A method for predicting steam throughput capacity

Abstract

This invention provides a method for predicting steam huff and puff production capacity, belonging to the field of oil and gas field development. The method includes acquiring reservoir geological parameters and steam huff and puff injection and production parameters; after steam injection, well shut-in is performed, followed by production. The production process after shut-in is divided into n stages; each stage is further divided into steam zone, hot water zone, and cold zone according to temperature changes. Combined with seepage velocity, the average formation pressure, water saturation, and heavy oil viscosity of each stage are iteratively calculated; using the average formation pressure, water saturation, and heavy oil viscosity of each stage, the production capacity of each stage is calculated; the production capacities of the n stages are summed to obtain the production capacity of one steam huff and puff cycle. This method considers the viscosity variation with temperature and seepage velocity during low-velocity heavy oil seepage and can calculate the starting pressure gradient and bottom hole pressure changes during heavy oil production, improving the accuracy of steam huff and puff prediction results.

Description

Technical Field

[0001] This invention belongs to the field of oil and gas field development, and particularly relates to a method for predicting steam injection capacity. Background Technology

[0002] With the continuous development of heavy oil reservoirs in oilfields, the current heavy oil huff and puff production is characterized by "multiple wells with low production and low oil-to-steam ratio." Experiments have been conducted on some inefficient oil wells using hydraulic pumping units to achieve a "long stroke, low stroke" operating system. Results show that steam huff and puff significantly increases production in low-yield, inefficient wells and can achieve cold extraction of heavy oil to some extent; however, the applicable conditions are unclear, and widespread adoption faces difficulties. Under the development orientation of low energy consumption and high efficiency, there is an urgent need to implement methods such as injection stoppage and slow injection in inefficient areas to fully promote increased heavy oil production and efficiency.

[0003] If we can accurately predict the production capacity of low-yield and inefficient wells after the conversion of production systems at different development stages, it will provide a theoretical basis for improving the quality and efficiency of inefficient areas. Summary of the Invention

[0004] To address the problems existing in the prior art, this invention provides a steam injection capacity prediction method. The technical problem this invention aims to solve is how to accurately predict the capacity of low-yield and inefficient wells after switching to a different production system at different development stages.

[0005] To address the aforementioned technical problems, this invention provides a method for predicting steam throughput capacity, comprising the following steps:

[0006] Step S1: Obtain reservoir geological parameters and steam injection / production parameters;

[0007] Step S2: After steam injection, the well is shut down. Production begins after the well shut-down is completed. The production process after the well shut-down is completed is divided into n stages.

[0008] Step S3: Divide each stage into steam zone, hot water zone and cold zone according to temperature changes, and iteratively calculate the average formation pressure, water saturation and heavy oil viscosity of each stage in combination with seepage velocity;

[0009] Step S4: Calculate the production capacity of each stage using the average formation pressure, water saturation, and heavy oil viscosity at each stage;

[0010] Step S5: Sum the capacity of n stages to obtain the capacity of one steam throughput cycle.

[0011] Furthermore, in step S1, the reservoir geological parameters include the original formation pressure, formation permeability, original water saturation, original formation temperature, hydrothermal front temperature, pressure fluctuation amplitude, pressure fluctuation period, and steam injection and production parameters including steam temperature.

[0012] Furthermore, in step S3, the water saturation of the current stage is obtained by using the water saturation of the previous stage.

[0013] Furthermore, in step S3, each stage is divided into a steam zone, a hot water zone, and a cold zone. Based on the principle of energy balance, the heating radius of the steam zone and the heating radius of the hot water zone are calculated. Then, the average oil layer temperature of the steam zone and the average oil layer temperature of the hot water zone are calculated.

[0014] Furthermore, in step S3, the average seepage velocity at the current stage is obtained by using the oil production in the previous stage and the average seepage area of ​​the steam zone, hot water zone and cold zone at the current stage.

[0015] Furthermore, in step S3, the current viscosity of heavy oil is obtained by using the current average temperature of the oil layer in the steam zone, the average temperature of the oil layer in the hot water zone, and the average seepage velocity.

[0016] Furthermore, in step S3, the average formation pressure at the current stage is obtained by using the average oil layer temperature in the steam zone and the average oil layer temperature in the hot water zone.

[0017] Furthermore, the formula for calculating the water saturation in the first stage is as follows:

[0018]

[0019] In the formula: This represents the initial water saturation level. This represents the water saturation level for the first stage. Density of formation water under original conditions, kg·m -3 ; The density of formation water in the first stage is kg·m³. -3 h represents the oil layer thickness; Porosity value; For cumulative water production;

[0020] The water saturation of the (j+1)th stage can be calculated by establishing a mass conservation equation for the water phase: groundwater volume at a certain moment = original groundwater volume + injected water volume - produced water volume.

[0021]

[0022] In the formula: Let be the water saturation level at stage j+1; Let be the formation water density at stage j+1, in kg·m³. -3 h represents the oil layer thickness; This represents the porosity value.

[0023] Furthermore, in step S3, the heating radius of the steam zone in the first stage is obtained using the Marx-Langenheim method, and the calculation formula is as follows:

[0024]

[0025] In the formula: Let be the radius of the steam zone, in meters. The steam injection rate is expressed in kg·s. -1 ; Steam dryness; For latent heat of vapor, J·Kg -1 ; For the heat capacity of the oil reservoir, J·m -3 ·℃ -1 ; Let the oil layer thickness be m; m is the thermal diffusivity of the top and bottom layers. 2 ·h -1 ; The thermal conductivity of the top and bottom layers of rock is given in W·m. -1 ·℃ -1 ; The original formation temperature is ℃; The steam injection time is in hours (h). The steam temperature is in °C. The original formation temperature is ℃;

[0026] The heating radius of the steam zone in the (j+1)th stage is obtained using the Marx-Langenheim method, and the calculation formula is as follows:

[0027]

[0028] Let be the temperature of the steam zone in stage j; j is the stage number, j=1, 2, ..., n.

[0029] Furthermore, in step S3, the heating radius of the hot water zone in the first stage is obtained using the energy conservation equation, and the calculation formula is as follows:

[0030] in:

[0031] , , ,a=( T f -T s ) / (r h -r s ), c=T s ;

[0032] Where r is the radius (m) from a point in the hot water zone to the oil well; T is the radius of the hot water zone, in meters. f A represents the temperature at the leading edge of the hot water zone. , a and c are intermediate quantities with no substantial meaning.

[0033] The heating radius of the hot water zone in the (j+1)th stage is obtained using the energy conservation equation, and the calculation formula is as follows:

[0034] in:

[0035] , , .

[0036] Let A be the temperature of the hot water zone in the j-th stage; , and These are all intermediate quantities and have no substantial meaning.

[0037] Furthermore, in step S3, the formula for calculating the average oil layer temperature in the steam zone of the first stage is as follows:

[0038]

[0039] In the formula: and These are the factors influencing the temperature drop in the steam zone and hot water zone due to radial heat loss, respectively. The average temperature of the oil layer in the first stage of the steam zone;

[0040] The formula for calculating the average temperature of the oil layer in the first stage hot water zone is as follows:

[0041] ;

[0042] in, The average formation temperature of the hot water zone at the start of well simmering:

[0043]

[0044] In the formula: and These are the factors influencing the temperature drop in the steam zone and hot water zone due to vertical heat loss at the top and bottom layers, respectively. The average temperature of the oil layer in the first stage of the hot water zone;

[0045] The formula for calculating the average oil reservoir temperature in the steam zone of stage j+1 is as follows:

[0046]

[0047] in, Let be the average temperature of the oil layer in the steam zone of stage j; The average temperature of the oil reservoir in the steam zone of stage j+1;

[0048] The formula for calculating the average oil reservoir temperature in the hot water zone of stage j+1 is as follows:

[0049] Let be the average temperature of the oil layer in the hot water zone of stage j; The average temperature of the oil layer is the temperature of the hot water zone in stage j+1.

[0050] Furthermore, the formulas for calculating the average seepage velocity in the steam zone, hot water zone, and cold water zone at each stage are as follows:

[0051]

[0052] In the formula: Let be the average seepage velocity in stage j, in cm·s. -1 ; Let be the average seepage cross-sectional area of ​​the steam zone, hot water zone, and cold water zone in stage j, in cm². 2 ; Let J be the oil production in stage j-1. When j=1, Its oil production is zero.

[0053] Furthermore, the formulas for calculating the viscosity of heavy oil at each stage are as follows:

[0054]

[0055] in:

[0056]

[0057]

[0058]

[0059]

[0060] In the formula: , and The heavy oil viscosity in the steam zone, hot water zone, and cold zone are respectively, in mPa·s; The shear rate is 0.001 s. -1 Crude oil viscosity at time, mPa·s; The shear rate is 0.1 s. -1 Crude oil viscosity at time, mPa·s; , where is the shear rate, s -1 ; The average temperature of the oil layer is the temperature of the hot water zone in each stage. The average temperature of the oil layer is the vapor zone temperature at each stage.

[0061] Furthermore, in step S3, the formula for calculating the average formation pressure in the first stage is as follows:

[0062]

[0063] In the formula: The mean formation pressure at each stage; The original formation pressure is expressed in MPa. The mean formation pressure during the first stage at the end of well shut-in, in MPa; The average formation temperature in the steam zone at the end of well steaming, °C; The average formation temperature of the hot water zone at the end of the well-steaming process, in °C; and These are the volume coefficients of formation water and crude oil under reservoir conditions, respectively; The overall compressibility factor is expressed in MPa. -1 ; For the comprehensive thermal expansion coefficient, °C -1 N represents total geological reserves, in m³ 3 ; The original geological reserves of the steam zone, m 3 ; The original geological reserves of the hot water area, m 3 G represents the cumulative steam injection rate (surface water equivalent), in m 3 .

[0064] The formula for calculating the average formation pressure in stage j+1 is as follows:

[0065]

[0066] In the formula: The mean formation pressure for stage j+1 is given in MPa. To accumulate water production, m 3 ; To accumulate oil production, m 3 .

[0067] Furthermore, in step S4, the production capacity of each stage is calculated by considering the start-up pressure gradient under fluctuating conditions. The formula for calculating the start-up pressure gradient under fluctuating conditions is:

[0068]

[0069]

[0070] In the formula, , as well as The starting pressure gradients (MPa·m) for the cold zone, hot water zone, and steam zone under stable conditions are respectively. -1 K represents the formation permeability, 10 -3 μm 2 ; The viscosity of heavy oil in any of the steam zone, hot water zone, and cold zone;

[0071] The formula for calculating the starting pressure gradient under pressure fluctuation conditions is as follows:

[0072]

[0073] In the formula: This refers to the starting pressure gradient when there are bottom hole pressure fluctuations, in MPa·m. -1 A represents the pressure fluctuation amplitude, in MPa; T represents the pressure fluctuation period, in seconds.

[0074] Furthermore, the formula for calculating the starting pressure under fluctuating conditions is as follows:

[0075]

[0076] The formula for calculating the starting pressure when pressure fluctuations exist is as follows:

[0077]

[0078] The starting pressure for the cold zone, hot water zone, and steam zone is given in MPa; e The supply radius is in meters (m).

[0079] Furthermore, when there are fluctuations in bottom hole pressure, the bottom hole pressure changes according to a sinusoidal function as follows:

[0080]

[0081] In the formula: The bottom hole flowing pressure during pressure fluctuations, in MPa; ω is the initial bottom hole pressure, MPa; w is the angular velocity of the wave, rad / s; t is a moment in the wave period.

[0082] Production capacity at each stage is calculated using the average formation pressure, water saturation, and heavy oil viscosity at each stage.

[0083] Furthermore, quasi-steady-state calculations of oil and water production were performed using a well at the center of a circular, closed formation, taking into account the initiation pressure gradient:

[0084]

[0085]

[0086] in:

[0087]

[0088]

[0089]

[0090]

[0091]

[0092]

[0093] In the formula: For oil production, cm 3 ·s -1 ; For water production, cm 3 ·s -1 ; , and The viscosity of formation water in the steam zone, hot water zone, and cold zone are respectively, in mPa·s; , , The relative permeability of the oil phase in the steam zone, hot water zone, and cold zone are respectively. , , These represent the relative permeability of the water phase in the steam zone, hot water zone, and cold zone, respectively; s is the skin coefficient; r w The well diameter is in meters (m). , , , , and These are all intermediate quantities and have no substantial meaning.

[0094] Furthermore, cumulative oil production The calculation formula is as follows:

[0095]

[0096] In the formula, To accumulate oil production;

[0097] Cumulative water production The calculation formula is as follows:

[0098]

[0099] In the formula, This refers to the cumulative water production.

[0100] This invention provides a steam injection capacity prediction method. By dividing the production process into n stages, each stage is further divided into steam zone, hot water zone, and cold zone according to temperature changes. Combining the seepage velocity, the average formation pressure, water saturation, and heavy oil viscosity of each stage are iteratively calculated. Considering the start-up pressure under fluctuating conditions, the capacity of each stage is calculated using the average formation pressure, water saturation, and heavy oil viscosity. The capacities of the n stages are summed to obtain the capacity of a steam injection cycle, thus achieving accurate prediction of the capacity of low-yield and inefficient wells after the conversion of production systems at different development stages.

[0101] This invention provides a steam injection capacity prediction method that considers the viscosity variation with temperature and flow rate during low-speed heavy oil seepage. It can also calculate the starting pressure gradient and bottom hole pressure variation during heavy oil production, taking into account the effects of heavy oil start-up and continuous phase seepage at low speeds. This improves the accuracy of steam injection prediction results and optimizes production parameters. Attached Figure Description

[0102] Figure 1 This is a schematic diagram of the temperature distribution in the formation after steam injection, as described in the steam injection capacity prediction method of this invention.

[0103] Figure 2 The present invention relates to a method for predicting steam injection capacity, which describes the velocity distribution in the formation during the production process; wherein r1 is the high-speed shear rate region and r2 is the low-speed shear rate region.

[0104] Figure 3 This is a heavy oil viscosity curve for a steam injection capacity prediction method according to the present invention.

[0105] Figure 4 This is a schematic diagram of the start-up pressure gradient under fluctuating conditions for the steam throughput capacity prediction method of the present invention.

[0106] Figure 5 This is a schematic diagram of the start-up pressure gradient under pressure fluctuation conditions in the steam throughput capacity prediction method of the present invention.

[0107] Figure 6 This is a schematic diagram showing the daily oil production over time under different formation permeability, calculated using the steam injection capacity prediction method of this invention.

[0108] Figure 7 This is a schematic diagram of the daily oil production variation curves over time under different bottom hole pressure fluctuation amplitudes calculated using the steam injection capacity prediction method of this invention.

[0109] Figure 8 This is a schematic diagram of the daily oil production variation curves over time under different bottom hole pressure fluctuation cycles calculated using the steam injection production prediction method of this invention.

[0110] Figure 9 This is to show the prediction results and actual daily oil production over time using different prediction methods.

[0111] Figure 10 The flowchart illustrates a steam throughput capacity prediction method based on the present invention. Detailed Implementation

[0112] To make the objectives, technical solutions, and advantages of the embodiments of the present invention clearer, the technical solutions of the embodiments of the present invention will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are only some embodiments of the present invention, not all embodiments. Based on the embodiments of the present invention, all other embodiments obtained by those skilled in the art without creative effort are within the scope of protection of the present invention.

[0113] Therefore, the following detailed description of the embodiments of the invention provided in the accompanying drawings is not intended to limit the scope of the claimed invention, but merely to illustrate selected embodiments of the invention. All other embodiments obtained by those skilled in the art based on the embodiments of the invention without inventive effort are within the scope of protection of the invention.

[0114] It should be noted that similar labels and letters in the following figures indicate similar items. Therefore, once an item is defined in one figure, it does not need to be further defined and explained in subsequent figures.

[0115] In this invention, unless otherwise explicitly specified and limited, the terms "installation," "connection," "linking," and "fixing," etc., should be interpreted broadly. For example, they can refer to a fixed connection, a detachable connection, or an integral part; they can refer to a direct connection or an indirect connection through an intermediate medium; they can refer to the internal communication of two components or the interaction between two components. Those skilled in the art can understand the specific meaning of the above terms in this invention according to the specific circumstances.

[0116] To better understand the purpose, structure, and function of this invention, a steam throughput capacity prediction method of this invention will be described in further detail below with reference to the accompanying drawings.

[0117] Example 1:

[0118] Figure 10This invention discloses a method for predicting steam throughput capacity, comprising the following steps:

[0119] Step S1: Obtain reservoir geological parameters and steam injection / production parameters;

[0120] Step S2: After steam injection, the well is shut down. Production begins after the well shut-down is completed. The production process after the well shut-down is completed is divided into n stages.

[0121] Step S3: Divide each stage into steam zone, hot water zone and cold zone according to temperature changes, and iteratively calculate the average formation pressure, water saturation and heavy oil viscosity of each stage in combination with seepage velocity;

[0122] Step S4: Calculate the production capacity of each stage using the average formation pressure, water saturation, and heavy oil viscosity at each stage;

[0123] Step S5: Sum the capacity of n stages to obtain the capacity of one steam throughput cycle.

[0124] Example 2:

[0125] Figure 10 This invention discloses a method for predicting steam throughput capacity, comprising the following steps:

[0126] Step S1: Obtain reservoir geological parameters and steam injection / production parameters;

[0127] Step S2: After steam injection, the well is shut down. Production begins after the well shut-down is completed. The production process after the well shut-down is completed is divided into n stages.

[0128] Step S3: Divide each stage into steam zone, hot water zone and cold zone according to temperature changes, and iteratively calculate the average formation pressure, water saturation and heavy oil viscosity of each stage in combination with seepage velocity;

[0129] Step S4: Calculate the production capacity of each stage using the average formation pressure, water saturation, and heavy oil viscosity at each stage;

[0130] Step S5: Sum the capacity of n stages to obtain the capacity of one steam throughput cycle.

[0131] The difference between this embodiment and the first embodiment is that:

[0132] Based on the principle of volume balance, the average formation pressure, average formation temperature in the steam zone, average formation temperature in the hot water zone, and water saturation are calculated for each stage.

[0133] In step S1, the reservoir geological parameters include the original formation pressure, formation permeability, original water saturation, original formation temperature, hydrothermal front temperature, pressure fluctuation amplitude, and pressure fluctuation period. The steam injection and production parameters include steam temperature.

[0134] like Figure 1 As shown, in step S3, each stage is divided into a steam zone, a hot water zone, and a cold zone. Based on the energy balance principle, the heating radius of the steam zone and the heating radius of the hot water zone are calculated. Then, the average oil layer temperature of the steam zone and the average oil layer temperature of the hot water zone are calculated. Using the oil production of the previous stage and the average seepage area of ​​the current steam zone, hot water zone, and cold zone, the average seepage velocity of the current stage is obtained. Using the average oil layer temperature of the current steam zone, the average oil layer temperature of the hot water zone, and the seepage velocity, the viscosity of the heavy oil is obtained. Using the average oil layer temperature of the current steam zone and the average oil layer temperature of the hot water zone, the average formation pressure of the current stage is obtained. Using the water saturation of the previous stage, the water saturation of the current stage is obtained.

[0135] like Figure 2 As shown, the flow rate is divided into a low-velocity zone and a high-velocity zone.

[0136] The heating radius of the steam zone in the first stage is obtained using the Marx-Langenheim method, and the calculation formula is as follows:

[0137]

[0138] In the formula: Let be the radius of the steam zone, in meters. The steam injection rate is expressed in kg·s. -1 ; Steam dryness; For latent heat of vapor, J·Kg -1 ; For the heat capacity of the oil reservoir, J·m -3 ·℃ -1 ; Let the oil layer thickness be m; m is the thermal diffusivity of the top and bottom layers. 2 ·h -1 ; The thermal conductivity of the top and bottom layers of rock is given in W·m. -1 ·℃ -1 ; The original formation temperature is ℃; The steam injection time is in hours (h). The steam temperature is in °C. The original stratum temperature is ℃.

[0139] The heating radius of the steam zone in the (j+1)th stage is obtained using the Marx-Langenheim method, and the calculation formula is as follows:

[0140]

[0141] T sj Let be the temperature of the steam zone in the j-th stage; j is the stage number, j=1, 2, ..., n;

[0142] The heating radius of the hot water zone in the first stage is obtained using the energy conservation equation, and the calculation formula is as follows:

[0143] in:

[0144] , ,

[0145] a=( T f -T s ) / (r h -r s ), c=T s ;

[0146] Where r is the radius (m) from a point in the hot water zone to the oil well; T is the radius of the hot water zone, in meters. f A represents the temperature at the leading edge of the hot water zone. , a and c are intermediate quantities with no substantial meaning.

[0147] The heating radius of the hot water zone in the (j+1)th stage is obtained using the energy conservation equation, and the calculation formula is as follows:

[0148] in:

[0149] , , .

[0150] Let A be the temperature of the hot water zone in the j-th stage; , and These are all intermediate quantities and have no substantial meaning.

[0151] The formula for calculating the average temperature of the oil reservoir in the first stage of the steam zone is as follows:

[0152]

[0153] In the formula: and These are the factors influencing the temperature drop in the steam zone and hot water zone due to radial heat loss, respectively, and are related to the well-closing time, thermal diffusivity, and heating radius; This represents the average temperature of the oil layer in the steam zone of the first stage.

[0154] The formula for calculating the average temperature of the oil layer in the first stage hot water zone is as follows:

[0155] ;

[0156] in, The average formation temperature of the hot water zone at the start of well simmering:

[0157]

[0158] In the formula: and These are the factors influencing the temperature drop in the steam zone and hot water zone due to vertical heat loss at the top and bottom layers, respectively, and are related to the well-closing time, thermal diffusivity, and oil layer thickness. This represents the average temperature of the oil layer in the first stage of the hot water zone.

[0159] The formula for calculating the average oil reservoir temperature in the steam zone of stage j+1 is as follows:

[0160]

[0161] in, Let be the average temperature of the oil layer in the steam zone of stage j; The average temperature of the oil layer in the steam zone of stage j+1 is denoted as .

[0162] The formula for calculating the average oil reservoir temperature in the hot water zone of stage j+1 is as follows:

[0163]

[0164] Let be the average temperature of the oil layer in the hot water zone of stage j; The average temperature of the oil layer is the temperature of the hot water zone in stage j+1.

[0165] The formula for calculating the average formation pressure in the first stage is as follows:

[0166]

[0167] In the formula: The mean formation pressure at each stage; The original formation pressure is expressed in MPa. The mean formation pressure during the first stage at the end of well shut-in, in MPa; The average formation temperature in the steam zone at the end of well steaming, °C; The average formation temperature of the hot water zone at the end of the well-steaming process, in °C; and These are the volume coefficients of formation water and crude oil under reservoir conditions, respectively; The overall compressibility factor is expressed in MPa. -1 ; For the comprehensive thermal expansion coefficient, °C -1 N represents total geological reserves, in m³ 3 ; The original geological reserves of the steam zone, m 3 ; The original geological reserves of the hot water area, m 3 G represents the cumulative steam injection rate (surface water equivalent), in m 3 .

[0168] The formula for calculating the average formation pressure in stage j+1 is as follows:

[0169]

[0170] In the formula: The mean formation pressure for stage j+1 is given in MPa. To accumulate water production, m 3 ; To accumulate oil production, m 3 .

[0171] The formulas for calculating the average seepage velocity in the steam zone, hot water zone, and cold water zone at each stage are as follows:

[0172]

[0173] In the formula: Let be the average seepage velocity in stage j, in cm·s. -1 ; Let be the average seepage cross-sectional area of ​​the steam zone, hot water zone, and cold water zone in stage j, in cm². 2 ; Let J be the oil production in stage j-1. When j=1, Its oil production is zero.

[0174] like Figure 3 As shown, the viscosity of heavy oil at each stage is calculated using the average seepage velocity, the average oil layer temperature in the steam zone, and the average oil layer temperature in the hot water zone. The calculation formula is as follows:

[0175]

[0176] in:

[0177]

[0178]

[0179]

[0180]

[0181] In the formula: , and The heavy oil viscosity in the steam zone, hot water zone, and cold zone are respectively, in mPa·s; The shear rate is 0.001 s. -1 Crude oil viscosity at time, mPa·s; The shear rate is 0.1 s. -1 Crude oil viscosity at time, mPa·s; , where is the shear rate, s -1 ; A speed greater than 0.1 / s is considered high-speed. The speed is less than 0.1 / s, which is considered a low-speed zone. The average temperature of the oil layer is the temperature of the hot water zone in each stage. The average temperature of the oil layer is the vapor zone temperature at each stage.

[0182] The formula for calculating the water saturation in the first stage is as follows:

[0183]

[0184] In the formula: This represents the initial water saturation level. This represents the water saturation level for the first stage. Density of formation water under original conditions, kg·m -3 ; The density of formation water in the first stage is kg·m³. -3 h represents the oil layer thickness; Porosity value; This refers to the cumulative water production (excluding the current cumulative water production).

[0185] The water saturation of the (j+1)th stage can be calculated by establishing a mass conservation equation for the water phase: groundwater volume at a certain moment = original groundwater volume + injected water volume - produced water volume.

[0186]

[0187] In the formula: Let be the water saturation level at stage j+1; Let be the formation water density at stage j+1, in kg·m³. -3h represents the oil layer thickness; This represents the porosity value.

[0188] Based on the water saturation at a certain moment, and through the relative permeability curve, the relative permeability at that water saturation can be obtained, and the production capacity can be calculated using the permeability.

[0189] The formula for calculating the starting pressure gradient under fluctuating conditions is:

[0190]

[0191]

[0192] In the formula, , as well as The starting pressure gradients (MPa·m) for the cold zone, hot water zone, and steam zone under stable conditions are respectively. -1 K represents the formation permeability, 10 -3 μm 2 ; The viscosity of heavy oil in any of the steam zone, hot water zone, and cold zone;

[0193]

[0194] In the formula: This refers to the starting pressure gradient when there are bottom hole pressure fluctuations, in MPa·m. -1 A represents the pressure fluctuation amplitude, in MPa; T represents the pressure fluctuation period, in seconds.

[0195] like Figure 4 As shown, the formula for calculating the starting pressure under fluctuating conditions is as follows:

[0196]

[0197] like Figure 5 As shown, the formula for calculating the starting pressure when pressure fluctuations exist is as follows:

[0198]

[0199] The starting pressure for the cold zone, hot water zone, and steam zone is given in MPa; e The supply radius is in meters (m).

[0200] When there are fluctuations in bottom hole pressure, the bottom hole pressure changes according to a sinusoidal function as follows:

[0201]

[0202] In the formula: The bottom hole flowing pressure during pressure fluctuations, in MPa; ω is the initial bottom hole pressure, MPa; w is the angular velocity, rad / s; t is a moment in the fluctuation period.

[0203] The production capacity at each stage is calculated using the average formation pressure, water saturation, and heavy oil viscosity. The calculation formula is as follows:

[0204] like Figure 6 , Figure 7 and Figure 8 As shown, the pseudo-steady-state calculation of oil and water production is performed using a well at the center of a circular, closed formation that considers the initiation pressure gradient:

[0205]

[0206]

[0207] in:

[0208]

[0209]

[0210]

[0211]

[0212]

[0213]

[0214] In the formula: For oil production, cm 3 ·s -1 ; For water production, cm 3 ·s -1 ; , and The viscosity of formation water in the steam zone, hot water zone, and cold zone are respectively, in mPa·s; , , These represent the relative permeability of the oil phase in the steam zone, hot water zone, and cold zone, respectively. , , The relative permeability of the water phase in the steam zone, hot water zone, and cold zone are respectively; r w The well diameter is in meters (m). , , , , and These are all intermediate quantities and have no substantial meaning.

[0215] Cumulative oil production The calculation formula is as follows:

[0216]

[0217] Cumulative water production The calculation formula is as follows:

[0218]

[0219] Example 3:

[0220] This invention provides a method for predicting steam injection capacity, which predicts the capacity change within a single injection cycle based on obtained reservoir data. The specific steps include:

[0221] (1) Obtain reservoir geological parameters and steam injection-production parameters (as shown in Table 1 and Table 2);

[0222] (2) After steam injection, the well is shut down and production is carried out after the well shut-down is completed. The production process after the well shut-down is completed is divided into n stages. Each stage is divided into steam zone, hot water zone and cold zone according to temperature change. Based on the principle of energy balance, the heating radius of steam zone and hot water zone is calculated. Combined with the seepage velocity, the formation is divided into low velocity zone and high velocity zone according to the seepage velocity. Then the average formation pressure, water saturation and heavy oil viscosity of each stage are calculated iteratively.

[0223] (3) Using the average formation pressure, water saturation and heavy oil viscosity of each stage, calculate the production capacity of each stage according to the pseudo-steady-state formula of a well in the center of a circular closed formation;

[0224] (4) Sum the capacity of n stages to obtain the capacity of one steam throughput cycle.

[0225] like Figure 9 As shown, this method predicts a cumulative oil production of 674.0t for a single well with steam injection, while the conventional viscosity-temperature model predicts a cumulative oil production of 873.2t. The actual cumulative oil production of a single well with steam injection is 735.7t. Compared with the cumulative oil production predicted by the conventional viscosity-temperature model, the error is 8.4%, and the prediction accuracy is improved by 10.3 percentage points.

[0226] Table 1 Reservoir Geological Parameters

[0227]

[0228] Table 2 Steam Injection and Production Parameters

[0229]

[0230] The above description is merely a preferred embodiment of the present invention and is not intended to limit the invention. Various modifications and variations can be made to the present invention by those skilled in the art. Any modifications, equivalent substitutions, improvements, etc., made within the spirit and principles of the present invention are included within the scope of protection of the present invention.

Claims

1. A method of predicting the performance of a steam soak, characterized by, The method comprises the following steps: Step S1: obtaining reservoir geological parameters and steam injection-production parameters; Step S2: after steam injection, soaking is carried out, and after the soaking is completed, production is carried out, and the production process after the soaking is completed is divided into n stages; Step S3: each stage is divided into a steam zone, a hot water zone and a cold zone according to temperature changes, and combined with seepage velocity, average formation pressure, water saturation and heavy oil viscosity of each stage are iteratively calculated; In the step S3, the water saturation of the present stage is obtained by using the water saturation of the last stage; In the step S3, the steam zone, the hot water zone and the cold zone of each stage are divided, and according to the energy balance principle, the heating radius of the steam zone and the heating radius of the hot water zone are obtained, and then the average oil layer temperature of the steam zone and the average oil layer temperature of the hot water zone are obtained; In the step S3, the average seepage velocity of the present stage is obtained by using the oil production of the last stage and the average seepage area of the steam zone, the hot water zone and the cold zone of the present stage; In the step S3, the heavy oil viscosity of the present stage is obtained by using the average oil layer temperature of the steam zone, the average oil layer temperature of the hot water zone and the average seepage velocity of the present stage; In the step S3, the average formation pressure of the present stage is obtained by using the average oil layer temperature of the steam zone and the average oil layer temperature of the hot water zone of the present stage; The water saturation calculation formula of the first stage is as follows: wherein: is the initial water saturation; is the water saturation at the first stage; is the formation water density at the initial condition, kg m -3 ; is the formation water density at the first stage, kg m -3 ; h is the oil layer thickness; is the porosity value; is the cumulative water production; is the cumulative steam injection; The water saturation of the j+1 stage is obtained by establishing a mass conservation equation for the water phase, and the underground water amount at a certain time = original underground water amount + injected water amount - produced water amount, and the water saturation of the hot zone in each production stage can be obtained: wherein: Sj+1is the water saturation of the j+1st stage; ρj+1is the formation water density of the j+1st stage, kg·m -3 h is the oil layer thickness; is the porosity value; In the step S3, the heating radius of the steam zone of the first stage is obtained by Marx-Langenheim method, and the calculation formula is as follows: where: Rvis the steam zone radius, m; vis the steam injection rate, kg s -1 ; vis the steam quality; vis the steam latent heat, J Kg -1 ; vis the oil formation heat capacity, J m -3 ·°C -1 ; vis the oil formation thickness, m; vis the top and bottom formation thermal diffusivity, m2 h -1 ; vis the top and bottom formation rock thermal conductivity, W m -1 ·°C -1 ; vis the initial formation temperature, °C; vis the steam injection time, h; vis the steam temperature, °C; The heating radius of the steam zone of the j+1 stage is obtained by Marx-Langenheim method, and the calculation formula is as follows: Tj is the temperature of the vapor zone for the jth stage; j is the stage number, j = 1, 2,..., n; In the step S3, the heating radius of the first-stage hot water zone is calculated by an energy conservation equation, and the calculation formula is as follows: wherein: , , a = (Tf - Ts) / (rh - rs), c = Ts; wherein r is the radius from a point in the hot water zone to the oil well, m; R is the radius of the hot water zone, m; Tf is the temperature of the front of the hot water zone; A 、 , a and c are intermediate quantities and have no substantial meaning; The heating radius of the hot water zone in the j+1th stage is calculated by an energy conservation equation, and the calculation formula is as follows: wherein: ， ， ； Tj is the temperature of the hot water zone for the jth stage; A , and are intermediate quantities without substantial meaning; In the step S3, the calculation formula of the average oil layer temperature of the steam zone of the first stage is as follows: wherein: and are the impact factors of the temperature drop in the steam zone and hot water zone, respectively, caused by the radial heat loss; is the average reservoir temperature of the steam zone in the first stage; The calculation formula of the average oil layer temperature of the hot water zone of the first stage is as follows: ； wherein Tavg is the average formation temperature of the hot water zone at the beginning of the soak wherein: and are the impact factors of the temperature drop in the steam zone and the hot water zone, respectively, caused by the vertical top and bottom layer heat loss; is the average reservoir temperature of the hot water zone in the first stage. The calculation formula of the average oil layer temperature of the steam zone of the j+1 stage is as follows: wherein, Tj is the oil formation average temperature of the jth stage of steam zone; Tj+1 is the oil formation average temperature of the j+1th stage of steam zone; The calculation formula of the average oil layer temperature of the hot water zone of the j+1 stage is as follows: the average temperature of the oil formation for the hot water zone of the jth stage; the average temperature of the oil formation for the hot water zone of the j+1th stage; The average seepage velocity calculation formula of the steam zone, the hot water zone and the cold water zone of each stage is as follows: wherein: Vj is the average flow velocity of the jth stage, cm s -1 ; Aji is the average flow cross-sectional area of the steam zone, hot water zone, and cold water zone of the jth stage, cm 2 ; Qj-1 is the oil production of the j-1th stage, when j = 1, Qj is zero. The heavy oil viscosity calculation formula of each stage is as follows: In the step S4, the productivity of each stage is calculated by using the average formation pressure, water saturation and heavy oil viscosity of each stage; In the formula: , and are the viscosities of the thick oil in the steam zone, hot water zone and cold zone, respectively, mPa·s; is the viscosity of the crude oil at a shear rate of 0.001 s -1 , mPa·s; is the viscosity of the crude oil at a shear rate of 0.1 s -1 , mPa·s; is the shear rate, s -1 ; is the average temperature of the oil layer in the hot water zone of each stage; is the average temperature of the oil layer in the steam zone of each stage; In the step S5, the productivities of the n stages are summed to obtain the productivity of a steam stimulation cycle. In the step S1, the reservoir geological parameters include original formation pressure, formation permeability, original water saturation, original formation temperature, hot water zone front temperature, pressure fluctuation amplitude, pressure fluctuation period, and the steam injection-production parameters include steam temperature.

2. The cyclic steam stimulation productivity prediction method of claim 1, wherein, In the step S3, the calculation formula of the average formation pressure of the first stage is as follows:

3. The cyclic steam stimulation productivity prediction method of claim 1, wherein, The calculation formula of the average formation pressure of the j+1 stage is as follows: wherein: P0is the initial formation pressure, MPa; P1is the average formation pressure of the first stage at the end of the soak, MPa; T1is the average formation temperature of the steam zone at the end of the soak, °C; T2is the average formation temperature of the hot water zone at the end of the soak, °C; and Bfand B0are the formation water and oil volume factors, respectively, under reservoir conditions; B is the overall compressibility, MPa -1 ; B is the overall thermal expansion coefficient, °C -1 ; N is the total geological reserves, m 3 ; N0is the initial geological reserves of the steam zone, m 3 ; N0is the initial geological reserves of the hot water zone, m 3 ; G is the cumulative steam injection, m 3 ; The calculation formula of the starting pressure gradient under the condition of pressure fluctuation is as follows: In the formula: Pj+1is the average formation pressure of the j+1th stage, MPa; Qw is the cumulative water production, m3; Qo is the cumulative oil production, m 3 .

4. The cyclic steam stimulation productivity prediction method of claim 3, wherein, In step S4, the deliverability of each stage is calculated by considering the threshold pressure gradient under fluctuation condition or not. The formula of the threshold pressure gradient under fluctuation condition is as follows: wherein, , and are the start-up pressure gradients of the cold zone, the hot water zone and the steam zone respectively under the condition of no fluctuation, MPa·m -1 ; K is the formation permeability, 10 -3 μm 2 ; is the viscosity of the heavy oil in any of the steam zone, the hot water zone and the cold zone. The calculation formula of the starting pressure under the condition of no fluctuation is as follows: wherein: is the threshold pressure gradient in the presence of bottom hole pressure fluctuations, MPa-m -1 ; A is the pressure fluctuation amplitude, MPa; T is the pressure fluctuation period, s.

5. The cyclic steam stimulation productivity prediction method of claim 4, wherein, ​ The formula for calculating the threshold pressure in the presence of pressure fluctuations is as follows: Pc is the start pressure for the cold zone, the hot water zone, and the steam zone, MPa; re is the supply radius, m.

6. The cyclic steam stimulation productivity prediction method of claim 5, wherein, When there are fluctuations in the bottom hole pressure, the bottom hole pressure changes according to the sine function and is expressed as: wherein: Pw is the wellbore pressure at the time of the pressure fluctuation, MPa; P0is the initial wellbore pressure, MPa; w is the angular velocity of the fluctuation, rad / s; t is the time at a certain moment in the fluctuation period.

7. The cyclic steam stimulation productivity prediction method of claim 6, wherein, The pseudo-steady-state calculation of oil and water production from a single well in the center of a circular closed formation considering the threshold pressure gradient is as follows: where: In the formula: is the oil production rate, cm 3 ·s -1 ; is the water production rate, cm 3 ·s -1 ; , and are the formation water viscosities of the steam zone, hot water zone and cold zone, respectively, mPa·s; , , are the relative permeabilities of the oil phase of the steam zone, hot water zone and cold zone, respectively; , , are the relative permeabilities of the water phase of the steam zone, hot water zone and cold zone, respectively; s is the skin factor; r w is the wellbore diameter, m; , , , , and are all intermediate quantities and have no substantial meaning; is the average bottom hole pressure.

8. The cyclic steam stimulation productivity prediction method of claim 7, wherein, Cumulative oil production The calculation formula is as follows: In the formula, is the cumulative oil production; Cumulative water production The calculation formula is as follows: In the formula, is the cumulative water production.

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