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.