Known as an underbalanced condition, this occurs when, in the wellbore, formation pressure is higher than the hydrostatic pressure and this lead to a well control situation. To overbalance formation pressure, the required hydrostatic pressure is normally provided through an adjustment in drilling fluid density. Hydrostatic pressure loss can occur for a number of reasons;
- ECD loss
- Surface drilling fluid dilution
- Cement density reduction
- Drilling process releasing formation fluids
- Weighting material movement from mud cleaning equipment
- Drilled cuttings or mud weighting materials settling
Since a reduction in the density of mud returns is sometimes happened, most wells are designed to have sufficient overbalance to encounter the small reduction of mud density and this should prevent a kick. However, if there is significant mud weight reduction, an investigation shall be performed to find any root cause and provide any preventive actions.
Causes of mud weight reductions are as follows;
1. Surface Drilling Fluid Dilution
What potential issues could initiate a kick? One possible problem could be, in the surface pits, a dilution of drilling liquid (normally accidental with the mud column receiving drilled-up, low-density formation fluids or make-up water).
Unfortunately, insufficient fluid density can be caused by poor pit discipline. To ensure the maintenance of fluid density for the fluid that’s pumped downhole, diligence is essential at all times. Without diligence, a leaking valve may not be noticed and this may create extra water. Elsewhere, it’s possible to open the wrong valve (pump suction manifold) and this leads to a tank of light weight fluid being pumped.
2. Cuttings or Mud Weighting Materials Settling
A reduction in mud density can also be caused by the settling of solids (in the mud settling); the same is also true when the bottom of the hole is filled with cuttings that have settled. When either of these occur, hydrostatic pressure reduces in the wellbore and this can cause a kick in the well.
When mud weighting materials settle in the wellbore, this is called ‘barite sag’ and it can occur in vertical wells (especially during non-circulation periods); this being said, it’s more common in extended and highly-deviated reach wells. Most experts believe barite sag can never be eliminated but there are various management techniques including pipe rotation maintenance, good mud design, and low annular velocity avoidance.
3. Releasing Formation Fluids (Influx) into Drilling Mud
It’s incredibly hard to avoid mud contamination when drilling through a formation. if the formation being penetrated is overbalanced, contamination can still occur. From the cuttings, this mud can combine with gas called ‘drilled gas’. The rate at which the drilled gas enters the mud will depend on formation porosity, rate of penetration, pressure, hole diameter, and gas saturation.
When a permeable formation with higher pressure than the pressure exerted by the mud column is drilled, this can cause a kick. When the mud has large amounts of gas entering into a wellbore, average mud density will fall and hydrostatic pressure from the drilling fluid will also reduce.
Over the years, the industry has learned that shallow gas blowouts in offshore environments can be caused by excessive gas cutting in shallow holes. Therefore, shallow holes must have controlled ROP. In order to disperse all gas in the mud, maintenance is also important for high pump output; this should keep variations in mud density to a minimum.
From cuttings or swabbing, the wellbore can often be invaded by salt water and oil which can cause a kick after decreasing the average density of the mud. Of course, liquids (oil and water) are heavier than gas and the average density isn’t affected as greatly for the same downhole volumes. When circulating them out, little expansion (or none at all) will occur as liquids are only slightly compressible. Compared to mud cut by gas, the decrease in bottomhole pressure is significantly greater when saltwater or oil invasions are measured at the surface since this causes a given mud weight reduction. When cut by a liquid, density reduction throughout the mud column can be more uniform.
4. Cement Density Reduction
Often, kicks can occur while mixing and pumping cement.Why does this occur? Typically, it happens when hydrostatic pressure of the fluid column reduces in the wellbore. Although most common cement density reduction is happened by improper mixing, there’s also a potential of cement density being cut by gas or formation water and this contaminates the slurry. If hydrostatic pressure reduces below formation pressure, the kick will be influx into the well. It’s important to find the cause which is normally one of the following;
- A loss of hydrostatic pressure can often result from lost circulation when the cement density is higher than normal.
- In many cases, there has been a failure in float equipment and this allows drilling fluid to U-tube up the casing. Within the annulus, there’s insufficient hydrostatic pressure.
- Normally, a flush or spacer will be pumped ahead of the cement; without the right density, the well can start to flow.
- It’s important to pay attention to right-angle and time, manner time, and the percentage of free water with cement design.
During cementing operation, the well needs to be monitored closely through every single phase. Until you can be absolutely sure there’s no danger of the well flowing, the BOPs should never be nippled down.
Additionally, when cement is in transition period (forming the bond), it will lose some hydrostatic pressure because cement becomes solid phase therefore water in the cement will provide hydrostatic pressure. During the cement transition period, there is a chance that hydrostatic pressure is less than formation. More details can be found here – Cement Transition Period in The Oil Well Can Cause Well Control Situation
5. ECD Effect Loss
Equivalent Circulating Density (ECD) lose when there is no flow. To make a connection, the pumps need to be shut down and this reduces bottomhole pressure until it eventually matches static bottomhole pressure (hydrostatic pressure). At this point, there is no annular friction so ECD is equal to hydrostatic pressure. When the ECD effect is lost, it’s much easier for fluids and formation gases to enter the wellbore. If the well is at slightly underbalance condition, formation gas/fluid cannot enter into a wellbore while drilling because ECD is higher than formation pressure. However, when pumps are off, gas can flow into the well while making up a connection. You can see a gas peak showing at similar stroke so this is called a ‘connection gas’. Practically, the trip margin should always be maintained to a level equal to the ECD value (at least). This way, bottomhole pressure can be maintained just above the formation pressure when the pumps are shut down. Too much connection gas will lead to excessive gas cutting which, in turn, will cause a kick by reducing bottomhole pressure.
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