Horizontal well energy storage volume fracturing development effect prediction method

Abstract

The invention belongs to the field of oil reservoir exploration and development, and discloses a horizontal well energy storage volume fracturing development effect prediction method. By using the flow-back rate method, the maximum accumulated oil production, the recovery ratio and the like of pressure accumulation production can be predicted, and on one hand, reference is provided for analysis of the single well fracturing effect and economic benefits and design and optimization of a fracturing scheme; and on the other hand, a basis is provided for extraction after pressure storage and production management, the energy storage volume fracturing underground fluid and fracturing energy are efficiently utilized, and an important basis is provided for achieving stable and high yield.

Description

Technical Field

[0001] This invention belongs to the field of oil reservoir exploration and development, specifically relating to a method for predicting the development effect of horizontal well energy storage volumetric fracturing. Background Technology

[0002] China possesses abundant tight oil and shale oil resources, which represent the most realistic and strategic alternative oil resources. China's recoverable shale oil resources amount to 55 × 10⁻⁶. 8 China's continental shale oil reserves account for 9.7% of the world's recoverable resources. With breakthroughs in oil and gas geological theory and advancements in engineering technology, China has achieved significant progress in continental shale oil exploration and development.

[0003] Currently, tight oil and shale oil development primarily relies on horizontal well fracturing with fractured networks (hereinafter referred to as "fracturing") to increase single-well production in the early stages of development. The fracturing mechanism is complex and influenced by numerous factors, involving geology, reservoir, technology, materials, and production management. Evaluation of fracturing effectiveness plays a crucial role in reservoir development, economical and effective utilization, fracturing technology advancement, and production system optimization, and related research has been conducted both domestically and internationally. Jiao Fangzheng established an empirical formula for fractured network swept volume and corrected it using production data, creating a correlation chart between fracturing and production capacity to guide the optimization of fracturing engineering parameters. However, this study did not consider the impact of different production systems on production after fracturing. Lu Xiangwei et al. evaluated the fracturing effects of horizontal wells of different scales over the years in the A83 shale reservoir, determining that formation energy is a key factor in ensuring fracturing effectiveness. Chang Lingyun used training and test data to establish an evaluation model, improved the gradient boosting decision tree, and analyzed the fracturing well effects to determine the fracturing outcome. Huang Zhiwen proposed a systematic evaluation of fracturing effectiveness based on four indicators: technological feasibility, production enhancement, maturity, and economic efficiency, but specific models and algorithms are lacking. Li Kaikai et al. studied the increase in single-well production after improvements in technology such as extreme cluster perforation, reservoir differentiation, and multi-stage dynamic temporary plugging in shale oil water injection and repeated fracturing for energy replenishment in horizontal wells. Evaluation of fracturing effectiveness is mainly limited to fracturing construction data analysis, microseismic monitoring, geostress modeling and fracture prediction, and reservoir numerical simulation analysis. Other studies focus more on geological and engineering factors affecting volumetric fracturing effectiveness, such as reservoir thickness, permeability, fracture orientation, interlayer frequency, fracture penetration ratio, and fracture conductivity. Backflow data is mostly used to calculate fracturing volume, lacking in-depth research on predicting and evaluating the effectiveness of fracture network volumetric fracturing using production dynamic indicators. Development and production indicators are the most objective and comprehensive indicators of drilling, pressure, and production engineering quality, including fracturing, and urgently need to be researched and established.

[0004] In conventional water-drive reservoirs, cumulative crude oil production and recovery rate can be determined using the A (B / C / D) type water-drive characteristic curve method or by directly applying definitions based on changes in oil saturation. However, in unconventional reservoirs, the formation pressure continuously decreases during the energy storage fracturing production stage, causing changes in crude oil volume factor, dissolved gas-oil ratio, crude oil viscosity, and crude oil density. Residual oil saturation and residual oil saturation also fluctuate, making them difficult to determine. Furthermore, unlike water-drive oilfields where formation pressure and seepage velocity are relatively stable and continuous water and energy replenishment is possible, energy storage fracturing involves a continuous decrease in formation pressure and water cut after early energy replenishment. Simply applying the Wp, Lp, WOR, and Np relationships of water-drive characteristics is insufficient because it does not satisfy the Buckley-Leverett water-drive theory, the Welge equation, and the condition of constant formation pressure. The linear or semi-logarithmic relationships of these indicators change with continuous production, becoming curves that are difficult to predict future trends in production indicators. Summary of the Invention

[0005] To overcome the shortcomings of existing technologies, this invention provides a method for predicting the development effect of horizontal well energy storage volumetric fracturing, called the flowback rate method. This method can predict the maximum cumulative oil production (fracturing estimated ultimate recovery, or F-EUR) and recovery rate of energy storage production. On the one hand, it provides a reference for the analysis of single-well fracturing effect and economic benefits, and for the design and optimization of fracturing schemes. On the other hand, it provides a basis for post-energy storage drainage and production management, and provides an important foundation for the efficient use of the fluid injected into the formation and fracturing energy in energy storage volumetric fracturing to achieve stable and high production.

[0006] The above-mentioned objective of this invention is achieved through the following technical solution: a method for predicting the development effect of horizontal well energy storage volumetric fracturing, comprising the following steps:

[0007] 1. Production data collection and organization;

[0008] 2. Calculate the fracturing fluid flowback rate and flowback volume;

[0009] 3. Calculate the return rate;

[0010] 4. Plot the semi-logarithmic relationship between the return rate and cumulative oil production;

[0011] 5. Determine the line segment from step 4, and apply trend line analysis to the line segment to obtain the intercept and slope;

[0012] 6. Predicting the development of F-EUR (Fuel Accumulation Regulator);

[0013] 7. Calculate the controlled geological reserves of a single well;

[0014] 8. Predict the recovery rate of fractured fracturing.

[0015] Furthermore, the production data in step 1 includes fracturing operation and production data, such as horizontal section length, oil layer encounter rate, fracturing section length, fluid injected into the formation, daily oil production, daily fluid production, daily water production, and cumulative oil production. The horizontal section length and oil layer encounter rate are used to predict well-controlled reserves. Daily fluid production and daily water production are used to determine the fracturing fluid flowback rate and flowback volume.

[0016] Furthermore, step 2 specifically involves: collecting data on injected water and fracturing fluid analysis; calculating the proportion of fracturing flowback fluid based on the analysis data using formula (1); multiplying this by the daily water production to obtain the daily production of fracturing flowback fluid; and summing the daily productions to obtain the cumulative fracturing fluid production W. f ;

[0017] Let x be the proportion of fracturing fluid in the daily produced fluid, Appm be the chloride concentration in the fracturing fluid mix, B ppm be the chloride concentration in the reservoir formation water, and C ppm be the chloride concentration in the venting or pumping produced fluid. Then:

[0018] x=(B–C) / (B–A) (1);

[0019] If the chloride concentration in the vented or pumped produced fluid is Appm, then x = 1, meaning the produced fluid is 100% fracturing fluid. Conversely, if the chloride concentration in the vented or pumped produced fluid is B ppm, then x = 0, meaning the produced fluid is 100% formation water.

[0020] Furthermore, step 3 specifically involves: using equation (2) and the W calculated in step 2... f Calculate the return rate

[0021] W fp =W f / Inj L *100 (2)

[0022] In the formula: W fp Return rate, %; W f Cumulative fracturing fluid production, m 3 Inj L Total amount of liquid entering the ground, m 3 .

[0023] Furthermore, the semi-logarithmic relationship between the return rate and cumulative oil production in step 4 is calculated using the following expression:

[0024] lg(W fp ) = a + b * N p (3)

[0025] In the formula: a and b are the intercept and slope of the trend line, respectively; the unit of a is dimensionless; and the unit of b is t. -1 ;

[0026] W fp , return rate, %;

[0027] N p Cumulative oil production, t.

[0028] Furthermore, in step 5, the straight line segment is R. 2 For line segments with a value greater than 0.81, a and b are the line intercept and slope, respectively. The unit of a is dimensionless, and the unit of b is t. -1 .

[0029] Furthermore, the cumulative oil production at 100% flowback of fracturing fluid in step 6, F-EUR, is the maximum cumulative oil production achievable during the fracturing development stage, N. p,max (unit: t), predict using the following formula:

[0030] N p,max = (2-a) / b (4)

[0031] Where a and b are the line intercept and slope in step 5, respectively; the unit of a is dimensionless, and the unit of b is t. -1 .

[0032] Furthermore, step 7 specifically involves: calculating the controlled geological reserves of a single well based on the horizontal section length and the oil layer drilling rate; if monitoring and numerical simulation are available to determine the effective reservoir volume (SRV), the actual single-well controlled reserves can also be calculated using the SRV volume method.

[0033] Furthermore, step 8 specifically involves: N from step 6 p,max Predict the recovery rate of fractured fracturing.

[0034] The beneficial effects of this invention compared with the prior art are as follows: The method proposed in this invention has been verified by all 15 energy storage fractured horizontal wells in two shale oil fields with a production time of more than 80 months and continuous production data: The logarithm of the flowback rate and the cumulative oil production have a linear correlation coefficient of 0.9645-0.9937 after the flowback rate reaches 20%, with an average of 0.9846.

[0035] The technology of this invention was applied to predict the oil recovery rate of major tight oil wells and shale oil wells in the oilfield, and the predictions were consistent with the production indicators and effects of each well. The fluid control production system design proposed in this invention has already achieved the expected results of increasing oil production and reducing water cut, and will guide the design of dozens of blowout and drainage wells in the future. Attached Figure Description

[0036] The present invention will be further described below with reference to the accompanying drawings and specific embodiments.

[0037] Figure 1These are two energy storage volumetric fracturing development wells that achieved increased oil production and reduced water production after adopting the fluid control production system proposed in this patent. In the figure, 1 is the vertical axis, with the left side representing daily fluid production and daily oil production (m³). 3 / d, t / d), the right side is the water content (%); 2. Horizontal axis, production date.

[0038] Figure 2 These are production curves of typical wells that exhibit different development effects due to varying drainage and production management systems after the commissioning of energy storage volumetric fracturing. In the figure, 1 is the horizontal axis, representing cumulative oil production (t); 2 is the vertical axis, representing the logarithm of the flowback rate (commonly used).

[0039] Figure 3 This is a correlation analysis curve between the runoff rate and cumulative oil production. In the figure, 1 is the horizontal axis, cumulative oil production (t); 2 is the vertical axis, the logarithm of the runoff rate, dimensionless. Detailed Implementation

[0040] The present invention is described in detail below through specific embodiments, but this does not limit the scope of protection of the present invention. Unless otherwise specified, the experimental methods used in the present invention are all conventional methods, and the experimental equipment, materials, reagents, etc. used can all be obtained commercially.

[0041] Example 1

[0042] Step 1: Production data collection and processing, including fracturing operation and production data such as horizontal section length, oil layer penetration rate, fractured section length, fluid injected into the formation, daily oil production, daily fluid production, daily water production, and cumulative oil production. Among these, horizontal section length and oil layer penetration rate are used to predict well-controlled reserves. Daily fluid production and daily water production are used to determine the fracturing fluid output.

[0043] Step 2: Collect data on water injection and fracturing fluid analysis. Based on the analysis data such as water properties, determine the fracturing fluid flowback rate and flowback volume.

[0044] Step 3: Calculate the return rate according to formulas (1) and (2).

[0045] Step 4: Apply equation (3) to plot the semi-logarithmic relationship curve between the return rate and cumulative oil production, and determine the straight line segment, i.e., R. 2 Line segments with a value greater than 0.81.

[0046] Step 5: Apply trendline analysis to the straight line segment to obtain the intercept and slope.

[0047] Step 6: Predict the F-EUR of the pressure storage development using Equation (4).

[0048] Step 7: Calculate the controlled geological reserves of a single well using the volumetric method based on the horizontal section length and reservoir encounter rate. If monitoring and numerical simulations determine the effective reservoir volume (SRV), the actual controlled reserves can also be calculated using the SRV volumetric method, thus predicting the fracture network fracturing recovery rate from Np,max.

[0049] The accumulation mechanism and characteristics of tight oil and shale oil, driven by overpressure, hydrocarbon generation, and self-enclosed reservoir formation, determine that shale oil is extracted through fracturing fluid percolation, displacement, and relocation, and is produced along with the fracturing fluid. The flowback rate is defined as the ratio of the cumulative fracturing fluid production to the total fluid injected into the formation, i.e.:

[0050] W fp =W f / Inj L *100 (1)

[0051] In the formula: W fp Return rate, %; W f Cumulative fracturing fluid production, m 3 Inj L Total amount of liquid entering the ground, m 3 .

[0052] The fracturing fluid production rate can be determined and calculated by combining the produced water volume with the produced water salinity / ion content, formation water salinity / ion content, fracturing fluid distribution salinity / ion content, and whether it is affected by water injection.

[0053] Let x be the proportion of fracturing fluid in the daily produced fluid, Appm be the chloride concentration in the fracturing fluid mix, B ppm be the chloride concentration in the reservoir formation water, and C ppm be the chloride concentration in the blowout (pumped) produced fluid. Then:

[0054] x=(B–C) / (B–A) (2)

[0055] If the chloride concentration in the venting (pumping) produced fluid is Appm, then x = 1, meaning the produced fluid is 100% fracturing fluid. Conversely, if the chloride concentration in the venting (pumping) produced fluid is B ppm, then x = 0, meaning the produced fluid is 100% formation water.

[0056] This allows us to determine the true backflow rate, apparent backflow rate, and liquid volume in the reservoir.

[0057] Based on the fracturing fluid percolation and drainage / oil displacement mechanism, and combined with statistical data on drainage and production, after the flowback rate exceeds 20%, the logarithm of the flowback rate shows a strong linear correlation with the cumulative oil production. That is, the semi-logarithmic relationship between the flowback rate and cumulative oil production in energy storage volume fracturing can be expressed as:

[0058] lg(W fp ) = a + b * N p (3)

[0059] In the formula: a and b are the intercept and slope of the trend line, respectively; the unit of a is dimensionless; and the unit of b is t. -1 ;

[0060] W fp , return rate, %;

[0061] N p Cumulative oil production, in tons;

[0062] The cumulative oil production when 100% of the fracturing fluid is flowed back is the maximum cumulative oil production achievable during the fracturing development phase, N. p,max (unit: t), predict using the following formula:

[0063] N p,max = (2-a) / b (4)

[0064] Innovation Point 1: A method for predicting the maximum cumulative oil production and recovery rate during the energy storage volume fracturing stage of energy storage fracturing based on the flowback rate method.

[0065] As the flowback rate increases, the formation pressure gradually decreases to the pre-fracturing level, the artificial fractures tend to close, and the stored energy is continuously released. Theoretically, a 100% flowback rate corresponds to the maximum cumulative oil production (F-EUR) of a single well during the energy storage volume fracturing development stage, which can be used as one of the indicators for predicting and evaluating fracturing effectiveness. In reality, due to the permeation and replacement of crude oil in the reservoir, a portion of the fracturing fluid will eventually remain in the micropores and fractures, and the actual flowback rate cannot reach 100%. Therefore, the predicted F-EUR is theoretical, but it still has significance as an evaluation and comparison indicator.

[0066] Because horizontal well length, drilling rate, oil layer thickness, and reservoir properties vary, dividing the maximum cumulative oil production of a single well by the single-controlled reserves yields a more consistent recovery rate for volumetric fracturing, which can be used as a normalized evaluation index to evaluate the production effect of volumetric fracturing.

[0067] Unlike waterflooding, energy storage volumetric fracturing is closer to large-scale huff and puff. It cannot directly use the waterflooding curve relationship based on the Buckley-Leverett linear displacement and Welge average water saturation equation. As mentioned earlier, the relationship between the changes in indicators such as production volume, oil production, and water-oil ratio is unclear, and it is necessary to explore new parameters and development indicators that conform to the characteristics of unconventional reservoirs.

[0068] Analysis of the daily oil production, water cut, water-oil ratio, and cumulative oil production of all 13 horizontal wells in the ZN region with continuous production time exceeding 330 days after hydraulic fracturing revealed that both flowback rate and oil production increased with production time. Due to the low porosity and permeability of unconventional reservoirs such as tight oil and shale oil, non-Darcy flow exists, leading to a continuously increasing proportion of adsorption-displacement oil displacement. The four-stage characteristics of adsorption-displacement efficiency over time gradually become apparent. After the flowback rate reaches a certain proportion, the cumulative oil production shows a highly linear relationship with the logarithm of the flowback rate. The timing of the appearance of the straight segment is related to reservoir properties; better reservoir properties result in an earlier appearance of the straight segment, with ultra-low permeability wells exhibiting the straight segment earlier than ultra-low permeability wells. It is also related to the flowback operating regime; a higher flowback rate makes the oil phase less continuous and stable, resulting in a later appearance of the straight segment.

[0069] The semi-logarithmic relationship of pressure accumulation reflects the adsorption and drainage mechanism after fracturing. On the one hand, most crude oil in tight reservoirs is stored in micro- and nano-pores, and shale oil adsorption and drainage play an important role in seepage, which is a crucial factor affecting the production rate and efficiency. The pores in tight reservoirs are mainly at the nanoscale, and the fluid occurrence mode and flow mechanism are different from those in conventional oil reservoirs. Adsorption is a process of replacing the non-wetting phase with the wetting phase through capillary force. Capillary force is the main driving force, and the seepage process includes different stages of different pore sizes and different oil displacement efficiencies, such as strong displacement of weak adsorption, weak displacement of strong adsorption, and weak displacement of weak adsorption. Crude oil is drained by the adsorption of fracturing fluid, and the adsorption oil displacement efficiency has a staged variation characteristic. After the window period, it successively goes through a high-speed adsorption and drainage period, a rapid adsorption and drainage period, and a low-speed adsorption and drainage period. The staged variation characteristics of adsorption and drainage determine the semi-logarithmic relationship between the flowback rate and the cumulative oil production. On the other hand, pressure buildup and fracturing of the reservoir create artificial fractures, which couple with natural fractures and dynamic fractures to form oil flow channels. Among these, the flow through medium and large fracture networks follows Darcy's law, while the flow through micro-fractures exhibits non-Darcy flow. In the early stages of production after fracturing, the pressure within the fracture network is high, the network is open, and the proportion of medium and large fractures is high. In the later stages of production, as the flowback rate increases, fluid is discharged, the pressure decreases, the fracture network gradually closes, the proportion of micro-fractures increases, and therefore the production rate decreases accordingly.

[0070] Innovation Point 2: Evaluation method for the development effect of energy storage volumetric fracturing, including:

[0071] 1) To evaluate the effectiveness of energy storage volume fracturing development based on the average daily oil production, F-EUR and pressure recovery rate in the first year, it is necessary to normalize to the length of the 100-meter horizontal section, i.e. the average daily oil production and F-EUR in the first year per 100-meter section.

[0072] 2) Evaluate the rationality of the return flow rate and analyze the impact of the drainage work system on the development effect.

[0073] The flowback rate significantly impacts the utilization efficiency of fracturing fluid. A higher flowback rate means that artificially replenished energy is released and consumed more quickly, and higher water content results in lower fracturing fluid utilization efficiency. The average flowback rate is the ratio of cumulative fracturing fluid production to well operation time. Controlling the flowback rate and efficiently and rationally utilizing the reservoir energy replenished is crucial for achieving high production and improving reservoir recovery. High-speed flowback does not equate to high-efficiency flowback; it hinders the flow of fluid and impairs the effective utilization of elastic energy. Therefore, controlling the flowback rate to match the flow of fluid is essential to achieving higher F-EUR and improving reservoir recovery.

[0074] Innovation Point 3: The establishment of a reasonable operating system for energy storage volumetric fracturing, including:

[0075] 1) Combining medium- and high-speed blowout under sand control with dynamic well shut-in accelerates the drainage of movable water in low oil saturation reservoirs and strips crude oil that has seeped into the rock surface, thus shortening the time to oil breakthrough;

[0076] 2) After pumping, control the drainage rate to protect and efficiently utilize formation energy while adapting to the oil-water mobility ratio, ensuring early oil breakthrough and production. The initial drainage rate should be 30-35 m / s. 3 / (d.km), the drainage speed can be adjusted according to the depth and rate of change of the dynamic liquid surface, and can be reduced to a minimum of 5-10m. 3 / (d.km).

[0077] After significant optimization and shortening of drilling, fracturing, and shut-in cycles in horizontal wells of tight oil and shale reservoirs, the timing and frequency of oil breakthrough during blowout and pump-down production have become the biggest factors restricting the effectiveness of energy storage fracturing, production rate, F-EUR (Frequency-Effective Recovery), recovery rate, and economic benefits. Based on static atmospheric pressure percolation experiments in multi-media reservoirs using shale oil core samples, it was found that percolation displacement efficiency exhibits a four-stage variation pattern: a window period, a high-speed period, a rapid period, and a low-speed percolation drainage period. A method for formulating a reasonable post-fracturing production regime, combining control of drainage rate during the drainage period with blowout and dynamic shut-in, is proposed to efficiently utilize fracturing energy, accelerate oil breakthrough, improve production rate, and enhance F-EUR and recovery rate.

[0078] Innovation Point 4: Proposes the true return rate, which is different from the apparent return rate.

[0079] Since the produced water from production wells is not entirely fracturing flowback fluid, the flowback rate calculated based on the produced water is called the apparent flowback rate. After deducting the formation water, the calculated flowback rate is the true flowback rate. The apparent flowback rate is multiplied by x in equation (1) to obtain the true flowback rate. The difference between the true flowback rate and the apparent flowback rate after 300 days of blowout / pump commissioning is 13.5%-27.6%, and the difference after 400 days of commissioning is 16.2%-36%. The longer the commissioning time, the lower the proportion of fracturing fluid in the produced fluid, and the greater the error in calculating the flowback rate by treating the produced fluid as fracturing flowback fluid.

[0080] The embodiments described above are merely preferred embodiments of the present invention, and not all feasible embodiments of the present invention. Any obvious modifications made by those skilled in the art without departing from the principles and spirit of the present invention should be considered to be included within the scope of protection of the claims of the present invention.

Claims

1. A method for predicting the development effect of horizontal well energy storage volumetric fracturing, characterized in that, The steps are as follows: S1. Production data collection and processing; S2. Calculate the fracturing fluid flowback rate and flowback volume; S3. Calculate the return rate; S4. Plot the semi-logarithmic relationship between the return rate and cumulative oil production; S5. Determine the line segment from step S4, and apply trend line analysis to the line segment to obtain the intercept and slope; S6. Predicting the development of pressure storage F-EUR; S7. Calculate the controlled geological reserves of a single well; S8. Predict the recovery rate of fractured fracturing.

2. The method for predicting the development effect of horizontal well energy storage volumetric fracturing according to claim 1, characterized in that, The production data in step S1 includes fracturing operation and production data, including horizontal section length, oil layer drilling rate, fracturing section length, fluid injection volume, daily oil production, daily fluid production, daily water production, and cumulative oil production. Among them, the horizontal section length and oil layer drilling rate are used to predict well-controlled reserves; daily fluid production and daily water production are used to split the fracturing fluid flowback rate and flowback volume.

3. The method for predicting the development effect of horizontal well energy storage volumetric fracturing according to claim 1, characterized in that, Step S2 specifically involves: collecting data on injected water and fracturing fluid analysis; calculating the proportion of fracturing flowback fluid based on the analysis data using formula (1); multiplying this by the daily water production to obtain the daily production of fracturing flowback fluid; and summing the daily productions to obtain the cumulative fracturing fluid production W. f ; Let x be the proportion of fracturing fluid in the daily produced fluid, Appm be the chloride concentration in the fracturing fluid mix, Bppm be the chloride concentration in the reservoir formation water, and Cppm be the chloride concentration in the venting or pumping produced fluid. Then: x = (BC) / (BA) (1); If the chloride concentration in the vented or pumped produced fluid is Appm, then x = 1, meaning the produced fluid is 100% fracturing fluid. Conversely, if the chloride concentration in the vented or pumped produced fluid is B ppm, then x = 0, meaning the produced fluid is 100% formation water.

4. The method for predicting the development effect of horizontal well energy storage volumetric fracturing according to claim 1, characterized in that, Step S3 specifically involves: using the formula (2) and the W calculated in step 2... f Calculate the return rate W fp =W f / Inj L *100 (2) In the formula: W fp Return rate, %; W f Cumulative fracturing fluid production, m 3 Inj L Total amount of liquid entering the ground, m 3 .

5. The method for predicting the development effect of horizontal well energy storage volumetric fracturing according to claim 1, characterized in that, The semi-logarithmic relationship between the return rate and cumulative oil production in step S4 is expressed by the following correlation formula: lg(W fp )=a+b*N p (3) In the formula: a and b are the intercept and slope of the trend line, respectively; the unit of a is dimensionless; and the unit of b is t. -1 ; W fp , return rate, %; N p Cumulative oil production, t.

6. The method for predicting the development effect of horizontal well energy storage volumetric fracturing according to claim 5, characterized in that, The straight line segment in step S5 is the curve R in step S4. 2 For line segments with a value greater than 0.81, a and b are the line intercept and slope, respectively. The unit of a is dimensionless, and the unit of b is t. -1 .

7. The method for predicting the development effect of horizontal well energy storage volumetric fracturing according to claim 6, characterized in that, The cumulative oil production at 100% flowback of fracturing fluid in step S6, F-EUR, is the maximum cumulative oil production achievable during the fracturing development phase. p,max The unit is t, and the following formula is used for prediction: N p,max =(2-a) / b (4) Where a and b are the line intercept and slope in step S5, respectively, with a in dimensionless units and b in units of t. -1 .

8. The method for predicting the development effect of horizontal well energy storage volumetric fracturing according to claim 1, characterized in that, Step S7 specifically involves calculating the controlled geological reserves of a single well using the volumetric method based on the horizontal section length and the oil layer encounter rate.

9. The method for predicting the development effect of horizontal well energy storage volumetric fracturing according to claim 8, characterized in that, In step S7, if there is monitoring and digital model to determine the SRV, the actual single-control storage can also be calculated by the SRV volume method.

10. The method for predicting the development effect of horizontal well energy storage volumetric fracturing according to claim 7, characterized in that, Specifically, step S8 involves: N from step 6... p,max Predict the recovery rate of fractured fracturing.

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