This disclosure generally relates to the field of borehole seismic profiling for estimating of properties of the earth formation around a borehole.
Seismic profiling is well known and various devices and various techniques have been described for this purpose. Seismic profiling information, such as VSP information, may be used to estimate properties (such as elastic parameters) of an earth formation surrounding a borehole. Generally, seismic parameters may be determined using the reflection of seismic waves at a boundary between a first layer and a second layer of the earth formation. At a boundary, part of the energy of an incident seismic wave traveling through the first layer may be reflected back to be detected by seismic measurement devices located at the surface or within the first layer. These reflections may provide information regarding the properties of the earth formation. Estimates of seismic parameters of an earth formation based on the seismic profiling information may be limited by the uncertainty of the seismic profiling information. The present disclosure addresses the problem of this uncertainty.
In aspects, the present disclosure relates to the field of borehole seismic profiling for estimating of properties of the earth formation around a borehole. More specifically, the disclosure addresses the problem of increasing geophysical capabilities of vertical seismic profiling (VSP) through using borehole gravity measured in the same boreholes or borehole nearby where VSP information has been acquired.
One embodiment according to the present disclosure includes a method of evaluating an earth formation, the method comprising: estimating at least one parameter of interest of the earth formation using seismic parameters and density information, wherein a processor uses the density information to reduce uncertainty in the seismic parameters.
Another embodiment according to the present disclosure includes an apparatus for evaluating an earth formation, the apparatus comprising: a gravity data log; and a processor configured to estimate at least one parameter of interest of the earth formation using seismic parameters and density information, wherein the processor uses the density information to reduce uncertainty in the seismic parameters.
Examples of the more important features of the disclosure have been summarized rather broadly in order that the detailed description thereof that follows may be better understood and in order that the contributions they represent to the art may be appreciated.
For a detailed understanding of the present disclosure, reference should be made to the following detailed description of the embodiments, taken in conjunction with the accompanying drawings, in which like elements have been given like numerals, wherein:
The present disclosure generally relates to the field of borehole seismic profiling, such as vertical seismic profiling (VSP) for estimating of elastic properties of the earth around a borehole. More specifically, the disclosure addresses the problem of increasing geophysical capabilities of VSP through using borehole gravity measured for the same earth formations for which VSP information has been acquired. The present disclosure is susceptible to embodiments of different forms. There are shown in the drawings, and herein will be described in detail, specific embodiments of the present disclosure with the understanding that the present disclosure is to be considered an exemplification of the principles of the present disclosure and is not intended to limit the present disclosure to that illustrated and described herein.
Herein, the term “vertical seismic profiling” (VSP) relates measurement made in a vertical borehole with seismic measurement device disposed within the borehole and a seismic source at the surface. In one aspect, VSP may relate to any process that creates downgoing and upgoing seismic wavefields within the earth and then records both wavefields simultaneously. Either the source(s) or the receiver(s), or both, must be in the subsurface for these conditions to be satisfied. VSP may be used to estimate seismic parameters of an earth formation.
Herein, the term “AVA” (amplitude variation with angle) analysis relates to a technique which allows us to assess variations in seismic reflection amplitude with changes in angle of incidence. Conventional AVA analysis may be based on Zoeppritz equations. These equations describe the various reflection and transmission coefficients for plane waves as a function of angle of incidence, θ, the elastic constants and the densities of the two halfspaces.
Herein, the term “borehole gravity data” relates to values of vertical and/or horizontal components of gravitational acceleration measured in a borehole. The borehole may be the same or in close proximity to the boreholes where VSP signals have been acquired.
Herein, the term “information” relates to raw data, processed data, direct measurements, indirect measurements, and signals.
Herein, the following relations between elastic constants and wave velocities of P-wave velocity Vp and S-wave velocity Vs hold true:
where
ρ—formation density;
k—bulk modulus of the medium (incompressibility).
λ—1st Lame′ parameter.
μ—2nd Lame′ parameter or rigidity modulus of the medium (shear modulus);
The geophysical capabilities of seismic profiling (such as VSP) may be increased through the use of borehole gravity data. Different components of gravitational acceleration for an earth formation may be measured in the same boreholes where VSP information has been acquired or in boreholes located near VSP boreholes. The gravity information may be used to increase the resolution of VSP and to obtain improved estimates of elastic parameters of the formation surrounding the borehole at different depths. These improvements may be obtained by 1) using density information based on the gravity information as a priori data in combination with VSP information and/or 2) performing a joint inversion of a combination of VSP and gravity information.
A layer of an earth formation may be characterized by the layer's seismic parameters understood by those of skill in the art (P-wave velocity, S-wave velocity, density, etc.) Since an earth formation typically includes more than one homogenous layer, the boundary between two layers may include seismic parameters based on the seismic parameters of the adjacent layers. These boundary seismic parameters may include transmission coefficients, reflectivity coefficients, etc. The density information may include a space distribution of density. Estimates of rock density over a volume extending over hundreds of feet from the borehole may be obtained using the space distribution of density estimated from gravity information.
The use of seismic parameters to estimate at least one parameter of interest of the earth formation may involve inverting the values of the seismic parameters. Parameter of interest may include, but are not limited to, one or more of: i) a P-wave velocity in the first formation layer ii) a P-wave velocity in the second formation layer, iii) a difference between the P-wave velocity in the first formation layer and the P-wave velocity in the second formation layer, iv) an S-wave velocity in the first formation layer, v) an S-wave velocity in the second formation layer, vi) a difference between the S-wave velocity in the first formation layer and the S-wave velocity in the second formation layer vii) a density of the first formation layer, viii) a density of the second formation layer, ix) a difference between the density of the first formation layer and the density of the second formation layer, x) elastic constants of the first formation, and xi) elastic constants of the second formation. In one non-limiting embodiment, the procedure of inverting VSP information for the elastic parameters may include estimating reflectivity of the earth formation. Reflectivity may be estimated as a function of incidence angle for each point in the subsurface. In some aspects, true amplitude migration may be used to obtain angle-dependent reflectivity. Inverting VSP information may also include performing a mathematical inversion. The goal of the inversion may be achieved by minimizing the misfit between the angle-dependent reflectivity information and synthetic information obtained from numerical modeling of Zoeppritz equations.
Improved density information regarding a formation may allow for better inversion of seismic information. AVA analysis may not provide density information with adequate accuracy for the desired quality of VSP measurements. Density information for the formation surrounding a borehole may be obtained through an number of techniques, including, but not limited to, one or more of: i) gamma density logging, ii) acoustic density logging, and iii) borehole gravity logging.
Gamma density logging and acoustic density logging may provide a shallow depth of investigation (several inches to several feet), while the density information obtained from the borehole gravity logging may relate to large areas far from the borehole (hundreds of feet). The depth of investigation of borehole gravity logging may be comparable to the area covered by VSP measurement. The borehole gravity log information may include at least one of: i) vertical gravity component information and ii) horizontal gravity component information. A non-limiting embodiment of an apparatus configured to obtain density information for the earth formation is described below.
The gravimeter 100 may be a multi-component device with a predetermined orientation, such as an angular orientation. The gravimeter 100 may also include control electronics. The control electronics may be in the borehole or in at a surface location. The gravimeter 100 may provide components of the gravity vector that may be known under that local coordinate system of the gravimeter, however, this information may not be usable the orientation of the local coordinate system with respect to a global reference system, or at least a reference system that is valid over a region or volume that includes the earth formation, is unknown.
In some embodiments, the formation evaluation tool 40 may be configured to deploy the gravimeter 100 within the borehole 12 to a fixed position. Here, the gravimeter 100 may be detachable from the formation evaluation tool 40. The precise position of the gravimeter 100 may be estimated using methods well known within the hydrocarbon production community. An example would be to use the depth as measured along the borehole in combination with data from a well survey. At the selected depth, the gravimeter 100 may be positioned against the borehole wall 12, such as by a mechanism like a hydraulic cylinder, and attached to the earth formation or borehole casing by some method known to those skilled in the art of permanent sensing.
Once the borehole gravity information is obtained, it may be combined with VSP information. One method of combining VSP and borehole gravity information may include using the borehole gravity information with the layered earth model to find the density along the borehole, as well as, the density and the difference in the density between every pair of layers (for every interface). Then these values may be used as exact values in inversion of the VSP information through the AVA analysis (the conventional scheme assumes that we know only the mean density). The density of a layer may be obtained using gravity information. The density may be estimated using any mathematical operation known to those of skill in the art for converting gravity information into density information, including, but not limited to, inversion equations.
Another method for combining VSP and borehole gravity information may include a joint inversion, where VSP and borehole gravity information are inverted together. Mathematically, this combined inversion assumes a minimization of the combined goal functional misfit. In some embodiments, the joint inversion method may use a solution obtained by the VSP inversion only method as a starting point.
Greater precision in density information for portions of the earth formation far from the borehole, which may be obtained using borehole gravity information, may improve the accuracy of the AVA analysis. The accuracy of AVA analysis may be understood in terms of conditional uncertainty, where the uncertainty of indicators like Δ(VP/VS) improve when Δρ is given with higher accuracy.
Suppose that the parameters xj, j=n , of the model and the data yi, i=1, . . . , N, are connected by a linear map. The map
(x1, . . . , xn)(y1, . . . , yN) (2)
is called the forward map. If there is sufficient information for determination of the parameters, then the inverse map
(y1, . . . , yN)(x1, . . . , xn) (3)
arises. A change of the parameters x=(x1, . . . , xn) by δx=(δx1, . . . , δxn) may result in a change of the data y=(y1, . . . , yN) by δy=(δy1, . . . , δyN). And vice versa, a variation δy of the data may be caused by some variation δx of the parameters.
A measure of the variation of data may be a norm
where .,. denotes the Euclidean inner product and C=(cik) is a positive definite symmetric matrix called the covariance matrix. If all data have the same nature and scale, then C may be taken to be the identity matrix.
Assuming that some (unknown) variation of the parameters δx=(δx1, . . . , δxn) may lead to a variation δy of data and some parameter
is a linear combination of xj. Then, the maximal possible value of |δG|,
over all variations δx=(δx1, . . . , δxn) which lead to variations δy with ∥δy∥≦δ0 is called the uncertainty of_G corresponding to the data uncertainty δ0. Herein, the maximal possible value of |δG| is denoted by δGmax.
Once the dependence of the data on the parameters is linear, i.e.,
the variations δy and δx are connected by the same matrix A=(aij) :
Hence, it suffices to find δGmax for a single value δ0.
Mathematically, the problem of finding the uncertainty δGmax may be stated as the constrained maximization problem
with the positive definite symmetric matrix B=AT CA called the information matrix.
When estimating the uncertainty of some parameter
other parameters may be known with some accuracy (say the parameters with numbers n(1), . . . , n(k)), i.e., their variations do not exceed some values
|δxn(l)|≦δl, l=1, . . . k, (8)
where k≦n is the number of additional conditions.
The maximal value of |δG|,
over all variations δx=(δx1, . . . , δxn) such that |δxn(l)|≦δl, l=1, . . . k, which lead to data variations δy with ∥δy∥≦δ0 is called the conditional uncertainty of G. Herein the maximal value of conditional uncertainty of |δG| is denoted by δGcond.
Mathematically, the conditional uncertainty δGcond may be found by solving the constrained maximization problem
One non-limiting technique for solving the constrained maximization problem includes a general maximization problem arising in conditional linear uncertainty analysis solution. For example, to determine the uncertainty of parameter
while k conditions are imposed on the parameters with numbers n(1), . . . , n(k), 0≦k≦n. The generic problem requiring solution may be
where x is substituted for δx for purposes of illustrating the generic solution.
Denoted by U the set on which the maximum of f(x)=|G| is sought; i.e.,
U={x:
CAx, Ax
=δ
0
2
, |x
n(l)|≦δl, l=1, . . . , k}.
The set U is closed and bounded; therefore, f(x) attains its greatest value on U. However, finding the greatest value on such a set straightforwardly is not a simple problem. We will represent U as the union of simpler sets on each of which the greatest value can be found by a standard method.
Let
S
0
={x:
CAx, Ax
=δ
0
2} (11)
Let p=0, . . . , k be the number of “active” conditions and let 1≦β(1) < . . . <β(p)≦k be the numbers of the selected conditions. Denoted by Bp may be the set of all integer-valued vectors β=(β(1), . . . , β(p)) with the indicated condition. The set Bp comprises
elements. Extending each β ∈ Bp to a substitution of length k such that) β(p+1)< . . . <β(k), thus keeping the former notation β for the extended vector. For every p=0, . . . , p and β ∈ Bp introduce the set
S
p,β
={x | S
0
:|x
n(β(l))|=δβ(l), l=1, . . . , p, |xn(β(l))|≦δβ(l), l=p+1, . . . , k}. (12)
Each set Sp,β is the union of 2p pieces of (n−p)-dimensional spheres
S
p,β,s
={x ∈ S
0
:x
n(β(l))
=s
lδβ(l), l=1, . . . , p, |xn(β(l)|<δβ(l), l=p+1, . . . , k}. (13)
where vectors s=(s1, . . . , sp) have components sl=±1. There are 2p such vectors with their sets denoted by Σp.
Let Mp,β,s equal the greatest value of f(x) on Sp,β,s if f(x) has the greatest value of this set and −∞ otherwise. Thus,
Now, the remaining question is that of finding the greatest value of f(x) on each Sp,β,s. Note that Sp,β,s is a manifold without boundary on the (n−p)-dimensional sphere
p,β,s
={x ∈ S
0
:x
n(β(l))
=s
lδβ(l), l=1, . . . , p}. (16)
If f(x) attains the greatest value on Sp,β,s, this greatest value may occur only at a critical point (a point at which all partial derivatives are zero). All critical points of f(x) on Sp,β,s may be found using the algorithm described below. If at least one of the critical points belongs to Sp,β,s, then Mp,β,s is set to be the maximum of values of f(x) at these critical points. Otherwise, Mp,β,s=−∞.
Prior to applying the algorithm for finding critical points, the parameters may be rearranged such that the components with “active” conditions come first followed by the components with “inactive” conditions and then the “free” components. This rearrangement may be achieved by using the substitution σ defined as follows:
σ(l)=n(β(l)), l=1, . . . , k, σ(l)=n(l), l=k+1, . . . , n. (17)
Interchanging columns may change the matrix Λ to the new matrix Λσ with entries aijσ=aiσ(j). Also, new variables xjσ=xσ(j) and the new vector gjσ=gσ(j) may be introduced so as to arrive at the following problem: find the critical values of
CA
σ
x
σ
, A
σ
x
σ
=δ02, xlσ=slδβ(l), l=1, . . . , p. (19)
on the set
Herein, when solving for the critical points, the notation will drop the superscript a and denote B=AT CA and dl=slδβ(l). Using these notations, the critical points of the function
on the set
{x:
Bx, x
=δ
0
2
, x
l
=d
l
, l=1, . . . , p} (20)
may be determined.
First, the variables may be separated into two groups: x=(x1, . . . , xp, z1, . . . , zm), where m=n−p, and B may be expressed as a block matrix
where B0 is the (p×p)-matrix, D is the (m×p)-matrix, and C is the (m×m)-matrix. The single value determinant of the matrix C corresponding to the unconstrained variables: z1, . . . , zm: C=UΛUT, where Λ=diag(λ1, . . . , λm), U=(uij) may be calculated, and then the new variables y=UT Z may be introduced. Next,
since UUT=UTU=id.
Using the conditions xl=dl, l=1, . . . , p, and passing to the new variables, the first condition may be transformed
Thus, the problem takes the form
This problem may be solved using the Lagrange multipliers. Let
The critical points are found from the conditions
Express
from the first and insert them into the second:
Solving for α gives
if the expressions under the square roots are positive. If the square roots are negative, then the set on which the critical points are sought is empty and there are no critical points.
Once μ± are defined, two critical points x±=(x1±, . . . , xn±) (in the degenerate case they may coincide) may be obtained, where
After the maximization problem solution has been found, estimating the seismic parameters may proceed. If the reflection coefficients RPP(θ) are known for a number of angles θj, j=1, . . . , m, in some range, and the objective is to determine some parameter G depending on the velocities and densities, for example, the change of the P-impedance ΔIP=IP1−IP2=VP1ρ1−VP2ρ2, then our goal is to estimate the (conditional) uncertainty of G, provided that RPP(θ) and some parameters are known with certain accuracy. This may be accomplished using the parameters:
x1=VP, x2=ΔVP, x3=VS, x4=ΔVX, x5=ρ, x6=Δρ
After selected a set of parameters VP1, VP2, VS1, VS2, ρ1, ρ2 (or point x1, . . . , x6) and passing from the map (x1, . . . , x6)RPP(θj) to its linear approximation and replacing the parameter G with its linear analog, then the variations δx, δRPP, δG are connected by the linear maps as follows:
Thus, the problem is
(some of δl may equal ∞, which means that there may be no information about the corresponding parameter).
The result may depend on the set of parameters VP1, VP2, VS1, VS2, ρ1, ρ2 around which the map is linearized. For this example, there are four real sets of parameters (Table 1). The upper layer is shale and the lower layer is gas saturated sand.
For this example, RPP(θ) is given with an accuracy of 10%; i.e., ∥δRPP∥≦0.1≦RPP∥, and only a priori information is available for the mean values VP, VS, ρ, namely δ1=δ3=δ5=0. Under these conditions, using the above algorithm, the (conditional) uncertainty of the parameters
ΔVP, ΔVS, Δρ, Δ(VP/VS), Δ(VPρ), Δ(VSρ).
result in the four sets of parameters given in Table 2.
The uncertainties of the different parameters may be compared by rescaling. Hence each uncertainty may be divided by its corresponding range width, i.e., the difference between the maximal and minimal possible values of the parameter. If the uncertainty is greater than the range width, then the parameter cannot be determined. The uncertainties of the listed parameters divided by the corresponding range widths are given in Table 3.
Table 3 indicates that uncertainty may depend strongly on the situation. In set 1, the uncertainty of all parameters except Δ(VPρ) are very large. In sets 1, 3, and 4, the change in density exceeds the range width, thus indicating that the density may not be determined through inversion of seismic parameters. Finally, the change in P-impedance Δ(VPρ) may have a lower uncertainty than other uncertainty parameters.
In contrast to the above example, uncertainty of parameters may be determined using additional information about density. Herein, it is assumed that the change of density on the reflecting boundary is known with some accuracy from some other source, for example, from inversion of borehole gravity information. Namely, assuming that δ6=0, . . . , 0.5 (g/cm3) and evaluating again the (conditional) uncertainty of the same parameters.
The results of method 400 using the information from Tables 1-3 may be seen in Tables 4-6. Table 4 shows the improvement of uncertainty due to knowledge of density where the density accuracy is improved from 0.5 g/cm3 to 0.05 g/cm3. Table 5 shows the uncertainty when the density accuracy is 0.05 g/cm3. Table 6 shows the uncertainty for the density accuracy of 0.5 g/cm3. Tables 5 and 6 correspond to the unimproved density accuracy found in Table 2.
Generally, the velocity change parameters ΔVP and ΔVS may show greater improvement than other parameters. While impedance changes Δ(VPρ) and Δ(VSρ) may show less improvement. The degree of improvement may correspond to how much a parameter is affected by accuracy of the density parameter. In some cases, improvement may occur in Δ(VP/VS), which is an indicator of the presence of oil/gas.
As shown in
While the foregoing disclosure is directed to the one mode embodiments of the disclosure, various modifications will be apparent to those skilled in the art. It is intended that all variations be embraced by the foregoing disclosure.
Filing Document | Filing Date | Country | Kind | 371c Date |
---|---|---|---|---|
PCT/RU2011/000259 | 4/22/2011 | WO | 00 | 5/31/2012 |