New PDC bit designs include features that attempt to address common problems; however, these bits still have some shortcomings when drilling in extreme environments. Researchers are working to improve drill bit performance, and a reliable, thermally stable, polycrystalline (TSP) diamond bit is being developed.

Rate of penetration (ROP) is a major issue in deep wells. Low ROP (e.g., 3-5 ft./hour) primarily is a result of the high compressive strength of the highly overburdened formations encountered at greater depths. Initially, the tricone bits with hardened inserts used for drilling hard formations at shallower depths were applied as wells went deeper. However, at greater depths, it is more difficult to recognize when a tricone bit's bearings have failed, a situation that can occur with greater frequency when greater weight is applied to the bit in a deep well. This can lead to more frequent failures, lost cones, more frequent trips, higher costs and lower overall rates of penetration.

Fixed cutter bits with polycrystalline diamond compact (PDC) cutters were a solution to the problems inherent with tricone bit moving parts. The PDC cutting surface employs synthetic polycrystalline diamonds bonded to a tungsten-carbide stud or blade. First developed in the 1970s, this type of bit now holds the record for single-run footage in a well (22,000 ft.). PDC bits typically drill several times faster than tricone bits, particularly in softer formations, and PDC bit life has increased dramatically over the past 20 years. But PDC bits have their own set of problems in hard formations. For example, “bit whirl” is a problem that occurs when a PDC bit's center of rotation shifts away from its geometric center, producing a non-cylindrical hole. This can result from an unbalanced condition brought on by irregularities in the frictional forces between the rock and the bit, analogous to an unbalanced tire causing vibrations that spread throughout a car at higher speeds. PDC bits are more susceptible to this phenomenon, as well as to “stick slip” problems, where the bit hangs up momentarily, allowing its rotation to briefly stop, and then slips free at a high speed. While PDC cutters are very good at shearing rock, they are susceptible to damage from the sharp impacts that these problems can lead to in hard rocks, resulting in reduced bit life and lower overall rates of penetration. New PDC bit designs include features that attempt to address these problems - force balancing, spiraled or asymmetric cutter layouts, gauge rings, and hybrid cutter designs, to name a few.

However, PDC bits still have some shortcomings when drilling in extreme environments. Sandia National Laboratories currently is working in cooperation with industry and university partners to improve the hard-rock, high-pressure, high-temperature drilling capability of PDC bits. After much testing and computer modeling of stresses, high temperatures, hydraulics and wear mechanisms, a reliable thermally stable polycrystalline (TSP) diamond bit is being developed.

The next phase of bit-related technological advances for deep drilling may include not only improvements in conventional drill bit efficiency, durability and longevity, but also advancements in the development of less conventional drilling tools. Such tools might utilize heat, pressure, chemicals or electrohydraulic discharges to break and remove rock from the well bore, as opposed to the shearing and grinding mechanisms of conventional bits. For example, thermal-spalling drills could use heat (700-1,000 degrees Fahrenheit) to cause rock to spall or split away from the wellbore. Melting and vaporization drills could employ lasers or electron beams to achieve similar results. Chemical drills might employ highly reactive fluids, such as fluorine, to dissolve the rock, while mechanical stress drills might employ small explosions, implosions, pellets, sparks, ultrasound waves or turbines to break the rock. Each of these proposed mechanisms will require a careful accounting of energy requirements as well as rock removal efficiency, before any can be considered as an economic alternative.

Currently, there is one Deep Trek project focused specifically on the development of improved bit technologies. A second project is focused on the reduction of drill string vibration, an important issue in improving the performance of PDC bits and rates of penetration.

• TerraTek Inc. of Salt Lake City will head a group of research partners working to improve deep drilling performance through rigorous proof-of-concept testing of new drilling components at high borehole pressures. Joining Terra Tek will be the University of Tulsa, Hughes Christensen, BP America, Conoco, INTEQ Drilling Fluids, Marathon Oil Co., ExxonMobil and National Oilwell. With its private industry partners, TerraTek will develop and test prototypes of novel drill bits in high-temperature, high-pressure fluids suited for slow, deep-drilling operations. Researchers will benchmark the performance of these bits and fluids by conducting full-scale drilling tests in its laboratory followed by field-testing and eventual commercialization of the systems that perform up to expectations. Total cost of the project is $2.9 million, of which $1.24 million will be a cost-shared contribution by the industry partners.
• APS Technology Inc. of Cromwell, Conn., is developing a system to monitor and control drilling vibrations, one cause of premature equipment failure in deep wells. The two-component system includes a unique, multi-axis active vibration damper to minimize harmful axial, lateral and torsional vibrations. The hydraulic impedance (hardness) of this damper will be continuously adjusted using unique technology that is robust, fast-acting and reliable. The second element is a real-time system to monitor three-axis drill string vibration and related parameters, including weight-on-bit, torque-on-bit and temperature. This monitor will determine the vibration environment and adjust the damper accordingly. In some configurations, it also may send diagnostic information to the surface via real-time telemetry. Phase I includes the development of a design for the system, as well as an analytical and benchtop model study to prove its feasibility. In Phase II, a fully detailed prototype will be developed and tested in the lab, in test wells and in shallow commercial wells. Phase III will entail testing of a pre-commercial prototype in progressively deeper and more challenging wells. Total cost of the project, scheduled for completion in November 2006, is $2.24 million, of which $881,000 will be a cost-shared contribution by APS Technology.

ND

Bio:

This article is provided through the courtesy of the United States Department of Energy's National Energy Technology Laboratory.