What are kicks?
A “kick”, or otherwise known as an influx, is a flow of formation fluids into the wellbore. This can be either be a deliberate influx into the well (for example, to test the production viability of a formation) or an unintentional influx. If not handled correctly, an influx can have catastrophic consequences. It is possible to control an influx by utilizing correct procedures and ensuring the crew has the correct relevant training.
Why are kicks bad?
If a kick is not handled correctly, or it is not detected early enough, it can become an uncontrolled well blowout, which puts lives, equipment, and the environment at severe risk. A blowout is defined as an uncontrolled release of formation fluids at surface. Blowouts are extremely hazardous and costly to contain once they have occurred.
How do you detect kicks?
Flow rate increase. The only way to positively identify a kick is to turn off the pump, wait for the well to stabilize, and then observe the annulus for flow. Positive flow indicates that formation fluids are likely entering the wellbore, displacing wellbore fluids.
Pit volume increase. A flow rate increase is usually the first “positive indicator” of flow during normal drilling operations, and usually triggers the crew to perform a flow-check. If the well is flowing, the crew will then normally notice a “pit-gain”, which is caused by formation fluids entering the wellbore, displacing drilling fluid from the well.
Flowing well with pumps off. Any flow of formation fluids into the wellbore will naturally displace well bore fluids. This is generally known as a “positive indicator” of flow and will require the well to be secured promptly.
Pump pressure decrease and pump stroke increase. A positive indicator of an influx with older style pumps/power systems is with a Pump pressure decrease and pump stroke increase. This situation is created due to the influx simultaneously reducing the APL near the bit, and the formation pressure increase forcing pressure upwards, reducing the pump pressure. This creates less resistance on the pump, potentially increasing the stroke rate. As newer electrical systems more accurately control the pump stroke rate, this is not a common issue on newer style rigs.
Improper hole fill-up on trips. Monitoring fluid levels in the annulus is a critical job, because the only means of detecting a kick on trips is by constantly monitoring and comparing volumes with previous trips.
String weight change. This is often caused by the influx (usually a lighter fluid/gas) affecting buoyancy, combined with higher formation pressure, which increases the upwards cross-sectional force on the surface area of the bit. These factors can create a reduced hook load.
Drilling break. A drilling break is a rapid, dramatic increase (or decrease) in the rate of penetration (ROP). A “positive” drilling break (or increase in ROP) is usually a warning sign that requires a flow check, as the new formation may be more porous than previous formations, meaning that the formations may be holding higher quantities of fluids.
Cut mud weight. “Gas-Cut” mud is a situation where small quantities of drilled formation gases are released into the wellbore. This gas decreases the fluid density, reducing the hydrostatic pressure (HSP) applied by the fluid. This reduction in HSP may allow formation fluids to flow uncontrolled from the formations into the wellbore.
How do you deal with kicks?
Shut-in procedures hard vs. soft: The “Hard” shut-in method is a means of closing the well in rapidly, by firstly closing a BOP, and then opening a flow path to the closed choke manifold. This method results in a smaller influx volume but may introduce an initial pressure shock. To mitigate this, the “Soft” shut-in method was developed. The Soft shut-in firstly diverts flow through the opened remote choke, then a BOP is closed. Lastly, we slowly close the remote choke, which gradually closes in the well. This method reduces the likelihood of an initial pressure shock, but will result in a larger influx, as it takes longer to secure the well. The “Hard” shut-in method is by far the most used method in industry.
Does a well’s status as HPHT, horizontal, future carbon capture, future hydrogen storage change anything?
All of these factors will affect how we deal with incidents whilst drilling. HPHT (High Pressure / High Temperature) wells will have increased pressures (which can increase drilling fluid density due to compressibility) and higher temperatures (which could decrease drilling fluid density due to thermal expansion). Horizontal wells increase formation exposure, leading to larger influxes. The angle of the well will drastically affect how the influx behaves. Storage wells can “charge” formations with the injection of additional fluids, creating abnormal formation pressures.
Discuss human factors in detecting and responding to kicks?
Driller and Crew should be empowered to shut-in the well by quickest means, using the appropriate procedure so they can act fast to secure the well, and confirm that it is secured. Correct and relevant training helps ensure the competency of the crew to identify and react to problems.