COILED TUBING USED FOR SLIM HOLE RE-ENTRY

Eric Traonmilin
Elf Aquitaine
Paris

Ken Newman
Dowell Schlumberger
Montrouge, France

A coiled tubing unit with slim hole tools successfully re-entered and cored an existing Elf Aquitaine vertical well in the Paris basin in France.

This experiment proved that coiled tubing could be used to drill, core, and test a slim hole well.

Elf Aquitaine studied the use of coiled tubing for drilling inexpensive exploration wells in the Paris basin. As a result of this study, Elf believed that coiled tubing exploration drilling could significantly reduce exploration costs. 1

The study raised a number of questions:

Can coiled tubing be used effectively to drill slim open hole?
How would the drilling rate compare with a that of a conventional drilling rig? If the rate were too slow, coiled tubing drilling might not be economical.
Can a straight vertical well be drilled?
Coiled tubing pipe has a residual curvature from bending over the reel and gooseneck. Will this curvature make it impossible to drill straight?
Can the coiled tubing also be used to take cores?
Once the hole is drilled, can it be tested with coiled tubing?

Coiled tubing has been used for a number of years to drill out scale, cement, and fill in cased hole workovers. The use of coiled tubing to drill open holes has several benefits: reduced cost, underbalanced drilling, continuous pipe, and improved communication while drilling. Open hole drilling with coiled tubing has a number of applications:

Re-entry to deepen existing vertical wells
Re-entry to drill horizontal laterals to improve reservoir drainage
Inexpensive slim holes for exploration
Inexpensive slim holes for production-large coiled tubing (2 in. or 2-3/8 in.) may be used for drilling and then cemented in place to complete the well
Underbalanced drilling through the zone of interest, even if a conventional rig is used to drill most of the well
Drilling the last (smallest) portion of the well to reduce the trip time once a conventional rig has drilled most of the well.

In many cases, a coiled tubing unit is less expensive to operate than a drilling rig. The drill pad, road construction, transportation, and disposal costs can be reduced for a coiled tubing operation. Continuous coiled tubing allows running in and pulling out of the hole at rates in excess of 50 m/min (165 fpm). When numerous trips are required to replace motors or bits or to retrieve cores, coiled tubing can significantly reduce drilling time. With continuous pipe, it is not necessary to stop mud circulation to makeup or breakout joints and, therefore, joint-related problems are eliminated.

The reduced footprint, noise, and disposal problems associated with slim holes minimize the environmental impact of the drilling operation.

Because pipe handling is not necessary and full pressure control can be maintained, coiled tubing drilling can improve the safety of the operation.

With a logging cable located inside the coiled tubing, it can push logging tools into highly deviated wells. The coiled tubing logging technique can be used to allow electrical monitoring and control of the bottom hole assembly (BHA). Measurements while drilling and logging while drilling can be greatly improved with the ability to convey power and communicate through a logging cable.

EXPERIMENTAL WELL

Elf and Dowell Schlumberger formed a small project team to conduct a coiled tubing experiment which involved deepening an existing vertical well, the Saint Firmin 13 (Fig. 1). The use of an existing well avoided the problem and cost of having to set casing. Because there were wells adjacent to and deeper than Saint Firmin 13, Elf had a thorough knowledge of the formation types that would be drilled. 1

The basic plan for the project included the following:

Use the coiled tubing to squeeze cement into the perforated zones of Saint Firmin 13.
Drill a 98.4 mm (3-7/8 in.) vertical hole from the total depth (TD) of 642 m down to 1,288 m. Deviation measurements would be taken every 150 M.
After reaching TD, a 15-m interval would be cored and the well would be logged.
The formation selective treatment system (FSTS) would be used to straddle a section of the Dogger carbonate formation and perform a flow test while measuring the pressure between the straddle packers.

Neither Elf nor Dowell wanted to invest in specialized equipment for this experiment. Therefore, existing equipment was used as much as possible to keep the costs low. The following is a list of the surface equipment chosen for the experiment.

A standard coiled tubing unit with an injector capable of pulling 178 kN (40,000 lb), with a 78-mm ID stripper and blowout preventer (BOP)
A string of 1,829 m of 38 mm (1.5 in.) coiled tubing with a 3.96-mm wall thickness. (This short, heavy-wall coiled tubing string was chosen to reduce the mud friction pressure loss and to withstand the torque applied to the coiled tubing by the motor.)
A trailer for transporting the coiled tubing unit with a pedestal crane used to handle the BHA and install the injector on the wellhead *A derrick substructure from a workover rig for use as a work platform (Fig. 2)
A skid with three mud tanks with a total capacity of 28 cu m and two centrifugal solids separators
A mud logging system which measured penetration rate, mud pit levels, gas detection, and gas chromatography
A standard pump truck for pumping the mud and cement.

The major downhole tools included the following: a standard 98.4 mm polycrystalline diamond compact (PDC) slim hole bit; an 88.9 mm Drilex D350 low-speed, high-torque motor; a Trudril 82.6 mm high-speed, low-torque motor; 61 m of 79.4 mm drill collars; a double-flapper check valve; a 98.4 mm OD x 44.5 mm ID Diamant Boart CD 560 coring bit; 16 m of core barrel with 88.9 mm OD and 44.5 mm ID; and the FSTS tool string used for testing the well. The wellhead assembly is shown in Fig. 3.

DRILLING RESULTS

A cement plug was pumped through the coiled tubing and placed from TD to above the perforations in the old well. Squeeze pressure was applied, and the cement was allowed to set. After it set, the cement in the casing was drilled out.

The well was pressure tested from surface, but it would not hold pressure. Two more cement plugs were placed, squeezed, allowed to set, and then drilled out. Again, the well would not hold the 2.5 MPa pressure required for the pressure integrity test.

There were integrity problems in the 30-year-old casing in the well. It was decided to proceed with, but shorten, the experiment. The drilling depth was limited to 901 m, which allowed limestone coring but avoided a high-pressure aquifer for fear of cross flow into the weak casing above.

The average drilling rate while on bottom was about 5 m/hr. The average drilling rate of 50 m/day included trips and other miscellaneous operations. Improvements in this drilling rate are expected through optimization of the BHA, a reduction in nondrilling operations, and improvement in coiled tubing unit weight-on-bit control.

The deviation at the casing shoe at 642 m was 2 and deviation measurements at 720 m and 852 m were 2-3/4 and 2-1/4, respectively. This type of BHA used with coiled tubing drilling did not build angle (Fig. 4).

Two cores were cut with the high-torque, low-speed motor with the coring bit and core barrels. The first core was cut from 889.8 m to 892.0 m and the second from 892.0 m to 901.0 m. Both cores were retrieved completely with good core quality (Fig. 5).

DRILLSTRING TEST

Since the target formation could not be entered because of the casing integrity problems, no oil-bearing formation was available in the open hole for testing. To prove that a test could be done with the coiled tubing, the FSTS straddle packer system was run to perform a pressure drawdown test on a selected interval from 677 m to 680 M.

The FSTS tool string was run to 685 m and then picked up until the packers straddled the selected zone. Mud was pumped through the coiled tubing to the FSTS tool at a constant rate of 80 l./min for 5 min to inflate the packers. After 5 min, 15 kN (1,530 lb) of weight was set down on the FSTS tool while pumping continued. This set down weight cycled the tool from the packer inflate mode to the circulate mode, trapping the inflation pressure in the packers. In the circulate mode, circulation can take place above the set packers.

Nitrogen was circulated down the coiled tubing to displace the mud through the circulation ports in the FSTS tool. The FSTS tool was cycled to the test mode by picking up and then setting down weight on the tool. In the test mode the circulation ports were closed, and the path from the coiled tubing to the test interval between the packers was opened.

The nitrogen pressure in the coiled tubing was bled off at surface to atmospheric pressure over a period of 15 min. This surface pressure reduction caused a 700-psi drawdown between the packers, which was measured by the two memory gauges held in the spacers between the packers. This pressure drawdown was held for 45 min with no flow from the well.

The FSTS tool was cycled from the test mode to the circulate mode by again picking up and setting down weight on the tool. An attempt was made to fill the coiled tubing with mud by reverse circulating down the annulus, through the circulation ports, and up through the coiled tubing. This attempt failed because of the casing integrity problems. The coiled tubing was then filled by circulating mud down through the circulating ports.

The tool was cycled to the deflate mode by picking up and holding weight against the tool while an hydraulic time delay was activated. After 5 min the string weight returned to normal, indicating that the packers had deflated. The tool string was retrieved, and the packers were found to be in perfect condition.

The memory gauges were read, and the resulting data confirmed that the packers had maintained a pressure seal during the 45 min drawdown. If the formation had produced fluid it would have flowed up through the coiled tubing with the pressure transient being measured by the memory gauges.

Another trial with this reservoir objective is planned for early 1992. The hydrocarbon shows will be tested in a similar manner. Because specialized equipment was not used and an oilbearing formation was not actually reached, questions remain about the overall economics associated with this type of drilling and testing.

REFERENCE

Traonmilin, E., Courteille, J.M., Bergerot, J.L., Reysset, J.L., Laffiche, J., "First Field Trial of a Coiled Tubing for Exploration Drilling," IADC/SPE 23876, presented at the IADC/SPE Annual Drilling Conference, New Orleans, February 1992.