CN112324428A - Method and device for correcting inflow dynamic curve of gas well and computer storage medium - Google Patents
Method and device for correcting inflow dynamic curve of gas well and computer storage medium Download PDFInfo
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- CN112324428A CN112324428A CN201910716909.XA CN201910716909A CN112324428A CN 112324428 A CN112324428 A CN 112324428A CN 201910716909 A CN201910716909 A CN 201910716909A CN 112324428 A CN112324428 A CN 112324428A
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- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B49/00—Testing the nature of borehole walls; Formation testing; Methods or apparatus for obtaining samples of soil or well fluids, specially adapted to earth drilling or wells
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- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B47/00—Survey of boreholes or wells
Abstract
The invention discloses a method and a device for correcting a gas well inflow dynamic curve and a computer storage medium, wherein the method for correcting comprises the following steps: obtaining a wellbore outflow dynamic curve in a VLP model; acquiring a gas well inflow dynamic curve in an IPR model; if the gas production rate corresponding to the intersection point of the shaft outflow dynamic curve and the gas well inflow dynamic curve is not consistent with the actual gas production rate, correcting the gas well inflow dynamic curve according to adjusting parameters to enable the gas production rate corresponding to the intersection point to be consistent with the actual gas production rate, wherein the adjusting parameters comprise: at least one of formation pressure and gas phase permeability. The method can correct the gas well inflow dynamic curve of the IPR model in time in the gas well production process so as to ensure that the gas well can work in a reasonable working mode.
Description
Technical Field
The invention relates to the technical field of oil and gas field development, in particular to a method and a device for correcting a gas well inflow dynamic curve and a computer storage medium.
Background
The gas well shaft model is the key for connecting the ground gathering and transportation pipe network model and the gas reservoir model. Gas well wellbore models include a gas well Inflow dynamics (IPR) model and a wellbore outflow dynamics (VLP) model. The IPR model is a dynamic characteristic model of stratum flowing into a gas well and reflects the relation between bottom hole flowing pressure and gas production rate of a reservoir flowing to a shaft, and the VLP model is a pipe flow model of flowing change of multi-phase fluid in the shaft and reflects the relation between bottom hole flowing pressure and shaft production under specific shaft pipe size, shaft pipe descending depth and well mouth conditions. When the working mode of the gas well is formulated, a gas well inflow dynamic curve is usually extracted from the IPR model, and a reasonable working mode of the gas well is formulated according to the working characteristics of a gas layer reflected by the gas well inflow dynamic curve.
In the production process of the gas well, the formation pressure of a reservoir, the physical properties of the reservoir and the production state of the gas well are constantly changed, and the IPR model is related to the formation pressure of the reservoir, the physical properties of the reservoir and the production state of the gas well, so that the timely correction of the inflow dynamic curve of the gas well in the production process of the gas well is an important guarantee for the reasonable work of the gas well.
Disclosure of Invention
The embodiment of the invention provides a method and a device for correcting a gas well inflow dynamic curve and a computer storage medium, which can correct the gas well inflow dynamic curve of an IPR model in the production process of a gas well so as to ensure that the gas well can work in a reasonable working mode. The technical scheme is as follows:
in a first aspect, an embodiment of the present invention provides a method for correcting a gas well inflow dynamic curve, where the method includes: obtaining a wellbore outflow dynamic curve in a VLP model; acquiring a gas well inflow dynamic curve in an IPR model; if the gas production rate corresponding to the intersection point of the shaft outflow dynamic curve and the gas well inflow dynamic curve is not consistent with the actual gas production rate, correcting the gas well inflow dynamic curve according to adjusting parameters to enable the gas production rate corresponding to the intersection point to be consistent with the actual gas production rate, wherein the adjusting parameters comprise: at least one of formation pressure and gas phase permeability.
In one implementation of the embodiment of the present invention, the correcting the gas well inflow dynamic curve according to the adjustment parameter includes at least one of: adjusting the intercept of the bottom hole flowing pressure of the gas well inflow dynamic curve according to the formation pressure; and adjusting the slope of the gas well inflow dynamic curve according to the gas phase permeability.
In another implementation of an embodiment of the present invention, prior to said obtaining a wellbore outflow dynamic profile in a VLP model, said method further comprises: sequentially and iteratively calculating the pressure of a plurality of areas axially spaced in the shaft from the bottom to the top, wherein the pressure of each area in the plurality of areas is calculated by one of a plurality of different pipe flow pattern calculation methods until a plurality of top pressures are calculated; determining one of the plurality of wellhead pressures that is closest to the measured wellhead pressure; and establishing the VLP model according to the pipe flow pattern calculation method adopted by the plurality of zones when the wellhead pressure is calculated.
In another implementation of the embodiment of the invention, the calculation method for calculating the pressure of each area is selected according to at least one of the following manners: if the flow pattern of the area is a bubble flow, the selected pipe flow pattern calculation method is a Wallians-Griffith algorithm; if the flow pattern of the area is slug flow, the selected pipe flow pattern calculation method is a Hagedown-Brown algorithm; if the flow pattern of the area is transition flow, the selected pipe flow pattern calculation method is a Duns-Ros algorithm; if the flow pattern of the area is mist flow, the selected pipe flow pattern calculation method is a Duns-Ros algorithm.
In another implementation manner of the embodiment of the present invention, the correction method further includes: if the water-gas ratio of the gas well is less than 0.5m3/104m3Correcting the gas well inflow dynamic curve according to the frequency of 1 time/30 days; if the water-gas ratio of the gas well is not less than 0.5m3/104m3And not more than 1.0m3/104m3Correcting the gas well inflow dynamic curve according to the frequency of 1 time/15 days; if the water-gas ratio of the gas well is more than 1.0m3/104m3And correcting the gas well inflow dynamic curve according to the frequency of 1 time/7 days.
In a second aspect, an embodiment of the present invention provides a correction device for a gas well inflow dynamic curve, where the correction device includes: the obtaining module is used for obtaining a shaft outflow dynamic curve in the VLP model and a gas well inflow dynamic curve in the IPR model; the correction module is used for correcting the gas well inflow dynamic curve according to an adjusting parameter if the gas production rate corresponding to the intersection point of the shaft outflow dynamic curve and the gas well inflow dynamic curve is not consistent with the actual gas production rate, so that the gas production rate corresponding to the intersection point is consistent with the actual gas production rate, wherein the adjusting parameter comprises: at least one of formation pressure and gas phase permeability.
In another implementation of the embodiment of the invention, the correction module corrects the inflow dynamic curve of the gas well in at least one of the following two ways: adjusting the intercept of the bottom hole flowing pressure of the gas well inflow dynamic curve according to the formation pressure; and adjusting the slope of the gas well inflow dynamic curve according to the gas phase permeability.
In another implementation manner of the embodiment of the present invention, the correction apparatus further includes: the calculation module is used for sequentially and iteratively calculating the pressure of a plurality of axially spaced areas in the shaft from the bottom to the top, and the pressure of each area in the areas is calculated by adopting one of a plurality of different pipe flow pattern calculation methods until a plurality of top pressures are calculated; the determining module is used for determining one wellhead pressure which is closest to the measured wellhead pressure in the plurality of wellhead pressures; and the establishing module is used for establishing the VLP model according to the pipe flow pattern calculation method correspondingly adopted by the plurality of areas when the wellhead pressure is calculated.
In a third aspect, an embodiment of the present invention provides a correction device for a gas well inflow dynamic curve, where the correction device includes: a processor; a memory configured to store processor-executable instructions; wherein the processor is configured to perform the correction method described above.
In a fourth aspect, an embodiment of the present invention provides a computer storage medium, where the computer instructions, when executed by a processor, implement the correction method described above.
The technical scheme provided by the embodiment of the invention has the beneficial effects that at least:
by obtaining a shaft outflow dynamic curve from a VLP model and obtaining a gas well inflow dynamic curve from an IPR model, wherein the shaft outflow dynamic curve can reflect the relationship between the bottom hole flowing pressure in a shaft and the gas production rate of the gas well flowing to a well opening from the bottom of the shaft, the gas well inflow dynamic curve can reflect the relationship between the bottom hole flowing pressure and the gas production rate of a stratum flowing into the shaft, because the shaft outflow dynamic curve reflects the relationship between the bottom hole flowing pressure and the gas production rate of the gas well under the current state of the shaft, and the gas well inflow dynamic curve reflects the relationship between the gas production rate of the stratum flowing into the shaft and the bottom hole flowing pressure in the current reservoir, the intersection point of the shaft outflow dynamic curve and the gas well inflow dynamic curve can reflect the corresponding relationship between the bottom hole flowing pressure and the gas production rate determined by the current state of the shaft and the current reservoir, if the gas production rate corresponding to the intersection point of the shaft outflow dynamic curve and, therefore, under the condition that the gas yield corresponding to the intersection point of the shaft outflow dynamic curve and the gas well inflow dynamic curve is not consistent with the actual gas yield, the gas well inflow dynamic curve is corrected according to at least one of formation pressure and gas phase permeability, so that the gas yield corresponding to the intersection point is consistent with the actual gas yield, and the gas well inflow dynamic curve of the IPR model is corrected in time in the gas well production process, so that the gas well can work in a reasonable working mode.
Drawings
In order to more clearly illustrate the technical solutions in the embodiments of the present invention, the drawings needed to be used in the description of the embodiments will be briefly introduced below, and it is obvious that the drawings in the following description are only some embodiments of the present invention, and it is obvious for those skilled in the art to obtain other drawings based on these drawings without creative efforts.
FIG. 1 is a flow chart of a method for correcting a gas well inflow dynamic curve provided by an embodiment of the invention;
FIG. 2 is a flow chart of another method for correcting a gas well inflow dynamic curve provided by an embodiment of the invention;
FIG. 3 is a schematic illustration of a gas well inflow dynamic curve and a wellbore outflow dynamic curve provided by an embodiment of the present invention;
FIG. 4 is a schematic illustration of a gas well inflow dynamic curve correction provided by an embodiment of the present invention;
FIG. 5 is a schematic illustration of another gas well inflow dynamics correction apparatus provided in accordance with an embodiment of the present invention;
FIG. 6 is a schematic diagram of another gas well inflow dynamics correction apparatus provided by an embodiment of the present invention.
Detailed Description
In order to make the objects, technical solutions and advantages of the present invention more apparent, embodiments of the present invention will be described in detail with reference to the accompanying drawings.
During gas field development, a gas well wellbore model is typically built, and gas well production is predicted based on a VLP model and an IPR model in the gas well wellbore model. The IPR model reflects the change of bottom hole flowing pressure and yield, is the comprehensive reflection of the working characteristics of the gas layer, is an important basis for determining the reasonable working mode of the gas well, is related to the formation pressure, the physical properties of the reservoir layer and the production state of the gas well, and changes continuously along with the production time. In the process of developing a gas reservoir, the gas production rate of most gas wells in the production process is continuously reduced due to a plurality of factors such as the reduction of formation pressure, the invasion of bottom-edge water, the reduction of gas flow rate, the increase of bottom-hole liquid loading, the increase of liquid production amount and the like, so that an IPR model can also change along with the production of the gas wells, and in order to determine the reasonable working mode of the gas wells, it is necessary to correct the gas well inflow dynamic curve of the IPR model in time.
Fig. 1 is a flowchart of a method for correcting a gas well inflow dynamic curve according to an embodiment of the present invention. As shown in fig. 1, the calibration method is executed by an upper computer, and includes:
step 101: wellbore outflow dynamic profiles in a VLP model were obtained.
The dynamic curve of the flowing out of the shaft reflects the relationship between the bottom hole flowing pressure in the shaft and the gas production rate of the gas well flowing to the wellhead from the bottom hole.
Step 102: and acquiring a gas well inflow dynamic curve in the IPR model.
The gas well inflow dynamic curve reflects the relationship between bottom hole flowing pressure and gas production rate of stratum flowing into a shaft.
Step 103: and if the gas production rate corresponding to the intersection point of the shaft outflow dynamic curve and the gas well inflow dynamic curve is not consistent with the actual gas production rate, correcting the gas well inflow dynamic curve according to the adjusting parameters to ensure that the gas production rate corresponding to the intersection point is consistent with the actual gas production rate.
Wherein, the adjusting parameters comprise: at least one of formation pressure and gas phase permeability.
The coincidence means that the values are different within the allowable error range. For example, the actual gas production is Nm3Then, the gas production rate corresponding to the intersection point may be N + - [ N x (1% -2%) within the allowable error range]. So as to ensure the error and reasonable range between the gas production rate corresponding to the intersection point and the actual gas production rate, and ensure that the correction result is more accurate.
It should be noted that the allowable error range illustrated above does not limit the range of the acceptable value of the gas production rate corresponding to the intersection point in the embodiment of the present invention, as long as the gas production rate corresponding to the intersection point satisfies the required accuracy. For example, when the required accuracy is high, the gas production rate corresponding to the intersection point may be N + - (N × 1%); when the required accuracy is not high, the gas production rate corresponding to the intersection point may be N +/- (N × 2%), and this embodiment is not limited.
By obtaining a shaft outflow dynamic curve from a VLP model and obtaining a gas well inflow dynamic curve from an IPR model, wherein the shaft outflow dynamic curve can reflect the relationship between the bottom hole flowing pressure in a shaft and the gas production rate of the gas well flowing to a well opening from the bottom of the shaft, the gas well inflow dynamic curve can reflect the relationship between the bottom hole flowing pressure and the gas production rate of a stratum flowing into the shaft, because the shaft outflow dynamic curve reflects the relationship between the bottom hole flowing pressure and the gas production rate of the gas well under the current state of the shaft, and the gas well inflow dynamic curve reflects the relationship between the gas production rate of the stratum flowing into the shaft and the bottom hole flowing pressure in the current reservoir, the intersection point of the shaft outflow dynamic curve and the gas well inflow dynamic curve can reflect the corresponding relationship between the bottom hole flowing pressure and the gas production rate determined by the current state of the shaft and the current reservoir, if the gas production rate corresponding to the intersection point of the shaft outflow dynamic curve and, therefore, the gas well inflow dynamic curve is corrected according to at least one of formation pressure and gas phase permeability under the condition that the gas yield corresponding to the intersection point of the shaft outflow dynamic curve and the gas well inflow dynamic curve is not consistent with the actual gas yield, so that the gas yield corresponding to the intersection point is consistent with the actual gas yield, the gas well inflow dynamic curve of the IPR model is corrected in the gas well production process, and the gas well can work in a reasonable working mode.
FIG. 2 is a flow chart of another method for correcting a gas well inflow dynamic curve according to an embodiment of the invention. As shown in fig. 2, the calibration method is executed by an upper computer, and includes:
step 201: wellbore outflow dynamic profiles in a VLP model were obtained.
The dynamic curve of the flowing out of the shaft reflects the relationship between the bottom hole flowing pressure in the shaft and the gas production rate of the gas well flowing to the wellhead from the bottom hole. In this example, the wellbore outflow dynamic profile can be obtained directly from the VLP model.
Before step 201, it may also include modeling VLPs. The VLP model can be established as follows:
first, basic parameters of a shaft are obtained.
Since the VLP model is a model reflecting flow changes in the wellbore, basic parameters of the wellbore need to be obtained first when building the VLP model. The base parameters may include: at least one of PVT basic parameters, high pressure physical property analysis data, gas reservoir actual parameters, reservoir parameters, wellbore data, production data, and pressure test data.
Wherein, the PVT basic parameters comprise: natural gas relative density, separator pressure at sampling (Kpa), condensate-to-oil ratio (m)3/Km3) Density of condensate oil (Kg/m)3) Degree of water mineralization (ppm), H2Mole percent S, (%), CO2Mole percent (%), N2At least one of mole percent (%).
The high pressure physical analysis data included: deviation factor and natural gas volume coefficient (m) corresponding to different pressure (KPa) conditions at formation temperature3/m3) At least one of (1).
The actual parameters of the gas reservoir include: at least one of a reservoir virgin formation pressure (KPa), a reservoir temperature (deg.C).
The reservoir parameters include: at least one of reservoir effective thickness H (m), reservoir porosity (φ), reservoir permeability K (mD).
Wellbore data includes: well deviation data, tubular column structure, geothermal gradient, heat transfer coefficient, drainage area (m)2) And a well radius (m).
The production data includes: virgin formation pressure (Pr), bottom hole flow pressure (Pwf), daily gas production (Qg), daily water production (Qw), produced water to gas ratio (m)3/m3) At least one of (1).
The stress test data includes: at least one of time, temperature, bottom hole pressure is tested.
Inputting the basic data into a model attribute menu of an IPM software PROSPER module, and sequentially importing PVT basic parameters, high-pressure physical property analysis data, gas reservoir actual parameters, reservoir parameters, shaft data, production data and pressure test data.
And secondly, fitting the acquired PVT data.
Wherein, the fitting is that various different PVT basic parameters in the well bore are connected by a smooth curve. The PVT data refer to: fluid pressure in the wellbore, fluid volume, and temperature data within the wellbore. Fitting of PVT data, which is performed by a PROSPER module in IPM software, can obtain flow pressure, fluid volume and temperature data at various positions in the wellbore from the fitted curves.
After fitting of the PVT data is completed, pipe flow pattern calculation methods at different positions in the shaft are determined according to the fitted PVT data, and the pipe flow pattern calculation methods corresponding to the different positions in the shaft are combined together to establish a VLP model.
And thirdly, sequentially and iteratively calculating the pressure of a plurality of axially spaced areas in the shaft from the bottom to the top, wherein the pressure of each area in the plurality of areas is calculated by adopting one of a plurality of different pipe flow pattern calculation methods until a plurality of top pressures are calculated.
For example, the wellbore is divided into a plurality of sub-wellbores along the axial direction, the plurality of zones may be in the wellbore, the top end positions of the plurality of sub-wellbores are divided into, for example, 10 sub-wellbores, the top end position of each sub-wellbore is a zone, and the pressure of a certain zone is the pressure of the top end position of a certain sub-wellbore. Thus, when calculating the zone at the bottom of the well bore (the sub-well bore at the bottom of the well bore), the flowing pressure at the top end of the sub-well bore can be calculated according to the bottom flowing pressure and the PVT basic data in the well bore fitted in the second step, and then the flowing pressure at the top end of the sub-well bore is taken as the flowing pressure at the bottom end of the next sub-well bore, so that the flowing pressure at the top end of the sub-well bore at the top end is calculated iteratively from the bottom to the well bore.
Alternatively, the pressure in each zone may be calculated using one of the methods of Wallians-Griffith, Hagedorn-Brown, Duns-Ros, Orkiszewski, Mukheijee-Brill, Aziz, Cornish, Poettmann, and the various algorithms described above are capable of calculating pipe flows of different flow patterns. That is, each region may be calculated for flow pressure using any of the above-described calculation methods.
For example, the wellbore is divided into 10 zones, and any of the 8 algorithms described above may be employed in calculating each zone. For example, the first region may use Duns-Ros algorithm, and the second region may still use any one of 8 algorithms, that is, the region selection algorithms are not related to each other, and are all random options. Thus, when the wellbore is divided into 10 zones, a total of 8 can be calculated10The calculation result is 810Individual wellhead pressure.
In actual production, the process of fluid flowing from the bottom of a well bore to a well head is an unsteady state flow process, but the efficiency of the transient flow multiphase simulation calculation method is low, the stability is poor, and the requirement of real-time operation and maintenance of a gas field cannot be met. Therefore, the method for calculating the unsteady-state flowing fluid (such as a transient-flow multiphase simulation calculation method) is simplified into a plurality of sub-processes (see the following formula) approximate to the steady-state flowing in a large time dimension (more than 0.5 d). The method comprises the steps of optimizing a multiphase flow steady-state calculation model of different flow states of gas-water two-phase flow in each space position of a gas well shaft, applying an optimal multiphase steady-state flow calculation model for the different flow states of each space position according to flow state division standards when a shaft model is iteratively solved according to the sub-shaft, comparing pressure actual measurement data of a large number of water producing gas wells in a mine field with different sub-process steady-state flow calculation methods, and optimizing the calculation method meeting the real-time operation and maintenance requirements of the gas field and having the highest solving precision.
Wherein q isg/qwThe gas-liquid ratio; a. b and c are characteristic parameters of flow pattern division; A. b is a transition flow calculation coefficient which is related to fluid parameters such as Reynolds number and the like; v. ofDA dimensionless gas flow rate; subscript B, S, M represents bubble flow, slug flow, and mist flow, respectively; subscript G, F represents gravity, friction, respectively.
The left side (left part of parenthesis) in the above formula may be any one of the previously mentioned calculation methods Wallians-Griffith, Hagedorn-Brown, Duns-Ros, Orkiiszewski, Mukherijee-Brill, Aziz, Cornish, Poettmann. The right side of the formula (four sub-algorithms on the right side of the brace) is the sub-algorithm corresponding to different pipe flow patterns in each calculation method. From top to bottom, the first sub-algorithm is a sub-algorithm corresponding to bubble flow, the second sub-algorithm is a sub-algorithm corresponding to slug flow, the third sub-algorithm is a sub-algorithm corresponding to bubble flow and slug flow at the same time, and the fourth sub-algorithm is a sub-algorithm corresponding to mist flow.
In the above sub-algorithm, the gas-liquid ratio q is determinedg/qwDimensionless gas flow velocity vDJudging the flow pattern of the pipe flow, and selecting a sub-algorithm corresponding to the flow pattern in the calculation method after determining the flow pattern. For example, when q isg/qwWhen the flow pattern is determined to be bubble flow, the sub-algorithm shown in the first row can be selected to calculate the flow pressure in the corresponding area.
Fourthly, determining one wellhead pressure which is closest to the actually measured wellhead pressure in the plurality of wellhead pressures; and establishing a VLP model according to pipe flow pattern calculation methods correspondingly adopted by a plurality of areas when the pressure of one wellhead is calculated.
As illustrated in the third step, when the wellbore is divided into 10 zones and 8 are calculated by the method described in the third step10After calculating the result, from 810A calculation closest to the measured wellhead pressure is determined from the calculations. And the calculation methods adopted in the 10 areas in the calculation result are combined to establish a VLP model.
For example, the first region employs the Duns-Ros algorithm, the second region employs the Hagedorn-Brown, the third region employs the Cornish algorithm … …, and the tenth region employs the Hagedorn-Brown algorithm. The VLP model with high accuracy can be established by combining the 10 algorithms and using each algorithm to calculate the corresponding region in the shaft.
The iterative calculation method in the third step may be used to determine a plurality of different combinations of calculations for the wellbore, and the different combinations may be verified by comparing the calculated flow pressure at the wellhead region with the measured wellhead pressure. And when determining that the wellhead pressure is the pressure closest to the actually measured wellhead pressure, determining that the wellhead pressure has the best conformity degree to the precision requirement, and establishing a VLP model according to a pipe flow pattern calculation method correspondingly adopted by a plurality of areas when calculating the wellhead pressure.
Because the flow patterns of the sub-wellholes at different positions in the wellhole are different, and various pipe flow pattern calculation methods can be used for calculating fluids with different flow patterns, the method for determining the proper pipe flow pattern calculation method according to the flow patterns in the wellhole is greatly helpful for establishing an accurate VLP model. In this example, the following selection rules for the pipe flow pattern calculation method were obtained from a large amount of experimental data, as detailed in table 1:
if the flow pattern of the sub-area is a bubble flow, the selected pipe flow pattern calculation method is Wallians-Griffith algorithm. If the flow pattern of the area is slug flow, the selected pipe flow pattern calculation method is a Hagedown-Brown algorithm. If the flow pattern of the area is transition flow, the selected pipe flow pattern calculation method is a Duns-Ros algorithm. If the flow pattern of the area is mist flow, the selected pipe flow pattern calculation method is a Duns-Ros algorithm.
TABLE 1
Step 202: and acquiring a gas well inflow dynamic curve in the IPR model.
The gas well inflow dynamic curve reflects the relationship between bottom hole flowing pressure and gas production rate of stratum flowing into a shaft. In this embodiment, the downhole inflow dynamic curve may be obtained directly from the IPR model.
In this embodiment, the IPR model may be established in the following two ways:
firstly, for a gas well subjected to productivity test, calculating the unobstructed flow of the gas well by using a binomial productivity formula according to the productivity test data of the gas well, drawing a bottom-hole inflow dynamic curve, and establishing an IPR model. The process of establishing the binomial formula is a conventional technical means, and the embodiment is not described.
And secondly, for a gas well which is not subjected to the productivity test, an IPR model is established by using a PROSPER module in IPM software. In the establishing process, a model formula Petreleum Experts can be selected, actual parameters of the gas reservoir, such as reservoir thickness, average permeability, average porosity, average water saturation and natural gas density, are input, so that a bottom hole inflow dynamic curve is generated, and an IPR model is established.
Step 203: the wellbore outflow dynamic profile in combination with the VLP model corrects the gas well inflow dynamic profile of the IPR model.
Since the IPR model changes with gas well production during the development of the gas field, corrections to the IPR model are required. During correction, a shaft outflow dynamic curve and a gas well inflow dynamic curve are extracted from the VLP model and the IPR model, and both the shaft outflow dynamic curve and the gas well inflow dynamic curve are relative to the relation curve of bottom hole flow pressure and gas production, so that the two curves can be drawn in the same plane coordinate system. And the shaft outflow dynamic curve reflects the relation between the shaft bottom flowing pressure in the shaft and the gas well output, and the gas well inflow dynamic curve reflects the relation between the shaft bottom flowing pressure and the gas production rate of the stratum flowing to the shaft, so that the intersection point of the two curves can reflect the corresponding relation between the shaft bottom flowing pressure and the gas production rate determined by the shaft and the current reservoir condition under the current state, namely the gas production rate of the intersection point is the same as the actual gas production rate.
Having determined the intersection of the wellbore outflow dynamic curve and the gas well inflow dynamic curve, the gas well inflow dynamic curve may be corrected according to steps 203a and 203b below.
Step 203 a: and if the gas production rate corresponding to the intersection point of the shaft outflow dynamic curve and the gas well inflow dynamic curve is not consistent with the actual gas production rate, correcting the gas well inflow dynamic curve according to the adjusting parameters to ensure that the gas production rate corresponding to the intersection point is consistent with the actual gas production rate.
Wherein, the adjusting parameters comprise: at least one of formation pressure and gas phase permeability. Coincidence is defined as a difference between two values within an acceptable range.
The main reasons why the IPR model is subject to change over production time are: (1) the formation pressure changes; (2) reservoir parameters change. Since the gas well is put into production in the mine field, the formation pressure continuously decreases along with the production time, and the intersection point of the gas well inflow dynamic curve of the IPR model and the ordinate is continuously moved downwards. In addition, the average gas permeability of the near wellbore region reservoir may be reduced under the conditions that the near wellbore region reservoir is polluted by chemical agents (such as acid liquor, fracturing fluid, gel, polymer and the like) or water invasion from bottom to top caused by improper production measure treatment, and if the change of the formation pressure is small in a period of time and the gas well inflow dynamic curve of the IPR model is provided, the slope of the gas well inflow dynamic curve of the IPR model is changed due to the reduction of the average gas permeability of the near wellbore region reservoir. Therefore, if the gas production rate corresponding to the intersection point is not consistent with the actual gas production rate, the gas well inflow dynamic curve is corrected according to the formation pressure and the gas phase permeability.
The correction can include the following conditions:
first, gas wells produce no water. If the gas well does not produce water, the change of the well condition of the gas well is not large, and the gas phase permeability of the gas well does not change at the moment, so that the gas production rate of the intersection point is not consistent with the actual gas production rate due to the fact that the formation pressure is reduced due to gas well production. I.e. only the formation pressure is changed in the adjustment parameters.
As shown in fig. 3, the gas well inflow dynamic curve of the IPR model shows that the bottom hole flowing pressure is in inverse proportion to the gas well production, i.e. the bottom hole flowing pressure is larger, the gas well production is smaller, and when the gas well production is 0, the bottom hole flowing pressure reaches the maximum, and the formation pressure is the same as the bottom hole flowing pressure, so that the gas in the reservoir layer is difficult to enter the gas well from the reservoir layer without the action of differential pressure, and the gas well production is minimum. That is, when the gas well production is 0, the corresponding bottom hole flowing pressure should be equal to the formation pressure, and as can be seen from fig. 3, the intercept of the bottom hole flowing pressure of the gas well inflow dynamic curve is the formation pressure.
When the gas well inflow dynamic curve is corrected according to the formation pressure, the intercept of the bottom hole flow pressure of the gas well inflow dynamic curve can be corrected according to the formation pressure. Corresponding to the plane coordinate system, the gas well inflow dynamic curve is moved up and down along the vertical coordinate, and the combination of the graph in fig. 4, f (P)1，K1) For a well inflow dynamic curve before migration, f (P)2，K1) Is a shifted gas well inflow dynamics curve, wherein f (P)1，K1) And f (P)2，K1) The slopes of (a) are all the same, and the intercepts are P1 and P2, respectively. And (4) until the gas production rate corresponding to the intersection point is coincided with the actual gas production rate again, the formation pressure corresponding to the ordinate is the current formation pressure, and the correction is completed.
In this embodiment, the IPR model can be established by two different methods. If the productivity well testing data is adopted and the IPR model established by combining the binomial productivity formula is adopted, the formation pressure can be reversely solved by utilizing the pressure measurement data in the productivity well testing data, so that the intercept of the bottom hole flowing pressure of the gas well flowing dynamic curve can be directly determined according to the formation pressure for the gas well with the productivity well testing data, the gas well flowing dynamic curve does not need to move up and down along a vertical coordinate, and the gas production rate corresponding to the intersection point is not matched with the actual gas production rate again.
It should be noted that, because the productivity well testing data is only the productivity data tested within a certain period of working time of the gas well, when the productivity well testing data is not enough to meet the requirement of the back-pressure of the formation after the gas well works for a period of time, the inflow dynamic curve of the gas well is required to move up and down along the vertical coordinate according to the correction method, so that the intersection point is coincided with the actual gas production rate again.
If no well testing data is obtained by adopting an IPR model established by a PROSPER module in IPM software, the current formation pressure cannot be obtained, so that the gas well inflow dynamic curve can be corrected only by a method of enabling the gas well inflow dynamic curve to move up and down along a vertical coordinate until the gas production rate corresponding to the intersection point is coincided with the actual gas production rate again, and the correction of the gas well inflow dynamic curve is completed.
Second, gas well water production. If the gas well produces water, the change of the well condition of the gas well is large, the gas phase relative permeability of a reservoir layer in a near wellbore region is changed due to the gas well producing water, the previously obtained well testing permeability is not applicable, and the real-time formation pressure cannot be obtained, so that the gas production corresponding to the intersection point is not matched with the actual gas production. That is, the formation pressure and the gas phase permeability in the adjustment parameters are both changed, during correction, as the gas well produces water, the main factor influencing the gas well IPR model is the near-wellbore region reservoir average gas phase permeability within a certain time, firstly, the current formation pressure is determined by using static pressure measurement data (point static pressure measurement, pressure recovery test and the like) of the well or an adjacent well, and the slope of the gas well inflow dynamic curve is corrected by adjusting the near-wellbore region reservoir average gas phase permeability of the well until the intersection point is matched with the actual gas production, so that the correction is completed.
After determining the current formation pressure during correction, determining the ordinate of the gas well inflow dynamic curve in the coordinate system, and then correcting the slope of the gas well inflow dynamic curve by inputting the gas permeability in the PROSPER module in the IPM software (see fig. 4, f (P) in fig. 41，K1) And f (P)1，K2)). And the gas well inflow dynamic curve obtained after the gas phase permeability is adjusted is determined again until the gas production rate corresponding to the intersection point is consistent with the actual gas production rate, and the correction is completed.
Step 203 b: and if the gas production rate corresponding to the intersection point of the shaft outflow dynamic curve and the gas well inflow dynamic curve is consistent with the actual gas production rate, the gas well inflow dynamic curve is not corrected.
In this embodiment, for a gas well producing water, the average gas phase permeability in the near wellbore region changes rapidly, so whether the intersection point coincides with the actual gas production rate should be monitored in time, and the inflow dynamic curve of the gas well should be corrected in time.
Step 204: and determining the adjustment frequency of the gas well inflow dynamic curve according to the water-gas ratio of the gas well.
Alternatively, if the gas well has a water-to-gas ratio of less than 0.5m3/104m3And adjusting the inflow dynamic curve of the gas well according to the frequency of 1 time/30 days. If the water-gas ratio of the gas well is not less than 0.5m3/104m3And not more than 1.0m3/104m3And adjusting the inflow dynamic curve of the gas well according to the frequency of 1 time/15 days. If the water-gas ratio of the gas well is more than 1.0m3/104m3And adjusting the inflow dynamic curve of the gas well according to the frequency of 1 time/7 days.
The following table reflects the relationship between the gas-water ratio of an actual production well of a certain gas reservoir and the correction frequency of a gas well inflow dynamic curve, and can be known by combining the table 2.
For inclined wells, when the water-gas ratio of the gas well is less than 0.5m3/104m3The duration time that the gas production amount predicted by the IPR model accords with the reality is more than 45 days; for horizontal wells, when the gas well has a water-gas ratio of less than 0.5m3/104m3And the duration time of the gas production amount predicted by the IPR model is more than 90 days according with the actual gas production amount. Therefore, in order to ensure the accuracy of the IPR model, the adjustment frequency of the gas well inflow dynamic curve of the IPR model can be set to be 1 time/30 days.
For inclined wells, when the water-gas ratio of the gas well is not less than 0.5m3/104m3And not more than 1.0m3/104m3Then, the duration time of the gas production amount predicted by the IPR model and the actual gas production amount is 18; for a horizontal well, when the water-gas ratio of the gas well is not less than 0.5m3/104m3And not more than 1.0m3/104m3Then, the duration time of the gas production amount predicted by the IPR model and the actual gas production amount is 16 days; for a vertical well, when the water-gas ratio of the gas well is not less than 0.5m3/104m3And not more than 1.0m3/104m3The duration of the gas production predicted by the IPR model is 20 according to the actual gas production. Therefore, to ensure the accuracy of the IPR model, the adjustment of the gas well inflow dynamic curve of the IPR model can be setThe frequency was 1 time/15 days.
For inclined wells, when the water-gas ratio of the gas well is more than 1.0m3/104m3In time, the duration time of the gas production amount predicted by the IPR model and the actual gas production amount is 9 days; for horizontal wells, when the water-gas ratio of the vertical well is more than 1.0m3/104m3And in time, the duration of the gas production rate predicted by the IPR model and the actual duration are all more than 10 days. Therefore, in order to ensure the accuracy of the IPR model, the adjustment frequency of the gas well inflow dynamic curve of the IPR model can be set to be 1 time/7 days.
TABLE 2
FIG. 5 is a schematic diagram of another gas well inflow dynamics correction apparatus provided by an embodiment of the present invention. As shown in fig. 5, the correction device includes: an acquisition module 100 and a correction module 200. The obtaining module 100 is configured to obtain a wellbore outflow dynamic curve in a VLP model and a gas well inflow dynamic curve in an IPR model. The correction module 200 is configured to correct the gas well inflow dynamic curve according to the adjustment parameter if the gas production rate corresponding to the intersection point of the wellbore outflow dynamic curve and the gas well inflow dynamic curve is not consistent with the actual gas production rate, so that the gas production rate corresponding to the intersection point is consistent with the actual gas production rate, and the adjustment parameter includes: at least one of formation pressure and gas phase permeability.
Optionally, the correction module 200 corrects the gas well inflow dynamics in at least one of two ways: adjusting the intercept of the bottom hole flowing pressure of the gas well inflow dynamic curve according to the formation pressure; and adjusting the slope of the gas well inflow dynamic curve according to the gas phase permeability.
Optionally, the correction device further comprises a calculation module 300, a determination module 400 and a setup module 500. The calculation module 300 is configured to iteratively calculate pressures of a plurality of axially spaced zones within the wellbore from the bottom of the wellbore to the top of the wellbore in sequence, wherein the pressure of each of the plurality of zones is calculated using one of a plurality of different pipe flow pattern calculation methods until a plurality of top of the wellbore pressures are calculated. The determination module 400 is configured to determine a wellhead pressure of the plurality of wellhead pressures that is closest to the measured wellhead pressure. The building block 500 is configured to build a VLP model according to pipe flow pattern calculation methods correspondingly adopted by a plurality of zones when calculating a wellhead pressure.
FIG. 6 is a schematic diagram of another gas well inflow dynamics correction apparatus provided by an embodiment of the present invention. As shown in fig. 6, the gas well inflow dynamics curve calibration device 700 may be a computer or the like.
In general, the device 700 for correcting the inflow dynamic curve of a gas well comprises: a processor 701 and a memory 702.
The processor 701 may include one or more processing cores, such as a 4-core processor, an 8-core processor, and so on. The processor 701 may be implemented in at least one hardware form of a DSP (Digital Signal Processing), an FPGA (Field-Programmable Gate Array), and a PLA (Programmable Logic Array). The processor 701 may also include a main processor and a coprocessor, where the main processor is a processor for Processing data in an awake state, and is also called a Central Processing Unit (CPU); a coprocessor is a low power processor for processing data in a standby state. In some embodiments, the processor 701 may be integrated with a GPU (Graphics Processing Unit), which is responsible for rendering and drawing the content required to be displayed on the display screen. In some embodiments, the processor 701 may further include an AI (Artificial Intelligence) processor for processing computing operations related to machine learning.
In some embodiments, the device 700 for correcting the inflow dynamic curve of the gas well may further include: a peripheral interface 703 and at least one peripheral. The processor 701, the memory 702, and the peripheral interface 703 may be connected by buses or signal lines. Various peripheral devices may be connected to peripheral interface 703 via a bus, signal line, or circuit board. Specifically, the peripheral device includes: at least one of radio frequency circuitry 704, touch screen display 705, camera 706, audio circuitry 707, positioning components 708, and power source 709.
The peripheral interface 703 may be used to connect at least one peripheral related to I/O (Input/Output) to the processor 701 and the memory 702. In some embodiments, processor 701, memory 702, and peripheral interface 703 are integrated on the same chip or circuit board; in some other embodiments, any one or two of the processor 701, the memory 702, and the peripheral interface 703 may be implemented on a separate chip or circuit board, which is not limited in this embodiment.
The display screen 705 is used to display a UI (User Interface). The UI may include graphics, text, icons, video, and any combination thereof. When the display screen 705 is a touch display screen, the display screen 705 also has the ability to capture touch signals on or over the surface of the display screen 705. The touch signal may be input to the processor 701 as a control signal for processing. At this point, the display 705 may also be used to provide virtual buttons and/or a virtual keyboard, also referred to as soft buttons and/or a soft keyboard. In some embodiments, the display screen 705 may be a front panel of the correction device 700 that sets the gas well inflow dynamics; in other embodiments, the display screen 705 may be at least two, each disposed on a different surface of the gas well inflow dynamics correction apparatus 700 or in a folded design; in still other embodiments, the display 705 may be a flexible display disposed on a curved surface or a folding surface of the gas well inflow dynamics correction apparatus 700. Even more, the display 705 may be arranged in a non-rectangular irregular pattern, i.e. a shaped screen. The Display 705 may be made of LCD (Liquid Crystal Display), OLED (Organic Light-Emitting Diode), or the like.
A power supply 709 is used to supply power to the various components of the gas well inflow dynamics correction apparatus 700. The power source 709 may be alternating current, direct current, disposable batteries, or rechargeable batteries. When power source 709 includes a rechargeable battery, the rechargeable battery may support wired or wireless charging. The rechargeable battery may also be used to support fast charge technology.
Those skilled in the art will appreciate that the configuration shown in FIG. 5 does not constitute a definition of a correction device 700 for gas well inflow dynamics and may include more or fewer components than shown, or some components in combination, or a different arrangement of components.
Embodiments of the present invention also provide a computer storage medium, where instructions in the computer storage medium, when executed by a processor of a gas well inflow dynamic curve correction device, enable the gas well inflow dynamic curve correction device to execute the gas well inflow dynamic curve correction method provided in the embodiment shown in fig. 1 or fig. 2.
A computer program product containing instructions which, when run on a computer, cause the computer to perform the method of correcting a gas well inflow dynamic curve as provided in the embodiments of fig. 1 or 2 above.
It will be understood by those skilled in the art that all or part of the steps for implementing the above embodiments may be implemented by hardware, or may be implemented by a program instructing relevant hardware, where the program may be stored in a computer-readable storage medium, and the above-mentioned storage medium may be a read-only memory, a magnetic disk or an optical disk, etc.
The present invention is not limited to the above preferred embodiments, and any modifications, equivalent replacements, improvements, etc. within the spirit and principle of the present invention should be included in the protection scope of the present invention.
Claims (10)
1. A method for correcting a gas well inflow dynamics, the method comprising:
obtaining a wellbore outflow dynamic curve in a VLP model;
acquiring a gas well inflow dynamic curve in an IPR model;
if the gas production rate corresponding to the intersection point of the shaft outflow dynamic curve and the gas well inflow dynamic curve is not consistent with the actual gas production rate, correcting the gas well inflow dynamic curve according to adjusting parameters to enable the gas production rate corresponding to the intersection point to be consistent with the actual gas production rate, wherein the adjusting parameters comprise: at least one of formation pressure and gas phase permeability.
2. The method for correcting the gas well inflow dynamic curve according to claim 1, wherein the correcting the gas well inflow dynamic curve according to the adjustment parameter comprises at least one of the following:
adjusting the intercept of the bottom hole flowing pressure of the gas well inflow dynamic curve according to the formation pressure;
and adjusting the slope of the gas well inflow dynamic curve according to the gas phase permeability.
3. The method of correcting a gas well inflow dynamic profile of claim 1, wherein prior to the obtaining a wellbore outflow dynamic profile in a VLP model, the method further comprises:
sequentially and iteratively calculating the pressure of a plurality of areas axially spaced in the shaft from the bottom to the top, wherein the pressure of each area in the plurality of areas is calculated by one of a plurality of different pipe flow pattern calculation methods until a plurality of top pressures are calculated;
determining one of the plurality of wellhead pressures that is closest to the measured wellhead pressure;
and establishing the VLP model according to the pipe flow pattern calculation method adopted by the plurality of zones when the wellhead pressure is calculated.
4. The method of correcting the gas well inflow dynamics as set forth in claim 3, wherein the calculation method for calculating the pressure of each zone is selected according to at least one of the following:
if the flow pattern of the area is a bubble flow, the selected pipe flow pattern calculation method is a Wallians-Griffith algorithm;
if the flow pattern of the area is slug flow, the selected pipe flow pattern calculation method is a Hagedown-Brown algorithm;
if the flow pattern of the area is transition flow, the selected pipe flow pattern calculation method is a Duns-Ros algorithm;
if the flow pattern of the area is mist flow, the selected pipe flow pattern calculation method is a Duns-Ros algorithm.
5. The method for correcting the inflow dynamic curve of a gas well according to any one of claims 1 to 4, further comprising:
if the water-gas ratio of the gas well is less than 0.5m3/104m3Correcting the gas well inflow dynamic curve according to the frequency of 1 time/30 days;
if the water-gas ratio of the gas well is not less than 0.5m3/104m3And not more than 1.0m3/104m3Correcting the gas well inflow dynamic curve according to the frequency of 1 time/15 days;
if the water-gas ratio of the gas well is more than 1.0m3/104m3And correcting the gas well inflow dynamic curve according to the frequency of 1 time/7 days.
6. A gas well inflow dynamics correction apparatus, comprising:
the obtaining module is used for obtaining a shaft outflow dynamic curve in the VLP model and a gas well inflow dynamic curve in the IPR model;
the correction module is used for correcting the gas well inflow dynamic curve according to an adjusting parameter if the gas production rate corresponding to the intersection point of the shaft outflow dynamic curve and the gas well inflow dynamic curve is not consistent with the actual gas production rate, so that the gas production rate corresponding to the intersection point is consistent with the actual gas production rate, wherein the adjusting parameter comprises: at least one of formation pressure and gas phase permeability.
7. The gas well inflow dynamics correction apparatus of claim 6 wherein the correction module corrects the gas well inflow dynamics in at least one of the following two ways:
adjusting the intercept of the bottom hole flowing pressure of the gas well inflow dynamic curve according to the formation pressure;
and adjusting the slope of the gas well inflow dynamic curve according to the gas phase permeability.
8. The gas well inflow dynamics correction apparatus of claim 6 further comprising:
the calculation module is used for sequentially and iteratively calculating the pressure of a plurality of axially spaced areas in the shaft from the bottom to the top, and the pressure of each area in the areas is calculated by adopting one of a plurality of different pipe flow pattern calculation methods until a plurality of top pressures are calculated;
the determining module is used for determining one wellhead pressure which is closest to the measured wellhead pressure in the plurality of wellhead pressures;
and the establishing module is used for establishing the VLP model according to the pipe flow pattern calculation method correspondingly adopted by the plurality of areas when the wellhead pressure is calculated.
9. A gas well inflow dynamics correction apparatus, comprising:
a processor;
a memory configured to store processor-executable instructions;
wherein the processor is configured to perform the correction method of any one of claims 1 to 5.
10. A computer storage medium having computer instructions stored thereon, wherein the computer instructions, when executed by a processor, implement the correction method of any one of claims 1 to 5.
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| WO2016192077A1 (en) * | 2015-06-04 | 2016-12-08 | 中国石油集团川庆钻探工程有限公司长庆井下技术作业公司 | Method for establishing and solving numerical well-testing model of horizontal well for tight gas hydraulic fracturing |
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| WO2016192077A1 (en) * | 2015-06-04 | 2016-12-08 | 中国石油集团川庆钻探工程有限公司长庆井下技术作业公司 | Method for establishing and solving numerical well-testing model of horizontal well for tight gas hydraulic fracturing |
| CN107301306A (en) * | 2017-08-04 | 2017-10-27 | 中国石油化工股份有限公司华北油气分公司 | Dynamic open-flow capacity Forecasting Methodology for DAMAGE OF TIGHT SAND GAS RESERVOIRS pressure break horizontal well |
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