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Abstract

For more than 50 years, the U.S. natural gas industry has been developing unconventional gas reservoirs. Production of natural gas from eastern Devonian Shales and tight gas sands in Texas and in the Rocky Mountain and Midcontinent regions has been the proving ground for many innovations in well drilling, completion, and stimulation. Over the past two decades, successful gas production from coal seams and from shales, such as the Barnett Shale, has led to new drilling and completion technologies. In 2007, unconventional gas production was 9.15 Tcf, accounting for 47% of the U.S. dry gas production, and eight of the top ten U.S. gas plays were producing from unconventional reservoirs. Unconventional gas reservoirs, led by shale, are expected to provide the majority of the U.S. gas supply growth in coming decades. Clearly, many basins worldwide contain large volumes of unconventional gas resources that have not been assessed. As conventional oil and gas reservoirs are depleted in those basins, inevitably, unconventional gas reservoirs will be developed. The key to successful development will be the proper application of existing technologies and the continued development of new technologies.

Over the past 5 years, a team of engineers and geoscientists in the Crisman Institute at Texas A&M University have worked to capture the critical geologic and engineering properties of unconventional gas reservoir in 25 North American basins. The primary objectives of this research are to (1) understand the gas resource distributions and the best technologies for unconventional gas recovery and economics, and (2) assess the volumes of unconventional gas in basins, worldwide, beginning with North America, using the concept that resources are log-normally distributed (resource triangle). Our evaluations of North American basins indicate that the Technically Recoverable Resource of unconventional gas in any basin will be approximately 5-10 times greater than the ultimate recovery (cumulative production plus proved reserves) from all conventional oil and gas reservoirs in the same basin.

Our research shows that historic unconventional gas drilling and production have been impacted strongly by technology and gas prices. The oil and gas industry should continue developing new technology to access unconventional gas reservoirs in diverse settings. The Research Partnership to Secure Energy for America (RPSEA) is supporting the development of new technology to optimize recovery of unconventional gas resources in the U.S. In coming decades, this technology that is being developed in the U.S. will be deployed worldwide to increase natural gas production from unconventional reservoirs and to contribute needed energy supplies.

Introduction

For more than 50 years, the natural gas industry has been developing unconventional gas reservoirs in the U.S. Unconventional gas production has grown over the past 3 decades, until today, it nearly equals production from conventional gas reservoirs. Unconventional gas is the term commonly used to refer to low-permeability reservoirs that produce mainly dry natural gas. Many of the low-permeability reservoirs that have been developed in the past were tight sandstone, but increasingly large quantities of gas are being produced from low-permeability carbonates, shales, and coal seams.

To optimize the development of an unconventional gas reservoir, geoscientists and engineers must optimize the number of wells drilled, as well as the drilling and completion procedures for each well. Often, more data and more engineering manpower are required to understand and develop unconventional gas reservoirs than are required for higher permeability, conventional reservoirs. On an individual well basis, unconventional gas wells will produce less gas over a longer period of time than one expects from a well completed in a higher permeability, conventional reservoir. As such, many more wells (or smaller well spacing) must be drilled in a unconventional gas reservoir to recover a large percentage of the original gas in place, when compared to a conventional reservoir.

The optimum drilling, completion and stimulation methods for each well are a function of the reservoir characteristics and the economic situation. Some unconventional gas reservoirs are in south Texas, while others are in the deserts of Egypt. In fact, every major oil and gas basin in the world has unconventional gas reservoirs that can be developed, given the right combination of gas prices and development costs. The costs to drill, complete, and stimulate any given well, as well as the price of natural gas and the availability of a gas market, affect how unconventional gas reservoirs are developed. As with all engineering problems, the technology used is a function of the economic conditions associated with the project.

Definition of Unconventional Gas

In the 1970s, the United States Government declared that tight sands, coal beds, and shales were to be considered as unconventional gas reservoirs and would be eligible for higher gas prices or tax credits (Section 29 tax credit). The government defined a tight gas sand formation as a reservoir where the expected value of permeability to gas flow would be less than 0.1 md. In fact, the definition a “tight gas” reservoir is a function of many physical and economic factors, and it applies to many types of reservoirs. The best way to define a tight gas reservoir is that “the reservoir cannot be produced at economic flow rates or recover economic volumes of natural gas unless the well is stimulated by a large hydraulic fracture treatment, a horizontal wellbore, or by using multilateral wellbores” (Holditch, 2006).

So what is a typical unconventional gas reservoir? The answer is that there are no “typical” unconventional gas reservoirs. An unconventional gas reservoir may be deep or shallow, high pressure or low pressure, high temperature or low temperature, blanket or lenticular geometry, homogeneous or heterogeneous, naturally fractured or not, single layered or multilayered, water productive or not, and it may contain thermogenic or biogenic gas. It is this complexity of unconventional gas reservoirs that requires continual development of new exploration philosophies and technologies to facilitate discovery and economic resource development.

The Resource Triangle-Unconventional Gas Resource Abundance

The resource triangle concept (Fig. 1) has been used by Canadian Hunter to find large gas resources and to build a successful exploration and production company in the 1970’s (Gray, 1977; Masters, 1979). The concept is that all natural resources have a log-normal distribution in nature. Whether prospecting for gold, silver, iron, zinc, oil, natural gas, or any resource, the best or highest-grade deposits are small, and once found, extraction is relatively easy, straightforward and economic; the hard part is to find these pure veins of gold or high-permeability gas fields.

Figure 1.

Resource triangle for natural gas (from Holditch, 2006; after Masters [1979] and Gray [1977]).

Figure 1.

Resource triangle for natural gas (from Holditch, 2006; after Masters [1979] and Gray [1977]).

In the resource triangle concept (Gray, 1977; Masters, 1979), the limited quantities of gas in conventional, high-permeability reservoirs are shown at the apex of the triangle. Reservoir quality diminishes with depth from the triangle apex, but the quantities of lowgrade, unconventional oil and gas deposits are much greater and easier to find than are resources in the highquality, conventional reservoirs at the apex. The common theme is that economic development of lowquality oil and natural gas deposits requires applications of improved technology and higher gas prices than those required for development of conventional reservoirs.

The concept of the resource triangle (logarithmic resource distribution) should apply to hydrocarbon-producing basins, worldwide. If so, knowledge of the conventional gas resources of a basin may allow estimation of the unconventional gas in that basin. Then, the relationship between conventional gas and unconventional gas volumes in that basin may be used to predict unconventional gas resources in similar basins, worldwide. Moreover, we should be able to test this concept in North America, where there is a long history of conventional and unconventional gas production from many basins.

Unconventional Gas Reservoirs in the United States

Unconventional gas has been produced in the U.S. for more than 50 years, and it has played an increasingly important role in meeting the U.S. natural gas demand over the past three decades. Unconventional gas activity in the early 1980’s (e.g., Antrim Shale and San Juan Basin coalbed methane) was due in large part to development of new technology that was encouraged by the Section 29 tax credit. Since the 1990’s, unconventional gas activity has been driven by new of play concepts and associated technologies (i.e., Powder River basin coalbed methane and Barnett Shale gas), supported by higher gas prices.

Driven by demand and facilitated by tax credits, higher gas prices, new technology and new concepts, unconventional gas production has increased from insignificant values in 1980 to 9.15 Tcf (trillion cubic feet) in 2007, when it accounted for 47% of the U.S. dry gas production and 62% of the booked reserves (EIA, 2009a). Unconventional gas is poised to dominate U.S. gas production in coming decades (EIA, 2008; Fig. 2).

Figure 2.

Onshore unconventional gas production is the only growing component of the U.S. gas supply (EIA, 2008).

Figure 2.

Onshore unconventional gas production is the only growing component of the U.S. gas supply (EIA, 2008).

In 2007, eight of the top ten U.S. gas plays were producing from unconventional reservoirs (Table 1). In 2007, total U.S. dry gas production was 19.3 Tcf. That year, tight sands produced 6.2 Tcf, coal beds produced 1.8 Tcf, and shales produced 1.2 Tcf of gas, accounting for 31.9%, 9.5%, and 6%, respectively of the total dry gas production (EIA, 2009b). Recent success of the Barnett Shale play triggered widespread North American shale exploration, leasing, and production, resulting in numerous new shale plays (Haynesville, Marcellus, Eagle Ford, etc.).

Table 1.

Top ten gas producing fields in the U.S. in 2007. All but Hugoton and Prudhoe Bay produce from unconventional reservoirs (data from EIA 2008).

As a result, unconventional gas annual production, reserves, and resources are increasing rapidly. Production and reserves of shale gas reservoirs are gaining rapidly on coalbed and tight sand reservoirs. By 2007, shale gas reserves have grown to 21.5 Tcf, nearly equal to reserves of coalbed methane (21.9 Tcf), and each accounted for more than 9% of the total U.S. dry gas reserves (225.2 Tcf) (EIA 2009b).

Although annual production and reserves of all unconventional gas reservoir types have increased in the past decade, shale gas production and reserves (Figs. 3 and 4) are growing more rapidly than those of tight sands and coal beds. Unconventional gas, led by shale gas, is expected to provide the majority of the U.S. gas supply growth in coming decades (EIA, 2008). Already, unconventional gas reservoirs are the major contributor to recent growth in natural gas production in the Lower 48 states (Fig. 5). In fact, owing to the intense development of unconventional gas, EIA forecasts have consistently under-estimated annual unconventional gas production (Fig. 6; Navigant, 2008). Certainly, the tremendous and growing success of unconventional gas reservoirs in the U.S. bode well for a robust international unconventional gas industry in coming decades.

Figure 3.

U.S. annual shale gas production (Navigant, 2008).

Figure 3.

U.S. annual shale gas production (Navigant, 2008).

Figure 4.

Coalbed and shale gas proved reserves, 2006 and 2007 (from EIA, 2009b).

Figure 4.

Coalbed and shale gas proved reserves, 2006 and 2007 (from EIA, 2009b).

Figure 5.

Recent growth in natural gas production in the Lower 48 States, attributed largely to unconventional gas (EIA, 2009a).

Figure 5.

Recent growth in natural gas production in the Lower 48 States, attributed largely to unconventional gas (EIA, 2009a).

Figure 6.

EIA AEO unconventional gas production forecasts consistently under-estimate actual production (Navigant, 2008).

Figure 6.

EIA AEO unconventional gas production forecasts consistently under-estimate actual production (Navigant, 2008).

Worldwide Unconventional Gas Development

Historically, most of the production from unconventional gas reservoirs and most of the technology used to produce these reservoirs have been developed in North America. However, it is clear that this unconventional resources technology will be applied globally. In coming decades, the production of natural gas from low permeability gas reservoirs (tight sands, coal beds and shales) will occur in every major oil and gas basin in the world (Holditch, 2009), driven by increasing energy demand and depleting conventional energy supplies, and facilitated by higher prices and development and application of existing and new technology.

Effects of product prices and technology

As the price of a resource increases and technology improves, industry should be able to dip deeper into the resource triangle and produce more of the unconventional resources (Masters, 1979). BP (www.bp.com) provides information on the effects of geopolitics and technology on oil prices (Fig. 7), and Flores (2008) presents a list of the major changes in product prices and technology in the U.S. oil and gas industry over the past century (Table 2). Flores (2008) clearly validates application of the resource triangle concept to oil and gas production. Using numerous data sets from North America, she demonstrates that when prices increase, owing to geopolitical or other causes, or when technology improves, more wells are drilled in unconventional reservoirs and more oil and gas are produced (Tables 2 and 3, and Figs. 8 and 9). Changes in oil and gas prices, plus improvements in technology affected the number of wells drilled and the oil and gas produced from unconventional reservoirs in 1973, 1978, and the mid-2000s. The effect of decreased of oil price in 1986 and 1998 (Fig. 7) resulted in fewer producing wells and plateaus on the cumulative productions curves (Figs. 8 and 9). Flores showed that technology improvements, such as hydraulic fracturing and horizontal drilling, as well as oil and gas price changes, affected drilling activity and production from the Austin Chalk formation in Texas. The updip Austin Chalk produces oil, whereas the downdip Austin Chalk produces gas. Flores converted the natural gas production to barrels of oil equivalent (BOE) to enable graphing production as a single unit (Figs. 8 and 9, and Table 3).

Figure 7.

Technology and economic events affecting the oil industry (www.bp.com).

Figure 7.

Technology and economic events affecting the oil industry (www.bp.com).

Figure 8.

Affects of price and technology on Austin Chalk production (Flores, 2008).

Figure 8.

Affects of price and technology on Austin Chalk production (Flores, 2008).

Figure 9.

Affects of price and technology on Cotton Valley production (Flores, 2008).

Figure 9.

Affects of price and technology on Cotton Valley production (Flores, 2008).

Table 2.

Oil industry major events since the discovery of rotary drilling (Flores, 2008).

Table 3.

Events affecting Austin Chalk production (Flores, 2008).

The production of oil and gas from the Austin Chalk formation was affected by the inventions of acidizing, hydraulic fracturing, and horizontal drilling. Also, the sudden oil price and gas price increases in the 1970’s instigated a drilling boom that turned this marginal oil and gas play into a play that has already produced more than 2.24 BOE. In another of several examples, Flores (2008) showed that price increases in the 1970’s, tax incentives to drill tight gas reservoirs, and the improvements in hydraulic fracture technology resulted in a dramatic increases in drilling and gas production in the Cotton Valley formation in East Texas (Fig. 9).

Worldwide unconventional gas resources

The resource triangle concept should be valid for all natural resources in all basins of the world. Thus, it is logical to believe that enormous volumes of gas will be found in unconventional reservoirs, developed and produced in every basin that now produces significant volumes of oil and gas from conventional reservoirs. Various organizations have analyzed parts of the UCG resource base in specific regions of the world. However, no organization regularly publishes a comprehensive estimate of the volume of gas that might be found in unconventional reservoirs, worldwide.

Rogner (1996) has estimated significant volumes of unconventional gas worldwide (Table 4). It is noteworthy that the largest volumes of unconventional gas are attributed to North America, which of course, is the region where there has been the most exploration, development, and production of unconventional gas. As such, there is more information available to evaluate the unconventional gas in North America, and there are more gas estimates available from multiple organizations. However, it is evident that unconventional gas resources in North America have been underestimated, and it is quite likely that Rogner (1996) has underestimated the worldwide volumes of UCG. If we apply the concept of the resource triangle, the volume of gas in unconventional reservoirs around the world should be much larger than the volume of gas in conventional reservoirs.

Table 4.

Distribution of unconventional gas resources, worldwide (from Kawata and Fujita, 2001; after Rogner, 1996).

North America as an analog to worldwide UCG resources

A recent study suggested that one should be able to estimate the volumes of gas contained in low-quality reservoirs in a specific basin by understanding the relationship between the volumes of conventional and unconventional resources (Old, 2008; Old et al., 2008). To test the resource triangle concept (logarithmic distribution of resources), Old (2008) used published resource data to compare the volumes of conventional oil and gas reservoirs to the volumes of technically recoverable gas in unconventional reservoirs for eight North America basins that have resources estimates for most conventional and unconventional reservoirs. Two of the eight basins (the Uinta and Piceance basins) were combined and treated as a single basin due to the way the resource information is combined for these two basins by several reporting agencies.

The conventional oil resource value was converted to gas equivalent and was added to conventional gas for combined volumes of conventional hydrocarbon resources in each basin. Then, the volumes of gas in coal beds, tight sands, and shales were summed for the combined volumes of unconventional resources. Conventional and unconventional resources were summed for the basin-wide total recoverable resources. All total recoverable resources values are considered technically recoverable, but not necessarily economic. More complete details of the methodology used are in Old (2008) and Old et al. (2008).

The results of the analyses of total recoverable resources, by resource type (conventional or unconventional) and total basin resource were determined for the seven basins, and the ratio of conventional to unconventional gas was calculated (Fig. 10). For these 7 basins, 10 to 20 % of the hydrocarbon resources are conventional and 80 to 90% are unconventional, which is consistent with the concept of the hydrocarbon resource triangle (Fig. 1). The Black Warrior and Wind River basins (79 and 80% unconventional gas, respectively) did not have publically available shale gas resources values. We have subsequently reviewed the data on total recoverable resources for 17 other basins in North America with similar results, but there is still a lot of uncertainty in the results, because many large gas shale assets, such as the Haynesville, Eagle Ford, and Marcellus shales were not included in the databases used to calculate values of total recoverable resources.

Figure 10.

Percentages of conventional and unconventional hydrocarbon resources in 7 reference basins.

Figure 10.

Percentages of conventional and unconventional hydrocarbon resources in 7 reference basins.

From our analyses of 25 U.S. basins, it appears probable that for every 1 Tcfe of oil and gas produced from conventional reservoirs, there will be 5 to 10 Tcfe of total recoverable resources gas from unconventional gas reservoirs in those same basins. The total recoverable resources approach requires that we know where the gas is located, and we can use existing technology to drill and produce the gas. However, it may or may not be economic, depending on the gas prices and the finding and development (F&D) costs. More work needs to be done to determine how much of the total recoverable resources can be produced economically for various assumptions of gas price, F&D costs and the location of the asset. For example, a lot of unconventional gas may be producible but not accessible to a market.

Technology Requirements for Unconventional Gas Reservoirs

In coming decades, the production of natural gas from unconventional gas reservoirs will occur in nearly every major oil and gas basin in the world. Technology transfer will be the key to economically developing these worldwide unconventional gas resources. Most of this technology has been developed in North America during the past few decades. Yet, new tools and technologies are needed. The technologies that will most affect the ability of the industry to successfully and economically produce gas from unconventional reservoirs fall into several categories, including petrophysics, geoscience, hydraulic fracturing, horizontal drilling, microseismic analysis, water management, environmental issues, and gas-to-liquids technology. Many of these needs are being addressed by RPSEA.

RPSEA is a not-for-profit organization that administers a $37.5 million annual research portfolio. Approximately half of this budget is goes to ultra-deep water research, with much of the rest directed to unconventional gas resources. RPSEA issues annual requests for proposals and uses a matrix (Fig. 11) developed by a Program Advisory Committee to guide its selection of projects to be funded. The unconventional gas projects fund will be distributed among coalbed methane (10%), shale gas (45%), and tight sands (45%) reservoirs (Fig. 11). Within each reservoir type, research needs are prioritized as high, medium, or low (Fig. 11). The objective is to fund projects that are most likely to affect increased energy supply. High priority is given to drilling, stimulation, completion, reservoir engineering and exploration technologies in both gas shales and tight sands (Fig. 11). More information about RPSEA and upcoming requests for proposals are available on their website (http://rpsea.org/).

Figure 11.

Technology needs for unconventional gas reservoirs (courtesy of RPSEA). A RPSEA Program Advisory Committee recommended that funding be prioritized with CBM receiving 10% and shale gas and tight sand projects each receiving 45% of the allotted unconventional gas research funds. Within each reservoir type, research needs are prioritized as High, Medium, or Low.

Figure 11.

Technology needs for unconventional gas reservoirs (courtesy of RPSEA). A RPSEA Program Advisory Committee recommended that funding be prioritized with CBM receiving 10% and shale gas and tight sand projects each receiving 45% of the allotted unconventional gas research funds. Within each reservoir type, research needs are prioritized as High, Medium, or Low.

Petrophysics

Petrophysicists use well log, core and well test data to describe the physical properties of formations that affect the production of oil and gas. Because unconventional gas reservoirs are generally low porosity, low permeability, multi-layered formations, the use of open-hole well logs to determine the formation properties is extremely important. We need better technology to really pin-point the best layers in thick, multi-layered formations. Also, we need much better petrophysics methods and tools to characterize gas shale reservoir properties and to recognize the best zones to complete and to more accurately predict ultimate gas recovery.

Specifically, we need to properly apply existing logging tools that provide resistivity arrays, sonic arrays, imaging logs, and nuclear magnetic resonance to determine porosity, permeability, and to describe the natural fractures. We must improve methods of combining well log analyses with special core analyses to determine the proper number of flow units and to correlate flow units. In addition to porosity and permeability, we also need petrophysical methods to measure adsorbed gas in gas shales and coal seams, as well as capillary pressure, relative permeability, and mechanical properties for all rock layers. New logging tools, like the recently developed sonic scanner (Fig. 12) may be used to understand better natural fractures and permeability anisotropy.

Figure 12.

Use of sonic scanner to interpret reservoir anisotropy (courtesy of Schlumberger).

Figure 12.

Use of sonic scanner to interpret reservoir anisotropy (courtesy of Schlumberger).

Geosciences

The use of seismic data to find the best locations (sweet spots) to drill and complete unconventional gas wells is extremely important. We need better methods for multi-azimuth seismic diffraction imaging for fracture characterization in low-permeability gas formations. Also, we need seismic improvements that allow evaluation of fracture systems and stress fields within gas shale reservoirs, such as the Marcellus Shale.

Another recent technology that both needs to be further developed in North America and applied worldwide is the use of microseismic mapping to determine the extent of induced hydraulic fractures. When fractures are induced in formations by pumping fluids at high pressures, microseismic activity occurs in the rock near the fracture (Fig. 13). With properly placed geophones, we can map the microseismic noise and determine the orientation of the fracture and, in gas shales, the volume of rock that is affected by the fracture.

Figure 13.

Use of microseismic mapping to optimize fracture stimulation (courtesy of Schlumberger).

Figure 13.

Use of microseismic mapping to optimize fracture stimulation (courtesy of Schlumberger).

Stimulation and completion

To economically develop an unconventional gas reservoir, every well must be successfully fracturetreated to produce at commercial gas flow rates. In most sandstone and coal seam reservoirs, most wells are vertical. Nearly all recent gas shale reservoirs have been developed using horizontal wells. In all cases, the wells must be fracture-treated. During the past few decades, the industry has made many improvements in the fracture stimulation technology for unconventional wells. However, there is still much to be done to optimize stimulation treatments.

When developing unconventional gas worldwide, the first step is to export existing stimulation and completion technology from North America to the basin under development. This is easier said than done, because it requires a very sophisticated and experienced service company infrastructure that does not exist in many countries. Although Australia, China, India, and some countries in Western Europe have investigated tight sands and/or coalbed methane projects for as much as a decade, in most cases, the infrastructure is not well developed.

In addition, we need better fracture fluids and better propping agents that can be transported in fracture networks to keep the hydraulic fractures open. In Figure 14, we illustrate that sustaining fracture area and conductivity of gas shale reservoirs for enhancing longterm production and recovery is very important, and new products need to be developed to help keep fractures open.

Figure 14.

Evaluating conductivity of induced fractures during shale gas reservoirs stimulation (courtesy of Schlum-berger).

Figure 14.

Evaluating conductivity of induced fractures during shale gas reservoirs stimulation (courtesy of Schlum-berger).

Water management and environmental considerations

Nearly every source of energy, including wind, solar, nuclear, and biofuels, as well as oil and gas, has to consider both water and environmental issues associated with the production of the energy. Today, we recognize that the use of water developing in many sources of energy, such as biofuels, could be a limiting factor. As such, the oil and gas industry must continue doing research on ways to limit water use and to protect the environment while still meeting the energy demanded of the public.

Because water management issues are very important in the domestic oil and gas industry, and worldwide, RPSEA has awarded research contracts to look at Barnett Shale and Appalachian gas shale water management issues. The horizontal wells drilled to develop gas shales require a lot of water for both drilling and fracture treatments. We need to develop technologies for cleaning and reusing the returned fracture water. In addition, we need to continue research to reduce the environmental foot print as we develop unconventional gas reservoirs. Along those lines, RPSEA is working with the Houston Area Research Center and Texas A&M University to manage the Environmentally Friendly Drilling Systems Program, which looks at a broad range of environmental issues. The Environmentally Friendly Drilling program has sponsored disappearing road contests and is evaluating ways to reduce the footprint of drilling operations in highly forested areas, along seashores and in desert terrains.

Uses of natural gas

There are several types of energy that the public and the industrial sector can select. Electricity can be generated from boilers using oil, coal or natural gas or heat from nuclear or geothermal sources. Electricity can also be generated using wind farms or solar panel farms. Critics point out limitations with every energy source, including water use, nuclear waste, land-use footprints, endangering birds, and emitting carbon to the atmosphere.

However, we need fuel for homes, cars, trucks, trains, boats, and planes. The fuels now used for transportation are gasoline, diesel or jet fuel made from crude oil. In the future, we should look more to biofuels, compressed natural gas and liquids made from natural gas as other sources of transportation fuel.

In the very near future, natural gas will be used more for generation of electricity, to replace coal as the primary fuel. Many environmental organizations are behind the efforts to use more natural gas to reduce carbon emissions as a short term solution. The oil and gas industry in North America, and most likely in China and India, can find enough gas in unconventional reservoirs to make this a viable option.

Also, we can use natural gas as a liquid fuels and for chemical feedstock. For example, natural gas can be converted to liquid fuels (Fig. 15) using the Fischer-Tropsch process. There are gas to liquid plants in South Africa, Malaysia, and Qatar. At today’s gas prices, these plants are economically marginal, but they represent a step in the right direction. More research should lead to technical breakthroughs or even radical new processes to convert the gaseous molecules into liquid molecules that are more easily transportable.

Figure 15.

Use of natural gas as feedstock for other products.

Figure 15.

Use of natural gas as feedstock for other products.

Some individuals and organizations suggest that we are running out of natural gas, because we have experienced shortages periodically in the past. However, we now know that there is an extremely large ‘gas resource’ both in North America and in the world. The key to tapping that resource in a consistent, reliable manner is to expand the market for natural gas. As the size of the market increases, we can develop the known accumulations, look for new accumulations in all oil and gas basins, worldwide, and develop the technologies required to economically produce resources that are deeper in the resource triangle.

Conclusions

On the basis of decades of publications by many engineers and scientists, and from the work our graduate students have performed during the past few years that has been touched upon in this paper, we offer the following conclusions.

  1. Our evaluations of hydrocarbon production and resource data from North American basins that have produced large volumes of unconventional gas confirm the concept of the resource triangle, as suggested by Masters (1979).

  2. Natural gas resources are distributed log-normally in nature and can be thought of in terms of a resource triangle. As gas prices increase and technology improves, more natural gas can be developed and produced.

  3. Thus far, our evaluations of North American basins indicate that the technically recoverable resource of unconventional gas in any basin will be approximately 5-10 times greater than the ultimate recovery (cumulative production plus proved reserves) from all conventional oil and gas reservoirs in the same basin.

  4. In 2007, unconventional gas production was 9.15 Tcf, and it accounted for 47% of the U.S. dry gas production; eight of the top ten U.S. gas plays were producing from unconventional reservoirs. 5. Unconventional gas production, reserves, and resources are increasing rapidly; unconventional gas, led by shale gas, is expected to provide the majority of the U.S. gas supply growth in coming decades.

  5. Unconventional gas resources in North America have been underestimated, and most likely, the worldwide volumes of unconventional gas are much greater than reported.

  6. Unconventional drilling and gas production are strongly impacted by technology and gas prices. The oil and gas industry should continue developing new technology; we have touched on only a few of these needs in this paper.

  7. To develop unconventional gas resources worldwide, it will be necessary to transfer the technology developed in North America in the past few decades to international oil and gas basins. The application of industry best practices in every phase of unconventional gas reservoir development will be critical to success.

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Acknowledgments

We would like to thank the members of the Crisman Institute for Petroleum Research for providing the funding for the students who have been working on well stimulation and resource assessments of unconventional gas reservoirs for the past 5 years. Also, we thank graduate students Husameddin Almadani, Kirill Bogatchev, Kun Cheng, Cecilia Flores, Nick Groves, Raj Malpani, Obinna Ogueri, Charles Ozobeme, Sara Old, Nicholas Pilisi, Sunil Ramaswamy, Kalwant Singh, Nick Tschirhart, Yilin Wang, Yunan Wei, and Ram Yalavarthi, whose research results are partially incorporated into the ideas presented in the paper.

Figures & Tables

Table 1.

Top ten gas producing fields in the U.S. in 2007. All but Hugoton and Prudhoe Bay produce from unconventional reservoirs (data from EIA 2008).

Table 2.

Oil industry major events since the discovery of rotary drilling (Flores, 2008).

Table 3.

Events affecting Austin Chalk production (Flores, 2008).

Table 4.

Distribution of unconventional gas resources, worldwide (from Kawata and Fujita, 2001; after Rogner, 1996).

Contents

GeoRef

References

References

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