Information processing apparatus and information processing method

Abstract

To provide an information processor and an information processing method for simplifying the optimization of the press-in section of CCS.SOLUTION: The setting unit 1 sets an injection section by changing an upper end position in a depth direction of the injection section with respect to an injection well in a reservoir model to which data of a reservoir storing carbon dioxide and data of the injection well disposed in the reservoir are given. Further, the setting unit 1 sets the pressure of the carbon dioxide in the injection well at the upper end position in the depth direction of the injection section with respect to the set injection section. The calculation unit 2 calculates the injection rate for the set injection section based on the density of the carbon dioxide in the injection well, the viscosity of the carbon dioxide in the injection well, and the pressure of the carbon dioxide in the injection well at each position in the depth direction of the injection section. The determination part 3 determines a press-fitting section in which the calculated press-fitting rate indicates a maximum value.SELECTED DRAWING: Figure 1

Description

[Technical Field]

[0001] The present invention relates to an information processing device and an information processing method. [Background technology]

[0002] In recent years, there has been active development of technologies related to carbon dioxide capture and storage (CCS), and related inventions have been published. For example, Patent Document 1 discloses an underground carbon dioxide storage facility that uses a natural geological layer capable of blocking carbon dioxide as a shielding layer and stores carbon dioxide in a geological layer below the shielding layer. This underground storage facility is configured by injecting grout into the geological layer directly below the shielding layer to form an artificial shield that can block carbon dioxide integrally with the shielding layer, and by using the shielding layer to define a storage area for storing carbon dioxide in the geological layer below the shielding layer. [Prior art documents] [Patent documents]

[0003] [Patent Document 1] Japanese Patent Application Laid-Open No. 2011-147869 Summary of the Invention [Problem to be solved by the invention]

[0004] In CCS, CO2 is injected into a reservoir (storage area) through an injection well. The injection well is protected by a non-perforated casing to prevent the borehole walls from collapsing. Of the entire casing section, the injection section into which CO2 is injected is determined, and holes are made in the injection section using explosives or other means (perforation). Here, it is rational to optimize the injection section to enable more CO2 to be injected. However, optimizing the injection section requires enormous calculation costs and time, and is not easy. Prior art, including the invention of Patent Document 1, does not even raise the issue of optimizing the injection section.

[0005] From this perspective, an object of the present invention is to propose an information processing device and an information processing method that simplify the optimization of the injection section of a CCS. [Means for solving the problem]

[0006] The present invention provides a first setting step of setting an injection section by changing a depthwise upper end position of the injection section for the injection well in a reservoir model given data on a reservoir that stores carbon dioxide and data on an injection well to be placed in the reservoir; A second setting step of setting a pressure of carbon dioxide in the injection well at an upper end position in a depth direction of the set injection section; a calculation step of calculating an injection rate for the set injection section based on the density of carbon dioxide in the injection well, the viscosity of carbon dioxide in the injection well, and the pressure of carbon dioxide in the injection well at each position in the depth direction of the injection section; and a determining step of determining an injection section in which the calculated injection rate shows a maximum value. The present invention also provides a first setting unit that sets an injection section by changing a depthwise upper end position of the injection section for the injection well in a reservoir model given data on a reservoir that stores carbon dioxide and data on an injection well to be placed in the reservoir; a second setting unit that sets a pressure of carbon dioxide in the injection well at an upper end position in a depth direction of the set injection section; a calculation unit that calculates an injection rate for the set injection section based on the density of carbon dioxide in the injection well, the viscosity of carbon dioxide in the injection well, and the pressure of carbon dioxide in the injection well at each position in the depth direction of the injection section; a determination unit that determines an injection section in which the calculated injection rate shows a maximum value. With this configuration, there is no need to perform trial and error simulations of carbon dioxide injection using CCS, as in the past, which reduces calculation costs and shortens calculation time.

[0007] In addition, in the second setting step, it is preferable that the pressure of carbon dioxide in the injection well at the upper end position in the depth direction of the injection section is set to be a predetermined pressure lower than the formation fracture pressure at the upper end position in the depth direction. This can improve the efficiency of carbon dioxide injection.

[0008] In addition, in the calculation step, it is preferable to calculate the injection rate based on at least one of the following [1] to [4]. [1]: The relative permeability of carbon dioxide to water in the reservoir around the injection well at each depth position in the injection section is 1. [2]: The pressure in the reservoir around the injection well is constant at each depth position in the injection section. [3]: The pressure of carbon dioxide in the injection well at each depth position of the injection section is equal to or greater than the pressure of water in the reservoir surrounding the injection well at each depth position of the injection section. [4]: The value indicating the skin effect due to the placement of the injection well is constant. This makes it possible to further reduce calculation costs and calculation time while maintaining a desired calculation accuracy.

[0009] In addition, in the second setting step, a temperature of carbon dioxide in the injection well at an upper end position in the depth direction of the injection section is set, In the calculation step, It is preferable to determine the pressure, density, and viscosity of carbon dioxide in the injection well at each position in the depth direction of the injection section by repeated calculation using the temperature of carbon dioxide in the injection well at each position in the depth direction of the injection section. This avoids underestimating the carbon dioxide in the injection well. [Effects of the Invention]

[0010] According to the present invention, it is possible to easily optimize the injection section of a CCS. [Brief explanation of the drawings]

[0011] [Figure 1] FIG. 1 is a functional configuration diagram of an information processing apparatus according to an embodiment of the present invention. [Figure 2] FIG. 1 is an explanatory diagram of a perforation pattern (part 1). [Figure 3] FIG. 10 is an explanatory diagram of a perforation pattern (part 2). [Figure 4] FIG. 1 is an explanatory diagram of a reservoir model. [Figure 5] FIG. 1 is an explanatory diagram of a skin effect. [Figure 6] 1 is an example of a flowchart illustrating an information processing method according to an embodiment of the present invention. [Figure 7] FIG. 1 is a schematic diagram of a well grid arranged in the depth direction in the injection section. [Figure 8] 1 is an example of a flowchart for calculating the pressure, density, and viscosity of carbon dioxide in each well grid arranged in the injection section. DETAILED DESCRIPTION OF THE INVENTION

[0012] Hereinafter, embodiments of the present invention will be described in detail with reference to the accompanying drawings. Each drawing is merely a schematic illustration to allow a sufficient understanding of the present invention. Therefore, the present invention is not limited to the illustrated examples. In each drawing, common or similar components are designated by the same reference numerals, and redundant explanations thereof will be omitted.

[0013] [composition] FIG. 1 is a functional configuration diagram of an information processing device according to this embodiment. The information processing device 100 is a computer that evaluates the amount of carbon dioxide that can be injected using CCS. The information processing device 100 is a computer equipped with hardware such as an input unit, an output unit, a control unit, and a storage unit. For example, if the control unit is configured from a CPU (Central Processing Unit), information processing by a computer including the control unit is realized by program execution processing by the CPU. Furthermore, the storage unit included in the computer stores various programs for realizing the functions of the computer in response to instructions from the CPU. This realizes collaboration between software and hardware. The programs can be provided by recording them on a recording medium or via a network. Furthermore, the storage unit may be implemented as a cloud.

[0014] The information processing device 100 includes a setting unit 1, a calculation unit 2, and a determination unit 3. The information processing device 100 also stores a reservoir model 4. The reservoir model 4 is a virtual model of the ground to which CCS is applied. CCS requires a reservoir layer located at a predetermined underground depth (e.g., 1 km or greater) that stores carbon dioxide, and a shielding layer located above the reservoir layer that shields the stored carbon dioxide. The reservoir layer may be, for example, but is not limited to, a sandstone layer containing water. The shielding layer may be, for example, but is not limited to, a mudstone layer. For example, the reservoir model 4 can associate the results of a geological survey at each location of the reproduced ground. The results of the geological survey may be, for example, but are not limited to, soil components (e.g., elemental analysis results), hydraulic parameters including absolute water permeability and absolute carbon dioxide permeability at each location of the ground. The geological survey may be, for example, but is not limited to, a drilling survey or an elastic wave survey. The drilling survey may be, for example, but is not limited to, laboratory testing of cores obtained by drilling or logging using a borehole. Elastic wave exploration can provide the velocity distribution of elastic waves over a wide area of ​​a site, which can be used to estimate the distribution of hydraulic parameters.

[0015] Therefore, the reservoir model 4 can provide data such as hydraulic parameters for the reservoir. The reservoir model 4 also includes a well model as data for the injection well. The injection well is a well that extends from a predetermined position on the surface in the depth direction to reach the inside of the reservoir, and enables carbon dioxide to be injected into the reservoir. The well model is a model that virtually reproduces the injection well.

[0016] The setting unit 1 makes various settings for the reservoir model 4. For example, the setting unit 1 can set an injection section for a well model. The injection section is a section of the entire surrounding wall of the injection well where holes are formed that can inject carbon dioxide from the injection well into the reservoir. The setting unit 1 can set the injection section in the well model by changing the upper end position of the injection section in the depth direction. Furthermore, the setting unit 1 can set the pressure of carbon dioxide in the injection well at the upper end position of the injection section in the depth direction in the well model.

[0017] The calculation unit 2 performs various calculations using the reservoir model 4. For example, the calculation unit 2 calculates an injection rate for an injection section based on the density of carbon dioxide in the injection well, the viscosity of carbon dioxide in the injection well, and the pressure of carbon dioxide in the injection well at each position in the depth direction of the injection section. The injection rate is a value that indicates the carbon dioxide injection performance. The determination unit 3 determines the injection section in which the calculated injection rate is at the maximum value.

[0018] (Perforation details) Figure 2 is an explanatory diagram of a perforation pattern (part 1). An injection well 10 is drilled from the ground in the depth direction (Z direction) using a specified drilling machine (not shown), and then the sides of the drilled well are covered with cementing 11, and the cementing 11 is further protected with a casing 12. The drilling and protection by the cementing 11 and casing 12 can be repeated in multiple stages in the depth direction. As a result, an injection well 10 can be formed that penetrates the shielding layer 13 and reaches the reservoir 14.

[0019] For the portion of the injection well 10 buried in the reservoir 14, holes 15 can be drilled (perforated) in the peripheral wall surface of the injection well 10 along the axial direction of the injection well 10 using explosives or the like. As a result, carbon dioxide can be injected into the injection well 10 by operating a pump (not shown) installed on the ground. When injecting carbon dioxide, the pressure inside the injection well 10 is made greater than the water pressure in the reservoir 14. This makes it possible to prevent backflow of water into the injection well 10. Here, the condition that the pressure inside the injection well 10 is greater than the water pressure in the reservoir 14 needs to be satisfied throughout the section in which the holes 15 are formed. The depth section in which the holes 15 are formed is the injection section.

[0020] Graph 16 of FIG. 2 shows the water pressure (hydrostatic pressure) P of the reservoir 14 in the depth direction (Z direction). r and the pressure of carbon dioxide (static CO2 pressure) P w The line 18 shows the change in pressure P of water. The density of water is greater than the density of carbon dioxide. Therefore, as depth increases, the pressure P of water r The increase in the pressure of carbon dioxide P w In other words, as the depth increases, the water pressure P r and the pressure of carbon dioxide P w The pressure difference ΔP1 between the pressure at the bottom and the pressure at the bottom decreases. Therefore, as the depth increases, the carbon dioxide injection performance at each depth position decreases. Also, carbon dioxide tends to accumulate upward due to buoyancy. For this reason, the decrease in injection performance becomes more pronounced. Also, the pressure P w The change in pressure P of carbon dioxide to the injection well 10 is generally nonlinear, but for convenience of calculation, it may be assumed to be linear. w Although the amount of carbon dioxide injected into the reservoir 14 can be increased by increasing the value of the pressure, the above-mentioned circumstances must be taken into consideration.

[0021] (Geological formation burst pressure) Also, the pressure P of carbon dioxide on the injection well 10 wIt is preferable to consider the formation failure pressure for the above. The formation failure pressure is the minimum pressure that can be applied to the formation without causing the formation to fail. The reservoir model 4 can be provided with the formation failure pressure at each position of the ground (particularly the reservoir) as a result of a geological survey.

[0022] A leak-off test can be used to measure formation fracture pressure. A leak-off test involves drilling a well just short of the target location, cementing the excavated section, then drilling a small distance to form an open-hole at the target location, and pouring mud into the open-hole to determine the maximum mud density. The leak-off test is well-known, so a detailed explanation is omitted. Formation fracture pressure can be determined from the maximum mud density and depth. It is generally reasonable to assume that the maximum mud density obtained in a leak-off test represents the same maximum mud density in the rock mass surrounding the open-hole. The reservoir model 4 can include the formation fracture pressure and maximum mud density at each location in the reproduced ground (especially the reservoir) as a result of geological surveys.

[0023] Graph 16 in Figure 2 shows line 19, which indicates the change in formation rupture pressure with depth (Z direction). It is common and reasonable to consider formation rupture pressure as a linear function of depth. As shown by line 19, the formation rupture pressure increases as the depth increases.

[0024] The pressure P of carbon dioxide in the injection well 10 w is preferably smaller than the formation fracture pressure at each position in the depth direction. In view of the low density of carbon dioxide, the increase in the formation fracture pressure is proportional to the pressure P w Therefore, the pressure P of carbon dioxide in the injection well 10 at the top end position in the depth direction of the injection section becomes larger than the increase in the pressure P w is smaller than the formation fracture pressure, the pressure P of carbon dioxide in the injection well 10 is wOn the other hand, since there is also a desire to maximize the injection performance, for example, the pressure P of carbon dioxide in the injection well 10 at the top end position in the depth direction of the injection section w It is preferable to set the pressure P of the carbon dioxide in the injection well 10 to 0.9 times the formation fracture pressure. w is preferably set to be smaller than the formation fracture pressure by a predetermined pressure.

[0025] 2 shows an example in which a hole 15 is formed throughout the entire portion of the injection well 10 that is buried in the reservoir 14, and the buried portion is the injection section. In other words, the upper end position of the injection section in the depth direction is at (slightly below) the boundary between the shielding layer 13 and the reservoir 14. Figure 3 is an explanatory diagram of a perforation pattern (part 2). In explaining Figure 3, explanations of parts that overlap with Figure 2 will be omitted, and differences will be explained. Figure 3 is an explanatory diagram of a geological formation in which an injection well 10 is formed, where a mudstone layer 13a is mixed in with a reservoir layer 14 that exists below a shielding layer 13. The mudstone layer 13a is an example of a layer that shields carbon dioxide. The injection well 10 reaches the reservoir layer 14 below the mudstone layer 13a.

[0026] In the case of pattern (2) of Figure 3, it is preferable to shorten the injection section compared to pattern (1) of Figure 2. Specifically, it is preferable to drill holes 15a in the wall surface of the injection well 10 along the axial direction of the injection well 10 using explosives or the like for the portion of the injection well 10 that is buried in the reservoir 14 below the mudstone layer 13a. In other words, the upper end position (perforation top) of the injection section in the depth direction of pattern (2) of Figure 3 is lower than the lower end position of the injection section in the depth direction of pattern (1) of Figure 2. For ease of explanation, the lower end position of the injection section in the depth direction of pattern (2) of Figure 3 is assumed to be the same as the lower end position of the injection section in the depth direction of pattern (1) of Figure 2.

[0027] At this time, perforation is not performed on the portion of the injection well 10 that is buried in the mudstone layer 13a. Also, perforation is not performed on the portion of the injection well 10 that is buried in the reservoir layer 14 that exists between the shielding layer 13 and the mudstone layer 13a. In other words, two or more injection sections are not prepared (although this does not prevent the preparation of more than two injection sections, for the sake of convenience of explanation, this case is not mentioned in this embodiment).

[0028] Graph 20 of FIG. 3 shows, in addition to lines 17 to 19 shown in graph 16 of FIG. 2, the pressure (static CO pressure) P of carbon dioxide in injection well 10 in pattern (part 2) of FIG. w In the case of the pattern (2) of FIG. 3, shortening the injection section increases the formation fracture pressure at the upper end position of the injection section in the depth direction. According to the setting policy described above, the pressure P of carbon dioxide in the injection well 10 at the upper end position of the injection section in the depth direction is larger than that in the pattern (1) of FIG. w In other words, the water pressure P at the top end position in the depth direction of the injection section can be made larger (see reference numeral 22). r and the pressure of carbon dioxide P w The differential pressure ΔP2 between the injection zone and the pressure vessel can be set to be larger than the differential pressure ΔP1. Therefore, depending on the dimensions of the injection section, it may be possible to improve the carbon dioxide injection performance in the pattern (2) of Figure 3 compared to the case of the pattern (1) of Figure 2.

[0029] (Method for evaluating carbon dioxide injection performance) A method for evaluating carbon dioxide injection performance using a reservoir model 4 will be described. FIG. 4 is an explanatory diagram of the reservoir model. The reservoir model 4 has a reservoir region 41, a shielding layer region 42, and a well region 43. Note that although the reservoir model 4 can be constructed as a three-dimensional model, FIG. 4 shows it as a two-dimensional cross-sectional model cut in the depth direction.

[0030] The reservoir region 41 is a region that simulates a reservoir. The setting unit 1 can set a reservoir grid 44 for the reservoir region 41. The reservoir grid 44 is a rectangular analysis grid used for calculations by the calculation unit 2. The dimensions of each side of the reservoir grid 44 can be designed as appropriate. In this embodiment, the grid thickness (dimension in the depth direction) of each reservoir grid 44 is H. For each reservoir grid 44, the setting unit 1 can set data such as hydraulic parameters at the position of the reservoir corresponding to the position of the reservoir grid 44.

[0031] The shielding layer region 42 is a region that simulates a shielding layer. The setting unit 1 does not need to create an analysis grid for the shielding layer region 42, but setting one is not prohibited. For example, the setting unit 1 can set the absolute permeability of carbon dioxide as a hydraulic parameter to 0 for the shielding layer region 42.

[0032] The well region 43 is a region that simulates an injection well. The setting unit 1 can set a well grid 45 for the well region 43. The well grid 45 is a rectangular analysis grid used for calculations by the calculation unit 2. The dimensions of each side of the well grid 45 can be designed as appropriate, and do not have to be the same as the dimensions of the reservoir grid 44, although it is not prohibited to make them the same. Furthermore, the dimensions of each well grid do not have to be the same, but it is not prohibited to make them the same.

[0033] 4, the reservoir region 41 is made up of a plurality of layers 41a to 41e, which simulates a heterogeneous reservoir. The setting unit 1 can set a reservoir lattice 44 for each of the layers 41a to 41e. The setting unit 1 can set different values ​​of absolute permeability of carbon dioxide for the reservoir lattice 44 set for each of the layers 41a to 41e.

[0034] Carbon dioxide injection performance can be evaluated by the injection rate. Simply put, the injection rate Q [kg / s] can be calculated using the following formula 1. Here, j in Equation 1 is a serial number (j=1, 2, . . . , n) assigned in the depth direction to the reservoir grids 44 (analysis grids set in the reservoir around the injection well) adjacent to the well region 43. j=1 is assigned to the reservoir grid 44 at the top end position in the depth direction of the injection section, and j=2, 3, . . . are assigned in the depth direction thereafter. Also, K[m 2 ] is the absolute carbon dioxide permeability set in the j-th reservoir lattice 44. Furthermore, H in Equation 1 is the lattice thickness of the j-th reservoir lattice 44 (in this embodiment, it is a constant independent of j). ΔP [Pa] in Equation 1 is the pressure P of carbon dioxide in the portion of the entire well area 43 adjacent to the j-th reservoir lattice 44. w and the water pressure P in the j-th reservoir grid 44. r differential pressure (P w -P r )

[0035]

number

[0036] In the graph 46 of FIG. 4, the well area 43 adjacent to the i-th reservoir lattice 44 is set as the top end position (perforation top) of the injection section in the depth direction, and the carbon dioxide pressure P w The graph shows the differential pressure ΔP when the above is set, plotted for each order of the reservoir grid 44 (i=1,...,10). As explained with reference to Figure 3, the formation fracture pressure increases along the depth direction, so the differential pressure ΔP can be made larger as the perforation top is lowered. On the other hand, the injection section becomes shorter.

[0037] Graph 47 in FIG. 4 shows a graph in which the absolute permeability K of carbon dioxide set in the i-th reservoir lattice 44 adjacent to the well region 43 is plotted for each reservoir lattice 44 (i=1, ..., 10). If the reservoir is heterogeneous, different values ​​of the absolute permeability of carbon dioxide are plotted for each of the reservoir data 41a to 41e.

[0038] Graph 48 in Fig. 4 shows a graph in which the injection rate Q calculated by Equation 1 when the well region 43 portion adjacent to the i-th reservoir lattice 44 is set as the upper end position (perforation top) of the injection section in the depth direction is plotted for each reservoir lattice 44 (i = 1, ..., 10). For ease of explanation, the lower end position of the injection section in the depth direction is fixed. When calculating the injection rate Q, each differential pressure ΔP in the i-th reservoir lattice 44 in graph 46 indicates the differential pressure when each i-th reservoir lattice 44 in graph 48 is set as the perforation top. The differential pressure in the reservoir lattice 44 depthwise below the perforation top decreases as the depth increases (see the explanation with reference to Figures 2 and 3).

[0039] Plot 48-1 in graph 48 shows the value of the injection rate Q when the first (i=1) reservoir lattice 44 (adjacent to the shielding layer region 42) located at the highest position in the depth direction is set as the perforation top. In other words, plot 48-1 is the value of the injection rate Q when the injection section is set to the longest length (n=10 in Equation 1), and corresponds to pattern (1) in Figure 2. Plot 48-2 in graph 48 shows the value of the injection rate Q when the second (i=2) reservoir lattice 44 is set as the perforation top. In other words, plot 48-2 is the value of the injection rate Q when the injection interval is set to the second longest (n=9 in Equation 1). The value of the injection rate Q shown by plot 48-2 is smaller than the value of the injection rate Q shown by plot 48-1. This is because the first (i=1) reservoir lattice 44, which has a higher absolute permeability of carbon dioxide, was excluded from the injection interval. Plot 48-3 in graph 48 shows the value of the injection rate Q when the sixth (i=6) reservoir lattice 44 is set as the perforation top. That is, plot 48-3 is the value of the injection rate Q when the injection section is set as the sixth longest (n=5 in Equation 1). The value of the injection rate Q shown by plot 48-3 is the maximum among all the plots in graph 48. This is because the absolute permeability of carbon dioxide in the sixth (i=6) reservoir lattice 44 is large, and the differential pressure ΔP can be made large in accordance with the setting policy (described above) for the formation fracture pressure at the location where the absolute permeability of carbon dioxide is large. As mentioned above, it is useful to incorporate reservoir heterogeneity when assessing carbon dioxide injection performance.

[0040] (skin effect) FIG. 5 is an explanatory diagram of the skin effect. As shown in FIG. 5, when drilling is performed from the surface to a reservoir 50 at a predetermined depth or more, water in the reservoir 50 seeps into a borehole 51. As a result, the water level in the borehole 51 rises above the depth position of the reservoir 50 (the groundwater level before drilling). When the pressure in the borehole 51 increases, the pressure propagates to the strata 52 surrounding the borehole 51. The pressure propagation decreases the further away from the borehole 51. The range that the pressure propagation reaches is called the radius of influence. The progression of the pressure propagation can be shown as a pressure rise curve 53.

[0041] When the well 51 is placed, a mud film 54 (skin) is formed around the well 51. When the mud film 54 is formed, the decrease in pressure propagation accelerates. The acceleration of the decrease in pressure propagation due to the mud film 54 is called the skin effect. The transition of pressure propagation taking the skin effect into account can be shown as a pressure rise curve 53a. In addition, the skin effect increases the radius of influence r o becomes smaller.

[0042] The value S indicating the skin effect can be calculated using the following equation 2. where K is the absolute permeability of the fluid (e.g., water) in the formation 52. s is the absolute permeability of the fluid in the mud film 54. sis the skin region width. e is the radius of the well 51.

[0043]

number

[0044] K s and r s can be uniformly applied to the mud film 54. In light of the purpose of the present invention of optimizing the injection section, the value S indicating the skin effect can be set to a constant.

[0045] When evaluating the carbon dioxide injection performance, the skin effect can be taken into account. Specifically, the injection rate Q in Equation 1 can be modified to express the injection rate q as shown in Equation 3. Here, j in Equation 3 is a serial number (j=1, 2, . . . , n) assigned in the depth direction to the reservoir grids 44 (analysis grids set in the reservoir around the injection well) adjacent to the well model 43. j=1 is assigned to the reservoir grid 44 located at the top end position in the depth direction of the injection section, and j=2, 3, . . . are assigned in the depth direction thereafter. Also, K in Eq. r is the relative permeability of carbon dioxide to water set in the j-th reservoir grid 44. Also, ρ in Eq. CO2 is the density of carbon dioxide within the portion of the entire well area 43 adjacent to the jth reservoir grid 44. Also, μ in Eq. CO2 is the viscosity of carbon dioxide within the portion of the entire well region 43 adjacent to the jth reservoir lattice 44. Also, K in Equation 3 is the absolute permeability of water set in the jth reservoir grid 44. Furthermore, H in Equation 3 is the lattice thickness of the j-th reservoir lattice 44 (in this embodiment, it is a constant independent of j). Also, r in Eq. o is the radius of influence of the well region 43. Also, r in Eq. eis the radius of the well model 43. Furthermore, S in Equation 3 is a value indicating the skin effect caused by the arrangement of the well region 43. Also, P in Eq. w is the pressure of carbon dioxide in the portion of the entire well area 43 adjacent to the j-th reservoir lattice 44. Also, P in Eq. r is the water pressure in the jth reservoir lattice 44.

[0046]

number

[0047] K in Equation 3 r , K, and P r is a value (hydraulic parameter) that can be set by the setting unit 1 for the corresponding reservoir grid 44. CO2 , μ CO2 , and P w is calculated by the calculation unit 2. The calculation method will be described later. o , r e , and S are assumed to be known. According to Equation 3, the injection rate q is reduced due to the skin effect, and the carbon dioxide injection performance can be estimated lower (more accurately).

[0048] Equation 3 is a simplified expression for calculating the injection rate in one-dimensional space in the depth direction, assuming that the injection well is a vertical well and the injection section is limited to the depth direction.More generally, if the injection well is assumed to extend diagonally, etc., and the injection section is treated as three-dimensional, the injection rate Q in three-dimensional space can be calculated using Equation 4. Here, j in Equation 4 is a serial number (j=1, 2, . . . , n) assigned in the depth direction to the reservoir grids 44 (analysis grids set in the reservoir around the injection well) adjacent to the well region 43. j=1 is assigned to the reservoir grid 44 at the top end position in the depth direction of the injection section, and j=2, 3, . . . are assigned in the depth direction thereafter. Also, K in Eq. ris the relative permeability of carbon dioxide to water set in the j-th reservoir grid 44. Also, ρ in Eq. CO2 is the density of carbon dioxide within the portion of the entire well area 43 adjacent to the jth reservoir grid 44. Also, μ in Eq. CO2 is the viscosity of carbon dioxide within the portion of the entire well region 43 adjacent to the jth reservoir lattice 44. Also, P in Eq. w is the pressure of carbon dioxide in the portion of the entire well area 43 adjacent to the j-th reservoir lattice 44. Also, P in Eq. r is the water pressure in the jth reservoir lattice 44. Also, r in Eq. e is the radius of the well region 43. Furthermore, S in Equation 4 is a value indicating the skin effect caused by the arrangement of the well region 43. Also, h in Equation 4 x , h y , h z are the grid lengths in the X direction (one direction on the horizontal plane), Y direction (one direction on the horizontal plane perpendicular to the X direction), and Z direction (depth direction) of the reservoir grid 44 (which is a three-dimensional rectangular parallelepiped) adjacent to the well region 43, respectively. Also, k in Eq. x , k y , k z are the X-direction component, Y-direction component, and Z-direction component of the absolute permeability of water set in the j-th reservoir grid 44, respectively. Also, D in Equation 4 x , D y , D z are the grid lengths in the X direction, Y direction, and Z direction of the well grid adjacent to the j-th reservoir grid 44 among the well grids set in the well region 43, respectively.

[0049]

number

[0050] Equation 4 is the so-called Peaceman equation. Whether the injection well is a deviated well or a vertical well is not an essential issue in determining the injection section where the injection rate is at its maximum. The present invention takes an approach of calculating the flow rate of carbon dioxide by determining the pressure, density, and viscosity of carbon dioxide in the injection well, so the calculation results are the same whether the well is a deviated well or a vertical well. Therefore, although it is sufficient to use Equation 3, there is no prohibition on using Equation 4.

[0051] (Calculation assumptions) The purpose of the present invention is to optimize the injection section, and the determination unit 3 determines the injection section in which the carbon dioxide injection rate is the maximum. In light of this purpose, the evaluation of the carbon dioxide injection performance may be qualitative to a certain extent. Specifically, the injection rate does not need to be calculated as precisely as using Equation 3, and the accuracy of optimization of the injection section can be sufficiently improved as long as there is a high rank correlation between the injection rates obtained from different injection sections.

[0052] Based on the above considerations, we approximate Equation 3 using the following assumptions [1] to [4] to estimate the injection rate. Assumption [1]: The reservoir around the injection well is filled with carbon dioxide. Assumption [2]: When carbon dioxide is injected into the injection well, the increase in pressure in the reservoir around the injection well is not taken into account. Assumption [3]: The injection well is always filled with carbon dioxide, and water in the reservoir does not flow into the injection well. Assumption [4]: ​​The skin effect throughout the injection well is uniform.

[0053] According to assumption [1], the saturation of carbon dioxide in the reservoir around the injection well is 1. Therefore, the relative permeability of carbon dioxide to water in the reservoir around the injection well at each depth position in the injection section can be set to 1. In other words, K in Equation 3 r =1. According to assumption [2], the pressure in the reservoir around the injection well is the pressure of the water in the reservoir. Therefore, the pressure in the reservoir around the injection well at each depth position in the injection section is constant. That is, P in Equation 3 r can be constant. According to the assumption [3], the pressure of carbon dioxide in the injection well at each depth position in the injection section can be equal to or greater than the pressure of water in the reservoir surrounding the injection well at each depth position in the injection section. w -P r is P w -P r ≧0. According to the assumption [4], the value S, which indicates the skin effect due to the arrangement of the injection well, can be assumed to be constant. For example, 2π / (log(r o / r e )+S)=1.

[0054] When the assumptions [1] to [3] are applied, the injection rate q in Equation 3 can be approximated as the injection rate Qe in Equation 5.

[0055]

number

[0056] In Equation 5, P w -P r < 0 means that the water in the reservoir flows back into the injection well. If such a section is not considered as an injection section in the first place, max(P w -P r ,0) is realistic.

[0057] Furthermore, when the assumptions [1] to [4] are applied, the injection rate Q'e in Equation 5 can be approximated by Equation 6.

[0058]

number

[0059] At least one of the assumptions [1] to [4] can be selected to appropriately approximate the injection rate q in Equation 3.

[0060] [process] The processing of this embodiment will be explained. FIG. 6 is an example of a flowchart showing the information processing method of this embodiment. When processing FIG. 6, the information processing device 100 uses a reservoir model 4 including a well region 43. The setting unit 1 has already set a reservoir grid 44 of a predetermined size for the reservoir region 41 of the reservoir model 4. The setting unit 1 has also already set a well grid 45 of a predetermined size arranged in parallel in the depth direction for the well region 43. Equation 5 is used to calculate the injection rate. The influence radius r of the well region 43 o , radius r of well model 43 e , and a value S indicating the skin effect due to the arrangement of the well region 43 have already been input. In addition, the absolute permeability K of water set in the reservoir lattice 44 adjacent to the well region 43 has already been obtained from the reservoir model 4. In addition, the lattice thickness H of the reservoir lattice 44 adjacent to the well region 43 has already been obtained from the reservoir model 4.

[0061] First, the setting unit 1 of the information processing device 100 sets an injection section of a predetermined length for the well region 43 (step A1). Specifically, the setting unit 1 selects a well lattice 45 that will become a perforation top from among the well lattices 45 set in the well region 43. For convenience, the lower end of the injection section is fixed. In other words, among the well lattices 45 set in the well region 43, the well lattice 45 that corresponds to the lower end of the injection section is assumed to be predetermined. By selecting the well lattice 45 that will become a perforation top, the length of the injection section is selected, and the number of well lattices 45 that correspond to the injection section is selected.

[0062] Next, the setting unit 1 sets the carbon dioxide pressure in the well lattice 45 at the top of the set injection section (step A2). Specifically, the setting unit 1 can set the carbon dioxide pressure to be set in the well lattice 45 that becomes the perforation top to 0.9 times the formation fracture pressure at the same depth position as the perforation top.

[0063] Next, the calculation unit 2 calculates the pressure, density, and viscosity of carbon dioxide in each of the well grids 45 corresponding to the injection section (step A3). Details of the calculation in step A3 will be described later. As a result, the depth distribution of the pressure, density, and viscosity of carbon dioxide over the injection section can be obtained.

[0064] Next, the calculation unit 2 calculates the injection rate (step A4). Specifically, the calculation unit 2 substitutes the calculation result obtained in step A3 into Equation 5 to obtain the injection rate Qe. Next, the information processing device 100 determines whether there is an injection section with a length for which the injection rate has not been calculated (step A5). For example, suppose that steps A1 to A4 are calculated for the top row of multiple well lattices 45 set in the well region 43, and then steps A1 to A4 are calculated for the row one row below as the perforation top. In this case, when steps A1 to A4 are calculated for the bottom row of the well lattice 45 corresponding to the injection section as the perforation top, a set of injection rates (injection rates equal to the number of well lattices 45 corresponding to the injection section) is finally calculated. In the above procedure, the case where "there is an injection section with a length for which the injection rate has not been calculated" corresponds to the case where steps A1 to A4 are not calculated for at least the bottom row of the well lattice 45 corresponding to the injection section as the perforation top. Note that the order of calculations in steps A1 to A4 does not have to be one row at a time from the top of the well lattice 45, and any order is acceptable.

[0065] In step A5, if there is an injection section with a length for which the injection rate has not been calculated (Yes in step A5), the process returns to step A1, and the information processing device 100 changes the length of the injection section and executes steps A1 to A4. Specifically, the information processing device 100 selects a different well lattice 45 to serve as the perforation top and executes steps A1 to A4. At this time, it is preferable that the carbon dioxide pressure set in step A2 be the pressure set in accordance with the setting policy for the formation fracture pressure described above. On the other hand, if there is no injection section with a length for which the injection rate has not been calculated in step A5 (No in step A5), the determination unit 3 determines the injection section that shows the maximum value of the calculated injection rates (step A6). This completes the processing in FIG.

[0066] (Details of calculation in step A3 of Figure 6) A description will be given of a method for calculating the pressure, density, and viscosity of carbon dioxide in step A3 of Fig. 6. Fig. 7 is a schematic diagram of a well grid arranged in the depth direction in the injection section.

[0067] As shown in FIG. 7, the lattice thickness of each of N well lattices 45 arranged in parallel in the injection section among the well lattices set in the well region 43 is set to 2ΔL m (m = 1, 2, , N). The pressure, density, viscosity, and temperature of carbon dioxide in the m-th well lattice 45 are respectively P w,m , ρ CO2,m , μ CO2,m , T w,m The pressure of carbon dioxide in the first well grid 45 is P w,1 , density ρ CO2,1 , viscosity μ CO2,1 , temperature T w,1 is a value that can be initially set and is a known value. The temperature of carbon dioxide in the injection well has a temperature gradient in the depth direction. Specifically, the temperature rises by 3°C for every 100 m depth. Therefore, the temperature T of carbon dioxide in the first well grid 45 is w,1 If we initialize the temperature T of carbon dioxide in the m-th (m = 2, , N) well lattice 45, w,1 can be initially set.

[0068] The pressure P of carbon dioxide in the first well grid 45 is known. w,1 , and density ρ CO2,1 The pressure P of carbon dioxide in the second well grid 45, which is located at a depth of ΔL2 from w,2 When calculating P, if the density is constant in the depth direction, w,2 = P w,1 + ρ CO2,1 × ΔL2×g (g is the gravitational acceleration). However, since both pressure and density change with depth, the pressure P calculated above w,2 Therefore, the combination of pressure and density is calculated repeatedly. Also, according to the results of laboratory tests, density and viscosity are functions of pressure and temperature (ρ CO2,m = ρ(P w,m , T w,m ), μ CO2,m = μ(P w,m , T w,m )) Therefore, the pressure P w,m If we know the density ρ CO2,m and viscosity μ CO2,m can also be calculated.

[0069] Figure 8 is an example of a flowchart for calculating the pressure, density, and viscosity of carbon dioxide in each well grid arranged in parallel to each injection section. The process in Figure 8 is a subroutine of step A3 in Figure 6. The pressure P of carbon dioxide in the first well grid 45 of N well grids 45 arranged in parallel to each injection section is calculated. w,1 , density ρ CO2,1 , viscosity μ CO2,1 , temperature T w,1 is known.

[0070] First, the calculation unit 2 executes a loop process of steps B2 to B5 for m (step B1). In this case, the pressure P of carbon dioxide in the (m+1)th well lattice 45 is calculated. w,m+1 , density ρ CO2, m+1 , viscosity μ CO2, m+1 When calculating the pressure P of carbon dioxide in the m-th well grid 45, w,m , density ρ CO2, m , viscosity μ CO2, m, and temperature T w,m , T w,m+1 is known.

[0071] Next, the setting unit 1 calculates the pressure P of carbon dioxide in the (m+1)th well lattice 45, which takes an appropriate value, based on the input from the input unit of the information processing device 100. w,m+1 Next, the calculation unit 2 calculates the pressure P w,m+1 and temperature T w,m+1 From this, the density ρ of carbon dioxide in the m+1-th well lattice 45 CO2,m+1 and viscosity μ CO2,m+1 (Step B3). Next, the calculation unit 2 calculates the calculated density ρ CO2,m+1 Using this, the evaluation value ε(= P w,m+1 - P w,m - (ρ CO2,m ΔL m + ρ CO2,m+1 ΔL m+1 ) × g) is calculated (Step B4). Next, if ε is sufficiently small (Yes in Step B5), the density ρ calculated in Step B3 is calculated. CO2,m+1 and viscosity μ CO2,m+1 Then, m is incremented and the loop process is repeated. On the other hand, if ε is not small enough (No in step B5), the process returns to step B2 and another value of pressure P w,m+1 The calculation is repeated until ε becomes sufficiently small. After the loop processing is completed, proceed to step A4 in FIG.

[0072] For example, in step B2, P w,m+1 = P w,m The pressure P w,m+1 (first iteration). In this case, ε = - (ρ CO2,m ΔL m + ρ CO2,m+1 ΔL m+1 ) × g) The calculated ε is ρ where ε≒0. CO2,m+1 is found, so the pressure P w,m+1 (= ρ CO2,m+1 × 2ΔL m+1 × g) (2nd iteration). The calculated pressure P w,m+1 Steps B3 to B5 are executed using the above formula to calculate ε. The calculated ε is the pressure Pw,m+1 (3rd iteration) After that, the calculation is repeated to find the pressure P w,m+1 will be adopted.

[0073] [effect] According to this embodiment, the injection section of the CCS can be easily optimized. More specifically, there is no need to perform trial and error simulations of carbon dioxide injection using CCS, as was previously required, which reduces calculation costs and shortens calculation time. Furthermore, by setting the carbon dioxide pressure at the perforation top in consideration of the formation fracture pressure, the efficiency of carbon dioxide injection can be improved. Furthermore, by using at least one of the assumptions [1] to [4], it is possible to further reduce the calculation cost and the calculation time while maintaining the desired calculation accuracy. In addition, by performing the iterative calculations shown in Figure 8, it is possible to avoid underestimating the carbon dioxide in the injection well.

[0074] [others] (a): In this embodiment, the injection rate was calculated while fixing the lower end position of the injection section in the depth direction and changing the upper end position of the injection section in the depth direction. However, the injection rate may also be calculated while fixing the upper end position of the injection section in the depth direction and changing the lower end position of the injection section in the depth direction. (b): In this embodiment, the pressure, density, and viscosity of carbon dioxide are determined over the entire injection well by repeated calculation ( FIG. 8 ) using an evaluation value ε for two variables using the pressure and density of carbon dioxide in the well lattice. However, for example, the pressure, density, and viscosity of carbon dioxide may be determined over the entire injection well by repeated calculation using another type of evaluation value for two variables using the pressure and viscosity of carbon dioxide in the well lattice. Furthermore, the pressure, density, and viscosity of carbon dioxide may be determined over the entire injection well by repeated calculation using yet another type of evaluation value for three variables using the pressure, density, and viscosity of carbon dioxide in the well lattice.

[0075] (c) It is also possible to realize a technology that appropriately combines the various technologies described in this embodiment. (d) The software described in this embodiment can be realized as hardware, and vice versa. (e) In addition, the components of the present invention can be modified as appropriate within the scope of the invention. [Explanation of symbols]

[0076] 100 Information processing device 1. Settings 2 Calculation part 3 Judgment section 4 Reservoir model

Claims

1. a first setting step of setting an injection section by changing a depthwise upper end position of the injection section for the injection well in a reservoir model given data on a reservoir that stores carbon dioxide and data on an injection well to be placed in the reservoir; a second setting step of setting a pressure of carbon dioxide in the injection well at an upper end position in a depth direction of the set injection section; a calculation step of calculating an injection rate for the set injection section based on the density of carbon dioxide in the injection well, the viscosity of carbon dioxide in the injection well, and the pressure of carbon dioxide in the injection well at each position in the depth direction of the injection section; and determining an injection section in which the calculated injection rate exhibits a maximum value.

2. 2. The information processing method according to claim 1, wherein in the second setting step, the pressure of carbon dioxide in the injection well at the upper end position of the injection section in the depth direction is set to be a predetermined pressure lower than the formation fracture pressure at the upper end position in the depth direction.

3. 2. The information processing method according to claim 1, wherein in the calculation step, the injection rate is calculated based on at least one of the following [1] to [4]: [1]: The relative permeability of carbon dioxide to water in the reservoir around the injection well at each position in the depth direction of the injection section is 1. [2]: The pressure in the reservoir around the injection well is constant at each position in the depth direction of the injection section. [3]: The pressure of carbon dioxide in the injection well at each position in the depth direction of the injection section is equal to or greater than the pressure of water in the reservoir around the injection well at each position in the depth direction of the injection section. [4]: The value indicating the skin effect due to the placement of the injection well is constant.

4. In the second setting step, a temperature of carbon dioxide in the injection well at an upper end position in a depth direction of the injection section is set; In the calculation step, 2. The information processing method according to claim 1, wherein the pressure, density, and viscosity of the carbon dioxide in the injection well at each position in the depth direction of the injection section are determined by repeated calculations using the temperature of the carbon dioxide in the injection well at each position in the depth direction of the injection section.

5. a first setting unit that sets an injection section by changing a position of an upper end of the injection section in a depth direction for the injection well in a reservoir model to which data of a reservoir that stores carbon dioxide and data of an injection well to be placed in the reservoir are given; a second setting unit that sets a pressure of carbon dioxide in the injection well at an upper end position in a depth direction of the set injection section; a calculation unit that calculates an injection rate for the set injection section based on the density of carbon dioxide in the injection well, the viscosity of carbon dioxide in the injection well, and the pressure of carbon dioxide in the injection well at each position in the depth direction of the injection section; a determination unit that determines an injection section in which the calculated injection rate shows a maximum value.

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