CN112464586A - Shale gas well control reserve calculation method - Google Patents
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Abstract
The invention discloses a shale gas well control reserve calculation method, which aims at the characteristics of low porosity and low permeability of a shale gas reservoir, and has the defects that the well closing pressure recovery speed is slow when the formation pressure is obtained, the production is influenced, and the existing shale gas reservoir single well reserve calculation method is difficult to apply. The idea of adopting a material balance equation, firstly assuming single well control reserves and calculating the formation pressure by using single well production data is provided, and the formation pressure can be obtained under the condition of not closing the well. And then, a flowing substance balance equation is adopted, and the control reserves of the single well are obtained through regression by utilizing the stratum pressure and the single well production data obtained through calculation. And finally, comparing the assumed storage quantity value with the calculated storage quantity value, and if the assumed storage quantity value meets the error limit, obtaining the shale gas reservoir single-well control storage quantity and the formation pressure value. In addition, the invention also establishes an automatic calculation mathematical model, converts the trial calculation process into automatic calculation, reduces the workload, reduces the operation difficulty and improves the working efficiency of the reserve calculation.
Description
Technical Field
The invention relates to the field of shale gas well control reserve rating, in particular to a shale gas well control reserve calculation method.
Background
At present, shale gas reservoir reserves commonly used at home and abroad are calculated by a material balance method, an unstable well testing method and the like, and the methods all need an important parameter of average formation pressure. However, the shut-in pressure of the shale gas reservoir which is a low-porosity and low-permeability gas reservoir is recovered slowly, and long-time shut-in is needed to obtain the parameters. This results in very limited application of these methods, which brings about inconvenience for field application, and thus the prior art has yet to be improved and enhanced.
Disclosure of Invention
In view of the defects of the prior art, the invention provides a novel shale gas well reserve control method, which can calculate the single-well control reserve by using production dynamic data without closing a well and measuring pressure, and improves the practicability of the method.
In order to achieve the purpose, the invention adopts the following technical scheme:
the invention provides a shale gas well control reserve calculation method, which comprises the following steps:
s1, acquiring basic data of a single well, wherein the basic data comprises static data: irreducible water saturation, langmuir volume, langmuir pressure, porosity, shale density, gas reservoir original temperature, gas reservoir original pressure; phase state data: pressure and compression factor, pressure and gas viscosity; production data: daily gas production, accumulated gas production and bottom hole flow pressure.
S2, assuming single well to control the reserves, and calculating the average formation pressure by using a material balance equation;
the material balance equation is:
in the formula: p is the formation pressure, MPa; z*To correct the bias factor; z is a deviation factor; gpFor cumulative production, 108m3(ii) a G is single well controlled reserve, 108m3；swcIrreducible water saturation, f; rhobIs the density of rock, g/cm3；VLIs the Langmuir volume, m3/t；pLLane pressure, MPa; phi is the free porosity, f; t is the formation temperature, K; p is a radical ofscPressure under standard conditions, MPa; t isscTemperature under standard conditions, K; zscIs the deviation factor under standard conditions, i is the initial mark.
S3, fitting regression to calculate the single well control reserve according to the average formation pressure calculated in the step S2 by using a flowing substance balance equation and gas well production data;
the flow material balance equation is:
in the formula: μ is the gas viscosity, mPas; m (p) is the pseudo-pressure, MPa2/mpa·s；tca *Simulating time for material balance, d; c. CgIs a free gas compression coefficient, MPa-1；caTo adsorb a gas compression coefficient, MPa-1；ct *Is a comprehensive compression coefficient, MPa-1；qgIs the daily gas production, m3/d；kpssThe slope of the fit for equation (3); m (p)wf) Simulating pressure, MPa, for bottom hole flowing pressure2/mpa·s。
S4, establishing a relative error model according to the function relation between the single-well control reserves assumed in the step S2 and the single-well control reserves calculated in the step S3;
the relative error model is:
lb≤x≤ub (10)
in the formula: lb is the lower limit of the single well control reserve, the default is the current cumulative yield, 108m3(ii) a ub is the upper limit of the single well controlled reserve, and the default is 10 × 108m3(ii) a x is the single well control reserve assumed in step S2, g (x) is the single well control reserve calculated in step S3; f (x) represents a relative error.
And S5, calculating a reasonable single-well control reserve G by adopting a binary search method for the relative error model in the step S4.
The binary search method calculation of the relative error model comprises the following steps:
(1) respectively calculating f (lb), f (ub) and
a value of (d);
(2) judgment of
Whether it is greater than zero, if so, order
If less than zero, order
(3) Judging (ub-lb) or
If it is less than the limit value, and if any value is less than the limit value, the calculation is ended,
and (3) the reserve G is reasonably controlled by the single well, otherwise, the step (1) is skipped until the calculation result meets the precision requirement.
Compared with the prior art, the shale gas well control reserve calculation method provided by the invention does not need to carry out well shut-in pressure measurement, and can obtain the single-well control reserve and the average formation pressure only by analyzing the existing production data of the gas well under the condition of not influencing the production plan of the gas well; meanwhile, the method for automatically calculating the control reserves greatly reduces the workload of reserve calculation and realizes the automation of reserve calculation.
Drawings
FIG. 1 is a flow chart of shale gas well reserves calculation provided by the present invention.
FIG. 2 is a diagram of the results of an automatically computed mathematical model provided by the present invention.
FIG. 3 is a flow chart of the automated calculation provided by the present invention.
FIG. 4 is a production dynamic diagram for an X1 well in an example of the present invention.
FIG. 5 is a calculated fit graph of shale gas well reserves of an X1 well in an embodiment of the invention.
Detailed Description
The invention provides a shale gas well control reserve calculation method, and in order to make the purpose, technical scheme and effect of the invention clearer and clearer, the invention is further described in detail below by referring to the attached drawings and embodiments. It should be understood that the specific embodiments described herein are merely illustrative of the invention and are not intended to limit the invention.
Referring to fig. 1, the shale gas well control reserve calculation method provided by the embodiment of the invention includes the following steps:
s1, acquiring basic data of a single well, wherein the basic data comprises static data: irreducible water saturation, langmuir volume, langmuir pressure, porosity, shale density, gas reservoir original temperature, gas reservoir original pressure; phase state data: pressure and compression factor, pressure and gas viscosity; production data: daily gas production, accumulated gas production and bottom hole flow pressure;
specifically, the method comprises the following steps:
analyzing and obtaining a relational expression between pressure p and a compression factor Z by adopting a regression analysis method and utilizing data between the pressure and the compression factor, wherein Z is f (p);
analyzing a relation between pressure p and gas viscosity mu by using data between the pressure and the gas viscosity by adopting a regression analysis method, wherein mu is g (p);
s2, assuming single well to control the reserves, and calculating the average formation pressure by using a material balance equation;
specifically, the method comprises the following steps:
in the formula: p is the formation pressure, MPa; z*To correct the bias factor; z is a deviation factor; gpFor cumulative production, 108m3(ii) a G is single well controlled reserve, 108m3；swcIrreducible water saturation, f; rhobIs the density of rock, g/cm3；VLIs the Langmuir volume, m3/t；pLLane pressure, MPa; phi is the free porosity, f; t is the formation temperature, K; p is a radical ofscPressure under standard conditions, MPa; t isscTemperature under standard conditions, K; zscIs the deviation factor under standard conditions, i is the initial mark.
S3, fitting regression to calculate the single well control reserve according to the average formation pressure calculated in the step S2 by utilizing a flowing substance balance equation and gas well production data;
specifically, the method comprises the following steps:
Z＝f(p) (8)
μ＝g(p) (9)
in the formula: μ is the gas viscosity, mPas; m (p) is the pseudo-pressure, MPa2/mpa·s；tca *Simulating time for material balance, d; c. CgIs a free gas compression coefficient, MPa-1；caTo adsorb a gas compression coefficient, MPa-1；ct *Is a comprehensive compression coefficient, MPa-1；qgIs the daily gas production, m3/d；kpssThe slope of the fit for equation (3); m (p)wf) Simulating pressure, MPa, for bottom hole flowing pressure2/mpa·s。
Are respectively provided with
Is the y-axis, and
for the x axis, the relation between the two is obtained by regression, and the slope is kpssThen, the formula (3) shows that:
s4, establishing a relative error model according to the function relation between the single-well control reserves assumed in the step S2 and the single-well control reserves calculated in the step S3;
specifically, the method comprises the following steps:
the assumed single-well controlled reserve is defined as x, the single-well controlled reserve calculated from the production data is defined as y, and y is g (x) as shown in equations (1), (3) and (10).
The relative error model is now established as follows:
lb≤x≤ub (12)
in the formula: lb is the lower limit of the single well control reserve, the default is the current cumulative yield, 108m3(ii) a ub is the upper limit of the single well controlled reserve, and the default is 10 × 108m3；
Through a large number of experimental analyses, fig. 2 can be obtained, from which fig. 2 an empirical conclusion can be drawn: f (lb) and f (ub) have opposite signs, and f (x) there must be a zero between lb and ub, which is a reasonable single well control reserve G.
And S5, calculating a reasonable single-well control reserve G by adopting a binary search method for the relative error model in the step S4. The calculation flow is shown in FIG. 3;
specifically, the method comprises the following steps:
(1) respectively calculating f (lb), f (ub) and
a value of (d);
(2) judgment of
Whether it is greater than zero, if so, order
If less than zero, order
(3) Judging (ub-lb) or
If it is less than the limit value, and if any value is less than the limit value, the calculation is ended,
and (3) the reserve G is reasonably controlled by the single well, otherwise, the step (1) is skipped until the calculation result meets the precision requirement.
In specific application, collecting static data of a certain shale gas well: irreducible water saturation, langmuir volume, langmuir pressure, porosity, shale density, gas reservoir original temperature, gas reservoir original pressure; phase state data: pressure and compression factor, pressure and gas viscosity; production dynamic data: daily gas production, accumulated gas production and bottom hole flow pressure; the production dynamics data is shown in figure 4.
By adopting the shale gas well reserves calculation method provided by the invention, a shale gas well reserves calculation fitting graph can be obtained, as shown in fig. 5, the graph shows that the method provided by the invention has high fitting degree, and the correlation coefficient reaches 0.99.
By adopting the automatic calculation method provided by the invention, an iterative process of shale gas well reserves calculation can be obtained, and as shown in table 1, the automatic calculation method provided by the invention has high calculation speed, only 13 iterations are needed, the time is consumed for 29.36 seconds, and the relative error can reach 0.003691407% precision.
In conclusion, the shale gas well control reserve calculation method adopted by the embodiment can obtain high precision and high calculation speed, greatly improves the working efficiency, and solves the problem that the production of a gas well is influenced because the well closing back pressure is needed in the reserve calculation process.
It should be understood that equivalents and modifications of the technical solution and inventive concept thereof may occur to those skilled in the art, and all such modifications and alterations should fall within the scope of the appended claims.
Claims (6)
1. A shale gas well control reserve calculation method is characterized by comprising the following steps:
s1, acquiring basic data of a single well;
s2, assuming single well to control the reserves, and calculating the average formation pressure by using a material balance equation;
s3, fitting regression to calculate the single well control reserve according to the average formation pressure calculated in the step S2 by using a flowing substance balance equation and gas well production data;
s4, establishing a relative error model according to the function relation between the single-well control reserves assumed in the step S2 and the single-well control reserves calculated in the step S3;
and S5, calculating reasonable single-well control reserves by adopting a binary search method for the relative error model in the step S4.
2. The shale gas well control reserve calculation method of claim 1, wherein the basic data of the single well in step S1 comprises static data: irreducible water saturation, langmuir volume, langmuir pressure, porosity, shale density, gas reservoir original temperature, gas reservoir original pressure; phase state data: pressure and compression factor, pressure and gas viscosity; production data: daily gas production, accumulated gas production and bottom hole flow pressure.
3. The shale gas well control reserve calculation method of claim 1, wherein the material balance equation in step S2 is:
in the formula: p is the formation pressure, MPa; z*To correct the bias factor; z is a deviation factor; gpFor cumulative production, 108m3(ii) a G is single well controlled reserve, 108m3；swcIrreducible water saturation, f; rhobIs the density of rock, g/cm3；VLIs the Langmuir volume, m3/t；pLLane pressure, MPa; phi is the free porosity, f; t is the formation temperature, K; p is a radical ofscPressure under standard conditions, MPa; t isscTemperature under standard conditions, K; zscIs the deviation factor under standard conditions, i is the initial mark.
4. The shale gas well control reserve calculation method of claim 1, wherein the flowing material balance equation in step S3 is:
in the formula: μ is the gas viscosity, mPas; m (p) is the pseudo-pressure, MPa2/mpa·s；tca *Simulating time for material balance, d; c. CgIs a free gas compression coefficient, MPa-1；caTo adsorb a gas compression coefficient, MPa-1；ct *Is a comprehensive compression coefficient, MPa-1；qgIs the daily gas production, m3/d；kpssThe slope of the fit for equation (3); m (p)wf) Simulating pressure, MPa, for bottom hole flowing pressure2/mpa·s。
5. The shale gas well control reserve calculation method of claim 1, wherein the relative error model in step S4 is:
lb≤x≤ub (10)
in the formula: lb is the lower limit of the single well control reserve, the default is the current cumulative yield, 108m3(ii) a ub is the upper limit of the single well controlled reserve, and the default is 10 × 108m3(ii) a x is the single well control reserve assumed in step S2, g (x) is the single well control reserve calculated in step S3; f (x) represents a relative error.
6. The shale gas well control reserve calculation method of claim 5, wherein the calculation steps of the binary search method for the relative error model are as follows:
(1) respectively calculating f (lb), f (ub) and
a value of (d);
(2) judgment of
Whether it is greater than zero, if so, order
If less than zero, order
(3) Judging (ub-lb) or
If it is less than the limit value, and if any value is less than the limit value, the calculation is ended,
and (3) the reserve G is reasonably controlled by the single well, otherwise, the step (1) is skipped until the calculation result meets the precision requirement.
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|---|---|---|---|---|
| CN113818873A (en) * | 2021-10-20 | 2021-12-21 | 中国石油大学(北京) | Method and device for calculating dynamic reserves of gas reservoir under action of hidden gas-containing area |
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| CN113818873A (en) * | 2021-10-20 | 2021-12-21 | 中国石油大学(北京) | Method and device for calculating dynamic reserves of gas reservoir under action of hidden gas-containing area |
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