A method for optimizing the design of dual-size proppant combination parameters for fracturing and filling of loose sandstone reservoirs

Abstract

The present invention belongs to the oil and gas extraction industry, and specifically relates to a method for optimizing the design of dual-particle-size proppant combination parameters for fracturing and filling loose sandstone reservoirs. According to reservoir and oil well conditions, and corresponding dual-particle-size combination methods, specific proppant parameters such as filling particle size, filling seam length ratio, and filling sequence are optimized and designed, ultimately achieving the comprehensive effects of effectively blocking sand while reducing the invasion and blockage of formation sand into the fracture filling layer and the damage to permeability, reducing fracture flow resistance, improving comprehensive conductivity, and releasing oil and gas well production capacity.

Description

Technical Field

[0001] The invention belongs to the oil and gas mining industry, and in particular relates to a method for optimizing the design of combined parameters of dual-size proppants for fracturing and filling loose sandstone reservoirs. 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 proppants to form high-conductivity cracks supported by proppants (such as Figure 1 High-conductivity fractures become the main channels for reservoir fluid to flow into the wellbore, increasing production. At the same time, the solid particles filling the fractures act as sand barriers, providing a sand control function.

[0003] Traditional proppant injection for fracturing medium- and high-permeability reservoirs is primarily based on artificial ceramsite in offshore oilfields, while conventional quartz sand is more commonly used in onshore oilfields, with artificial ceramsite being less common. Generally, a single particle size is used for fracturing injection in the same well. Currently, the three main proppant sizes used in the field are 0.3-0.6mm, 0.4-0.8mm, and 0.6-1.2mm.

[0004] Since loose sandstones with medium and high permeability are prone to sand production, the design and implementation of reservoir fracturing and filling require that the proppant in the fractures have a sand retaining function that can effectively block the formation sand that invades the fractures; at the same time, the formation sand that invades the fractures will cause blockage and loss of fracture conductivity, affecting production capacity. Therefore, for the fracturing and filling of loose sandstones with medium and high permeability, it is required to ensure both the sand retaining capacity and the fracture conductivity (this is quite different from the low permeability reservoir that only requires the conductivity to be maintained without sand production). Since the current single particle size proppant is difficult to meet the above requirements under some reservoir conditions, a dual particle size proppant combination filling mode has emerged, mainly including three modes: fine outside and coarse inside, coarse outside and fine inside, and coarse and fine mixed (such as Figure 2 shown).

[0005] At present, when fracturing and filling medium- and high-permeability loose sandstone reservoirs with dual-size proppant combination filling, although the above three combination modes can be adopted, their specific design and implementation have the following key problems:

[0006] (1) Currently, there is a lack of methods for designing the specific sizes of coarse and fine particle proppants for the three coarse and fine particle size combinations. Designing based on experience is difficult to fully consider the reservoir geological conditions and production conditions to ensure sand control and production increase effects. Therefore, there is an urgent need for a fast and simple method that can design and select the specific particle sizes of coarse and fine proppants based on the formation sand particle size and characteristic parameters to improve the sand control and production increase effects of the dual-size proppant combination fracturing and filling process.

[0007] (2) Currently, there is a lack of design methods for the filling length (ratio) and specific filling amount of coarse and fine particle proppants in fractures. 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 invade and block the fractures in various flow modes, mainly at the toe of the fracture, mainly at the root of the fracture, or mainly at uniform invasion. Under different flow modes, the invasion and blocking form of formation sand on the fracture filling layer is different. It is urgent to design the filling position of coarse and fine particle sizes in the fractures and the corresponding filling section length and filling amount according to the key invasion parts and forms, so as to give full play to the respective functions of coarse and fine particle proppants and give full play to the sand control and production increase effects of the dual particle size combination fracturing filling process technology.

[0008] (3) Currently, the 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. Therefore, the optimal design of the fracturing fill particle size can only select one of these three. However, the intervals between these three particle sizes are large, making it difficult to accurately match the formation sand particle size according to the optimal 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

[0009] The present invention proposes a method for optimizing the design of dual-particle proppant combination parameters for fracturing and filling of loose sandstone reservoirs, which aims to optimize the specific parameters of proppants such as filling particle size, filling seam length ratio, and filling order according to the reservoir, oil well conditions and the corresponding dual-particle size combination method, so as to ultimately achieve the comprehensive effect of effectively blocking sand while reducing the invasion and blockage of formation sand on the fracture filling layer and the damage to permeability, reducing the flow resistance of the fracture, improving the comprehensive conductivity, and releasing the production capacity of oil and gas wells. Among them, the purpose of optimizing the filling length ratio and filling amount of dual-particle proppants is to design corresponding coarse and fine proppants to fill the fracture positions according to the key invasion and blockage positions of formation sand on the fracture, so as to achieve a balance between overall sand blocking and diversion in the fracture, and ensure that the combined filling technology of coarse and fine particle proppants can play its potential and role, and improve the sand control and production increase effect. The purpose of the dual-size proppant particle size optimization design for fracturing and filling wells is to design the particle size according to the particle size characteristics of the formation sand, so as to ensure that the ratio of the particle size of the fracturing and filling proppant to the particle size of the formation sand is always in the optimal range, which can not only ensure the sand retaining effect, but also avoid the damage to the fracture conductivity and production capacity caused by excessive intrusion of formation sand.

[0010] The present invention provides a method for optimizing the design of dual-size proppant combination parameters for fracturing and filling loose sandstone reservoirs, comprising:

[0011] S1. Calculate the invasion site discrimination characteristic index:

[0012] First, the severity of sand production is evaluated according to formation parameters and production conditions; then the characteristic coefficient of fracture invasion position of fracturing filling formation sand is calculated (Fracture Sand Invasion, F SI index).

[0013] S2. Optimize the filling sequence and fracture length ratio of dual-size proppants in fracture filling wells:

[0014] According to the F calculated in step S1 SI The index divides the blockage area of formation sand invasion into the fracture into the slightly invaded area and the severely invaded area, thereby distinguishing the flow pattern of reservoir fluid and formation sand into the fracture;

[0015] According to the F calculated in step S1 SI The filling order of coarse-grained proppant and fine-grained proppant and the ratio of fracture length are obtained by using the index.

[0016] Preferably, the volume usage of the coarse and fine proppants can be calculated based on the ratio of the filling length of the coarse-grained proppant to the fine-grained proppant and the fracture geometric parameters.

[0017] S3. Optimize the coarse and fine particle size of the dual-size proppant combination for fracturing and filling wells:

[0018] According to the severity of formation sand production, the median particle size of the formation sand and the uniformity coefficient, the design value of the median particle size of the fine-grained proppant is calculated, thereby optimizing the design of the proppant particle size.

[0019] In step S1, the formation parameters include reservoir thickness, original permeability, and fracture scale geometry.

[0020] In step S2, the severely invaded area refers to the area where the reservoir fluid and formation sand flow into the fracture unevenly, the inflow velocity is relatively high, the formation sand invades quickly, and the filling proppant blocks the fracture more seriously. The length of the area in the fracture is recorded as L. fa .

[0021] The slightly invaded area refers to the area where the reservoir fluid and formation sand flow unevenly into the fracture, the inflow velocity is relatively low, the formation sand invades slowly, and the blockage of the filling proppant is relatively weak. The length of the area in the fracture is recorded as L. fb .

[0022] According to reservoir geological conditions, fracture geometry parameters and conductivity, production conditions and other characteristics, there are two modes for the relative positions of slightly invaded areas and severely invaded areas:

[0023] Mode A: As attached Figure 3 As shown, the area near the crack toe is the severe invasion area, and the area near the crack root is the slight invasion area;

[0024] Mode B: As attached Figure 4 As shown, the area near the crack root is the severe invasion area, and the area near the crack toe is the slight invasion area.

[0025] The scientific rationale and basis for the above-mentioned invasion zone classification is that the high permeability and conductivity of the fracture filling (the product of fracture width and filling permeability) facilitate the flow of reservoir fluids within the fractures. Unlike low-permeability reservoirs, where the reservoir permeability is extremely low and reservoir flow primarily enters the fractures via a bilinear flow pattern, medium- and high-permeability loose sandstone reservoirs inherently have high permeability, and fluids possess a certain degree of flow capacity within the reservoir. Therefore, within the fracture-reservoir flow system of medium- and high-permeability loose sandstone, reservoir fluids closer to the fracture flow into the fracture, while some fluids farther from the fracture flow through the reservoir toward the wellbore, forming a complex flow pattern. This results in a generally non-uniform inflow of reservoir-carried formation sand into the fractures. Based on the specific flow conditions and characteristics, the fractures can be divided into mildly invaded and severely invaded zones.

[0026] Furthermore, if the fracture length is shorter than the reservoir control radius, the fracture conductivity is excellent, its fluidity is much higher than that of the reservoir, and it is easier to flow into the fracture from the fracture toe position, forming the situation of mode A (such as Figure 3 On the contrary, it is easier to form pattern B (as shown in Figure 4 shown).

[0027] For the flow of mode A and mode B, if the length L of the slightly intruded region can be obtained fb and the length of the severe intrusion area L fa The filling length and amount of coarse and fine proppants can be designed based on the size of the proppant.

[0028] Specifically, a method for optimizing the design of dual-size proppant combination parameters for fracturing and filling unconsolidated sandstone reservoirs includes:

[0029] S1. Calculate the invasion site discrimination characteristic index.

[0030] S101. Evaluate the severity of sand production and obtain an influx index of sand production into fractures in a fracture-filled well.

[0031] The Sanding Inflow Index (S I ) characterizes the severity of sand production when the reservoir in a fracture-filled well flows into the fractures. Its calculation formula is:

[0032] (1);

[0033] In the above formula, △Pis the average production pressure difference of the oil well, MPa; △P c is the critical production pressure difference of oil well sand production, obtained by sand production prediction calculation, MPa; B s is the reservoir sand production index, MP 2 ; B sc The sand index limit corresponding to severe sand production in empirical qualitative sand production prediction is 1.5×10 4 MPa 2 ; S I is the sand inflow intrusion index, dimensionless.

[0034] S I is an exponent with a value around 1, S I The larger the value above 1, the more serious the sand intrusion into the fracture from the reservoir. S I When the value is lower than 1 and the array is smaller, it means that the sand inflow invasion of the reservoir into the fracture is weaker.

[0035] The above S I The scientificity and rationality of index calculation lies in: the sand production index characterizes the sand production risk based on reservoir geological conditions and rock strength properties. B sc / B s The larger the ratio, the higher the risk of sand production from the perspective of reservoir geology; its weight is relatively weak, with a value of 0.25. On the other hand, the severity of sand production depends more on the comparison between the actual production pressure difference and the critical pressure difference of sand production. The greater the former exceeds the latter, the more serious the actual sand production is. △P / △P c The larger it is, the more serious the sand inflow invasion of the reservoir into the fracture is; its weight is relatively large, with a value of 0.75.

[0036] S102, calculate the invasion site discrimination characteristic index (Fracture Sand Invasion, F SI The index is used to evaluate the relative positions of the slightly invaded and severely invaded areas where fluids and formation sands flow into fractures, as well as their boundary positions.

[0037] F SI The index is:

[0038] (5);

[0039] Where, F SIis the discriminant characteristic index of the invasion site, dimensionless; X Lf 、 X hf、 X kwf They are the single influencing factor of fracture filling length, the single influencing factor of fracture filling height, and the single influencing factor of fracture filling fracture conductivity, which are dimensionless. W Lf 、 W hf and W kwf They are the weight coefficients of the single influencing factor of seam length, the single influencing factor of seam height, and the influencing factor of conductivity.

[0040] Preferably, W Lf 、 W hf and W kwf The values are 0.45±0.02, 0.25±0.02 and 0.3±0.02 respectively.

[0041] Among them, the single influencing factor of the fracturing filling length is X Lf for:

[0042] (2);

[0043] Where, X Lf is the single factor affecting the length of the fracture filling, dimensionless; R e is the reservoir radius controlled by the oil well, m; L f is the length of the single wing of the crack, m; α It is the correction coefficient of fracture filling length.

[0044] The fracturing filling seam length correction factor α This is to achieve a weighted average of the same order of magnitude as other individual influencing factors.

[0045] Preferably, the fracturing filling seam length correction coefficient α The value is 1.5385.

[0046] Single influencing factor of fracturing filling length X Lf The smaller the value, the shorter the fracture radius is compared to the reservoir radius controlled by the oil well, and the more the flow of reservoir fluid into the fracture tends to be in mode B; otherwise, it tends to be in mode A.

[0047] The single factor affecting the high fracture filling X hffor:

[0048] (3);

[0049] Where, X hf is the single factor affecting the height of fracture filling, dimensionless; H e is the reservoir thickness, m; h f is the crack height, m; β It is the correction factor for fracture filling height.

[0050] The high correction factor of the fracture filling seam β This is to achieve a weighted average of the same order of magnitude as other individual influencing factors.

[0051] Preferably, the fracturing filling seam height correction coefficient β The value is 1.058.

[0052] Single factor influencing the height of fracture filling X Lf The smaller the value, the shorter the fracture height is compared to the reservoir thickness, and the more the reservoir fluid flows into the fracture, the more it tends to be in mode B; otherwise, it tends to be in mode A.

[0053] The single influencing factor of the conductivity of the fracture filling X kwf for:

[0054] (4);

[0055] Where, X kwf is the single factor affecting the conductivity of the fracture filling, dimensionless; K e is the reservoir permeability, D; k f is the fracture filling permeability, D; w f is the crack width, mm; γ is the correction coefficient for the conductivity of fracture filling.

[0056] The fracturing filling fracture conductivity correction coefficient γ This is to achieve a weighted average of the same order of magnitude as other individual influencing factors.

[0057] Preferably, the γ The value is 2.15.

[0058] Single influencing factor of fracture conductivity of hydraulic fracturing filling X kwfThe smaller it is, the closer the fracture conductivity is to the reservoir fluidity, and the reservoir fluid is less inclined to flow into the fracture, but more inclined to flow toward the fracture root, that is, the more inclined to mode B; conversely, the more inclined to mode A.

[0059] S2. Optimize the filling sequence and fracture length ratio of dual-size proppants in fracture filling wells:

[0060] S201, according to F SI The index determines the flow pattern of reservoir fluid and formation sand toward fractures:

[0061] If F SI >1.15, the flow pattern of reservoir fluid and formation sand toward fractures is mode A;

[0062] If F SI <0.85, the flow pattern of reservoir fluid and formation sand toward fractures is mode B;

[0063] If 0.85≤F SI ≤1.15, the flow pattern of reservoir fluid and formation sand toward the fracture tends to be uniform flow, not mode A and mode B.

[0064] According to F SI The definition and characteristics of the index, when F SI When the index is greater than 1.15, the flow pattern is A; F SI The higher the index, the more obvious the flow invasion pattern tends to be towards pattern A, and the boundary line between the inner slightly invaded area close to the wellbore direction and the outer severely invaded area close to the reservoir direction moves outward. In order to achieve the balance of sand blocking and the best effect, coarse-grained proppant is used to fill the inner slightly invaded area, and fine-grained proppant is used to fill the outer severely invaded area. SI As the index increases, the filling length of the inner coarse-grained proppant becomes longer and the filling length of the outer fine-grained proppant becomes shorter.

[0065] Similarly, when F SI When the index is less than 0.85, the flow pattern is pattern B; F SI The lower the index, the more pronounced the flow invasion pattern tends toward Pattern B, and the boundary between the heavily invaded zone (inner) toward the wellbore and the slightly invaded zone (outer) toward the reservoir shifts further inward (toward the wellbore). The inner fine-grained proppant packing section becomes shorter, while the outer coarse-grained proppant packing length becomes longer.

[0066] S202, according to the flow pattern and F SI Index design of the ratio of filling length and filling order of coarse and fine particle proppants:

[0067] Based on the above principles, a design method for the ratio of coarse and fine particle proppant filling lengths is proposed, as shown in Table 1.

[0068] The packing sequence is carried out according to the rule that the severely invaded area is filled with fine-grained proppant and the slightly invaded area is filled with coarse-grained proppant.

[0069] Table 1 Design method for the ratio of coarse and fine particle proppant filling length

[0070]

[0071] S3. Optimize the coarse and fine particle size of the dual-size proppant combination for fracturing and filling wells:

[0072] The specific particle size of coarse and fine particle proppants is designed based on the severity of formation sand production, the median particle size of the formation sand, and the uniformity coefficient. In the fracturing filling mode of combined filling of coarse and fine particle proppants, the fine particle proppant mainly plays the role of sand retention. The method for designing the median particle size is as follows:

[0073] (6);

[0074] In the formula S I is the sand inflow invasion index of the reservoir into the fracture, dimensionless; J s is the formation sand uniformity coefficient, dimensionless; d s50 is the median size of formation sand, mm; D g50a is the design value of the median particle size of fine-particle proppant, mm.

[0075] when D g50a When the particle size is less than 0.3, the particle size of the fine-grained proppant is selected to be 0.3-0.6 mm, and the particle size of the coarse-grained proppant is selected to be 0.3-0.6 mm;

[0076] When 0.3≤ D g50a When the particle size is less than 0.6, the particle size of the fine-grained proppant is selected to be 0.3-0.6 mm, and the particle size of the coarse-grained proppant is selected to be 0.4-0.8 mm;

[0077] When 0.6≤ D g50a When the particle size is less than 0.8, the particle size of the fine-grained proppant is selected to be 0.4-0.8 mm, and the particle size of the coarse-grained proppant is selected to be 0.6-1.2 mm;

[0078] When 0.8≤ D g50aWhen selecting fine-grained proppant, the particle size of the fine-grained proppant is 0.6-1.2 mm, and the particle size of the coarse-grained proppant is 0.6-1.2 mm.

[0079] For example, the traditional Saucier method designs proppant particle size based on a median particle size equal to 5-6 times the median particle size of the formation sand. This approach, which ignores production and sand production conditions and only considers the median particle size of the formation sand, makes it difficult to balance productivity and sand control effectiveness. However, the present invention considers not only the median particle size of the formation sand but also the severity of sand production and the formation sand uniformity coefficient. This ensures sand retention while preventing damage to fracture conductivity and productivity caused by excessive intrusion of formation sand.

[0080] The optimization principle of dual-size proppant particle size for fracture-fill wells is as follows: the more severe the sand production, the more difficult it is to stop it, and the more likely the formation sand is to invade the fracture filling zone, causing blockage and production loss; the less uniform the formation sand (the higher the uniformity coefficient), the more difficult it is to stop it; under both of the above trends, a finer proppant particle size should be used; otherwise, a coarser proppant particle size should be selected.

[0081] Beneficial effects:

[0082] (1) The method for optimizing the design of dual-particle proppant combination parameters for fracturing and filling loose sandstone reservoirs proposed in the present invention can optimize the design of specific parameters such as proppant filling particle size, filling seam length ratio, and filling sequence according to the selected reservoir and oil well conditions and the corresponding dual-particle combination mode, thereby achieving the comprehensive effect of effectively blocking sand while reducing the invasion and blockage of formation sand on the fracture filling layer and the damage to the permeability, reducing the flow resistance of the fracture, improving the comprehensive conductivity, and releasing the production capacity of the oil and gas well.

[0083] (2) The present invention designs and selects the particle sizes of coarse and fine proppants based on the particle size and characteristic indicators of the formation sand. The blending ratio of coarse and fine proppants can be designed based on the particle size characteristics of the formation sand. This solves the problem that the three types of proppants commonly used in oil and gas fields currently have large particle size gaps, making it difficult to cover part of the formation sand particle size with the optimal particle size ratio. Overall, the ratio of the fracturing fill proppant particle size to the formation sand particle size is always within the optimal range, ensuring the sand retaining effect while preventing excessive intrusion of formation sand from damaging the fracture conductivity and production capacity.

[0084] (3) The present invention aims at two combination modes of coarse and fine proppants, namely, coarse outside and fine inside, and fine outside and coarse inside. The method of the ratio of the length of coarse and fine proppants filled in the fracture and the corresponding filling amount is proposed. The method fully considers the influence of reservoir geological conditions, fracture geometric parameters, and production fluid conditions on the key invasion and blockage sites of formation sand. According to the key invasion and blockage sites, the corresponding coarse and fine proppants are designed to fill the fracture sites, which can achieve "fine-grained sand blocking and coarse-grained diversion", give full play to the respective functions of coarse and fine-grained proppants, and achieve a balance between the overall sand blocking and diversion of the fracture, which can ensure that the combined filling technology of coarse and fine-grained proppants can play its potential and role, and improve the sand control and production increase effect. BRIEF DESCRIPTION OF THE DRAWINGS

[0085] Figure 1 This is a schematic diagram of single-size proppant fracturing filling;

[0086] Figure 2 Schematic diagram of three dual-size proppant combination modes;

[0087] Figure 3 Schematic diagram of reservoir fluid and formation sand filling mode A into the fracture;

[0088] Figure 4 Schematic diagram of reservoir fluid and formation sand filling mode B into the fracture;

[0089] Figure 5 Schematic diagram of the filling ratio of reservoir fluid and formation sand into fracture flow pattern A;

[0090] Figure 6 Schematic diagram of the filling ratio of reservoir fluid and formation sand into fracture flow pattern B.

[0091] Among them, 1-1 is the wellbore, 1-2 is the reservoir, 1-3 is the proppant filling fracture, 2-1 is the wellbore, 2-2 is the coarse-grained proppant, and 2-3 is the fine-grained proppant. DETAILED DESCRIPTION

[0092] Example 1:

[0093] There is an oil well with loose geological bonding, belonging to loose sandstone oil and gas reservoir. The reservoir radius controlled by the oil well is R e The average production pressure difference of the oil well is 200m △P The critical production pressure difference of sand production in this oil well is 4.2MPa. △P c 4MPa, reservoir sand production index B s 1.6×10 4 MPa 2 The oil well is generally in a sandy state. Currently, dual-size filling and fracturing is being adopted.

[0094] The critical production pressure difference of sand production in oil wells △P c The prediction method refers to Dong Changyin. Theory and Technology of Sand Control in Oil and Gas Wells[M]. China University of Petroleum Press, 2012:45.

[0095] The limits of severe sanding, slight sanding and no sanding in the empirical qualitative sanding prediction are determined by reference to the combined modulus method. For details, please refer to Dong Changyin. Theory and Technology of Sand Control in Oil and Gas Wells [M]. China University of Petroleum Press, 2012: 32.

[0096] S101. Calculate the Sanding Inflow Index (S I )

[0097] According to the given data and formula (1), S I It is 1.054, and it is preliminarily judged that the sand inflow intrusion of the reservoir into the fracture is serious.

[0098] S102, calculate F SI

[0099] According to formulas (2), (3), and (4), calculate the single factor influencing the length of the fracture filling seam X Lf , high single factor influencing the fracturing filling X hf , Single influencing factors of fracture conductivity of hydraulic fracturing filling X kwf , the calculation conditions and results are shown in Table 2.

[0100] Table 2 Calculation conditions and results

[0101]

[0102] In this embodiment, the weight coefficients W of the single factor affecting the length of the fracture filling seam, the single factor affecting the height of the fracture filling seam, and the factor affecting the conductivity of the fracture filling are: Lf 、W hf and W kwf , with values of 0.45, 0.25 and 0.3 respectively. The FSI index value calculated according to formula (5) is 1.32.

[0103] S201. Since the FSI index is greater than 1.15, it is determined that the flow pattern of the reservoir fluid and formation sand toward the fracture is pattern A.

[0104] S202, determining the filling order of coarse and fine proppants based on the flow pattern: coarse inside and fine outside;

[0105] According to F SIThe index shows that the ratio of coarse-grained proppant to fine-grained proppant filling seam length is 4:6.

[0106] S3. Optimization of coarse and fine particle sizes of dual-size proppant combinations

[0107] The reservoir sand uniformity coefficient J s is 2.25, the median particle size of the formation sand d s50 The median design value of the fine particle size proppant is 0.1 mm, and the median design value of the fine particle size proppant is calculated according to formula (6): is 0.65.

[0108] Since 0.6≤ D g50a <0.8, the particle size of the fine-grained proppant is selected to be 0.4-0.8 mm, and the particle size of the coarse-grained proppant is selected to be 0.6-1.2 mm.

[0109] According to the total length of the fracture filling seam of 35m, it is calculated that the filling length of the coarse-grained proppant is 14m and the fine-grained proppant is 21m.

[0110] In summary, the design results are as follows: according to the design scheme of coarse inside and fine outside, coarse-grained proppant with a filling length of 14m is filled near the wellbore end, and fine-grained proppant with a filling length of 21m is continued to be filled.

[0111] Comparative Example 1:

[0112] This comparative example used the traditional Saucier method to design the proppant particle size, assuming the median particle size of the sand-retaining proppant is 5-6 times the median particle size of the formation sand. The proppant particle size used was 0.4-0.8 mm. Furthermore, this comparative example did not distinguish between areas of severe and mild invasion, and a single particle size proppant was used.

[0113] Table 3 Comparison of the effects of Example 1 and Comparative Example 1

[0114]

[0115] The initial relative permeability is measured by a gas permeability instrument. For dual-size filling, a weighted average method is required, that is, (permeability of section A × length of section A + permeability of section B × length of section B) / total length of the crack.

[0116] The time of first sand production, the stable sand content after sand production, and the production increase effect before and after construction can be obtained from field data. The samples were taken from the Shengli Oilfield in Dongying.

[0117] Although the initial relative permeability of the proppant is slightly lower in the case of dual-particle filling, field practice shows that dual-particle filling can significantly increase the time to first sand production in the oil well and the stable sand content after sand production, achieving sufficient sand control while maintaining stable and increased oil well production.

Claims

1. A method for optimizing the design of dual-size proppant combination parameters for fracturing and filling loose sandstone reservoirs, characterized in that: include: S1. Calculate the invasion site discrimination characteristic index: First, the severity of sand production is evaluated based on formation parameters and production conditions; Then calculate the characteristic index F of the fracture invasion position of the fracturing filling formation sand SI ; S2. Optimize the filling sequence and fracture length ratio of dual-size proppants in fracture filling wells: According to the F calculated in step S1 SI Index, distinguishing the flow patterns of reservoir fluid and formation sand into fractures; obtaining the filling order of coarse-grained proppant and fine-grained proppant, and the ratio of fracture length; S3. Optimize the coarse and fine particle size of the dual-size proppant combination for fracturing and filling wells: According to the severity of formation sand production, the median size of formation sand and the uniformity coefficient, the design value of the median size of fine-grained proppant is calculated, thereby optimizing the design of proppant size; In step S1, the invasion site discrimination characteristic index is calculated as follows: S101. Obtain the sand inflow intrusion index of the reservoir into the fracture of the fracture filling well: The calculation formula for the sand inflow intrusion index of the reservoir into the fracture of the fracture filling well is: (1)； In the above formula, △P is the average production pressure difference of the oil well, MPa; △P c is the critical production pressure difference of oil well sand production, MPa; B s is the reservoir sand production index, MPa 2 ; B sc The sand index limit corresponding to severe sand production in empirical qualitative sand production prediction is 1.5×10 4 MPa 2 ; S I is the sand inflow intrusion index, dimensionless; S102. Calculate the invasion site discrimination characteristic index: The discriminant characteristic index of invasion site is: (5)； Where, F SI is the discriminant characteristic index of the invasion site, dimensionless; X Lf 、 X hf 、 X kwf They are the single influencing factor of fracture filling length, the single influencing factor of fracture filling height, and the single influencing factor of fracture filling fracture conductivity, which are dimensionless. W Lf 、 W hf and W kwf They are the weight coefficients of the single influencing factor of the fracture filling seam length, the single influencing factor of the fracture filling seam height, and the influencing factor of the fracture filling conductivity.

2. The method for optimizing the design of dual-size proppant combination parameters for fracturing and filling loose sandstone reservoirs according to claim 1, characterized in that: The method for optimizing the design of dual-size proppant combination parameters for fracturing and filling of loose sandstone reservoirs specifically includes: S1. Calculate the invasion site discrimination characteristic index: S101. Obtain the sand inflow intrusion index of the reservoir into the fracture of the fracture filling well: The calculation formula for the sand inflow intrusion index of the reservoir into the fracture of the fracture filling well is: (1)； In the above formula, △P is the average production pressure difference of the oil well, MPa; △P c is the critical production pressure difference of sand production in oil wells, MPa; B s is the reservoir sand production index, MPa 2 ; B sc The sand index limit corresponding to severe sand production in empirical qualitative sand production prediction is 1.5×10 4 MPa 2 ; S I is the sand inflow intrusion index, dimensionless; S102. Calculate the invasion site discrimination characteristic index: The discriminant characteristic index of invasion site is: (5)； Where, F SI is the discriminant characteristic index of the invasion site, dimensionless; X Lf 、 X hf 、 X kwf They are the single influencing factor of fracture filling length, the single influencing factor of fracture filling height, and the single influencing factor of fracture filling fracture conductivity, which are dimensionless. W Lf 、 W hf and W kwf They are the weight coefficients of the single influencing factor of the fracture filling seam length, the single influencing factor of the fracture filling seam height, and the influencing factor of the fracture filling conductivity; S2. Optimize the filling sequence and fracture length ratio of dual-size proppants in fracture filling wells: S201, according to F SI The index determines the flow pattern of reservoir fluid and formation sand toward fractures: If F SI >1.15, the flow pattern of reservoir fluid and formation sand toward fractures is mode A; If F SI <0.85, the flow pattern of reservoir fluid and formation sand toward fractures is mode B; If 0.85≤F SI ≤1.15, the flow pattern of reservoir fluid and formation sand toward fractures is non-mode A or non-mode B; Among them, mode A is: the area near the crack toe is the severe invasion area, and the area near the crack root is the slight invasion area; Mode B: the area near the crack root is a severe invasion area, and the area near the crack toe is a slight invasion area; S202, according to the flow pattern and F SI Index design of the ratio of filling length and filling order of coarse and fine particle proppants: When 2.0 <F SI When the filling length ratio of coarse-grained proppant to fine-grained proppant is 7:3; When 1.75 <F SI When ≤2.0, the ratio of the filling length of coarse-grained to fine-grained proppants is 6:4; When 1.55 <F SI When ≤1.75, the ratio of the filling length of coarse-grained and fine-grained proppants is 5:5; When 1.25 <F SI When ≤1.55, the ratio of the filling length of coarse-grained to fine-grained proppants is 4:6; When 1.15 <F SI When ≤1.25, the ratio of the filling seam length of coarse-grained to fine-grained proppants is 3:7; When 0.7≤F SI When I<0.85, the ratio of the filling seam length of fine-grained to coarse-grained proppants is 7:3; When 0.55≤F SI When <0.7, the ratio of the filling length of fine-grained to coarse-grained proppants is 6:4; When 0.4≤F SI When <0.55, the ratio of the filling length of fine-grained proppant to that of coarse-grained proppant is 5:5; When 0.25≤F SI When <0.4, the ratio of the filling length of fine-grained proppant to coarse-grained proppant is 4:6; When FSI < 0.25, the ratio of the filling length of fine-grained to coarse-grained proppants is 3:7; The filling sequence is carried out according to the rule that the severely invaded area is filled with fine-grained proppant and the slightly invaded area is filled with coarse-grained proppant; S3. Optimize the coarse and fine particle size of the dual-size proppant combination for fracturing and filling wells: The method for designing the median particle size of the fine particle size proppant is as follows: (6)； Where, S I is the sand inflow intrusion index, dimensionless; J s is the formation sand uniformity coefficient, dimensionless; d s50 is the median size of formation sand, mm; D g50a is the design value of the median particle size of fine-particle proppant, mm; when D g50a When the particle size is less than 0.3, the particle size of the fine-grained proppant is selected to be 0.3-0.6 mm, and the particle size of the coarse-grained proppant is selected to be 0.3-0.6 mm; When 0.3≤ D g50a When the particle size is less than 0.6, the particle size of the fine-grained proppant is selected to be 0.3-0.6 mm, and the particle size of the coarse-grained proppant is selected to be 0.4-0.8 mm; When 0.6≤ D g50a When the particle size is less than 0.8, the particle size of the fine-grained proppant is selected to be 0.4-0.8 mm, and the particle size of the coarse-grained proppant is selected to be 0.6-1.2 mm; When 0.8≤ D g50a When selecting fine-grained proppant, the particle size of the fine-grained proppant is 0.6-1.2 mm, and the particle size of the coarse-grained proppant is 0.6-1.2 mm.

3. The method for optimizing the design of dual-size proppant combination parameters for fracturing and filling loose sandstone reservoirs according to claim 2, characterized in that: W Lf 、 W hf and W kwf The values are 0.45±0.02, 0.25±0.02 and 0.3±0.02 respectively.

4. The method for optimizing the design of dual-size proppant combination parameters for fracturing and filling unconsolidated sandstone reservoirs according to claim 2, characterized in that: The single influencing factor of the fracturing filling length X Lf for: (2)； Where, X Lf is the single factor affecting the length of the fracture filling, dimensionless; R e is the reservoir radius controlled by the oil well, m; L f is the length of the single wing of the crack, m; α It is the correction coefficient of fracture filling length.

5. The method for optimizing the design of dual-size proppant combination parameters for fracturing and filling loose sandstone reservoirs according to claim 4, characterized in that: The fracturing filling seam length correction coefficient α The value is 1.5385.

6. The method for optimizing the design of dual-size proppant combination parameters for fracturing and filling loose sandstone reservoirs according to claim 2, characterized in that: The single factor affecting the high fracture filling X hf for: (3)； Where, X hf is the single factor affecting the height of fracture filling, dimensionless; H e is the reservoir thickness, m; h f is the crack height, m; β It is the correction factor for fracture filling height.

7. The method for optimizing the design of dual-size proppant combination parameters for fracturing and filling loose sandstone reservoirs according to claim 6, characterized in that: The high correction factor of the fracture filling seam β The value is 1.

058.

8. The method for optimizing the design of dual-size proppant combination parameters for fracturing and filling unconsolidated sandstone reservoirs according to claim 2, characterized in that: The single influencing factor of the conductivity of the fracture filling X kwf for: (4)； Where, X kwf is the single factor affecting the conductivity of the fracture filling, dimensionless; K e is the reservoir permeability, D; k f is the fracture filling permeability, D; w f is the crack width, mm; γ is the correction coefficient of fracture conductivity of hydraulic fracturing filling; R e is the reservoir radius controlled by the oil well, m.

9. The method for optimizing the design of dual-size proppant combination parameters for fracturing and filling unconsolidated sandstone reservoirs according to claim 8, characterized in that: The fracturing filling fracture conductivity correction coefficient γ The value is 2.

15.

10. The method for optimizing the design of dual-size proppant combination parameters for fracturing and filling unconsolidated sandstone reservoirs according to claim 2, characterized in that: The volume usage of coarse and fine proppants is calculated based on the ratio of the filling length of coarse and fine proppants and the fracture geometric parameters.

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