A method for quantitatively evaluating gas invasion risk and optimizing wellbore structure under controlled risk

Abstract

The application discloses a gas invasion risk quantitative evaluation and risk controlled wellbore structure optimization method, which comprises the following steps: collecting the error between the predicted formation pore pressure equivalent drilling fluid density and the measured formation pore pressure equivalent drilling fluid density of each single well reservoir section of a design well and a block drilled well, and establishing an error sample space; obtaining the probability density function and the cumulative distribution function of the sample space by using a statistical method; obtaining the data of the design well, and completing the preliminary design wellbore structure; adding the preliminary determined reservoir section drilling fluid density additional value into the cumulative distribution function to determine the gas invasion risk probability; comparing with the maximum acceptable gas invasion risk probability to make a judgment; calculating the maximum reservoir section formation pore pressure equivalent drilling fluid density value; solving the pressure caused by the gas column height and the gas column weight of the invaded wellbore; solving the circulating pressure equivalent drilling fluid density value borne by the open hole section formation in the gas invasion pressure control process of the reservoir section; and optimizing the casing setting depth.

Description

Technical Field

[0001] This invention relates to the field of oilfield drilling and production technology, and is particularly applicable to the design and optimization of wellbore structures for high gas content wells. Background Technology

[0002] Since the 1960s, with the development of formation pore pressure and fracturing pressure prediction and detection technologies, especially the promotion of near-balanced drilling technology and the mastery of well control technology, the petroleum industry has gradually summarized a relatively scientific design method for casing layers and running depth in wellbore structures. The industry standard SY / T 5431-2008, "Wellbore Structure Design Method," proposes a design philosophy that prioritizes preventing well kicks, preventing formation fracturing at the casing shoe, and avoiding differential pressure sticking, while meeting the constraint of the mandatory sealing point. It establishes a design method based on two pressure profiles—formation pore pressure and fracturing pressure—using graphical or analytical methods, either bottom-up or combined with a top-down approach, to determine the casing layers and running depth, and then adjusting them according to constraints. This method is currently the most commonly used wellbore structure design method in various oilfields in China.

[0003] However, this design method has significant shortcomings. The rationality of each casing depth depends entirely on the accuracy and sufficiency of the understanding of the underlying formation characteristics. More precisely, it depends on the error range of the formation pore pressure and fracture pressure predictions based on adjacent well data before drilling. The impact of this error on the rationality of the wellbore structure is related to the reservoir fluid type. For oil wells, the reservoir fluid is liquid. During drilling, if the drilling fluid design density is too low due to inaccurate pressure prediction, it cannot balance the formation pressure and a well kick may occur. However, because the reservoir fluid has a large self-weight, the internal pressure of the formation at the upper casing shoe and other weak and easily leaking formations above it is much lower than the reservoir pressure at the well kick location. Even if the upper casing depth is unreasonable, the fluid upward velocity is slow, and the well crew has ample time for well control actions, so the well control risk remains relatively low. However, for gas wells, the upward velocity of gas during a well kick is extremely fast, and its weight is relatively small, even negligible in shallow wells. The internal pressure of a well kick on the formation at the upper casing shoe and other weak and easily leaking formations above it is close to the reservoir pressure at the kick point. At the same time, the well crew has very little time to react to well control actions, resulting in significant well control risks, especially in high-pressure, high-gas-content wells, where the situation will be even more severe once a well kick occurs. Therefore, under the same conditions, the appropriate depth of the upper casing becomes particularly important for gas wells.

[0004] In general, current wellbore design methods are entirely based on predictions of formation pore pressure and fracture pressure (or leakage pressure) made before drilling, using data from neighboring wells in the same or adjacent blocks. However, these methods cannot eliminate the impact of pressure prediction errors. Since formation pressure prediction inevitably involves errors, the commonly used wellbore design methods are also inherently flawed, inevitably introducing additional well control risks to drilling operations. The magnitude of these risks is related to the reservoir fluid type, and is particularly pronounced for gas. Summary of the Invention

[0005] The technical problem to be solved by this invention is to provide a wellbore structure optimization method that can be applied to the quantitative evaluation and risk control of gas invasion risk in high gas-bearing wells. Based on the preliminary wellbore structure design of a single well, the method comprehensively considers the gas invasion risk at the bottom of the well caused by formation pressure and its prediction error, optimizes the casing depth of each opening, and ensures well control safety.

[0006] To solve the above-mentioned technical problems, the technical solution adopted by the present invention is: a method for quantitative assessment and risk-controlled wellbore structure optimization of gas invasion risk, comprising the following steps:

[0007] (1) The error between the predicted formation pore pressure equivalent drilling fluid density and the measured formation pore pressure equivalent drilling fluid density of each single well completed in the same block of the design well was statistically analyzed, and an error sample space was established.

[0008] (2) Apply statistical methods to obtain the probability density function and cumulative distribution function of the sample space;

[0009] (3) Obtain the data of the design well and complete the preliminary design of the well structure;

[0010] (4) Substitute the preliminarily determined additional value of drilling fluid density in the reservoir section into the cumulative distribution function to determine the probability of gas intrusion risk under the preliminary design wellbore structure;

[0011] (5) Compare with the maximum acceptable probability of air intrusion risk;

[0012] (6) Calculate the equivalent drilling fluid density value of the formation pore pressure in the maximum reservoir section under the acceptable gas invasion risk probability.

[0013] (7) Determine the height of the gas column and the pressure caused by the weight of the gas column at point H when the natural gas enters the wellbore;

[0014] (8) Determine the equivalent drilling fluid density value of the circulating pressure borne by the formation in the open hole section during the gas intrusion process in the reservoir section;

[0015] (9) Optimize the casing depth.

[0016] Specifically, the following steps are included:

[0017] (1) Analyze the error between the predicted formation pore pressure equivalent drilling fluid density and the measured formation pore pressure equivalent drilling fluid density in the reservoir section of each well completed in the same block as the designed well, and establish an error sample space S. Δρ ;

[0018] (2) Applying statistical methods to fit the sample space S Δρ From the overall distribution, we obtain the probability density function f(x) of the sample space, and further obtain its cumulative distribution function F. X (x);

[0019] (3) Obtain geological data, formation pressure prediction data, and actual drilling data from adjacent wells for the design well, complete the preliminary design of the wellbore structure, and preliminarily determine the drilling fluid density value ρ used in the reservoir section of the design well. m0 And additional values ​​Δρ0, number of well openings, wellbore gradation, and casing depth data for each layer;

[0020] (4) Substitute the preliminary determined reservoir section drilling fluid density increment Δρ0 from step (3) into the cumulative distribution function F obtained in step (2). X In (x), the gas intrusion risk probability P0 under the preliminary wellbore structure design is obtained, and its solution method is as follows:

[0021] P0 = 1 - X (Δρ0)

[0022] (5) Compare the P0 obtained in step (4) with the maximum gas invasion risk probability P that the block or oilfield where the design well is located can accept. max Make a comparison judgment; if P0 ≤ P max If the current wellbore structure has an acceptable gas intrusion risk, then no further optimization is needed; if P0 > P max If the current well structure has an unacceptable risk of gas intrusion, it should be further optimized to reduce the risk of gas intrusion. Step (6) should be executed.

[0023] (6) Let P max =1- X (x), calculate the error Δρ between the drilling fluid density equivalent to the formation pore pressure in the maximum reservoir section under the acceptable gas invasion risk probability and the predicted value. max Furthermore, the equivalent drilling fluid density value ρ of the formation pore pressure in the maximum reservoir section under the acceptable probability of gas invasion risk was obtained. pmax The calculation method is as follows:

[0024] ρ pmax =ρ p +Δρ max

[0025] In the formula, ρ p The drilling fluid density is the equivalent of the predicted formation pore pressure in the reservoir section of the design well.

[0026] (7) Under the condition of preliminary casing program design, it is assumed that gas invasion occurs in the reservoir section during drilling, and the depths of the top boundary and the bottom boundary of the reservoir section are H t and H respectively, the formation pore pressure equivalent drilling fluid density of the reservoir section is the maximum reservoir section formation pore pressure equivalent drilling fluid density ρ determined in step (6) pmax ; the allowable gas kick volume ΔV is determined according to the well control response time at the operation site max to solve for the gas column height h of natural gas invading the wellbore w and the pressure P generated by the weight of the gas column at H w ;

[0027] The calculation method of allowable gas kick volume ΔV max is as follows:

[0028]

[0029] wherein t is the well control response time at the operation site, which is related to the accuracy of well control equipment and the capability of the operation team; T a is the standard state temperature, taken as 293K; K is the reservoir permeability; A is the cross-sectional area of the reservoir; P a is the standard atmospheric pressure; μ is the viscosity of reservoir natural gas; z is the compressibility factor of reservoir natural gas; T H is the reservoir temperature; L is the length from the wellbore center at well depth H to the effective boundary of the reservoir;

[0030] (8) Taking ρ pmax as the drilling fluid density value used for drilling the reservoir section at well depth H, after gas invasion occurs in the reservoir section at well depth H, solve for the circulating pressure equivalent drilling fluid density value borne by the open hole formation between well depth H and the depth H0 of the last casing shoe above it during killing operation;

[0031] (9) Determine that under the condition that the designed well meets the acceptable gas invasion risk probability P max , the optimized setting depth of the last casing above the reservoir at well depth H is h1, which satisfies the following condition: for any well depths h1 and h2 in the open hole section, where H0≤h1<h2<H, there is always ρ h1max ≥ρ h1l and ρ h2max <ρ h2l , or ρ h1max ≥ρ h1f and ρ h2max <ρ h2f , wherein, ρ h1l and ρ h2l are the predicted lost circulation pressure equivalent drilling fluid density values of the formation at well depths h1 and h2 respectively, T h1f and ρ h2fThese are the drilling fluid density values ​​equivalent to the predicted fracture pressure of the formation at well depths h1 and h2, respectively.

[0032] In step (3), the preliminary design of the well shaft structure is completed in accordance with the industry standard SY / T 5431-2008 "Well Structure Design Method".

[0033] In step (7), the well control response time t at the work site is related to the accuracy of the well control equipment and the capabilities of the work team.

[0034] In step (7), the height h of the gas column of natural gas invading the wellbore is calculated based on the wellbore gradation. w The pressure P caused by the weight of the air column at point H w :

[0035]

[0036]

[0037] In the formula, V a T is the unit annular volume of the wellbore, which is related to the wellbore gradation; S is the ratio of the weight of reservoir natural gas to the weight of an equal volume of air; T H Z represents the reservoir temperature. H is the compressibility coefficient of the reservoir natural gas.

[0038] In step (8), for any well depth h in the open hole section, where H0≤h<H, the maximum circulating pressure equivalent drilling fluid density value ρ experienced during well control is... hmax The calculation method is as follows:

[0039]

[0040] In the formula, G m0 ΔP represents the hydrostatic pressure gradient of the drilling fluid column during gas invasion; Y represents the compressibility ratio of the same gas column at well depths h and H; ΔP wpm0 This represents the decrease in drilling fluid column pressure caused by natural gas intrusion into the wellbore.

[0041] The beneficial effects of this invention are: it can be applied to high gas-bearing wells, and based on the preliminary wellbore structure design of a single well, it comprehensively considers the risk of gas intrusion at the bottom of the well caused by formation pressure and its prediction errors, optimizes the casing depth of each opening, and ensures well control safety. Attached Figure Description

[0042] Figure 1 This is a flowchart of the method of the present invention.

[0043] Figure 2 For the sample space S Δρ The fit of its overall distribution.

[0044] Figure 3 It is the cumulative distribution function F X (x) curve.

[0045] Figure 4 This is a predicted formation pressure profile for a certain design well.

[0046] Figure 5 It is a neighboring well S in the same block as a certain design well. Δρ The overall distribution is fitted.

[0047] Figure 6 It is a neighboring well S in the same block as a certain design well. Δρ The cumulative probability distribution function curve.

[0048] Figure 7 It is a profile of predicted formation pressure and a well control curve profile for a certain design well. Detailed Implementation

[0049] The technical solutions of the present invention will be clearly and completely described below with reference to the accompanying drawings of the embodiments of the present invention. Obviously, the described embodiments are only some embodiments of the present invention, and not all embodiments. All other embodiments obtained by those skilled in the art based on the embodiments of the present invention without creative effort are within the scope of protection of the present invention.

[0050] like Figure 1 As shown, the method for quantitative assessment of gas invasion risk and optimization of wellbore structure with risk control of the present invention includes the following steps:

[0051] (1) The error between the predicted formation pore pressure equivalent drilling fluid density and the measured formation pore pressure equivalent drilling fluid density of each single well completed in the same block of the design well was statistically analyzed, and an error sample space was established.

[0052] (2) Apply statistical methods to obtain the probability density function and cumulative distribution function of the sample space;

[0053] (3) Obtain the data of the design well and complete the preliminary design of the well structure;

[0054] (4) Substitute the preliminarily determined additional value of drilling fluid density in the reservoir section into the cumulative distribution function to determine the probability of gas intrusion risk under the preliminary design wellbore structure;

[0055] (5) Compare with the maximum acceptable probability of air intrusion risk;

[0056] (6) Calculate the equivalent drilling fluid density value of the formation pore pressure in the maximum reservoir section under the acceptable gas invasion risk probability.

[0057] (7) Determine the height of the gas column and the pressure caused by the weight of the gas column at point H when the natural gas enters the wellbore;

[0058] (8) Determine the equivalent drilling fluid density value of the circulating pressure borne by the formation in the open hole section during the gas intrusion process in the reservoir section;

[0059] (9) Optimize the casing depth.

[0060] Specifically, the following steps are included:

[0061] (1) Analyze the error between the predicted formation pore pressure equivalent drilling fluid density and the measured formation pore pressure equivalent drilling fluid density in the reservoir section of each well completed in the same block as the designed well, and establish an error sample space S. Δρ ;

[0062] (2) Applying statistical methods to fit the sample space S Δρ The overall distribution, such as Figure 2 As shown, the probability density function f(x) of the sample space is obtained, and its cumulative distribution function F is further obtained. X (x), such as Figure 3 As shown;

[0063] (3) Obtain geological data, formation pressure prediction data, and actual drilling data from adjacent wells for the design well, complete the preliminary design of the wellbore structure, and preliminarily determine the drilling fluid density value ρ used in the reservoir section of the design well. m0 And additional values ​​Δρ0, number of well openings, wellbore gradation, and casing depth data for each layer;

[0064] (4) Substitute the preliminary determined reservoir section drilling fluid density increment Δρ0 from step (3) into the cumulative distribution function F obtained in step (2). X In (x), the gas intrusion risk probability P0 under the preliminary wellbore structure design is obtained, and its solution method is as follows:

[0065] P0 = 1 - X (Δρ0)

[0066] (5) Compare the P0 obtained in step (4) with the maximum gas invasion risk probability P that the block or oilfield where the design well is located can accept. max Make a comparison judgment; if P0 ≤ P max If the current wellbore structure has an acceptable gas intrusion risk, then no further optimization is needed; if P0 > P max If the current well structure has an unacceptable risk of gas intrusion, it should be further optimized to reduce the risk of gas intrusion. Step (6) should be executed.

[0067] (6) Let P max =1- X (x), inverse calculation or through Figure 3 This yields the error Δρ between the drilling fluid density equivalent to the formation pore pressure in the maximum reservoir section under the acceptable probability of gas invasion and the predicted value.max , further obtain the maximum formation pore pressure equivalent drilling fluid density value ρ of the reservoir interval under the acceptable gas kick risk probability pmax , and the calculation method is:

[0068] ρ pmax =ρ p +Δρ max

[0069] wherein, ρ p is the predicted formation pore pressure equivalent drilling fluid density of the reservoir interval of the designed well;

[0070] (7) Under the condition of the preliminary casing program design, it is assumed that gas kick occurs in the reservoir interval during drilling, and the depths of the top boundary and the bottom boundary of the reservoir interval are H t and H respectively, and the formation pore pressure equivalent drilling fluid density value of the reservoir interval is the maximum formation pore pressure equivalent drilling fluid density value ρ of the reservoir interval determined in step (6) pmax ; determine the gas kick and kick tolerance ΔV according to the well control response time at the operation site max , and solve for the gas column height h of natural gas invading the wellbore w and the pressure P generated by the weight of the gas column at H w ;

[0071] the calculation method of gas kick and kick tolerance ΔV max is:

[0072]

[0073] wherein, t is the well control response time at the operation site, which is related to the accuracy of well control equipment and the capability of the operation team; T a is the standard state temperature, which is taken as 293K; K is the reservoir permeability; A is the cross-sectional area of the reservoir; P a is the standard atmospheric pressure; μ is the viscosity of natural gas in the reservoir; z is the compressibility factor of natural gas in the reservoir; T H is the reservoir temperature; L is the length from the wellbore center at well depth H to the effective boundary of the reservoir;

[0074] (8) Taking ρ pmax as the drilling fluid density value used for drilling the reservoir interval at well depth H, after gas kick occurs in the reservoir interval at well depth H, solve for the circulating pressure equivalent drilling fluid density value borne by the formation of the open hole section from well depth H to the depth H0 of the uppermost last casing shoe during killing operation;

[0075] (9) Determine that for the designed well, under the acceptable gas kick risk probability P max , the optimized setting depth of the last casing above the reservoir at well depth H is h1, and the satisfied condition is: for any well depths h1 and h2 in the open hole section, where H0≤h1<h2<H, ρ h1max ≥ρh1l And ρ h2max <ρ h2l , or ρ h1max ≥ρ h1f And ρ h2max <ρ h2f , where ρ h1l and ρ h2l These are the predicted lost circulation pressure equivalent drilling fluid density values ​​for the formation at well depths h1 and h2, respectively, ρ h1f and ρ h2f These are the drilling fluid density values ​​equivalent to the predicted fracture pressure of the formation at well depths h1 and h2, respectively.

[0076] In step (3), the preliminary design of the well shaft structure is completed in accordance with the industry standard SY / T 5431-2008 "Well Structure Design Method".

[0077] In step (7), the well control response time t at the work site is related to the accuracy of the well control equipment and the capabilities of the work team.

[0078] In step (7), the height h of the gas column of natural gas invading the wellbore is calculated based on the wellbore gradation. w The pressure P caused by the weight of the air column at point H w :

[0079]

[0080]

[0081] In the formula, V a T is the unit annular volume of the wellbore, which is related to the wellbore gradation; S is the ratio of the weight of reservoir natural gas to the weight of an equal volume of air; T H Z represents the reservoir temperature. H is the compressibility coefficient of the reservoir natural gas.

[0082] In step (8), for any well depth h in the open hole section, where H0≤h<H, the maximum circulating pressure equivalent drilling fluid density value ρ experienced during well control is... hmax The calculation method is as follows:

[0083]

[0084] In the formula, G m0 ΔP represents the hydrostatic pressure gradient of the drilling fluid column during gas invasion; Y represents the compressibility ratio of the same gas column at well depths h and H; ΔP wpm0 This represents the decrease in drilling fluid column pressure caused by natural gas intrusion into the wellbore.

[0085] The following description is based on specific embodiments:

[0086] (1) The designed well has a natural gas reservoir depth of 3250m. The drill bit diameter used in the oil section is Φ215.9mm, and the drill pipe is Φ127mm. The maximum acceptable gas intrusion risk probability in the oilfield is 5%. The geothermal gradient is 3℃ / 100m. The natural gas compressibility ratios at the wellhead, 1950m, and 3250m are 0.8, 1.05, and 1.20, respectively. The weight ratio of natural gas to air of the same volume is 0.6. The overflow shut-in time is 300s. The reservoir permeability is 104mD, and the reservoir natural gas viscosity is 12.55×10⁻⁶ m³ / s. -3 The reservoir's compressibility factor is 0.965, and the effective reservoir boundary at 3250m is 234m from the wellbore center. The predicted formation pressure equivalent drilling fluid density is shown in Table 1, and the formation pressure profile is as follows: Figure 4 As shown:

[0087] Table 1. Drilling fluid density equivalent to predicted formation pressure for a certain design well.

[0088]

[0089] (2) The error between the predicted formation pore pressure equivalent drilling fluid density and the measured formation pore pressure equivalent drilling fluid density of each single well completed in recent years in the same block of the design well was statistically analyzed, and an error sample space of S was established. Δρ ={0.28,0.23,0.33,-0.22,-0.20…}, as shown in Table 2:

[0090] Table 2. Space of error samples for the same block of the designed well (partial)

[0091]

[0092] (3) Fitting the sample space S Δρ The overall distribution, such as Figure 5 As shown, it conforms to a normal distribution, from which the probability density function f(x) and cumulative distribution function F can be obtained. X (x) are respectively:

[0093]

[0094]

[0095] (4) Based on the industry standard SY / T 5431-2008 "Well Structure Design Method", the preliminary design of the well structure and other parameters of the designed well is determined, as shown in Table 3.

[0096] Table 3 Preliminary design wellbore structure and parameters

[0097]

[0098] (5) As shown in Table 3, the drilling fluid density value ρ of the reservoir section in the preliminary design section is... m0 =1.38g / cm 3 ;

[0099] Δρ0=ρ m0 -ρ p =1.38g / cm 3 -1.23g / cm 3 =0.15g / cm 3 ;

[0100] Substitute Δρ0 into F X Solving for (x), we get P0 = 1 - F. X (Δρ0)=7%.

[0101] (6)P max =5%, and by comparison we know P0 > P max Let P max =1-F X (x), by inverse calculation we can obtain Δρ max =0.18, then ρ pmax =Δρ p0 +Δρ max =1.41g / cm 3 .

[0102] (7) Under the preliminary design of the wellbore structure, it is assumed that gas invasion occurs in the reservoir section at a depth of 3248-3250m during the third drilling process, and the formation pore pressure equivalent drilling fluid density value is ρ. pmax =1.41g / cm 3 Calculate the allowable gas inrush well flow ΔV max The reservoir cross-sectional area A = 0.2159 × 2 = 0.4318 m² 2 ,

[0103] reservoir temperature T H =3250×3 / 100+273=370.5K,

[0104] but

[0105]

[0106] (8) The diameter of the three-section wellbore is 215.9 mm, and the diameter of the drill pipe used is 127 mm. According to the drilling manual, the unit annular volume of the three-section wellbore is V. a = 23.97 L / m. The well inrush allowable capacity ΔV has already been calculated. max =1.5m 3 Under the given conditions, calculate the height h of the natural gas column intruding into the wellbore. w ,

[0107]

[0108] Calculate the pressure P caused by the weight of the gas column at 3250m w ,

[0109] Z H =1.2

[0110] S=0.6

[0111]

[0112] (9) After gas invasion occurs in the reservoir section at the well depth of 3250m, solve for the equivalent circulating drilling fluid density ρ of the formation pressure at any depth h in the open hole section between 3250m (well depth of the third spudding section during killing) and 1825m (depth of the last casing shoe above the depth of the second spudding intermediate casing shoe in the preliminary wellbore structure design) hmax .

[0113] Take the well depth of 1950m as an example for the calculation process:

[0114] G m0 =ρ pmax g=1.41×0.00981=0.0138MPa / m

[0115] T h =1950×3 / 100+273=331.5K

[0116] Z h =1.05

[0117]

[0118] ΔP wpm0 =h w G m0 =62.6×0.0138=0.8639MPa

[0119]

[0120] The equivalent circulating drilling fluid density values calculated for other well depths are shown in Table 4, and a kill weight equivalent density profile curve is established in the formation pressure profile, as shown in Figure 7 . Figure 7 The deepest depth h1 corresponding to the intersection of the kill weight equivalent density profile curve and the formation leakage pressure equivalent density curve satisfies the judgment condition in step (9). For any well depths h1 and h2 in the open hole section (1950m≤h1<h2<3250m), it is always true that ρ h1max ≥ρ h1l and ρ h2max <ρ h2lTherefore, h1 is determined to be the optimized casing depth for the second-stage drilling technique, and the drilling fluid density for the third-stage reservoir section is optimized to 1.41 g / cm³. 3 The design parameters can meet the requirement that the probability of air intrusion risk is no more than 5%, and the optimized design parameters are shown in Table 5.

[0121] Table 4 shows the drilling fluid density values ​​calculated for some well depths.

[0122]

[0123] Table 5. Wellbore structure data after design optimization

[0124]

[0125] In summary, the content of this invention is not limited to the above-described embodiments. Those skilled in the art can easily propose other embodiments within the technical guiding principles of this invention, but such embodiments are all included within the scope of this invention.

Claims

1. A method for quantitative evaluation of gas invasion risk and optimization of well profile structure with controlled risk, characterized in that, Specifically comprising the following steps: (1) Statistics of the error between the predicted formation pore pressure equivalent drilling fluid density and the measured formation pore pressure equivalent drilling fluid density of each single well reservoir section of the designed well in the same block, and establishes an error sample space ; (2) Apply statistical methods to fit the error sample space From the overall distribution, we can obtain the probability density function of the sample space. Furthermore, its cumulative distribution function is obtained. ; (3) Obtain the geological data of the design well, formation pressure prediction data, and actual drilling data of adjacent wells, complete the preliminary design well structure of the design well, and preliminarily determine the drilling fluid density value used in the reservoir section of the design well and the drilling fluid density additional value , the opening number, the hole size grading, and the casing depth data of each layer (4) Adding the value of the drilling fluid density of the reservoir section preliminarily determined in step (3) The cumulative distribution function obtained in step (2) is substituted into step (3) The gas invasion risk probability under the preliminary designed well profile is obtained The solution method is as follows: ； (5) the well structure obtained in step (4) is used as the initial well structure of step (1), and steps (1) to (4) are repeated until the well structure obtained in step (4) is the same as the well structure obtained in step (1), or the number of iterations reaches the preset maximum number of iterations and the maximum gas invasion risk probability acceptable by the block or oilfield where the design well is located is compared, if the current design well structure is a well structure with acceptable gas invasion risk, and further optimization is not required; if the gas invasion risk of the current well structure is not acceptable, further optimization is required to reduce the gas invasion risk, and step (6) is performed. (6) Let , calculate the error between the maximum reservoir section formation pore pressure equivalent drilling fluid density under the acceptable gas invasion risk probability and the predicted value , further obtain the maximum reservoir section formation pore pressure equivalent drilling fluid density value under the acceptable gas invasion risk probability , the calculation method is: ； wherein PREF is the predicted formation pore pressure equivalent mud density for the design well reservoir section; (7) under the condition of the preliminary design of the wellbore structure, assuming that gas invasion occurs in the reservoir section during drilling, the top boundary and bottom boundary depths of the reservoir section are and respectively, and the equivalent drilling fluid density value of the formation pore pressure of the reservoir section is the maximum equivalent drilling fluid density value of the formation pore pressure of the reservoir section determined in step (6) ; the gas invasion well flow allowance is determined according to the well control reaction time on the operation site , the gas column height of the invaded natural gas in the wellbore is solved , and the pressure caused by the gas column weight at H is solved ; Gas influx well kick volume The calculation method is: ； In the formula, The well control reaction time of the operation site is related to the accuracy of the well control equipment and the ability of the operation team. The standard state temperature is 293 K. The reservoir permeability is The reservoir cross-sectional area is The standard atmospheric pressure is The reservoir natural gas viscosity is The reservoir natural gas compressibility factor is The reservoir temperature is The length from the wellbore center at the well depth H to the effective boundary of the reservoir is (8) to As the well depth The maximum circulating pressure equivalent drilling fluid density value of the open hole section between the well depth H and the last casing shoe depth H0 above it during the killing process after the gas invasion of the reservoir section at the well depth H is solved, and the drilling fluid density value used in the drilling process of the reservoir section at the well depth H0. For any well depth h of the open hole section, H0≤h<H, the maximum circulating pressure equivalent drilling fluid density value during the killing process is , and the calculation method is: ； wherein is the static fluid column pressure gradient of the drilling fluid when gas invasion occurs; is the compression ratio of the same gas column at well depths h and H; is the drilling fluid column pressure reduction value due to the invasion of natural gas into the wellbore; (9) determine the design well to meet the acceptable gas invasion risk probability The optimized down depth of the last casing of the upper reservoir at the well depth H is , which satisfies the condition that for any well depth of the open hole section and , wherein H0≤ < <H, have and , or and , wherein and are the predicted lost circulation equivalent mud density values of the formation at the well depths and , and are the predicted fracture pressure equivalent mud density values of the formation at the well depths and ; and are the maximum circulating pressure equivalent mud density values at and .

2. The method according to claim 1, wherein, In step (3), according to the industry standard SY / T 5431-2008 "Well structure design method", the preliminary design well structure of the design well is completed.

3. The method for gas invasion risk quantitative evaluation and risk-controlled well profile optimization according to claim 1, characterized in that, In step (7), the well control response time at the work site It is related to the accuracy of the well control equipment and the capabilities of the operating team.

4. The method for gas invasion risk quantitative evaluation and risk-controlled well profile optimization according to claim 1, characterized in that, In step (7), the gas column height of the natural gas invading the wellbore is solved in combination with the wellbore grading condition and the pressure caused by the gas column weight at H : ； ； wherein is the unit annular volume of the wellbore, related to the hole grading; S is the ratio of the weight of the reservoir natural gas to the weight of the same volume of air; is the reservoir temperature; is the compressibility of the reservoir natural gas.

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