US10385259B2 - Method for removing bitumen to enhance formation permeability - Google Patents
Method for removing bitumen to enhance formation permeability Download PDFInfo
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- US10385259B2 US10385259B2 US14/910,615 US201414910615A US10385259B2 US 10385259 B2 US10385259 B2 US 10385259B2 US 201414910615 A US201414910615 A US 201414910615A US 10385259 B2 US10385259 B2 US 10385259B2
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- United States
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- shale formation
- solvent
- formation
- treatment fluid
- bitumen
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Images
Classifications
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- 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
- C09K8/60—Compositions for stimulating production by acting on the underground formation
- C09K8/62—Compositions for forming crevices or fractures
- C09K8/64—Oil-based compositions
-
- 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
-
- 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
- C09K8/58—Compositions for enhanced recovery methods for obtaining hydrocarbons, i.e. for improving the mobility of the oil, e.g. displacing fluids
-
- 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
- C09K8/60—Compositions for stimulating production by acting on the underground formation
- C09K8/62—Compositions for forming crevices or fractures
- C09K8/70—Compositions for forming crevices or fractures characterised by their form or by the form of their components, e.g. foams
- C09K8/703—Foams
-
- 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
- C09K8/60—Compositions for stimulating production by acting on the underground formation
- C09K8/82—Oil-based compositions
-
- 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
- C09K8/60—Compositions for stimulating production by acting on the underground formation
- C09K8/92—Compositions for stimulating production by acting on the underground formation characterised by their form or by the form of their components, e.g. encapsulated material
- C09K8/94—Foams
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- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
- E21B43/166—Injecting a gaseous medium; Injecting a gaseous medium and a liquid medium
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
- E21B43/24—Enhanced recovery methods for obtaining hydrocarbons using heat, e.g. steam injection
- E21B43/2405—Enhanced recovery methods for obtaining hydrocarbons using heat, e.g. steam injection in association with fracturing or crevice forming processes
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
- E21B43/24—Enhanced recovery methods for obtaining hydrocarbons using heat, e.g. steam injection
- E21B43/241—Enhanced recovery methods for obtaining hydrocarbons using heat, e.g. steam injection combined with solution mining of non-hydrocarbon minerals, e.g. solvent pyrolysis of oil shale
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/25—Methods for stimulating production
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- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/25—Methods for stimulating production
- E21B43/26—Methods for stimulating production by forming crevices or fractures
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- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/25—Methods for stimulating production
- E21B43/26—Methods for stimulating production by forming crevices or fractures
- E21B43/2605—Methods for stimulating production by forming crevices or fractures using gas or liquefied gas
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- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/34—Arrangements for separating materials produced by the well
- E21B43/40—Separation associated with re-injection of separated materials
Definitions
- This disclosure relates to hydrocarbon recovery from formations.
- this disclosure relates to treating formations to enhance formation permeability.
- Hydrocarbons such as oil and gas
- the formations include many pores that include hydrocarbons.
- the hydrocarbons are recovered by drilling a wellbore that traverses the subterranean formation.
- the hydrocarbons migrate through connected pores and fractures within the subterranean formation and into the wellbore, where they travel to the surface.
- Conventional reservoirs are relatively permeable so hydrocarbons pass more easily into the wellbore.
- unconventional reservoirs, such as organic shale formations are less permeable.
- organic shale formations include immobile organic matter that can block the flow of hydrocarbons between and through pores within the formation.
- FIG. 1 shows a method a method for treating an organic shale formation to increase permeability in accordance with one embodiment of the present disclosure
- FIG. 2 shows a hydraulic fracturing operation in accordance with one embodiment of the present disclosure
- FIG. 3 shows a plot of efficacy of various treatment fluids, composed of pure solvents, in dissolving bitumen in organic shale formation samples, in accordance with various embodiments of the present disclosure
- FIG. 5 shows a plot of absorbance for treatment fluids, composed of a solvent and a combination of two surfactants at different ratios of the two surfactants, after exposure to organic shale formation samples in accordance with various embodiments of the present disclosure
- FIG. 6 shows a plot of absorbance for treatment fluids, composed of emulsions with different solvent-surfactant ratios, after exposure to organic shale formation samples in accordance with various embodiments of the present disclosure
- FIG. 7 shows a plot of absorbance for treatment fluids, composed of emulsions with varying salinity, after exposure to organic shale formation samples in accordance with various embodiments of the present disclosure
- FIG. 8 shows a plot of absorbance for treatment fluids, composed of emulsions with varying methanol content, after exposure to organic shale formation samples in accordance with various embodiments of the present disclosure
- FIG. 10 shows a plot of absorbance for treatment fluids, composed of solvent-solvent mixtures, after exposure to organic shale formation samples in accordance with various embodiments of the present disclosure.
- Keogen is an organic solid material that is insoluble in organic solvents.
- “Bitumen” is an organic, immobile, and highly viscous substance that is soluble in organic solvents.
- An “oil” is a liquid hydrocarbon that is mobile (without obstruction) under natural temperature and pressure conditions within a formation.
- a range “from X to Y” includes the values of “X” and “Y.” The ranges stated herein should be interpreted to include boundary values.
- Illustrative embodiments of the present disclosure are directed to methods and treatment fluids for treating an organic shale formation to increase permeability.
- FIG. 1 shows an example of the method 100 .
- an organic shale formation is treated with a treatment fluid.
- the treatment fluid is transported to a portion of the shale formation using a wellbore that traverses the formation.
- the treatment fluid includes a solvent that dissolves bitumen in the shale formation and increases permeability of the shale formation.
- oil is recovered from the shale formation. By removing bitumen from pores and pore throats within the formation, the solvent increases permeability of the formation and allows mobile oil to flow more easily through the formation. Details of illustrative embodiments are provided below.
- the treatment fluid can have one or more components with different concentrations.
- the treatment fluid is composed of a pure solvent (e.g., 100% concentration) or a combination of two or more solvents.
- the treatment fluid is composed of one or more solvents and one or more other components.
- the concentration of the solvent within the treatment fluid can vary from 0.01% to 100%.
- the solvent can be a terpene-based solvent.
- the terpene-based solvent is a limonene-based solvent (e.g., d-limonene) and/or a pinene-based solvent (e.g., turpentine).
- a limonene-based solvent e.g., d-limonene
- a pinene-based solvent e.g., turpentine
- Many terpene-based solvents are biodegradable.
- the solvent may also be cyclohexanone, N-methylpyrrolidinone, an aromatic fluid, a dialkyl ether, an alkenoic acid ester, 2-methyltetrahydrofuran, an alkylated fatty acid, and/or a fatty acid alkyl ester (e.g., biodiesel, methyl caprylate/caprate, methyl laurate, methyl myristate, canola methyl ester, soya methyl ester, methyl and/or palmitate/oleate).
- the solvent may include a combination of two or more of the components listed above in this paragraph.
- xylene is not used as a solvent.
- the treatment fluid can include one or more other components.
- the treatment fluid may include a diluent, such as water or a gas-based foam.
- the gas-based foam can include nitrogen, carbon dioxide, methane, and/or propane.
- the solvent is diluted within the diluent.
- a surfactant can be used to create an emulsion between the water and the solvent.
- the emulsion is used to make a stable mixture of the solvent and the water.
- the surfactant can be a nonionic ethoxylated surfactant that includes (i) an alcohol, (ii) an octyl-phenol or nonylphenol, (iii) a sorbitan fatty-acid ester, and/or (iv) a fatty acid.
- the surfactant can be an anionic surfactant, such as an alkyl sulfate, a dialkyl sulfosuccinate, and/or a linear alkyl benzene sulphonate.
- the solvent is emulsified within the water (where water is the external phase). In other embodiments, the water is emulsified within the solvent (where solvent is the external phase).
- FIG. 2 shows a hydraulic fracturing operation in accordance with one embodiment of the present disclosure.
- the hydraulic fracturing operation is performed in a production wellbore 200 that traverses an organic shale formation 202 .
- the fracturing operation is performed by pumping a treatment fluid (liquid, gaseous, or a combination) into the wellbore from a surface reservoir 204 using a pump 206 .
- the treatment fluid communicates with the formation through a series of perforations 208 .
- the treatment fluid communicates with the formation through port collar opening devices or through injection into uncased open-hole intervals.
- the treatment fluid may be hydraulically confined to a particular portion of the wellbore by using packers ( 210 and 212 ). For example, if the wellbore includes a completion with packers, then some or all of the perforations 208 in a particular area may be hydraulically isolated from other portions of the wellbore so that the fracturing is performed on a particular portion of the shale formation 202 .
- the pressure of the treatment fluid is increased using the pump 206 .
- the communication of that increased pressure to the shale formation 202 creates new fractures and widens existing fractures (collectively, fractures 214 in the formation).
- the solvent is a component of the treatment fluid (e.g., hydraulic fracturing fluid).
- the concentration of the solvent within the treatment fluid is from 0.01% to 5.0%.
- the solvent is emulsified in an aqueous treatment fluid using a surfactant. The solvent flows into the fractures 214 of the formation and/or the solid matrix 202 of the formation and dissolves bitumen within the fractures, pore throats, and/or pores of the shale formation. The treatment fluid then flows back from the formation 202 and into the wellbore 200 .
- the fluid As the treatment fluid flows back into the wellbore 200 , the fluid carries the dissolved bitumen with it. By removing a portion of the bitumen, the solvent within the treatment fluid enhances the permeability of the shale formation 202 . Additionally or alternatively, a treatment fluid with the solvent can be used as a spearhead fluid. Spearhead fluids are used to treat the shale formation 202 prior to performing the main fracturing treatment and to remove perforation debris from the near-wellbore zone.
- the treatment fluids can be used as part of an enhanced oil recovery (EOR) operation.
- EOR enhanced oil recovery
- a treatment fluid is injected through an injection wellbore and into the organic shale formation.
- the treatment fluid passes through the shale formation and is recovered at a production wellbore.
- the treatment fluid flushes out oil in the formation and facilitates movement of the oil through the formation and into the production wellbore.
- the solvent may be a component of the treatment fluid (e.g., EOR fluid) used to recover oil.
- the concentration of the solvent within the EOR treatment fluid is from 0.01% to 100%.
- the combination of the surfactant and the solvent has a concentration from 5% to 10%.
- the EOR operation can be performed only in the production wellbore. The treatment fluid is injected into the production wellbore and into the shale formation. Then, after a time period that allows the treatment fluid to dissolve bitumen, the treatment fluid is pumped back to the production wellbore.
- the treatment fluids described herein can be used as part of a remedial treatment.
- Remedial treatments typically occur after the organic shale formation has been producing oil over an extended time period.
- solids and viscous materials are transported through the formation with lighter oils.
- the solids and viscous materials are deposited in fractures and pores within the formation.
- Bitumen is one material that is deposited in this manner.
- a treatment fluid can be injected through the production wellbore and into (i) a solid matrix within the formation, (ii) a fracture within the formation, (iii) a fracture within the formation and then into the solid matrix of the formation, or (iv) a combination thereof.
- the treatment fluid dissolves the bitumen that has been deposited by the production process.
- the fluid flushes out the dissolved bitumen.
- the solvent may be a component of the treatment fluid used to flush out the bitumen.
- the concentration of the solvent within the remedial treatment fluid is from 0.01% to 100%.
- the treatment fluid is pumped and injected into a far-wellbore zone of an organic shale formation. More specifically, the far-wellbore zone includes areas of the organic shale formation that are at least 100 meters (e.g., 500 meters or 1000 meters) away from a production wellbore.
- the far-wellbore zone includes areas of the organic shale formation that are at least 100 meters (e.g., 500 meters or 1000 meters) away from a production wellbore.
- the treatment fluids and treatment methods described herein are not limited to removing any particular type of bitumen.
- the treatment fluids are used to dissolve and remove naturally-occurring bitumen within organic shale formations, such as in the hydraulic fracturing and EOR operations described above.
- the treatment fluids can be used to dissolve and remove bitumen deposited by the production process, such as in the remedial operation described above.
- the treatment fluid can be pumped and injected into an organic shale formation at various temperatures.
- the treatment fluid can be heated at the surface to temperatures above 150° C. and then injected into the formation.
- the high temperature of the treatment fluid can help dissolve and reduce the viscosity of the bitumen within the formation.
- the treatment fluid is not heated at the surface and enters the wellbore from the surface at temperatures below 150° C. Treatment fluids at cooler temperatures are also capable of dissolving and removing bitumen from organic shale formations.
- FIGS. 3-10 were generated by exposing organic shale formation samples to various treatment fluids.
- the formation samples were exposed to pure solvents, solvent mixtures, or solvent emulsions at 80° C. until bitumen dissolution had equilibrated.
- the treatment fluids (with dissolved bitumen) were then measured using visible light absorbance at 411 nm, 534 nm, and/or 574 nm. Generally, the greater the absorbance of the treatment fluid (with dissolved bitumen), the more effectively the fluid removed bitumen from the sample.
- the absorbance values were background-corrected using nearby lower absorbance regions at 470 nm (for 411 nm measurements) and 780 nm (for 534 nm and 574 nm measurements) to account for light scattering of emulsion droplets or suspended particles resulting in higher absorbance values.
- FIG. 3 shows a plot of efficacy for various treatment fluids in dissolving bitumen in organic formation samples.
- the treatment fluids were composed of pure solvents.
- One application for a treatment fluid composed of a pure solvent is as part of a remedial treatment operation.
- FIG. 3 shows a plot of efficacy for various treatment fluids in dissolving bitumen in organic formation samples.
- the treatment fluids were composed of pure solvents.
- One application for a treatment fluid composed of a pure solvent is as part of a remedial treatment operation.
- the solvents include (i) medium-chain ethers (NACOL 6TM and NACOL 8TM from Sasol of Africa), (ii) different grades of d-limonene (TECHNICAL GRADE D-LIMONENETM and LIMONENE OSTM from Florida Chemical, Inc., of Winter Haven, Fla.), (iii) a terpene-based xylene replacement (FC-PROTM from Florida Chemical, Inc.), (iv) low-molecular weight alcohols (methanol, ethanol, and isopropanol), and (v) an aromatic solvent (AROMATIC 150 NDTM from ExxonMobil of Irving, Tex.). Dichloromethane was used as a positive control and water was used as a negative control. As shown in FIG. 3 , the d-limonene solvents and the terpene-based xylene replacement most effectively removed bitumen from the organic formation samples.
- NACOL 6TM and NACOL 8TM from Sasol of Africa
- FIGS. 4-9 were generated by exposing formation samples to different treatment fluids composed of surfactant-based emulsions.
- the emulsions were composed of a 5% surfactant-solvent portion and a 95% aqueous/alcohol portion by volume.
- TECHNICAL GRADE D-LIMONENETM was used as the emulsified solvent.
- a treatment fluid with this concentration of solvent can be used as part of hydraulic fracturing operation, an EOR operation, and/or a remedial treatment.
- the treatment fluids described herein can use surfactants with various hydrophilic-lipophilic balance (HLB) values.
- a solvent in water emulsion may have an HLB value from 10.5 to 18.
- the solvent in water emulsion may have an HLB value from 13.5 to 15.5.
- the HLB of a surfactant is a measure of the proportion of hydrophilic to hydrophobic moieties the surfactant contains.
- the HLB can be matched to a given organic solvent to ensure good emulsification of that solvent in an aqueous media.
- FIG. 4 shows a plot of absorbance for treatment fluids composed of surfactants with different HLB values.
- the figure shows bitumen dissolution for treatment fluid with a ratio of 1:2 of polysorbate and d-limonene, respectively.
- the polysorbate was a mixture of TWEEN 20TM and TWEEN 85TM.
- concentrations of TWEEN 20TM and TWEEN 85TM were varied to produce a particular HLB value.
- One optima is at an HLB value of 14 for 534 nm and 574 nm components, while the other optima is at an HLB value of 15 for the 411 nm component.
- FIG. 5 shows a plot of absorbance for treatment fluids composed of a solvent and a combination of two surfactants at different ratios of the two surfactants.
- the surfactants include (i) a polysorbate mixture prepared at an HLB value of 13.5 and (ii) TRITON-X100TM, which naturally has the same HLB value.
- the high absorbance values at 534 nm and 574 nm in the 4:1 sample may be due to interference from emulsion droplet light-scattering background.
- FIG. 5 shows that efficiency can depend on the composition of the surfactant, not just its HLB value.
- the treatment fluids described herein can have different solvent-surfactant ratios.
- solvent-surfactant ratios can be from 1:1 to 1:3.
- FIG. 6 shows a plot of absorbance for treatment fluids composed of emulsions with different solvent-surfactant ratios. Although higher concentrations of solvent better dissolve bitumen, higher concentrations of surfactant should better emulsify the dissolved bitumen.
- FIG. 6 shows that higher concentrations of surfactant best emulsify bitumen components that absorb at 411 nm, while intermediate ratios best emulsify bitumen components that absorb at 534 nm and 574 nm.
- FIG. 7 shows a plot of absorbance for treatment fluids composed of emulsions with varying salinity equilibrated against powdered shale at 80° C.
- the salinity of the emulsions was varied using potassium chloride (KCL).
- Emulsion A included a ratio of 3:1 for TRITON X100TM and d-limonene, respectively.
- Emulsion B included a ratio of 1:2:1 for polysorbate, TRITON X100TM, and d-limonene, respectively.
- Emulsion C included a ratio of 3:1 for polysorbate and d-limonene, respectively.
- Emulsions A-C had a surfactant plus limonene content of 5% and the polysorbate was a blend of TWEEN 20TM and TWEEN 85TM with a HLB value of 14.5.
- columns marked with “N.D.” could not be measured (Emulsion A at 0.05M KCl and Emulsion B at 0.2M KCl exhibited two separate liquid phases and could not be quantified).
- FIG. 7 shows that increases in salinity increase bitumen emulsification, but can also cause destabilization of the resulting emulsion. For this reason, in various embodiments, the amount of salt within the treatment fluid is less than 1%.
- FIG. 8 shows a plot of absorbance for treatment fluids composed of emulsions with varying methanol content equilibrated against rock powder.
- Emulsion A included a ratio of 3:1 for polysorbate and d-limonene (with 0.2M KCl).
- Emulsion B included a ratio of 4:1:2.5 for TRITON X100TM, polysorbate, and d-limonene, respectively.
- Emulsion C included a ratio of 3:1:1:2.5 for TRITON X100TM, polysorbate, 1M dioctyl sodium sulfosuccinate dissolved in isopropanol, and d-limonene, respectively.
- Emulsion A was a blend of TWEEN 20TM and TWEEN 85TM with an HLB value of 14.5.
- the polysorbate in Emulsions B and C was a blend of TWEEN 80TM and TWEEN 85TM with an HLB value of 13.5.
- FIG. 9 shows a plot of absorbance for treatment fluids composed of emulsions with varying isopropanol content equilibrated against rock powder.
- Emulsion A included a ratio of 4:1:2.5 for TRITON X100TM, polysorbate, and d-limonene, respectively.
- Emulsion B included a ratio of 3:1:1:2.5 for TRITON X100TM, polysorbate, 1M dioctyl sodium sulfosuccinate dissolved in isopropanol, and d-limonene, respectively.
- the polysorbate was a mixture of TWEEN 20TM and TWEEN 85TM with an HLB value of 13.5 in both emulsions.
- FIGS. 8 and 9 show that increases in alcohol content (e.g., methanol or isopropanol) decrease bitumen emulsification.
- FIG. 10 shows a plot of absorbance for treatment fluids composed of solvent-solvent mixtures. The figure was generated by exposing formation samples to different treatment fluids composed of solvent-solvent mixtures.
- a first set of mixtures included an aromatic solvent (AROMATIC 150 NDTM) with 5%, 10%, and 20% concentrations of cyclohexane.
- a second set of mixtures included the aromatic solvent (AROMATIC 150 NDTM) with 5%, 10%, and 20% concentrations of limonene. The 0% and 100% concentrations were used as controls.
- FIG. 10 shows that a concentration from 5% to 20% of cyclohexane or limonene can significantly improve the performance of the aromatic fluid.
Abstract
Description
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US11339321B2 (en) | 2019-12-31 | 2022-05-24 | Saudi Arabian Oil Company | Reactive hydraulic fracturing fluid |
RU2738055C1 (en) * | 2020-03-05 | 2020-12-07 | Общество с ограниченной ответственностью "Вэл Инжиниринг" | Process fluid for cleaning bottomhole formation zone, well shaft, inner surface of tubing string, borehole filters |
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