Shale oil horizontal well staged fracturing construction method

Abstract

The invention relates to a staged fracturing construction method for a shale oil horizontal well, and belongs to the technical field of oil exploration and development. According to the method, the horizontal well is segmented, and a continuous sand body with the high mudstone content and the low sandstone content serves as the bridge plug position of each segment; then determining the number and the position of perforation clusters in each section, and determining the level of the section according to each reservoir parameter in each section; and finally, according to the level of each section and the number of perforation clusters, a fracturing construction pump injection process of each section is formulated, and fracturing construction is conducted on each section according to the determined fracturing construction pump injection process. Therefore, the horizontal well is segmented, the fracturing construction pumping flow and parameters of each segment are determined, corresponding fracturing construction can be carried out according to the condition of each segment, and then the yield after fracturing is improved.

Description

Technical Field

[0001] The invention relates to a staged fracturing construction method for a shale oil horizontal well, belonging to the technical field of petroleum exploration and development. Background Art

[0002] Shale reservoirs are characterized by low porosity and permeability, as well as strong intra-layer heterogeneity. This has led to a lack of effective production methods for evaluating their potential. Conventional development of these reservoirs is difficult, necessitating the use of hydraulic fracturing to stimulate the formation.

[0003] Existing horizontal well fracturing technologies for shale reservoirs include: packer string staged fracturing, casing flow restriction fracturing, bridge plug fracturing, and coiled tubing drag fracturing. The principle of the packer string staged fracturing process is to use packers to seal each fractured zone, and then set the seal by throttling the sandblaster during the operation. This allows for fracturing multiple sections in a single run. The principle of the casing flow restriction fracturing process is to simultaneously open different sections by optimizing the number and size of perforations. Its core technology lies in accurately calculating interlayer in-situ stresses, rationally optimizing perforation sections, and optimizing the design of fracturing fluid flow rates to ensure the required number of fractures in each section. This technology is suitable for wells with complex horizontal sections and difficult to reach horizontal sections. The bridge plug fracturing process utilizes the sealing effect of bridge plugs to implement staged fracturing. After fracturing, the bridge plugs can be drilled sequentially to the bottom of the well using coiled tubing, simplifying the operation process. The main principle of coiled tubing hydraulic jet fracturing technology is to implement the first layer fracturing transformation by using the annular sand adding method on the basis of perforating the horizontal section, and then inject sand into the coiled tubing to form a sand plug to seal the already fracturing layer. After the pressure test is qualified, the coiled tubing hydraulic jet tool is used to perforate the second layer, and this cycle is repeated until the last layer is fractured.

[0004] However, due to the influence of the ancient geological sedimentary environment, shale reservoirs are mainly lake-phase deposits with high clay mineral content and mainly illite-montmorillonite mixed layers. External fracturing fluids react chemically with clay minerals, and clay migration and expansion lead to a decrease in rock permeability, reducing oil and gas flow channels. Shale oil reservoirs are formed early, have deep burial depths, large horizontal stress differences, and high clay content. Shale rocks are plastically damaged by fracture, forming single-wing fractures, which are 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 tight reservoirs and cannot be mined.

[0005] Because shale reservoirs are characterized by deep rock burial depth, low permeability, and low porosity, horizontal well drilling is often used to maximize oil production. By drilling long horizontal sections and conducting large-scale fracturing stimulation, a wide range of artificial fractures is created across a wide range of lengths and widths, hoping to achieve better economic returns. However, due to limitations in formation inclination and drilling technology, the vertical distance between target points A and B in the horizontal drilling 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, gravity affects the fracturing fluid, making it difficult to return to the surface. Furthermore, the formation pressure coefficient is typical of a normal pressure system, making it impossible to expel the fracturing fluid from the formation solely by relying on formation pressure. This causes the fracturing fluid to remain within the reservoir, chemically reacting with the reservoir clay, reducing reservoir permeability and restricting oil and gas flow paths. During the cementing phase, cement injected from the surface into the gap between the casing and the formation is affected by gravity and the length of the horizontal section, resulting in a low rate of good cement consolidation quality in the horizontal well section, with some areas experiencing poor or no cement consolidation. If construction is carried out in areas with poor or no cement consolidation, high-pressure fluid can squeeze and damage the casing, rendering the well useless. Due to the lacustrine sedimentary environment, shale reservoirs have an uneven distribution of oil content and a large disparity between rich and poor reservoirs. Within the horizontal well section, there are both oil-rich and oil-poor reservoirs, as well as areas with poor casing cement quality that are unsuitable for fracturing.

[0006] Therefore, the current fracturing construction method is not suitable for the horizontal section of the shale reservoir, which can easily lead to casing damage in the horizontal section of the shale reservoir and a decrease in reservoir permeability, thereby affecting oil production. Summary of the Invention

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

[0008] In order to solve the above technical problems, the present invention provides a shale oil horizontal well staged fracturing construction method, which includes the following steps:

[0009] 1) Remove the continuous length of mudstone in the horizontal well. On this basis, segment the sandstone body containing mudstone to find a continuous sand body with high mudstone content and low sandstone content. Use the continuous sand body as the interval between the two adjacent ends, and set the bridge plug of each section in the continuous sand body between the two adjacent sections;

[0010] 2) Obtain the number and location of reservoirs in each section to determine the number and location of perforation clusters, and determine the quality level of the reservoir in each section based on the parameters of each reservoir in the section;

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

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

[0013] Furthermore, the number of cycles of the pre-fluid treatment stage and the sand-carrying fluid treatment stage is related to the number of perforation clusters in each section. The more perforation clusters in each section, the more cycles there are.

[0014] Furthermore, the perforation cluster is selected in a target layer where a sand body with low mud content and high sandstone content is located.

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

[0016] Furthermore, the formula of low-viscosity slippery water is: 0.1%-0.2% thickener + 0.5% clay stabilizer + 0.2% waterproof lock agent + 0.2% low-temperature gel breaker activator + 0.2% bleaching agent; the formula of medium-viscosity slippery water is: 0.3%-0.4% thickener + 0.3% clay stabilizer + 0.2% waterproof lock agent + 0.3% low-temperature gel breaker activator + 1% bleaching agent; the formula of high-viscosity slippery water is: 0.5%-0.6% thickener + 0.3% clay stabilizer + 0.2% waterproof lock agent + 0.3% low-temperature gel breaker activator + 1% bleaching agent.

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

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

[0019] Furthermore, the classification of each section is determined based on the organic carbon content, porosity, oil saturation and brittle minerals in each reservoir section. 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 of the reservoir section.

[0020] The beneficial effects of the present invention are as follows: as an improved invention, the present invention divides the horizontal well into two stages, first removing the set continuous length mudstone section to avoid fracturing construction in the relatively long mudstone section, and on this basis, taking the continuous sand body with higher mudstone content and lower sandstone content as the basis for fine segmentation, that is, any two adjacent sections have the said continuous sand body, and the bridge plug position of each section is in the continuous sand body between the adjacent two ends; through this segmentation method, it can be ensured that the positions of the subsequent perforation clusters are all in the reservoir with higher sandstone content, thereby improving the fracturing effect. In addition, the present invention formulates the fracturing construction pumping process for each section according to the level of each section and the number of perforation clusters, and performs fracturing construction on each section according to the determined fracturing construction pumping process, so that each section has its own fracturing construction pumping process, further improving the fracturing effect. BRIEF DESCRIPTION OF THE DRAWINGS

[0021] Figure 1 1 is a schematic plan view of the horizontal section of Well No. 1 according to an embodiment of the present invention;

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

[0023] Figure 3 This is a schematic diagram of the cluster selection position of 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 position of the 8th section of Well No. 1 in an embodiment of the present invention;

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

[0026] Figure 6 This is a distribution diagram of the fracturing sweet spot of Well 1 (1HF) in an embodiment of the present invention;

[0027] Figure 7 It is a schematic cross-sectional view of the oil and gas reservoir of Well No. 1 in an embodiment of the present invention. DETAILED DESCRIPTION

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

[0029] The present invention removes a set continuous length of mudstone section in a horizontal well, and on this basis, divides the sandstone sand body containing mudstone into sections, and uses the continuous sand body with higher mudstone content and lower sandstone content as the bridge plug position of each section; then, the number and position of the reservoirs in each section are obtained to determine the number and position of the perforation clusters, and the level of the section is determined according to the parameters of each reservoir in each section; finally, a fracturing construction pumping process for each section is formulated according to the level of each section and the number of perforation clusters, and fracturing construction is carried out on each section according to the determined fracturing construction pumping process; the fracturing construction pumping process for each section includes a formation pretreatment stage, a pre-fluid treatment stage, a sand-carrying fluid treatment stage and a displacement fluid treatment stage, and the pre-fluid treatment stage and the sand-carrying fluid treatment stage are executed alternately in a cycle, and the number of cycles is not less than 2.

[0030] The specific implementation method of the present invention is described in detail below using 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 layer; second, to strive to obtain industrial production capacity and achieve a breakthrough in shale oil in the depression. Well No. 1 was drilled on August 15, 2022. The side drilling point depth was 2403m, the A target point depth was 3039.68m, and the K target point depth was 3906.60m. On September 22, the well was deepened to a depth of 5100m and completed. The horizontal well trajectory is downward-inclined, with a vertical depth of 2820.21m for the A target point and 3182.70m for the B target point, with a vertical depth difference of 362.49m. The well was completed with the lower oil layer casing (139.7mm), and the casing bottom depth was 5085.79m. The choke ring depth was 5036.52m, and the artificial well bottom was 5028m.

[0031] The basic parameters of Well 1 are shown in Table 1. The horizontal section of Well 1 is shown in the plan and cross-sectional diagrams. Figure 1 、 Figure 2 As shown. Figure 1 It can be seen that the geographical location of Well No. 1 is shown in the figure. Figure 2 As can be seen, Well 1 is horizontal, with Target A marking the beginning of the horizontal section and Target B marking the end. The 3039.68-3531 m (491.82 m long) section is located in the H3III2 shale layer, Sublayer ②; the 3531-4535 m (1004 m long) section is located in the H3III2 shale layer, Sublayer ③; and the 4535-5100 m (565 m long) section is located in the H3III2 shale layer, Sublayer ②. Target A began drilling in Sublayer ② of the H3III2 shale layer, passed through Sublayer ③ of the H3III2 shale layer, and reached Target K. Finally, drilling concluded at Target K in Sublayer ② of the H3III2 shale layer. Targets A, K, and B form a single horizontal well section.

[0032] Table 1

[0033]

[0034]

[0035] The cementing quality of the horizontal section of Well 1 was evaluated using the cementing quality evaluation method SY / T 6592-2016. Poor cementing quality indicates that the cement bond between the casing and the formation is not suitable for fracturing. During fracturing, the plugging tool should be inserted in the well section with medium to good cementing quality.

[0036] Table 2 shows that, based on the statistics of cementing quality logging in Well 1, there are 183 well-interpreted layers with good cementation at the first interface, with a cumulative thickness of 732.7 m, accounting for 35.8% of the analyzed section; 352 layers with moderately interpreted cementation, with a cumulative thickness of 768 m, accounting for 37.5% of the analyzed section; and 169 layers with poorly interpreted cementation, with a cumulative thickness of 547.3 m, accounting for 26.7% of the analyzed section. There are 75 well-interpreted layers with good cementation at the second interface, with a cumulative thickness of 410.1 m, accounting for 20% of the analyzed section; 107 layers with moderately interpreted cementation, with a cumulative thickness of 1329.1 m, accounting for 64.9% of the analyzed section; and 38 layers with poorly interpreted cementation, with a cumulative thickness of 308.9 m, accounting for 15.1% of the analyzed section. In the horizontal section, 35.8% of the first interface and 20% of the second interface have good cementation quality. The well sections with poor cementing quality are mainly concentrated in the H3Ⅲ2-③ sublayer with relatively good performance, ranging from 3650 to 4150 m, and there is a risk of pressure channeling between sections and casing change.

[0037] Table 2

[0038]

[0039] Based on the measured formation pressure of some wells in this area, the pressure coefficient of the H3III layer is relatively low. The specific data are shown in Table 3. The low formation pressure, especially the vertical depth of target B is lower than that of target A, is not conducive to the formation energy to return the hydrated fracturing fluid from the underground rock to the formation. Based on the adjacent well No. 2, the crude oil density is estimated to be 0.8606-0.8639 g / cm 3 , viscosity 28.26~32.62mPa·s, gas-oil ratio 46~62m 3 / t. The crude oil from the adjacent Well 2 tested 35.66% wax and 16.98% colloids and asphaltene, indicating poor fluidity. The target layer in Well 1 exhibits a well-developed layered structure, comprising a laminated 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 target layer in Well 1, H3Ⅲ2-②, has a relatively high TOC, but the H3Ⅲ2-③ sublayer has relatively good oil saturation and mobile hydrocarbons. The H3Ⅲ2-② sublayer has an average TOC (organic matter) of 3.27%, an average S1 (effective source rock) of 2.36, and an average oil saturation of 48.4%. The H3Ⅲ2-③ sublayer has an average TOC of 2.68%, an average S1 of 2.5, and an average oil saturation of 52.8%.

[0040] Analysis of elemental logging data indicates that the H3Ⅲ2-② sublayer has high calcium, low magnesium, and low clay content, while the H3Ⅲ2-③ sublayer has high magnesium, low calcium, and high clay content. Overall, the H3Ⅲ2-② sublayer is relatively brittle.

[0041] Core rock mechanical parameter testing results show that the elastic modulus of the H3Ⅲ2 shale layer ranges from 26.19 to 40.28 GPa (at a confining pressure of 30 MPa), with an average of 32.98 GPa; the Poisson's ratio ranges from 0.235 to 0.279 (at a confining pressure of 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 evaluation indicates that the target layer exhibits a medium elastic modulus, a high Poisson's ratio, a low mechanical brittleness index, and predominantly plastic failure.

[0042] Core rock stress testing results indicate that the target layer exhibits a normal fault stress state: vertical stress > maximum horizontal principal stress > minimum horizontal principal stress. Maximum horizontal principal stress ranges from 67.41 to 69.8 MPa, while minimum horizontal principal stress ranges from 57.93 to 58.94 MPa, resulting in a stress gradient of 2.08 to 2.11 MPa / 100 m. The horizontal stress difference ranges from 8.91 to 9.64 MPa, averaging 9.4 MPa; the stress difference coefficient is 0.16. Under confining pressure (30 MPa) in Well 1, Young's modulus and Poisson's ratio are higher, as are tensile strength and fracture toughness, and the horizontal stress difference is greater. This indicates that complex fracture formation in Well 1 is challenging, and fracturing is relatively challenging.

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

[0044] 1. Segment the horizontal well section.

[0045] Segmentation refers to the use of bridge plugs to separate a horizontal well section into several large sections.

[0046] First, we select the mudstone sand body section with high mud content and a certain continuous length as the boundary section and perform a segmentation. According to the mudstone content and the length of the mudstone section, the horizontal section of Well 1 (1HF) is roughly divided into 4 major sections. Figure 6 This is the distribution map of the fracturing sweet spots in Well 1 (1HF), showing the mudstone section in the first row between sections 12 and 11, the mudstone section in the first row between sections 9 and 8, the mudstone section in the first row between sections 5 and 4, and the mudstone section in the first row between sections 2 and 1. High mud content refers to a logging gamma API value greater than 120 (a higher gamma value indicates a higher mudstone content), a logging-interpreted mud content greater than 20%, a permeability less than 0.01 Md, and a porosity less than 5%. The "continuous length" mudstone sand body in this example refers to a mudstone sand body greater than 20 meters in length.

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

[0048] Secondly, after separating the long mudstone section, the remaining section is a sandstone section with a large proportion of sandstone and a low mudstone content. The sandstone sandstone section with a certain continuous length containing mudstone is then secondary segmented. Among them, the low mud content is the logging gamma value API value of 90-120 (the smaller the gamma value, the lower the mudstone content and the greater the sandstone content), and the logging interpretation shows a mud content of 5-15%, a permeability of 0.01-0.1Md, and a porosity of 6-15%. In this embodiment, the length of the sandstone sandstone containing mudstone of a certain continuous length is 20-70m.

[0049] Based on the primary segmentation, the mudstone-containing sandstone sand body is further segmented. Specifically, continuous sand bodies with high mudstone content and low sandstone content are found in each segment of the primary segmentation. This continuous sand body is used as the basis for further segmentation (secondary segmentation). After the segmentation, the adjacent segments are separated by a continuous sand body. The bridge plugs between the adjacent segments are also located in the continuous sand body between the adjacent segments to achieve plugging between the fracturing time periods and segments. The sand body characteristics of the continuous sand body with high mudstone content and low sandstone content meet the following requirements: well logging gamma value API value of 110-120, well logging interpretation of mud content of 10-15%, permeability of 0.01-0.05Md, porosity of 6-8%, and sand body length of 5-20m.

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

[0051] 2. Determine the perforation cluster locations for each section.

[0052] After segmentation, sand bodies with low shale content and high sandstone content in each segment serve as target layers for perforation clusters. Clustering involves perforating specific, smaller locations within a larger segment. The specific perforation locations are selected based on well logging data. Cluster selection is based on the following criteria: 1) Perforation points should avoid casing collar locations; 2) Perforation points should be selected in well sections with high gamma, resistivity, gas log anomalies, and relatively high oil saturation index.

[0053] In this example, the sandstone characteristics of each section are: API logging gamma values of 90-110, well logging interpretations of shale content of 5-10%, permeability of 0.3-0.9 Md, porosity of 10-15%, and sand body length of 15-50 m. Therefore, multiple perforation points are possible within each cluster, and perforation points should be placed away from casing collar locations. Perforation points should be selected in sections with high gamma values, high resistivity, high gas logging anomalies, and relatively high oil saturation index.

[0054] The electrical characteristics of shale oil in the depression region of this example are generally characterized by "four highs and one low": high resistivity, high acoustic wave, high neutron, high gamma, and low density. Based on the characteristics of the shale reservoir in the Biyang Sag, interpretation models for key parameters such as porosity, organic carbon content, oil saturation, brittle mineral content, and brittleness index were established. The shale reservoir in the Biyang Sag was then classified according to the well logging classification evaluation criteria, as shown in Table 3.

[0055] Table 3

[0056]

[0057] The shale oil layers are divided into three categories: Class I (good), Class II (medium), and Class III (poor). Well Yangyeyou 1HF interpreted a total of 82 layers: 1,648.2 m of Class I shale oil layers in 29 layers; 771.7 m of Class II shale oil layers in 35 layers; 47.2 m of dry layers in 9 layers; and 44 m of water layers in 9 layers. Within the horizontal section of the target layer (2,982-5,081 m), 1,501.2 m of Class I shale oil layers were found in 21 layers, accounting for 71.52%; and 597.8 m of Class II shale oil layers were found in 20 layers, accounting for 28.48%.

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

[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 work their way toward the shallow end of the wellhead, with the deepest segment being segment 1 and the shallowest being segment 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, ...; Upper perforation limit (deep position, m) - Lower perforation limit (shallow position, m) = Perforation length (m); Number of perforation charges perforating the casing = Perforation length (m) x 16 charges / m; Number of perforation clusters = Number of clusters in that segment. In this example, well No. 1, segments 2 through 33, were fracturing stages using soluble bridge plugs placed in the casing as a tool for staged, clustered volume fracturing. This well primarily perforated 3-6 clusters, using spiral perforation at a 60° phase angle. Coiled tubing was used for the first segment, while wireline-conveyed bridge plugs and perforation were used in the remaining segments. Perforation parameters are shown in Table 5.

[0069] Table 5

[0070]

[0071]

[0072] 3. Formulate a pumping process for each section of fracturing construction based on the level of each section and the number of perforation clusters, and perform fracturing construction on each section according to the determined pumping process; the pumping process for each section of fracturing construction includes the formation pretreatment stage, the pre-fluid treatment stage, the sand-carrying fluid treatment stage, and the 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 preflush treatment stage is to inject preflush into the formation to form formation fractures; the sand-carrying fluid treatment stage is used to support the formed fractures; and the displacement fluid treatment stage is used for liquid displacement. During formation pretreatment, acid is added to the formation or CO2 is injected; the preflush treatment stage involves injecting preflush into the formation, using low-viscosity slickwater as the preflush; the sand-carrying fluid treatment stage is used to sequentially inject low-viscosity and high-viscosity sand-carrying fluids into the formation. The low-viscosity sand-carrying fluid uses medium-viscosity slickwater to control fracture height, expand fracture flow area, and form a fracture network. The high-viscosity sand-carrying fluid uses high-viscosity slickwater to control fracture length. The particle size in the pre-fluid is 70 / 140 mesh, and the particle size of the proppant in the low-viscosity sand-carrying fluid is 40 / 70 mesh; the particle size of the proppant in the high-viscosity sand-carrying fluid increases from 40 / 70 mesh to 20 / 40 mesh, where 70 mesh = a sieve with an aperture of 0.212 mm, and 20 mesh = a sieve with an aperture of 0.850 mm.

[0074] The formula of low-viscosity slippery water is: 0.1%-0.2% thickener + 0.5% clay stabilizer + 0.2% waterproof lock agent + 0.2% low-temperature gel breaker activator + 0.2% wicking agent;

[0075] The formula of medium viscosity slippery water is: 0.3%-0.4% thickener + 0.3% clay stabilizer + 0.2% waterproof lock agent + 0.3% low temperature gel breaker activator + 1% wicking agent;

[0076] The formula of high viscosity slippery water is: 0.5%-0.6% thickener + 0.3% clay stabilizer + 0.2% waterproof lock agent + 0.3% low temperature gel breaker activator + 1% imbibing agent.

[0077] In this embodiment, a corresponding fracturing construction pumping process is formulated for each section. Since there are a total of 33 sections, three sections are selected for illustration below. To be more representative, the three selected sections are of different quality grades, among which section 2 is selected as the representative of Grade III, section 8 is selected as the representative of Grade II, and section 28 is selected as the representative of Grade I. The fracturing construction pumping processes for sections 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 "middle top" refers to the liquid that serves as a barrier between the two stages. This highly viscoelastic, gel-like liquid acts as a plugging barrier. The first stage consists of pumping pre-treatment to the formation, followed by the intermediate displacement liquid, followed by the second stage's injection of liquid and proppant, followed by the intermediate displacement liquid, and so on. The "glue" consists of 0.8%-1% thickener, 0.3% clay stabilizer, 0.2% waterproofing agent, and 0.3% low-temperature gel breaker activator.

[0085] In the determined fracturing construction pumping process of each section, if the reservoir quality level of this section is high, CO2 is injected into the formation during the formation pretreatment; if the reservoir quality level of this section is low, acid is injected into the formation during the formation pretreatment. Since the dolomitic ash content of the target layer 4535-5028m of Well No. 1 in this embodiment is 13.6-31%, after acid treatment, the dolomitic ash reservoir can effectively communicate with the natural pores, effectively reduce the rock modulus, and reduce the fracture pressure; at the same time, it has a good dissolution and unblocking effect on the plugging agent during the drilling process. Optimization is only carried out in the 1st to 5th sections (4535-5028m) of the pre-fracturing construction, and the pre-acid solution is used to reduce the fracture pressure, and each section is optimized for 25-30m 3 The preferred acid solution formula is: 10% HCL + 2% acidizing corrosion inhibitor + 2% iron ion stabilizer + 1% clay stabilizer. The diluted on-site acid is required to meet the following technical indicators: (1) uniform liquid appearance, completely soluble in water; (2) organic chlorine content is 0; (3) static corrosion rate at 90℃ and normal pressure ≤5g / (m 2 .h).

[0086] In this example, the reservoir of Well No. 1 is highly stress-sensitive and the fluidity of crude oil is weak. Therefore, maintaining a certain conductivity and extending the effective time of fractures are the keys to stable production. Using large-volume, small-particle quartz sand for construction reduces proppant sedimentation and allows for further laying, achieving effective support for distal fractures; large-particle 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 of 70 / 140 mesh and 40 / 70 mesh to achieve full filling of fractures of different scales, reducing the adverse effects of mixing of different particle sizes on conductivity. Small particle size and low sand ratio (70 / 140 mesh quartz sand) are used for grinding, filtration reduction and support of micro-fractures; long-section plugs (40 / 70 mesh quartz sand) are used to support the formation of branch fractures with a certain conductivity; high sand ratio (40 / 70 mesh ceramsite) supports the formation of high-conductivity main fractures.

[0087] During the fracturing and pumping process described above, slurry enters multiple perforation clusters during the first fracturing. Because the sand bodies corresponding to the perforation clusters vary in permeability, the slurry enters more permeable sand bodies and less permeable sand bodies after the first fracturing. Therefore, a secondary fracturing and temporary plugging ball injection are employed. During the secondary fracturing, the temporary plugging balls flow with the slurry to the perforation clusters with higher permeability and block the perforations of higher permeability at the perforation clusters on the casing wall. This forces the subsequent secondary fracturing to allow the slurry to enter the perforation clusters with lower permeability, ultimately achieving the goal of uniformly reforming multiple perforation clusters. The standard for adding temporary plugging balls is when the permeability difference between clusters is at least three times. At this point, the slurry enters more permeable sand bodies and less permeable sand bodies. In the embodiment of the present invention, temporary plugging balls are added when there are 5-6 perforation clusters, and no temporary plugging balls are added when there are 4 clusters. Taking the fracturing and pumping process for the third section of Well 1 as an example, 21 temporary plugging balls were deployed. The relationship between the number of temporary plugging balls deployed and the perforation plugging is: Number of temporary plugging balls / 16 (perforations / m) = Sand body thickness plugged. The number of temporary plugging balls is based on the perforation standard: 16 perforating charges correspond to 16 perforations per 1m sand body thickness. 21 temporary plugging balls, therefore, will plug perforations with a sand body thickness of 1.3m. The reservoir properties at 1.3m are better, allowing more slurry to enter.

[0088] Temporary plugging agents can also be added as needed. These particles can enter the formation along with the fluid, forming a plugging layer within the high-porosity, high-permeability fluid flow channels within the formation. This plugging layer has a lower permeability than the surrounding formation, forcing subsequent fluid flow to divert to lower-permeability formations, opening fractures in different directions and increasing the fracture area. The fracturing parameters for each section of Well 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, ultimately increasing oil production from both rich and poor reservoirs. By pumping different combinations of construction materials, such as acid, CO2, fracturing fluid, temporary plugging agents within fractures, and temporary plugging balls for perforation plugging, three different combinations of pumping materials, pumping rates, and injection fluid volumes are employed for the three different reservoir characteristics, thereby increasing oil well production.

[0093] In order to better illustrate the effect of the present invention, Well No. 2 is taken as a comparative example, and the existing mining process is adopted for Well No. 2.

[0094] Wellhead No. 2 is located northeast of the wellhead of the pilot wellhead of Well No. 1. It is a horizontal shale oil well with a horizontal section length of 1402.00m. The unconventional interpretation shows that the favorable shale oil and gas layer is 1636.70m / 10 sections. The target layer of this well corresponds to the HⅢ2 layer of the pilot well of Well No. 1, with an effective horizontal section length of 1344.10m. The "easy-to-drill bridge plug sealing-cluster perforation combined operation" process was used. Fracturing construction was carried out in 21 sections, and the maximum daily oil production during the self-flowing stage was 4.8m 3 (Liquid volume 33m 3 ), since the start of post-fracturing test production on January 31, 2013, the highest daily oil production is 28.1m 3 The cumulative oil production was 2945.54t (41.87t in the oil test phase and 2903.67t in the production phase). The well was shut in July 2017. The daily oil production before shutting in was 0.3t (liquid volume 4.8m 3 ).

[0095] After the fracturing construction was carried out in accordance with the method of this embodiment, the newly drilled Well No. 1 began to flow back the fracturing fluid on August 21, 2023, and the flowback was completed on September 11. Oil production began on September 12, 2023. Under the surface self-flowing state, the initial daily oil production was 4.1 cubic meters / day and the daily liquid production was 41 cubic meters / day. As of November 27, 2023, under the self-flowing state, the daily oil production was 8.3 cubic meters / day and the daily liquid production was 25 cubic meters / day; 90 days after fracturing, the total oil production was 446.8 cubic meters and the liquid production was 2674 cubic meters. It can be seen that the fracturing construction method of the present invention can be used to perform fracturing transformation on Well No. 1, greatly improving the oil production of Well No. 1.

Claims

1. A shale oil horizontal well staged fracturing construction method, characterized in that: The method comprises the following steps: 1) Remove the continuous length of mudstone in the horizontal well. On this basis, segment the sandstone body containing mudstone to find a continuous sand body with high mudstone content and low sandstone content. Use the continuous sand body as the interval between the two adjacent ends, and set the bridge plug of each section in the continuous sand body between the two adjacent sections; 2) Obtain the number and location of reservoirs in each section to determine the number and location of perforation clusters, and determine the quality level of the reservoir in each section based on the parameters of each reservoir in the section; 3) Formulate a pumping process for the fracturing construction for each section based on the quality level and the number of perforation clusters of each section, and perform fracturing construction on each section according to the determined pumping process; the pumping process for the fracturing construction for each section includes a formation pretreatment stage, a pre-fluid treatment stage, a sand-carrying fluid treatment stage, and a displacement fluid treatment stage. The pre-fluid treatment stage and the sand-carrying fluid treatment stage are executed alternately in a cycle, and the number of cycles is not less than 2.

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

3. The shale oil horizontal well staged fracturing construction method according to claim 1, characterized in that: The number of cycles in the pre-fluid treatment stage and the sand-carrying fluid treatment stage is related to the number of perforation clusters in each section. The more perforation clusters in each section, the more cycles there are.

4. The shale oil horizontal well staged fracturing construction method according to claim 1, characterized in that: The perforation cluster is selected in a target layer where a sand body with low mud content and high sandstone content is located.

5. The shale oil horizontal well staged fracturing construction method according to claim 1, characterized in that: During the formation pretreatment, acid is added to the formation or CO2 is injected; the pre-pad treatment stage refers to injecting pre-pad fluid into the formation, and the pre-pad fluid uses low-viscosity slick water; 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, and the low-viscosity sand-carrying fluid uses medium-viscosity slick water to control the height of the fracture, expand the fracture flow area, and form a fracture network. The high-viscosity sand-carrying fluid is used to control the length of the fracture and uses high-viscosity slick water.

6. The shale oil horizontal well staged fracturing construction method according to claim 5, characterized in that: The formula of low-viscosity slippery water is: 0.1%-0.2% thickener + 0.5% clay stabilizer + 0.2% waterproof lock agent + 0.2% low-temperature gel-breaking activator + 0.2% imbibition agent; the formula of medium-viscosity slippery water is: 0.3%-0.4% thickener + 0.3% clay stabilizer + 0.2% waterproof lock agent + 0.3% low-temperature gel-breaking activator + 1% imbibition agent; the formula of high-viscosity slippery water is: 0.5%-0.6% thickener + 0.3% clay stabilizer + 0.2% waterproof lock agent + 0.3% low-temperature gel-breaking activator + 1% imbibition agent.

7. The shale oil horizontal well staged fracturing construction method according to claim 5, characterized in that: The particle size of the pre-fluid is 70 / 140 mesh, the particle size of the proppant in the low-viscosity sand-carrying fluid is 40 / 70 mesh; the particle size of the proppant in the high-viscosity sand-carrying fluid increases from 40 / 70 mesh to 20 / 40 mesh.

8. The shale oil horizontal well staged fracturing construction method according to claim 1, characterized in that: In the determined pumping process of each section of the fracturing construction, if the reservoir quality level of this section is high, CO2 is injected into the formation during formation pretreatment; if the reservoir quality level of this section is low, acid is injected into the formation during formation pretreatment.

9. The shale oil horizontal well staged fracturing construction method according to claim 1, characterized in that: The classification of each section is determined based on the organic carbon content, porosity, oil saturation and brittle minerals in each reservoir section. 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 of the reservoir section.

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