The Relationship Between Recovery Efficiency and Depositional
Setting in a Deltaic Plain Environment.
Robert C. Shoup
ABSTRACT
A Full Field Review was conducted for a
structurally and stratigraphically complex field
offshore Sarawak. The East portion of the field
is a relatively simple, west-plunging flowerstructure fold. The West portion of the field
consists of a series of normal conjugate faults
that formed in response to tensional bending
over a deep-seated normal basement fault.
These
faults
result
in
the
severe
compartmentalization of the western portion of
the field.
There are over 20 separate reservoirs in the
field, comprising both channel sands and
incised valley fill sequences that were deposited
by a generally westward flowing river system.
The eastern portion of the field was situated in
the upper deltaic plain where deposition was
from a fluvial environment, whereas the
depositional setting for the western portion of
the field was the lower deltaic plain estuarine
setting.
the field, the same reservoir systems exhibit
virtually no aquifer support and low recovery
efficiencies. This paper focuses on the causes of
that observed difference.
The Temana Field is situated in the south
central region of the Balingian Province of the
Sarawak Basin. It is located offshore Sarawak
35 km west of Bintulu in 96’ (30m) of water
(Figure 1). Structural development of the
Sarawak Basin initiated during the Cretaceous
with subduction and accretionary folding.
Eocene aged carbonates were subsequently
deposited on paleo-Cretaceous highs and
accretionary folds. Clastic deposition followed
as sediments shed off of the Rajang orogenic
belt south and east of Temana Field prograded
into the Sarawak Basin during the Oligocene
and Miocene.
Production from the fluvial reservoirs in the
eastern portion of the field exhibit little to no
aquifer support and recovery efficiencies range
from 20 to 35%. Production from the estuarine
reservoirs in the western portion of the field
have significant aquifer support, and recovery
efficiencies range from 35 to 50%.
INTRODUCTION
A full-field review was conducted for the
Temana Field located offshore Sarawak. There
are over one hundred separate reservoir
compartments in the field. In the course of this
study, it was observed that fluvial-dominated
reservoirs in the western portion of the field
have strong aquifer support and high recovery
efficiencies, whereas in the eastern portion of
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Figure 1: Balingian Basin Geologic Setting
(modified from Modan and Abolins, 1999)
…………………………………………….
Structural Overview
The Temana field encompasses two structural
regimes, an extensional regime comprising
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Temana West and a wrench regime comprising
Temana East and Central (Figure 2). Temana
West consists of a series of normal conjugate
faults that formed in response to both tensional
bending over deep-seated down-to-the-west
normal faults that delineate the edge of the
Balingian Sub-Basin and late stage uplift and
thrust faulting believed to be associated with
Mid to Late Miocene reactivation of the West
Balingian wrench fault.
The Temana East and Central structure is a
reverse fault bounded, elongated east-west
trending, west-plunging anticline formed as a
high-angle flower-structure fold associated with
the right-lateral West Balingian wrench fault
(Figure 1). The south-bounding reverse fault is
believed to have initially formed as
syndepositional growth faults that was
reactivated with left-lateral slip during the Mid
to Late Miocene reactivation of the West
Balingian wrench fault. Westward plunge of the
Temana East anticline sets up the Temana
Central Field.
Figure 2: I60 Depth Structure Map
Stratigraphic Overview
Sediments in the southern portion of the
Balingian Province consist of siliclastic
sediments of Cycles I to VIII (Oligocene to
Recent) overlying the Rajang Group (Figure 3),
a tightly folded Late Cretaceous to Late Eocene
flysch succession (Madon and Abolins, 1999).
The provenance for these siliciclastic sediments
was the Rajang Orogenic Belt which trends into
onshore Sarawak between Bintulu and Kuching
(Madon, 1999).
Figure 3: Generalized Balingian Basin
Stratigraphy (from Modan and Abolins, 1999)
On the western margin of the Balingian
Province, the Luconia deltaic complex
prograded eastward off of the Penian High,
which is separated from the Balingian Province
by the West Balingian Line, a right-lateral
wrench fault system (Figure 1). The Temana
Field reservoirs were deposited by the TatauKemana deltaic complex. This deltaic complex
is situated along the southeastern margin of the
Balingian Province, and prograded northnorthwestward into the Balingian Basin from
Sarawak (Figure 1).
Modern Depositional Environment
Analogs
The evaluation of the conventional cores
indicates that there were both deltaic and delta
plain/mangrove swamp sediments, which
include coals, meandering channels and incised
valley channel systems, deposited at Temana.
The recognition of these depositional facies in
the remaining well control was facilitated by
using modern depositional analogs. The use of
modern depositional analogs provided a better
understanding of facies juxtaposition, stacking
patterns, and expected thicknesses.
Previous workers had placed the depositional
environment in a generalized delta to delta plain
setting, without differentiating between
transgressive or regressive phases. The
sequence stratigraphic analysis, along with the
core evaluations, suggests a principally deltaic
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environment for the J and K sands, and a more
fluvial origin for the H and I sands.
Furthermore, there is core evidence that the
fluvial system was tidally influenced,
suggesting an estuarine to coastal mangrove
swamp environment for the H and I sands.
Deltas
Studies of modern deltas have shown that there
are three basic geomorphic styles of deltas,
River Dominated, Wave Dominated, and Tidal
Dominated (Wright and Coleman, 1973;
Coleman and Wright, 1975). The present day
Baram Delta is a classic wave-dominated delta.
Since any delta forming in the Bintulu region
would be subject to the same wave regime as
the Baram, it is safe to assume that the delta
there was also wave-dominated.
The basal section of a prograding delta is
marine shale overlain by outer fringe prodelta
shale with occasional interbeds of siltstone and
thin-bedded sandstones (Figure 4). This in turn
is overlain by interbedded sandstone, siltstone
and shale of the inner fringe (LeBlanc,
unpublished Shell Training Manual).
Figure 5: Transgressive – Regressive Cycle in
a Deltaic Sequence
Mangrove Swamp
Mangrove swamps are generally found in
tropical to sub-tropical coastal environments.
They typically consist of a series of
anastamosing
waterways
separated
by
mangrove covered islands (Figure 6). There are
two types of waterways within the swamp,
tidally influenced estuarine and meandering
fluvial channels, which may also exhibit tidal
influence.
Figure 6: Facies Juxtaposition and Stacking
Patterns in Mangrove Swamp Environments
Figure 4: Facies juxtaposition and Stacking
Patterns in Deltaic Environments
The inner fringe grades upward to the
shoreface, which is comprised of thick bedded
massive mouth-bar sandstones with thin
interbedded shales. The sequence may be
capped by distributary channel sands and delta
plain mudstones (Figure 4), although in wave
dominated deltas, wave processes typically
redistribute this facies into the shoreface.
During periods of sea-level high-stand, the delta
is reworked to form a coastal barrier island
system (Figure 5).
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Meandering Channels
Fluvial channels in mangrove swamp
environments are typically meandering
channels; however, they tend to be less sinuous
than meandering rivers in other environments
due to the effects of the mangroves. The width
of these channels can vary from several dozen
to several hundred feet, although the overall
width of the meander belt within which the
channel meanders can be several miles
wide. The depth of the channels will range
from a few feet up to about 50 feet.
Mudstones are the most prevalent rock type
within the mangrove swamp environment.
Coals are also prevalent, but patchy in their
overall distribution within the swamp
(Figure 6). Point bar deposits associated
3
with the meandering channel are the
predominant reservoir facies (Figure 7).
During periods of flooding, overbank
deposits consisting of laminated sands and
shales are deposited along the channel
margins and within the estuarine
waterways. These laminated sections are
often characterized by both low resistivity
and low gamma ray contrast in well logs,
making them difficult to recognize.
Figure 8: Facies Juxtaposition and Stacking
Patterns in an Incised Valley Environment
I60 Reservoir
The I60 and underlying I65 reservoirs were
deposited as a series of incised valley fill
sequences (Figure 9). The I60 Incised Valley
sequence is observed in both the more fluviallydominated central and eastern portions of the
field as well as the more estuarine dominated
western portion of the field (Figure 10). Core
from this sequence in the TE 26 well suggests a
tidal influence, confirming that the western
portion of the field was situated in an estuarine
setting.
Figure 7: Facies Juxtaposition and Stacking
Patterns in Meandering Channel Environments
Incised Valleys
With the exception of major river systems,
the majority of rivers in the world today
have channels less than 50’; therefore,
channel deposits thicker than 50 feet are
most likely associated with incised valley
sequences. The facies distribution of an
incised valley sequence is the same as that
of a meandering channel sequence with the
exception that point bar deposition is
confined to within the incised valley until
such time as the incised valley has been
back-filled (Figure 8). In the highly
estuarine environment of a mangrove
swamp, the incised valley system has a
significant overbank component associated
with it (Figure 8) due to the numerous
flooding events that are common in the
tropical latitudes.
Figure 9: I60 – I65 Depositional Environments
Figure 10: I60 – I67 Sand Percent Map showing
core location
Fault Block 10/11
Overview
Fault Block 10/11 is the principal producing
block in western portion of the field; having
produced over 10.7 MMSTB. There are eight
penetrations in this block (Figure 11) of which
all but two are completed in the interval.
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I60 – I65 Water Movement
All three sands have exhibited water movement
through time. In the I40 sand, the TE 26 well
started producing significant water in 1981 and
the TE 25 well in 1984. In the I60 sand, the
water moved through the TE 47 well in 1989
and the TE 26 well in 1989. And in the I65
sand, the TE 49 well saw a significant increase
in water production in 1991.
Figure 11: I60 - I65 Penetrations, Fault Block
10/11
The initial correlations for this fault block were
that the two thick sands observed were the I60
and I65 sands (Figure 12). Subsequent to that
interpretation, the TE 41st was drilled and
found a different oil-water contact than that
previously observed. To account for that
difference, the original interpreters added a
fault. However, that fault can not be observed
on seismic. An alternative interpretation is that
the observed sands represent 3 ‘shingled’
channels. With this interpretation, the top sand
correlates to the I40, the middle sand to I60 and
the basal sand as I65 (Figure 13).
I60 – I65 Gas Cap
No gas cap has been observed nor has there
been a significant increase in gas production.
I60 – I65 Volumetrics
Net pay maps were constructed for the I40 sand
(Figure 14) and for the I60 – I65 sands (Figure
15). The STOIIP for the combined sands ranges
from 16.2 to 29.6 MMSTB, with a base case
volume of 21.4 MMSTB. The Estimated
Ultimate Recovery for the block ranges from 11
to 13 MMSTB assuming a recovery factor of 45
to 55 percent, which is comparable to that
derived from material balance and decline
curve analysis.
Figure 12: Geologic Cross-section, Fault Block
10/11, original Interpretation
Figure 14: I40 Net Pay, Fault Block 10/11
Figure 13: Geologic Cross-section, Fault Block
10/11, revised Interpretation
I60 – I65 Free Water Level
The oil-water contact for the I60 sand is
observed in the TE31st1 well at 3605 feet
TVDss. The oil-water contact for the I65 sand
is observed in the TE31st1 well at 3784 feet
TVDss.
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Figure 169: I60 – 65 Penetrations, Fault Block
54/99
Figure 15: I60 – I65 Net Pay, Fault Block 10/11
Fault Block 54/99
Overview
Fault Block 54/99 is the fault block that
comprises the central portion of the Temana
Field. This is one of the principal producing
blocks of the field, having produced just over
20 MMSTB. There are eighteen penetrations in
the block, ten of which are completed in the I60
(Figure 16).
The I60 Incised Valley Sequence trends
northeast to southwest, and is seen in some
wells as well developed, and other wells as
laminated, thin , or absent all together (Figure
17). Several wells encounter a thin channel
sand below the I60 that has been correlated as
I62. These thin channels pre-dated the
unconformity that resulted in the formation of
the I60 Incised Valley.
The I65 Incised Valley Sequence is observed
only in the TE 72 well (Figure 17). Based on
other observations of the I65 sand in the
Temana Saddle area, and on seismic amplitudes
(Figure 18) it is believed that the I65 Incised
Valley Sequence trends from southeast to
northwest across the Temana Saddle (Figure
194).
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Figure 17: Geologic Cross-section, Fault Block
54/99
Figure 18: I60-I65 Seismic Amplitude, Fault
Block 54/99
I60 – I65 Water Level
The oil-water contact is not observed in this
compartment. RFT analysis predicts a free
water level at 3400 feet, which is coincident
with the observed downdip termination of the
seismic amplitude (Drilling in 2006 has
confirmed that the water-level is at 3402 feet
TVDss).
I60 – I65 Water Movement
Four wells have had associated water
production, the TE54st, TE56st, TE 70
(horizontal) and TE 71st. The TE54st and
TE56st produced water from the I62 sand as
6
opposed to the I60 sand. The TE70 well had in
excess of 1000 bbls of losses while drilling and
the associated water production has not yet
exceeded that number. The TE71st crosses a
small fault on the northern flank of the field.
The water production in that well is intermittent
and appears to be associated with water moving
into the well bore along the fault plane.
It is therefore concluded that none of the
observed water production is associated with
movement of the I60 water level.
I60 – I65 Gas Cap
There is no evidence for an original gas cap.
Shortly after initial production, the reservoir
pressure dropped below the bubble-point and a
secondary gas cap developed. The gas cap has
expanded as far downdip as the TE 64 well
(Figure 19). A downdip secondary gas cap has
also developed in the saddle structure at TE72.
This subsidiary closed high is filled to the
structural spill point.
Figure 19: Secondary Gas Cap Development,
I60 Fault Block 54/99
I60 Volumetrics
The net pay maps were contoured using an
Incised Valley Fill model (Figure 20). The
accumulation is trapped by the Incised Valley
Margin to the north and the south.
Deterministic assessment of the STOIIP based
on the net pay maps results in a range of 62.7 to
112.1 MMSTB, with a base case volume of
87.6 MMSTB.
Figure 19: I60 Net Pay, Fault Block 54-99
CONCLUSION
Fault Block 10/11 is situated in the western
portion of the field which, at I60 time, was
characterized by an estuarine setting where
extensive laminated sandstones were deposited
in an overbank setting. These laminated
sandstones are connected to the channel
sandstones reservoirs and provide aquifer
support. As a result, recovery efficiencies for
Fault Block 10/11 approach 50%.
Fault Block 54/99 is situated
portion of the field which, at
inland of the estuarine setting.
are no connected overbank
therefore, no aquifer support,
recovery efficiency of 30%.
in the eastern
I60 time, was
As such, there
deposits and
resulting in a
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