GEOL 115: The Earth’s Energy Resources

Uranium deposits can be viewed as products of the rock cycle. Uranium occurs in small amounts in the Earth’s crust.  This uranium typically occurs as the mineral uraninite (UO₂) or is present in other minerals as a trace component.  The mineral zircon (ZrSiO₄), for example, may contain uranium in concentrations in excess of 1,000 parts per million. If the crust is cycled and partially remelted, the uranium tends to be concentrated in the magma. When the magma cools the uranium will again occur as uraninite in the igneous rock. If the system contains sufficient uranium and conditions are right a uranium deposit might form in the igneous rock. The Rossing deposit of Namibia is an example of such a deposit in igneous rock. Although the Rossing deposit contains low grade uranium ore, uranium is the primary product and Rossing accounts for the bulk of Namibia’s uranium production. In modern environments uraninite will dissolve as the uranium oxidizes. Dissolved uranium from a uranium deposit or simply from rocks that contain anomalous amounts of uranium may be carried in solution in surface waters. These waters become reduced as they percolate into the subsurface. When the uranium is reduced it will precipitate out of solution as uraninite. If sufficient fluid carrying sufficient uranium flows through a reducing “trap” a sandstone uranium deposit will form. These can be quite variable in size and grade but are never among the largest deposits. It doesn’t matter whether you look at them in terms of the amount of ore, the grade of the ore, or the amount of uranium produced, sandstone uranium deposits generally sit in the middle. Crow Butte is a sandstone uranium deposit in located near Crawford, Nebraska. It is large for a sandstone deposit and should continue producing uranium for several years.   Sandstone deposits are widespread and contribute to the bulk of uranium production from Kazakhstan, Niger, and Gabon. The highest grade (richest) deposits shown on these diagrams are unconformity-related deposits. These deposits occur near unconformities at the base of some ancient sedimentary basins. The mineralization occurs in rocks above and below the unconformity that marks the basal contact of the sedimentary basin. The mineralization must be younger than the rocks immediately above the unconformity. Unconformity-related deposits are the primary reason why Canada is one of the world’s leaders in uranium production (something that is worth remembering). Their formation is still a bit of a mystery but they must involve a chemical trap where U⁶⁺ is reduced to U⁴⁺ and precipitated as uraninite. In Canada they are concentrated at the base of the Athabasca Basin in Saskatchewan. Similar deposits occur in Australia but they carry much lower uranium ore grades. Australia is another of the world’s top two uranium producers. Although Australia has some large unconformity-related deposits, more than 70% of their uranium production is derived from the giant Olympic Dam Iron oxide-Copper-Gold-Uranium (IOCG-U) deposit. Olympic Dam is one of the largest mining operations in the world; it is the largest uranium mine in the world and uranium is produced only as a byproduct of the copper and gold that they are mining. Among the lower grade uranium deposits are the quartz-pebble conglomerates or the Witwaterand-type deposits. These are quite different from the other deposits discussed above. These deposits comprise ancient (2.2 billion years old) stream gravels. If you check the images from the lecture you will see examples of rounded grains of uraninite and pyrite. These minerals are typically oxidized rapidly and dissolved in the modern world. Their persistance in these stream gravels indicates that the Earth’s atmosphere contain very little oxygen 2.2 billion years ago. Another important feature of quartz-pebble conglomerates or Witwatersrand-type deposits is their low grade. These deposits are only economic when the price of uranium is high or if the uranium can be recovered as a byproduct. Although some of these deposits contain uranium only(Blind River, Ontario) , many contain significant amounts of gold (Witwatersrand, S.A.; Jacobina Brazil). These latter deposits are mined for the gold and the uranium is recovered as a bonus (the Jacobina deposits contained no significant uranium, only gold). As a result they can afford to work with very low grades of uranium ore.

We can’t get into the details of nuclear physics in this class but we can discuss some important points and view some interesting videos!

All matter consists of atoms.  A nuclide is a species of atom.  The chart of the nuclides is an graphical presentation of all the different species of atoms with neutron number plotted along the abscissa and proton number plotted along the ordinate.  You can click on any of the nuclides in the chart of the nuclides to learn more about it.  Nuclides that reside in the same row are called isotopes; they are nuclides that have the same atomic number but differing neutron numbers.  The nuclides that share columns are called isotones; they have the same neutron number but differing atomic numbers.  The nuclides that fall along diagonal lines such that they have the same atomic mass numbers (proton number+neutron number) are called isobars.

Remember that the actual atomic mass of a nuclide is almost never equal to the mass of the protons and neutrons (the nucleons) contained in the nucleus. Some of the mass in those nucleons is converted to the binding energy that holds the nucleus together.

Light nuclides can be fused together to make heavier nuclides with the release of energy and very heavy nuclides can be split apart to make lighter nuclides (also with a release of energy).

We can construct a fission reactor to generate power.  A fission reactor would take heavy nuclides and split them to produce lighter nuclides.

The fuel for a fission reactor must meet certain criteria

1. It must be capable of being split into lighter nuclides yielding energy. It will therefore be a nuclide that is heavier than ⁵⁶Fe (the nuclide that resides at the top of the curve of binding energy)
2. It must be able to capture neutrons. We can help things out here by introducing a moderator. A moderator is a substance that will adjust the energy of neutrons so that the nuclides in the fuels can capture them more easily.
3. It must yield at least two neutrons of the appropriate energy upon fission. This is will allow for the propagation of a self-sustaining chain reaction.
4. It must be sufficiently abundant that we can find it and work with it. We will see that there are some potential fuels that do not occur naturally but which can be made in nuclear reactors.

One of the best isotopes for fuel is ²³⁵U, one of the naturally occurring isotopes of uranium.

Nuclear power has had a rather checkered history in the United States and worldwide.  There was considerable enthusiasm for nuclear power in the post WWII years: it was viewed as part of the futuristic society in which we would live.  In 1979, however, an incident at a nuclear power plant in Pennsylvania (Three Mile Island) coincided with a popular film about a potential accident at a nuclear power plant, crusading reporters and sinister power plant executives. Enthusiasm for nuclear power flagged in the US.  In 1980 Disney repackaged some of their earlier material from “Your Friend the Atom,” added some new material, and released it as a public affairs film on nuclear power. That video is available below and although rather dated is still quite informative (I’m a sucker for the mousetrap demonstration).

While we are looking at videos this little number is rather entertaining and actually pretty good at explaining the science.  You have to take it as a product of its time; its rather sexist.

Anyway back to our story about nuclear power.  Little happened in terms of nuclear power plant construction in the US in the wake of the Three Mile Island incident (no construction permits were issued between 1979 and 2008). The permitting process was fraught with sufficient uncertainty that utilities were not interested in building reactors. Nuclear power plant construction continued in a number of other countries; France currently generates nearly 80% of its electricity from nuclear power.  The French approach to nuclear power and nuclear waster storage has much to offer, if the US intends to make nuclear power a significant portion of its energy budget.

On April 25, 1986 technicians at the Chernobyl power plant in the Ukraine began some rather odd experiments. The result of these experiments was that in the early morning hours of April 26, 1986 one of the reactors at the Chernobyl plant failed catastrophically. Although the Chernobyl reactor design was an unusual one (and an unusually dangerous one) the accident led to increased resistance to nuclear power elsewhere in the world.  I described the Chernobyl accident in a series of posts that you can access here.  The Chernobyl accident is a good example of an inherently unsafe reactor that was operated in an unsafe manner.  We can do better.

The point of this lecture was to discuss a way to convert solid fuels (or stranded gas) into fuels that society values more highly. The fuel that society values most is gasoline. We can convert reduced carbon compounds into gasoline by using several sets of reactions

For our purposes we will consider the partial oxidation process and the water gas shift reaction.
The partial oxidation reaction is typically presented as
CH₄+1/2O₂ = CO + 2H₂
Here a fuel is burned under controlled conditions. Because a limited amount of oxygen is allowed into the system, some of the other material will be converted to carbon monoxide and hydrogen. If coal is used as the carbon source this process is referred to as “coal gasification”

The reaction of organic material with steam will also produce carbon monoxide and hydrogen following the reaction
C + H₂O = CO + H₂

We can optimize hydrogen production by using what is called the water-gas shift reaction
CO + H₂O = H₂ + CO₂
Thus by adding water to the system we can generate additional amounts of hydrogen (if that is our goal).

The mixture of carbon monoxide and hydrogen is referred to as “synthesis gas.”

You should understand what the above reactions do.

But back to producing liquid fuels. If we are going to produce liquid fuels, we need to convert the synthesis gas (CO and H₂) to liquid hydrocarbons. Fortunately carbon monoxide and hydrogen are not happy when placed together and they do want to react. The problem is to get them to make the right thing. This problem is addressed by using catalysts. Catalysts are substances that help reactions to happen. They are neither consumed nor produced in reactions so in theory can be re-used. In the presence of the proper catalyst the Fischer-Tropsch synthesis will proceed from left to right and release heat
(2n+1)H₂ + nCO = C_nH_2n+2+ nH₂O
In this reaction the species in synthesis gas (the mixture of hydrogen (H₂) and carbon monoxide (CO)) are on the left whereas the hydrocarbons ( C_nH_2n+2) and water are on the right. By using these processes we can convert almost any carbon-based substance into gasoline. Thus we can convert stranded natural gas to liquids, coal to liquids, and biomass to liquids.

Do we have sufficient reserves of coal to support the conversion of coal to liquid fuels? Although the US has sufficient coal to support more than 100 years of use at current rates, there is no evidence (yet) that we have sufficient supplies for 250 years or more. If we began to consume coal at rates to support our current transportation needs we would begin to draw down our coal reserves much more rapidly (in decades rather than centuries).

Because coal is a solid we can’t extract it from the ground through a pipe, we have to go get it. Coal mines are like very large construction projects; large amounts of material must be moved, massive equipment is used, and the “footprint” of the operation is considerable. More so than conventional petroleum operations, much of the emphasis in mining operations is placed on moving material (coal, overburden rock and soil) efficiently.

The average citizen typically laments that mining companies don’t refill the mine when operations are completed. Consider the Berkeley Pit in Butte, Montana. This image of Berkeley Pit was taken from the International Space Station. Nobody’s gonna fill that hole up: it would be too expensive and the company or companies that made the pit are no longer generating any revenue from the mine to use on such reclamation. We’ll return to this thought later in the discussion on surface mining.

Underground Mining Methods
Underground mining methods generally leave a smaller surface footprint.

Longwall mining is reasonably safe and yields high coal recovery. The coal is transported out of the mine largely on conveyors eliminating the need for vehicles to transport the coal (in those small spaces only small vehicles could be used). This video from a University of Wollongong site shows a shearer removing coal from a face while the supports move toward the face from behind the miners. The back (roof or ceiling) may then collapse behind the supports as they move forward. You can see images of the equipment in the lecture notes. The disadvantage to longwall mining is that as the overlying rock collapses, the collapse may reach and disrupt the surface. Thus if there are roads, buildings (a built environment) or an important aquifer over the a thick coal seam, longwall mining may not be the preferred method.

Room and pillar mining allows one to retrieve the coal without any subsidence or surface collapse. It is a straightforward process in concept; you leave pillars of coal to support the overlying rocks.

The main problem with the room and pillar technique is that the pillars may be very large (about 40% of the coal in the area mined). Reducing pillar size or removing pillars (called retreat mining when the miners are working back toward the “exit”) yields greater financial return but at the cost of greater risk to the miners (from unstable ground conditions within the mine). Its worth noting that every action that you take (using a seat belt, studying for an exam) involves some consideration of risks and rewards. This consideration is particularly stark when considering retreat mining: probably the most hazardous mining activity in the United States. On July 31, 2007 Assistant Secretary of Labor Richard Strickler opened a scientific conference on ground control (the science of preventing big rocks from falling on you in a mine) with a statement that included the following words

Roof and rib (the wall of the mine RMK) fatalities and injuries appear to be disproportionately high during retreat mining. For example, since 2000, fourteen of 49 fatalities (29 percent) occurred during room-and-pillar retreat mining operations. This percentage is high when you consider that mines which use this mining method employ only around 19 percent of underground coal miners and account for about 18 percent of the underground coal production. In addition, the actual retreat process accounts for only a portion of the production.

This doesn’t mean that companies that engage in retreat mining are run by bad people. It does mean that this activity is one that needs to be undertaken carefully and with appropriate recognition of the risks involved.

Surface Mining Methods
Surface mining has many advantages over underground mining. Many of the the ground control, dust control, and ventilation problems that are faced underground disappear. It is somewhat unfortunate that the most environmentally benign and safest surface mining technique has gotten a bad rap.

This brings us to strip mining.

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Strip mining is a technique by which you mine a near-horizontal coal seam in a series of strips. The example above is from Beulah North Dakota. 1)A trench is dug from one end of the property to the other from the surface to the top of the coal seam. The overburden removed is placed along side the trench. 2)As the trench is dug equipment follows removing the coal from bottom of the trench. 3)Upon completion of the initial strip, a second trench is dug adjacent to the first exposing more coal. The overburden (spoils) is placed in the first trench. 4)The coal is removed from the bottom of the new trench. 5)Steps 3 and 4 repeat until the coal is completely mined. The equipment used for overburden removal quite large and may be a walking dragline (these guys can hook you up if you’re in the market). The equipment used to remove the coal is a bit smaller (although still massive by our standards). The gigantic bucket-wheel excavator that we looked at in class was the Tenova TAKRAF RB293 (one of the largest vehicles in human history).

One great advantage to true strip mining is that the company doing the mining can regrade the spoils piles while they are earning money from the mine. Thus the environmental impact is minimized: you fill the hole as part of the mining process and have revenue from the mining operation to use to perform the reclamation. You can see some reclaimed areas immediately north of the active mining area in the map above.

Strip mining got a bad rap for two reasons. 1)Early strip mines weren’t reclaimed.

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This example is from Illinois. You’ll get a better picture if you move the map around and enlage portions of it. You will easily see which areas have been disturbed by mining. The spoils piles are unsightly. The spoils prevent the surface from draining properly after rainfall (this is referred to as a deranged drainage). Because the spoils contained significant amounts of pyrite the piles are also an environmental hazard: the pyrite oxidizes for form acidic waters that may contain elevated concentrations of various metals.

2)The term strip mine has been applied to all surface mines many of which are not as easy to reclaim as strip mines. Examples include contour mines and mountain top removal mines. In the former method a portion of a slope is excavated to make a flat surface on which equipment can work. An exposure of a coal seam is then followed in an area of irregular topography. Rock and soil above the coal seam is removed and placed downslope. The coal is mined out until the stripping ratio (the mass rock and soil that has to be moved divided by the mass of coal recovered) becomes excessive. In the latter method large amounts of rock are graded off the top of a topographic high, deposited in a low area and a coal seam is removed. The effects of both contour and mountaintop removal are visually jarring. Both methods are hard to reclaim compared to strip mining. Much of the value of the land in areas of high relief resides in its irregular topography. It is often impossible to regrade the land to its original contours and relatively little reclamation can take place until much of the mining has been completed (at this point the operation generates no more revenue). On the other hand mountaintop removal proponents would argue that the newly leveled land is suitable for commercial uses and will spur economic development. An example shown below is the Twisted Gun Golf Club in West Virginia.

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The utility of any flat land for commercial development will of course depend on its proximity to population as well as energy and transportation infrastructure. Flat land in areas where there is demand for commercial or industrial sites is quite valuable; flat land in areas where such demand does not exist is just flat land.

In general strip mining, which typically allows much of the heavy work in reclamation to take place at the same time as mining, is a superior operation. Greater recovery of the resource is possible. Reclamation occurs when the mining operation is generating a positive cash flow. Finally, because the lease holders will want to continue operations they will be more willing to heed the suggestions of a environmental regulator that represents the citizens.

When we were dealing with oil, heavy oil, or oil shale we were discussing fossil fuels that are derived largely from lipid-rich organisms that lived in water. Coal on the other hand is derived almost exclusively from ancient land plants. Thus oil(and much gas), heavy oil, and oil shale, form when carbon dioxide is photosynthetically reduced by aquatic plants that are preserved as kerogen. Coal forms when carbon dioxide is reduced photosynthetically by land plants.

Organic matter is converted to coal as thick accumulations of land plants are buried to progressively greater depths and exposed to greater thermal stress. The increased temperature causes loss of volatiles such as carbon dioxide and light hydrocarbons (water will also be lost during this process). As volatiles and water are lost, carbon content increases (slightly). Although carbon content doesn’t increase much, the H:C and O:C ratios of the organic matter (on an atomic basis) decrease dramatically.  This process is also called an increase in coal rank. It is important to remember that it is the increasing temperature that drives the coalification process rather than increasing pressure.

Whereas minerals are the building blocks of rocks, macerals are the building blocks of coal. Macerals are plant remains that have distinctive physical and chemical properties. These properties allow the macerals to be identified and correlated with their plant precursors. John Crelling of Southern Illinois University has an excellent website devoted to coal macerals. One of the macerals that he has pictured is called vitrinite (The bar scale with the 25µ label is 25 microns long; 40 of those bar scales end to end would make a millimeter). Vitrinite comprises the woody material of a plant; fossil cell walls can be recognized this maceral. Other macerals comprise spores, resins, or even old charcoal.

In general, the heat content of coal will increase as its rank increases. All else being equal, therefore, coal with a higher rank should be more valuable than coal with a lower rank. Of course all else will not be equal.

The variables that control the value of coal are rank, coal seam thickness, ash content, the depth and dip of the seam, and the sulfur content of the coal.

Seam thickness, depth and dip all control the mining method and therefore the cost of recovering the coal. Obviously thick coal seams are more attractive than thin coal seams. The issues of depth and dip (combined with surface topography) control whether the coal can be recovered using surface mining methods (safer, cheaper) or will require underground techniques. We’ll consider these in greater detail later.

We can get some indication of the significance of thickness, seam depth and dip by looking at the table of coal production.  If you look at the very bottom of that table you will note that there are many more mines in the eastern US.  This is because the complex geology in many eastern coalfields (irregular topography and deep coal seams with steep dips) lends itself to numerous mines.   Yet the relatively few mines in the western US produce significantly more coal.  The coal ranks in the Appalachians and Eastern Interior are higher than those in the western states yet the western states produce significantly more coal. Western state produce more coal in part because the geology permits mining on a very large scale.

Ash content and sulfur content are also important. Ash is the term given to the inorganic minerals present in coal. Depending on the amount and type of ash in coal, deposits may form on boiler pipes of heat exchangers. Other ash may be collected from the flue gas (fly ash) or at the bottom of the furnace (bottom ash). This fly ash is typically collected and stored as a sludge. Storage of the sludge can be problematic.

Lets consider the depositional environments of coal. A reasonable modern analog for the environments that formed coal in the past is the Orinoco Delta of Venezuela. The Orinoco delta is the area circled on the map shown here where the Orinoco River system empties into the Atlantic Ocean.

This is a large feature and it is difficult for a few images to convey the scope of the delta system. But if you look at these images you should think about three things. 1)Woody vegetation is abundant. 2.)The streams that flow through the delta will flood periodically and deposit the clay and silt that they are transporting among that vegetation. That silt and clay becomes ash in coal that forms later. 3)Finally note the delta has very low relief (low elevation and little difference from the highest elevation to the lowest) and is close to sea level.  A small rise in sea level would flood the delta with sea water.  Much of this delta is influenced by tidal activity and small changes in sea level over geologic time can cause complete inundation  of the delta.

The seawater influence is important because it contains significant sulfate whereas freshwater does not. Microbes (similar to those that eat oil) eat the organic matter in the swamp sediment and the sulfate converting the organic matter to carbon dioxide (CO₂) and the sulfur to hydrogen sulfide (H₂S). The H₂S would then combine with iron bearing minerals to make pyrite (FeS₂; fool’s gold). The reduced sulfur is converted to sulfur dioxide (SO₂) when pyrite-bearing coal is burned. The SO₂ is converted to sulfuric acid in the atmosphere thus producing acid rain. Acid rain is an significant environmental issue that can be addressed by treating the smokestack exhaust and (more easily) by purchasing coal that contains small amounts of sulfur. Most western coal has never seen seawater, contains very little sulfur and is; therefore, a desired commodity even though it is of low rank compared to Eastern and Interior States coal.

Oil shale is a petroleum source rock that has not yet generated oil.

So far we’ve considered several non-conventional hydrocarbon resources that contain enormous amounts of energy.  Methane hydrates are distributed over much of the cold regions of the Earth and may contain more energy than all the combined conventional fossil fuel resources known.  The Athabasca tar sands and the the Orinoco Heavy Oil belt contain heavy petroleum resources that are sufficient to supply the world for a significant period.  But none of these non-conventional resources are present in the good old USA in great quantity.  That is where oil shale comes in.  Oil shale is important, in part, because it is a resource that exists in the United States in great quantity.  The downside is that significant energy input may be required to generate and extract the oil.

The amount of oil in question is potentially huge, on the order of the amount of oil that will be produced by the world using conventional means.  The oil shale problem is similar to the tar sand problem: we have to put energy in before we can get the oil out.  But when working with tar sands we merely need to extract heavy oil from a reservoir.  When working with oil shale we must make the source rock generate oil.  The processing of tar sands merely requires an extension of our work with heavy oil reservoirs.  Oil shales are a whole new animal.  The upside is that the quality of the crude recovered may be superior; the oil is tar sands is strongly biodegraded after all.

Large capital investments may be required.  The BLM web site has the plans for the research leases in Colorado and Utah.  The Utah leases will be tested by mining the oil shale and retorting it at the surface using the Alberta Taciuk Process (ATP).  The ATP process is has actually being been used in an oil shale mine in Queensland, Australia.  The Colorado leases are being developed using a variety of in-situ techniques.  Each of the three companies will require significant physical plants at the surface.  In my quick reading the Shell and E.G.L. Resources plans are the most detailed.

E.G.L. Resources proposed to circulate steam and other hot fluids through cased holes to cause the rock to generate oil.  They also held out the prospect of using electric heaters.  E.G.L. Resources has been reorganized and is now called American Shale Oil.  Their plans may change significantly as they seem to have new management and a new Chief Technology Officer.  They have not yet updated their web site, however.

Shell proposes to use downhole electrical resistance heaters to mature the oil shale and generate the crude.  They have submitted one of the most detailed proposals and virtually all the current oil shale “hype” and news relates to the Shell project.

Other techniques that been proposed that would involve “microwaving” the oil shale in situ!

If the price of electricity increases significantly during the lifetime of Shell’s project, their shale oil project may become less attractive (even if they build a dedicated power plant it may make more sense to sell the power rather than to use it on the oil shale project).   On the other hand, if our economy changes in a way that de-emphasizes petroleum, then their final product may have less value.  Thus extraction technology that relies on in-situ combustion of oil shale to power the retorting process may be more attractive in the long run.

Investing large sums of money for long periods of time is expensive and risky.  Corporations won’t do this unless risk can be minimized.

In my opinion oil companies are at a cross-roads.  They can assume that their current business model will remain viable for the future and place all their efforts into looking for conventional sources of oil.  Big oil ompanies will need to find billion barrel fields to secure their future.  The alternative is to start considering another type of hydrocarbon resource (methane hydrate, heavy oil, oil shale) in earnest.  The energy density of gasoline and diesel fuel sugests that heavy oil and oil shale are more atractive in the long run than are oil sands.  Almost all of these efforts to find a new source of hydrocarbon energy will fail.  If one succeeds it may change the way that the hydrocarbon energy industry operates, however.  The early explorers are likely to acquire the best acreage.

We have considered the problems inherent in preserving petroleum at great depth; the stable forms of carbon at shallow levels in the crust are methane, carbon dioxide, or graphite.  The hydrocarbons in oil are trying to become one of those species depending on the chemistry of the system.  The speed with which hydrocarbons in oil will revert to one of those stable species increases as temperature increases with depth. There are equally significant problems preserving petroleum at very shallow levels in the crust.  Microbes are relentless and will always find a way to thrive provided temperatures are moderate (less than about 120^oC) and the organisms have access to food, oxidants (not necessarily oxygen), water, and nutrients.

Most very shallow oil fields have experienced some level of microbial degradation and many oil fields have experienced substantial biodegradation.  A major advance in our understanding of these processes has been the realization that these organisms don’t require oxygen to oxidize the oil. Whereas we breath oxygen, eat reduced carbon materials (e.g. carbohydrates, proteins, etc.), and exhale carbon dioxide, these organisms will “breath” sulfate ions (SO₄^2-) in the water in which they live, eat compounds in oil, and “exhale” carbon dioxide and hydrogen sulfide.  Oil degrading microbes eat hydrocarbons in a specific order: 1)n-alkanes, followed by 2)isoalkanes. 3)cycloalkanes, and finally 4)aromatics.  Oils affected by biodegradation are heavy, have relatively few short chain n-alkanes, and contain significant amounts of sulfur.  The oils are heavy because the short chain compounds have been eaten leaving only the larger molecules.  The sulfur content is high because the H₂S generated during biodegradation attacks the organic cimpounds and converts them to organo-sulfur compounds. They contain abundant metals, in part because the oil that didn’t contain metaals was eaten. They are; therefore, very viscous and yield little gasoline upon distillation (the gasoline range hydrocarbons have been eaten). The sulfur and metals must be removed before any reforming processes (metals and sulfur will poison the catalysts).

Although gasoline content controls oil value, viscosity controls whether a heavy oil resource can be produced and how it might be produced. Oils as heavy as 10^o API are produced routinely in many onshore areas. It is difficult to produce oils with API gravity values greater than 14^o in offshore areas. The difference in API gravity between onshore and offshore facilities is controlled by the fact that oil viscosity is related to temperature. Oil produced from offshore facilities will have to flow through pipelines on the seafloor. Heating these pipelines would be prohibitive; if the oil won’t flow at low temperatures, then the oil can’t be produced. This operational constraint limits offshore production to 14^o API or lighter oils.

Petrobras is attempting to develop a reservoir that contains 12.8^o API oil from the Siri field in the Campos basin.  This project got the go-ahead this summer and is expected to commence production in 2014-2016.  Ultimate daily production is expected to be about 100,000 barrels of oil per day.  This project is located in shallow water (311′) and it will be interesting to see how the technology gets ported to deeper water depths.

Production of most heavy oil and tar sands is currently accomplished either by mining the material and removing the oil from the sand using a caustic solution or by injecting steam into the reservoir and producing the warmer, less viscous oil. Steam flooding can be accomplished using continuous steam flooding with vertical injection and production wells, cyclic steam stimulation (huff and puff), or steam assisted gravity drainage (SAGD).

Production of steam is energy intensive and expensive. Thus the best operations incorporate cogeneration facilities which generate the steam during power plant operation. These facilities can also use the produced water from the wells as feedwater for the power plants. Because they are treating the water for use in the power plants they can treat all well effluent and sell the excess as irrigation water.

Most cogeneration facilities do not involve heavy oil production (in California only 83 out of 940 cogeneration plants are used for oil production). Most of these heavy oil generation plants use natural gas to produce the steam; they are gas-fired power plants. The situation is similar in Canada where natural gas is currently the fuel of choice for production of oil from the Athabasca Tar Sands. Continued exploitation of heavy oil therefore involves trading the energy in gas for electricity plus heavy oil that can be converted into gasoline. As conventional oil supplies diminish, exploitation of heavy oil will increase the demand on gas resources (probably driving up the price).

One way around this is to use the heavy oil as the fuel to generate heat in-situ (in place) and forgo the cogeneration possibilities.  One of the best options may be the “Toe to Heel Air Injection” protocol discussed in class.  The key to success here is minimizing the distance that the heated oil has to travel to reach the well bore.  If the oil has to travel too far it won’t make it to the well bore and may simply get combusted.

Remember that the heavy oil resource base is immense; the Athabasca Tar Sands and the Orinoco Heavy Oil Belt contain trillions of barrels of heavy oil. Both of these resources occur in foreland basin systems that have generated enormous amounts of oil that has been biodegraded heavily. If the microbes hadn’t gotten to these accumulations we probably wouldn’t be concerned about future oil supplies.

The truly large unconventional gas accumulations are methane hydrates. Methane hydrates were laboratory curiosities until they were found to clog pipelines in cold climates and in deep water.

This phase diagram has been scaled in depth rather than pressure by assuming a hydrostatic pressure gradient (roughly 0.5 psi/ft). You can see by inspecting the diagram that methane hydrates will be stable only at pressures exceeding 250 psi and at low temperatures. As T increases the pressure required to stabilize methane hydrate also increases. The only places where methane hydrates are stable are in permafrost areas or in deep waters of the the oceans.

Methane hydrates are identified easily on seismic records. One simply looks for a BSR (bottom simulating reflector) that cuts across sedimentary strata and has a polarity opposite that of the water bottom. The BSR is the bottom of the methane hydrate zone. At the water bottom seismic waves will speed up as they pass from water to sediment. The reversed polarity of the BSR means that seismic waves must be slowing down at the BSR. The methane hydrate-cemented sediment will have a higher acoustic impedance than the uncemented sediment; thus, the base of the methane hydrate zone should have a polarity reversed from that of the water-bottom.

These systems are a potential energy bonanza: some workers have proposed that methane hydrates may contain more carbon than is present in all the fossil fuels known on the planet. They also represent a bit of a threat; destabilization of marine methane hydrates could cause tsunamis and the addition of large amounts of methane to the atmosphere could cause rapid climate change. One of the more rapid climate shifts in the geologic history occurred during what is called the Paleocene-Eocene Thermal Maximum (PETM). Temperatures during the PETM were probably considerably warmer than they are today and the event is coincident with a significant mass extinction. The wikipedia entry on the PETM is pretty good. Evidence is accumulating that destabilization of methane hydrates may have caused the rapid climate change. This is one of the reasons that scientists are concerned about climate change; we don’t fully understand the system and there is evidence that it can shift catastrophically under the right circumstances.

We’re learning about methane hydrates rapidly and are fortunate that one of the world’s experts is on faculty here at UNL.

Natural gas comprises largely methane. It can be thermogenic in origin; meaning that it is produced by the same processes that produce oil. Organic matter is exposed to heat and methyl groups break off the larger organic molecules while combining with hydrogen to form methane. Natural gas can also have a biogenic origin. Microbes will reduce combine hydrogen and carbon dioxide to produce methane and water following the reaction

CO₂ + 4H₂ = CH₄ + 2H₂O

In some sedimentary environments microbes can derive energy from this reaction and use it to fuel their existence.

Natural gas has traditionally been less valuable than oil. Recall the table in the PowerPoint file from the lecture that showed that you can get roughly three times the calories per dollar from natural gas that you can from oil (based on prices at the start of the semester). This differential exists for a couple of reasons. 1)We do not use natural gas as a transportation fuel (in the US). 2)Significant amounts of natural gas are produced as a byproduct of petroleum production (associated gas) and, therefore, ample supplies typically exist.

In the absence of a market or close proximity to a pipeline in the United States, Canada, Mexico, South American or Eurasia natural gas has little value. When you look at the pipeline maps you will note that many large natural gas fields (e.g. Urengoy) are in sparsely populated areas, however.

Associated gas (gas produced during the production of oil) will typically be flared if a pipeline is lacking. In recent years it was realized that flaring this stranded gas (gas that cannot find a market) represented a significant CO₂ input to the atmosphere and was a wasting a resource. The amount of gas flared would satisfy 27% of US demand for natural gas. You can go here for a video tour of gas flares around the world (warning: its a big file). The World Bank has made reduction of gas flaring a priority. We will consider a method to increase the value of stranded gas later in the semester.

Although there are seven Liquified Natural Gas (LNG) import terminals and one export terminal operating in the US, there is considerable public resistance to construction of these facilities.

Unconventional gas accumulations are exploited in areas close to markets. These plays include tight gas sands, gas-bearing shales, and coal bed methane. All of these accumulations may occur off structure and may require hydraulic fracturing of the reservoir. These plays have generated tremendous interest in the petroleum industry. The Barnett Shale (TX), is probably the best known gas-bearing shale. Tight gas sands are nearly ubiquitous and this article will give you an idea of their widespread nature. Although a variety of basins produce coal bed methane the activity seems to have been particularly intense in the mountain west (in the USA). These accumulations are possible because of the low permeability of the reservoir. As the gas is generated it either is adsorbed on organic matter in the source rock, migrates into pores in the source rock or migrates into a “reservoir” rock. If the rock is insufficiently permeable to allow much migration of hydrocarbons, the gas will only displace the water in the pore spaces. The pore spaces will fill with gas which can migrate only slowly through the rock. In coal bed methane systems the methane is adsorbed on the organic matter in the coal. In all cases you drill into the rock, fracture it if necessary, establish a pressure gradient (by producing any formation fluid such as water) and produce the gas.

Every President since Nixon has sought the holy grail of U.S. energy independence.  Some have stated this goal more explicitly than others.  Implicit in this goal is the suggestion that the declining US production trend can be reversed. The Hubbert analysis suggests that it can’t, at least for conventional petroleum resources. In this lecture we took a qualitative look at whether there are potential large conventional petroleum provinces that remain untapped.

There are a few onshore provinces that we did not examine (MidContinent Rift, ANWR). But outside of these it is unlikely that there will be large discoveries onshore in the US. (By large I mean 500 million barrels or more). Even a 500 million barrel field is insufficient to reverse the decline in US production. Most US oil producing states have production profiles that look something like Oklahoma’s, they seem to be in an irreversible decline.  That’s not to say that production doesn’t exhibit short term increases in response to sharp price spikes.  These increases are small and transient however.

Moreover, there is little interest in petroleum exploration in places like Oklahoma. You can see this by notices of intent to drill in the state or in a more qualitative ways. In the 1950’s every major oil company had a large exploration office in the state of Oklahoma; now relatively few do. There are a large number of oil companies in Oklahoma but they are smaller, have lower reserves, and more restricted operations. Oklahoma has gone from being a vigorous center of the oil industry to being something less than that.

We looked at offshore areas. Its important to note that before the Santa Barbara Channel oil spill there was little resistance to petroleum exploration anywhere. The oil industry was able to nominate interesting areas for lease, the federal goverment held lease sales, and drilling proceeded with little objection.  A number of the areas off California would generate interest if offered for lease today. But the interest would still be tempered by the industry’s experience with the Pt Arguello field (a large field that didn’t produce as hoped).  Petrobras is developing techniques for the retrieval of heavy oil from offshore reservoirs.  The success of those efforts may be critical to future efforts off the central and northern California coast.

The colors on this map actually tell the story.  The basins in light blue and green are part of prolific petroleum systems and are actively developed.  The basins in pink may lack sufficient overburden to cause the source rock to mature and may lack good reservoirs.  The basins in purple contain good source rock that has probably not been buried sufficiently to generate oil.  The basins in brown contain substantial amounts of heavy oil; probably on the order of a few billion barrels.  The basins in yellow lack good source rock.

Most of offshore Alaska lacks good oil-generating source rock.  The exceptions here are the Chukchi and Beaufort areas.  These latter areas are being actively explored.  We know that good source rocks are present in the National Petroleum Reserve-Alaska.  Are there “game-changers” up there?  Probably not.  We would need to find something comparable to Ghawar to really change the long-term conventional petroleum supply picture.

There has already been considerable drilling activity on the east coast of the US.  Again source rocks seem to be the problem there.

The bright spot is the deepwater Gulf of Mexico.  Here a large petroleum province may have been discovered that will be about the size of production to date from the Gulf of Mexico OCS.  It will be interesting to see how the production from this province measures up over time.

It looks like Hubbert was about right on the U.S.  Finding additional large provinces will require some new ways of thinking and finding more supplies of hydrocarbons will require utilizing unconventional resources.

Corporations are right to seek the right to explore domestically; in fact they have a fiduciary responsibility to do so. It is probable that there are a number of giant oil fields that could be discovered. Such discoveries would be very important to an individual corporation. A 500 million bbl or 1 billion bbl discovery won’t change the overall energy picture for the USA however.