A horizontal well arrangement method based on fracture development intensity characteristics

Abstract

The application discloses a horizontal well arrangement method based on fracture development intensity characteristics, which comprises the following steps: first, establishing a reservoir fracture development degree intensity model; second, establishing a reservoir fracture development degree classification standard; third, selecting a development mode according to the fracture development intensity classification, wherein a first fracture intensity area adopts long horizontal well quasi-natural energy development, and second and third fracture intensity areas adopt rectangular well pattern advanced water injection development; and fourth, determining the water injection development mode, and adopting different modes for the second fracture intensity area and the third fracture intensity area. Based on the natural fracture azimuth identification of logging, the fracture development degree classification standard based on logging parameters is constructed, different horizontal well arrangement modes are formulated according to different fracture intensity classifications, the horizontal well pattern parameters are optimized, the adaptability of the horizontal well pattern reservoir is improved, water drive effect is finally improved, the water breakthrough risk is reduced, and the target of efficient development is achieved.

Description

Technical Field

[0001] This invention belongs to the field of oilfield development technology, specifically relating to a horizontal well placement method based on fracture development intensity characteristics. Background Technology

[0002] In recent years, with the deepening of oilfield development, the target of new production areas has gradually shifted from low-permeability and ultra-low-permeability reservoirs to ultra-low-permeability and tight oil reservoirs. Currently, the main development method for ultra-permeable and tight oil reservoirs is horizontal well development. Horizontal wells have become the main technical means to increase the production of single wells in the early stage of such reservoirs. However, the development of ultra-low-permeability reservoirs by water injection in horizontal wells has the problem of compatibility between well network and fractures, resulting in problems such as easy water encounter during production, low effectiveness, large decline, and low oil production rate.

[0003] Domestic scholars' research on the development patterns and well networks of fractured horizontal wells mainly focuses on the productivity of combined horizontal and vertical well networks. There is limited research on the production decline and water cut increase patterns of low-permeability horizontal wells, and conventional prediction methods for medium-to-high permeability reservoirs are still used or only partially modified, resulting in poor adaptability. Regarding formation energy replenishment, conventional waterflooding has been adopted, and technologies such as pre-injection and mild water injection have been developed. However, these technologies still face problems such as insufficient energy replenishment, poor waterflooding effect, and susceptibility to water channeling in horizontal well development. Furthermore, adjustments in the later stages of horizontal well development are difficult. Summary of the Invention

[0004] The purpose of this invention is to provide a horizontal well layout method based on fracture development intensity characteristics. Different well layout methods are adopted according to fracture development intensity to improve the adaptability of the horizontal well network to fractures, thereby improving water drive effectiveness and reducing the risk of water breakthrough.

[0005] The objective of this invention is achieved through the following technical means: a horizontal well placement method based on fracture development intensity characteristics, comprising the following steps:

[0006] The first step is to establish a reservoir fracture development intensity model and calculate the fracture intensity SFI of the sand layer and the fracture intensity FFI within the layer.

[0007] The second step is to establish a classification standard for the degree of reservoir fracture development. Based on production dynamic data, SFI and FFI values, a relationship curve between production dynamic data and SFI or FFI values ​​is plotted using the intersection plot method. The relationship curve is a trend line summarized by scatter plots. The trend line is intersected by the curve tangents to obtain the boundary points A and B. The x-coordinate values ​​of A and B are the specific boundary values. Where the x-coordinate of A is less than the x-coordinate of B, and the SFI or FFI value is less than the x-coordinate of A, it is the third category; where the x-coordinate is greater than or equal to the x-coordinate of A to less than or equal to the x-coordinate of B, it is the second category; and where the x-coordinate is greater than the x-coordinate of B, it is the first category. When there is fracture development in only one segment of the reservoir, SFI is used as the x-coordinate; when there is fracture development in multiple segments of the reservoir, FFI is used as the x-coordinate.

[0008] The third step is to select the development method according to the classification of fracture development intensity. In areas with the first type of fracture intensity, long horizontal wells are used for quasi-natural energy development. In areas with the second and third types of fracture intensity, rectangular well networks are used for advanced water injection development.

[0009] Step 4: Determine the water injection development method.

[0010] For areas with the second type of fracture intensity, the coupling degree between the orientation of natural and artificial fractures and the principal stress direction is statistically analyzed based on imaging logging data. When the coupling degree is higher than 85%, the horizontal well orientation is perpendicular to the principal stress direction; when the coupling degree is lower than 85%, the horizontal well orientation is perpendicular to the angle of the natural fracture.

[0011] For areas with third-class fracture intensity, the horizontal well orientation is perpendicular to the principal stress direction.

[0012] The degree of coupling is the percentage of the total number of cracks, both natural and artificial, that are located within a safe angle range.

[0013] The safe angle range is between δ-α and δ+α, where δ-α is the minimum safe angle, δ+α is the maximum safe angle, α is the angle between the injection well and the horizontal well, and δ is the angle of the maximum principal stress direction.

[0014] The Where L is the thickness of the sand body segment, i1 is the top depth of the i-th fracture development segment of the sand body segment, i2 is the bottom depth of the i-th fracture development segment of the sand body segment, and FIP(x) is the fracture index parameter value at depth x.

[0015] The L i Let be the thickness of the i-th sand body segment, i1 be the top depth of the i-th fracture development segment of the k-th sand body segment, i2 be the bottom depth of the i-th fracture development segment of the k-th sand body segment, and FIP(x) be the fracture index parameter value at depth x.

[0016] The beneficial effects of this invention are as follows: based on the identification of natural fracture orientation by well logging, a classification standard for fracture development degree based on well logging parameters is constructed. According to different fracture intensities, different horizontal well layout methods are formulated, horizontal well network parameters are optimized, the adaptability of horizontal well network reservoirs is improved, and ultimately, the effectiveness of water drive is improved, the risk of water breakthrough is reduced, and the goal of efficient development is achieved. Attached Figure Description

[0017] Figure 1 This is a flowchart of a horizontal well placement method based on fracture development intensity characteristics;

[0018] Figure 2 Schematic diagram of crack strength and intralayer crack strength;

[0019] Figure 3 A classification map of Huaqing Maling area based on FFI and monthly liquid production;

[0020] Figure 4 This is a schematic diagram illustrating the safe angle range;

[0021] Figure 5 A statistical table of crack development degree and coupling characteristics for Class III blocks;

[0022] Figure 6 A statistical diagram showing the distribution of natural fracture angles in imaging logging of the L183 area;

[0023] Figure 7 A statistical diagram of the distribution of natural fracture angles in imaging logging in the S183 area;

[0024] The present invention will be further described in detail below with reference to the accompanying drawings and embodiments. Detailed Implementation

[0025]

Example 1

[0026] like Figure 1 As shown, a horizontal well placement method based on fracture development intensity characteristics includes the following steps:

[0027] The first step is to establish a reservoir fracture development intensity model and calculate the fracture strength SFI and intra-layer fracture strength FFI of the sand layer. The fracture strength SFI of the sand layer is for when there is only one fracture segment. Figure 2 When calculating the crack strength only within the L1 segment, SFI is used for the calculation.

[0028] If multiple fracture development segments, such as L1 and L3, are considered, the intra-layer fracture strength (FFI) is used for calculation, therefore FFI includes SFI.

[0029] The second step is to establish a classification standard for the degree of reservoir fracture development. Based on production dynamic data, SFI and FFI values, a relationship curve between production dynamic data and SFI or FFI values ​​is plotted using the intersection plot method. The relationship curve is a trend line summarized by scatter plots. The trend line is intersected by the curve tangents to obtain the boundary points A and B. The x-coordinate values ​​of A and B are the specific boundary values. Where the x-coordinate of A is less than the x-coordinate of B, and the SFI or FFI value is less than the x-coordinate of A, it is the third category; where the x-coordinate is greater than or equal to the x-coordinate of A to less than or equal to the x-coordinate of B, it is the second category; and where the x-coordinate is greater than the x-coordinate of B, it is the first category. When there is fracture development in only one segment of the reservoir, SFI is used as the x-coordinate; when there is fracture development in multiple segments of the reservoir, FFI is used as the x-coordinate.

[0030] Similarly, when plotting the curve, if there is a single fracture development segment, SFI is used as the horizontal axis; if there are multiple fracture development segments, FFI is used as the horizontal axis.

[0031] When plotting, use production dynamics data, such as monthly liquid production, as the vertical axis and FFI or SFI as the horizontal axis. Mark the various scatter points on the graph and draw a trend line summarizing the monthly production data from these scatter points. Figure 3 Lines A and C are trend lines derived from scattered data points in the Maling and Huaqing areas, respectively. A typical trend line can be divided into three segments, each with a different curvature and therefore a different tangent. Using the curve tangent intersection method, a tangent is drawn for each trend line segment. The tangents of adjacent trend lines intersect at a single point, resulting in a total of two intersection points for the three segments. Figure 2 As shown, lines b and d are the tangents to the trend lines in the Maling and Huaqing areas, respectively.

[0032] The point with the smaller x-coordinate is designated as the dividing point A, and the point with the larger x-coordinate is designated as the dividing point B. Taking the tangent in the Maling area as an example, the x-coordinate of point A is 0.048, and the x-coordinate of point B is 0.081.

[0033] In the Maling area, FFI values ​​between 0 and 0.048 (excluding 0.048) are classified as Category III; values ​​between 0.048 and 0.081 (inclusive) are classified as Category II; and values ​​greater than 0.081 (excluding 0.081) are classified as Category III. See the table below for details.

[0034]

[0035]

[0036] The third step is to select the development method according to the classification of fracture development intensity. In areas with the first type of fracture intensity, long horizontal wells are used for quasi-natural energy development. In areas with the second and third types of fracture intensity, rectangular well networks are used for advanced water injection development.

[0037] In areas with high fracture intensity, such as the western part of the basin affected by the Indosinian and Himalayan faults, microfractures are well-developed in the YC6 reservoir. Although imaging logging shows that the fracture angles are generally within a safe range, the high density of bedding fractures and high water production still presents significant challenges. For example, the Y31 horizontal well showed water production at five points, but the rate of water production decreased significantly, resulting in poor development outcomes. The Y192 high-angle rectangular well pattern also suffers from water production problems and poor development results. Therefore, for this type of reservoir, quasi-natural energy development using long horizontal wells is recommended.

[0038] Step 4: Determine the water injection development method.

[0039] For areas with the second type of fracture intensity, the coupling degree between the orientation of natural and artificial fractures and the principal stress direction is statistically analyzed based on imaging logging data. When the coupling degree is higher than 85%, the horizontal well orientation is perpendicular to the principal stress direction; when the coupling degree is lower than 85%, the horizontal well orientation is perpendicular to the angle of the natural fracture.

[0040] For areas with a third-degree fracture intensity, the horizontal well azimuth is perpendicular to the principal stress direction. Since fractures are not well-developed in areas with a third-degree fracture intensity, the influence of fractures does not need to be considered, and the horizontal well azimuth can simply be perpendicular to the principal stress direction.

[0041] The degree of coupling is the percentage of the total number of cracks, both natural and artificial, that are located within a safe angle range.

[0042] like Figure 4 As shown, the safe angle range is between δ-α and δ+α, where δ-α is the minimum safe angle, δ+α is the maximum safe angle, α is the angle between the injection well and the horizontal well, and δ is the angle of the maximum principal stress direction. When the fracture orientation is within the safe angle range, the risk of water breakthrough due to fracture is reduced.

[0043] Through outcrop profiles and imaging logging, natural fractures in the same area show a high degree of consistency in orientation over a large range. However, for reservoirs with well-developed natural fractures or poor coupling between natural fracture orientation and geostress, and with excessively large angles, even if the reservoir has good compressibility, good fluid properties, and uniform pore throat distribution, premature water flooding of oil wells can still occur, affecting the reservoir development effect. Through follow-up research on horizontal well development areas with well-developed natural fractures in the Heshui area, the proportion of fracture-type water breakthroughs is about 20%, with an average water breakthrough period of 14 months, and the difficulty of remediation after water breakthrough is high.

[0044] like Figure 5 As shown, the better the coupling between the natural and artificial fractures and the principal stress, the lower the proportion of wells that reach water; conversely, the lower the coupling, the higher the proportion of wells that reach water.

[0045] Therefore, the direction and angle of each fracture in the block's natural and artificial fractures are first determined based on imaging logging data. The coupling degree is then calculated, indicating how many fractures are within the safe angle range.

[0046] like Figure 6 and Figure 7 As shown, taking the S177 and L83 well areas as examples, the direction of the maximum principal stress in both L183 and S177 areas is 73.6° northeast. The angle between the injection well and the horizontal section projection is 21.8°, and the safe angle range is between 53.2° and 96.8°. Statistical data from imaging logging show that nearly 20% of the fracture distribution in the S177 area exceeds the safe range. Field practice has proven that the proportion of fractured water breakthrough in the S177 area is indeed greater than that in the L183 area.

[0047] When the coupling degree is higher than 85%, the horizontal well azimuth should be perpendicular to the direction of the principal stress; when the coupling degree is lower than 85%, the horizontal well azimuth should be perpendicular to the angle of the natural fracture.

[0048] like Figure 2 As shown, the Where L is the thickness of the sand body segment, i1 is the top depth of the i-th fracture-developed segment of the sand body segment, i2 is the bottom depth of the i-th fracture-developed segment of the sand body segment, and FIP(x) is the fracture index parameter value at depth x. Existing SFI methods simply calculate (h1+h2) / L1, meaning L1 is the thickness of the sand body segment L1, and h1 and h2 are the thicknesses of the two fracture-developed segments of segment L1, respectively. L represents the thickness of the step segment, S represents the fracture development intensity area, and h represents the thickness of the fracture-developed segment.

[0049] The L i Let be the thickness of the i-th sand body segment, i1 be the top depth of the i-th fracture-developed segment of the k-th sand body segment, i2 be the bottom depth of the i-th fracture-developed segment of the k-th sand body segment, and FIP(x) be the fracture index parameter value at depth x. The existing FFI is (h1+h2+h3) / (L1+L3), that is, the sum of the thicknesses of the three fracture-developed segments within segments L1 and L3 is divided by the sum of the thicknesses of the two sand body segments.

[0050] Specifically, in the Y192 block of the Chang 6 reservoir, the permeability is 0.19 mD and the median radius is 0.16 μm. Due to the development of natural fractures, this method is used to adjust the well pattern parameters:

[0051] 1. A reservoir fracture development intensity model was established, and the fracture intensity was evaluated using the fracture intensity of sand layers (SFI) and the fracture intensity within the layers (FFI). 70 fractures were identified in a 101m long section of the 6th segment.

[0052] 2. Based on the classification criteria for the degree of reservoir fracture development, the development mode of this area with a fracture development intensity of is determined to be Category II, and the rectangular well pattern with advanced water injection development is adopted.

[0053] 3. The maximum principal stress azimuth in this area is mainly NE70°, the safe angle range is between 53.2° and 96.8°, the coupling degree between fracture angle and principal stress is less than 85%, and the fracture angle is mainly concentrated between 80° and 90°. Adjust the horizontal well azimuth to be perpendicular to the principal fracture angle.

[0054] The initial production capacity is projected to be 8.7t-11.0t, reaching 6.9t-9.5t in the year of full production, with an internal rate of return of 8.1%, indicating that it can be effectively developed.

Claims

1. A horizontal well placement method based on fracture development intensity characteristics, characterized in that, Includes the following steps: The first step is to establish a reservoir fracture development intensity model and calculate the fracture intensity SFI of the sand layer and the fracture intensity FFI within the layer. The second step is to establish a classification standard for the degree of reservoir fracture development. Based on production dynamic data, SFI and FFI values, a relationship curve between production dynamic data and SFI or FFI values ​​is plotted using the intersection plot method. The relationship curve is a trend line summarized by scatter plots. The trend line is intersected by the curve tangents to obtain the boundary points A and B. The x-coordinate values ​​of A and B are the specific boundary values. Where the x-coordinate of A is less than the x-coordinate of B, and the SFI or FFI value is less than the x-coordinate of A, it is the third category; where the x-coordinate is greater than or equal to the x-coordinate of A to less than or equal to the x-coordinate of B, it is the second category; and where the x-coordinate is greater than the x-coordinate of B, it is the first category. When there is fracture development in only one segment of the reservoir, SFI is used as the x-coordinate; when there is fracture development in multiple segments of the reservoir, FFI is used as the x-coordinate. The third step is to select the development method according to the classification of fracture development intensity. In areas with the first type of fracture intensity, long horizontal wells are used for quasi-natural energy development. In areas with the second and third types of fracture intensity, rectangular well networks are used for advanced water injection development. Step 4: Determine the water injection development method. For areas with the second type of fracture intensity, the coupling degree between the orientation of natural and artificial fractures and the principal stress direction is statistically analyzed based on imaging logging data. When the coupling degree is higher than 85%, the horizontal well orientation is perpendicular to the principal stress direction; when the coupling degree is lower than 85%, the horizontal well orientation is perpendicular to the angle of the natural fracture. For areas with third-class fracture intensity, the horizontal well orientation is perpendicular to the principal stress direction.

2. The horizontal well placement method based on fracture development intensity characteristics according to claim 1, characterized in that: The degree of coupling is the percentage of the total number of cracks, both natural and artificial, that are located within a safe angle range.

3. The horizontal well placement method based on fracture development intensity characteristics according to claim 2, characterized in that: The safe angle range is between δ-α and δ+α, where δ-α is the minimum safe angle, δ+α is the maximum safe angle, α is the angle between the injection well and the horizontal well, and δ is the angle of the maximum principal stress direction.

4. The horizontal well placement method based on fracture development intensity characteristics according to claim 1, characterized in that: The , where L is the thickness of the sand body segment, i1 is the top depth of the i-th fracture development segment of the sand body segment, i2 is the bottom depth of the i-th fracture development segment of the sand body segment, and FIP(x) is the fracture index parameter value at depth x.

5. A horizontal well placement method based on fracture development intensity characteristics according to claim 1, characterized in that: The L k Let be the thickness of the i-th sand body segment, i1 be the top depth of the i-th fracture development segment of the k-th sand body segment, i2 be the bottom depth of the i-th fracture development segment of the k-th sand body segment, and FIP(x) be the fracture index parameter value at depth x.

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