Mineral oils: processes and products – Asphalts – tars – pitches and resins; making – treating and... – Chemical modification of asphalt – tar – pitch or resin
Reexamination Certificate
2000-02-28
2002-06-11
Tucker, Philip (Department: 1712)
Mineral oils: processes and products
Asphalts, tars, pitches and resins; making, treating and...
Chemical modification of asphalt, tar, pitch or resin
C208S039000, C208S040000, C507S239000, C507S244000
Reexamination Certificate
active
06402934
ABSTRACT:
BACKGROUND OF THE INVENTION
The present invention relates generally to the field of petroleum production and transportation. In particular, the present invention relates to the use of certain amine-chelate complexes to reduce significantly the viscosity of heavy crude oils.
Heavy crude oils (“HCO” or “HCOs”) constitute a significant portion of the known global petroleum reserves. Vast deposits of HCOs are located in Colombia, Venezuela, Mexico and Canada. HCOs are highly viscous or solid at ambient temperature, and have a gravity of 20 or less on the API (American Petroleum Institute) density scale. HCOs include the high molecular weight hydrocarbons referred to as “tars,” “petroleum tars” or “tar sands,” such as the deposit known as the Athabasca Tar Sands in Alberta, Canada. In comparison, “conventional” or “light” crudes such as those found in the Middle East typically have API gravity of 37 or greater.
In addition to being more viscous than conventional crude oils, certain HCOs are rich in asphaltenes, metals and resins. While there is a wide variety in HCO composition and physical properties, many HCOs typically contain high levels of sulfur, nitrogen, nickel and vanadium, and are rich in the condensed polyaromatic compounds which react readily to form coke. The presence of these types of compounds in HCOs can lead to various problems in the recovery, transportation, treatment and refining of crude oils.
In order for the extraction and transportation of HCOs to be economically viable, the flow resistance of the HCO must be reduced sufficiently to enable the use of reasonably sized wellbores, pipelines and pumping equipment. Some common methods of reducing flow resistance include: heat, dilution, partial field upgrading, water-emulsification, and lubrication and core-annular flow. Heat is generally applied using steam generated at or near the well site.
The primary method for recovering HCOs from oil-bearing formations is steam injection, also know as steam flooding. Although there are numerous variations, there are two basic techniques: the “huff and puff” (or “push-pull”) involves injecting steam into a formation, alternating with back-producing the oil through the same well; and the “steam drive” involves injecting steam into a formation through one well (an “injection” well) and producing the oil from a different well (a “production” or “recovery” well). Variations include the number and type of wells, as well as their location and configuration.
The steam injection method is useful in recovery of HCOs because relatively small increases in the temperature of HCOs result in relatively large reductions in viscosity. This also explains some of the limitations and problems of this method. For example, it is expensive but necessary to locate steam generators near the injection wells. In addition, heating of the oil-bearing formation also results in heating of the adjacent rock. Third, there is a lower limit to the well depth to which the steam injection can be effectively applied, since the steam cools and liquefies as it proceeds down the well-bore. This well depth limit will depend on the particular conditions at the well site, but will generally be about 2,000 feet (600 meters). Many wells are much deeper, and are measured in terms of miles. Moreover, as the steam cools and becomes water, the crude returns to its original highly viscous state, complicated by the material being a water-oil emulsion from which the desired petroleum products are hard to separate and refine.
Alternate heat recovery methods have been developed to overcome some of the deficiencies of the steam injection methods. These include: the use of gas-fired radiant tube heaters located at the well bottom to heat the oil-bearing formation; the use of heated organic vapor in place of steam to heat the formation; and in situ exothermic reactions (i.e., alkali metals and water).
An alternative technique is to reduce viscosity by diluting the crude with less viscous hydrocarbons such as condensates, naphtha, or other solvents. Pipeline transportation usually requires blending the crude with lighter hydrocarbon diluents to obtain a kinematic viscosity of 1000 cps or less; however, supplies of diluent are insufficient to meet projected requirements.
Other chemical means for reducing HCO viscosity in oil-bearing formations include the use of solvents and surfactant systems, certain high molecular weight polymers and polysaccharide solutions. See for example, U.S. Pat. No. 4,687,586 (Argabright et al.), U.S. Pat. No. 4,425,246 (Holzwarth et al.), U.S. Pat. No. 4,192,755 (Flournoy et al.) and U.S. Pat. No. 3,964,548 (Schroeder Jr, et al.). The main problem with these chemical methods is the large volume of solvent needed (generally about 10-20% by volume of HCO).
In similar vein, U.S. Pat. No. 4,876,014 (Karydas) discloses the use of certain fluorochemical compounds having oleophobic and hydrophobic groups to reduce the viscosity of asphaltenic crude oils, optionally in combination with a low viscosity diluent.
In spite of these and numerous other methods, high viscosity and the resultant lack of flow remains problematic in the recovery of HCOs. Moreover, many of these methods are ineffective in extracting petroleum from tar sands. Last, even if the HCO can be extracted from the formation, transportation of the HCO from the well site to the refinery or to storage is often difficult and expensive. The most prevalent form of transportation from the well site is by pipeline. With HCOs, the pipelines must be heated in order to maintain the flow of oil.
Thus, there remains a need for other HCO recovery methods, especially where the means of extraction can also be used to facilitate transportation of the material from the well site.
STATEMENT OF THE INVENTION
The present invention is directed to novel amine-chelate complexes formed by heating together at least one organic amine; and at least one chelating agent. The present invention also includes compositions for reducing the viscosity of heavy crude oils, comprising 0.01-50 wt % of at least one such amine-chelate complex and an organic solvent.
The present invention is also directed to a method for recovering heavy crude oil from an oil-bearing formation having at least one well penetrating said formation and in fluid communication therewith, comprising the steps of: (a) injecting into the well and the formation a viscosity-reducing amount of an amine-chelate complex as described above; (b) allowing the amine-chelate complex to disperse into the formation; and (c) recovering the reduced viscosity oil.
In yet another aspect, the present invention is also directed to a method for reducing viscosity of heavy crude oils in significantly non-reversible manner, comprising the steps of: adding a viscosity-reducing amount of an amine-chelate complex of the present invention to a heavy crude oil, and dispersing the amine-chelate complex throughout a portion of the heavy crude oil.
DETAILED DESCRIPTION OF THE INVENTION
As used in this specification, the terms “crude” and “crude oil” are used interchangeably, and refer to unrefined petroleum. The following abbreviations are used throughout this specification: mL=milliliter; m=meter; km=kilometer; g=grams; wt %=percent by weight; ppm=parts per million; rpm=revolutions per minute; cps=centipoise; HOAc=acetic acid; EDTA=ethylenediamine tetraacetic acid; NTA=nitrilotriacetic acid. Unless otherwise indicated, all ranges (including ranges of ratios) are inclusive.
The complexes of the present invention are generally formed by heating certain organic amines with certain chelating agents. The amounts of amine and chelating agent used to form the complexes can vary greatly, depending on several factors such as the particular application, the HCO composition, and the physical properties of the HCO and the formation from which it is to be extracted; however, in general the molar equivalent ratio of amine to chelating agent acid equivalent will be in the range of
Banavali Rajiv Manohar
Chheda Bharati Dinkar
Mazza Guido
Crimaldi Kenneth
Howell Thomas J.
Rohm and Haas Company
Tucker Philip
LandOfFree
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