Note: Descriptions are shown in the official language in which they were submitted.
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METHOD FOR HORIZON BINNING AND DERIVING
SEISMIC ATTRRIBUTE FILE FOR AN AREA OF INTEREST
FIELD OF THE INVENTION
The present invention relates to the binning of oil and gas exploration and
production
scientific data for an area of interest and relates to the generation of oil
and gas exploration and
production data attributes.
BACKGROUND OF ME INVENTION
The goal of hydrocarbon exploration is to find porous and permeable geologic
deposits
containing high pore-space saturations of hydrocarbons, under sufficient
pressure to allow some
mode of commercial production. In pursuit of this goal, companies, countries
and individuals
collect and process many types of geophysical and geological data. The data is
often analyzed to
find anomalous zones that can reasonably be attributed to the presence of
hydrocarbons.
The usage of 2D and 3D seismic data anomalies has been a standard practice in
the petroleum
industry since the 1960s. Other geologic and geophysical data anomalies have
beentried, sometimes
successfully, for over a century. These include various graviinetric,
electromagnetic, chemical,
biological and speculative methods.
The usage of anomalies for oil and gas detection has been plagued by several
problems.
First, most remote sensing anomalies (e.g., a 3D seismic amplitude anomaly)
cannot be directly tied
to a rock property that could be measured in the laboratory or using well
logs. Much effort is
expended attempting to tie observed anomalies to known rock responses by
modeling the expected
attribute response or otherwise correlating with a known producing reservoir.
This work is often
based on the experience of the practitioner.
A second problem is that the anomalies themselves are often evaluated or tied
to response
models in a qualitative manner. With qualitative assessment as the basis,
quantitative, objective and
reproducible error analysis has not been possible.
A third problem is that a basic physical property at work in hydrocarbon
reservoirs is that
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both oil and gas are less dense than water. This generally causes oil and gas
to accumulate up-
structure in the pore-space of potential reservoir rocks. The higher water
saturations are found,
generally, down-structure. This separation of saturations is driven by
gravity. When such a
separation of fluid types occurs, flat interfaces, in depth, are expected to
form.
This separation causes numerous possible classes of data attribute response.
First, the
hydrocarbon reservoir will have one response for each hydrocarbon type. The
water-saturated part
of the reservoir may have a second data response and the interfacial area a
third type of attribute data
response. This sequence of responses in the processed attribute data allows
for a simultaneous
analysis of the three classes. In this sequence of responses, neither the
water saturated reservoir
response nor the single component hydrocarbon saturated reservoir response are
expected to vary
with structural position. The transition from one type of fluid saturation to
another, having a
different density, is expected to occur at a single depth or seismic travel
time within the attribute
data set. This change from saturation state to another at a given depth and
location should be
detectable using a quantitative tool.
Another problem is that the strength of many types of data attribute anomalies
is dependent
on the rock physics of the geologic systems. Some anomalies are very evident
in the data. Others
can be very subtle and cause considerable debate. Another associated problem
is that much work
in hydrocarbon exploration continues to be done in areas where the data are
poor, noisy or difficult
to interpret. In areas of good data quality, many high-strength anomalies are
adequately interpreted
by inspection. As the data quality and/or imagining ability of the data
degrade, it can be very
difficult to verify that a legitimate anomaly does or does not exist in a
given set of data, especially
when the rock physics suggests that any meaningful anomaly would be subtle.
The lack of quantification, error analysis, subjectivity of analysis and data
quality issues
cause variations in the appraisal of data anomalies in oil and gas exploration
and production projects.
It is not uncommon for different individuals or companies to examine the same
anomaly and reach
irreconcilably, different conclusions. In many cases, it has not been possible
to explain
quantitatively why the anomaly of one prospect should be "believed or trusted"
more than that of
another prospect. This causes different entities to make drastically different
investment decisions
concerning prospects based on the same underlying data.
The present invention is designed for the quantification and evaluation of
data anomalies in
the search for producible hydrocarbon deposits. It is designed to
simultaneously quantify and
summarize the hydrocarbon reservoir part of the anomaly, the water reservoir
part of the data and
the interfacial zone. The invention addresses the case of multiple hydrocarbon
zones, e.g., gas over
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oil over water. It is designed to specifically test the model wherein gas is
less dense than oil and oil
is less dense than water, with data responses varying by structural position.
This current invention also can be used for the quantification of changes in
lithology, facies,
or rock fabric from one location to another. It is designed to function in
areas of low signal-to-noise
and aid in the determination of data suitability for hydrocarbon detection for
the expected rock
physics environment. This allows the invention to be applied to the detection
of subtle hydrocarbon
related data anomalies.
This invention also is designed to quantify responses and quantify response
uncertainties in
a manner that can be consistently defined, reported and replicated by others.
Quantification and
replication make the output of this invention suitable for quantitative
comparison with rock physics
analyses, petro-physical analyses, response modeling and geologic analyses
(e.g., fit to structure
analysis). This combination of capabilities represents an advance over current
methods.
SUMMARY OF THE INVENTION
The method of the present invention provides a method for horizon binning for
an area of
interest by merging an attribute file with a second horizon file. The method
also entails identifying
an area of interest of the merged file and identifying a time range for a time
horizon file, or a depth
range for a depth horizon file, over which to perform the analysis. The next
step is proposing a
theory that the identified area has a portion contiguous between a hydrocarbon
and water-bearing
area.
The method continues by binning the attribute data within the identified area
of interest using
a file with time or depth values and computing a calculated value for each
time or depth bin. Next,
the method entails creating a plot of the computed value versus the first
value for each bin and
viewing the plot to ascertain if a discontinuity corresponding to a fluid
contact is evident. The
method ends by using a magnitude shift in the attribute statistic of the water
and hydrocarbon
reservoir models to confirm the theory and using the magnitude shift to
determine a boundary
between the water and hydrocarbon reservoir model and the corresponding water
and hydrocarbon
reservoirs for an identified area.
The method for deriving a GrAZ seismic attribute file entails inputting
horizon file data and
then obtaining the gradient of the horizon file, thereby producing a horizon
vector file. The method
next involves inputting attribute file data, indexing from the attribute file
data at corresponding
geographic locations of the horizon file, forming an attribute file, and
obtaining the gradient of the
attribute file thereby producing an attribute vector file. The method ends by
performing a
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compilation of the horizon vector file and the attribute vector to ascertain
if changes are in a
direction towards a surface datum for a narrow time and depth range are
detected and measured.
BRIEF DESCRIPTION OF THE DRAWINGS
A specific embodiment of the method will be described by way of example with
reference
to the accompanying drawings, in which:
FIG 1 is a diagram of the overall method;
FIG 2 depicts the hydrocarbon reservoir interface with a water reservoir;
FIG 3 depicts interfaces formed with a plurality of hydrocarbon types; and
FIG 4 depicts the interface along the water reservoir as alternating between
hydrocarbon
types.
The present method is detailed below with reference to the listed Figures.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS
Before explaining the present method in detail, it is to be understood that
the method is not
limited to the particular embodiments and that it can be practiced or carried
out in various ways.
The present method was conceived to detect the changes in attribute response
when moving
from a water reservoir to a hydrocarbon reservoir in order to determine if
exploration or production
activities should continue in a given area. In addition, the method was
conceived to operate in high
noise, low signal to noise environments, where the data quality is poor. The
method was designed
to operate on subtle hydrocarbon indicators. It was designed to fully
characterize the water reservoir
inner and outer edges and the hydrocarbon inner and outer edges as well as the
interface between
these reservoirs. Finally, the method was also conceived to determine the
errors and uncertainties
in all measurements and data attribute results relative to a given hydrocarbon
reservoir and the
corresponding water reservoir.
The preferred embodiment is a method for horizon binning for an area of
interest. An area
of interest means within the context of this patent application, a closed
polygon, such as a shape with
at least 3 sides, like a triangle, and more preferably a shape having up to N
sides, for a positive
integer N> 2. The closed polygon may have more sides if the area of interest
includes a group or
a set of closed polygons or if more sides are needed to describe the region of
under study.
The area of interest also can be the interior of the closed polygon or the
union of the interiors
of the set of closed polygons. Each closed polygon can be defined using
geographic coordinates
such as latitude-longitude, x-y prospect coordinate system, the x-y field
development coordinate
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system and the internal 3-D seismic survey coordinates, such as line and trace
numbers from a
specific survey.
In addition, an area of interest can be either a geographic area for a
hydrocarbon reservoir,
an associated water reservoir, contiguous combinations of these or
combinations of these with other
reservoirs.
As a first step, an attribute file with attribute values is merged with a
second file. An
attribute file is defined as either a set of compiled seismic reflection data,
such as 3-D data sets in
an area considered to be for oil and gas production, which is then processed
using a defined attribute
generating algorithm, such as instantaneous amplitude, AVO slope, or RMS
amplitude over a
window. A particularly useful defined attribute is the background normalized
root means squared
(RMS) amplitude.
Once the defined attribute generating algorithm is used to process the set of
compiled seismic
reflection data, attribute data associated with a horizon of interest is
extracted using the processed
data. A horizon of interest is a geologic or geophysical surface in the earth
that is considered a good
prospect for oil and gas production. The horizon of interest can be defined by
a time file that is a
set of two way seismic time values depicting the seismic travel time from the
datum to the horizon
of interest and back to the datum.
The datum is the reference elevation from which travel times in a seismic
dataset time file
or interpretation is measured. Alternatively, the datum is the reference
elevation from which depths
for a horizon of interest are measured. The horizon of interest can be defined
by a depth file that is
a set of values that depict the depth from the datum to the horizon of
interest, with increasing depth
values toward the center of gravity of the Earth.
Another attribute file can be a set of compiled seismic velocity data
processed using a
defined attribute generating algorithm and extracted for or in conjunction
with a horizon of interest.
Still another attribute file usable in the method can be a set of geophysical
gravity data extract,
compiled or collected for a horizon of interest. Another usable attribute file
can be a set of
geophysical remote sensing data extracted for a horizon of interest, or a set
of compiled or collected
geologic measurements for a horizon of interest, such as fluid saturation
within a reservoir
formation. Two other attribute files that usable within this method would be a
set of petro-physical
measurements, such as resistively, for a horizon of interest, and a set of
compiled or collected
engineering data, such as initial production rate (IP) for a horizon of
interest.
More specifically, the attribute file can be a set of compiled seismic
reflection data,
processed using a defined attribute generating algorithm and extracted for, in
relation to or in
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conjunction with a horizon of interest or a set of compiled seismic velocity
data processed using a
defined attribute generating algorithm and extracted for or in conjunction
with a horizon of interest.
The attribute file can also be a set of geophysical gravity data extracted,
compiled, or collected for
a horizon of interest or a set of geophysical remote sensing data extracted or
compiled for a horizon
of interest. Finally, the attribute file can also be a set of petro-physical
measurements for a horizon
of interest, a set of compiled or collected engineering data for a horizon of
interest, or any
combination thereof.
The second file can be a time file with time values, such as the seismic
travel time from and
to a horizon of interest in a 3-D seismic data set. Alternatively, the second
file can be a depth file
with depth values, such as the depth from sea level to specific geologic
formation within the Earth.
By merging the attribute file with the second file, a merged file is formed.
In one embodiment of
the method, the merging of the two files is performed using geographic
coordinates such as
longitude-latitude, the x-y prospect coordinate system for an area undergoing
hydrocarbon
prospecting or development, the x-y prospect field development coordinate
system of a field
undergoing hydrocarbon prospecting or development, or 3-D seismic survey
coordinates, such as
line and trace numbers from a specific survey.
Next, an identified area of interest is formed from the merged file. In a
preferred
embodiment, the area of interest is the geographic intersection of the area of
interest and the merged
file. The geographic intersection is created by constructing file sets taken
from the merged file
whose members include, a geographic location G, an attribute at geographic
location G, a horizon
time or depth value at geographic location G where all such geographic
locations G are within the
area of interest.
As a next step in the method, a theory is proposed that has the identified
area having at least
a portion that is contiguous between a hydrocarbon reservoir and a water
reservoir forming an
interface.
The interface of the hydrocarbon reservoir with the water reservoir is
proposed as the furthest
extent of high hydrocarbon saturation in the down structure direction. The
interface is a point of
contact between dissimilar fluids within the pore space. A hydrocarbon
reservoir can have a
plurality of interfaces of hydrocarbon types, such as oil and gas, with a
plurality of water reservoirs.
It is contemplated that the hydrocarbon interface can be a plurality of
layered hydrocarbon types.
The hydrocarbon reservoir interfaces with the water reservoir at the greatest
extent of
hydrocarbon saturation in a down structure direction or at a discontinuity in
hydrocarbon saturation.
The theory also can include the hypothesis that the interface is located at a
single depth, or
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at a depth corresponding to a single two way seismic travel time.
Binning is then performed on the identified area of interest. Binning usable
in this method
is contemplated as traditional numerical binning, with conventional data
parameters, such as bin
starting value, bin ending value, and increments thereof.
The identified area of interest is binned using a first value that is either a
start time value or
a start depth value, and then a second value that is either an end time value
or an end depth value.
Between the first value and second value binning, a plurality of bins are
constructed using specified
increments in either time or depth. An example of a specified increment could
be, 100 feet of depth
or 20 milliseconds of time. It is contemplated that the specified increments
can range in feet from
1 to 500 feet and the specified increments in time can range from 1 to 100
milliseconds.
A calculated value for each bin is formed using any of the following:
a. an average of attribute values within the bin;
b. an average absolute value of the attribute values within the bin;
c. a standard deviation for attribute values within the bin;
d. a maximum of attribute values within the bin;
e. a minimum of attribute values within the bin;
f. a range of attribute values within the bin;
g. a range of attribute absolute values within the bin;
h. a median for attribute values within the bin;
i. a mode for attribute values within the bin;
j. a skewness for attribute values within the bin;
k. a plurality of defined moments for attribute values within the bin; and
1. combinations of these values noted above and the
corresponding uncertainty
of each for each bin.
Next, a diagram or plot is created of the above values by plotting the
computed value relative
to the first value, second value, or mid-point value for each formed bin.
The plot is then viewed to determine if a discontinuity or interface between a
hydrocarbon
reservoir and a water reservoir exists that depicts a fluid contact.
The interface is inferred by considering the area believed to be the water
reservoir and the
area believed to be the hydrocarbon reservoir. Then, the following query is
made: "Are these two
reservoirs distinguishable?". A second query is posed, "Is the change in
magnitude from the water
level to the hydrocarbon level consistent with the change expected from high
water saturation to
high hydrocarbon saturation, thereby confirming the hypothesized theory?". A
third query posed,
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"Is the transition duration in time or depth from the water attribute
magnitude level to the
hydrocarbon attribute magnitude level consistent with the observed structural
dip and expected
reservoir thickness?".
Three outcomes occur with this method:
a. the theory is confirmed that an interface is observed from a water
reservoir
to a hydrocarbon reservoir;
b. no significant difference is found in the area proposed to be
hydrocarbon with
the area proposed to be water, thereby condemning the possibility of further
exploration for hydrocarbons; and
c. the data quality is poor or random such that no determination can be
made
from the presented data as to the existence or lack thereof of a hydrocarbon/
water reservoir interface or of a water-to-hydrocarbon transition in attribute
magnitude levels.
This method is particularly useful in areas where the signal to noise ratio in
the data is
particularly low, in situations where there is more noise than signal in the
data.
The method is better understood with reference to the Figures.
FIG 1 depicts the overall flow of the method. Initially, the horizon and data
attributes are
chosen (Step 110). The horizon is input to the program as a time file or as a
depth file that is
geographically indexed (Step 120) and the data attribute is extracted and
input to the program as a
geographically indexed file (Step 130). The horizon file is merged with the
attribute file using
geographic coordinates (Step 140). This step forms a file termed a merged
file.
The next step, shown in FIG 1, is that a closed polygon and/or a set of closed
polygons are
geographically defined as the area of interest (Step 160). Portions of the
merged files not within the
set of closed polygons are deleted (Step 180) thereby generating an identified
area.
Next, a theory is proposed that within the identified area (Step 200) exists a
fluid interface
caused by hydrocarbons above water or lighter hydrocarbons above denser
hydrocarbons.
The existence of a flat fluid contact separating portions of the reservoir
having different pore
fluid saturations is theorized as the cause of the data attribute anomaly
change from lower to upper
structural positions. The theory is further extended to propose that the
identified area contains some
portion wherein different fluid saturations are contiguous (Step 220).
Next, (i) a range of data in time or depth of the identified area and (ii) the
sequence of bins
for the identified area are specified (Step 240).
The attribute data of the identified area are binned forming a set of binned
data (Step 260).
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Each bin is identified by the time or depth range of the values of the
identified area within the bin.
The statistics to be computed for each bin of the binned data are chosen (Step
280).
The statistics and the uncertainties for each statistic are then computed for
each bin of the
binned data (Step 300).
Next, the statistics for each bin of the binned data are plotted, or otherwise
displayed, with
the uncertainties as a function of bin-center time or depth (Step 320).
Alternatively. The statistics
can be presented as a function of the bin edge in time or depth.
As an optional step, the results of external studies, modeling the geological
attribute
response, geophysical attribute response or engineering attribute response of
the theorized system,
are input to the process (Step 330). In this case, the theorized and modeled
system should address
the geologic, rock physics, pore saturation, data acquisition, data processing
and data presentation
elements of the process as it applies to the identified area at the horizon of
interest.
The statistics and uncertainties for all bins are examined to determine if
they and any input
model results are consistent with the theory of the existence of at least one
interface separating
regions of different pore fluid saturation for fluids of differing densities
(Step 340). This
examination step also determines if the up-structure bin statistics and
uncertainties are consistent
with at least one hydrocarbon response and whether the down-structure bin
statistics and
uncertainties are consistent with a high water saturation response or a
heavier hydrocarbon response.
The range of times or depths (for an input time file or input depth file,
respectively) of the at least
one interface is estimated and corresponding uncertainties are computed (Step
360).
The geographic location (in two dimension (2D) and three dimension (3D)) of
interpreted
interfaces are then computed using the range of locations and uncertainties of
the inferred interfaces
and the horizon of interest within the identified area (Step 370).
Finally, the final output results are written, plotted in map form, and/or
displayed in a 3D
visualization format using an electronic display device (Step 380) and the
final output results are
written, plotted in map form and/or displayed in a 3D visualization format in
a document format
(Step 390).
FIG 2 shows the geometry of a hydrocarbon reservoir 404, a water reservoir 405
and the
interface 406 between the hydrocarbon reservoir and the water reservoir. It is
also possible that 405
can be a heavier hydrocarbon reservoir as compared with hydrocarbon reservoir
404. The datum
surface 400 is the datum from that all depths and times are measured. Element
401 indicates the
direction of increasing depth and/or increasing seismic travel time as
measured from the datum
surface 400.
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The surface 402 gives the bounds of the hydrocarbon/water reservoirs. The
bottom 403 gives
the lower bounds of the hydrocarbon/water reservoirs. Either the top surface
402 or the bottom
surface 403 may serve as a typical horizon of interest. The horizon of
interest may be any surface
defined to be as surface expressible as a one-to-one function of either (or
both) the top surface 402
or the bottom surface 403.
The geologic region of proPosed high water saturation and minimal or no
productive
hydrocarbon saturation 405 is also shown in FIG 2. The interface 406 divides
the two geological
regions, 404 and 405. The interface 406 is normally expected to be flat with
respect to the depth or
time axis 401.
FIG 3 depicts the interface as a plurality of hydrocarbon reservoir types and
water reservoirs
separated by interfaces. The interface is shown with respect to an axis
indicating the direction of
increasing depth and/or increasing seismic travel time 500 from a datum 510.
The bottom layer 504
is predominately a water reservoir containing a high water saturation and
minimal or no productive
hydrocarbon saturation. The layer 501 is a hydrocarbon reservoir containing a
high hydrocarbon
saturation of a type that is less dense than the saturating fluid(s) in the
layer below, 504.
The layer 502 is another hydrocarbon reservoir containing a high hydrocarbon
saturation of
a type that is less dense than the saturating fluid(s) in the layer 501. The
top layer 503 is a
hydrocarbon reservoir containing a high hydrocarbon saturation of a type that
is less dense than the
saturating fluid(s) in the layer 502. It is to be understood that FIG 3
illustrates only one
embodiment, and various reservoirs can form specific layers of the form shown
as 503, 502, 501,
and 504.
FIG 4 depicts the interface between a plurality of hydrocarbon saturation
types along the
water reservoir, separated by permeability barriers or other barriers to fluid
exchange.
The interface is shown with respect to an axis indicating the direction of
increasing depth
and/or increasing seismic travel time 600 from a datum 601. The bottom
reservoir 604 contains a
high water saturation and minimal or no productive hydrocarbon saturation.
Reservoirs, 610, 620,
630, 640, and 650, above the bottom reservoir 604 contain high hydrocarbon
saturation of types less
dense than the saturating fluid(s) found in the bottom reservoir 604. Layer
660 is an interface.
Reservoirs, 610, 620, 630, 640, and 650, are shown as isolated from one
another by
permeability barriers or other barriers to flow.
In FIG 4, the impermeable layers are shown as elements 624, 634, 644, and 654.
These
impermeable layers can be faults, gouge materials, facies changes or similar
geologic elements.
Again, FIG 4 is only one embodiment. Various other elements can form each
specific layer, 604,
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610, 620, 630, 640, and 650.
In discussing this method, several terms require consistent definition. The
water reservoir
is a geologic rock formation having both porosity and permeability and
saturated primarily by water.
The water formation may contain a partial hydrocarbon saturation, but at a
sufficiently low level so
as to preclude economic development.
Similarly, the hydrocarbon reservoir is a geologic rock formation having both
porosity and
permeability and saturated in most cases by a combination of water and
hydrocarbons. The
saturation of hydrocarbons must be sufficiently high so as to allow economic
development. If the
saturation of hydrocarbons does not allow the production of hydrocarbons and
associated water in
quantities that are commercial, the reservoir would not be called a
hydrocarbon reservoir. Typically,
the hydrocarbon reservoir is found up-structure of the water reservoir, which
is located down-
structure. In this discussion, up-structure refers to shallower depths from
the surface within the
earth. Down-structure refers to deeper depths within the earth. In the case of
seismic travel times,
deeper depths correspond to larger absolute value seismic travel times and
shallower depths to
smaller absolute value travel times.
Both depths and seismic travel times are typically measured from a specified
datum. The
datum is a specified surface to which measurements are referenced. The term
deeper means
increasing depth values from the datum toward the center of gravity of the
Earth. Seismic two way
travel times will typically increase for reflections from geologic units in
the general direction of the
center of gravity of the Earth from the datum.
For example, in offshore exploration and production, the datum is typically
taken to be mean
sea level. Depths or seismic times are then referenced to mean sea level as
the datum and increase,
indicating deeper, in a direction toward the center of gravity of the Earth.
In this discussion, the
difference between the center of gravity of the Earth and the centroid center
of the Earth is
considered negligible.
In conjunction with the described method, an embodiment is a method for
deriving a seismic
attribute file. The method addresses the case of multiple hydrocarbon zones,
such as, gas over oil
over water. It is designed to specifically test a model wherein gas is less
dense than oil and oil is less
dense than water, and data responses vary by structural position, but
transition in a narrow range of
depths or two-way seismic times. In a preferred embodiment, the narrow range
would not exceed
5% of the total seismic two-way time or depth range contained within the
horizon file.
Within a portion of the data attribute dataset, characterizing a single
saturating fluid, this
method is designed to verify that the data attribute response is invariant
with respect to structural
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position. The quantification of this invariance and the associated uncertainty
allow baselines to be
established with respect to which the significance of an interfacial signal
can be assessed.
This method is also designed to quantify responses and quantify response
uncertainties in
a manner that can be consistently defined, reported and replicated by others.
Quantification and
replication make the output of this method suitable for quantitative
comparison with rock physics
analyses, petro-physical analyses, response modeling and geologic analyses
(e.g., fit to structure
analysis). This quantification allows this method to be used in those cases
where the hydrocarbon
response is subtle and/or the signal to noise level is low. This combination
of capabilities represents
an advance over current methods.
The preferred embodiment is a method for computing a new data attribute for an
area of
interest. An area of interest means within the context of this patent
application, either a geographic
area for a hydrocarbon reservoir, an associated water reservoir, contiguous
combinations of these
or combinations of these with other reservoirs.
The preferred embodiment also relates to a method for deriving a GrAZ seismic
attribute file.
The method begins by inputting a horizon file and inputting an attribute file.
The attribute file and the horizon file must contain data elements at
corresponding
geographic coordinates. The geographic coordinates can be an X-Y prospect
coordinate system, X-
Y field development system, latitude and longitude, internal 3D seismic survey
coordinates, and
combinations thereof. The data must be sufficiently continuous to allow the
computation of a first
derivative in each coordinate direction in each file, neglecting geographic
edge effects.
The next step involves obtaining the gradient of the horizon file thereby
producing a horizon
vector file, having components, dHl and dH2 at each location G. The first
component, dHl, is the
partial derivative of the horizon depth or seismic two-way time in the first
coordinate direction at
G. The second component, dH2, is the partial derivative of the horizon depth
or seismic two-way
time in the second coordinate direction at G.
The next step involves obtaining the gradient of the attribute file thereby
producing an
attribute vector file, having components, dAtl and dAt2 at each location G.
The first component,
dAtl , is the partial derivative of the attribute value in the first
coordinate direction at G. The second
component, dAt2, is the partial derivative of the attribute value in the
second coordinate direction
at G.
The final step of the method involves performing a compilation of the horizon
vector file and
the attribute vector file to form a combined attribute file, GrAZ. The
combined attribute file is
studied to ascertain if observed changes in the attribute file are in a
direction towards a surface
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datum for a narrow range of time and depth. If any components of either the
horizon vector file or
the attribute vector file do not exist or can not be computed at a location G,
then no member of the
combined attribute file, GrAZ exists at G or is assigned to the location G.
After the compilation is performed, horizon binning, plotting or other
analysis techniques
may be performed to analyze the combined attribute file, GrAZ.
The method can further include the step of using dot product mathematics to
perform the
compilation. The dot product mathematics is a summation at each geographic
location G of the
product of corresponding elements of the horizon vector file and the attribute
vector file at each
geographic location G.
For example, if at a location G, the components of the horizon vector file are
c1H1 and dH2
and if at a location G, the components of the attribute vector file are dAt 1
and dAt2, then the dot
product is the sum of dH I multiplied by dAtl with dH2 multiplied by dAt2. If
any of the quantities
dHl, dH2, dAtl or dAt2 do not exist or cannot be computed as finite real
numbers at a location G,
then a dot product is not performed and no element of the combined attribute
file, GrAZ, exists at
G or is assigned to the location G.
The method contemplates that the horizon file is a time horizon file made of a
set of two-way
seismic time values depicting the seismic travel time from the datum to the
horizon of interest and
back to a datum. In addition, the horizon file can be a depth horizon file
made of a set of values that
depict the depth from a datum to the horizon of interest within the Earth.
The attribute file in the method can one member of the following:
a. a set of compiled seismic reflection data processed using a defined
attribute
generating algorithm, and extracted for a horizon of interest;
b. a set of compiled seismic reflection data processed using a defined
attribute
generating algorithm in conjunction with a horizon of interest;
c. a set of compiled seismic velocity data processed using a defined
attribute
generating algorithm and extracted for a horizon of interest;
d. a set of compiled seismic velocity data processed using a defined
attlibute
generating algorithm in conjunction with a horizon of interest;
e. a set of geophysical gravity data extracted for a horizon of interest;
f. a set of geophysical gravity data compiled for a horizon of interest;
g. a set of geophysical gravity data collected for a horizon of interest;
h. a set of geophysical remote sensing data extracted for a horizon of
interest;
i. a set of geophysical remote sensing data compiled for a horizon of
interest;
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WO 2004/070531 PCT/US2004/000213
j. a set of geophysical gravity data collected for a horizon of interest;
k. a set of compiled geologic measurements for a horizon of interest;
1. a set of collected geologic measurements for a horizon of
interest;
m. a set of petro-physical measurements for a horizon of interest;
n. a set of compiled or collected engineering data for a horizon of
interest; and
o. combinations thereof.
While this method has been described with emphasis on the preferred
embodiments, it
should be understood that within the scope of the appended claims, the method
can be practiced
other than as specifically described herein.
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