CN109025953A - A kind of application method of the gel foamable composition of heavy crude heat extraction inhibition bottom water coning - Google Patents
A kind of application method of the gel foamable composition of heavy crude heat extraction inhibition bottom water coning Download PDFInfo
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- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 title claims abstract description 96
- 239000000203 mixture Substances 0.000 title claims abstract description 32
- 238000000034 method Methods 0.000 title claims abstract description 29
- 238000000605 extraction Methods 0.000 title abstract description 7
- 230000005764 inhibitory process Effects 0.000 title description 4
- IJGRMHOSHXDMSA-UHFFFAOYSA-N Atomic nitrogen Chemical compound N#N IJGRMHOSHXDMSA-UHFFFAOYSA-N 0.000 claims abstract description 163
- 229910052757 nitrogen Inorganic materials 0.000 claims abstract description 85
- 239000006260 foam Substances 0.000 claims abstract description 77
- 239000003795 chemical substances by application Substances 0.000 claims abstract description 21
- 239000000243 solution Substances 0.000 claims abstract description 19
- 239000007924 injection Substances 0.000 claims description 58
- 238000002347 injection Methods 0.000 claims description 58
- 238000011084 recovery Methods 0.000 claims description 22
- 239000007789 gas Substances 0.000 claims description 15
- 238000013461 design Methods 0.000 claims description 10
- 239000010410 layer Substances 0.000 claims description 10
- 229910052708 sodium Inorganic materials 0.000 claims description 7
- 239000011734 sodium Substances 0.000 claims description 7
- 239000004711 α-olefin Substances 0.000 claims description 7
- 239000003431 cross linking reagent Substances 0.000 claims description 6
- BDHFUVZGWQCTTF-UHFFFAOYSA-M sulfonate Chemical compound [O-]S(=O)=O BDHFUVZGWQCTTF-UHFFFAOYSA-M 0.000 claims description 6
- HRPVXLWXLXDGHG-UHFFFAOYSA-N Acrylamide Chemical compound NC(=O)C=C HRPVXLWXLXDGHG-UHFFFAOYSA-N 0.000 claims description 5
- DGAQECJNVWCQMB-PUAWFVPOSA-M Ilexoside XXIX Chemical compound C[C@@H]1CC[C@@]2(CC[C@@]3(C(=CC[C@H]4[C@]3(CC[C@@H]5[C@@]4(CC[C@@H](C5(C)C)OS(=O)(=O)[O-])C)C)[C@@H]2[C@]1(C)O)C)C(=O)O[C@H]6[C@@H]([C@H]([C@@H]([C@H](O6)CO)O)O)O.[Na+] DGAQECJNVWCQMB-PUAWFVPOSA-M 0.000 claims description 5
- -1 N, N- methylene bisacrylamide Amide Chemical class 0.000 claims description 5
- 239000000945 filler Substances 0.000 claims description 5
- 239000011229 interlayer Substances 0.000 claims description 5
- 239000011837 N,N-methylenebisacrylamide Substances 0.000 claims description 4
- QJGQUHMNIGDVPM-UHFFFAOYSA-N nitrogen(.) Chemical compound [N] QJGQUHMNIGDVPM-UHFFFAOYSA-N 0.000 claims description 4
- 239000002689 soil Substances 0.000 claims description 4
- OMPJBNCRMGITSC-UHFFFAOYSA-N Benzoylperoxide Chemical compound C=1C=CC=CC=1C(=O)OOC(=O)C1=CC=CC=C1 OMPJBNCRMGITSC-UHFFFAOYSA-N 0.000 claims description 2
- 235000019400 benzoyl peroxide Nutrition 0.000 claims description 2
- 239000010881 fly ash Substances 0.000 claims description 2
- LSNNMFCWUKXFEE-UHFFFAOYSA-M Bisulfite Chemical compound OS([O-])=O LSNNMFCWUKXFEE-UHFFFAOYSA-M 0.000 claims 1
- QAOWNCQODCNURD-UHFFFAOYSA-L Sulfate Chemical compound [O-]S([O-])(=O)=O QAOWNCQODCNURD-UHFFFAOYSA-L 0.000 claims 1
- 238000010793 Steam injection (oil industry) Methods 0.000 abstract description 16
- 230000000694 effects Effects 0.000 abstract description 11
- 239000002981 blocking agent Substances 0.000 abstract description 7
- 238000011161 development Methods 0.000 abstract description 5
- 239000003921 oil Substances 0.000 description 27
- 239000007788 liquid Substances 0.000 description 18
- 238000006243 chemical reaction Methods 0.000 description 14
- 239000004088 foaming agent Substances 0.000 description 14
- 238000004519 manufacturing process Methods 0.000 description 9
- 239000000178 monomer Substances 0.000 description 9
- 150000003254 radicals Chemical class 0.000 description 9
- 238000012360 testing method Methods 0.000 description 9
- 239000010779 crude oil Substances 0.000 description 8
- VYPSYNLAJGMNEJ-UHFFFAOYSA-N Silicium dioxide Chemical compound O=[Si]=O VYPSYNLAJGMNEJ-UHFFFAOYSA-N 0.000 description 5
- 230000007423 decrease Effects 0.000 description 5
- 239000004576 sand Substances 0.000 description 5
- 239000003129 oil well Substances 0.000 description 4
- 229920000642 polymer Polymers 0.000 description 4
- 238000006116 polymerization reaction Methods 0.000 description 4
- 238000004088 simulation Methods 0.000 description 4
- 241000237858 Gastropoda Species 0.000 description 3
- 230000015572 biosynthetic process Effects 0.000 description 3
- 230000000903 blocking effect Effects 0.000 description 3
- 230000008859 change Effects 0.000 description 3
- 230000005465 channeling Effects 0.000 description 3
- 239000002131 composite material Substances 0.000 description 3
- 238000010586 diagram Methods 0.000 description 3
- 239000000295 fuel oil Substances 0.000 description 3
- 238000001879 gelation Methods 0.000 description 3
- ZIUHHBKFKCYYJD-UHFFFAOYSA-N n,n'-methylenebisacrylamide Chemical compound C=CC(=O)NCNC(=O)C=C ZIUHHBKFKCYYJD-UHFFFAOYSA-N 0.000 description 3
- 238000007789 sealing Methods 0.000 description 3
- PXHVJJICTQNCMI-UHFFFAOYSA-N Nickel Chemical compound [Ni] PXHVJJICTQNCMI-UHFFFAOYSA-N 0.000 description 2
- 230000004913 activation Effects 0.000 description 2
- 238000007259 addition reaction Methods 0.000 description 2
- 238000004364 calculation method Methods 0.000 description 2
- 239000000084 colloidal system Substances 0.000 description 2
- 150000001875 compounds Chemical class 0.000 description 2
- 238000007596 consolidation process Methods 0.000 description 2
- 230000001186 cumulative effect Effects 0.000 description 2
- 238000006073 displacement reaction Methods 0.000 description 2
- 238000005553 drilling Methods 0.000 description 2
- 239000004615 ingredient Substances 0.000 description 2
- 238000009413 insulation Methods 0.000 description 2
- JRZJOMJEPLMPRA-UHFFFAOYSA-N olefin Natural products CCCCCCCC=C JRZJOMJEPLMPRA-UHFFFAOYSA-N 0.000 description 2
- 238000005457 optimization Methods 0.000 description 2
- 230000035699 permeability Effects 0.000 description 2
- 238000001556 precipitation Methods 0.000 description 2
- 230000008569 process Effects 0.000 description 2
- 239000011435 rock Substances 0.000 description 2
- 230000000638 stimulation Effects 0.000 description 2
- 238000010998 test method Methods 0.000 description 2
- 235000020681 well water Nutrition 0.000 description 2
- 239000002349 well water Substances 0.000 description 2
- 239000004215 Carbon black (E152) Substances 0.000 description 1
- 238000010794 Cyclic Steam Stimulation Methods 0.000 description 1
- 239000006004 Quartz sand Substances 0.000 description 1
- NINIDFKCEFEMDL-UHFFFAOYSA-N Sulfur Chemical compound [S] NINIDFKCEFEMDL-UHFFFAOYSA-N 0.000 description 1
- 239000005864 Sulphur Substances 0.000 description 1
- 150000001408 amides Chemical class 0.000 description 1
- 238000004458 analytical method Methods 0.000 description 1
- 239000010426 asphalt Substances 0.000 description 1
- QVGXLLKOCUKJST-UHFFFAOYSA-N atomic oxygen Chemical compound [O] QVGXLLKOCUKJST-UHFFFAOYSA-N 0.000 description 1
- 230000009286 beneficial effect Effects 0.000 description 1
- 238000009833 condensation Methods 0.000 description 1
- 230000005494 condensation Effects 0.000 description 1
- 238000004132 cross linking Methods 0.000 description 1
- 125000004122 cyclic group Chemical group 0.000 description 1
- 230000003247 decreasing effect Effects 0.000 description 1
- 238000010790 dilution Methods 0.000 description 1
- 239000012895 dilution Substances 0.000 description 1
- 239000012153 distilled water Substances 0.000 description 1
- 235000013399 edible fruits Nutrition 0.000 description 1
- 238000002474 experimental method Methods 0.000 description 1
- 239000012530 fluid Substances 0.000 description 1
- 238000005187 foaming Methods 0.000 description 1
- 239000000499 gel Substances 0.000 description 1
- 230000005484 gravity Effects 0.000 description 1
- 238000010438 heat treatment Methods 0.000 description 1
- 229930195733 hydrocarbon Natural products 0.000 description 1
- 150000002430 hydrocarbons Chemical class 0.000 description 1
- 239000003999 initiator Substances 0.000 description 1
- 230000000977 initiatory effect Effects 0.000 description 1
- 238000009434 installation Methods 0.000 description 1
- 230000009545 invasion Effects 0.000 description 1
- 230000007246 mechanism Effects 0.000 description 1
- 229910052751 metal Inorganic materials 0.000 description 1
- 239000002184 metal Substances 0.000 description 1
- 229910052759 nickel Inorganic materials 0.000 description 1
- 239000002332 oil field water Substances 0.000 description 1
- 229910052760 oxygen Inorganic materials 0.000 description 1
- 239000001301 oxygen Substances 0.000 description 1
- 238000005325 percolation Methods 0.000 description 1
- JRKICGRDRMAZLK-UHFFFAOYSA-L peroxydisulfate Chemical compound [O-]S(=O)(=O)OOS([O-])(=O)=O JRKICGRDRMAZLK-UHFFFAOYSA-L 0.000 description 1
- 239000004033 plastic Substances 0.000 description 1
- 239000011148 porous material Substances 0.000 description 1
- USHAGKDGDHPEEY-UHFFFAOYSA-L potassium persulfate Chemical compound [K+].[K+].[O-]S(=O)(=O)OOS([O-])(=O)=O USHAGKDGDHPEEY-UHFFFAOYSA-L 0.000 description 1
- 235000019394 potassium persulphate Nutrition 0.000 description 1
- 230000005855 radiation Effects 0.000 description 1
- 238000010526 radical polymerization reaction Methods 0.000 description 1
- 239000002994 raw material Substances 0.000 description 1
- 239000000376 reactant Substances 0.000 description 1
- 230000009467 reduction Effects 0.000 description 1
- 238000011160 research Methods 0.000 description 1
- 229920006395 saturated elastomer Polymers 0.000 description 1
- 238000005204 segregation Methods 0.000 description 1
- 239000000126 substance Substances 0.000 description 1
- GPPXJZIENCGNKB-UHFFFAOYSA-N vanadium Chemical compound [V]#[V] GPPXJZIENCGNKB-UHFFFAOYSA-N 0.000 description 1
- 229910052720 vanadium Inorganic materials 0.000 description 1
- 239000002351 wastewater Substances 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
-
- 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
- E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
- E21B43/24—Enhanced recovery methods for obtaining hydrocarbons using heat, e.g. steam injection
-
- C—CHEMISTRY; METALLURGY
- C08—ORGANIC MACROMOLECULAR COMPOUNDS; THEIR PREPARATION OR CHEMICAL WORKING-UP; COMPOSITIONS BASED THEREON
- C08F—MACROMOLECULAR COMPOUNDS OBTAINED BY REACTIONS ONLY INVOLVING CARBON-TO-CARBON UNSATURATED BONDS
- C08F220/00—Copolymers of compounds having one or more unsaturated aliphatic radicals, each having only one carbon-to-carbon double bond, and only one being terminated by only one carboxyl radical or a salt, anhydride ester, amide, imide or nitrile thereof
- C08F220/02—Monocarboxylic acids having less than ten carbon atoms; Derivatives thereof
- C08F220/52—Amides or imides
- C08F220/54—Amides, e.g. N,N-dimethylacrylamide or N-isopropylacrylamide
- C08F220/56—Acrylamide; Methacrylamide
-
- C—CHEMISTRY; METALLURGY
- C08—ORGANIC MACROMOLECULAR COMPOUNDS; THEIR PREPARATION OR CHEMICAL WORKING-UP; COMPOSITIONS BASED THEREON
- C08K—Use of inorganic or non-macromolecular organic substances as compounding ingredients
- C08K3/00—Use of inorganic substances as compounding ingredients
- C08K3/01—Use of inorganic substances as compounding ingredients characterized by their specific function
- C08K3/011—Crosslinking or vulcanising agents, e.g. accelerators
-
- C—CHEMISTRY; METALLURGY
- C08—ORGANIC MACROMOLECULAR COMPOUNDS; THEIR PREPARATION OR CHEMICAL WORKING-UP; COMPOSITIONS BASED THEREON
- C08K—Use of inorganic or non-macromolecular organic substances as compounding ingredients
- C08K3/00—Use of inorganic substances as compounding ingredients
- C08K3/01—Use of inorganic substances as compounding ingredients characterized by their specific function
- C08K3/013—Fillers, pigments or reinforcing additives
-
- C—CHEMISTRY; METALLURGY
- C08—ORGANIC MACROMOLECULAR COMPOUNDS; THEIR PREPARATION OR CHEMICAL WORKING-UP; COMPOSITIONS BASED THEREON
- C08K—Use of inorganic or non-macromolecular organic substances as compounding ingredients
- C08K3/00—Use of inorganic substances as compounding ingredients
- C08K3/34—Silicon-containing compounds
- C08K3/346—Clay
-
- 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
- E21B33/00—Sealing or packing boreholes or wells
- E21B33/10—Sealing or packing boreholes or wells in the borehole
- E21B33/13—Methods or devices for cementing, for plugging holes, crevices or the like
- E21B33/134—Bridging plugs
-
- 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
- E21B43/16—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 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
- E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
- E21B43/166—Injecting a gaseous medium; Injecting a gaseous medium and a liquid medium
- E21B43/168—Injecting a gaseous medium
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- Mining & Mineral Resources (AREA)
- Geology (AREA)
- Engineering & Computer Science (AREA)
- Life Sciences & Earth Sciences (AREA)
- Chemical & Material Sciences (AREA)
- Environmental & Geological Engineering (AREA)
- Geochemistry & Mineralogy (AREA)
- Physics & Mathematics (AREA)
- General Life Sciences & Earth Sciences (AREA)
- Fluid Mechanics (AREA)
- Organic Chemistry (AREA)
- Health & Medical Sciences (AREA)
- Chemical Kinetics & Catalysis (AREA)
- Polymers & Plastics (AREA)
- Medicinal Chemistry (AREA)
- Dispersion Chemistry (AREA)
- Excavating Of Shafts Or Tunnels (AREA)
- Consolidation Of Soil By Introduction Of Solidifying Substances Into Soil (AREA)
- Soil Conditioners And Soil-Stabilizing Materials (AREA)
Abstract
The invention discloses the application methods that a kind of heavy crude heat extraction inhibits the gel foamable composition of bottom water coning, belong to oilfield exploitation and technical field of oilfield chemistry.Method includes the following steps: 1) inject nitrogen into producing well when producing well period comprehensive water cut is greater than 90%, form preposition nitrogen slug；2) continue the mixed system for injecting nitrogen and gel foam agent solution into producing well, form nitrogen-gel foam main body slug；3) nitrogen is injected into producing well, is formed and is replaced nitrogen slug；4) steam is injected.Pit shaft and stratum near wellbore zone water can be pushed into oil reservoir by preposition nitrogen slug, equilibrium strata pressure, nitrogen-gel foam main body slug effectively can inhibit bottom water to invade, gel foam blocking agent can be replaced out in screen casing and nearly pit shaft area by replacing nitrogen slug, it prevents blocking agent from consolidating in nearly near wellbore, blocks steam injection, oil channel.This method can delay bottom water coning speed, improve steam sweep efficiency and utilization rate, improve effect of reservoir development.
Description
The application is the divisional application of following applications,
The applying date of original application: on 08 23rd, 2016,
The application number of original application: 201610709754.3,
The denomination of invention of original application: the thick oil thermal recovery method of gel foam inhibition bottom water coning.
Technical field
The present invention relates to the application methods that a kind of heavy crude heat extraction inhibits the gel foamable composition of bottom water coning, belong to oilfield exploitation
And technical field of oilfield chemistry.
Background technique
Viscous crude is also known as heavy crude or highly viscous crude, crude oil d4 20> 0.92.Especially straight chain waxy hydrocarbon light fraction in viscous crude
Content is few, and colloid, asphalt content are high, and the content of the metal components such as the element compounds such as sulphur, oxygen, nitrogen and nickel, vanadium is also higher,
Thus have the characteristics that than great, viscosity is high, condensation point is low, and is in Newtonian fluid characteristic in wider temperature range.Due to ground
The viscosity of viscous crude is higher at a temperature of layer, and autonomous flow is difficult in prime stratum, and there are larger difficulties for common exploitation, it is necessary to use
The mode of thermal recovery is developed, and steam injection is current most important heavy crude heat extraction mode.Exploitation via steam injection includes steam soak and steam
It drives, wherein steam soak is recovered the oil by the way of periodicity or cyclicity steam injection, by infusing to heavy oil wells into high temperature and pressure
Wet saturated steam comes out back production after crude oil heating viscosity-reducing a certain range of in oil reservoir, that is, gulps down into steam, discharge crude oil.It steams
It is the major technique of Development of Viscous Crude Oil that vapour, which is handled up, but with the extension of production cycle, oil yield is remarkably decreased.Particularly with
Super-heavy oil deposit with bottom water, since reservoir interlayer is thin, oil reservoir closely or is directly connected with bottom water away from lower water layer, and by level
Well development mode influences, and water breakthrough channel is shorter, easily causes water layer to alter logical or bottom water coning after investment steam soak exploitation, leads to oil
Well is aqueous to be substantially increased.It is influenced due to the heterogeneity feature of heavy crude reservoir and by Simulation on whole pay zones, colloid after multi-cycle stimulation,
The density variation of asphaltene deposits, steam and water etc. leads to gravity segregation, causes steam in high permeability formation channelling, water breakthrough, vapour occurs
It alters.As steam is advanced by leaps and bounds along high permeability zone, steam sweep efficiency is gradually reduced, and steam effective area and utilization rate are substantially reduced.
In addition stratum pressure drop increases after multi-cycle stimulation, is influenced by side water, bottom water invasion etc., the every condition of cyclic steam stimulation effect variation is cured
Difference, single-well crude oil yield gradually decrease, and oil recovery efficiency is substantially reduced.
The patent of invention of publication No. CN105064962A discloses a kind of nitrogen foam and inhibits heavy crude heat extraction edge water propelling
Method is first injected before nitrogen formed for the heavy crude heat extraction steam-stimulated well of period composite water cut >=90% before steam injection
Nitrogen slug is set, then (foaming agent accounts for 0.4%~0.8% to injection expanding foam solution, and ingredient is referring to patent into producing well
CN104109523A), foaming (1~2:1 of gas liquid ratio) is contacted with preposition nitrogen, be then poured into nitrogen formed in set nitrogen slug,
Steam is finally injected into producing well, wherein it is preceding, in set the nitrogen injection rate of nitrogen slug be the 40~80 of steam injection
Times, the nitrogen injection rate of preposition nitrogen slug is the 1/3~1/2 of total nitrogen injection rate.This method can effectively block side water, inhibit
Side water coning, while the sweep efficiency and displacement efficiency of injection steam are improved, improve Heavy Oil Thermal Recovery Effect, but foam blocking is strong
Spend weak, and oil reservoir bottom water ability is strong, not good enough to the inhibition effectiveness of bottom water coning.The patent of invention of notification number CN102876304B is public
A kind of horizontal well bottom water plugging technique has been opened, has first sealed EXIT POINT with mechanical packer card, annular chemical packer has been injected, according to water
Reservoir temperature locating for horizontal well selects sealing agent system, for horizontal well thermal recovery, using inorganic precipitation type system and nitrogen foam body
System or thermo-sensitive gel system, and two slugs is divided to inject, inorganic precipitation type System forming first is first injected in volume ratio 1~3:3~1
Slug reinjects the second slug of nitrogen foam system or thermo-sensitive gel System forming, replaces closing well plastic after appropriate oil field water.It should
Method is suitable for High water cut or ultra-high water-containing horizontal well, can reach high-intensitive indepth plugging purpose, it is aqueous that horizontal well is effectively reduced
Rate improves oil well productivity, but bottom water oil reservoir is not possible to accurately find water exit position at present, it is difficult to be sealed and is discharged with packer card
Point can only take the measure generally blocked, it is necessary to use selective water-plugging, and be influenced by sieve tube completion mode, is not available
Graininess blocking agent bottom water plugging.
Summary of the invention
The object of the present invention is to provide the thick oil thermal recovery methods that a kind of gel foam inhibits bottom water coning.
In order to achieve the goal above, the technical scheme adopted by the invention is that:
A kind of gel foam inhibits the thick oil thermal recovery method of bottom water coning, and steps are as follows:
1) when producing well period comprehensive water cut is greater than 90%, nitrogen is injected into producing well, forms preposition nitrogen slug；
2) continue the mixed system for injecting nitrogen and gel foam agent solution into producing well, form nitrogen-gel foam
Main body slug；
3) nitrogen is injected into producing well, is formed and is replaced nitrogen slug；
4) steam is injected；
Gel foamable composition is made of α olefin sulfonate, acrylamide, filler, crosslinking agent and controlling agent in step 2), with
Mass ratio meter, α olefin sulfonate: acrylamide: filler: crosslinking agent: controlling agent=(0.5~1): (1.5~3): (1.5~
3.5): (0.05~0.1): (0.0025~0.025).
The injection rate of nitrogen 1 calculates according to the following formula in step 1):
Formula 1:VPreposition nitrogen=VStraight well section+VHorizontal segment=π D1 2/4·H1+π·D2 2/4·H2；
In formula: VPreposition nitrogenFor the nitrogen injection rate of preposition nitrogen slug, Nm3(mark side)；VStraight well sectionFor horizontal well straight well section pit shaft
Volume, Nm3；VHorizontal segmentFor horizontal well horizontal segment axial line cylinder volume, Nm3；D1For casing inner diameter, m；D2For with net horizontal section
For the cylinder diameter of axial line, m, 3~5m of design radial；H1For straight well segment length, m；H2For horizontal section length, m.
The dosage of gel foamable composition 2 calculates according to the following formula in step 2):
Formula 2:mGel foamable composition=VBlock volume·nDosing concentration·ρGel foam agent solution；
In formula: mGel foamable compositionFor the dosage of gel foamable composition, kg；VBlock volumeTo block volume, m3；nDosing concentrationIt is dense with liquid
Degree, %, design concentration 5%~10%；ρGel foam agent solutionFor the density of gel foam agent solution, kg/m3；
Block volume VBlock volumeAccording to the triangular prism modelling of water ridge numerical simulation graph reduction, calculation formula is as follows:
Formula 3:VBlock volume=LH2·tanθ·Φ·α；
In formula: L is water ridge length, and m (easily breakthrough well section), water ridge length is generally the 1/4~1/3 of producing well segment length；H
For water ridge height, i.e. thickness of interlayer of the oil reservoir lower boundary to water layer coboundary, m；θ is water ridge angle, °, experience value 30~
60°；Φ is easy breakthrough well hole porosity, %；α is injection ratio, dimensionless, experience value 0.53~0.6.
The injection rate of nitrogen in step 2) (i.e. with nitrogen injection) is to block 1~2 times of volume (i.e. gas liquid ratio n is 1~2, is
Refer to the ratio of nitrogen injection rate and closure volume under reservoir temperature, pressure condition), it blocks volume and is calculated according to equation 3 above.
α olefin sulfonate is α-sodium olefin sulfonate in the gel foamable composition of step 2), is used as heatproof foaming agent.Acryloyl
Amine is gel host agent, and monomer structure is simple, and molecular weight is small, and initial viscosity is lower when injection.
Sodium soil, flyash etc. can be used in the filler.
N,N methylene bis acrylamide, dibenzoyl peroxide etc. can be used in the crosslinking agent.
Azobisisoheptonitrile, persulfate (such as potassium peroxydisulfate) can be used in the controlling agent.
Cross-linking reaction mechanism is as follows: unsaturated amides raw material monomer AM polymerization belongs to Raolical polymerizable, radical polymerization
Closing reaction is chain polymerization, is at least caused by chain, three elementary reactions of chain growth and chain termination form.Wherein chain initiation reaction is
The reaction of free radical is formed, heat, light, high-energy radiation and initiator etc. can make monomer generate monomer radical, and oil field is to cause
Agent causes easy to operate；Chain propagation reaction is similar with the reaction of monomer radical is formed, and also belongs to exothermic reaction, anti-due to increasing
Answer activation energy lower, rate is high, and with monomer molecule addition reaction occurs for monomer radical at once Yi Dan generated, and generation contains
There is the chain free radical of more monomeric units, the continuous addition reaction of monomer molecule and chain free radical increases chain constantly；Chain is whole
The chain free radical that only reaction increases reacts with each other, and loses activity and generates the process of stable high-molecular compound, chain termination is anti-
The activation energy answered is extremely low, and sometimes even zero, therefore terminate that reaction rate constant is very big, and chain propagation reaction and chain termination reaction are
A pair of of growth and decline reaction, the generation of high polymer additionally depend on the concentration of reactant, and monomer concentration compares free radical in usual polymerization system
Concentration is much bigger, and rate of chain growth is higher than chain termination rate thousands of and ten tens of thousands of orders of magnitude, it is sufficient to it is very high to generate the degree of polymerization
Long-chain free radical and macromolecular.
The injection rate of nitrogen is equal to mineshaft annulus volume (namely horizontal well straight well section wellbore volume) and crosses and pushes up in step 3)
For the product of coefficient, 4 calculate according to the following formula:
Formula 4:VReplace nitrogen=β VMineshaft annulus volume=β VStraight well section=β π D1 2/4·H1；
In formula: VReplace nitrogenFor the nitrogen injection rate for replacing nitrogen slug, Nm3；VMineshaft annulus bodyFor horizontal well straight well section annular space body
Product, Nm3；VStraight well sectionFor horizontal well straight well section wellbore volume, Nm3；D1For casing inner diameter, m；H1For straight well segment length, m；β was top
For coefficient, dimensionless, experience value 1.2~1.5.
The injection rate of steam is cycle design gas injection rate in step 4).In general, according to numerical simulation study result and oil well week
Phase occurrence comprehensively considers.
Step 1)~4) in nitrogen, gel foam agent solution injection pressure without particular/special requirement, injection rate is set by injecting
Standby control, such as 900m3/h。
Beneficial effects of the present invention:
The present invention uses gel foam water-plugging technique, and mentality of designing is using three slugs, i.e. preposed attributives, main body slug
With replacement slug, preposed attributives use nitrogen, pit shaft and stratum near wellbore zone water are pushed into oil reservoir, while equilibrium strata pressure,
Main body slug injects the mixed system of nitrogen and gel foamable composition, and nitrogen-gel foam slug is formed in water breakthrough channel, inhibits
Bottom water intrusion replaces slug and equally uses nitrogen, gel foam blocking agent is replaced out screen casing and nearly pit shaft area, prevents blocking agent from existing
Nearly near wellbore consolidation, blocks steam injection, oil channel, while playing the role of thermal insulation protection to tubing string.
The present invention forms gel-foam system by applying gel foam water-plugging technique, by foaming agent and gel cross-linkage,
Ground clear water or oily wastewater dilution after, by ground installation fill nitrogen, make the ingredients such as foaming agent, gel, crosslinking agent with
Nitrogen is sufficiently mixed, and forms gel foam, in well head and nitrogen mixed injection when injection, gel foam is made to form stable foam
Stream implements gel foam closure into stratum.Gel foam is the foam with gel for foreign minister, and gel foam has before Cheng Ning
There is the characteristics of water base foam, have the characteristics that elastic gel again after Cheng Ning, with shut-off capacity is strong, stability is good, selection
The features such as property is good.After steam-stimulated well injects high temperature gel foam system, gel foam can block oil reservoir water breakthrough channel, effectively press down
Steam processed enters water layer, and turns to heated oil reservoir, improves steam sweep efficiency and utilization rate, while delaying bottom water coning speed,
Improve effect of reservoir development.
Detailed description of the invention
Fig. 1 is preposed attributives nitrogen use level design diagram in the embodiment of the present invention 1；
Fig. 2 is horizontal well water ridge numerical simulation figure in the embodiment of the present invention 1；
Fig. 3 is water ridge simplified model figure in the embodiment of the present invention 1；
Fig. 4 is foaming agent solution resistance factor in test example of the invention with the change curve of inject gas to liquid ratio；
Fig. 5 is gel foam resistance factor in test example of the invention with the change curve of injection rate；
Fig. 6 is the structural schematic diagram of basic sandpack column in test example of the invention.
Specific embodiment
Only invention is further described in detail for following embodiments, but does not constitute any limitation of the invention.
Embodiment 1
1, oil well basic condition
10 II 2-9-3H well of service shaft spring is the horizontal producing well of a bite of In The Eastern Junggar Basin, and finishing drilling layer position is Shawan group
One section of II 2 substratum, finishing drilling well depth: oblique depth 1394.00m, vertical depth 962.34m；Track inlet point (N1S1Ⅱ2Sand top): it is tiltedly deep
1066.00m, vertical depth 960.41m, horizontal displacement 195.19m.
2, mentality of designing and water blockoff parameter designing
Mentality of designing:
Using gel foam water-plugging technique, mentality of designing is using three slugs: preposed attributives, main body slug and replacement section
Plug.Preposed attributives mainly use nitrogen, pit shaft and stratum near wellbore zone water are pushed into oil reservoir with nitrogen, while being evenly laminated
Power；Main body slug injects nitrogen and gel foamable composition, and nitrogen-gel foam slug is formed in water breakthrough channel, and bottom water is inhibited to invade
Enter；Replacement slug is nitrogen slug, and gel foam blocking agent is mainly replaced out screen casing and nearly pit shaft area, prevents blocking agent close
Near wellbore consolidation, blocks steam injection, oil channel, while playing the role of thermal insulation protection to tubing string.
Water blockoff parameter designing:
1) preposed attributives nitrogen use level design (see Fig. 1)
V is calculated according to formula 1Preposition nitrogen, by the nitrogen volume under Clapyron Equation (PV=nRT) conversion mark condition, i.e.,
5500Nm3。
2) gel foamable composition dosage designs
In bottom water reservoir recovery process, horizontal well is easily blocked from interlayer in steam injection process since the interlayer effect of blocking is weak
Weak part infuses channeling water layer, causes to alter in bottom water to form water ridge (see Fig. 2).
It is calculated to simplify gel foamable composition dosage, is triangular prism shape by horizontal well water ridge model simplification (see Fig. 3).
Volume is blocked according to simplified triangular prism modelling, service shaft horizontal section length 277.36m, according to similar horizontal
Well producing profile testing data, water ridge length are generally the 1/4~1/3 of producing well segment length, this well is according to producing well segment length
1/3 calculate water ridge length be 55m, block volume parameter designing see the table below 1.
1 service shaft main body slug occluding body of table accumulates parameter designing
Block volume VBlock volumeCalculation formula it is as follows:
Formula 3:VBlock volume=LH2α=55 × 4.1 tan θ Φ2×tan45°×0.263×0.53≈130m3。
The gel foamable composition is by α-sodium olefin sulfonate, acrylamide, sodium soil, N,N methylene bis acrylamide and azo
Two different heptonitrile compositions, by quality ratio, α olefin sulfonate: acrylamide: sodium soil: N, N- methylene-bisacrylamide: azo
Two different heptonitrile=1:3:3.5:0.1:0.025.
The dosage of gel foamable composition 2 calculates according to the following formula:
Formula 2:mGel foamable composition=VBlock volume·nDosing concentration·ρGel foam agent solution=1305% ρGel foam agent solution6.5 tons of ≈.
3) nitrogen-gel foam slug is designed with nitrogen injection dosage
VBlock volume=LH2·tanθ·Φ·α；
VWith nitrogen injection=VBlock volume·n；It is 13380Nm by the nitrogen volume that Clapyron Equation converts under mark condition3。
4) design of slug nitrogen use level is replaced
V is calculated according to formula 4Replace nitrogen, it is 6300Nm by the nitrogen volume that Clapyron Equation converts under mark condition3, anti-nitrogen injection
6800Nm3Thermally insulating the borehole.
5) steam consumption designs
Cycle design steam consumption is 1500t.
Service shaft spring 10 II 2-9-3H well, three slug parameter designings see the table below 2.
2 spring of the table each slug parameter designing of 10 II 2-9-3H well
3, measure step and the condition of production
1254 tons, steam injection pressure 17.9MPa of the 1st cyclic steam injection volume of service shaft, 748 tons of period oil-producing, comprehensive water cut 52%,
Water recovery rate 63.7%；2nd period steam injection pressure 13.5MPa, steam injection pressure decline, 742 tons of production cycle oil-producing, comprehensive water cut
75%, water recovery rate 283.7%, comprehensive water cut and water recovery rate are substantially increased compared with the 1st period, when judging this period steam injection
With lower water layer channeling, lead to aqueous after producing be substantially increased；3rd period steam injection pressure 12.9MPa, comprehensive water cut after production
89.3%, water recovery rate 629.8%, liquid measure 38.2t/d, day oil-producing 4.1t/d dropped to by 9.3t/d before channeling, produce occurrence
High liquid measure High water cut；Comprehensive analysis determines to implement the measure of gel foam water blockoff in the 4th period, extends effective production cycle.
Steps are as follows for measure:
1) when service shaft period comprehensive water cut is 90%, at injection pressure 7.5MPa, the anti-nitrogen injection into service shaft
5500Nm3；
2) at injection pressure 10MPa, prepared gel foamable composition is mixed with nitrogen using ground three-way device, then
It is injected into pit shaft, forms stable foam stream in pit shaft；
3) at injection pressure 11.5MPa, first nitrogen injection 6300Nm positive into service shaft3, then anti-nitrogen injection 6800Nm3；
4) at injection pressure 12MPa, the positive steam injection 1500t into service shaft.
After measure implementation up to now, accumulative production 103.8 days, 543.3 tons of stages period oil-producing, peak value oil-producing 8.9t/
D, comprehensive water cut 87%, than before measure, aqueous 95% 8 percentage points of decline, adds up to increase 404 tons of oil up to now, lasts have
Effect.Service shaft period throughput prediction statistics see the table below 3.
3 service shaft period throughput prediction of table statistics
Test example
1, injection timing is studied
It assembles and tries referring to model (structural schematic diagram is shown in attached drawing 3 in patent) two-tube in patent (publication No. CN105064962A)
Experiment device injects gel foam in period comprehensive water cut 75%, 80% and 90% respectively and inhibits bottom water, optimizes injection timing, examination
Testing result see the table below 4.
The different opportunity injection development effectiveness comparisons of table 4
From table 4, it can be seen that water stream channel can preferably be blocked by injecting gel foam when the period, comprehensive water cut was higher, press down
Bottom water coning processed.Also, the cumulative oil production that gel foam is injected when high comprehensive water cut injects gel when being higher than low comprehensive water cut
The water-control oil-increasing ability that gel foam is injected when the cumulative oil production, i.e. high comprehensive water cut of foam is more preferable.Analyze reason: crude oil is deposited
Foam stability can be seriously being reduced, sealing characteristics of the foam in porous media is influenced.When the period, composite water cut was lower
Gel foam is injected, since crude oil exists, foam stability is poor, and it is weaker to the shut-off capacity in the hypertonic channel of bottom water, but with
Formation crude oil is constantly plucked out of, and oil saturation gradually decreases, and foam stability gradually increases, and sealing characteristics is become better and better.
Therefore, injection gel foam inhibits the opportunity of bottom water should not be too early, and gel foam pair is injected when the period, composite water cut was higher
The plugging effect of bottom water is best.
2, injection parameter research
1) in gel foamable composition foaming agent and polymer concentration optimization
Under the conditions of 25 DEG C of temperature, respectively measure density of foaming agent 0.3wt%, 0.5wt%, 0.7wt%, 0.8wt%,
0.9wt%, when bubble volume and half-life period, as a result see the table below 5.
Influence of 5 density of foaming agent of table to bubble volume and half-life period
| Density of foaming agent (%) | Bubble volume (mL) | Drain half-life period (min) | Half foam life period (min) |
| 0.3 | 260 | 3.5 | / |
| 0.5 | 250 | 3.5 | 140 |
| 0.7 | 670 | 3.5 | 145 |
| 0.8 | 790 | 4 | 140 |
| 0.9 | 810 | 4 | 153 |
As can be seen from Table 5, when density of foaming agent is 0.7%~0.8% in gel foamable composition, bubble effect is preferable, bubble
Foam stability is stronger.
Under the conditions of 75 DEG C of gelling temperature, influence of the polymer concentration to gelation time and foam viscosity, test knot are measured
Fruit see the table below 6.
Influence of the PAM concentration to gelation time and foam viscosity in 6 gel foamable composition of table
| PAM (%) | Gelation time (h) | Foam viscosity (mpas) |
| 0.05 | 86 | 8600 |
| 0.1 | 72 | 26000 |
| 0.2 | 56 | 36000 |
| 0.3 | 51 | 48000 |
| 0.35 | 48 | 78000 |
As can be seen from Table 6, effect is ideal when polymer concentration is 0.3% in gel foamable composition.
2) nitrogen-gel foam slug inject gas to liquid ratio optimization
Under the conditions of 25 DEG C of temperature, respectively measure nitrogen-gel foam slug inject gas to liquid ratio 0.5:1,1:1,1.5:1,
The resistance factor of foaming agent solution (concentration 0.7wt%), as a result see the table below 7 when 2:1,3:1.
The resistance factor of foaming agent solution when 7 difference inject gas to liquid ratio of table
| Gas liquid ratio | Foaming agent solution resistance factor |
| 0.5:1 | 40.12 |
| 1:1 | 103.98 |
| 1.5:1 | 100.89 |
| 2:1 | 93.02 |
| 3:1 | 85.35 |
Foaming agent solution resistance factor is drawn with the change curve of inject gas to liquid ratio according to data in table 7, sees Fig. 4.Fig. 4
When showing that inject gas to liquid ratio is low, foam generates slowly and amount is few, and the pressure formed in rock core is low, and resistance factor is small；Inject gas
When liquor ratio is high, generate the of poor quality of foam, foam is big, it is sparse easily go out, stability is poor, and resistance factor is small.Therefore, inject gas to liquid ratio
It is preferred when between 1~2:1, the bubble formed within this range is fine and closely woven, stablizes, and apparent viscosity is high.
3, influence of the injection rate to gel foam resistance factor
Test method: nitrogen and gel foam agent solution are injected into fill out sand tube by 1:1 gas liquid ratio, records fill out sand tube both ends
Pressure difference as basic pressure difference；Under 1:1 gas liquid ratio, using 0.5mL/min, 1mL/min, 1.5mL/min, 2mL/min,
The injection rate of 2.5mL/min, 3mL/min, 3.5mL/min, 4mL/min inject nitrogen into fill out sand tube and gel foamable composition is molten
Liquid, records the pressure difference (i.e. operting differential pressure) at rock core both ends under friction speed, the ratio between operting differential pressure and basic pressure difference be resistance because
As a result son is shown in Fig. 5.
When Fig. 5 shows that gel foamable composition injection rate is too low, percolation flow velocity is slow, and basic pressure difference, which does not measure, to be come；Injection rate
Foam could be effectively generated when up to 0.3mL/min, but foam quality is poor at this time, pressure difference is smaller；With the increase of injection rate,
The quality for generating foam gradually improves, and injection pressure and resistance factor are also gradually increased；When injection rate be greater than 1.5mL/min,
Increase injection rate, resistance factor variation is little.Therefore it when field application, lower than under formation fracture pressure, should improve as far as possible
Injection rate.
4, influence of the injection mode to gel foam recovery ratio and resistance factor
Test method: 100 μm are filled out using quartz sand and fill out sand tube2The basic sandpack column (see Fig. 6) of left and right, tests it
Pore volume PV measures its basic pressure difference with distilled water in core flooding test device；According to injection mode in table 8 simultaneously or
Nitrogen and gel foamable composition are successively injected in sandpack column, are tested it and are broken through pressure difference, and calculate resistance factor, as a result see the table below
8。
Resistance factor comparison under the different injection modes of table 8
As can be seen from Table 8, when gas-liquid mixed water injection, resistance factor reaches 100 or more, and plugging effect is good；Gas-liquid is alternately injected
When, alternate frequency is higher, and alternately slug is smaller, and resistance factor is bigger, and foam blocking effect is good.It is excellent when therefore applying at the scene
Select the mode of nitrogen Yu the continuous mixed injection of gel foamable composition.
Claims (9)
1. the thick oil thermal recovery method that a kind of gel foam inhibits bottom water coning, it is characterised in that: steps are as follows:
1) when producing well period comprehensive water cut is greater than 90%, nitrogen is injected into producing well, forms preposition nitrogen slug；
2) continue the mixed system for injecting nitrogen and gel foam agent solution into producing well, form nitrogen-gel foam main body
Slug；
3) nitrogen is injected into producing well, is formed and is replaced nitrogen slug；
4) steam is injected；
Gel foamable composition is grouped as by the group of following mass ratio in step 2): α olefin sulfonate: acrylamide: filler: crosslinking
Agent: controlling agent=0.5~1:1.5~3:1.5~3.5:0.05~0.1:0.0025~0.025；
The dosage of gel foamable composition 2 calculates according to the following formula in step 2):
Formula 2:mGel foamable composition=VBlock volume·nDosing concentration·ρGel foam agent solution；
In formula: mGel foamable compositionFor the dosage of gel foamable composition, kg；VBlock volumeTo block volume, m3；nDosing concentrationFor dosing concentration, %, if
Count concentration 5%~10%；ρGel foam agent solutionFor the density of gel foam agent solution, kg/m3；
Formula 3:VBlock volume=LH2·tanθ·Φ·α；
In formula: L is water ridge length, and m, water ridge length is generally the 1/4~1/3 of producing well segment length；H is water ridge height, i.e., oily
Thickness of interlayer of the layer lower boundary to water layer coboundary, m；θ is water ridge angle, °, 30~60 ° of experience value；Φ is easily to break through well section
Porosity, %；α is injection ratio, dimensionless, experience value 0.53~0.6.
2. thick oil thermal recovery method according to claim 1, it is characterised in that: the injection rate of nitrogen is occluding body in step 2)
Long-pending 1~2 times.
3. thick oil thermal recovery method according to claim 1, it is characterised in that: the α olefin sulfonate is α-olefin sulfonic acid
Sodium.
4. thick oil thermal recovery method according to claim 1, it is characterised in that: the filler is sodium soil and/or flyash.
5. thick oil thermal recovery method according to claim 1, it is characterised in that: the crosslinking agent is N, N- methylene bisacrylamide
Amide or dibenzoyl peroxide.
6. thick oil thermal recovery method according to claim 1, it is characterised in that: the controlling agent is azobisisoheptonitrile or mistake
Sulfate.
7. thick oil thermal recovery method according to claim 1, it is characterised in that: the injection rate of nitrogen is equal to level in step 3)
Well straight well section wellbore volume and the product for crossing replacement coefficient 4 calculate according to the following formula:
Formula 4:VReplace nitrogen=β VMineshaft annulus volume=β VStraight well section=β π D1 2/4·H1；
In formula: VReplace nitrogenFor the nitrogen injection rate for replacing nitrogen slug, Nm3；VMineshaft annulus bodyFor horizontal well straight well section annular volume, Nm3；
VStraight well sectionFor horizontal well straight well section wellbore volume, Nm3；D1For casing inner diameter, m；H1For straight well segment length, m；β was replacement coefficient,
Dimensionless, experience value 1.2~1.5.
8. thick oil thermal recovery method according to claim 1, it is characterised in that: the injection rate of steam sets in step 4) for the period
Count gas injection rate.
9. according to the described in any item thick oil thermal recovery methods of claim 2-8, it is characterised in that: the injection rate of nitrogen in step 1)
It 1 calculates according to the following formula:
Formula 1:VPreposition nitrogen=VStraight well section+VHorizontal segment=π D1 2/4·H1+π·D2 2/4·H2；
In formula: VPreposition nitrogenFor the nitrogen injection rate of preposition nitrogen slug, Nm3；VStraight well sectionFor horizontal well straight well section wellbore volume, Nm3；
VHorizontal segmentFor horizontal well horizontal segment axial line cylinder volume, Nm3；D1For casing inner diameter, m；D2For using net horizontal section as axial line
Cylinder diameter, m, 3~5m of design radial；H1For straight well segment length, m；H2For horizontal section length, m.
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| CN110905460A (en) * | 2019-12-02 | 2020-03-24 | 中国石油化工股份有限公司 | Viscosity-reducing foaming exploitation method for common heavy oil reservoir |
| CN110905460B (en) * | 2019-12-02 | 2021-08-20 | 中国石油化工股份有限公司 | Viscosity-reducing foaming exploitation method for common heavy oil reservoir |
| CN113464087A (en) * | 2021-07-29 | 2021-10-01 | 西南石油大学 | Selective water plugging method for bottom water reservoir high-water-cut oil well |
| CN113464087B (en) * | 2021-07-29 | 2022-12-06 | 西南石油大学 | Selective water plugging method for bottom water reservoir high-water-cut oil well |
| CN115059430A (en) * | 2022-07-08 | 2022-09-16 | 中海石油(中国)有限公司 | Selective cone pressing water plugging method for bottom water reservoir oil well |
| CN115059430B (en) * | 2022-07-08 | 2024-01-23 | 中海石油(中国)有限公司 | Selective cone pressing water plugging method for oil well of side bottom water reservoir |
Also Published As
| Publication number | Publication date |
|---|---|
| CN109356561A (en) | 2019-02-19 |
| CN106150466A (en) | 2016-11-23 |
| CN106150466B (en) | 2018-11-27 |
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