Method and device for exploiting water-containing tight sandstone gas reservoir gas well

Abstract

The invention discloses a water-containing tight sandstone gas reservoir gas well exploitation method and device, and relates to the technical field of oil and gas development, and the method comprises the following steps: obtaining gas reservoir stratum data and fluid property data; the gas reservoir stratum data, the fluid property data and the gas-water two-phase mathematical model are used for calculation, and the water phase yield and the gas phase yield of the gas well are output; the gas-water two-phase mathematical model is established in advance based on fluid kinematics by utilizing a gas-water phase permeability curve under the condition that the crack has infinite flow conductivity and the water-gas ratio continuously changes in the process that fluid permeates to a shaft through the crack; the input of the gas-water two-phase mathematical model is gas reservoir stratum data and fluid property data, and the output of the gas-water two-phase mathematical model is water phase yield and gas phase yield; the cracks are symmetrically distributed along two wings of the shaft; and determining the production allocation proportion of the gas well by using the water phase yield and the gas phase yield of the gas well. According to the method, the prediction accuracy of the water phase yield and the gas phase yield of the water-containing tight sandstone gas reservoir gas well can be improved.

Description

Technical Field

[0001] This invention relates to the field of oil and gas development technology, and in particular to a method and apparatus for developing gas wells in water-bearing tight sandstone gas reservoirs. Background Technology

[0002] This section is intended to provide background or context for the embodiments of the invention set forth in the claims. The description herein is not an admission that it is prior art simply because it is included in this section.

[0003] Water-bearing tight gas reservoirs are characterized by strong heterogeneity, low permeability, and high water saturation, leading to significant challenges in the overall effective development of these reservoirs. They commonly suffer from the "three lows" problem: low reserve control, low single-well productivity, and low recovery rate, posing a severe challenge to the effective utilization of reserves. Tight gas reservoirs typically contain water, have complex gas-water relationships, and often exhibit wellbore fluid accumulation, resulting in low reserve utilization rates, sometimes as low as 25.7%. Furthermore, the reservoir area usually contains substantial untapped geological reserves, reaching up to 0.84 × 10¹² m³. 3 Water production from gas wells severely restricts the development of gas fields.

[0004] Currently, the development of gas reservoirs typically utilizes gas well production data for production allocation design. For example, gas well productivity equations are established using gas well production engineering parameters, and production allocation is designed using these equations. Alternatively, shale gas reservoirs are divided into fracture systems and matrix systems, and productivity equations for each system are used to predict the water phase and gas phase production of gas wells, followed by production allocation design. Another approach is to combine well productivity equations with gas reservoir mass balance equations for gas well production design. However, these existing technologies are not well-suited for water-bearing tight gas reservoirs. Water-bearing tight gas reservoirs have high water production, and the existing productivity equations have low accuracy in predicting the water phase and gas phase production of gas wells in these reservoirs, resulting in poor reliability in the design of gas well production schemes for water-bearing tight sandstone gas reservoirs. Summary of the Invention

[0005] This invention provides a method for developing gas wells in water-bearing tight sandstone gas reservoirs, aiming to improve the accuracy of predicting the water phase and gas phase production of gas wells in such reservoirs and enhance the reliability of gas well development schemes. The method includes:

[0006] Acquire gas reservoir formation data and fluid property data;

[0007] The gas well's water phase production and gas phase production are calculated using gas reservoir formation data, fluid property data, and a gas-water two-phase mathematical model. The gas-water two-phase mathematical model is pre-established based on fluid kinematics, taking into account the infinite conductivity of fractures and the continuous change in the water-to-gas ratio as the fluid seeps through the fractures into the wellbore. The inputs to the gas-water two-phase mathematical model are gas reservoir formation data and fluid property data, and the outputs are water phase production and gas phase production. The fractures are symmetrically distributed along both sides of the wellbore.

[0008] The production ratio of gas wells is determined by using the water phase production and gas phase production of the gas wells.

[0009] This invention also provides a gas well development device for water-bearing tight sandstone gas reservoirs, used to improve the accuracy of predicting the water phase production and gas phase production of gas wells in water-bearing tight sandstone gas reservoirs, and to improve the reliability of gas well development schemes for water-bearing tight sandstone gas reservoirs. The device includes:

[0010] The data acquisition module is used to acquire gas reservoir formation data and fluid property data;

[0011] The production capacity calculation module is used to calculate the water phase production and gas phase production of the gas well using gas reservoir formation data, fluid property data, and a gas-water two-phase mathematical model. The gas-water two-phase mathematical model is established in advance based on fluid kinematics, taking into account the infinite conductivity of fractures and the continuous change of the water-gas ratio during fluid seepage through fractures to the wellbore. The inputs to the gas-water two-phase mathematical model are gas reservoir formation data and fluid property data, and the outputs are water phase production and gas phase production. The fractures are symmetrically distributed along both sides of the wellbore.

[0012] The production ratio determination module is used to determine the production ratio of gas wells based on the water phase production and gas phase production of the gas wells.

[0013] This invention also provides a computer device, including a memory, a processor, and a computer program stored in the memory and executable on the processor. When the processor executes the computer program, it implements the above-described method for developing gas wells in water-bearing tight sandstone gas reservoirs.

[0014] This invention also provides a computer-readable storage medium storing a computer program that, when executed by a processor, implements the above-described method for developing gas wells in water-bearing tight sandstone gas reservoirs.

[0015] This invention also provides a computer program product, which includes a computer program that, when executed by a processor, implements the above-described method for developing gas wells in water-bearing tight sandstone gas reservoirs.

[0016] In this embodiment of the invention, gas reservoir formation data and fluid property data are acquired; calculations are performed using the gas reservoir formation data, fluid property data, and a gas-water two-phase mathematical model to output the water phase production and gas phase production of the gas well; the gas-water two-phase mathematical model is established in advance based on fluid kinematics, taking into account the infinite conductivity of fractures and the continuous change of the water-gas ratio during fluid seepage through fractures to the wellbore; the inputs to the gas-water two-phase mathematical model are gas reservoir formation data and fluid property data, and the outputs are water phase production and gas phase production; the fractures are symmetrically distributed along both sides of the wellbore; the gas well production ratio is determined using the water phase production and gas phase production of the gas well. In this embodiment of the invention, considering the infinite conductivity of fractures and the continuous change of the water-gas ratio during fluid seepage through fractures to the wellbore, a two-phase mathematical model of gas and water is established based on fluid kinematics using the gas-water phase permeation curve. This model calculates the water phase yield and gas phase yield based on the characteristics of infinite conductivity of fractures and the continuous change of the water-gas ratio. Experiments show that the calculation results of this model are consistent with the water and gas distribution of water-bearing tight sandstone gas reservoirs, making it more suitable for the exploitation design of water-bearing tight sandstone gas reservoirs. This improves the accuracy of predicting the water phase yield and gas phase yield of gas wells in water-bearing tight sandstone gas reservoirs and enhances the reliability of gas well exploitation schemes in water-bearing tight sandstone gas reservoirs. Attached Figure Description

[0017] To more clearly illustrate the technical solutions in the embodiments of the present invention or the prior art, the drawings used in the description of the embodiments or the prior art will be briefly introduced below. Obviously, the drawings described below are only some embodiments of the present invention. For those skilled in the art, other drawings can be obtained based on these drawings without creative effort. In the drawings:

[0018] Figure 1 This is a schematic flowchart of the gas well extraction method for water-bearing tight sandstone gas reservoirs in an embodiment of the present invention;

[0019] Figure 2 This is a schematic diagram of a pressure drop funnel in a tight gas reservoir according to an embodiment of the present invention;

[0020] Figure 3 This is a schematic diagram illustrating the change in the water-to-gas ratio with the bottom-hole flowing pressure in an embodiment of the present invention;

[0021] Figure 4 This is a side view of the physical model for vertical well fracturing in an embodiment of the present invention;

[0022] Figure 5 This is a top view schematic diagram of the vertical well fracturing seepage model in an embodiment of the present invention;

[0023] Figure 6 This is a schematic diagram of isobars and streamlines of a two-dimensional elliptical flow in a planar configuration according to an embodiment of the present invention.

[0024] Figure 7 The gas-water phase permeation curve is shown in the embodiment of the present invention;

[0025] Figure 8 This is a graph showing the variation of water-gas ratio with bottom hole flowing pressure in an embodiment of the present invention;

[0026] Figure 9 This is a graph showing the change in yield with water-to-air ratio in an embodiment of the present invention;

[0027] Figure 10 This is an example diagram of crack half-length sensitivity analysis in an embodiment of the present invention;

[0028] Figure 11 This is an example diagram of reservoir permeability sensitivity analysis in an embodiment of the present invention;

[0029] Figure 12 This is a comparison chart of the production capacity curves of well A in an embodiment of the present invention;

[0030] Figure 13 This is a comparison chart of the production capacity curves of well B in an embodiment of the present invention;

[0031] Figure 14 This is a graph showing the pressure loss relationship under different water-to-air ratios in an embodiment of the present invention.

[0032] Figure 15 This is a production curve diagram of a low-water-yield gas well in an embodiment of the present invention;

[0033] Figure 16 This is a production curve diagram of a gas well with high atmospheric and high water content in an embodiment of the present invention;

[0034] Figure 17 This is a production curve diagram of a medium-to-high water-yielding gas well in an embodiment of the present invention;

[0035] Figure 18 This is a schematic diagram of the variation of the production coefficient of water-producing gas wells in an embodiment of the present invention;

[0036] Figure 19 This is a schematic diagram of fluid flow in the reservoir and wellbore in an embodiment of the present invention;

[0037] Figure 20 This is a graph showing the relationship between the critical velocity coefficient and the gas-water velocity ratio in an embodiment of the present invention;

[0038] Figure 21 This is a schematic diagram illustrating the calculation results of the critical liquid-carrying flow rate in an embodiment of the present invention;

[0039] Figure 22 Illustrations of technical countermeasures for the full life cycle management of different types of gas wells in embodiments of the present invention;

[0040] Figure 23This is a schematic diagram of a gas well extraction device for a water-bearing tight sandstone gas reservoir in an embodiment of the present invention. Detailed Implementation

[0041] To make the objectives, technical solutions, and advantages of the embodiments of the present invention clearer, the embodiments of the present invention will be further described in detail below with reference to the accompanying drawings. Here, the illustrative embodiments of the present invention and their descriptions are used to explain the present invention, but are not intended to limit the present invention.

[0042] The acquisition, storage, use, and processing of data in this application all comply with the relevant provisions of national laws and regulations.

[0043] The applicant found that the existing production capacity equations have low accuracy in predicting the water phase and gas phase production of gas wells in water-bearing tight gas reservoirs, resulting in poor reliability in the design of gas well development schemes for water-bearing tight sandstone gas reservoirs. Therefore, the applicant proposes a method for developing gas wells in water-bearing tight sandstone gas reservoirs.

[0044] Figure 1 This is a schematic flowchart of a gas well extraction method for water-bearing tight sandstone gas reservoirs in an embodiment of the present invention, as shown below. Figure 1 As shown, the method includes:

[0045] Step 101: Obtain gas reservoir formation data and fluid property data;

[0046] Step 102: Calculate the water phase production and gas phase production of the gas well using gas reservoir formation data, fluid property data, and a gas-water two-phase mathematical model. The gas-water two-phase mathematical model is pre-established based on fluid kinematics, taking into account the infinite conductivity of fractures and the continuous change of the water-gas ratio during fluid seepage through fractures to the wellbore. The inputs to the gas-water two-phase mathematical model are gas reservoir formation data and fluid property data, and the outputs are water phase production and gas phase production. The fractures are symmetrically distributed along both sides of the wellbore.

[0047] Step 103: Determine the gas well production ratio by using the water phase production and gas phase production of the gas well.

[0048] from Figure 1As can be seen from the flowchart, in this embodiment of the invention, considering the infinite conductivity of fractures and the continuous change of the water-gas ratio during the fluid seepage through the fractures to the wellbore, a two-phase mathematical model of gas and water is established based on fluid kinematics using the gas-water phase permeation curve. This model calculates the water phase production and gas phase production based on the characteristics of infinite conductivity of fractures and the continuous change of the water-gas ratio. Experiments show that the calculation results of this model are consistent with the water and gas distribution of water-bearing tight sandstone gas reservoirs, making it more suitable for the exploitation design of water-bearing tight sandstone gas reservoirs. This improves the accuracy of predicting the water phase production and gas phase production of gas wells in water-bearing tight sandstone gas reservoirs and enhances the reliability of gas well exploitation schemes in water-bearing tight sandstone gas reservoirs.

[0049] The following is a detailed explanation of the gas well extraction method for water-bearing tight sandstone gas reservoirs in the embodiments of the present invention.

[0050] In this embodiment of the invention, engineering data and production data of gas well extraction are first obtained, mainly gas reservoir formation data and fluid property data.

[0051] In one embodiment, the gas reservoir formation data includes, but is not limited to, one or any combination of the following:

[0052] Permeability, matrix stress sensitivity coefficient, original formation pressure, fracture tip pressure;

[0053] The fluid property data includes, but is not limited to, one or any combination of the following:

[0054] Vapor phase viscosity, aqueous phase viscosity, vapor phase density, aqueous phase density.

[0055] The aforementioned gas reservoir formation data and fluid property data are obtained for subsequent production capacity calculations.

[0056] In order to efficiently obtain effective gas reservoir formation data and fluid property data, the gas-water distribution pattern of the gas reservoir to be exploited can be analyzed first. Based on the gas-water distribution pattern, gas reservoir formation data and fluid property data can be obtained from gas wells at appropriate locations.

[0057] The following example illustrates the gas-water distribution pattern analysis of 577 test wells in three gas reservoirs (A, B, and C) to be exploited.

[0058] Production dynamics analysis was conducted using data from 577 test wells in three gas reservoirs (A, B, and C) to be developed. The analysis revealed that 240 of these wells produced water during testing, with an average water-to-gas ratio of 1.0–1.4 m³. 3 / 10 4 m 3Due to high water production, the proportion of low-yield and inefficient wells in all three well areas exceeds 60%. The undeveloped gas field is generally located near the gas-water transition zone at the reservoir boundary, exhibiting weak hydrocarbon generation and poor ability to displace formation water. The reservoirs exist in a gas-water co-layered manner, with pure gas layers scattered and gas-water-bearing layers widely distributed. Vertically, gas and water layers are distributed in a lenticular, intersecting pattern, without a unified gas-water interface; there is no significant gas-water differentiation within the same reservoir unit; the proportion of gas layers gradually decreases from bottom to top, while the proportion of gas-water co-layers and gas-water-bearing layers increases. The effective reservoir has a high water saturation, and production wells often produce both gas and water simultaneously, resulting in wellbore fluid accumulation. Single-well water production ranges from 0 to 46.5 m³. 3 / d, the main types are stagnant water and free water.

[0059] During implementation, after obtaining data from test wells and a textual description of gas-water distribution patterns, quantitative results of gas-water distribution patterns are calculated and output using big data decision-making and natural language processing. For example, the output may include the following three aspects of results, which are not limited to textual form but can also be output in the form of charts and graphs.

[0060] (1) Results of research on microscopic water production mechanism

[0061] The gas-water occurrence state of the gas reservoir to be developed is divided into four residual water distribution patterns: thin water film, thick water film, water column, and water droplet. The original water saturation ranges from 30.5% to 62.7%, with an average water saturation of 42.0%. The relative permeability of the gas phase decreases faster than that of the water phase. The saturation of bound water is lower than that at room temperature. The high saturation of movable water seriously affects the production of gas wells. Water production is affected by the combined effects of reservoir properties, reservoir heterogeneity, production pressure differential, and gas saturation.

[0062] (2) Distribution pattern of air surface

[0063] The hydrocarbon generation intensity of the gas reservoirs to be developed varies considerably, gradually decreasing from southeast to northwest. The development of gas-water layers and gas-water co-layers gradually increases. In the eastern nose-ridge, natural gas is generally enriched, while water is produced in the nose depression and local structural low-lying areas, with few and scattered water-producing wells. In the south, there is a water-rich zone, with concentrated formation water in the structural nose depression, and some wells producing significant water. Formation water is scattered in the central area, and the water volume is relatively large. The western area is generally water-rich, with large water production at water-producing wells, and local natural gas enrichment in the nose-ridge, resulting in significant overall water production. The northern low-permeability zone is mainly composed of stagnant water and isolated lenticular water, with more gas-water co-layers.

[0064] (3) The gas and water content are significantly different, with no uniform gas-water interface.

[0065] The hydrocarbon generation intensity in the gas reservoir to be developed is significantly correlated with the development of the gas layer, controlling the macroscopic distribution pattern of gas and water. The greater the hydrocarbon generation intensity, the more developed the gas layer is. The heterogeneity of the reservoir mainly controls the charging and accumulation of natural gas. Overall, the aquifer is developed, and vertically, gas and water are mainly in the same layer. The gas and water are poorly differentiated inside the reservoir, and there is no unified gas-water interface.

[0066] Based on the distribution patterns of steam and water, select appropriate gas wells to obtain gas reservoir formation data and fluid property data.

[0067] Then, the gas-water two-phase mathematical model is used to calculate the production capacity. The gas-water two-phase mathematical model is established in advance based on fluid kinematics, taking into account the infinite conductivity of the fractures and the continuous change of the water-gas ratio during the fluid seepage through the fractures to the wellbore. The inputs of the gas-water two-phase mathematical model are gas reservoir formation data and fluid property data, and the outputs are water phase production and gas phase production.

[0068] The process of establishing the gas-water two-phase mathematical model is described below.

[0069] The gas-water two-phase flow equation is crucial for the production of water-producing gas wells. In actual production, the water-gas ratio varies widely, and the changes in reservoir stress have a significant impact on production capacity. In order to accurately describe the variation law of production capacity of water-producing gas wells, this embodiment of the invention adopts flow theory and gas reservoir engineering methods to establish a new gas-water two-phase production capacity equation, namely the variable water-gas ratio two-phase equation.

[0070] Refer to Table 1. Figure 2 The pore throats of tight gas reservoirs are mainly composed of nano- and micro-capillary structures. The pressure drop funnel of tight gas reservoirs is steeper. As the effective pressure increases, the rate of permeability decreases rapidly. According to the Krüger curve, the slippage effect has little impact on permeability. Therefore, microscopic mechanism studies show that tight gas reservoirs have obvious non-Darcy flow and stress sensitivity characteristics.

[0071] Table 1. Reservoir parameters for tight gas reservoirs with different pore-throat types.

[0072]

[0073] Raw gas-water two-phase flow production capacity equation:

[0074]

[0075] In formula (1), q gsc The gas phase yield is represented by k, reservoir permeability is represented by h, and p' is represented by p'. w For the water phase pressure, p wf λ is the bottom hole flowing pressure, λ is the starting pressure, and ψ(p') is the bottom hole flowing pressure. w ) represents the pseudo-pressure of the water phase, ψ(p) wf) represents the pseudo-pressure of the bottom hole flowing pressure, ψ(λ) represents the pseudo-pressure of the starting pressure, and ρ gsc ρ is the gas phase density under standard conditions. wsc The density of the aqueous phase under standard conditions is given by WGR, which represents the water-to-air ratio, and r is the density of the aqueous phase under standard conditions. e r represents the radius of the gas reservoir. w S represents the wellbore radius, and S represents the skin coefficient.

[0076] The following settings are made in the embodiments of the present invention:

[0077] (1) Assuming the reservoir is isotropic, it is divided into two regions: the outer sandstone reservoir is dense with low permeability and the gas-water two-phase flow is elliptical, and dissolved gas is not considered; the inner reservoir has vertical fractures, which are symmetrically distributed along the two wings of the wellbore and have unlimited conductivity.

[0078] (2) Consider the stress sensitivity of the reservoir, that is, the permeability will decrease as the formation pressure decreases;

[0079] (3) Assume that during the seepage process, the water-to-gas ratio changes with the bottom-hole pressure;

[0080] (4) The model derivation uses SI mining farm practical units. For ease of calculation, the gas production unit is m. 3 / d means.

[0081] Figure 3 This is a schematic diagram illustrating the change in the water-to-gas ratio with bottom hole flowing pressure in an embodiment of the present invention, as shown below. Figure 3 As shown, the production water-gas ratio increases with decreasing bottom hole pressure, and the rate of increase accelerates. This indicates that a constant water-gas ratio should not be used when calculating gas well productivity; instead, a productivity equation that considers a variable water-gas ratio should be used.

[0082] Figure 4 This is a side view schematic diagram of the physical model for vertical well fracturing in an embodiment of the present invention. Figure 5 This is a top view schematic diagram of the vertical well fracturing seepage model in an embodiment of the present invention, with reference to... Figure 4 Considering a gas reservoir with a circular, closed boundary and a reservoir thickness of h, fractures extend along both sides of the wellbore, penetrating the entire thickness of the reservoir, with a fracture width of w. f The half-length of the crack is x f ,refer to Figure 5 The fluid first flows into the fracture, and then flows from the fracture into the wellbore.

[0083] The presence of vertical cracks causes the fluid to undergo planar two-dimensional elliptical seepage during the seepage process. The equipotential lines are a cluster of ellipses with the crack half-length as the focal length, and the streamlines are a cluster of hyperbolas with the crack half-length as the focal length. (Reference) Figure 6 , Figure 6This is a schematic diagram of isobars and streamlines for a two-dimensional elliptical flow in a planar configuration according to an embodiment of the present invention. The isobars and streamlines for a two-dimensional elliptical seepage flow in a planar configuration can be represented as follows:

[0084]

[0085]

[0086] In formulas (2) and (3), a and b are the semi-major and semi-minor axes of the ellipse, respectively, in meters (m); x f ξ is the half-length of the crack, in meters. ch and sh are the hyperbolic cosine and hyperbolic sine functions, respectively. cos and sin are the cosine and sine functions, respectively. ξ is the angle corresponding to the ellipse equation, and η is the angle corresponding to the hyperbolic equation.

[0087] For ease of solution, based on the concept of perturbation ellipse, the isobaric elliptic family is described by an evolved rectangular family:

[0088]

[0089] In formula (4), and The rectangular clusters formed represent isobars.

[0090] For a vertical crack parallel to the x-axis, x f >>w f The fluid seepage from the reservoir to the fracture is mainly along the y-direction. Therefore, considering only the fluid seepage perpendicular to the fracture surface and conforming to Darcy's law, the fluid motion equation can be expressed as follows:

[0091]

[0092] In formula (5), K m The value represents matrix permeability, expressed in mD, while μ represents fluid viscosity, expressed in mPa·s. represent Directional pressure gradient, in MPa.

[0093] Considering the two-phase motion of gas and water and the sensitivity to permeability stress, the motion equations for the gas and water phases are obtained respectively:

[0094]

[0095] In formula (6), v g and v w Representing gas phase yield and aqueous phase yield respectively, m 3 / d; Kmi represents the initial permeability of the matrix, mD; K rg and K rw They represent the relative permeability of the gas phase and the relative permeability of the aqueous phase, respectively; decimal; μg μ w Representing the gas phase viscosity and aqueous phase viscosity, respectively, in m·Pas; α m Represents the matrix stress sensitivity coefficient, MPa -1 ;p i Represents the original formation pressure, in MPa.

[0096] In formula (6):

[0097]

[0098]

[0099] In formula (8), q gsc The gas phase yield under standard conditions, m 3 / d;ρ gsc Gas density under standard conditions, kg / m³ 3 ;ρ g Represents the gas phase density under reservoir conditions, kg / m³ 3 h represents reservoir thickness, in meters (m).

[0100]

[0101] In formula (9), q wsc The yield of aqueous phase under standard conditions, m 3 / d;ρ wsc The density of the aqueous phase under standard conditions is kg / m³. 3 ;ρ w Represents the density of the water phase under reservoir conditions, kg / m³ 3 Formulas (8) and (9) represent the conversion of surface flow rate into underground flow velocity.

[0102] Separating the variables from equation (6), we obtain the governing equations for the gas phase and the aqueous phase, respectively:

[0103]

[0104]

[0105] Define the pseudo-pressure of the gas phase as:

[0106]

[0107] Define the pseudo-pressure of the aqueous phase as:

[0108]

[0109] The production capacity formulas for the gas phase and the water phase are obtained separately, i.e., the two-phase equations with varying water-to-gas ratio:

[0110]

[0111]

[0112] There are also some variables in equations (14) and (15), refer to equations (12) and (13), where ξ e The corresponding major semi-axis is r e An ellipse, ξ f Corresponding semi-major axis a→x f At this point, the minor semi-axis b→0. For ease of calculation, we take ξ. f The corresponding minor axis is w f / 2, from the perturbation ellipse, we get:

[0113]

[0114] In summary, equations (12)(13)(14)(15)(16) constitute a two-phase equation with varying water-to-gas ratio.

[0115] It can be seen that the inputs to the two-phase equation with varying water-to-gas ratio include the relative permeability of the gas phase and the relative permeability of the water phase. The relative permeability of the gas phase and the relative permeability of the water phase can be determined as follows:

[0116] 1) Define the ratio of water-gas two-phase volumetric flow rates (water-gas ratio) under standard surface conditions as WGR, i.e.:

[0117]

[0118] In formula (17), q wsc q represents the aqueous phase yield under standard conditions. gsc This represents the gas phase yield under standard conditions.

[0119] 2) Determine the mathematical relationship between the first ratio and the water-air ratio. The first ratio is the ratio of the relative permeability of the gas phase to the relative permeability of the water phase:

[0120]

[0121] In formula (18), K rg and K rw They represent the relative permeability of the gas phase and the relative permeability of the water phase, respectively. The character interpretations are the same as in equations (6), (7), and (8).

[0122] 3) Obtain the gas-water phase permeability curve through experiments. Figure 7 The gas-water phase permeation curve is shown in the embodiment of the present invention. Figure 7 Display the relative permeability curves of the matrix air and water. Figure 7 In the equation, the horizontal axis represents water saturation, and the vertical axis represents the relative permeability of the gas and water phases. The regression equation represents the change in relative permeability with water saturation.

[0123] 4) Based on the gas-water phase permeability curve, the mathematical relationship between the first ratio and the water-gas ratio, and the WGR value, the relative permeability of the gas phase and the relative permeability of the water phase can be obtained.

[0124] Therefore, in one embodiment, the gas-water two-phase mathematical model includes a variable water-gas ratio two-phase equation, a gas-water phase permeability curve, and a mathematical relationship between a first ratio and the water-gas ratio; the first ratio is the ratio of the relative permeability of the gas phase to the relative permeability of the water phase, and the variable water-gas ratio two-phase equation is established based on fluid kinematics under the condition that the fracture has infinite conductivity and the water-gas ratio changes continuously during the process of fluid seeping through the fracture to the wellbore. The variable water-gas ratio two-phase equation reflects the correspondence between gas reservoir formation data, fluid property data, and water phase production and gas phase production.

[0125] Step 102 may include:

[0126] Set the initial water-air ratio and crack tip pressure;

[0127] Using the initial water-air ratio and the pressure at the fracture tip, perform the following iterative calculations until the difference between the initial water-air ratio and the latest water-air ratio is less than a preset value:

[0128] Using the mathematical relationship between the first ratio and the water-air ratio, and the initial water-air ratio, determine the ratio of the relative permeability of the gas phase to the relative permeability of the water phase.

[0129] The relative permeability of the gas phase and the relative permeability of the water phase are obtained by using the ratio of the relative permeability of the gas phase to the relative permeability of the water phase and the gas-water phase permeability curve.

[0130] Input the relative permeability of the gas phase, the relative permeability of the water phase, the fracture tip pressure, and the fluid properties into the variable water-gas ratio two-phase equation to output the water phase production and gas phase production of the gas well;

[0131] The latest water-gas ratio is obtained by utilizing the water phase production and gas phase production of the gas well;

[0132] Calculate the difference between the initial water-air ratio and the latest water-air ratio;

[0133] If the difference between the initial water-gas ratio and the latest water-gas ratio is not less than the preset value, the latest water-gas ratio is assigned to the initial water-gas ratio.

[0134] During implementation, since it is assumed that the fracture has infinite conductivity, the bottom hole pressure is equal to the fracture tip pressure. Given a bottom hole pressure, i.e., the fracture tip pressure, the corresponding water production and gas production can be calculated. The solution is obtained by iteratively solving the problem based on the calculated water-gas ratio and the initial water-gas ratio.

[0135] The specific steps are as follows:

[0136] (1) Assuming an initial water-to-gas ratio WGR 0;

[0137] (2) Using the gas-water interpenetration curve, the mathematical relationship between the first ratio and the water-air ratio, and WGR 0 Calculate the relative permeability of the gas phase and the relative permeability of the water phase respectively;

[0138] (3) Calculate the corresponding pseudo-pressure using equations (12) and (13);

[0139] (3) Using equations (14), (15), and (16), calculate the water phase production and gas phase production under a certain bottom hole flowing pressure, and calculate the corresponding water-gas ratio WGR. 1 ;

[0140] (4) Compare WGR 0 and WGR 1 If the accuracy requirement is met, i.e., |WGR 0 -WGR 1 If |<ε, (preset value ε=0.00001) then WGR is considered to be... 1 The water-gas ratio corresponding to a certain bottomhole flowing pressure is the actual production capacity; otherwise, the calculated WGR will be used. 1 Use the substitute as the initial water-to-gas ratio input and repeat steps (2)-(4).

[0141] It should be noted that if the number of iterations for calculating the gas production under a certain bottomhole flowing pressure exceeds the set value (set according to the actual situation, for example, if the number of iterations is too many and good results are not obtained), the loop will be terminated. This indicates that there is a problem with the gas reservoir formation data, fluid property data or some parameters used in the formula, and all of them need to be re-determined and recalculated.

[0142] The theoretical calculation results of the gas-water two-phase mathematical model show that the water-gas ratio changes with the bottom hole pressure in some gas wells, which is consistent with actual production. Furthermore, the variable water-gas ratio two-phase equation takes into account the influence of stress sensitivity. Theoretical analysis suggests that for gas wells, the production capacity is significantly affected by stress sensitivity. As the stress sensitivity index increases, the unobstructed flow rate and maximum flow rate of the gas well decrease. The lower the bottom hole pressure, the greater the impact of stress sensitivity on production capacity. This demonstrates that the gas-water two-phase mathematical model in this embodiment has a wider range of applications.

[0143] The water-to-gas ratio is not constant during changes in bottom hole pressure; rather, it increases as the bottom hole pressure decreases. Therefore, using a constant water-to-gas ratio to calculate gas well productivity may lead to an overestimation of the calculated productivity, thus affecting production allocation and exacerbating water production in the gas well. (Refer to...) Figure 8 , Figure 8 In the middle, the horizontal axis P wf The bottom-hole flowing pressure is represented by the main vertical axis and the secondary vertical axis, which are the gas phase production and the water-gas ratio, respectively.

[0144] Figure 9 The relationship between gas well production and water-gas ratio during the iteration process is shown. Figure 9 In the diagram, the horizontal axis represents the water-to-gas ratio, and the vertical axis represents the gas phase yield. Figure 9 As can be seen, gas well productivity is positively correlated with the water-gas ratio, reflecting that the water-gas ratio also changes continuously as gas well production changes. Therefore, it is reasonable to consider an iterative solution model with a variable water-gas ratio.

[0145] The embodiments of the present invention consider the impact of crack length on production capacity and perform crack half-length sensitivity analysis. Figure 10 This is an example diagram of crack half-length sensitivity analysis in an embodiment of the present invention, provided by... Figure 10 It can be seen that as the fracture half-length increases, the gas well production capacity increases. Without considering water production, appropriate measures can be taken to increase the fracture half-length as much as possible to maximize production capacity.

[0146] The embodiments of the present invention consider the impact of reservoir permeability on production capacity and perform reservoir permeability sensitivity analysis. Figure 11 This is an example diagram of reservoir permeability sensitivity analysis in an embodiment of the present invention. Figure 11 It can be seen that as the matrix stress sensitivity coefficient α... m As stress sensitivity increases, gas well production capacity decreases, but this decrease is not indefinite. As stress sensitivity coefficient continues to increase, its impact on production capacity gradually diminishes.

[0147] The following is a comparative experimental example illustrating the calculation of aqueous phase yield and gas phase yield using the gas-water two-phase mathematical model in this embodiment of the invention.

[0148] There are two wells, A and B. Well A has a formation pressure of 17.63 MPa, currently 9.5 MPa, permeability of 1.37 mD, gas layer thickness of 5.7 m, wellbore radius of 0.0797 m, supply radius of 800 m, skin factor of -0.0128, formation temperature of 384.1 K, and gas relative density of 0.6379 dim. Well B has a formation pressure of 29 MPa, currently 12.5 MPa, permeability of 0.19 mD, gas layer thickness of 5.1 m, wellbore radius of 0.0797 m, supply radius of 500 m, skin factor of -4.56, formation temperature of 370 K, and gas relative density of 0.5894 dim. Substituting the basic parameters of the two wells into the gas-water two-phase mathematical model and the existing production capacity equation (e.g., formula (1)) yields the production capacity comparison curves of the two wells, as follows: Figure 12 , Figure 13 As shown, Figure 12 , Figure 13 In the middle, q sc This refers to the output under the specified conditions, p. wfThis refers to the bottom-hole flowing pressure. The new formula represents the gas-water two-phase mathematical model in this embodiment of the invention. The original formula is the production capacity equation in the prior art. Also refer to Table 2.

[0149] Table 2

[0150]

[0151] The production capacity calculation results of the two water-producing gas wells show that the gas-water two-phase mathematical model in this embodiment of the invention is closer to reality than the production capacity equation in the prior art, with smaller errors and higher accuracy.

[0152] In this embodiment of the invention, the impact of a gas-water two-phase mathematical model on the productivity and recovery rate of water-producing gas wells was analyzed, with reference to... Figure 14 It was found that when the water-to-gas ratio is less than 0.5, the impact of water production on gas well production indicators is relatively small; however, when the water-to-gas ratio is greater than 1, its impact on production capacity exceeds 50%, recovery rate decreases by more than 17%, and pressure is affected by more than 10%. Figure 14 In the equation, y = 0.0421x 3 -1.1202x 2 +12.901x+0.8826 is the regression equation of the curve, where x represents the water-to-air ratio and y represents the percentage of pressure lost during water production.

[0153] Finally, in step 103, the gas well production ratio is determined using the water phase production and gas phase production of the gas well.

[0154] In one embodiment, before acquiring gas reservoir formation data and fluid property data, the following may also be included:

[0155] Acquire gas reservoir well test data, including the water-gas ratio;

[0156] Gas well types are determined by the water-to-gas ratio, and these types include water-producing gas wells, medium-to-high water-producing gas wells, and large-volume, high-water-producing gas wells.

[0157] Calculations are performed using gas reservoir formation data, fluid property data, and a gas-water two-phase mathematical model to output the water phase production and gas phase production of the gas well, including:

[0158] Calculations are performed using gas reservoir formation data, fluid property data, and a gas-water two-phase mathematical model to output the water phase production and gas phase production of different types of gas wells.

[0159] Determining the gas well production ratio based on the water phase and gas phase yields of the gas wells includes:

[0160] By utilizing the water phase and gas phase yields of different types of gas wells, the production allocation ratio for different types of gas wells can be determined.

[0161] In practical implementation, considering the scattered distribution of water-producing wells in the water-producing reservoir, their widespread distribution in the plane, the complex gas-water relationship in the vertical direction, and the diverse forms of formation water occurrence, research is quite difficult. Existing technologies classify formation water into three types—free water, impounded water, and bound water—based on the microscopic pore structure of the water-producing reservoir and the strong hydrophilicity of quartz sandstone. Based on the formation water occurrence state, this embodiment of the invention, according to structural characteristics, reservoir properties, the relationship between natural gas and formation water occurrence states, and combined with gas well testing patterns and production characteristics analysis, classifies gas well produced water into three categories: condensate water, formation pore water, and special locally sealed formation water.

[0162] (1) Condensate

[0163] Condensate water refers to formation water that coexists with natural gas in the form of gaseous molecules. There are two reasons for its formation: First, during the generation and migration of natural gas, high paleogeothermal temperatures promote the generation of a large amount of natural gas from organic matter in the source rock, and at the same time, cause the water in the source rock to change from liquid to gaseous state. Second, bound water in the reservoir pores can also be partially converted into gaseous condensate water under high temperature and high pressure conditions in the formation.

[0164] The water-to-gas ratio of condensate from gas wells in the study area is very low, averaging 0.08 m. 3 / 10 4 m 3 The production of condensate water is basically negligible.

[0165] (2) Formation pore water

[0166] Based on the microstructure and the strong hydrophilicity of quartz sandstone reservoirs, pore water is classified into three types: bound water, capillary water, and free water. The water-to-air ratio is less than 1 and relatively stable during production. Bound water is adsorbed on the rock surface and mainly develops in tight sandstone reservoirs, with a porosity <8% and permeability <0.35×10⁻⁶. -3 μm 2 Pore ​​size distribution <0.2μm; capillary water is typically distributed in reservoirs with strong vertical heterogeneity, containing water in small pores, with porosity distribution ranging from 8% to 10% and permeability distribution ranging from 0.35 to 1.1×10⁻⁶. -3 μm 2 The pore size distribution ranges from 0.2 to 0.7 μm; free water is typically found in reservoirs with homogeneity and good porosity, exhibiting weak vertical differentiation between gas and water, with porosity >10% and permeability >1.1 × 10⁻⁶. -3 μm 2 .

[0167] (3) Localized sealing of formation water

[0168] Locally sealed formation water exists in certain formations and can be subdivided into three categories based on the main controlling factors: edge (bottom) water, lens water, and residual formation water in gas reservoirs. Edge (bottom) water is located in reservoirs with good physical properties and high permeability. Due to the significant influence of structural undulations, water production is severe in the lower parts of the gas reservoir. In contrast, residual formation water in gas reservoirs has poorer physical properties and lower hydrocarbon expulsion pressure. This type of locally sealed formation water is significantly affected by reservoir heterogeneity and is more dispersed. Lens water is mainly distributed in the He8 Upper 1 formation. Due to migration conditions and the migration distance of source rocks, the water body is sealed by tight sandstone to form interlayers, exhibiting an isolated distribution. The water-to-gas ratio of locally sealed formation water is generally greater than 1. Due to the presence of sealed water at the bottom of the structural edge, gas wells exhibit characteristics of large gas production in the early stage of production, stable water-to-gas ratio, and a sudden increase in water-to-gas ratio in the later stage.

[0169] Different types of gas wells have different production characteristics.

[0170] refer to Figure 15 Low-yield water-producing wells have high initial production, reaching up to 10 × 10⁴ m³ per day. 3 / d, the pressure drop rate is relatively small, and the curve shows a gradual decreasing trend, which can maintain a good production state;

[0171] refer to Figure 16 Large-volume, high-water-yield wells have high initial production, maintaining a daily output of over 10,000 cubic meters. However, the pressure drop rate is relatively fast, with pressure and daily gas production decreasing rapidly in the early stages of production. The rate of decline remains high in the later stages, resulting in good initial production conditions but severe water production in the later stages, which restricts the production capacity of this type of gas well.

[0172] refer to Figure 17 Medium- to high-yield water-producing wells have low initial production, less than 10,000 cubic meters per day. In addition, the pressure drop rate is relatively fast, and the pressure drops rapidly in the early stage of production. There is not enough energy to carry the liquid for production, and the gas production capacity is even worse in the later stage. If no measures are taken to drain the water and produce gas, the life of such gas wells will be greatly reduced.

[0173] Table 3 shows the production statistics of different types of water-producing gas wells. As can be seen from Table 3, low-water-producing gas wells have the highest EUR (Ultimate Recoverable Reserves) value, and water production has the least impact on them. Medium- and high-water-producing gas wells have lower EUR indices and are the key wells for optimization measures. Timely drainage measures can extend the gas well's gas production life. Large-volume, high-water-producing gas wells also have higher EUR indices, but severe water production in the later stages of production greatly affects the gas well's production capacity and prevents it from realizing the advantages of EUR. Therefore, it is necessary to strengthen gas well management and prevent gas well flooding.

[0174] Table 3

[0175]

[0176] In practice, the water phase production and gas phase production of each type of gas well are calculated using the gas-water two-phase mathematical model in the embodiments of the present invention. The production ratio of different types of gas wells is determined by using the water phase production and gas phase production of different types of gas wells.

[0177] In one embodiment, determining the production ratio of different types of gas wells based on their water phase production and gas phase production can include:

[0178] The unobstructed flow rate during the gas well production process is determined by using the water phase production and gas phase production of the gas well.

[0179] By utilizing the unobstructed flow rate, gas well type, and pre-constructed production coefficient variation charts corresponding to different water-producing gas wells during the gas well production process, the reasonable production ratio of the gas well is determined.

[0180] Among them, the unobstructed flow rate refers to the maximum production when the bottom pressure is 0. In the gas-water two-phase mathematical model, the gas phase production when the bottom pressure is 0 is the unobstructed flow rate of the gas well.

[0181] Figure 18 This is a schematic diagram of the production coefficient variation of water-producing gas wells in an embodiment of the present invention. The reasonable production ratio of gas wells is determined by using the production coefficient corresponding to the unobstructed flow rate.

[0182] In one embodiment, after determining the gas well production allocation ratio using the water phase production and gas phase production of the gas well, the method may further include:

[0183] Obtain the natural gas density, droplet density, and surface tension of natural gas and droplets for each type of gas well;

[0184] Using the natural gas density, droplet density, surface tension of natural gas and droplets for each type of gas well, and a pre-constructed critical flow rate formula for each type of gas well, the critical liquid-carrying flow rate for each type of gas well is calculated.

[0185] By utilizing the critical liquid-carrying flow rate of each type of gas well, the drainage and gas production process for each type of gas well is determined.

[0186] In practice, once a gas well produces water, its liquid-carrying capacity decreases, which greatly affects production capacity.

[0187] Liquid in a water-producing gas well is mainly extracted in two forms: one is as a liquid film rising along the pipe wall, and the other is as droplets mixed in with the rising gas flow. In actual production, both forms exist and are constantly transformed and exchanged during the ascent.

[0188] Existing droplet models have certain limitations. When calculating the critical liquid-carrying flow rate, the forces acting on the droplet during its transport through the wellbore are calculated under equilibrium conditions, considering only the wellbore's liquid-carrying capacity and neglecting the influence of the reservoir's gas-water production capacity on the liquid-carrying flow rate. Therefore, the resulting critical liquid-carrying flow rate for gas wells is inaccurate. This invention combines reservoir and wellbore considerations to evaluate the critical liquid-carrying flow rate of a gas well. The critical gas-water flow velocities under reservoir conditions are calculated using relative permeability curves, while the critical gas-water flow velocities under wellbore conditions are calculated using liquid holdup.

[0189] refer to Figure 19 Water phase pressure equation:

[0190]

[0191] In the formula, p w (x) represents the bottom-hole flowing pressure of the aqueous phase, p1 represents the formation pressure, and μ w Let x be the viscosity of the aqueous phase, x be the discharge length of the aqueous phase, x1 be the discharge length, and B be the viscosity of the aqueous phase. w Q is the formation water volume factor. w (t) represents the water production, and K represents the effective permeability of the reservoir. rw Let A be the relative permeability of the water phase and A be the fluid seepage area.

[0192] Vapor phase pressure equation:

[0193]

[0194] In formula (20), p1(x) is the formation pressure, p g (x) represents the bottom-hole flowing pressure of the gas phase, Z represents the gas deviation coefficient, T represents the gas reservoir temperature, and μ g Where ρ is the gas phase viscosity. g Q is the relative density of natural gas. g (t) represents the gas production rate.

[0195] After simplification, we get:

[0196]

[0197] In formula (21), B g Formation gas volume coefficient.

[0198] Under standard conditions, T sc =293K, p sc =0.101325MPa.

[0199] Under reservoir conditions, assuming the gas phase pressure is greater than the water phase pressure, the reservoir can carry liquid for production, i.e., p g (x)≥p w (x), then:

[0200]

[0201]

[0202] Therefore, the critical liquid-carrying phase permeability condition for gas wells is:

[0203]

[0204] refer to Figure 20 Based on the wellbore liquid holdup and different liquid-carrying model formulas, the gas-water velocity ratio and critical velocity coefficient under different pressures and water-water ratios were calculated, and a chart of the critical velocity coefficient and gas-water velocity ratio was established. Figure 20 The formula reflects the critical phase permeability conditions for liquid carrying capacity in gas wells.

[0205] In one embodiment, the critical flow velocity formula is expressed as follows:

[0206]

[0207] Where, x i ρ represents the critical velocity coefficient for different types of gas wells. i Let ρ be the droplet density. g Let ρ be the density of natural gas, and σ be the surface tension of natural gas and droplets.

[0208] During implementation, different liquid accumulation conditions have different impacts on gas well production. Combining the research results on the critical liquid carrying capacity of the reservoir and wellbore under different water production characteristics, the gas-water flow rate ratio parameter is used to obtain the critical flow rate coefficient under different water production characteristics through the gas-water flow rate ratio chart, and then the calculation formula of the critical liquid carrying capacity of gas well under different water production characteristics is obtained.

[0209] For low-water-yield reservoirs, the critical coefficient is 0.5, and the critical velocity formula is:

[0210]

[0211] For atmospheric and high-water reservoirs, the critical coefficient is 1.2, and the critical velocity formula is:

[0212]

[0213] For medium-to-high water-yielding reservoirs, the critical coefficient is 0.6, and the critical flow velocity formula is:

[0214]

[0215] The critical liquid-carrying flow rate of a gas well is calculated using the method described in this embodiment of the invention, and then compared and verified with the actual gas production of the gas well, with reference to... Figure 21 , Figure 21This is a schematic diagram illustrating the calculation results of the critical liquid-carrying flow rate in an embodiment of the present invention. Figure 21 It can be seen that the actual gas production of liquid-filled gas wells is generally lower than the critical liquid-carrying flow rate, while the actual gas production of non-liquid-filled gas wells is higher than the critical liquid-carrying flow rate. This calculation result is consistent with the actual production situation. Blue represents liquid-filled wells that have undergone production testing. The actual production of liquid-filled wells calculated by the method in this embodiment of the invention is lower than the critical liquid-carrying flow rate. The calculation result of the method in this embodiment of the invention is consistent with the actual production monitoring, indicating that the method in this embodiment of the invention is reliable.

[0216] In one embodiment, determining the drainage and gas production process for each type of gas well using the critical liquid-carrying flow rate for each type of gas well may include:

[0217] Using a gas well lifecycle management technology strategy chart, the drainage and gas production process for each type of gas well is determined; the gas well lifecycle management technology strategy chart includes drainage and gas production process measures and the timing of intervention for different types of gas wells.

[0218] The following section introduces different drainage gas extraction processes.

[0219] Common drainage and gas production methods for water-bearing gas reservoirs are mainly divided into mechanical methods and physicochemical methods. Mechanical methods include velocity tubing drainage, plunger drainage, gas lift drainage, electric submersible pump drainage, and mechanical pumping drainage. Physicochemical methods include foam drainage and chemical shut-off. The Sulige gas field commonly uses foam drainage, velocity tubing, plunger drainage, and gas lift drainage.

[0220] Foam drainage gas production technology is an effective method for removing accumulated liquid and is also the most commonly used drainage technology in water-bearing gas fields. This method mainly utilizes foaming agents, which are surfactants that foam upon contact with water. When liquid accumulates in the wellbore, foaming agents are injected into the wellbore. When the foaming agents come into contact with the accumulated liquid, a large amount of low-density water-bearing foam is generated by the flow and agitation produced during gas production. This foam is carried to the surface by the gas flow, thereby achieving the purpose of removing the accumulated liquid.

[0221] Velocity tubing drainage gas production is a mature method. This process involves inserting small-diameter tubing or continuous tubing into the well tubing. By reducing the flow area, it increases the gas flow velocity, thereby enhancing the gas's liquid-carrying capacity and achieving drainage of the water-producing gas well. This method is low-cost, simple in operation, has a short construction period, and provides good drainage results.

[0222] Plunger drainage gas production technology is low-cost, highly effective, and intelligent, making it one of the commonly used low-cost development technologies for water-bearing tight sandstone gas reservoirs. Plunger drainage gas production accumulates energy through intermittent well shut-in, driving a plunger inside the tubing to repeatedly expel fluid from the wellbore. This technology is easy to install and maintain, with low operating and maintenance costs. Utilizing formation energy for continuous operation can increase well productivity, reduce production decline rate, and extend the flow period and lifespan of wells with high gas-water ratios.

[0223] Gas lift drainage gas production technology is less constrained by gas source and is widely used in shale gas and tight gas water-bearing wells. It is the only drainage gas production technology that runs through the entire life cycle. This method mainly increases production capacity and removes accumulated liquid by injecting high-pressure gas into the wellbore, reducing the density of the liquid in the wellbore, and increasing the production pressure differential. Gas lift itself does not consume gas, has a wide range of production capacity adjustment, and has great flexibility, economy, and applicability, making it the second largest main drainage gas production technology.

[0224] This invention proposes a differentiated management strategy for the entire lifecycle of gas wells. Because water-producing gas wells experience significant variations across production stages, consistently employing a single production method or following the management practices of ordinary gas wells can easily overlook the serious impact of water production, missing the optimal time for intervention with drainage and gas production methods, and reducing the well's production lifespan. Therefore, developing corresponding differentiated management strategies tailored to different water production types, characteristics, and production variation patterns of gas wells is crucial. This invention, based on the aforementioned research, first differentiates the production allocation methods for different types of water-producing gas wells, accurately identifies the timing of liquid accumulation in water-bearing gas wells, optimizes the overall operating system of water-producing gas wells, and differentiates the main drainage and gas production process measures and their intervention timing for different types of water-producing gas wells, thus forming a comprehensive lifecycle management strategy for different types of water-producing gas wells.

[0225] Figure 22 This is a diagram illustrating the technical countermeasures for the full life cycle management of different types of gas wells in embodiments of the present invention, such as... Figure 22 As shown, gas wells with large atmospheric pressure and high water content are prone to fluid accumulation when the casing pressure is 10-15 MPa and the daily production is 10-15,000 cubic meters. In the early stage of production (about one and a half years), there is no need to take drainage and gas production measures. After one and a half years of production, when the daily gas production drops to 10,000 cubic meters and the casing pressure is 10 MPa, foam drainage should be used to remove the fluid accumulation at the bottom of the well. After four years of continued production, the production capacity drops significantly. Installing a speed tubing string increases the liquid flow rate and accelerates the discharge of fluid accumulation in the wellbore. After five years of continued production, the fluid accumulation becomes severe, and a plunger drainage and gas production method is introduced, along with gas lift for resumption of production.

[0226] Low-water-producing gas wells are prone to fluid accumulation when the casing pressure is 8-10 MPa and the daily production is 0.8-10,000 cubic meters. In the early stage of production (about six months), foam drainage is adopted. After two years of production, a velocity tubing string is installed to drain the fluid accumulation in the wellbore. After seven years of production, a plunger drainage gas production method is introduced, and gas lift is used to resume production.

[0227] Medium- to high-yield water-producing gas wells are prone to fluid accumulation when the casing pressure is 10–12 MPa and the daily production is 0.9–1.1 million cubic meters. A velocity tubing string should be installed to drain the fluid from the beginning of production. If the fluid accumulation is severe after 5 years of production, a plunger drainage gas production method should be introduced and gas lift should be used to resume production.

[0228] Different types of water-producing gas wells are affected by accumulated liquid to varying degrees, requiring different drainage and production technologies and intervention timings. A comparison of the three types of gas wells shows that medium-to-high water-producing gas wells should be addressed with more significant technological interventions from the initial production stage, relying on supplemental energy or technological measures to extend the well's lifespan. Large-volume, high-water-producing and low-water-producing gas wells can initially utilize their own capacity to drain accumulated liquid, allowing for later intervention of drainage technologies, thus saving costs and maximizing efficiency. The technical countermeasures in this invention embodiment can guide the development of similar gas reservoirs, maximizing gas well productivity, extending well lifespan, and increasing reservoir production efficiency.

[0229] In summary, this invention, from both dynamic and static perspectives, has conducted research on differentiated management technologies and strategies for the entire lifecycle of gas wells, including gas-water two-phase flow characteristics, variable water-gas ratio two-phase equations, characteristics and production patterns of water-producing gas wells, liquid accumulation timing identification, and production system optimization. The lifecycle management technologies and strategies for high water-cut tight sandstone gas reservoirs developed through this research can address the current development challenges of gas wells in water-cut tight sandstone gas reservoirs, providing technical support for the continuous and stable production of gas fields.

[0230] The embodiments of this invention provide the following conclusions regarding the development of gas wells in water-bearing tight sandstone gas reservoirs:

[0231] 1) In actual production of gas wells in water-bearing tight sandstone gas reservoirs, the range of gas-water variation is large, and the change in reservoir stress has a significant impact on production capacity. Using seepage theory and gas reservoir engineering methods, a gas-water two-phase mathematical model and a variable water-gas ratio two-phase equation were established. The gas-water two-phase mathematical model considers the effects of stress sensitivity and water-gas ratio changes, and the production capacity evaluation results are closer to reality. Based on the gas-water two-phase mathematical model, the impact of water-producing gas wells on production capacity and recovery rate was analyzed. It was found that when the water-gas ratio is less than 0.5, water production has little impact on gas well production indicators. When the water-gas ratio is greater than 1, its impact on production capacity exceeds 50%, recovery rate decreases by more than 17%, and pressure impact is greater than 10%.

[0232] 2) Water-producing wells in water-bearing tight sandstone gas reservoirs are scattered and widely distributed in the plane, while the gas-water relationship is complex in the vertical direction. Based on structural characteristics, reservoir properties, the occurrence state of natural gas and formation water, and combined with the analysis of gas well testing patterns and production characteristics, the water produced by gas wells is divided into three categories: condensate water, formation pore water, and special locally sealed formation water. Different types of water-producing gas wells have obvious production characteristics. Low-water-producing wells have high initial production and low pressure drop rate, and can maintain a good production state. High-water-producing wells have high initial production, but the pressure drop rate is fast, resulting in a good initial production state. However, due to severe water production in the later stage, the production capacity of this type of gas well is restricted. Medium-high water-producing wells have low initial production and fast pressure drop rate, resulting in even worse gas production capacity in the later stage, requiring timely intervention to drain water.

[0233] This invention also provides a gas well development device for water-bearing tight sandstone gas reservoirs, as described in the following embodiments. Since the principle by which this device solves the problem is similar to the gas well development method for water-bearing tight sandstone gas reservoirs, the implementation of this device can refer to the implementation of the gas well development method for water-bearing tight sandstone gas reservoirs; repeated details will not be elaborated further.

[0234] Figure 23 This is a schematic diagram of a gas well extraction device for a water-bearing tight sandstone gas reservoir in an embodiment of the present invention, as shown below. Figure 23 As shown, the device includes:

[0235] Data acquisition module 2301 is used to acquire gas reservoir formation data and fluid property data;

[0236] The production capacity calculation module 2302 is used to calculate the water phase production and gas phase production of the gas well using gas reservoir formation data, fluid property data, and a gas-water two-phase mathematical model. The gas-water two-phase mathematical model is established in advance based on fluid kinematics, taking into account the infinite conductivity of fractures and the continuous change of the water-gas ratio during fluid seepage through fractures to the wellbore. The inputs to the gas-water two-phase mathematical model are gas reservoir formation data and fluid property data, and the outputs are water phase production and gas phase production. The fractures are symmetrically distributed along both sides of the wellbore.

[0237] The production ratio determination module 2303 is used to determine the production ratio of gas wells by utilizing the water phase production and gas phase production of gas wells.

[0238] In one embodiment, the gas-water two-phase mathematical model includes a variable water-gas ratio two-phase equation, a gas-water phase permeability curve, and a mathematical relationship between a first ratio and the water-gas ratio. The first ratio is the ratio of the relative permeability of the gas phase to the relative permeability of the water phase. The variable water-gas ratio two-phase equation is established based on fluid kinematics, under the condition that the fracture has infinite conductivity and the water-gas ratio changes continuously during the process of fluid seeping through the fracture to the wellbore. The variable water-gas ratio two-phase equation reflects the correspondence between gas reservoir formation data, fluid property data, and water phase production and gas phase production.

[0239] In one embodiment, the gas reservoir formation data includes fracture tip pressure;

[0240] The capacity calculation module 2302 is specifically used for:

[0241] Set the initial water-air ratio and crack tip pressure;

[0242] Using the initial water-air ratio and the pressure at the fracture tip, perform the following iterative calculations until the difference between the initial water-air ratio and the latest water-air ratio is less than a preset value:

[0243] Using the mathematical relationship between the first ratio and the water-air ratio, and the initial water-air ratio, determine the ratio of the relative permeability of the gas phase to the relative permeability of the water phase.

[0244] The relative permeability of the gas phase and the relative permeability of the water phase are obtained by using the ratio of the relative permeability of the gas phase to the relative permeability of the water phase and the gas-water phase permeability curve.

[0245] Input the relative permeability of the gas phase, the relative permeability of the water phase, the fracture tip pressure, and the fluid properties into the variable water-gas ratio two-phase equation to output the water phase production and gas phase production of the gas well;

[0246] The latest water-gas ratio is obtained by utilizing the water phase production and gas phase production of the gas well;

[0247] Calculate the difference between the initial water-air ratio and the latest water-air ratio;

[0248] If the difference between the initial water-gas ratio and the latest water-gas ratio is not less than the preset value, the latest water-gas ratio is assigned to the initial water-gas ratio.

[0249] In one embodiment, the variable water-gas ratio two-phase equation is expressed by the following formula:

[0250]

[0251]

[0252]

[0253]

[0254]

[0255] In the formula, m g (p) is used to calculate the pseudo-pressure in the gas phase, m w (p) is used to calculate the pseudo-pressure of the aqueous phase. Substitute p into p e or p f , p e For formation pressure, p f For the pressure at the crack tip, ρ gsc ρ is the gas phase density under standard conditions. wsc q represents the density of the aqueous phase under standard conditions. gsc q represents the gas phase yield under standard conditions. wsc K represents the aqueous phase yield under standard conditions. mi The initial permeability of the matrix is ​​represented by h, where h is the reservoir thickness, and x is the initial permeability of the matrix. f It is half the length of the crack, w f r is the crack width. e The major semi-axis of the ellipse is ρ, which is formed based on the fluid seepage process in the crack. g ρ represents the gas phase density under reservoir conditions. w K represents the density of the water phase under reservoir conditions. rg K rw Representing the relative permeability of the gas phase and the relative permeability of the aqueous phase, respectively, μ g μ w Representing the viscosity of the gas phase and the viscosity of the aqueous phase, respectively, α m p represents the matrix stress sensitivity coefficient. i This represents the original formation pressure.

[0256] In one embodiment, the gas reservoir formation data includes one or any combination of the following:

[0257] Permeability, matrix stress sensitivity coefficient, original formation pressure, fracture tip pressure;

[0258] The fluid property data includes one or any combination of the following:

[0259] Vapor phase viscosity, aqueous phase viscosity, vapor phase density, aqueous phase density.

[0260] In one embodiment, it also includes:

[0261] The gas well type determination module is used to acquire gas reservoir well test data before the data acquisition module 2301 acquires gas reservoir formation data and fluid property data. The gas reservoir well test data includes the water-gas ratio.

[0262] Gas well types are determined using the water-to-gas ratio, and these types include low-water-yield gas wells, medium-to-high-water-yield gas wells, and high-water-yield gas wells.

[0263] The capacity calculation module 2302 is specifically used for:

[0264] Calculations are performed using gas reservoir formation data, fluid property data, and a gas-water two-phase mathematical model to output the water phase production and gas phase production of different types of gas wells.

[0265] Determining the gas well production ratio based on the water phase and gas phase yields of the gas wells includes:

[0266] By utilizing the water phase and gas phase yields of different types of gas wells, the production allocation ratio for different types of gas wells can be determined.

[0267] In one embodiment, the production allocation ratio determination module 2303 is specifically used for:

[0268] The unobstructed flow rate during the gas well production process is determined by using the water phase production and gas phase production of the gas well.

[0269] By utilizing the unobstructed flow rate, gas well type, and pre-constructed production coefficient variation charts corresponding to different water-producing gas wells during the gas well production process, the reasonable production ratio of the gas well is determined.

[0270] In one embodiment, it also includes:

[0271] The drainage gas production process module is used to obtain the natural gas density, droplet density, and surface tension of natural gas and droplets for each type of gas well after the gas well water phase production and gas phase production of the gas well production ratio determination module 2303 determine the gas well production ratio.

[0272] Using the natural gas density, droplet density, surface tension of natural gas and droplets for each type of gas well, and a pre-constructed critical flow rate formula for each type of gas well, the critical liquid-carrying flow rate for each type of gas well is calculated.

[0273] By utilizing the critical liquid-carrying flow rate of each type of gas well, the drainage and gas production process for each type of gas well is determined.

[0274] In one embodiment, the critical flow velocity formula is expressed as follows:

[0275]

[0276] Where, x i ρ represents the critical velocity coefficient for different types of gas wells. i Let ρ be the droplet density. g Let ρ be the density of natural gas, and σ be the surface tension of natural gas and droplets.

[0277] In one embodiment, the drainage gas extraction process module is specifically used for:

[0278] Using a gas well lifecycle management technology strategy chart, the drainage and gas production process for each type of gas well is determined; the gas well lifecycle management technology strategy chart includes drainage and gas production process measures and the timing of intervention for different types of gas wells.

[0279] This invention also provides a computer device, including a memory, a processor, and a computer program stored in the memory and executable on the processor. When the processor executes the computer program, it implements the above-described method for developing gas wells in water-bearing tight sandstone gas reservoirs.

[0280] This invention also provides a computer-readable storage medium storing a computer program that, when executed by a processor, implements the above-described method for developing gas wells in water-bearing tight sandstone gas reservoirs.

[0281] This invention also provides a computer program product, which includes a computer program that, when executed by a processor, implements the above-described method for developing gas wells in water-bearing tight sandstone gas reservoirs.

[0282] In this embodiment of the invention, gas reservoir formation data and fluid property data are acquired; calculations are performed using the gas reservoir formation data, fluid property data, and a gas-water two-phase mathematical model to output the water phase production and gas phase production of the gas well; the gas-water two-phase mathematical model is established in advance based on fluid kinematics, taking into account the infinite conductivity of fractures and the continuous change of the water-gas ratio during fluid seepage through fractures to the wellbore; the inputs to the gas-water two-phase mathematical model are gas reservoir formation data and fluid property data, and the outputs are water phase production and gas phase production; the fractures are symmetrically distributed along both sides of the wellbore; the gas well production ratio is determined using the water phase production and gas phase production of the gas well. In this embodiment of the invention, considering the infinite conductivity of fractures and the continuous change of the water-gas ratio during fluid seepage through fractures to the wellbore, a two-phase mathematical model of gas and water is established based on fluid kinematics using the gas-water phase permeation curve. This model calculates the water phase yield and gas phase yield based on the characteristics of infinite conductivity of fractures and the continuous change of the water-gas ratio. Experiments show that the calculation results of this model are consistent with the water and gas distribution of water-bearing tight sandstone gas reservoirs, making it more suitable for the exploitation design of water-bearing tight sandstone gas reservoirs. This improves the accuracy of predicting the water phase yield and gas phase yield of gas wells in water-bearing tight sandstone gas reservoirs and enhances the reliability of gas well exploitation schemes in water-bearing tight sandstone gas reservoirs.

[0283] Those skilled in the art will understand that embodiments of the present invention can be provided as methods, systems, or computer program products. Therefore, the present invention can take the form of a completely hardware embodiment, a completely software embodiment, or an embodiment combining software and hardware aspects. Furthermore, the present invention can take the form of a computer program product embodied on one or more computer-usable storage media (including, but not limited to, disk storage, CD-ROM, optical storage, etc.) containing computer-usable program code.

[0284] This invention is described with reference to flowchart illustrations and / or block diagrams of methods, apparatus (systems), and computer program products according to embodiments of the invention. It will be understood that each block of the flowchart illustrations and / or block diagrams, and combinations of blocks in the flowchart illustrations and / or block diagrams, can be implemented by computer program instructions. These computer program instructions can be provided to a processor of a general-purpose computer, special-purpose computer, embedded processor, or other programmable data processing apparatus to produce a machine, such that the instructions, which execute via the processor of the computer or other programmable data processing apparatus, generate instructions for implementing the flowchart illustrations and / or block diagrams. Figure 1 a process or multiple processes and / or boxes Figure 1 A device that provides the functions specified in a block or multiple blocks.

[0285] These computer program instructions may also be stored in a computer-readable storage medium that can direct a computer or other programmable data processing device to function in a particular manner, such that the instructions stored in the computer-readable storage medium produce an article of manufacture including instruction means, which are implemented in a process Figure 1 a process or multiple processes and / or boxes Figure 1 The function specified in one or more boxes.

[0286] These computer program instructions may also be loaded onto a computer or other programmable data processing equipment to cause a series of operational steps to be performed on the computer or other programmable equipment to produce a computer-implemented process, thereby providing instructions that execute on the computer or other programmable equipment for implementing the process. Figure 1 a process or multiple processes and / or boxes Figure 1 A step that specifies a function in one or more boxes.

[0287] The specific embodiments described above further illustrate the purpose, technical solution, and beneficial effects of the present invention. It should be understood that the above descriptions are merely specific embodiments of the present invention and are not intended to limit the scope of protection of the present invention. Any modifications, equivalent substitutions, improvements, etc., made within the spirit and principles of the present invention should be included within the scope of protection of the present invention.

Claims

1. A method for developing gas wells in water-bearing tight sandstone gas reservoirs, characterized in that, include: Acquire gas reservoir formation data and fluid property data; The gas well's water phase production and gas phase production are calculated using gas reservoir formation data, fluid property data, and a gas-water two-phase mathematical model. The gas-water two-phase mathematical model is pre-established based on fluid kinematics, taking into account the infinite conductivity of fractures and the continuous change in the water-to-gas ratio as the fluid seeps through the fractures into the wellbore. The inputs to the gas-water two-phase mathematical model are gas reservoir formation data and fluid property data, and the outputs are water phase production and gas phase production. The fractures are symmetrically distributed along both sides of the wellbore. The production ratio of gas wells is determined by using the water phase production and gas phase production of the gas wells.

2. The method as described in claim 1, characterized in that, The gas-water two-phase mathematical model includes a variable water-gas ratio two-phase equation, a gas-water phase permeability curve, and a mathematical relationship between a first ratio and the water-gas ratio. The first ratio is the ratio of the relative permeability of the gas phase to the relative permeability of the water phase. The variable water-gas ratio two-phase equation is established based on fluid kinematics, under the condition that the fracture has infinite conductivity and the water-gas ratio changes continuously during the process of fluid seeping through the fracture to the wellbore. The variable water-gas ratio two-phase equation reflects the correspondence between gas reservoir formation data, fluid property data, and water phase production and gas phase production.

3. The method as described in claim 2, characterized in that, The gas reservoir formation data includes fracture tip pressure; Calculations are performed using gas reservoir formation data, fluid property data, and a gas-water two-phase mathematical model to output the water phase production and gas phase production of the gas well, including: Set the initial water-air ratio and crack tip pressure; Using the initial water-air ratio and the pressure at the fracture tip, perform the following iterative calculations until the difference between the initial water-air ratio and the latest water-air ratio is less than a preset value: Using the mathematical relationship between the first ratio and the water-air ratio, and the initial water-air ratio, determine the ratio of the relative permeability of the gas phase to the relative permeability of the water phase. The relative permeability of the gas phase and the relative permeability of the water phase are obtained by using the ratio of the relative permeability of the gas phase to the relative permeability of the water phase and the gas-water phase permeability curve. Input the relative permeability of the gas phase, the relative permeability of the water phase, the fracture tip pressure, and the fluid properties into the variable water-gas ratio two-phase equation to output the water phase production and gas phase production of the gas well; The latest water-gas ratio is obtained by utilizing the water phase production and gas phase production of the gas well; Calculate the difference between the initial water-air ratio and the latest water-air ratio; If the difference between the initial water-gas ratio and the latest water-gas ratio is not less than the preset value, the latest water-gas ratio is assigned to the initial water-gas ratio.

4. The method as described in claim 2, characterized in that, The two-phase equation with varying water-to-gas ratio is expressed by the following formula: In the formula, m g (p) is used to calculate the pseudo-pressure in the gas phase, m w (p) is used to calculate the pseudo-pressure of the aqueous phase. Substitute p into p e or p f , p e For formation pressure, p f ρ is the pressure at the crack tip. gsc ρ is the gas phase density under standard conditions. wsc q represents the density of the aqueous phase under standard conditions. gsc q represents the gas phase yield under standard conditions. wsc K represents the aqueous phase yield under standard conditions. mi The initial permeability of the matrix is ​​represented by h, where h is the reservoir thickness, and x is the initial permeability of the matrix. f It is half the length of the crack, w f r is the crack width. e The major semi-axis of the ellipse is ρ, which is formed based on the fluid seepage process in the crack. g ρ represents the gas phase density under reservoir conditions. w K represents the density of the water phase under reservoir conditions. rg K rw Representing the relative permeability of the gas phase and the relative permeability of the aqueous phase, respectively, μ g μ w Representing the viscosity of the gas phase and the viscosity of the aqueous phase, respectively, α m p represents the matrix stress sensitivity coefficient. i This represents the original formation pressure.

5. The method as described in claim 1, characterized in that, The gas reservoir stratigraphic data includes one or any combination of the following: Permeability, matrix stress sensitivity coefficient, original formation pressure, fracture tip pressure; The fluid property data includes one or any combination of the following: Vapor phase viscosity, aqueous phase viscosity, vapor phase density, aqueous phase density.

6. The method as described in claim 1, characterized in that, Before acquiring gas reservoir formation data and fluid property data, the following steps are also included: Acquire gas reservoir well test data, including the water-gas ratio; Gas well types are determined using the water-to-gas ratio, and these types include low-water-yield gas wells, medium-to-high-water-yield gas wells, and high-water-yield gas wells. Calculations are performed using gas reservoir formation data, fluid property data, and a gas-water two-phase mathematical model to output the water phase production and gas phase production of the gas well, including: Calculations are performed using gas reservoir formation data, fluid property data, and a gas-water two-phase mathematical model to output the water phase production and gas phase production of different types of gas wells. Determining the gas well production ratio based on the water phase and gas phase yields of the gas wells includes: By utilizing the water phase and gas phase yields of different types of gas wells, the production allocation ratio for different types of gas wells can be determined.

7. The method as described in claim 6, characterized in that, By utilizing the water phase and gas phase yields of different types of gas wells, the production allocation ratios for different types of gas wells are determined, including: The unobstructed flow rate during the gas well production process is determined by using the water phase production and gas phase production of the gas well. By utilizing the unobstructed flow rate, gas well type, and pre-constructed production coefficient variation charts corresponding to different water-producing gas wells during the gas well production process, the reasonable production ratio of the gas well is determined.

8. The method as described in claim 6, characterized in that, After determining the gas well production allocation ratio using the water phase and gas phase yields of the gas wells, the process also includes: Obtain the natural gas density, droplet density, and surface tension of natural gas and droplets for each type of gas well; Using the natural gas density, droplet density, surface tension of natural gas and droplets for each type of gas well, and a pre-constructed critical flow rate formula for each type of gas well, the critical liquid-carrying flow rate for each type of gas well is calculated. By utilizing the critical liquid-carrying flow rate of each type of gas well, the drainage and gas production process for each type of gas well is determined.

9. The method as described in claim 8, characterized in that, The critical flow velocity formula is expressed as follows: Among them, x i ρ represents the critical velocity coefficient for different types of gas wells. i Let ρ be the droplet density. g Let ρ be the density of natural gas, and σ be the surface tension of natural gas and droplets.

10. The method as described in claim 8, characterized in that, Using the critical liquid-carrying flow rate for each type of gas well, the drainage and gas production process for each type of gas well is determined, including: Using a gas well lifecycle management technology strategy chart, the drainage and gas production process for each type of gas well is determined; the gas well lifecycle management technology strategy chart includes drainage and gas production process measures and the timing of intervention for different types of gas wells.

11. A gas well extraction device for a water-bearing tight sandstone gas reservoir, characterized in that, include: The data acquisition module is used to acquire gas reservoir formation data and fluid property data; The production capacity calculation module is used to calculate the water phase production and gas phase production of the gas well using gas reservoir formation data, fluid property data, and a gas-water two-phase mathematical model. The gas-water two-phase mathematical model is established in advance based on fluid kinematics, taking into account the infinite conductivity of fractures and the continuous change of the water-gas ratio during fluid seepage through fractures to the wellbore. The inputs to the gas-water two-phase mathematical model are gas reservoir formation data and fluid property data, and the outputs are water phase production and gas phase production. The fractures are symmetrically distributed along both sides of the wellbore. The production ratio determination module is used to determine the production ratio of gas wells based on the water phase production and gas phase production of the gas wells.

12. A computer device, comprising a memory, a processor, and a computer program stored in the memory and executable on the processor, characterized in that, When the processor executes the computer program, it implements the method of any one of claims 1 to 10.

13. A computer-readable storage medium, characterized in that, The computer-readable storage medium stores a computer program that, when executed by a processor, implements the method of any one of claims 1 to 10.

14. A computer program product, characterized in that, The computer program product includes a computer program that, when executed by a processor, implements the method of any one of claims 1 to 10.

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