A method for sequential energy replenishment in long horizontal CO2 pre-fracturing

Abstract

The application provides a long horizontal section CO2 pre-fracturing gradient energy supplement method, and belongs to the technical field of oil and gas exploitation. The gradient energy supplement method quantitatively characterizes the influence of carbon injection amount on the parameters such as crude oil viscosity and rock mechanics through indoor experiments, determines the optimal carbon injection amount under different reservoir conditions with the target of improving the crude oil mobility ratio, and simultaneously adopts the methods such as increasing reservoir energy and drainage area to establish a CO2 injection gradient decreasing from the toe end to the heel end, and determines the optimal carbon injection amount at different horizontal section positions, so as to realize the improvement of the long horizontal section balanced producing degree and single well production through the multi-mechanism synergistic effect and differential energy supplement injection design.

Description

Technical Field

[0001] This invention belongs to the field of oil and gas extraction technology and provides a method for sequential energy replenishment through CO2 pre-fracturing in long horizontal sections. Background Technology

[0002] Shale oil reservoirs are influenced by sedimentary environments and diagenesis, resulting in variations in microstructure, fluid properties, and pressure coefficients. Given the deep burial depth and poor matrix properties of shale oil reservoirs, a development approach of "horizontal wells / high-angle wells + volumetric fracturing" is typically employed. This often involves increasing the length of the horizontal section to achieve efficient development. However, during production in long horizontal sections, two main factors arise: firstly, geological factors, primarily differences in formation pressure coefficients, porosity, permeability, and the degree of natural fracture development, lead to varying starting pressures and seepage capacities for crude oil within the reservoir; secondly, engineering factors primarily involve differences in flow resistance after crude oil flows from the reservoir into the wellbore, with resistance increasing closer to the toe, making it harder for crude oil to reach the wellhead. This severely impacts the overall inter-section equilibrium and limits oil recovery. A common problem is "inter-section non-equilibrium utilization," where production at the heel is significantly higher than at the toe. CO2 pre-fracturing technology, as a production enhancement measure, offers advantages such as increasing reservoir energy, reducing crude oil viscosity, and improving reservoir properties.

[0003] Chinese invention patent application CN116025322A discloses a multi-stage CO2 pre-fracturing system and method. This system forms a complete CO2 pre-fracturing operation system through the parallel design of multiple CO2 storage tanks, pressure regulation of vertical buffer tanks, and series configuration of multi-stage booster pumps. In terms of process design, it specifies that the pressure in the pre-CO2 injection stage will be controlled at 80%-90% of the rock fracturing pressure, variable displacement control will be implemented in the main fracturing fluid injection stage, and a stepped proppant addition procedure will be adopted in the proppant injection stage. Simultaneously, combined with an intelligent control system, the construction plan can be adjusted in real time according to the formation response. However, the optimization of injection parameters mainly focuses on improving efficiency at single points, lacking a perspective of balanced utilization across the entire well section.

[0004] In addition, existing CO2 pre-fracturing technologies mostly adopt uniform injection or simple slug injection, which fail to be specifically designed for the uneven pressure distribution and reservoir characteristics of long horizontal well sections. This results in insufficient energy replenishment and effect of CO2 at the toe, and cannot effectively solve the problem of balanced utilization.

[0005] Therefore, there is an urgent need for a new CO2 pre-fracturing technology that can achieve balanced and efficient utilization throughout the entire well section. Summary of the Invention

[0006] Due to the strong heterogeneity of the reservoir and the large differences in flow resistance in long horizontal sections, the uneven energy distribution between the heel and toe ends results in significant differences in production contributions between sections, with production near the heel being much higher than near the toe, leading to low final recovery rates. Existing CO2 pre-fracturing technologies mostly employ uniform injection or simple slug injection, which are not suitable for the uneven pressure distribution and reservoir characteristics in long horizontal wells. Therefore, this invention provides a stepwise energy replenishment method for long horizontal CO2 pre-fracturing and related technologies. It comprehensively considers geological and engineering factors that may affect production, synergistically utilizes multiple CO2 production-enhancing mechanisms, maximizes the mobility ratio of crude oil in the reservoir and the near-toe flow capacity in the wellbore, establishes a CO2 injection gradient decreasing from the toe to the heel, effectively compensates for the energy disadvantage at the toe, and achieves balanced utilization of long horizontal sections and improved single-well production.

[0007] Terminology Explanation: Unless otherwise defined, all technical terms used herein have the same meanings as commonly understood by one of ordinary skill in the art to which this subject matter pertains. Unless otherwise stated, all patents, patent inventions, and disclosures cited throughout this document are incorporated herein by reference in their entirety. Where multiple definitions exist for terms herein, the definitions provided in this chapter shall prevail.

[0008] It should be understood that the above brief description and the following detailed description are exemplary and for illustrative purposes only, and do not limit the subject matter of the invention in any way. In this invention, the singular is used in conjunction with the plural unless otherwise specifically stated. It should also be noted that, unless otherwise stated, the use of “or” or “or” means “and / or”. Furthermore, the use of the term “comprising” and other forms such as “including,” “containing,” and “contains” are not limiting.

[0009] The definition of the standard chemical term can be found in the reference "Theory and Technology of Heavy Oil Extraction", edited by Lu Teng, Li Zhaomin and Li Binfei, published by China Petrochemical Press in June 2021.

[0010] Unless otherwise stated, conventional methods within the scope of the art shall be used.

[0011] Unless specifically defined herein, the use of all commercially available products herein employs standard techniques. For example, it may be carried out using the manufacturer's instructions for use with the kit, or in accordance with methods known in the art or the description of this invention. The techniques and methods described herein can generally be implemented according to conventional methods well known in the art, based on the descriptions in the various summary and more specific documents cited and discussed in this specification.

[0012] The terms “optional / arbitrary” or “optionally / arbitrarily” mean that the event or situation described below may or may not occur, including both the occurrence and non-occurrence of the event or situation.

[0013] This invention provides a method for sequential energy replenishment through CO2 pre-fracturing in long horizontal sections, comprising the following steps: S1: Determine the optimal carbon injection amount to improve the mobility ratio: Sequentially determine the optimal carbon injection amount to reduce crude oil viscosity and the optimal carbon injection amount to improve reservoir properties, and then determine the optimal carbon injection amount to improve the mobility ratio; S2: Determine the optimal carbon injection amount to balance the flow resistance of the long horizontal section: The specific operation is as follows: (1) Divide the horizontal segment into i segments and calculate the frictional pressure drop of each segment according to the Darcy-Weisbach equation. ΔP f,i and target energy replenishment pressure difference ΔP target,i ; (2) Using the principle of mass balance, the increase in fluid volume Δ required to raise the regional pressure is obtained. V req,i ; (3) Based on the CO2 density under the wellhead injection pressure, convert the underground volume to the CO2 volume under the standard surface conditions; S3: Design of sequential energy replenishment carbon injection parameters: Based on the optimal carbon injection amount for improving the flow ratio obtained in step S1, and combined with the optimal carbon injection amount for balancing the flow resistance of the long horizontal section calculated in S2, determine the sequential energy replenishment carbon injection amount. S4: Validation and Optimization: Analyze and evaluate the degree of balanced utilization between long horizontal segments using tracer monitoring technology, optimize the amount of carbon injected and injection parameters, and achieve balanced utilization and maximum production of long horizontal segments.

[0014] As some preferred embodiments of the present invention, in S1, under reservoir temperature and pressure conditions, the viscosity of crude oil under different carbon injection amounts is tested to determine the optimal carbon injection amount to reduce crude oil viscosity.

[0015] As some more preferred embodiments of the present invention, in S1, the minimum amount of CO2 during the stage where the crude oil viscosity remains stable as the amount of carbon injected increases is the optimal amount of carbon injected.

[0016] As some preferred embodiments of the present invention, in S1, under reservoir temperature and pressure conditions, the mineral composition and dissolution pore size variation characteristics of core samples under different carbon injection amounts are tested, and the permeability variation characteristics at different reaction times after carbon injection are tested to determine the optimal carbon injection amount for improving reservoir properties.

[0017] As a more preferred embodiment of the present invention, in S1, the optimal CO2 injection amount is the lowest amount in which the relative decrease in the content of calcite and dolomite remains stable as the amount of carbon injection increases, and the increase in the proportion of dissolution pore sizes of 30-60 μm and 60-80 μm remains stable. Since CO2 injection into the reservoir dissolves the unstable minerals calcite and dolomite in the rock, the space occupied by these dissolved minerals is transformed into pores, leading to an increase in reservoir pore size and thus improving fluid flow channels. Combined with the characteristic that permeability increases with increasing reaction time after carbon injection, this further confirms that CO2 has the effect of improving physical properties.

[0018] As some preferred embodiments of the present invention, in S1, the overlap between the optimal carbon injection amount for reducing crude oil viscosity and the optimal carbon injection amount for improving reservoir properties is taken as the optimal carbon injection amount for increasing the mobility ratio.

[0019] As some preferred embodiments of the present invention, the frictional voltage drop ΔP f,i The calculation formula is as follows: Δ P f,i = f ×( L i / D )×( ρv ² / 2); In the formula: f This is the friction coefficient, which is related to the pipe wall roughness and Reynolds number; L i Let m be the length of the pipe from any point on the horizontal section to the wellhead; D Pipe diameter, in meters (m); ρ The fluid density is expressed in kg / m³. v The average flow velocity is expressed in m / s.

[0020] As some preferred embodiments of the present invention, the target energy replenishment pressure difference ΔP target,i The calculation formula is as follows: Δ P target,i =Δ P f,i -ΔP f,min ; In the formula: ΔP f,min The frictional resistance is approximately 0. ΔP f , i Let be the frictional resistance of the i-th segment, and the frictional resistance pressure drop of each segment is the pressure difference that needs to be compensated for that segment.

[0021] As some preferred embodiments of the present invention, the required increase in fluid volume Δ V req,i The calculation formula is as follows: Δ V req,i = C t × V p × ΔP target,i ; In the formula: V p The pore volume within the injection region; C t This is the overall compression coefficient.

[0022] As some preferred embodiments of the present invention, in S3, the optimal carbon injection amount for increasing the flow ratio is added to the optimal carbon injection amount for balancing the flow resistance of the long horizontal section, and this is taken as the optimal carbon injection amount.

[0023] As some preferred embodiments of the present invention, in S4, tracer monitoring technology is used to analyze the contribution rate of each fracturing section to evaluate the degree of balanced utilization between long horizontal sections, determine whether the preset level has been reached, and repeat steps S1-S3 based on actual production data and tracer monitoring results to optimize the amount of carbon injected.

[0024] In some specific embodiments of the present invention, when the production contribution rate of the proximal toe end is increased by more than 20% compared with that of a conventional hydraulically fractured adjacent well, the balance of production between long horizontal sections is effectively improved, which is considered to have reached the preset level.

[0025] Compared with the prior art, the beneficial effects of the present invention are as follows: The method of this invention takes into account the differentiated injection parameter design of "improving the reservoir crude oil mobility ratio" and "balancing the flow resistance in the wellbore". On the one hand, it comprehensively considers the influence on parameters such as crude oil viscosity and rock mechanics to determine the optimal carbon injection amount to improve the mobility ratio. On the other hand, it determines the optimal carbon injection amount to balance the flow resistance of the long horizontal section by "fixing the pressure difference with friction, the compensation with the pressure difference, and the volume with the compensation". By combining the optimal carbon injection amounts from both aspects, it achieves gradient energy replenishment in the long horizontal section.

[0026] Simultaneously, it is equipped with tracer monitoring technology to construct an integrated technology of "experimental characterization-theoretical modeling-dynamic regulation" to achieve synergistic effects of energy replenishment and reservoir transformation, providing reliable technical support for the efficient and balanced development of deep shale oil long horizontal sections.

[0027] Verification showed that, compared with conventional hydraulic fracturing wells, the experimental well significantly improved the production per unit pressure drop, the stable production period, and the peak production. At the same time, while ensuring that the production contribution rate of the middle section and the near-heel end did not decrease significantly, the production contribution rate of the near-toe end was greatly improved, significantly enhancing the utilization of the near-toe reservoir and effectively improving the balanced utilization between long horizontal sections. Attached Figure Description

[0028] Figure 1 This is a schematic diagram illustrating the formation of a long horizontal section of the wellbore with lower friction and higher kinetic energy according to the present invention. Figure 2 This is a flowchart of the long horizontal CO2 pre-fracturing gradient energy replenishment method of the present invention; Figure 3 This is a graph showing the relationship between different carbon injection amounts and viscosity of crude oil in a certain block, according to an embodiment of the present invention. Figure 4 This is a graph showing the change in mineral composition of a rock core from a certain block after reacting with CO2, according to one embodiment of the present invention. Figure 5 This is a graph showing the change in the radius of dissolution pores before and after the reaction of a rock core from a certain block with CO2 in one embodiment of the present invention. Figure 6 This is a permeability change curve of a rock core from a certain block after reacting with CO2 in one embodiment of the present invention; Figure 7 The tracer is used to monitor the product flow in each stage of the long horizontal CO2 pre-fracturing sequence replenishment method of the present invention. Figure 8 It serves as a tracer for monitoring the production of fluid in each stage of conventional hydraulic fracturing. Detailed Implementation

[0029] The following non-limiting embodiments are intended to enable those skilled in the art to gain a more comprehensive understanding of the present invention, but do not limit the invention in any way. The following content is merely an exemplary description of the scope of protection claimed by the present invention, and those skilled in the art can make various changes and modifications to the present invention based on the disclosed content, and such changes should also fall within the scope of protection claimed by the present invention.

[0030] The present invention will be further described below by way of specific embodiments. Unless otherwise specified, all instruments, devices, equipment, reagents, products, etc., used in the embodiments of the present invention are obtained through conventional commercial means.

[0031] like Figure 1 As shown, according to fluid mechanics theory, the frictional pressure drop in a horizontal wellbore follows the Darcy-Weisbach equation and is related to the flow distance. D Proportional to the decrease in friction along the toe tip (point B) and heel tip (point A). △PThe flow curve shows that near the toe (point B), the fluid must flow through the entire wellbore to reach the wellhead, resulting in the longest flow path and the greatest frictional loss. Near the heel (point A), which is closer to the production end, the flow path is the shortest, and the frictional loss is the smallest and can be approximately ignored. Simultaneously, as the fluid flows from the toe (point B) to the heel (point A), reservoir fluid continuously flows in along the way, causing variations in flow rate and velocity. v The pressure continues to increase, causing pressure at various points in the wellbore. P The difference in energy distribution from the toe to the heel results in a significantly higher effective production pressure differential at the heel end compared to the toe end under the same bottom hole pressure, leading to a much higher production contribution rate at the heel end compared to the toe end.

[0032] Therefore, this invention provides a method for sequential energy replenishment through CO2 pre-fracturing in long horizontal sections, such as... Figure 2 As shown, it includes the following steps: S1: Determine the optimal carbon injection amount to improve the mobility ratio: Sequentially determine the optimal carbon injection amount to reduce crude oil viscosity and the optimal carbon injection amount to improve reservoir properties, and then determine the optimal carbon injection amount to improve the mobility ratio; The optimal carbon injection amount for reducing crude oil viscosity is determined by testing the crude oil viscosity at different carbon injection amounts under reservoir temperature and pressure conditions. The lowest CO2 level during the period when the crude oil viscosity remains stable as the carbon injection amount increases is considered the optimal carbon injection amount.

[0033] The optimal carbon injection amount for improving reservoir properties was determined as follows: Under reservoir temperature and pressure conditions, the mineral composition and CO2 dissolution pore size changes of core samples were tested at different carbon injection amounts. The permeability changes at different reaction times after carbon injection were also tested to determine the optimal carbon injection amount for improving reservoir properties. The lowest CO2 injection amount, where the decrease in the relative content of calcite and dolomite slows down with increasing carbon injection amount, and the increase in the proportion of 30-60μm and 60-80μm dissolution pore sizes slows down, was identified as the optimal carbon injection amount. This, combined with the characteristic that permeability increases with increasing reaction time after carbon injection, further confirms that CO2 has a role in improving reservoir properties.

[0034] Furthermore, the overlap between the optimal carbon injection amount for reducing crude oil viscosity and the optimal carbon injection amount for improving reservoir properties is taken as the optimal carbon injection amount for increasing the mobility ratio.

[0035] S2: Determine the optimal carbon injection amount to balance the flow resistance of the long horizontal section: Based on the fluid dynamics theory of horizontal wellbore and the principle of energy conservation, determine the frictional pressure drop of the tubing in the long horizontal section, the target energy replenishment pressure difference, and the increase in fluid volume required for pressure boosting; determine the energy replenishment pressure difference required to balance the frictional resistance based on the frictional pressure drop characterizing the energy loss along the friction, and convert the energy replenishment pressure difference into fluid volume; Specifically, determining the optimal amount of carbon injection to balance the flow resistance of a long horizontal section includes the following steps: (1) Divide the horizontal segment into i segments and calculate the frictional pressure drop of each segment according to the Darcy-Weisbach equation. ΔP f,i and target energy replenishment pressure difference ΔP target,i ; (2) Using the principle of mass balance, the increase in fluid volume Δ required to raise the regional pressure is obtained. V req,i ; (3) Based on the CO2 density under the wellhead injection pressure, convert the underground volume to the CO2 volume under the standard surface conditions.

[0036] Wherein, the frictional voltage drop ΔP f,i The calculation formula is as follows: Δ P f,i = f ×( L i / D )×( ρv ² / 2) In the formula: f This is the friction coefficient, which is related to the pipe wall roughness and Reynolds number; L i Let m be the length of the pipe from any point on the horizontal section to the wellhead; D Pipe diameter, in meters (m); ρ The fluid density is expressed in kg / m³. v The average flow velocity is expressed in m / s.

[0037] Among them, the target energy replenishment pressure difference ΔP target,i The calculation formula is as follows: Δ P target,i =Δ P f,i -ΔP f,min In the formula: ΔP f,min The frictional resistance is approximately 0. ΔP f , i Let be the frictional resistance of the i-th segment, and the frictional resistance voltage drop of each segment is the energy required to compensate for that segment.

[0038] Wherein, the required increase in fluid volume Δ V req,i The calculation formula is as follows: Δ V req,i = C t ×V p × ΔP target,i In the formula: V p The pore volume within the injection region; C t This is the overall compression coefficient.

[0039] S3: Design of sequential carbon injection parameters: Based on the optimal carbon injection amount for improving the flow ratio obtained in step S1, and combined with the optimal carbon injection amount for balancing the flow resistance of the long horizontal section calculated in S2, determine the carbon injection amount. Specifically, the optimal carbon injection amount is obtained by adding the optimal carbon injection amount to increase the flow ratio and the optimal carbon injection amount to balance the flow resistance of the long horizontal section.

[0040] S4: Validation and Optimization: Analyze and evaluate the degree of balanced utilization between long horizontal segments using tracer monitoring technology, optimize the amount of carbon injected and injection parameters, and achieve balanced utilization and maximum production of long horizontal segments.

[0041] Specifically, tracer monitoring technology is used to analyze the production contribution rate of each fracturing section to assess the degree of balanced utilization between long horizontal sections, determine whether the process has achieved the expected results (the production contribution rate near the toe is increased by more than 20% compared with the conventional hydraulic fracturing of adjacent wells, effectively improving the balance of utilization between long horizontal sections), and repeat steps S1-S3 based on actual production data and tracer monitoring results to optimize the carbon injection amount.

[0042] Example This embodiment will provide a detailed description of the long horizontal section CO2 pre-fracturing sequence energy replenishment method of the present invention in conjunction with the CO2 pre-fracturing of well X in a certain block.

[0043] A method for sequential energy replenishment through CO2 pre-fracturing in long horizontal sections, comprising the following specific steps: The X well has a 1221.0m long fracturing section with a corresponding vertical depth of about 5000m. The total drilling depth is 6073.3m. There are a total of 23 fracturing sections and 76 clusters, with an average section spacing of 56m and an average cluster spacing of 17m. The surface crude oil viscosity at 50℃ is 35.65mPa·s. 139.7mm casing with a wall thickness of 14.27mm is used for production.

[0044] S1: Determine the optimal amount of carbon injection to reduce crude oil viscosity. Since CO2 dissolution reduces crude oil viscosity, a viscosity reduction experiment of the CO2-crude oil system was conducted under reservoir temperature of 110℃ and pressure of 70MPa, as detailed below: The carbon injection rate gradient was set to 5 mol%, 20 mol%, 40 mol%, 60 mol%, 80 mol%, and 95 mol%, with a reaction time of 24 h. The viscosity changes of crude oil under different carbon injection rates were measured using a high-temperature, high-pressure viscometer. The experimental results are as follows: Figure 3 As shown.

[0045] Figure 3 The results show that the 40mol%-60mol% range is saturated with stable viscosity. Considering both economic and viscosity-reducing advantages, the minimum carbon injection amount of 40 mol% in this range is taken as the optimal carbon injection amount, which translates to approximately 150-200t of carbon injection amount on site.

[0046] S2: Determine the optimal carbon injection amount to improve reservoir properties: Since CO2 dissolution improves reservoir properties, a CO2-water-rock reaction experiment was conducted using a CO2 immersion rock experimental apparatus at a temperature of 110℃ and a pressure of 20MPa, as detailed below: The experimental conditions were as follows: undersaturated (CO2 solubility of 0.3 mol / kg), saturated (CO2 solubility of 1.11 mol / kg), and supersaturated (CO2 solubility of 5 mol / kg). The parameters were set according to the following conditions: CO2 no longer dissolves in water and precipitates in solid form as the saturated state. The CO2 injection amount was designed and the reaction time was 24 h.

[0047] The changes in mineral composition were analyzed by X-ray diffraction and the changes in dissolution pore size were analyzed by scanning electron microscopy. The results are as follows: Figure 4 , Figure 5 As shown, permeability tests were conducted simultaneously before and after CO2 immersion, and the results are as follows. Figure 6 As shown.

[0048] Figure 4 The results showed that with the increase of carbon injection, the reaction degree of unstable minerals calcite and dolomite continuously increased, and their relative contents continuously decreased: the relative contents of calcite and dolomite in the undersaturated state decreased by 4.8% and 2.6% respectively compared with no CO2 injection; the relative contents of calcite and dolomite from the undersaturated state to the saturated state decreased by 6.1% and 4.6% respectively; and the relative contents of calcite and dolomite from the saturated state to the supersaturated state decreased by 4.9% and 3.2% respectively, with the decrease rate significantly narrowing compared with the previous stage, indicating a weakening of the dissolution effect.

[0049] Figure 5The results show that under the undersaturated state, the dissolution effect is limited, with the 30-60 μm pore size accounting for about 13.5% and the 60-80 μm pore size accounting for about 7.0%. From the undersaturated state to the saturated state, the proportion of the 30-60 μm pore size increases by about 25% and the proportion of the 60-80 μm pore size increases by about 11%, indicating that the effective pore space is significantly expanded after mineral dissolution and the seepage channels are greatly improved. From the saturated state to the supersaturated state, the proportion of the 30-60 μm range increases by only about 3% and the proportion of the 60-80 μm pore size increases by only about 6%, with the increase slowing down significantly.

[0050] At the same time Figure 6 The permeability tests before and after CO2 soaking showed that the permeability increased by 3.4 times after 14 days of reaction, further confirming that CO2 can improve reservoir properties by dissolving minerals and expanding pore size.

[0051] Considering economic factors, the degree of mineral dissolution, and changes in pore size ratio, the relative content of unstable minerals decreased most significantly after dissolution under saturated conditions, while the proportion of pore sizes in the 30-60μm and 60-80μm ranges increased the most. Under supersaturated conditions, the increase in these proportions slowed considerably, and further increases in carbon injection did not yield a proportional return on reservoir property improvement. Therefore, considering both the improvement effect of CO2 on reservoir properties and its utilization efficiency, the optimal carbon injection level for improving reservoir properties is at saturation (CO2 solubility of 1.11 mol / kg), which translates to approximately 100-150 tons of carbon injection on-site.

[0052] S3: Determine the optimal carbon injection amount to balance the flow resistance of the long horizontal section: The horizontal section of Well X is divided into three zones: a 1221m long horizontal section, further divided into three segments: the near-toe segment (814-1221m), the middle segment (407-814m), and the near-heel segment (0-407m). Based on the differences in frictional pressure required for different segment lengths, and considering the optimal carbon injection amount needed for crude oil viscosity reduction and permeability enhancement, the optimal carbon injection amount is calculated according to the increased formation pressure and the tubing friction that needs to be overcome after injecting different carbon amounts into the reservoir. The specific process is as follows: (1) Pressure drop due to friction in each section: Proximal toe segment: ΔP f,i =f×(L i / D)×(ρv² / 2) =1.54MPa; Middle section: ΔP f,i =f×(L i / D)×(ρv² / 2) =0.924MPa; Proximal heel section: ΔP f,i =f×(Li / D)×(ρv² / 2) =0.308MPa.

[0053] (2) Target energy replenishment pressure difference: Proximal toe segment: Δ P target,i =Δ P f,i -ΔP f,min =1.232MPa; Middle section: Δ P target,i =Δ P f,i -ΔP f,min =0.616MPa; Proximal heel section: Δ P target,i =Δ P f,i -ΔP f,min =0MPa.

[0054] (3) Required increase in fluid volume: Proximal toe segment: Δ V req,i = C t × V p × ΔP target,i =181m 3 ; Middle section: Δ V req,i = C t × V p × ΔP target,i =90.5m 3 ; Proximal heel section: Δ V req,i = C t × V p × ΔP target,i =0m 3 .

[0055] (4) Convert to ground CO2 mass: Proximal toe segment: Q ,i = ΔV req,i × ρ CO2 ×10 -3 =99.55t; Middle section: Q ,i = ΔV req,i × ρ CO2 × 10 -3 =49.78t; Proximal heel section: Q ,i = ΔV req,i × ρ CO2 × 10 -3 =0t.

[0056] The calculated carbon injection amounts required for the three sections from the toe to the heel are 100t, 50t, and 0t, respectively.

[0057] S4: Implement the "interval injection + first create a crack and then inject carbon" operation mode.

[0058] The optimized carbon injection amount in step S1 is approximately 150-200 t, and in step S2 it is approximately 100-150 t. The carbon injection amount required to supplement the toe segment to the heel segment in step S3 is 100t, 50t, and 0t, respectively. Therefore, based on the optimized original carbon injection amount of S1 and S2, it is 150t / segment. Adding the carbon injection amount of 100t, 50t, and 0t required to supplement the friction loss along the way in each segment, the pre-energy replenishment stage is defined as follows: the carbon injection amount is designed to be 250t / segment for the near toe 1 / 3 segment, 200t / segment for the middle 1 / 3 segment, and 150t / segment for the near heel 1 / 3 segment. The well employs a "segmented injection + fracture creation followed by carbon injection" operation mode, with a total of 12 injection segments. Among them, the near-toe 1 / 3 segment has 4 carbon injection segments with a carbon injection volume of 1000 tons (250t / segment × 4 segments = 1000 tons); the middle 1 / 3 segment has 4 carbon injection segments with a carbon injection volume of 800 tons (200t / segment × 4 segments = 800 tons); and the near-heel 1 / 3 segment has 4 carbon injection segments with a carbon injection volume of 600 tons (1500t / segment × 4 segments = 600 tons). The total designed carbon injection volume for this well is 2400 tons, and the carbon discharge rate is constructed according to the maximum discharge rate that the carbon dioxide storage tank equipped on site can provide.

[0059] Hydraulic fracturing stage: Displacement rate 16-18m³ 3 / min, sand strength 2.0m 3 / m, liquid strength 37.8m 3 / m, the proppant uses a combination of 70 / 140+40 / 70 mesh ceramsite, and the fracturing fluid uses a polymer system for conventional hydraulic fracturing.

[0060] S5: A comprehensive evaluation system for utilizing production dynamic monitoring and tracer monitoring analysis: The production data of each section monitored by tracer in the test well and adjacent well (conventional hydraulic fracturing) are shown below. Figure 7 and Figure 8 The key indicators such as unit pressure drop production, stable production period, and peak production were compared and analyzed with those of adjacent wells. At the same time, the production contribution rate of each section was accurately measured, and the inter-section utilization balance was evaluated. The results are shown in Table 1.

[0061] Table 1

[0062] Compared with conventional hydraulically fractured adjacent wells, the production contribution rate of the near-toe 1 / 3 of the test well X increased by 22.4%, significantly improving the utilization of the near-toe reservoir and effectively improving the balanced utilization between long horizontal sections.

[0063] Finally, it should be noted that the above content is only used to illustrate the technical solution of the present invention, and is not intended to limit the scope of protection of the present invention. Simple modifications or equivalent substitutions made by those skilled in the art to the technical solution of the present invention do not depart from the essence and scope of the technical solution of the present invention.

Claims

1. A method for sequential energy replenishment through CO2 pre-fracturing in long horizontal sections, characterized in that, Includes the following steps: S1: Determine the optimal carbon injection amount to improve the mobility ratio: Sequentially determine the optimal carbon injection amount to reduce crude oil viscosity and the optimal carbon injection amount to improve reservoir properties, and then determine the optimal carbon injection amount to improve the mobility ratio; S2: Determine the optimal amount of carbon injection to balance the flow resistance of the long horizontal section. The specific operation is as follows: (1) Divide the horizontal segment into i segments and calculate the frictional pressure drop of each segment according to the Darcy-Weisbach equation. ΔP f,i and target energy replenishment pressure difference ΔP target,i ; (2) Using the principle of mass balance, the increase in fluid volume Δ required to raise the regional pressure is obtained. V req,i ; (3) Based on the CO2 density under the wellhead injection pressure, convert the underground volume to the CO2 volume under the standard surface conditions; S3: Design of sequential energy replenishment carbon injection parameters: Based on the optimal carbon injection amount for improving the flow ratio obtained in step S1, and combined with the optimal carbon injection amount for balancing the flow resistance of the long horizontal section calculated in S2, determine the sequential energy replenishment carbon injection amount. S4: Validation and Optimization: Analyze and evaluate the degree of balanced utilization between long horizontal segments using tracer monitoring technology, optimize the amount of carbon injected and injection parameters, and achieve balanced utilization and maximum production of long horizontal segments.

2. The long horizontal CO2 pre-fracturing gradient energy replenishment method according to claim 1, characterized in that, In S1, under reservoir temperature and pressure conditions, the viscosity of crude oil under different carbon injection amounts is tested to determine the optimal carbon injection amount to reduce crude oil viscosity.

3. The long horizontal CO2 pre-fracturing gradient energy replenishment method according to claim 2, characterized in that, In S1, the optimal amount of carbon injection is the lowest CO2 level during the stage where the crude oil viscosity remains stable as the amount of carbon injected increases.

4. The long horizontal CO2 pre-fracturing gradient energy replenishment method according to claim 1, characterized in that, In S1, under reservoir temperature and pressure conditions, the mineral composition and dissolution pore size of core samples with different carbon injection amounts were tested, and the permeability changes at different reaction times after carbon injection were tested to obtain the optimal carbon injection amount for improving reservoir properties.

5. The long horizontal CO2 pre-fracturing gradient energy replenishment method according to claim 4, characterized in that, In S1, the optimal carbon injection amount is the lowest CO2 amount in the stage where the relative content of mineral components calcite and dolomite decreases steadily with the increase of carbon injection amount, and the increase of the proportion of dissolution pore size in 30-60μm and 60-80μm remains stable.

6. The long horizontal CO2 pre-fracturing gradient energy replenishment method according to claim 1, characterized in that, In S1, the overlap between the optimal carbon injection amount for reducing crude oil viscosity and the optimal carbon injection amount for improving reservoir properties is taken as the optimal carbon injection amount for increasing the mobility ratio.

7. The long horizontal CO2 pre-fracturing gradient energy replenishment method according to claim 1, characterized in that, The frictional voltage drop ΔP f,i The calculation formula is as follows: D P f,i = f ×( L i / D )×( ρv ² / 2); In the formula: f This is the friction coefficient, which is related to the pipe wall roughness and Reynolds number; L i Let m be the length of the pipe from any point on the horizontal section to the wellhead; D Pipe diameter, in meters (m); ρ The fluid density is expressed in kg / m³. v The average flow velocity is expressed in m / s.

8. The long horizontal CO2 pre-fracturing gradient energy replenishment method according to claim 1, characterized in that, The target energy replenishment pressure difference ΔP target,i The calculation formula is as follows: D P target,i =D P f,i -ΔP f,min ; In the formula: ΔP f,min To keep up with the friction, ΔP f,i Let be the frictional resistance of the i-th segment, and the pressure drop across each segment is the pressure difference that needs to be compensated for in the i-th segment.

9. The long horizontal CO2 pre-fracturing gradient energy replenishment method according to claim 1, characterized in that, The required increase in fluid volume Δ V req,i The calculation formula is as follows: D V req,i = C t × V p × ΔP target,i ; In the formula: V p The pore volume within the injection region; C t This is the overall compression coefficient.

10. The long horizontal CO2 pre-fracturing gradient energy replenishment method according to claim 1, characterized in that, In S3, the optimal carbon injection amount for increasing the flow ratio is added to the optimal carbon injection amount for balancing the flow resistance of the long horizontal section, and this is taken as the optimal carbon injection amount.

11. The long horizontal CO2 pre-fracturing gradient energy replenishment method according to claim 1, characterized in that, In S4, tracer monitoring technology is used to analyze the contribution rate of each fracturing section to assess the degree of balanced utilization between long horizontal sections, determine whether the preset level has been reached, and repeat steps S1-S3 based on actual production data and tracer monitoring results to optimize the amount of carbon injected.

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