A method for fine depiction of single-well flow boundary of heterogeneous reservoir based on starting pressure gradient zoning model

Abstract

This invention discloses a method for finely characterizing the flow boundary of a single well in a heterogeneous reservoir based on a zoning model of starting pressure gradient. This method accurately calculates the limiting flow distance in each direction of the heterogeneous reservoir, generating irregularly shaped flow boundaries, thereby improving the scientific rigor of reserve utilization evaluation and well network design. The method includes: constructing a three-dimensional permeability field of the target reservoir area; dividing the target reservoir area into a low-permeability flow zone and an ultra-low permeability diffusion zone; constructing a zoning starting pressure gradient calculation model, and obtaining the functional relationship between the starting pressure gradient and permeability of the low-permeability flow zone / ultra-low permeability diffusion zone through fitting; establishing an oil saturation correction model to correct the basic starting pressure gradient point by point, obtaining the actual starting pressure gradient field of the target area; calculating the limiting flow distance in each direction centered on the target well; and connecting the endpoints of the limiting flow distances in each direction to generate a closed, irregular, effective flow boundary for the single well.

Description

Technical Field

[0001] This invention relates to the field of low-permeability, ultra-low-permeability and shale oil and gas reservoir development technology, and in particular to a method for fine characterization of the flow boundary of a single well in a heterogeneous reservoir based on a starting pressure gradient zoning model. Background Technology

[0002] In the development of low-permeability, ultra-low-permeability, and shale oil and gas reservoirs, determining the effective flow boundary of a single well (i.e., the range of reserves controlled by a single well) is the core basis for well network deployment, well spacing design, and injection-production regime optimization. Current conventional methods mainly include: (1) Darcy's Law Method: Based on the linear seepage theory, it assumes that there is no threshold for fluid flow and uses the pressure transmission coefficient to calculate the affected area.

[0003] (2) Well test analysis method: The detection radius is estimated by the boundary response characteristics of the shut-in pressure recovery curve.

[0004] (3) Homogeneous numerical simulation method: The reservoir parameters are averaged and uniform seepage parameters are set for simulation.

[0005] However, the above method has significant drawbacks for complex, heterogeneous reservoirs containing condensate / shale oil: (1) It ignores the nonlinear characteristics of the starting pressure gradient: Experiments have shown that in low-permeability media, fluid flow must overcome the starting pressure gradient. When the driving pressure difference is less than the product of the starting pressure gradient and the distance, the fluid cannot flow. Traditional linear methods will seriously overestimate the flow range.

[0006] (2) Homogenization masked local differences: In actual reservoirs, low-permeability zones (1~5 mD) and ultra-low-permeability zones (<1 mD) coexist. Experimental data show that the difference in starting pressure gradient between the two can be several times (e.g., 0.024 MPa / m: 0.144 MPa / m). Using uniform average parameters for calculation leads to an underestimation of the "sweet spot" and an overestimation of the tight zone, which cannot guide precise development.

[0007] (3) The dynamic hindrance effect of oil saturation is not considered: The amount of condensate oil or shale oil in the pores (oil saturation) will significantly change the starting difficulty of gas or fluid. Experiments show that when the oil saturation increases from 20% to 60%, the starting gradient increases by nearly 80%. Existing models lack coupling correction for this fluid distribution factor. Summary of the Invention

[0008] The purpose of this invention is to overcome the shortcomings of the prior art and provide a method for fine characterization of the flow boundary of a single well in a heterogeneous reservoir based on the starting pressure gradient zoning model. This method accurately calculates the limit flow distance in each direction of the heterogeneous reservoir and generates irregular flow boundaries, thereby improving the scientific nature of reserve utilization evaluation and well network design.

[0009] The objective of this invention is achieved as follows: A method for fine characterization of flow boundaries in a single well of a heterogeneous reservoir based on a starting pressure gradient zoning model, characterized by the following steps: Step S1: Based on well logging interpretation, seismic inversion, and geological modeling data, construct a three-dimensional permeability field for the target reservoir area. The three-dimensional permeability field is in grid form. Step S2: Based on the permeability threshold, the target reservoir area is divided into differentiated permeability property zones, which include low-permeability flow zones and ultra-low-permeability diffusion zones. Step S3: Construct a zoned initiation pressure gradient calculation model. Using core experimental data from the target reservoir area, obtain the functional relationship between the initiation pressure gradient and permeability in the low-permeability flow zone / ultra-low-permeability diffusion zone through fitting. Step S4: Establish an oil saturation correction model, and correct the basic starting pressure gradient of the corresponding grid obtained in Step S3 point by point to obtain the actual starting pressure gradient field of the target area. Step S5: Based on the integral balance relationship between the production pressure differential and the actual start-up pressure gradient field, calculate the limiting flow distance in each direction with the target well as the center. Step S6: Connect the endpoints of the limit flow distances in each direction to generate a closed, irregular single-well effective flow boundary.

[0010] Further, the permeability threshold mentioned in step S2 is 1.0 mD; the permeability range of the low-permeability flow zone is 1.0 mD to 5.0 mD, and the permeability range of the ultra-low permeability diffusion zone is 0.1 mD to 1.0 mD.

[0011] Furthermore, the partition startup pressure gradient calculation model described in step S3 adopts a power function form: in, To initiate the pressure gradient, , These are the fitting coefficients. This refers to penetration rate.

[0012] Furthermore, the oil saturation correction model mentioned in step S4 is as follows: in, This is the corrected actual startup pressure gradient. The starting pressure gradient is calculated solely based on permeability. The oil saturation level within the grid. , These are the fitting coefficients determined based on multiphase flow experiments using cores with different permeabilities. The influence of bound water is ignored, and the oil saturation within the grid is used directly for simplified processing.

[0013] Furthermore, the oil saturation correction model mentioned in step S4 is as follows: in, This is the corrected actual startup pressure gradient. The starting pressure gradient is calculated solely based on permeability. The oil saturation level within the grid. The retardation enhancement coefficient, To restrict water saturation, , These are the fitting coefficients determined based on multiphase flow experiments using cores with different permeabilities. The actual initiation pressure gradient for each grid node is calculated by superimposing the reservoir oil saturation field. By taking into account the bound water saturation and using the effective oil saturation, it is more in line with physical reality.

[0014] Furthermore, the method for calculating the limiting flow distance in step S5 is as follows: taking the well point of the target well as the origin, along a preset angle direction... Establish the ray path and solve for the limiting distance. This makes the integral of the starting pressure gradient along this path equal to the production pressure differential: in, This is the difference between formation pressure and bottom hole flowing pressure. It is the azimuth angle. Distance from well point on the ray path The actual starting pressure gradient value at the location.

[0015] Furthermore, it also includes step S7: using the obtained effective flow boundary of an irregular single well to guide the deployment of the well network.

[0016] Furthermore, the well network deployment method is as follows: deploy additional wells in the blank areas not covered by the effective flow boundaries of irregular single wells of multiple adjacent wells; or, adjust the direction of the injection and production well array according to the major and minor axis directions of the effective flow boundaries of irregular single wells.

[0017] Furthermore, the method is applied to the dynamic storage capacity evaluation of low-permeability condensate gas reservoir-type underground gas storage facilities: Define the oil saturation at different production stages, including: Stage A: oil saturation at the initial stage of tank construction; Stage B: oil saturation after a set operating time. Calculate the starting pressure gradient after saturation correction for each stage; Set the allowable production pressure difference for injection and extraction operations, back-calculate the effective flow boundary, and conduct dynamic evaluation of reservoir capacity.

[0018] Due to the adoption of the above technical solution, the present invention has the following beneficial effects: (1) Improved accuracy: Compared with the traditional homogeneous model, this method can identify the irregularity of the flow range caused by changes in sedimentary microfacies, and the calculation accuracy is improved by more than 30%.

[0019] (2) Risk avoidance: accurately identify the flow dead zone in the ultra-low permeability zone and avoid blindly deploying well locations in areas that cannot be utilized.

[0020] (3) Dynamic adaptation: The model is coupled with the oil saturation parameter, which can predict the dynamic shrinkage of the flow boundary caused by the change of oil content as mining progresses. Attached Figure Description

[0021] Figure 1 Schematic diagram of reservoir permeability field and Zone-I / Zone-II partitioning; Figure 2 Differential fitting curves of start-up pressure gradient and permeability under different zones; Figure 3 Start-up pressure gradient correction pattern under different oil saturation levels; Figure 4 Comparison diagram of irregular single-well flow boundary calculated by this method and traditional circular boundary. Detailed Implementation

[0022] A method for finely characterizing the flow boundary of a single well in a heterogeneous reservoir based on a starting pressure gradient zoning model is proposed. This method establishes a technical system of property zoning, differentiated starting gradient model, and liquid saturation correction to accurately calculate the limiting flow distance in each direction of the heterogeneous reservoir, generating irregularly shaped flow boundaries, thereby improving the scientific rigor of reserve utilization evaluation and well network design. The core of this method lies in breaking the homogenization assumption and establishing a zoning and hierarchical nonlinear seepage control boundary model. The specific steps are as follows: Step 1: Characterization of reservoir heterogeneity and zoning of physical properties (1) Based on well logging interpretation, seismic inversion and geological modeling data, a three-dimensional permeability field of the target area is constructed. .

[0023] (2) Based on the fluid flow characteristic thresholds revealed by the experiment, the reservoir is divided into different seepage units: Low-permeability flow zone: permeability Features: Good pore-throat connectivity, low starting pressure gradient, and gradual change with permeability.

[0024] Ultra-low permeability retention zone: permeability Features: Dominated by micro / nanopore throats, extremely high initiation pressure gradient, and extremely sensitive to changes in permeability.

[0025] Generate reservoir property zoning maps.

[0026] Step 2: Construct a partitioned startup pressure gradient model Based on core experimental data, differentiated initiation pressure gradients were established for different zones. ) and penetration rate ( Association model of ) For Zone-I (low-permeability zone): Establish a slowly varying power function model. .

[0027] For Zone-II (ultra-low permeability zone): Establish a steeply variable power function model. .

[0028] Note: Significantly greater than This reflects the rapid nonlinear increase in flow resistance in ultra-low permeability zones.

[0029] Step 3: Introduce oil saturation correction factor Considering the "liquid lock" effect of condensate oil / shale oil saturation on flow, a system based on oil saturation ( The modified model:

[0030] in, The retardation enhancement coefficient, To restrict water saturation, , The fitting constants are determined based on experiments at different permeability levels. The actual initiation pressure gradient for each grid node is calculated by superimposing the reservoir oil saturation field. .

[0031] Step 4: Discretize and calculate the effective flow boundary (1) A ray is emitted in a circular direction centered on the target well point.

[0032] (2) Perform integration calculations along each ray path. The limiting condition for fluid flow is the pressure difference between the bottom of the well and a certain point in the formation. This was exactly offset by the accumulated startup pressure loss along the way.

[0033] (3) The calculation formula is to solve for the limit distance that satisfies the following equation. : in It is a function of permeability and oil saturation along the path.

[0034] (4) The limit distances connecting each direction This forms a closed, irregular flow boundary loop.

[0035] Step 5: Output and Application of Results (1) Output irregular flow boundary map and identify the "long axis" (high permeability direction) and "short axis" (dense direction).

[0036] (2) Calculate the effective usable area and shape factor.

[0037] (3) Determine the location of the infill well and the injection-production pressure difference limit based on the boundary range.

[0038] Example 1: Characterization of the flow boundary of a single well in a heterogeneous, low-permeability condensate gas reservoir in a certain block This embodiment demonstrates how the partitioning method of the present invention can solve the problem that traditional homogeneous models cannot accurately describe the flow range of heterogeneous reservoirs.

[0039] 1. Basic parameters and geological background Analysis was conducted on production well X-1 in block M of an oilfield. The geological features of the area controlled by this well are complex, and the main parameters are as follows: Reservoir depth: 3500 m; Initial formation pressure: 35 MPa; Bottom hole flowing pressure: 25 MPa (i.e., production pressure difference ΔP = 10 MPa); Permeability distribution: It is extremely heterogeneous. There is a high-permeability sand body in the eastern part of the well (consistent with the river channel direction), with a permeability of about 2.5~4.0 mD; the western and southern parts are tight reservoirs with a permeability of only 0.15~0.5 mD.

[0040] 2. Implementation Steps Step S1: Physical property zoning. Based on the three-dimensional permeability field interpreted from well logging, zoning is performed with a threshold of K=1.0mD. Zone-I (Low-permeability flow zone): Distributed in the northeast direction around the well, with an average K≈3.0mD.

[0041] Zone-II (Ultra-low permeability diffusion zone): Distributed in the southwest direction around the well, with an average K≈0.3mD.

[0042] Step S2: Establish a zoned initiation pressure gradient model. Based on the core experimental data of this block, two models are fitted: Zone-I model: G1 = 0.04 × K − 0.4 (MPa / m). When K = 3.0, the basic initiation gradient... ≈0.026MPa / m.

[0043] Zone-II model: G2 = 0.08 × K − 0.7 (MPa / m). When K = 0.3, the basic initiation gradient... ≈0.186MPa / m.

[0044] As can be seen from the comparison, the starting resistance in the ultra-low permeability zone is more than 7 times that in the low permeability zone.

[0045] Step S3: Oil saturation correction, well perimeter average oil saturation S o =25%. According to the corrected formula f(So)=1+0.5×S o The correction factor is 1.125.

[0046] Zone-I Actual Gradient G real1 =0.026×1.125≈0.029MPa / m.

[0047] Zone-II Actual Gradient G real2 =0.186×1.125≈0.209MPa / m.

[0048] Step S4: Calculate the flow boundary using the formula R=ΔP / G rea1 Calculate the limiting flow radius: Northeast (Zone-I): R max =10 / 0.029≈344.8m.

[0049] Southwest (Zone-II): R min =10 / 0.209≈47.8m.

[0050] 3. Implementation Results and Comparison (1) Traditional method: If the average permeability of the whole area (about 1.2 mD) and the linear Darcy formula are used, the average flow radius is calculated to be a perfect circle of about 180 m.

[0051] (2) The method of the present invention: the generated flow boundary is irregular lentil-shaped.

[0052] (3) In the northeast direction, the present invention has identified that the conventional method underestimates the operational range by about 160m, and recommends that infiltration drilling be temporarily suspended in this direction; (4) In the southwest direction, the present invention identifies that the conventional method overestimates the utilization range by 130m. In fact, most of the reserves in this area have not been utilized and it is a potential area for deploying infill wells.

[0053] Example 2: Dynamic evaluation of the flow boundary in the high condensate oil content zone of an underground gas storage facility This embodiment focuses on a gas storage facility converted from a condensate gas reservoir, demonstrating the dynamic compression effect of changes in oil saturation on the flow boundary, and providing guidance for the design of injection-production pressure differential.

[0054] 1. Basic parameters: The gas storage injection-production well Y-2 is located in a typical ultra-low permeability sandstone reservoir.

[0055] Permeability: Relatively homogeneous, with an average K=0.5mD (belonging to Zone-II).

[0056] Basic startup gradient: Tested G base =0.10MPa / m.

[0057] Operating Background: With multi-cycle injection and production operation, condensate oil precipitation and reverse condensation occur around the well, leading to an increase in the near-wellbore oil saturation S. o It has been increasing year by year.

[0058] 2. Implementation Steps Step S1: Define the oil saturation at different production stages Phase A (Initial stage of tank construction): Oil saturation S o =10%.

[0059] Phase B (after 5 years of operation): Due to oil lock caused by anti-condensation, the oil saturation rises to S. o =40%.

[0060] Step S2: Calculate the saturation-corrected starting gradient using the correction model proposed in this invention: G real =G base ×(1+S o2 ×3).

[0061] Phase A: Correction factor f(0.1) = 1 + 0.01 × 3 = 1.03. G real_A =0.10×1.03=0.103MPa / m.

[0062] Phase B: Correction factor f(0.4) = 1 + 0.16 × 3 = 1.48. G real_B =0.10×1.48=0.148MPa / m.

[0063] Note: The flow resistance increased by nearly 50% solely due to the increase in oil saturation.

[0064] Step S3: Back-calculate the effective flow boundary and set the allowable production pressure difference ΔP for injection and production operations to be fixed at 12 MPa.

[0065] Initial flow radius: RA = 12 / 0.103 ≈ 116.5.

[0066] Later flow radius: RB = 12 / 0.148 ≈ 81.1m.

[0067] 3. Application of Results and Engineering Guidance Storage capacity dynamics evaluation: Calculations show that after 5 years of operation, the effective planar area controlled by a single well has decreased by approximately 51.5% ((116.52−81.12) / 116.52). This explains why the gas storage's injection and production capacity decreases over time.

[0068] Injection strategy adjustment: Option 1: To maintain the original control range (116.5m), the production pressure differential needs to be increased to ΔP. new =116.5 × 0.148 ≈ 17.2 MPa. However, it is necessary to assess whether this high pressure difference will cause rapid-sensitive injury.

[0069] Option 2: If the pressure differential is limited, gas injection or chemical unblocking measures need to be implemented at the original well control edge (beyond 80m) to reduce S. o To restore the flow capacity.

[0070] in conclusion This embodiment demonstrates that the method of the present invention can quantify the flow boundary contraction caused by the "oil lock" effect, providing a precise quantitative basis for gas storage facilities to formulate reasonable dynamic production and injection schemes.

[0071] Symbol Explanation Table

[0072]

[0073]

[0074] Finally, it should be noted that the above preferred embodiments are only used to illustrate the technical solutions of the present invention and are not intended to limit it. Although the present invention has been described in detail through the above preferred embodiments, those skilled in the art should understand that various changes can be made to it in form and detail without departing from the scope defined by the claims of the present invention.

Claims

1. A method for fine delineation of single-well flow boundaries in a heterogeneous reservoir based on a starting pressure gradient zonation model, characterized in that, Includes the following steps: Step S1: Based on well logging interpretation, seismic inversion, and geological modeling data, construct a three-dimensional permeability field for the target reservoir area. The three-dimensional permeability field is in grid form. Step S2: Based on the permeability threshold, the target reservoir area is divided into differentiated permeability property zones, which include low-permeability flow zones and ultra-low-permeability diffusion zones. Step S3: Construct a zoned initiation pressure gradient calculation model. Using core experimental data from the target reservoir area, obtain the functional relationship between the initiation pressure gradient and permeability in the low-permeability flow zone / ultra-low-permeability diffusion zone through fitting. Step S4: Establish an oil saturation correction model, and correct the basic starting pressure gradient of the corresponding grid obtained in Step S3 point by point to obtain the actual starting pressure gradient field of the target area. Step S5: Based on the integral balance relationship between the production pressure differential and the actual start-up pressure gradient field, calculate the limiting flow distance in each direction with the target well as the center. Step S6: Connect the endpoints of the limit flow distances in each direction to generate a closed, irregular single-well effective flow boundary.

2. The method according to claim 1, wherein, The permeability threshold mentioned in step S2 is 1.0 mD; the permeability range of the low-permeability flow zone is 1.0 mD to 5.0 mD, and the permeability range of the ultra-low permeability diffusion zone is 0.1 mD to 1.0 mD.

3. The method according to claim 1, wherein, The partition startup pressure gradient calculation model described in step S3 adopts a power function form: in, To initiate the pressure gradient, , These are the fitting coefficients. This refers to penetration rate.

4. The method for fine characterization of the flow boundary of a single well in a heterogeneous reservoir based on a starting pressure gradient zoning model according to claim 1, characterized in that, The oil saturation correction model mentioned in step S4 is as follows: in, This is the corrected actual startup pressure gradient. The starting pressure gradient is calculated solely based on permeability. The oil saturation level within the grid. , These are the fitting coefficients determined based on multiphase flow experiments using cores with different permeabilities.

5. The method for fine characterization of the flow boundary of a single well in a heterogeneous reservoir based on a starting pressure gradient zoning model according to claim 1, characterized in that, The oil saturation correction model mentioned in step S4 is as follows: in, This is the corrected actual startup pressure gradient. The starting pressure gradient is calculated solely based on permeability. The oil saturation level within the grid. The retardation enhancement coefficient, To restrict water saturation, , These are the fitting coefficients determined based on multiphase flow experiments using cores with different permeabilities.

6. The method for fine characterization of the flow boundary of a single well in a heterogeneous reservoir based on a starting pressure gradient zoning model according to claim 1, characterized in that, The method for calculating the limiting flow distance mentioned in step S5 is as follows: Using the target well point as the origin, along the preset angle direction Establish the ray path and solve for the limiting distance. This makes the integral of the starting pressure gradient along this path equal to the production pressure differential: in, This is the difference between formation pressure and bottom hole flowing pressure. It is the azimuth angle. Distance from well point on the ray path The actual starting pressure gradient value at the location.

7. The method for fine characterization of the flow boundary of a single well in a heterogeneous reservoir based on a starting pressure gradient zoning model according to claim 1, characterized in that, It also includes step S7: using the obtained effective flow boundary of an irregular single well to guide the deployment of the well network.

8. The method for fine characterization of the flow boundary of a single well in a heterogeneous reservoir based on a starting pressure gradient zoning model according to claim 7, characterized in that, The well network deployment method is as follows: deploy additional wells in the blank areas not covered by the effective flow boundaries of irregular single wells of multiple adjacent wells; or, adjust the direction of the injection and production well rows according to the major and minor axis directions of the effective flow boundaries of irregular single wells.

9. The method for fine characterization of the flow boundary of a single well in a heterogeneous reservoir based on a starting pressure gradient zoning model according to claim 1, characterized in that, It also includes the step of: dynamic capacity evaluation of low-permeability condensate gas reservoir-type underground gas storage facilities. The evaluation method is as follows: Define the oil saturation at different production stages, including: Stage A: oil saturation at the initial stage of tank construction; Stage B: oil saturation after a set operating time. Calculate the starting pressure gradient after saturation correction for each stage; Set the allowable production pressure difference for injection and extraction operations, back-calculate the effective flow boundary, and conduct dynamic evaluation of reservoir capacity.

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