CN104330822A - Method and device for determining remaining oil and gas distribution through coupling four-dimensional seismic inversion - Google Patents

Abstract

An embodiment of the invention provides a method and a device for determining the remaining oil and gas distribution through the coupling four-dimensional seismic inversion. The method comprises establishing an elastic parameter model of every seismic collection time point for at least two seismic collection time points; obtaining longitudinal wave speed, transverse speed and density data of every seismic collection time point by a coupling pre-stack four-dimensional seismic inversion method; calculating the fluid factor variation between a fluid factor which is corresponding to the earliest time of seismic collection time point in the at least two seismic collection time points and a fluid factor which is corresponding to any other seismic collection time point except the earliest time of seismic collection time point in the at least two seismic collection time points according to the longitudinal wave speed, transverse speed and density data of every seismic collection time point, wherein the longitudinal wave speed, transverse speed and density data are obtained through the inversion; determining the distribution of the remaining oil and gas according to the fluid factor variation. According to the method and the device for determining the remaining oil and gas distribution through the coupling four-dimensional seismic inversion, the combination with the technologies of the pre-stack four-dimensional seismic inversion, the fluid factor detection technology and the like is implemented and accordingly the accuracy of the determined remaining oil and gas distribution result can be improved.

Description

Adopt method and the device of the distribution of coupling time lapse seismic inverting determination Remaining Oil And Gas

Technical field

The present invention relates to reservoir geophysics technical field, particularly a kind of method and device adopting the distribution of coupling time lapse seismic inverting determination Remaining Oil And Gas.

Background technology

Time lapse seismic technology utilizes twice or the seismic data of multi collect, the basis of cross equalization processing is carried out the technology that seismic inversion obtains changes in reservoir information, is that maturing field increases new reserves, develops project setting, improve the important method of recovery ratio, be also called time-lapse seismic.Time lapse seismic inverting is the method utilizing inverting, gathers from Repeating earthquakes the method that data obtains elastic parameter variable quantity.

Time lapse seismic inverting can be divided into non-coupled inversion method, coupling inversion method and difference inversion method.Non-coupled inversion method is exactly carry out separately to multi collect seismic data the elastic parameter model that inverting obtains different times, and the difference then comparing them obtains the variable quantity of elastic parameter;

Coupling time lapse seismic inversion method is repeatedly the inversion result of geological data time lapse seismic inversion method constrained each other.The thinking realizing the inverting of coupling time lapse seismic has two kinds.A kind of thinking first carries out inverting to first time collection seismic data to obtain playing parameter model (inversion result), then allow this elastic parameter model participate in the inverting of seismic data in other, finally more multiple inversion result obtains the variable quantity of elastic parameter or the variable quantity of direct acquisition elastic parameter in period; Another kind of thinking is by the geological data of different acquisition time point and elastic parameter model, and be building up in a unified objective function, Simultaneous Inversion obtains the elastic parameter of different acquisition time point.Coupling time lapse seismic of the present invention inverting have employed rear a kind of thinking.

Difference inversion method directly carries out inverting to the difference of twice collection seismic data, obtains the variable quantity of elastic parameter.

According to the algorithm characteristic of time lapse seismic inverting, the inverting of determinacy time lapse seismic and random time lapse seismic inverting can be divided into again.As its name suggests, the feature of determinacy time lapse seismic inversion method is inversion result is determine, the result of the inverting of random time lapse seismic is random.

But for determining the method that Remaining Oil And Gas distributes, in the prior art, mainly carrying out based on the data of time lapse seismic inverting or numerical simulation data, making the Remaining Oil And Gas distribution results precision determined low.

Summary of the invention

Embodiments provide a kind of method adopting the distribution of coupling prestack time lapse seismic inverting determination Remaining Oil And Gas, to improve the precision of the Remaining Oil And Gas distribution results determined, the method comprises: at least two earthquake-capturing time points, sets up the elastic parameter model of each earthquake-capturing time point respectively; Adopt coupling prestack time lapse seismic inverting mode, obtain the velocity of longitudinal wave of each earthquake-capturing time point, shear wave velocity and density data; The velocity of longitudinal wave of each earthquake-capturing time point obtained according to inverting, shear wave velocity and density data, calculate the fluid factor that each earthquake-capturing time point is corresponding, and the fluid factor variable quantity between the fluid factor that described in calculating, time earthquake-capturing time point is the earliest corresponding at least two earthquake-capturing time points with the fluid factor that in described at least two earthquake-capturing time points, other arbitrary earthquake-capturing time points are corresponding except time earthquake-capturing time point the earliest; According to described fluid factor variable quantity, determine the distribution of Remaining Oil And Gas.

In one embodiment, adopt coupling prestack time lapse seismic inverting mode, obtain the velocity of longitudinal wave of each earthquake-capturing time point, shear wave velocity and density data, comprise: carry out prestacking forward modeling according to the elastic parameter model of described each earthquake-capturing time point and wavelet, obtain the theogram of this earthquake-capturing time point; Calculate the residual error of the described seismic channel set of each earthquake-capturing time point and the theogram of this earthquake-capturing time point, and residual error corresponding for described at least two earthquake-capturing time points addition is obtained total residual error; When described total residual error is less than preset value, export the velocity of longitudinal wave of each earthquake-capturing time point that the inverting of prestack time lapse seismic obtains, shear wave velocity and density data; Or, when described total residual error is less than preset value and the velocity of longitudinal wave of each earthquake-capturing time point of obtaining of prestack time lapse seismic inverting, shear wave velocity and density data meet the default inversion result upper limit constraint condition corresponding with this earthquake-capturing time point and lower limit constraint condition, export the velocity of longitudinal wave of each earthquake-capturing time point that the inverting of prestack time lapse seismic obtains, shear wave velocity and density data.

In one embodiment, the velocity of longitudinal wave of each earthquake-capturing time point obtained according to inverting, shear wave velocity and density data, calculate the fluid factor of each earthquake-capturing time point, comprise: the velocity of longitudinal wave of each earthquake-capturing time point obtained according to inverting by following formula, shear wave velocity and density data, calculate the fluid factor that each earthquake-capturing time point is corresponding: DHI=ρ ²(v _p ²-2.33v _s ²), wherein, DHI is the fluid factor that this earthquake-capturing time point is corresponding, and ρ is the density data of this earthquake-capturing time point that inverting obtains, v _pthe velocity of longitudinal wave data of this earthquake-capturing time point that inverting obtains, v _sthe shear wave velocity data of this earthquake-capturing time point that inverting obtains.

In one embodiment, by the fluid factor variable quantity between fluid factor corresponding to two earthquake-capturing time points described in following formulae discovery: Δ DHI=(DHI ^ti-DHI ^t1)/DHI ^t1wherein, Δ DHI is fluid factor that in described at least two earthquake-capturing time points, time earthquake-capturing time point is the earliest corresponding and the fluid factor variable quantity between the fluid factor that in described at least two earthquake-capturing time points, other arbitrary earthquake-capturing time points are corresponding except time earthquake-capturing time point the earliest, DHI ^t1the fluid factor that in described at least two earthquake-capturing time points, time earthquake-capturing time point is the earliest corresponding, DHI ^tithe fluid factor that in described at least two earthquake-capturing time points, other arbitrary earthquake-capturing time points are corresponding except time earthquake-capturing time point the earliest.

In one embodiment, according to described fluid factor variable quantity, determine the distribution of Remaining Oil And Gas, comprising: determine the Remaining Oil And Gas change of reserves amount in the earthquake-capturing time point the earliest of time at least two earthquake-capturing time points and described at least two earthquake-capturing time points except time earthquake-capturing time point the earliest between other arbitrary earthquake-capturing time points according to described fluid factor variable quantity; The Remaining Oil And Gas reserves corresponding according to time earthquake-capturing time point the earliest in described Remaining Oil And Gas change of reserves amount and described at least two earthquake-capturing time points, determine the distribution of Remaining Oil And Gas.

In one embodiment, Remaining Oil And Gas change of reserves amount between Remaining Oil And Gas change of reserves amount at least two earthquake-capturing time points described in being determined according to described fluid factor variable quantity by following formula in time earthquake-capturing time point the earliest and described at least two earthquake-capturing time points except time earthquake-capturing time point the earliest between other arbitrary earthquake-capturing time points: Δ Q=a Δ DHI+b, wherein, Δ DHI is described fluid factor variable quantity, Δ Q is the Remaining Oil And Gas change of reserves amount in described at least two earthquake-capturing time points in time earthquake-capturing time point the earliest and described at least two earthquake-capturing time points except time earthquake-capturing time point the earliest between other arbitrary earthquake-capturing time points, a, b is constant.

In one embodiment, according to time earthquake-capturing time point the earliest in described Remaining Oil And Gas change of reserves amount and described at least two earthquake-capturing time points, determine the distribution of Remaining Oil And Gas, comprising: determine that described Remaining Oil And Gas change of reserves amount is less than the first preset value and the region that the Remaining Oil And Gas reserves that in described at least two earthquake-capturing time points, time earthquake-capturing time point is the earliest corresponding are greater than the second preset value is the region that Remaining Oil And Gas distributes.

The embodiment of the present invention additionally provides a kind of device adopting the distribution of coupling prestack time lapse seismic inverting determination Remaining Oil And Gas, to improve the precision of the Remaining Oil And Gas distribution results determined, this device comprises: model building module, for at least two earthquake-capturing time points, set up the elastic parameter model of each earthquake-capturing time point respectively; Coupling prestack time lapse seismic inverting module, for adopting coupling prestack time lapse seismic inverting mode, obtains the velocity of longitudinal wave of each earthquake-capturing time point, shear wave velocity and density data; Computing module, for the velocity of longitudinal wave of each earthquake-capturing time point of obtaining according to inverting, shear wave velocity and density data, calculate the fluid factor that each earthquake-capturing time point is corresponding, and the fluid factor variable quantity between the fluid factor that described in calculating, time earthquake-capturing time point is the earliest corresponding at least two earthquake-capturing time points with the fluid factor that in described at least two earthquake-capturing time points, other arbitrary earthquake-capturing time points are corresponding except time earthquake-capturing time point the earliest; Determination module, for according to described fluid factor variable quantity, determines the distribution of Remaining Oil And Gas.

In one embodiment, described coupling prestack time lapse seismic inverting module, comprising: prestacking forward modeling unit, for carrying out prestacking forward modeling according to the elastic parameter model of described each earthquake-capturing time point and wavelet, obtaining the theogram of this earthquake-capturing time point; Residual computations unit, for calculating the residual error of the described seismic channel set of each earthquake-capturing time point and the theogram of this earthquake-capturing time point, and obtains total residual error by residual error corresponding for described at least two earthquake-capturing time points addition; Output unit, for when described total residual error is less than preset value, exports the velocity of longitudinal wave of each earthquake-capturing time point that the inverting of prestack time lapse seismic obtains, shear wave velocity and density data; Or, when described total residual error is less than preset value and the velocity of longitudinal wave of each earthquake-capturing time point of obtaining of prestack time lapse seismic inverting, shear wave velocity and density data meet the default inversion result upper limit constraint condition corresponding with this earthquake-capturing time point and lower limit constraint condition, export the velocity of longitudinal wave of each earthquake-capturing time point that the inverting of prestack time lapse seismic obtains, shear wave velocity and density data.

In one embodiment, described computing module is used for the velocity of longitudinal wave of each earthquake-capturing time point obtained according to inverting by following formula, shear wave velocity and density data, calculates the fluid factor that each earthquake-capturing time point is corresponding:

DHI=ρ ²(v _p ²-2.33v _s ²), wherein, DHI is the fluid factor that this earthquake-capturing time point is corresponding, and ρ is the density data of this earthquake-capturing time point that inverting obtains, v _pthe velocity of longitudinal wave data of this earthquake-capturing time point that inverting obtains, v _sthe shear wave velocity data of this earthquake-capturing time point that inverting obtains.

In one embodiment, described computing module is also for by the fluid factor variable quantity between fluid factor corresponding to time earthquake-capturing time point the earliest at least two earthquake-capturing time points described in following formulae discovery with the fluid factor that in described at least two earthquake-capturing time points, other arbitrary earthquake-capturing time points are corresponding except time earthquake-capturing time point the earliest: Δ DHI=(DHI ^ti-DHI ^t1)/DHI ^t1wherein, Δ DHI is fluid factor that in described at least two earthquake-capturing time points, time earthquake-capturing time point is the earliest corresponding and the fluid factor variable quantity between the fluid factor that in described at least two earthquake-capturing time points, other arbitrary earthquake-capturing time points are corresponding except time earthquake-capturing time point the earliest, DHI ^t1the fluid factor that in described at least two earthquake-capturing time points, time earthquake-capturing time point is the earliest corresponding, DHI ^tiit is the fluid factor that in described at least two earthquake-capturing time points, other arbitrary earthquake-capturing time points are corresponding except time earthquake-capturing time point the earliest.

In one embodiment, described determination module, comprise: Remaining Oil And Gas change of reserves amount determining unit, for the Remaining Oil And Gas change of reserves amount in the earthquake-capturing time point the earliest of time at least two earthquake-capturing time points described in determining according to described fluid factor variable quantity and described at least two earthquake-capturing time points except time earthquake-capturing time point the earliest between other arbitrary earthquake-capturing time points; Remaining Oil And Gas distribution determining unit, for the Remaining Oil And Gas reserves corresponding according to time earthquake-capturing time point the earliest in described Remaining Oil And Gas change of reserves amount and described at least two earthquake-capturing time points, determines the distribution of Remaining Oil And Gas.

In one embodiment, described Remaining Oil And Gas change of reserves amount determining unit to be determined according to described fluid factor variable quantity by following formula described in Remaining Oil And Gas change of reserves amount at least two earthquake-capturing time points in time earthquake-capturing time point the earliest and described at least two earthquake-capturing time points except time earthquake-capturing time point the earliest between other arbitrary earthquake-capturing time points: Δ Q=a Δ DHI+b, wherein, Δ DHI is described fluid factor variable quantity, Δ Q is the Remaining Oil And Gas change of reserves amount in described at least two earthquake-capturing time points in time earthquake-capturing time point the earliest and described at least two earthquake-capturing time points except time earthquake-capturing time point the earliest between other arbitrary earthquake-capturing time points, a, b is constant.

In one embodiment, described Remaining Oil And Gas distribution determining unit is specifically for determining described Remaining Oil And Gas change of reserves amount and be less than the first preset value and the region that the Remaining Oil And Gas reserves that in described at least two earthquake-capturing time points, time earthquake-capturing time point is the earliest corresponding are greater than the second preset value being the region of Remaining Oil And Gas distribution.

In embodiments of the present invention, for two earthquake-capturing time points, set up the elastic parameter model of each earthquake-capturing time point respectively (such as, Geologic modeling can be adopted, numerical reservoir simulation, the technology such as rock physics modeling), and adopt coupling prestack time lapse seismic inverting mode, the inverting of prestack time lapse seismic is carried out to the elastic parameter model of multiple earthquake-capturing time point simultaneously, obtain the velocity of longitudinal wave of each earthquake-capturing time point, shear wave velocity and density data, again according to the velocity of longitudinal wave of each earthquake-capturing time point, shear wave velocity and density data, calculate the fluid factor that this earthquake-capturing time point is corresponding, and the fluid factor variable quantity between fluid factor corresponding to two earthquake-capturing time points, finally by fluid factor variable quantity, determine the distribution of Remaining Oil And Gas, achieve in conjunction with Geologic modeling, numerical reservoir simulation, rock physics modeling, the technology such as the inverting of prestack time lapse seismic and fluid factor detection determine the distribution of Remaining Oil And Gas, with determine compared with the method that Remaining Oil And Gas distributes in prior art, the precision of the Remaining Oil And Gas distribution results determined can be improved.

Accompanying drawing explanation

Accompanying drawing described herein is used to provide a further understanding of the present invention, forms a application's part, does not form limitation of the invention.In the accompanying drawings:

Fig. 1 is a kind of process flow diagram adopting the method for coupling prestack time lapse seismic inverting determination Remaining Oil And Gas distribution that the embodiment of the present invention provides;

Fig. 2 is a kind of process flow diagram setting up four-dimensional elastic parameter model that the embodiment of the present invention provides;

Fig. 3 is the coupling prestack time lapse seismic inverting process flow diagram of the one that provides of the embodiment of the present invention based on CDP (common depth point) road collection;

Fig. 4 is a kind of structured flowchart adopting the device of coupling prestack time lapse seismic inverting determination Remaining Oil And Gas distribution that the embodiment of the present invention provides.

Embodiment

For making the object, technical solutions and advantages of the present invention clearly understand, below in conjunction with embodiment and accompanying drawing, the present invention is described in further details.At this, exemplary embodiment of the present invention and illustrating for explaining the present invention, but not as a limitation of the invention.

In embodiments of the present invention, provide a kind of method adopting the distribution of coupling prestack time lapse seismic inverting determination Remaining Oil And Gas, as shown in Figure 1, the method comprises:

Step 101: at least two earthquake-capturing time points, sets up the elastic parameter model of each earthquake-capturing time point respectively;

Step 102: adopt coupling prestack time lapse seismic inverting mode, obtain the velocity of longitudinal wave of each earthquake-capturing time point, shear wave velocity and density data;

Step 103: the velocity of longitudinal wave of each earthquake-capturing time point obtained according to inverting, shear wave velocity and density data, calculate the fluid factor that each earthquake-capturing time point is corresponding, and the fluid factor variable quantity between the fluid factor that described in calculating, time earthquake-capturing time point is the earliest corresponding at least two earthquake-capturing time points with the fluid factor that in described at least two earthquake-capturing time points, other arbitrary earthquake-capturing time points are corresponding except time earthquake-capturing time point the earliest;

Step 104: according to described fluid factor variable quantity, determine the distribution of Remaining Oil And Gas.

Flow process is as shown in Figure 1 known, in embodiments of the present invention, for two earthquake-capturing time points, set up the elastic parameter model of each earthquake-capturing time point respectively (such as, Geologic modeling can be adopted, numerical reservoir simulation, the technology such as rock physics modeling), adopt coupling time lapse seismic inverting module to carry out the inverting of prestack time lapse seismic to the elastic parameter model of multiple earthquake-capturing time point simultaneously, obtain the velocity of longitudinal wave of each earthquake-capturing time point, shear wave velocity and density data, again according to the velocity of longitudinal wave of each earthquake-capturing time point, shear wave velocity and density data, calculate the fluid factor that this earthquake-capturing time point is corresponding, and the fluid factor variable quantity between fluid factor corresponding to two earthquake-capturing time points, finally by fluid factor variable quantity, determine the distribution of Remaining Oil And Gas, achieve in conjunction with Geologic modeling, numerical reservoir simulation, rock physics modeling, the technology such as the inverting of prestack time lapse seismic and fluid factor detection determine the distribution of Remaining Oil And Gas, with determine compared with the method that Remaining Oil And Gas distributes in prior art, the precision of the Remaining Oil And Gas distribution results determined can be improved.

Concrete, in prior art, not combined the method determining that Remaining Oil And Gas distributes by the prestack time lapse seismic inverting of coupling and fluid factor detection technique, such as, the state of the art of determinacy time lapse seismic inverting has following several:

Ivar Brevik (1999) proposes one and carries out petrophysical model inverting based on time lapse seismic data and whilst on tour association attributes, obtain the method for oil deposit parameter variable quantity, and test based on the stability of simulated data to the method, when result shows to use compressional wave whilst on tour and shear wave whilst on tour variable quantity data simultaneously, inversion algorithm is more stable, if when using compressional wave whilst on tour variable quantity and whilst on tour ratio variable quantity, inversion algorithm is unstable.

Yajun Zhang (2004) proposes a kind of time lapse seismic inversion method based on seismic trace difference, Hilbert transform and coefficient spiking deconvolution method are introduced refutation process by the method, comparatively strong to the recognition capability of thin reservoir, and be applicable to the condition of higher noise levels.

Li Jingye etc. (2005) utilize method for numerical simulation to describe time lapse seismic AVO (Amplitude Versus Offset, the change of amplitude offset distance) inverting distinguish oil deposit parameter change feasibility, from Aki approximate expression, detailed P-P ripple and the P-S transformed wave time-lapse seismic AVO computing formula of having derived, and carry out many ripples time lapse seismic AVO inverting according to actual oil reservoir development situation, distinguish oil reservoir oil saturation and effective pressure change, time lapse seismic data quantitative is explained.

Liu Guoping etc. (2006) adopt the compressional wave angular stack data of simulation, the size of reservoir compressional wave and S-wave impedance before and after oil reservoir development is calculated by elastic impedance inversion method, time shift compressional wave and S-wave impedance difference before and after exploitation, the change of multiple elastic parameter can be finally inversed by, then reservoir parameter is converted to further in conjunction with petrophysical model, as the change of fluid saturation and pressure.

Chen Xiaohong etc. (2006) propose a kind of non-linear time lapse seismic inverting based on hybrid optimization algorithm and petrophysical model and obtain speed or in length and breadth wave impedance in length and breadth, and then the method for forecast pressure and saturation degree change.

Sweet sharp lamps (2010) etc. carry out twice elastic impedance inverting by adopting identical inverted parameters, realize four-dimensional elastic impedance inverting, and this result is applied to the deposit dynamic monitoring of NW Hebei, result shows that elastic impedance conversion only occurs near producing well, can reflect the fluid saturation change of oil reservoir to a certain extent.

But present inventor finds by the combine with technique such as the prestack time lapse seismic inverting of coupling and fluid factor detection can be determined remaining oil distribution, and improve the precision determining remaining oil distribution result.

During concrete enforcement, as shown in Figure 2, the elastic parameter model of each earthquake-capturing time point can be set up by following steps:

Step 1: adopt Geological Modeling to set up the geologic model of oil reservoir, shale index, porosity data body are provided; Research Numerical Simulation Techique is adopted to obtain the water-saturation model of different time.Assuming that shale index, sandstone (quartz) content, factor of porosity that institute's Geologic modeling obtains are respectively V _clay, V _quartzand φ, wherein V _clay+ V _quartz=1; Assuming that numerical reservoir simulation obtain two acquisition time T1 (at least two earthquake-capturing time points namely time earthquake-capturing time point the earliest) and T2 (in described at least two earthquake-capturing time points except time earthquake-capturing time point the earliest other arbitrary earthquake-capturing time points) water saturation be respectively with , the Remaining Oil And Gas reserves of two acquisition times are respectively Q ₁and Q ₂.Here Geologic modeling and numerical simulation can adopt petrel software and eclipse software to complete respectively.

Step 2: adopt K-T model (Kuster and , 1974) and method obtains the bulk modulus (K of dry rock skeleton _d), modulus of shearing (μ _d), expression formula is as formula (1-a):

$\left\{\begin{array}{c}(K_d-K_{\mathrm{solid}})\frac{K_{\mathrm{solid}}+\frac{4}{3}{\mathrm{\μ}}_{\mathrm{solid}}}{K_{\mathrm{solid}}^{*}+\frac{4}{3}{\mathrm{\μ}}_{\mathrm{solid}}}=K_{\mathrm{solid}}({\mathrm{\φ}}_{\mathrm{clay}}{P}^{\mathrm{clay}}+{\mathrm{\φ}}_{\mathrm{quartz}}{P}^{\mathrm{quartz}})\\ ({\mathrm{\μ}}_d-{\mathrm{\μ}}_{\mathrm{solid}})\frac{{\mathrm{\μ}}_{\mathrm{solid}}+{\mathrm{\ζ}}_h}{{\mathrm{\μ}}_d+{\mathrm{\ζ}}_h}={\mathrm{\μ}}_{\mathrm{solid}}({\mathrm{\φ}}_{\mathrm{clay}}{Q}^{\mathrm{clay}}+{\mathrm{\φ}}_{\mathrm{quartz}}{Q}^{\mathrm{quartz}}),\mathrm{\ζ}=\frac{\mathrm{\μ}}{6}\frac{9K+8\mathrm{\μ}}{K+2\mathrm{\μ}}\end{array}\right.---(1-a)$

Wherein: K _solidand μ _solidrepresent the equivalent volume modulus of rock mesostroma respectively, formula (1-b to 1-g) specifically can be adopted to calculate:

K _solid＝0.5*(K _voigt+K _reuss) (1-b)

K _Voigt＝V _clay·K _clay+V _quartz·K _quartz(1-c)

K _Ruess＝(V _clay/K _clay+V _quartz/K _quartz) ^-1(1-d)

μ _solid＝0.5*(μ _Voigt+μ _Reuss) (1-e)

μ _Voigt＝V _clay·μ _clay+V _quartz·μ _quartz(1-f)

μ _Ruess＝(V _Clay/μ _clay+V _quartz/μ _quartz) ^-1(1-g)

φ _quartzand φ _clayrepresent the factor of porosity relevant with clay mineral with quartz respectively:

φ _quartz＝φ·V _quartz(1-h)

φ _clay＝φ·V _clay(1-i)

P ^quartz, Q ^quartz, P ^clay, Q ^clayfor polarization factor, the relevant hole length breadth ratio (α of quartz respectively ₁) hole length breadth ratio (α relevant with shale ₂) relevant, specific formula for calculation is see Gary Mavko (1998) rock physics handbook.K _quartz, μ _quartz, K _clay, μ _clayrepresent bulk modulus, modulus of shearing, the bulk modulus of clay, the modulus of shearing of quartz respectively.

Density (the ρ of dry rock skeleton _d) adopt lower formula (2) to calculate:

ρ _d＝(ρ _quartzV _quartz+ρ _clayV _clay)(1-φ) (2)

α is related to altogether in formula (1-a to 1-i) and formula (2) ₁, α ₂, K _quartz, μ _quartz, ρ _quartzk _clay, μ _clay, ρ _claydeng 8 parameters, these parameter values can first with reference to formula see the given initial value of Gary Mavko (1998) rock physics handbook, then according to velocity of longitudinal wave, shear wave velocity and the density calibration above-mentioned parameter of actual measurement.Above-mentioned calculating and parameter calibration process realize for using for reference existing business software (as Powerlog, Rokdoc).Here the parameter that above-mentioned parameter has been demarcated is supposed.

Step 3: adopt Gassmann equation and other dependent equation to calculate the bulk modulus of saturated rock modulus of shearing, density, velocity of longitudinal wave, shear wave velocity etc.

The bulk modulus of saturated rock and modulus of shearing can adopt the Gassmann equation shown in formula (3) to calculate:

$\left\{\begin{array}{c}{K}_{\mathrm{sat}}=K_d+\frac{{(1-\frac{K_d}{K_{\mathrm{solid}}})}^2}{\frac{\mathrm{\φ}}{K_f}+\frac{1-\mathrm{\φ}}{K_{\mathrm{solid}}}-\frac{K_d}{K_{\mathrm{solid}}^2}}\\ {\mathrm{\μ}}_{\mathrm{sat}}={\mathrm{\μ}}_d\end{array}\right.---\left(3\right)$

Wherein: K _ffor the bulk modulus of fluid, relevant with water saturation, Brie formula (4) can be adopted to calculate:

K _f＝(K _w-K _oil)S _w ^e+K _oil(4)

E is customized parameter, and general value is that the density of 1 ~ 5. saturated rock adopts formula (5) to calculate:

ρ _sat＝ρ _d+ρ _f(1-φ)，ρ _f＝ρ _oil(1-S _w)+ρ _wS _w(5)

K _oiland K _wbe respectively the bulk modulus of oil and water, ρ _oiland ρ _wrespectively with density that is oily and water, these parameters are relevant with temperature, reservoir pressure, output gas oil ratio, salinity etc., circular can, with reference to Gary Mavko (1998) rock physics handbook, also can utilize business software (as Powerlog, Rokdoc) to realize.

The velocity of longitudinal wave V of saturated rock _{p, sat}with shear wave velocity V _{s, sat}formula (6-a and 6-b) is adopted to calculate:

$V_{p,\mathrm{sat}}=\sqrt{\frac{K_{\mathrm{sat}}+(4/3)\·{\mathrm{\μ}}_{\mathrm{sat}}}{{\mathrm{\ρ}}_{\mathrm{sat}}}}---(6-a)$

$V_{s,\mathrm{sat}}=\sqrt{\frac{{\mathrm{\μ}}_{\mathrm{sat}}}{{\mathrm{\ρ}}_{\mathrm{sat}}}}---(6-b)$

During concrete enforcement, as shown in Figure 3, adopt coupling prestack time lapse seismic inverting mode by following steps, obtain the velocity of longitudinal wave of each earthquake-capturing time point, shear wave velocity and density data:

Step 1: carry out the inverting of prestack time lapse seismic according to the elastic parameter model of described each earthquake-capturing time point and wavelet, obtains the theogram (namely synthesizing CDP road collection) (step 1 is the step that the square frame indicating 1 in Fig. 3 comprises) of this earthquake-capturing time point; Such as, according to twice earthquake-capturing time point velocity of longitudinal wave, shear wave velocity and density initial model (i.e. elastic parameter model) and wavelet inverting CDP road collection record respectively.Assuming that the elastic parameter model of twice earthquake-capturing time point is respectively $L_1=(v_p^{T1},v_s^{T1},{\mathrm{\ρ}}^{T1}),L_2=(v_p^{T2},v_s^{T2},{\mathrm{\ρ}}^{T2}),$ W ₁(t) and W ₂t () represents the wavelet that twice earthquake-capturing time point is corresponding, θ respectively _irepresent the incident angle that i-th offset is corresponding, R _pp(θ _i, L ₁, t), R _pp(θ _i, L ₂, t) represent the longitudinal wave reflection coefficient that twice earthquake-capturing time point, i-th incident angle is corresponding respectively, (*) represents convolution operation, and so the theogram of twice earthquake-capturing time point can be expressed as: W ₁(t) * R _pp(θ _i, L _{1, initial}, t) and W ₂* R _pp(θ _i, L _{2, initial}, t), longitudinal wave reflection coefficient can adopt Zoeppritz formula Aki-Richard approximate formula to calculate.As i-th incident angle, a kth sampling point reflection coefficient can be expressed as:

$\begin{array}{c}{R}_{\mathrm{pp}}({\mathrm{\θ}}_i,t_k)\≈\frac{1}{2}(1-4\frac{{v_s}^2}{{v_p}^2}{\sin }^2{\mathrm{\θ}}_i)\frac{({\mathrm{\ρ}}_k-{\mathrm{\ρ}}_{k-1})}{0.5({\mathrm{\ρ}}_k+{\mathrm{\ρ}}_{k-1})}\\ +\frac{{\sec }^2{\mathrm{\θ}}_i}{2}\frac{(v_{p,k}-v_{p,k-1})}{0.5(v_{p,k}-v_{p,k-1})}-4\frac{{v_s}^2}{{v_p}^2}{\sin }^2{\mathrm{\θ}}_i\frac{(v_{s,k}-v_{s,k-1})}{0.5(v_{s,k}-v_{s,k-1})}\end{array}---\left(\text{7}\right)$

Wherein, formula (7) supposes that the elastic parameter change on reflecting interface both sides is little, for getting background value.

Step 2: the residual error calculating the described seismic channel set of each earthquake-capturing time point and the theogram of this earthquake-capturing time point, and residual error corresponding for described at least two earthquake-capturing time points addition is obtained total residual error (step 2 is the step that the square frame indicating 2 in Fig. 3 comprises); Such as, formula (8-a) and (8-b) is adopted to calculate the seismic channel set S of earthquake-capturing time point T1 respectively ₁the theogram W corresponding with earthquake-capturing time point T1 ₁(t) * R _pp(θ _i, L _{1, initial}, residual error J t) ₁and the seismic channel set S of earthquake-capturing time point T2 ₂the theogram W corresponding with earthquake-capturing time point T2 ₂* R _pp(θ _i, L _{2, initial}, residual error J t) ₂:

$J_1=\underset{i=1}{\overset{N}{\mathrm{\Σ}}}{(S_1(i,t_k)-W_1*R_{\mathrm{pp}}({\mathrm{\θ}}_i,L_1))}^T(S_1\left(i\right)-W_1*R_{\mathrm{pp}}({\mathrm{\θ}}_i,L_1))---(8-a)$

$J_2=\underset{i=1}{\overset{N}{\mathrm{\Σ}}}{(S_2(i,t_k)-W_2*R_{\mathrm{pp}}({\mathrm{\θ}}_i,L_2))}^T(S_2\left(i\right)-W_2*R_{\mathrm{pp}}({\mathrm{\θ}}_i,L_2))---(8-b)$

Calculate total residual error:

J＝J ₁+J ₂(8-c)

Step 3: when described total residual error is less than preset value, exports the velocity of longitudinal wave of each earthquake-capturing time point that the inverting of prestack time lapse seismic obtains, shear wave velocity and density data; Such as, judge whether total residual error J is less than preset value, if not then adopting method of conjugate gradient Renewal model and proceeding to the step 1 recalculating theogram; If total residual error J is less than preset value, judge whether the inversion result of two earthquake-capturing time points meets constraint condition (9-a), (9-b) and (9-c) further.If do not met, inversion result is tied on border by force, and carries out loop iteration next time.

L _1,low(k)<L _1,k<L _1,high(k)) (9-a)

L _2,low(k)<L _2,k<L _2,high(k)) (9-b)

$\mathrm{abs}(L_{2,k}-L_{1,k})<\mathrm{\&epsiv;}\&CenterDot;\mathrm{abs}(L_{2,k}^{\mathrm{init}}-L_{1,k}^{\mathrm{init}})---(9-c)$

Wherein, L _{1, low (k)}and L _{1, high (k)}represent lower limit and the upper limit constraint condition of the inversion result of earthquake-capturing time point T1 respectively; L _{2, low (k)}and L _{2, high (k)}represent lower limit and the upper limit constraint condition of the inversion result of earthquake-capturing time point T2 respectively.Lower limit and the upper limit can limit according to initial model, as be no more than initial model ± 25%; The ε factor ratio of difference relative to initial model difference retraining T2 time and T1 time reversal result.

If meet, and reach certain iterations, then export the inversion result of two earthquake-capturing time points, comprise the velocity of longitudinal wave of two earthquake-capturing time points respectively the shear wave velocity of two earthquake-capturing time points , the density of two earthquake-capturing time points and calculate the variable quantity such as velocity of longitudinal wave, shear wave velocity, density of the converse result of twice earthquake-capturing time point with

During concrete enforcement, the velocity of longitudinal wave of each earthquake-capturing time point that can be obtained according to inverting by following formula, shear wave velocity and density data, calculate the fluid factor that each earthquake-capturing time point is corresponding:

DHI＝ρ ²(v _p ²-2.33v _s ²) (10)

Wherein, DHI is the fluid factor that this earthquake-capturing time point is corresponding, and ρ is the density data of this earthquake-capturing time point that inverting obtains, v _pthe velocity of longitudinal wave data of this earthquake-capturing time point that inverting obtains, v _sthe shear wave velocity data of this earthquake-capturing time point that inverting obtains, such as, if calculate the fluid factor DHI of earthquake-capturing time point T1 (at least two earthquake-capturing time points namely time earthquake-capturing time point the earliest) ^t1then in formula (10): ρ is v _pfor v _sfor calculate the fluid factor DHI of earthquake-capturing time point T2 (at least two earthquake-capturing time points namely except time earthquake-capturing time point the earliest other arbitrary earthquake-capturing time points) ^t2time, then the ρ successively in replacement formula (10) is v _pfor v _sfor

And calculate the fluid factor variable quantity between fluid factor corresponding to two earthquake-capturing time points by formula (11):

ΔDHI＝(DHI ^T2-DHI ^T1)/DHI ^T1(11)

Wherein, Δ DHI is fluid factor that in described at least two earthquake-capturing time points, time earthquake-capturing time point is the earliest corresponding and the fluid factor variable quantity between the fluid factor that in described at least two earthquake-capturing time points, other arbitrary earthquake-capturing time points are corresponding except time earthquake-capturing time point the earliest, DHI ^t1the fluid factor that in described at least two earthquake-capturing time points, time earthquake-capturing time point is the earliest corresponding, DHI ^tithe fluid factor that in described at least two earthquake-capturing time points, other arbitrary earthquake-capturing time points are corresponding except time earthquake-capturing time point the earliest, DHI ^t2be DHI ^ti.

After fluid factor variable quantity between the fluid factor that time earthquake-capturing time point is the earliest corresponding at least two earthquake-capturing time points described in calculating with the fluid factor that in described at least two earthquake-capturing time points, other arbitrary earthquake-capturing time points are corresponding except time earthquake-capturing time point the earliest, the Remaining Oil And Gas change of reserves amount in the earthquake-capturing time point the earliest of time at least two earthquake-capturing time points and described at least two earthquake-capturing time points except time earthquake-capturing time point the earliest between other arbitrary earthquake-capturing time points is determined according to fluid factor variable quantity, and the Remaining Oil And Gas reserves corresponding according to time earthquake-capturing time point the earliest in excess oil gas change of reserves amount and described at least two earthquake-capturing time points, determine the distribution of Remaining Oil And Gas.

Concrete, the Remaining Oil And Gas change of reserves amount at least two earthquake-capturing time points described in being determined according to described fluid factor variable quantity by following formula (12) in time earthquake-capturing time point the earliest and described at least two earthquake-capturing time points except time earthquake-capturing time point the earliest between other arbitrary earthquake-capturing time points:

ΔQ＝a·ΔDHI+b (12)

Wherein, Δ DHI is described fluid factor variable quantity, Δ Q is the Remaining Oil And Gas change of reserves amount in described at least two earthquake-capturing time points in time earthquake-capturing time point the earliest and described at least two earthquake-capturing time points except time earthquake-capturing time point the earliest between other arbitrary earthquake-capturing time points, and a, b are constants.Namely Δ Q is the Remaining Oil And Gas reserves Q of earthquake-capturing time point T2 ₂with the Remaining Oil And Gas reserves Q of earthquake-capturing time point T1 ₁difference, a, b are experience factor, obtain according to work area actual conditions matching.

After Remaining Oil And Gas change of reserves amount Δ Q at least two earthquake-capturing time points described in determining in time earthquake-capturing time point the earliest and described at least two earthquake-capturing time points except time earthquake-capturing time point the earliest between other arbitrary earthquake-capturing time points, namely Remaining Oil And Gas reserves that can be corresponding according to time earthquake-capturing time point the earliest in Remaining Oil And Gas change of reserves amount and described at least two earthquake-capturing time points, determine the distribution of Remaining Oil And Gas.Such as, determine that Remaining Oil And Gas change of reserves amount is less than the first preset value and the region that the Remaining Oil And Gas reserves that in described at least two earthquake-capturing time points, time earthquake-capturing time point is the earliest corresponding are greater than the second preset value is the region that Remaining Oil And Gas distributes, concrete, such as, the Remaining Oil And Gas reserves Q of earthquake-capturing time point T1 ₁be greater than the second preset value, and the region that the Remaining Oil And Gas change of reserves amount Δ Q determined is less than the first preset value is exactly the large regions of earthquake-capturing time point T2 Remaining Oil And Gas distribution potentiality.

Be that Daqing oil field time lapse seismic block is for example is to describe the method for above-mentioned employing coupling prestack time lapse seismic inverting determination Remaining Oil And Gas distribution in detail below with test site, this work area principal lithologic is sand shale, have passed through long-term waterflooding, enter high water-cut stage, remaining oil sporadicly distributes, prediction difficulty is large, and inherence, work area acquires twice three dimensional seismic data in 2007 and 2010 respectively, and namely at least two earthquake-capturing time points are for 2007 and 2,010 two earthquake-capturing time points.Concrete the method comprises the steps:

Step 1: in conjunction with Geologic modeling, numerical reservoir simulation and rock physics modeling method set up the end of the year 2007 and the end of the year 2010 two earthquake-capturing time points velocity of longitudinal wave, shear wave velocity and density model (i.e. elastic parameter model).

Specifically comprise the following steps: (a) establishes static reservoir model by Geological Modeling, obtain shale index model (V _clay), quartz content model (V _quartz) and porosity model (φ); By numerical reservoir simulation obtain the end of the year 2007 and the end of the year 2010 two earthquake-capturing time points water-saturation model with with remaining oil reserves Q in 2007 ²⁰⁰⁷.

B () adopts the KT model shown in formula (1-a) to calculate the elastic parameter model of dry rock skeleton.

(c) adopt formula (3)-(5) calculate the end of the year 2007 and the end of the year 2010 elastic parameter model ( ); And calculate the difference of two earthquake-capturing time point elastic parameter models.

Step 2: by time lapse seismic inverting obtain the end of the year 2007 and the end of the year 2010 two earthquake-capturing time points elastic parameter inversion result ( ).Inverting process flow diagram as shown in Figure 3.In refutation process, elastic parameter model be have employed to the hard constraint of 25%, by the span of inversion result control initial model ± 25% within, difference constraint factor ε value is 1, namely requires that the difference span of the difference of inversion result and initial model is suitable.The velocity of longitudinal wave of 2007 and 2010, shear wave velocity and inversion of Density result is obtained according to inverting; And calculate the velocity of longitudinal wave to 3 years in 2010, shear wave velocity and variable density amount in 2007.

Step 3: the fluid factor relative variation calculating 2007 and 2010 according to prestack time lapse seismic inversion result, and determine remaining oil distribution REGION OF WATER INJECTION OILFIELD.

Specifically comprise the following steps: (a) is according to formula (10) and (11) Fluid Computation factor and relative variation (Δ DHI) thereof.

Statistics shows, there is following linear relationship between test site inner fluid factor relative variation and digital-to-analogue change of reserves amount:

ΔQ＝0.5526·ΔDHI+0.559 (13)

B () determines the remaining oil change of reserves amount (Δ Q) of 2007 to 2010 according to formula (13).

C () was according to digital-to-analogue remaining oil reserves (Q in 2007 ²⁰⁰⁷) and the remaining oil change of reserves amount (Δ Q) of 2007 to 2010, determine remaining oil distribution REGION OF WATER INJECTION OILFIELD, determine that the principle of REGION OF WATER INJECTION OILFIELD is: within 2007, remaining oil reserves are higher than preset value, and 2007 to 2010 3 years remaining oil change of reserves amounts are less than the position of preset value, it is the region that current remaining oil distribution potentiality are large.

According to the determination result of the remaining oil distribution REGION OF WATER INJECTION OILFIELD that said process is determined, carry out perforations adding operation, actual production proves, determination result coincidence rate is 90%.

Based on same inventive concept, additionally provide a kind of device adopting the distribution of coupling prestack time lapse seismic inverting determination Remaining Oil And Gas in the embodiment of the present invention, as described in the following examples.Because the principle adopting the device of coupling prestack time lapse seismic inverting determination Remaining Oil And Gas distribution to deal with problems is similar with the method adopting the prestack time lapse seismic inverting determination Remaining Oil And Gas that is coupled to distribute, therefore the enforcement of the device of coupling prestack time lapse seismic inverting determination Remaining Oil And Gas distribution is adopted see the enforcement of the method for employing coupling prestack time lapse seismic inverting determination Remaining Oil And Gas distribution, part can be repeated and repeat no more.Following used, term " unit " or " module " can realize the software of predetermined function and/or the combination of hardware.Although the device described by following examples preferably realizes with software, hardware, or the realization of the combination of software and hardware also may and conceived.

Fig. 4 is a kind of structured flowchart of the device of the employing coupling prestack time lapse seismic inverting determination Remaining Oil And Gas distribution of the embodiment of the present invention, as shown in Figure 4, comprise: model building module 401, coupling prestack time lapse seismic inverting module 402, computing module 403 and determination module 404, be described this structure below.

Model building module 401, at least for two earthquake-capturing time points, sets up the elastic parameter model of each earthquake-capturing time point respectively;

Coupling prestack time lapse seismic inverting module 402, is connected with model building module 401, for adopting coupling prestack time lapse seismic inverting mode, obtains the velocity of longitudinal wave of each earthquake-capturing time point, shear wave velocity and density data;

Computing module 403, be connected with coupling prestack time lapse seismic inverting module 402, for the velocity of longitudinal wave of each earthquake-capturing time point of obtaining according to inverting, shear wave velocity and density data, calculate the fluid factor that each earthquake-capturing time point is corresponding, and the fluid factor variable quantity between the fluid factor that described in calculating, time earthquake-capturing time point is the earliest corresponding at least two earthquake-capturing time points with the fluid factor that in described at least two earthquake-capturing time points, other arbitrary earthquake-capturing time points are corresponding except time earthquake-capturing time point the earliest;

Determination module 404, is connected with computing module 403, for according to described fluid factor variable quantity, determines the distribution of Remaining Oil And Gas.

In one embodiment, described coupling prestack time lapse seismic inverting module 402, comprising: prestacking forward modeling unit, for carrying out prestacking forward modeling according to the elastic parameter model of described each earthquake-capturing time point and wavelet, obtaining the theogram of this earthquake-capturing time point; Residual computations unit, be connected with prestacking forward modeling unit, for calculating the residual error of the described seismic channel set of each earthquake-capturing time point and the theogram of this earthquake-capturing time point, and residual error corresponding for described at least two earthquake-capturing time points addition is obtained total residual error; Output unit, is connected with residual computations unit, for when described total residual error is less than preset value, exports the velocity of longitudinal wave of each earthquake-capturing time point that the inverting of prestack time lapse seismic obtains, shear wave velocity and density data; Or, when described total residual error is less than preset value and the velocity of longitudinal wave of each earthquake-capturing time point of obtaining of prestack time lapse seismic inverting, shear wave velocity and density data meet the default inversion result upper limit constraint condition corresponding with this earthquake-capturing time point and lower limit constraint condition, export the velocity of longitudinal wave of each earthquake-capturing time point that the inverting of prestack time lapse seismic obtains, shear wave velocity and density data.

In one embodiment, described computing module 403, for the velocity of longitudinal wave of each earthquake-capturing time point of being obtained according to inverting by following formula, shear wave velocity and density data, calculates the fluid factor that each earthquake-capturing time point is corresponding: DHI=ρ ²(v _p ²-2.33v _s ²), wherein, DHI is the fluid factor that this earthquake-capturing time point is corresponding, and ρ is the density data of this earthquake-capturing time point that inverting obtains, v _pthe velocity of longitudinal wave data of this earthquake-capturing time point that inverting obtains, v _sthe shear wave velocity data of this earthquake-capturing time point that inverting obtains.

In one embodiment, described computing module 403 is also for by the fluid factor variable quantity between fluid factor corresponding to time earthquake-capturing time point the earliest at least two earthquake-capturing time points described in following formulae discovery with the fluid factor that in described at least two earthquake-capturing time points, other arbitrary earthquake-capturing time points are corresponding except time earthquake-capturing time point the earliest: Δ DHI=(DHI ^ti-DHI ^t1)/DHI ^t1wherein, Δ DHI is fluid factor that in described at least two earthquake-capturing time points, time earthquake-capturing time point is the earliest corresponding and the fluid factor variable quantity between the fluid factor that in described at least two earthquake-capturing time points, other arbitrary earthquake-capturing time points are corresponding except time earthquake-capturing time point the earliest, DHI ^t1the fluid factor that in described at least two earthquake-capturing time points, time earthquake-capturing time point is the earliest corresponding, DHI ^tiit is the fluid factor that in described at least two earthquake-capturing time points, other arbitrary earthquake-capturing time points are corresponding except time earthquake-capturing time point the earliest.

In one embodiment, described determination module 404, comprise: Remaining Oil And Gas change of reserves amount determining unit, for the Remaining Oil And Gas change of reserves amount in the earthquake-capturing time point the earliest of time at least two earthquake-capturing time points described in determining according to described fluid factor variable quantity and described at least two earthquake-capturing time points except time earthquake-capturing time point the earliest between other arbitrary earthquake-capturing time points; Remaining Oil And Gas distribution determining unit, be connected with Remaining Oil And Gas change of reserves amount determining unit, for the Remaining Oil And Gas reserves corresponding according to time earthquake-capturing time point the earliest in described Remaining Oil And Gas change of reserves amount and described at least two earthquake-capturing time points, determine the distribution of Remaining Oil And Gas.

In one embodiment, described Remaining Oil And Gas change of reserves amount determining unit to be determined according to described fluid factor variable quantity by following formula described in Remaining Oil And Gas change of reserves amount at least two earthquake-capturing time points in time earthquake-capturing time point the earliest and described at least two earthquake-capturing time points except time earthquake-capturing time point the earliest between other arbitrary earthquake-capturing time points: Δ Q=a Δ DHI+b, wherein, Δ DHI is described fluid factor variable quantity, Δ Q is the Remaining Oil And Gas change of reserves amount in described at least two earthquake-capturing time points in time earthquake-capturing time point the earliest and described at least two earthquake-capturing time points except time earthquake-capturing time point the earliest between other arbitrary earthquake-capturing time points, a, b is constant.

In one embodiment, described Remaining Oil And Gas distribution determining unit is specifically for determining described Remaining Oil And Gas change of reserves amount and be less than the first preset value and the region that the Remaining Oil And Gas reserves that in described at least two earthquake-capturing time points, time earthquake-capturing time point is the earliest corresponding are greater than the second preset value being the region of Remaining Oil And Gas distribution.

In embodiments of the present invention, for two earthquake-capturing time points, set up the elastic parameter model of each earthquake-capturing time point respectively (such as, Geologic modeling can be adopted, numerical reservoir simulation, the technology such as rock physics modeling), and the inverting of prestack time lapse seismic is carried out to the elastic parameter model of multiple earthquake-capturing time point simultaneously, obtain the velocity of longitudinal wave of each earthquake-capturing time point, shear wave velocity and density data, again according to the velocity of longitudinal wave of each earthquake-capturing time point, shear wave velocity and density data, calculate the fluid factor that this earthquake-capturing time point is corresponding, and the fluid factor variable quantity between fluid factor corresponding to two earthquake-capturing time points, finally by fluid factor variable quantity, determine the distribution of Remaining Oil And Gas, achieve in conjunction with Geologic modeling, numerical reservoir simulation, rock physics modeling, the technology such as the inverting of prestack time lapse seismic and fluid factor detection determine the distribution of Remaining Oil And Gas, with determine compared with the method that Remaining Oil And Gas distributes in prior art, the precision of the Remaining Oil And Gas distribution results determined can be improved.

Obviously, those skilled in the art should be understood that, each module of the above-mentioned embodiment of the present invention or each step can realize with general calculation element, they can concentrate on single calculation element, or be distributed on network that multiple calculation element forms, alternatively, they can realize with the executable program code of calculation element, thus, they can be stored and be performed by calculation element in the storage device, and in some cases, step shown or described by can performing with the order be different from herein, or they are made into each integrated circuit modules respectively, or the multiple module in them or step are made into single integrated circuit module to realize.Like this, the embodiment of the present invention is not restricted to any specific hardware and software combination.

The foregoing is only the preferred embodiments of the present invention, be not limited to the present invention, for a person skilled in the art, the embodiment of the present invention can have various modifications and variations.Within the spirit and principles in the present invention all, any amendment done, equivalent replacement, improvement etc., all should be included within protection scope of the present invention.

Claims (14)

1. adopt a method for coupling prestack time lapse seismic inverting determination Remaining Oil And Gas distribution, it is characterized in that, comprising:

For at least two earthquake-capturing time points, set up the elastic parameter model of each earthquake-capturing time point respectively;

Adopt coupling prestack time lapse seismic inverting mode, obtain the velocity of longitudinal wave of each earthquake-capturing time point, shear wave velocity and density data;

The velocity of longitudinal wave of each earthquake-capturing time point obtained according to inverting, shear wave velocity and density data, calculate the fluid factor that each earthquake-capturing time point is corresponding, and the fluid factor variable quantity between the fluid factor that described in calculating, time earthquake-capturing time point is the earliest corresponding at least two earthquake-capturing time points with the fluid factor that in described at least two earthquake-capturing time points, other arbitrary earthquake-capturing time points are corresponding except time earthquake-capturing time point the earliest;

According to described fluid factor variable quantity, determine the distribution of Remaining Oil And Gas.

2. adopt the method for coupling prestack time lapse seismic inverting determination Remaining Oil And Gas distribution as claimed in claim 1, it is characterized in that, adopt coupling prestack time lapse seismic inverting mode, obtain the velocity of longitudinal wave of each earthquake-capturing time point, shear wave velocity and density data, comprising:

Carry out prestacking forward modeling according to the elastic parameter model of described each earthquake-capturing time point and wavelet, obtain the theogram of this earthquake-capturing time point;

Calculate the residual error of the described seismic channel set of each earthquake-capturing time point and the theogram of this earthquake-capturing time point, and residual error corresponding for described at least two earthquake-capturing time points addition is obtained total residual error;

When described total residual error is less than preset value, export the velocity of longitudinal wave of each earthquake-capturing time point that the inverting of prestack time lapse seismic obtains, shear wave velocity and density data; Or, when described total residual error is less than preset value and the velocity of longitudinal wave of each earthquake-capturing time point of obtaining of prestack time lapse seismic inverting, shear wave velocity and density data meet the default inversion result upper limit constraint condition corresponding with this earthquake-capturing time point and lower limit constraint condition, export the velocity of longitudinal wave of each earthquake-capturing time point that the inverting of prestack time lapse seismic obtains, shear wave velocity and density data.

3. adopt the method for coupling prestack time lapse seismic inverting determination Remaining Oil And Gas distribution as claimed in claim 1, it is characterized in that, the velocity of longitudinal wave of each earthquake-capturing time point obtained according to inverting, shear wave velocity and density data, calculate the fluid factor of each earthquake-capturing time point, comprising:

The velocity of longitudinal wave of each earthquake-capturing time point obtained according to inverting by following formula, shear wave velocity and density data, calculate the fluid factor that each earthquake-capturing time point is corresponding:

DHI＝ρ ²(v _p ²-2.33v _s ²)，

Wherein, DHI is the fluid factor that this earthquake-capturing time point is corresponding, and ρ is the density data of this earthquake-capturing time point that inverting obtains, v _pthe velocity of longitudinal wave data of this earthquake-capturing time point that inverting obtains, v _sthe shear wave velocity data of this earthquake-capturing time point that inverting obtains.

4. adopt the method for coupling prestack time lapse seismic inverting determination Remaining Oil And Gas distribution as claimed in claim 3, it is characterized in that, the fluid factor variable quantity by between fluid factor corresponding to time earthquake-capturing time point the earliest at least two earthquake-capturing time points described in following formulae discovery with the fluid factor that in described at least two earthquake-capturing time points, other arbitrary earthquake-capturing time points are corresponding except time earthquake-capturing time point the earliest:

ΔDHI＝(DHI ^Ti-DHI ^T1)/DHI ^T1，

Wherein, Δ DHI is fluid factor that in described at least two earthquake-capturing time points, time earthquake-capturing time point is the earliest corresponding and the fluid factor variable quantity between the fluid factor that in described at least two earthquake-capturing time points, other arbitrary earthquake-capturing time points are corresponding except time earthquake-capturing time point the earliest, DHI ^t1the fluid factor that in described at least two earthquake-capturing time points, time earthquake-capturing time point is the earliest corresponding, DHI ^tiit is the fluid factor that in described at least two earthquake-capturing time points, other arbitrary earthquake-capturing time points are corresponding except time earthquake-capturing time point the earliest.

5. according to any one of Claims 1-4, adopt the method for coupling prestack time lapse seismic inverting determination Remaining Oil And Gas distribution, it is characterized in that, according to described fluid factor variable quantity, determine the distribution of Remaining Oil And Gas, comprising:

Remaining Oil And Gas change of reserves amount at least two earthquake-capturing time points described in determining according to described fluid factor variable quantity in time earthquake-capturing time point the earliest and described at least two earthquake-capturing time points except time earthquake-capturing time point the earliest between other arbitrary earthquake-capturing time points;

The Remaining Oil And Gas reserves corresponding according to time earthquake-capturing time point the earliest in described Remaining Oil And Gas change of reserves amount and described at least two earthquake-capturing time points, determine the distribution of Remaining Oil And Gas.

6. adopt the method for coupling prestack time lapse seismic inverting determination Remaining Oil And Gas distribution as claimed in claim 5, it is characterized in that, the Remaining Oil And Gas change of reserves amount at least two earthquake-capturing time points described in being determined according to described fluid factor variable quantity by following formula in time earthquake-capturing time point the earliest and described at least two earthquake-capturing time points except time earthquake-capturing time point the earliest between other arbitrary earthquake-capturing time points:

ΔQ＝a·ΔDHI+b，

Wherein, Δ DHI is described fluid factor variable quantity, Δ Q is the Remaining Oil And Gas change of reserves amount in described at least two earthquake-capturing time points in time earthquake-capturing time point the earliest and described at least two earthquake-capturing time points except time earthquake-capturing time point the earliest between other arbitrary earthquake-capturing time points, and a, b are constants.

7. adopt the method for coupling prestack time lapse seismic inverting determination Remaining Oil And Gas distribution as claimed in claim 5, it is characterized in that, the Remaining Oil And Gas reserves corresponding according to time earthquake-capturing time point the earliest in described Remaining Oil And Gas change of reserves amount and described at least two earthquake-capturing time points, determine the distribution of Remaining Oil And Gas, comprising:

Determine that described Remaining Oil And Gas change of reserves amount is less than the first preset value and the region that the Remaining Oil And Gas reserves that in described at least two earthquake-capturing time points, time earthquake-capturing time point is the earliest corresponding are greater than the second preset value is the region that Remaining Oil And Gas distributes.

8. adopt a device for coupling prestack time lapse seismic inverting determination Remaining Oil And Gas distribution, it is characterized in that, comprising:

Model building module, for at least two earthquake-capturing time points, sets up the elastic parameter model of each earthquake-capturing time point respectively;

Coupling prestack time lapse seismic inverting module, for adopting coupling prestack time lapse seismic inverting mode, obtains the velocity of longitudinal wave of each earthquake-capturing time point, shear wave velocity and density data;

Computing module, for the velocity of longitudinal wave of each earthquake-capturing time point of obtaining according to inverting, shear wave velocity and density data, calculate the fluid factor that each earthquake-capturing time point is corresponding, and the fluid factor variable quantity between the fluid factor that described in calculating, time earthquake-capturing time point is the earliest corresponding at least two earthquake-capturing time points with the fluid factor that in described at least two earthquake-capturing time points, other arbitrary earthquake-capturing time points are corresponding except time earthquake-capturing time point the earliest;

Determination module, for according to described fluid factor variable quantity, determines the distribution of Remaining Oil And Gas.

9. adopt the device of coupling prestack time lapse seismic inverting determination Remaining Oil And Gas distribution as claimed in claim 8, it is characterized in that, described coupling prestack time lapse seismic inverting module, comprising:

Prestacking forward modeling unit, for carrying out prestacking forward modeling according to the elastic parameter model of described each earthquake-capturing time point and wavelet, obtains the theogram of this earthquake-capturing time point;

Residual computations unit, for calculating the residual error of the described seismic channel set of each earthquake-capturing time point and the theogram of this earthquake-capturing time point, and obtains total residual error by residual error corresponding for described at least two earthquake-capturing time points addition;

Output unit, for when described total residual error is less than preset value, exports the velocity of longitudinal wave of each earthquake-capturing time point that the inverting of prestack time lapse seismic obtains, shear wave velocity and density data; Or, when described total residual error is less than preset value and the velocity of longitudinal wave of each earthquake-capturing time point of obtaining of prestack time lapse seismic inverting, shear wave velocity and density data meet the default inversion result upper limit constraint condition corresponding with this earthquake-capturing time point and lower limit constraint condition, export the velocity of longitudinal wave of each earthquake-capturing time point that the inverting of prestack time lapse seismic obtains, shear wave velocity and density data.

10. adopt the device of coupling prestack time lapse seismic inverting determination Remaining Oil And Gas distribution as claimed in claim 8, it is characterized in that, described computing module is used for the velocity of longitudinal wave of each earthquake-capturing time point obtained according to inverting by following formula, shear wave velocity and density data, calculates the fluid factor that each earthquake-capturing time point is corresponding:

DHI＝ρ ²(v _p ²-2.33v _s ²)，

Wherein, DHI is the fluid factor that this earthquake-capturing time point is corresponding, and ρ is the density data of this earthquake-capturing time point that inverting obtains, v _pthe velocity of longitudinal wave data of this earthquake-capturing time point that inverting obtains, v _sthe shear wave velocity data of this earthquake-capturing time point that inverting obtains.

11. devices adopting coupling prestack time lapse seismic inverting determination Remaining Oil And Gas to distribute as claimed in claim 10, it is characterized in that, described computing module is also for by the fluid factor variable quantity between fluid factor corresponding to time earthquake-capturing time point the earliest at least two earthquake-capturing time points described in following formulae discovery with the fluid factor that in described at least two earthquake-capturing time points, other arbitrary earthquake-capturing time points are corresponding except time earthquake-capturing time point the earliest:

ΔDHI＝(DHI ^Ti-DHI ^T1)/DHI ^T1，

Wherein, Δ DHI is fluid factor that in described at least two earthquake-capturing time points, time earthquake-capturing time point is the earliest corresponding and the fluid factor variable quantity between the fluid factor that in described at least two earthquake-capturing time points, other arbitrary earthquake-capturing time points are corresponding except time earthquake-capturing time point the earliest, DHI ^t1the fluid factor that in described at least two earthquake-capturing time points, time earthquake-capturing time point is the earliest corresponding, DHI ^tiit is the fluid factor that in described at least two earthquake-capturing time points, other arbitrary earthquake-capturing time points are corresponding except time earthquake-capturing time point the earliest.

12. devices adopting coupling prestack time lapse seismic inverting determination Remaining Oil And Gas to distribute according to any one of claim 8 to 11, it is characterized in that, described determination module, comprising:

Remaining Oil And Gas change of reserves amount determining unit, for the Remaining Oil And Gas change of reserves amount in the earthquake-capturing time point the earliest of time at least two earthquake-capturing time points described in determining according to described fluid factor variable quantity and described at least two earthquake-capturing time points except time earthquake-capturing time point the earliest between other arbitrary earthquake-capturing time points;

Remaining Oil And Gas distribution determining unit, for the Remaining Oil And Gas reserves corresponding according to time earthquake-capturing time point the earliest in described Remaining Oil And Gas change of reserves amount and described at least two earthquake-capturing time points, determines the distribution of Remaining Oil And Gas.

13. devices adopting coupling prestack time lapse seismic inverting determination Remaining Oil And Gas to distribute as claimed in claim 12, it is characterized in that, described Remaining Oil And Gas change of reserves amount determining unit to be determined according to described fluid factor variable quantity by following formula described in Remaining Oil And Gas change of reserves amount at least two earthquake-capturing time points in time earthquake-capturing time point the earliest and described at least two earthquake-capturing time points except time earthquake-capturing time point the earliest between other arbitrary earthquake-capturing time points:

ΔQ＝a·ΔDHI+b，

Wherein, Δ DHI is described fluid factor variable quantity, Δ Q is the Remaining Oil And Gas change of reserves amount in described at least two earthquake-capturing time points in time earthquake-capturing time point the earliest and described at least two earthquake-capturing time points except time earthquake-capturing time point the earliest between other arbitrary earthquake-capturing time points, and a, b are constants.

14. devices adopting coupling prestack time lapse seismic inverting determination Remaining Oil And Gas to distribute as claimed in claim 12, it is characterized in that, described Remaining Oil And Gas distribution determining unit is specifically for determining described Remaining Oil And Gas change of reserves amount and be less than the first preset value and the region that the Remaining Oil And Gas reserves that in described at least two earthquake-capturing time points, time earthquake-capturing time point is the earliest corresponding are greater than the second preset value being the region of Remaining Oil And Gas distribution.