Method for mud / shale formation collapse pressure prediction from well logs

Abstract

This invention discloses a logging method for rapidly predicting collapse pressure in mudstone / shale formations, obtaining the formation depth h, formation pore fluid pressure gradient (FPG), formation lithology density (DEN), and formation clay content (V) of the target formation. sh The drilling fluid system used – the system influence coefficient ε and the clay influence coefficient ξ are determined based on the drilling fluid system – using the formula PCG=(0.1×DEN×g+FPG+ξ×V) sh The formation collapse pressure gradient PCG is calculated using the formula P(ε) / 2-1, where ε is the system influence coefficient of the drilling fluid system. c =0.01×PCG×h to calculate the formation collapse pressure P c It effectively overcomes the complex experimental process required by traditional methods to determine parameters such as the internal friction angle, cohesion, and Biot coefficient of the rock; it also overcomes the drawbacks of relying on personal experience for calculation, which involves many subjective factors, and avoids random interference that is difficult to quantify, program, and maintain stability.

Description

TECHNICAL FIELD

[0001] The present application relates to the field of safety of oil and gas drilling engineering and logging engineering technology, and particularly relates to a logging method for quickly predicting collapse pressure of mud / shale formation. BACKGROUND

[0002] Accurate prediction of formation collapse pressure can purposefully, directionally and preparedly prevent wellbore collapse instability, drill pipe burying, drill pipe sticking, logging resistance and sticking and other problems, prevent downhole accidents, and is conducive to realizing oil engineering speed, quality and efficiency, and creating green oil and gas development engineering.

[0003] For a long time, drilling site engineering technicians have prevented wellbore collapse and blockage by means of practical experience and by continuously adjusting drilling fluid density and related performance, although the effect is good, but it needs to continuously improve experience through trial and error, which is high in cost and low in efficiency, and seeking an experiential mathematical model has been the long-term pursuit of many site engineering technicians.

[0004] In the theoretical research of predicting formation collapse pressure, predecessors have proposed many innovative prediction methods and mathematical models and empirical formulas based on mud shale water sensitivity, ground stress, bedding and fracture, strength criterion and the like, such as the invention patent CN106351650A (201510420240.1, a wellbore collapse pressure calculation method suitable for bedded and fractured formation), CN108071389B (201711306426.X, a shale gas well borehole collapse pressure prediction method), and a formation collapse pressure calculation method based on Mohr circle envelope (Jiang Wei, 2019, Southwest Petroleum University). Due to the complexity of the theory, too many basic parameters need to be determined through experimental tests, and it is difficult to apply and play its due engineering guidance value on site. SUMMARY

[0005] The present application provides a logging method for quickly predicting collapse pressure of mud / shale formation to overcome the shortcomings of the prior art and provide reliable formation collapse pressure data for safe drilling in time.

[0006] To achieve the above purpose, the present application provides a logging method for quickly predicting collapse pressure of mud / shale formation, which comprises:

[0007] 1) obtaining formation vertical depth h, formation pore fluid pressure gradient FPG, formation lithology density DEN, formation argillaceous content V sh and the drilling fluid system used in the target interval;

[0008] 2) determining system influence coefficient ε and argillaceous influence coefficient ξ according to the drilling fluid system;

[0009] 3) calculating formation collapse pressure gradient PCG by formula PCG = (0.1 x DEN x g + FPG + ξ x V + ε) / 2 - 1, g is regional formation gravity acceleration, ε is system influence coefficient of drilling fluid system; calculating formation collapse pressure P by formula P = 0.01 x PCG x h c .

[0010] Further, it further comprises selecting to provide formation collapse pressure gradient PCG or formation collapse pressure Pc according to field drilling requirements.

[0011] Further, in the step 1), formation pore fluid pressure gradient FPG under normal pressure is between 1.03 MPa / hm and 1.25 MPa / hm; FPG of abnormal high pressure formation is greater than 1.25 MPa / hm, FPG of low pressure formation is greater than or equal to 0.9 and less than 1.03 MPa / hm, and FPG of abnormal low pressure formation is less than 0.9 MPa / hm.

[0012] Further, in the step 1), formation shale content V sh , when there is corresponding logging data processing result data, formation shale content V sh is processed by using logging data processing result data; when there is no corresponding logging data processing result data, V sh is processed by using corresponding comprehensive logging dc index data, V sh = (dcn - dc) / (dcn - dcs), dcn is dc index of adjacent standard shale layer, dcs is dc index of adjacent typical sandstone layer, when there is no corresponding comprehensive logging dc index data, V n is processed by using corresponding logging drilling time ROP data, V n = (ROP s - ROP) / (ROP n - ROP s ), ROP is drilling time of interest point, ROP sh is drilling time of adjacent shale caprock, and ROP 3 is drilling time of standard or typical sandstone layer.

[0013] Further, in the step 2), the drilling fluid system comprises water-based drilling fluid system, oil-based drilling fluid system and air drilling fluid system; the influence coefficient ε of the drilling fluid system is in the range of -2.0 MPa / hm to 0.5 MPa / hm.

[0014] Further, the ε of the water-based drilling fluid system is 0 MPa / hm, the ε of the air drilling fluid system is -1.0 MPa / hm, and the ε of the oil-based drilling fluid system is -0.5 MPa / hm.

[0015] Further, in the step 2), the argillaceous influence coefficient ξ is in the range of 0.5-1.5 MPa / hm.

[0016] Compared with the prior art, the present application has the following advantages:

[0017] 1) The complex test process of determining the rock internal friction angle, cohesion, Biot coefficient parameters and the like in the traditional method is effectively overcome;

[0018] 2) The problem of high coring cost is avoided;

[0019] 3) The drawbacks of many subjective factors caused by relying on personal experience are overcome, and the random interference which is not easy to quantify, program and continuously stable is avoided;

[0020] 4) Based on the consideration of the three influencing factors of formation pressure, formation argillaceous content and drilling fluid system type of the target interval, compared with the prior art methods such as CN106351650A (201510420240.1, a wellbore collapse pressure calculation method suitable for stratified fractured formation), CN108071389B (201711306426.X, a shale gas well borehole collapse pressure prediction method), and the formation collapse pressure calculation method based on Mohr circle envelope (Jiang Wei, 2019, Southwest Petroleum University), the present application increases the key internal formation argillaceous content and external factor drilling fluid system type which affect the prediction accuracy of formation collapse pressure, so that the technical solution has stronger applicability; 5) The calculation parameters used in the technical solution disclosed in the present application are easy to obtain in the logging and drilling site, the data resource occupation is less, the implementation cost is low, and the technical solution is simple, practical, easy to use and easy to popularize and apply in the drilling, logging and logging site. BRIEF DESCRIPTION OF DRAWINGS

[0021] Figure 1 It is a logging method flowchart of the present application. DETAILED DESCRIPTION

[0022] 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 replacement within the basic spirit of the embodiments still belongs to the scope of protection claimed by the present application.

[0023] The logging method flowchart for quickly predicting the collapse pressure of argillaceous / shale formation is shown in Figure 1 .

[0024] 1) Obtain the formation vertical depth h, formation pore fluid pressure gradient FPG, formation lithology density DEN, formation argillaceous content V and the used drilling fluid system of the target interval, wherein the dimensions of h, FPG and DEN are m, MPa / hm and g / cm sh , respectively. 3 sh ​Expressed in decimal form;

[0025] The formation pore fluid pressure gradient FPG under normal pressure is between 1.03 MPa / hm and 1.25 MPa / hm, and by default is 1.07 MPa / hm; the FPG of an abnormal high pressure formation is greater than 1.25 MPa / hm, the FPG of a low pressure formation is greater than or equal to 0.9 and less than 1.03 MPa / hm, and the FPG of an abnormal low pressure formation is less than 0.9 MPa / hm.

[0026] Formation shale content V sh When there is corresponding logging data processing result data, the formation shale content V sh When there is corresponding logging data processing result data, the formation shale content V sh = (dcn-dc) / (dcn-dcs), dcn is the dc index (dimensionless) of the adjacent standard shale layer, dcs is the dc index (dimensionless) of the adjacent typical sandstone layer, and when there is no corresponding comprehensive logging dc index data, the formation shale content V sh = (ROP n -ROP) / (ROP n -ROP s ), ROP is the drilling time (min / m) of the point of interest, ROP n is the drilling time (min / m) of the adjacent shale cap rock, and ROP s is the drilling time (min / m) of the standard or typical sandstone layer.

[0027] 2) Determine the system influence coefficient ε and the shale influence coefficient ξ according to the drilling fluid system;

[0028] The drilling fluid system includes a water-based drilling fluid system, an oil-based drilling fluid system, and an air drilling fluid system; the system influence coefficient ε of the drilling fluid system has a value range of -2.0 MPa / hm to 0.5 MPa / hm; the ε value of the water-based drilling fluid system is 0 MPa / hm, the ε value of the air drilling fluid system is -1.0 MPa / hm, and the ε value of the oil-based drilling fluid system is -0.5 MPa / hm;

[0029] The shale influence coefficient ξ has a value range of 0.5 MPa / hm to 1.5 MPa / hm, and by default the value of ξ is 1.0 MPa / hm.

[0030] 3) Calculate the formation collapse pressure gradient PCG by the formula PCG = (0.1×DEN×g+FPG+ξ×V sh +ε) / 2-1, g is the regional formation gravitational acceleration, and ε is the influence coefficient of the drilling fluid system (PCG has the dimension of MPa / hm); calculate the formation fracture pressure gradient P c= 0.01 x PCG x h c (P c = 0.01 x PCG x h

[0031] 4) According to the on-site drilling requirements, the formation collapse pressure gradient PCG or the formation collapse pressure Pc is selected; if necessary, the collapse pressure profile is provided; the collapse pressure profile includes the formation vertical depth h, the formation lithology, the formation lithology density DEN, the formation shale content Vsh, the formation collapse pressure Pc, and the formation collapse pressure gradient PCG, and the data points are spaced at 1 m. sh

[0032] The above is the point-by-point rapid prediction of the formation collapse pressure Pc and the formation collapse pressure gradient PCG, and when the lithology is segmented for prediction, the minimum value of the formation collapse pressure gradient PCG of each point in the segment is taken, and the purpose is to ensure the safety of drilling and to minimize the quality and safety cost of drilling.

[0033] The present application rapidly predicts the formation collapse pressure Pc and the formation collapse pressure gradient PCG by the formation vertical depth h and the formation pressure gradient FPG, the formation lithology density DEN, and the formation shale content Vsh data information of the target layer, effectively overcomes the problems of the traditional method such as the Mohr Coulomb failure criterion method, which needs to determine the rock internal friction angle, cohesion, Biot coefficient parameters and other complex tests, and the high cost of coring, overcomes the disadvantages of being difficult to quantify, programmatic and subjective factors relying on personal experience, and the method is simple and practical, realizes low cost, and is easy to promote and apply on site.

[0034] The present application has been applied to more than 160 wells in Jianghan Oilfield, Fuling Shale Gas Field, and Hongxing Block in E'xi Area, and according to the present application, the drilling fluid is configured by using the formation collapse pressure Pc and the formation collapse pressure gradient PCG predicted by the adjacent well before drilling, which can to some extent avoid the downhole complex situation caused by the instability of the well wall, and the total effective rate is more than 85%. Practice has also proved that since the core of the present application is a formation collapse pressure logging prediction method based on the full consideration of the formation pressure, the formation shale content and the drilling fluid system type, the mud / shale water sensitivity, the bedding seam development and the suction interference factors when the drilling tools are lifted are not considered, and there is a certain limitation in use.

[0035] Example 1

[0036] Well HY-1 in Hongxing Block, Jiaozhou Formation, 3500-3600 m well section

[0037] ​HY-1 well is a vertical well, which is the first shale gas exploration well in Hongxing block of E'xi area. The lithology of the well section of 3500-3600m in Maokou formation is shale. The top of the shale section is 3500m, the bottom is 3600m, and the middle is 3550m. The section is a good shale gas display layer in the region. The wellbore has the characteristics of easy collapse, collapse and caving. These wellbore instability characteristics are collectively referred to as collapse in the field. The formation pressure detection shows that the formation pressure changes normally, the formation pore fluid pressure gradient FPG=1.07MPa / hm, and the cuttings samples obtained during logging have obvious falling pieces. The logging curve shows that the formation lithology density DEN=2.55g / cm 3 , the hole diameter curve expands obviously, the hole diameter expands 2cm-5cm, the formation shale content V sh =60%, expressed as V sh =0.6; the field drilling uses water-based drilling fluid, the drilling fluid density Dw=1.10g / cm 3 , the system influence coefficient of the drilling fluid system ε=0MPa / hm, and the shale influence coefficient ξ=1.0MPa / hm. The formation collapse pressure gradient PCG=(0.1×DEN×g+FPG+ξ×V sh +ε) / 2-1=(0.1×2.55×10+1.07+1.0×0.6+0) / 2-1=1.11(MPa / hm).

[0038] The formation collapse pressure P C =0.01×1.11×3500=38.85(MPa) at 3500m, the formation collapse pressure P C =0.01×1.11×3600=39.96(MPa) at 3600m, and the formation collapse pressure P C =0.01×1.11×3550=39.405(MPa) at the middle 3550m.

[0039] The drilling fluid column pressure P C =0.01×1.10×3500=38.50(MPa) at 3500m, the drilling fluid column pressure P C =0.01×1.10×3600=39.60(MPa) at 3600m, and the drilling fluid column pressure P C =0.01×1.10×3550=39.05(MPa) at the middle 3550m.

[0040] The difference between the drilling fluid column pressure and the formation collapse pressure in the 3500-3600m well section of the Maokou Formation is -0.35-0.36MPa, which is in a "negative collapse pressure" state. The drilling fluid density is less than the formation collapse pressure gradient, which causes the borehole wall to be unstable during drilling, and there are phenomena of borehole wall collapse, collapse and collapse. The hole diameter logging curve also confirms the objective existence of this phenomenon. Subsequently, the drilling fluid density was adjusted from 1.10g / cm 3 to 1.25g / cm 3 . The falling pieces in the cuttings samples during the logging process gradually decreased until they disappeared.

[0041] This example proves that the shale formation collapse pressure gradient PCG of the 3500-3600m well section of the Maokou Formation is 1.11MPa / hm. The water-based drilling fluid density Dw for subsequent development of the shale gas layer in this section should not be less than 1.11g / cm 3 and not higher than 1.25g / cm 3 .

[0042] Based on the prediction of the shale formation collapse pressure in the 3500-3600m well section of the Maokou Formation in the HY-1 well of the Hongxing block, through the exploration test of the optimal water-based drilling fluid density window for preventing shale collapse in the Maokou Formation and Wujiaping Formation in 12 wells such as HY-2 and HY-3 in the block, the optimal recommended value of the water-based drilling fluid density in the block is determined to be 1.25g / cm 3 , and the minimum is not less than 1.20g / cm 3 .

Claims

1. A logging method for rapidly predicting collapse pressure in mudstone / shale formations, characterized in that: The logging method includes: 1) Obtain the formation vertical depth h, formation pore fluid pressure gradient (FPG), formation lithology density (DEN), and formation clay content (V) of the target formation. sh and the drilling fluid system used; 2) Determine the system influence coefficient ε and the clay influence coefficient ξ based on the drilling fluid system; 3) Using the formula PCG = (0.1 × DEN × g + FPG + ξ × V) sh The formation collapse pressure gradient PCG is calculated using (+ε) / 2-1, where g is the regional formation gravitational acceleration, and ε is the system influence coefficient of the drilling fluid system; P is calculated using the formula P c = 0.01×PCG×h Calculate the formation collapse pressure P c ; It also includes the option to provide either formation collapse pressure gradient (PCG) or formation collapse pressure (Pc) based on the on-site drilling requirements. In step 1), the formation pore fluid pressure gradient (FPG) under normal pressure is between 1.03 MPa / hm and 1.25 MPa / hm; the FPG of abnormally high-pressure formations is greater than 1.25 MPa / hm; the FPG of low-pressure formations is greater than or equal to 0.9 and less than 1.03 MPa / hm; the FPG of abnormally low-pressure formations is less than 0.9 MPa / hm; and 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 When drilling standard or typical sandstone formations; In step 2), the drilling fluid system includes a water-based drilling fluid system, an oil-based drilling fluid system, and an air drilling fluid system; the influence coefficient ε of the drilling fluid system ranges from -2.0 MPa / hm to 0.5 MPa / hm; the ε value of the water-based drilling fluid system is 0 MPa / hm, the ε value of the air drilling fluid system is -1.0 MPa / hm, and the ε value of the oil-based drilling fluid system is -0.5 MPa / hm; the influence coefficient ξ of the clay content ranges from 0.5 MPa / hm to 1.5 MPa / hm.

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