Coalbed Gas Enters the Energy Mix
A basin divided
Coal miners have long been aware of hazardous natural gas that lurks in coal deposits. During mining operations, the gas can seep into the mines and lead to potentially dangerous explosions. In the 1970s, the now-defunct U.S. Bureau of Mines began looking at ways to reduce the chance of explosions. They determined that drilling vertical wells from the surface would relieve the gas pressure in the coal seams.
Over the past decade, development of methane gas from coalbeds has taken off in the United States, including at the Powder River Basin located in Wyoming and Montana. Wastewater impoundments, shown here, store water that is disposed of in the process of producing the gas. Photograph is by Ray Muggli; copyright 2002 Northern Plains Resource Council.
It did not take gas companies long, however, to realize that there was a potential goldmine in these coal seams in the form of the natural gas. So they began producing the gas, known as coalbed methane, instead of just burning it off. By the mid-1980s, coalbed methane had become part of the U.S. energy portfolio.
Today, coalbed methane provides about 8 percent of the natural gas the country uses — a number projected to rise significantly. In the next 20 to 25 years, natural gas production from unconventional resources such as coalbed methane will need to double to address economic growth and depletion of conventional gas resources, says Kent Perry, executive director of the exploration and production program at the Gas Technology Institute in Des Plaines, Ill.
Indeed, companies are increasingly turning to coalbed methane, as it is an abundant source of energy, given the prevalence of coalbeds throughout the world and especially in the United States. The trick now is to find more cost-effective ways to extract it.
Breaking it down
“Coalbed methane is identical to conventional natural gas,” Ayers says. In fact, he says, along with conventional natural gas, coalbed methane is delivered through pipelines to markets, where it has varying uses, including for residential heating, electrical power generation, and in the manufacturing of fertilizers and plastics. The two types of gas, while similar in composition, are stored differently underground.
Conventional gas forms in limestone and shale formation source rocks, and under the influence of gravity and density differences, it migrates to highly permeable reservoirs, where it is stored as free gas occupying the reservoir pores, Ayers says. It is trapped by impermeable layers, such as shale or salt. If oil is also present in the “trap,” he says, the natural gas will lie atop the oil and water. Typically, conventional natural gas is produced from reservoirs 300 to 6,000 meters (roughly 1,000 to 20,000 feet) deep.
By contrast, coalbed methane usually is stored in coal seams at depths shallower than about 1,500 meters (5,000 feet), and usually formed in the reservoir in which it is discovered. The gas occurs in the coal as free gas in fractures, as gas dissolved in water or as gas “adsorbed,” or stuck, onto the solid surfaces of the coal and held there by pressure. The adsorbed gas accounts for most of the gas present in the coal, as coal can store six to seven times as much gas as conventional reservoirs of similar size because coal has such a large internal surface area, according to the U.S. Geological Survey (USGS).
The methane can move about in the coal seams through fractures, and is held in place if water and “overburden” pressures are sufficient, says Peter Warwick, a coalbed methane researcher at USGS in Reston, Va. Those same pressures, however, can sometimes preclude the gas from being economically producible, he says. Another challenge associated with coalbed methane production is water — and its disposal — which almost always occurs with the gas.
Despite the challenges, coalbed methane is a pretty attractive resource, Warwick says. Finding the gas is not as labor-intensive as finding new conventional gas or oil reservoirs, as most of the large coal deposits in the United States and elsewhere have been mapped already, and methane occurs in most coal basins. Furthermore, most coalbed methane is easy to extract as it lies at shallow depths, he says, and tests to find the gas are relatively straightforward.
Defining the resource
Still, USGS says that coal is the most abundant fossil fuel resource in the United States, underlying some 13 percent of the lower 48 states. The United States also leads the world in coalbed methane production, producing about 1.3 trillion cubic feet of gas annually, according to the U.S. Energy Information Administration (EIA). Estimates vary widely on the amount of coalbed methane resources in the lower 48 states, but Ayers estimates that 700 trillion cubic feet of gas exist with more than 100 trillion cubic feet economically recoverable.
In the Powder River Basin, coal is so close to the surface and the coalbeds are so thick that companies producing methane from the coal seams use truck-mounted drilling rigs, which leave a smaller development footprint than traditional gas drilling rigs. Photograph is by Romeo Flores.
In 2004, EIA reported that the lower 48 states have 18.4 trillion cubic feet of coalbed methane that can be produced given current technology and prices. That number has certainly increased recently, Ayers says, as operators have drilled new wells in response to higher gas prices.
Today, close to 90 percent of coalbed methane production in the United States comes from the Rocky Mountain region. The major producing basins are the San Juan Basin in Colorado and New Mexico and the Powder River Basin in Wyoming and Montana, followed by other basins in Colorado, Utah, Alabama and the Virginias. The Gulf Coast and Illinois also host coal basins that are potential large resources of gas, says Perry of the Gas Technology Institute.
In any basin, coalbed methane production feasibility is dependent on several factors that vary from basin to basin, Warwick says. Generally, gas companies look for basins that have undergone geologic processes that have fractured the coalbeds somewhat, which can increase the production pathways and reduce the costs of producing the wells. However, too much faulting is not good either, as the gas will escape, he adds.
Gas operators also look for areas with large coal deposits, and ideally either little water in the coal or higher quality water with easy disposal options. Companies also prefer to develop coal deposits near infrastructure that will provide a way to get the gas to market. That is why Alaska, although possessing a tremendous amount of coal and methane, is not being produced as much as it could be, and why the Gulf Coast is an active producer despite having less gas than other places, Warwick says.
The San Juan Basin has been the most productive coalbed methane field in the world to date, but the Powder River Basin has now surpassed it in annual production, and is growing even more attractive due to lower production costs, says Romeo Flores, a project chief on the Powder River Basin at USGS in Lakewood, Colo. The discovery of vast amounts of gas in the Powder River Basin was surprising, as it challenged many early ideas about the ideal conditions for the occurrence of coalbed methane resources.
Although the Powder River Basin is a great source of thick mineable coalbeds, many people did not think the basin would be a good economic producer of coalbed methane due to several factors, Ayers says. First, “the coal is low rank,” — coal is ranked according to its caloric content; the higher the ranking, the better the coal. “And the gas content is only 30 to 70 cubic feet per ton of coal of biogenic methane, versus the preferred 300 cubic feet of thermogenic gas per ton of coal or more” that is seen in many other basins. Additionally, he says, the coal also contains a lot of water that would have to be drained off before gas could be produced.
So when companies began producing gas in the Powder River Basin in the mid-1990s, “we got thrown a curveball,” Ayers says. The economic environment, with tax subsidies and high gas prices, had made the basin an inviting prospect.
Today, the Powder River Basin is “one of the hottest” coalbed-methane-producing regions in the world, he says, with more than 17,000 producing coalbed methane wells, according to USGS. Almost all of those wells are in Wyoming, due to permitting issues in Montana (see sidebar). Another 50,000 wells are expected to be installed in the next several years, Flores says.
Each well in the Powder River Basin produces an average of 60 million cubic feet of gas per day, Flores says, as opposed to the more-productive San Juan wells that produce an average of 800 million cubic feet per day. Yet each Powder River well only costs $75,000 to $200,000 to install — versus the average $275,000 to install in San Juan — so operators can install more.
Part of the reason that wells cost so little to drill in Powder River is that the coal seams are very thick (up to 60 meters), and are very close to the surface — less than 865 meters in the center of the basin — which means it’s a lot easier and less expensive to get to the gas, Flores says. The average well in the basin, he says, is about 330 meters deep. Furthermore, he says, most of the wells are drilled by mobile water well rigs mounted on trucks, as opposed to more traditional oil and gas drilling rigs, which leave a large development “footprint.”
The coalbed methane wells can be drilled and completed in less than a week, Flores says, after which it takes three to six months to be connected to a pipeline and other infrastructure to start sending gas to market. Most coalbed methane wells initially produce almost solely water (using submersible pumps), and then, as the pressure decreases, the wells start producing more gas.
Wells in the Powder River Basin produce more water than elsewhere, which is a significant challenge facing gas companies there, due to the area’s semi-arid nature and the depletion of precious groundwater that comes with producing the gas, Flores says. In the basin, water is of potable quality, and is presently pumped at average rates of 105 barrels per day per well, so it must be disposed of, usually in surface runoff or reservoirs. But even with the considerable amount of water that has to be disposed of, the wells pay for themselves very quickly.
Producing gas in other basins isn’t quite as easy, Warwick says. In the Black Warrior Basin of Alabama and the Central Appalachian Basin of West Virginia and Virginia, for example, the wells are typically far deeper, and the coal seams far thinner (sometimes less than a meter thick in places). Although less water accompanies the higher ranked coals, the water is lower quality and cannot be run off, and so it is often reinjected into the aquifers, incurring an additional cost. Still, as natural gas prices keep rising and technologies improve, he says, even the harder-to-produce wells become more and more attractive.
“This tremendous resource is important to our future,” Ayers says, as it is to the future energy needs of countries around the world. However, to see a significant influx of money into coalbed methane exploration and production, “we need better gas prices and better technologies to economically produce gas from lower permeability coalbeds,” he says. While “research in this field is not as active as it should be,” there is a good bit going on.
Horizontal drilling is one such technology being actively developed for use in coalbed methane reservoirs. Already in use in the Appalachians, horizontal drilling technologies — in which companies drill one deep well bore and then extend out from it up to 1,060 meters laterally — cost more, but leave a smaller footprint, Warwick says.
One newer type of horizontal drilling uses “pinnate wells,” in which one primary well is drilled and four horizontal offshoots are drilled out from it at 90 degree angles. Multiple short extensions are then drilled from these offshoots creating a pattern like the veins in a leaf, Ayers says. This technology adds a greater recovery of total gas with fewer surface well heads.
Also under development are ways to enhance the gas recovery through injection of nitrogen or carbon dioxide, Ayers says. Because coal has a greater affinity for carbon dioxide and nitrogen molecules than methane, the carbon dioxide and methane will cause the methane molecules to be released from the coal matrix, making it more available for extraction, he says. That option has the added benefit, he says, of allowing “carbon sequestration,” in which carbon dioxide is permanently stored in the coal seams to offset atmospheric emissions of the gas. The Department of Energy is actively researching this field.
Still yet another area of research, Flores says, is “looking into the sustainability or renewability of biogenic gas.” One way to generate a continuous source of methane after it has been depleted from lower rank coalbeds, such as those in the Powder River Basin, he says, is to stimulate the growth of methanogens — microbes and bacteria that eat coal and process it into methane — in the coal to renew or stimulate gas production once the naturally occurring gas is extracted. “This is a new and exciting frontier,” Flores says, and something to keep an eye on.
“As we deplete conventional gas supplies worldwide, coalbed methane and other unconventional reservoirs such as tight sands and fractured shales will assume greater importance in meeting U.S. and international energy demands,” Ayers says. And as new technologies develop and gas prices continue to rise, coalbed methane will be a growing international resource over the coming decades, Warwick adds. “It won’t supply all our energy needs because we just use too much, but it’s still an important resource.”