A method for acid fracturing network fractures of a fractured carbonate reservoir

Abstract

The application relates to a method for acid fracturing network cracks of a fractured carbonate rock oil reservoir, which comprises the following steps: step 1, opening and establishing a long, open and conductive hydraulic main fracture channel; step 2, injecting a large amount of low-viscosity slick water along the hydraulic main fracture channel; step 3, injecting an acid liquid system to perform acid corrosion reconstruction on the fracture system; step 4, performing temporary plugging and directional acid fracturing by injecting a temporary plugging agent carried by fracturing fluid; step 5, performing alternating acid fracturing; step 6, reducing the construction discharge to 1.5-3 m<3> / min, and performing closed acidification reconstruction on the hydraulic main fracture, branch fracture and natural fracture formed by the multi-round alternating acid fracturing under the condition of near-closed pressure, so that a wide concave or channel is avoided from being formed around the wellbore and in the fracture far from the wellbore through the closed acidification effect; even in the case of fracture closure, a high flow conductivity can still be maintained through the concave opening state; and step 7, after the well is closed for 2-3 hours, liquid is discharged and production is started. 3 / min, and performing closed acidification reconstruction on the hydraulic main fracture, branch fracture and natural fracture formed by the multi-round alternating acid fracturing under the condition of near-closed pressure, so that a wide concave or channel is avoided from being formed around the wellbore and in the fracture far from the wellbore through the closed acidification effect; even in the case of fracture closure, a high flow conductivity can still be maintained through the concave opening state; and step 7, after the well is closed for 2-3 hours, liquid is discharged and production is started.

Description

Technical Field

[0001] This invention relates to the field of oilfield development technology, and in particular to a method for acid fracturing network fractures in fractured carbonate reservoirs. Background Technology

[0002] Carbonate reservoirs account for over 30% of my country's total oil and gas resources, making them a crucial area for increasing oil and gas reserves and production. However, carbonate reservoirs have poor matrix properties, and the fractures and cavern systems formed by secondary diagenesis are the main reservoir spaces and seepage channels. Furthermore, the development of oil and gas-rich fractures and caverns is discontinuous, and over 90% of carbonate oil and gas reservoirs require acid fracturing to achieve large-scale, cost-effective development.

[0003] Fractured carbonate reservoirs are a common type of carbonate reservoir, widely distributed in the Jiyang Depression and Tarim Basin of my country. These reservoirs are developed using conventional acid fracturing. Conventional acid fracturing techniques include... Figure 2 As shown, under limited flow rates, a hydraulic main fracture channel 2 is opened using cross-linked high-viscosity fracturing fluid in the matrix reservoir 9 of a fractured carbonate reservoir. Acid fracturing then only connects some randomly distributed natural fractures 4 on the flanks of the adjacent hydraulic main fracture channel 2. Simultaneously, acid dissolution along the dominant fractures exacerbates acid loss through wormholes. Even with alternating fracturing fluid extension of the main fracture and gelled acid etching, the length of the main fracture that can be modified and the connection of natural fractures are limited, and the volume affected by acid dissolution is small. Due to the rapid reaction rate of the acid-rock mixture and severe acid loss in the microfractures, the effective length and conductivity of the acid-etched fractures are limited. Furthermore, the strong heterogeneity of the reservoir fracture distribution results in a small affected volume for acid fracturing. While some initial production can usually be achieved, production declines rapidly, making stable production difficult. Summary of the Invention

[0004] To address the shortcomings of existing acid fracturing techniques in fractured carbonate reservoirs, such as short fracture lengths and small effective volumes, this invention provides a method for creating a network of fractures through acid fracturing. This invention couples acid fracturing with fracture systems of different scales, including hydraulic fractures, branch fractures, and natural fractures. Based on the creation of main hydraulic fractures using cross-linked high-viscosity fracturing fluid and branch fractures using slickwater to connect with natural fractures, gelled acid is injected to etch and modify the main fractures, branch fractures, and natural fractures. This is complemented by a temporary plugging and redirection acid fracturing technique to temporarily plug acid-etched wormholes formed by the dissolution of dominant natural fractures and some branch fractures through multi-stage temporary plugging. Furthermore, multi-stage alternating acid fracturing with fracturing fluid and gelled acid is implemented. By increasing the effective fracture length through acid fracturing and coupling the main hydraulic fractures, branch fractures, and natural fractures, this method improves the acid fracturing volume and single-well production in fractured carbonate reservoirs.

[0005] Technical solution: A method for acid fracturing network fractures in fractured carbonate reservoirs, comprising:

[0006] Step 1: Hydraulic fracturing is performed on the target layer fractured carbonate reservoir matrix by injecting cross-linked high-viscosity fracturing fluid to open and establish a long, open, conductive hydraulic main fracture channel, extending from the wellbore to a position at a horizontal distance of a meters in the deep formation, where 30≤a≤40;

[0007] Step 2: Based on the hydraulic main fracture channel opened in Step 1, low-viscosity slickwater is injected at a large volume along the hydraulic main fracture channel. The high net pressure forces the opening of the primary branch fractures. At the same time, the low-viscosity slickwater seeps into the initially connected random natural fractures, and a preliminary undissolved fracture system is established, consisting of the hydraulic main fracture channel, the primary branch fractures, and the initially connected random natural fractures.

[0008] Step 3: Inject acid solution system to carry out acid dissolution modification of the fracture system. As the amount of injected acid solution increases, acid dissolution and crack widening modification are carried out sequentially on the main hydraulic fracture channel, the initial branch fracture, and the initially connected random natural fracture.

[0009] Step 4: Temporary plugging and acid fracturing are carried out by fracturing fluid carrying the injection of temporary plugging agent. The main purpose is to use the temporary plugging agent to dissolve the dominant natural fractures in the fractured carbonate reservoir to form acid wormholes and some branch fractures in multiple stages, forcing the acid system to communicate and dissolve more natural fractures and branch fracture systems.

[0010] Step 5: Implement alternating injection acid fracturing. Following the first round of acid fracturing in steps 1-4, implement the Nth round of injection. By injecting cross-linked high-viscosity fracturing fluid, extend the hydraulic main fracture channel again, resulting in the Nth hydraulic main fracture. Extend the existing hydraulic main fracture channel length (a meters) by (N-1)b meters, making the distance between the hydraulic main fracture channel and the Nth hydraulic main fracture a + (N-1)b meters. Then, use slickwater to create fractures, forming the Nth branch fracture. Simultaneously, low-viscosity slickwater infiltrates into the randomly distributed natural fractures connected by the Nth branch fracture. Then, inject gelling acid to etch the fractures and perform redirecting acid fracturing, forming an acid fracturing network fracture. This increases the effective length of the etched main fracture and the volume of acid fracturing modification. Specifically:

[0011] N is a positive integer ≥ 2, and 20 ≤ b ≤ 30;

[0012] Step 6: Reduce the construction displacement to 1.5-3m³. 3 / min, under near-closed pressure conditions, the hydraulic main fracture, branch fracture and natural fracture formed by multiple rounds of alternating acid fracturing are closed and acidized. Through the closed acidizing effect, wide grooves or channels are avoided in the fractures around the well and away from the well. Even when the fracture is closed, the high conductivity can still be maintained by the groove opening state.

[0013] Step 7: After shutting in the well for 2-3 hours, drain the fluid and start production.

[0014] Furthermore, the viscosity of the cross-linked high-viscosity fracturing fluid described in step 1 is 200–400 mPa·s.

[0015] Further, the crosslinked high-viscosity fracturing fluid described in step 1 comprises, by mass percentage: 0.8–1.2% acrylamide polymer, 0.3–0.4% crosslinking agent, 0.15–0.3% quaternary ammonium salt clay stabilizer, 0.2–0.3% nanoemulsion, with the balance being water, wherein:

[0016] The nanoemulsion is prepared by mixing dimethylammonium chloride, ethanolamide, and ethanol in a mass ratio of (1-5):(1-5):100.

[0017] Furthermore, the crosslinking agent is one of a polycarboxylic acid, a polyol, or a polyamine condensation polymer.

[0018] Furthermore, the viscosity of the low-viscosity slippery water mentioned in step 2 is 5–10 mPa·s, and the large discharge capacity mentioned in step 2 refers to a construction discharge capacity of 6–10 m³ / s. 3 / min.

[0019] Further, the low-viscosity slippery water mentioned in step 2, by mass percentage, comprises: 0.1–0.2% acrylamide polymer, 0.15–0.3% quaternary ammonium salt clay stabilizer, 0.2–0.3% nanoemulsion, with the balance being water, wherein:

[0020] The nanoemulsion is prepared by mixing dimethylammonium chloride, ethanolamide, and ethanol in a mass ratio of (1-5):(1-5):100.

[0021] Furthermore, the acid system described in step 3 is a gelling acid system with a viscosity of 30–60 mPa·s. The gelling acid system was chosen to reduce the acid-rock reaction rate and acid filtration loss, thereby improving acid utilization efficiency.

[0022] Furthermore, the gelling acid system described in step 3, by mass percentage, comprises: 10%–15% of a 25–37% hydrochloric acid aqueous solution, 1.0–1.2% of acrylamide polymer, 3–5% imidazoline, 0.2–0.3% of nano-microemulsion, 2–3% of sodium ethylenediaminetetraacetate or sodium isoascorbate, 0.15–0.3% of quaternary ammonium salt clay stabilizer, with the balance being water.

[0023] The nanoemulsion is prepared by mixing dimethylammonium chloride, ethanolamide, and ethanol in a mass ratio of (1-5):(1-5):100.

[0024] Further, the temporary plugging agent described in step 4 is composed of viren fibers and temporary plugging particles, wherein:

[0025] The length of vilan fibers is 8–12 mm;

[0026] The diameter of the temporary plugging particles is 5-8 mm;

[0027] The weight ratio of vilan fibers to temporary plugging particles is (2-4):1.

[0028] Furthermore, the temporary plugging particles mentioned in step 4 are polyvinyl alcohol or polyacrylamide polymers.

[0029] Furthermore, the number of rounds N mentioned in step 5 is 2, 3, or 4.

[0030] The method for acid fracturing network fractures in fractured carbonate reservoirs disclosed in this invention has the following beneficial effects:

[0031] 1. Compared with conventional acid fracturing processes, this invention utilizes cross-linked high-viscosity fracturing hydraulic pressure to open a main fracture channel and a large volume of slickwater to open branch fractures and natural fractures. It then uses gelling acid to acid-dissolve and enlarge the main fracture, branch fractures, and natural fractures, achieving coupled acid fracturing of a multi-scale fracture system in fractured carbonate rocks. This increases the volume of acid-etched fracture modification, such as... Figure 1 As shown;

[0032] 2. Using temporary plugging agents to temporarily plug acid-etched wormholes and some branch fractures formed by the dissolution of dominant natural fractures in fractured carbonate reservoirs in multiple stages, forcing the acid to communicate and dissolve more micro-fractures and branch fracture systems, which not only increases the complexity of fractures and the volume of branch fracture modification, but also effectively reduces the acid loss of acid-etched wormholes at dominant fractures and improves the efficiency of acid etching modification.

[0033] 3. Multiple rounds of alternating acid injection and fracturing further increase the effective length of the main acid-etched crack and improve the volume of acid-etched modification of branch cracks and natural cracks;

[0034] 4. Low-displacement near-balanced closed acidizing technology: This technology performs closed acidizing on multi-scale fractures around and far from the wellbore under near-closed conditions, forming acid-etched fractures that are staggered and have a grooved appearance. Even after the fractures are closed, they still have relatively high conductivity, thus effectively improving the production capacity after pressure treatment. Attached Figure Description

[0035] Figure 1 This is a schematic diagram of a method for acid fracturing network fractures in fractured carbonate reservoirs disclosed in this invention;

[0036] Figure 2 A schematic diagram of existing conventional acid fracturing methods for fractured carbonate oil and gas reservoirs;

[0037] 1-Oil well bore

[0038] 2-Hydraulic main fracture channel

[0039] 3-Initial branch crack

[0040] 4- Randomly Distributed Natural Cracks During Initial Communication

[0041] 5- The Nth hydraulic main fracture

[0042] 6-Nth branch crack

[0043] 7- Randomly distributed natural cracks in the Nth communication

[0044] 8-Temporary plugging agent

[0045] 9- Fractured carbonate reservoir matrix Detailed implementation method:

[0046] The specific embodiments of the present invention are described in detail below.

[0047] Example 1

[0048] ZX-1 and ZX-4 are two oil wells deployed in the ZX block of carbonate reservoirs. Their burial depth and reservoir thickness are similar. Specific physical properties are shown in Table 1.

[0049] Table 1

[0050]

[0051] (1) Well ZX-1 employs conventional acid fracturing technology, such as Figure 2 The specific implementation steps are shown below:

[0052] First inject 100m 3 Cross-linked fracturing fluid, discharge rate 4.5m³. 3 / min;

[0053] Then inject 80m 3 Gelatinous acid, construction flow rate 4.5m³ 3 / min;

[0054] Two more alternating injections of fracturing fluid, each 80m³, were performed. 3 80m gelling acid 3 A total of 240m³ of acid solution was injected. 3 260m of fracturing fluid 3 After acid pressing, the liquid is drained and put into production 1 hour later.

[0055] Initially, the highest daily liquid volume was 25 t / d, and the daily oil volume was 18.5 t / d.

[0056] (2) Well ZX-4 employs the aforementioned acid fracturing network fracture technology, specifically as follows:

[0057] like Figure 1 As shown, a method for creating an acid fracturing network fracture in a fractured carbonate reservoir includes:

[0058] Step 1: Hydraulic fracturing is performed on the target layer fractured carbonate reservoir matrix 9 by injecting cross-linked high-viscosity fracturing fluid to open and establish a long, open, conductive hydraulic main fracture channel 2, extending from the wellbore 1 to a position 35 meters deep in the formation.

[0059] Step 2: Based on the hydraulic main fracture channel 2 opened in Step 1, low-viscosity slickwater is injected at a large rate along the hydraulic main fracture channel 2. The high net pressure forces the opening of the primary branch fracture 3. At the same time, the low-viscosity slickwater seeps into the initially connected random natural fractures 4, and a preliminary undissolved fracture system is established, consisting of the hydraulic main fracture channel 2, the primary branch fracture 3, and the initially connected random natural fractures 4.

[0060] Step 3: Inject acid solution system to carry out acid dissolution modification of the fracture system. As the amount of injected acid solution increases, acid dissolution and crack widening modification are carried out sequentially on the hydraulic main fracture channel 2, the initial branch fracture 3, and the initially connected random natural fracture 4.

[0061] Step 4: Temporary plugging and acid fracturing are carried out by injecting temporary plugging agent 8 through fracturing fluid. The main purpose is to use temporary plugging agent 8 to dissolve the dominant natural fractures in the fractured carbonate reservoir to form acid wormholes and some branch fractures in multiple stages, so as to force the acid system to communicate and dissolve more natural fractures and branch fracture systems.

[0062] Step 5: Implement alternating injection acid fracturing. Following the first round of acid fracturing in steps 1-4, implement the Nth round of injection. By injecting cross-linked high-viscosity fracturing fluid, extend the hydraulic main fracture channel 2 again, resulting in the Nth hydraulic main fracture 5. Extend the hydraulic main fracture channel 2 by (N-1)b meters from its original length of a meters, making the distance between the hydraulic main fracture channel 2 and the Nth hydraulic main fracture 5 a + (N-1)b meters. Then, use slickwater to create fractures, forming the Nth branch fracture 6. Simultaneously, low-viscosity slickwater infiltrates the randomly distributed natural fractures 7 that connect to the Nth branch. Then, inject gelling acid to etch the fractures and perform redirecting acid fracturing, forming an acid fracturing network fracture. This increases the effective length of the etched main fracture and the volume of the acid fracturing modification. Where: N = 2; B = 35.

[0063] Step 6: Reduce the construction displacement to 2m 3 / min, under near-closed pressure conditions, the hydraulic main fracture, branch fracture and natural fracture formed by multiple rounds of alternating acid fracturing are closed and acidized. Through the closed acidizing effect, wide grooves or channels are avoided in the fractures around the well and away from the well. Even when the fracture is closed, the high conductivity can still be maintained by the groove opening state.

[0064] Step 7: After shutting in the well for 2 hours, drain the fluid and start production.

[0065] Furthermore, the viscosity of the cross-linked high-viscosity fracturing fluid described in step 1 is 300 mPa·s.

[0066] Further, the crosslinked high-viscosity fracturing fluid described in step 1 comprises, by mass percentage: 1% acrylamide polymer, 0.35% crosslinking agent, 0.2% quaternary ammonium salt clay stabilizer, 0.25% nanoemulsion, and the balance being water, wherein:

[0067] The nanoemulsion is prepared by mixing dimethylammonium chloride, ethanolamide, and ethanol in a mass ratio of 2:3:100.

[0068] Furthermore, the crosslinking agent is a polycarboxylic acid.

[0069] Furthermore, the viscosity of the low-viscosity slippery water mentioned in step 2 is 8 mPa·s, and the large discharge volume mentioned in step 2 refers to a construction discharge volume of 8 m³ / s. 3 / min.

[0070] Further, the low-viscosity slippery water mentioned in step 2, by mass percentage, comprises: 0.1% acrylamide polymer, 0.15% quaternary ammonium salt clay stabilizer, 0.2% nano-microemulsion, and the balance being water, wherein:

[0071] The nanoemulsion is prepared by mixing dimethylammonium chloride, ethanolamide, and ethanol in a mass ratio of 2:3:100.

[0072] Furthermore, the acid system described in step 3 is a gelling acid system with a viscosity of 30–60 mPa·s. The gelling acid system was chosen to reduce the acid-rock reaction rate and acid filtration loss, thereby improving acid utilization efficiency.

[0073] Furthermore, the gelling acid system described in step 3, by mass percentage, comprises: 10% of a 25% hydrochloric acid aqueous solution, 1.0% of acrylamide polymer, 3% imidazoline, 0.2% of nanoemulsion, 2% sodium ethylenediaminetetraacetate, 0.15% quaternary ammonium salt clay stabilizer, and the balance being water, wherein:

[0074] The nanoemulsion is prepared by mixing dimethylammonium chloride, ethanolamide, and ethanol in a mass ratio of 2:3:100.

[0075] Further, the temporary plugging agent 8 described in step 4 is composed of viren fibers and temporary plugging particles, wherein:

[0076] The length of the vilan fiber is 10mm;

[0077] The diameter of the temporary plugging particles is 6mm;

[0078] The weight ratio of vilan fibers to temporary plugging particles is 3:1.

[0079] Furthermore, the temporary plugging particles mentioned in step 4 are polyvinyl alcohol.

[0080] The initial peak daily fluid production was 63.5 t / d, and the daily oil production was 34.1 t / d. Compared with traditional conventional acid fracturing technology, the initial daily fluid and oil production of well ZX-4 were significantly increased after implementing this invention.

[0081] Example 2

[0082] A method for acid fracturing network fractures in fractured carbonate reservoirs includes:

[0083] Step 1: Hydraulic fracturing is performed on the target layer fractured carbonate reservoir matrix 9 by injecting cross-linked high-viscosity fracturing fluid to open and establish a long, open, conductive hydraulic main fracture channel 2, extending from the wellbore 1 to a position at a horizontal distance of a meters in the deep formation, where a = 30.

[0084] Step 2: Based on the hydraulic main fracture channel 2 opened in Step 1, low-viscosity slickwater is injected at a large rate along the hydraulic main fracture channel 2. The high net pressure forces the opening of the primary branch fracture 3. At the same time, the low-viscosity slickwater seeps into the initially connected random natural fractures 4, and a preliminary undissolved fracture system is established, consisting of the hydraulic main fracture channel 2, the primary branch fracture 3, and the initially connected random natural fractures 4.

[0085] Step 3: Inject acid solution system to carry out acid dissolution modification of the fracture system. As the amount of injected acid solution increases, acid dissolution and crack widening modification are carried out sequentially on the hydraulic main fracture channel 2, the initial branch fracture 3, and the initially connected random natural fracture 4.

[0086] Step 4: Temporary plugging and acid fracturing are carried out by injecting temporary plugging agent 8 through fracturing fluid. The main purpose is to use temporary plugging agent 8 to dissolve the dominant natural fractures in the fractured carbonate reservoir to form acid wormholes and some branch fractures in multiple stages, so as to force the acid system to communicate and dissolve more natural fractures and branch fracture systems.

[0087] Step 5: Implement alternating injection acid fracturing. Following the first round of acid fracturing in steps 1-4, implement the Nth round of injection. By injecting cross-linked high-viscosity fracturing fluid, extend the hydraulic main fracture channel 2 again, resulting in the Nth hydraulic main fracture 5. Extend the hydraulic main fracture channel 2 by (N-1)b meters from its original length of a meters, making the distance between the hydraulic main fracture channel 2 and the Nth hydraulic main fracture 5 a + (N-1)b meters. Then, use slickwater to create fractures, forming the Nth branch fracture 6. Simultaneously, low-viscosity slickwater infiltrates the randomly distributed natural fractures 7 that connect to the Nth fracture. Then, inject gelling acid to etch the fractures and perform redirecting acid fracturing, forming an acid fracturing network fracture. This increases the effective length of the etched main fracture and the volume of acid fracturing, where: N = 2; b = 20.

[0088] Step 6: Reduce the construction displacement to 1.5m 3 / min, under near-closed pressure conditions, the hydraulic main fracture, branch fracture and natural fracture formed by multiple rounds of alternating acid fracturing are closed and acidized. Through the closed acidizing effect, wide grooves or channels are avoided in the fractures around the well and away from the well. Even when the fracture is closed, the high conductivity can still be maintained by the groove opening state.

[0089] Step 7: After shutting in the well for 2 hours, drain the fluid and start production.

[0090] Furthermore, the viscosity of the cross-linked high-viscosity fracturing fluid described in step 1 is 200 mPa·s.

[0091] Further, the crosslinked high-viscosity fracturing fluid described in step 1 comprises, by mass percentage: 0.8% acrylamide polymer, 0.3% crosslinking agent, 0.15% quaternary ammonium salt clay stabilizer, 0.2% nanoemulsion, and the balance being water, wherein:

[0092] The nanoemulsion is prepared by mixing dimethylammonium chloride, ethanolamide, and ethanol in a mass ratio of 1:1:100.

[0093] Furthermore, the crosslinking agent is a polycarboxylic acid.

[0094] Furthermore, the viscosity of the low-viscosity slippery water mentioned in step 2 is 5 mPa·s, and the large discharge capacity mentioned in step 2 refers to a construction discharge capacity of 6 m³ / s. 3 / min.

[0095] Further, the low-viscosity slippery water mentioned in step 2, by mass percentage, comprises: 0.1% acrylamide polymer, 0.15% quaternary ammonium salt clay stabilizer, 0.2% nano-microemulsion, and the balance being water, wherein:

[0096] The nanoemulsion is prepared by mixing dimethylammonium chloride, ethanolamide, and ethanol in a mass ratio of 1:1:100.

[0097] Furthermore, the acid system described in step 3 is a gelling acid system with a viscosity of 30 mPa·s. The gelling acid system was chosen to reduce the acid-rock reaction rate and acid loss, thereby improving acid utilization efficiency.

[0098] Furthermore, the gelling acid system described in step 3, by mass percentage, comprises: 10% of a 25% hydrochloric acid aqueous solution, 1.0% of acrylamide polymer, 3% imidazoline, 0.2% of nanoemulsion, 2% sodium ethylenediaminetetraacetate, 0.15% quaternary ammonium salt clay stabilizer, and the balance being water, wherein:

[0099] The nanoemulsion is prepared by mixing dimethylammonium chloride, ethanolamide, and ethanol in a mass ratio of 1:1:100.

[0100] Further, the temporary plugging agent 8 described in step 4 is composed of viren fibers and temporary plugging particles, wherein:

[0101] The length of the vilan fiber is 8mm;

[0102] The diameter of the temporary plugging particles is 5mm;

[0103] The weight ratio of vilan fibers to temporary plugging particles is 2:1.

[0104] Furthermore, the temporary plugging particles mentioned in step 4 are polyvinyl alcohol.

[0105] Example 3

[0106] A method for acid fracturing network fractures in fractured carbonate reservoirs includes:

[0107] Step 1: Hydraulic fracturing is performed on the target layer fractured carbonate reservoir matrix 9 by injecting cross-linked high-viscosity fracturing fluid to open and establish a long, open, conductive hydraulic main fracture channel 2, extending from the wellbore 1 to a position at a horizontal distance of a meters in the deep formation, where a = 40.

[0108] Step 2: Based on the hydraulic main fracture channel 2 opened in Step 1, low-viscosity slickwater is injected at a large rate along the hydraulic main fracture channel 2. The high net pressure forces the opening of the primary branch fracture 3. At the same time, the low-viscosity slickwater seeps into the initially connected random natural fractures 4, and a preliminary undissolved fracture system is established, consisting of the hydraulic main fracture channel 2, the primary branch fracture 3, and the initially connected random natural fractures 4.

[0109] Step 3: Inject acid solution system to carry out acid dissolution modification of the fracture system. As the amount of injected acid solution increases, acid dissolution and crack widening modification are carried out sequentially on the hydraulic main fracture channel 2, the initial branch fracture 3, and the initially connected random natural fracture 4.

[0110] Step 4: Temporary plugging and acid fracturing are carried out by injecting temporary plugging agent 8 through fracturing fluid. The main purpose is to use temporary plugging agent 8 to dissolve the dominant natural fractures in the fractured carbonate reservoir to form acid wormholes and some branch fractures in multiple stages, so as to force the acid system to communicate and dissolve more natural fractures and branch fracture systems.

[0111] Step 5: Implement alternating injection acid fracturing. Following the first round of acid fracturing completed in steps 1-4, implement the Nth round of injection. By injecting cross-linked high-viscosity fracturing fluid, extend the hydraulic main fracture channel 2 again, resulting in the Nth hydraulic main fracture 5. Extend the hydraulic main fracture channel 2 by (N-1)b meters from its original length of a meters, making the distance between the hydraulic main fracture channel 2 and the Nth hydraulic main fracture 5 a + (N-1)b meters. Then, implement slickwater fracturing to form the Nth branch fracture 6. Simultaneously, low-viscosity slickwater infiltrates the randomly distributed natural fractures 7 that connect to the Nth branch fracture. Then, inject gelling acid to etch the fractures and perform redirecting acid fracturing, forming an acid fracturing network fracture. This increases the effective length of the etched main fracture and the volume of acid fracturing, where: N = 3; b = 30.

[0112] Step 6: Reduce the construction displacement to 3m³ 3 / min, under near-closed pressure conditions, the hydraulic main fracture, branch fracture and natural fracture formed by multiple rounds of alternating acid fracturing are closed and acidized. Through the closed acidizing effect, wide grooves or channels are avoided in the fractures around the well and away from the well. Even when the fracture is closed, the high conductivity can still be maintained by the groove opening state.

[0113] Step 7: After shutting in the well for 3 hours, drain the fluid and start production.

[0114] Furthermore, the viscosity of the cross-linked high-viscosity fracturing fluid described in step 1 is 400 mPa·s.

[0115] Further, the crosslinked high-viscosity fracturing fluid described in step 1 comprises, by mass percentage: 1.2% acrylamide polymer, 0.4% crosslinking agent, 0.3% quaternary ammonium salt clay stabilizer, 0.3% nanoemulsion, and the balance being water, wherein:

[0116] The nanoemulsion is prepared by mixing dimethylammonium chloride, ethanolamide, and ethanol in a mass ratio of 5:5:100.

[0117] Furthermore, the crosslinking agent is a polyol.

[0118] Furthermore, the viscosity of the low-viscosity slippery water mentioned in step 2 is 10 mPa·s, and the large discharge capacity mentioned in step 2 refers to a construction discharge capacity of 10 m³ / s. 3 / min.

[0119] Further, the low-viscosity slippery water mentioned in step 2, by mass percentage, comprises: 0.2% acrylamide polymer, 0.3% quaternary ammonium salt clay stabilizer, 0.3% nano-microemulsion, and the balance being water, wherein:

[0120] The nanoemulsion is prepared by mixing dimethylammonium chloride, ethanolamide, and ethanol in a mass ratio of 5:5:100.

[0121] Furthermore, the acid system described in step 3 is a gelling acid system with a viscosity of 60 mPa·s. The gelling acid system was chosen to reduce the acid-rock reaction rate and acid filtration loss, thereby improving acid utilization efficiency.

[0122] Furthermore, the gelling acid system described in step 3, by mass percentage, comprises: 15% of a 37% hydrochloric acid aqueous solution, 1.2% of acrylamide polymer, 5% imidazoline, 0.3% nano-microemulsion, 3% sodium isoascorbate, 0.3% quaternary ammonium clay stabilizer, and the balance being water, wherein:

[0123] The nanoemulsion is prepared by mixing dimethylammonium chloride, ethanolamide, and ethanol in a mass ratio of 5:5:100.

[0124] Further, the temporary plugging agent 8 described in step 4 is composed of viren fibers and temporary plugging particles, wherein:

[0125] The length of the vilan fiber is 12mm;

[0126] The diameter of the temporary plugging particles is 8mm;

[0127] The weight ratio of vilan fibers to temporary plugging particles is 4:1.

[0128] Furthermore, the temporary plugging particles mentioned in step 4 are polyacrylamide polymers.

[0129] Example 4

[0130] A method for acid fracturing network fractures in fractured carbonate reservoirs includes:

[0131] Step 1: Hydraulic fracturing is performed on the target layer fractured carbonate reservoir matrix 9 by injecting cross-linked high-viscosity fracturing fluid to open and establish a long, open, conductive hydraulic main fracture channel 2, extending from the wellbore 1 to a position at a horizontal distance of a meters in the deep formation, where a = 35.

[0132] Step 2: Based on the hydraulic main fracture channel 2 opened in Step 1, low-viscosity slickwater is injected at a large rate along the hydraulic main fracture channel 2. The high net pressure forces the opening of the primary branch fracture 3. At the same time, the low-viscosity slickwater seeps into the initially connected random natural fractures 4, and a preliminary undissolved fracture system is established, consisting of the hydraulic main fracture channel 2, the primary branch fracture 3, and the initially connected random natural fractures 4.

[0133] Step 3: Inject acid solution system to carry out acid dissolution modification of the fracture system. As the amount of injected acid solution increases, acid dissolution and crack widening modification are carried out sequentially on the hydraulic main fracture channel 2, the initial branch fracture 3, and the initially connected random natural fracture 4.

[0134] Step 4: Temporary plugging and acid fracturing are carried out by injecting temporary plugging agent 8 through fracturing fluid. The main purpose is to use temporary plugging agent 8 to dissolve the dominant natural fractures in the fractured carbonate reservoir to form acid wormholes and some branch fractures in multiple stages, so as to force the acid system to communicate and dissolve more natural fractures and branch fracture systems.

[0135] Step 5: Implement alternating injection acid fracturing. Following the first round of acid fracturing completed in steps 1-4, implement the Nth round of injection. By injecting cross-linked high-viscosity fracturing fluid, extend the hydraulic main fracture channel 2 again, resulting in the Nth hydraulic main fracture 5. Extend the hydraulic main fracture channel 2 by (N-1)b meters from its original length of a meters, making the distance between the hydraulic main fracture channel 2 and the Nth hydraulic main fracture 5 a + (N-1)b meters. Then, implement slickwater fracturing to form the Nth branch fracture 6. Simultaneously, low-viscosity slickwater infiltrates the randomly distributed natural fractures 7 that connect to the Nth branch fracture. Then, inject gelling acid to etch the fractures and perform redirecting acid fracturing, forming an acid fracturing network fracture. This increases the effective length of the etched main fracture and the volume of acid fracturing, where: N = 4; b = 25.

[0136] Step 6: Reduce the construction displacement to 2m 3 / min, under near-closed pressure conditions, the hydraulic main fracture, branch fracture and natural fracture formed by multiple rounds of alternating acid fracturing are closed and acidized. Through the closed acidizing effect, wide grooves or channels are avoided in the fractures around the well and away from the well. Even when the fracture is closed, the high conductivity can still be maintained by the groove opening state.

[0137] Step 7: After shutting in the well for 2.5 hours, drain the fluid and start production.

[0138] Furthermore, the viscosity of the cross-linked high-viscosity fracturing fluid described in step 1 is 300 mPa·s.

[0139] Further, the crosslinked high-viscosity fracturing fluid described in step 1 comprises, by mass percentage: 1% acrylamide polymer, 0.35% crosslinking agent, 0.2% quaternary ammonium salt clay stabilizer, 0.25% nanoemulsion, and the balance being water, wherein:

[0140] The nanoemulsion is prepared by mixing dimethylammonium chloride, ethanolamide, and ethanol in a mass ratio of 2:2:100.

[0141] Furthermore, the crosslinking agent is a polyamine condensation polymer.

[0142] Furthermore, the viscosity of the low-viscosity slippery water mentioned in step 2 is 8 mPa·s, and the large discharge volume mentioned in step 2 refers to a construction discharge volume of 8 m³ / s. 3 / min.

[0143] Further, the low-viscosity slippery water mentioned in step 2, by mass percentage, comprises: 0.15% acrylamide polymer, 0.2% quaternary ammonium salt clay stabilizer, 0.25% nano-microemulsion, and the balance being water, wherein:

[0144] The nanoemulsion is prepared by mixing dimethylammonium chloride, ethanolamide, and ethanol in a mass ratio of 2:2:100.

[0145] Furthermore, the acid system described in step 3 is a gelling acid system with a viscosity of 40 mPa·s. The gelling acid system was chosen to reduce the acid-rock reaction rate and acid loss, thereby improving acid utilization efficiency.

[0146] Furthermore, the gelling acid system described in step 3, by mass percentage, comprises: 12% of a 31% hydrochloric acid aqueous solution, 1.1% of acrylamide polymer, 4% imidazoline, 0.25% nanoemulsion, 2.5% sodium isoascorbate, 0.15–0.3% quaternary ammonium salt clay stabilizer, and the balance being water, wherein:

[0147] The nanoemulsion is prepared by mixing dimethylammonium chloride, ethanolamide, and ethanol in a mass ratio of 2:2:100.

[0148] Further, the temporary plugging agent 8 described in step 4 is composed of viren fibers and temporary plugging particles, wherein:

[0149] The length of the vilan fiber is 10mm;

[0150] The diameter of the temporary plugging particles is 6mm;

[0151] The weight ratio of vilan fibers to temporary plugging particles is 3:1.

[0152] Furthermore, the temporary plugging particles mentioned in step 4 are polyvinyl alcohol.

[0153] The embodiments of the present invention have been described in detail above. However, the present invention is not limited to the above embodiments, and various changes can be made within the scope of knowledge possessed by those skilled in the art without departing from the spirit of the present invention.

Claims

1. A method for constructing acid-fission network fractures in fractured carbonate reservoirs, characterized in that, include: Step 1: Hydraulic fracturing is performed on the target layer fractured carbonate reservoir matrix by injecting cross-linked high-viscosity fracturing fluid to open and establish a long, open, conductive hydraulic main fracture channel, extending from the wellbore to a position at a horizontal distance of a meters in the deep formation, where 30≤a≤40; Step 2: Based on the hydraulic main fracture channel opened in Step 1, low-viscosity slickwater is injected at a large volume along the hydraulic main fracture channel. The high net pressure forces the opening of the primary branch fractures. At the same time, the low-viscosity slickwater seeps into the initially connected random natural fractures, and a preliminary undissolved fracture system is established, consisting of the hydraulic main fracture channel, the primary branch fractures, and the initially connected random natural fractures. Step 3: Inject acid solution system to carry out acid dissolution modification of the fracture system. As the amount of injected acid solution increases, acid dissolution and crack widening modification are carried out sequentially on the main hydraulic fracture channel, the initial branch fracture, and the initially connected random natural fracture. Step 4: Temporary plugging and acid fracturing are carried out by fracturing fluid carrying the injection of temporary plugging agent. The main purpose is to use the temporary plugging agent to dissolve the dominant natural fractures in the fractured carbonate reservoir to form acid wormholes and some branch fractures in multiple stages, forcing the acid system to communicate and dissolve more natural fractures and branch fracture systems. Step 5: Implement alternating injection acid fracturing. Following the first round of acid fracturing in steps 1-4, implement the Nth round of injection. By injecting cross-linked high-viscosity fracturing fluid, extend the hydraulic main fracture channel again, resulting in the Nth hydraulic main fracture. Extend the existing hydraulic main fracture channel length (a meters) by (N-1)b meters, making the distance between the hydraulic main fracture channel and the Nth hydraulic main fracture a + (N-1)b meters. Then, use slickwater to create fractures, forming the Nth branch fracture. Simultaneously, low-viscosity slickwater infiltrates into the randomly distributed natural fractures connected by the Nth branch fracture. Then, inject gelling acid to etch the fractures and perform redirecting acid fracturing, forming an acid fracturing network fracture. This increases the effective length of the etched main fracture and the volume of acid fracturing modification. Specifically: N is a positive integer ≥ 2, and 20 ≤ b ≤ 30; Step 6: Reduce the construction displacement to 1.5-3m³. 3 / min, under near-closed pressure conditions, the hydraulic main fracture, branch fracture and natural fracture formed by multiple rounds of alternating acid fracturing are closed and acidized. Through the closed acidizing effect, wide grooves or channels are avoided in the fractures around the well and away from the well. Even when the fracture is closed, the high conductivity can still be maintained by the groove opening state. Step 7: After shutting in the well for 2-3 hours, drain the fluid and start production, including: The crosslinked high-viscosity fracturing fluid described in step 1 comprises, by mass percentage: 0.8–1.2% acrylamide polymer, 0.3–0.4% crosslinking agent, 0.15–0.3% quaternary ammonium salt clay stabilizer, 0.2–0.3% nanoemulsion, with the balance being water. The nanoemulsion is prepared by mixing dimethylammonium chloride, ethanolamide, and ethanol in a mass ratio of (1-5):(1-5):

100. The crosslinking agent is one of polycarboxylic acids, polyols, or polyamine condensation polymers; The acid system described in step 3 is a gelling acid system. By mass percentage, the gelling acid system comprises: 10%–15% of a 25–37% hydrochloric acid aqueous solution, 1.0–1.2% of acrylamide polymer, 3–5% of imidazoline, 0.2–0.3% of nanoemulsion, 2–3% of sodium ethylenediaminetetraacetate or sodium isoascorbate, 0.15–0.3% of quaternary ammonium salt clay stabilizer, and the balance being water. The nanoemulsion is prepared by mixing dimethylammonium chloride, ethanolamide, and ethanol in a mass ratio of (1-5):(1-5):

100.

2. The method for acid fracturing network fractures in fractured carbonate reservoirs as described in claim 1, characterized in that, The viscosity of the cross-linked high-viscosity fracturing fluid mentioned in step 1 is 200–400 mPa·s, the viscosity of the low-viscosity slickwater mentioned in step 2 is 5–10 mPa·s, and the large discharge rate mentioned in step 2 refers to an operational discharge rate of 6–10 m³ / s. 3 / min.

3. The method for acid fracturing network fractures in fractured carbonate reservoirs as described in claim 1, characterized in that, The low-viscosity slippery water mentioned in step 2, by mass percentage, comprises: 0.1–0.2% acrylamide polymer, 0.15–0.3% quaternary ammonium salt clay stabilizer, 0.2–0.3% nanoemulsion, with the balance being water, wherein: The nanoemulsion is prepared by mixing dimethylammonium chloride, ethanolamide, and ethanol in a mass ratio of (1-5):(1-5):

100.

4. The method for acid fracturing network fractures in fractured carbonate reservoirs as described in claim 1, characterized in that, The viscosity of the gelling acid system described in step 3 is 30–60 mPa·s.

5. The method for acid fracturing network fractures in fractured carbonate reservoirs as described in claim 1, characterized in that, The temporary plugging agent described in step 4 consists of viren fibers and temporary plugging particles, wherein: The length of vilan fibers is 8–12 mm; The diameter of the temporary plugging particles is 5–8 mm; The weight ratio of vilan fibers to temporary plugging particles is (2-4):

1.

6. The method for acid fracturing network fractures in fractured carbonate reservoirs as described in claim 5, characterized in that, The temporary plugging particles mentioned in step 4 are polyvinyl alcohol or polyacrylamide polymers.

7. The method for acid fracturing network fractures in fractured carbonate reservoirs as described in claim 1, characterized in that, The number of rounds N mentioned in step 5 is 2, 3, or 4.

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