Method for analyzing productivity of horizontal well of deep tight oil reservoir

Abstract

The invention discloses a method for analyzing the productivity of a horizontal well of a deep tight oil reservoir, and belongs to the technical field of deep tight oil reservoir development. The method comprises the following steps: establishing a nonlinear seepage parameter characterization model; condition assumption; after condition hypothesis is completed, an oil-gas phase seepage mathematical model based on linear flow hypothesis is established, and the reservoir fracture and matrix area is divided into an artificial fracture area, a transformed area and an untransformed area; introducing a nonlinear seepage parameter characterization model into the artificial fracture area, the transformed area and the untransformed area to construct a mass conservation equation of each phase of each area; and solving according to the constructed mass conservation equation to obtain the horizontal well productivity of the deep tight oil reservoir. According to the analysis method for the horizontal well productivity of the deep tight oil reservoir, the nonlinear seepage characteristics of the deep tight oil reservoir are considered on the whole, and rapid quantitative prediction of the oil-gas two-phase yield of the production well is achieved in combination with an ordinary differential equation numerical solution method, so that compared with traditional oil reservoir numerical simulation, the analysis method is faster and more accurate.

Description

Technical Field

[0001] This invention relates to the field of deep tight oil reservoir development technology, and specifically to an analytical method for the productivity of horizontal wells in deep tight oil reservoirs. Background Technology

[0002] In the past, when developing low-permeability oil reservoirs, the horizontal well volumetric fracturing method was often used. Horizontal wells have a much larger drainage area than vertical wells, and the artificial fractures formed after volumetric fracturing can serve as channels for crude oil flow, further improving the production capacity of oil wells.

[0003] In 1981, Cinco-Ley et al. proposed a bilinear flow model, which for the first time assumed a bilinear flow process for crude oil in a vertical well in an infinitely large reservoir with vertical fractures. In this model, the flow process is divided into radial flow in the formation and flow in the fractures, with the fractures possessing infinite conductivity. In 1986, Harrington et al., building upon Cinco-Ley et al.'s bilinear flow model for a fractured vertical well in an infinitely large reservoir, considered actual field conditions and modified the infinite conductivity of the fractures to represent infinite conductivity, thus improving the bilinear flow model. Also in 1986, Lee and Brock-enbrough first proposed a trilinear flow model, studying the trilinear flow model for vertically fractured wells with finite conductivity under infinitely large reservoir conditions. In 2009, Ozkan et al. applied a trilinear flow model to volumetric fractured horizontal wells. By comparing it with the semi-analytical pressure of trilinear flow obtained by Medeiros et al. in 2008, the correctness of the trilinear model was verified by the fit between the pressure and its derivative curve at the beginning of the intermediate flow. However, the model did not consider the effects of nonlinearity and the initiation pressure gradient. In 2010, Liu Yongliang et al. combined the seepage characteristics of vertically fractured wells in dual-medium reservoirs with the Warrant-Root model, considering the influence of the initiation pressure gradient, and established a mathematical model of bilinear flow in low-permeability dual-medium reservoirs. However, they did not apply it to fractured horizontal wells. In 2011, Yao Jun applied a trilinear flow model to fractured horizontal wells, where region I represents linear flow in the formation parallel to the artificial fractures, region II represents linear flow between fractures, and region III represents linear flow within the artificial fractures. The new model considered the influence of the initiation pressure gradient and solved the mathematical model of trilinear flow seepage in fractured horizontal wells under unstable conditions. The bottom hole pressure was obtained using Laplace transform and Stehfest numerical inversion. In 2013, M. Cossio et al. conducted rigorous analysis and numerical studies on the fractal diffusion equation (FDE), showing that it was more accurate than the classical linear and radial diffusion equations. Therefore, they combined the trilinear flow model with the fractal diffusion equation and ultimately derived a semi-analytical solution for flow in vertical fractures with finite conductivity. In 2022, Cao Renyi et al. applied the trilinear flow model to a volumetrically fractured horizontal well in a tight oil reservoir, considering the flow of the oil and gas two phases under dissolved gas drive conditions. They combined the mass balance equation and Newton's iteration method to solve for the three-zone pressure and oil and gas two-phase saturation at different times, obtaining a semi-analytical solution for the productivity of the oil and gas two phases in the tight oil reservoir. The model considered the influence of the starting pressure gradient but did not consider the influence of nonlinear seepage. Also in 2022, Tang Bin divided the flow process of crude oil in a tight oil reservoir into a matrix zone, an SRV zone, and an artificial fracture zone, establishing a volumetrically fractured horizontal well oil and gas two-phase model for tight oil reservoirs. The semi-analytical solution of the model was obtained using the Musketeer method and the steady-state successive substitution method.

[0004] Since its inception, the trilinear flow model has been widely used in fracturing vertical and horizontal wells in low-permeability reservoirs. The three flow processes are not entirely the same due to the different characteristics of each model. However, there are few examples of its application in tight reservoirs, and most of them do not consider the influence of nonlinear seepage.

[0005] Deep tight oil reservoirs exhibit the characteristics of "1 many, 2 strong, 3 high, and 4 low": namely, multiple lithological superpositions, strong rock mass deformation and fluid-structure interaction, high temperature-high pressure-high stress, belonging to ultra-low porosity and ultra-low permeability reservoirs, low recovery rate, and low reserve abundance; high-angle natural fractures are well-developed, and heterogeneity is strong. The complex multi-medium environment makes the seepage characteristics of deep tight oil reservoirs unclear and the seepage laws difficult to grasp, resulting in a lack of theoretical guidance for the development of deep tight oil reservoirs, which is still in the exploratory stage.

[0006] The development and exploration of deep tight oil reservoirs employs complex well types and complex fracturing processes, making it difficult to evaluate the productivity of development wells with different well types (vertical wells, highly deviated wells, horizontal wells) and different fracturing modes (multi-stage fracturing, multi-stage multi-cluster fracturing, volumetric fracturing). Summary of the Invention

[0007] The purpose of this invention is to provide an analytical method for the productivity of horizontal wells in deep tight oil reservoirs, which can solve the technical problem of the difficulty in predicting the productivity of existing horizontal wells in deep tight oil reservoirs.

[0008] To achieve the above objectives, one embodiment of the present invention provides a method for analyzing the productivity of horizontal wells in deep tight oil reservoirs, comprising the following steps:

[0009] Establish a nonlinear seepage parameter characterization model;

[0010] Conditional assumptions;

[0011] After the conditional assumptions are completed, a mathematical model of oil and gas phase seepage based on the linear flow assumption is established, and the reservoir fracture and matrix regions are divided into artificial fracture zone, stimulated zone and unstimulated zone.

[0012] Nonlinear seepage parameter characterization models were introduced in the artificial fracture zone, the modified zone, and the unmodified zone to construct the mass conservation equations for each phase in each region.

[0013] The productivity of horizontal wells in deep tight oil reservoirs is obtained by solving the constructed mass conservation equation.

[0014] One preferred embodiment of the present invention is that the nonlinear seepage parameter characterization model includes a stress-sensitive characterization model of the matrix and matrix-cracks, and a characterization model of the matrix's initiation pressure gradient.

[0015] One preferred embodiment of the present invention is as follows: the method for establishing the stress-sensitive characterization model of the matrix and matrix-fracture and the initiation pressure gradient characterization model of the matrix is ​​as follows: on-site sampling, preparation of matrix and matrix-fracture cores, permeability stress-sensitive experiments and initiation pressure gradient experiments are carried out, and then the experimental data are fitted to obtain the expression for permeability and pressure.

[0016] One preferred embodiment of the present invention includes the following assumptions:

[0017] (1) The reservoir is a horizontal homogeneous and uniformly thick stratum, and anisotropy is not considered;

[0018] (2) The original fluid in the reservoir was a two-phase mixture of oil and gas;

[0019] (3) Consider the limited flow of the fracture and ensure that the initial permeability, porosity and compressibility of each fracture are consistent.

[0020] (4) Ignoring the effects of gravity and capillary force, the fluid undergoes isothermal Darcy flow in the matrix and cracks;

[0021] (5) Stress sensitivity exists in the reservoir fracture zone, stimulated zone, and unstimulated zone;

[0022] (6) The pressure gradient for both unmodified and modified areas should be considered.

[0023] One preferred embodiment of the present invention establishes a mathematical model for oil-gas phase seepage based on the linear flow assumption, comprising the following steps:

[0024] Determine the dynamic sweep range of the horizontal well;

[0025] The reservoir fracture and matrix region is divided into artificial fracture zone, stimulated zone, and unstimulated zone;

[0026] The flow states in the artificial fracture zone, the modified zone, and the unmodified zone were analyzed, and flow equations for the gas and oil phases that relate flow rate and pressure in each zone were constructed.

[0027] One preferred embodiment of the present invention provides a formula for determining the dynamic sweep range of a horizontal well as follows:

[0028]

[0029] A = 4x f y doi ;

[0030] In the formula, y doi Let η be the sweep distance of a single-phase flow reservoir, η be the single-phase flow pressure conductivity, and k be the single-phase flow pressure conductivity. m φ represents the matrix permeability. m Where μ is the matrix porosity, C is the fluid viscosity, and μ is the fluid viscosity. tm α is the overall compression coefficient.cp The value is 2.45, where t is the well production time, A is the dynamic sweep range of the horizontal well, and x is the value of t. f The length of the crack is half its length.

[0031] One preferred embodiment of the present invention analyzes the flow states in the artificially fractured zone, the modified zone, and the unmodified zone, and constructs flow equations for the gas and oil phases that relate flow rate and pressure in each zone, including:

[0032] Define the flow between regions:

[0033] From the artificial fracture zone to the bottom of the well:

[0034] From the modified area to the artificial crack area:

[0035] From unrenovated area to renovated area:

[0036] In the formula, q is the fluid flow rate; The pressure represents the average pressure in each zone. The subscript α represents the oil and gas phases, the subscript f represents the artificially fractured zone, the subscript EFR represents the modified zone, the subscript NSR represents the unmodified zone, T represents the oil and gas conductivity coefficients, and m represents the average pressure in each zone. pg p is a pressure-related mass parameter. wf For hydraulic pressure;

[0037] The oil and gas conductivity coefficients are shown in the following formulas:

[0038]

[0039] In the formula, T represents the transmission coefficients of the oil and gas components, T g,fe T is the gas phase conductivity coefficient. o,fe Let y be the oil phase conductivity coefficient. doi x represents the sweep distance of a single-phase flow reservoir. f For half the length of the crack, k rge k is the relative permeability of the gas phase. e For effective penetration rate, k represents thickness or height. roe R represents the relative permeability of the oil phase. se For an effective gasoline-to-water ratio, R ve For the effective pore volume dissolved gas-oil ratio, B oe μ is the oil phase volume factor. oe B is the viscosity of the oil phase. ge μ is the gas phase volume coefficient. ge This refers to the viscosity of the gas phase.

[0040] The pressure-related mass parameters are shown in the following formula:

[0041]

[0042] In the formula, k pi Permeability under initial pressure conditions, μ o The viscosity of the oil phase is μ. g B is the viscosity of the gas phase. o Z is the volume factor of the oil phase. p The compressibility coefficient of the gas;

[0043] The permeability modulus is defined as:

[0044] The permeability of stress-sensitive large-scale cracks is:

[0045] In the formula, γ is the reservoir and fracture permeability modulus, and k i p represents the initial permeability of each region. i denoted as the initial pressure, and p as the pressure value measured at any given time.

[0046] One preferred embodiment of the present invention is that the initial condition of the oil-gas phase seepage mathematical model based on the linear flow assumption is that each region maintains its original pressure and original saturation before production.

[0047] In one preferred embodiment of the present invention, when considering the startup pressure gradient, the average pressure gradient of each partition at each time step is calculated using the following formula and compared with the proposed startup pressure gradient:

[0048] ΔP g =(P NSR , t -P EFR,t ) / y doi ;

[0049] ΔP g =(P EFR,t -P f,t ) / y doi ;

[0050] In the formula, ΔP g P represents the average pressure gradient of the zone. a，t The average pressure of different zones at different time steps is given, with subscript f representing the artificially fractured zone, subscript EFR representing the modified zone, and subscript NSR representing the unmodified zone. doi This represents the sweep distance of a single-phase flow reservoir.

[0051] In one preferred embodiment of the present invention, when the average pressure gradient is less than or equal to the proposed start-up pressure gradient, the unmodified zone cannot be utilized, and the pressure and saturation from the previous time step are used; when the average pressure gradient is greater than the proposed start-up pressure, mass transfer proceeds to the next zone, with the sweep distance minus the obstruction distance, as shown in the following formula:

[0052] lα =(k NSR , i / μ α,EFR,i )×λ×y doi ×t

[0053] In the formula, l α Let λ be the resistance distance, λ be the proposed initiation pressure gradient, and y be the resistance distance. doi k represents the sweep distance of a single-phase flow reservoir. NSR，i The permeability of the unmodified zone is μ, where t is time. α,EFR,i The viscosity of the modified zone.

[0054] In one preferred embodiment of the present invention, the mass conservation equations for each phase in each region are as follows:

[0055]

[0056] In the formula, n is the number of fractures, N is the final productivity of the horizontal well, q is the fluid flow rate; subscript α refers to the oil and gas two phases, subscript f is the artificial fracture zone, subscript EFR is the stimulated zone, subscript NSR is the unstimulated zone, B is the volume factor, and x f For half the length of the crack, w f Where φ is the crack width, h is the thickness or height, φ is the porosity, and S is the saturation. Let A be the average saturation, Δt be the time difference between the initial time and any subsequent time point, and A be the average saturation. f The dynamic sweep range of a horizontal well.

[0057] In summary, the beneficial effects of the present invention are as follows:

[0058] 1. The method for analyzing the productivity of horizontal wells in deep tight oil reservoirs in this invention adopts a semi-analytical approach. Based on a three-zone linear seepage theory model, it considers the stress-sensitive changes and starting pressure during the development of deep tight oil reservoirs, further refining the nonlinear seepage models of the fracture zone, the stimulated zone, and the unstimulated zone. In the unstimulated zone, the crude oil flow considers the starting pressure gradient; in the stimulated zone, seepage is affected by the starting pressure gradient and stress sensitivity; and in the fracture zone, the pressure drop is significant and stress sensitivity cannot be ignored. This method discretizes time and couples the three zones using the mass balance equation to obtain the average pressure and water saturation of each zone at different time steps, achieving time-shifted updates of the dynamic productivity model.

[0059] 2. The method for analyzing the production capacity of horizontal wells in deep tight oil reservoirs in this invention takes into account the nonlinear seepage characteristics of deep tight oil reservoirs and combines the numerical solution method of ordinary differential equations to realize the rapid quantitative prediction of the two-phase production of oil and gas in production wells. Therefore, it is faster and more accurate than traditional reservoir numerical simulation.

[0060] 3. The method for analyzing the productivity of horizontal wells in deep tight oil reservoirs in this invention establishes a mathematical model of oil and gas phase seepage based on the linear flow assumption, and divides the reservoir fracture and matrix region into three regions: artificial fracture zone, modified zone, and unmodified zone. Nonlinear seepage parameter characterization models are introduced in each of the three regions to characterize the nonlinear seepage parameters, making the results more reliable and convincing. Attached Figure Description

[0061] Figure 1 This is a flowchart illustrating the method for analyzing the productivity of horizontal wells in deep tight oil reservoirs according to the present invention.

[0062] Figure 2 This is a schematic diagram of reservoir zoning in the method for analyzing the productivity of horizontal wells in deep tight oil reservoirs according to the present invention;

[0063] Figure 3 This is a pressure saturation diagram at different time steps in the method for analyzing the productivity of horizontal wells in deep tight oil reservoirs according to the present invention.

[0064] Figure 4 This is a verification diagram of the daily oil production of well 37520 in Example 1 of the present invention.

[0065] Among them, 1-artificial crack area, 2-modified area, 3-unmodified area. Detailed Implementation

[0066] To make the objectives, technical solutions, and advantages of the embodiments of this disclosure clearer, the technical solutions of the embodiments of this disclosure will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are only some embodiments of this disclosure, and not all embodiments. Based on the embodiments of this disclosure, all other embodiments obtained by those skilled in the art without creative effort are within the scope of protection of this disclosure.

[0067] This invention provides a method for analyzing the productivity of horizontal wells in deep tight oil reservoirs, such as... Figure 1 As shown, it includes the following steps:

[0068] Step (1): Establish a nonlinear seepage parameter characterization model; specifically, the nonlinear seepage parameter characterization model includes a stress-sensitive characterization model of the matrix and matrix-crack and a starting pressure gradient characterization model of the matrix. The stress-sensitive characterization model of the matrix and matrix-crack is to fit the experimental data with a power function, and the starting pressure gradient characterization model of the matrix is ​​to fit the experimental data linearly.

[0069] The method for establishing this is as follows: mainly through field sampling, preparation of matrix and matrix-fracture cores in the laboratory, conducting permeability stress sensitivity experiments and initiation pressure gradient experiments, and then fitting the experimental data to obtain the expression for permeability versus pressure; conducting nonlinear seepage experiments on different media types to characterize nonlinear seepage parameters, the results are more reliable and convincing; stress sensitivity refers to the phenomenon that when reservoir pressure changes, the rock skeleton deforms, causing a decrease in reservoir permeability; the initiation pressure gradient refers to an additional pressure gradient that fluid must overcome when seeping in a low-permeability reservoir. This pressure gradient is generated by the resistance caused by the adsorption film or hydration film on the rock surface. Only when the driving pressure gradient exceeds this initiation pressure gradient can the formation fluid begin to flow. Both are functions of pressure, and changes in pressure will cause changes in production capacity;

[0070] Step (2): Conditional assumptions; specifically including:

[0071] ①The reservoir is a horizontal, homogeneous, and uniformly thick stratum, and anisotropy is not considered;

[0072] ②The original fluid within the reservoir consisted of two phases: oil and gas.

[0073] ③Consider the limited conductivity of the fractures and ensure that the initial permeability, porosity, and compressibility of each fracture remain consistent;

[0074] ④ Ignoring the effects of gravity and capillary forces, the fluid undergoes isothermal Darcy flow in the matrix and cracks;

[0075] ⑤ The reservoir fracture zone, the stimulated zone 2, and the unstimulated zone 3 all exhibit a certain degree of stress sensitivity;

[0076] ⑥ Consider activating the pressure gradient in unmodified zone 3 and modified zone 2;

[0077] Step (3): After the condition assumptions are completed, a mathematical model of oil and gas phase seepage based on the linear flow assumption is established, and the reservoir fracture and matrix regions are divided into artificial fracture zone 1, modified zone 2 and unmodified zone 3.

[0078] The establishment of a mathematical model for oil and gas phase seepage based on the linear flow assumption includes the following steps:

[0079] Step (301): Determine the dynamic sweep range of the horizontal well;

[0080] In tight and shale reservoirs, due to poor reservoir properties and low permeability, the pressure propagation velocity is much lower than in conventional reservoirs. Therefore, to clarify the reservoir utilization range at different stages, scholars have proposed the concept of Dynamic Sweep Distance (DDA) from the well testing concept. Behmanesh et al. derived a theoretical formula for the sweep distance (DOI) of single-phase flow reservoirs based on the linear flow assumption. DOI is a direct function of reservoir rock and fluid properties. When the flow pressure is constant, DOI can be written as follows:

[0081]

[0082] In the formula, y doi Let η be the sweep distance of a single-phase flow reservoir, η be the single-phase flow permeability coefficient, and k be the single-phase flow permeability coefficient. m φ represents the matrix permeability. m Where μ is the matrix porosity, C is the fluid viscosity, and μ is the fluid viscosity. tm α is the overall compression coefficient. cp The value is 2.45, where t is the oil well production time;

[0083] The DOI equation is a key component of the DDA concept. The DOI equation can be used to estimate the distance to the reservoir boundary, thereby estimating the dynamic sweep range at any given time, as shown in the following equation:

[0084] A = 4x f y doi ;

[0085] In the formula, A represents the dynamic sweep range of the horizontal well, and y doi x represents the sweep distance of a single-phase flow reservoir. f The length of the crack is half its length;

[0086] Step (302): As Figure 2 As shown, the reservoir fracture and matrix region is divided into artificial fracture zone 1, stimulated zone 2, and unstimulated zone 3. Specifically, the reservoir fracture and matrix region can be divided into three parts: artificial fracture zone 1 (PHF), stimulated zone 2 (EFR), and unstimulated zone 3 (NSR). Due to the high permeability of the fractures, it is assumed from the beginning of production that the flow pattern within the fractures is boundary-dominated flow. For the flow inside the reservoir, the first flow pattern is linear flow within the stimulated zone. When the sweep distance reaches the boundary of the stimulated zone, boundary-dominated flow initiates in the stimulated zone, and the matrix region begins to flow towards the stimulated zone.

[0087] Step (303): Analyze the flow state of artificial fracture zone 1, modified zone 2 and unmodified zone 3, and construct flow equations for the gas phase and oil phase that relate flow rate and pressure in each zone;

[0088] Specifically, such as Figure 3As shown, to calculate the average pressure and saturation at each time step, the two-phase linear flow productivity exponential equation and the mass conservation equation are coupled and solved iteratively to achieve rapid calculation of the production of each phase in the oil well. The flow equations for the gas and oil phases used to relate the flow rates and pressures in the fractured zone (subscript f), the modified zone 2 (subscript EFR), and the unmodified zone 3 (subscript NSR) are as follows:

[0089] Define the flow between regions:

[0090] Artificial fracture zone 1 to the bottom of the well:

[0091] From renovation zone 2 to artificial crack zone 1:

[0092] From unrenovated area 3 to renovated area 1:

[0093] In the formula, q is the fluid flow rate; The average pressure for each zone is given by the subscript α, which represents the oil and gas phases; the subscript f represents artificial fracture zone 1; the subscript EFR represents modified zone 2; the subscript NSR represents unmodified zone 3; T represents the oil and gas conductivity coefficients; and m represents the average pressure for each zone. pg p is a pressure-related mass parameter. wf For hydraulic pressure;

[0094] Based on the quasi-steady-state linear flow assumption, the transmission coefficients for each region can be obtained. The transmission coefficients for oil and gas are shown in the following equations:

[0095]

[0096] In the formula, T represents the transmission coefficients of the oil and gas components, T g,fe T is the gas phase conductivity coefficient. o,fe Let y be the oil phase conductivity coefficient. doi x represents the sweep distance of a single-phase flow reservoir. f For half the length of the crack, k rge k is the relative permeability of the gas phase. e For effective penetration rate, k represents thickness or height. roe R represents the relative permeability of the oil phase. se For an effective gasoline-to-water ratio, R ve For the effective pore volume dissolved gas-oil ratio, B oe μ is the oil phase volume factor. oe B is the viscosity of the oil phase. ge μ is the gas phase volume coefficient. ge This refers to the viscosity of the gas phase.

[0097] Pressure-related mass parameters, i.e., pressure-related rock and fluid properties, are shown in the following formula:

[0098]

[0099] In the formula, k pi Permeability under initial pressure conditions, μ o The viscosity of the oil phase is μ. g B is the viscosity of the gas phase. o Z is the volume factor of the oil phase. p The compressibility coefficient of the gas;

[0100] The permeability of each region is a function of pressure. For permeability stress-sensitive treatment, the permeability modulus is first defined as:

[0101] After introducing the permeability modulus, the permeability of stress-sensitive large-scale fractures is:

[0102] In the formula, γ is the reservoir and fracture permeability modulus, in MPa. -1 ;k i Let mD and p be the initial permeability of each region. i denoted as the initial pressure, and p as the pressure value measured at any given time.

[0103] The initial condition for the mathematical model of oil and gas phase seepage based on the linear flow assumption is that each region maintains its original pressure and original saturation before production:

[0104]

[0105] In the formula, the unknowns are the oil and water saturation (s) and average pressure (p) of each region. The subscript f refers to the artificial fracture zone 1, the subscript EFR refers to the modified zone 2, and the subscript NSR refers to the unmodified zone 3. There are three sets of equations in each region. The number of equations is equal to the number of unknowns. The model is closed-loop.

[0106] When considering the startup pressure gradient, the average pressure gradient of each partition at each time step is calculated using the following formula and compared with the proposed startup pressure gradient:

[0107] ΔP g =(P NSR , t -P EFR,t ) / y doi ;

[0108] ΔP g =(P EFR,t -P f,t ) / y doi ;

[0109] In the formula, ΔP g P represents the average pressure gradient of the zone. a ,t This represents the average pressure in different zones at different time steps. The subscript f indicates the artificially fractured zone, the subscript EFR indicates the modified zone, and the subscript NSR indicates the unmodified zone. doi This refers to the sweep distance of a single-phase flow reservoir.

[0110] When the average pressure gradient is less than or equal to the proposed start-up pressure gradient, unmodified zone 3 cannot be used; the pressure and saturation from the previous time step should continue to be used. When the average pressure gradient is greater than the proposed start-up pressure, mass transfer can proceed to the next zone, but the affected distance should be reduced by the obstruction distance caused by considering the start-up pressure gradient, i.e.:

[0111] l α =(k NSR，i / μ α,EFR,i )×λ×y doi ×t

[0112] In the formula, l α Let λ be the resistance distance, λ be the proposed initiation pressure gradient, and y be the resistance distance. doi k represents the sweep distance of a single-phase flow reservoir. NSR，i The permeability of the unmodified zone is μ, where t is time. α,EFR,i The viscosity of the modified zone;

[0113] Step (4): In the artificial crack zone 1, the modified zone 2 and the unmodified zone 3, a nonlinear seepage parameter characterization model is introduced to construct the mass conservation equations of each phase in each region;

[0114] The mass conservation equations for each phase in each region are as follows:

[0115]

[0116] In the formula, n is the number of fractures, N is the final productivity of the horizontal well, q is the fluid flow rate; subscript α refers to the oil and gas two phases, subscript f is the artificial fracture zone, subscript EFR is the stimulated zone, subscript NSR is the unstimulated zone, B is the volume factor, and x f For half the length of the crack, w f Where φ is the crack width, h is the thickness or height, φ is the porosity, and S is the saturation. Let A be the average saturation, Δt be the time difference between the initial time and any subsequent time point, and A be the average saturation. f The dynamic sweep range of a horizontal well;

[0117] Step (5): Solve the constructed mass conservation equation to obtain the production capacity of horizontal wells in deep tight oil reservoirs.

[0118] Example 1

[0119] This paper predicts the production output of a volumetric fractured horizontal well (well 37520) in a deep tight oil reservoir of a certain oilfield. Reservoir properties and fracture parameters are substituted into the model. Reservoir properties are shown in Table 1, and fracture parameters are shown in Table 2. The model results are then compared with actual production results. Figure 4 As shown.

[0120] Table 1 Reservoir physical properties

[0121]

[0122]

[0123] Table 2 Crack Parameters

[0124]

[0125]

[0126] from Figure 4 As can be seen from the data, the data predicted by the model in the method for analyzing the productivity of horizontal wells in deep tight oil reservoirs in this invention are basically consistent with the actual production data, thus demonstrating that the productivity results obtained by the method for analyzing the productivity of horizontal wells in this invention are reliable, accurate, and convincing.

[0127] The embodiments described above are merely preferred embodiments of the present invention and are not intended to limit the scope of the present invention. Various modifications and improvements made by those skilled in the art to the technical solutions of the present invention without departing from the spirit of the present invention should fall within the protection scope defined by the claims of the present invention.

Claims

1. A method for analyzing the productivity of horizontal wells in deep tight oil reservoirs, characterized in that, Includes the following steps: Establish a nonlinear seepage parameter characterization model; Conditional assumptions; After the conditional assumptions are completed, a mathematical model of oil and gas phase seepage based on the linear flow assumption is established, and the reservoir fracture and matrix regions are divided into artificial fracture zone, stimulated zone and unstimulated zone. Nonlinear seepage parameter characterization models were introduced in the artificial fracture zone, the modified zone, and the unmodified zone to construct the mass conservation equations for each phase in each region. The productivity of horizontal wells in deep tight oil reservoirs is obtained by solving the constructed mass conservation equation.

2. The method for analyzing the productivity of horizontal wells in deep tight oil reservoirs as described in claim 1, characterized in that: The nonlinear seepage parameter characterization model includes a stress-sensitive characterization model of the matrix and matrix-cracks, as well as a characterization model of the matrix's initiation pressure gradient.

3. The method for analyzing the productivity of horizontal wells in deep tight oil reservoirs as described in claim 2, characterized in that, The method for establishing the stress sensitivity characterization model of the matrix and matrix-fracture and the initiation pressure gradient characterization model of the matrix is ​​as follows: take samples in the field, prepare matrix and matrix-fracture cores, conduct permeability stress sensitivity experiments and initiation pressure gradient experiments, and then fit the experimental data to obtain the expression for permeability and pressure.

4. The method for analyzing the productivity of horizontal wells in deep tight oil reservoirs as described in claim 1, characterized in that, The conditions and assumptions include: (1) The reservoir is a horizontal homogeneous and uniformly thick stratum, and anisotropy is not considered; (2) The original fluid in the reservoir was a two-phase mixture of oil and gas; (3) Consider the limited flow of the fracture and ensure that the initial permeability, porosity and compressibility of each fracture are consistent. (4) Ignoring the effects of gravity and capillary force, the fluid undergoes isothermal Darcy flow in the matrix and cracks; (5) Stress sensitivity exists in the reservoir fracture zone, stimulated zone, and unstimulated zone; (6) The pressure gradient should be considered for both unmodified and modified areas.

5. The method for analyzing the productivity of horizontal wells in deep tight oil reservoirs as described in claim 1, characterized in that, The establishment of a mathematical model for oil and gas phase seepage based on the linear flow assumption includes the following steps: Determine the dynamic sweep range of the horizontal well; The reservoir fracture and matrix region is divided into artificial fracture zone, stimulated zone, and unstimulated zone; The flow states in the artificial fracture zone, the modified zone, and the unmodified zone were analyzed, and flow equations for the gas and oil phases that relate flow rate and pressure in each zone were constructed.

6. The method for analyzing the productivity of horizontal wells in deep tight oil reservoirs as described in claim 5, characterized in that, The formula for determining the dynamic sweep range of a horizontal well is as follows: A=4x f y doi ; In the formula, y doi Let η be the sweep distance of a single-phase flow reservoir, η be the single-phase flow pressure conductivity, and k be the single-phase flow pressure conductivity. m φ represents the matrix permeability. m Where μ is the matrix porosity, C is the fluid viscosity, and μ is the fluid viscosity. tm The overall compression coefficient, α cp The value is 2.45, where t is the well production time, A is the dynamic sweep range of the horizontal well, and x is the value of t. f The length of the crack is half its length.

7. The method for analyzing the productivity of horizontal wells in deep tight oil reservoirs as described in claim 5, characterized in that, The analysis examines the flow states in the artificially fractured zone, the modified zone, and the unmodified zone, constructing flow equations for the gas and oil phases that relate flow rate to pressure in each region, including: Define the flow between regions: From the artificial fracture zone to the bottom of the well: From the modified area to the artificial crack area: From unrenovated area to renovated area: In the formula, q is the fluid flow rate; The pressure represents the average pressure in each zone. The subscript α represents the oil and gas phases, the subscript f represents the artificially fractured zone, the subscript EFR represents the modified zone, the subscript NSR represents the unmodified zone, T represents the oil and gas conductivity coefficients, and m represents the average pressure in each zone. pg p is a pressure-related mass parameter. wf For hydraulic pressure; The oil and gas conductivity coefficients are shown in the following formulas: In the formula, T represents the transmission coefficients of the oil and gas components, T g,fe T is the gas phase conductivity coefficient. o,fe Let y be the oil phase conductivity coefficient. doi x represents the sweep distance of a single-phase flow reservoir. f For half the length of the crack, k rge k is the relative permeability of the gas phase. e For effective penetration rate, k represents thickness or height. roe R represents the relative permeability of the oil phase. se For an effective gasoline-to-water ratio, R ve For the effective pore volume dissolved gas-oil ratio, B oe μ is the oil phase volume factor. oe B is the viscosity of the oil phase. ge μ is the gas phase volume coefficient. ge This refers to the viscosity of the gas phase. The pressure-related mass parameters are shown in the following formula: In the formula, k pi Permeability under initial pressure conditions, μ o The viscosity of the oil phase is μ. g B is the viscosity of the gas phase. o Z is the volume factor of the oil phase. p The compressibility coefficient of the gas; The permeability modulus is defined as: The permeability of stress-sensitive large-scale cracks is: In the formula, γ is the reservoir and fracture permeability modulus, and k i p represents the initial permeability of each region. i denoted as the initial pressure, and p as the pressure value measured at any given time.

8. The method for analyzing the productivity of horizontal wells in deep tight oil reservoirs as described in claim 5, characterized in that, The initial condition for the oil and gas phase seepage mathematical model based on the linear flow assumption is that each region maintains its original pressure and original saturation before production.

9. The method for analyzing the productivity of horizontal wells in deep tight oil reservoirs as described in claim 5, characterized in that: When considering the startup pressure gradient, the average pressure gradient of each partition at each time step is calculated using the following formula and compared with the proposed startup pressure gradient: ΔP g =(P NSR , t -P EFR,t ) / y doi ; ΔP g =(P EFR,t -P f,t ) / y doi ; In the formula, ΔP g P represents the average pressure gradient of the zone. a , t The average pressure of different zones at different time steps, with subscript f for artificially fractured zones, subscript EFR for modified zones, and subscript NSR for unmodified zones, y doi This represents the sweep distance of a single-phase flow reservoir.

10. The method for analyzing the productivity of horizontal wells in deep tight oil reservoirs as described in claim 9, characterized in that: When the average pressure gradient is less than or equal to the proposed start-up pressure gradient, the unmodified zone cannot be used, and the pressure and saturation from the previous time step are adopted; when the average pressure gradient is greater than the proposed start-up pressure, mass transfer proceeds to the next zone, with the sweep distance minus the barrier distance, as shown in the following formula: l α =(k NSR，i / m α,EFR,i )×λ×y doi ×t In the formula, l α Let λ be the resistance distance, λ be the proposed initiation pressure gradient, and y be the resistance distance. doi k represents the sweep distance of a single-phase flow reservoir. NSR，i The permeability of the unmodified zone is μ, where t is time. α,EFR,i The viscosity of the modified zone.

11. The method for analyzing the productivity of horizontal wells in deep tight oil reservoirs as described in claim 1, characterized in that, The mass conservation equations for each phase in each region are as follows: In the formula, n is the number of fractures, N is the final productivity of the horizontal well, q is the fluid flow rate; subscript α refers to the oil and gas two phases, subscript f is the artificial fracture zone, subscript EFR is the stimulated zone, subscript NSR is the unstimulated zone, B is the volume factor, and x f For half the length of the crack, w f Where φ is the crack width, h is the thickness or height, φ is the porosity, and S is the saturation. Let A be the average saturation, Δt be the time difference between the initial time and any subsequent time point, and A be the average saturation. f The dynamic sweep range of a horizontal well.

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