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Noble et al 2016 KOFIAU AND CENDRAWASIH BAY FRONTIER BASIN EXPLORATION: FROM JOINT STUDIES TO POST-DRILL ASSESSMENT

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In this article, we describe the exploration activities for two frontier deepwater basins in Eastern Indonesia, undertaken over a period from 2006 to 2013. The two basins are the Kofiau Basin and Cendrawasih Bay (Waipoga) Basin, located respectively on the northwestern and eastern margins of the Bird's Head terrane of West Papua. Significant datasets were acquired in both basins during the pre-tender stage (open area-joint study) and PSC operations stage. This included regional 2D seismic, gravity/magnetics, high resolution sea floor multi-beam, piston core geochemistry, and prospect-specific 2D and 3D seismic programs. Two deepwater exploration wells were subsequently drilled in Kofiau (Ajek-1 and Elit-1) and one well in Cendrawasih Bay (Elang-1).
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* Agra Energi Indonesia, Jakarta Indonesia
** Oro Negro Exploration, California USA
6-TS-16
INDONESIAN PETROLEUM ASSOCIATION
2016 Technical Symposium, Indonesia Exploration: Where From - Where To
KOFIAU AND CENDRAWASIH BAY FRONTIER BASIN EXPLORATION: FROM JOINT
STUDIES TO POST-DRILL ASSESSMENT
R. Noble*
P. Teas**
J. Decker**
T. McCullagh*
Deddy Sebayang*
D. Orange**
ABSTRACT
In this article, we describe the exploration activities
for two frontier deepwater basins in Eastern
Indonesia, undertaken over a period from 2006 to
2013. The two basins are the Kofiau Basin and
Cendrawasih Bay (Waipoga) Basin, located
respectively on the northwestern and eastern margins
of the Bird’s Head terrane of West Papua. Significant
datasets were acquired in both basins during the pre-
tender stage (open area-joint study) and PSC
operations stage. This included regional 2D seismic,
gravity/magnetics, high resolution sea floor multi-
beam, piston core geochemistry, and prospect-
specific 2D and 3D seismic programs. Two
deepwater exploration wells were subsequently
drilled in Kofiau (Ajek-1 and Elit-1) and one well in
Cendrawasih Bay (Elang-1).
The two basins show some similarities in their
stratigraphic architecture, but also some important
differences in tectonic setting and structural
evolution. The Kofiau basin is a northeast-southwest
trending depocenter with two major episodes of
basin formation; one in the early Pliocene, followed
by a period of deformation and erosion, and another
depositional period lasting from the mid Pliocene
until Recent. The basin evolution is controlled by the
Sorong Fault Zone, the main strike slip plate
bounding fault between the Australian Plate and the
Pacific Plate. Eocene to late Miocene carbonates of
the New Guinea Limestone (NGL) comprise the
effective basement of the Kofiau basin. The Kais
limestone member at the top of NGL is likely to
occur at drillable depths in the northern part of the
basin, but is generally too deep to be of interest over
much of the area.
The Cendrawasih Bay (Waipoga) Basin belongs to a
large Plio-Pleistocene post-collisional clastic.basin
complex which extends across northern New Guinea.
The northern margin is formed by the major east-
west trending Sorong-Yapen Fault zone, to the west
and southwest by the Bird’s Head and Lengguru Fold
Belt, to the south by the Weyland mountain terranes,
and to the east by the Waipoga Foldbelt. It contains
Miocene to Pleistocene sequences which attain
sediment thicknesses of at least 25,000 ft in the
Waipoga Trough.
Sea-floor piston cores revealed the presence of
significant oil and gas seepage. Crude oil biomarkers
and carbon isotopes showed that, in both basins, the
oil was derived from a Tertiary source rock, most
likely of the Klasafet Formation type (Late Miocene-
Pliocene). Seepage of thermogenic and biogenic
gases was also recorded, although the relative
amounts of each differed between areas. Two
exploration wells in Kofiau targeted Plio-Pleistocene
sands in structural/stratigraphic traps, and showed
the presence of good quality sands charged with
mixed thermogenic-biogenic gas, although the pay
sands at these locations were not sufficiently thick
for commercial development. The exploration well
in Cendrawasih Bay targeted a sedimentary package
comprising carbonates and clastics of Tertiary age in
a large four-way structural anticline. The well
successfully encountered a moderately thick
limestone section of Miocene to Eocene age,
however the carbonate was tight and non-productive.
No indications of thermogenic hydrocarbons were
seen in the well.
Reconciliation of the drilling results with evidence
for active petroleum systems in both basins provides
the impetus and direction for follow-up exploration
activity.
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INTRODUCTION
Eastern Indonesia offers many opportunities for oil
and gas exploration. The region also poses
significant challenges. The opportunities stem from
a large number of under-explored basins with a
variety of attractive play types. The challenges lie
both above ground and in the subsurface, not the least
of which is the availability of sufficient seismic and
well data to encourage frontier exploration activity.
Due to high project costs and substantial investment
risk, work has tended to focus around areas with
proven oil and gas. Not surprisingly, most activity
has followed previous exploration success, which is
mainly centered around the Salawati basin, Bintuni
basin, onshore Seram and Timor Sea regions. This
has left many sedimentary basins largely undrilled,
despite the apparent prospectivity of the acreage.
In order to encourage exploration activity, MIGAS
introduced the Direct Award process for tendering
work areas (Minister Decree no. 1480/ year 2004).
This allowed companies to conduct joint studies with
Government approved universities prior to
submitting a bid for the nominated block. The
initiative has been very successful, with a significant
increase in PSC licensing activity occurring between
2004-2011, particularly in deepwater and frontier
regions. The Joint Study process also promoted the
acquisition of new data in remote areas on a non-
proprietary basis. One such program was the
Indonesia Frontier Basin (IFB) project, conducted by
TGS-NOPEC / TDI Brooks, and underwritten by
Black Gold Energy LLC and its affiliates (Orange et
al., 2009). The IFB project provided a significant
volume of marine 2D seismic, gravity/magnetics,
seafloor bathymetry and piston core geochemistry
over many undrilled or under-explored basins in
Eastern Indonesia (Bernard et al., 2008).
In this paper, two areas are described that were
initially covered by data from the IFB program. Joint
studies were carried out in the Kofiau and
Cendrawasih Bay basins in 2006/2008 and PSC
blocks were released by MIGAS for bidding in
2008/2009. After PSC award, additional 2D and 3D
seismic were acquired, prospects were mapped, a
drilling program was designed, and exploration wells
were drilled. The results of the program are described
herein, with particular reference to the reconciliation
of pre-drill insights and post-drill outcomes.
EXPLORATION AREAS
The two areas of interest, Kofiau and Cendrawasih
Bay, are shown in Figure 1, together with the main
tectonic elements of the Bird’s Head / West Papua
region.
A. KOFIAU BASIN
Regional Structure
The Kofiau basin is a northeast-southwest trending
depocenter with two major episodes of formation,
one in the early Pliocene followed by a period of
deformation and erosion and another period of
deposition lasting from the mid Pliocene until recent
formation of the basin is controlled by the Sorong-
Yapen Fault Zone, the main strike slip plate
bounding fault between the Australian Plate and the
Pacific Plate (Decker et al., 2009). The Sorong Fault
initiated approximately 7Ma in the region of the
Bird’s Head of West Papua. Net movement across
the fault is likely in the 100s of kilometers in
magnitude and is responsible for distributing
fragments of Australian-affinity crust from eastern to
central Indonesia. Strike slip fault movement
resulted in local transtensional deformation and the
formation of restricted marine basins along the trend
of the fault zone. While the transtensional motion in
the Kofiau basin region dominates, with associated
normal faulting and roll over folding, relatively
minor shifts in plate motion vectors or activation of
non-optimally oriented fault surfaces can result in
transpression accompanied by folding and uplift.
Such a case is likely responsible for the mid Pliocene
unconformity as well as more recent folding in the
eastern part of the Kofiau PSC.
Regional Stratigraphy
The generalized stratigraphy of the Kofiau and
Salawati Basins is shown in Figure 2. The Eocene to
late Miocene carbonates of the New Guinea
Formation comprise the effective basement of the
Kofiau basin. Beneath the New Guinea section is
likely to be Mesozoic continental rocks of Australian
northwest shelf affinity, however, these units are
considered too deep to impact the petroleum system.
The New Guinea carbonate is generally capped by
the Kais Formation which is defined as lagoonal reef
build-ups at the top of the carbonate unit (Satyana,
2003). The Klasafet formation is a marine shale
deposited contemporaneously with the Kais as facies
equivalent deep-water shale to the Kais reef build-
ups. The Klasafet is overlain by the Klasaman
Formation which is a lithologically similar, marine
shale dominant unit. Limestone and sandstone occur
within both the Klasafet and Klasaman formations
but are not distinguished with unique formation
names. The Klasafet-Klasaman transition effectively
occurs at the Miocene-Pliocene transition. A major
regional unconformity occurs in the mid Pliocene
and exposed rocks at least as old as the mid Miocene
New Guinea Formation. This results in Klasaman
being superimposed on a large range of sub-cropping
units. The Klasaman appears to be more sand prone
above the mid Pliocene unconformity, likely as a
result of uplifted hinterlands shedding more coarse
clastic debris into the marine system. The Pliocene-
Pleistocene boundary is also marked by a major
unconformity and overlain by the Sele Formation
which typically forms a mollase deposit.
Petroleum System and Play Concept
A seismic transect illustrating Kofiau Basin play
concepts is shown in Figure 3. Each element of the
petroleum system is described as follows:
Source Rocks:
Miocene Klasafet and Pliocene Klasaman shales are
the expected source rocks in the Kofiau basin.
Regionally, the Klasafet-Klasaman section is
considered the primary source for Salawati trend
hydrocarbons (Satyana, 2009; and references
therein). The Klasafet is a restricted marine source
with detrital land plant organic matter. Pre-drill
insights in to the type of source rock in Kofiau were
gained from geochemical analysis of sea-floor seeps
obtained from piston cores in the Misool region
(Noble et al., 2009). Biomarker profiles and carbon
isotope ratios for the oil seeps indicate a Tertiary
marine shale containing abundant detrital plant
matter. The oil characteristics are typical of a
Klasafet-type source rock, with likely contributions
from the younger Klasaman Formation.
Reservoir Rocks:
Regionally proven reservoir rocks are the Kais
Formation carbonate build-ups and reef deposits.
However, in the Kofiau prospect area of interest, the
Kais Formation is too deeply buried to be accessible.
Hence the reservoir targets in the Kofiau exploration
wells are Plio-Pleistocene sandstones, which will be
trend-opening in regards to reservoir facies.
Provenance of the sands is considered to be from the
Kemum High, located in the Bird’s Head province,
east of Kofiau. Deposition of sands is likely in a
shallow marine shoreface setting, with sediment
transport via channelized systems in a westerly-
northwesterly direction.
Seal Rocks:
Basinal shales of the Klasaman Formation provide
the seal for the Kofiau trend of prospects and leads.
The shale is a proven seal in the nearby Salawati
fields, and is effective even at relatively shallow
burial (~3000 ft).
Trapping Mechanisms:
The types of anticlinal traps observed in the western
Kofiau basin are not present regionally and had not
been tested prior to this drilling program. Four-way
structural closures occur at the mid Pliocene
unconformity and throughout the upper Pliocene
section, at least to the Pleistocene unconformity. The
anticlinal trends extending across the area are not
consistent with compression in the strike slip system,
and have been interpreted to be a result of roll over
associated with extension. The large normal faults
are consistent with transtension along the Sorong
Fault Zone. Structure formation occurred throughout
the late Pliocene as evidenced by differential
deposition across the major normal faults and
development of a depocenter on the downthrown
blocks. Deformation appears to have accelerated up
to the Pleistocene unconformity and then to have
ceased. The structures are therefore quite young, but
are not active within the Pleistocene. Stratigraphic
trap potential is also evident, with channel-like
geometries of sand deposition within a shallow
marine shelfal environment.
Migration and Timing of Hydrocarbon Charge:
Within the Misool/Kofiau area, a large number of oil
and gas seeps were identified on the seafloor using
multibeam bathymetry and backscatter, and sampled
by piston coring (Noble et al., 2009). The oil and
thermogenic gas seeps prove the existence of vertical
migration pathways from the main kitchen in the
northeastern part of the Kofiau basin along active
structural conduits. Burial of the Kofiau basin is
relatively recent, following the mid Pliocene
unconformity of approximately 4Ma. However, this
loading event is likely also responsible for the
generation of the oils charging Salawati. So, while
timing is limited to the last several million years, the
system appears to be very active and capable of
delivering significant hydrocarbon resources.
B. CENDRAWASIH BAY
Regional Structure
Cendrawasih Bay is located within the Waipoga
Basin which is part of North Irian Basin. The
northern margin of the basin is formed by the major
east-west trending Sorong-Yapen Fault zone, to the
west and south-west by the Wandaman Peninsula
and Lengguru Fold Belt, to the south by the Weyland
mountain overthrust terranes and to the east by the
Waipoga Foldbelt (Figure 1; Sapiie et al., 2010).
The Waipoga Basin belongs to a large Plio-
Pleistocene post-collisional clastic basin complex
which extends across northern New Guinea and West
Papua. It contains Miocene to Pleistocene sequences
which attain offshore an estimated thickness of over
20,000 ft (sediments overlying the economic
basement reach a thickness of 4.5 seconds in
Cendrawasih Bay). Onshore, at least 25,000 ft of
sediments are contained within the Waipoga Trough.
Plio-Pleistocene deposits are interpreted as clastics
deposited in a deep marine to a near-shore
environment whereas older sediments are interpreted
as fluvial-shelfal sands (McAdoo and Haebig, 1999).
Northward movement of the Australia-India Plate,
coupled with the westward relative motion of the
Caroline and Philippine plates, produced oblique
convergence along the northern edge of the
Australian continent. Convergence and transform
motion have dominated the evolution of the northern
Australian Margin since the latest Miocene and have
probably resulted in major crustal shortening in
northeastern Papua. Structural exploration targets in
Cendrawasih Bay are interpreted as products of this
oblique movement.
The plate collision caused the formation of an
orogenic zone parallel to the Australian continental
margin, extending through Irian Jaya and New
Guinea (New Guinea Fold Belt) and characterized by
"thin-skin"deformation. In order to accommodate the
difference in crustal shortening between the New
Guinea Mobile Belt and Bird’s Head, two major
crustal breaks, the southwest trending Waipoga Fault
and the complementary southeast trending
Wandamen Fault were formed at an early stage of the
convergence. The stress generated at the intersection
of these fracture systems was relieved by
overthrusting of continental segments to form the
Weyland Overthrust. Large slabs of crustal rocks
have been thrust tens of kilometers southwards over
the Australian continental crust (Dow & Sukamto,
1984). Plate convergence is also marked by the
collision of the Australian continent with the
Melanesian Arc of the oceanic province and by the
cessation of island arc volcanism.
Regional Stratigraphy
The generalized stratigraphy of the North Irian basin
is shown in Figure 4. Sediment fill, as observed and
measured in outcrop, has been continuous through
the Tertiary with the exception of a regional
depositional hiatus in the Late Miocene. This hiatus
resulted in a major unconformity that can be traced
over large areas of the basin on seismic data. This
unconformity marks the base of the Mamberamo
Formation and the top of the Makats Formation or
older formations. Prior to the hiatus, almost 19,000
feet of dominantly clastic sediments had
accumulated in the North Irian Basin. Lateral facies
changes resulted in locally significant carbonate
buildups. These sediments are assigned to the
Auwewa, Darante and Makats Formations. Post
hiatus, deposition of the Mamberamo Formation
continued uninterrupted until the present except for
local, minor unconformities. The Mamberamo
Formation consists of 4 members totaling 23,000 feet
in thickness as measured in outcrop. These
thicknesses assuming the maximum section of each
formation is in the same place would imply a total
North Irian Basin fill of nearly 42,000 feet. Seismic
evidence is available which indicates that the North
Irian Basin is at least 25,000 to 30,000 feet deep
along its axis. Local down-warped areas may exist
which are even deeper (McAdoo and Haebig, 1999).
Petroleum System and Play Concept
Seismic transects, illustrating the play concept in
Cendrawasih Bay are shown in Figure 5. Each
element of the petroleum system is described as
follows:
Source Rocks:
The presence of hydrocarbon shows in onshore
exploration wells and the proximity of oil and gas
surface seeps in the offshore Mamberamo delta area
are indicative of effective source rocks in the region
(McAdoo and Haebig, 1999). The source of the
hydrocarbons has not been proven conclusively, but
is likely to be within the Neogene section (Makat and
Memberamo formations). Biogenic gas is also
important, as seen in Mamberamo sandstone
reservoirs of the Niengo-1 well which flowed gas on
test (Satyana et al., 2007).
Seep analysis of sea bed piston cores in Cendrawasih
Bay indicated mainly gas occurrences. Biogenic gas
was commonly in high abundance. Thermogenic gas
was less prevalent, but identifiable in some cores.
One significant oil seep was positively identified on
the basin flank, and its geochemical characteristics
indicated a marine source rock of Tertiary age (Noble
et al., 2009). The positive indication of an active oil
migration system provided a strong incentive to test
the basin potential with an exploration well. In
addition, in-situ biogenic gas was considered a viable
charging option for Pleistocene prospects.
Reservoir Rocks:
Regionally proven reservoir rocks in the adjacent
Waropen Basin are Memberamo sands and Hollandia
carbonates. Mamberamo Formation sandstones in
the R-1, Niengo-1 and other exploration wells exhibit
good porosities in the order of 23% (McAdoo and
Haebig, 1999). The main reservoir target in the
deepwater Waipoga Basin was a seismically defined
thick sedimentary package interpreted as fluvial-
deltaic sediments overlain by a limestone section.
The interval may be equivalent to the Oligo-Miocene
Darante to Makat formation in the neighboring
Waropen Basin, although, the exact age and type of
reservoir facies was uncertain prior to drilling.
Seal Rocks:
Intraformational shales equivalent to the Makat and
Memberamo Formations provide seal for prospects
in Cendrawasih Bay area. Seismic interpretation and
outcrop data indicate these shale formations are
widely deposited regionally.
Trapping Mechanisms:
Traps for gas discoveries in the neighboring
Waropen Basin, such as Niengo, are four way
anticlinal closures that are most likely related to
transpressional deformation. A similar trapping
mechanism is anticipated for prospects and leads
located within the offshore Waipoga basin.
Migration and Timing of Hydrocarbon Charge:
The low geothermal gradient generally observed in
northern Irian Jaya implies that mature source rocks
would only be found in the deepest parts of the basin
(McAdoo and Haebig, 1999). The Cendrawasih Bay
kitchen is most likely located in the southeast corner
of Waipoga Basin, corresponding to the main Plio-
Pleistocene sediment depocenter. Migration is
expected to occur laterally and vertically into
permeable beds that drain the mature kitchen.
Charging events are considered to be young,
corresponding to the massive thickness of Plio-
Pleistocene sediments in the basin depocenter.
EXPLORATION DRILLING
A. Kofiau
Two wells were drilled in the Kofiau study area:
Ajek-1 (Dec 2012), water depth 1,853 ft; and Elit-1
(Aug 2013), water depth 1,334 ft. Both wells were
located within 3D seismic coverage (Figure 6).
Ajek-1 successfully tested a series of high amplitude
reflector packages, which were prognosed as
hydrocarbon saturated, sand prone strata. The
Kofiau basin was formed by movement of the Sorong
Fault during the Late Pliocene providing
accommodation space for a thick package of
sediment. Drilling results indicated this section
comprised thick claystones with minor siltstones and
occasional sandstone and limestone beds, deposited
in a shallow marine environment. Thin layers of gas
bearing, fine grained, quartzose clastic deposits with
common to abundant shell debris were intersected at
the depths corresponding to seismic reflector
packages. The well drilled through the mid Pliocene
Unconformity and reached a total depth of 6,185 ft
TVDSS in a predominantly claystone section. Based
on mud gas readings and wireline log measurements,
all zones with adequate porosity were found to be gas
saturated. Hydrocarbon samples obtained by MDT in
three such porous intervals confirmed the presence
of gas charged sands. However, net pay thickness at
this well location was insufficient to support a
commercial gas development.
The second well drilled in the basin, Elit-1, also
tested a series of high amplitude reflector packages
of Late Pliocene age. The primary amplitude target
was intersected at the prognosed depth of 3,700 ft,
with a significant gas kick at the top of the reservoir.
Wireline logs and sample analysis indicated gas
bearing sands, although the net pay count was below
the commercial threshold. The well reached a total
depth of 3,914 ft TVDSS in Late Pliocene claystones.
Mud gas compositional profiles and MDT samples
were used to gain insights into the origin of
hydrocarbons. Isotube mud gas samples were
collected in Ajek-1. Real time rig-site measurement
of mud gas carbon isotopes was conducted in Elit-1
(Schlumberger). Figure 7 shows a plot of gas isotope
ratio (delta C13 of methane) versus depth below mud
line for both wells. A mixing trend between biogenic
and thermogenic methane is clearly evident. The
shallowest samples are characterized by isotopically
light methane, which is of bacterial origin. A trend
towards heavier carbon isotopes is seen with depth,
which indicates an increasing contribution from
thermogenic gas. Mud gas composition in Ajek-1
(not illustrated here) also indicates an increasing
amount of wet gas with depth (C2+). Hence it is
interpreted that a thermogenic migration front is
moving vertically through conduits in the sediment
column, and has contributed to the charging of
porous intervals. The deepest MDT sample from
Ajek-1 (5,310 ft) has C2+ content of 13% and delta
C13 methane value of -46 per mil, indicating a
significant contribution of thermogenic gas, with
possible oil affinity.
B. Cendrawasih Bay
The Elang-1 exploration well (July, 2013) was
successfully drilled to test the hydrocarbon potential
of a large anticlinal structure covered by 3D seismic
in Cendrawasih Bay. Water depth at the well location
was 5,033 ft (Figure 8).
Elang-1 targeted a seismic package which was
prognosed as carbonates overlying a fluvio-deltaic
section. The top of the primary target was
encountered at 13,665 ft, after drilling through a
thicker than expected Pleistocene section with 8,350
feet of sediments deposited at an extremely high rate
of 5,500 ft/Ma. The upper part of the target interval
comprised a massive micritic limestone, with
occasional marls and mudstones. The limestone was
tight, with no hydrocarbon indications during
drilling. Biostratigraphy indicated Miocene to
Oligocene age, similar to Wurui Limestones and
related units seen in outcrop (Pieters et al, 1983).
Below 14,125 ft the section graded to interbedded
mudstones, siltstones and claystones, and eventually,
to volcanogenic sediments to the base of the well at
15,779 ft TVDSS. The oldest dateable sediments
were of Middle Eocene age. No adequate reservoir
properties were encountered over the target section.
Mud gas samples were continuously monitored at the
rig site for composition (C1 to C5) and carbon
isotope ratios of methane. The gas compositional
profile indicated low levels of methane over the
entire section, with negligible C2+ components.
Delta C13 ratios for methane ranged from -75 to -65
per mil, indicating gas of biogenic origin only
(Figure 9). This remarkable profile indicates that
thermogenic hydrocarbons had not migrated into the
section of interest at the Elang-1 well location, which
was further supported by a lack of wet gas and
hydrocarbon fluorescence in the cuttings.
RECONCILIATION OF PRE- AND POST-
DRILL RESULTS
It is instructive to look back at the exploration
concepts developed during the joint study and PSC
technical evaluation stage, and compare these to the
actual results of drilling in both exploration areas.
A. KOFIAU
The Misool JSA identified the Kofiau basin as a
structurally interesting province due to the tectonic
interaction of two major plates: the Pacific plate and
the Australian plate. The Kofiau area straddles the
Sorong strike slip fault which is taken as a major
tectonic boundary between the two plates. The
Sorong-Yapen Fault is a major left-lateral fault that
has been active since the early Pliocene. The regional
tectonic regime of this boundary is transpressional
resulting from relatively northward movement of
Australia and westward movement of the Pacific.
However, at Kofiau, the Sorong fault bends left
around the Bird’s Head and is transtentional, with the
dominant local structures being a series of en
echelon roll over folds and synthetic leftlateral
faults trending in a NNE – SSW direction (Decker et
al., 2009). This has resulted in several well defined
four-way and three-way faulted anticlinal closures
that are readily mapped on seismic. From a look-
back perspective, the structural targets identified for
drilling in Kofiau are very robust, and unlikely to
change significantly with information gained from
the well data.
Reservoir development in the previously untested
Plio-Pleistocene section of the Kofiau Basin was a
key risk prior to drilling. Seismic amplitude mapping
played an important role in defining likely
channelized sand fairways. Amplitude extractions
were mapped at multiple stratigraphic levels, and
well locations were selected in order to intersect the
best stacked reservoirs. However, post drill
evaluation of Ajek-1 showed that sands were not
particularly well developed, although where present,
the sands displayed good reservoir properties. Ajek-
1 was drilled at a crestal location on a large anticlinal
feature. It is probable that the structural elevation at
the time of sediment deposition resulted in sand by-
pass at the structural crest. It is considered that
locations on the flanks of structural highs would
likely contain ponded sediments with potential for
thicker sand development. This would offer
attractive opportunities for follow-on exploration in
the Pliocene play.
The Elit-1 well, in contrast, targeted a clearly defined
channelized body from 3D seismic mapping. This
was largely a stratigraphic trap within the Late
Pliocene depositional fairway. Drilling results
indicted a much thicker sand body, compared to
those encountered at Ajek. This is a positive result
with respect to the sand delivery system in the Kofiau
area. As stated earlier, the net pay count at Elit-1 was
below commercial threshold. This is most likely due
to limitations of the trap/seal geometry, rather than a
lack of reservoir or charge.
In terms of hydrocarbon charge, an important feature
observed during the open area-joint study phase, was
the seepage of oil and gas on the sea floor. The
Misool JSA had oil seeps that were tied
geochemically to a Late Tertiary Klasafet–type
source system (Noble et al, 2009). Gas of
thermogenic and biogenic origin was also observed
in the sea bed cores. Drilling at Ajek-1 and Elit-1
discovered only gas in the sandstones, the
composition of which was confirmed by MDT
sampling. A question then arises as to why there was
such a strong indication of oil pre-drill, but only gas
in the two wells. The answer lies in the hydrocarbon
migration and basin plumbing system. The oil on the
sea floor is mainly associated with mud volcanoes
which are widely known as vertical conduits for fluid
movement (Kopf, 2002; Hansen et al., 2005). There
is a high correspondence between prolific oil seepage
and the presence of mud volcanoes in the study area.
In other locations away from the mud volcanoes,
migration takes place at normal rates via typical
carrier bed networks, both lateral and vertical. It
therefore appears that the Ajek and Elit wells were
drilled in locations where the oil migration front has
not reached the targeted stratigraphic level. In a
young, vertically drained basin such as Kofiau,
considerable “migration lag” is likely to occur.
Future drilling for deeper targets, or in other parts of
the basin, holds promise to uncover the hidden oil
potential.
B. CENDRAWASIH BAY
Prior to the Cendrawasih Bay Joint Study in 2006,
the deepwater section of the Waipoga Basin had
received no exploration attention. The only
exploration wells drilled were in shallow water
locations on the present day shelf, and some onshore
wells in the adjacent Waropen basin. The majority of
these wells targeted the Plio-Pleistocene interval, and
there were no penetrations of sections similar to the
primary objective of Elang-1. Technical work
undertaken during the Joint study showed that
Cendrawasih Bay contained a thick sedimentary
section that thickened progressively from west to
east. The section was deformed in a compressional
foldbelt that appears to be actively forming at the
present time (Decker et al., 2009). This foldbelt was
not the focus of the initial exploration program,
although it remains an interesting opportunity for the
future. Instead a large basement high that was clearly
apparent in the center of the basin (Sapiie et al.,
2010) provided the target for the Elang-1 exploration
well.
The size and location of the Elang structural closure
was not a concern and the new well information (i.e.
check shot velocities) will only serve to improve the
depth structural picture going forward. The major
uncertainties were in the make-up of the sedimentary
section below the Pliocene unconformity. What type
of reservoir and source rock facies would be
encountered, if any? Also, the composition and
crustal affinity of the basement was unknown. There
had been much debate in the literature on whether the
basin was underlain by continental, transitional or
oceanic crust and the differing heat flow scenarios
offered by each hypotheses (Dow and Hartono, 1982;
McAdoo and Haebig, 1999; Decker et al., 2009).
Such questions are typical of frontier basin
exploration, and the answers can only be known by
drilling. As it turns out, the Elang-1well did not
encounter high quality reservoir rocks in the target
interval. The lack of thermogenic hydrocarbons also
threw in to question the presence of good quality
source rocks, adequate heat flow, migration
pathways and timing of events. Cendrawasih Bay
covers a vast area of over 30,000 sqkm, and other
play types in the basin offer alternative elements to
an effective petroleum system.
Reconciliation of another key piece of pre-drill
information is required. A very positive oil seep was
identified on the flanks of the basin from seafloor
geochemical analysis (Noble et al., 2009). Pre-drill
basin modeling indicated that oil migration would
have occurred from a structural low in the southeast
sector of Cendrawasih Bay (see Sapiie et al., 2010
for basin structure map). This migration scenario
resulted in flow vectors that pass through the Elang
well location, which was not borne out by drilling
results. Hence another migration scenario must exist
for the oil seep, which adds to the allure of future
exploration activity. Furthermore, the sea floor
geochemistry identified large amounts biogenic gas
seepage. This is encouraging for biogenic gas plays
which are known to occur in North Papuan basins
(Satyana et al., 2007).
CONCLUSIONS
Exploration activities were conducted in two frontier
deepwater basins of Eastern Indonesia; namely, the
Kofiau Basin and Cendrawasih Bay (Waipoga)
Basin, located respectively on the northwestern and
eastern margins of the Bird’s Head of West Papua.
The prospectivity of the two areas was initially
defined by Joint Studies supported by MIGAS and
Indonesian universities. The Joint Studies were
followed by PSC operations under the supervision of
SKK MIGAS, which led to the drilling of two
exploration wells in Kofiau, and one exploration well
in Cendrawasih Bay. These wells represented the
first deepwater drilling operations in each respective
basin. In the Kofiau basin, a thick Pliocene section
was targeted in structural and stratigraphic trapping
configurations with seismic amplitude support. The
two wells (Ajek-1 and Elit-1) encountered gas pay in
good quality Late Pliocene shallow marine sands,
although the net pay thickness was below
commercial threshold. In Cendrawasih Bay, a large
four way anticlinal closure in the basin center was
targeted, with pre-drill prognosis of a carbonate
reservoir facies overlying a fluvio-deltaic section.
The well (Elang-1) encountered a massive micritic
limestone of Miocene to Oligocene age which was
tight, with no hydrocarbon indications during
drilling.
Reconciliation of pre-drill and post-drill results in
Kofiau showed that reservoir quality sands in the
Pliocene section were correctly predicted. Additional
work is required to locate areas where the sands have
thickened in suitable trapping configurations to offer
attractive drilling targets. Furthermore, the
widespread occurrence of crude oil seepage on the
seafloor holds promise that an oil play exists below
the section tested by the two wells. In Cendrawasih
Bay, the absence of high quality reservoir rocks and
lack of thermogenic hydrocarbons indicate that key
elements of the petroleum system are missing at this
well location. However, an unquestionable oil seep
has been identified previously on the sea floor, as
well as abundant seepage of gas derived mainly from
biogenic sources. Cendrawasih Bay covers a vast
area, and other play types in the basin offer
alternative opportunities to discovering a new
hydrocarbon province.
ACKNOWLEDGMENTS
The authors wish to thank their colleagues, past and
present, for their contributions to the technical work
described in this article. The exploration programs
were conducted when Black Gold Energy, and
subsequently Niko Resources Limited, operated the
two study areas. Both companies and their
managements demonstrated great creativity,
commitment and passion towards frontier basin
exploration in Indonesia. The authors also
acknowledge the contributions of various joint
venture partners who participated in the two study
areas. MIGAS and SKK MIGAS are gratefully
acknowledged for their support of the project and
their permission to publish this historical
information.
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Figure 1 - Kofiau and Cendrawasih Bay Location Map and Tectonic Elements (modified after Decker et al., 2009)
Figure 2 - Kofiau and Salawati Basins Generalized Stratigraphy
Figure 3 - Seismic Transect illustrating Play Concepts in the Kofiau Basin (modified after Decker et al., 2009)
Figure 4 - North Irian Basin Generalized Stratigraphy (modified after McAdoo and Haebig, 1999)
Figure 5 - Seismic Transects illustrating the Play Concepts in Cendrawasih Bay (modified after Decker et al., 2009; Sapiie et al., 2010). See Decker et al., 2009
for stratigraphic definitions.
Figure 6 - Seismic Transect showing Ajek-1 and Elit-1 wells in Kofiau Basin. MPU = Mid Pliocene Unconformity
Figure 7 - Gas isotope (delta C13 methane) versus depth plot for Kofiau Basin wells
Figure 8 - Seismic Transect showing Elang-1 well in Cendrawasih Bay
Figure 9 - Gas isotope (delta C13 methane) versus depth plot for Cendrawasih Bay well
... A magmatic arc complex and forearc basin formed along the convergent margin between the Caroline-Pacific Plate and Indo-Australian Plate, likely during Palaeocene. Late Cretaceous to Early Tertiary collision occurred between the magmatic arc complex and Indo-Australian Continent, followed by suture of the arc in the Late Miocene (McAdoo & Haebig, 1999;Noble et al., 2016). The east-west trending mountain ranges of North Papua, New Guinea and Yapen Island reflect this collision. ...
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