CA2279876A1 - Oil production method - Google Patents
Oil production method Download PDFInfo
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- CA2279876A1 CA2279876A1 CA002279876A CA2279876A CA2279876A1 CA 2279876 A1 CA2279876 A1 CA 2279876A1 CA 002279876 A CA002279876 A CA 002279876A CA 2279876 A CA2279876 A CA 2279876A CA 2279876 A1 CA2279876 A1 CA 2279876A1
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- 238000004519 manufacturing process Methods 0.000 title claims description 15
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 claims abstract description 72
- 239000000243 solution Substances 0.000 claims abstract description 53
- 239000003795 chemical substances by application Substances 0.000 claims abstract description 51
- 239000013049 sediment Substances 0.000 claims abstract description 33
- 239000000839 emulsion Substances 0.000 claims abstract description 29
- 238000002347 injection Methods 0.000 claims abstract description 27
- 239000007924 injection Substances 0.000 claims abstract description 27
- 239000007762 w/o emulsion Substances 0.000 claims abstract description 23
- UHOVQNZJYSORNB-UHFFFAOYSA-N Benzene Chemical compound C1=CC=CC=C1 UHOVQNZJYSORNB-UHFFFAOYSA-N 0.000 claims abstract description 18
- 239000004215 Carbon black (E152) Substances 0.000 claims abstract description 18
- 229930195733 hydrocarbon Natural products 0.000 claims abstract description 18
- 150000002430 hydrocarbons Chemical class 0.000 claims abstract description 18
- 238000006243 chemical reaction Methods 0.000 claims abstract description 16
- 239000002904 solvent Substances 0.000 claims abstract description 12
- 230000004888 barrier function Effects 0.000 claims abstract description 11
- 239000003350 kerosene Substances 0.000 claims abstract description 8
- 239000011347 resin Substances 0.000 claims abstract description 6
- 229920005989 resin Polymers 0.000 claims abstract description 6
- 238000002955 isolation Methods 0.000 claims abstract description 5
- 230000002028 premature Effects 0.000 claims abstract description 5
- 230000015572 biosynthetic process Effects 0.000 claims abstract description 3
- 238000000034 method Methods 0.000 claims description 51
- 230000006378 damage Effects 0.000 claims description 9
- 230000035699 permeability Effects 0.000 claims description 8
- 238000002156 mixing Methods 0.000 claims description 5
- 239000002245 particle Substances 0.000 claims description 3
- XQCFHQBGMWUEMY-ZPUQHVIOSA-N Nitrovin Chemical compound C=1C=C([N+]([O-])=O)OC=1\C=C\C(=NNC(=N)N)\C=C\C1=CC=C([N+]([O-])=O)O1 XQCFHQBGMWUEMY-ZPUQHVIOSA-N 0.000 claims description 2
- 239000011148 porous material Substances 0.000 claims description 2
- 230000001681 protective effect Effects 0.000 claims 1
- 239000000203 mixture Substances 0.000 abstract description 14
- 229920000642 polymer Polymers 0.000 abstract description 7
- 238000001179 sorption measurement Methods 0.000 abstract description 5
- 238000004132 cross linking Methods 0.000 abstract description 4
- 239000006185 dispersion Substances 0.000 abstract 1
- 229920002401 polyacrylamide Polymers 0.000 description 16
- 150000003839 salts Chemical class 0.000 description 10
- QTBSBXVTEAMEQO-UHFFFAOYSA-M Acetate Chemical compound CC([O-])=O QTBSBXVTEAMEQO-UHFFFAOYSA-M 0.000 description 8
- VYZAMTAEIAYCRO-UHFFFAOYSA-N Chromium Chemical compound [Cr] VYZAMTAEIAYCRO-UHFFFAOYSA-N 0.000 description 7
- 238000001914 filtration Methods 0.000 description 7
- 230000000903 blocking effect Effects 0.000 description 6
- 239000012530 fluid Substances 0.000 description 6
- 239000000126 substance Substances 0.000 description 6
- UXVMQQNJUSDDNG-UHFFFAOYSA-L Calcium chloride Chemical compound [Cl-].[Cl-].[Ca+2] UXVMQQNJUSDDNG-UHFFFAOYSA-L 0.000 description 5
- 229910052784 alkaline earth metal Inorganic materials 0.000 description 5
- 239000001110 calcium chloride Substances 0.000 description 5
- 229910001628 calcium chloride Inorganic materials 0.000 description 5
- 235000011148 calcium chloride Nutrition 0.000 description 5
- 150000001875 compounds Chemical class 0.000 description 5
- 239000003431 cross linking reagent Substances 0.000 description 5
- 238000006073 displacement reaction Methods 0.000 description 5
- 229910052911 sodium silicate Inorganic materials 0.000 description 5
- 239000003381 stabilizer Substances 0.000 description 5
- -1 aluminum salt Chemical class 0.000 description 4
- WDIHJSXYQDMJHN-UHFFFAOYSA-L barium chloride Chemical compound [Cl-].[Cl-].[Ba+2] WDIHJSXYQDMJHN-UHFFFAOYSA-L 0.000 description 4
- 229910001626 barium chloride Inorganic materials 0.000 description 4
- 150000007519 polyprotic acids Polymers 0.000 description 4
- 239000004094 surface-active agent Substances 0.000 description 4
- 239000004115 Sodium Silicate Substances 0.000 description 3
- YXFVVABEGXRONW-UHFFFAOYSA-N Toluene Chemical compound CC1=CC=CC=C1 YXFVVABEGXRONW-UHFFFAOYSA-N 0.000 description 3
- 150000001342 alkaline earth metals Chemical class 0.000 description 3
- 238000013459 approach Methods 0.000 description 3
- QIFOFCWBJPAXTM-UHFFFAOYSA-N chembl375232 Chemical compound C1=CC(C(=O)O)=CC=C1C(C1=CC=C(N1)C(C=1C=CN=CC=1)=C1C=CC(=N1)C(C=1C=CN=CC=1)=C1C=CC(N1)=C1C=2C=CN=CC=2)=C2N=C1C=C2 QIFOFCWBJPAXTM-UHFFFAOYSA-N 0.000 description 3
- 239000013505 freshwater Substances 0.000 description 3
- NTHWMYGWWRZVTN-UHFFFAOYSA-N sodium silicate Chemical compound [Na+].[Na+].[O-][Si]([O-])=O NTHWMYGWWRZVTN-UHFFFAOYSA-N 0.000 description 3
- TWRXJAOTZQYOKJ-UHFFFAOYSA-L Magnesium chloride Chemical compound [Mg+2].[Cl-].[Cl-] TWRXJAOTZQYOKJ-UHFFFAOYSA-L 0.000 description 2
- 239000003849 aromatic solvent Substances 0.000 description 2
- 235000013372 meat Nutrition 0.000 description 2
- 238000005191 phase separation Methods 0.000 description 2
- 239000011435 rock Substances 0.000 description 2
- 238000000926 separation method Methods 0.000 description 2
- CDBYLPFSWZWCQE-UHFFFAOYSA-L sodium carbonate Substances [Na+].[Na+].[O-]C([O-])=O CDBYLPFSWZWCQE-UHFFFAOYSA-L 0.000 description 2
- 238000012360 testing method Methods 0.000 description 2
- 229920002134 Carboxymethyl cellulose Polymers 0.000 description 1
- 241000566515 Nedra Species 0.000 description 1
- 229910052782 aluminium Inorganic materials 0.000 description 1
- BFNBIHQBYMNNAN-UHFFFAOYSA-N ammonium sulfate Chemical compound N.N.OS(O)(=O)=O BFNBIHQBYMNNAN-UHFFFAOYSA-N 0.000 description 1
- 229910052921 ammonium sulfate Inorganic materials 0.000 description 1
- 239000001166 ammonium sulphate Substances 0.000 description 1
- 235000011130 ammonium sulphate Nutrition 0.000 description 1
- 150000001450 anions Chemical class 0.000 description 1
- 238000004581 coalescence Methods 0.000 description 1
- JHIVVAPYMSGYDF-UHFFFAOYSA-N cyclohexanone Chemical compound O=C1CCCCC1 JHIVVAPYMSGYDF-UHFFFAOYSA-N 0.000 description 1
- 239000002283 diesel fuel Substances 0.000 description 1
- 230000000694 effects Effects 0.000 description 1
- 238000005187 foaming Methods 0.000 description 1
- 238000009533 lab test Methods 0.000 description 1
- 229910001629 magnesium chloride Inorganic materials 0.000 description 1
- 150000007522 mineralic acids Chemical class 0.000 description 1
- 239000003921 oil Substances 0.000 description 1
- 230000035515 penetration Effects 0.000 description 1
- 235000019353 potassium silicate Nutrition 0.000 description 1
- 238000002360 preparation method Methods 0.000 description 1
- 229920006395 saturated elastomer Polymers 0.000 description 1
- 229910000029 sodium carbonate Inorganic materials 0.000 description 1
- 239000001488 sodium phosphate Substances 0.000 description 1
- 229910000162 sodium phosphate Inorganic materials 0.000 description 1
- 230000006641 stabilisation Effects 0.000 description 1
- 238000011105 stabilization Methods 0.000 description 1
- RYFMWSXOAZQYPI-UHFFFAOYSA-K trisodium phosphate Chemical compound [Na+].[Na+].[Na+].[O-]P([O-])([O-])=O RYFMWSXOAZQYPI-UHFFFAOYSA-K 0.000 description 1
Classifications
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK 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
- E21B43/32—Preventing gas- or water-coning phenomena, i.e. the formation of a conical column of gas or water around wells
-
- 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
- C09K8/50—Compositions for plastering borehole walls, i.e. compositions for temporary consolidation of borehole walls
- C09K8/504—Compositions based on water or polar solvents
- C09K8/506—Compositions based on water or polar solvents containing organic compounds
-
- 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
- C09K8/50—Compositions for plastering borehole walls, i.e. compositions for temporary consolidation of borehole walls
- C09K8/504—Compositions based on water or polar solvents
- C09K8/506—Compositions based on water or polar solvents containing organic compounds
- C09K8/508—Compositions based on water or polar solvents containing organic compounds macromolecular compounds
- C09K8/512—Compositions based on water or polar solvents containing organic compounds macromolecular compounds containing cross-linking agents
Landscapes
- Life Sciences & Earth Sciences (AREA)
- General Life Sciences & Earth Sciences (AREA)
- Chemical & Material Sciences (AREA)
- Engineering & Computer Science (AREA)
- Organic Chemistry (AREA)
- Materials Engineering (AREA)
- Geology (AREA)
- Mining & Mineral Resources (AREA)
- Geochemistry & Mineralogy (AREA)
- Physics & Mathematics (AREA)
- Fluid Mechanics (AREA)
- Environmental & Geological Engineering (AREA)
- Colloid Chemistry (AREA)
- Production Of Liquid Hydrocarbon Mixture For Refining Petroleum (AREA)
- Nitrogen And Oxygen Or Sulfur-Condensed Heterocyclic Ring Systems (AREA)
- Liquid Carbonaceous Fuels (AREA)
Abstract
Essence of invention: to create water isolation barrier in flushed highly permeable sections of the reservoir though injecting water solutions of two or more gel or sediment forming agents water solutions of the agents are injected into the reservoir in the form of blends (1:1 in volume) of a 50% aggregate stable water-in-oil emulsion in low viscosity hydrocarbon solvent (benzene, kerosene etc.) where prior to this 5-20 mass % of concentrated porphirine and asphaltene-resin oil components are dissolved (i.e. OPA agent prepared as per TU -24358-001-21166006-97). Dispersion of the resulting water-in-oil emulsion (dimensions of stabilized water droplets in "oil") should be comparable to the dimensions of flushed highly permeable sections of the reservoir. For the chemical reaction of injected gel or sediment forming agents to take place after the injection of blended 50% aggregate stable water-in-oil emulsion into highly permeable sections of the formation, its concentration in these sections, a hydrocarbon solution of water-in-oil emulsions demulsifier is injected in the reservoir. Concentrated water-in-oil emulsion is destroyed, water solutions of gel and sediment forming agents are formed and blended and chemical reaction of these agents tales place in highly permeable section of the reservoir resulting in a water isolation barrier (cross linking polymer composition or insoluble in water sediment). The present invention allows to increase effectiveness of treatment considerably through water solutions of two or more gel or sediment forming agents due to avoiding premature chemical reaction of applied agents and their adsorption in reservoir conditions.
Description
OIL PRODUCTION METHOD
The invention is referred to oil production, in particular to methods of oil production from heterogeneous reservoirs with conformance control to level out injectivity profile of injection wells and decrease water inflow of production wells. The method includes simultaneous or consequent injection of solutions of two or more gel or sediment forming agents.
The essence of the invention: avoidance of premature chemical reaction and adsorption of agents in the process of injecting their water solutions into the reservoir and raising the efficiency of blocking water flushed intervals and reservoir fractures due to forming viscous elastic gel directly in such areas with the use of polyacrylamide (PAA) water solutions and salts of polyvalence ration or forming a stable non soluble sediment when injecting water solutions of salts of polybasic acid such as sodium silicate and alkaline-earth metal, such as calcium chloride. The method is applied through injection of water solution of two or more gel or sediment forming agents into the reservoir as an aggregate stable water-in-oil emulsion in low viscosity hydrocarbon solvent (benzene, kerosene etc). 5-20% of mass of porphirine and asphaltene-resin oil components are dissolved in the hydrocarbon solvent prior to that. For every applied water agent solution first 50%
(volume) of aggregate stable water-in-oil emulsion is prepared separately with the size of particles (globules of emulsified water agent solution) comparable to the size of pores of high permeability sections of the reservoir. Then previously prepared emulsions of gel or sediment forming agents are blended in equal volumes prior to injection. After injection of a blended emulsion for its destruction and foaming a water blocking barrier in the high permeability sections of the reservoir a hydrocarbon solution of demulsifier of a water-in-oil emulsion is injected into the reservoir in a form of viscous elastic gel (or non-soluble sediment) in the amount sufficient for destruction of injected volume of the aggregate stable water-in-oil emulsion There exist oil production blocking methods through leveling out injectivity profile of a heterogeneous reservoir. They involve simultaneous or consequent injection of a water PAA solution with a cross linking agent (water solution of a polyvalence ration salt) into the reservoir where to decrease polymer volume and control velocity of the chemical reaction of gel forming (linking) a pH of water PAA solution and the linking agent is kept at the level of 3-4 after blending and after injection it reaches 7-10 (a.c.
SU 1128573 A, C
08 L33/26 and C 08 K 3/24, E 21 B 43/22 and SU 1627678 Al, E21 B./43, 33/138).
However these methods do not prevent a change in the concentration of injected agents in reservoir conditions and have a limited application due to complications in reaching the pH of 7-10 of injected water solutions in the reservoir. Besides, using an inorganic acid to control the time of linking does not prevent chemical destruction of the PAA
molecules and in general is not applicable to control velocity of the chemical reaction of residue forming agents.
In the oil production method (Patent RU 2086757 C1, 6E 21 B 43/22) to control the time of gel forming (linking) and decrease mechanical and chemical (salt) destruction of the PAA water solutions of PAA and cross linking agent (aluminum salt) are consequently injected into the reservoir and fresh water is injected between them. With this method there is a possibility that water PAA solution, fresh water and water based cross linking agent being low viscosity systems will flow into both high and low permeability sections of the reservoir. This in its turn will inevitably result in unnecessary high volumes of applied agents. Besides, this method is not ei~ective at consequent injection of water based salt forming agents into the reservoir due to a sharp decrease in the velocity of the chemical reaction when these solutions are diluted with fresh water.
The closest to the proposed method in its technical essence is the method of injecting solution of polybasic acid salt emulsified in hydrocarbon fluid (for example, sodium silicate, sodium phosphate or sodium carbonate) into the reservoir (Patent RU
1, 6 E21 B 43/22). As a compound containing alkaline-earth metal salt a water solution of an alkaline-earth metal is used (for example, calcium chloride, magnesium chloride or barium chloride) or its emulsion in a hydrocarbon fluid (for example, in oil, diesel fuel, kerosene). As an emulsion stabilizer low soluble surfactants are used:
Emultal, Neftechim, Neftenol, Neonol, AF9-4, AF9-6, OP-4, sodium salts of SZHK
(Translator's note: unclear abbreviation) etc.
The major disadvantage of this method selected as a prototype of the invention is low aggregate stability of water-in-oil emulsions stabilized by the aforementioned low soluble surfactants which leads to their destruction (water phase separation) at a short depth of penetration (filtration) of the water-in-oil emulsion into the reservoir. This circumstance shows that it is impossible to ei~ectively apply this method at blending and simultaneous injection into the reservoir of two or more water solutions of sediment forming agents as a water-in-oil emulsion as the chance of emulsion separation and forming non soluble sediment in the near well bore area is high. Therefore this method can only be applied through consequent injection of water solution of a salt of polybasic acid emulsified in hydrocarbon fluid in the presence of a low soluble surfactant and then water solution containing a alkaline-earth metal salt or an emulsion of this solution in a hydrocarbon solvent, also in the presence of a low soluble surfactant.
The method is applied as follows. An estimated volume of aggregate stable (50%
of volume) water-in-oil emulsions in low viscosity hydrocarbon solvent (for example, kerosene containing prior dissolved 5-20% (mass) of asphaltene-resin and porphirin (ARP) compounds - natural stabilizers of water-in-oil emulsions) is prepared for each of the used water solutions of gel or sediment forming agents. This is performed at the well selected for blocking methods taking into view geophysical and physical parameters of the reservoir and current development parameters. The intensity and time of blending for each of applied water solutions of agents with specified concentration and hydrocarbon solvent containing specified amount of natural stabilizers of the water-in-oil emulsion should be such that finally for applied water solution of gel or sediment forming agent a thinly dispersed (the dimensions of water globules should be comparable to the dimensions of flushed highly permeable sections of the reservoir) aggregate stable (not coalescenting while settling and being treated in a centrifugal filed) water-in-oil emulsion would result. These properties of formed water-in-oil emulsions are easily controlled in practice with the use of a common microscope and vile centrifuge with 6,000 RPMs.
Prior to injecting water-in-oil emulsions of two or more gel or sediment forming agents into the reservoir for each selected composition water-in-oil emulsions are blended in equal volumes, i.e. in each instance both with gel forming and sediment forming compositions water blends of the aforementioned agents are injected into the reservoir as a thinly dispersed aggregate stable water-in-oil emulsion in low viscosity hydrocarbon solvent. The drops (globules) of this or that injected agent water solution are isolated from one another by a strong armored film of natural stabilizers which do not only prevent early chemical reaction between injected compounds but also prevent adsorption of injected agents on active hard areas of the reservoir which allows to drastically decrease volumes of applied compounds and reach expected results. Aggregate stable blend of water-in-oil emulsions are injected in volumes sufficient to form highly viscous emulsion "plugs" in flushed and permeable sections which in reality is traced through the change (excess) of injection pressure of the injected into the reservoir system. Then a specified volume of hydrocarbon (mainly in an aromatic solvent) solution of a demulsifier is injected into the well in the amount sufficient to destroy injected aggregate stable water-in-oil emulsion. The well is then allowed 12-36 hours for a reaction. Within this time a destruction (coalescence) of injected into the reservoir water-in-oil emulsion and blending of formed water solutions of gel or sediment forming agents takes places as well as their chemical reaction the result of which is forming water blocking barriers in flushed and highly permeable sections. The barriers are made of highly viscous cross-linking polymer compositions (CLPC) or sediment that is strong and not destructed by water.
The objective of the proposed method is to raise the efficiency of oil production due to avoiding premature chemical reaction and adsorption of two or more applied gel or sediment forming agents in the process of simultaneous injection of their water solutions into the reservoir.
The objective is achieved though the fact that in the proposed method of oil production water solutions of applied agents are injected into the reservoir as an aggregate stable water-in-oil emulsion in a low viscosity hydrocarbon solvent (benzene, kerosene etc.) in which 5-20% (mass) of porphirin and asphaltene-resin oil components are dissolved prior to it, porphirin and asphaltene-resin oil components being the major most capable natural stabilizers of water-in-oil emulsions ("Stabilization and Destruction of Oil Emulsions" by G.N. Pozdnyshev, M. "Nedra", 1982, page 221 ).
Another distinction of the proposed method is that for each water agent a 50%
(volume) aggregate stable water-in-oil emulsion is prepared separately prior to injection with the dimensions of the particles (globules of emulsified agent solution) comparable to the dimensions of flushed highly permeable reservoir sections and later prior to injection aggregate stable emulsions of gel or sediment forming agents are blended in equal volumes. At the time of injection of such a blend of aggregate stable emulsions i.e.
emulsions which are not destroyed while filtering through the porous reservoir rock, the emulsion is concentrated (packed) in the most permeable and fracture sections of the reservoir up to formation of highly viscous emulsion "plugs' containing 90-95%
(volume) of blended globules of water solutions of gel or sediment forming agents. Thus without free water phase separation (separation of the injected agents' water solutions) not only is adsorption of applied agents on the hard reservoir rock surface avoided, but a chemical reaction of the applied agents does not take place.
The process of forming highly viscous concentrated "plugs" of blended water-in-oil emulsions from aggregate stable globules of agents' water solutions (not reacting with one another) in highly permeable and fracture reservoir sections has great importance as a water blocking barrier. The fact that such a barrier is formed can be easily traced through the increase of injection pressure (at constant injection volumes) or through decrease in injection volumes at constant injection pressure.
Another distinction of the developed technical approach is a possibility to make the barrier stronger due to injection of a demulsifier in volumes sufficient to separate injected aggregate stable water-in-oil emulsion and a chemical reaction between gel and sediment forming agents forming cross-linking polymer systems (CLPS) or sediment forming salt compounds.
Parameters which make the proposed technical approach distinct from the prototype were not traced in other technical approaches and as a result the proposed method complies with "sufficient distinction" category.
The following chemicals and brands containing them are applied in the method:
~ As gel forming agents: 0.01-5.0% water solutions of anion polymer i.e.
polyacrylamid, carboxyl methyl cellulose etc. and as a cross linking agent water solution (0.003-0.2%) of polyvalence ration salts, i.e. chrome acetate etc.
~ As sediment forming agents: water solutions of salts of polybasic acids, i.e. water solution (10-20%) of sodium silicate (liquid glass), ammonium sulphate etc and water solutions (10-30%) of salts of alkaline-earth metals i.e. calcium chloride, barium chloride etc.
When 50% water-in-oil emulsions are formed the above water solutions disperse in low viscous hydrocarbon solvent i.e. kerosene (or gas benzene) where 5-20%
concentrated ARP compounds are dissolved prior to that, such as OPA (TU 2458-001-21166006-97).
To prepare water solutions in the field process or produced water is used. The major requirement to water is the absence of a water-in-oil emulsion demulsifier.
To destroy injected water-in-oil emulsions a 0.01-0.1% solution of a water-in-oil emulsion demulsifier in an aromatic solvent is used, i.e. Dissolvan 4411, 4490 etc.
The effectiveness of the developed method and the prototype method was evaluated in laboratory conditions based on the change in the velocity of fluid filtration in core samples of various permeability and an increase in oil displacement rate which were calculated accordingly based on the change in production rates and watercut of the produced oil. Incremental oil and fluid production rate were determined on the model for chemical oil displacement processes in porous media, a modified I11PK model.
Preparation of the reservoir model and fluids prior to testing was performed according STP 0148070-013-91 "Methods of Laboratory Tests".
All tests were performed on the reservoir model that consisted of two intervals with different permeability in the form of two filled columns 40 cm long and 3.7 cm in diameter. The intervals were consequently saturated by produced water and then oil.
Later oil was displaced by produced water to 100% of product watercut. Then gel or sediment forming composition was injected according to the proposed method (in the form of a blend of water-in-oil emulsions with later injection of a 0.01%
demulsifier in toluene for their destruction. The prototype method was also performed.
As per Table 1, gel forming polymer compositions, proposed method allows to decrease velocity of water filtration in high permeability sections of the reservoir and thus provide a considerable (2.5-4.5%) increase of oil displacement rate at much lower (2-2.5 times) volumes of expensive chemicals (water soluble PAA and cross-linking agent -chrome acetate) in correlation to the prototype. As per Table 2, the application of the proposed method of treatment of highly permeable sections of the reservoir with sediment forming compositions in correlation to the prototype allows to achieve a higher water isolation effect which is reflected in a 2-2.5 fold decrease of watercut in product 13.
Table 1 Effectiveness of redistribution of filtration flows and oil displacement with the proposed method and prototype, gel forming (cross linking) polymer compositions.
# Reservoir Oil Method i'iltration Oil by velocity model water correlation displace-displace meat meat increase, rate, ChemicalWater Prior After to solution chemicalchemical concentrationinjectioninjection maSB
Pro sect method 1 heterogeneous47.4 PAA 0.25 4.0 3.6 2.5 Chrome acetate 0.01 Proto a method 2 heterogeneous47.4 PAA 0.25 4.0 3.9 0.5 Chrome acetate 0.01 Pro sect method 3 heterogeneous50.5 PAA 0.25 5.5 2.4 3.5 Chrome acetate 0.01 Proto a method 4 heterogeneous50.5 PAA 0.25 4.5 3.4 1.5 Chrome acetate 0.01 heterogeneous49.7 PAA 1.0 5.0 1.1 4.5 Chrome acetate 0.08 heterogeneous50.3 PAA 1.0 5.0 3.0 2.0 Chrome acetate 0.08 Table 2 Effectiveness of filtration flow redistribution and oil displacement with the proposed method and prototype, sediment forming compositions.
# Reser CorrelMethod Filtration Watercut velocity, in product, voir anon milesJhour model of Chemical Water Prior After Prior After to to perme solutionchgmicalchemicalchemicalchemical ability concentra-injectioninjectioninjectioninjection tlOn maS9 Pro Method 1 Hetero-13.5 Na2Si03 15 5.5 0.4 91.7 19.4 eneous CaCl2 13 Pinto Method 2 Hetero-12.3 Na2Si03 15 5.4 1.5 92.3 39.5 eneous CaCl2 13 Pro sed Method 3 Hetero-14.3 (NH4)250420 5.0 0.2 93.7 15.3 eneous BaCl2 30 Pro Method 4 Hetero-13.7 (NH4)250420 5.1 2.1 92.7 49.4 I I I
geneous BaCl2 30 OIL PRODUCTION METHOD
Invention formula The method of oil production creating water isolation barriers in flushed high permeability sections of the pay zone as a result of simultaneous or consequent injection of water solutions of two or more gel or sediment forming agents is unique due to the fact that to improve efficiency of the process of reservoir treatment and avoid premature chemical reaction of the applied agents in the injection process water solution of gel or sediment forming agents are injected into the reservoir as an aggregate stable water-in-oil emulsion in low viscosity hydrocarbon solvent (benzene, kerosene etc). S-20%
of mass of
The invention is referred to oil production, in particular to methods of oil production from heterogeneous reservoirs with conformance control to level out injectivity profile of injection wells and decrease water inflow of production wells. The method includes simultaneous or consequent injection of solutions of two or more gel or sediment forming agents.
The essence of the invention: avoidance of premature chemical reaction and adsorption of agents in the process of injecting their water solutions into the reservoir and raising the efficiency of blocking water flushed intervals and reservoir fractures due to forming viscous elastic gel directly in such areas with the use of polyacrylamide (PAA) water solutions and salts of polyvalence ration or forming a stable non soluble sediment when injecting water solutions of salts of polybasic acid such as sodium silicate and alkaline-earth metal, such as calcium chloride. The method is applied through injection of water solution of two or more gel or sediment forming agents into the reservoir as an aggregate stable water-in-oil emulsion in low viscosity hydrocarbon solvent (benzene, kerosene etc). 5-20% of mass of porphirine and asphaltene-resin oil components are dissolved in the hydrocarbon solvent prior to that. For every applied water agent solution first 50%
(volume) of aggregate stable water-in-oil emulsion is prepared separately with the size of particles (globules of emulsified water agent solution) comparable to the size of pores of high permeability sections of the reservoir. Then previously prepared emulsions of gel or sediment forming agents are blended in equal volumes prior to injection. After injection of a blended emulsion for its destruction and foaming a water blocking barrier in the high permeability sections of the reservoir a hydrocarbon solution of demulsifier of a water-in-oil emulsion is injected into the reservoir in a form of viscous elastic gel (or non-soluble sediment) in the amount sufficient for destruction of injected volume of the aggregate stable water-in-oil emulsion There exist oil production blocking methods through leveling out injectivity profile of a heterogeneous reservoir. They involve simultaneous or consequent injection of a water PAA solution with a cross linking agent (water solution of a polyvalence ration salt) into the reservoir where to decrease polymer volume and control velocity of the chemical reaction of gel forming (linking) a pH of water PAA solution and the linking agent is kept at the level of 3-4 after blending and after injection it reaches 7-10 (a.c.
SU 1128573 A, C
08 L33/26 and C 08 K 3/24, E 21 B 43/22 and SU 1627678 Al, E21 B./43, 33/138).
However these methods do not prevent a change in the concentration of injected agents in reservoir conditions and have a limited application due to complications in reaching the pH of 7-10 of injected water solutions in the reservoir. Besides, using an inorganic acid to control the time of linking does not prevent chemical destruction of the PAA
molecules and in general is not applicable to control velocity of the chemical reaction of residue forming agents.
In the oil production method (Patent RU 2086757 C1, 6E 21 B 43/22) to control the time of gel forming (linking) and decrease mechanical and chemical (salt) destruction of the PAA water solutions of PAA and cross linking agent (aluminum salt) are consequently injected into the reservoir and fresh water is injected between them. With this method there is a possibility that water PAA solution, fresh water and water based cross linking agent being low viscosity systems will flow into both high and low permeability sections of the reservoir. This in its turn will inevitably result in unnecessary high volumes of applied agents. Besides, this method is not ei~ective at consequent injection of water based salt forming agents into the reservoir due to a sharp decrease in the velocity of the chemical reaction when these solutions are diluted with fresh water.
The closest to the proposed method in its technical essence is the method of injecting solution of polybasic acid salt emulsified in hydrocarbon fluid (for example, sodium silicate, sodium phosphate or sodium carbonate) into the reservoir (Patent RU
1, 6 E21 B 43/22). As a compound containing alkaline-earth metal salt a water solution of an alkaline-earth metal is used (for example, calcium chloride, magnesium chloride or barium chloride) or its emulsion in a hydrocarbon fluid (for example, in oil, diesel fuel, kerosene). As an emulsion stabilizer low soluble surfactants are used:
Emultal, Neftechim, Neftenol, Neonol, AF9-4, AF9-6, OP-4, sodium salts of SZHK
(Translator's note: unclear abbreviation) etc.
The major disadvantage of this method selected as a prototype of the invention is low aggregate stability of water-in-oil emulsions stabilized by the aforementioned low soluble surfactants which leads to their destruction (water phase separation) at a short depth of penetration (filtration) of the water-in-oil emulsion into the reservoir. This circumstance shows that it is impossible to ei~ectively apply this method at blending and simultaneous injection into the reservoir of two or more water solutions of sediment forming agents as a water-in-oil emulsion as the chance of emulsion separation and forming non soluble sediment in the near well bore area is high. Therefore this method can only be applied through consequent injection of water solution of a salt of polybasic acid emulsified in hydrocarbon fluid in the presence of a low soluble surfactant and then water solution containing a alkaline-earth metal salt or an emulsion of this solution in a hydrocarbon solvent, also in the presence of a low soluble surfactant.
The method is applied as follows. An estimated volume of aggregate stable (50%
of volume) water-in-oil emulsions in low viscosity hydrocarbon solvent (for example, kerosene containing prior dissolved 5-20% (mass) of asphaltene-resin and porphirin (ARP) compounds - natural stabilizers of water-in-oil emulsions) is prepared for each of the used water solutions of gel or sediment forming agents. This is performed at the well selected for blocking methods taking into view geophysical and physical parameters of the reservoir and current development parameters. The intensity and time of blending for each of applied water solutions of agents with specified concentration and hydrocarbon solvent containing specified amount of natural stabilizers of the water-in-oil emulsion should be such that finally for applied water solution of gel or sediment forming agent a thinly dispersed (the dimensions of water globules should be comparable to the dimensions of flushed highly permeable sections of the reservoir) aggregate stable (not coalescenting while settling and being treated in a centrifugal filed) water-in-oil emulsion would result. These properties of formed water-in-oil emulsions are easily controlled in practice with the use of a common microscope and vile centrifuge with 6,000 RPMs.
Prior to injecting water-in-oil emulsions of two or more gel or sediment forming agents into the reservoir for each selected composition water-in-oil emulsions are blended in equal volumes, i.e. in each instance both with gel forming and sediment forming compositions water blends of the aforementioned agents are injected into the reservoir as a thinly dispersed aggregate stable water-in-oil emulsion in low viscosity hydrocarbon solvent. The drops (globules) of this or that injected agent water solution are isolated from one another by a strong armored film of natural stabilizers which do not only prevent early chemical reaction between injected compounds but also prevent adsorption of injected agents on active hard areas of the reservoir which allows to drastically decrease volumes of applied compounds and reach expected results. Aggregate stable blend of water-in-oil emulsions are injected in volumes sufficient to form highly viscous emulsion "plugs" in flushed and permeable sections which in reality is traced through the change (excess) of injection pressure of the injected into the reservoir system. Then a specified volume of hydrocarbon (mainly in an aromatic solvent) solution of a demulsifier is injected into the well in the amount sufficient to destroy injected aggregate stable water-in-oil emulsion. The well is then allowed 12-36 hours for a reaction. Within this time a destruction (coalescence) of injected into the reservoir water-in-oil emulsion and blending of formed water solutions of gel or sediment forming agents takes places as well as their chemical reaction the result of which is forming water blocking barriers in flushed and highly permeable sections. The barriers are made of highly viscous cross-linking polymer compositions (CLPC) or sediment that is strong and not destructed by water.
The objective of the proposed method is to raise the efficiency of oil production due to avoiding premature chemical reaction and adsorption of two or more applied gel or sediment forming agents in the process of simultaneous injection of their water solutions into the reservoir.
The objective is achieved though the fact that in the proposed method of oil production water solutions of applied agents are injected into the reservoir as an aggregate stable water-in-oil emulsion in a low viscosity hydrocarbon solvent (benzene, kerosene etc.) in which 5-20% (mass) of porphirin and asphaltene-resin oil components are dissolved prior to it, porphirin and asphaltene-resin oil components being the major most capable natural stabilizers of water-in-oil emulsions ("Stabilization and Destruction of Oil Emulsions" by G.N. Pozdnyshev, M. "Nedra", 1982, page 221 ).
Another distinction of the proposed method is that for each water agent a 50%
(volume) aggregate stable water-in-oil emulsion is prepared separately prior to injection with the dimensions of the particles (globules of emulsified agent solution) comparable to the dimensions of flushed highly permeable reservoir sections and later prior to injection aggregate stable emulsions of gel or sediment forming agents are blended in equal volumes. At the time of injection of such a blend of aggregate stable emulsions i.e.
emulsions which are not destroyed while filtering through the porous reservoir rock, the emulsion is concentrated (packed) in the most permeable and fracture sections of the reservoir up to formation of highly viscous emulsion "plugs' containing 90-95%
(volume) of blended globules of water solutions of gel or sediment forming agents. Thus without free water phase separation (separation of the injected agents' water solutions) not only is adsorption of applied agents on the hard reservoir rock surface avoided, but a chemical reaction of the applied agents does not take place.
The process of forming highly viscous concentrated "plugs" of blended water-in-oil emulsions from aggregate stable globules of agents' water solutions (not reacting with one another) in highly permeable and fracture reservoir sections has great importance as a water blocking barrier. The fact that such a barrier is formed can be easily traced through the increase of injection pressure (at constant injection volumes) or through decrease in injection volumes at constant injection pressure.
Another distinction of the developed technical approach is a possibility to make the barrier stronger due to injection of a demulsifier in volumes sufficient to separate injected aggregate stable water-in-oil emulsion and a chemical reaction between gel and sediment forming agents forming cross-linking polymer systems (CLPS) or sediment forming salt compounds.
Parameters which make the proposed technical approach distinct from the prototype were not traced in other technical approaches and as a result the proposed method complies with "sufficient distinction" category.
The following chemicals and brands containing them are applied in the method:
~ As gel forming agents: 0.01-5.0% water solutions of anion polymer i.e.
polyacrylamid, carboxyl methyl cellulose etc. and as a cross linking agent water solution (0.003-0.2%) of polyvalence ration salts, i.e. chrome acetate etc.
~ As sediment forming agents: water solutions of salts of polybasic acids, i.e. water solution (10-20%) of sodium silicate (liquid glass), ammonium sulphate etc and water solutions (10-30%) of salts of alkaline-earth metals i.e. calcium chloride, barium chloride etc.
When 50% water-in-oil emulsions are formed the above water solutions disperse in low viscous hydrocarbon solvent i.e. kerosene (or gas benzene) where 5-20%
concentrated ARP compounds are dissolved prior to that, such as OPA (TU 2458-001-21166006-97).
To prepare water solutions in the field process or produced water is used. The major requirement to water is the absence of a water-in-oil emulsion demulsifier.
To destroy injected water-in-oil emulsions a 0.01-0.1% solution of a water-in-oil emulsion demulsifier in an aromatic solvent is used, i.e. Dissolvan 4411, 4490 etc.
The effectiveness of the developed method and the prototype method was evaluated in laboratory conditions based on the change in the velocity of fluid filtration in core samples of various permeability and an increase in oil displacement rate which were calculated accordingly based on the change in production rates and watercut of the produced oil. Incremental oil and fluid production rate were determined on the model for chemical oil displacement processes in porous media, a modified I11PK model.
Preparation of the reservoir model and fluids prior to testing was performed according STP 0148070-013-91 "Methods of Laboratory Tests".
All tests were performed on the reservoir model that consisted of two intervals with different permeability in the form of two filled columns 40 cm long and 3.7 cm in diameter. The intervals were consequently saturated by produced water and then oil.
Later oil was displaced by produced water to 100% of product watercut. Then gel or sediment forming composition was injected according to the proposed method (in the form of a blend of water-in-oil emulsions with later injection of a 0.01%
demulsifier in toluene for their destruction. The prototype method was also performed.
As per Table 1, gel forming polymer compositions, proposed method allows to decrease velocity of water filtration in high permeability sections of the reservoir and thus provide a considerable (2.5-4.5%) increase of oil displacement rate at much lower (2-2.5 times) volumes of expensive chemicals (water soluble PAA and cross-linking agent -chrome acetate) in correlation to the prototype. As per Table 2, the application of the proposed method of treatment of highly permeable sections of the reservoir with sediment forming compositions in correlation to the prototype allows to achieve a higher water isolation effect which is reflected in a 2-2.5 fold decrease of watercut in product 13.
Table 1 Effectiveness of redistribution of filtration flows and oil displacement with the proposed method and prototype, gel forming (cross linking) polymer compositions.
# Reservoir Oil Method i'iltration Oil by velocity model water correlation displace-displace meat meat increase, rate, ChemicalWater Prior After to solution chemicalchemical concentrationinjectioninjection maSB
Pro sect method 1 heterogeneous47.4 PAA 0.25 4.0 3.6 2.5 Chrome acetate 0.01 Proto a method 2 heterogeneous47.4 PAA 0.25 4.0 3.9 0.5 Chrome acetate 0.01 Pro sect method 3 heterogeneous50.5 PAA 0.25 5.5 2.4 3.5 Chrome acetate 0.01 Proto a method 4 heterogeneous50.5 PAA 0.25 4.5 3.4 1.5 Chrome acetate 0.01 heterogeneous49.7 PAA 1.0 5.0 1.1 4.5 Chrome acetate 0.08 heterogeneous50.3 PAA 1.0 5.0 3.0 2.0 Chrome acetate 0.08 Table 2 Effectiveness of filtration flow redistribution and oil displacement with the proposed method and prototype, sediment forming compositions.
# Reser CorrelMethod Filtration Watercut velocity, in product, voir anon milesJhour model of Chemical Water Prior After Prior After to to perme solutionchgmicalchemicalchemicalchemical ability concentra-injectioninjectioninjectioninjection tlOn maS9 Pro Method 1 Hetero-13.5 Na2Si03 15 5.5 0.4 91.7 19.4 eneous CaCl2 13 Pinto Method 2 Hetero-12.3 Na2Si03 15 5.4 1.5 92.3 39.5 eneous CaCl2 13 Pro sed Method 3 Hetero-14.3 (NH4)250420 5.0 0.2 93.7 15.3 eneous BaCl2 30 Pro Method 4 Hetero-13.7 (NH4)250420 5.1 2.1 92.7 49.4 I I I
geneous BaCl2 30 OIL PRODUCTION METHOD
Invention formula The method of oil production creating water isolation barriers in flushed high permeability sections of the pay zone as a result of simultaneous or consequent injection of water solutions of two or more gel or sediment forming agents is unique due to the fact that to improve efficiency of the process of reservoir treatment and avoid premature chemical reaction of the applied agents in the injection process water solution of gel or sediment forming agents are injected into the reservoir as an aggregate stable water-in-oil emulsion in low viscosity hydrocarbon solvent (benzene, kerosene etc). S-20%
of mass of
Claims (4)
- OIL PRODUCTION METHOD
Invention formula The method of oil production creating water isolation barriers in flushed high permeability sections of the pay zone as a result of simultaneous or consequent injection of water solutions of two or more gel or sediment forming agents is unique due to the fact that to improve efficiency of the process of reservoir treatment and avoid premature chemical reaction of the applied agents in the injection process water solution of gel or sediment forming agents are injected into the reservoir as an aggregate stable water-in-oil emulsion in low viscosity hydrocarbon solvent (benzene, kerosene etc). 5-20%
of mass of porphirine and asphaltene-resin oil components are dissolved in the hydrocarbon solvent prior to that. - 2. The Method as per paragraph 1 is unique due to the fact that for each water solution of the agent 50% (volume) aggregate stable water-in-oil emulsions are prepared.
The particle dimensions (globules of emulsified water solution of the agent) are comparable to the pore dimensions of flushed highly permeable sections of the reservoir. - 3. The Method as per paragraphs 2-3 is unique due to the fact that injection of aggregate stable emulsions of gel or sediment forming agents into the reservoir is performed after their prior blending in equal volumes.
- 4. The Method as per paragraphs 1-3 is unique due to the fact that to destroy protective film of aggregate stable emulsions and for the chemical reaction between gel or sediment forming agents to take place in the highly permeable sections of the reservoir with the formation of water isolating barrier a demulsifier is injected into the reservoir in volume sufficient for destruction of injected stable water-in-oil emulsion.
Applications Claiming Priority (3)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| RU98115677A RU2136870C1 (en) | 1998-08-10 | 1998-08-10 | Method of insulating washed high-permeability zones of productive formation |
| RU98115677 | 1998-08-10 | ||
| PCT/RU1998/000419 WO2000009856A1 (en) | 1998-08-10 | 1998-12-21 | Crude-oil extraction method |
Publications (1)
| Publication Number | Publication Date |
|---|---|
| CA2279876A1 true CA2279876A1 (en) | 2000-02-10 |
Family
ID=20209658
Family Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CA002279876A Abandoned CA2279876A1 (en) | 1998-08-10 | 1998-12-21 | Oil production method |
Country Status (3)
| Country | Link |
|---|---|
| CA (1) | CA2279876A1 (en) |
| RU (1) | RU2136870C1 (en) |
| WO (1) | WO2000009856A1 (en) |
Cited By (2)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US8256511B2 (en) | 2007-07-24 | 2012-09-04 | Exxonmobil Upstream Research Company | Use of a heavy petroleum fraction as a drive fluid in the recovery of hydrocarbons from a subterranean formation |
| WO2022011096A1 (en) * | 2020-07-08 | 2022-01-13 | Saudi Arabian Oil Company | Asphaltene solution for water shut off |
Families Citing this family (4)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US6914036B2 (en) * | 2001-03-15 | 2005-07-05 | Baker Hughes Incorporated | Demulsifier for aqueous completion fluids |
| RU2454448C1 (en) * | 2010-11-10 | 2012-06-27 | Общество с ограниченной ответственностью "Самараойл" | Reagent for treating oil reservoir and method of using said reagent |
| RU2456439C1 (en) * | 2011-01-11 | 2012-07-20 | Государственное образовательное учреждение высшего профессионального образования "Санкт-Петербургский государственный горный институт имени Г.В. Плеханова (технический университет)" | Method for balancing injection well water-intake capacity profile and restriction of water influx to production wells |
| RU2703598C1 (en) * | 2018-10-09 | 2019-10-21 | Публичное акционерное общество "Татнефть" имени В.Д. Шашина | Gel-forming composition for isolation of water influx into well (versions) |
Family Cites Families (5)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US3866680A (en) * | 1973-07-09 | 1975-02-18 | Amoco Prod Co | Miscible flood process |
| DE3105913C2 (en) * | 1981-02-18 | 1983-10-27 | Chemische Werke Hüls AG, 4370 Marl | Process for the extraction of oil from underground reservoirs by emulsion flooding |
| RU2109132C1 (en) * | 1996-06-27 | 1998-04-20 | Закрытое акционерное общество "Тюмень-Технология" | Method for increasing oil recovery from beds |
| RU2094601C1 (en) * | 1996-07-05 | 1997-10-27 | Акционерное общество открытого типа "Ноябрьскнефтегаз" | Method for development of oil deposit |
| RU2101486C1 (en) * | 1996-11-27 | 1998-01-10 | Владимир Владимирович Мазаев | Method for isolation of brine water inflow |
-
1998
- 1998-08-10 RU RU98115677A patent/RU2136870C1/en not_active IP Right Cessation
- 1998-12-21 CA CA002279876A patent/CA2279876A1/en not_active Abandoned
- 1998-12-21 WO PCT/RU1998/000419 patent/WO2000009856A1/en unknown
Cited By (3)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US8256511B2 (en) | 2007-07-24 | 2012-09-04 | Exxonmobil Upstream Research Company | Use of a heavy petroleum fraction as a drive fluid in the recovery of hydrocarbons from a subterranean formation |
| WO2022011096A1 (en) * | 2020-07-08 | 2022-01-13 | Saudi Arabian Oil Company | Asphaltene solution for water shut off |
| US11447683B2 (en) | 2020-07-08 | 2022-09-20 | Saudi Arabian Oil Company | Asphaltene solution for water shut off |
Also Published As
| Publication number | Publication date |
|---|---|
| WO2000009856A1 (en) | 2000-02-24 |
| RU2136870C1 (en) | 1999-09-10 |
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