The continental shelf of Vietnam comprises several major Tertiary basins, of which the petroleum potential has been confirmed including Song Hong Basin, Phu Khanh Basin, Cuu Long Basin, Nam Con Son Basin and Malay-Tho Chu Basin.
            Recent studies indicated the estimated reserves and resources, both onshore and offshore Vietnam to be 3-4 billion cubic metres (BCM) of oil and gas, comprising 0.9-1.2 BCM of oil and 2.1-2.8 BCM of natural gas. About 50 oil and gas prospects have been found with reserves of approximately 3 billions barrels of oil and 23 TCF of natural gas. Commercial oil has been discovered and produced in Cuu Long, Nam Con Son and Malay-Tho Chu Basins, while commercial gas is being produced in Song Hong and developed in Nam Con Son and Malay-Tho Chu Basins.
            Cuu Long Basin is now considered to be mature, with greater than 50% probability that more than 50% of the total petroleum in the region has been discovered, generally covered by extensive seismic grid and high drilling density. Submature regions such as Song Hong, Nam Con Son and Malay-Tho Chu Basins have a greater than 50% probability that less than 50% of the region's total petroleum resources has been discovered with medium seismic and drilling density. Phu Khanh Basin and frontier areas are those without petroleum discoveries, where seismic coverage is sparse and with few wells drilled.
  Regional Geological Setting
  Tectonic Evolution
            The Vietnam continental shelf area constitutes a part of a system of Cenozoic sedimentary basins that lies within a transition zone from the continental crust of the Indochina Craton to the sub oceanic crust of the eastern deep water basins. The basins developed here are rift basins with multiphase history. Tectonic evolution of the East Vietnam Sea Cenozoic Basins can be divided into the following main stages:
            1. Late Cretaceous-Eocene: pre rift uplift/initial rifting phase. The major tectonic event is the collision of India and Eurasia, resulted in the southeastward extrusion in Indochina, represented by strike-slip movements. In Late Eocene a change in the spreading direction in the SE Pacific resulted in the development of a new NE-SW subduction zone.
            2. Late Eocene-Oligocene: main rifting phase/initial ocean floor spreading phase. This was the most powerful, resulted in the development of most of the main structure elements in the basins. The dominating style of the deformation was extension and transtensional.
            3. Early-Middle Miocene: regional subsidence/renewed rifting. In the majority of the basins, there happened a shift from the rift to the thermally controlled high-rate subsidence. Significant tectonic pulses occurred at the end of this period marking a major inter basinal inversion event.
            4. Late Miocene: partial inversion/regional subsidence. During this stage, the whole area became dominated by compression, which, in combination with the dextral strike-slip fault system east offshore Vietnam, might be the driving force for the contemporary basin uplift and partial inversion in most of the basins.
            5. Pliocene-Pleistocene: regional subsidence/renewed rifting. The tectonic activity at that stage was diverse in different basins, from low to moderate-amplitude differential uplift. The high-rate fault bounded subsidence in the outer area can be considered as the rifting activation phase associated with the spreading of the deepwater basins.
  Depositional Evolution
            The main regular sedimentation along Indochina margin were defined by rate of subsidence and structure of the basement, location of large river system of the South East Asia, eustatic sea level changes and paleoclimate factor. The basins are characterised by high sedimentation rates, abrupt facies changes, abrupt thickening of sedimentary sequences over short ranges, numerous unconformities and scattered volcanic/extrusive activity.
            1. Palaeocene-Eocene: sediments with great thickness were deposited in the fluvial-lacustrine/coastal plain/deltaic conditions
            2. Oligocene: time of maximum development of the non-marine to transitive deltaic/coastal plain conditions, including lacustrine and estuarine environments, which posses the main source potential in the basins all over the Indochina margin.
            3. Early-Middle Miocene: within the period, sedimentation was simultaneous with a sea level eustatic rise. The rifting caused a rapid increase in subsidence rate in all the basins, resulted in the westward regression of the delta/coastal plain systems.
            4. Late Miocene: the marine transgressive deposition continued, but its rate was reduced. The shelf edge carbonate platforms were deposited in most of southern basins.
            5. Pliocene-Pleistocene: sediment input increased, associated with high-rate of subsidence in almost all the basins. Rapid eastwards progradation of the shelf edge of the basins were accompanied by deposition of submarine fan slope systems.
  Location of Tertiary Basins in Vietnam
  Song Hong Basin
  Geological Development
            Song Hong Basin, the largest Tertiary basin in the continental shelf of Vietnam, is classified as a pull-apart system, filled up with up to 15,000 m of Eocene to Recent sediment, evolving in several phases throughout Oligocene to Pliocene times. The onset of the basin's formation is related to the collision of the Indian sub-continent with Asia during the Late Eocene.
            Left lateral strike-slip and pull apart along the Song Hong Fault Zone in which two main fault systems formed the eastern and western limits of its main depocentre controlled the shape of the basin. The Eocene-Oligocene marked the major rifting phase. Sedimentation was primarily in fluvio-lacustrine environment, reflecting the restricted nature of the basin coupled with rapid sediment filling.

            The Early-Middle Miocene was a quiescent marine sedimentation period. Carbonate development along shelf boundary prolonged and backstepped in areas during the Middle Miocene sea level transgression. Throughout the Late Miocene to Plio-Pleistocene, abundant clastic sediment continued as a result of thermal contraction and subsidence.
  Petroleum System
            Two potential source rocks have been identified in the basin: Oligocene lacustrine oil prone shales and Oligo-Miocene deltaic/paralic gas-prone coals/coaly shales. Modeling results indicate that most of the basin is mature for gas (Kerogen type III/II). Paleogene sediments are mature for oil only in the northwestern part and in some of the half-graben area in the western margin of the basin.

            Reservoirs in the basin comprised predominantly of Miocene/Oligocene clastic sediments associated with rifting and subsequent thermal contraction and sag. The carbonates including carbonate build-ups and reefs can be found in the basin's central parts or margins where uplift has occurred caused by listric faulting. Fractured basement could also be an exploration target.

            The major trap types in Song Hong basin are rollover folds, tilted fault blocks, basement high and carbonates buildups. The dominant seal in the Song Hong Basin is the Tertiary seal and although there is very little regionally correlatable shale across the basin, local shales forming intraformational seals are numerous and appear to be very competent.
            Song Hong Basin is assessed to contain 15% of the total hydrocarbon resources of Vietnam. The major petroleum plays in the Song Hong Basin include:
  • Pre-Tertiary fractured granite drape across basement high blocks
  • Oligocene/Miocene sandstones structure associated with tilted fault blocks, basement blocks or inversion
  • Oligocene/Miocene sandstones stratigraphic plays (especially turbidites)
  • Middle Miocene carbonates reef platforms
            There are 4 petroleum contracts that remained in active in the Song Hong Basin. There is one small producing field, and another is being developed at the onshore northwestern part of the basin. In the southern area, a number of significant gas discoveries were made, but unfortunately contaminated by high CO2 content.

  Phu Khanh Basin
  Geological Development
            Phu Khanh Basin is a present deepwater basin. It shows characteristic rift structures, which belong to the transtensional system developed along the mega shear zone at the boundary between the relatively rigid continental block and the more mobile spreading zone of the East Sea.
            The Basin was formed during the Oligocene to Early Miocene main rifting phase. The dominant styles of deformation were extension and transtension. During the Middle Miocene, a regional subsidence took place with a tilting towards the east that affected the entire basin, and a medium rate of subsidence was maintained. Two significant transpressional tectonic events took place during the Middle Miocene, forming large-size flower structures in sedimentary succession and partial inversion of the basement blocks.
            During the Late Miocene-Quaternary, the tectonic activity was a rifting phase with high rate of subsidence. The deepening of the basin was accompanied by minor events of submarine erosion and non-deposition in the shelf areas. The final subsidence along the inherited fault zones at the shelf margin and a relatively low amplitude uplift of the western part of the inner shelf gave the basin its present day morphostructures.
  Petroleum System and Prospectivity
            Since there have been no exploratory wells drilled in the area, hydrocarbon systems as well as characteristics of source rocks, reservoirs and cap rocks in the basin have been assessed on the basis of analogue from adjacent basins (Song Hong, Cuu Long and Nam Con Son).
            The main source rock is believed to be Oligocene and possible Lower Miocene and Eocene organic rich shale. There are several types of reservoirs, including Oligocene/Miocene deltaic to shallow marine sandstones; Paleogene/Miocene carbonates platforms and reefs, and possible fractured granite. The major trap types are related to fault blocks associated with transtensional and transpressional movements; but carbonates-in-situ and basement are prospective exploration targets. Potential seals are Oligocene and Miocene claystones and claystones intercalated with siltstones.

            Phu Khanh Basin is forecasted to contain 10% of the total hydrocarbon resources of Vietnam. The major petroleum plays in the Phu Khanh Basin include:
  • Oligocene/Miocene shallow marine sandstones fault blocks structures
  • Miocene/Paleogene carbonates reefs/build-ups
  • Miocene stratigraphic plays related to pinch-out, submarine fan, turbidites
  • Fractured/weathered granite pre-Tertiary basement blocks
  Cuu Long Basin
  Geological Development
            Cuu Long Basin, a NE-SW trending extensional basin, is formed within the Sundaland craton at the Late Eocene. During the first phase of extension, narrow grabens were created. During Early Oligocene, a broader down warping produced a shallow sag basin. The axial zone of the basin subsided rapidly again in the Late Oligocene. A regional unconformity at the end of the Oligocene marked a period of uplift.
            During the earliest rifting phase (Palaeocene or Eocene), narrow grabens subsided rapidly and were filled with great thickness of the non-marine clastics. The basin subsided broadly during the Oligocene, and the fluvial lacustrine formations were deposited, containing coarse clastics in its lower part and grades upward into sand, silts and mudstones.
            During the Middle Miocene, a widespread marine incursion flooded the Cuu Long Basin, depositing the Rotalia mudstones, a thick shale section, which act as a regional seal. This formation comprises a prograding delta sequences, from prodelta to delta plain. The Upper Miocene and the overlying Pliocene-Quaternary sediments were deposited during transgressive/regressive cycles of the modern Cuu Long delta. They appear to be controlled by changes in eustatic sea level.
  Petroleum System
            The common source rocks in Cuu Long Basin are Oligocene lacustrine mudstones with high TOC. Kerogen is mainly of type I/II (oil prone).
            The most important reservoir rocks in Cuu Long Basin are weathered and fractured granite and granodiorite basement with more than 1,000 m thickness. Fractures in the basement are developed into vertically different zones with porosity of 1-5%. Oil test rate is greater than 10,000 bopd. The remaining proven reservoirs are Oligocene and Miocene sandstones.
            The Oligocene and Miocene Rotalia shale provides both vertical and lateral seals. Local caprocks are Lower Oligocene lacustrine clay and Lower Miocene mudstones. Trap types encountered are: basement highs, rollover folds, tilted fault blocks, drape anticlines and stratigraphic pinchouts.
            Cuu Long Basin is assessed to contain 20% of the total hydrocarbon resources of Vietnam. The major petroleum plays in the Cuu Long Basin include:

  • Pre-Tertiary granite-fractured basement on horst or tilted fault blocks,
  • Oligocene and Lower Miocene clastics associated with four-way dip structures, drape above basement fault blocks, locally by inversion.
            Cuu Long Basin is the major source for Vietnam oil production. Currently, oil is produced from four fields with average of 330,000 bopd, 90% of which is from fractured basement. With the recent significant oil field discovery, the production is expected to increase 80,000-120,000 bopd by 2004. Also, the basin is presently supplying all the associated gas with production of approx. 165 mmcfd through the first pipeline system. Eight petroleum contracts have been signed since 1988 and 7 of them are still effective. The success rate for exploration wells in the basin is greater than 50%.

  Nam Con Son Basin
  Geological Development
            Development of the Nam Con Son Basin situated at the intersection of two major tectonic systems related to Indochina extrusion and East Sea floor spreading, was initiated during the Paleogene.
            During the Eocene-Oligocene, extension related to the early opening of the East Sea resulted in the development of NE-SW trending half-graben; rift sequences fill of these half-graben are continental. As thermal subsidence set in and the individual discrete half-graben filled, the sediment provenance became more regional resulting in the basin-wide deposition of high net to gross fluvial sediments from the west. Sag sequences became more non-marine upward and more marine west to east, due to overall transgression and backstepping of deltas during the earliest Miocene.
            Toward the end of Early Miocene, NW-SE extension associated with a change in spreading direction of the East Sea led to enhanced topographic relief within the basin centre and structurally controlled facies pattern, in which carbonate systems were restricted to platform or footwall locations whilst deeper shelf and slope facies were deposited within the graben. In the Late Miocene, the basin was again tectonically restructured by a mild inversion, followed by thermal subsidence, resulting in large carbonate reefal buildups and infilled sandy turbidites, basin floor. The process was interrupted during the early Pliocene due to a major transgression.
  Petroleum System
            The Lower Miocene paralic mudstones of the upper post-rift are established as the major, oil prone source rocks. Upper Oligocene coals (Kerogen type II and II, gas prone) and Oligocene syn-rift lacustrine oil-prone shales are also of importance.

            Three major types of reservoirs identified in the Nam Con Son Basin are, pre-Cenozoic weathered fractured basement, Oligocene and Miocene clastics, ranging from continental deltas to deep marine turbidites in origin, and high quality Miocene carbonates.
            There are a variety of trap types recognised in the Nam Con Son, the major ones are rollover folds, extensional tilted fault blocks, basement highs and carbonate buildups. Developed throughout the basin, Upper Miocene-Pliocene mudstones are considered as a regional seal. Oligocene, Miocene interbedded mudstones are local seals.
            Nam Con Son Basin is assessed to contain 20% of the total hydrocarbon resources of Vietnam. The major petroleum plays in the basin include:
  • Pre-Tertiary fractured granite at basement highs
  • Oligocene clastics on four-way dip structures, drape across basement faults
  • Miocene clastics on rollover fault blocks, four-way dip or anticline
  • Upper Miocene sandstones associated with turbidites
  • Upper Miocene carbonate platforms
            Currently, operations are performed on 8 contracts in the Nam Con Son Basin. Although oil is producing in Dai Hung field, the basin is considered to have mainly natural gas potential with proven reserves estimated at around 10 Tcf. Besides the Lan Tay-Lan Do field with first gas in the end of 2002, other fields such as Rong Doi, Hai Thach-Moc Tinh, etc., are scheduled to be brought on production during the period of 2005-2007. Additional gas discoveries in blocks 04-3, 12 have been on appraisal. The Nam Con Son pipeline system which has a capacity of 6-7 bcm per year marked a milestone in the development of the gas industry of South Vietnam.

  Malay-Tho Chu Basin
  Geological Development
            Malay-Tho Chu Basin is known as the Vietnamese part of the Malay Basin. This can be described as an intra-cratonic basin, which was created in Early Tertiary as a result of the collision between the India plate and the Eurasian plate, involving three main phases of structural deformation.
            The first phase was related to rifting, which commenced in Late Eocene/Early Oligocene resulting in the formation of numerous East-West orientated half grabens, some cut by North-South trending faults. This rift phase was connected to the drift of the Indochina block relative to the Asia mainland, which moved along the main left-lateral strike-slip faults. The sedimentation in the early part of rift phase was dominated by alluvial-fluvial facies deposited in narrow, half-graben-like area, and followed by deposition of a possible lake facies at the late stage in wider basin.

            The second phase was a sag phase, which lasted until the Late Miocene. During the Late Miocene, the transtensional stress changed to transpressional movement, where the graben fills were inverted, basically along East-West orientated anticline and associated with wrench related folds. The inversion phase ended with an eustatic drop in sea level, causing the erosion of most anticlines. A weak extensional phase prevailed in this area during most of the Pliocene-Pleistocene time, which is referred to as the third phase.
  Petroleum System
            The Upper Oligocene and Lower Miocene coal/claystones sequence is the primary source rocks in the Malay-Tho Chu Basin. The Oligocene lacustrine claystones are proven to be world class oil source rock within the basin (Kerogen type I and II), while the Lower Miocene deltaic and lagoonal liptic coals and claystones are good source for both oil and gas. The organic matter comprises a mixture of type I and III kerogens with a probable upward trend towards type III. The Middle and Upper Miocene sections are therefore believed to be more gas prone.
            Reservoirs in the basin are primarily vertically stacked sandstones deposited in a variety of continental to shallow marine environment, including Oligocene deltaic, alluvial fan and lacustrine sandstones; widely-distributed Lower Miocene delta plain deposits, and locally Middle Miocene fluvial and lacustrine sandstones.
            There are a number of trap types found in the basin, such as structures inherited from basement horsts, extension tilted blocks, extension related drape closure, four-way dip closure, stratigraphic pinch-outs, etc. Regional seal is Upper Miocene-Lower Pliocene marine mudstones. Local seal is Oligocene/Miocene alternating mudstones.
            Malay-Tho Chu Basin is assessed to contain 5% of the total hydrocarbon resources of Vietnam. The major petroleum plays in the Malay-Tho Chu Basin include:
  • Oligocene sandstone anticlines or fault blocks (may be associated with extensional tilted blocks
  • Lower/Middle Miocene sandstone anticlines or fault blocks
            There have been 3 petroleum contracts signed. For the Vietnam-Malaysia overlapping overlapping area, the first discovery Bunga Orkid was made in 1991 followed by a series of other oil and gas discoveries. Currently, the Bunga Kekwa field produces approximately 15,000 bopd; adjacent fields are developing. With the area's proven reserves of about 6 Tcf gas, the second gas pipeline system with capacity of 1.5-3 bcm per year has been scheduled to complete in 2005.

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Last Update: 8 August 2002