Real-time optimization method for size of oil nozzle in post-pressure flowback stage of shale gas horizontal well

Abstract

The invention provides a real-time optimization method for the size of an oil nozzle in the flowback stage after shale gas horizontal well fracturing. The method comprises the following steps that firstly, production dynamic data in the flowback stage of a shale gas well is recorded; 2, obtaining continuous and complete pressure decreasing data based on the pressure data before the peak pressure is reversely deduced; thirdly, according to the shale gas well flow-back stage production dynamic data and the continuous and complete pressure decline curve, flow-back stage dynamic characteristic parameters are calculated; and 4, optimizing the size of the oil nozzle in the flow-back stage in real time based on the dynamic characteristic parameters in the flow-back stage. Dynamic changes of various key indexes under different oil nozzle systems are calculated in real time by combining production dynamic data recorded at the shale gas well flowback stage site according to time intervals, the real-time optimization method for the size of the oil nozzle in the shale gas horizontal well after-fracturing flowback stage is established for the first time, real-time optimization of the oil nozzle in the shale gas well flowback stage is achieved, and real-time optimization of the oil nozzle in the shale gas well flowback stage is achieved. The shale gas development effect is improved.

Description

Technical Field

[0001] The present invention relates to the technical field of shale gas, and in particular to a real-time optimization method for choke size in a shale gas horizontal well during a post-pressure flowback stage. Background Art

[0002] Shale gas is a significant unconventional natural gas resource, and horizontal well fracturing has become a primary method of shale gas development. The flowback phase of a shale gas well refers to the process of draining the fracturing fluid after the horizontal well is completed to promote shale gas production. This process often results in pressure drops and production declines due to reservoir heterogeneity and the presence of fracturing fluid. To improve the production efficiency and stability of shale gas horizontal wells, effective flowback measures are necessary, and the choke system is a key flowback method.

[0003] The choke system controls bottomhole pressure and flow. A choke is a device that adjusts parameters such as the choke's opening and position to control bottomhole pressure and flow, thereby optimizing production and improving recovery. In the actual shale gas well flowback process, a reasonable choke system not only controls the magnitude and fluctuation of bottomhole pressure, optimizes the direction and velocity of shale gas flow, and increases production and stability, but also reduces gas-liquid flowback resistance within the wellbore, minimizing pressure loss and allowing gas to fully flow out of the formation, thereby increasing recovery.

[0004] Therefore, a reasonable nozzle system is very important during the flowback stage of shale gas horizontal wells. It can effectively improve production efficiency and stability, reduce production costs, and also help improve the effect of shale gas development. However, adjusting the nozzle system during the flowback stage of horizontal wells is also a complex technical task. A reasonable nozzle system adjustment plan needs to be implemented according to the on-site situation of shale gas wells, and real-time monitoring and adjustment should be carried out to ensure that the adjustment effect meets the expectations and timely adjustment and optimization are carried out. At present, there is no systematic real-time optimization and control method for the reasonable nozzle system during the flowback stage of shale gas wells. It is urgent to establish a real-time optimization plan for the nozzle system to provide technical support for the high-quality development of shale gas. Summary of the Invention

[0005] In order to solve the problems of insufficient rationality, lack of real-time performance and lack of systematicness in the existing shale gas horizontal well flowback stage choke system regulation, the present invention combines the production dynamic data (including parameters such as gas production, water production, pressure and choke size) collected at time intervals on site during the shale gas well flowback stage to analyze the dynamic changes of multiple key indicators under different choke systems in real time. For the first time, a real-time optimization method for choke size in the post-pressurization flowback stage of shale gas horizontal wells is established, which realizes real-time regulation and optimization of chokes in the flowback stage of shale gas wells and improves the shale gas development effect.

[0006] The present invention provides a method for real-time optimization of nozzle size during the flowback stage of a shale gas horizontal well after pressure reduction, comprising the following steps:

[0007] Step 1: Record the production dynamic data of shale gas well flowback stage;

[0008] Step 2: Based on the pressure data before the reverse estimation peak pressure, obtain continuous and complete pressure reduction data;

[0009] Step 3: Calculate the dynamic characteristic parameters of the flowback stage based on the production dynamic data of the shale gas well and the continuous and complete pressure decline curve;

[0010] Step 4: Based on the dynamic characteristic parameters of the flowback stage, optimize the nozzle size in the flowback stage in real time.

[0011] Furthermore, in step 1, the production dynamic data of the shale gas well during the flowback phase includes water production, gas production, wellhead pressure and nozzle size recorded at certain time intervals.

[0012] Furthermore, step 2 includes:

[0013] After determining that the wellhead pressure of the shale gas well has reached the peak pressure, the decreasing trend line after the peak pressure is fitted to obtain the decreasing trend line formula;

[0014] According to the decreasing trend line formula, the pressure data before the peak pressure is reversed and the reversed pressure before the peak pressure is obtained by plotting;

[0015] The connection between the reverse thrust pressure and the actual wellhead pressure data after the peak pressure is the continuous pressure decline data of the shale gas well.

[0016] Furthermore, in step three, the dynamic characteristic parameters of the flowback stage include gas production per unit pressure drop, water production per unit pressure drop, water-gas ratio, pressure drop rate and daily average pressure drop per unit gas-liquid total flow rate.

[0017] Furthermore, in step 3, the calculation formula for the pressure drop rate is as follows:

[0018] △P=(P b0 -P bi ) / (t i -t0)

[0019] Where:

[0020] P b0， P bi Represent the wellhead pressure at the initial moment and at any moment respectively;

[0021] t 0， t i Respectively represent the initial moment and the time corresponding to any moment;

[0022] △P shows the pressure drop rate during the flowback stage of shale gas wells.

[0023] Furthermore, in step 3, the calculation formula for gas production per unit pressure drop is as follows:

[0024] △Pg=(G gi -G g0 ) / (P f0 -P fi )

[0025] Where:

[0026] G g0 Indicates the cumulative gas production corresponding to the start of gas production, G gi =q g0 ;

[0027] G gi Indicates the cumulative gas production at any time after the start of gas production, G gi =q g0 +q g1 +···+q gi , i=1,2,…;

[0028] P f0 Indicates the reverse thrust pressure corresponding to the start of gas production;

[0029] P fi Indicates the reverse thrust pressure P at any moment after gas production begins but before the wellhead pressure reaches the peak pressure fi , where if the wellhead pressure reaches the peak pressure, the actual wellhead pressure P bi ;

[0030] △Pg represents the gas production per unit pressure drop during the flowback stage of a shale gas well.

[0031] Furthermore, in step 3, the calculation formula for water production per unit pressure drop is as follows:

[0032] △Pw=(G wi -G w0 ) / (P f0 -P fi )

[0033] Where:

[0034] G w0 Indicates the cumulative water production corresponding to the start of water production, Gw i =q w0 ;

[0035] G wi Indicates the cumulative water production at any time after the start of water production, G wi =q w0 +qw1 +···+q wi , i=1,2,…;

[0036] P f0 Indicates the reverse prediction pressure corresponding to the start of water production;

[0037] P fi Indicates the reverse thrust pressure P at any moment after gas production begins but before the wellhead pressure reaches the peak pressure fi , where if the wellhead pressure reaches the peak pressure, the actual wellhead pressure P bi ;

[0038] △Pw represents the water production per unit pressure drop during the flowback stage of a shale gas well.

[0039] Furthermore, in step 3, the calculation formula of the water-gas ratio is as follows:

[0040] Wg=q wi / q gi

[0041] Where:

[0042] q wi Indicates the water production at a certain moment in the flowback stage of a shale gas well;

[0043] q gi Indicates the gas production at a certain moment in the flowback stage of a shale gas well;

[0044] Wg represents the water-gas ratio corresponding to a certain moment in the flowback stage of a shale gas well.

[0045] Furthermore, in step 3, the calculation method of the daily average pressure drop under the unit total gas-liquid flow rate includes:

[0046] According to the water production and gas production recorded at a certain time interval, the total equivalent underground gas-liquid flow of the gas well can be obtained by equivalent underground flow:

[0047] q t =(q g ·B g 10000+q w ·B w )

[0048] Where:

[0049] q t It represents the equivalent total underground gas-liquid flow rate at any time after the shale gas well starts producing water;

[0050] q g It indicates the gas production of shale gas wells recorded at a certain time interval;

[0051] qw It indicates the water production of shale gas wells recorded at a certain time interval;

[0052] B g represents the volume coefficient of dimensionless gas;

[0053] B w represents the volume coefficient of dimensionless water;

[0054] Calculate the average daily pressure drop per unit gas-liquid total flow rate:

[0055] △Pt=(P b0 -P bi ) / (G ti -G t0 )·twenty four

[0056] Where:

[0057] △Pt represents the daily average pressure drop per unit gas-liquid total flow rate at any time after the shale gas well starts producing water;

[0058] G i0 G represents the total accumulated gas-liquid flow rate corresponding to the start of water production in the shale gas well. ti =q t0 ;

[0059] G ti G represents the total gas-liquid flow at any time after the shale gas well starts producing water. ti =q t0 +q t1 +···+q ti , i=1,2,….

[0060] Furthermore, in step 4, the real-time change curve of the dynamic characteristic parameters in the flowback stage is plotted to timely reflect the stable production effect of the shale gas well, thereby guiding the real-time optimization of the nozzle size in the flowback stage. Under a certain nozzle size, the real-time optimization of the nozzle size in the flowback stage includes:

[0061] If the gas production per unit pressure drop gradually increases or stabilizes, the water production per unit pressure drop stabilizes or decreases, the water-gas ratio gradually decreases, and the daily average pressure drop and pressure drop rate per unit gas-liquid flow rate decrease, it indicates that the gas well has a good flowback effect, and the size of the first-stage nozzle should be increased;

[0062] If the gas production per unit pressure drop gradually decreases, the water production per unit pressure drop is stable or increases, and the daily average pressure drop and pressure drop rate per unit gas-liquid flow rate are stable, it indicates that the gas well flowback effect is affected and the size of the first-stage nozzle needs to be reduced;

[0063] If the gas production per unit pressure drop is stable, the water production per unit pressure drop is stable or decreasing, and the daily average pressure drop and pressure drop rate per unit gas-liquid total flow rate are decreasing or stable, it indicates that the gas-liquid flowback of the gas well is relatively stable, and the current nozzle size should be maintained to continue the flowback.

[0064] In summary, due to the adoption of the above technical solution, the beneficial effects of the present invention are:

[0065] 1. Based on the analysis of actual flowback dynamic characteristic parameters, the present invention can evaluate the production potential of shale gas wells and quantitatively determine the production pressure loss. With the goal of continuous and stable gas flowback and maximum production capacity maintenance, it guides the optimization and control of the flowback nozzle size of shale gas wells.

[0066] 2. The present invention reflects the gas-liquid flow characteristics and production capacity change rules of shale gas wells through the real-time production dynamic characteristic parameters of actual shale gas well wellheads. It can timely and effectively reflect the dynamic changes of shale gas well backflow effect over time under different nozzle sizes, and provide real-time guidance for the optimization and control of nozzle size.

[0067] 3. By establishing a shale gas well flowback stage effect evaluation and a nozzle size adjustment guidance chart, the present invention can achieve real-time evaluation of the flowback effect of shale gas wells in different blocks, and provide technical support for shale gas well capacity construction, production optimization and management optimization. BRIEF DESCRIPTION OF THE DRAWINGS

[0068] In order to more clearly illustrate the technical solutions of the embodiments of the present invention, the drawings in the embodiments will be briefly introduced below. It should be understood that the following drawings only illustrate certain embodiments of the present invention and therefore should not be regarded as limiting the scope. For ordinary technicians in this field, other relevant drawings can be obtained based on these drawings without paying any creative work.

[0069] Figure 1 Flowchart of a method for real-time optimization of nozzle size during the post-pressure flowback stage of a shale gas horizontal well in an embodiment of the present invention.

[0070] Figure 2 Schematic diagram of gas-liquid flow and distribution during the flowback stage of a shale gas well.

[0071] Figure 3 This is a production dynamic data curve diagram of a shale gas well in the flowback stage in an embodiment of the present invention.

[0072] Figure 4 This is a curve chart of production dynamic data plus reverse thrust pressure during the flowback stage of a shale gas well in an embodiment of the present invention.

[0073] Figure 5 Graph showing the gas production per unit pressure drop ΔPg, water production per unit pressure drop ΔPw, and water-gas ratio Wg during the flowback stage of a shale gas well in an embodiment of the present invention.

[0074] Figure 6 Graph showing the pressure drop rate ΔP during the flowback phase of a shale gas well and the average daily pressure drop ΔPt per unit total gas-liquid flow rate in an embodiment of the present invention.

[0075] Figure 7 Schematic diagram of the decreasing fitting trend line after the peak pressure in the flowback stage of a shale gas well in an embodiment of the present invention.

[0076] Figure 8 Schematic diagram of peak pressure followed by reverse thrust pressure in an embodiment of the present invention.

[0077] Figure 9 This is a production dynamic data curve diagram of the H1 flowback stage of a shale gas well in an example of an embodiment of the present invention.

[0078] Figure 10 This is a schematic diagram of a decreasing fitting trend line of the peak pressure after the H1 flowback stage of a shale gas well according to an example of an embodiment of the present invention.

[0079] Figure 11 This is a schematic diagram of the reverse thrust pressure after the peak pressure of H1 in a shale gas well according to an example of an embodiment of the present invention.

[0080] Figure 12 Graph showing the gas production per unit pressure drop ΔPg, water production per unit pressure drop ΔPw, and water-gas ratio Wg during the flowback phase of a shale gas well H1 according to an example of an embodiment of the present invention.

[0081] Figure 13 1 is a graph showing the pressure drop rate ΔP during the flowback phase of a shale gas well H1 and the average daily pressure drop ΔPt per unit total gas-liquid flow rate in an example of an embodiment of the present invention. DETAILED DESCRIPTION

[0082] To make the objectives, technical solutions, and advantages of the embodiments of the present invention more clear, the technical solutions of the embodiments of the present invention will be clearly and completely described below in conjunction with the accompanying drawings of the embodiments of the present invention. Obviously, the described embodiments are only part of the embodiments of the present invention, not all of the embodiments. Generally, the components of the embodiments of the present invention described and shown in the drawings herein can be arranged and designed in various different configurations.

[0083] Therefore, the following detailed description of the embodiments of the present invention provided in the accompanying drawings is not intended to limit the scope of the invention as claimed, but rather merely represents selected embodiments of the present invention. All other embodiments derived by persons of ordinary skill in the art based on the embodiments of the present invention without creative effort are intended to fall within the scope of protection of the present invention.

[0084] Example

[0085] like Figure 1As shown, this embodiment proposes a real-time optimization method for the nozzle size in the flowback stage after shale gas horizontal well fracturing, including the following steps:

[0086] Step 1: Record the production dynamic data of the shale gas well flowback stage; the shale gas well flowback stage mainly includes the initial pure liquid flow stage, the transitional liquid-dominated gas-liquid two-phase flow stage, and the late gas-dominated gas-liquid two-phase flow stage. The flow diagram is shown in the figure below. Figure 2 As shown. Record the production dynamic data at a certain time interval (in this embodiment, every hour), including water production qw, gas production qg, wellhead pressure pb and nozzle size CS, and draw the change curve of water production qw, gas production qg, wellhead pressure pb and nozzle size CS over time, as shown in Figure 3 shown.

[0087] Step 2: Based on the pressure data before the reverse estimate of the peak pressure, obtain continuous and complete pressure reduction data; specifically including:

[0088] After determining that the wellhead pressure of the shale gas well has reached the peak pressure, the decreasing trend line after the peak pressure is fitted to obtain the decreasing trend line formula, as shown in the following example: Figure 7 As shown;

[0089] According to the decreasing trend line formula, the pressure data before the peak pressure is reversed and the reverse pressure before the peak pressure is obtained by plotting. Figure 4 As shown;

[0090] The reverse thrust pressure is connected with the actual wellhead pressure data after the peak pressure, which is the continuous pressure decline data of the shale gas well, such as Figure 8 shown.

[0091] Step 3: Calculate the dynamic characteristic parameters of the flowback stage based on the production dynamic data of the shale gas well in the flowback stage and the continuous and complete pressure decline curve; wherein the dynamic characteristic parameters of the flowback stage include gas production per unit pressure drop, water production per unit pressure drop, water-gas ratio, pressure drop rate and daily average pressure drop per unit gas-liquid total flow rate, such as Figure 5 、 Figure 6 The specific calculation method is as follows:

[0092] (1) The calculation formula of pressure drop rate is as follows:

[0093] △P=(P b0 -P bi ) / (t i -t0)

[0094] Where:

[0095] P b0， P bi Represent the wellhead pressure at the initial moment and at any moment respectively;

[0096] t 0， t i Respectively represent the initial moment and the time corresponding to any moment;

[0097] △P shows the pressure drop rate during the flowback stage of shale gas wells.

[0098] (2) The calculation formula for gas production per unit pressure drop is as follows:

[0099] △Pg=(G gi -G g0 ) / (P f0 -P fi )

[0100] Where:

[0101] G g0 Indicates the cumulative gas production corresponding to the start of gas production, G gi =q g0 ;

[0102] G gi Indicates the cumulative gas production at any time after the start of gas production, G gi =q g0 +q g1 +···+q gi , i=1,2,…;

[0103] P f0 Indicates the reverse thrust pressure corresponding to the start of gas production;

[0104] P fi Indicates the reverse thrust pressure P at any moment after gas production begins but before the wellhead pressure reaches the peak pressure fi , where if the wellhead pressure reaches the peak pressure, the actual wellhead pressure P bi ;

[0105] △Pg represents the gas production per unit pressure drop during the flowback stage of a shale gas well.

[0106] (3) In step 3, the calculation formula for water production per unit pressure drop is as follows:

[0107] △Pw=(G wi -G w0 ) / (P f0 -P fi )

[0108] Where:

[0109] G w0 Indicates the cumulative water production corresponding to the start of water production, Gw i =q w0 ;

[0110] Gwi Indicates the cumulative water production at any time after the start of water production, G wi =q w0 +q w1 +···+q wi , i=1,2,…;

[0111] P f0 Indicates the reverse prediction pressure corresponding to the start of water production;

[0112] P fi Indicates the reverse thrust pressure P at any moment after gas production begins but before the wellhead pressure reaches the peak pressure fi , where if the wellhead pressure reaches the peak pressure, the actual wellhead pressure P bi ;

[0113] △Pw represents the water production per unit pressure drop during the flowback stage of a shale gas well.

[0114] (4) The calculation formula of water-gas ratio is as follows:

[0115] Wg=q wi / q gi

[0116] Where:

[0117] q wi Indicates the water production at a certain moment in the flowback stage of a shale gas well;

[0118] q gi Indicates the gas production at a certain moment in the flowback stage of a shale gas well;

[0119] Wg represents the water-gas ratio corresponding to a certain moment in the flowback stage of a shale gas well.

[0120] (5) The calculation method of the daily average pressure drop under the unit total gas-liquid flow rate includes:

[0121] According to the water production and gas production recorded at a certain time interval, the total equivalent underground gas-liquid flow of the gas well can be obtained by equivalent underground flow:

[0122] q t =(q g ·B g 10000+q w ·B w )

[0123] Where:

[0124] q t It represents the equivalent total underground gas-liquid flow rate at any time after the shale gas well starts producing water;

[0125] q gIt indicates the gas production of shale gas wells recorded at a certain time interval;

[0126] q w It indicates the water production of shale gas wells recorded at a certain time interval;

[0127] B g represents the volume coefficient of dimensionless gas;

[0128] B w represents the volume coefficient of dimensionless water;

[0129] Calculate the average daily pressure drop per unit gas-liquid total flow rate:

[0130] △Pt=(P b0 -P bi ) / (G ti -G t0 )·twenty four

[0131] Where:

[0132] △Pt represents the daily average pressure drop per unit gas-liquid total flow rate at any time after the shale gas well starts producing water;

[0133] G i0 G represents the total accumulated gas-liquid flow rate corresponding to the start of water production in the shale gas well. ti =q t0 ;

[0134] G ti G represents the total gas-liquid flow at any time after the shale gas well starts producing water. ti =q t0 +q t1 +···+q ti , i=1,2,…;

[0135] It should be noted that, since the production dynamic data in this embodiment is recorded every hour, "24" is because there are 24 hours in a day. If the recording time interval of the production dynamic data is adjusted, the "24" is calculated based on the specific time interval.

[0136] Step 4: Based on the dynamic characteristic parameters of the flowback phase, optimize the flowback nozzle size in real time. By plotting the real-time change curves of the dynamic characteristic parameters of the flowback phase (gas production per unit pressure drop, water production per unit pressure drop, water-gas ratio, pressure drop rate, and daily average pressure drop per unit gas-liquid flow), the stable production effect of the shale gas well is promptly reflected. The goal is to maximize production potential, minimize production pressure loss, achieve continuous and stable gas-dominated flowback, and maintain production capacity to the greatest extent possible. This guides the real-time optimization of the flowback nozzle size.

[0137] The greater the gas production per unit pressure drop and the gradually decreasing water production per unit pressure drop, the better the gas well's flowback effect. The lower the water-gas ratio and the faster the reduction rate, the more gas dominates the gas-liquid flow in the shale gas well and the faster the establishment of a stable gas-dominated flow channel. The lower the daily average pressure drop and pressure drop rate per unit gas-liquid flow rate and the faster the reduction amplitude, the gradually decreasing pressure loss of the shale gas well and the effective maintenance of production capacity. Therefore, under a certain nozzle size, the real-time optimization of the nozzle size during the flowback phase includes:

[0138] If the gas production per unit pressure drop gradually increases or stabilizes, the water production per unit pressure drop stabilizes or decreases, the water-gas ratio gradually decreases, and the daily average pressure drop and pressure drop rate per unit gas-liquid flow rate decrease, it indicates that the gas well has a good flowback effect, and the size of the first-stage nozzle should be increased;

[0139] If the gas production per unit pressure drop gradually decreases, the water production per unit pressure drop is stable or increases, and the daily average pressure drop and pressure drop rate per unit gas-liquid flow rate are stable, it indicates that the gas well flowback effect is affected and the size of the first-stage nozzle needs to be reduced;

[0140] If the gas production per unit pressure drop is stable, the water production per unit pressure drop is stable or decreasing, and the daily average pressure drop and pressure drop rate per unit gas-liquid total flow rate are decreasing or stable, it indicates that the gas-liquid flowback of the gas well is relatively stable, and the current nozzle size should be maintained to continue the flowback.

[0141] Example:

[0142] Gas volume coefficient B of shale gas well H1 g The volume coefficient of water is 0.00275, B w is 1.01, and the comprehensive compression coefficient c t 0.00478MPa -1 .

[0143] Step 1: Record the production dynamic data of shale gas well flowback stage every hour, including gas production q g , water production q w , wellhead pressure p b , nozzle size CS and other parameters, and the specific analysis data are shown in Table 1. Draw the curve of water production qw, gas production qg, wellhead pressure pb and nozzle size CS over time, as shown in Figure 9 shown.

[0144] Table 1, production performance data of shale gas well H1 flowback stage:

[0145]

[0146]

[0147] Step 2: Based on the pressure data before the reversed peak pressure, obtain continuous and complete pressure decline data; specifically: after determining that the wellhead pressure of the shale gas well has reached the peak pressure, use the post-peak pressure decline fitting trend line to obtain the decline trend line formula, such as Figure 10 As shown; according to the decreasing trend line formula, the pressure data before the peak pressure is reversed and the reverse pressure before the peak pressure p is obtained. f The reverse thrust pressure is connected with the actual wellhead pressure data after the peak pressure, which is the continuous pressure decline data of the shale gas well, such as Figure 11 shown.

[0148] Step 3: Calculate the dynamic characteristic parameters of the flowback stage based on the production dynamic data of the shale gas well in the flowback stage and the continuous and complete pressure decline curve; wherein, the dynamic characteristic parameters of the flowback stage include gas production per unit pressure drop △Pg, water production per unit pressure drop △Pw, water-gas ratio Wg, pressure drop rate △P and daily average pressure drop per unit gas-liquid total flow rate △Pt, as shown in Table 2, and draw a curve graph, as shown in Table 2. Figure 12 、 Figure 13 shown.

[0149] Table 2, dynamic characteristic parameters of shale gas well H1 flowback stage:

[0150]

[0151]

[0152] Step 4: Based on the dynamic characteristic parameters of the flowback stage, optimize the nozzle size of the flowback stage in real time. Figure 9 The production dynamic data curve of the flowback stage and Figure 12 and Figure 13 The dynamic characteristic parameter curve shown in the figure shows that, at the current 6mm nozzle size, the gas production per unit pressure drop gradually increases, the water production per unit pressure drop decreases, the water-gas ratio gradually decreases, and the daily average pressure drop and pressure drop rate per unit gas-liquid flow rate decrease and stabilize. This indicates that the gas well production capacity is relatively stable, the pressure loss is small, and the overall gas well flowback effect is good. Therefore, the first-level nozzle size can be increased to 7mm to continue flowback, so as to observe the changes in dynamic characteristic parameters in real time and formulate a nozzle optimization and control plan in a timely manner.

[0153] The foregoing description is merely a preferred embodiment of the present invention and is not intended to limit the present invention. Those skilled in the art will readily appreciate that various modifications and variations of the present invention are possible. Any modifications, equivalent substitutions, or improvements made within the spirit and principles of the present invention are intended to be within the scope of protection of the present invention.

Claims

1. A real-time optimization method for nozzle size in the flowback stage after shale gas horizontal well pressure reduction, characterized in that: The steps include: Step 1: Record the production dynamic data of shale gas well flowback stage; Step 2: Based on the pressure data before the reverse estimation peak pressure, obtain continuous and complete pressure reduction data; Step 3: Calculate the dynamic characteristic parameters of the flowback stage based on the production dynamic data of the shale gas well and the continuous and complete pressure decline curve; Step 4: Based on the dynamic characteristic parameters of the flowback stage, optimize the nozzle size in the flowback stage in real time.

2. The method for real-time optimization of nozzle size in the flowback stage after pressure reduction of a shale gas horizontal well according to claim 1 is characterized in that: In step 1, the production dynamic data of the shale gas well during the flowback phase includes water production, gas production, wellhead pressure and nozzle size recorded at certain time intervals.

3. The method for real-time optimization of nozzle size in the flowback stage after pressure reduction of a shale gas horizontal well according to claim 2 is characterized in that: Step 2 includes: After determining that the wellhead pressure of the shale gas well has reached the peak pressure, the decreasing trend line after the peak pressure is fitted to obtain the decreasing trend line formula; According to the decreasing trend line formula, the pressure data before the peak pressure is reversed and the reversed pressure before the peak pressure is obtained by plotting; The connection between the reverse thrust pressure and the actual wellhead pressure data after the peak pressure is the continuous pressure decline data of the shale gas well.

4. The method for real-time optimization of nozzle size in the post-pressure flowback stage of a shale gas horizontal well according to claim 2, characterized in that: In step three, the dynamic characteristic parameters of the flowback stage include gas production per unit pressure drop, water production per unit pressure drop, water-gas ratio, pressure drop rate and daily average pressure drop per unit gas-liquid total flow rate.

5. The method for real-time optimization of choke size in the post-pressure flowback stage of a shale gas horizontal well according to claim 4, characterized in that: In step 3, the calculation formula for the pressure drop rate is as follows: △P=(P b0 -P bi ) / (t i -t0) Where: P b0， P bi Represent the wellhead pressure at the initial moment and at any moment respectively; t 0， t i Respectively represent the initial moment and the time corresponding to any moment; △P shows the pressure drop rate during the flowback stage of shale gas wells.

6. The method for real-time optimization of choke size in the post-pressure flowback stage of a shale gas horizontal well according to claim 4, characterized in that: In step 3, the calculation formula for gas production per unit pressure drop is as follows: △Pg=(G gi -G g0 ) / (P f0 -P fi ) Where: G g0 Indicates the cumulative gas production corresponding to the start of gas production, G gi =q g0 ; G gi Indicates the cumulative gas production at any time after the start of gas production, G gi =q g0 +q g1 +···+q gi , i=1,2,…; P f0 Indicates the reverse thrust pressure corresponding to the start of gas production; P fi Indicates the reverse thrust pressure P at any moment after gas production begins but before the wellhead pressure reaches the peak pressure fi , where if the wellhead pressure reaches the peak pressure, the actual wellhead pressure P bi ; △Pg represents the gas production per unit pressure drop during the flowback stage of a shale gas well.

7. The method for real-time optimization of nozzle size in the flowback stage after pressure reduction of a shale gas horizontal well according to claim 4 is characterized in that: In step 3, the calculation formula for water production per unit pressure drop is as follows: △Pw=(G wi -G w0 ) / (P f0 -P fi ) Where: G w0 Indicates the cumulative water production corresponding to the start of water production, Gw i =q w0 ; G wi Indicates the cumulative water production at any time after the start of water production, G wi =q w0 +q w1 +···+q wi , i=1,2,…; P f0 Indicates the reverse prediction pressure corresponding to the start of water production; P fi Indicates the reverse thrust pressure P at any moment after gas production begins but before the wellhead pressure reaches the peak pressure fi , where if the wellhead pressure reaches the peak pressure, the actual wellhead pressure P bi ; △Pw represents the water production per unit pressure drop during the flowback stage of a shale gas well.

8. The method for real-time optimization of nozzle size in the flowback stage after pressure reduction of a shale gas horizontal well according to claim 4 is characterized in that: In step 3, the water-gas ratio is calculated as follows: Wg=q wi / q gi Where: q wi Indicates the water production at a certain moment in the flowback stage of a shale gas well; q gi Indicates the gas production at a certain moment in the flowback stage of a shale gas well; Wg represents the water-gas ratio corresponding to a certain moment in the flowback stage of a shale gas well.

9. The method for real-time optimization of choke size in the post-pressure flowback stage of a shale gas horizontal well according to claim 4, characterized in that: In step 3, the calculation method of the daily average pressure drop under the unit total gas-liquid flow rate includes: According to the water production and gas production recorded at a certain time interval, the total equivalent underground gas-liquid flow of the gas well can be obtained by equivalent underground flow: q t =(q g ·B g ·10000+q w ·B w ) Where: q t It represents the equivalent total underground gas-liquid flow rate at any time after the shale gas well starts producing water; q g It indicates the gas production of shale gas wells recorded at a certain time interval; q w It indicates the water production of shale gas wells recorded at a certain time interval; B g represents the volume coefficient of dimensionless gas; B w represents the volume coefficient of dimensionless water; Calculate the average daily pressure drop per unit gas-liquid total flow rate: △Pt=(P b0 -P bi ) / (G ti -G t0 )·24 Where: △Pt represents the daily average pressure drop per unit gas-liquid total flow rate at any time after the shale gas well starts producing water; G i0 G represents the total accumulated gas-liquid flow rate corresponding to the start of water production in the shale gas well. ti =q t0 ; G ti G represents the total gas-liquid flow at any time after the shale gas well starts producing water. ti =q t0 +q t1 +···+q ti , i=1,2,….

10. The method for real-time optimization of choke size in the post-pressure flowback stage of a shale gas horizontal well according to any one of claims 4 to 9, characterized in that: In step 4, the real-time change curve of the dynamic characteristic parameters during the flowback phase is plotted to promptly reflect the stable production effect of the shale gas well, thereby guiding the real-time optimization of the nozzle size during the flowback phase. Under a certain nozzle size, the real-time optimization of the nozzle size during the flowback phase includes: If the gas production per unit pressure drop gradually increases or stabilizes, the water production per unit pressure drop stabilizes or decreases, the water-gas ratio gradually decreases, and the daily average pressure drop and pressure drop rate per unit gas-liquid flow rate decrease, it indicates that the gas well has a good flowback effect, and the size of the first-stage nozzle should be increased; If the gas production per unit pressure drop gradually decreases, the water production per unit pressure drop is stable or increases, and the daily average pressure drop and pressure drop rate per unit gas-liquid flow rate are stable, it indicates that the gas well flowback effect is affected and the size of the first-stage nozzle needs to be reduced; If the gas production per unit pressure drop is stable, the water production per unit pressure drop is stable or decreasing, and the daily average pressure drop and pressure drop rate per unit gas-liquid total flow rate are decreasing or stable, it indicates that the gas-liquid flowback of the gas well is relatively stable, and the current nozzle size should be maintained to continue the flowback.

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