Current extended-reach-drilling (ERD) well technology limits the well lengths to approximately 12 km, with a horizontal departure of approximately 10 km. This paper presents a concept that enables simultaneous drilling and completion, with an aim to extend well reach substantially and with an ultimate objective of constructing 30-km-long production wells. Longer-reach wells can be used to drain remote reserves using existing production facilities and to provide a means to access reservoirs located beneath environmentally sensitive areas.
The concept introduces a new way of constructing production wells. During drilling, the annulus is closed by packers and the well is drilled to the final target with one hole diameter. A steerable drilling module performs the drilling operation. A dual-wall casing replaces the drillstring and enables the drill cuttings to be transported to surface inside the inner casing. The string does not rotate during drilling but is pulled forward by a multiple-traction system composed of traction modules tentatively spaced at 120-m intervals along the drillstring. Tools for well completion, such as sand screens, sensors, and control systems, are integrated into the dual-wall casing.
System Description
This project investigated two versions of the concept: a casing-drilling system sized for 12¼-in. hole and a liner-drilling version deployed on drillpipe for an 8½‑in. hole size. Recently, the project has focused primarily on the liner version. The developed solutions, however, are applicable to both versions.
The liner concept provides a liner-drilling solution able to extend the well from a pre-existing production-casing-shoe depth. The liner assembly that can be deployed will be limited by the depth of the production-casing shoe and, thus, can enable the construction of wells up to perhaps 20 km in length. The liner is deployed using standard drillpipe; therefore, conventional rig equipment can be used for the drilling/completion operations. In contrast, the full production-casing-drilling concept can drill deeper wells but will require considerable modifications to topside facilities.
The main components of the liner system are a pipe-in-pipe circulation system and multiple hydraulically powered traction units to overcome mechanical friction and provide weight on bit. The liner system is deployed on drillpipe using a running tool that channels the mud supply and cuttings returns in addition to connecting data communication between the surface and bottomhole assemblies (BHAs).
Hydraulic pressure expands the traction-unit packer radially until it is constrained by the wellbore. Once the packer is expanded, traction force relative to the borehole can be applied by supplying drive pressure to either side of the traction-unit sleeve. Depending on which side is chosen, the force will either push the liner into the well or pull it out of the well. During normal operation, the axial force overcomes the friction between the liner and the wellbore and provides weight on bit for drilling. The combination of the packer-expansion pressure and the formation friction factor will govern the maximum axial force that can be delivered. At the end of its stroke, the packer is retracted before repositioning it for a new stroke.
The stroke of the traction unit determines how often the packer has to be anchored and reset. For a 10-km well section, a 2-m sleeve stroke will require 5,000 packer activations.
The inner pipe that passes through the traction unit allows cuttings to return to surface, whereas mud is supplied through the remaining annular space.
Interconnections. A dual-pipe connection system has been designed to enable the liner sections to be made up quickly on the rig floor. The connection incorporates a standard outer-casing joint with a modified collar, an inner production pipe, and an upper and lower inner coupling equipped with an electrical connector and a device for orienting the liner sections during makeup. Once assembled, the inner pipe has a degree of freedom to move axially inside a polished bore, to compensate for differences in temperature between the inner and outer pipe that can result in differences in their relative length.
Drilling BHA. A conventional drilling motor is a candidate for driving the bit for the liner concept, although the operational life will limit the interval that can be drilled. An important advantage with this concept is the drilling BHA being anchored to the wellbore close to the bit. The anchor effectively decouples the drillstring from the dynamics caused by the BHA and drill bit, preventing traditional harmful dynamic drilling dysfunctions, such as bit bouncing, stick/slip, lateral shocks, and whirl. Avoiding such problems will also maximize the life of the bit and the BHA.
An alternative to using mud motors is to use electrical motors, which can have a mean time between failure of thousands of hours.
Power and Control System. A 10-km liner may require up to 80 traction-unit pairs (on the basis of 120-m spacing). The power required under normal operating conditions is low per traction unit. A pulling force of 3.5 t at 10 m/h represents a power of only 100 W. Including system losses, an input power of roughly 200 W would be required and the total power to supply all the traction units would be approximately 16 kW.
A hydraulic line supplying power to all traction units has been considered. However, the pressure drop through the long tubing required would be very high. Instead, multiple motor-driven hydraulic pump units (HPUs) will be required downhole to supply the traction units. An electromotor-powered pump was chosen as a primary solution. The pressure to the different hydraulic functions will be steered by solenoid valves that are electronically controlled from the surface. The HPU, hydraulic control valves, and electronics will be located in the annular space through which the mud is supplied.
In addition to actuating the traction unit, the electrohydraulic controls will steer the different traction units in relation to one another and avoid a “tug of war” or potential lock-up situation.
Production-Inflow Valve. Once the well is completed, production is enabled through an inflow-control section by use of an adjustable piston-type inflow valve, with sand screens symmetrically placed on either side of it. Production enters the annular cavity inside the flow sub through the screens with a flow rate controlled by the piston-valve setting. The valve position is controlled by an electric motor and ball-screw-type gear.
Liner Hanger. For the liner concept, a liner hanger and liner-running tool are required. A design has been modeled that includes a liner hanger and integral liner packer mounted on a one-piece mandrel. An upper polished-bore receptacle is included, enabling a tieback to the upper completion and incorporating the internal profile for a completion latch connection.
Electrical power is generated by a mud-flow-powered turbine driving an electrical power generator inside the running tool.
When total depth is reached, the liner hanger is hydraulically actuated inside the casing. Once the slips are set, the liner packer is set to seal inside the casing. The packer can be set hydraulically by applying pressure inside the drillpipe or by applying weight as a contingency solution. Once pressure tested, the running tool can be disconnected either hydraulically or by right-hand rotation and pulled out of hole.
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