IPA05-G-039 p067 089

IPA05-G-039
PROCEEDINGS, INDONESIAN PETROLEUM ASSOCIATION
Thirtieth Annual Convention & Exhibition, August 2005
THE PETROLEUM SYSTEMS AND FUTURE POTENTIAL OF THE SOUTH SUMATRA BASIN
David Ginger*
Kevin Fielding**
ABSTRACT
This review is based on analysis of field and well
data, palaeogeographic mapping, and seismic-based
studies of structural history, maturity, migration
pathways and trapping mechanisms. The mapped
distribution and quality of source, reservoir and seal
are reviewed to determine the critical factors
constraining the basin’s petroleum systems. Playbased creaming curves are used to estimate remaining
potential.
The South Sumatra Basin contains a mixed
terriginous, volcaniclastic and carbonate fill. Five
plays account for the majority of discoveries to date.
These are found in; Pre-Tertiary fractured basement,
Oligocene to Early Miocene (Lower Talang Akar
Formation) fluvio-deltaic sandstones, Early Miocene
(Batu Raja Formation) carbonates and Early Miocene
(Gumai Formation) and Middle Miocene (Air
Benakat Formation) shallow marine sandstones.
Oligocene-Early Miocene age lacustrine and deltaic
source rocks are recorded or implied by discovered
oil characteristics. Source-rock type and distribution
has influenced the distribution of hydrocarbons while
in some areas hydrocarbon generation predates
structure formation. The pinch-out of Oligocene and
Miocene regional seals limit prospectivity on the
eastern side of the basin.
Cumulative oil production has exceeded 2 BBO from
an estimated original reserve of almost 3 BBO.
Original gas reserves are estimated at 22 TCF, with
less than 6 TCF produced to date. An estimated 6 to
10 TCF of gas and 0.2 to 0.5 MMB of oil remain to
be discovered in proven plays.
*
**
Amerada Hess Malaysia
Amerada Hess Limited
Historically oil production dominated with associated
gas being flared. More recently gas has been exported
to Central Sumatra and Singapore. These new
markets helped to stimulate exploration activity in the
1990’s. Local markets are developing although
considerable stranded gas remains to be exploited.
Securing further gas markets will revive exploration
activity.
INTRODUCTION
Analysis of a basin-wide data set has allowed the
generation of a sequence of palaeogeographic maps
for each commercial reservoir horizon in the South
Sumatra Basin. A regional analysis of source rocks
and oil types and the timing and distribution of
hydrocarbon migration has helped determine critical
factors for successful petroleum systems. For the first
time an overview of the basin as a whole has been
assembled, providing a better understanding of its
petroleum systems. The exploration and discovery
history of the basin is analysed to estimate future
potential.
DATA BASE
Approximately 18,000 km of seismic 2D data and
several 3D seismic data volumes were reviewed as
part of this study. In addition, well data of variable
quality were incorporated from approximately 250
wells, constraining the distribution of major
stratigraphic units as well as palaeogeographic and
facies variations.
A fields and discovery data base was generated from
industry and proprietary sources covering some 275
fields, although pre-1920 fields were poorly
represented due to a lack of reliable data.
Oil geochemistry data used for this study were
derived from GeoMark’s 1993 Far East Oil Study and
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their Reservoir Fluid Database, the related paper by
Schiefelbein and Cameron (1997) and a separate
study by Rashid et al (1998) on 40 oils from the south
of the basin.
STRUCTURAL HISTORY
The history of the basin can be divided in the three
tectonic megasequences described below and
illustrated in Figure 1. The key structural elements in
the basin are shown in Figure 2. See Longley (1997)
for a discussion of the plate tectonic events
controlling the structural history of the South Sumatra
Basin.
Syn-Rift Megasequence (c. 40 – c. 29 Ma)
As a result of subduction along the West Sumatran
Trench, the continental crust in the South Sumatra
area was subjected to a major extensional event from
Eocene to Early Oligocene times. This extension
resulted in the opening up of numerous half-grabens
whose geometry and orientation was influenced by
basement heterogeneity. Initially, extension appears
to have been orientated east-west producing a
sequence of north-south horsts and grabens. South
Sumatra has been rotated by approximately 15
degrees clockwise since the Miocene according to
Hall (1995) resulting in a present day north-northeast
south-southwest graben orientation.
Post Rift Megasequence (c. 29 – c. 5 Ma)
Rifting ceased approximately 29 Ma ago, however,
the thinned continental crust under the South Sumatra
Basin continued to subside as lithospheric thermal
equilibrium was re-established. In parts of the basin,
such as the Central Palembang Sub-basin, this
megasequence reaches thicknesses in excess of
13,000 ft. High subsidence rates and high relative sea
level resulted in a long-lived transgression of the
basin which reached its maximum extent
approximately 16 Ma ago with flooding of virtually
the entire basin.
Slowing subsidence rates and/or increased sediment
input into the basin from 16 Ma to 5 Ma resulted in a
pronounced regression. There is no evidence that
local tectonic activity was a significant influence in
this regression.
Syn-Orogenic/Inversion Megasequence (c. 5 Ma –
Present)
A widespread orogenic event, the Barisan Orogeny,
occurred across South Sumatra from 5 Ma to present,
although there is some evidence for local uplift as
early as 10 Ma (Chalik et al, 2004). Elongate
northwest-southeast orientated transpressional folds
of varying magnitude were formed across the basin
and cut across much of the underlying syn-rift fabric.
Numerous hydrocarbon-bearing structural traps in the
centre of the basin were formed at this time, though in
some areas existing petroleum accumulations were
exposed and breached.
Beyond the elongate
transpressional folds, basin subsidence continued as
sediment input in to the basin was enhanced by
erosion of the newly formed Barisan Mountains to the
south and west.
STRATIGRAPHIC OVERVIEW
A chronostratigraphic scheme, employed to overcome
the limitations of the different lithostratigraphic
nomenclature used by different oil companies in the
South Sumatra Basin, is shown in Figure 1.
Pre- and Early Tertiary Basement
The complex intercalation of igneous, metamorphic
and sedimentary rocks which forms the basement to
the South Sumatra basin has been simplified into a
number of NW-SE basement slices each of variable
composition and age (Figure 3). The oldest, least
deformed basement, considered part of the Malacca
Microplate, underlies the northern and eastern
portions of the basin. Further south lie the heavily
deformed remains of the Mergui Microplate, possibly
representing a weaker continental fragment. The
Malacca and Mergui Microplates are separated by the
Mutus assemblage, deformed fragments of material
acquired during northerly transport and collision.
Heavily deformed granite, volcanic and metamorphic
rock (of late Cretaceous and Tertiary age) underlies
the remainder of the South Sumatra Basin.
This basement morphology is believed to have
influenced the Eo-Oligocene rift morphology,
location
and
extent
of
Plio-Pleistocene
inversion/strike-slip, local high carbon dioxide
content in hydrocarbon gas, and the extent of
fractures in basement.
68
Late Eocene to Middle Oligocene (Lemat/Lahat
Formations)
Deposition in the South Sumatra Basin commenced
during the Eocene to early Oligocene (De Coster,
1974). Drilled sections consist of a tuffaceous, coarse
clastic sequence or granite wash (the Kikim Member)
conformably overlain by shale, siltstone, sandstone,
and coal deposited in lacustrine and marginal
lacustrine environments (the Benakat Member). The
section is thin or absent at the graben margins and on
intra-graben highs and up to 1000m thick in the South
and Central Palembang sub-basins.
Owing to the very limited number of penetrations of
the Lahat/Lemat Formations, the palaeogeographic
map for this interval (Figure 4) is considered
speculative.
Late Oligocene to Earliest Miocene (Talang Akar
Formation)
During the late syn-rift to early post-rift thermal sag
phase of tectonic evolution of the South Sumatra
Basin, widespread fluviatile and deltaic deposition
occurred across the basin. A trend from “proximal”
sand-rich braid-plain to “distal” sand-poor meander
belt and overbank sediments coincided with
progressively more marginal marine and marine
influences on sedimentation as subsidence continued.
The section is often very thick in the basin centres
and pinches out onto intra-basinal highs and at the
basin margins.
Figure 5 is a summary diagram showing the
distribution of depositional environments during
Oligocene times, equivalent to the Lower Talang
Akar Formation (Figure 1).
In the earliest Miocene, fluviatile conditions were
replaced by deltaic, marginal marine and shallow to
deep marine conditions over much of the South
Sumatra Basin by a pronounced transgressive event.
Figure 6 is a summary diagram showing the
distribution of facies belts at this time, equivalent to
the Upper Talang Akar Formation.
Early Miocene (Batu Raja Formation)
Marine transgression continued in the Early Miocene
with deeper marine shale deposition over the graben
areas, and shallow marine conditions over intra-
basinal highs and much of the eastern side of the
basin. Carbonate production flourished at this time
and resulted in the deposition of limestones both on
the platforms at the margins of the basin, and as reefs
on subtle intra-basinal highs. High quality carbonate
reservoirs are common in the south of the basin, but
are rarer in the Jambi sub-basin to the north. This is
due to increased sediment input northwards and more
pronounced exposure of bioherms enhancing
secondary porosity to the south and east.
Figure 7 shows the distribution of these facies during
this period in the Early Miocene.
Early to Middle Miocene (Gumai Formation)
Continuing marine transgression during the latter part
of the Early Miocene resulted in the deposition of
marine shales, siltstones and sandstones (named the
Gumai Formation) with rare carbonate deposition
over the crests of basement highs. During the peak of
the transgression, deposition of open marine,
glauconitic Gumai shales dominated the whole basin
creating the most widespread regional seal.
Later, progradation of deltaic sediments across the
basin occurred and transitional and then shallow
marine sediments gradually replaced open marine
shales. Platform areas to the east and north-east
dominated sediment input, although by this time some
volcaniclastic sediment was being sourced from
isolated exposed volcanic islands to the west.
Figure 8 illustrates the distribution
beginning of the Middle Miocene
maximum extent of Early Miocene
maximum extent of the preceding
shown in Figure 9.
of facies at the
and shows the
regression. The
transgression is
Middle Miocene (Air Benakat Formation)
The deep marine conditions prevalent in the latest
Early Miocene were gradually replaced by shallower
marine and then marginal marine conditions as a
result of continued sediment input from the margins
of the basin. With a few exceptions at the basin
centre, high-quality shallow marine reservoir
sandstones of Middle Miocene age are widespread
over the South Sumatra Basin. At the basin margins,
marginal marine to coastal plain conditions prevailed
(Figure 10).
69
As a result of the igneous activity in the Barisan
Mountains, many of these sandstones have significant
volcaniclastic content. This is especially true in the
west, where reservoir quality is severely degraded.
the D/E type using the Pepper and Corvi (1995)
classification.
Late Miocene (Muara Enim Formation)
The Late Miocene sediments within the South
Sumatra Basin record a period of increased volcanism
and the emergence of the Barisan Mountains, to the
west, as the major source of sedimentary input into
the basin. In the majority of wells, fluvial-deltaic and
coastal swamp sediments form the majority of the
Muara Enim interval, with no evidence for any
regionally extensive marine shale seals.
The Lemat/Lahat Formation of Eocene-Oligocene age
is described by Todd et al. (1997) as a lacustrine to
paralic source rock. Some wells in the Bentayan field
have penetrated shales with TOC values in the range
1 to 3% and are interpreted to be Class C algal oil
source rocks (Pepper and Corvi, 1995) deposited in a
shallow lacustrine environment. However, most
drilled Lemat Formation sections have little or no
source rock potential and therefore the significance of
this sequence as a source rock remains questionable.
Pliocene – Pleistocene (Kasai Formation)
Gumai Potential Source Rocks
During the Pliocene, major volcanism in the Barisan
Mountains led to further increases in volcaniclastic
component and further regression resulted in
continental conditions being established over all of
South Sumatra. The sediments are tuffs, continental
claystones
and
volcaniclastic
sandstones.
Sedimentation had become patchy by Pleistocene
times, with rapid uplift and erosion over inversion
features coinciding with further deposition between
folds to produce the current structural morphology.
Source potential is locally found in Gumai Formation
marine shales, generally towards the base of the
section close to the maximum flooding surface for the
basin as a whole. In some wells in the north of the
basin TOC's up to 8% and HI's up to 350 mgHC/g
have been recorded. These source rocks, although
immature where penetrated, would form effective
source kitchens if present in the deepest parts of the
Central Palembang Depression and Lematang Deep.
There little evidence for migration of significant
hydrocarbons from this source rock, although an oil
characterisation study by Rashid et al. (1998)
suggested that a marine shale source rock had been
the source for four oils within a restricted area of the
south of the basin.
SOURCE ROCKS AND HYDROCARBON
MIGRATION
Talang Akar Formation Source Rocks
The Talang Akar Formation is believed to be the
dominant source for commercial hydrocarbons in the
South Sumatra basin. Talang Akar intervals drilled at
the graben margins contain only poor quality gasprone source rocks whilst both paralic shales and coal
horizons have significant source rock quality in
thicker sections within the Central Palembang subbasin, the Benakat Gully (Sarjono and Sarjito, 1989;
Kamal, 1999; Argakoesoemah and Kamal, 2004) and
wells from the Jambi sub-Basin. In Senyerang-1, for
example, in the north of the basin, TOC values within
the Upper Talang Akar section are variable, but can
be as high as 36% with Hydrogen Index (HI) values
of between 200 and 350 mgHC/g. In the Benakat
Gully area shales have been reported with TOC
values of 5% and HI values ranging from 110 to 400
mgHC/g, while coals are reported with HI values of
400-470 mgHC/g. These source rocks are similar to
Lemat/Lahat Source Rocks
Characteristics of Migrated Oils
The analysed oils from the South Sumatra basin can
be divided into three main types:
(a) Oils derived from terrestrial Type D/E kerogens
(equivalent to Group (iii) of Schiefelbein and
Cameron (1997) and the Resinitic/Oleanic oils of
Rashid et al, 1998)
(b) Oils derived from Lacustrine Type C kerogens
(equivalent to the Group (i) of Schiefelbein and
Cameron (1997) and the Aquatic oils of Rashid
et al, 1998)
(c) Oils derived from mixed Type D/E and Type C
kerogens (equivalent to Group (ii) of
70
Schiefelbein and Cameron (1997) and the
Deltaic oils of Rashid et al, 1998).
The oils derived from marine Types A and B source
rocks identified by Rashid et al, 1998 are additional
oil types within a restricted area and are not observed
elsewhere in the basin.
Figure 11 is a plot of pristane: phytane ratio versus
nC17: pristane ratio for oils in the South Sumatra
basin. There is a clear trend from terrestrial sourced
oils to aquatic (Lacustrine) sourced oils. The oil
families described above have been identified based
on their geochemical data. Known terrestrial oils from
Mahakam and Ardjuna basins have also been plotted
for comparison as well as known lacustrine oils from
the Sunda and Central Sumatra basins. Figure 12 is a
plot of the δC13 isotope values for the same oils with
the same subdivision of oil types.
The oil groups derived from the geochemical data
also have a spatial relationship (Figure 13). Oils
derived from terrigenous source rocks are found in
the north-east and south-east, while lacustrine oils
appear to be prevalent to the west and in particular the
southwest part of the basin. The oils derived from a
mixed terrigenous/lacustrine source lie on the eastern
central area of the basin. The regional distribution of
oil types may be explained by reference to the Lahat
and Talang Akar Formation palaeogeographic maps
(Figures 4 to 6). During the Oligocene and Early
Miocene the areas of highest sediment input were the
fluvio-deltaic systems in the north-eastern and southeastern parts of the basin, resulting in a dominance of
terrestrially-derived kerogen in source material in
these locations. Between these two delta systems,
and towards the centre of the basin, lower sediment
input allowed the formation of localised non-marine
and marginal marine lakes and swamps and thus
mixed kerogen composition. Further to the west,
terrestrial input was negligible, and lacustrine
kerogens thus dominate.
CARBON DIOXIDE
Variable carbon dioxide contents in hydrocarbon gas
have been encountered across the basin, in some cases
at concentrations sufficient to delay or prohibit
commercial development (i.e. greater than 50%).
Although there are exceptions, moderate to low
carbon dioxide content dominates in Talang Akar
Formation reservoirs and δC13 data indicate that age
equivalent thermally immature coals (75 – 120oC) are
the principal source. At slightly deeper levels
(>150ºC), carbon dioxide is produced by low
temperature carbonate metamporphism and where the
Batu Raja Formation is deeply buried, such as at
Singa Field, this may explain the higher carbon
dioxide content. Metamorphic mineral reactions
continue to greater depths (350ºC and beyond) with
carbonates, granites and calcareous shales producing
further carbon dioxide with a characteristic δC13
signature - this is the major source of carbon dioxide
in South Sumatra, especially above deep basins where
carbonates exist within the Pre-Tertiary basement
(e.g. under the Jambi Central Basin, as also discussed
by Suklis et al, 2004).
MATURATION AND MIGRATION
PATHWAYS
Maturity Modelling
Figure 14 is a maturity map on basement derived
from well-based burial history models from across the
basin and based on seismic mapping modifying
earlier regional work by BEICIP (1985) and
Pertamina-BPPKA (1997). Geothermal gradients
were calculated from corrected bottom-hole
temperatures (BHT). Either Type C lacustrine source
rock, Type D/E oil-prone coal source or a mixture of
the these kerogens representative of what was
believed to be the source potential of Talang Akar
sediments at that particular part of the basin were
used in the modelling.
In the majority of modelled areas an estimation of the
amount of uplift and erosion within the last 2-5 Ma
has been required (Figure 15). The estimates are
based upon seismic and well data, with considerable
sediment thicknesses removed in the majority of wells
located on relatively recent inversion structures.
Models for each basin area were calibrated to wellderived vitrinite reflectance data. This was a difficult
task as in most cases modelled vitrinite profiles based
on BHT data and standard LLNL vitrinite kinetics
(Burnham et al, 1987) generated higher (hotter)
profiles than implied by observed vitrinite data. The
explanation for this apparent “vitrinite suppression”
lies in the use of LLNL vitrinite kinetics which are
inappropriate for Tertiary-age vitrinite. In Southeast
Asia, vitrinite from Tertiary sediments often contains
high levels of desmocollinite and is described as
71
perhydrous vitrinite. Custom kinetics representing
this type of vitrinite were used to achieve a generally
better match and support the heatflow derived from
BHT data.
Talang Akar Formation source rocks (and underlying
Lemat/Lahat where present) are either currently
mature or were mature prior to inversion over
virtually the whole of the South Sumatra Basin
(Figure 14). Source rock immaturity is only an issue
in certain small graben and intermediate terrace areas
at the margins of the basin. For the majority of the
basin, maximum expulsion of hydrocarbons was
taking place at, or immediately before the time of
Plio-Pleistocene inversion.
This coincidence of
timing resulted in migration of hydrocarbons into
these inversion trends, in addition to a degree of
remigration of previously expelled hydrocarbons.
There is a timing problem for hydrocarbon
entrapment in the deep western parts of the basin (e.g.
Central Palembang Trough) where maturation and
expulsion of hydrocarbons were essentially complete
prior to the commencement of formation of PlioPleistocene inversion structures.
The marine Gumai Formation source rock is
calculated to have reached maturity prior to inversion
over large parts of the Central Palembang and Jambi
Central sub-basins. However, there is no evidence
that the Gumai has source potential in these areas.
RESERVOIR
Pre-Tertiary Basement
Where drilled to date basement reservoirs consist of
fractured granites, carbonates, conglomerates and
sandstones with low porosity (< 10%) and minimal
matrix permeability.
Hydrothermal activity and
karstification of carbonate basement has provided
some locally developed secondary porosity (Chalik et
al, 2004). Shale-prone Pre-Tertiary rocks are
generally non-reservoir.
Permeability (and thus
deliverability) is fracture controlled and good gas
flow rates are achieved where extensive fracture
systems are present. Chalik et al., 2004 conclude that
the principal control on the development of fractures
in the Sumpal field was the latest tectonic event
characterised by regional folding and uplift. A
number of granite basement sections have flowed
water at high rates, the highest to date being the Pulau
Gading-1 well on the Merang High at 1800 bwpd. In
general, however, reservoir quality is to date
insufficient to allow significant oil flow (flow rates of
<100 bopd from Beringen wells are the only current
oil production).
Lemat Formation
The sandy Benakat Member of the Lemat Formation
is a proven commercial reservoir in the Benakat Field.
Lemat/Lahat sediments have also been reported as
reservoirs in the Puyuh (Maulana et al, 1999;
Tarazona et al, 1999) and Ibul fields. Porosities in
these sandstones and conglomerates are highly
variable though good porosity and permeability have
been reported by Maulana et al, 1999. Over most of
the basin Lemat sediments, where present, are beyond
reach of the drill bit.
Talang Akar Formation
The Lower Talang Akar Formation reservoirs consist
mainly of channel-fill, crevasse splay and point bar
sandstones of fluvio-deltaic origin in the north, and
delta-plain channel, delta-front, river mouth-bar and
marine barrier-bar environments in the south.
However, the regional variations related to proximity
to the open ocean are modified by local effects related
to rate of subsidence and proximity to sediment
source.
The non-marine succession (alluvial fans, braid-plain
and meander systems) shows a vertical proximal to
distal progression with time which equates to the
marine transgression seen further south at Raja
(Hutapea, 1981). Reservoir quality sands are
concentrated within braid-plain and meander
channels.
There is a spatial relationship between fluvial facies
with respect to both time from inception of rift
topography and distance from sediment source.
Reservoir quality is poor in poorly sorted, proximal
alluvial sediments and distal deltaics, with porosities
in the region of 10-15% (depending on depth) and
permeabilities in the 1-50 mD range. In contrast,
reservoir quality is good within sediments deposited
far enough away from the sedimentary source area to
have moderate to high textural and mineralogical
maturity, but still within high energy environments.
Here, porosities are concentrated in the 15-29%
range, with permeabilities from 100-3000 mD.
72
Figure 16 summarises the trends and environments
seen in Lower Talang Akar reservoirs.
pay in many wells due to a combination of low
reservoir energy and relatively poor permeability.
In the west of the basin an increase in volcanic
content results in a limited drop in porosity and a
marked degradation in permeability due to the
blocking of pore throats by authigenic clays. The best
quality sandstones therefore lie in the east, away from
the contemporaneous island arc volcanics, where flow
rates ≤ 3000 bopd are recorded.
SEALS
Batu Raja Formation
Outcrops at Batu Raja comprise a mixed succession
of wackestones, packstones, grainstones and true
framework reef rocks (Hadi and Simpolon, 1976).
Well data show that Batu Raja Formation porosity is
generally secondary in origin, the result of phreatic
exposure soon after deposition and prior to burial
(e.g. Clure and Fiptiani, 2001). However, high
porosity layers within the Batu Raja are related to
depositional as well as diagenetic processes and the
extent of potentially porous clean carbonates is
influenced by original depositional facies. Average
porosity in producing fields is 21%. Down to 8000 ft
there is no clear relationship between porosity and
depth and commercial gas flow rates have been
achieved from 11,700 ft in the Singa field (Crawley
and Ginger, 1998). In the Pulau Gading field a gas
flow rate of 17.7 mmscfd and 630 bcpd was achieved
from a Batu Raja reservoir with average porosity of
11%.
Reservoir permeability in producing fields ranges
from 25 mD to 3.8 Darcys, although commercial flow
normally only occurs after acidisation (Musi field
being an exception) and flow rates up to 4300 bopd
and 33 mmscfd have been achieved.
Regional Seal
The Early to Middle Miocene open marine shales
provide the highest quality seal on a regional scale
(Upper Talang Akar, Batu Raja equivalent and Gumai
formations). The depostional limit of this sealing
facies during the history of the Early Miocene
transgression (equivalent to each formation age) is
shown on Figure 9. The Upper Talang Akar
Formation seal is most effective in the central parts of
the basin where it is draped over basement highs and
has been proven to seal gas columns of over 500 m.
The only area where the lower Gumai Formation is
not an effective seal is in the west close to or within
the Barisan Mountains where coarse tuffaceous
sediments were deposited during Gumai times, and in
five wells in the extreme east close to clastic input
from the Sunda Shield.
Intraformational and Lateral Seals
Batu Raja Formation non-reef platform carbonates,
although not effective as a seal on a regional scale, do
appear able to trap hydrocarbons on a field-wide
scale. Examples of this trapping are seen at Kaji,
Semoga and Sungai Kenawang fields (Hutapea, 1998
and Clure and Fiptiani, 2001). Local sealing capacity
is common within the cyclical sedimentation in the
Talang Akar, Gumai and Air Benakat Formations and
has resulted in numerous examples of stacked pay
within fields in the basin.
PETROLEUM SYSTEMS DISCUSSION
Air Benakat/Gumai Formation
Pre-Tertiary Basement Play
The best reservoir sandstones are generally between 5
and 40m thick and found within the shallow marine or
coastal deltaic environments.
They have high
porosities (generally > 20%) but variable permeability
(10 mD to 3 Darcys), with 16-18% representing an
effective reservoir cut-off in most fields (k < 5mD).
This high cut-off is ascribed to a volcaniclastic
component in the sandstones, and high clay contents
due to low to moderate energy depositional
environments.
Flow rates are generally only
moderate (< 3,000 BOPD) despite relatively thick net
The precise extent of the basement play fairway is
poorly defined due its low maturity. Three proven
areas of the play exist, two in the Jambi Sub-Basin
(the Corridor/Jambi Selatan "B" PSC's and northern
part of UEP II Jambi Barat) and one in the South
Palembang Sub-Basin (the Beringen area). The
critical factors for the play are reservoir effectiveness
(brittle pre-Tertiary lithologies must be intensely
fractured by recent inversion to provide effective
hydrocarbon flow rates), gas charge of variable
carbon dioxide content (causing commercial problems
73
and occasionally technical failure e.g. Hallintar-1),
and seal (a key control in the east of the basin as
thick, continuous shale is required to support the
large, connected gas columns required for significant
reserves).
Lower Talang Akar Formation (and Lemat/Lahat)
Play
The main fairway for oil lies in the north and as a
strip along the eastern side of the basin, with gas
potential in the central parts of the basin. The critical
factors for the play are reservoir presence/
effectiveness
(high
quality
sandstones
are
concentrated along the eastern margin of the basin
close to sediment input points, with poor reservoirs
containing high volcaniclastic content to the west and
thin sandstones in the basin centre), migration/timing
of trap formation (interpreted to be the cause of
failure for certain wells on the Hari Terrace, and a
control on the play fairway in the east away from
proven source kitchens as well as in the deep western
parts of the Palembang Sub-basin where generation
preceded structuration) and source (the interpreted
lack of source rock in the extreme southwest of the
basin is thought to limit the play fairway in this
direction).
Air Benakat Formation Play
The Air Benakat Formation play fairway lies in a
central strip of the basin. The critical factor for the
play is seal, with source, migration and reservoir
presence all low risk across the fairway. Intraformational seals are present in the lowermost part of
the Air Benakat section over the centre of the basin
but are absent higher in the succession. Seal is
therefore both the stratigraphic and areal limit to the
play fairway.
EXPLORATION AND LICENCE HISTORY
Since the discovery of oil in 1896 within the
Kampung Minyak surface anticline there have been
four major peaks of exploration activity in the basin
(Figure 17):
1928 - 1940:
Pre-war success for the Shell-led
BPM consortium using modern
exploration seismic and drilling
techniques for the first time.
1968 - 1975:
Successes
resulting
from
the
introduction of the PSC system in
South Sumatra, with western oil
companies again active in the basin.
1984 - 1988:
Release of the best Pertamina
reserved acreage to the industry
Batu Raja Formation Play
The proven area of the Batu Raja Formation play
fairway lies in the east and south of the basin. The
critical factors for the play are reservoir
presence/effectiveness (high porosity carbonate
reservoirs are concentrated in the east and south of the
basin with too much sediment input to the north and a
lack of secondary porosity enhancement to the west)
and seal (with failed Batu Raja tests on the extreme
eastern side of the basin, at the limit of the Gumai
Formation seal).
Gumai Formation Play
The Gumai Formation play fairway lies in the north
and east of the basin. The critical factors for the play
are reservoir presence/effectiveness (clean, high
porosity sandstone reservoirs are concentrated in the
north-east within the high energy shallow marine
environment and close to the sediment input from the
Sunda Platform) and seal (controlling the eastern play
limit).
1994-Present: Recent successes related to the switch
from solely oil exploration to an
emphasis on gas.
Since the first discovery, over 100 fields have
produced oil and gas, with over sixty of these fields
still producing today. Cumulative oil production of
2.3 BBO has been achieved to date from recoverable
reserves of some 3.1 BBO. In addition, cumulative
gas reserves discovered in the basin has reached
approximately 22 TCF with less than 6 TCF
produced.
Figure 18 shows the cumulative discovery curve for
the South Sumatra Basin split by hydrocarbon type
and by play. The Talang Akar Formation sandstones
have historically been the most volumetrically
74
significant play followed by the basement and Batu
Raja Formation plays.
essentially mature though the low gas to oil ratio
could indicate some future gas potential.
The Talang Akar Formation discovery history
(Figure 19a) shows some indications of a resurgence
of gas discoveries in recent times (e.g. North East
Betara and Gemah), which may continue, but for oil
the Talang Akar play is clearly mature. Total reserves
discovered to date are 1918 MMBO and 5.8 TCF gas,
a ratio of 66% oil versus 34% gas. The average field
size is 41 MMBOE with the largest field being Talang
Akar itself at approximately 415 MMBOE
recoverable.
The mean field size derived from the full population
of South Sumatra fields is relatively small at less than
30 MMBOE, although the mean post-war oil field
size is 36 MMBO, with a P10 (high side) field size of
58 MMBO. For gas, the mean field size to date is
smaller at 135 BCF (22.5 MMBOE), with a P10 field
size of over 272 BCF (45 MMBOE).
The Pre-Tertiary fractured basement play was only
proven to be volumetrically significant with the
discovery of the Dayung Field in 1991 (Figure 19b).
Since then, however, some 8.5 TCF of gas has been
discovered in a relatively restricted area of the basin.
The majority of exploration wells have been
successful, although a number have encountered
hydrocarbon gas with high associated carbon dioxide.
The play is clearly under-explored and significant
future discoveries can be expected. Total reserves
discovered to date are 50 MMBO and 8.5 TCF gas
(96% gas). The average field size is 62 MMBOE with
the largest field, also the largest in the basin, being
Suban at approximately 5 TCF (850 MMBOE)
recoverable.
Batu Raja exploration in the South Sumatra Basin has
had a long history stretching back to the 1930's.
Despite this, Figure 19c illustrates that it is a
relatively immature play. This surprising combination
can be explained by the initial discoveries being gasdominated structural closures (of little or no
commercial interest at the time), whilst recent deeper
or stratigraphically controlled features have been
found using improved seismic acquisition and
processing. Total reserves discovered to date are 590
MMBO and 4.2 TCF gas a ratio of 46% oil versus
54% gas. The average field size is 31 MMBOE with
the largest field being Musi at approximately 184
MMBOE recoverable.
Overall, volumes discovered in Air Benakat and
Gumai Sandstones in South Sumatra are
approximately 850 MMBO and 1.2 TCF (Figures 19d
and 19e). This represents a ratio of 80% oil and 20%
gas, the most oil-prone of all the South Sumatra plays.
The ratio may be distorted by the past allocation of
small gas discoveries as dry holes. These plays are
Figure 20 is a graphical representation of discoveries
made in the South Sumatra Basin between 1988 and
2005.
Approximately 2.4 BBOE have been
discovered during this time about 27% of the total
estimated ultimate recoverable reserves for all fields
discovered to date. Of these discoveries over 83% of
the reserves were gas and 60% of the reserves were
discovered in fractured basement. During the
same period the rate of reserve additions was
significantly higher than before reflecting a move
to exploration in under-explored, stratigraphically
older and structurally deeper reservoirs. In contrast,
contemporaneous exploration in four way dip closed
Air Benakat/Gumai structures in the centre and on the
western margin of the basin resulted in failure or only
the discovery of sub-commercial reserves. Pinchout
plays at the margins of the basin at a number of
stratigraphic levels were also tested without success.
However, pinchout plays within the central parts of
the basin remain an attractive target.
FUTURE EXPLORATION POTENTIAL
Given the long exploration history and generally
benign operating environment of the South Sumatra
Basin, it is unsurprisingly a relatively mature oil
province.
It is anticipated that few oil fields
containing reserves in excess of 25 MMBO will be
drilled on long-established play fairways, although
some significant oil finds to 100 MMBO may be
made in new or emerging play types. Extrapolating
recent trends indicates that predicted oil reserve
additions will be in the range of 200 to 500 MMBO.
In contrast to the basin's mature oil status, the South
Sumatra Basin is under-explored for gas, and contains
good remaining gas potential in both new and existing
successful plays. Extrapolation of recent trends in the
basement, Talang Akar and Batu Raja discovery
histories indicates that a further 6 to 10 TCF gas
could be discovered.
75
The last 15 years have seen some of the most
successful exploration in the history of exploration in
the South Sumatra Basin. This can be explained by
the switch in emphasis from oil to gas exploration
spurred on by the development of the Singapore gas
market in the late 1990’s as well as improvements in
seismic acquisition and processing. The remaining
potential of the South Sumatra Basin is heavily
dominated by gas. The exploration for these yet to be
found reserves relies on the continued development of
gas markets with Sumatra and West Java. The
demand for gas in these areas is well documented as
is Indonesia’s need to reduce fuel oil usage for power
generation and to bolster declining oil production. Yet
there is currently at least 4 TCF of uncontracted gas
in the South Sumatra Basin. It is therefore critically
important that current stranded gas reserves are
brought to the Sumatra and West Java markets as
soon as possible and that there is open and fair access
to these markets for all.
the Delineation and Production of a Fractured
Basement
Reservoir:
Indonesian
Petroleum
Association, Proceedings, Deepwater and Frontier
Exploration In Asia & Australasia Symposium, p.
199-224.
Clure J. and Fiptiani N., 2001. Hydrocarbon
Exploration in the Merang Triangle, South Sumatra
Basin:
Proceedings
Indonesian
Petroleum
Association, 28th Annual Convention, p. 803-824.
Crawley, M. and Ginger, D., 1998. Depth Prediction
Ahead of the Bit: A Case Study from the Singa-1
Discovery Well, South Sumatra: Proceedings
Indonesian Petroleum Association, 26th Annual
Convention, p. 251-264.
De Coster, G.L., 1974. The Geology of the Central
and South Sumatra Basins. Proceedings Indonesian
Petroleum Association 3rd Annual Convention, p. 77110.
ACKNOWLEDGEMENTS
The original work for this paper was undertaken at
Amerada Hess in London by Kevin Fielding in 1999,
with contributions from David Ginger and Steve
Meadows. The authors would like to thank BPMigas
and Amerada Hess for permission to publish this
paper and Alasdair Duncan for comments on an early
draft.
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Kamal, A., 1999. Hydrocarbon Potential in the
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77
78
Figure 1 - A simplified chronostratigraphic scheme for the South Sumatra basin.
79
Figure 2 - Key structural elements of the South Sumatra basin,
showing Eo-Oligocene age (northeast-southwest orientated)
rifts cross cut by Plio-pleistocene inversion/transpressional.
Figure 3 - Pre- and Early Tertiary basement terrains of southern
Sumatra.
80
Figure 4 - Interpreted Late Eocene to Middle Oligocene (Lemat/Lahat
Formations) palaeogeography.
Figure 5 - Interpreted Late Oligocene (Lower Talang Akar Formation)
palaeogeography.
81
Figure 6 - Interpreted Earliest Miocene
Formation) palaeogeography.
(Upper
Talang
Akar
Figure 7 - Early Miocene (Batu Raja Formation) palaeogeography.
82
Figure 8 - Interpreted Middle Miocene (Gumai
palaeogeography – maximum regression.
Formation)
Figure 9 - Interpreted palaeogeography at maximum transgression
within the early Miocene (Batu Raja Formation equivalent)
and Middle Miocene (Gumai Formation) and the extent of
effective regional seal.
83
Figure 10 - Interpreted Middle-Late Miocene
Formation) palaeogeography.
(Air
Benakat
Figure 11 - A plot of pristane: phytane ratio versus nC17: pristane
ratio for oils in the South Sumatra basin, showing the
subdivision of oils in to groups derived from terrigenous,
lacustrine and mixed kerogens.
84
Figure 12 - A Plot of δC13 isotope values for oils in the South
Sumatra basin, showing the subdivision of oils in to
groups derived from terrigenous, lacustrine and mixed
kerogens.
Figure 13 - Distribution of discovered oil character within the
Southern Sumatra basin, showing the same sub-division
of oil groups as in Figures 11 and 12.
85
Figure 14 - Present day maturity map on top basement.
Figure 15 - An estimate of minimum uplift and erosion from 5ma to
present day across the South Sumatra basin, based upon
a combination of missing sections at drilled well
locations and seismic interpretation.
Figure 16 - Lower Talang Akar Formation reservoirs – type section and interpreted environment of deposition.
Figure 17 - Exploration history of the South Sumatra basin.
86
87
Figure 18 - Cumulative discovery curve for the South Sumatra basin split by play and hydrocarbon type
Figure 19 - Discovery history curves for: (a) Talang Akar Formation; (b) Pre-Tertiary basement; (c) Batu Raja
Formation; (d) Gumai Formation and (e) Air Benakat Formation.
88
Figure 20 - A Graphical representation of discoveries made in the South Sumatra basin between 1988 and
2005. Approximately 2.4 BBOE have been discovered during this time about 27% of the total
estimated ultimate recoverable reserves for all fields discovered to date.
89