A method and system for predicting the steam huff and puff production capacity of multi-layered heavy oil reservoirs at sea.

Abstract

This invention relates to a method and system for predicting the steam injection production capacity of multi-layered heavy oil reservoirs at sea, comprising the following steps: collecting basic parameters of the multi-layered heavy oil reservoir at sea; calculating bottom hole steam parameters using the collected basic parameters and a pre-constructed wellbore heat loss characterization model considering the characteristics of offshore areas; and calculating the production dynamics of each layer of the multi-layered heavy oil reservoir at sea based on the bottom hole steam parameters and the pre-constructed steam injection production capacity prediction model. This invention characterizes the actual temperature distribution of the hydrothermal zone, considers the special characteristics of offshore heavy oil reservoirs, establishes a wellbore heat transfer and pressure drop model for steam injection development of offshore heavy oil reservoirs, and thus forms an integrated injection production capacity evaluation and prediction model considering wellbore-reservoir coupling. This model can accurately evaluate the initial production capacity of offshore heavy oil injection development, providing an important basis for the efficient development of offshore heavy oil reservoirs. Therefore, this invention can be widely applied in the field of reservoir development technology.

Description

Technical Field

[0001] This invention relates to a method and system for predicting the steam huff and puff capacity of multi-layered heavy oil reservoirs at sea, belonging to the field of reservoir development technology. Background Technology

[0002] Thermal recovery methods for heavy oil reservoirs mainly include steam injection, steam drive, reservoir combustion, and steam-assisted gravity drainage. Among these, steam injection, as a single-well development method, involves injecting steam into a single well and producing oil in the same well. It has the advantages of rapid heating, lower initial investment, simpler technology, rapid production increase, and considerable early-stage yields. Therefore, this technology is currently the most widely used thermal recovery technology.

[0003] In recent years, the large-scale development of thermal recovery of offshore heavy oil reservoirs has been steadily advancing. Unlike the development of conventional onshore heavy oil reservoirs, steam injection for offshore heavy oil reservoirs requires consideration of the impact of riser on wellbore heat transfer. After steam is injected into the oil layer, the difference in density between crude oil and steam causes gravitational differentiation, making it easier for steam to migrate to the top of the oil layer, resulting in steam overlap. The presence of steam overlap exacerbates heat loss caused by heat conduction between the oil layer and the top and bottom caprocks. Unlike conventional crude oil, heavy oil exhibits a Newtonian fluid state at a certain temperature, but below this temperature (transformation temperature), it exhibits a non-Newtonian fluid state, i.e., a starting pressure gradient exists. Commonly used methods for calculating the heating radius of steam injection assume that the heating zone is isothermal and that the temperature is equal to the bottomhole steam temperature. In reality, due to the continuous outward diffusion of heat in the heating zone, the temperature in the heating zone gradually decreases from the steam temperature to the original formation temperature. Considering the temperature changes in the heating zone, a non-isothermal distribution model of the heating zone needs to be established.

[0004] However, existing heavy oil reservoir throughput models are mostly designed for single-layer heavy oil reservoirs and do not consider the impact of wellbore heat loss on steam parameters. Summary of the Invention

[0005] To address the aforementioned problems, the purpose of this invention is to provide a method and system for predicting the steam huff and puff production capacity of multi-layered heavy oil reservoirs at sea. Based on considering the heat loss of the wellbore in offshore heavy oil reservoirs, a steam huff and puff production capacity model for multi-layered heavy oil reservoirs at sea is established to achieve accurate evaluation of the production capacity in the early stage of offshore heavy oil huff and puff development.

[0006] To achieve the above objectives, the present invention adopts the following technical solution:

[0007] In a first aspect, the present invention provides a method for predicting the steam huff and puff capacity of offshore multi-layered heavy oil reservoirs, comprising the following steps:

[0008] Basic parameters of multi-layered heavy oil reservoirs at sea were collected;

[0009] Using the collected basic parameters and a pre-constructed wellbore heat loss characterization model that considers marine characteristics, the bottom hole steam parameters are calculated.

[0010] Based on bottom hole steam parameters and a pre-built steam throughput production prediction model, the production dynamics of each layer in a multi-layered heavy oil reservoir at sea are calculated.

[0011] Furthermore, the calculation of bottom hole steam parameters using the collected basic parameters and a pre-constructed wellbore heat loss characterization model considering offshore characteristics includes the following steps:

[0012] The tubing string of thermal recovery wells in offshore heavy oil reservoirs is subdivided along the axial direction, and a pressure gradient calculation model along the friction is established based on the momentum conservation equation.

[0013] Based on the steady-state heat transfer theory, calculation models for heat transfer between the steam injection pipe string and the outer edge of the cement sheath, and between the outer edge of the cement sheath and the formation, are established respectively.

[0014] The heat transfer process between the seawater section and the mud section is processed, and a calculation model for the total heat transfer in the seawater section is established.

[0015] Considering the influence of wellbore friction loss on steam dryness within a micro-element, a steam dryness calculation model is established based on the energy conservation equation.

[0016] Based on the collected basic parameters, the above calculation models are solved using the subdivision micro-element method to obtain the bottom hole steam parameters, which include bottom hole steam temperature and steam dryness.

[0017] Furthermore, based on bottom-hole steam parameters and a pre-built steam huff and puff production capacity prediction model, the production dynamics of each layer in a multi-layered heavy oil reservoir at sea are calculated, including:

[0018] Let the number of smaller layers j = 1;

[0019] Using bottom hole steam parameters and a pre-built steam huff and puff production capacity prediction model, the production dynamics of different huff and puff cycles in reservoir j were calculated.

[0020] Let the number of sub-layers j = j + 1. Compare the size of j with Z. If j > Z, stop the calculation. If j ≤ Z, repeat the previous step until the production dynamics of each layer in the multi-layered heavy oil reservoir at sea are obtained, where Z is the number of sub-layers in the reservoir.

[0021] Furthermore, the production dynamics of different huff and puff cycles in reservoir j are calculated using bottom-hole steam parameters and a pre-built steam huff and puff production prediction model, including:

[0022] Let the number of cycles N = 1, and divide the reservoir formation area of ​​this small layer into steam zone, hydrothermal zone and cold zone at the end of the steam injection stage, and calculate the heating radius of each zone using bottom hole steam parameters;

[0023] Determine the average temperature T of the steam zone at the end of well steaming. savg Average temperature T of the hydrothermal zone havg Mean formation pressure P of the oil reservoir avg,s and average water saturation S w And calculate the daily oil production Q. o ;

[0024] Determine the average temperature T of the steam zone during the production stage as Average temperature T of the hydrothermal zone ah Mean formation pressure P of the oil reservoir avg,p and average water saturation S w Calculate the daily oil production Q o ;

[0025] Let the number of cycles N = N + 1, and compare N with the number of throughput rounds N. max The size, such as N > N max The calculation ends here; proceed to the next step; if N≤N max Then calculate the residual heat E of the heating zone for that cycle. rs and E rh The residual heat from the heating zone is then added to the heat injection for the next cycle of throughput. All the above steps are repeated to obtain the production dynamics of different throughput cycles for each small layer.

[0026] Furthermore, the process of dividing the small reservoir formation area at the end of the steam injection stage and calculating the heating radius of each zone using bottom hole steam parameters includes:

[0027] At the end of the steam injection stage, the formation area is divided into three regions: steam zone, hydrothermal zone, and cold zone.

[0028] The steam injection volume of each sub-layer is divided according to the formation coefficient, and the heating radius of the steam zone and the hydrothermal zone are calculated using the bottom hole steam parameters and the pre-established calculation model of the heating radius of the steam zone and the hydrothermal zone.

[0029] Furthermore, the determination of the average temperature T in the steam zone at the end of well steaming... savg Average temperature T of the hydrothermal zone havg Mean formation pressure P of the oil reservoir avg,s and average water saturation S w And calculate the daily oil production Q. o ,include:

[0030] Determine the average temperature T of the steam zone at the end of well steaming. savg and the average temperature T of the hydrothermal zonehavg And based on the average temperature T in the steam zone savg and the average temperature T of the hydrothermal zone havg The mean formation pressure P of the reservoir was calculated. avg,s and average water saturation S w ;

[0031] Based on the calculated average formation pressure P of the reservoir avg,s Using a pre-built steam injection capacity prediction model, the daily oil production at the end of well shut-in was calculated.

[0032] Furthermore, the determination of the average temperature T in the steam zone during the production stage... as Average temperature T of the hydrothermal zone ah Mean formation pressure P of the oil reservoir avg,p and average water saturation S w Calculate the daily oil production Q o ,include:

[0033] Determine the production stage and the average temperature T in the steam zone. as and the average temperature T of the hydrothermal zone ah And based on the average temperature T in the steam zone as and the average temperature T of the hydrothermal zone ah The mean formation pressure P of the reservoir was calculated. avg,p and average water saturation S w ;

[0034] Based on the calculated average formation pressure P of the reservoir avg,p Based on the pre-built steam development capacity model, the daily oil production during the production phase is calculated.

[0035] Secondly, the present invention provides a steam huff and puff production capacity prediction system for multi-layered heavy oil reservoirs at sea, comprising:

[0036] The data acquisition module is used to collect basic parameters of multi-layered heavy oil reservoirs at sea;

[0037] The bottom hole steam parameter calculation module is used to calculate the bottom hole steam parameters using the collected basic parameters and a pre-built wellbore heat loss characterization model that takes into account the characteristics of the sea.

[0038] The reservoir integrated production capacity prediction module is used to calculate the production dynamics of different steam injection cycles in multi-layer heavy oil reservoirs by utilizing bottom hole steam parameters and a pre-built steam injection production capacity prediction model.

[0039] Thirdly, the present invention provides a processing device, the processing device including at least a processor and a memory, the memory storing a computer program, and the processor executing the computer program to perform steps for predicting the steam huff and puff capacity of the offshore multi-layered heavy oil reservoir.

[0040] Fourthly, the present invention provides a computer storage medium storing computer-readable instructions that can be executed by a processor to implement the steps of the method for predicting the steam injection capacity of the offshore multi-layered heavy oil reservoir.

[0041] The present invention has the following advantages due to the adoption of the above technical solutions:

[0042] 1. This invention establishes a steam injection production capacity model for multi-layer heavy oil reservoirs, which divides the steam injection volume of small layers by formation coefficient and considers the influence of wellbore heat loss on steam parameters.

[0043] 2. This invention takes into account steam over-coverage and modifies the heating radius calculation model considering heat absorption by the interlayer;

[0044] 3. The reservoir temperature is divided into three zones, in which the hydrothermal zone is considered to have a nonlinear temperature distribution, and the temperature distribution of the hydrothermal zone is determined by numerical inversion using a sand-filled pipe model at the laboratory scale.

[0045] 4. Consider the starting pressure gradient effect, and the starting pressure gradient is a function of mobility, that is, the starting pressure gradient of each layer can be calculated separately based on the corresponding reservoir permeability and crude oil viscosity.

[0046] Therefore, this invention can be widely applied in the field of reservoir development technology. Attached Figure Description

[0047] Various other advantages and benefits will become apparent to those skilled in the art upon reading the following detailed description of preferred embodiments. The accompanying drawings are for illustrative purposes only and are not intended to limit the invention. Throughout the drawings, the same reference numerals denote the same parts. In the drawings:

[0048] Figure 1 A flowchart of a method for predicting the steam huff and puff capacity of multi-layered heavy oil reservoirs at sea, provided in an embodiment of the present invention;

[0049] Figure 2 Oil-water phase permeation curves at different temperatures provided in embodiments of the present invention;

[0050] Figure 3 Crude oil viscosity-temperature curves provided for embodiments of the present invention;

[0051] Figure 4This is a schematic diagram of a tubing string for a thermal recovery well in a heavy oil reservoir at sea, provided as an embodiment of the present invention.

[0052] Figure 5 This is a schematic diagram of a wellbore micro-segment provided in an embodiment of the present invention;

[0053] Figure 6 This is a schematic diagram of the distribution of the steam injection end heating zone provided in an embodiment of the present invention;

[0054] Figure 7 The dimensionless temperature distribution in the hydrothermal zone provided in the embodiments of the present invention;

[0055] Figure 8 A flowchart of the model calculation steps provided in this embodiment of the invention;

[0056] Figure 9 This is a comparison chart of the predicted steam huff and puff capacity of a multi-layered heavy oil reservoir in an offshore oilfield, provided in an embodiment of the present invention.

[0057] The markings in the diagram are as follows:

[0058] 1. Steam injection pipe; 2. Casing; 3. Casing; 4. Insulation pipe; 5. Air layer; 6. Seawater section; 7. Mud section; 8. Formation. Detailed Implementation

[0059] 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, not all, of the embodiments of the present invention. All other embodiments obtained by those skilled in the art based on the described embodiments of the present invention are within the scope of protection of the present invention.

[0060] It should be noted that the terminology used herein is for the purpose of describing particular embodiments only and is not intended to limit the exemplary embodiments according to this application. As used herein, the singular form is intended to include the plural form as well, unless the context clearly indicates otherwise. Furthermore, it should be understood that when the terms "comprising" and / or "including" are used in this specification, they indicate the presence of features, steps, operations, devices, components, and / or combinations thereof.

[0061] In some embodiments of the present invention, a method for predicting the steam huff and puff production capacity of multi-layered heavy oil reservoirs at sea is provided. First, the production dynamic data of any sub-layer reservoir is determined, such as the oil production rate and cumulative oil production. Then, the production dynamic data of the entire multi-layered heavy oil reservoir is obtained by combining the production dynamic data of each sub-layer. When calculating the production dynamic data of any sub-layer reservoir, the bottom hole steam parameters are obtained based on a wellbore heat loss characterization model considering the characteristics of offshore thermal recovery wells. Then, based on the bottom hole steam parameters and the steam huff and puff production capacity prediction model, the daily oil production at different stages is calculated. This invention can achieve accurate evaluation of the production capacity in the early stages of offshore heavy oil huff and puff development.

[0062] Correspondingly, other embodiments of the present invention provide a steam huff and puff capacity prediction system, equipment, and storage medium for offshore multilayer heavy oil reservoirs.

[0063] Example 1

[0064] like Figure 1 As shown in the figure, this embodiment provides a method for predicting the steam huff and puff capacity of multi-layered heavy oil reservoirs at sea, which includes the following steps:

[0065] 1) Collect basic parameters of multi-layered heavy oil reservoirs at sea;

[0066] 2) Using the collected basic parameters and a pre-constructed wellbore heat loss characterization model that considers marine characteristics, the bottom hole steam parameters are calculated;

[0067] 3) Based on the bottom hole steam parameters and the pre-built steam throughput production prediction model, the production dynamics of each layer in the offshore multi-layer heavy oil reservoir are calculated.

[0068] Preferably, in step 1) above, the basic parameters collected for a multi-layered heavy oil reservoir at sea include wellbore structural parameters, steam injection parameters, and reservoir parameters. The wellbore structural parameters include riser length, steam injection pipe inner (outer) diameter, insulation pipe inner (outer) diameter, and wellbore vertical depth. The steam injection parameters include steam injection rate, wellhead steam dryness, wellhead injection temperature, and steam injection time. The reservoir parameters include the number of oil layers in the multi-layered reservoir, the permeability of each layer, the thickness of each layer, the initial reservoir pressure, the initial reservoir temperature, the initial reservoir porosity, the initial reservoir water saturation, the pore compressibility coefficient, the bottom hole flowing pressure, the reservoir heat capacity, the reservoir thermal conductivity, and the oil-water phase permeability relationship at different temperatures. Figure 2 Crude oil viscosity-temperature relationship Figure 3 )wait.

[0069] Preferably, in step 2) above, the wellbore heat loss characterization model pre-constructed in this embodiment, considering the characteristics of the marine environment, is divided into four parts: a pressure gradient calculation model along the wellbore, a heat transfer calculation model, a total heat transfer calculation model for the seawater section, and a steam dryness calculation model. Specifically, the calculation of the bottom hole steam parameters includes the following steps:

[0070] 2.1) The tubing string of thermal recovery wells in offshore heavy oil reservoirs is subdivided along the axial direction, and a pressure gradient calculation model along the friction is established based on the momentum conservation equation.

[0071] like Figure 4 The diagram shows a schematic of a thermal recovery well string for offshore heavy oil reservoirs. This string includes, from the inside out, a steam injection pipe, casing, insulation pipe, and riser. A gap is provided between the steam injection pipe and the casing for steam injection. The casing penetrates the air layer, seawater section, mud section, and formation sequentially from top to bottom. The insulation pipe is fitted outside the casing. The riser is located outside the insulation pipe and penetrates the air layer, seawater section, and mud section sequentially from top to bottom, entering the upper formation.

[0072] like Figure 5 As shown, a schematic diagram of the steam injection wellbore micro-segments is obtained by subdividing the thermal recovery well casing along the axial direction. Based on the momentum conservation equation, the calculation model for the saturated steam pressure loss (calculated along the pressure gradient) of the micro-segment is expressed as follows:

[0073]

[0074] Where, ρ m The average density of water vapor in the micro-element segment is kg / m³. 3 θ is the inclination angle of the micro-element segment, deg; ρ1 and ρ2 are the water vapor densities of the two cross sections before and after the micro-element segment, respectively, in kg / m³. 3 v1 and v2 are the water vapor velocities at the two cross sections before and after the micro-element, respectively, in m / s; τ f The frictional force on the water vapor in the infinitesimal segment is N; A is the cross-sectional area of ​​the infinitesimal segment, m. 2 dp is the pressure loss of the micro-element, MPa; dz is the length of the micro-element, m.

[0075] 2.2) Based on the steady-state heat transfer theory, heat transfer calculation models are established between the steam injection pipe and the outer edge of the cement sheath, and between the outer edge of the cement sheath and the formation.

[0076] According to steady-state heat transfer theory, the heat transfer calculation model from the steam injection pipe to the outer edge of the cement ring is expressed as follows:

[0077]

[0078] Where dQ represents the heat transfer of the micro-element, in W; T sm The average temperature of the infinitesimal segment is expressed in °C; T c R represents the outer edge temperature of the cement ring, in °C. C1 The total thermal resistance is expressed as:

[0079]

[0080] Where, λ tub λ represents the thermal conductivity of the steam injection pipe and the insulation pipe, in W / (m·℃); r1 and r2 are the inner and outer radii of the steam injection pipe, respectively, in meters; λ ins r3 is the thermal conductivity of the insulation material, W / (m·℃); r3 and r4 are the inner and outer radii of the insulation pipe, respectively, in meters; h c and h r These are the convective heat transfer coefficients of the annulus filled with air, in W / (m²). 2 ·℃); λ cas R is the thermal conductivity of the sleeve, W / (m·℃); ci and r co These are the inner and outer radii of the casing, respectively, in meters (m); λ cem The thermal conductivity of the cement ring is W / (m·℃); r h Let be the outer radius of the cement ring, in meters (m).

[0081] The calculation model for heat transfer between the outer edge of the cement sheath and the formation can be expressed as:

[0082]

[0083] Where, λ e T represents the thermal conductivity of the formation, in W / (m·℃); e Let be the formation temperature, in °C; f(t) is the dimensionless formation heat conduction time function, solved using the Hasan formula:

[0084]

[0085] Where, τ D For dimensionless thermal conduction time, α is the thermal diffusivity of the formation, m 2 / h; τ is the steam injection time, in hours.

[0086] 2.3) The heat transfer process between the seawater section and the mud section is processed, and a calculation model for the total heat transfer of the seawater section is established.

[0087] Assuming the seawater temperature remains constant, the heat transfer process between the steam injection wellbore and the seawater should be a steady-state heat transfer process; the mud section can also be treated as an isothermal zone (the heat transfer process between the seawater section and the mud section is treated as such). Therefore, the calculation model for the total heat transfer in the seawater section can be expressed as:

[0088]

[0089] Among them, T sw R represents the seawater temperature, in °C. C2 The total heat transfer resistance of the seawater section is expressed as:

[0090]

[0091] Where, λ iw The thermal conductivity of the riser pipe is given in W / (m·℃); r wi and r wo These are the inner and outer radii of the riser pipe, respectively, in meters (m); h sw The convective heat transfer coefficient of seawater is W / (m²). 2 ·℃).

[0092] 2.4) Consider the influence of wellbore friction loss on the steam dryness within the micro-element, and establish a steam dryness calculation model based on the energy conservation equation.

[0093] The steam dryness calculation model is expressed as follows:

[0094]

[0095]

[0096]

[0097] Where dQ is the total heat transfer of the infinitesimal element, W; dW is the work done by the water vapor friction in the infinitesimal element, W; H m The enthalpy of water vapor is kJ / kg; s v is the mass flow rate of water vapor, kg / s; m L represents the average velocity of water vapor in the micro-element segment, in m / s. v H represents the latent heat of vaporization, kJ / kg; x represents the dryness fraction of water vapor in the infinitesimal range, a decimal; H w ν is the enthalpy of saturated water, kJ / kg; g is the acceleration due to gravity, m / s². 2 .

[0098] 2.5) Based on the basic parameters of the collected multi-layer heavy oil reservoir, the subdivision micro-element method is used to solve the calculation models in steps 2.1) to 2.4). That is, the wellbore is divided into several micro-element segments, and the calculation is performed segment by segment from the wellhead to the bottom of the well to obtain the bottom-hole steam parameters, which include the bottom-hole steam temperature and steam dryness.

[0099] Preferably, in step 3) above, the production dynamics of each layer in a multi-layered heavy oil reservoir at sea are calculated based on the bottom hole steam parameters and a pre-built steam huff and puff production capacity prediction model, including the following steps:

[0100] 3.1) Let the number of layers j = 1, and use the bottom hole steam parameters and the pre-built steam huff and puff production capacity prediction model to calculate the production dynamics of different huff and puff cycles in the j-layer reservoir;

[0101] 3.2) Let the number of sub-layers j = j + 1, and compare the size of j with the number of sub-layers Z in the reservoir. If j > Z, stop the calculation; if j ≤ Z, repeat step 3.1) until the production dynamics of all sub-layers in the multi-layered heavy oil reservoir at sea are obtained.

[0102] Preferably, step 3.1) above includes the following steps:

[0103] 3.1.1) Let the number of cycles N = 1, divide the reservoir formation region of this small layer into steam zone, hydrothermal zone and cold zone at the end of the steam injection stage, and calculate the heating radius of each zone using the bottom hole steam parameters;

[0104] 3.1.2) Determine the average temperature T of the steam zone at the end of well steaming. savg Average temperature T of the hydrothermal zone havg Mean formation pressure P of the oil reservoir avg,s and average water saturation S w And calculate the daily oil production Q. o ;

[0105] 3.1.3) Determine the average temperature T of the steam zone during the production stage. as Average temperature T of the hydrothermal zone ah Mean formation pressure P of the oil reservoir avg,p and average water saturation S w Calculate the daily oil production Q o ;

[0106] 3.1.4) Let the number of cycles N = N + 1, and compare the number of cycles N with the number of throughput rounds N. max The size, such as N > N max The calculation ends here; proceed to step 3.1.2); if N≤N max Then calculate the residual heat E of the heating zone for that cycle. rs and E rh The residual heat in the heating zone is added to the heat injection for the next cycle of throughput, and then steps 3.1.1) to 3.1.3) are repeated to obtain the production dynamics of different throughput cycles of the small layer.

[0107] Preferably, step 3.1.1) above includes the following steps:

[0108] 3.1.1.1) At the end of the steam injection stage, the reservoir formation of this small layer is divided into three regions: steam zone, hydrothermal zone and cold zone, and the relationship between the radius and temperature of the hydrothermal zone is fitted.

[0109] like Figure 6As shown, in this embodiment, the reservoir formation is divided into three regions at the end of the steam injection stage: a steam zone, a hydrothermal zone, and a cold zone. The temperature in the steam zone is the saturated steam temperature, and the temperature distribution in the hydrothermal zone is determined using a numerical inversion method based on a laboratory-scale sand-filled pipe model.

[0110] For evaluating the production capacity of huff and puff wells during the thermal exploitation of heavy oil reservoirs, accurate characterization of reservoir temperature is crucial. Therefore, this invention employs a numerical inversion method based on a laboratory-scale sand-filled pipe model to study the temperature distribution patterns in hydrothermal zones. Specifically, the approach involves fitting a numerical simulation model to the oil production conditions of sand-filled pipe experiments, thereby obtaining the simulated temperature distribution results of the hydrothermal zone. Based on the hydrothermal zone temperature distribution, both the hydrothermal zone radius and temperature can be dimensionlessly processed to obtain a normalized hydrothermal zone temperature distribution (e.g., ...). Figure 7 As shown in the figure, the fitting results of the experimental data show that the dimensionless radius and dimensionless temperature of the hydrothermal zone conform to an exponential function distribution.

[0111] Dimensionless radius of hydrothermal region:

[0112]

[0113] Dimensionless temperature of hydrothermal zone:

[0114]

[0115] Based on the fitting results of the experimental data, the dimensionless temperature and dimensionless radius of the hydrothermal region satisfy the following relationship:

[0116]

[0117] Where r is the distance from the hydrothermal zone to the wellbore, in meters; r hl T is the radius of the hydrothermal zone, in meters. h (r) represents the temperature at a distance r from the wellhead, in °C; T s T represents the bottom-hole steam temperature in °C. i The original reservoir temperature is ℃.

[0118] 3.1.1.2) Divide the steam injection volume of each sub-layer according to the formation coefficient, and calculate the heating radius r of the steam zone using the bottom hole steam parameters and the pre-established calculation model of the heating radius of the steam zone and hydrothermal zone. s and the heating radius r of the hydrothermal zone h .

[0119] In multi-layered heavy oil reservoirs, permeable sub-layers are separated by impermeable layers. A general steam injection method is used to inject steam into the reservoir, assuming that steam can only penetrate the permeable sub-layers. Before determining the radius of the heating zone for each sub-layer, it is necessary to determine the amount of steam injected into each sub-layer, and to divide the steam injection amount into sub-layers according to the formation coefficient:

[0120]

[0121] Among them, I s Total steam injection rate, kg / d; Z is the number of reservoir layers; K j Let mD be the permeability of the j-th oil layer; h be the permeability of the j-th oil layer. j Let i be the thickness of the j-th oil layer, m; s,j Let be the steam injection rate of the j-th oil layer, in kg / d.

[0122] Considering the influence of steam overburden, we assume the steam zone is an inverted frustum centered on the huff and puff well. According to the law of conservation of energy, the rate of heat injection into the reservoir equals the sum of the heat loss rates of the top and bottom caprocks and the energy increase rate of the reservoir. Specifically for the steam zone, the injected heat is the latent heat of steam, and the heating radius at the bottom of the steam zone can be obtained as follows:

[0123]

[0124] Where, r b λ is the heating radius at the bottom of the steam zone, in meters; y is the ratio of the heating radii of the top and bottom cover layers; λ e ′ represents the thermal conductivity of the top and bottom cap layers, kJ / (d·m·℃); λ represents the ratio of the heat capacity of the oil layer to the heat capacity of the interlayer, λ=MR2 / MR1; MR1 is the heat capacity of the interlayer, kJ / (m 3 ·℃); MR2 is the heat capacity of the oil reservoir, kJ / (m³). 3 ·℃); t D For dimensionless steam injection time, t D =4λ e ′t / (MR1h j 2 ); t is the steam injection time, d.

[0125] To facilitate output calculation, the steam zone is considered equivalent to a cylinder. The equivalent heating radius of the steam zone can then be expressed as:

[0126]

[0127] According to the law of conservation of energy, the rate of heat injection into the reservoir is equal to the sum of the heat loss rates of the top and bottom caprocks and the energy increase rate of the reservoir. Specifically, in the hydrothermal zone, the injected heat is the enthalpy of saturated hot water, which can be obtained as follows:

[0128]

[0129] Among them, T h The temperature of the hydrothermal zone can be determined using equations (12) to (14):

[0130] T h (r)=T i +T D ·(Ts -T i (18)

[0131] F(r hl The equation ) = 0 is a nonlinear equation, and the radius of the hydrothermal region can be solved using Newton's iteration method.

[0132]

[0133] Where, r hl Where h is the radius of the hydrothermal zone, in meters; ws The enthalpy of saturated hot water, kJ / kg; h wr The enthalpy of water under the initial reservoir temperature conditions, kJ / kg; M R The reservoir heat capacity is expressed in kJ / (m³). 3 ·℃); α′ is the thermal diffusivity of the top and bottom of the reservoir, m 2 / d;erfc(x) is the error compensation function.

[0134] Preferably, step 3.1.2) above includes the following steps:

[0135] 3.1.2.1) Determine the average temperature T of the steam zone at the end of well steaming. savg and the average temperature T of the hydrothermal zone havg And based on the average temperature T in the steam zone savg and the average temperature T of the hydrothermal zone havg The mean formation pressure P of the reservoir was calculated. avg,s and average water saturation S w .

[0136] At the end of the steam injection stage, the steam zone temperature remains at the saturated steam temperature. During the well shut-in stage, considering the temperature decrease in the heating zone caused by heat conduction, including both vertical and radial heat losses, the calculation model for the average temperature of the steam zone at the end of the well shut-in stage is as follows:

[0137] T savg =T i +(T s -T i V rs V zs (20)

[0138] Among them, T savg V represents the average temperature of the steam zone at the end of the well steaming process, in °C. rs V is the radial heat loss coefficient in the steam zone. zs This is the vertical heat loss coefficient for the steam zone.

[0139] At the end of the steam injection stage, the average temperature (area-weighted average) of the hydrothermal zone can be expressed as:

[0140]

[0141] During the well-sealing process, the temperature drop caused by heat conduction needs to be considered. Similarly, the average temperature of the hydrothermal zone at the end of the well-sealing process can be obtained as follows:

[0142]

[0143] Among them, T havg V represents the average temperature of the hydrothermal zone at the end of the well-steaming process, in °C. rh V is the radial heat loss coefficient in the hydrothermal zone. zh This is the vertical heat loss coefficient in the hydrothermal zone.

[0144] During the steam injection stage, the injection of steam causes an increase in reservoir pressure. According to the mass balance equation, the volume of injected steam underground is equal to the sum of the expansion of pore volume and the compression of reservoir fluid volume. Therefore, at the end of the well shut-in process, the average formation pressure can be expressed as:

[0145]

[0146] Among them, P avg,s P represents the average formation pressure at the end of well shut-in, in MPa; i Initial reservoir pressure, MPa; G w The cumulative steam injection volume (equivalent to ground-level cold water) is expressed in m. 3 B w is the volume factor of water; N is the geological reserves of crude oil in the spillway, in m³. 3 B o C is the crude oil volume coefficient; e The overall compression ratio is expressed in MPa. -1 N os For the geological reserves of crude oil in the steam zone, m 3 ;β e To take into account the coefficient of thermal expansion, ℃ -1 N oh For the geological reserves of crude oil in the hydrothermal vent area, m 3 .

[0147] According to the mass conservation law of the aqueous phase, the average water saturation in the heating zone is equal to the sum of the initial water saturation and the changes in water saturation caused by steam injection during the steam injection stage and water production during the production stage. Therefore, water saturation can be expressed as:

[0148]

[0149] Among them, S wi d represents the bound water saturation. wi The density of water at the initial moment, kg / m³ 3 ;d wThe density of water during the production stage, kg / m³ 3 φ represents the formation porosity.

[0150] 3.1.2.2) Based on the calculated mean formation pressure P of the reservoir avg,s Using a pre-built steam injection capacity prediction model, the daily oil production at the end of well shut-in was calculated.

[0151] Based on a quasi-steady-state production capacity model with a three-zone composite strata, a circular closed boundary, and a central single-well injection / pumping system, a steam development production capacity model for multi-layer directional wells can be derived:

[0152]

[0153]

[0154]

[0155]

[0156] Among them, Q o Daily oil production, m 3 / d;P avg P represents the mean formation pressure of the reservoir, in MPa; wf R is the bottom hole flowing pressure, MPa; TPG is the starting pressure gradient, MPa / m; o1 R o2 R o3 These represent the crude oil seepage resistance in the steam zone, hydrothermal zone, and cold zone, respectively, in MPa·d / m. 3 ;r e and r w These represent the drain radius and wellbore radius, respectively, in meters; K is the absolute permeability of the reservoir, in meters; K ros K roh and K roc The relative permeability of the oil phase in the steam zone, hydrothermal zone, and cold zone are respectively; μ os μ oh and μ oc The crude oil viscosities (mPa·s) for the steam zone, hydrothermal zone, and cold zone are respectively; S is the skin coefficient; t p d represents production time; M represents throughput rounds.

[0157] At low reservoir temperatures, heavy oil exhibits a non-Newtonian fluid state, necessitating consideration of the impact of the start-up pressure gradient on production capacity in the model. Based on experimental data, a start-up pressure gradient model based on mobility was constructed. The model showed a high degree of fit between the experimental data and the correlation equation, exhibiting a power-law relationship. According to the fitting results of the experimental data, the start-up pressure gradient and mobility satisfy the following relationship:

[0158]

[0159] Preferably, step 3.1.3 above includes the following steps:

[0160] 3.1.3.1) Determine the production stage and the average temperature T in the steam zone. as and the average temperature T of the hydrothermal zone ah And based on the average temperature T in the steam zone as and the average temperature T of the hydrothermal zone ah The mean formation pressure P of the reservoir was calculated. avg,p and average water saturation S w .

[0161] During the production stage, the heat carried by the produced fluid also needs to be considered. The average temperature of the steam zone can be expressed as:

[0162] T as (t p ,M,j)=T i +(T s -T i (V) rs V zs (1-O s )-O s (30)

[0163] Among them, T as The average temperature of the steam zone during the production phase is expressed in °C; t p For production time, d; M is the throughput cycle; j is the j-th oil layer; O s The temperature of the dimensionless liquid produced in the steam zone.

[0164] Similarly, the average temperature of the hydrothermal zone during the production stage can be expressed as:

[0165]

[0166] Among them, T ah The average temperature of the hydrothermal zone during the production phase, in °C; O h The temperature at which the hydrothermal fluid is produced is dimensionless.

[0167] Similarly, during the production phase, the production of fluid causes a decrease in reservoir pressure. The underground volume of the produced fluid equals the sum of the reservoir fluid volume expansion and pore volume compression. Therefore, during the production phase, the mean formation pressure of the reservoir can be expressed as:

[0168]

[0169] Among them, P avg,p The mean reservoir pressure during the production phase is expressed in MPa and N. w For cumulative water production, m 3 N oFor cumulative oil production, m 3 .

[0170] 3.1.3.2) Based on the calculated mean formation pressure P of the reservoir avg,p Based on the pre-built steam development capacity model, the daily oil production during the production phase is calculated.

[0171] Preferably, in step 3.1.4) above, when starting a new huff and puff cycle, the influence of residual heat from the previous cycle needs to be considered. In the model, starting from the second cycle, the method for handling residual heat is to assume that the reservoir temperature is still the initial reservoir temperature before steam injection begins, and the influence of residual heat is reflected in the calculation of the heating zone radius for the next huff and puff cycle. The periodic residual heat of the steam zone and the hydrothermal zone can be expressed as follows:

[0172] E rs =πr s 2 h j M R (T as (t p ,M,j)-T i (33)

[0173] E rh =π(r hl 2 -r s 2 )h j M R (T ah (t p ,M,j)-T i (34)

[0174] Among them, E rs E represents the periodic waste heat of the steam zone, in kJ. rh The residual heat of the hydrothermal zone during the cycle is expressed in kJ.

[0175] Example 2

[0176] refer to Figures 1 to 8 Using the wellbore structure parameters, reservoir parameters, and steam injection parameters (Table 1) of a certain offshore oilfield as input parameters for the model, this method was applied to calculate its steam huff and puff capacity. Finally, the calculation results were compared with the CMG numerical simulation results. Figure 9 As shown in the figure, the maximum daily oil production decreases with increasing huff and puff cycles, mainly due to the gradual decrease in formation pressure as fluid is produced. The production capacity calculation results of this invention agree well with the CMG simulation results. The comparison results demonstrate that this invention can be used to evaluate the initial production capacity of multi-layered heavy oil reservoirs.

[0177] Table 1 Basic Parameters Table

[0178]

[0179]

[0180] Example 3

[0181] The above-described embodiment 1 provides a method for predicting the steam injection capacity of multi-layered heavy oil reservoirs at sea. Correspondingly, this embodiment provides a system for predicting the steam injection capacity of multi-layered heavy oil reservoirs at sea. The system provided in this embodiment can implement the steam injection capacity prediction method for multi-layered heavy oil reservoirs at sea as described in embodiment 1. This system can be implemented through software, hardware, or a combination of both. For example, the system may include integrated or separate functional modules or units to execute the corresponding steps in the methods of embodiment 1. Since the system in this embodiment is basically similar to the method embodiment, the description process in this embodiment is relatively simple. For relevant details, please refer to the description of embodiment 1. The system embodiment provided in this embodiment is merely illustrative.

[0182] The steam huff and puff production capacity prediction system for multi-layered heavy oil reservoirs at sea provided in this embodiment includes:

[0183] The data acquisition module is used to collect basic parameters of multi-layered heavy oil reservoirs at sea;

[0184] The bottom hole steam parameter calculation module is used to calculate the bottom hole steam parameters using the collected basic parameters and a pre-built wellbore heat loss characterization model that takes into account the characteristics of the sea.

[0185] The reservoir integrated production capacity prediction module is used to calculate the production dynamics of different steam injection cycles in multi-layer heavy oil reservoirs by utilizing bottom hole steam parameters and a pre-built steam injection production capacity prediction model.

[0186] Example 4

[0187] This embodiment provides a processing device corresponding to the steam huff and puff capacity prediction method for offshore multi-layer heavy oil reservoirs provided in Embodiment 1. The processing device can be a client-side processing device, such as a mobile phone, laptop, tablet computer, desktop computer, etc., to execute the method of Embodiment 1.

[0188] The processing device includes a processor, a memory, a communication interface, and a bus. The processor, memory, and communication interface are connected via the bus to enable communication between them. The memory stores a computer program that can run on the processor. When the processor runs the computer program, it executes the steam huff and puff production capacity prediction method for multi-layered heavy oil reservoirs at sea provided in Embodiment 1.

[0189] In some embodiments, the memory may be high-speed random access memory (RAM), and may also include non-volatile memory, such as at least one disk storage device.

[0190] In other embodiments, the processor can be a general-purpose processor of various types, such as a central processing unit (CPU) or a digital signal processor (DSP), and is not limited thereto.

[0191] Example 5

[0192] The steam injection capacity prediction method for offshore multi-layered heavy oil reservoirs in Embodiment 1 can be specifically implemented as a computer program product. The computer program product may include a computer-readable storage medium on which computer-readable program instructions for executing the steam injection capacity prediction method for offshore multi-layered heavy oil reservoirs described in Embodiment 1 are loaded.

[0193] A computer-readable storage medium can be a tangible device that holds and stores instructions for use by an instruction execution device. A computer-readable storage medium can be, for example, but not limited to, an electrical storage device, a magnetic storage device, an optical storage device, an electromagnetic storage device, a semiconductor storage device, or any combination thereof.

[0194] Finally, it should be noted that the above embodiments are only used to illustrate the technical solutions of the present invention, and not to limit them; although the present invention has been described in detail with reference to the foregoing embodiments, those skilled in the art should understand that modifications can still be made to the technical solutions described in the foregoing embodiments, or equivalent substitutions can be made to some of the technical features; and these modifications or substitutions do not cause the essence of the corresponding technical solutions to deviate from the spirit and scope of the technical solutions of the embodiments of the present invention.

Claims

1. A method for predicting the steam huff and puff production capacity of multi-layered heavy oil reservoirs at sea, characterized in that, Includes the following steps: Basic parameters of multi-layered heavy oil reservoirs at sea were collected; Using the collected basic parameters and a pre-constructed wellbore heat loss characterization model that considers marine characteristics, the bottom hole steam parameters are calculated. Based on bottom hole steam parameters and a pre-built steam huff and puff production capacity prediction model, the production dynamics of each layer in a multi-layered heavy oil reservoir at sea are calculated. The calculation of bottom hole steam parameters using the collected basic parameters and a pre-constructed wellbore heat loss characterization model considering marine characteristics includes the following steps: The tubing string of thermal recovery wells in offshore heavy oil reservoirs is subdivided along the axial direction, and a pressure gradient calculation model along the friction is established based on the momentum conservation equation. Based on the steady-state heat transfer theory, calculation models for heat transfer between the steam injection pipe string and the outer edge of the cement sheath, and between the outer edge of the cement sheath and the formation, are established respectively. The heat transfer process between the seawater section and the mud section is processed, and a calculation model for the total heat transfer in the seawater section is established. Considering the influence of wellbore friction loss on steam dryness within a micro-element, a steam dryness calculation model is established based on the energy conservation equation. Based on the collected basic parameters, the above calculation models are solved using the subdivision micro-element method to obtain the bottom hole steam parameters, which include bottom hole steam temperature and steam dryness.

2. The method for predicting the steam huff and puff production capacity of a multi-layered heavy oil reservoir at sea as described in claim 1, characterized in that, The production dynamics of each layer in a multi-layered heavy oil reservoir at sea are calculated based on bottom-hole steam parameters and a pre-built steam huff and puff production prediction model, including: Let the smaller layer number j = 1; Using bottom hole steam parameters and a pre-built steam huff and puff production capacity prediction model, the production dynamics of different huff and puff cycles in reservoir j were calculated. Let the number of layers be small ,Compare and Size, such as Then stop the calculation; if Then repeat the previous step until the production dynamics of each layer in a multi-layered heavy oil reservoir at sea are obtained, among which... This refers to a small number of layers in an oil reservoir.

3. The method for predicting the steam huff and puff production capacity of a multi-layered heavy oil reservoir at sea as described in claim 2, characterized in that, The production dynamics of different injection cycles in reservoir j are calculated using bottom-hole steam parameters and a pre-built steam injection production prediction model, including: ① Let the number of cycles N=1, divide the reservoir formation area of ​​this small layer into steam zone, hydrothermal zone and cold zone at the end of the steam injection stage, and calculate the heating radius of each zone using the bottom hole steam parameters; ② Determine the average temperature of the steam zone after well shut-in Average temperature of hydrothermal zone Mean formation pressure of oil reservoir and average water saturation And calculate daily oil production. ; ③ Determine the average temperature of the steam zone during the production stage Average temperature of hydrothermal zone Mean formation pressure of oil reservoir and average water saturation Calculate daily oil production ; ④ Let the number of cycles ,Compare With throughput rounds Size, such as The calculation ends here; proceed to the next step. Then calculate the residual heat of the heating zone for that cycle. and The residual heat from the heating zone is added to the heat injection for the next cycle of throughput, and then steps ① to ③ are repeated to obtain the production dynamics of different throughput cycles for a specific small layer.

4. The method for predicting the steam huff and puff production capacity of a multi-layered heavy oil reservoir at sea as described in claim 3, characterized in that, The process of dividing the reservoir formation into zones at the end of the steam injection stage and calculating the heating radius of each zone using bottom-hole steam parameters includes: At the end of the steam injection stage, the formation area is divided into three regions: steam zone, hydrothermal zone, and cold zone. The steam injection volume of each sub-layer is divided according to the formation coefficient, and the heating radius of the steam zone and the hydrothermal zone are calculated using the bottom hole steam parameters and the pre-established calculation model of the heating radius of the steam zone and the hydrothermal zone.

5. The method for predicting the steam huff and puff production capacity of a multi-layered heavy oil reservoir at sea as described in claim 3, characterized in that, The average temperature of the steam zone at the end of well steaming was determined. Average temperature of hydrothermal zone Mean formation pressure of oil reservoir and average water saturation And calculate daily oil production. ,include: Determine the average temperature of the steam zone at the end of well steaming. and the average temperature of the hydrothermal zone And based on the average temperature of the steam zone and the average temperature of the hydrothermal zone The mean formation pressure of the reservoir was calculated. and average water saturation ; Based on the calculated average formation pressure of the reservoir Using a pre-built steam injection capacity prediction model, the daily oil production at the end of well shut-in was calculated.

6. The method for predicting the steam huff and puff production capacity of a multi-layered heavy oil reservoir at sea as described in claim 3, characterized in that, The determination of the average temperature of the steam zone during the production stage Average temperature of hydrothermal zone Mean formation pressure of oil reservoir and average water saturation Calculate daily oil production ,include: Determine the production stage and the average temperature of the steam zone. and the average temperature of the hydrothermal zone And based on the average temperature of the steam zone and the average temperature of the hydrothermal zone The mean formation pressure of the reservoir was calculated. and average water saturation ; Based on the calculated average formation pressure of the reservoir Based on the pre-built steam development capacity model, the daily oil production during the production phase is calculated.

7. A steam huff and puff production capacity prediction system for offshore multi-layered heavy oil reservoirs, characterized in that... include: The data acquisition module is used to collect basic parameters of multi-layered heavy oil reservoirs at sea; The bottom hole steam parameter calculation module is used to calculate the bottom hole steam parameters using the collected basic parameters and a pre-built wellbore heat loss characterization model that takes into account the characteristics of the sea. The reservoir integrated production capacity prediction module is used to calculate the production dynamics of different injection cycles in multi-layer heavy oil reservoirs by utilizing bottom hole steam parameters and a pre-built steam injection production capacity prediction model. The bottom hole steam parameters are calculated using the collected basic parameters and a pre-constructed wellbore heat loss characterization model that considers marine characteristics, including: The tubing string of thermal recovery wells in offshore heavy oil reservoirs is subdivided along the axial direction, and a pressure gradient calculation model along the friction is established based on the momentum conservation equation. Based on the steady-state heat transfer theory, calculation models for heat transfer between the steam injection pipe string and the outer edge of the cement sheath, and between the outer edge of the cement sheath and the formation, are established respectively. The heat transfer process between the seawater section and the mud section is processed, and a calculation model for the total heat transfer in the seawater section is established. Considering the influence of wellbore friction loss on steam dryness within a micro-element, a steam dryness calculation model is established based on the energy conservation equation. Based on the collected basic parameters, the above calculation models are solved using the subdivision micro-element method to obtain the bottom hole steam parameters, which include bottom hole steam temperature and steam dryness.

8. A processing apparatus, the processing apparatus comprising at least a processor and a memory, the memory storing a computer program, characterized in that, When the processor runs the computer program, it performs the steps of predicting the steam injection capacity of a multi-layered heavy oil reservoir at sea according to any one of claims 1 to 6.

9. A computer storage medium, characterized in that, It stores computer-readable instructions that can be executed by a processor to implement the steps of the method for predicting the steam huff and puff capacity of offshore multi-layered heavy oil reservoirs according to any one of claims 1 to 6.

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