Post on 28-Oct-2021
Fort Hays State University Fort Hays State University
FHSU Scholars Repository FHSU Scholars Repository
Master's Theses Graduate School
Summer 2013
3D Seismic Analysis and Characterization of a Stacked Turbidite 3D Seismic Analysis and Characterization of a Stacked Turbidite
Channel: Niger Delta Complex Channel: Niger Delta Complex
Anthony Luna Fort Hays State University, anthonyluna44@hotmail.com
Follow this and additional works at: https://scholars.fhsu.edu/theses
Part of the Geology Commons
Recommended Citation Recommended Citation Luna, Anthony, "3D Seismic Analysis and Characterization of a Stacked Turbidite Channel: Niger Delta Complex" (2013). Master's Theses. 90. https://scholars.fhsu.edu/theses/90
This Thesis is brought to you for free and open access by the Graduate School at FHSU Scholars Repository. It has been accepted for inclusion in Master's Theses by an authorized administrator of FHSU Scholars Repository.
3D SEISMIC ANALYSIS AND CHARACTERIZATION OF A STACKED
TURBIDITE CHANNEL: NIGER DELTA COMPLEX
being
A Thesis Presented to the Graduate Faculty
of the Fort Hays State University in
Partial Fulfillment of the Requirements for
the Degree of Master of Science
by
Anthony Luna
B.S., University of California Santa Barbara
Date______________________ Approved____________________________ Major Professor Approved____________________________ Chair, Graduate Committee
i
GRADUATE COMMITTEE APPROVAL
The Graduate Committee of Anthony Luna hereby approves his thesis as meeting partial
fulfillment of the requirement for the Degree of Master of Science.
Approved________________________________ Chair, Graduate Committee
Approved________________________________ Committee Member
Approved________________________________ Committee Member
Approved________________________________ Committee Member
Date____________________
ii
ABSTRACT
A stacked turbidite channel was interpreted from 3D seismic data acquired in the
Niger Delta off the west coast of Africa. In offshore environments, such as the Niger
Delta, submarine canyons provide a conduit for currents to transport large sediment loads
to form stacked turbidites. Turbidite channels are typically convoluted deposits and
contain sands that are potential reservoir targets of hydrocarbon exploration. The internal
characteristics of these turbidites are often complex and difficult to interpret accurately.
This study characterizes the morphology of a stacked turbidite deposit by describing key
features that are commonly found in turbidite channels, including: channel sinuosity,
facies, repeated cutting and filling, and stacking patterns. These ubiquitous components
of deepwater deposits are important for efficient reservoir characterization and can be
resolved in most seismic data sets. The presence of shale diapirs in the Niger Delta
Complex complicates the interpretation of channel morphology and potential reservoir
areas. By interpreting the channel’s key features it was determined that the channel is
highly sinuous and has been cut off in several sections forming oxbows. Channel fill is
highly variable, but most likely consists of four main facies: basal lags, slumps, high net
to gross stacked channels, and low net to gross channel levees. Subchannels present in the
data are commonly stacked in vertical and lateral patterns. Also, through attribute
analysis three potential reservoirs were identified and recommended as drilling targets.
iii
ACKNOWLEDGEMENTS
I am very grateful for my wife Nina, without her I would not have made it this
far. I would also like to thank all my friends and family for their support during stressful
times. I thank the Fort Hays Geosciences Department especially: Dr. Hendratta Ali, Dr.
Ken Neuhauser, Dr. John Heinrichs, Dr. Chunfu Zhang, and Patricia Duffey for their help
and support. I especially thank Matt Dreiling for his taking the time to help me with my
project. I would also like to thank Marry, Angie, and Ruby from the Upward Bound
program, they gave me the tools and motivation to continue my education in order better
me and my family.
iv
TABLE OF CONTENTS
GRADUATE COMMITTEE APPROVAL .......................................................................i
ABSTRACT ................................................................................................................... ii
ACKNOWLEDGEMENTS ........................................................................................... iii
TABLE OF CONTENTS ................................................................................................ iv
LIST OF FIGURES ......................................................................................................... v
INTRODUCTION ........................................................................................................... 1
Purpose ............................................................................................................... 1
Study Area .......................................................................................................... 1
REGIONAL GEOLOGY ................................................................................................. 3
Stratigraphy ....................................................................................................... 5
Akata Shale .............................................................................................. 6
Agbada Formation ................................................................................... 9
Benin Formation ...................................................................................... 9
TURBIDITES ............................................................................................................... 10
METHODS ................................................................................................................... 12
Data Description............................................................................................... 12
Mapping ........................................................................................................... 12
Attributes.......................................................................................................... 13
INTERPRETATION ..................................................................................................... 14
Sinuosity ........................................................................................................... 17
Facies ................................................................................................................ 20
Repeated Cutting and Filling ........................................................................... 23
v
Stacking Patterns ............................................................................................. 25
Shale Diapirs .................................................................................................... 28
Reservoir Identification ................................................................................... 29
Reservoir #1 ........................................................................................... 30
Reservoir #2 ........................................................................................... 30
Reservoir #3 ........................................................................................... 30
CONCULSIONS ........................................................................................................... 40
FUTURE WORK .......................................................................................................... 41
REFERENCES .............................................................................................................. 42
vi
LIST OF FIGURES
Figure Page
1 Map of study area; offshore Niger Delta (Adapted from ESRI). ...........................2
2 Aerial view schematic of the structural zones of the Niger Delta (Corredor et al.,
2005). .......................................................................................................3
3 Uninterpreted and interpreted seismic data of the five structural zones of the Niger
Delta (Corredor et al., 2005). ....................................................................4
4 Stratigraphic column of the Niger Delta. The three main formations of the study
area are circled (red). ................................................................................5
5 Spontaneous potential and resistivity logs of the type sections of the Benin,
Agbada, and Akata formations (Short and Stäublee, 1965)........................6
6 Shale diapirs (outlined in blue) intruding overlying beds. .....................................8
7 Depiction of a turbidite system highlighting it submarine canyon and cross
sectional views of turbidite channel deposits as it moves from the
continental slope to the basin plain. Modified from (Bouma et al., 2000). ..
............................................................................................................... 10
8 Southwest - northeast crossline 3407 showing recoginition of channel by choatic
reflection patterns. The yellow horizon represents the channel top and
green represents the base. The vertical scale is in seconds. The index map
located in the top right corner of the image shows the crossline location
within the survey. ................................................................................... 11
-
vii
9 Inline 908 showing the turbidite channel determined by termination of amplitude
reflectors against a convex downward shaped feature. The green horizon is
the channel base and the yellow horizon represents the channel top. ....... 15
10 Mayall et al., (2006) defining the turbidite channel based on reflection
characteristics. The yellow horizon represents the channel base. ............. 16
11 Channel base time structure map. The channel’s deepest parts are represented by
the blue areas and a topographic high area to the south is shown in yellow
and red. .................................................................................................. 16
12 Channel top time structure map. Topographic highs present in the south are
represented by red and yellows followed by lower areas to the north. ..... 17
13 Isochron map showing channel thickness. Thicker intervals are represented by
red and yellows and thinner areas by blues. ............................................ 17
14 Time slice at 2.088 seconds showing a map view of the turbidite channel
(outlined in blue) and its sinuousity. ....................................................... 18
15 "Box of snakes" schematic of stacked channels (Bouma et al., 2002 p. 61)
compared to 3D view of the Niger Delta. Green horizon represents the
channel base. .......................................................................................... 19
16 The sinuous turbidite channel (yellow) and surrounding shale (green). Map is an
RMS amplitude from a 90 ms window within the channel. ..................... 20
17 Peak Amplitude map showing stacked channel sinuosity and meander cut-
offs/oxbows. ........................................................................................... 20
18 NW to SE cross section comparing the Niger Delta data (a) and the four main
turbidite facies as described by (b) Mayall and Stewart (2002)................ 21
viii
19 Facies interpretation from Mayall et al., (2006). The amplitude reflection patterns
and facies distribution is similar to the Niger Delta data (Figure 18a)...... 22
20 Schematics of stacked channel distributions and associated net to gross
percentages (modified from Mayall et al., 2006). .................................... 23
21 Inline 777 displaying an axial core of stacked channels and moderate N:G as
shown in middle box of Figure 20. The chaotic reflections (blue circle)
represent the stacked channels. ............................................................... 24
22 Inline 908(a) shows the main channel defined by the yellow (top) and green
(base) horizons. Image (b) shows the interpreted subchannel bases (blue)
within main channel. The amplitude reflection patterns in image (c) show
several episodes of cutting and filling by the subchannels. ...................... 25
23 Stacking of subchannels (blue) within main channel. Subchannels are recognized
by a convex downward seismic expression. ............................................ 26
24 Example of a vertical stacking pattern from the Niger Delta data........................ 27
25 Vertical stacking pattern example from Mayall et al., (2006) is similar Figure 24
from the Niger Delta. .............................................................................. 27
26 Lateral stacking pattern comparison between the study area (a) and (b) from
Mayall et al., (2006). .............................................................................. 28
27 3D view of shale diapirs (arrowed). Recognized seismically by intrusive low
amplitude reflections. The data cube represents a time interval of 1.7
seconds to 2.5 seconds ............................................................................ 29
28 The channel is truncated in the northwest area by a shale diapir (blue). .............. 30
ix
29 Timeslice at 1.996 seconds with increased amplitude gain. Reservoir #1 is the
large bright spot within the red square. ................................................... 32
30 RMS amplitude map from 50 ms window near the channel top. The high RMS
area (red square) matches the high amplitude area in Figure 29............... 33
31 Inline 815 showing a strong correlation between the amplitude bright spot with a
high sweetness response. ........................................................................ 34
32 Timeslice at 1.996 seconds showing amplitude bright spot with increased gain
interpreted as Reservoir #2 (red square). ................................................. 35
33 RMS amplitude map matching bright spot location in Figure 32 (red square). .... 36
34 Inline 751 showing a strong correlation between the amplitude bright spot with a
high sweetness response (blue circle). ..................................................... 37
35 Timeslice at 1.964 seconds showing a bright spot (red square) interpreted as
Reservoir #3. .......................................................................................... 38
36 RMS amplitude map showing a strong response in the area interpreted as
Reservoir #3. .......................................................................................... 39
37 Inline 719 showing a strong correlation between the amplitude bright spot with a
high sweetness response (blue circle). ..................................................... 40
1
INTRODUCTION
Extensive investigation for hydrocarbons has been conducted on land, leaving
offshore drilling as one of the last remaining frontiers for petroleum exploration.
Turbidite channels are one of the major drilling targets of offshore exploration programs.
Through the use of 3D seismic data, especially from West Africa, Gulf Coast, and North
Sea, the industry has significantly increased its knowledge about these complex deep
water reservoirs (Mayall et al., 2006).
Purpose
Understanding these complex deposits is important for hydrocarbon exploration
via reservoir characterization and development. The purpose of this study is to
characterize a turbidite channel and apply it to reservoir identification. Similar to the
approach described by Mayall et al., (2006), I characterized a turbidite channel
interpreted from 3D seismic data by:
Mapping important horizons such as, the main channel’s base and top
Describing and analyzing “key elements” found in turbidite channels such as,
sinuosity, facies, cut and fill episodes, and stacking patterns
Analyzing shale diapirs effects
Extracting attributes to locate possible reservoirs
Study Area
The study area is located within the Gulf of Guinea off the west coast of the Niger
Delta in Africa (Figure 1). The Niger Delta Complex covers an area of approximately
100,000 square miles; the offshore portion covers approximately 70,000 square miles
(Chukwu, 1991; Magbagbeola and Willis, 2007).
2
Sediments deposited within the study area consist of marine and fluvial sediments
that range in age from Cretaceous to Holocene (Kostenko et al., 2008). Short and
Stäublee (1965) described type sections for three main Niger Delta formations. These
formations, from oldest to youngest, are the Akata Shale, Agbada Formation, and the
Benin Formation. Roll-over anticlines, toe-thrust faults, shale diapirs, and deepwater
channel systems are major features present in the Niger Delta (Chukwu, 1991; Cross et
al., 2009).
Figure 1. Map of study area: offshore Niger Delta (Adapted from ESRI).
3
REGIONAL GEOLOGY
The Niger Delta is located at the southern end of the Benue trough and formed
from the failed arm of a rift triple junction. This occurred when South America and
Africa began to rift in the Late Jurassic; rifting ceased in the Late Cretaceous (Lehner and
De Ruiter, 1977). The Benue Trough itself represents the third failed arm of the rift
system (Owoyemi and Willis, 2006). Quaternary studies in this area show that if
sediment supply was relatively stable, submarine canyons could have been cut and filled
repeatedly in the same general area throughout the Tertiary (Burke, 1972).
Structural complexity results from growth faults, shale diapirs, and toe thrusts.
Two fold and thrust belts formed in the Tertiary and are still active in some areas. The
thrust belts compensate for extensional forces influenced by gravity on the continental
shelf. Corredor et al. (2005) divided the Niger Delta into five main structural zones or
sections (Figure 2 and Figure 3).
These zones include an
extensional area that is
characterized by growth faults and
rollover anticlines; followed by a
shale diapir zone. Continuing
basinward, the delta has an inner
and outer fold and thrust belt
separated by a transitional
detachment zone.
Figure 2. Schematic aerial view of Niger Delta structural zones (Corredor et al., 2005).
4
Figure 3. Uninterpreted and interpreted seismic data of the five Niger Delta structural zones (Corredor et al., 2005).
5
Stratigraphy
The Niger Delta consists of three main Tertiary formations: the Akata Shale,
Agbada Formation, and Benin Formation (Figure 4) (Short and Stäublee, 1965). The
Akata Shale is the oldest formation and represents a deep marine depositional
environment (Figure 4 and Figure 5). The Agbada Formation overlies the Akata Shale
and represents a nearshore environment (Figure 4 andFigure 5). The Benin Formation
overlies the Agbada and represents the active deltaic environment (Figure 4 andFigure 5)
Figure 4. Niger Delta stratigraphic column. The three main study area formations are circled (red) (Modified from Doust and Omatsola, 1990).
6
(Burke, 1972).
Figure 5. Spontaneous potential and resistivity logs for the Benin, Agbada, and Akata type sections (Short and Stäublee, 1965). Akata Shale
The Akata Shale underlies the entire Niger Delta and reaches a thickness up to
22,000 feet in some areas (Doust and Omatsola, 1990; Evamy et al., 1978; Short and
Stäublee, 1965). In the Paleocene, the Sokoto transgression deposited the Akata Shale,
7
which became the primary source rock for the Niger Delta petroleum system (Doust and
Omatsola, 1990). The Akata also contains turbidite sands deposited when the delta was
developing and is the most likely location of the turbidite channel for this study (Burke,
1972).
An interesting characteristic of the Akata Shale is its mobility. The shale is under-
compacted and over-pressured from the overlying, denser Benin Formation; this
combination of factors caused the Akata to intrude the overlying formations creating
shale diapirs (Figure 6) (Burke, 1972). These diapirs increase seismic interpretation
complexity because they have chaotic amplitude reflection patterns and distort channel
features.
8
Figure 6. Shale diapirs (outlined in blue) intruding overlying beds.
9
Agbada Formation
The Agbada Formation underlies the entire Niger delta area and is approximately
10,000 to 12,000 feet thick (Short and Stäublee, 1965; Avbovbo, 1978). Short and
Stäublee (1965) approximate the Agbada’s age to be Pliocene to Eocene with the oldest
part of the formation in the north and youngest in the south. It is composed of
interbedded sandstones and shales. The upper Agbada is dominated by sandstones with
fewer shale intervals. The lower Agbada contains more shale beds with minor
intercalated sandstones (Short and Stäublee, 1965; Tuttle et al., 2009). Most petroleum in
the Niger Delta is produced from the Agbada Formation. It is the primary reservoir and
cap rock, with most petroleum extracted from rollover anticlines formed from growth
faults (Short and Stäublee, 1965). Evamy et al., (1978), suggested that in some areas
lower Agbada shale units are also contributing source rocks.
Benin Formation
The Benin Formation is the youngest primary Niger Delta rock unit with an age
range from Miocene to Recent. The Benin Formation is present across the entire Niger
delta and consists of the present coast line (Short and Stäublee, 1965). It consists of
predominantly sand with minor shale intercalations and is described as coarse grained to
very fine grained, poorly sorted, subangular to well rounded alluvial and upper coastal
plain sands (Short and Stäublee, 1965). Its thickness varies, but may be more than 6,000
feet thick in some areas (Avbovbo, 1978; Short and Stäublee, 1965).
10
TURBIDITES
A turbidity current is a type of density current initiated by gravity and
morphologically resembles meandering rivers in a subaerial environment (Weser, 1977).
In some cases, continental shelf sediments build up and become unstable. When failure
occurs, these sediments flow down the continental slope and carve out a canyon like
feature. However, some density currents are not erosive and only deposit sediment
(Bouma et al., 2002). These after formation submarine canyons act as a conduit for
turbidity currents and their resulting deposits, termed turbidites. Turbidity currents can
also form when sea level drops and exposes the continental shelf. Continental runoff,
flows across the exposed shelf and incises into the shelf and continental slope, forming
incised valleys (Bouma et al., 2002). Figure 7 shows a simple depiction of a turbidite
system.
Figure 7. Turbidite system depiction highlighting it submarine canyon and cross sectional views of turbidite channel deposits. Modified from Bouma et al., (2000).
11
As turbidity currents flow from the canyon to basin floor they lose momentum
and deposit a heterogeneous sediment mixture. Turbidite channels are characterized in
seismic data by high amplitude chaotic reflection patterns (Figure 8) (Bouma et al., 1985;
Weimer, 1989). Many turbidite systems display stacking patterns with younger channels
deposited on top of older channels. Stacked turbidites are known as a turbidite complex
and are often important deep water reservoirs because they contain large amounts of sand
encased in shales (Bouma et al., 2002; Mayall et al., 2006).
Figure 8. Southwest - northeast crossline 3407 showing recoginition of channel by choatic reflection patterns. The yellow horizon represents the channel top and green represents the base. The vertical scale is in seconds. The index map located in the top right corner of the image shows the crossline location within the survey. Mayall et al. (2006) explained that turbidite channels are rarely identical, but
possess four basic elements consistently which aid in a successful seismic interpretation.
These elements are described as the channels’ sinuosity, facies, cut and fill episodes, and
12
stacking patterns. The configuration of these elements helps determine sand and shale
distribution within the channel.
13
METHODS
This study is based on a model set forth by Mayall et al., (2006) in which they
explain that a turbidite channel is a complex environment that can be broken down into
four elements for efficient characterization. These key elements are: sinuosity, facies, cut
and fill episodes, and stacking patterns. In addition, the Niger Delta contains shale diapirs
which are an added element that needs to be considered for this study. This approach plus
attribute analysis will be utilized to characterize the turbidite channel and identify
potential reservoirs.
Data Description
The 3D pre-stack migrated seismic data were provided by an anonymous donor.
The data set used for this study is missing data in several sections. The entire survey
covers approximately 21.8 square miles. The data consists of 576 inlines oriented
northeast - southwest and 460 crosslines oriented southeast - northwest. Inline interval
was 61.5 feet apart and crossline interval was 41 feet. Due to the proprietary nature of
this 3D data the exact location is not known and there was no associated core or well
data. As a result, my interpretation is based on reflection patterns, knowledge from
previous work, and seismic attributes.
Mapping
The stacked turbidite channel present in the seismic data was analyzed and
interpreted using Kingdom SMT 8.5. The chaotic reflection patterns present required
manual picking when mapping key horizons. The main channel top, base, and individual
subchannels were mapped using a one inline spacing interval. The only horizon not
manually picked was a parallel reflector above the channel. This parallel reflector was
14
picked using 3D Hunt and was used to flatten the data. The 3D Hunt feature interprets a
chosen reflector throughout the entire data set.
Attributes
An attribute is any measureable property of seismic data (Schlumberger Oil Field
Glossary). Attributes were extracted to characterize channel features and for reservoir
identification. The attributes generated and analyzed in this study consisted of Amplitude,
Time, Gain Amplitude, Peak Amplitude, Root Mean Squared (RMS), isochron, and
Sweetness. Peak Amplitude, Gain Amplitude, and RMS attributes are amplitude based
and show differences in reflectivity magnitude related to acoustic impedance change.
Isochrons are time-based and shows thickness between two interpreted horizons.
Sweetness is calculated by dividing the instantaneous amplitude by the square rooted
instantaneous frequency. Areas with high sweetness have been interpreted as areas
containing sand or hydrocabons.
15
INTERPRETATION
The main turbidite channel in the Niger Delta data was determined by the
termination of parallel amplitude reflectors against a convex downward feature. This
feature is filled with chaotic reflection patterns and contains continuous parallel reflectors
above and below, which is characteristic of turbidite channels in seismic data (Figure 8
and Figure 9) (Bouma et al., 1985; Weimer, 1989). Mayall et al., (2006) determined their
channel base recognizing the same reflection pattern geometry (Figure 10).
1.800
1.900
2.000
2.100
2.200
Project: O_hna
Project Location: O_survey_1 Line 908.0, Amplitudes
908.03300.0
908.03400.0
908.03500.0
Line:Trace:
1.800
1.900
2.000
2.100
2.200
24240.39821443.42818646.45915849.49013052.52110255.5537458.5834661.6141864.646-932.323-3729.292-6526.262-9323.230-12120.199-14917.168-17714.137-20511.105
-24240.398
SW NE
1600 1800
2000 2200
2400
2600
2600
2800
2800
3000
3000
3200
3200
3400
3400
3600
3600
3800
3800
4000
4000
4200
4200
200
400
600
800
1000
1200
1400
643100 648100 653100 658100 663100 668100 673100 678100 683100 688100
583100
588100
593100
598100
603100
608100643100 648100 653100 658100 663100 668100 673100 678100 683100 688100X/Y:
Meters
583100
588100
593100
598100
603100
608100
N
Figure 9. Inline 908 showing the main turbidite channel determined by termination of amplitude reflectors against a convex downward shaped feature. The green horizon is the main channel base and the yellow horizon represents the channel top. Using the planimeter tool, the approximate channel size is 5.85 miles long and
1.67 miles wide, covering an area of 8.25 square miles. Figure 11 and Figure 12 are time
structure maps showing regional tilt of the study area with structural highs in the southern
portion of the data and lows to the north. The deepest part of the channel is represented
by the blue areas in Figure 11. This area contains more accommodation space and
NW SE
16
therefore thicker sediments. Figure 13 is an isochron map showing channel thickness
with thicker intervals shown in red, which matches the deep areas in Figure 11.
Figure 10. Mayall et al., (2006) defining the turbidite channel based on reflection characteristics. The yellow horizon represents the channel base.
2800
2800
3000
3000
3200
3200
3400
3400
3600
3600
3800
3800
4000
4000
400
400
600
600
800
800
1000
1000
1200
1200
1400
1400
653100 658100 663100
588100
593100
653100 658100 663100X/Y:Meters
588100
593100
1.7181.7551.7911.8281.8651.9011.9381.9752.0112.0482.0852.1222.1582.1952.2322.2682.3052.3422.3782.4152.452
N
Figure 11. Channel base time structure map. The main channel’s deepest parts are represented by the blue areas and a structural high to the south is shown in yellow and red.
N
17
2600
2600
2800
2800
3000
3000
3200
3200
3400
3400
3600
3600
3800
3800
4000
4000
4200
4200
200
200
400
400
600
600
800
800
1000
1000
1200
1200
1400
1400
653100 658100 663100 668100
588100
593100
653100 658100 663100 668100X/Y:Meters
588100
593100
1.6041.6271.6511.6741.6981.7211.7451.7681.7921.8161.8391.8631.8861.9101.9331.9571.9802.0042.0272.0512.074
N
Figure 12. Channel top time structure map. Structural highs are present in the southern section are represented by red and yellows followed by lower areas to the north.
2800
2800
3000
3000
3200
3200
3400
3400
3600
3600
3800
3800
4000
4000
4200
4200
400
400
600
600
800
800
1000
1000
1200
1200
1400
1400
0 5065 m1013 2026 3039 4052
Scale = 1:101300
652100 655100 658100 661100 664100
589100
592100
595100
Project: O_hna
Project Location:
Horizon: isochron (hnali) (DeepSkyBlue), Data Type: Isochron
0 5065 m1013 2026 3039 4052
Scale = 1:101300
652100 655100 658100 661100 664100X/Y:Meters
589100
592100
5951000.2850.2700.2550.2400.2250.2100.1950.1800.1650.1500.1350.1200.1050.0900.0750.0600.0450.0300.012
N
Figure 13. Isochron map showing the main channel thickness. Thicker intervals are represented by reds and yellows and thinner areas by blues.
N
N
18
Sinuosity
Mayall et al. (2006) postulated four causes of sinuosity in turbidite channels:
initial erosive base, lateral stacking, lateral accretion, and sea-floor topography. Although
the seismic survey is missing data in some sections, the channel’s sinuosity was resolved
and examples of the previously mentioned causes were present. Channel sinuosity was
analyzed using time slices, which are horizontal amplitude slices through the data at a
chosen time. This provides a map view of the channel (Figure 14). The different episodes
of deposition and variation of the density current itself causes the channels to be stacked
successively in different patterns. In map view, sinuous stacked channels can resemble a
“long box full of snakes” (Figure 15) (Bouma et al., 2002 p. 61).
Figure 14. Time slice at 2.088 seconds showing a map view of the main turbidite channel (outlined in blue) and its sinuousity.
19
RMS and Peak Amplitude attributes are amplitude based and are often used to
infer changes in lithology because variation in amplitude correlate to changes in acoustic
impedance. Root mean squared (RMS) amplitude was used to differentiate the channel
from surrounding material and was helpful in showing subchannel sinuosity (Figure 16).
The yellow areas represent higher amplitude reflectivity which can be inferred as an area
containing more sand than the lower RMS values represented by green areas. The Peak
Amplitude attribute highlights sinuosity within the main channel and channel cut-offs,
known as oxbows (Figure 17). These attributes provide evidence that channel fill
sediments are different than surrounding rocks and that subchannels are highly sinuous.
N
Figure 15. "Box of snakes" schematic of stacked subchannels (Bouma et al., 2002 p. 61) compared to 3D view the Niger Delta data. Green horizon represents the main channel base. The 3D cube represents a time interval from 2.148 to 2.5 seconds.
20
3000
3000
3200
3200
3400
3400
3600
3600
3800
3800
600
600
800
800
1000
1000
1200
1200
0 3686 m737 1474 2212 2949
Scale = 1:73717
655100 658100 661100 664100
589100
592100
Project: O_hna
Project Location:
0 3686 m737 1474 2212 2949
Scale = 1:73717
655100 658100 661100 664100X/Y:Meters
589100
592100
152481.344143332.469134183.594125034.703115885.828106736.94597588.06388439.18079290.29770141.42260992.53951843.65642694.77733545.89824397.01615248.135
0
N
Figure 16. The sinuous turbidite channel (yellow) and surrounding shale (green). Map is an RMS amplitude from a 90ms window within the channel.
3000
3000
3200
3200
3400
3400
3600
3600
3800
3800
600
600
800
800
1000
1000
1200
1200
0 3686 m737 1474 2212 2949
Scale = 1:73717
655100 658100 661100 664100
589100
592100
Project: O_hna
Project Location:
Horizon: hate attribute (hnali) (Red), Data Type: Amplitudes
0 3686 m737 1474 2212 2949
Scale = 1:73717
655100 658100 661100 664100X/Y:Meters
589100
592100
509936.375481606.594453276.813424947.000396617.188368287.406339957.594311627.813283298.000254968.203226638.406198308.594169978.797141649.000113319.20384989.39856659.60228329.8010
N
Figure 17. Peak Amplitude map showing stacked channel sinuosity and meander cut-offs/oxbows.
Oxbow
Oxbow
21
Facies
Turbidite channels contain a wide variety of sediments and rock types depending
on the nature of the tubidity flow and material derived from the surrounding environment.
Mayall and Stewart (2000) proposed dividing turbidite channel fill into four main facies:
basal lags, slumps, high net to gross (N:G) stacked channels, and low N:G channel-levee
(Figure 18). This approach was chosen because facies distribution is important for
reservoir characterization and often recognizable in most seismic data (Mayall et al.,
2006).
Figure 18. NW to SE cross section comparing the Niger Delta data (a) and the four main turbidite facies as described by (b) Mayall and Stewart (2000).
Slumps
Basal lag
High N:G stacked channels
Low N:G levee
Slumps
Basal lag
High N:G stacked channels
Low N:G levee
(a)
(b)
22
Figure 19. Facies interpretation from Mayall et al., (2006). The amplitude reflection patterns and facies distribution is similar to the Niger Delta data (Figure 18a). Most basal lag deposits consist of coarse sandstones and conglomerates and have
a high net sand content (Labourdette, 2007). They generally have higher acoustic
impedance than adjacent shales and are distinguished in seismic data as bright reflectors
at the channel base (Figure 18a and Figure 19) (Mayall et al., 2006). These lag deposits
are the first channel fill deposits following initial erosion and are significant due to their
potential as permeable and porous zones to accumulate petroleum (Labourdette, 2007).
Slumps are recognized seismically by weak non-stratified reflections (Figure 19)
(Mayall et al., 2006). The area in Figure 18a labeled as a “slump” was interpreted as such
due to its dim reflection, lack of bedding, and position near the channel edge. The slump
material was likely derived from the channel wall or nearby source (Labourdette, 2007).
23
The slump facies is important because it can act as a fluid flow barrier and is not an ideal
reservoir (Mayall et al., 2006).
The high net to gross facies consists of multiple channels stacking and is
recognized on seismic data as a cluster of strong convex downward reflections (Figure 18
and Figure 19). This facies contains mostly sand with possible lags at the base of
individual channels (Mayall et al., 2006). The stacked channel facies is the ideal
petroleum reservoir facies due to its high sand content and good connectivity. Mayall et
al., (2006) used the phrase “axial core” to describe a channel fill with moderate N:G and
focused channel stacking (Figure 20). The net to gross distribution shown in Figure 21 is
an example of the axial core configuration.
Low N:G channel levees often form the last part of the channel fill and are
characterized on seismic data by weak to moderate semi-parallel amplitude reflections
(Figure 18a). They contain small sand pockets, but are not ideal reservoirs due to high
shale content (Mayall et al., 2006).
Figure 20. Schematics of stacked channel distributions and associated net to gross percentages (modified from Mayall et al., 2006).
24
1.800
1.900
2.000
2.100
2.200
Project: O_hna
Project Location: O_survey_1 Line 777.0, Amplitudes
777.03300.0
777.03400.0
777.03500.0
Line:Trace:
1.800
1.900
2.000
2.100
2.200
24240.39821977.96319715.52517453.08815190.65012928.21410665.7768403.3396140.9023878.4651616.027-646.410-2908.847-5171.284-7433.722-9696.159-11958.596-14221.033-16483.471-18745.908-21008.346
-24240.398
Figure 21. Inline 777 displaying an axial core of stacked channels and moderate N:G as shown in middle box of Figure 20. The chaotic reflections (blue circle) represent the stacked channels. Repeated Cutting and Filling
Within the main turbidite channel smaller subchannels have repeatedly eroded
pre-existing fill material and deposited younger sediments (Figure 22) (Labourdette,
2007; Mayall et al., 2006). Quaternary studies show that if controlling conditions were
constant, many incision and deposition episodes could have taken place in the same area
over an extended period of time (Burke, 1972). In areas that have been cut and filled
excessively, older channel remnants may be present. This increases the difficulty of
interpretation due to chaotic reflection patterns. Repeated cutting and filling is significant
because each episode can affect the reservoir quality and potential (Mayall et al., 2006).
NW SE
25
Figure 22. Inline 908(a) shows the main channel defined by the yellow (top) and green (base) horizons. Image (b) shows the interpreted subchannel bases (blue) within main channel. The amplitude reflection patterns in image (c) show several episodes of cutting and filling by the subchannels.
26
Stacking Patterns
Stacking occurs when older subchannels are partially eroded and younger
sediments are deposited on top or to the side of the previous channel (Figure 23). The
base of each successive subchannel is recognized by a high amplitude convex downward
reflection. As previously mentioned, stacked channels contain ideal reservoir
characteristics and understanding them can aid in a successful evaluation and
development of any reserves that may exist (Mayall et al., 2006).
Stacking patterns can vary greatly over short distances throughout the channel,
but are often generalized into two categories: vertical stacking and lateral stacking.
Vertical stacking occurs when channels are successively stacked directly on top of the
previous channel (Figure 24 and Figure 25). Vertical stacking may be related to channel
stability and focusing with little to no migration (Mayall et al., 2006); whereas lateral
Figure 23. Stacking of subchannels (blue) within main channel. Subchannels are recognized by a convex downward seismic expression.
27
stacking patterns are produced from channel migration in a particular direction (Figure
26).
Figure 25. Vertical stacking pattern example from Mayall et al., (2006) is similar Figure 24 from the Niger Delta.
Figure 24. Example of a vertical stacking pattern from the Niger Delta data.
28
Figure 26. Lateral stacking pattern comparison between the study area (a) and (b) from Mayall et al., (2006).
B
A
29
Shale Diapirs
Shale diapirs are present in the data and are recognized as intrusive vertical
structures that have low amplitude reflections. Diapirs were formed by the deposition of
higher density sands from the Benin Formation on top of the under-compacted and over-
pressured Akata Shale (Burke, 1972; Tuttle et al., 2009). This density differential caused
the mobile shale to intrude overlying formations, similar to the way salt domes form
(Figure 27).
Figure 27. 3D view of shale diapirs (arrowed). Recognized seismically by intrusive low amplitude reflections. The data cube represents a time interval of 1.7 seconds to 2.5 seconds
30
Shale diapirs disrupt channel morphology and cause chaotic reflection patterns in
the data. In the northwest portion of the survey, the main channel is truncated by diapiric
structures (Figure 28); furthermore, in some areas the channel is unrecognizable due to
the diapirs. The influence of shale diapirs on channel morphology is important for
reservoir characterization because they can form localities where oil and gas accumulate.
However, they can also have detrimental effects such as destroying previous reservoirs or
forming faults that act as leaks.
Figure 28. The channel is truncated in the northeast area by a shale diapir (blue).
Reservoir Identification
Using attributes such as, root mean squared (RMS) amplitude, amplitude gain,
and sweetness three potential reservoirs were identified. RMS was used to find areas with
high amplitude reflectivity because this correlates to areas with high acoustic impedance.
High RMS localities were interpreted as areas containing sand and possibly
31
hydrocarbons. Increasing the amplitude gain was used to locate bright spots and phase
changes in the data which are direct hydrocarbons indicators. The sweetness attribute was
used to locate areas with high amplitude reflectivity and low frequency which indicates
the presence of hydrocarbons.
Reservoir #1
Reservoir #1 is located in the north central part of the main channel and is the
largest reservoir (Figure 29). There is a good correlation with the bright spot in Figure 29
and the high RMS response in Figure 30. Inline 815 has high sweetness which matching
the amplitude bright spot in the same area (Figure 31).
Reservoir #2
Reservoir #2 is a smaller reservoir located southwest of Reservoir #1 (Figure 32).
Figure 33 is an RMS amplitude map that shows a high RMS response in the same area as
the amplitude bright spot in Figure 32. Figure 34 shows inline 751 with an area
containing high sweetness and two direct hydrocarbon indicators, an amplitude bright
spot and phase change.
Reservoir #3
Reservoir #3 is located southwest of Reservoirs #1 and #2 (Figure 35). It was
interpreted as a reservoir due to its high RMS amplitude response that matched an
amplitude bright spot and high sweetness response in inline 719 (Figure 36 and Figure
37).
32
2600
2600
2800
2800
3000
3000
3200
3200
3400
3400
3600
3600
3800
3800
4000
4000
4200
4200
400
400
600
600
800
800
1000
1000
1200
1200
1400
1400
653100658100
663100
588100
593100
653100658100
663100X/Y:
Meters588100
593100
254179.000224850.641195522.297166193.953136865.609107537.26678208.92248880.57019552.227-9776.119-39104.465-68432.813-97761.156-127089.500-156417.844-185746.188-215074.531
-254179.000
N
Figure 29. Timeslice at 1.996 seconds with increased amplitude gain. Reservoir #1 is the large bright spot within the red square.
33
Figure 30. RMS amplitude map from 50ms window near the channel top. The high RMS area (red square) matches the high amplitude area in Figure 29.
2800
2800
3000
3000
3200
3200
3400
3400
3600
3600
3800
3800
4000
4000
400
400
600
600
800
800
1000
1000
1200
1200
653100658100
663100
593100
653100658100
663100X/Y:
Meters593100
277790.563261180.406244570.250227960.094211349.938194739.781178129.625161519.453144909.297128299.148111688.98495078.82878468.67261858.51645248.35528638.199
954.602
N
34
1.900
2.000
2.100
2.200
815.03300.0
815.03400.0
815.03500.0
Line:Trace:
1.900
2.000
2.100
2.200
406686.406375402.844344119.281312835.719281552.125250268.563218985.000187701.438156417.859125134.28993850.71962567.14831283.5780.00781-31283.563-62567.133-93850.703-125134.273-156417.844-187701.406-218984.984-250268.563-281552.125-312835.688-344119.250-375402.844-406686.406
1.900
2.000
2.100
2.200
815.03300.0
815.03400.0
815.03500.0
Line:Trace:
1.900
2.000
2.100
2.200
107052.203102934.81398817.42294700.03190582.64186465.24282347.85278230.46174113.06369995.67265878.28161760.89157643.49653526.10249408.71145291.32041173.92637056.53132939.14128821.74824704.35520586.96316469.57012352.1788234.7854117.3930
Figure 31. Inline 815 showing a strong correlation between the amplitude bright spot with a high sweetness response.
35
2600
2600
2800
2800
3000
3000
3200
3200
3400
3400
3600
3600
3800
3800
4000
4000
4200
4200
400
400
600
600
800
800
1000
1000
1200
1200
1400
1400
Well_D
654100659100
664100
588900
593900
654100659100
664100X/Y:
Meters588900
593900
406684.000359758.938312833.844265908.781218983.688172058.625125133.53978208.46131283.387-15641.690-62566.766-109491.844-156416.922-203342.000-250267.078-297192.156-344117.219-406684.000
N
Figure 32. Timeslice at 1.996 seconds showing amplitude bright spot with increased gain interpreted as Reservoir #2 (red square).
36
2800
2800
3000
3000
3200
3200
3400
3400
3600
3600
3800
3800
4000
4000
400
400
600
600
800
800
1000
1000
1200
1200
653100658100
663100
593100
653100658100
663100X
/Y:M
eters593100
277790.563261180.406244570.250227960.094211349.938194739.781178129.625161519.453144909.297128299.148111688.98495078.82878468.67261858.51645248.35528638.199
954.602
N
Figure 33. RMS amplitude map matching bright spot location in Figure 32 (red square).
37
1.900
2.000
2.100
2.200
751.03300.0
751.03400.0
Line:Trace:
1.900
2.000
2.100
2.200
406686.406375402.844344119.281312835.719281552.125250268.563218985.000187701.438156417.859125134.28993850.71962567.14831283.5780.00781-31283.563-62567.133-93850.703-125134.273-156417.844-187701.406-218984.984-250268.563-281552.125-312835.688-344119.250-375402.844-406686.406
1.900
2.000
2.100
2.200
751.03300.0
751.03400.0
Line:Trace:
1.900
2.000
2.100
2.200
107052.203102934.81398817.42294700.03190582.64186465.24282347.85278230.46174113.06369995.67265878.28161760.89157643.49653526.10249408.71145291.32041173.92637056.53132939.14128821.74824704.35520586.96316469.57012352.1788234.7854117.3930
Figure 34. Inline 751 showing a strong correlation between the amplitude bright spot with a high sweetness response (blue circle).
38
2800
2800
3000
3000
3200
3200
3400
3400
3600
3600
3800
3800
4000
4000
400
400
600
600
800
800
1000
1000
1200
1200
1400
1400
653100658100
663100
588100
593100
653100658100
663100X/Y:
Meters588100
593100
406686.406359761.063312835.719265910.344218985.000172059.641125134.28978208.93831283.578-15641.777-62567.133-109492.484-156417.844-203343.203-250268.563-297193.906-344119.250-406686.406
N
Figure 35. Timeslice at 1.964 seconds showing a bright spot (red square) interpreted as Reservoir #3.
39
2800
2800
3000
3000
3200
3200
3400
3400
3600
3600
3800
3800
4000
4000
400
400
600
600
800
800
1000
1000
1200
1200
653100658100
663100
593100
653100658100
663100X/Y:
Meters593100
277790.563261180.406244570.250227960.094211349.938194739.781178129.625161519.453144909.297128299.148111688.98495078.82878468.67261858.51645248.35528638.199
954.602
N
Figure 36. RMS amplitude map showing a strong response in the area interpreted as Reservoir #3.
40
1.700
1.800
1.900
2.000
2.100
2.200
2.300
719.03300.0
719.03400.0
719.03500.0
Line:Trace:
1.700
1.800
1.900
2.000
2.100
2.200
2.300
406686.406375402.844344119.281312835.719281552.125250268.563218985.000187701.438156417.859125134.28993850.71962567.14831283.5780.00781-31283.563-62567.133-93850.703-125134.273-156417.844-187701.406-218984.984-250268.563-281552.125-312835.688-344119.250-375402.844-406686.406
1.900
2.000
2.100
2.200
719.03300.0
719.03400.0
719.03500.0
Line:Trace:
1.900
2.000
2.100
2.200
107052.203102934.81398817.42294700.03190582.64186465.24282347.85278230.46174113.06369995.67265878.28161760.89157643.49653526.10249408.71145291.32041173.92637056.53132939.14128821.74824704.35520586.96316469.57012352.1788234.7854117.3930
Figure 37. Inline 719 showing a strong correlation between the amplitude bright spot with a high sweetness response (blue circle).
41
CONCLUSIONS
The stacked turbidite channel characterization yielded important information
about turbidite channel morphology. It was determined that the main channel contains
highly sinuous subchannels and channel cut-offs, also known as oxbows, which can have
implications for sand distribution. The main channel’s facies are variable, but four main
facies: basal lags, slumps, high N:G stacked channels, and low N:G channel levees can be
resolved in the seismic data. The facies are important because they can restrict or allow
fluid flow. Within the channel system several subchannels have been successively
stacked; most commonly in vertical and lateral patterns which can affect reservoir
connectivity. Shale diapirs are present in the data and have disrupted the channel in some
areas.
Using attributes such as, amplitude, RMS amplitude, and sweetness three
reservoirs were located and recommended for development. These locations were chosen
because they contained direct hydrocarbon indicators such as, bright spots, flat spots, and
phase changes which matched areas with high RMS and Sweetness values. Applying
turbidite channel characterization along with attribute analysis aids in understanding
these complex deposits and identifying potential reservoirs.
42
FUTURE WORK
Computing an Inversion would greatly enhance the interpretation. Inversion is
reverse processing that can yield rock properties from the data. Upon finishing the
Inversion process, lithologies and their distribution within the channel might be able to be
determined. I would also like to compute important attributes such as coherency,
curvature, and spectral decomposition, but these are not available on the software
package provided by Fort Hays State University Geosciences Department. Well logs and
core data would also provide quality control and a means for stratigraphic correlation
with the seismic data, but due to the proprietary nature of this data and field area it is not
likely to become available in the foreseeable future.
43
REFERENCES
Avbovbo, A.A., 1978, Tertiary lithostratigraphy of Niger Delta: American Association of
Petroleum Geologists Bulletin, 62, 295-306.
Bouma, A. H., W. R. Normark, and N. E. Barnes, 1985, Submarine fans and related
turbidite systems: developments in sedimentary geology, New York, Springer-
Verlag, 351.
Bouma, A.H., 2000, Fine-grained, mud-rich turbidite systems: model and comparison
with coarse-grained, sand-rich systems: in A.H Bouma and C.G. Stone, eds.,
Fine-grained turbidite systems, American Association of Petroleum Geologists,
Memoir 72/SEPM Special Publication, 68, 9-20.
Bouma, A. H., R. A. Sprague, and A. M. Khan, 2002, Geological reservoir characteristics
of fine-grained turbidite systems: Gulf Coast Association of Geological
Societies Transactions, 52, 59-64.
Burke, K., 1972, Longshore drift, submarine canyons and submarine fans in development
of Niger Delta: American Association of Petroleum Geologists Bulletin, 56,
1975-1983.
Chukwu, G.A., 1991, The Niger Delta Complex basin: Stratigraphy, structure, and
hydrocarbon potential: Journal of Petroleum Geology, 14, 211-220.
Corredor, F., J. H. Shaw, and F. Bilotti, 2005, Structural styles in the deep-water fold-
and-thrust belts of the Niger Delta: American Association of Petroleum
Geologists Bulletin, 89, 753-780.
Cross, N. E., A. Cunningham, R.J. Cook, A. Taha, E. Esmaie, and N. El Swidan, 2009,
3D Seismic geomorphology of a deepwater slope channel system: the Sequoia
44
Field, offshore west Nile Delta, Egypt: Adapted from oral presentation at AAPG
Convention, Denver, Colorado, June 7-10, 2009.
Doust, H., and E. Omatsola, 1990, Niger Delta, American Association of Petroleum
Geologists Memoir, 48, 201-238.
Evamy, B. D., J. Haremboure, P. Kamerling, W. A. Knaap, F. A. Molloy, and P. H.
Rowlands, 1978, Hydrocarbon habitat of Tertiary Niger Delta: American
Association of Petroleum Geologists Bulletin, 62, 277-298.
Kostenko, O.V., S.J. Naruk, W. Hack, M. Poupon, H.J. Meyer, M. M. Glukstad, C.
Anowai, and M. Mordi, 2008, Structural evaluation of column-height controls at a
toe-thrust discovery, deep-water Niger Delta: American Association of Petroleum
Geologists Bulletin, 92, 1615-1638.
Labourette, R., 2007, Integrated three-dimensional modeling approach of stacked
turbidite channels: American Association of Petroleum Geologists Bulletin, 91,
1603-1618.
Lehner, P., and P.A.C. De Ruiter, 1977, Structural history of Atlantic margin of Africa:
American Association of Petroleum Geologists Bulletin, 61, 961-981.
Magbabbeola, O.A., and B.J. Willis, 2007, Sequence stratigraphy and syndepositional
deformation of the Agbada Formation, Robertkiri field, Niger Delta, Nigeria:
American Association of Petroleum Geologists Bulletin, 91, 945-958.
Mayall, M., and I. Stewart., 2000, The architecture of turbidite slope channels. In:
Weimer, P., Slatt, R.M., Coleman, J.L., Rosen, N., Nelson, C.H., Bouma, A.H.,
Styzen, M., Lawrence, D.T. (Eds.), Global Deep-Water Reservoirs: Gulf Coast
45
Section SEPM Foundation 20th Annual Bob F Perkins Research Conference,
578–586.
Mayall, M., E. Jones, and M. Casey, 2006, Turbidite channel reservoirs-Key elements in
facies prediction and effective development: Marine and Petroleum Geology, 23,
821-841.
Owoyemi, A.O., and B.J. Willis, 2006, Depositional patterns across syndepositional
normal faults, Niger Delta, Nigeria: Journal of Sedimentary Research, 76, 346-
363.
Short, K. C., and A. J. Stäublee, 1965, Outline of geology of Niger Delta: American
Association of Petroleum Geologists Bulletin, 51, 761-779.
Tuttle, M.L.W., R.R. Charpentier, and M.E. Brownfield, 1999, The Niger Delta
Petroleum System: Niger Delta Province, Nigeria Cameroon, and Equatorial
Guinea, Africa: United States Geological Survey open-file report, 99-50-H, 1-64.
Weimer, P., 1989, Sequence stratigraphy of the Mississippi Fan (Plio-Pleistocene), Gulf
of Mexico: Geo-Marine Letters, 9, 185–272.
Weser, O.E., 1977, Deep water oil sand reservoirs: ancient case histories and modern
concepts education course note series #6: American Association of Petroleum
Geologists Department of Education, 2-10.