Learn what's on the horizon with this up-and-coming technology.

Drilling a geothermal well. Courtesy of Cleveland Green Building Coalition.
The driller, hard hat and coveralls splashed with mud and grease, stands before the rig floor console and watches the drill string turn. Ten thousand feet below, at the other end of the spinning string of pipe, the bit chews away at a hot, hard layer of abrasive rock that lies above the pay zone. Operations like this are expensive – costing upward of $15,000 a day for a small land rig to drill geothermal wells. Drilling and well completion can account for more than half of the capital cost of a geothermal power project; drilling costs can have a “make or break” effect on proposed geothermal development.

The potential pitfalls the rig can run into are many. For example, the bit can wear out quickly, causing the driller to spend hours pulling thousands of feet of drill pipe out of the hole to install a new bit. The drill string can twist off, or it can cause the drilling assembly to get stuck in the hole. The drilling fluid can leak off into formation fractures before it reaches the surface, causing stuck pipe and costly delays. New technology is being developed to minimize these problems so that geothermal wells can be drilled cost-effectively.

For more than two decades, the Department of Energy (DOE) has been working to cut the costs of geothermal well drilling and completion, working closely with industry and holding quarterly meetings with industry advisors. “We’re very conscious of the need for industry feedback. We want to ensure that we are trying to solve relevant problems and are doing so in an appropriate way, so we aim to maintain open lines of communication around our research developments,” says John Finger, principal member of the technical staff of Sandia National Laboratories in Albuquerque, N. M. Drilling cost reduction can be achieved in several ways — faster drilling rates, increased bitv or tool life, less trouble (twist-offs, stuck pipe), higher per-well production through multi-laterals (horizontal offshoots) and others. Researchers are working in all of these areas to ultimately reduce the cost of drilling geothermal wells by 50 percent.

Working closely with the geothermal and drilling industries, the DOE’s efforts are focused on the following functions:

  • Drilling systems analysis – understanding costs in order to focus research and development effort

  • High-temperature instrumentation – developing high-performance electronics for downhole applications, reduced tool failure rates and less expensive reservoir characterization

  • Lost circulation technology – finding ways to prevent losses of drilling fluid, and thereby lower the cost of drilling

  • Hard-rock drill bit technology – developing longer-lasting bits and better systems for faster, less expensive drilling

  • Diagnostics-while-drilling (DWD) – developing advanced systems for real-time data gathering based on high-speed data telemetry between the bit and the surface

Among the problems that plague all types of drilling, including geothermal, is a lack of timely information about what is happening downhole — where the bit is cutting the rock. This limited knowledge, combined with a lack of control, complicates the driller’s job and adds to the cost.

Personnel from Unocal Geothermal, Tonto Drilling Services and Epoch Well Logging Services examine a core-laden inner liner just extruded from a wireline-retrieved inner tube of a core barrel. Photo by Jeff Hulen, University of Utah.
Drillers have few options in conventional drilling operations. They only can control weight-on-bit (the force that drives the bit into the rock), the rotary speed of the drill string, and the flow rate of drilling mud. The long, slender drill pipe gives the operator little information about what may be happening downhole. Is the bit bouncing off the bottom and breaking its teeth, soon to become unusable? Has the temperature of the rock suddenly risen? Has the bit penetrated a pocket of high-pressure fluid?

Even in trouble-free drilling, with the driller simply trying to optimize performance by changing weight-on-bit or rotary speed, it may be a few minutes to an hour before he can assess the effect of a change. Quick, reliable data communications from downhole to the surface could revolutionize the drilling process.

Efforts to improve drillstring communication began more than half a century ago. For the past 20 years, a rudimentary technology called measurement-while-drilling (MWD) has helped get the measured data to the surface. MWD today is used primarily to control the path of wells. Data are transmitted via pressure pulses in the stream of mud that circulates in the well (also called mud-pulse telemetry). But the information travels relatively slowly — almost always under 10 bits per second (baud). (Common computer modems transfer data at 57,000 baud.) This technology also fails under high temperatures.

Diagnostics-while-drilling technology will use a data loop, which will bring high speed (100,00 bits per second or more), realtime data up the hole, combine it with measurements made at the surface, integrate and analyze these measurements to advise the driller, and then return signals downhole for control of “smart” tools. Sensors near the bit will measure such things as pressure, temperature, and vibration, and will show if the bit is turning smoothly. All signals will be sent uphole in real time.

Drill rig used to make holes for ground-coupled heat exchangers used with a geothermal heat-pump system. Photo by Craig Miller Productions.
When the DWD concept is put to commercial use, drillers immediately will know when problems arise and will have time to take corrective action. They will know when the bit drills into a new kind of rock or, in many cases, even when it is about to fail. A prototype DWD system with synthetic polycrystalline diamond compact (PDC) bits will be tested in hard, abrasive rock. The system will send bit-performance data to the surface at almost 200,000 baud. DWD’s ability to anticipate problems should greatly reduce the amount of time the rig stands idle while the driller waits for data.

Acoustic telemetry – wireless data communication – also has great potential to reduce costs. This method sends a signal through sound waves that travel up the steel of the drill string. Acoustic telemetry will provide information at a much broader bandwidth — more data, faster – than mud-pulse telemetry. In addition to numerous field trials of prototype equipment in deep wells, researchers use a surface drill string – 1,400 feet long – to integrate operations, test new devices, and optimize operation of the entire communication system.

Sandia project manager Douglas Drumheller says mud-pulse telemetry has been a useful tool, but more and more often it is failing to do the job. “Something more is needed, and that’s why acoustic telemetry technology is so promising. Acoustic telemetry works when the mud isn’t circulating, and the rate at which it sends data is at least one order of magnitude faster than mud-pulse signals,” says Drumheller.

Typical horizontal residential loop field. Courtesy of the Geoexchange.
Comparing mud-pulse telemetry to acoustic telemetry is like comparing the telegraph to the telephone: Because mud-pulse components are mechanical, the data transfer rate is thousands of times slower than the slowest computer modem, causing information bottlenecks. In acoustic telemetry, the electronic signal is transmitted by stress waves in the drill string. With a new repeater component under development, the acoustic communications will have an unlimited range capability with power from flashlight batteries. The communication range of the primary transmitter will operate down to 10,000 feet and is capable of penetrating more than 15,000 feet.

A leading drilling service company has been interested enough in the system to acquire a nonexclusive license for the technology, as has a Canadian venture capital firm.

Another promising method of getting signals to the surface is by transmitting them via optical fiber. Because optical signals have essentially unlimited bandwidth, they have enormous data-carrying capacity. Researchers are experimenting with ways to use optical fiber simply and more cost-effectively. In partnership with the Gas Technology Institute, the DOE is developing a system for deploying an optical fiber inside drill pipe to serve as a data link. After drilling, the fiber is disposed of easily and inexpensively.

In the area of high-temperature electronics, DOE is assisting private industry by developing tools that can withstand the high temperatures of geothermal wells. Hard, hot, abrasive rocks reduce the life span of bits and electronic tools to about eight hours. Almost 50 percent of conventional electronics fail at 300 degrees F, and of the remaining 50 percent, 80 percent of those fail before reaching 400 degrees F.

This geothermal project utilized a top-drive drilling system. Courtesy of Sandia National Laboratories.
“A huge need exists for high-temperature electronics and sensors on drilling operations, but the relatively small market for geothermal energy gives equipment manufacturers little incentive to produce tools,” says principal investigator Randy Normann. “Commercial geothermal well-bore instruments capable of operating above 400 degrees F are almost nonexistent, and those that are available have a high price tag. Our target temperature is 575 degrees F, which is hot enough to cover 90 percent of the geothermal wells within the United States.”

Most common well-logging and well-bore measurements are performed using a custom, application-specific integrated circuit with silicon-oninsulator (SOI) technology. SOI technology hardens silicon electronic components so they can perform in extremely high temperatures, similar to the way electronic components are hardened to withstand radiation. Working with Honeywell’s Solid State Electronics Center, Sandia developed and demonstrated the industry’s first 575 degrees F microprocessor-based circuit, a device that ran for more than 200 hours through several temperature cycles. SOI prototypes already have been tested successfully in wells at temperatures above 475 degrees F.

“Lost circulation” of expensive drilling mud also frequently adds to drilling costs. A recent success in controlling lost circulation demonstrated the value of polyurethane foam for plugging problematic zones in geothermal wells. Researchers plugged a loss zone in a well in Nevada where more than 20 previous attempts with cement had failed. Since that successful field demonstration, several inquiriesa have been received from industry.

Twenty-two professionals with diverse technical backgrounds support the work at Sandia. Mechanical, petroleum, and electrical engineers, physical scientists and skilled technologists work together to first understand the difficulties of geothermal drilling, and then develop systems to overcome these difficulties. “Taking drilling improvements from concept through development and laboratory validation, to field testing and commercialization is what makes the job fun — you get a real sense of accomplishment,” says Mike Prairie, leader of Sandia’s geothermal research program.

Sandia has a variety of tools for tackling the problems of geothermal drilling. Dedicated facilities and equipment include:

  • The Hard-Rock Drilling Facility, a laboratory drill rig used for studying the performance and durability of PDC cutters under a variety of conditions

  • The Linear-Cutter Test Facility for making detailed measurements of the forces acting on PDC cutters as they remove rock from samples characteristic of geothermal reservoirs

  • The Orpheus Mobile Acoustic Lab, a fully equipped instrumentation trailer that houses sophisticated instrumentation and computers for gathering data in the field

  • The Engineered-Lithology Test Facility (ELTF), a structure where simulated geothermal lithologies can be built up around simulated well bores, mainly for lost circulation experiments

  • The Area III Geotechnical Range that houses the ELTF and 1,400 feet of horizontally mounted drill pipe of two diameters used mainly for telemetry system tests

  • The Well-Bore Hydraulics Test Facility, a flow loop for testing mud-handling instrumentation (flowmeters, etc.)

  • A fleet of vehicles for use in the field including a fully equipped logging truck, a mobile crane, a diesel tractor and several 4WD trucks

As research brings drilling costs down, reliable geothermal energy will become more accessible.

Beneficial Impacts of Geothermal Energy

  • Electricity produced from geothermal resources in the United States prevents the emission of 22 million tons of carbon dioxide, 200,000 tons of sulfur dioxide, 80,000 tons of nitrogen oxides, and 110,000 tons of particulate matter every year compared to conventional coal-fired plants.

  • The average geothermal power plant requires a total of less than 1,400 square feet of land to produce a gigawatt of power over 30 years. Compare that to the enormous amount of land needed for coal and nuclear plants, all the open-pit and other mining required to fuel them, and the storage and transportation requirements for that fuel.

  • Geothermal energy production in the United States is a $1.5-billion-dollar-per-year industry.

  • Geothermal energy currently produces the third most energy of all renewables, after hydroelectricity and biomass.

  • For each 1,000 houses using geothermal heat pumps, a utility can avoid installing 2 to 5 megawatts of capacity.

  • Almost 3,000 megawatts of geothermal electric power capacity is available in the United States – equal to burning 60 million barrels of oil each year.