Fort Hays State University Fort Hays State University

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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

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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

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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.

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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.

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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

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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

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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

-

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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

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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).

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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.

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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).

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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).

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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

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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.

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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.

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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.

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Figure 13. Isochron map showing the main channel thickness. Thicker intervals are represented by reds and yellows and thinner areas by blues.

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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.

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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

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Figure 16. The sinuous turbidite channel (yellow) and surrounding shale (green). Map is an RMS amplitude from a 90ms window within the channel.

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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

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-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

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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

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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.

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277790.563261180.406244570.250227960.094211349.938194739.781178129.625161519.453144909.297128299.148111688.98495078.82878468.67261858.51645248.35528638.199

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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

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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

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Figure 32. Timeslice at 1.996 seconds showing amplitude bright spot with increased gain interpreted as Reservoir #2 (red square).

36

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Figure 33. RMS amplitude map matching bright spot location in Figure 32 (red square).

37

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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

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Figure 35. Timeslice at 1.964 seconds showing a bright spot (red square) interpreted as Reservoir #3.

39

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Figure 36. RMS amplitude map showing a strong response in the area interpreted as Reservoir #3.

40

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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

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