GRC Transactions, Vol. 38, 2014

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High-Temperature, 300°C Directional Drilling System Including Drill Bit, Steerable Motor, and Drilling Fluid

Kamalesh Chatterjee, Aaron Dick, Harald Grimmer, Jan Herlitzius, Mike Otto, Sundaie Klotzer, Dave Epplin, Jon Schroder, and John Macpherson

Baker Hughes Incorporated

KeywordsEGS, 300°C, directional drilling system, fracture imaging; measurement-while-drilling (MWD), HPHT, navigation

ABSTRACT

Geothermal energy is the cleanest form of alternative energy, because it has the least environmental impact. The United States has vast untapped geothermal energy potential; using enhanced geothermal systems (EGS) technology, geothermal wells can supply the energy consumption for the USA for 2,000 years [1]. The Department of Energy (DOE) spearheads research and in-novation in tools and technologies required for successful and economical use of EGS reservoirs. Temperatures in some EGS reservoirs can exceed 300°C. This paper provides a status update and technology review for “high temperature 300°C directional drilling system, including drill bit, steerable motor, and drilling fluid, for enhanced geothermal systems,” being developed with funding assistance from DOE (DE-EE0002782). We are close to delivery on the directional drilling systems tools. The drill bit, motor and fluid were all been developed for operation at 300°C; a complete drilling system was assembled and tested at the Baker Hughes Experimental Test Area (BETA), Oklahoma, and the drill-ing parameters and test results are provided.

Introduction

Drilling geothermal wells for Enhanced Geothermal Systems (EGS) require precise placement of injection and production wells [2]. Any short circuit (or direct pathway) in the water path from the injection to production well causes insufficient heat exchange. On the other hand, when heat exchange impedance is too much (for example, if the wells are too far apart lacking any connect-ing fractures) the flow becomes poor and heat exchange remains insufficient. Important steps in geothermal well development are illustrated in Figure 1 [taken from reference 2]. Precise well positioning achieves maximum heat exchange and could render EGS economical. The precise placement can only be done with

a directional drilling system and measurement-while-drilling (MWD) system. There is no directional drilling system in indus-try capable of surviving temperatures encountered in deep EGS wells, where formation temperatures can be in excess of 300°C. Current commercial offerings for directional drilling systems are rated for 175°C.

Two US Department of Energy (DOE) Geothermal Technolo-gies Program (GTP) projects were awarded to Baker Hughes to develop a 300°C (572°F) drilling system. The first project (DE-EE0002782) covers the development of drill bit, steerable motor, and drilling fluid all rated for 300°C and capable of operating at least 50 hours at depths up to 10,000 m [3]. The system is built for an 8.5-in. (diameter) hole. The second DOE project (DE-EE0005505) covers the power source, telemetry and navigation sensors and electronics for a 300°C measurement while drilling (MWD) system. We have completed the conceptual system de-sign and submitted to DOE for approval to proceed to the next phase. The two systems together provide a complete directional measurement while drilling solution.

In our last paper [4] we provided an update on the design and fabrication status of each of the subsystems for the directional drill-ing systems (DE-EE0002782). In the past year we have completed

Figure 1. Typical production and injection well in an enhanced geother-mal power installation [2].

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the design and manufacturing stage, have assembled complete drilling systems, and have tested those systems drilling in gran-ite at our test facility in BETA, Tulsa, OK. Adjustable Kick-Off rings (AKO) are used to build an angle when directional drilling is desired. The remainder of the paper describes the directional drilling system.

Drill Bits Rated for 300°C

Both hybrid PDC-rolling cone bits and Tricone rolling cone bits were selected for this application. The main design challenge at 300°C operation is the removal of all elastomeric components in the system. We have incorporated metal mechanical face seals, high temperature bearing grease and metal bellows grease pres-sure compensator, all capable of sustaining a 300°C environment. These modifications are illustrated in Figure 2. Typically me-chanical face seals use elastomer components to energize a metal rotary seal. For this high temperature application, the path taken was towards an all metal sculptured seal that is self-energizing. Eliminating the elastomers in this system required a singular seal design comprised of four key features. The material had to be suitable to operate at 300°C, static seal on one end, dynamic seal on the other, and the dynamic sealing face to be capable of seal-ing a differential pressure. The seal was designed and tested and packaged into the full bit design to be utilized in the Tricone bits.

In order to equalize the differential pressure from the lubricant reservoir to the downhole environment, a pressure compensation system is used. This reduces the pressure differential across the rotary seal as the downhole pressure increases and decreases by allowing the diaphragm to be exposed to the same pressure. Typically an elastomeric diaphragm is used to accomplish this; however they are not capable of withstanding 300°C. To accom-plish the system temperature requirements, an all metal bellows with welded flanges was developed. The Inconel material used is capable of operating at the required temperatures, while allowing weld attachment to the bit body and displays excellent fatigue strength. The bellows were successfully fatigue tested to almost 3 million cycles without failure.

Conventional greases used in rock bits will not be able to maintain properties; a new formula had to be developed. Using standard bit grease as a baseline in independent tests, it became

evident that the thickener would break down early at these elevated temperatures. Beyond a certain temperature, the coefficient of friction increases rapidly. Several new formulas were developed and put through seizure and wear tests at temperature. One par-ticular formula stood out, yielding up to 10 times lower friction and significantly smaller wear scar diameters. During aging tests, it was able to maintain properties after 50 hours of exposure to 300°C in contrast to the baseline which was severely degraded, losing lubricity. This grease was then procured for bit testing.

Mud Motor Rated for 300°C

A directional motor design based on the positive displacement motor (PDM) was selected. A PDM is driven by mud flow through the power section of the tool, and its simple mechanical design en-ables excellent reliability. A typical industry standard mud motor uses elastomer to reduce friction and prevents fluid from leaking; at 300°C the challenge is finding an alternative to this elastomer. The developed mud motor features an industry-first, metal-coated metal-to-metal (M2M) contact between the rotor and the stator. An extensive coating evaluation program was performed to locate a coating technology that could successfully meet the 50 hour tool lifetime requirement and the operating parameters required by the drill bit. In addition, manufacturing techniques were developed to control the clearance gap between the rotor and stator to maximize hydraulic efficiency. Development of the technology to precisely machine the rotor and stator bodies was quite challenging, as was the selection of a viable metal coating for both parts.

Rotors and stators had to be precisely machined with special tooling to achieve tight tolerance constraints leaving room for coating thickness. Fit tolerance yields the best efficiency and yet allows the rotor to turn freely. Two complete motor assemblies with different tolerances have been designed in order to test the different efficiencies of the power section. Special tools were also required to machine the rotors to eliminate the possibility of rotors being bent.

Our method for evaluating and eliminating selected coatings involved an extensive laboratory evaluation to measure performance under anticipated downhole conditions; wear resistance of metal-metal sliding contact in drilling fluid, coating adhesion, erosion and corrosion resistance. Separate coatings were evaluated for the rotor and the stator. The coating system must resist adhesive wear from the metal-metal contact, but also resist abrasive wear from the

Figure 2. Drill bit modifications in hybrid PDC-rolling cone bits to enable 300°C operation.

Figure 3. Metal to metal profiling used to determine straightness and cut-ting accuracy. This example illustrates a bent rotor.

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retained drill solids in the drilling fluid passing through the motor. One of the biggest coating challenges was applying a uniform coat-ing thickness to the rotor and determining the straightness of the rotor in order to be able to assemble the rotor and stator. Using 3D scanning techniques we were able to improve the accuracy of the cutting profile while controlling the straightness as the rotor was being machined. Figure 3 shows 3D scanning results of a rotor; in this example the rotor is bent and not usable. We also used 3D scanning studies to ensure uniform coating thickness on the stator and rotor. The 3D scanning technique provided us with a 3D view of the surface so that we could determine the coating thickness required in order to achieve the best fit between the rotor and stator.

One challenge in manufacturing this metal to metal motor is to find the correct machine and processes that could engage the rotor into the stator with enough force while maintaining align-

ment. Figure 4 shows the assembly process and the torque machine used to assemble the ro-tor and stator. Care must be taken to ensure the rotor does not damage the stator surface during the assembly process. We were able to improve the accuracy of the cutting profile while controlling the straightness as the ro-tor was being machined. Figure 3 shows profile measurements of a rotor; in this example the rotor is bent and not usable. We also ensured uni-form coating thickness on the stator and rotor, so that we could determine the coating thickness re-quired in order to achieve the best fit between the rotor and stator.

Drilling Fluid Rated for 300°C

The drilling fluid is critical to the operation of this drilling system. The metal to metal motor operation requires that the drill-ing fluid should contain a special lubricant for the mud motor and drill bits. Some geothermal operators drill with water and polymer sweeps as the drilling fluid. This directional drilling system would require a lubricant be added to the water. The feasibility of drill-ing with water and polymer sweeps depends on the temperature modeling and polymer viscosity measurements. When borehole conditions require a drilling fluid, it is imperative that this fluid remain thermally stable. Tests on possible drilling fluid formula-tions guided us to the selection of a (powerdrill) fluid containing bentonite stabilized with a low molecular-weight copolymer. Filtration control and supplemental viscosity are obtained with variations of vinyl sulfonated copolymers.

Tests indicate the drilling fluid remains stable with low shear strengths after being aged at 300°C for 50 hours. However, the post-aged drilling fluid did show reduced viscosity and increased filtration rates (Figure 5). Increasing the initial bentonite concen-tration improves post aged properties but results in viscosities that are too high when initially exposed to temperature. During drilling operations, circulating fluids are gradually exposed to high temperatures and the bentonite becomes temperature seasoned. Supplemental treatments occur during circulation so that desired fluid characteristics are maintained.

Initial formulations were evaluated after aging at 56°C (150°F) and 300˚C (572°F). Mud rheological properties were tested on a viscometer and are reported as plastic viscosity in units of centi-poise, yield point and gel strengths in units of pounds/100 sq.ft. API fluid loss and HPHT filtration rates were reported in units of ml/30 min. The HP/HT fluid loss was tested at 150°C (300°F) and 500 psi differential pressure. These results are presented in Figure 5.

Optimized fluid formulations provided sufficient fluid properties before and after aging. The drilling simulator testing to evaluate the bit was conducted with water, a conventional water based mud (WBM) and the powerdrill drilling fluid with

the lubricant. Lubricity is essential because directional wells normally produce higher torque and drag than vertically drilled wells. There is a higher probability that these wells will require a lubricant because the wells will be directionally drilled into hard rock. Figure 6 depicts the difference in the wear scar of a ring test specimen for a drilling fluid without (left) and with (right) a wear

Figure 4. Metal to metal motor assembly process. Ensuring alignment and the right torque during assembly requires skilled professional assembly.

Figure 5. Drilling fluid properties after exposure to 56°C and 300°C. Shear strength is in units of lb/100 ft2 , plastic viscosity (PV) is in centipoise, yield point (YP) is in lb/100 ft2.

Figure 6. Block on ring test specimens show wear scar for a drilling fluid without (left) and with (right) a drilling fluid wear reducing additive. This additive is formulated for 300°C (572°F) stability to aid durability of the metal to metal motor.

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reducing additive. This additive is formulated for 300°C (572°F) stability to aid durability of the metal to metal motor.

Complete testing of the directional drilling system at the BETA test site was conducted with a Wyoming bentonite/polyanionic cellulose polymer (GEL/PAC) drilling fluid conditioned with the lubricant. The test rig also allowed for the evaluation of a solids control equipment package while drilling granite with the directional drilling system.

Successful Testing of the Complete Drilling Tool

We have successfully tested the com-plete drilling system at the Baker Hughes Experimental Test Area (BETA) south of Tulsa, Oklahoma in Dec 2013. The system drilled 197 ft for 16 hours in granite at the target weight-on-bit, with the mud provid-ing lubrication of the motor and bit. Repeat testing occurred in April 2014; 180 feet were drilled through granite and steering with a BUR of 6°/100ft with higher rate of penetration than the initial test. Figure 7 shows the pictures at the test site as the tool is lowered into the borehole during the first test.

In the second test, drilling concluded at a depth of 5,382 feet after 15 hours of circulating and just over 11 hours of on-bottom drilling. The system drilled 180 feet in hard granite, and demonstrated a Build Up Rate of 6°/100ft. Maximum Dog Leg Severity (DLS) was just over 7.2°/100ft. The BHA had the following orientation over the test run: Initial After Drilling 180'Azimuth 202.48° Azimuth 210.76°Inclination 2.57° Inclination 7.69°

The Rate of Penetration varied depending on weight-on-bit and bit rotation rate (motor speed plus drillstring rotation rate) but ranged between 15 to 25ft/hour for most of the run. Towards the end of the test, with the same test parameters there was a small decline of ROP which may be associated with the wear on the diamond heels of the drill bit. We are investigating the bit and the motor after the run.

Summary

Following the directive of US Department of Energy Geo-thermal Technologies Program a directional drilling system rated for operation at 300°C and suitable for EGS was developed. The complete drilling system was tested at a test well and showed excellent performance; customer field testing is scheduled for Q3 2014.

For full MWD capability we have also completed the conceptu-al system design of a complementary measurement-while-drilling

system and submitted the design to the DOE for approval before proceeding to build prototype tools.

The two systems provide a complete measurement while drilling solution enabling accurate directional wellbore place-ment in deep EGS wells. These tools not only provide enabling technology but also lower well installation costs and move

EGS energy production closer to com-mercialization.

Acknowledgements

This material is based upon work supported by the Department of Energy Geothermal Technologies Program un-der award numbers DE-EE0002782 and DE-EE0005505. The authors thank Al-taRock, Geodynamics and the Geothermal Resource Group for providing well data and advice on EGS and conventional geothermal well requirements.

Disclaimer

This paper was prepared as an account of work sponsored by an agency of the United States Government. Neither the United States Government nor any agency thereof, nor any of their employees, makes any warranty, expressed or implied, or assumes any legal liability or responsi-bility for the accuracy, completeness, or usefulness of any information, apparatus, product, or process disclosed, or repre-sents that its use would not infringe upon privately owned rights. Reference herein

to any specific commercial product, process, or service by trade name, trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, recommendation, or favor-ing by the United States Government or any agency thereof. The views and opinions of authors expressed herein do not necessar-ily state or reflect those of the United States Government or any agency thereof.

References[1] U.S. Department of Energy 2006, The Future of Geothermal Energy:

Impact of Enhanced Geothermal Systems (EGS) on the United States in the 21st Century, Massachusetts Institute of Technology, Boston.

[2] “An Evaluation of Enhanced Geothermal Systems Technology,” A report from Geothermal Technologies Program, 2008, Energy Efficiency and Renewable Energy, US Department of Energy.

[3] Dick, A.J., M. Otto, K. Taylor, J. Macpherson, et.al.“A 300°C Directional Drilling System for EGS Well Installation”. Paper presented at the 2012 Geothermal Resource Council Annual Meeting, Reno, NV, Oct 2012.

[4] Dick, A.J., M. Otto, J Schnitger, J. Macpherson, at.al. “Progress on a 300°C Directional Drilling System for EGS Well Installation,” GRC Transactions, Vol. 37, 2013, Reno.

Figure 7. The metal to metal motor, high temperature bit, and mud lubricant on its first trial at the BETA test site, December 2013. M2M stands for metal to metal.