CN106150466A - The thick oil thermal recovery method of gel foam suppression bottom water coning - Google Patents
The thick oil thermal recovery method of gel foam suppression bottom water coning Download PDFInfo
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- CN106150466A CN106150466A CN201610709754.3A CN201610709754A CN106150466A CN 106150466 A CN106150466 A CN 106150466A CN 201610709754 A CN201610709754 A CN 201610709754A CN 106150466 A CN106150466 A CN 106150466A
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- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
- E21B43/24—Enhanced recovery methods for obtaining hydrocarbons using heat, e.g. steam injection
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/32—Preventing gas- or water-coning phenomena, i.e. the formation of a conical column of gas or water around wells
-
- 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 DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP 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 DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
- E21B43/166—Injecting a gaseous medium; Injecting a gaseous medium and a liquid medium
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
- E21B43/166—Injecting a gaseous medium; Injecting a gaseous medium and a liquid medium
- E21B43/168—Injecting a gaseous medium
Abstract
The invention discloses the thick oil thermal recovery method of a kind of gel foam suppression bottom water coning, belong to oilfield exploitation and technical field of oilfield chemistry.The method comprises the following steps: when 1) producing well cycle comprehensive water cut is more than 90%, and nitrogen injection in producing well forms preposition nitrogen slug；2) continue nitrogen injection and the mixed system of gel foam agent solution in producing well, form nitrogen gel foam main body slug；3) nitrogen injection in producing well, is formed and replaces nitrogen slug；4) steam is injected, can wherein, pit shaft and near wellbore zone, stratum water can be pushed into oil reservoir by preposition nitrogen slug, equilibrium strata pressure, nitrogen gel foam main body slug can effectively suppress bottom water to invade, replace nitrogen slug and gel foam blocking agent can be replaced out screen casing and nearly pit shaft area, prevent blocking agent from consolidating at nearly near wellbore, block steam injection, oil recovery passage.The method can delay bottom water coning speed, improves steam sweep efficiency and utilization rate, improves effect of reservoir development.
Description
Technical field
The present invention relates to the thick oil thermal recovery method of a kind of gel foam suppression bottom water coning, belong to oilfield exploitation and oil field
Learn a skill field.
Background technology
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 element compound such as sulfur, oxygen, nitrogen and the metal ingredient such as nickel, vanadium is the highest,
Thus have than the feature such as great, viscosity is high, condensation point is low, and in Newtonian fluid characteristic within the scope of wider temperature.Due to ground
At a temperature of Ceng, thick oil viscosity is higher, is difficult to from main flow in prime stratum, and common exploitation exists bigger difficulty, it is necessary to use
The mode of thermal recovery is developed, and steam injection is current topmost heavy crude heat extraction mode.Exploitation via steam injection includes steam soak and steam
Driving, wherein steam soak is that the mode using periodicity or cyclicity steam injection is recovered the oil, by noting into High Temperature High Pressure to heavy oil wells
Wet saturated steam, by back production after crude oil heating viscosity-reducing a range of in oil reservoir out, i.e. gulps down into steam, discharge crude oil.Steam
It is the major technique of Development of Viscous Crude Oil that vapour is handled up, but is as the prolongation of production cycle, and oil yield is remarkably decreased.Particularly with
Having the super-heavy oil deposit of bottom water, owing to reservoir interlayer is thin, oil reservoir is near away from lower water layer or is directly connected with bottom water, and by level
Well development mode affects, and water breakthrough passage is shorter, easily causes water layer to alter logical or bottom water coning, cause oil after putting into steam soak exploitation
Well is aqueous to be substantially increased.Due to the anisotropism feature of heavy crude reservoir and affected by Simulation on whole pay zones, colloid after multi-cycle stimulation,
Asphaltene deposits, steam causes gravity segregation with the density variation of water etc., causes steam in high permeability formation channelling, water breakthrough, vapour occur
Alter.Along with steam is advanced by leaps and bounds along high permeability zone, steam sweep efficiency is gradually reduced, and steam effective area and utilization rate substantially reduce.
In addition after multi-cycle stimulation, stratum pressure drop increases, and is affected by limit water, bottom water invasion and attack etc., and cyclic steam stimulation effect is deteriorated every condition more
Difference, single-well crude oil yield gradually decreases, and oil recovery efficiency substantially reduces.
The patent of invention of publication No. CN105064962A discloses a kind of nitrogen foam suppression heavy crude heat extraction edge water propelling
Method, for the heavy crude heat extraction steam-stimulated well of cycle composite water cut >=90%, before before steam injection, first nitrogen injection is formed
Put nitrogen slug, then (foaming agent accounts for 0.4%～0.8%, and composition sees patent to inject expanding foam solution in producing well
CN104109523A), contact foaming (gas liquid ratio 1～2:1) with preposition nitrogen, be then poured into during nitrogen is formed putting nitrogen slug,
Inject steam in the most backward producing well, wherein, front, in put the nitrogen injection rate of nitrogen slug be the 40～80 of steam injection rate
Times, the nitrogen injection rate of preposition nitrogen slug is the 1/3～1/2 of total nitrogen injection rate.The method can effectively block limit water, suppression
Limit water coning, improves sweep efficiency and the displacement efficiency injecting steam simultaneously, improves 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 suppression effectiveness of bottom water coning.The patent of invention of notification number CN102876304B is public
Open a kind of horizontal well bottom water plugging technique, first sealed EXIT POINT with mechanical packer card, inject annular chemical packer, according to water
Reservoir temperature residing for horizontal well selects sealing agent system, for horizontal well thermal recovery, uses inorganic precipitation type system and nitrogen foam body
System or thermosensitive hydrogel system, and point two slugs injections, volume ratio 1～3:3～1, first inject inorganic precipitation type System forming first
Slug, reinjects nitrogen foam system or thermosensitive hydrogel System forming the second slug, replaces closing well plastic after the water of appropriate oil field.Should
Method is applicable to High water cut or ultra-high water-containing horizontal well, can reach high intensity indepth plugging purpose, effectively reduces horizontal well aqueous
Rate, improves oil well productivity, but bottom water oil reservoir there is no method at present and accurately finds water exit position, it is difficult to seal water outlet with packer card
Point, can only take the measure generally blocked, it is necessary to uses selective water-plugging, and is affected by sieve tube completion mode, it is impossible to use
Graininess blocking agent bottom water plugging.
Summary of the invention
It is an object of the invention to provide the thick oil thermal recovery method of a kind of gel foam suppression bottom water coning.
In order to realize object above, the technical solution adopted in the present invention is:
A kind of thick oil thermal recovery method of gel foam suppression bottom water coning, step is as follows:
1) when producing well cycle comprehensive water cut is more than 90%, nitrogen injection in producing well, form preposition nitrogen slug；
2) continue nitrogen injection and the mixed system of gel foam agent solution in producing well, form nitrogen-gel foam
Main body slug；
3) nitrogen injection in producing well, is formed and replaces nitrogen slug；
4) steam is injected,；
Step 2) in gel foamable composition be made up of α olefin sulfonate, acrylamide, filler, cross-linking agent and controlling agent, with
Mass ratio meter, α olefin sulfonate: acrylamide: filler: cross-linking agent: controlling agent=(0.5～1): (1.5～3): (1.5～
3.5): (0.05～0.1): (0.0025～0.025).
Step 1) in nitrogen injection rate according to the following formula 1 calculate:
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, design radial 3～5m；H1For straight well segment length, m；H2For horizontal section length, m.
Step 2) in gel foamable composition consumption according to the following formula 2 calculate:
Formula 2:mGel foamable composition=VClosure volume·nDosing concentration·ρGel foam agent solution；
In formula: mGel foamable compositionFor the consumption of gel foamable composition, kg；VClosure volumeFor closure volume, m3；nDosing concentrationDense for dosing
Degree, %, design concentration 5%～10%；ρGel foam agent solutionFor the density of gel foam agent solution, kg/m3；
Closure volume VClosure volumeAccording to the triangular prism modelling of water ridge numerical simulation graph reduction, computing formula is as follows:
Formula 3:VClosure volume=L H2·tanθ·Φ·α；
In formula: L is water ridge length, m (easy 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. oil reservoir lower boundary to the thickness of interlayer of water layer coboundary, m；θ is water ridge angle, °, experience value 30～
60°；Φ is easy breakthrough well sector hole porosity, %；α is injection ratio, dimensionless, experience value 0.53～0.6.
Step 2) in the injection rate of nitrogen (i.e. accompanying nitrogen injection) be that (i.e. gas liquid ratio n is 1～2, is for 1～2 times of closure volume
Refer to nitrogen injection rate and the ratio blocking volume under reservoir temperature, pressure condition), closure volume is calculated according to equation 3 above.
Step 2) gel foamable composition in α olefin sulfonate be α-sodium olefin sulfonate, as heatproof foaming agent.Acryloyl
Amine is gel host, and monomer structure is simple, and molecular weight is little, and during injection, initial viscosity is relatively low.
Described filler can use sodium soil, flyash etc..
Described cross-linking agent can use N,N methylene bis acrylamide, dibenzoyl peroxide etc..
Described controlling agent can use 2,2'-Azobis(2,4-dimethylvaleronitrile), persulfate (such as potassium peroxydisulfate) etc..
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 made up of chain initiation, chain growth and three elementary reactions of chain termination.Wherein chain initiation reaction is
Forming the reaction of free radical, heat, light, high-energy radiation and initiator etc. all 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 forming monomer radical, falls within exothermic reaction, anti-owing to increasing
Answering activation energy relatively low, speed is high, and after monomer radical once generates, at once with monomer molecule generation additive reaction, generation contains
The chain free radical of more monomeric unit, monomer molecule is had to make chain constantly increase with the continuous additive reaction of chain free radical；Chain is eventually
Only reacting the chain free radical i.e. increased to react with each other, lose activity and generate the process of stable macromolecular compound, chain termination is anti-
The activation energy answered is extremely low, and the most even zero, therefore terminate reaction rate constant very big, chain propagation reaction and chain termination reaction are
A pair growth and decline is reacted, and the generation of high polymer additionally depends on the concentration of reactant, and in usual polymerization system, monomer concentration compares free radical
Concentration is much bigger, and rate of chain growth is high more thousand of than chain termination speed and tens0000 orders of magnitude, it is sufficient to generate the degree of polymerization the highest
Long-chain free radical and macromole.
Step 3) in nitrogen injection rate equal to mineshaft annulus volume (namely horizontal well straight well section wellbore volume) with cross top
For the product of coefficient, 4 calculate according to the following formula:
VReplace nitrogen=β VMineshaft annulus volume=β VStraight well section=β π D1 2/4·H1；
In formula: VReplace nitrogenFor replacing the nitrogen injection rate of nitrogen slug, Nm3；VStraight well sectionFor horizontal well straight well section wellbore volume,
Nm3；D1For casing inner diameter, m；H1For pit shaft length, m；β was replacement coefficient, dimensionless, experience value 1.2～1.5.
Step 4) in the injection rate of steam be cycle design gas injection rate.General, according to numerical simulation study result and oil well week
Phase occurrence considers.
Step 1)～4) in nitrogen, the injection pressure of gel foam agent solution set by injection without particular/special requirement, injection rate
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 to use three slugs, i.e. preposed attributives, main body slug
With replacement slug, preposed attributives uses nitrogen, pit shaft and near wellbore zone, stratum water is pushed into oil reservoir, equilibrium strata pressure simultaneously,
Main body slug nitrogen injection and the mixed system of gel foamable composition, form nitrogen-gel foam slug, suppression in water breakthrough passage
Bottom water invades, and replaces slug and uses nitrogen equally, gel foam blocking agent replaces out screen casing and nearly pit shaft area, prevents blocking agent from existing
Nearly near wellbore consolidation, blocks steam injection, oil recovery passage, tubing string plays thermal insulation protection effect simultaneously.
Foaming agent, by application gel foam water-plugging technique, is formed gel-foam system with gel cross-linkage by the present invention,
Ground clear water or oil-polluted water dilution after, add nitrogen injection by ground installation, make the compositions such as foaming agent, gel, cross-linking agent with
Nitrogen is sufficiently mixed, and forms gel foam, mixes injection at well head with nitrogen, make gel foam form stable foam during injection
Stream, enters stratum and implements gel foam closure.Gel foam is the foam with gel as foreign minister, and gel foam had before Cheng Ning
Have the feature of water base foam, there is again after Cheng Ning the feature of elastic gel, have that shut-off capacity is strong, good stability, selection
Property the feature such as good.After steam-stimulated well injects high temperature gel foam system, gel foam can block oil reservoir water breakthrough passage, effectively presses down
Steam processed enters water layer, and turns to heating oil reservoir, improves steam sweep efficiency and utilization rate, delays bottom water coning speed simultaneously,
Improve effect of reservoir development.
Accompanying drawing explanation
Fig. 1 is preposed attributives nitrogen use level design diagram in embodiment 1；
Fig. 2 is horizontal well water ridge numerical simulation figure；
Fig. 3 is water ridge simplified model figure；
Fig. 4 be in test example foaming agent solution resistance factor with the change curve of IGLR；
Fig. 5 is the gel foam resistance factor change curve with injection rate；
The structural representation of sandpack column based on Fig. 6.
Detailed description of the invention
The present invention is only described in further detail by following embodiment, but does not constitute any limitation of the invention.
Embodiment 1
1, oil well basic condition
Service shaft spring 10 II 2-9-3H well 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: the deepest 1394.00m, vertical depth 962.34m；Track inlet point (N1S1Ⅱ2Sand top): the deepest
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 to use three slugs: preposed attributives, main body slug and replacement section
Plug.Preposed attributives mainly uses nitrogen, with nitrogen, pit shaft and near wellbore zone, stratum water is pushed into oil reservoir, is laminated evenly simultaneously
Power；Main body slug nitrogen injection and gel foamable composition, form nitrogen-gel foam slug in water breakthrough passage, and suppression bottom water is invaded
Enter；Replacing slug is nitrogen slug, gel foam blocking agent mainly replaces out screen casing and nearly pit shaft area, prevents blocking agent closely
Near wellbore consolidates, and blocks steam injection, oil recovery passage, tubing string plays thermal insulation protection effect simultaneously.
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 consumption design
In bottom water reservoir recovery process, horizontal well is weak due to the interlayer effect of blocking, and easily blocks from interlayer in steam injection process
Weak part note channeling water layer, causes and alters formation water ridge (see Fig. 2) on bottom water.
Calculate for simplifying gel foamable composition consumption, be triangular prism shape (see Fig. 3) by horizontal well water ridge model simplification.
Closure volume is according to the triangular prism modelling simplified, and service shaft horizontal section length 277.36m, according to similar level
Well producing profile testing data, water ridge length is generally the 1/4～1/3 of producing well segment length, and this well is according to producing well segment length
1/3 calculating a length of 55m of water ridge, closure volume parameter designing see table 1.
Table 1 service shaft main body slug occluding body amasss parameter designing
Closure volume VClosure volumeComputing formula as follows:
Formula 3:VClosure volume=L H2Tan θ Φ α=55 × 4.12×tan45°×0.263×0.53≈130m3。
Described 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 bis acrylamide: azo
Two different heptonitrile=1:3:3.5:0.1:0.025.
The consumption of gel foamable composition 2 calculates according to the following formula:
Formula 2:mGel foamable composition=VClosure volume·nDosing concentration·ρGel foam agent solution=130 5% ρGel foam agent solution≈ 6.5 tons.
3) nitrogen-gel foam slug companion's nitrogen injection consumption design
VClosure volume=L H2·tanθ·Φ·α；
VCompanion's nitrogen injection=VClosure volume·n；It is 13380Nm by the nitrogen volume under Clapyron Equation conversion mark condition3。
4) design of slug nitrogen use level is replaced
V is calculated according to formula 4Replace nitrogen, the nitrogen volume under Clapyron Equation conversion mark condition it is 6300Nm3, anti-nitrogen injection
6800Nm3Thermally insulating the borehole.
5) steam consumption design
Cycle design steam consumption is 1500t.
Three slug parameter designing of service shaft spring 10 II 2-9-3H well see table 2.
Each slug parameter designing of table 2 spring 10 II 2-9-3H well
3, measure step and the condition of production
Service shaft the 1st cyclic steam injection volume 1254 tons, steam injection pressure 17.9MPa, cycle oil-producing 748 tons, comprehensive water cut 52%,
Water recovery rate 63.7%；2nd cycle steam injection pressure 13.5MPa, steam injection pressure declines, production cycle oil-producing 742 tons, comprehensive water cut
75%, water recovery rate 283.7%, comprehensive water cut and water recovery rate are substantially increased compared with the 1st cycle, it is judged that during this cycle steam injection
Alter with lower water layer vapour, aqueous be substantially increased after causing producing；3rd cycle 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 altered front 9.3t/d by vapour and drop to 4.1t/d, produce occurrence
High liquid measure High water cut；Comprehensive analysis, determines to implement gel foam water blockoff measure in the 4th cycle, extends effective production cycle.
Measure step is as follows:
1) when service shaft cycle comprehensive water cut is 90%, under injection pressure 7.5MPa, anti-nitrogen injection in service shaft
5500Nm3；
2) under injection pressure 10MPa, ground three-way device is utilized to be mixed with nitrogen by the gel foamable composition prepared, then
It is injected in pit shaft, in pit shaft, forms stable foam stream；
3) under injection pressure 11.5MPa, first positive nitrogen injection 6300Nm in service shaft3, more anti-nitrogen injection 6800Nm3；
3) under injection pressure 12MPa, positive steam injection 1500t in service shaft,.
After measure enforcement up to now, accumulative production 103.8 days, stages period oil-producing 543.3 tons, peak value oil-producing 8.9t/
D, comprehensive water cut 87%, than before measure, aqueous 95% declines 8 percentage points, up to now accumulative increasing oil 404 tons, and lasts has
Effect.Service shaft cycle throughput prediction statistics see table 3.
Table 3 service shaft cycle throughput prediction is added up
Test example
1, injection timing research
Examination is assembled with reference to two-tube model (structural representation is shown in accompanying drawing 3 in patent) in patent (publication No. CN105064962A)
Experiment device, injects gel foam suppression bottom water in cycle comprehensive water cut 75%, 80% and 90% respectively, optimizes injection timing, examination
Test result and see table 4.
Table 4 injects development effectiveness contrast different opportunity
From table 4, it can be seen that inject gel foam can preferably block water stream channel when the cycle, comprehensive water cut was higher, press down
Bottom water coning processed.Further, the cumulative oil production of gel foam is injected during high comprehensive water cut higher than injecting gel during low comprehensive water cut
The cumulative oil production of foam, the water-control oil-increasing ability injecting gel foam during the highest comprehensive water cut is more preferable.Analyze reason: crude oil is deposited
Can seriously reduce foam stability, affect foam sealing characteristics in porous media.When the cycle, composite water cut was relatively low
Injecting gel foam, owing to crude oil exists, foam stability is poor, more weak to the shut-off capacity in bottom water high bleed-through road, but along with
Formation crude oil is constantly plucked out of, and oil saturation is gradually lowered, and foam stability gradually strengthens, and sealing characteristics is become better and better.
Therefore, the opportunity injecting gel foam suppression bottom water is unsuitable too early, injects gel foam pair when the cycle, composite water cut was higher
The plugging effect of bottom water is best.
2, injection parameter research
1) foaming agent and the optimization of polymer concentration in gel foamable composition
Under the conditions of temperature 25 DEG C, respectively measure density of foaming agent 0.3wt%, 0.5wt%, 0.7wt%, 0.8wt%,
0.9wt%, time bubble volume and the half-life, result see table 5.
Table 5 density of foaming agent is on bubble volume and the impact of half-life
| Density of foaming agent (%) | Bubble volume (mL) | The discharge opeing half-life (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 in gel foamable composition, density of foaming agent is 0.7%～0.8%, bubble effect is preferable, bubble
Foam stability is stronger.
Under the conditions of gelling temperature 75 DEG C, measure polymer concentration to gelation time and the impact of foam viscosity, test knot
Fruit see table 6.
In table 6 gel foamable composition, PAM concentration is on gelation time and the impact of foam viscosity
| PAM (%) | Gelation time (h) | Foam viscosity (mpa s) |
| 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, when in gel foamable composition, polymer concentration is 0.3%, effect is ideal.
2) optimization of nitrogen-gel foam slug IGLR
Under the conditions of temperature 25 DEG C, measure respectively nitrogen-gel foam slug IGLR 0.5:1,1:1,1.5:1,
The resistance factor of foaming agent solution (concentration 0.7wt%) when 2:1,3:1, result see table 7.
The resistance factor of foaming agent solution during table 7 different IGLR
| 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 |
With the change curve of IGLR, Fig. 4 is seen according to data drafting foaming agent solution resistance factor in table 7.Fig. 4
Showing, when IGLR is low, foam produces slowly and amount is few, and the pressure formed in rock core is low, and resistance factor is little；Inject gas
During liquor ratio height, producing the of poor quality of foam, foam is big, sparse easily to go out, and poor stability, resistance factor is little.Therefore, IGLR
Being preferred when 1～2:1, the bubble formed in the range of this is fine and closely woven, stable, and apparent viscosity is high.
3, the injection rate impact on gel foam resistance factor
Test method: by 1:1 gas liquid ratio nitrogen injection and gel foam agent solution in fill out sand tube, records fill out sand tube two ends
Pressure reduction based on pressure reduction；Under 1:1 gas liquid ratio, use 0.5mL/min, 1mL/min, 1.5mL/min, 2mL/min,
The injection rate of 2.5mL/min, 3mL/min, 3.5mL/min, 4mL/min nitrogen injection and gel foamable composition in fill out sand tube is molten
Liquid, the pressure reduction (i.e. operting differential pressure) at rock core two ends under record friction speed, the ratio of operting differential pressure and basis pressure reduction be resistance because of
Son, result is shown in Fig. 5.
Fig. 5 shows, when gel foamable composition injection rate is too low, percolation flow velocity is slow, and basis pressure reduction does not measures；Injection rate
Could effectively produce foam when reaching 0.3mL/min, but now foam quality is poor, pressure reduction is less；Along with the increase of injection rate,
The quality producing foam gradually improves, and injection pressure and resistance factor are also gradually increased；When injection rate is more than 1.5mL/min,
Increasing injection rate, resistance factor change is little.Therefore, during on-the-spot application, under less than formation fracture pressure, should improve as far as possible
Injection rate.
4, injection mode is on gel foam recovery ratio and the impact of resistance factor
Test method: utilize quartz sand and fill out sand tube to fill out 100 μm2The basic sandpack column (see Fig. 6) of left and right, tests it
Pore volume PV, measures its basis pressure reduction with distilled water in core flooding test device；According to injection mode in table 8 simultaneously or
Successively nitrogen injection and gel foamable composition in sandpack column, tests it and breaks through pressure reduction, and calculate resistance factor, and result see table
8。
Resistance factor contrast under the different injection mode of table 8
As can be seen from Table 8, during gas-liquid mixed water injection, resistance factor reaches more than 100, and plugging effect is good；Gas-liquid is alternately injected
Time, frequency alternately is the highest, and alternately slug is the least, and resistance factor is the biggest, and foam blocking is effective.Excellent during application the most at the scene
Nitrogen is selected to mix the mode of injection continuously with gel foamable composition.
Claims (10)
1. the thick oil thermal recovery method of a gel foam suppression bottom water coning, it is characterised in that: step is as follows:
1) when producing well cycle comprehensive water cut is more than 90%, nitrogen injection in producing well, form preposition nitrogen slug；
2) continue nitrogen injection and the mixed system of gel foam agent solution in producing well, form nitrogen-gel foam main body
Slug；
3) nitrogen injection in producing well, is formed and replaces nitrogen slug；
4) steam is injected,；
Step 2) in gel foamable composition be made up of the component of following mass ratio: 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.
Thick oil thermal recovery method the most according to claim 1, it is characterised in that: step 1) in nitrogen injection rate according to the following formula
1 calculates:
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 with net horizontal section as axial line
Cylinder diameter, m, design radial 3～5m；H1For straight well segment length, m；H2For horizontal section length, m.
Thick oil thermal recovery method the most according to claim 1, it is characterised in that: step 2) in gel foamable composition consumption according to
Following formula 2 calculates:
Formula 2:mGel foamable composition=VClosure volume·nDosing concentration·ρGel foam agent solution；
In formula: mGel foamable compositionFor the consumption of gel foamable composition, kg；VClosure volumeFor closure volume, m3；nDosing concentrationFor dosing concentration, %, if
Meter concentration 5%～10%；ρGel foam agent solutionFor the density of gel foam agent solution, kg/m3；
Formula 3:VClosure volume=L H2·tanθ·Φ·α；
In formula: L is water ridge length, m, water ridge length is generally the 1/4～1/3 of producing well segment length；H is water ridge height, i.e. oil
Layer lower boundary is to the thickness of interlayer of water layer coboundary, m；θ is water ridge angle, °, experience value 30～60 °；Φ is easy breakthrough well section
Porosity, %；α is injection ratio, dimensionless, experience value 0.53～0.6.
Thick oil thermal recovery method the most according to claim 3, it is characterised in that: step 2) in the injection rate of nitrogen be occluding body
Long-pending 1～2 times.
Thick oil thermal recovery method the most according to claim 1, it is characterised in that: described α olefin sulfonate is α-olefin sulfonic acid
Sodium.
Thick oil thermal recovery method the most according to claim 1, it is characterised in that: described filler is sodium soil and/or flyash.
Thick oil thermal recovery method the most according to claim 1, it is characterised in that: described cross-linking agent is N, N-methylene bisacrylamide
Amide or dibenzoyl peroxide.
Thick oil thermal recovery method the most according to claim 1, it is characterised in that: described controlling agent is 2,2'-Azobis(2,4-dimethylvaleronitrile) or mistake
Sulfate.
Thick oil thermal recovery method the most according to claim 1, it is characterised in that: step 3) in the injection rate of nitrogen equal to level
Well straight well section wellbore volume replaces the product of coefficient with crossing, and 4 calculates according to the following formula:
VReplace nitrogen=β VMineshaft annulus volume=β VStraight well section=β π D1 2/4·H1；
In formula: VReplace nitrogenFor replacing the nitrogen injection rate of nitrogen slug, Nm3；VStraight well sectionFor horizontal well straight well section wellbore volume, Nm3；D1
For casing inner diameter, m；H1For pit shaft length, m；β was replacement coefficient, dimensionless, experience value 1.2～1.5.
Thick oil thermal recovery method the most according to claim 1, it is characterised in that: step 4) in the injection rate of steam be the cycle
Design gas injection rate.
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| CN201810971764.3A CN109025953A (en) | 2016-08-23 | 2016-08-23 | A kind of application method of the gel foamable composition of heavy crude heat extraction inhibition bottom water coning |
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