Managed pressure drilling episode 5
4- Controlled Mud Cap System:
A newer drilling concept that is still being tested, this system is similar to the pressurized mud-cap system except that the level of the mud cap is adjusted by a mud pump to better manage the bottom hole pressure.
Fig. 2.Controlled mud cap setup (From Juvkam-Wold).
Fig. 2 shows a basic setup of this system for a well being drilled in deepwater. A 12.5 in. ID riser is run. A subsea mudlift-pump is connected to the riser by a riser-outlet joint. The outlet joint has high-pressure valves that enable it to isolate the pump system from the riser. The pump is connected to the mud pits by a return and a fill line. This allows the pump to increase or decrease the amount of mud in the riser. To determine the level of the mud in the riser, pressure sensors are located throughout the riser. The drilling riser is filled with air above the mud cap.
The basic concept of this system is to compensate for ECD and thus manage the BHP. In single-phase flow, to compensate for friction pressure fluctuations related to factors such as pipe connections and circulation rate, the height of mud in the riser will be adjusted. This system enables a driller to compensate for ECD at a specific depth in the open hole section.
For multiphase flow, Jenner, J.W. is currently working on a simulator to calculate the pressure profile throughout the wellbore annulus. This simulator is also being designed to predict the amount of hydrocarbons in the drilling riser as a function of time to prepare the crew to take the necessary action.
The main challenge with this system is to compensate for the hydrostatic pressure that is caused by the standing column of mud in the drill pipe. Having a full column of mud with the subsea BOP closed would cause the BHP to become higher than the fracture pressure. This is due to the system using a higher mud weight than is used in conventional drilling. A u-tube effect occurs where the mud in the drill pipe flows into the annulus until the pressure equalizes between the annulus and the drill pipe.
One way to neutralize this effect is to have a pressure differential valve in the drill string. The valve would be open at a predetermined pressure and compensate for the static imbalance between the drill pipe and the annulus. The valve would be closed if the pressure in the annulus is lower than the pressure in the drill pipe. This blocks the annulus from being affected by the standing column of mud when the subsea BOP is closed.
To show the advantages of CMC (Controlled Mud Cap system), Jenner ran a case to show how much gas each method can circulate out of the well without fracturing the weakest formation in the open hole. This is referred to as kick margin (KM). The case is for a vertical well and in 4100 ft of water depth. The test also assumed that the weakest formation is at the top of the openhole section and the influx is bubble flow. This case involves drilling an 8-1/2-in. hole from the casing shoe at 7550 ft to 12500 ft.
The Following Table shows the results of the case:
From the results we can notice that:
- The differential pressure between fracture pressure and borehole pressure at the casing shoe is significantly higher for the CMC method. This means that the operating window for the CMC method is larger.
- The kick margin is also higher, meaning that this method can handle a larger volume of gas flowing into the wellbore.
- The other two methods have low kick margins and thus may have to stop drilling and have a casing point at a higher level than the CMC method.
In sum, CMC method has many advantages. A driller is able to control downhole pressure almost instantaneously by adjusting the height of mud in the riser. Hydrocarbon influxes can be controlled and circulated out with ease. This system also can act as either a closed or open system, depending on what is needed.