A method for quantitatively determining effective producing pressure difference of steam stimulation in thickened oil reservoir

Abstract

The present application provides a kind of method for quantitatively determining effective production pressure difference of steam stimulation of thickened oil reservoir, first collect the static data of basic parameters of geological reservoir of target block, then obtain the relationship between threshold pressure gradient and mobility according to the experimental data of target area threshold pressure gradient;Again, according to the situation of threshold pressure gradient, the formation of steam injection is divided into four different percolation regions;The pressure drop of four different percolation regions is calculated respectively, and the pressure drop curve diagram of different percolation regions is drawn, according to the calculated data, the actual pressure gradient corresponding to region three and region four is compared with the threshold pressure gradient, to determine the supply pressure;According to the pressure distribution of effective percolation area, the effective production pressure difference of steam stimulation of thickened oil reservoir is calculated.The beneficial effects of the present application are that the production pressure difference determined by the scheme in the present application makes the actual formation percolation of steam stimulation process more accurate, and has strong operability, which has important significance for the design of steam stimulation scheme of thickened oil reservoir and the optimization of injection-production parameters.

Description

Technical Field

[0001] This invention relates to the field of heavy oil development technology, and more specifically to a method for quantitatively determining the effective production pressure differential of steam huff and puff in heavy oil reservoirs. Background Technology

[0002] Currently, the commonly used method for determining the production pressure differential during heavy oil steam huff and puff is consistent with the calculation method for conventional cold production: production pressure differential = formation pressure - bottom hole flowing pressure. However, because the starting pressure gradient of heavy oil in different formation regions varies significantly with temperature during thermal production huff and puff, this method fails to account for the differences in seepage resistance in different regions after steam huff and puff, resulting in a large discrepancy between the obtained production pressure differential value and the actual formation pressure differential. Currently, there is no mature technical solution for quantitatively determining the effective production pressure differential of heavy oil reservoir steam huff and puff. Summary of the Invention

[0003] This invention overcomes the shortcomings of the prior art and provides a method for quantitatively determining the effective production pressure differential of steam huff and puff in heavy oil reservoirs.

[0004] The objective of this invention is achieved through the following technical solution.

[0005] A method for quantitatively determining the effective production pressure differential during steam huff and puff in heavy oil reservoirs includes the following steps:

[0006] S1. Collect static data on basic geological reservoir parameters of the target block;

[0007] S2. Based on the experimental data of the starting pressure gradient in the target area, obtain the relationship between the starting pressure gradient and the flow rate;

[0008] S3. Based on the starting pressure gradient, the formation to which steam is injected is divided into four different seepage zones: Zone 1 is the high-temperature heating zone, Zone 2 is the effective heating zone, Zone 3 is the heating transition zone, and Zone 4 is the unheated zone.

[0009] S4, Set crude oil viscosity μ o1 μ is a constant value o1 =C1, with the starting pressure gradient G1 being a constant value G1=0, calculate the pressure drop in the high-temperature heating zone;

[0010] S5, Set crude oil viscosity μ o2 The change value μ o2 =f1(T), the starting pressure gradient G2 is a constant value G2=0, calculate the pressure drop of the effective heating zone;

[0011] S6, Set crude oil viscosity μ o3 The change value μ o3 =f2(T), the starting pressure gradient G3 is the change value G3 = f3(T), calculate the pressure drop in the heating transition zone;

[0012] S7, Set crude oil viscosity μ o4 constant value (μ) o4 =C2, the starting pressure gradient G4 is a constant value (G4=C4), calculate the pressure drop in the unheated zone;

[0013] S8. Draw pressure drop curves for different seepage zones, with the distance R from the wellbore as the abscissa and the formation pressure p as the ordinate, and plot the relationship between reservoir pressure p and wellbore distance R.

[0014] S9. Compare the actual pressure gradients and starting pressure gradients corresponding to Region 3 and Region 4 to determine the supply pressure.

[0015] Determine the supply pressure by comparing the pressure gradients in regions three and four with the starting pressure gradient;

[0016] S10. Calculate the effective production pressure difference of steam huff and puff in heavy oil reservoirs based on the pressure distribution in the effective seepage zone.

[0017] Step S2 involves conducting a startup pressure gradient experiment using crude oil samples and cores from the target area. The startup pressure gradients at different temperatures and permeabilities are recorded, and the critical temperature for the existence of the startup pressure gradient is obtained. The obtained data is then substituted into the following formula to establish the relationship between the startup pressure gradient and the mobility.

[0018] G = 0.1854e -0.3048(K / μ)

[0019] In the formula, μ o ρ represents the crude oil viscosity under formation conditions, in mPa·s; K represents the absolute permeability of the formation, in mD.

[0020] The mathematical models for the temperature and pressure distribution established in each region of S3 are as follows:

[0021] Region 1, R≤R s T = T s ;

[0022] Region 2, R s <R≤R h1 T s <T≤T h ;

[0023] Region 3, R h1 <R≤R h2 T h <T≤T r ;

[0024] Region 4, R>R h2 T = T r .

[0025] Among them, the formation temperature distribution characteristics of each region, R s R represents the radius of the leading edge of the steam chamber. h1 R is the radius of the leading edge of the effective heating zone. h2 The location of the leading edge of the heating transition zone, T s T represents the temperature of the steam chamber. h T is the inflection point temperature of rheology. r This represents the original formation temperature.

[0026] In S4, the formula for calculating the pressure drop in the high-temperature heating zone is:

[0027]

[0028]

[0029] In the formula, Δp 1i Let q be the pressure drop in region i, in MPa; si Let m be the formation flow rate in the i-th segment. 3 / ks;μ o1 K represents the fluid viscosity in region 1, in mPa·s; K represents the absolute permeability of the formation, in mD; K roc1 The relative permeability of the region is mD; h is the oil layer thickness, m; L i R is the length of the i-th horizontal section of the wellbore, in meters; δ is the eccentricity of the horizontal well, in meters; w Where a is the radius of the wellbore, in meters; a 1i Let be the pressure conductivity coefficient of the i-th segment in region 1, a decimal.

[0030] In S5, the formula for calculating the pressure drop in the effective heating zone is:

[0031]

[0032]

[0033] log 10 (μ o2 ) = 10.3935 - 4.0671 log 10 (T)(R 2 =0.9954)

[0034] In the formula, Δp 2i Let q be the pressure drop in region 2 of segment i, in MPa; si Let m be the flow rate of the second formation in the i-th segment. 3 / ks;μ o2 Here is the fluid viscosity in region two, in mPa·s; K. roc2 Let mD be the relative permeability of region two; a 2i Let be the pressure conductivity coefficient of the i-th segment in region two, a decimal.

[0035] In S6, the formula for calculating the pressure drop in the heating transition zone is,

[0036]

[0037]

[0038] where, p 3i is the formation pressure of the i-th section of zone three, MPa; q hi2 is the formation flow rate of the i-th section of zone three, m 3 / d; μ o3 is the fluid viscosity of zone three, mPa·s; K roc3 is the oil phase relative permeability of zone three; a 3i is the pressure transmissibility coefficient of the i-th section of zone three, a decimal.

[0039] In S7, the formula for calculating the pressure drop in the unheated zone is,

[0040]

[0041]

[0042] where, p 4i is the formation pressure of the i-th section of zone four, MPa; C4 is the formation pressure gradient value of the i-th section of zone four, MPa; q ei is the formation flow rate of the i-th section of zone four, m 3 / d; μ e is the fluid viscosity of the i-th section of zone four, mPa·s; K roc4 is the oil phase relative permeability of the i-th section of zone four; a 4i is the pressure transmissibility coefficient of the i-th section of zone four, a decimal.

[0043] In S9, the method for determining the supply pressure is:

[0044] When ΔP / L<G3, the supply pressure p e =p3;

[0045] When G3≦ΔP / L≦G4, the supply pressure p e =p4.

[0046] In S10, the method for calculating the effective production pressure difference of cyclic steam stimulation in heavy oil reservoirs based on the pressure distribution of the effective seepage zone is:

[0047] When ΔP / L<G3, the effective pressure difference calculation formula is,

[0048] Δp 有效 =p3-p wf

[0049] When G3≦ΔP / L≦G4, the effective pressure difference calculation formula is:

[0050] Δp 有效 =p4-p wf .

[0051] The beneficial effects of this invention are as follows:

[0052] 1. The formation after steam injection is divided into four different seepage zones, namely, a high-temperature heating zone, an effective heating zone, a heating transition zone, and an unheated zone. This is more in line with reality than the existing technology that divides the seepage zone into two zones: a heating zone and an unheated zone.

[0053] 2. The starting pressure gradient of different seepage zones is described differently, providing a more detailed description of the seepage characteristics of the steam huff and puff process in different zones;

[0054] 3. By considering the difference between the starting pressure gradient and the actual pressure gradient of heavy oil in different seepage zones, the pressure drop variation pattern in different zones can be determined.

[0055] The production pressure differential determined by the scheme in this invention provides a more accurate description of the actual formation seepage during the steam huff and puff process, and is highly operable. This is of great significance for the design of steam huff and puff schemes and the optimization of injection and production parameters in heavy oil reservoirs. Attached Figure Description

[0056] Figure 1 This is a flowchart of the present invention;

[0057] Figure 2 These are the start-up pressure gradient curves under different temperature conditions in the heavy oil field in Example 1;

[0058] Figure 3 This is a schematic diagram of dividing the formation after steam injection into four different seepage zones in Example 1;

[0059] Figure 4 This is a graph showing the relationship between crude oil viscosity and temperature in Example 1;

[0060] Figure 5 This refers to the pressure curves plotted for different seepage zones in Example 1;

[0061] Figure 6 This is a schematic diagram illustrating the determination of supply pressure in different seepage zones in Example 1;

[0062] Figure 7 This is a pressure curve diagram of different seepage zones in the M heavy oil reservoir in Example 2;

[0063] Figure 8 This is a schematic diagram of determining the supply pressure of different seepage zones in the M heavy oil reservoir in Example 2. Detailed Implementation

[0064] The technical solution of the present invention will be further described below through specific embodiments.

[0065] Example 1

[0066] like Figure 1 As shown, this embodiment takes a typical heavy oil reservoir (L) as an example.

[0067] S1. Collect static data on basic geological reservoir parameters of the target block. The main data collected are shown in Table 1.

[0068] Table 1 Typical Basic Data of L Heavy Oil Field

[0069]

[0070] S2. Based on the experimental data of the starting pressure gradient in the target area, the relationship between the starting pressure gradient and the mobility was obtained. Starting pressure gradient tests were conducted using crude oil samples and cores from the target area of ​​the L oilfield. The starting pressure gradients of cores at different temperatures and permeabilities were recorded, and the critical temperature value for the existence of the starting pressure gradient was obtained.

[0071] The flow characteristics of heavy oil in porous media are different from those of conventional crude oil. There is a starting pressure gradient, that is, heavy oil only begins to flow when the displacement pressure gradient exceeds the starting pressure gradient.

[0072] The starting pressure gradient and mobility are related as follows:

[0073] G = 0.1854e -0.3048(K / μ) (1)

[0074] In the formula, μ o ρ represents the crude oil viscosity under formation conditions, in mPa·s; K represents the absolute permeability of the formation, in mD.

[0075] like Figure 2 As shown, this embodiment takes a typical heavy oil reservoir, L, as an example. The average formation permeability is 2008 mD, and the critical temperature for the existence of the starting pressure gradient is 100℃. The relationship between the starting pressure gradient and mobility in the typical heavy oil reservoir L is obtained as follows:

[0076] G = 0.1854e -0.3048(2008 / μ) (2)

[0077] S3. Based on the starting pressure gradient, the formation for steam injection is divided into four different seepage zones.

[0078] The formation after steam injection was divided into four seepage zones based on different seepage resistances:

[0079] Zone 1 is a high-temperature heating zone (G=0, where crude oil can flow naturally).

[0080] Zone 2 is the effective heating zone (G=0, crude oil can flow naturally).

[0081] Region 3 is the heating transition zone (G≠0, but the value is relatively small).

[0082] Region 4 is the unheated area (G≠0, but the value is relatively large).

[0083] like Figure 3 As shown, the original formation pressure P is at the distal end of the formation. i The near-bottom-hole flowing pressure P is near the formation. wf .

[0084] S4, Set crude oil viscosity μ o1 μ is a constant value o1 =C1, the starting pressure gradient G1 is a constant value G1=0, calculate the pressure drop in the high-temperature heating zone.

[0085] Under steady-flow conditions, the solution for the formation pressure supplied by the i-th section of the horizontal wellbore is:

[0086]

[0087]

[0088] In the formula, Δp 1i Let q be the pressure drop in region i, in MPa; si Let m be the formation flow rate in the i-th segment. 3 / ks;μ o1 K represents the fluid viscosity in region 1, in mPa·s; K represents the absolute permeability of the formation, in mD; K roc1 The relative permeability of the region is mD; h is the oil layer thickness, m; L i R is the length of the i-th horizontal section of the wellbore, in meters; δ is the eccentricity of the horizontal well, in meters; w Where a is the radius of the wellbore, in meters; a 1i Let be the pressure conductivity coefficient of the i-th segment in region 1, a decimal.

[0089] S5, Set crude oil viscosity μ o2 The change value μ o2 =f1(T), the starting pressure gradient G2 is a constant value (G2=0), calculate the pressure drop of the effective heating zone.

[0090] Under steady-flow conditions, the solution for the formation pressure supplied by the i-th section of the horizontal wellbore is:

[0091]

[0092]

[0093] like Figure 4 As shown, the relationship between crude oil viscosity and temperature can be obtained by fitting the viscosity-temperature data:

[0094] log 10 (μ o ) = 10.3935 - 4.0671 log 10 (T)(R 2 =0.9954) (7)

[0095] In the formula, Δp 2i Let q be the pressure drop in region 2 of segment i, in MPa; si Let m be the flow rate of the second formation in the i-th segment. 3 / ks;μ o2 Here is the fluid viscosity in region two, in mPa·s; K. roc2 Let mD be the relative permeability of region two; a 2i Let be the pressure conductivity coefficient of the i-th segment in region two, a decimal.

[0096] S6, Set crude oil viscosity μ o3 The change value μ o3 =f2(T), the starting pressure gradient G3 is the change value G3 = f3(T), calculate the pressure drop in the heating transition zone.

[0097] For region 3, under stable seepage conditions, the solution for the formation pressure produced by the horizontal wellbore in the i-th segment, considering the initiation pressure gradient, is:

[0098]

[0099]

[0100] In the formula, p 3i Let q be the formation pressure in region 3 of segment i, in MPa; hi2 Let m be the flow rate of the three formations in the i-th segment. 3 / d;μ o3 The viscosity of the fluid in region three is given in mPa·s; K. roc3 The relative permeability of the three oil phases in the region; a 3i Let be the three-dimensional pressure coefficient of the i-th segment, a decimal.

[0101] S7, Set crude oil viscosity μ o4 μ is a constant value o4 =C2, the starting pressure gradient G4 is a constant value (G4=C4), calculate the pressure drop in the unheated zone.

[0102] For region four, under stable seepage conditions, the solution for the formation pressure produced by the inrush and outflow of the i-th segment of the horizontal wellbore, considering the initiation pressure gradient, is:

[0103]

[0104]

[0105] In the formula, p 4i is the formation pressure of the i-th section of Zone Four, in MPa; C4 is the formation pressure gradient value of the i-th section of Zone Four, in MPa; q ei is the formation flow rate of the i-th section of Zone Four, in m 3 / d; μ e is the fluid viscosity of the i-th section of Zone Four, in mPa·s; K roc4 is the oil-phase relative permeability of the i-th section of Zone Four; a 4i is the pressure diffusivity coefficient of the i-th section of Zone Four, as a decimal.

[0106] S8. Draw the pressure drop curves of different seepage zones.

[0107] As shown in Figure 5 , taking the distance R from the wellbore as the abscissa and the formation pressure p as the ordinate, draw the relationship chart of reservoir pressure p versus wellbore distance R.

[0108] S9. Compare the pressure gradients and starting pressure gradients of Zone Three and Zone Four to determine the supply pressure. Calculate the actual pressure gradient (ΔP / L) of Seepage Zone Three, and compare it with the starting pressure gradient G3 of Seepage Zone Three.

[0109] As shown in Figure 6 , if ΔP / L<G3 (actual pressure gradient < starting pressure gradient of Zone Three), Zone Three cannot be effectively produced, and at this time the supply pressure p e =p3.

[0110] If G3≦ΔP / L≦G4 (starting pressure gradient of Zone Three < actual pressure gradient ≦ starting pressure gradient of Zone Four), Zone Three can be fully and effectively produced, and at this time the supply pressure p e =p4.

[0111] S10. Calculate the effective production pressure differential for cyclic steam stimulation in heavy oil reservoirs based on the pressure distribution in the effective seepage zone.

[0112] If ΔP / L<G3, the effective pressure differential calculation formula is:

[0113] Δp 有效 =p3-p wf (13)

[0114] If G3≦ΔP / L≦G4, the effective pressure differential calculation formula is:

[0115] Δp 有效 =p4-p wf(14)

[0116] Example 2

[0117] This embodiment uses basic parameters of a certain reservoir to determine the effective production pressure differential for steam huff and puff in heavy oil reservoirs. The basic parameters are: average permeability of 2460 × 10⁻⁶. -3 μm 2 The formation conditions are as follows: crude oil viscosity is 2909 mPa·s, and original formation pressure is 15.5 MPa.

[0118] This invention provides a method for quantitatively determining the effective production pressure differential during steam huff and puff in heavy oil reservoirs, comprising:

[0119] S1. Collect static data on the basic geological parameters of the target block's oil reservoirs.

[0120] Collect basic data such as formation permeability and degassed crude oil viscosity-temperature curves for the target block M heavy oil reservoir. See Table 2 for specific data.

[0121] Table 2 Typical Basic Data of M Heavy Oil Field

[0122]

[0123] S2. Based on the experimental data of the starting pressure gradient in the target area, the relationship between the starting pressure gradient and the flow rate is obtained.

[0124] Starting pressure gradient tests were conducted using crude oil samples and cores from the target area of ​​the M oilfield. The starting pressure gradients of cores at different temperatures and permeabilities were recorded, and the critical temperature values ​​for the existence of the starting pressure gradient were obtained.

[0125] The flow characteristics of heavy oil in porous media are different from those of conventional crude oil. There is a starting pressure gradient, that is, heavy oil only begins to flow when the displacement pressure gradient exceeds the starting pressure gradient.

[0126] The starting pressure gradient and mobility are related as follows:

[0127] G = 0.1854e -0.3048(K / μ) (1)

[0128] In the formula, μ o ρ represents the crude oil viscosity under formation conditions, in mPa·s; K represents the absolute permeability of the formation, in mD.

[0129] Taking the typical heavy oil reservoir M in this embodiment as an example, the average formation permeability is 2008 mD, and the critical temperature for the existence of the starting pressure gradient is 100℃. The relationship between the starting pressure gradient and mobility in the typical heavy oil reservoir M can be obtained as follows:

[0130] G = 0.1854e -0.3048(2008 / μ) (2)

[0131] S3. Based on the starting pressure gradient, the formation for steam injection is divided into four different seepage zones.

[0132] The formation after steam injection was divided into four seepage zones based on different seepage resistances:

[0133] Zone 1 is a high-temperature heating zone (G=0, where crude oil can flow naturally).

[0134] Zone 2 is the effective heating zone (G=0, crude oil can flow naturally).

[0135] Region 3 is the heating transition zone (G≠0, but the value is relatively small).

[0136] Region 4 is the unheated area (G≠0, but the value is relatively large).

[0137] like Figure 7 As shown, the original formation pressure P is at the distal end of the formation. i The near-bottom-hole flowing pressure P is near the formation. wf .

[0138] S4, Set crude oil viscosity μ o1 μ is a constant value o1 =C1, the starting pressure gradient G1 is a constant value G1=0, calculate the pressure drop in the high-temperature heating zone.

[0139] Under steady-flow conditions, the solution for the formation pressure supplied by the i-th section of the horizontal wellbore is:

[0140]

[0141]

[0142] In the formula, Δp 1i Let q be the pressure drop in region i, in MPa; si Let m be the formation flow rate in the i-th segment. 3 / ks;μ o1 K represents the fluid viscosity in region 1, in mPa·s; K represents the absolute permeability of the formation, in mD; K roc1 The relative permeability of the region is mD; h is the oil layer thickness, m; L i R is the length of the i-th horizontal section of the wellbore, in meters; δ is the eccentricity of the horizontal well, in meters; w Where a is the radius of the wellbore, in meters; a 1i Let be the pressure conductivity coefficient of the i-th segment in region 1, a decimal.

[0143] S5, Set crude oil viscosity μ o2 The change value μ o2 =f1(T), the starting pressure gradient G2 is a constant value (G2=0), calculate the pressure drop of the effective heating zone.

[0144] Under steady-flow conditions, the solution for the formation pressure supplied by the i-th section of the horizontal wellbore is:

[0145]

[0146]

[0147] Based on the viscosity-temperature data of reservoir M, the relationship between crude oil viscosity and temperature can be fitted to obtain the following formula:

[0148] log 10 (μ o ) = 10.3935 - 4.0671 log 10 (T)(R 2 =0.9954) (7)

[0149] In the formula, Δp 2i Let q be the pressure drop in region 2 of segment i, in MPa; si Let m be the flow rate of the second formation in the i-th segment. 3 / ks;μ o2 Here is the fluid viscosity in region two, in mPa·s; K. roc2 Let mD be the relative permeability of region two; a 2i Let be the pressure conductivity coefficient of the i-th segment in region two, a decimal.

[0150] S6, Set crude oil viscosity μ o3 The change value μ o3 =f2(T), the starting pressure gradient G3 is the change value G3 = f3(T), calculate the pressure drop in the heating transition zone.

[0151] For region 3, under stable seepage conditions, the solution for the formation pressure produced by the horizontal wellbore in the i-th segment, considering the initiation pressure gradient, is:

[0152]

[0153]

[0154] In the formula, p 3i Let q be the formation pressure in region 3 of segment i, in MPa; hi2 Let m be the flow rate of the three formations in the i-th segment. 3 / d;μ o3 The viscosity of the fluid in region three is given in mPa·s; K. roc3 The relative permeability of the three oil phases in the region; a 3i Let be the three-dimensional pressure coefficient of the i-th segment, a decimal.

[0155] S7, Set crude oil viscosity μ o4 μ is a constant valueo4 =C2, the threshold pressure gradient G4 is a constant value (G4=C4), and the pressure drop of the unheated zone is calculated.

[0156] For Zone 4, under steady seepage conditions, the formation pressure solution for huff and puff production in the i-th horizontal well section considering the threshold pressure gradient is as follows:

[0157]

[0158]

[0159] In the formula, p 4i is the formation pressure of the i-th section Zone 4, MPa; C4 is the formation pressure gradient value of the i-th section Zone 4, MPa; q ei is the formation flow rate of the i-th section Zone 4, m 3 / d; μ e is the fluid viscosity of the i-th section Zone 4, mPa·s; K roc4 is the oil phase relative permeability of the i-th section Zone 4; a 4i is the pressure diffusivity coefficient of the i-th section Zone 4, dimensionless.

[0160] S8. Draw the pressure drop curves of different seepage zones.

[0161] As shown in Figure 7 , taking the distance R from the wellbore as the abscissa and the formation pressure p as the ordinate, a chart of the relationship between reservoir pressure p and wellbore distance R is drawn.

[0162] S9. Compare the pressure gradients of Zone 3 and Zone 4 with the threshold pressure gradients to determine the supply pressure. Calculate the actual pressure gradient (ΔP / L) of seepage Zone 3, and compare it with the threshold pressure gradient G3 of seepage Zone 3.

[0163] As shown in Figure 8 , if ΔP / L<G3 (the actual pressure gradient < the threshold pressure gradient of Zone 3), Zone 3 cannot be effectively produced, and at this time the supply pressure p e =p3. If G3≦ΔP / L≦G4 (the threshold pressure gradient of Zone 3 < the actual pressure gradient ≦ the threshold pressure gradient of Zone 4), Zone 3 can be fully and effectively produced, and at this time the supply pressure p e =p4.

[0164] The actual pressure gradient of Zone 3 in the M heavy oil reservoir is:

[0165] ΔP3 / L=(5.6-2.3)MPa / 55m=0.060MPa / m.

[0166] The actual pressure gradient of Zone 4 in the M heavy oil reservoir is:

[0167] ΔP4 / L=(15.5-5.6)MPa / 90m=0.11MPa / m.

[0168] Taking the average temperature of Zone 3 as 75°C (the average of the starting pressure inflection point temperature of 100°C and the original reservoir temperature of 50°C), the corresponding crude oil viscosity is calculated to be 600 mPa·s according to Equation (7); according to Equation (2), the starting pressure gradient of Zone 3 is calculated as:

[0169] G3=0.1854e -0.3048(2008 / μ) =0.1854e -0.3048(2008 / 600) =0.065MPa / m

[0170] According to Equation (2), the starting pressure gradient of Zone 4 is calculated as:

[0171] G4=0.1854e -0.3048(2008 / μ) =0.1854e -0.3048(2008 / 2909) =0.15MPa / m

[0172] Since ΔP / L<G3 (that is, 0.06MPa / m≦ΔP3 / L) is satisfied, the determined supply pressure is p e =p3=6MPa.

[0173] S10. Calculate the effective producing pressure differential for cyclic steam stimulation in heavy oil reservoirs based on the pressure distribution in the effective seepage zone.

[0174] When ΔP / L<G3, the effective pressure differential calculation formula is:

[0175] Δp 有效 =p3-p wf (13)

[0176] When G3≦ΔP / L≦G4, the effective pressure differential calculation formula is:

[0177] Δp 有效 =p4-p wf (14)

[0178] When the heavy oil reservoir is produced at a constant daily oil production of 100 cubic meters per day, assuming that the minimum bottomhole flowing pressure at this time is 2.0 MPa, according to the result of S9, the corresponding effective producing pressure differential at this time is ΔP 有效 =6.0MPa-2.0MPa=4.0MPa. However, if the conventional method is adopted, which is consistent with the calculation method of conventional cold production, that is, producing pressure differential = formation pressure - bottomhole flowing pressure, the calculation result is relatively large, which is 9.5MPa.

[0179] The embodiments of the present invention have been described in detail above, but the content described is only a preferred embodiment of the present invention and should not be considered as limiting the scope of the present invention. All equivalent changes and improvements made within the scope of the present invention should still fall within the patent coverage of the present invention.

Claims

1. A method for quantitatively determining the effective production pressure differential during steam huff and puff in heavy oil reservoirs, characterized in that, The steps include the following: S1. Collect static data on basic geological reservoir parameters of the target block; S2. Based on the experimental data of the starting pressure gradient in the target area, obtain the relationship between the starting pressure gradient and the flow rate; S3. Based on the starting pressure gradient, the formation to which steam is injected is divided into four different seepage zones: Zone 1 is the high-temperature heating zone, Zone 2 is the effective heating zone, Zone 3 is the heating transition zone, and Zone 4 is the unheated zone. S4, Set crude oil viscosity μ o1 μ is a constant value o1 =C1, with the starting pressure gradient G1 being a constant value G1=0, calculate the pressure drop in the high-temperature heating zone; S5, Set crude oil viscosity μ o2 For the change value μ o2 = f 1( T Start the pressure ladder G 2 is a constant value G 2=0, calculate the pressure drop in the effective heating zone; S6, Set crude oil viscosity μ o3 For the change value μ o3 = f 2( T ), Initiate pressure gradient G 3 represents the change value. G 3= f 3( T ), calculate the pressure drop in the heating transition zone; S7, Set crude oil viscosity μ o4 constant value μ o4 = C 2. Activate the pressure gradient G 4 is a constant value G 4= C 4. Calculate the pressure drop in the unheated zone; S8. Draw pressure drop curves for different seepage zones, with the distance R from the wellbore as the abscissa and the formation pressure p as the ordinate, and plot the relationship between formation pressure p and wellbore distance R. S9. Determine the magnitude of the pressure gradient in region 3 compared to the starting pressure gradients in regions 3 and 4, and determine the supply pressure. S10. Calculate the effective production pressure differential for steam huff and puff in heavy oil reservoirs based on the pressure distribution in the effective seepage zone; The mathematical models for the temperature and pressure distribution established in each region of S3 are as follows: Region 1, R≤R s T=T s ; Region 2, R s <R≤R h1 T s <T≤T h ; Region 3, R h1 <R≤R h2 T h <T≤T r ; Region 4, R>R h2 T=T r ; Among them, the formation temperature distribution characteristics of each region, R s R represents the radius of the leading edge of the steam chamber. h1 R is the radius of the leading edge of the effective heating zone. h2 T is the radius of the leading edge of the heating transition region. s T represents the temperature of the steam chamber. h T is the inflection point temperature of rheology. r The original formation temperature; In S4, the formula for calculating the pressure drop in the high-temperature heating zone is: In the formula, p 1i Let be the pressure drop in the i-th segment of region 1, in MPa; q si Let m be the formation flow rate in the i-th segment. 3 / d; μ o1 Let be the fluid viscosity in region 1, in mPa·s; K The absolute permeability of the formation is expressed in mD. K roc1 The relative permeability of the region is expressed in mD. h Let the oil layer thickness be m; L i Let be the length of the i-th horizontal section of the wellbore, in meters. δ Let be the eccentricity of the horizontal well, in meters (m). R w Let be the radius of the wellbore, in meters (m). a 1i The pressure conductivity coefficient of the i-th segment in region 1 is a decimal. In S5, the formula for calculating the effective heating zone pressure drop is: In the formula, p 2i Let be the pressure drop in region 2 of segment i, in MPa; q si Let m be the flow rate of the second formation in the i-th segment. 3 / d; Let be the fluid viscosity in region 2, in mPa·s; K roc2 Let mD be the relative permeability of region two. a 2i The pressure conductivity coefficient of the i-th segment in region two is a decimal. In S6, the formula for calculating the pressure drop in the heating transition region is: In the formula, p 3i Let be the pressure drop in region 3 of segment i, in MPa; q hi2 Let m be the flow rate of the three formations in the i-th segment. 3 / d; μ o3 Let be the fluid viscosity in region 3, in mPa·s; K roc3 The relative permeability of the three oil phases in the region; a 3i The three-dimensional pressure coefficient of the i-th segment is a decimal. In S7, the formula for calculating the pressure drop in the unheated zone is: In the formula, p 4i Let be the formation pressure in region four of segment i, in MPa; C 4 Let be the formation pressure gradient value of region 4 in segment i, in MPa; q ei Let m be the flow rate of the fourth formation in the i-th segment. 3 / d; μ e Let be the fluid viscosity in region 4 of segment i, in mPa·s; K roc4 Let be the relative permeability of the four oil phases in the i-th segment; a 4i The four-dimensional pressure coefficient of the i-th segment is a decimal. In S9, the method for determining supply pressure is as follows: When the actual pressure gradient ΔP / L in region 3 of the M heavy oil reservoir is less than G3, the supply pressure... p e = p 3; when G 3≦ΔP / L ≦ G 4. Supply pressure p e = p 4; In S10, the method for calculating the effective production pressure differential of heavy oil reservoir steam huff and puff based on the pressure distribution in the effective seepage zone is as follows: When Δ P / L < G3 The effective pressure difference is calculated using the following formula: when G3 ≦Δ P / L ≦ G4 The effective pressure difference is calculated using the following formula: 。 2. The method for quantitatively determining the effective production pressure differential of steam huff and puff in heavy oil reservoirs according to claim 1, characterized in that: Step S2 involves conducting a startup pressure gradient experiment using crude oil samples and cores from the target area. The startup pressure gradients at different temperatures and permeabilities are recorded, and the critical temperature for the existence of the startup pressure gradient is obtained. The obtained data is then substituted into the following formula to establish the relationship between the startup pressure gradient and the mobility. G = 0.1854 e -0.3048 (K / µ) In the formula, ρ represents the crude oil viscosity under formation conditions, in mPa·s; K represents the absolute permeability of the formation, in mD.

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