IPA05-G-159 PROCEEDINGS, INDONESIAN PETROLEUM ASSOCIATION Thirtieth Annual Convention & Exhibition, August 2005 PETROLEUM GEOCHEMISTRY STUDY IN A SEQUENCE STRATIGRAPHIC FRAMEWORK IN THE SIMENGGARIS BLOCK, TARAKAN BASIN, EAST KALIMANTAN, INDONESIA Eddy A. Subroto* Bambang P. Muritno** Sukowitono** Dardji Noeradi* Djuhaeni* ABSTRACT Hydrocarbon exploration in the Tarakan Basin indicates that, in general, the eastern part (e.g. Tarakan and Bunyu fields) is more promising than the western area. In order to find more potential area(s), particularly in the western part, a new approach based on an integration study between stratigraphic framework and geochemistry has been conducted to analyse the petroleum system. A sequence stratigraphic framework has been established in the Simenggaris Block with eight sequences of Oligocene to Pliocene age having been identified (SB-1 to SB-8). A geochemical study reveals that shales belonging to SB-1 to SB-8 contain organic carbon (TOC) between 0.65 and 7%, indicating that several are sufficiently rich to be considered hydrocarbon source rocks. Moreover, almost all sequences contain some coals or carbonaceous materials with TOC content up to 70%. In terms of maturity, well data show that only SB-2 and SB-1 (Naintupo Formation and older) have reached optimal maturity to generate hydrocarbons. However, basin modelling results for the deeper areas adjacent to structural highs indicate that SB-5 to SB-3 sequences (Meliat Formation) are in the middle mature stage (around 0.7 to 1% vitrinite reflectance equivalent). Furthermore, peak oil generation in the area was reached between 10 and 1 million years before present. On the basis of their hydrogen index (HI) values, all formations within the SB-1 to SB-2 interval consist of a mixture between type II and type III kerogens (HI 50-454), indicating that they may produce oil and gas. * Institute Technology Bandung ** JOB Pertamina-Medco Simenggaris Pty. Ltd In this study, ten crude oil samples were collected from the study area. Geochemical analyses on these crude oils reveal that they appear to be predominantly generated from the Naintupo Formation of SB-2. However, another formation (i.e. Meliat Formation of SB-5 to SB-3) could also be the source of these oils. INTRODUCTION The Tarakan Basin, located in northeast Kalimantan, is an important petroleum basin of Indonesia (Figure 1). In the 1970s and 1980s, the hydrocarbon exploration activities in the area were very intensive. Out of the 35 exploration wells drilled, nine discoveries were made (Biantoro et al., 1996). Furthermore, Lentini and Darman (1996) reported that the exploration in the basin resulted in the discovery of 14 oil and gas fields. Some of the discovery wells reported from this area are well A, which produced oil from four sand layers in the Meliat Formation; well I produced oil in Middle to Late Miocene Tabul and Meliat Formations, and well P from the Tabul Formation. From the exploration history of the basin, it appears that the eastern part of the basin is more promising than the western part with many discoveries having been made in the eastern province (e.g. the Tarakan and Bunyu fields). Geologically, there appears to be no significant difference between the western and the eastern parts of the basin. This apparent similarity may be real, or it may be due to a lack of detailed geological information needed to define the differences (e.g. detailed stratigraphy and tectonics). More work is therefore needed. The aim of this paper is to establish a regional stratigraphic framework in the Tarakan Basin using well and seismic data and 421
then evaluate the petroleum system and hydrocarbon potential of the basin. GEOLOGICAL SETTING The Tarakan Basin has four major depocentres of Paleogene and Neogene age which covers over 40,000 km 2, namely Tidung, Berau, Tarakan, and Muara Sub-basins (Figure 1). The basin is generally a passive deltaic margin with a minor wrench tectonic overprint. Magnetic anomalies imply sea-floor spreading with associated NW trending transform faults. The general regional geology of the area, including stratigraphy and tectonics, has been published elsewhere (e.g. Heriyanto et al., 1992; Biantoro et al., 1996; Lentini and Darman, 1996, Noon et al., 2003). In brief, the Tarakan Basin has been an active depositional site since the formation of a rift basin in the Paleogene. The Berau and Tidung depocentres have been subjected to uplift and erosion since Middle Miocene time, while in the Tarakan and Muara depocentres, sediments of the deltaic system have been deposited continuously from Late Miocene until the present day. In the Tarakan Sub-basin, the siliciclastic sediments have been deposited dominantly since the Middle Miocene, while carbonate sedimentation was dominant since the Early Oligocene in the Muara Sub-basin. In the Berau Sub-basin, the domination of carbonates began from the Early Oligocene to Early Miocene. Sources of clastic sediments were from the west, near the Tarakan Sub-basin. The simplified geological map of the basin is shown in Figure 1. Stratigraphically, the framework of the Tarakan Basin can be divided into two main sedimentary systems, i.e. the older sediments, which are non-deltaic and the younger deltaic sediments. The non-deltaic sedimentary system occurred during Eocene to Early Miocene. Sediments deposited during this time consist of volcanic material of deep marine to continental origin. This series was detected above the basement complex comprising strongly metamorphosed and faulted igneous rocks. The lithostratigraphy of the non-deltaic sedimentary system can be recognised as Sembakung, Sajau, Seilor, Mangkabua, Tempilan, Tabalar, Mesaloi, and Naintupo Formations. The deltaic sedimentary system took place during Middle Miocene to Quaternary. This system consists of a prograding deltaic series lying unconformably above the prodelta sequence of the Naintupo Formation. The clastic materials of the deltaic series were derived from the western part of the Tarakan Basin, known as the Central Range of Kalimantan or Kuching High. The general stratigraphy of the Tarakan Basin is given in Figure 2. Five depositional cycles have been defined above the basement complex. These cycles are separated by unconformities and each cycle began with a clastic influx which graded upwards and basinward into more argillaceous facies or marine carbonate. SEQUENCE STRATIGRAPHY Sequence stratigraphy developed in this study is mainly based on well log analysis. Generally, a sequence boundary (SB) is coincident with the contact between the blocky to bell-shape gamma ray (GR) log of fluvial channel deposits above and shaly to spiky GR log of marine shale below (Figure 3). A more detailed analysis beyond the recognition sequence boundaries (e.g. system tract to parasequence unit) was not possible due to the rapid change of lithofacies in the deltaic system which made detailed lithostratigraphic correlation very difficult. The micropaleontology data were very limited, and most of the seismic data were old vintage and not good quality. For these reasons, our analysis was limited to the identification of eight sequence boundaries defined as follows: SB-8 (5.6 Ma), SB-7 (7.2 Ma), SB-6 (11.3 Ma), SB-5 (12.5 Ma), SB-4 (15.0 Ma), SB-3 (16.7 Ma), SB-2 (17.2 Ma), and SB- 1 (23.2 Ma). GEOCHEMICAL ANALYSIS Source Rock Evaluation Table 1 shows the geochemical results for organic carbon content (TOC) and hydrogen indices (HI). The data are grouped based on the sequences defined for the area. It should be noted that the data for sequence 0 are limited, because most of the wells drilled in the Tarakan Basin do not reach the Paleogene section. The following discussion on source rock potential will progress from the youngest sequence 8 to the oldest sequence 0. Lithology of sequence 8 (Santul Formation) comprises a sand-dominated interval with minor 422
interbedded coals and coaly shales with the lower part comprising limestones and shales. Shales of this sequence contain TOC ranging from fair to excellent (0.6 to 4.5%), while coal of this sequence has TOC up to 69%. HI values range from 30 to 328, indicating gas prone with some liquids potential. The HI values indicate that these samples consist of a mixed type III/II and are interpreted to be derived from degradation from higher plant materials. Sequences 7 to 6 (Tabul Formation) consist of interbedded sandstone, shale, minor coal seams and occasional thin limestone. Shales of these sequences have good to excellent organic contents (0.5 to 4%). Some coals were also found in these sequences with TOC content up to 72%. Kerogen of the shale and coal samples of the sequences 7 to 6 is predominated by a mixture of type III and type II (HI between 60 and 280), which is, again, interpreted as gas prone with minor liquids potential. Sequences 5 to 3 (Early Middle Miocene Meliat Formation) contain predominantly claystones with interbedded sandstone and coals and occasional dolomites. The clay samples contain organic carbon ranging from 0.7 to 6.5%. HI values mainly indicate gas generative characteristics. Coal seems to be detected in most of the sequences. In these sequences, coals in several wells show excellent carbon organic contents, reaching up to 70%. HI values (up to 417) suggest a mixed oil and gas prone potential source rock. Visual kerogen analysis of coal and clay samples from some wells indicates a type III predominance. Sequences 2 to 1 (Early Miocene Naintupo Formation) mostly consist of shale and clay with thin sand and coal. Coal samples from these sequences show high organic contents with TOC values up to 72%. HI values (up to 450) indicate mixed oil and gas potential. Visual kerogen analyses show abundance of inertinite. Shales of these sequences generally have fair to good organic contents with HI values exhibiting moderate oil and gas potential. From visual kerogen analysis, type III and some type II kerogens were observed. Sequence 0 (Late Oligocene) sediments were penetrated only by the wells I and K in the vicinity of the Simenggaris Block. This sequence is also represented by a large number of outcrop samples from the Tempilan-Mesaloi Formations to the north. In well I, only a single TOC value (0.95%) is available from a SWC. TOC s of sequence 0 sediments in the well K are fair to good, but those from outcrop are typically only fair, with low hydrogen indices (< 200), indicating modest source potential for gas only. The kerogen type is almost exclusively Type III-IV gas-prone, and is largely terrestrial/deltaic in nature. Pyrolysis-gas chromatography (PY-GC) data are available for several outcrops from the Tempilan-Mesaloi Formations. These yielded pyrolysates containing a mixture of octene and xylenes. Maturity was estimated using 1D and 2D basin modelling software (BasinMod 1D and 2D). Geochemical input data for the model included vitrinite reflectance (%Ro), pyrolysis Tmax, kerogen type, hydrogen index (HI), oxygen index, total organic carbon (TOC), and production index (PI). Figure 4 shows the burial history model for well K. It shows that the early mature stage (Ro=0.5%) started at nine mya (million years ago) for Naintupo Formation and five mya for Meliat Formation, whereas the more mature stage (Ro=0.7%) started at three mya for Naintupo Formation and 1.5 mya for Meliat Formation. In general, on the basis of the well data, the mature stage of source rock evolution was only detected in sequences 0, 1, and 2. This is because the wells were drilled on structural highs and thus the maturity of the drilled formations is relatively low compared with that of the same formation in adjacent lows. Therefore, maturity assessment based on 2D modelling was performed using integrated geochemical, geological, and geophysical data. Seven wells around the area were used in this maturity modelling. A cross section model showing two pseudo-wells created along the east-west seismic line (Figure 5A) is illustrated in Figure 5B. The two pseudo-wells represent the deeper area within the basin. It is apparent that the bottom of the Meliat Formation has reached the peak of oil generation, progressing to the onset of wet gas (Ro between 1 and 1.3%), while the Naintupo Formation is in the early gas generation stage (Ro between 1.3 and 1.5%). This model also reveals that sequences 8 to 6 (Santul and Tabul Formations) in the deeper area have reached middle mature stage with Ro up to 0.7%. Figure 5C illustrates that the peak of oil generation (Ro=1.0%) started ten million years before present for the Naintupo Formation and seven million years before present for the Meliat Formation. 423
Source Rock to Oil Correlation Correlation between source rocks and crude oils was based on the distribution of n-alkanes, biomarkers, and stable isotope. This correlation study includes ten crude oils and several samples from wells and outcrops. It is noted that the type of geochemical data obtained for crude oil samples was not always the same. Some crude oils were analysed for their biomarkers and/or stable isotopes, whereas others only for their n-alkanes distribution. Therefore, all of them could not be correlated in a similar manner. Figure 6A shows a comparation of n-alkane distributions in three crude oils (A, I, and J) and three source rocks. The source rock samples represent the Meliat (2 samples) and Naintupo (1 sample) Formations. It appears that the three crude oils belong to one genetic family, indicated by relatively similar distribution of their n-alkanes. On the contrary, the n- alkanes distribution of the two source rocks of the Meliat Formation shows different patterns compared with that of the crude oils. The shallower sample (1275.5 m) indicates a very immature sample, shown by a strong predominance of the odd alkanes. This odd alkane predominance becomes weaker in the deeper sample (1671 m). The n-alkanes distribution in the Naintupo sediment reveals a close relationship with that of the three crude oils. Such a relationship is better illustrated in Figure 6B. It is therefore concluded that the crude oils found in the area were most likely derived from the Naintupo Formation. However, since there is a trend for Meliat sediments to be more similar in their n-alkane characteristics compared with those of the crude oils when they become more mature, then the possibility for the Meliat sediments being source rocks of the crude oils is still open. Biomarkers and stable isotope have also been applied in this correlation study. The best biomarkers used for assessing the origin of the organic matter are steranes. Figures 7A and 7C show the ternary diagram of Huang and Meinschein (1979) for crude oils and sediment samples, respectively. It seems that the organic matter contained in both sediments and crude oils cannot be divided sharply on the basis of their depositional environment. They show a range of depositional environments from terrestrial to estuarine. This is characteristic of deltaic environments. On the other hand, based on the stable isotope analysis, it appears that the crude oils can be divided into two groups (Figure 7B).However, the difference between the group 1 and group 2 oils in terms of depositional environment is not too significant. They both lie around the transition lines between the terrestrial and algal zones; with group 1 closer to the terrestrial sector and group 2 closer to the algal sector. Again, such a phenomenon is a characteristic of the deltaic environment, which includes elements of both the terrestrial and marine environment. The plot of the sediment isotopes is bounded around the two oil groups, except for a sample from sequences 5 to 7, which has very light isotopes. This sample appears to be anomalous, which is likely due to analytical problems. The isotope results suggest two groups, although the difference in their depositional environment is not significant. The results for the sediments indicate that they belong to a broad group that shows good correlation with the crude oils. CONCLUSIONS Two potential source sequences are identified in the Tarakan Basin, namely the Naintupo and Meliat Formations. Two other formations (Tabul and Santul) may also include important source rocks, particularly in the deepest parts of the basin. This study documents the source rock distribution in terms of source rock sequences, organic carbon content, kerogen type, and thermal maturity. Within the limitations of the data, crude oils can be classified into one large genetic family with two possible sub-groups. Migration has occurred since ten million years before present. The slight variation in the sterane and isotopic compositions is likely due to variations within the deltaic depositional environment. The crude oil samples appear to correlate with sediment extracts of the Naintupo Formation. ACKNOWLEDGEMENTS We are grateful to the management of JOB Pertamina-Medco Simenggaris and BPMIGAS for permission to publish this work. We thank PT Geoservices (Ltd.) for the laboratory analytical works. We also thank Dr. Ron Noble for his valuable comments and suggestions on the earlier version of this manuscript. 424
REFERENCES CITED Biantoro, E., Kusuma, M.I., and Rotinsulu, L.F., 1996. Tarakan Sub-basin growth faults, northeast Kalimantan: their roles in hydrocarbon entrapment. Proceedings Indonesian Petroleum Association, 25 th Silver Anniversary Convention, Jakarta, v. 1, p. 175-189. Heriyanto, N., Satoto, W., and Sardjono, S., 1992. An overview of hydrocarbon maturity and its migration aspects in Bunyu Island, Tarakan Basin. Proceedings Indonesian Petroleum Association, 21 st Annual Convention, Jakarta, v. 1, p. 1-22. Huang, W.-Y. and Meinschein, W.G., 1979. Sterols as ecological indicators. Geochimica et Cosmochimica Acta, 43, p. 739-745. Lentini, M.R. and Darman, H., 1996. Aspects of the Neogene tectonic history and hydrocarbon geology of the Tarakan Basin. Proceedings Indonesian Petroleum Association, 25 th Silver Anniversary Convention, Jakarta, v. 1, p. 241-251. Netherwood, R. and Wight, A, 1993. Structurallycontrolled, linear reefs in a Pliocene delta-front setting, Tarakan Basin, northeast Kalimantan. In Siemens et al. (eds.) Carbonate Rocks and Reservoirs of Indonesia. IPA Core Workshop, p. 3/1-3/16. Noon, S., Harrington, J., and Darman, H., 2003. The Tarakan Basin, East Kalimantan: proven Neogene fluvio-deltaic, prospective deep-water and Paleogene plays in a regional stratigraphic context. Proceedings Indonesian Petroleum Association, 29 th Annual Convention, Jakarta, digital file IPA03-G-136. Situmorang, R.L. and Burhan, G., 1992. Peta Geologi Lembar Tanjung Redeb, Kalimantan Timur (Geological Map of Tanjung Redeb, East Kalimantan). Geological Research and Development Centre. Sofer, Z., 1984. Stable carbon isotope compositions of crude oils: application to source depositional environments and petroleum alteration. Bull. AAPG, 68, p. 31-49. 425
TABLE 1 TOTAL ORGANIC CARBON CONTENT AND HYDROGEN INDICES DETERMINATION OF THE SEDIMENT SAMPLES ACCORDING TO THEIR SEQUENCES 426
Figure 1 - Simplified geologic map of the Tarakan Basin (modified from Situmorang and Burhan,1992; Netherwood and Wight, 1993). 427
Figure 2 - Stratigraphy and tectonic setting of the Tarakan Basin (after Lentiti and Darman, 1996, and references therein). 428
Figure 3 - Example of the sequence boundary identification based on well data. Figure 4 - Burial history model of Well K, showing an early mature stage (Ro=0.5%) started at 9 mya for Naintupo Formation and 5 mya for Meliat Formation, and a more mature (Ro=0.7%) started at 3 mya for Naintupo Formation and 1.5 mya for Meliat Formation. 429
Figure 5 - A cross section shows maturity model along an east-west seismic line (A). In the deeper area the Naintupo Formation has reached main wet gas generation whereas the Meliat Formation a late mature stage for Naintupo Formation (B). Time vs %Ro curve for Naintupo Formation in the Pseudo-1 well indicating time of peak oil generation (Ro=1.0%) started at 10 mya (C). 430
Figure 6 - n-c 15-30 distributions for three crude oils and three sediments (A), and for three crude oils and a sediment (B). 431
Figure 7 - C 27-29 steranes triangle diagram of Huang and Meinschein (1979) for crude oils (A) and sediments (C) collected from the Tarakan Basin. (B) and (D) illustrate plots of the stable carbon isotope data in the Sofer s diagram. 432