Upload
ngotuong
View
221
Download
4
Embed Size (px)
Citation preview
Single well seismic imaging of a gas-filled hydrofracture
Thomas M. Daley, Roland Gritto, Ernest L. Majer
Lawrence Berkeley National Laboratory, 1 Cyclotron Rd. MS 90-1116, Berkeley,
CA, 94720
(November 4, 2003)
ABSTRACT
A single well seismic survey was conducted at the Lost Hills, Ca oil field in a mon-
itoring well as part of a CO2 injection test. The source was a piezoelectric seismic
source and the sensors were a string of hydrophones hanging below the source. The
survey was processed using standard CMP reflection seismology techniques. A poten-
tial reflection event was observed and interpreted as being caused by a near vertical
hydrofracture. The radial distance between the survey well and the hydrofracture
is estimated from Kirchoff migration using a velocity model derived from cross well
seismic tomography. The hydrofracture location imaged after migration agrees with
the location of an existing hydrofracture.
INTRODUCTION
Since the beginning of seismic exploration in the 1930’s, borehole seismic measure-
ments have been used to augment surface seismic methods (e.g. check-shot velocity
surveys) or well-logging methods (e.g. sonic logging). These borehole techniques
were developed into current technologies such as 3D Vertical Seismic Profiles (VSP)
for structural imaging and dual dipole sonic logging for measuring anisotropic rock
properties. Crosswell seismic methods have also been developed to improve subsur-
face properties measurement and structural imaging over interwell distances (typically
1
less than 1000 m). The fundamental issues driving this technology development are
the ability to improve resolution (via increased frequency content) by placing seismic
sources and/or sensors in the subsurface, below the highly attenuating near-surface
material, and the ability to measure seismic properties in a zone of interest without
adding uncertainty from propagation through other zones. These same issues con-
tinue to drive recent research in developing and applying methods of extending the
penetration of conventional seismic logging from a few meters out to tens if not hun-
dreds of meters. This logical extension of sonic logging, using techniques developed in
VSP and crosswell seismic acquisition, including borehole seismic sensor strings and
sources capable of exciting frequencies from 10s to 1000s of Hz, both on a single cable,
is termed single well seismic imaging (SWSI). As exploration and production wells
increase in both cost and accuracy of positioning, methods to image in the vicinity
of a single well and guide drilling become more necessary. Development of single well
acquisition systems has been anticipated by attempts to numerically model single well
data (Kurkjian, et al., 1994).
Initial success at single well imaging of a gas-filled fracture zone in a shallow
ground-water test site (Majer, et al., 1997), led to development of a larger scale system
for deeper wells (Daley, 1997; Daley, 1998). Our SWSI acquisition development work
has progressed through these various field tests to a current system capable of CMP
type borehole surveys with multiple borehole source and receiver options on a 10,000
ft cable. Recent field experiments have been aimed at targets which present a strong
velocity contrast with near vertical orientation such as the flank of a salt dome or a
gas filled hydrofracture. The results from a gas-filled (CO2) hydrofracture imaging
experiment are presented in the following.
2
DATA ACQUISITION
Field Site - Lost Hills, California
The field site was developed as a subsurface CO2 injection pilot program operated
by Chevron USA Production Company in the Lost Hills, California oil field. This
pilot program, which was partially funded by the U.S. Department of Energy (DOE)
as an enhanced oil recovery project, provided a site with dedicated observation wells
near a hydrofracture (Figure 1). Figure 1 shows two hydrofracs near the single well
survey, an initial water injection in well 11-8W, and the CO2 injection in 11-8WR
(a redrilled section of 11-8W). The hydrofrac direction is estimated from previous
well tests, local faulting, and tilt meter measurements (Perri, et al, 2000). The
well 11-8WR was drilled, cased, perforated (in the interval from 1627 to 2105 ft)
and hydrofracured using standard methods. The observation well OB-C1 is located
about 18 m (60 ft) from the current injection well and about 12 m (40 ft) from the
previous hydrofrac and water injection well (at reservoir depths and allowing for well
deviations).
The reservoir rock in the Lost Hills field is a form of diatomite. The composition
of the diatomite at Lost Hills is varying parts biogenic silica, clay and silt/sand
(Graham and Williams, 1985). The reservoir extends from about 425 m (1400 ft) to
640 m (2100 ft) below ground level, with some variation in diatomite composition,
over this interval. Porosity is 50-60% and permeability is 1-3 mDa (Fossum and
Fredrich, 2000).
The injection of CO2 began in August of 2000 and continued with varying injection
pressures up to the time the single well survey was performed. The wellhead pressure
was held at 800-900 psi, and the reservoir temperature was about 108 oF. At this
pressure and temperature, the CO2 would be in gas phase in the reservoir. The site
had a water flood operating previously, so the reservoir fluids are a mix of water, oil
3
and gas.
Single well seismic equipment
The single well system developed by LBNL uses modified equipment originally
built for crosswell or VSP acquisition, along with a wireline cable and tube-wave
suppressor (TWS) specifically designed for single well seismic acquisition. Modular-
ization allows sources and sensors to changed independently. The configuration used
to acquire the data presented here consisted of a piezoelectric seismic source, a bore-
hole digitizer, a tube-wave suppressor, and a string of 24 borehole hydrophones (at
10 ft interval spacing). The minimum source-receiver offset (to the top sensor) was
90 ft. The special design piezoelectric source has a frequency range of approximately
500 to 5000 Hz. The TWS was developed by Idaho National Engineering Labora-
tory and uses a gas filled bladder kept slightly below borehole pressure to attenuate
tube-waves. The borehole digitizer, which has 24 data channels and uses fiber-optic
communication, and the hydrophone string were built by Geospace Engineering. A
special design wireline (1.1 inch diameter, 10,000 ft length) with fiber-optic (FO) ca-
bles for data transmission is used with specially designed FO connections to deploy
the system components in the borehole. A schematic representation of the acquisition
equipment as deployed is shown in Figure 2.
OB-C1 Acquisition
The survey was designed to allow borehole CMP imaging. Borehole CMP imaging
is accomplished by increasing the distance between the source and the receiver in the
well from a few meters to over a hundred meters, depending upon the desired distance
of investigation. Optimal data acquisition would allow the source-sensor spacing to
be variable depending on the target distance. As with surface seismic acquisition, a
4
good acquisition geometry would have source-receiver offsets both less and greater
than the target distance.
Unfortunately, our system could not be optimally configured for the Lost Hills site
because of modification costs and time constraints. The hydrofracture was expected
at 30 to 60 ft distance and our minimum offset was 90 ft. Also, the receiver spacing
of 10 ft was not optimal because the dominant wavelength of the data was about 4 ft
(1500 Hz frequency for 5500 ft/s velocity) so waves traveling along the borehole were
spatially aliased. The spatial aliasing limited use of some analysis tools such as F-K
filtering in shot gathers. Also, the longer offset sensors (from about 200 to 320 ft)
had no contribution to the CMP stack at the arrival time of the hydrofrac reflection.
Nonetheless, the data acquisition produced high signal-to-noise with significant (20
to 30 dB) tube-wave reduction (Daley, et al., 2003). The data acquisition parameters
for the OB-C1 survey are given in Table 1. An example shot gather is shown in
Figure 3. In this shot gather the direct P-wave arrival is identified along with the
event which is interpreted as a reflection from the hydrofracture. A small (¡ 1 ms)
variation in delay time between the direct P-wave and the reflection event is seen in
Figure 4 in which the direct P-wave is shifted to be aligned at 10 ms. This variable
delay time indicates the event is not a multiple. Discriminating between multiples
and reflections is difficult because of the long source-receiver offset, and is discussed
later.
Acquisition time is usually an important issue in borehole recording because of
costs and well stability. The use of fluid coupled source and sensors decreased ac-
quisition time to less than one minute per shot point using a stop-to-shoot method.
Shooting while moving, as is done in sonic logging and some crosswell surveys, is
possible and would further decrease acquisition time.
5
TABLES
Table 1: OB-C1 SWSI Acquisition Parameters
Source Type: Piezoelectric with 0.5 ms Pulse ( 500-4000 Hz)
Sensor Type: Hydrophone
Survey Shot Depths: 1100-1800 ft
Shot Spacing: 2 ft
Sensor Spacing: 10 ft
Minimum Offset: 90 ft
Maximum Offset: 240 ft
Sample Rate: 0.125 ms
Record Length: 250 ms
6
DATA ANALYSIS
Processing
The data processing followed the flow chart shown in Figure 5. Initial signal
enhancement, such as bandpass filtering and predictive deconvolution (used to reduce
short path multiples) was done with common offset gathers (equivalent to common
receiver) because the spatial aliasing apparent in shot gathers was not problematic
in offset gathers. It is notable that a SWSI common offset gather is equivalent to a
very long spaced, full-waveform sonic log, albeit with different frequency content. An
example common offset gather is shown in Figure 6 which also demonstrates the effect
of the predictive deconvolution. The same gather is shown after normalizing the
amplitudes and aligning the first arrival in Figure 7. The time difference between
the direct arrival and the interpreted reflection is shown in Figure 8. The 0.3 ms
variation in time difference is about 9% of the total. This variation indicates the
reflection event is not a simple multiple which would have constant time difference.
A first break mute was used to prevent the first arrival being stacked in the CMP
gather. A source static of 2.5 ms was applied because of the difference between record-
ing zero time and the beginning of the source pulse (as measured by an accelerometer
mounted on the source).
The velocity analysis is the processing step potentially most different from surface
seismic because, for a vertical borehole, typical velocity layering is perpendicular to
the acquisition line, rather than parallel. In our data the velocity analysis was limited
by the lack of short offsets, and poor resolution of the hydrofrac reflection on the far
offsets because of NMO stretch. After binning CMP’s 3-to-1, giving a 3 ft bin size
with maximum fold of 24, and applying a stretch mute, there were typically only 6-9
traces with non-zero amplitude stacking at the hydrofracture reflection arrival time.
We approached this problem by making a simplifying assumption. We assumed the
7
diatomite unit could be treated as having constant stacking velocity. This assumption
was validated (within 10%) by first arrival picking and by semblance analysis of the
hydrofracture event. The stacking velocity used, 5500 ft/s, was in agreement with
the velocity measured by first arrivals and semblance analysis. The result of a typical
semblance velocity analysis is shown in Figure 9. We interpret the high semblance
energy apparent at low velocity ( below 4500 ft/s) in Figure 9 as being associated with
tube-waves propagating up and down the borehole. We did not attempt to remove
borehole tube-waves beyond bandpass filtering and the in-field attenuation gained by
the TWS. This was acceptable because our reflection of interest (the hydrofracture
plane) was expected to arrive before the tube-wave. After choosing the stacking
velocity, the data was corrected for NMO. A typical CMP gather after NMO correction
using the 5500 ft/s stacking velocity is shown in Figure 10 The complete single-well
CMP time section is shown in Figure 11.
The final processing step was a Kirchoff depth migration, using a 2D velocity
model. This velocity model was taken from crosswell tomography between OB-C1 and
OB-C2 with well spacing of about 25 m /citeGritto03. The migrated single well result
is analogous to a surface seismic depth section. For single well imaging, the analogue
of a depth section is a ”radial” section in which two-way reflection time is converted
to the radial distance from the borehole. In this domain, any reflecting object or
interface at equal radial distance for a given borehole depth will be superimposed.
The result of the depth migration is shown in Figure 12.
Interpretation
The high amplitude reflection between 12 and 14 m distance in Figure 12 is in-
terpreted as the hydrofracture. Because the azimuth of this reflection is unknown,
the interpretation is based on a ”most likely cause” reasoning. Two hydrofracs are
located within 10 to 20 m of the survey well, a water-flood hydrofrac from well 11-8W
8
and the CO2 injection hydrofrac in the redrilled 11-8WR (shown in Figure 1). We
assume that the reflection is in the plane containing the survey well and normal to
the hydrofrac. At 12-14 m distance, the reflection event is most likely associated with
the original water-flood hydrofrac, rather than the current CO2 injection hydrofrac.
Our interpretation is that the two hydrofracs are connected by high permeability
sub-parallel fracturing and that the gas phase CO2 has displaced water in both hy-
drofracs. Communication with field production personnel has confirmed that this
type of ”interference” between the hydrofracs is possible. The previous water floods
(which were ongoing for years) could have created high permeability pathways for the
gas phase CO2.
A second reflection event at about 18 m distance is interpreted as the 11-8WR
hydrofrac. The strong reflection from the closer hydrofrac will limit the energy avail-
able for reflection from the main CO2 hydrofrac in 11-8WR since energy must be
transmitted twice through the closer 11-8W hydrofrac.
The 11-8W hydrofrac reflection is easily seen in a common offset gather in Figure
6 at about 29 ms with reversed polarity from the direct arrival (at about 25 ms).
The polarity reversal is consistent with a low-velocity reflector such as a gas-filled
fracture zone. Accurate modeling of reflection from a hydrofracture would be best
accomplished using the method of (Coates and Schoenberg, 1995) which would allow
the hydrofracture to be a displacement discontinuity. Such a discontinuity should
have a P-to-S conversion. We calculated the travel time for P-to-S conversion from a
vertical interface at 12 m distance in a homogeneous media with P velocity of 1675
m/s and S velocity of 800 m/s. This travel time for a 36.6 m offset (120 ft) has a
11.4 ms delay after the P-to-P reflection. On Figure 6 this P-to-S event would arrive
at about 40 ms where there is some energy arriving, although it is dominated by low
frequencies which are probably tube-waves (expected to arrive at about 37 ms).
If the event interpreted as a reflection from the 11-8W hydrofrac is not a reflection
from a vertical interface parallel to the borehole, a remaining possibility is that it is
9
a multiple reflection from the equipment string. The lack of small receiver offsets in
the CMP gathers prevents discrimination based on move-out analysis. However, the
possibility of an equipment multiple is discounted because the following observations.
First, there is a variation in amplitude as a function of depth seen in the migrated
section in Figure 12. An equipment multiple should not vary in amplitude as the
equipment moves. Furthermore, the event shows some variation in delay time as a
function of depth as shown in Figure 8. Also, the 4 ms delay time after the direct
arrival (shown in Figure 6) corresponds to about a 6 ft distance for a tube-wave peg-leg
multiple or a 7.3 ft distance for a p-wave multiple, and nothing in the equipment string
has this separation from the source. Therefor, the event is not easily attributable to
a simple multiple, and the best interpretation is a reflection.
The reflection is strongest between 1500 and 1750 ft, with a shallower high am-
plitude zone between 1250 and 1350 ft. The field operators reported that hydrofrac
injection pressures were allowed to rise above lithostatic pressure. We therefor believe
that the 1250 to 1350 ft interval represents an accumulation of gas, which has likely
been able to migrate upward when the hydrofrac propagated above the injection in-
terval. A later event seen at about 15 m radial distance in Figure 12 is possibly due to
the second hydrofracture (in well 11-8WR) shown in Figure 1 at about 15 m distance
from the bottom of well OB-C1.
CONCLUSIONS
We have successfully applied the recently developed SWSI technique to reflection
imaging of gas-filled fracture zones in an oil field. The radial distance to the frac-
ture zone was determined, as a function of depth. Variations in the fracture zone
reflectivity as a function of depth were observed.
Specific equipment geometry (ie the minimum source-receiver distance) limited
the CMP imaging method. Allowing for improvements in acquisition equipment,
10
we believe that improved imaging, including imaging of fluid-filled fracture zones, is
possible. Single-well imaging could also be a powerful method if used in a time-lapse
sense where borehole effects do not vary.
Borehole CMP imaging is accomplished by varying the distance between the source
and the receiver in the well. However, as one increases the source-receiver distance
many problems become more severe. In effect, one now is trying to image in a true
3-D sense away from the well, therefore, directionality becomes important for the
transmitted as well as the received signals. This technique needs multicomponent
sources and receivers with independent azimuthal measurement to address true 3D
issues. Although this can be an advantage, such issues as radiation patterns, source
generated noise, borehole interaction, tube waves and other sources of noise become
more problematic.
Recent and near future advances in instrumentation will make the method more
economical and possibly deployable through the end of tubing. Current applications
include hydrofracture monitoring, steam/water flood monitoring, fracture mapping
and validation of drilling paths in horizontal drilling applications.
REFERENCES
Coates, R. T. and Schoenberg, M., 1995, Finite-difference modeling of faults and
fractures: Geophysics, Soc. of Expl. Geophys., 60, 1514-1526.
Daley, T.M., Gritto, R., Majer, E.L. and West, P., Tube-wave suppression in single-
well seismic acquisition, Geophysics, 68, 863-869.
Daley, T.M. and Cox, D., 2001, Orbital vibrator seismic source for simultaneous P-
and S-wave crosswell acquisition, Geophysics, 66, 1471-1480.
Daley, T.M., 1998, Single Well Seismic Imaging Tests: Nov 1997 at Bayou Choctaw
Site, LBNL Report #42672, Berkeley, Ca.
11
Daley, T.M., 1997, Single Well Seismic Imaging in a Deep Borehole using a piezoelec-
tric Orbital Vibrator, LBNL Report #42673, Berkeley, Ca.
Fossum, A.F., and Fredrich, J.T., 2000, Constitutive models for the Etchegoin sands,
Belridge diatomite, and overburden formations at the Lost Hills Oil Field, Califor-
nia, Sandia National Laboratory Report, SAND2000-0827.
Graham, S.A. and Williams, L.A., 1985, Tectonic, depositional, and diagenetic history
of Monterey formation (Miocene), central San Joaquin basin, California, AAPG
Bulletin, 69, p385-411.
Gritto, R., Daley, T. M., Myer, L. R., Joint Cross Well and Single Well Studies at
Lost Hills, California, submitted to Geophysical Exploration, Lawrence Berkeley
National Laboratory Report, LBNL-50651, Berkeley, CA, 2002.
Kurkjian, A.L., Coates, R.T., White, J.E., and Schmidt, H., 1994, Finite-difference
and frequency-wavenumber modeling of seismic monopole sources and receivers in
fluid-filled boreholes, Geophysics, 59, p1053-1064.
Majer, E.L., Peterson, J.E., Daley, T.M., Kaelin, B., Queen, J., D’Onfro, P., and
Rizer. W, 1997, Fracture Detection using Crosswell and Single Well Surveys, Geo-
physics, 62, 495-504.
Perri, P.A., Emanuele, M.A., Fong, W.S., and Morea, M.F., 2000, Lost Hills CO2
pilot: evaluation, design, injectivity test results and implementation, Proceedings
SPE/AAPG Western Regional Meeting, SPE 62526, pp 13.
ACKNOWLEDGMENTS
This work was supported by the Assistant Secretary for Fossil Energy, National
Petroleum Office of the U.S. Department of Energy under Contract No. DE-AC03-
12
76SF00098. Thanks to Mike Morea of Chevron and to the LBNL field personnel,
especially Cecil Hoffpauir and Don Lippert.
13
FIGURES
FIG. 1. Well locations and estimated hydrofrac locations for the Lost Hills CO2 injec-
tion site. Well OB-C1 was used for single-well imaging. Note that both observation
wells are deviated and the top and bottom locations are marked separately (circle and
X, respectively) with dots showing intermediate locations. The section of well used
for data acquisition was nearly vertical and aligned with the bottom hole location of
OB-C1.
FIG. 2. Schematic of LBNL’s single well acquisition equipment.
FIG. 3. Single well shot gather for a source at 1600 ft and sensors from 1690 to
1920 ft. The data has been bandpass filtered from 1200 to 3500 Hz.
FIG. 4. Shot gather from Figure ?? after time shifting to align the direct P-wave at
10 ms. Each trace is normalized to its own maximum amplitude (not true relative
amplitude).
FIG. 5. Flow chart for processing sequence of the single well CMP data.
FIG. 6. Comparison of common offset gather (offset = 120 ft) before (left) and
after (right) predictive deconvolution for source depths 1600 to 1700 ft. The decon-
volution had an operator length of 1.5 ms and a prediction length of 0.75 ms with
0.1% noise added.
FIG. 7. Same data as Figure ?? with amplitudes normalized to individual trace
maximum and time shifted to align the direct arrival at 25 ms.
FIG. 8. Travel time difference between the direct P-wave arrival and the interpreted
14
reflection event for the data in Figure ??.
FIG. 9. Velocity semblance for cmp #645. Higher semblance is red (meaning larger
amplitude within a time window after stacking). The small red bullseye at 12-14
ms and 5500 ft/s represents the energy associated with the interpreted hydrofracture
reflection. The low velocity, high semblance energy is interpreted as borehole tube
waves.
FIG. 10. NMO corrected CMP gather. Data are plotted at true relative ampli-
tude after applying spherical divergence correction.
FIG. 11. Single well stacked CMP time section.
FIG. 12. Migrated single well CMP section. Distance in this section is radial (essen-
tially horizontal) from the borehole, while depth is vertical along the borehole.
15
OB-C1Top
OB-C2Top
OB-C1Bottom
OB-C2Bottom
Hydrofra
cs
X
X
11-8W
11-8WR
3
6
12
15
18
21
24
9
6 m
¨j©?ªQ«]¬7«{ �R®¯®a® �B°*±7²?³ �i´µy±0´~¶+�Rµ@²?³ ��±7²Ü�R¶�·�¸B¶G���0¹ª�n±0°=® �B°*±7²?³ �i´~µY¹p�X�8²?·"��ºI�iµ?²8»k³¯®¯®¯µ8¼�½ � ³¯´�¾Ü�R°M²?³ �i´µ?³¿²Ü� «, �R®¯®(½`À�ÁG¼ ¬� ±0µ2Ã~µÜ�R¶�¹p�X�&µ?³¯´~Äi® �MÁ  �R®!®�³ ��±7Äi³¯´�Ä « ���0²Ü�,²?·±7²+���0²?·S�X�µÜ�l����±7²?³ �i´  �R®¯®!µo±W���¶G�l��³¯±7²Ü�R¶&±0´¶�²?·G�^²Ü�0ÅQ±0´~¶^���0²@²Ü���:® �B°*±7²?³ �i´µY±W���þ�,±W�?ÆX�R¶&µÜ�*Å�±W�n±7²Ü�R®¿¸Ë�.°*³ �n°*® ��±0´~¶�ÇÄ�/���Rµ@Å��R°M²?³ �X�R®¿¸"� ³¿²?·�¶G�0²?µ�µ?·G�  ³¯´�ÄQ³¯´�²Ü�l���-�R¶~³¯±7²Ü�k® ��°*±7²?³ �i´~µ «^È ·"�{µÜ�R°M²?³ �i´5�0¹  �R®¯®]Ã~µÜ�R¶g¹ª�X� ¶~±7²?±Q±0°*ÉBÃ~³¯µ?³¿²?³ �i´  ±0µ´G�R±W�n®¯¸Ò�X�l�?²?³!°*±0®Y±0´~¶J±0®¯³¯Äi´G�R¶  ³¿²?·z²?·G�+���0²@²Ü���Ê·G�i® �o® ��°*±7²?³ �i´Ã�0¹=½`À�ÁG¼ ¬7«
î0A
Piezoelectric Source
Downhole 24 Chan A/D with Fiber Optic Telemetry
Sensor String: 16 Hydrophones @ 3 m Spacing
9.1 m
27.5 m
3 m
3 m
3200 m 1.1" Armored Fiber Optic Cable
Tube-wave Suppressor
¨j©@ª�« � «kË °n·G�/��±7²?³!°½�0¹�ºyÀA�{º=Ì͵�µ?³¯´~Äi® �  �R®¯®y±0°*É�Ã~³!µ?³¿²?³ �i´5�RÉBÃ~³¿ÅZ�-�R´�² «
îi�
Direct P-Wave 161820222426283032343638404244
161820222426283032343638404244
Reflection
515 521 527 533 539 546 552Sensor Depth (m)
Tim
e (ms)
Tim
e (m
s)
¨j©?ªQ« � «�Ë ³¯´�Äi® �  �R®!®�µ?·"�0²�Äi±7²?·G�l� ¹p�X� ±2µ��iÃG�n°h��±7² ¬RÎ �X��¹�²�±0´~¶zµÜ�R´~µÜ�X�nµ�¹p����� ¬RÎ0Ï ��²Ü� ¬RÏ �W��¹�² «È ·G�o¶±7²?±�·~±0µ����l�R´Ã�±0´¶�ű0µ?µ�Ю¯²Ü�l���R¶z¹ª����� ¬ �W�X��²Ü�Ò�0ÑW�X�g»�Ò «
î0
¨j©?ªQ« � «2Ë ·G�0²kÄi±7²?·G�l��¹p����� ¨ ³¯ÄiÃG���-�,±7¹�²Ü�l��²?³ �-��µ?·~³¿¹�²?³¯´�Ä,²Ü�z±0®!³¿Äi´h²?·"��¶³ ���R°M²`Ó�Á  ±/�X��±7² ¬ ���µ «�Ô ±0°n·�²Ü�n±0°h�`³¯µ=´G�X�z��±0®¯³¿Òl�R¶,²Ü�Q³¿²?µ �  ´s��±�Õ�³ �QÃ"�Ö±X��Å®¯³¿²?Ã~¶"�+�.´G�0²=²Ü�nÃ"�����R®¯±7²?³ �X�{±X�;Å®!³¿²?Ã~¶G�[� «
îXï
Apply Geometery
Sort to Offset Gathers
Predictive Deconvolution
Bandpass Filter
First Break Mute
Apply Source Static
Apply Spherical Divergence Correction
Velocity Semblance Analysis and C.V. Stacks
Stack CMP Gathers
Sort to CMP Gathers
Kirchoff Depth Migration
Input Shot Gathers
¨j©@ª�« Ñ «�¨ ® �  °×·~±W�?²�¹p�X��Å"����°h�Rµ?µ?³!´�Ä;µÜ�RÉ�Ã"�R´~°h�^�0¹j²?·G�&µ?³¯´~Äi® �  �R®¯®y¼�ØhÓ�¶~±7²?± «
Êeñ
Direct P-Wave
Reflection
¨j©?ªQ«uÎB« ¼K����űW�n³¯µÜ�i´��0¹�°h���Ë�-�i´~�7ÙlµÜ�*²QÄi±7²?·G�l�>�p�7Ùuµ��*²�Ú ¬ �W�P¹�²z�^���*¹ª�X���S�.® �*¹�²z��±0´~¶U±7¹�²Ü�l��p�n³¿Äi·�²z��ÅZ���R¶~³¯°M²?³ �X�Q¶G�R°h�i´·�X�i®¯Ã�²?³ �i´P¹ª�X�`µÜ�iÃG�×°h�2¶G�*Å~²?·µ ¬RÎ �X��²Ü� ¬TÛ �X��¹�² «�È ·G�2¶G�R°h�i´$�X�i®!Ã�²?³ �i´�·~±0¶±0´Ã�0Å��l�n±7²Ü�X�k® �R´�Ä0²?·Ã�0¹ ¬7« ÑË��µ�±0´~¶$±;Å"���R¶³¯°M²?³ �i´$® �R´�Ä0²?·s�0¹¾� «�Û Ñ%��µ  ³¿²?·Ã� «¯¬TÜ ´G�i³¯µÜ�o±0¶¶G�R¶ «
Ê�î
¨j©?ªQ«�Û�«�Ë ±X�-�(¶~±7²?±{±0µ ¨ ³¿ÄiÃG��� Î� ³¿²?·&±X�;Å�®¯³¿²?Ã~¶G�Rµy´G�X����±0®¯³¯Òl�R¶o²Ü�`³¯´~¶~³ ��³¯¶~ñ0®"²Ü�×±0°h�K��±�Õ�³ �QÃ"�±0´~¶$²?³â�-�oµ?·~³¿¹�²Ü�R¶z²Ü�,±0®¯³¯Äi´z²?·G�&¶~³ ���R°M²�±W���n³ �7±0®u±7²��0ÑË��µ «
ÊÊ
¨j©?ªQ«YÝB«,È �×±/�X�R® ²?³ �Ë�z¶³rÙ��l���R´~°h�Ò���*²  �l�R´�²?·"�J¶~³ ���R°M²�Ó�Á  ±/�X�h±W���n³ �7±0®(±0´¶d²?·"�J³¯´a²Ü�l�nÅ"���*²Ü�R¶���*Þ"�R°M²?³ �i´Ã�l�X�R´a²{¹ª�X��²?·G�&¶~±7²?±�³!´ ¨ ³¯ÄiÃG��� Û�«
Êeð
¨j©?ªQ«YÏB«gß �R® ��°*³¿²4¸UµÜ�/���®¯±0´°h�$¹ª�X�,°l��Å�à Î �aÑ « »{³¯Äi·G�l�,µÜ�/���®¯±0´~°h�$³¯µ����R¶Ý���-�R±0´~³¯´~Ä�®!±W�?ÄX�l�±X�;Å®!³¿²?Ã~¶G�  ³¿²?·~³¯´�±�²?³ �-�  ³¯´~¶G�  ±7¹�²Ü�l�&µ@²?±0°nÆB³!´�Ä·� «;È ·G�;µ���±0®¯®1���R¶£��Ã~®¯®¯µÜ�*¸X��±7² ¬ �"Á ¬ �>�,µo±0´~¶Ñ0ÑW�X�U¹�²×á�µÒ���*Å"���RµÜ�R´a²?µg²?·G�]�R´G�l�?Ä0¸b±0µ?µÜ��°*³¯±7²Ü�R¶  ³¿²?·c²?·G�P³¯´�²Ü�l�?Å"���*²Ü�R¶c·�¸B¶G���0¹ª�n±0°M²?Ã"���>���*ÞZ�R°M²?³ �i´ «È ·G�o® �  �X�R® ��°*³¿²4¸X��·~³¿Äi·$µ��/�+�®!±0´~°h�½�R´G�l�?Ä0¸$³¯µ ³¯´�²Ü�l�?Å"���*²Ü�R¶J±0µ����X���R·G�i® ��²?Ã"���  ±/�X�Rµ «
��
Reflection
¨j©?ªQ«]¬ � « �kØ�½â°h�X�����R°M²Ü�R¶z¼ ØPÓHÄi±7²?·"�l� «^ã ±7²?±&±W��� Å® �0²@²Ü�R¶,±7²^²Ü�nÃ"�����R®¯±7²?³ �X��±X�;Å�®¯³¿²?Ã~¶G��±7¹�²Ü�l�±7Å~Å®¯¸B³¯´~ÄQµ@Å�·G�l�n³¯°*±0®l¶~³ �X�l�?ÄX�R´~°h�o°h�X�����R°M²?³ �i´ «
�C
350 390 425 465 500 535 575Depth (m)
¨j©@ª�«]¬0¬7«�Ë ³¯´�Äi® �  �R®¯®Yµ@²?±0°nÆX�R¶�¼ ØPÓb²?³â�-�oµÜ�R°M²?³ �i´ «
ÊBA
5
10
15
20
25
30
Dis
tanc
e (m
)
350 390 426 463 500 536 573Depth (m)
¨j©?ªQ«]¬ � « Øh³¯ÄX�n±7²Ü�R¶;µ?³¯´�Äi® �  �R®¯®�¼�ØhÓ�µÜ�R°M²?³ �i´ «�ã ³!µ@²?±0´~°h� ³¯´2²?·~³¯µjµÜ�R°M²?³ �i´�³¯µ1�n±0¶~³¯±0®��p�Rµ?µÜ�R´�²?³¯±0®¯®¯¸·G�X�n³¯Òl�i´a²?±0®ª��¹p�����ä²?·"�^���X���R·G�i® �X�  ·³¯® �`¶G�*Å~²?·$³¯µ��X�l�n²?³¯°*±0®Y±0® �i´�Ä,²?·G�½���X���R·G�i® � «
��