CN106600442B - Method for optimizing critical liquid carrying condition of deepwater gas well test - Google Patents

Method for optimizing critical liquid carrying condition of deepwater gas well test Download PDF

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CN106600442B
CN106600442B CN201611107501.5A CN201611107501A CN106600442B CN 106600442 B CN106600442 B CN 106600442B CN 201611107501 A CN201611107501 A CN 201611107501A CN 106600442 B CN106600442 B CN 106600442B
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gas
critical
pressure
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CN106600442A (en
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李紫晗
何玉发
高飞
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China National Offshore Oil Corp CNOOC
CNOOC Research Institute Co Ltd
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CNOOC Research Institute Co Ltd
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Abstract

The invention relates to a method for optimizing a critical liquid carrying condition of a deepwater gas well test, which is characterized by comprising the following steps of: 1) determining the testing flow of a shaft, calculating natural gas compression factors at each point in the shaft according to the relative density of natural gas of adjacent wells, the internal diameter data of a testing pipe column, the predicted absolute pressure of natural gas of the shaft and the predicted absolute temperature of the natural gas, then calculating the natural gas density, the natural gas relative molecular mass, the natural gas viscosity and the natural gas surface tension at the corresponding point in the shaft according to the obtained natural gas compression factors at each point in the shaft, and determining the drag coefficient of liquid drops at each point in the shaft carried out of a well mouth by using the obtained natural gas viscosity; 2) calculating the critical liquid carrying flow velocity and the critical liquid carrying flow of the deepwater test gas well; 3) and calculating corresponding bottom hole flowing pressure under the critical liquid carrying flow of the deep water testing gas well according to the testing pressure and gas flow data of the adjacent well, and calculating the critical testing pressure difference required by the deep water testing gas well by using the bottom hole flowing pressure.

Description

Method for optimizing critical liquid carrying condition of deepwater gas well test
Technical Field
The invention relates to a method for optimizing a critical liquid carrying condition for testing a deepwater gas well, and belongs to the technical field of exploration and development of oil and gas fields.
Background
The deep water test is an important link of deep water oil and gas exploration and development and is the most direct means for acquiring formation physical property parameters and boundary conditions. During testing of the deepwater gas well, if the testing liquid pad and the induced-injection liquid pad cannot be completely drained from the bottom of the well in the well cleaning stage, a gas reservoir stratum can be polluted, and a fluid sample cannot be obtained in deepwater testing. In the open flow stage of the deepwater test, the pressure and the temperature in a shaft are reduced, so that a large amount of condensate is separated out, and accumulated liquid is easily formed at the bottom of a well, so that certain back pressure is generated, the production capacity of a gas well is limited, the reservoir productivity cannot be accurately evaluated, even the complete stop of the flow during the deepwater test is caused, and finally the deepwater test fails. Because the development of deep water oil and gas fields in China is still in a groping stage at present, a set of reasonable deep water test critical liquid carrying flow conditions and a deep water test differential pressure optimization design method are lacked.
The calculation of the critical carrier flow conditions greatly depends on the selection of the drag coefficient of the liquid drops and the accurate calculation of the high-pressure physical property parameters of the natural gas. At present, the conventional method is to calculate the high-pressure physical property parameters of the natural gas by using an empirical plate method, carry out critical liquid carrying flow condition design on the temperature and pressure conditions of a wellhead by using a critical liquid carrying Turner model, and predict and test the pressure difference. However, in the deep water gas well testing process, because the pressure and temperature change range in the shaft is large, a large amount of condensate is likely to be separated out, and if the critical liquid carrying flow condition and the testing differential pressure are designed by a conventional method, large errors are likely to exist, the field testing operation is likely to have failure risks. For the calculation of the high-pressure physical property parameters of the natural gas and the prediction of the critical liquid carrying flow conditions, although the more mature commercial software PIPEIM (multiphase flow steady-state simulation software) and WELLFLO (hydraulic simulation software) already exist abroad, the PIPEIM and WELLFLO software are adopted to calculate the high-pressure physical property parameters of the natural gas and predict the critical liquid carrying flow conditions, and the following defects are usually existed: firstly, the model for calculating the high-pressure physical property parameters of the natural gas has a small applicable pressure range, needs repeated iterative calculation, and has obviously low precision; and secondly, because the critical liquid carrying flow condition of the whole well section is predicted by adopting a constant drag coefficient Turner model, the design result is small, and the liquid carrying condition of the whole well section of the deepwater gas well cannot be reasonably judged.
Disclosure of Invention
Aiming at the problems, the invention aims to provide the deep water gas well test critical liquid carrying condition optimization method which is suitable for variable-pressure and variable-temperature shaft environments, can reasonably judge the liquid carrying condition of the whole well section of the deep water gas well and has high precision.
In order to achieve the purpose, the invention adopts the following technical scheme: a method for optimizing a critical liquid carrying condition in a deepwater gas well test is characterized by comprising the following steps: 1) determining the testing flow of a shaft, calculating natural gas compression factors at each point in the shaft according to the relative density of natural gas of adjacent wells, the internal diameter data of a testing pipe column, the predicted absolute pressure of natural gas of the shaft and the predicted absolute temperature of the natural gas, then calculating the natural gas density, the natural gas relative molecular mass, the natural gas viscosity and the natural gas surface tension at the corresponding point in the shaft according to the obtained natural gas compression factors at each point in the shaft, and determining the drag coefficient of liquid drops at each point in the shaft carried out of a well mouth by using the obtained natural gas viscosity; 2) acquiring liquid density data according to an adjacent well, and calculating the critical liquid carrying flow rate and the critical liquid carrying flow rate of the deepwater test gas well according to the natural gas compression factor, the natural gas density, the natural gas viscosity and the natural gas surface tension at each point in the shaft and the drag coefficient of liquid drops at each point in the shaft carried out of the well mouth, which are obtained in the step 1); 3) and (3) comparing the critical liquid carrying flow obtained in the step (2) with the test flow determined in the step (1) according to the adjacent well test pressure and gas flow data, when the test flow is larger than or equal to the critical liquid carrying flow, further calculating the corresponding bottom hole flow pressure under the critical liquid carrying flow of the deep water test gas well according to the predicted original formation pressure of the gas reservoir, and then calculating the critical test pressure difference required by the deep water test gas well by using the bottom hole flow pressure.
In step 1), an empirical formula of the apparent critical parameter according to which the apparent critical pressure and the apparent critical temperature are calculated:
when gamma isg≥0.7：Ppc＝4.8815-0.3861γg，Tpc＝92.2222+176.6667γg(1)
When gamma isg<0.7：Ppc＝4.788-0.2482γg，Tpc＝92.2222+176.6667γg(2)
Calculating an apparent contrast pressure and apparent contrast temperature formula according to which the apparent contrast pressure and the apparent contrast temperature are calculated:
Ppr＝P/Ppc，Tpr＝T/Tpc(3)
the formula of LXF-RMP according to which the natural gas compression factor is calculated is as follows:
when P is more than or equal to 0prT is less than or equal to 5 and less than or equal to 1.25pr≤3，
Figure BDA0001171707300000021
In the formula (I), the compound is shown in the specification,
Figure BDA0001171707300000022
Figure BDA0001171707300000023
Figure BDA0001171707300000024
Figure BDA0001171707300000025
when P is more than or equal to 0prT is not less than 1.4 and not more than 1.05pr≤1.25，
Figure BDA0001171707300000026
In the formula (I), the compound is shown in the specification,
Figure BDA0001171707300000027
Figure BDA0001171707300000028
Figure BDA0001171707300000029
when P is more than or equal to 1.4prT is not less than 5 and not more than 1.05pr≤1.25，
Figure BDA00011717073000000210
In the formula (I), the compound is shown in the specification,
Figure BDA00011717073000000211
Figure BDA0001171707300000031
Figure BDA0001171707300000032
Figure BDA0001171707300000033
when P is more than or equal to 5pr<9 and 1.05. ltoreq. Tpr<3，Z＝a×Ppr+b (7)
In the formula (I), the compound is shown in the specification,
Figure BDA0001171707300000034
Figure BDA0001171707300000035
when 9 is less than or equal to Ppr<15 and 1.05. ltoreq. Tpr<3，Z＝a×Ppr+b (8)
In the formula (I), the compound is shown in the specification,
Figure BDA0001171707300000036
when 15 is less than or equal to Ppr<T is 30 and 1.05 ≤pr<3，Z＝a×Ppr+b (9)
In the formula (I), the compound is shown in the specification,
Figure BDA0001171707300000037
in said step 1), the formula according to which the natural gas density is calculated:
Figure BDA0001171707300000038
in the formula, ρgThe density of the natural gas under the absolute pressure and absolute temperature conditions, and Z is a natural gas compression factor.
In the step 1), a formula according to which the relative molecular mass of the natural gas is calculated:
Figure BDA0001171707300000039
in the formula, MgIs the relative molecular mass of natural gas.
In the step 1), the formula according to which the viscosity of the natural gas is calculated:
Figure BDA00011717073000000310
Figure BDA00011717073000000311
Figure BDA00011717073000000312
Y＝2.447-0.2224X (15)
in the formula, mugIs the viscosity of natural gas under certain pressure P and temperature T.
In the step 1), a formula according to which the surface tension of the natural gas is calculated:
Figure BDA00011717073000000313
σ(23.33)＝76×e-0.0362575P(17)
σ(137.78)＝52.5-0.87018P (18)。
in the step 1), a global nonlinear fitting method and a drag coefficient formula of Reynolds number correction are adopted:
Figure BDA0001171707300000041
Figure BDA0001171707300000042
in the formula, qscRe is the Reynolds number, d, for the flow rate measurementstiTo test the internal diameter of the string.
In the step 2), a calculation formula according to which the liquid carrying capacity of the deepwater test gas well is ensured is as follows:
Fg+FD＝GW(21)
Figure BDA0001171707300000043
in the formula, FgIs liquid buoyancy, FDIs drag force of liquid, GwIs the liquid gravity, d is the droplet diameter, CdIs the drag coefficient, ucrIs the gas well critical liquid carrying velocity, rhogIs the gas density, g is the acceleration of gravity, ρlIs the liquid density; the calculation formula of the critical liquid carrying flow rate of the deepwater testing gas well is as follows:
Figure BDA0001171707300000044
in the formula ucrTesting the critical liquid carrying flow rate of the gas well;
the formula according to which the maximum droplet diameter is calculated:
Figure BDA0001171707300000045
Figure BDA0001171707300000046
in the formula, NweIs the weber number, d is the maximum droplet diameter;
determining a calculation formula of the critical liquid carrying flow rate of the deepwater test gas well:
Figure BDA0001171707300000047
the formula according to which the critical liquid carrying flow is calculated:
Figure BDA0001171707300000051
Figure BDA0001171707300000052
in the formula, qcrIn order to test the critical liquid carrying flow of the gas well, A is the area of a test pipe column.
In the step 3), determining a quasi-steady-state energy production binomial equation of the deepwater test gas well according to the test pressure and gas volume data of the adjacent well:
Figure BDA0001171707300000053
Figure BDA0001171707300000054
Figure BDA0001171707300000055
in the formula, pwfFor bottom hole flow pressure, pRIs the formation pressure, A is the laminar flow term coefficient, B is the turbulent flow term coefficient,
Figure BDA0001171707300000056
n is the number of test points, and q is the test gas volume of an adjacent well;
according to the predicted original formation pressure of the gas reservoir, calculating a formula according to which the corresponding bottom hole flow pressure under the critical liquid carrying flow of the deepwater test gas well is calculated:
Figure BDA0001171707300000057
in the step 3), a formula according to which the critical test pressure difference is calculated:
Δptest＝pR-pwf(33)。
due to the adoption of the technical scheme, the invention has the following advantages: 1. according to the method, a natural gas parameter empirical formula is utilized according to the relative density of natural gas of adjacent wells, the inner diameter data of a wellbore testing pipe column, the predicted absolute pressure of the natural gas of the wellbore and the predicted absolute temperature of the natural gas, and a critical liquid carrying flow rate model for solving the deepwater testing gas well are established on the basis of a Turner model and by adopting a global nonlinear fitting method and a Reynolds number correction drag coefficient calculation model. 2. According to the invention, the quasi-steady state energy production binomial equation of the deepwater test gas well is determined according to the test pressure and gas volume data of the adjacent well, the corresponding bottom hole flow pressure of the deepwater test gas well under the critical liquid carrying flow is further calculated according to the predicted original formation pressure of the gas reservoir, and then the critical test pressure difference required by the deepwater test gas well is calculated by utilizing the bottom hole flow pressure, so that the prediction precision is improved, the test design requirement of the deepwater test gas well can be met, and the normal liquid carrying in the actual test operation process is ensured.
Drawings
FIG. 1 is a schematic view of the flow structure of the present invention
Detailed Description
The invention is described in detail below with reference to the figures and examples.
As shown in fig. 1, the method for optimizing the critical liquid carrying condition of the deepwater gas well test provided by the invention comprises the following steps:
1) determining the testing flow of a shaft, calculating natural gas compression factors at each point in the shaft according to the relative density of natural gas of adjacent wells, the internal diameter data of a testing pipe column, the predicted absolute pressure of natural gas of the shaft and the predicted absolute temperature of the natural gas, then calculating the natural gas density, the natural gas relative molecular mass, the natural gas viscosity and the natural gas surface tension at the corresponding point in the shaft according to the obtained natural gas compression factors at each point in the shaft, and determining the drag coefficient of liquid drops at each point in the shaft carried out of a well mouth by using the obtained natural gas viscosity;
in step 1), the specific process of calculating the natural gas compression factor at each point in the wellbore is as follows:
① obtaining the apparent critical pressure and the apparent critical temperature according to the empirical formula of the apparent critical parameters, wherein the empirical formula of the apparent critical pressure and the apparent critical temperature according to which is calculated:
when gamma isg≥0.7：Ppc＝4.8815-0.3861γg，Tpc＝92.2222+176.6667γg(1)
When gamma isg<0.7：Ppc＝4.788-0.2482γg，Tpc＝92.2222+176.6667γg(2)
In the formula, gammagIs the relative density of natural gas, PpcIs apparent critical pressure of natural gas, TpcIs the apparent critical temperature of natural gas;
② determining apparent contrast pressure and apparent contrast temperature, calculating apparent contrast pressure and apparent contrast temperature formulas according to which:
Ppr＝P/Ppc，Tpr＝T/Tpc(3)
in the formula, PprContrast pressure, TprFor comparison temperature, P is the absolute pressure of the natural gas, and T is the absolute temperature of the natural gas;
③, calculating a natural gas compression factor based on the apparent contrast pressure and the apparent contrast temperature, wherein the formula of LXF-RMP (high precision, full pressure, full temperature range natural gas deviation coefficient analytical model) on which the natural gas compression factor is calculated:
when P is more than or equal to 0prT is less than or equal to 5 and less than or equal to 1.25pr≤3，
Figure BDA0001171707300000061
In the formula (I), the compound is shown in the specification,
Figure BDA0001171707300000062
Figure BDA0001171707300000063
Figure BDA0001171707300000064
Figure BDA0001171707300000071
when P is more than or equal to 0prT is not less than 1.4 and not more than 1.05pr≤1.25，
Figure BDA0001171707300000072
In the formula (I), the compound is shown in the specification,
Figure BDA0001171707300000073
Figure BDA0001171707300000074
Figure BDA0001171707300000075
when P is more than or equal to 1.4prT is not less than 5 and not more than 1.05pr≤1.25，
Figure BDA0001171707300000076
In the formula (I), the compound is shown in the specification,
Figure BDA0001171707300000077
Figure BDA0001171707300000078
Figure BDA0001171707300000079
Figure BDA00011717073000000710
when P is more than or equal to 5pr<9 and 1.05. ltoreq. Tpr<3，Z＝a×Ppr+b (7)
In the formula (I), the compound is shown in the specification,
Figure BDA00011717073000000711
Figure BDA00011717073000000712
when 9 is less than or equal to Ppr<15 and 1.05. ltoreq. Tpr<3，Z＝a×Ppr+b (8)
In the formula (I), the compound is shown in the specification,
Figure BDA00011717073000000713
when 15 is less than or equal to Ppr<T is 30 and 1.05 ≤pr<3，Z＝a×Ppr+b (9)
In the formula (I), the compound is shown in the specification,
Figure BDA00011717073000000714
in step 1), the formula according to which the natural gas density is calculated:
Figure BDA00011717073000000715
in the formula, ρgThe density of the natural gas under the conditions of absolute pressure and absolute temperature is shown, and Z is a natural gas compression factor;
in step 1), the formula according to which the relative molecular mass of the natural gas is calculated:
Figure BDA00011717073000000716
in the formula, MgIs the relative molecular mass of natural gas;
in step 1), the formula according to which the viscosity of the natural gas is calculated:
Figure BDA0001171707300000081
Figure BDA0001171707300000082
Figure BDA0001171707300000083
Y＝2.447-0.2224X (15)
in the formula, mugThe viscosity of natural gas under certain pressure P and temperature T conditions;
in step 1), the formula according to which the surface tension of the natural gas is calculated:
Figure BDA0001171707300000084
σ(23.33)＝76×e-0.0362575P(17)
σ(137.78)＝52.5-0.87018P (18)
in the step 1), a global nonlinear fitting method and a Reynolds number modified drag coefficient formula are adopted:
Figure BDA0001171707300000085
Figure BDA0001171707300000086
in the formula, qscRe is the Reynolds number, d, for the flow rate measurementstiTo test the internal diameter of the string.
2) Acquiring liquid density data according to an adjacent well, and calculating the critical liquid carrying flow rate and the critical liquid carrying flow rate of the deepwater test gas well according to the natural gas compression factor, the natural gas density, the natural gas viscosity and the natural gas surface tension at each point in the shaft and the drag coefficient of liquid drops at each point in the shaft carried out of the well mouth, which are obtained in the step 1);
if the liquid in the deepwater test gas well is carried out of the shaft by the gas, the minimum condition required for discharging the accumulated liquid of the deepwater test gas well is to enable the maximum liquid drop in the gas flow to continuously move upwards according to the assumption of the liquid drop model. The critical liquid carrying flow velocity of the deepwater gas well can be determined according to the maximum liquid drop stress condition, namely the sum of the buoyancy and drag force borne by the maximum liquid drop is equal to the self gravity, so that the deepwater test gas well is ensured to have a calculation formula according to the liquid carrying capacity:
Fg+FD＝GW(21)
Figure BDA0001171707300000087
in the formula, FgIs liquid buoyancy, FDIs drag force of liquid, GwIs the liquid gravity, d is the liquid diameter, CdIs the drag coefficient, ucrIs the gas well critical liquid carrying velocity, rhogIs the gas density, g is the acceleration of gravity, ρlIs the liquid density.
And (3) obtaining a calculation formula of the critical liquid carrying flow rate of the deepwater test gas well according to the formulas (20) and (21):
Figure BDA0001171707300000091
in the formula ucrThe method is used for testing the critical liquid carrying flow rate of the gas well.
Since the droplet diameter is controlled by the inertial force of the gas stream, which tries to break up the droplets, and the surface tension of the liquid, which tries to agglomerate the droplets, the maximum droplet diameter can be determined from the weber number. After the Weber number exceeds the critical value 30, the balance between the inertia force of the airflow and the surface tension of the liquid drops is broken, the liquid drops are broken, and the formula according to which the maximum liquid drop diameter is calculated is as follows:
Figure BDA0001171707300000092
Figure BDA0001171707300000093
in the formula, NweIs the weber number and d is the maximum droplet diameter.
Substituting the formulas (18) and (24) into the formula (22) to further determine a calculation formula of the critical liquid carrying flow rate of the deepwater test gas well:
Figure BDA0001171707300000094
the formula according to which the critical liquid carrying flow is calculated:
Figure BDA0001171707300000095
Figure BDA0001171707300000096
in the formula, qcrIn order to test the critical liquid carrying flow of the gas well, A is the area of a test pipe column.
3) According to the adjacent well test pressure and gas volume data, comparing the critical liquid carrying flow obtained in the step 2) with the test flow determined in the step 1), when the test flow is larger than or equal to the critical liquid carrying flow, further calculating corresponding bottom hole flow pressure under the critical liquid carrying flow of the deep water test gas well according to the predicted original formation pressure of the gas reservoir, and then calculating the critical test pressure difference required by the deep water test gas well by using the bottom hole flow pressure;
in the step 3), determining a quasi-steady-state energy production binomial equation of the deepwater test gas well according to the test pressure and gas volume data of the adjacent well:
Figure BDA0001171707300000097
Figure BDA0001171707300000101
Figure BDA0001171707300000102
in the formula, pwfFor bottom hole flow pressure, pRIs the formation pressure, A is the laminar flow term coefficient, B is the turbulent flow term coefficient,
Figure BDA0001171707300000103
n is the number of test points, and q is the test gas volume of an adjacent well;
in the step 3), according to the predicted original formation pressure of the gas reservoir, calculating a formula according to which the corresponding bottom hole flow pressure under the critical liquid carrying flow of the deepwater test gas well is calculated:
Figure BDA0001171707300000104
in step 3), a formula according to which the critical test differential pressure is calculated:
△ptest＝pR-pwf(33)。
an embodiment is described below to illustrate the process of determining the capacity binomial equation:
TABLE 1 neighbor well test pressure and gas volume data
Figure BDA0001171707300000105
Where N is 4, a is 0.01275 according to equation (29), and B is 0.00029 according to equation (30); substituting A and B into a formula (28) to obtain a binomial equation of the quasi-steady state productivity of the deepwater test gas well:
Figure BDA0001171707300000106
the above embodiments are only used for illustrating the present invention, and the structure, connection mode and the like of each component can be changed, and all equivalent changes and improvements made on the basis of the technical scheme of the present invention should not be excluded from the protection scope of the present invention.

Claims (7)

1. A method for optimizing a critical liquid carrying condition in a deepwater gas well test is characterized by comprising the following steps:
1) determining the testing flow of a shaft, calculating natural gas compression factors at all points in the shaft according to the relative density of natural gas of adjacent wells, the predicted absolute pressure of natural gas of the shaft and the predicted absolute temperature of the natural gas, then calculating the natural gas density, the natural gas relative molecular mass, the natural gas viscosity and the natural gas surface tension at corresponding points in the shaft according to the obtained natural gas compression factors at all points in the shaft, and determining the drag coefficient of liquid drops at all points in the shaft carried out of a well mouth by using the obtained natural gas viscosity; wherein, a global nonlinear fitting method and a drag coefficient formula of Reynolds number correction are adopted:
Figure FDA0002415693240000011
Figure FDA0002415693240000012
in the formula, CdIs the drag coefficient, qscRe is the Reynolds number, d, for the flow rate measurementstiFor testing the internal diameter, gamma, of the pipe stringgIs the relative density of natural gas, mugThe viscosity of the natural gas is measured under the conditions of a certain pressure P and a certain temperature T, wherein P is the absolute pressure of the natural gas, and T is the absolute temperature of the natural gas;
2) acquiring liquid density data according to an adjacent well, and calculating the critical liquid carrying flow rate and the critical liquid carrying flow rate of the deepwater test gas well according to the natural gas compression factor, the natural gas density, the natural gas viscosity and the natural gas surface tension at each point in the shaft and the drag coefficient of liquid drops at each point in the shaft carried out of the well mouth, which are obtained in the step 1);
3) comparing the critical liquid carrying flow obtained in the step 2) with the test flow determined in the step 1), when the test flow is more than or equal to the critical liquid carrying flow, further calculating the corresponding bottom hole flow pressure of the deep water test gas well under the critical liquid carrying flow according to the predicted original formation pressure of the gas reservoir, and then calculating the critical test pressure difference required by the deep water test gas well by using the bottom hole flow pressure; the method comprises the following steps of determining a quasi-steady-state energy production binomial equation of the deepwater test gas well according to adjacent well test pressure and gas volume data:
Figure FDA0002415693240000013
Figure FDA0002415693240000014
Figure FDA0002415693240000015
in the formula, pwfFor bottom hole flow pressure, pRIs the formation pressure, A1Is the coefficient of the laminar flow term, B1In order to be the coefficient of the turbulence term,
Figure FDA0002415693240000016
n is the number of test points, and q is the test gas volume of an adjacent well;
according to the predicted original formation pressure of the gas reservoir, calculating a formula according to which the corresponding bottom hole flow pressure under the critical liquid carrying flow of the deepwater test gas well is calculated:
Figure FDA0002415693240000021
qcrtesting the critical liquid carrying flow of the gas well;
the formula according to which the critical test differential pressure is calculated:
Δptest＝pR-pwf(33)。
2. the method for optimizing the critical liquid carrying condition for testing the deepwater gas well as recited in claim 1, wherein: in step 1), an empirical formula of the apparent critical parameter according to which the apparent critical pressure and the apparent critical temperature are calculated:
when gamma isg≥0.7：Ppc＝4.8815-0.3861γg，Tpc＝92.2222+176.6667γg(1)
When gamma isg＜0.7：Ppc＝4.788-0.2482γg，Tpc＝92.2222+176.6667γg(2)
In the formula, PpcIs apparent critical pressure of natural gas, TpcIs the apparent critical temperature of natural gas;
calculating an apparent contrast pressure and apparent contrast temperature formula according to which the apparent contrast pressure and the apparent contrast temperature are calculated:
Ppr＝P/Ppc，Tpr＝T/Tpc(3)
in the formula, PprTo look at the contrast pressure, TprAccording to the contrast temperature, P is the absolute pressure of the natural gas, and T is the absolute temperature of the natural gas;
the formula of LXF-RMP according to which the natural gas compression factor Z is calculated is as follows:
when P is more than or equal to 0prT is less than or equal to 5 and less than or equal to 1.25pr≤3，
Figure FDA0002415693240000022
In the formula (I), the compound is shown in the specification,
Figure FDA0002415693240000023
Figure FDA0002415693240000024
Figure FDA0002415693240000025
Figure FDA0002415693240000026
when P is more than or equal to 0prT is not less than 1.4 and not more than 1.05pr＜1.25，
Figure FDA0002415693240000027
In the formula (I), the compound is shown in the specification,
Figure FDA0002415693240000028
Figure FDA0002415693240000029
Figure FDA00024156932400000210
when 1.4 < PprT is not less than 5 and not more than 1.05pr＜1.25，
Figure FDA00024156932400000211
In the formula (I), the compound is shown in the specification,
Figure FDA00024156932400000212
Figure FDA00024156932400000213
Figure FDA0002415693240000031
Figure FDA0002415693240000032
Figure FDA0002415693240000033
when 5 < PprT is less than 9 and not more than 1.05pr＜3，Z＝a×Ppr+b (7)
In the formula (I), the compound is shown in the specification,
Figure FDA0002415693240000034
Figure FDA0002415693240000035
when 9 is less than or equal to PprT is less than 15 and not more than 1.05pr＜3，Z＝a×Ppr+b (8)
In the formula (I), the compound is shown in the specification,
Figure FDA0002415693240000036
when 15 is less than or equal to PprT is less than 30 and not more than 1.05pr＜3，Z＝a×Ppr+b (9)
In the formula (I), the compound is shown in the specification,
Figure FDA0002415693240000037
3. the method for optimizing the critical liquid carrying condition for testing the deepwater gas well as defined in claim 2, wherein the critical liquid carrying condition comprises the following steps: in said step 1), the formula according to which the natural gas density is calculated:
Figure FDA0002415693240000038
in the formula, ρgThe density of the natural gas under the absolute pressure and absolute temperature conditions, and Z is a natural gas compression factor.
4. The method for optimizing the critical liquid-carrying condition for testing the deepwater gas well as recited in claim 3, wherein: in the step 1), a formula according to which the relative molecular mass of the natural gas is calculated:
Figure FDA0002415693240000039
in the formula, MgIs the relative molecular mass of natural gas.
5. The method for optimizing the critical liquid-carrying condition for testing the deepwater gas well as defined in claim 4, wherein the critical liquid-carrying condition comprises the following steps: in the step 1), the formula according to which the viscosity of the natural gas is calculated:
Figure FDA00024156932400000310
Figure FDA00024156932400000311
Figure FDA00024156932400000312
Y＝2.447-0.2224X (15)
in the formula, mugIs the viscosity of natural gas under certain pressure P and temperature T.
6. The method for optimizing the critical liquid-carrying condition for testing the deepwater gas well as recited in claim 5, wherein: in the step 1), a formula according to which the surface tension of the natural gas is calculated:
Figure FDA0002415693240000041
σ(23.33)＝76×e-0.0362575P(17)
σ(137.78)＝52.5-0.87018P (18)。
7. the method for optimizing the critical liquid-carrying condition for testing the deepwater gas well as defined in claim 6, wherein the critical liquid-carrying condition comprises the following steps: in the step 2), a calculation formula according to which the liquid carrying capacity of the deepwater test gas well is ensured is as follows:
Fg+FD＝GW(21)
Figure FDA0002415693240000042
in the formula, FgIs liquid buoyancy, FDIs drag force of liquid, GWIs the liquid gravity, d is the droplet diameter, CdIs the drag coefficient, ucrIs the gas well critical liquid carrying velocity, rhogIs the gas density, g is the acceleration of gravity, ρlIs the liquid density; the calculation formula of the critical liquid carrying flow rate of the deepwater testing gas well is as follows:
Figure FDA0002415693240000043
in the formula ucrFor testing critical liquid-carrying flow rate of gas well；
The formula according to which the maximum droplet diameter is calculated:
Figure FDA0002415693240000044
Figure FDA0002415693240000045
in the formula, NweIs the Weber number, d is the droplet diameter;
determining a calculation formula of the critical liquid carrying flow rate of the deepwater test gas well:
Figure FDA0002415693240000046
the formula according to which the critical liquid carrying flow is calculated:
Figure FDA0002415693240000047
Figure FDA0002415693240000048
in the formula, qcrIn order to test the critical liquid carrying flow of the gas well, A is the area of a test pipe column.
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