GEOL 115: The Earth’s Energy Resources

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.