Horizontal Drilling With Dual-Channel Drillpipe
new drilling method provides a solution for challenges encountered in drilling of long horizontal wells, incorporating a dual drillstring with a separate channel for the return fluid from the well.
A new drilling method provides a solution for challenges encountered in drilling of long horizontal wells, incorporating a dual drillstring with a separate channel for the return fluid from the well. This arrangement enables managed-gradient drilling (i.e., to drill with a constant downhole pressure gradient that can be controlled to be nearly independent of the flow rate). The solution is similar to managed-pressure drilling (MPD) but differs in that the downhole pressure gradient is managed instead of the pressure at one depth in the well.
The technology for drilling and completion of long horizontal sections has improved significantly in recent years. However, challenges such as hole cleaning, equivalent-circulating-density (ECD) control, and torque-and-drag reduction still exist. ECD is linked to hole cleaning and is often a limiting factor. Long-reach horizontal wells can also be limited by the torque and drag of the drillstring.
The dual-drillstring configuration has specifically been developed to provide solutions to these challenges,as follows:
- Hole cleaning: Drill cuttings are removed from the bottom of the hole through a separate flow channel inside the drillstring.
- ECD control: Managed-gradient drilling creates a constant downhole pressure gradient independent of the flow rate.
- Torque and drag: A heavy-over-light fluid solution reduces torque and drag through buoyancy.
Fig. 1 presents a schematic of the drilling-fluid flow for this arrangement. The dual drillstring allows drilling mud to be pumped down the annulus inside the drillpipe, with the return flow up the concentric inner pipe. The system can be installed on a standard drilling rig. A topdrive adapter connects the rig’s topdrive to the top of the dual drillstring. The adapter contains a swivel that allows for pumping mud into the drillpipe annulus and for the return flow from the inner pipe to be directed back to the surface mud system. The lower end of the dual drillstring connects to a standard bottomhole assembly (BHA) by means of an inner-pipe valve, which contains entrance ports for the return fluid and isolates the well during pipe connections.
The dual-drillstring configuration allows two different types of fluid to be used in the well during the drilling operation. A low-density and low-viscosity active drilling fluid is circulated inside the dual drillstring and around the BHA and is optimized for efficient cleaning capability and ECD control. The annulus outside the dual drillstring is filled with a near-static passive fluid, preferably a fluid optimized for torque-and-drag reduction and for downhole pressure control.
This heavy-over-light configuration results in the passive well-annulus fluid having a greater density than the active fluid inside the dual drillstring. When using the heavy-over-light solution, the dual drillstring is exposed to positive buoyancy forces because of the differences in fluid densities inside and outside the string. The buoyancy forces result in a reduction of wall-contact forces, thereby leading to a reduction in torque and drag during drilling. Additionally, the heavy-over-light solution means that surface backpressure on the well annulus can be kept low during operation, enabling managed-gradient-drilling operations to be performed with little or no wellhead casing pressure.
An onshore wellsite in Alberta was selected for a verification of the new technology. The target for the horizontal well was a zone between approximately 450- and 470-m true vertical depth (TVD) predicted to be a relatively homogeneous sand with no hydrocarbons and therefore suitable for the trial well. The rig was capable of handling Range 3 drillpipes. The flow-control unit, installed in the driller’s cabin, enables remote control of system functions, data logging, and sensor monitoring. The control-unit software provides automated procedures for pump startup, shutdown, pressure control on selected set points, and alarms with associated recommended actions.
Two different types of dual-channel drillpipes were used during the operation: 6⅝-in. steel dual drillpipes, mainly for use in the vertical section of the well, and new aluminum dual drillpipes, mainly for use in the horizontal section of the well. The intermediate 13½-in.-hole section was directionally drilled with conventional 5-in. drillpipe to 803-m measured depth (MD) and 465-m TVD. The 10¾-in. casing was cemented in place, and formation integrity was tested.
The specialized dual drillstring combined with a conventional rotary-steerable-system BHA was used for drilling the 9⅞-in. horizontal section. A 1.1-specific-gravity (sg) water-based drilling fluid was used for both active and passive fluids to a depth of 1100-m MD. The fluid in the annulus outside the dual drillstring was then displaced to a 1.6-sg-density fluid to continue drilling the horizontal section in heavy-over-light mode. The remaining section to the target at 1510‑m MD and 452-m TVD was drilled in this mode with active/passive-fluid densities maintained at 1.1 sg and 1.6 sg, respectively. The effect of the heavy-over-light fluid configuration on torque and drag was measured at total depth. Torque-and-drag readings were obtained first with the 1.1-sg/1.6-sg light/heavy fluid configuration. The well was then displaced to 1.6 sg in the well annulus and in both channels of the drillstring, and the measurements were repeated.
The well-control procedures with the dual drillstring were tested as a last part of the trial. After setting a bridge plug in the 10¾-in. casing at 783 m, nitrogen was displaced through the dual drillstring and trapped in the casing at the plug to create a volume of 430 L of compressed gas. During the subsequent circulation, the nitrogen was detected and circulated out of the well successfully in accordance with the established well-control procedure. The well was then abandoned in accordance with local regulations. Results of the operation are described in detail in the complete paper.
The drilling operation from spud to abandonment was completed in 15 days, which went according to plan. There was no downtime on the downhole drilling tools and equipment during the operations. All the planned activities were conducted as per the program.
The surface and downhole logging results show that high rates of penetration were obtained at relatively low flow rates when compared with values seen in conventional drilling, which demonstrates the capability of the dual-drillpipe system to drill and clean the hole effectively. The results indicate that the downhole pressure gradient is held constant to within 50 kPa during starting and stopping of the mud pumps. Detailed analysis of the downhole pressures indicated that the pressure variations during connections were in the range of 5 bar, when using start/stop times for the pump of 1–2 minutes under auto-mated mud-pump-control procedures. If necessary, smaller pressure variations can be achieved by taking longer to ramp up from pump startup to full circulation flow. The torque-and-drag measurements show that the torque of the drillstring was reduced by approximately 30%, which is in agreement with the model.
Large cuttings were observed at the shale shaker when drilling hard stringers while approaching the final well depth. Normally, the cuttings were very fine and had a particle size of less than 1 mm. The observed large cuttings may have been created as a result of bit vibrations when drilling the hard stringers because of relatively large cutter elements on the bit. It is interesting to note that the bottoms-up transport time for the cuttings is estimated to be 9 minutes at total depth. Hence, the large cuttings may be very valuable for formation evaluation while drilling. In this regard, too, the dual drillstring differs from conventional drilling, during which much of the information from the cuttings is lost because of long transport times and the grinding and mixing during transport in the well annulus.
A steady increase of the drilling-fluid density is evident as a result of fines accumulating during the drilling process. The small increase in the fluid density for every joint being drilled clearly shows the effect of the cuttings on the return-flow density, and also proves the efficient cuttings-transport capability. Laboratory analysis of the mud samples confirmed that the buildup of fluid density was caused by drilled solids, and was not a result of intermixing of barite from the heavy fluid when performing the heavy-over-light operation in the last part of the well.
The pressure- and flow-measurement recordings made during the well-control trial demonstrate the ability to detect gas in the well quickly with the Coriolis flowmeter. The ability to monitor the flow and downhole pressures using the static conduit in the dual drillstring was also verified. The ability to circulate gas out in a controlled and safe manner was proved by the two well-control trials performed.
Conventional MPD imposes a dynamic pressure gradient on the well annulus that may require installation of a casing or liner when the dynamic pressure exceeds the downhole pressure window. Managed-gradient drilling, enabled by the dual-conduit drillstring, can, by adjustment of flow rates and surface choking, provide a constant pressure gradient at all times, independent of whether the pumps are running or not. Managed-gradient drilling is thus capable of overcoming section-length limitations associated with conventional MPD.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 184683, “Horizontal Drilling With Dual-Channel Drillpipe,” by O.M. Vestavik and J. Thorogood, Reelwell; E. Bourdelet, Total; and B. Schmalhorst and J.P. Roed, DEA Deutsche Erdoel, prepared for the 2017 SPE/IADC Drilling Conference and Exhibition, The Hague, The Netherlands, 14–16 March. The paper has not been peer reviewed.