TECHNOLOGY Tandem motors increase well bore penetration rate

Steve Matthews
Halliburton Drilling Systems
Calgary

Ron McCosh
CenAlta Well Services Inc.
Calgary

Running a positive displacement downhole motor with tandem power sections and the proper bit significantly increases the rate of penetration and reduces stalling problems.

The use of positive displacement mud motors (PDMs) with two power sections has improved penetration rates on a number of drilling applications in western Canada. The majority of all the tandem motor runs to date have been successful. Results of these tandem runs show that tandem motors should be considered in any situation where a single motor is run.

The most recent push for tandem motors began in 1993 in the Austin chalk in Texas. Applications of tandem motors spread to Canada by late 1993. In 1995, tandem motor runs became more common in Canada as word of the success filtered through the industry. Tandem motors have been run in both directional and horizontal applications. Interest is growing in the application of tandem motors in straight holes.

Halliburton Drilling Systems began using the Dyna-Drill tandem motor in Canada in December 1993. The first drilling application involved running a 120-mm F2000S tandem slow-speed/high-torque motor in the horizontal section of the hole. The tandem motor drilled nearly 700 m of 159-mm hole in Devonian carbonate formations. The rate of penetration (ROP) was nearly 50% greater than that for single motor runs.

Since then, Halliburton Drilling Systems has had more than 40 additional Dyna-Drill tandem runs, with varying degrees of success, throughout western Canada. In one recent instance, an operator achieved a 300% increase in ROP compared to drilling rates achieved by single motors.

Why use tandem motors?

There are several good reasons for running tandem motors:

• To meet torque and rotational speed (rpm) requirements of polycrystalline diamond compact (PDC) and roller cone bits

Current roller cone bits and PDC bits for downhole motors have much more aggressive cutting structures. These new bits require higher torque and rpm to take advantage of the rock bit technology. Achieving greater ROPs with these bits requires more power from PDMs. The tandem design increases power by 50-100%, compared to single-motor designs.

• To reduce stalling and increase drilling efficiency

  Tandem motors can reduce stalling. PDM stalling occurs frequently with PDC bits or in high-angle/high-drag holes. Reduced stalling improves drilling efficiency from a faster net ROP because of more time on bottom.

Stick/slip-type drilling in high-angle or horizontal wells results from drillstring drag. The drillstring temporarily hangs up then "slingshots" ahead, causing PDM overleads and near stalling or stalling. Tandem motors reduce the likelihood of stalling in these cases.

• Higher weight on bit and flatter rpm

Drilling with a tandem motor allows more weight on bit (WOB) to be carried before PDM stalling occurs. Higher WOB leads to higher ROP. Typically, a single 165-mm, slow-speed motor might stall at 10-20,000 daN, whereas a tandem motor can be loaded to 18,000 daN WOB. The tandem design gives a flatter rpm curve, which means higher bit rpm because of increased efficiency.

PDM design

A positive displacement mud motor (PDM) is a tool used to convert the drilling rig pump's hydraulic power into mechanical power at the bit. A PDM's power results from motor rpm and torque.

PDM power = speed (rpm) x torque

The power section of a PDM consists of a rubber stator tube with a metal rotor inside. The stator has one more spiral lobe than the rotor. The lobes of the rotor and stator act like a gearbox. The metal rotor rotates inside the rubber stator as fluid is pumped through the PDM. The rotor/stator length needed for a single lobe to make one complete 360 spiral is called a stage length. Generally, single PDMs have 1-4 stages in the power section.

The first drilling PDMs were 1:2 (rotor:stator) lobe configurations. The 1:2 single lobe PDMs are high efficiency. Power produced by these PDMs is based on high rotor speeds and low torque. This motor is commonly referred to as a high-speed/low-torque motor. These high-speed motors are used for sidetracks, shallow directional wells, and kick offs. The low-torque motor did not require steering tools or measurement-while-drilling (MWD) tools to locate tool face.

More than 20 years ago, Smith International Inc. patented the Dyna-Drill tandem PDM. This PDM had two power sections, which doubled the power produced. At the time, the high-speed tandem was short lived with the advent of tungsten carbide insert (TCI) roller cone bits.

TCI bits became commonplace in the late 1970s. These bits required lower rpm to obtain longer bit life. PDMs were then designed with a larger number of lobes (that is, 5:6, 7:8, 9:10). The higher number of lobes (multilobe design) decreased the motor rpm and increased the torque. This style of PDM is commonly referred to as a low-speed/high-torque motor. Unfortunately, because of increased seal area and friction, the multilobe PDM was less efficient.

PDM efficiency = mechanical power/hydraulic power

Motor power, as a result, had not changed significantly.

Most current PDMs were designed for drilling with roller cone bits. Fixed-cutter PDC bits recently became more popular in areas such as the Austin chalk. Operators demanded more torque and rpm because of the easy stalling of PDM/PDC combinations at low bit weights.

Initially, medium-speed motors with tighter lobe spirals and shorter stage lengths were tried. The next step was the addition of stages by reintroduction of the tandem motor.

PDM power increases almost linearly with the increased number of stages with the tandem design. The following designs were developed:

• For roller cone bits, a low-speed/high-torque Dyna-Drill tandem PDM with two power sections

• For PDC bits, a medium-speed/medium-torque Dyna-Drill tandem PDM with one and one-half power sections.

  By combining one and one-half to two power sections, the following occurs (compared to similar single power section PDMs):

• 50-100% increase in torque output at the same circulation rates

• 50-100% increase in DP (pressure drop) across the motor at similar circulation rates

• Reduced DP per stage, which decreases fluid bypass of the rotor/stator seal

• Increased rpm and efficiency because of reduced fluid bypass

• Extended stator life.

Tandem motor applications

To run tandem motors properly, a learning curve is needed. Early applications revealed several limitations of tandems, including the following:

• Insufficient available surface pressure from the drilling rig pumps

• Increased MWD sensor-to-bit distance of 3-7 m, which can reduce the quality of MWD and logging-while-drilling measurements and the quality of drillers' decisions

• Insufficient ROP increases to offset increased tandem motor charge (Tandem motor costs are about 175-200% the rates for single motors.)

• Loss of directional control of tool face because of the high reactive torque when steerable assemblies are run with PDC bits in deviated well profiles.

  An economic analysis of the tandem motor run should be done to establish the break-even ROP necessary to justify the additional tandem charge.

Adequate hydraulics are necessary to obtain the benefit of tandem motors. No additional volumes above a single PDM are needed; however, 2,500-3,500 kPa motor pressure differential between off-bottom and on-bottom is required to load the motor properly and drive the bit.

In higher-drag drilling conditions, such as horizontal drilling, it may only be possible to achieve 1,500-2,000 kPa motor pressure differential. This lower differential is sufficient to improve ROP greatly in these conditions compared to that for single PDMs.

The following is an example of the hydraulics requirements. Given a hole size of 222 mm, a measured depth of 2,500 m, a drillstring consisting of 114-mm drill pipe and 165-mm drill collars, a pump output of 1,300 l./min, and a 165-mm tandem motor with two power sections, the minimum standpipe pressure needed is 10,000 kPa.

Western Canada

Halliburton Drilling Systems has run 44 tandem motors in western Canada since December 1993 with the following operators: Amoco Canada, 29 runs; Paloma Petroleum, 5; Olympia Energy, 4; Numac Energy, 3; Union Pacific Resources Co., 2; and Canadian Hunter, 1. Tandem motors have been run in a wide range of hole sizes, from 149 mm to 222 mm in both directional and horizontal wells.

Bit selection

Tandem motors have been run with both TCI and PDC bits. Currently, tandem PDMs have been run with 28 TCI and 16 PDC bits.

Regardless of the type of bit selected, it is extremely important to run bits that have sufficient gauge protection for motor drilling applications. Directional wells require that the steerability of the bit, particularly with PDC bits, be strongly considered during bit selection.

Insert bits can be run with higher WOBs when tandem motors are used than when a single motor is used. High WOB will stall a single motor. Tandem motors provide additional power, and, therefore, insert bits may be subject to higher than normal combinations of WOB and rpm. The bearing structure may become overloaded, and the only method of detection is by monitoring the ROP.

Drilling with a motor does not allow direct monitoring of the torque at the bit. Bearing failure may result in the loss of cones.

PDC bits tend to drill best at lower WOB and higher rpm. The one-piece design of PDC bits eliminates the possibility of lost cones. The additional torque output of the tandem motor allows a wider range of PDC bit designs to be run.

If the PDC bit selected is too aggressive for the formations to be drilled, the tandem motor will supply enough torque to allow the bit to continue drilling rather than stalling. This additional power allows more experimentation with PDC bits.

To date, more insert bits than PDC bits have been run with tandem motors. This trend possibly results from the fact that the majority of these runs have been on directional wells. Directional drillers, in general, are more comfortable steering bottom hole assemblies with TCI bits. Some PDC bits have had difficulty building angle in directional wells. It should be noted, however, that not all PDC bits have had this difficulty.

Mud systems

Tandem motors have been run with both invert and gel-chemical mud systems. Tandem motors do not require any specific or special mud properties. If an oil-based mud system is proposed, the oil should be analyzed to determine the aniline point to ensure that the rubber components of the motor will not deteriorate prematurely. This recommendation applies for single as well as tandem motors.

Ricinus/Caroline area

Amoco Canada has been a strong supporter of this technology development. It is because of this interest that such a large data base exists in the Ricinus/Caroline area of central Alberta.

Twenty-four of the 44 Dyna-Drill tandem motor runs have occurred in this area, with 20 of the runs occurring on Amoco directional wells. The other four runs were on an Olympia Caroline horizontal well.

Tandem motors replaced single motors on 20 bit runs on seven directional wells in the Ricinus/Caroline area. Two motor failures occurred on the first and third tandem runs in the area. These motor failures were operational related and have now been corrected.

Of the remaining 18 tandem motor runs, 12 used TCI bits, and 6 used PDC bits. All of the runs occurred below the kick-off point in these directional wells. Tandem motors were used to drill the build-and-hold portion of these well profiles. All the wells were drilled with invert mud systems.

The economics of the hourly directional drilling costs (with motors and MWD tools) showed that the increased cost of a tandem motor compared to a single motor is approximately 10%. Therefore, the ROP must increase by at least 10% for the run to be an economical success. Using these economics and comparing the typical ROP for wells in the Ricinus/Caroline area the following results were obtained: 13 economic successes, one marginal success, four uneconomic runs, and two motor failures. Fig. 1 [54043 bytes] shows the results of the tandem runs.

For all 18 tandem runs, the total average ROP increase was 87%. The ROP data show that 8 of the runs had double the expected ROP, and 2 runs had triple the expected ROP.

Caroline horizontal well

The Olympia Caroline horizontal well provides a good example for comparing single motors to tandem motors. The entire 156-mm horizontal hole section was drilled with the same type of insert bit (Smith F37). The hydraulics for the well, including flow rate, nozzle sizes, and mud weight, remained constant for the entire interval. The same slick steerable bottom hole assembly was used to drill the entire horizontal section.

The casing shoe was drilled out with a single motor and a slick bottom hole assembly. The single motor was picked up again and drilled from 2,760 to 2,866 m measured depth. The ROP for drilling this interval was 2.42 m/hr. This bit run drilled with a large amount of sliding and was therefore not used in the comparison with tandem runs.

The next bit run also was drilled with a single motor. It drilled from 2,866 to 3,007 m measured depth in 47 hr. The ROP for this run was 3.0 m/hr. This single-motor run was used to compare the ROPs, as it contained mostly rotational drilling similar to the tandem runs.

The tandem motor was run with the same bottom hole assembly (including bit type) on the next four bit runs. The overall interval drilled with the tandem motor (3,007 m to 3,625 m measured depth) was 4.9 m/hr, which is an average ROP increase of 63%. The individual bit runs are listed in the bit record shown in Table 1. [16451 bytes]

This example shows that in this horizontal well under very similar drilling conditions, the tandem motor performed significantly better than a single motor.

It is important to note that the additional length of the tandem motor means that the directional sensors are farther behind the bit than when a single motor is used. This consideration must be taken into account when deciding whether or not to run tandem motors on horizontal wells.

Acknowledgment

The authors thank the drilling staffs of Amoco Canada, Union Pacific Resources Co., Paloma Petroleum, Canadian Hunter, Numac Energy, and Bissett Resource Consultants. The authors would like to thank the directional drilling supervisors of Halliburton Drilling Systems of Canada and the support from Houston engineering and sales for Halliburton Drilling Systems.

Bibliography

Califf, B., and Johnson, M., "How Tandem Motors Improve Drilling Performance," World Oil, October 1994, pp. 77-82.

Daigle, C., "Tandem Motors Here to Stay," Halliburton Newsletter, Fall 1994.

Hooper, M., "Tandem Motors Product Introduction Information," Halliburton Drilling Systems memo, Feb. 20, 1995.

The Authors