1. IntroductionThe term “unconventional resources” (UHC) refers to those hydrocarbons obtained from natural petroleum reservoirs that are deemed unusual for oil and gas companies to produce due to physically limiting factors such as low permeability and high hydrocarbon viscosity. The most popular unconventional fuels come from gas shale, tight gas sands, and coal bed methane; however a more complete list would include oil shale, tar sands, heavy oil reservoirs, and methane hydrates as well.
Since there is a wide variety of factors that would make a resource play unconventional and since these factors are sometimes unique to particular reserve types, there are different ways to define unconventional hydrocarbons. For example, the NPC defines unconventional gas as natural gas that can only be recovered after using a combination of several advanced recovery technologies whereas oil sands are defined as reservoirs of semi-liquid hydrocarbons with a viscosity in excess of 10000cP.
These definitions are often incomplete by themselves. The key point is that unconventional resources are lower quality fuel sources and are not as economically viable as crude oil and conventional gas. To further understand the importance of unconventional resources this it is useful to also understand the resource triangle concept.
2. Resource TriangleThe Resource Triangle concept illustrates a trend where resource deposits that are technologically complex to exploit are more ubiquitous than those deposits in which resources can easily be extracted from. For example crude oil reservoirs, at the tip of the triangle, are simple to develop but short in supply; whereas, methane hydrates, at the base of the triangle, are practically infinite in supply but several technical barriers prevent their extraction. A recent evaluation of unconventional and conventional hydrocarbons in 7 United States basins confirmed that this relationship holds true for hydrocarbon reservoirs throughout the country.
There are several characteristics of unconventional hydrocarbons that exemplify the resource triangle trends. They are as follows: • Unconventional hydrocarbon deposits are of lower quality but higher prevalence than conventional hydrocarbon deposits. • As technology improves unconventional hydrocarbons will become more feasible to pursue. • As demand for oil increases unconventional reserves will become more profitable to develop. • As the availability of conventional reserves reaches a peak value a smooth transition of unconventional resources entering the market will supply the demand gap.
The Resource Triangle concept is useful in two ways. It provides a Hierarchical arrangement of resources with the higher quality reserves at the thinner tip of a pyramid (indicating the rarity of the reserve) and the lower quality reserves at the broader base of the pyramid (indicating the extensiveness of the reserve). The concept can also be used as a rough approximation to correlate the total recoverable conventional resources in a basin to the total recoverable unconventional resources in that basin. 3. Classification & Evaluation
The purpose of classifying hydrocarbon resources is ultimately to facilitate communication of key concepts. Resource classification elucidates the commercial potential of a given accumulation of petroleum. The SPE, AAPG, WPE, and SPEE have funded the development of the Petroleum Resource Management System (PRMS) in an effort to standardize the definitions of petroleum resources and how they are estimated. According to this classification scheme all petroleum resources, conventional and unconventional, fall under the overall category of “Total Petroleum Initially in Place (PIIP)”.
This category is then subdivided into “Discovered PIIP” and “Undiscovered PIIP”. Discovered PIIP is divided into “Commercial” and “Sub-commercial”. Commercial PIIP includes petroleum that is currently being “Produced” and petroleum “Reserves” which are recoverable accumulations that are soon to be produced. Unconventional hydrocarbons currently span this classification scheme from Sub-commercial petroleum accumulations to petroleum reserves to petroleum that is being produced.
So it is important to realize that “unconventional hydrocarbons” is an umbrella term that is inclusive of resources we are currently producing, about to produce, developing technologies to produce, and contemplating one day being able to produce. While unconventional hydrocarbons can be classified under the same system as conventional hydrocarbons it has been proposed that a different evaluation scheme be developed. Evaluation of resources is important for determining the level of uncertainty associated with developing a petroleum reserve for production.
Since there is much data from a long history of pursuing conventional resources a common method for evaluating the uncertainty of a conventional reservoir is by comparing the physical parameters associated with that reservoir with an analogous historical reservoir.Clearly such methods are not as available for evaluating unconventional resources since there is a less developed history and limited data associated with these reserves. A better unconventional evaluation scheme will be developed as the pursuit of these resources matures with time.
3.1. Unconventional Oil (Liquid)Unconventional liquids currently provide 2.1% of world annual liquids production. Annual average production growth, however, is unlikely to exceed 0.4 million b/d (barrels/day). This compares with ~ 4 million b/d annual decline in the world’s currently producing conventional fields. Unfortunately, liquid unconventionals also come with a lot of issues: energy intensity (and therefore greenhouse gas emissions); water supply/disposal; high capital costs and labour requirements; footprint. We can expect that technology will solve many (but not all) of these issues. There are three principal types of unconventional hydrocarbon liquids:
3.1.1. Heavy OilConventional oil is formed at high temperatures below earth’s surface. If conventional oil accumulations migrate to the surface region where the temperature is lower and bacteria thrive they will be partially consumed by microbial and chemical processes, degraded by weathering, and lighter hydrocarbons will escape the accumulation. This ultimately produces a lower grade, more viscous hydrocarbon referred to as heavy oil. Heavy oil, extra-heavy oil, and bitumen are deficient in hydrogen and have high carbon, sulfur, and heavy metal content. Hence, they require additional processing to become a suitable feedstock for a normal refinery.
The Largest accumulations of heavy oil are located in Canada (1.7 trillion barrels in place) and Venezuela’s Faja Tar Belt (1.2 trillion barrels in place). The United States on the other hand only has an estimated .0437 trillion barrels of heavy oil in place throughout the continental states (excluding Alaska). Naturally, Canadian companies have been responsible for many of the technological advances in heavy oil applications.
Heavy oil is considered an unconventional hydrocarbon because it is three to four times more costly to produce than conventional oil. This additional cost is present for two reasons: One, enhanced recovery techniques must be used to produce heavy oil since it is too viscous to flow at bottom hole pressures. And two, the recovered bitumen must undergo additional processing because the hydrogen (and thus energy) content is so low.
The most common method for producing heavy oil in situ (in place) is steam assisted gravity drainage (SAGD). In this process two horizontal wells are drilled in the reservoir, a steam injection well and a production well. The Steam injection well runs parallel to the production well and several meters above it. As steam is released into the reservoir reducing the viscosity of the heavy oil, it begins to sag downwards due to gravity and will be collected in the production well where it is pumped to the surface.
Another method developed by Siemens will use eddy currents created by electromagnetic induction to “melt” the heavy oil. In their process a large inductor, kilometers long, will run through a horizontally drilled well above a production well as a ground level power supply runs current through the inductor. This method is the same as SAGD except the energy used to heat the viscous oil comes from running current through a conductor rather than heating steam in a boiler.
3.1.2. Tar SandsTar obtained from tar sands, also known as oil sands or bitumen sands, can be thought of as an extremely viscous version of the heavy oil described above. According to common terminology, Heavy oil is less viscous than Extra heavy oil which is less viscous than Tar. Each of these resources are pursued because of their bitumen content. Bitumen, an organic material, is also considered the source rock for other conventional and unconventionalhydrocarbons.
It is unusual to develop tar sand reservoirs using SAGD or other enhanced recovery techniques; rather, the tar must be physically extracted using open pit mining. After the tar is extracted the bitumen must be upgraded. Typically this is done by “coking” the bitumen which involves a high temperature process that reduces the tar into a low grade, low viscosity hydrocarbon. This low viscosity is desirable because these hydrocarbons must be pipelined to refineries. However, before they are sent off, the low grade fuel, which is also unstable, must be upgraded and stabilized through a secondary process which may vary from company to company.
A large portion of the world’s supply of synthetic crude oil comes from the Alberta province of Canada. In fact over half of the synthetic crude oil produced by Canada is used by United States consumers. The Athabasca oil sands reserve is the largest in Alberta containing an estimated 335 billion barrels of crude bitumen.
Synthetic crude oil made from bitumen is one example of an unconventional hydrocarbon that is actually a major component of the world energy market. Gas from shale, tight sands, and coal would be another such example.
3.1.3. Shale OilOil shale is the name given to a class of fine grained sedimentary rocks that are rich in kerogen, a hydrocarbon made up of cyanobacteria remains. Kerogen is naturally converted into oil over a geologic timescale. If an oil shale deposit is buried deep enough that it is exposed to the proper pressure and temperature for a long period of time the kerogen in the reservoir will gradually be converted to higher grade oil.
The Utah, Colorado, and Wyoming region hosts the world’s largest accumulation of oil shale, 1.5-1.8 trillion barrels worth. The black rock can be seen within the western slopes and outcrops of the area. There is an old western lore of a settler in the 1800s that built his homestead in the Piceance Basin of Colorado. According to the story the settler finished of his log cabin by constructing a chimney and fireplace made from the surrounding rocks of the region. Shortly after he lit his first fire the chimney became engulfed in flames and his cabin was reduced to ashes; he had built the chimney out of oil shale.
In order to obtain a fuel from oil shale developers must synthetically convert the kerogen within the rock into oil by retorting it, heating it to temperatures above 650F. the first commercial retorting facility was constructed in France in the 1830s. Oil shale is an unconventional hydrocarbon not due to technological limitations but due to the fact that the pursuit of oil shale depends on oil prices in the market which, amongst other things, is a function of supply and demand. Since more money goes into the retorting of oil shale energy companies have historically only pursued this resource when the price was right.
For instance in the early 1800s there was a thriving oil shale industry but then after 1859 the entrance of easily obtainable crude oil into the market lowered prices and killed the oil shale industry. Another example of oil shale’s inability to compete with conventional oil can be found in china’s oil shale history. Prior to the 1960s china’s oil shale industry was thriving with a maximum annual production of 5.46 million barrels of oil; however, after the large Daqing oil field was discovered oil shale production declined and then shut down. In this way oil shale is a perfectly modeled by the resource triangle concept.
There are three general procedures for extracting oil from oil shale, open pit mining, modified in situ extraction, and true in situ extraction. Each of the particular technologies that have been developed for working oil shale fields falls under one of these categories. Additionally, are slightly more eco-friendly versions of mining which require a lesser degree of surface removal and are sort of a cross between modified in situ and open pit mining.
However, true in situ technologies are least topographically damaging as they involve drilling for oil shale rather than the removal of vast amounts of overburden. The following is a brief description of each of the said procedures. In open pit mining the overburden (portions of the ground that do not contain oil shale) is removed creating a large open pit and the pit becomes deeper and deeper as the oil shale is mined until there is no longer a significant ratio of oil shale to overburden.
The oil shale fragments are then transported to surface retorts which process the oil shale producing a low grade synthetic oil which must then be sent to a refinery for further processing. In modified in situ processing underground oil shale mines are excavated and rather than transporting oil shale fragments to an external retort, the oil shale is retorted in place, in situ. This is done by reducing sections of a shale bed into rubble and the subsequently heating the rubble and collecting the synthetic oil and gas byproducts. True in-situ processing does not require mining. Instead, the oil shale is retorted underground by drilling a series of heating holes into a shale bed, heating the reservoir for a period of time and then pumping the synthetically processed oil and gas up a production well.
There are a number of companies that have developed true in-situ processes however Shell is the only company that has actually constructed several pilot fields and demonstrated the feasibility of their technology. The most recently developed true-in situ processes are fundamentally the same differing only in how the developer chooses to heat the oil shale. For instance, Shell’s In Situ Conversion Process (ICP) uses electric heaters suspended in vertical wells that conduct heat to the reservoir for a period of up to 2 years. Raytheon and CF take an even more creative approach.
Their process uses an inverted radio frequency transmitter that emits high frequency radio waves which can sufficiently heat the reservoir in only several months. Independent Energy Partners (IEP) takes the technology a step further, implementing the use of specialized solid oxide fuel cells. Their Geothermic Fuel Cells produce intense heat (up to 1000°C) powered by the use of native hydrocarbons as a source of ions.
3.2. Unconventional GasUnconventional gas is no longer unconventional in the United States. The three principal types of unconventional gas accounted for 46% of US gas production in 2007 (Fig. 4).In 2007, unconventional natural gas provided 9.4% of global gas production. Apart from the USA the other principal producers are Canada and Australia.
Unconventional natural gas resources offer significantly less resource potential than unconventional liquids but global distribution of these gas resources is much more evenly spread. Recoverable resources can require good technology in order to be convertedinto reserves (micro-seismic mapping; fracture and stimulation; smart wells). Most plays are «statistical» in nature: many wells are needed to understand the play and best drilling/completion techniques.
Horizontal drilling with multilaterals has transformed unconventional gas production. To convert resources into reserves may also require a very large number of wells (10-acrespacing vs. 640 for conventional). As per-well reserves and productivity are low, unconventional resources are more attractive where an established pipeline infrastructure already exists (e.g. North America; Europe). Unconventional gas has fewer serious issues than liquids. Most of these are environmental but it also provides the possibility of CO2 sequestration in coal seams. There are three main sources of unconventional gas production and a fourth that has significant future potential.
Fig. 4: US annual natural gas production by source. Data source: US Energy Information Administration.
3.2.1 Coalbed GasCoalbed methane is a natural gas that occurs in association with coal. During the coalification process, large amounts of methane are produced. Since coal has such a large internal surface area the methane is adsorbed into the coal matrix. In fact, coal beds can store 7 times the amount of gas that a conventional gas reservoir of equal rock volume can. So why is coal bed methane considered an unconventional resource?
Coal beds are also natural aquifers and the water that runs through the natural fractures and pores in a coal bed traps the methane inside of the coal. In order to produce methane from coal bed reservoirs added expenses must go into artificial lift to remove the water and free the methane. Additionally, waste water treatment expenses contribute to making coal bed methane less economically viable than conventional gas.
A major issue in the production of coal bed gas is the trade-off between greater pressure and gas content with increasing depth/coal rank and better permeability and produced water quality if shallow. The shallow depth of many potentially productive coal seams gives rise to a number of environmental problems, however, among them being the need for a large number of wells and the potential impact of hydraulic fracturing on drinking water.
According to the US Geological Survey there are 7,500 tcf of coal bed methane in place worldwide 700 of which is in the United States. As such, coal bed methane plays have received much attention in the the US. For instance, in the Powder River Basin play of Wyoming over 11,000 wells were drilled by 2004 and production rates have been as high as 1 billion cubic feet a day.
3.2.2. Anomalously-Pressured Basin-Centred Gas («Tight Sand Gas») This type of unconventional gas play comprises gas dissolved in abnormally-pressured low-permeability aquifers in the central (generally deeper) part of basins. They tend to be overpressured in subsiding basins and underpressured in uplifted and eroded basins. Tight gas reservoirs are generally gas saturated with little or no free water. As the name suggests the typical lithology is sandstone/siltstone and only very rarely carbonate.
The updip seal may be a gas/water transition zone, causing a reduction in relative permeability. Matrix permeabilities are low in any case (0.001 – 0.1 millidarcies) as are matrix porosities (< 13%). As a consequence, tight reservoirs have significant irreducible minimum water saturation (> 30%) and require hydraulic fracturing. The methods for extracting gas from tight sand formations are analogous to those methods used for extracting gas from shale. Hydraulic fracturing and horizontal drilling are essential in most formations; however, there is no defined protocol for working gas from tight sands and shale.
This is why the task is often assigned to engineers with many years of practical experience who can develop particularized solutions for any given reservoir. In place resources in North America alone are enormous (USA: 6,800 tcf; Canada: 560 tcf) but although tight gas reservoirs are known from around the world, estimated global recoverable resources are much smaller at some 1,500 tcf, mainly on account of the typically low recovery factors. Recovery is a function of the extent to which fractures extend from each well. In the US, this has resulted in drilling densities as high as one well per 10 acres (64 wells per square mile, 25 wells per square km).
3.2.3. Shale GasOver 30 years ago development of the Barnett shale in northwest Texas kicked off the beginning of the next generation of gas shale technology. The challenges that have been faced include low permeability, high capillary pressure, and an overall tight encapsulation of gas within the shale matrix. A variety of technical procedures were established as Barnett shale play developers combated these issues. The general procedures that had evolved and are widely used today involve three main steps. First a series of wells are drilled horizontally through the shale bed to maximize wellbore exposure.
Then fractures are administered through the wellbore casing and the surrounding reservoir rock. These fractures enable the flow of gas into the wellbore. Finally, production is maximized through the use of enhanced oil recovery techniques where heated fluids, typically steam, are injected into the reservoir to pressurize the natural gas forcing it into the well bore. Recovery efficiency using the above techniques ranges from 15-35% and can be as high as 50% of the total resources. As a reference, the average recovery efficiency in conventional reservoirs is about 70%. Low recoverability and increased energy input illustrate a common theme in unconventional resource development.
3.2.4. Gas HydratesGas Hydrates are crystalline formations where water molecules surround individual gas molecules forming a structured lattice. Hydrates form along a very particular pressure-temperature gradient. This gradient is maintained beneath the sea floor where anaerobic bacteria thrive. at these depths the pressure is great enough and the geothermal temperature is low enough that methane hydrates form as methanogens release methane, a byproduct of their respiration.
This has created vast reservoirs of methane hydrates locked up between the pore spaces of deep sea sediments. As mentioned previously these reserves are estimated to contain on the order of 1017 cubic feet of natural gas. In order to extract this gas the methane hydrates must be tempted past their crystalline stability point by depressurizing portions of the reservoir. This can be done by recovering water and conventional gas deposits that surround the hydrates thus decreasing the local pressure.
When this is done the hydrate will “melt” and a mixture of water and gas will be recovered in the production well. While the technology for working hydrate reservoirs is not beyond energy company capabilities, the methane hydrates are still considered unconventional because an economically viable production solution has yet to be developed.
The Largest step in the direction for sustained methane hydrate production tests was taken by Japanese and Canadian organizations that funded the Mallik production program. These novel tests successfully produced methane hydrates using depressurization for a period of 6 days, something that had never before been accomplished.
4. The FutureThe availability of conventional fuel sources, particularly crude oil, is dwindling. Many misinterpret this as an indication that the oil and gas industry will soon come to an end. On the contrary there is an estimated 8 trillion barrels worth of in-place unconventional oil, 32,598 trillion cubic feet of tight gas in place, and 730,589 trillion cubic feet of gas hydrates in place.
Together these resources are many times greater than the known accumulations of conventional hydrocarbons; However, the vast majority of unconventional hydrocarbon accumulations are not obtainable with current technologies. The question is this: will increasing demand for oil and gas drive the incentive for research and development to such a degree that we can gain access to these reservoirs?
And more importantly, will the production of unconventional hydrocarbons succeed in filling the demand gap? Stark showed that, to date, the supply of unconventional gas and oil has lagged behind the demand. However, recent history tells us that strong economic cues play a very large role in advancing or halting the pursuit of unconventional hydrocarbons.
1.Altun, N. E.; Hiçyilmaz, C.; Hwang, J.-Y.; Suat Bağci, A.; Kök, M. V. (2006). “Oil Shales in the world and Turkey; reserves, current situation and future prospects: a review” (PDF). Oil Shale. A Scientific-Technical Journal (Estonian Academy Publishers) 23 (3): 211–227. ISSN 0208-189X. Retrieved 2007-06-16.
2.Andrews, Anthony (2006-04-13) (PDF). Oil Shale: History, Incentives, and Policy. Congressional Research Service. Retrieved 2007-06-25.
3.Bartis, James T.; LaTourrette, Tom; Dixon, Lloyd; Peterson, D.J.; Cecchine, Gary (2005) (PDF). Oil Shale Development in the United States. Prospects and Policy Issues. Prepared for the National Energy Technology Laboratory of the U.S. Department of Energy. The RAND Corporation. ISBN 978-0-8330-3848-7. Retrieved 2007-06-29.
4.Brendow, K. (2003). “Global oil shale issues and perspectives. Synthesis of the Symposium on Oil Shale. 18–19 November, Tallinn” (PDF). Oil Shale. A Scientific-Technical Journal (Estonian Academy Publishers) 20 (1): 81–92. ISSN 0208-189X. Retrieved 2007-07-21.
5.Dyni, John R. (2006) (PDF). Geology and resources of some world oil shale deposits. Scientific Investigations Report 2005–5294. United States Department of the Interior, United States Geological Survey. Retrieved 2007-07-09.
6.”Special Wastes”. United States Environmental Protection Agency. United States Federal Government. March 9, 2009. Retrieved 30 December 2009.
7.Francu, Juraj; Harvie, Barbra; Laenen, Ben; Siirde, Andres; Veiderma, Mihkelformat = PDF (May 2007). A study on the EU oil shale industry viewed in the light of the Estonian experience. A report by EASAC to the Committee on Industry, Research and Energy of the European Parliament. European Academies Science Advisory Council. Retrieved 2011-05-06. (PDF) Annual Energy Outlook 2006. Energy Information Administration. February 2006. Retrieved 2008-04-18.
8.(PDF) World Energy Outlook 2001: Assessing Today’s Supplies to Fuel Tomorrow’s Growth. Organisation for Economic Co-operation and Development/International Energy Agency. 2001. ISBN 92-64-19658-7. Retrieved 2009-06-27.
9.Koel, Mihkel (1999). “Estonian oil shale”. Oil Shale. A Scientific-Technical Journal (Estonian Academy Publishers) (Extra). ISSN0208-189X. Retrieved 2007-07-21.
10. Luik, Hans (2009-06-08). “Alternative technologies for oil shale liquefaction and upgrading” (PDF). International Oil Shale Symposium. Tallinn, Estonia: Tallinn University of Technology. Retrieved 2009-06-09.
11.Qian, Jialin; Wang, Jianqiu; Li, Shuyuan (2003). “Oil Shale Development in China” (PDF). Oil Shale. A Scientific-Technical Journal (Estonian Academy Publishers) 20 (3): 356–359. ISSN 0208-189X. Retrieved 2007-06-16.
12.(PDF) NPR’s National Strategic Unconventional Resource Model. United States Department of Energy. April 2006. Retrieved 2007-07-09.
13.(PDF) Survey of energy resources (edition 21 ed.). World Energy Council. 2007. pp. 93–115. ISBN 0-946121-26-5. Retrieved 2007-11-13.
14.Attanasi, E. D. and Meyer, R. F., 2007, Natural bitumen and extra-heavy oil, in Survey of Energy Resources 2007, eds. J. Trinnaman and A. Clarke: World Energy Council, p. 119-143. http://www.worldenergy.org/publications/survey_of_energy_resources_2007/default.asp
15.Bartberger, C.E., Dyman, T.S., and Condon, S.M., 2002, Is There a Basin-Centered Gas Accumulation in Cotton Valley Group Sandstones, Gulf Coast Basin, USA?, in Nuccio, V. F., and Dyman, T.S., eds., Geologic Studies of Basin-Centered Gas Systems: U.S. Geological Survey Bulletin 2184-D, 38 p. http://pubs.usgs.gov/bul/b2184-d/
16.Bartberger, C.E., Dyman, T.S., and Condon, S.M., 2003, Potential for Deep Basin-Centered Gas Accumulation in Travis Peak (Hosston) Formation, Gulf Coast Basin, USA, in Nuccio, V. F., and Dyman, T.S., eds., Geologic Studies of Basin-Centered Gas Systems: U.S. Geological Survey Bulletin 2184-E, 36 p. http://pubs.usgs.gov/bul/b2184-e/
17.Burruss, R.C., 1997, Migration of Hydrocarbon and Nonhydrocarbon GasesFrom the Deep Crust; Composition, Flux, and Tectonic Setting, Chapter M, in Dyman, T. S., Rice, D.D., and Westcott, W.A., eds., Geologic Controls of Deep Natural Gas Resources in the United States: U.S. Geological Survey Bulletin 2146-M, p. 211-215. http://pubs.usgs.gov/bul/b2146/M.pdf
18.Dyman, T.S., and Kuuskraa, V.A., eds., 2001, Geologic Studies of Deep Natural Gas Resources: U.S. Geological Survey Digital Data Series DDS-67, Version 1.00. [CD-ROM]. http://pubs.usgs.gov/dds/dds-067/
19.Crovelli, R.A., 2001, Probabilistic Method for Subdividing Petroleum Resources into Depth Slices, Chapter F, in Dyman, T. S., and Kuuskraa, V.A., eds., U.S. Geological Survey Studies of Deep Natural Gas Resources: U.S. Geological Survey Digital Data Series DDS-67, Version 1.00, p. F1-F5. [CD-ROM]. http://pubs.usgs.gov/dds/dds-067/CHF.pdf
20.Crysdale, B.L., Schenk, C.J., and Meyer, R.F., 1992, Tar sands and heavy oils; resources, recovery, and realism, in Carter, L. M. H., ed., U.S. Geological Survey Research on Energy Resources–1992 Program and Abstracts Eighth V.E. McKelvey Forum on Mineral and Energy Resources, Houston, TX, February 17-20, 1992: U.S. Geological Survey Circular 1074, p. 15-16. http://pubs.er.usgs.gov/pubs/cir/cir1074
21.Dolton, G.L., and Crovelli, R.A., 1997, Assessment Methodology for Deep Natural Gas Resources, Chapter O, in Dyman, T. S., Rice, D.D., and Wescott, P.A., eds., Geologic Controls of Deep Natural Gas Resources in the United States: U.S. Geological Survey Bulletin 2146-O, p. 233-239. http://pubs.usgs.gov/bul/b2146/O.pdf
22.Dyman, T.S., and Cook, T.A., 2001, Summary of Deep Oil and Gas Wells in the United States through 1998, Chapter B, in Dyman, T. S., and Kuuskraa, V.A., eds., Geologic Studies of Deep Natural Gas Resources: U.S. Geological Survey Digital Data Series DDS-67, Version 1.00, p. B1-B9. [CD-ROM]. http://pubs.usgs.gov/dds/dds-