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Sustainable Society:  A society that balances the environment, other life forms, and human interactions over an indefinite time period.







Peaking Of World Oil Production:

Impacts, Mitigation, & Risk Management

Hirsch, Bezdek, and Wendling



I. Most Meaningful EIA Oil Peaking Case

II. More Historical Oil Crisis Considerations

III. Likely Future Oil Demand

IV. Rationales For The Wedges

    A. Vehicle Efficiency Wedge
    B. Coal Liquids
    C. Heavy oils / Oil Sands
    D. Improved Oil Recovery
    E. Gas-To-Liquids
    F. Sum of the Wedges

V. Notes On Shale Oil And Biomass

VI. Topics For Future Study


Appendix I. Most Meaningful EIA Oil Peaking Case

In the year 2000, EIA developed 12 scenarios for world oil production peaking using three U.S. Geological Survey (USGS) estimates of the world conventional oil resource base (Low, Expected, and High) and four annual world oil demand growth rates (0, 1, 2, and 3 percent per year).120 We believe the most likely of the EIA scenarios is the one based on the USGS expected ultimate world recoverable oil of 3,003 billion barrels coupled with a 2% annual world oil demand escalation.

Figure A-I shows the two EIA scenarios based on these assumptions. The difference between the two profiles is attributable to two assumed production decay rates following peak production. Both curves assume a 2 percent per year growth from the year 2000 until the peak. One scenario assumes a 2 percent decline after the world oil production peak, while the other assumes a steeper drop after the world oil production peak. Because the areas under both curves must equal the projected 3,003 billion barrels of recoverable conventional oil from the year 2000 forward, the rapid decay curve will inherently yield the later occurring, higher world oil production peak.

The EIA scenario that peaks in 2016 looks like the relatively symmetric U.S. Lower 48 production profile in Figure II-2. The EIA scenario that peaks in 2037 not only differs dramatically from the U.S. experience, it differs from typical individual oil reservoir experience, which often displays a relatively symmetric production profile, not the sharp drop illustrated in the alternate EIA case. On this basis, we believe that the EIA 2016 peaking case appears much more credible than the 2037 peaking case. The associated 21-year difference between the two predicted production peaks clearly would have profound implications for the time available for mitigation.

It is worth noting that the USGS mean estimate for the remaining recoverable world oil resource is much higher than estimates made by other investigators, according to K.S. Deffeyes, retired Shell geologist and emeritus Princeton geology professor.121 Deffeyes also opined “… in 2000 the USGS again released implausibly large estimates of world oil.” A lower total reserves estimate would of course mean a world oil production peak earlier than 2016.

Figure A-1. Two EIA oil production scenarios based on expected ultimate world-recoverable oil of 3,003 billion barrels and a 2 percent annual world oil demand escalation


Appendix II. More Historical Oil Crisis Considerations

Economists have debated whether the economic problems of the 1970s were due to the oil supply disruptions or to inappropriate fiscal, monetary, and energy policies implemented to deal with them. The consensus is that the disruptions would have caused economic problems irrespective of fiscal, monetary, and energy policies, but that price and allocation controls exacerbated the impacts in the U.S. during the 1970s.122 There is general consensus on the following:

  • Appropriate actions taken included CAFE, the 55 mph speed limit, reorganization of the Federal energy bureaucracy, greatly increased energy R&D, establishment of the Strategic Petroleum Reserve (SPR), energy efficiency standards and building codes, establishment of IEA and EIA, and burden sharing agreements among nations.

  • Inadvisable actions included price and allocation controls, excessive regulations, de-facto gasoline rationing, “excess profits” taxes, policies targeting “greedy energy companies,” prohibitions on energy use, and subsidy programs.

  • Some actions that seemed to be inappropriate may have been desirable if the problem had not been short-lived. For example, synthetic fuel initiatives may have looked prescient had oil prices not collapsed in the mid 1980s.123

Estimated costs to the U.S. of oil supply disruptions range from $25 billion to $75 billion per year, and the cumulative costs since 1973-74 total about $4 trillion.124 Nevertheless, except for several serious disruptions (and then only temporarily), oil prices have risen little in real terms over the past century, as shown in Figure A-2.

Cost of living adjustment clauses imbedded in many contracts, labor agreements, and government programs (e.g., Social Security) are less visible but important inflation drivers. Price increases generated by oil supply disruptions automatically trigger successive inflationary adjustments throughout the economy, and these complicate monetary policies designed to counter the inflationary effects of the disruption.125

Figure A-2. Oil Prices in Current and Constant Dollars: 1900 - 2004

The U.S. is currently less oil-dependent (in terms of oil / GDP ratios) than during the 1970s. However, as shown in Figure A-3, the U.S. is now importing twice as much oil (in percentage terms) as 30 years ago and its transportation sector consumes a larger portion of total oil consumption.126 Further, by 2000 most of the energy saving trends resulting from the 1970s disruptions (increased energy efficiency and conservation, increased vehicle mpg, etc.) had been captured.

The primary effect of the 1973-74 disruption was oil price increases. As shown in Figure A-2, the real price of oil peaked in 1981 and has never again reached similar levels.

At present, oil would have to be nearly $80 per barrel and gasoline would have exceed $3 per gallon to equal real 1981 prices. Even then, however, energy would still be less significant factor in the U.S. economy because average U.S. per capita incomes have doubled since 1981 and energy is a much smaller component of expenditures.127

Nevertheless, over the past 20 years, oil prices have been extremely volatile –more volatile than virtually any other commodity.128

Figure A-3. U.S. Oil Imports and Transportation Shares of Oil Consumption, 1973 and 2003


Appendix III. Likely Future Oil Demand

Petroleum consumption has been inexorably linked to population growth, industrial development, and economic growth for the past century. This relationship is expected to continue worldwide for the foreseeable future. While the U.S. consumes more oil than any other country – about 20 MM bpd, it represents only 26 percent of world production, compared to the 46 percent of world oil production the U.S. consumed in 1960. As shown in Figure A-4, Western Europe currently consumes the second largest amount (18 percent) followed by Japan (7 percent), China (6 percent), and the FSU (5 percent), with over 150 other countries accounting for the remaining 38 percent of production.129

Figure A-4. World Petroleum Consumption, 1960-2025


Energy forecasting is difficult due to the numerous complex factors that influence energy supply and demand.130 Here we utilize the U.S. Energy Department's Energy Information Administration forecasts of future world oil requirements.

Table A-1 presents summary statistics for the EIA 2001-2025 forecast including 24-year country or country group projections for petroleum consumption, gross domestic product (GDP), and population.

Table A-1.Reference Case Projections, 2001-2025
(Average annual % change)

  Petroleum Consumption GDP
(Con. $)
U.S. 1.5 3.0 0.8
W.Europe 0.5 2.0 0.1
China 4.0 6.1 0.5
FSU 2.1 4.2 -0.2
Japan 0.3 1.7 -0.1
Other 2.0 4.0 1.3
World 1.9 3.0 1.0

Oil consumption in China is expected to increase 4 percent a year, and by 2025 China is projected to be the second largest oil consuming country in the world, accounting for 11 percent of total world consumption. The second fastest growing market is projected to be the FSU countries, where petroleum consumption is forecast to increase an average of over 2 percent per year.

The remaining large consumers, including the U.S., Western Europe, and Japan are forecast to experience consumption growth over the 24-year period at or below the world average. The U.S. is forecast to increase oil consumption at a rate of 1.5 percent per year, and by 2025 the U.S. share of world oil consumption is forecast to decline to 23 percent (29.7 MM bpd), while Western Europe's share decreases to 13 percent (14.4 MM bpd). The many countries grouped as "Other" above, including India, Mexico, and Brazil, are expected to experience oil consumption growth rates 10 to 30 percent higher than the world average. By 2025, this group is forecast to account for 43 percent of world oil consumption.

In sum, in the EIA reference case, world oil consumption of 80 MM bpd in 2003 is projected to increase to 121 MM bpd in 2025, with the most rapid increases occurring in nations other than the U.S., Japan, or those in Western Europe. Average annual world oil demand growth is projected as 1.9 percent over the period.

Appendix IV. Rationales For The Wedges

A. Vehicle Fuel Efficiency

The original U.S. Corporate Average Fuel Efficiency (CAFE) timetable, enacted in 1975, mandated a 53 percent increase in vehicle fuel efficiency, from 18 mpg to 27.5 mpg, over the seven years between 1978 and 1985. Average on-road vehicle fuel efficiency began to improve markedly in the early 1980s and continued to improve substantially every year through 1995. It showed little change between 1995 and 1999, and then began to decline gradually due to the shift to greater purchases of light trucks and SUVs. Between 1982 and 1995, average on-road vehicle fuel efficiency increased from about 14 mpg to 20 mpg.

In other words, the first major U.S. oil disruption occurred in the fall of 1973; CAFE was not enacted until two years later; the increased mpg requirements did not begin until 1978, and were phased in through 1985; and significant increases in average on-road vehicle fuel efficiency did not occur until the mid- to late 1980s.132 From the time world oil peaking occurs or is recognized, it may thus take as long as 15 years until strengthened vehicle fuel efficiency standards significantly increase average on-road fleet fuel efficiency. However, care must be exercised in making extrapolations. Most “realistic” enhanced vehicle fuel efficiency standards might not actually decrease future total gasoline consumed in the U.S. due to the anticipated continued increase in numbers of drivers and vehicles. Thus, a new CAFE mandate might decrease the rate at which future gasoline consumption increases, but not necessarily reduce total consumption.133 Only aggressive vehicle fuel efficiency standards legislation that “pushes the envelope” of fuel efficiency technologies over the next two decades (as determined, for example, in the study by the National Research Council of the National Academy of Sciences134) is likely to actually reduce total U.S. gasoline consumption.

Savings in the U.S. Assuming a crisis atmosphere, we hypothesize an aggressive vehicle fuel efficiency scenario, based on the NRC CAFE report and other studies that estimate the fuel efficiency gains possible from incremental technologies available or likely to be available within the next decade.135 We assume that legislation is enacted on the action date in each scenario. We further assume that vehicle fuel efficiency standards are increased 30 percent three years later —for cars from 27.5 mpg to 35.75 mpg and for light trucks from 20.7 mpg to 26.9— and then increased to 50 percent above the base eight years later —for cars from 27.5 mpg to 41.25 mpg and for light trucks from 20.7 mpg to 31 mpg; finally, we assume full implementation is assumed 12 years after the legislation is enacted. These assumptions “push the envelope” on the fuel efficiency gains possible from current or impending technologies.136

On the basis of our assumptions, the U.S. would save 500 thousand barrels per day of liquid fuels 10 ten years after legislation is enacted; 1.5 million barrels per day of liquid fuels at year 15; and 3 million barrels per day of liquid fuels at year 20.

Worldwide Savings. The U.S. currently has about 25 percent of total world vehicle registrations, but consumes nearly 40 percent of the liquid fuels used in transportation worldwide.137 Since we could not find credible forecasts of the potential impacts of increased worldwide vehicle fuel efficiency standards, we assumed that the impact in the rest of the world of enhanced vehicle fuel efficiency standards will be about equal to that in the U.S. In total, the worldwide impact of increased vehicle fuel efficiency standards would thus yield a savings of 1 million barrels per day of liquid fuels 10 years after legislation is enacted; 3 million barrels per day 15 years after legislation is enacted; and 6 million barrels per day 20 years after legislation is enacted.

Increased vehicle fuel efficiency standards are a powerful way to reduce liquid fuels consumption. However, they required long lead-times to enact, implement, and become effective in the past. On the other hand, their importance and contributions continue to grow over time as older vehicles are retired. Our world vehicle fuel efficiency wedge is assumed to be as follows:

We note that a detailed study of these issues and opportunities would be of great value.

B. Coal Liquids

High quality liquid fuels can be made from coal via direct liquefaction or via gasification followed by Fisher-Tropsch synthesis. A number of coal liquefaction plants were built and operated during World War II, and the Sasol Company in South Africa subsequently built a number of larger, more modern gasification based facilities.138

While the first two Sasol coal liquids production plants were built under normal business conditions, the Sasol Three facility was designed and constructed on a crash basis in response to the Iranian revolution of 1978-79. The project was completed in just over three years after the decision to proceed. Sasol Three was essentially a duplicate of Sasol Two on the same site using a large cadre of experienced personnel. Sasol Three was brought “up to speed almost immediately.”139

The Sasol Three example represents the lower bound on what might be accomplished in a twenty-first century crash program to build coal liquefaction plants. This is because the South African government made a quick decision to replicate an existing plant on an existing, coal mine-mouth site without the delays associated with site selection, environmental reviews, public comment periods, etc. In addition, engineering and construction personnel were readily available, and there were a number of manufacturers capable of providing the required heavy process vessels, pumps, and other auxiliary equipment. While we have not done a survey of worldwide capabilities to perform similar tasks today, it is our belief that such capabilities are now in much shorter supply – a situation that will worsen dramatically with the advent of a worldwide crash program to build alternate fuels plants. We have therefore attempted to strike a balance between what we believe could be a somewhat slow startup of a worldwide coal liquefaction industry and a later speed up as experience is gained and new plants are built as essentially duplicates of previous plants.

Our coal liquefaction wedge thus assumes that the first coal liquefaction plants in a worldwide crash program would begin operation four years after a decision to proceed. We assume plant sizes of 100,000 bpd of finished, refined product, and we assume that five such plants could be brought into operation each year. We cannot predict where in the world these coal liquefaction plants might be built. Candidate countries with large coal reserves include the U.S. and the Former Soviet Union with the largest, followed in descending order by China, India and Australia.140 We note that a consortium of Chinese companies has recently signed a letter of intent with Sasol for feasibility studies on the construction of two new coal-to-liquids plans in China.141

If U.S. siting and environmental reviews of new energy facilities were to continue to be as time consuming as they are today, few coal liquefaction plants would likely be built in the U.S. On the other hand, China has been quick to approve major new facilities, so coal liquefaction plants in that country might well be built expeditiously and economically. Because there is presently a large international trade in coal, it is not inconceivable that coal-poor counties might become the sites of many coal liquefaction plants using imported coal, possibly even from the U.S.

Our coal liquefaction wedge then appears be as follows:

C. Heavy Oils / Oil Sands

As noted, significant heavy oil production currently exists in Canada and Venezuela. While their total resource is estimated to be 3-4 trillion barrels, recoverable oil reserves are estimated to be roughly 600 billion barrels.142 Such reserves could support a massive expansion in production of these unconventional oils.

In the case of Canadian oil sands, a number of factors would challenge a crash program expansion, such as the need for massive supplies of auxiliary energy, huge land and water requirements, environmental management, and the harsh climate in the region. In the case of Venezuela, large amounts of supplemental energy, inherently low well productivity and other factors will likely pose significant challenges.

We know of no comprehensive analysis of how fast the Canadian and Venezuelan heavy oil production might be accelerated in a world suddenly short of conventional oil. Recent statements by the World Energy Council (WEC) guided our wedge estimates:143

  • “Unconventional oil is unlikely to fill the gap (associated with conventional oil peaking). Although the resource base is large and technological progress has been able to bring costs down to competitive levels, the dynamics do not suggest a rapid increase in supply but, rather, a long, slow growth over several decades.”

  •  “(Extrapolating expectations of TOTAL Oil Company in the Orinoco, Venezuela) overall reserves today would be only ~60 Gb over 30 years, allowing at best 6 MM bpd of production in 2030 if the entire area were put into production.”

  • “Current estimates put the additional production of Canada (heavy oil) … at less than 2 MM bpd in 2015-2025.”

In line with the WEC, we assume the following for our Venezuelan Heavy Oils wedge:

 1. Accelerated production might begin three years after a decision to proceed with a crash program. This delay is based on the fact that the country already has significant production underway. Starting from scratch would require much more time.

2. Under business-as-usual conditions assumed by the WEC, Venezuela would have production of 6 MM bpd in 2030 —5.5 MM bpd beyond production of 0.5 MM bpd in 2003. If we assume this level of production is achieved 10 years after initiation of a crash program, rather than the roughly 25 years estimated by WEC, then roughly 5.5 MM bpd of incremental production might be achieved 13 years from a decision to accelerate.

3. In contrast to the WEC, we assume that Venezuelan production is not capped at 6 MM bpd but continues to expand for the period covered by our approximations. Note: We ignore the currently extremely unstable political environment in Venezuela and assume that scale-up timing is not hindered by local politics.

Our assumptions for Canadian oil sands are as follows:

1. Again, accelerated production might begin three years after a decision to proceed with a crash program, based in large part on the fact that the country already has significant production underway.

2. Current plans are for production of 3 MM bpd of synthetic crude oil from which refined fuels can be produced by 2030. This is above current production of 0.6 MM bpd. If we assume this level of production is achieved 10 years after initiation of a crash program, rather than the roughly 25 years targeted by the Canadians, then roughly 2.5 MM bpd of incremental production might be achieved 13 years from a decision to accelerate.

3. We know of no upper limit on Canadian oil sands production, so for purposes of this order-of-magnitude illustration, we do not assume one.

Our heavy oil wedge therefore is approximated as follows:

D. Enhanced Oil Recovery

Because it is impossible to evaluate the worldwide impact of Improved Oil Recovery (IOR) techniques, we can only provide a rough estimate of what might be achieved. We focus on a major subset of IOR technologies – Enhanced Oil Recovery (EOR). While EOR can add significantly to reserves, it is normally not applied to a conventional oil reservoir until after production has peaked. As discussed earlier, the most widely applicable EOR process involves the injection of CO2 into conventional oil reservoirs to dissolve and move residual oil.

Because EOR processes require extensive planning, large capital expenditures, procurement of very large volumes of CO2, and major equipment for large reservoirs, our simplified assumptions parallel those for our heavy oil and coal liquids wedges.

We assume that the massive application of EOR worldwide will not begin to show production enhancement until 5 years after the peaking of world oil production, paced primarily by the difficulties of procuring CO2. We further assume that world oil production enhancement due to such a crash effort worldwide will increase world oil production by roughly 3 percent after 10 years.144 We translate the 3 percent to 3 MM bpd, based on our assumed world oil peaking level of roughly 100 MM bpd.

Our EOR wedge thus appears as follows:

E. Gas-To-Liquids

Estimating how fast world Gas-To-Liquids (GTL) production might grow as a result of the peaking of world oil production is an extremely complex undertaking because of the need to consider the total world energy system, its likely growth by country, future energy economics, other resources that compete with natural gas, etc. In a crash program, GTL plants might be built in a number of counties that have large reserves of stranded gas.. Once operational, GTL product could be moved to markets around the world by conventional oil product tankers.

Our estimates for a crash program of world GTL production are tempered by the conflicting world demand for Liquefied Natural Gas (LNG), whose export volumes are currently growing at a rapid pace. The tradeoffs involved in estimating the future LNG / GTL balance are complex, and a world crash program in GTL could yield higher or lower volumes than our estimates. Note also that seven countries currently account for almost 80 percent of the world gas export market, and it is not inconceivable that the recently formed Gas Exporting Countries Forum (GECF) might well evolve into a future OPEC-like cartel.145

Again, we assume a startup delay of three years before crash program GTL plants might come into operation. Using a base case, business-as-usual production forecast of 1.0 MM bpd in 2015 from the current level of essentially zero, we assume that a crash program might yield the 1.0 MM bpd in 5 years.

The resultant wedge might then be as follows:

F. Sum of the Wedges

A summary of the estimates from the foregoing is presented in Table A-2.

Table A-2. Summary of Consumption and Production Wedge Estimates


Delay Until First Impact
Impact 10 Years Later
(MM bpd)
Vehicle Efficiency 3 3
Gas-To-Liquids 3 2
Heavy Oils / Oil Sands 3 8
Coal Liquids 4 5
Enhanced Oil Recovery 5 3

Ordering the various contributions by their starting dates, the total mitigation wedge is as shown in Figure A-5.

Figure A-5. The total of the wedge estimates

Appendix V. Notes On Shale Oil And Biomass

A. Oil Shale by Gilbert McGurl, NETL

Worldwide resources of oil shale comprise an estimated 2.6 trillion barrels, of which two trillion are located within the United States. The richest deposits, 1.5 trillion bbl with high concentrations of kerogen, lie in Colorado, Utah, and Wyoming. An additional 16 billion barrels of rich but physically different oil shale is found in Kentucky, Indiana, and Ohio. A recent estimate is that, from the Green River deposits, 130 billion barrels of oil may be produced. Technology development on oil shale ‘retorting’ reached a high point in the late 1970s, with the major oil companies leading the way. The oil price collapse of the 1980s, the dissolution of the synfuels program, and the termination of the Unocal project in 1991 led to the demise of oil shale production in the United States.

A recent study performed by the DOE Office of Naval Petroleum and Oil Shale Reserves advocates a research and development program with a production goal of two million barrels per day by 2020.146 Production would be initiated by 2011. Traditional technologies for mining and preparation of oil shale ores and for aboveground upgrading have been ‘proven’ at less-than-commercial scale.

Newer Canadian technologies have been tested at demonstration projects in Australia. However, that project, the Stuart upgrading project, is currently suspended pending project re-design. Nonetheless, the same technology has been licensed by operators in Estonia. Technologies for in-situ recovery are newer and less developed. In 2000, Shell revived an oil shale project called “Mahogany” in Colorado.147 Shell aims to test its process until 2010. If successful, the in-situ method would leave heavier hydrocarbons in the shale while producing lighter hydrocarbons and using much less water than traditional methods.

Most Estonian processing of oil shale has been for boiler fuel for electricity production. Small liquids facilities have been operating at “full capacity” given recent market oil prices. There are no solid figures for cost in large-scale plants since none have been built. The aborted Australian project estimated $8.50/bbl in operating costs once a commercial plant had been built. The Estonians estimate a break-even point at $21 Brent price (app $23 WTI) and low capacity factor. At higher capacity factors, plants may operate profitably even with prices in the mid-teens.

Besides water use and production, environmental concerns include fine particulates and carbon dioxide emissions. Since the last US oil shale project ceased operation before the implementation of the 1990 Clean Air Act amendments, new emission-control equipment would need to be tested on US shales.

B. Biofuels by Peter Balash, NETL

Bioethanol is produced as a transportation fuel largely in only two countries. In 2003 the US produced about 2.8 billion gallons and Brazil produced 3.5 billion gallons. All of this ethanol is produced by conversion of starch to sugar and fermentation to ethanol. In the US ethanol represents about 1.4% of the BTU content (2.0% by volume) of gasoline used in transportation. Current costs for ethanol production in the US are said to be $0.90 per gallon,148 which is equivalent to a gasoline price of $1.35 per gallon. Because of recent increases in energy costs current costs will be somewhat higher. Grain ethanol provides only a modest net energy gain because of the energy required to produce it. USDA calculated a net energy gain of 34% for a modern corn to ethanol plant,149 but there is considerable controversy over the real efficiency of the process. Most of the energy used to produce ethanol comes from natural gas and electricity. The production of ethanol uses only about 5% of the corn crop in the US. Significant expansion is possible but at some point there might be an impact on food prices.

Cellulosic ethanol is currently being produced only in two rather small pilot plants but is capable of producing about 40% conversion of cellulosic biomass to ethanol while providing all the energy needed for the process and exporting a modest amount of energy as electricity. It is anticipated that successful research may reduce the cost of cellulosic ethanol to about $1.10 per gallon by 2010. If this occurs the potential ethanol to mitigate peaking is high. Using only waste biomass and grass grown on land currently in the conservation reserve could produce 50 billion gallons of ethanol which would be equivalent to 35 billion gallons of gasoline or 17% of current US consumption. This could be achieved without any impact on current food production and at prices only $ 0.35 per gallon higher than refinery prices for gasoline. Since ethanol has an RON of 130 and a MON of 96 it raises the octane of the gasoline to which it is added and has a premium value as a result.

Appendix VI: Areas For Further Study

1. Economic Benefits to the U.S. Associated With an Aggressive Mitigation Initiative

Important economic and jobs benefits could result from a concerted U.S. effort to develop substitute fuels plants based on U.S. coal and shale resources and scale up of EOR. The impacts might include hundreds of billions of dollars of investment, hundreds of thousands of jobs, a rejuvenation of various domestic industries, and increased tax revenues for the Federal, state, and local governments. The identification and analysis of such benefits require analysis.

In the short run, the U.S would be hard-pressed to find adequate physical and human resources to plan, develop, construct, and operate the required facilities. Given that oil peaking is a world problem, it is virtually certain that at the same time the U.S. embarked on an aggressive mitigation program, other major initiatives would likely be undertaken elsewhere in the world. All would require similar types of capital, technology, and human resources, generating additional constraints and inflationary pressures on the U.S. program. Assessment of the impacts of these constraints on the feasibility, costs, and timing of a major U.S. mitigation program merits investigation.

2. Oil Peaking Risk Analysis: Cost of Premature Mitigation versus Waiting

The date of world oil production peaking is unknowable, but it may occur in the not too distant future. Large-scale mitigation is needed more than a decade before the onset of peaking if economic hardship is to be avoided. If major efforts were initiated early and peaking was to occur decades later, there might be an unproductive use of resources. On the other hand, mitigation initiated at the time of peaking will not spare the world from a decade or more of devastating economic impacts. A careful analysis of the benefits / costs of early versus late mitigation could provide valuable insights.

3. U.S. Natural Gas Production as a Paradigm for Viewing World Oil Peaking

The history of U.S. natural gas production is cited as an example of the perils of over-optimistic resource forecasts. A detailed analysis of the North American natural gas history, status, and outlook might provide lessons useful in addressing world oil production peaking.

4. Potential for Non-transportation Oil Fuel-Switching

World non-transportation liquid fuel usage is amenable to fuel switching, thereby freeing up liquids for transportation. If switching were to occur on a large-scale, it would likely take place gradually because other energy substitutes would have to be scaled up to meet the new demands associated with a major shift, e.g., electric power plants built, refineries expanded to produce a different product slate, etc. A detailed study would provide an understanding of how difficult, expensive, time-consuming and productive worldwide non-transportation fuel switching might be.

5. World Coal-To- Liquids Potential

Sasol has operational coal-to-liquids (CTL) production plants and is under contract to study the construction of similar facilities in China. An analysis of worldwide large-scale CTL potential could yield a useful estimate of complexity, timing and potential.

6. World Heavy Oil / Oil Sands Potential

Canada, Venezuela, and, to a lesser degree, other countries have potential to massively scale up their unconventional oil production. A better understanding of how quickly scale-up might be implemented, the related barriers, and ultimate potential would help in the understanding the potential contribution of these resources.

7. World EOR Potential

An analysis of worldwide large-scale EOR potential could provide an estimate of complexity, timing and potential.

8. World GTL Potential

An analysis of worldwide large-scale GTL potential could yield a useful estimate of complexity, timing and potential. In particular, the likely conflicts between GTL and LNG production could provide a quantitative estimate of likely future use of world stranded gas.

9. World Transportation Fuel Efficiency Improvement Potential

It is important that we have the best possible understanding of the U.S. and worldwide potential for the upgrading of transportation fuel efficiency, including possible timing, cost, and savings as a function of time. Excellent data is available on U.S. transportation fleets, but fleets elsewhere in the world are less well described. A careful study is needed.

10. Impacts of Oil Prices and Technology on U.S. Lower 48 Oil Production

Analysis of U.S. Lower 48 oil production since the 1970 peak strongly suggests that oil prices and advancing technology had little impact on the production decline. However, a number of institutional factors also impacted Lower 48 oil production, e.g., allowables (Texas Railroad Commission), price and allocation controls (1970s), free market pricing (since 1981), foreign opportunities for multi-national oil companies, etc. An in-depth understanding of these various influences might provide useful guidance for the future.

11. Technological Options for Coal Liquefaction

Current world coal liquefaction R & D is focused on gasification of coal followed by the Fischer-Tropsch synthesis. Other coal-to-liquids processes have been proposed, some of which were tested at relatively large scale. It may be worthwhile to revisit the various options in light of today’s technology and environmental requirements to determine if any of them might also have competitive potential.

12. Performance of Oil Provinces Outside of the U.S.

There is a strong rationale for using U.S Lower 48 oil production as a surrogate pattern for future world oil production peaking and decline. Other large oil province histories could also yield valuable insights and alternate patterns. Related analysis might provide an improved basis for modeling future world oil production.

13. How the U.S. Could Again Become the World’s Largest Oil Producer

After the peaking of world conventional oil production, there will be a major world transition from the current world liquid fuel infrastructure. Over time, major conservation and energy switching initiatives will almost certainly be implemented, but the need for liquid fuels will not disappear for at least the remainder of this century because there are no known alternatives for a number of transportation applications. An analysis of the major factors required for the U.S. to return to a position of oil supremacy and oil independence would be enlightening.

14. Market Signals in Advance of Peaking

Increases in oil prices and oil price volatility have been identified as two precursors of world oil peaking, but both are likely short-term signals. The identification and character of longer-term signals, if they exist, could be of significant value.

15. Risk of Repeating the Synthetic Fuels Experience of 1970s and 1980s

One risk of embarking on aggressive oil peaking mitigation is that OPEC might undermine such efforts by dramatically increasing conventional oil production. This could only happen if excess capacity were to exist, which could happen if world oil peaking was many decades away. Were such a dramatic increase in OPEC production to occur, governments would be under pressure to terminate support for their mitigation programs. Related scenarios might worthy of study.

16. Effects of Oil Price Spikes in Causing U.S. Recessions

Oil price spike have been followed by U.S. recessions, but they are not the only cause of recessions. A detailed study of the role of oil prices and other factors in causing recessions might be worth further study.

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