A fracturing method for strong plastic shale oil reservoirs and its application

Abstract

The application discloses a fracturing method for strong plastic shale oil reservoirs and application thereof. The fracturing method comprises the following steps: (1) evaluating key reservoir parameters; (2) preparing and optimizing variable mass foam slick water and variable mass foam gel; (3) optimizing fracture parameters and fracturing operation parameters; (4) lowering and operating a cementing sliding sleeve; (5) opening the sliding sleeve by ball dropping; (6) acid pretreatment operation; (7) foam gel main fracture construction; (8) low-viscosity slick water injection operation; (9) foam slick water proppant injection operation; (10) foam gel proppant injection operation; and (11) displacement operation. The fracturing method can form uniform main fractures and relatively complex branch fractures in the horizontal wellbore direction, can enlarge the drainage area, can penetrate the shale bedding in the vertical direction and can improve the reconstruction volume, and thus provides a powerful means for fully utilizing the strong plastic shale oil reservoirs.

Description

Technical Field

[0001] This invention relates to the technical field of oil and gas reservoir development, and more specifically, to a fracturing method for highly plastic shale oil reservoirs and its application. Background Technology

[0002] With the deepening of unconventional oil and gas exploration and development and the continuous advancement of volumetric fracturing technology, previously difficult-to-develop continental shale oil has become an important strategic successor for my country's future oil and gas resources. However, the geological conditions of domestic continental shale oil are extremely complex, with prominent problems such as difficulty in stabilizing production, low cumulative production per well, and high overall development costs. Large-scale, efficient development still faces many challenges, especially given the large proportion of high-mud-content, highly plastic reservoirs in domestic continental shale oil, sometimes with mud content exceeding 40%. The main characteristics of such reservoirs are high mud content and high plasticity, making fracture initiation and propagation during fracturing difficult, especially the initiation and propagation of branch fractures, resulting in narrow fracture widths and a high risk of sand plugging during fracturing.

[0003] Currently, the commonly used horizontal well dense-cluster perforation fracturing technology faces significant challenges in its application to high-clay, highly plastic reservoirs. In brittle reservoirs, because the fracture length extends fastest, increasing the number of perforation clusters has almost no impact on the fracture width extension, and the three-dimensional geometry of each cluster is relatively small, resulting in minimal impact on subsequent proppant addition and a low risk of sand plugging. However, in high-clay, highly plastic reservoirs using intra-section multi-cluster perforation fracturing, as the number of perforation clusters increases, the flow rate of each cluster decreases accordingly. Therefore, the length, width, and height of each cluster are significantly reduced, not only diminishing the induced stress effect but also potentially causing sand plugging during subsequent proppant addition.

[0004] Furthermore, high-mud-content, highly plastic reservoirs have limited effectiveness of induced stress, necessitating an increase in the number of perforation clusters within each fracturing stage and a reduction in cluster spacing to enhance the promoting effect of induced stress on complex fractures. To address this issue, conventional fracturing techniques have primarily employed fracturing techniques with a smaller number of clusters, such as two clusters per stage. However, this significantly reduces the effectiveness of induced stress and substantially increases the number of fracturing stages, leading to a substantial increase in fracturing costs and casting a significant shadow over the economical and effective development of these reservoirs.

[0005] Currently, literature and patents on shale reservoir fracturing mainly focus on shale gas reservoirs, with relatively few concerning shale oil reservoirs. Patent CN108678723A provides a fracturing stimulation method for shale oil reservoirs in closed lacustrine basins. It primarily targets different reservoir types and lithologies, such as layered, interbedded, and sandwiched reservoirs, optimizing fracturing processes, fracturing fluid systems, and proppant selection. The fracturing fluid system mainly uses slickwater and conventional guar gum, while the proppant uses quartz sand and ceramsite.

[0006] Patent CN112431580A discloses a method for improving shale oil recovery. This method is based on modified fracturing fluid, combining hydraulic fracturing and microwave irradiation technologies to extract shale oil. The method first utilizes the water solubility of water-soluble organic compounds, incorporating them into the fracturing fluid. Second, it uses hydraulic fracturing and microwave irradiation technologies to directly extract light shale oil. Finally, it leverages the extractive properties of the water-soluble organic compounds and the advantages of microwave-assisted extraction to extract difficult-to-extract heavy shale oil into the fracturing fluid, indirectly extracting shale oil. This invention provides both a clean and efficient method for shale oil extraction and a pathway for utilizing organic compounds and microwaves. The water-soluble organic compounds used are methanol, ethanol, or propanol, and their molar percentage in the fracturing fluid is 10%–35%.

[0007] Patent CN113445976A discloses a fracturing method for highly plastic formations. It primarily employs alternating injections of homoionic acidic slickwater and acidic clean fracturing fluid, followed by sequential injection of 150-180 mesh small-particle-size proppant and 30-50 mesh resin-coated proppant. The viscosity of the acidic clean fracturing fluid is more than 10 times that of the homoionic acidic slickwater. This method fully leverages the advantages of homoionic acidic fracturing fluid, combined with acidic clean fracturing fluid, to create a viscous fingering effect, increasing fracture complexity. Simultaneously, it optimizes the injection ratio and timing of proppant of different particle sizes, mitigating proppant embedding in plastic formations and wall compaction effects, thus improving the effectiveness of fracturing stimulation. The optimized results of this patent can effectively guide fracturing operations, increase stimulation volume, and improve operational results, thereby maximizing economic benefits. However, this patent primarily uses acidic slickwater and acidic clean fracturing fluid as the fracturing fluid system for highly plastic reservoirs.

[0008] However, the pressure effect of the above fracturing methods is limited, and it is necessary to study and propose a new fracturing method suitable for shale oil reservoirs. Summary of the Invention

[0009] To address the problems in existing technologies, this invention proposes a fracturing method for highly plastic shale oil reservoirs and its application. Targeting the high clay content and strong plasticity of shale oil reservoirs, this invention employs a multi-cluster optimized design method with fewer segments, combined with a cementing sliding sleeve scheme. This significantly enhances the induced stress effect while ensuring that the intensity of each cluster of fractures is not reduced, enabling the formed fractures to extend and initiate uniformly. Furthermore, by combining variable-mass foam adhesive, variable-mass foam slickwater, and low-viscosity slickwater, clay expansion and migration can be effectively suppressed, reducing reservoir damage. This allows for the formation of a complex fracture system with effective opening of main and branch fractures. Finally, a combination of proppants with different particle sizes effectively supports the formed main and branch fractures, ultimately creating a complex fracture network with good conductivity, improving post-fracturing production enhancement and stabilization.

[0010] One objective of this invention is to provide a fracturing method for highly plastic shale oil reservoirs, the method comprising:

[0011] (1) Evaluation of key reservoir parameters;

[0012] (2) Preparation and optimization of variable mass foam slipper and variable mass foam liquid;

[0013] (3) Optimization of fracture parameters and hydraulic fracturing construction parameters;

[0014] (4) Installation of cementing sliding sleeve;

[0015] (5) Throwing the ball while opening the sliding sleeve;

[0016] (6) Acid pretreatment operation;

[0017] (7) Construction of main cracks using foam adhesive;

[0018] (8) Low-viscosity slickwater injection construction;

[0019] (9) Injection of foam-slippery water carrying proppant;

[0020] (10) Injection of foam adhesive carrying support agent;

[0021] (11) Substitute work.

[0022] Preferably,

[0023] Step (1) Evaluation of key reservoir parameters includes the lithology and whole-rock mineral composition, physical properties, rock mechanical parameters, triaxial geostress and geostress distribution characteristics of each longitudinal sublayer, development of horizontal bedding fractures and high-angle natural fractures, etc.

[0024] In-situ stress results can be obtained by verifying adjacent well fracturing data based on well logging interpretation results. On this basis, core sampling can be performed using a vertical pilot well to obtain corresponding physical properties and rock mechanical parameters under simulated in-situ stress conditions. Whole-rock mineral analysis results can be referenced. The development of horizontal bedding fractures and high-angle natural fractures is mainly obtained through core observation.

[0025] The relevant parameters for the horizontal section are mainly obtained based on the analogy results of well logging parameters.

[0026] Preferably,

[0027] In step (2), the mass of carbon dioxide foam in the foamy slippery water is 30% to 90%, more preferably 30% to 70%;

[0028] The viscosity of the foamy slippery water is 6 mPa·s to 9 mPa·s;

[0029] In foamy slippery water, the concentration of acid drag reducer is 0.2wt%-1.0wt%.

[0030] The carbon dioxide foam content of the foam adhesive is 30%–90%.

[0031] The viscosity of the foam adhesive is 50 mPa·s to 60 mPa·s;

[0032] In the foam adhesive, the concentration of the acid drag reducer is 0.2wt%-1.0wt%.

[0033] In this invention, since foam slippery water and foam adhesive have higher friction than conventional slippery water and adhesive, it is necessary to add a drag-reducing agent to reduce friction in order to meet the friction requirements of each cluster of crack liquid inlet channels in step (4). The drag-reducing agent can be the commonly used acidic drag-reducing agent, preferably SRAP-1 acid drag-reducing agent.

[0034] In this invention, the foam slick or foam adhesive becomes acidic due to the injection of CO2, with a pH value ranging from 3 to 6. Because the fracturing section has a high mud content and correspondingly high clay content, using an acidic medium fluid (i.e., foam adhesive or foam slick) with a pH range of 3-6 can, on the one hand, inhibit clay expansion and reduce damage to conductivity; on the other hand, it can dissolve carbonate minerals in the rock, promoting the formation of complex fractures; finally, it can also reduce the rock's strength and fracturing pressure, further promoting the formation of complex fractures.

[0035] In this invention, variable-mass foam slicks and variable-mass foam adhesives refer to foam slicks and foam adhesive systems with different foam masses. The typical foam mass of carbon dioxide fracturing fluid is 30%–70% or even 90%. Rheological parameters, proppant settling properties, and half-life of the foam fluid are tested to select the appropriate foam mass at each stage of fracturing. For example, 60%–90% foam mass can be used in the fracture-building stage. Considering the need for sand addition to carbon dioxide foam fracturing fluid, as the sand-fluid ratio increases, the mass of carbon dioxide foam can be gradually reduced to around 30% depending on the formation conditions.

[0036] Preferably,

[0037] In this invention, commonly used commercial simulation software ECLIPSE and MEYER are applied to simulate and optimize fracture length, conductivity, and cluster spacing. Generally, the optimized main fracture length should be 200m–250m, the conductivity 3d.cm–5d.cm, and the cluster spacing 15m–20m. The optimization results for branch fractures are between 30% and 40% of those for the main fractures (fracture spacing can be 100%).

[0038] Then, combining the fracture propagation simulation results, optimized combinations of fracturing operation parameters are obtained, such as flow rate, fluid volume, viscosity, proppant dosage, sand-fluid ratio, and proppant addition procedure. Generally, the pure fracturing fluid volume for 3-4 clusters is around 1600 m³. 3 ~1800m 3 Supportive dose 70m 3 ~80m 3 (Among which, the proportion of 70-140 mesh small particles is 30%-40%, and the proportion of 30-50 mesh is 60%-70%); the volume of pure fracturing fluid in 4-5 clusters is 1900m³. 3 ~2000m 3 Supportive dose 90m 3 ~100m 3 The ratio of proppant particle size is the same as that of 3-4 clusters.

[0039] Considering the low probability of tertiary fractures in highly plastic reservoirs, the optimization of the above fracture parameters can be achieved using an orthogonal design method to simulate the fracture length, conductivity, and cluster spacing of the main fracture and branch fractures respectively. For simplicity, the length and conductivity of the branch fractures can be taken as 30%–40% of that of the main fracture, and the fracture spacing of the branch fractures can be the same as that of the main fracture. Considering the need to reduce construction costs, a fracturing construction design with fewer segments and more clusters is adopted. The total number of segments can be optimized with reference to data from conventional brittle reservoirs, with each segment length taken as 60–70 m and the number of clusters as 3–4 or 4–5. To ensure safe and smooth construction, the design number of clusters for the first three fracturing segments is preferably 3–4, and the design number of clusters for subsequent fracturing segments is preferably 4–5.

[0040] Preferably,

[0041] Step (4): A multi-stage, single-ball cementing sleeve is selected for the cementing sleeve. The cementing sleeve is set at the fracture position of each cluster of perforations to avoid competition for fluid absorption in each perforation under the conventional spiral perforation method. In this invention, a conventional multi-stage, single-ball cementing sleeve can be used for the cementing sleeve.

[0042] The jetting velocity of each fracture cluster is above 130 m / s; the friction of the fluid inlet channel of each fracture cluster is between 3 MPa and 5 MPa. In this invention, the jetting velocity of each fracture cluster is required to be above 130 m / s, mainly considering that at the vertical position along the horizontal wellbore, the high-speed water jet effect can split the barrier effect of each horizontal bedding fracture and multiple longitudinal stress shielding layers, so as to ensure that the height of each fracture cluster does not decrease even under multi-cluster perforation conditions. At the same time, the high-speed jet effect in the horizontal direction can also disperse the proppant accumulation effect near the wellbore that may induce sand blockage in the early stage.

[0043] In this invention, the friction of the liquid inlet channel of each cluster of fractures is required to be between 3MPa and 5MPa. The purpose is to ensure that each cluster of fractures meets the flow restriction requirements and that each cluster of fractures can be uniformly initiated and extended under the condition of multiple perforations.

[0044] In this invention, a cementing sliding sleeve fracturing process is employed. Through the pre-setting of the cementing sliding sleeve, the aforementioned technical requirements for flow restriction and jetting are met, ensuring that the enhancement strength of each cluster of fractures is not reduced. Specifically, the cementing sliding sleeve of this invention is set according to the different flow rates at different wellbore locations. To ensure that the flow rate and jet velocity at each perforation cluster meet the above requirements, and ideally, that the guaranteed flow rate and jet velocity of each perforation cluster are the same, the groove area and shape of each cluster of sliding sleeves can be appropriately changed. For example, from near target point A (i.e., the starting point of the horizontal wellbore) to target point B (i.e., the ending point of the horizontal wellbore), the required groove area for each perforation cluster is gradually increased. The specific increase ratio can be based on hydraulic calculation results, achieving both flow restriction and hydraulic jetting effects, as well as the requirement of uniform jetting velocity. More preferably, the cementing sliding sleeve includes 3-4 rectangular grooves, each groove having a length of 10-15 mm and a width of 2-4 mm, with the grooves evenly distributed on the circumference of the cementing sliding sleeve.

[0045] The optimal method is to select the area of ​​the cementing sleeve so that the injection velocity of each cluster of fractures is equal and the friction of the fluid inlet channel of each cluster of fractures is equal.

[0046] Preferably,

[0047] Step (5): As per standard requirements, open the slipper when throwing the ball.

[0048] Preferably,

[0049] Step (6), the acid used for acid pretreatment is hydrochloric acid or rare earth acid;

[0050] The dosage should be adjusted appropriately based on the number of clusters in a single segment, with the preferred acid dosage being 10 mg / L. 3 ~20m 3 ;

[0051] Displacement is 1.0 to 1.5m. 3 / min.

[0052] Preferably,

[0053] Step (7) uses the foam adhesive prepared in step (2), wherein the mass of carbon dioxide foam in the foam adhesive is 80%–90%; the volume of the foam adhesive is 150 m³. 3 ~200m 3 The displacement is taken as the maximum value under the wellhead pressure limit.

[0054] Preferably,

[0055] Step (8): The viscosity of the low-viscosity slickwater is 6 mPa·s to 9 mPa·s, and the volume is 80 m³ / s. 3 ~100m 3 The displacement is taken as the maximum value under the wellhead pressure limit.

[0056] In this invention, step (8) uses ordinary low-viscosity slippery water without carbon dioxide foam for construction injection, in order to utilize its low viscosity characteristics to connect and extend the support crack system; otherwise, the foam adhesive in step (7) cannot form the support crack system.

[0057] Preferably,

[0058] Step (9): Foamed slickwater carrying 70-140 mesh proppant is injected. Initially, a slug injection mode is used, with a proppant-to-liquid ratio of 2%-4%-6%-8%, and the volume ratio of each slug to the spacer fluid is 1:1. The discharge rate is taken as the maximum value under the wellhead pressure limit, preferably 14-16 m³ / h. 3 / min; After the slug injection is completed, a long slug injection mode is adopted, with a sand-to-fluid ratio of 10%–12%–14%–16%, and the volume ratio of each slug to the spacer fluid is 1:1; the discharge rate is taken as the maximum value under the wellhead pressure limit, preferably 14-16m. 3 / min;

[0059] When each fracturing section consists of 3-4 clusters of perforations, in the slug injection mode, the dosage per sand-fluid ratio is 30m³. 3 ~40m 3 In the long slug injection mode, the dosage for each sand-liquid ratio is 40m³. 3 ~50m 3 ;

[0060] When each fracturing section has 4-5 clusters of perforations, in the slug injection mode, the dosage per sand-to-fluid ratio is 36m³. 3~52m 3 In the long slug injection mode, the dosage per sand-liquid ratio is 48m³. 3 ~65m 3 ;

[0061] The carbon dioxide foam content of foamy slicks is 50%–70%.

[0062] In this invention, the total fluid volume of the slug injection mode can be controlled according to actual conditions. Preferably, when each fracturing stage has 3 to 4 clusters of perforations, the total fluid volume of the slug injection mode is 240-320 m³. 3 The total fluid volume in the long slug injection mode is 320-400 m³. 3 .

[0063] When each fracturing section has 4-5 clusters of perforations, the total fluid volume in the slug injection mode is 288-416 m³. 3 The total fluid volume in the long slug injection mode is 384-520m³. 3 .

[0064] In this invention, the application ratio of small-diameter proppant (70-140 mesh proppant) is significantly increased. Considering the uniform initiation and extension of the aforementioned multi-cluster fractures, the width of each cluster fracture will decrease to some extent due to the reduced displacement and the superposition effect of stress induced by the multi-cluster fractures. Simultaneously, the "candy-goose" effect of the longitudinal fracture width profile formed by multiple longitudinal stress-shielding layers necessitates an appropriate reduction in proppant particle size to facilitate proppant transport from the horizontal wellbore against gravity to the multiple longitudinal stress layers. Furthermore, with the increase in small-diameter proppant, due to the relatively poor flow following of the proppant and fracturing fluid, proppant tends to accumulate in large quantities in the perforation cluster fracture openings near target point A in the horizontal wellbore, leading to a corresponding fracture sand plugging effect, which in turn forces a large amount of subsequent proppant and fracturing fluid into the fractures near target point B. Therefore, increasing the proportion of small-diameter proppant also promotes the uniform extension of multi-cluster fractures.

[0065] Preferably,

[0066] Step (10): In order to increase the sand-liquid ratio to overcome the embedding effect of high clay content, foam adhesive liquid carrying 30-50 mesh proppant is injected, and a continuous sand addition mode is adopted, with a sand-liquid ratio of 12%-15%-18%-21%-24%.

[0067] When each fracturing section has 3-4 clusters of perforations, the dosage per sand-fluid ratio is 40m³. 3 ~50m 3 ;

[0068] When each fracturing section has 4-5 clusters of perforations, the dosage per sand-to-fluid ratio is 48m³. 3 ~65m 3;

[0069] The mass of carbon dioxide foam in the foam adhesive is 30-50%;

[0070] The displacement is taken as the maximum value under the wellhead pressure limit.

[0071] In this invention, the total fluid volume in the continuous proppant addition mode can be controlled according to actual conditions. Preferably, when each fracturing stage has 3 to 4 perforations, the total fluid volume in the continuous proppant addition mode is 200-250 m³. 3 ;

[0072] When each fracturing stage consists of 4–5 perforations, the total fluid volume in the continuous propulsion mode is 240–365 m³. 3 .

[0073] Preferably,

[0074] Step (11): Use an appropriate over-displacement strategy, with the displacement amount being 110% to 120% of the wellbore volume of the current section; the first 30% to 40% of the displacement amount is replaced with foam adhesive, and then replaced with foam slickwater.

[0075] The mass of carbon dioxide foam in the foam adhesive is 30-50%;

[0076] The mass of carbon dioxide foam in slippery water is 30-50%.

[0077] The displacement is taken as the maximum value under the wellhead pressure limit.

[0078] Step (12) For the fracturing operations of other sections, repeat steps 5) to 11) until all sections are completed.

[0079] Step (13) Post-pressurization return, testing and production, etc., shall be carried out in accordance with the conventional process and parameters.

[0080] A second objective of this invention is to provide the application of the fracturing method described in one objective of this invention in oil drilling.

[0081] Compared with the prior art, the present invention has at least the following advantages:

[0082] Fracturing and stimulation of existing high-mud-content, highly plastic reservoirs is challenging. Not only is the extension of the main fracture difficult, but the opening and extension of branch fractures and horizontal bedding fractures are even more difficult. Even when opened, the fracture width is often very narrow, making subsequent sand addition prone to sand blockage. The fracturing method for highly plastic shale oil reservoirs proposed in this invention provides a guiding solution for forming a uniform, complex fracture network while avoiding sand blockage. Fracturing operations using this method can create both uniform main fractures and relatively complex branch fractures in the horizontal wellbore direction to expand the drainage area. Vertically, it can penetrate shale bedding to increase the stimulation volume, providing a powerful means to fully utilize highly plastic shale oil reservoirs.

[0083] The fracturing method for highly plastic shale oil reservoirs proposed in this invention reduces the number of fracturing stages, increases the number of perforation clusters, and reduces the overall cost of fracturing operations. Compared with conventional multi-cluster perforation fracturing in brittle reservoirs, the number of fracturing stages is reduced by 20% to 30%, and the number of perforation clusters is increased by 30% to 50%.

[0084] This invention proposes a multi-cluster perforation fracturing method for high-mud-content, highly plastic reservoirs. While reducing fracturing costs, it can also reduce costs by adjusting the pre-set area and shape of the cementing sleeve grooves according to different flow rates at different wellbore locations. This ensures that the flow rate and jet velocity are the same at each cluster of perforations, thereby achieving uniform fracture opening and increasing the scale of proppant addition. This provides a feasible technical means for the effective stimulation of high-mud-content, highly plastic reservoirs.

[0085] In the fracturing method of this invention, by combining variable-mass foam adhesive, variable-mass foam slickwater, and low-viscosity slickwater, clay expansion and migration can be effectively suppressed, reservoir damage can be reduced, and a complex fracture system with effective opening of main fractures and branch fractures can be formed. Then, by combining proppants of different particle sizes, the main fractures and branch fractures formed are effectively supported, and finally a complex fracture network with good conductivity is formed, thereby improving the post-fracturing production increase and stabilization effect. Detailed Implementation

[0086] The present invention will now be described in detail with reference to specific embodiments. It should be noted that the following embodiments are only used to further illustrate the present invention and should not be construed as limiting the scope of protection of the present invention. Some non-essential improvements and adjustments made by those skilled in the art based on the content of the present invention are still within the scope of protection of the present invention.

[0087] All raw materials used in this invention can be purchased directly.

[0088] Example 1

[0089] Well X is a shale oil well. It is a horizontal well with a horizontal section length of 1200m, a total drilled depth of 3720m, and a vertical depth of 2632m. The target formation is the 7th layer of the Yanchang Formation, with a reservoir thickness of 18m. The drilled section of the target formation is from 2697.0m to 3697.0m. The lithology of this section is mainly shale and tight sandstone, with overlying and underlying mudstone strata. The target formation is a low-porosity, ultra-low-permeability reservoir with an average porosity of 11.3% and an average permeability of 0.17mD. It has well-developed natural fractures with a density of 1.2 fractures / m, and a low brittleness index (27%–38%). The original formation pressure is 14.7–16.9 MPa, with a pressure coefficient of 0.77–0.84, classifying it as a low-pressure shale oil reservoir.

[0090] The following is a detailed implementation process of the embodiment:

[0091] 1) Assessment of key reservoir parameters

[0092] First, the lithology, whole-rock mineral composition, physical properties, rock mechanical parameters, triaxial geostress, and geostress distribution characteristics of each longitudinal sublayer were analyzed and evaluated for the core sample of the target layer in Well X. The development of horizontal bedding fractures and high-angle natural fractures was also assessed. The corresponding parameters for the horizontal sections were mainly obtained based on analogy results from well logging parameters.

[0093] 2) Preparation of construction foam slippery water and foam adhesive

[0094] According to the fracturing design plan, 250 ml of CO2 foam adhesive with 80% foam content was prepared on-site before construction. 3 The viscosity is 60 mPa·s; 350 ml of CO2 foam adhesive with a foam mass of 40% is used. 3 Viscosity of 50 mPa·s; Low viscosity slickwater 120 m 3 The viscosity is 9 mPa·s; 800 m³ of CO2 foam slick water with a foam mass of 65% was produced. 3 A 100m³ CO2 foam slick with a viscosity of 6 mPa·s and a foam mass of 50% was prepared. 3 The viscosity is 6 mPa·s; in the above foam slick, the concentration of SRAP-1 acid drag reducer is 0.3 wt%, and in the above foam adhesive, the concentration of SRAP-1 acid drag reducer is 0.6 wt%. Due to on-site construction needs, the prepared liquid should be 10-15% more than the actual amount of liquid used in construction.

[0095] 3) Optimization of fracture parameters and fracturing operation parameters

[0096] The fracture length, conductivity, and cluster spacing were optimized using the reservoir numerical simulation software ECLIPSE. The optimal number of fracturing segments was determined to be 15, with 3 clusters per segment in segments 1-3 and 4 clusters per segment in segments 4-15. The main fracture length was 235 m, with a conductivity of 5 d.cm and a cluster spacing of 18 m. The secondary fracture length was 80 m, with a secondary fracture spacing of 18 m and a conductivity of 3 d.cm.

[0097] Based on the reservoir numerical simulation results, the fracturing operation parameters were optimized using the fracture propagation simulation software MEYER. The optimal fracturing displacement was determined to be 16 m³ / s. 3 / min, average total liquid volume per segment 1600m 3 Supportive dose 100m 3 (of which, 40% are small particles with a diameter of 70–140 mesh) 3 , 30~50 mesh 60m 3 The proppant is medium-density, high-strength ceramic aggregate.

[0098] 4) Lowering the cementing sleeve

[0099] Based on the fracturing design scheme and the optimized segment cluster results in step 3), a compliant multi-stage cementing sleeve was installed and cementing operations were performed according to specifications. The cementing sleeve was positioned at each perforation cluster location in the fracturing design, and each sleeve contained a rectangular groove evenly distributed around its circumference. The number of grooves was the same as the number of perforation clusters in the section to be fractured. Each groove had a length of 15mm and a width of 2mm, ensuring that the injection velocity of each fracture cluster in the fracturing section was above 130m / s, and the friction of the fluid inlet channel in each fracture cluster was 4MPa.

[0100] 5) Open the slide when throwing the ball.

[0101] After cementing with the sliding sleeve is completed, before fracturing operations, a ball is dropped to open the three grooved sliding sleeves of the first stage of fracturing for three-cluster perforation.

[0102] 6) Acid pretreatment operation

[0103] The first stage of fracturing operation used a 15m... 3 Hydrochloric acid, at a concentration of 20 wt%, was used for pretreatment to reduce reservoir fracture pressure, with a discharge rate of 1.0 m³. 3 / min.

[0104] 7) Inject foam adhesive to create the main joint

[0105] The CO2 foam adhesive prepared in step 2) with a foam mass of 80% was injected during construction, totaling 200m³. 3 The displacement is 16m 3 / min.

[0106] 8) Inject low-viscosity slippery water to create branch joints

[0107] The low-viscosity slickwater prepared in step 2) was injected during construction to connect and extend the branch joint system. A total of 100 m³ of slickwater with a viscosity of 9 mPa·s was injected. 3 The displacement is 16m 3 / min.

[0108] 9) Inject foam-slippery water carrying 70-140 mesh proppant to create and support branch joints.

[0109] After the slickwater injection in step 8), begin injecting CO2 foam slickwater containing 70-140 mesh proppant at a foam mass of 65%. Initially, a slug injection mode is used, with a proppant-to-liquid ratio of 2%-4%-6%-8%. The volume ratio of each slug to the proppant is 1:1, and the amount of proppant used per slug is 40m³. 3 320m of foam slick water 3Injecting another volume of spacer fluid (equivalent to one wellbore volume) will further increase the sand-to-fluid ratio to 10%–12%–14%–16%. The volume ratio of each slug to spacer fluid is 1:1, and the dosage for each sand-to-fluid ratio is 50 m³. 3 A total of 400m³ of CO2 foam slick water was used. 3 .

[0110] 10) Inject foam adhesive along with 30-50 mesh support agent to support the main joint.

[0111] The foam prepared in step 2) consists of 40% CO2 foam adhesive carrying 30-50 mesh proppant to support the main crack. Continuous sand addition is used, with a sand-to-liquid ratio of 12%-15%-18%-21%-24%, and the amount of sand used per sand-to-liquid ratio is 50 mg / L. 3 A total of 250m³ of CO2 foam adhesive was used. 3 The displacement is 16m 3 / min.

[0112] 11) Substitute work

[0113] After all sand additions are completed, 30m³ of foam with a mass of 40% CO2 foam adhesive prepared in step 2) is used to replace the foam. 3 Then, replace 70m of the CO2 foam slick water prepared in step 2) with the foam mass of 50%. 3 This will continue until the completion of the first phase of construction. The displacement is 16m³. 3 / min.

[0114] 12) For fracturing operations in other sections, repeat steps 5) to 11), and gradually increase the area of ​​the groove required for each cluster of perforations in the direction from near target point A (i.e., the starting point of the horizontal wellbore) to target point B (i.e., the ending point of the horizontal wellbore). The specific increase ratio can be based on the hydraulic calculation results, so as to achieve a jetting velocity of more than 130 m / s for each cluster of fractures and a frictional resistance of 3 MPa to 5 MPa for the fluid inlet channel of each cluster of fractures; until all sections are completed.

[0115] 13) After pressing, return flow, testing and production shall be carried out in accordance with the conventional process and parameters.

[0116] By implementing the fracturing method of this invention in this well, the flowback rate after fracturing reached 44.8%, which is 1.8 times that of conventional fracturing. The post-fracturing production reached 7.3 tons / day, which is 1.5 times higher than that of conventional fracturing methods in adjacent wells at the same formation.

[0117] Example 2

[0118] Well Y is a continental shale oil well. It is a horizontal well with a horizontal section length of 1200m, a total drilled depth of 4191m, and a vertical depth of 2449.99m. The well traverses a high-quality shale section ② of the Dongyuemiao Formation, East Sub-section, of the Lower Jurassic Ziliujing Group, with a reservoir thickness of 20m. The target formation ranges from 2555m to 4150.50mm; the lithology of this target formation is shale oil reservoir. Well logging interpretation shows a high clay mineral content (48.59-61.58%, average 53.57%), a felsic content (28.12-33.65%, average 30.70%), and a carbonate content (3.94-20.88%, average 13.69%).

[0119] The following is a detailed implementation process of the embodiment:

[0120] 1) Assessment of key reservoir parameters

[0121] First, the lithology, whole-rock mineral composition, physical properties, rock mechanical parameters, triaxial geostress, and geostress distribution characteristics of each longitudinal sublayer were analyzed and evaluated for the core sample of the target layer in well Y. The development of horizontal bedding fractures and high-angle natural fractures was also assessed. The corresponding parameters for the horizontal sections were mainly obtained based on analogy results from well logging parameters.

[0122] 2) Preparation of construction foam slippery water and foam adhesive

[0123] According to the fracturing design plan, 150 ml of CO2 foam adhesive with a foam content of 90% was prepared on-site before construction. 3 The viscosity is 60 mPa·s; 320 ml of CO2 foam adhesive with a foam mass of 30% is used. 3 Viscosity of 50 mPa·s; Low viscosity slickwater 100 m 3 The viscosity is 6 mPa·s; 900 m³ of CO2 foam slick water with a foam mass of 50% was produced. 3 A 100m³ CO2 foam slick with a viscosity of 6 mPa·s and a foam mass of 45% was prepared. 3 The viscosity is 6 mPa·s. In the above foamed slick, the concentration of SRAP-1 acid as a drag reducer is 0.2 wt%, and in the above foamed adhesive, the concentration of SRAP-1 acid as a drag reducer is 0.5 wt%.

[0124] 3) Optimization of fracture parameters and fracturing operation parameters

[0125] (1) The fracture length, conductivity, and cluster spacing were optimized using the reservoir numerical simulation software ECLIPSE. The optimal number of fracturing sections was 33 sections. In this well, the main fracturing sections consist of 3-4 clusters of perforations with a cluster spacing of 9-12m, averaging 10.1m, and a section spacing of 13-16m. Sections 1, 12, 13, 16-18, 21, and 32 have 3 clusters of perforations, while the remaining sections have 4 clusters of perforations. The main fracture length is 255m, and the conductivity is 3d.cm. The branch fracture length is 110m, the branch fracture spacing is 8.3m, and the conductivity is 1d.cm.

[0126] Based on the reservoir numerical simulation results, the fracturing operation parameters were optimized using the fracture propagation simulation software MEYER. The optimal fracturing displacement was determined to be 16 m³ / s. 3 / min, average total liquid volume per segment 1700m 3 Supportive dose 84.2m 3 (Of which, the proportion of small particles with a diameter of 70–140 mesh is 39.2m) 3 , 30~50 mesh 84.2m 3 The proppant is silica sand;

[0127] 4) Lowering the cementing sleeve

[0128] Based on the fracturing design scheme and the optimized segment cluster results in step 3), a compliant multi-stage cementing sleeve was installed and cementing operations were performed according to specifications. The cementing sleeve was positioned at each perforation cluster location in the fracturing design, and each sleeve contained a rectangular groove evenly distributed around its circumference. The number of grooves was the same as the number of perforation clusters in the section to be fractured. Each groove had a length of 13mm and a width of 3mm, ensuring that the injection velocity of each fracture cluster in the fracturing section was above 130m / s and the friction of the fluid inlet channel in each fracture cluster was 5MPa.

[0129] 5) Open the slide when throwing the ball.

[0130] After cementing the sliding sleeve is completed, before fracturing operations, a ball is dropped to open the three grooved sliding sleeves of the first stage of fracturing and perform three cluster perforations.

[0131] 6) Acid pretreatment operation

[0132] The first stage of fracturing operation used a 10m... 3 Rare earth acid, with a concentration of 15 wt%, is used for pretreatment to reduce reservoir fracture pressure, with a discharge rate of 2 m³ / min.

[0133] 7) Inject foam adhesive to create the main joint

[0134] The foam adhesive prepared in step 2) with a foam mass of 90% was injected during construction, and a total of 100m³ of foam adhesive was injected. 3 The displacement is 16m 3 / min.

[0135] 8) Inject low-viscosity slippery water to create branch joints

[0136] The low-viscosity slickwater prepared in step 2) was injected during construction to connect and extend the branch joint system. A total of 60 m³ of slickwater with a viscosity of 6 mPa·s was injected. 3 The displacement is 16m 3 / min.

[0137] 9) Inject foam-slippery water carrying 70-140 mesh proppant to create and support branch joints.

[0138] After the slickwater injection in step 8), begin injecting CO2 foam slickwater with 70-140 mesh proppant, comprising 50% of the foam mass. Initially, a slug injection method is used, with a proppant-to-liquid ratio of 2%-4%-6%-8%. The volume ratio of each slug to the proppant is 1:1, and the amount of proppant used per slug is 40m³. 3 320m of foam slick water 3 Injecting another volume of spacer fluid (equivalent to one wellbore volume) will further increase the sand-to-fluid ratio to 10%–12%–14%–16%. The volume ratio of each slug to spacer fluid is 1:1, and the dosage for each sand-to-fluid ratio is 60 m³. 3 A total of 480m³ of CO2 foam slick water was used. 3 A total of 39.2m of proppant was used. 3 The displacement is 16m 3 / min.

[0139] 10) Inject foam adhesive along with 30-50 mesh support agent to support the main joint.

[0140] The foam prepared in step 2) has a mass of 30% foam adhesive, which carries 30-50 mesh proppant to support the main crack. Continuous sand addition is used, with a sand-to-liquid ratio of 12%-15%-18%-21%-24%, and the amount of sand used for each sand-to-liquid ratio is 50 mg / L. 3 A total of 250m³ of foam adhesive was used. 3 A total of 45.0m of proppant was used. 3 The displacement is 16m 3 / min.

[0141] 11) Substitute work

[0142] After all sand additions are completed, 40m³ of foam adhesive prepared in step 2) is used to replace the foam. 3 Then, replace 60m of the CO2 foam slick water prepared in step 2) with the foam mass of 45%. 3 This will continue until the completion of the first phase of construction. The displacement is 16m³. 3 / min.

[0143] 12) For fracturing operations in other sections, repeat steps 5) to 11), and gradually increase the area of ​​the groove required for each cluster of perforations in the direction from near target point A (i.e., the starting point of the horizontal wellbore) to target point B (i.e., the ending point of the horizontal wellbore). The specific increase ratio can be based on the hydraulic calculation results, so as to achieve a jetting velocity of more than 130 m / s for each cluster of fractures and a frictional resistance of 3 MPa to 5 MPa for the fluid inlet channel of each cluster of fractures; until all sections are completed.

[0144] 13) After pressing, return flow, testing and production shall be carried out in accordance with the conventional process and parameters.

[0145] By implementing the fracturing method of this invention in this well, the flowback rate after fracturing reached 53.2%, which is 1.3 times that of conventional fracturing. The post-fracturing production reached 33.2 tons / day, which is 1.2 times higher than that of conventional fracturing methods in adjacent wells at the same formation.

[0146] The various embodiments of the present invention have been described above. These descriptions are exemplary and not exhaustive, nor are they limited to the disclosed embodiments. Many modifications and variations will be apparent to those skilled in the art without departing from the scope and spirit of the described embodiments.

Claims

1. A fracturing method for highly plastic shale oil reservoirs, characterized in that, The method includes: (1) Evaluation of key reservoir parameters; (2) Preparation and optimization of variable mass foam slipper and variable mass foam liquid; (3) Optimization of fracture parameters and fracturing construction parameters: adopt a fracturing construction design with fewer segments and more clusters, with each segment length being 60-70m and the number of clusters being 3-4 or 4-5 clusters; (4) Installation of cementing sleeve: The cementing sleeve is a multi-stage ball cementing sleeve; the cementing sleeve is set at the fracture position of each cluster of perforations; the jetting velocity of each cluster of fractures is above 130m / s; the friction of the fluid inlet channel of each cluster of fractures is 3MPa to 5MPa. (5) Open the cementing sleeve; (6) Acid pretreatment operation; (7) Construction of main cracks using foam adhesive; the carbon dioxide foam content of the foam adhesive is 80% to 90%; (8) Low-viscosity slickwater injection construction; (9) Injection of foamed slick water carrying proppant; injection of foamed slick water carrying 70-140 mesh proppant; viscosity of foamed slick water is 6 mPa.s to 9 mPa.s; (10) Injection of foam adhesive carrying proppant; injection of foam adhesive carrying 30-50 mesh proppant; viscosity of foam adhesive is 50 mPa.s to 60 mPa.s; (11) Substitute work.

2. The fracturing method as described in claim 1, characterized in that: Step (2), the mass of carbon dioxide foam in the foamy slippery water is 30% to 90%; In foamy, slippery water, the concentration of acid drag reducer is 0.2wt%-1.0wt%. The carbon dioxide foam content of the foam adhesive is 30%–90%. In the foam adhesive, the concentration of the acid drag reducer is 0.2wt%-1.0wt%.

3. The fracturing method as described in claim 1, characterized in that: In step (3), the number of clusters designed for the first three fracturing stages is 3 to 4, and the number of clusters designed for the subsequent fracturing stages is 4 to 5.

4. The fracturing method as described in claim 1, characterized in that: Step (4), The cementing sleeve includes 3 to 4 rectangular grooves, each groove being 10 to 15 mm long and 2 to 4 mm wide, and the grooves are evenly distributed on the circumference of the cementing sleeve.

5. The fracturing method as described in claim 4, characterized in that: The jetting velocity of each cluster of fissures is equal, and the friction of the liquid inlet channel of each cluster of fissures is equal.

6. The fracturing method as described in claim 1, characterized in that: Step (6), the acid used for acid pretreatment is hydrochloric acid or rare earth acid; The amount of acid used is 10m. 3 ~20m 3 ; Displacement is 1.0 to 1.5m. 3 / min.

7. The fracturing method as described in claim 2, characterized in that: Step (7), the volume of the foam adhesive liquid is 150m³. 3 ~200m 3 The displacement is taken as the maximum value under the wellhead pressure limit.

8. The fracturing method as described in claim 1, characterized in that: Step (8): The viscosity of the low-viscosity slickwater is 6 mPa·s to 9 mPa·s, and the volume is 80 m³ / s. 3 ~100m 3 The displacement is taken as the maximum value under the wellhead pressure limit.

9. The fracturing method as described in claim 2, characterized in that: Step (9): Foamed slickwater carrying 70-140 mesh proppant is injected. Initially, a slug injection mode is used, with a sand-to-liquid ratio of 2%-4%-6%-8%; the displacement is taken as the maximum value under the wellhead pressure limit. After the slug injection is completed, a long slug injection mode is used, with a sand-to-liquid ratio of 10%-12%-14%-16%; the displacement is taken as the maximum value under the wellhead pressure limit. When each fracturing section consists of 3–4 clusters of perforations, in the slug injection mode, the dosage per sand-fluid ratio is 30m³. 3 ~40m 3 In the long slug injection mode, the dosage for each sand-liquid ratio is 40m³. 3 ~50m 3 ; When each fracturing section has 4-5 clusters of perforations, in the slug injection mode, the dosage per sand-to-fluid ratio is 36m³. 3 ~52m 3 In the long slug injection mode, the dosage per sand-liquid ratio is 48m³. 3 ~65m 3 ; The carbon dioxide foam content of foamy slicks is 50%–70%.

10. The fracturing method as described in claim 2, characterized in that: Step (10): Foam adhesive liquid carrying 30-50 mesh proppant is injected, using a continuous sand addition mode, with a sand-liquid ratio of 12%-15%-18%-21%-24%; When each fracturing section has 3-4 clusters of perforations, the dosage per sand-fluid ratio is 40m³. 3 ~50m 3 ; When each fracturing section has 4-5 clusters of perforations, the dosage per sand-to-fluid ratio is 48m³. 3 ~65m 3 ; The mass of carbon dioxide foam in the foam adhesive is 30-50%; The displacement is taken as the maximum value under the wellhead pressure limit.

11. The fracturing method as described in claim 2, characterized in that: Step (11): The displacement amount is 110% to 120% of the volume of the wellbore in the current section; the first 30% to 40% of the displacement amount is replaced with foam adhesive, and then replaced with foam slickwater. The mass of carbon dioxide foam in the foam adhesive is 30-50%; The mass of carbon dioxide foam in slippery water is 30-50%. The displacement is taken as the maximum value under the wellhead pressure limit.

12. The application of a fracturing method as described in any one of claims 1 to 11 in oil drilling.