Method for determining formation leak-off pressure in a well log

Abstract

This invention relates to a logging method for rapidly determining formation leakage pressure, obtaining formation lithology and reservoir space type, formation vertical depth h, formation pore fluid pressure gradient (FPG), and formation water density D at points of interest in the target interval. W and formation clay content V sh The influence coefficients ε1 (strata lithology) and ε2 (reservoir space type) are determined by stratigraphic lithology and reservoir space type; the formula CPL = CFP + ε1 × ε2 × V is used to determine these influence coefficients. sh Calculate the formation leakage pressure coefficient CPL at the point of interest in the target layer; using the formula PL = 0.1 × CPL × D. W The formation leakage pressure PL at the target layer point of interest is calculated using the formula PLG = PL / h. The formation leakage pressure gradient PLG at the target layer point of interest is then calculated using this formula. Calculating the formation leakage pressure gradient can fully reflect the essential characteristics of the formation, requires minimal data resources, has low implementation costs, is simple and easy to implement, and is more readily applicable in the field.

Description

TECHNICAL FIELD

[0001] The present application relates to the field of oil and gas drilling engineering safety and logging engineering technology, and in particular to a logging method for quickly determining formation leakage pressure. BACKGROUND

[0002] Formation leakage pressure refers to the pressure at which drilling fluid leakage begins to occur at a certain depth in the well, and is an important parameter for determining the upper limit of drilling fluid density in safe drilling of oil engineering. It is provided by logging and well logging engineering service personnel during drilling. During drilling, including stopping drilling and waiting or performing other related occupations, accurate knowledge of formation leakage pressure is beneficial to ensuring safety in the well and preventing unexpected complications, and is more conducive to efficient and safe drilling and the creation of a green oil and gas development project.

[0003] Currently, the formation pore fluid pressure can be accurately determined while drilling using the data of a comprehensive logging instrument on the site of oil and gas drilling engineering. For the measurement of formation leakage pressure, the main method is to measure it through a formation leakage test method after drilling for about 5m after casing. The core of this method is to shut in and slowly open the pump, and use the comprehensive logging instrument to record the change of standpipe pressure curve. When the standpipe pressure reaches the peak value and then decreases, and then remains stable, it is considered that drilling fluid leakage occurs at the bottom of the well, and the drilling fluid pressure at the bottom of the well is the formation leakage pressure. This traditional method can only be tested and measured once after each casing, and cannot quickly determine the formation leakage pressure data that needs to be grasped in time while drilling. In addition, the means of using shut-in pressure to cause formation leakage is easy to cause a large amount of drilling fluid leakage and unnecessary drilling safety hazards.

[0004] CN109184674A (CN201811238134.1) patent proposes a new method for measuring formation leakage pressure while drilling: 1) after the drill bit enters the reservoir, stop drilling, stabilize the wellhead casing pressure value PC, and circulate the drilling fluid; 2) gradually increase the wellhead casing pressure value PC, monitor the wellhead drilling fluid flow through the micro-flow monitoring system, and determine whether the wellhead drilling fluid flow deviates from the normal flow average; 3) when the outlet drilling fluid flow is just lower than the normal flow average, record the bottom hole pressure BHP at this time through the downhole pressure while drilling monitoring system, and the formation leakage pressure PL≈BHP at this time, that is, PL=BHP, and the formation leakage pressure PL is obtained. This method also needs to perform a formation leakage test, only the micro-flow monitoring makes the amount of drilling fluid leakage smaller, and there is still a risk of causing a large amount of formation leakage, and from the perspective of drilling safety, this micro-flow test cannot be performed continuously for a long time.

[0005] CN109458171A(CN201811238131.8) patent proposes a new narrow safety density window formation leakage pressure measurement method: 1) stop the pump, quickly close the throttle valve to increase the casing pressure value Pc, stop closing the stop valve when the casing pressure value reaches the design casing pressure value Pcmax, wherein the design casing pressure value Pcmax=Pfm+PCD+△P, Pfm is the estimated circulation loss value when the drilling fluid circulates, PCD is the casing pressure value when drilling normally;△P is an additional value considering the estimated circulation loss value error and safety when the drilling fluid circulates, 0.1MPa≤△P≤7Mpa; 2) observe the casing pressure value, when the casing pressure value gradually tends to be stable, take the stable casing pressure value PCL; 3) calculate the leakage pressure PL=PH+PCL, wherein PH=DEN*9.81*TVD, DEN is the density of drilling fluid, and TVD is the well vertical depth. This method still needs to be pumped, stopped, and the maximum casing pressure value Pcmax is reached, and the formation leakage pressure is estimated by leakage, which cannot be continuously measured for a long time while drilling, and is not suitable for long well section formation leakage pressure measurement.

[0006] The new method for calculating drilling formation leakage pressure based on logging data proposed by Zhou Jinyu team (Logging Interpretation, Vol. 47, No. 1, February 2023) gives a new model for calculating the formation leakage pressure of long-pore leakage, dissolution leakage and fracture leakage in drilling geological profile. The new calculation method disclosed in the paper needs to obtain the tensile strength of rock when calculating the pore formation leakage pressure, and needs to obtain the formation fracture surface dip angle, cohesion and other parameters when calculating the fracture formation leakage pressure. The process of obtaining these parameters is too complex, and it is not possible to achieve the conditions in the field operation process, which cannot meet the rapid determination requirements and is suitable for post-completion comprehensive research work.

[0007] In summary, the formation leakage pressure is determined by the formation leakage test and micro-flow monitoring test, and the narrow safety density window test method, which has hysteresis and safety hazards, and the calculation accuracy of the formation leakage pressure is not high and not timely, which greatly reduces the guiding significance and value of drilling. SUMMARY

[0008] The present application provides a method for quickly determining the formation leakage pressure, which overcomes the shortcomings of the prior art and provides reliable formation leakage pressure data for safe drilling in a timely manner.

[0009] To achieve the above object, the present application provides a method for quickly determining the formation leakage pressure, which comprises:

[0010] 1) obtaining the formation lithology and reservoir space type, formation vertical depth h, formation pore fluid pressure gradient FPG, and formation water density D of the interest point of the target interval Wand formation clay content V sh ;

[0011] 2) Determine the influence coefficient ε1 of stratigraphy and the influence coefficient ε2 of reservoir space type by stratigraphy lithology and reservoir space type;

[0012] The formula CFP = 10 × FPG × h / (D) W The formation pore fluid pressure coefficient (CFP) is calculated using the formula (×g×h), where CFP is a dimensionless quantity; and h is the formation vertical depth, FPG is the formation pore fluid pressure gradient, and D... W Let g be the density of the formation water, and g be the gravitational acceleration of the regional formation.

[0013] 3) Using the formula CPL=CFP+ε1×ε2×V sh Calculate the formation leakage pressure coefficient CPL at the point of interest in the target layer; using the formula PL = 0.1 × CPL × D. W The formation leakage pressure PL at the target layer point of interest is calculated using the formula PLG = PL / h.

[0014] Furthermore, it also includes selecting, based on the on-site drilling requirements, the formation leakage pressure coefficient CPL, formation leakage pressure PL, or formation leakage pressure gradient PLG for the target formation point of interest.

[0015] Furthermore, in step 1), the formation pore fluid pressure gradient (FPG) under normal pressure is between 1.03 and 1.25 MPa / hm.

[0016] Furthermore, in step 1), there is a corresponding regional formation water total salinity KHD.

[0017] Use formula D when processing data. W =6×10 -7 Calculate the formation water density D using ×KHD+0.9992. W When corresponding regional formation water chloride ion content (CL-) data are available, use formula D. W =1×10 -6 Calculate formation water density D using ×CL-+0.9997 W When both formation water total salinity (KHD) and formation water chloride ion content (CL-) data are available, formation water total salinity (KHD) data should be used preferentially; when formation water total salinity (KHD) and formation water chloride ion content (CL-) data are lacking, formation water density (D) should be used. W Take 1.07 g / cm 3 At the work site, the total mineralization (KHD) and chloride ion content (CL) of formation water were lacking. - When analyzing data, the formation water density D is qualitatively determined to be freshwater.W Take 1.03 g / cm 3 If the formation water is qualitatively determined to be saturated saline, then the formation water density D W Take 1.25g / cm 3 .

[0018] Furthermore, in step 1), the formation clay content V sh When there is corresponding well logging data processing results, the formation clay content V sh Process the results using well logging data; if no corresponding well logging data is available, use the corresponding integrated well logging DC index data for processing. sh = (dcn - dc) / (dcn - dcs), where dcn is the DC index of the adjacent standard mudstone layer and dcs is the DC index of the adjacent typical sandstone layer. If no corresponding comprehensive logging DC index data is available, the corresponding logging ROP data is used for processing. V sh =(ROP n -ROP) / (ROP n -ROP s ROP stands for Point of Interest (ROP) drill-through time. n When drilling adjacent mudstone caprock, ROP s Drilling time for standard or typical sandstone formations.

[0019] Furthermore, in step 2), when the strata are sand or mudstone (collectively referred to as sand and mudstone), ε1 = 1.0, and when the strata are carbonate rocks, ε1 = 1.1.

[0020] Furthermore, in step 2), when the storage space type is a porous storage space, ε2 = 1; when the storage space type is a cracked (including microcracks) storage space, ε2 = 0.5; when the storage space type is a cavern or pore-type storage space, ε2 = 0.1; when the storage space type is a combined storage space, ε2 takes the minimum value of ε2 corresponding to different types of space.

[0021] Furthermore, in step 2), the formation pore fluid pressure coefficient (CFP) of the normal pressure formation is 0.9 to 1.1; the formation pore fluid pressure coefficient (CFP) of the abnormally high pressure formation is greater than 1.1; and the formation pore fluid pressure coefficient (CFP) of the abnormally low pressure formation is less than 0.9.

[0022] Furthermore, in step 3), formation leakage occurs when the difference between the drilling fluid column pressure and the formation leakage pressure PL exceeds the threshold value of 4 MPa, does not occur when it is less than the threshold value of 2 MPa, and whether well leakage occurs between 2 MPa and 4 MPa is constrained by drilling conditions.

[0023] Compared with the prior art, the present application has the advantages that the present application can fully reflect the essential characteristics of the formation by calculating the formation leakage pressure gradient, occupies less data information resources, has low method implementation cost, is simple and easy to implement, and is more easy to promote and apply on site; the formation leakage pressure of the well to be drilled can be predicted by using the present application and the logging data of the adjacent well, and the effect of the safe drilling fluid density window can be played in advance. BRIEF DESCRIPTION OF DRAWINGS

[0024] Figure 1 is a flowchart of the logging method of the present application;

[0025] Figure 2 is a graph of the relationship between the total salinity of formation water and the formation water density;

[0026] Figure 3 is a graph of the relationship between the chloride ion content of formation water and the formation water density. DETAILED DESCRIPTION

[0027] The specific embodiments of the present application will be further described in detail below, but the present application is not limited to these embodiments, and any improvement or substitution in the basic spirit of the present embodiments still belongs to the scope of protection claimed by the present application.

[0028] The flowchart of the logging method for quickly determining the formation leakage pressure is shown in Figure 1 .

[0029] 1) Obtain the formation lithology and reservoir space type of the interest point of the target interval, the formation vertical depth h, the formation pore fluid pressure gradient FPG, the formation water density D W , and the formation shale content V sh , wherein the dimensions of h, FPG, and D W are hm, MPa / hm, and g / cm 3 , respectively, and V sh is expressed as a decimal number;

[0030] The formation lithology and reservoir space type, the formation vertical depth h, and the logging reservoir description data information are selected;

[0031] The real-time acquisition and processing results data of the comprehensive logging formation pressure detection are taken, and the formation pore fluid pressure gradient FPG under normal pressure is between 1.03 MPa / hm and 1.25 MPa / hm, and is taken as 1.07 MPa / hm by default.

[0032] The data of the comprehensive logging formation pressure detection are taken, and when there are corresponding regional formation water total salinity KHD data, the formation water density D W is calculated by the formula D -7 = 6 x 10 W x KHD + 0.9992 (as shown in Table 1 and Figure 2(As shown); there is a corresponding regional formation water chloride ion content (CL). - Use formula D when processing data. W =1×10 -6 ×CL - +0.9997 Calculate formation water density D W (as shown in Table 2 and) Figure 3 (As shown); Formation water density D used for on-site integrated well logging and ground pressure detection. W The data is also based on the total mineralization degree (KHD) of formation water and the chloride ion content (CL) of the formation. - This is a recalculation based on the calculated data; it also includes formation water total salinity data (KHD) and formation water chloride ion content (CL). - When selecting data, KHD (Koil total salinity) data should be prioritized. In cases where KHD or chloride ion content (CL) data is unavailable... - When data is collected, the formation water density D W Take 1.07 g / cm 3 When data on total formation water salinity (KHD) and chloride ion content (CL-) are lacking at the work site, the formation water density (D) is used to qualitatively determine if the formation water is freshwater. W Take 1.03 g / cm 3 If the formation water is qualitatively determined to be saturated saline, then the formation water density D W Take 1.25g / cm 3 .

[0033] Table 1 Formation water salinity (KHD) and formation water density (D) W Correspondence relationship experimental data table

[0034]

[0035] Table 2. Formation water chloride ion content (CL-) and formation water density (D). W Correspondence relationship experimental data table

[0036]

[0037] Formation clay content V sh When there is corresponding well logging data processing results, the formation clay content V sh Process the results using well logging data; if no corresponding well logging data is available, use the corresponding integrated well logging DC index data for processing. sh = (dcn - dc) / (dcn - dcs), where dcn is the DC index (dimensionless) of the adjacent standard mudstone layer, and dcs is the DC index (dimensionless) of the adjacent typical sandstone layer. When no corresponding comprehensive logging DC index data is available, the corresponding logging ROP data is used for processing. V sh =(ROP n-ROP) / (ROP n -ROP s ), ROP is the point drilling time of interest (min / m), ROP n is the drilling time of adjacent mudstone cap rock (min / m), ROP s is the drilling time of standard or typical sandstone layer (min / m).

[0038] 2) Determine the formation lithology influence coefficient ε1 and the reservoir space type influence coefficient ε2 by formation lithology and reservoir space type, both of which are dimensionless quantities;

[0039] When the formation lithology is sand or mudstone formation (collectively referred to as sand-mudstone formation), ε1 = 1.0, and when the formation lithology is carbonate rock formation, ε1 = 1.1;

[0040] When the reservoir space type is pore type reservoir space, ε2 = 1, when the reservoir space type is fracture (including micro-fracture) type reservoir space, ε2 = 0.5, and when the reservoir space type is cave or pore type reservoir space, ε2 = 0.1; when the reservoir space type is a combination type reservoir space, ε2 takes the minimum value of the corresponding ε2 of different types of space (for example, the combination type reservoir space includes pore type reservoir space and fracture type reservoir space, and the minimum value of the two spaces ε2 is taken);

[0041] Calculate the formation pore fluid pressure coefficient CFP by the formula CFP = 10 × FPG × h / (D W × g × h), CFP is a dimensionless quantity; wherein, h is the formation vertical depth, FPG is the formation pore fluid pressure gradient, D W is the formation water density, and g is the regional formation gravity acceleration;

[0042] Here, g is 9.8 N / kg, for the convenience of rapid calculation on site, g ≈ 10 N / kg is taken, that is, 1 kg force = 9.8 N ≈ 10 N, 1 MPa = 10 kg / cm 2 = 100 N / cm 2 , the formula CFP = 10 × FPG × h / (D W × g × h) is simplified to CFP = FPG / D W , which is regarded as a dimension conversion coefficient of 1 unit, that is, 1 cm 3 / g;

[0043] The formation pore fluid pressure coefficient CFP of a normal pressure formation is 0.9-1.1 (generally CFP ≈ 1); the formation pore fluid pressure coefficient CFP of an abnormal high pressure formation is greater than 1.1, and the formation pore fluid pressure coefficient CFP of an abnormal low pressure formation is less than 0.9.

[0044] 3) Calculate the formation pore fluid pressure coefficient CFP by the formula CFP = 10 × FPG × h / (D shCalculate the formation leakage pressure coefficient CPL at the point of interest in the target layer; using the formula PL = 0.1 × CPL × D. W The formation leakage pressure PL at the point of interest in the target layer is calculated using the formula ×g×h, which simplifies to PL=CPL×D. W ×h, PL is in MPa; the formation leakage pressure gradient PLG of the target segment point of interest is calculated by the formula PLG=PL / h, and PLG is in MPa / hm.

[0045] 4) Based on the on-site drilling requirements, select the formation leakage pressure coefficient (CPL), formation leakage pressure (PL), or formation leakage pressure gradient (PLG) for the target formation point of interest. Drilling engineers can quickly and directly match the upper limit of drilling fluid density based on the formation leakage pressure gradient (PLG), overcoming the shortcomings of traditional methods. This method is simple and practical.

[0046] This invention has been applied in over 120 wells in the Laoxin area of ​​Jianghan Oilfield, the Baima and Jiangdong blocks of Fuling Shale Gas Field, and the Hongxing area of ​​western Hubei and eastern Chongqing. Based on this invention, drilling fluid is prepared before drilling according to the formation leakage pressure (PL) and formation leakage pressure gradient (PLG) predicted by adjacent wells, avoiding leakage zones, achieving an overall effectiveness rate of 96%. During field application, it was found that leakage does not occur when the difference between the drilling fluid column pressure and the formation leakage pressure is less than 2 MPa, but leakage occurs when the difference is greater than 4 MPa. Whether well leakage occurs between 2 MPa and 4 MPa pressure differences is constrained by various drilling conditions, such as tripping speed.

[0047] Practice has also shown that, since this invention does not consider the influence of faults encountered during drilling, there will be certain limitations if faults are found in the formation during drilling. In this case, the fault segment should be determined as a cave-type or pore-type reservoir space, which will result in uncertainty.

[0048] Example 1

[0049] TYA well section 3708-3712m

[0050] Well TYA is a vertical well, and the formation is sandstone and mudstone with ε1 = 1.0. The geological design specifies that the required formation water density D in this area is... W It is 1.05cm 3 / g, the formation water chloride ion content (CL-) is 51200 mg / L, and the known formation water density value is directly used for calculation; the comprehensive logging shows that the formation pore fluid pressure gradient (FPG) is 1.622 MPa / hm, and the formation pressure exhibits abnormally high characteristics; the mudstone content V obtained from the processed logging data is... sh =15%, expressed as a decimal, V sh= 0.15; resistivity imaging logging shows that there are two cracks on the well wall, the crack length is 1.5-2.2 m, the crack width is 0.04 mm, which belongs to a typical micro-fractured formation, ε2 = 0.5; according to the formula CPL = CFP + ε1 × ε2 × V sh The formation leakage pressure coefficient CPL = CFP + ε1 × ε2 × V of the target layer section of the well section 3708-3712 m of the Xujia section is calculated sh = FPG / D W + ε1 × ε2 × V sh = 1.622 / 1.05 + 1.0 × 0.5 × 0.15

[0051] = 1.62, the formation leakage pressure gradient PLG = CPL × D W = 1.62 × 1.05 ≈ 1.70 (MPa / hm); the formation leakage pressure PL at the vertical depth 3708 m (h = 37.08 hm) is PLG × h = 1.70 × 37.08 ≈ 63.04 MPa, and the formation leakage pressure PL at the vertical depth 3712 m (h = 37.12 hm) is PLG × h = 1.70 × 37.12 ≈ 63.10 MPa.

[0052] During drilling, the actually selected drilling fluid density is 1.83 cm 3 / g, and the drilling fluid column pressure range of the well section 3708-3712 m is 1.83 × 37.08 MPa-1.83 × 37.12 MPa, i.e. 67.86 MPa-67.93 MPa, the drilling fluid column pressure difference exceeds 4.5 MPa from the formation leakage pressure, which meets the condition that the drilling fluid column pressure difference is greater than 4 MPa from the formation leakage pressure, and the drilling fluid leakage of the formation in this section is 11.9 m 3 . The Xujia team of the well uses the new method for calculating the drilling formation leakage pressure based on logging data to calculate the formation leakage pressure gradient of the well section 3708-3712 m of the Xujia section, which is 1.82 MPa / hm, and uses the traditional model to calculate the formation leakage pressure gradient of the well section, which is 1.84 MPa / hm. Obviously, the calculation of the formation leakage pressure gradient by using the patent technology can more reflect the essential characteristics of the formation, and the method is simple and easy to operate.

[0053] Example 2

[0054] The well section 3520-3570 m of the Xujia section of the TPB-1 well

[0055] The well type of the TPB-1 well is a straight well, and the formation is a sandstone and mudstone formation, ε1 = 1; the water chloride ion content (CL - ) of the Xujia section of the well in the region given in the geological design is 51215 mg / L, and the chloride ion content is directly selected to calculate the formation water density value, D W = 1 × 10 -6×51215 - +0.9997=1.050915(cm 3 / g), retaining 2 decimal places, D W =1.05cm 3 / g; comprehensive logging shows that the formation presents normal pressure change, the formation pore fluid pressure gradient FPG value is equal to the formation water density D W value, the formation pressure is hydrostatic pressure, the formation pore fluid pressure gradient FPG = 1.05 MPa / hm; the mud content V sh obtained by processing logging data = 20%, expressed as V sh = 0.20; resistivity imaging logging shows that there is no fracture on the well wall, which belongs to a typical pore type formation, ε2 = 1.0; according to the formula CPL = CFP + ε1 × ε2 × V sh , the formation leakage pressure coefficient CPL = CFP + ε1 × ε2 × V of the 3708-3712m well section of the target layer section is calculated sh = FPG / D W + ε1 × ε2 × V sh = 1.05 / 1.05 + 1.0 × 1.0 × 0.20

[0056] = 1.20, the formation leakage pressure gradient PLG = CPL × D W = 1.20 × 1.05 = 1.26 (MPa / hm); the formation leakage pressure PL at the vertical depth of 3520m (h = 35.20hm) is PLG × h = 1.26 × 35.20 ≈ 44.35MPa, the formation leakage pressure PL at the vertical depth of 3570m (h = 35.7hm) is PLG × h = 1.26 × 35.70 ≈ 44.98MPa. During drilling, the actually selected drilling fluid density is 1.25cm 3 / g, the drilling fluid column pressure of the 3520-3570m well section is close to the formation leakage pressure, the difference between the drilling fluid column pressure and the formation leakage pressure tends to zero, which meets the condition that the difference between the drilling fluid column pressure and the formation leakage pressure is less than 2MPa, and the formation of this section does not occur drilling fluid leakage. Obviously, the formation leakage pressure gradient calculated by using the patent technology is simple and efficient, the method is simple and easy to operate, and it is more beneficial for on-site technical personnel to popularize and apply.

Claims

1. A logging method for rapidly determining formation leakage pressure, characterized in that: The logging method includes: 1) Obtain the stratigraphic lithology and reservoir space type, formation vertical depth h, formation pore fluid pressure gradient (FPG), and formation water density (D) of the target stratigraphic segment's point of interest. W and formation clay content V sh ; 2) Determine the influence coefficient ε1 of stratigraphy and the influence coefficient ε2 of reservoir space type by means of stratigraphy lithology and reservoir space type; The formula CFP = 10 × FPG × h / (D) W The formation pore fluid pressure coefficient (CFP) is calculated using the formula (×g×h), where CFP is a dimensionless quantity; and h is the formation vertical depth, FPG is the formation pore fluid pressure gradient, and D... W Let g be the density of the formation water, and g be the gravitational acceleration of the regional formation. 3) Using the formula CPL=CFP+ε1×ε2×V sh Calculate the formation leakage pressure coefficient CPL at the point of interest in the target layer; using the formula PL = 0.1 × CPL × D. W Calculate the formation leakage pressure PL at the point of interest in the target layer using ×g×h; calculate the formation leakage pressure gradient PLG at the point of interest in the target layer using the formula PLG=PL / h; It also includes selecting, based on the on-site drilling needs, the formation leakage pressure coefficient CPL, formation leakage pressure PL, or formation leakage pressure gradient PLG for the target interval point of interest; In step 1), the formation pore fluid pressure gradient (FPG) under normal pressure is between 1.03 MPa / hm and 1.25 MPa / hm; when corresponding regional formation water total salinity (KHD) data is available, formula D is used. W =6×10 -7 Calculate the formation water density D using ×KHD+0.9992. W There is a corresponding regional formation water chloride ion content (CL). - Use formula D when processing data. W =1×10 -6 × CL - Calculate formation water density D using +0.9997. W It also possesses formation water total mineralization data (KHD) and formation water chloride ion content (CL). - When selecting data, KHD (Korean mineralization degree) data should be prioritized; if KHD or chloride ion content data is unavailable, further data may be used. - When data is collected, the formation water density D W Take 1.07 g / cm 3 At the work site, the total mineralization (KHD) and chloride ion content (CL) of formation water were lacking. - When analyzing data, the formation water density D is qualitatively determined to be freshwater. W Take 1.03 g / cm 3 If the formation water is qualitatively determined to be saturated saline, then the formation water density D W Take 1.25 g / cm 3 ; In step 2), ε1 = 1 when the strata are sandstone or mudstone, and ε1 = 1.1 when the strata are carbonate rocks; ε2 = 1 when the reservoir type is a porous reservoir, ε2 = 0.5 when the reservoir type is a fractured reservoir, and ε2 = 0.1 when the reservoir type is a cavernous or porous reservoir; when the reservoir type is a combined reservoir, ε2 takes the minimum value of ε2 corresponding to different types of space.

2. The logging method for rapidly determining formation leakage pressure according to claim 1, characterized in that: In step 1), the formation clay content V sh When there is corresponding well logging data processing results, the formation clay content V sh Process the results using well logging data; if no corresponding well logging data is available, use the corresponding integrated well logging DC index data for processing. sh =(dcn-dc) / (dcn-dcs), where dcn is the DC index of the adjacent standard mudstone layer and dcs is the DC index of the adjacent typical sandstone layer. If no corresponding comprehensive logging DC index data is available, the corresponding logging ROP data is used for processing. V sh =(ROP n -ROP) / (ROP n -ROP s ROP stands for Point of Interest (ROP) drill-through time. n When drilling adjacent mudstone caprock, ROP s Drilling time for standard or typical sandstone formations.

3. The logging method for rapidly determining formation leakage pressure according to claim 1, characterized in that: In step 2), the formation pore fluid pressure coefficient (CFP) of the normal pressure formation is 0.9~1.1; the formation pore fluid pressure coefficient (CFP) of the abnormally high pressure formation is greater than 1.1; and the formation pore fluid pressure coefficient (CFP) of the abnormally low pressure formation is less than 0.

9.

4. The logging method for rapidly determining formation leakage pressure according to claim 1, characterized in that: In step 3), formation leakage occurs when the difference between the drilling fluid column pressure and the formation leakage pressure PL exceeds the threshold value of 4 MPa, does not occur when it is less than the threshold value of 2 MPa, and whether well leakage occurs between 2 MPa and 4 MPa is constrained by drilling conditions.

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