Refining Industry Overview

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Refining Industry Overview

Background
From 1981 to 1989, the number of U.S. refineries dropped from 324 to 204, representing a loss of 3 million barrels per day (MMbd) in operable capacity, while refining capacity utilization increased from 69% to 86%. Much of the decline in U.S. refining capacity resulted from the 1981 deregulation (elimination of price controls and allocations), which effectively removed the major prop from underneath many marginally profitable, often smaller, refineries.

It has been over 25 years since a new grass roots refinery has been built in the US. Since the mid-90's, another 50 U.S. refineries have been lost but capacity has increased, from 15.0 MMbd in 1994 to 16.8 MMbd in 2002. As of the end of 2002, utilization of operating capacity at U.S. refineries averaged 88% to 94%.

The United States is the largest producer of refined petroleum products in the world, with over 20 percent of global production and 154 of the world's 732 major operating refineries. In 2002, refineries supplied more than 6 billion barrels of finished products, employed about 65,000 people, and had shipments totaling $160 billion annually.

Petroleum

Petroleum is the single largest source of energy used in the United States. The nation uses two times more petroleum than either coal or natural gas, and four times more than nuclear power or renewable energy sources. Before petroleum can be used, it is sent to a refinery where it is physically, thermally, and chemically separated into fractions and then converted into finished products. About 90% of these products are fuels such as gasoline, aviation fuels, distillate and residual oil, liquefied petroleum gas (LPG), coke, and kerosene. Refineries also produce non-fuel products; including petrochemicals, asphalt, road oil, lubricants, solvents, and wax. Petrochemicals (ethylene, propylene, benzene, and others) are shipped to chemical plants, where they are used to manufacture chemicals and plastics.

Crude Oil Contents

Petroleum is a complex mixture of organic liquids (crude oil) and natural gas. Crude oil varies from oilfield to oilfield in color and composition, from a pale yellow low viscosity liquid to heavy black. An "average" raw crude oil contains about 84% carbon, 14% hydrogen, 1% to 3% sulfur, and less than 1% each of nitrogen, oxygen, metals, and salts. In the refinery, most of these non-hydrocarbon substances are removed and the oil is broken down into its various components, and blended into useful products.

Paraffins, Naphthenes, Aromatics

Petroleum consists of three main hydrocarbon groups. Paraffins consist of straight or branched carbon rings saturated with hydrogen atoms. Naphthenes consist of carbon rings, sometimes with side chains, saturated with hydrogen atoms. Aromatics hydrocarbons are compounds that contain a ring of six carbon atoms with alternating double and single bonds and six attached hydrogen atoms. The more carbon atoms a hydrocarbon molecule has, the "heavier" it is (the higher is its molecular weight) and the higher is its boiling point.

Petroleum Refining

A petroleum refinery is a processing plant designed to produce physical and chemical changes in crude oil to convert it into everyday products. Three basic processes are employed at most US refineries; distillation (sometimes referred to separation), conversion (cracking and coking), and treatment.

Crude Oil Pretreatment (Desalting)

Crude oil often contains water, inorganic salts, suspended solids, and water-soluble trace metals. As a first step in the refining process these contaminants must be removed by desalting (dehydration). The two most common methods of crude oil desalting are chemical and electrostatic separation.

Distillation

Two types of distillation are performed: atmospheric and vacuum. Atmospheric distillation takes place in a distilling column at or near atmospheric pressure. The desalted crude feedstock is preheated using recovered process heat. The feedstock then flows to a direct-fired crude charge heater where it is fed into the vertical distillation column just above the bottom, at pressures slightly above atmospheric and at temperatures ranging from 650° to 700° F.

As the hot vapor rises in the tower, its temperature is reduced. Heavy fuel oil or asphalt residue is taken from the bottom. At successively higher points on the tower, the various major products including lubricating oil, heating oil, kerosene, gasoline, and light gases, methane, ethane, propane and butane (which condense at lower temperatures) are drawn off.

The fractionating tower, a steel cylinder about 120 feet high, contains horizontal steel trays for separating and collecting the liquids. At each tray, vapors from below enter perforations and bubble caps. This permits the vapors to bubble through the liquid on the tray, causing some condensation at the temperature of that tray. An overflow pipe drains the condensed liquids from each tray back to the tray below, where the higher temperature causes re-evaporation. The evaporation, condensing, and scrubbing operation is repeated many times until the desired degree of product purity is reached.

In order to recover additional heavy distillates from this residue or topped crude from the atmospheric tower at higher temperatures (this allows heavy hydrocarbons with boiling points of 850°F and higher to be separated), reduced pressure is required to prevent thermal cracking. The process takes place in one or more vacuum distillation towers. The principles of vacuum distillation resemble those of fractional distillation and, except that larger diameter columns are used to maintain comparable vapor velocities at the reduced pressures, the equipment is also similar. Vacuum towers are typically used to separate catalytic cracking feedstock from surplus residuum.

Within refineries there are numerous other, smaller distillation towers called columns, designed to separate specific and unique products. Columns all work on the same principles as the towers described above. For example, a depropanizer is a small column designed to separate propane and lighter gases from butane and heavier components. Another larger column is used to separate ethyl benzene and xylene. Small "bubble" towers called strippers use steam to remove trace amounts of light products from heavier product streams.

The heavy distillates recovered by vacuum distillation can be converted into lubricating oils by a variety of processes. The most common of these is called solvent extraction. The purpose of solvent extraction is to prevent corrosion, to protect catalysts in subsequent processes, and to improve finished products by removing unsaturated, aromatic hydrocarbons from lubricant and grease stocks. The solvent extraction process separates aromatics, naphthenes, and impurities from the product stream. The selection of specific processes and chemical agents depends on the nature of the feedstock being treated, the contaminants present, and the finished product requirements.

Solvent de-waxing is used to remove wax from either distillate or residual basestocks at any stage in the refining process. There are several processes in use for solvent de-waxing.
Reforming

Reforming is a process which uses heat, pressure, and a catalyst (usually containing platinum) to bring about chemical reactions which upgrade naphthas into high octane gasoline and petrochemical feedstock. Reforming converts a portion of these compounds to isoparaffins and aromatics, which are used to blend higher octane gasoline. Paraffins are converted to isoparaffins and naphthenes, and naphthenes are converted to aromatics.

Cracking

Cracking processes break down heavier hydrocarbon molecules (high boiling point oils) into lighter products such as gasoline and diesel. These processes include catalytic cracking, thermal cracking (heat), and hydrocracking (pressure). There are three basic functions in the catalytic racking process: reaction - feedstock react with a catalyst and cracks into different hydrocarbons, regeneration - catalyst is reactivated by burning off coke, and fractionation - cracked hydrocarbon stream is separated into various products.

Catalytic cracking is used to convert heavy hydrocarbon fractions obtained by vacuum distillation into a mixture of more useful products such as gasoline and light fuel oil. In this process, the feedstock undergoes a chemical breakdown; typical temperatures are from 850° to 950°F at much lower pressures of 10 to 20 psi. The cracking reaction yields gasoline, LPG, unsaturated olefin compounds, cracked gas oils, a liquid residue called cycle oil, light gases and a solid coke residue.

Fluid catalytic cracking uses a catalyst in the form of a very fine powder, which flows like a liquid when agitated by steam, air or vapor. Feedstock entering the process immediately meets a stream of very hot catalyst and vaporizes. There are three basic functions in the catalytic cracking process: reaction - feedstock react with a catalyst and cracks into different hydrocarbons, regeneration - catalyst is reactivated by burning off coke, and fractionation - cracked hydrocarbon stream is separated into various products. The catalyst is usually a mixture of aluminum oxide and silica. Most recently, the introduction of synthetic zeolite catalysts has allowed much shorter reaction times and improved yields and octane numbers of the cracked gasolines.

Thermal cracking uses heat to break down the residue from vacuum distillation. The lighter elements produced from this process can be made into distillate fuels and gasoline. Cracked gases are converted to gasoline blending components by alkylation or polymerization. Naphtha is upgraded to high quality gasoline by reforming. Gas oil can be used as diesel fuel or can be converted to gasoline by hydrocracking. The heavy residue is converted into residual oil or coke.

The Business Of Petroleum Refining

Future Growth Prospects – North America

U.S. refining capacity is forecast by the Energy Information Administration (EIA) to increase an annual average of 0.7%. This would be from 16.9 MMbd presently to 19.8 MMbd by 2025. Although financial, environmental, and legal considerations make it unlikely that new refineries will be built in the United States, expansion at existing refineries likely will increase total U.S. refining capacity.

Natural Gas Processing

Background

The United States has estimated proven natural gas reserves of 177 trillion cubic feet (Tcf). For all of 2002, U.S. production of dry natural gas was 19.2 Tcf. The U.S. produced over 29% of the world's natural gas liquids (NGL's) in 2002 from approximately 500 major and over 250 other processing plants. The U.S. production of NGL’s was 754 million barrels (MMbbls) in 1991 and 890 MMbbls in 2000. Total US Proved Reserves of NGL’s was estimated by the EIA to be 8,000 MMbbls in 2001.

Natural Gas Processing

Natural gas, as we use it, is almost entirely methane. Natural gas as it found underground generally contains a variety of other compounds and gases, as well as oil and water. Natural gas transported through pipelines must meet purity specifications to be allowed in, so most natural gas processing occurs near the well.

Some processing can be accomplished at or near the wellhead (field processing), but the complete processing of natural gas takes place at a processing plant, usually located in a natural gas producing region. Scrubbers are often positioned near the well head to remove sand and other large-particle impurities. The natural gas is transported to these processing plants through a network of gathering pipelines, which are small-diameter, low-pressure pipes. The gathering system may have small natural gas-fired heaters installed to eliminate the formation of natural gas hydrates.

In addition to the processing done at the wellhead and at centralized processing plants, some final processing is also sometimes accomplished at "straddle" extraction plants. These plants are located on major pipeline systems. Although the natural gas that arrives at these straddle extraction plants is already of pipeline quality, there may still exist small quantities of NGL's.

Oil and Condensate Removal

In order to process and transport associated dissolved natural gas, it must be separated from the oil in which it is dissolved. This separation of natural gas from oil is most often done using equipment installed at or near the wellhead. Raw natural gas from different regions may have different compositions and separation requirements. Natural gas may be dissolved in oil underground primarily due to formation pressure.

When this natural gas and oil is produced, it may separate on its own due to decreased pressure. A separator consisting of a simple closed tank may be used. The force of gravity serves to separate the heavier liquids, oil, and the lighter natural gas. Often specialized equipment is necessary to separate oil and natural gas such as a Low-Temperature Separator (LTX) unit. These separators use pressure differentials to cool the wet natural gas and separate the oil and condensate.

Water Removal

Most of the liquid, free water associated with extracted natural gas is removed by simple separation methods at or near the wellhead. However, the removal of the water vapor that exists in solution in natural gas requires a more complex treatment. This treatment consists of dehydrating the natural gas, which usually involves either absorption or adsorption. Absorption occurs when the water vapor is removed by a dehydrating agent. Adsorption occurs when the water vapor is condensed and collected on the surface.

Absorption dehydration is known as glycol dehydration. In this process, a liquid desiccant dehydrator serves to absorb water vapor from the gas stream. Glycol, the principal agent in this process, has a chemical affinity for water. When in contact with a stream of natural gas containing water, glycol will absorb the water from the wet gas. Once absorbed, the glycol particles become heavier and sink to the bottom where they are removed.

More recently, to decrease the amount of methane and other compounds that are lost, flash tank separator-condensers are used to remove these compounds before the glycol solution reaches the boiler. A flash tank separator consists of a device that reduces the pressure of the glycol solution stream, allowing the methane and other hydrocarbons to vaporize (flash).

Solid-Desiccant Dehydration

Solid-desiccant dehydration is the primary form of dehydrating natural gas using adsorption, and usually consists of two or more adsorption towers, which are filled with a solid desiccant. Typical desiccants include activated alumina or a granular silica gel material. Solid-desiccant dehydrators are typically more effective than glycol dehydrators, and are usually installed as a type of straddle system along natural gas pipelines.

These types of dehydration systems are best suited for large volumes of gas under very high pressure, and are thus usually located on a pipeline downstream of a compressor station. Two or more towers are required to ensure unsaturated desiccant is available

Water Removal

Cryogenic Expansion Process

Cryogenic processes are also used to extract the lighter hydrocarbons, such as ethane. These processes consist of dropping the temperature of the gas stream to -120° F. A turbo expander uses external refrigerants to cool the natural gas stream. An expansion turbine is used to rapidly expand the chilled gases, which causes the temperature to drop significantly. This rapid temperature drop condenses ethane and other light hydrocarbons in the gas stream, while maintaining methane in gaseous form. This process allows for the recovery of about 90 to 95% of the ethane.

Fractionation

Once NGL's have been removed from the natural gas stream, they must be broken down into their base components to be useful. That is, the mixed stream of different NGL's must be separated out. The process used to accomplish this task is called fractionation. Fractionation works based on the different boiling points of the different hydrocarbons in the NGL stream. Essentially, fractionation occurs in stages consisting of the boiling off of hydrocarbons one by one.

Sulfur and Carbon Dioxide Removal

Natural gas from some wells contains significant amounts of sulfur and carbon dioxide and is commonly called "sour gas." Sour gas is undesirable because the sulfur compounds it contains can be extremely harmful, even lethal, to breathe and extremely corrosive. In addition, the sulfur can be extracted and marketed on its own.

Gas Sweetening

Sulfur exists in natural gas as hydrogen sulfide (H2S), and the gas is usually considered sour if the hydrogen sulfide content exceeds 5.7 milligrams of H2S per cubic meter of natural gas. The process for removing hydrogen sulfide from sour gas is commonly referred to as "sweetening." The primary process for sweetening sour natural gas is the amine process. The sour gas run through a tower, which contains the amine solution. This solution has an affinity for sulfur and absorbs it. The effluent gas is virtually free of sulfur compounds, and thus loses its sour gas status.

Gas processing is an essential part of natural gas well head to market process. Gas processing enhances natural gas use as clean and pure as possible, making it the clean burning and environmentally sound energy choice.

The Business of Gas Processing

Future Growth Prospects – North America

U.S. natural gas consumption is forecasted by the EIA to increase at an annual percentage growth rate of 1.8% from 2001 to 2025. During that period an annual production growth of 1.3% for dry natural gas is forecast for the “Reference Case Forecast.” The production of Natural Gas Plant Liquids is projected to increase at an annual growth percentage of 1.5%. This growth rate would require approximately 10 to 15 MMbbls a year in additional processing, storage, and transportation capability. Canada’s growth in dry gas shipments to the U.S. would also result in the need for additional processing capability .

Future Growth Prospects – International

The Outside North America natural gas consumption is forecasted by the EIA’s “Reference Case Forecast” to increase at an annual percentage growth rate in excess of 2% from 2001 to 2025. The production of Natural Gas Plant Liquids is projected to increase at an annual growth percentage close to the 2.0%. This growth rate would require additional processing, storage, and transportation capability.

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