Drilling efficiency increases with technology
Even critics of the natural gas industry in Garfield County seem willing to concede the point. However one feels about drilling, energy developers are doing a remarkable job of tapping the vast gas resource lying beneath us.Developers are incorporating a variety of technological advances to produce gas locally.”It’s a pretty adept process, getting gas out of the ground,” said Randy Udall. A Carbondale resident and director of the Community Office for Resource Efficiency, an Aspen-based nonprofit office that promotes renewable energy and energy efficiency, Udall has been a vocal critic of the industry in other regards.Brian Macke, deputy director of the Colorado Oil and Gas Conservation Commission, credits strong natural gas prices and improved technology as the factors behind the county’s gas boom.”Those two conditions combined have very much increased the level of activity out in Garfield County,” he said.In everything from directional drilling to drill bits, the industry has been taking advantage of technological advances to improve local drilling performance.These advances have been important because the Piceance Basin is a nontraditional, unconventional gas field. Early attempts to produce gas locally, back in the 1950s, weren’t productive. The gas is trapped in what are called tight sands – essentially, sandstone, with gas trapped between individual grains of sand.The Williams Fork/ Mesaverde geological formation that contains this sandstone is visible aboveground in places such as Cameo near Grand Junction, and the Grand Hogback in Garfield County. But elsewhere in the county, the sandstone is thousands of feet deep, the overlying earth having trapped the gas until drills have brought it to the surface.But the sandstone doesn’t give up the gas easily, and this is where technology has come into play, aided by gas prices high enough to make it worth the investment.Exploration pays offEarly research and development in the Piceance Basin produced information now being put to use. The U.S. Department of Energy was involved along with a company later acquired by Williams Production, a leading gas producer in the county today.
The exploration focused on wells in the Rulison area, in the late 1980s and early 1990s. One effort made use of basin analysis, three-dimensional seismic testing and other means to identify clusters of natural fractures underground – “sweet spots,” as drillers refer to them.Wells drilled in these sweet spots were found to yield two or more times as much gas as nearby wells.Macke said the Department of Energy’s testing in Rulison also proved fruitful in advancing technology aimed at opening up more passages for natural gas flow. Experiments were conducted on different hydraulic fracturing techniques, and the tests showed that local gas fields could be developed far more productively and efficiently than had been thought.Fracturing involves injecting fluids and sands down the drill hole to prop open formations so gas can be released. The technology continues to improve, as do the fluids used in the process. Today’s fluids cause less damage to the formations being drilled and do a better job of increasing gas production.Steve Soychak, district manager in Parachute for Williams Production, said one well advancement has involved installing solar-powered, radio-based remote controls that let the company track production, and any abnormal trends, from the office.One analyst found that area wells were averaging 0.79 billion cubic feet in estimated ultimate production before 1995, while average production is now about 2 billion cubic feet per well.The denser, the better?Macke said energy developers also discovered during the 1990s the value of increasing drilling density to tap reserves more fully. Soychak said the Department of Energy’s experiments contributed to Williams’ decision to drill more densely.The gas-producing sandstone bodies being drilled are often described as lenticular, or lens-like, because of their shape. They are stacked vertically for hundreds of feet, but don’t extend very far horizontally, and don’t connect with other sandstones.As a result, drilling density was increased to access these individual lenses better.”I think it’s being shown that there’s a lot of places where 10-acre density is necessary,” said Macke.One well per 10 acres is the densest drilling in the world. But the math has borne it out. Producers have found that as they increase density, successive wells are about as productive as the early ones.
For example, said Macke, in the Parachute field, one well every 160 acres was found to drain about 5 percent of the gas in place. One every 80 acres recovers 10 percent; one every 40 acres, 20 percent, one every 20 acres, 40 percent; and one every 10 acres, 80 percent.Forty-acre spacing results in 16 wells per square mile; 20-acre spacing, 32 wells; and 10-acre spacing, 64 wells.Any denser, said Macke, and wells start to “communicate with each other.” That means they’re draining the same sand lenses – which makes additional drilling unnecessary.But Udall, of CORE, said he’s being told by the industry that communication isn’t necessarily occurring between wells drilled at 10-acre density, “which suggests to me that 5-acre spacing may not be out of the question.”Ken Wonstolen of the Colorado Oil & Gas Association said it wouldn’t surprise him if 5-acre spacing is eventually pursued. Some sandstone lenses are perhaps the size of a football field, or about one acre, so they can be missed with 10-acre drilling, he said.Drilling also is being improved by the advent of diamond-based drilling bits, said Soychak. These can cost $40,000 to $45,000 each, but drill faster than bits made of carbon steel.They also do better at boring through the abrasive sands encountered by local drilling operators. Most local drilling rigs are using the diamond-based drill bits, and wells that used to take 30 days to drill now take half the time, said Soychak.Drilling in new directionsAlthough the density of wells has increased immensely in Garfield County, underground drilling density is not always equivalent to surface density. No 10-acre surface drilling density has been approved in the county, said Brian Macke of the Colorado Oil and Gas Conservation Commission. Rather, companies are using directional drilling from existing pads to tap gas reserves more fully.EnCana, for example, is drilling from surface wells of one per 160 acres to obtain 10-acre down-hole density south of Silt.
“The directional technology has helped a lot. … It’s much more successful than it used to be,” said Steve Soychak of Williams Production, another big energy producer in the county.The technology has been around since the 1920s, with some of its first applications taking place off the California coast, said Charles Brister, a directional drilling specialist who has worked in Garfield County’s gas fields.Nudging the drill bit in different directions from above is no great challenge – it’s as easy as inserting a wedge down the drill hole so the bit is diverted at an angle. But the challenge is determining where the drill is heading.Brister said directional drillers originally made use of bubble levels and a time-operated camera to record the angle of the well bore. Then Elmer Sperry, who developed the navigational gyroscope for airplanes and ships, used gyro technology for taking drilling measurements in the late 1920s.In the late 1970s, directional drillers began to use mud pulse telemetry. Vibrations of mud in the drill hole correlate to drilling direction, and a computer decodes measures of mud pulses at the surface.This is still the primary technology used, but another one has shown to be successful in the Garfield County’s Piceance Basin. Brister said a method making use of electromagnetic tools first was developed for directional boring to run fiber-optic cables beneath rivers. But it proved to be useful in oil and gas development. “These tools essentially transmit the data using radio waves similar to the wireless networking systems, except that the transmission is through the earth,” Brister said.The method can be limited by depth and by absorption by rock formations, Brister said. But it has proven useful in local drilling because of a tendency of conventional mud-based surveying systems to plug up in geological formations here.Brister said drilling a directional well may be more expensive, but the overall cost of the well can end up being the same.”This is because of the reduction of infrastructure cost, such as location building, roads, pipelines, etc., that are reduced by having multiple wells per pad,” he said. The primary reason for directional drilling is to cut down on surface impacts, and it’s the responsible approach, Brister believes.”This will become increasingly important for all U.S. land drilling. Directional drilling is without doubt the future of oil and gas development for the foreseeable future.”