PROCEEDINGS INDONESIAN PETROLEUM ASSOCIATION Eighteenth Annual Convention, October 1989
THE HYDROCARBON POTENTIAL OF THE LOWER TANJUNG FORMATION, BARITO BASIN, S.E. KALIMANTAN
Indra Kusuma * Thomas Darin **
A B S T R A C T Early exploration efforts in the Barito Basin focused
on the large surface defined thrust structures in the northern areas. Despite the large initial discoveries in the Lower Tanjung Formation of the Tanjung Oil Field in 1939, no sustained exploration program has focused on this known prolific sedimentary section, and the poor understanding of its stratigraphy has produced only limited successes since.
Recent exploration efforts have defined a period of early Tertiary rifting giving rise to a series of northwest to southeast trending horsts and grabens across the basin. These early Tertiary structural elements have been over- printed by a Neogene compressional regime which con- tinues to the present day. This more recent compression has produced a left-lateral reactivation of the earlier normal faults, giving rise to the recent structural confi- guration of the basin.
Major thickness and facies changes with four distinct stages of deposition can be recognized and correlated across the basin in the Tanjung Formation. These varia- tions result primarily from the topography produced by the early Tertiary rifting.
The terrestrial coals and organically rich shales of the Lower Tanjung Formation are prolific hydrocarbon source rocks, and have produced the oil emplaced in the Tanjung Field. These source facies are at optimum maturity IeveIs over large areas of the basin.
At least five of these early Tertiary rifts have been identified. In terms of migration and entrapment, each must be considered a separate self-contained basinal depocenter. Only the Tanjung Field graben, with over 600 MMBOOIP, has been adequately tested.
The Barito Basin is located along the south-eastern edge of the continental Sunda Shield. It is separated from the Asem-Asem and Pasir Basins to the east by the recent- ly uplifted Meratus Mountains. To the north it is dis- tinguished from the Kutei basin by the Adang Fault/ Flexure system or Barito-Kutei Cross High (Fig. 1). Within its internal framework, the Barito Basin contains the present day NE-SW trending Barito Foredeep, which is flanked to the west by the Barito Platform or Shelf and to the east by the Meratus Mountains. The Buntok Basin is situated 60 km north-west of the Barito Foredeep, and is an extension of the main basin which is now separated from it by the south-westerly plunging Kesale- Sihung High.
Early Tertiary tensile stress produced a rifted series of NW-SE horst and graben structures. The exact age of this rifting is not known, but the Late Cretaceous age of the underlying basement and Middle Eocene age of overlying sediments places it within the Paleocene to Early Eocene (Fig. 2). While the bounding normal faults of these rifts extended longitudinally for more than 50 km, their vertical expression was probably no more than 500- 1000 meters.
The Lower Tanjung Formation (Stages 1 to 3) was deposited in these rifts as a transgressive sequence of alluvial facies in the lower part, to shallow marine de- posits in the uppermost part. The Upper Tanjung marine shales and mark (or Stage 4) were deposited across most of the present day basin as this transgression eventually submerged the topographic remnants of the horsts and grabens. Relatively stable marine conditions with numerous minor cyclic eustatic fluctuations prevailed throughout Upper Tanjung times until a major regressive event in the Middle Oligocene exposed most of the basin for a prolonged period.
Following this erosional phase the shallow marine
Carbonate deposition continued into the Early Miocene, but was increasingly interrupted by the influx of fine
BASINAL GEOLOGIC OVERVIEW
formation, a brief discussion of the Tertiary basin evo- lution is presented here to place it in the proper context.
Although the focus of this paper is the Lower Tanjung Berai carbonates were deposited in the Late Oligocene.
PERTAMINA BKKA ** Trend Energy Kalirnantan Ltd.
grained clastics which may have prevented any large scale biohermal build-ups. Carbonate development ceased in the Early Miocene with the beginning of significant
prodeltaic clastic input from the west. Miocene deposition was dominated by an easterly prograding regressive deltaic sequence.
This deltaic deposition was punctuated by a number of abrupt regressive events, and can regionally be divided into five stages comprising the Upper and Lower Warukin Formations. The Lower Warukin grades from the pro- deltaic Berai Marl at the base through delta front to lower delta plain facies at the top.
It is separated from the Upper Warukin by a sharp break in formation water salinities and an abrupt change to upper delta plain facies. Compressional wrench forces were initiated in the Late Miocene with t.he emergence of the Meratus Mountains to the east, the Adang Flexure to the north, and rapid loading and subsidence across the present depocenter.
The Dahor Formation was deposited in the rapidly subsiding depocenter as deltaics from the north and west inter-fingered with thick clastic wedges being shed off the mountains to the east. This depositional regime continues to the present day, with the Dahor thickness exceeding 3000 meters near the mountain front.
EXPLORATION HISTORY
The first geological reconnaissance of the Barito Basin was conducted in 1854. In the late 19th century, B.P.M. (the forerunner of Royal Dutch Shell), conducted the first systematic exploration in the Barito Basin. Small amounts of oil were recovered from shallow boreholes around seeps on the Warukin surface structures, but none were commercial. B.P.M. began an extensive reconnaissance of the basin in the 1930’s which included detailed surface mapping, surface pit excavation, shallow hand auger drilling, and gravimetric surveying (Fig. 3).
Despite the occurrence of numerous seeps and surface structures in the Tanjung Raya, B.P.M. initially focused its efforts on the western parts of the basin where a number of gravity anomalies had been recognized, but only one out of over forty wells tested a small amount of gas. In 1937, NKPM (the forerunner of STANVAC) also drilled a number of shallow wells in the western area around the Kahajan River without encountering any hydrocarbons.
B.P.M shifted its exploration focus back to the surface structures in the Tanjung Raya area in the late 1930’s with an extensive surface geological survey. Numerous shallow stratigraphic holes were drilled across the thrust faulted Tanjung Anticline, a number of which encountered significant oil shows. The deeper Tanjung-1 well was completed as an oiI discovery in Lower Tanjung Formation sandstones in 1938. Minor amounts of Lower Tanjung oil were also found in the Kambitin structure to the west. Tests of the Miocene deltaics in both the
Warukin and Paringin structures to the east failed to encounter any significant hydrocarbon shows. Just prior to the war seven delineation wells were drilled in the Tanjung field, and extensive geological and photogeo- logical surveys of the surface anticlines abutting the Kesale Range were undertaken.
After the war, B.P.M. concentrated on development of the Tanjung field and the construction of a pipeline to Balikpapan, and by 1965 had drilled 89 wells in the field. Four additional wells were drilled in the Kambitin structure from 1959 - 1964 to follow-up the small Kambitin-1 discovery, but these also yielded only small amounts of oil. The Menunggul and Hayup surface structures were also unsuccessfully tested to the Lower Tanjung.
In 1965, an offset to the earlier well in the Warukin structure discovered commercial oil in Miocene Lower Warukin sediments. At the end of 1965, PERTAMINA assumed responsibility for exploration and development in the Barito Basin from SHELL.
PERTAMINA continued with the development of the Tanjung and Warukin fields, and completed the first regionally extensive seismic reflection program (Fig. 4). Further Miocene tests were drilled along the thrusted anticlinal trend of the Warukin field, leading to the discovery of the Tapian Timur Field in 1967. The Lower Tanjung was also tested at the Bonkang structure without encountering any significant hydrocarbons. A test at Dahor Selatan-I, which at the time was believed to be the southern extension of the Tanjung Field structure, was abandoned after an oil blow-out from the Lower Warukin, but an offset well failed to encounter the oil bearing reservoir. By 1972 most of the easily recognized surface structures had been drilled, and PERTAMINA began a detailed seismic program to better define the sub- surface structures. Numerous wells were drilled on these structures with limited success. In many cases the Lower Tanjung Formation was poorly developed and/or largely absent. Tanta-1 drilled a basement high on an apparent southerly extension of the Tanjung Anticline, and although the Lower Tanjung was thin and poorly de- veloped, modest amounts of oil were tested from fractured Oligocene Berai limestone. A shallow Lower Warukin sand in Bongkang-2 (which had targeted the Lower Tanjung) tested a moderate amount of dry gas. Two of the three further tests of the Kambitin structure flowed small quantities of oil. In 1986, Bagok-1 was drilled on the southerly plunging nose of the Kambitin structure, and although the Lower Tanjung sands were poorly developed they tested in excess of lo00 BOPD. The appraisal well Bagok-2 was drilled in an up-dip position 1.5 km to the north, but tested onIy water from these sands. The structural configuration of the Bagok/ Kambitin accumulations provided a strong indication of
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the stratigraphic trapping .component in the Lower Tanjung sands. By 1983, declining production in the Tanjung Field had prompted two separate pilot water- flood projects, but a poor understanding of the complex Lower Tanjung stratigraphy produced disappointing results.
In 1968, CONOCO obtained exploration rights to a large part of the southern basin area and focused their efforts on Berai reef plays. Five wells on the shallow shelf area failed to encounter any significant biohermal build- ups or hydrocarbons. In 1972, CONOCO farmed out to PHILLIPS, who concentrated on Tanjung-type moun- tain front thrust structures. A sub-thrust structural test (Martapura-lx) encountered only minor oil shows in the poorly developed Lower Tanjung sands, and PHILLIPS PSC relinquished the acreage.
PEXAMIN acquired exploration rights to an area just west of the Kambitin wells in 1970. Two wells tested subtle anticlinal features, but development of the Lower Tanjung was poor and no hydrocarbon indications were encountered.
In 1981, AMOCO was awarded Block “C” encom- passing the western shelfal area of the basin where CONOCO had worked earlier. Their 24-fold seismic coverage yielded far better results than CONOCO’s earlier 6-fold coverage. Their first well targeted the Lower Tanjung across a seismically defined basement high, but the target sands were largely absent and the well was sidetracked to test an interpreted Berai reefal build-up nearby. Some limited posr-Berai biohermal carbonates were encountered, but tested only water, and AMOCO relinquished the block in 1984.
Also in 1981, TREND was awaided Block “l3” covering the southern and central portions of the basin. TREND initially focused on the mountain front edge (where numerous oil seeps had been found) with 1196 km of 24-fold seismic coverage. The first well, Miyawa-I, tested the Lower Tanjung in a sub-thrusted fault trap, and encountered over 600’ of good oil shows. However, the well had entered a complex fault zone and tests of this interval failed to recover any fluids. A second well, Birik-1 was drilled to test a seismically defined deep sub- thrust roll-over in the Miocene Warukin formation. Numerous oil shows were encountered, but reservoir quality was again poor. The results also showed that the interpreted structure was probably a velocity artifact of the thick overlying Dahor conglomerates. TREND then focused on the central basin area with the acquisition of a further 1687 km of seismic and 1900 km of gravity. Bangkau-1 tested a subtle fault closed roll-over in the Warukin Formation and encountered numerous good oil shows in poor quality reservoir sands. The well was suspended in severe over-pressures with large amounts of free oil invading the borehole from thin silt laminae
in the Lower Warukin pro-deltaics. Semuda-1 was drilled to test a seismically defined basement high, and en- countered only a thin veneer of shaley Lower Tanjung sands with good live oil shows before penetrating Paleocene andesitic volcanics where the well was sus- pended.
TREND then entered into a 9 month joint technical study with PERTAMINA utilizing their combined data- bases and further detailed field work in an attempt to better define the development and distribution of the Lower Tanjung Formation. The concept of Early Tertiary rifting led to the further acquisition of 300 km of seismic by TREND in 1988.
STRUCTURE OF THE BARITO BASIN The Barito Basin lies on the south-eastern edge of the
continental Sundaland plate fragment. Based on detailed surface mapping in the Southern Meratus Mountains, Sikurnbang (1 986) developed the geological model illustrated in Figure 5 for the Pre-Tertiary evolution of the area. His work provides the framework for a possible interpretation of the complex tectonic evolution of this area since the Early Cretaceous. Based on fossil evidence and radiometric dating, he postulated a mid-Cretaceous period N-S subduction and volcanic arc formation along the eastern margins of Sundaland. This was followed by a Late Cretaceous arc-continent collision with oblique subduction/obduction. This left-lateral wrenching along the Meratus suture produced a NW-SE Late Cretaceous pull-apart basin bounded by syn-depositional left-lateral wrench faults (Fig. 9). By the Early Eocene a divergent \+ rench stress regime dominated Southeast Kalimantan, possibly as the result of changes in the relative motion of the Australian plate. This tensional stress gave rise to a series of NW-SE trending rift basins followed by a prolonged period of subsidence and sedimentation ex- tending into the Late Miocene. Since then, the westward strike-slip propagation of the Pacific plate along the Sorong and Tarera Faults has re-activated the old Meratus convergence zone.
Large variations in the pre-Tertiary basement topo- graphy and rapid lateral variations in the Lower Tanjung stratigraphy had been suggested by gravity data and earlier well correlations (Fig. 12). The presence of NW- SE aligned horsts and grabens was clearly demonstrated with the integration of photogeology, radar imagery, field data, well data, gravity, and seismic mapping. The more recent detailed field napping along the mountain front (Fig. 13) revealed thickness and facies variations very similar to those observed in distant well correlations. The seismic data also clearly showed the basement fault block structures (Fig. 6) and the pervasive NW-SE trend of normal faults bounding these fault blocks. Although it is difficult to correlate deep events across the current depocenter, these normal faults can be tied to those
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revealed by photo-geolqgy and radar imagery interpre- tation in the mountain from outcrops.
Bouguer gravity data and subsequent gravity modeling also showed large gravity minimum trends corresponding to the seismically interpreted grabens. The alignment of the horsts and grabens is best revealed by a time isopach map constructed from an intra-Tanjung reflector to basement (Fig. 7).
Following the relatively rapid graben infilling, rates of sedimentation from the Late Eocene to the Middle Miocene were reduced, but increased significantly with the Middle-Late Miocene advance of the Warukin deltaics. The effect of the basement topography on deposition decreased with time, yet differential compac- tion within the grabens continued to influence depo- sitional patterns. Even today, away from the rapid deposition near the mountain front, subtle geomorphic features across the large low lying southern swampy areas of the basin reflect the underlying basement topography.
Beginning in the Mid-Late Miocene and extending to the present day a major tectonic event began to affect south-eastern Kalimantan. The large scale regional mechanics of this movement are not perfectly understood, byi h e result has been a general north-south left-lateral convergent wrench reactivation of the Meratus suture zone. Further north the influence of the WNW-ESE left- lateral motion along the Adang Fault adds a third regional stress regime, and considerably complicates t!le structural configuration in that area. The Adang fault (or flexure, as it is poorly defined at the surface) is probably a manifestation of the westward movement of the Pacific plate propagated along the Sorong and Tarera Faults. It may also reflect a re-activated southern bounding normal fault of a large Paleogene graben which underlies the Kutei Basin to the north. This is evidenced by much deeper marine Tanjung sedimentation to the north, and the occurrence of Quaternary volcanics in the Teweh area.
The idealized diagrams in Figures 8 and 9 best illus- trate the model for structural development of the area. Oblique convergent wrenching produced the primary thrusts and folds observed along the mountain front which are characteristic of a welt. Numerous antithetic WSW-ENE right-lateral wrench faults are associated with the primary wrenching, and are will defined from the field, photo-geology and radar imagery. Other subsidiary structural features along the primary wrench include pinnate tensional and shear fractures, and second order left-lateral wrenches. The principal horizontal com- pressional stress is in a NW-SE direction, and the NW- SE Early Tertiary normal faults represent pre-existing lines of weakness which were subsequently re-activated as synthetic left-lateral wrenches.
These synthetic faults are observed in outcrop in the Meratus Mountains and Kesale-Sihung High area, as well as observed seismically. Older Cretaceous structural elements bordering the Manunggul Basin have also undergone re-activation as NE-SW left-lateral wrenches. In the Kesale-Sihung uplift, these faults grade laterally into first order thrust structures as their orientation changes to N-S and horizontal compression is re-oriented
The arcuate form of these thrusted anticlines, and their oblique orientation relative to the main mountain zone of deformation, are also characteristic of the overall convergent wrench stress regime. The thrusted features display a distinct en echelon arrangement which de- teriorates away from the major Meratus Mountain Front zone of deformation. The structural cross-section in Figure 10 illustrates the en echelon (or imbricate) thrust faulted structures near the mountain front which give way northwest to thrust faulted anticlines and eventually to gentle unfaulted anticlines. A true en echelon pattern seems to require wrenching, or at least some component of wrenching, and thus may be unique to the wrench assemblage style (Lowell, 1985). The tectonic wrench model also accounts for the almost complete lack of recent compressive structural influence in the southern portions of the basin where the model predicts a localized tensile stress regime. However, seismic data indicate areas in the south along the current depocenter with anomalous thick Upper Warukin sections. This may reflect the tensile reactivation of underlying older Paleogene normal faults in this area, although seismic quality at these deep basement levels is admittedly poor.
In summary, the Tertiary structural development of the Barito Basin is the result of two separate stress regimes: a Paleogene period of divergent wrenching and rifting followed by a Neogene period of convergent wrenching and uplift. The consequence of this stress rerersal has been a re-activation of the older structural elements during the more recent compression, rather than the development of entirely new structures. The form of the Early Tertiary Barito Basin is therefore quite different from the present-day basin.
to E-W.
STRATIGRAPHY OF THE LOWER TANJUNG FORMATION
The Lower Tanjung Formation sediments represent a transgressive sequence of rift infill sediment (Fig. 11). The source of these clastics was the exposed Sunda Shield to the west and the intervening horst highs. The deposi- tion and thickness of these sediments was governed by the topographic relief of the Paleocene horsts and grabens. Regional cross sections (Fig. 12) indicate four distinct stages of deposition with unique lithostratigraphic characteristics.
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The gross properties of these Stages can also be readily identified in the Field (Fig. 13). The lowermost three Stages comprise the Lower Tanjung Formation, and primarily represent localized non-marine rift infilling sediments. The uppermost Stage 4 (also termed the Upper Tanjung Formation) represents regional marine deposition. The 100 Tanjung Field wells provide additional detail on local variations.
The graben depositional setting provides a fair degree of stratigraphic complexity and rapid lateral ’facies variations. Numerous faults have been invoked in the past to explain the wide variability in observed oil-water contacts in the Tanjung Field.Whi1e some of these faults are syn-depositional in nature, most variations within the field are related to stratigraphic changes.
infilling. Three distinct units are recognizable within this stage: a basal unit of continental red-bed facies, an inter- mediate unit of lower fan to lacustrine clastics, and an upper unit of lacustrine or estuarine fine clastics.
The lowermost “red-bed” unit consists of inner to middle alluvial fan conglomerates which are typically poorly sorted and poorly bedded. The basal cong- lomerates contain an abundance of well rounded quartz pebbles to cobbles, with associated silicified rhyolite and volcanic debris. The poorly sorted clay to sand matrix precludes them as potential reservoirs. The radial concave upward profile of these fans can be recognized in the Tanjung Field.
The intermediate Stage 1 unit consists of middle to lower alluvial fan coarse stream flow and stream flood deposits near the graben margins. These grzde into finer and better sorted shallow lacustrine deltaic sands and eventually to prodeltaic muds toward the graben axis. The maximum thickness and lithofacies variations are observed in this unit, and volurnetrically it represents the majority of graben infilling. Two sands, the Z-1015 and Z-950 (Fig. 12), produce from this interval in the Tanjung Field, and the rapid lateral facies variations provide a very strong stratigraphic trapping component. The fair to good reservoir quality of these sands make them attractive exploration targets.
The uppermost part of Stage 1 was deposited in a much lower relief shallow lacustrine or possibly estuarine (although marine indicators are lacking) environment following the initial rapid infilling.
It consists of low energy shales, silts, and sandy silts with numerous thin coals of limited extent. These clastics display distinct fining upward cycles suggesting periodic higher energy conditions followed by periods of fluid stagnation. This unit is fairly uniform in thickness and gross lithologic composition across the grabens away
from the bounding horsts. Continued rifting and block faulting occurred with
decreasing frequency and intensity throughout Stage 1 deposition. This is indicated by field evidence of syn- depositional normal faults, seismically defined post- depositional block faulting, and by the fault compart- ments within the Tanjung Field at this level which only rarely extend into the overlying stages.
Stage 2 A distinct change in sedimentary character occurs at
the Stage 1 and 2 boundary where shallow lacustrine facies give way abruptly to fluvio-deltaics. This dis- cordance probably represents a minor uplift and erosional hiatus which may be related to doming in the final phase of vulcanism associated with the rifting cycle.
This uplift and erosion produced a lower relief topography across the remnant basement highs. As a result, the Stage 2 deltaics were not restricted to the grabens as the Stage 1 sediments had been. Initial de- position occurred as distributary channel sands incised into the underlying unconformity surface. These fining upward sands are coarse, clean, well sorted, and massively bedded, and are a major producer designated as the 2-860 in the Tanjung Field. They comprise a series of stacked, incised channels whose overall NW-SE orientation is well defined from dipmeter data. These sedimentary features provide a fairly strong stratigraphic trapping component in the Tanjung Field. They comprise a series of stacked, to the grabens, but later Stage 2 sediments progressively onlap the remnant horst highs. These later sediments consist of fine-grained shaly distributary and lenticular crevasse splay sands, and organic-rich interdistributary shales and coals which become dominant in response to peneplanation and decreasing relief. Dipmeter data clearly indicate the fan-like crevasse splay nature of the productive but shaly 2-825 sand in the Tanjung Field. The top of Stage 2 deposition is marked by a distinct thick coal section which provides an easily mapable seismic event, and can be regionally correlated from wells to outcrop. The lower Stage 2 fluvio-deltaic sands are a primary exploration focus due to their more regionally consistent reservoir quality. By the end of Stage 2, graben infilling was virtually complete. Most of the intervening horst blocks had been onlapped and clastjc input from them had largely ceased.
Stage 3
Stage 3 deposition marks the first appearance of marine influence in response to the continuing regional subsidence. This interval contains the first datable (Mid- Late Eocene) marine micro-lossils and glauconite. elastic input and grain size rapidly diminish as the last of the remnant horsts are onlapped. The clastic source recedes to the distant west producing a mud-rich/sand-poor low
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energy marine environment and stratigraphic patterns which are regionally correlatable. The underlying basement topography continued to influence deposition through differential compaction in the grabens, resulting in slightly shallower coarser grained facies around the horsts.
A final post-rift igneous event, which was probably associated with the earlier pre-Stage 2 uplift and possible doming, occurred during early Stage 3 deposition. This is evidenced by volcanics described as dolerite (this description relies on cores recovered during early appraisal drilling) at this level in the Tanjung field, and by stratigraphically equivalent andesitic lavas at one outcrop locale and at TD in the Semuda-1 well. The limits of this volcanic body are well defined in the Tanjung Field. Its geometry and the appearance of increased heavy minerals in the overlying sands indicates an extrusive event.
The lower part of the Stage 3 sequence is characterized by nearshore facies. The productive 2-710 sand in the Tanjung Field and at Bagok-1 is composed of a number of thin to locally thick, fine-grained, clean to shaly sands. Dipmeter characteristics, coarsening upward cycles, and the planar cross-stratification observed in outcrop strongly suggest barrier or intertidal bar deposition. These sands become much cleaner and slightly coarser where they onlap the volcanic extrusives (which are up to 35 meters thick) in the Tanjung field, indicating that the lavas provided a shallower locus for sand deposition.
Sand distribution becomes more lenticular and sporadic towards the top of Stage 3 with increasing water depth, but again higher concentrations and improved reservoir qualities are present in the vicinity of the underlying highs. The marginally productive 2-670 shaly sands and silts in the Tanjung Field and Bagok-1 consist of individual discontinuous lenticular bodies deposited as distal bars or pro-deltaic facies. Stage 3 deposition is terminated by the transition to deeper marine conditions above the regional MI log marker.
In general, the stratigraphic disposition of reservoir quality sands within Stage 3 renders them a difficult exploration obiective, but the testing of over 10oO BOPD in Bagok-1 from these sands highlights their prospectivity.
Stage 4
Stage 4 sediments were deposited following a minor depositional hiatus at the MI log marker. Low energy middle sublittoral marine conditions prevailed with sedimentation rates and subsidence in rough equilibrium. This stable basinal configuration persisted well into mid- Oligocene when Stage 4 deposition was terminated by a drastic eustatic sea level fall. Also termed the Upper Tanjung Formation, Stage 4 deposition is characterized by numerous small cyclic eustatic fI uctuations with thin
calcareous coarser grained clastics and detrital coals deposited during the regressive peaks, and marine shales and marls in the intervening transgressions. These small cyclic events can be correlated regionally on modern high- resolution wireline logs. Despite numerous oil shows in this interval and the testing of oil from a thin shaly sand at Bagok-1, poor reservoir quality severely limits its prospectivity.
GEOCHEMISTRY
An exhaustive and integrated geochemical evaluation of the Barito Basin has yielded very positive results in terms of hydrocarbon potential, and has permitted a fairly complete picture of the complex geochemistry of the basin to emerge. Due to the mobile nature of hydro- carbons in the subsurface, the following discussion is necessarily expanded beyond the bounds of the Lower Tanjung Formation.
Heat flow modelling
A heat flow study of the basin was undertaken to gain a better understanding of the large differences in geo- thermal gradients observed in the well data, and to aid in defining the various maturity levels in the basin. Heat flow calculations were performed utilizing specialized software to tie previously measured thermal conductivities (Thamrin, 1987) to sonic logs in order to correct for the considerable effects of compaction throughout the stra- tigraphic column. Reliable formation temperatures were obtained from wireline log and DST data to calibrate the computer calculated thermal conductivity and tem- perature profile models of the wells. The objective of this approach was to minimize the effects of the highly variable thermal conductivities of the overlying sedi- mentary column in order to discern whether the observed geothermal gradient anomalies were related to actual crustal heat flow anomalies.
Geothermal gradients around the Barito Basin are quite variable (Fig.l4), ranging from a low of 1 .OS°F/lOO ft. at Birik-1 to a high of 3.08"F/100ft.at Bagok-I. Due to the low compaction and high percentages of coal in the Warukin and Dahor Formations, geothermal gradients are usually lower where they have been removed by erosion. Gradients generally decrease from the west towards the Meratus Mountains in the east, and this eastwards cooling is due in part to the effect of meteoric flushing of the very permeable Warukin sands exposed in the mountain front (artesian flow was observed in an Upper Warukin sand tested at Bangkau-1) which effec- tively act as a huge radiator.
The large mass of highly corlductive igneous rocks in the mountains also provide a ready conduit for heat propagation. The most interesting thermal feature is the high gradient anomaly in the BagokIKambitin area,
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particularly in relation to the much lower temperatures in the adjacent areas.
The heat flow map (Fig. 14) shows the observed regional geothermal gradients generally reflect the ambient heat flow, and are not simply a function of variable thermal conductivities. The hot spot in the Bagok/Kambitin area remains intact and is all the more puzzling considering that meteoric flushing of some of the Tanjung sands appears to be occurring here via the nearby outcrops to the north, which would presumably have a cooling effect. The early Tertiary heat flows were undoubtably much higher following initial rifting, but it is unlikely that this initial high geothermal flux around the grabens (due to crustal thinning) has persisted to the present day. The more recent structural activity might produce an increased crustal heat flow, but the localized nature of this anomaly seems to preclude a tectonic cause. Most plausibly, the Bagok/Kambitin anomaly probably reflects heat transfer via subsurface fluid movements from deeper and hotter areas to the southeast.
Vitrinite reflectance (Ro) profiles can serve as a type of paleothermometer to qualitatively give an idea of past geothermal gradients. Higher heat flows that persist through time ivould be expected to produce higher Ro gradients. Figure 15 compares all the available well Ro data with the calculated heat flows in an attempt to quantify this relationship. Many of the wells are clustered around the basin average, among them all of the wells in the structurally undisturbed areas of Blocks “B” and “C” supporting the essumption that the thermal regime of the areas away from the Late Miocene tectonism have remained fairly constant through time. From the limited data and the inherent weaknesses of this technique, it is impossible to derive an empirical relationship between Ro gradients and heat flow, but it does serve to highlight the deviations.
The wells located below an admittedly subjective expected “ normal trend” would indicate higher relative Ro gradients than the current low heat flows would warrant, while those above would indicate lower relative Ro gradients than the current high heat flows would suggest.
Bagok-1 shows the largest deviation from the basin average, suggesting that its high heat flow is indeed a relatively recent event. Conversely, the data from wells along the mountain front and in uplifted areas suggest relatively higher heat flows in the past than at present. This recent cooling is easier to explain in light of the uplift and removal of the insulating blanket of Miocene-Recent sediments, and the quenching effect of meteoric flushing through outcrops along the mountain front.
This initial rudimentary understanding of the thermal regime of the basin has assisted in defining the mature source areas for hydrocarbon generation. The identifii-
cation.of the high heat flow anomaly and its likely hydro- thermal cause has important implications for maturation and hydrocarbon migration for the area to the south of Bagok-1.
Maturation
Lopatin’s Time-Temperature Index (TTI) has proven a popular analytical technique for maturity determination because the required input data are simple, easy to obtain, and seismic data can be utilized away from control points where formation tops can be identified. The Lopatin method does underestimate maturity in the later stages of catagenesis, but this does not detract from its use- fulness in identifying the areas within the current oil window. The real catalyst for oil generation in the Barito Basin was the deposition of the Upper Warukin and Dahor Formations which formed a thermal blanket over the basin. As such, the higher rift phase temperatures of the early basin are of minor importance in the TTI cal- culations due to the shallow depths of burial, while the recent Post-Warukin temperatures assume major im- portance. The results of the heat flow modelling provide the required temperature input, and the TTI model can be calibrated to existing well Ro data (Waples, 1985). This calibration procedure shows that the localized recent cooling and warming events, highlighted by the Ro versus heat flow plot, must be built into the TTI model to achieve at match with well Ro data in these areas. Away from these recent thermal anomalies, temperature histories taken as constant through time yield TTI values in agreement with the well Ro data. Building these thermal parameters into the TTI modelling yields a fairly reliable indication of maturity in most wells in the basin. A number of horizons are well defined seismically and can be mapped with confidence, while other levels can be estimated by interpolating thicknesses from surrounding wells for burial history reconstructions. A large number of TTI models were thus constructed where seismic coverage exists using regional geothermal gradients and thermal history evidence obtained from the heat flow study.
Figure 16 shows the TTI maturation map at the top Stage 2 level where thick coals produce a strong seismic reflector. The hydrocarbon deadlines on the maps are derived from empirical work and are expressed at the 80 percent confidence level (Waples, 1985). Heavier hydro- carbons could occur at higher TTI values, but their occurrences would be rather rare.
Due to the dominance of terrestrial kerogen, these deadlines probably extend to slightly higher TTI values, with the bottom of the oil window in the TTI 180 to 200 range. The TTI map at this level reliably shows an area in excess of 2500 km2 which has, or is currently going through the catagenic phase of hydrocarbon generation.
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Large areas exist in the current depocenter where the Lower Tanjung has already exhausted most of its generative potential. The mature areas gradually diminish in areal extent at progressively shallower hoiizons. The top of the oil window extends well into the Lower Warukin Fornation, and over 2500m of mature Warukin is present in the current depocenter areas. Away from the structural and thermal complexities in the north, the top of the oil window is generally subparallel to the regional structural dip, increasing from a high of about 8000 ft. in the Western limits to below 13000ft. in the much cooler mountain front sub-thrust zone.
The TTI models also illustrate the various maturity levels through time. The depocenter model in Fig. 16 shows that at the base Tanjung level, oil generation (TTI 15) began about 20 million years ago during the initial stages of Early Miocene Warukin deposition. Oil ex- pulsion at this level was well under way (TTI 40) by 15 million years ago, predating the Late Miocene Meratus structural elements by a significant length of time.
Source potential
Lower Tanjung Formation TOC analyses from wells and outcrops show wide variations, from a low of under 0.50% to over 70% in Stage 1 and 2 coals. Overall, the organic carbon content is greatest in the deltaics of Stage 2, averaging between S-10% in the organically rich shales.
Sparse data also show similar concentrations in the lacustrine upper Stage 1, indicating excellent source potential for both these intervals. TOC decreases substantially in the marine Stage 3 and 4 sections, but still averages 1.5070, resulting in poor to fair source potential.
The kerogen type of the dr‘ganic carbon determines the likely hydrocarbon products. Figure 17 illustrates the pyrolysis derived hydrocarbon index (HI) versus Tmax plot. The best oil source potential (HI > 200) occurs in the Stage I sediments, with Stages 2 and 3 apparently containing more gas prone Type 111 kerogen. The visual kerogen analyses summarized in Fig. 17, show an almost complete dominance of terrestrial derived Type 111 kerogen.
The macerals are composed primarily of herbaceous organic matter such as resinite, exinite, and cutinite (resins, spores, and leaf cuticles), and are similar to gas prone Type III by elemental cornposition.
However, it has become widely accepted that non- sapropelic (humic) coals can act as oil sources, and that Type I11 kerogen can generate waxy oil, probably from the cuticle and leaf coatings of higher plants. Horsfield (1984) has termed this kerogen Type 111 H. The source extract GC scan from the Lower Tanjung in Fig. 18 shows large peaks clustered around C29, a high odd n-alkane preference in this range, high pristane/phytane ratios,
and a minor resinite hump in the C15 range, which are all indicative of terrestrial kerogens. In fact, terrestrial kerogens of a very similar composition predominate over the full Tertiary sedimentary sequence of the Barito Basin. Even the marine facies contain an abundance of terrestrial kerogen (although it is generally degraded as a result of longer distance transport), indicating the proximity of the ancient shoreline throughout the basin’s history.
It has been shown that the Miocene coals of the nearby Mahakam Delta are related to the oils (Thompson eta!., 1985, Monthioux el al., 1983, and that potentially oil generative coals are common in many areas of Southeast Asia. The various source rock parameters show that the Lower Tanjung coals are typical of waxy oil prone organic matter and are very similar to the Warukin coals, which in turn are similar to those from the Mahakam Delta (Curry, 1987). In order to determine if these coals can in fact generate oil, artificial maturation experiments were conducted on Lower Tanjung and Lower Warukin coal samples. The coal was heated at 325°C for differing periods. The results in the following table show that both the Tanjung and Warukin coals can generate appreciable amount of liquid products. Analyses of these artificially generated oils show that they closely resemble the oils in the basin.
Artificial Maturation Results
Yo coal converted to C15+ liauids
Lower Taniune coal outcror,
3 Days 6 Days
6.7 5.2
Bangkau-I Lower Ii’arukin coal
3 Days 10.3 6 Days 10.7
Quantitatively, these results indicate that these Type IIIH coals will generate approximately 0.02 to 0.04 barrels of oil per cubic meter of sediment per one percent TOC. With an average hydrocarbon/carbon ratio of 0.95, approxi- mately 12 to 15 percent of the organic matter is assumed to be converted to oil before gas generation becomes dominant at a H/C ratio of 0.80. This represents generated oil and does not take into account expulsion or migration efficiencies. Applying these quantities to rough volumetric calculations, p:oduces a figure of 2000- 4000 MMBO generated in the Stage 2 coals alone over the mature areas of the Tanjung Field graben (using a conservative average co21 thickness of 5 meters, mature areal extent of 400 km2, and average TOC of 50%).
115
Factoring in expulsion and migration efficiencies of 10 percent yields a range of 200 to 400 MMBO available for entrapment in the Tanjpng graben from this single coal. These figures do not take into account the varying maturity levels of this coal across the graben to account for oil versus gas generation, but they are in the range of the amount of oil found in the area to date.
Characterization of oils
All the oils recovered from wells and surface seeps display very 'similar attributes. The terrestrial nature of the oils is clearly illustrated by their high wax content, high pristane/phytane ratios, high pristane/nC17 ratios, high resin content shown by anomalous peaks in the C13 to C16 range, and the dominance of C29 isomers in the sterane component of the G U M S data (Fig. 19, peaks 7-9). The oils display a fairly narrow range of low to moderate maturity levels. Subtle variations, such as the depletion of light end alkanes in the C8 to C13 range of the Warukin oils, can be attributed to possible water washing effects in the hydrodynamically active Warukin Formation. Other variations result from biodegradation, varying source maturities, and subtle differences in source organic facies.
0il:Oil and 0il:Source Correlations
The similarity in the organic source facies of the Tanjung and Warukin Formations leads to difficulties in determining the origin of the oils. Differences in the relative distributions of GC measured compounds, as illustrated by the scans and ternary diagram in Figures 18 and 20, may simply be the result of different maturity levels of the source or varying degrees of biodegradation and/or water washing of the oils. GC/MS biomarker distributions (Figs. 19 and 20), which are in some cases independent of maturity and/or biodegradation, likewise show similar distributions with subtle but distinct differences in the oils,
By far the most useful property for differentiating the two groups has been carbon isotope data (Fig. 21), which clearly defines a distinct separation and shows that the Warukin Formation oils are about 2 per mil more depleted in 13C (isotopically lighter) than the Tanjung Formation oils. This difference can not be accounted for solely on the basis of the slightly different maturity levels of the two groups. The combination of GC, G U M S , and carbon isotope data clearly define two separate oil groups within the basin. The separtion of these groups is in most cases coincident with the stratigraphic occurrence of the oils. An exception is the oil recovered from fractured Berai Limestone in the Tanta-1 well which shows a strong affinity with the Warukin Formation oils. Another interesting anomaly is the Bangkau-1 oil recovered from a Berai Marl sand at 10,200 feet within the transition zone
to severe overpressures. This oil is 5 to 7 per mil more negative (isotopically lighter) than the other oils, and is one of the most negative del 13C values published for oil anywhere (Curry, 1987). It is consistently anomalous in most other respects, and emerges as the one exception to the clear groupings of the other oils. As such, this oil may represent the only example of a previously unknown third distinct group.
Problems in correlating the oils with potential sources arise due to the significant differences in the maturity levels of the oils and the source extracts. Since none of the wells penetrated very far into the oil window, no data was available from source intervals with maturity levels comparable to the oils. These differences in concentration between extracts and oils have been observed in the Mahakam Delta fields and are also probably related to maturity (Schoell el al. 1983).
However, enough data does exist to provide for reasonable correlations. The G U M S and carbon isotope distributions (Figs. 20 and 21) show that the best source match for the Warukin group of oils are the Lower Warukin Formation coals in the Bangkau-1. These coals are marginally mature, and along with the Birik-1 coal GC in Figure 18 are the most mature Warukin Formation samples available. The best match for tlhe Tanjung oils are Stage 2 coals from outcrop and from the Tanjung-15 well. These samples are likewise marginally mature, but again are the most mature Lower 'Tanjung samples available. Although this data is not entirely definitive, when taken in the context of the separate stratigraphic distributions of the two oil groups, it demonstrates that the coals and organically rich shales of the Lower Warukin and Lower Tanjung Formations are the primary source facies for oil generation in the basin. At much higher maturity levels other organically leaner facies are probably also significant hydrocarbon sources, as demonstrated by the anomalous Bangkau-1 oil.
EXPLORATION IMPLICATIONS
A number of Early Tertiary grabens have been defined within the Barito Basin. These rifted basins provided the locus for deposition of the highly variable non-marine facies of the Lower Tanjung Formation. The occurrence and quality of suitable Lower Tanjung reservoirs is thus dependent on their overall position within these individual localized basins. From an exploration viewpoint, the locations of these rift basins are quite independent of the current structural configuration of the Barito Basin.
Geochemical analyses have clearly demonstrated major oil source potential within the organically rich facies of the Lower Tanjung Formatio:i, and large areas of thermal maturity dictate large scale hydrocarbon generation and expulsion. Of particular interest is the fact
116
that oil generated within the Lower Tanjung Formation is always observed to be restricted to reservoirs within the Lower Tanjung, even in the presence of large thrust faults as in the Tanjung Raya area. Also significant is the lack of any known oil seepages or occurrences updip on the Barito Shelf to the west of the mature areas or the Tanjung Formation pinch-out edge. These observed features imply that in terms of generation and migration, each rift basin can be considered as a ‘separate self- contained sealed system.
Detailed seismic coverage and extensive surface geological investigations up to 1970 had revealed and tested most or all of the prominent dip closed thrust structures in the basin. The more recent exploration activities have continued to focus only on these structural aspects, and have been largely unsuccessful.
The tests of the northernmost Bonkang and Hayup structures were probably geochemical failures due to the lack of mature source within this graben. The Neogene structures within the Tanjung Graben have proven in excess of 600 MMBOOIP, although outside of the Tanjung Field hydrocarbon occurrences have been irregular. Recent studies show that trapping within these large dip closed structures contains a strong stratigraphic component, as might be expected within the highly variable Lower Tanjung facies. At least three other seismically defined grabens exist to the south of the Tanjung graben at much higher levels of thermal maturity. The Neogene tectonism which gave rise to the prominent structures in the Tanjung Raya area has had little effect on these areas to the south except in the complex thrusted structures along the mountain front.
The concepts which have emerged in recent years provide an exploration framework for exploiting the prolific potential of these untested grabens, and future explo- ration efforts will therefore have to focus on the stra- tigraphy of the Lower Tanjung Formation to define stratigraphic or combined StructuraVstratigraphic trapping mechanisms in order to benefit from these concepts.
ACKNOWLEDGMENTS
The author wishes to thank the managements of PERTAMINA and TREND ENERGY KALIMANTAN LIMITED for permission to publish this paper. Many of the concepts outlined here were developed or refined within the PERTAMINA/TREND Barito Basin joint study, and many thanks are due to the creative efforts of the technical staff of that joint study under the supervision of P.R. Davies (who was instrumental in developing portions of the concepts outlined here), and to N.M. Henry.
REFERENCES
Bishop, W. 1980. Structure, stratigraphy and hydro- carbons offshore Southern Kalimantan, Indonesia. Bulletin of the American Association of Petroleum Geologists 64, 37-58.
Curry, D.J. 1987. Geochemical evaluation of the Barito Basin, onshore Kalimantan, Indonesia. Sun Oil E&P Geochemical Services Group Report No. T071-1-87.
Harding, T.P. 1974. Petroleum traps associated with wrench faults. Bulletin of the American Association of Petroleum Geologists 58, 1290- 1304.
Horsfield, B. 1984. Pyrolysis studies and petroleum exploration. Advances in Petroleum Geochemistry, 247-298.
Lowel, J.D. 1985. Structural Styles in Petroleum Explo- ration. Oil and Gas Consultants International Publi- cations 49.
Monthiousm, M., Landais P. and Monin J.C. 1985. Comparison between natural and artificial maturation series of humic coals from the Mahakam Delta, Indo- nesia. Organic Geochemistry 8, 275-292.
PERTAMINA/TREND ENERGY 1987. The hydro- carbon potential of the Lower Tanjung Formation, Barito Basin, S.E. Kalimantan, Indonesia. Internal report on the results of a joint technical study between PERTAMINA and TREND ENERGY KALI- MANTAN LTD./PARTNERS.
Schoell, M., Teschner M., Wehner H., Durand B., Oudin J.L. 1981. Maturity related biomarker and stable isotope variations and their application to oil/source rock correlation in the Mahakam Delta, Kalimantan. Advances in Organic Geochemistry, 156-163.
Sikumbang, N. 1986. Geology and tectonics of Pre- Tertiary Rocks in the Meratus Mountains, South-East Kalimantan, Indonesia. Unpublished doctoral thesis submitted to University of London.
Thamrin M., 1987. Terrestrial heat flow map of Indone- sian basins. Indonesian Petroleum Association pu- blication.
Thompson, S., Morley R.J., Barnard P.C. and Cooper B.S. 1985. Facies recognition of some Tertiary coals applied to prediction of oil source rock occurrence. Marine and Petroleum Geology 2, 288-297.
Van de Weerd, A., Armin R.A., Mahadi S. and Ware P.L.B. 1987. Geologic setting of the Kerendan Gas and Condensate discovery, Tertiary sedimentation and paleogeography of the northwestern part of the
117
Kutei Basin, Kalimantan, Indonesia. Proceedings of the Sixteenth Annual Convention of the Indonesian
Ieum exploration. Bulletin of the American Associa- tion of Petroleum Geologists 64, 9 16-926.
Petroleum Association 1, 317-338. Waples, D.W. 1985. Geochemistry in Petroleum Expio-
Waples, D. w. 1980. Time and temperature in petroleum formation: application of Lopatin’s method to petro-
ration. Boston International Human Resources De- velopment Corporation 125-138 and 198-202.
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[TRITERPANES
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I STERANES 2
WARUKIN OIL
(C27 20SC20R)
S
J
I
N
I I TANJUNG FIELD LOWER TANJUNG OIL
9
FIGURE 19 - Oil gas chromatograph/Mass spectrometer scans.
137
GC DISTRIBUTIONS
f l -C l7 WARUKRIO(L8 0 1 - SEEP. L -313 8P.136
P * SEEP. L - a i s WELLHEAD
3 I TAPIAN TWUR-1S 4 - TAPIAN TIMUR-14
6 . WARUKIN EELATAN-17
E - WARUUIN SELATAN-10
7 - RIRIK-1 . M U 0 EAMPLF A
E - BIRIU-1. Mu0 SAMPLE C - TANlA- l .B fRAl
10- SANOUAlbl
1 1 - W A R W I N FIELD OLENO
TAK*MO ON8 0 11 - UAMBKW-2.XEPE
IS- TA-IS. 2 8 2 W Z E W
14- T A ” W 3 - 7 0 . Z S 6 o ~ Z 1 0 1 6
16- BA00U-1. M1A
18. .Awl-1. 2 7 1 0
17 - TAMNNO FIELD BLEND
PRISTANE n-C25
WARUKIN OIL8
1: W A W M $ELATAN-1
QC/MS STEZANE DISTRIBUTIONS
A ( C 2 8 20S+20R) SOURCE ROCKS
n= WARUKIN
FIGURE 20 - Ternary diagram of oil and source extract GC and GC/MS compound distributions.
-32
- 31
-30
- 29
-28
-27
- 26
-25
WARUKIN OILS
TANJUNG O I L S ,
K e y
0 O I L GROUPS
d' WHOLE O I L A N A L Y S I S ,
---Q--- S A T U R A T E F R A C T I O N A N A L Y S I S
, -25 -26 - 27 - 28 -29
S13C OF AROMATICS
T A N J U N G O I L S D I = MIYAWA AREA SEEP # I 21 K A Y O I T I N - 2 , STAGE 2 3. TANJUNG-58, STAGE I 4 = TANJUNG-76. STAGE 2 5 1 MIYAWA AREA S E E P X P 6 . 8AGOK- I , S T A G E 4 7. BAGOK- I , STAGE 3
W A R U K I N O I L 8 0 8 s BIRIK AREA S E E P 9. BlRlK AREA O L D W E L L
10. TAPIAN TIMUR- 13 11 . T A P I A N T I M U R - 14 12. W A R M I N S E L A T A N - 1 7 3- WARUKIN S E L A T A N - 1 9 14- OANGKAU- 1 5 = T A N T A - I , OERAl L S T .
HEAD SEEP
E X T R A C T S
] * TANJUNG F M T
WARUKIN FMT.
A = E A R I T O - I . STAG€ 3 0 : DIDI-I , B T A G E 2 C: COAL OUTCROP, STAGE I/*
Or MARIOU- I,LOWER WARUKIN E x EANGKAU -I, LOWER
WARUKIN C O A L .
FIGURE 21 - Barito Basin carbon isotope distributions of oil and source extracts.
