Drilling efficiency increases with technological advances
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.Much of the technology that has unlocked local gas reserves was described in December in an Oil & Gas Journal article by Vello Kuuskraa, president of Advanced Resources International – a gas and oil consulting firm that has worked in Garfield County – and Gregory Bank, a geologist with ARI.Among the factors they outlined were:• Improving exploration technology to identify more highly permeable sandstones with natural fractures that allow gas to flow.• Working to drive down well-drilling and completion costs.• Applying intensive resource development, through such means as “fracing,” or using fracturing techniques, and drilling more wells per acre.Rulison R&D paid offARI was involved in some of the early research and development in the Piceance Basin that produced results being put to use there. So was the U.S. Department of Energy, along with Barrett, which was later acquired by Williams Production, a leading gas producer in the county today.The R&D 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 – permeability “sweet spots,” as ARI refers to them.Seismic testing involves creating vibrations in the earth through use of dynamite, so-called “thumper trucks” or other means, then taking seismic readings.Wells drilled in these sweet spots were found to yield two or more times as much gas as nearby wells.Macke said the DOE’s testing in Rulison also proved fruitful in advancing fracing 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. Fracing 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.Improved fracturing and other technological advances have vastly improved gas recovery per well. 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.ARI found that area wells were averaging 0.79 billion cubic feet in estimated ultimate production before 1995, while average production is now about 2 bcf per well.”At the same time, the dry hole rate has declined from 9 percent for the pre-1995 wells to essentially zero,” ARI’s Kuuskraa and Bank wrote in their Oil & Gas Journal article.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 DOE 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.Diamonds a driller’s best friendDrilling 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.That’s important, with only 1,350 drilling rigs available to search for gas in North America. Soychak said there’s a shortage of not just rigs but manpower – the dozens of people needed to haul water, oversee directional drilling, handle the drill bits, run the mud systems involved in drilling, serve as consultants, and otherwise service a rig.Typically it can cost $1 million to $1.5 million to drill a well. Soychak said increasing steel prices are adding to the cost of well casing, and energy producers also are facing rising costs for the specialized sand used in the fracing process.But the payoff is a well that over its lifetime could produce gas worth $10 million.Contact Dennis Webb: 945-8515, ext. firstname.lastname@example.org
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