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Geological Modelling of the Offshore Orange Basin, West Coast of South Africa (2 nd Edition)*
Curnell J. Campher 1 , R. di Primio 2 , G. Kuhlmann 2 , D. van der Spuy 1 , and R. Domoney 3
Search and Discovery Article #10191 (2009)
Posted April 21, 2009, Revised May 14, 2010
*Adapted from oral presentation at AAPG International Conference and Exhibition, Cape Town, South Africa, October 26-29, 2008, along with poster
presentation at AAPG International Conference and Exhibition, Rio de Janeiro, Brazil, November 15-18, 2009.
1 Petroleum Agency SA, Cape Town, South Africa (mailto:campherc@petroleumagencysa.com)
2 GeoForschungsZentrum, Potsdam, Germany
2 University of the Western Cape, Cape Town, South Africa
Abstract
The Orange Basin covers an area of roughly 130,000 square kilometers relevant to the 200 m isobath (Gerrard and Smith, 1982) and
has roughly one well drilled for every 4000 square kilometers. The basin has proven hydrocarbon reserves and potential for further
discoveries.
The study area is located within South African exploration license blocks 3A/4A and 3B/4B and covers a region of roughly 97 km by
150 km. The study aims at understanding the geological processes responsible for the formation of the Orange Basin with a focus on
the evolution of source rocks maturity. The Petrel software was used for seismic interpretation and well correlation and PetroMod
(IES, Version 10) for basin modelling and assessing source rock maturity.
Preliminary seismic interpretation of the post Hauterivian succession shows a relative thickening of the sedimentary sequence
westward as the basin evolves from the early drift to complete drift phase. Initial results from petroleum system modelling indicate
that the Barremian- early Aptian source rock is at present over mature and producing mostly gas in the shelf areas, whereas potential
for oil is most likely still present in the deep water area of the basin where Tertiary progradation has resulted in renewed petroleum
generation. The younger Cenomanian-Turonian source rock shows a lower transformation ratio than the older source rocks and
modelling indicates that the source rock is mainly producing oil. Additional modelling is needed to further constrain the model results.
Copyright © AAPG. Serial rights given by author. For all other rights contact author directly.

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Geological Modeling of the Offshore
Orange Basin, West Coast of South Africa
by: Curnell Campher
1 2
2 3
Supervisors: D. Van der Spuy, G. Kulmann, R.di Primio, and R. Domoney
1
1
2
3
Petroleum Agency, PO Box 1174, Parow 7499, South Africa.
GeoForschungs Zentrum, Telegrafenberg, 14473 Potsdam, Germany.
University of the Western Cape Private Bag X17, Bellville 7535, South Africa.
Introduction
The Orange Basin is the largest and youngest of the offshore the potential multi-trillion cubic feet of natural gas reserves. 10 for basin modeling. The aim was to reconstruct the
South African basins (Figure 1A) and covers an area of roughly This poster presents results and conclusions of the basin geological history including the basin formation, heat-flow
130 000 square kilometres relevant to the 200m isobaths modeling conducted in the study area located within the South regimes over time, sequence stratigraphy, depositional
(Gerrard and Smith, 1982). The basin is classified as under- African exploration blocks 3A/4A and 3B/4B (Figure 1B) regimes and the subsequent maturity evolution of two
explored with one well drilled for every 4000 square kilometres. covering an area of roughly 97 kilometres by 150 kilometres. identified post-rift source rocks in the Orange Basin namely,
Despite this, the basin has confirmed hydrocarbon reserves in The methods followed included the use of Petrel for seismic the older Barremian to Early Aptian, and the younger
the form of large gas fields (Ibhubesi and Kudu gas fields) with interpretation and well correlation and PetroMod IES version Cenomanian to Turonian source rock.
K-H1
K-F1
A-l1
A-L1
A-A1
N
Block 3B/4B
Block 3A/4A
X'
X
N
Figure 1 (A): Location of the Orange Basin with exploration license blocks 3A/4A and 3B/4B
Figure 1 (B): Location of the Study Area with well locations in exploration
license blocks 3A/4A and 3B/4B
Rifting
Km
0
5
10
SW
X
C
(Jungslager 1999)
4
Tert iary
Ca m -
Maas
Seismic gas chimneys
and seeps
3
K/T
Santonian - Coniacian
F l
u
F l
u
80 Ma
Flu
Turonian
Cen
m - u Alb
67 Ma
u A
pt - l Alb
13At1
+
+
93
Ma
103 Ma
3
+
22At1
+
+
+
Medial
Hinge
17At1
+
1
+
4
4
2
+
15At1
14At1
+
+
?
+
+
6At 1
1At1
1
+
2
+
+
+
+
+
+
+
1
+
2
+
+
+
+
Gas
seep
+
NE
+
Margin
Hinge
Hauterivian
RIFTED
CONTINENTAL CRUST
T
A-J
Graben
X'
Time
Drifting
• Onset of full drift signified by
13At1 unconformity
(Brown et al 1995)
• Sequence described as thick
Sedimentary wedge
• Contain large growth, slump
Structures and associated toe
Thrusts along shelf edge
Early Drift
• Between Mid Aptian- Early
Aptian (Brown et al 1995)
• Corresponding to
unconformities 6At1 and 13At1
• Classified as
intermediate succession.
• Barremian-Early Aptian
source.
• Rifting was initiated along
the west coast during the Late
Jurassic (Muntingh 1993)
• Divergent passive margin
with underlying grabens and
half grabens.
• Rifting continued until the
Late Hauterivian marked by
the 6At1 unconformity
(Muntingh 1993)
Figure 1C: Generalized cross section through the Orange Basin indicating basin evolution from rifting,
early drifting to complete drifting.
• Source rock association with
Global Cenomanian - Turonian
Anoxic event.
Basin evolution
The Orange Basin sediments can be categorised into three phase and are later influenced by eustatic sea level change, sedimentation barrier (Figure 2A). The onset of full drift
units, namely the syn-rift, early drift and complete drift tectonics and sediment influx. The thickness map of the 6A resulted in a northward shift of the depocentre (as indicated
sediments, corresponding to the active rifting, onset of drifting sequence indicates depocentres towards the middle of the on the thickness map of 13A (Figure 2A)) as the affect of
and complete drifting phases of the Orange Basin's evolution study area trending sub-parallel with the coast (Figure 2A). basement architecture diminished. The 22A thickness map
(Figure 1C, 2B). Sediment thickness maps indicate the These depocentres can be attributed to basement grabens and shows a thin interval on the shelf due to Late Tertiary erosion.
development of depocentres influenced by areas of adequate half grabens which also trend sub-parallel to the west coast of This contributed to the development of a depocentre in the
accommodation space. These depocentres are commonly South Africa. The 6A sequence thins westward due to the distal part of the basin as eroded sediment was redeposited
developed within basement grabens during the initial rifting Agulhas Columbine Arch (basement high) providing a basinward (Figure 2A).
erosion
Two erosional events have been incorporated in the basin illustrated as two erosional maps 17At1 and 18At1 indicating over a much larger area as indicated on the 22At1 erosional
model. The first and more intense of these occur during the the aerial extent and intensity of the erosion (Figure 2C). The map (Figure 2C).
Early Paleogene eroding an estimated thickness of 960 meters second, less intense erosional event of the Early Miocene,
down to the 17A sequence (Figure 2C). This erosional event is eroded an estimated thickness of 420 meters of sediments
Petroleum Agency SA, PO Box 1174, Parow 7499, South Africa
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Isopach Maps indicating the thickness in metres at various
stages in the Orange Basin evolution
Standard
Chronost-
ratigraphy
Time
in SEQUENCE CHRONOSTRATIGRAPHIC FRAMEWORK
Ma DISTAL PROXIMAL
MAIN EVENTS
2B
Erosion maps indicating the amount of sediments
removed in meters
Erosion map of 22A sequence
2C
Meters
2A
QUA-
TER N -
ARY
T E R T I A R Y
S E R I E S
HOLO
PLEI
PL
MI
OL
EO
30
THI N DIAMOND-
BEARING VENEER
WHERE SAMPLED
EPISODIC UPLIFT
OF HINTERLAND
DURING THE
TERTIARY
LATE CRETACEO
US /
EARLY TERTIARY
INTRUSIONS
Meters
Isopach at 22At1 unconformity
U P P E R C R E T A C E O U S
S T A G E S
PA
MA
CA
SA
CO
TU
CE
67
80
93
22At1
17At1
15At1
D R I F T
EN D OF MAIN
FLUVIA L INPUT
GR OWTH FAULTING
A ND TOE-THRUSTING
MAJOR UPLIFT
OF
MARGIN AND
GRAVI TY FAULTING
CANYONING AND
GRAVITY FAULTING
ALONG SHELF EDGE
ATLANTIC
FU LLY OPEN
Erosion map of 18A sequence
Meters
Isopach at 13At1 unconformity
L O W E R C R E T A C E O U S
S T A G E S
AL
AP
BA
HA
VA
BE
103
112
117,5
121
14At1
13At1
6At1
1At1
v v v
v v v v v
v v v v v
v v v v v v v
ONSET OF THERMAL
SAG AND DRIFTING
v v
v v v v v v v v v v
POSSIBLE
RI FT BASINS
BELOW TH E BASALTS
AR E UNKNOWN
?
H
I
N
G
E
S Y N R I F T T -
RANSIT IONAL
I I THERMAL
SUBSIDENC E /
EUSTATI C EFFECTS
REGIONAL
DROWNING
FIRST
MARINE INCURSIONS
BREAK-UP
UNCONFORMITY
TH E CHRONO-
STRATIGRAPHY
BE LOW THE
HAUTERIVIA N STAGE
I S SPECULATIVE
Meters
Erosion map of 17A sequence
Meters
UP PE R JURA S S IC
STAGES
T
PRE-JURASSIC
ONSET OF RIFTING
BASEMENT
v
v
v
DATE OF ONSET
OF RIFTING IS
UNCERTAIN
MAY INCLUDE POSSIBLE
KAROO, CAPE, NAMA AND
MALMESBURY SUPERGROUPS
AND CRYSTALLINE ROCKS
Meters
Isopach at 6At1 unconformity
Figure 2A: Modeled depocentre development in the study area after rifting, (2B) shows the chronostratigraphy of the Orange Basin, (2C) erosional events
affecting the Orange Basin in the study area.
3A
3B
3C
Figure 3A: Basin modeling input data showing different lithologies and source rock characteristics, (3B) heat flow model incorporated in
basin model, (3C) map view of the heat flow trend over study area, (3D) global mean surface temperature for the southern
hemisphere at latitude 33.
Source rock modeling parameters
3D
Heat Flow = 80Mw (Rifting) to 45Mw (Present)
Stretching factor 1.5
Well log Lithologies
Computed sediment water interface temperature
Two erosional events (illustrated in three erosional maps in figure 2C)
Type II source rock for both source intervals
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A-A1
A-L1
Barremian to Early
A p t i a n S o u r c e
Rock
Cenomanian to
Turonian Source
Rock
K-F1
K-H1
A-A1
K-F1
2730 m - 2830 m
A-L1
2961 m - 2987 m
3010 m - 3040 m
3040 m - 3051 m
1616 m - 1634 m
2335 m - 2830 m
(Scattered)
Cenomanian to Turonian
Source Rock
K-H1
2580 m - 2657 m
2657 m - 2697 m
Barremian to early Aptian
Source Rock
4A
4B
4C
Figure 4A: Source rocks in wells A-A1 and A-L1 (Barremian to Early Aptian Source Rock), (4B) total organic carbon plotted against depth for both Cenomanian to Turonian source rock, and Barremian to Early Aptian source rock.
(4C) source rocks in wells K-F1 and K-H1, (Cenomanian to Turonian Source Rock).
Source Rock characterisation: Two main source rock units coast of South Africa. Along the west coast of South Africa the Barremian to reaching 5 percent in well 2012/13 1 (Bray, 1998). In the Bredasdorp Basin
are known to exist in the Orange Basin, the Hauterivian syn-rift source rock Early Aptian source interval has been intersected by several wells. The P-A1 along the south coast of South Africa this source interval is described as
and the Barremian to Early Aptian source rock. There is also the potential for well to the south of the study area record total organic carbon (TOC) values having potential for wet gas or oil generation (Davies, 1997). Studying the
a third regionally developed source interval at the Cenomanian to Turonian of 4 percent, the A-C1 to 3 wells record TOC's ranging from 2 to 4 percent, TOC plot for the two source rock intervals as intersected by the four wells,
sequence boundary (Barton, 1993). The two source intervals investigated in and DSDP 361 well have TOC's ranging from 3 to 15 percent for the the Barremian to Early Aptian source rock can be categorised by having
this poster are the Barremian to Early Aptian and the postulated Barremian to Early Aptian source interval (van der Spuy, 2003). The TOC values ranging from 0.6 to 3 percent. The younger Cenomanian to
Cenomanian to Turonian source rocks (Figures 4 A, 4 C). The Barremian to postulated Cenomanian to Turonian source rocks are, immature where Turonian source rocks have a TOC range of between 0.6 and 2.3 percent
Early Aptian source rock has been well documented along the southern and drilled with a possibility of improving to oil prone quality down dip in the (Figure 4B). The Barremian to Early Aptian and the Cenomanin to Turonian
western margins of South Africa with a proven hydrocarbon system (Oribi Orange Basin (Jungslager, 1999). This source rock was intersected in wells source rocks have been respectively classified by (Muntingh 1993) to be
oilfield) in the Bredasdorp Basin in the Southern Outeniqua, along the south further north, in the Namibian section of the Orange Basin with TOC's type II and Type II/Type III mixed source rocks in the Orange Basin.
Source Rock burial history: Burial history diagrams of the
K-H1 and A-I1 wells (Figure 5A) reveal the evolution of the Barremian to
Early Aptian and Cenomanian to Turonian source rocks assuming thermal
maturation for oil is reached at temperature between 60 and 120 º C.
K-H1
Investigating the maturation evolution of the Barremian to Early Aptian and
the Cenomanian to Turonian source rocks at well location K-H1 reveal that
the former is presently found to be thermally overmature at a depth of
approximately 5000 m and temperature of between 150 to 165ºC.
This source rock has been matured even more during the Late Cretaceous
to Early Paleogene. A maximum subsidence was then reached for the
Orange Basin with a maximum burial and temperature of 5300 m and 195 to
210ºC respectively (Figure 5B). The Cenomanian to Turonian source rock
in this area is presently found within the thermally mature stage of 90 to
105ºC. This source rock has also been subjected to slightly deeper burial
and higher temperature during maximum burial of 2700 m and 120ºC
(Figure 5B).
K-H1
K-F1 A-l1
5A
A-L1
A-A1
A-I1
Investigating the maturation evolution of the Barremian to Early Aptian and the
Cenomanian to Turonian source rocks of the A-I1 well reveals that the
Barremian to Early Aptian source rock is presently found at a depth of
approximately 4200 m. This source rock is therefore within the late stage of
thermal maturity ranging from 90 to 135ºC (Figure 5C). The source rock has
however, been subjected to deeper burial and higher temperatures during the
Late Cretaceous to Early Paleogene, reaching a maximum depth of
approximately 4500 m and a maximum temperature of 180ºC. This places it
within the thermal regime of a matured source rock (Figure 5C). The burial
history of the A-I1 well indicates that the Cenomanian to Turonian source rock is
at present found within the very early stages of thermal maturity with
temperature ranging from 45 to 60ºC (Figure 5C). This source rock has also
been subjected to higher temperature and deeper burial during the Late
Cretaceous to Early Paleogene when maximum burial was reached for the
Orange Basin sediments. The source rock reached thermal maturity during the
Late Cretaceous, reaching a maximum depth and temperature of 2400 m and
90ºC respectively (Figure 5C). Investigating the maturity evolution of both
source rocks of the K-H1 and A-I1 wells reveal that the source rocks have
entered thermal maturity earlier at the K-H1 well as compared with the A-I1 well.
5B
5C
Figure 5A: Show study area with well locations, (5B) burial history highlighting source rock maturity evolution at the K-H1 well, (5C) burial history highlighting source rock maturity evolution at the A-I1 well
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Source Rock Transformation Ratio overlay
Cenomanian to Turonian source rock: The transformation ratio overlay on the Cenomanian to Turonian
source rock indicates that most of the source rock is in the oil mature phase with a more mature depocentre
in the middle of the study area (depocentre of the basin) (Figure 6B). Time extractions reveal that the
maximum temperature and maturity were also reached during the Late Cretaceous and Early Cenozoic
respectively (Figure 6C).
Barremian to Early Aptian source rock: The transformation overlay on the Barremian to Early Aptian source
rock indicates that most of the source rock is overmature and is currently producing mainly gas in the central
region. There is potential for oil in the distal areas of the basin (Figure 6D). Time extractions (Figure 6E) reveal
that maximum temperature was reached during the Late Cretaceous and subsequent maturity was reached
during the Early Cenozoic.
Temperature evolution
6A
6B
Peak Temperature
6C
Maturation evolution
Peak hydrocarbon generation
Figure 6: (6A) modeled cross section through the Orange Basin,
(6B) three-dimensional source rock surface of the Cenomanian to
Turonian Source Rock with transformation ratio ovelay,
Temperature evolution
(6C) time extractions showing peak temperature and maturation for the
Cenomanian to Turonian Source Rock,
(6D) three-dimensional source rock surface of the Barremian to Early
Aptian Source Rock with transformation ratio ovelay,
(6E) time extractions showing peak temperature and maturation for the
Barremian to Early Aptian Source Rock.
6D
Peak Temperature
Basin Modeling Calibration
6E
Maturation evolution
Modeled calibration of temperature and vitrinite reflectance for wells
K-H1 and A-I1 follows a trend that can be closely correlated to the actual
evolution of the Orange Basin sediments with temperatures slightly
higher than actual (Figures 7A & 7B). Comparing the modeled results
with previous basin modeling conducted in the Orange Basin produces
comparable results. This is shown when comparing the maturity
modeling conducted by (Jungslager 1999) on the Barremian to Early
Aptian source rock with the maturity modeling of this study for the same
source rock (Figures 7C & 7D).
Peak hydrocarbon generation
K-H1
A-I1
7C
7A
7B
7D
Figure 7A: Vitrinite reflectance and temperature calibration at well location K-H1, (7B) Vitrinite reflectance and temperature calibration at well location A-I1, (7C) modeled maturity of the Barremian to Early Aptian Source Rock by Jungslager 1999,
(7D) modeled maturity of this study of the Barremian to Early Aptian Source Rock.
Conclusion
Basin modeling show that both the Barremian to Early Aptian and the Cenomanian to Turonian
source rock appeared to have a centrally mature region perhaps due to the thicker overburden
developed over this region. Renewed source rock maturity for both the Barremian to Early
Aptian and the Cenomanian to Turonian source rock is possible further basinward where
thicker overburden development due to erosion of the shelf result in redeposition of sediments
in the distal parts of the basin.
Reference
Barton, K.R., Muntingh, A., Noble, R.D.P., (1993), Geophysical and Geological studies applied to hydrocarbon exploration on the West Coast Margin of South Africa. Extended abstract of the Third International Congress of the Brazilian Geophysical Society, Rio de Janeiro, Brazil,
Nov. 7-11, 1993
Bray, R., Swart, R., and Lawrence, S., (1998). Source rock, maturity data indicate potential off Namibia, National petroleumcorporation of Namibia (Pty.) Ltd. Windhoek, Oil and Gas Journal, 84 89.
Brown, L.F., Benson, Jr.J.M., Brink, G.J., Doherty, S., Jollands, A., Jungslager, E.H.A., Keenan, J.H.G., Muntingh, A., and van Wyk, N.J.S., (1995). Sequence Stratigraphy in Offshore South African Divergent Basins. In: American Association of Petroleum Geologists, Tulsa,
Oklahoma, Studies in Geology, 41, An Atlas on Exploration for Cretaceous Lowstand Traps by Soekor (Pty) Ltd. 139-182.
Davies, C. P. N., (1997). Hydrocarbon Evolution of the Bredasdorp Basin, Offshore South Africa: From Source to Reservoir. Phd, thesis, University of Stellenbosch.
Gerrard, I., Smith,G.C., (1982), Post-Paleozoic Succession and Structure of the Southwestern Africa Continental Margin. In: American Association of Petroleum Geologists, p 49 74
Jungslager, E.H.A., (1999), Petroleum habitats of the Atlantic margin of South Africa. In: Cameron, N.R., Bate, R.H & Clure, V.S. (eds), The oil and gas habitats of the South Atlantic, Geological Society, London, Special Publication, 153, pg 153 168
Van der Spuy, D., (2003). Aptian source rocks in some South African Cretaceous basins. In: Arthur,T.J., MacGregor, D.S & Cameron, N.R. (eds), Petroleum Geology of Africa: New Themes and Developing Technologies. Geological Society, London, Special Publication, 207, 185-
202, The Geological Society of London.
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