CA2090306E - Oil and gas well operation fluid used for the solvation of waxes and asphaltenes, and method of use thereof - Google Patents
Oil and gas well operation fluid used for the solvation of waxes and asphaltenes, and method of use thereofInfo
- Publication number
- CA2090306E CA2090306E CA 2090306 CA2090306A CA2090306E CA 2090306 E CA2090306 E CA 2090306E CA 2090306 CA2090306 CA 2090306 CA 2090306 A CA2090306 A CA 2090306A CA 2090306 E CA2090306 E CA 2090306E
- Authority
- CA
- Canada
- Prior art keywords
- fluid
- hydrocarbon fluid
- hydrocarbon
- oil
- carbon atoms
- Prior art date
- Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
- Expired - Lifetime
Links
Classifications
-
- C—CHEMISTRY; METALLURGY
- C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
- C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
- C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
- C09K8/52—Compositions for preventing, limiting or eliminating depositions, e.g. for cleaning
- C09K8/524—Compositions for preventing, limiting or eliminating depositions, e.g. for cleaning organic depositions, e.g. paraffins or asphaltenes
Landscapes
- Chemical & Material Sciences (AREA)
- Life Sciences & Earth Sciences (AREA)
- General Life Sciences & Earth Sciences (AREA)
- Engineering & Computer Science (AREA)
- Materials Engineering (AREA)
- Organic Chemistry (AREA)
- Production Of Liquid Hydrocarbon Mixture For Refining Petroleum (AREA)
Abstract
A wax and asphaltene solvation fluid for use in oil and gas wells is derived as a residual fluid from a feedstock that includes a greater mass percentage of trimethylbenzene than decane, and is preferably sour. Mass percentage of both aromatics and asphaltenes in the residual fluid is in the 30% - 70%
range, and a complex mixture of both is described.
range, and a complex mixture of both is described.
Description
TITLE: OIL AND GAS WELL OPERATION FLUID USED FOR THE
SOLVATION OF WAXES AND ASPHALTENES, AND METHOD OF USE
THEREOF
INVENTORS: DONALD A. THORSSEN AND DWIGHT N. LOREE
FIELD OF THE INVENTION
This invention relates to oil and gas well operation fluids, particularly those used for the removal of contaminants from wells.
BACKGROUND AND SUMMARY OF THE INVENTION
The rocks that contain oil and gas in oil and gas reservoirs are porous and to remove the oil or gas from the reservoirs requires that the oil or gas move through the pores in the rock. If the pores are blocked, then it is difficult and it may even become impossible to remove the oil or gas from the reservoir, with consequent economic loss to the oil or gas well owner.
Two notorious contaminants that may block the pores are waxes and asphaltenes. A wax is normally defined as a hydrocarbon that is a solid at room temperature and has 20 carbon atoms or more. An asphaltene is an agglomerate of aromatic hydrocarbons, and may contain bound oxygen, nitrogen and sulphur atoms. The oil and gas in many, if not most, reservoirs contains both waxes and asphaltenes. These waxes and asphaltenes may be dissolved in the oil. In some cases, however, the waxes and asphaltenes may partially block the pores, or, as production continues, the very action of removing oil from a reservoir may cause waxes and asphaltenes to precipitate out of solution and block the pores.
Also, the waxes and asphaltenes may precipitate out of solution in the well bore itself, or in equipment used for the production of oil and gas and reduce or block the flow of oil from the well.
The economic damage from waxes and asphaltene precipitation can be very high, killing some wells entirely. Consequently, a great deal of attention has been devoted to developing cost effective ways of preventing waxes and asphaltenes from precipitating out of solution or of removing the waxes and asphaltenes from an oil reservoir or well bore.
One such attempt at a solution has been to apply to a well a mixture of a significant proportion of the aromatic xylene (about 45%) and a lesser proportion of the paraffinic hydrocarbon hexane (about 30%), together with about 25% methanol. This product is known by the name NP760 and is available from Wellchem of Calgary, Alberta, Canada. The xylene is intended to solvate asphaltenes and the hexane is intended to solvate waxes. The xylene and hexane components of the composition are each derived from refining a feedstock and removing that particular component from the feedstock. The result is a product that has moderate success in solvating at least some waxes and asphaltenes, but because the fluid is made from a complex process, the fluid is relatively expensive.
One difficulty with the use of hexane or other alkanes is that they tend to cause asphaltenes to precipitate out of solution. This in turn is believed to increase the precipitation of waxes. How this is believed to occur is as follows. Waxes require nucleation sites in the oil formation or well bore to which they can attach. Any such site will become a nucleation site for the further accretion of waxes. In 2û9~306 time, the waxes, mixed with asphaltenes, build outward and block the well bore or pores in the formation. In a typical oil formation water surrounds the rock in the formation and waxes will tend to slide off the water and not attach to the rock. However, if asphaltenes are present, they may attach to the rock surface since reservoir rock contains positively and negatively charged molecules (cations and anions) which attract the polar asphaltenes. The asphaltenes may then protrude beyond the water layer surrounding the rock particle and form a nucleation site for waxes. Hence a precondition for wax deposition is the precipitation of asphaltenes from the oil in the reservoir. It is the hexane that causes the precipitation of the asphaltenes and thus the formation of nucleation sites for waxes. The xylene is added to solvate the asphaltenes and prevent the formation of nucleation sites.
However, such a product, formed of an alkane (particularly pentane, hexane and heptane) and an aromatic, and similar products that are produced by the steps of: (a) refining a feedstock, (b) selectively removing hydrocarbons and (c) subsequently mixing the selected hydrocarbons, are not believed very effective in removing gummy layers of waxes and asphaltenes that are typically found in oil and gas reservoirs and well bores in relation to their cost.
The waxy depositions in oil and gas formations are complex aggregations of molecules, with many layers and globules of different waxes and asphaltenes, which the inventors have found are not readily removed by simple compositions. Such products, requiring several processing steps, tend to be expensive. Also, in some wells such mixtures of an aromatic, alkane and alcohol -4 209030~
or other polar substance may increase the precipitation of waxes and asphaltenes. Thus for example, in the general case, stabilized C5+
condensates tend to precipitate asphaltenes, with the future risk of wax contamination for the reasons just mentioned. That is to say, while it is possible to tailor a particular composition of alkanes and aromatics to a particular well formation, such a procedure is relatively expensive and may produce a product that is useful for one well formation but not for another. With the expense of the product and the risk of actually damaging the well, the application of such a product to a well is a venture not lightly undertaken.
The inventors have found a composition and a method for its use that helps to remove the uncertainty from applying wax solvating materials to wells, while at the same time significantly reducing the cost of making and using the composition. The composition is formed from a complex mixture of aromatics and alkanes (preferably C7+ ) . The complex mixture provides different components that solvate different waxes and asphaltenes. Rather than using a composition derived from selecting individual components during refining, the composition is the residue after lighter components (preferably substantially all C1, C2, C3, C4 and C5) have been removed during refining. With the appropriate selection of the feedstock, an improved wax solvating and asphaltene solvating composition may be derived.
The feedstock should be selected to have a significant proportion of aromatics and alkanes. The inventors have found that if a feedstock has a mass percentage of trimethylbenzene higher than the mass percentage of n-decane as determined by gas chromatography then the feedstock will have a sufficiently complex mixture of aromatics and alkanes for the efficient solvating of asphaltenes and waxes, particularly after the lighter ends (C1, C2, C3, C4 and C5 ) have been removed by distillation from the feedstock. By a sufficiently complex mixture of aromatics is meant aromatics other than, but not necessarily excluding, the simple aromatics benzene, toluene, ethylbenzene and xylene. These simple aromatics are the aromatics normally measured in gas chromatography since they usually yield well defined peaks. The inventors have found that it is necessary to have a good quantity of other aromatics, and the presence of these other aromatics is indicated by the quantity of trimethylbenzene.
Another indication that a feedstock contains a suitably complex blend of aromatics and alkanes to solvate complex gummy layers of waxes and asphaltenes is the presence of sulphur containing compounds in the feedstock. It is believed that sulphur is a catalyst for the conversion of alkanes to aromatics during the many years that the hydrocarbon deposit evolves underground. Hence, the more sulphur, the greater the conversion of alkanes to aromatics. Thus the presence of sulphur is an indication that the feedstock will have a suitable proportion of aromatics to alkanes.
Aromatic composition and alkane composition should be in the range 30% to 70% by mass percentage as determined by gas chromatography for a suitable composition. However, it is not believed that such a ratio of aromatics to alkanes is sufficient: the composition must be suitably complex as noted above.
E
Further, it has been found desirable that the feedstock be clear or have a light colour such as ~ "''"~
,;
-6 2~90306 amber. Dark colour indicates the presence of heavy ends (C16+) that assist in the formation of waxes. The C16+ content of the fluid should preferably be below
SOLVATION OF WAXES AND ASPHALTENES, AND METHOD OF USE
THEREOF
INVENTORS: DONALD A. THORSSEN AND DWIGHT N. LOREE
FIELD OF THE INVENTION
This invention relates to oil and gas well operation fluids, particularly those used for the removal of contaminants from wells.
BACKGROUND AND SUMMARY OF THE INVENTION
The rocks that contain oil and gas in oil and gas reservoirs are porous and to remove the oil or gas from the reservoirs requires that the oil or gas move through the pores in the rock. If the pores are blocked, then it is difficult and it may even become impossible to remove the oil or gas from the reservoir, with consequent economic loss to the oil or gas well owner.
Two notorious contaminants that may block the pores are waxes and asphaltenes. A wax is normally defined as a hydrocarbon that is a solid at room temperature and has 20 carbon atoms or more. An asphaltene is an agglomerate of aromatic hydrocarbons, and may contain bound oxygen, nitrogen and sulphur atoms. The oil and gas in many, if not most, reservoirs contains both waxes and asphaltenes. These waxes and asphaltenes may be dissolved in the oil. In some cases, however, the waxes and asphaltenes may partially block the pores, or, as production continues, the very action of removing oil from a reservoir may cause waxes and asphaltenes to precipitate out of solution and block the pores.
Also, the waxes and asphaltenes may precipitate out of solution in the well bore itself, or in equipment used for the production of oil and gas and reduce or block the flow of oil from the well.
The economic damage from waxes and asphaltene precipitation can be very high, killing some wells entirely. Consequently, a great deal of attention has been devoted to developing cost effective ways of preventing waxes and asphaltenes from precipitating out of solution or of removing the waxes and asphaltenes from an oil reservoir or well bore.
One such attempt at a solution has been to apply to a well a mixture of a significant proportion of the aromatic xylene (about 45%) and a lesser proportion of the paraffinic hydrocarbon hexane (about 30%), together with about 25% methanol. This product is known by the name NP760 and is available from Wellchem of Calgary, Alberta, Canada. The xylene is intended to solvate asphaltenes and the hexane is intended to solvate waxes. The xylene and hexane components of the composition are each derived from refining a feedstock and removing that particular component from the feedstock. The result is a product that has moderate success in solvating at least some waxes and asphaltenes, but because the fluid is made from a complex process, the fluid is relatively expensive.
One difficulty with the use of hexane or other alkanes is that they tend to cause asphaltenes to precipitate out of solution. This in turn is believed to increase the precipitation of waxes. How this is believed to occur is as follows. Waxes require nucleation sites in the oil formation or well bore to which they can attach. Any such site will become a nucleation site for the further accretion of waxes. In 2û9~306 time, the waxes, mixed with asphaltenes, build outward and block the well bore or pores in the formation. In a typical oil formation water surrounds the rock in the formation and waxes will tend to slide off the water and not attach to the rock. However, if asphaltenes are present, they may attach to the rock surface since reservoir rock contains positively and negatively charged molecules (cations and anions) which attract the polar asphaltenes. The asphaltenes may then protrude beyond the water layer surrounding the rock particle and form a nucleation site for waxes. Hence a precondition for wax deposition is the precipitation of asphaltenes from the oil in the reservoir. It is the hexane that causes the precipitation of the asphaltenes and thus the formation of nucleation sites for waxes. The xylene is added to solvate the asphaltenes and prevent the formation of nucleation sites.
However, such a product, formed of an alkane (particularly pentane, hexane and heptane) and an aromatic, and similar products that are produced by the steps of: (a) refining a feedstock, (b) selectively removing hydrocarbons and (c) subsequently mixing the selected hydrocarbons, are not believed very effective in removing gummy layers of waxes and asphaltenes that are typically found in oil and gas reservoirs and well bores in relation to their cost.
The waxy depositions in oil and gas formations are complex aggregations of molecules, with many layers and globules of different waxes and asphaltenes, which the inventors have found are not readily removed by simple compositions. Such products, requiring several processing steps, tend to be expensive. Also, in some wells such mixtures of an aromatic, alkane and alcohol -4 209030~
or other polar substance may increase the precipitation of waxes and asphaltenes. Thus for example, in the general case, stabilized C5+
condensates tend to precipitate asphaltenes, with the future risk of wax contamination for the reasons just mentioned. That is to say, while it is possible to tailor a particular composition of alkanes and aromatics to a particular well formation, such a procedure is relatively expensive and may produce a product that is useful for one well formation but not for another. With the expense of the product and the risk of actually damaging the well, the application of such a product to a well is a venture not lightly undertaken.
The inventors have found a composition and a method for its use that helps to remove the uncertainty from applying wax solvating materials to wells, while at the same time significantly reducing the cost of making and using the composition. The composition is formed from a complex mixture of aromatics and alkanes (preferably C7+ ) . The complex mixture provides different components that solvate different waxes and asphaltenes. Rather than using a composition derived from selecting individual components during refining, the composition is the residue after lighter components (preferably substantially all C1, C2, C3, C4 and C5) have been removed during refining. With the appropriate selection of the feedstock, an improved wax solvating and asphaltene solvating composition may be derived.
The feedstock should be selected to have a significant proportion of aromatics and alkanes. The inventors have found that if a feedstock has a mass percentage of trimethylbenzene higher than the mass percentage of n-decane as determined by gas chromatography then the feedstock will have a sufficiently complex mixture of aromatics and alkanes for the efficient solvating of asphaltenes and waxes, particularly after the lighter ends (C1, C2, C3, C4 and C5 ) have been removed by distillation from the feedstock. By a sufficiently complex mixture of aromatics is meant aromatics other than, but not necessarily excluding, the simple aromatics benzene, toluene, ethylbenzene and xylene. These simple aromatics are the aromatics normally measured in gas chromatography since they usually yield well defined peaks. The inventors have found that it is necessary to have a good quantity of other aromatics, and the presence of these other aromatics is indicated by the quantity of trimethylbenzene.
Another indication that a feedstock contains a suitably complex blend of aromatics and alkanes to solvate complex gummy layers of waxes and asphaltenes is the presence of sulphur containing compounds in the feedstock. It is believed that sulphur is a catalyst for the conversion of alkanes to aromatics during the many years that the hydrocarbon deposit evolves underground. Hence, the more sulphur, the greater the conversion of alkanes to aromatics. Thus the presence of sulphur is an indication that the feedstock will have a suitable proportion of aromatics to alkanes.
Aromatic composition and alkane composition should be in the range 30% to 70% by mass percentage as determined by gas chromatography for a suitable composition. However, it is not believed that such a ratio of aromatics to alkanes is sufficient: the composition must be suitably complex as noted above.
E
Further, it has been found desirable that the feedstock be clear or have a light colour such as ~ "''"~
,;
-6 2~90306 amber. Dark colour indicates the presence of heavy ends (C16+) that assist in the formation of waxes. The C16+ content of the fluid should preferably be below
2% by mass as determined by gas chromatography. If the feedstock contains greater than 2% C16+ content, then an additional cut may be taken to remove all or substantially all the higher ends.
Alternatively, the fluid may be formulated for pure asphaltene solvation. Pure asphaltene generally occurs in only two situations in the reservoir. In one case, pyrobitumen can be present ingas reservoirs. This is generally believed to have been deposited long ago when oil which had occupied the reservoir migrated out and left the pyrobitumen 15- behind. This pyrobitumen can move during production and plug the formation or wellbore.
Another case is in tertiary recovery using hydrocarbon miscible solvents floods. Light hydrocarbons in the C2 to C5 range are injected into the reservoir to push the oil to production wells.
While these light hydrocarbons will solvate paraffinic molecules they act to precipitate asphaltenic molecules. Thus asphaltene will precipitate without heavy paraffinic molecules present.
The-fluid is formulated for solvating pure asphaltenes by increasing the temperature of the cutpoint. This removes the C6 and C7 components which contain a lower percentage of aromatics than the bulk residue. The aromatics in this region are small and not as effective as the more complex aromatics in the remainder of the fluid.
Asphaltenes are normally colloidally suspended in crude oil by peptizing resins (maltenes).
These peptizing resins are aromatic and polar at one ~-- 2090306 end and paraffinic or neutral at the other end. The polar end is attracted to the asphaltene and the nonpolar end to the crude oil. When the solid asphaltene is completely surrounded by peptizing resins it becomes a colloidally suspended particule completely suspended in the crude oil.
Currently the main way of treating these precipitations is by injecting pure xylene down a well. Xylene is a simple aromatic with short paraffinic side chains. The more complex aromatics in the C8+ fluid described here with longer side chains provide superior emulation of the maltenes that originally suspended the asphaltene molecules than just pure xylene.
BRIEF DESCRIPTION OF THE FIGURES
Figs. 1 and 2, and tables 2 and 3, are gas chromatographic profiles of preferred compositions of the feedstock from which the fluid according to the invention may be derived. Fig. 1 (Table 2) is a gas chromatograph profile of the C5+ feed from the Wildcat Hills plant in Alberta, Canada. Fig. 2 (Table 3) is a gas chromatograph profile of the C5+ feed from the Jumping Pound plant in Alberta, Canada. The trimethylbenzene marker is indicated at lO and the n-decane marker is indicated at 12 in each figure.
DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS
As used in this patent document: a residual fluid is a fluid that remains after light components (particularly Cl, C2, C3, C4 and C5 components) of a hydrocarbon feedstock are removed during the refining of the hydrocarbon feedstock; a hydrocarbon feedstock i8 a hydrocarbon fluid that has been produced directly from an oil or gas bearing formation; sour means -which the fluid according to the invention is derived should -20903~6 sulphur containing. Cn+ indicates no greater than a small percentage (less than 5%) of Cl, C2, ... Cn_1.
The preferred composition is a residual hydrocarbon fluid derived from a hydrocarbon feedstock having a complex mixture of aromatics. Complex in this context means that there are included in the mixture aromatics other than benzene, toluene, ethylbenzene and xylene, such as methylethylbenzene, diethylbenzene and propylethylbenzene, to name but a few of the possibilities, although the mixture may also include the simple aromatics. The hydrocarbon feedstock from which the fluid according to the invention is derived should contain a greater percentage of trimethylbenzene than n-decane, in which case it is believed that the fluid will have the desirable wax and asphaltene solvating properties. It should be noted that these aromatics, other than benzene, toluene, ethylbenzene and xylene, are not readily identifiable using gas chromatography, and so having the trimethylbenzene peak higher than n-decane is the manner in which the appropriate feedstock may be identified. The feedstock is preferably but not necessarily refined to remove essentially all C1, C2, C3, C4 and C5 components. It is not necessary that the feedstock have a relatively low ratio of alkanes if the alkanes are concentrated in the lighter ends and the lighter ends are removed by distillation. The feedstock is preferably sour and clear or light amber, with sulphur content exceeding 1500 ppm, and preferably has no more than about 2% C16+. In general, it is believed that the more sulphonated the feedstock, the better for asphaltene solvation. If the C16+ content is greater than 2%, a further cut should preferably be taken to remove the higher ends.
-To produce the formulation of the invention from the feedstocks shown in Figs. 1 and 2, the feedstocks are refined to remove substantially all of the Cl. C2, C3, C4 and C5 components, with a small percentage of C6, C7 and C8.
With a 120C cut, the resulting fluid, as determined by gas chromatography, has about 0.1%
pentane, 7% hexanes, 13% heptanes, 13% octanes, 7%
nonanes, 9% decanes, 5% undecanes, 3% dodecanes, 2%
tridecanes, 1% tetradecanes, 0.6% pentadecanes, 0.3%
hexadecanes, 0.1% heptadecanes, 0.05% octadecanes, 1%
benzene, 9% toluene, 12% ethyl benzene and meta- and para xylene, 2.6% ortho-xylene, 2.2% 1,2,4 trimethylbenzene, 0.1% cyclopentane, 2%
methylcyclopentane, 2.6% cyclohexane, 8%
methylcyclohexane and less than 0.05% of any other constituent, including cumulatively less than 0.1%
C19+. Naphthene content is greater than about 3%.
With a 130C cut, the resulting fluid, as determined by gas chromatography, has about 0%
pentanes, 2% hexanes, 13% heptanes, 13% octanes, 7%
nonanes, 9% decanes, 5% undecanes, 3% dodecanes, 2%
tridecanes, 1% tetradecanes, 0.5~ pentadecanes, 0.2%
hexadecanes, 0.1% heptadecanes, 0.05% octadecanes, 1.5% benzene, 12.6% toluene, 15% ethyl benzene and meta- and para xylene, 2.4% ortho-xylene, 2.2% 1,2,4 trimethylbenzene, 0% cyclopentanes, 1%
methylcyclopentane, 1.9% cyclohexane, 7.8%
methylcyclohexane and less than 0.05% of any other constituent, including cumulatively less than 0.1%
C19+. It will be observed that with the higher cut, all of the remaining pentane, and more than 2/3 of the hexanes have been removed while the aromatic content has increased.
With a 140C cut, the resulting fluid, as determined by gas chromatography, has about 0%
pentanes, 0.3% hexanes, 8.7% heptanes, 13.5% octanes, 6.7% nonanes, 10.7% decanes, 6% undecanes, 4%
dodecanes, 2% tridecanes, 1% tetradecanes, 0.6%
pentadecanes, 0.3% hexadecanes, 0.1% heptadecanes, 0.06% octadecanes, 0.6% benzene, 13.7% toluene, 17.9%
ethyl benzene and meta- and para xylene, 2.7% ortho-xylene, 2.7% 1,2,4 trimethylbenzene, 0% cyclopentanes, 0.3% methylcyclopentane, 0.7% cyclohexane, 7%
methylcyclohexane and less than 0.1% of any other constituent, including cumulatively less than 0.05%
cl9+ .
With a 150C cut, the resulting fluid, as determined by gas chromatography, has about 0%
pentanes, 0.01% hexanes, 2.5% heptanes, 14.4% octanes, 9.5% nonanes, 14.1% decanes, 8.1% undecanes, 5.2%
dodecanes, 3.1% tridecanes, 1.8% tetradecanes, 1%
pentadecanes, 0.4% hexadecanes, 0.2% heptadecanes, 0.1% octadecanes, 0.01% benzene, 8.3% toluene, 20.3%
ethyl benzene and meta- and para xylene, 3.5% ortho-xylene, 3.5% 1,2,4 trimethylbenzene, 0% cyclopentane, 0% methylcyclopentane, 0.07% cyclohexane, 3.7%
methylcyclohexane and less than 0.05% of any other constituent, including cumulatively less than 0.1%
cl9+ .
With a 160C cut, the resulting fluid, as determined by gas chromatography, has about 0%
pentanes, 0% hexanes, 0.2% heptanes, 7.9% octanes,
Alternatively, the fluid may be formulated for pure asphaltene solvation. Pure asphaltene generally occurs in only two situations in the reservoir. In one case, pyrobitumen can be present ingas reservoirs. This is generally believed to have been deposited long ago when oil which had occupied the reservoir migrated out and left the pyrobitumen 15- behind. This pyrobitumen can move during production and plug the formation or wellbore.
Another case is in tertiary recovery using hydrocarbon miscible solvents floods. Light hydrocarbons in the C2 to C5 range are injected into the reservoir to push the oil to production wells.
While these light hydrocarbons will solvate paraffinic molecules they act to precipitate asphaltenic molecules. Thus asphaltene will precipitate without heavy paraffinic molecules present.
The-fluid is formulated for solvating pure asphaltenes by increasing the temperature of the cutpoint. This removes the C6 and C7 components which contain a lower percentage of aromatics than the bulk residue. The aromatics in this region are small and not as effective as the more complex aromatics in the remainder of the fluid.
Asphaltenes are normally colloidally suspended in crude oil by peptizing resins (maltenes).
These peptizing resins are aromatic and polar at one ~-- 2090306 end and paraffinic or neutral at the other end. The polar end is attracted to the asphaltene and the nonpolar end to the crude oil. When the solid asphaltene is completely surrounded by peptizing resins it becomes a colloidally suspended particule completely suspended in the crude oil.
Currently the main way of treating these precipitations is by injecting pure xylene down a well. Xylene is a simple aromatic with short paraffinic side chains. The more complex aromatics in the C8+ fluid described here with longer side chains provide superior emulation of the maltenes that originally suspended the asphaltene molecules than just pure xylene.
BRIEF DESCRIPTION OF THE FIGURES
Figs. 1 and 2, and tables 2 and 3, are gas chromatographic profiles of preferred compositions of the feedstock from which the fluid according to the invention may be derived. Fig. 1 (Table 2) is a gas chromatograph profile of the C5+ feed from the Wildcat Hills plant in Alberta, Canada. Fig. 2 (Table 3) is a gas chromatograph profile of the C5+ feed from the Jumping Pound plant in Alberta, Canada. The trimethylbenzene marker is indicated at lO and the n-decane marker is indicated at 12 in each figure.
DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS
As used in this patent document: a residual fluid is a fluid that remains after light components (particularly Cl, C2, C3, C4 and C5 components) of a hydrocarbon feedstock are removed during the refining of the hydrocarbon feedstock; a hydrocarbon feedstock i8 a hydrocarbon fluid that has been produced directly from an oil or gas bearing formation; sour means -which the fluid according to the invention is derived should -20903~6 sulphur containing. Cn+ indicates no greater than a small percentage (less than 5%) of Cl, C2, ... Cn_1.
The preferred composition is a residual hydrocarbon fluid derived from a hydrocarbon feedstock having a complex mixture of aromatics. Complex in this context means that there are included in the mixture aromatics other than benzene, toluene, ethylbenzene and xylene, such as methylethylbenzene, diethylbenzene and propylethylbenzene, to name but a few of the possibilities, although the mixture may also include the simple aromatics. The hydrocarbon feedstock from which the fluid according to the invention is derived should contain a greater percentage of trimethylbenzene than n-decane, in which case it is believed that the fluid will have the desirable wax and asphaltene solvating properties. It should be noted that these aromatics, other than benzene, toluene, ethylbenzene and xylene, are not readily identifiable using gas chromatography, and so having the trimethylbenzene peak higher than n-decane is the manner in which the appropriate feedstock may be identified. The feedstock is preferably but not necessarily refined to remove essentially all C1, C2, C3, C4 and C5 components. It is not necessary that the feedstock have a relatively low ratio of alkanes if the alkanes are concentrated in the lighter ends and the lighter ends are removed by distillation. The feedstock is preferably sour and clear or light amber, with sulphur content exceeding 1500 ppm, and preferably has no more than about 2% C16+. In general, it is believed that the more sulphonated the feedstock, the better for asphaltene solvation. If the C16+ content is greater than 2%, a further cut should preferably be taken to remove the higher ends.
-To produce the formulation of the invention from the feedstocks shown in Figs. 1 and 2, the feedstocks are refined to remove substantially all of the Cl. C2, C3, C4 and C5 components, with a small percentage of C6, C7 and C8.
With a 120C cut, the resulting fluid, as determined by gas chromatography, has about 0.1%
pentane, 7% hexanes, 13% heptanes, 13% octanes, 7%
nonanes, 9% decanes, 5% undecanes, 3% dodecanes, 2%
tridecanes, 1% tetradecanes, 0.6% pentadecanes, 0.3%
hexadecanes, 0.1% heptadecanes, 0.05% octadecanes, 1%
benzene, 9% toluene, 12% ethyl benzene and meta- and para xylene, 2.6% ortho-xylene, 2.2% 1,2,4 trimethylbenzene, 0.1% cyclopentane, 2%
methylcyclopentane, 2.6% cyclohexane, 8%
methylcyclohexane and less than 0.05% of any other constituent, including cumulatively less than 0.1%
C19+. Naphthene content is greater than about 3%.
With a 130C cut, the resulting fluid, as determined by gas chromatography, has about 0%
pentanes, 2% hexanes, 13% heptanes, 13% octanes, 7%
nonanes, 9% decanes, 5% undecanes, 3% dodecanes, 2%
tridecanes, 1% tetradecanes, 0.5~ pentadecanes, 0.2%
hexadecanes, 0.1% heptadecanes, 0.05% octadecanes, 1.5% benzene, 12.6% toluene, 15% ethyl benzene and meta- and para xylene, 2.4% ortho-xylene, 2.2% 1,2,4 trimethylbenzene, 0% cyclopentanes, 1%
methylcyclopentane, 1.9% cyclohexane, 7.8%
methylcyclohexane and less than 0.05% of any other constituent, including cumulatively less than 0.1%
C19+. It will be observed that with the higher cut, all of the remaining pentane, and more than 2/3 of the hexanes have been removed while the aromatic content has increased.
With a 140C cut, the resulting fluid, as determined by gas chromatography, has about 0%
pentanes, 0.3% hexanes, 8.7% heptanes, 13.5% octanes, 6.7% nonanes, 10.7% decanes, 6% undecanes, 4%
dodecanes, 2% tridecanes, 1% tetradecanes, 0.6%
pentadecanes, 0.3% hexadecanes, 0.1% heptadecanes, 0.06% octadecanes, 0.6% benzene, 13.7% toluene, 17.9%
ethyl benzene and meta- and para xylene, 2.7% ortho-xylene, 2.7% 1,2,4 trimethylbenzene, 0% cyclopentanes, 0.3% methylcyclopentane, 0.7% cyclohexane, 7%
methylcyclohexane and less than 0.1% of any other constituent, including cumulatively less than 0.05%
cl9+ .
With a 150C cut, the resulting fluid, as determined by gas chromatography, has about 0%
pentanes, 0.01% hexanes, 2.5% heptanes, 14.4% octanes, 9.5% nonanes, 14.1% decanes, 8.1% undecanes, 5.2%
dodecanes, 3.1% tridecanes, 1.8% tetradecanes, 1%
pentadecanes, 0.4% hexadecanes, 0.2% heptadecanes, 0.1% octadecanes, 0.01% benzene, 8.3% toluene, 20.3%
ethyl benzene and meta- and para xylene, 3.5% ortho-xylene, 3.5% 1,2,4 trimethylbenzene, 0% cyclopentane, 0% methylcyclopentane, 0.07% cyclohexane, 3.7%
methylcyclohexane and less than 0.05% of any other constituent, including cumulatively less than 0.1%
cl9+ .
With a 160C cut, the resulting fluid, as determined by gas chromatography, has about 0%
pentanes, 0% hexanes, 0.2% heptanes, 7.9% octanes,
3~ 9.8% nonanes, 18.6% decanes, 10.8% undecanes, 6.9%
dodecanes, 4.1% tridecanes, 2.3% tetradecanes, 1.2%
pentadecanes, 0.5% hexadecanes, 0.2% heptadecanes, 0.1% octadecanes, 0% benzene, 2.2% toluene, 25.3%
ethyl benzene and meta- and para xylene, 4.2% ortho-11 2~90306 xylene, 5.0% 1,2,4 trimethylbenzene, 0% cyclopentane, 0% methylcyclopentane, 0% cyclohexane, 0.5%
methylcyclohexane and less than 0.05% of any other constituent, including an undetectable amount of C19+.
For each of the 120C, 130C, 140C, 150C
and 160C cuts, all percentages are mass fraction.
Only simple aromatics are identified. Supercritical fluid chromatography shows that the actual aromatic content is greater than 40%. For C5 to Cl8, the percentage given is the sum of the peaks from the gas chromatographic analysis. Thus, the figure for "decanes" includes the figure for straight chain decane. The higher cuts show increased percentages of C8 and Cl0, and increased xylene, particularly the 150C cut. The 130C cut is preferred for wax and asphaltene solvation. For the 120C cut, the fluid is amber in colour with a density of 780kg/m3. Boiling point at 1 atm is 100-300C, freezing point about -60C, vapour pressure <15kpa, with a closed cup flaxh point of >10C. As a flammable amd toxic liquid, this fluid should be treated with well known safety precautions. At the higher cuts (150C cut), effectively all of the C6 and C7 iS removed, with consequent increase in the xylene content to over 25%.
Such a fluid is useful for pure asphaltene solvation.
Thus a preferred composition of the invention has less than 1% cumulatively of methane, ethane, propane, butane and pentane; 0 to 10% hexanes;
1 to 15% heptanes; 5 to 15% octanes; 5 to 15% nonanes;
5 to 15~ decanes; 3 to 10~ undecanes; 1 to 7%
dodecanes; 0 to 5% tridecanes; 0 to 3% tetradecanes;
0 to 2~ pentadecanes; 0 to 1% hexadecanes; 0 to 1%
heptadecanes; 0 to 1~ octadecanes; 0 to 3~ benzene; 5 to 20% toluene; 10 to 35% xylenes; 1 to 5%
12 205030~
1,2,4trimethylbenzene; and cumulatively less than 2%
C16+, all of the percentages being mass fraction as determined by gas chromatography. In another preferred composition according to the invention, the fluid includes less than 5% hexanes; O to 15% heptanes; O to 15% octanes; 5 to 15% nonanes; 5 to 25% decanes; 3 to 15% undecanes; 2 to 10% dodecanes; O to 5% tridecanes;
O to 3% tetradecanes; O to 2% pentadecanes; O to 1%
hexadecanes; O to 1% heptadecanes; O to 1%
octadecanes; O to 3% benzene; 5 to 15% toluene; 15 to 40% xylenes; and 1 to 896 1,2,4trimethylbenzene.
Solvation tests using the formulation according to the invention have yielded the following results.
Table 1 No. Location SolventContaminant %
Dissolved 1. 08-20-044-04W5 #81.0284 86.8 2. 02-09-039-07 #80.9714 98.2 3. 02-20-039-07 #80.9959 97.0
dodecanes, 4.1% tridecanes, 2.3% tetradecanes, 1.2%
pentadecanes, 0.5% hexadecanes, 0.2% heptadecanes, 0.1% octadecanes, 0% benzene, 2.2% toluene, 25.3%
ethyl benzene and meta- and para xylene, 4.2% ortho-11 2~90306 xylene, 5.0% 1,2,4 trimethylbenzene, 0% cyclopentane, 0% methylcyclopentane, 0% cyclohexane, 0.5%
methylcyclohexane and less than 0.05% of any other constituent, including an undetectable amount of C19+.
For each of the 120C, 130C, 140C, 150C
and 160C cuts, all percentages are mass fraction.
Only simple aromatics are identified. Supercritical fluid chromatography shows that the actual aromatic content is greater than 40%. For C5 to Cl8, the percentage given is the sum of the peaks from the gas chromatographic analysis. Thus, the figure for "decanes" includes the figure for straight chain decane. The higher cuts show increased percentages of C8 and Cl0, and increased xylene, particularly the 150C cut. The 130C cut is preferred for wax and asphaltene solvation. For the 120C cut, the fluid is amber in colour with a density of 780kg/m3. Boiling point at 1 atm is 100-300C, freezing point about -60C, vapour pressure <15kpa, with a closed cup flaxh point of >10C. As a flammable amd toxic liquid, this fluid should be treated with well known safety precautions. At the higher cuts (150C cut), effectively all of the C6 and C7 iS removed, with consequent increase in the xylene content to over 25%.
Such a fluid is useful for pure asphaltene solvation.
Thus a preferred composition of the invention has less than 1% cumulatively of methane, ethane, propane, butane and pentane; 0 to 10% hexanes;
1 to 15% heptanes; 5 to 15% octanes; 5 to 15% nonanes;
5 to 15~ decanes; 3 to 10~ undecanes; 1 to 7%
dodecanes; 0 to 5% tridecanes; 0 to 3% tetradecanes;
0 to 2~ pentadecanes; 0 to 1% hexadecanes; 0 to 1%
heptadecanes; 0 to 1~ octadecanes; 0 to 3~ benzene; 5 to 20% toluene; 10 to 35% xylenes; 1 to 5%
12 205030~
1,2,4trimethylbenzene; and cumulatively less than 2%
C16+, all of the percentages being mass fraction as determined by gas chromatography. In another preferred composition according to the invention, the fluid includes less than 5% hexanes; O to 15% heptanes; O to 15% octanes; 5 to 15% nonanes; 5 to 25% decanes; 3 to 15% undecanes; 2 to 10% dodecanes; O to 5% tridecanes;
O to 3% tetradecanes; O to 2% pentadecanes; O to 1%
hexadecanes; O to 1% heptadecanes; O to 1%
octadecanes; O to 3% benzene; 5 to 15% toluene; 15 to 40% xylenes; and 1 to 896 1,2,4trimethylbenzene.
Solvation tests using the formulation according to the invention have yielded the following results.
Table 1 No. Location SolventContaminant %
Dissolved 1. 08-20-044-04W5 #81.0284 86.8 2. 02-09-039-07 #80.9714 98.2 3. 02-20-039-07 #80.9959 97.0
4. 10-13 (Viking) #81.0033 87.4
5. 06-10-035-06W4 #81.0280 96.2
6. 10-13 (Viking) #100.9972 63.2
7. 06-10-035-06W4 #100.9547 ~.2
8. 10-24-001-26 #81.0005 71.7
9. 8" Group Line #81.0004 ffl.6
10. 11-14-041-25 #81.0017 76.8
11. 08-14-041-25 #81.0567 935
12. 11-14-041-25 #91.0011 81.1
13. OB-14-041-25 #90.9987 97.2
14. Utikuma Keg R. #80.9536 63.0
15. Utikuma Slave #81.0221 g3.2
16. Hutton 12-18 #81.0543 83.2
17. 10-18-048-08W5 #81.1200 97.8 1~. 12-24-047-Og W4 #160.97S6 993 19. 12C-19-036-04 #80.4624 87.3@22C
20. 16-01-004-21W3 #80.2992 75.2@22C
21. Intensity Res. #80.9845 97.1 22. 05-03-055-13W5 #80.9904 96.6 23. 16-14-055-13W5 #81.0509 21.4 23a. 16-14-055-13W5 Toluene 1.0458 * 38.1 24. Esso Wizard Lk. 90/10 0.9813 933 25. Esso Wizard Lk. #8 0.9940 96.6 26. Esso Wizard Lk. Run 95 1.0018 913 27. Esso Wizard Lk. 90/lOXy 0.9726 97.0 28. Esso Wizard Lk. lOOXy 0.9676 965 29. 16-03-040-04W5 #8 1.0485 8~5 30. 16-03-040-04W5 #9 1.0264 96.1 31. 046-09W5 Comaplex #8 1.0545 76.1 32. 046-09W5 Comaplex #9 0.9974 ~.6 33. 07-11-053-26 #8 1.0292 979 34a. 16-19-071-04Chevron #8 0.9756 94.4 34b. 02-06-072-04Chevron #8 1.0014 98.7 34c. 16-19-071-04Chevron lOOXylene O.9588 ~;.7 35. 02-06-072-04Chevron lOOXylene 1.4169 933 36. Chauvco Unit No. 2 #8 0.9799 97.6 37. 06-10-035-03W5 #8 0.9548 665 38. 08-20-026-12W4 #8 1.10157 ~2 39. 03-13-044-09Amoco #8 1.0397 82.9 40. 04-22-043-08Amoco #8 0.9671 94.1 41. 02-05-043-08Amoco #8 1.0202 93.8 42. 03-13-044-09Amoco #9 0.9975 72.5 43. 04-22-043-08Amoco #9 0.9760 96.1 44. 02-05-043-08Amoco ~9 1.0372 55.3 45. Willesden Green #8 1.0127 94.1 Notes to Table 1: Wax or asphaltene amount is listed in grams under the heading "contaminant".
The sample is indicated by the location of the well, in the Province of Alberta, Canada, from which the sample was derived. % dissolved is the percentage of the original sample that was dissolved in the solvent.
It is a general indicator of the effectiveness of the solvent on that particular composition of contaminant.
The amount of solvent used was lOOmL. #8 and #16 is the fluid described above as the 120C cut. #9 is a blend of NP760tm and 10% Super A Soltm, which is available from Wellchem of Calgary, Alberta, Canada.
#10 is Petro Rep condensate having about 15% butanes, 46% pentanes, 19% hexanes and less than 1% aromatics as determined by gas chromatography. Run 95 is 100%
FRACSOL well site operation fluid available from Trisol Inc., of Calgary, Alberta. 90/10 is 90% of the 120C cut with 10% of a non-aromatic brominated non-fluorinated hydrocarbon such as dibromomethane.
90/lOXy is 90~ of the 150C cut described above with 10% of a non-aromatic brominated non-fluorinated hydrocarbon such as dibromomethane. lOOXy is 100% of the 150C cut described above. lOOXylene is pure xylene. Toluene is pure toluene. The oils from which some of the contaminants precipitated so far as known have the following composition: Sample 1. 8.26%
asphaltene, 11.2% wax; Sample 4. 10% asphaltene;
Sample 5. 23% asphaltene; Sample 22. 1.11% asphaltene, 4.7% wax; Sample 34c. 6.12% asphaltene, 2.9% wax;
Sample 36. 3.43% asphaltene, 3.8% wax.
These results show that the formulation of the present invention provides comparable solvation properties to highly refined and expensive wax solvation products when applied to a variety of wells without specifically formulating the composition to the well formation.
By comparison with the product of the present invention, so far as known, the condensate available from other gas plants located in the Province of Alberta is not desirable for use as a wax and asphaltene removing fluid. Thus, for condensate from Amerada Hess (Bearberry~, while the fluid is clear, showing low heavy ends, the aromatic content is too low by comparison with the light ends for a useful feedstock. Condensate from the Can-Oxy Mazeppa plant is dark red from the plant, which becomes black when the lighter ends are removed, that is, when a C7+ cut is taken, thus indicating the presence of undesirable heavy ends. Condensate from the Burnt Timber plant has too many heavy ends to work as a solvent, but may be formation compatible in some wells. Condensate from the Brazeau plant has too few aromatics, and too many waxes to be useful as a solvent. Condensate from Mobil Oil Lone Pine Creek has 6~ xylene, which might suggest it is similar to the Jumping Pound feed (6.5% xylene).
However, the relative lower percentage of lighter ends means that the concentration of xylene and other aromatics does not increase greatly if the lighter ends are removed in accordance with the principles of the invention. Consequently, the feed is not very useful as a solvent. Condensate from the Husky OIl Ram River plant has too many heavy ends, as indicated by its dark colour, and has too few aromatics to make it a useful feed for a solvent.
In the method of the invention, a C5+
hydrocarbon feedstock is obtained in which feedstock the mass percentage of trimethylbenzene exceeds the mass percentage of decane as determined by gas chromatography; and substantially all hydrocarbons having 1, 2, 3, 4 and 5 carbon atoms are removed, thereby producing a residual fluid, effectively a C7+
fluid. The fluid is applied to a well as follows.
For pumping or flowing wells, the well should be de-waxed before attempting to clean up the formation. To clean a pumping well, an amount of the fluid of the invention equal to about one half of the tubing volume should be circulated in the well with a bottomhole pump for about 24 hours. To clean the nearby well bore formation, a squeeze volume (1.0 -1.5 m3 per meter of perforations) of the fluid according to the invention should be squeezed into the formation with a clean, formation compatible fluid.
Preferably, the displacement fluid should be filtered to remove fines. After the fluid has been squeezed into the formation, the well should be shut in, and 16 ~o9 o306 the fluid allowed to stand for 12 hours before putting the well back on pump.
To clean a partially plugged flowing well, a volume of the fluid according to the invention equal to one half o the tubing volume should be injected down the tubing string and allowed to soak for 24 hours. The well may then be placed back on production and tested.
To clean a completely plugged well, an attempt should be made to solubilize the plug by injecting a volume of the fluid according to the invention down the tubing string. If the plug can be solubilized, then the well should be allowed to soak for 24 hours and the well may be placed back on production and tested. If the plug cannot be solubilized, then the plug may be removed by such procedures as drilling or jetting with coiled tubing, using the fluid according to the invention as the jetting fluid. The well may then be placed back on production and evaluated.
To squeeze a flowing well in which the tubing is set in a packer, it is preferred to inject the fluid according to the invention directly through the perforations into the well bore using coiled tubing. This helps to prevent well fluid entrained solids from being re-injected into the well. If this procedure is not viable, then an attempt may be made to force the fluid according to the invention through the tubing into the formation with a clean formation compatible chase fluid. Care should be taken not to overflush the chase fluid into the formation.
To squeeze a flowing well in which the tubing is not set in a packer, it is preferred to squeeze a squeeze volume of the fluid according to the invention down the annulus to the perforations. The flowline should be kept open until the resident annulus fluid has been displaced up the tubing into the flowline. Typical squeeze volumes are 1.0 - 1.5 m3 of the fluid according to the invention per meter of perforations. Once the fluid is in the annulus, the tubing valve may be closed and the fluid squeezed into the formation with a clean formation compatible fluid (which should not be overflushed). In either case (with or without the tubing set in a packer), the well may be shut in, allowed to soak and after 24 hours or so, placed back on production and tested.
If a flowing well does not flow after treatment, it may be desirable at that point to swab the well.
The formulation of the present invention, identified by Trisol Inc.ls tradename WAXSOL is preferably pumped into the well at below fracturing pressures. Pumping is carried out at ambient temperature. As known in the art, since the formulation of the invention is aromatic rich, contact with elastomeric components in the well should be minimized. For removal of the formulation of the invention from the well, high (maximum) pump speeds are recommended to aid in preventing the plugging of downhole pumps by release of fines and scale from downhole wax as it is dissolved.
A person skilled in the art could make immaterial modifications to the invention described and claimed in this patent without departing from the essence of the invention.
TABLE 2 (PART I) RT AREA% NAME RT AREA% NAME
3.202 .07S08 iC4 14.970 .09517 3.912 .35699 nC4 15.048 .08244 5.784 2.69133 iC5 15.195 .49210 6.514 2.72246 nC5 15.370 .75489 7.492 .67313 Cyclopentane 15.510 .46649 8.340 .89997 15.759 .45354 m+p xylene 8.487 3.99820 16.000 10.08547 m+p xylene 8.875 2.17882 16.157 .54391 9.377 6.74750 C6 16.504 1.51593 oxylene 10.097 2.47707 Methyl 16.615 .14003 cyclopentane 16.742 1.95847 C9 10.340 .08951 17.068 .12964 10.752 3.93949 Benzene 17.161 .14645 10.887 .18034 17.366 .27271 11.012 2.71877 Cyclohexane 17.508 .58216 11.201 2.88368 17.822 .17800 11.428 2.21393 17.946 .79982 11.641 .47199 18.105 1.68490 11.774 1.38668 18.245 .29447 12.062 4.72465 C7 18.347 .13771 12.688 6.65060 Methyl 18.493 .12346 cyclohexane
20. 16-01-004-21W3 #80.2992 75.2@22C
21. Intensity Res. #80.9845 97.1 22. 05-03-055-13W5 #80.9904 96.6 23. 16-14-055-13W5 #81.0509 21.4 23a. 16-14-055-13W5 Toluene 1.0458 * 38.1 24. Esso Wizard Lk. 90/10 0.9813 933 25. Esso Wizard Lk. #8 0.9940 96.6 26. Esso Wizard Lk. Run 95 1.0018 913 27. Esso Wizard Lk. 90/lOXy 0.9726 97.0 28. Esso Wizard Lk. lOOXy 0.9676 965 29. 16-03-040-04W5 #8 1.0485 8~5 30. 16-03-040-04W5 #9 1.0264 96.1 31. 046-09W5 Comaplex #8 1.0545 76.1 32. 046-09W5 Comaplex #9 0.9974 ~.6 33. 07-11-053-26 #8 1.0292 979 34a. 16-19-071-04Chevron #8 0.9756 94.4 34b. 02-06-072-04Chevron #8 1.0014 98.7 34c. 16-19-071-04Chevron lOOXylene O.9588 ~;.7 35. 02-06-072-04Chevron lOOXylene 1.4169 933 36. Chauvco Unit No. 2 #8 0.9799 97.6 37. 06-10-035-03W5 #8 0.9548 665 38. 08-20-026-12W4 #8 1.10157 ~2 39. 03-13-044-09Amoco #8 1.0397 82.9 40. 04-22-043-08Amoco #8 0.9671 94.1 41. 02-05-043-08Amoco #8 1.0202 93.8 42. 03-13-044-09Amoco #9 0.9975 72.5 43. 04-22-043-08Amoco #9 0.9760 96.1 44. 02-05-043-08Amoco ~9 1.0372 55.3 45. Willesden Green #8 1.0127 94.1 Notes to Table 1: Wax or asphaltene amount is listed in grams under the heading "contaminant".
The sample is indicated by the location of the well, in the Province of Alberta, Canada, from which the sample was derived. % dissolved is the percentage of the original sample that was dissolved in the solvent.
It is a general indicator of the effectiveness of the solvent on that particular composition of contaminant.
The amount of solvent used was lOOmL. #8 and #16 is the fluid described above as the 120C cut. #9 is a blend of NP760tm and 10% Super A Soltm, which is available from Wellchem of Calgary, Alberta, Canada.
#10 is Petro Rep condensate having about 15% butanes, 46% pentanes, 19% hexanes and less than 1% aromatics as determined by gas chromatography. Run 95 is 100%
FRACSOL well site operation fluid available from Trisol Inc., of Calgary, Alberta. 90/10 is 90% of the 120C cut with 10% of a non-aromatic brominated non-fluorinated hydrocarbon such as dibromomethane.
90/lOXy is 90~ of the 150C cut described above with 10% of a non-aromatic brominated non-fluorinated hydrocarbon such as dibromomethane. lOOXy is 100% of the 150C cut described above. lOOXylene is pure xylene. Toluene is pure toluene. The oils from which some of the contaminants precipitated so far as known have the following composition: Sample 1. 8.26%
asphaltene, 11.2% wax; Sample 4. 10% asphaltene;
Sample 5. 23% asphaltene; Sample 22. 1.11% asphaltene, 4.7% wax; Sample 34c. 6.12% asphaltene, 2.9% wax;
Sample 36. 3.43% asphaltene, 3.8% wax.
These results show that the formulation of the present invention provides comparable solvation properties to highly refined and expensive wax solvation products when applied to a variety of wells without specifically formulating the composition to the well formation.
By comparison with the product of the present invention, so far as known, the condensate available from other gas plants located in the Province of Alberta is not desirable for use as a wax and asphaltene removing fluid. Thus, for condensate from Amerada Hess (Bearberry~, while the fluid is clear, showing low heavy ends, the aromatic content is too low by comparison with the light ends for a useful feedstock. Condensate from the Can-Oxy Mazeppa plant is dark red from the plant, which becomes black when the lighter ends are removed, that is, when a C7+ cut is taken, thus indicating the presence of undesirable heavy ends. Condensate from the Burnt Timber plant has too many heavy ends to work as a solvent, but may be formation compatible in some wells. Condensate from the Brazeau plant has too few aromatics, and too many waxes to be useful as a solvent. Condensate from Mobil Oil Lone Pine Creek has 6~ xylene, which might suggest it is similar to the Jumping Pound feed (6.5% xylene).
However, the relative lower percentage of lighter ends means that the concentration of xylene and other aromatics does not increase greatly if the lighter ends are removed in accordance with the principles of the invention. Consequently, the feed is not very useful as a solvent. Condensate from the Husky OIl Ram River plant has too many heavy ends, as indicated by its dark colour, and has too few aromatics to make it a useful feed for a solvent.
In the method of the invention, a C5+
hydrocarbon feedstock is obtained in which feedstock the mass percentage of trimethylbenzene exceeds the mass percentage of decane as determined by gas chromatography; and substantially all hydrocarbons having 1, 2, 3, 4 and 5 carbon atoms are removed, thereby producing a residual fluid, effectively a C7+
fluid. The fluid is applied to a well as follows.
For pumping or flowing wells, the well should be de-waxed before attempting to clean up the formation. To clean a pumping well, an amount of the fluid of the invention equal to about one half of the tubing volume should be circulated in the well with a bottomhole pump for about 24 hours. To clean the nearby well bore formation, a squeeze volume (1.0 -1.5 m3 per meter of perforations) of the fluid according to the invention should be squeezed into the formation with a clean, formation compatible fluid.
Preferably, the displacement fluid should be filtered to remove fines. After the fluid has been squeezed into the formation, the well should be shut in, and 16 ~o9 o306 the fluid allowed to stand for 12 hours before putting the well back on pump.
To clean a partially plugged flowing well, a volume of the fluid according to the invention equal to one half o the tubing volume should be injected down the tubing string and allowed to soak for 24 hours. The well may then be placed back on production and tested.
To clean a completely plugged well, an attempt should be made to solubilize the plug by injecting a volume of the fluid according to the invention down the tubing string. If the plug can be solubilized, then the well should be allowed to soak for 24 hours and the well may be placed back on production and tested. If the plug cannot be solubilized, then the plug may be removed by such procedures as drilling or jetting with coiled tubing, using the fluid according to the invention as the jetting fluid. The well may then be placed back on production and evaluated.
To squeeze a flowing well in which the tubing is set in a packer, it is preferred to inject the fluid according to the invention directly through the perforations into the well bore using coiled tubing. This helps to prevent well fluid entrained solids from being re-injected into the well. If this procedure is not viable, then an attempt may be made to force the fluid according to the invention through the tubing into the formation with a clean formation compatible chase fluid. Care should be taken not to overflush the chase fluid into the formation.
To squeeze a flowing well in which the tubing is not set in a packer, it is preferred to squeeze a squeeze volume of the fluid according to the invention down the annulus to the perforations. The flowline should be kept open until the resident annulus fluid has been displaced up the tubing into the flowline. Typical squeeze volumes are 1.0 - 1.5 m3 of the fluid according to the invention per meter of perforations. Once the fluid is in the annulus, the tubing valve may be closed and the fluid squeezed into the formation with a clean formation compatible fluid (which should not be overflushed). In either case (with or without the tubing set in a packer), the well may be shut in, allowed to soak and after 24 hours or so, placed back on production and tested.
If a flowing well does not flow after treatment, it may be desirable at that point to swab the well.
The formulation of the present invention, identified by Trisol Inc.ls tradename WAXSOL is preferably pumped into the well at below fracturing pressures. Pumping is carried out at ambient temperature. As known in the art, since the formulation of the invention is aromatic rich, contact with elastomeric components in the well should be minimized. For removal of the formulation of the invention from the well, high (maximum) pump speeds are recommended to aid in preventing the plugging of downhole pumps by release of fines and scale from downhole wax as it is dissolved.
A person skilled in the art could make immaterial modifications to the invention described and claimed in this patent without departing from the essence of the invention.
TABLE 2 (PART I) RT AREA% NAME RT AREA% NAME
3.202 .07S08 iC4 14.970 .09517 3.912 .35699 nC4 15.048 .08244 5.784 2.69133 iC5 15.195 .49210 6.514 2.72246 nC5 15.370 .75489 7.492 .67313 Cyclopentane 15.510 .46649 8.340 .89997 15.759 .45354 m+p xylene 8.487 3.99820 16.000 10.08547 m+p xylene 8.875 2.17882 16.157 .54391 9.377 6.74750 C6 16.504 1.51593 oxylene 10.097 2.47707 Methyl 16.615 .14003 cyclopentane 16.742 1.95847 C9 10.340 .08951 17.068 .12964 10.752 3.93949 Benzene 17.161 .14645 10.887 .18034 17.366 .27271 11.012 2.71877 Cyclohexane 17.508 .58216 11.201 2.88368 17.822 .17800 11.428 2.21393 17.946 .79982 11.641 .47199 18.105 1.68490 11.774 1.38668 18.245 .29447 12.062 4.72465 C7 18.347 .13771 12.688 6.65060 Methyl 18.493 .12346 cyclohexane
18.660 1.32512 trimethyl 12.910 .72919 benzene 13.125 .22715 18.800 1.26158 C10 13.313 .18384 18.965 .11433 13.554 12.71929 Toluene 19.256 .53542 13.710 2.10055 19.382 .07666 13.900 1.04831 19.525 .11942 14.090 1.44920 19.616 .15763 14.287 .47715 19.746 .13944 14.505 3.13432 C8 19.856 .32040 14.716 .17785 20.044 .31498 ~ 2090306 TABLE 2 (PART II) RT AREA~ NAME
20.180 .13753 20.279 .10719 20.420 .10568 20.701 .94819 Cll 20.885 .15028 21.060 .11153 21.140 .11705 21.250 .14451 21.545 .19119 21.732 .20552 21.853 .13484 21.980 .11113 22.466 .63371 C12 22.653 .05706 22.740 .11454 23.247 .06810 23.367 .09962 23.543 .12426 23.749 .08606 23.866 .06625 24.119 .28868 C13 24.306 .10446 25.387 .05999 25.668 .13514 C14 27.125 .06827 C15 TABLE 3(PART I) RT AREA% NAME RT AREA% NAME
2.341 .97890 12.101 .14885 2.618 6.86497 C4 12.358 .07718 2.816 .38619 12.588 .41137 3.697 14.33011 iC5 12.760 .53539 4.236 10.12231 nC5 12.899 .41128 5.066 .76730 Cyclopentene 13.147 .27011 m+p xylene 5.784 .93620 13.399 6.57036 m+p xylene 5.928 4.10632 13.560 .39226 6.290 1.97614 13.904 1.23017 oxylene 6.765 7.04991 iC6 14.155 1.50142 C9 7.470 2.18292 Methyl 14.471 .08211 cyclopentane 14.569 .10035 8.095 .89846 Benzene 14.774 .18688 8.240 .13707 14.917 .40929 8.371 2.14099 Cyclohexane 15.237 .13187 8.551 2.20204 15.355 .50748 8.775 1.54438 15.520 1.27618 8.995 .35825 15.663 .19968 9.129 1.05050 15.758 .09574 9.421 3.83012 C7 15.909 .10972 10.054 5.15676 Methyl 16.079 1.01203 trimethyl cyclohexane benzene 10.274 .55886 16.224 .96784 C10 10.488 .16983 16.379 .08264 10.675 .13411 16.674 .36803 10.904 5.37600 Toluene 16.943 .07889 11.082 1.53461 17.033 .10599 11.277 .64754 17.160 .08998 11.465 1.21~31 17.275 .21482 11.660 .25546 17.469 .23662 11.739 .10947 17.602 .09868 11.895 2.41510 C8 18.130 .64582 C11 TABLE 3 (PART II) RT AREA% NAME
18.300 .09683 18.485 .07766 18.561 .08832 18.669 .09555 18.966 .12143
20.180 .13753 20.279 .10719 20.420 .10568 20.701 .94819 Cll 20.885 .15028 21.060 .11153 21.140 .11705 21.250 .14451 21.545 .19119 21.732 .20552 21.853 .13484 21.980 .11113 22.466 .63371 C12 22.653 .05706 22.740 .11454 23.247 .06810 23.367 .09962 23.543 .12426 23.749 .08606 23.866 .06625 24.119 .28868 C13 24.306 .10446 25.387 .05999 25.668 .13514 C14 27.125 .06827 C15 TABLE 3(PART I) RT AREA% NAME RT AREA% NAME
2.341 .97890 12.101 .14885 2.618 6.86497 C4 12.358 .07718 2.816 .38619 12.588 .41137 3.697 14.33011 iC5 12.760 .53539 4.236 10.12231 nC5 12.899 .41128 5.066 .76730 Cyclopentene 13.147 .27011 m+p xylene 5.784 .93620 13.399 6.57036 m+p xylene 5.928 4.10632 13.560 .39226 6.290 1.97614 13.904 1.23017 oxylene 6.765 7.04991 iC6 14.155 1.50142 C9 7.470 2.18292 Methyl 14.471 .08211 cyclopentane 14.569 .10035 8.095 .89846 Benzene 14.774 .18688 8.240 .13707 14.917 .40929 8.371 2.14099 Cyclohexane 15.237 .13187 8.551 2.20204 15.355 .50748 8.775 1.54438 15.520 1.27618 8.995 .35825 15.663 .19968 9.129 1.05050 15.758 .09574 9.421 3.83012 C7 15.909 .10972 10.054 5.15676 Methyl 16.079 1.01203 trimethyl cyclohexane benzene 10.274 .55886 16.224 .96784 C10 10.488 .16983 16.379 .08264 10.675 .13411 16.674 .36803 10.904 5.37600 Toluene 16.943 .07889 11.082 1.53461 17.033 .10599 11.277 .64754 17.160 .08998 11.465 1.21~31 17.275 .21482 11.660 .25546 17.469 .23662 11.739 .10947 17.602 .09868 11.895 2.41510 C8 18.130 .64582 C11 TABLE 3 (PART II) RT AREA% NAME
18.300 .09683 18.485 .07766 18.561 .08832 18.669 .09555 18.966 .12143
19.155 .13286 19.281 .11464 19.405 .07735 19.899 .48104 C12
20.168 .07798 20.974 .10136
21.553 .25211 C13 21.733 .08036 23.105 .14083 C14 24.563 .07604 C15
Claims (73)
PROPERTY OR PRIVILEGE IS CLAIMED ARE DEFINED AS FOLLOWS:
1. An oil and gas well operation fluid comprising:
a residual C6+ hydrocarbon fluid derived from a hydrocarbon feedstock, the hydrocarbon feedstock and the residual C6+ hydrocarbon fluid having a complex mixture of aromatics;
the hydrocarbon feedstock having been produced directly from an oil or gas bearing formation, the hydrocarbon feedstock and the residual C6+ hydrocarbon fluid containing at least hydrocarbons having eight, nine, ten, eleven and twelve carbon atoms, including trimethylbenzene and n-decane;
the hydrocarbon feedstock containing a greater mass percentage of trimethylbenzene than n-decane as determined by gas chromatography.
a residual C6+ hydrocarbon fluid derived from a hydrocarbon feedstock, the hydrocarbon feedstock and the residual C6+ hydrocarbon fluid having a complex mixture of aromatics;
the hydrocarbon feedstock having been produced directly from an oil or gas bearing formation, the hydrocarbon feedstock and the residual C6+ hydrocarbon fluid containing at least hydrocarbons having eight, nine, ten, eleven and twelve carbon atoms, including trimethylbenzene and n-decane;
the hydrocarbon feedstock containing a greater mass percentage of trimethylbenzene than n-decane as determined by gas chromatography.
2. The oil and gas well operation fluid of claim 1 in which the hydrocarbon fluid is a C8+ fluid and in which the xylene content of the hydrocarbon fluid is greater than 25% mass fraction.
3. The oil and gas well operation fluid of claim 1 in which the hydrocarbon fluid is a C7+ fluid.
4. The fluid of claims 1, 2 or 3 in which the mass content of sulphur containing compounds in the feedstock exceeds 1500 ppm.
5. The fluid of claims 1, 2 or 3 in which the hydrocarbon feedstock is clear.
6. The fluid of claims 1, 2 or 3 in which the hydrocarbon fluid has no more than 2% mass fraction hydrocarbons having more than 16 carbon atoms.
7. The fluid of claims 1, 2 or 3 in which the aromatic content of the fluid is greater than 40% mass fraction.
8. A residual hydrocarbon fluid derived from a hydrocarbon feedstock, the hydrocarbon feedstock and the residual feedstock fluid having a complex mixture of aromatics in which feedstock the mass percentage of trimethylbenzene exceeds the mass percentage of n-decane as determined by gas chromatography for use as an oil well site operation fluid used in the solvation of waxes and asphaltenes.
9. The new use of the fluid of claim 8 in which the hydrocarbon fluid contains no more than 1% hydrocarbons with 1, 2, 3, 4 or 5 carbon atoms.
10. The new use of the fluid of claims 8 or 9 in which the mass content of sulphur containing compounds in the feedstock exceeds 1500 ppm.
11. The new use of the fluid of claims 8 or 9 in which the xylene content is greater than 25% mass fraction as determined by gas chromatography.
12. The new use of the fluid of claims 8 or 9 in which the hydrocarbon feedstock is clear.
13. The new use of the fluid of claims 8 or 9 in which the hydrocarbon fluid has no more than 2% mass fraction hydrocarbons with more than 16 carbon atoms.
14. The new use of the fluid of claims 8 or 9 in which the aromatic content of the hydrocarbon fluid is greater than 40% mass fraction.
15. A method of treating an oil or gas well with an oil well site operation fluid comprising the steps of:
obtaining a residual C5+ hydrocarbon fluid derived from a hydrocarbon feedstock, the residual C5+
hydrocarbon fluid and the hydrocarbon feedstock containing a complex mixture of aromatics in which feedstock the mass percentage of trimethylbenzene exceeds the mass percentage of n-decane as determined by gas chromatography; and applying the residual C5+ hydrocarbon fluid to an oil or gas well having contaminants.
obtaining a residual C5+ hydrocarbon fluid derived from a hydrocarbon feedstock, the residual C5+
hydrocarbon fluid and the hydrocarbon feedstock containing a complex mixture of aromatics in which feedstock the mass percentage of trimethylbenzene exceeds the mass percentage of n-decane as determined by gas chromatography; and applying the residual C5+ hydrocarbon fluid to an oil or gas well having contaminants.
16. The method of claim 15 in which the residual C5+
hydrocarbon fluid is allowed to stand in the well, and subsequently recovering the residual fluid from the well.
hydrocarbon fluid is allowed to stand in the well, and subsequently recovering the residual fluid from the well.
17. The method of claim 15 in which pressure is applied to the hydrocarbon fluid in the well to squeeze the fluid.
18. The method of claims 15, 16 or 17 in which the hydrocarbon fluid includes hydrocarbons having 6 carbon atoms and the method further comprising:
before applying the hydrocarbon fluid to a well, refining the hydrocarbon fluid to remove substantially all hydrocarbons having 6 or fewer carbon atoms.
before applying the hydrocarbon fluid to a well, refining the hydrocarbon fluid to remove substantially all hydrocarbons having 6 or fewer carbon atoms.
19. The method of claims 15, 16 or 17 in which the hydrocarbon fluid includes hydrocarbons having 7 carbon atoms and the method further comprising:
before applying the hydrocarbon fluid to a well, refining the hydrocarbon fluid to remove substantially all hydrocarbons having 7 or fewer carbon atoms.
before applying the hydrocarbon fluid to a well, refining the hydrocarbon fluid to remove substantially all hydrocarbons having 7 or fewer carbon atoms.
20. The method of claims 15, 16 or 17 further comprising:
before applying the hydrocarbon fluid to a well, refining the fluid to substantially remove hydrocarbons having more than 16 carbon atoms.
before applying the hydrocarbon fluid to a well, refining the fluid to substantially remove hydrocarbons having more than 16 carbon atoms.
21. A method of producing a wax and asphaltene solvating oil well site operation fluid and using the operation fluid to treat an oil or gas well, the method comprising the steps of:
obtaining a hydrocarbon feedstock that has been produced directly from an oil or gas bearing formation, the hydrocarbon feedstock containing at least hydrocarbons having eight, nine, ten, eleven and twelve carbon atoms, including trimethylbenzene and n-decane;
performing a gas chromatographic analysis on the feedstock to determine whether the mass percentage of trimethylbenzene exceeds the mass percentage of n-decane;
and if the mass percentage of trimethylbenzene exceeds the mass percentage of n-decane, then subsequently applying the feedstock or a residual fluid derived from the feedstock to an oil or gas well having contaminants.
obtaining a hydrocarbon feedstock that has been produced directly from an oil or gas bearing formation, the hydrocarbon feedstock containing at least hydrocarbons having eight, nine, ten, eleven and twelve carbon atoms, including trimethylbenzene and n-decane;
performing a gas chromatographic analysis on the feedstock to determine whether the mass percentage of trimethylbenzene exceeds the mass percentage of n-decane;
and if the mass percentage of trimethylbenzene exceeds the mass percentage of n-decane, then subsequently applying the feedstock or a residual fluid derived from the feedstock to an oil or gas well having contaminants.
22. The method of claim 21 further including removing substantially all hydrocarbons having 1, 2, 3, 4 and 5 carbon atoms from the feedstock, thereby producing a residual fluid derived from the feedstock which is applied to the oil or gas well.
23. The method of claim 22 in which the residual fluid is allowed to stand in the well and further including recovering the residual fluid from the well.
24. The method of claims 22 or 23 in which the feedstock includes hydrocarbons with 6 carbon atoms and the method further comprising:
further refining the residual fluid to remove substantially all hydrocarbons having 6 or fewer carbon atoms.
further refining the residual fluid to remove substantially all hydrocarbons having 6 or fewer carbon atoms.
25. The method of claims 22 or 23 in which the feedstock includes hydrocarbons with 7 carbon atoms and the method further comprising:
further refining the residual fluid to remove substantially all hydrocarbons having 7 or fewer carbon atoms.
further refining the residual fluid to remove substantially all hydrocarbons having 7 or fewer carbon atoms.
26. The method of claims 22 or 23 further comprising:
further refining the residual fluid so that the hydrocarbon fluid has no more that about 2% mass fraction hydrocarbons having more than 16 carbon atoms.
further refining the residual fluid so that the hydrocarbon fluid has no more that about 2% mass fraction hydrocarbons having more than 16 carbon atoms.
27. The method of claims 22 or 23 further including refining the residual fluid to increase the mass fraction of xylene to above 25% mass fraction.
28. The method of claim 24 in which the residual fluid includes aromatics in an amount greater than 40% mass fraction of the residual fluid.
29. An oil and gas well operation fluid comprising:
a residual C6+ hydrocarbon fluid derived from a hydrocarbon feedstock, the hydrocarbon feedstock and the residual C6+ hydrocarbon fluid having a complex mixture of aromatics;
the hydrocarbon feedstock containing a greater percentage of trimethylbenzene than n-decane, for the new use as a fluid used to treat oil and gas wells to remove wax and asphaltene from the wells.
a residual C6+ hydrocarbon fluid derived from a hydrocarbon feedstock, the hydrocarbon feedstock and the residual C6+ hydrocarbon fluid having a complex mixture of aromatics;
the hydrocarbon feedstock containing a greater percentage of trimethylbenzene than n-decane, for the new use as a fluid used to treat oil and gas wells to remove wax and asphaltene from the wells.
30. The oil and gas well operation fluid of claim 29 in which the hydrocarbon fluid is a C8+ fluid and in which the xylene content of the hydrocarbon fluid is greater than 25% mass fraction.
31. The oil and gas well operation fluid of claim 29 in which the hydrocarbon fluid is a C7+ fluid.
32. A method of producing a wax and asphaltene solvating oil well site operation fluid comprising the steps of:
obtaining a hydrocarbon feedstock that has been produced directly from an oil or gas bearing formation, the hydrocarbon feedstock containing at least hydrocarbons having eight, nine, ten, eleven and twelve carbon atoms, including trimethylbenzene and n-decane;
verifying whether the mass percentage of trimethylbenzene exceeds the mass percentage of n-decane in the hydrocarbon feedstock; and if the mass percentage of trimethylbenzene exceeds the mass percentage of n-decane, then subsequently applying the feedstock or a residual fluid derived from the feedstock to an oil or gas well having contaminants.
obtaining a hydrocarbon feedstock that has been produced directly from an oil or gas bearing formation, the hydrocarbon feedstock containing at least hydrocarbons having eight, nine, ten, eleven and twelve carbon atoms, including trimethylbenzene and n-decane;
verifying whether the mass percentage of trimethylbenzene exceeds the mass percentage of n-decane in the hydrocarbon feedstock; and if the mass percentage of trimethylbenzene exceeds the mass percentage of n-decane, then subsequently applying the feedstock or a residual fluid derived from the feedstock to an oil or gas well having contaminants.
33. A method of treating an oil or gas well with an oil well site operation fluid to remove asphaltene and wax from the well, the method comprising the steps of:
obtaining a hydrocarbon fluid that has been produced directly from an oil or gas bearing formation, the hydrocarbon fluid containing at least hydrocarbons having eight, nine, ten, eleven and twelve carbon atoms, including trimethylbenzene and n-decane, and containing a complex mixture of aromatics, in which fluid the mass percentage of trimethylbenzene exceeds the mass percentage of n-decane as determined by gas chromatography; and applying the hydrocarbon fluid to an oil or gas well having contaminants.
obtaining a hydrocarbon fluid that has been produced directly from an oil or gas bearing formation, the hydrocarbon fluid containing at least hydrocarbons having eight, nine, ten, eleven and twelve carbon atoms, including trimethylbenzene and n-decane, and containing a complex mixture of aromatics, in which fluid the mass percentage of trimethylbenzene exceeds the mass percentage of n-decane as determined by gas chromatography; and applying the hydrocarbon fluid to an oil or gas well having contaminants.
34. The method of claim 33 in which the hydrocarbon fluid includes hydrocarbons having 5 carbon atoms and further comprising the step of:
before applying the hydrocarbon fluid to a well, refining the hydrocarbon fluid to remove substantially all hydrocarbons having 5 or fewer carbon atoms.
before applying the hydrocarbon fluid to a well, refining the hydrocarbon fluid to remove substantially all hydrocarbons having 5 or fewer carbon atoms.
35. The method of claim 33 in which the hydrocarbon fluid includes hydrocarbons having 6 carbon atoms and further comprising the step of:
before applying the hydrocarbon fluid to a well, refining the hydrocarbon fluid to remove substantially all hydrocarbons having 6 or fewer carbon atoms.
before applying the hydrocarbon fluid to a well, refining the hydrocarbon fluid to remove substantially all hydrocarbons having 6 or fewer carbon atoms.
36. The method of claim 33 in which the hydrocarbon fluid includes hydrocarbons having 7 carbon atoms and further comprising the step of:
before applying the hydrocarbon fluid to a well, refining the hydrocarbon fluid to remove substantially all hydrocarbons having 7 or fewer carbon atoms.
before applying the hydrocarbon fluid to a well, refining the hydrocarbon fluid to remove substantially all hydrocarbons having 7 or fewer carbon atoms.
37. The method of claims 34, 35 or 36 in which the hydrocarbon fluid has at least 2% mass fraction hydrocarbons having more than 16 carbon atoms and the method further comprising the step of:
before applying the hydrocarbon fluid to a well, refining the hydrocarbon fluid to reduce C16+ content.
before applying the hydrocarbon fluid to a well, refining the hydrocarbon fluid to reduce C16+ content.
38. The method of claims 34, 35 or 36 in which the hydrocarbon fluid is allowed to stand in the well for at least 12 hours, and subsequently recovering the hydrocarbon fluid from the well.
39. The method of claim 33 in which pressure is applied to the hydrocarbon fluid in the well.
40. The method of claims 34, 35 or 36 in which pressure is applied to the hydrocarbon fluid in the well.
41. The method of claim 33 in which the hydrocarbon fluid includes hydrocarbons having 5 carbon atoms and further comprising the step of:
before applying the hydrocarbon fluid to a well, refining the hydrocarbon fluid to reduce C1 to C5 content to cumulatively less than 5% mass fraction.
before applying the hydrocarbon fluid to a well, refining the hydrocarbon fluid to reduce C1 to C5 content to cumulatively less than 5% mass fraction.
42. The method of claim 33 in which the hydrocarbon fluid includes hydrocarbons having 6 carbon atoms and further comprising the step of:
before applying the hydrocarbon fluid to a well, refining the hydrocarbon fluid to reduce C1 to C6 content to cumulatively less than 5% mass fraction.
before applying the hydrocarbon fluid to a well, refining the hydrocarbon fluid to reduce C1 to C6 content to cumulatively less than 5% mass fraction.
43. The method of claim 33 in which the hydrocarbon fluid includes hydrocarbons having 7 carbon atoms and further comprising the step of:
before applying the hydrocarbon fluid to a well, refining the hydrocarbon fluid to reduce C1 to C7 content to cumulatively less than 5% mass fraction.
before applying the hydrocarbon fluid to a well, refining the hydrocarbon fluid to reduce C1 to C7 content to cumulatively less than 5% mass fraction.
44. The method of claims 41, 42 or 43 in which the hydrocarbon fluid has at least 2% mass fraction hydrocarbons having more than 16 carbon atoms and the method further comprising the step of:
before applying the hydrocarbon fluid to a well, refining the hydrocarbon fluid to reduce C16+ content.
before applying the hydrocarbon fluid to a well, refining the hydrocarbon fluid to reduce C16+ content.
45. The method of claims 41, 42 or 43 in which the hydrocarbon fluid is allowed to stand in the well for at least 12 hours, and subsequently recovering the hydrocarbon fluid from the well.
46. The method of claims 41, 42 or 43 in which pressure is applied to the hydrocarbon fluid in the well.
47. A method of treating oil or gas production equipment with a hydrocarbon fluid, wherein the oil or gas production equipment is contaminated with wax or asphaltene contaminants, the method comprising the steps of:
obtaining a hydrocarbon fluid that has been produced directly from an oil or gas bearing formation, the hydrocarbon fluid containing at least hydrocarbons having eight, nine, ten, eleven and twelve carbon atoms, including trimethylbenzene and n-decane, and containing a complex mixture of aromatics, in which fluid the mass percentage of trimethylbenzene exceeds the mass percentage of n-decane as determined by gas chromatography; and injecting the hydrocarbon fluid into the oil or gas production equipment to solvate contaminants in the oil or gas production equipment.
obtaining a hydrocarbon fluid that has been produced directly from an oil or gas bearing formation, the hydrocarbon fluid containing at least hydrocarbons having eight, nine, ten, eleven and twelve carbon atoms, including trimethylbenzene and n-decane, and containing a complex mixture of aromatics, in which fluid the mass percentage of trimethylbenzene exceeds the mass percentage of n-decane as determined by gas chromatography; and injecting the hydrocarbon fluid into the oil or gas production equipment to solvate contaminants in the oil or gas production equipment.
48. The method of claim 47 in which the hydrocarbon fluid includes hydrocarbons having 5 carbon atoms and further comprising the step of:
before injecting the hydrocarbon fluid into oil or gas production equipment, refining the hydrocarbon fluid to reduce C1 to C5 content to cumulatively less than 5% mass fraction.
before injecting the hydrocarbon fluid into oil or gas production equipment, refining the hydrocarbon fluid to reduce C1 to C5 content to cumulatively less than 5% mass fraction.
49. The method of claim 47 in which the hydrocarbon fluid includes hydrocarbons having 6 carbon atoms and further comprising the step of:
before injecting the hydrocarbon fluid into oil or gas production equipment, refining the hydrocarbon fluid to reduce C1 to C6 content to cumulatively less than 5% mass fraction.
before injecting the hydrocarbon fluid into oil or gas production equipment, refining the hydrocarbon fluid to reduce C1 to C6 content to cumulatively less than 5% mass fraction.
50. The method of claim 47 in which the hydrocarbon fluid includes hydrocarbons having 7 carbon atoms and further comprising the step of:
before injecting the hydrocarbon fluid into oil or gas production equipment, refining the hydrocarbon fluid to reduce C1 to C5 content to cumulatively less than 5% mass fraction.
before injecting the hydrocarbon fluid into oil or gas production equipment, refining the hydrocarbon fluid to reduce C1 to C5 content to cumulatively less than 5% mass fraction.
51. The method of claims 48, 49 or 50 in which the hydrocarbon fluid has at least 2% mass fraction hydrocarbons having more than 16 carbon atoms and the method further comprising the step of:
before applying the hydrocarbon fluid to oil or gas production equipment, refining the hydrocarbon fluid to reduce C16+ content.
before applying the hydrocarbon fluid to oil or gas production equipment, refining the hydrocarbon fluid to reduce C16+ content.
52. The method of claim 47 in which the hydrocarbon fluid includes hydrocarbons having 5 carbon atoms and further comprising the step of:
before injecting the hydrocarbon fluid into oil or gas production equipment, refining the hydrocarbon fluid to remove substantially all hydrocarbons having 5 or fewer carbon atoms.
before injecting the hydrocarbon fluid into oil or gas production equipment, refining the hydrocarbon fluid to remove substantially all hydrocarbons having 5 or fewer carbon atoms.
53. The method of claim 47 in which the hydrocarbon fluid includes hydrocarbons having 6 carbon atoms and further comprising the step of:
before injecting the hydrocarbon fluid into oil or gas production equipment, refining the hydrocarbon fluid to remove substantially all hydrocarbons having 6 or fewer carbon atoms.
before injecting the hydrocarbon fluid into oil or gas production equipment, refining the hydrocarbon fluid to remove substantially all hydrocarbons having 6 or fewer carbon atoms.
54. The method of claim 47 in which the hydrocarbon fluid includes hydrocarbons having 7 carbon atoms and further comprising the step of:
before injecting the hydrocarbon fluid into oil or gas production equipment, refining the hydrocarbon fluid to remove substantially all hydrocarbons having 7 or fewer carbon atoms.
before injecting the hydrocarbon fluid into oil or gas production equipment, refining the hydrocarbon fluid to remove substantially all hydrocarbons having 7 or fewer carbon atoms.
55. The method of claims 52, 53 or 54 in which the hydrocarbon fluid has at least 2% mass fraction hydrocarbons having more than 16 carbon atoms and the method further comprising the step of:
before applying the hydrocarbon fluid to oil or gas production equipment, refining the hydrocarbon fluid to reduce C16+ content.
before applying the hydrocarbon fluid to oil or gas production equipment, refining the hydrocarbon fluid to reduce C16+ content.
56. A method of treating oil or gas production equipment with a hydrocarbon fluid, the method comprising the steps of:
obtaining a residual hydrocarbon fluid derived from a hydrocarbon feedstock that has been produced directly from an oil or gas bearing formation, the hydrocarbon feedstock and the residual hydrocarbon fluid containing at least hydrocarbons having eight, nine, ten, eleven and twelve carbon atoms, including trimethylbenzene and n-decane, and containing a complex mixture of aromatics, in which feedstock the mass percentage of trimethylbenzene is known to exceed the mass percentage of n-decane as determined by gas chromatography; and injecting the hydrocarbon fluid into the oil or gas production equipment.
obtaining a residual hydrocarbon fluid derived from a hydrocarbon feedstock that has been produced directly from an oil or gas bearing formation, the hydrocarbon feedstock and the residual hydrocarbon fluid containing at least hydrocarbons having eight, nine, ten, eleven and twelve carbon atoms, including trimethylbenzene and n-decane, and containing a complex mixture of aromatics, in which feedstock the mass percentage of trimethylbenzene is known to exceed the mass percentage of n-decane as determined by gas chromatography; and injecting the hydrocarbon fluid into the oil or gas production equipment.
57. The method of claim 56 in which the hydrocarbon feedstock includes hydrocarbons having 5 carbon atoms and further comprising the step of:
before injecting the hydrocarbon fluid into oil or gas production equipment, refining the hydrocarbon fluid to remove substantially all hydrocarbons having 5 or fewer carbon atoms.
before injecting the hydrocarbon fluid into oil or gas production equipment, refining the hydrocarbon fluid to remove substantially all hydrocarbons having 5 or fewer carbon atoms.
58. The method of claim 56 in which the hydrocarbon feedstock includes hydrocarbons having 6 carbon atoms and further comprising the step of:
before injecting the hydrocarbon fluid into oil or gas production equipment, refining the hydrocarbon fluid to remove substantially all hydrocarbons having 6 or fewer carbon atoms.
before injecting the hydrocarbon fluid into oil or gas production equipment, refining the hydrocarbon fluid to remove substantially all hydrocarbons having 6 or fewer carbon atoms.
59. The method of claim 56 in which the hydrocarbon feedstock includes hydrocarbons having 7 carbon atoms and further comprising the step of:
before injecting the hydrocarbon fluid into oil or gas production equipment, refining the hydrocarbon fluid to remove substantially all hydrocarbons having 7 or fewer carbon atoms.
before injecting the hydrocarbon fluid into oil or gas production equipment, refining the hydrocarbon fluid to remove substantially all hydrocarbons having 7 or fewer carbon atoms.
60. A method of treating oil or gas production equipment with a hydrocarbon fluid, wherein the oil or gas production equipment carries crude oil contaminated with asphaltenes, the method comprising the steps of:
obtaining a residual hydrocarbon fluid derived from a hydrocarbon feedstock that has been produced directly from an oil or gas bearing formation, the hydrocarbon feedstock and the residual hydrocarbon fluid containing at least hydrocarbons having eight, nine, ten, eleven and twelve carbon atoms, including trimethylbenzene and n-decane, and containing a complex mixture of aromatics, in which feedstock the mass percentage of trimethylbenzene exceeds the mass percentage of n-decane as determined by gas chromatography; and injecting the hydrocarbon fluid into the oil or gas production equipment to suspend asphaltenes carried by the crude oil.
obtaining a residual hydrocarbon fluid derived from a hydrocarbon feedstock that has been produced directly from an oil or gas bearing formation, the hydrocarbon feedstock and the residual hydrocarbon fluid containing at least hydrocarbons having eight, nine, ten, eleven and twelve carbon atoms, including trimethylbenzene and n-decane, and containing a complex mixture of aromatics, in which feedstock the mass percentage of trimethylbenzene exceeds the mass percentage of n-decane as determined by gas chromatography; and injecting the hydrocarbon fluid into the oil or gas production equipment to suspend asphaltenes carried by the crude oil.
61. The method of claim 60 in which the hydrocarbon feedstock includes hydrocarbons having 5 carbon atoms and further comprising the step of:
before injecting the hydrocarbon fluid into oil or gas production equipment, refining the hydrocarbon fluid to reduce C1 to C5 content to cumulatively less than 5% mass fraction.
before injecting the hydrocarbon fluid into oil or gas production equipment, refining the hydrocarbon fluid to reduce C1 to C5 content to cumulatively less than 5% mass fraction.
62. The method of claim 60 in which the hydrocarbon feedstock includes hydrocarbons having 6 carbon atoms and further comprising the step of:
before injecting the hydrocarbon fluid into oil or gas production equipment, refining the hydrocarbon fluid to reduce C1 to C6 content to cumulatively less than 5% mass fraction.
before injecting the hydrocarbon fluid into oil or gas production equipment, refining the hydrocarbon fluid to reduce C1 to C6 content to cumulatively less than 5% mass fraction.
63. The method of claim 60 in which the hydrocarbon feedstock includes hydrocarbons having 7 carbon atoms and further comprising the step of:
before injecting the hydrocarbon fluid into oil or gas production equipment, refining the hydrocarbon fluid to reduce C1 to C7 content to cumulatively less than 5% mass fraction.
before injecting the hydrocarbon fluid into oil or gas production equipment, refining the hydrocarbon fluid to reduce C1 to C7 content to cumulatively less than 5% mass fraction.
64. The method of claims 61, 62 or 63 in which the hydrocarbon feedstock has at least 2% mass fraction hydrocarbons having more than 16 carbon atoms and the method further comprising the step of:
before applying the hydrocarbon fluid to oil or gas production equipment, refining the hydrocarbon fluid to reduce C16+ content.
before applying the hydrocarbon fluid to oil or gas production equipment, refining the hydrocarbon fluid to reduce C16+ content.
65. The method of claim 60 in which the hydrocarbon feedstock includes hydrocarbons having 5 carbon atoms and further comprising the step of:
before injecting the hydrocarbon fluid into oil or gas production equipment, refining the hydrocarbon fluid to remove substantially all hydrocarbons having 5 or fewer carbon atoms.
before injecting the hydrocarbon fluid into oil or gas production equipment, refining the hydrocarbon fluid to remove substantially all hydrocarbons having 5 or fewer carbon atoms.
66. The method of claim 60 in which the hydrocarbon feedstock includes hydrocarbons having 6 carbon atoms and further comprising the step of:
before injecting the hydrocarbon fluid into oil or gas production equipment, refining the hydrocarbon fluid to remove substantially all hydrocarbons having 6 or fewer carbon atoms.
before injecting the hydrocarbon fluid into oil or gas production equipment, refining the hydrocarbon fluid to remove substantially all hydrocarbons having 6 or fewer carbon atoms.
67. The method of claim 60 in which the hydrocarbon feedstock includes hydrocarbons having 7 carbon atoms and further comprising the step of:
before injecting the hydrocarbon fluid into oil or gas production equipment, refining the hydrocarbon fluid to remove substantially all hydrocarbons having 7 or fewer carbon atoms.
before injecting the hydrocarbon fluid into oil or gas production equipment, refining the hydrocarbon fluid to remove substantially all hydrocarbons having 7 or fewer carbon atoms.
68. The method of claims 65, 66 or 67 in which the hydrocarbon feedstock has at least 2% mass fraction hydrocarbons having more than 16 carbon atoms and the method further comprising the step of:
before applying the hydrocarbon fluid to oil or gas production equipment, refining the hydrocarbon fluid to reduce C16+ content.
before applying the hydrocarbon fluid to oil or gas production equipment, refining the hydrocarbon fluid to reduce C16+ content.
69. A method of treating a well with a wax and asphaltene solvating oil well site operation fluid, the method comprising the steps of:
obtaining a hydrocarbon feedstock that has been produced directly from an oil or gas bearing formation, the hydrocarbon feedstock containing at least hydrocarbons having eight, nine, ten, eleven and twelve carbon atoms;
refining the hydrocarbon feedstock to reduce mass fraction of the hydrocarbon feedstock having more than 16 carbon atoms; and subsequently applying the feedstock or a residual fluid derived from the feedstock to an oil or gas well having contaminants selected from the group consisting of wax and asphaltenes.
obtaining a hydrocarbon feedstock that has been produced directly from an oil or gas bearing formation, the hydrocarbon feedstock containing at least hydrocarbons having eight, nine, ten, eleven and twelve carbon atoms;
refining the hydrocarbon feedstock to reduce mass fraction of the hydrocarbon feedstock having more than 16 carbon atoms; and subsequently applying the feedstock or a residual fluid derived from the feedstock to an oil or gas well having contaminants selected from the group consisting of wax and asphaltenes.
70. A method of treating an oil or gas well with an oil well site operation fluid to remove asphaltene and wax from the well, the method comprising the steps of:
obtaining a residual C5+ hydrocarbon fluid derived from a hydrocarbon feedstock;
the residual C5+ hydrocarbon fluid including greater than 2% mass fraction hydrocarbons having more than 16 carbon atoms;
refining the residual C5+ hydrocarbon fluid to reduce the mass fraction of the hydrocarbons having more than 16 carbon atoms to produced a refined residual C5+ hycrocarbon fluid; and applying the refined residual C5+ hydrocarbon fluid to an oil or gas well having contaminants.
obtaining a residual C5+ hydrocarbon fluid derived from a hydrocarbon feedstock;
the residual C5+ hydrocarbon fluid including greater than 2% mass fraction hydrocarbons having more than 16 carbon atoms;
refining the residual C5+ hydrocarbon fluid to reduce the mass fraction of the hydrocarbons having more than 16 carbon atoms to produced a refined residual C5+ hycrocarbon fluid; and applying the refined residual C5+ hydrocarbon fluid to an oil or gas well having contaminants.
71. A method of treating oil or gas production equipment with a hydrocarbon fluid, wherein the oil or gas production equipment is contaminated with wax or asphaltene contaminants, the method comprising the steps of:
obtaining a hydrocarbon fluid that has been produced directly from an oil or gas bearing formation, the hydrocarbon fluid containing at least hydrocarbons having eight, nine, ten, eleven and twelve carbon atoms;
the hydrocarbon fluid having at least 2% mass fraction hydrocarbons having more than 16 carbon atoms:
refining the hydrocarbon fluid to reduce mass fraction of the hydrocarbon fluid having more than 16 carbon atoms and thereby produce a refined hydrocarbon fluid; and injecting the refined hydrocarbon fluid into the oil or gas production equipment to solvate contaminants in the oil or gas production equipment.
obtaining a hydrocarbon fluid that has been produced directly from an oil or gas bearing formation, the hydrocarbon fluid containing at least hydrocarbons having eight, nine, ten, eleven and twelve carbon atoms;
the hydrocarbon fluid having at least 2% mass fraction hydrocarbons having more than 16 carbon atoms:
refining the hydrocarbon fluid to reduce mass fraction of the hydrocarbon fluid having more than 16 carbon atoms and thereby produce a refined hydrocarbon fluid; and injecting the refined hydrocarbon fluid into the oil or gas production equipment to solvate contaminants in the oil or gas production equipment.
72. A method of treating oil or gas production equipment with a hydrocarbon fluid, the method comprising the steps of:
obtaining a residual hydrocarbon fluid derived from a hydrocarbon feedstock that has been produced directly from an oil or gas bearing formation, the hydrocarbon feedstock and the residual hydrocarbon fluid containing at least hydrocarbons having eight, nine, ten, eleven and twelve carbon atoms;
refining the residual hydrocarbon fluid to reduce hydrocarbon content having more than 16 carbon atoms to produce a refined residual hydrocarbon fluid; and injecting the refined hydrocarbon fluid into the oil or gas production equipment.
obtaining a residual hydrocarbon fluid derived from a hydrocarbon feedstock that has been produced directly from an oil or gas bearing formation, the hydrocarbon feedstock and the residual hydrocarbon fluid containing at least hydrocarbons having eight, nine, ten, eleven and twelve carbon atoms;
refining the residual hydrocarbon fluid to reduce hydrocarbon content having more than 16 carbon atoms to produce a refined residual hydrocarbon fluid; and injecting the refined hydrocarbon fluid into the oil or gas production equipment.
73. The method of any one of claims 69-72 in which the hydrocarbons having more than 16 carbon atoms are reduced to less than 2% mass fraction.
Priority Applications (5)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| CA 2090306 CA2090306E (en) | 1993-02-24 | 1993-02-24 | Oil and gas well operation fluid used for the solvation of waxes and asphaltenes, and method of use thereof |
| PCT/CA1994/000109 WO1994019575A2 (en) | 1993-02-24 | 1994-02-24 | Oil well wax removal fluid |
| AU61519/94A AU6151994A (en) | 1993-02-24 | 1994-02-24 | Oil well wax removal fluid |
| US09/133,385 US5902775A (en) | 1993-02-24 | 1998-08-13 | Oil and gas well operation fluid used for the solvation of waxes and asphaltenes, and method of use thereof |
| US09/275,693 US6093684A (en) | 1993-02-24 | 1999-03-24 | Oil and gas well operation fluid used for the solvation of waxes and asphaltenes, and method of use thereof |
Applications Claiming Priority (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| CA 2090306 CA2090306E (en) | 1993-02-24 | 1993-02-24 | Oil and gas well operation fluid used for the solvation of waxes and asphaltenes, and method of use thereof |
Publications (3)
| Publication Number | Publication Date |
|---|---|
| CA2090306A1 CA2090306A1 (en) | 1994-08-25 |
| CA2090306C CA2090306C (en) | 1996-12-03 |
| CA2090306E true CA2090306E (en) | 2001-03-27 |
Family
ID=4151197
Family Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CA 2090306 Expired - Lifetime CA2090306E (en) | 1993-02-24 | 1993-02-24 | Oil and gas well operation fluid used for the solvation of waxes and asphaltenes, and method of use thereof |
Country Status (3)
| Country | Link |
|---|---|
| AU (1) | AU6151994A (en) |
| CA (1) | CA2090306E (en) |
| WO (1) | WO1994019575A2 (en) |
Families Citing this family (5)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| IT1273513B (en) * | 1995-04-07 | 1997-07-08 | Agip Spa | EFFECTIVE COMPOSITION IN THE REMOVAL OF ASPHALTENES |
| CA2246040A1 (en) | 1998-08-28 | 2000-02-28 | Roderick D. Mcleod | Lateral jet drilling system |
| CA2781273C (en) * | 2012-06-28 | 2014-05-20 | Imperial Oil Resources Limited | Diluting agent for diluting viscous oil |
| US11008523B2 (en) * | 2014-10-17 | 2021-05-18 | Cameron International Corporation | Chemical inhibitors with sub-micron materials as additives for enhanced flow assurance |
| CN115639308B (en) * | 2021-12-28 | 2024-12-06 | 东北石油大学 | A wax removal experimental method based on in-situ utilization of asphaltene |
Family Cites Families (8)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| SU432384A1 (en) * | 1972-06-15 | 1974-06-15 | Г. В. Туков, С. Нуртдинов, Л. Н. Калинчук, В. Ф. Новиков | |
| US3998743A (en) * | 1973-12-07 | 1976-12-21 | Union Oil Company Of California | Method and solvent composition for stimulating the production of oil from a producing well |
| SU789558A1 (en) * | 1978-09-26 | 1980-12-23 | Башкирский Государственный Научно- Исследовательский И Проектный Институт Нефтяной Промышленности | Composition for removing tarry-asphaltenic and paraffin deposits |
| FR2496504A1 (en) * | 1980-12-23 | 1982-06-25 | Somalor Ferrari Somafer Ets | COMPOSITION AND PROCESS FOR RECOVERING AND ENHANCING PETROLEUM PRODUCTS |
| US4592424A (en) * | 1984-08-13 | 1986-06-03 | Texaco Inc. | Secondary recovery procedure |
| SU1421751A1 (en) * | 1985-08-30 | 1988-09-07 | Научно-Производственное Объединение По Химизации Технологических Процессов В Нефтяной Промышленности "Союзнефтепромхим" | Composition for removing asphalt-paraffin-resin deposits |
| AT393715B (en) * | 1989-12-20 | 1991-12-10 | Vni I Pk I Problemam Osvoenia | METHOD FOR TREATING A PUNCHED UNDER LAYER SATURATED WITH HYDROCARBON GAS |
| BR9004200A (en) * | 1990-08-24 | 1992-03-03 | Petroleo Brasileiro Sa | DEPARING PROCESS FOR PRODUCING FORMATIONS |
-
1993
- 1993-02-24 CA CA 2090306 patent/CA2090306E/en not_active Expired - Lifetime
-
1994
- 1994-02-24 WO PCT/CA1994/000109 patent/WO1994019575A2/en active Application Filing
- 1994-02-24 AU AU61519/94A patent/AU6151994A/en not_active Abandoned
Also Published As
| Publication number | Publication date |
|---|---|
| AU6151994A (en) | 1994-09-14 |
| CA2090306A1 (en) | 1994-08-25 |
| CA2090306C (en) | 1996-12-03 |
| WO1994019575A3 (en) | 1994-10-13 |
| WO1994019575A2 (en) | 1994-09-01 |
Similar Documents
| Publication | Publication Date | Title |
|---|---|---|
| US10731071B2 (en) | Methods and compositions for use in oil and/or gas wells comprising microemulsions with terpene, silicone solvent, and surfactant | |
| CA2590829C (en) | Compositions and methods of using same in producing heavy oil and bitumen | |
| US5104556A (en) | Oil well treatment composition | |
| EP3067404B1 (en) | Methods for use in oil and/or gas wells | |
| US10000693B2 (en) | Methods and compositions for use in oil and/or gas wells | |
| US3729053A (en) | Method for increasing permeability of oil-bearing formations | |
| US5358052A (en) | Conditioning of formation for sandstone acidizing | |
| CA2906165C (en) | Methods and compositions for use in oil and/or gas wells | |
| AU696025B2 (en) | Application of N,N-dialkylamides to control the formation of emulsions or sludge during drilling or workover of producing oil wells | |
| CA2891278A1 (en) | Methods and compositions for use in oil and / or gas wells | |
| CA2658189A1 (en) | Method for removing asphaltene deposits | |
| US20100022417A1 (en) | Composition and Method for the Removal or Control of Paraffin Wax and/or Asphaltine Deposits | |
| MXPA02010423A (en) | Mineral acid enhanced thermal treatment for viscosity reduction of oils (ecb-0002). | |
| CA2904735C (en) | Methods and compositions for use in oil and/or gas wells | |
| US5515923A (en) | Oil and gas well productivity | |
| CA2090306E (en) | Oil and gas well operation fluid used for the solvation of waxes and asphaltenes, and method of use thereof | |
| US4825952A (en) | Fracturing process for low permeability reservoirs employing a compatible hydrocarbon-liquid carbon dioxide mixture | |
| US6093684A (en) | Oil and gas well operation fluid used for the solvation of waxes and asphaltenes, and method of use thereof | |
| US3276519A (en) | Paraffin control method | |
| Curtis | Environmentally favorable terpene solvents find diverse applications in stimulation, sand control and cementing operations | |
| US20160122612A1 (en) | Non-Toxic, Inexpensive, Low Viscosity Mineral Oil Based Drilling Fluid | |
| US5232050A (en) | Conditioning of formation for sandstone acidizing | |
| US5827803A (en) | Well treatment fluid | |
| CA2141111C (en) | Method of improving oil and gas well productivity | |
| CA2189610C (en) | Well treatment fluid |
Legal Events
| Date | Code | Title | Description |
|---|---|---|---|
| EEER | Examination request | ||
| NARE | Reissued | ||
| NARE | Reissued |
Effective date: 20010327 |
|
| MKLA | Lapsed |
Effective date: 20130225 |
|
| MKEC | Expiry (correction) |
Effective date: 20131009 |