Fracking (Hydraulic Fracturing)
As the reserves of recoverable liquid petroleum diminish, oil companies are increasingly turning to unconventional resources. Unconventional resources include such things as extra heavy oil and shale. It is estimated that as much as 30% of total world oil reserves are in the form of shale. Because shale is a fine-grained, sedimentary rock, the oil it contains does not easily flow and therefore must be “released” before it can be pumped from the ground. The process employed is called hydraulic fracturing, and generally consists of four stages.
Hydraulic fracturing is most often performed in horizontally drilled wells. After a period of vertical drilling in order to reach shale deposits, a lateral extension of up to 5000 feet is drilled parallel to the rock layer containing the shale. Lateral drilling has many advantages, including reduce ground surface disruption.
In the next step, water is injected into the recently bored hole. Occasionally, other substances such as gels, foams, compressed gases and even air are injected. Chemical mixtures are usually included in the injection. Chemicals are intended to increase the permeability of the rock by dissolving various components. The exact composition of the chemical injection is based on the geological composition of the area. Added chemicals include acids, biocides to kill bacteria, corrosion inhibitors, and surfactant. Specifics include hydrochloric acid, methanol, ammonium chloride, ethylene glycol (antifreeze), isopropanol (rubbing alcohol). Approximately 750 chemicals are listed as possible additives for hydraulic fracturing. The fluid is injected under high pressure with the intent of fracturing the soft shale. Pressures can reach as high as 15,000 pounds per square inch (100 Mpa) and injection rates can be as high as 265 liters per minute. Injected fluid is recovered, to some degree, and stored in surface containers. Do to the chemical additives, this material is often toxic.
Seismic monitoring is used to estimate how large the induced fractures are as well as their orientation, resulting in a rough geometric map of the fracture. This mapping helps to ensure that injected fluids are not leaked during progressive lengthening of the fracture zone. Fracturing monitoring also allows for the identification of underground “reservoir zones,” where a shale deposit may expand beyond the lateral bore hole.
This refers to the cessation of fracturing and the active recovery of liquid petroleum. This process usually involves preparing the “bottom” of the well, running piping, and cementing a casing. It is no different than the process that would be used to pump liquid oil from “traditional” deposits. Additional fracturing may occur at later dates in an effort to “stimulate” or enhance production in a slowing well.
Environmental risks include air quality damage, migration of gases to the surface, and groundwater contamination. The Energy Policy Act of 2005 amended the Safe Drinking Water Act to exclude the chemical and fluids used in fracking from EPA jurisdiction. There have been claims of water contamination due to fracturing in Texas, North Dakota, Pennsylvania, Colorado, and Louisiana. The EPA has jurisdiction over waste disposal of any fluids recovered from fracking and brought to the surface. They have limited authority over those fluids that remain in the ground. A leak from a surface containment facility is within EPA jurisdiction, but a leak in the underground borehole may not be.
Petroleum reserves are any quantity of petroleum that is commercially recoverable. In order to be considered a reserve, a given deposit of petroleum must satisfy four criteria:
Petroleum reserves fall into four different categories based on how certain it is the petroleum can be recovered and how a given deposit of oil factors into a nation’s security planning. Petroleum reserves, while resting in specific countries, are considered global resources as the impact of oil is global.
A proven reserve is one in which there is 90% certainty that the petroleum is recoverable. To determine the “recoverability” of a given reserve geologic, economic, and political conditions are all taken into account. Such proven reserves are referred to as P90 in the industry, meaning they have a 90% chance of being produced. Proven reserves can be sub-classified as either “proven developed” (PD) or “proven undeveloped” (PUD). PD simply means that wells have already been drilled on these reserves or that little additional investment is needed. PUD reserves require more substantial investment in order to make them productive. The five largest proven oil reserves lie in Saudi Arabia, Canada, Iran, Iraq, and Kuwait. While the largest quantities of oil are found in the Middle East, when divided by country, Canada has the second largest number of proven reserves at roughly 19 to 20% of global total. The United States ranks fourteenth and the United Kingdom at thirty.
Unproven reserves are geologically equivalent to proven reserves. Their “unproven” status rests on technical, regulatory, or political issues. This is an example of the global criteria used to classify a reserve. If the reserve is producing oil, but is being used only internally by a country due to political or contractual issues, then it is classified as unproven. If that same well were to begin producing oil for global consumption, it would then be classified as proven.
Unproven reserves fall into two categories: probable and possible. A probable reserve is the same as a P50 reserve in industry jargon, which simply means there is a 50% chance of recovering oil from the reserve. A possible reserve is also called a P10 reserve. P10 reserves generally receive their designation for technical or economic concerns and not for political reasons.
Strategic reserves are government-controlled oil “stockpiles” maintained to protect a country’s economy and national security. Countries that maintain reserves fall into two categories: those that belong to the International Energy Agency (IEA) and those that do not. IEA members are required to keep a reserve equal to 90 days of the prior year’s net oil imports, unless the country is a net exporter, such as Canada. Many of these countries have emergency oil sharing agreements that provide for oil bartering during times of emergency or disaster. Countries in the IEA include the United States, Canada, the United Kingdom, France, Denmark, Germany, and Japan. China is not a member or the IEA, but maintains a strategic reserve that is planned to equal 90 days of supply by 2020.
In 2007, the Society of Petroleum Engineers (SPE) adopted new evaluation criteria for classifying reserves. The term “reserve” was replaced by “resource.” The new criteria add categories for contingent and prospective resources in addition to the standards discussed above. Contingent reserves are those that are potentially recoverable, but for which commercial development is not yet feasible due to one or more “contingencies.” This includes reserves for which the market has not yet matured (meaning the price of extraction is not offset by current market prices of oil) and reserves that depend on recovery technology that is still under development. Prospective reserves are complicated. They can generally be defined as locations where there is an estimated chance of discovery and development, but for which no actual discovery of oil (no wells drilled) has occurred. Many offshore reserves are could be considered prospective.
A final classification is unconventional resources. It also was introduced in 2007 by the SPE. This classification includes petroleum accumulations that require specialized technology to extract, as opposed to wells, in addition to significant processing and investment prior to sales. This includes resources such as extra heavy oil and shale. The total amount of unconventional resources is thought to be substantially greater than conventional, but they are harder to recover and more expensive to develop.