Natural gas production from deep, hydrocarbon-rich shale formations, known as “shale gas,” is one of the most quickly expanding trends in onshore domestic oil and gas exploration. Recent activity in North America has demonstrated a wide distribution of these shales containing vast resources of natural gas. Shale traditionally has been regarded as a hydrocarbon source rock or seal. Following applied research and experimentation by government, academia and industry over the past few decades, shales currently are recognized as complex gas reservoirs that require unconventional thinking to produce gas. It has taken many decades to reach the current understanding of how gas is stored in coal beds and how to produce the gas (coalbed methane). In many ways, shales are even more complex than coals, and our knowledge of shale-gas production is still at the beginning of the learning curve.
Definition of Shale Gas and Liquids
Gas shales are thought of dually as hydrocarbon source rocks and fine-grained tight-gas reservoirs. Economic gas-shale plays include both a hydrocarbon source rock for the source of methane (thermogenic and/or biogenic) and a brittle lithology that contains natural and induced fractures that provide permeability to access the gas-storage sites. Lacking either a source of methane or permeability will result in an uneconomic gas shale.
Even though shale makes up much of the rock record, not all shales will be economic gas shales. The best gas shales are organic-rich black shales commonly in the gas window (typically >1.4% vitrinite reflectance), but with some important exceptions. Most gas shales contain oil-generative organic matter (e.g., Type II kerogen) in quantities (measured as Total Organic Carbon content) high enough to generate commercial quantities of methane. In addition to free gas stored in pores and fractures, gas shales also contain sorbed (adsorbed and absorbed) gas associated with the organics and in solution.
History of Gas Shales
According to Curtis (2002), the first commercial gas well in the U.S. was completed in the organic-rich Dunkirk Shale (Devonian) in New York in 1821. Hill and Nelson (2000) estimated more than 28,000 shale-gas wells have been drilled in the U.S. since the early 1800s.
The first gas production from the Barnett Shale in the Fort Worth Basin was in 1981 by Mitchell Energy and Development Corporation (Curtis, 2002). Until the success of the Barnett Shale, it was thought that natural fractures needed to be present in gas shales. Low-permeability gas-shale plays are currently viewed as technological plays where advances in horizontal drilling, fracture stimulation and multiple frac stages, micro-seismic fracture mapping, simul-fracs, and the application of 3-D seismic have contributed to the success of gas-shale wells.
Curtis (2002) summarized the main gas-shale plays to that time: Antrim Shale (Devonian) in the northern Michigan Basin; Barnett Shale (Mississippian) in the Fort Worth Basin, Texas; Lewis Shale (Cretaceous) in the San Juan Basin; New Albany Shale (Devonian) in the Illinois Basin; and Ohio Shale (Devonian) in the Appalachian Basin. Recent additions include the Woodford Shale (Devonian) in Oklahoma; Fayetteville Shale (Mississippian) in Arkansas; Haynesville Shale (Jurassic) in Louisiana; Marcellus Shale (Devonian) in the Appalachian Basin; Utica Shale (Ordovician) in New York; and Eagle Ford Shale (Late Cretaceous) in Texas. Cardott (2008) listed 57 United States and Canada gas-shale plays.
Gas-Shale Reservoirs and Technology
It cannot be emphasized enough that gas shales are complex petroleum systems and generalizations have limited application. Having said that, some of the generalized lessons learned about gas shales from recent presentations and articles are as follows.
- Gas shales require fractures as permeability pathways for gas. Fractures can be either natural or induced. Orientation, extent, type, and frequency of fractures need to be studied and understood.
- Mineralogy of shales is important for fracture generation. Fractures are more prevalent and created more easily in silica-rich and carbonate-rich shales than in clay-rich shales. Mineralogy alone may make or break a gas-shale play lacking innovative completion technology with particular attention to frac fluid types.
- Gas shales drainage area depends on the extent of fracture development (permeability) and whether the well is vertical or horizontal. In general, drainage area for a vertical well is considered to be on the order of tens of acres with well spacing of 10-27 acres. Horizontal wells push this drainage area along the length of the lateral. Drainage area is an ongoing concern and area of research.
- Type II kerogen (oil-generative organic matter) is the predominant type of organic matter in current gas-shale plays.
- Liquid hydrocarbons and water are detrimental to a gas-shale play.
- If present in abundance in the oil window, large oil molecules may plug permeability and slow the rate of gas production. The transition from the oil window to the gas window is currently estimated to occur at 1.15-1.4% vitrinite reflectance (Ro) (Jarvie and others, 2005). Higher gas rates are possible at >1.4% Ro.
- Antrim and New Albany shales produce significant amounts of water (average of 30 bbl/day) with predominantly biogenic methane (Curtis, 2002). Connection to an aquifer (especially along faults) will ruin an otherwise good gas-shale well. Unlike coalbed methane wells where water is beneficial for gas desorption, water is generally a detriment to gas shale wells.
- Even though gas sorbed (adsorbed and absorbed) on organic matter and clays is important during the life of the well, free gas is important in the first months of a gas-shale well. How free gas occurs in shales and conditions necessary for production are currently not well understood.
Concerning minimum requirements, some parameters may be interchangeable or are too variable to specify.
- Thickness (although 50 ft has been suggested as a minimum thickness, it depends on many variables, including economics).
- Depth (what are the minimum and maximum economic depth limits?).
- Pressure (what is the importance of pressure, from hydrostatic to overpressured, to drive gas production?).
- Organic matter type (kerogen type) and quantity (total organic carbon) limits.
- Thermal maturity (minimum and maximum limits; optimum range?).
- Gas type (biogenic, thermogenic, or mixed).
- Gas content (measurement methods; acceptable range?) and gas composition.
We invite you to join the Energy Minerals Division to gain access to the Shale Gas & Liquids Committee members-only web site where there are reports, presentations, reference lists, meeting abstracts, web links, calendar of gas shale conferences, and more.
For a complete version of the above, see the Committee’s Annual Report (May 2013) on the EMD Members Only page (log-in required).
If you would like to learn more about gas shales or to receive information on gas shales, or on activities of the EMD Shale Gas & Liquids Committee, join the EMD http://emd.aapg.org/emdApplication.pdf . If you are already an EMD Member, see “Members Only Page” http://emd.aapg.org/members_only/gas_shales/index.cfm for updates on gas shales, for links to technical information on gas shales, and for related environmental information that may impact gas shales.
For further information on this committee’s activities, go to the Members’ Only Web page or contact:
Neil Fishman, Chair
Phone: +1 (713) 496-5160