Combination mode and selection method of double-particle-size proppant for fracturing and filling of loose sandstone reservoir

Abstract

The invention discloses a loose sandstone reservoir fracturing filling double-particle-size proppant combination mode and a selection method. The selection method comprises the following steps that S1, reservoir geological parameters, production condition parameters and fracture geometric parameters are obtained, so that the flow rule and the flow mode of reservoir fluid in a reservoir-fracture dual-medium system are judged, and the key invasion blocking part of stratum sand to a fracture is judged according to the flow mode; s2, according to the flow mode determined in the step S1 and the key invasion and blockage part of the stratum sand to the crack, any one of the following dual-particle-size proppant combination modes (1)-(3) is selected: (1) the combination mode with the thick outer part and the thin inner part; 2) a thin-outside and thick-inside combined mode; and 3) a coarse and fine mixing combination mode. According to different reservoir conditions and fracture geometric dimensions, a corresponding and reasonable double-particle-size proppant combination mode can be quickly and conveniently selected, the problem of adaptability evaluation of different-particle-size combination modes on reservoirs and oil wells is solved, and it can be ensured that a novel combined filling mode can play potential and functions.

Description

Technical Field

[0001] The invention relates to a combination mode of double-particle-size proppants for fracturing and filling loose sandstone reservoirs and a selection method thereof, and belongs to the oil and natural gas mining industry. Background Art

[0002] Fracturing filling is a commonly used sand control and production enhancement technology for medium- and high-permeability loose sandstone oil and gas reservoirs prone to sand production. It uses hydraulic fracturing to form cracks in loose sandstone reservoirs and fills the cracks with solid granular materials such as conventional quartz sand or artificial ceramsite as proppant to form high conductivity cracks supported by proppant ( Figure 1 High-conductivity fractures become the main channels for reservoir fluid to flow into the wellbore, thus increasing production. At the same time, the solid particles filling the fractures act as sand barriers, thus preventing sand from forming.

[0003] After the fracturing and filling of medium- and high-permeability loose sandstone reservoirs prone to sand production is put into production, compared with the hydraulic fracturing of conventional low-permeability tight reservoirs and unconventional tight reservoirs, its special and different features are: (1) Since the formation is prone to sand production, the particle size of the proppant in the fracture needs to be reasonably designed to play a sand-blocking role while maintaining a high conductivity; (2) After the reservoir continues to produce sand after production, the sand produced by the formation will enter the fracture, causing blockage of the fracture filling layer and reduced conductivity; (3) From the perspective of the strength of medium- and high-permeability reservoirs, the phenomenon of fracture width loss caused by the embedding of proppant in the formation is more obvious; (4) The permeability of the medium- and high-permeability reservoir itself is relatively high. Although the fracture has high conductivity, the formation still plays a circulation role; that is, the fluid not only flows in the fracture, but also flows in the reservoir toward the wellbore at the same time (this is significantly different from the low-permeability reservoir). In view of the above-mentioned characteristics of fracturing and filling in medium- and high-permeability loose sandstone reservoirs and their special requirements for production increase and sand control, the optimization of fracturing and filling parameters in medium- and high-permeability loose sandstone oil and gas reservoirs prone to sand production is of great significance for achieving good sand control and production increase effects.

[0004] However, currently, the fracturing and filling technologies used in medium- and high-permeability loose sandstone reservoirs at home and abroad all use single-size proppant filling. For medium- and high-permeability reservoirs prone to sand production, single-size filling has the following problems in some reservoir conditions:

[0005] (1) For reservoirs with finer formation sand particle sizes, finer proppants are required to ensure good sand retention. However, finer proppants have lower permeability, especially after being clogged by formation sand. The permeability continues to decrease, restricting the productivity of oil and gas wells. Single-particle filling cannot achieve the ideal balance between sand retention and productivity under certain reservoir conditions, thus restricting both sand retention and production effectiveness.

[0006] (2) The permeability gradient of medium and high permeability reservoirs is wide. According to the different reservoir permeabilities and flow properties as well as the length of the fractures, the reservoir fluid will flow into the fractures in a variety of flow modes. Under different flow modes, the invasion and blockage of the formation sand into the fracture filling layer are different. The single particle size design is not conducive to reducing the invasion and maintaining the conductivity of the fracture. It is necessary to optimize the particle size combination according to different inflow modes.

[0007] (3) Currently, the three most commonly used fracturing proppant sizes for medium- and high-permeability reservoirs are 0.3-0.6mm, 0.4-0.8mm, and 0.6-1.2mm. For all fracturing proppant size optimization designs, only one of these three can be selected. However, the intervals between these three particle sizes are large, making it difficult to accurately match the formation sand particle size according to the optimization matching criteria. This can cause excessive intrusion blockage or loss of fluidity, restricting the effectiveness of fracturing to increase production and control sand. Summary of the Invention

[0008] The purpose of the present invention is to provide a dual-particle size proppant combination method and selection method for fracturing and filling loose sandstone reservoirs, aiming to overcome the limitations of the existing single filling particle size, reduce the invasion and blockage of the fracture filling layer and the damage to the permeability of the formation sand through the dual-particle size combination, reduce the flow resistance of the fracture, improve the comprehensive conductivity, and release the production capacity of the fracturing and filling oil and gas wells.

[0009] The present invention discloses three dual-particle size proppant combinations for fracturing and filling loose sandstone reservoirs. The purpose is to overcome the problem of excessive sand invasion and permeability damage caused by existing single-particle size filling under different reservoir conditions and fracture size conditions, thereby restricting production efficiency, through multiple dual-particle size combination filling methods.

[0010] The method disclosed in the present invention is to determine the key invasion and blockage locations of formation sand in a reservoir-fracture system of a fracturing filling well, and aims to determine the key invasion and blockage locations of formation sand in a reservoir-fracture system according to different reservoir conditions and fracture geometric dimensions.

[0011] The method for selecting a dual-particle-size proppant combination for fracturing and filling loose sandstone reservoirs disclosed in the present invention aims to further select a corresponding reasonable dual-particle-size proppant combination according to the key invasion and blockage locations of fractures by different formation sands, so as to improve the comprehensive effect of sand control and production increase through dual-particle-size proppant fracturing and filling.

[0012] The dual-particle-size proppant combination provided by the present invention is any one of the following 1)-3):

[0013] 1) Combination of fine outer and coarse inner double-size proppant

[0014] Fill the fractures with proppants of both coarse and fine particle sizes. The outer, coarse, and fine-particle proppant combination involves filling the outer fractures toward the reservoir with fine-particle proppant, and filling the fractures toward the wellbore with coarse-particle proppant, forming a fine-outer, coarse-inner proppant combination.

[0015] 2) Coarse outer and fine inner dual-size proppant combination

[0016] The outer coarse and inner fine dual-size proppant combination is to fill the outer fracture part of the fracture toward the reservoir with coarse-size proppant, and fill the fracture close to the wellbore with fine-size proppant, thus forming an outer coarse and inner fine proppant combination.

[0017] 3) Coarse and fine mixed dual particle size proppant combination

[0018] The coarse and fine mixed dual particle size proppant combination method refers to mixing coarse and fine particle size proppant to fill the entire fracture.

[0019] The method for selecting a dual-size proppant combination for fracturing and filling loose sandstone reservoirs provided by the present invention comprises the following steps:

[0020] S1. Obtaining reservoir geological parameters, production condition parameters, and fracture geometry parameters to determine the flow pattern and flow pattern of the reservoir fluid in the reservoir-fracture dual medium system, and determining the key locations of fracture blockage caused by formation sand intrusion based on the flow pattern;

[0021] S2. Select a dual-size proppant combination mode based on the flow pattern determined in step S1 and the key blockage location of the fracture by formation sand.

[0022] In the selection method of the present invention, step S1 includes the following steps:

[0023] A) obtaining reservoir geological parameters, production parameters, and fracture scale parameters, and thereby obtaining flow pattern characteristic indicators;

[0024] B) judging the reservoir-fracture fluid flow pattern and the key invasion locations of formation sand into the fractures based on the flow pattern characteristic indicators.

[0025] In the selection method of the present invention, in step A), the reservoir condition geological parameters include reservoir thickness h and reservoir permeability kf, which can be directly obtained as basic data;

[0026] The production condition parameters include the fluid production Ql of the oil well after fracturing and the crude oil viscosity Ul. The fluid production after fracturing is obtained by preliminary fracturing effect prediction, and the crude oil viscosity is directly obtained as basic data;

[0027] The fracture scale parameters include single-wing fracture length Lf, fracture height Hf and average fracture width Wf, which are obtained from the early stage of fracturing and filling scale optimization design.

[0028] In the selection method of the present invention, in step A), the fracture shape characteristic coefficient, the reservoir and fracture transformation matching characteristic coefficient and the production condition characteristic coefficient are obtained according to the reservoir condition geological parameters, the production condition parameters and the fracture scale parameters, and then the flow pattern characteristic index is obtained.

[0029] In the selection method of the present invention, the crack shape characteristic coefficient is obtained according to formula (1):

[0030]

[0031] According to formula (2), the matching characteristic coefficient between the reservoir and the fracture transformation is obtained:

[0032]

[0033] According to formula (3), the production condition characteristic coefficient is obtained:

[0034]

[0035] According to formula (4), the flow pattern characteristic index is obtained:

[0036]

[0037] Where R is the characteristic index of the flow pattern, dimensionless; A is the correction coefficient of the characteristic index of the flow pattern, dimensionless; S f is the characteristic parameter of crack shape, dimensionless; G f is the matching coefficient between reservoir and fracture transformation, dimensionless; D f is the characteristic coefficient of production conditions, dimensionless; W f , L f and H f are the crack width, length and height, in cm, m, m respectively; W ref , L ref , H ref They are the characteristic fracture width, length and height, which are generally the maximum fracture values ​​of the block where the oil well is located, with units of cm, m, and m respectively; h is the reservoir thickness, m; h re is the characteristic reservoir thickness, m, which is generally taken as the maximum reservoir thickness in the block where the oil well is located; k f represents the reservoir permeability, mD; k t Fracture filling permeability, mD; U l is the reservoir fluid viscosity, mPa·s; U relCharacteristic reservoir fluid viscosity, mPa·s, generally taken as the viscosity at room temperature 25°C; Q l is the reservoir fluid production, m 3 / h;Q rel Characteristic reservoir fluid production, m 3 / h, generally the maximum liquid production of the oil well is taken.

[0038] In the selection method of the present invention, in step S2, the flow pattern includes any one of the following:

[0039] Mode A: The flow pattern is dominated by converging flow toward the root of the fracture, with the root of the fracture as the key invasion and blockage site of formation sand;

[0040] Mode B: The flow pattern is dominated by converging flow toward the end of the fracture, with the end of the fracture as the key invasion and blockage site of formation sand;

[0041] Mode C: The flow mode is dominated by uniform convergence flow toward the fracture, and the formation sand invades the fracture relatively uniformly.

[0042] Preferably, the discrimination between mode A and mode C is achieved through the following a)-c):

[0043] a) If the flow pattern characteristic index is ≤0.3, it is determined to be the flow pattern A;

[0044] b) if the flow pattern characteristic index is ≥0.6, it is determined to be the flow pattern B;

[0045] c) The remaining cases are determined as Mode C.

[0046] More preferably, the discrimination between mode A and mode C is achieved through the following a1)-c1):

[0047] a1) when the fracture shape characteristic coefficient is ≤0.15, the reservoir and fracture reconstruction matching characteristic coefficient is ≤0.2, the production condition characteristic coefficient is ≤0.2, and the flow pattern characteristic index correction coefficient is 50, it is determined to be the said mode A;

[0048] b1) when the fracture shape characteristic coefficient is ≥0.3, the reservoir and fracture reconstruction matching characteristic coefficient is ≥0.4, the production condition characteristic coefficient is ≥0.4, and the flow pattern characteristic index correction coefficient is 12.5, it is determined to be the said mode B;

[0049] c1) When the fracture shape characteristic coefficient, the reservoir and fracture reconstruction matching characteristic coefficient, and the production condition characteristic coefficient do not meet a) and b), it is determined to be the mode C.

[0050] In mode A, reservoir fluid flows toward the wellbore and high-conductivity fractures, primarily converging toward the fracture roots near the wellbore. In this flow pattern, because the reservoir fluid carries sand from the formation, the fracture roots or the fracture root segments close to the wellbore are the primary locations for sand to invade and block the fractures.

[0051] In mode B, reservoir fluid flows toward the wellbore and high-conductivity fractures, primarily converging toward the reservoir at the fracture ends. In this flow pattern, because the reservoir fluid carries sand from the formation, the fracture ends or sections near them are the primary locations where sand invades and blocks the fractures.

[0052] In Mode C, reservoir fluid flows toward the wellbore and high-conductivity fractures, with a flow pattern similar to the bilinear flow pattern observed after hydraulic fracturing of a low-permeability reservoir. The flow of reservoir fluid into the fractures is primarily uniform and convergent. In this flow pattern, because the reservoir fluid carries sand from the formation, the produced sand is distributed more evenly toward the areas where the fractures have invaded and become blocked.

[0053] In the selection method of the present invention, a reasonable dual-particle-size proppant combination pattern is selected based on the key invasion locations of the formation sand into the fracture filling layer, so as to give full play to the potential and effect of the dual-particle-size combination filling method in reducing sand invasion and conductivity loss:

[0054] When the flow pattern is pattern A, the combination method in step S2 1) is selected;

[0055] When the flow pattern is pattern B, selecting the combination mode in step S2 2);

[0056] When the flow mode is mode C, the combination mode in step S2 3) or the conventional single particle size filling mode is selected.

[0057] Specifically, when the flow mode is mode C, the filling mode is determined according to the following I) or II):

[0058] Ⅰ) If the median particle size of the formation sand is within the range of 0.075-0.09, 0.1-0.12 or 0.15-0.18, then the single particle size filling mode is selected;

[0059] II) If the median particle size of the formation sand is within the range of 0.09-0.1 mm or 0.12-0.15 mm, the combination method in step S2 3) is selected.

[0060] The present invention has the following beneficial technical effects:

[0061] (1) Based on the traditional single-particle filling method for unconsolidated sandstone reservoir fracturing, this invention innovatively proposes multiple dual-particle combination filling methods. By combining different coarse and fine particle proppants, this method overcomes the problems of excessive sand invasion and permeability damage caused by existing single-particle filling, which in turn restricts productivity. For some reservoirs that meet the requirements, it can further reduce fracture flow resistance and improve productivity.

[0062] (2) The present invention proposes a method for selecting a dual-particle proppant combination for fracturing and filling loose sandstone reservoirs based on different particle size combinations. This method allows for rapid and convenient selection of a suitable dual-particle proppant combination based on different reservoir conditions and fracture geometry. This method addresses the issue of evaluating the adaptability of different particle size combinations to reservoirs and oil wells, ensuring that the new combination filling method can realize its potential and effectiveness. BRIEF DESCRIPTION OF THE DRAWINGS

[0063] Figure 1 Schematic diagram of conventional single-size proppant fracturing filling.

[0064] Figure 2 The schematic diagram shows the principle of three dual-size proppant combination modes.

[0065] Figure 3 Schematic diagram of reservoir-fracture flow mode A—converging flow at the fracture root.

[0066] Figure 4 Schematic diagram of reservoir-fracture flow mode B—converging flow at the fracture end.

[0067] Figure 5 Schematic diagram of reservoir-fracture flow mode C—uniform converging flow in fractures.

[0068] Figure 6 The diagrams are the matching principles of three dual-particle size combination modes and reservoir-fracture flow modes, among which Figure a is the combination of root invasion and outer coarse and inner fine, Figure b is the combination of end invasion and outer fine and inner coarse, and Figure c is the uniform invasion and coarse and fine mixed combination. DETAILED DESCRIPTION

[0069] Unless otherwise specified, the experimental methods used in the following examples are conventional methods.

[0070] Unless otherwise specified, the materials and reagents used in the following examples can be obtained from commercial sources.

[0071] The dual-particle proppant combinations provided by this invention for fracturing unconsolidated sandstone reservoirs include three specific particle size combinations: fine outside and coarse inside, coarse outside and fine inside, and a mixture of coarse and fine. This approach aims to adapt to diverse reservoir and production conditions by combining coarse and fine proppants, overcoming the problems of excessive sand invasion and permeability loss caused by existing single-particle proppant packing, which in turn limits productivity.

[0072] The present invention provides a method for identifying the key invasion and blockage locations of fractures in a reservoir-fracture system of a fracturing filling well. First, the flow law and flow pattern of the reservoir fluid in the reservoir-fracture dual medium system are determined based on parameters such as reservoir thickness, original permeability, sand production severity, fracture geometry and scale, and production conditions. That is, the main mode of fluid flow into the fracture and the key inflow location ( Figure 3 、 Figure 4 and Figure 5 ); Determine the key areas of fracture blockage caused by formation sand based on the flow pattern, and use it to optimize the subsequent dual-size proppant combination mode.

[0073] The method for selecting a dual-particle proppant combination for fracturing and filling of loose sandstone reservoirs provided by the present invention is mainly based on the flow pattern of reservoir fluid in the reservoir-fracture dual medium system of the fracturing filling well and the key invasion and blocking position of the formation sand on the fracture, and according to the principle of using fine particle size in the key invasion position of the formation sand and coarse particle size in the non-key invasion position, a reasonable dual-particle proppant combination mode is selected ( Figure 6 ). This will give full play to the potential and role of the dual-size combined filling method in reducing sand invasion and conductivity loss.

[0074] 1. Three dual-size proppant combinations for fracturing and filling loose sandstone reservoirs

[0075] 1) Combination of fine outer and coarse inner double-size proppant

[0076] Fill the cracks with proppants of coarse and fine particle sizes. Figure 2 As shown in the upper middle figure, the dual-size proppant combination of fine outside and coarse inside is to fill the outer fracture part of the fracture toward the reservoir with fine-size proppant, and fill the fracture close to the wellbore with coarse-size proppant, forming a proppant combination of fine outside and coarse inside.

[0077] 2) Coarse outer and fine inner dual-size proppant combination

[0078] like Figure 2 As shown in the middle figure in the figure, the combination of dual-size proppants with coarse outside and fine inside is to fill the outer crack part of the crack toward the reservoir with coarse-size proppant, and fill the crack close to the wellbore with fine-size proppant, forming a proppant combination with coarse outside and fine inside.

[0079] 3) Coarse and fine mixed dual particle size proppant combination

[0080] like Figure 2 As shown in the lower figure, the coarse and fine mixed dual-particle proppant combination method refers to mixing coarse and fine particle proppant to fill the entire fracture.

[0081] 2. Method for determining the key invasion and blockage locations of formation sand in fractures in reservoir-fracture system of fracture filling wells

[0082] (1) Obtain key parameters such as reservoir geology, production conditions, and fracture size

[0083] The required reservoir condition parameters mainly include reservoir thickness h and reservoir permeability kf, which can be directly obtained as basic data.

[0084] The required production condition parameters include the post-fracture fluid production Ql and crude oil viscosity Ul. The post-fracture fluid production is obtained from the preliminary fracturing effect prediction, and the crude oil viscosity is directly obtained as basic data.

[0085] The required fracture scale parameters mainly include single-wing fracture length Lf, fracture height Hf and average fracture width Wf. These data are obtained from the early fracturing filling scale optimization design.

[0086] (2) Calculate flow pattern characteristic indicators based on key parameters such as reservoir geology, production conditions, and fracture scale

[0087] According to the principles of seepage mechanics and hydraulic fracturing, in a reservoir-fracture dual-medium system, the pattern of reservoir fluid flow toward the well is related to conditions such as formation permeability, fracture filling permeability, reservoir thickness, and fracture length.

[0088] The crack shape characteristic coefficient is proposed:

[0089]

[0090] Reservoir and fracture transformation matching characteristic coefficient:

[0091]

[0092] Production condition characteristic coefficient:

[0093]

[0094] Flow pattern characteristic indicators:

[0095]

[0096] Where R is the characteristic index of the flow pattern, dimensionless; A is the correction coefficient of the characteristic index of the flow pattern, dimensionless; S f is the characteristic parameter of crack shape, dimensionless; G f is the matching coefficient between reservoir and fracture transformation, dimensionless; D f W is the characteristic coefficient of production conditions, dimensionless. f , L f and H fare the crack width, length and height, in cm, m, m respectively; W ref , L ref , H ref They are the characteristic fracture width, length and height, which are generally the maximum fracture values ​​of the block where the oil well is located, with units of cm, m, and m respectively; h is the reservoir thickness, m; h re is the characteristic reservoir thickness, m, which is generally taken as the maximum reservoir thickness in the block where the oil well is located. f represents the reservoir permeability, mD; k t Fracture filling permeability, mD; U l is the reservoir fluid viscosity, mPa·s; U rel Characteristic reservoir fluid viscosity, mPa·s, generally taken as the viscosity at room temperature 25°C; Q l is the reservoir fluid production, m 3 / h;Q rel Characteristic reservoir fluid production, m 3 / h, generally the maximum liquid production of the oil well is taken.

[0097] (3) Determine the reservoir-fracture fluid flow pattern and the key invasion locations of formation sand into fractures based on the flow pattern characteristic indicators

[0098] The present invention classifies the reservoir fluid into the well flow pattern and the corresponding formation sand into the key invasion and blockage position of the fracture into the following three types:

[0099] A) Mode A: The flow pattern is mainly convergent flow toward the root of the fracture, with the root of the fracture as the key invasion and blockage site of formation sand.

[0100] In this mode, the reservoir fluid flows toward the wellbore and high conductivity fractures, and the flow direction is mainly convergent flow toward the root of the fracture near the wellbore ( Figure 3 In this flow mode, the reservoir fluid carries sand from the formation, and the key location for the formation produced sand to invade and block the fracture is the fracture root or the fracture root section close to the wellbore ( Figure 3 ).

[0101] Under the combined conditions of higher formation permeability compared to fracture filling permeability, thinner reservoir thickness, and shorter fracture length, the reservoir fluid tends to flow toward the well in mode A.

[0102] The specific judgment conditions are: when S f ≤0.15, G f ≤0.2, D f When ≤0.2, A is taken as 50, and the required R is ≤0.3.

[0103] B) Mode B: Flow pattern where the flow mainly converges toward the end of the fracture, and the end of the fracture is the focus of formation sand invasion and blockage.

[0104] In this mode, the reservoir fluid flows toward the wellbore and high conductivity fractures, and the flow direction is mainly convergent flow at the end of the fracture toward the reservoir ( Figure 4 In this flow mode, since the reservoir fluid flows and carries the formation sand, the key location for the formation sand to invade and block the fracture is the end of the fracture or the fracture section close to the end of the fracture ( Figure 4 ).

[0105] Under the combined conditions that the lower the formation permeability is compared to the fracture filling permeability, the thicker the reservoir thickness is, and the longer the fracture length is, the more the reservoir fluid tends to flow toward the well in mode B.

[0106] The judgment condition is: when S f ≥0.3, G f ≥0.4, D f ≥0.4, A is 12.5, and the required R is ≥0.6

[0107] C) Mode C: Flow pattern in which uniform converging flow is dominant toward the fractures and formation sand relatively uniformly intrudes into the fractures

[0108] In this mode, the reservoir fluid flows toward the wellbore and high conductivity fractures. The flow pattern is similar to the bilinear flow pattern after the hydraulic fracturing transformation of the low permeability reservoir is put into production. The flow of the reservoir fluid toward the fracture is mainly uniform convergence flow ( Figure 5 In this flow mode, the reservoir fluid flows and carries out sand production from the formation, and the sand produced from the formation is distributed more evenly to the locations where the fractures invade and become blocked ( Figure 4 ).

[0109] Under comprehensive conditions such as relatively homogeneous formation and uniform reservoir thickness, the reservoir fluid tends to flow toward the well in mode C.

[0110] The judgment conditions are: S f , G f 、D f It does not meet the conditions for distinguishing modes A and B and is judged to be uniform flow mode C. In summary, the judgment of reservoir fluid flow mode is summarized in Table 1 below.

[0111] Table 1 Identification of reservoir fluid flow patterns

[0112]

[0113] Using the method of the present invention and the parameters in Table 2, it is calculated that R is equal to 1.1, which belongs to the end flow of the mode B fluid.

[0114] Table 2 Parameters of flow mode B

[0115]

[0116] 3. Selection method of dual-size proppant combination for fracturing and filling of loose sandstone reservoirs

[0117] Based on the key areas of formation sand intrusion into the fracture filling layer, a reasonable dual-particle size proppant combination pattern is selected to fully utilize the potential and effect of the dual-particle size combination filling method in reducing sand invasion and conductivity loss. The specific method for selecting the coarse and fine particle size combination is as follows:

[0118] (1) In mode A, select the outer coarse and inner fine dual particle size combination mode ( Figure 6 (Figure a in the middle).

[0119] (2) In the case of mode B, select the outer fine and inner coarse dual particle size combination mode ( Figure 6 (middle panel b).

[0120] (3) In mode C, select coarse and fine mixing or conventional single particle size filling mode ( Figure 6 The following are the specific principles and methods for selecting these two modes.

[0121] The rationale behind the selection of these two modes is that, based on the principle that formation sand is blocked by the gravel layer / proppant, achieving good sand retention and flow performance requires the median size of the proppant or gravel to be 5-6 times the median size of the formation sand. However, proppant particle sizes commonly used in oil and gas fields are 0.3-0.6 mm (median approximately 0.45 mm), 0.4-0.8 mm (median approximately 0.6 mm), and 0.6-1.2 mm (median approximately 0.9 mm). Based on the aforementioned 5-6 times principle, the three particle sizes accommodate and cover a certain range of median formation sand sizes. Therefore, if the median formation sand size falls within the range of median sizes that can be covered by the three proppant sizes described above according to the optimal matching principle, conventional single-particle packing is selected; otherwise, a mixed coarse and fine dual-particle packing mode is required.

[0122] According to the above principles, the specific selection method is as follows:

[0123] A) If the median formation sand particle size is in the range of 0.075-0.09, 0.1-0.12, or 0.15-0.18, select the single particle size filling mode;

[0124] B) If the median particle size of the formation sand is within the range of 0.09-0.1mm or 0.12-0.15mm, the coarse and fine mixed dual particle size filling mode is selected.

Claims

1. A method for selecting a dual-size proppant combination for fracturing and filling loose sandstone reservoirs, comprising the following steps: S1. Obtaining reservoir geological parameters, production condition parameters, and fracture geometry parameters to determine the flow pattern and flow pattern of the reservoir fluid in the reservoir-fracture dual medium system, and determining the key locations of fracture blockage caused by formation sand intrusion based on the flow pattern; S2. According to the flow pattern determined in step S1 and the key blockage location of the fracture by formation sand, select any one of the following dual-particle-size proppant combination patterns 1) to 3): 1) Coarse-outer-fine-inner combination mode: The outer area of ​​the fracture near the reservoir is filled with coarse-grained proppant, and the inner area near the wellbore is filled with fine-grained proppant; 2) Fine-outer and coarse-inner combination mode: the fracture area near the reservoir is filled with fine-grained proppant, and the area near the wellbore is filled with coarse-grained proppant; 3) Coarse-fine mixed combination mode: Coarse-grained proppant and fine-grained proppant are evenly mixed and filled in the entire fracture space.

2. The selection method according to claim 1, wherein: Step S1 includes the following steps: A) obtaining reservoir geological parameters, production parameters, and fracture scale parameters, and thereby obtaining flow pattern characteristic indicators; B) judging the reservoir-fracture fluid flow pattern and the key invasion locations of formation sand into the fractures based on the flow pattern characteristic indicators.

3. The selection method according to claim 2, wherein: In step A), the reservoir geological parameters include reservoir thickness h and reservoir permeability kf; The production condition parameters include the fluid production Ql and crude oil viscosity Ul after oil well fracturing; The crack scale parameters include single-wing crack length Lf, crack height Hf and average crack width Wf.

4. The selection method according to claim 2 or 3, characterized in that: In step A), the fracture shape characteristic coefficient, the reservoir and fracture transformation matching characteristic coefficient and the production condition characteristic coefficient are obtained according to the reservoir condition geological parameters, the production condition parameters and the fracture scale parameters, and then the flow pattern characteristic index is obtained.

5. The selection method according to claim 4, characterized in that: The crack shape characteristic coefficient is obtained according to formula (1): According to formula (2), the matching characteristic coefficient between the reservoir and fracture transformation is obtained: According to formula (3), the production condition characteristic coefficient is obtained: According to formula (4), the flow pattern characteristic index is obtained: Where R is the characteristic index of the flow pattern, dimensionless; A is the correction coefficient of the characteristic index of the flow pattern, dimensionless; S f is the characteristic parameter of crack shape, dimensionless; G f is the matching coefficient between reservoir and fracture transformation, dimensionless; D f is the characteristic coefficient of production conditions, dimensionless; W f , L f and H f are the crack width, length and height, in cm, m, m respectively; W ref , L ref , H ref are the characteristic fracture width, length and height, in cm, m, m respectively; h is the reservoir thickness, m; h re is the characteristic reservoir thickness, m; k f represents the reservoir permeability, mD; k t Fracture filling permeability, mD; U l is the reservoir fluid viscosity, mPa·s; U rel Characteristic reservoir fluid viscosity, mPa·s; Q l is the reservoir fluid production, m 3 / h;Q rel Characteristic reservoir fluid production, m 3 / h.

6. The selection method according to any one of claims 1 to 5, characterized in that: In step S2, the flow mode includes any of the following: Mode A: The flow pattern is dominated by converging flow toward the root of the fracture, with the root of the fracture as the key invasion and blockage site of formation sand; Mode B: The flow pattern is dominated by converging flow toward the end of the fracture, with the end of the fracture as the key invasion and blockage site of formation sand; Mode C: The flow mode is dominated by uniform convergence flow toward the fracture, and the formation sand invades the fracture relatively uniformly.

7. The selection method according to claim 6, characterized in that: The discrimination between mode A and mode C is achieved through the following a)-c): a) If the flow pattern characteristic index is ≤0.3, it is determined to be the flow pattern A; b) if the flow pattern characteristic index is ≥0.6, it is determined to be the flow pattern B; c) The remaining cases are determined as Mode C.

8. The selection method according to claim 7, characterized in that: The discrimination between mode A and mode C is achieved through the following steps a1)-c1): a1) when the fracture shape characteristic coefficient is ≤0.15, the reservoir and fracture reconstruction matching characteristic coefficient is ≤0.2, the production condition characteristic coefficient is ≤0.2, and the flow pattern characteristic index correction coefficient is 50, it is determined to be the said mode A; b1) when the fracture shape characteristic coefficient is ≥0.3, the reservoir and fracture reconstruction matching characteristic coefficient is ≥0.4, the production condition characteristic coefficient is ≥0.4, and the flow pattern characteristic index correction coefficient is 12.5, it is determined to be the said mode B; c1) When the fracture shape characteristic coefficient, the reservoir and fracture reconstruction matching characteristic coefficient, and the production condition characteristic coefficient do not meet a) and b), it is determined to be the mode C.

9. The selection method according to any one of claims 6 to 8, characterized in that: When the flow pattern is pattern A, the combination method in step S2 1) is selected; When the flow pattern is pattern B, selecting the combination mode in step S2 2); When the flow mode is mode C, the combination mode in step S2 3) or the conventional single particle size filling mode is selected.

10. The selection method according to claim 9, characterized in that: When the flow mode is mode C, the filling mode is determined according to the following I) or II): Ⅰ) If the median particle size of the formation sand is within the range of 0.075-0.09, 0.1-0.12 or 0.15-0.18, then the single particle size filling mode is selected; II) If the median particle size of the formation sand is within the range of 0.09-0.1 mm or 0.12-0.15 mm, the combination method in step S2 3) is selected.

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