A shale oil horizontal well staged fracturing construction method

Abstract

The present application relates to a kind of shale oil horizontal well segmented fracturing construction method, belong to petroleum exploration and development technical field.The present application carries out segmentation to horizontal well, and the continuous sand body with higher mudstone content and lower sandstone content is used as the bridge plug position of each section;Then determine the number and position of perforating cluster in each section, and according to each reservoir parameter in each section, determine the level of the section;Finally, according to the level and perforating cluster number of each section, formulate the fracturing construction pump injection process of each section, and carry out fracturing construction to each section according to the determined fracturing construction pump injection process.Therefore, the present application carries out segmentation to horizontal well, determines the fracturing construction pump injection process and parameter of each section, can carry out corresponding fracturing construction according to the condition of each section, and then improves the yield after fracturing.

Description

Technical Field

[0001] This invention relates to a method for staged fracturing of horizontal wells in shale oil, belonging to the field of petroleum exploration and development technology. Background Technology

[0002] Shale oil reservoirs are characterized by low porosity and low permeability, and are also highly heterogeneous within the formations. This has resulted in a lack of effective production methods for assessing the exploitation potential of shale oil reservoirs. Developing these reservoirs using conventional methods is difficult, making formation fracturing necessary.

[0003] Existing horizontal well fracturing techniques for shale reservoirs mainly include: packer-string segmented fracturing, casing-controlled flow fracturing, bridge plug fracturing, and coiled tubing-driven fracturing. The packer-string segmented fracturing technique utilizes packers to seal each fracturing segment, and the pressure differential from the sandblasting nozzle during operation allows for multi-segment fracturing in a single run. The casing-controlled flow fracturing technique optimizes the number and diameter of perforations to simultaneously open different segments. Its core technology involves accurately calculating inter-layer stress, rationally optimizing the perforation interval, and optimizing the fracturing fluid discharge to ensure the required number of fractures for each segment. This technique is suitable for wells with complex horizontal trajectories and where running the fracturing string into the horizontal section is difficult. The bridge plug fracturing technique utilizes the sealing effect of bridge plugs for segmented fracturing. After fracturing, the bridge plugs can be drilled sequentially through coiled tubing to the artificial bottom of the well, simplifying the operation. The main principle of coiled tubing hydraulic jet fracturing is to perform first-stage fracturing and modification by perforating the horizontal section and then using annular sand injection to seal the fractured layer by injecting sand into the coiled tubing. After the pressure test is passed, the second stage is perforated using coiled tubing hydraulic jet tools, and this process is repeated until the last stage is fracturing.

[0004] However, due to the influence of paleogeological sedimentary environment, shale reservoirs are mainly lacustrine deposits. In lacustrine sedimentary environments, the clay mineral content is high and the mixture of illite and shale is dominant. External fracturing fluids react chemically with clay minerals, and the migration and expansion of clay lead to a decrease in rock permeability, reducing the flow channels for oil and gas. Shale oil reservoirs are formed early, buried at deep depths, have large horizontal stress differences, and high clay content. Shale rocks are fractured in a plastic fractured state, forming single-wing fractures, making it difficult to form complex network fractures. The reservoir fracture range is small, the oil and gas flow range is narrow, and more oil and gas are trapped in the tight reservoir and cannot be extracted.

[0005] Because shale oil reservoirs are characterized by deep rock burial, low permeability, and low porosity, horizontal well drilling is often employed to maximize oil production. This involves drilling long horizontal sections and large-scale fracturing to create extensive artificial fractures across a wide range of length and width, aiming for better economic returns. However, due to limitations imposed by formation dip and drilling technology, the vertical distance between target points A and B in the horizontal section is large (target point A is closer to the wellhead, target point B is closer to the bottom of the well), and target point A is higher than target point B. When the reservoir near target point B is fractured first, the fracturing fluid is difficult to return to the surface due to gravity. Simultaneously, the formation pressure coefficient is typical of ordinary pressure systems; formation pressure alone cannot expel the fracturing fluid from the formation, causing it to remain trapped within the reservoir. This leads to chemical reactions between the fracturing fluid and the reservoir clay, resulting in decreased reservoir permeability and reduced oil and gas flow pathways. During the cementing stage, the cement injected from the surface into the formation between the cemented casing and the formation is affected by gravity and the length of the horizontal section, resulting in a low rate of excellent cement consolidation quality in the horizontal well section. Some locations exhibit poor cementing quality or no cement consolidation. If drilling is carried out in locations with poor or no cement consolidation, high-pressure fluid can damage the casing, leading to well abandonment. Due to the lacustrine sedimentary environment, shale oil reservoirs exhibit uneven oil content and significant differences in oil richness and poorness in the horizontal well section. The reservoir contains both oil-rich and oil-poor reservoirs, and there are also sections with poor casing cement consolidation quality unsuitable for fracturing.

[0006] Therefore, current fracturing methods are not suitable for the horizontal sections of shale reservoirs, as they can easily lead to casing damage and decreased reservoir permeability, thereby affecting oil production. Summary of the Invention

[0007] The purpose of this invention is to provide a method for staged fracturing of shale oil horizontal wells to solve the problems of poor fracturing effect and insignificant increase in oil production in current fracturing operations.

[0008] To solve the above-mentioned technical problems, this invention provides a method for staged fracturing of shale oil horizontal wells, the method comprising the following steps:

[0009] 1) Remove the continuous mudstone section in the horizontal well. On this basis, segment the mudstone-bearing sandstone body and find the continuous sandstone body with high mudstone content and low sandstone content. Use the continuous sandstone body as the interval between the two adjacent ends. Set the bridge plug position of each segment in the continuous sandstone body between the two adjacent segments.

[0010] 2) Determine the number and location of the reservoirs in each segment, as well as the number and location of the perforation clusters, and determine the quality level of the reservoir in each segment based on the parameters of each reservoir.

[0011] 3) Develop a fracturing construction pumping process for each segment based on the quality level and the number of perforation clusters for each segment, and carry out fracturing construction for each segment according to the determined fracturing construction pumping process; the fracturing construction pumping process for each segment includes a formation pretreatment stage, a pre-flush fluid treatment stage, a proppant-carrying fluid treatment stage, and a displacement fluid treatment stage. The pre-flush fluid treatment stage and the proppant-carrying fluid treatment stage are executed alternately in cycles, and the number of cycles is not less than 2.

[0012] Furthermore, the bridge plug is located in a continuous sand body with high mudstone content and low sandstone content, avoiding the location of the casing coupling.

[0013] Furthermore, the number of cycles in the pretreatment and sand-carrying fluid treatment stages is related to the number of perforation clusters in each segment; the more perforation clusters in each segment, the more cycles are required.

[0014] Furthermore, the perforation clusters are selected in the target strata where the sand body has low mud content and high sandstone content.

[0015] Furthermore, during the formation pretreatment, acid is added to the formation or CO2 is injected; the pre-treatment stage refers to the injection of a pre-treatment fluid into the formation, wherein the pre-treatment fluid is low-viscosity slickwater; the sand-carrying fluid treatment stage is used to sequentially inject low-viscosity sand-carrying fluid and high-viscosity sand-carrying fluid into the formation, wherein the low-viscosity sand-carrying fluid is medium-viscosity slickwater, used to control fracture height, expand fracture flow area, and form fracture network, and the high-viscosity sand-carrying fluid is used to control fracture length, wherein high-viscosity slickwater is used.

[0016] Furthermore, the formulation of low-viscosity slippery water is: 0.1%-0.2% thickener + 0.5% clay stabilizer + 0.2% waterproofing agent + 0.2% low-temperature breaking activator + 0.2% penetrant; the formulation of medium-viscosity slippery water is: 0.3%-0.4% thickener + 0.3% clay stabilizer + 0.2% waterproofing agent + 0.3% low-temperature breaking activator + 1% penetrant; and the formulation of high-viscosity slippery water is: 0.5%-0.6% thickener + 0.3% clay stabilizer + 0.2% waterproofing agent + 0.3% low-temperature breaking activator + 1% penetrant.

[0017] Furthermore, the particle size in the pretreatment solution is 70 / 140 mesh, and the particle size of the proppant in the low-viscosity sand-carrying solution is 40 / 70 mesh; the particle size of the proppant in the high-viscosity sand-carrying solution increases from 40 / 70 mesh to 20 / 40 mesh.

[0018] Furthermore, in the determined fracturing construction pumping process for each segment, if the reservoir quality level of that segment is high, CO2 is injected into the formation during formation pretreatment; if the reservoir quality level of that segment is low, acid is injected into the formation during formation pretreatment.

[0019] Furthermore, the classification of each segment is determined based on the organic carbon content, porosity, oil saturation, and brittle minerals in each segment of the reservoir. The higher the organic carbon content, the greater the porosity, the greater the oil saturation, and the more brittle minerals there are, the higher the quality level of that segment of the reservoir.

[0020] The beneficial effects of this invention are as follows: As an improved invention, this invention divides horizontal wells into two stages. First, a continuous mudstone section of a predetermined length is removed to avoid fracturing operations in relatively long mudstone sections. Based on this, continuous sandstone bodies with high mudstone content and low sandstone content are used as the basis for further segmentation. That is, any two adjacent sections contain the aforementioned continuous sandstone body, and the bridge plug position of each section is located within the continuous sandstone body between the adjacent ends. This segmentation method ensures that subsequent perforation clusters are placed in reservoirs with high sandstone content, thereby improving the fracturing effect. Furthermore, this invention formulates a fracturing pumping procedure for each section based on its level and the number of perforation clusters. Fracturing operations are performed on each section according to the determined fracturing pumping procedure, giving each section its own fracturing pumping procedure, further improving the fracturing effect. Attached Figure Description

[0021] Figure 1 This is a plan view of the horizontal section of well No. 1 in an embodiment of the present invention;

[0022] Figure 2 This is a schematic cross-sectional view of the horizontal section of well No. 1 in an embodiment of the present invention;

[0023] Figure 3 This is a schematic diagram of the cluster selection location in the second section of well No. 1 in an embodiment of the present invention;

[0024] Figure 4 This is a schematic diagram of the cluster selection location in the 8th segment of well No. 1 in this embodiment of the invention;

[0025] Figure 5 This is a schematic diagram of the cluster selection location of the 28th segment of well No. 1 in an embodiment of the present invention;

[0026] Figure 6 This is a distribution map of the sweet spot segment of fracturing in Well No. 1 (1HF) in an embodiment of the present invention;

[0027] Figure 7 This is a schematic diagram of the oil and gas reservoir profile of Well No. 1 in an embodiment of the present invention. Detailed Implementation

[0028] The specific embodiments of the present invention will be further described below with reference to the accompanying drawings.

[0029] This invention removes the continuous mudstone section in the horizontal well and then segments the mudstone-bearing sandstone body. The continuous sandstone body with higher mudstone content and lower sandstone content is used as the bridge plug location for each segment. Then, the number and location of reservoirs in each segment are obtained to determine the number and location of perforation clusters, and the level of each segment is determined based on the reservoir parameters. Finally, a fracturing pumping process is formulated for each segment based on its level and the number of perforation clusters, and fracturing is performed on each segment according to the determined fracturing pumping process. The fracturing pumping process for each segment includes a formation pretreatment stage, a pre-flush fluid treatment stage, a proppant-carrying fluid treatment stage, and a displacement fluid treatment stage. The pre-flush fluid treatment stage and the proppant-carrying fluid treatment stage are executed alternately in cycles, with a minimum of two cycles.

[0030] The following detailed description of the specific implementation of this invention uses Well No. 1 as an example. Well No. 1 in this embodiment is a shale oil risk exploration well deployed in a certain depression area. The main drilling objectives of this well are: first, to evaluate the oil and gas content and production capacity of the shale formation; and second, to strive for industrial production capacity and achieve a breakthrough in shale oil production in this depression. Well No. 1 was started on August 15, 2022, with a sidetracking depth of 2403m, target point A depth of 3039.68m, and target point K depth of 3906.60m. Drilling was completed on September 22nd, reaching a depth of 5100m. The horizontal well trajectory is downdipated, with a vertical depth of 2820.21m at target point A and 3182.70m at target point B, a vertical depth difference of 362.49m. The lower oil layer casing (139.7mm) was used for completion, with a casing bottom depth of 5085.79m. The flow-blocking annulus depth is 5036.52m, and the artificial bottom depth is 5028m.

[0031] The basic parameters of Well No. 1 are shown in Table 1. The plan and cross-sectional schematic diagrams of the horizontal section of Well No. 1 are shown in Table 1. Figure 1 , Figure 2 As shown. By Figure 1 As can be seen, the geographical location of Well No. 1 shown in the diagram is... Figure 2 It can be seen that Well No. 1 is horizontal, with target point A marking the beginning of the horizontal section and target point B marking the end. Specifically, the 3039.68-3531 (491.82m long) section is the second sub-layer of the H3Ⅲ2 shale layer; the 3531-4535m (1004m long) section is the third sub-layer of the H3Ⅲ2 shale layer; and the 4535-5100m (565m long) section is also the second sub-layer of the H3Ⅲ2 shale layer. Target point A begins drilling a horizontal section from the second sub-layer of the H3Ⅲ2 shale layer, passes through the third sub-layer of the H3Ⅲ2 shale layer, reaches target point K, and finally ends at target point K within the second sub-layer of the H3Ⅲ2 shale layer. Overall, target points A, K, and B constitute a single horizontal well section.

[0032] Table 1

[0033]

[0034]

[0035] The cementing quality evaluation method SY / T 6592-2016 was used to evaluate the cementing quality of the horizontal section of Well No. 1. If the cementing quality is poor, it indicates that the cement bond between the casing and the formation is not suitable for fracturing. During fracturing, the plugging tools should be positioned in well sections with moderate to good cementing quality.

[0036] Table 2 shows the following statistics based on the cementing quality logging of Well No. 1: For the first interface, 183 layers with good cementation were interpreted, with a cumulative thickness of 732.7m, accounting for 35.8% of the statistical section; 352 layers with moderate cementation were interpreted, with a cumulative thickness of 768m, accounting for 37.5% of the statistical section; and 169 layers with poor cementation were interpreted, with a cumulative thickness of 547.3m, accounting for 26.7% of the statistical section. For the second interface, 75 layers with good cementation were interpreted, with a cumulative thickness of 410.1m, accounting for 20% of the statistical section; 107 layers with moderate cementation were interpreted, with a cumulative thickness of 1329.1m, accounting for 64.9% of the statistical section; and 38 layers with poor cementation were interpreted, with a cumulative thickness of 308.9m, accounting for 15.1% of the statistical section. In the horizontal section, the first interface with good cementing quality accounted for 35.8%, and the second interface accounted for 20%. Poor cementing quality well sections are mainly concentrated in the H3Ⅲ2-③ sublayer 3650-4150m, which has relatively good indications, and there is a risk of inter-section cross-flow and casing deformation.

[0037] Table 2

[0038]

[0039] Based on measured formation pressures from some wells in this area, the pressure coefficient of formation H3Ⅲ is low, as shown in Table 3. The low formation pressure, especially at target point B where the vertical depth is lower than at target point A, hinders the formation energy from expelling hydrated fracturing fluid from the underground rock. Based on the estimated crude oil density from adjacent well No. 2, the density is 0.8606–0.8639 g / cm³. 3 Viscosity 28.26–32.62 mPa·s, gas-oil ratio 46–62 m 3 / t, the crude oil from well No. 2, a neighboring well, had a wax content of 35.66% and a resin and asphalt content of 16.98%, indicating poor fluidity. Well No. 1's target layer exhibits a well-developed layered structure, consisting of lamellar mixed shale. The H3Ⅲ2-③ sublayer in this well has the best physical properties, with an average total porosity of 6.9% and an average effective porosity of 3.78%. The TOC of the H3Ⅲ2-② sublayer in Well No. 1 is relatively high, but the oil saturation and mobile hydrocarbons of the H3Ⅲ2-③ sublayer are relatively better. The average TOC (organic matter) of the H3Ⅲ2-② sublayer is 3.27%, the average S1 (effective source rock) is 2.36%, and the average oil saturation is 48.4%; the average TOC of the H3Ⅲ2-③ sublayer is 2.68%, the average S1 is 2.5%, and the average oil saturation is 52.8%.

[0040] Analysis of elemental logging data shows that layer H3Ⅲ2-② is high in calcium, low in magnesium, and low in clay, while layer H3Ⅲ2-③ is high in magnesium, low in calcium, and high in clay. Overall, layer H3Ⅲ2-② exhibits relatively good brittleness.

[0041] The core rock mechanical parameter test results show that the elastic modulus of the H3Ⅲ2 shale layer ranges from 26.19 to 40.28 GPa (confining pressure 30 MPa), with an average of 32.98 GPa; the Poisson's ratio ranges from 0.235 to 0.279 (confining pressure 30 MPa), with an average of 0.257; and the mechanical brittleness index ranges from 0.42 to 0.50, with an average of 0.45. Overall, the target layer rock exhibits characteristics of moderate elastic modulus, high Poisson's ratio, and low mechanical brittleness index, indicating that plastic failure is the predominant mode.

[0042] Based on the core rock stress test results, the target layer is in a normal fault stress state: vertical stress > maximum horizontal principal stress > minimum horizontal principal stress. The maximum horizontal principal stress is 67.41–69.8 MPa, the minimum horizontal principal stress is 57.93–58.94 MPa, and the stress gradient is 2.08–2.11 MPa / 100m. The horizontal stress difference is 8.91–9.64 MPa, with an average of 9.4 MPa; the stress difference coefficient is 0.16. Under the confining pressure (30 MPa) of Well No. 1, the Young's modulus and Poisson's ratio are higher, the tensile strength and fracture toughness are greater, and the horizontal stress difference is larger. In summary, it can be concluded that the formation of complex fractures in Well No. 1 is difficult, and fracturing is relatively challenging.

[0043] Therefore, in this embodiment, the shale oil horizontal well segmented fracturing construction method of the present invention is applied to well No. 1 to verify the effect of the present invention.

[0044] 1. The horizontal well section is segmented.

[0045] Segmentation refers to dividing a horizontal well section into several large segments using bridge plug packers.

[0046] First, a mudstone sandstone section with high mud content and a certain continuous length was selected as the boundary section for initial segmentation. Based on the mudstone content and the length of the mudstone section, the horizontal section of Well No. 1 (1HF) was roughly divided into four major sections. Figure 6 This is a distribution map of the sweet spot sections in fracturing well No. 1 (1HF). The first row of mudstone sections is shown between sections 12 and 11, 9 and 8, 5 and 4, and 2 and 1. High mudstone content is defined as an API gamma value > 120 (a higher gamma value indicates higher mudstone content), interpreted as mudstone content > 20%, permeability < 0.01 Md, and porosity < 5%. In this embodiment, a certain continuous length of mudstone sand body refers to a mudstone sand body with a length > 20 m.

[0047] Segment 1: 5018-4996m, Segment 2: 4977-4944m, the distance between 4996-4977m is the first row of mudstone between Segment 2 and Segment 1. Segment 5: 4804-4751m, Segment 4: 4871-4818m, the distance between 4818-4804m is the first row of mudstone between Segment 4 and Segment 5. Segment 9: 4544-4486m, Segment 8: 4611-4565m, the distance between 4565-4544m is the first row of mudstone between Segment 4 and Segment 5. Segment 12: 4355-4323m, Segment 11: 4407-4370m, the distance between 4370-4355m is the first row of mudstone between Segment 12 and Segment 11.

[0048] Secondly, after separating the long mudstone section, the remaining part is a sandstone body section with a high proportion of sandstone and low mudstone content. Then, the mudstone-bearing sandstone body section of a certain continuous length is further segmented. Among them, the mudstone content is low, with a well logging gamma value API value of 90-120 (the smaller the gamma value, the lower the mudstone content and the higher the sandstone content). Well logging interpretation shows a mudstone content of 5-15%, permeability of 0.01-0.1 Md, and porosity of 6-15%. In this embodiment, the length of the mudstone-bearing sandstone body of a certain continuous length is 20-70m.

[0049] Based on the initial segmentation, the mudstone-bearing sandstone body is further subdivided. Specifically, this involves identifying continuous sandstone bodies with high mudstone content and low sandstone content within each segment of the initial segmentation. These continuous sandstone bodies serve as the basis for further segmentation (secondary segmentation), ensuring that adjacent segments are continuous sandstone bodies after the secondary segmentation. The bridge plugs for adjacent segments are also located within these continuous sandstone bodies to achieve sealing between fracturing stages and segments. The continuous sandstone bodies with high mudstone content and low sandstone content exhibit the following characteristics: API gamma value of 110-120, interpreted mudstone content of 10-15%, permeability of 0.01-0.05 Md, porosity of 6-8%, and sandstone body length of 5-20 m.

[0050] like Figure 7 As shown, in this embodiment, the measured depth at target point A in well No. 1 is 3039.68m, and the completed well depth is 5100m. The total length of its horizontal section (target point A to the bottom of the well) is 2060.32m. In this embodiment, the total length of the 2060.32m horizontal section (target point A to the bottom of the well) in well No. 1 is divided into 33 segments. In this embodiment, a continuous sand body with high mudstone content and low sandstone content is selected as the location for the bridge plug to be installed. The sand body characteristics within the range of the bridge plug installation location are as follows: API gamma value 110-120, interpreted mudstone content 10-15%, permeability 0.01-0.05Md, porosity 6-8%, and sand body length 5-20m.

[0051] 2. Determine the location of the perforation clusters in each segment.

[0052] After segmentation, each segment's sand body is selected as the target layer for perforation clusters, characterized by low clay content and high sandstone content. Clustering refers to selecting several specific small locations within a large segment for perforation. These specific small perforation locations are determined based on well logging data. The selection criteria for clustering are: 1) Perforation points should avoid casing coupling locations; 2) Perforation points should be selected as much as possible in well sections with high gamma rays, high resistivity, high gas logging anomalies, and relatively high oil saturation index.

[0053] In this embodiment, the sandstone characteristics of each segment are as follows: API gamma value of 90-110, interpreted clay content of 5-10%, permeability of 0.3-0.9 Md, porosity of 10-15%, and length of 15-50 m. Therefore, each cluster may have multiple perforation points, which should avoid the casing coupling location; perforation points should be selected as much as possible in well sections with high gamma, high resistivity, high gas logging anomalies, and relatively high oil saturation index.

[0054] In this embodiment, the overall electrical properties of the shale oil in the depression area are characterized by "four highs and one low," namely, high resistivity, high acoustic intensity, high neutron content, high gamma ray density, and low density. Based on the characteristics of the shale reservoirs in the Biyang Depression, interpretation models for key parameters such as porosity, organic carbon content, oil saturation, brittle mineral content, and brittleness index were established. The shale reservoirs in the Biyang Depression were classified according to well logging classification and evaluation standards, as shown in Table 3.

[0055] Table 3

[0056]

[0057] The shale layers were divided into three categories: Category I (good), Category II (medium), and Category III (poor). The Yangye Oil 1HF well interpreted a total of 82 layers: Category I shale oil layers (1648.2m / 29 layers); Category II shale oil layers (771.7m / 35 layers); dry layers (47.2m / 9 layers); and water-bearing layers (44m / 9 layers). Within the target layer's horizontal section (2982-5081 meters): Category I shale oil layers (1501.2m / 21 layers, accounting for 71.52%); and Category II shale oil layers (597.8m / 20 layers, accounting for 28.48%).

[0058] Based on the above data, the position of each cluster in each segment can be determined, with the cluster positions in segments 2, 8, and 28 as follows: Figure 3 , Figure 4 and Figure 5 As shown in Table 4, the clustering optimization results for each segment are as follows.

[0059] Table 4

[0060]

[0061]

[0062]

[0063]

[0064]

[0065]

[0066]

[0067]

[0068] The segment numbers in Table 4 start from the deep bottom of the horizontal well and move towards the shallow top, with the deepest segment being No. 1 and the shallowest being No. 33; (interpretation conclusion level 1 = Class I (good), 2 = Class II (medium), 3 = Class III (poor)). Cluster numbers: from shallow to deep, 1, 2, 3, 4...; perforation upper boundary (deep position, m) - perforation lower boundary (shallow position, m) = perforation length (m); number of perforation guns perforating the casing = perforation length (m) × 16 perforation guns / m; number of perforation clusters = number of cluster numbers in this segment. In embodiment 1 of this invention, the fracturing of well No. 1, from the 2nd to the 33rd segment, all used soluble bridge plugs placed inside the casing as the tool for implementing segmented and clustered volumetric fracturing. This well mainly used 3 to 6 clusters of perforation, using 60° phase angle spiral perforation. The first segment used continuous tubing for perforation, and the remaining segments used cable-driven bridge plug perforation. The perforation parameters are shown in Table 5.

[0069] Table 5

[0070]

[0071]

[0072] 3. Develop a fracturing construction pumping process for each segment based on the level and number of perforation clusters, and carry out fracturing construction for each segment according to the determined fracturing construction pumping process; the fracturing construction pumping process for each segment includes a formation pretreatment stage, a pre-flush fluid treatment stage, a proppant-carrying fluid treatment stage, and a displacement fluid treatment stage.

[0073] The formation pretreatment stage is used to pretreat the formation, which can be achieved by injecting acid or CO2 into the formation. The pre-fluid treatment stage involves injecting a pre-fluid into the formation to form formation fractures. The proppant-carrying fluid treatment stage is used to support the formed fractures. The displacement fluid treatment stage is used for liquid displacement. During formation pretreatment, acid is added to the formation or CO2 is injected. The pre-fluid treatment stage refers to the injection of a pre-fluid, which uses low-viscosity slickwater. The proppant-carrying fluid treatment stage involves sequentially injecting low-viscosity proppant-carrying fluid and high-viscosity proppant-carrying fluid into the formation. The low-viscosity proppant-carrying fluid uses medium-viscosity slickwater to control fracture height, expand fracture flow area, and form a fracture network. The high-viscosity proppant-carrying fluid uses high-viscosity slickwater to control fracture length. The particle size in the pretreatment solution is 70 / 140 mesh, and the particle size of the proppant in the low-viscosity sand solution is 40 / 70 mesh; the particle size of the proppant in the high-viscosity sand solution increases from 40 / 70 mesh to 20 / 40 mesh, wherein the 70 mesh is a sieve with an aperture of 0.212 mm, and the 20 mesh is a sieve with an aperture of 0.850 mm.

[0074] The formula for low-viscosity slippery water is: 0.1%-0.2% thickener + 0.5% clay stabilizer + 0.2% waterproofing agent + 0.2% low-temperature gel breaking activator + 0.2% penetrant;

[0075] The formula for medium-viscosity slippery water is: 0.3%-0.4% thickener + 0.3% clay stabilizer + 0.2% waterproofing agent + 0.3% low-temperature debonding activator + 1% penetrant;

[0076] The formula for high-viscosity slippery water is: 0.5%-0.6% thickener + 0.3% clay stabilizer + 0.2% waterproofing lock agent + 0.3% low-temperature debonding activator + 1% penetrant.

[0077] This embodiment specifies a corresponding fracturing construction pumping process for each segment. Since there are a total of 33 segments, three segments are selected for explanation below. For greater representativeness, the three segments are selected for different quality levels. Segment 2 is selected as the representative of level III, segment 8 as the representative of level II, and segment 28 as the representative of level I. The fracturing construction pumping processes for segments 2, 8, and 28 are shown in Tables 6, 7, and 8, respectively.

[0078] Table 6

[0079]

[0080] Table 7

[0081]

[0082] Table 8

[0083]

[0084] In Tables 6-8, the term "top adhesive" refers to the liquid used as a separator between the two stages. It is a highly viscoelastic, gel-like liquid that acts as a sealant. The process is as follows: Stage 1 pumping pre-treated formation + intermediate displacement liquid + Stage 2 pumping liquid and proppant + intermediate displacement liquid + and so on; the "adhesive" consists of 0.8%-1% thickener + 0.3% clay stabilizer + 0.2% waterproofing lock agent + 0.3% low-temperature gel breaking activator.

[0085] In the determined fracturing pumping process for each segment, if the reservoir quality level is high, CO2 is injected into the formation during formation pretreatment; if the reservoir quality level is low, acid is injected into the formation during formation pretreatment. Since the dolomitic limestone content in the target layer (4535-5028m) of Well 1 in this embodiment is 13.6-31%, acid treatment can effectively connect natural pores in the dolomitic limestone reservoir, effectively reduce the rock modulus, and lower the fracturing pressure; it also has a good dissolving and unblocking effect on the plugging agent during drilling. Optimization is only applied to the first 5 segments of the pre-fracturing operation (4535-5028m), using pre-fracturing acid to reduce fracturing pressure, optimizing each segment by 25-30m. 3 The preferred acid formulation is: 10% HCl + 2% acid corrosion inhibitor + 2% iron ion stabilizer + 1% clay stabilizer. The diluted acid for field use must meet the following technical specifications: (1) a uniform liquid appearance, completely soluble in water; (2) an organochlorine content of 0; (3) a static corrosion rate of ≤5g / (m³) at 90℃ and normal pressure. 2 .h).

[0086] In this embodiment, Well No. 1 has a highly stress-sensitive reservoir and weak crude oil fluidity. Therefore, maintaining a certain conductivity and extending the effective time of fractures are key to stable production. High-volume, small-particle-size quartz sand is used for proppant application, reducing proppant settling and allowing for wider placement, thus effectively supporting distal fractures. Large-particle-size quartz sand provides strong support for the main fractures, achieving the goal of full support for the multi-level fracture network. Considering the support requirements for different fracture sizes, the main body uses two proppant particle sizes: 70 / 140 mesh and 40 / 70 mesh, to saturate fractures of different scales and reduce the adverse effects of particle size mixing on conductivity. Small-particle-size, low-ratio sand (70 / 140 mesh quartz sand) is used for grinding, filtration, and supporting micro-fractures; long stubs (40 / 70 mesh quartz sand) are used to support branch fractures with a certain conductivity; and high-ratio sand (40 / 70 mesh ceramsite) supports the formation of high-conductivity main fractures.

[0087] When performing fracturing and pumping operations according to the above-described procedure, the slurry enters multiple perforation clusters during the first fracturing operation. Because the permeability of the sand bodies corresponding to these perforation clusters differs, more slurry enters the sand bodies with higher permeability after the first fracturing, and less enters the sand bodies with lower permeability. Therefore, a secondary fracturing operation is employed, involving the insertion of temporary plugging balls. During the secondary fracturing, the plugging balls flow with the slurry to the perforation clusters with higher permeability and block the perforations at these clusters on the casing wall. This forces subsequent secondary fracturing to allow the slurry to enter the perforation clusters with relatively lower permeability, ultimately achieving the goal of uniformly modifying multiple perforation clusters. The standard for adding plugging balls is when the permeability difference between each cluster is more than three times; at this point, more slurry enters the sand bodies with higher permeability, and less enters the sand bodies with lower permeability. In this embodiment of the invention, the standard for adding plugging balls is to add them when there are 5-6 perforation clusters, and not to add them when there are 4 clusters. Taking the fracturing and pumping procedure of the third stage of Well No. 1 as an example, 21 plugging balls were inserted. The relationship between the number of temporary plugging balls and the sealing of perforations is as follows: Number of temporary plugging balls / 16 (holes / m) = Sand body thickness to be sealed. The number of temporary plugging balls is based on the perforation standard: 1m of sand body thickness corresponds to 16 perforating balls, and 16 perforating balls correspond to 16 perforations. 21 temporary plugging balls would seal a perforation with a sand body thickness of 1.3m. A 1.3m layer corresponds to a reservoir with relatively good physical properties, allowing for the introduction of more slurry.

[0088] Temporary plugging agents can also be added as needed. These agents are in granular form and can enter the formation with the fluid, forming a plugging layer within the high-porosity, high-permeability fluid flow channels. This plugging layer has lower permeability than the surrounding formation, forcing subsequent fluids to divert to formations with lower permeability, opening fractures in different directions and increasing the fracture area. The fracturing parameters for each section of Well No. 1 are shown in Table 9.

[0089] Table 9

[0090]

[0091]

[0092] This application classifies shale reservoirs into three different types and employs differentiated fracturing techniques for each type, thereby generally improving oil production from both rich and poor reservoirs. By using different combinations of fracturing materials, such as acid, CO2, fracturing fluid, interstitial plugging agent, and plugging balls to seal perforations, and employing three different combinations of pumping materials, pumping rates, and pumping fluid volumes for the three types of reservoirs with different characteristics, oil well production is increased.

[0093] To better illustrate the effects of the present invention, well No. 2 is used as a comparative example, and existing mining technology is applied to well No. 2.

[0094] Well No. 2 is located northeast of the wellhead of the pilot well No. 1. It is a shale oil horizontal well with a horizontal section length of 1402.00m. The unconventional interpretation shows a favorable shale oil and gas layer of 1636.70m / 10 sections. The target layer of this well corresponds to layer HⅢ2 in the pilot well No. 1, with an effective horizontal section length of 1344.10m. The "easy-drill bridge plug sealing-cluster perforation combined operation" technology was employed, and fracturing operations were carried out in 21 sections. During the self-flowing stage, the highest daily oil production was 4.8m³. 3 (Liquid volume 33m 3 The plant began trial production after pressure reduction on January 31, 2013, with a maximum daily oil production of 28.1 m³. 3 The cumulative oil production was 2945.54 tons (41.87 tons during the trial production phase and 2903.67 tons during the production phase). The well was shut down in July 2017, with a daily oil production of 0.3 tons (liquid volume 4.8m³) before shutdown. 3 ).

[0095] Following the fracturing operation as described in this embodiment, the newly drilled Well No. 1 began flowback of fracturing fluid on August 21, 2023, and completed flowback on September 11. Oil production began on September 12, 2023. Under surface flow conditions, the initial daily oil production was 4.1 cubic meters / day and the daily fluid production was 41 cubic meters / day. By November 27, 2023, under surface flow conditions, the daily oil production was 8.3 cubic meters / day and the daily fluid production was 25 cubic meters / day. In the 90 days following fracturing, a total of 446.8 cubic meters of oil and 2674 cubic meters of fluid were produced. It is evident that the fracturing operation method of this invention can effectively fracture and transform Well No. 1, significantly increasing its oil production.

Claims

1. A method for staged fracturing construction of shale oil horizontal wells, characterized in that, The method includes the following steps: 1) Remove the continuous mudstone section in the horizontal well. On this basis, segment the mudstone-bearing sandstone body and find the continuous sandstone body with high mudstone content and low sandstone content. Use the continuous sandstone body as the interval between two adjacent segments. Set the bridge plug position of each segment in the continuous sandstone body between the two adjacent segments. 2) Obtain the number and location of reservoirs in each segment to determine the number and location of perforation clusters, and determine the quality level of the reservoir in each segment based on the parameters of each reservoir. The classification of each segment is determined based on the organic carbon content, porosity, oil saturation and brittle minerals in each segment of the reservoir. The higher the organic carbon content, the greater the porosity, the greater the oil saturation and the more brittle minerals, the higher the quality level. 3) Develop a fracturing pumping procedure for each segment based on its quality level and the number of perforation clusters. Perform fracturing operations on each segment according to the determined fracturing pumping procedure. The fracturing pumping procedure for each segment includes a formation pretreatment stage, a pre-flush fluid treatment stage, a proppant-carrying fluid treatment stage, and a displacement fluid treatment stage. If the reservoir quality level of the segment is high, CO2 is injected into the formation during formation pretreatment. If the reservoir quality level of the segment is low, acid is injected into the formation during formation pretreatment. The pre-flush fluid treatment stage and the proppant-carrying fluid treatment stage are executed alternately in cycles, and the number of cycles is not less than 2. The number of cycles for the pre-flush fluid treatment stage and the proppant-carrying fluid treatment stage is related to the number of perforation clusters in each segment. The more perforation clusters in each segment, the more cycles are required.

2. The method for staged fracturing of shale oil horizontal wells according to claim 1, characterized in that, The bridge plug is located in a continuous sand body with high mudstone content and low sandstone content, avoiding the location of the casing coupling.

3. The method for staged fracturing of shale oil horizontal wells according to claim 1, characterized in that, A higher well logging gamma value indicates a higher mudstone content; a lower well logging gamma value indicates a lower mudstone content and a higher sandstone content.

4. The method for staged fracturing of shale oil horizontal wells according to claim 1, characterized in that, The perforation clusters are selected in the target strata where the sand body has low mud content and high sandstone content.

5. The method for staged fracturing of shale oil horizontal wells according to claim 1, characterized in that, During the formation pretreatment, acid is added to the formation or CO2 is injected. The pre-fluid treatment stage refers to the injection of a pre-fluid into the formation, which is a low-viscosity slickwater. The sand-carrying fluid treatment stage involves sequentially injecting a low-viscosity sand-carrying fluid and a high-viscosity sand-carrying fluid into the formation. The low-viscosity sand-carrying fluid is a medium-viscosity slickwater used to control fracture height, expand fracture flow area, and form a fracture network. The high-viscosity sand-carrying fluid is used to control fracture length and is a high-viscosity slickwater.

6. The method for staged fracturing of shale oil horizontal wells according to claim 5, characterized in that, The formulation of low-viscosity slippery water is: 0.1%-0.2% thickener + 0.5% clay stabilizer + 0.2% waterproofing agent + 0.2% low-temperature breaking activator + 0.2% penetrant; the formulation of medium-viscosity slippery water is: 0.3%-0.4% thickener + 0.3% clay stabilizer + 0.2% waterproofing agent + 0.3% low-temperature breaking activator + 1% penetrant; the formulation of high-viscosity slippery water is: 0.5%-0.6% thickener + 0.3% clay stabilizer + 0.2% waterproofing agent + 0.3% low-temperature breaking activator + 1% penetrant.

7. The method for staged fracturing of shale oil horizontal wells according to claim 5, characterized in that, The particle size in the pretreatment solution is 70 / 140 mesh, and the particle size of the proppant in the low-viscosity sand-carrying solution is 40 / 70 mesh; the particle size of the proppant in the high-viscosity sand-carrying solution increases from 40 / 70 mesh to 20 / 40 mesh.

8. The method for staged fracturing of shale oil horizontal wells according to claim 1, characterized in that, When carrying out hydraulic fracturing, a combination of secondary fracturing and temporary plugging ball placement is adopted.

9. The method for staged fracturing of shale oil horizontal wells according to claim 8, characterized in that, The standard for adding temporary blocking balls is that the permeability of each cluster differs by more than three times.

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