A method, system, and medium for optimizing parameters of tight oil and gas complex reservoir stimulation.

Abstract

This invention discloses a method, system, and medium for optimizing parameters of complex tight oil and gas reservoirs. The method includes: determining reservoir sections based on logging curves; selecting test sections based on these sections; obtaining the number, location, and calcium content of natural fractures based on the logging and imaging curves of the test sections; classifying reservoir types according to the number, location, and calcium content of natural fractures; including porous reservoirs, fractured reservoirs, and mixed reservoirs; determining perforation locations using different perforation determination methods for different reservoir types; optimizing the scale of proppant addition and fluid usage using different stimulation techniques and parameters; optimizing the pump sequence using different fracturing methods; and completing the proppant addition and fluid usage in stages. This invention overcomes the problems of abnormal construction and poor matching between fracturing parameters and reservoir conditions in conventional proppant fracturing methods in complex reservoirs, enabling full utilization of complex reservoirs and increasing single-well production.

Description

Technical Field

[0001] This invention relates to the field of tight oil and gas exploration and development, specifically to a method, system, and medium for optimizing parameters of complex tight oil and gas reservoir stimulation. Background Technology

[0002] With the increasing complexity of oil and gas exploration targets, tight oil and gas reservoirs have become an important replacement area. The Xujiahe Formation oil and gas reservoirs in the Tianfu Gas Field in the central Sichuan Basin are rich in resources and widely distributed, making it an important new block for oil and gas development in Sichuan and Chongqing. The Jianyang Block of the Tianfu Gas Field has a total of 20 numbered faults, all of which are reverse faults, with a main trend of NE-NE-East and the lithology mainly consisting of sandstone and shale.

[0003] The Xujiahe Formation sandstone and shale gas reservoirs in the Tianfu area are typical examples. However, the reservoir lithology is complex and the degree of development of natural fractures varies. Traditional slickwater fracturing technology with sand addition is used for reservoirs with underdeveloped natural fractures and those with developed fractures. This has led to difficulties in sand addition during some well operations, and the scale and discharge of the operation did not meet the design requirements. Sand blockage and other phenomena have occurred, failing to achieve the goal of fully transforming the reservoir and releasing the formation's production capacity.

[0004] The existing patent document CN117972575A, "A Method for Optimizing Fracturing Parameters in Tight Sandstone Gas Reservoirs," uses a mathematical clustering method based on the K-means algorithm to optimize fracturing parameters based on optimal production capacity. However, it does not consider specific reservoir types or the presence of natural fractures in the reservoir. Furthermore, it only optimizes proppant fracturing parameters and does not optimize acidizing process parameters during reservoir stimulation. Similarly, the existing patent document CN117108257A, "A Method for Optimizing Channel Fracturing Parameters," only considers whether the channels formed in the fractures after adding fiber to the proppant meet the conductivity requirements for oil and gas migration. It does not consider the amount of proppant added, the amount of fluid used, or the discharge rate for different reservoir types, nor does it consider the impact of the presence of natural fractures on the construction parameters.

[0005] In view of the above, this application is hereby submitted. Summary of the Invention

[0006] The technical problem this invention aims to solve is the difficulties encountered in conventional proppant fracturing, such as construction anomalies and poor matching between fracturing parameters and reservoir conditions. These limitations make it unsuitable for heterogeneous reservoirs with complex lithology and varying degrees of natural fracture development. The purpose of this invention is to provide a method, system, and medium for optimizing stimulation parameters in tight oil and gas complex reservoirs. Employing a categorized optimization method for complex reservoir stimulation parameters, this invention can match appropriate fracturing parameters to different types of reservoirs, fully utilizing the reservoir and releasing formation productivity while ensuring no waste of fracturing fluid and proppant. This invention overcomes the problems of construction anomalies and poor matching between fracturing parameters and reservoir conditions in conventional proppant fracturing in complex reservoirs, adapting to heterogeneous reservoirs with complex lithology and varying degrees of natural fracture development; achieving full utilization of complex reservoirs and increasing single-well production.

[0007] This invention is achieved through the following technical solution:

[0008] In a first aspect, the present invention provides a method for optimizing parameters of tight oil and gas complex reservoir stimulation, the method comprising:

[0009] The reservoir section is determined based on the well logging curve, and the oil testing section is selected based on the reservoir section;

[0010] Based on the logging curves and imaging logging curves of the test formation, the number, location, and calcium content of natural fractures were obtained.

[0011] Based on the number, location, and calcium content of natural fractures, different reservoir types are classified; reservoir types include porous reservoirs, fractured reservoirs, and mixed reservoirs.

[0012] For different reservoir types, different perforation determination methods are used to determine the perforation location, and different stimulation processes and parameters are used to optimize the scale of sand addition and fluid usage.

[0013] Furthermore, different reservoir types are classified, including:

[0014] If the number of fractures per unit length is greater than or equal to the first threshold, and the calcium content meets the first condition, then the reservoir type is a fractured reservoir.

[0015] If the number of fractures per unit length is greater than or equal to the second threshold, and the calcium content meets the second condition, then the reservoir type is a mixed reservoir.

[0016] If the number of fractures per unit length is greater than or equal to the third threshold but less than the second threshold, and the calcium content meets the third condition, then the reservoir type is a porous reservoir.

[0017] Furthermore, different methods for determining the location of perforations are employed, including:

[0018] For porous and mixed reservoirs, the perforation location is determined by cluster perforation.

[0019] For fractured reservoirs, continuous perforation is used to determine the perforation location.

[0020] Furthermore, the location of the perforation is determined using a clustered perforation method, including:

[0021] Based on the logging curves and imaging logging curves of the test zone, calculate the reservoir rock mechanical parameter curves along the well trajectory;

[0022] Based on the reservoir rock mechanical parameter curves, calculate the stress, fracture pressure, and brittleness index profile of the reservoir section;

[0023] Based on the reservoir properties and the stress, fracturing pressure and brittleness index profile of the reservoir section, cluster perforation is performed at locations where the reservoir properties meet the fourth condition, the stress and fracturing pressure meet the fifth condition, and the brittleness index meets the sixth condition. Each cluster adopts a spiral perforation method with a perforation density of 20 holes / meter and a cluster spacing of 8 to 10 meters / cluster, for a total of 40 to 48 holes / section.

[0024] Among them, the fourth condition refers to the reservoir porosity being greater than 0.085, the fifth condition refers to the minimum horizontal principal stress being at its minimum value within the reservoir section, and the sixth condition refers to the brittleness index being at its maximum value within the reservoir section.

[0025] Furthermore, the location of the perforation is determined using a continuous perforation method, including:

[0026] Based on the large-scale perforation within the reservoir section, spiral perforation is carried out from the top boundary to the bottom boundary of the reservoir section, with a perforation density of 16 holes / meter.

[0027] Furthermore, different modification processes and parameters were used to optimize the scale of sand addition and liquid usage, including:

[0028] For fractured reservoirs, a soil acid acidification process is adopted, and the skin coefficient is simulated using PT software to optimize the amount of acid used.

[0029] For mixed reservoirs, a composite temporary plugging + variable viscosity slickwater sand fracturing process is adopted. Based on Petrel numerical simulation of fracture length and conductivity, the amount of temporary plugging material, sand addition scale and fluid use scale are optimized.

[0030] For porous reservoirs, a fracturing process of pre-filled dilute hydrochloric acid + viscous slickwater with sand is adopted, and the amount of dilute hydrochloric acid used is half the volume of the wellbore. The scale of sand addition and fluid usage is optimized based on Petrel numerical simulation of fracture length and conductivity.

[0031] Furthermore, it also includes: optimizing injection displacement for different reservoir types, including:

[0032] For fractured reservoirs, the injection displacement is optimized based on the dissolution rate of the filling material in the fractures.

[0033] For porous reservoirs, the injection rate is optimized based on the range of injection string diameters.

[0034] For mixed reservoirs, the injection rate is optimized based on the dissolution rate of the filling material in the fractures and the range of injection string diameters.

[0035] Furthermore, the method also includes: optimizing the pump sequence using different fracturing methods, and completing the sand addition and fluid usage in stages.

[0036] Furthermore, the pump sequence was optimized using different fracturing methods, and the sand addition and fluid usage were completed in stages, including:

[0037] For fractured reservoirs, acidizing operations are carried out in stages to complete the sand addition and fluid usage.

[0038] For mixed-type and porous reservoirs, the proppant fracturing pump sequence is used to complete the proppant addition and fluid usage in stages, and slug fracturing is used in the early stage.

[0039] Furthermore, the criteria for determining the reservoir section are: matrix porosity ≥7%, or cement slurry leakage during logging with a leakage volume ≥10m³. 3 Or, the number of natural cracks developed is ≥2 per meter.

[0040] Secondly, the present invention provides a parameter optimization system for the stimulation of tight oil and gas complex reservoirs, the system comprising:

[0041] The reservoir section identification unit is used to identify reservoir sections based on well logging curves.

[0042] The oil testing zone selection unit is used to select the oil testing zone based on the reservoir zone;

[0043] The acquisition unit is used to obtain the number, location, and calcium content of natural fractures based on the logging curves and imaging logging curves of the test formation.

[0044] The reservoir type classification unit is used to classify different reservoir types based on the number, location, and calcium content of natural fractures; reservoir types include porous reservoirs, fractured reservoirs, and mixed reservoirs.

[0045] The optimization unit is used to determine the perforation location for different reservoir types using different perforation determination methods, and to optimize the scale of sand addition and fluid usage using different stimulation processes and parameters.

[0046] Furthermore, different reservoir types are classified, including:

[0047] If the number of fractures per unit length is greater than or equal to the first threshold, and the calcium content meets the first condition, then the reservoir type is a fractured reservoir.

[0048] If the number of fractures per unit length is greater than or equal to the second threshold, and the calcium content meets the second condition, then the reservoir type is a mixed reservoir.

[0049] If the number of fractures per unit length is greater than or equal to the third threshold but less than the second threshold, and the calcium content meets the third condition, then the reservoir type is a porous reservoir.

[0050] Furthermore, the optimization unit includes:

[0051] The first optimization subunit is used to determine the perforation location for different reservoir types using different perforation determination methods, including: for porous reservoirs and mixed reservoirs, using cluster perforation to determine the perforation location; for fractured reservoirs, using continuous perforation to determine the perforation location.

[0052] The second optimization subunit is used to optimize the scale of proppant addition and fluid usage for different reservoir types using different stimulation processes and parameters. This includes: for fractured reservoirs, using a soil-acid acidizing process and PT software to simulate the skin coefficient to optimize acid usage; for mixed reservoirs, using a composite temporary plugging + variable viscosity slickwater proppant fracturing process, optimizing the amount of temporary plugging material, proppant addition, and fluid usage based on Petrel numerical simulations of fracture length and conductivity; and for porous reservoirs, using a pre-concentrated dilute hydrochloric acid + variable viscosity slickwater proppant fracturing process, using half the wellbore volume of dilute hydrochloric acid pre-concentrated, optimizing the scale of proppant addition and fluid usage based on Petrel numerical simulations of fracture length and conductivity.

[0053] Furthermore, the location of the perforation is determined using a clustered perforation method, including:

[0054] Based on the logging curves and imaging logging curves of the test zone, calculate the reservoir rock mechanical parameter curves along the well trajectory;

[0055] Based on the reservoir rock mechanical parameter curves, calculate the stress, fracture pressure, and brittleness index profile of the reservoir section;

[0056] Based on the reservoir properties and the stress, fracturing pressure and brittleness index profile of the reservoir section, cluster perforations are performed at locations where the reservoir properties meet the fourth condition, the stress and fracturing pressure meet the fifth condition, and the brittleness index meets the sixth condition, and each cluster uses spiral perforations.

[0057] Among them, the fourth condition refers to the reservoir porosity being greater than 0.085, the fifth condition refers to the minimum horizontal principal stress being at its minimum value within the reservoir section, and the sixth condition refers to the brittleness index being at its maximum value within the reservoir section.

[0058] Determining the location of perforations using a continuous perforation method includes:

[0059] Based on the large-scale perforation within the reservoir section, spiral perforation is performed from the top boundary to the bottom boundary of the reservoir section.

[0060] Furthermore, the optimization unit also includes:

[0061] The third optimization subunit is used to optimize the pump sequence using different fracturing methods, and to complete the sand addition and fluid usage in stages. This includes: for fractured reservoirs, using acidizing pump sequence to complete the sand addition and fluid usage in stages; for mixed and porous reservoirs, using sand fracturing pump sequence to complete the sand addition and fluid usage in stages, with slug fracturing used in the early stage.

[0062] Thirdly, the present invention also provides an electronic device, including a memory, a processor, and a computer program stored in the memory and executable on the processor, wherein the processor executes the computer program to implement the above-mentioned method for optimizing parameters of tight oil and gas complex reservoirs.

[0063] Fourthly, the present invention also provides a computer-readable storage medium storing a computer program that, when executed by a processor, implements the above-described method for optimizing parameters of tight oil and gas complex reservoirs.

[0064] Fifthly, the present invention also provides a computer program product, including a computer program / instruction, which, when executed by a processor, implements the steps of the above-described method for optimizing parameters of a tight oil and gas complex reservoir.

[0065] Compared with the prior art, the present invention has the following advantages and beneficial effects:

[0066] This invention discloses a method, system, and medium for optimizing parameters in complex tight oil and gas reservoirs. It employs a categorized optimization method for complex reservoirs, enabling the matching of appropriate fracturing parameters to different reservoir types. This fully utilizes the reservoir and releases formation productivity while ensuring minimal waste of fracturing fluid and proppant. This invention overcomes the challenges of abnormal fracturing operations and poor matching between fracturing parameters and reservoir conditions in conventional proppant fracturing methods for complex reservoirs. It is suitable for heterogeneous reservoirs with complex lithology and varying degrees of natural fracture development, achieving full utilization of complex reservoirs and increasing single-well production. Attached Figure Description

[0067] The accompanying drawings, which are included to provide a further understanding of embodiments of the invention and form part of this application, do not constitute a limitation thereof. In the drawings:

[0068] Figure 1This is a flowchart of a method for optimizing parameters of tight oil and gas complex reservoir stimulation according to the present invention;

[0069] Figure 2 This is the logging curve of well A in oilfield B according to the present invention;

[0070] Figure 3 This is the first imaging interpretation of the present invention (no cracks observed);

[0071] Figure 4 The second imaging interpretation of this invention is based on a core sample (showing multiple low-angle cracks).

[0072] Figure 5 This is the third imaging interpretation of the present invention, and the core sample (showing well-developed dark-colored, medium- to low-angle fractures);

[0073] Figure 6 This represents the cumulative gas production of the first stage of Well A over 5 years under different sand addition intensities according to this invention.

[0074] Figure 7 The length of the first fracture section in well A under different fluid volumes according to the present invention;

[0075] Figure 8 This represents the cumulative gas production of the second section of Well A over 5 years under different sand addition intensities according to this invention.

[0076] Figure 9 This represents the cumulative gas production of the second stage of Well A over 5 years under different fluid volumes according to this invention.

[0077] Figure 10 This is a diagram showing the optimized acid dosage of the present invention;

[0078] Figure 11 This is a structural block diagram of a tight oil and gas complex reservoir stimulation parameter optimization system according to the present invention. Detailed Implementation

[0079] To make the objectives, technical solutions, and advantages of the present invention clearer, the present invention will be further described in detail below with reference to the embodiments and accompanying drawings. The illustrative embodiments and descriptions of the present invention are only used to explain the present invention and are not intended to limit the present invention.

[0080] Traditional slickwater fracturing with proppant was employed in both poorly developed and well-developed fractured reservoirs. This resulted in difficulties with proppant addition during some well runs, with the scale and flow rate falling short of design requirements, leading to sand blockage and other issues. Consequently, the reservoirs were not fully stimulated to release formation productivity. Therefore, it is urgent to implement classified stimulation process design and parameter optimization for the tight sandstone and shale reservoirs in this block. This approach aims to reduce the probability of operational anomalies, shorten operation time, and ensure timely flowback to minimize secondary damage to the reservoirs, thereby maximizing reservoir stimulation effectiveness.

[0081] This invention targets heterogeneous reservoirs with complex lithology and varying degrees of natural fracture development. It employs a method for optimizing the design of complex reservoir stimulation parameters based on different types of reservoirs. This method can match reasonable fracturing construction parameters for different types of reservoirs, fully utilizing the reservoir, releasing formation productivity, and increasing single-well production while ensuring that fracturing fluid and proppant are not wasted.

[0082] Example 1

[0083] like Figure 1 As shown, this invention provides a method for optimizing parameters of tight oil and gas complex reservoir stimulation, the method comprising:

[0084] S1. Determine the reservoir section based on the logging curve, and select the oil testing section based on the reservoir section;

[0085] Specifically, the criteria for determining the reservoir section are: matrix porosity ≥7%, or cement slurry leakage during logging with a leakage volume ≥10m³. 3 Or, the number of natural cracks developed is ≥2 per meter.

[0086] Specifically, several segments are selected from the reservoir sections as oil testing sections. For example, if 10 reservoir sections are identified based on the logging curves, 5 of them can be selected as oil testing sections.

[0087] S2, based on the logging curves and imaging logging curves of the test zone, obtain the number, location and calcium content of natural fractures;

[0088] S3, based on the number, location, and calcium content of natural fractures, different reservoir types are classified; reservoir types include porous reservoirs, fractured reservoirs, and mixed reservoirs;

[0089] Specifically, different reservoir types are classified, including:

[0090] If the number of fractures per unit length is greater than or equal to the first threshold, and the calcium content meets the first condition, then the reservoir type is a fractured reservoir.

[0091] If the number of fractures per unit length is greater than or equal to the second threshold, and the calcium content meets the second condition, then the reservoir type is a mixed reservoir.

[0092] If the number of fractures per unit length is greater than or equal to the third threshold but less than the second threshold, and the calcium content meets the third condition, then the reservoir type is a porous reservoir.

[0093] In this embodiment, the first threshold is 1, the second threshold is 0.5, and the third threshold is 0.1; the first condition is 2% to 5%, the second condition is 5% to 10%, and the third condition is ≥10%.

[0094] S4. For different reservoir types, different perforation determination methods are used to determine the perforation location, and different stimulation processes and parameters are used to optimize the scale of sand addition and fluid usage. Different fracturing methods are used to optimize the pump sequence, and the scale of sand addition and fluid usage are completed in stages.

[0095] Specifically, S4 includes:

[0096] S41. Different perforation determination methods are used to determine the perforation location for different reservoir types;

[0097] S42, for different reservoir types, different stimulation processes and parameters are used to optimize the scale of sand addition and fluid usage.

[0098] S43, for different reservoir types, adopt different fracturing methods to optimize the pump sequence, and complete the sand addition and fluid usage in stages.

[0099] In this embodiment, different perforation determination methods are used in S41 to determine the perforation location, including:

[0100] For porous and mixed reservoirs, the perforation location is determined by cluster perforation.

[0101] For fractured reservoirs, continuous perforation is used to determine the perforation location.

[0102] In this embodiment, the perforation location is determined using a clustered perforation method, including:

[0103] Based on the logging curves and imaging logging curves of the test zone, calculate the reservoir rock mechanical parameter curves along the well trajectory;

[0104] Based on the reservoir rock mechanical parameter curves, calculate the stress, fracture pressure, and brittleness index profile of the reservoir section;

[0105] Based on the reservoir properties and the stress, fracture pressure and brittleness index profiles of the reservoir section, cluster perforations are performed in positions where the reservoir porosity is greater than 0.085, the minimum horizontal principal stress is at its minimum value within the reservoir section, and the brittleness index is at its maximum value within the reservoir section. Each cluster adopts a spiral perforation method with a perforation density of 20 holes / meter and a cluster spacing of 8 to 10 meters / cluster, for a total of 40 to 48 holes / section.

[0106] In this embodiment, the perforation location is determined using a continuous perforation method, including:

[0107] Based on the large-scale perforation within the reservoir section (i.e., the entire reservoir section is perforated), spiral perforation is carried out from the top boundary to the bottom boundary of the reservoir section, with a perforation density of 16 holes / meter.

[0108] In this embodiment, S42 optimizes the sand addition scale and liquid usage scale using different modification processes and parameters, including:

[0109] For fractured reservoirs, a soil acid acidification process is adopted, and the skin coefficient is simulated using PT software to optimize the amount of acid used.

[0110] For mixed reservoirs, a composite temporary plugging + variable viscosity slickwater sand fracturing process is adopted. Based on Petrel numerical simulation of fracture length and conductivity, the amount of temporary plugging material, sand addition scale and fluid use scale are optimized.

[0111] For porous reservoirs, a fracturing process using pre-filled dilute hydrochloric acid + viscous slickwater with proppant is employed, with a pre-filled volume of dilute hydrochloric acid equal to half the wellbore volume, V = π / 8 * D^2m. 3 In the formula, V is the amount of dilute hydrochloric acid used, and D is the volume from the top of the casing to the top of the perforation cluster. The scale of sand addition and liquid usage are optimized based on Petrel numerical simulation of the fracture length and conductivity.

[0112] This embodiment also includes: optimizing the injection displacement for different reservoir types, including:

[0113] For fractured reservoirs, the injection displacement is optimized based on the dissolution rate of the filling material in the fractures.

[0114] For porous reservoirs, the injection rate is optimized based on the range of injection string diameters.

[0115] For mixed reservoirs, the injection rate is optimized based on the dissolution rate of the filling material in the fractures and the range of injection string diameters.

[0116] Specifically, for fractured reservoirs, the injection rate is 2–3 cubic meters per minute; for porous reservoirs, when the injection string diameter is less than or equal to 88.9 mm, the injection rate is 8–12 cubic meters per minute; when the injection string diameter is in the range of 88.9–114.3 mm, the injection rate is 12–14 cubic meters per minute; and when the injection string diameter is greater than 114.3 mm, the injection rate is 14–18 cubic meters per minute.

[0117] It should be noted that, depending on the specific construction conditions on site, if the injection displacement is within the range and the ground construction pressure is lower than the maximum control pressure of the tubing column when the maximum displacement is taken, then the maximum displacement shall be used.

[0118] In this embodiment, S43 optimizes the pump sequence using different fracturing methods, completing the sand addition and fluid usage in stages, including:

[0119] For fractured reservoirs, acidizing operations are carried out in stages to complete the sand addition and fluid usage.

[0120] For mixed-type and porous reservoirs, the proppant fracturing pump sequence is used to complete the proppant addition and fluid usage in stages, and slug fracturing is used in the early stage.

[0121] In specific implementation, the A well in Oilfield B was used as the target. A well is a vertical well in the Xujiahe Formation, with the completed formation being the Xujiahe Section 3. The completed well depth is 3710m (vertical depth 3632.5m). The casing for the oil layer uses TP140V grade tubing with an outer diameter of 139.7mm and a wall thickness of 12.7mm. The formation pressure coefficient is 1.8, and the formation temperature is 96.0℃ / 3710.00m. In the early stages, a concentration of 1.92–1.96 g / cm³ was used in this well. 3 Potassium polysulfone drilling fluid was used for drilling. Six gas anomalies and two gas intrusions (both ignited and burned, with flame heights of 1-2 meters) were observed at depths of 3116.0-3224.0 m, with a peak gas flow rate of 58.016%. Overall, the geological conditions of the Xujiahe Formation reservoir in this well are considered relatively good. Therefore, a well test was conducted on the Xujiahe Formation to obtain data on fluid properties, production, and pressure.

[0122] The method of this invention is used to design staged fracturing according to the following steps:

[0123] Step 1: Collect logging curves and data from Well A, and divide the test zones. According to the reservoir division standard, the test zones are as follows: Zone 1: 3223–3227m, length 4m; Zone 2: 3165–3210m, length 45m; Zone 3: 3120–3165m, length 45m. Figure 2 As shown, Figure 2 The logging curve for well A in oilfield B.

[0124] Step 2: According to the logging data of the reservoir section, the well test section showed 6 gas anomalies and 2 gas invasions, with no leakage, as shown in Table 1. Based on the imaging logging curves and core sampling, the first section has no natural fractures and a calcium content of 15%. The second section shows multiple low-angle fractures with a fracture density of 5 fractures / m. 3 The calcium content is 8%. The third segment shows well-developed dark-colored, low-angle cracks, with a crack density of 10 cracks / m². 3 Calcium content 3%. First segment imaging interpretation (no cracks observed) see [link / reference]. Figure 3 The second segment of the imaging interpretation and the core sample (showing multiple low-angle cracks) can be found here. Figure 4 The third segment of the imaging interpretation and the core sample (showing well-developed dark-colored, low-angle fractures) can be found in [the image / reference]. Figure 5 .

[0125] Table 1A Well Logging Interpretation Table

[0126]

[0127]

[0128] Step 3: Based on the reservoir classification criteria, the first section (3223–3227m) shows no obvious fracture development, with a fracture density ≤0.5 fractures / m, classifying it as a porous reservoir; the second section (3165–3210m) exhibits multiple low-angle fractures, with a fracture density of 5 fractures / m. 3 The reservoir has a calcium content of 8% and is classified as a mixed-type reservoir. The third section (3120–3165 m) shows well-developed dark-colored, low-angle fractures with a fracture density of 10 fractures / m. 3 It has a calcium content of 3% and is classified as a fractured reservoir.

[0129] Step 4: Determine the perforation method and location. The first section (3223–3227 m) and the second section (3165–3210 m) belong to a porous, mixed-type reservoir. A cluster perforation method is adopted. First, the reservoir rock mechanical parameters are calculated, including stress, fracture pressure, and brittleness index profiles, as shown below. Figure 2 Cluster perforations were performed at locations with good reservoir properties, low stress and fracture pressure, and high brittleness index. The optimized perforation parameters are shown in Table 2 below.

[0130] Table 2A Well First and Second Stage Perforation Parameter Optimization Table

[0131]

[0132] The third section, from 3120 to 3165 m, is a fractured reservoir. Continuous perforation was used to perforate a large portion of the reservoir section. The optimized perforation parameters are shown in Table 3 below.

[0133] Table 3A Well Third Section Perforation Parameter Optimization Table

[0134]

[0135] Step 5: The first segment belongs to a porous reservoir and adopts the "pre-filled dilute hydrochloric acid + viscous slickwater plus sand fracturing process". The pre-filled dilute hydrochloric acid is 16.5m. 3 Optimize sand addition scale: 4t / m (increasing sand addition intensity at 4t / m and above slows down the cumulative output growth), equivalent to 108t of sand addition; optimize liquid usage scale: 1300m. 3 (liquid volume is 1300m) 3 Afterwards, the increase in fracture length slowed down. The cumulative gas production of the first section of Well A over 5 years under different sand-addition intensities is shown below. Figure 6 , Figure 6 The horizontal axis represents time (days), and the vertical axis represents cumulative gas production (10,000 cubic meters); the length of the first fracture section in well A under different fluid usage is shown in [reference needed]. Figure 7 .

[0136] The second section belongs to a mixed reservoir and adopts a "composite temporary plugging + variable viscosity slickwater fracturing process with proppant addition". The optimized process uses 150 kg of temporary plugging particles and 150 kg of temporary plugging powder. The proppant addition rate is 4.5 t / m (further increasing the proppant addition rate beyond 4.5 t / m slows down the cumulative production increase), translating to a proppant addition of 76 t. The fluid usage is 800 m³. 3 (liquid volume is 800m) 3 Afterwards, the increase in fracture length slowed down. The cumulative gas production of the second section of Well A over 5 years under different sand-addition intensities is shown below. Figure 8 , Figure 8 The horizontal axis represents time (days), and the vertical axis represents cumulative gas production (10,000 cubic meters); the cumulative gas production of the second section of Well A over 5 years under different fluid usage is shown in the figure. Figure 9 .

[0137] The third section belongs to a fractured reservoir and employs a "soil-acid acidification" process. When the total acid content reaches 200 m³, 3 At that time, the total surface area no longer decreased, and the optimized compound soil acid 200m 3 (Slow-release hydrochloric acid: regenerated soil acid: slow-release soil acid = 2:1:1), wherein 100ml of slow-release hydrochloric acid 3 , regenerated soil acid 50m 3 Slow-release acid 50m 3 . Figure 10 See the optimized acid dosage chart. Figure 10 .

[0138] Step Six: Design the first stage of the optimized pump sequence for the porous reservoir, with a total liquid volume of 1316.5 m³. 3 Of which 16.5 mg / L was dilute hydrochloric acid. 3 Slippery water 1310m 3 The pump sequence table for the first stage is shown in Table 4.

[0139] Table 4 Pump Sequence Table for the First Stage

[0140]

[0141] The second stage of the pump sequence is designed to optimize the mixed reservoir, with a total flow rate of 810 m³. 3 Total sand volume: 76t. See the second pump sequence table. Figure 5 .

[0142] Table 5 Pump Sequence Table for Second Stage

[0143]

[0144]

[0145] Design an optimized pump sequence for the third stage of the fractured reservoir, with a total flow rate of 200 m³. 3 Of which 100ml of slow-release hydrochloric acid 3 , regenerated soil acid 50m3 Slow-release acid 50m 3 Add 15m of anti-swelling liquid 3 The third pump sequence table is shown in Table 6.

[0146] Table 6 Pump Sequence Table for the Third Stage

[0147]

[0148] This invention provides a method for optimizing parameters in the stimulation of complex tight oil and gas reservoirs. Targeting complex reservoirs similar to the Xujiahe Formation in the Sichuan Basin, it studies the impact of different cluster spacing, proppant addition intensity, fluid usage scale, and injection rate on fracture propagation in different reservoir types. The method optimizes the impact of these parameters on reservoir stimulation volume and fracture complexity. This approach enables full utilization of different reservoir types, increases single-well production, and provides guidance for developing optimized fracturing stimulation schemes for typical tight gas horizontal wells.

[0149] Example 2

[0150] like Figure 11 As shown, the difference between this embodiment and Embodiment 1 is that this embodiment provides a parameter optimization system for the stimulation of complex tight oil and gas reservoirs. This system corresponds one-to-one with the parameter optimization method for the stimulation of complex tight oil and gas reservoirs in Embodiment 1. The system includes:

[0151] The reservoir section identification unit is used to identify reservoir sections based on well logging curves.

[0152] The oil testing zone selection unit is used to select the oil testing zone based on the reservoir zone;

[0153] The acquisition unit is used to obtain the number, location, and calcium content of natural fractures based on the logging curves and imaging logging curves of the test formation.

[0154] The reservoir type classification unit is used to classify different reservoir types based on the number, location, and calcium content of natural fractures; reservoir types include porous reservoirs, fractured reservoirs, and mixed reservoirs.

[0155] The optimization unit is used to determine the perforation location for different reservoir types using different perforation determination methods, and to optimize the scale of sand addition and fluid usage using different stimulation processes and parameters.

[0156] As a further implementation, different reservoir types are classified, including:

[0157] If the number of fractures per unit length is greater than or equal to the first threshold, and the calcium content meets the first condition, then the reservoir type is a fractured reservoir.

[0158] If the number of fractures per unit length is greater than or equal to the second threshold, and the calcium content meets the second condition, then the reservoir type is a mixed reservoir.

[0159] If the number of fractures per unit length is greater than or equal to the third threshold but less than the second threshold, and the calcium content meets the third condition, then the reservoir type is a porous reservoir.

[0160] In this embodiment, the first threshold is 1, the second threshold is 0.5, and the third threshold is 0.1; the first condition is 2% to 5%, the second condition is 5% to 10%, and the third condition is ≥10%.

[0161] As a further implementation, the optimization unit includes:

[0162] The first optimization subunit is used to determine the perforation location for different reservoir types using different perforation determination methods, including: for porous reservoirs and mixed reservoirs, using cluster perforation to determine the perforation location; for fractured reservoirs, using continuous perforation to determine the perforation location.

[0163] The second optimization subunit is used to optimize the scale of proppant addition and fluid usage for different reservoir types using different stimulation processes and parameters. This includes: for fractured reservoirs, using a soil-acid acidizing process and PT software to simulate the skin coefficient to optimize acid usage; for mixed reservoirs, using a composite temporary plugging + variable viscosity slickwater proppant fracturing process, optimizing the amount of temporary plugging material, proppant addition, and fluid usage based on Petrel numerical simulations of fracture length and conductivity; and for porous reservoirs, using a pre-concentrated dilute hydrochloric acid + variable viscosity slickwater proppant fracturing process, using half the wellbore volume of dilute hydrochloric acid pre-concentrated, optimizing the scale of proppant addition and fluid usage based on Petrel numerical simulations of fracture length and conductivity.

[0164] As a further implementation, the perforation location is determined using a clustered perforation method, including:

[0165] Based on the logging curves and imaging logging curves of the test zone, calculate the reservoir rock mechanical parameter curves along the well trajectory;

[0166] Based on the reservoir rock mechanical parameter curves, calculate the stress, fracture pressure, and brittleness index profile of the reservoir section;

[0167] Based on the reservoir properties and the stress, fracturing pressure and brittleness index profile of the reservoir section, cluster perforations are performed at locations where the reservoir properties meet the fourth condition, the stress and fracturing pressure meet the fifth condition, and the brittleness index meets the sixth condition, and each cluster uses spiral perforations.

[0168] Among them, the fourth condition refers to the reservoir porosity being greater than 0.085, the fifth condition refers to the minimum horizontal principal stress being at its minimum value within the reservoir section, and the sixth condition refers to the brittleness index being at its maximum value within the reservoir section.

[0169] Determining the location of perforations using a continuous perforation method includes:

[0170] Based on the large-scale perforation within the reservoir section, spiral perforation is performed from the top boundary to the bottom boundary of the reservoir section.

[0171] As a further implementation, the optimization unit also includes:

[0172] The third optimization subunit is used to optimize the pump sequence using different fracturing methods, and to complete the sand addition and fluid usage in stages. This includes: for fractured reservoirs, using acidizing pump sequence to complete the sand addition and fluid usage in stages; for mixed and porous reservoirs, using sand fracturing pump sequence to complete the sand addition and fluid usage in stages, with slug fracturing used in the early stage.

[0173] The execution process of each unit can be carried out according to the procedure of the tight oil and gas complex reservoir stimulation parameter optimization method in Example 1, and will not be described in detail in this example.

[0174] Meanwhile, the present invention also provides an electronic device, including a memory, a processor, and a computer program stored in the memory and executable on the processor. When the processor executes the computer program, it implements the above-mentioned method for optimizing parameters of tight oil and gas complex reservoirs.

[0175] Meanwhile, the present invention also provides a computer-readable storage medium storing a computer program, which, when executed by a processor, implements the above-mentioned method for optimizing parameters of tight oil and gas complex reservoirs.

[0176] Meanwhile, the present invention also provides a computer program product, including a computer program / instruction, which, when executed by a processor, implements the steps of the above-described method for optimizing parameters of a tight oil and gas complex reservoir.

[0177] Those skilled in the art will understand that embodiments of this application can be provided as methods, systems, or computer program products. Therefore, this application can take the form of a completely hardware embodiment, a completely software embodiment, or an embodiment combining software and hardware aspects. Furthermore, this application can take the form of a computer program product embodied on one or more computer-usable storage media (including but not limited to disk storage, CD-ROM, optical storage, etc.) containing computer-usable program code.

[0178] This application is described with reference to flowchart illustrations and / or block diagrams of methods, apparatus (systems), and computer program products according to embodiments of this application. It will be understood that each block of the flowchart illustrations and / or block diagrams, and combinations of blocks in the flowchart illustrations and / or block diagrams, can be implemented by computer program instructions. These computer program instructions can be provided to a processor of a general-purpose computer, special-purpose computer, embedded processor, or other programmable data processing apparatus to produce a machine, such that the instructions, which execute via the processor of the computer or other programmable data processing apparatus, generate instructions for implementing the flowchart... Figure 1 One or more processes and / or boxes Figure 1 A device that provides the functions specified in one or more boxes.

[0179] These computer program instructions may also be stored in a computer-readable storage medium that can direct a computer or other programmable data processing device to function in a particular manner, such that the instructions stored in the computer-readable storage medium produce an article of manufacture including instruction means, which are implemented in a process Figure 1 One or more processes and / or boxes Figure 1 The function specified in one or more boxes.

[0180] These computer program instructions may also be loaded onto a computer or other programmable data processing equipment to cause a series of operational steps to be performed on the computer or other programmable equipment to produce a computer-implemented process, thereby providing instructions that execute on the computer or other programmable equipment for implementing the process. Figure 1 One or more processes and / or boxes Figure 1 The steps of the function specified in one or more boxes.

[0181] The specific embodiments described above further illustrate the purpose, technical solution, and beneficial effects of the present invention. It should be understood that the above description is only a specific embodiment of the present invention and is not intended to limit the scope of protection of the present invention. Any modifications, equivalent substitutions, improvements, etc., made within the spirit and principles of the present invention should be included within the scope of protection of the present invention.

Claims

1. A method for optimizing parameters of tight oil and gas complex reservoir stimulation, characterized in that, The method includes: The reservoir section is determined based on the well logging curve, and the oil testing section is selected based on the reservoir section; Based on the logging curves and imaging logging curves of the tested oil-bearing zone, the number, location, and calcium content of natural fractures were obtained. Based on the number, location, and calcium content of natural fractures, different reservoir types are classified; these reservoir types include porous reservoirs, fractured reservoirs, and mixed reservoirs. For different reservoir types, different perforation determination methods are used to determine the perforation location, and different stimulation processes and parameters are used to optimize the scale of sand addition and fluid usage.

2. The method for optimizing parameters of tight oil and gas complex reservoir stimulation according to claim 1, characterized in that, Different reservoir types are classified, including: If the number of fractures per unit length is greater than or equal to the first threshold, and the calcium content meets the first condition, then the reservoir type is a fractured reservoir. If the number of fractures per unit length is greater than or equal to the second threshold, and the calcium content meets the second condition, then the reservoir type is a mixed reservoir. If the number of fractures per unit length is greater than or equal to the third threshold but less than the second threshold, and the calcium content meets the third condition, then the reservoir type is a porous reservoir.

3. The method for optimizing parameters of tight oil and gas complex reservoir stimulation according to claim 1, characterized in that, Different methods for determining perforation locations are employed, including: For porous and mixed reservoirs, the perforation location is determined by cluster perforation. For the fractured reservoir, the perforation location is determined by continuous perforation.

4. The method for optimizing parameters of tight oil and gas complex reservoir stimulation according to claim 3, characterized in that, Determining perforation locations using a clustered perforation method includes: Based on the logging curves and imaging logging curves of the tested oil section, calculate the reservoir rock mechanical parameter curves along the well trajectory; Based on the reservoir rock mechanical parameter curves, calculate the stress, fracture pressure, and brittleness index profile of the reservoir section; Based on the reservoir properties and the stress, fracturing pressure and brittleness index profiles of the reservoir section, cluster perforations are performed at locations where the reservoir properties meet the fourth condition, the stress and fracturing pressure meet the fifth condition, and the brittleness index meets the sixth condition, and each cluster uses spiral perforations.

5. The method for optimizing parameters of tight oil and gas complex reservoir stimulation according to claim 3, characterized in that, Determining the location of perforations using a continuous perforation method includes: Based on the large-scale perforation within the reservoir section, spiral perforation is performed from the top boundary to the bottom boundary of the reservoir section.

6. The method for optimizing parameters of tight oil and gas complex reservoir stimulation according to claim 1, characterized in that, Different modification processes and parameters were used to optimize the sand addition scale and liquid usage scale, including: For fractured reservoirs, a soil acid acidification process is adopted, and the skin coefficient is simulated using PT software to optimize the amount of acid used. For mixed reservoirs, a composite temporary plugging + variable viscosity slickwater sand fracturing process is adopted. Based on Petrel numerical simulation of fracture length and conductivity, the amount of temporary plugging material, sand addition scale and fluid use scale are optimized. For porous reservoirs, a fracturing process of pre-filled dilute hydrochloric acid + viscous slickwater with sand is adopted, and the amount of dilute hydrochloric acid used is half the volume of the wellbore. The scale of sand addition and fluid usage is optimized based on Petrel numerical simulation of fracture length and conductivity.

7. The method for optimizing parameters of tight oil and gas complex reservoir stimulation according to claim 6, characterized in that, Also includes: For different reservoir types, injection displacement optimization is performed, including: For fractured reservoirs, the injection displacement is optimized based on the dissolution rate of the filling material in the fractures. For porous reservoirs, the injection rate is optimized based on the range of injection string diameters. For mixed reservoirs, the injection rate is optimized based on the dissolution rate of the filling material in the fractures and the range of injection string diameters.

8. The method for optimizing parameters of tight oil and gas complex reservoir stimulation according to claim 1, characterized in that, The method also includes: optimizing the pump sequence using different fracturing methods, and completing the sand addition and liquid usage in stages.

9. The method for optimizing parameters of tight oil and gas complex reservoir stimulation according to claim 8, characterized in that, Optimize the pump sequence using different fracturing methods, and complete the sand addition and fluid usage in stages, including: For fractured reservoirs, the acidizing operation pump sequence is used to complete the sand addition and fluid usage in stages; For mixed-type and porous reservoirs, the sand addition and fluid usage are completed in stages using a sand addition fracturing pump sequence, with slug fracturing used in the early stages.

10. The method for optimizing parameters of tight oil and gas complex reservoir stimulation according to claim 1, characterized in that, The criteria for determining the reservoir section are: matrix porosity ≥7%, or cement slurry leakage during logging with a leakage volume ≥10m³. 3 Or, the number of natural cracks developed is ≥2 per meter.

11. A parameter optimization system for the stimulation of tight oil and gas complex reservoirs, characterized in that, The system includes: The reservoir section identification unit is used to identify reservoir sections based on well logging curves. The oil testing zone selection unit is used to select an oil testing zone based on the reservoir zone. The acquisition unit is used to obtain the number, location, and calcium content of natural fractures based on the logging curves and imaging logging curves of the tested oil layer. The reservoir type classification unit is used to classify different reservoir types based on the number, location, and calcium content of natural fractures; the reservoir types include porous reservoirs, fractured reservoirs, and mixed reservoirs. The optimization unit is used to determine the perforation location for different reservoir types using different perforation determination methods, and to optimize the scale of sand addition and fluid usage using different stimulation processes and parameters.

12. The tight oil and gas complex reservoir stimulation parameter optimization system according to claim 11, characterized in that, Different reservoir types are classified, including: If the number of fractures per unit length is greater than or equal to the first threshold, and the calcium content meets the first condition, then the reservoir type is a fractured reservoir. If the number of fractures per unit length is greater than or equal to the second threshold, and the calcium content meets the second condition, then the reservoir type is a mixed reservoir. If the number of fractures per unit length is greater than or equal to the third threshold but less than the second threshold, and the calcium content meets the third condition, then the reservoir type is a porous reservoir.

13. The parameter optimization system for tight oil and gas complex reservoir stimulation according to claim 11, characterized in that, The optimization unit includes: The first optimization subunit is used to determine the perforation location for different reservoir types using different perforation determination methods, including: for porous reservoirs and mixed reservoirs, using a cluster perforation method to determine the perforation location; and for fractured reservoirs, using a continuous perforation method to determine the perforation location. The second optimization subunit is used to optimize the scale of proppant addition and fluid usage for different reservoir types using different stimulation processes and parameters. This includes: for fractured reservoirs, using a soil-acid acidizing process and PT software to simulate the skin coefficient to optimize acid usage; for mixed reservoirs, using a composite temporary plugging + variable viscosity slickwater proppant fracturing process, optimizing the amount of temporary plugging material, proppant addition, and fluid usage based on Petrel numerical simulations of fracture length and conductivity; and for porous reservoirs, using a pre-concentrated dilute hydrochloric acid + variable viscosity slickwater proppant fracturing process, using half the wellbore volume of dilute hydrochloric acid pre-concentrated, optimizing the scale of proppant addition and fluid usage based on Petrel numerical simulations of fracture length and conductivity.

14. The parameter optimization system for tight oil and gas complex reservoir stimulation according to claim 13, characterized in that, Determining perforation locations using a clustered perforation method includes: Based on the logging curves and imaging logging curves of the tested oil section, calculate the reservoir rock mechanical parameter curves along the well trajectory; Based on the reservoir rock mechanical parameter curves, calculate the stress, fracture pressure, and brittleness index profile of the reservoir section; Based on the reservoir properties and the stress, fracturing pressure and brittleness index profile of the reservoir section, cluster perforations are performed at locations where the reservoir properties meet the fourth condition, the stress and fracturing pressure meet the fifth condition, and the brittleness index meets the sixth condition, and each cluster uses spiral perforations. Determining the location of perforations using a continuous perforation method includes: Based on the large-scale perforation within the reservoir section, spiral perforation is performed from the top boundary to the bottom boundary of the reservoir section.

15. The parameter optimization system for tight oil and gas complex reservoir stimulation according to claim 13, characterized in that, The optimization unit further includes: The third optimization subunit is used to optimize the pump sequence using different fracturing methods, and to complete the sand addition and fluid usage in stages. This includes: for fractured reservoirs, using acidizing pump sequence to complete the sand addition and fluid usage in stages; for mixed and porous reservoirs, using sand fracturing pump sequence to complete the sand addition and fluid usage in stages, with slug fracturing used in the early stage.

16. An electronic device comprising a memory, a processor, and a computer program stored in the memory and executable on the processor, characterized in that, When the processor executes the computer program, it implements a method for optimizing parameters of tight oil and gas complex reservoirs as described in any one of claims 1 to 10.

17. A computer-readable storage medium storing a computer program, characterized in that, When the computer program is executed by the processor, it implements a method for optimizing parameters of tight oil and gas complex reservoirs as described in any one of claims 1 to 10.

18. A computer program product comprising a computer program / instructions, characterized in that, When the computer program / instructions are executed by the processor, they implement the steps of the method for optimizing the stimulation parameters of tight oil and gas complex reservoirs as described in any one of claims 1 to 10.

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