U.S. patent application number 14/070802 was filed with the patent office on 2014-05-08 for enhanced seismic surveying.
This patent application is currently assigned to SILIXA LTD.. The applicant listed for this patent is Silixa Ltd.. Invention is credited to Mahmoud Farhadiroushan, Daniel Finfer, Tom Parker.
Application Number | 20140126325 14/070802 |
Document ID | / |
Family ID | 49767597 |
Filed Date | 2014-05-08 |
United States Patent
Application |
20140126325 |
Kind Code |
A1 |
Farhadiroushan; Mahmoud ; et
al. |
May 8, 2014 |
ENHANCED SEISMIC SURVEYING
Abstract
Embodiments of the present invention help in the processing and
interpretation of seismic survey data, by correlating or otherwise
comparing or associating seismic data obtained from a seismic
survey with flow information obtained from a well or borehole in
the surveyed area. In particular, embodiments of the present
invention allow for flow data representing a flow profile along a
well that is being monitored by a distributed acoustic sensor to be
determined, such that regions of higher flow in the well can be
determined. For example, in the production zone the well will be
perforated to allow oil to enter the well, but it has not
previously been possible to determine accurately where in the
production zone the oil is entering the well. However, by
determining a flow rate profile along the well using the i)AS then
this provides information as to where in the perforated production
zone oil is entering the well, and hence the location of oil
bearing sands. This location can then be combined or otherwise
correlated, used, or associated with petroleum reservoir location
information obtained from the seismic survey, to improve the
confidence and/or accuracy in the determined petroleum reservoir
location.
Inventors: |
Farhadiroushan; Mahmoud;
(Hertfordshire, GB) ; Parker; Tom; (Hertfordshire,
GB) ; Finfer; Daniel; (Hertfordshire, GB) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Silixa Ltd. |
Elstree |
|
GB |
|
|
Assignee: |
SILIXA LTD.
Elstree
GB
|
Family ID: |
49767597 |
Appl. No.: |
14/070802 |
Filed: |
November 4, 2013 |
Current U.S.
Class: |
367/35 |
Current CPC
Class: |
E21B 47/135 20200501;
G01V 2210/1429 20130101; G01V 2210/644 20130101; G01V 11/00
20130101; G01V 1/40 20130101; G01V 2210/6161 20130101; G01V 1/226
20130101 |
Class at
Publication: |
367/35 |
International
Class: |
G01V 1/30 20060101
G01V001/30 |
Foreign Application Data
Date |
Code |
Application Number |
Nov 2, 2012 |
GB |
1219797.6 |
Nov 5, 2012 |
GB |
1219852.9 |
Claims
1. A method for enhancing seismic survey results, comprising:
receiving seismic data from a seismic survey of an area provided
with a well or borehole arranged to tap an underground reservoir;
monitoring the well or borehole with a distributed acoustic sensor
(DAS); determining the fluid flow from the reservoir along one or
more parts of the well or borehole using acoustic measurements
obtained by the DAS; and combining, for example by correlation,
association or other use, the determined fluid flow data with the
seismic data to improve the confidence or accuracy of determined
characteristics of the underground reservoir.
2. A method according to claim 1, wherein the characteristics
include one or more of the size, depth, extent, volume, and/or
pressure of the reservoir.
3. A method according to claim 1, and further comprising
acoustically illuminating the well or borehole with a controllable
sound source.
4. A method for hydrocarbons recovery, comprising: undertaking
fluid injection into an underground hydrocarbons reservoir provided
with a production well or borehole; and monitoring the production
well or borehole with a distributed acoustic sensor (DAS) to
determine the type of fluid that is being received at one or more
parts of the well or borehole.
5. A method according to claim 4, wherein the monitoring comprises
determining the speed of sound in received fluid at one or more
parts of the well to thereby determine the type of fluid.
6. A method according to claim 4, and further comprising
acoustically illuminating the well or borehole with a controllable
sound source.
7. A method according to claim 4 wherein the injected fluid is any
of water, hydraulic fracturing fluid, or steam.
8. A method according to claim 4, wherein the fluid received at one
or more parts of the well is recovered hydrocarbons, or injected
fluid, depending on location in the well.
9. A method according to claim 4, wherein the fluid injection
further comprises water injection.
10. A method according to claim 4, wherein the fluid injection
further comprises hydraulic fracturing.
11. A method according to claim 4, wherein the fluid injection
further comprises steam assisted gravity drainage (SAGD).
12. A method according to claim 4, wherein the fluid injection
further comprises cyclic steam stimulation (CSS) or high pressure
CSS (HPCSS).
Description
TECHNICAL FIELD
[0001] The present invention relates to a method and system which
provides for enhanced seismic surveying techniques, and in
particular in some embodiments by correlating or otherwise
comparing or associating seismic data obtained from a seismic
survey with flow information obtained from a well or borehole in
the surveyed area.
BACKGROUND TO THE INVENTION AND PRIOR ART
[0002] Seismic surveying for the exploration of hydrocarbon
reserves is well known in the art, and involves the use of
reflection seismology to detect and map geologic features
characteristic of petroleum reservoirs. A large aspect of seismic
surveying is the post-processing and interpretation that is applied
to the obtained seismic data, to identify the presence of oil
bearing sands underneath a trap and seal, and to map the extent and
depth of a detected reservoir. Any significant development that can
help with the post-processing and interpretation of seismic data to
provide improved results can be very commercially valuable.
[0003] In addition, and unrelated to the above, optical fibre based
distributed acoustic sensors (DAS) are known in the art. One high
performance example is the iDAS, available from Silixa Limited, of
Elstree, UK. Further details of the operation of a suitable DAS are
given in WO2010/0136809, which also discloses that distributed
acoustic sensors may be used for in-well applications, in that an
acoustic noise profile can be obtained from along a well, and used
to measure the flow by noise logging at every location along the
well. In addition, the noise spectrum can be used to identify the
phase of the fluid.
[0004] However, one problem that arises in the use of DAS for flow
monitoring is in fluid carrying structures such as wells or
boreholes where the flow is substantially laminar, with few eddies
or other turbulent regions that cause noise. In such a case
acoustic monitoring of the fluid carrying structure is unable to
determine the fluid flow, or the fluid phase, due to the lack of
input information into the sensor. Moreover, in fluid carrying
structures where the flow is sometimes turbulent and sometimes
laminar, the monitoring of such structures with a DAS can result in
large amounts of data, much of which is of little use when no noise
is present.
[0005] Examples of flow carrying structures that are sometimes too
quiet for conventional DAS monitoring are oil wells with low flow
rates, such as late-life production wells in aging fields such as
the North Sea, and shale oil or shale gas wells.
SUMMARY OF THE INVENTION
[0006] Embodiments of the present invention provide a new technique
to help in the processing and interpretation of seismic survey
data, by correlating or otherwise comparing or associating seismic
data obtained from a seismic survey with flow information obtained
from a well or borehole in the surveyed area. In particular,
embodiments of the present invention allow for flow data
representing a flow profile along a well that is being monitored by
a DAS to be determined, such that regions of higher flow in the
well can be determined. For example, in the production zone the
well will be perforated to allow oil to enter the well, but it has
not previously been possible to determine accurately where in the
production zone the oil is entering the well. However, by
determining a flow rate profile along the well using the DAS then
this provides information as to where in the perforated production
zone oil is entering the well, and hence the location of oil
bearing sands. This location can then be combined or otherwise
correlated, used, or associated with petroleum reservoir location
information obtained from the seismic survey, to improve the
confidence and/or accuracy in the determined petroleum reservoir
location.
[0007] In some embodiments, as part of determining the flow rate
along the well the speed of sound along the well is found. This
information itself indicates the type and/or phase of the fluid in
the well, e.g. whether the fluid is oil, gas, water, brine, etc.
This information can be used in enhanced oil recovery (EOR)
production techniques, such as water injection, by informing when
and where in the well water is being received rather than oil. Of
course, the total amount of water compared to oil can be determined
at the surface when the recovered material is processed, but using
the DAS techniques of the present invention it is possible to know
where in the well water is received compared to where oil is
received. This should help inform and direct future water injection
operations.
[0008] In addition, in further embodiments address the problem of
quiet wells making flow detection difficult can be overcome by
making use of a physical effect observed by the present applicants
that externally generated noise can be coupled into a fluid
carrying structure such as a pipe, well, or borehole so as to
artificially acoustically "illuminate" the pipe, well, or borehole,
and allow fluid flow in the structure to be determined. In
particular, in embodiments of the invention externally generated
noise is coupled into the structure being monitored at the same
time as data logging required to undertake the monitoring is
performed. This has three effects, in that firstly the externally
generated sound is coupled into the structure so as to "illuminate"
acoustically the structure to allow data to be collected from which
fluid flow or structural integrity may be determined, and secondly
the amount of data that need be collected is reduced, as there is
no need to log data when the structure is not being illuminated.
Thirdly, there are signal processing advantages in having the data
logging being undertaken only when the acoustic illumination
occurs, in that any data averaging that needs to be performed is
taken only over the (usually short) period of illumination. This
can increase the signal to noise ratio considerably. Thus, in these
embodiments flow profile data and/or speed of sound data for use in
the above techniques can be obtained even from quiet, low flow
wells.
[0009] In view of the above, from one aspect one embodiment
provides a method for enhancing seismic survey results, comprising
receiving seismic data from a seismic survey of an area provided
with a well or borehole arranged to tap an underground reservoir.
The well or borehole is monitored with a distributed acoustic
sensor (DAS), and the fluid flow from the reservoir along one or
more parts of the well or borehole is then determined using
acoustic measurements obtained by the DAS. The determined fluid
flow data may then be combined, for example by correlation,
association or other use, with the seismic data to improve the
confidence or accuracy of determined characteristics of the
underground reservoir.
[0010] In one embodiment the characteristics include one or more of
the size, depth, extent, volume, and/or pressure of the
reservoir.
[0011] Moreover, in one embodiment the well or borehole may be
acoustically illuminated with a controllable sound source.
[0012] Another embodiment according to another aspect provides a
method for enhanced oil recovery, comprising undertaking water
injection into an underground oil reservoir provided with a
production well or borehole, and monitoring the production well or
borehole with a distributed acoustic sensor (DAS) to determine
whether oil or water is being received at one or more parts of the
well.
[0013] In one embodiment of the above aspect the monitoring may
comprise determining the speed of sound in received fluid at one or
more parts of the well to thereby determine the type of fluid.
[0014] Moreover, in one embodiment the well or borehole may be
acoustically illuminated with a controllable sound source.
[0015] Where acoustic illumination is used, this may comprise
determining the generation of an acoustic wave; and at the same
time as the generated acoustic wave is incident on the structure,
sensing, using a distributed acoustic sensor, acoustic energy
coupled into the fluid-flow carrying structure from the incident
generated acoustic wave. Acoustic data corresponding to the sensed
acoustic energy may then be stored, at least temporarily.
[0016] With the above, a "quiet" flow carrying structure may be
deliberately illuminated by the generated acoustic wave, and
acoustic data resulting from the illumination then sensed and
stored for later use.
[0017] For example, in one embodiment the method calculates the
speed of sound in one or more parts of the structure or in the
fluid from the acoustic data. As such, embodiments of the invention
may be used for both fluid phase determination, as well as
structural integrity checking.
[0018] In another embodiment the stored or sensed data may be used
to determine properties of fluid flow in the structure from the
acoustic data. In one preferred embodiment the properties include
the speed of fluid flow in the structure. As such, this embodiment
may be used for fluid flow monitoring purpose.
[0019] For example, in one embodiment the method uses the stored
acoustic data to calculate the speed of sound in the fluid from the
acoustic data. In another embodiment the stored or sensed data may
be used to calculate the speed of fluid flow in the structure from
the acoustic data.
[0020] In one embodiment a processor is provided that is arranged
to plot the acoustic data as a two dimensional space-time image.
The processor then applies a two dimensional Fourier transform to
the space-time image to obtain a transformed image. Gradients may
then be identified in the transformed image, the identified
gradients corresponding to the speed of sound, or at least a
property or derivative thereof, of the coupled acoustic energy.
[0021] In one embodiment the identified gradients indicate the
speed of sound in opposite directions along the flow carrying
structure. This allows the processor to calculate the fluid flow in
dependence on a difference between the respective speeds of sound
in the fluid in the opposite directions.
[0022] In one embodiment the acoustic wave is generated remote from
the structure, whereas in another embodiment the acoustic wave may
be generated next to or within the structure.
[0023] In one embodiment the acoustic wave is generated by a
seismic source, wherein preferably the seismic source is a source
selected from the group comprising: airguns, vibroseis, explosives,
or piezo transducers.
[0024] In another embodiment the acoustic wave is generated by an
internal source to the structure. In particular the acoustic source
may be a mechanism driven by the fluid flow.
[0025] The acoustic wave may take many forms, and may be for
example one of a pseudo random sequence or an impulse.
[0026] In a preferred embodiment acoustic data is not stored
substantially during time periods between the periods when the
acoustic wave is incident on and propagating through the structure.
This reduces the amount of data that is generated and stored by the
DAS.
[0027] In one embodiment the generation of the acoustic wave and
the sensing and storing of acoustic data are synchronised. In
particular, the generation of the acoustic wave may be triggered,
and then the DAS may wait for any propagation delay until the
generated wave is incident on the structure before sensing the
coupled acoustic energy and storing corresponding acoustic
data.
[0028] In the above embodiment the DAS preferably ceases the
storing of acoustic data once the acoustic wave has propagated
along the structure.
[0029] In a particularly preferred embodiment the distributed
acoustic sensor is an optical fibre based sensor. Moreover,
preferably the structure is a pipe, well, or borehole.
[0030] In another aspect an embodiment of the present invention
also provides a fluid-flow carrying structure comprising an
elongate fluid carrying channel through which fluid may flow; and
an acoustic transmission mechanism arranged in use to couple
incident acoustic energy into the fluid flow carrying structure. In
this aspect the fluid flow carrying structure may be specially
adapted to allow illuminating acoustic energy incident from the
outside to be coupled therein, thereby enhancing the acoustic
illumination effect of the present invention.
[0031] In one embodiment the acoustic transmission mechanism
comprises a drum structure having a first surface and a second
surface and an acoustic connection mechanism to conduct acoustic
energy incident on the first surface to the second surface. The
first surface is reactive to incident acoustic waves and vibrates
when such waves are incident thereon. The acoustic vibrations are
passed by the acoustic connection mechanism (such as one or more
linking arms or the like) to the second surface, which is arranged
to radiate the acoustic energy outwards, into the structure, and
thereby couple the energy into the structure.
[0032] In another embodiment the acoustic transmission mechanism
comprises an acoustic transmission rod extending through at least
one part of the structure for transmitting acoustic energy through
the at least one part. In this case incident acoustic vibrations
are passed by the rod into the structure, and thereby coupled into
the structure.
[0033] In some embodiments the structure is a pipe, well, or
borehole, and particularly an oil or gas well.
[0034] Further features and aspects of the invention will be
apparent from the appended claims.
BRIEF DESCRIPTION OF THE DRAWINGS
[0035] Further features and advantages of the present invention
will become apparent from the following description of an
embodiment thereof, presented by way of example only, and by
reference to the drawings, wherein like reference numerals refer to
like parts, and wherein:
[0036] FIG. 1 is a diagram illustrating an example DAS deployment
of the prior art;
[0037] FIG. 2 is a drawing of an example space-time plot of the
data collected by a DAS in a deployment like that of FIG. 1;
[0038] FIG. 3 is a drawing of a 2D Fourier transform (k.omega.
plot) of the space-time plot of FIG. 2;
[0039] FIG. 4 is a graph showing upwards and downwards speed of
sounds in a pipe, (top) together with calculated Doppler shifts
(bottom) that provide fluid velocity measurements;
[0040] FIGS. 5 to 7 are drawings of example kw plots taken at
different times in the same well subject to acoustic illumination
(which occurs in FIG. 6);
[0041] FIGS. 8 to 10 are diagrams illustrating how various noise
sources may be provided in embodiments of the invention;
[0042] FIG. 11 is a flow diagram illustrating the sequence of
operations in embodiments of the invention;
[0043] FIG. 12 is a drawing illustrating possible modifications to
be made to casing of a well to allow the well to be more
acoustically coupled to the surroundings;
[0044] FIG. 13 is a drawing illustrating one of the modifications
of FIG. 12 in more detail;
[0045] FIG. 14 is a drawing illustrating another of the
modifications of FIG. 12 in more detail;
[0046] FIG. 15 is a drawing illustrating how seismic data may be
used in combination with flow data to identify petroleum reservoir
locations;
[0047] FIG. 16 is flow diagram illustrating the steps involved in
the operation of the embodiment of FIG. 15;
[0048] FIGS. 17 and 18 are drawings illustrating a typical water
injection EOR process; and
[0049] FIG. 19 is a flow diagram illustrating the steps involved in
using a DAS to aid EOR water injection processes.
DESCRIPTION OF THE EMBODIMENTS
Overview of Embodiments
[0050] Embodiments of the invention relate to using a distributed
acoustic sensor to determine fluid flow along a well or borehole,
and then combining this information with information relating to
oil reservoir location obtained from a seismic survey of the area
to improve the confidence and/or accuracy of the reservoir location
data. In particular, the seismic survey data may indicate, often in
3D, the location of a reservoir to within the sensing resolution of
the seismic detection array. This may be in the order of 12-25 m,
or more appropriately 20-200 m, depending on wavelength (cf
Cartwright et. al "3D seismic technology: the geological `Hubble`"
Basin Research (2005) No. 17, pp. 1-20). However, the DAS can
provide flow profile data with a much greater resolution, sometimes
down to 1 m in the case of the Silixa iDAS.TM., but often around 5
m. Therefore, supplementing the seismic data with much higher
resolution DAS data indicating flow rates in the well (and hence
where the reservoir is producing) can help to more accurately map
and characterize the location and other properties of the petroleum
reservoir.
[0051] In addition, using the DAS to distinguish between material
and phase of the produced fluid (e.g. oil, water, gas etc) using
speed of sound measurements (which are, as will be seen below, a
precursor to flow rate calculation) can help inform on the efficacy
of EOR techniques such as water injection.
[0052] Finally, the success of DAS-based fluid flow measurements
depends on the presence of audio frequency and sub-audio frequency
noise within the flow. Quiet flows have been seen not to produce
useful k-omega (k-.omega.) data. Ambient noise from the ground
surrounding boreholes can `creep in` to pipes to illuminate them
acoustically, but naturally generated ambient levels are usually
much too low to be detectable by a DAS. To solve this problem some
embodiments of the invention combine a sound source in
synchronization with monitoring using a DAS, so that the sound
source acoustically illuminates the interior of the borehole, and
allows the DAS to log data that can be used to determine the fluid
flow.
[0053] There follows various sections describing how fluid flow may
be determined, firstly more generally, and then in quiet wells
using acoustic illumination techniques. Various techniques for
improving the acoustic illumination are then described, and then
embodiments of the invention relating to combining the fluid flow
profile data with seismic data are described.
[0054] Determination of Fluid Flow
[0055] FIG. 1 illustrates a typical DAS deployment in an oil well.
The well 12 extends through rock strata as shown, and a fibre optic
cable 14 is provided running along the length of the well, in this
case substantially parallel thereto. In other embodiments the cable
may extend along the well in a different manner, for example
wrapped around elements of the well. In this respect, all that is
important is that there is a known relationship between the
different parts of the cable and the different parts of the
well.
[0056] The fibre optic cable 14 is connected to a distributed
acoustic sensor (DAS), such as the Silixa Ltd iDAS, referenced
previously. The DAS is able to record sound incident on the cable
at between 1 m and 5 m resolution along the whole length of the
cable, at frequencies up to around 100 kHz. Hence, monitoring of
the well with the DAS results in a large amount of data, that may
be represented by a two dimensional space-time plot, an example of
which is shown in FIG. 2. Here, the horizontal axis shows "depth",
or distance along the cable, and the left hand vertical axis shows
time. The right hand vertical axis shows a colour chart, with
different colours representing sound of different intensity. Hence,
the 2D space time plot provides a visual record of where on the
cable sound was heard, and at what measurement time.
[0057] In more detail, the DAS system can measure the phase of the
acoustic signal coherently along the fibre optic cable. Therefore,
it is possible to use a variety of methods to identify the presence
of propagating acoustic waves. Digital signal processing can
transform the time and linear space (along the well) into a diagram
showing frequency (.omega.) and wavenumber (k) in k-.omega. space.
A frequency independent speed of sound propagation along the well
will show up as a line in k-.omega. space. FIG. 2 shows the time
and space signal and FIG. 3 shows the corresponding k-.omega.
space. Using the data in FIG. 3, a good fit for the speed of sound
can be calculated, by determining the gradient of the diagonal
lines. The frequency band over which the speed of sound can be
determined is more than sufficient for compositional and flow
characterization. With the DAS system the speed of sound can be
evaluated over a large section of the well and, therefore, measure
the distributed variations of the flow composition and
characteristics along the well. The technique is particularly
powerful for determining the composition of the flow--for example,
gas has a speed of sound of around 600 m/s whereas water has a
speed of sound around 1500 m/s.
[0058] Using k-.omega. analysis the speed of sound can also be
determined throughout the entire length of the well. Importantly,
each of the two diagonal lines shown in the k-.omega. space of FIG.
3 corresponds to the speed of sound either travelling up or down
the well. These two lines can be analysed to reveal the
Doppler-shifted sound speeds for upward and downward propagating
sound within the fluid of interest. FIG. 4 shows the distributed
flow determined in a gas injector based on Doppler shift
measurements for a 30 s sampling. The determined flow speed varies
with depth in the well corresponding to the change in hydrostatic
pressure for a section of tubing with a uniform inner dimension and
a gradually sloped well trajectory. In total the instantaneous and
locally determined flow is roughly within +/-0.3 m/s (that for this
well is 10%) of the actual flow speed. The match to reference
measurements is within the uncertainties of an instantaneous
measurement, the fluid property and the distribution of the
pressure drop within the well.
[0059] In further detail, it is possible to estimate the speed of a
given flow by monitoring the speeds of sound within that flow. In
this analysis, it is assumed that the flow direction is coincident
with the array layout (e.g. the direction of arrival for acoustic
signals is known to be 0 or 180 degrees). The main principle used
is that any sound contained within the flow reaches each
consecutive sensor with a certain delay. Knowledge of the spatial
sampling (i.e. the distribution of the cable along the well) can be
used to calculate speed of sound by taking the ratio of average
inter-sensor time difference of arrival and the average spatial
distance between sensors. This operation can be easily done in the
frequency domain. To perform this operation, one constructs a
space-time plot of the signal across a neighbourhood of sensors.
The 2D Fourier Transform of information this will give a
wavenumber-frequency (k-.omega.) plot.
[0060] If the speed of sound is constant across all frequencies
(i.e. there is no dispersion) then each frequency (.omega.) of a
signal will correspond to a certain wavenumber (k) on the k-.omega.
plot. Thus ideally a space-time signal will be mapped into a single
straight line on the k-.omega. plot. From the wave equation we know
that kc=w, where c is the speed of sound. So estimating the slope
of the line of highest energy on the k-.omega. plot will give us
the speed of sound in the medium.
[0061] Since the waveguide can sustain propagation both along and
against the direction of flow, the k-.omega. plot can show two
slopes for each mode of propagation: one positive and one negative.
As the slope of each of these lines indicates the sound speed in
each direction, the Doppler method can be used to derive the speed
of sound from the 2D FFT according to the well-known method of
analysis below.
[0062] c+=c+v [speed of sound along the flow]
[0063] c-=c-v [speed of sound against the flow]
[0064] c+ and c- are found as slopes on a k-.omega. plot.
Combination of the two equations above gives the flow speed
(Ev.sup.1) as v=(c+-c-)/2.
[0065] In addition, as noted above, the measured speed of sound at
points along the well indicates the composition or phase of the
fluid at that point, due to speed of sound differences dependent on
the material. Hence, the profile of the speed of sound along the
well indicates the material prevalent at each point on the
profile.
[0066] Illumination using Noise Sources
[0067] As noted above, some embodiments of the invention are
directed at determining fluid flow of quiet wells, by using an
acoustic source to "illuminate" the well and allow the DAS to
collect data from which the fluid flow can then be found. It is
therefore necessary to consider the physical mechanism of how
acoustic energy can be coupled into a fluid carrying structure such
as a pipe, well, or borehole.
[0068] Waveguides are systems which exhibit a very high propensity
to direct energy along particular pathways. Pipes are
one-dimensional acoustic waveguides, the acoustic characteristics
of which have been well-analysed within the classical acoustics
literature. As a result of these waveguide properties, acoustic
sources external to pipes can be used to illuminate acoustically
the internal volumes of those pipes even when the source of
interest is external to the pipe. In one embodiment of the present
invention, a source in the vicinity of the pipe, such as a
vibroseis or dropped weight, will drive an acoustic signal into the
ground. As the signal radiates through the ground and encounters
the pipe, acoustic energy will tend to be coupled into the pipe and
be redirected along the pipe primary dimension. An acoustic sensor
array mounted within or along the pipe coincident with the pipe
principal dimension can be used to interpret the speed of sound
within the pipe volume and wall (and, if present, the outer
annulus). Regardless of the relative phase of different acoustic
waves as they enter the pipe, the speeds of sound in both the
forward and reverse directions of propagation can be determined,
and hence flow speed can be observed. One aspect is that the energy
entering the pipe should preferably be below the cutoff frequency
for the waveguide, else energy will not propagate as a plane wave
and wave speed determination will be increased in complexity.
[0069] Potential Noise Sources
[0070] Many different noise sources may be used in embodiments of
the invention which provide for acoustic illumination, as shown in
FIGS. 8 to 10. For example, seismic sources such as seismic source
90 remote from the well, as shown in FIG. 8, or next to or in the
well, as shown in FIG. 9, may be used. 1. Such seismic sources (90,
100) may be airguns, vibroseis, explosives, or piezo transducers
either placed outside the well or in the well.
[0071] In addition, passive sources powered by the flow, for
example a clapper or a spinner 110 with a clicking mechanism
attached may be used, as shown in FIG. 10.
[0072] Additionally, in further embodiments active sources powered
by power harvesting techniques may be used. An example is that the
flow or vibrations in the well may be used to generate power which
is then used to power a device (for example a pulsing piezo).
[0073] With respect to the precise noise signal that may be used,
the use of random or pseudo-random vibroseis-generated signals in a
zero-offset arrangement tandem with a flowing well monitored by a
DAS should allow for sufficient averaging to yield useful flow data
even in nearly silent wells. Noise generated within wells could
also be used for this type of illumination.
[0074] In practice, this would involve bringing a vibroseis up to a
well, and driving it with a pseudo-random signal for a while (maybe
a few minutes) while the DAS acquires data. This could also be done
with other excitations (single pulses, chirps) but pseudo-random is
practically and theoretically the most robust method.
[0075] Method of Operation of Acoustic Illumination
[0076] FIG. 11 illustrates the overall operation of the embodiments
in FIGS. 8 to 10 where acoustic illumination is used to help obtain
the fluid flow. At step 12.2 the acoustic illuminator (i.e. the
sound source, whether seismic or otherwise) is operated. If the
sound source is some (known) distance away then it is necessary to
wait for the illumination acoustic wave to propagate to the site of
the well, pipe, or borehole, as shown at step 12.4. However, if the
sound source is local, then it is not necessary to wait for this
propagation period.
[0077] At the same time as (or just before) the acoustic wave is
incident on the well, pipe, or borehole, the DAS system 10 is
activated to begin logging space-time acoustic data, at step 12.6.
Thus, the DAS begins to record acoustic data representative of the
incident acoustic wave being coupled into the fluid carrying
structure. Once the acoustic energy has been coupled into the
structure and propagated therealong, the data logging can then
stop. Hence, it becomes necessary to log data for only a short
period of time during the actual illumination by the acoustic
source.
[0078] Once the space time data has been obtained, at steps 12.8
and 12.10 the same steps as described above to calculate the speed
of sound in the flowing medium, and then the actual flow speed
itself are performed. These steps may be performed substantially in
real time immediately after the data has been captured, or as a
post-processing step some time later.
[0079] One benefit to using active acoustic illumination in fluid
flow metering in boreholes is the ability to synchronize the flow
measurement with the acoustic source firing. This can greatly
increase the signal to noise ratio of results by allowing averaging
to be calculated using only data known to contain useful acoustic
signal. Quiet periods outside of the time when an acoustic
illumination signal is present are not recorded and hence do not
contribute to the averaged signal. This method also allows for a
significant reduction in the amount of data that needs to be
collected since the period of acoustic illumination represents only
a fraction of the recording time when compared to continuous data
logging.
[0080] For this to be done effectively it is necessary to
synchronize the acoustic source generation with the recording made
by the DAS. In embodiments of the invention this can be done in two
ways. The first method uses an accurately timed trigger signal to
initiate the acoustic source and the DAS data recording at the same
time. Depending on the position of the acoustic source used to
provide the illumination relative to the borehole, delays can be
built into the recording start time to allow for the travel time of
the acoustic waves to the borehole or a specific region of the
borehole. For each source firing a short recording is made and the
flow speed calculated, in between source firings data does not need
to be collected. The second method fires the source at regular
intervals synchronized to an accurate clock signal such as GPS
time. The DAS, which must also be synchronized to the same clock,
records at the same intervals or offset by a certain amount of time
to allow for travel time of the acoustic illumination source
signal
[0081] Results of Acoustic Illumination
[0082] Example results showing fluid flows provided by an
embodiment of the invention using acoustic illumination are shown
in FIGS. 5 to 7, which show k-.omega. plots for a number of
discrete times during an experiment. In this experiment, an
otherwise quiet pipe with fluid flowing therein pipe was struck
with a hammer to provide an acoustic impulse. When k-.omega. plots
are made in the absence of any acoustic illumination (as shown in
FIGS. 5, and 7), the speed of sound cannot be seen. However, when
k-.omega. plots are made during time periods coincident with the
impulse (corresponding to FIG. 6), the speeds of sound
corresponding to the various media within the pipe cross-section
can be seen. As described above, these speeds of sound can be used
to derive (1) the flow speed (2) information concerning the nature
of the fluid and (3) well integrity data.
[0083] As noted, FIGS. 5 to 7 show k-.omega. results are shown for
a cement-lined pipe with a dense acoustic sensor array embedded
within the array.
TABLE-US-00001 Figure Number Time period Condition Summary of
k.omega. plot 5 .sup. 0 s-0.15 Silence No speeds visible 6 0.20
s-0.35 s Impulse Waveguide characteristics introduced by including
fluid sound hammer on pipe speed clearly visible exterior 7 0.40
s-0.55 s Silence No speeds visible
[0084] In summary, therefore, some embodiments of the present
invention provide for the deliberate incidence of an actively
generated acoustic wave onto a fluid flow carrying structure
simultaneous with data logging being undertaken by a DAS that
monitors the structure. The incident acoustic energy couples into
the fluid flow carrying structure and effectively acoustically
propagates along the fluid, allowing speed of sound in the fluid to
be determined, from which fluid flow speed can then be determined.
Many different sound sources either within or without the fluid
flow carrying structure may be used, such as seismic sources, or
flow driven devices.
[0085] Well Adaptation for Acoustic Illumination
[0086] Some further embodiments of the present invention relate to
the adaptation of the fluid flow carrying structure itself so as to
enhance its ability to couple into its interior acoustic energy
incident from the outside. In this respect external acoustic
illumination of the interior of the structure can be enhanced by
coupling into the structure more of the incident energy. Thus, for
example, in the case of an oil or gas well the outer casing of the
well may be adapted by the provision of an acoustic coupling
mechanism arranged to couple into the interior of the well acoustic
energy incident externally. FIGS. 12 to 14 illustrate specific
examples.
[0087] As shown in FIG. 12, the outer casing of a well 12 may be
provided with devices or other adaptations to improve the ability
of the well to couple into its interior incident acoustic energy,
that then travels along the well in waveguide mode, as described
previously. In particular, one such mechanism is a drum type
arrangement 132 which passes from the outside of the well through
the outer cement and casing, into the interior, and which operates
similar to an ear drum to transmit acoustic energy. FIG. 13
illustrates the arrangement in further detail.
[0088] More specifically, in FIG. 13 an acoustic transmission drum
132 is shown, wherein the drum extends in this case through (in
order from outside in the direction inwards) the cement, casing,
annulus, and tubing into the interior of the well. In other
embodiments the drum may only extend through a subset of these
layers, for example, may extend through the cement or casing into,
but not through, the annulus, or through the tubing and annulus
from the casing. In further embodiments individual drums 132 may be
provided in the respective layers, or a subset of the layers of the
well. For example, the tubing layer may be provided with a
respective drum that passes therethrough, and the casing layer may
be provided with a respective drum that passes therethrough. Others
of the layers may also be provided with their own respective drums.
In some embodiments, where one or more drums per layer are
provided, the drums may preferably be in spatial alignment from
layer to layer, such that acoustic energy may be passed from drum
to drum.
[0089] An acoustic transmission drum 132 is shown in more detail in
FIG. 13. The drum includes a first acoustically reactive surface
142, such as a membrane or the like, which is sensitive to incoming
acoustic vibrations such that the vibrations are transferred into
the membrane. A second acoustically reactive surface 144, which may
also be a membrane, is mechanically coupled to the first surface
such that any acoustic vibrations induced in the first surface are
transferred to the second surface. In this respect, the mechanical
coupling 146 may be arranged to amplify the acoustic vibrations
transferred to the second surface, for example by using a linked
arm arrangement with a pivot point arranged to provide a mechanical
advantage. In particular, as shown in FIG. 13, a first arm attached
at one end to the first surface 142 is pivotally attached to a
linking arm. The linking arm is pivotally mounted about a fixed
pivot point, and is pivotally attached at its other end to one end
of a second arm. The second arm is attached at its other end to the
second surface 144. The position of the fixed pivot can be set such
that the acoustic vibrations transferred from first surface to the
second surface are increased or decreased in amplitude.
[0090] Other transfer mechanisms may be used. For example, a
straight-arm linkage (i.e. without the pivots) may be made between
the two surfaces, so that vibrations in the first surface are
directly transferred to the second surface. Such a linkage may
simply comprise a connecting rod connecting the inner surfaces of
the two surfaces.
[0091] In the embodiment of FIG. 13, the outer face of second
surface 144 is located within the main body of the well, in direct
contact with any fluid flowing therethrough. Therefore, acoustic
vibrations can be transferred directly into the fluid, to then
propagate up and down the fluid carrying structure, as described
previously, and as shown.
[0092] The operation of the arrangement is as follows. External
acoustic vibrations incident on the first surface are transferred
to the first surface, and then, via the linkage mechanism, to the
second surface. The acoustic vibration of the second surface is
then coupled into the fluid in the structure, and propagates up and
down the structure as if the structure were a waveguide, as
described previously.
[0093] A second acoustic coupling mechanism is shown in FIGS. 12
and 14. This mechanism comprises rods 134 which extend from the
casing through the cement layer and into the surrounding rock
strata. On FIG. 12 the rods are not shown to scale, and as an
example may be a few (2-3) to several (20-30) centimetres in
length, although other lengths may be used. As shown in FIG. 14,
the rods are coupled through the cement, casing, annulus and tubing
into the well interior, and are provided on their inner ends with
vibration surfaces 152 to transmit any acoustic vibrations in the
rods into the fluid in the well. The rods may be firmly mounted
such that they cannot move, or alternatively may be slightly sprung
mounted (not shown), such that they are able to move in and out in
their elongate direction, as shown in FIG. 14.
[0094] The operation of the arrangement of FIG. 14 is as follows.
External acoustic vibrations in the surrounding rock strata and
incident on the rods are transferred to the through the rods into
the interior of the structure, and via the vibration surfaces into
the fluid flowing therethrough. The acoustic vibration of vibration
surfaces is coupled into the fluid in the structure, and propagates
up and down the structure as if the structure were a waveguide, as
described previously.
[0095] In variations of the embodiment of FIG. 14, the rods may
only extend through some of the outer layers, such as the cement
layer and the casing for example, but not through all of the outer
layers.
[0096] The above described arrangements therefore describe how
fluid flow measurements, including speed of sound measurements from
which material identification may be made, may be obtained along a
well using a DAS, either in the case of a noisy well where there is
plenty of sound energy to detect, or for quiet wells where internal
or external acoustic illumination may be used. In view of these
techniques, we next describe embodiments of the invention where the
fluid flow data is correlated with, or otherwise associated,
combined, or used with seismic data to more accurately map the
location of underground reservoirs.
[0097] Correlating or Combining Flow Information with Seismic
Information
[0098] FIG. 15 illustrates a typical scenario where embodiments of
the present invention which combine DAS based flow and speed of
sound measurements with seismic data. In FIG. 15 a conventional
seismic survey of the area of the well or borehole 12 is undertaken
by seismic source 90 and seismic detectors (not shown). The seismic
survey depends on changes in acoustic impedance to provide
reflections and refractions from rock strata of different types,
and from underground reservoirs, as is known in the art. The
seismic survey should therefore be able to detect underground
petroleum reservoir 152 from the acoustic signal reflected back
therefrom, and from identification of typical oil bearing rock
formations in the vicinity of the reservoir. As noted previously,
the spatial resolution of a 3D seismic survey can be as high as 12
m, but may typically be lower than this, in some cases in the range
25 to 200 m, depending on acoustic conditions.
[0099] Thus, whilst seismic surveys can reliably detect the
presence of reservoirs, precise mapping of their size and extent is
still dependent on the imaging resolution of the seismic survey
equipment. In order to improve this, and in particular where test
or production wells have already been drilled, embodiments of the
invention make use of the flow data that is obtainable via DAS 10
as described previously to improve the accuracy of the location or
extent of the reservoir. Specifically, the flow profile data
available via the DAS can tell the well operator where in the
production zone of the well flow is actually occurring i.e. into
which part of the perforated zone of the well fluid is actually
flowing, substantially at the resolution of the DAS. Therefore, the
flow data helps to pinpoint at much higher resolutions where flow
from the reservoir actually occurs. If the well intersects the
reservoir such that flow into the well occurs at the points along
the intersection, then the intersect length can be determined,
which may indicate the depth of the reservoir at the intersection
point.
[0100] FIG. 16 illustrates the process in more detail. Firstly, at
step 16.2 a seismic survey is undertaken to identify the location
of the reservoir 152. Then, at s. 16.4 flow monitoring is
undertaken using the DAS based techniques described above to obtain
fluid flow data along the well. Where the well is quiet, acoustic
illumination techniques may be used, as described. Conveniently,
the acoustic illumination may be the acoustic energy from the
seismic survey, such that the seismic survey and the flow
monitoring takes place at the same time.
[0101] Once the flow data has been obtained and the seismic survey
results obtained, at s.16.6 the two sets of data are correlated
with each other, or otherwise combined, associated, or used
together, to help improve knowledge of the characteristics of the
reservoir, for example such as the size, depth, extent, and volume
of the reservoir, as well as other characteristics such as the
pressure and resultant flow speed obtainable. In this respect,
because the DAS has higher resolution than the seismic survey
system, use of the DAS based data should help to improve the
accuracy of the findings from the seismic system.
[0102] Using DAS during EOR
[0103] In a further embodiment, the DAS based measurement system
may also be used during Enhanced Oil Recovery (EOR) procedures such
as water injection, hydraulic fracturing, steam assisted gravity
drainage (SAGD), cyclic steam stimulation (CSS) or high pressure
CSS (HPCSS). In a water injection procedure, shown in FIGS. 17 and
18, a water injector is used to inject water down an injection well
174 into an oil reservoir 152 so as to help to force the oil 152
towards the production well 12, and out of the well 12. Such water
injection EOR techniques are often used in aging wells where the
production pressure is failing, and help to improve oil recovery
from the reservoir. Water injection can take a significant amount
of time, for example several years, as the injected water migrates
along the reservoir, forcing the oil towards the production well.
Eventually, all the recoverable oil from the well will have been
obtained, and the well will start to produce a greater percentage
of water, as shown in FIG. 18.
[0104] The DAS based monitoring system of the present embodiments
can help in this situation due to its ability to distinguish
between oil and water based on speed of sound measurements. In
particular, as shown in FIG. 19, during a water injection process
of s. 19.2 the well is monitored by the DAS to determine the speed
of sound at profile along the well, using the space-time and
k-.omega. techniques described previously. From the speed of sound
profile it is then possible to determine what liquid is actually
present at each point along the well, and particularly whether it
is oil or water. By obtaining such information along the perforated
production zone of the well, it becomes possible to more accurately
map where oil is still being produced, and where water is being
received instead. Thus, it may be possible to more accurately
control the water injection to enhance the oil producing regions of
the perforated production zone.
[0105] Likewise in hydraulic fracturing (fracking), where fluid is
pumped into a well at pressure to fracture the surrounding rock
strata to aid in oil flow, it can be helpful to be able to
discriminate along the perforated production zone of a well where
oil is being received, or where fracking fluids are entering the
well. The ability of the DAS to determine speed of sound profiles
along a well using the techniques described above allows
discrimination between oil and fracking fluids to be made, in the
same manner as with the oil and water discrimination above.
[0106] Within steam assisted gravity drainage (SAGD) two wells are
created one above the other, and heated steam injected into the
upper well to help create a heated steam chamber in the rock and
tar deposits. The heat from the steam chamber lowers the viscosity
of heavy crude oil and bitumen in the rock, allowing it to sink
through the steam chamber and into the lower well for collection.
Again, the ability of the DAS to discriminate material types via
speed of sound measurements over an area can help to map the extent
of the steam chamber, and where heavy crude and bitumen is flowing
into the lower well.
[0107] In cyclic steam stimulation and high pressure cyclic steam
stimulation a single well is used, and the process cycles between
forming a steam chamber around the well injection of heated steam,
and then collection of the lowered viscosity heavy crude and
bitumen deposits via the same well. The DAS can help to map the
extent to which petroleum products such as the heavy crude and
bitumen are flowing into the well along its length, during the
production phase.
[0108] Various modifications may be made to the above described
embodiments to provide further embodiments, any and all of which
are intended to be encompassed by the appended claims.
* * * * *