QCB 4013 Regional and Petroleum Geology of Malaysia and Southeast Asia - May 2021 Semester PDF

OFFSHORE BASIN PENINSULA MALAY BASIN MOHD SUHAILI ISMAIL QCB 4013 REGIONAL AND PETROLEUM GEOLOGY OF MALAYSIA AND SOUTHEAST ASIA MAY 2021 SEMESTER INTRODUCTION : MALAY BASIN Located in the southern part of the Gulf of Thailand, between Vietnam and Penin...

OFFSHORE BASIN PENINSULA MALAY BASIN MOHD SUHAILI ISMAIL QCB 4013 REGIONAL AND PETROLEUM GEOLOGY OF MALAYSIA AND SOUTHEAST ASIA MAY 2021 SEMESTER INTRODUCTION : MALAY BASIN Located in the southern part of the Gulf of Thailand, between Vietnam and Peninsula Malaysia Covers an area of 80000 km2 , filled with about 14 km thick sediment. Continues northwestwards to merge with Thailand’s Pattani Trough and southeastwards with the Indonesia’s West Natuna Basin. Petroleum exploration in the Malay basin began in 1968. Many oil and gas accumulations have been discovered, several are producing EXPLORATION HISTORY First concession were awarded to Essso and Conoco in 1968. Esso operated in the area north of 5o N latitude while Conoco was given the area to the south which includes the Penyu Basin.. Starting in 1974, exploration were awarded to oil companies under production-sharing contracts In 1969, Esso drilled its first well, Tapis-1, followed by Tapis-2 (1974) in the southern part of the basin. Tapis-1 found gas in sandstones, Tapis-2 found oil Continuous exploration found the first significant oil discoveries at Seligi and Bekok. First oil production came from Pulai and Tapis field in 1978. EXPLORATION HISTORY Seligi is the largest oil field in the basin, with over 550 MMSTB EUR Further drilling resulted in the discovery of the Angsi, Besar, Palas, Guntong,Irong, Irong Barat, Semangkok, Tinggi and Dulang fields. By the end of 1997, some 330 exploration wells were drilled. Exploration had discovered some 50 oil and 30 gas accumulations.   Malay Basin is located at the centre of Sundaland.  One of the deepest continental extensional basins in the region.  Believed to have formed during early Tertiary. TECTONIC  The Tenggol Arch separates it from the Penyu Basin, the Narathiwat High separate it from the Pattani Basin. FRAMEWORK  Elongate NW-SE trending basin, underlain by a pre- Tertiary basement of metamorphic, igneous and sedimentary rocks.  Basement rocks believed to be the offshore continuation of the geology of eastern Peninsular Malaysia.   Bounded by relatively shallow ( < 1.5 km) basement areas:  Terengganu Platform and Tenggol Arch to the southwest  The Narathiwat High to the northwest  Con Son Swell to the northeast TECTONIC  Complexed rift composed of numerous extensional grabens interpreted from geophysics data because of FRAMEWORK their great depths (not penetrated by drilling)  Some smaller grabens identified from seismic mapping on the west-central margin.  Pre-Tertiary basement shallows to the southeast as a result of late Middle Miocene tectonic deformation and uplift which resulted in numerous compressional anticlines.   Various tectonic models have been proposed for the origin of the Malay Basin.  The model by Tjia (199) is refer to as the triple junction model in which the Malay Basin together with the Penyu and West Natuna basins, were formed as a failed rift arms of triple junction above a Late Cretaceous thermal dome (mantle hot spot)  This model interpreted that there is a hot spot located at the triple TECTONIC junction of the three basins based on diastrophic activities onshore and offshore Peninsular. ORIGIN  The hot spot presumably composed of a mantle plume appears to have developed a “circular regional uplift” (names as the Malay Dome).  In plate tectonic theory, the T-shaped rift arms may spread out and produces ocean basins. In the case of the Malay Basin, Penyu, w.Natuna, the rift arms spread out to form regional grabens radiating from the triple junction and become depocenter for sediment deposition.   Malay Basin strata are subdivided informally into seismostratigraphic units where each unit is known as Group.  Groups are designated alphabetically in order of increasing age, from A to M.  Stratigraphic development is directly related to its structural STRATIGRAPHY evolution, which occurred in 3 phases:  A pre-Miocene extensional or synrift phase  An Early to Middle Miocene thermal/tectonic subsidence phase  A Late Miocene –Quaternary subsidence phase (which presents a tectonically quiescent period.   MIOCENE PHASE  Represents the extensional phase of basin development, during which subsidence is controlled by faulting  Initially, sedimentation in isolated half graben depocenters deposited thick synrift successions of alternating sand-dominated and shale-dominated, fluviolacustrine sequences.  Group M to K fill the extensional sub-basins comprised the STRATIGRAPHY deposits of braided streams, coastal plains, lacustrine deltas and lakes.  Extensional faulting ceased during the Late Oligocene but continued thermal subsidence resulted in the deposition of Groups L to D.  Basin was probably at or near sea level by Early Miocene times, indicated by abundance of coal-bearing strata in the succession.   EARLY –MIDDLE MIOCENE PHASE  Period of thermal/tectonic subsidence accompanied by compressional deformation which resulted in local inversion of half grabens by re-activation of their bounding faults, and a major uplift in the southeastern part of the basin. STRATIGRAPHY  An unconformity truncated the folded and uplifted strata as old as Group H in the southern part of the basin.  The unconformity is overlain by undeformed marine sediment of Groups A and B.  LATE MIOCENE – QUATERNARY PHASE  Phase of gentle subsidence without significant tectonic activity.  Fully open marine conditions were established.  Group A and Group B consists of predominantly marine clays and silts deposited during an overall marine transgression in near shore to shallow marine. STRATIGRAPHY  Reconstruction of the palaeogeographic development of the Malay Basin shows progression from mainly nonmarine (alluvial to coastal plain) environments during Oligocene (Groups L and M), which is the synrift basin development phase, to increasingly marine environments (coastal fluviomarine to inner neritic) during the Miocene and later (Groups K to A/B).  Malay Basin was a narrow seaway or gulf that received sediment from its northeastern and southwestern flanks.  Southern part of the basin contains most the oil reserves, including several giant fields such as Seligi and Tapis (both have EURs of almost 600 MMSTB). Hydrocarbons occur in reservoirs from Group L to D. Group E, I, J and K are the most prolific. Geographically, the basin can be generally subdivided into a northern gas prone province and a southern oil-prone province although there are exceptions. On a regional scale, the geographic and stratigraphic HYDROCARBON distribution oil ands gas appears to be controlled by basin morphology. OCCURENCES On a semi-regional scale, the main factors controlling oil and gas distribution include source-rock quality and maturity, and the relative timing of generation and structuration. The effective source rocks are coaly in the north (mainly in Group I) and lacustrine in the south (Groups K, L, and M). Relative timing between structuration and hydrocarbon migration varies from south to north Structures were formed earlier in the south thus were able to trap oil, whereas late structuration in the north resulted in more gas being trapped.  Hydrocarbon occurrences in the Malay basin may be categorised according to the structural style of the traps HYDROCARBON Main structural trap styles are mostly PLAYS AND compressional anticlines and fault dip closures. In the following slides, trap styles and TRAP STYLES hydrocarbon plays are categorised based on structural features, geographic and stratigraphic distribution, and source-reservoir relationships. COMPRESSIONAL ANTICLINES Most prolific trap style Comprises E-W trending anticlines formed by inverted grabens. Are located mainly along the central/axial part of the basin. Formed during the basin inversion phase in the Middle Miocene (beginning of Group F times. Most of the anticlines are the result of wrench movement associated with transpressional deformation of the underlying fault-bounded half- grabens. Clearly observed in the southern part of the basin. Many major discoveries in the Malay basin are of this play e.g. Tabu, Irong, Jambu, Seligi, Tapis COMPRESSIONAL ANTICLINES Hydrocarbon occurrences and distribution of traps styles/play types in the Malay Basin. Compressional anticlines in the south are more oil-prone while in the north are gas prone. Main reservoirs are shallow marine and fluvial sandstone of Structures are seal by intra- group H, I, J,K. group claystone and shale Hydrocarbon in these structures beds. were sourced from interbedded carbonaceous shales and coals mainly in Group 1. COMPRESSIONAL ANTICLINES Hydrocarbon occurrences and distribution of traps styles/play types in the southern part of Malay Basin showing major oil and gas trends COMPRESSIONAL ANTICLINES – CENTRAL PART Compressional anticlines in the Central part of basin involve reservoirs generally formed by shallow marine sandstones of Group D and E. Seals are interbedded claystone and shale units within Group D and E. Source rocks are deeply buried rocks in Group 1, migrating vertically through fault conduits. Examples of this play are Bintang, Lawit, Jerneh, Dulang, Sepat, Noring,Bujang, Ular, Tangga, Bergading, Inas, COMPRESSIONAL ANTICLINES – SOUTHWESTERN PART Southwestern part is a major gas trend close to the Tenggol Fault. It is the Angsi-Duyong trend which includes major gas discoveries of Angsi and Besar. These are large compressional anticlines and are structurally similar to those in the main oil province to the north. Are underlain by synrift hal-grabens controlled by normal faults. Only Duyong is currently producing  Tenggol Arch is a relatively shallow and flat, NW-trending pre- Tertiary basement that separates the Malay and Penyu basins. Its northeastern boundary is marked by the Tenggol Fault, a major normal fault zone with a maximum throw of about 2500 m. Source of sediment for the half-grabens in the north. TENGGOL ARCH Relatively featureless except for isolated basement mounds of which some of them become structural closures when Tertiary sediments are draped over them upon compaction. PLAYS The basement drapes form a unique trap style in which oil has been discovered in one of the structures at Malong, where it occurs in the Group J shallow marine sandstones. Hydrocarbon at Malong are probably charged from Group K or older lacustrine shales in the basin across the Tenggol Fault, migrated up-dip onto the Tenggol Arch. Interbedded shales provide the top seal for drape structures.  Sedimentary succession on the Tenggol Arch is generally less than 1500 m thick, any potential rock will be immatured. Thus, the malong oil may have come from deeper half-grabens, situated in the northeast of the Tenggol Fault. TENGGOL ARCH The migration distance to the Malong structure is at most 10 km. PLAYS Malong discovery spur interest in the other basement structures on the arch with the assumption that oil migrated over long distances (30-60 km) from the Malay Basin to fill up the structures. However, some of the sbasement structures were tested and found to be dry thus the migration model need to revised. TENGGOL ARCH PLAYS  NE RAMP MARGIN PLAY 19 oil and 15 gas discoveries were made in the northeastern flank of the Malay Basin. The major trap styles include subtle stratigraphic/fault traps in Group I, J and K such as Larut and Bunga Raya field. Faulted anticlinal traps in Group I, J, K reservoirs occur in the northeastern and eastern parts parts of the basin. Lateral seal is provided by sand-shale juxtaposition Top seal is provided by the interbedded shale. Hydrocarbons are sourced either from in situ interbedded source beds or from beds down-dip (Group K and L shales) via long range migration. Eg of these trap style are Bunga Orkid, Bunga Kekwa and Bunga Raya oilfields (PM3 CAA area), Lerek, Pantai, lumut, east Belumut, Larut, Abu oilfields in PM5 and PM8. NE RAMP MARGIN PLAY Other trap styles include traps formed by basement drapes, similar to those on the Tenggol Arc. Example is the South Raya Field, oil and gas have been found in Group I, J, K reservoirs Stratigraphic channel plays, eg Bindu discovery. Stratigraphic pinch-out trap. Onlap trap. DEEP RESERVOIR PLAY This play type involves reservoirs within or below the overpressured zone, thought to be present beneath existing discoveries/fields. The Bergading structure, an example of a normal fault bounded N-trending anticline, located in northern part of the basin (near JDA). Bergading-1 well found gas in Group B, D, E. Bergading Deep-1 well was drilled to about 3100 m, successfully penetrated the overpressured zone in Group F. Substantial amounts of gas and condensate were found in Group H and I reservoirs.  Hydrocarbons in the Malay Basin are found in sandstone reservoirs of Group D down to K. Depositional environment of the sandstones vary with stratigraphy. RESERVOIR In older groups (K,L,M) reservoirs are formed, mainly ROCKS fluvial channels in a nonmarine-lacustrine setting. In J and younger groups, sandstones are predominantly shoreface and subtidal shelf sands (esp in J) and fluvial-deltaic to estuarine channel complexes (I group and younger). RESERVOIR ROCKS  The abundant oil and gas reserves in the Malay Basin give testimony to the presence of effective source rocks. Geochemical studies indicated two main depositional settings for source rocks – lacustrine and fluviodeltaic, with varying degree of mixing between the two end- members. Lacustrine source rocks: consist of shales rich in algal components. Occur in Oligocene/Early Miocene K, L, M and pre SOURCE ROCKS M/synrift groups. Have only been penetrated at shallow depths on the flanks of the basin. Fluviodeltaic source rocks: Found mainly in the Lower-Middle Miocene I and E groups, Mainly in coastal plain shales and coal/carbonaceous shales. Are encountered in the basin centre.  The Malay basin is not purely an oil province but also contains several large gas accumulations. Natural gas is estimated to represent more than half of the hydrocarbon reserves of the basin. Total gas reserve in place is estimated to exceed 60 TSCF. Large propotion of the reserve is in the Jernih, Lawit, Duyong and Seligi fields. Largest gas accumulations occur mainly in the reservoirs of Group D, E, I and J. NATURAL GASES Northwestern part, gas found in stratigraphically younger reservoirs, in the south occur in older/deeper reservoirs. Biogenic gas are mainly confined to the eastern flank of the basin within Group H and older units. Thermogenic gas generated from source rocks, maybe generated by kerogen decomposition or derived from the cracking of oils. The Malay Basin gases may be classified into three stratigraphic groupings: Group E and younger rocks, Group H and I gases, and Pre-Group I gases. THANK YOU