A JIP proves the effectiveness of a new drilling method at IRIS’s Ullrigg facility.
Ola Vestavik and Ove Hole, Reelwell; Stuart Brown, Shell UK
The idea for a new drilling method was born at Rogaland Research, now the International Research Institute of Stavanger (IRIS) in Stavanger, Norway. The idea was motivated by the challenges of solving hole cleaning and weight-on-bit control for coiled tubing drilling applications. After a feasibility study, the method was refined and found applicable to solve several challenges for jointed pipe drilling as well. The patented Reelwell Drilling Method showed unique features for the following applications:
- Managed pressure drilling: Pipe connections can be performed at constant downhole pressure without any shut-in pressure at surface using a downhole valve.
- Liner drilling: A liner can be installed in the same run, while a new section is being drilled. Also, there is an option to expand the liner in the same run.
- Deepwater drilling: Return fluid is transported back to surface through the drillstring, enabling advanced gradients of the annular well fluid.
- Extended-reach drilling: The method generates hydraulic thrust downhole and offers unique hole cleaning capability.
In 2004, Reelwell was founded and acquired intellectual property rights to the technology. A joint industry project to verify the method was then conducted from 2005-2008, funded by StatoilHydro, Shell and the Research Council of Norway. Beginning in 2005, the Research Council of Norway and Statoil funded a feasibility study, which was conducted by Reelwell. In 2006, Shell joined the project and the critical components were built and tested in the laboratory. Last year, a full-scale prototype was tested at IRIS using the research rig, Ullrigg.
The main goal for the project was to verify the:
- Proof of concept and its practical application on conventional drilling rigs
- Capability for hole cleaning and downhole pressure/traction control
- Drill-in liner application and optional liner expansion.
This article presents the basics of the method and the results from the verification program.
NEW EQUIPMENT
The new drilling method is based on a patented drilling fluid flow arrangement. It incorporates a pipe-in-pipe concentric drill, where one conduit is used to pump fluid into the well and the other carries the return fluid from the well. A sliding piston, attached to the drillstring downhole, separates dual-gradient annular drilling fluid and aids in pressure/traction control. Lastly, an optional liner can be inserted while drilling and expanded downhole during the same run. This option enables mono diameter well designs, simultaneously drilling and lining the well.
DRILLING RIG ADAPTATION
The Ullrigg Drilling and Well Centre is a well-equipped, full-scale drilling rig with pumps, mud cleaning system, storage tanks, well-control equipment, 5-in. drill pipe etc. The vertical U1 well was used in the verification program. It has 13 3/8-in. surface casing to 354-m (1,161-ft) MD, and a 12 ¼-in. openhole section to 1,258-m (4,127-ft) MD. A 300-m-long 13¾-in. casing was installed and an 80-m-long cement plug was placed in the casing’s lower part for the drilling tests.
The basic drilling setup uses a top-string adapter, the dual drillstring, a sliding piston, dual float and flow crossover. The setup is the same for both plain and line drilling, with field-proven rotating BOP and under-reamer technology used as enablers of the system, Fig. 1.
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Fig. 1. The verification program tested plain drilling and liner drilling using two different tool sets.
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Plain drilling’s equipment arrangement is shown on the left side of the figure. The sliding piston is attached to the dual drill pipe some distance above the lower BHA. The dual float and flow crossover are positioned at the top of the lower BHA.
Liner drilling’s arrangement is shown on the right side of the figure including: a liner coupling attached to the dual float in the lower BHA, a liner expander, attached to the sliding piston and a liner attached between the liner coupling and the liner expander.
The surface system includes a mud pump, which pumps drilling fluid into the side entry port of the top-string adapter and down the annular drillstring channel. The returning fluid comes back through the inner channel of the dual drillstring and passes through a surface choke system before returning to the shaker and mud tanks, Fig. 2. On the top of the BOP is a Rotating Control Device (RCD), which allows well annulus pressurization while drilling. The upper well annulus, between the sliding piston and the RCD, is pressurized by a pump.
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Fig. 2. This flow schematic of the surface system includes a mud pump, a surface choke system shaker, mud tanks and rotating control device on the top of the BOP.
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The drilling sample consisted of a 300-m-long, 10¾-in. casing assembly hanging in the wellhead. The lower casing joint had a welded steel plug on the bottom end. The casing contains an 80-m cemented section on the bottom, covered by 15 m of sand, which was used for the drilling trials. The sand was removed from the well for inspection after drilling and lining was completed.
A ¼-in. hydraulic control line is installed in the annulus between the 133/8-in. casing and the 10¾-in. casing to measure well pressure while drilling and for kick trials. The upper end of the line is connected to a pressure gauge at surface near the wellhead. The lower end of the line is connected to the inside of the 10¾-in. casing through a hole drilled in the casing at about 200 m depth, i.e. 100 m above the bottom steel plug.
The 10¾-in. casing joints in the drilling sample were point welded in the connections to avoid unscrewing during drilling trials and the casing was locked for possible rotation at the casing hanger by a special arrangement. The 10¾-in. drilling sample was removed from the well after testing.
At Ullrigg, the drilling fluid flow arrangement was modified, Fig. 3. The fluid is pumped into the side entry port of the top-string adapter through a separate 2-in. hose from the pump manifold. The return flow from the well comes from the top of the top-string adapter, through the main mud hose. From the standpipe the fluid flows through a 2-in. hose via the choke and down to the normal return-flow conduit.
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Fig. 3. At Ullrigg, the drilling fluid flow arrangement was modified so that the return flow from the well comes from the top of the top-string adapter, through the main mud hose.
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TOOLS AND EQUIPMENT
The following tools were used for plain drilling. The top-string adapter is positioned at the top of the dual drill pipe. This adapter contains a swivel and has one flow port to allow pumping drilling fluid down into the well and another port for the return flow from the well. The top-string adapter is attached to a hose for the side-entry inflow and is attached to the conventional swivel in the travelling block for the return flow.
The dual drill pipe is a conventional 5-in. drillstring that was modified with inner pipe inserts in a patented arrangement. This allows for quick and easy modification of a conventional drillstring into a dual drillstring at the wellsite.
The sliding piston is attached to the dual drill pipe downhole. It is arranged to always run inside the casing, and isolates the well annulus outside the dual drillstring. The piston allows for bypass flow when required, but also allows pressurization of the well annulus between the piston and the BOP/RCD. This arrangement converts the well into a hydraulic cylinder, where the sliding piston is the cylinder piston and the dual drillstring is the cylinder rod. The sliding piston allows the use of different fluid properties below and above the piston. Thus, it is possible to have a high-density kill mud in the well above the sliding piston, while the fluid in the well below the sliding piston is a lower density active circulation fluid.
The dual float is a patented automatic pressure-operated valve positioned at the lower end of the dual drill pipe. This float enables simultaneous closure and opening of both drillstring channels. In the failsafe default position, the valve closes both channels. The float enables downhole isolation of the well and thus pressure-less connections at surface during Managed Pressure Drilling (MPD).
The data acquisition and sensor package contains pressure sensors and flowmeters. The in-flow meter is mounted at the standpipe manifold and the return flowmeter is mounted at the exit of the return choke. The system has built-in computer models for diagnosis and control.
The RCD was rented from Weatherford, a Williams model 9000. The tool is a simple, passive RCD with a 500 psi maximum pressure rating.
The upper annulus control consists of a pump set up for a maximum flow of about 400 liters per minute (lpm). The pump is remotely controlled from the driller’s cabin.
The return choke was a remote dual choke, rented from Ullrigg. The choke panel was positioned next to the driller cabin to ensure easy communication between the driller and the choke operator.
LINER DRILLING TOOLS
Several additional pieces of equipment are needed for liner drilling. The liner expander is a patented system. The liner coupling is also patented and allows for the coupling of the liner to the drillstring with built-in switches for flow and rotation control.
The under-reamer, a DTU 7200, was rented from Smith. The under-reamer was mounted directly to a 7 7⁄8-in. tri-cone drill bit from Smith. This tool opened the hole from 7 7⁄8-in. to 9 1⁄2-in.
The spider acts as a secondary drill floor and enables the setting of slips on the drill pipe when running the drillstring through the 8 5⁄8-in. liner, while the liner hangs in slips at the drill floor. It was rented from Odfjell.
Ullrigg was set up for rotation with a hexagonal kelly. The kelly was modified with an inner string to match the inner string in the dual drill pipe. The top-string adapter was mounted on the top of the kelly.
RESULTS
After the 10¾-in. casing sample was installed and the BOP was mounted, the drilling sample was pressure tested to 270 bar against the closed BOP shear ram. The RCD was installed and tested prior to drilling.
Figure 4 presents the results from the initial pressure tests of the upper annular volume in the well, i.e. the volume enclosed by the following surfaces: in the radial direction between the outside of the dual drill pipe and the inside of the 10¾-in. casing, and in the axial direction between the closed annular BOP and the sliding piston.
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Fig. 4. During the annulus test, the hook load increases in steps according to the increase in the annular pressure, demonstrating the hydraulic force transfer capability of the sliding piston.
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During the test sequence, the pressure in the well annulus was increased stepwise to 50 bar using the upper annulus control pump. The test was performed with continuous circulation through the drill bit. The hook load increased in steps according to the increase in the annular pressure demonstrating the hydraulic force transfer capability of the sliding piston to the hook load. It also demonstrates the sealing capability, since there was no need to supply fluid to hold the pressure.
When the drillstring is first lowered into the hole, and then pulled out of the hole, the return flow from the well responds immediately when moving the drillstring, Fig. 5. When not moving the drillstring, the return flow and the inflow have equal value. When moving the drillstring into/out of the well, the return flow increases/decreases respectively, due to the added closed-end steel volume that is lowered into the well.
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Fig. 5. When moving the drillstring inside the well, the return flow responds immediately when the drillstring is moved.
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The figure shows that differential flow can be measured precisely and that the sensitivity to detect kick and drilling fluid loss is high. The resolution in measuring the volume changes by the differential flow arrangement is judged to be less than 10 lpm, i.e. very precise and fast compared to conventional detection methods.
Drilling trials. Figure 6 presents the records from drilling one drill pipe joint through the cement plug using the plain drilling system. The pipe joint was drilled down in 40 min. with ROP up to 20 m/hr. The return flowrate is generally slightly higher than the inflow rate during drilling. Spikes occur in the return flow measurement at startup, and occasionally in the following minutes due to pipe movements etc. Occasional leaks were observed on the RCD during the trials, especially when the tool joints passed through the rubber sealing element.
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Fig. 6. When drilling the cement with the plain drilling system the return flowrate is slightly higher than the inflow rate.
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Cuttings transport. The cuttings are particles with a maximum size of a few millimeters. However, in some instances particles of 1-3 cm were produced and efficiently transported to the surface during drilling operations.
The demonstration program verified efficient transport of solids up to 10% concentration by volume. No plugging of the return flow conduit occurred during the tests. This demonstrates very high cleaning efficiency, and indicates the potential of the method to solve hole cleaning problems experienced in the field. The surface choke once showed a tendency to accumulate cuttings; however, it was successfully cleaned by flushing.
Downhole pressure control. The pressure control system in the upper annulus above the sliding piston operated efficiently and reliably. When drilling, downhole pressure is determined by the drilling fluid density and the dynamic friction component in the return flow. When the pump is stopped, the dynamic component is zero.
To keep constant downhole pressure in the well while the mud pump is stopped, pressure regulation is done by choking the return flow. After the dual float is closed, pressure in the well is isolated downhole by the sliding piston and the dual float. Thus, during connections there is no surface pressure.
When restarting circulation after the connection, the dual float is again opened, and the circulation flowrate is established and adjusted, so that all required choking is performed through the return conduit and little or no choking is performed at the surface. The system’s capability to keep the downhole pressure near constant during connections was successfully proven during the test program.
Controlling influx and loss. Proper well control was demonstrated by precisely measuring the gain/loss from the well, controlling gain/loss rapidly by choke or flowrate control and by closing the dual float to isolate the well at depth. The flow sensor arrangement enabled fast and precise detection of kick and loss, and both control methods were successfully demonstrated. The ability to avoid loss of the annular well fluid above the sliding piston was demonstrated in the pressure tests. The establishment of detailed well control procedures and the certification of tools are ongoing.
Pipe handling. Figure 7 presents the situation while handling dual drill pipe, showing a connection at the drill floor. In general, the pipe handling was performed without any large difficulty or problem. Prior to operations, the return pipes were individually adapted and inserted into the conventional 5-in. drill pipe. The handling of the dual drill pipe then followed procedures similar to conventional pipe handling. The dual drill pipe was handled efficiently in singles, and was also racked in stands into the derrick.
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Fig. 7. Prior to the drilling, the return pipes were individually adapted and inserted into conventional 5-in. drill pipe.
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Liner drilling. Drilling with liner was difficult because of a failure in the under-reamer tool. The only available tool, suited for our application, was used elsewhere prior to the test. The failure implied that the under-reamer arms did not open the hole to the required size. Drilling engineers decided to stop when the liner was drilled about 20 m into the new section. The liner was then expanded to hang in the 10¾-in. casing and released from the drilling BHA. After liner release, the drillstring was pulled to the surface, leaving the 85 m long liner section downhole as planned.
Tool performance. The top-string adapter worked without any problems throughout the test period. The sliding piston showed excellent performance. The results indicate that 30 bar of backpressure gives about an extra 10 tons on the hook. The hook load increase represents a hydraulic force provided by the sliding piston, which can be converted into a downhole thrust force. The large potential and capacity for hydraulic WOB was thus proven.
The dual float was subjected to an extensive test program in the laboratory. The tool experienced a leakage during the first part of the tests, due to a failure in the opening procedure. However, the tool was repaired and performed according to specifications during the rest of the trials. The tool has proven to be efficient for downhole pressure control.
The liner expander performed well in several tests and the combination of the liner expander and the sliding piston proved to be a very efficient liner expansion system. The liner coupling also showed good performance during the trials. After pulling out of hole, the liner coupling was in good condition, and the primary mechanism for liner release was proven.
CONCLUSION
The new drilling method was successfully proven during the verification program, demonstrating that the sliding piston provides weight-on-bit by hydraulic means and prevents loss of the annular well fluid. Hole cleaning was efficient and could transport large cuttings in the returns. Gain/loss volumes of less than 1:100 were rapidly detected. Downhole well isolation was good and only small pressure fluctuations occurred during pipe connections. Drilling with liner was shown to be feasible, including liner hanger expansion and release from the liner after drilling.
All components of the drilling system have proven acceptable performance. The verification program was challenged by a hole diameter less than planned, due to an improperly working under-reamer. This issue will be solved in future applications.
The verification program has confirmed the practical application of this new drilling method. It also has large potential for MPD, for challenging pressure zones and depleted reservoirs. The method also has special features for extended-reach drilling and for deepwater applications. The next step is to demonstrate the method for deeper drilling in an onshore well. 
ACKNOWLEDGEMENT
The authors thank the Research Council of Norway, Shell and StatoilHydro for their support and funding of the development and test program. Special thanks are extended to Bernt Pedersen and his colleagues in Shell, and to Scott Kerr, Alastair Buchanan, Tore Welzin, Arne Torsvoll, Jafar Abdollahi and their colleagues in StatoilHydro for valuable input during the planning and execution of the verification program. Thanks also to Per Simensen and his colleagues at IRIS for their constructive cooperation, to other cooperating companies and colleagues for their efforts.
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THE AUTHORS
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Ola Vestavik earned an MSc in physics at the Norwegian Institute of Technology and a PhD in petroleum from Technische Universität Clausthal. He has 24 years of experience in drilling and well technology, starting at Rogaland Research and then to Statoil in 1996 as staff and operations engineer in drilling and well technology. In 2004, Vestavik founded Reelwell at ipark in Stavanger, Norway, and has since then been General Manager and Project Manager for the drilling method’s development.
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Ove Hole earned a MSc in petroleum engineering from Stavanger Universty. He has 23 years of experience in detail engineering for drilling equipment and drilling operations. He also has experience in project management as a team member for newbuild and modification projects for drilling and FPSO vessels. Hole joined Reelwell in early 2008 and is Marketing Director for the Reelwell Drilling Method.
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Stuart Brown earned a BSc in Eng Science from Aberdeen University. He has 32 years of oilfield experience, starting his career with Baker Oil Tools as Design Engineer for downhole tools. In 1978, he joined Shell Well Services, testing/installing subsea equipment, planning and executing well tests and as Offshore Drilling Supervisor on semisubmersible rigs. Brown now promotes emerging technologies and drilling innovation and is presently working as part of a team to economically recover Central North Sea reserves.
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