Youngquist on Oil, natural gas, heavy oil, tar sands, GTL, GTO, oil shale

Preface. I was fortunate enough to know Walter for 15 years. He became a friend and mentor, helping me learn to become a better science writer, and sending me material I might be interested in, and delightful pictures of him sitting in a lawn chair and feeding wild deer who weren’t afraid of him. I thought his book Geodestinies: The Inevitable Control of Earth Resources over Nations and Individuals, published in 1997, was the best overview of energy and natural resources ever written, and encouraged him to write a second edition. He did try, but he spent so much time taking care of his ill wife, that he died before finishing it. I’ve made eight posts in Experts/Walter Youngquist of just a few topics from the version that was in progress when he died at 96 years old in 2018 (500 pages).

Key points:

  • The worldwide oil depletion rate has been estimated at between 4 to 9% annually. A figure of 6.7% seems to be the current situation. The huge investments needed just to slow this decline are not forthcoming. Many countries spend their oil income mostly on domestic needs and cannot or do not invest in oil production enhancement projects on which little immediate return is available. Mexico, for example, has underfunded its oil infrastructure to pay for social programs.
  • What seems clear is that the era of cheap oil has passed. The easy oil has been discovered and developed and the oil industry has moved into far more expensive frontier areas such as the Arctic regions and deeper ocean waters.
  • The precise date of the peak of world oil production, however, is an irrelevant academic exercise, since the true peak will be known only in retrospect, after several years of well-documented declining production. The important fact is that oil production will inevitably peak and then decline.
  • Oil production (some call it “extraction”) has exceeded the volume of oil discoveries since 1981, now by a factor of four. Around the world, the 31 billion barrels of oil consumed each year are not replaced with discovery.  We have been consuming oil at an unsustainable exponential rate.

Other Youngquist Geodestinies Posts:

Alice Friedemann www.energyskeptic.com  author of “Life After Fossil Fuels: A Reality Check on Alternative Energy“, 2021, Springer; “When Trucks Stop Running: Energy and the Future of Transportation”, 2015, Springer; Barriers to Making Algal Biofuels, and “Crunch! Whole Grain Artisan Chips and Crackers”. Podcasts: Collapse Chronicles, Derrick Jensen, Practical Prepping, KunstlerCast 253, KunstlerCast278, Peak Prosperity , XX2 report

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Depending on how one defines the limits of a basin, there are about 600 sedimentary basins worldwide, most of which have been explored to a greater or lesser extent. Only about two hundred of them are oil productive, and of these, only a very few basins contain the huge oil fields in which most oil is located. The Earth has been fully explored and the larger and most productive oil basins have been drilled and are now in production.

This organic material accumulates with other sediments in structural basins in the Earth, both within continents invaded by the ocean, and along the continental margins. The central deep ocean regions do not have any significant accumulation of sediments and, therefore, have no oil.

The organic material from which oil is derived is mostly plants, with algae in many areas being the predominant source material. Campbell (2005a) notes that, “Isotopic examinations show that oil was derived from algae.” Algae in ancient oceans furnished the basis for industrialization and for dramatically different lifestyles from previous centuries. The course of human history has been greatly influenced by simple algae transformed into oil. Other sources of oil include the buried mangrove swamps found in offshore Angola and in Southeast Asia. Plankton, both floating animal and plant forms are also important. The unicellular animals, foraminifera, may be a major source of the oil found in the Sirte Basin of Libya. Most oil is formed in marine environments. A few commercial deposits have been discovered in deeply buried organic materials (mostly algae) in lake basins in Nevada and China. Freshwater algae produce quite a different type of oil than does marine algae. There are about 30,000 species of algae.

Many kinds of oil. The kind of source material, how long the organic material and then the oil are “cooked,” and at what temperatures, how deeply it is buried (pressure) and for how long, determine the many different kinds and qualities of oil. The Oil & Gas Journal lists prices for fourteen different oils produced just in the United States.

Oil can be classified in various ways, but a common way is to designate it either as “sweet” (less than 5 percent sulfur) or “sour” (5 percent or more sulfur). It is also classed by how light (thin) or heavy (thick) it is. This is expressed by a “gravity” figure, inverse in numbers to how thick or thin the oil is. A 40 gravity oil is light, and a 20 gravity oil is heavy. At around 52 gravity, the oil becomes gas. Oil in the Maricaibo basin of Venezuela is heavy crude (around 20 gravity). It is so heavy that the oil storage tanks are not painted silver to reflect the Sun’s heat, but black to absorb heat and keep the oil thin for pipeline movement.

Refineries prefer to refine light oils with a low sulfur content, since they can be more easily made into higher value end products. Worldwide, these oils have generally been produced first, so remaining oil is a heavier and lower quality crude. Refineries are gradually having to adjust to this new reality, with related higher refining costs.

Once deposited in an anaerobic (oxygen-lacking) environment through which the organic material is preserved, it must be buried deeply enough so that the geothermal (temperature) gradient of the Earth is such that a temperature of about 156oF is reached (minimum temperature for the start of “oil window”). Together, with the pressure of the overlying sediments, the organic material is slowly “cooked” to produce oil.

Using plant material as the theoretical originating material, Jeffrey Dukes, biologist and biochemist at the University of Massachusetts, has calculated that it takes approximately 190,000 pounds (95 tons) of prehistoric plant material to yield 13.2 pounds of crude oil, including 6.2 pounds (one gallon) of gasoline.

Just drill deeper? To prolong the oil interval we now enjoy, it is sometimes suggested that we should simply drill deeper for more oil. This might be true in a limited number of places, but if it was possible and feasible, oil exploration companies already would have done so. At 10,000 feet, and in some regions such as Kansas, even shallower, the drill bit would hit either igneous or metamorphic rock (so-called “basement rocks”) where oil is not generated and does not exist. Oil is limited vertically by the depth needed for the “oil window” temperature to be reached, but oil occurrence also is limited at greater depth. In most of the Earth, below 15,000 to 16,000 feet, the geothermal gradient (increase in temperature with depth) is such that at these depths and related temperatures, oil is not stable and breaks into the simplest hydrocarbon molecule, methane.

There is an ultimate depth below which no oil, only natural gas occurs. So “drilling deeper” is generally not the answer to finding more oil.

The terms “reserves” and “resources” are sometimes confused. The term reserves applied to any natural resource including oil, means the amount that can be produced with existing technology at current prices. Obviously, reserves may vary in size depending on the development of new and more efficient technology and current prices. This has certainly been seen in the case of both oil and natural gas, and in metals, with wide fluctuations in the prices of gold and silver and the size of “reserves” of these commodities changing.

Resources are the total amount of the commodity in the Earth, only a portion of which at any time can correctly be termed reserves. Also, the term “oil in place” is sometimes used in the oil industry to describe the resource. Press reporters and others may make the error of assuming oil in place (resource) is a reserve. An example is the oil in the Caspian region, where the oil in place initially was estimated at 200 billion barrels and the press reported an oil discovery “nearly equal to the reserves of Saudi Arabia.” However, when geologists and engineers later reevaluated the Caspian reserves, they arrived at a figure of about 40 billion barrels.

The Athabasca oil sand deposits are another example. Estimated to have as much as two trillion barrels of oil in place, the economically recoverable oil (reserves) are estimated to be in the vicinity of 175 billion barrels. With the steep drop in the price of oil during 2007-2008, from more than $147 a barrel to briefly less than $40, part of the Athabasca oil reserves were relegated back to the status of resources. Development of some oil sand projects were put on “hold” to a time when the price of oil again rises, and some of the resources revert to reserve status.

“Political reserves” may serve a couple of purposes. They may be inflated because the people in charge of oil field operations in a country are prone to report to the politicians in charge that they have found more oil that year than they produced, so reserves happily go up. Workers continue to keep their jobs and may even get a raise. Also, in OPEC countries, agreed upon production quotas are based on reserves. Some countries in OPEC can increase their production to increase their oil export by inflating the reserves. The end result is that unaudited reserve figures are suspect

In a belated response to the first oil embargo crisis of 1973, the U.S. established the U.S. Department of Energy in 1977, with the stated purpose “to lessen our dependence on foreign oil.”

Large oil fields, because they are large, are usually discovered early in exploring a basin. As drilling proceeds, less and less oil is found per foot drilled. French geologist, Jean Laherrère, putting this trend in graphic form, calls it the creaming curve.

A spurt in worldwide drilling from 1976 to 1983 did not find a commensurate amount of oil, illustrating that large, easier to find oil accumulations had already been discovered. What remained required more drilling. Thus each barrel of oil discovered is more expensive than it was in earlier years.

The depletion problem Like the proverbial alligator continuing to eat up a leg, depletion of oil fields continues everywhere. When primary (flowing and pumping) and secondary recovery (water flood and gas injection) have been used, sometimes a third method of oil production is used termed Enhanced Oil Recovery (EOR). These methods include injection of steam or chemicals to improve oil flow to wells from the reservoir. Costs range from $1.50 to $30 for each additional barrel recovered. But this technology has been only moderately successful, and does not add much to the total oil being produced.

The worldwide oil depletion rate has been estimated at between 4 to 9% annually. A figure of 6.7% seems to be the current situation. The huge investments needed just to slow this decline are not forthcoming. Many countries spend their oil income mostly on domestic needs and cannot or do not invest in oil production enhancement projects on which little immediate return is available. Mexico, for example, has underfunded its oil infrastructure to pay for social programs.

What seems clear is that the era of cheap oil has passed. The easy oil has been discovered and developed and the oil industry has moved into far more expensive frontier areas such as the Arctic regions and deeper ocean waters.

The precise date of the peak of world oil production, however, is an irrelevant academic exercise, since the true peak will be known only in retrospect, after several years of well-documented declining production. The important fact is that oil production will inevitably peak and then decline.

Currently NOCs control about 90% of world oil reserves. The combined reserves of ExxonMobil, BP, Shell, ConocoPhillips, Chevron and Total (a French company) are less than 25% of the reserves Saudi Arabia claims. In countries where IOCs can still operate because they have the technology and the capital (i.e., Angola, Algeria, and Nigeria), the host nations are demanding so much of the profits that some IOCs have decided they can no longer operate there. ExxonMobil abandoned the Orinoco heavy oil deposits when Venezuela abruptly raised taxes from 1 percent to sixteen percent. It takes as long as 10 years from the time of winning bids (all proceeds going to the country of ownership regardless of whether oil is found or not) to reach any oil production. Corporate plans have to be made on the basis of the initial financial agreements. Countries may, and increasingly do, simply tear up existing contracts and insist on new ones. One country did so after a company had spent years and millions of dollars in exploration and finally discovered oil. The host country then canceled the original contract. When asked about this action, the country told the company that “we gave you the lease at the original agreed cost because we didn’t expect you to find any oil.” In another country, before leases were issued, an IOC spent two years and millions of dollars determining which of the lease blocks being offered had the best prospects. When they told the host country they would take the leases, the NOC of the host company took the leases for itself instead. So the IOC did all the work and the NOC took all the benefit.

If IOCs are to continue finding oil after their home country has been thoroughly explored, as the onshore United States has been for example, they must explore new areas and depend on other countries for their survival as oil companies. This has also pushed drilling offshore, sometimes to depths down to 10,000 feet, making these ventures very costly. Major oil companies in the United States have moved both abroad and into the Gulf of Mexico, drilling as far as 200 miles offshore, risking hurricanes and other harsh conditions. Offshore drilling platforms are leased and the daily lease cost for one drill rig is as high as $700,000. A company has to find a lot of oil to justify such costs, and, at best, the oil is very expensive to recover.

In 2011, the largest investor-owned companies, ExxonMobil, Royal Dutch Shell, commonly known as Shell, and BP reported higher profits but they produced less oil from fields around the world. Their decline in production was 7%. The results highlighted a growing problem. New petroleum supplies are increasingly hard to find, and they cost more to find and develop. A decade ago, bringing in an oil well cost about $20 for every barrel produced. The cost now is estimated to be $50 to $60 per barrel. Cost is calculated on the basis of exploration and subsequent field development expenses amortized over the life of the field and oil produced.

Petroleum industry’s use of technology No other industry employs the magnitude and diversity of technology that petroleum does through its exploration, production, and refining. The scope of technology used includes satellites for positioning offshore drilling platforms and for transmitting data from remote drilling locations to regional offices to get a vision of the internal structure of the Earth. Completing ocean floor oil wells with robots laying and repairing thousands of miles of ocean floor pipelines to facilitate gathering crude oil and natural gas from wells to central locations is now possible. And there is much more. In refining, the chemistry and physics complexities involved are enormous.

Lengths to which oil industry now goes to reach oil. There have been many advances in oil exploration and production. One has been the increased distance to which multiple drilling bits can now be steered to reach an oil reservoir from a single drilling platform. The most recent record is 7.6 miles. This extended reach drilling (ERD) means that the “footprint” of oil production is greatly reduced, as ERD can now reach an area of as much as 4.4 square miles.

Not replacing their reserves. Because they now have fewer quality exploration opportunities, most major IOCs are not replacing their production with new discoveries. In 2008, for example, ConocoPhillips only replaced one out of every four barrels of oil they produced.

Oil production (some call it “extraction”) has exceeded the volume of oil discoveries since 1981, now by a factor of four. Around the world, the 31 billion barrels of oil consumed each year are not replaced with discovery.  We have been consuming oil at an unsustainable exponential rate. As a widely used advertisement by Chevron says, “It took us 125 years to use the first trillion barrels of oil. We’ll use the next trillion in 30.”

Newly utilized technology of drilling vertically to a target shale formation and then drilling horizontally and hydraulic fracturing (“hydrofracking” or just “fracking”) the shale with chemically treated water and sand greatly increases the amount of gas ultimately recovered. Experience has shown that using this technology may also recover oil from shales. These strata were previously regarded only as oil source beds, not producible oil reservoirs. Combined with the rise in the price of oil, likely to remain at $80/barrel or higher, oil is now being economically recovered using this technology directly from some shales.

The volume of shale strata around the world is enormous, but there are also great unknowns. Still to be discovered in many areas is whether the shales have been buried deeply enough and long enough over geologic time to have reached the temperature (the “oil window”) at which oil is formed. If the shales are not yet mature, the organic material is still kerogen, the precursor of oil, as is the case of misnamed “oil shale” strata, which have no oil.

The reason why gasoline is so expensive in some countries is that these nations put higher and higher taxes on it as a general source of government revenue. In the United States, there is a popular idea that taxes on transportation fuels, gasoline, and diesel, are to be dedicated to the building and maintenance of the road system. The public is under this impression. However, a study by the American Petroleum Institute revealed that user taxes and fees subsidize many other government activities. At the present time in the United States, the federal excise tax on gasoline collects about $20 billion annually. State and local government taxes add another $30 billion.

The United States, among all countries, is by far the largest per capita consumer of oil. Each day, California alone consumes more oil than either Germany or Japan. The rest of the world also has a rising consumption of oil. With regard to the concentration of oil in the Gulf area, the comment has been made that, “Not only is the world addicted to cheap oil, but the largest gas station is in a very dangerous neighborhood.

The mobility that oil provides to people on an individual basis through the private automobile has changed the social structure. When the younger generation got “wheels,” the family fabric began to be stressed. Family togetherness in the past, when weekends were times of local gatherings of clans, was replaced by diverse activities of the several family members, frequently going in different directions and considerable distances. It is no longer remarkable to travel hundreds of miles or more on a weekend to visit some point of interest or engage in a recreational activity. Just a century ago, this was not possible. A hundred years ago, Americans may have dashed through the snow across town in a one-horse open sleigh to get to grandma’s in time for Thanksgiving or Christmas; today travelers fill airports, and jet planes fill the skies to whisk people home for these holidays from across the continent.

SHALE “FRACKED” OIL

Shales which have gone through the “oil window” differ in the amount of oil they may contain. Some have very little. Individual shales may also have “sweet spots” subject to economic exploitation. Other areas where the oil content is lower may not be economic to drill.

There are environmental impacts from the amount of water needed by each well (5-6 million gallons), and from the subsequent disposal of the recovered water containing chemicals used to thicken the water to enable it to carry sand farther into the formation to hold open the fractures. Obtaining enough suitable sand for fracking operations is a problem in some localities. Bowing to environmental concerns, France, Germany, South Africa, and in the U.S., New Jersey, New York, Maryland, and some other states have imposed temporary or permanent bans on fracking.

With the large number of shale deposits in the United States and abroad, the frontiers of exploration have been greatly enlarged. Shale deposits may have large production potential not earlier recognized. Broadly interpreted, there are 600 sedimentary basins in the world (Guoyo, 2011). Evaluating all these prospects will take many years, so the amount of oil and gas that can be produced from these basins is unknown today. Exploitation of these resources may well result in two peaks rather than one oil production peak. The first is the peak (possibly already passed) of oil recovered from conventional reservoirs (usually sandstones or fractured or vulgar limestones). The second peak may come from conventional oil production with the added increment of oil from shale. A peak made independently by shale oil alone is possible, but not likely.

Key to economically recovering both oil and gas using the hydrofracking technology is the energy/profit ratio, also termed energy recovered on energy invested (EROEI). Because the technology is new, it is premature to make a study, but eventually it will be done to give an overall view of the worth of the technology. The energy/profit ratio for shale oil is likely to be less than for conventional oil now, estimated to be about 15 to 1. This ratio is declining as more costly oil is being produced in more difficult environments like deep water and Arctic regions.

The production of oil from shale by fracking is likely to reduce but not eliminate the need for imported oil. Longer term, the U.S. and many other countries will still depend on the Gulf countries,

It is frequently said that we have sufficient oil left for 40 years at the current rate of production. But the current rate probably cannot be maintained. Furthermore, oil production does not proceed at a fixed rate for 40 years and then drop off to zero. Production curves rise from zero to a peak and then decline back to essentially zero. Some oil will be produced for many more years, but there will be less, and it will cost more. Oil will be used only for higher end-value uses.

The extravagant ways in which we have used oil, have within them the seeds of oil’s ultimate demise. The decline of world oil production will sort out excesses and pare down waste. A post-oil energy paradigm will emerge, but for many uses, there is no adequate satisfactory substitute for oil.

Conversion equivalents. That theoretical 42-gallon barrel of crude oil is equal in energy to 5,800,000 British thermal units (Btus), 5,614 cubic feet of natural gas, or 0.22 short ton (short ton = 2000 pounds) of bituminous coal. Various crude oils differ in density, but the average barrel of crude oil weighs about 310 pounds.

NATURAL GAS

In common usage, “gas” means gasoline, but in the oil industry, gas means natural gas, which is mostly methane. With four hydrogen atoms attached to one carbon atom (CH4), methane is the lightest of the hydrocarbon gases.

Once considered a nuisance in the oil fields and simply flared (burned off), natural gas is now in increasing demand as a feedstock for petrochemicals, for home heating and industrial use, and more recently, as a replacement for coal to produce electricity. As gas occurs in a greater variety of geological circumstances than oil does, and is more widespread in its occurrence, it now appears likely that the overall energy content of all gas reserves may be larger than that of all oil reserves. Gas may displace oil as the dominant fossil fuel in this century.

Gas pipelines now reach all 48 adjacent states. About 60 percent of U.S. homes are heated with gas, and 70 percent of new subdivisions are being designed for natural gas heat. Much of northern Europe is heated with natural gas from the North Sea fields and Russia.

The United States is the world’s largest consumer of natural gas, and currently uses about 23 trillion cubic feet (Tcf) annually, equal to 26 percent of world production.

Although gas from the Earth is mainly methane, other associated gases exist including carbon dioxide, nitrogen, and usually small amounts of hydrogen sulfide. Some gas wells also produce helium, which is the only known source of that gas.

Methane comes from a greater variety of organic material than oil does. Deltaic sediments contain relatively large amounts of woody and other land-derived material, and are more likely to have gas than are deposits that are more marine in origin.

There are two principal processes that form natural gas. It may be expelled from microorganisms during the digestion of organic matter. Methanogens are methane-producing micro-organisms, which pervade the near-surfaces of the Earth’s crust and are devoid of oxygen, and where temperatures do not exceed 207 F (97 C). Methanogens also live in the intestines of most mammals (humans included), and in the cuds of ruminant animals such as cows and sheep. This is called biogenic gas.

Methane gas is also produced by the decomposition of organic matter by heat and pressure, and accordingly is called thermogenic gas. This methane is formed similar to oil. Organic material deposited in mud and other sediment is deeply buried, heated, and compressed, causing carbon bonds to break down and form oil with some gas. Because the temperature of the Earth increases with depth, below about 15,000 to 16,000 feet, the temperature is so high that oil cannot exist and decomposes into methane. Gas is now being drilled and produced from depths of 25,000 feet and more.

Unlike oil formed by organic material, which must go through a heat “window” of at least 156 F, natural gas can form at relatively low (normal atmospheric) temperatures and pressures. The bubbles you observe in lakes are not due to fish blowing bubbles as folklore would have it, but results from the production of natural gas from the decaying vegetation in the lake bottom. The relatively shallow Devonian black shales (black because of their organic material) of the eastern and central United States and the Cretaceous black shales of the Great Plains, some of which lie at shallow depth, contain methane gas. Farmers have drilled shallow wells (from a few dozen to a few hundred of feet deep) in their backyards and produced gas, which they piped into their farmhouses, and into other farm areas for various purposes.

Gas is often associated with oil, but a considerable amount of gas is not— thus the terms associated and non-associated gas. Gas associated with oil commonly is composed of a variety of gases including mainly methane but also ethane, propane, butane, pentane, and hexane, and is called wet gas. Gas not associated with oil usually does not have many other gases besides methane and is called dry gas. Some gas contains hydrogen sulfide, H2S, and is called sour gas. The amount of hydrogen sulfide can be very large, to the point where one well in southwestern Alberta was classified as a sulfur mine. Many of the wells in the Caspian Sea region produce sour gas and also oil with hydrogen sulfide, which has to be taken out. The result is huge piles of sulfur for which there is no immediate use. Sulfur in oil and gas combines with water to form highly corrosive sulfuric acid, attacking any metal equipment it touches. Likewise, acid rain, which damages aquatic ecosystems, soils, and forests, is formed when sulfur dioxide (SO2) combines with water to produce sulfuric acid (H2SO4).

Coalbed Methane and Gas Hydrates

Gas found by drilling a well into sediments in which various organic materials have produced gas is called conventional gas. This is where most gas comes from today. However, there are special occurrences of gas. One of these is coalbed methane gas.  The bane of underground coal mining is the toxic and explosive methane gas trapped in coal deposits. The miners’ canary was taken into the mine to provide early detection of methane gas. Recently, with surging demand for natural gas in North America, particularly the United States, the search for gas supplies has expanded to coalbed methane.

Coalbed methane accounts for about 10% of total U.S. gas supplies. The estimated resource base is large, most of it located in the Rocky Mountain States, which now produce 80% of the coalbed gas. The wells for the most part are shallow and coal can be reached at less than 300 feet in many places with a truck-mounted drill rig as they do in the Powder River Basin of Wyoming. There, a well costs around $65,000 and the gas finding cost is about 16 cents per thousand cubic feet, with average well reserves of 400 million cubic feet. In other places, costs are substantially higher but it still may be economic to drill.

To release the gas in the coal, the coal has to be dewatered. As water is pumped out, gas is released from the coal as water pressure is reduced. However, pumping out the water can result in regional lowering of the water table, and the water may also be toxic, and if discharged on the surface, can contaminate both the landscape and local streams. In some areas, there is now substantial public resistance to coalbed methane development.

Nevertheless, coalbed methane development is continuing with many thousands of wells projected to be drilled in the next decade. Canada and Australia have begun to develop their considerable coalbed methane resources, which appear to be considerable. Mexico is investigating its prospects, which, however, appear to be modest.

Gas hydrates (also termed gas clathrates) remain a tantalizing elusive source for the gas industry. Gas hydrates occur worldwide as solid material composed of water molecules forming a rigid lattice of cages of various sizes with most of the cages containing a molecule of gas, chiefly methane. Laherrere (2000) reports that methane hydrates generally occur as dispersed grains and very thin laminae, with the thickest bed recorded so far, as being about one meter.

Stranded Gas: LNG, GTL and GTO

As noted earlier, gas is widely distributed; many deposits are located where there is no ready local market, nor can a pipeline be economically built to reach a market. This is called stranded gas. Of all known gas deposits, about 60% are classified as stranded

Liquefied Natural Gas (LNG)

The technology for liquefying natural gas has been known for many years, dating back to the 19th  century when British chemist and physicist Michael Faraday experimented with liquefying different types of gases including methane. The technology involves a liquefaction plant (called a “train”) located where the gas is produced. There, gas is cooled to a liquid at -260 F, at which temperature it occupies 1/600th of its volume as a gas. Then it is put into refrigerated containers on a ship and transported to a regasification terminal and stored until it is ready to be released into a pipeline system. There are four regasification terminals in the United States, which supply about two percent of U.S. gas demand.

LNG is expensive because the cost of the facilities at each end of transportation and the specially built ships which have to be built. One such system can cost several billion dollars. LNG tankers of the size now operating can carry from 150,000 to 200,000 cubic meters of LNG, about 4.2 billion cubic feet of gas per ship. One tanker can meet the energy needs of about 14 million U.S. households for one average day of space heating and other heat requirements.

But the energy involved in cooling gas to a liquid, and required to transport it makes the net energy recovery considerably less than that from gas produced locally, processed, and then put into a pipeline. Depending on the distance it has to be shipped, as much as 30% of the energy equivalent of the gas being transported can be consumed by the LNG system.

The safety record of natural gas transport is excellent. There have been more than 33,000 LNG shipments in 45 years without a significant accident or cargo spill (Glenn, 2004). However, safety concerns, particularly with respect to what terrorists might do to regasification installations, has created considerable local opposition to the siting of regasification plants.

LNG tankers are huge. A typical tanker is longer than three football fields and contains more than 33 million gallons of LNG. However, raising the risk of terrorist attacks, articles have appeared stating that a terrorist attack on an LNG tanker “ …would have the force of a small nuclear explosion.” Such concerns have generated strong opposition to siting LNG landing sites along any coast. Zellner and Hindo (2005) reported, “From Maine to California developers of liquefied natural gas (LNG) terminals are facing protests at every turn.” “Liquefied gas projects energize opposition” read the headline with respect to four proposals to put LNG terminals along the lower Columbia River to supply Oregon and Washington now that an expanded population consumes all the power that can be guaranteed from the dams on the river.

How dangerous LNG would be in a terrorist attack is disputed. The Federal Energy Regulatory Commission says that, “ …LNG won’t explode and won’t burn in its liquid state.” In a spill, the product can be ignited but only after it vaporizes and combines with a mixture of air ranging from 5 percent to 15 percent. Mixtures outside that range are either too lean or too rich to burn and most of the gas, being lighter than air, quickly dissipates, so any resulting fire would be of very short duration.

Before the present concerns for LNG were thought of, a number of LNG regasification sites were built onshore. There are now 17 LNG export terminals and 40 LNG import terminals worldwide, and about 150 specially designed LNG ships in operation. LNG landing facilities exist in many countries, including Taiwan, Turkey, France, Greece, Spain, Belgium, South Korea, India, and others. China is planning to build as many as 10 LNG terminals over the next few years and is tying up long-term supply contracts with Indonesia, Russia, and the Persian Gulf nations.

Gas to liquid — GTL. The International Energy Agency (IEA) says that the gas-to-liquid technology is wasteful, with about 45% of the natural gas lost in conversion. The process consumes 10,000 cubic feet of natural gas to make one barrel of fuel. This is partially offset, however, by the fact that the end product is a high-grade, clean, diesel fuel, which does not need further refining.

GTO — gas to olefins. This is a new process for producing the basic chemicals needed to make polymers and other olefin-based chemicals. The process turns natural gas into ethylene and propylene— the high-value basic building blocks for making products ranging from food packaging and diapers to auto parts, toys, and medical supplies. The gas is first turned into methanol which can be easily transported. The methanol can be either shipped to the ultimate customer location for conversion into olefins or converted directly to olefins at the remote location. What makes GTO particularly appealing is its potential to use natural gas from remote fields that doesn’t have easy access to world markets— “gas that otherwise would be difficult to sell” (The Lamp, 2004). The first on-site GTO plant, however, is several years away.

Gas as Aid to Oil Production. Gas associated with oil may occur as a gas cap over the oil in an oil-bearing structure, and also dissolved in the oil. Gas dissolved in the oil makes the oil more fluid and, therefore, easier to move to the well bore for recovery. Gas above the oil in a gas cap pressures the oil, moving it to the well bore and also aiding in greater oil recovery. So when oil is being produced, the ratio of gas to oil, the gas/oil ratio (usually expressed in cubic feet per barrel of oil) is kept as low as possible, by “choking” the well with small aperture valves. These apertures are sometimes as small as 1/8th or 1/4th inch in diameter, to produce oil more slowly and retain as much gas as possible in the reservoir. If the well were run wide open, the gas dissolved in the oil tends to come out first, reducing the pressure, leaving the oil behind. This is oil and gas reservoir engineering, a very important part of oil and gas production, managed by highly trained petroleum reservoir engineers. If there is no pipeline to remove gas from the well site, the gas is almost always pumped back into the producing formation to aid in further oil production. This is the situation in the north Alaskan Prudhoe Bay Field. Eventually, this gas could be piped down to the 48 contiguous states. In the meantime, it is retained in the oil reservoir, except for a small amount that is used locally to support the living and working facilities of the oil camp. It gets as cold as -60 F in north Alaska, so the gas is very useful.

World Natural Gas Reserves. Because serious natural gas exploration has occurred much more recently than oil, reserve figures as we have them now, will no doubt be subject to substantial revision over the next decade or two. In the United States and Canada, about 80% of all wells now being drilled are for natural gas — quite a reversal from time past when oil was the prime exploration target. 

Currently, the United States produces about 19.2 Tcf of gas per year, but uses about 23 Tcf. Gas demand is expected to grow to 30 Tcf within a decade. Can this demand be met? To make up for the growing deficiency in domestic gas production, more and more gas has to be imported from Canada, which now amounts to about 16 percent of U.S. supply. At present, average per capita gas production in the United States is 68,790 cubic feet. For Canada, a much colder country on average, per capita consumption is 192,190 cubic feet per year. This very large per capita gas consumption makes Canada vulnerable to the time when its gas production peaks and begins to decline.

This already may have occurred. In 2002, Canada drilled 18,000 gas wells, but production fell (Potential Gas Committee, 2003). There are two reasons for this. Gas wells have very high decline rates compared with oil wells. In Canada, first-year gas well depletion rates may be as high as 50 percent or more (some as high as 83 percent). The depletion rates settle down after about two years to 20 to 28 percent (Youngquist and Duncan, 2003). Also, the size of new discoveries has been falling. In 1991, average initial production per gas well drilled in the Western Canadian Sedimentary Basin (lying between the granitic Canadian Shield to the east and the folded Rocky Mountains to the west) was 775 thousand cubic feet a day. In 2001, average initial production was 375 thousand cubic feet a day. Obviously, the new reservoirs being discovered are decreasing in size which is typical of a maturing exploration region.

Mexico uses 12,020 cubic feet per capita per year, almost all of it for industrial purposes. Although the U.S. imports gas from Canada, the U.S. is a net exporter of gas to Mexico— a somewhat anomalous situation required by NAFTA.

Oil and gas reservoirs are managed quite differently from one another. Gas travels through pore spaces in the reservoir far easier and faster than oil. An oil well usually has a water-drive. If an oil well is run wide open, the water will tend to “channel,” because the reservoir rock has different degrees of permeability. The result is that water, which can move through reservoir rock more easily than oil, will channel through the more permeable strata, bypassing the oil. The well then tends to go to water, leaving a lot of oil still in the reservoir. Oil wells are “choked” down so the oil is produced slowly, and while it moves slowly through the reservoir rock, water does not bypass it. This concept is termed the maximum efficient rate of production (MER).

In contrast, in a pure gas well, the gas rises through any water to the well bore. There is no channeling problem, and the well can be run essentially wide open. Thus, all the gas in the reservoir is produced rather quickly. As there is a time value for money invested in drilling the well, the quicker the gas is recovered, the higher the rate of return. The only major restraints may be the market for the gas and the availability of pipelines to carry the gas. In summary, all these factors result in a much higher decline rate for gas wells than for oil wells. The average onshore gas well in the United States experiences on average, a 22% annual decline, much higher in early well life, but lower later. Offshore wells in the Gulf of Mexico have as high as a 50% annual decline rate. Gas wells, therefore, have a much shorter life than oil wells. This means many new gas wells must be drilled each year just to maintain production levels, which we are not doing. In 2003, the United States drilled 23,000 gas wells and the overall production level barely changed. It is a treadmill, and as gas drilling goes deeper, it is an increasingly expensive treadmill. In the first quarter of 2002, the top 30 U.S. gas producing companies suffered a gas production drop of 3% from the fourth quarter of 2001. These companies generate more than half of all U.S. gas production.

Size of discoveries. Larger fields tend to be found early because they are large. Simple random drilling can find them. As exploration proceeds, it takes more drilling to find gas and the amount of gas found per drilling rig declines. In the United States in 1994, the added production found by each drilling rig was 27.9 million cubic feet a day. By 2001, this figure had dropped to 13.9 million cubic feet a day.

Alaskan gas.  There is a large amount of gas in the Prudhoe Bay and adjacent oil fields. Currently, this gas, which is associated with oil production, is reinjected into the reservoir to maintain reservoir pressure. Eventually, as the oil is depleted, more of this gas could be commercially produced. But this will require a pipeline using some route to the lower 48 states. The volatile price of natural gas, which in the early years of the 21st century has ranged from $2 to $10 per thousand cubic feet, creates economic uncertainty for the viability of the project. The new Alaska pipeline will be built, but the cost is estimated to be $20 billion, and no gas is expected through the projected line until 2015 at the earliest.

More drilling. With the rapid depletion rates of gas wells, in order to get more domestic gas production, more drilling must be done, and done consistently. Emphasis should be placed on discovery of “giant” gas wells. These wells generally are deep (to 25,000 feet, and more) and very expensive.

Where are the prospects for more U.S. natural gas? The U.S. Geological Survey has estimated where future U.S. gas supplies will be found. The study suggests that the Rocky Mountains and offshore areas of the United States offer the best prospects. Because of environmental restrictions in the Rockies, more and more U.S. gas exploration is taking place offshore. But there are drilling bans in effect on both the East and West Coasts, and in parts of the Gulf of Mexico. So areas open for gas exploration and development are limited.

Natural gas in Canada. Natural gas production in Canada has a long history of continuous expansion. From a peak in 2001, production has declined 4.5%. At this writing, the decline continues. Exploration is gradually moving northward, as well as seaward into more hostile, remote, and expensive to develop terrains. The last frontiers for major gas finds in Canada appear to be offshore Newfoundland and Labrador, and northwest Canada in the Beaufort Sea-Mackenzie Delta Basin (BMB).

Gas discoveries have already been made here in the BMB, but without a pipeline, have not been producing. The gas from the BMB may never reach the United States or even southern Canada because the energy-intensive Athabasca oil sands are projected for substantially increased development. Processing the oil sands may use all the gas from the BMB. The gas will be transported by a 1,200-kilometer pipeline at a cost of $7.7 billion (Canadian dollars). This will stimulate more drilling in the BMB, where there is apparently considerably more gas to be discovered. But wells drilled in this difficult environment are costly. Onshore wells cost about $20 to 25 million (Canadian dollars). Some gas may be found off the coast of British Columbia, but environmental objections have already been raised there. Eventually, drilling is likely to proceed.

it is estimated that by 2020, some 25 percent of western Canada’s gas production may be used for Athabasca oil sand operations. Canada now exports 60 percent of its natural gas production to the United States. But there is already dissent in the Canadian Parliament against this volume of gas exports. As Canada’s population grows, and gas supplies are inevitably depleted, Canada no doubt will choose to keep warm first rather than send gas to the United States. Anticipating the time when its gas supplies are limited, Canada is considering sites for LNG landing facilities.

Gas — Expanding Use, Production, and Export.  Natural gas is now being discovered in many areas that were ignored in oil exploration. Gas wells are simple to complete because gas does not need pumps, it flows. Processing gas to a usable quality is also simpler than the refining processes for oil.

World Gas Reserves. Similar to oil, estimating proven natural gas reserves is not an exact science. Only rough estimates of the resource positions of various countries can be made at this time. The world’s largest single gas deposit probably already has been discovered. It is located partly in Qatar and partly in Iran, in a large anticlinal structure that stretches across the lower end of the Persian Gulf between the two countries and holds an estimated 10 to 12% of the world’s known gas reserves.

The Worldwide Future of Gas. The energy contained in world gas reserves is probably equal to, if not larger, than the energy in remaining oil reserves. The public has great faith in the ability of science and industry to solve the problem of the looming depletion of fossil fuels. The common view is that we can move to other energy sources with no great difficulty or adjustment to today’s lifestyle. Policy makers and government officials promote this optimistic view. Few people in public life are likely to admit we have a problem for which there is no easy solution.

In 2004, Alan Greenspan, then Chairman of the Federal Reserve Board of Governors, discussed rising oil costs. He said, “If history is any guide, oil will eventually be overtaken by less-costly alternatives well before conventional oil reserves run out.” The subsequent news headline read: “Greenspan: Alternative fuel will eventually handle demand.” Although assured by a high government official that there is no future energy problem, the statement was an example of unsupported optimism by someone with no background or experience in energy resources.

Factually, there are no less-costly alternatives to oil in sight. Chairman Greenspan did not clarify any alternatives. The reporter writing the article noted that the Chairman’s comment was, “consistent with Greenspan’s deeply held belief that market forces will eventually solve almost any kind of shortage ….” This is the standard view of most economists, and has been accepted uncritically by much of the public.

Until 1880, wood was the principal fuel used in the United States. From about 1880 to about 1945, coal became the largest single energy source. Since 1945, petroleum (oil and natural gas) has been the most important energy source and now constitutes about 65 percent of U.S. energy supply. Nuclear energy has met stiff resistance in the U.S. No new plants have been started here since 1976.

There is a very large amount of heavy oil worldwide. It is more difficult to produce and to refine than lighter oil, but with higher oil prices, more of this oil is becoming more economical to recover. In conventional oil fields, usually less than half the oil in place is being recovered, and in general, heavier oil fractions are left behind. With higher prices, better technology, and by applying new technologies, more may be produced than is now included in “conventional proven reserves.” This will help stretch out oil supplies, but the low-cost flush production of higher quality oil that the United States and other mature oil producing countries have enjoyed is gone. There is still a lot of oil available in various kinds of deposits both here and abroad, but at a price, and with a considerable time lag in development to put the needed equipment in place. The higher cost of recovering this oil will be passed on to the consumer.

In California, which passed its peak of production many years ago, heavy oil resources are the last to be developed because they are the most expensive. And lighter oils are mostly depleted. Northwest of Taft, in the southwestern San Joaquin Valley, the site of one of the very early oil fields developed in that state, there is a huge complex of steam generating stations, which pipe steam into the ground to reduce the viscosity of the oil so it can be pumped to the surface. Pumping each barrel of crude oil here requires about 320 gallons of water, in an area where water is scarce and coveted by agriculture as well (Miller, 2010). This is far less efficient and more costly than drilling a well and having the oil flow to the surface. It represents the final effort to get oil left behind by earlier flowing or pumping methods of oil production. Another huge oil field in North America, the Alaskan Kuparak River Field, lies northwest of Prudhoe Bay. The oil reservoir is at a depth of about 7,000 feet below the surface. But above that is another potential oil field, the West Sak. It is a shallower unit (about 3,500 feet deep), and contains an estimated 20 billion barrels of oil, almost twice as large as the Prudhoe Bay Field. But the oil is thick, and the reservoir rocks are a loose, sandy formation, which tends to clog up wells. This is an example of an oil deposit that is technically “recoverable.” However, the cost would be high and the net energy that would be obtained would be small after the energy inputs of the production processes are subtracted.

There are very large deposits of heavy oil in the world that were never developed as oil fields. This is oil that has lost its lighter fractions, or was initially composed of organic compounds which did not mature in the Earth as conventional oil does, and never were very fluid. The two most notable of these deposits are in eastern Alberta and adjacent western Saskatchewan, and in eastern Venezuela.

HEAVY OIL & TAR SANDS

Heavy oil in sands can be produced by the CSS method (cyclic steam stimulation). In this process used by Imperial Oil for the Cold Lake region of eastern Alberta and also used in similar deposits in western Saskatchewan, steam is injected into the formation for a time to warm the bitumen and make it flow. Then the well is pumped. This cycle can be repeated several times. Since oil flows much better horizontally than vertically, and because shale partings are present in oil sands, this is the most effective way of producing oil in situ (Deffeyes, 2005). Imperial Oil later announced that they had patented a process to improve oil recovery still more by adding a solvent to the steam being injected. These oil deposits are being developed and can marginally compete with conventional sources. There are at least 25 billion barrels, and perhaps several times that much in these deposits. How much can be recovered economically is not known, but the net energy recovery will be low.

There is a large heavy oil (really tar) deposit in eastern Siberia. Largely unknown because of its remote location and undeveloped status, the deposit is comparable in size to the Canadian Athabasca oil sands and appears to be the broad exposed edge of an ancient oil basin. Since Russia has far easier oil resources to develop, and the cost of exploiting the Siberian deposit would be prohibitive, it is unlikely to be developed in the immediate future.

One of the world’s largest deposits of heavy oil is in southeastern Venezuela, estimated to be about 1.2 trillion barrels. It spans about 54,000 square kms (20,800 square miles), but the main development covers about 13,600 square km (5,250 square miles). The deposit lies along the east-flowing Orinoco River whose course is controlled by the northern edge of the ancient rocks of the south flank of the East Venezuela oil basin, which has received a huge charge of oil from the richly organic Cretaceous La Luna Formation (Green, 2006). This exceedingly thick Orinoco Valley oil is found in an elongated deposit sometimes called the “cinturon de la brea” (belt of tar). To produce it, they drilled a pattern of five wells with the peripheral ones injecting steam to drive oil to the central producer. More recently they have been able to extract some oil by horizontal wells partly without steam (Campbell, 2005a). Production was expected to rise from 680,000 barrels a day to about one million barrels a day by 2010. However, in 2006, Venezuelan President Hugo Chavez canceled all oil development contracts with foreign companies working in the region and imposed new taxes several times higher than those in their original agreements. In January 2007, President Chavez announced he would simply nationalize all Orinoco operations (Wertheim, 2007). Given the record of nationalization in Venezuela and elsewhere, the end result will probably be a reduction in oil output as the investor-owned companies and their technical expertise depart.

Oil Sands. These deposits are ancient oil fields that have been uncovered by erosion or ones from which oil has migrated to the surface or near-surface, and has lost its lighter, more volatile elements. The largest of these deposits is in northern Alberta, the Athabasca oil sands a few miles north of Fort McMurray. The sands contain an estimated 1.7 to 2.0 trillion or more barrels of semi-solid hydrocarbons (Suncor, 1995). These deposits at Peace River, Athabasca, and the Cold Lake deposits (which do not exist at the surface) cover approximately 149,000 square km (57,514 square miles), an area about the size of Michigan. If regarded as a single oil field, it would be the world’s largest. It underlies about 23% of the Canadian Province of Alberta. The hub of operations is the city of Fort McMurray, once a small fur trading post, which now has a population of 70,000.

Contrary to enthusiastic investment letters, oil sand deposits are not like an underground lake of oil. The deposit consists of grains of sand each of which has a thin film of water and outside this water film there is another coating of oil. There are two main methods of recovering the oil. One is by open pit strip mining in which the oil sand is loaded into the world’s largest trucks. These are 400-ton capacity behemoths have tires that cost $45,000 each. The sand is trucked to a processing plant or to a conveyor system going to the plant. It takes two tons of oil sand to produce one barrel of oil. Using a hot water floatation process, the oil is stripped away from the sand. Initially, on recovery, the hydrocarbon is a black, viscous, tar-like material. In several steps, chiefly involving the addition of a light hydrocarbon solvent, the bitumen is upgraded to a straw-colored synthetic crude oil. Then it can be pumped and piped to a refinery where it is further upgraded to the various end products produced from ordinary crude oil.

However, up to 80% of oil sand deposits are too deeply buried to be recovered by surface strip mining, so an in situ process has been developed. Two wells are drilled vertically to the productive strata, and then deviated horizontally to exactly five meters vertically apart, and cased with perforated pipe. Steam is injected in one well which reduces the viscosity of the bitumen that is then pumped out using the other well. This is the SAGD (pronounced “SAG-D”) process — steam assisted gravity drainage recovery method. It can recover from 60 to 80 percent of the bitumen in the formation.

How much can be produced? The Alberta Energy and Utilities Board says that of the approximately 1.7 trillion barrels of crude bitumen estimated to be in place, only about 19% of it (315 billion barrels) can eventually be produced. Using today’s technology, only about 174 billion barrels can be recovered given current and economic forecast conditions. So, of the vast amounts of oil in the oil sands that are enthusiastically cited by writers of investment letters and other reports, much less than half will ever be produced.

What is the ultimate daily rate of production? The processes by which oil is recovered from oil sand do not lend themselves easily to large production rates. The weather is also a limiting factor. At times, it is 50 F below zero in winter. And because much of the land is boggy tundra, some operations, such as putting in new installations, must be done when the ground is frozen. To stop the newly mined moist sand from freezing to the bottoms of the trucks, truck beds are electrically heated. In summary, the conditions of production are vastly different and far more difficult than drilling a well in Texas or in the Persian Gulf.

There are two main limiting factors in oil sands production. First, it is an energy-intensive operation. Natural gas is now the chief energy source, although there is some effort to use some of the heavy elements of the oil sands themselves as fuel. It takes 1000 cubic feet of gas, using the SAGD process, to produce a barrel of bitumen. Each day, enough natural gas is consumed in the oil sands operation to heat 3.5 million Canadian homes. The seven trillion cubic feet of gas discovered in the Mackenzie Delta may be piped to the Athabasca oil sands operation, and all of it may be used just for that purpose, with none available for other needs in Canada. To produce two million barrels [of oil] per day would require approximately two billion cubic feet of natural gas, which is roughly equivalent to the amount of natural gas needed to heat every home in Canada for a day.

A second factor limiting production is that large quantities of water are needed for both processes, and water is limited in the resource area. The Athabasca River is the main source of water. But the river has insufficient flow to support the needs of all the planned oil sands operations.

A third possible limitation on oil sand production is the diluent needed to thin out the bitumen so it will flow at ambient temperature and move by pipeline. This light diluent oil is produced by conventional oil production in Canada, which is declining. So there is some doubt that domestic sources can supply all the diluent required for the projected expansion of the oil sands operations.

Net energy recovery. Generally, the comparisons made between the recoverable volumes of oil sand oil with the reserves of Saudi Arabia simply state that Alberta has 174 billion barrels and Saudi Arabia claims 264 billion barrels. But this is a misleading comparison because the net energy recovery of a barrel of oil from oil sand is considerably lower than from a barrel of oil from a Saudi oil well. Besides the energy cost of the natural gas it takes to recover a barrel of oil sand oil, there are other energy costs incurred in the surface mining, stripping off the overburden, loading and hauling the oil sand, and the ultimate disposal of the leftover sand. Saudi Arabian oil incurs none of these costs.

I have discussed the issue of calculating net energy recovery with various people in the oil sand country, and even suggested that the cost of supplying and heating the Fort McMurray population should be included in the energy cost. In northern Alberta, winter is severe, arrives early, and stays a long time. Conducting mining and plant operations in sub-zero temperatures, and keeping all the equipment working is difficult. The quartz sand in these deposits is harder than steel and it inevitably gets into the machinery and causes maintenance difficulties. Including the narrower and more immediate energy costs, the open pit mining and floatation process reportedly yields an eight to one ratio of energy recovered to energy invested. The SAGD process yields a four to one energy recovery ratio.

Environmental effects of oil sand developments. The impacts of oil sands development in Alberta are considerable. Aside from carbon dioxide emissions discussed in Chapter 20, there are several other significant environmental impacts (Clarke, 2009; Nikiforuk, 2008). Waste water and large volumes of sand resulting from the extraction of oil are dumped into tailings ponds, which now cover more than 50 square kilometers (19.3 square miles).

Taking water from the Athabasca River, especially in winter when the flow is substantially reduced, has an adverse effect on the fish population. It also has a negative impact on the Peace-Athabasca Delta in Lake Athabasca, which is the largest boreal delta in the world, and one of the most important waterfowl nesting areas in North America. The areas where strip mining is conducted leaves a moonscape land surface, of which only about 17 percent has been reclaimed to date.

Huge piles of discarded sand mar the landscape along with great quantities of contaminated waste water. The original pristine landscape of bog, marsh, and boreal forest cannot be restored. In situ SAGD recovery process (which will gradually replace surface mining) has considerably less impact than strip mining. But there is environmental damage from roads and drill sites.

Upgrading oil obtained by either process also causes a substantial increase in carbon dioxide emissions to the degree that the pledge Canada signed in the Kyoto Protocol to reduce carbon emissions has not been met. Instead, emissions have increased. In 2011, Canada formally withdrew from the Kyoto Protocol.

A last refuge for the oil companies. Since most of North America is thoroughly explored and drilled, there are few new places left for major oil companies to operate. Canada has a stable government, a pleasant change from what companies experience in many other countries. There is also little or no exploration cost or risk to operating in the oil sands. We know where they are, and except for drilling a few holes to determine the depth and thickness of productive strata, there is little drilling to be done except for putting the pipes in place for the SAGD production process. The long lead times required to negotiate leases with unstable and corrupt governments, the lengthy and costly exploration operations, the billions it now costs to build and put drilling platforms offshore in as much as 10,000 feet of water where they are subject to hurricanes and the possibilities of terrorist attacks, are all avoided by operating in the Alberta oil sands. It is a last refuge for the oil companies, not only for North American companies, but also for those of other countries like Shell from the Netherlands, and Total of France.

The recovery of oil from oil sands is not a geological matter but a manufacturing process. Costs are quite predictable. There is also a greater stability and security than in many other oil operations in distant lands where pipelines are blown up and workers on oil rigs are kidnapped. Oil field workers have been killed by local insurgent groups in places where oil companies operate in regions of civil war, as in Nigeria and Colombia.

There are very few oil sand deposits in the United States. Some exist in Utah and elsewhere, but these are small, and the hydrocarbon is dense and, therefore, takes even more processing than Canadian oil sand. In the past, fuel production from unconventional sources usually depended on large government subsidies. The Canadian oil sand industry is an exception. It succeeded, where others have failed.

As a result, several major oil companies and a number of other companies are vigorously pursuing oil sand resources. Several oil sands plants are in operation and more are planned. The largest are the Syncrude plant (a consortium of companies, including the Alberta government), and the Suncor operation (an independent company based in Calgary). Canadian Natural Resources is another major player in oil sands development. The production activity in the Alberta oil sands is currently the largest single industrial development in the world.

What can oil sands do for future world oil supply? There are very optimistic projections as to what oil sands can do for the world’s oil supply. But given current world oil consumption of 84 million barrels a day, four million barrels of oil a day from oil sands by 2030 can only meet a small fraction of world oil demand. Furthermore, by 2030, when four million barrels a day of production could be reached, Canada’s conventional oil resources will be largely depleted and Canada itself will need increasing amounts of oil from the oil sands. In 2001, daily oil production from oil sands exceeded the production from conventional oil wells in Canada, and it has done so ever since.

Minimum Canadian demand on the oil sand oil by 2030 could be two million barrels a day. Canada rightly will take care of its own needs first, leaving perhaps two million barrels a day to be divided among all the other consumer nations waiting in line, including the United States. The United States, with its current consumption of 19 million barrels of oil a day, will not see its oil supply problem solved by Canadian oil sand oil.

OIL SHALE (KEROGEN)

For more than 90 years, numerous attempts have been made to develop a shale oil industry in the U.S. Shortly after World War II, the U.S. Bureau of Mines built an oil shale demonstration plant just north of Rifle, Colorado. It was closed. Other projects include Occidental Petroleum’s project near De Beque, Colorado, which involved tunneling into the shale, excavating a room, and then blasting down shale from the ceiling. The room was then sealed off, and the fragmented shale set afire. The oil released from the shale by the fire was to be drained out through a trough previously cut in the floor. The project proved unsuccessful and was abandoned. Equity Oil and the U.S. Department of Energy did a joint project in which 1,000º F steam was injected into the shale through numerous wells under pressure of 1,500 pounds per square inch. Water, oil and gas were to be recovered from the injected zone through production wells. This was unsuccessful. Unocal (now part of Chevron) has been working on oil shale technology since the 1920s. One small experimental plant was built many years ago in upper Parachute Creek Canyon, in western Colorado, then abandoned.

Oil shale comes in various degrees of richness. Some deposits can produce up to 100 gallons of oil per ton like the famous Mahogany Ledge of the Piceance Basin. A good average grade that could be economical is about 30 gallons per ton. The differences in grades can be substantial in vertical distances in the strata of only a few feet, which is one of the problems in economically recovering the oil. A consistently good grade thickness of shale is required for efficient mining. The main thing that the kerogen in oil shale needs to become oil is heat. To speed up Nature’s process, the conventional approach has been to first mine the rock and then load it on trucks to be hauled to a plant where it is ground into fine particles and heated to a temperature of about 900º F. This produces a tarry mass to which hydrogen must be added to make it flow readily. Currently, the chief source of hydrogen is natural gas, which unfortunately brings us back to petroleum, which we are trying to replace.

Oil shale, when heated, tends to pop like popcorn, so the resulting volume, even after the organic material is removed, is larger than the volume of rock initially mined. This creates a huge waste disposal problem. The waste material has to be hauled somewhere. The ideal situation would be to have a mountain of oil shale near a large canyon, where the oil shale could be brought down the mountain largely by gravity, run through the processing plant, and the waste material dumped into the adjacent canyon. Because there are various toxic elements associated with the oil shale waste, the pile of oil shale waste would have to be stabilized and sealed off from groundwater or surface water to avoid contamination.

How much net energy? Developing oil shale deposits by other than in situ methods, involves huge materials handling and disposal problems. Also, when the energy costs of mining, transporting, refining (including the addition of hydrogen), and waste disposal are all added up, the net amount of energy recovered from oil shale is relatively small. It does not begin to compare with the net energy reward now obtained through conventional oil well drilling and production operations. Some studies suggest that the final figure for the net energy in oil recovered from oil shale is negative. At best, it is not large, and surface mining for oil shale may disturb up to five times as much land as that caused by coal mining for the same net amount of energy. It also would be far more destructive to the landscape than oil wells producing the same net amount of energy.

Another problem with the Utah and Colorado oil shale deposits is that the processing and the auxiliary support facilities need large amounts of water. The richest oil shale deposits are located in the headwaters of the Colorado River. This river now barely reaches the Gulf of Lower California. Present demand for water already exceeds what the river can meet. Water supply would be a serious problem for any large development of oil shale because it would take at least two barrels of water to produce one barrel of oil. The states downstream from the oil shale deposits have already protested the withdrawal of Colorado River water for shale oil production. The development would immediately pit Colorado and Utah shale oil projects against California, Nevada, and especially Arizona. These

So far, very little oil, except on a pilot plant scale, has been produced. The major oil companies have tried to develop a viable, economic, commercial operation, but none has been successful thus far.

An attempt to economically recover an oil-like substance from oil shale reached a rather astounding climax and conclusion in the 1980s and early 90s. With the oil crises of 1973 and 1979 fresh in mind, both Exxon and Unocal launched huge projects in the area of Parachute Creek just north of the Colorado River. In 1980, Exxon began construction of the Colony II project designed to produce 47,000 barrels of oil a day, and announced that production of 15 million barrels a day of synthetic fuels by 2010 would not be “beyond achievement” (Business Week, 1980). To support this project, it was even suggested to divert part of the Missouri River, some 700 miles away.

To get the project started, Exxon announced it would spend $5 billion on various preliminary projects, and build a town for 25,000 workers. To house this small city of employees, Exxon built a model community across the Colorado River on a broad gently sloping upland called Battlement Mesa. It had everything including a recreation center. But about the time that the Battlement Mesa community was completed, Exxon concluded that the oil shale project was uneconomic. On May 2, 1982, dubbed “Black Sunday” in the town of Parachute, Exxon announced it was abandoning the project (Gulliford, 1989; Symonds, 1990).

Backed by a government production subsidy, Unocal persisted and built a large plant just north of the town of Parachute (previously called Grand Valley). Construction was completed in August of 1983, at a cost of $654 million. In its 1987 annual report, Unocal said: “The ultimate goal is to achieve steady production at design capacity – about 10,000 barrels a day.” Peak production of 7,000 barrels a day was achieved in October 1989.

During its experimental phase, the plant operated with the aid of a $400 million federal subsidy. By 1991, Unocal had used $114 million of this subsidy, and received $42.23 a barrel for the oil produced at Parachute Creek, with the U.S. government paying $23.46 of that amount. Unocal’s production costs were about $57 a barrel.

On June 1, 1991, this $654 million plant was permanently closed, and the project was abandoned. Parts of the plant have been sold or moved to other Unocal operations. Much of the plant, remains, however, as a monument to the failed efforts to develop a viable shale oil operation.

Oil shale development has been “just around the corner” for over fifty years, and may continue to be in that position for some time to come, perhaps indefinitely.

Shale oil can, at most, supply only a small portion of current world oil demand. And shale oil, by its composition, is better adapted for use as a raw material for petrochemical plants than for the production of gasoline. As a petrochemical feedstock, shale oil may play a modest role in the future economy.

Now Shell Oil Company is once again (2012) attempting to produce oil from oil shale in commercial amounts. It built an experimental operation in the Piceance Basin of Colorado in which a series of holes are drilled in a block of oil shale, and electrodes are inserted to heat the rock. To prevent groundwater from migrating through the rock and cooling it, a perimeter of frozen ground was created around this block of shale. Shell says it will take several years to heat the shale to the point that the kerogen is converted to oil. Then it is to be produced from wells drilled into the shale.

However, shale is not very permeable. This in situ operation eliminates several problems of conventional shale oil production. The handling of great volumes of rock material is eliminated. There are no mining, transportation or grinding costs. There is no waste disposal or stabilization problem, and the demand for water is modest. Shell is famous for having good engineers, and they claim they could generate a positive energy recovery ratio of 3.7/1. Since rocks are good insulators, it will take a very large amount of electricity to heat the rock and convert the kerogen to oil. How many electric power plants will it take to provide the power for a significant production of oil by this process? And what are the fuel requirements for the power plants? Even if the Shell project proves successful, it is difficult to see how it can make a significant contribution to world oil supplies, given the years it takes to heat a block of oil shale, and the power plant requirements and other infrastructure that are required.

Skeptics including Randy Udall and Steve Andrews (2005) doubt the success of this project. These long-time observers of oil shale resources make some interesting observations about the Shell project: The plan is audacious. Shell proposes to heat a 1000-foot-thick section of shale to 700 degrees, then keep it hot for three years… Imagine a 100 acre production plot. Inside that area, the company would drill as many as 1,000 wells. Next, long electric heaters would be inserted in preparation for a multi-year bake. It is a high stakes gamble, but if it works, a 6-mile by 6-mile area could, over the coming century, produce 20 billion barrels [of oil], roughly equal to remaining reserves in the lower 48 states.

Although Shell’s methods avoid the need to mine shale, it requires a mind-boggling amount of electricity. To produce 100,000 barrels per day, the company would need to construct the largest power plant in Colorado history. Costing about $3 billion, it would consume 5 million tons of coal each year, producing 10 million tons of greenhouse gases. (The Company’s annual electric bill would be about $500 million…. A million barrels a day [1/20th of U.S. current daily consumption] would require 10 new power plants and five new coal mines…. Using coal-fired electricity to wring oil out of rocks is like feeding steak to the dog and eating his Alpo. [Laherrere has estimated that at the current cost of electricity in the region, the cost in electricity of each barrel of oil produced could be as high as $800.]

In 2008, Raytheon (inventor of the microwave oven) launched a project to recover oil by underground heating of the shale with microwaves beamed from transmitters lowered into the shale. The process, like Shell’s, would use large amounts of electricity but also involves multiple steps of heat conversion with some energy lost during each stage, a method more complex than Shell’s approach. But unlike Shell’s project with electrodes, microwaves can generate heat faster than convection heat (Shell’s process) and reduce the heating time to a month or two, rather than years. As both the Shell project and the Raytheon project have yet to be completed, results are not now known. ExxonMobil has also resumed interest in oil shale.

A study by the Rand Corporation for the U.S. Department of Energy found that producing just 100,000 barrels of oil per day (bpd) using the currently most advanced in situ process would require 1.2 billion watts of dedicated electricity for heating. This would require a power plant equal in size to the largest coal-fired plant now operating in Colorado. It would cost $3 billion to build and would burn five million tons of coal annually, producing 10 million tons of greenhouse gases. Putting all this in perspective, even the most enthusiastic forecast of 500,000 bpd oil from oil shale production, when viewed against the current U.S. oil use of approximately 20 million barrels a day, or the world use of 84 million barrels a day, shale oil would be only the proverbial “drop in the bucket.”

Oil shale/oil sands — again, the distinction These are sometimes confused by writers. For the sake of clarity, the differences are worth repeating and very obvious when oil sand and oil shale are seen together. Oil shale contains no oil as such, but has an intermediate form of hydrocarbon between plants and oil, called kerogen. Oil shale usually contains some carbonates so it is technically a marl. It is a hard, dense rock, which on fresh exposure is black but weathers to a tan or grey color. Oil sands are black, do not weather to another color, and contain true oil but it is very heavy (thick). It occurs in sand which is not solid rock, as is the case of oil shale, but is friable and can be mined with a power shovel.

Nationalization of oil and mineral companies

The nationalization of oil companies abroad, and the continued movement of U.S. oil companies overseas because domestic exploration prospects are diminishing, have made U.S. companies increasingly hostage to foreign governments. There, overseas investor-owned oil companies rarely own the oil, they simply have lease arrangements for developing those resources and may get a percentage of the production. Foreign governments own the oil and have control. In turn, the American oil-consuming public is hostage to foreign governments. The balance of economic power has shifted abroad in the past four decades, and oil has been a chief factor.

Chile nationalized the American copper companies, Kennecott and Anaconda. Zambia and Zaire took over all multinational copper operations there. “American” was rubbed out of the name Arabian American Oil Company in the desert sands of Saudi Arabia. All foreign interests in Iran and Iraq were taken over. Kuwait nationalized Gulf Oil’s interest there. Venezuela nationalized Creole Petroleum Corporation, formerly a division of ExxonMobil Corporation, the company that had developed the great oil deposits of the Lake Maracaibo Basin. Peru took over International Petroleum Company, also at the time an Exxon affiliate. This was done with no compensation whatsoever. And was done not long after Exxon had invested large sums in rebuilding the oil camp and related facilities, including a modern hospital free to all employees and their families, and had built the safest water supply system in the entire country, and even a fine large church.

After nationalizing their minerals, many countries discovered they did not have the technical expertise to run the nationalized operations. Also, in some cases, so much money was drained from operations into political and social pockets and causes, that there was not enough capital left to maintain and develop the resource facilities. Therefore, many countries invited foreign companies to come back, under various financial arrangements. In a 2-page ad in 1995, Zambia announced it was privatizing the government monopoly of copper mining, and asked for foreign capital to come in and help. On January 1, 1976, Venezuela took over all foreign oil interests. But in 1995, Venezuela needed help to run its oil operations, and made arrangements to auction off some exploration rights in various prospective areas to foreign oil companies. It should be noted that Venezuela was not risking any money. If the leases are unproductive, the companies lose all their lease and exploration costs. However, the terms included taxes that took from 71 percent to 88 percent of the profits from any successful ventures.

With the breakup of the Soviet Union, a new political order caused by oil appeared in that region. Large oil deposits exist in several countries that split away from the USSR. The extensive Caspian Sea area oil is now owned by Turkmenistan, Azerbaijan, Iran, Russia, and Kazakhstan. Some oil, an estimated 4.1 billion barrels, also is located in nearby Ukraine. Kazakhstan, five times larger than France in area, and larger than all of the other former Soviet Republics combined, excluding Russia itself, is reported to have as much as three to 10 times as much oil as Alaska’s Prudhoe Bay Field. [my comment: but after the U.S. imposed sanctions on Russia in 2013, Exxon had to leave Siberia and Russia was depending on their help to drill for deep sea arctic oil, because they have little expertise themselves.]

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