CN115902160B - Evaluation of CO in brine layer geology 2 Method for storing potential - Google Patents
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- CN115902160B CN115902160B CN202211499215.3A CN202211499215A CN115902160B CN 115902160 B CN115902160 B CN 115902160B CN 202211499215 A CN202211499215 A CN 202211499215A CN 115902160 B CN115902160 B CN 115902160B
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- HPALAKNZSZLMCH-UHFFFAOYSA-M sodium;chloride;hydrate Chemical compound O.[Na+].[Cl-] HPALAKNZSZLMCH-UHFFFAOYSA-M 0.000 title claims abstract description 91
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- 238000000034 method Methods 0.000 title claims abstract description 43
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Abstract
The invention discloses a method for evaluating CO in saline water layer geology 2 A method of sequestering potential comprising the steps of: s1, collecting geological stratum data; s2, determining the thickness of the closed saline layer, the effective boundary of the saline layer and the initial CO 2 Injection rate; setting CO 2 Injecting a closed brine layer with infinite radial range through a vertical shaft; s3, according to CO 2 Plume thickness divides the saline layer into three regions 1, 2, and 3, and determines absolute pressure within regions 1, 2, and 3; s4, determining CO at the next moment according to the absolute pressure at the current moment 2 Is a rate of injection of (a); s5, determining CO according to S4 2 Determining the distribution of brine profiles at the injection rate; s6, evaluating CO 2 Is stored in the storage container. The absolute pressure in the brine layer at the current moment can be determined through an absolute pressure equation, so that when the absolute pressure exceeds a certain threshold value, the CO after the current moment is adjusted in real time 2 The injection rate can avoid CO damage caused by overlarge formation pressure 2 Injection equipment and the occurrence of blowout accidents.
Description
Technical Field
The present invention relates to CO 2 The technical field of trapping and sealing, in particular to a method for evaluating CO in brine layer geology 2 Method for storing potential
Background
At present, the global climate has been obviously changed, extreme climate phenomena are frequently generated, geological disasters caused by the extreme climate phenomena are obviously increased, the influence of greenhouse gases on the global climate is common, and CO 2 There is also increasing interest as the most important greenhouse gases. From large CO 2 Emissions sources capture carbon dioxide, which is then stored in subsurface deep geologic formations, commonly referred to as carbon capture and storage, which has been demonstrated to reduce CO 2 Means of efficient method discharge. CO 2 The geological sequestration technology is to directly sequester CO 2 Techniques for injecting and permanently sealing the appropriate geologic formations in the subsurface.
CO 2 Suitable candidatesThe reservoirs mainly include brine layers, depleted oil and gas reservoirs, and the like. Because of the short industrial exploitation time of petroleum and natural gas in China, depleted oil fields and gas fields are relatively few, and compared with other geological structures, the deep airtight brine layer has larger CO sequestration 2 And is widely distributed in China, thus, CO is sealed in a saline water layer 2 Has great potential.
CO at present 2 In the evaluation of sequestration potential, for example, chinese patent CN115128244a provides a method for analyzing sequestration potential of injected carbon dioxide in consideration of rock fluid force, which takes into consideration rock fluid force (van der waals force, electrostatic force, structural force) and capillary force of air-water interface, and establishes a method for analyzing carbon dioxide formation water sequestration under different displacement pressures in pores of different shapes; and (3) calculating the saturation degree of carbon dioxide invaded by the pore network in the pores, and analyzing the carbon dioxide sequestration potential under different displacement pressures.
For example, chinese patent CN113821937a provides a method for quantitatively predicting carbon dioxide enhanced gas reservoir mining and sequestration, by combining GCMC and PR EOS, to achieve simulated reduction of multiple continuous injection and production processes, including primary depressurization and multiple CO 2 Throughput process.
For example, chinese patent CN104850742a relates to a method for calculating CO 2 Method for the sequestration potential of minerals in a salt water layer based on the consumption of CO per unit rock volume by dissolution of feldspar-like minerals 2 The amount and the rock effective volume calculate CO 2 Sealing potential.
For example, chinese patent CN103544361A provides a CO in oil and gas development 2 Method for evaluating geological sequestration potential, involving CO 2 Geological comprehensive evaluation of the capper at the early stage of injection 2 Injection process fluid dynamics and CO 2 And (3) evaluating leakage risk after injection is completed, and providing a method for finely describing geological features and trapping conditions of the lower sealed-up body by using a hydrocarbon reservoir description principle.
For example, chinese patent CN108614076a provides a method for evaluating geological sequestration of carbon dioxide, by determining CO through short-term in-house water rock simulation experiments 2 Filling oilThe reaction path and reaction process after the gas layer, and on the basis, the sealing amount evaluation is carried out by long-term numerical simulation to enable CO to be obtained 2 The filling simulation process is closer to the actual carbon dioxide scale filling experiment, avoiding the presumption of CO according to typical chemical reaction equations 2 The uncertainty of the sealing quantity evaluation is caused in the sealing process after filling, and the accuracy of the sealing potential evaluation of the actual sealing geologic body is obviously improved.
However, most of the carbon dioxide sequestration potential prediction methods in the prior art qualitatively analyze the sequestration potential of carbon dioxide in an indirect manner. On the other hand, some quantitative calculation methods of carbon dioxide sequestration potential are provided in the prior art, however, these calculation methods require a large number of key parameters as input parameters, which certainly increases the calculation cost; also, some key parameters are estimated using only a few input parameters, which in turn affects the accuracy of the calculation result.
Therefore, how to provide a method for rapidly and accurately quantitatively evaluating CO in saline water layer geology 2 The method of library sealing and storing potential becomes a technical problem to be solved in the field.
Disclosure of Invention
The invention adopts the following technical scheme:
the invention adopts a method for evaluating CO in saline water layer geology 2 A method of sequestering potential comprising the steps of:
s1, collecting geological stratum data:
the geological formation data includes: CO 2 Injection rate, brine layer thickness, permeability coefficient, brine effective permeability, CO 2 Effective permeability, relative viscosity of brine, and CO 2 Relative viscosity, formation porosity and CO 2 And brine mobility;
s2, determining an injection scheme:
determining the thickness of the closed brine layer, the effective boundary of the brine layer, and the initial CO 2 Injection rate;
setting CO 2 Injecting a closed brine layer with infinite radial range through a vertical shaft;
s3, determining the space-time change of the absolute pressure in the stratum:
according to CO 2 Plume thickness divides the saline layer into three regions 1, 2, and 3, and determines absolute pressure within regions 1, 2, and 3;
s4, determining CO at the next moment according to the absolute pressure at the current moment 2 Is a rate of injection of (a);
s5, determining CO according to S4 2 Determining the distribution of brine profiles at the injection rate;
s6, evaluating CO 2 The storage amount of (2):
the saturated brine section equation of the brine layer is integrated to obtain the CO 2 Is stored in the storage container.
Further, in S3:
CO 2 the plume thickness of (2) is:
wherein b is the upper layer CO of the saline layer 2 The thickness of the gas plume, meters; r is the radial distance from the center of the injection well, meters; t is CO 2 Injection time, s; b is the thickness of the aquifer and meters; lambda is CO 2 And the ratio of the mobilities of brine; q (Q) well Is CO 2 The rate of initial injection, kg/s; psi is the formation porosity; s is S wb Is salt water saturation;
wherein λ=λ c /λ w ；λ c Is CO 2 And lambda c ＝k c /μ c ，k c Is CO 2 Effective permeability, rice 2 ，μ c Is CO 2 Relative viscosity, mpa·s; lambda (lambda) w Is the fluidity parameter of brine, lambda w ＝k b /μ b ，k b For salt water to be effective permeability, rice 2 ；μ b The relative viscosity of brine is MPa.s.
Further, in S3:
the absolute pressures in zones 1, 2 and 3 are:
wherein P is 1 (r, t) is the pressure distribution in zone 1, MPa; p (P) 2 (r, t) is the pressure distribution in zone 2, MPa; p (P) 3 (r, t) is the pressure distribution in zone 3, MPa; p (P) R∞ Is R ∞ Formation pressure at MPa; k is the permeability coefficient.
Further, in S4:
determining whether the next moment CO needs to be adjusted according to the absolute pressure at the current moment 2 Is the injection rate of (2):
wherein,
in which Q 1 For the next moment CO 2 Is a rate of injection of (a); p is the absolute pressure calculated in the step 3 at the current time;is a threshold value.
Further, in S5:
saturated brine section equation S b (r, t) is:
wherein S is b1 (r, t) is the saturated brine profile equation in region 1; s is S b2 (r, t) is the saturated brine profile equation in region 2; s is S b3 (r, t) is the saturated brine profile equation in region 3.
Further, in S6:
the storage amount of CO2 is:
compared with the prior art, the invention has the following advantages:
(1)CO 2 the storage capacity assessment method of (1) introduces permeability coefficient and CO 2 Ratio to mobility of brine, and CO 2 The radial parameter of the plume is fully considered on the capability of conducting fluid in the saline water layer and CO 2 Interaction with brine two-phase fluid in confined space and CO 2 The distribution range in the horizontal direction is more accurate in calculation result and has more engineering practicability.
(2) CO of the invention 2 The method for evaluating the sequestration potential has time variability and can not only determine the CO in the initial state 2 The sequestration potential can also determine the CO at the current injection time 2 Is excluded from assuming CO 2 The injection rate remains unchanged and the accuracy of the calculation is higher.
(3) The absolute pressure in the brine layer at the current moment can be determined through an absolute pressure equation, so that when the absolute pressure exceeds a certain threshold value, the CO after the current moment is adjusted in real time 2 The injection rate can avoid CO damage caused by overlarge formation pressure 2 Injection equipment and the occurrence of blowout accidents.
(4) The saturated brine section equation is also time-varying, avoiding the CO assumed in the calculation of the saturated brine section equation in the prior art 2 The injection rate remains unchanged, improving the accuracy of the calculation.
Drawings
FIG. 1 is a graph of CO evaluation in saline aquifer geology 2 A method flow chart of the sequestration potential;
FIG. 2 is CO 2 A schematic distribution diagram of the closed brine layer is injected.
Detailed Description
The following detailed description of embodiments of the invention, provided in the accompanying drawings, is not intended to limit the scope of the invention, as claimed, but is merely representative of selected embodiments of the invention. All other embodiments, based on the embodiments of the invention, which are apparent to those of ordinary skill in the art without inventive faculty, are intended to be within the scope of the invention.
As shown in fig. 1The embodiment provides a method for evaluating CO in saline water layer geology 2 A method of sequestering potential comprising the steps of:
step 1, collecting geological formation data:
the geological formation data includes: CO 2 Injection rate, brine layer thickness, permeability coefficient, brine effective permeability, CO 2 Effective permeability, relative viscosity of brine, and CO 2 Relative viscosity, formation porosity and CO 2 And brine mobility.
The data can be obtained through geological exploration, such as logging and sampling by using the outcrop of the earth, a exploratory trench, a shallow well, in a tunnel, a borehole and the like, and using the prior art of geophysical well logging results and the like. It will be appreciated that the measurement of each datum should be chosen to suit the underlying CO 2 Geological conditions of the repository.
Step 2: determining an injection scheme:
first, the thickness of the closed brine layer, the effective boundary of the brine layer, and the initial CO are determined 2 Injection rate.
It will be appreciated that the thickness of the closed brine layer and the effective boundaries of the brine layer may be obtained by geological exploration. CO 2 Is required to reasonably determine the initial CO based on the formation initial pressure 2 Injection rate; CO 2 After the start of injection, CO is injected 2 The accumulation amount is continuously increased, and the CO is continuously increased along with the formation pressure 2 The injection rate is also reduced to avoid CO easily caused at weak parts of stratum rock mass 2 Leakage causes new environmental impact.
Thus, the CO of the present embodiment 2 The method for evaluating the sequestration potential is time-varying and can not only determine the CO in the initial state 2 The sequestration potential can also determine the CO at the current injection time 2 Is used for the storage potential of the (C).
Next, CO is determined 2 Is injected by the injection method. In the present embodiment, CO 2 A closed brine layer of infinite radial extent is injected through the shaft. It should be noted that the injection method is most commonly used in practical engineering for the implementationMode CO 2 The evaluation method of the sealing potential has engineering application value.
Step 3, determining the absolute pressure space-time change in the stratum:
referring to FIG. 2, first, according to CO 2 The plume thickness divides the saline layer into three regions.
Wherein CO 2 The plume thickness of (2) is:
wherein b is the upper layer CO of the saline layer 2 The thickness of the gas plume, meters; r is the radial distance from the center of the injection well, meters; t is CO 2 Injection time, s; b is the thickness of the aquifer and meters; lambda is CO 2 And the ratio of the mobilities of brine; q (Q) well Is CO 2 The rate of initial injection, kg/s; psi is the formation porosity; s is S wb Is salt water saturation.
Wherein λ=λ c /λ w ；λ c Is CO 2 And lambda c ＝k c /μ c ，k c Is CO 2 Effective permeability, rice 2 ，μ c Is CO 2 Relative viscosity, mpa·s; lambda (lambda) w Is the fluidity parameter of brine, lambda w ＝k b /μ b ，k b For salt water to be effective permeability, rice 2 ；μ b The relative viscosity of brine is MPa.s.
It will be appreciated that CO injected into the closed brine layer and in a supercritical state 2 Generating plume migration in a confined brine layer, at CO 2 At plume migration radius r, the upper formation limit of the saline water layer and CO 2 The vertical distance from the brine interface is called CO 2 Plume thickness.
It was thus determined that the region 1 was fully filled with CO in the vertical formation direction and radial to the injection well 2 Plume, CO 2 Single phase zone, on the subsurface of the formation, CO 2 The distance between the junction of the plume and the salt water and the center of the injection well is r min The method comprises the steps of carrying out a first treatment on the surface of the In zone 2 at the same time by CO 2 And brine is filled with CO 2 And a mixed phase zone of brine, on the upper surface of the stratum, CO 2 The distance from the center of the injection well at the maximum radial extent of the plume is r max The method comprises the steps of carrying out a first treatment on the surface of the The region 3 is filled with brine, and is a single-phase region of brine, and the brine extends to R ∞ 。
Next, the absolute pressures in zones 1, 2 and 3 were determined as:
wherein P is 1 (r, t) is the pressure distribution in zone 1, MPa; p (P) 2 (r, t) is the pressure distribution in zone 2, MPa; p (P) 3 (r, t) is the pressure distribution in zone 3, MPa; p (P) R∞ Is R ∞ Formation pressure at MPa; k is the permeability coefficient.
In this embodiment, the absolute pressure in the brine layer at the current time can be determined by the brine layer absolute pressure equation, so that when the absolute pressure exceeds a certain threshold, the CO after the current time is adjusted in real time 2 The injection rate can avoid CO damage caused by overlarge formation pressure 2 Injection equipment and the occurrence of blowout accidents.
Step 4, determining whether the next moment CO needs to be adjusted according to the absolute pressure at the current moment 2 Is the injection rate of (2):
specific:
in which Q 1 For the next moment CO 2 Is a rate of injection of (a); p is the absolute pressure calculated in the step 3 at the current time;is a threshold value. It will be appreciated that if the absolute pressure value calculated in step 3 does not exceed the threshold value, the CO at the next time is 2 Is kept constantA change; if the absolute pressure value calculated in step 3 exceeds the threshold value, CO at the next time 2 The injection rate of (c) needs to be suitably small.
Step 5, determining the distribution of brine sections:
in the present embodiment, CO in region 3 2 The gas plume thickness was zero and the aquifer in this region was fully saturated with brine. Due to the presence of gas (CO) in the zone 1 brine aquifer 2 ) At the juncture of the maximum saturation and the residual saturation of brine, B (r, t) is equivalent to B (1-S) wb ). That is, any brine or liquid phase present in zone 1 is considered to be non-mobile.
Thereby, saturated brine section equation S b (r, t) is:
wherein S is b1 (r, t) is the saturated brine profile equation in region 1; s is S b2 (r, t) is the saturated brine profile equation in region 2; s is S b3 (r, t) is the saturated brine profile equation in region 3.
Notably, the saturated brine profile equation is also time-varying. Avoiding the assumed CO in the calculation of saturated brine section equation in the prior art 2 The injection rate remains unchanged, improving the accuracy of the calculation.
Step 6, evaluating CO 2 The storage amount of (2):
specifically, the saturated brine section equation of the brine layer is integrated to obtain CO 2 The storage amount of (2) is as follows:
it will be appreciated that the CO of the present embodiment 2 The storage capacity method of (2) also has time variability, eliminating the assumption of CO 2 The injection rate remains unchanged and the accuracy of the calculation is higher.
At the same time, CO 2 Is stored in a storage device of (a)The stock assessment method introduces permeability coefficient and CO 2 Ratio to mobility of brine, and CO 2 Radial radius of the plume and other parameters; wherein the permeability coefficient is CO 2 The ratio of the effective permeability to the effective permeability of the brine, the effective permeability being the capacity of the porous medium to allow the passage of fluids, is a parameter characterizing the capacity of the soil or rock mass itself to transmit fluids; CO 2 The ratio of the mobility of the brine is CO 2 The ratio of fluidity to brine, taking into account CO 2 And brine two-phase fluid in a closed space, which affects CO 2 Migration and location of brine interface; CO 2 The plume radial radius represents the single injection well perimeter, CO in the horizontal direction 2 Distribution range.
Thus, the CO of the present embodiment 2 Fully considers the capability of conducting fluid in the saline water layer and CO 2 Interaction with brine two-phase fluid in confined space and CO 2 The distribution range in the horizontal direction is more accurate in calculation result and has more engineering practicability.
In the embodiment, geological data of the geology of the potential saline water layer is obtained through geological exploration, a space-time change equation of the absolute pressure in the saline water layer is obtained, a section equation of saturated saline water is obtained, and the potential CO is deduced finally 2 And (5) storing an equation of the amount.
The foregoing is illustrative of the best mode of carrying out the invention, and is not presented in any detail as is known to those of ordinary skill in the art. The protection scope of the invention is defined by the claims, and any equivalent transformation based on the technical teaching of the invention is also within the protection scope of the invention.
Claims (6)
1. Evaluation of CO in brine layer geology 2 A method for sequestering potential, comprising the steps of:
s1, collecting geological stratum data:
the geological formation data includes: CO 2 Injection rate, brine layer thickness, permeability coefficient, brine presenceEffective permeability, CO 2 Effective permeability, relative viscosity of brine, and CO 2 Relative viscosity, formation porosity and CO 2 And brine mobility;
s2, determining an injection scheme:
determining the thickness of the closed brine layer, the effective boundary of the brine layer, and the initial CO 2 Injection rate;
setting CO 2 Injecting a closed brine layer with infinite radial range through a vertical shaft;
s3, determining the space-time change of the absolute pressure in the stratum:
according to CO 2 Plume thickness divides the saline layer into three regions 1, 2, and 3, and determines absolute pressure within regions 1, 2, and 3;
s4, determining CO at the next moment according to the absolute pressure at the current moment 2 Is a rate of injection of (a);
s5, determining CO according to S4 2 Determining the distribution of brine profiles at the injection rate;
s6, evaluating CO 2 The storage amount of (2):
the saturated brine section equation of the brine layer is integrated to obtain the CO 2 Is stored in the storage container.
2. The method of claim 1, wherein: in the step S3, the processing unit,
CO 2 the plume thickness of (2) is:
wherein b is the upper layer CO of the saline layer 2 The thickness of the gas plume, meters; r is the radial distance from the center of the injection well, meters; t is CO 2 Injection time, s; b is the thickness of the aquifer and meters; lambda is CO 2 And the ratio of the mobilities of brine; q (Q) well Is CO 2 The rate of initial injection, kg/s; psi is the formation porosity; s is S wb Is salt water saturation;
wherein λ=λ c /λ w ；λ c Is CO 2 And lambda c ＝k c /μ c ，k c Is CO 2 Effective permeability, rice 2 ，μ c Is CO 2 Relative viscosity, mpa·s; lambda (lambda) w Is the fluidity parameter of brine, lambda w ＝k b /μ b ，k b For salt water to be effective permeability, rice 2 ；μ b The relative viscosity of brine is MPa.s.
3. The method of claim 2, wherein: in the step S3, the processing unit,
the absolute pressures in zones 1, 2 and 3 are:
wherein P is 1 (r, t) is the pressure distribution in zone 1, MPa; p (P) 2 (r, t) is the pressure distribution in zone 2, MPa; p (P) 3 (r, t) is the pressure distribution in zone 3, MPa; p (P) R∞ Is R ∞ Formation pressure at MPa; k is the permeability coefficient.
4. A method as claimed in claim 3, wherein: in S4, the processing unit is configured to,
determining whether the next moment CO needs to be adjusted according to the absolute pressure at the current moment 2 Is the injection rate of (2):
wherein,
in which Q 1 The injection rate of CO2 is the next moment; p is the absolute pressure calculated in the step 3 at the current time;is a threshold value.
5. The method of claim 4, wherein: in S5, the processing unit is configured to,
saturated brine section equation S b (r, t) is:
wherein S is b1 (r, t) is the saturated brine profile equation in region 1; s is S b2 (r, t) is the saturated brine profile equation in region 2; s is S b3 (r, t) is the saturated brine profile equation in region 3.
6. The method of claim 5, wherein: in S6, the processing unit is configured to,
CO 2 the storage amount of (2) is as follows:
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