Gasified Liquids
Gasified Liquid Drilling Procedures and Operating Considerations
The bottomhole pressure is controlled either by adjusting the bypass choke or nitrogen pump rate if used. Depending on the pit volume, the air rate can be adjusted to reduce or increase the bottomhole pressure. Because of the compressibility of circulating system, pressure response to an adjustment of injection rate takes a certain amount of time.
The following steps should be followed while making connections during gasified liquid drilling:
- Stop gas injection
- Shut down the liquid pumps
- Bleed down the pressure before breaking open a joint
The drilling fluid does not have to be displaced by gas or liquid when annular gas injection is performed.
Tripping
Gas and liquid injection should be shut down during trips. After making sure that the well is dead, the rotating head or rotating BOP can be disconnected.
During a trip, gas may break out of the drilling fluid, forming a gas zone within the wellbore. Once the liquid and gas injection is restored, liquid in the well will start flowing up the annulus. If there is a lost circulation zone, the gasified drilling fluid will probably flow into this zone rather than up the annulus.
Gas injection should be used to reduce the annular pressure and establish circulation, before pumping any liquids into the well.
If hydrocarbons are present, the tripping procedure is more complicated. The BHA can be stripped out of the well while it is flowing, or the well should be killed before the tripping procedure starts. Drill pipe is stripped through the rotating head while allowing the well to flow. Typically, cylindrical collars and larger diameter string components can be stripped through the annular. During this process, the well can be flowed through an open choke to the separator. This also helps to keep the wellhead pressure at a minimum value. Under these conditions, there is always the risk of experiencing a “pipe light” condition, which causes the drill string to be pushed out of the wellbore due to the pressure differential.
Normally, the sealing elements of the rotating BOP can provide the frictional forces needed to keep the string in the hole. If the wellhead pressure is too high a snubbing unit might be necessary to withdraw the string from the well. A portable hydraulic rig assist (HRA), shown in Figure 1, is used for underbalanced drilling with a conventional rig and rotating BOP.
Even though killing the well is not a desired option, it may be the only way to run the BHA in and out of the hole. In that case, the kill fluid should be selected to minimize formation damage. It should be placed on top of the produced crude to reduce a possible damaging contact with the producing formation.
