shale gas: geological perspective of baong formation for ... 20130104.pdf · the mergui, north...

Majalah Geologi Indonesia, Vol. 28 No. 1 April 2013: 41-49

41Naskah diterima: 24 September 2012, revisi terakhir: 05 April 2013, disetujui: 08 April 2013

Shale Gas: Geological Perspective of Baong Formation for Future Chances of North Sumatra Basin;

Compared to Fort Worth Basin in USA

Gas Serpih: Perspektif Geologis Formasi Baong untuk Kemgungkinan Masa Depan Cekungan Sumatra Utara; dibandingkan dengan Cekungan Fort Worth, Amerika Serikat

Nur Amalia Murtrijito, Fetty Maria Naibaho, and Wijayanti Ashuri

Department of Geological Engineering, Bandung Institute of Technology, Indonesia

ABSTRACTBaong Formation, situated in North Sumatra Basin, has other potential resources besides the ability of formation to be an oil-prone sediments. Gas is generated in an interbedded black shale and limestone of this formation. The black shale derived from the deposition of organic-rich material and influenced by the presence of sandy shale is possible to produce natural fractures within this formation leading to the increasing porosity and permeability significantly. The presence of interfingering limestone also contribute to the natural fracture amount. The Baong Formation has particular similarities with Barnett Shale of the Fort Worth Basin in petroleum system and lithology. Therefore, it is not impossible if the Baong Formation become a commercial gas resource as Barnett Shale. On the other hand, Peutu-, Arun, and Belumai Formations, comprising limestone with minor dolomite and sand, which lithologically are similar with Ellenburger Formation in Fort Worth Basin, may become good quality reservoirs for the underlying Parapat-Bampo source rock. Moreover, Parapat – Bampo Formations as fluvial deposits become a good source rock as Riley Formation in Fort Worth Basin consisting of sandy fluvial deltaic sediments. Besides the similarity in lithology, the Baong Formation, tectonostratigraphically is also similar to Barnett Formation in Fort Worth Basin. In syn-rift depositional period, the Riley Formation in Fort Worth Basin and Parapat - Bampo Formations in North Sumatra Basin were deposited first. It was continued by the deposition of Ellenburger Formation in Fort Worth Basin, and Peutu -, Arun -, and Belumai Formations in North Sumatera Basin, then followed by the conformably deposition of the potential gas-prone sediments, those are Baong Formation in North Sumatra Basin and Barnett Shale in Fort Worth Basin. During the gas-prone sediment formation, active faults formed fault belt system impacting thermal subsidence and uplift could occurred.Keywords: Baong Formation, North Sumatra Basin, Barnett Shale, Fort Worth Basin, Indonesia, USA

SARIFormasi Baong, yang terletak di Cekungan Sumatra Utara, selain sebagai batuan sedimen bersifat oil-prone, juga berpotensi sebagai sumber gas serpih yang terbentuk di dalam perselingan serpih hitam dan batugamping. Serpih hitam yang terendapkan sebagai sedimen yang kaya akan bahan organik dan mengandung sisipan serpih pasiran sangat memungkinkan untuk mengalami rekahan secara alamiah, sehingga akan meningkatkan porositas dan permeabilitasnya secara signifikan. Keberadaan batugamping yang menjemari dengan serpih juga menambah peringkat rekahan alamiah tersebut. Formasi Baong memperlihatkan kesamaan sistem petroleum dan litologi dengan Serpih Barnett dari Cekungan Fort Worth. Hal ini tidak menutup kemungkinan jika Formasi Baong menjadi sesumber gas seperti Serpih Barnett. Di lain fihak, Formasi Peutu, Arun, dan Belumai yang tersusun terutama oleh batugamping, dengan sedikit dolomit dan batupasir, dan secara litologi sama dengan Formasi Ellenburger di Cekungan Fort Worth, akan berfungsi sebagai reservoir berkualitas bagus bagi batuan sumber yang mengalasinya, yaitu Formasi Parapat-Bampo. Lebih jauh lagi, Formasi Parapat-Bampo yang merupakan endapan fluviatil akan menjadi batuan sumber yang baik seperti Formasi Riley di


42

INTRODUCTION

Shale gas is an unconventional hydrocarbon or natural gas produced from shale forma-tions, which has been developed in several countries. Indonesia has shale gas potential in some basins, one of which is North Su-matra Basin, where Baong Formation was deposited as a regional seal for the three main reservoirs below the Baong Formation, those are the Belumai, Arun, and Peutu Formations.

The purpose of this study is to examine the potential of unconventional hydrocarbons from geological point of view, so the authors have tried to compare with the success of shale gas that has been first produced in the Barnett Shale in the Fort Worth Basin, Texas, USA, based on the petroleum system, geo-chemical analysis, and the forming of North Sumatra Basin related to basin infill.

GEOLOGICAL BACKGROUND

North Sumatra Basin is a back-arc basin (Figure 1). Almost the entire basin fill is marine deposits, much of them, especially in the north, comprise basinal deeper marine claystone, shale, and shallow water reefal limestone. The later developed on structural highs. Regressive shallow water deltaic facies are found in the southeast area. The sequence predominantly composed of argil-

laceous material and divided into four-basin stages is somewhat arbitrary (Doust and Noble, 2008).

Late post-rift (Middle Miocene to Pliocene) stage is a regressive sequence comprises argillaceous Baong Formation, in which turbidite sands occur, and the overlying paralic shale, silt, and sand of the Keutapang and Seurula Formations. In the north, deeper marine facies continued, while towards the southeast, these formations became shal-lower with the deposition of regressive deltaic sand of moderate to good reservoir quality (Doust, and Noble, 2008).

TECTONIC SETTING

NNorth Sumatra Basin, a back-arc basin, is located in the northeast area of Bukit Barisan (Figure 1). This basin extends in the northwest - southeast direction and is bounded by Bukit Barisan to the west and Malacca Platform in the east.

The Burman Plate being slowly dragged northward by the Indo-Australian Plate. A clockwise rotation of the Burman and Shan Plates led to the opening (rifting) of the Mergui, North Sumatra, Martaban, and Central Burman Basins. Early Miocene plate reconstruction and basin evolution show a continuing northward drift of the Burman Plate and rotation of the Burman and Shan

Cekungan Fort Worth, yang terdiri atas batuan sedimen delta-fluviatil pasiran. Selain kesamaan dalam litologi, Formasi Baong dengan Formasi Barnett juga memperlihatkan kesamaam secara tektonostratigrafis. Dalam periode pengendapan syn-rift, Formasi Riley di Cekungan Fort Worth dan Formasi Parapat-Bampo di Cekungan Sumatra adalah paling awal terendapkan. Selanjutnya diikuti oleh pengendapan Formasi Ellenburger di Cekungan Fort Wort dan Formasi Peutu, Arun, dan Belumai di Cekungan Sumatra Utara. Kemudian, secara selaras di atasnya terendapkan Formasi Baong di Cekungan Sumatra Utara dan Serpih Barnett di Cekungan Fort Worth, yang keduanya bersifat oil-prone. Selama pengendapan kedua formasi ini, terjadi sesar aktif yang membentuk sistem jalur sesar dan berpengaruh kuat terhadap penurunan dan pengangkatan secara termal di kawasan tersebut.Kata kunci: Formasi Baong, Cekungan Sumatra Utara, Serpih Barnett, Cekungan Fort Worth, Indonesia, Amerika Serikat

Shale Gas: Geological Perspective of Baong Formation for Future Chances of North Sumatra Basin; Compared to Fort Worth Basin in USA (N. A. Murtrijito et al.)

43

Plates. Middle Miocene plate reconstruction and basin evolution display an accelerated northward drift of the Burman Plate causes the opening of the modern Andaman Basin west of the Mergui Ridge (Figure 2). Com-pression intensifying plate rotation causes a major left-lateral movement along the Ra-nong Fault. Early Pliocene plate reconstruc-tion and basin evolution indicate sediments pouring off the rising Barisan Mountains on Sumatra, and then causing a significant downwarping of the southern North Sumatra Basin margin (Anderson et al., 1997).

There are two main structure trends in North Sumatra Basin, those are the N-S trend representing pre-Miocene structure, and the NW-SE that is post Miocene structure. Both trends are a product of three tectonic events, comprising initial extension phase in Late

Eocene-Early Oligocene, wrench tectonism in Middle Miocene, and compressional tec-tonism in Pliocene-Pleistocene.

METHODOLOGY AND CHARAC-TERIZATION OF SHALE GAS

Shale gas consists of 70 - 90% dry methane gas (some in the form of wet gas), 20% is a mixture of ethane, butane, and propane, and the rest comprises CO2, O2, N, and H2S. Shale gas was once considered to be in a for-mation serving as a source rock and seal that accumulates near the reservoir sandstones and carbonates (from onshore gas). Shale is usually deposited in a quiet low-energy environments such as lacustrine or seawater environment in which clay sediment was de-posited in a suspension mechanism through

Figure 1. Regional tectonic setting of Sumatra.

North Sumatra

Basin

MalaccaPlatform

Active volcano

Key

Base of trench slope

Regional fault system

Fore arc ridge

Fore Arc Ridge

Nias

Sibolga Basin

Central Sumatra

Basin

Bangka

Jakarta

SouthSumatra

Basin

Tigapuluh High

Sumatra Fault System

(SFS)

Barisan

Mentaw

ai Fault System (M

FS)

Mentawai Islands

BengkuluBasin

Relative Plate

Motion

Toe of melange w

edge

Top of melange w

edge

Sunda Trench

Accretionary W

edgeActive Subduction Zone

Asa

han

Arc

h

N

o6 N

o0

o 6 S

o N

E

0 200 400 km


44

a quiet water environment. During deposi-tion of this clay grains, shale can also accu-mulate with organic material (algae, plants, animal shell debris). This layer is very thin (sheet-laminae) and make arrangement of horizontal permeability of the shale which is very small, and also limited permeability in the vertical succession.

As a comparison, Shale Gas Potential of the most vibrant play is in the Barnett Shale located in Fort Worth Basin, where horizon-

tal drilling and stimulation techniques have resulted in multiple zones of growth of 0.2 bcf/d in 1999-2004 to more than 1.3 bcf/d in 2005. Shale gas exploration is the complex interplay and balance of the controlling fac-tors of organic richness, thermal maturity, lithology, mineralogy, depth, and fractur-ing characteristics that lead to this type of gas accumulation. Factors like production technique and infrastructure determine the economic value of shale gas resources.

Figure 2. The tectonic evolution of North Sumatera Basin (Anderson et al.,1997).

Indian Plate Burman

Plate

Shan Plate

Indian Plate

Burman Plate

Shan Plate

Indian Plate

Burman Plate Shan

Plate

16 Ma

Indian Plate

Burman Plate

Shan Plate

A

30 Ma


45

RESULTS

Screening Analysis of Baong and Barnett Formations

Rock-Eval analysis and petrographic data obtained from the Baong Formation show that TOC varies between 0.8 - 2% with type II kerogen, vitrinite reflectance (Rv) of 0.55 - 0.6%, HI varies from 50 - 150, and maximum temperature (Tmax) from 420 - 455o C. In addition, shales and mud-stones of the Bampo and Peutu Formations are dominantly type III kerogen with TOC ranging from 0.5% to 3% (Buck and Mc-Culloh, 1994).

Organic richness and composition of the Barnett Shale lead to an excellent to mixed oil-gas-prone source rock potential at low to moderate thermal maturity (Jarvie et al., 2005; Kinley et al, 2008). Geochemical analysis shows that the Barnett Shale tends to indicate a little unique aspects, shown by its type II kerogen, TOC 3 - 5%, vitrinite reflectance (Rv) of 1.0 - 1.4%, HI from 13 - 59, and the maximum temperature (Tmax) > 455o C (Jarvie et al., 2005).

Gas originated from the shale in Fort Worth Basin produces in two types, dry gas and wet gas. Therefore, when the organic material have a secondary cracking would be wet and when biodegradation occurs, dry gas formed. Gas produced in Barnett Shale is of thermogenic origin produced from greater depth (Montgomery et al., 2005), in the form of dry gas with a little bit of sulphur. It indicates mature hydrocarbons, shown by Tmax > 455o C . Gas yields are very high in the Barnett Shale in accordance with the abundant organic content and original hydrocarbon generation potential. Type of gas produced in the reservoir is strongly influenced by the composition of gas and isotopic carbon and the content of gas itself is directly proportional to the TOC (in the

gas window, TOC can be reduced by 30 - 50%), kerogen type, and level of maturity.

Depositional Environment

Based on stratigraphic column which has been generalized (Figure 3), in the Early Oligocene, Parapat Formation was depos-ited in a fluvial-lacustrine environment, then Bampo Formation deposited in a deep marine environment with dominant lithology comprises marine shale. Upwards, Peutu and Arum Limestone formed during the marine transgression is composed of reef and carbonate build-up. At the same time, phase of basinal slope carried sand-size material from Asahan Highs forming Belumai Formation that is overlain by deep marine Baong shale interbedded with sandy Baong itself. Above the regional seal of Middle Miocene unit, that is the Baong Formation, the Keutapang Formation was formed widespread within a shallow marine environment, which then was continued by a deposition of Seurula Formation due to rapidly shallowing basin through quantity of clastic sediment influx from the uplifted Barisan. Then from the shallow marine, the environment changed gradually to be del-taic, then to fluvial environment, where Julu Rayeu Formation was deposited. Thereby, when viewed from the bottom to Julu Rayeu Formation, it shows a coarsening upward pattern consisting of sandstones and shales in vertical succession, in general.

Figure 4 display that at the Fort Worth Basin, shelf carbonate system was deposited in the Ordovician Ellenburger Formation on a passive continental margin (Montgomery et al., 2005: Pollastro, 2007), while the Barnett Shale of Late Mississpian is char-acterized by basin edge carbonate system. Both these carbonate systems are variation of the carbonate platform. Then, during the main phase of subsidence in Pennsylvanian time, a fluctuation of sea level progressively


46

occurred represented by the deposition of Marble Falls Formation (Montgomery et al., 2005; Pollastro, 2007). Interbed-ding dark limestone and grey-black shale at lower part and limestone at upper part constitute the formation. Loucks and Rup-pel (2007) found that phosphate indicates marine upwelling. The marine upwelling is the chance of explosion of development of organisms below the sea water which is the hemipelagic plume condition by deposition of fine-sized sediment (shaly) in the sea. Exposure of carbonate sediments dominated by crinoidal carbonates, pinnacle reef, and shell material and all derived from the slope toward the hemipelagic basin (carbon-ate grains are coarser), can be originated

through the mechanism from debris flow. Some of the Ellenburger carbonates crop out to the surface.

LITHOLOGY

North Sumatra Basin located in Sumatra was filled in with sediments deposited during Oligocene through Pliocene epoch. The first formation is Basement of the basin consists of low grade metamorphics and metagrey-wacke. During Early Oligocene, the Parapat Formation was deposited, consisting of sandstone that is characterized by porosity of <5%. After that, the Bampo Formation was formed in Late Oligocene, composed of

Figure 3. Generalized stratigraphic section of North Sumatra Basin (Pertamina BPPKA, 1996).

West East

Alluvium

Holocene

Pli

ocen

e M

ioce

neO

ligo

cene

Eoc

ene

Late

Late

Late

Late

Middle

Middle

Middle

Early

Early

Early

Early

Early

Hiatus

Julu Rayeu Formation

Seurula Formation

Keutapang Formation

Baong Formation

Peutu Formation

Arun Formation

Belumai Formation

Bampo Formation

Parapat Formation

Hiatus


47

claystone. In the Early Miocene, the Peutu Limestone was conformably deposited on top of Bampo Formation. Overlying the Bampo Formation are the Arun and Belumai Formations, comprising reef and sandstone, respectively. Furthermore, the Peutu Formation consisting of limestone and Arun Formation are interbedded. Up-wards, Keutapang and Seurula Formations are present as shallow marine sandstone and shale. Finally, the Julu Rayeu Formation composed of sandstone began to be depos-ited in Pliocene (Figure 4).

On the other hand, Fort Worth Basin in Texas was infilled by sediments during Cambrian

through Cretaceous (Figure 4). Basement of the basin is composed of granite, diorite, and metasediments of Precambrian age. The first sediments occurring in Fort Worth Basin is Upper Cambrian Wilberns-Riley-Hickory Formations composed of granitic conglomerate, sandstone, and shale as ma-rine deposits. There are no Silurian and Devonian sedimentary strata recognized, probably they might be eroded. Ordovician until Lower Pennsylvanian was dominated by carbonates. Deposition of Ellenburger Group began in Lower Ordovician, fol-lowed by Simpson Group, and then Viola Limestone on Upper Ordovician. In Missis-

Figure 4. Stratigraphy of Fort Worth Basin (Pollastro, 2007).

Period Stratigraphy Unit Oil Gas

Cretaceous Undifferentiated

Permian Cisco Group

Pennsylvanian Canyon GroupStrawn SsCaddo LsPregnant ShAtoka Ss and Smithwick ShBendMarble Falls Ls

Comyn

Mississippian Barnet Shale Upper Barnett

Forestburg Ls

Lower Barnett

Ordovician Chappel Ls Simpson Gp

Ellenbuger Da/Ls

CambrianRileyHickory

Precambrian Granite & Diorite


48

sippian, Barnett Shale comprising siliceous shale, limestone, and minor dolomite, oc-curs as marine sediments, unconformably deposited on Viola Limestone (Montgomery et al., 2005). A significant proportion of limestone within the Barnett Shale called Forestburg Limestone was deposited in a series of debris flows into the deeper part of the basin (Bowker, 2002, in Montgomery et al., 2005), accompanying sea level drop, in Early Pennsylvanian. This unit interfin-gering with the middle part of the Barnett Shale tends to divide the Barnett Shale into two members, those are Lower Barnett Shale and Upper Barnett Shale. The Lower Member consists of five shale unit which is separated by the interbedded of limestone with 10 - 30 ft thick. Meanwhile the Upper Barnett Shale is thinner than Lower Barnett Shale (Figure 3).

DISCUSSION AND CONCLUSION

Fort Worth Basin has an unconventional pe-troleum system when it begins from Barnett Shale as source rock, and it regionally seals Marble Falls Limestone overlying above and Viola Limestone and Simpson Group underlying below, so that the Marble Falls, Viola Limestones, and Simpson Group could become barriers stabilizing the Barnett Shale when it began to be fractured. Moreover, the Barnett Shale itself becomes a reservoir. Barnett shale itself as source rock from it shale and from accumulation fractured El-lenburger Formation, so that Barnett Shale become a seal for Ellenburger Formation. When the system is conventional, Pennsyl-vanian rock become good quality reservoir, and the important source rock for this basin is Barnett Shale.

North Sumatra Basin has a particular way to its petroleum system. The first source rock formed is Parapat and Bampo Formations.

The Parapat Formation is fluvio-lacustrine sediments whilst the Bampo one occurs as marine sediments. Hydrocarbon began expelled through Peutu, Arun, and Belu-mai Formations, so that the Peutu -, Arun -, and Belumai Formations are present as a good quality reservoirs, when it begin to be fractured, and then hydrocarbon moved to the Baong Shale. Baong Formation become source rock from its shale and became seal of the accumulated hydrocarbon below it. So that Keutapang Formation has become both good quality source rock and regional seal rock.

Based on Peters and Cassa (1994), TOC in Baong Formation has an enough good content of organic material, whereas the TOC of Barnett Shale has very good content of organic material. Maturity of the rock sample is determined based on the pyrolysis temperature (Tmax) and vitrinite reflectance (Ro).

Determination of initial maturity of organic material is at a temperature of 435o C and pyrolysis 0.6% Ro (Peters and Cassa, 1994). From this reference, it was found that the organic content in the Baong Formation is good, but not yet mature, whereas in the Bar-nett Shale organic matter is at the end of the maturity level and both tend to produce gas based on kerogen type and its HI content.

Both Forth Worth Basin and North Sumatra Basin are almost similar in their lithology and petroleum system, but the difference be-tween them is in their age, hydrogen index, and maturity. Therefore, North Sumatra Ba-sin has a chance to become unconventional energy for the future.

ACKNOWLEDGEMENT

The paper has been presented in The 41st Annual Convention and Exhibition IAGI Yogyakarta 2012. The authors acknowledge committee of the conven-tion for permission to publish the paper in Majalah Geologi Indonesia (MGI) IAGI. Thank is due to


49

Kang Dadan who always give support to authors in writing and discussing the paper.

REFERENCES

Anderson, I., Wight, A., Friestad, H., Wicaksono, P., and Reminton, C. H., 1997. Exploration History of the Offshore Southeast Sumatra PSC, Java Sea, Indonesia. In: Fraser, A. J. et al. (Eds.), Petroleum Geology of Southeast Asia. Geological Society Spe-cial Edition, 80, p.331-371. Buck, S.P. and McCulloh, T.H., 1994. Bampo-Peutu Petroleum System, North Sumatra, Indonesia In: Magoon, L.B., and Dow, W.G. (Eds.), The Petroleum System-from Source to Trap: American Association of Petroleum Geologists Memoir, 60, p.625-637. Doust, H. and Noble, R.A., 2008. Petroleum Systems of Indonesia. Marine and Petroleum Geology, 25, p.103-129, Elsevier Science Direct. Jarvie, D. M., Hill, R., and Pollastro, R., 2003. As-sessment of the Gas Potential and Yields from Shales: the Barnett Shale Model. In: Cardott, B.J. (ed.), Unconventional Energy Resources in the Southern Midcontinent, 2004 Symposium I; Oklahoma Geo-logical Survey Circular, 110, p.37-50. Kinley, T.L., Cook, L., Breyer, J., Jarvie, D., and Busbey, A., 2008. Hydrocarbon Potential of the Barnett Shale (Mississippian), Delaware Basin, West

Texas and Southeastern New Mexico. American Association of Petroleum Geologists, Bulletin, 92 (8), p.967-991. Loucks, R. G. and Ruppel, S. C., 2007. Mississippian Barnett Shale: Lithofacies and depositional setting of a deep-water shale-gas succession in the Fort Worth Basin, Texas. American Association of Petroleum Geologists, Bulletin, 91, p.579-601.

Montgomery, S.L., Jarvie, D.M., Bowker, K.A., and Pollastro, R.M., 2005. Mississippian Barnett Shale, Fort Worth basin, north-central Texas: Gas-shale play with multi-trillion cubic foot potential. Ameri-can Association of Petroleum Geologists, Bulletin, 89(2), p.155-175. Pertamina BPPKA (ed.), 1996. Petroleum geology of Indoneisan basins principles, methods, and ap-plication. Volume I North Sumatra Basin. Pertamina BPPKA, Jakarta, Indonesia, 85pp.

Peter, K.E. and Cassa, M.R., 1994. Applied Source Rock Geochemistry. In: Magoon, L.B. and Dow, W.G. (Eds.), The Petroleum system - from source to trap; American Association of Petroleum Geologists, Memoir, 60, p.93-120.

Pollastro, R. M., 2007. Total Petroleum System As-sessment of undiscovered resources in giant Barnett Shale continuous (unconventional) gas accumula-tion, Fort Worth Basin, Texas. American Association of Petroleum Geologists, Bulletin, 91(4), p.551-578.

shale gas: geological perspective of baong formation for ... 20130104.pdf · the mergui, north...

Documents