CN111257932B - Method for updating stratum seismic velocity - Google Patents

Method for updating stratum seismic velocity Download PDF

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CN111257932B
CN111257932B CN201910846320.1A CN201910846320A CN111257932B CN 111257932 B CN111257932 B CN 111257932B CN 201910846320 A CN201910846320 A CN 201910846320A CN 111257932 B CN111257932 B CN 111257932B
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seismic velocity
seismic
horizon
velocity
area
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CN111257932A (en
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路保平
袁多
吴超
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China Petroleum and Chemical Corp
Sinopec Research Institute of Petroleum Engineering
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China Petroleum and Chemical Corp
Sinopec Research Institute of Petroleum Engineering
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    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
    • G01V1/00—Seismology; Seismic or acoustic prospecting or detecting
    • G01V1/28—Processing seismic data, e.g. analysis, for interpretation, for correction
    • G01V1/30—Analysis
    • G01V1/303—Analysis for determining velocity profiles or travel times
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
    • G01V2210/00—Details of seismic processing or analysis
    • G01V2210/50—Corrections or adjustments related to wave propagation
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
    • G01V2210/00—Details of seismic processing or analysis
    • G01V2210/60—Analysis
    • G01V2210/62—Physical property of subsurface
    • G01V2210/622—Velocity, density or impedance
    • G01V2210/6222—Velocity; travel time

Abstract

A method of updating the seismic velocities of a formation, comprising: updating the seismic velocity of the drilled area according to the seismic time horizon interpretation result data and the real depth of each horizon to obtain an initial seismic velocity model of the drilled area; carrying out prestack depth migration by using an initial seismic velocity model of a target area to obtain a common imaging point gather of the target area; based on the common imaging point gather, selecting reflection points with different depths on a channel corresponding to a well track of the non-drilling area, respectively obtaining imaging depths corresponding to different reflection angles and ray lengths of corresponding reflection rays in all layers for each reflection point, and updating the initial seismic velocity of the stratum of the corresponding non-drilling area to obtain the updated seismic velocity of the non-drilling area. The method can greatly reduce the number of parameters of the traditional seismic tomography, thereby improving the speed modeling efficiency and laying a foundation for correcting the geomechanical model of the stratum to be drilled in real time.

Description

Method for updating stratum seismic velocity
Cross reference to related art
The present application claims the title filed 2018, 11, 30: priority of chinese patent application CN 201811453329.8, "a method of updating the seismic velocities of earth formations", is incorporated herein by reference in its entirety.
Technical Field
The invention relates to the technical field of oil and gas exploration and development, in particular to a geophysical drilling guidance method, and specifically relates to a method for updating stratum seismic velocity.
Background
The oil and gas drilling faces increasingly complex geological environments, geological and mechanical characteristics of a target area are accurately described, and the drilling risk can be greatly reduced by reasonably establishing a model of the underground before drilling. At present, the method for establishing the underground model before drilling is mainly carried out by comprehensively using the geophysical and rock mechanics method on the basis of conventional seismic imaging.
The establishment of a velocity model in the seismic imaging process often has a multi-solution problem, which causes great errors in predicted horizons, structures, lithology and mechanical characteristics in certain work areas, and can cause adverse effects on the scientificity and accuracy of drilling design.
Correcting the geomechanical model while drilling requires quickly updating the seismic velocity field information of the formation during the actual drilling process. The traditional tomography technology gridds the whole stratum, the number of inversion parameters is increased by the mode, the efficiency is low, and the method is not suitable for the environment while drilling. The articles and patents disclosed so far are silent about the seismic velocity modeling method applicable to this environment.
Disclosure of Invention
In order to solve the above problems, the present invention provides a method for updating seismic velocities of an earth formation to be drilled, the method comprising:
acquiring seismic time horizon interpretation result data of horizons in a drilled area in a target area, wherein the horizons cannot directly acquire original one-dimensional acoustic logging data;
determining an initial seismic velocity model of a drilled area according to the seismic time horizon interpretation result data and the real depth of each horizon, constructing the initial seismic velocity model of the target area according to the initial seismic velocity model of the drilled area, and performing prestack depth migration by using the initial seismic velocity model of the target area to obtain a common imaging point gather of the target area;
thirdly, based on the common imaging point gather, selecting reflection points with different depths on a track corresponding to a well track of an undrilled area, and respectively obtaining imaging depths corresponding to different reflection angles and ray lengths of corresponding reflection rays in all layers for all the reflection points;
and fourthly, updating the initial seismic velocity of the stratum of the non-drilled area corresponding to each reflection point according to the imaging depth and the ray length of the corresponding reflection ray in each layer, and obtaining the updated seismic velocity of the non-drilled area.
According to an embodiment of the present invention, in the second step, the true depth of each horizon in the target region is determined according to the obtained real drilling and logging data.
According to one embodiment of the present invention, in the second step,
determining the estimated seismic velocity of the horizon to be updated in the drilled area according to the seismic time horizon interpretation result data and the real depth of each horizon;
updating the estimated seismic velocity of the horizon to be updated according to the real depth of each horizon in the target area to obtain the one-dimensional seismic velocity of the first horizon;
filtering the acquired original one-dimensional acoustic logging data of a second layer of the target area to obtain the one-dimensional seismic velocity of the second layer;
splicing the updated seismic velocity of the first layer and the one-dimensional seismic velocity of the second layer;
and obtaining a three-dimensional interpolation seismic velocity field of the drilled area according to the spliced one-dimensional seismic velocity, and fusing the three-dimensional interpolation seismic velocity field and the original basic seismic velocity field to obtain an initial seismic velocity model of the drilled area of the target area.
According to an embodiment of the invention, in the second step, the estimated seismic velocity is updated according to the following expression:
Figure BDA0002195365130000021
wherein z isiAnd zi-1Respectively representing the true depth of the ith horizon and the (i-1) th horizon in the target region, zjAnd zj-1Respectively representing the true depth of the jth horizon and the jth-1 horizon in the target region, thetaiAnd thetajRespectively representing the inclination angles of the ith and jth horizons in the target area,
Figure BDA0002195365130000031
representing the updated seismic velocity of the ith horizon, cjAnd
Figure BDA0002195365130000032
respectively representing the preset correction coefficient and the estimated seismic velocity of the jth horizon,
Figure BDA0002195365130000033
and reflecting seismic wave travel time by the horizon representing the jth horizon.
According to one embodiment of the invention, the step of determining the three-dimensional interpolated seismic velocity field comprises:
expanding the updated one-dimensional seismic velocity to a three-dimensional space to obtain a three-dimensional velocity interpolation result;
and acquiring the geological structure characteristics of the target area, and performing structural constraint on the three-dimensional velocity interpolation result according to the geological structure characteristics to obtain the three-dimensional interpolation seismic velocity field.
According to one embodiment of the invention, in said step four,
determining an updating coefficient in a seismic velocity updating model according to the imaging depth and the ray length of the corresponding reflection ray in each horizon;
and updating the initial seismic velocity of the stratum of the non-drilling area corresponding to each reflection point by using the seismic updating model according to the updating coefficient to obtain the updated seismic velocity of the non-drilling area.
According to an embodiment of the present invention, in the fourth step, the update coefficients are determined by the following steps:
determining the seismic velocity deformation corresponding to each reflection point according to the imaging depth and the ray length of the corresponding reflection ray in each horizon;
and determining an updating coefficient in a seismic velocity updating model according to the seismic velocity deformation.
According to an embodiment of the present invention, in the fourth step, the seismic velocity deformation corresponding to each reflection point is determined according to the following expression:
Figure BDA0002195365130000034
wherein the content of the first and second substances,
Figure BDA0002195365130000035
representing the initial seismic velocity, theta, of the formation corresponding to the ith reflection point1,iAnd theta2,iTwo different reflection angles, l, respectively representing the ith reflection point1,iAnd l2,iRespectively represent the reflection angle theta1,iAnd theta2,iThe ray length of the corresponding reflected ray in the formation corresponding to the ith reflection point,
Figure BDA0002195365130000036
and
Figure BDA0002195365130000037
respectively represent the reflection angle theta1,iAnd theta2,iCorresponding imaging depth, Δ miRepresenting the deformation of the seismic velocity corresponding to the ith reflection point,
Figure BDA0002195365130000038
and indicating the stratum inclination angle corresponding to the ith reflection point.
According to one embodiment of the invention, update coefficients in the seismic velocity update model are determined according to the following expression:
Figure BDA0002195365130000039
wherein the content of the first and second substances,
Figure BDA0002195365130000041
representing the updated seismic velocity of the formation corresponding to the ith reflection point, c0,iAnd c1,iAnd indicating the updating coefficient corresponding to the ith reflection point.
According to one embodiment of the invention, the coefficient c is updated0,iIs 1.
According to an embodiment of the invention, in the fifth step, the initial seismic velocity of the stratum of the non-drilled area corresponding to each reflection point is updated according to the following expression:
Figure BDA0002195365130000042
wherein the content of the first and second substances,
Figure BDA0002195365130000043
representing the updated seismic velocity of the formation corresponding to the ith reflection point, c0,iAnd c1,iRepresents the updating coefficient corresponding to the ith reflection point,
Figure BDA0002195365130000044
and representing the initial seismic velocity of the stratum corresponding to the ith reflection point.
The method for updating the seismic velocity of the stratum to be drilled can greatly reduce the quantity of parameters of the traditional seismic tomography, thereby improving the velocity modeling efficiency (in actual use, computer software can rapidly complete the updating and re-modeling of the seismic velocity of the stratum to be drilled within 24 hours), and laying a foundation for correcting the geomechanical model of the stratum to be drilled in real time.
Additional features and advantages of the invention will be set forth in the description which follows, and in part will be obvious from the description, or may be learned by practice of the invention. The objectives and other advantages of the invention will be realized and attained by the structure particularly pointed out in the written description and claims hereof as well as the appended drawings.
Drawings
In order to more clearly illustrate the embodiments of the present invention or the technical solutions in the prior art, the following briefly introduces the drawings required in the description of the embodiments or the prior art:
FIG. 1 is a schematic flow diagram of an implementation of a method for updating the seismic velocities of a formation according to one embodiment of the invention;
FIG. 2 is a schematic diagram of the structure of a target area according to one embodiment of the present invention;
FIG. 3 is a schematic diagram of seismic time horizon interpretation results according to one embodiment of the invention;
FIG. 4 is a schematic illustration of a true depth of a horizon drilled through a formation according to one embodiment of the invention;
FIG. 5 is a schematic flow diagram of an implementation of a model for determining initial seismic velocities of a drilled area according to one embodiment of the invention;
FIG. 6 is a schematic diagram of a one-dimensional seismic velocity model according to one embodiment of the invention;
FIG. 7 is a schematic diagram of a three-dimensional interpolated seismic velocity field of a target area according to one embodiment of the invention;
FIG. 8 is a schematic illustration of a seismic velocity field being fused according to one embodiment of the invention
FIG. 9 is a schematic of initial pre-stack depth migration imaging depth in accordance with one embodiment of the present invention;
FIG. 10 is a schematic diagram of a common imaging point gather, in accordance with one embodiment of the present invention;
FIG. 11 is a schematic illustration of reflected rays according to one embodiment of the present invention;
FIG. 12 is a flow chart illustrating an implementation of determining update coefficients according to one embodiment of the present invention;
FIG. 13 is a schematic flow diagram of an implementation of a geophysical guided drilling method according to one embodiment of the invention;
FIG. 14 is a schematic illustration of modifying a key pre-bit horizon, according to an embodiment of the invention;
FIG. 15 is a schematic representation of a modified formation pore pressure model ahead of the bit in accordance with an embodiment of the invention;
FIG. 16 is a schematic representation of a modified formation fracture pressure ahead of bit model in accordance with an embodiment of the present invention.
Detailed Description
The following detailed description of the embodiments of the present invention will be provided with reference to the drawings and examples, so that how to apply the technical means to solve the technical problems and achieve the technical effects can be fully understood and implemented. It should be noted that, as long as there is no conflict, the embodiments and the features of the embodiments of the present invention may be combined with each other, and the technical solutions formed are within the scope of the present invention.
In the following description, for purposes of explanation, numerous specific details are set forth in order to provide a thorough understanding of the embodiments of the invention. It will be apparent, however, to one skilled in the art that the present invention may be practiced without some of these specific details or with other methods described herein.
Additionally, the steps illustrated in the flow charts of the figures may be performed in a computer system such as a set of computer-executable instructions and, although a logical order is illustrated in the flow charts, in some cases, the steps illustrated or described may be performed in an order different than here.
The multi-solution problem often exists in the velocity model establishment in the seismic imaging process, which causes great errors in predicted horizon, structure, lithology and mechanical characteristics in certain work areas, and further causes adverse effects on the scientificity and accuracy of drilling design. An effective solution is to reprocess the seismic velocity information provided by the drilled area as a constraint to improve the accuracy of a large-scale geomechanical model ahead of the drill bit, a technique known as seismic guided drilling.
An important link in the technique is to obtain the three-dimensional seismic velocity of the drilled area. At present, expensive VSP while drilling and other systems are generally adopted to obtain the information, but limited by production cost, VSP while drilling instruments are rarely applied in China, most wells only have geological horizons and acoustic logging data which are obtained by basic logging data cards, and the logging data cannot cover all drilled areas. How to acquire the three-dimensional information seismic velocity of the drilled area in this situation is critical.
Aiming at the problems in the prior art, the stratum seismic velocity updating method provided by the invention updates the seismic velocity of the drilled area by using the conventional wellbore data obtained in the drilling process so as to obtain more accurate seismic velocity of the drilled area.
As shown in fig. 1, in the method for updating the seismic velocity of the peri-well stratum in the drilled area according to the embodiment, in step S101, the result data is interpreted according to the acquired seismic time horizon of the first type of horizon in the target area. In this embodiment, the seismic time horizon interpretation result data acquired in step S101 by the method preferably includes horizon reflection seismic wave travel time. In this embodiment, the target area is a drilled area, which is preferably divided into a first layer and a second layer, where the first layer represents a layer where the original one-dimensional acoustic logging data cannot be directly obtained, and the second layer represents a layer where the original one-dimensional acoustic logging data can be directly obtained.
FIG. 2 illustrates data for a typical drilled interval, where region 1 represents a interval lacking sonic logging data (e.g., horizon-reflected seismic travel time) (i.e., a first type of horizon), region 2 represents a interval measured and having sonic logging data (i.e., a second type of horizon), region 3 represents a segment to be drilled, and region 1 and region 2 together are referred to as a drilled region, and region 3 is referred to as an undrilled region.
Seismic time horizon interpretation result data can characterize the horizon partitioning of each horizon in the target region. Assuming that there are n seismic interpretation horizons within the target depth region, these horizons are labeled 1, 2, … …, n layer by layer from top to bottom. As shown in FIG. 3, the seismic time horizon interpretation results T of the individual horizons1、T2、…、TnThe real travel time of seismic wave reflected by the horizon of the corresponding horizon is reflected.
In step S102, the method determines the true depth of each horizon in the target region according to the obtained real drilling data. According to the obtained real-time logging data in the real drilling process, the method can determine the real depth of the drilled stratum layer in real time, and therefore the real depth of each layer in the target area can be obtained.
Specifically, as shown in fig. 4, in this embodiment, the real-time logging data may determine a true depth of a horizon drilled through a formation, and the true depths of the horizons in the target region may be obtained by performing one-to-one matching between the true depths of the horizons and the determined horizons in the target region.
As shown in fig. 1 again, in this embodiment, after obtaining the stratum time horizon interpretation result data of the first-type horizon and the real depth of each horizon, the method updates the seismic velocity of the drilled area according to the seismic time horizon interpretation result data and the real depth of each horizon in step S103, so as to obtain an initial seismic velocity model of the drilled area;
specifically, in this embodiment, as shown in fig. 5, the method first determines the estimated seismic velocity of the horizon to be updated according to the seismic time horizon interpretation result data and the real depth of each horizon in step S501. And then, in step S502, updating the estimated seismic velocity of the horizon to be updated in the drilled area according to the real depth of each horizon in the target area to obtain an initial seismic velocity model of the drilled area.
In this embodiment, the method may preferably determine the estimated seismic velocity by calculating a ratio of the true depth of the first-type horizon to seismic time horizon interpretation result data in step S501.
There are n seismic-interpretation horizons, i.e. there are n horizons to be updated, within the assumed shallow region, i.e. the first-type horizon region. These horizons are labeled 1, 2, …, n from top to bottom, respectively, and update the one-dimensional seismic velocities layer by layer from top to bottom. In this embodiment, the principle of updating the seismic velocity is preferably as follows: assuming that a constant multiple error exists in the speed in one layer, and expressing the error by using a correction coefficient; the horizon time position of the seismic interpretation is equal to the reflection travel time of the real horizon.
Specifically, in this embodiment, the method preferably updates the estimated seismic velocities of the horizons to be updated in the drilled area according to the following expression, for example, for the jth horizon in the target area, there is:
Figure BDA0002195365130000071
wherein z isiAnd zi-1Respectively representing the true depth of the ith horizon and the (i-1) th horizon in the target region, zjAnd zj-1Respectively representing the true depth of the jth horizon and the jth-1 horizon in the target region, thetaiAnd thetajRespectively representing the inclination angles of the ith and jth horizons in the target area,
Figure BDA0002195365130000072
representing the updated seismic velocity of the ith horizon, cjAnd
Figure BDA0002195365130000073
respectively representing the preset correction coefficient and the estimated seismic velocity of the jth horizon,
Figure BDA0002195365130000074
and reflecting seismic wave travel time by the horizon representing the jth horizon.
Wherein, the preset correction coefficient of each horizon may preferably take a value of 1. It should be noted that, in this embodiment, the true depth z of the first-layer horizon0Is preferably zero.
Of course, in other embodiments of the present invention, the pre-set correction factors for each horizon in the drilled area and/or the true depth z of the first horizon may be determined as desired0The method can also be configured into other reasonable values, and the method does not preset correction coefficients of all the layers and the real depth z of the first layer0The specific value of (a) is defined.
Therefore, for the horizon at which the seismic velocity cannot be directly obtained, the method can obtain more accurate seismic velocity according to logging data and seismic time horizon interpretation results which are easily obtained in the actual drilling process.
In this embodiment, the method preferably obtains the complete one-dimensional seismic velocity of the target area (i.e., the drilled section) by obtaining the one-dimensional seismic velocity model of the second layer in the drilled area and splicing the updated seismic velocity of the first layer and the one-dimensional seismic velocity of the second layer.
Optionally, in this embodiment, the method preferably filters the acquired original one-dimensional acoustic logging data of the target area in step S503, so as to obtain a one-dimensional seismic velocity model. For example, according to actual needs, the method may perform filtering operations such as median filtering and smoothing filtering on the raw one-dimensional sonic logging data of the target region, thereby obtaining a one-dimensional seismic velocity model such as that shown in fig. 6.
Of course, in other embodiments of the invention, the method may also use other reasonable ways to determine the one-dimensional seismic velocity model of the target area, and the invention is not limited thereto.
In this embodiment, the method splices the updated seismic velocity of the first layer of the drilled area and the one-dimensional seismic velocity of the second layer in step S504, so as to obtain a complete one-dimensional seismic velocity of the drilled area in the target area.
It should be noted that, in this embodiment, when the updated seismic velocities of the first-type horizons and the one-dimensional seismic velocities of the second-type horizons are spliced, if there is an overlapping area, the method preferably uses the one-dimensional seismic velocity model of the second-type horizons (i.e., the measured horizons) as a reference.
In this embodiment, after obtaining the updated one-dimensional seismic velocity model, the method further expands the one-dimensional seismic velocity of the target area to a three-dimensional space in step S505, so as to obtain a three-dimensional interpolation seismic velocity field of the target area.
Specifically, in this embodiment, the method first expands the obtained one-dimensional seismic velocity of the drilled area to a three-dimensional space to obtain a three-dimensional velocity interpolation result, then obtains a geological structure characteristic of the target area, and performs structural constraint on the three-dimensional velocity interpolation result according to the geological structure characteristic, thereby obtaining a three-dimensional interpolation seismic velocity field of the drilled area. This also results in a three-dimensional interpolated seismic velocity field as shown in figure 7.
In this embodiment, the method preferably performs structural constraint on the three-dimensional velocity interpolation result of the drilled region by using an elliptical equation in the partial differential equation according to the geologic structure characteristics.
Of course, in other embodiments of the present invention, the method may also use other reasonable ways to perform structural constraint on the three-dimensional velocity interpolation result of the drilled area, or use other reasonable ways to expand the one-dimensional seismic velocity of the drilled area to a three-dimensional space, according to the actual needs, and the present invention is not limited thereto.
As shown in fig. 5, in this embodiment, after obtaining the three-dimensional interpolated seismic velocity field of the drilled area, in step S506, the method fuses the obtained three-dimensional interpolated seismic velocity field of the drilled area and the known original basic seismic velocity field of the drilled area, so as to obtain a more accurate seismic velocity model of the target area.
Specifically, in this embodiment, the method preferably first converts the three-dimensional interpolation seismic velocity field of the target area and the known original basic seismic velocity field of the target area into the wavenumber domain, then performs fusion in the wavenumber domain, and then converts the wavenumber domain back into the spatial domain, so as to obtain the drilled area seismic velocity model of the target area. This results in a schematic representation of the drilled region seismic velocity model of the fused target region as shown in FIG. 8.
For example, in this embodiment, the method may convert the three-dimensional interpolation seismic velocity field and the original basic seismic velocity field into the wavenumber domain respectively by using a Gabor transform.
Of course, in other embodiments of the present invention, the method may also adopt other reasonable manners to fuse the three-dimensional interpolation seismic velocity field of the target area with the original basic seismic velocity field according to actual needs, and the present invention is not limited thereto.
It can be seen from the above description that the method for updating the seismic velocity of the stratum provided by the invention can obtain more accurate seismic velocity according to logging data which are easily obtained in the actual drilling process and the seismic time horizon interpretation result, thereby realizing the updating of the three-dimensional seismic velocity around the well in the drilled area.
Compared with the prior art, the method can realize the quick update and correction of the one-dimensional seismic velocity model and the three-dimensional seismic velocity model around the well in the drilled area, plays a key constraint role in the real-time processing of the seismic data beside the well, and is beneficial to realizing the real-time quick correction of the seismic model before the drill bit.
As shown in fig. 1 again, in this embodiment, after obtaining the initial seismic velocity model of the drilled area, in step S104, the method constructs an initial seismic velocity model of the target area by using the initial seismic velocity model of the drilled area, and performs prestack depth migration by using the initial seismic velocity model of the target area, so as to obtain a common imaging point gather of the target area.
When the subsurface formation is horizontal or near horizontal, the position and morphology of the formation as reflected in the horizontal stacking profile corresponds or substantially corresponds to the actual condition of the formation in the subsurface. However, when the formation is dipping or has large variations in attitude, the position and shape of the formation as reflected in the horizontal stacking profile may deviate from the actual situation, and even deviate significantly. In order to correct such a deviation, an offset process is required.
Therefore, in this embodiment, the method performs prestack depth migration on the velocity model of the target region in step S104. It should be noted that, in this embodiment, the velocity model of the drilled area in the target area is an updated velocity model using the seismic time horizon interpretation result data and the actual drilling and logging data.
Specifically, in this embodiment, the method may preferably perform prestack depth migration using a velocity model of the target region by using a ray theory-based migration algorithm such as gaussian beam, kirchhoff, and the like, so as to obtain an imaging profile and a common imaging point gather. Fig. 9 shows an initial prestack depth migration imaging depth diagram in the present embodiment, and fig. 10 shows a common imaging point gather diagram.
Of course, in other embodiments of the present invention, the method may also perform prestack depth migration on the velocity model of the target region in other reasonable manners according to actual needs, and the present invention is not limited thereto.
As shown in fig. 1 again, in the present embodiment, after the prestack depth is shifted, in step S105, based on the common imaging point gather, the method selects reflection points with different depths from the tracks corresponding to the well tracks in the non-drilled area. Specifically, in this embodiment, the method preferably picks up the depth coordinates of the reflection points at different depths on the trajectory corresponding to the well trajectory in step S105, and the picking operation does not need to be particularly precise.
Of course, in other embodiments of the present invention, the method may also adopt other reasonable manners to select the reflection point in step S105 according to actual needs, and the present invention is not limited thereto.
For example, in one embodiment of the present invention, the method may further determine, in step S105, a reflection point corresponding to a next horizon according to the depth of the reflection point corresponding to the one horizon, and the seismic time horizon interpretation result data and the initial seismic velocity data of the next horizon of the horizon.
Specifically, the method may determine a reflection point corresponding to a next horizon according to the following expression:
Figure BDA0002195365130000101
wherein the content of the first and second substances,
Figure BDA0002195365130000102
seismic time horizon interpretation result data, z, representing the jth horizoniAnd zi-1Respectively representing the depth of the reflection point corresponding to the ith layer position and the reflection point corresponding to the (i-1) th layer position in the target area，viRepresenting the initial seismic velocity, θ, of the ith horizoniRepresenting the dip of the formation for the ith horizon.
Thus, reflection points with different depths can be obtained.
After selecting reflection points of different depths on a trace corresponding to a well trajectory of an undrilled area, as shown in fig. 1, in this embodiment, the method preferably obtains, for each reflection point, an imaging depth corresponding to a different reflection angle and a ray length of a corresponding reflection ray in each layer in step S106, and updates, in step S107, an initial seismic velocity of a stratum of the undrilled area corresponding to each reflection point according to the imaging depth corresponding to the different reflection angle and the ray length of the corresponding reflection ray in each layer, so as to obtain an updated seismic velocity of the undrilled area.
Specifically, in this embodiment, for any reflection point, the method preferably picks up the residual time difference RMO in the common imaging point gather in step S106, and obtains the imaging depths corresponding to different reflection angles according to the residual time difference RMO.
For example, as shown in fig. 11, the two different reflection angles of the ith reflection point are θ1,iAnd theta2,iThe imaging depths corresponding to the two reflection angles are respectively
Figure BDA0002195365130000111
And
Figure BDA0002195365130000112
for the simulated reflected rays corresponding to each reflection angle, in this embodiment, the method preferably traces the reflected rays from the emission point to the surface direction at the specified reflection angle, and the tracing of the reflected rays is preferably to the interface between the drilled area and the unwritten area, and does not need to trace to the surface completely. That is, the total length of the reflected rays acquired by the method within each horizon is preferably the ray length from the reflection point to the interface between the undrilled and drilled regions.
Of course, in other embodiments of the present invention, the method may also use other reasonable ways to determine the imaging depths corresponding to different reflection angles and the ray lengths of the corresponding reflected rays in the respective horizons.
Specifically, in this embodiment, the method preferably determines an update coefficient in the seismic velocity update model according to the obtained imaging depth and the ray length of the corresponding reflection ray in each layer, and then updates the initial seismic velocity of the formation of the uncalled area corresponding to each reflection point by using the seismic update model according to the update coefficient, thereby obtaining the updated seismic velocity of the uncalled area.
As shown in fig. 12, in this embodiment, the method preferably determines the seismic velocity deformation corresponding to each reflection point according to the obtained imaging depth and the ray length of the corresponding reflection ray in each horizon in step S1201, and then determines the update coefficient in the seismic velocity update model according to the seismic velocity deformation in step S1202.
Specifically, for example, for the ith reflection point, in this embodiment, the method preferably determines the seismic velocity deformation corresponding to the reflection point according to the following expression in step S1201:
Figure BDA0002195365130000113
wherein the content of the first and second substances,
Figure BDA0002195365130000114
representing the initial seismic velocity, theta, of the formation corresponding to the ith reflection point1,iAnd theta2,iTwo different reflection angles, l, respectively representing the ith reflection point1,iAnd l2,iRespectively represent the reflection angle theta1,iAnd theta2,iThe corresponding reflection ray has the internal reflection length in the stratum corresponding to the first reflection point,
Figure BDA0002195365130000115
and
Figure BDA0002195365130000116
respectively represents,. DELTA.miRepresenting the deformation of the seismic velocity corresponding to the ith reflection point,
Figure BDA0002195365130000117
and indicating the stratum inclination angle corresponding to the ith reflection point.
According to the expression (3), the method can determine the seismic velocity deformation delta m corresponding to the ith reflection pointi. And the method preferably bases the seismic velocity deformation Δ m corresponding to the ith reflection point in step S1202iDetermining update coefficients in the seismic velocity update model using the following expression:
Figure BDA0002195365130000118
wherein the content of the first and second substances,
Figure BDA0002195365130000119
representing the updated seismic velocity of the formation corresponding to the ith reflection point, c0,iAnd c1,iIndicating the update coefficient.
In this embodiment, the coefficient c is updated0Is 1. Of course, in other embodiments of the present invention, the coefficient c is updated0The value of (b) can also be other reasonable values.
By using the expression (4), the method can determine the update coefficient c corresponding to the ith reflection point0,iAnd c1,i. Based on the same principle, the method can also determine the updating coefficient corresponding to the ith reflection point.
After the update coefficients are obtained, the method can update the initial seismic velocity of the stratum corresponding to each emission point by using the seismic update model according to the update coefficients.
Specifically, in this embodiment, the seismic update model may be represented as:
Figure BDA0002195365130000121
wherein the content of the first and second substances,
Figure BDA0002195365130000122
representing the updated seismic velocity of the formation corresponding to the ith reflection point, c0,iAnd c1,iRepresents the updating coefficient corresponding to the ith reflection point,
Figure BDA0002195365130000123
and representing the initial seismic velocity of the stratum corresponding to the ith reflection point.
Based on the principle, the method can update the seismic velocity of the stratum corresponding to each emission point, so that each reflecting surface in the finally obtained common imaging point trace set is leveled.
From the above description, it can be seen that the method for updating the seismic velocity of the stratum to be drilled provided by the invention can greatly reduce the number of parameters of the traditional seismic tomography, thereby improving the velocity modeling efficiency (in actual use, computer software can rapidly complete the updating and re-modeling of the seismic velocity of the stratum to be drilled within 24 hours), and laying a foundation for correcting the geomechanical model of the stratum to be drilled in real time.
Based on the method for updating the seismic velocity of the stratum, the invention also provides a geophysical drilling guidance method, which can accurately predict certain geological characteristic parameters of the stratum which is not drilled before the drill bit, and can purposefully optimize drilling design and construction, thereby realizing safe, high-quality and high-efficiency drilling.
Fig. 13 shows a flow chart of an implementation of the geophysical guided drilling method provided by the present embodiment.
As shown in fig. 13, in the geophysical guided drilling method provided in this embodiment, an original reference seismic velocity model of a target area is first obtained in step S1301, and the original reference seismic velocity model is modified and updated according to real drilling wellbore data obtained in a drilling process as constraints, so as to obtain an updated seismic velocity model.
In this embodiment, the original seismic data of the target area acquired by the method in step S1301 is preferably pre-stack seismic data with a central point falling within a certain range around the well (for example, typically, bottom hole displacement plus 3000m-5000m) determined according to the bottom hole displacement size and an initial seismic velocity model of the corresponding area. Of course, in other embodiments of the invention, the raw seismic data of the target area may also be seismic data of other reasonable areas.
The specific implementation manner of step S1301 has been described in detail in the foregoing method for updating the seismic velocity of the formation, and therefore, details of step S1301 are not repeated herein.
After obtaining the updated seismic velocity model, as shown in fig. 13, in this embodiment, the method preferably determines a seismic profile according to the updated seismic velocity model in step S1302, acquires the seismic profile of the region to be drilled according to the seismic profile obtained in step S1302 in step S1303, and corrects the preset geological feature parameters in front of the drill bit according to the seismic profile of the region to be drilled.
Specifically, in this embodiment, in step S1302, the method preferably applies the updated borehole seismic velocity model to perform depth migration imaging, so as to obtain the latest seismic imaging data of the area to be drilled, and then obtain the latest seismic profile. Meanwhile, in step S1303, the method may correct geological feature parameters such as key layer positions, faults, reservoir positions, and the like according to the latest seismic imaging data of the region to be drilled and the interpretation conclusion of sensitive geological features of the drilling well before drilling, and redraws the dip angle and the crack zone of the formation to be drilled by applying principal component analysis and curvature body analysis techniques.
FIG. 14 shows a schematic of the correction of key pre-bit horizons (e.g., horizon 1 and horizon 2). As shown in fig. 14, the difference between the design depth and the actual drilling depth is large, the positions of the updated stratum 1 and the updated stratum 2 in the longitudinal direction are greatly changed (adjusted by 80 meters and 136 meters respectively), the error between the updated depth and the actual measurement depth is obviously reduced, and the accuracy is respectively improved by 94.1% and 80%.
As shown in fig. 13 again, in this embodiment, after obtaining the updated seismic velocity model, in order to obtain a seismic velocity model with a higher resolution, the method preferably corrects the pre-set drilling geological environment factor in front of the drill bit according to the updated seismic velocity model and the pre-established mechanical model in step S1304.
In this embodiment, the pre-set drilling geological environment factors in front of the drill bit may include a formation pore pressure in front of the drill bit and/or a formation fracture pressure in front of the drill bit, and the method may correct the formation pore pressure model in front of the drill bit and/or the formation fracture pressure model in front of the drill bit in step S1304.
In particular, the method preferably rejects log data for non-compliant depth segments based on caliper data for the drilled segment. The method also collects logging longitudinal and transverse wave velocity data of the drilled stratum and carries out normalization processing on the data.
For example, the method may normalize the log compressional-compressional velocity data by the expression:
Xnor＝(Xi-Xmin)/(Xmax-Xmin) (6)
wherein, XnorRepresenting normalized velocity values, XiRepresenting the value of the velocity, X, of the shear or longitudinal wave before normalizationmaxAnd XminThe maximum and minimum values of the longitudinal wave velocity or the transverse wave velocity are respectively indicated.
In this embodiment, the method may preferably use a GDBT algorithm to simulate the relationship between the compressional wave velocity and the shear wave velocity in the present well. Of course, in other embodiments of the present invention, the relationship between the simulated compressional velocity and the shear velocity in the present well may also be obtained by other reasonable algorithms, and the present invention is not limited to this.
And then, according to GR well logging data, preferably, the normal compaction trend line of the well is obtained by selecting a shale stratum of a drilled well section and eliminating irregular parts of the well diameter and fitting the linear relation between the shale stratum and the depth by utilizing longitudinal wave velocity well logging data.
In this embodiment, the modulus of elasticity and poisson's ratio values of the compaction used in determining the compaction trend line are preferably determined by the formation density and the acoustic depth.
For example, the method may determine the modulus of elasticity and poisson's ratio according to the following expression:
E＝ρvs 2(3vp 2-4vs 2)/(vp 2-vs 2) (7)
μ＝(vp 2-2vs 2)/2(vp 2-vs 2) (8)
wherein E represents an elastic modulus, μ represents a Poisson's ratio, vpAnd vsRepresenting compressional and shear velocities, respectively, with ρ representing formation density.
It should be noted that, in step S1304, according to actual needs, the method may preferably further use a post-stack seismic inversion technique to obtain a pre-stack seismic velocity model with a higher resolution according to the seismic profile determined in step S1303, so as to correct the pre-set drilling geological environment factor in front of the drill bit according to the pre-stack seismic velocity model with the higher resolution and the pre-established mechanical model.
In this embodiment, the mechanical model created by the method preferably comprises an overburden pressure model. In the method, when the overburden pressure model is established, the overburden pressure gradient is preferably determined firstly, and then the overburden pressure model of the whole well section is established according to the overburden pressure gradient and the well depth.
In this embodiment, the method preferably uses the log data of the adjacent well density of the well (i.e., the well to be analyzed) to calculate the scatter data of the overburden pressure gradient of the well. The overburden pressure gradient can then be calculated according to the following expression:
Figure BDA0002195365130000141
wherein G is0Representing the overburden pressure gradient, a1、a2、a3And a4All represent calculated parameters and h represents well depth.
Of course, in other embodiments of the invention, the method may also use other reasonable ways to determine the overburden pressure model, and the invention is not limited thereto.
The pressure generated by the fluid in the formation rock pores is called the pore pressure, which is very closely related to the speed of sound. In this embodiment, the method preferably determines the formation pore pressure according to the expression:
Figure BDA0002195365130000151
wherein, PpRepresenting the formation pore pressure, σ0Denotes the overlying pressure, P0Denotes the hydrostatic pressure, v0Indicating normal compaction speed (which may be obtained by plotting normal compaction trend lines), E0Representing the calculation parameters. FIG. 15 shows a schematic diagram of a corrected pore pressure model of the formation ahead of the bit in this embodiment.
Through analysis, the calculation process of the ground stress needs to consider the influence factors including: modulus of elasticity, poisson's ratio, pore pressure, and formation stress factor. In this embodiment, the method preferably calculates the ground stress according to the following expression:
Figure BDA0002195365130000152
Figure BDA0002195365130000153
wherein σHAnd σhRespectively representing horizontal maximum stress and horizontal minimum stress, ξHAnd xihRespectively representing maximum horizontal constructional ground shouldForce coefficient and minimum horizontal tectonic stress coefficient (which can be obtained by fitting the results of laboratory rock mechanics experiments or drilling field tests), σvIndicating overburden pressure.
Of course, in other embodiments of the present invention, the method may also adopt other reasonable manners to calculate the ground stress according to actual needs, and the present invention is not limited to this specifically.
The tensile strength of the rock, also called tensile strength, refers to the ultimate strength of the rock to failure under tensile force, and is numerically equal to the maximum tensile stress at failure. In this embodiment, the method preferably obtains a relational expression between the tensile strength of the rock and the elastic modulus and the shale content of the rock through statistical analysis of rock mechanical property test results. For example, the quantitative relationship may be expressed as:
St＝[K0Ed(1-Vsh)+K1VshEd]/Kt (13)
wherein S istDenotes the tensile strength, K0、K1And KtAll represent calculated parameters, EdDenotes the dynamic modulus of elasticity, VshIndicating the argillaceous content.
In this embodiment, the method preferably calculates the shale content V from the acoustic velocitysh. For example, the method may calculate the argillaceous content V according to the following expressionsh：
Vsh＝b1+b2vp+b3vs (14)
Wherein, b1、b2And b3Are all calculation parameters.
At a certain depth in the formation, when the pressure generated by the drilling fluid column in the well rises enough to fracture the formation, the original fracture will be opened and extended or a new fracture will be formed, and the fluid pressure in the well is called the fracture pressure of the formation. The magnitude of the fracture pressure of the formation is closely related to the magnitude of the ground stress. Mechanically, formation fracture is caused by the circumferential stress on the rock reaching the tensile strength of the rock due to the fact that the well bore fluid density in the well is too high.
In this embodiment, the method preferably calculates the formation fracture pressure according to the expression:
Pf＝3σh-σH-αPp+St (15)
wherein, PfRepresenting the formation fracture pressure and alpha representing the effective stress factor.
FIG. 16 shows a schematic diagram of a corrected formation fracture pressure model ahead of the bit in this example.
Of course, in other embodiments of the present invention, the method may also adopt other reasonable ways to modify the formation pore pressure model and/or the formation fracture pressure model in front of the drill bit according to actual needs, and the present invention is not limited to this.
Meanwhile, it should be noted that, in other embodiments of the present invention, the above-mentioned geological environment factors of the drill bit ahead of the drill bit may also include other reasonable parameters according to actual needs, and the present invention also does not specifically limit this.
Finally, after the correction of the pre-set geological feature parameter in front of the drill bit and the pre-set drilling geological environment factor in front of the drill bit is completed, the method preferably performs the drilling risk fault prediction and/or the drilling process adjustment optimization according to the corrected pre-set geological feature parameter in front of the drill bit and the corrected pre-set drilling geological environment factor in front of the drill bit in step S1305.
From the description, the geophysical drilling guidance method provided by the invention can be used for correcting and updating the stratum depth model while drilling by utilizing the actual drilling barrel data obtained in the drilling process, and can be used for processing the pre-stack seismic data in a certain range around the well hole in real time, so that the prediction and description of the stratum characteristics of the specified well section in front of the drill bit and the drilling geological environment factors are realized, and the drilling construction process is guided and optimized. Experiments prove that the overall updating aging of the method is less than 20 hours, and the method can meet the requirement of drilling aging.
The method can accurately predict and describe the geological characteristics of the to-be-drilled well or the to-be-drilled stratum and the drilling geological environment factors, and has very important significance for scientific drilling design and efficient drilling construction. Meanwhile, the method can also enable researchers to purposefully optimize drilling design and construction, so that safe, high-quality and efficient drilling is realized.
It is to be understood that the disclosed embodiments of the invention are not limited to the particular structures or process steps disclosed herein, but extend to equivalents thereof as would be understood by those skilled in the relevant art. It is also to be understood that the terminology used herein is for the purpose of describing particular embodiments only, and is not intended to be limiting.
Reference in the specification to "one embodiment" or "an embodiment" means that a particular feature, structure, or characteristic described in connection with the embodiment is included in at least one embodiment of the invention. Thus, the appearances of the phrase "one embodiment" or "an embodiment" in various places throughout this specification are not necessarily all referring to the same embodiment.
While the above examples are illustrative of the principles of the present invention in one or more applications, it will be apparent to those of ordinary skill in the art that various changes in form, usage and details of implementation can be made without departing from the principles and concepts of the invention. Accordingly, the invention is defined by the appended claims.

Claims (11)

1. A method of updating the seismic velocities of a formation, the method comprising:
acquiring seismic time horizon interpretation result data of horizons in a drilled area in a target area, wherein the horizons cannot directly acquire original one-dimensional acoustic logging data;
determining an initial seismic velocity model of a drilled area according to the seismic time horizon interpretation result data and the real depth of each horizon, constructing the initial seismic velocity model of the target area according to the initial seismic velocity model of the drilled area, and performing prestack depth migration by using the initial seismic velocity model of the target area to obtain a common imaging point gather of the target area;
thirdly, based on the common imaging point gather, selecting reflection points with different depths on a track corresponding to a well track of an undrilled area, and respectively obtaining imaging depths corresponding to different reflection angles and ray lengths of corresponding reflection rays in all layers for all the reflection points;
and fourthly, updating the initial seismic velocity of the stratum of the non-drilled area corresponding to each reflection point according to the imaging depth and the ray length of the corresponding reflection ray in each layer, and obtaining the updated seismic velocity of the non-drilled area.
2. The method of claim 1, wherein in step two, the true depth of each horizon in the target region is determined from the obtained real borehole log data.
3. The method of claim 1, wherein, in step two,
determining the estimated seismic velocity of the horizon to be updated in the drilled area according to the seismic time horizon interpretation result data and the real depth of each horizon;
updating the estimated seismic velocity of the horizon to be updated according to the real depth of each horizon in the target area to obtain the one-dimensional seismic velocity of the first horizon;
filtering the acquired original one-dimensional acoustic logging data of a second layer of the target area to obtain the one-dimensional seismic velocity of the second layer;
splicing the updated seismic velocity of the first layer and the one-dimensional seismic velocity of the second layer;
and obtaining a three-dimensional interpolation seismic velocity field of the drilled area according to the spliced one-dimensional seismic velocity, and fusing the three-dimensional interpolation seismic velocity field and the original basic seismic velocity field to obtain an initial seismic velocity model of the drilled area of the target area.
4. A method as claimed in claim 3, wherein in step two, the estimated seismic velocities are updated according to the expression:
Figure FDA0002841050720000021
wherein z iskAnd zk-1Respectively representing the true depth of the kth horizon and the kth-1 horizon in the target region, zjAnd zj-1Respectively representing the true depth of the jth horizon and the jth-1 horizon in the target region, thetakAnd thetajRespectively representing the inclination angles of the kth horizon and the jth horizon in the target region,
Figure FDA0002841050720000022
representing updated seismic velocities of the kth horizon, cjAnd
Figure FDA0002841050720000023
respectively representing the preset correction coefficient and the estimated seismic velocity of the jth horizon,
Figure FDA0002841050720000024
and reflecting seismic wave travel time by the horizon representing the jth horizon.
5. The method of claim 3, wherein the step of determining the three-dimensional interpolated seismic velocity field comprises:
expanding the updated one-dimensional seismic velocity to a three-dimensional space to obtain a three-dimensional velocity interpolation result;
and acquiring the geological structure characteristics of the target area, and performing structural constraint on the three-dimensional velocity interpolation result according to the geological structure characteristics to obtain the three-dimensional interpolation seismic velocity field.
6. The method of claim 1, wherein in step four,
determining an updating coefficient in a seismic velocity updating model according to the imaging depth and the ray length of the corresponding reflection ray in each horizon;
and updating the initial seismic velocity of the stratum of the non-drilling area corresponding to each reflection point by using the seismic velocity updating model according to the updating coefficient to obtain the updated seismic velocity of the non-drilling area.
7. The method according to claim 6, wherein in the fourth step, the update coefficients are determined by:
determining the seismic velocity deformation corresponding to each reflection point according to the imaging depth and the ray length of the corresponding reflection ray in each horizon;
and determining an updating coefficient in a seismic velocity updating model according to the seismic velocity deformation.
8. The method according to claim 7, wherein in the fourth step, the seismic velocity deformation corresponding to each reflection point is determined according to the following expression:
Figure FDA0002841050720000025
wherein the content of the first and second substances,
Figure FDA0002841050720000026
representing the initial seismic velocity, theta, of the formation corresponding to the ith reflection point1,iAnd theta2,iTwo different reflection angles, l, respectively representing the ith reflection point1,iAnd l2,iRespectively represent the reflection angle theta1,iAnd theta2,iThe ray length of the corresponding reflected ray in the formation corresponding to the ith reflection point,
Figure FDA0002841050720000027
and
Figure FDA0002841050720000028
respectively represent the reflection angle theta1,iAnd theta2,iCorresponding imaging depth, Δ miRepresenting the deformation of the seismic velocity corresponding to the ith reflection point,
Figure FDA0002841050720000031
and indicating the stratum inclination angle corresponding to the ith reflection point.
9. The method of claim 8, wherein the update coefficients in the seismic velocity update model are determined according to the following expression:
Figure FDA0002841050720000032
wherein the content of the first and second substances,
Figure FDA0002841050720000033
representing the updated seismic velocity of the formation corresponding to the ith reflection point, c0,iAnd c1,iAnd indicating the updating coefficient corresponding to the ith reflection point.
10. The method of claim 9, wherein the coefficient c is updated0,iIs 1.
11. The method according to any one of claims 1 to 10, wherein in the fourth step, the initial seismic velocity of the stratum of the undrilled area corresponding to each reflection point is updated according to the following expression:
Figure FDA0002841050720000034
wherein the content of the first and second substances,
Figure FDA0002841050720000035
representing the updated seismic velocity of the formation corresponding to the ith reflection point, c0,iAnd c1,iRepresents the updating coefficient corresponding to the ith reflection point,
Figure FDA0002841050720000036
and representing the initial seismic velocity of the stratum corresponding to the ith reflection point.
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