CN106803003A - Determine that the well head of fluid injects the method and device of phase - Google Patents
Determine that the well head of fluid injects the method and device of phase Download PDFInfo
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Abstract
The invention discloses the method and device that a kind of well head for determining fluid injects phase.Wherein, the method includes：The critical condition of injection well downhole formation is obtained, wherein, critical condition at least includes：The design temperature of the security restriction condition, flow restriction condition and shaft bottom of downhole formation, injection well is used to inject fluid in each implanted layer；The critical condition of acquisition is converted to the boundary condition of the well head of injection well；According to well head boundary condition transformation result, the well head injection phase of fluid is determined.Well head phase designs irrational technical problem during the present invention solves correlation technique.
Description
Technical Field
The invention relates to the field of environmental protection, in particular to a method and a device for determining a wellhead injection phase state of fluid.
Background
In the fields of carbon dioxide geological storage, underground fluid energy development and the like, a shaft is a unique channel for communicating the earth surface with an underground reservoir. To achieve established engineering goals, including production, site safety, etc., one can only regulate and control the injection process through wellhead operations. The main control objects of the wellhead are the temperature and pressure of the injected fluid, i.e. the phase state of the fluid. Therefore, the phase state of the well head fluid is a direct technical parameter for determining whether a plurality of engineering targets can be effectively realized, and an effective well head fluid injection phase state design method is crucial to the successful implementation of related engineering.
However, in the process of injecting fluid into the formation through the wellbore, various problems are involved, such as wellbore pipe flow, wellbore heat transfer, formation infiltration flow, formation rock mechanics, etc., due to complexity and uncertainty of geological conditions, the involved parameters are numerous, and the values of the parameters are often incomplete in the engineering design stage.
In the traditional oil and gas reservoir field, the design of wellhead pressure mainly considers the flowing friction pressure drop of a shaft and the fluid gravity, and a very simplified method is adopted for estimation, so that the consideration of the pressure for heat transfer and formation safety control is very limited. In recent years, researchers have conducted research efforts to improve these shortcomings, such as designing well head pressure based on numerical simulation techniques. However, this method also has some problems: first, numerical simulation requires relatively accurate geological and geometric models and numerous parameters, which are difficult to achieve in the engineering design phase. Second, the wellbore size and formation size differ significantly, making a wellbore-formation joint simulation results in an extremely large number of grids, making the simulation difficult to perform. Third, numerical simulation techniques are generally forward methods, i.e., computing the physical quantity field in the domain given the initial-edge condition. However, the wellhead pressure is a boundary condition, and therefore, the design of the wellhead pressure is a process of calculating one part of the boundary condition (downhole) and another part of the boundary condition, which is a typical inversion analysis. In order to design the wellhead pressure by using a numerical simulation method, the original problem must be changed into a series of forward calculation, namely, the possible forward calculation results are searched, and therefore, the calculation amount is greatly increased. Furthermore, none of the above methods target injection temperature as a design objective and therefore do not directly give phase design of the wellhead fluid.
In view of the above problems, no effective solution has been proposed.
Disclosure of Invention
The embodiment of the invention provides a method and a device for determining a wellhead injection phase state of fluid, which at least solve the technical problem of unreasonable wellhead phase state design in the related art.
According to an aspect of an embodiment of the present invention, there is provided a method of determining a wellhead injection phase of a fluid, comprising: obtaining critical conditions of a formation downhole of an injection well, wherein the critical conditions include at least: safety restrictions, flow restrictions, and downhole design temperature of the formation, the injection well being configured to inject fluids into the injection zones; converting the obtained critical conditions into boundary conditions of a wellhead of the injection well; and determining the wellhead injection phase state of the fluid according to the wellhead boundary condition conversion result.
Further, obtaining critical conditions for the formation downhole of the injection well comprises: acquiring the pressure ratio of each reservoir in the bottom-hole stratum of the injection well; comparing the obtained pressure ratios of the reservoirs to obtain the maximum pressure ratio in the pressure ratios of the reservoirs; the maximum pressure ratio is taken as the safety limit for the downhole formation.
Further, obtaining a pressure ratio for each reservoir in the downhole formation of the injection well comprises: acquiring the pressure of injected fluid at each reservoir; acquiring the maximum allowable injection pressure of the stratum; calculating a ratio between the injected fluid pressure at each of said reservoirs and a maximum injection pressure allowed for said formation; and taking the calculated result as the pressure ratio of each reservoir.
Further, obtaining a pressure ratio for each reservoir in the downhole formation of the injection well comprises: acquiring the pressure of injected fluid at each reservoir; acquiring the maximum allowable injection pressure of the stratum; acquiring an empirical coefficient influencing the maximum injection pressure allowed by the stratum from an empirical value database; taking the product of the maximum injection pressure allowed by the stratum and the empirical coefficient as the maximum injection pressure allowed by the new stratum; calculating a ratio between the injected fluid pressure at each of said reservoirs and a maximum injection pressure allowed for said new formation; and taking the calculated result as the pressure ratio of each reservoir.
Further, obtaining the maximum allowable injection pressure of the formation comprises: determining the number N of layers of the reservoir in the bottom-hole stratum of the injection well; reversely pushing from bottom to top from the reservoir of the Nth layer, comparing whether the well head pressure obtained from the lower layer is larger than the stratum fracture pressure of the reservoir of the upper layer, if so, continuously pushing the bottom hole pressure injected as the next layer, if not, continuously pushing the bottom hole pressure obtained as the next layer until the surface of the earth, and obtaining the well head pressure; the wellhead pressure is taken as the maximum injection pressure allowed for the formation.
There is also provided, in accordance with another aspect of an embodiment of the present invention, apparatus for determining a wellhead injection phase of a fluid, including: an obtaining unit for obtaining a critical condition of a formation downhole of an injection well, wherein the critical condition at least comprises: safety restrictions, flow restrictions, and downhole design temperature of the formation, the injection well being configured to inject fluids into the injection zones; a conversion unit, configured to convert the acquired critical conditions into boundary conditions of a wellhead of the injection well; and the determining unit is used for determining the wellhead injection phase state of the fluid according to the wellhead boundary condition conversion result.
Further, the acquiring unit includes: the acquisition module is used for acquiring the pressure ratio of each reservoir in the bottom-hole stratum of the injection well; the comparison module is used for comparing the acquired pressure ratios of the reservoirs to obtain the maximum pressure ratio in the pressure ratios of the reservoirs; a determination module for determining the maximum pressure ratio as the safety limit condition for the downhole formation.
Further, the obtaining module includes: a first obtaining sub-module for obtaining injected fluid pressures at each reservoir; the second acquisition sub-module is used for acquiring the maximum injection pressure allowed by the stratum; a first calculation submodule for calculating a ratio between an injection fluid pressure at each of the reservoirs and a maximum injection pressure allowed for the formation; and the first determining submodule is used for determining the calculated result as the pressure ratio of each reservoir.
Further, the obtaining module includes: a third obtaining sub-module for obtaining injected fluid pressures at each reservoir; the fourth acquisition submodule is used for acquiring the maximum allowable injection pressure of the stratum; a fifth obtaining submodule, configured to obtain an empirical coefficient, which affects a magnitude of a maximum injection pressure allowed for the formation, from an empirical value database; a second determining submodule, configured to determine a product of the maximum injection pressure allowed by the formation and the empirical coefficient as a maximum injection pressure allowed by a new formation; a second calculation submodule for calculating a ratio between the injected fluid pressure at each of the reservoirs and a maximum injection pressure allowed for the new formation; and the third determining submodule is used for determining the calculated result as the pressure ratio of each reservoir.
Further, the second obtaining sub-module is configured to perform the following steps: determining the number N of layers of the reservoir in the bottom-hole stratum of the injection well; reversely pushing from bottom to top from the reservoir of the Nth layer, comparing whether the well head pressure obtained from the lower layer is larger than the stratum fracture pressure of the reservoir of the upper layer, if so, continuously pushing the bottom hole pressure injected as the next layer, if not, continuously pushing the bottom hole pressure obtained as the next layer until the surface of the earth, and obtaining the well head pressure; the wellhead pressure is taken as the maximum injection pressure allowed for the formation.
In the embodiment of the invention, the method for determining the wellhead injection phase state of the fluid is adopted, and the method is used for acquiring the critical conditions of the stratum at the bottom of the injection well, wherein the critical conditions at least comprise: safety limits, flow limits, and design temperature at the bottom of the well for injecting fluids into each injection zone; converting the obtained critical conditions into boundary conditions of a wellhead of the injection well; according to the wellhead boundary condition conversion result, the wellhead injection phase state of the fluid is determined, and the purpose of reasonably determining the wellhead injection phase state of the fluid is achieved, so that the technical effects of few dependent parameters and high calculation efficiency during rapid design of the wellhead injection phase state are achieved, and the technical problem of unreasonable wellhead phase state design in the related technology is solved.
Drawings
The accompanying drawings, which are included to provide a further understanding of the invention and are incorporated in and constitute a part of this application, illustrate embodiment(s) of the invention and together with the description serve to explain the invention without limiting the invention. In the drawings:
FIG. 1 is a flow chart of an alternative method of determining a uphole injection phase of a fluid in accordance with an embodiment of the invention;
FIG. 2 is a schematic diagram of an alternative apparatus for determining a uphole injection phase of a fluid, according to an embodiment of the invention.
Detailed Description
In order to make the technical solutions of the present invention better understood, the technical solutions in the embodiments of the present invention will be clearly and completely described below with reference to the drawings in the embodiments of the present invention, and it is obvious that the described embodiments are only a part of the embodiments of the present invention, and not all of the embodiments. All other embodiments, which can be derived by a person skilled in the art from the embodiments given herein without making any creative effort, shall fall within the protection scope of the present invention.
It should be noted that the terms "first," "second," and the like in the description and claims of the present invention and in the drawings described above are used for distinguishing between similar elements and not necessarily for describing a particular sequential or chronological order. It is to be understood that the data so used is interchangeable under appropriate circumstances such that the embodiments of the invention described herein are capable of operation in sequences other than those illustrated or described herein. Furthermore, the terms "comprises," "comprising," and "having," and any variations thereof, are intended to cover a non-exclusive inclusion, such that a process, method, system, article, or apparatus that comprises a list of steps or elements is not necessarily limited to those steps or elements expressly listed, but may include other steps or elements not expressly listed or inherent to such process, method, article, or apparatus.
Example 1
In accordance with an embodiment of the present invention, there is provided an embodiment of a method of determining a uphole injection phase of a fluid, it being noted that the steps illustrated in the flowchart of the figures may be performed in a computer system such as a set of computer executable instructions and that while a logical order is illustrated in the flowchart, in some cases the steps illustrated or described may be performed in an order different than that presented herein.
FIG. 1 is a flow chart of an alternative method of determining a uphole injection phase of a fluid, as shown in FIG. 1, comprising the steps of:
step S102, obtaining critical conditions of a stratum at the bottom of an injection well, wherein the critical conditions at least comprise: safety limits, flow limits, and design temperature at the bottom of the well for injecting fluids into each injection zone;
step S104, converting the acquired critical conditions into boundary conditions of a wellhead of an injection well;
and S106, determining a wellhead injection phase state of the fluid according to the wellhead boundary condition conversion result.
Given the complexity, uncertainty, and variability of the injection work of field fluids in a real field, given a single wellhead phase, it is not practical. Thus, critical conditions of the formation downhole of the injection well are obtained, the critical conditions including at least: safety limits, flow limits, and design temperature at the bottom of the well may be used to provide a range of guidance for field operations, as long as the range of critical conditions is not exceeded. After obtaining the critical conditions of at least one of the above-mentioned layers at the bottom of the injection well, such as the safety limit condition, the flow limit condition and the design temperature at the bottom of the well, the obtained critical conditions are converted into the boundary conditions at the top of the injection well by using a corresponding conversion method, and the boundary conditions can also comprise the safety limit condition, the flow limit condition and the design temperature at the top of the well. And finally, determining the wellhead injection phase state of the fluid according to the converted boundary conditions, wherein the obtained wellhead injection phase state is a guide value capable of meeting the engineering design target.
In the embodiment of the invention, the method for determining the wellhead injection phase state of the fluid is adopted, and the method is used for acquiring the critical conditions of the stratum at the bottom of the injection well, wherein the critical conditions at least comprise: safety limits, flow limits, and design temperature at the bottom of the well for injecting fluids into each injection zone; converting the obtained critical conditions into boundary conditions of a wellhead of the injection well; according to the wellhead boundary condition conversion result, the wellhead injection phase state of the fluid is determined, and the purpose of reasonably determining the wellhead injection phase state of the fluid is achieved, so that the technical effects of few dependent parameters and high calculation efficiency during rapid design of the wellhead injection phase state are achieved, and the technical problem of unreasonable wellhead phase state design in the related technology is solved.
Optionally, obtaining the critical conditions of the formation downhole of the injection well comprises: acquiring the pressure ratio of each reservoir in the bottom hole stratum of the injection well; comparing the obtained pressure ratios of the reservoirs to obtain the maximum pressure ratio of the pressure ratios of the reservoirs; the maximum pressure ratio is taken as a safety limit for the downhole formation.
That is, when the critical condition of the bottom-hole stratum of the injection well is obtained as the pressure ratio of each reservoir in the bottom-hole stratum, the maximum pressure ratio in the pressure ratios of the reservoirs is obtained by comparing the obtained pressure ratios of the reservoirs, the maximum pressure ratio is used as the safety limiting condition of the bottom-hole stratum, and then the obtained maximum pressure ratio is converted into the boundary condition of the wellhead of the injection well by adopting a corresponding conversion method.
Optionally, obtaining a pressure ratio for each reservoir in the downhole formation of the injection well comprises: acquiring the pressure of injected fluid at each reservoir; acquiring the maximum allowable injection pressure of the stratum; calculating a ratio between the injected fluid pressure at each reservoir and the maximum injection pressure allowed for the formation; and taking the calculated result as the pressure ratio of each reservoir.
For a system comprising any number of reservoirs, it is required that each reservoir be stable during injection, and for this reason, the most dangerous reservoir needs to be stable, and therefore the degree of risk of each reservoir needs to be evaluated. If the most dangerous reservoir is found, it may be determined whether the other reservoirs are stable. Defining a characterization indicator of the reservoir's risk level, the reservoir's risk level depending on two factors, one being the injected fluid pressure at the reservoir and the other being the maximum allowable injection pressure of the formation at that location, generally related to the fracture pressure of the formation at that location, and taking the ratio between the injected fluid pressure at each reservoir and the maximum allowable injection pressure of the formation as the pressure ratio P of each reservoirki/[Pki]Defining a reservoir hazard level, wherein PkiRepresenting the fluid pressure at the ith reservoir, [ P [ ]ki]Represents the maximum pressure allowed for the ith reservoir and is related to the formation fracture pressure. But during actual injection, the largest of all reservoir pressure ratios may also be required to satisfy the following conditions, while requiring a specified reservoir fluid temperature, e.g.,
the conditions are satisfied:
wherein the first expression represents a control range of injection pressure at the ith formation, PbiRepresents capillary pressure (in Pa); p0iRepresenting the formation pressure (in Pa), PkiRepresenting the borehole wall injection pressure (unit Pa) of the ith reservoir; [ P ]ki]Maximum allowable injection pressure (Pa) for the ith reservoir; the second expression represents the control condition of the injection amount, CWHTotal injection flow (in kg/s), C, set for the projectiRepresenting the actual injection flow rate (in kg/s) of the ith reservoir; m0 represents the total target injection amount (in t/a); the third expression represents the bottom hole temperature control condition, TiWhich represents the actual injection temperature at the formation, is the lower temperature limit set by the project. Usually, [ T ]i]The phase state of the fluid downhole may be controlled by setting temperature conditions at the formation downhole, optionally to supercritical conditions.
Optionally, obtaining a pressure ratio for each reservoir in the downhole formation of the injection well comprises: acquiring the pressure of injected fluid at each reservoir; acquiring the maximum allowable injection pressure of the stratum; acquiring an empirical coefficient influencing the maximum injection pressure allowed by the stratum from an empirical value database; taking the product of the maximum injection pressure allowed by the formation and the empirical coefficient as the maximum injection pressure allowed by the new formation; calculating a ratio between the injected fluid pressure at each reservoir and the maximum injection pressure allowed for the new formation; and taking the calculated result as the pressure ratio of each reservoir.
Since the maximum allowable injection pressure is generally required not to fracture the formation, and therefore, is less than the formation fracture pressure, various influence coefficients and safety reserve coefficients are introduced based on the formation pressure, as shown in the following formula:
[Pki]＝ηPfi(2)
wherein, PfiThe formation fracture pressure of the ith formation, η is a comprehensive influence factor considering various influence factors and safety reserve, η is S. ξ1·ξ2…ξm(3)
S·ξ1·ξ2…ξmThe determination of these coefficients can be determined by empirical investigation of other related projects such as sour fluid reinjection and reservoir projects. These empirical coefficients may form a dedicated database of empirical values.
Namely, after the injection fluid pressure at each reservoir is obtained, the maximum injection pressure allowed by the stratum can be obtained; then acquiring an empirical coefficient influencing the maximum injection pressure allowed by the stratum from an empirical value database; and taking the product of the maximum injection pressure allowed by the stratum and the empirical coefficient as the maximum injection pressure allowed by the new stratum, further calculating the ratio of the injection fluid pressure at each reservoir to the maximum injection pressure allowed by the new stratum, and taking the ratio as the pressure ratio of each reservoir.
In addition, wellbore flow and formation infiltration are coupled processes. The flow from the wellbore into the formation is calculated using the following formula, which is based on an analytical solution for formation flow.
Because the risk of the formation depends on the pressure ratio, including the fluid pressure at the formation and the formation fracture pressure, among other factors. Thus, for many formations, it is desirable to find the most dangerous reservoir during fluid flow in the wellbore and to the formation. For simultaneous injection of multiple layers, it is not known in advance which reservoir pressure will reach the fracture pressure of its formation first. Optionally, obtaining the maximum allowable injection pressure of the formation comprises: determining the number N of layers of a reservoir in a bottom hole stratum of an injection well; reversely pushing from bottom to top from the reservoir of the Nth layer, comparing whether the well head pressure obtained from the lower layer is larger than the stratum fracture pressure of the reservoir of the upper layer, if so, continuously pushing the bottom hole pressure injected as the next layer, if not, continuously pushing the bottom hole pressure obtained as the next layer until the surface of the earth, and obtaining the well head pressure; the wellhead pressure is taken as the maximum injection pressure allowed for the formation.
That is, the method of splitting and then stacking is adopted, a plurality of gas storage layers are regarded as a whole formed by combining a plurality of single reservoir layers,the vertical superposition of N single-layer injection working conditions is regarded, and a fast explicit finite difference method can be adopted for solving each single-layer injection. Starting from the Nth reservoir, reversely deducing from bottom to top, and calculating the 'false wellhead pressure' P of the lower layerki(i.e., the pressure at the cap of a reservoir) and the formation fracture pressure P of the previous reservoirfiMaking a comparison if Pki>PfiThen get Pki＝PfiThe bottom hole pressure as the next monolayer injection continues to push up, otherwise the calculated PkiContinuously pushing up until the ground surface to obtain the real wellhead pressure P0As the maximum allowable injection pressure for multilayer injection.
It should be noted that the method can also be applied to the application fields related to the control of the fluid injection temperature, the injection pressure and the shaft safety at the well mouth in the fluid injection engineering, such as carbon dioxide geological storage, carbon dioxide geological utilization (oil displacement, gas displacement, heat recovery enhancement and the like), acid fluid reinjection, oil and gas reservoir engineering and the like.
In addition, with respect to the wellbore-formation heat transfer model, the heat transfer process can be studied by using Ramy analytical solution of wellbore-formation heat transfer, but the original equation needs to be transformed into an inverse solution. This is because the Ramy analytic solution itself is a forward solution, and in the wellhead phase (temperature) design, the temperature value of the wellhead needs to be obtained according to the bottom temperature condition.
The analytic solution of Ramy wellbore fluid temperature is that the inversion form of Ramy wellbore fluid temperature is carried out by adopting a numerical iteration method. T (H, T) ═ aH + b-aA + (T)0+aA-b)e(-H/A)(5)
Wherein,
and the number of the first and second groups,
wherein a is a geothermal gradient (. degree. C./m); b is the surface temperature (. degree. C.); t0 is the temperature (. degree. C.) of the injected fluid; h is the depth (m) at which the fluid is located; t is the injection time(s); gt is the injection rate (t/d); k is the rock heat conductivity coefficient (W/m/K); rt0 is the casing outer radius (m); the average heat release coefficient (m2/s) of the formation; rh is the borehole radius (m); ut is the overall heat transfer coefficient of the fluid to the formation (W/m 2/K).
The inversion of wellhead pressure and temperature, the system of equations for wellbore flow can be re-expressed as equations for fluid pressure,
we use the explicit difference format of this equation to solve, which is as follows,
to reflect the formation heat transfer process to the wellbore fluid, a Ramy temperature solution is invoked within each difference segment. By the solving process, the design temperature and the design pressure value of the wellhead fluid can be obtained by calculating from the critical condition of the bottom of the well to the wellhead. By the method, the flowing heat transfer of the shaft is refined into a semi-analytic model to obtain an analytic model of a formation flow equation, and the analytic model are combined to form a simple analytic model of the process of shaft flowing, heat transfer and formation injection. The simple model is solved based on an analytic solution and an explicit difference method, so that the calculation speed is high. Compared with the traditional forward numerical simulation method, the method has the advantages that the dependence on parameters is less, a large-scale grid is not needed, forward iteration is not needed, and therefore the calculation amount is extremely small. The method is applicable to any number of reservoir-cap combinations and to various stages of engineering injection implementation, and is helpful for injection design before engineering start-up.
Example 2
There is also provided, in accordance with another aspect of an embodiment of the present invention, apparatus for determining a uphole injection phase of a fluid, fig. 2 is a schematic diagram of an alternative apparatus for determining a uphole injection phase of a fluid, in accordance with an embodiment of the present invention, the apparatus including: an obtaining unit 20 for obtaining critical conditions of the formation downhole of the injection well, wherein the critical conditions comprise at least: safety limits, flow limits, and design temperature at the bottom of the well for injecting fluids into each injection zone; a conversion unit 40 for converting the obtained critical conditions into boundary conditions of a wellhead of the injection well; and the determining unit 60 is used for determining the wellhead injection phase state of the fluid according to the wellhead boundary condition conversion result.
In the embodiment of the invention, the device achieves the purpose of reasonably determining the wellhead injection phase state of the fluid, thereby realizing the technical effects of less dependent parameters and high calculation efficiency when rapidly designing the wellhead injection phase state, and further solving the technical problem of unreasonable wellhead phase state design in the related technology.
Optionally, the obtaining unit includes: the acquisition module is used for acquiring the pressure ratio of each reservoir in the bottom-hole stratum of the injection well; the comparison module is used for comparing the obtained pressure ratios of the reservoirs to obtain the maximum pressure ratio in the pressure ratios of the reservoirs; a determination module to determine the maximum pressure ratio as a safe limit condition for the downhole formation.
Optionally, the obtaining module includes: a first obtaining sub-module for obtaining injected fluid pressures at each reservoir; the second acquisition sub-module is used for acquiring the maximum injection pressure allowed by the stratum; a first calculation submodule for calculating a ratio between an injection fluid pressure at each reservoir and a maximum injection pressure allowed for the formation; and a first determining submodule for determining the calculated result as a pressure ratio of each reservoir.
Optionally, the obtaining module includes: a third obtaining sub-module for obtaining injected fluid pressures at each reservoir; the fourth acquisition submodule is used for acquiring the maximum allowable injection pressure of the stratum; the fifth acquisition submodule is used for acquiring an empirical coefficient influencing the maximum injection pressure allowed by the stratum from the empirical value database; a second determination submodule for determining the product of the maximum injection pressure allowed by the formation and the empirical coefficient as the maximum injection pressure allowed by the new formation; a second calculation submodule for calculating a ratio between the injected fluid pressure at each reservoir and a maximum injection pressure allowed for the new formation; and a third determining submodule for determining the calculated result as a pressure ratio of each reservoir.
Optionally, the second obtaining sub-module is configured to perform the following steps: determining the number N of layers of a reservoir in a bottom hole stratum of an injection well; reversely pushing from bottom to top from the reservoir of the Nth layer, comparing whether the well head pressure obtained from the lower layer is larger than the stratum fracture pressure of the reservoir of the upper layer, if so, continuously pushing the bottom hole pressure injected as the next layer, if not, continuously pushing the bottom hole pressure obtained as the next layer until the surface of the earth, and obtaining the well head pressure; the wellhead pressure is taken as the maximum injection pressure allowed for the formation.
It should be noted that the embodiments of the apparatus part in example 2 correspond to the embodiments of the method part in example 1, and are not described again here.
The sequence numbers of the embodiments of the present invention are merely for description, and do not represent the advantages or disadvantages of the embodiments.
In the embodiments of the present invention, the descriptions of the respective embodiments have respective emphasis, and for parts that are not described in detail in a certain embodiment, reference may be made to related descriptions of other embodiments.
In the embodiments provided in the present application, it should be understood that the disclosed technology can be implemented in other ways. The above-described embodiments of the apparatus are merely illustrative, and for example, the division of the units may be a logical division, and in actual implementation, there may be another division, for example, multiple units or components may be combined or integrated into another system, or some features may be omitted, or not executed. In addition, the shown or discussed mutual coupling or direct coupling or communication connection may be an indirect coupling or communication connection through some interfaces, units or modules, and may be in an electrical or other form.
The units described as separate parts may or may not be physically separate, and parts displayed as units may or may not be physical units, may be located in one place, or may be distributed on a plurality of units. Some or all of the units can be selected according to actual needs to achieve the purpose of the solution of the embodiment.
In addition, functional units in the embodiments of the present invention may be integrated into one processing unit, or each unit may exist alone physically, or two or more units are integrated into one unit. The integrated unit can be realized in a form of hardware or a form of software functional unit.
The integrated unit, if implemented in the form of a software functional unit and sold or used as a stand-alone product, may be stored in a computer readable storage medium. Based on such understanding, the technical solution of the present invention may be embodied in the form of a software product, which is stored in a storage medium and includes instructions for causing a computer device (which may be a personal computer, a server, or a network device) to execute all or part of the steps of the method according to the embodiments of the present invention. And the aforementioned storage medium includes: a U-disk, a Read-Only Memory (ROM), a Random Access Memory (RAM), a removable hard disk, a magnetic or optical disk, and other various media capable of storing program codes.
The foregoing is only a preferred embodiment of the present invention, and it should be noted that, for those skilled in the art, various modifications and decorations can be made without departing from the principle of the present invention, and these modifications and decorations should also be regarded as the protection scope of the present invention.
Claims (10)
1. A method of determining a wellhead injection phase of a fluid, comprising:
obtaining a critical condition of a formation downhole of an injection well, wherein the critical condition comprises at least: safety restrictions, flow restrictions, and design temperature downhole of the formation, the injection well for injecting fluids into each injection zone;
converting the obtained critical conditions into boundary conditions of a wellhead of the injection well;
and determining the wellhead injection phase state of the fluid according to the wellhead boundary condition conversion result.
2. The method of claim 1, wherein obtaining critical conditions for the formation downhole of the injection well comprises:
obtaining a pressure ratio of each reservoir in a bottom hole formation of the injection well;
comparing the obtained pressure ratios of the reservoirs to obtain the maximum pressure ratio of the pressure ratios of the reservoirs;
the maximum pressure ratio is taken as the safety limit for the downhole formation.
3. The method of claim 2, wherein obtaining a pressure ratio for each reservoir in a downhole formation of the injection well comprises:
acquiring the pressure of injected fluid at each reservoir;
acquiring the maximum allowable injection pressure of the stratum;
calculating a ratio between an injected fluid pressure at the reservoirs and a maximum injection pressure allowed for the formation;
and taking the calculated result as the pressure ratio of each reservoir.
4. The method of claim 2, wherein obtaining a pressure ratio for each reservoir in a downhole formation of the injection well comprises:
acquiring the pressure of injected fluid at each reservoir;
acquiring the maximum allowable injection pressure of the stratum;
acquiring an empirical coefficient influencing the maximum injection pressure allowed by the stratum from an empirical value database;
taking the product of the maximum injection pressure allowed by the formation and the empirical coefficient as the maximum injection pressure allowed by the new formation;
calculating a ratio between the injected fluid pressure at each reservoir and the maximum injection pressure allowed for the new formation;
and taking the calculated result as the pressure ratio of each reservoir.
5. The method of claim 3 or 4, wherein obtaining the maximum allowable injection pressure of the formation comprises:
determining the number N of layers of the reservoir in the bottom hole stratum of the injection well;
from the Nth reservoir, reversely deducing from bottom to top, and comparing the well head pressure P obtained from the lower layerkiWhether it is greater than the formation fracture pressure P of the upper reservoirfiIf greater than, then P will beki＝PfiContinuously pushing up the bottom hole pressure as the next layer injection, and if the bottom hole pressure is not greater than the next layer injection, taking the calculated PkiThe bottom hole pressure injected as the next layer is continuously pushed up to the surface, and the wellhead pressure P is obtained0；
Will the well head pressure P0As the maximum injection pressure allowed for the formation.
6. An apparatus for determining a wellhead injection phase of a fluid, comprising:
an obtaining unit for obtaining a critical condition of a formation downhole of an injection well, wherein the critical condition comprises at least: safety restrictions, flow restrictions, and design temperature downhole of the formation, the injection well for injecting fluids into each injection zone;
a conversion unit for converting the obtained critical conditions into boundary conditions of a wellhead of the injection well;
and the determining unit is used for determining the wellhead injection phase state of the fluid according to the wellhead boundary condition conversion result.
7. The apparatus of claim 6, wherein the obtaining unit comprises:
an obtaining module for obtaining a pressure ratio of each reservoir in a bottom hole formation of the injection well;
the comparison module is used for comparing the obtained pressure ratios of the reservoirs to obtain the maximum pressure ratio in the pressure ratios of the reservoirs;
a determination module to determine the maximum pressure ratio as the safe limit condition for the downhole formation.
8. The apparatus of claim 7, wherein the obtaining module comprises:
a first obtaining sub-module for obtaining injected fluid pressures at each reservoir;
the second acquisition sub-module is used for acquiring the maximum injection pressure allowed by the stratum;
a first calculation submodule for calculating a ratio between an injection fluid pressure at the reservoirs and a maximum injection pressure allowed for the formation;
a first determining submodule for determining the calculated result as a pressure ratio of the reservoirs.
9. The apparatus of claim 7, wherein the obtaining module comprises:
a third obtaining sub-module for obtaining injected fluid pressures at each reservoir;
the fourth acquisition submodule is used for acquiring the maximum allowable injection pressure of the stratum;
a fifth obtaining submodule, configured to obtain an empirical coefficient, which affects a magnitude of a maximum injection pressure allowed for the formation, from an empirical value database;
a second determination submodule for determining the product of the maximum injection pressure allowed by the formation and the empirical coefficient as the maximum injection pressure allowed by the new formation;
a second calculation submodule for calculating a ratio between the injected fluid pressure at each reservoir and a maximum injection pressure allowed for the new formation;
and a third determining submodule for determining the calculated result as the pressure ratio of each reservoir.
10. The apparatus of claim 8, wherein the second obtaining sub-module is configured to perform the following steps:
determining the number N of layers of the reservoir in the bottom hole stratum of the injection well;
from the Nth reservoir, reversely deducing from bottom to top, and comparing the well head pressure P obtained from the lower layerkiWhether it is greater than the formation fracture pressure P of the upper reservoirfiIf greater than, then P will beki＝PfiContinuously pushing up the bottom hole pressure as the next layer injection, and if the bottom hole pressure is not greater than the next layer injection, taking the calculated PkiThe bottom hole pressure injected as the next layer is continuously pushed up to the surface, and the wellhead pressure P is obtained0；
Will the well head pressure P0As the maximum injection pressure allowed for the formation.
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