Steam huff and puff productivity prediction method

Abstract

The invention provides a steam huff and puff productivity prediction method, which belongs to the field of oil-gas field development and comprises the following steps: acquiring oil reservoir geological parameters and steam huff and puff injection-production parameters; after steam injection, soaking is carried out, production is carried out after soaking is finished, and the production process after soaking is finished is divided into n stages; dividing each stage into a steam area, a hot water area and a cold area according to temperature change, and iteratively calculating the average formation pressure, water saturation and thick oil viscosity of each stage by combining the seepage velocity; calculating the productivity of each stage by using the average formation pressure, the water saturation and the viscosity of the thickened oil of each stage; summing the productivity of the n stages to obtain the productivity of one steam huff and puff cycle. According to the method, the change of the viscosity along with the temperature and the seepage speed in the low-speed thick oil seepage process is considered, the starting pressure gradient and the bottom hole pressure change condition in the thick oil production process when pressure fluctuation exists or not can be calculated, and the accuracy of the prediction result of steam huff and puff is improved.

Description

Technical Field

[0001] The invention belongs to the field of oil and gas field development, and in particular relates to a steam throughput capacity prediction method. Background Art

[0002] With the continuous deepening of the development of heavy oil reservoirs in Xinjiang Oilfield, the current heavy oil throughput production is characterized by "many wells with low production and low oil-steam ratio". The results of the experiment on the use of hydraulic pumping units to achieve the "long stroke, low stroke" working system for some inefficient oil production wells show that for low-yield and inefficient wells, steam throughput has a significant effect on increasing production and can achieve heavy oil cold production to a certain extent, but the applicable conditions are unclear and promotion is difficult. In the context of low energy consumption and high efficiency as the development orientation, it is urgently needed to implement stop injection, slow injection and other methods in the inefficient areas to fully promote the increase of heavy oil production and efficiency.

[0003] If the production capacity of low-yield and low-efficiency wells at different development stages can be accurately predicted after the production system is converted, it will provide a theoretical basis for improving the quality and efficiency of low-efficiency areas. Summary of the invention

[0004] In view of the problems existing in the above-mentioned prior art, the present invention provides a steam throughput capacity prediction method. The technical problem to be solved by the present invention is how to accurately predict the capacity of low-yield and low-efficiency wells in different development stages after the production system is converted.

[0005] In order to solve the above technical problems, the present invention provides a method for predicting steam throughput capacity, comprising the following steps:

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

[0007] Step S2: After steam injection, the well is soaked, and production is carried out after the soaking is completed, and the production process after the soaking 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 change, and iteratively calculate the average formation pressure, water saturation and heavy oil viscosity of each stage in combination with the seepage velocity;

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

[0010] Step S5: summing up the capacities of n stages to obtain the capacity of a steam throughput cycle.

[0011] Furthermore, in 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 and production parameters include steam temperature.

[0012] Furthermore, in step S3, the water saturation of the previous stage is used to obtain the water saturation of the current stage.

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

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

[0015] Furthermore, in step S3, the current viscosity of the heavy oil is obtained by using the current average temperature of the oil layer in the steam zone, the current 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 at the current stage.

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

[0018]

[0019] Where: S wi is the initial water saturation; is the water saturation in the first stage; ρ wi is the formation water density under original conditions, kg·m -3 ; is the formation water density in the first stage, kg·m -3 ; h is the oil layer thickness; φ is the porosity value; N w is the cumulative water production;

[0020] The water saturation in the j+1 stage is calculated by establishing a mass conservation equation for the water phase. The groundwater volume at a certain moment = the original groundwater volume + the injected water volume - the produced water volume. The water saturation of the hot zone in each production stage can be calculated as follows:

[0021]

[0022] Where: is the water saturation at stage j+1; is the formation water density at stage j+1, kg·m -3 ; h is the oil layer thickness; φ is the porosity value.

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

[0024]

[0025] Where: r s is the radius of the steam zone, m; i s is the steam injection rate, kg·s -1 ; x is steam dryness; L v is the latent heat of steam, J·Kg -1 ;M R is the oil layer heat capacity, J·m -3 ℃ -1 ; h is the oil layer thickness, m; α s is the thermal diffusion coefficient of the top and bottom layers, m 2 ·h -1 ; s is the thermal conductivity of top and bottom rocks, W·m -1 ℃ -1 ; T i is the original formation temperature, °C; t D is the steam injection time, h; T s is the steam temperature, °C; T i is the original formation temperature, °C;

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

[0027]

[0028] is the temperature of the steam zone in the jth stage; 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 calculated by the energy conservation equation, and the calculation formula is as follows:

[0030]

[0031] in:

[0032] a=(T f -T s ) / (r h -r s ),c=T s ;

[0033] Where r is the radius from a point in the hot water area to the oil well, m; r h is the radius of the hot water area, m; T f is the front edge temperature of the hot water area; A′, a′, b′, c′, a and c are all intermediate quantities and have no substantial meaning.

[0034] The heating radius of the hot water zone in the j+1th stage is calculated by the energy conservation equation, and the calculation formula is as follows:

[0035]

[0036] in:

[0037]

[0038] is the temperature of the hot water zone in the jth stage; A″, a″, b″ and c″ are all intermediate quantities and have no substantial meaning.

[0039] Furthermore, in step S3, the calculation formula for the average temperature of the oil layer in the steam zone of the first stage is as follows:

[0040]

[0041] Where: and are the influencing factors of the temperature drop in the steam zone and the hot water zone caused by radial heat loss; is the average temperature of the oil layer in the steam zone of the first stage;

[0042] The calculation formula for the average temperature of the oil layer in the hot water area of ​​the first stage is as follows:

[0043]

[0044] Among them, T h is the average formation temperature of the hot water area at the beginning of soaking:

[0045]

[0046] Where: and are the influencing factors of the temperature drop in the steam zone and the hot water zone caused by the vertical heat loss in the top and bottom layers; is the average temperature of the oil layer in the hot water area of ​​the first stage;

[0047] The calculation formula for the average oil layer temperature in the steam zone of the j+1th stage is as follows:

[0048]

[0049] in, is the average oil layer temperature in the steam zone of stage j; is the average oil layer temperature in the steam zone of the j+1th stage;

[0050] The calculation formula for the average temperature of the oil layer in the hot water area of ​​the j+1th stage is as follows:

[0051] is the average temperature of the oil layer in the hot water area at stage j; The hot water area in the j+1th stage is the average temperature of the oil layer.

[0052] Furthermore, the calculation formula for the average seepage velocity of the steam zone, hot water zone and cold water zone at each stage is:

[0053]

[0054] Where: V j is the average seepage velocity in the jth stage, cm·s -1 ; A j is the average seepage cross-sectional area of ​​the steam zone, hot water zone and cold water zone in the jth stage, cm 2 ;Q j-1 is the oil production in the j-1th stage. When j=1, Q 0 The oil production is zero.

[0055] Furthermore, the calculation formula of the viscosity of heavy oil at each stage is as follows:

[0056]

[0057]

[0058]

[0059] in:

[0060] ln(μ 1 ) T =-0.0175T+9.9857

[0061] ln(μ 2 ) T =-0.0108T+5.6677

[0062] b=-n ln(0.001)+ln(μ 1 )

[0063]

[0064] Where: μ os , μ oh and μ ocare the heavy oil viscosities in the steam zone, hot water zone and cold zone, mPa·s; mPa·s; μ 1 The shear rate is 0.001s -1 Crude oil viscosity, mPa·s; μ 2 The shear rate is 0.1s -1 The viscosity of crude oil at , mPa·s; γ, is the shear rate, s -1 ; The hot water area in each stage is the average temperature of the oil layer; The steam zone in each stage is the average temperature of the oil layer.

[0065] Furthermore, in step S3, the calculation formula of the average formation pressure in the first stage is as follows:

[0066]

[0067] Where: is the average formation pressure at each stage; p i is the original formation pressure, MPa; is the average formation pressure in the first stage at the end of soaking, MPa; is the average formation temperature in the steam zone at the end of soaking, ℃; is the average formation temperature of the hot water area at the end of the soaking, ℃; B w and B o are the volume coefficients of formation water and crude oil under reservoir conditions; C e is the comprehensive compression coefficient, MPa -1 β e is the comprehensive thermal expansion coefficient, ℃ -1 ; N is the total geological reserves, m 3 ; N os is the original geological reserves of the steam zone, m 3 ; N oh is the original geological reserves of the hot water area, m 3 ; G is the cumulative steam injection volume (ground water equivalent), m 3 .

[0068] The calculation formula of the average formation pressure in the j+1 stage is as follows:

[0069]

[0070] Where: is the average formation pressure in the j+1th stage, MPa; N w is the cumulative water production, m 3 ; N o is the cumulative oil production, m 3 .

[0071] Furthermore, in step S4, the capacity of each stage is calculated by considering the startup pressure gradient under the condition of fluctuation or not, and the calculation formula of the startup pressure gradient under the condition of no fluctuation is:

[0072]

[0073]

[0074]

[0075] In the formula, G noc , G noh and G nos are the starting pressure gradients of the cold zone, hot water zone and steam zone under non-fluctuation conditions, MPa·m -1 ; K is the formation permeability, 10 -3 μm 2 ;μ o is the viscosity of heavy oil in any of the steam zone, hot water zone and cold zone;

[0076] The calculation formula for the starting pressure gradient under pressure fluctuation conditions is:

[0077]

[0078] Where: G w is the starting pressure gradient when there is bottom hole pressure fluctuation, MPa·m -1 ; A is the pressure fluctuation amplitude, MPa; T is the pressure fluctuation period, s.

[0079] Furthermore, the calculation formula for the starting pressure under non-surge conditions is as follows:

[0080]

[0081] The calculation formula for the starting pressure when there is pressure fluctuation is as follows:

[0082]

[0083] P G is the starting pressure of the cold zone, hot water zone and steam zone, MPa; r e is the supply radius, m.

[0084] Furthermore, when there is a bottom hole pressure fluctuation, the bottom hole pressure changes according to the sine function law and is expressed as:

[0085] P wf =P 0 +A sin(wt)

[0086] Where: P wfis the bottom hole flow pressure during pressure fluctuation, MPa; P 0 is the initial bottom hole flowing pressure, MPa; w is the angular velocity of fluctuation, rad / s; t is a certain moment in the fluctuation cycle.

[0087] The production capacity of each stage is calculated using the average formation pressure, water saturation and heavy oil viscosity of each stage.

[0088] Furthermore, the oil and water production is calculated using a pseudo-steady-state calculation of a well in the center of a circular closed formation taking into account the starting pressure gradient:

[0089]

[0090]

[0091] in:

[0092]

[0093]

[0094]

[0095]

[0096]

[0097]

[0098] Where: Q o is the oil yield, cm 3 ·s -1 ;Q w is the water production, cm 3 ·s -1 ;μ ws , μ wh and μ wc are the formation water viscosities in the steam zone, hot water zone, and cold zone, mPa·s; K ros , K roh , K roc are the relative permeabilities of the oil phase in the steam zone, hot water zone and cold zone respectively; K rws , K rwh , K rwc are the relative permeabilities of water phase in the steam zone, hot water zone and cold zone respectively; s is the skin coefficient; r w is the well diameter, m; R 1 (o) , R 2 (o) , R 3 (o) , R 1 (w), R 2 (w) and R 3 (w) They are all intermediate quantities and have no substantive meaning.

[0099] Furthermore, the cumulative oil production N o The calculation formula is as follows:

[0100]

[0101] Where N o is the cumulative oil production;

[0102] Cumulative water production N w The calculation formula is as follows:

[0103]

[0104] Where N w is the cumulative water production.

[0105] The method for predicting the production capacity of steam throughput of the present invention divides the production process into n stages, divides each stage into a steam zone, a hot water zone and a cold zone according to temperature changes, and iteratively calculates the average formation pressure, water saturation and heavy oil viscosity of each stage in combination with the seepage velocity. The production capacity of each stage is calculated by using the average formation pressure, water saturation and heavy oil viscosity of each stage under the starting pressure under the fluctuating condition, and the production capacity of the n stages is summed to obtain the production capacity of a steam throughput cycle, thereby realizing accurate prediction of the production capacity of low-yield and low-efficiency wells in different development stages after the production system is converted.

[0106] The steam throughput capacity prediction method of the present invention takes into account the change of viscosity with temperature and seepage velocity during the low-speed heavy oil seepage process, and can calculate the starting pressure gradient with or without pressure fluctuation during the heavy oil production process, and the change of bottom hole pressure, taking into account the influence of heavy oil startup and continuous phase seepage at low speed, improving the accuracy of steam throughput prediction results, and optimizing production parameters. BRIEF DESCRIPTION OF THE DRAWINGS

[0107] Figure 1 A schematic diagram of temperature distribution in a formation after steam injection in a method for predicting steam throughput capacity of the present invention.

[0108] Figure 2 is the flow velocity distribution in the formation during the production process of the steam throughput capacity prediction method of the present invention; wherein, r 1 is the high shear rate region, r 2 It is the low shear rate area.

[0109] Figure 3 The present invention provides a heavy oil viscosity curve diagram of a steam throughput capacity prediction method.

[0110] Figure 4 A schematic diagram of the startup pressure gradient under non-fluctuation conditions of a steam throughput capacity prediction method of the present invention.

[0111] Figure 5 A schematic diagram of the startup pressure gradient under pressure fluctuation conditions of a steam throughput capacity prediction method of the present invention.

[0112] Figure 6 The figure is a schematic diagram of a curve showing daily oil production changing with time under different formation permeabilities calculated by a steam throughput prediction method of the present invention.

[0113] Figure 7 The figure is a schematic diagram of a curve showing daily oil production changing with time under different bottom hole pressure fluctuation amplitudes calculated by a steam throughput prediction method of the present invention.

[0114] Figure 8 The figure is a schematic diagram of a curve showing daily oil production changing with time under different bottom hole pressure fluctuation periods calculated by a steam throughput prediction method of the present invention.

[0115] Fig. 9 The prediction results of different prediction methods and the actual daily oil production curve over time.

[0116] Fig.10 The present invention is a flow chart of a method for predicting steam throughput capacity using the present invention. DETAILED DESCRIPTION

[0117] In order to make the purpose, technical solutions and advantages of the embodiments of the present invention clearer, the technical solutions in the embodiments of the present invention will be clearly and completely described below in conjunction with the drawings in the embodiments of the present invention. Obviously, the described embodiments are part of the embodiments of the present invention, not all of the embodiments. Based on the embodiments of the present invention, all other embodiments obtained by ordinary technicians in this field without creative work are within the scope of protection of the present invention.

[0118] Therefore, the following detailed description of the embodiments of the present invention provided in the accompanying drawings is not intended to limit the scope of the invention claimed for protection, but merely represents selected embodiments of the present invention. Based on the embodiments of the present invention, all other embodiments obtained by ordinary technicians in this field without creative work are within the scope of protection of the present invention.

[0119] It should be noted that similar reference numerals and letters denote similar items in the following drawings, and therefore, once an item is defined in one drawing, further definition and explanation thereof is not required in subsequent drawings.

[0120] In the present invention, unless otherwise clearly specified and limited, the terms "installed", "connected", "connected", "fixed" and the like should be understood in a broad sense, for example, it can be a fixed connection, a detachable connection, or an integral connection; it can be directly connected or indirectly connected through an intermediate medium, it can be the internal connection of two elements or the interaction relationship between two elements. For ordinary technicians in this field, the specific meanings of the above terms in the present invention can be understood according to specific circumstances.

[0121] In order to better understand the purpose, structure and function of the present invention, a steam throughput capacity prediction method of the present invention is further described in detail below in conjunction with the accompanying drawings.

[0122] Embodiment 1:

[0123] Fig.10 A steam throughput capacity prediction method of the present invention is shown, comprising the following steps:

[0124] Step S1: Obtaining reservoir geological parameters and steam injection and production parameters;

[0125] Step S2: After steam injection, the well is soaked, and production is carried out after the soaking is completed, and the production process after the soaking is completed is divided into n stages;

[0126] Step S3: Divide each stage into steam zone, hot water zone and cold zone according to temperature change, and iteratively calculate the average formation pressure, water saturation and heavy oil viscosity of each stage in combination with the seepage velocity;

[0127] Step S4: Calculate the production capacity of each stage using the average formation pressure, water saturation and heavy oil viscosity of each stage;

[0128] Step S5: summing up the capacities of n stages to obtain the capacity of a steam throughput cycle.

[0129] Embodiment 2:

[0130] Fig.10 A steam throughput capacity prediction method of the present invention is shown, comprising the following steps:

[0131] Step S1: Obtaining reservoir geological parameters and steam injection and production parameters;

[0132] Step S2: After steam injection, the well is soaked, and production is carried out after the soaking is completed, and the production process after the soaking is completed is divided into n stages;

[0133] Step S3: Divide each stage into steam zone, hot water zone and cold zone according to temperature change, and iteratively calculate the average formation pressure, water saturation and heavy oil viscosity of each stage in combination with the seepage velocity;

[0134] Step S4: Calculate the production capacity of each stage using the average formation pressure, water saturation and heavy oil viscosity of each stage;

[0135] Step S5: summing up the capacities of n stages to obtain the capacity of a steam throughput cycle.

[0136] The difference between this embodiment and the first embodiment is that:

[0137] According to the volume balance principle, the average formation pressure, average formation temperature in the steam zone, average formation temperature in the hot water zone and water saturation in each stage are calculated;

[0138] In 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 and production parameters include steam temperature.

[0139] like Figure 1 As shown, in step S3, each stage is divided into a steam zone, a hot water zone and a cold zone, and according to the energy balance principle, the heating radius of the steam zone and the heating radius of the hot water zone are calculated, and then the average oil layer temperature of the steam zone and the average oil layer temperature of the hot water zone are calculated; the average seepage velocity of the current stage is obtained by using the oil production of the previous stage and the average seepage area of ​​the steam zone, the hot water zone and the cold zone at the current stage; the viscosity of the heavy oil 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 seepage velocity at the current stage; the average formation pressure of the current 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 at the current stage; the water saturation of the current stage is obtained by using the water saturation of the previous stage;

[0140] like Figure 2 As shown, it is divided into low-speed area and high-speed area according to the seepage velocity;

[0141] The heating radius of the steam zone in the first stage is calculated by the Marx-Langenheim method, and the calculation formula is as follows:

[0142]

[0143] Where: r s is the radius of the steam zone, m; i s is the steam injection rate, kg·s -1 ; x is steam dryness; L v is the latent heat of steam, J·Kg -1 ;M R is the oil layer heat capacity, J·m -3 ℃ -1 ; h is the oil layer thickness, m; α sis the thermal diffusion coefficient of the top and bottom layers, m 2 ·h -1 ; s is the thermal conductivity of top and bottom rocks, W·m -1 ℃ -1 ; T i is the original formation temperature, °C; t D is the steam injection time, h; T s is the steam temperature, °C; T i is the original formation temperature, ℃.

[0144] The heating radius of the steam zone in the j+1th stage is calculated using the Marx-Langenheim method, and the calculation formula is as follows:

[0145]

[0146] T sj is the temperature of the steam zone in the jth stage; j is the stage number, j = 1, 2, ..., n;

[0147] The heating radius of the hot water zone in the first stage is calculated by the energy conservation equation, and the calculation formula is as follows:

[0148]

[0149] in:

[0150]

[0151] a=(T f -T s ) / (r h -r s ),c=T s ;

[0152] Where r is the radius from a point in the hot water area to the oil well, m; r h is the radius of the hot water area, m; T f is the front edge temperature of the hot water area; A′, a′, b′, c′, a and c are all intermediate quantities and have no substantial meaning.

[0153] The heating radius of the hot water zone in the j+1th stage is calculated by the energy conservation equation, and the calculation formula is as follows:

[0154]

[0155] in:

[0156]

[0157] is the temperature of the hot water zone in the jth stage; A″, a″, b″ and c″ are all intermediate quantities and have no substantial meaning.

[0158] The calculation formula for the average temperature of the oil layer in the steam zone of the first stage is as follows:

[0159]

[0160] Where: and They are the influencing factors of the temperature drop in the steam zone and the hot water zone caused by radial heat loss, which are related to the soaking time, thermal diffusion coefficient and heating radius; is the average temperature of the oil layer in the steam zone of the first stage.

[0161] The calculation formula for the average temperature of the oil layer in the hot water area of ​​the first stage is as follows:

[0162]

[0163] Among them, T h is the average formation temperature of the hot water area at the beginning of soaking:

[0164]

[0165] Where: and They are the influencing factors of the temperature drop in the steam zone and the hot water zone caused by the vertical heat loss in the top and bottom layers, which are related to the soaking time, thermal diffusion coefficient and oil layer thickness; is the average temperature of the oil layer in the hot water area in the first stage.

[0166] The calculation formula for the average oil layer temperature in the steam zone of the j+1th stage is as follows:

[0167]

[0168] in, is the average oil layer temperature in the steam zone of stage j; is the average oil layer temperature in the steam zone of the j+1th stage.

[0169] The calculation formula for the average temperature of the oil layer in the hot water area of ​​the j+1th stage is as follows:

[0170]

[0171] is the average temperature of the oil layer in the hot water area at stage j; The hot water area in the j+1th stage is the average temperature of the oil layer.

[0172] The calculation formula for the average formation pressure in the first stage is as follows:

[0173]

[0174] Where: is the average formation pressure at each stage; p i is the original formation pressure, MPa; is the average formation pressure in the first stage at the end of soaking, MPa; is the average formation temperature in the steam zone at the end of soaking, ℃; is the average formation temperature of the hot water area at the end of the soaking, ℃; B w and B o are the volume coefficients of formation water and crude oil under reservoir conditions; C e is the comprehensive compression coefficient, MPa -1 β e is the comprehensive thermal expansion coefficient, ℃ -1 ; N is the total geological reserves, m 3 ; N os is the original geological reserves of the steam zone, m 3 ; N oh is the original geological reserves of the hot water area, m 3 ; G is the cumulative steam injection volume (ground water equivalent), m 3 .

[0175] The calculation formula of the average formation pressure in the j+1 stage is as follows:

[0176]

[0177] Where: is the average formation pressure in the j+1th stage, MPa; N w is the cumulative water production, m 3 ; N o is the cumulative oil production, m 3 .

[0178] The calculation formula for the average seepage velocity in the steam zone, hot water zone and cold water zone at each stage is:

[0179]

[0180] Where: V j is the average seepage velocity in the jth stage, cm·s -1 ; A j is the average seepage cross-sectional area of ​​the steam zone, hot water zone and cold water zone in the jth stage, cm 2 ;Q j-1 is the oil production in the j-1th stage. When j=1, Q 0 The oil production is zero.

[0181] like Figure 3As shown in the figure, the viscosity of heavy oil in each stage is calculated by using the average seepage velocity, the average temperature of the oil layer in the steam zone and the average temperature of the oil layer in the hot water zone. The calculation formula is as follows:

[0182]

[0183]

[0184]

[0185] in:

[0186] ln(μ 1 ) T =-0.0175T+9.9857

[0187] ln(μ 2 ) T =-0.0108T+5.6677

[0188] b=-nln(0.001)+ln(μ 1 )

[0189]

[0190] Where: μ os , μ oh and μ oc are the heavy oil viscosities in the steam zone, hot water zone and cold zone, mPa·s;, mPa·s; μ 1 The shear rate is 0.001s -1 Crude oil viscosity, mPa·s; μ 2 The shear rate is 0.1s -1 The viscosity of crude oil at , mPa·s; γ, is the shear rate, s -1 ; When γ is greater than 0.1 / s, it is a high-speed zone, and when γ is less than 0.1 / s, it is a low-speed zone; The hot water area in each stage is the average temperature of the oil layer; The steam zone in each stage is the average temperature of the oil layer.

[0191] The calculation formula of water saturation in the first stage is as follows:

[0192]

[0193] Where: S wi is the initial water saturation; is the water saturation in the first stage; ρ wi is the formation water density under original conditions, kg·m -3 ; is the formation water density in the first stage, kg·m -3; h is the oil layer thickness; φ is the porosity value; N w It is the cumulative water production (excluding the cumulative water production at the current stage).

[0194] The water saturation in the j+1 stage is calculated by establishing a mass conservation equation for the water phase. The groundwater volume at a certain moment = the original groundwater volume + the injected water volume - the produced water volume. The water saturation of the hot zone in each production stage can be calculated as follows:

[0195]

[0196] Where: is the water saturation at stage j+1; is the formation water density at stage j+1, kg·m -3 ; h is the oil layer thickness; φ is the porosity value.

[0197] According to the water saturation at a certain moment, the relative permeability at a certain water saturation can be obtained through the phase permeability curve, and the production capacity can be calculated using the permeability.

[0198] The calculation formula for the starting pressure gradient under no fluctuation conditions is:

[0199]

[0200]

[0201]

[0202] In the formula, G noc , G noh and G nos are the starting pressure gradients of the cold zone, hot water zone and steam zone under non-fluctuation conditions, MPa·m -1 ; K is the formation permeability, 10 -3 μm 2 ;μ o is the viscosity of heavy oil in any of the steam zone, hot water zone and cold zone;

[0203]

[0204] Where: G w is the starting pressure gradient when there is bottom hole pressure fluctuation, MPa·m -1 ; A is the pressure fluctuation amplitude, MPa; T is the pressure fluctuation period, s.

[0205] like Figure 4 As shown, the calculation formula for the starting pressure under non-surge conditions is as follows:

[0206]

[0207] like Figure 5 As shown in the figure, the calculation formula for the starting pressure when there is pressure fluctuation is as follows:

[0208]

[0209] P G is the starting pressure of the cold zone, hot water zone and steam zone, MPa; r e is the supply radius, m.

[0210] When there is a bottom hole pressure fluctuation, the bottom hole pressure changes according to the law of the sine function and is expressed as:

[0211] P wf =P 0 +A sin(wt)

[0212] Where: P wf is the bottom hole flow pressure during pressure fluctuation, MPa; P 0 is the initial bottom hole flowing pressure, MPa; w is the angular velocity, rad / s; t is a certain moment in the fluctuation cycle.

[0213] The production capacity of each stage is calculated using the average formation pressure, water saturation and heavy oil viscosity of each stage. The calculation formula is as follows:

[0214] like Figure 6 , Figure 7 and Figure 8 As shown, the oil and water production is calculated using a pseudo-steady state calculation of a well in the center of a circular closed formation taking into account the starting pressure gradient:

[0215]

[0216]

[0217] in:

[0218]

[0219]

[0220]

[0221]

[0222]

[0223]

[0224] Where: Q o is the oil yield, cm 3 ·s -1 ;Q wis the water production, cm 3 ·s -1 ;μ ws , μ wh and μ wc are the formation water viscosities in the steam zone, hot water zone, and cold zone, mPa·s; K ros , K roh , K roc are the oil phase relative permeabilities in the steam zone, hot water zone and cold zone respectively; K rws , K rwh , K rwc are the relative permeabilities of water phase in steam zone, hot water zone and cold zone respectively; r w is the well diameter, m; R 1 (o) , R 2 (o) , R 3 (o) , R 1 (w) , R 2 (w) and R 3 (w) They are all intermediate quantities and have no substantive meaning.

[0225] Cumulative oil production N o The calculation formula is as follows:

[0226]

[0227] Cumulative water production N w The calculation formula is as follows:

[0228]

[0229] Embodiment 3:

[0230] The present invention provides a steam throughput capacity prediction method, which predicts the capacity change within a throughput cycle based on the obtained reservoir data, and the specific steps include:

[0231] (1) Obtaining reservoir geological parameters and steam injection and production parameters (as shown in Tables 1 and 2);

[0232] (2) After steam injection, the well is soaked and then production is carried out. The production process after soaking is divided into n stages. Each stage is divided into steam zone, hot water zone and cold zone according to temperature change. The heating radius of the steam zone and the hot water zone is calculated based on the energy balance principle. Combined with the seepage velocity, the formation is divided into a low-speed zone and a high-speed zone according to the seepage velocity. Then, the average formation pressure, water saturation and heavy oil viscosity of each stage are iteratively calculated;

[0233] (3) Using the average formation pressure, water saturation and heavy oil viscosity at each stage, the production capacity of each stage is calculated according to the pseudo-steady-state formula of a well in the center of a circular closed formation;

[0234] (4) The capacity of n stages is summed to obtain the capacity of a steam throughput cycle.

[0235] like Fig. 9 As shown in the figure, the cumulative oil production of a single well predicted by this method is 674.0t, the cumulative oil production predicted by the conventional viscosity-temperature model is 873.2t, and the actual cumulative oil production of a single well predicted by steam stimulation 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.

[0236] Table 1 Reservoir geological parameters

[0237]

[0238] Table 2 Steam injection and production parameters

[0239]

[0240] The above description is only a preferred embodiment of the present invention and is not intended to limit the present invention. For those skilled in the art, the present invention may have various modifications and variations. Any modification, equivalent replacement, improvement, etc. made within the spirit and principle of the present invention are included in the protection scope of the present invention.

Claims

1. A method for predicting steam throughput, characterized in that: The following steps are involved: Step S1: Obtaining reservoir geological parameters and steam injection and production parameters; Step S2: After steam injection, the well is soaked, and production is carried out after the soaking is completed, and the production process after the soaking is completed is divided into n stages; Step S3: Divide each stage into steam zone, hot water zone and cold zone according to temperature change, and iteratively calculate the average formation pressure, water saturation and heavy oil viscosity of each stage in combination with the seepage velocity; Step S4: Calculate the production capacity of each stage using the average formation pressure, water saturation and heavy oil viscosity of each stage; Step S5: summing up the capacities of n stages to obtain the capacity of a steam throughput cycle.

2. The method for predicting steam throughput according to claim 1, characterized in that: In 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 steam injection and production parameters include steam temperature.

3. The method for predicting steam throughput capacity according to claim 1, characterized in that: In step S3, the water saturation of the previous stage is used to obtain the water saturation of the current stage.

4. The method for predicting steam throughput capacity according to claim 3, characterized in that: In step S3, each stage is divided into a steam zone, a hot water zone and a cold zone, and the heating radius of the steam zone and the heating radius of the hot water zone are calculated according to the energy balance principle, and then the average temperature of the oil layer in the steam zone and the average temperature of the oil layer in the hot water zone are calculated.

5. The method for predicting steam throughput according to claim 4, characterized in that: In step S3, the average seepage velocity at the current stage is obtained by using the oil production at the previous stage and the average seepage areas of the steam zone, the hot water zone and the cold zone at the current stage.

6. The method for predicting steam throughput capacity according to claim 5, characterized in that: In step S3, the viscosity of the heavy oil at the current stage is obtained by using the 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 at the current stage.

7. The method for predicting steam throughput capacity according to claim 6, characterized in that: 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 at the current stage.

8. The method for predicting steam throughput according to claim 7, characterized in that: The calculation formula of water saturation in the first stage is as follows: Where: S wi is the initial water saturation; is the water saturation in the first stage; ρ wi is the formation water density under original conditions, kg·m -3 ; is the formation water density in the first stage, kg·m -3 ; h is the oil layer thickness; φ is the porosity value; N w is the cumulative water production; The water saturation in the j+1 stage is calculated by establishing a mass conservation equation for the water phase. The groundwater volume at a certain moment = the original groundwater volume + the injected water volume - the produced water volume. The water saturation of the hot zone in each production stage can be calculated as follows: Where: is the water saturation at stage j+1; is the formation water density at stage j+1, kg·m -3 ; h is the oil layer thickness; φ is the porosity value.

9. The method for predicting steam throughput according to claim 8, characterized in that: In step S3, the heating radius of the steam zone in the first stage is calculated by the Marx-Langenheim method, and the calculation formula is as follows: Where: r s is the radius of the steam zone, m; i s is the steam injection rate, kg·s -1 ; x is steam dryness; L v is the latent heat of steam, J·Kg -1 ;M R is the oil layer heat capacity, J·m -3 ℃ -1 ; h is the oil layer thickness, m; α s is the thermal diffusion coefficient of the top and bottom layers, m 2 ·h -1 ; λ s is the thermal conductivity of top and bottom rocks, W·m -1 ℃ -1 ; T i is the original formation temperature, °C; t D is the steam injection time, h; T s is the steam temperature, °C; T i is the original formation temperature, °C; The heating radius of the steam zone in the j+1th stage is calculated by the Marx-Langenheim method, and the calculation formula is as follows: T sj is the temperature of the steam zone in the jth stage; j is the stage number, j = 1, 2, …, n.

10. The steam throughput capacity prediction method according to claim 9, characterized in that: In step S3, the heating radius of the hot water zone in the first stage is calculated by the energy conservation equation, and the calculation formula is as follows: in: a=(T f -T s ) / (r h -r s ),c=T s ; Where r is the radius from a point in the hot water area to the oil well, m; r h is the radius of the hot water area, m; T f is the front edge temperature of the hot water area; A′, a′, b′, c′, a and c are all intermediate quantities and have no substantial meaning; The heating radius of the hot water zone in the j+1th stage is calculated by the energy conservation equation, and the calculation formula is as follows: in: is the temperature of the hot water zone in the jth stage; A″, a″, b″ and c″ are all intermediate quantities and have no substantial meaning.

11. The steam throughput capacity prediction method according to claim 10, characterized in that: In step S3, the calculation formula for the average temperature of the oil layer in the steam zone of the first stage is as follows: Where: and are the influencing factors of the temperature drop in the steam zone and the hot water zone caused by radial heat loss; is the average temperature of the oil layer in the steam zone of the first stage; The calculation formula for the average temperature of the oil layer in the hot water area of ​​the first stage is as follows: Among them, T h is the average formation temperature of the hot water area at the beginning of soaking: Where: and are the influencing factors of the temperature drop in the steam zone and the hot water zone caused by the vertical heat loss in the top and bottom layers; is the average temperature of the oil layer in the hot water area of ​​the first stage; The calculation formula for the average oil layer temperature in the steam zone of the j+1th stage is as follows: in, is the average oil layer temperature in the steam zone of stage j; is the average oil layer temperature in the steam zone of the j+1th stage; The calculation formula for the average temperature of the oil layer in the hot water area of ​​the j+1th stage is as follows: is the average temperature of the oil layer in the hot water area at stage j; The hot water area in the j+1th stage is the average temperature of the oil layer.

12. The steam throughput capacity prediction method according to claim 11, characterized in that: The calculation formula for the average seepage velocity in the steam zone, hot water zone and cold water zone at each stage is: Where: V j is the average seepage velocity in the jth stage, cm·s -1 ; A j is the average seepage cross-sectional area of ​​the steam zone, hot water zone and cold water zone in the jth stage, cm 2 ;Q j-1 is the oil production in the j-1th stage. When j=1, the oil production of Q0 is zero.

13. The method for predicting steam throughput capacity according to claim 12, characterized in that: The calculation formula of heavy oil viscosity at each stage is as follows: in: ln(μ1) T =-0.0175T+9.9857 ln(μ2) T =-0.0108T+5.6677 b=-nln(0.001)+ln(μ1) Where: μ os , μ oh and μ oc are the viscosity of heavy oil in steam zone, hot water zone and cold zone, mPa·s; mPa·s; μ1 is the shear rate of 0.001s -1 Crude oil viscosity at 10000 s, mPa·s; μ2 is the shear rate 0.1s -1 The viscosity of crude oil at , mPa·s; γ is the shear rate, s -1 ; The hot water area in each stage is the average temperature of the oil layer; The steam zone in each stage is the average temperature of the oil layer.

14. The method for predicting steam throughput capacity according to claim 13, characterized in that: In step S3, the calculation formula of the average formation pressure in the first stage is as follows: Where: p i is the original formation pressure, MPa; is the average formation pressure in the first stage at the end of soaking, MPa; is the average formation temperature in the steam zone at the end of soaking, °C; B is the average formation temperature of the hot water area at the end of the soaking, ℃; w and B o are the volume coefficients of formation water and crude oil under reservoir conditions; C e is the comprehensive compression coefficient, MPa -1 ; β e is the comprehensive thermal expansion coefficient, ℃ -1 ; N is the total geological reserves, m 3 ; N os is the original geological reserves of the steam zone, m 3 ; N oh is the original geological reserves of the hot water area, m 3 ; G is the cumulative steam injection volume (ground water equivalent), m 3 ; The calculation formula of the average formation pressure in the j+1 stage is as follows: Where: is the average formation pressure in the j+1th stage, MPa; N w is the cumulative water production, m 3 ; N o is the cumulative oil production, m 3 .

15. The method for predicting steam throughput according to claim 14, characterized in that: In step S4, the capacity of each stage is calculated by considering the starting pressure gradient under the condition of fluctuation or not. The calculation formula of the starting pressure gradient under the condition of no fluctuation is: In the formula, G noc , G noh and G nos are the starting pressure gradients of the cold zone, hot water zone and steam zone under non-fluctuation conditions, MPa·m -1 ; K is the formation permeability, 10 -3 μm 2 ;μ o is the viscosity of heavy oil in any of the steam zone, hot water zone and cold zone; The calculation formula for the starting pressure gradient under pressure fluctuation conditions is: Where: G w is the starting pressure gradient when there is bottom hole pressure fluctuation, MPa·m -1 ; A is the pressure fluctuation amplitude, MPa; T is the pressure fluctuation period, s.

16. The method for predicting steam throughput capacity according to claim 15, characterized in that: The calculation formula for the starting pressure under non-surge conditions is as follows: The calculation formula for the starting pressure when there is pressure fluctuation is as follows: P G is the starting pressure of the cold zone, hot water zone and steam zone, MPa; r e is the supply radius, m.

17. The method for predicting steam throughput according to claim 16, characterized in that: When there is a bottom hole pressure fluctuation, the bottom hole pressure changes according to the law of the sine function and is expressed as: P wf =P0+A sin(wt) Where: P wf is the bottom hole flow pressure during pressure fluctuation, MPa; P0 is the initial bottom hole flow pressure, MPa; w is the angular velocity of fluctuation, rad / s; t is a certain moment in the fluctuation cycle.

18. The method for predicting steam throughput according to claim 17, characterized in that: Calculate the oil and water production using a pseudo-steady-state calculation of a well in the center of a circular closed formation taking into account the start-up pressure gradient: in: Where: Q o is the oil yield, cm 3 ·s -1 ;Q w is the water production, cm 3 ·s -1 ;μ ws , μ wh and μ wc are the formation water viscosities in the steam zone, hot water zone, and cold zone, mPa·s; K ros , K roh , K roc are the relative permeabilities of the oil phase in the steam zone, hot water zone and cold zone respectively; K rws , K rwh , K rwc are the relative permeabilities of water phase in the steam zone, hot water zone and cold zone respectively; s is the skin coefficient; r w is the well diameter, m; R1 (o) , R2 (o) 、R3 (o) 、R1 (w) , R2 (w) and R3 (w) They are all intermediate quantities and have no substantive meaning.

19. The method for predicting steam throughput capacity according to claim 18, characterized in that: Cumulative oil production N o The calculation formula is as follows: Where N o is the cumulative oil production; Cumulative water production N w The calculation formula is as follows: Where N w is the cumulative water production.

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