Khamis, 8 Mac 2012
فطاني دارالسلام كايا دغن ميق دان فيتروليوم
The Gulf of Thailand contains several structurally complex trans-tensional basins. These are made up of asymmetrical grabens filled with non-marine to marginal marine Tertiary sediments as old as Eocene. Underlying the graben sediments are a variety of Paleozoic marine carbonates, granitic intrusive rocks, and metasediments. Many of the basins contain thick sequences of oil-prone source rocks, but the limited lateral extent of these deposits, combined with vatiations in heat flow and depth of burial of the source rocks, causes the distribution of hydrocarbons to be complex and difficult to predict. Numerous exploration opportunities remain, but the outlook is for a large number of smaller discoveries. The Thai Department of Mineral Fuels maintains a current concession map of the Gulf of Thailand.
Gulf of Thailand Basins
The regional pattern of the grabens and related faults strongly suggests that the grabens in the Gulf of Thailand are the result of the collision of India with Central Asia that began in Eocene time. The collision forced the area to the west of the Gulf of Thailand to the north and west relative to the area to the east, causing grabens and strike-slip faults with right- lateral movements, as well as en-echelon normal faults trending generally north-south. A similar structural picture has been mapped onshore Thailand.
The only modern Southeast Asian analogue to the Gulf of Thailand basins during Tertiary time is the Tonle Sap area in Cambodia. This large lake is today being filled with lacustrine sands and shales and in places with fresh-water limestones. These lacustrine shales are sufficiently rich in organic matter to be excellent oil source rocks. The reason that most hydrocarbon production in the Gulf of Thailand is gas is the combination of deep burial and high thermal gradients. Because the source units are not laterally extensive, they are absent on the basin flanks where they would be in the oil window.
Not all basins in the Gulf of Thailand have adequate lacustrine source rocks. An important factor in the deposition of lacustrine shale source rocks is that the lake in question should have a limited sediment supply relative to the rate of subsidence, so an open lake can form. In the Gulf of Thailand, the sediment supply was probably controlled by the river systems in existence during the Tertiary. The thick source rock sequences of the Chumpon, Kra and North Pattani Basins indicate that the Paleo Chao Phraya River system probably bypassed them.
Migration of hydrocarbons in rift basins tends to be lateral in the central parts but nearly vertical along the basin margins. The major reason for this is that the basin-bounding faults are usually active over much of the basinâ€™s history, which causes many normal and strike-slip faults to form that serve as barriers for lateral migration of hydrocarbons. In the central parts of the basins, faults are scarcer and turbidite distributary fan lobes act as conduits for hydrocarbon migration toward the basin margins.
Carbon dioxide content is a common problem in gas reservoirs in the Gulf of Thailand. This problem occurs intermittently from the Malaysia-Thailand Joint Development Area in the south all the way to Jasmine Field in the north. The problem is not unique to the deepest parts of the basins, suggesting that it may be due to overmature source rocks in the Pre-Tertiary section.
The Malay Basin is a major oil-producing basin offshore peninsular Malaysia, but yields mostly gas in Thailand. The Thai portion of the Malay Basin includes the Bongkot Gas Field, Thailandâ€™s largest, as well as recent major gas discoveries in the Arthit area that have added substantially to Thailandâ€™s gas reserve base. The Malay Basin has more marine influence than the Pattani Basin. Although large voumes of oil are produced from this basin in Malaysia, the only oil production on the Thai side is from oil rims in shallow gas reservoirs in the northern part of Bongkot Field. These have been developed with horizontal wells.
The deepest part of the Malay Basin is beneath the southern part of Bongkot Field and the Malaysia-Thailand Joint Development Area. In these areas, carbon dioxide content is a problem in most gas reservoirs. The carbon dioxide content is highly variable but, as a general rule, deeper reservoirs and those further south tend to have higher carbon dioxide content.
The northern part of the Bongkot Field is a north-south trending trans-tensional structure similar to the Erawan Field in the Pattani Basin, but the structural style changes to the south because of a component of north-south compression. Fields such as Muda in the Joint Development Area have multiple structural culminations along an east-west trend. Many of the oil fields offshore Malaysia display this same structural style.