Today, unconventional natural gas already accounts for one-third of the annual domestic production of the slightly more than 18 trillion cubic feet (Tcf) of natural gas from the lower 48 states, according to DOE. Most unconventional gas is differentiated from traditional natural gas sources in that the gas is produced from reservoir rocks with poor permeability — so poor that drillers must routinely enhance permeability in the rocks surrounding each producing well. Unconventional resources occur in low-permeability sandstones (tight gas), within unusual host rocks such as shales (shale gas) or coal seams (coalbed methane), or within gas hydrates in offshore continental margins and onshore Arctic permafrost. Although the U.S. Energy Information Administration (EIA) and National Petroleum Council foresee slight declines in future production of conventional natural gas in the lower 48 states, both onshore and shallow offshore, unconventional natural gas, as well as deepwater and subsalt offshore gas, will continue to provide a greater share of the overall gas supply in the future.
Ambrose, Potter and Briceno: Sources: EIA and NPC
The continuing growth of unconventional domestic gas supplies will lessen the need for LNG. These gas “plays” have already spurred a dramatic rise in drilling activity, with the U.S. gas-rig count surpassing 1,400 since August 2006, double the levels of 2002, according to Jeremy Platt, chair of the Energy Economics Committee of the Energy Minerals Division (EMD) of the American Association of Petroleum Geologists. This upsurge in drilling activity is attributable to rising natural gas prices. The sources of unconventional gas certainly vary, but many are currently economically viable.
Because unconventional gas resources are generally lower-grade compared to conventional gas, more wells — closely spaced over large areas (whole counties or larger) — are required to produce them. Tens of thousands of new wells have been drilled in the United States for unconventional gas in the past decade. Cost-effective exploration and production strategies must take into account the unique set of play elements that exist for each type of unconventional gas reservoir. An in-depth look at the rock properties is vital to understanding the true complexity of these unusual reservoirs.
Stephen Laubach and his team at the Bureau of Economic Geology (BEG) at the University of Texas at Austin are investigating low-permeability sandstones in the deep subsurface and examining links between mechanical and chemical processes in open fractures that can serve as permeability pathways for gas migration to the well bore. Observations of microfractures in thin sections demonstrate that fracturing and mineral cementation are linked processes. Laubach’s team learned that, ironically, fractures can be both clogged (bad news) or propped open (good news) by quartz cementation. Research efforts are now directed at predicting areas of enhanced fracturing where the cracks remain partially open to fluid flow.
Coalbed methane production in the United States and Canada is centered in the West.
Coalbed methane has a unique set of factors that affect production, including the type of coal, as well as cleat and fracture development, which together control migration of gas to the well bore. Coal-seam thickness and continuity also play a role in coalbed methane resource size by controlling reservoir volumes and extent. For example, the greatest coalbed methane production in the Cretaceous Fruitland Formation in the San Juan Basin in New Mexico and Colorado coincides with thick coal seams that accumulated landward (southwestward) of ancient shorelines of the shallow sea that once covered this region about 73 million years ago.
Shale gas research is expanding rapidly as a result of successes in the Barnett in Texas and the age-equivalent Fayetteville Shale in northern Arkansas, and the push to repeat those successes elsewhere. This research covers a wide spectrum of issues. Fundamental depositional controls on mudstones are being reexamined by geologists such as Juergen Schieber at Indiana University in Bloomington. Other major areas of study include pore and fracture development, physical rock properties of shales, and burial/thermal history with related hydrocarbon expulsion. All of these areas of research will help determine production strategies during the lifetime of shale gas plays, targeting recovery of a larger fraction of in-place resources.
Still, there are challenges to this production. The need for safe and efficient disposal of waste water produced during production can be a significant cost factor for producing both coalbed methane and shale gas. Many coalbed methane wells (for example, in the Powder River Basin in Wyoming) require the production of substantial volumes of water before methane becomes mobile and migrates to the well bore. Water is commonly used to fracture the rocks to enhance production in shale gas reservoirs such as the Barnett Shale, where an individual horizontal well can require up to 3 million gallons of water for multiple “frac jobs” in the well-completion process. The Railroad Commission of Texas reports that about 2.6 billion gallons of water were used for frac jobs in the Barnett Shale in 2006. Basinwide, this amounts to 2 percent of total water usage, but in some areas in the Fort Worth Basin, frac water is 10 to 20 percent of the local usage from the Trinity aquifer, according to Jean-Philippe Nicot of BEG. Most of this frac water is produced with the gas and must be disposed of by deep injection. One implication for the oil and gas industry, particularly in the Barnett Shale play, is that operators may eventually have to rely on fracturing techniques that use reconditioned, produced water or less water in general.
Gas hydrates —The New Frontier
Although natural gas from hydrates is not yet economically feasible to produce, it has been produced successfully in pilot wells in permafrost regions of Russia and Canada. Lessons learned from these investigations could result in viable commercial production by 2015, according to Art Johnson, chair of the EMD Gas Hydrates Committee. However, several safety and technical issues need to be resolved before gas hydrates can become a viable source of unconventional gas. For example, seafloor stability must be assured, as large-scale slumping of shallow, hydrate-bearing strata during production could potentially damage production facilities and release large amounts of methane into the water column and eventually into the atmosphere. Methane, volume-for-volume, is about 20 times more potent than carbon dioxide as a greenhouse gas, so unintended releases must be guarded against.
Important technical issues for gas hydrates include the need for improved petrophysical characterization — a difficult proposition, however. The three-dimensional distribution of gas hydrates can be complex, occurring either in disseminated or tabular form. Realistic modeling of this distribution has a significant bearing on an accurate determination of gas saturation and, thus, on potential resource size. One step in determining distribution of hydrates in sediments involves the correlation of gas-hydrate rock properties with seismic data.
Ambrose, Potter and Briceno are all at the Bureau of Economic Geology at the University of Texas at Austin. The authors gratefully acknowledge Joel Lardon, who drafted the second figure, and Lana Dieterich, who helped edit the manuscript.