CN113494284A - Deep shale gas reservoir hydrofracture parameter determination method and device and storage medium - Google Patents
Deep shale gas reservoir hydrofracture parameter determination method and device and storage medium Download PDFInfo
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- E—FIXED CONSTRUCTIONS
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- E21B43/261—Separate steps of (1) cementing, plugging or consolidating and (2) fracturing or attacking the formation
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- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/25—Methods for stimulating production
- E21B43/26—Methods for stimulating production by forming crevices or fractures
- E21B43/267—Methods for stimulating production by forming crevices or fractures reinforcing fractures by propping
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Abstract
The invention provides a deep shale gas reservoir hydraulic fracturing parameter determination method, a deep shale gas reservoir hydraulic fracturing parameter determination device and a deep shale gas reservoir hydraulic fracturing parameter determination storage medium, and belongs to the field of oil and gas development. The determination method comprises the following steps: acquiring geological parameters of a section to be fractured in a deep shale gas reservoir; and determining the hydraulic fracturing parameters corresponding to the geological parameters of the section to be fractured according to the corresponding relation between the geological parameters and the hydraulic fracturing parameters, wherein the values of the hydraulic fracturing parameters corresponding to the geological parameters in different value ranges are different, and the determined hydraulic fracturing parameters are construction parameters during hydraulic fracturing of the section to be fractured. According to the method, the geological parameters of the sections to be fractured in the deep shale gas reservoir are obtained, the hydraulic fracturing parameters corresponding to the geological parameters of the sections to be fractured are determined according to the corresponding relation between the geological parameters and the hydraulic parameters, the adaptive hydraulic fracturing parameters can be adopted for construction according to different geological conditions of each fracturing section of each well, and the natural gas yield of the deep shale gas reservoir is effectively improved.
Description
Technical Field
The disclosure relates to the field of oil and gas development, in particular to a deep shale gas reservoir hydraulic fracturing parameter determination method, a deep shale gas reservoir hydraulic fracturing parameter determination device and a deep shale gas reservoir hydraulic fracturing parameter determination storage medium.
Background
Shale gas is natural gas resources which are stored in shale layers and can be exploited, and most of shale gas is located in deep layers below 3500 m. The efficient development of deep shale gas is an important guarantee for realizing the planning of the natural gas industry.
Hydraulic fracturing is the main form of oil and gas exploitation at present, and a fracture is formed in an oil and gas reservoir by utilizing the hydraulic action so as to improve the oil and gas yield. The hydrocarbon reservoirs are distributed in the stratum at intervals, and are generally subjected to staged fracturing according to the sequence of wells from bottom to top. In the related technology, the construction parameters such as the discharge capacity, the volume, the concentration and the like of the fracturing fluid are the same when each section of hydraulic fracturing is carried out. However, deep shale gas reservoirs have strong heterogeneity, and staged fracturing with uniform construction parameters cannot ensure good adaptability of each fracturing section of each well, resulting in low yield of natural gas.
Disclosure of Invention
The embodiment of the disclosure provides a method and a device for determining hydraulic fracturing parameters of a deep shale gas reservoir, and a storage medium, which can determine the hydraulic fracturing parameters aiming at different fracturing sections of different wells, and effectively improve the yield of natural gas. The technical scheme is as follows:
in a first aspect, the disclosed embodiments provide a method for determining a deep shale gas reservoir hydraulic fracturing parameter, where the method for determining includes:
acquiring geological parameters of a section to be fractured in a deep shale gas reservoir;
determining the hydraulic fracturing parameters corresponding to the geological parameters of the section to be fractured according to the corresponding relation between the geological parameters and the hydraulic fracturing parameters, wherein the values of the hydraulic fracturing parameters corresponding to the geological parameters in different value ranges are different, and the determined hydraulic fracturing parameters are construction parameters during hydraulic fracturing of the section to be fractured.
Optionally, the geological parameters comprise at least one of the following parameters: setting the volume ratio of the morphological gas, the content of carbonate minerals, the Young modulus, the fracture pressure, the distribution position of a natural fracture zone, the brittleness index, the fracture toughness index, the development degree of the natural fracture zone, the formation bedding development degree, the development index of the weak surface of a rock mass, the complexity of a fracture network, the fracture extension and the steering index; the volume ratio of the gas in the set shape is the free gas content ratio or the adsorption gas content ratio;
the hydraulic fracturing parameters include at least one of the following: the method comprises the following steps of (1) counting the number of each cluster in a multi-cluster perforation, the volume of acid liquor in a pad fluid, the volume of the pad fluid, the displacement of the pad fluid, the volume of a sand carrying fluid, the displacement of the sand carrying fluid, the weight ratio of small-particle-size proppants in the sand carrying fluid, the weight of proppants in the sand carrying fluid, the concentration of temporary plugging agents in the sand carrying fluid, the form of temporary plugging agents in the sand carrying fluid and the volume of a displacement fluid;
the hydraulic fracturing parameter corresponding to the geological parameter of the section to be fractured is determined according to the corresponding relation between the geological parameter and the hydraulic fracturing parameter, and the method comprises at least one of the following modes:
determining the number of each cluster hole in the multi-cluster perforation corresponding to the volume ratio of the gas in the set form of the section to be fractured according to the corresponding relationship between the volume ratio of the gas in the set form and the number of each cluster hole in the multi-cluster perforation;
determining the volume of acid liquor in the pad fluid corresponding to the carbonate mineral content of the section to be fractured according to the wellhead pressure drop before and after the pad fluid is injected into the 1 st fracturing section and the corresponding relation between the carbonate mineral content and the volume of the acid liquor in the pad fluid;
determining the volume of the pad fluid corresponding to the Young modulus of the section to be fractured according to the corresponding relation between the Young modulus and the volume of the pad fluid;
determining the displacement of the pad fluid corresponding to the fracture rupture pressure of the section to be fractured according to the corresponding relation between the fracture rupture pressure and the displacement of the pad fluid;
determining the distribution position of the natural fracture zone of the section to be fractured and the volume of the sand carrying liquid corresponding to the brittleness index according to the corresponding relation of the distribution position of the natural fracture zone, the brittleness index and the volume of the sand carrying liquid;
determining the sand-carrying fluid displacement corresponding to the fracture toughness index of the section to be fractured according to the variation amplitude of the wellhead pressure during the hydraulic fracturing of the 1 st fracturing section, the average value of the wellhead pressure during the hydraulic fracturing of the 1 st fracturing section and the corresponding relation between the fracture toughness index and the sand-carrying fluid displacement;
determining the weight ratio of the small-particle-size proppant in the sand-carrying fluid corresponding to the Young modulus of the section to be fractured according to the corresponding relationship between the Young modulus and the weight ratio of the small-particle-size proppant in the sand-carrying fluid;
determining the development degree of the natural fracture zone of the section to be fractured, the bedding development degree of the rock stratum and the weight of the proppant in the sand carrying liquid corresponding to the weak surface development index of the rock mass according to the corresponding relation of the development degree of the natural fracture zone, the bedding development degree of the rock stratum and the development index of the rock mass;
determining the addition mode of the proppant in the sand carrying fluid and the concentration of the proppant in the sand carrying fluid corresponding to the complexity of the fracture network of the section to be fractured according to the corresponding relationship among the complexity of the fracture network, the addition mode of the proppant in the sand carrying fluid and the concentration of the proppant in the sand carrying fluid;
determining the concentration of the temporary plugging agent in the sand carrying liquid corresponding to the fracture extension and the steering index of the section to be fractured according to the corresponding relationship between the fracture extension and the steering index and the concentration of the temporary plugging agent in the sand carrying liquid;
determining the form of the temporary plugging agent in the sand carrying liquid corresponding to the Young modulus of the section to be fractured according to the corresponding relation between the Young modulus and the form of the temporary plugging agent in the sand carrying liquid;
and determining the volume of the displacement liquid corresponding to the brittleness index and the seam network complexity of the section to be fractured according to the corresponding relation of the brittleness index, the seam network complexity and the volume of the displacement liquid.
Optionally, the determining, according to the wellhead pressure drop before and after the injection of the pad fluid into the 1 st fracturing stage and the corresponding relationship between the content of the carbonate minerals and the volume of the acid liquid in the pad fluid, the volume of the acid liquid in the pad fluid corresponding to the content of the carbonate minerals in the stage to be fractured includes:
when the content of carbonate minerals in the 1 st fracturing section is greater than or equal to a content threshold value, and the wellhead pressure drop before and after the 1 st fracturing section is injected with the pad fluid is greater than or equal to a wellhead pressure drop threshold value, if the content of the carbonate minerals in the to-be-fractured section is greater than or equal to the content threshold value, the volume of acid liquor in the pad fluid of the to-be-fractured section is equal to the volume of acid liquor in the pad fluid of the 1 st fracturing section; if the content of the carbonate minerals in the section to be fractured is smaller than the content threshold value, the volume of the acid liquor in the pad fluid of the section to be fractured is smaller than the volume of the acid liquor in the pad fluid of the 1 st fracturing section;
when the content of carbonate minerals in the 1 st fracturing section is greater than or equal to a content threshold value, and the wellhead pressure drop before and after the 1 st fracturing section is injected with the pad fluid is less than a wellhead pressure drop threshold value, if the content of the carbonate minerals in the to-be-fractured section is greater than or equal to the content threshold value, the volume of acid liquor in the pad fluid of the to-be-fractured section is greater than the volume of acid liquor in the pad fluid of the 1 st fracturing section; if the content of the carbonate minerals in the section to be fractured is smaller than the content threshold value, the volume of the acid liquor in the pad fluid of the section to be fractured is equal to the volume of the acid liquor in the pad fluid of the 1 st fracturing section;
when the content of carbonate minerals in the 1 st fracturing section is less than a content threshold value, and the wellhead pressure drop before and after the 1 st fracturing section is injected with the pad fluid is greater than or equal to a wellhead pressure drop threshold value, the volume of acid liquor in the pad fluid of the section to be fractured is equal to the volume of acid liquor in the pad fluid of the 1 st fracturing section;
and when the content of the carbonate minerals in the 1 st fracturing section is less than the content threshold value and the wellhead pressure drop before and after the 1 st fracturing section is injected with the pad fluid is less than the wellhead pressure drop threshold value, the volume of the acid liquid in the pad fluid of the section to be fractured is greater than that of the acid liquid in the pad fluid of the 1 st fracturing section.
Optionally, the determining, according to the variation range of the wellhead pressure during hydraulic fracturing of the 1 st fracturing segment, the average value of the wellhead pressure during hydraulic fracturing of the 1 st fracturing segment, and the corresponding relationship between the fracture toughness index and the sand carrying fluid displacement, the sand carrying fluid displacement corresponding to the fracture toughness index of the segment to be fractured includes:
when the fracture toughness index of the 1 st fracturing section is greater than or equal to the fracture toughness index threshold value, the variation amplitude of wellhead pressure during hydraulic fracturing of the 1 st fracturing section is smaller than the amplitude threshold value, and the average value of the wellhead pressure during hydraulic fracturing of the 1 st fracturing section is smaller than the wellhead pressure threshold value, if the fracture toughness index of the section to be fractured is greater than or equal to the fracture toughness index threshold value, the sand carrying fluid displacement of the section to be fractured is equal to the sum of the sand carrying fluid displacement of the 1 st fracturing section and a first increasing value, and the first increasing value is greater than 0; if the fracture toughness index of the to-be-fractured section is smaller than the fracture toughness index threshold value, the displacement of the sand-carrying fluid of the to-be-fractured section is equal to that of the 1 st fracturing section;
when the fracture toughness index of the 1 st fracturing section is larger than or equal to the fracture toughness index threshold value, and the variation amplitude of wellhead pressure during hydraulic fracturing of the 1 st fracturing section is larger than or equal to the amplitude threshold value, the displacement of the sand carrying fluid of the section to be fractured is equal to that of the 1 st fracturing section;
when the fracture toughness index of the 1 st fracturing section is greater than or equal to the fracture toughness index threshold value, and the average value of wellhead pressure during hydraulic fracturing of the 1 st fracturing section is greater than or equal to the wellhead pressure threshold value, the sand-carrying fluid displacement of the section to be fractured is equal to that of the 1 st fracturing section;
when the fracture toughness index of the 1 st fracturing section is smaller than the fracture toughness index threshold value, the variation amplitude of wellhead pressure during hydraulic fracturing of the 1 st fracturing section is smaller than the amplitude threshold value, and the average value of the wellhead pressure during hydraulic fracturing of the 1 st fracturing section is smaller than the wellhead pressure threshold value, if the fracture toughness index of the section to be fractured is larger than or equal to the fracture toughness index threshold value, the sand-carrying fluid displacement of the section to be fractured is equal to the sum of the sand-carrying fluid displacement of the 1 st fracturing section and a second increase value, and the second increase value is larger than 0 and smaller than the first increase value; if the fracture toughness index of the to-be-fractured section is smaller than the fracture toughness index threshold value, the displacement of the sand-carrying fluid of the to-be-fractured section is equal to that of the 1 st fracturing section;
when the fracture toughness index of the 1 st fracturing section is smaller than the fracture toughness index threshold value and the variation amplitude of the wellhead pressure during hydraulic fracturing of the 1 st fracturing section is larger than or equal to the amplitude threshold value, the sand-carrying fluid displacement of the section to be fractured is smaller than that of the 1 st fracturing section;
when the fracture toughness index of the 1 st fracturing section is larger than or equal to the fracture toughness index threshold value, and the average value of wellhead pressure in hydraulic fracturing of the 1 st fracturing section is larger than or equal to the wellhead pressure threshold value, the sand-carrying fluid displacement of the section to be fractured is smaller than that of the 1 st fracturing section;
wherein the wellhead pressure threshold is equal to a product of a wellhead pressure bearing limit and a first percentage.
Optionally, the determining, according to the volume ratio of the gas in the set form and the corresponding relationship between the number of the clusters of perforations in the multiple clusters of perforations, the number of the clusters of perforations in the multiple clusters of perforations corresponding to the volume ratio of the gas in the set form of the segment to be fractured includes:
when the free gas content ratio of the to-be-fractured section is greater than or equal to a free gas content ratio threshold value, or when the adsorption gas content ratio of the to-be-fractured section is less than or equal to an adsorption gas content ratio threshold value, the number of clusters of holes in the multiple clusters of perforations of the to-be-fractured section is equal;
when the free gas content ratio of the to-be-fractured section is smaller than the free gas content ratio threshold value, or when the adsorption gas content ratio of the to-be-fractured section is larger than the adsorption gas content ratio threshold value, the number of cluster holes on two sides in the multi-cluster perforation of the to-be-fractured section is smaller than the number of cluster holes in the middle;
and the sum of the free gas quantity ratio threshold value and the adsorption gas quantity ratio is equal to 1, j is more than or equal to 1 and less than or equal to N, j is an integer, and N is the number of fracturing sections in the well.
Optionally, the determining the pad fluid volume corresponding to the young modulus of the section to be fractured according to the corresponding relationship between the young modulus and the pad fluid volume includes:
when the Young modulus of the section to be fractured is larger than or equal to the Young modulus threshold value, the front liquid volume of the section to be fractured is between a first set volume and a second set volume, and the second set volume is larger than the first set volume;
and when the Young modulus of the section to be fractured is smaller than the Young modulus threshold value, the front liquid volume of the section to be fractured is larger than the second set volume.
Optionally, the determining the pre-fluid displacement corresponding to the fracture cracking pressure of the to-be-fractured section according to the corresponding relationship between the fracture cracking pressure and the pre-fluid displacement includes:
when fracture rupture pressure of the to-be-fractured section is greater than or equal to a rupture pressure threshold value, the displacement of the pad fluid of the to-be-fractured section is smaller than a first set displacement;
when the fracture rupture pressure of the section to be fractured is smaller than a fracture pressure threshold value, the displacement of the section to be fractured for injecting the pad fluid is between the first set displacement and a second set displacement, and the second set displacement is larger than the first set displacement;
wherein the burst pressure threshold is equal to the product of the wellhead pressure bearing limit and a second percentage.
Optionally, the determining, according to the corresponding relationship between the distribution position of the natural fracture zone, the brittleness index and the volume of the sand-carrying fluid, the distribution position of the natural fracture zone of the section to be fractured and the volume of the sand-carrying fluid corresponding to the brittleness index includes:
when the shortest distance between the natural fracture zone of the section to be fractured and the shaft is smaller than a distance threshold value, the volume of the sand-carrying fluid of the section to be fractured is smaller than or equal to a third set volume;
when the shortest distance between the natural fracture zone of the section to be fractured and the shaft is greater than or equal to a distance threshold value, if the brittleness index of the section to be fractured is greater than or equal to a brittleness index threshold value, the volume of the sand carrying fluid of the section to be fractured is between a fourth set volume and a third set volume, and the third set volume is greater than the fourth set volume; and if the brittleness index of the section to be fractured is smaller than the brittleness index threshold value, the volume of the sand carrying liquid of the section to be fractured is larger than the third set volume.
Optionally, the determining, according to the corresponding relationship between the young modulus and the weight ratio of the small-particle-size proppant in the sand-carrying fluid, the weight ratio of the small-particle-size proppant in the sand-carrying fluid corresponding to the young modulus of the section to be fractured includes:
when the Young modulus of the section to be fractured is greater than or equal to the Young modulus threshold value, the weight ratio of the small-particle-size proppant in the sand carrying fluid of the section to be fractured is greater than a first set proportion;
when the Young modulus of the section to be fractured is smaller than the Young modulus threshold value, the weight ratio of the small-particle-size proppant in the sand-carrying fluid of the section to be fractured is between a second set proportion and the first set proportion, and the second set proportion is smaller than the first set proportion.
Optionally, the determining, according to the corresponding relationship between the development degree of the natural fracture zone, the formation bedding development degree, the weak face development index of the rock mass, and the weight of the proppant in the sand carrying fluid corresponding to the development degree of the natural fracture zone, the formation bedding development degree, and the weak face development index of the rock mass of the section to be fractured includes:
when the development degree of the natural fracture zone of the section to be fractured is greater than or equal to a natural fracture zone development degree threshold value, or when the formation bedding development degree of the section to be fractured is greater than or equal to a formation bedding development degree threshold value, or when the rock mass weak plane development index of the section to be fractured is greater than or equal to a rock mass weak plane development index threshold value, the weight of the propping agent in the sand carrying fluid of the section to be fractured is between a first set weight and a second set weight, and the second set weight is greater than the first set weight;
and when the development degree of the natural fracture zone of the section to be fractured is smaller than the development degree threshold of the natural fracture zone, the formation bedding development degree of the section to be fractured is smaller than the formation bedding development degree threshold, and the weak rock face development index of the section to be fractured is smaller than the weak rock face development index threshold, the weight of the propping agent in the sand carrying liquid of the section to be fractured is larger than the second set weight.
Optionally, determining the adding mode of the proppant in the sand carrying fluid and the concentration of the proppant in the sand carrying fluid corresponding to the fracture network complexity of the section to be fractured according to the corresponding relationship between the fracture network complexity and the adding mode of the proppant in the sand carrying fluid and the concentration of the proppant in the sand carrying fluid includes:
when the complexity of the fracture network of the section to be fractured is greater than or equal to a fracture network complexity threshold value, adding a proppant in the sand carrying fluid of the section to be fractured in a slug type sand adding mode, wherein the concentration of the proppant of the section to be fractured is between a second set concentration and a first set concentration, and the second set concentration is smaller than the first set concentration;
and when the fracture network complexity of the section to be fractured is smaller than the fracture network complexity threshold value, the adding mode of the proppant in the sand carrying liquid of the section to be fractured adopts the combination of continuous sand adding and slug sand adding, and the proppant concentration of the section to be fractured is smaller than the second set concentration.
Optionally, determining the concentration of the temporary plugging agent in the sand carrying fluid corresponding to the fracture extension and the steering index of the section to be fractured according to the corresponding relationship between the fracture extension and the steering index and the concentration of the temporary plugging agent in the sand carrying fluid, includes:
when the fracture extension and steering index of the section to be fractured is larger than or equal to the fracture extension and steering index threshold value, the concentration of the temporary plugging agent in the sand-carrying fluid of the section to be fractured is equal to 0;
and when the fracture extension and steering index of the section to be fractured is smaller than the fracture extension and steering index threshold value, the concentration of the temporary plugging agent in the sand carrying liquid of the section to be fractured is larger than 0.
Optionally, determining the form of the temporary plugging agent in the sand-carrying fluid corresponding to the young modulus of the section to be fractured according to the corresponding relationship between the young modulus and the form of the temporary plugging agent in the sand-carrying fluid includes:
when the Young modulus of the section to be fractured is greater than or equal to the Young modulus threshold value, the temporary plugging agent in the sand carrying liquid of the section to be fractured is in a powder form;
when the Young modulus of the section to be fractured is smaller than the Young modulus threshold value, the form of the temporary plugging agent in the sand carrying fluid of the section to be fractured comprises powder and particles, and the weight ratio of the powder is larger than or equal to a third set proportion.
Optionally, determining the volume of the displacement liquid corresponding to the brittleness index and the seam-network complexity of the segment to be fractured according to the corresponding relationship between the brittleness index, the seam-network complexity and the volume of the displacement liquid includes:
when the brittleness index of the section to be fractured is larger than or equal to the brittleness index threshold value and the fracture network complexity of the section to be fractured is larger than or equal to the fracture network complexity threshold value, the volume of the displacement liquid of the section to be fractured is equal to the volume of the shaft;
when the brittleness index of the section to be fractured is smaller than the brittleness index threshold value or when the fracture network complexity of the section to be fractured is smaller than the fracture network complexity threshold value, the volume of the displacement liquid of the section to be fractured is larger than the volume of the shaft.
Optionally, the obtaining of the geological parameters of the to-be-fractured segment in the deep shale gas reservoir includes:
obtaining a geological model of the deep shale gas reservoir, wherein the geological model comprises geological parameters of each region of the deep shale gas reservoir;
and acquiring the geological parameters of the section to be fractured according to the area of the section to be fractured in the deep shale gas reservoir.
Optionally, the method further comprises: acquiring unit volume gas quantity of the section to be fractured;
the method for acquiring the geological parameters of the section to be fractured in the deep shale gas reservoir comprises the following steps:
and when the gas volume per unit volume is greater than or equal to the gas volume threshold value, acquiring the geological parameters of the section to be fractured.
In a second aspect, the disclosed embodiments provide an apparatus for determining deep shale gas reservoir hydraulic fracturing parameters, where the apparatus includes:
the geological parameter acquisition module is used for acquiring geological parameters of a section to be fractured in the deep shale gas reservoir;
and the fracturing parameter determining module is used for determining the hydraulic fracturing parameters corresponding to the geological parameters of the section to be fractured according to the corresponding relation between the geological parameters and the hydraulic fracturing parameters, the value ranges of the hydraulic fracturing parameters corresponding to the geological parameters in different value ranges are different, and the determined hydraulic fracturing parameters are the construction parameters during hydraulic fracturing of the section to be fractured.
In a third aspect, the disclosed embodiment provides a device for determining deep shale gas reservoir hydraulic fracturing parameters, where the device includes: a memory and a processor, the memory and the processor being communicatively connected with each other, the memory storing computer instructions, and the processor executing the computer instructions to perform the method for determining deep shale gas reservoir hydraulic fracturing parameters as provided in the first aspect.
In a fourth aspect, embodiments of the present disclosure provide a computer-readable storage medium having stored thereon computer instructions for causing a computer to execute the method for determining deep shale gas reservoir hydraulic fracturing parameters as provided in the first aspect.
The technical scheme provided by the embodiment of the disclosure has the following beneficial effects:
by acquiring the geological parameters of the sections to be fractured in the deep shale gas reservoir and determining the hydraulic fracturing parameters corresponding to the geological parameters of the sections to be fractured according to the corresponding relation between the geological parameters and the hydraulic parameters, the construction can be carried out by adopting the adaptive hydraulic fracturing parameters according to different geological conditions of each fracturing section of each well, and the natural gas yield of the deep shale gas reservoir is effectively improved.
Drawings
In order to more clearly illustrate the technical solutions in the embodiments of the present disclosure, the drawings needed to be used in the description of the embodiments are briefly introduced below, and it is obvious that the drawings in the following description are only some embodiments of the present disclosure, and it is obvious for those skilled in the art to obtain other drawings based on the drawings without creative efforts.
Fig. 1 is a flowchart of a method for determining deep shale gas reservoir hydraulic fracturing parameters according to an embodiment of the present disclosure;
fig. 2 is a schematic structural diagram of an apparatus for determining deep shale gas reservoir hydraulic fracturing parameters according to an embodiment of the present disclosure;
fig. 3 is a schematic structural diagram of a device for determining deep shale gas reservoir hydraulic fracturing parameters, provided by an embodiment of the present disclosure.
Detailed Description
To make the objects, technical solutions and advantages of the present disclosure more apparent, embodiments of the present disclosure will be described in detail with reference to the accompanying drawings.
Hydraulic fracturing is a method of using hydraulic power to fracture oil and gas layers. The hydrocarbon reservoirs are distributed in the stratum at intervals, and are generally subjected to staged fracturing according to the sequence of wells from bottom to top. The process at the time of hydraulic fracturing of each fracturing section may be as follows:
firstly, a ground high-pressure pump is utilized to squeeze and inject the pad fluid containing acid liquor into an oil layer through a well bore. When the rate of pad injection exceeds the absorbent capacity of the reservoir, high pressure builds up on the reservoir at the bottom of the well. When this pressure exceeds the fracture pressure of the reservoir rock near the bottom of the well, the reservoir will be forced open and create a fracture. At this time, the pad fluid is continuously squeezed into the oil layer, and the crack is continuously expanded into the oil layer. To keep the pressed open fractures in an open state, a sand-carrying fluid with proppant (usually quartz sand) is then squeezed into the formation. After the sand-carrying fluid enters the fracture, on one hand, the fracture can continue to extend forwards, and on the other hand, the pressed-open fracture can be supported to avoid closing. And then, injecting a displacement fluid, completely displacing the sand-carrying fluid in the shaft into the fracture, and propping the fracture by using a propping agent. And finally, most of the injected pad fluid, sand carrying fluid and displacing fluid can be automatically degraded and discharged out of the shaft, one or more cracks with different lengths, widths and heights are left in the oil layer, and a new fluid channel is established between the oil layer and the shaft.
Based on the above process, the construction parameters (i.e. hydraulic fracturing parameters) in hydraulic fracturing of one fracturing section may include at least one of the following parameters: the method comprises the following steps of counting the number of each cluster of holes in a multi-cluster perforation, the volume of acid liquid in a pad fluid, the volume of the pad fluid, the displacement of the pad fluid, the volume of a sand carrying fluid, the displacement of the sand carrying fluid, the weight ratio of small-particle-size proppants in the sand carrying fluid, the weight of proppants in the sand carrying fluid, the concentration of temporary plugging agents in the sand carrying fluid, the form of temporary plugging agents in the sand carrying fluid and the volume of a displacement fluid. Wherein, the multiple shower holes are used for injecting at least one of the pad fluid, the sand carrying fluid and the displacing fluid.
The embodiment of the disclosure provides a method for determining a hydraulic fracturing parameter of a deep shale gas reservoir. Fig. 1 is a flowchart of a method for determining a hydraulic fracturing parameter of a deep shale gas reservoir according to an embodiment of the present disclosure. Referring to fig. 1, the determination method includes:
step 101: and acquiring geological parameters of a section to be fractured in the deep shale gas reservoir.
In the embodiment of the disclosure, the to-be-fractured zone is one of a plurality of fracturing zones for staged fracturing of a deep shale gas reservoir, and any fracturing zone is not subjected to hydraulic fracturing.
Illustratively, the geological parameters may include at least one of the following parameters: setting the volume ratio of the morphological gas, the content of carbonate minerals, the Young modulus, the fracture pressure, the distribution position of a natural fracture zone, the brittleness index, the fracture toughness index, the development degree of the natural fracture zone, the formation bedding development degree, the development index of the weak surface of a rock mass, the complexity of a fracture network, the fracture extension and the steering index; setting the volume ratio of the morphological gas as the free gas content ratio or the adsorption gas content ratio.
The free gas content ratio is the volume ratio of the free gas content to the total gas content, and the adsorbed gas content ratio is the volume ratio of the adsorbed gas content to the total gas content. The carbonate mineral content is the ratio of the weight of carbonate minerals in the formation to the weight of the formation. The young's modulus is the modulus of elasticity in the direction of stress, which is the stress in a unidirectional stress state divided by the strain in that direction. The brittleness index is a measure of the property of a material that undergoes only a small deformation, i.e., fracture damage, under an external force (e.g., stretching, impact, etc.). The location of the distribution of natural fracture zones is the area within the formation where fracture zones formed prior to hydraulic fracturing are distributed within the formation. The extent of natural fracture zone development is the development of fracture zones within the formation that form prior to hydraulic fracturing. The stratum bedding development degree is the development condition of the stratum bedding in the stratum, and the bedding is a layered structure generated by the change of the rock along the vertical direction. The weak face development index of the rock mass is an index representing the development condition of the weak face in the rock mass, and the weak face is a stress weak face which is easy to break and slide under stress. Fracture pressure is the pressure at which a fracture in the formation fractures. The fracture toughness index is a resistance value exhibited by a material when unstable fracture (rapid fracture starting from a crack or crack-like defect) occurs in the case where a crack or crack-like defect exists in a specimen or member. Fracture propagation and diversion indices are indicative of the likelihood of fracture propagation or diversion. Gap net complexity is a measure of the complexity of the network formed by the criss-crossing of fractures in the formation.
Optionally, this step 101 may include:
acquiring a geological model of the deep shale gas reservoir, wherein the geological model comprises geological parameters of each region of the deep shale gas reservoir;
and acquiring geological parameters of the section to be fractured according to the area of the section to be fractured in the deep shale gas reservoir.
The geological parameters of the section to be fractured can be conveniently obtained according to the region of the section to be fractured in the deep shale gas reservoir by utilizing the geological model comprising the geological parameters of each region of the deep shale gas reservoir.
Step 102: and determining the hydraulic fracturing parameters corresponding to the geological parameters of the section to be fractured according to the corresponding relation between the geological parameters and the hydraulic fracturing parameters.
In the embodiment of the disclosure, the value ranges of the hydraulic fracturing parameters corresponding to the geological parameters in different value ranges are different, and the determined hydraulic fracturing parameters are construction parameters during hydraulic fracturing of a section to be fractured.
According to the embodiment of the method and the device, the geological parameters of the sections to be fractured in the deep shale gas reservoir are obtained, the hydraulic fracturing parameters corresponding to the geological parameters of the sections to be fractured are determined according to the corresponding relation between the geological parameters and the hydraulic parameters, the adaptive hydraulic fracturing parameters can be adopted for construction according to different geological conditions of each fracturing section of each well, and the natural gas yield of the deep shale gas reservoir is effectively improved.
Optionally, this step 102 may include at least one of the following:
determining the number of each cluster hole in the multi-cluster perforation corresponding to the volume ratio of the gas in the set form of the section to be fractured according to the corresponding relationship between the volume ratio of the gas in the set form and the number of each cluster hole in the multi-cluster perforation;
determining the volume of acid liquor in the pad fluid corresponding to the carbonate mineral content of the section to be fractured according to the wellhead pressure drop before and after the pad fluid is injected into the 1 st fracturing section and the corresponding relation between the carbonate mineral content and the volume of the acid liquor in the pad fluid;
determining the volume of the pad fluid corresponding to the Young modulus of the section to be fractured according to the corresponding relation between the Young modulus and the volume of the pad fluid;
determining the displacement of the pad fluid corresponding to the fracture rupture pressure of the section to be fractured according to the corresponding relation between the fracture rupture pressure and the displacement of the pad fluid;
determining the distribution position of the natural fracture zone of the section to be fractured and the volume of the sand carrying liquid corresponding to the brittleness index according to the corresponding relation of the distribution position of the natural fracture zone, the brittleness index and the volume of the sand carrying liquid;
determining the sand-carrying fluid displacement corresponding to the fracture toughness index of the section to be fractured according to the variation amplitude of the wellhead pressure during the hydraulic fracturing of the 1 st fracturing section, the average value of the wellhead pressure during the hydraulic fracturing of the 1 st fracturing section and the corresponding relation between the fracture toughness index and the sand-carrying fluid displacement;
determining the weight ratio of the small-particle-size proppant in the sand-carrying fluid corresponding to the Young modulus of the section to be fractured according to the corresponding relationship between the Young modulus and the weight ratio of the small-particle-size proppant in the sand-carrying fluid;
determining the development degree of the natural fracture zone of the section to be fractured, the bedding development degree of the rock stratum and the weight of the proppant in the sand carrying liquid corresponding to the weak surface development index of the rock mass according to the corresponding relation of the development degree of the natural fracture zone, the bedding development degree of the rock stratum and the development index of the rock mass;
determining the addition mode of the proppant in the sand carrying fluid and the concentration of the proppant in the sand carrying fluid corresponding to the complexity of the fracture network of the section to be fractured according to the corresponding relationship among the complexity of the fracture network, the addition mode of the proppant in the sand carrying fluid and the concentration of the proppant in the sand carrying fluid;
determining the concentration of the temporary plugging agent in the sand carrying liquid corresponding to the fracture extension and the steering index of the section to be fractured according to the corresponding relationship between the fracture extension and the steering index and the concentration of the temporary plugging agent in the sand carrying liquid;
determining the form of the temporary plugging agent in the sand carrying liquid corresponding to the Young modulus of the section to be fractured according to the corresponding relation between the Young modulus and the form of the temporary plugging agent in the sand carrying liquid;
and determining the volume of the displacement liquid corresponding to the brittleness index and the seam network complexity of the section to be fractured according to the corresponding relation of the brittleness index, the seam network complexity and the volume of the displacement liquid.
And selecting different geological parameters to establish a corresponding relation aiming at different hydraulic fracturing parameters based on the mutual influence between the geological parameters and the hydraulic fracturing parameters.
In practical application, deep shale gas reservoir hydraulic fracturing can be divided into a plurality of sections and carried out, hydraulic fracturing is carried out in proper order from big to little from the distance between the well head, each region of hydraulic fracturing is called 1 st fracturing section respectively, 2 nd fracturing section, 3 rd fracturing section, … … is that the distance between 1 st fracturing section and the well head is greater than the distance between 2 nd fracturing section and the well head, the distance between 2 nd fracturing section and the well head is greater than the distance between 3 rd fracturing section and the well head, … … carries out hydraulic fracturing most first from the 1 st fracturing section farthest from the well head, can reflect the hydraulic fracturing effect of whole well, be favorable to accurately determining the hydraulic fracturing parameters of other fracturing sections.
Exemplarily, the determining method may further include:
wellhead pressure was measured while hydraulic fracturing was performed in the 1 st fracturing stage.
According to the method, the wellhead pressure is measured when the 1 st fracturing section is subjected to hydraulic fracturing, the wellhead pressure drop before and after the 1 st fracturing section is injected with the pad fluid, the variation amplitude of the wellhead pressure during the hydraulic fracturing of the 1 st fracturing section and the average value of the wellhead pressure during the hydraulic fracturing of the 1 st fracturing section can be determined.
In practical application, a part of hydraulic fracturing parameters of the 1 st fracturing stage can be determined by adopting the implementation manner, and the other part of hydraulic fracturing parameters can be set manually. Specifically, the volume of the acid solution in the pad fluid and the displacement of the sand carrying fluid can be manually set for trial, and the number of holes in each cluster in the multi-cluster perforation, the volume of the pad fluid, the displacement of the pad fluid, the volume of the sand carrying fluid, the weight ratio of small-particle-size proppants in the sand carrying fluid, the weight of the proppants in the sand carrying fluid, the adding mode of the proppants in the sand carrying fluid, the concentration of temporary plugging agents in the sand carrying fluid, the form of the temporary plugging agents in the sand carrying fluid and the displacement fluid volume can be determined by adopting the steps 101 to 102.
In addition, for a well as an example, the geological parameters of each fracture zone are shown in the following table:
table geological parameters of each fracturing stage of a well
In a first implementation manner of the embodiment of the present disclosure, determining, according to a wellhead pressure drop before and after injecting the pad fluid into the 1 st fracturing stage and a corresponding relationship between the carbonate mineral content and the volume of the acid solution in the pad fluid, the volume of the acid solution in the pad fluid corresponding to the carbonate mineral content of the to-be-fractured stage may include:
when the content of carbonate minerals in the 1 st fracturing section is greater than or equal to a content threshold value, and the wellhead pressure drop before and after the 1 st fracturing section is injected with the pad fluid is greater than or equal to a wellhead pressure drop threshold value, if the content of the carbonate minerals in the to-be-fractured section is greater than or equal to the content threshold value, the volume of acid liquor in the pad fluid of the to-be-fractured section is equal to the volume of acid liquor in the pad fluid of the 1 st fracturing section; if the content of the carbonate minerals in the section to be fractured is smaller than the content threshold value, the volume of the acid liquid in the pad fluid of the section to be fractured is smaller than the volume of the acid liquid in the pad fluid of the 1 st fracturing section;
when the content of carbonate minerals in the 1 st fracturing section is greater than or equal to a content threshold value, and the wellhead pressure drop before and after the 1 st fracturing section is injected with the pad fluid is less than a wellhead pressure drop threshold value, if the content of the carbonate minerals in the to-be-fractured section is greater than or equal to the content threshold value, the volume of acid liquor in the pad fluid of the to-be-fractured section is greater than the volume of acid liquor in the pad fluid of the 1 st fracturing section; if the content of the carbonate minerals in the section to be fractured is smaller than the content threshold value, the volume of the acid liquor in the pad fluid of the section to be fractured is equal to the volume of the acid liquor in the pad fluid of the 1 st fracturing section;
when the content of carbonate minerals in the 1 st fracturing section is less than a content threshold value and the wellhead pressure drop before and after the 1 st fracturing section is injected with the pad fluid is greater than or equal to a wellhead pressure drop threshold value, the volume of the acid liquid in the pad fluid of the section to be fractured is equal to the volume of the acid liquid in the pad fluid of the 1 st fracturing section;
when the content of carbonate minerals in the 1 st fracturing section is smaller than a content threshold value, and the wellhead pressure drop before and after the 1 st fracturing section is injected with the pad fluid is smaller than a wellhead pressure drop threshold value, the volume of the acid liquid in the pad fluid of the section to be fractured is larger than that of the acid liquid in the pad fluid of the 1 st fracturing section.
The acid solution in the pad fluid is used for enhancing the erosion degree of the stratum. When the content of the carbonate minerals in the 1 st fracturing stage is greater than or equal to the content threshold value, the carbonate minerals in the stratum are more, and the carbonate minerals can react with the acid liquor, so that the volume of the acid liquor in the pad fluid of the 1 st fracturing stage is more, and the carbonate minerals are fully corroded. If the content of the carbonate minerals in the section to be fractured is smaller than the content threshold value, the volume of the acid liquor in the pad fluid of the section to be fractured is equal to or even smaller than the volume of the acid liquor in the pad fluid of the 1 st fracturing section, so that the waste of the acid liquor can be avoided. If the content of the carbonate minerals in the section to be fractured is greater than or equal to the content threshold value, the volume of the acid solution in the pad fluid of the section to be fractured is equal to or even greater than the volume of the acid solution in the pad fluid of the 1 st fracturing section, so that the corrosion degree of the stratum can be enhanced, and the formation of a fluid channel is facilitated. When the content of the carbonate minerals in the 1 st fracturing section is smaller than the content threshold, the carbonate minerals in the stratum are less, the volume of the acid liquid in the pad fluid of the 1 st fracturing section is less, and the volume of the acid liquid in the pad fluid of the section to be fractured is equal to or even larger than the volume of the acid liquid in the pad fluid of the 1 st fracturing section, so that the corrosion degree of the stratum can be enhanced, and the formation of a fluid channel is facilitated.
In addition, when the wellhead pressure drop before and after the 1 st fracturing section is injected with the pad fluid is greater than or equal to the wellhead pressure drop threshold, the erosion degree of the stratum is higher, the volume of the acid liquid in the pad fluid of the fracturing section is equal to or even smaller than that of the pad fluid of the 1 st fracturing section, and the stratum structure can be prevented from being damaged due to overhigh erosion degree of the stratum. When the pressure drop of the wellhead before and after the 1 st fracturing section is injected with the pad fluid is smaller than the threshold value of the pressure drop of the wellhead, the volume of the acid liquid in the pad fluid of the fracturing section is equal to or even larger than that of the pad fluid of the 1 st fracturing section, so that the corrosion degree of the stratum can be enhanced, and the formation of a fluid channel is facilitated.
Illustratively, the content threshold may be 10%, and the wellhead pressure drop threshold may be 10 MPa; the volume of the acid solution in the pad fluid of the to-be-fractured section is smaller than that of the acid solution in the pad fluid of the 1 st fracturing section, and can be 50% of that of the acid solution in the pad fluid of the to-be-fractured section; the volume of the acid solution in the pad fluid of the to-be-fractured section is greater than the volume capacity of the acid solution in the pad fluid of the 1 st fracturing section, and can be 2 times that of the acid solution in the pad fluid of the to-be-fractured section.
For example, the wellhead pressure drop before and after the injection of the pad fluid into the 1 st fracturing stage may be 13MPa, then the carbonate mineral content 13.5% in the 1 st fracturing stage is greater than the content threshold 10%, and the wellhead pressure drop 13MPa before and after the injection of the pad fluid into the 1 st fracturing stage is greater than the wellhead pressure drop threshold 10 MPa. The volume of acid in the pad fluid of the 1 st fracturing stage may be 20m3If the content of carbonate minerals in the 2 nd to 10 th fracturing stages is 13.5 percent and is more than the content threshold value of 10 percent, the volume of the acid liquor in the pad fluid of the 2 nd to 10 th fracturing stages is 20m3(ii) a The content of carbonate minerals in the 11 th to 25 th fracturing stages is 8.2 percent and is less than the content threshold value of 10 percent, and the volume of acid liquor in the front liquid of the 11 th to 25 th fracturing stages is 20m350% of (i.e. 10 m)3。
In a second implementation manner of the embodiment of the present disclosure, determining a pad fluid volume corresponding to the young modulus of the to-be-fractured segment according to a corresponding relationship between the young modulus and the pad fluid volume includes:
when the Young modulus of the section to be fractured is greater than or equal to the Young modulus threshold value, the preposed liquid of the section to be fractured is accumulated between a first set volume and a second set volume, and the second set volume is greater than the first set volume;
and when the Young modulus of the section to be fractured is smaller than the Young modulus threshold value, the front liquid volume of the section to be fractured is larger than or equal to a second set volume.
Young's modulus is a physical quantity that describes the ability of a solid material to resist deformation. When the Young modulus of the section to be fractured is larger than or equal to the Young modulus threshold value, the section to be fractured has strong deformation resistance, the fracture is easy to expand, the front liquid volume of the section to be fractured is small, the fracture can be expanded, and the injection of the sand carrying liquid is ensured. When the Young modulus of the section to be fractured is smaller than the Young modulus threshold value, the deformation resistance of the section to be fractured is poor, the crack is not easy to expand, and the volume of the front liquid of the section to be fractured is large, so that the crack can be expanded, and the injection of the sand carrying liquid is ensured.
Illustratively, the Young's modulus threshold may be 40GPa, and the first set volume may be 400m3The second set volume may be 500m3。
For example, the Young's modulus of the 1 st to 10 th fracture stages is 45.5GPa, the Young's modulus of the 11 th to 25 th fracture stages is 41.2GPa, both are larger than the Young's modulus threshold value of 40GPa, and the front liquid volume of the 1 st to 25 th fracture stages can be 500m3At a first set volume of 400m3And a second set volume of 500m3In the meantime.
In a third implementation manner of the embodiment of the present disclosure, determining the pad fluid displacement corresponding to the fracture pressure of the to-be-fractured segment according to the corresponding relationship between the fracture pressure and the pad fluid displacement may include:
when fracture rupture pressure of a section to be fractured is greater than or equal to a rupture pressure threshold value, the displacement of the pad fluid of the section to be fractured is less than or equal to a first set displacement;
when fracture rupture pressure of a section to be fractured is smaller than a rupture pressure threshold value, the displacement of the pad fluid of the section to be fractured is between a first set displacement and a second set displacement, and the second set displacement is larger than the first set displacement;
wherein the burst pressure threshold is equal to the product of the wellhead pressure bearing limit and the second percentage.
When the fracture cracking pressure of the section to be fractured is greater than or equal to the fracture pressure threshold value, the fracture cracking pressure is higher, and the pressure generated by equipment operation is higher. If the displacement of the front liquid of the section to be fractured is also large, the realization difficulty of the equipment is high. When the fracture rupture pressure of the section to be fractured is smaller than the fracture pressure threshold value, the fracture rupture pressure is smaller, the realization difficulty of the equipment is lower, and the displacement of the front liquid of the section to be fractured is larger at the moment, so that the formation of the fracture is facilitated.
For example, the second percentage may be 90%, and the first set displacement may be 3m3Min, the second set displacement may be 4m3/min。
In practical applications, the wellhead pressure bearing limit may be 120 MPa.
For example, if the fracture pressure threshold is 120MPa by 90%, namely 108MPa, the fracture pressure 104MPa of the 1 st to 10 th fracturing stages and the fracture pressure 96MPa of the 11 th to 25 th fracturing stages are both smaller than the fracture pressure threshold 108MPa, and the discharge capacity of the injection pad of the 1 st to 25 th fracturing stages is 3m at the first set discharge capacity3Min and second set displacement 4m3And/min.
In a fourth implementation manner of the embodiment of the present disclosure, determining the distribution position of the natural fracture zone of the segment to be fractured and the volume of the sand-carrying fluid corresponding to the brittleness index according to the corresponding relationship between the distribution position of the natural fracture zone, the brittleness index and the volume of the sand-carrying fluid may include:
when the shortest distance between the natural fracture zone of the section to be fractured and the shaft is smaller than the distance threshold value, the volume of the sand carrying fluid of the section to be fractured is smaller than or equal to a third set volume;
when the shortest distance between the natural fracture zone of the section to be fractured and the shaft is greater than or equal to a distance threshold value, if the brittleness index of the section to be fractured is greater than or equal to a brittleness index threshold value, the volume of the sand-carrying fluid of the section to be fractured is between a fourth set volume and a third set volume, and the third set volume is greater than the fourth set volume; and if the brittleness index of the section to be fractured is smaller than the brittleness index threshold value, the volume of the sand carrying liquid of the section to be fractured is larger than a third set volume.
When the distance between the natural crack zone of the section to be fractured and the shaft is smaller than the distance threshold value, the natural crack zone of the section to be fractured is very close to the shaft, the natural crack zone is easy to expand, the volume of the sand carrying liquid is small, a good fracturing effect can be achieved, and the constraint of stratum brittleness can be ignored.
Brittleness is the property of a material that undergoes only a small deformation under an external force (e.g., stretching, impact, etc.) and breaks. When the distance between the natural fracture zone of the section to be fractured and the shaft is greater than or equal to the distance threshold value, if the brittleness index of the section to be fractured is greater than or equal to the brittleness index threshold value, the section to be fractured is more brittle and is easy to form cracks, and the cracks can be expanded due to the smaller volume of the sand-carrying fluid of the section to be fractured, so that the fracturing effect is ensured; if the brittleness index of the to-be-fractured section is smaller than the brittleness index threshold value, the brittleness of the to-be-fractured section is smaller, the difficulty of fracture extension is larger, and the volume of the sand-carrying liquid of the to-be-fractured section is larger, so that the formation of the fracture can be effectively promoted, and the fracturing effect is ensured.
Illustratively, the distance threshold may be 200m, the friability index threshold may be 0.5, and the third set volume may be 1800m3The fourth set volume may be 1500m3。
For example, the brittleness index of 1 st to 10 th fracturing stages is 0.66, the brittleness index of 11 th to 25 th fracturing stages is 0.59, which are both larger than the brittleness index threshold value of 0.5, and the volume of the sand carrying fluid injected into the 1 st to 25 th fracturing stages is 1700m3At the fourth set volume 1500m3And a third set volume 1800m3In the meantime.
In a fifth implementation manner of the embodiment of the present disclosure, determining, according to a variation range of wellhead pressure during hydraulic fracturing of a 1 st fracturing segment, an average value of wellhead pressure during hydraulic fracturing of the 1 st fracturing segment, and a corresponding relationship between a fracture toughness index and a sand-carrying fluid displacement, a sand-carrying fluid displacement corresponding to the fracture toughness index of a to-be-fractured segment may include:
when the fracture toughness index of the 1 st fracturing section is greater than or equal to the fracture toughness index threshold value, the variation amplitude of the wellhead pressure during hydraulic fracturing of the 1 st fracturing section is smaller than the amplitude threshold value, and the average value of the wellhead pressure during hydraulic fracturing of the 1 st fracturing section is smaller than the wellhead pressure threshold value, if the fracture toughness index of the section to be fractured is greater than or equal to the fracture toughness index threshold value, the displacement of the sand carrying fluid of the section to be fractured is equal to the sum of the displacement of the sand carrying fluid of the 1 st fracturing section and a first increase value, and the first increase value is greater than 0; if the fracture toughness index of the to-be-fractured section is smaller than the fracture toughness index threshold value, the discharge capacity of the sand-carrying fluid of the to-be-fractured section is equal to that of the 1 st fracturing section;
when the fracture toughness index of the 1 st fracturing section is greater than or equal to the fracture toughness index threshold value, and the wellhead pressure variation amplitude during hydraulic fracturing of the 1 st fracturing section is greater than or equal to the amplitude threshold value, the sand-carrying fluid displacement of the section to be fractured is equal to that of the 1 st fracturing section;
when the fracture toughness index of the 1 st fracturing section is greater than or equal to the fracture toughness index threshold value, and the average value of wellhead pressure during hydraulic fracturing of the 1 st fracturing section is greater than or equal to the wellhead pressure threshold value, the sand-carrying fluid displacement of the section to be fractured is equal to that of the 1 st fracturing section;
when the fracture toughness index of the 1 st fracturing section is smaller than the fracture toughness index threshold value, the variation amplitude of the wellhead pressure during hydraulic fracturing of the 1 st fracturing section is smaller than the amplitude threshold value, and the average value of the wellhead pressure during hydraulic fracturing of the 1 st fracturing section is smaller than the wellhead pressure threshold value, if the fracture toughness index of the section to be fractured is larger than or equal to the fracture toughness index threshold value, the sand-carrying fluid displacement of the section to be fractured is equal to the sum of the sand-carrying fluid displacement of the 1 st fracturing section and a second increase value, and the second increase value is larger than 0 and smaller than the first increase value; if the fracture toughness index of the to-be-fractured section is smaller than the fracture toughness index threshold value, the discharge capacity of the sand-carrying fluid of the to-be-fractured section is equal to that of the 1 st fracturing section;
when the fracture toughness index of the 1 st fracturing section is smaller than the fracture toughness index threshold value and the wellhead pressure variation amplitude during hydraulic fracturing of the 1 st fracturing section is larger than or equal to the amplitude threshold value, the sand-carrying fluid displacement of the section to be fractured is smaller than that of the 1 st fracturing section;
when the fracture toughness index of the 1 st fracturing section is greater than or equal to the fracture toughness index threshold value, and the average value of wellhead pressure during hydraulic fracturing of the 1 st fracturing section is greater than or equal to the wellhead pressure threshold value, the discharge capacity of the sand-carrying fluid of the section to be fractured is less than that of the 1 st fracturing section;
wherein the wellhead pressure threshold is equal to the product of the wellhead pressure bearing limit and the first percentage.
Fracture toughness is the resistance value exhibited by a material when unstable fracture (fast-reading fracture starting from a crack or crack-like defect) occurs in the case of a crack or crack-like defect in a sample or member, and can characterize the ability of the material to resist crack propagation. When the fracture toughness index of the 1 st fracturing segment is larger than or equal to the fracture toughness index threshold value, the fracture toughness of the stratum is good, the ductility of the fracture is poor, the sand-carrying fluid displacement of the segment to be fractured is kept unchanged on the basis of the sand-carrying fluid and the displacement of the 1 st fracturing segment, even a first large increasing value is added, the sand-carrying fluid displacement of the segment to be fractured is large, and the fracture extension is facilitated. When the fracture toughness index of the 1 st fracturing section is smaller than the fracture toughness index threshold value, the fracture toughness of the stratum is poor, the ductility of the fracture is good, the sand-carrying fluid displacement of the to-be-fractured section is at most added with a second smaller increment value on the basis of the sand-carrying fluid displacement of the 1 st fracturing section and is even smaller than the sand-carrying fluid displacement of the 1 st fracturing section, and the fracture can be ensured to extend when the sand-carrying fluid displacement of the to-be-fractured section is smaller.
In addition, when the pressure variation amplitude of the wellhead is smaller than the amplitude threshold value during hydraulic fracturing of the 1 st fracturing section, and the average value of the pressure of the wellhead is smaller than the pressure threshold value during hydraulic fracturing of the 1 st fracturing section, the pressure of the wellhead is more stable, the pressure of the wellhead is smaller, the discharge capacity of the sand-carrying fluid of the section to be fractured can be increased as much as possible, and the extension of the fracture is facilitated. When wellhead pressure variation amplitude is greater than or equal to the amplitude threshold value during hydraulic fracturing of the 1 st fracturing section, or when wellhead pressure average value is greater than or equal to the wellhead pressure threshold value during hydraulic fracturing of the 1 st fracturing section, wellhead pressure fluctuation is large or wellhead pressure is large, the displacement of sand carrying liquid of the section to be fractured is reduced, and collapse caused by overlarge wellhead pressure can be avoided.
Illustratively, the fracture toughness index threshold may be 0.5 and the first percentage may be 80%.
For example, if the average value of the wellhead pressure during hydraulic fracturing of the 1 st fracturing stage is 95MPa, and the wellhead pressure threshold value is 120MPa x 80%, that is, 96MPa, the fracture toughness index 0.57 of the 1 st fracturing stage is greater than the fracture toughness index threshold value 0.5, the variation amplitude of the wellhead pressure during hydraulic fracturing of the 1 st fracturing stage is less than the amplitude threshold value, and the average value of the wellhead pressure 95MPa during hydraulic fracturing of the 1 st fracturing stage is less than the wellhead pressure threshold value and is 96 MPa. The fracture toughness index of 1 st to 10 th fracturing sections is 0.57, the fracture toughness index of 11 th to 25 th fracturing sections is 0.64, and the discharge capacity of the sand-carrying fluid of 2 nd to 25 th fracturing sections is 0.5, and the discharge capacity of the sand-carrying fluid of 1 st fracturing section is larger.
In practical application, the discharge capacity of the sand-carrying fluid of the section to be fractured can be greater than or equal to 14m3Min to ensure that sufficient pressure is generated to overcome the stresses within the formation to promote fracture propagation or propagation.
In a sixth implementation manner of the embodiment of the present disclosure, determining, according to a corresponding relationship between the young modulus and a weight ratio of the small-particle-size proppant in the sand-carrying fluid, a weight ratio of the small-particle-size proppant in the sand-carrying fluid corresponding to the young modulus of the section to be fractured may include:
when the Young modulus of the section to be fractured is greater than or equal to the Young modulus threshold value, the weight ratio of the small-particle-size proppant in the sand-carrying fluid of the section to be fractured is greater than or equal to a first set proportion;
and when the Young modulus of the section to be fractured is smaller than the Young modulus threshold value, the weight ratio of the small-particle-size propping agent in the sand carrying liquid of the section to be fractured is between a second set proportion and the first set proportion, and the second set proportion is smaller than the first set proportion.
Young's modulus is a physical quantity that describes the ability of a solid material to resist deformation. When the Young modulus of the section to be fractured is larger than or equal to the Young modulus threshold value, the section to be fractured has stronger deformation resistance and narrower crack gaps, the weight of the small-particle-size propping agent in the sand carrying liquid of the section to be fractured is larger, and the number of small-particle-size propping agents is more, so that the situation that the large-particle-size propping agent is not easy to pass through and is blocked can be avoided, and the problem that the sand carrying liquid is difficult to inject is solved. When the Young modulus of the section to be fractured is smaller than the Young modulus threshold value, the deformation resistance of the section to be fractured is poor, the crack gap is easy to enlarge, the weight of the small-particle-size propping agent in the sand carrying liquid of the section to be fractured is smaller, the large-particle-size propping agent is more, and the expansion of the crack is facilitated.
Illustratively, the threshold young's modulus may be 40GPa, the first set proportion may be 30%, and the second set proportion may be 20%.
For example, the Young's modulus of the 1 st to 10 th fracturing stages is 45.5Gpa, the Young's modulus of the 11 th to 25 th fracturing stages is 41.2Gpa, both of which are larger than the Young's modulus threshold value of 40GPa, and the weight ratio of the small-particle-size proppant in the sand-carrying fluid of the 1 st to 25 th fracturing stages is larger than or equal to the first set proportion of 30%.
In a seventh implementation manner of the embodiment of the present disclosure, determining, according to a corresponding relationship between a development degree of a natural fracture zone, a formation bedding development degree, a weak face development index of a rock mass, and a weight of a proppant in a sand-carrying fluid corresponding to the development degree of the natural fracture zone, the formation bedding development degree, and the weak face development index of the rock mass of a section to be fractured may include:
when the development degree of the natural fracture zone of the section to be fractured is greater than or equal to the development degree threshold value of the natural fracture zone, or when the formation bedding development degree of the section to be fractured is greater than or equal to the formation bedding development degree threshold value, or when the development index of the weak face of the rock body of the section to be fractured is greater than or equal to the development index threshold value of the weak face of the rock body, the weight of the propping agent in the sand carrying liquid of the section to be fractured is between a first set weight and a second set weight, and the second set weight is greater than the first set weight;
and when the development degree of the natural fracture zone of the section to be fractured is smaller than the development degree threshold of the natural fracture zone, the formation bedding development degree of the section to be fractured is smaller than the development degree threshold of the natural fracture zone, and the development index of the weak face of the rock mass of the section to be fractured is smaller than the development index threshold of the weak face of the rock mass, the weight of the propping agent in the sand carrying liquid of the section to be fractured is larger than or equal to a second set weight.
When the development degree of the natural fracture zone of the section to be fractured is greater than or equal to the development degree threshold value of the natural fracture zone, or when the formation bedding development degree of the section to be fractured is greater than or equal to the formation bedding development degree threshold value, or when the development index of the weak face of the rock body of the section to be fractured is greater than or equal to the development index threshold value of the weak face of the rock body, the formation, extension or bracing of the fracture in the section to be fractured is easier, the weight of the propping agent in the sand carrying liquid of the section to be fractured is smaller, the use of the propping agent can be reduced as far as possible, and the fracture blockage is avoided. When the development degree of the natural fracture zone of the section to be fractured is smaller than the development degree threshold of the natural fracture zone, the formation bedding development degree of the section to be fractured is smaller than the development degree threshold of the natural fracture zone, and the development index of the weak face of the rock body of the section to be fractured is smaller than the development index threshold of the weak face of the rock body, the formation, extension or propping of the fracture in the section to be fractured is difficult, the weight of the propping agent in the sand carrying liquid of the section to be fractured is larger, and the propping agent can be utilized to promote the formation, extension or propping of the fracture.
Illustratively, the threshold of the development degree of the natural fracture zone can be 80 strips mm/m, the threshold of the formation bedding development degree can be 120 layers/m, the threshold of the development index of the weak face of the rock mass can be 0.55, the first set weight can be 90t, and the second set weight can be 120 t.
For example, the development degree of the natural fracture zone of the 1 st to 10 th fracturing sections is 95 mm/m, the development degree of the natural fracture zone of the 11 th to 25 th fracturing sections is 88 mm/m, which are all greater than the development degree threshold value of the natural fracture zone of 80 mm/m, the formation bedding development degree of the 1 st to 10 th fracturing sections is 118 layers/m, the formation bedding development degree of the 11 th to 25 th fracturing sections is 98 layers/m, which are all less than the formation bedding development degree threshold value of 120 layers/m, the weak face development index of the rock mass of the 1 st to 10 th fracturing sections is 0.66, the weak face development index of the rock mass of the 11 th to 25 th fracturing sections is 0.62, which is greater than the weak face development index threshold value of the rock mass of 0.55, the weight of the propping agent in the sand carrier fluid of the 1 st to 25 th fracturing sections is greater than or equal to the first set weight of 90t, and the adding degree of the propping agent can be greater than or equal to 1.5 t/m.
In an eighth implementation manner of the embodiment of the present disclosure, determining, according to a correspondence between the complexity of the slotted network and the addition manner of the proppant in the sand carrying fluid and the concentration of the proppant in the sand carrying fluid, which correspond to the complexity of the slotted network of the section to be fractured, may include:
when the complexity of the fracture network of the section to be fractured is greater than or equal to the threshold of the complexity of the fracture network, adding a proppant into a sand carrying liquid of the section to be fractured in a slug type sand adding mode, wherein the concentration of the proppant in the sand carrying liquid of the section to be fractured is less than or equal to a first set concentration;
when the complexity of the fracture network of the section to be fractured is smaller than the threshold value of the complexity of the fracture network, the adding mode of the proppant in the sand carrying liquid of the section to be fractured adopts the combination of continuous sand adding and slug sand adding, the concentration of the proppant in the sand carrying liquid of the section to be fractured is smaller than or equal to a second set concentration, and the second set concentration is smaller than the first set concentration.
The fracture network is a network structure formed by criss-crossing fractures in the formation. When the net-sewing complexity of the section to be fractured is greater than or equal to the net-sewing complexity threshold value, the net-sewing of the section to be fractured is relatively complex, and the blocking of the propping agent is favorably avoided by adopting the slug type sand adding; and the concentration of the proppant is higher, so that the proppant can be used for effectively supporting the seam net. When the complexity of the fracture network of the section to be fractured is smaller than the threshold value of the complexity of the fracture network, the fracture network of the section to be fractured is simpler, continuous sand adding and slug sand adding are combined, a propping agent can be matched in time while the fracture extends, and the fracturing effect is better; and the concentration of the propping agent is low, which is beneficial to continuously adding sand and avoiding the propping agent from being blocked.
Illustratively, the stitch net complexity threshold may be 0.5, and the first set concentration may be 140kg/m3The second set concentration may be 100kg/m3。
For example, the fracture network complexity of 1 st to 10 th fracturing sections is 0.55, the fracture network complexity of 11 th to 25 th fracturing sections is 0.54, which is greater than the fracture network complexity threshold value 0.5, the proppant is added into the sand-carrying fluid of 1 st to 25 th fracturing sections in a section plug type sand adding mode, and the concentration of the proppant is less than or equal to the first set concentration of 140kg/m3。
In a ninth implementation manner of the embodiment of the present disclosure, determining, according to a corresponding relationship between fracture extension and a steering index and a concentration of a temporary plugging agent in a sand-carrying fluid, a concentration of the temporary plugging agent in the sand-carrying fluid corresponding to the fracture extension and the steering index of a to-be-fractured segment may include:
when the fracture extension and the steering index of the section to be fractured are larger than or equal to the fracture extension and steering index threshold values, the concentration of the temporary plugging agent in the sand-carrying fluid of the section to be fractured is equal to 0 (namely the temporary plugging agent is not used);
when the fracture extension and the steering index of the section to be fractured are smaller than the fracture extension and steering index threshold value, the concentration of the temporary plugging agent in the sand carrying fluid of the section to be fractured is larger than 0 (the temporary plugging agent is generally used in the middle stage of the sand carrying fluid stage).
Fracture propagation and steering indices are used to indicate the likelihood of fracture propagation or steering. When the fracture extension and diversion index of the section to be fractured is greater than or equal to the fracture extension and diversion index threshold value, the fracture extension or diversion is easier, and the temporary plugging agent can be omitted. When the fracture extension and the steering index of the to-be-fractured section are smaller than the fracture extension and steering index threshold value, the fracture extension or steering is difficult, the flow direction of the sand-carrying liquid can be guided by using the temporary plugging agent, and the formation, extension or expansion of the fracture is facilitated.
Illustratively, the fracture propagation and steering index threshold may be 0.5.
For example, the fracture extension and steering index of 1-10 fracturing stages is 0.54 greater than the fracture extension and steering index threshold value of 0.5, and the concentration of the temporary plugging agent in the sand-carrying fluid of 1-10 fracturing stages is equal to 0; the fracture extension and steering index of the 11 th to 25 th fracturing stages is 0.47 smaller than the fracture extension and steering index threshold value of 0.5, and the concentration of the temporary plugging agent in the sand carrying liquid of the 11 th to 25 th fracturing stages is larger than 0.
In a tenth implementation manner of the embodiment of the present disclosure, determining, according to a corresponding relationship between the young modulus and a form of the temporary plugging agent in the sand-carrying fluid, a form of the temporary plugging agent in the sand-carrying fluid corresponding to the young modulus of the section to be fractured may include:
when the Young modulus of the section to be fractured is greater than or equal to the Young modulus threshold value, the temporary plugging agent in the sand-carrying liquid of the section to be fractured is in a powder form;
when the Young modulus of the section to be fractured is smaller than the Young modulus threshold value, the form of the temporary plugging agent in the sand carrying liquid of the section to be fractured comprises powder and particles, and the weight ratio of the powder is larger than or equal to a third set proportion.
Young's modulus is a physical quantity that describes the ability of a solid material to resist deformation. When the Young modulus of the section to be fractured is greater than or equal to the Young modulus threshold value, the deformation resistance of the section to be fractured is strong, the crack gap is narrow, and the temporary plugging agent in the sand-carrying liquid of the section to be fractured is completely powdery, so that the condition that the temporary plugging agent is not easy to pass through and is clamped, even blocked for a long time or blocked permanently can be avoided. When the Young modulus of the section to be fractured is smaller than the Young modulus threshold value, the deformation resistance of the section to be fractured is poor, the crack gap is easy to enlarge, and the temporary plugging agent in the sand carrying liquid of the section to be fractured contains particles with larger particle size, so that the plugging effect is better.
Illustratively, the threshold young modulus may be 40GPa and the third set proportion may be 80%.
For example, the Young's modulus of the 1 st to 10 th fracturing stages is 45.5Gpa, the Young's modulus of the 11 th to 25 th fracturing stages is 41.2Gpa, both of which are greater than the Young's modulus threshold value of 40GPa, the temporary plugging agent in the sand-carrying fluid of the 1 st to 25 th fracturing stages is in the form of powder, and the adding degree of the powder can be 200 kg/stage.
In practical application, the weight of the temporary plugging agent in the sand-carrying fluid of the section to be fractured can be 200 kg-300 kg.
In an eleventh implementation manner of the embodiment of the present disclosure, determining, according to a corresponding relationship between the volume ratio of the gas in the set form and the number of each cluster of perforations in the multiple clusters of perforations, the number of each cluster of perforations in the multiple clusters of perforations corresponding to the volume ratio of the gas in the set form of the to-be-fractured segment may include:
when the free gas content ratio of the to-be-fractured section is greater than or equal to the free gas content ratio threshold value, or when the adsorption gas content ratio of the to-be-fractured section is less than or equal to the adsorption gas content ratio threshold value, the number of clusters of holes in the multiple clusters of perforations of the to-be-fractured section is equal;
when the free gas content ratio of the to-be-fractured section is smaller than the free gas content ratio threshold value, or when the adsorption gas content ratio of the to-be-fractured section is larger than the adsorption gas content ratio threshold value, the number of cluster holes on two sides in the multi-cluster perforation of the to-be-fractured section is smaller than the number of cluster holes in the middle;
and the sum of the free gas amount ratio threshold and the adsorption gas amount ratio threshold is equal to 1.
When the free gas content ratio of the to-be-fractured section is greater than or equal to the free gas content ratio threshold value, or when the adsorbed gas content ratio of the to-be-fractured section is less than or equal to the adsorbed gas content ratio threshold value, more free gas and less adsorbed gas exist in the to-be-fractured section, the number of cluster holes in the multi-cluster perforation of the to-be-fractured section is equal, and the free gas can be acted on the free gas on average. When the free gas content ratio of the to-be-fractured section is smaller than the free gas content ratio threshold value, or when the adsorption gas content ratio is larger than the adsorption gas content ratio threshold value, the free gas content of the to-be-fractured section is less and the adsorption gas content is more, and the number of cluster holes on two sides in the multi-cluster perforation of the to-be-fractured section is smaller than that of cluster holes in the middle, so that the adsorption gas is favorably avoided.
Illustratively, the free gas amount ratio threshold may be 60%, and the adsorption gas amount ratio threshold may be 40%.
For example, the free gas content ratio of 1-10 fracturing stages is greater than 60% of the free gas content ratio threshold, the adsorption gas content ratio of 1-10 fracturing stages is less than 40% of the adsorption gas content ratio threshold, and the number of the cluster holes in the multi-cluster perforation of 1-10 fracturing stages is equal to 12; the free gas content of 11-25 fracturing stages is less than 60% of the free gas content, the adsorption gas content of 11-25 fracturing stages is greater than 40% of the adsorption gas content, 12 holes on two sides of the multiple-cluster perforation of 11-25 fracturing stages are less than 16 holes on the middle cluster perforation, or 8 holes on two sides of the multiple-cluster perforation of 11-25 fracturing stages are less than 12 holes on the middle cluster perforation.
In practical applications, the density of the holes in the multiple shower holes may be 12 holes/m.
In a twelfth implementation manner of the embodiment of the present disclosure, determining, according to a corresponding relationship between the brittleness index, the seam-network complexity, and the volume of the displacement liquid, a volume of the displacement liquid corresponding to the brittleness index and the seam-network complexity of the segment to be fractured may include:
when the brittleness index of the section to be fractured is greater than or equal to the brittleness index threshold value and the fracture network complexity of the section to be fractured is greater than or equal to the fracture network complexity threshold value, the volume of the displacement liquid of the section to be fractured is equal to the volume of the shaft;
and when the brittleness index of the section to be fractured is smaller than the brittleness index threshold value or when the fracture network complexity of the section to be fractured is smaller than the fracture network complexity threshold value, the volume of the displacement liquid of the section to be fractured is larger than the volume of the shaft.
When the brittleness index of the section to be fractured is larger than or equal to the brittleness index threshold value and the fracture network complexity of the section to be fractured is larger than or equal to the fracture network complexity threshold value, the section to be fractured is larger in brittleness and more complex in fracture network, the fracture is easier to form, extend and strut, the sand-carrying liquid of the shaft can be completely replaced into the fracture when the volume of the replacing liquid of the section to be fractured is equal to the volume of the shaft, and the fracture is supported by quartz sand. When the brittleness index of the section to be fractured is smaller than the brittleness index threshold value or the fracture network complexity of the section to be fractured is smaller than the fracture network complexity threshold value, the brittleness of the section to be fractured is reduced or the fracture network is simpler, the formation, extension and opening of the fracture are more difficult, the volume of the displacement liquid of the section to be fractured is larger than the volume of the shaft, so that the sand-carrying liquid of the shaft is ensured to completely displace into the fracture, and the fracture is supported by quartz sand.
Illustratively, the friability index threshold may be 0.5, the stitch-web complexity threshold may be 0.5; the volume of the displacement liquid of the section to be fractured is larger than the volume of the shaft, and can be 1.5 times of the volume of the shaft.
For example, the brittleness index of 1-10 fracturing stages is 0.66, the brittleness index of 11-25 fracturing stages is 0.59, the fracture network complexity of 1-10 fracturing stages is 0.55, the fracture network complexity of 11-25 fracturing stages is 0.54, and the displacement liquid volume of 1-25 fracturing stages is equal to the volume of a shaft.
In practical applications, one or more of the various implementations described above may be performed. When all of the above-mentioned various implementation modes are implemented, the pressure parameters of each fractured section in the well can be optimized to the greatest extent, so that the pressure parameters are adapted to the different reservoir parameters of each fractured section in the well, and the yield of the whole well is improved.
Optionally, the determining method may further include:
and acquiring the unit volume gas quantity of the section to be fractured.
Accordingly, this step 101 may comprise:
and when the unit volume gas quantity of the section to be fractured is greater than or equal to the gas quantity threshold value, acquiring the geological parameters of the section to be fractured.
When the unit volume gas quantity of the section to be fractured is smaller than the gas quantity threshold value, the gas quantity which can be exploited by the section to be fractured is less, and the value of fracturing construction is not possessed, so that hydraulic fracturing can not be carried out. When the gas volume per unit volume of the to-be-fractured segment is greater than or equal to the gas volume threshold value, the gas volume which can be exploited by the to-be-fractured segment is large, and the to-be-fractured segment has the value of fracturing construction, so that hydraulic fracturing is performed, and therefore geological parameters of the to-be-fractured segment are obtained (namely step 101).
Exemplarily, the gas amount threshold value can be 2t/m3。
For example, the gas amount per unit volume of 1 st to 10 th fracturing stages is 6.8t/m3And the unit volume gas quantity of 11 th to 25 th fracturing sections is 5.5t/m3Are all larger than the gas threshold value of 2t/m3And performing hydraulic fracturing on the 1 st to 25 th fracturing stages.
Optionally, before step 101, the determining method may further include:
and establishing a geological model of the deep shale gas reservoir.
In embodiments of the present disclosure, the geological model of the deep shale gas reservoir may include at least one of the following geological models: the method comprises the following steps of geological model of carbonate mineral content, geological model of Young modulus, geological model of brittleness index, geological model of distribution position of natural crack zone, geological model of development degree of natural crack zone, geological model of formation bedding development degree, geological model of rock weak face development index, geological model of crack fracture pressure, geological model of fracture toughness index, geological model of crack extension and steering index, geological model of crack network complexity, geological model of free gas content ratio, geological model of adsorbed gas content ratio and geological model of unit volume gas content.
In a first implementation, establishing a geological model of carbonate mineral content may include:
measuring a plurality of areas by adopting a geophysical exploration technology, and respectively substituting the measured data of the areas into a set formula to obtain the carbonate mineral content of each area;
and obtaining the carbonate mineral contents of all the regions of the deep shale gas reservoir by adopting a sequential Gaussian simulation algorithm based on the carbonate mineral contents of all the regions, and establishing a geological model comprising the carbonate mineral contents.
In embodiments of the present disclosure, the geophysical prospecting techniques may include at least one of geophysical logging techniques and seismic prospecting techniques. Geophysical logging is the process of exploring and exploiting petroleum, coal and metal ore bodies by measuring the physical parameters of underground rock strata and the technical conditions of wells with various instruments, analyzing the recorded data and researching geology and engineering. Seismic exploration is a geophysical exploration method which utilizes the difference of elasticity and density of underground media caused by artificial excitation and infers the properties and the forms of underground rock layers by observing and analyzing the propagation rule of seismic waves generated by artificial earthquake in the underground.
In a second implementation, establishing a geological model of young's modulus may include:
measuring a plurality of regions by adopting a geophysical exploration technology, and respectively substituting the measured data of the plurality of regions into a set formula to obtain the Young modulus of each region;
and obtaining the Young modulus of all the regions of the deep shale gas reservoir by adopting a sequential Gaussian simulation algorithm based on the Young modulus of each region, and establishing a geological model comprising the Young modulus.
In a third implementation, establishing a geological model of brittleness index may include:
measuring a plurality of regions by adopting a geophysical exploration technology, and respectively substituting the measured data of the plurality of regions into a set formula to obtain the Young modulus and the Poisson ratio of each region;
substituting the Young modulus and the Poisson ratio of each region into the following formula (1) to obtain the brittleness index Brit of each region:
wherein Brit is a brittleness index and is dimensionless; enYoung's modulus, dimensionless; v isnIs Poisson's ratio and is dimensionless; (E)n/νn)minIs the minimum value of the ratio of Young's modulus to Poisson's ratio, (E)n/νn)maxMaximum value of the ratio of Young's modulus to Poisson's ratio;
and obtaining the brittleness indexes of all the regions of the deep shale gas reservoir by adopting a sequential Gaussian simulation algorithm based on the brittleness indexes of all the regions, and establishing a geological model comprising the Young modulus.
In a fourth implementation, establishing a geological model of the distribution locations of natural fracture zones may include:
measuring the plurality of regions by adopting a geophysical exploration technology to obtain measurement data of the plurality of regions;
based on the measurement data of a plurality of areas, the distribution position of the natural crack belt is identified by adopting an ant body tracking technology, and a geological model comprising Young modulus is established.
In a fifth implementation, establishing a geological model of the extent of development of a natural fracture zone may include:
measuring a plurality of regions by adopting a geophysical exploration technology, and respectively substituting the measured data of the plurality of regions into a set formula to obtain the siliceous mineral content and the carbonate mineral content of each region;
substituting the siliceous mineral content and the carbonate mineral content of each region into the following formula (2) to obtain the natural fissure zone development degree I of each regionn：
In＝0.55×fSi+1.5×fCa+48.5 (2)
Wherein, InFor natural fracturesThe degree of belt development is in the unit of strip.mm/m; f. ofsiIs the siliceous mineral content, in%; f. ofCaCarbonate mineral content in units of%;
and obtaining the natural fissure zone development degrees of all the regions of the deep shale gas reservoir by adopting a sequential Gaussian simulation algorithm based on the natural fissure zone development degrees of all the regions, and establishing a geological model comprising the natural fissure zone development degrees.
In a sixth implementation, the establishing a geological model of the stratigraphic development degree of the rock formation may include:
measuring a plurality of regions by adopting a geophysical exploration technology, and respectively substituting the measured data of the plurality of regions into a set formula to obtain the siliceous mineral content and the carbonate mineral content of each region;
substituting the siliceous mineral content and the carbonate mineral content of each region into the following formula (3) to obtain the rock stratum bedding development degree S of each regionn：
Wherein S isnThe bedding development degree of the rock stratum is shown as the unit of stratum/m; f. ofsiIs the siliceous mineral content, in%; f. ofCaCarbonate mineral content in units of%;
and obtaining the rock stratum bedding development degrees of all the regions of the deep shale gas reservoir by adopting a sequential Gaussian simulation algorithm based on the rock stratum bedding development degrees of all the regions, and establishing a geological model comprising the rock stratum bedding development degrees.
In a seventh implementation manner, the establishing of the geological model of the rock mass weak plane development index may include:
measuring a plurality of regions by adopting a geophysical exploration technology, and respectively substituting the measured data of the plurality of regions into a set formula to obtain the siliceous mineral content and the carbonate mineral content of each region;
substituting the siliceous mineral content and the carbonate mineral content of each region into the following formula (2) to obtain the development degree of the natural crack belt of each region;
substituting the siliceous mineral content and the carbonate mineral content of each region into the following formula (3) to obtain the rock stratum bedding development degree of each region;
substituting the natural fissure zone development degree and the rock stratum bedding development degree of each geographical position into the following formula (4) to obtain the rock mass weak plane development index L of each regionN：
Wherein L isNThe rock mass weak surface development index is dimensionless; snThe bedding development degree of the rock stratum is shown as the unit of stratum/m; sminIs the minimum value of the degree of formation bedding development, SmaxThe maximum value of the formation bedding development degree; i isnThe development degree of the natural fissure zone is shown in the unit of strip mm/m; i isminMinimum degree of development of natural fissure zone, ImaxThe maximum value of the development degree of the natural fissure zone;
and obtaining the rock mass weak plane development indexes of all the regions of the deep shale gas reservoir by adopting a sequential Gaussian simulation algorithm based on the rock mass weak plane development indexes of all the regions, and establishing a geological model comprising the rock mass weak plane development indexes.
In an eighth implementation, creating a geological model of fracture cracking pressure may include:
measuring a plurality of regions by adopting a geophysical exploration technology, and respectively substituting the measured data of the regions into a set formula to obtain the magnitude and direction of the stress borne by the wall surface of the natural crack of each region and the inclination angle of the natural crack;
substituting the magnitude and direction of the stress borne by the wall surface of the natural fracture of each region and the inclination angle of the natural fracture into the following formula (5) to obtain fracture pressure sigma of each regionn：
σn＝Svcos2γ+Sysin2γsin2θ+Sxsin2γcos2θ (5)
Wherein σnFracture pressure in MPa; svThe vertical stress on the wall surface of the natural crack is in MPa; gamma is the natural fracture dip angle, and the unit is DEG; syThe maximum horizontal main stress borne by the wall surface of the natural crack is MPa; theta is the direction included angle between the natural crack and the maximum horizontal principal stress, and the unit is DEG; sxThe minimum horizontal principal stress borne by the wall surface of the natural crack is MPa;
and obtaining fracture pressures of all the regions of the deep shale gas reservoir by adopting a sequential Gaussian simulation algorithm based on the fracture pressure of each region, and establishing a geological model comprising the fracture pressures.
In a ninth implementation, creating a geological model of fracture toughness index may include:
measuring a plurality of areas by adopting a geophysical exploration technology, and respectively substituting the measured data of the areas into a set formula to obtain the I-type fracture toughness of each area;
substituting the type I fracture toughness of each region into the following formula (6) to obtain the fracture toughness index K of each regionN：
Wherein, KNIs fracture toughness index, and has no dimension; kⅠIs type I fracture toughness with the unit of MPa.m0.5；KⅠmaxMaximum value of type I fracture toughness, KⅠminIs the minimum value of type I fracture toughness;
and obtaining fracture toughness indexes of all the regions of the deep shale gas reservoir by adopting a sequential Gaussian simulation algorithm based on the fracture toughness indexes of all the regions, and establishing a geological model comprising the fracture toughness indexes.
In a tenth implementation, creating a geological model of fracture propagation and steering index may include:
measuring a plurality of regions by adopting a geophysical exploration technology, and respectively substituting the measured data of the regions into a set formula to obtain the magnitude and direction of the stress borne by the wall surface of the natural crack of each region and the inclination angle of the natural crack;
substituting the magnitude and direction of the stress borne by the wall surface of the natural fracture of each region and the inclination angle of the natural fracture into the following formula (7) to obtain the minimum net pressure P of fracture extension and steering of each region1：
Wherein, P1Minimum net pressure in MPa for fracture extension and steering; pxThe net pressure for crack extension in MPa; svThe vertical stress on the wall surface of the natural crack is in MPa; sxThe minimum horizontal principal stress borne by the wall surface of the natural crack is MPa; theta is the direction included angle between the natural crack and the maximum horizontal principal stress, and the unit is DEG; pyThe net pressure of the crack deflection is in MPa; t is0Tensile strength in MPa, typically a constant of 3 MPa;
substituting the minimum net pressure of fracture extension and steering of each zone into the following formula (8) to obtain the fracture extension and steering index P of each zonenet：
Wherein, PnetIs fracture propagation and steering index, dimensionless; p1Minimum net pressure in MPa for fracture extension and steering; p1maxMaximum value of net pressure for fracture propagation and diversion, P1minThe minimum of net pressure for fracture propagation and diversion;
and obtaining fracture extension and steering indexes of all regions of the deep shale gas reservoir by adopting a sequential Gaussian simulation algorithm based on the fracture extension and steering indexes of all regions, and establishing a geological model comprising the fracture extension and steering indexes.
In an eleventh implementation, building a geological model of seam-mesh complexity may include:
measuring a plurality of regions by adopting a geophysical exploration technology, and respectively substituting the measured data of the regions into a set formula to obtain the I-type fracture toughness, the magnitude and the direction of stress borne by the wall surface of the natural fracture and the inclination angle of the natural fracture of each region;
substituting the type I fracture toughness of each region into the following formula (6) to obtain the fracture toughness index of each region;
substituting the magnitude and direction of the stress borne by the wall surface of the natural fracture of each region and the inclination angle of the natural fracture into the following formula (7) to obtain the minimum net pressure of fracture extension and steering of each region;
substituting the minimum net pressure for fracture propagation and steering for each zone into the following equation (8) to obtain fracture propagation and steering indices for each zone:
substituting the magnitude and direction of the stress borne by the wall surface of the natural crack of each region and the inclination angle of the natural crack into the following formula (5) to obtain the fracture pressure of each region;
the fracture cracking pressure of each region is substituted into the following formula (9) to obtain a fracture cracking pressure index σ of each regionN：
Wherein σNIs a seam rupture pressure index, dimensionless; sigmanFracture pressure in MPa; sigmanmaxMaximum value of fracture cracking pressure, σnminIs the minimum value of fracture cracking pressure;
substituting the fracture rupture pressure index, the fracture extension and turning index and the fracture toughness index of each area into the following formula (10) to obtain the fracture network complexity F of each arean：
Wherein, FnThe mesh sewing complexity is zero dimension; kNIs fracture toughness index, and has no dimension; sigmaNIs a seam rupture pressure index, dimensionless; pnetIs fracture propagation and steering index, dimensionless;
and (3) based on the seam network complexity of each region, obtaining the seam network complexity of all regions of the deep shale gas reservoir by adopting a sequential Gaussian simulation algorithm, and establishing a geological model comprising the seam network complexity.
In a twelfth implementation manner, establishing a free gas amount ratio geological model and an adsorbed gas amount ratio geological model may include:
measuring a plurality of areas by adopting a geophysical exploration technology, and respectively substituting the measured data of the areas into a set formula to obtain the free gas amount and the adsorbed gas amount of each area;
substituting the free gas amount and the adsorption gas amount of each region into the following formula (11) to obtain the free gas amount ratio R of each region1And the adsorbed gas amount is R2：
Wherein R is1The content of free gas is in percentage by weight; b isfIs the amount of free gas, in m3/t；BaIs the amount of adsorbed gas, and has the unit of m3/t；R2The unit is% of the adsorbed gas amount;
based on the free gas content ratios of all the regions, obtaining the free gas content ratios of all the regions of the deep shale gas reservoir by adopting a sequential Gaussian simulation algorithm, and establishing a geological model comprising the free gas content ratios;
and obtaining the adsorption gas volume ratios of all the regions of the deep shale gas reservoir by adopting a sequential Gaussian simulation algorithm based on the adsorption gas volume ratios of all the regions, and establishing a geological model comprising the adsorption gas volume ratios.
In a thirteenth implementation, the establishing a geological model of the gas volume per unit volume may include:
measuring a plurality of areas by adopting a geophysical exploration technology, and respectively substituting the measured data of the areas into a set formula to obtain the free gas amount and the adsorbed gas amount of each area;
substituting the free gas amount and the adsorption gas amount of each region into the following formula (11) to obtain the free gas amount ratio and the adsorption gas amount ratio of each region;
substituting the free gas quantity ratio and the adsorption gas quantity ratio of each region into the following formula (12) to obtain the unit volume gas quantity B of each regiont：
Bt＝Ba+Bf (12)
Wherein, BtIs the unit volume gas quantity, and the unit is m3/t；BfIs the amount of free gas, in m3/t；BaIs the amount of adsorbed gas, and has the unit of m3/t；
And based on the unit volume gas of each region, obtaining the unit volume gas of all regions of the deep shale gas reservoir by adopting a sequential Gaussian simulation algorithm, and establishing a geological model comprising the unit volume gas.
The embodiment of the disclosure provides a device for determining deep shale gas reservoir hydraulic fracturing parameters, which is suitable for a method for determining deep shale gas reservoir hydraulic fracturing parameters shown in fig. 1. Fig. 2 is a schematic structural diagram of a device for determining deep shale gas reservoir hydraulic fracturing parameters according to an embodiment of the present disclosure. Referring to fig. 2, the determination means includes:
the geological parameter acquisition module 201 is used for acquiring geological parameters of a section to be fractured in the deep shale gas reservoir;
the fracturing parameter determining module 202 is configured to determine a hydraulic fracturing parameter corresponding to the geological parameter of the to-be-fractured section according to a corresponding relationship between the geological parameter and the hydraulic fracturing parameter, where the range of the hydraulic fracturing parameter corresponding to the geological parameter in different ranges is different, and the determined hydraulic fracturing parameter is a construction parameter during hydraulic fracturing of the to-be-fractured section.
Optionally, the geological parameters comprise at least one of the following parameters: setting the volume ratio of the morphological gas, the content of carbonate minerals, the Young modulus, the fracture pressure, the distribution position of a natural fracture zone, the brittleness index, the fracture toughness index, the development degree of the natural fracture zone, the formation bedding development degree, the development index of the weak surface of a rock mass, the complexity of a fracture network, the fracture extension and the steering index; setting the volume ratio of the morphological gas as the free gas content ratio or the adsorption gas content ratio.
The hydraulic fracturing parameters include at least one of the following parameters: the method comprises the following steps of counting the number of each cluster of holes in a multi-cluster perforation, the volume of acid liquid in a pad fluid, the volume of the pad fluid, the displacement of the pad fluid, the volume of a sand carrying fluid, the displacement of the sand carrying fluid, the weight ratio of small-particle-size proppants in the sand carrying fluid, the weight of proppants in the sand carrying fluid, the concentration of temporary plugging agents in the sand carrying fluid, the form of temporary plugging agents in the sand carrying fluid and the volume of a displacement fluid.
The fracture parameter determination module 202 may be used to implement at least one of the following:
determining the number of each cluster hole in the multi-cluster perforation corresponding to the volume ratio of the gas in the set form of the section to be fractured according to the corresponding relationship between the volume ratio of the gas in the set form and the number of each cluster hole in the multi-cluster perforation;
determining the volume of acid liquor in the pad fluid corresponding to the carbonate mineral content of the section to be fractured according to the wellhead pressure drop before and after the pad fluid is injected into the 1 st fracturing section and the corresponding relation between the carbonate mineral content and the volume of the acid liquor in the pad fluid;
determining the volume of the pad fluid corresponding to the Young modulus of the section to be fractured according to the corresponding relation between the Young modulus and the volume of the pad fluid;
determining the displacement of the pad fluid corresponding to the fracture rupture pressure of the section to be fractured according to the corresponding relation between the fracture rupture pressure and the displacement of the pad fluid;
determining the distribution position of the natural fracture zone of the section to be fractured and the volume of the sand carrying liquid corresponding to the brittleness index according to the corresponding relation of the distribution position of the natural fracture zone, the brittleness index and the volume of the sand carrying liquid;
determining the sand-carrying fluid displacement corresponding to the fracture toughness index of the section to be fractured according to the variation amplitude of the wellhead pressure during the hydraulic fracturing of the 1 st fracturing section, the average value of the wellhead pressure during the hydraulic fracturing of the 1 st fracturing section and the corresponding relation between the fracture toughness index and the sand-carrying fluid displacement;
determining the weight ratio of the small-particle-size proppant in the sand-carrying fluid corresponding to the Young modulus of the section to be fractured according to the corresponding relationship between the Young modulus and the weight ratio of the small-particle-size proppant in the sand-carrying fluid;
determining the development degree of the natural fracture zone of the section to be fractured, the bedding development degree of the rock stratum and the weight of the proppant in the sand carrying liquid corresponding to the weak surface development index of the rock mass according to the corresponding relation of the development degree of the natural fracture zone, the bedding development degree of the rock stratum and the development index of the rock mass;
determining the addition mode of the proppant in the sand carrying fluid and the concentration of the proppant in the sand carrying fluid corresponding to the complexity of the fracture network of the section to be fractured according to the corresponding relationship among the complexity of the fracture network, the addition mode of the proppant in the sand carrying fluid and the concentration of the proppant in the sand carrying fluid;
determining the concentration of the temporary plugging agent in the sand carrying liquid corresponding to the fracture extension and the steering index of the section to be fractured according to the corresponding relationship between the fracture extension and the steering index and the concentration of the temporary plugging agent in the sand carrying liquid;
determining the form of the temporary plugging agent in the sand carrying liquid corresponding to the Young modulus of the section to be fractured according to the corresponding relation between the Young modulus and the form of the temporary plugging agent in the sand carrying liquid;
and determining the volume of the displacement liquid corresponding to the brittleness index and the seam network complexity of the section to be fractured according to the corresponding relation of the brittleness index, the seam network complexity and the volume of the displacement liquid.
Optionally, the determining means may further include:
and the measuring module is used for measuring the wellhead pressure when the 1 st fracturing section is subjected to hydraulic fracturing.
Fig. 3 is a schematic structural diagram of a deep shale gas reservoir hydraulic fracturing parameter determination device according to an exemplary embodiment of the present disclosure. As shown in fig. 3, the apparatus may be a computer device 900. The computer device 900 includes a Central Processing Unit (CPU)901, a system memory 904 including a Random Access Memory (RAM)902 and a Read Only Memory (ROM)903, and a system bus 905 connecting the system memory 904 and the central processing unit 901. The computer device 900 also includes a basic input/output system (I/O system) 906 for facilitating information transfer between devices within the computer, and a mass storage device 907 for storing an operating system 913, application programs 914, and other program modules 915.
The basic input/output system 906 includes a display 908 for displaying information and an input device 909 such as a mouse, keyboard, etc. for user input of information. Wherein the display 908 and the input device 909 are connected to the central processing unit 901 through an input output controller 910 connected to the system bus 905. The basic input/output system 906 may also include an input/output controller 910 for receiving and processing input from a number of other devices, such as a keyboard, mouse, or electronic stylus. Similarly, input-output controller 910 also provides output to a display screen, a printer, or other type of output device.
The mass storage device 907 is connected to the central processing unit 901 through a mass storage controller (not shown) connected to the system bus 905. The mass storage device 907 and its associated computer-readable media provide non-volatile storage for the computer device 900. That is, the mass storage device 907 may include a computer-readable medium (not shown) such as a hard disk or CD-ROM drive.
Without loss of generality, the computer-readable media may comprise computer storage media and communication media. Computer storage media includes volatile and nonvolatile, removable and non-removable media implemented in any method or technology for storage of information such as computer readable instructions, data structures, program modules or other data. Computer storage media includes RAM, ROM, EPROM, EEPROM, flash memory or other solid state memory technology, CD-ROM, DVD, or other optical storage, magnetic cassettes, magnetic tape, magnetic disk storage or other magnetic storage devices. Of course, those skilled in the art will appreciate that the computer storage media is not limited to the foregoing. The system memory 904 and mass storage device 907 described above may be collectively referred to as memory.
The computer device 900 may also operate as a remote computer connected to a network via a network, such as the internet, in accordance with various embodiments of the invention. That is, the computer device 900 may be connected to the network 912 through the network interface unit 911 coupled to the system bus 905, or the network interface unit 911 may be used to connect to other types of networks or remote computer systems (not shown).
The memory further includes one or more programs, the one or more programs are stored in the memory, and the central processor 901 implements the method for determining the deep shale gas reservoir hydraulic fracturing parameters shown in fig. 1 by executing the one or more programs.
In an exemplary embodiment, a non-transitory computer-readable storage medium, such as a memory, including instructions executable by a processor of a computer device to perform a method of determining deep shale gas reservoir hydraulic fracturing parameters as illustrated in various embodiments of the present invention is also provided. For example, the non-transitory computer readable storage medium may be a ROM, a Random Access Memory (RAM), a CD-ROM, a magnetic tape, a floppy disk, an optical data storage device, and the like.
It will be understood by those skilled in the art that all or part of the steps for implementing the above embodiments may be implemented by hardware, or may be implemented by a program instructing relevant hardware, where the program may be stored in a computer-readable storage medium, and the above-mentioned storage medium may be a read-only memory, a magnetic disk or an optical disk, etc.
The above description is intended to be exemplary only and not to limit the present disclosure, and any modification, equivalent replacement, or improvement made without departing from the spirit and scope of the present disclosure is to be considered as the same as the present disclosure.
Claims (19)
1. A method for determining hydraulic fracturing parameters of a deep shale gas reservoir is characterized by comprising the following steps:
acquiring geological parameters of a section to be fractured in a deep shale gas reservoir;
determining the hydraulic fracturing parameters corresponding to the geological parameters of the section to be fractured according to the corresponding relation between the geological parameters and the hydraulic fracturing parameters, wherein the values of the hydraulic fracturing parameters corresponding to the geological parameters in different value ranges are different, and the determined hydraulic fracturing parameters are construction parameters during hydraulic fracturing of the section to be fractured.
2. The method of determining according to claim 1, wherein the geological parameters comprise at least one of the following parameters: setting the volume ratio of the morphological gas, the content of carbonate minerals, the Young modulus, the fracture pressure, the distribution position of a natural fracture zone, the brittleness index, the fracture toughness index, the development degree of the natural fracture zone, the formation bedding development degree, the development index of the weak surface of a rock mass, the complexity of a fracture network, the fracture extension and the steering index; the volume ratio of the gas in the set shape is the free gas content ratio or the adsorption gas content ratio;
the hydraulic fracturing parameters include at least one of the following: the method comprises the following steps of (1) counting the number of each cluster in a multi-cluster perforation, the volume of acid liquor in a pad fluid, the volume of the pad fluid, the displacement of the pad fluid, the volume of a sand carrying fluid, the displacement of the sand carrying fluid, the weight ratio of small-particle-size proppants in the sand carrying fluid, the weight of proppants in the sand carrying fluid, the concentration of temporary plugging agents in the sand carrying fluid, the form of temporary plugging agents in the sand carrying fluid and the volume of a displacement fluid;
the hydraulic fracturing parameter corresponding to the geological parameter of the section to be fractured is determined according to the corresponding relation between the geological parameter and the hydraulic fracturing parameter, and the method comprises at least one of the following modes:
determining the number of each cluster hole in the multi-cluster perforation corresponding to the volume ratio of the gas in the set form of the section to be fractured according to the corresponding relationship between the volume ratio of the gas in the set form and the number of each cluster hole in the multi-cluster perforation;
determining the volume of acid liquor in the pad fluid corresponding to the carbonate mineral content of the section to be fractured according to the wellhead pressure drop before and after the pad fluid is injected into the 1 st fracturing section and the corresponding relation between the carbonate mineral content and the volume of the acid liquor in the pad fluid;
determining the volume of the pad fluid corresponding to the Young modulus of the section to be fractured according to the corresponding relation between the Young modulus and the volume of the pad fluid;
determining the displacement of the pad fluid corresponding to the fracture rupture pressure of the section to be fractured according to the corresponding relation between the fracture rupture pressure and the displacement of the pad fluid;
determining the distribution position of the natural fracture zone of the section to be fractured and the volume of the sand carrying liquid corresponding to the brittleness index according to the corresponding relation of the distribution position of the natural fracture zone, the brittleness index and the volume of the sand carrying liquid;
determining the sand-carrying fluid displacement corresponding to the fracture toughness index of the section to be fractured according to the variation amplitude of the wellhead pressure during the hydraulic fracturing of the 1 st fracturing section, the average value of the wellhead pressure during the hydraulic fracturing of the 1 st fracturing section and the corresponding relation between the fracture toughness index and the sand-carrying fluid displacement;
determining the weight ratio of the small-particle-size proppant in the sand-carrying fluid corresponding to the Young modulus of the section to be fractured according to the corresponding relationship between the Young modulus and the weight ratio of the small-particle-size proppant in the sand-carrying fluid;
determining the development degree of the natural fracture zone of the section to be fractured, the bedding development degree of the rock stratum and the weight of the proppant in the sand carrying liquid corresponding to the weak surface development index of the rock mass according to the corresponding relation of the development degree of the natural fracture zone, the bedding development degree of the rock stratum and the development index of the rock mass;
determining the addition mode of the proppant in the sand carrying fluid and the concentration of the proppant in the sand carrying fluid corresponding to the complexity of the fracture network of the section to be fractured according to the corresponding relationship among the complexity of the fracture network, the addition mode of the proppant in the sand carrying fluid and the concentration of the proppant in the sand carrying fluid;
determining the concentration of the temporary plugging agent in the sand carrying liquid corresponding to the fracture extension and the steering index of the section to be fractured according to the corresponding relationship between the fracture extension and the steering index and the concentration of the temporary plugging agent in the sand carrying liquid;
determining the form of the temporary plugging agent in the sand carrying liquid corresponding to the Young modulus of the section to be fractured according to the corresponding relation between the Young modulus and the form of the temporary plugging agent in the sand carrying liquid;
and determining the volume of the displacement liquid corresponding to the brittleness index and the seam network complexity of the section to be fractured according to the corresponding relation of the brittleness index, the seam network complexity and the volume of the displacement liquid.
3. The determination method according to claim 2, wherein the determining the volume of the acid solution in the pad fluid corresponding to the carbonate mineral content of the to-be-fractured section according to the wellhead pressure drop before and after the pad fluid is injected into the 1 st fracturing section and the corresponding relationship between the carbonate mineral content and the volume of the acid solution in the pad fluid comprises:
when the content of carbonate minerals in the 1 st fracturing section is greater than or equal to a content threshold value, and the wellhead pressure drop before and after the 1 st fracturing section is injected with the pad fluid is greater than or equal to a wellhead pressure drop threshold value, if the content of the carbonate minerals in the to-be-fractured section is greater than or equal to the content threshold value, the volume of acid liquor in the pad fluid of the to-be-fractured section is equal to the volume of acid liquor in the pad fluid of the 1 st fracturing section; if the content of the carbonate minerals in the section to be fractured is smaller than the content threshold value, the volume of the acid liquor in the pad fluid of the section to be fractured is smaller than the volume of the acid liquor in the pad fluid of the 1 st fracturing section;
when the content of carbonate minerals in the 1 st fracturing section is greater than or equal to a content threshold value, and the wellhead pressure drop before and after the 1 st fracturing section is injected with the pad fluid is less than a wellhead pressure drop threshold value, if the content of the carbonate minerals in the to-be-fractured section is greater than or equal to the content threshold value, the volume of acid liquor in the pad fluid of the to-be-fractured section is greater than the volume of acid liquor in the pad fluid of the 1 st fracturing section; if the content of the carbonate minerals in the section to be fractured is smaller than the content threshold value, the volume of the acid liquor in the pad fluid of the section to be fractured is equal to the volume of the acid liquor in the pad fluid of the 1 st fracturing section;
when the content of carbonate minerals in the 1 st fracturing section is less than a content threshold value, and the wellhead pressure drop before and after the 1 st fracturing section is injected with the pad fluid is greater than or equal to a wellhead pressure drop threshold value, the volume of acid liquor in the pad fluid of the section to be fractured is equal to the volume of acid liquor in the pad fluid of the 1 st fracturing section;
and when the content of the carbonate minerals in the 1 st fracturing section is less than the content threshold value and the wellhead pressure drop before and after the 1 st fracturing section is injected with the pad fluid is less than the wellhead pressure drop threshold value, the volume of the acid liquid in the pad fluid of the section to be fractured is greater than that of the acid liquid in the pad fluid of the 1 st fracturing section.
4. The determination method according to claim 2 or 3, wherein the determining of the sand-carrying fluid displacement corresponding to the fracture toughness index of the to-be-fractured section according to the variation amplitude of the wellhead pressure during the hydraulic fracturing of the 1 st fractured section, the average value of the wellhead pressure during the hydraulic fracturing of the 1 st fractured section, and the corresponding relationship between the fracture toughness index and the sand-carrying fluid displacement comprises:
when the fracture toughness index of the 1 st fracturing section is greater than or equal to the fracture toughness index threshold value, the variation amplitude of wellhead pressure during hydraulic fracturing of the 1 st fracturing section is smaller than the amplitude threshold value, and the average value of the wellhead pressure during hydraulic fracturing of the 1 st fracturing section is smaller than the wellhead pressure threshold value, if the fracture toughness index of the section to be fractured is greater than or equal to the fracture toughness index threshold value, the sand carrying fluid displacement of the section to be fractured is equal to the sum of the sand carrying fluid displacement of the 1 st fracturing section and a first increasing value, and the first increasing value is greater than 0; if the fracture toughness index of the to-be-fractured section is smaller than the fracture toughness index threshold value, the displacement of the sand-carrying fluid of the to-be-fractured section is equal to that of the 1 st fracturing section;
when the fracture toughness index of the 1 st fracturing section is larger than or equal to the fracture toughness index threshold value, and the variation amplitude of wellhead pressure during hydraulic fracturing of the 1 st fracturing section is larger than or equal to the amplitude threshold value, the displacement of the sand carrying fluid of the section to be fractured is equal to that of the 1 st fracturing section;
when the fracture toughness index of the 1 st fracturing section is greater than or equal to the fracture toughness index threshold value, and the average value of wellhead pressure during hydraulic fracturing of the 1 st fracturing section is greater than or equal to the wellhead pressure threshold value, the sand-carrying fluid displacement of the section to be fractured is equal to that of the 1 st fracturing section;
when the fracture toughness index of the 1 st fracturing section is smaller than the fracture toughness index threshold value, the variation amplitude of wellhead pressure during hydraulic fracturing of the 1 st fracturing section is smaller than the amplitude threshold value, and the average value of the wellhead pressure during hydraulic fracturing of the 1 st fracturing section is smaller than the wellhead pressure threshold value, if the fracture toughness index of the section to be fractured is larger than or equal to the fracture toughness index threshold value, the sand-carrying fluid displacement of the section to be fractured is equal to the sum of the sand-carrying fluid displacement of the 1 st fracturing section and a second increase value, and the second increase value is larger than 0 and smaller than the first increase value; if the fracture toughness index of the to-be-fractured section is smaller than the fracture toughness index threshold value, the displacement of the sand-carrying fluid of the to-be-fractured section is equal to that of the 1 st fracturing section;
when the fracture toughness index of the 1 st fracturing section is smaller than the fracture toughness index threshold value and the variation amplitude of the wellhead pressure during hydraulic fracturing of the 1 st fracturing section is larger than or equal to the amplitude threshold value, the sand-carrying fluid displacement of the section to be fractured is smaller than that of the 1 st fracturing section;
when the fracture toughness index of the 1 st fracturing section is larger than or equal to the fracture toughness index threshold value, and the average value of wellhead pressure in hydraulic fracturing of the 1 st fracturing section is larger than or equal to the wellhead pressure threshold value, the sand-carrying fluid displacement of the section to be fractured is smaller than that of the 1 st fracturing section;
wherein the wellhead pressure threshold is equal to a product of a wellhead pressure bearing limit and a first percentage.
5. The determination method according to claim 2 or 3, wherein the determining the number of the clusters of perforations corresponding to the volume ratio of the gas in the set shape of the segment to be fractured according to the corresponding relationship between the volume ratio of the gas in the set shape and the number of the clusters of perforations in the clusters of perforations comprises:
when the free gas content ratio of the to-be-fractured section is greater than or equal to a free gas content ratio threshold value, or when the adsorption gas content ratio of the to-be-fractured section is less than or equal to an adsorption gas content ratio threshold value, the number of clusters of holes in the multiple clusters of perforations of the to-be-fractured section is equal;
when the free gas content ratio of the to-be-fractured section is smaller than the free gas content ratio threshold value, or when the adsorption gas content ratio of the to-be-fractured section is larger than the adsorption gas content ratio threshold value, the number of cluster holes on two sides in the multi-cluster perforation of the to-be-fractured section is smaller than the number of cluster holes in the middle;
and the sum of the free gas quantity ratio threshold value and the adsorption gas quantity ratio is equal to 1, j is more than or equal to 1 and less than or equal to N, j is an integer, and N is the number of fracturing sections in the well.
6. The determination method according to claim 2 or 3, wherein determining the pad fluid volume corresponding to the Young's modulus of the section to be fractured according to the corresponding relationship between the Young's modulus and the pad fluid volume comprises:
when the Young modulus of the section to be fractured is larger than or equal to the Young modulus threshold value, the front liquid volume of the section to be fractured is between a first set volume and a second set volume, and the second set volume is larger than the first set volume;
and when the Young modulus of the section to be fractured is smaller than the Young modulus threshold value, the front liquid volume of the section to be fractured is larger than the second set volume.
7. The determination method according to claim 2 or 3, wherein the determining of the pad fluid displacement corresponding to the fracture pressure of the to-be-fractured section according to the corresponding relationship between the fracture pressure and the pad fluid displacement comprises:
when fracture rupture pressure of the to-be-fractured section is greater than or equal to a rupture pressure threshold value, the displacement of the pad fluid of the to-be-fractured section is smaller than a first set displacement;
when the fracture rupture pressure of the section to be fractured is smaller than a fracture pressure threshold value, the displacement of the section to be fractured for injecting the pad fluid is between the first set displacement and a second set displacement, and the second set displacement is larger than the first set displacement;
wherein the burst pressure threshold is equal to the product of the wellhead pressure bearing limit and a second percentage.
8. The determination method according to claim 2 or 3, wherein the determining the distribution position of the natural fracture zone of the section to be fractured and the sand carrying fluid volume corresponding to the brittleness index according to the corresponding relation among the distribution position of the natural fracture zone, the brittleness index and the sand carrying fluid volume comprises the following steps:
when the shortest distance between the natural fracture zone of the section to be fractured and the shaft is smaller than a distance threshold value, the volume of the sand-carrying fluid of the section to be fractured is smaller than or equal to a third set volume;
when the shortest distance between the natural fracture zone of the section to be fractured and the shaft is greater than or equal to a distance threshold value, if the brittleness index of the section to be fractured is greater than or equal to a brittleness index threshold value, the volume of the sand carrying fluid of the section to be fractured is between a fourth set volume and a third set volume, and the third set volume is greater than the fourth set volume; and if the brittleness index of the section to be fractured is smaller than the brittleness index threshold value, the volume of the sand carrying liquid of the section to be fractured is larger than the third set volume.
9. The determination method according to claim 2 or 3, wherein determining the weight ratio of the small-particle size proppant in the sand-carrying fluid corresponding to the Young modulus of the section to be fractured according to the corresponding relationship between the Young modulus and the weight ratio of the small-particle size proppant in the sand-carrying fluid comprises:
when the Young modulus of the section to be fractured is greater than or equal to the Young modulus threshold value, the weight ratio of the small-particle-size proppant in the sand carrying fluid of the section to be fractured is greater than a first set proportion;
when the Young modulus of the section to be fractured is smaller than the Young modulus threshold value, the weight ratio of the small-particle-size proppant in the sand-carrying fluid of the section to be fractured is between a second set proportion and the first set proportion, and the second set proportion is smaller than the first set proportion.
10. The determination method according to claim 2 or 3, wherein the determining the weight of the proppant in the sand-carrying fluid corresponding to the natural fracture zone development degree, the rock stratum bedding development degree and the rock weak plane development index of the section to be fractured according to the corresponding relationship of the natural fracture zone development degree, the rock stratum bedding development degree, the rock weak plane development index and the weight of the proppant in the sand-carrying fluid comprises:
when the development degree of the natural fracture zone of the section to be fractured is greater than or equal to a natural fracture zone development degree threshold value, or when the formation bedding development degree of the section to be fractured is greater than or equal to a formation bedding development degree threshold value, or when the rock mass weak plane development index of the section to be fractured is greater than or equal to a rock mass weak plane development index threshold value, the weight of the propping agent in the sand carrying fluid of the section to be fractured is between a first set weight and a second set weight, and the second set weight is greater than the first set weight;
and when the development degree of the natural fracture zone of the section to be fractured is smaller than the development degree threshold of the natural fracture zone, the formation bedding development degree of the section to be fractured is smaller than the formation bedding development degree threshold, and the weak rock face development index of the section to be fractured is smaller than the weak rock face development index threshold, the weight of the propping agent in the sand carrying liquid of the section to be fractured is larger than the second set weight.
11. The determination method according to claim 2 or 3, wherein the determining the addition mode of the proppant in the sand-carrying fluid and the concentration of the proppant in the sand-carrying fluid corresponding to the fracture network complexity of the section to be fractured according to the corresponding relationship between the fracture network complexity and the addition mode of the proppant in the sand-carrying fluid and the concentration of the proppant in the sand-carrying fluid comprises:
when the complexity of the fracture network of the section to be fractured is greater than or equal to a fracture network complexity threshold value, adding a proppant in the sand carrying fluid of the section to be fractured in a slug type sand adding mode, wherein the concentration of the proppant of the section to be fractured is between a second set concentration and a first set concentration, and the second set concentration is smaller than the first set concentration;
and when the fracture network complexity of the section to be fractured is smaller than the fracture network complexity threshold value, the adding mode of the proppant in the sand carrying liquid of the section to be fractured adopts the combination of continuous sand adding and slug sand adding, and the proppant concentration of the section to be fractured is smaller than the second set concentration.
12. The determination method according to claim 2 or 3, wherein the determining the concentration of the temporary plugging agent in the sand carrying fluid corresponding to the fracture extension and the diversion index of the section to be fractured according to the corresponding relationship between the fracture extension and the diversion index and the concentration of the temporary plugging agent in the sand carrying fluid comprises:
when the fracture extension and steering index of the section to be fractured is larger than or equal to the fracture extension and steering index threshold value, the concentration of the temporary plugging agent in the sand-carrying fluid of the section to be fractured is equal to 0;
and when the fracture extension and steering index of the section to be fractured is smaller than the fracture extension and steering index threshold value, the concentration of the temporary plugging agent in the sand carrying liquid of the section to be fractured is larger than 0.
13. The determination method according to claim 2 or 3, wherein the determining the form of the temporary plugging agent in the sand-carrying fluid corresponding to the Young modulus of the section to be fractured according to the corresponding relationship between the Young modulus and the form of the temporary plugging agent in the sand-carrying fluid comprises:
when the Young modulus of the section to be fractured is greater than or equal to the Young modulus threshold value, the temporary plugging agent in the sand carrying liquid of the section to be fractured is in a powder form;
when the Young modulus of the section to be fractured is smaller than the Young modulus threshold value, the form of the temporary plugging agent in the sand carrying fluid of the section to be fractured comprises powder and particles, and the weight ratio of the powder is larger than or equal to a third set proportion.
14. The determination method according to claim 2 or 3, wherein the determining of the displacement fluid volume corresponding to the brittleness index and the seam-network complexity of the segment to be fractured according to the corresponding relationship of the brittleness index, the seam-network complexity and the displacement fluid volume comprises:
when the brittleness index of the section to be fractured is larger than or equal to the brittleness index threshold value and the fracture network complexity of the section to be fractured is larger than or equal to the fracture network complexity threshold value, the volume of the displacement liquid of the section to be fractured is equal to the volume of the shaft;
when the brittleness index of the section to be fractured is smaller than the brittleness index threshold value or when the fracture network complexity of the section to be fractured is smaller than the fracture network complexity threshold value, the volume of the displacement liquid of the section to be fractured is larger than the volume of the shaft.
15. The determination method according to any one of claims 1 to 3, wherein the obtaining of the geological parameters of the section to be fractured in the deep shale gas reservoir comprises:
obtaining a geological model of the deep shale gas reservoir, wherein the geological model comprises geological parameters of each region of the deep shale gas reservoir;
and acquiring the geological parameters of the section to be fractured according to the area of the section to be fractured in the deep shale gas reservoir.
16. The method for determining according to any one of claims 1 to 3, further comprising: acquiring unit volume gas quantity of the section to be fractured;
the method for acquiring the geological parameters of the section to be fractured in the deep shale gas reservoir comprises the following steps:
and when the gas volume per unit volume is greater than or equal to the gas volume threshold value, acquiring the geological parameters of the section to be fractured.
17. An apparatus for determining hydraulic fracturing parameters of a deep shale gas reservoir, the apparatus comprising:
the geological parameter acquisition module is used for acquiring geological parameters of a section to be fractured in the deep shale gas reservoir;
and the fracturing parameter determining module is used for determining the hydraulic fracturing parameters corresponding to the geological parameters of the section to be fractured according to the corresponding relation between the geological parameters and the hydraulic fracturing parameters, the value ranges of the hydraulic fracturing parameters corresponding to the geological parameters in different value ranges are different, and the determined hydraulic fracturing parameters are the construction parameters during hydraulic fracturing of the section to be fractured.
18. An apparatus for determining hydraulic fracturing parameters of a deep shale gas reservoir, the apparatus comprising: a memory and a processor, the memory and the processor being communicatively connected to each other, the memory storing computer instructions, and the processor executing the computer instructions to perform the method for determining deep shale gas reservoir hydraulic fracturing parameters as claimed in any one of claims 1 to 16.
19. A computer readable storage medium storing computer instructions for causing a computer to perform the method of determining deep shale gas reservoir hydraulic fracturing parameters of any of claims 1 to 16.
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