# Introduction

n the last decade and more, shale gas resources have emerged as a viable energy source. The development of these shales changed the traditional approach geologists had been following-that of the sequence of gas first being generated in the source rock, followed by its migration into the reservoir rock in which it is trapped. The shale layer acts as both source and reservoir rock in gas reservoir, there is no need for migration and since the permeability is near zero, it forms its own seal. Large amount of gas is generated in shale layers by sedimentation of organic matter. It is important for development of shale gas reservoirs to locate such layers where gas can be generated and accumulated in a sedimentary basin as well as the sweet spot with shale gas deposits. To accomplish this, the tectonics of shale sedimentary basins have to be analyzed, along with the sedimentary environment and sequence stratigraphy. As different shale gas reservoirs have different properties, it is imperative to study them before any exploration plan is put in place.

Shale gas consists of 70-90% methane, it is often called unconventional natural gas and is taken from different rock layers than traditional gas. shale gas exploration and exploitation is governed by many factors such as the areal extent of shale layer, thickness, total organiccarbon content, kerogen type, maturity, mineralogy, brittleness verses ductility etc. integrated studies of geological, geochemical, geophysical, petrophysical, geo mechanical can help evaluating all these factors to identify the sweet spots for shale gas exploration and exploitation. The shale itself has very low permeability and, without employing fracturing technology, production well flow rates would be minimal, (Satinder et al, 2012 andHamada, 2017).

The main method of shale gas production is hydraulic fracturing, which requires a tremendous amount of water. Every shale gas well needs millions of gallons of water. The hydraulic fracturing process shoots out a mixture of water and chemicals at high pressure to extract the gas, inevitably requiring large amounts of water. Thus, the most important issue in developing shale gas in SE ASIA developing the technology to minimize water usage. In summary, it can be stated that the potential for shale gas as a source of energy in Southeast Asia appears to be good. However, more work needs to be carried out to ascertain the exact capacity of this gas in each country mentioned earlier.

For a shale gas reservoir to become a successful shale gas play, the following characteristics need to be considered: organic richness (TOC), maturation, thickness, gas in place, permeability, mineralogy, brittleness and pore pressure. An optimum combination of these factors leads to favorable productivity. Geophysical methods can help in characterizing the shale gas resource plays. However, the methodology adopted is in general quite different from methodologies applied to conventional reservoirs. In addition, the characterization of each shale reservoir could require particular types of tools and approaches to well understand the sedimentation conditions and the petrrophysical properties to meet the growing challenges and expectations of shale gas resources.

Exploration and production activity started in Southeast Asia in the beginning of the last century. Shale gas resources are widely spread across the globe, there is great interest in the economic potential for developing shale gas more widely. The main objective of this study is to discuss the potential of shale gas reserves in Malaysia and South-East Asia sedimentary basins. Shale can be a game changer in South East Asia and mainly for Malaysia, China, India, Pakistan, Indonesia and Thailand. All these countries are big importers of crude oil and shale has the potential to drastically reduce the huge import bills of these nations. However, Southeast Asia has strengthened its important role in the global energy market, due to the growing economies in the region.


# II.


# Malaysia Basins And Shale Gas Potential

Malaysia is in rapid economic growth while oil and gas is expected to play an important role in the economy towards the year 2020, when the country is expected to be fully industrialized.

Malaysia is the world's third-largest exporter of liquefied natural gas, and the second-largest oil and natural gas producer in the Southeast Asia. Malaysian sedimentary basins are major areas for potential oil and gas reservoirs as they contain many faults and natural traps, which collects and accumulate hydrocarbons under its impermeable layer. Six major Tertiary sedimentary basins are present in Malaysia: the Malay, Penyu, Sarawak, Sabah, Sandakan and a portion of Tarakan basins (Fig. 1   Peninsular Malaysia region have four main basins, The Malay Basin and the Penyu Basin are located offshore to the east of the peninsula. Other two basins, namely the Central Sumatra Basin and the North Sumatra Basin lie to the west of the peninsula and are mostly offshore with a small portion lying onshore. The Malay Basin contains about 12-km thick Neogene sediments that were deposited within the non-marine to shallow marine environment. In the Penyu Basin, oil has been discovered on horst blocks of Oligocene synrift play consisting of fluvial sandstones reservoirs.


# III. China Potential And Major Shale Gas Prospects

China is the third country gaining shale gas discovery in the world after the United States and Canada. China has a huge shale gas resources. According to some estimates, it is the world's largest reserve. China possesses 31.6 trillion cubic meters (1,115 trillion cubic feet) of technically recoverable shale gas resources(EIA, 2013).

For geographical distribution, target areas can be divided into four regions (Fig The Sichuan and Tarim Basins are two large organic rich shale plays, and other five less prospective basins are the Songliao, Bohai, Ordos, Tuha and Jungar Basins. The Sichuan Basin is considered as the most promising basin to develop shale gas in short term, because of its well-developed gas pipeline network and mature gas market.

Shale Gas Reserve potential in the Sedentary Basins of Malaysia and South-East Asia Region 


# a)

Sichuan Basin is one of the richest shale gas basins in China. Shale exploration activity in China has been focused on the Sichuan Basin, which contains marine-deposited, dry-gas mature source rock shales that resemble commercially productive shales. The Sichuan Basin covers a large 190,000-km2 area in south central China. The basin currently produces about 1.5 Bcf/d of natural gas from conventional and lowpermeability sandstones and carbonates within the Triassic Xujiahe and Feixianguan formations, from complex structural-stratigraphic traps (mainly faulted anticlines) that are distributed across the basin. Sichuan Basin is the Changning-Weiyuan area, which is found to be high in thermal evolution degree (Ro: 2.0%-4.0%), porosity (3.0%-4.8%), gas concentration (2.82-3.28 m3/t) and the burial depth is relatively moderate (1500-4500 m). ( The Sichuan Basin, primary focus for shale gas, has multiple shale targets but also significant geologic challenges, such as numerous faults, often steep dips, high tectonic stress, slow drilling in hard formations, and high H2S and CO2 in places. Table-1 data provides good control of shale thickness, depth, structural geology, thermal maturity, and organic content.

The Sichuan basin has four tectonic zones: the Northwest Depression, Central Uplift, and the East and South Fold Belts. The Central Uplift, characterized by relatively simple structure and comparatively few faults, appears to be the most attractive region for shale gas development. In contrast, the East and South Fold Belts are structurally more complex, with numerous closely spaced folds and faults.

The four-main organic-rich shale targets in the Sichuan Basin are the Lower Cambrian Qiongzhusi, Lower Silurian Longmaxi, Lower Permian Qixia, and the Upper Permian Longtan formations. (Figure 3). Most important is the Lower Silurian Longmaxi Formation, which contains an average 300 m of organically rich, black, graptolitic-bearing, siliceous to cherty shale. TOC is mostly low to moderate, reaching 4% and consisting mainly of Type II kerogen (Liu et al., 2011). Thermal maturity ishigh and increases with depth, ranging from dry gas prone to over mature (Ro 2.4% to 3.6%).

Another shale gas target in the Sichuan Basin is the Cambrian Qiongzhusi Formation. Even though deeper than the Longmaxi and mostly screened out by the 5-km depth, the Qiongzhusi contains high-quality source rocks that provide stacked shale resource potential. The formation was deposited under shallow marine continental shelf conditions and has an overall thickness of 250 to 600m.  The Tarim Basin, located in the Xinjiang Autonomous Region, is China's largest onshore sedimentary basin (600,000 km2, the Tarim Basin produces 260,000 B/D of oil and 1.6 Bcfd of natural gas from conventional reservoirs, which were sourced mainly by organic-rich Cambrian and Ordovician shales. Figure 7 shows the structural elements of the Tarim Basin, and Prospective of shale gas.

The Tarim Basin is sub-divided by fault and fold systems into a series of seven distinct structural zones, comprising three uplifts and four depressions.  


# India Shale Gas Potential

Natural gas is rapidly substituting fuel to suffice the growing energy requirement of today's world. As the consumption of natural gas is increasing rapidly, it is essential to identify and develop the available energy resources. India has the huge prospects of unconventional shale gas resources. Commercial exploration of these shale gas resources can effectively make the global natural gas curve more elastic.

There is a sizeable deposit of shale formations in several sedimentary basins of India with different total organic (TOC) content and maturity history. The Cambay, Krishna-Godavari, Cauvery and Damodar valley are the four major basins of shale gas reservoirs as indicated by considerable thickness of shales; sufficient TOC (2 to 6 wt%) content; and good thermal maturity with vitrinite reflectance of more than 1.0. (Ind., 2014). The reservoir properties and resource potential (290 TCF) of shale gas, estimated by ARI, are shown in Table-3.

According to ARI (American Research Institute), shale gas reserves would be anywhere between 600 Tcf to 2000 Tcf and technically recoverable shale gas resource is estimated as 63 Tcf in spread over many sedimentary basins India. Most of Indian basins especially the Cambay, Krishna-Godavari, Cauvery and Damodar Valley have good prospects of shale gas (Fig. 9). Several other basins such as the Vindhyan, Upper Assam, Pranhita-Godavari and Rajasthan, though show thermal immaturity, contain measurable thickness of shale with good TOC content. 


# b)

It is located on the east coast of India; land part covers an area of 15000 sq. km and the offshore part covers an area of 25,000 sq. km. Shale in the Krishna Godavari Basin is limited to the four grabens (subbasins) where the thermal maturity is sufficiently high for wet to dry gas generation. (Mahto, 2014) Estimated risked shale gas in place is of 136 Tcf, with a risked technically recoverable resource of 27 Tcf.


# c)

The Cauvery basin covers an area (25,000 sq.km) and shallow offshore areas (30,000 sq. km). The basin contains a thick interval of organic rich source rocks in Lower Cretaceous Andimadam and Sattapadi shale formations. The oldest rocks in the Cauvery Basin : are the shallow marine, late Jurassic sediments and early Cretaceous deposits. Average resource around 43 Tcf of risked shale gas in-place is estimated of which 9 Tcf is considered technically recoverable.


# d)

The Damodar Valley Basin is part of a group of basins collectively named as Gondwanas. (Pradhan, 2015) The Gondwanas, comprising the Satpura, Pranhita-Godavari, Son-Mahanadi and Damodar Basins. In this basin around 33 Tcf of risked shale gas in-place is estimated of which 7 Tcf is considered technically recoverable.


# e)

The Southern Indus Basin is in southern Pakistan adjacent to the border with India. Southern Indus Basin has five commercial oil discoveries and one gas discovery in the conventional Cretaceous-age and three gas discoveries and one gas condensate discovery in shallower formations. Moreover, with the help of this technology the well can drain shale gas resources from a geographical area that is much larger than a single vertical well within the same shale formation.  The Lower Indus basin has two types of shale formations, which are Sembar and Ranikotformation. Within the overall prospective area of the Lower Indus Basin, the Sembar Shale has risked shale gas in-place of 531 Tcf, with 101 Tcf as the risked, technically recoverable shale gas resource. In addition, prospective area of the Lower Indus Basin, the Ranikot Shale has 55 Tcf of risked shale gas in-place and 82 billion barrels of risked shale oil in-place.


# Cambay Basin Krishna Godavari Basin
Cauvery
Sembar Formation

? It mainly consists of clastic rocks, typically shale with lesser quantities of siltstone and sandstone in the Lower Indus. The sand content increases towards the Southeast in the Lower Indus Basin. However, in the Middle Indus Basin, the formation is composed of siltstone with few marl and shales.

? Shale in Sembar Formation is basically medium hard, pyritic, moderately indurated and slightly calcareous in the area. The gross thickness varies from >50m to800 m. ? The TOC and thermal maturity (Ro) of Sembar formation as per exploration targets is around 2% and 1%-1.6% respectively. ? The shale in Paleocene Ranikot Formations is primarily upper carbonate unit, which is tailored with fossiliferous limestone inter-bedded with dolomitic shale, calcareous sandstone and abundant bituminous material. ? The prospective area of the Ranikot formation has a thickness of around 1,000-3,000ft with net shale thickness of 200 ft.


# Ranikot Formation

i.

ii.


# Lower Indus Basin

Global Journal of Researches in Engineering ( ) Volume XVII Issue IV Version I VI.


# Thailand

This large Southeast Asian country has significant prospective shale gas potential. Nearly 90% of its current petroleum output comes from offshore fields in the Gulf of Thailand, with only limited production from small onshore fields. Approximately 40% of Thailand's primary energy consumption is supplied by natural gas.

Thailand's greatest potential appears to be shale gas deposits contained in Permian and Triassic shale source rocks in the Khorat, the country's largest onshore sedimentary basin. (Jeenagool, 2015) These shales can be locally thick, organic-rich, dry gas prone, deeply buried, and overpressure.

Thailand has three main onshore sedimentary basins which may have unconventional oil and gas potential, Figure -13. These include the large Khorat Basin in the northeast; a series of smaller, isolated pullapart basins in the Northern Intermontane Basin, where shale oil deposits are being mined; and the similarly complex Central Plains Basin.

The Khorat Basin in northeast Thailand has an estimated 5 Tcf of risked technically recoverable shale gas resources. While no shale gas/oil exploration activity has been reported to date. The structural Khorat Basin depression was initiated during the Middle Paleozoic, with widespread deposition of clastic and carbonate sedimentary rocks, beginning with the Carboniferous Si That Formation.  Fluvial and lacustrine deposits of the Triassic Kuchinarai Group also have been identified as petroleum source rocks in the Khorat Basin, with high-TOC intervals. The Kuchinarai Group reportedly averages a prospective 6,500 to 7,000 feet deep within the basin. Thermal maturity modeling suggests it reaches the dry gas window, with no liquids potential (Ro> 2.0%).  


# Indonesia Shale Gas Potential

Indonesia is the world's fourth most populous country (250 million) and a major producer of coal, oil, and natural gas. Indonesia has shale gas and shale oil potential within selected marine-deposited formations, as well as more extensive shale resources within nonmarine and often coaly shale deposits, Estimated 46 Tcf technically recoverable shale gas resources out of 303 Tcf of risked shale gas in-place. in central and western Indonesia. (Fig. 15 shows Stratigraphy of Source Rocks) 


# a)

The Bintuni Basin, located in the eastern side of the Bird's Head region, appears to have the simplest structural conditions and best shale prospectively in the eastern Indonesia region. The stratigraphic section resembles that of the Salawati Basin, with preserved Paleozoic, Mesozoic, and Tertiary units. The prospective areas of the Permian Aifam formation have an estimated 29 TCF of technically recoverable shale gas resources out of 114 Tcf of gas in-place. (Kuuskraa V. S., 2013) This marine-deposited unit could be the best shale gas target in Indonesia. To date No shale gas/oil leasing or exploration activity has been reported in eastern Indonesia.


# b)

Sumatra has shale oil and gas potential in three deep basin complexes: The North, Central, and South Sumatra basins. The North Sumatra Basin produces mainly conventional gas both onshore and offshore. Central Sumatra Basin one of main resources in Shale gas with technically recoverable resources from the Brown Shale are estimated at 3.3 Tcf out of 42 Tcf shale gas.

South Sumatra Basin, this basin is a significant conventional oil and gas producing area as well as a focus of Shale gas & coalbed methane exploration. The basin contains late Eocene to early Oligocene deposits of clastic sediments in transgressional pull-apart depressions. The Eocene to Oligocene TalangAkar Formation is prospective within a large 15,490-mi2 area and estimated to have a 367-ft thick high-graded zone with average 5% TOC and 0.7% Ro. The pressure gradient is normal and the clay content is considered high. The TalangAkar Formation has an estimated 4.1 of technically recoverable shale gas resources, out of 68 Tcf.


# VIII.


# Conclusion

? Shale gas refers to natural gas in organic rich fine grained rocks (shale and/or mud rock). Gas stored in shale as: 1) adsorbed gas attached to organic matter, 2) free gas in matrix pores, micro pores and natural; fractures and 3) solution gas in liquids such as bitumen and oil. For shale gas, hydraulic

Shale Gas Reserve potential in the Sedentary Basins of Malaysia and South-East Asia Region Tarakan basins in Kalimantan; most reserve of shale gas in the eastern part (Salawati, Bintuni, Tomori) but it structurally complex basins. Other basins in Indonesia appear to be less prospective due to low TOC, high clay and CO2 contents Many of Indonesia's organic-rich shales are non-marine coaly deposits that may not be brittle enough for shale development. Their depositional setting ranges from deepwater marine in eastern Indonesia to mostly lacustrine and deltaic environments Indonesia has shale gas within selected marinedeposited formations, more extensive shale resources. The petroleum source rocks in onshore Indonesian basins are relatively young, mostly Eocene to Pliocene. (Rahmalia, 2012) Indonesia have many onshore sedimentary basins (Figure 15) which may have shale gas potential, these include the Central and South Sumatra basins on Sumatra Island; the Kutei and ? The economic feasibility of shale gas as unconventional resources is highly dependent on the price of conventional resources, and the assumption that the price will remain at a certain level for some time to come. Available technology and development plans have great impact on the forecasting of unconventional resources either as complement or replacement of the conventional resources. considered: organic richness (TOC), maturation, thickness, gas in place, permeability, mineralogy, brittleness and pore pressure. An optimum combination of these factors leads to favorable productivity. Geophysical methods can help in characterizing the shale gas resource plays ? Shale gas reservoir to become a successful shale gas play, the following characteristics need to be fracturing of a reservoir is the preferred stimulation method.
![) (EIA, 2013). Of these basins, only in Sarawak and Sabah basins have been proven to contain significant Shale gas accumulations that have been discovered. The six basins are grouped into three main regions: Peninsular basin, Sarawak & Sabah basin. Sarawak and Sabah basins area have been identified as a potential for unconventional play but in the early stage of exploration and no drilled wells to test the play. East Malaysia of sabah and Sarwak is a huge area totaling almost 200,000 sq km making up approximately 60 % of the Malaysia land mass. Based on preliminary resource assessment, Malaysia has an estimated hydrocarbon initial in place of 8.8 Tcf shale gas resources. (PETRONAS, 2016). The development of unconventional gas resources especially shale gasis still under study.](image-2.png "")
12![Figure 1: Sedimentary Basins in Malaysia (CCOP, 2010)](image-3.png "Figure 1 :Figure 2 :")
3![Figure 3: Location map of Sarawak and Sabah basins (IEA,1994)](image-4.png "Figure 3 :")
4![Figure 4: Basins in China (Wang and Wang, 2011) The estimated amount of technically recoverable gas in two China shale basins shown in Fig. 5, Tarim and Sichuan, rank the country among the world's richest. The EIA study estimated that the Sichuan and Tarim basins hold 1,275 Tcf of technically recoverable gas, assuming that about 25% of the gas can be produced. The Sichuan and Tarim Basins are two large organic rich shale plays, and other five less prospective](image-5.png "Figure 4 :")
56![Figure 5: Shale Geographic Distribution in China(Zhang, 2010) ](image-6.png "Figure 5 :Figure 6 :")
2![Stratigraphy of Source Rock Shale Targets in the Sichuan Basin b) marine deposited black shales of Cambrian and particularly Ordovician age are considered the most important source rocks in the basin. (Cai et al., 2009)Tarim and the Northern China area are marine deposits often have high organic matter content and Ro value of 1.1%-2.5%. the organic matter is mostly II-III type kerogen. while those in the Tarim average 13,500 ft. deep. (Rassenfoss, Jul 2012).By 2020, China's annual shale gas production will be expected to reach 300 × 10^8 m3. No shale leasing or drilling have beenreported, probably because of this basin's remoteness and extreme depth of the shale..](image-7.png "Table 2 :")
7![Figure 7: Shale Prospective Areas in the Tarim Basin (ARI, 2013)](image-8.png "Figure 7 :")
![(Xiao et al., 2000) Petroleum source rocks are found in the Cambrian, Ordovician, Carboniferous Triassic, Cretaceous, and Tertiary, Figure8 shows which the Tarim Basin Global Journal of Researches in Engineering ( ) Volume XVII Issue](image-9.png "")
8![Figure 8: Stratigraphy of the Tarim Basin, Highlighting Prospective Cambrian, Ordovician, Carboniferous, Triassic, Cretaceous, and Tertiary Source Rocks](image-10.png "Figure 8 :")
9![Figure 9 Shale gas basins of India (US EIA 2011)](image-11.png "Figure 9")
310![Figure 10 : General stratigraphic column of the Cambay Basin (Sivan et al., 2008) India has vast resources of shale gas and it is mainly untapped due to strict government policies, lack of new technologies & technical expertise and lack of interest from the industry. But, it is essential to explore and exploit the shale due growing energy needs in the country. Cambay, Krishna Godavari, Cauvery and the Damodar Valley are the most prospective](image-12.png "3 :Figure 10 :")
11![Figure 11: Shale gas Potential in Pakistan (ARI, 2013) Shale gas and oil assessment is restricted to the extensive in Central and Southern Indus basins, together called the Lower Indus Basin. (Kuuskraa V. S., 2013)The shales in this basin have sourced the significant volumes of conventional oil and gas discovered and produced in Pakistan. However, no shale specific exploration has been publicly reported for Pakistan.Shale gas and oil assessment is restricted to the extensive in Central and Southern Indus basins, together called the Lower Indus Basin. (Kuuskraa V. S., 2013)The shales in this basin have sourced the significant volumes of conventional oil and gas discovered and produced in Pakistan. However, no shale specific exploration has been publicly reported for Pakistan.](image-13.png "Figure 11 :")
12![Figure 12: Stratigraphic Column for Pakistan (EIA, 2013)](image-14.png "Figure 12 :")
13![Figure 13: Thailand sedimentary basin (EIA, 2013)](image-15.png "Figure 13 :")
4![Figure 14 illustrates the stratigraphy and petroleum systems of the Khorat Basin.The shallow marine to basinal Permian Saraburi Group is considered the primary source rock, while the fluvial to lacustrine Triassic Kuchinarai and HuaiHinLat Groups offer additional source rock potential. Permian dolomite and karstedlimestones form the main conventional petroleum reservoirs.](image-16.png "ShaleTable 4 :")
14![Figure 14: Stratigraphy an Petroleum Systems of the Khorat Basin. Shallow Marine Permian Saraburi Group is the Primary Source Rock](image-17.png "Figure 14 :")
15![Figure 15: Shale gas Potential in Indonesia (EIA 2013) Indonesia has two main shale gas potentials, which are Bintuni basin and Sumatra Basin.](image-18.png "Figure 15 :")
![](image-19.png "")
![](image-20.png "")


1Year 201742IV Version I( ) Volume XVII Issue JGlobal Journal of Researches in EngineeringSichuan BasinZou C. D., 2010) The EIA shale report assessment said the shale formations in the Sichuan shale are, on average, around 11,000 ft. deep. Sichuan basins technically recoverable resources which are 17. 716 trillion of cubic meters. (Xin-gang, 2015). Some available data on this basin are are summarized in Table1.
CountryBasinRisked Gas in place TCFMalaysiaSarawak & Sabah8.8SichuanChinaTarim1,115OrdosCambay146IndiaGodavari Cauvery381 30Damodar27PakistanIndus, Balochistan & Pasheen105ThailandKhorat22IndonesiaSumatra Bintumi68 114
			© 2017 Global Journals Inc. (US)Shale Gas Reserve potential in the Sedentary Basins of Malaysia and South-East Asia Region
			© 2017 Global Journals Inc. (US)
			Shale Gas Reserve potential in the Sedentary Basins of Malaysia and South-East Asia Region © 2017 Global Journals Inc. (US)
		
		

			

## Acknowledgment

The authors would like to address sincere thanks to Shale Gas Research Group, MOREOR, Universit Teknology Petronas for the continuous support for this work.

			

			

				


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