CN116023919B - Capsule blocking remover and composite blocking removing method - Google Patents
Capsule blocking remover and composite blocking removing method Download PDFInfo
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- CN116023919B CN116023919B CN202111256356.8A CN202111256356A CN116023919B CN 116023919 B CN116023919 B CN 116023919B CN 202111256356 A CN202111256356 A CN 202111256356A CN 116023919 B CN116023919 B CN 116023919B
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- 230000000903 blocking effect Effects 0.000 title claims abstract description 282
- 239000002775 capsule Substances 0.000 title claims abstract description 199
- 239000002131 composite material Substances 0.000 title claims abstract description 54
- 238000000034 method Methods 0.000 title claims abstract description 49
- 239000003795 chemical substances by application Substances 0.000 claims abstract description 102
- 239000012530 fluid Substances 0.000 claims abstract description 77
- 239000002253 acid Substances 0.000 claims abstract description 76
- 239000011248 coating agent Substances 0.000 claims abstract description 51
- 238000000576 coating method Methods 0.000 claims abstract description 51
- 210000002489 tectorial membrane Anatomy 0.000 claims abstract description 18
- 239000000499 gel Substances 0.000 claims description 86
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 claims description 40
- 239000003431 cross linking reagent Substances 0.000 claims description 30
- VYPSYNLAJGMNEJ-UHFFFAOYSA-N Silicium dioxide Chemical compound O=[Si]=O VYPSYNLAJGMNEJ-UHFFFAOYSA-N 0.000 claims description 27
- KRHYYFGTRYWZRS-UHFFFAOYSA-N Fluorane Chemical compound F KRHYYFGTRYWZRS-UHFFFAOYSA-N 0.000 claims description 26
- 239000004576 sand Substances 0.000 claims description 20
- 239000004520 water soluble gel Substances 0.000 claims description 20
- 239000000654 additive Substances 0.000 claims description 19
- 230000000996 additive effect Effects 0.000 claims description 19
- 239000004927 clay Substances 0.000 claims description 19
- 238000004090 dissolution Methods 0.000 claims description 19
- 239000002245 particle Substances 0.000 claims description 19
- 239000003381 stabilizer Substances 0.000 claims description 19
- 239000002562 thickening agent Substances 0.000 claims description 19
- VEXZGXHMUGYJMC-UHFFFAOYSA-N Hydrochloric acid Chemical compound Cl VEXZGXHMUGYJMC-UHFFFAOYSA-N 0.000 claims description 18
- 239000007787 solid Substances 0.000 claims description 18
- 229920000036 polyvinylpyrrolidone Polymers 0.000 claims description 17
- 239000001267 polyvinylpyrrolidone Substances 0.000 claims description 17
- 235000013855 polyvinylpyrrolidone Nutrition 0.000 claims description 17
- 239000001856 Ethyl cellulose Substances 0.000 claims description 15
- ZZSNKZQZMQGXPY-UHFFFAOYSA-N Ethyl cellulose Chemical compound CCOCC1OC(OC)C(OCC)C(OCC)C1OC1C(O)C(O)C(OC)C(CO)O1 ZZSNKZQZMQGXPY-UHFFFAOYSA-N 0.000 claims description 15
- 229920001249 ethyl cellulose Polymers 0.000 claims description 15
- 235000019325 ethyl cellulose Nutrition 0.000 claims description 15
- 239000011435 rock Substances 0.000 claims description 14
- 108010010803 Gelatin Proteins 0.000 claims description 13
- 239000008273 gelatin Substances 0.000 claims description 13
- 229920000159 gelatin Polymers 0.000 claims description 13
- 235000019322 gelatine Nutrition 0.000 claims description 13
- 235000011852 gelatine desserts Nutrition 0.000 claims description 13
- ROOXNKNUYICQNP-UHFFFAOYSA-N ammonium persulfate Chemical group [NH4+].[NH4+].[O-]S(=O)(=O)OOS([O-])(=O)=O ROOXNKNUYICQNP-UHFFFAOYSA-N 0.000 claims description 12
- LNOPIUAQISRISI-UHFFFAOYSA-N n'-hydroxy-2-propan-2-ylsulfonylethanimidamide Chemical compound CC(C)S(=O)(=O)CC(N)=NO LNOPIUAQISRISI-UHFFFAOYSA-N 0.000 claims description 11
- 229920002401 polyacrylamide Polymers 0.000 claims description 9
- QTBSBXVTEAMEQO-UHFFFAOYSA-N Acetic acid Chemical compound CC(O)=O QTBSBXVTEAMEQO-UHFFFAOYSA-N 0.000 claims description 8
- 239000004343 Calcium peroxide Substances 0.000 claims description 8
- 239000005708 Sodium hypochlorite Substances 0.000 claims description 8
- 239000007864 aqueous solution Substances 0.000 claims description 8
- LHJQIRIGXXHNLA-UHFFFAOYSA-N calcium peroxide Chemical compound [Ca+2].[O-][O-] LHJQIRIGXXHNLA-UHFFFAOYSA-N 0.000 claims description 8
- 235000019402 calcium peroxide Nutrition 0.000 claims description 8
- SUKJFIGYRHOWBL-UHFFFAOYSA-N sodium hypochlorite Chemical compound [Na+].Cl[O-] SUKJFIGYRHOWBL-UHFFFAOYSA-N 0.000 claims description 8
- 239000006004 Quartz sand Substances 0.000 claims description 7
- DZSVIVLGBJKQAP-UHFFFAOYSA-N 1-(2-methyl-5-propan-2-ylcyclohex-2-en-1-yl)propan-1-one Chemical compound CCC(=O)C1CC(C(C)C)CC=C1C DZSVIVLGBJKQAP-UHFFFAOYSA-N 0.000 claims description 6
- SMZOUWXMTYCWNB-UHFFFAOYSA-N 2-(2-methoxy-5-methylphenyl)ethanamine Chemical compound COC1=CC=C(C)C=C1CCN SMZOUWXMTYCWNB-UHFFFAOYSA-N 0.000 claims description 6
- NIXOWILDQLNWCW-UHFFFAOYSA-N 2-Propenoic acid Natural products OC(=O)C=C NIXOWILDQLNWCW-UHFFFAOYSA-N 0.000 claims description 6
- HRPVXLWXLXDGHG-UHFFFAOYSA-N Acrylamide Chemical compound NC(=O)C=C HRPVXLWXLXDGHG-UHFFFAOYSA-N 0.000 claims description 6
- NLXLAEXVIDQMFP-UHFFFAOYSA-N Ammonia chloride Chemical compound [NH4+].[Cl-] NLXLAEXVIDQMFP-UHFFFAOYSA-N 0.000 claims description 6
- 239000011837 N,N-methylenebisacrylamide Substances 0.000 claims description 6
- WHNWPMSKXPGLAX-UHFFFAOYSA-N N-Vinyl-2-pyrrolidone Chemical compound C=CN1CCCC1=O WHNWPMSKXPGLAX-UHFFFAOYSA-N 0.000 claims description 6
- WCUXLLCKKVVCTQ-UHFFFAOYSA-M Potassium chloride Chemical compound [Cl-].[K+] WCUXLLCKKVVCTQ-UHFFFAOYSA-M 0.000 claims description 6
- 230000006978 adaptation Effects 0.000 claims description 6
- 229910001870 ammonium persulfate Inorganic materials 0.000 claims description 6
- FOCAUTSVDIKZOP-UHFFFAOYSA-N chloroacetic acid Chemical compound OC(=O)CCl FOCAUTSVDIKZOP-UHFFFAOYSA-N 0.000 claims description 6
- 229940106681 chloroacetic acid Drugs 0.000 claims description 6
- VTIIJXUACCWYHX-UHFFFAOYSA-L disodium;carboxylatooxy carbonate Chemical compound [Na+].[Na+].[O-]C(=O)OOC([O-])=O VTIIJXUACCWYHX-UHFFFAOYSA-L 0.000 claims description 6
- BDAGIHXWWSANSR-UHFFFAOYSA-N methanoic acid Natural products OC=O BDAGIHXWWSANSR-UHFFFAOYSA-N 0.000 claims description 6
- ZIUHHBKFKCYYJD-UHFFFAOYSA-N n,n'-methylenebisacrylamide Chemical compound C=CC(=O)NCNC(=O)C=C ZIUHHBKFKCYYJD-UHFFFAOYSA-N 0.000 claims description 6
- 229940045872 sodium percarbonate Drugs 0.000 claims description 6
- 229920006029 tetra-polymer Polymers 0.000 claims description 6
- QCWXUUIWCKQGHC-UHFFFAOYSA-N Zirconium Chemical compound [Zr] QCWXUUIWCKQGHC-UHFFFAOYSA-N 0.000 claims description 5
- -1 alkyl glycoside Chemical class 0.000 claims description 5
- 239000003093 cationic surfactant Substances 0.000 claims description 5
- 229930182470 glycoside Natural products 0.000 claims description 5
- 239000002736 nonionic surfactant Substances 0.000 claims description 5
- 150000003242 quaternary ammonium salts Chemical group 0.000 claims description 5
- 229910052726 zirconium Inorganic materials 0.000 claims description 5
- KXGFMDJXCMQABM-UHFFFAOYSA-N 2-methoxy-6-methylphenol Chemical compound [CH]OC1=CC=CC([CH])=C1O KXGFMDJXCMQABM-UHFFFAOYSA-N 0.000 claims description 4
- MIMUSZHMZBJBPO-UHFFFAOYSA-N 6-methoxy-8-nitroquinoline Chemical compound N1=CC=CC2=CC(OC)=CC([N+]([O-])=O)=C21 MIMUSZHMZBJBPO-UHFFFAOYSA-N 0.000 claims description 4
- 229920001807 Urea-formaldehyde Polymers 0.000 claims description 4
- 229920001568 phenolic resin Polymers 0.000 claims description 4
- 239000005011 phenolic resin Substances 0.000 claims description 4
- OSWFIVFLDKOXQC-UHFFFAOYSA-N 4-(3-methoxyphenyl)aniline Chemical compound COC1=CC=CC(C=2C=CC(N)=CC=2)=C1 OSWFIVFLDKOXQC-UHFFFAOYSA-N 0.000 claims description 3
- YCKRFDGAMUMZLT-UHFFFAOYSA-N Fluorine atom Chemical compound [F] YCKRFDGAMUMZLT-UHFFFAOYSA-N 0.000 claims description 3
- GRYLNZFGIOXLOG-UHFFFAOYSA-N Nitric acid Chemical compound O[N+]([O-])=O GRYLNZFGIOXLOG-UHFFFAOYSA-N 0.000 claims description 3
- 239000013543 active substance Substances 0.000 claims description 3
- GZCGUPFRVQAUEE-SLPGGIOYSA-N aldehydo-D-glucose Chemical compound OC[C@@H](O)[C@@H](O)[C@H](O)[C@@H](O)C=O GZCGUPFRVQAUEE-SLPGGIOYSA-N 0.000 claims description 3
- 235000019270 ammonium chloride Nutrition 0.000 claims description 3
- 239000011737 fluorine Substances 0.000 claims description 3
- 229910052731 fluorine Inorganic materials 0.000 claims description 3
- 235000019253 formic acid Nutrition 0.000 claims description 3
- 239000007849 furan resin Substances 0.000 claims description 3
- 229910017604 nitric acid Inorganic materials 0.000 claims description 3
- 239000003002 pH adjusting agent Substances 0.000 claims description 3
- 229940051841 polyoxyethylene ether Drugs 0.000 claims description 3
- 229920000056 polyoxyethylene ether Polymers 0.000 claims description 3
- 229920005749 polyurethane resin Polymers 0.000 claims description 3
- 239000001103 potassium chloride Substances 0.000 claims description 3
- 235000011164 potassium chloride Nutrition 0.000 claims description 3
- USHAGKDGDHPEEY-UHFFFAOYSA-L potassium persulfate Chemical compound [K+].[K+].[O-]S(=O)(=O)OOS([O-])(=O)=O USHAGKDGDHPEEY-UHFFFAOYSA-L 0.000 claims description 3
- 239000000843 powder Substances 0.000 claims description 3
- 229920005989 resin Polymers 0.000 claims description 3
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- 238000009826 distribution Methods 0.000 claims description 2
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- 239000012948 isocyanate Substances 0.000 claims description 2
- 150000002513 isocyanates Chemical class 0.000 claims description 2
- IIACRCGMVDHOTQ-UHFFFAOYSA-N sulfamic acid group Chemical group S(N)(O)(=O)=O IIACRCGMVDHOTQ-UHFFFAOYSA-N 0.000 claims description 2
- 239000000919 ceramic Substances 0.000 claims 1
- 230000009286 beneficial effect Effects 0.000 abstract description 3
- 239000010779 crude oil Substances 0.000 abstract description 2
- 238000011084 recovery Methods 0.000 abstract description 2
- 230000015572 biosynthetic process Effects 0.000 abstract 1
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- 238000002347 injection Methods 0.000 description 28
- 239000007924 injection Substances 0.000 description 28
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- FAPWRFPIFSIZLT-UHFFFAOYSA-M Sodium chloride Chemical compound [Na+].[Cl-] FAPWRFPIFSIZLT-UHFFFAOYSA-M 0.000 description 6
- 238000010276 construction Methods 0.000 description 6
- 238000001914 filtration Methods 0.000 description 6
- 238000010008 shearing Methods 0.000 description 6
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- 239000000356 contaminant Substances 0.000 description 4
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- RECVMTHOQWMYFX-UHFFFAOYSA-N oxygen(1+) dihydride Chemical compound [OH2+] RECVMTHOQWMYFX-UHFFFAOYSA-N 0.000 description 2
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- OWIKHYCFFJSOEH-UHFFFAOYSA-N Isocyanic acid Chemical compound N=C=O OWIKHYCFFJSOEH-UHFFFAOYSA-N 0.000 description 1
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- XLJMAIOERFSOGZ-UHFFFAOYSA-N anhydrous cyanic acid Natural products OC#N XLJMAIOERFSOGZ-UHFFFAOYSA-N 0.000 description 1
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Landscapes
- Detergent Compositions (AREA)
Abstract
The invention belongs to the field of crude oil recovery, and particularly relates to a capsule blocking remover and a composite blocking removing method. The capsule blocking remover consists of a capsule core and a capsule coating wrapping the capsule core, wherein the capsule blocking remover is divided into an organic capsule blocking remover and an inorganic capsule blocking remover, and the capsule core of the organic capsule blocking remover is an organic blocking remover capable of removing blocking of organic matters; the capsule core of the inorganic capsule blocking remover is an inorganic blocking remover capable of removing inorganic blocking. A composite unblocking method comprising: (1) injecting an aqueous temporary plugging agent solution into the formation; (2) Injecting fracturing pre-fluid carrying the capsule blocking remover into the stratum to enable the fracturing pre-fluid to enter the deep part of the stratum; (3) And (3) injecting acid gel sand-carrying fluid carrying the tectorial membrane propping agent into the stratum to enable the acid gel sand-carrying fluid to enter the stratum, so that deep composite blocking removal is realized. The beneficial effects of the invention are as follows: 1. the synergism of a plurality of blocking remover ensures that deep blocking of stratum is removed; 2. secondary pollution to stratum is avoided; 3. the blocking remover is utilized efficiently.
Description
Technical Field
The invention belongs to the field of crude oil recovery, and particularly relates to a capsule blocking remover and a composite blocking removing method.
Background
The reservoir stratum of the loose sandstone oil reservoir is cemented and loose, the clay mineral of the reservoir stratum is easy to expand and particles move in the development process, and the oil reservoir is subjected to measures such as long-term water injection, polymer injection, multiple-time profile control and water shutoff, the physical/chemical products generated in the construction processes of water injection impurities, oil sludge sand, blockage and adjustment, three-production and the like are adsorbed and retained in the stratum pores to form blockage, so that the subsequent measures effects of water injection development, blockage and adjustment, three-production and the like are seriously affected.
Although the common chemical blocking removal can relieve the problem of stratum blocking to a certain extent, the existing chemical blocking removal technology is difficult to move the blocking removal agent to the deep part of the stratum to perform the blocking removal function. The injection amount of the common chemical blocking remover is small, and the blocking hypotonic part is difficult to reach due to the filtration phenomenon of the high-permeability zone of the ground layer, so that the action radius is small; the large-scale injection of the plugging removing agent can remove the deep plugging of partial stratum, but the input and output are relatively low.
Because of the physical property and mechanical property of the loose sandstone oil reservoir, the plastic property of the stratum is strong, the permeability is extremely poor in the longitudinal direction, the dominant passageway is obvious, the fluid loss property is strong, the conventional hydraulic fracturing mode is adopted to make a seam difficult, the injected blocking remover preferentially enters a high-permeability zone, the low-permeability blocking zone cannot be effectively blocked, the injection increasing amount is low, the effective period is short, the blocking removing effect is poor, and the resource waste is caused.
Disclosure of Invention
The invention aims to provide a capsule blocking remover and a composite blocking removing method, which solve the problem of blocking in a near wellbore zone of a loose sandstone reservoir.
The technical scheme is as follows: the capsule blocking remover consists of a capsule core and a capsule coating wrapping the capsule core, wherein the capsule blocking remover is divided into two types of organic capsule blocking remover and inorganic capsule blocking remover, wherein:
the capsule core of the organic capsule blocking remover is an organic blocking remover capable of removing the blocking of organic matters;
the capsule core of the inorganic capsule blocking remover is an inorganic blocking remover capable of removing inorganic blocking.
Further, the organic blocking remover is a solid oxidizer.
Further, the organic blocking remover is one or more of calcium peroxide, sodium hypochlorite and sodium percarbonate.
Further, the inorganic blocking remover consists of a first component and a second component, wherein the first component accounts for 50-70 wt% and the second component accounts for 30-50 wt%;
the first component is one of sulfamic acid, chloroacetic acid and solid nitric acid powder, preferably sulfamic acid;
the second component is one of solid hydrofluoric acid and ammonium bifluoride, preferably solid hydrofluoric acid.
Further, the capsule coat is composed of ethylcellulose, polyvinylpyrrolidone and gelatin, wherein: the mass ratio of the ethyl cellulose to the polyvinylpyrrolidone to the gelatin is (65-85): (5-10): (10-30).
A composite unblocking method comprises the following steps:
(1) Injecting a temporary plugging agent aqueous solution into the stratum;
(2) Injecting fracturing pre-fluid carrying the capsule blocking remover into the stratum to enable the fracturing pre-fluid to enter the deep part of the stratum;
(3) And (3) injecting acid gel sand-carrying fluid carrying the tectorial membrane propping agent into the stratum to enable the acid gel sand-carrying fluid to enter the stratum, so that deep composite blocking removal is realized.
Further, the temporary plugging agent in the step (1) is a water-soluble gel temporary plugging agent, wherein:
the adaptation temperature range of the water-soluble gel temporary plugging agent is 60-100 ℃, the dissolution time is more than 4 hours, the use concentration is 5-10 wt%, and the bearing pressure of the sand-filled rock core is more than 30MPa.
Furthermore, the water-soluble gel temporary plugging agent is a tetrapolymer of acrylic acid, acrylamide, N-vinyl pyrrolidone and N, N-methylene bisacrylamide.
Further, the capsule blocking remover in the step (2) comprises an organic capsule blocking remover and an inorganic capsule blocking remover, wherein:
the dosage ratio of the organic capsule blocking remover to the inorganic capsule blocking remover is 1:1-20;
the accumulated use concentration of the organic capsule blocking remover and the inorganic capsule blocking remover is 5-30%;
the particle size distribution of the capsule blocking remover in the step (2) is 450-600 mu m.
Further, the acid gel sand-carrying fluid in the step (3) consists of a thickening agent, a pH regulator, a clay stabilizer, a cross-linking agent, a cleanup additive, a gel breaker and water, wherein the mass percentages of the components are as follows: 0.3 to 0.6 percent of thickening agent, 0.5 to 2 percent of pH regulator, 0.15 to 0.3 percent of clay stabilizer, 0.6 to 0.7 percent of cross-linking agent, 0.3 to 0.45 percent of cleanup additive, 0.04 to 0.1 percent of gel breaker and the balance of water, wherein:
the pH value of the acid gel sand-carrying fluid is 1-2.
Still further, the thickener is polyacrylamide or polyacrylamide modified by 2-acrylamide-2-methylpropanesulfonic acid, preferably polyacrylamide modified by 2-acrylamide-2-methylpropanesulfonic acid.
Further, the pH regulator is one of hydrochloric acid, acetic acid, formic acid, earth acid, sulfamic acid and chloroacetic acid, preferably hydrochloric acid.
Still further, the clay stabilizer is a quaternary ammonium salt cationic surfactant or potassium chloride or ammonium chloride, preferably a quaternary ammonium salt cationic surfactant.
Further, the crosslinking agent is an organoboron zirconium composite crosslinking agent, an organoboron crosslinking agent, an organozirconium crosslinking agent, preferably an organoboron zirconium composite crosslinking agent.
Further, the cleanup additive is alkyl glycoside nonionic surfactant, polyoxyethylene ether and fluorine-containing active agent, preferably alkyl glycoside nonionic surfactant.
Still further, the breaker is ammonium persulfate or potassium persulfate, preferably ammonium persulfate.
Further, the coating propping agent is quartz sand or ceramsite coated with an organic coating.
Further, the organic coating is one of an epoxy resin coating, a urea resin coating, a phenolic resin coating, a polyvinylpyrrolidone coating, a polyurethane resin coating, a furan resin coating and an isocyanate resin coating.
Further, the particle size of the coating proppants is 20-40 meshes.
Further, the sand ratio of the film-coated propping agent and the acid gel sand-carrying fluid in the step (3) is 20-30%.
The invention provides a composite blocking removing method, which comprises the following steps:
firstly, injecting temporary plugging agent, temporarily plugging a high-permeability dominant channel, and reducing the filtration loss of the plugging removing agent;
secondly, carrying a capsule blocking remover by fracturing pre-fluid into the deep part of the stratum, accumulating the capsule blocking remover into the deep part of the stratum to form a capsule filter cake, reducing the filtration loss of the blocking remover, and slowly releasing the blocking remover by the capsule to remove the blocking in the deep part of the stratum;
and finally, carrying the tectorial membrane propping agent into the stratum by the acid gel sand-carrying fluid, further eroding inorganic matters around cracks after the acid gel sand-carrying fluid breaks the gel in the deep part of the stratum, and simultaneously, carrying the tectorial membrane propping agent into the stratum by the acid gel sand-carrying fluid, thereby improving the diversion capability of the stratum and further realizing the deep unblocking of the stratum.
The temporary plugging agent reduces the filtration loss of the plugging removing agent through the temporary plugging stratum dominant channel, ensures that cracks are generated in a low-permeability plugging zone in the subsequent fracturing process, and facilitates subsequent further plugging removal; the temporary plugging agent is water-soluble, and the injected temporary plugging agent can be gradually dissolved in the stratum, so that secondary pollution to the stratum is avoided.
The adopted capsule blocking remover is a slow-release capsule blocking remover, after the capsule blocking remover enters a low-permeability blocking zone, a filter cake is formed in the deep part of the stratum, the filtration loss of the blocking remover is reduced, and meanwhile, the slowly released blocking remover gradually dissolves the blocking object, so that the stratum blocking is fully removed.
The pH value of the acid gel sand-carrying fluid system is 1-2, and the acid gel sand-carrying fluid system can further erode inorganic plugs after deep gel breaking of the stratum, so that the stratum plug is removed to the greatest extent; meanwhile, the tectorial membrane propping agent carried by acid gel sand-carrying fluid forms a framework in the loose sandstone stratum, so that the stratum diversion capacity is improved.
The indoor experimental result of the capsule blocking remover and the composite blocking removing method provided by the invention shows that: after the composite blocking removal method is applied, the permeability of the parallel rock core is recovered from 1:14.5 before blocking removal to 1:3.3 after blocking removal, the degree of non-uniformity of the heterogeneous rock core is obviously improved, and the requirement of deep blocking removal of a loose sandstone reservoir can be met.
The beneficial effects are that: the beneficial effects of the invention are mainly as follows:
1. the synergism of a plurality of blocking remover ensures that deep blocking of stratum is removed
The invention adopts a temporary plugging and fracturing process, after temporary plugging, the fracturing and seam making range is enlarged, and the subsequent plugging removing agent has the characteristic of double-support double-plugging removal, and can effectively remove the deep plugging of the stratum. The fracturing pre-fluid carries the capsule blocking remover into the deep part of the stratum to form a weak support of a filter cake, and the blocking remover is slowly released and fully reacts with the blocking object; the acid gel sand-carrying fluid carries the tectorial membrane propping agent into the stratum, and the tectorial membrane propping agent is embedded into the stratum to form strong support, so that the cracks are prevented from being closed again, and surrounding plugs are further eroded.
2. No secondary pollution to stratum
The temporary plugging agent in the composite plugging removing method adopted by the invention is a water-soluble temporary plugging agent, and is gradually dissolved after being injected into the stratum, so that the stratum is not blocked; the plugging removing agent and the acid gel sand-carrying fluid adopted are good in compatibility with formation water, and the products are also dissolved in water, so that no sediment is generated.
3. The blocking remover is efficiently utilized
The temporary plugging agent and the capsule-coated plugging removing agent adopted in the invention have the effects of reducing the filtration loss of the plugging removing agent and improving the utilization rate of the plugging removing agent; besides carrying functions, the fracturing pad fluid and the acid gel sand-carrying fluid can erode plugs around cracks to different degrees, so that an advantage dredging channel is further enlarged, and the plug removal construction effect is improved to the greatest extent.
Drawings
FIG. 1 is a graph showing the time-dependent change of the effective content of the blocking remover for organic capsules in embodiment 4 of the invention.
FIG. 2 is a graph showing the time-dependent change of the effective contents of the components of the inorganic capsule blocking remover in the embodiment 4 of the invention.
FIG. 3 is a graph showing the cumulative release rate of the organic capsule blocking remover according to embodiment 4 of the present invention.
FIG. 4 is a graph showing the cumulative release rate of each component of the inorganic capsule blocking remover according to embodiment 4 of the present invention over time.
Fig. 5 is a schematic diagram of the result of the temperature-resistant and shear-resistant experiment of the acid gel sand-carrying fluid in embodiment 8 of the invention.
The specific embodiment is as follows:
the following detailed description of specific embodiments of the invention.
The concentrations in this application refer to mass concentrations unless otherwise specified.
In this application: the acid gel sand-carrying fluid has the advantages of temperature resistance, shearing resistance and adaptation to the temperature of 65 ℃ for 170s -1 The apparent viscosity at shear rate is greater than 70mpa.s.
The acid gel sand-carrying fluid has the gel breaking time of 2-4 h, the apparent viscosity after gel breaking is less than or equal to 5 Pa.s, and the corrosion rate of the gel breaking fluid to the stratum is 5-10%.
Example 1:
the experiment tests the change of the dissolution time of the water-soluble gel temporary plugging agent along with the experiment temperature.
The water-soluble gel temporary plugging agent is a tetrapolymer of acrylic acid, acrylamide, N-vinyl pyrrolidone and N, N-methylene bisacrylamide.
The experimental method is as follows: at different temperatures, simulated formation water is used for preparing aqueous solution of temporary plugging agent with concentration of 5wt%, the dissolution time is measured respectively, and the experimental results are shown in table 1.
TABLE 1 solubility of Water-soluble gel-based temporary blocking Agents
As can be seen from table 1, as the temperature increases, the dissolution time of the temporary plugging agent becomes shorter.
Example 2:
the experiment tests the bearing capacity of the water-soluble gel temporary plugging agent in the embodiment 1 at 60 DEG C
The experimental method is as follows: the size phi of the core is 2.5 multiplied by 10cm, and the core is filled;
the whole experimental temperature of the experiment is 60 ℃; firstly, 0.9% sodium chloride solution is injected at the speed of 0.34ml/min, and the original permeability of the test core is 923.6mD;
injecting 5% water-soluble gel temporary plugging agent 1PV into the core at the speed of 10ml/min, and cleaning the inlet end of the core;
injecting 0.9% sodium chloride solution, testing the breakthrough pressure of the core in a constant pressure mode, and measuring the breakthrough pressure of the core after temporary plugging to be 32.2MPa;
0.9% sodium chloride solution was injected at a rate of 0.34ml/min and the core permeability after temporary plugging was tested to be 62.3mD.
From experimental results, the effective permeability of the core after temporary plugging is reduced by 93.3%, and the pressure-bearing strength of the water-soluble gel temporary plugging agent is more than 30MPa.
Example 3:
the experiment optimizes the content of each component of the capsule coat
The capsule coating is made of Ethyl Cellulose (EC), polyvinylpyrrolidone and gelatin, three factors including capsule coating thickness, capsule core release time and effective capsule core content are comprehensively considered, the mass percentages of all components in the preparation of the capsule coating are optimized by adopting an orthogonal method in the experiment, and the experimental results are shown in Table 2.
TABLE 2 results of orthogonal experiments for optimization of the various components of the capsule
The capsule coating effective content is used as an examination index in the capsule coating component optimization experiment, the influence size of the components in the orthogonal experiment is ordered as EC content > gelatin content > polyvinylpyrrolidone content, and the capsule coating of the capsule blocking remover is prepared by the mass percentage of the preferable composition parameters: ethyl Cellulose (EC) 74%, polyvinylpyrrolidone 4% and gelatin 22%.
Example 4
The experiment tests the dissolution effective content and the effective release rate of the organic/inorganic capsule blocking remover in the capsule blocking remover (the organic blocking remover in the capsule core is sodium percarbonate).
The organic blocking remover capsule core of the experiment is sodium percarbonate, and the inorganic blocking remover capsule core comprises the following components in percentage by mass: 60% of sulfamic acid and 40% of solid hydrofluoric acid.
After 5.0g of the organic/inorganic capsule blocking remover was crushed (the amount of the organic/inorganic blocking remover coated in the capsule, i.e., the effective content of the capsule-coated blocking remover was tested) at 65 ℃ respectively, the organic/inorganic capsule blocking remover was placed in 1000mL of deionized water, the change of the dissolution amount of the organic/inorganic capsule blocking remover with time in the aqueous solution was tested, the maximum dissolution amount of the organic capsule blocking remover was 1.96g, the effective content was 39.2%, and the change result of the effective content with stirring time was shown in fig. 1.
The maximum dissolution amount of each component of the inorganic blocking remover is 1.93g of sulfamic acid, 0.45g of solid hydrofluoric acid, the effective content of the inorganic blocking remover is 38.6% of sulfamic acid, the effective content of hydrofluoric acid is 9% of sulfamic acid, the total effective content of the inorganic blocking remover in the inorganic capsule blocking remover is 47.6%, and the change result of the effective content of the inorganic blocking remover along with the stirring time is shown in figure 2.
5.0g of organic/inorganic capsule blocking remover is respectively placed in 1000mL of deionized water (the capsule blocking remover is naturally and slowly released in an aqueous solution), the concentration of the blocking remover in the solution is measured every 30min, the accumulated release rate of the blocking remover is detected, the accumulated release rate of the organic capsule blocking remover is 79%, and the change result of the accumulated release rate of the organic capsule blocking remover along with the stirring time is shown in figure 3. The cumulative release rate of each component of the inorganic capsule blocking remover is 69% of sulfamic acid and 65% of hydrofluoric acid respectively, and the result of the change of the cumulative release rate of the inorganic capsule blocking remover along with the stirring time is shown in figure 4.
Example 5
After the components of the capsule core of the organic capsule blocking remover are changed into calcium peroxide and sodium hypochlorite, the effective content and the accumulated release rate of the organic capsule blocking remover are tested.
The organic blocking remover in the capsule core of the experimental capsule comprises the following components in percentage by mass: 50% of calcium peroxide and 50% of sodium hypochlorite. Measured at 65℃according to the procedure of example 4: the effective content of the organic blocking remover is 55%, wherein the effective content of calcium peroxide is 25.3% and the effective content of sodium hypochlorite is 29.7%; the accumulated release rate of each component of the organic blocking remover is 65% of calcium peroxide and 71% of sodium hypochlorite respectively.
Example 6
The experiment tests the degradation speed of the blocking remover coated and uncoated by the capsule on pollutants.
Using the blocking remover of example 4, placing the encapsulated and unwrapped blocking removers (the amount of the encapsulated blocking remover released by the blocking remover is consistent with that of the unwrapped blocking remover, the capsule blocking remover released amount=the capsule mass×the effective content×the cumulative release rate) into a solution containing 5% of pollutants prepared by using simulated formation water at 65 ℃; the ratio of the organic blocking remover to the inorganic blocking remover is 1:10 (the ratio of the organic blocking remover to the inorganic blocking remover is different for the blocking matters with different components), and when the total concentration of the capsule blocking remover is 20%, the rate of degrading pollutants of the encapsulated capsule and the non-encapsulated capsule blocking remover is compared as shown in Table 3.
Experimental results show that the final degradation rate of pollutants is basically the same as that of whether the blocking remover is wrapped or not, but the degradation time difference is larger, and the blocking remover capsule is adopted to delay degradation for 150 minutes compared with the non-wrapped capsule, so that the field construction requirement can be met.
Table 3 comparison of contaminant degradation rates for blocking remover for encapsulated and uncoated capsules
| Degradation time/min | Unwrapped capsule degradation contaminant rate/% | Rate of degradation of contaminants by the encapsulated capsule/% |
| 30 | 56.3 | 24.5 |
| 60 | 70.9 | 32.6 |
| 90 | 81.3 | 42.8 |
| 120 | 81.3 | 54.7 |
| 150 | / | 67.9 |
| 180 | / | 74.8 |
| 210 | / | 77.9 |
| 240 | / | 81.2 |
| 270 | / | 81.2 |
Example 7
The experiment tests the influence of the use concentration of the capsule blocking remover on the degradation rate of pollutants.
The capsule blocking remover (example 4) is adopted, the capsule blocking remover is placed in a solution containing 5 percent of pollutants prepared by simulated stratum water, and when the using amount ratio of the organic capsule blocking remover to the inorganic capsule blocking remover is 1:10, the degradation rate of the capsule blocking remover with the concentration of 15 percent to the pollutants is 80.1 percent; the degradation rate of the capsule blocking remover with the concentration of 30% on pollutants is 87.2%;
example 8
The experiment tests the change of the viscosity of the acid gel sand-carrying fluid solution along with the shearing time.
The experimental acid gel sand-carrying fluid comprises the following components in percentage by mass: 0.4% of thickener, 0.5% of pH regulator, 0.2% of clay stabilizer, 0.6% of cross-linking agent, 0.4% of cleanup additive, 0.04% of gel breaker and the balance of water; acid gel sand-carrying liquid pH is2; at 65 ℃, the acid gel sand-carrying fluid passes through 170s -1 After shearing, the solution viscosity was varied with shearing time as shown in FIG. 5. The apparent viscosity of the acid gel sand-carrying fluid after gel breaking is 3.21mPa.s.
Example 9
The experiment tests the influence of the dosage of the pH regulator on the solution viscosity in acid gel sand-carrying fluid.
The experimental acid gel sand-carrying fluid comprises the following components in percentage by mass: 0.4% of thickener, 2% of pH regulator, 0.2% of clay stabilizer, 0.6% of cross-linking agent, 0.4% of cleanup additive, 0.04% of gel breaker and the balance of water; the pH value of the acid gel sand-carrying fluid is 1, and the acid gel sand-carrying fluid passes through 170s at 65 DEG C -1 After shearing, the solution viscosity is 90mPa.s, and the apparent viscosity after breaking the acid gel sand-carrying fluid is 3.12mPa.s.
Example 10
The experiment tests the influence of the content of the pH regulator and the breaker on the solution viscosity by changing the pH regulator in acid gel sand-carrying fluid.
In the experiment, the acid gel sand-carrying fluid comprises the following components in percentage by mass: 0.4% of thickener, 1% of pH regulator, 0.2% of clay stabilizer, 0.6% of cross-linking agent, 0.4% of cleanup additive, 0.1% of gel breaker and the balance of water; the pH value of the acid gel sand-carrying fluid is 1, and the acid gel sand-carrying fluid passes through 170s at 65 DEG C -1 After shearing, the solution viscosity is 120mPa.s, and the apparent viscosity of the acid gel sand-carrying fluid after gel breaking is 1.07mPa.s.
Example 11
The test is carried out to test the corrosion resistance of the acid gel carrying sand breaking liquid to the polluted core.
The experimental method for corrosion of the acid gel carried sand-breaking gel solution to the polluted rock core comprises the following steps: the size of the core phi is 2.5 multiplied by 30cm, and the core is filled first; at room temperature, injecting simulated formation water at a speed of 0.34ml/min, and measuring the original permeability of the rock core to be 726mD; injecting simulated formation water into the core to prepare a 0.3% pollutant solution 5PV; placing the core at 65 ℃ for closed curing for 24 hours; water is driven to be stable in pressure at the speed of 0.34ml/min, and the core permeability after pollution is measured to be 63.2mD; injecting acid gel sand-carrying gel breaking solution (example 9) with concentration of 2.7% at 65 ℃ at a speed of 30ml/min, and aging for 12 hours at both ends of a closed core; water flooding was continued at a rate of 0.34ml/min to a plateau pressure, and core permeability after erosion was measured to be 135.6mD.
From the experimental results, it can be seen that: under the strong acid condition, after the acid gel is injected at high speed to carry sand and break glue solution, the core permeability is recovered from 63.2mD to 135.6mD, the core effective permeability is recovered from 8.7% after pollution to 18.7%, and the corrosion rate is 10%.
Example 12
The experimental tectorial membrane propping agent consists of quartz sand and phenolic resin. The particle size of the coating propping agent is 20 meshes; the acid dissolution rate is 4.5% under the condition that the ratio of hydrochloric acid to solid hydrofluoric acid is 4:1; the crushing rate under 35MPa is 2.78%.
Example 13
The experimental tectorial membrane propping agent consists of quartz sand and urea-formaldehyde resin; the particle size of the coating propping agent is 40 meshes; the acid dissolution rate is 4.2% under the condition that the ratio of hydrochloric acid to solid hydrofluoric acid is 4:1; the crushing rate under 35MPa is 3.1%.
Example 14
The experimental tectorial membrane propping agent consists of quartz sand and epoxy resin; the particle size of the coating propping agent is 30 meshes; the acid dissolution rate is 4.35% under the condition that the ratio of hydrochloric acid to solid hydrofluoric acid is 4:1; the crushing rate under 35MPa is 4.67%.
Example 15
The experimental tectorial membrane propping agent consists of ceramsite and polyvinylpyrrolidone; the particle size of the coating propping agent is 30 meshes; the acid dissolution rate is 4.45% under the condition that the ratio of hydrochloric acid to solid hydrofluoric acid is 4:1; the crushing rate under 35MPa is 4.9%.
Example 16
The test tests the plugging capability of the temporary plugging agent on the parallel heterogeneous sand-filled core and optimizes the injection speed of the temporary plugging agent.
The experimental method for the injection speed of the temporary plugging agent is as follows: the core size phi 2.5 multiplied by 30cm is firstly filled with 3 groups of high-permeability and low-permeability cores with similar extremely poor core permeability respectively; at room temperature, saturated simulated formation water at a rate of 0.34ml/min was tested for porosity and water phase permeability, respectively; respectively connecting 3 groups of cores in parallel, and measuring the water flooding injection balance pressure and the shunt volume before temporary plugging of the cores in parallel; at 65 ℃, the injection concentration of 5% temporary plugging agent solution is respectively injected at the speed of 3ml/min, 6ml/min and 10ml/min (respectively corresponding to 1/10, 1/5 and 1/3 of the injection speed of the acid gel sand-carrying gel breaking liquid) to be 0.3PV, and the injection pressure is measured; and cleaning the inlet end of the core, injecting stratum simulation water at the speed of 0.34ml/min, and respectively measuring the breakthrough pressure, the water flooding balance pressure and the shunt volume after the temporary plugging agent is injected. The experimental results of the temporary plugging agent on the double-pipe parallel sand-filled core are shown in table 4. From the experimental results, it can be seen that: the lower the injection speed of the temporary plugging agent is, the smaller the pollution to the hypotonic core is, the higher the plugging and the lower the plugging are, but in the field construction process, the injection speed is too low, the construction period is long, and under the low Reynolds number, the temporary plugging agent is easy to precipitate in the pipe column to plug the pipe column, so the indoor injection speed of the temporary plugging agent is 6ml/min.
Table 4 temporary plugging agent to double-pipe parallel sand-filling core plugging test results
Example 17
The composite blocking removal capability test is carried out on the single-tube sand-filled polluted core by the experimental result, and the end-face effect of the capsule particles and the coated propping agent in the indoor core test is considered, so that the single-tube core is relatively homogeneous, and the blocking removal experiment only examines the synergistic blocking removal effect of the blocking removal agent (not coated with the capsule) solution and the acid gel sand-carrying fluid.
The single-tube sand-filled core composite blocking removal experimental method comprises the following steps: the size phi of the core is 2.5 multiplied by 30cm, and the core is filled; at room temperature, saturated simulated formation water is used at the speed of 0.34ml/min, and the porosity and the permeability of the simulated formation water are respectively measured; injecting simulated formation water at a rate of 0.34ml/min to prepare a 0.3% contaminant solution 5PV; placing the core at 65 ℃ for closed curing for 24 hours; at room temperature, injecting simulated formation water at a speed of 0.34ml/min until the pressure is stable, wherein the core permeability after pollution is 66.3mD; accumulating injection concentration of 5% of blocking remover solution (implementation 4) at 65 ℃ at a speed of 3mL/min to obtain 1PV, wherein the injection sequence is 0.5PV of organic blocking remover, 10mL of clear water and 0.5PV of inorganic blocking remover; injecting acid gel sand-carrying fluid (9) with concentration of 2.7% at 30ml/min to 1PV, and sealing and curing the two ends of the core for 12h; at room temperature, the water is driven to injection pressure at a speed of 0.34ml/min, the permeability of the core after blocking removal is 206.1mD, and the composite blocking removal experimental result of the single-tube core is shown in Table 5.
From the experimental results, under the synergistic effect of the blocking remover and acid gel sand-carrying fluid, the core permeability is recovered from 66.3mD before blocking removal to 206.1mD after blocking removal.
Table 5 single tube sand-filled core composite blocking removal experimental result
| Core size/cm | Φ2.5×30 |
| Porosity/% | 32.5 |
| Original core water phase permeability/mD | 756.3 |
| Water flooding equilibrium pressure/MPa after pollution | 0.0522 |
| Core water phase permeability/mD after pollution | 66.3 |
| Injection of organic unblocking doses (PV) | 0.5 |
| Injection spacer fluid volume/mL | 10 |
| Injection of inorganic unblocking dose (PV) | 0.5 |
| Injecting acid gel sand-carrying fluid (PV) | 1 |
| Water drive balance pressure/MPa after unblocking | 0.0168 |
| Core water phase permeability/mD after unblocking | 206.1 |
Example 18
The experiment uses the experimental result to carry out the composite blocking removal experiment after the parallel sand filling pipe core simulates the stratum pollution, and considers that the capsule particles and the tectorial membrane propping agent have end-face effects in the indoor core experiment, so the blocking removal experiment only considers temporary blocking, oxidative degradation and acidification, the oxidative degradation adopts an organic blocking remover solution, and the acidification adopts an inorganic blocking remover solution and acid gel sand-carrying fluid.
The double-pipe parallel sand-filling core composite blocking removal experimental method comprises the following steps: the core size phi 2.5 multiplied by 30cm is firstly filled with 2 cores with similar permeability respectively; at room temperature, the simulated formation water was saturated at a rate of 0.34ml/min, and tested for porosity and permeability, respectively, for 714.2mD (1#) and 734.6mD (2#); injecting simulated formation water into the No. 1 rock core to prepare a 0.3% pollutant solution 5PV, and sealing and curing for 24 hours at 65 ℃; at room temperature, simulated formation water is injected at a speed of 0.34ml/min until the pressure is stable, and the permeability of the 1# rock core after pollution testing is 50.7mD. Parallelly connecting the 1# core and the 2# core, and measuring the water flooding injection balance pressure and the shunt volume before the parallel core deblocking; injecting 5% temporary plugging agent solution at a speed of 6ml/min and a concentration of 0.3PV at 65 ℃, cleaning the inlet end of the rock core, injecting stratum simulation water at a speed of 0.34ml/min, measuring the breakthrough pressure of 5.481MPa after the temporary plugging agent is injected, and measuring the water flooding balance pressure of 1.623MPa; the blocking remover (embodiment 4) with the concentration of 5% is injected at the speed of 3mL/min for 0.5PV, and the injection sequence is as follows: 0.25PV of organic blocking remover solution, 10mL of clear water, and 0.25PV of inorganic blocking remover solution; injecting acid gel sand-carrying fluid with concentration of 2.7% at a speed of 30mL/min to 0.5PV (implementation 9), and aging for 12h at both ends of the closed core; at room temperature, simulated formation water is injected at the speed of 0.34ml/min until the injection pressure is stable, and the water flooding injection balance pressure, the shunt quantity of the parallel cores and the permeability of the cores 1# and 2# after deblocking are measured, wherein the composite deblocking experimental result of the double-pipe parallel sand-filled core is shown in Table 6. From the experimental results, it can be seen that: after the double-pipe parallel sand-filling core is subjected to composite unblocking, the permeability of the low-permeability core is recovered from 50.7mD after being polluted to 216.3mD; the permeability of the core in parallel connection is recovered from 1:14.5 before the blockage removal to 1:3.3 after the blockage removal; and the shunt flow is recovered from 1:38.6 before deblocking to 1:1.3 after deblocking by stopping the outlet end of the parallel rock cores to the end of the experiment, and the heterogeneous degree of the parallel rock cores is obviously improved.
Table 6 double-tube parallel sand-filling core composite blocking removal experimental result
In the core experiment, the end face effect of the capsule particles and the tectorial membrane propping agent in the core is considered, so that solutions are adopted in the injection in the core experiment process, and the capsule wrapping blocking remover and tectorial membrane propping agent are not considered.
The core experiment is carried out to prepare the blocking remover solution, and the organic blocking remover and the inorganic blocking remover are mixed and injected to cause severe reaction, so that a biliquid method is used, and clear water is used as a spacer fluid in the middle. When the organic blocking remover and the inorganic blocking remover are injected on site, the organic blocking remover and the inorganic blocking remover are wrapped by the capsules, and the organic blocking remover and the inorganic blocking remover are slowly released in the injection process, so that severe reaction can be avoided, and the use proportion of the organic/inorganic capsule blocking remover is determined according to the components of the on-site blocking object during blocking removal construction.
The simulated formation water ion content adopted in the experiment is shown in Table 7, and the content of each component of the flowback pollutant is shown in Table 8;
table 7 simulated formation water ion content
TABLE 8 Return blow-down dye composition content
The composite blocking removal method has no end face effect of the indoor core, and the capsule-coated blocking removal agent and the coated propping agent are added on the basis of the test, so that the deep blocking of the near-wellbore zone of the loose sandstone reservoir can be effectively removed.
Example 19
The components of the capsule blocking remover are changed
The capsule blocking remover consists of a capsule core and a capsule coating wrapping the capsule core, wherein the capsule blocking remover is divided into two types of organic capsule blocking remover and inorganic capsule blocking remover, wherein:
the capsule core of the organic capsule blocking remover is an organic blocking remover capable of removing the blocking of organic matters;
the capsule core of the inorganic capsule blocking remover is an inorganic blocking remover capable of removing inorganic blocking.
Further, the organic blocking remover is a solid oxidizer.
Further, the organic blocking remover is calcium peroxide.
Further, the inorganic blocking remover consists of a first component and a second component, wherein the first component accounts for 50wt% and the second component accounts for 50wt%;
the first component is sulfamic acid;
the second component is solid hydrofluoric acid.
Further, the capsule coat is composed of ethylcellulose, polyvinylpyrrolidone and gelatin, wherein: the mass ratio of the ethyl cellulose to the polyvinylpyrrolidone to the gelatin is 65:5:30.
example 20
Component change II of capsule blocking remover
The capsule blocking remover consists of a capsule core and a capsule coating wrapping the capsule core, wherein the capsule blocking remover is divided into two types of organic capsule blocking remover and inorganic capsule blocking remover, wherein:
the capsule core of the organic capsule blocking remover is an organic blocking remover capable of removing the blocking of organic matters;
the capsule core of the inorganic capsule blocking remover is an inorganic blocking remover capable of removing inorganic blocking.
Further, the organic blocking remover is a solid oxidizer.
Further, the organic blocking remover is sodium hypochlorite.
Further, the inorganic blocking remover consists of a first component and a second component, wherein the first component accounts for 70wt% and the second component accounts for 30wt%;
the first component is chloroacetic acid;
the second component is ammonium bifluoride.
Further, the capsule coat is composed of ethylcellulose, polyvinylpyrrolidone and gelatin, wherein: the mass ratio of the ethyl cellulose to the polyvinylpyrrolidone to the gelatin is 85:5:10.
example 21
All the components of the capsule blocking remover change three
The capsule blocking remover consists of a capsule core and a capsule coating wrapping the capsule core, wherein the capsule blocking remover is divided into two types of organic capsule blocking remover and inorganic capsule blocking remover, wherein:
the capsule core of the organic capsule blocking remover is an organic blocking remover capable of removing the blocking of organic matters;
the capsule core of the inorganic capsule blocking remover is an inorganic blocking remover capable of removing inorganic blocking.
Further, the organic blocking remover is a solid oxidizer.
Further, the organic blocking remover is a mixture of calcium peroxide, sodium hypochlorite and sodium percarbonate in equal mass ratio.
Further, the inorganic blocking remover consists of a first component and a second component, wherein the first component accounts for 60wt% and the second component accounts for 40wt%;
the first component is solid nitric acid powder;
the second component is ammonium bifluoride.
Further, the capsule coat is composed of ethylcellulose, polyvinylpyrrolidone and gelatin, wherein: the mass ratio of the ethyl cellulose to the polyvinylpyrrolidone to the gelatin is 80:8:12.
example 22
Substantially the same as in example 21, except that the organic blocking remover was different:
in this embodiment, the organic blocking remover is sodium percarbonate.
Example 23
The proportion of each component of the unblocking system in the composite unblocking method is changed firstly
A composite unblocking method comprises the following steps:
(1) Injecting a temporary plugging agent aqueous solution into the stratum;
(2) Injecting fracturing pre-fluid carrying the capsule blocking remover into the stratum to enable the fracturing pre-fluid to enter the deep part of the stratum;
(3) And (3) injecting acid gel sand-carrying fluid carrying the tectorial membrane propping agent into the stratum to enable the acid gel sand-carrying fluid to enter the stratum, so that deep composite blocking removal is realized.
Further, the temporary plugging agent in the step (1) is a water-soluble gel temporary plugging agent, wherein:
the adaptation temperature range of the water-soluble gel temporary plugging agent is 60-100 ℃, the dissolution time is more than 4 hours, the use concentration is 5-10 wt%, and the bearing pressure of the sand-filled rock core is more than 30MPa.
Furthermore, the water-soluble gel temporary plugging agent is a tetrapolymer of acrylic acid, acrylamide, N-vinyl pyrrolidone and N, N-methylene bisacrylamide.
Further, the particle size of the capsule blocking remover in the step (2) is 450 μm. The total effective content of each component of the capsule blocking remover is 39-55%; the accumulated release rate of each component is 65-79%; the delay release time is 2-5 h.
Further, the capsule blocking remover in the step (2) comprises an organic capsule blocking remover and an inorganic capsule blocking remover, wherein:
the dosage ratio of the organic capsule blocking remover to the inorganic capsule blocking remover is 1:1;
the accumulated use concentration of the organic capsule blocking remover and the inorganic capsule blocking remover is 5 percent.
Further, the acid gel sand-carrying fluid in the step (3) consists of a thickening agent, a pH regulator, a clay stabilizer, a cross-linking agent, a cleanup additive, a gel breaker and water, wherein the mass percentages of the components are as follows: 0.3% of thickener, 1% of pH regulator, 0.15% of clay stabilizer, 0.6% of cross-linking agent, 0.3% of cleanup additive, 0.04% of gel breaker and the balance of water, wherein:
the pH value of the acid gel sand-carrying fluid is 1.
Further, the thickener is polyacrylamide.
Further, the pH regulator is hydrochloric acid.
Further, the clay stabilizer is a quaternary ammonium salt cationic surfactant.
Further, the cross-linking agent is an organoboron zirconium composite cross-linking agent.
Further, the cleanup additive is an alkyl glycoside nonionic surfactant.
Further, the breaker is ammonium persulfate.
Further, the coating propping agent is quartz sand coated with an organic coating.
Still further, the organic coating is an epoxy coating.
Further, the particle size of the film-coated propping agent is 20 meshes. The acid dissolution rate of the coated propping agent is less than 5%, and the crushing rate under 35MPa is less than 5%.
Further, the sand ratio of the film-coated propping agent and the acid gel sand-carrying fluid in the step (3) is 20%.
Example 24
Component proportion change II of blocking removal system in composite blocking removal method
A composite unblocking method comprises the following steps:
(1) Injecting a temporary plugging agent aqueous solution into the stratum;
(2) Injecting fracturing pre-fluid carrying the capsule blocking remover into the stratum to enable the fracturing pre-fluid to enter the deep part of the stratum;
(3) And (3) injecting acid gel sand-carrying fluid carrying the tectorial membrane propping agent into the stratum to enable the acid gel sand-carrying fluid to enter the stratum, so that deep composite blocking removal is realized.
Further, the temporary plugging agent in the step (1) is a water-soluble gel temporary plugging agent, wherein:
the adaptation temperature range of the water-soluble gel temporary plugging agent is 60-100 ℃, the dissolution time is more than 4 hours, the use concentration is 5-10 wt%, and the bearing pressure of the sand-filled rock core is more than 30MPa.
Furthermore, the water-soluble gel temporary plugging agent is a tetrapolymer of acrylic acid, acrylamide, N-vinyl pyrrolidone and N, N-methylene bisacrylamide.
Further, the particle size of the capsule blocking remover in the step (2) is 600 μm. The total effective content of each component of the capsule blocking remover is 39-55%; the accumulated release rate of each component is 65-79%; the delay release time is 2-5 h.
Further, the capsule blocking remover in the step (2) comprises an organic capsule blocking remover and an inorganic capsule blocking remover, wherein:
the dosage ratio of the organic capsule blocking remover to the inorganic capsule blocking remover is 1:20;
the accumulated use concentration of the organic capsule blocking remover and the inorganic capsule blocking remover is 30 percent.
Further, the acid gel sand-carrying fluid in the step (3) consists of a thickening agent, a pH regulator, a clay stabilizer, a cross-linking agent, a cleanup additive, a gel breaker and water, wherein the mass percentages of the components are as follows: 0.6% of thickener, 1.5% of pH regulator, 0.3% of clay stabilizer, 0.7% of cross-linking agent, 0.45% of cleanup additive, 0.1% of gel breaker and the balance of water, wherein:
the pH value of the acid gel sand-carrying fluid is 2.
Further, the thickener is 2-acrylamide-2-methylpropanesulfonic acid modified polyacrylamide.
Still further, the pH adjuster is acetic acid.
Further, the clay stabilizer is potassium chloride.
Further, the crosslinking agent is an organoboron crosslinking agent.
Further, the cleanup additive is polyoxyethylene ether.
Still further, the breaker is potassium persulfate.
Further, the coating propping agent is ceramsite coated with an organic coating.
Further, the organic coating is a urea-formaldehyde resin coating.
Further, the particle size of the film-coated propping agent is 40 mesh. The acid dissolution rate of the coated propping agent is less than 5%, and the crushing rate under 35MPa is less than 5%.
Further, the sand ratio of the film-coated propping agent and the acid gel sand-carrying fluid in the step (3) is 30%.
Example 25
Three component proportion changes of the unblocking system in the composite unblocking method
A composite unblocking method comprises the following steps:
(1) Injecting a temporary plugging agent aqueous solution into the stratum;
(2) Injecting fracturing pre-fluid carrying the capsule blocking remover into the stratum to enable the fracturing pre-fluid to enter the deep part of the stratum;
(3) And (3) injecting acid gel sand-carrying fluid carrying the tectorial membrane propping agent into the stratum to enable the acid gel sand-carrying fluid to enter the stratum, so that deep composite blocking removal is realized.
Further, the temporary plugging agent in the step (1) is a water-soluble gel temporary plugging agent, wherein:
the adaptation temperature range of the water-soluble gel temporary plugging agent is 60-100 ℃, the dissolution time is more than 4 hours, the use concentration is 5-10 wt%, and the bearing pressure of the sand-filled rock core is more than 30MPa.
Further, the temporary plugging agent is a tetrapolymer of acrylic acid, acrylamide, N-vinyl pyrrolidone and N, N-methylene bisacrylamide.
Further, the particle size of the capsule blocking remover in the step (2) is 500 μm. The total effective content of each component of the capsule blocking remover is 39-55%; the accumulated release rate of each component is 65-79%; the delay release time is 2-5 h.
Further, the capsule blocking remover in the step (2) comprises an organic capsule blocking remover and an inorganic capsule blocking remover, wherein:
the dosage ratio of the organic capsule blocking remover to the inorganic capsule blocking remover is 1:10;
the accumulated use concentration of the organic capsule blocking remover and the inorganic capsule blocking remover is 25 percent.
Further, the acid gel sand-carrying fluid in the step (3) consists of a thickening agent, a pH regulator, a clay stabilizer, a cross-linking agent, a cleanup additive, a gel breaker and water, wherein the mass percentages of the components are as follows: 0.4% of thickener, 2% of pH regulator, 0.2% of clay stabilizer, 0.65% of cross-linking agent, 0.4% of cleanup additive, 0.08% of gel breaker and the balance of water, wherein:
the pH value of the acid gel sand-carrying fluid is 2.
Further, the thickener is 2-acrylamide-2-methylpropanesulfonic acid modified polyacrylamide.
Further, the pH regulator is formic acid.
Further, the clay stabilizer is ammonium chloride.
Further, the crosslinking agent is an organozirconium crosslinking agent.
Further, the cleanup additive is a fluorine-containing active agent.
Further, the breaker is ammonium persulfate.
Further, the coating propping agent is quartz sand coated with an organic coating.
Still further, the organic coating is a phenolic resin coating.
Further, the particle size of the film-coated propping agent is 30 meshes. The acid dissolution rate of the film-coated propping agent is less than 5%, and the breaking rate under 35MPa is less than 5%.
Further, the sand ratio of the film-coated propping agent and the acid gel sand-carrying fluid in the step (3) is 25%.
Examples 26 to 28
Substantially the same as in example 25, except that the pH adjustor was changed:
| PH regulator | |
| Example 26 | Tu acid |
| Example 27 | Sulfamic acid |
| Example 28 | Chloroacetic acid |
Examples 29 to 32
Substantially the same as in example 25, except that the organic coating layer was different:
| organic coating | |
| Example 29 | Polyurethane resin coating |
| Example 30 | Furan resin coating |
| Example 31 | Isocyanic acid resin coating |
| Example 32 | Polyvinylpyrrolidone coating |
The embodiments of the present invention have been described in detail. However, the present invention is not limited to the above-described embodiments, and various modifications may be made within the knowledge of those skilled in the art without departing from the spirit of the present invention.
Claims (20)
1. The composite unblocking method is characterized by comprising the following steps of:
(1) Injecting a temporary plugging agent aqueous solution into the stratum;
(2) Injecting fracturing pre-fluid carrying a capsule blocking remover into the stratum to enable the fracturing pre-fluid to enter the deep part of the stratum;
(3) Injecting acid gel sand-carrying fluid carrying a tectorial membrane propping agent into a stratum to enable the acid gel sand-carrying fluid to enter the stratum, thereby realizing deep composite blocking removal, wherein:
the temporary plugging agent in the step (1) is a water-soluble gel temporary plugging agent, wherein:
the adaptation temperature range of the water-soluble gel temporary plugging agent is 60-100 ℃, the dissolution time is more than 4 hours, the use concentration is 5-10 wt%, and the bearing pressure of the sand-filled rock core is more than 30MPa;
the water-soluble gel temporary plugging agent is a tetrapolymer of acrylic acid, acrylamide, N-vinyl pyrrolidone and N, N-methylene bisacrylamide;
the capsule blocking remover in the step (2) consists of a capsule core and a capsule coating wrapping the capsule core, wherein the capsule blocking remover comprises an organic capsule blocking remover and an inorganic capsule blocking remover, and the method comprises the following steps:
the capsule core of the organic capsule blocking remover is an organic blocking remover capable of removing the blocking of organic matters;
the capsule core of the inorganic capsule blocking remover is an inorganic blocking remover capable of removing inorganic blocking;
the dosage ratio of the organic capsule blocking remover to the inorganic capsule blocking remover is 1:1-20;
the accumulated use concentration of the organic capsule blocking remover and the inorganic capsule blocking remover is 5-30%;
the particle size distribution of the capsule blocking remover in the step (2) is 450-600 mu m;
the organic blocking remover is one or more of calcium peroxide, sodium hypochlorite and sodium percarbonate;
the inorganic blocking remover consists of a first component and a second component, wherein the first component accounts for 50-70wt% and the second component accounts for 30-50wt%;
the first component is one of sulfamic acid, chloroacetic acid and solid nitric acid powder;
the second component is one of solid hydrofluoric acid and ammonium bifluoride.
2. The composite blocking removing method as set forth in claim 1, wherein the acid gel sand-carrying fluid in the step (3) is composed of a thickener, a pH regulator, a clay stabilizer, a cross-linking agent, a cleanup additive, a gel breaker and water, and the weight percentages of the components are as follows: 0.3 to 0.6 percent of thickening agent, 0.5 to 2 percent of pH regulator, 0.15 to 0.3 percent of clay stabilizer, 0.6 to 0.7 percent of cross-linking agent, 0.3 to 0.45 percent of cleanup additive, 0.04 to 0.1 percent of gel breaker and the balance of water, wherein:
the pH value of the acid gel sand-carrying fluid is 1-2.
3. The composite unblocking method according to claim 2, wherein the thickener is polyacrylamide or 2-acrylamide-2-methylpropanesulfonic acid modified polyacrylamide.
4. A composite unblocking method according to claim 3, wherein the thickener is 2-acrylamide-2-methylpropanesulfonic acid modified polyacrylamide.
5. The method of claim 2, wherein the pH adjuster is one of hydrochloric acid, acetic acid, formic acid, earth acid, sulfamic acid, and chloroacetic acid.
6. The method of claim 5, wherein the pH adjuster is hydrochloric acid.
7. The composite unblocking method according to claim 2, wherein the clay stabilizer is a quaternary ammonium salt cationic surfactant or potassium chloride or ammonium chloride.
8. The composite unblocking method of claim 7, wherein the clay stabilizer is a quaternary ammonium salt cationic surfactant.
9. The composite unblocking method of claim 2, wherein the crosslinking agent is an organoboron zirconium composite crosslinking agent, an organoboron crosslinking agent, or an organozirconium crosslinking agent.
10. The composite unblocking method of claim 9, wherein the cross-linking agent is an organoboron zirconium composite cross-linking agent.
11. The composite unblocking method according to claim 2, wherein the cleanup additive is an alkyl glycoside nonionic surfactant, a polyoxyethylene ether and a fluorine-containing active agent.
12. The composite unblocking method of claim 11, wherein the cleanup additive is an alkyl glycoside nonionic surfactant.
13. The method of claim 2, wherein the breaker is ammonium persulfate or potassium persulfate.
14. The method of claim 13, wherein the breaker is ammonium persulfate.
15. The composite unblocking method of claim 1, wherein the coating proppant is an organic coated quartz sand or ceramic particle.
16. The composite unblocking method of claim 15, wherein the organic coating is one of an epoxy coating, a urea-formaldehyde resin coating, a phenolic resin coating, a polyvinylpyrrolidone coating, a polyurethane resin coating, a furan resin coating, an isocyanate resin coating.
17. The composite unblocking method of claim 15, wherein the coated proppant has a particle size of 20-40 mesh.
18. The composite unblocking method according to claim 1, wherein the sand ratio of the film-coated propping agent and the acid gel sand-carrying fluid in the step (3) is 20-30%.
19. A composite unblocking method according to claim 1, wherein the first component is sulfamic acid and the second component is solid hydrofluoric acid.
20. A composite unblocking method according to claim 1, wherein the capsule is comprised of ethylcellulose, polyvinylpyrrolidone and gelatin, wherein: the mass ratio of the ethyl cellulose to the polyvinylpyrrolidone to the gelatin is (65-85): (5-10): (10-30).
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| CN106479477A (en) * | 2015-08-31 | 2017-03-08 | 中国石油化工股份有限公司 | A kind of encapsulating solids acid and its preparation and application |
| CA2992554A1 (en) * | 2015-09-02 | 2017-03-09 | Halliburton Energy Services, Inc. | Wrinkled capsules for treatment of subterranean formations |
| CN111574981A (en) * | 2020-06-19 | 2020-08-25 | 西北大学 | Blocking remover for oil field and preparation method thereof |
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| CN102925128A (en) * | 2012-11-05 | 2013-02-13 | 中国海洋石油总公司 | Compound chemical blocking removing agent of oil field polymer injection well |
| CN106190075A (en) * | 2015-04-30 | 2016-12-07 | 中国海洋石油总公司 | A kind of combined oxidation de-plugging agent |
| CN106479477A (en) * | 2015-08-31 | 2017-03-08 | 中国石油化工股份有限公司 | A kind of encapsulating solids acid and its preparation and application |
| CA2992554A1 (en) * | 2015-09-02 | 2017-03-09 | Halliburton Energy Services, Inc. | Wrinkled capsules for treatment of subterranean formations |
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