TIME was when a wildcatter would cross his fingers, sink a well, and hope for a gusher. Now, with oil getting harder to find and explorers having to drill to 10,000 feet (3,000 meters), the cost of a well can run in the multimillion-dollar range. So when an oil exploration company is planning its next well, its management wants to rely on something a little more substantial than hope.
That's why the R&D 100 Award-winning Oil Field Tiltmeter has such a great future, enabling explorers to determine where to put their next multimillion-dollar well to get maximum production.
More than half of American oil-producing wells require help, usually in the form of cracking the underground rock to provide channels through which the oil can flow. This hydrofracturing is done by pumping a mixture of water, polymers, and sand down a well under high pressure, which causes the surrounding rock to crack and move slightly. In the past, an array of ultrasensitive tiltmeters was placed near the surface to detect the slight tilting, which reveals the primary direction of the cracking several thousand feet below. This information helps drillers decide where to sink additional wells.
But these surface tiltmeters were not without problems. They could measure hydrofracturing only to a depth of 6,000 feet (1,800 meters), which excluded about 80% of the oil wells in the nation. They also were vulnerable to "noise" at the surface--wind, thermal expansion, rain, vehicle traffic, pumps, even the tidal effects of the moon and the sun. To overcome these shortcomings, oil explorers tried deploying the tiltmeters deeper in the ground, but that required manual leveling, which could not be done accurately at depths greater than 20 feet (6 meters).

Solving the Problems
Lawrence Livermore researcher David Castillo had a better idea. He and colleagues Carl Boro and Steven Hunter developed the new Oil Field Tiltmeter that is smaller, sends digital signals, takes less time to install, and costs considerably less than competing products. Working with Pinnacle Technologies in San Francisco, they brought the product to market in October 1996 as the Pinnacle 5000 Oil Field Tiltmeter--and subsequently won an R&D 100 Award for the technology.
"The tiltmeter works on the same principle as a carpenter's level," Hunter says. "The sensor is a liquid-filled glass tube with a gas bubble in it. The difference is that the tiltmeter sensor has electrodes in it so the circuitry can detect the position of the bubble."
The self-leveling mechanisms allowed a smaller tiltmeter design. For deployment at 40- to 100-foot (12- to 30-meter) depths, Hunter and the team designed their product for slim-hole technologies--wells that are only 3 inches (7.6 centimeters) in diameter. In turn, the tiltmeters benefit from more stable hole conditions because the ground is disturbed less when smaller holes are drilled. Other features of the new tiltmeter include an electronic compass for instrument orientation, a downhole analog-digital converter to reduce electronic noise, and an internal data logger with a large memory.
The signal from the new tiltmeter goes to a differential amplifier, is rectified (made to flow in one direction only), and is further amplified. After it is filtered, the signal is digitized by a 24-bit converter, which provides a signal with higher resolution than previously used 16-bit converters. This digitized signal is much less susceptible to electronic noise and thus results in much more reliable data, which are stored in a random-access memory device until a technician downloads it to a lap-top computer.

Pulling It All Together
In an oil field, an array of about 20 instruments defines the magnitude and direction of the tilt vectors at each location; these tilt vectors are used to generate a map of the surface deformation around the well. A modeling program derives the hydrofracture direction that must be present to produce the observed tilt vectors, and these data enable explorers to determine the best locations for additional wells.
This information is invaluable when an explorer is planning a deep well. The cost of drilling a 10,000-foot-deep well is far greater than twice the cost of drilling a well that is one-half that deep. Such a well will cost at least $1 million--much more if problems develop during drilling. Given these high development costs, it is essential that an oil exploration company has solid data to rely on.
When compared with other products on the market, an array of the new Pinnacle 5000 instruments shows distinct advantages. Resolution of the angle-of-tilt data has improved from 10 nanoradian to about 1 nanoradian. How fine is this resolution? If you could lay two straight rods next to each other stretching from New York to San Francisco and create an angle by placing a a quarter between them in New York, the angle would be a nanoradian. In fact, this tiltmeter can measure the angle created by adding an atom or two under one side. Power has been reduced from 360 to 200 milliwatts for longer battery life, operating range has been increased from 3 to 10 degrees of tilt for simplified installation, and installation time has been reduced from 40 minutes to 25 minutes. But the most impressive features are the unit's small size, enabling it to fit in a 3-inch-diameter hole vs the 10-inch holes required for other units; the built-in data logger, which allows deeper deployment with less electrical noise; and its low cost.
Hunter says that other applications for the new tiltmeter include tools for studying earthquake faults and geothermal energy production, civil engineering monitors, improved underground mapping for environmental cleanup projects, and more accurate monitoring of subsurface waste disposal operations.

--Sam Hunter

Key words: earthquake faults, geothermal energy, oil-well-drilling, Oil Field Tiltmeter, R&D 100 Award.

For further information contact Steven Hunter (510) 423-2219 (hunter5@llnl.gov).

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