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2D seismic data and gas chimney interpretation in the South 2D seismic data and gas chimney interpretation in the South

Taranaki Graben, New Zealand Taranaki Graben, New Zealand

Taqi Talib Alzaki

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Recommended Citation Recommended Citation Alzaki, Taqi Talib, "2D seismic data and gas chimney interpretation in the South Taranaki Graben, New Zealand" (2016). Masters Theses. 7495. https://scholarsmine.mst.edu/masters_theses/7495

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2D SEISMIC DATA AND GAS CHIMNEY INTERPRETATION IN THE SOUTH

TARANAKI GRABEN, NEW ZEALAND

by

TAQI TALIB ALZAKI

A THESIS

Presented to the Faculty of the Graduate School of the

MISSOURI UNIVERSITY OF SCIENCE AND TECHNOLOGY

In Partial Fulfillment of the Requirements for the Degree

MASTER OF SCIENCE IN GEOLOGY AND GEOPHYSICS

2016

Approved by

Dr. Kelly Liu

Dr. Stephen Gao

Dr. Wan Yang

ii

2016

Taqi Talib Alzaki

All Rights Reserved

iii

ABSTRACT

The Taranaki Basin is one of the major oil and gas producing basins offshore New Zealand.

The study area covers an area of 10,000 km² in the basin, and includes 171 2D seismic lines and

six wells, which are provided by the New Zealand Petroleum & Minerals. Some previous studies

refer to the study area as the South Taranaki Graben.

This thesis provides detailed mapping and interpreted subsurface stratigraphy and structure

of five horizons, i.e. basement top, Pakawau Group top, Kapuni Group top, Wai-iti Group top, and

seafloor. It undertakes studies of the relation between the basin evolution, faults, and depositional

patterns. In addition, the gas chimneys were investigated along with hydrocarbon migration

pathways to surrounding oil and gas fields.

The horizons were identified based on observed discontinuities and seismic attributes. The

seismic reflection characters of the horizons and their associated sequences are described in this

study. The horizons have been mapped as time structural, isochron, and isopach maps. Seismic

attributes were used in horizon interpretation and gas chimney detection.

The mapping of these horizons combined with seismic facies character provides detailed

overview of the structural evolution and depositional history in the study area. A map of the gas

chimneys along with the late normal faults distribution shows that the gas chimneys are mostly

common above the Cretaceous source rocks. Fault provide migration pathways for the gases

through the seal rocks. Petrophysical analysis shows that the Kapuni Group contains a sizable

amount of hydrocarbons, high porosities, and permeability. In combination with the structure of

the Kapuni Group, the hydrocarbons within the group migrate to two producing fields through two

migration pathways.

iv

ACKNOWLEDGMENTS

This thesis has benefitted greatly from the combined input of many generous people

who gave me their time, support, knowledge, and friendship. First I would like to express

my sincere gratitude to my advisor Dr. Kelly Liu for her continuous support and guidance

during my research work. In addition, I would like to spread my deep appreciation and

respect to my committee members Dr. Stephen Gao and Dr. Yang Wang; Dr. Stephen Gao

for his great advices to end up with a perfect thesis, and Dr. Yang Wang for his informative

adds to my petroleum geology understanding.

My thanks to the Saudi Ministry of Higher Education for the scholarship they

honored me with to get my master degree. Accordingly, the thanks go to my technical

advisor from Saudi Arabian Cultural Mission (SACM), Dr. Nabil Khoury for his help and

support.

In addition, I would like to thank all my colleagues in the Department of Geological

Sciences and Engineering for motivating me. Thanks for all my officemates at McNutt B16

who made the lab such a friendly place. Special thanks to my colleague Mr. Aamer

Alhakeem for his help and guidance.

v

TABLE OF CONTENTS

Page

ABSTRACT ....................................................................................................................... iii

ACKNOWLEDGMENTS ................................................................................................. iv

LIST OF ILLUSTRATIONS ............................................................................................. ix

LIST OF TABLE .............................................................................................................. xii

NOMENCLATURE ........................................................................................................ xiii

SECTION

1. INTRODUCTION ...................................................................................................... 1

1.1. AREA OF STUDY ............................................................................................. 1

1.2. PREVIOUS STUDIES........................................................................................ 4

1.3. OBJECTIVES ..................................................................................................... 4

2. REGIONAL GEOLOGY ........................................................................................... 6

2.1. BASIN EVOLUTION ........................................................................................ 6

2.1.1. Early Basin History .................................................................................. 7

2.1.2. Middle Basin History. .............................................................................. 9

2.1.3. Late Basin History. ................................................................................. 10

2.2. GEOLOGICAL STRATIGRAPHY ................................................................. 10

2.2.1. Pakawau Group. ..................................................................................... 11

2.2.2. Kapuni Group and Moa Group ............................................................... 14

2.2.3. Ngatoro Group and Wai-iti Group ......................................................... 15

2.2.4. Rotokare Group ...................................................................................... 15

vi

2.3. GEOLOGICAL STRUCTURES ...................................................................... 16

2.4. PETROLEUM SYSTEM .................................................................................. 18

2.4.1. Source Rocks .......................................................................................... 18

2.4.2. Reservoir Rocks ..................................................................................... 19

2.4.3. Seals and Traps ....................................................................................... 20

3. DATA AND METHOD ........................................................................................... 22

3.1. DATA ............................................................................................................... 22

3.2. METHOD ......................................................................................................... 22

3.2.1. Software .................................................................................................. 22

3.2.2. Seismic Stratigraphy and Horizon Mapping .......................................... 24

3.2.3. Seismic Attributes. ................................................................................. 24

3.2.3.1. Chaos..........................................................................................26

3.2.3.2. Instantaneous frequency.............................................................27

3.2.3.3. RMS amplitude. .........................................................................27

3.2.3.4. Reflection intensity. ...................................................................27

3.2.4. Gas Chimney Identification. ................................................................... 27

4. STRUCTURAL INTERPERTATION ..................................................................... 28

4.1. INTRODUCTION ............................................................................................ 28

4.2. SYNTHETIC GENERATION.......................................................................... 28

4.3. SYNTHETIC MATCHING .............................................................................. 28

4.4. HORIZON INTERPERTATION...................................................................... 32

4.4.1. Basement ................................................................................................ 32

4.4.2. Pakawau .................................................................................................. 38

vii

4.4.3. Kapuni .................................................................................................... 38

4.4.4. Wai-iti/Ngatoro. ..................................................................................... 43

4.5. FAULT INTERPERTATION ........................................................................... 45

4.6. SEISMIC FACIES ............................................................................................ 45

4.7. ISOPACH MAP ................................................................................................ 47

5. HYDROCARBON DETECTION ............................................................................ 54

5.1. GAS CHIMNEYS ............................................................................................. 54

5.2. GAS CHIMNEY DETECTION ....................................................................... 55

5.3. MIGRATION PATHWAYS ............................................................................ 56

6. PETROPHYSICS ..................................................................................................... 66

6.1. INTRODUCTION ............................................................................................ 66

6.2. VOLUME OF SHALE (VSH) .......................................................................... 67

6.3. POROSITY ....................................................................................................... 67

6.4. WATER SATURATION .................................................................................. 68

6.5. PERMEABILITY ............................................................................................. 70

6.6. WELL LOGS .................................................................................................... 71

6.7. CROSSPLOTS .................................................................................................. 73

7. CONCLUSION ........................................................................................................ 76

7.1. SEDIMENT DISTRIBUTION ......................................................................... 76

7.2. MANAIA FAULT ............................................................................................ 77

7.3. LIMITATIONS AND RECOMMENDATIONS ............................................. 77

viii

7.4. GAS CHIMNEYS ............................................................................................. 78

BIBLIOGRAPHY ............................................................................................................. 79

VITA ................................................................................................................................ 85

ix

LIST OF ILLUSTRATIONS

Figure Page

1.1. Offshore sedimentary basins in the New Zealand area (modified from Christie & Barker, 2013). .............................................................................................................. 2

1.2. Structural overview of the Taranaki Basin (modified from Baur, 2012; Stern & Davey, 1990; Mikenorton, 2010). ................................................................................ 3

2.1. Evolution time table in the Taranaki Basin (modified from King & Thrasher, 1996). ........................................................................................................................... 8

2.2. Tectonic forces acting on the Taranaki Basin (72 Ma.) (King & Thrasher, 1996). ..... 9

2.3. Stratigraphic units in the Taranaki Basin (Fohrmann et al., 2012). ........................... 13

2.4. Structural overview of the South Taranaki Graben in the Taranaki Basin (Reilly et al., 2014). ............................................................................................................... 17

2.5. Location of the Sub-Basin Kitchens in the Taranaki Basin (modified from Funnell et al., 2004). .................................................................................................. 19

2.6. History of the petroleum system in the Taranaki Basin (modified from King & Thrasher, 1996). ......................................................................................................... 21

3.1. The basemap of study area. ........................................................................................ 23

4.1. Uninterpreted seismic section of Line BO_hzt82a-118-2992. .................................. 29

4.2. Synthetic seismogram generated for Well Tahi-1. .................................................... 30

4.3. Seismic section of Line BO_hzt82a-142-2992 with the generated synthetic seismograms of Well Maui-2. .................................................................................... 31

4.4. Interpreted west-east seismic section of Line BO_hzt82a-118-2992. ....................... 34

4.5. Interpreted arbitrary seismic section including lines BO_hzt82a-142, BO_hzt82a-115, and BO_hzt82a-118. ....................................................................... 35

x

4.6. Interpreted south-north seismic Line BO_hzt82a-101. .............................................. 36

4.7. Time structure map of the basement top. ................................................................... 37

4.8. Time structure map of the Pakawau Group top. ........................................................ 39

4.9. Reflection intensity attribute on Line BO_hzt82a-118-2992..................................... 40

4.10. Seismic section of Line P116-81-21 showing toplaps on to the Kapuni top. .......... 41

4.11. Time structure map of the Kapuni Group top. ......................................................... 42

4.12. Seismic section of Line BO_hzt82a-118-2992 showing the unconformity of the Wai-iti group top. ....................................................................................................... 43

4.13. Time structure map of the Wai-iti Group top (Urenui Formation). ......................... 44

4.14. Seismic Line BO_hzt82a-118-2992 showing the Manaia Fault. ............................. 46

4.15. Reconstruction of depositional history in the Taranaki Basin (King & Thrasher, 1996). ......................................................................................................................... 47

4.16. Isopach map of the Pakawau Group. ....................................................................... 50

4.17. Isopach map of the Kapuni Group. .......................................................................... 51

4.18. Isopach map of both the Ngatoro and Wai-iti groups. ............................................. 52

4.19. Isopach map of the Rotokare Group. ....................................................................... 53

5.1. 2-D gas migration model in the south Taranaki Basin (Bradley et al., 2012). .......... 54

5.2. Line BO_hzt82a-136 showing the possible gas chimneys and normal faults using the chaos attribute. ..................................................................................................... 58

5.3. Line BO_hzt82a-136 showing the possible gas chimneys and normal faults using the edge attribute. ....................................................................................................... 59

5.4. Line BO_hzt82a-136 using instantaneous frequency. Possible gas chimneys are marked with red arrows. ............................................................................................ 60

xi

5.5. Line BO_hzt82a-152 showing the possible gas chimneys and normal faults using the chaos attribute. ..................................................................................................... 61

5.6. Line BO_hzt82a-152 showing the bright spots associated with the gas chimney using RMS amplitude attribute .................................................................................. 62

5.7. Map showing the seismic lines locations and the gas chimney distribution in the study area. .................................................................................................................. 63

5.8. Sub-basin kitchens and migration pathways to the known oil and gas fields in the Taranaki Basin (Octanex, 2003). ......................................................................... 64

5.9. Arbitrary seismic line including lines hzt82a-133, hzt82a-188, hzt82a-101, and hzt82a-90-1946 showing the migration pathway with arrows to the Maari field. ..... 65

6.1. Determination of the SPsh, SPcln, GRsh, and GRcln................................................ 68

6.2. Logs generated for Well Kupe-1 at the depth of the Kapuni Formation. .................. 69

6.3. Logs generated for Well Hochstetter-1 at the depth of the Kapuni Formation. ........ 70

6.4. Logs generated for Well Kea-1 at the depth of the Kapuni Formation. .................... 72

6.5. Logs generated for Well Maui-2 at the depth of the Kapuni Formation. .................. 73

6.6. Logs generated for Well Maui-4 at the depth of the Kapuni Formation. .................. 74

6.7. Neutron-density crossplot for Kapuni Group in Well Kupe-1................................... 75

xii

LIST OF TABLE

Table Page

2.1. Sequence groups representing the main stratigraphy and their formations in the Taranaki Basin. (modified from King & Thrasher, 1996; Higgs et al., 2010; King et al., 2010). ............................................................................................................... 12

3.1. Chart of the logs provided in each well (Mills, 2000; Palmer, 1984; Shell BP, 1970; Shell BP, 1976; STOS & Shell BP, 1970; EL). ............................................... 25

3.2. Formation tops for all the wells used in the study (Mills, 2000; Palmer, 1984; Shell BP, 1970; Shell BP, 1976; STOS & Shell BP, 1970; EL). ............................... 26

3.3. The KINGDOM software modules used in the study. ............................................... 24

4.1. Summary of interpreted seismic horizons.................................................................. 33

4.2. Seismic facies of the different depositional groups in the study. .............................. 49

6.1. Calculated reservoir properties for the Kapuni Group for each well. ........................ 66

xiii

NOMENCLATURE

Symbol Description

2D Two Dimensional

AI Acoustic impedance

BS Bit size

CALI Caliper log

CG Central Graben

DENS Density log

DENS_CORR Corrected Density log

DPHI Density porosity

DRHO Density log correction

DTC Delta T compressional

DTS Delta T shear

EM Emerald Basin

EMB Eastern Mobile Belt

ECB East Coast Basin

FM Formation

GR Gamma Ray log

GR_CORR Gamma Ray corrected

KB Kelly Bushing

km² Square kilometer

m Meters

xiv

MShB Marlborough shearbelts

msec Millisecond

NEUT Neutron log porosity (NPHI)

NEUT_CORR Corrected NPHI

NG Northern Graben

NIShB North Island shearbelts

NPHI Neutron porosity

PEF Photo Electric Cross Section

RC Reflection coefficient

RESD Induction deep resistivity (ILD)

RESD_CORR Borehole corrected ILD

RESM Medium Induction Log (ILM)

RESM_CORR Borehole corrected ILM

RESS Spherically Focused Log Unaveraged (SFLU)

RESS_CORR Borehole corrected SFL

RHOB Density log

RMS Root mean square

RT True resistivity

Rw Resistivity of water

sec Seconds

SMTPHIE Effective porosity

MSTSW Water saturation

SMTVSH Volume of shale

xv

SP Spontaneous Potential Log

SPcln Spontaneous Potential of clean sand layer

SPsh Spontaneous Potential of a shale layer

Sw Water saturation

TD Time-Depth

TEMP Temperature of the Borehole (WTBH)

TF Taranaki Fault

TENS Cable tension at surface

TWT, TWTT Two Way Time

VSH Volume of Shale

WB Wanganui Basin

WF Waimea/Flaxmore Fault

WP Western Platform

1. INTRODUCTION

1.1. AREA OF STUDY

A number of offshore sedimentary basins are located in the New Zealand area

(Figure 1.1). One of these basins is the Taranaki Basin, which is situated along the western

side of New Zealand’s north island and north of the south island (Figure 1.2). The majority

of the Taranaki Basin is offshore with an area about 100,000 km² and holds most of New

Zealand’s hydrocarbon production (Collier & Johnston, 1991; Collen & Newman, 1991).

The basin was formed through many tectonic processes and phases and was under water

for most of that period (Carter & Norris, 1976). These tectonic episodes resulted in the

formation of the many sub-basins and uplifting in the basin (King & Thrasher, 1996). The

study area lays in the South Taranaki Graben which is enclosed between the Taranaki Fault

and the Cape Egmont Fault (Figure 1.2) (Czochanska et al., 1988).

The Taranaki Basin is dominated by north-south subsurface geological structures.

The major feature of the basin is the Taranaki Fault, which defines the eastern boundary of

the basin (Figure 1.2). To the west, the basin shallows until it meets the oceanic bathymetric

high in the Challenger Plateau (Figure 1.1) (Thrasher, 1990). The basin merges with other

sub basins in the north, northwest and south which makes it hard to identify the limits of

the Taranaki Basin in those areas (Thrasher, 1990).

Oil exploration in the Taranaki Basin had been ongoing for more than 50 years. The

largest five fields (Maui, Kapuni, Kupe South, McKee, and Waihapa-Ngaere) have an

estimated recoverable reserves of 5 trillion cubic feet (TFC) of gas and 300 million barrels

(MMB) (Figure 1.1) (Hood et al., 2002; King & Thrasher, 1996). Other smaller fields had

been discovered but were not economical enough for production (King & Thrasher, 1996).

2

Figure 1.1. Offshore sedimentary basins in the New Zealand area. The inset map shows the oil and gas fields in the Taranaki Basin (modified from Christie & Barker, 2013).

Study area

3

Figure 1.2. Structural overview of the Taranaki Basin. A) The basin is located where the Pacific Plate subducts under the continental Australian Plate. B) Structural cross-section X-X’ shown in A). DTB: Deepwater Taranaki Basin; EMB: Eastern Mobile Belt; WB: Wanganui Basin; ECB: East Coast Basin (modified from Baur, 2012; Stern & Davey, 1990; Mikenorton, 2010).

EMB

DTB A

Study area

B

New Zealand

Western Stable platform

https://commons.wikimedia.org/wiki/User:Mikenorton

4

1.2. PREVIOUS STUDIES

The Taranaki Basin contains the largest oil and gas reserves in the New Zealand

area. Many potential reservoir formations within a complete petroleum system exist in the

basin. As a result, many studies were conducted around the basin.

King and Thrasher (1996) have conducted studies and collected many industrial

information along with published and unpublished work done in the Taranaki Basin since

1985 into a monograph. The monograph covers the geology of the petroleum system and

also includes the basin history and depositional system studies.

Bradley et al. (2012) have studied the detection of gas chimneys and their relation

with normal faults in the south of the basin. The study uses seismic attributes and other

methods to indicate the presence of gas chimneys. The study also analyzes the migration

path and mechanism for moving hydrocarbons through faults.

A detailed seismic mapping and interpretation was performed by Fohrmann et al.

(2012) on the KUP area in the basin. The study identified, mapped and gridded 17 seismic

horizons in the KUP area. The 17 seismic horizons have also been converted into time

structures and isopach maps.

1.3. OBJECTIVES

The objective of this study is to produce structural maps to understand the different

geological sequences and structures within the South Taranaki Basin. The geological

subsurface structures were mapped within five main horizons. The horizons are the

basement top, Pakawau Group top, Kapuni Group top, Wai-iti Group top, and seafloor.

These horizons divide the sediments within the basin into four main depositional cycles,

5

i.e. Pakawau Group, Kapuni Group, Ngatoro & Wai-iti Groups, and Rotokare Group (King

& Thrasher, 1996). The time structural, isochron, and isopach maps were constructed from

the interpreted horizons. Stratigraphic and structural interpretations were performed on the

four depositional sequences and the major faults (Cape Egmont, Manaia, Motumate) in the

study area.

Gas chimney detection was performed using seismic attributes such as chaos, edge,

frequency, and RMS amplitude. Normal faults associated with the gas chimneys were

mapped with the distribution of the gas chimneys in the study area. Finally, reservoir

properties were calculated using petrophysical analysis which includes the shale volume,

water saturation, hydrocarbon saturation, and permeability.

6

2. REGIONAL GEOLOGY

2.1. BASIN EVOLUTION

The Taranaki Basin is located in the western part of the northern island of New

Zealand on the boundary between the Australian Plate and Pacific Plate (Figure 1.2). The

basin began forming as a failed rift system in the late Early Cretaceous period (Uruski &

Wood, 1990). It continued to grow through subsidence processes during the Cretaceous

period until present (Stern & Davey, 1990). The Cretaceous sediments appear to be of

terrestrial origins, ranging from coarse conglomerates to mudstone, but marine

environment sediments are present in the subbasins (Collen & Newman, 1991; Thrasher,

1990). The presence of marine environment sediments in the subbasins indicates that there

were water bodies during the period of Cretaceous (Thrasher, 1990). Many subbasins

which were formed by the fault systems during the basin formation are scattered around

the Taranaki Basin.

The majority of the continental crust of the New Zealand subcontinent is under

water. The exposed continental crust formed the New Zealand islands (King & Thrasher,

1996). The continental crust under the Taranaki Basin is thinner and varies in thickness

(Uruski & Wood, 1990). Under the Western Stable Platform, the crustal thickness is around

28 km, but it changes (to 38 ± 3 km) under the southeastern margin of the basin (Figure

1.2) (Holt & Stern 1991, 1994). The New Caledonaia Basin, northwest of the Taranaki

Basin, has a crustal thickness of 15 km (Figure 1.1) (Shor et al., 1971). Although the

Taranaki Basin sits on a continental crust, it has evolved as a marine basin and was initially

part of the New Caledonaia Basin (King & Thrasher, 1996; Uruski & Wood, 1990). Early

7

Cretaceous marked the end of tectonic converging processes, ending with an erosional

surface between the basement rocks and the Taranaki Basin sediments (Bradshaw, 1989;

Uruski & Wood, 1990).

King and Thrasher (1996) divided the complex history of the Taranaki Basin into

three phases (Figure 2.1). The first is the early basin history during the mid-late Cretaceous

to Paleocene in which intracontinental rift and extensional forces acted on the basin. The

second phase is the middle basin history, which occurred during the Eocene and Early

Oligocene and is categorized by a post-rift and a passive margin, along with basin-wide

deposition and subsidence. The third phase is the late basin history, when the plate tectonic

regime acted as a convergent plate boundary with an active margin (Eastern Mobile Belt)

and a passive margin (Western Stable Platform) (Figure 1.2).

2.1.1. Early Basin History. The early basin history (from mid-late Cretaceous to

Paleocene) was mainly characterized as an intracontinental rift (King & Thrasher, 1996).

The early basin history included two main tectonic phases, i.e. pre-rift break up (mid-

Cretaceous) and syn-rift/draft phase (late Cretaceous and Paleocene) (King & Thrasher,

1996). Carter & Norris (1976) suggested that New Zealand separated from the Australia-

Antarctica plate during this period.

During the syn-rift/draft phase of the early basin history, the Rakopi and North

Cape formations were deposited in several subbasins and half-grabens formed by

subsidence and active normal faults striking in the north and northeast direction (King &

Thrasher, 1996). These sub-basins are small and elongated in the north and northeast

direction, and hold most of the petroleum production in the Taranaki Basin. During this

time, the Taranaki Rift was under extensional stresses and left-lateral shear forces caused

8

by oceanic spreading and opening of the Tasman Sea (Figure 2.2) (Carter & Norris, 1976;

Uruski & Wood, 1990; King & Thrasher, 1996).

Figure 2.1. Evolution time table of the Taranaki Basin (modified from King & Thrasher, 1996).

Formations

Rakopi

North Cape

Farewell

Kaimiro

Mangahewa Mckee

Turi

Tangaroa

Taimana

Tikorangi Otaraoa

Urenui Mt. Messenger

Taimana Taimana Taimana

Rotokare

9

Figure 2.2. Tectonic forces acting on the Taranaki Basin (72 Ma.). Opening of the Tasman Sea and the formation of the New Caledonia Basin and the Taranaki Basin (King & Thrasher, 1996).

2.1.2. Middle Basin History. The middle basin history spans through the Eocene

and Oligocene. During the period between the Paleocene to early Oligocene, the Taranaki

Basin was in a post-rift/drift passive margin phase (Hood et al., 2002; King & Thrasher,

1996). Subsidence changed from being restricted within the subbasins to become basin-

wide but with declining subsidence rates (King & Thrasher, 1996). Carter & Norris (1976)

suggested that the spreading of the Tasman Sea stopped during the Eocene period. The

Eocene deposits are the main reservoir rocks in the basin.

The Australian-Pacific Plate boundary began acting on the basin during the late

Eocene with transtensional forces affecting mostly the subbasins in the south (King &

Thrasher, 1996). The subbasins in the south were under extensional forces, where to the

10

west the passive margin development remained uninterrupted during the Paleocene to the

end of the Eocene (Knox, 1982).

The late Oligocene marked the beginning of rapid subsidence in the eastern part of

the basin, mainly due to the transpression forces on the Taranaki Fault (Figure 1.2) (Carter

& Norris, 1976). Rising sea levels, subsidence, and low clastic influx resulted in

developing an underfilled marine basin during this period (King & Thrasher, 1996). The

marine transgression reached its peak during this period (Carter & Norris, 1976).

2.1.3. Late Basin History. The early Miocene developed as a convergent phase

with overthrusting in the eastern margin and on the Taranaki Fault (Hood et al., 2002;

Uruski & Wood, 1990). Meanwhile the basin began acting as a foreland basin with

subsidence and progradational overfilling (King & Thrasher, 1996). Volcanic activities

began during the Miocene age in the north (Uruski & Wood, 1990). The beginning of the

Miocene also ended the transgression mega-cycle and began the regression phase (Hood et

al., 2002). The period from 11 to 13 Ma. marked the end of the contraction in the

northeastern margin and changed most of the faults from reverse to normal movement

faults (King & Thrasher, 1996).

2.2. GEOLOGICAL STRATIGRAPHY

Sedimentary deposits in the Taranaki Basin date back to the Upper Cretaceous and

can be divided into four main depositional sequences that can be observed basin wide

(Table 2.1) (King & Thrasher, 1996; Thrasher, 1991). These main subdivisions are, i.e.

Pakawau Group, Kapuni & Moa Groups, Ngatoro & Wai-iti Groups, and Rotokare Group.

These subdivisions could be identified within main reflectors in seismic sections, i.e. top

11

of basement, top of Cretaceous, top of Eocene, and top of Miocene (Fohramann et al.,

2012). These reflectors could also be identified as erosional surfaces in most of the basin

(Uruski & Wood, 1990). Previous studies show that the Taranaki Basin went through a

phase of transgression deposits until the end of Eocene and then went through a period of

regression and sea level fall (Table 2.1) (Hood et al., 2002). The stratigraphic units in the

study area of the Taranaki Basin are shown in Figure 2.3.

2.2.1. Pakawau Group. The Pakawau Group was deposited during the Late

Cretaceous when New Zealand rifted from Gondwana continent on top of the basement

rocks, mostly in sub-basins and next to major faults (Wizevich et al., 1992; King &

Thrasher, 1996). It is considered the main source of hydrocarbons in the Taranaki Basin

and is comprise of two formations, i.e. Rakopi Formation and North Cape Formation

(Thompson, 1982; Wizevich et al., 1992). The top and bottom of the Pakawau Group are

marked with two unconformities (Uruski & Wood, 1990).

The Rakopi Formation appears in the lower section of the Pakawau Group and is

mostly comprised of terrestrial coal measures and sandstone interbedded with cycles of

conglomerate, siltstone, and mudstone (Johnston et al., 1991). These lithofacies could be

explained as swamp and overbank on fluvial flood plains (Collen & Newman, 1991;

Thrasher, 1992).

The North Cape Formation, located in the upper section of the Pakawau Group,

differs from the Rakopi Formation by having shallow marine deposits with thick layers of

siltstone, conglomerate, sandstone, and coal seams (Wizevich et al., 1992). This

environment change indicates a transgression period during the Late Cretaceous (King &

Thrasher, 1996).

12

Age Phase Group Petroleum element Formation Abbreviation Facieses EnvironmentMangaa Ma Deep-water sandstones Slope

Giant Foresets GfFine grained siltstone and mudstone Basin floor

Tanaghoe TnFine grained interbedded sandstones and mudstone Shelf deposits

Matemateaonga MtSandstones, limestone, mudstone shell beds, coal, Shelf, marginal marine, and terrestrial environments

Urenui Ur Slope siltstone SlopeMount Messenger Mm Sandstone turbidite Volcanic sediments

Mohakatino MkDeep-water volcanoclastic deposits

Submarine fans

Moki Mo Sandstone turbidite Submarine fansManganui Mg Mudstones Shelf to basin floorTaimana Ta

mudstone, limestone Slope

Tikorangi TiLimestone carbonates Outer shelf to the upper slope

Oligocene Otaraoa OtCalcareous siltstone and sandstone Outer shelf to upper bathyal water

Tangaroa Tg Deep marine sandstones Debris flows

Turi TuMarine mudstone Shelf and bathyal regions

Mckee Mc Sandstone Shallow marine

Mangahewa MhSandstone, coal, mudstone, siltstone Lower coastal plain and marginal marine

Kaimiro Ka Sandstone, siltstone, mudstone coal

Lower alluvial plain, delta, coastal plain, and marginal marine

Paleocene Farewell Fa Sandstone, coal mudstone, Coastal plain

North Cape NcSiltstone, conglomerate, sandstone, coal seams

Shallow marine

Rakopi RaCoal measures, sandstone, siltstone, mudstone

Swamp and overbank on fluvial flood plains

Seal, Reservoir

Source

Source, Reservoir, Seal

Seal, Reservoir

Seal, Reservoir

Seal, Reservoir

Plio-Pleistocene

Regr

essi

ve

Rotokare

Pakawau

Kapuni

Ngtoro

Moa

Wai-iti

Miocene

Late Cretaceous

Eocene

Tran

sgre

ssiv

e

Table 2.1. Sequence groups representing the main stratigraphy and their formations in the Taranaki Basin. TR: color of targeted reflections utilized on the seismic sections (modified from King & Thrasher, 1996; Higgs et al., 2010; King et al., 2010).

TR

13

Figure 2.3. Stratigraphic units in the Taranaki Basin (Fohrmann et al., 2012).

14

2.2.2. Kapuni Group and Moa Group. This stratigraphic unit contains two

groups, i.e. Kapuni and Moa, which are deposited during the Paleocene and Eocene periods

(King & Thrasher, 1996). An erosional surface can be identified basin-wide on top of the

Moa Kapuni groups (King & Thrasher, 1996). Both of the Kapuni and Moa groups’

stratigraphic unit will be referred to as the Kapuni Group in this study.

The Kapuni Group includes the Farewell, Kaimiro, Mangahewa, and McKee

formations (Voggenreiter, 1993). The group is considered as a source rock and a reservoir

at the same time and is one of the main targets of drilling in the Taranaki Basin (Collier &

Johnston, 1991). The group was deposited in a non-marine low energy environment, most

likely to be coastal plain and alluvial plain, and mainly contains sandstones and some

mudstone (Johnston et al., 1991; Shell BP, 1976). The Farewell Formation is the lowest

formation in the Kapuni Group and mainly contains conglomerate, interbedded sandstone

and siltstone, coal, and coaly mudstone (Higgs et al., 2010). This formation is only found

in sub-basins and next to major faults in the Taranaki Basin (King & Thrasher, 1996). The

lithology of Kaimiro, Mangahewa, and Mckee formations are mainly interbedded

sandstone, siltstone, mudstone, and coal (Palmer, 1985). The depositional system of the

Kaimiro and Mangahewa formations includes a lower alluvial plain, delta, coastal plain,

and marginal marine (King & Thrasher, 1996).

The Moa Group is divided into two formations, i.e. Turi and Tangaroa. The Turi

Formation consists mainly of marine mudstone deposited in shelf and bathyal regions

during sea-level rise in the Taranaki Basin (Johnston et al., 1991; King & Thrasher, 1996).

The Tangaroa Formation consists of deep marine fan sandstones with grain sizes ranging

from fine to coarse (Higgs, 2009).

15

2.2.3. Ngatoro Group and Wai-iti Group. The Ngatoro Group, ranging from

Oligocene to early Miocene in age, is dominated by carbonate-rich sequences and is

divided into the Otaraoa, Tikorangi, and Taimana formations (Hood et al., 2002). The

Ngatoro Group is separated from the Kapuni/Moa Group by a major unconformity (Uruski

& Wood, 1990).

The Otaraoa Formation deposited on the outer shelf to upper bathyal water is

mainly comprised of calcareous siltstone, mudstone, and sandstone (Johnston et al., 1991;

King & Thrasher, 1996). The Tikorangi Formation deposited on the outer shelf to the

upper slope mainly consists of limestone carbonates (Hood et al., 2002; Johnston et al.,

1991). The Taimana Formation contains interbedded calcareous silts and fine sandstone

(Hopcroft, 2009).

The Wai-iti Group was deposited over the Ngatoro Group during the Miocene age

and is divided into several formations, i.e. Manganui, Moki, Mohakatino, Mount

Messenger, Urenui, and Ariki (King & Thrasher, 1996). The Wai-iti Group marks the start

of the regressive cycle in the basin and consists of marine clastic sediments ranging

between shelf, slope, and seafloor deposits (Hood et al., 2002). The Manganui Formation

consists mainly of mudstones, siltstone, and sandstone deposited on the basin floor

(Johnston et al., 1991; King & Thrasher, 1996). Moki and Mount Messenger Formations

are dominated by sandstone turbidite, and the Mohakatino Formation consists mainly of

deep-water volcaniclastic deposits and silty mudstone (Johnston et al., 1991; King &

Thrasher, 1996). The Urenui Formation consists of slope siltstone.

2.2.4. Rotokare Group. The Rotokare Group was deposited during the Pliocene-

Pleistocene and is divided into four formations, i.e. the Matemateaonga, Tangahoe, Giant

16

Foresets, and Mangaa formations (King & Thrasher, 1996). The boundary between the

Wai-iti Group and Rotokare Group is an unconformity surface observed around the

majority of the Taranaki Basin (Uruski & Wood, 1990). The Matemateaonga Formation

consists of sandstones with some limestone, mudstone, shell beds, coal, and conglomerate

deposited in shelf, marginal marine, and terrestrial environments (Johnston et al., 1991).

The Tangahoe Formation shelf deposits are mainly fine grained interbedded sandstones

and silty mudstone, the Giant Foresets Formation is mainly fine grained siltstone and

mudstone, and the Mangaa Formation is fine deep-water sandstones (Johnston et al., 1991;

King & Thrasher, 1996).

2.3. GEOLOGICAL STRUCTURES

The fault system in the Taranaki Basin strikes along the north and northeast

direction (Figure 2.4) (King & Thrasher, 1996). Most of these faults suggested are to have

been initiated during the Late Cretaceous as normal faults and reactivated during the Late

Paleogene to Neogene as reverse faults, except for the Turi Fault Zone in the north, which

was not reactivated (Figure 1.2) (Thrasher, 1990). These reverse faults bring basement

rocks over younger strata like in the Taranaki Fault (King & Thrasher, 1996).

The major feature of the Taranaki Basin is the Taranaki Fault, which marks the eastern side

of the basin (Figure 2.4). The fault extends around 400 km north to south with a vertical

offset of 5-10 km and a strike-slip displacement of 10 km (Johnston et al., 1991; Stagpoole,

2004). The fault has a dipping angle of 25-45º to the east (Nicol et al., 2004). It acted as a

reverse fault from the late Paleogone to the Neogene and offsets basement rocks above the

younger basin sediments on the west side of the fault (Thrasher, 1990). Several previous

17

studies (Wernick, 1985; Mills, 1990; King & Thrasher, 1992) have suggested that during

the breakup of the Gondwana continent, the Taranaki Fault formed as a normal fault and

was later reactivated as a reverse fault. Present observations show extensional offset in the

Taranaki Fault, which indicates normal fault activity (Thrasher, 1990).

Figure 2.4. Structural overview of the South Taranaki Graben in the Taranaki Basin. Cross-sections a-a’ shown in the lower section with the different colors indicating different ages. TF: Taranaki Fault; MaF: Manaia Fault; MoF: Motumate Fault; CEF: Cape Egmont Fault; WF: Whitiki Fault (Reilly et al., 2014).

Study area

TF MaF MoF CEF

WF

18

Exploration well data show that the oldest strata on top of the basement rocks are

from the Late Cretaceous age (King & Thrasher, 1996). Those observations were based

on wells located west of the Taranaki Fault or the wells that reached the basement.

Previous studies (King, 1991; King et al., 1991; King & Thrasher, 1996) divided

the Taranaki Basin based on its structural regions into the Western Stable Platform and the

Eastern Mobile Belt (Figure 1.2). The Eastern Mobile Belt contains the eastern area of the

Taranaki Basin where several fault systems are present. This region was formed in the mid-

late Cenozoic and also known as the South Taranaki Graben (King & Thrasher, 1996). The

Western Stable Platform was not affected by tectonic processes as much as the Eastern

Mobile Belt, which is why it remained subhorizontal and unfaulted (King & Thrasher,

1996). The deposition system in the Western Stable Platform is characterized by

progradational deposition and regional subsiding seafloor (King & Thrasher, 1996).

2.4. PETROLEUM SYSTEM

2.4.1. Source Rocks. Formations that contain coal seams in the Late Cretaceous

and Paleocene age from the Pakawau and Kapuni Groups are considered the main source

rocks for hydrocarbon in the Taranaki Basin (Johnston et al., 1991; Collen & Newman,

1991; Czochanska et al., 1987). The depositional environment of these coal measures are

suggested to be of terrestrial fresh water swamps (Collier & Johnston, 1991; Collen &

Newman, 1991). The formations that contain coals are mainly the Rakopi, Farewell,

Kaimiro, and Mangahewa formations (King & Thrasher, 1996). Most of the samples taken

from these formations contain more than 1% TOC (total organic carbon) and an average of

10% TOC (King & Thrasher, 1996). The maturity of these formations is for oil and gas

19

generation and their distribution is shown in Figure 2.5 (Stagpoole, 2004). Previous studies

suggest that the oils from the coal seams start to release hydrocarbons at depths deeper than

5.5 km (Collen & Newman, 1991).

Figure 2.5. Location of the sub-basin kitchens in the Taranaki Basin. Study area is shown in the black box (modified from Funnell et al., 2004).

2.4.2. Reservoir Rocks. Reservoir formations in the Taranaki Basin appear

through the Paleocene to the Plio-Pleistocene age with different depositional environments.

The main reservoir formations are found in the Kapuni Group of Paleocene and Eocene

ages and includes coastal plain sandstones of the Farewell Formation, and shoreline and

lower coastal plain sandstones of the Kaimiro, Mangahewa, and Mckee formations (Collier

& Johnston, 1991; Collen & Newman, 1991; King & Thrasher, 1996). The early Miocene

Tikorangi Formation limestone of the Ngatoro Group is also considered a reservoir

Study area

20

formation and producing oil in the Waihapa oil field (Figure 1.1) (Hood et al., 2002). The

Late Miocene Wai-iti Group includes the deep-water turbidite sandstones of the Moki and

Mount Messenger Formations (King & Thrasher, 1996). The Plio-Pleistocene

Metemateaonga Formation is one of the shallowest reservoir formations from the Rotokare

Group, containing shelf sandstones (King & Thrasher, 1996).

2.4.3. Seals and Traps. The Eocene to Miocene mudstones and carbonates are the

main seals in the Taranaki Basin (Stagpoole, 2004). The Kapuni Group is sealed by the

overlaying Late Eocene Turi Formation. The mudstones within the Kapuni Group also acts

as a seal for the formations within the Kapuni Group. Since most of these seals are highly

fractured in the Taranaki Basin, most of the traps in the basin are structural traps. They are

located in the Eastern Mobile Belt and are fault related (King & Thrasher, 1996). Many of

the main hydrocarbon fields in the Taranaki Basin are anticlines next to major faults in the

Eastern Mobile Belt (King & Thrasher, 1996). These faults also provide migration

pathways for hydrocarbons to escape and, in many cases, are the initial migration pathway

for gas chimneys (Bradley et al., 2012). The history of the petroleum system in the

Taranaki Basin is shown in Figure 2.6.

21

Figure 2.6. History of the petroleum system in the Taranaki Basin. The black arrow marks the critical moment when all the elements for hydrocarbon accumulation are met. The shaded arrow marks the charging of some of the reservoirs in the Taranaki Basin (modified from King & Thrasher, 1996).

22

3. DATA AND METHOD

3.1. DATA

The data set used in this project was provided by the New Zealand Petroleum and

Minerals. It contains offshore 2D seismic data covering the South Taranaki Graben in the

Taranaki Basin and includes 171 2D seismic profile lines, 6 wells, well logs, and formation

tops. The data set covers an area of around 10,000 km² with an average spacing between

2D seismic lines of 2 km (Figure 3.1). Limited well data were acquired in the study area or

in the South Taranaki Graben, which is why wells located near the border of the study area

were used.

Detailed mapping of the different reflectors and layers of varying depths was

conducted on an area of ~5,000 km² in the study area (Figure 3.1). The seismic lines

provided high-quality two way travel time (TWTT) with reflection resolution up to 4.5

seconds. The New Zealand coordinate system was used when the data were imported.

3.2. METHOD

3.2.1. Software. The main software used in the project was the KINGDOM

software 8.8, which provides geological, geophysical, and petrophysical interpretations for

2D seismic data. The KINGDOM software has several modules available including

2d/3dPAK, EarthPAK, AVOPAK, SynPAK, VelPAK, and VuPAK (Table 3.1). The Petrel

software (2013 & 2014) was also used in this project to produce seismic attributes and

import them back into the KINGDOM Software for further interpretation.

23

Figure 3.1. The basemap of the study area. Marked on the map is the location and name of the oil and gas fields in the basin, wells used, and the 2D seismic lines (Black lines).

The six imported wells include Kupe-1, Kea-1, Tahi-1, Maui-2, Maui-4, and

Hochstetter-1. The wells contained several logs including gamma ray, spontaneous

potential, density, neutron porosity, and resistivity (Table 3.2). Each well had different

formation tops imported from the well reports shown in Table 3.3.

24

Table 3.1. The KINGDOM software modules used in the study. Modules Features 2d/3dPAK Horizon Interpretation, Gridding, Fault Interpretation EarthPAK Cross Section, Log Calculations, Data Management, Mapping,

Facies Modeling, Composite Log, Petrophysics, Log Subsets, Log and Formation Top Aliasing

AVOPAK Import Gathers, Display Gathers, Horizon Interpretation and AVO Attribute Computation, AVO Attribute Analysis

SynPAK Synthetic Generation, Seismic Matching, Synthetic Display VelPAK Depth Conversion, Layer Definition, Manual Depth Conversion of

One Layer VuPAK Horizon Picking, Animation and Rendering

3.2.2. Seismic Stratigraphy and Horizon Mapping. This study mainly used

seismic reflections from the 2D seismic lines and tied them to the formation tops in the

wells to identify the main reflectors in the South Taranaki Graben. Limited well

information within the South Taranaki Graben made it essential to rely on the seismic

reflections, seismic facies, and seismic attributes for identifying and tracing the targeted

horizons. The horizon interpretation at high depths was difficult due to the poor reflection

resolution, lack of seismic coverage, and structural complexity in the area of study. These

issues made it hard to map the basement and the Pakawau Group in some of the deep

sections. Previous studies and seismic reports encountered similar issues in mapping the

basement top in many areas of the Taranaki Basin. Fault interpretation and picking were

manually performed on each line. Faults in shallow layers (<2.5 sec) were picked with the

aid of the chaos attribute. The chaos attribute couldn’t show faults deeper than 2.5 sec.

3.2.3. Seismic Attributes. Seismic attributes were used in the process of seismic

interpretation in horizon identification, fault picking, and as gas chimney indicators. The

main seismic attributes used include chaos, edge, instantaneous frequency, reflection

intensity, sweetness, variance, and Root Mean Square amplitude (RMS).

25

Table 3.2. Chart of the logs provided in each well (Mills, 2000; Palmer, 1984; Shell BP, 1970; Shell BP, 1976; STOS & Shell BP, 1970; EL).

Description Log Tahi-1 Kea-1 Maui-2 Maui-4 Hochstetter-1 Kupe-1

DEPTH.M DEPTH ✓ ✓ ✓ ✓ ✓ ✓

Bit Size BS ✓ ✓ ✓ ✓ ✓ ✓

Caliper Log CALI ✓ ✓ ✓ ✓ ✓ ✓

Density Log (RHOB) DENS ✓ ✓ ✓ ✓ ✓ ✓ Borehole Corrected Density Log

DENS_CORR ✓ ✓ ✓ ✓ ✓ ✓

Density Log Correction (DRHO) DRHO ✓ ✓ ✓ ✓ ✓ ✓

Delta T (DT) DTC ✓ ✓ ✓ ✓ ✓ ✓

(DTSF) DTS ✓

Gamma-Ray Log (GR) GR ✓ ✓ ✓ ✓ ✓ ✓

Gamma Ray Corrected GR_CORR ✓ ✓ ✓ ✓ ✓ ✓

Neutron Log Porosity (NPHI) NEUT ✓ ✓ ✓ ✓ ✓ ✓

Corrected NPHI (limestone units)

NEUT_CORR ✓ ✓ ✓ ✓ ✓ ✓

Photo Electric Cross Section (PE) PEF

✓

✓

Induction Deep Resistivity (ILD) RESD ✓ ✓ ✓ ✓ ✓ ✓

Borehole Corrected ILD

RESD_CORR ✓ ✓

✓ ✓ ✓

Medium Induction Log (ILM) RESM ✓

Borehole Corrected ILM

RESM_CORR ✓

Spherically Focused Log Unaveraged (SFLU)

RESS ✓ ✓ ✓ ✓ ✓

Borehole Corrected SFL

RESS_CORR ✓ ✓

✓ ✓

Spontaneous Potential Log (SP) SP ✓ ✓ ✓ ✓ ✓

Temperature of the Borehole (WTBH) TEMP ✓ ✓ ✓

Cable Tension at surface (TENS) TENS ✓ ✓

✓

26

3.2.3.1. Chaos. The chaos attribute is one of the major attributes that was used in

this study for fault picking and as a gas chimney indicator. The chaos attribute measures

the lack of organization in the seismic section, and is used to show discontinuities in a

horizontal continuity (Ahanor, 2012; Chopra & Marfurt, 2007). Other attributes such as

variance and coherency might be used similarly to the chaos attribute. The chaos attribute

could also be used in time slices to show faults, salt bodies, and channels (Ahanor, 2012;

Chopra & Marfurt, 2007).

Table 3.3. Formation tops for all the wells used in the study (Mills, 2000; Palmer, 1984; Shell BP, 1970; Shell BP, 1976; STOS & Shell BP, 1970; EL).

Depth (m) Time (sec) Top Depth (m) Time (sec) Top0 -0.02243 Egmont Volcanices 218 0.27301 Pliocene/Recent

335 0.33903 Matemateaonga/Tangahoe 487 0.47456 Giant Foresets 675 0.69113 Urenui 1526 1.24915 Manganui

1113 1.06451 Waikiekie 2711 2.2855 Tikorangi Limestone1344 1.2367 Mokau/Mohakation 2780 2.336 Turi 2414 1.90452 Mahoenui 2939 2.44388 Kapuni2554 1.98111 Takaka/Te Kuiti Limestone 2939 2.44388 Kapuni D Sandstone2710 2.05785 Kapuni 3075 2.57124 Kapuni E Shale 3450 2.50688 Pakawau Coal Measures 3177 2.65979 Tane Siltstone 3481 2.51885 Rotoroa Igneous Complex 3203 2.68407 Kapuni F Sandstone

Depth (m) Time (sec) Top Depth (m) Time (sec) Top126 0.09326 Pliocene/Recent 213 0.20545 Whenuakura

1047 1.00738 Mohakation/Waikiekie 944 0.89002 Tangahoe2208 1.79224 Mokau 1144 1.06006 Matemateaonga 2574 1.96839 Mahoenui 1877 1.55011 Urenui2805 2.05549 Tikorangi Limestone 1980 1.61015 Mohakation/Waikiekie 2901 2.07154 Otaraoa 2377 1.84757 Mokau2925 2.11847 Turi 2540 1.93825 Mahoenui 2963 2.15891 Kapuni 3191 2.30105 Kapuni

Depth (m) Time (sec) Top Depth (m) Time (sec) Top324 0.32091 Pleistocene 390 0.39866 Late Pliocene/Pleistocene 415 0.40876 Waikiekie 598 0.61261 Tangahoe628 0.6085 Mokau/Mohakation 764 0.76135 Matemateaonga

1707 1.28349 Mahoenui 1106 1.04175 Late Miocene/ Urenui2005 1.43809 Kapuni 1167 1.08646 Late Cretaceous/ Pakawau Group 3839 2.31065 Separation

Kea-1

Maui-2 Hochstetter-1

Kupe-1

Tahi-1Maui-4

27

3.2.3.2. Instantaneous frequency. The instantaneous frequency attribute takes the

time derivative of the instantaneous phase. It is a good indicator for severe attenuation,

which might correspond to the presence of faults or fluids such as gas (Ahanor, 2012;

Bradly et al., 2012). The change in the instantaneous frequency attribute was used as a gas

indicator in this study (Figure 5.4).

3.2.3.3. RMS amplitude. The RMS amplitude attribute calculates the amplitude

averages over a given time window. High RMS amplitude values were used as a gas

chimney indicator because they relate to high-porosity lithology with hydrocarbon

potential (Figure 5.6) (Bradly et al., 2012; Pennington et al., 2001; Pereira, 2009).

3.2.3.4. Reflection intensity. The reflection intensity attribute takes the average

amplitude over a defined moving window and multiples it by the sample interval.

Reflection intensity was used in horizon identification and picking (Figure 4.9) (Pereira,

2009).

3.2.4. Gas Chimney identification. Previous studies indicated the presence of gas

chimneys in South Taranaki Basin due to leakage in the seals (Bradly et al., 2012). The

presence of gas would show effects on the seismic data since it lowers the P-wave

velocities, increases attenuation, and increases the wave scattering (Bradly et al., 2012).

The gas chimney properties could show different anomalies on the seismic data such as

low amplitude, high amplitude (bright spots), low frequency, low coherency, or high

chaotic noise (Bradly et al., 2012; Chopra, 2007).

28

4. STRUCTURAL INTERPERTATION

4.1. INTRODUCTION

Seismic data, well logs, and formation tops were studied to gain a general

understanding of the area in the South Taranaki Graben (Figure 4.1). The targeted

reflections are the basement top, Pakawau Group top, Kapuni Group top, Wai-iti Group

top, and seafloor.

4.2. SYNTHETIC GENERATION

A synthetic seismogram is a simulated seismic response computed from well data.

A synthetic seismogram was generated for all six wells in the study. The Time-Depth (TD)

chart, velocity log, density log (RHOB), acoustic impedance (AI), reflection coefficient

(RC), and wavelet are needed to compute the synthetic seismogram. Figure 4.2 illustrates

all the components used in generating the seismic seismogram for Well Tahi-1. The TD

charts are used to connect the wells, which are in depth units, to the seismic sections, which

are in time. The TD charts were imported separately after the data set for all the wells was

imported. The wavelet is extracted from the seismic traces surrounding the well.

4.3. SYNTHETIC MATCHING

After a synthetic seismogram is generated, it has to be matched to the seismic data.

The first step is to extract the closest seismic trace each well. This extracted trace is the

real seismic data used in the synthetic matching. The synthetic trace could then be shifted,

29

W E

Figure 4.1. Uninterpreted seismic section of Line BO_hzt82a-118-2992. Seismic reflections are clear up to TWTT 5 sec.

30

Lower Pakawau

Figure 4.2. Synthetic seismogram generated for Well Tahi-1. Illustrated is all the components used to generate the synthetic seismogram. A good matching is achieved between the seismic trace and the synthetic seismogram. The Lower Pakawau is shown in this synthetic seismogram.

31

stretched, or squeezed to achieve the best matching between the synthetic seismogram and

the seismic trace (Figure 4.2). The SnyPak calculates the cross-correlation coefficient (r)

between the seismic trace and the synthetic seismogram during the matching process

(Figure 4.2). The synthetic seismogram shown in Figure 4.3 overlays the seismic data from

Well Maui-2 on Line BO_hzt82a-142-2992.

Figure 4.3. Seismic section of Line BO_hzt82a-142-2992 with the generated synthetic seismograms of Well Maui-2. Formation tops of Kapuni and Mahoenui are also included.

Mahoenui

Takaka/Te Kuiti Limestone

Kapuni

32

4.4. HORIZON INTERPERTATION

Horizon interpretation was performed by picking five horizons across all the 2D

seismic lines in the study area (Table 4.1) (Figures 4.4, 4.5, and 4.6). Due to the erosional

nature of the reflectors, the picking was done manually for all of the reflectors to insure

accurate horizon picking. Depending on the resolution and continuity of the reflector, 2D

Hunt was used for automated picking. The picked reflectors were the basement top,

Pakawau Group top, Kapuni Group top, Wai-iti Group top, and seafloor. The formation

tops in the wells surrounding the area were used to determine the targeted reflectors. The

five reflectors picked were amplitude peaks on the seismic section, which matches the

picking and interpretation conducted by Fohrmann et al. (2012) (Table 4.1). Facies change

was observed between the top and bottom of these five reflectors (Table 4.2). After the

horizons were picked, they were converted into grids to make a time structural map

(Figures 4.7, 4.8, 4.11, and 4.13). Time structural maps show the two way travel time

(TWTT) to the picked horizon.

4.4.1. Basement. The basement top picked in this study is defined by seismic

reflections because most of the wells did not reach the basement top. Fohrmann (2012)

defined the basement top reflection in the KUP area of the Taranaki Basin as the deepest

continuous seismic reflector. The method of identifying the basement top was used in this

study. The basement top is an erosional surface, which is hard to map on many areas in the

basin due to the low impedance contrast at its reflector (Uruski & Wood, 1990). Other

limitations on the basement resolution are the limitation of the seismic record to 5 sec, poor

imaging below 5000 m, the coal effect, and the fault effect on the wave path (Fohrmann,

2012). The coal layers within the Pakawau and Kapuni Groups create a masking effect on

33

the seismic resolution (Carter et al., 2015). The basement top reflection shows low or high

amplitudes depending on the area (Figure 4.1). The region below the basement reflector is

defined by a low amplitude and sub-parallel discontinues reflections. Mapping the top of

the basement helps in calculating the thickness of the groups above it, i.e. Pakawau Group

and Kapuni Group. Not many wells in the basin have reached the basement, except the

three used in this study, i.e. Tahi-1, Maui-2, and Maui-4. The time structural map of the

basement top is shown in Figure 4.7 with three major faults cutting through it and

displacing the basement rocks, i.e. the Manaia Fault, Motumate Fault, and Cape Egmont

Fault. The basement top appears to be dipping in the northeastern direction, with TWTT of

~4.5 sec in the northwest and ~2 sec in the southwestern area (Figure 4.7). The area

between the Manaia Fault and the Motumate Fault is defined as the Waiokura Syncline

(Figure 4.4) (Fohrmann, 2012).

Table 4.1. Summary of interpreted seismic horizons.

Horizon Color Acoustic

Impedance change

Boundary type Reflector

Seafloor Brown High Erosional Peak

Wai-iti Group top Navy Blue High Erosional/

Disconformable Peak / Zero

crossing Kapuni Group

top Green High Erosional Peak

Pakawau Group top Light Blue Low Erosional Peak

Basement top Black Low Erosional Peak

34

Tangaho Matemateaong

Urenui

Waikiekie/Mohakati

Manganui Kapuni

Baseme

Motumate Manaia

W E

Pakawa

Lower Pakawau

Figure 4.4. Interpreted west-east seismic section of Line BO_hzt82a-118-2992. Well Kupe-1 is shown in the far right. Unnamed faults are marked in black. The yellow box shows an interpreted canyon which is 800 m wide and 200 msec deep. The canyon is part of the Wai-iti sequence where the dominant depositional environment is submarine fans.

35

A’ A

Basement

Wai-iti & Ngatoro

Rotokare

Cape Egmont Fault

Urenui

Kapuni

Basemen

Pakawua

Pakawua

A

A’ Waiokura Syncline

BO_hzt82a-142 BO_hzt82a-115 BO_hzt82a-118

Figure 4.5. Interpreted arbitrary seismic section including lines BO_hzt82a-142, BO_hzt82a-115, and BO_hzt82a-118. The interpreted horizons and the late normal faults (Black lines) (<2.5 sec) are marked. Well Maui-2 and its formation tops are located on the left side of the section and Well Kupe-1 on the right.

36

Wai-iti & Ngatoro

Basement

Rotokare

S N

Urenui

Kapuni

Pakawau

Lower Pakawau

Figure 4.6. Interpreted south-north seismic Line BO_hzt82a-101. The horizons and late normal faults (Black lines) are shown. The Pakawau and Kapuni Groups are shown to be thickest in the north and thin out to the south.

37

Figure 4.7. Time structural map of the basement top. A) Map view of the time structural map showing the basement top dipping to the northeast. B) 3D time structural map of the basement top. Three major faults cut through the basement top, Green: the Manaia Fault; Pink: Motumate Fault; Red: Cape Egmont Fault.

Cape Egmont Fault

Manaia Fault Motumate Fault

TWTT (second)

Basement Top

Manaia Fault

Motumate Fault

A

B

Cape Egmont Fault

38

4.4.2. Pakawau. The Pakawau Group top is a highly-eroded surface. This erosional

surface spans most or all of the Pakawau Group in most of the South Taranaki Graben area

resulting in eroding most of it (Uruski & Wood, 1990). The remaining Pakawau sediments

that were not eroded are mainly in the north of the study area. The Pakawau Group top has

a low amplitude reflection which makes it hard to map. The time structural map of the

Pakawau Group top is shown in Figure 4.8 with three major faults cutting through it, i.e.,

the Manaia Fault, Motumate Fault, and Cape Egmont Fault. The Pakawau Group follows

the same trend as the basement top and dips to the northeast direction. The Pakawau Group

is divided into upper and lower. The upper Pakawau Group is the North Cape Formation,

and the lower Pakawau Group is the Rakopi Formation.

4.4.3. Kapuni. The Kapuni Group top is an erosional surface and is characterized

with a high amplitude. The reflection intensity attribute was used to show and pick the

Kapuni Group’s top reflection (Figure 4.9), which was useful because both the Motumate

and Manaia Faults displace the Kapuni Group to up to 2 sec in the east of the study area

(Figure 4.4). Another indicator for mapping the Kapuni Group top is the presence of

seismic toplaps and downlaps, which are commonly visible on erosional surfaces (Figure

4.10). The time structural map of the Kapuni Group’s top is shown in Figure 4.11 with

three major faults cutting through it. The top of the Kapuni Group appears to be dipping in

the northeast direction. The Kapuni Group top is located at 4.5 sec in the Waiokura

Syncline and 3.3 sec west of the Motumate Fault and shallows to 2.3 sec to the southwest

(Figure 4.11).

39

Figure 4.8. Time structural map of the Pakawau Group top. The Pakawau top is shown dipping to the northeast. Three major faults cut through the Pakawau Group top, Green: the Manaia Fault; Pink: Motumate Fault; Red: Cape Egmont Fault. The Manaia Fault and Cape Egmont Fault both show a high displacement in the Pakawau Group.

Cape Egmont Fault

Manaia Fault

Motumate Fault

TWTT (second)

40

Kapuni

Pakawau

Wai-iti

Waiokura Syncline

Meter

Figure 4.9. Reflection intensity attribute on Line BO_hzt82a-118-2992. The major reflection horizons i.e. Kapuni top and Wai-iti top are clearly visible. The Pakawau top could also be observed in a small area of the seismic section.

41

Meters

Kapuni

Figure 4.10. Seismic section of Line P116-81-21 showing toplaps (red arrows) on to the Kapuni top (green line). Change in seismic facies is observed from above the green line which is the Ngatoro Group and below the Kapuni Group.

42

Figure 4.11. Time structural map of the Kapuni Group top. A) Map view of the time structural map shown dipping to the northeast. B) 3D view of the time structural map. Three major faults cut through the Kapuni Group top, Green: the Manaia Fault; Pink: Motumate Fault; Red: Cape Egmont Fault. The Manaia Fault and Cape Egmont Faults both show a high displacement on the Kapuni Group.

Cape Egmont Fault

Manaia Fault Motumate Fault

TWTT (second)

Manaia Fault

Motumate Fault Kapuni Group Top

A

B

43

4.4.4. Wai-iti/Ngatoro. The Wai-iti/Ngatoro Group top in this area (also the top of

the Urenui Formation) is an erosional surface (Uruski & Wood, 1990). The reflection

intensity attribute was used to pick the Wai-iti/Ngatoro Group top reflection (Figure 4.9).

Another indicator for mapping the Wai-iti top is the presence of toplaps and downlaps,

which are common on erosional surfaces (Figure 4.12). Neither the Manaia Fault nor the

Motumate Fault cut into the Wai-iti top. The time structural map for the Wai-iti top in

Figure 4.13 shows the reflection dipping in the north direction. The Wai-iti Group top depth

is <1 sec in the southern area and is deepest south of the Cape Egmont Fault in the north at

~2.4 sec (Figure 4.13).

Figure 4.12. Seismic section of Line BO_hzt82a-118-2992 showing the unconformity of the Wai-iti group top. The toplaps (red arrows) are shown against the unconformity of the Wai-iti Group top (blue line).

Urenui

Rotokare Group

Wai-iti Group

Meters

44

Figure 4.13. Time structural map of the Wai-iti Group top (Urenui Formation). A) Map view of the time structural map of the Wai-iti Group top shown dipping to the north. B) 3D time structural view of the Kapuni top (lower horizon) and the Wai-iti top (upper horizon).

Kapuni Group Top

Wai-iti Group Top

Manaia Fault

Cape Egmont Fault

Cape Egmont Fault A

B

45

4.5. FAULT INTERPERTATION

Three major faults, i.e. the Manaia Fault, Motumate Fault, and Cape Egmont Fault,

cut through the study area. The relation between the faults and the thickness of sediments

of different ages gives an understanding of the basin evolution and the forces that acted on

the basin in the past.

The three faults started as normal faults during the Cretaceous age, which resulted

in thicker Cretaceous and Eocene deposits on the east side of the Manaia Fault (Figure

4.15). Basin-wide subsidence and deposition occurred during the Oligocene passive margin

instead of being localized in the grabens and half grabens (Hood et al., 2002). The faults

were subjected to reverse movement during the Miocene age, resulting in upthrusting of

the sediments east of the Manaia Fault. This is observed in several formations, such as the

Kapuni and Pakawau Formations, uplifted on the east side of the Manaia Fault (Figure

4.14). The faults were reactivated as normal faults after the end of the Miocene age with

high amounts of slip east of the Cape Egmont Fault. The Cape Egmont Fault’s normal

movement during the Plio-Pleistocene age could be observed with the thicker sediments of

the same age on the east side of the fault (Figure 4.5). The presence of late normal faults

in the Plio-Pleistocene age layers provides more evidence of extensional forces acting on

the region during the period.

4.6. SEISMIC FACIES

Seismic facies analysis was used to characterize the different depositional groups

in the study area. This method examines the reflections within a sequence to display the

seismic response to the sequence’s lithofacies. The parameters that were studied are the

46

amplitude, frequency (bed spacing), and continuity of the layers. The seismic facies for the

basement, Pakawau Group, Kapuni Group, Ngatoro Group, Wai-iti Group, and Rotokare

Group are shown in Table 4.2.

Figure 4.14. Seismic Line BO_hzt82a-118-2992 showing the Manaia Fault. The fault displaces the Kapuni Group top from 4.1 sec west of the fault to 2.3 sec east of the fault. Visible change is observed in the thickness of the Kapuni, Ngatoro, and Wai-iti Groups east and west of the Manaia Fault.

Manaia Fault Basement

Pakawau

Kapuni

Ngatoro

Wai-iti

Rotokare

Kapuni

W E

Kapuni

Urenui

Mahoenu

Pakawau

Basment

47

Figure 4.15. Reconstruction of depositional history in the Taranaki Basin. Shaded gray color marks the basement (King & Thrasher, 1996).

4.7. ISOPACH MAP

Once the horizons have been picked, the isochron maps were constructed. The

isochron maps show the thickness of a layer in TWTT. After the isochron maps were

generated, they were converted into isopach maps using average interval velocities from

the wells. The interval velocity is the seismic velocity over a certain interval of rock. It can

be expressed mathematically using

𝑉𝑉𝑉𝑉𝑉𝑉𝑉𝑉 = 2(𝐷𝐷1−𝐷𝐷2)𝑇𝑇1−𝑇𝑇2

, (1)

48

where Vint is the interval velocity, D1 is the depth of the first reflector, D2 is the

depth of the second reflector, T1 is the TWTT of the first reflector, and T2 is the TWTT of

the second reflector.

The isopach maps are shown in Figures 4.16, 4.17, 4.18 and 4.19. Most of the

deposits of the Pakawau Group were eroded with some remains in the central and west of

the study area of up to 1400 m in thickness (Figure 4.16). The deposits of the Pakawau

Group have a huge increase in thickness east of the Manaia Fault (Figure 4.16).

The Kapuni Group is fully eroded in the south area and increases in thickness in

the north direction (Figure 4.17). The Kapuni Group reaches thicknesses of 1200 m in some

areas to the north. The Ngatoro/Wai-iti Group has the thickest values between the Manaia

Fault and the Motumate Fault in the Waiokura Syncline, which is up to 5400 m in thickness

and decreases to the west (Figures 4.18 and 4.5). The Rotokare Group has a general trend

of increasing thickness to the northeast and decreasing thickness to the southwest (Figure

4.19). The highest values for the Rotokare Group are next to the Cape Egmont Fault in the

northwest of the study area (Figure 4.19)

49

Table 4.2. Seismic facies of the different depositional groups in the study.

Group Seismic section Amplitude Continuity Frequency (Bedding)

Rotokare

High to medium High High

Wai-iti

High to low Low to medium Low

Ngatoro

Low High High to medium

Kapuni

High to low Medium to high Medium

Pakawau

Low Medium to low Medium

Basement

Low Low Medium to low

50

Figure 4.16. Isopach map of the Pakawau Group. Thickness values vary between 0-1500 m. The group is mostly weathered south of the study area but still has some deposits in the central and northwest area. Thicker deposits of the group is visble in the east of the study area, east of the Manaia Fault.

Manaia Fault

Meters

51

Figure 4.17. Isopach map of the Kapuni Group. Thickness values vary between 0-1200 m. The group appears to become thicker to the northwest and decreases to the southeast until it is fully eroded. Thicker deposits of the group is visible in the east of the study area, east of the Manaia Fault.

Meters

52

Figure 4.18. Isopach map of both the Ngatoro and Wai-iti groups. Thickness values range between 1500-5000 m. The thickness of the two groups show the highest values in blue in the area between the Manaia Fault and the Motumate Fault in the Waiokura Syncline. The thickness values decrease to the west.

Meters

53

Figure 4.19. Isopach map of the Rotokare Group. Thickness values range between 300-2800 m. The thickness of the group increases to the north, and is thickest in the northwest next to the Cape Egmont Fault.

Meters

54

5. HYDROCARBON DETECTION

5.1. GAS CHIMNEYS

Previous studies have shown the relation between gas chimneys and the late age

faults in the South Taranaki Basin. Gases escape the Pakawau and the Kapuni source rocks

through faults and fractures in the Miocene seals (Bradley et al., 2012). These faults

provide the path for gases to migrate to the upper layers and sometimes to the seafloor

(Figure 5.1) (Bradley et al., 2012). The Plio-Pleistocene faults around the study area that

provide migration paths for gas chimneys were mapped. Seismic attributes were used to

detect the gas chimneys on the seismic data and to generate a map for the location of the

gas chimneys in the study area.

Figure 5.1. 2-D gas migration model in the south Taranaki Basin. Solid lines: faults; Arrows: migration pathway; Dotted lines: gas chimney. Gases migrate from the Eocene and Cretaceous source rocks through faults that cut the seal rocks on top of it (Bradley et al., 2012).

55

5.2. GAS CHIMNEY DETECTION

Gas chimneys have an effect on the seismic data, which allows the seismic data to

be used to find the gas chimneys. Gas chimney may be indicated as of low amplitude, high

amplitude (bright spots), change in frequency, and low coherency. Seismic attributes,

including chaos, edge, frequency, and RMS amplitude, were used to detect those changes

on the seismic data (Figures 5.2, 5.3, 5.4, 5.5, and 5.6). Not all indicators were found in

every gas chimney, but a chimney was identified if three or more indicators were present.

The presence of bright spots near the seabed indicates that the gas chimney is still active

(Figure 5.6) (Bradley et al., 2012). Bradley et al. (2012) suggested that gas chimneys deeper

than 500 msec are usually identified with low amplitude and low coherency.

After all the gas chimneys in the study area were detected, a map was generated to

show their distribution (Figure 5.7). The late stage normal faults were also mapped on the

same figure. All of the normal late stage faults show a NE-SW strike direction. These faults

were mapped because they provide the migration pathway for some of these gas chimneys,

although not all gas chimneys are fault related as suggested by Bradley et al. (2012) (Figure

5.7). An example of a non-fault related gas chimney is shown in Figure 5.2, 5.3, and 5.4;

and an example of a fault related gas chimney is shown in Figure 5.5 and 5.6.

Another observation is the location of the gas chimneys. They are mostly located

in the north of the study area where the Pakawau and the Kapuni source rocks are present,

unlike the south part where the two groups decrease in thickness until they are fully eroded

(Figures 5.5 and 5.6). Both the Pakawau and Kapuni Groups are the main source rocks in

the Taranaki Basin and are likely to be the source of the gas chimneys present in the study

area. Previous studies by Funnell et al. (2004) have shown that the source rock in the area

56

is mature enough to produce gas (Figure 2.5). This suggests that the location of the gas

chimneys is controlled by the distribution of the source rock.

5.3. MIGRATION PATHWAYS

The Upper Cretaceous and Eocene rocks in the study area are the source rocks for

two oil and gas fields in the Taranaki Basin, i.e. Maui and Maari fields (Figures 2.5 and

5.8). Several studies suggest presence of mature kitchens in the northern part of the study

area (Funnell et al., 2004; Thrasher, 1990; Funnell et al., 2001). The hydrocarbons migrate

to the two fields through two pathways, i.e. through the Cape Egmont Fault and through

the reservoir rocks in the Kapuni Group.

The Maui field, northwest of the study area, accumulates hydrocarbons from a

number of source rocks. One of these sources are the Upper Cretaceous and Eocene rocks

in the northern area of the South Taranaki Graben. The Upper Cretaceous and Eocene

source rocks in the north of the South Taranaki Graben are the deepest and thickest

compared to the rest of the graben. The Cape Egmont Fault, northwest of the study area,

provides the migration pathway for the hydrocarbons to migrate from the source rocks to

the Maui field (Funnell et al., 2004) (Figure 4.5).

The second migration pathway is interpreted from the source rocks north of the

study area to the Maari Field in the southwest. This was also suggested by a number of

studies (Funnell et al., 2004; Thrasher, 1990; Funnell et al., 2001). Collire & Johnston

(1991) suggest that the coals in Well Maui-4 are not mature enough to be the source of the

hydrocarbons in that field, thus the hydrocarbons must have been migrated from a deeper

source (>3000 m). This indicates that the north of the South Taranaki Graben is the source

57

for the hydrocarbons in the Marri Field. The South Taranaki Graben has a general trend of

dipping to the northeast and shallowing to the southwest (Figures 4.8 and 4.11). This allows

the hydrocarbons to migrate from the high pressure areas in the deeper sections to the

shallow sections. Marri field anticline traps in the southwest of the South Taranaki Graben

provide an accumulation trap at the end of the migration path (Figure 5.9).

58

Figure 5.2. Line BO_hzt82a-136 showing the possible gas chimneys and normal faults using the chaos attribute. Red arrows indicate gas chimneys in high chaos values (dark color). Normal faults are better observed with chaos attribute at shallow depth <2.5 sec.

59

Figure 5.3. Line BO_hzt82a-136 showing the possible gas chimneys and normal faults using the edge attribute. Red arrows indicate gas chimneys in high edge values (dark color).

60

Figure 5.4. Line BO_hzt82a-136 showing instantaneous frequency. Possible gas chimneys are marked with red arrows.

61

Figure 5.5. Line BO_hzt82a-152 showing the possible gas chimneys (Red box) and normal faults using the chaos attribute. Normal faults are better observed with chaos attribute at shallow depth <2.5 sec.

62

Figure 5.6. Line BO_hzt82a-152 showing the bright spots associated with the gas chimney (red circles) using the RMS amplitude attribute. The red arrow shows the fault associated with the gas chimney and the migration path for the gases. The lower two circles might also be possible hydrocarbon traps.

63

Figure 5.7. Map showing the 2D seismic line locations and the gas chimney distribution in the study area. Red circles mark gas chimneys. Blue circles show the location of the wells. The late age faults are shown striking in NE-SW direction.

Kupe-1

Tahi-1

Maui-2

Maui-4

Kea-1

64

Figure 5.8. Sub-basin kitchens and migration pathways to the known oil and gas fields in the Taranaki Basin (Octanex, 2003).

Study area

65

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66

6. PETROPHYSICS

6.1. INTRODUCTION

Petrophysical analysis uses well log information to determine formation properties

such as the type of lithology, porosity, permeability, pore fluids, and other information.

Table 3.2 shows the logs available from all the wells used in the study. The parameters

described in the reservoir properties can be used for the volumetric calculation (Table 6.1).

The well log information available in the wells only covers the Kapuni Group. Well

Tahi-1 does not encounter the Kapuni Group due to the erosion of the group in the well

location, therefore it is not included in the petrophysical analysis.

Table 6.1. Calculated reservoir properties for the Kapuni Group for each well. GROSS: The thickness between the top and bottom of Kapuni Group. NET: Thickness of potential

reservoir rock. NGR: is the NET/GROSS ratio. PHA: average porosity. SWA: average water saturation. PHIH: average porosity multiplied by NET thickness. KH: average permeability

multiplied by NET thickness. KM: average permeability. HPV: PHIH multiplied by the hydrocarbon saturation.

Well GROSS (m)

HPV (m) KH (m) KM

(md) NET (m) NGR PHA PHIH

(m) SWA

Hochstetter-1 300 46.7

8 37375.0

3 14.77 306.93 0.6 0.18 55.43 0.14

Kea-1 200 16.12

54826.96 0.28 152.1

6 0.3 0.12 17.94 0.09

Kupe-1 510 60.84

204009.6 6.59 423.7 0.83 0.17 71.13 0.13

Maui-2 500 56.15

257562.5 3.21 413.1 0.81 0.16 66.71 0.13

Maui-4 300 33.34

167449.3 0.73 275.3

3 0.54 0.13 36.68 0.08

67

6.2. VOLUME OF SHALE (VSH)

The volume of shale (VSH) is an important parameter in determining the lithology

of the rock. Either a Gamma Ray (GR) or a Spontaneous Potential (SP) log can be used to

determine the VSH. The GR log gives useful information about the lithology by calculating

the radioactivity of the formations. The radioactivity helps in differentiating between shale

(high radioactivity) and sand (low radioactivity) (Asquith & Kryqowski, 2004). The SP log

determines the lithology type based on the rock’s electric properties. The SP log was used

in this study to calculate the VSH (Asquith & Kryqowski, 2004):

𝑉𝑉𝑉𝑉ℎ = 𝑆𝑆𝑆𝑆−𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆ℎ−𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆𝑆

, (2)

where SP is the spontaneous potential (in millivolts) at that depth. The SPcln is the

SP value of clean sand (in millivolts), and SPsh is the value of a shale interval (in

millivolts). The determination of both the values of SPsh and SPcln can be observed in

Figure 6.1 using SP and GR logs. The VSH log is shown in Figures 6.2, 6.3, 6.4, 6.5, and

6.6.

6.3. POROSITY

Porosity refers to the percentage of the rock’s pore volume. The most important

type of measured porosity is the effective porosity, which measures the connected voids in

the rock. The effective porosity was calculated (Asquith & Kryqowski, 2004):

𝑃𝑃𝑃𝑃𝑃𝑃𝑃𝑃 = (𝐷𝐷𝑆𝑆𝐷𝐷𝐷𝐷+𝑁𝑁𝑆𝑆𝐷𝐷𝐷𝐷)(1−𝑉𝑉𝑆𝑆ℎ)2

, (3)

68

where DPHI = density porosity (in decimals), NPHI = neutron porosity (in

decimals), and Vsh = shale volume (in decimals). Effective porosity logs are shown in

Figures 6.2, 6.4, 6.5, and 6.6.

Figure 6.1. Determination of the SPsh, SPcln, GRsh, and GRcln. On the logs from Well Kupe-1, the chosen clean and shale lines are shown in blue and red for both the GR and SP logs.

6.4. WATER SATURATION

The water saturation (Sw) is the percentage of the pore volume that is filled with

water. The water saturation can be calculated using Archie equation for generalized water

saturation (4):

69

𝑆𝑆𝑆𝑆 = � 𝐴𝐴∗𝑅𝑅𝑅𝑅φ𝑚𝑚∗𝑅𝑅𝑅𝑅

𝑛𝑛 , (4)

where Rw = resistivity of water (in ohm-meters), RT = true resistivity (in ohm-

meters), 𝜑𝜑 = porosity (in decimals), and A, M, and N are constants. Water saturation logs

are shown in Figures 6.2, 6.4, 6.5, and 6.6.

Figure 6.2. Logs generated for Well Kupe-1 at the depth of the Kapuni Formation. SMTVSH: the volume of shale, SMTPHIE: the effective porosity, MSTSW: water saturation, and SMTSXO: is the difference between the flushed zone water saturation calculated by the Archie Clean Formation Equation and that calculated by the user-selected Equation.

70

Figure 6.3. Logs generated for Well Hochstetter-1 at the depth of the Kapuni Formation. SMTVSH: the volume of shale, SMTPHIE: the effective porosity, MSTSW: water saturation, and SMTSXO: is the difference between the flushed zone water saturation calculated by the Archie Clean Formation Equation and that calculated by the user-selected Equation.

6.5. PERMEABILITY

Permeability is the ability of fluids within a rock to move. Many equations are

available to calculate the permeability depending on the conditions. The Kingdom software

uses the Wylie-Rose permeability equation with the Morris-Biggs parameters for a

permeability constant:

71

𝑘𝑘 = 62500∗φ𝑒𝑒6

𝑆𝑆𝑅𝑅𝑖𝑖2 , (5)

where φe is the effective porosity (fractional), Swi is the irreducible water

saturation (fractional), and k is the permeability (millidarcies). Permeability logs are shown

in Figures 6.2, 6.4, 6.5, and 6.6.

6.6. WELL LOGS

The well log for Well Kupe-1 shows interbedded sandstone and shale with 80%

sandstone and 20% shale (Figure 6.2). The sandstone has porosity values of 16-25% and

water saturation above 90% in most of the logged section. Hydrocarbon indicators are

observed at depth intervals of 3190-3220 m and 3390-3530 m. Traces of hydrocarbon can

also be observed in the majority of the sandstone in the logged section. This could be an

indication of the presence of hydrocarbon in the past.

The well log for Well Kea-1 covers the Kapuni Group and shows interbedded

sandstone and shale (Figure 6.4). The sandstone shows porosity values of 10-20% and

water saturation values of 70-90%. The zone between 2945-2955 m shows a high

indication of hydrocarbons. Traces of hydrocarbon can also be observed in many sections

of the Kapuni Group but not in high amounts.

The well logs for Well Maui-2 and Well Maui-4 both cover the Kapuni Group

(Figures 6.5 & 6.6). Both wells show sandstone interbedded with shale and the highest

hydrocarbon accumulations compared to the other wells. Well Maui-2 shows a significant

amount of hydrocarbons in the interval of 2740-2760 m and porosity values between 15-

72

22%. Well Maui-4 also shows significant amounts of hydrocarbon between 1970 and 2030

m and porosity values between 12-17%.

Figure 6.4. Logs generated for Well Kea-1 at the depth of the Kapuni Formation. SMTVSH: the volume of shale, SMTPHIE: the effective porosity, MSTSW: water saturation, and SMTSXO: is the difference between the flushed zone water saturation calculated by the Archie Clean Formation Equation and that calculated by the user-selected Equation.

73

Figure 6.5. Logs generated for Well Maui-2 at the depth of the Kapuni Formation. SMTVSH: the volume of shale, SMTPHIE: the effective porosity, MSTSW: water saturation, and SMTSXO: is the difference between the flushed zone water saturation calculated by the Archie Clean Formation Equation and that calculated by the user-selected Equation.

6.7. CROSSPLOTS

Crossplots are used to study the subsurface rock properties in wells. Several

crossplot techniques can be used to obtain geological information, i.e. neutron-density,

neutron-sonic, density-sonic, and M-N crossplots. Neutron-density crossplots were

generated in this study because they are useful in determining the lithology and porosity.

74

Figure 6.6. Logs generated for Well Maui-4 at the depth of the Kapuni Formation. SMTVSH: the volume of shale, SMTPHIE: the effective porosity, MSTSW: water saturation, and SMTSXO: is the difference between the flushed zone water saturation calculated by the Archie Clean Formation Equation and that calculated by the user-selected Equation.

The neutron-density crossplot for the Kapuni Group in the Well Kupe-1 is shown

in Figure 6.7. The GR log was used to differentiate the shales (that have high GR values)

from the sandstone. The well reports in the study area all indicate the presence of sandstone,

shaly coal, and shale in the Kapuni Group. According to Asquith & Krygowski (2004),

neutron-density crossplots could be used when a limited number of lithologies are present.

75

Taking that into consideration, points that lay on the limestone or dolomite line in the

crossplots (Figure 6.7) are interpreted as shaly sandstone. The coals are also shifted from

their averaged values on the crossplots due to the shale effect. Figure 6.7 shows the porosity

values for the sand in the Kapuni Group clustered between 15-20%.

Figure 6.7. Neutron-density crossplot for Kapuni Group in Well Kupe-1. Z-axis in colors shows gamma-ray values, high values correspond to shales and low values to sand. The areas of sandstone, shale, and shaly coal are marked. Porosity values for the sand are clustered mainly around ~20%.

Shaly coal

Sandstone

Shale

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7. CONCLUSION

The interpretation and mapping of five seismic horizons over the South Taranaki

Graben have led to a better understanding of the geology, sediment distribution,

hydrocarbon presence, and structural evolution in the study area. The major faults, i.e. Cape

Egmont, Manaia, and Motumate show initial normal movement during the Cretaceous to

Paleocene age, reverse faulting from Late Eocene to Late Miocene, and normal movement

from Pliocene age to the present as suggested by King & Thrasher, (1996) and Fohrmann

et al., (2012). Evidence of the faults movement is observed on the seismic sections through

the sedimentary distribution of each period.

7.1. SEDIMENT DISTRIBUTION

Most of the depositional groups show a trend of thickening to the north. The

Pakawau Group is only present in the northern area with a thickness up to 1500 m. The

thickness of the Pakawau Group increases greatly to the west of the Manaia Fault, but its

thickness is hard to determine due to the low resolution of the basement top below it.

The Kapuni Group has a higher distribution than the Pakawau Group and also

thickens to the north. The Kapuni Group is fully eroded in the south. Both the Kapuni and

Pakawau Groups might be the source rock and migration pathways to the anticline trap

fields that lie southwest and west of the study area in the Maui and Maari fields.

Hydrocarbons reach the Maui Field through the Cape Egmont Fault. The Maari Field is the

shallowest point connected to the study area forming an excellent trap for the migrating

hydrocarbons from the deeper kitchens in the north of the study area.

77

The Ngatoro and Wai-iti Groups have the greatest thickness in the Waiokura

Syncline and decrease in thickness to the west. The Rotokare Group has a general trend of

thickening to the northeast but has the highest values south of the Cape Egmont Fault, in

the northwest of the study area.

7.2. MANAIA FAULT

The Manaia Fault controlled the development of the Upper Cretaceous to Eocene

rocks in the south of the Taranaki Basin. The thicker deposits from the Upper Cretaceous

to the Eocene, east of the Manaia Fault, suggest that the east was subsiding during that age,

while the west side was subjected to erosional processes. Reverse faulting on the Manaia

Fault is observed with the uplifting of the Miocene and older strata in the east of the fault

and the formation of the Manaia anticline. The presence of normal faults in the Plio-

Pleistocene succession implies an extensional period.

7.3. LIMITATIONS AND RECOMMENDATIONS

The interpretation of the seismic data in the study area has its limitations. Thus it

produces uncertainties within the horizon interpretation. The first issue is with the seismic

surveys. The study area covers a number of different acquisition projects with different

acquisition parameters, processing steps, and record lengths. This requires matching the

seismic response of the different seismic surveys. Another limitation is the poor coverage

of the 2D seismic lines on many places of the study area. This makes it hard to determine

and trace the reflection in areas with faults like the area around Well Tahi-1. The loss of

resolution due to high depths of reflectors and the presence of coal make it difficult to trace

78

deep reflectors such as the basement and Pakawau. Areas around the major faults (Cape

Egmont, Manaia, and Motumate) are poorly imaged. This is due to the deformation around

these faults and the effect of the faults on the ray path. The lack of wells within the South

Taranaki Graben limited the ability to identify individual formations within the

depositional groups. An accurate velocity map could not be generated due to the absence

of wells in the South Taranaki Graben.

7.4. GAS CHIMNEYS

A number of gas chimneys were imaged in the South Taranaki Basin using 2D

seismic lines and seismic attributes. Seismic attributes proved to be a great tool in detecting

gas chimneys. The two main factors that control the distribution of these gas chimneys are

the distribution of the Upper Cretaceous and Eocene source rocks and distribution of the

late normal faults. The gas chimneys are mostly present in the northern area of the South

Taranaki Graben where the thicker Late Cretaceous and Eocene source rocks are located.

Half of the gas chimneys appear to be related to late normal faults. Other gas chimneys

may have migrated from deeper faults that cut through the seal rocks.

79

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VITA

Taqi Alzaki was born in Dhahran, Saudi Araba. In May 2012, he received his

bachelor’s degree in Geophysics from King Fahad University of Petroleum and Minerals

(KFUPM). During his undergraduate degree, he worked on internships and projects with

LUKSAR, ARGAS, and the Research Institute at KFUPM. In May 2016, Taqi received

his Master’s degree in Geology & Geophysics from Missouri University of Science and

Technology (Missouri S&T). While Pursuing his degree, he served as the International

Student Club as an event coordinator. He was also a member of the SEG chapter in both

Missouri S&T and KFUPM.

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