CN114991738A - Sandstone reservoir composite transformation method - Google Patents
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- CN114991738A CN114991738A CN202110224978.6A CN202110224978A CN114991738A CN 114991738 A CN114991738 A CN 114991738A CN 202110224978 A CN202110224978 A CN 202110224978A CN 114991738 A CN114991738 A CN 114991738A
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- 239000002131 composite material Substances 0.000 title claims abstract description 18
- 238000011426 transformation method Methods 0.000 title claims abstract description 8
- 239000012530 fluid Substances 0.000 claims abstract description 100
- 239000002253 acid Substances 0.000 claims abstract description 52
- TZCXTZWJZNENPQ-UHFFFAOYSA-L barium sulfate Chemical compound [Ba+2].[O-]S([O-])(=O)=O TZCXTZWJZNENPQ-UHFFFAOYSA-L 0.000 claims abstract description 48
- 229910052601 baryte Inorganic materials 0.000 claims abstract description 48
- 239000010428 baryte Substances 0.000 claims abstract description 48
- 239000007788 liquid Substances 0.000 claims abstract description 29
- 238000000034 method Methods 0.000 claims abstract description 28
- 239000004576 sand Substances 0.000 claims abstract description 14
- 239000000126 substance Substances 0.000 claims abstract description 4
- VYPSYNLAJGMNEJ-UHFFFAOYSA-N Silicium dioxide Chemical compound O=[Si]=O VYPSYNLAJGMNEJ-UHFFFAOYSA-N 0.000 claims description 17
- 238000006073 displacement reaction Methods 0.000 claims description 17
- 238000001125 extrusion Methods 0.000 claims description 15
- 230000008569 process Effects 0.000 claims description 13
- VEXZGXHMUGYJMC-UHFFFAOYSA-N Hydrochloric acid Chemical compound Cl VEXZGXHMUGYJMC-UHFFFAOYSA-N 0.000 claims description 12
- 239000000654 additive Substances 0.000 claims description 12
- 230000000996 additive effect Effects 0.000 claims description 10
- 239000002245 particle Substances 0.000 claims description 10
- 230000007797 corrosion Effects 0.000 claims description 9
- 238000005260 corrosion Methods 0.000 claims description 9
- 230000009471 action Effects 0.000 claims description 7
- 238000007599 discharging Methods 0.000 claims description 7
- 230000020477 pH reduction Effects 0.000 claims description 7
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 claims description 7
- KRHYYFGTRYWZRS-UHFFFAOYSA-N Fluorane Chemical compound F KRHYYFGTRYWZRS-UHFFFAOYSA-N 0.000 claims description 6
- 239000004927 clay Substances 0.000 claims description 6
- 239000003112 inhibitor Substances 0.000 claims description 6
- 239000003381 stabilizer Substances 0.000 claims description 6
- 239000006004 Quartz sand Substances 0.000 claims description 4
- 239000002738 chelating agent Substances 0.000 claims description 4
- 239000002904 solvent Substances 0.000 claims description 4
- CIWBSHSKHKDKBQ-JLAZNSOCSA-N Ascorbic acid Natural products OC[C@H](O)[C@H]1OC(=O)C(O)=C1O CIWBSHSKHKDKBQ-JLAZNSOCSA-N 0.000 claims description 2
- CIWBSHSKHKDKBQ-DUZGATOHSA-N D-isoascorbic acid Chemical compound OC[C@@H](O)[C@H]1OC(=O)C(O)=C1O CIWBSHSKHKDKBQ-DUZGATOHSA-N 0.000 claims description 2
- AFVFQIVMOAPDHO-UHFFFAOYSA-N Methanesulfonic acid Chemical class CS(O)(=O)=O AFVFQIVMOAPDHO-UHFFFAOYSA-N 0.000 claims description 2
- QPCDCPDFJACHGM-UHFFFAOYSA-N N,N-bis{2-[bis(carboxymethyl)amino]ethyl}glycine Chemical compound OC(=O)CN(CC(O)=O)CCN(CC(=O)O)CCN(CC(O)=O)CC(O)=O QPCDCPDFJACHGM-UHFFFAOYSA-N 0.000 claims description 2
- QDNXXZDINQUMNZ-UHFFFAOYSA-N N1=CC=CC=C1.C1(=CC=CC=C1)S(=O)(=O)OC Chemical compound N1=CC=CC=C1.C1(=CC=CC=C1)S(=O)(=O)OC QDNXXZDINQUMNZ-UHFFFAOYSA-N 0.000 claims description 2
- GQOKIYDTHHZSCJ-UHFFFAOYSA-M dimethyl-bis(prop-2-enyl)azanium;chloride Chemical compound [Cl-].C=CC[N+](C)(C)CC=C GQOKIYDTHHZSCJ-UHFFFAOYSA-M 0.000 claims description 2
- 235000010350 erythorbic acid Nutrition 0.000 claims description 2
- 229940026239 isoascorbic acid Drugs 0.000 claims description 2
- 238000002715 modification method Methods 0.000 claims description 2
- MGFYIUFZLHCRTH-UHFFFAOYSA-N nitrilotriacetic acid Chemical compound OC(=O)CN(CC(O)=O)CC(O)=O MGFYIUFZLHCRTH-UHFFFAOYSA-N 0.000 claims description 2
- 229960003330 pentetic acid Drugs 0.000 claims description 2
- 239000003795 chemical substances by application Substances 0.000 claims 2
- 238000005553 drilling Methods 0.000 abstract description 9
- 239000011435 rock Substances 0.000 abstract description 9
- 239000011148 porous material Substances 0.000 abstract description 7
- 239000000243 solution Substances 0.000 description 27
- 238000010276 construction Methods 0.000 description 6
- 230000000694 effects Effects 0.000 description 6
- 230000004048 modification Effects 0.000 description 6
- 238000012986 modification Methods 0.000 description 6
- 230000009466 transformation Effects 0.000 description 6
- BVKZGUZCCUSVTD-UHFFFAOYSA-L Carbonate Chemical compound [O-]C([O-])=O BVKZGUZCCUSVTD-UHFFFAOYSA-L 0.000 description 5
- 238000005086 pumping Methods 0.000 description 4
- 239000013078 crystal Substances 0.000 description 3
- 238000011161 development Methods 0.000 description 3
- 239000004575 stone Substances 0.000 description 3
- 244000007835 Cyamopsis tetragonoloba Species 0.000 description 2
- 238000004364 calculation method Methods 0.000 description 2
- 239000013522 chelant Substances 0.000 description 2
- 238000012937 correction Methods 0.000 description 2
- 238000001914 filtration Methods 0.000 description 2
- 230000009286 beneficial effect Effects 0.000 description 1
- 239000003431 cross linking reagent Substances 0.000 description 1
- 230000001186 cumulative effect Effects 0.000 description 1
- 230000007547 defect Effects 0.000 description 1
- 239000004318 erythorbic acid Substances 0.000 description 1
- 238000011156 evaluation Methods 0.000 description 1
- 238000002474 experimental method Methods 0.000 description 1
- 230000006872 improvement Effects 0.000 description 1
- 239000011259 mixed solution Substances 0.000 description 1
- 238000005457 optimization Methods 0.000 description 1
- 238000009991 scouring Methods 0.000 description 1
- 238000005406 washing Methods 0.000 description 1
- 230000004580 weight loss Effects 0.000 description 1
Classifications
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/25—Methods for stimulating production
- E21B43/26—Methods for stimulating production by forming crevices or fractures
- E21B43/267—Methods for stimulating production by forming crevices or fractures reinforcing fractures by propping
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/25—Methods for stimulating production
- E21B43/26—Methods for stimulating production by forming crevices or fractures
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- Life Sciences & Earth Sciences (AREA)
- Engineering & Computer Science (AREA)
- Geology (AREA)
- Mining & Mineral Resources (AREA)
- Physics & Mathematics (AREA)
- Environmental & Geological Engineering (AREA)
- Fluid Mechanics (AREA)
- General Life Sciences & Earth Sciences (AREA)
- Geochemistry & Mineralogy (AREA)
- Consolidation Of Soil By Introduction Of Solidifying Substances Into Soil (AREA)
Abstract
The invention provides a sandstone reservoir composite transformation method, which comprises the following steps: carrying out barite removal treatment on the sandstone reservoir by adopting a barite removal liquid so as to discharge the barite in the sandstone reservoir; acidizing the sandstone reservoir subjected to barite removal treatment by using acid liquor; and performing sand fracturing treatment on the sandstone reservoir subjected to the acidizing treatment by using a first fracturing fluid and a second fracturing fluid, wherein the second fracturing fluid contains a proppant, and the first fracturing fluid does not contain the proppant. The method can effectively solve the pollution problem of the near wellbore zone caused by the barite after well drilling and completion, dissolve acid soluble substances in the near wellbore reservoir pores and fractures, reduce the strength of near wellbore reservoir rocks, obtain longer artificial fracture channels, meet the yield and efficiency increasing requirements of different types of sandstone reservoirs, and greatly improve the productivity of oil and gas wells.
Description
Technical Field
The invention relates to the field of yield-increasing transformation of oil and gas reservoirs, in particular to a sandstone reservoir composite transformation method.
Background
Reservoir transformation is an indispensable technological measure for increasing yield of various large oil and gas fields at home and abroad, and is widely applied to reservoirs of carbonate rock, sandstone, shale gas and the like. The reservoir transformation mainly comprises three categories of hydraulic fracturing, acid fracturing and acidification, wherein the hydraulic fracturing is mainly applied to sandstone and shale gas, the acid fracturing is mainly applied to carbonate rock, and the acidification is mainly applied to sandstone and carbonate rock. Along with the continuous development of exploration and development, oil and gas reservoirs are more and more complex, the price of oil and gas is greatly reduced, and higher requirements are provided for the reservoir transformation effect.
For example, for carbonate reservoir reformation, chinese patent document CN201710571875.0 discloses a carbonate reservoir composite reformation method, which provides a reformation process combining hydraulic sand fracturing and acid fracturing, and an artificial fracture supported by a proppant is formed at a far end through hydraulic sand fracturing, and then an acid-etched fracture with an uneven surface is formed near a near well through acid fracturing, so as to achieve the purpose of deep reformation. However, for sandstone reservoir modification, the existing process has large limitation, and the sandstone modification effect needs to be further improved.
Disclosure of Invention
In order to overcome the defects in the prior art, the invention provides the sandstone reservoir composite modification method, which has a good modification effect on sandstone and greatly improves the productivity of oil-gas wells.
The invention provides a sandstone reservoir composite transformation method, which comprises the following steps: carrying out barite removal treatment on the sandstone reservoir by adopting a barite removal liquid so as to discharge the barite in the sandstone reservoir; acidizing the sandstone reservoir subjected to barite removal treatment by using acid liquor; and performing sand fracturing treatment on the sandstone reservoir subjected to acidizing treatment by adopting a first fracturing fluid and a second fracturing fluid, wherein the second fracturing fluid contains a proppant, and the first fracturing fluid does not contain the proppant.
The sandstone reservoir composite transformation method provided by the invention can effectively solve the pollution problem of barite on a near-wellbore zone after well drilling and completion, dissolve acid soluble substances in pores and cracks of a near-wellbore reservoir, and reduce the strength of rocks of the near-wellbore reservoir so as to obtain a longer artificial crack channel, meet the yield and efficiency increasing requirements of different types of sandstone reservoirs, and greatly improve the productivity of oil and gas wells.
At one endIn some embodiments, the barite removal process may include: the barite solution is added at a ratio of 0.5-3m 3 And extruding the sandstone reservoir at the displacement of/min, keeping for at least 4 hours after the extrusion is finished, then discharging a first return liquid formed by the action of the barite removing liquid and the sandstone reservoir in the sandstone reservoir, and then injecting a first displacement liquid into the sandstone reservoir to realize barite removing treatment. The discharge amount of the barite solution is the amount of the barite solution squeezed into the sandstone reservoir per minute. When concrete implementation, keep at least 4 hours and can make the barite remove liquid fully chelate, dissolve, loose barite of filtration loss in the near-well reservoir, then take out ground loose barite through washing away through flowback to and remove the barite in the liquid and dissolve and chelated barite flowback to ground, push the barite far away when avoiding follow-up sand fracturing construction, secondary deep pollution reservoir.
In some embodiments, the barite release solution includes a chelating agent, which may include at least one of diethylenetriaminepentaacetic acid, methane sulfonic acid derivatives, erythorbic acid, nitrilotriacetic acid, pyridine methylbenzenesulfonate, or dimethyldiallylammonium chloride, and a solvent, which may include water. The combination of the chelating agent and the solvent can fully chelate, dissolve and loosen the barite lost by filtration in the near-well reservoir, is beneficial to subsequent treatment and improves the sandstone modification effect.
In some embodiments, 1m is obtained by indoor evaluation 3 The barite solution can remove about 350kg barite by the combined action of chelating, dissolving, loosening and scouring, so that the extrusion amount y of the barite solution 1 Satisfy y 1 ＝ax 1 /350+k 1 ，0≤k 1 ≤ax 1 /3500，x 1 The mass of the barite in the sandstone reservoir is that a is 0.6-1.5, if reservoir fractures develop, the value of a correction coefficient can be smaller, and if the reservoir fractures do not develop, the value of a can be larger. In practice, through k 1 The value y is adjusted to be closest to ax 1 Integer of value/350 and a multiple of 10 to facilitate operation, e.g., in one embodiment of the present inventionCalculating to obtain the mass of the barite in the sandstone reservoir to be 52000 kg; the development condition of the sandstone reservoir can be generally judged according to the fracture line density rho of the sandstone reservoir, when the fracture line density rho is less than or equal to 0.5/m, the surface fracture is generally developed, a can be 0.8-1.6, when the fracture line density rho is more than 0.5/m, the surface fracture is relatively developed, a can be 0.6-0.8, for example, in one embodiment, the fracture line density rho is 0.4/m, the fracture is relatively developed, and a can be 0.8, and ax is obtained 1 /350＝0.8×52000/350＝118.9m 3 ，k 1 The value may be 1.1, y may be 120m 3 . Generally, the dosage of the barite relieving liquid is not more than 500m 3 The specific dosage is determined by the amounts of the drilling fluid, the completion fluid and the workover fluid which are leaked in the drilling and completion processes and the workover processes.
In some embodiments, the acidification process may include: sequentially adding the pre-acid solution, the main acid solution and the post-acid solution at a ratio of 2-4m 3 Extruding the displacement of/min into the sandstone reservoir subjected to barite removal treatment, keeping for at least 4 hours after the extrusion is finished, then back-discharging a second back-flow liquid formed by the action of the pre-acid liquid, the main acid liquid, the post-acid liquid and the sandstone reservoir in the sandstone reservoir, and then injecting a second displacement liquid into the sandstone reservoir to realize the acidification treatment; wherein the pre-acid solution can comprise 8-12 wt% of hydrochloric acid, 1-2 wt% of clay stabilizer, 1-2 wt% of cleanup additive, 2-4 wt% of corrosion inhibitor and the balance additive; the main acid solution can comprise 8-12 wt% of hydrochloric acid, 1-2.5 wt% of hydrofluoric acid, 1-2 wt% of clay stabilizer, 1-2 wt% of cleanup additive, 2-4 wt% of corrosion inhibitor and the balance additive; the post acid solution can comprise a mixed solution of the pre acid solution and water according to the mass ratio of 1: 1. The acidizing treatment can dissolve acid soluble matters in the near-well cracks and pores, can reduce the strength of near-well rocks and reduce the extension pressure of near-well artificial cracks during subsequent sand fracturing.
In some embodiments, the amount of the pre-acid solution to be squeezed is greater than the amount of the main acid solution and the post-acid solution to be squeezed, for example, in one embodiment, the amount of the pre-acid solution to be squeezed may be 1.2 to 1.5 times of the amount of the main acid solution to be squeezed, and the amount of the post-acid solution to be squeezed may be 0.8 to 1.0 times of the amount of the main acid solution to be squeezed. In particular toThe extrusion amount of the main acid liquid is V 1 Then the extrusion amount V of the pre-acid solution 2 Can be 1.2-1.5V 1 Extrusion amount V of the post acid solution 3 Can be 0.8-1.0V 1 (ii) a Wherein, V 1 Equal to the sum of the pore volume of the fractures within the reservoir and the pore volume of the pores, i.e. it satisfies V 1 ＝3.14×r 2 ×d×Φ+n×i×h×w+k 2 R is the radius of the holes in the reservoir, phi is the porosity (namely the number of inner holes in the thickness of the reservoir), d is the thickness of the reservoir (well layers in specific operation), n is the number of cracks in the reservoir, i, w and h are the length, width and height of the cracks respectively, and k is more than or equal to 0 2 ≤3.14×r 2 X d x phi + n x i x h x w, when embodied, by k 2 Value adjustment V 1 Is closest to 3.14 xr 2 And a value of xdΦ + nxl × h × w, which is an integer of a multiple of 10, for easy operation. In general, in sandstone reservoirs, r is 1-1.5m, i is 20-40m, w is 5-8mm, and h is 3-8 m.
In some embodiments, the second fracturing fluid comprises a fracturing fluid a, a fracturing fluid B and a fracturing fluid C, wherein the particle size of the proppant in the fracturing fluid a is smaller than that of the proppant in the fracturing fluid B, and the particle size of the proppant in the fracturing fluid B is smaller than that of the proppant in the fracturing fluid C; the sand fracturing treatment process can comprise the following steps: according to not less than 3m 3 Discharging volume per minute, alternately extruding a first fracturing fluid and a fracturing fluid A into the sandstone reservoir subjected to the acidizing treatment for 2-4 times; according to the standard of not less than 3m 3 The discharge amount of the fracturing fluid per minute is that a first fracturing fluid and a fracturing fluid B are sequentially squeezed into a sandstone reservoir; then according to the proportion of not less than 3m 3 Displacement per minute, squeezing fracturing fluid C into the sandstone reservoir; and then, discharging a third flowback fluid formed by the action of the first fracturing fluid, the second fracturing fluid and the sandstone reservoir in the sandstone reservoir, and then injecting a third displacement fluid into the sandstone reservoir to realize the sand-adding fracturing treatment. The total times of squeezing the first fracturing fluid and the fracturing fluid A are 2-4 times, the squeezing of the first fracturing fluid and the fracturing fluid A can reduce near-well friction resistance, activate and communicate more natural fractures, and particularly natural fractures with larger included angles with the maximum horizontal principal stress direction of a reservoir stratum; the artificial crack with high flow conductivity can be obtained by squeezing the first fracturing fluid and the fracturing fluid B;the squeezing of the fracturing fluid C can prevent the fracturing fluid B from returning out, and the improvement effect on the sandstone reservoir is facilitated.
In some embodiments, the particle size of the proppant in the fracturing fluid a may be 70/100 mesh or 100/140 mesh, the particle size of the proppant in the fracturing fluid B may be 40/70 mesh, and the particle size of the proppant in the fracturing fluid C may be 20/40 mesh or 30/50 mesh. In order to obtain a better sandstone reservoir transformation effect, in specific implementation, the corrosion rate of the preposed acid liquid to 20/40-mesh reservoir rock debris is generally not less than 10%, and the corrosion rate of the main acid liquid to 20/40-mesh reservoir rock debris is generally not less than 15%.
In some embodiments, the proppant may include at least one of ceramsite, quartz sand, coated ceramsite, and coated quartz sand.
In some embodiments, the first fracturing fluid may comprise at least one of a crosslinked fracturing fluid, a non-crosslinked fluid, and slickwater; and/or the second fracturing fluid may comprise a base fluid and the proppant, and the base fluid may comprise at least one of a crosslinked fracturing fluid, a non-crosslinked fluid, and slick water. In particular implementations, the crosslinked fracturing fluid can include a guar crosslinked fracturing fluid.
In the present invention, the displacement fluid (the first displacement fluid, the second displacement fluid and the third displacement fluid) used can be water or other displacement fluids conventional in the art, such as a conventional guar fracturing fluid without adding a cross-linking agent, and is not particularly limited.
The sandstone reservoir composite transformation method can effectively solve the pollution problem of barite on a near-wellbore zone after well drilling and completion, dissolve acid soluble substances in pores and cracks of the near-wellbore reservoir, reduce the strength of rocks of the near-wellbore reservoir, obtain a longer artificial crack channel, meet the yield and efficiency increasing requirements of different types of sandstone reservoirs, realize the yield increasing transformation of oil and gas reservoirs (sandstone reservoirs) and greatly improve the productivity of oil and gas wells.
Detailed Description
In order to make the objects, technical solutions and advantages of the present invention clearer, the technical solutions in the embodiments of the present invention will be clearly and completely described below with reference to the embodiments of the present invention. All other embodiments, which can be derived by a person skilled in the art from the embodiments given herein without making any creative effort, shall fall within the protection scope of the present invention.
Example 1
The experimental well selected in the embodiment is a certain A block A-1 well of a sandstone reservoir of a Tarim oil field, the depth of a target layer (namely the sandstone reservoir to be modified) of the well is 6930.00-6968.50 m, the density of fracture lines is 0.4 per meter, and the accumulated loss in the drilling process is 2.05g/cm 3 Drilling fluid 30m 3 And predicting the fracture extension gradient of 2.20MPa/100m in the reservoir sand fracturing modification process. The sandstone reservoir modification comprises the following steps:
(1) barite removal treatment
Cumulative loss of 2.05g/cm in the process of drilling at target layer 3 Drilling fluid 30m 3 According to the calculation, 52000kg of weight loss crystal stone (namely the mass of the crystal stone in the sandstone reservoir) is obtained, the density of the well fracture line is 0.4/m, the fracture is relatively developed, therefore, the correction coefficient a is 0.8, and the extrusion amount y of the crystal stone relief solution can be calculated 1 ＝0.8×52000/350+k 1 Take 120m 3 . The pumping procedure and conditions for barite removal (the squeeze-in amount, the discharge amount during squeezing, and the pump pressure during squeezing of the barite removal liquid and the first displacement liquid) are shown in table 1.
Table 1 barite release construction schedule
(2) Acidification treatment
Preparing a preposed acid solution through a corrosion rate experiment: 9% hydrochloric acid, 1% clay stabilizer, 1% cleanup additive, 2% corrosion inhibitor and the balance additive, and the main acid solution: 9% of hydrochloric acid, 1% of hydrofluoric acid, 1% of clay stabilizer, 1% of cleanup additive, 2% of corrosion inhibitor and the balance of additives. The thickness of the reservoir stratum of the well is 38.5m, the porosity is 5.8%, the number of natural fractures is 15, the average length of the natural fractures of the reservoir stratum is 30m, the height is 5m, the width is 0.005m, and V is obtained by calculation 1 ＝30m 3 ，V 2 Take 45m 3 ，V 3 Take 30m 3 . The pumping procedure and conditions (squeeze amount of the pre-acid, the main acid, the post-acid, and the second displacement fluid, discharge amount during squeezing, and pump pressure during squeezing) of the acidification treatment are shown in table 2.
TABLE 2 acidizing procedure Table
(3) Sand fracturing treatment
The construction scale and the discharge capacity are mainly optimized through related software simulation, and the total volume of the fracturing fluid is 720m through mangrove software simulation optimization 3 Proppant 47.63m 3 (wherein, 70/100 mesh 1.88m 3 40/70 mesh proppant 40.75m 3 30/50 mesh coated ceramsite 5m 3 ) Discharge capacity of 4.5m 3 And/min. The fracturing fluids and displacing fluids used in the sand fracturing construction are shown in table 3, and the pumping procedures and conditions (the extrusion amount, the discharge amount and the pumping pressure of the first fracturing fluid, the second fracturing fluid and the third displacing fluid) are shown in table 4.
TABLE 4 fracturing fluid and displacing fluid for sand fracturing construction
TABLE 3 Sand fracturing construction procedure table
Claims (10)
1. A sandstone reservoir composite transformation method is characterized by comprising the following steps:
carrying out barite removal treatment on the sandstone reservoir by adopting a barite removal liquid so as to discharge the barite in the sandstone reservoir;
acidizing the sandstone reservoir subjected to barite removal treatment by using acid liquor;
and carrying out sand fracturing treatment on the sandstone reservoir subjected to the acidizing treatment by adopting a first fracturing fluid and a second fracturing fluid, wherein the second fracturing fluid contains a propping agent, and the first fracturing fluid does not contain the propping agent.
2. The sandstone reservoir composite reformation method of claim 1, wherein the barite removal treatment process comprises: the barite relieving liquid is added by 0.5-3m 3 And extruding the sandstone reservoir at the displacement of/min, keeping for at least 4 hours after the extrusion is finished, then discharging a first return liquid formed by the action of the barite removing liquid and the sandstone reservoir in the sandstone reservoir, and then injecting a first displacing liquid into the sandstone reservoir to realize the barite removing treatment.
3. The sandstone reservoir reformation method of claim 1 or 2, wherein the barite release fluid comprises a chelating agent and a solvent, the chelating agent comprises at least one of diethylenetriamine pentaacetic acid, a methane sulfonic acid derivative, isoascorbic acid, nitrilotriacetic acid, pyridine methyl benzene sulfonate, or dimethyldiallylammonium chloride, and the solvent comprises water.
4. The sandstone reservoir composite reformation method of claim 3, characterized in that the extrusion amount y of the barite releasing liquid 1 Satisfy y 1 ＝ax 1 /350+k 1 ，0≤k 1 ≤ax 1 /3500，x 1 And a is 0.6-1.5, which is the mass of barite in the sandstone reservoir.
5. The sandstone reservoir composite reformation method of claim 1, wherein the acidizing process comprises: sequentially extruding the pre-acid solution, the main acid solution and the post-acid solution into the sandstone reservoir subjected to barite removal treatment at a discharge capacity of 2-4m3/min, keeping for at least 4 hours after the extrusion is finished, then back-discharging a second back-discharge liquid formed by the action of the pre-acid solution, the main acid solution, the post-acid solution and the sandstone reservoir in the sandstone reservoir, and then injecting a second displacement liquid into the sandstone reservoir to realize the acidification treatment; wherein the content of the first and second substances,
the pre-acid solution comprises 8-12 wt% of hydrochloric acid, 1-2 wt% of a clay stabilizer, 1-2 wt% of a cleanup additive, 2-4 wt% of a corrosion inhibitor and the balance of additives;
the main acid solution comprises 8-12 wt% of hydrochloric acid, 1-2.5 wt% of hydrofluoric acid, 1-2 wt% of clay stabilizer, 1-2 wt% of cleanup additive, 2-4 wt% of corrosion inhibitor and the balance additive;
the post acid liquid comprises mixed liquid formed by the pre acid liquid and water according to the mass ratio of 1: 1.
6. The sandstone reservoir composite reformation method of claim 5, wherein the extrusion amount of the pre-acid is 1.2 to 1.5 times of the extrusion amount of the main acid, and the extrusion amount of the post-acid is 0.8 to 1.0 times of the extrusion amount of the main acid.
7. The sandstone reservoir composite reformation method of claim 1, wherein the second fracturing fluid comprises a fracturing fluid A, a fracturing fluid B and a fracturing fluid C, the particle size of the proppant in the fracturing fluid A is smaller than that of the proppant in the fracturing fluid B, and the particle size of the proppant in the fracturing fluid B is smaller than that of the proppant in the fracturing fluid C; the sand fracturing treatment process comprises the following steps:
according to not less than 3m 3 The discharge amount per minute is that the first fracturing fluid and the fracturing fluid A are alternately squeezed into the sandstone reservoir after the acidizing treatment for 2-4 times; according to the standard of not less than 3m 3 The discharge amount of/min is that the first fracturing fluid and the fracturing fluid B are sequentially squeezed into the sandstone reservoir; then according to no longerLess than 3m 3 Displacement per min, squeezing the fracturing fluid C into a sandstone reservoir; and then, returning and discharging a third returning fluid formed by the action of the first fracturing fluid, the second fracturing fluid and the sandstone reservoir in the sandstone reservoir, and then injecting a third displacement fluid into the sandstone reservoir to realize the sand-adding fracturing treatment.
8. The sandstone reservoir composite modification method of claim 7, wherein the particle size of the proppant in the fracturing fluid A is 70/100 meshes and 100/140 meshes, the particle size of the proppant in the fracturing fluid B is 40/70 meshes, and the particle size of the proppant in the fracturing fluid C is 20/40 meshes or 30/50 meshes.
9. The sandstone reservoir composite reformation method of any one of claims 1, 7 and 8, wherein the proppant comprises at least one of ceramsite, quartz sand, coated ceramsite and coated quartz sand.
10. The sandstone reservoir composite reformation method of any one of claims 1, 7, and 8, wherein the first fracturing fluid comprises at least one of a crosslinked fracturing fluid, a non-crosslinked fluid, and slickwater; and/or the second fracturing fluid comprises a base fluid and the proppant, wherein the base fluid comprises at least one of a cross-linked fracturing fluid, a non-cross-linked fluid and slick water.
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