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FACIES ANALYSIS AND PETROLEUM SYSTEM OF
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SAN SAI OIL FIELD, FANG BASIN
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Running head: FACIES ANALYSIS AND PETROLEUM SYSTEM OF SAN
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SAI OIL FIELD, FANG BASIN
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Peerawat Kongurai1 and Chongphan Chonglakmani2*
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School of Geotechnology, Institute of Engineering, Suranaree University of
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Technology, 111 University Avenue, Muang District, Nakhon Ratchasima 30000,
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Thailand.
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Email: p.kongurai@gmail.com
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* Corresponding Author
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Abstract
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The San Sai oil field is an important oil field in the Fang Basin.
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sedimentary facies and basin evolution have been interpreted using well data
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incorporated with 2D seismic profiles. The study indicates that the Fang
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Basin was subsided as a half-graben in the Late Eocene by regional plate
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tectonism. The deposit is thicker westward toward the major fault. The
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sedimentary sequence of the Fang Basin can be subdivided into two
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formations which comprise five associated depositional environments. The
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results of total organic carbon content (TOC), vitrinnite reflectance (%Ro),
The
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Rock-Eval pyrolysis and headspace gas analyses and the study of basin
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modeling using PetroMod1D software are compiled and interpreted. They
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indicate that source rocks of kerogen type II and III with 1.78 – 3.13%wt.
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TOC were mature and generated mainly oil at 5,600 – 6,700 feet deep
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(Middle Mae Sod Formation). Source rocks of kerogen type II and III with
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2.07 – 39.07%wt. TOC locating deeper than 6,700 feet (Lower Mae Sod
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Formation) were mature to late mature and generated mainly gas at this
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level.
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hydrocarbon generation took place in the Middle Miocene and the generated
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oil and gas migrated through fractures and faults to accumulate in traps at
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2,900-4,000 feet deep (Upper Mae Sod Formation).
According to TTI modeling using PetroMod11.1D software,
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Keywords:
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Depositional environment
Rift
basin,
Basin
modeling,
Petroleum
geochemistry,
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Introduction
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Fang oil field was the first discovered field in Thailand and has been operated till
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today by the Defense Energy Department, Ministry of Defense. It is located in
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Fang district, Chiang Mai province of northern Thailand near Thai-Myanmar
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border. In Thailand, hydrocarbons are found in pre-Tertiary and Tertiary basins.
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Pre-Tertiary basins include the Khorat Plateau and its vicinity. Tertiary basins
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can be found both onshore and offshore which include northern intermontane, the
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central plain, the Gulf of Thailand and the Andaman Sea basins. The Tertiary
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basins began to accumulate sediments in the Oligocene. Most of deposits are
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accumulated in non-marine environment except the Andaman Sea sediments are
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mainly marine.
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Geological setting of the Fang Basin
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The Fang Basin is one of the Cenozoic intermontane basins of northern Thailand
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(Figure 1). It represents the flood plain of approximately 1 to 3 kilometers wide.
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However, in the central part of the basin the flood plain increases in width to 6
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kilometers.
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longitudinal trunk stream. On the western and the southern sides of the basin the
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inner hilly belt ends abruptly against a high rugged mountain range whose
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summits rise about 1,400 meters above the basin floor. The eastern margin is
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lower elevated area. Presumably, the eastern margin is geomorphological more
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mature than that of the western one (Kaewsang, 1987). The geology of the Fang
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Basin and the adjacent areas (Figure 2a and 2b) were previously studied by
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numerous workers, namely, Dutescu et al (1980), Bunopas and Vella (1983),
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Braun and Hahn (1976), Settakul (1985) and etc. The basin is located on the
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western side of the Sukhothai Fold Belt, which comprises Paleozoic to Triassic
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strata and volcanic rocks that were accumulated on the eastern margin of the
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Shan-Thai Craton prior to the Indosinian orogeny. This fold belt is complex and
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trends north and northeast-southwest. These rocks were uplifted, deformed and
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intruded by granite during the collision of the Indochina and the Shan-Thai
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Cratons (Bunopas and Vella, 1983).
This flood plain is bisected by the Mae Fang River which is a
The Fang Basin was formed in early
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Paleogene by reactivation of these structures as the result of the Himalayan
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Orogeny.
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Cenozoic rocks and sediments consist of shale, sandstone, conglomerate, sand,
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and gravel (Braun and Hahn, 1976). Settakul (1985) classified sediments and
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rocks in the Fang Basin into two units. These units are the younger Mae Fang
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Formation and the older Mae Sod Formation. The depositional environment in
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the Tertiary time was fluvial-lacustrine and changed to fluvial and alluvial in
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Quaternary time.
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sandstone, claystone and shale. The Quaternary deposits are silt, clay, sand and
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gravel and they occur as stream channel, terrace and alluvial fan deposits. These
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sediments are covered by recent soil and lateritic sand. The pre-Tertiary basement
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rocks consist of sedimentary, metamorphic and igneous rocks. On the western
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side of the basin, the rocks are consisted of Cambrian-Permian sediments and the
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Carboniferous granite. While on the eastern side, the rocks are Silurian-Devonian
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and Jurassic sediments together with the Triassic granite.
It was filled with rocks of Tertiary and Quaternary age.
These
The Tertiary rocks of the Fang Basin are conglomerate,
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Structure of the Fang Basin
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Zollner and Moller (1996) summarized the structural setting of Fang Basin and
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adjacent basins in northern Thailand as a series of intramontane basin generally
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trending NNE-SSW. These basins were formed in Early-Mid Tertiary time as
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pull-apart basins in a transtensional regime followed by Pliocene to Pleistocene
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compressional tectonics. Fang Basin is subdivided into three sub-basins separated
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by basement ridges. It is composed of the Huai Pa Sang, the Huai Ngu and the Pa
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Ngew sub-basins. The basin has an elongated rhombohedra outer shape. The
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southern part is trending N-S and the northern part is deflected to a NE-SW
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direction. The 3D seismic survey data indicates that the Fang Basin is bordered to
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the west by a steep dipping NNE-SSW trending basin margin fault. Petersen
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(2006) described the Fang Basin as an onshore Cenozoic rift-basin and is 2-4 km
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deep. Approximately 800 bbls/day of crude oil is produced from the Fang field,
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which in reality consists of a number of minor structures including the Ban Thi,
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the Pong Nok, the San Sai, the Nong Yao and the Mae Soon.
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Lithological Sequence
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The sedimentary facies of the San Sai oil field can be divided into two formations.
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The upper part is Mae Fang Formation and the lower part is Mae Sod Formation.
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These two formations comprise five associated environment of deposition. The
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typical lithological sequence of San Sai area which is compiled from the
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subsurface data of seven drilled wells is shown in Figure 3 and the overall
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lithological sequence is shown in Figure 4.
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Mae Fang Formation
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The Mae Fang Formation (Pleistocene to Recent in age), 2,500 feet thick,
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is composed mainly of clay, coarse- to very coarse-grained sandstones, gravel and
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carbonized woods which were deposited in fluvial environment. It overlies
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unconformably on the Mae Sod Formation. The uppermost portion of the Mae
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Fang Formation is represented by approximately 500 feet thick of mainly sand
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with some thin layers of gravel, clay and trace of coal and thin top-soil. The sand
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is generally light gray to dark gray, coarse- to very coarse-grained with some
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granule and moderately sorted. The gravel is light gray to gray, with some coarse-
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to very coarse-grained and poorly sorted sand. The clay is generally gray. The
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lithological succession is composed of texturally and mineralogically immature
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sand and gravel. Sand is poorly to moderately sorted with high angular grains.
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The overall geometry is tabular or wedge shape which was deposited in a high
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energy environment of braided stream system.
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approximately 2,000 feet thick sequence of sand interbedded with shale. The sand
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is light gray to dark gray, medium- to very coarse-grained and mostly well sorted.
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The shale layers are 7 to 25 feet thick and are generally dark gray color. The
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sequence of sand and clay is fining upward.
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Mae Sod Formation
Underlying the upper part is
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The Mae Sod Formation, overlying unconformably on pre-Tertiary
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basement, can be divided into three parts, i.e., A, B, and C which comprise four
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depositional environments.
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Sub-unit A (upper Mae Sod Formation). The unit can be divided into two
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parts. The upper part consists of interbedded shale with sandstone. It is about
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1,400 feet thick. Shale is characterized by gray to dark gray and brown color,
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whereas the sandstone is generally light gray to gray color and is medium- to very
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coarse-grained and mostly well sorted. Oil show is present in some sandstone
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beds. The upper part is interpreted to be the marginal lacustrine facies (Late
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Miocene to Pliocene in age).
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The lower part is composed of thick shale with fine-grained sandstone
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intercalations. The total thickness of this sequence is approximately 1,000 feet.
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The shale is characterized by dark gray, black and dark brown color and with
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some coal layers. It represents a shallow to deep lacustrine facies (Early Late
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Miocene in age).
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Sub-unit B (middle Mae Sod Formaion). The unit consists of extremely
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thick dark gray shale, fine-grained sandstone and coal.
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succession is interpreted to be deposited in low energy condition of fresh water
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paleo-lake. The products accumulated in this environment are sedimentary rocks
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of lacustrine facies (Oligocene in age).
This lithological
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Sub-unit C (lower Mae Sod Formation). The lower part of unit consists of
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sandstone and coal bed interbedded with black shale. The upper part comprises
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coal beds approximately 200 feet thick and some sandstone.
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generally red and gray color, fine- to very coarse-grained with some layers of very
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clean sand. It represents a marginal lacustrine facies (Late Eocene in age).
Sandstone is
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Structural Evolution
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The Fang Basin can be divided into three stages of tectonic events based on
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interpretation of 2D seismic profiles as shown in Figure 5.
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The first stage or the initial stage (pre-rift) represents an early extensional
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rifting phase formed by north-south normal faults in the Late Eocene (Figure 6A).
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Sandstone is accumulated at the basin margin and predominantly claystone at the
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basin center in the fluviatile environment.
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The secondary stage (syn-rift) represents a rapid subsidence phase in the
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Oligocene to Pliocene (Figure 6B). The basin accumulated mainly the lacustrine
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shale facies.
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The third stage (post-rift) represents a slow subsidence stage in the
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Pleistocene (Figure 6C). The basin accumulated mainly the semi-consolidated
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gravel, sand, silt and clay of the alluvial facies.
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Petroleum system
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Characteristics of sedimentary organic matter
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In order to characterize source rock potential its maturity level, the cutting and
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core samples of Well no. FA-SS-35-04 were analysed geochemically by the Core
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Laboratories Malaysia SDN BHL (Ablins, 1992).
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The whole section of Mae Sod Formation below the depth of 2,500 feet
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was analyzed for the total organic carbon content (TOC). The values of TOC of
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upper Mae Sod Formation, at depth of 2,500 to 5,900 feet, are in the range of 2.05
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– 4.27%. The values of middle Mae Sod Formation, at depth 5,900 to 6,700 feet,
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are in range of 1.78 – 3.13% . The values of lower Mae Sod Formation, at depth
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of 6,700 to 9,100 feet, are in the range of 2.05 – 39.07% (Figure 7). According to
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the headspace gas analysis as shown in Figures 8a and 8b, the result is consistent
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with the TOC values which are fair to excellent. It indicates that the potential of
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the whole section of Mae Sod Formation is a good source rock.
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The modified Van Krevelen diagram comparing hydrogen index (mg HC/g TOC)
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and oxygen index (mg HC/g TOC) data obtained from rock-eval pyrolysis
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analysis is used for indicating the kerogen types of the source rock. The result of
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Mae Sod Formation indicates that the organic matter of the upper Mae Sod
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Formation is type I/II oil prone (Figure 9) and the middle and lower Mae Sod
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Formation are type II/III of mixed oil and gas prone kerogen (Figure 10-11).
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Thermal maturation
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There are many criteria to indicate the thermal maturity level of source
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rocks, such as, vitrinite reflectance (%Ro) (Figure 12a), Tmax (Figure 12b), result
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of headspace gas analysis
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Production Index (Figure 14a).
(Figure 13a), iC4/nC4 ratio (Figure 13b) and
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The upper Mae Sod Formation has Ro values in the range of 0.31 - 0.61%,
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Tmax in the range of 428° – 447°C and PI in the range of 0.01 – 0.1. The middle
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Mae Sod Formation has Ro values in the range of 0.67 – 0.76, Tmax in the range
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of 447° – 458°C and PI in the range of 0.09 – 0.25. The lower Mae Sod has Ro
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values in range of 0.81 – 1.31%, Tmax 448° - 491°C and PI 0.04 - 0.17. In
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conclusion, the result of Ro indicates the source rock is early mature at a depth of
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5,600 to 8,300 feet and is mature below 8,300 feet. The result of Tmax indicates
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that the source rock is early mature at a depth of 4,000 to 4,700 feet, mature at
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4,700 to 7,900 feet and late mature below 7,900 feet. The result of PI indicates
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that most of source rock is immature and some samples below 6,400 to 7,600 feet
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are mature. PI (Production Index) values which are in a range of 0.15 – 0.40
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indicate that the source rock is mature for hydrocarbon generation (Peters and
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Cassa, 1994). The result of gas wetness indicates that the source rock is early
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mature between a depth of 4,160 to 4,600 feet, mature at 4,600 to 6,800 feet deep
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and late mature at 6,800 feet to total depth. Finally, the result of iC4/nC4 ratio
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indicates that the source rock is mature below a depth of 4,180 feet to total depth.
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The result of burial history modeling from Well FA-SS-35-04 including TTI and
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Ro data indicates that the source rock is mature in middle Mae Sod Formation
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(Oligocene) below 5,900 feet and is over mature at lower Mae Sod formation
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below 6,800 feet as shown in Figure 15-16. In conclusion the source rock were
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mature and generate mainly oil at 5,600 – 6,700 feet. The source rock deeper than
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6,700 feet were late mature and generate mainly gas.
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Petroleum migration
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The buoyancy force is the main driving force for petroleum migration
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from the kitchen areas (approximately 7.7 km2.). The generated and expelled
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hydrocarbon migrated through fractures and fault zone to the reservoir rock in the
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combination of fault and structural traps. (Figure 17)
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Conclusion
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1. The correlation of seven seismic profiles and lithological data of seven
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drilled wells indicates that the Fang Basin was subsided as a half-graben in the
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Late Eocene. The sedimentary fills of the basin can be subdivided into two
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formations which comprise five associated depositional environments.
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2. The source rocks of middle Mae Sod Formation at 5,600 – 6,700 feet
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deep are composed of 1.78 – 3.13%wt. TOC of type I/II oil prone kerogen and
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were mature. The source rocks of kerogen Type II and III with 2.07 – 39.0%wt.
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TOC are located deeper than 6,700 feet (lower Mae Sod Formation). They were
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mature to late mature and generated mainly gas.
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3. The migration of generated hydrocarbon took place in the Middle
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Miocene through fractures or faults and was accumulated in traps at 2,900-4,000
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feet deep.
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Acknowledgement
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The authors would like to express our sincere appreciation to the School of
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Geotechnology, Suranaree University of Technology for all supports and also to
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Department of Geology, Northern Petroleum Development Center, Defence
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Energy Department for providing the geophysical and drilling data for use in this
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study. In addition I am grateful to Schlumberger Oversea S.A. for supporting the
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software “Petral and PetroMod”.
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Reference
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Ablins, P. (1992). A geochemical evaluation of well FA-WR-35-04 Fang Basin,
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on the present stage of the exploration and exploration activity for oil in
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Fang Basin. Defence Energy Department. Thailand:38.
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Khantaprab, C. and Kaewsang, K. (1987). Sedimentary Facies Analysis and
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Petroleum Potential Assessment of the Cenozoic Intermontane Fang Basin,
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Kaewsang, K. (1978). Sedimentary facies analysis of some upper tertiary deposits
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of Fang Basin, Changwat Chiang Mai. M.S. thesis, Chulalongkorn
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University, Thailand.
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Miall, A.D. (1982). Alluvial Sedimentary Basin : Tectonic Setting and Basin
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Architecture. Sedimentation and Tectonic in Alluvial Basin. The
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Morley, C. K., Charusiri, P. and Watkinson, I. (2011). Structural geology of
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Thailand during the Cenozoic. (Ridd, M. F., A.J. Barber, and M.J. Crow.
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eds.) The Geology of Thailand. Geological society, London. p. 273-334.
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Peters, K.E. and Cassa, M.R. (1994). Applied source rockgeochemistry, in
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Magoon, L.B. and Dow, W.G., eds. The petroleum system—From source
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to trap: Tulsa, Okla., American Association of Petroleum Geologists
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Memoir 60. p. 93-117.
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Petersen, H. I., Foopatthanakamol, A. and Ratanasthien, B. (2006). Petroleum
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potential, thermal maturity and the oil window of oil shales and coals in
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Cenozoic Rift Basin, Central and Northern Thailand. Journal of Petroleum
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Geologgy, 29, p. 337-360.
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Sethakul, B. (1985). Petroleum Geology of Fang Basin. Division of oil
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Sweeney, J.J. and Burnham, A.K. (1990). Evaluation of a simple model of
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1559-1570.
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Zollner, C. and Moller, N. (1996). 3D Seismics Interpretation Central Fang Basin,
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Figure 1. Map showing the Tertiary basins of Thailand. The lines onshore are the
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principal rivers draining Northern and Central Thailand and the Khorat Plateau
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(Morley and Racey, 2011).
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Figure 2(a). The geological map of Fang area (after Khantaprab and Keawsang, 1987).
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Figure 2(b). The geological symbols of Fang area (after
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Keawsang, 1987).
Khantaprab and
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Figure 3. Map showing study area with seismic lines and well locations.
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Figure 4. Composite lithological sequence of the San Sai area.
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Figure 5. Facies interpretation from 2D seismic profile line F2.
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Figure 6. Basin evolution and sedimentary facies of the Fang Basin.
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Figure 7. Total organic carbon content (TOC) in %wt. of the Mae Sod Formation.
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Figure 8. Headspace gas analyses of the Mae Sod Formation (a) C1-C4
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concentration and (b) C5+ concentration.
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Figure 9. Plot of hydrogen index (HI) versus oxygen index (OI) of upper Mae Sod
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Formation.
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Figure 410. Plot of hydrogen index (HI) versus oxygen index (OI) of middle Mae Sod
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Formation.
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Figure 11. Plot of hydrogen index (HI) versus oxygen index (OI) of lower Mae Sod
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Formation.
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Figure 12. Maturity of source rock of Mae Sod Formation. (a) Ro (%) and (b) Tmax
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(°C).
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Figure 13. Headspace gas analysis for hydrocarbon maturation indicator (a) from
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gas wetness. (b) from of iC4/nC4 ratio.
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Figure 14. (a) Maturity of source rock of Mae Sod Formation from production
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index. (b) hydrogen index.
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Figure 15. Burial history at the San Sai oil field. The overlay shows organic matter
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maturation calculated as time and temperature index model (TTI).
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Figure 16. Burial history at the San Sai oil field. The overlay shows organic matter
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maturation calculated as vitrinite reflectance (EASY%Ro, Sweeney and Burnham
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1990).
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Figure 17. Cross section of the San Sai oil field showing the migration pathway and oil accumulations.