Method and device for quantitatively predicting gas reservoir recovery ratio

Abstract

The invention discloses a method and a device for quantitatively predicting the recovery ratio of a gas reservoir. The method comprises the following steps: acquiring related gas reservoir parameters of a target gas reservoir; determining a comprehensive compression coefficient in the gas reservoir parameters according to a pre-established relationship between the comprehensive compression coefficient and the stress sensitivity coefficient in the gas reservoir parameters; determining the waste bottom hole flowing pressure of the gas reservoir according to the related gas reservoir parameters, and determining the waste stratum pressure of the gas reservoir by using a calculation formula of the waste stratum pressure; and according to the comprehensive compression coefficient and the wasteland stratum pressure of the gas reservoir, determining the recovery ratio of the gas reservoir by utilizing a pre-established water-containing gas reservoir recovery ratio model.

Description

Technical Field

[0001] This article relates to the field of exploration and development technology of oil and gas geological resources, and in particular to a method and apparatus for quantitatively predicting gas reservoir recovery rate. Background Technology

[0002] CN201910975185.0 describes a method and apparatus for predicting oil and gas reservoir recovery rate. The method obtains the basic score of the recovery rate of a target oil and gas reservoir; obtains the correction coefficients of the factors influencing the recovery rate of the target oil and gas reservoir; and obtains the recovery rate of the target oil and gas reservoir based on the basic score and the correction coefficients of the factors influencing the recovery rate. This invention, when analyzing oil and gas reservoir recovery rate, not only considers the magnitude of the parameter values ​​of the factors influencing the recovery rate but also distinguishes between different types of oil and gas reservoirs, thus improving the accuracy of the oil and gas reservoir recovery rate analysis results.

[0003] CN202111313995.3 discloses a gas reservoir recovery rate prediction method based on multiple regression. The method involves selecting target reservoir rocks, processing them into parallel samples, and pre-processing them. Based on the characteristics of the selected target reservoir, multiple single factors affecting gas reservoir recovery are pre-determined, and the target parameters of each single factor are obtained through corresponding experiments. The impact of each single factor on the gas reservoir recovery rate is analyzed, and multiple single factors that have a major influence on the gas reservoir recovery rate are screened out. Based on a multiple regression model, the predicted value of the recovery rate is calculated. This invention more realistically recreates the reservoir gas production process and uses multiple regression to incorporate multiple controlling factors into the calculation to obtain the recovery rate, reducing the calculation error of the recovery rate. Compared with traditional recovery rate prediction methods, it greatly reduces the dependence on field production data and is also suitable for gas reservoir prediction of various types, different development methods, and different development stages, making it widely applicable.

[0004] CN02121106.X presents a method for calculating gas reservoir recovery rate and recoverable reserves. This method considers the dynamic reserve ratio and the difference in gas saturation between the original and abandoned stages of a water-driven gas reservoir. It proposes a new method for calculating gas reservoir recovery rate and recoverable reserves—the "Modified Volumetric Method"—and derives a new calculation formula. This invention improves the theory of calculating gas reservoir recovery rate and recoverable reserves using the volumetric method, corrects the original calculation formula, and obtains reliable calculation results. It clarifies or defines concepts crucial to gas field development, such as "dynamic reserves," "dynamic reserve ratio," "dynamic reserve recovery rate," and the "Modified Volumetric Method." It clarifies the differences and connections between similar concepts, elucidates the logical correspondence and matching relationships between related concepts, and corrects the shortcomings of mutual confusion and ambiguity in the original similar concepts.

[0005] CN202210262151.9 discloses a method and system for constructing a gas reservoir recovery model. Based on the macroscopic and microscopic heterogeneity characteristics of the gas reservoir, it obtains the recovery rate in the pure gas zone; based on the macroscopic and microscopic heterogeneity characteristics of the gas reservoir, it obtains the recovery rate in the water-swept zone; and based on the recovery rates in the pure gas zone and the water-swept zone, it constructs a gas reservoir recovery model. This recovery model comprehensively considers the macroscopic and microscopic heterogeneity characteristics of the gas reservoir, and can more meticulously and comprehensively reflect the key indicator system affecting the gas reservoir recovery rate. It is highly operable and also provides a basis for formulating targeted technical countermeasures to improve gas reservoir recovery.

[0006] The aforementioned methods for calculating gas reservoir recovery rate include a modified volumetric recovery rate formula, establishing the relationship between factors influencing gas reservoir recovery rate and the recovery rate itself, and constructing recovery rate models that consider the macroscopic and microscopic heterogeneity characteristics of gas reservoirs and different well types. Although these methods consider water production, they only consider single-phase gas flow when applying the vertical pipe flow method to calculate bottom hole flowing pressure. In actual production, there is a two-phase flow of formation water and gas-water in the wellbore. Therefore, a more quantitative method for predicting gas reservoir recovery rate that is more in line with actual production is needed. Summary of the Invention

[0007] This application provides a method and apparatus for quantitatively predicting gas reservoir recovery. Due to the presence of water in the gas reservoir, the method takes into account stress sensitivity and the influence of the starting pressure gradient based on the material balance method, and combines the gas-water two-phase vertical pipe flow method to quantitatively predict the gas reservoir recovery.

[0008] In a first aspect, this application provides a method for quantitatively predicting gas reservoir recovery rate. The method includes: acquiring relevant gas reservoir parameters of the target gas reservoir; determining the comprehensive compressibility coefficient of the gas reservoir parameters based on the pre-established relationship between the comprehensive compressibility coefficient and the stress sensitivity coefficient; determining the abandoned bottomhole flowing pressure of the gas reservoir based on the relevant gas reservoir parameters, and determining the abandoned formation pressure of the gas reservoir using the calculation formula for abandoned formation pressure; and determining the gas reservoir recovery rate using a pre-established water-bearing gas reservoir recovery rate model based on the comprehensive compressibility coefficient and the abandoned formation pressure of the gas reservoir.

[0009] Secondly, embodiments of the present invention also provide an apparatus for quantitatively predicting gas reservoir recovery rate, the apparatus comprising: a memory and a processor; the memory is used to store a program for quantitatively predicting gas reservoir recovery rate, and the processor is used to read and execute the program for quantitatively predicting gas reservoir recovery rate, and execute the method for quantitatively predicting gas reservoir recovery rate described in the above embodiments.

[0010] Thirdly, embodiments of the present invention also provide a computer-readable storage medium storing a data processing program, wherein the data processing program is executed by a processor using the method for quantitatively predicting gas reservoir recovery rate described in the above embodiments.

[0011] Compared with related technologies, this application provides a method and apparatus for quantitatively predicting gas reservoir recovery. The method includes: acquiring relevant reservoir parameters of the target gas reservoir; determining the comprehensive compressibility coefficient of the reservoir parameters based on a pre-established relationship between the comprehensive compressibility coefficient and the stress sensitivity coefficient; determining the abandoned bottomhole flowing pressure of the gas reservoir based on the relevant reservoir parameters, and determining the abandoned formation pressure of the gas reservoir using the calculation formula for abandoned formation pressure; and determining the gas reservoir recovery rate using a pre-established water-bearing gas reservoir recovery rate model based on the comprehensive compressibility coefficient and the abandoned formation pressure of the gas reservoir. This application, based on the mass balance method, considers the influence of stress sensitivity and the starting pressure gradient, and combines the gas-water two-phase vertical pipe flow method to quantitatively predict gas reservoir recovery.

[0012] Other features and advantages of this application will be set forth in the following description, and will be apparent in part from the description, or may be learned by practicing the application. Other advantages of this application can be realized and obtained by means of the solutions described in the description and the accompanying drawings. Attached Figure Description

[0013] The accompanying drawings are used to provide an understanding of the technical solutions of this application and constitute a part of the specification. They are used together with the embodiments of this application to explain the technical solutions of this application and do not constitute a limitation on the technical solutions of this application.

[0014] Figure 1 This is a flowchart of a method for quantitatively predicting gas reservoir recovery according to an embodiment of this application;

[0015] Figure 2 This is a schematic diagram of a device for quantitatively predicting gas reservoir recovery rate according to an embodiment of this application;

[0016] Figure 3 In some exemplary embodiments, N l -CN l Relationship curve;

[0017] Figure 4 Correction coefficients in some exemplary embodiments;

[0018] Figure 5 For some exemplary embodiments, the liquid holdup coefficient is used;

[0019] Figure 6 This is a flowchart illustrating the calculation of pressure distribution along the oil pipe in some exemplary embodiments;

[0020] Figure 7 This is a mean abandoned bottom flow pressure map of a target block gas reservoir in some exemplary embodiments. Detailed Implementation

[0021] This application describes several embodiments, but these descriptions are exemplary and not restrictive, and it will be apparent to those skilled in the art that many more embodiments and implementations are possible within the scope of the embodiments described herein. Although many possible combinations of features are shown in the drawings and discussed in the detailed description, many other combinations of the disclosed features are also possible. Unless specifically limited, any feature or element of any embodiment may be used in combination with, or may replace, any feature or element of any other embodiment.

[0022] This application includes and contemplates combinations of features and elements known to those skilled in the art. The embodiments, features, and elements disclosed in this application may also be combined with any conventional features or elements to form a unique inventive scheme as defined by the claims. Any feature or element of any embodiment may also be combined with features or elements from other inventive schemes to form another unique inventive scheme as defined by the claims. Therefore, it should be understood that any feature shown and / or discussed in this application may be implemented individually or in any suitable combination. Therefore, the embodiments are not limited except by the limitations imposed by the appended claims and their equivalents. Furthermore, various modifications and changes may be made within the scope of the appended claims.

[0023] Furthermore, in describing representative embodiments, the specification may have presented methods and / or processes as a specific sequence of steps. However, the method or process should not be limited to the specific order of steps described herein, to the extent that it does not depend on such a specific order. As will be understood by those skilled in the art, other sequences of steps are also possible. Therefore, the specific order of steps set forth in the specification should not be construed as a limitation of the claims. Moreover, the claims concerning the method and / or process should not be limited to the steps performed in the written order, and those skilled in the art will readily understand that these orders can be varied and still remain within the spirit and scope of the embodiments of this application.

[0024] This invention provides a method for quantitatively predicting gas reservoir recovery rate, such as... Figure 1 As shown, the method includes steps 100-130:

[0025] S100: Obtain relevant gas reservoir parameters for the target block;

[0026] S110: Determine the comprehensive compressibility coefficient in the gas reservoir parameters based on the pre-established relationship between the comprehensive compressibility coefficient and the stress sensitivity coefficient;

[0027] S120: Determine the abandoned bottomhole flowing pressure of the gas reservoir based on relevant gas reservoir parameters, and determine the abandoned formation pressure of the gas reservoir using the calculation formula for abandoned formation pressure;

[0028] S130: Based on the comprehensive compression coefficient and the abandoned formation pressure of the gas reservoir, the gas reservoir recovery rate is determined using a pre-established water-bearing gas reservoir recovery rate model.

[0029] In this embodiment, the relevant gas reservoir parameters include: porosity (Unit: %), Initial penetration rate K m0 (Unit: mD), original formation pressure p i (Unit: MPa), Abandoned well bottom flowing pressure p wa (Unit: MPa), water saturation S wi (Unit: %), Overall Compression Coefficient C e (Unit: MPa) -1 Formation water compressibility coefficient C w (Unit: MPa) -1 ), wellbore radius r w (Unit: m), Supply radius r e (Unit: m), stress sensitivity coefficient α k (Unit: MPa) -1 ), starting pressure gradient λ T (Unit: MPa / m), Gas deviation factor Z under original formation pressure i The gas deviation factor Za and the water volume coefficient ω under abandoned formation pressure are given. Z is the gas deviation factor when the formation pressure is P, which varies with the formation pressure.

[0030] In one exemplary embodiment, the process of establishing a water-bearing gas reservoir recovery model using the mass balance equation of the water-bearing gas reservoir is as follows:

[0031] The first step is to obtain the material balance equation expression for a water-bearing gas reservoir:

[0032]

[0033] B g B gi The expression is:

[0034]

[0035]

[0036] The second step is to transform the material balance equation of the water-bearing gas reservoir:

[0037] Divide both sides of (1) by GB. gi ,have to:

[0038]

[0039] The expression for the formation water volume factor is:

[0040] B w =(1+ΔV) wt (1+ΔV) wp (5)

[0041] in:

[0042] ΔV wt =-0.0057325+0.000240104T+0.00000178412(T+17.78) 2

[0043] ΔV wp = -5.10 × 10 -7 p(T+17.78)-6.54×10 -9 p 2 (T+17.78)-5.21×10 -5 p-4.74×10 - 6 p 2

[0044] In the above formula, ΔV wt ΔV represents the change in the total volume of formation water. wp This indicates the volume change of the produced water.

[0045] make:

[0046]

[0047] The mass balance equation can be transformed into:

[0048]

[0049] The third step is to establish a model for the recovery rate of water-bearing gas reservoirs based on the modified material balance equation:

[0050]

[0051] Where: R is the gas reservoir recovery rate, %;

[0052] G represents the geological reserves of the gas reservoir, m 3 ;

[0053] G p For the cumulative gas production of the gas reservoir, m 3 ;

[0054] Z aThis refers to the gas deviation factor under formation abandonment pressure.

[0055] Z i This is the gas deviation factor under the original formation pressure;

[0056] B gi This is the volume factor of the gas under the original formation pressure;

[0057] B g is the volume coefficient of the gas at pressure p;

[0058] B w This is the volume factor of formation water.

[0059] p i The original formation pressure is expressed in MPa.

[0060] p represents the current formation pressure, in MPa;

[0061] p sc The pressure of the gas under standard conditions, in MPa;

[0062] W e For water intrusion, m 3 ;

[0063] W p To accumulate water production, m 3 ;

[0064] C p The compressibility coefficient of the rock is given in MPa. -1 ;

[0065] C w The compressibility of the liquid is expressed in MPa. -1 ;

[0066] C e The overall compressibility factor is expressed in MPa. -1 ;

[0067] S wi To bind water saturation;

[0068] T sc Let K be the temperature of the gas under standard conditions.

[0069] ω is the water storage volume coefficient;

[0070] p a This refers to the pressure in abandoned formations.

[0071] In one exemplary embodiment, the water-bearing gas reservoir recovery model includes a two-phase fluid of gas and water, based on the cumulative water production W. p The volume factor B of gas under the original formation pressure gi and the volume factor B of formation waterw The current water volume factor is calculated using the water volume factor formula:

[0072]

[0073] Where ω is the water storage volume coefficient, W is the geological storage of water in the gas reservoir, and W p To accumulate water production, B gi B is the volume factor of the gas under the original formation pressure; g B is the volume coefficient of the gas at pressure p; w B is the volume factor of formation water. wi This is the volume factor of water under the original formation pressure.

[0074] In one exemplary embodiment, the overall compression coefficient C e The process of determining is as follows:

[0075] Step 1: Obtain the overall compression coefficient C e With rock compressibility coefficient C p Relationship;

[0076]

[0077] In the above formula, C e C is the overall compression factor. w S is the compressibility coefficient of the liquid. wi To constrain water saturation, C p is the rock's compressibility coefficient.

[0078] Step 2: Establish the rock compressibility coefficient C p With stress sensitivity coefficient α k Relationship;

[0079] Step 3: Establish the overall compression coefficient C e With stress sensitivity coefficient α k The relationship is used to determine the overall compression coefficient C. e The calculation formula is as follows:

[0080]

[0081] Where Δp is the pressure difference, Δp = p i -p a p i p represents the original formation pressure. a For abandoned formation pressure; C w S is the compressibility coefficient of the liquid. wi To constrain water saturation, α k This is the stress sensitivity coefficient.

[0082] In one exemplary embodiment, stress sensitivity refers to the influence of the pressure difference generated by the combined action of skeletal stress and pore fluid pressure on the micropore structure. Based on the above influence, the rock compressibility coefficient C is established. p With stress sensitivity coefficient α k The relationship process is as follows:

[0083] For the rock cross-section under the original formation pressure, the average pore radius is:

[0084]

[0085] The expression for porosity is:

[0086]

[0087] According to the Kozeny-Carman equation, the expression for rock permeability under the original formation pressure is:

[0088]

[0089] Under current formation pressure, the expression for rock permeability is:

[0090]

[0091] From formulas (11), (12), and (13), we get:

[0092]

[0093] The expression for the rock compressibility coefficient is:

[0094]

[0095] When the pressure decreases by Δp, the pore area is compressed to:

[0096] A p =A pi (1-C p Δp) (16)

[0097] Based on the principle that the porosity of a rock remains constant during its deformation, when the pressure decreases by Δp, the surface area of ​​the rock becomes:

[0098] A = A i (1-C p Δp) (17)

[0099] Substituting formulas (16) and (17) into formula (14), we get:

[0100]

[0101] When considering stress sensitivity, the formula for absolute formation permeability is:

[0102]

[0103] Substituting formula (19) into formula (18) yields:

[0104]

[0105] Equation (20) can be transformed to obtain the rock compressibility coefficient C. p The relationship with the stress sensitivity coefficient is as follows:

[0106]

[0107] Where: n is the number of pores;

[0108] A is the surface area of ​​the rock under pressure p, in m 2 ;

[0109] A i The surface area of ​​the rock under the original formation pressure, in m 2 ;

[0110] A p Let m be the pore area of ​​the rock at pressure p. 2 ;

[0111] A pi The pore area of ​​the rock under the original formation pressure is m. 2 ;

[0112] τ represents the degree of tortuosity;

[0113] α k The stress sensitivity coefficient is based on experimental data.

[0114] Furthermore, according to formula (21), the rock compressibility coefficient C p The relationship between stress sensitivity coefficient and overall compressibility coefficient C e With rock compressibility coefficient C p The relationship determines the overall compression coefficient C e With stress sensitivity coefficient α k Relationship:

[0115]

[0116] Where Δp is the pressure difference, Δp = p i -p a p i p represents the original formation pressure. a For abandoned formation pressure; C w S is the compressibility coefficient of the liquid. wi To constrain water saturation, α kThis is the stress sensitivity coefficient.

[0117] In one exemplary embodiment, considering the initiation pressure gradient λ T Determine the pressure p in the abandoned gas reservoir formation. a The process is as follows:

[0118] Step 1: Determine the pressure gradient at any point;

[0119] In the early stages of gas reservoir development, the gas flows in a single phase within the formation. Assuming that the gas follows a steady radial flow in the plane, the pressure gradient at any point can be expressed as:

[0120]

[0121] Step 2: Determine the pressure gradient in the formation and the initiation pressure gradient λ. T The relationship is:

[0122]

[0123] Third, when the gas reservoir reaches the point of abandonment, the pressure gradient should be at least equal to the starting pressure gradient λ. T ,but:

[0124]

[0125] The starting pressure gradient λ was considered. T Formula (24) can be transformed into:

[0126]

[0127] Step 4: Determine the pressure of the abandoned formation when the pressure gradient should be equal to the starting pressure gradient;

[0128] When the pressure gradient should be equal to the starting pressure gradient but

[0129]

[0130] According to Formula 26, the pressure gradient should be equal to the pressure of the abandoned formation under the starting pressure gradient:

[0131]

[0132] in:

[0133] p e To supply the boundary pressure, MPa;

[0134] p wf The bottom hole flowing pressure is in MPa.

[0135] r e Let vent radius be m;

[0136] r w Let be the radius of the wellbore, in meters (m).

[0137] λ T To initiate the pressure gradient, MPa / m;

[0138] p a The abandoned formation pressure is expressed in MPa.

[0139] p wa The pressure at the bottom of the abandoned well is MPa.

[0140] In one exemplary embodiment, the bottom flow pressure p of the abandoned well is... wa The calculation process is as follows:

[0141] Step 1: Determine the pressure at the abandoned wellhead;

[0142] Before calculating the bottom pressure of the abandoned well, the head pressure of the abandoned well must first be determined, which is determined by the actual production of the oilfield.

[0143] The second step is to determine the waste output.

[0144] Determined based on actual oilfield production.

[0145] The third step is to calculate the bottom flow pressure p of the abandoned well based on the abandoned wellhead pressure and abandoned production rate using a gas-water two-phase vertical pipe flow model. wa .

[0146] In this step, gas wells generally produce water in the later stages of development. At this point, the bottom-flow pressure of abandoned wells is calculated using the gas-water two-phase vertical pipe flow calculation method proposed by Hagedorn-Brown. Figure 6 The flowchart shown illustrates the calculation process for pressure distribution along the tubing. The specific steps are as follows: Based on the Hagedom-Brown method for calculating vertical gas-water two-phase pipe flow, the flow pressure at different depths is obtained, combined with the liquid holdup H... l The calculation process, under the condition of known block abandonment production and abandoned wellhead pressure, is plotted as follows: Figure 7 The chart shown is a map of the average abandoned wellbore flowing pressure of a target gas reservoir. The average abandoned wellbore flowing pressure of the gas reservoir can be obtained by referring to the chart based on the burial depth of the gas reservoir.

[0147] Based on the gas-water two-phase vertical pipe flow calculation method proposed by Hagedorn-Brown, the calculation process along the pressure distribution in the tubing is as follows: Figure 6As shown, the bottomhole flowing pressure corresponding to a certain depth in a gas reservoir can be calculated using an iterative method. For example, given the wellhead pressure (assumed to be 0.5) and production rate, the depth corresponding to a pressure difference of 1 MPa from the wellhead to the bottom of the well can be calculated. If the wellhead pressure is 0, then according to the process, when the pressure increases by 1 MPa, the depth difference calculated using the formula below is 1000 m. Therefore, the point on the chart is defined as pressure 0.5 + 1 = 1.5 and depth 1000 m. Then, when the pressure increases by another 1 MPa, the depth difference calculated using the formula is 980 m. Therefore, the point on the chart is defined as pressure 1.5 + 1 = 2.5 and depth 1000 + 980 = 1980 m. Using this method, the bottomhole depth is calculated. All the calculated data points form the average abandoned well bottomhole flowing pressure distribution chart.

[0148] Step 31. Determine the total pressure gradient equation as follows:

[0149]

[0150] in:

[0151] ρ m =ρ l H l +ρ g (1-H l (29)

[0152] G m =G g +G l =A(v sl ρ l +v sg ρ g (30)

[0153] v sg =q g / A (31)

[0154] v sl =q l / A (32)

[0155] Two-phase friction coefficient f m The expression is:

[0156]

[0157] Step 32. Calculate the liquid holdup H l

[0158] The calculation method for vertical two-phase gas-water pipe flow proposed by Hagedom-Brown involves the liquid holdup H. l Regarding the calculation of liquid holdup H lThe process is as follows:

[0159] Step 321. Calculate the four dimensionless variables under flow conditions;

[0160] Liquid phase velocity number:

[0161] Gas phase velocity number:

[0162] Liquid phase viscosity number:

[0163] Pipe diameter number:

[0164] Step 322. From N l -CN l Relationship curve, based on N l Determine CN l value;

[0165] like Figure 3 N shown l -CN l The relationship curve is based on the determined liquid phase viscosity number N. l The corresponding CN can be determined. l value.

[0166] Step 323. Determine the ratio

[0167] According to the determined Value, using Figure 5 The liquid holdup coefficient can be a ratio The relevant parameters in the above formula can be obtained in advance.

[0168] Step 324. Determine the value of ψ (correction factor);

[0169] Depend on Figure 4 ,according to Determine the value of ψ (correction factor);

[0170] Figure it out first The value, and then according to Figure 4 The correction coefficient curve is plotted to determine the value of the corresponding ordinate on the curve, i.e., the value of ψ (correction coefficient). The relevant parameters in the above formula can be obtained in advance.

[0171] Step 325. Based on the liquid holdup H l The formula for calculating liquid holdup is as follows;

[0172]

[0173] Step 33. Calculate the pressure gradient

[0174] In this step, the pressure gradient is calculated using an iterative method based on the pipe length increment method. The pressure gradient equation is expressed using the pipe length increment:

[0175]

[0176] Where: ρ g ρ l ρ m Densities of gas phase, liquid phase, and gas-liquid mixture, respectively, in kg / m³ 3 ;

[0177] g is the gravitational acceleration constant, m / s² 2 ;

[0178] A is the cross-sectional area of ​​the pipe, in meters. 2 ;

[0179] D is the inner diameter of the pipe, in meters (m).

[0180] Gm is the mass flow rate of the gas-liquid mixture, kg / s;

[0181] G g G l These are the gas phase and liquid phase mass flow rates, respectively, in kg / s;

[0182] v sg v sl v m The flow velocities are, respectively, those of the gas phase, liquid phase, and gas-liquid mixture, in m / s;

[0183] q g q l These are the gas phase and liquid phase volumetric flow rates, respectively, in m. 3 / s;

[0184] μ g μ l μ m The viscosity of the gas phase, liquid phase, and gas-liquid mixture are respectively, in mPa·s;

[0185] λ l For non-slippage liquid retention, λ l =v sl / v m ;

[0186] σ is the surface tension of the gas-liquid mixture, in N / m;

[0187] i is the node number;

[0188] H is the depth at the bottom of the well, in meters;

[0189] z is the length of the oil pipe, in meters;

[0190] Δ zi The increment is the length of the oil pipe, in meters (m).

[0191] ε is the error constant (a pre-set number);

[0192] This represents the function value on the right-hand side of the pressure gradient equation.

[0193] Step 34. Determine the abandoned pressure of the gas reservoir.

[0194] When z0 = 0, z0 is the length of the tubing, which is zero, meaning it is located at the wellhead. Given the known abandoned wellhead pressure p... tf When, then p0 = p tf The calculation process for pressure distribution along the tubing is as follows: Figure 6 As shown.

[0195] According to the process, draw a map of the average abandoned wellbore flowing pressure in the target gas reservoir when the gas well reaches the abandonment conditions (assuming abandoned gas production of 0.074 million cubic meters / day, abandoned water production of 3 cubic meters / day, and abandoned wellhead pressure of 0.5 MPa), as shown below. Figure 7 As shown.

[0196] When the tubing pressure is the abandoned wellhead pressure, the calculated bottom hole flowing pressure is the abandoned bottom hole flowing pressure.

[0197] In one exemplary embodiment, the recovery rate is calculated:

[0198] Combining formulas (6), (9), (21), and (27), we obtain:

[0199]

[0200] Equation (37) is a method for quantitatively predicting the recovery rate of tight sandstone gas reservoirs in rift basins that takes into account the influence of micro-permeability factors.

[0201] The calculation takes into account formation water content and wellbore gas-water two-phase flow, which is more consistent with the actual gas reservoir production, and therefore the calculated gas reservoir recovery rate is more reliable.

[0202] Secondly, embodiments of the present invention also provide an apparatus for quantitatively predicting the recovery rate of tight sandstone gas reservoirs in rift basins, such as... Figure 2 As shown, the device includes a memory 200 and a processor 210; the memory is used to store a program for quantitatively predicting the recovery rate of tight sandstone gas reservoirs in rift basins, and the processor is used to read and execute the program for quantitatively predicting the recovery rate of tight sandstone gas reservoirs in rift basins, and to execute the method for quantitatively predicting the recovery rate of tight sandstone gas reservoirs in rift basins as described in the above embodiment.

[0203] Thirdly, embodiments of the present invention also provide a computer-readable storage medium storing a data processing program, wherein the data processing program is executed by a processor using the method described in the above embodiments for quantitatively predicting the recovery rate of tight sandstone gas reservoirs in rift basins.

[0204] Example 1

[0205] This example demonstrates a method for quantitatively predicting the recovery rate of tight sandstone gas reservoirs in rift basins. The specific process is as follows:

[0206] The first step is to obtain relevant data on the gas reservoir in the target block, as shown in Table 1, which is a basic data statistics table.

[0207] Step 2: Calculate parameter b, water volume coefficient ω, and overall compressibility coefficient C based on the above parameters. e ;

[0208]

[0209] Step 3: Determine the bottom pressure p of the abandoned well. wa Based on the determined bottom flow pressure p of the abandoned well wa Determine the pressure p in the abandoned formation a .

[0210] Using a pressure distribution calculation process along the tubing, and under the condition of known abandoned production and abandoned wellhead pressure in the block, the following diagram is plotted: Figure 7 The average abandoned wellbore bottom pressure distribution chart shown can be used to determine the average abandoned wellbore bottom pressure of the gas reservoir based on the reservoir's burial depth.

[0211] The bottom hole flowing pressure at each depth point is calculated when the tubing pressure is the abandoned wellhead pressure. The obtained bottom hole flowing pressure is the abandoned wellhead flowing pressure.

[0212] The abandoned formation pressure of a gas reservoir can be obtained by combining the bottom-flow pressure of the abandoned well with the expression for the abandoned formation pressure of the gas reservoir.

[0213]

[0214] Step 4: Calculate the recovery rate:

[0215]

[0216] Substituting the relevant gas reservoir data from Table 1 into the formula, the recovery rate was calculated to be 32.76%.

[0217] Table 1

[0218]

[0219] The quantitative method for predicting the recovery rate of tight sandstone gas reservoirs in rift basins presented in this example, based on the mass balance equation for water-bearing gas reservoirs, considers the effects of stress sensitivity and starting pressure gradient, and combines the gas-water two-phase vertical pipe flow method to achieve a method for calculating the recovery rate of tight sandstone gas reservoirs in rift basins. This method takes into account both formation water aquifers and wellbore gas-water two-phase flow, and the calculated recovery rate results are more consistent with actual production conditions.

[0220] It will be understood by those skilled in the art that all or some of the steps, systems, or apparatuses disclosed above, and their functional modules / units, can be implemented as software, firmware, hardware, or suitable combinations thereof. In hardware implementations, the division between functional modules / units mentioned above does not necessarily correspond to the division of physical components; for example, a physical component may have multiple functions, or a function or step may be performed collaboratively by several physical components. Some or all components may be implemented as software executed by a processor, such as a digital signal processor or microprocessor, or as hardware, or as an integrated circuit, such as an application-specific integrated circuit (ASIC). Such software may be distributed on a computer-readable medium, which may include computer storage media (or non-transitory media) and communication media (or transient media). As is known to those skilled in the art, the term computer storage media includes volatile and non-volatile, removable and non-removable media implemented in any method or technology for storing information (such as computer-readable instructions, data structures, program modules, or other data). Computer storage media include, but are not limited to, RAM, ROM, EEPROM, flash memory or other memory technologies, CD-ROM, digital versatile disc (DVD) or other optical disc storage, magnetic cartridges, magnetic tape, disk storage or other magnetic storage devices, or any other medium that can be used to store desired information and can be accessed by a computer. Furthermore, it is well known to those skilled in the art that communication media typically contain computer-readable instructions, data structures, program modules, or other data in modulated data signals such as carrier waves or other transmission mechanisms, and may include any information delivery medium.

Claims

1. A method for quantitatively predicting gas reservoir recovery rate, characterized in that, The method includes: Obtain relevant reservoir parameters for the target gas reservoir; Based on the pre-established relationship between the comprehensive compressibility coefficient and the stress sensitivity coefficient in the gas reservoir parameters, the comprehensive compressibility coefficient in the gas reservoir parameters is determined; The abandoned wellbore flowing pressure of the gas reservoir is determined based on relevant gas reservoir parameters, and the abandoned formation pressure of the gas reservoir is determined using the calculation formula of abandoned formation pressure. The gas recovery rate is determined using a pre-established water-bearing gas reservoir recovery model based on the comprehensive compression coefficient and the abandoned formation pressure of the gas reservoir.

2. The method for quantitatively predicting gas reservoir recovery rate according to claim 1, characterized in that, The recovery rate model for the water-bearing gas reservoir is as follows: Where R is the gas reservoir recovery rate, G is the gas reservoir geological reserves, and G p The cumulative gas production of the gas reservoir; p a For abandoned formation pressure, p i Z represents the original formation pressure. a Z is the gas deviation factor under formation abandonment pressure. i C is the gas deviation factor under the original formation pressure. e The overall compression coefficient; Δp = p i -p a Δp is the pressure difference between the original formation and the abandoned formation; ω is the water volume coefficient.

3. The method for quantitatively predicting gas reservoir recovery rate according to claim 2, characterized in that, The water storage volume coefficient is: Where ω is the water storage volume coefficient, W is the geological storage of water in the gas reservoir, and W p To accumulate water production, B w B is the volume factor of formation water. Wi B is the volume factor of water under the original formation pressure. gi This is the volume factor of the gas under the original formation pressure.

4. The method for quantitatively predicting gas reservoir recovery rate according to claim 1, characterized in that, The overall compression coefficient C e for: Where Δp is the pressure difference, Δp = p i -p a p i p represents the original formation pressure. a For abandoned formation pressure; C w S is the compressibility coefficient of the liquid. wi To constrain water saturation, α k This is the stress sensitivity coefficient.

5. The method for quantitatively predicting gas reservoir recovery rate according to claim 4, characterized in that, The process of establishing the relationship between the comprehensive compressibility coefficient and the stress sensitivity coefficient in gas reservoir parameters is as follows: Establish the relationship between rock compressibility coefficient and stress sensitivity coefficient based on gas reservoir parameters; To obtain the relationship between the overall compression coefficient and the rock compression coefficient; Based on the relationship between the rock compressibility coefficient and the stress sensitivity coefficient, and the relationship between the comprehensive compressibility coefficient and the rock compressibility coefficient, a relationship between the comprehensive compressibility coefficient and the stress sensitivity coefficient is established.

6. The method for quantitatively predicting gas reservoir recovery rate according to claim 5, characterized in that, Relationship between rock compressibility coefficient and stress sensitivity coefficient: Among them, C p is the rock compressibility coefficient.

7. The method for quantitatively predicting gas reservoir recovery rate according to claim 1, characterized in that, The process of determining the bottom-hole flowing pressure of an abandoned gas reservoir is as follows: Obtain abandoned wellhead pressure and abandoned production; Based on the abandoned wellhead pressure and abandoned production, the abandoned well bottom pressure is calculated using a gas-water two-phase vertical pipe flow model.

8. The method for quantitatively predicting gas reservoir recovery rate according to claim 7, characterized in that, The pressure of the abandoned formation is: Where, p a For abandoned formation pressure, p wa For abandoned well bottom flow pressure; Where, r e r is the vent radius. w Let λ be the radius of the wellbore. T To initiate the pressure gradient.

9. A device for quantitatively predicting gas reservoir recovery rate, characterized in that, The apparatus includes a memory and a processor; the memory is used to store a program for quantitatively predicting gas reservoir recovery, and the processor is used to read and execute the program for quantitatively predicting gas reservoir recovery, and to execute the method according to any one of claims 1-8.

10. A computer-readable storage medium storing a data processing program, the data processing program being executed by a processor as the method for quantitatively predicting gas reservoir recovery according to any one of claims 1-8.

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