks and shut-in data
A kick is an unplanned flow of formation fluid (gas, oil or water) into the wellbore, caused when the pressure in the well falls below the pore pressure of a permeable formation. Caught early, a kick is a routine operation: shut in, read the pressures, circulate the influx out. Caught late, the influx is larger, the kill pressures are higher and the margin to the weakest formation shrinks. Kick detection is about keeping the influx small.
Why kicks happen
The mud column is the primary barrier. Anything that lowers the bottom-hole pressure, or anything that raises the formation pressure above what the plan expected, can let the well flow. The usual causes are:
- Not keeping the hole full. Pulling pipe removes steel volume. If the hole is not topped up by the same amount, the mud level drops and so does the hydrostatic pressure.
- Swabbing. Pulling pipe too fast, especially with a balled bit or stabilizers, or in thick mud, drags fluid upwards and briefly reduces the pressure below the bit. Swabbed influx often shows up as the hole taking less fill than it should.
- Mud weight too low. Drilling into a zone with higher pore pressure than forecast, or letting the mud weight drop through dilution or gas cutting.
- Lost circulation. Losses lower the fluid level in the annulus, which can let a shallower permeable zone flow. A loss followed by a gain is a classic sequence.
- Abnormal pressure. Charged sands, faulted blocks or depleted and undepleted zones side by side.
Primary indicators: the well is flowing
Primary indicators mean formation fluid is entering the well now. Any one of them is a reason to stop and flow check, or to shut in directly if that is what the standing instructions say.
| Indicator | What you see | Notes |
|---|---|---|
| Flow rate increase | Return flow sensor (paddle or Coriolis) reads higher than the pump rate going in | Usually the first sign at surface. Compare with the trend, not one reading. |
| Pit gain | Active system volume rises with no transfer or mud addition | Every transfer, dump or chemical addition must be called to the driller, or real gains are lost in the noise. |
| Flow with pumps off | The well keeps flowing after the pumps are stopped | Allow for normal drain-back from the flowline and surface lines, which is why knowing your rig's drain-back volume matters. |
| Wrong trip tank volume | Hole takes less than calculated fill when pulling, or gives back more than displacement when running in | Compare against the trip sheet stand by stand. |
Secondary indicators: warning, not proof
Secondary indicators mean the conditions for a kick may be developing. They are not proof of influx on their own, but they should prompt a flow check or at least closer watching.
- Drilling break. A sudden rise in rate of penetration can mean the bit has entered a more porous zone, or that the overbalance has fallen because pore pressure has gone up. Many rigs flow check every significant drilling break.
- Pump pressure drop with stroke rate increase. Lighter formation fluid in the annulus reduces annular hydrostatic, so the drill pipe side can U-tube and the pump runs faster at lower pressure. A washout in the string can give a similar pressure drop, so the two must be told apart.
- Gas-cut mud. Rising background gas, connection gas or trip gas, and reduced mud weight at the flowline. Gas cutting at surface reduces bottom-hole pressure less than most people expect, because the gas only expands near the top, but a rising trend is a sign of reducing overbalance.
- Changes in cuttings, torque and drag. Larger, splintery cavings and increasing torque and overpull can point to rising pore pressure in shales.
The flow check
A flow check answers one question: is the well flowing with the pumps off? A typical sequence while drilling is: stop rotating, pick up to the shut-in position so that no tool joint is across the rams you would close, stop the pumps, and watch the flowline and the trip tank for the time set by your policy. In oil-based mud, gas can stay dissolved until it is near surface, so policies often call for longer checks and more caution with small gains.
Common mistakes are watching the wrong tank, not lining up the trip tank so that small flows are visible, and confusing drain-back with flow. If in doubt, the safe choice is to shut the well in and read the pressures. A shut-in well with no influx costs a little time; an open well with an influx can cost far more.
Shut-in methods
There are two general methods. In a hard shut-in, the choke is already closed and the BOP (annular or pipe ram) is closed directly, stopping the flow as fast as possible. In a soft shut-in, the choke line is open to the choke, the BOP is closed, and then the choke is closed. The hard method lets in the least extra influx; the soft method was historically used to reduce the pressure surge on the formation. Many operators now prefer the hard method, but the method used on your rig is set by the company policy and the rig's procedures, and the choke manifold line-up must match it.
Recording SIDPP, SICP and pit gain
Once the well is shut in, record the pit gain, the shut-in drill pipe pressure (SIDPP) and the shut-in casing pressure (SICP), with the time of each reading. Pressures normally build and then level off as the formation around the well recovers; the stabilised values are used for the kill. If they keep climbing slowly after stabilising, gas migration may be the cause, and the procedures for managing migration apply. With a non-ported float in the string, the SIDPP will read zero or too low until the float is opened by carefully bumping it with the pump.
SIDPP is the more useful number for formation pressure because the drill pipe is full of mud of known weight. The annulus contains the influx, so SICP is normally higher than SIDPP when the influx is lighter than the mud.
In metric units, formation pressure (bar) = SIDPP (bar) + 0.0981 × MW (sg) × TVD (m), and pit gain in m³ is the level rise in metres times the pit area in m². One barrel is 0.159 m³.
Worked example 1: pit gain from level change
The active system is two connected pits, each 30 ft long and 8 ft wide. After the well is shut in, the level in both has risen 2.5 in above the reference.
A 2.5 in change is easy to miss on a single gauge, which is why gain alarms are set on the total active volume, and why the barrels per inch of the active system should be written on the driller's board.
Estimating the influx type
If you know the influx volume and the annular capacity where it sits, you can estimate the height of the influx and, from the difference between SICP and SIDPP, its density gradient. It assumes the influx is a single slug around the bottom of the BHA, the hole is in gauge, and the pressures are stabilised. Real influxes are spread out and mixed with mud, so treat the result as an indication, never as proof.
As a rough guide, a gradient below about 0.25 psi/ft suggests mostly gas, around 0.3 to 0.4 psi/ft oil or a gas and liquid mix, and above about 0.4 psi/ft mainly water. The bands overlap, and a large error in the hole size gives a large error in the answer.
Worked example 2: influx gradient and formation pressure
8.5 in hole, 6.5 in drill collars 600 ft long, mud 11.0 ppg, bit at 10,000 ft TVD. Shut-in data: pit gain 10 bbl, SIDPP 350 psi, SICP 520 psi.
A gradient around 0.08 psi/ft points to gas. That means the influx will expand as it is circulated up, the casing pressure will rise during the kill, and migration is possible if the well stays shut in. The kill mud weight from these numbers is about 11.7 ppg; see the kill sheet guide for the full calculation.
Why early detection matters
A smaller influx gives a lower SICP at shut-in and a lower peak casing pressure when gas reaches the shoe and the surface. That keeps the shoe pressure further below the fracture pressure measured by the leak-off test, and reduces the risk of an underground blowout. It also keeps the kill simple. In practice, the difference between a 5 bbl and a 25 bbl gas kick can be the difference between a quiet circulation and a kill where the MAASP is approached.
Good practice
- Know the barrels per inch of the active system and the rig's normal drain-back volume.
- Call every pit transfer, dump and mud addition to the driller before it happens.
- Fill in the trip sheet for every stand or every few stands, and act on a discrepancy at once.
- When in doubt, shut in. Then read and record stabilised SIDPP, SICP and pit gain with times.
- Keep slow circulating rates and pressures up to date, so the kill sheet is ready before it is needed.