U.S. patent application number 11/568056 was filed with the patent office on 2011-06-16 for microseismic fracture mapping using seismic source timing measurements for velocity calibration.
This patent application is currently assigned to PINNACLE TECHNOLOGIES, INC.. Invention is credited to Eric Davis, James E. Uhl, James Ward, Norman Warpinski, Chris Wright.
Application Number | 20110141846 11/568056 |
Document ID | / |
Family ID | 35242300 |
Filed Date | 2011-06-16 |
United States Patent
Application |
20110141846 |
Kind Code |
A1 |
Uhl; James E. ; et
al. |
June 16, 2011 |
MICROSEISMIC FRACTURE MAPPING USING SEISMIC SOURCE TIMING
MEASUREMENTS FOR VELOCITY CALIBRATION
Abstract
A system and method for micro seismic fracture mapping using
seismic source timing measurements for velocity calibration (28)
and mapping. The system is deployed and coupled to a wire line (36)
and a seismic source trigger with the sensor and transmitter
coupled to the sensor with transmission of the time value of the
first signal and the receiver and micro seismic velocity analyzer
using receiving and transmitting of the first signal and the
receiving and transmitting of the second signal transmitted to the
analyzer (28) and the micro seismic velocity is calibrated based on
the time difference between the first time value and a second time
value associated with the second signal.
Inventors: |
Uhl; James E.; (Albuquerque,
NM) ; Wright; Chris; (Mill Valley, CA) ;
Davis; Eric; (El Cerrito, CA) ; Ward; James;
(San Francisco, CA) ; Warpinski; Norman;
(Albuquerque, NM) |
Assignee: |
PINNACLE TECHNOLOGIES, INC.
San Francisco
CA
HALLIBURTON ENERGY SERVICES, INC.
Houston
TX
|
Family ID: |
35242300 |
Appl. No.: |
11/568056 |
Filed: |
April 21, 2005 |
PCT Filed: |
April 21, 2005 |
PCT NO: |
PCT/US2005/013622 |
371 Date: |
June 4, 2009 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
60564055 |
Apr 21, 2004 |
|
|
|
Current U.S.
Class: |
367/35 |
Current CPC
Class: |
G01V 1/40 20130101; G01V
1/008 20130101 |
Class at
Publication: |
367/35 |
International
Class: |
G01V 1/40 20060101
G01V001/40 |
Claims
1-10. (canceled)
11. A method for calibrating microseismic velocity, comprising the
acts of: transmitting a first signal through a wireline to trigger
a seismic source; detecting the first signal; identifying a first
time value associated with the first signal; detecting an event
associated with the seismic source; transmitting a second signal
from a first receiver unit to an analyzer, the second signal
associated with the seismic source event; and calibrating a
microseismic velocity based on the time difference between the
first time value and a second time value associated with the second
signal.
12. The method of claim 11, further comprising the act of:
transmitting a third signal from a second receiver unit to the
analyzer, the third signal also associated with the seismic source
event.
13. The method of claim 11, wherein the act of transmitting a first
signal comprises transmitting an electric current through the
wireline, and wherein the act of the detecting the first signal
comprises detects a change in the electric current in the
wireline.
14. The method of claim 11, further comprising the act of filtering
the first signal; and wherein the act of identifying the first time
value comprises generating a high-amplitude timing pulse associated
with the first signal.
15. The method of claim 11, wherein the act of calibrating a
microseismic velocity further comprises performing a ray-tracing
inversion associated with the seismic source event.
16. The method of claim 15 further comprising the act of applying a
general forward model to the ray-tracing inversion.
17. The method of claim 11, further comprising the act of
conducting a grid search to determine a velocity structure of the
event.
18. A computer readable medium containing executable instructions,
which, when executed in a processing system, cause said processing
system to perform operations comprising: transmitting an electric
current through a wireline to trigger a seismic source; receiving
an indicator of a change in the electric current to the first
wireline; identifying a first time value by generating a
high-amplitude timing pulse associated with the signal;
transmitting the first time value; receiving a second signal
associated with the event; and calibrating a microseismic velocity
based on the time difference between the first time value and a
second time value associated with the second signal.
19. A computer readable medium containing executable instructions,
which, when executed in a processing system, cause said processing
system to perform operations comprising: calculating an angle
associated with a microseismic event; estimating a velocity of a
wave associated with the microseismic event; receiving perforation
arrival-time data associated with the microseismic event; updating
the estimated velocity using the perforation arrival-time data;
re-calculating the angle using the updated estimated velocity; and
calculating the velocity using the re-calculated angle.
20. A method of monitoring microseismic events, comprising the acts
of: transmitting a first signal through a wireline to actuate a
seismic source; identifying a time value associated with the first
signal; detecting a microseismic event resulting from actuation of
the seismic source; determining a time difference between the
transmitting of the first signal and the detecting of the
microseismic event; and determining a formation velocity in
reference to the determine time difference.
21. The method of claim 20, wherein the act of identifying a time
value associated with the first signal comprises communicating
information to an analyzer which establishes a time reference for
the first signal.
22. The method of claim 21, further comprising the act of
communicating information associated with the detecting of the
microseismic event to the analyzer, and wherein the determining of
a time difference between the transmitting of the first signal and
the detecting of the microseismic event is performed by the
analyzer.
23. The method of claim 20, wherein the seismic source comprises a
perforating gun.
24. The method of claim 20, wherein the act of detecting a
microseismic event resulting from actuation of the seismic source
comprises using a plurality of receivers to detect the microseismic
event.
25. A method of determining a formation velocity, comprising the
acts of: transmitting a trigger signal through a wireline to
actuate a seismic source, the seismic source located in a first
well; generating a reference signal identifying the time of
transmission of the trigger signal; using a first receiver to
detect a microseismic event resulting from actuation of the seismic
source and to generate a receiver signal indicative of the
microseismic event, the first receiver located in a second well;
determining a time difference between the transmitting of the
trigger signal and the detecting of the first microseismic event
resulting from the seismic source through reference to the
reference signal and the receiver signal; and evaluating the
formation velocity of the formation between the first and second
wells in reference to the determined time difference.
26. The method of claim 25, further comprising the acts of:
communicating the reference signal to an analyzer; and
communicating the receiver signal to the analyzer; and wherein the
act of determining a time difference is performed by the
analyzer.
27. The method of claim 26, wherein the steps of communicating the
reference signal and the receiver signal to the analyzer are each
performed essentially as the signals are generated.
28. The method of claim 25, further comprising the acts of: using a
plurality of receivers to detect the microseismic event, and
determining the average velocity between the seismic source and at
least a portion of the plurality of receivers.
Description
FIELD OF THE INVENTION
[0001] This invention relates generally to microseismic events and,
more particularly, to a method for the in situ determination of the
distribution and orientation of fractures in subterranean
formations.
BACKGROUND OF THE INVENTION
[0002] Seismic data is used in many scientific fields to monitor
underground events in subterranean rock formations. In order to
investigate these underground events, micro-earthquakes, also known
as microseisms, are detected and monitored. Like earthquakes,
microseisms emit elastic waves--compressional ("p-waves") and shear
("s-waves"), but they occur at much higher frequencies than those
of earthquakes and generally fall within the acoustic frequency
range of 200 Hz to more than 2000 Hz. Standard microseismic
analysis techniques locate the sources of the microseismic activity
by fluid injection or hydraulic fracturing. In many gas fields,
permeability is too low to effectively produce gas in economic
quantities. Hydraulic fracturing addresses this problem by
intentionally creating fractures in the gas fields that provide
conduits to enhance gas flow. Fluid is pumped into wells at
sufficient pressure to fracture the rock. The fluid also transports
a propping agent (also known as "proppant") into the fracture. The
proppant, usually sand or ceramic pellets, settles in the fractures
and helps keep the fracture open when the fracturing operation
ceases. Production of gas is accelerated as a result of improved
capability for flow within the reservoir. Similarly, water flooding
of largely expended oil fields seeks to push oil to other wells
where it is produced. Fractures are often created in this process
that direct the oil in a potentially unknown direction. In this
process, water, or possibly steam, is used to increase pressure
and/or temperature to displace the oil to a more favorable
production location.
[0003] Microseismic detection is often utilized in conjunction with
hydraulic fracturing or water flooding techniques to map created
fractures. A hydraulic fracture induces an increase in the
formation stress proportional to the net fracturing pressure as
well as an increase in pore pressure due to fracturing fluid leak
off. Large tensile stresses are formed ahead of the crack tip,
which creates large amounts of shear stress. Both mechanisms, pore
pressure increase and formation stress increase, affect the
stability of planes of weakness (such as natural fractures and
bedding planes) surrounding the hydraulic fracture and cause them
to undergo shear slippage. It is these shear slippages that are
analogous to small earthquakes along faults.
[0004] Microseisms are detected with multiple receivers
(transducers) deployed on a wireline array in one or more offset
well bores. With the receivers deployed in several wells, the
microseism locations can be triangulated as is done in earthquake
detection. Triangulation is accomplished by determining the arrival
times of the various p- and s-waves, and using formation velocities
to find the best-fit location of the microseisms. However, multiple
offset wells are not usually available. With only a single nearby
offset observation well, a multi-level vertical array of receivers
is used to locate the microseisms. Data is then transferred to the
surface for subsequent processing to yield a map of the hydraulic
fracture geometry and azimuth. Once the microseisms are located,
the actual fracture is interpreted within the envelope of
microseisms mapped. However, the precise length, direction, and
height of the created fractures will not be obtainable unless the
microseismic events are accurately detected from beginning to
end.
BRIEF DESCRIPTION OF THE DRAWINGS
[0005] FIG. 1 is a schematic of an embodiment of the present
invention;
[0006] FIG. 2 is a schematic of a transmitter system in one
embodiment of the present invention;
[0007] FIG. 3 is a schematic of a data analysis system in one
embodiment of the present invention;
[0008] FIG. 4 is an illustration of an operational flow of one
embodiment of the present invention; and
[0009] FIG. 5 is a graph of the data generated by one embodiment of
the present invention.
[0010] FIG. 6 is a schematic of a computer system for implementing
one embodiment of the present invention.
DETAILED DESCRIPTION OF THE INVENTION
[0011] The invention relates to microseismic events and, more
particularly, to a method for the in situ determination of the
distribution and orientation of fractures in subterranean
formations. It is understood, however, that the following
disclosure provides many different embodiments or examples.
Specific examples of components and arrangements are described
below to simplify the present disclosure. These are, of course,
merely examples and are not intended to be limiting. In addition,
the present disclosure may repeat reference numerals and/or letters
in the various examples. This repetition is for the purpose of
simplicity and clarity and does not in itself dictate a
relationship between the various embodiments and/or configurations
discussed. Further, the drawings are used to facilitate the present
disclosure, and are not necessarily drawn to scale.
[0012] Referring now to FIG. 1, a partial cutaway view 10 is shown
with a treatment well 18 that extends downward into strata 12,
through one or more geological layers 14a-14e. While wells are
conventionally vertical, the invention is not limited to use with
vertical wells. Thus, the terms "vertical" and "horizontal" are
used in a general sense in their reference to wells of various
orientations.
[0013] The preparation of treatment well 18 for hydraulic
fracturing typically comprises drilling a bore 20. Bore 20 may be
drilled to any desired depth. A casing 22 may be cemented into well
18 to seal the bore 20 from the geological layers 14.
[0014] A perforation timing assembly 28 can be used to conduct
microseismic fracture mapping using seismic source timing
measurements for velocity calibration. In one embodiment,
perforation timing assembly 28 comprises a transmitter system 30
and a data analysis system 32 coupled via a transmitting medium 34,
such as fiber optic cable, wire cable, radio or other conventional
transmission system.
[0015] In one embodiment, transmitter system 30 is attached to a
wireline 36 that is extended into well 18. A seismic source 38 may
be coupled to wireline 36. As one skilled in the art will
appreciate, seismic source 38 may be any type of apparatus capable
of generating a seismic event, for example, a perforating gun,
string shot, primacord wrapped around a perforation gun or other
tool, or any other triggered seismic source. In one embodiment,
seismic source is triggered electrically through wireline 36. For
testing purposes, a perforating gun simulator could be coupled to
wireline 36 in addition to, or in lieu of, perforating gun 38.
[0016] In one embodiment, perforating gun 38 creates perforations
40 through casing 22. While embodiments of the present invention
may be practiced in a cased well, it is contemplated that
embodiments of the present invention may also be practiced in an
uncased well.
[0017] Perforating gun 38 may be raised and lowered within well 18
by adjusting the length of wireline 36. The location of
perforations 40 may be at any desired depth within well 20, but are
typically at the level of a rock formation 16, which may be within
one or more of the geological layers 14a-14e. Rock formation 16 may
consist of oil and/or gas, as well as other fluids and materials
that have fluid-like properties.
[0018] In one embodiment, data analysis system 32 may extend a
wireline 44 into a well 42. One or more receiver units 46 may be
coupled to wireline 44. In one embodiment, an array of receiver
units 46 are coupled to wireline 44. Receiver units 46 preferably
contain tri-axial seismic receivers (transducers) such as geophones
or accelerometers, i.e., three orthogonal geophones or
accelerometers, although for some applications it will not be
necessary that receivers be used for all three directions. The type
of receiver unit chosen will depend upon the characteristics of the
event to be detected. In one embodiment, the characteristic may be
the frequency of the event.
[0019] The desired amount of independent information, as well as
the degree of accuracy of the information to be obtained from a
seismic event will affect the minimum number of receiver units 46
used. In a number of applications, including the hydraulic
fracturing technique, important information includes the elevation
of the source of the microseismic waves with regard to an
individual receiver unit 46, and the distance away from a given
receiver unit 46. Time of origination of seismic event is a
frequently used metric, as well. As shown in FIG. 1, at least one
receiver unit 60 is vertically disposed within well 42 on a
wireline 44. According to certain embodiments of the present
invention, multiple receiver units 46 may be spaced apart on
wireline 44. The distance between individual receiver units 46 in a
multi-unit array is selected to be sufficient to allow a measurable
difference in the time of arrival of acoustic waves from a seismic
event that originates from well 18.
[0020] Well 42 may be laterally spaced from well 18 and may extend
downwardly through rock formation 16. While in many instances only
a single offset well bore is available near the treatment well, it
will be appreciated that multiple wells 42 may exist in proximity
to well 18, and that multiple data analysis systems 32 may be used
in with multiple wells 42. The distance between well 18 and well 42
is often dependent on the location of existing wells, and the
permeability of the local strata. For example, in certain
locations, the surrounding strata may require that well 18 and well
42 to be located relatively close together. In other locations, the
surrounding strata may enable well 18 and well 42 to be located
relatively far apart. It will also be appreciated that well 42 may
contain a casing or be uncased.
[0021] Referring now to FIG. 2, an exemplary transmitter assembly
30 is illustrated. In this embodiment, transmitter assembly 30
includes a sensor or current probe 48, an amplifier 50, a filter
52, a function generator or trigger detection circuits 54, an
oscilloscope 56, and a transmitter 58. Certain embodiments of
transmitter assembly 30 may also include a microphone 62. It is
contemplated by the present invention that some or all of
components of transmitter system 30 could be combined into one or
more computing devices.
[0022] In one embodiment, perforating gun 38 is connected via
wireline 36 to a seismic source trigger 68. In one embodiment,
seismic source 68 trigger is a power supply that provides the
electrical energy to enable perforating gun 28 to create the
perforations in the well. It will be appreciated that some or all
of the sections of wireline 36 may be any type of electrical
connection means suitable for connecting perforating gun 38 to
power supply 68 including, but not limited to, electrical wire,
cable or fiber optic cable. In one embodiment, a firing line 70 may
be used.
[0023] Sensor 48 may be any sensor or sensor probe capable of
measuring the electromagnetic field near an electrical
current-carrying wire or cable or measuring the current itself,
such as the 5200 sensor probe sold by Fluke Corporation of Everett,
Wash. In one embodiment, sensor 48 is placed around either the
center conductor or outer conductor of firing line 70 if the center
conductor can be isolated from the outer conductor. In another
embodiment, a bypass wire may be clamped to the exposed armor of a
section of wireline 36 in two locations and sensor 48 may be placed
around either the bypass wire or the section of wireline 36 that
has been bypassed. If the resistance of the bypass wire is not
significantly higher than the resistance of the armor of wireline
36, enough current may shunted into the bypass wire to allow sensor
48 to detect the current sent from power supply 68 to perforating
gun 38.
[0024] Sensor 48 may also be connected to amplifier 50. Amplifier
50 may be a current probe amplifier, such as the AM503S amplifier
(DC to 50 MHz, 20 A Continuous/50 A Peak, Max. Conductor Diameter
0.15 in) sold by Tektronix of Beaverton, Oreg. Amplifier 50
transmits the signal to filter 52. Filter 52 is any filter system
suitable to reduce the amplitude of any extraneous signals. In one
embodiment, filter 52 has minimum transient distortion to minimize
any delay to the filtering of the signal.
[0025] Filter 52 provides at least two output signals. The first
output signal from filter 52 is sent to transmitter 58 for
transmission via transmission medium 34. The second output signal
from filter 52 is sent to function generator 54. Function generator
54 is a conventional function generator used to detect the filtered
pulse and generate a high-amplitude timing pulse (fidu). In one
embodiment, a preferred function generator 54 has a pulse output of
5V at 1 mS. Transmitter 58 is capable of transmitting the
high-amplitude timing pulse via transmission medium 34.
[0026] In one embodiment, an operator may use oscilloscope 56 to
monitor the filtered signal transmitting from filter 52 and the
output from function generator 54. A test system can also be used
to provide a test signal in order to correctly adjust the settings
for amplifier 50, filter 52, and function generator 54.
[0027] Referring now to FIG. 3, an exemplary data analysis system
32 is illustrated. In this embodiment, data analysis system 32
includes receiver 72, amplifier 74, digital converter 76, analog
signal recorder 78, digital trigger recorder 80, speaker 82,
analyzer 84, and storage memory 86. It is contemplated by the
present invention that some or all of components of data analysis
system 32 could be combined into one or more computing devices.
[0028] When a seismic event occurs, receiver units 60 detect the
seismic waves. Receiver units 60 transmit the detected waves along
signal line 88 to receiver 72. In one embodiment, the detected
waves are amplified using amplifier 74.
[0029] Digital converter 76 is capable of converting the detected
waves into digital signals. Analyzer 84 analyzes the digital
signals to discern properties about the seismic event. A personal
computer may be used to as analyzer 84.
[0030] Additionally, the detected waves may be recorded in original
analog form by analog signal recorder 78. The analog signals may be
stored in storage memory 86, as well as delivered aurally by
speaker 82.
[0031] Storage memory 86 may be such media as a tape backup, hard
drive, CD-ROM, DVD, or the like. A standard file format, such as
the SEG2 format, may be used. In one embodiment, a single
microseismic event may occupy about 286 kilobytes of file space. In
another embodiment, a recording of signals at sampling frequencies
of 4,000 Hz in a continuous mode for four seconds results in about
2 megabytes of file space.
[0032] Referring now to FIG. 4, an exemplary operational flow 400
of an embodiment of the present invention is illustrated. At step
402, a seismic event is initiated. In one embodiment, a power
supply sends an electrical signal to a perforating gun down a well.
In other embodiments, other explosive sources of seismic energy can
also be used. In particular, string shots (primacord wrapped around
a piece of metal) are often used for repeat shots, for cases where
the perforations had already been performed, and for cases where
the treatment well is not cased (usually horizontal wells).
[0033] At step 404, the time of the seismic event is observed. In
one embodiment, the sensor capable of detecting an electrical
signal is coupled to a wire between the power supply and the
perforating gun. The sensor sends out a signal when it detects a
current change in the wire between the power supply and the
perforating gun.
[0034] At step 406, the seismic-event-detected signal may
amplified. At step 408, the signal is filtered to remove noise or
other signals caused by other devices or events, such as the signal
caused by the acoustic safety alarm that is often activated prior
to the triggering of a seismic event.
[0035] At step 410, the seismic-event-detected signal may then be
split. The first split signal may be transmitted to a data analysis
system, step 412. At step 414, a function generator detects the
filtered pulse from the second split signal and generates a
high-amplitude timing pulse. At step 416, the high-amplitude timing
pulse is transmitted to a data analysis system, thereby
establishing the exact time at the seismic event occurred.
[0036] At step 418, the acoustic signal generated by the firing of
perforation gun is detected. The acoustic signal contains both p-
and s-waves. At step 420, the time difference between the
occurrence of the seismic event and the acoustic signal arrival at
receiver units is used to calculate the formation velocity given
the interval distance between the well in which the seismic event
occurred and the well in which the receiver units were located.
[0037] In the perforation-timing procedure of the present
invention, cross-well velocity data is obtained by monitoring the
firing pulse from the receiver-orientation perforations (or string
shots) and recording the timing pulse along with the arrival data.
The timing resolution is normally set by the sample rate of the
data acquisition system. An example of this condition would be
typically 125 to 250 microseconds. From these results, a simple
one-dimensional model of velocities can be extracted and used to
validate, refine, or correct the detailed dipole sonic data or
provide a warning of discrepancies.
[0038] Perforation-timing data can be used to calculate the average
velocities between the perforation and each receiver to correct
events that occur near the perforations. If there is sufficient
information to determine the boundaries of a limited number of
major layers, and if it is assumed that each of the layers has
constant p-wave and s-wave velocities, then the travel time
information can be inverted for velocities in those layers. The
additional information delimiting layers would optimally be
obtained from a dipole sonic log, but could also be determined from
various lithology logs.
[0039] Any wave passing through a layered formation must obey
Snell's law, which for any case is given by
sin .theta. j = V j V j + 1 sin .theta. j + 1 = V j V j + 2 sin
.theta. j + 2 = = V j V j + 1 n sin .theta. j + n ##EQU00001##
where the V.sub.j are the velocities in the layers and the
.theta..sub.j are the incident angles.
[0040] Once one of the angles is known, all of the others can be
computed from Snell's law. To obtain the angles, it is only
necessary to find the takeoff angle (e.g., the angle leaving the
perforation) that gives an arrival at the receiver station. This is
assured by stipulating that r=x.sub.j+x.sub.j+1+x.sub.j+2+ . . .
+x.sub.j+n, for however many layers. The resulting expression for
the takeoff angle can be written in a form that allows for
efficient iterative solution by
tan .theta. j = rV j / [ d j V j + d j + 1 V j + 1 1 - sin 2
.theta. j 1 - ( V j + 1 V j ) 2 sin 2 .theta. j + d j + 2 V j + 2 1
- sin 2 .theta. j 1 - ( V j + 2 V j ) 2 sin 2 .theta. j + + d j + n
V j + n 1 - sin 2 .theta. j 1 - ( V j + n V j ) 2 sin 2 .theta. j ]
##EQU00002##
[0041] In this equation, the d.sub.j are the vertical distances the
wave travels in the j.sup.th layer. It may be the layer thickness
or the distance from the layer boundary to the perforation or the
receiver. The equation is solved by choosing an initial guess for
.theta..sub.j and iterating until it converges on the correct
values. All the other angles are then computed from Snell's law. It
is necessary, however, to test the angles at each iterative step to
assure that angles greater than the critical angle do not
develop.
[0042] However, this calculation requires knowledge of the
velocities, so an initial guess is made (uniform velocity is a
reasonable initial guess) and the angles are calculated. Next, the
perforation arrival-time data are used in a regression to find an
updated estimate of the velocities. The travel time from
perforation to receiver is given by
.DELTA. t i = d j V j cos .theta. j + d j + 1 V j + 1 cos .theta. j
+ 1 + d j + 2 V j + 2 cos .theta. j + 2 + + d j + n V j + n cos
.theta. j + n , ( 3 ) ##EQU00003##
where the .DELTA.t.sub.i refers to the total travel time from the
perforation to the i.sup.th receiver (the total time is obtained
from the timing measurements).
[0043] Velocities can now be determined using a multiple linear
regression that results in a system of equations of the form
1 V 1 i d 1 i 2 cos 2 .theta. 1 i + 1 V 2 i d 1 i d 2 i cos .theta.
1 i cos .theta. 2 i + + 1 V n i d 1 i d ni cos .theta. 1 i cos
.theta. ni = i d 1 i .DELTA. t i cos .theta. 1 i ##EQU00004## 1 V 1
i d 1 i d 2 i cos .theta. 1 i cos .theta. 2 i + 1 V 2 i d 2 i 2 cos
2 .theta. 2 i + + 1 V n i d 2 i d ni cos .theta. 2 i cos .theta. ni
= i d 2 i .DELTA. t i cos .theta. 2 i ##EQU00004.2## ##EQU00004.3##
1 V 1 i d 1 i d nk cos .theta. 1 i cos .theta. ni + 1 V 2 i d 2 i d
ni cos .theta. 2 i cos .theta. ni + + 1 V n i d ni 2 cos 2 .theta.
ni = i d ni .DELTA. t i cos .theta. ni ##EQU00004.4##
for each of the n layers.
[0044] In this case, the subscripts on d refer to the layer number
and then the receiver/perforation pair. That is, for each
perforation, every receiver has a different travel path through the
reservoir and consequently has a different set of d values.
[0045] The resulting system of equations can be solved directly for
the velocities (all of the summation terms are known, given the
previous update or initial guess). Using the new velocities, the
angles are recomputed and the velocities solved again. This is done
until convergence occurs.
[0046] One other situation is the occurrence of head waves, if
sufficient conditions exist. Fortunately, if there is a head wave,
then the incident angles are known (the critical angle occurs at
the head-wave layer) and there is no need to iterate on the takeoff
angle. It is only necessary to extrapolate back to the receiver and
perforation using Snell's law (making sure that the distance
traveled in the head-wave layer is positive) and then checking to
see if the travel times are less through the head-wave layer than
they are through the normal refracted path. If there are head
waves, the system of equations is the same, but another layer is
added for the head-wave layer and additional terms are added to
account for the additional path. Any number of layers can be
checked to determine if head waves are possible.
[0047] Generally, the number of layer velocities that can be
extracted is about 1/3 to 1/2 of the number of perforation-receiver
pairs, with the additional constraint that each layer is
interrogated by at least 2 pairs of data. This analysis is
performed for both p and s waves, if sufficient data are
available.
[0048] If the layers are not uniform, such as in dipping or
pinching beds or near faults, then a more complicated approach can
be employed if the layer geometry is known from other information,
such as nearby wells or surface seismic surveys. In such a case,
the forward-model and grid-search algorithms of Vidale and Nelson
can be employed in a procedure to optimize the velocities such that
they correctly locate the perforation while minimizing residuals
(difference between calculated and observed travel times).
[0049] One procedure for extracting the one-dimensional velocity
model from the perforation timing results is a simplified
ray-tracing inversion, although other approaches may also be
applied. Since there will only be a few ray paths (even if several
perforation shots are monitored), a detailed tomogram of the
velocity structure cannot be developed. However, if standard
geophysical logs can be used to discriminate a limited number of
major layers assumed to have constant velocities within those
layers, then an inversion of the data for velocities can be
obtained using ray-tracing techniques (including head waves). In
more complicated cases, such as where a fault is known to exist and
the fault displacement is known, iteration using a general forward
model (e.g., Vidale) may also be applied.
[0050] FIG. 5 depicts a data set with the perforation fidu and the
seismic arrivals of the perforation signals. The top trace shows
the perforation fidu. The next trace is not used, but the third
trace shows the analog signal from the sensor probe. The remaining
traces are the seismic data from the receiver units in groups of
three. The arrivals are the compressional wave (p-wave) and the
timing difference between the perforation fidu and the arrival can
be used to determine the velocity between the perforation location
and the receiver unit location. In this data set, twelve receiver
units were used.
[0051] Other embodiments of the present invention include
monitoring of any injection processes, such as drill cuttings
injection, steam injection, waterflooding, and other enhanced oil
recovery techniques, as well as the monitoring of general reservoir
behavior during production (reservoir management).
[0052] It will also be understood by those having skill in the art
that one or more (including all) of the elements/steps of the
present invention may be implemented using software executed on a
general purpose computer system or networked computer systems,
using special purpose hardware-based computer systems, or using
combinations of special purpose hardware and software. Referring to
FIG. 6, an illustrative node 600 for implementing an embodiment of
the method is depicted. Node 600 includes a microprocessor 602, an
input device 604, a storage device 606, a video controller 608, a
system memory 610, and a display 614, and a communication device
616 all interconnected by one or more buses 612. The storage device
606 could be a floppy drive, hard drive, CD-ROM, optical drive, or
any other form of storage device. In addition, the storage device
606 may be capable of receiving a floppy disk, CD-ROM, DVD-ROM, or
any other form of computer-readable medium that may contain
computer-executable instructions. Further communication device 916
could be a modem, network card, or any other device to enable the
node to communicate with other nodes. It is understood that any
node could represent a plurality of interconnected (whether by
intranet or Internet) computer systems, including without
limitation, personal computers, mainframes, PDAs, and cell
phones.
[0053] A computer system typically includes at least hardware
capable of executing machine readable instructions, as well as the
software for executing acts (typically machine-readable
instructions) that produce a desired result. In addition, a
computer system may include hybrids of hardware and software, as
well as computer sub-systems.
[0054] Hardware generally includes at least processor-capable
platforms, such as client-machines (also known as personal
computers or servers), and hand-held processing devices (such as
smart phones, personal digital assistants (PDAs), or personal
computing devices (PCDs), for example). Further, hardware may
include any physical device that is capable of storing
machine-readable instructions, such as memory or other data storage
devices. Other forms of hardware include hardware sub-systems,
including transfer devices such as modems, modem cards, ports, and
port cards, for example.
[0055] Software includes any machine code stored in any memory
medium, such as RAM or ROM, and machine code stored on other
devices (such as floppy disks, flash memory, or a CD ROM, for
example). Software may include source or object code, for example.
In addition, software encompasses any set of instructions capable
of being executed in a client machine or server.
[0056] Combinations of software and hardware could also be used for
providing enhanced functionality and performance for certain
embodiments of the disclosed invention. One example is to directly
manufacture software functions into a silicon chip. Accordingly, it
should be understood that combinations of hardware and software are
also included within the definition of a computer system and are
thus envisioned by the invention as possible equivalent structures
and equivalent methods.
[0057] Computer-readable mediums include passive data storage, such
as a random access memory (RAM) as well as semi-permanent data
storage such as a compact disk read only memory (CD-ROM). In
addition, an embodiment of the invention may be embodied in the RAM
of a computer to transform a standard computer into a new specific
computing machine.
[0058] Data structures are defined organizations of data that may
enable an embodiment of the invention. For example, a data
structure may provide an organization of data, or an organization
of executable code. Data signals could be carried across
transmission mediums and store and transport various data
structures, and, thus, may be used to transport an embodiment of
the invention.
[0059] The system may be designed to work on any specific
architecture. For example, the system may be executed on a single
computer, local area networks, client-server networks, wide area
networks, internets, hand-held and other portable and wireless
devices and networks.
[0060] A database may be any standard or proprietary database
software, such as Oracle, Microsoft Access, SyBase, or DBase II,
for example. The database may have fields, records, data, and other
database elements that may be associated through database specific
software. Additionally, data may be mapped. Mapping is the process
of associating one data entry with another data entry. For example,
the data contained in the location of a character file can be
mapped to a field in a second table. The physical location of the
database is not limiting, and the database may be distributed. For
example, the database may exist remotely from the server, and run
on a separate platform. Further, the database may be accessible
across the Internet. Note that more than one database may be
implemented.
[0061] In the foregoing specification, the invention has been
described with reference to specific exemplary embodiments thereof.
It will, however, be evident that various modifications and changes
may be made thereto without departing from the broader spirit and
scope of the invention as set forth in the appended claims. The
specification and drawings are, accordingly, to be regarded in an
illustrative sense rather than a restrictive sense.
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