Method for determining length of fractured cracks of different flow conductivity in condensate gas reservoir by pressure measurement

Abstract

The application relates to a method for judging the lengths of different flow conductivity fractures of a condensate gas reservoir by pressure measurement, comprising the following steps: establishing a physical model and a mathematical model of the condensate gas reservoir, drawing a typical curve of well testing of a multi-section gas production uneven fracturing well of the condensate gas reservoir, and dividing five flow stages; comparing the typical curve of well testing of the multi-section gas production uneven fracturing well of the condensate gas reservoir with a typical curve of well testing of a conventional uniform flow fracture model, judging a linear flow interference stage by using the physical model and the mathematical model of the condensate gas reservoir, fitting pressure history data, and explaining and evaluating reservoir and fracture parameters; and judging the lengths of the fractures with different flow conductivities of the condensate gas reservoir according to the explanation and evaluation. The method has important guiding significance for correctly evaluating the effect of fracturing measures, adjusting the next step work of the condensate gas reservoir, and improving the yield of the condensate gas reservoir.

Description

Technical Field

[0001] This application relates to the field of condensate gas reservoir development technology, specifically to a method for determining the degree of reverse condensation in condensate gas wells using pressure measurement data from different stages. Background Technology

[0002] Hydrocarbon gases produced deep underground under high temperature and pressure conditions, upon reaching the surface, will condense into liquid petroleum due to the decrease in temperature and pressure. This liquid, light oil is called condensate oil, and the gas reservoir is called a condensate gas reservoir. Condensate gas reservoirs undergo corresponding phase changes with pressure variations, exhibiting a relatively complex seepage mechanism. During extraction, when pressure decreases, reverse condensation occurs, and the high-temperature, high-pressure characteristics of condensate gas seepage differ from the ideal gas law. Therefore, research on the seepage laws and well test analysis of condensate gas reservoirs is currently at the forefront of condensate gas reservoir development research, possessing significant theoretical challenges and depth.

[0003] Condensate gas reservoirs were discovered abroad as early as the early 1930s, and the earliest research on condensate gas seepage problems began in 1965. Currently, there is a wealth of foreign literature on well test analysis of condensate gas reservoirs. Most reservoir models only consider two-zone radial composite reservoirs, with representative zones being the near-wellbore condensate zone and the far-wellbore gas single-phase zone. However, laboratory researchers believe that based on different fluid mobility ratios, the reservoir can be divided into three zones: the far-wellbore liquid-condensate saturated zone; the intermediate zone, an oil-gas mixing zone where condensate saturation increases and gas mobility decreases; and the near-wellbore zone, where the high capillary number increases the relative permeability of the gas, leading to a recovery in gas mobility.

[0004] Conventional well test interpretation models for fractured wells include uniform flow fracture models, infinite conductivity fracture models, and finite conductivity fracture models. The uniform flow fracture model assumes fluid flows uniformly into the fracture, the infinite conductivity fracture model assumes an infinitely large fracture conductivity, and the finite conductivity fracture model assumes a constant conductivity along the fracture. However, in actual engineering, formation pressure drops and proppant rupture in the fractured fracture can lead to partial fracture closure, while residual fracturing fluid and perforation damage can cause reservoir damage near the fracture. Partial fracture closure and reservoir damage further lead to uneven fluid flow density into the fracture and uneven distribution of the fracture conductivity along the fracture, thus affecting the accuracy of well test interpretation. A new well test interpretation model for uneven fracture conductivity is established to determine the length of fractures with different conductivity in condensate gas reservoirs. Summary of the Invention

[0005] To address the aforementioned issues, the purpose of this application is to establish a well test interpretation model for multi-stage non-uniform gas production fractured wells in condensate gas reservoirs, based on conventional uniform flow fracture models, infinite conductivity fracture models, and finite conductivity fracture models, taking into account the three-phase flow of condensate gas reservoirs, and to calculate the length of fractures with different conductivity capacities.

[0006] To achieve the above objectives, this application adopts the following technical solution:

[0007] A method for determining the length of fracturing fractures with different conductivity in condensate gas reservoirs by pressure measurement includes:

[0008] Establish physical and mathematical models of condensate gas reservoirs, plot typical well test curves of fractured wells with uneven gas production in multiple stages of condensate gas reservoirs, and divide them into five flow stages;

[0009] By comparing the typical well test curves of fractured wells with uneven gas production in multi-stage fractures in condensate gas reservoirs with those of conventional uniform flow fracture models, the physical and mathematical models of condensate gas reservoirs are used to determine the stage of interference with linear flow. Pressure history data is fitted, and reservoir and fracture parameters are interpreted and evaluated.

[0010] The length of fractures with different conductivity in condensate gas reservoirs is determined based on the interpretation and evaluation.

[0011] The process of plotting typical well test curves for fractured wells with uneven gas production in multiple stages of condensate gas reservoirs includes: establishing an interpretation model for the uneven gas production in multiple stages of fractured wells in condensate gas reservoirs, solving for a semi-analytical solution, plotting typical well test curves, and conducting sensitivity factor analysis.

[0012] The dimensionless bottom hole pressure and pressure derivative response indicate that the well test curve of the fractured well with uneven gas production in multiple segments shows the presence of a flow stage. The flow stages are named the first interfering linear flow stage and the second interfering linear flow stage, and they show slowly rising lines with slopes of m1 and m2, respectively. When m1≠m2≠1 / 2, it is determined that the fracture has a multi-segment uneven gas production phenomenon. The parameters of the fracture segment are interpreted by analyzing the interfering linear flow stage and by fitting actual pressure measurement data.

[0013] The physical model for the non-uniform conductivity of fractures in laminar fracturing assumes the following: infinite horizontal displacement, isotropic, and a compressibility coefficient of C exists in the homogeneous reservoir. t And a fluid with viscosity μ; the crack penetrates completely from top to bottom, and the half-length of the crack is x. f Width w f Porosity φ f Overall compression ratio C fi ; Reservoir porous media permeability k, porosity φ, thickness h, initial pressure p i ; the crack half-length x f Divide into n segments: the half-length of the i-th crack segment xfi Conductivity C fi Gas production Oil and gas flow into the wellbore only through fractures; seepage in the reservoir follows Darcy's law and the effect of gravity is ignored.

[0014] Control equations for multi-stage non-uniform gas production and seepage in fractured wells

[0015]

[0016] Boundary conditions

[0017] ψ(x→∞,y→∞,t)=ψ i (2)

[0018] Initial conditions

[0019] ψ(x,y,t=0)=ψ i (3)

[0020] pseudo-pressure is defined as

[0021]

[0022] Dimensionless is defined as

[0023]

[0024] Considering no pressure drop along the wellbore, the pressure drop across the fracture and the skin effect are combined into a total skin effect s. f express

[0025]

[0026] Considering the absence of pressure drop along the wellbore, the pressure at the connection between the first fracture segment and the wellbore is treated as a dimensionless pseudo-bottom pressure. This yields the dimensionless pseudo-bottom pressure after considering the fracture skin in a fractured well with uneven gas production across multiple fracture segments:

[0027]

[0028] The dimensionless bottom hole pseudo-pressure after considering the well-reservoir effect is expressed as:

[0029]

[0030] Applying the Laplace transform to the above equation yields the dimensionless bottom hole pseudo-pressure in a fractured well with uneven gas production across multiple segments within the Laplace space, considering both the skin and reservoir layers:

[0031]

[0032] In well test analysis of condensate gas reservoirs, the pseudo-pressure method is mainly divided into three categories:

[0033] Single-phase gas simulated pressure

[0034]

[0035] Two-phase pressure

[0036] To describe the effects of two-phase flow, a two-phase pseudo-pressure function is defined using a method similar to that used for single-phase gas pseudo-pressure:

[0037]

[0038] Three areas are expected to face pressure.

[0039] Zone I:

[0040] Zone II:

[0041] Zone III:

[0042] In the formula,

[0043] p * —Pressure at the outer boundary of Zone I;

[0044] p d —Dew point pressure;

[0045] p0—Reference pressure;

[0046] S wi —Residual water saturation;

[0047] The outer boundary pressure p of region I * Equal to the dew point pressure of the production well fluid, which can be determined based on r s =1 / R p Sure;

[0048] By performing Stehfest inversion on equation (9) and considering the pseudo-pressure of the condensate gas reservoir, the solution of the interpretation model for the uneven gas production in multi-stage well testing of fractured wells in condensate gas reservoirs in real space can be obtained.

[0049] Typical well test curves for fractured wells with uneven oil production in multiple segments can be divided into six flow stages: the wellbore reservoir stage, where both pressure and pressure derivative are straight lines with a slope of 1; the transitional flow stage, where the wellbore reservoir seeps into the formation; the formation linear flow stage, where the pressure derivative curve is a straight line with a slope of 1 / 2; the first interfering formation linear flow stage, where the pressure derivative curve is a straight line with a slope of m1; the second interfering formation linear flow stage, where the pressure derivative curve is a straight line with a slope of m2 (m1≠m2≠1 / 2); and the system radial flow stage, where the pressure derivative curve is a horizontal segment with a slope of 0.5.

[0050] When both pressure and pressure derivative value change with x f1DWhen x increases with the increase of x f1D The increase means that the half length of the first crack segment x f1 The increase in x leads to a longer gas inflow into the first fracture segment, resulting in a longer duration of the linear flow phase and a delay in the linear flow phase of the first disturbed formation. The slope m1 of the straight segment characterizing the linear flow phase of the first disturbed formation changes with x. f1D x increases with the increase of x f1D It has no effect on either the linear flow stage of the second disturbing stratum or the radial flow stage of the system. f2D It has a significant impact only on the linear flow stages of the first and second disturbed formations. The pressure derivative curves for the early and late stages at different values ​​overlap. A comparison of the pressure derivative curves shows that x f2D The increase in x leads to a longer duration of the first linear flow phase in the disturbed formation and a delay in the second linear flow phase in the disturbed formation. f2D The increase of x in the second crack segment will increase the half length of the crack segment. f2 As x increases, gas requires more time to flow into the second fracture segment, and the slope m1 of the straight segment characterizing the linear flow stage of the first disturbed formation increases with x. f2D As x increases, it decreases. f2d When the value increases, the first linear flow stage of the disturbing formation will cover the second linear flow stage of the disturbing formation. The second linear flow stage of the disturbing formation cannot be observed from the pressure derivative curve. The fracture segment parameters can be interpreted by fitting actual pressure measurement data, and thus the fracture lengths of different conductivity in condensate gas reservoirs can be obtained.

[0051] This application has the following advantages due to the adoption of the above technical solution:

[0052] The uneven gas production well test model for condensate gas reservoirs proposed in this invention interprets the fracture half-lengths of fractures with different conductivity in fractured wells that are more in line with engineering practice. The proposed method can effectively determine the length of fractures with different conductivity, which has important guiding significance for correctly evaluating the effect of fracturing measures, adjusting the next steps of work in condensate gas reservoirs, and improving the production of condensate gas reservoirs. Attached Figure Description

[0053] Various other advantages and benefits will become apparent to those skilled in the art upon reading the following detailed description of preferred embodiments. The accompanying drawings are for illustrative purposes only and are not intended to limit the scope of this application. Throughout the drawings, the same reference numerals denote the same parts. In the drawings:

[0054] Figure 1 This invention provides a physical model for the non-uniform conductivity of multi-layer hydraulic fracturing fractures.

[0055] Figure 2This invention defines the typical well test curves and flow stages of fractured wells with uneven gas production in multiple fractured sections, as presented in this paper.

[0056] Figure 3 This is the second stage of linear flow disturbance in the formation of a fractured well with uneven gas production across multiple fractured segments.

[0057] Figure 4 Showing different x f1D Comparison of dimensionless pseudo-pressure and pressure derivative curves under the given value;

[0058] Figure 5 Showing different x f2D Comparison of dimensionless pseudo-pressure and pressure derivative curves under different values.

[0059] The markings in the attached diagram are as follows:

[0060] 1. Wellbore; 2. Fracture; 3. Gas flowing into the fracture; 4. Wellbore storage stage; 5. Transition flow stage; 6. Formation linear flow stage; 7. First disturbed formation linear flow stage; 8. Second disturbed formation linear flow stage; 9. System radial flow stage. Detailed Implementation

[0061] Exemplary embodiments of this application will now be described in more detail with reference to the accompanying drawings. While exemplary embodiments of this application are shown in the drawings, it should be understood that this application may be implemented in various forms and should not be limited to the embodiments set forth herein. Rather, these embodiments are provided to enable a more thorough understanding of this application and to fully convey the scope of this application to those skilled in the art.

[0062] Existing methods for determining fracture length in fractured wells are generally based on the assumption that fractures have the same conductivity and that oil and gas production is uniform. However, in actual engineering, the conductivity of fractures is often different, and multiphase flow can occur in condensate gas reservoirs. Therefore, it is impossible to determine the fracture length with different conductivity under multiphase flow.

[0063] This invention first proposes the concept of uneven gas production in multiphase flow fractures in condensate gas reservoirs based on the phenomenon of partial fracture closure, and establishes a method for determining the fracture length of fractured wells using a multi-segment multiphase uneven well test model.

[0064] Then, the semi-analytical solution of the well test model was obtained using the Green function and the Newman product method, and typical well test curves were plotted.

[0065] Finally, the fracture lengths with different conductivity were obtained by analyzing and interpreting the well test curves.

[0066] This invention can accurately determine the fracture length of different conductivity levels in condensate gas reservoirs, guiding the efficient development of condensate gas reservoirs.

[0067] According to some embodiments of this application, the method for determining the length of fractures with different conductivity in condensate gas reservoirs by pressure measurement includes the following steps: establishing a physical model and a mathematical model of the condensate gas reservoir; plotting typical well test curves of multi-stage non-uniform gas production fractured wells in condensate gas reservoirs, dividing them into five flow stages; comparing the typical well test curves of the multi-stage non-uniform gas production fractured well model and the conventional uniform flow fracture model, using the new model to determine the interfering linear flow stage that the conventional uniform flow model cannot determine, thereby more accurately fitting the historical pressure data and more accurately interpreting and evaluating the reservoir and fracture parameters; and determining the length of fractures with different conductivity in condensate gas reservoirs.

[0068] This invention establishes a novel interpretation model for multi-stage uneven gas production in fractured wells of condensate gas reservoirs. A new semi-analytical solution was obtained, typical well test curves were plotted, and sensitivity factor analysis was performed. The dimensionless bottomhole pressure and pressure derivative response indicate that new flow stages have emerged in the well test curves of fractured wells with multi-stage uneven gas production. These flow stages are named the first and second interfering linear flow stages, and they exhibit slowly rising slopes of m1 and m2, respectively. When m1 ≠ m2 ≠ 1 / 2, it can be determined that multi-stage uneven gas production has occurred in the fracture. The parameters of the fracture stages can be interpreted through analysis of the interfering linear flow stages and example fitting of actual pressure measurement data.

[0069] Step 1: Figure 1 This invention presents a physical model of non-uniform conductivity in multi-layered fracturing fractures, using a single fractured well within a sealed top and bottom formation. Other assumptions are as follows:

[0070] (1) Infinitely large in the horizontal direction, isotropic, and homogeneous reservoirs with a compressibility coefficient of C exist. t And fluids with a viscosity of μ.

[0071] (2) The crack extends completely from top to bottom, and the half-length of the crack is x f Width w f Porosity φ f Overall compression ratio C fi .

[0072] (3) Permeability k, porosity φ, thickness h, and initial pressure p of the reservoir porous medium i .

[0073] (4) Figure 1 The crack half-length x is shown. f Divide into n segments: the half-length of the i-th crack segment x fi Conductivity C fi Gas production

[0074] (5) Oil (gas) flows into wellbore 1 only through fracture 2.

[0075] (6) The flow in the reservoir follows Darcy's law and the influence of gravity is ignored.

[0076] Control equations for multi-stage non-uniform gas production and seepage in fractured wells

[0077]

[0078] Boundary conditions

[0079] ψ(x→∞,y→∞,t)=ψ i (2)

[0080] Initial conditions

[0081] ψ(x,y,t=0)=ψ i (3)

[0082] The pseudo-pressure is defined as follows (standardized pseudo-pressure can be used, resulting in a smaller calculated value):

[0083]

[0084] The definition of dimensionless is as follows:

[0085]

[0086] In the formula

[0087] k — relative penetration rate;

[0088] μ—the viscosity of the fluid; —Porosity;

[0089] C t —Comprehensive compression ratio;

[0090] ψ—Pseudo-pressure value;

[0091] x f —The crack is half-length;

[0092] q — Traffic;

[0093] t — pressure wave propagation time;

[0094] h—crack height;

[0095] D – Dimensionless quantity.

[0096] Considering no pressure drop along wellbore 1, the pressure drop of fracture 2 and its own skin effect are combined into a total skin effect s. f express

[0097]

[0098] In the formula

[0099] Δψ s —The pseudo-pressure drop value corresponding to the crack pressure drop;

[0100] N—Number of discrete segments of the crack;

[0101] q iD —The flow rate corresponding to each crack segment;

[0102] C fiD — Crack compressibility coefficient;

[0103] S f —Crack surface coefficient.

[0104] Considering the absence of pressure drop along wellbore 1, and treating the pressure at the connection between the first fracture segment and the wellbore as the dimensionless pseudo-bottom pressure, we can obtain the dimensionless pseudo-bottom pressure of a fractured well with uneven gas production across multiple fracture segments, considering the fracture skin:

[0105]

[0106] The dimensionless bottom hole pseudo-pressure after considering the well-reservoir effect is expressed as:

[0107]

[0108] Applying the Laplace transform to the above equation yields the dimensionless bottom hole pseudo-pressure in a fractured well with uneven gas production across multiple segments within the Laplace space, considering both the skin and reservoir layers:

[0109]

[0110] In the formula

[0111] —Dimensionless pseudo-pressure value corresponding to the bottom hole pressure in the pull-type space;

[0112] C D —Dimensionless wellbore storage coefficient;

[0113] u — Laplace transform variable;

[0114] T sc ,P sc —Temperature and pressure under standard conditions;

[0115] The function erf(x) is defined as follows:

[0116]

[0117] x wD —The well has no dimensionless x-axis;

[0118] i — the i-th crack segment.

[0119] In well testing analysis of condensate gas reservoirs, the pseudo-pressure method is mainly divided into three categories, and their definitions are as follows.

[0120] 1) Single-phase gas simulated pressure

[0121]

[0122] 2) Two-phase pseudo-pressure

[0123] To describe the effects of two-phase flow, a two-phase pseudo-pressure function can be defined using a method similar to that used for single-phase gas pseudo-pressure:

[0124]

[0125] 3) Proposed pressure in the three regions

[0126] Zone I:

[0127] Zone II:

[0128] Zone III:

[0129] In the formula,

[0130] p * —Pressure at the outer boundary of Zone 1;

[0131] p d —Dew point pressure;

[0132] p0—Reference pressure;

[0133] S wi — Residual water saturation.

[0134] k ri i = o, g — relative permeability values ​​of oil phase and gas phase;

[0135] μ i i = o, g — viscosity of oil phase and gas phase;

[0136] ρ i i = o, g — density of oil phase and gas phase;

[0137] The outer boundary pressure p of region I * Equal to the dew point pressure of the production well fluid, which can be determined based on r s =1 / R p Sure.

[0138] By performing Stehfest inversion on (9) and considering the pseudo-pressure of the condensate gas reservoir, the solution of the interpretation model for the uneven gas production in multi-stage well testing of the fractured well in the condensate gas reservoir in real space can be obtained.

[0139] Step Two: Figure 2 This invention relates to typical well test curves and flow stage divisions for fractured wells with uneven gas production in multi-stage fractured reservoirs. Typical well test curves for fractured wells with uneven oil production in multi-stage fractured reservoirs can be divided into six flow stages: Wellbore reservoir stage 4, where both pressure and pressure derivative are straight lines with a slope of 1; Transitional flow stage 5, the stage of wellbore reservoir seepage into the formation; Formation linear flow stage 6, where the pressure derivative curve is a straight line with a slope of 1 / 2; First interfering formation linear flow stage 7, where the pressure derivative curve is a straight line with a slope of m1; Second interfering formation linear flow stage 8, where the pressure derivative curve is a straight line with a slope of m2 (m1≠m2≠1 / 2); System radial flow stage, where the pressure derivative curve is a horizontal segment with a slope of 0.5.

[0140] Step 3: From Figure 4 It can be seen that both the pressure and the pressure derivative value change with x. f1D It increases with the increase of x. f1D The increase means that the half length of the first crack segment x f1 This increase means that gas needs more time to flow into the first fracture segment, ultimately leading to a longer duration of the linear flow phase and a delay in the linear flow phase of the first disturbed formation. Furthermore, it can be seen from... Figure 4 It can be seen that the slope m1 of the straight line segment representing the linear flow stage of the first disturbed stratum changes with x. f1D It increases with the increase of x. f1D It has no effect on the linear flow stage of the second disturbing stratum or the radial flow stage of the system.

[0141] Step 4: x f2D It has a significant impact only on the linear flow stages of the first and second disturbed formations. The pressure derivative curves for the early and late stages coincide at different values. Figure 5 The comparison of the pressure derivative curves shows that x f2D An increase in x leads to a longer duration of the first linear flow phase in the disturbed formation and a delay in the second linear flow phase. This is because x f2D The increase means that the half length x of the second crack segment f2 This increases the time required for gas to flow into the second fracture segment.

[0142] In addition, it can be seen from Figure 5 It can be seen that the slope m1 of the straight line segment representing the linear flow stage of the first disturbed stratum changes with x. f2D It decreases as x increases. f2DWhen the value is very large, the first linear flow stage of the disturbing formation will completely cover the second linear flow stage of the disturbing formation, and the second linear flow stage of the disturbing formation will not be observed from the pressure derivative curve chart.

[0143] Step 5: By analyzing Step 3 and Step 4 and performing example fitting on actual pressure measurement data, the fracture segment parameters can be interpreted, thereby obtaining the fracture lengths of different conductivity in condensate gas reservoirs.

[0144] Finally, it should be noted that the above embodiments are only used to illustrate the technical solutions of this application, and are not intended to limit them. Although this application has been described in detail with reference to the foregoing embodiments, those skilled in the art should understand that modifications can still be made to the technical solutions described in the foregoing embodiments, or equivalent substitutions can be made to some of the technical features. Such modifications or substitutions do not cause the essence of the corresponding technical solutions to deviate from the spirit and scope of the technical solutions of the embodiments of this application.

Claims

1. A method for determining the length of fracturing fractures with different conductivity in condensate gas reservoirs by pressure measurement, characterized in that, include: Step S1: Establish physical and mathematical models of condensate gas reservoirs, plot typical well test curves of fractured wells with uneven gas production in multiple stages of condensate gas reservoirs, and divide the typical well test curves of fractured wells with uneven gas production in multiple stages of condensate gas reservoirs into five flow stages. The process of plotting typical well test curves for multi-stage uneven gas production in condensate gas reservoir fractures includes: establishing an interpretation model for multi-stage uneven gas production in condensate gas reservoir fractures, solving for a semi-analytical solution, plotting typical well test curves, and conducting sensitivity factor analysis. Step S2: Compare the typical well test curves of the fractured well with the non-uniform gas production in the condensate gas reservoir with the typical well test curves of the conventional uniform flow fracture model. Use the physical and mathematical models of the condensate gas reservoir to determine the stage of interference with linear flow, fit the pressure history data, and interpret and evaluate the reservoir and fracture parameters. Among them, the dimensionless bottom hole pressure and pressure derivative response indicate that the typical curve of the fracture test well with uneven gas production in multiple segments of condensate gas reservoir fractures shows the appearance of a flow stage. The flow stage is named the first interfering linear flow stage and the second interfering linear flow stage, and they show a slow rising line with slopes of m1 and m2, respectively. When m1≠m2≠1 / 2, it is judged that the fracture has a multi-segment uneven gas production phenomenon. The fracture segment parameters are interpreted by analyzing the interfering linear flow stage and by fitting actual pressure measurement data. The typical well test curves for multi-stage, unevenly produced gas in fractured wells in condensate gas reservoirs are assumed to be: infinitely large in the horizontal direction, isotropic, and exist in homogeneous reservoirs with a comprehensive compressibility coefficient of [missing value]. And fluids with viscosity μ; the crack extends completely from top to bottom, and half the crack length... Width Relative permeability value of the reservoir Porosity initial pressure ; cut half the length of the crack Divided into N segments: half the length of the i-th crack segment , No. i Conductivity of segmental cracks , No. i Flow rate corresponding to segment crack Oil and gas flow into the wellbore only through fractures; seepage in the reservoir follows Darcy's law and the effect of gravity is ignored; Typical well test curve equations for fractured wells with uneven gas production in multi-stage fractured reservoirs: （1） Boundary conditions （2） Initial conditions （3） pseudo-pressure is defined as （4） Dimensionless is defined as （5） —Relative penetration rate; —The viscosity of the fluid; —Porosity; —Comprehensive compression ratio; —Pseudo-pressure value; —The crack is half-length; --flow; —Pressure wave propagation time; — Crack height; —Dimensionless quantity; Considering no pressure drop along the wellbore, the fracture pressure drop and the skin effect are combined using a total fracture skin coefficient. express: （6） —The pseudo-pressure drop value corresponding to the crack pressure drop; —Number of discrete segments of the crack; ——No. i Flow rate corresponding to the segment crack; —Conduction coefficient; —Crack surface coefficient; Considering the absence of pressure drop along the wellbore, the pressure at the connection between the first fracture segment and the wellbore is treated as a dimensionless pseudo-bottom pressure. This yields the dimensionless pseudo-bottom pressure after considering the fracture skin in a fractured well with uneven gas production across multiple fracture segments: （7） The dimensionless bottom hole pseudo-pressure after considering the well-reservoir effect is expressed as: （8） Applying the Laplace transform to the above equation yields the dimensionless bottom hole pseudo-pressure in a fractured well with uneven gas production across multiple segments within the Laplace space, considering both the skin and reservoir layers: （9） —Dimensionless pseudo-pressure value corresponding to the bottom hole pressure in the pull-type space; —Dimensionless wellbore storage coefficient; —Laplace transform variables; —Temperature and pressure under standard conditions; function The definition is as follows: ; —The well has no dimensionless x-axis; i — the i-th crack segment; In well test analysis of condensate gas reservoirs, the pseudo-pressure method is divided into three categories: The pseudo-pressure of single-phase gas is defined using Equation 4: （10） Two-phase pressure To describe the effects of two-phase flow, a two-phase pseudo-pressure function is defined using a method similar to that used for single-phase gas pseudo-pressure: (11) Three areas are expected to face pressure. District I: , (12) Zone II: , (13) Zone III: , (14) In the formula, —Pressure at the outer boundary of Zone I; —Dew point pressure; —Reference pressure; — Residual water saturation; —Relative permeability values ​​of oil phase and gas phase; —Oil phase and gas phase viscosity; —Oil phase and gas phase density; outer boundary pressure of region I Equal to the dew point pressure of the production well fluid, according to Sure; By performing Stehfest inversion on equation (9) and considering the pseudo-pressure of the condensate gas reservoir, the solution of the interpretation model for the uneven gas production in multi-stage well testing of the fractured well in the condensate gas reservoir in real space can be obtained. Typical well test curves for fractured wells with uneven oil production in multiple segments can be divided into five flow stages: the wellbore reservoir stage, where both pressure and pressure derivative are straight lines with a slope of 1; the transitional flow stage, where the wellbore reservoir seeps into the formation; the linear formation flow stage, where the pressure derivative curve is a straight line with a slope of 1 / 2; the first interfering linear formation flow stage, where the pressure derivative curve is a straight line with a slope of m1; the second interfering linear formation flow stage, where the pressure derivative curve is a straight line with a slope of m2; and the system radial flow stage, where the pressure derivative curve is a horizontal segment with a slope of 0.

5. When pressure and pressure derivative both follow When it increases with the increase, The increase means that the half length of the first crack segment The increase in flow rate leads to a longer gas inflow into the first fracture segment, resulting in a longer duration of the linear flow phase and a delay in the linear flow phase of the first disturbed formation. This is reflected in the slope m1 of the straight segment characterizing the linear flow phase of the first disturbed formation. It increases with the increase of [something]. It had no effect on either the linear flow stage of the second disturbing stratum or the radial flow stage of the system. It only has a significant impact on the linear flow stages of the first and second disturbed formations. The pressure derivative curves of the early and late stages at different values ​​coincide. The comparison of the pressure derivative curves shows that... The increase in this will lead to a longer duration of the first linear flow phase in the disturbed formation and a delay in the second linear flow phase in the disturbed formation. The increase of the second crack segment half length As gas increases, it takes more time to flow into the second fracture segment, and the slope m1 of the straight segment characterizing the linear flow stage of the first disturbed formation increases with... As it increases, it decreases, when When the value increases, the first linear flow stage of the disturbing formation will cover the second linear flow stage of the disturbing formation. The second linear flow stage of the disturbing formation cannot be observed from the pressure derivative curve. The fracture segment parameters are interpreted by fitting actual pressure measurement data to obtain the fracture lengths of different conductivity in condensate gas reservoirs. Step S3: Evaluate and determine the fracture length of different conductivity in condensate gas reservoirs based on the explanation.

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