Mineral oils: processes and products – Chemical conversion of hydrocarbons – Reforming
Reexamination Certificate
2001-08-08
2004-10-26
Griffin, Walter D. (Department: 1764)
Mineral oils: processes and products
Chemical conversion of hydrocarbons
Reforming
C208S134000, C208S135000, C208S136000, C208S141000, C208S265000, C208S281000, C208S295000, C208S299000, C208S307000, C208S015000
Reexamination Certificate
active
06808621
ABSTRACT:
FIELD OF THE INVENTION
The present invention is directed to a method and catalyst compounds for treating hydrocarbons, including petroleum, sour gas, as well as for extracting petroleum products from tar sands and shale and for enhancing production from conventional oil and gas wells. The compounds of the present invention can also be used to clean soil contaminated by heavy metals and/or hydrocarbons, as well to clean as polluting stack emissions. The compounds of the present invention can be used in extracting oil from plants, for eliminating bacteria, fungi, and parasites from vegetation, as well as for odor control.
BACKGROUND OF THE INVENTION
Cisneros, in U.S. Pat. No. 5,308,553, the entire contents of which are hereby incorporated by reference, discloses metal hydride compounds comprising a mixture of at least one metal selected from the group consisting of silicon, aluminum, tin, and zinc; an alkali metal hydroxide; and water. These compounds have heretofore been used for separating coal fines from coal fine waste slurries, cleaning and desludging hydrocarbon storage tanks, providing fire-retardant properties to composite materials, and protecting metal parts from corrosion.
Crude oil can be easily separated into its principal produces, i.e. gasoline, distillate fuels, and residual fuels, by simple distillation. However, neither the amounts nor quality of these natural products matches demand. The refining industry has devoted considerable research and engineering effort as well as financial resources to convert naturally occurring molecules into acceptable fuels. There is a real need to meet the tremendous demand for gasoline without overproducing other petroleum products for which there is less demand. As the price of crude oil increases, it is even more critical to be able to produce the highest value products from the crude oil.
Catalytic cracking is the primary refinery process for changing the molecular structure of the crude oil. The principal class of reactions in the fluidized bed catalytic cracking process, the one most commonly used, converts high boiling, low octane normal paraffins to lower boiling, higher octane olefins, naphthenes (cycloparaffins), and aromatics. However, naphtha converted by fluidized bed catalytic cracking may contain unacceptably high amounts of foul smelling mercaptans, and its thermal stability may be too low for it to be economically useful.
Catalytic reforming can also be used to increase the octane of gasoline components. The feed is usually naphtha boiling in the 80-210° C. range, and the catalysts used are platinum on alumina, normally with small amounts of other metals such as rhenium. Depending upon the catalysts and operating conditions, the following types of reactions occur to a greater or lesser extent:
1. Heavy paraffins lose hydrogen and form aromatic rings;
2. Cycloparaffins lose hydrogen to form corresponding aromatics;
3. Straight-chain paraffins rearrange to form isomers and
4. Heavy paraffins are hydrocracked to form lighter paraffins.
Reforming generates highly aromatic, high octane product streams and much hydrogen. The hydrogen, which can be used to improve the quality of many other refiner streams, is an extremely valuable product of reforming. However, reforming also produces benzene, polynuclear or multiring aromatics, and light gas (one to four carbon atoms). Benzene is a recognized carcinogen and its concentration in gasoline is regulated in the United States. Polynuclear aromatics can contribute to deposits in the combustion chamber of automobiles; these compounds can be removed by distilling the entire reformate and discarding the heaviest fractions.
Hydroprocessing or hydrotreatment to remove undesirable components from hydrocarbon feed streams catalytically is well know to increase the commercial value of heavy hydrocarbons. However, “heavy” hydrocarbons liquid streams, and particularly reduced crude oils, petroleum residua, tar, sand bitumen, shale oil or liquid coal or reclaimed oil, generally contain contaminants such as sulfur and/or nitrogen which deactivate catalyst particles during contact by the feed stream and hydrogen under hydroprocessing conditions. Hydroprocessing conditions are normally in the range of 212° F. to 1200° F. at pressures of from 20 to 300 atmospheres.
Since 1990, the Clean Air Act Amendment has mandated reformulation of gasoline and diesel fuel to achieve specific reductions in emissions of volatile organic compounds, toxic compounds, and carbon monoxide without increasing emissions of nitrogen oxides. Gasoline must be reformulated to have lower vapor pressure and benzene content, as well as lower total aromatics of about less than 25%, depending upon the benzene content. There are also baselines for olefins, sulfur, and 90% distillation point. Diesel fuel specifications were changed to specify a maximum of 0.05% sulfur and a minimum cetane index of 40, or a maximum aromatics content of 35% vol for on-road diesel. For off-road diesel, higher sulfur concentrations are permitted.
MTBE, methyl tertiary butyl ether, is the most widely used ingredient in reformulated gasoline. In 1999 the United States produced 4.5 billion gallons of MTBE. A gallon of gasoline contains 10% MBTE. Unfortunately, MTBE does not break down easily, and is more soluble in water than any other ingredient in gasoline. MTBE, even at low levels, gives water a turpentine odor and taste, and is now considered to be a possible carcinogen. MTBE has been found contaminating ground and surface water in all fifty states. The cost to clean up just one city in Southern California has been estimated at $100,000,000.00. The federal government has declared that MTBE will be banned by 2003 because of environmental problems and possible risks to humans.
There is a real need for a method for producing gasoline and diesel fuels that will reduce harmful emissions and retain fuel economy.
Additionally, changes in market conditions and plant operating economics require examination of traditional processes and operating procedures for petroleum products and natural gas treating applications for upgrading to more stringent standards of efficiency in order to remain competitive, while returning a satisfactory operating profit margin to the company.
A typical petroleum refinery has acid gas treating requirements for several streams, including at least one of the following:
Recovered gas to fuel produced as crude oil feed is upgraded to lighter liquid products
Ethylene concentrate prepared for feedstock
Gasoline concentrate prepared for petrochemical feedstock
Liquid LPG streams (i.e., propane, ethane, butane, etc.)
Recycle hydrogen and hydrogen desulfurizing processes
Hydrogen production for hydrocracking
Sulfur recovery unit tail gas treating
Sour water treating.
Unfortunately, the requirements for treating the above streams vary considerably. While specific solvents might be chosen for optimum treatment of each stream, in order to minimize cost, the typical refinery usually treats several streams with one solvent.
The choice of solvent may be based on individual expenses, trouble-free performance, treated product specifications, or the expectation that the overall performance will be favorable, there being more positive benefits in one solvent than liabilities. Monoethanolamine (MEA) and diethanolamine (DEA) are the more traditional solvents used in typical refinery main system acid gas removal processes.
MEA has a number of advantages as a solvent for use in refineries, including a capability of producing the lowest levels of hydrogen sulfide and carbon dioxide in the product. MEA can be partially reclaimed in the event of thermal degradation or buildup of heat stable salts. Moreover, MEA can hydrolyze carbonyl sulfide for removal. Unfortunately, MEA has high heats of reaction with hydrogen sulfide and carbon dioxide. MEA lacks selectivity, and for applications where this is a preference, energy requirements are further increased. MEA is appreciably soluble in liquid hydrocarbon streams. The potential for corrosion limits solut
Griffin Walter D.
Nguyen Tam M.
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