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Downhole equipment for UBD operations
Successful underbalanced drilling (UBD) requires downhole equipment to provide real-time information to the surface for monitoring conditions during drilling operations.
Pressure while drilling (PWD) sensors
Pressure while drilling (PWD) sensors have proved invaluable in every UBD operation to date, when they have been included in the drillstring and operated without downtime. However, quite a number of these sensors have proved problematic, because of the vibration problems and fast drilling rates encountered with UBD. Adding a downhole gauge or sensor on the injection side and in the drillstring has a few of the following benefits: enhanced UBD operation, help optimize the drilling process, and increase the operator’s knowledge of the reservoir.
Conventional measurement while drilling (MWD) tools in UBD
The most common technique for transmitting measurement while drilling (MWD) data uses the drilling fluid pumped down through the drillstring as a transmission medium for acoustic waves. Mud-pulse telemetry transmits data to the surface by modifying the flow of mud in the drillpipe in such a way that there are changes in fluid pressure at surface. It involves the sequential operation of a downhole mechanism to selectively vary or modulate the dynamic flowing pressure in the drillstring, and sends the real-time data gathered by the downhole sensors. This variation in the dynamic pressure is detected at the surface, where it is demodulated back into the real measurements and parameters from the downhole sensors.
Signal strength at the surface depends on many factors including, but not limited to:
- The mud properties
- Drillstring arrangement
- Flow rate
- Signal strength generated at the tool
- Telemetry frequency
Experience to date indicates that this enhanced mud-pulse telemetry system is best applied to scenarios with a maximum gas percentage of 20% (by volume at the standpipe), and this ratio can be extended somewhat depending on a number of factors, including:
- Well depth
- Liquid-phase fluid
- Drillstring/bottomhole assembly (BHA)
- Pumping pressure
- Flow rates.
Further reductions in borehole pressure are possible with gas lift applications in which N2 is injected into the annulus. A major disadvantage of the mud pulse is that it will not work if high-quality foam is needed. For such fluids, an electromagnetic method must be used.
If annular gas injection is used, we have a single-phase fluid down the drillstring, and conventional MWD systems can be used. If drillstring gas injection is considered, the option of using electromagnetic MWD tools must be considered.
Electromagnetic measurement while drilling (EMWD)
Electromagnetic telemetry transmits data to the surface by pulsing low-frequency waves through the Earth. The first application of PWD measurements has been primarily for drilling and mud performance, kick detection, and equivalent circulating density (ECD) monitoring.
Float valves are necessary for UBD to prevent influx of reservoir fluids inside the drillstring either when tripping or making connections. It must be recognized that there is pressure below nonreturn valves. The positions of the float valve in the drillstring depend on the tools in the bottomhole assembly (BHA) and the policy of the operating philosophy underpinning the safety management of the operation. The number of float valves in the BHA and the drillstring is also a matter of company policy consistent with perceived risks and management thereof. If the drilling float valve(s) should all fail, the well may have to be circulated to kill weight fluid, and a string trip undertaken to replace or repair the float valves.
It is good practice to install a float valve in the top of the drillstring, often referred to as the string float valve, because it aids operational efficiency by reducing the time it takes to bleed off the pressure before making connections while also serving as an additional barrier in the event of a failure of the float valves in the BHA. This top valve is often a wireline retrievable float valve that can be retrieved, as access through the string is required. In general, a double float valve is installed just above the BHA, and a further double float valve is installed above the bit so that there is redundant service. Two types of non-ported drillstring floats that are commonly used are the flapper and plunger floats.
The underbalanced deployment valve has been designed to eliminate the need for snubbing operations or the need to kill the well to trip the drillstring during UBD operations. During UBD operations, the well is allowed to flow. The result is a flowing or shut-in pressure in the annulus at surface. With any significant pressures while tripping the drillstring, it has been necessary to either use a snubbing unit or kill the well.
The deployment valve is run as an integral part of the casing program, allowing full-bore passage for the drill bit when in the open position. When it becomes necessary to trip the drillstring, the string is tripped out until the bit is above the valve, at which time the deployment valve is closed, and the annulus above the valve bled off. At this time, the drillstring can be tripped out of the well without the use of a snubbing unit at conventional tripping speeds, reducing rig time requirements, and providing improved personnel safety. The drillstring can then be tripped back into the well until the bit is just above the deployment valve. After this is completed, the deployment valve can be opened, and the drillstring run in to continue drilling operations.
The deployment valve can either be run with the casing using an external casing packer for isolation, or with a liner hanger and tieback. Once installed, the valve is controlled through pressure applied to the annulus, created between the intermediate and surface casing. The valve can also be controlled through dual control lines. When using a snubbing unit, the operator not only has to consider the actual cost of the snubbing service, but should also include rig-up and rig-down time together with the increased tripping times to determine the overall daily drilling costs.