Method and device for determining carbonate gas reservoir productivity, electronic equipment and storage medium

Abstract

The disclosure provides a carbonate gas reservoir productivity determination method and device, electronic equipment and storage medium, belonging to the technical field of oil and gas exploration. The method comprises the following steps: based on the heterogeneity of the carbonate gas reservoir, a radial composite model is constructed, the radial composite model is divided into two homogeneous regions I and II, and the II region surrounds the I region; taking the interface between the I region and the II region as a node, the flow equation of the I region and the flow equation of the II region are determined; taking the flow equation of the II region as the inflow equation and the flow equation of the I region as the outflow equation, a typical inflow and outflow curve is drawn respectively, and a gas well inflow and outflow typical chart is constructed; based on the gas well inflow and outflow typical chart, the absolute open flow capacity of the gas well and the maximum gas supply capacity of the underground under the current working condition are determined.

Description

Technical Field

[0001] This disclosure relates to the field of oil and gas exploration technology, and in particular to a method, apparatus, electronic equipment and storage medium for determining the production capacity of carbonate gas reservoirs. Background Technology

[0002] Determining the production capacity is a crucial task in gas reservoir development. Production capacity depends on well allocation, which in turn depends on well productivity evaluation. With advancements in science and technology, low-permeability carbonate gas reservoirs can achieve larger venting radii and increased seepage capacity within the stimulated area through the implementation of process wells and reservoir stimulation, thus enabling profitable development. However, carbonate gas reservoirs exhibit complex relationships between pores, cavities, and fractures of varying scales, resulting in strong heterogeneity. Gas wells often show significant flow differences between the stimulated area and outside, exhibiting multi-well-area composite seepage characteristics. This makes it difficult to achieve a quasi-steady state during productivity testing, and each production regime in productivity testing corresponds to a different flow stage, thus hindering the accurate establishment of productivity equations.

[0003] The issue of evaluating the production capacity of gas wells in this type of reservoir has not been effectively resolved, and has long plagued gas field developers. According to the "Outline for Natural Gas Development and Management," although gas fields conduct gas well production capacity verification work every year, the verification relies on the production site, and the verified production capacity is difficult to quantitatively describe the underground gas production potential. Summary of the Invention

[0004] This disclosure provides a method, apparatus, electronic device, and storage medium for determining the production capacity of carbonate gas reservoirs. The technical solution is as follows:

[0005] On the one hand, a method for determining the production capacity of carbonate gas reservoirs is provided, the method comprising:

[0006] Based on the heterogeneity of carbonate gas reservoirs, a radial composite model is constructed. The radial composite model is divided into two homogeneous regions, region I and region II, with region II surrounding region I.

[0007] Using the interface between region I and region II as nodes, determine the flow equations for region I and region II;

[0008] Using the flow equation of Zone II as the inflow equation and the flow equation of Zone I as the outflow equation, typical inflow and outflow curves are plotted to construct a typical inflow and outflow chart for gas wells.

[0009] Based on the typical inflow and outflow charts of the gas well, the absolute unobstructed flow rate of the gas well and the maximum underground gas supply capacity under the current operating conditions are determined.

[0010] Optionally, the flow equation for region I is as follows:

[0011]

[0012] in,

[0013]

[0014]

[0015] Where, p I The pressure at the interface is expressed in MPa; p wf A is the bottom hole flowing pressure, in MPa. I This is the Darcy seepage coefficient for zone I, in MPa. 2 / (10 4 m 3 / d);q sc Gas production, in units of 10. 4 m 3 / d;B I The coefficient for the non-Darcy seepage term in Zone I is given in MPa. 2 / (10 4 m 3 / d) 2 μ is the gas viscosity, in mPa·s; Z is the deviation factor, dimensionless; T is the reservoir temperature, in K; K I For penetration rate, m 2 ;r I r is the outer boundary radius of region I, in meters. w The inner boundary radius of region I is given in meters (m); S is the skin factor, dimensionless; h is the reservoir thickness in meters (m); and D is the non-Darcy flow term coefficient in MPa. 2 / (10 4 m 3 / d).

[0016] Optionally, the flow equation for region II is as follows:

[0017]

[0018] in,

[0019]

[0020]

[0021] Where, p e The outer boundary pressure of zone II is expressed in MPa; p I The pressure at the interface is expressed in MPa; A II This is the Darcy seepage coefficient for Zone II, in MPa. 2 / (10 4 m3 / d);q sc Gas production, in units of 10. 4 m 3 / d;B II The coefficient for the non-Darcy seepage term in Zone II is given in MPa. 2 / (10 4 m 3 / d) 2 μ is the gas viscosity, in mPa·s; Z is the deviation factor, dimensionless; T is the reservoir temperature, in K; K II Permeability, in meters (m) 2 ;r e r is the vent radius, in meters (m). I The outer boundary radius of region I is given in meters (m); h is the reservoir thickness in meters (m); and D is the non-Darcy flow term coefficient in MPa. 2 / (10 4 m 3 / d).

[0022] Optionally, the outflow curve includes a first outflow curve when the bottom hole pressure is atmospheric pressure, and a second outflow curve when the bottom hole pressure is the current operating condition; the inflow curve includes a first inflow curve when the bottom hole pressure is atmospheric pressure, and a second inflow curve when the bottom hole pressure is the current operating condition.

[0023] The determination of the absolute unobstructed flow rate of the gas well and the maximum underground gas supply capacity under current operating conditions based on the typical inflow and outflow chart of the gas well includes:

[0024] The absolute unobstructed flow rate of the gas well is determined based on the intersection of the first outflow curve and the first inflow curve.

[0025] Based on the intersection of the second outflow curve and the second inflow curve, the maximum underground gas supply capacity under the current operating conditions is determined.

[0026] On the one hand, a device for determining the production capacity of a carbonate gas reservoir is provided, the device comprising:

[0027] The first construction module is used to construct a radial composite model based on the heterogeneity of carbonate gas reservoirs. The radial composite model is divided into two homogeneous regions, region I and region II, with region II surrounding region I.

[0028] The first determining module is used to determine the flow equations of region I and region II, with the interface between region I and region II as nodes;

[0029] The second construction module is used to draw typical inflow and outflow curves using the flow equation of Zone II as the inflow equation and the flow equation of Zone I as the outflow equation, and to construct a typical inflow and outflow chart for gas wells.

[0030] The second determining module is used to determine the absolute unobstructed flow rate of the gas well and the maximum underground gas supply capacity under the current operating conditions based on the typical inflow and outflow chart of the gas well.

[0031] Optionally, the flow equation for region I is as follows:

[0032]

[0033] in,

[0034]

[0035]

[0036] Where, p I The pressure at the interface is expressed in MPa; p wf A is the bottom hole flowing pressure, in MPa. I This is the Darcy seepage coefficient for zone I, in MPa. 2 / (10 4 m 3 / d);q sc Gas production, in units of 10. 4 m 3 / d;B I The coefficient for the non-Darcy seepage term in Zone I is given in MPa. 2 / (10 4 m 3 / d) 2 μ is the gas viscosity, in mPa·s; Z is the deviation factor, dimensionless; T is the reservoir temperature, in K; K I For penetration rate, m 2 ;r I r is the outer boundary radius of region I, in meters. w The inner boundary radius of region I is given in meters (m); S is the skin factor, dimensionless; h is the reservoir thickness in meters (m); and D is the non-Darcy flow term coefficient in MPa. 2 / (10 4 m 3 / d); D is the coefficient for the non-Darcy seepage term, in MPa. 2 / (10 4 m 3 / d).

[0037] Optionally, the flow equation for region II is as follows:

[0038]

[0039] in,

[0040]

[0041]

[0042] Where, p e The outer boundary pressure of zone II is expressed in MPa; p I The pressure at the interface is expressed in MPa; A II This is the Darcy seepage coefficient for Zone II, in MPa. 2 / (10 4 m 3 / d);q sc Gas production, in units of 10. 4 m 3 / d;B II The coefficient for the non-Darcy seepage term in Zone II is given in MPa. 2 / (10 4 m 3 / d) 2 μ is the gas viscosity, in mPa·s; Z is the deviation factor, dimensionless; T is the reservoir temperature, in K; K II Permeability, in meters (m) 2 ;r e r is the vent radius, in meters (m). I is the outer boundary radius of region I, in meters; h is the reservoir thickness, in meters.

[0043] Optionally, the outflow curve includes a first outflow curve when the bottom hole pressure is atmospheric pressure, and a second outflow curve when the bottom hole pressure is the current operating condition; the inflow curve includes a first inflow curve when the bottom hole pressure is atmospheric pressure, and a second inflow curve when the bottom hole pressure is the current operating condition; the second determining module is used to determine the absolute unobstructed flow rate of the gas well based on the intersection of the first outflow curve and the first inflow curve;

[0044] Based on the intersection of the second outflow curve and the second inflow curve, the maximum underground gas supply capacity under the current operating conditions is determined.

[0045] On the one hand, an electronic device is provided, comprising a processor and a memory, the memory storing at least one piece of program code, which is loaded and executed by the processor to implement the aforementioned method for determining the production capacity of carbonate gas reservoirs.

[0046] On the one hand, a computer-readable storage medium is provided, the computer-readable storage medium storing at least one piece of program code, the program code being loaded and executed by the processor to implement the aforementioned method for determining the production capacity of carbonate gas reservoirs.

[0047] The beneficial effects of the technical solutions provided in this disclosure include at least the following:

[0048] This method for determining the production capacity of carbonate gas reservoirs starts from the concept of system node analysis. It identifies two homogeneous zones, Zone I and Zone II, by constructing a radial composite model. Based on the radial composite model, it determines the flow equation, and then calculates the inflow and outflow curves of the gas wells. This curve can graphically determine the maximum underground gas supply capacity and the absolute unobstructed flow rate of the gas well. This method provides a means to determine the production capacity of carbonate gas reservoirs, thus offering guidance for evaluating and determining the production capacity of gas wells. Attached Figure Description

[0049] To more clearly illustrate the technical solutions in the embodiments of this disclosure, the accompanying drawings used in the description of the embodiments will be briefly introduced below. Obviously, the accompanying drawings described below are only some embodiments of this disclosure. For those skilled in the art, other drawings can be obtained based on these drawings without creative effort.

[0050] Figure 1 This is a schematic diagram of the inflow and outflow curves;

[0051] Figure 2 This is a schematic flowchart illustrating a method for determining the production capacity of a carbonate gas reservoir according to an illustrative embodiment of this disclosure;

[0052] Figure 3 This is a schematic flowchart illustrating a method for determining the production capacity of a carbonate gas reservoir according to an illustrative embodiment of this disclosure;

[0053] Figure 4 and Figure 5 A schematic diagram of a radial composite model provided in an embodiment of this disclosure;

[0054] Figure 6 and Figure 7 Two pressure derivative fitting curves and a schematic diagram of the pressure fitting curves provided in the embodiments of this disclosure;

[0055] Figure 8 A schematic diagram of typical inflow and outflow curves provided in embodiments of this disclosure;

[0056] Figure 9 A schematic diagram illustrating the gas reservoir production capacity provided in an embodiment of this disclosure;

[0057] Figures 10 to 13Schematic diagrams of four double logarithmic curves provided in embodiments of this disclosure;

[0058] Figures 14 to 17 A schematic diagram of four gas well inflow and outflow curves provided in the embodiments of this disclosure;

[0059] Figure 18 A structural block diagram of a carbonate gas reservoir production capacity determination device provided in this embodiment of the present disclosure;

[0060] Figure 19 This is a schematic diagram of the structure of an electronic device provided in an embodiment of this disclosure. Detailed Implementation

[0061] To make the objectives, technical solutions, and advantages of this disclosure clearer, the embodiments of this disclosure will be described in further detail below with reference to the accompanying drawings.

[0062] In related technologies, early evaluation of mine capacity generally uses Chen Yuanqian's "one-point method" to estimate the absolute unobstructed flow rate of gas wells, using this absolute unobstructed flow rate value as a reference for gas well capacity. However, this method has the following problems: 1. The calculation of the absolute unobstructed flow rate is based on the assumption that the gas well flow reaches a quasi-steady state. However, the method's applicability is often lacking in the evaluation of its suitability during mine testing and calculation, leading to incorrect capacity evaluation; 2. If the physical properties of the near-wellbore area are better than those of the far-wellbore area, the capacity will be optimistically estimated, the production scale will be too large, and the surface processing capacity will be greater than the underground gas supply capacity, resulting in wasted investment; 3. If the physical properties of the far-wellbore area are better than those of the near-wellbore area, the capacity evaluation will be conservative, the production scale will be too small, the surface processing capacity will be less than the underground gas supply capacity, creating a gathering and transportation bottleneck and increasing the investment recovery period.

[0063] Therefore, this disclosure provides a method for determining the production capacity of carbonate gas reservoirs, which aims to provide a new approach for determining the production capacity of low-permeability carbonate gas reservoirs, evaluate gas well production capacity, and guide production scale.

[0064] This method for determining the reservoir capacity of carbonate gas reservoirs is based on the concept of system node analysis and is applicable to determining the reservoir capacity, including the absolute unobstructed flow rate of gas wells and the maximum underground gas supply capacity.

[0065] To facilitate understanding, the concept of node analysis will be introduced first. Specifically:

[0066] Node analysis, also known as production system analysis, was proposed by Gilbert in 1954. Since the 1980s, it has been widely used in the design of oil and gas wells and water injection well systems, as well as in production dynamics prediction and gas production engineering design. Please refer to [link to relevant documentation]. Figure 1This method divides the entire system into two subsystems at specific locations: an inflow system and an outflow system, corresponding to the "inflow curve" and "outflow curve," respectively. This location is called a "node." The inflow system is the permeation system from the node to the bottom of the well, and the outflow system is the permeation system from the gas well boundary to the node. Most nodes are located in the middle of the perforated section at the bottom of the well, and the choice of node is irrelevant to the final result of the system analysis. For example... Figure 1 As shown, both the "inflow curve" and the "outflow curve" represent the relationship between production and node pressure. Figure 1 The central coordination point is the intersection of the inflow curve and the outflow curve.

[0067] Figure 2 This is a schematic flowchart illustrating a method for determining the production capacity of a carbonate gas reservoir according to an illustrative embodiment of this disclosure. Figure 2 As shown, this method is executed after well test data is available, and the method may include:

[0068] In step 101: Based on the heterogeneity of carbonate gas reservoirs, a radial composite model is constructed. The radial composite model is divided into two homogeneous regions, region I and region II, with region II surrounding region I.

[0069] The radial composite model is a mathematical model. The steps for constructing the radial composite model are usually as follows: obtain well test data through pressure recovery well testing; where pressure recovery well testing refers to lowering a test pressure gauge into the well, recording the curve of bottom hole pressure and temperature change over time after shut-in, and obtaining reservoir parameters such as permeability and skin depth by interpreting the test data.

[0070] Two homogeneous regions were divided based on the permeability in the well test data, and the radii of these two homogeneous regions were obtained.

[0071] In this context, homogeneity and heterogeneity are determined based on the permeability of each region. Regions with similar or identical permeability are considered homogeneous, while those with different permeability are considered heterogeneous. Therefore, the homogeneous region referred to in this application is not necessarily a completely homogeneous region, but rather an approximately homogeneous region.

[0072] In step 102: using the interface between region I and region II as a node, determine the flow equations for region I and region II.

[0073] In step 103: using the flow equation of zone II as the inflow equation and the flow equation of zone I as the outflow equation, typical inflow and outflow curves are plotted to construct a typical inflow and outflow chart for gas wells.

[0074] In step 104: Based on the typical inflow and outflow chart of the gas well, determine the absolute unobstructed flow rate of the gas well and the maximum underground gas supply capacity under the current operating conditions.

[0075] In this embodiment, the method for determining the production capacity of carbonate gas reservoirs starts from the concept of system node analysis. It identifies two homogeneous regions, Zone I and Zone II, by constructing a radial composite model. Based on the radial composite model, it determines the flow equation, and then calculates the inflow and outflow curves of the gas wells. This curve can graphically determine the maximum underground gas supply capacity and the absolute unobstructed flow rate of the gas well. This method provides a means to determine the production capacity of carbonate gas reservoirs, thereby providing guidance for evaluating gas well production capacity and determining production levels.

[0076] Figure 3 This is a schematic flowchart illustrating a method for determining the production capacity of a carbonate gas reservoir according to an illustrative embodiment of this disclosure. Figure 3 As shown, the method may include:

[0077] In step 201: Based on the heterogeneity of carbonate gas reservoirs, a radial composite model is constructed. The radial composite model is divided into two homogeneous regions, region I and region II, with region II surrounding region I.

[0078] Carbonate gas reservoirs exhibit strong heterogeneity, and radial composite models (i.e., composite systems) are common models used in well test interpretation, widely applied in this type of reservoir. The model consists of a flow system composed of two homogeneous annular formations; the geological model is shown below. Figure 4 and Figure 5 ,in Figure 4 This is a plan view of the composite model. Figure 5 This is a cross-sectional view of the composite model.

[0079] Depend on Figure 4 It can be seen that the composite system can be divided into two homogeneous regions, region I and region II, with the outer boundary radius of region I being r. I The inner boundary radius is r w The outer boundary radius of region II is r II The pressure at the boundary (i.e., the outer boundary of region I) is p. I The outer boundary pressure of zone II is pe. It is worth noting that... Figure 4 The smallest circle in the middle represents the wellbore of the gas well.

[0080] The formation thickness in zones I and II is h, and the permeability of zone I is K. I The penetration rate in Zone II is K. II .

[0081] In step 202: the flow equation of region I is determined using the interface between region I and region II as a node.

[0082] For example, the flow equation for region I is as follows:

[0083]

[0084] in,

[0085]

[0086]

[0087] Where, p I The pressure at the interface is expressed in MPa; p wf A is the bottom hole flowing pressure, in MPa. I This is the Darcy seepage coefficient for zone I, in MPa. 2 / (10 4 m 3 / d);q sc Gas production, in units of 10. 4 m 3 / d;B I The coefficient for the non-Darcy seepage term in Zone I is given in MPa. 2 / (10 4 m 3 / d) 2 μ is the gas viscosity, in mPa·s; Z is the deviation factor, dimensionless (i.e., dimensionless); T is the reservoir temperature, in K; K I For penetration rate, m 2 ;r I r is the outer boundary radius of region I, in meters. w The inner boundary radius of region I is given in meters (m); S is the skin factor, dimensionless; h is the reservoir thickness in meters (m); and D is the non-Darcy flow term coefficient in MPa. 2 / (10 4 m 3 / d).

[0088] Among the parameters mentioned above, r w The parameters are obtained from well completion data, h from well logging, and Z, μ, etc., from experimental or empirical formulas. Other parameters can be obtained from well test data. The methods for obtaining parameters in subsequent formulas are similar and will not be repeated here.

[0089] In step 203: the flow equation of region II is determined using the interface between region I and region II as a node.

[0090] For example, the flow equation for region II is as follows:

[0091]

[0092] in,

[0093]

[0094]

[0095] Where, p e The outer boundary pressure of zone II is expressed in MPa; p I The pressure at the interface is expressed in MPa; A II This is the Darcy seepage coefficient for Zone II, in MPa. 2 / (10 4 m 3 / d);q sc Gas production, in units of 10. 4 m 3 / d;B II The coefficient for the non-Darcy seepage term in Zone II is given in MPa. 2 / (10 4 m 3 / d) 2 μ is the gas viscosity, in mPa·s; Z is the deviation factor, dimensionless; T is the reservoir temperature, in K; K II Permeability, in meters (m) 2 ;r e r is the vent radius, in meters (m). I The outer boundary radius of region I is given in meters (m); h is the reservoir thickness in meters (m); and D is the non-Darcy flow term coefficient in MPa. 2 / (10 4 m 3 / d).

[0096] In step 204: using the flow equation of zone II as the inflow equation and the flow equation of zone I as the outflow equation, typical inflow and outflow curves are plotted to construct a typical inflow and outflow chart for gas wells.

[0097] Highly heterogeneous carbonate gas reservoirs often exhibit two forms in well test logarithmic curves, representing two typical reservoir types, as shown below. Figure 6 and Figure 7 .exist Figure 6 In this type of well, the post-reservoir cavern response is significant, reaching short-term radial flow in the second logarithmic cycle. The pressure derivative fitting curve (based on measured pressure derivative fitting) shows a large slope increase in the latter part, indicating low permeability in the outer zone as interpreted by well testing. These wells typically experience high leakage and high production during drilling and testing, but have poor stable production capacity. Figure 7 In this case, artificially modified fractures showed a significant response, indicating a negative skin layer. The permeability of the inner zone was lower than that of the outer zone. During drilling and testing, the loss of these wells was very small, resulting in low production.

[0098] The flow patterns of both types of reservoir gas wells mentioned above can be described by the composite system flow equation. Using the flow equation for zone II of the gas well as the inflow equation and the flow equation for zone I as the outflow equation, typical inflow and outflow curves are plotted as follows: Figure 8 As shown in the figure: Type 1 reservoir is of the external poor and internal good type. The inflow curve shows poor gas supply capacity and rapid pressure drop. The outflow curve of the inner zone has a small flow pressure difference. Combined with its well test double logarithmic curve, it is believed that the "one-point method" evaluation of production capacity is higher than the actual production capacity of the gas well. Type 2 reservoir is of the external good and internal poor type. The well test curve shows significant stimulation effect, but the inner zone reservoir may be contaminated by the influent fluid, resulting in lower permeability in the inner zone than in the outer zone. The inflow curve shows good gas supply capacity, but the deterioration of physical properties in the inner zone restricts gas flow. The outflow curve of the inner zone has a large flow pressure difference. The "one-point method" evaluation of production capacity is lower than the actual production capacity of the gas well.

[0099] The process of plotting typical inflow and outflow curves is as follows: obtain the parameters of reservoir zone I and zone II through well test data; calculate the inflow and outflow pressures at nodes under different gas production rates based on the parameters of reservoir zone I and zone II and the inflow and outflow equations; and plot the inflow and outflow curves based on the gas production rate and the inflow and outflow pressures.

[0100] The outflow curve can be drawn not only based on the current bottom hole pressure, but also based on ideal conditions, that is, based on atmospheric pressure at the bottom hole pressure.

[0101] That is, the outflow curve includes the first outflow curve when the bottom hole pressure is atmospheric pressure, and the second outflow curve when the bottom hole pressure is the current operating condition.

[0102] In step 205: Based on the typical inflow and outflow chart of the gas well, determine the absolute unobstructed flow rate of the gas well and the maximum underground gas supply capacity under the current operating conditions.

[0103] For example, the step includes:

[0104] The absolute unobstructed flow rate of the gas well is determined based on the intersection of the first outflow curve and the first inflow curve.

[0105] Based on the intersection of the second outflow curve and the second inflow curve, the maximum underground gas supply capacity under the current operating conditions is determined.

[0106] Among them, by interpreting typical inflow and outflow charts of gas wells, the intersection point of the outflow curve and the inflow curve is obtained.

[0107] The following describes in further detail the method for determining the production capacity of carbonate gas reservoirs provided in this disclosure, with reference to specific embodiments.

[0108] The Dengying Formation of the Sinian System and the Qixia Formation of the Lower Permian System in the Anyue Gas Field of the Sichuan Basin are key gas reservoirs for exploration and development by Southwest Oil & Gas Field Company. The Dengying Formation is currently in the production construction stage, while the Qixia Formation is in the trial production evaluation stage. The main development indicators for these reservoirs are shown in Table 1. The Dengying and Qixia Formations exhibit low permeability and strong heterogeneity. Although multiple production well tests have been conducted, the wells have failed to reach a near-steady state during testing, failing to meet the requirements of the "Technical Specification for Natural Gas Well Testing" (SY / T 5440-2009). Figure 9 (Table 2) The established production capacity equation has low accuracy and cannot describe the true seepage law of gas wells. This disclosure uses four wells from the Dengying Formation and Qixia Formation gas reservoirs as examples to illustrate the application of the method established in this disclosure in determining gas well production capacity and surface support.

[0109] Table 1 Summary of Gas Reservoir Indicators in Dengying Formation and Qixia Formation, Anyue Gas Field, Sichuan Basin

[0110]

[0111] Table 2 Evaluation Table of Production Capacity Test Data for a Certain Well

[0112]

[0113] Examples include calculations for three gas wells from the Dengying Formation and one from the Qixia Formation, and oil testing of the above four wells.

[0114] Table 3 summarizes the capacity evaluation and production scale of the "single-point method". As can be seen from the table, the production scale is 1 / 6 to 1 / 5 of the absolute unobstructed flow rate of the "single-point method".

[0115] Table 3 Summary of Example Well Tests and Surface Support

[0116]

[0117] In this example, pressure recovery tests were conducted on all four wells. The test interpretations revealed low permeability and strong heterogeneity. The results are shown in Table 4. The table shows that wells A and D are type 1 reservoirs, with better external properties than internal properties, resulting in strong gas supply capacity. Well C is a type 2 reservoir, with worse external properties than internal properties, resulting in weak gas supply capacity. Well B, although belonging to type 1 reservoirs, shows relatively small differences in external and internal properties.

[0118] Table 4 Summary of Well Test Interpretation Results for Example Wells

[0119]

[0120] Based on the well test interpretation data in Table 4, the productivity coefficients A and B for Zones I and II of the four example wells were calculated, and gas well inflow and outflow charts were plotted. Well number A is shown in [reference]. Figure 14 See also B (hash symbol). Figure 15 See hash C. Figure 16 See hash symbol D. Figure 17 .from Figures 14-17 As can be seen from the data, the gas production at the coordination points of the four example wells were 55, 52, 24, and 48 × 10⁻⁶, respectively. 4 m / d, this gas production rate represents the current maximum underground gas production capacity of these four wells. Furthermore, considering the outflow curves under the condition of zero bottom-hole flowing pressure, the absolute unobstructed flow rates of the four wells can be obtained as 168, 160, 40, and 250 × 10⁻⁶ m / d, respectively. 4 m / d.

[0121] Comparing the maximum gas production capacity of gas wells with the designated production scale, it is easy to see that there is a certain mismatch between the designated production scale and the underground production capacity (Table 5). Well C has a high test production, and the "single-point method" for absolute unobstructed flow rate optimistically estimates the gas well's production capacity, resulting in an overestimation of the designated production capacity. However, the physical properties of the outer zone of this well are worse than those of the inner zone, leading to insufficient gas supply capacity. Wells A, B, and D have better physical properties in the outer zone than in the inner zone. Therefore, the production capacity evaluated by the "single-point method" for unobstructed flow rate is relatively conservative, and the surface infrastructure is underdeveloped.

[0122] Table 5 Evaluation of the Correspondence between Underground Production Capacity and Surface Support in Example Wells

[0123]

[0124] Field practice using this method has revealed that for low-permeability carbonate gas reservoirs, the "single-point method" for evaluating well productivity using well test data often results in significant errors, making it difficult to match the determined production scale with the actual underground production capacity. This method, based on well test interpretation and nodal analysis-based production allocation, supplements existing methods for determining production capacity. It calculates the production coefficients for inner and outer zones based on well test interpretation data, evaluates the absolute unobstructed flow rate of the gas well by plotting underground inflow and outflow curves, and determines the maximum underground gas production capacity. This method is computationally convenient, highly operable, and effectively solves the problem of production capacity evaluation for this type of gas reservoir.

[0125] This method for determining the production capacity of carbonate gas reservoirs, based on the concept of system node analysis, proposes to use pressure recovery well test interpretation data to create a graph of gas well inflow and outflow curves. This graph can graphically determine the maximum underground gas supply capacity and the absolute unobstructed flow rate of the gas well. This method supplements existing gas well production capacity evaluation methods, providing guidance for evaluating and determining gas well production capacity. Its practicality has been demonstrated through case studies of the Dengying and Qixia Formations gas reservoirs in the Anyue Gas Field of the Sichuan Basin.

[0126] The following are embodiments of the apparatus disclosed herein, which can be used to execute embodiments of the method disclosed herein. For details not disclosed in the apparatus embodiments of this disclosure, please refer to the embodiments of the method disclosed herein.

[0127] Figure 18 This is a structural block diagram of a carbonate gas reservoir productivity determination device according to an embodiment of this disclosure. This device can be implemented as all or part of an electronic device. Figure 18 As shown, the device includes: a first construction module 301, a first determination module 302, a second construction module 303, and a second determination module 304.

[0128] The first construction module 301 is used to construct a radial composite model based on the heterogeneity of carbonate gas reservoirs. The radial composite model is divided into two homogeneous regions, region I and region II, with region II surrounding region I.

[0129] The first determining module 302 is used to determine the flow equation of the I region and the flow equation of the II region, with the interface between the I region and the II region as the node;

[0130] The second construction module 303 is used to draw typical inflow and outflow curves using the flow equation of the II zone as the inflow equation and the flow equation of the I zone as the outflow equation, and to construct a typical inflow and outflow chart of the gas well.

[0131] The second determining module 304 is used to determine the absolute unobstructed flow rate of the gas well and the maximum underground gas supply capacity under the current operating conditions based on the typical inflow and outflow chart of the gas well.

[0132] Optionally, the flow equation for region I is as follows:

[0133]

[0134] in,

[0135]

[0136]

[0137] Where, p I The pressure at the interface is expressed in MPa; p wf A is the bottom hole flowing pressure, in MPa. I This is the Darcy seepage coefficient for zone I, in MPa. 2 / (10 4 m 3 / d);q sc Gas production, in units of 10. 4 m 3 / d;B I The coefficient for the non-Darcy seepage term in Zone I is given in MPa. 2 / (10 4 m 3 / d) 2 μ is the gas viscosity, in mPa·s; Z is the deviation factor, dimensionless; T is the reservoir temperature, in K; K I For penetration rate, m 2 ;rI r is the outer boundary radius of region I, in meters. w The inner boundary radius of region I is given in meters (m); S is the skin factor, dimensionless; h is the reservoir thickness in meters (m); and D is the non-Darcy flow term coefficient in MPa. 2 / (10 4 m 3 / d).

[0138] Optionally, the flow equation for region II is as follows:

[0139]

[0140] in,

[0141]

[0142]

[0143] Where, p e The outer boundary pressure of zone II is expressed in MPa; p I The pressure at the interface is expressed in MPa; A II This is the Darcy seepage coefficient for Zone II, in MPa. 2 / (10 4 m 3 / d);q sc Gas production, in units of 10. 4 m 3 / d;B II The coefficient for the non-Darcy seepage term in Zone II is given in MPa. 2 / (10 4 m 3 / d) 2 μ is the gas viscosity, in mPa·s; Z is the deviation factor, dimensionless; T is the reservoir temperature, in K; K II Permeability, in meters (m) 2 ;r e r is the vent radius, in meters (m). I The outer boundary radius of region I is given in meters (m); h is the reservoir thickness in meters (m); and D is the non-Darcy flow term coefficient in MPa. 2 / (10 4 m 3 / d).

[0144] Optionally, the outflow curve includes a first outflow curve when the bottom hole pressure is atmospheric pressure, and a second outflow curve when the bottom hole pressure is the current operating condition; the inflow curve includes a first inflow curve when the bottom hole pressure is atmospheric pressure, and a second inflow curve when the bottom hole pressure is the current operating condition.

[0145] The second determining module 304 is used to determine the absolute unobstructed flow rate of the gas well based on the intersection of the first outflow curve and the first inflow curve;

[0146] Based on the intersection of the second outflow curve and the second inflow curve, the maximum underground gas supply capacity under the current operating conditions is determined.

[0147] This disclosure also provides an electronic device, which may be the aforementioned terminal or server. The electronic device may include a processor and a memory, the memory storing at least one line of program code, which is loaded and executed by the processor to implement the aforementioned method.

[0148] Figure 19 This is a schematic diagram of the structure of an electronic device provided in an embodiment of this disclosure. See also... Figure 19 The electronic device 400 includes a central processing unit (CPU) 401, a system memory 404 including random access memory (RAM) 402 and read-only memory (ROM) 403, and a system bus 405 connecting the system memory 404 and the CPU 401. The electronic device 400 also includes a basic input / output system (I / O system) 406 that facilitates information transfer between various devices within the computer, and a mass storage device 407 for storing the operating system 413, application programs 414, and other program modules 415.

[0149] The basic input / output system 406 includes a display 408 for displaying information and an input device 409 for user input, such as a mouse or keyboard. Both the display 408 and the input device 409 are connected to the central processing unit 401 via an input / output controller 410 connected to the system bus 405. The basic input / output system 406 may also include the input / output controller 410 for receiving and processing input from multiple other devices such as a keyboard, mouse, or electronic stylus. Similarly, the input / output controller 410 also provides output to a display screen, printer, or other types of output devices.

[0150] Mass storage device 407 is connected to central processing unit 401 via a mass storage controller (not shown) connected to system bus 405. Mass storage device 407 and its associated computer-readable media provide non-volatile storage for electronic device 400. That is, mass storage device 407 may include computer-readable media (not shown) such as hard disk or CD-ROM drive.

[0151] Without loss of generality, computer-readable media can include computer storage media and communication media. Computer storage media include volatile and non-volatile, removable and non-removable media implemented using any method or technology for storing information such as computer-readable instructions, data structures, program modules, or other data. Computer storage media include RAM, ROM, erasable programmable read-only memory (EPROM), electrically erasable programmable read-only memory (EEPROM), flash memory or other solid-state storage technologies, compact disc read-only memory (CD-ROM), digital video disc (DVD) or other optical storage, magnetic tape cassettes, magnetic tape, disk storage, or other magnetic storage devices. Of course, those skilled in the art will recognize that computer storage media are not limited to the above-mentioned types. The system memory 404 and mass storage device 407 described above can be collectively referred to as memory.

[0152] According to various embodiments of this disclosure, electronic device 400 can also be connected to a remote computer on a network, such as the Internet. That is, electronic device 400 can be connected to network 412 via network interface unit 411 connected to system bus 405, or it can use network interface unit 411 to connect to other types of networks or remote computer systems (not shown).

[0153] The aforementioned memory also includes one or more programs, which are stored in the memory and configured to be executed by the CPU. The CPU 401 implements the aforementioned method for determining the production capacity of carbonate gas reservoirs by executing the one or more programs.

[0154] Those skilled in the art will understand that Figure 16 The structure shown does not constitute a limitation on the electronic device 400, and may include more or fewer components than shown, or combine certain components, or use different component arrangements.

[0155] This disclosure also provides a computer-readable storage medium storing at least one line of program code, which is loaded and executed by the processor to implement the method described above. For example, the computer-readable storage medium may be a ROM, random access memory (RAM), CD-ROM, magnetic tape, floppy disk, or optical data storage device.

[0156] This disclosure also provides a computer program product that stores at least one piece of program code, which is loaded and executed by the processor to implement the method described above.

[0157] It should be understood that "multiple" as used in this disclosure refers to two or more. "And / or" describes the relationship between related objects, indicating that three relationships can exist. For example, A and / or B can represent: A alone, A and B simultaneously, or B alone. The character " / " generally indicates that the preceding and following related objects have an "or" relationship.

[0158] Those skilled in the art will understand that all or part of the steps of the above embodiments can be implemented by hardware or by a program instructing related hardware. The program can be stored in a computer-readable storage medium, such as a read-only memory, a disk, or an optical disk.

[0159] The above description is merely a specific embodiment of this disclosure, but the scope of protection of this disclosure is not limited thereto. Any variations or substitutions that can be easily conceived by those skilled in the art within the scope of the technology disclosed in this disclosure should be included within the scope of protection of this disclosure. Therefore, the scope of protection of this disclosure should be determined by the scope of the claims.

Claims

1. A method for determining the production capacity of a carbonate gas reservoir, characterized in that, The method includes: Based on the heterogeneity of carbonate gas reservoirs, a radial composite model is constructed. The radial composite model is divided into two homogeneous regions, region I and region II, with region II surrounding region I. Using the interface between region I and region II as nodes, determine the flow equations for region I and region II; Using the flow equation of Zone II as the inflow equation and the flow equation of Zone I as the outflow equation, typical inflow and outflow curves are plotted to construct a typical inflow and outflow chart for gas wells. Based on the typical inflow and outflow charts of the gas well, the absolute unobstructed flow rate of the gas well and the maximum underground gas supply capacity under the current operating conditions are determined.

2. The method according to claim 1, characterized in that, The flow equations for region I are as follows: in, Where, p I The pressure at the interface is expressed in MPa; p wf A is the bottom hole flowing pressure, in MPa. I This is the Darcy seepage coefficient for zone I, in MPa. 2 / (10 4 m 3 / d);q sc Gas production, in units of 10. 4 m 3 / d;B I The coefficient for the non-Darcy seepage term in Zone I is given in MPa. 2 / (10 4 m 3 / d) 2 μ is the gas viscosity, in mPa·s; Z is the deviation factor, dimensionless; T is the reservoir temperature, in K; K I For penetration rate, m 2 ;r I r is the outer boundary radius of region I, in meters. w The inner boundary radius of region I is given in meters (m); S is the skin factor, dimensionless; h is the reservoir thickness in meters (m); and D is the non-Darcy flow term coefficient in MPa. 2 / (10 4 m 3 / d).

3. The method according to claim 1, characterized in that, The flow equations for region II are as follows: in, Where, p e The outer boundary pressure of zone II is expressed in MPa; p I The pressure at the interface is expressed in MPa; A II This is the Darcy seepage coefficient for Zone II, in MPa. 2 / (10 4 m 3 / d);q sc Gas production, in units of 10. 4 m 3 / d;B II The coefficient for the non-Darcy seepage term in Zone II is given in MPa. 2 / (10 4 m 3 / d) 2 μ is the gas viscosity, in mPa·s; Z is the deviation factor, dimensionless; T is the reservoir temperature, in K; K II Permeability, in meters (m) 2 ;r e r is the vent radius, in meters (m). I The outer boundary radius of region I is given in meters (m); h is the reservoir thickness in meters (m); and D is the non-Darcy flow term coefficient in MPa. 2 / (10 4 m 3 / d).

4. The method according to any one of claims 1 to 3, characterized in that, The outflow curve includes a first outflow curve when the bottom hole pressure is atmospheric pressure, and a second outflow curve when the bottom hole pressure is the current operating condition; the inflow curve includes a first inflow curve when the bottom hole pressure is atmospheric pressure, and a second inflow curve when the bottom hole pressure is the current operating condition. The determination of the absolute unobstructed flow rate of the gas well and the maximum underground gas supply capacity under current operating conditions based on the typical inflow and outflow chart of the gas well includes: The absolute unobstructed flow rate of the gas well is determined based on the intersection of the first outflow curve and the first inflow curve. Based on the intersection of the second outflow curve and the second inflow curve, the maximum underground gas supply capacity under the current operating conditions is determined.

5. A device for determining the production capacity of a carbonate gas reservoir, characterized in that, The device includes: The first construction module is used to construct a radial composite model based on the heterogeneity of carbonate gas reservoirs. The radial composite model is divided into two homogeneous regions, region I and region II, with region II surrounding region I. The first determining module is used to determine the flow equations of region I and region II, with the interface between region I and region II as nodes; The second construction module is used to draw typical inflow and outflow curves using the flow equation of Zone II as the inflow equation and the flow equation of Zone I as the outflow equation, and to construct a typical inflow and outflow chart for gas wells. The second determining module is used to determine the absolute unobstructed flow rate of the gas well and the maximum underground gas supply capacity under the current operating conditions based on the typical inflow and outflow chart of the gas well.

6. The apparatus according to claim 5, characterized in that, The flow equations for region I are as follows: in, Where, p I The pressure at the interface is expressed in MPa; p wf A is the bottom hole flowing pressure, in MPa. I This is the Darcy seepage coefficient for zone I, in MPa. 2 / (10 4 m 3 / d);q sc Gas production, in units of 10. 4 m 3 / d;B I The coefficient for the non-Darcy seepage term in Zone I is given in MPa. 2 / (10 4 m 3 / d) 2 μ is the gas viscosity, in mPa·s; Z is the deviation factor, dimensionless; T is the reservoir temperature, in K; K I For penetration rate, m 2 ;r I r is the outer boundary radius of region I, in meters. w The inner boundary radius of region I is given in meters (m); S is the skin factor, dimensionless; h is the reservoir thickness in meters (m); and D is the non-Darcy flow term coefficient in MPa. 2 / (10 4 m 3 / d).

7. The apparatus according to claim 5, characterized in that, The flow equations for region II are as follows: in, Where, p e The outer boundary pressure of zone II is expressed in MPa; p I The pressure at the interface is expressed in MPa; A II This is the Darcy seepage coefficient for Zone II, in MPa. 2 / (10 4 m 3 / d);q sc Gas production, in units of 10. 4 m 3 / d;B II The coefficient for the non-Darcy seepage term in Zone II is given in MPa. 2 / (10 4 m 3 / d) 2 μ is the gas viscosity, in mPa·s; Z is the deviation factor, dimensionless; T is the reservoir temperature, in K; K II Permeability, in meters (m) 2 ;r e r is the vent radius, in meters (m). I The outer boundary radius of region I is given in meters (m); h is the reservoir thickness in meters (m); and D is the non-Darcy flow term coefficient in MPa. 2 / (10 4 m 3 / d).

8. The apparatus according to any one of claims 5 to 7, characterized in that, The outflow curve includes a first outflow curve when the bottom-hole pressure is atmospheric pressure, and a second outflow curve when the bottom-hole pressure is the current operating condition; the inflow curve includes a first inflow curve when the bottom-hole pressure is atmospheric pressure, and a second inflow curve when the bottom-hole pressure is the current operating condition; the second determining module is used to determine the absolute unobstructed flow rate of the gas well based on the intersection of the first outflow curve and the first inflow curve; Based on the intersection of the second outflow curve and the second inflow curve, the maximum underground gas supply capacity under the current operating conditions is determined.

9. An electronic device, characterized in that, The electronic device includes a processor and a memory, the memory storing at least one piece of program code, which is loaded and executed by the processor to implement the method as claimed in any one of claims 1 to 4.

10. A computer-readable storage medium, characterized in that, The computer-readable storage medium stores at least one piece of program code, which is loaded and executed by a processor to implement the method as described in any one of claims 1 to 4.

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