Fossil Fuel Endowments in North, Central and South America

Several scientific studies, including a 2000 United States Geological Survey study, estimate that there exist large volumes of hydrocarbons in the world that “can be recovered given sufficient research and development and appropriate public policies” (Aguilera et al. 2009).  Two scientists from the Society of Petroleum Engineers used data from this USGS survey to create a model specifically designed to estimate regional fossil fuel endowments.  This method was used to estimate the oil endowments of North, Central and South America, as well as the natural gas and natural gas liquids that exist in these regions.  The scientists concluded that North, Central and South America have large petroleum endowments that will last for several decades, and these fossil fuel reserves have the capacity to “contribute significantly” to the energy needs of these regions. — Caitrin O’Brien 
Aguilera, R.F. and Aguilera, R., 2009. Oil, Natural Gas and NGL Endowment in North, Central and South America. Society of Petroleum Engineers 2009 Technical Conference, 1–8.

 Roberto Aguilera and Roberto F. Aguilera of the Society of Petroleum Engineers combined data from a 2000 US Geological Survey estimation of world petroleum supplies and a variable shape distribution model to estimate the endowments of natural gas, oil, and natural gas liquids (NGL) throughout North, Central and South America.  The USGS survey estimated average global oil endowments by assessing conventional petroleum reserves for 409 of the world’s 937 different petroleum provinces.  Unconventional oil was not assessed.  The survey also estimated the world’s natural gas endowment, but again did not include unconventional sources of natural gas.  In 2006, Aguilera developed a variable shape distribution (VSD) model, which has been used to forecast conventional oil, natural gas, and natural gas liquid endowments in the petroleum provinces evaluated by the USGS.  The authors used this model to determine oil, natural gas and natural gas liquid endowments for North, Central and South America.
Aguilera and Aguilera used the VSD model to estimate Central and South American oil endowments of 367 billion barrels of oil equivalent (boe), which is significantly higher than the USGS estimate of 219 billion boe.  The natural gas endowment for these regions was nearly the same, with the USGS estimating 759 trillion cubic feet (tcf) of natural gas in Central and South America, and the VSD model generating an estimate of 756 tcf.  The VSD model estimated that natural gas liquid endowments in Central and South America are approximately 22,674 million boe, which is very similar to the USGS estimate of 22,698 million boe.  For North America, the USGS and the VSD models generated the same estimate of 434 billion boe of oil and natural gas liquids.  The natural gas for this region was estimated at 1,787 tcf for the USGS model, which compares well to the 1,772 tcf calculated by the VSD model.  The composite conventional oil endowment in North, Central and South America was found to be 882 billion stock tank barrels of oil, and the cumulative conventional natural gas endowment was estimated to be 3,440 tcf.  Overall, the authors determined that the VSD model accurately estimates the amount of hydrocarbons available in different regions, and determined that large endowments of oil, natural gas and natural gas liquids exist in North, Central and South America.  If scientists and policymakers actively pursue research and development of petroleum reserves, these endowments have the capacity to last for decades.

Role of Conventional and Unconventional Hydrocarbons in the 21st Century

      Energy demand is expected to quadruple in the 21st century, whereas worldwide oil production is predicted to peak prior to the year 2015.  Increasing production of unconventional hydrocarbons has been suggested as a potential method of meeting rising global energy demands (Lakatos et al., 2009).  Lakatos and Lakatos-Szabó estimated the availability of these unconventional sources of oil and gas by evaluating and comparing existing data, including approximations of recovery rates based on present average values and probable technological progress.  In situ and ex situ techniques, as well as chemical methods, were considered.  Overall, the scientists estimated that recoverable unconventional hydrocarbons far exceed current industrial reserves of oil and gas, and that recent advances in tar sand oil and coalbed methane extraction have made many types of unconventional hydrocarbons competitive with crude oils and natural gases.  This study proposes that research, development and utilization of new recovery technologies for unconventional oils and gas will be of critical importance in the 21st century, as production of conventional sources of oil and gas begin to decline. .— Caitrin O’Brien 
Lakatos, I., Lakatos-Szabó, J., 2009.  “Role of Conventional and Unconventional Hydrocarbons in the 21st Century: Comparison of Resources, Reserves, Recovery Factors and Technologies.  71st EAGE Conference and Exhibition, the Netherlands, 8–11 June 2009, 1–13.

 I. Lakatos and J. Lakatos-Szabó of the University of Miskolc evaluated and compared data from “reliable organizations” to determine the potential of worldwide unconventional oils and gases.  The authors classify unconventional oils as oil shale, oil and tar sands, and pyrobitumen, while unconventional gases include gas shale, gas sand, tight gas sand, basin-concentrated gas accumulation, and coalbed methane.  Lakatos and Lakatos-Szabó compared historical production of unconventional sources of oil with estimates by the UN Energy Map of the World (1995) and the US Geological Survey.  The potential of unconventional gases were found by comparing forecasts from the BP Statistical Review and the US Geological Survey.  After comparing projected estimates of ultimately recoverable unconventional gas and oil resources, the authors estimated the production costs of these hydrocarbons for different recovery methods.  This final data was used to determine the effects that unconventional hydrocarbons could have on global oil and gas demand.
The authors determined that while “it seems very probably that natural hydrocarbons will remain the mainstay of energy supply until the middle of the 21st century,” unconventional hydrocarbons will be critically important in the future.  Global reserves of unconventional gases and oils “significantly exceed” the estimated availability of conventional hydrocarbons.  Production of several of these unconventional hydrocarbons has already started in several countries.  In particular, shale oil, sand oil, and coalbed methane resources are already being tapped using alternative extraction methods such as hydraulic fracturing.  Recent increases in hydrocarbon prices may further accelerate the production of unconventional sources of oil and gas, especially because production cost of tar sand oil and coalbed methane gas are now competitive with recovery costs of conventional hydrocarbons.  Overall, more research and development activities are needed to allow for wider application of new, sophisticated recovery technologies that could be key to increasing extraction of unconventional hydrocarbons.

Effects of Unconventional Oil Production on Peak Oil

      It is estimated that conventional oil production will reach its peak prior to 2025.  Unconventional methods of oil production may have the potential to mitigate the effects of peaking worldwide oil production (Mohr et al., 2010).  Extra heavy oil and oil that is trapped in tar sands and shale can be retrieved through mining and through in situ techniques.  The efficacy of in situ and mining techniques in extracting this unconventional oil was projected under three different models, which were used to estimate when unconventional oil production will peak, and whether alternative methods of production can delay the onset of peak oil.  The authors determined that unconventional oil production will peak between 2076 and 2084, and that unconventional methods alone cannot mitigate the onset of peak oil.— Caitrin O’Brien 
Mohr, F., Evans, G.M., 2010.  Long term predictions of unconventional oil production. Energy Policy 38, 265–276.

 S.H. Mohr and G.M. Evans developed a model to project unconventional oil production, including in situ and mining extraction techniques.  Unconventional types of oil include extra heavy oil, natural bitumen from oil sands and tar sands, and oil shale.  In situ techniques involve injecting steam into the well to heat the oil, forcing the hot oil towards the surface.  Steam Assisted Gravity Drainage (SAGD) is a type of in situ technology that extracts the oil through horizontal drilling.  Using the Cyclic Steam Stimulation (CSS) method, the well is put through cycles of steam injection, soak, and oil production until the hot oil can be pumped out of the well.  The model developed by the authors was calibrated based on Canadian data of historic bitumen production.  Mohr and Evans developed the unconventional oil production model based on their previous model for worldwide coal production.  Production for mining is determined by the sum of the individual mines in the basin.  Production from in situ is identical to the mining model, but the data is from a SAGD/CSS plant rather than a mine. Three scenarios were determined from the model, providing “pessimistic,” “optimistic,” and “best guess” estimates of ultimately recoverable resources from unconventional oil production.  Finally, the data extracted from the model were combined with conventional oil analysis and literature to obtain combined oil production projections.  The authors compared these results to estimates of worldwide peak oil production, to determine whether unconventional oil production can provide a smooth transition when conventional oil peaks.
Unconventional oil is primarily found in 3 countries: Canada, Venezuela and the United States.  The Former Soviet Union is also predicted to contribute considerable amounts of unconventional oil in the future.  Mohr and Evans used the in situ model to model in situ natural bitumen and extra heavy oil production, whereas the mining model was used to predict production from mined natural bitumen and shale oil production.  Based on the three scenarios, unconventional oil production will peak between 18 billion barrels per year (Gb/year) in 2076 and 32 Gb/year in 2084.  The best guess scenario estimates that production will peak at 22 Gb/year in the 2077.  Shale oil has the biggest production potential, although it also has the greatest uncertainty regarding its extraction methods and economic viability.  Mohr and Evans’s total unconventional oil production projections are higher than the estimates from most scientific literature on the subject, and the authors theorize that this is because their scenarios do not consider economic constraints.  In spite of the overall optimistic nature of the assumptions in these scenarios, both the pessimistic and the best guess scenario forecast that total oil production will decline within 5 years.  The authors estimate that unconventional oil will only delay the peak of world oil production by twenty-five years at the most.  After combining the three scenarios developed in this model with literature projections of oil production, only the optimistic scenario estimates that unconventional oil could partially mitigate the peak of conventional oil production, extending the worldwide oil production peak to 2050.  The pessimistic and the best guess scenarios both estimate that total oil production will peak within the next 5 years, and unconventional oil production will not significantly offset this peak.

The Effects of Climate Change and Oil Depletion on Global Trade

The global market depends on reliable, inexpensive transport of goods along long-distance supply chains.  Global warming and oil depletion have the potential to dramatically alter transportation costs and freight movement.  Fred Curtis argues that climate change and oil depletion will result in “peak globalization,” after which point the volume of world exports will decline (Curtis, 2009).  By examining scholarly literature on the pathways of the effects of global climate change and oil consumption on global trade, Curtis takes a unique look at the effects of climate change and natural resource management on human goods and transportation, and concludes that current policies designed to mitigate climate change and oil depletion will be ineffective in halting the onset of “peak globalization.” Cattrin O’Brien
Curtis, F., 2009. Peak Globalization: Climate change, oil depletion and global trade. Ecological Economics 69, 427–434

Fred Curtis examined existing scholarly literature on globalization and the environment in tandem with data on peak oil and climate change.  While most existing scientific literature has focused on “the impact trade treaties and increased global trade flows have on the ecosystem,” Curtis examines how environmental changes have the capacity to alter human trade.  In particular, Curtis focuses on oil depletion, as oil is heavily used in global transportation, and on the effects that global warming will have on oil use and transportation infrastructure.  Finally, Curtis examines both real and proposed policies designed to mitigate climate change and oil depletion, and concludes that these policies are “too little and too late” to prevent peak globalization, and will not be able to protect global supply chains.
Globalization, or the liberalization of international trade among nations, has caused a rapid increase in global economic growth and international trade.  This growth in global exports has been supported by the creation of a massive global transportation infrastructure, as goods are transported worldwide over roads, railways, ports and airports.  In order for this long-distance trade to be efficient, transportation must be cost-efficient, rapid and predictable.  The physical impacts of global warming will reduce this efficiency, and increase the cost of transportation.  Melting arctic ice is expected to cause sea levels to rise by three to six feet by the end of the century, which will threaten coastal roads, railways, port and airport facilities.  Greater evaporation due to rising temperatures is expected to lower water levels in intercontinental lakes and rivers, which will reduce the amount of goods that can pass through these waterways, slowing transportation and increasing costs.  Climate change is expected to cause an increase in catastrophic natural disasters similar to Hurricane Katrina, which can have devastating impacts on transportation infrastructure.  Climate change is also predicted to have devastating effects on agriculture and manufacturing, as higher temperatures and changes in precipitation decrease crop output and make the transportation of manufactured goods less predictable and more expensive.  Overall, Curtis argues that climate change will damage physical infrastructure, cause delays in freight transit, and increase costs to the extent that global warming will “undermine the economic logic of current supply chains.” 
The effects of climate change on globalization will be reinforced by the effects of oil depletion.  Petroleum is the most common fuel used for the movement of goods, and it has been predicted that peak oil will occur prior to the year 2015.  After this point, world oil production will begin to decline, and the price of crude oil will rise significantly and become much more volatile.  Shortages and interruptions in oil supply will be common as world oil continues to decline.  Oil depletion will have a huge effect on the global trade of goods.  Air freight uses the most fuel per ton-mile of all transportation modes, so it will be the most adversely effected by increased oil prices.  Air speeds can be slowed to conserve fuel, but this would decrease the efficiency of the supply chain.  Container ships use bunker fuel oil, which is untaxed on international journeys and therefore will not be as impacted by oil price jumps as air travel.  However, Curtis notes that “it is possible for ocean shipping costs to rise high enough to impact the global sourcing of production.”  High oil prices also destroy global supply chains by impacting goods production, as higher oil prices result in increased food production costs.  The current global trade market will be greatly impacted by higher fuel costs, slower movement of freight and potential fuel supply interruptions as a result of peak oil. 
Curtis argues that the current policy responses to climate change and oil depletion are too late and too costly to prevent peak globalization.  Climate change policies designed to reduce greenhouse gas emissions could have direct impacts on globalization, but these policies have not been effectively implemented.  These policies, which would involve taxes, regulations and/or cap-and-trade systems, would not prevent the shrinking of global supply chains.  Policies designed to slow the onset of peak oil primarily include increasing vehicle fuel efficiency, fuel taxes, and improving oil recovery techniques using new technologies such as hydraulic fracturing.  The author argues that even if the most ambitious of these policies were implemented, the impending worldwide oil crisis would not be avoided.  Curtis concludes that globalization will be threatened as long as climate change and oil depletion continue, and the only solution would be for production and trade to become more local or regionally-based. 

Lessons Learned from Hydraulic Fracturing in the Marcellus Shale

The Marcellus Formation is a shale reservoir in eastern North America whose natural gas reserves are accessible primarily through hydraulic fracturing.  Over 100 fracture wells have been stimulated in the shale’s Pennsylvania region, “resulting in an in-depth understanding of details needed to achieve optimal frac performance” (Houston et al., 2009).  Type and concentration of fracturing fluid, drill cutting placement, geochemical controls, proppant and perforation strategies have all varied significantly from the beginning of Marcellus Shale extraction to the present. These important factors of hydraulic fracturing have been tested and evaluated in order to capture the best hydraulic fracturing practices for the Marcellus Shale formation.  By studying the effects of fracturing strategies and technologies used for these test wells, more rapid advancement towards full-scale natural gas extraction in the Marcellus Shale region can be achieved.— Caitrin O’Brien          
Houston, N, Blauch, M, Weaver, D, Miller, D, O’Hara, D.  Fracture-Stimulation in the Marcellus Shale- Lessons Learned in Fluid Selection and Execution.  Society of Petroleum Engineers, 2009 SPE Eastern Regional Meeting, 23-25 September 2009, 1-11.
Nathan Houston and colleagues from the Society of Petroleum Engineers reviewed methods and technologies used in the Marcellus Shale from early development of the field to the present.  By evaluating and capturing the best practices of hydraulic fracturing in this reservoir, the scientists hope to develop standing operating procedures that can be put towards full-scale development of natural gas extraction in the Marcellus Shale.  Houston and his colleagues considered practices from hydraulic fracturing in other shale reservoirs, as well as several new techniques that have been developed specifically for the Marcellus.  The scientists reviewed the best type of fluids used to stimulate fractures while minimizing runoff and leaks, as well as the best methods of analyzing fracture placement for drill cuttings.  Houston and his colleagues also analyzed types of geochemical controls that are used in the fracturing fluid in the Marcellus Shale, such as biocides, scale control and iron control, as well as the results of using different types of surfactant, sand, and perforating and fracture techniques.  After reviewing the results of different methodologies, the scientists determined how these each factor interacts with the unique geologic composition of the Marcellus Shale, and made decisions as to which technology or fluid composition was best suited to hydraulic fracturing in this region. 
The Marcellus Shale formation is characterized by low permeability rock that has high amounts of organic matter and clay, very fine grain size, and extremely fine porosity.  This combination of traits has required hydraulic fracture stimulation fluids with low viscosities, high rates of flow, and large quantities of proppant to hold fractures open.  Houston and his colleagues determined that the most effective fracturing fluids for the Marcellus Shale region are slickwater stimulation fluids pumped at high rates, with low sand concentrations.  This combination minimizes leakoff, and when combined with a liquid-polymer additive, the slickwater reduces friction in the shale fractures.  Analysis of drill cuttings is an important technology to optimize fluid design and fracture placement, and X-ray technology was found to be the best method of identifying the unique mineralogy and fracture geometry of fracture in the reservoir.  The scientists found that including several geochemical controls in fracturing fluids is crucial to optimize fracture production and minimize damage to the shale.  In particular, “environmentally responsible” biocides that kill sulfate-reducing and slime-forming bacteria are useful to inhibit any potential damage to the shale.  Similarly, geochemical precipitants and scale control are useful to protect against carbonate, sulfate and iron-based scale build up in fractures, which can reduce productivity.  Houston and his colleagues also determined the most useful concentration of surfactant and proppant, as well as the most effective rate of proppant to be used in the Marcellus Shale.  The use of surfactant in the Marcellus Shale fractures has been found to reduce surface tension and lower the pressure in the fractures, resulting in increased recovery of natural gas.  White sand has evolved to be the proppant of choice in the Marcellus reservoir, and sand concentrations between 0.25 to 2.5 lb/gallon of fluid have been proven, through trial and error, to be the best concentrations to prop fractures open.  Finally, Houston and his colleagues determined the best perforation and fractures for the Marcellus Shale to be those made using deep-penetrating and cleaner-hole technologies, to reduce fracture initiation and breakdown pressures.  A mixture of 7.5% hydrochloric acid has proven most effective in reducing friction in the fractures and enhancing performance.  By reviewing the lessons learned from the stimulation of more than 100 shale gas wells, Nathan Houston and colleagues from the Society of Petroleum Engineers were able to outline the most effective methodologies for natural gas extraction in the Marcellus Shale region. 

Development of a New Hydraulic Fracturing Fluid

Hydraulic fracturing pumps fluid into fractures in rock bed in order to extract oil or gas.  The chemical composition of fracturing fluids is dependent on the type of rock, the size of the fracture, and the fuel being extracted.  Scientists with the Society of Petroleum Engineers developed a new hydraulic fracturing fluid designed to be used in low permeability tight gas wells (Gupta et al., 2009).  After evaluating the chemical mixture based on its viscosity, foam generation, fluid loss, and conductivity, the scientists tested the fluid’s efficiency in a field study in the Greater Green River Basin, Wyoming.  The results of this study were compared to similar treatments using conventional fluid, and the new fluid was found to have better initial and cumulative field production compared to standard hydraulic fracturing fluids.— Caitrin O’Brien
Gupta, D, Jackson, T, Hlavinka, G, Evans, J, Le, H, Batrashkin, A, Shaefer, 2009, M.  Development and Field Application of a Low-pH, Efficient Fracturing Fluid for Tight Gas Fields in the Greater Green River Basin, Wyoming.  Society of Petroleum Engineers, SPE Paper 116191, 602-610.
D.V.S. Gupta and his colleagues with the Society of Petroleum Engineers developed a new, low-pH fracturing fluid that is best suited for tight gas formations.  Low-pH fluids have been shown to cause less permeability damage and better fracture cleanup in these formations than fluids with a higher pH.  The newly developed hydraulic fracturing fluid is energized with N2 to create foam that can enhance the fluid recovery.  This fluid also has a crosslink system, which is used to minimize friction and reduce the energy necessary to pump the highly viscous fluid.  Gupta and his colleagues studied the new fluid’s viscosity by measuring how quickly the fluid traveled at different temperatures.  The fluid’s foam capabilities were tested using a foam generator, and the fluid loss was tested at various temperatures.  The scientists determined the fluid’s conductivity by measuring the time it took for a test proppant to move through a fake hydraulic fracture.  After thoroughly testing the properties of the newly developed fracturing fluid, 20 wells in the Frontier formation in southwest Wyoming were stimulated with the new fluid.  The productivity of these test wells was compared to that of other wells in the formation that utilize various conventional fracturing fluids.
The new low-pH, high yield fracturing fluid developed by Gupta and his colleagues is designed for optimal production in low permeability gas reservoirs.   The fluid was found to have adequate viscosity to initiate and propagate the fracture, and the fluid effectively transported the proppant in the fracture.  The foam produced by the fluid has reasonable stability compared to other types of fracturing fluid, and the lower polymer loadings in this fluid inflict less damage on the rock formation.  The newly designed fluid was found to be very conductive and did not cause obvious damage to the fracture.  The fluid was tested in the Frontier formation, a shale formation in southwest Wyoming, where the results were favorable.  Wells stimulated with the new fluid were found to produce more gas than conventional low-pH and high-pH efficient fluid systems.  

Estimating Coal Production Until 2100

Several different models have been devised to predict total remaining worldwide coal yield.  Projections of mineral resources are often made using the Hubbert linearization model, a method invented in 1976 that has been quite accurate in estimating oil production in the United States. Coal reserves have also been estimated using a method that sums estimates of current reserves with estimates of cumulative production.  S.H. Mohr and G.M. Evans devised a new methodology for estimating coal production that takes into account supply and demand interactions in different countries and for different types of coal (Mohr and Evans, 2009).  These three models are compared based on the predicted amounts of coal production by country, production levels by type of coal, and energy produced by the estimated amounts of coal.  The model devised by Mohr and Evans, the “Best Guess Method,” predicts that overall worldwide coal production will last much longer and provide more energy than the predictions of the Hubbert linearization model, but the model that sums reserves and cumulative production predicts higher coal production than the Best Guess and the Hubbert methods.  Based on the Best Guess methodology, the worldwide coal yield will between 700 and 1,243 gigatonnes, and worldwide coal production will peak in 2034 on a tonnage basis, and in 2026 on an energy basis.  The Best Guess model indicates that the notion that coal is widely abundant appears to be unjustified.— Caitrin O’Brien
Mohr, S., Evans, G., 2009. Forecasting coal production until 2100. Fuel 88, 2059-2067.
S.M. Mohr and G.M. Evans created a model for estimating coal production that takes into account more than 400 constants for 132 countries and many different coal types.  This new model includes data from external disruptions, such as wars and depressions, and can be used for any resource where production is derived from mining.  Mohr and Evans compared their new model to two more traditional models used to estimate coal production.  The Hubbert linearization method was devised in 1976 to plot production data for the US oil industry, and this method has been used to plot the depletion of other finite mineral resources.  This model assumes production to be a symmetric bell curve, and does not take into account estimated reserves of coal.  The second method that Mohr and Evans compare is denoted as the “R+C” model, which is the summation of current estimates of coal reserves and cumulative production worldwide.  The authors used these three methods to compare the coal production for each country or region of the world, in gigatonnes.  The three models were also compared based on their results for estimated production based on type of coal, and the amount of energy produced by each type of coal. 
The scientists found large discrepancies between the three models of coal production.  When comparing the scenarios based on coal production predictions, the R+C scenario predicted much higher overall coal production than the other two, and the Best Guess scenario is in between the Hubbert estimate and the R+C estimate.  All three of the models show China running out of coal around 2100, but the R+C scenario and the Best Guess scenario both predict a huge increase in coal production in the Former Soviet Union around 2110.  The Hubbert method shows very little production in any region past 2100, whereas the other two scenarios estimate that coal production will last beyond 2200, especially in the United States.  All of the scenarios show that Western Europe is the only continent where coal production has already peaked and is declining, and the study shows that European coal production peaked in 1988 and is declining at a rate of 3% per year.  All of the models indicate that world coal production in tones will peak between 2010 and 2048. 
Mohr and Evans compared worldwide coal production for each of the three models based on the amounts of coal estimated for each model.  Four different types of coal were considered- anthracite, bituminous, sub-bituminous, and lignite.  For all three scenarios, bituminous coal is the most prevalent, because bituminous coal is the most common coal in the world. Anthracite estimates are very low and approximately the same for each scenario. The Hubbert method estimates that the coal that is produced worldwide will be primarily bituminous, whereas the Best Guess and the R+C methods predict a huge spike in lignite extraction.  This is presumably because as bituminous coal begins to run out, the energy industry will increase production of less efficient types of coal such as lignite and sub-bituminous.
Finally, the authors compared the three models based on the energy values of the predicted coal extraction.  All models predicted that anthracite would produce high amounts of energy compared to its mass, although bituminous coal will produce the most overall energy because it is the world’s most prevalent coal.  The Hubbert method estimated that by the year 2100, less than 30 exajoules per year will be produced by coal worldwide, whereas the R+C scenario’s estimate for the same year is about 60 exajoules per year. The Best Guess methodology predicts that by 2100, over 90 exajoules per year will be produced by coal.  The author’s Best Guess scenario indicates that the amount of worldwide energy produced by coal will peak between 2011 and 2047.  Mohr and Evans conclude that the worldwide coal yield is between 700 and 1,243 gigatonnes, and that worldwide coal production will peak in 2034 on a tonnage basis and 2026 on an energy basis.  According to the research by Mohr and Evans, the world has almost reached its maximum levels of coal production, and by 2100 will have all but exhausted worldwide coal supplies.