Method, system and equipment for determining geological reserves and storage medium

Abstract

The embodiment of the invention relates to the field of petroleum and natural gas development, and discloses a method, system and equipment for determining geological reserves and a storage medium, and the method comprises the steps: generating a multi-component hydrocarbon system PT phase diagram through PVT phase state simulation calculation; according to the temperature and pressure of the stratum, the gas reservoir type is judged by combining a PT phase diagram; according to the PT phase diagram, obtaining corrected black oil PVT attribute data through phase state simulation; the original oil saturation is determined according to the original water saturation, the original formation pressure and the retrograde condensate volume percentage; establishing corresponding material balance relations under the three isothermal pressure drop paths; selecting a corresponding material balance relation according to the type of the gas reservoir, and solving the selected material balance relation by utilizing the corrected black oil PVT attribute data and the original oil saturation to obtain a solving result; and calculating the gas-bearing dynamic geological reserves and the accumulated water invasion amount according to the solving result. According to the embodiment of the invention, the problem that the calculation error is large when the gas condensate content is high is solved.

Description

TECHNICAL FIELD

[0001] The embodiment of the present disclosure relates to the technical field of oil and gas development, in particular to a linear regression method, system, device and storage medium for determining dynamic geological reserves of a water-drive condensate gas reservoir. BACKGROUND

[0002] Most of the conventional gas reservoirs in China belong to water-drive gas reservoirs to varying degrees. During the development of the gas reservoir, water gradually invades the gas reservoir as the formation pressure drops. The invasion of water can not only supplement the formation energy, but also form a seepage two-phase zone and reduce the recovery factor of the gas reservoir. Water-drive condensate gas reservoirs and water-drive fractured gas reservoirs are one of the most complex types of various discovered gas reservoirs. The conventional gas-drive gas reservoir dynamic reserve calculation method is not applicable to the reserve calculation of water-drive gas reservoirs. Obtaining accurate dynamic geological reserves and water body size is the basis for calibrating the recovery factor and is also a prerequisite for determining the development principles and adjusting the later development plan of the water-drive gas reservoir.

[0003] The pressure dynamic characteristics of the water-drive gas reservoir, that is, the relationship between the formation pressure (P / Z) and the cumulative gas production (GP), are different from those of the conventional gas reservoir. The pressure dynamic characteristics are not a straight line. The water invasion dynamics is related to the geometric shape of the water body, the contact interface pressure between the water area and the gas reservoir and other factors. The existing technical solutions are to convert the condensate oil into dry gas and then use the existing water-drive gas reservoir material balance equation to calculate the reserves. When the condensate oil content is high, the calculation error cannot be ignored. SUMMARY

[0004] The embodiment of the present disclosure provides a method, system, device and storage medium for determining geological reserves to solve or alleviate one or more technical problems in the prior art.

[0005] According to one aspect of the present disclosure, a method for determining geological reserves is provided, comprising:

[0006] generating a multi-component hydrocarbon system PT phase diagram through PVT phase state simulation calculation;

[0007] determining the type of the gas reservoir according to the temperature and pressure of the formation in combination with the PT phase diagram;

[0008] obtaining corrected black oil PVT attribute data through phase state simulation according to the PT phase diagram;

[0009] determining the original oil saturation according to the original water saturation, the original formation pressure and the anti-condensate liquid volume percentage;

[0010] establishing a corresponding material balance relationship under three isothermal pressure drop paths;

[0011] According to the type of the gas reservoir, a corresponding material balance relationship is selected, and the selected material balance relationship is solved by using the corrected black oil PVT attribute data and the original oil saturation to obtain a solving result;

[0012] According to the solving result, the gas dynamic geological reserves and the cumulative water invasion amount are calculated.

[0013] In a possible implementation, the corrected black oil PVT attribute data include four groups of experimental data series: pressure-oil volume coefficient, pressure-gas volume coefficient, pressure-dissolved gas-oil ratio, and pressure-volatile oil-gas ratio.

[0014] In a possible implementation, the original oil saturation is determined according to the original water saturation, the original formation pressure, and the retrograde condensate volume percentage, and includes the following steps.

[0015] The original water saturation is obtained through well logging interpretation;

[0016] The original formation pressure is obtained through formation testing;

[0017] A functional relationship between the pressure and the retrograde condensate percentage is established by using a linear interpolation method;

[0018] The original formation pressure is substituted into the function to obtain the original oil saturation.

[0019] In a possible implementation, the three isothermal pressure drop paths include a pressure drop path I from an unsaturated gas reservoir to an unsaturated gas reservoir, a pressure drop path II from a supersaturated gas reservoir to a supersaturated gas reservoir, and a pressure drop path III from an unsaturated gas reservoir to a supersaturated gas reservoir.

[0020] In a possible implementation, the material balance relationship under the pressure drop path I is as follows.

[0021]

[0022]

[0023]

[0024] In the formula, G i is the gas dynamic geological reserves; ω is the water invasion replacement coefficient; Δp is the formation pressure difference; C e is the equivalent compression coefficient; B g is the gas volume coefficient; B gi is the gas volume coefficient under the original formation pressure; G p is the surface cumulative gas production;

[0025] The material balance relationship under the pressure drop path II is as follows.

[0026]

[0027]

[0028]

[0029] G = G0(1 - ω) + G0ω i is the gas dynamic geological reserves; ω is the water invasion replacement coefficient; Δp is the formation pressure difference; λ is the equivalent gas saturation; C e is the equivalent compressibility; B g is the gas volume coefficient; B gi is the gas volume coefficient under the original formation pressure; B o is the oil volume coefficient; R v is the volatile oil gas ratio; R s is the dissolved gas oil ratio; S wi is the original water saturation; S oi is the original oil saturation; R si is the dissolved gas oil ratio under the original formation pressure; B oi is the oil volume coefficient under the original formation pressure; R vi is the volatile oil gas ratio under the original formation pressure; G p is the surface cumulative gas production; N p is the surface cumulative oil production;

[0030] The material balance relationship under the pressure drop path III is:

[0031]

[0032]

[0033]

[0034] G = G0(1 - ω) + G0ω i is the gas dynamic geological reserves; ω is the water invasion replacement coefficient; Δp is the formation pressure difference; λ is the equivalent gas saturation; C e is the equivalent compressibility; B g is the gas volume coefficient; B gi is the gas volume coefficient under the original formation pressure; B o is the oil volume coefficient; R v is the volatile oil gas ratio; R s is the dissolved gas oil ratio; R vi is the volatile oil gas ratio under the original formation pressure; N p is the surface cumulative oil production.

[0035] In one possible implementation, calculating the gas dynamic geological reserves and the cumulative water invasion according to the solving result comprises:

[0036] drawing an x-y data corresponding relationship curve according to the solving result;

[0037] According to the x-y data correspondence curve, a critical slope line passing through the origin is drawn;

[0038] Linear regression analysis is performed on the data points above the critical slope line to obtain the slope and intercept y 截距1 ;

[0039] According to the slope, the gas-bearing dynamic geological reserves are calculated, and according to the intercept y 截距1 , the equivalent compressibility is calculated;

[0040] For the data points deviating from the straight line segment, parallel lines parallel to the first linear regression straight line are drawn in turn, and the corresponding intercept y 截距2 is calculated.

[0041] According to the intercept y 截距1 and the intercept y 截距2 , the cumulative water influx at the corresponding time is determined.

[0042] According to one aspect of the present disclosure, a system for determining geological reserves is provided, comprising:

[0043] A generating unit is configured to generate a multi-component hydrocarbon system PT phase diagram through PVT phase simulation calculation;

[0044] A judging unit is configured to determine the gas reservoir type according to the temperature and pressure of the formation in combination with the PT phase diagram;

[0045] An obtaining unit is configured to obtain the corrected black oil PVT property data through phase simulation according to the PT phase diagram;

[0046] A determining unit is configured to determine the original oil saturation according to the original water saturation, the original formation pressure, and the retrograde condensate volume percentage;

[0047] An establishing unit is configured to establish the corresponding material balance relationship under three isothermal pressure drop paths;

[0048] A solving unit is configured to select the corresponding material balance relationship according to the gas reservoir type, solve the selected material balance relationship using the corrected black oil PVT property data and the original oil saturation, and obtain a solving result;

[0049] A calculating unit is configured to calculate the gas-bearing dynamic geological reserves and the cumulative water influx according to the solving result.

[0050] In one possible implementation, the corrected black oil PVT property data includes four series of experimental data: pressure-oil volume coefficient, pressure-gas volume coefficient, pressure-dissolved gas-oil ratio, and pressure-volatile oil-gas ratio.

[0051] In one possible implementation, the determining unit comprises:

[0052] The first obtaining module is configured to obtain the original water saturation through well logging interpretation;

[0053] The second obtaining module is configured to obtain the original formation pressure through formation testing;

[0054] The establishing module is configured to establish a functional relationship between the pressure and the retrograde condensate percentage through a linear interpolation method;

[0055] The substituting module is configured to substitute the original formation pressure into the function to obtain the original oil saturation.

[0056] In a possible implementation, the three isothermal pressure drop paths include a pressure drop path I from an unsaturated gas reservoir to an unsaturated gas reservoir, a pressure drop path II from a supersaturated gas reservoir to a supersaturated gas reservoir, and a pressure drop path III from an unsaturated gas reservoir to a supersaturated gas reservoir.

[0057] In a possible implementation, the material balance relationship under the pressure drop path I is:

[0058]

[0059]

[0060]

[0061] In the formula, G i is the gas-bearing dynamic geological reserves; ω is the water invasion replacement coefficient; Δp is the formation pressure difference; C e is the equivalent compressibility; B g is the gas volume coefficient; B gi is the gas volume coefficient under the original formation pressure; G p is the surface cumulative gas production;

[0062] The material balance relationship under the pressure drop path II is:

[0063]

[0064]

[0065]

[0066] In the formula, G i is the gas-bearing dynamic geological reserves; ω is the water invasion replacement coefficient; Δp is the formation pressure difference; λ is the equivalent gas saturation; C e is the equivalent compressibility; B g is the gas volume coefficient; B gi is the gas volume coefficient under the original formation pressure; B o is the oil volume coefficient; R v is the volatile oil gas ratio; R sB is the dissolved gas-oil ratio; S wi B is the original water saturation; S oi B is the original oil saturation; R si B is the dissolved gas-oil ratio under the original formation pressure; S oi B is the oil volume factor under the original formation pressure; R vi B is the volatile oil-gas ratio under the original formation pressure; G p B is the cumulative gas production on the ground; N p B is the cumulative oil production on the ground;

[0067] The material balance relationship under the pressure drop path III is:

[0068]

[0069]

[0070]

[0071] In the formula, G i B is the gas-bearing dynamic geological reserves; ω is the water invasion replacement coefficient; Δp is the formation pressure difference; C e B is the equivalent compressibility; B g B is the gas volume factor; B gi B is the gas volume factor under the original formation pressure; B o B is the oil volume factor; R v B is the volatile oil-gas ratio; R s B is the dissolved gas-oil ratio; R vi B is the volatile oil-gas ratio under the original formation pressure; N p B is the cumulative oil production on the ground.

[0072] In one possible implementation, the calculation unit comprises:

[0073] A first drawing module is configured to draw an x-y data corresponding relationship curve according to the solution result.

[0074] A second drawing module is configured to draw a critical slope line passing through the origin according to the x-y data corresponding relationship curve.

[0075] An analysis module is configured to perform linear regression analysis on data points above the critical slope line to obtain a slope and an intercept y 截距1 .

[0076] A first calculation module is configured to calculate the gas-bearing dynamic geological reserves according to the slope and calculate the equivalent compressibility according to the intercept y 截距1 .

[0077] A second calculation module is configured to draw parallel lines parallel to the first linear regression line in sequence for data points deviating from the straight line segment and calculate corresponding intercepts y 截距2;

[0078] determining module, configured to determine the cumulative water influx at the corresponding moment according to the intercept y 截距1 and the intercept y 截距2 determining the cumulative water influx at the corresponding moment.

[0079] According to one aspect of the present disclosure, there is provided an apparatus comprising:

[0080] a processor and a memory;

[0081] The memory is configured to store a computer program, and the processor is configured to invoke the computer program stored in the memory to execute the method for determining the geological reserves according to any one of the preceding aspects.

[0082] According to one aspect of the present disclosure, there is provided a computer readable storage medium having stored therein a computer program, which, when executed by a processor, causes the processor to perform the method for determining the geological reserves according to any one of the preceding aspects.

[0083] The exemplary embodiments of the present disclosure have the following beneficial effects: The exemplary embodiments of the present disclosure, on the basis of a given PT phase diagram, give the expressions of the material balance equations of water-drive condensate gas reservoirs under different pressure drop paths, and express the material balance equations in different linear forms, and determine the gas-bearing dynamic geological reserves through the intersection of the linear regression straight line and the coordinate axis, thereby solving the problem that the prior art uses the existing material balance equations of water-drive gas reservoirs to calculate the reserves, and the calculation error is large when the condensate oil content is high.

[0084] The details of one or more embodiments of the application are set forth in the accompanying drawings and the description below. Other features and advantages of the application will become apparent from the description in the drawings and the description below. It should be understood that the following general description and the detailed description are only exemplary and explanatory and are not restrictive of the application. BRIEF DESCRIPTION OF DRAWINGS

[0085] The accompanying drawings, which are incorporated in and constitute a part of this specification, illustrate embodiments consistent with the present disclosure and serve to explain the principles of the present disclosure. It is readily apparent to one skilled in the art that the following figures are merely some embodiments of the present disclosure, and other figures can be obtained from these figures without creative labor.

[0086] Figure 1 is a flowchart of a method for determining geological reserves according to the present exemplary embodiments;

[0087] Figure 2 is a PT phase diagram of a hydrocarbon system according to the present exemplary embodiments;

[0088] Figure 3is a volume percentage chart of the reversed condensate of this exemplary embodiment;

[0089] Figure 4 is a modified black oil PVT parameter chart of this exemplary embodiment;

[0090] Figure 5 is a schematic diagram of linear regression results of gas reservoir dynamic data when the water invasion replacement coefficient is low according to this exemplary embodiment;

[0091] Figure 6 3 is a schematic diagram of calculation results of water invasion amount in a gas reservoir when the water invasion replacement coefficient is high according to this exemplary embodiment;

[0092] Figure 7 is a block diagram of a system for determining geological reserves according to an exemplary embodiment;

[0093] Figure 8 FIG. 4 is a schematic structural diagram of a device according to the exemplary embodiment of the present invention. DETAILED DESCRIPTION

[0094] Example embodiments will now be described more fully with reference to the accompanying drawings. However, example embodiments can be implemented in a variety of forms and should not be construed as limited to the examples set forth herein; rather, these embodiments are provided so that the present disclosure will be more comprehensive and complete and will fully convey the concepts of the example embodiments to those skilled in the art. The described features, structures, or characteristics may be combined in any suitable manner in one or more embodiments. In the following description, many specific details are provided to provide a full understanding of the embodiments of the present disclosure. However, those skilled in the art will appreciate that the technical solutions of the present disclosure may be practiced while omitting one or more of the specific details, or that other methods, components, devices, steps, etc. may be employed. In other cases, well-known technical solutions are not shown or described in detail to avoid obscuring various aspects of the present disclosure.

[0095] In addition, the accompanying drawings are merely schematic illustrations of the present disclosure and are not necessarily drawn to scale. Identical reference numerals in the figures denote identical or similar parts, and thus repetitive descriptions thereof will be omitted. Some of the block diagrams shown in the accompanying drawings are functional entities that do not necessarily correspond to physically or logically separate entities. These functional entities may be implemented in software, in one or more hardware units or integrated circuits, or in different networks and / or processor devices and / or microcontroller devices.

[0096] The flowcharts shown in the accompanying drawings are merely illustrative and do not necessarily include all steps. For example, some steps may be decomposed, while some steps may be combined or partially combined, so the actual execution order may change according to actual circumstances.

[0097] The terms "first", "second", and the like, in the description and in the claims of the present application, and above, are used for distinguishing between similar objects and not necessarily for describing a specific sequential or chronological order. It is to be understood that the use of the terms so

[0098] Also, the terms "comprise", "comprising", "have", "having", "include", "including", "contain", "containing", and any variations thereof, are intended to cover a non-exclusive inclusion, such that a process, method, system, product, or apparatus that comprises, has, includes, contains a list of steps or components, or a subset thereof, is not necessarily limited to those steps or components, but can include additional steps or components not expressly listed or inherent to such process, method, system, product, or apparatus.

[0099] Figure 1 is a flow chart of a method for determining a geological reserve according to an example embodiment of the present disclosure, as shown in FIG. 1, the example embodiment of the present disclosure provides a method for determining a geological reserve, comprising: Figure 1

[0100] S1 generating a PT phase diagram of a multi-component hydrocarbon system through PVT phase simulation calculation;

[0101] S2 determining a gas reservoir type according to a temperature and a pressure of a formation in combination with the PT phase diagram;

[0102] S3 obtaining corrected black oil PVT attribute data through phase simulation according to the PT phase diagram;

[0103] S4 determining an original oil saturation according to an original water saturation, an original formation pressure, and a retrograde condensate volume percentage;

[0104] S5 establishing a corresponding material balance relationship under three isothermal pressure drop paths;

[0105] S6 selecting a corresponding material balance relationship according to the gas reservoir type, and solving the selected material balance relationship by using the corrected black oil PVT attribute data and the original oil saturation to obtain a solving result;

[0106] S7 calculating a dynamic gas-bearing geological reserve and a cumulative water invasion amount according to the solving result.

[0107] Specifically, the corrected black oil PVT attribute data includes four series of experimental data: pressure-oil volume factor, pressure-gas volume factor, pressure-dissolved gas-oil ratio, and pressure-volatile oil-gas ratio.

[0108] Specifically, determining the original oil saturation according to the original water saturation, the original formation pressure, and the retrograde condensate volume percentage includes:

[0109] ​The original water saturation is obtained by well logging interpretation;

[0110] The original formation pressure is obtained by formation testing;

[0111] The function relationship between the pressure and the percentage of retrograde condensate is established by the linear interpolation method;

[0112] The original oil saturation is obtained by substituting the original formation pressure into the function.

[0113] Specifically, the three isothermal pressure drop paths include a pressure drop path I from an unsaturated gas reservoir to an unsaturated gas reservoir, a pressure drop path II from a supersaturated gas reservoir to a supersaturated gas reservoir, and a pressure drop path III from an unsaturated gas reservoir to a supersaturated gas reservoir.

[0114] Specifically, the material balance relationship under the pressure drop path I is:

[0115]

[0116]

[0117]

[0118] In the formula, G i is the gas dynamic geological reserves; ω is the water invasion replacement coefficient; Δp is the formation pressure difference; C e is the equivalent compressibility; B g is the gas volume coefficient; B gi is the gas volume coefficient under the original formation pressure; G p is the cumulative gas production on the ground;

[0119] The material balance relationship under the pressure drop path II is:

[0120]

[0121]

[0122]

[0123] In the formula, G i is the gas dynamic geological reserves; ω is the water invasion replacement coefficient; Δp is the formation pressure difference; λ is the equivalent gas saturation; C e is the equivalent compressibility; B g is the gas volume coefficient; B gi is the gas volume coefficient under the original formation pressure; B o is the oil volume coefficient; R v is the volatile oil gas ratio; R s is the dissolved gas oil ratio; S wi is the original water saturation; S oiis the original oil saturation; R si is the dissolved gas-oil ratio under the original formation pressure; B oi is the oil volume factor under the original formation pressure; R vi is the gas-oil ratio under the original formation pressure; G p is the cumulative gas production on the ground; N p is the cumulative oil production on the ground;

[0124] The material balance relationship under the pressure drop path III is:

[0125]

[0126]

[0127]

[0128] In the formula: G i is the gas-bearing dynamic geological reserves; ω is the water invasion replacement coefficient; Δp is the formation pressure difference; C e is the equivalent compressibility; B g is the gas volume factor; B gi is the gas volume factor under the original formation pressure; B o is the oil volume factor; R v is the gas-oil ratio; R s is the dissolved gas-oil ratio; R vi is the gas-oil ratio under the original formation pressure; N p is the cumulative oil production on the ground.

[0129] Specifically, calculating the gas-bearing dynamic geological reserves and the cumulative water invasion amount according to the solving result includes:

[0130] According to the solving result, an x-y data corresponding relationship curve is drawn;

[0131] According to the x-y data corresponding relationship curve, a critical slope line passing through the origin is drawn;

[0132] Linear regression analysis is performed on the data points above the critical slope line to obtain the slope and intercept y 截距1 .

[0133] The gas-bearing dynamic geological reserves are calculated according to the slope, and the equivalent compressibility is calculated according to the intercept y 截距1 .

[0134] For the data points deviating from the straight line segment, parallel lines parallel to the first linear regression straight line are drawn in turn, and the corresponding intercepts y 截距2 are calculated.

[0135] The cumulative water invasion amount at the corresponding moment is determined according to the intercept y 截距1 and the intercept y 截距2 .

[0136] Exemplarily, the embodiment discloses a method for predicting ultimate recoverable reserves, comprising the following steps:

[0137] Step A), several important concepts or parameters are defined, including:

[0138] A1) the fluid in the gas reservoir is divided into hydrocarbon fluid and formation water, wherein the hydrocarbon refers to oil or gas;

[0139] A2) the phase envelope aCb separates the two-phase region and the single-phase region (as shown in Figure 2 ), wherein the inside of the envelope is the two-phase region, and the outside is the single-phase region, aC is the bubble point line, indicating the 100% isoflux line, and Cb is the dew point line, indicating the 0% isoflux line;

[0140] A3) the critical point, that is, Figure 2 the intersection point of the bubble point line and the dew point line, corresponding to the critical temperature and the critical pressure, and the temperature of the gas reservoir is higher than the critical temperature;

[0141] A4) the dew point pressure refers to the pressure on the dew point line, indicating that when the pressure is lower than the dew point pressure, liquid droplets appear in the hydrocarbon fluid.

[0142] Step B), judging the type of the gas reservoir according to the PT (pressure-temperature) phase diagram of the multi-component hydrocarbon system, the temperature and the pressure. Figure 2 , H points all indicate condensate gas reservoirs, and the temperature of the gas reservoir is between the critical temperature and the critical condensate temperature. Among them, the pressure of the J point is higher than the dew point pressure, is in the single-phase region, is in the single-phase gas state, and is an unsaturated gas reservoir. The pressure of the K point is all lower than the dew point pressure, is in the two-phase region (i.e. gas and liquid coexist), and forms a gas cap and an oil ring under the action of gas-liquid gravity differentiation, and is a supersaturated gas reservoir. The pressure of the H point is equal to the dew point pressure. When the pressure of the gas reservoir decreases from the J point to the H point, the hydrocarbon fluid is still in the gas state, and with the decrease of the formation pressure, liquid phase condensate is formed in the formation.

[0143] Step C), obtaining the temperature of the gas reservoir according to the test and interpretation of the geothermal gradient. According to the original water saturation determined and interpreted, the original oil saturation is determined through the retrograde condensate volume percentage chart (as shown in Figure 3 ).

[0144] S oi =(1-S wi )×V roCCE (p i );

[0145] In the formula, p i is the original formation pressure (MPa), S oi is the original oil saturation (dimensionless), S wi is the original water saturation (dimensionless), and VroCCE () is an interpolation function established according to the data of the same-component expansion experiment.

[0146] Step D), the corresponding material balance equation expressions under three isothermal pressure drop paths are given. In the case of a given gas reservoir temperature, the pressure drop path refers to the change range from the original reservoir pressure to the current reservoir pressure. Among them, the pressure drop path I refers to the change from the unsaturated gas reservoir to the unsaturated gas reservoir; the pressure drop path II refers to the change from the supersaturated gas reservoir to the supersaturated gas reservoir; and the pressure drop path III refers to the change from the unsaturated gas reservoir to the supersaturated gas reservoir.

[0147] Here, the hydrocarbon system in the condensate gas reservoir in path I always maintains a single gas phase, and gas and water coexist. The linear expression of the corresponding material balance equation is:

[0148]

[0149] The left side of equation (1) is denoted as y:

[0150]

[0151] The right side of equation (1) is denoted as x:

[0152]

[0153] In equations (1)-(3): B gi is the gas volume coefficient (dimensionless) under the original reservoir pressure, B w is the water volume coefficient (dimensionless), G p is the cumulative gas production on the ground (cubic meters), and △p is the difference in reservoir pressure (MPa), C e is the equivalent compressibility (1 / MPa), and the above parameters are known quantities. G i is the gas-bearing dynamic geological reserves (cubic meters), and ω is the water invasion replacement coefficient (dimensionless), and the above parameters are unknown quantities.

[0154] In path II, the hydrocarbon system is in two phases under the original state, and oil, gas and water coexist. The linear expression of the corresponding material balance equation is:

[0155]

[0156] The left side of equation (4) is denoted as y:

[0157]

[0158] The right side of equation (4) is denoted as x:

[0159]

[0160] In equations (4)-(6): B oiR is the oil volume factor (MPa) at initial reservoir pressure si R is the dissolved gas-oil ratio (dimensionless) at initial reservoir pressure vi R is the volatile oil-gas ratio (dimensionless) at initial reservoir pressure p N is the equivalent gas saturation (dimensionless)

[0161] In path III, the hydrocarbon system is in single-phase gas state at initial state. When the reservoir pressure is higher than the dew point pressure, the material balance equation is consistent with the formula in path I. When the reservoir pressure is lower than the dew point pressure, the linear expression of the corresponding material balance equation is:

[0162]

[0163] The left side of equation (7) is denoted as y:

[0164]

[0165] The right side of equation (7) is denoted as x:

[0166]

[0167] Step D) gives the data analysis steps,

[0168] D1) based on production data and reservoir pressure data, x and y are calculated respectively;

[0169] D2) plot the x-y data pair relationship curve, and draw the critical slope line passing through the origin;

[0170] D3) use the data points above the critical slope line for linear regression analysis. The reciprocal of the slope (y 斜率 ) is the dynamic gas-bearing geological reserves, and the calculation formula is The intercept (y 截距1 ) is the equivalent compressibility, and the calculation formula is y 截距1 = C e ;

[0171] D4) for the data points deviating from the straight line segment, draw parallel lines parallel to the first linear regression straight line in turn, and calculate the corresponding intercept (y 截距2 );

[0172] D5) determine the cumulative water influx at the corresponding time according to the intercept value. For gas reservoirs along path I and path III pressure drop, the cumulative water influx W e is calculated by the formula:

[0173] W e = B gi G i Δp(y 截距2-y 截距1 )+W p B w ; (10)

[0174] For gas reservoirs with pressure drop along path II, the cumulative water influx W e The calculation formula is:

[0175] W e = B gi G i Δp(y 截距2 -λy 截距1 )+W p B w ; (11)

[0176] Preferably, in step B), given the temperature, the calculation is further carried out according to the PT phase diagram using phase state simulation to obtain the corrected black oil PVT property data, including: C1) oil volume factor (B o ), C2) gas volume factor (B g ), C3) dissolved gas-oil ratio (R s ), C4) volatile oil-gas ratio (R v ).

[0177] Preferably, in step D), the corresponding intermediate variables are defined as, C e is defined as the equivalent compressibility factor:

[0178]

[0179] ω is defined as the water influx volume factor:

[0180]

[0181] λ is defined as the equivalent gas saturation:

[0182]

[0183] In formulas (10)-(14): c w is the water compressibility factor (1 / Mpa), W p is the surface cumulative water production (m3), and the above parameters are known quantities. W e is the cumulative water influx (m3), and the above parameters are unknown quantities. S wi is the original water saturation; B gi is the gas volume factor under the original formation pressure; G i is the gas-bearing dynamic geological reserves; S wi is the original water saturation; S oi is the original oil saturation; R si is the dissolved gas-oil ratio under the original formation pressure; B oiB is the oil volume factor (dimensionless) at the initial reservoir pressure. w B is the water volume factor (dimensionless).

[0184] The advantages and features of the present disclosure will be more clearly understood through the following detailed description of the preferred embodiments of the present disclosure with reference to the accompanying drawings, so as to make the scope of protection of the present disclosure clearer and more explicit.

[0185] In step A), according to the phase state test of the hydrocarbon system, the phase behavior described by the equation of state is fitted with the experimental data, and then various PVT phase state simulation calculations are carried out in combination with experimental processes such as isochoric expansion, isochoric depletion and dew point pressure test, and a PT phase diagram is generated. Specifically, in the fitting, Winprop is used to complete the phase state simulation software.

[0186] In step B), the modified black oil PVT attribute data (such as Figure 4 ) are obtained through phase state simulation, including four series of experimental data, i.e. pressure-oil volume factor, pressure-gas volume factor, pressure-dissolved gas-oil ratio and pressure-volatile oil-gas ratio. The functional relationship between pressure and PVT attribute is established by linear interpolation method.

[0187] In step C), the original water saturation value is obtained by well logging interpretation, and the original reservoir pressure is obtained by formation test. The functional relationship between pressure and retrograde condensate percentage is established by linear interpolation method, and the original oil saturation is obtained by substituting the original reservoir pressure into the function.

[0188] In step D), the water drive condensate gas reservoir dynamic data along path II pressure drop are taken as an example. The dynamic data are arranged in Table 1.

[0189] Table 1 Gas reservoir dynamic data table

[0190] Time Formation pressure Cumulative gas production Cumulative oil production Cumulative water production 1 [P1] G p1 ]]> <![CDATA[N p1 ]]> [WC p1 ]]> 2 [P2] G p2 ]]> <![CDATA[N p2 ]]> W p2 <!-- 10 -->]]> ··· ··· ··· ··· ···

[0191] D1)~D2), the calculated x and y are plotted in the rectangular coordinate system Figure 5 ), and the critical slope line (blue dotted line) passing through the origin is plotted;

[0192] D3) Linear regression analysis is carried out on the data points above the critical slope line (t1 below data), and the linear regression equation is y=1.05×10 -8 x-5.93×10 -8 , the gas-bearing dynamic geological reserves are calculated according to the slope as G i =9.83×10 7 m 3 , the equivalent compressibility C e =1.41×10 -10 1 / Pa;

[0193] D4) for the data points deviating from the straight line segment (t1 above data), sequentially draw parallel lines (parallel to the first linear regression straight line Figure 6 ) of the data points. Figure 6 Taking the t2 time point as an example, the corresponding intercept (y 截距2 ) is calculated, and according to the cumulative water influx calculation formula, the cumulative water influx at this time point is W e = 4.56 x 10 5 m 3 .

[0194] The above examples are only for illustrating the technical concept and characteristics of the present disclosure, and the purpose is to enable those skilled in the art to understand the content of the present disclosure and implement it, and cannot limit the protection scope of the present disclosure. Any equivalent changes or modifications made according to the spirit and essence of the present disclosure shall be covered within the protection scope of the present disclosure.

[0195] Figure 7 is a block diagram of a system for determining geological reserves according to an exemplary embodiment of the present disclosure, as shown in Figure 7 The exemplary embodiment of the present disclosure provides a system for determining geological reserves, comprising:

[0196] A generating unit 10 is configured to generate a multi-component hydrocarbon system PT phase diagram through PVT phase simulation calculation;

[0197] A judging unit 20 is configured to determine the gas reservoir type according to the temperature and pressure of the formation in combination with the PT phase diagram;

[0198] An obtaining unit 30 is configured to obtain the corrected black oil PVT property data through phase simulation according to the PT phase diagram;

[0199] A determining unit 40 is configured to determine the original oil saturation according to the original water saturation, the original formation pressure, and the retrograde condensate volume percentage;

[0200] An establishing unit 50 is configured to establish the corresponding material balance relationship under three isothermal pressure drop paths;

[0201] A solving unit 60 is configured to select the corresponding material balance relationship according to the gas reservoir type, solve the selected material balance relationship by using the corrected black oil PVT property data and the original oil saturation, and obtain a solving result;

[0202] A calculating unit 70 is configured to calculate the dynamic gas-bearing geological reserves and the cumulative water influx according to the solving result.

[0203] Specifically, the corrected black oil PVT property data includes four groups of experimental data series: pressure-oil volume coefficient, pressure-gas volume coefficient, pressure-dissolved gas-oil ratio, and pressure-volatile oil-gas ratio.

[0204] Specifically, the determining unit comprises:

[0205] The first obtaining module is configured to obtain the original water saturation through well logging interpretation;

[0206] The second obtaining module is configured to obtain the original formation pressure through formation testing;

[0207] The establishing module is configured to establish a functional relationship between the pressure and the retrograde condensate percentage through a linear interpolation method;

[0208] The substituting module is configured to substitute the original formation pressure into the function to obtain the original oil saturation.

[0209] Specifically, the three isothermal pressure drop paths comprise a pressure drop path I from an unsaturated gas reservoir to an unsaturated gas reservoir, a pressure drop path II from a supersaturated gas reservoir to a supersaturated gas reservoir, and a pressure drop path III from an unsaturated gas reservoir to a supersaturated gas reservoir.

[0210] Specifically, the material balance relationship under the pressure drop path I is:

[0211]

[0212]

[0213]

[0214] In the formula, G i is the gas-bearing dynamic geological reserves; ω is the water invasion replacement coefficient; Δp is the formation pressure difference; C e is the equivalent compressibility; B g is the gas volume coefficient; B gi is the gas volume coefficient under the original formation pressure; G p is the surface cumulative gas production;

[0215] The material balance relationship under the pressure drop path II is:

[0216]

[0217]

[0218]

[0219] In the formula, G i is the gas-bearing dynamic geological reserves; ω is the water invasion replacement coefficient; Δp is the formation pressure difference; λ is the equivalent gas saturation; C e is the equivalent compressibility; B g is the gas volume coefficient; B gi is the gas volume coefficient under the original formation pressure; B o is the oil volume coefficient; Rv is the volatile oil-gas ratio; R s is the solution gas-oil ratio; S wi is the original water saturation; S oi is the original oil saturation; R si is the solution gas-oil ratio at the original formation pressure; B oi is the oil volume factor at the original formation pressure; R vi is the volatile oil-gas ratio at the original formation pressure; G p is the cumulative gas production at the surface; N p is the cumulative oil production at the surface;

[0220] The material balance relationship under pressure drop path III is:

[0221]

[0222]

[0223]

[0224] wherein: G i is the gas-bearing dynamic geological reserves; ω is the water invasion replacement coefficient; Δp is the formation pressure difference; C e is the equivalent compressibility; B g is the gas volume factor; B gi is the gas volume factor at the original formation pressure; B o is the oil volume factor; R v is the volatile oil-gas ratio; R s is the solution gas-oil ratio; R vi is the volatile oil-gas ratio at the original formation pressure; N p is the cumulative oil production at the surface.

[0225] Specifically, the calculation unit comprises:

[0226] a first drawing module configured to draw an x-y data corresponding relationship curve according to the solution result;

[0227] a second drawing module configured to draw a critical slope line passing through the origin according to the x-y data corresponding relationship curve;

[0228] an analysis module configured to perform linear regression analysis on data points above the critical slope line to obtain a slope and an intercept y 截距1 ;

[0229] a first calculation module configured to calculate the gas-bearing dynamic geological reserves according to the slope and to calculate the equivalent compressibility according to the intercept y 截距1 ;

[0230] The second calculation module is configured to draw parallel lines of the first linear regression line in sequence for the data points deviating from the straight line segment, and calculate the corresponding intercept y 截距2 ;

[0231] The determination module is configured to determine the cumulative water influx at the corresponding moment according to the intercept y 截距1 and the intercept y 截距2 .

[0232] Figure 8 is a structural schematic diagram of a device of the present exemplary embodiment. As shown in Figure 8 Corresponding to the method for determining geological reserves provided above, the present disclosure further provides a device. Since the embodiments of the device are similar to the embodiments of the above method, the description is relatively simple, and the relevant parts can be referred to the description of the above method embodiment part. The device described below is only illustrative. The device can include a processor 1, a memory 2, a communication bus (i.e. the above device bus), and a lookup engine. The processor 1 and the memory 2 complete mutual communication through the communication bus, and communicate with the outside through a communication interface. The processor 1 can call the logical instructions in the memory 2 to execute the method for determining geological reserves.

[0233] In addition, the logical instructions in the memory 2 described above can be realized in the form of a software functional unit and sold or used as an independent product. When used, it can be stored in a computer readable storage medium. Based on such understanding, the technical solutions of the present disclosure essentially or the part that contributes to the prior art or part of the technical solutions can be embodied in the form of a software product. The computer software product is stored in a storage medium, and includes a plurality of instructions for causing a computer device (which can be a personal computer, a server, or a network device, etc.) to execute all or part of the steps of the methods of various embodiments of the present disclosure. The aforementioned storage medium includes a storage chip, a U disk, a mobile hard disk, a read-only memory (ROM, Read-Only Memory), a random access memory (RAM, Random Access Memory), a magnetic disk or an optical disk, and various media that can store program codes.

[0234] On the other hand, the present disclosure further provides a processor readable storage medium, and the processor readable storage medium stores a computer program 3. When the computer program 3 is executed by the processor 1, the method for determining geological reserves provided by each of the above embodiments is implemented.

[0235] The processor-readable storage medium can be any available medium or data storage device that the processor 1 can access, including but not limited to a magnetic storage (such as a floppy disk, a hard disk, a magnetic tape, a magneto-optical disk (MO), etc.), an optical storage (such as a CD, a DVD, a BD, a HVD, etc.), and a semiconductor storage (such as a ROM, an EPROM, an EEPROM, a non-volatile memory (NAND FLASH), a solid state disk (SSD)), etc.

[0236] The above is only the preferred embodiment of the present disclosure, and the protection scope of the present disclosure is not limited to the above-mentioned embodiments. Any technical solutions falling within the concept of the present disclosure shall fall within the protection scope of the present disclosure. It should be noted that, for ordinary skilled persons in the art, some improvements and refinements without departing from the principles of the present disclosure shall be considered as the protection scope of the present disclosure.

Claims

1. A method of determining a geological reserve, characterized in that, The method comprises the following steps: a PT phase diagram of a multi-component hydrocarbon system is generated by PVT phase state simulation calculation; a gas reservoir type is determined according to the temperature and pressure of a formation and in combination with the PT phase diagram; corrected black oil PVT attribute data is obtained by phase state simulation according to the PT phase diagram; original oil saturation is determined according to original water saturation, original formation pressure and condensate liquid volume percentage; corresponding material balance relationships under three isothermal pressure drop paths are established; a corresponding material balance relationship is selected according to the gas reservoir type, and the selected material balance relationship is solved by using the corrected black oil PVT attribute data and the original oil saturation to obtain a solving result; gas dynamic geological reserves and cumulative water invasion are calculated according to the solving result.

2. The method of determining a geological reserve according to claim 1, characterized in that, The corrected black oil PVT attribute data comprises four groups of experimental data series: pressure-oil volume coefficient, pressure-gas volume coefficient, pressure-dissolved gas-oil ratio and pressure-volatile oil-gas ratio.

3. The method of determining a geological reserve according to claim 1, characterized in that, The original oil saturation is determined according to the original water saturation, the original formation pressure and the condensate liquid volume percentage, which comprises the following steps: the original water saturation is obtained by well logging interpretation; the original formation pressure is obtained by formation testing; a functional relationship between pressure and condensate liquid percentage is established by a linear interpolation method; the original oil saturation is obtained by substituting the original formation pressure into the function.

4. The method of determining a geological reserve according to claim 1, characterized in that, The three isothermal pressure drop paths comprise a pressure drop path I from an unsaturated gas reservoir to an unsaturated gas reservoir, a pressure drop path II from a supersaturated gas reservoir to a supersaturated gas reservoir and a pressure drop path III from an unsaturated gas reservoir to a supersaturated gas reservoir.

5. The method for determining geological reserves according to claim 4, wherein: the material balance relationship under the pressure drop path I is: In the formula, G i is the gas-bearing dynamic geological reserves; ω is the water displacement coefficient; and Δp is the formation pressure difference. C e B is the equivalent compressibility; B g B is the gas volume factor; B gi B is the gas volume factor at the original reservoir pressure; G p Cumulative gas production to surface; the material balance relationship under the pressure drop path II is: where: G i is the gas dynamic geological reserves; ω is the water displacement coefficient; Δp is the formation pressure difference; λ is the equivalent gas saturation; C e is the equivalent compressibility; B g is the gas volume factor; B gi is the gas volume factor at the original formation pressure; B o is the oil volume factor; R v is the gas-oil ratio; R s is the dissolved gas-oil ratio; S wi is the initial water saturation; S oi is the initial oil saturation; R si is the dissolved gas-oil ratio at the original formation pressure; B oi is the oil volume factor at the original formation pressure; R vi is the gas-oil ratio at the original formation pressure; G p is the surface cumulative gas production; N p is the surface cumulative oil production; the material balance relationship under the pressure drop path III is: where: G i is the gas dynamic geological reserves; ω is the water displacement coefficient; Δp is the formation pressure difference; C e is the equivalent compressibility; B g is the gas volume factor; B gi is the gas volume factor at the original formation pressure; B o is the oil volume factor; R v is the gas-oil ratio; R s is the dissolved gas-oil ratio; R vi is the gas-oil ratio at the original formation pressure; N p is the cumulative oil production at the surface.

6. The method of determining a geological reserve according to claim 5, characterized in that, the gas dynamic geological reserves and the cumulative water invasion are calculated according to the solving result. The gas dynamic geological reserves and the cumulative water invasion are calculated according to the solving result, which comprises the following steps: a x-y data corresponding relationship curve is drawn according to the solving result; a critical slope line passing through the origin is drawn according to the x-y data corresponding relationship curve; Linear regression analysis was performed using data points above the critical slope line to obtain the slope and intercept y 截距1 ; According to the slope, the gas-bearing dynamic geological reserves are calculated, and according to the intercept y 截距1 The equivalent compressibility coefficient is calculated; parallel lines parallel to the first linear regression straight line are drawn for data points deviating from the straight line segment in sequence, calculating the corresponding intercept y 截距2 ; According to the intercept y 截距1 and the intercept y 截距2 determining the cumulative water influx at the respective time.

7. A system for determining a geological reserve, characterized in that, The method comprises the following steps: a generating unit is configured to generate a PT phase diagram of a multi-component hydrocarbon system by PVT phase state simulation calculation; a determining unit is configured to determine a gas reservoir type according to the temperature and pressure of a formation and in combination with the PT phase diagram; an obtaining unit is configured to obtain corrected black oil PVT attribute data according to the PT phase diagram by phase state simulation; a determining unit is configured to determine original oil saturation according to original water saturation, original formation pressure and condensate liquid volume percentage; an establishing unit is configured to establish corresponding material balance relationships under three isothermal pressure drop paths; a solving unit is configured to select a corresponding material balance relationship according to the gas reservoir type, solve the selected material balance relationship by using the corrected black oil PVT attribute data and the original oil saturation, and obtain a solving result; a calculating unit is configured to calculate gas dynamic geological reserves and cumulative water invasion according to the solving result. The corrected black oil PVT attribute data comprises four groups of experimental data series: pressure-oil volume coefficient, pressure-gas volume coefficient, pressure-dissolved gas-oil ratio and pressure-volatile oil-gas ratio. The determining unit comprises: a first obtaining module is configured to obtain original water saturation by well logging interpretation; 8. The system for determining a geological reserve according to claim 7, characterized in that, ​ 9. The system for determining a geological reserve according to claim 7, characterized in that, ​ ​ The second acquisition module is configured to acquire an original formation pressure through formation testing. The establishing module is configured to establish a functional relationship between the pressure and the percentage of retrograde condensate through a linear interpolation method. The substituting module is configured to substitute the original formation pressure into the function to acquire the original oil saturation.

10. The system for determining a geological reserve according to claim 7, characterized in that, The three isothermal pressure drop paths include a pressure drop path I from an unsaturated gas reservoir to an unsaturated gas reservoir, a pressure drop path II from a supersaturated gas reservoir to a supersaturated gas reservoir, and a pressure drop path III from an unsaturated gas reservoir to a supersaturated gas reservoir.

11. The system for determining the geological reserves according to claim 10, characterized in that: The material balance relationship under the pressure drop path I is: In the formula, G i is the gas dynamic geological reserves; ω is the water displacement coefficient; Δp is the formation pressure difference; C e is the equivalent compressibility; B g is the gas volume coefficient; B gi is the gas volume coefficient under the original formation pressure; G p is the cumulative gas production on the ground; The material balance relationship under the pressure drop path II is: where: G i is the gas dynamic geological reserves; ω is the water influx replacement coefficient; Δp is the formation pressure difference; λ is the equivalent gas saturation; C e is the equivalent compressibility; B g is the gas volume factor; B gi is the gas volume factor at the original formation pressure; B o is the oil volume factor; R v is the gas-oil ratio; R s is the solution gas-oil ratio; S wi is the initial water saturation; S oi is the initial oil saturation; R si is the solution gas-oil ratio at the original formation pressure; B oi is the oil volume factor at the original formation pressure; R vi is the gas-oil ratio at the original formation pressure; G p is the surface cumulative gas production; N p is the surface cumulative oil production; The material balance relationship under the pressure drop path III is: where: G i is the gas dynamic geological reserves; ω is the water displacement coefficient; Δp is the formation pressure difference; C e is the equivalent compressibility; B g is the gas volume factor; B gi is the gas volume factor at the original formation pressure; B o is the oil volume factor; R v is the gas-oil ratio; R s is the dissolved gas-oil ratio; R vi is the gas-oil ratio at the original formation pressure; N p is the cumulative surface oil production.

12. The system for determining a geological reserve according to claim 11, characterized in that, The calculation unit Comprises: The first drawing module is configured to draw an x-y data corresponding relationship curve according to the solving result. The second drawing module is configured to draw a critical slope line passing through the origin according to the x-y data corresponding relationship curve. an analysis module for performing a linear regression analysis using the data points above the critical slope line to obtain a slope and an intercept y 截距1 ; The first calculation module is configured to calculate the gas-bearing dynamic geological reserves according to the slope and the intercept y 截距1 calculate the equivalent compressibility coefficient; The second calculation module is configured to draw parallel lines of the first linear regression straight line in sequence for the data points deviating from the straight line segment, and calculate the corresponding intercept y 截距2 ; determining module configured to determine the accumulated water intrusion amount at the corresponding time point according to the intercept y 截距1 and the intercept y 截距2 determining the accumulated water intrusion amount at the corresponding time point.

13. An apparatus, comprising: Comprise: A processor and a memory; The memory is configured to store a computer program, and the processor is configured to call the computer program stored in the memory to execute the method for determining the geological reserves according to any one of claims 1 to 6.

14. A computer-readable storage medium, characterized in that, The computer readable storage medium stores a computer program, and when the computer program is executed by the processor, the processor can execute the method for determining the geological reserves according to any one of claims 1 to 6.

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