Crude Oil Classifications
Crude oil is classified by its non-hydrocarbon content (especially sulfur), its API gravity, and pricing benchmarks.
Crude oil containing low amounts of sulfur (<0.42 percent) and trace amounts of hydrogen sulfide and carbon dioxide is called sweet crude. Sweet crude oil is typically processed into gasoline. Sour crude oil has total sulfur amounts greater than 0.5 percent and higher hydrogen sulfide (>1 percent) and carbon dioxide concentrations. Because of the larger amounts of impurities in sour crude, larger portions of it are converted to heavy crude oil products, such as diesel and fuel oil.
The American Petroleum Institute (API) gravity of crude oil is an indicator of how heavy oil is compared to water. Oil with an API > 10° is lighter than water, while an API < 10° is heavier than water and will sink. In general, light crude oils have low viscosity, low wax content, and low density/high API gravity (>30° API). Medium crude oil has API gravity between approximately 20° API and 30° API. Heavy crude oil is more viscous, and has a higher density/lower API gravity (10–20° API). Extra heavy crude oil (also called bitumen) has an API gravity less than 10° API.
Because a large proportion of light sweet crude oil can be directly processed into gasoline and other petroleum products, it typically commands the highest prices on commodity markets. An example of light sweet crude is West Texas Intermediate (WTI) Crude from the Texas Permian Basin. It has an API gravity of ~ 39.6° and sulfur content of ~0.24 percent. WTI crude is used as a benchmark in crude oil prices and is usually priced several dollars higher per barrel than other common benchmarks such as the Organization of the Petroleum Exporting Countries (OPEC) Reference Basket and United Arab Emirates (UAE) - Dubai. Recently, however, North Sea Brent crude has been priced higher than WTI, even though North Sea Brent is less sweet (~0.37 percent sulfur).
Natural Gas Categories
Natural gas is often categorized based on its liquid content.
Dry natural gas is almost entirely methane and can be extracted from traditional reservoir rocks or from coal seams. It contains less than 0.1 gallon of liquid fractions per 1,000 ft3 of produced gas.
Wet natural gas contains a larger proportion of natural gas liquids than dry gas. Natural gas liquids (NGLs) are fractions of natural gas that are liquid at surface conditions, and are often separated from dry natural gas in processing facilities. NGLs with a low vapor pressure are called condensates, while NGLs with medium and high vapor pressures are called natural gasoline and liquefied petroleum gas, respectively. Examples of NGLs include propane, butane, isobutene, hexane, heptane, and pentane. Ethane is not typically considered an NGL because it needs to be refrigerated in order to maintain a liquid state. Wet gas typically sells at higher prices than dry gas.
Uses for Crude Oil & Natural Gas
Oil & Gas Traps
The high pressures under which hydrocarbons are formed also force or “squeeze” oil and gas out of their original source shale deposit. Oil and natural gas will migrate vertically
and laterally through porous rock formations, such as sandstone and limestone, as well as through faults and natural fractures until an impermeable barrier stops their movement. These barriers to hydrocarbon movement are commonly called traps. Oil and/or natural gas accumulate in these traps to form large hydrocarbon deposits. The rock layer in which the hydrocarbons are trapped is called the reservoir.
There are two main categories of conventional oil/gas traps: structural and stratigraphic. Structural traps form when rock layers are deformed and the resulting geometry prohibits the hydrocarbons from migrating any further. Common structural traps include anticlinal folds and faults. Salt Creek, Wyoming’s most productive (and nearly oldest) oil field is an anticlinal trap.
Exploration geologists and engineers use a variety of techniques to determine where oil and natural gas are located underground. Data from nearby wells, regional geology, computer models, satellite imagery, and mapped surface oil seeps are some of the tools that can help predict where a productive oil well might be located.
Geophysical (seismic) surveying is one of the best methods of finding oil and gas, because it enables geologists to map underground formations and structures. A noise source – typically either a vibrating/thumping truck or an explosive discharge – directs sound waves through the subsurface. The waves reflect off the different rock layers and structures. Geophones record the time it takes for the waves to return to the surface. The raw seismic data is then processed and interpreted to determine the possibility of oil and/or gas. Three-dimensional (3D) seismic surveys allow geologists to make even more accurate interpretations and predictions of oil and gas deposits.
Ultimately, drilling test wells confirms whether oil and/or gas exists in a suspected area or formation. While some test wells lead to the successful discovery of hydrocarbons, others turn out to be “dry holes.” On occasion, test wells help locate hydrocarbons in rock layers other than the original target formation.
Conventional and unconventional oil and gas resources are defined based on relative ease of development, cost, and recovery techniques. Conventional oil and gas resources generally consist of relatively high permeability reservoir rocks, defined hydrocarbon pools, and can be targeted with vertical wells. Unconventional reservoirs typically have lower
porosity and permeability, and rather than hydrocarbons collecting in pools as is the case in conventional reservoirs, they are distributed throughout pore spaces, making them more challenging to extract. With technological advancements, these previously uneconomical resources are becoming the focus of new oil and gas exploration and development. Techniques such as horizontal drilling and hydraulic fracturing are necessary to release the hydrocarbons from these unconventional reservoirs.
Unconventional resources that have contributed to Wyoming’s oil and gas industry include shale gas, tight gas and oil sands, shale oil, and coalbed natural gas. The recent increase in Wyoming’s oil production can largely be attributed to the exploration and development of unconventional reservoirs in the Powder River Basin (Sussex, Shannon, Turner, Parkman, Frontier, etc.).
Shale gas is natural gas locked in shale formations. In these reservoirs, the shale is both the source and the reservoir rock. An example of shale gas in Wyoming is the Hillard-Baxter play in the Greater Green River Basin.
Tight gas and oil reservoirs contain natural gas and oil trapped in the pores of siltstones and sandstones with very low permeability (<0.1 millidarcy) and very low porosity (<10%). The prolific Jonah, Pinedale, and Wamsutter fields are Wyoming’s largest tight gas reservoirs.
Shale oil is oil locked in shales and associated tight siltstones or carbonates – all of which have low permeability and porosity. Examples from Wyoming include the Niobrara Shale and Green River Formation. ***Please note that shale oil should not be confused with oil shale. Oil shales are shales that contain kerogen. Generally, hydrocarbons cannot be produced from oil shale using wells. Mining or in-situ heating processes are necessary to extract and convert the kerogen.***
Coalbed natural gas (CBNG), commonly called coalbed methane, is natural gas stored in coal beds. Wyoming’s Powder River Basin has produced large volumes of CBNG over the past 15 years, although production is currently declining. More information on CBNG in Wyoming can be found in the Coalbed Natural Gas section.
In general, exploration geologists and engineers attempt to locate hydrocarbon reservoirs that will be productive and profitable enough to outweigh the high costs associated with drilling a well. A single horizontal well can cost from $9 to $25 million.
Coalbed Natural Gas
Environments rich in plant material such as swamps, estuaries, and marshes were prolific in Wyoming during the Eocene Epoch (54 to 33 million years ago) and the Paleocene Epoch (65 to 54 million years ago). A large portion of the coal deposits that the U.S. exploits today were
formed during these epochs. Coalbed natural gas (CBNG), also called coalbed methane, formed in these coal seams by biogenic or thermal processes. The primarily subbituminous Wasatch (Eocene-aged) and Fort Union (Paleocene-aged) formations are currently the main targets of Wyoming CBNG development. CBNG development in Wyoming first occurred in the late 1970s, but did not boom until the 1990s. Today there are more than 21,000 producing and shut-in CBNG wells in Wyoming, with the bulk of the wells in the Powder River Basin (PRB). Because of competition from unconventional gas reservoirs and lower natural gas prices, Wyoming CBNG production is on the decline.
How is Coalbed Natural Gas Formed?
Coalbed natural gas forms in one of two ways. During the earliest stage of coalification (the process that turns plant detritus into coal), biogenic methane is generated as a byproduct of bacterial respiration. Aerobic bacteria (those that use
oxygen in respiration) first metabolize any free oxygen left in the plant detritus and the surrounding sediments. In fresh water environments, methane production begins immediately after the oxygen is depleted. Species of anaerobic bacteria (those that do not use oxygen) then reduce carbon dioxide and produce methane through anaerobic respiration. When the temperature of coal underground reaches approximately 122°F (50°C), and after a sufficient amount of time, most of the biogenic methane is fully generated. Also at this time nearly two-thirds of the moisture is expelled from the coal and it reaches a rank of subbituminous.
After the temperature of a coal exceeds 122°F (50°C), due to the geothermal gradient and excessive burial, thermogenic proceses begin to generate additional carbon dioxide, nitrogen, methane, and water. At this point the amount of hydrocarbons or volatile matter has increased and the coal reaches a rank of bituminous. When the temperature of the coal reaches 302°F (150°C), thermogenic production of methane is maximized.
Coalbed Natural Gas Extraction
In the Powder River Basin, most coalbed natural gas wells are completed open-hole. This method involves setting casing to the top of the target coalbed, under-reaming the underlying target zone, and cleaning the coal with a fresh-water flush. A down-hole submersible pump removes water from the coal and depressurizes the aquifer. The methane gas desorbs from the coal, flows up the annulus, and is piped to a metering facility where the gas and water production from each well is recorded. The methane then flows to a compressor station where the gas is compressed and shipped via pipeline. The produced water is either diverted to a central discharge point (called an outfall) and then into a drainage or impoundment, or is re-injected into nearby aquifers.
Enhanced Oil Recovery
Enhanced oil recovery defines methods of recovering stranded oil that remains in reservoirs after primary depletion.
Oil is first produced from reservoirs under primary recovery (due to in-situ reservoir pressure aided by pumps) and followed by secondary recovery. Secondary recovery generally
occurs by a waterflood, where water is injected into the reservoir to physically displace the residual oil, which is subsequently recovered by adjacent production wells. The success of waterfloods depends on the permeability of the reservoir and the properties of the oil.
Waterfloods can be followed by tertiary recovery techniques, referred to as enhanced oil recovery, or EOR. Primarily used in declining oil fields, EOR can occur as thermal recovery where heat injection reduces oil viscosity, chemical recovery to lower the surface tension and enhance reservoir flow, or gas injection that displaces and mixes with oil. Gas injection of carbon dioxide (CO2) has become the most significant technique, commonly referred to as CO2-EOR, and is often used interchangeably with EOR.
CO2-EOR has been successful in a handful of fields around Wyoming, including Lost Soldier and Wertz fields and the Monell unit in the Patrick Draw field of the Greater Green River Basin, Salt Creek field in the Powder River Basin, and Beaver Creek field in the Wind River Basin. Grieve field, in the Wind River Basin, began CO2-EOR operations in early 2013. Most of these fields underwent secondary waterflooding prior to CO2-EOR.
For more information on enhanced oil recovery in Wyoming, please see the University of Wyoming’s Enhanced Oil Recovery Institute website.
Hydraulic fracturing ("fracking") technology is used to enhance the productivity of wells by injecting water, a proppant (typically sand), and additives underground at high pressures to create fractures into rock bodies containing oil and gas. Creating fractures in the rock provides a pathway for those resources to travel to the well bore and the proppant helps hold the fractures open. Hydraulic fracturing has allowed for the rapid development of new unconventional plays across the nation.
Hydraulic Fracturing Constituents
Proppants can be manufactured (usually ceramic or metal) or natural. Most proppant sources are derived from clean sandstones. Ideal frac sands are between 0.106 mm and 2.36 mm in diameter, spherical, and have a high compressive
Fresh water is used in fracking to prevent interact with the chemical additives. Millions of gallons of water can be used on one multi-stage fracked horizontal well. Much of this water returns to the surface as flowback water, which is then disposed of in injection wells, pits, or treated and discharged into surface waters. It can also be recycled for use in another well.
Chemical additives in fracking fluids make the fracking process more efficient and effective. Because unique conditions are encountered with each well, the type and amount of chemical additives varies. According to FracFocus, three to 12 chemicals are typically added to a well’s fracturing fluids. While water comprises 98 percent to 99.2 pecent of the total fracturing fluid volume, additives account for 0.5 percent to 2 percent. The chemicals serve to prevent bacteria growth, scale deposits, and well casing corrosion. They control iron precipitation, adjust pH levels, reduce friction, and alter the fluid’s surface tension and viscosity. Other additives include emulsifying/thickening agents, acids that remove drilling mud damage, and gels.
Some operators are beginning to use propane gel (liquefied propane gas) instead of water to frack wells. The benefits of using propane gel include a reduction in water use and costs associated with transport and disposal of fracking wastewater, as well as reducing the possibility of soil or groundwater contamination from fracking wastewater. Because the propane gel becomes a gas under the high pressure and temperature in a well, it returns to the surface with the natural gas and can be recaptured, separated, and reused or sold. Finally, the propane gas does not carry fracking chemicals, salts, or natural radioactive material in it when it returns to the surface.
However, the use of propane gel to frack wells also has its disadvantages. It is more expensive than water. Because it is explosive, the propane gel requires special monitoring devices and safety equipment that water does not. Additional special equipment is needed onsite to keep the propane gel at a high pressure and low temperature. It also may not be as effective in deep formations where higher pressures are required to frack a well. Currently, there is a lack of infrastructure for the propane to be recaptured and reused. And because it is a relatively new technology, it has not been entirely proven and accepted by industry.
Hydraulic Fracturing—Past and Present
The idea of breaking up rock formations to expedite oil and gas flow into a well is not a new one. As early as the 1860s, black powder or nitroglycerin was detonated in wells to stimulate oil, gas, and water flow. This dangerous, but often successful method was called “shooting” a well. Injecting non-explosive acids into wells was first attempted in the 1930s to create and maintain fractures in reservoir rocks.
Modern hydraulic fracturing treatments were first developed and used by Stanolind Oil and Gas Corporation in 1947 on a Kansas gas well. Stanolind’s “Hydrafrac” process became patented and commercial in 1949. That same year, Halliburton Oil Well Cementing Company acquired a license for the Hydrafrac process and applied it to 332 wells. The large production increases seen from hydraulic fracturing led to its rapid and widespread application throughout the oil and gas industry.
Currently, the United States is going through an oil and gas boom from unconventional reservoirs. Tight sands, shale gas, and shale oil reservoirs were previously uneconomic due to their lower permeability and porosity and distribution of the oil and gas throughout the pore spaces of the reservoir rock, instead of in a defined (conventional) pool. But directional and horizontal drilling methods, coupled with hydraulic fracturing, are now allowing oil and gas operators to tap into these large unconventional oil and gas reserves. Hydraulic fracturing may account for a 30 percent and 90 percent (Dec, 2010) increase in U.S. recoverable reserves of oil and gas, respectively.
Because of its success, hydraulic fracturing will continue to be a standard industry practice. According to the American Petroleum Institute, hydraulic fracturing has been used on over 1 million wells in the United States and led to the production of more than 7 billion barrels of oil and 600 trillion cubic feet of natural gas. The U.S. Environmental Protection Agency estimated that 35,000 wells in the United States are hydraulically fractured each year. Halliburton estimates that approximately nine out of 10 onshore natural gas and oil wells will need to be hydraulically fractured to maintain their production rates.
For More Information on Hydraulic Fracturing