Future of Petroleum Production

The future of petroleum as a fuel remains somewhat controversial. USA Today news reported in 2004 that there were 40 years of petroleum left in the ground. Some argue that because the total amount of petroleum is finite, the dire predictions of the 1970s have merely been postponed. Others claim that technology will continue to allow for the production of cheap hydrocarbons and that the earth has vast sources of unconventional petroleum reserves in the form of tar sands, bitumen fields and oil shale that will allow for petroleum use to continue in the future, with both the Canadian tar sands and United States shale oil deposits representing potential reserves matching existing liquid petroleum deposits worldwide.

Getting Crude Oil

Crude oil is a smelly, yellow-to-black liquid and is usually found in underground areas called reservoirs. Scientists and engineers explore a chosen area by studying rock samples from the earth. Measurements are taken, and, if the site seems promising, drilling begins. Above the hole, a structure called a 'derrick' is built to house the tools and pipes going into the well. When finished, the drilled well will bring a steady flow of oil to the surface.

The amount of crude oil produced (domestically) in the United States has been getting smaller each year. However, the use of products made from crude oil has been growing, making it necessary to bring more oil from other countries. About 58 percent of the crude oil and petroleum products used in the United States comes from other countries.

Products Made from a Barrel of Crude Oil

After crude oil is removed from the ground, it is sent to a refinery by pipeline, ship or barge. At a refinery, different parts of the crude oil are separated into useable petroleum products. Crude oil is measured in barrels (abbreviated "bbls"). A 42-U.S. gallon barrel of crude oil provides slightly more than 44 gallons of petroleum products. This gain from processing the crude oil is similar to what happens to popcorn, it gets bigger after it is popped.

One barrel of crude oil, when refined, produces about 20 gallons of finished motor gasoline, and 7 gallons of diesel, as well as other petroleum products. Most of the petroleum products are used to produce energy. For instance, many people across the United States use propane to heat their homes and fuel their cars. Other products made from petroleum include: ink, crayons, bubble gum, dishwashing liquids, deodorant, eyeglasses, records, tires, ammonia, and heart valves.

Oil Impact On Environment

Products from oil (petroleum products) help us do many things. We use them to fuel our airplanes, cars, and trucks, to heat our homes, and to make products like medicines and plastics. Even though petroleum products make life easier - finding, producing, moving, and using them can cause problems for our environment like air and water pollution. Over the years, new technologies and laws have helped to reduce problems related to petroleum products. As with any industry, the government monitors how oil is produced, refined, stored, and sent to market to reduce the impact on the environment. Since 1990, fuels like gasoline and diesel fuel have also been improved so that they produce less pollution when we use them.
Exploring and drilling for oil may disturb land and ocean habitats. New technologies have greatly reduced the number and size of areas disturbed by drilling, sometimes called "footprints." Satellites, global positioning systems, remote sensing devices, and 3-D and 4-D seismic technologies, make it possible to discover oil reserves while drilling fewer wells. Plus, the use of horizontal and directional drilling make it possible for a single well to produce oil from much bigger areas. Today's production footprints are only about one-fourth the size of those 30 years ago, due to the development of movable drilling rigs and smaller "slimhole" drilling rigs. When the oil in a well is gone, the well must be plugged below ground, making it hard to tell that it was ever there. As part of the "rig-to-reefs" program, some old offshore rigs are toppled and left on the sea floor to become artificial reefs that attract fish and other marine life. Within six months to a year after a rig is toppled, it becomes covered with barnacles, coral, sponges, clams, and other sea creatures.
If oil is spilled into rivers or oceans it can harm wildlife.When we talk about "oil spills" people usually think about oil that leaks from ships when they crash. Although this type of spill can cause the biggest shock to wildlife because so much oil is released at one time, only 2 percent of all oil in the sea comes from ship or barge spills. The amount of oil spilled from ships dropped a lot during the 1990's partly because new ships were required to have a "double-hull" lining to protect against spills. While oil spills from ships are the most well-known problem with oil, more oil actually gets into water from natural oil seeps coming from the ocean floor. Or, from leaks that happen when we use petroleum products on land. For example, gasoline that sometimes drips onto the ground when people are filling their gas tanks, motor oil that gets thrown away after an oil change, or fuel that escapes from a leaky storage tank. When it rains, the spilled products get washed into the gutter and eventually go to rivers and the ocean. Another way that oil sometimes gets into water is when fuel is leaked from motorboats and jet skis.
A refinery is a factory where crude oil is processed into petroleum products. Because many different pollutants can escape from refineries into the air, the government monitors refineries and other factories to make sure that they meet environmental standards.
When a leak in a storage tank or pipeline occurs, petroleum products can also get into the ground, and the ground must be cleaned up. To prevent leaks from underground storage tanks, all buried tanks are supposed to be replaced by tanks with a double-lining. This hasn't happened everywhere yet. In some places where gasoline leaked from storage tanks, one of the gasoline ingredients called methyl tertiary butyl ether (MTBE) made its way into local water supplies. Since MTBE made water taste bad and many people were worried about drinking it, a number of states banned the use of MTBE in gasoline, and the refining industry voluntarily moved away from using it when blending reformulated gasoline.
Gasoline is used in cars, diesel fuel is used in trucks, and heating oil is used to heat our homes. When petroleum products are burned as fuel, they give off carbon dioxide, a greenhouse gas that is linked with global warming. The use of petroleum products also gives off pollutants - carbon monoxide, nitrogen oxides, particulate matter, and unburned hydrocarbons - that help form air pollution. Since a lot of air pollution comes from cars and trucks, many environmental laws have been aimed at changing the make-up of gasoline and diesel fuel so that they produce fewer emissions. These "reformulated fuels" are much cleaner-burning than gasoline and diesel fuel were in 1990. In the next few years, the amount of sulfur contained in gasoline and diesel fuel will be reduced dramatically so that they can be used with new, less-polluting engine technology.

Heavy Crude Oil

Heavy crude oil or Extra Heavy oil is any type of crude oil which does not flow easily. It is referred to as "heavy" because its density or specific gravity is higher than of light crude oil. Heavy crude oil has been defined as any liquid petroleum with an API gravity less than 20°,meaning that its specific gravity is greater than 0.933.
Production, transportation, and refining of heavy crude oil present special challenges compared to light crude oil. The largest reserves of heavy oil in the world are located north of the Orinoco river in Venezuela the same amount as the conventional oil reserves of Saudi Arabia,but 30 or more countries are known to have reserves. Heavy crude oil is closely related to tar sands, the main difference being that tar sands generally do not flow at all. Canada has large reserves of tar sands, located north and northeast of Edmonton, Alberta.
Physical properties that distinguish heavy crudes from lighter ones include higher viscosity and specific gravity, as well as heavier molecular composition. Extra heavy oil from the Orinoco region has a viscosity of over 10,000 centipoise and 10° API gravity Generally a diluent is added at regular distances in a pipeline carrying heavy crude to facilitate its flow.
Some petroleum geologists categorize bitumen from tar sands as extra heavy oil although bitumen does not flow at ambient conditions.

Economics

Heavy crude oils provide an interesting situation for the economics of petroleum development. The Resources of Heavy oil in the world are more than twice of those conventional light crude oil. On one hand, due to increased refining costs and high sulfur content, heavy crudes are often priced at a discount to lighter ones. The increased viscosity and density also makes production more difficult (see: reservoir engineering). On the other hand, large quantities of heavy crudes have been discovered in the Americas including Canada, Venezuela and Northern California. The relatively shallow depth of heavy oil fields(often less than 3000 feet) contributes to lower drilling costs.

Chemical properties

Heavy oil is asphaltic. It is "heavy" (dense and viscous) due to the high presence of naphthenes and paraffins. Heavy oil has over 60 carbon atoms and hence a high boiling point and molecular weight. For example, the viscosity of Venezuela's Orinoco extra-heavy crude oil lies in the range 1000-5000 cP, while Canadian extra-heavy crude has a viscosity in the range 5000-10,000 cP, about the same as molasses, and higher (up to 100,000 cP for the most viscous commercially exploitable deposits).A definition from the Chevron Phillips Chemical Company LP website is as follows:
The "heaviness" of heavy oil is primarily the result of a relatively high proportion of a mixed bag of complex, high molecular weight, non-paraffinic compounds and a low proportion of volatile, low molecular weight compounds. Heavy oils typically contain very little paraffin and may or may not contain high levels of asphaltenes.

Environmental Impact

As a rule, heavy crudes have a more severe environmental impact than light ones. With more difficult production comes the employment of a variety of enhanced oil recovery techniques, including steam flooding and tighter well spacing, often as close as one well per acre. Heavy crudes also carry contaminants. For example, Orinoco extra heavy oil contains 3.5% sulfur as well as vanadium and nickel.Heavy crude oils contain more carbon in relation to hydrogen, thus releasing more carbon dioxide (a greenhouse gas) per amount of usable energy when burned.
Advanced technologies are mitigating the environmental impact via horizontal wells and increased energy efficiency, but, barrel for barrel, heavy crudes will likely always be more environmentally damaging than light crudes.

Origin

Most geologists agree that crude becomes "heavy" as a result of biodegradation, in which lighter ends are preferentially consumed by bacterial activity in the reservoir, leaving heavier hydrocarbons behind. This hypothesis leans heavily on the techniques of petroleum geochemistry.

Crude Oil as an Input Cost to Refiners

It is true to say that the cost of crude oil is the major input cost for refiners. However, the relationship between such a cost and the final price for a petroleum product produced from that crude, such as petrol or diesel, is not as direct as one would think.
There are, for instance, additional petroleum product markers which give a guide to prices. That is, prices are not just a function of cost-push, but are also strongly influenced by demand-pull.
For example, USA environmental requirements for gasoline (petrol) have at times pushed up the prices in the USA by significantly more than the movements in crude prices. This is the market working as refiners who see these prices work hard to increase production to capture some of these high prices before they dissipate under competitive pressure – both from within the USA and from the resulting massive influx of product cargoes from other producing centers in the world.
There are also a number of other variables which affect the price of products such as petrol. In addition the perception of the purchasers and sellers in the market as to the price risk over time can also add or subtract premiums to the product marker price.

Pricing of Physical Crude Oil Trades

Generally this is based on a formula approach where a marker crude is used as the base and then a quality differential (premium/discount) as well as a demand/supply (premium/discount) is added depending on the crude being purchased.
Thus in times of tight supply this premium will rise and gradually drag up the Marker crude price, whilst in times of surplus supply, a reduced premium or even a discount will drag down the Marker crude price. Of course big changes, announcement or events that can significantly influence crude supply levels will sometimes result a large step change in the prices of crude oil (eg. OPEC announcements, civil unrest or wars, hurricane activity, major refinery shutdowns or outages etc).
That is, crude oils being purchased do not always slavishly follow marker crudes. Marker crudes are indicators of what is happening in regional markets.

Australian Crude Oil Requirements

Australia has seven major operating oil refineries. While Australia has substantial crude oil production, Australian refineries only source a minority of their crude oil requirements from Australian fields.
This is partly because Australia crude oil is generally light and getting lighter. Some heavier crude oils are required to produce heavier products such as lubricating oils and bitumen, and as this occurs Australian refineries (which are in general not designed to process large quantities of the very light crudes), must resort to heavier crude imports.
The other significant reason is that overseas crude oils can be purchased at lower prices. This is a function of the value that all oil refineries place on each possible crude they can purchase. Every refinery has a different configuration of plant and equipment and depending upon the product demand in their particular market, particular refinery limitations, and the different product yields (petrol, diesel, kerosene) that are produced from each crude oil, they will each see slightly different value for every crude oil at a particular point in time. Australian refineries are no different and with the highly competitive Australian market under considerable financial pressure, refiners are always seeking ways of reducing costs, and finding cheaper crudes (or better value crudes) is one of these.

Hydrotreating

The objective of the Hydrotreating prococess is to remove suplur as well as other unwanted compunds, e.g. unsaturated hydrocarbons, nitrogen from refinery process streams.Until the end of World War 2, there was little incentive for the oil industry to pay significant attention to improving product quality by hydrogen treatment. However, soon after the war the production of high sulphur crudes increased significantly, which gave a more stringent demand on the product blending flexibility of refineries, and the marketing specifications for the products became tighter, largely due to environmental considerations. Furthermore, the catalyst used in the Platforming process can only handle sulfur in the very low ppm level, so hydrotreating of naphtha became a must. The necessity for hydrotreating of middle distillates (kerosene/gasoil) originates from pressure to reduce sulfur emissions into the environment. Overall, this situation resulted in an increased necessity for high sulphur removal capability in many refineries.As catalytic reforming gives hydrogen as a byproduct, it gave additional momentum to the development of sulphur removal process by hydrogen treatment. In this treatment, the sulphur compounds are removed by converting them into hydrogen sulphide by reaction with hydrogen in the presence of a catalyst. This results in high liquid product yields, since only sulphur is removed. Furthermore, the hydrogen sulphide produced can be easily removed from the product gas stream, for example by an amine wash. In this way, hydrogen sulphide is recovered as a higly concentrated stream and can be further converted into elemental sulphur via the "Claus" process.Hydrodesulphursiation has been extensively used commercially for treating naphtha as feedstock for catalytic reformers to meet the very stringent sulphuir specification of less than 1 ppm wt to protect the platinum catalyst. It has also been widely used for removal of sulphur compounds from kerosine and gasoils to make them suitable as blending components. In cases where products are from catalytic or thermal crackers, hydrogen treatment is used to improve product quality specifications like colour, smoke point, cetane index, etc.For Hydrotreating, two basic processes are applied, the liquid phase (or trickle flow) process for kerosine and heavier straight-run and cracked distillates up to vacumn gas oil and the vapour phase process for light straight-run and cracked fractions.Both processes use the same basic configuration: the feedstock is mixed with hydrogen-rich make up gas and recycle gas. The mixture is heated by heat exchange with reactor effluent and by a furnace and enters a reactor loaded with catalyst. In the reactor, the sulphur amd nitrogen compounds present in the feedstock are converted into hydrogen sulphide and ammonia respectively. The olefins present are saturated with hydrogen to become di-olefins and part of the aromatics will be hydrogenated. If all aromatics needs to be hydrogenated, a higher pressure is needed in the reactor compared to the conventional operating mode.The reactor operates at temperatures in the range of 300-380 0C and at a pressure of 10-20 bar for naphta and kero, as compared with 30-50 bar for gasoil, with excess hydrogen supplied. The temperature should not exceed 380 0C, as above this temperature cracking reactions can occur, which deteriorates the colour of the final product. The reaction products leave the reactor and, after having been cooled to a low temperature, typically 40-50 0C, enter a liquid/gas separation stage. The hydrogen-rich gas from the high pressure separation is recycled to combine with the feedstock, and the low pressure off-gas stream rich in hydrogen sulphide is sent to a gas-treating unit, where hydrogen sulphide is removed. The clean gas is then suitable as fuel for the refinery furnaces. The liquid stream is the product from hydotreating. It is normally sent to a stripping column where H2S and other undesirable components are removed, and finally, in cases where steam is used for stripping, the product is sent to a vacumn drier for removal of water. Some refiners use a salt dryer in stead of a vacuum drier to remove the water.The catalyst used is normally cobalt, molybdenum and nickel finely distributed on alumina extrudates. It slowly becomes choked by coke and must be renewed at regular intervals (typically 2-3 years). It can be regenerated (by burning off the coke) and reused typically once or twice before the breakdown of the support's porous structure unacceptably reduces its activity. Catayst regeneration is, nowadays, mainly carried out ex- situ by specialised firms. Other catalysts have also been developed for applications where denitrification is the predominant reaction required or where high stauration of olefins is necessary.A more recent development is the application of Hydrotreating for pretreatment of feedstcok for the catalytic cracking process. By utilisation of a suitable hydrogenation-promoting catalyst for conversion of aromatics and nitrogen in potential feedstocks, and selection of severe operating conditions, hydrogen is taken up by the aromatic molecules. The increased hydrogen content of the feedstock obtained by this treatment leads to significant conversion advantages in subsequent catalytic cracking, and higher yield of light products can be achieved.Hydrotreatment can also be used for kerosine smoke point improvement (SPI). It closely resembles the conventional Hydrotreating Process however an aromatic hydrogenation catalyst consisting of noble metals on a special carrier is used. The reactor operates at pressure range of 50-70 bar and temperatures of 260-320 0C. To restrict temperature rise due to the highly exothermic aromatics conversion reactions, quench oil is applied between the catalysts beds. The catalyst used is very sensitive to traces of sulphur and nitrogen in the feedstock and therefore pretreatment is normally applied in a conventional hydrotreater before kerosine is introduced into the SPI unit. The main objective of Smoke Point Improvement is improvement in burning characteristics as the kerosine aromatics are converted to naphthenes.Hydrotreatment is also used for production of feedstocks for isomersiation unit from pyrolysis gasoline (pygas) which is one of the byproducts of steam cracking of hydrocarbon fractions such as naphtha and gasoil.A hyrotreater and a hydrodesulphuriser are basically the same process but a hydotreater termed is used for treating kerosene or lighter feedstock, while a hydodesulhuriser mainly refers to gasoil treating. The hydrotreatment process is used in every major refinery and is therefore also termed as the work horse of the refinery as it is the hydrotreater unit that ensures several significant product quality specifications. In most countries the Diesel produced is hydrodesulhurised before its sold. Sulphur specifications are getting more and more stringent. In Asia, countries such as Thailand, Singapore and Hong Kong already have a 0.05%S specification and large hydrodesulphurisation units are required to meet such specs.The by-products obtained from HDT/HDS are light ends formed from a small amounts of cracking and these products are used in the refinery fuelgas pool. The other main by-product is Hydrogen Sulphide which is oxidized to sulphur and sold to the chemical industry for further processingIn combination with temperature, the pressure level (or rather the partial pressure of hydrogen) generally determines the types of components that can be removed and also determines the working life of the catalyst. At higher (partial) pressures, the desulphurisation process is 'easier', however, the unit becomes more expensive for instance due to larger compressors and heavier reactors. Also, at higher pressure, the hydrogen consumption of the unit increases, which can be a signficant cost factor for the refinery. The minimum pressure required typically goes up with the required severity of the unit, i.e. the heavier the feedstock, or the lower levels of sulphur in product required.

Vacuum Distillation

To recover additional distillates from long residue, distillation at reduced pressure and high temperature has to be applied. This vacuum distillation process has become an important chain in maximising the upgrading of crude oil. As distillates, vacuum gas oil, lubricating oils and/or conversion feedstocks are generally produced. The residue from vacuum distillation - short residue - can be used as feedstock for further upgrading, as bitumen feedstock or as fuel component. The technology of vacuum distillation has developed considerably in recent decades. The main objectives have been to maximise the recovery of valuable distillates and to reduce the energy consumption of the units.At the place where the heated feed is introduced in the vacuum column - called the flash zone - the temperature should be high and the pressure as low as possible to obtain maximum distillate yield. The flash temperature is restricted to about 420 0C, however, in view of the cracking tendency of high-molecular-weight hydrocarbons. Vacuum is maintained with vacuum ejectors and lately also with liquid ring pumps. Lowest achievable vacuum in the flash zone is in the order of 10 mbar.In the older type high vacuum units the required low hydrocarbon partial pressure in the flash zone could not be achieved without the use of "lifting" steam. The steam acts in a similar manner as the stripping steam of crude distillation units. This type of units is called "wet" units. One of the latest developments in vacuum distillation has been the deep vacuum flashers, in which no steam is required. These "dry" units operate at very low flash zone pressures and low pressure drops over the column internals. For that reason the conventional reflux sections with fractionation trays have been replaced by low pressure- drop spray sections. Cooled reflux is sprayed via a number of specially designed spray nozzles in the column countercurrent to the up-flowing vapour. This spray of small droplets comes into close contact with the hot vapour, resulting in good heat and mass transfer between the liquid and vapour phase.To achieve low energy consumption, heat from the circulating refluxes and rundown streams is used to heat up the long residue feed. Surplus heat is used to produce medium and/or low-pressure steam or is exported to another process unit (via heat integration). The direct fuel consumption of a modern high-vacuum unit is approximately 1% on intake, depending on the quality of the feed. The steam consumption of the dry high-vacuum units is significantly lower than that of the "wet" units. They have become net producers of steam instead of steam consumers.Three types of high-vacuum units for long residue upgrading have been developed for commercial application:FEED PREPARATION UNITSLUBOIL HIGH- VACUUM UNITSHIGH - VACUUM UNITS FOR BITUMEN PRODUCTIONFeed Preparation UnitsThese units make a major contribution to deep conversion upgrading ("cutting deep in the barrel"). They produce distillate feedstocks for further upgrading in catalytic crackers, hydrocrackers and thermal crackers. To obtain an optimum waxy distillate quality a wash oil section is installed between feed flash zone and waxy distillate draw-off. The wash oil produced is used as fuel component or recycled to feed. The flashed residue (short residue) is cooled by heat exchange against long residue feed. A slipstream of this cooled short residue is returned to the bottom of the high-vacuum column as quench to minimise cracking (maintain low bottom temperature).Luboil High-Vacuum UnitsLuboil high vacuum units are specifically designed to produce high-quality distillate fractions for luboil manufacturing. Special precautions are therefore taken to prevent thermal degradation of the distillates produced. The units are of the "wet" type. Normally, three sharply fractionated distillates are produced (spindle oil, light machine oil and medium machine oil). Cutpoints between those fractions are typically controlled on their viscosity quality. Spindle oil and light machine oil are subsequently steam- stripped in dedicated strippers. The distillates are further processed to produce lubricating base oil. Short residue is normally used as feedstock for the solvent de-asphalting process to produce deasphalted oil, an intermediate for bright stock manufacturing.High-Vacuum Units for Bitumen ProductionSpecial vacuum flashers have been designed to produce straight-run bitumen and/or feedstocks for bitumen blowing. In principle, these units are designed on the same basis as the previously discussed feed preparation units, which may also be used to provide feedstocks for bitumen manufacturing.

Bitumen Blowing

Asphaltic bitumen, normally called "bitumen" is obtained by vacuum distillation or vacuum flashing of an atmospheric residue. This is " straight run" bitumen. An alternative method of bitumen production is by precipitation from residual fractions by propane or butane- solvent deasphalting.The bitumen thus obtained has properties which derive from the type of crude oil processed and from the mode of operation in the vacuum unit or in the solvent deasphalting unit. The grade of the bitumen depends on the amount of volatile material that remains in the product: the smaller the amount of volatiles, the harder the residual bitumen.In most cases, the refinery bitumen production by straight run vacuum distillation does not meet the market product quality requirements. Authorities and industrial users have formulated a variety of bitumen grades with often stringent quality specifications, such as narrow ranges for penetration and softening point. These special grades are manufactured by blowing air through the hot liquid bitumen in a BITUMEN BLOWING UNIT. What type of reactions take place when a certain bitumen is blown to grade? Bitumen may be regarded as colloidal system of highly condensed aromatic particles (asphaltenes) suspended in a continuous oil phase. By blowing, the asphaltenes are partially dehydrogenated (oxidised) and form larger chains of asphaltenic molecules via polymerisation and condensation mechanism. Blowing will yield a harder and more brittle bitumen (lower penetration, higher softening point), not by stripping off lighter components but changing the asphaltenes phase of the bitumen. The bitumen blowing process is not always successful: a too soft feedstock cannot be blown to an on-specification harder grade.The blowing process is carried out continuously in a blowing column. The liquid level in the blowing column is kept constant by means of an internal draw-off pipe. This makes it possible to set the air-to-feed ratio (and thus the product quality) by controlling both air supply and feed supply rate. The feed to the blowing unit (at approximately 210 0C), enters the column just below the liquid level and flows downward in the column and then upward through the draw-off pipe. Air is blown through the molten mass (280-300 0C) via an air distributor in the bottom of the column. The bitumen and air flow are countercurrent, so that air low in oxygen meets the fresh feed first. This, together with the mixing effect of the air bubbles jetting through the molten mass, will minimise the temperature effects of the exothermic oxidation reactions: local overheating and cracking of bituminous material. The blown bitumen is withdrawn continuously from the surge vessel under level control and pumped to storage through feed/product heat exchangers.

Hubbert peak theory

The Hubbert peak theory (also known as peak oil) posits that future world petroleum production will eventually peak and then decline at a similar rate to the rate of increase before the peak as these reserves are exhausted. It also suggests a method to calculate the timing of this peak, based on past production rates, past discovery rates, and proven oil reserves.
Controversy surrounds the theory for numerous reasons. Past predictions regarding the timing of the global peak have failed, causing a number of observers to disregard the theory. Further, predictions regarding the timing of the peak are highly dependent on the past production and discovery data used in the calculation.
Proponents of peak oil theory also refer as an example, that when any given oil well produces oil in similar volumes to the amount of water used to obtain the oil, it tends to produce less oil afterwards, leading to the relatively quick exhaustion and/or commercial inviability of the well in question.
The theory is applied to both individual regions and the world as a whole. Hubbert's prediction for when US oil production would peak turned out to be correct, and after this occurred in 1971 - causing the US to lose its excess production capacity - OPEC was finally able to manipulate oil prices, which led to the 1973 oil crisis. Since then, most other countries have also peaked: the United Kingdom's North Sea, for example in the late 1990s. China has confirmed that two of its largest producing regions are in decline, and Mexico's national oil company, Pemex, has announced that Cantarell Field, one of the world's largest offshore fields, was expected to peak in 2006, and then decline 14% per annum.
It is difficult to predict the oil peak in any given region, due to the lack of transparency in accounting of global oil reserves. Based on available production data, proponents have previously predicted the peak for the world to be in years 1989, 1995, or 1995-2000. Some of these predictions date from before the recession of the early 1980s, and the consequent reduction in global consumption, the effect of which was to delay the date of any peak by several years. A new prediction by Goldman Sachs picks 2007 for oil and some time later for natural gas. Just as the 1971 U.S. peak in oil production was only clearly recognized after the fact, a peak in world production will be difficult to discern until production clearly drops off.
Many proponents of the Hubbert peak theory argue that the production peak is imminent. The year 2005 saw a dramatic fall in announced new oil projects coming to production from 2008 onwards - in order to avoid the peak, these new projects would have to not only make up for the depletion of current fields, but increase total production annually to meet increasing demand.
The year 2005 also saw substantial increases in oil prices due to a number of circumstances, including war and political instability. Oil prices rose to new highs. Analysts such as Kenneth Deffeyes argue that these price increases indicate a general lack of spare capacity, and the price fluctuations can be interpreted as a sign that peak oil is imminent.

Alternative methods

During the oil price increases of 2004-2008, alternatives methods of producing oil gained importance. The most widely known alternatives involve extracting oil from sources such as oil shale or tar sands. These resources exist in large quantities; however, extracting the oil at low cost without excessively harming the environment remains a challenge.
It is also possible to chemically transform methane or coal into the various hydrocarbons found in oil. The best-known such method is the Fischer-Tropsch process. It was a concept pioneered in Nazi Germany when imports of petroleum were restricted due to war and Germany found a method to extract oil from coal. It was known as Ersatz (English:"substitute") oil, and accounted for nearly half the total oil used in WWII by Germany. However, the process was used only as a last resort as naturally occurring oil was much cheaper. As crude oil prices increase, the cost of coal to oil conversion becomes comparatively cheaper. The method involves converting high ash coal into synthetic oil in a multi-stage process.
Currently, two companies have commercialised their Fischer-Tropsch technology. Shell Oil in Bintulu, Malaysia, uses natural gas as a feedstock, and produces primarily low-sulfur diesel fuels.Sasol in South Africa uses coal as a feedstock, and produces a variety of synthetic petroleum products.
The process is today used in South Africa to produce most of the country's diesel fuel from coal by the company Sasol. The process was used in South Africa to meet its energy needs during its isolation under Apartheid. This process produces low sulfur diesel fuel but also produces large amounts of greenhouse gases.
An alternative method of converting coal into petroleum is the Karrick process, which was pioneered in the 1930s in the United States. It uses low temperatures in the absence of ambient air, to distill the short-chain hydrocarbons out of coal instead of petroleum.
Further information: Destructive distillation
More recently explored is thermal depolymerization (TDP), a process for the reduction of complex organic materials into light crude oil. Using pressure and heat, long chain polymers of hydrogen, oxygen, and carbon decompose into short-chain hydrocarbons. This mimics the natural geological processes thought to be involved in the production of fossil fuels. In theory, thermal depolymerization can convert any organic waste into petroleum substitutes.

Extraction

The most common method of obtaining petroleum is extracting it from oil wells found in oil fields. With improved technologies and higher demand for hydrocarbons various methods are applied in petroleum exploration and development to optimize the recovery of oil and gas (Enhanced Oil Recovery, EOR). Primary recovery methods are used to extract oil that is brought to the surface by underground pressure, and can generally recover about 20% of the oil present. The natural pressure can come from several different sources; where it is provided by an underlying water layer it is called a water drive reservoir and where it is from the gas cap above it is called gas drive. After the reservoir pressure has depleted to the point that the oil is no longer brought to the surface, secondary recovery methods draw another 5 to 10% of the oil in the well to the surface. In a water drive oil field, water can be injected into the water layer below the oil, and in a gas drive field it can be injected into the gas cap above to repressurize the reservoir. Finally, when secondary oil recovery methods are no longer viable, tertiary recovery methods reduce the viscosity of the oil in order to bring more to the surface. These may involve the injection of heat, vapor, surfactants, solvents, or miscible gases as in carbon dioxide flooding.

Classification

The petroleum industry classifies "crude" by the location of its origin (e.g., "West Texas Intermediate, WTI" or "Brent") and often by its relative weight or viscosity ("light", "intermediate" or "heavy"); refiners may also refer to it as "sweet," which means it contains relatively little sulfur, or as "sour," which means it contains substantial amounts of sulfur and requires more refining in order to meet current product specifications. Each crude oil has unique molecular characteristics which are understood by the use of crude oil assay analysis in petroleum laboratories.
Barrels from an area in which the crude oil's molecular characteristics have been determined and the oil has been classified are used as pricing references throughout the world. These references are known as Crude oil benchmarks.

Crude Oil

Crude oil varies greatly in appearance depending on its composition. It is usually black or dark brown (although it may be yellowish or even greenish). In the reservoir it is usually found in association with natural gas, which being lighter forms a gas cap over the petroleum, and saline water, which being heavier generally floats underneath it. Crude oil may also be found in semi-solid form mixed with sand, as in the Athabasca oil sands in Canada, where it may be referred to as crude bitumen.
Petroleum is used mostly, by volume, for producing fuel oil and gasoline (petrol), both important "primary energy" sources. 84% by volume of the hydrocarbons present in petroleum is converted into energy-rich fuels (petroleum-based fuels), including gasoline, diesel, jet, heating, and other fuel oils, and liquefied petroleum gas.
Due to its high energy density, easy transportability and relative abundance, it has become the world's most important source of energy since the mid-1950s. Petroleum is also the raw material for many chemical products, including pharmaceuticals, solvents, fertilizers, pesticides, and plastics; the 16% not used for energy production is converted into these other materials.
Petroleum (Latin Petroleum f. Latin petra f. Greek πέτρα - rock + Latin oleum f. Greek έλαιον - oil was first used in 1556 in a treatise published by the German mineralogist Georg Bauer, known as Georgius Agricola.) is a naturally occuring, flammable liquid found in rock formations in the Earth consisting of a complex mixture of hydrocarbons of various molecular weights, plus other organic compounds. The proportion of hydrocarbons in the mixture is highly variable and ranges from as much as 97% by weight in the lighter oils to as little as 50% in the heavier oils and bitumens.
The hydrocarbons in crude oil are mostly alkanes, cycloalkanes and various aromatic hydrocarbons while the other organic compounds contain nitrogen, oxygen and sulfur, and trace amounts of metals such as iron, nickel, copper and vanadium. The exact molecular composition varies widely from formation to formation but the proportion of chemical elements vary over fairly narrow Petroleum is found in porous rock formations in the upper strata of some areas of the Earth's crust. There is also petroleum in oil sands (tar sands). Known reserves of petroleum are typically estimated at around 140 km³ (1.2 trillion barrels) without oil sands, or 440 km³ (3.74 trillion barrels) with oil sands. However, oil production from oil sands is currently severely limited. Consumption is currently around 84 million barrels per day, or 3.6 km³ per year. Because the energy return over energy invested (EROEI) ratio of oil is constantly falling as petroleum recovery gets more difficult, recoverable oil reserves are significantly less than total oil-in-place. At current consumption levels, and assuming that oil will be consumed only from reservoirs, known recoverable reserves would be gone around 2039, potentially leading to a global energy crisis. However, there are factors which may extend or reduce this estimate, including the rapidly increasing demand for petroleum in China, India, and other developing nations; new discoveries; energy conservation and use of alternative energy sources; and new econonomically viable exploitation of non-conventional oil sources.