--> ABSTRACT: Characterization of Hydrocarbon and Source Rock in Berembang-Karangmakmur Deep Jambi Sub Basin, by Yosa Al Mizani; #90135 (2011).

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Characterization of Hydrocarbon and Source Rock in Berembang-Karangmakmur Deep Jambi Sub Basin

Yosa Al Mizani¹
(1) PT Pertamina EP, Indonesia

Abstract

Berembang-Karangmakmur deep in Jambi Sub-Basin belongs to PT Pertamina EP. This area has not been intensively explored. After doing some drilling in the area, it seems that productivity decreased. This phenomenon can be seen from the success ratio in this area which is around 51%. This study intends to explore the geochemical aspect, in this case assessing the characteristics of liquid hydrocarbons and source rocks around the deep, beside to understand to source potential for Gumai Formation.

Evaluation done during this study used twelve well data comprising source rocks, gases, and crude oils. Geochemical characteristics of the samples were based on some analyses, such as kerogen type, Rock-Eval pyrolysis, gas chromatography, biomarkers through GC-MS analysis, and carbon isotope. Some correlations, such as oil to oil, oil to source rock,  and gas to source rock that have been applied in the study area, in fact, could give a better explanation with regard to the hydrocarbon existence in the area. Maturity modelling and assessment of the migration pathway may confirm the history of the hydrocarbon generation and migration in the area.

Crude oils collected from Talang Akar and Gumai Formations could be differed based on their biomarkers content. Crude oils from Talang Akar Formation were generally deposited in the fluvio-deltaic environment whereas those of Gumai Formation might be deposited in a marine environment. Based on carbon isotope, gas generated in the Berembang-Karangmakmur deep may be classified as thermogenic gas with relatively high maturation.

Source rocks of Talang Akar and Gumai Formations contain types II and III kerogens. The Gumai shale has been deposited in a marine environment that is rich of algae material. On the other hand, the Talang Akar shale might be deposited in a fluvio-deltaic environment. In term of maturity, the Talang Akar sediments seem to be relatively mature whereas those of Gumai appear to be just mature. The oil to source correlation between crude oils collected from Gumai Formation and the sediments of Gumai Fomation indicate that they have a good correlation. This phenomenon indicates that the Gumai Formation in the deeper position may have been mature that they could produce some crude oils that were trapped within this formation. The results of 2D basin modelling show that hydrocarbons produced by the local deep had charged the nearest local reservoir since the local reservoir since the local reservoir (north and south) are separated by some sealing faults.

Jambi Sub-Basin

Knowing hydrocarbon potential in basin is most important in exploration activity. Jambi Sub Basin which is part of exploration PT. Pertamina EP is formed in Tertiary sedimentary basin. It is categorized as mature basin with view field have been developed such as Ketaling, Bajubang, Simpang Tuan etc. The development of this basin is controlled by tectonic activity afforded fold and fault that founded high and low area. Jambi Sub-Basin forms the north part of the South Sumatra Basin, which is trending northeast – southwest. De Coster (1974), South Sumatra Basin consists of three orogeny which produce South Sumatra Basin in Middle Mesozoic orogeny, Late Cretaceous-early Tertiary tectonism and Plio-Pleistocene orogeny. In mid-Mesozoic related to structural grain of Sumatra which is the Paleozoic and Mesozoic strata were metamorphosed, faulted and folded into large structural blocks and intruded by granite batholite. In second event occurred in Late Cretaceous and Early Tertiary, it formed tensional movements resulted horsts and half-graben structures, fault blocks in north-south trending. Appearance of the structure features comprised old structural in basin and controlled Eocene-Oligocene sedimentary. Syn rift deposited consist of granite wah in Lahat Formation during Eocene. In some place, volcanic and conglomerate rocks deposited in alluvial fan and fluvio deltaic raleted to gentle graben. In Late Oligocene-Miocene, burden isostacy until gentle tectonic raplaced to diastropsmed event in Barisan Mountains and minor structural in Middle Miocene. The boundary is defined by transgression as the result of eustacy influenced. Talang Akar Formation is composed of deltaic plain sandstone, siltstones and shale that grade basinward into marginal marine sandstone and shales, and from there farthere throughward into marine shales. Talang Akar Formation as reservoir mostly found by anticline structural and in deltaic consists of coal which is indicated it is main source rocks in Jambi sub basin. It is conviced by discovery oil and gas in some sincline. In basement high, we found limestone deposited, it is called Baturaja Formation good as reservoir. Baturaja Formation is composed of platform or bank limestone capped in restricted localities by further build up detrital, reefal and bank limestones. Shale in Gumai Formation is part of accumulation of shallow marine and developing of transgression. Shale in this formation propability contributed gas form in deep area. During Middle Miocene increasing of velocity subduction contributed to compression event. It is manifestated by exposed of Barisan Mountain activity and big folded in Sumatra. Regression phase started in shallow marine to deltaic depositional system in Air Benakat Formation and Muara Enim Formation especially in Jambi area. The generation petroleum during Early Miocene to Middle Miocene and continued until Late Miocene. It is showing amount of hydrocarbon significantly is occurred in structural period especially in Mid-Late Miocene. Plio-Pleistocene orogenic is reflected in shallow structures as resulted of compression system (Figure 1).

Method

Organofacies Attribute

Organofacies attribute produce compound in sediment which is have structural chemistry same with organism chemistry and as indicator of depositional sedimentary (Waples and Machihara, 1991). Although have the same meaning of biomarker, it is more influence to depositional sedimentary of material organic in crude oil itself. The application of biomarker in exploration increase significantly corresponded with technology of gas chromatography-spectrometry mass which is capable to determined mixing of complexity hydrocarbon. It is help to defined and identified transformation process of organic material after depositional process (Philip, 1985). The components of attribute biomarker of crude oil and rock extracts can be determined depositional system, source of material organic dan biodegradation process. Some biomarkers usually known are normal alkanes (n-alkanes), isoprenoids (pristane and phytane), sterane (m/z 217) and diastrerane, trisyclic terpane and tetrasyclic, triterpane pentasyclic. Normal alkanes are compound that found from gas chromatography analysis of saturated hydrocarbon fraction. Most commonly used in isoprenoids are pristane (pr) /phytane (ph) ratios. High pr/ph ratios (>3) are associated with terrestrially influenced sediments, including coal. If pr/ph ratios between 1-3 is associated with oxic marine sediments and less pr/ph ratios (<3) is associated with anoxic marine sediments. Steranes are valuable correlation parameters because of the direct dependence of C27, C28, and C29 regular steranes concentrations on their precursor C27-C29. C27 and C28 can found I n marine organism, sterol C29 is dominated by land plant material (Huang and Meinchein, 1979). In anoxic environment, steranes product and diasteranes are important things. Ratio of diatreranes/steranes can be use to determine source rock from clastic or carbonate.

Modelling

Modeling 1-D is associated with geological cross section as lines subsurface at the location being modeled. One-dimensional modeling can be done with the one well data. Maturity modeling used to predict the thermal maturity and hydrocarbon formation. This prediction can proceed to the area around or into the deeper areas of the basin. 1-D modeling usually begins with a burial history diagram. This chart takes the data depth to the upper boundary of the formation, thickness and age of the formations present in the upper formations millions of years. In addition, the data is used as a controller of shale porosity compacted (ignoring diagenetic) during the burial occurred. Based on simulated burial will affect maturation, hydrocarbon formation and expulsion. Compacting the rock is largely determined by the type of compaction in shale lithology such as reduced porosity rapidly at relatively shallow depths and slow down with increasing depth, whereas the sandstones are more homogeneous. By some researchers used a compaction mechanism is the Sclater and Christie (1980) for areas with rapid sedimentation, Falvey and Middleton (1981) for an area that has a slow sedimentation and Baldwin and Butler (1985) for local area flakes with normal pressure (River, 1994).

Thermal modeling is used to predict the level degree and the formation of hydrocarbon. Confidence of modeling results will greatly depend on the level of data accuracy input used. In this depends on the burial history, and how accurately the temperature paleo types of kerogen and kinetic parameters are known. In addition, the amount and composition of hydrocarbons formed can be determined through the thermal modeling.

Analysis

Hydrocarbon

Oil produced in this study are generally derived from the Talang Akar Formation but there are also derived from basement, Gumai Formation and Air Benakat Formation. Wells are used to identify Berembang-Karangmakmur deep that is Meranti-1 (MRT-1), Karangmakmur-1 (KRM-1), Karangmakmur-2 (KRM-2), Simpang Tuan-1 (SPT-1), Simpang Tuan-2 (SPT-2), Setiti Barat-1 (STB-1), Tuba Obi East-10 (TOE-10), Rengan Condong-C (RCD-C), Malapari-1 (MLP-1), Malapari-2 (MLP-2), Sengeti-6 (SNT-6), and Panerokan-2 (PRN-2).

Not all wells can be analyzed the value of its API, but generally API values in this deep ranging from 36° -47° (Table.1).

Table 1. Composition physical properties, isotopes carbon-13 (saturation and aromatic) and Pr/Ph of sample of crude oils.

Based on the API data obtained showed that the oil composition does not influenced of high maturity. According to BP Research (1991), the plot between the API and the ratio of Pr/Ph indicate that the oil belongs to the class D and E or the source rocks are interpreted as originating from a non-marine (Figure 2). Ratio pristanes/phytanes greater than 3.0 in the range 3-4 and at the Simpang Tuan-2 is 17.89. According to Robinson (1987), the ratio of Pr/Ph above 3.0 indicates the source rock derived from fluvio-deltaic environment. Plot pristanes and phytanes of normal alkanes used for the determination of oxic environment (Figure 3) and showing the difference between the wells located around Berembang-Karangmakmur deep northern and southern parts of the northern part of the source rocks was deposited on oxic environment, while in the southern part of the reduction is deposited on the environment. Gas chromatography data have varied but generally the characteristic can be concluded that the environment comes from fluvio-deltaic (Figure 3) from oxidative to highly oxidative. It can be seen from ratio pristanes to phytanes is high (Dydik, 1979, in Heriyanto, 2002). Crude oil on STB-1, a compound with a molecular weight <n-C7 was not found because of the influence of evaporation and oil in these well also indicated the origin of waxy land plants character because it has a distribution of long-chain n-alkanes.

Table. 2 Distribution and ratio of biomarker parameters from steranes and terpanes.

Based on data from crude oil biomarkers that have been collected suggest that the formation range from  terrestrial to marine in Talang Akar Formation. While Gumai Formation and Air Benakat Formation deposited on the marine environment (Figure 5). Generally, crude oil samples have 18α-oleanana high enough to show features of angiosperm resins. Some wells are dominated by C29 illustrates the high amount of plant material is deposited. Ratio hopanes/steranes also indicate the crude oil from oxic-suboxic terrestrial. In contrast to the surrounding wells are plotted, crude oil sample from RCD-C well (Gumai Formation) are shown the influence of algae.

Source rock

Samples sediment used here only with complete biomarker data. Samples are sought to represent formations from Berembang-Karangmakmur deep Sub-Basin of Jambi. Ten samples are used for the analysis of source rock consisting of Gumai Formation and Talang Akar Formation.

  Kerogen Type

Shales of Gumai Formation have richness of organic material from average to very good. In some wells there is coal that is above 20%. Shales with these characteristics tend to form a gas or oil and gas, but the RCD-1 wells there is oil sample form shales of Gumai formations. Source rock from shale of Gumai formation is believed to be proven in the sub-basin of Jambi. Kerogen type II and type III is generally very common in these formations that tend to generate oil and gas dominantly. The contribution of oil from kerogen type II in marine depositional system Gumai formation potentially to be source rock is described with TOC value between moderate to good. Some of shale from Gumai formation is not potential in top of formation. We can found kerogen type II and III in this formation (Figure 6 .

Facies Source Rocks

Bottom of Gumai as a source rock is indicated higher plants deposite. The ratio of Pr/Ph between top and bottom of Gumai formation is influenced by sea level rise and fall as a result of transgression and regression processes so that sampling at the bottom of the Gumai formation do not all show the process of transgression. However, when seen from Figure IV. 7 can be clearly demonstrated against hopan es to oleanan es ratio is lower than upper Talang Akar f ormation H opan es presence in bottom Gumai formation is higher than the top but both are still interpreted in association with environmental o xic with material from higher plants and some algae. C29 steran es distribution is dominated by material from higher plants with a slight increase in C27 steran es .

Gumai formation is a formation deposited on the marine environment, this is evidenced by the higher plants are transported and deposited on the marine environment. Ratio oleananes to hopanes is highest if compared between bottom and top of Talang Akar formation. In Indonesia, oleanana usully correlated with oil marine depositional system (Phoa and Samuel, 1986). Therefore, source rock in Gumai formations containing oleanana although highly correlated with higher plants that are resistant resin and transpor ted into the marine . Ratio h opan es to high steran is is indicate d input of higher plants and micro-organisms remain. Steran es distribution generally similar to Gumai formation, but the in KRM-1 C27 is dominated which is indicate d the contribution of organic material from higher waters. E ntire of formation can be known plot Pr/Ph of hopan es /steran es in Berembang-Karangmakmur deep source rock is affected by the terrestrial environment and deposited on the sub-oksik until oksik (Figure 8 .

Correlation Analysis

Correlation oil to source rock around Karangmakmur - Berembang deep based on finger print of biomarker results from the analysis of chromatography-spectrometry mass with view fragmentogram available.

- Oil Correlation of Oil

In the correlation of oil to oil, there is good correlation to oil derived from basement , Talang Akar Formation in hopan es group and also to the Gumai formation. Figure 9 shows fragmentogram triterpana of petroleum wells samples KRM .-1, STB-1 and RCD-C. Based on the expected correlation of oil from wells in KRM .-1 (tested on the Talang Akar Formation) and STB-1 (tested on basement has same organofasies, while the RCD-C wells are tested on Gumai ormation despite having the same resemblance but the relationship Ts to Tm is relatively higher than other oils samples. In addition, content of oil in the formation oleanan es Gumai formation relatively more than the oil from the basic rock samples and Talang Akar Formation . The difference of high and low occurrence of such data triterpana hopana and oleanana geokromatografi more due process, no uniform level of maturity as well as the position at the time was deposited closer to shore.

         Oil Correlation of Source Rocks

Correlation of biomarker fingerprints of several examples organosedimen of petroleum shows most of the oil samples samples organosedimen correlates well with Gumai formation and Talang Akar formation (Figure 10 ). Some of the patterns of similarity and host rock oil in between the dominance of C30 to C29 hopana relatively higher, the appearance oleanana, comparison of Tm to Ts, the dominance of C31-C35 homohopana, and minor C23 which is a type of terrestrial.

Burial History

Based on the burial history curve can be analyzed deposition and tectonic history of the Berembang –Karangmakmur deep , analysis time and maturity level of the source rock and formation hidrokarbonnya.

Maturity

Due to the evolving tectonic sub-basins in the area of "Cambria Math","serif";mso-bidi-"Cambria Math"'>‌‌ Jambi is a half-graben that Berembang - Karangmakmur deep kitchen can be a hydrocarbon. To discuss the formation of such depth that acts as an active hydrocarbon kitchen, use one-dimensional basin modeling. One-dimensional modeling in Figure 11 is represented by MLP-2 wells in the south of Berembang-Karangmakmur deep . Based on the modeling of wells a shadow (a pseudo-well), it was shown that mature early at 12.5 million years, at the age of the Middle Miocene, at a depth of 1268 meters. When the formation was deposited Gumai already entered the early mature at this depth is also a potential host rock. Subsequent one-dimensional modeling performed on the well distrib-2 (Figure 12 ) situated in the north of Berembang-Karangmakmur deep . Based on the modeling of wells a shadow (a pseudo-well), it was shown that mature early at 14.2 million years, beginning at a depth of 1235 meters. Formation Gumai also showed that a potential host rock. When compared between the two wells that have been carried out shadow 1-D modeling, that can be deduced that there are two sources of the host rock of different stem from both the well. This conjecture can be strengthened from the modeling results of 2-D burial history.

Hydrocarbon Formation

Modeling using shadow wells can also be used to determine the formation of hydrocarbons in Berembang - Karangmakmur deep. U sing three pseudo wells of MLP-2, RCD-C, and KRM- 2. MLP-2 wells and the RCD-C in the south of Berembang-Karangmakmur deep and KRM -2 wells located in the north-Karangmakmur Berembang deep . The following Figure 13 , Figure 14 and Figure 15 show ing the results of modeling of the 15 million years ago until the present. Based on 2-D modeling can be seen turned out to Berembang-Karangmakmur deep areas north and south have a different source depths

Migration

Two-dimensional modeling that has been tied to the seismic interpretation can describe patterns of migration pathways. Berembang-Karangmakmur deep have migrate d relatively vertically and laterally bounded by faults, so it relies heavily on the rocks of hydrocarbon carrier (carrier bed) and the pattern structure.Migration patterns in the area around Berembang-Karangmakmur deep follow the pattern altitude kitchen and existing oil and gas, the general direction of the kitchen hydrocarbons relative north-south and east-west (Figure 16 ). With the direction of migration and accumulation of hydrocarbon traps will find it easier to determine the potential for subsequent exploration wells.

Conclusions

Based on geochemical studies, Talang Akar Formation derived from source rocks in the suboxic-oxic environment (fluvio-deltaic) and Gumai formation from marine with the influence of algae. Correlation using fingerprint biomarkers indicated genetic relationship between crude oil and allegedly from the same organofacies. Based on the correlation of oil from Gumai formation  to source rock from Gumai style='mso-spacerun:yes'>  Formation characterize the similarities between the dominance of hopanes C30 to C29 relatively higher, the appearance oleanana, the ratio of Tm to Ts. It is possible, the Gumai Formation as source rock also potentially filled the reservoir of Air Benakat Formation. Maturity analysis using one-dimensional modeling in Berembang-Karangmakmur deep generally show Talang Akar Formation as source rock already mature and Gumai Formation mature into the initial window. Hydrocarbons in Berembang-Karangmakmur deep formed in the Middle Miocene age is 12.5 million years ago in southern part and 14.2 million years ago in the northern part. Hydrocarbons begin to form on the Formation of Middle Miocene to Late Miocene Talang Akar and Gumai Formation. The differences source rock of Berembang-Karangmakmur deep in northern and southern parts are indicated by two-dimensional modeling, which is closely related to tectonic events of the area.

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Figure 1. Stratigraphy of Jambi Sub-basin (Ryacudu, 2005)

Figure 2. Shows oil into a class D or E (non-Marine oil) based on the BP Research (1991).

Figure 3. Plot pristanes/n-C17 and phytanes/n-C18 of normal alkanes indicate conditions oxic to sub-oxic with fluvio-deltaic character.

Figure 4.  Gas chromatographic analysis of crude oil samples compared with the analysis has been carried out Robinson (1987)  that characterizes fluvio-deltaic environment.

Figure 5 Triangular diagram of C27-C28-C29 fragmentogram m/z 217 showing the environment of deposition.

Figure 6. Tmax and HI cross plot to evaluate the kerogen type and maturity.

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Figure 7. Chromatogram m/z 191 and m/z 217 was taken from the wells showed oleanana S.-2 and C27 in the formation Gumai relatively greater than the Air Benakat Formation.

Figure 8. Facies of source rock based hopanes/steranes and pristanes/phytanes shows precipitation in the area of ‌‌ sub-oxic to oxic.

Figure 9. Gas chromatography analysis from oil samples compared to Robinson analysis (1987) indicates fluvio-deltaic environment.

Figure 10. Fragmetogram triterpanes m/z 191 from oil to source rock (a) Talang Akar formation; (b) Gumai formation.

Figure 11. 1-D modelling from pseudo well KRM-2 in Berembang-Karangmakmur deep.

Figure 12. 1-D modelling from pseudo well MLP-2 in Berembang-Karangmakmur deep.

Figure 13. Generate hydrocarbon 15 million years ago.

Figure 14. Generate hydrocarbon 10 million years ago.

Figure 15. Generate hydrocarbon present day.

Figure 16. Migration pattern in Berembang-Karangmakmur deep.

 

AAPG Search and Discovery Article #90135©2011 AAPG International Conference and Exhibition, Milan, Italy, 23-26 October 2011.