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PETROLEUM SOURCE ROCK AND MIGRATION IN THE MERGUI
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BASIN, THE ANDAMAN SEA, THAILAND: PERDICT FROM AN ORGANIC
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GEOCHEMISTRY STUDY BY USING PETROMOD PROGRAM
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Nattaya Chaina*, Akkhapun Wannakomol, Bantita Terakulsatit
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Running head: Petroleum source rock and migration in the Mergui basin, The
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Andaman Sea, Thailand: Predict from an organic geochemistry study, PetroMod
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Program
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Abstract
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The main objective of this research is to identify petroleum source rock and
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petroleum migration path of the Mergui basin, Andaman Sea, Thailand. An
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assessment of petroleum generation was performed by using geochemical
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analysis of rock and running basin modelling under commercial computer
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software named PetroMod, whilst migration path was conducted by porosity of
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the Ranong Formation and thermal maturity of the sedimentary. Results of the
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study indicated that source rocks have been presented in the Yala, Kantang, and
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Trang Formations but immature throughout the basin. However, only the Yala
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Formation could be proper to generate petroleum. Petroleum source rock of the
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Yala Formation is marine shale which has total organic carbon (TOC) values
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range between 0.5 and 1.5 percent. Its organic matter is Type III terrestrial
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which represents a gas prone kerogen whilst its thermal maturity has vitrinite
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reflectance (Ro) range between 0.6 and 1.0. Tmax of the Yala formation is range
School of Geotechnology, Institute of Engineering, Suranaree University of Technology, 111
University Avenue, Muang District, NakhonRatchasima 30000, Thailand.
E-mail: nattaya_c@windowslive.com
*
Corresponding author
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between 430C to nearly 450C and its production index (PI) is range between
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0.1 and 0.4. The oil window lies around 2,100 m, 3,000 m and 4,500 m in the
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North Mergui basin, Main Mergui basin and Andaman slope areas, respectively.
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The Oligocene to Early Miocene Yala Formation is mature over most of the
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basin. Results from potential of reservoir in the Ranong Formation with thermal
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maturity, geothermal gradient in basin indicated that hydrocarbons expulsion
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and migration were believed to take place mainly begun around the Middle
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Miocene and continues today. Hydrocarbons are primarily being generated and
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migrating from the deep East Mergui, West Mergui, and Ranong trough,
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respectively.
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Keywords: Petroleum source rock, Migration pathway, PetroMod, Mergui basin, The
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Andaman Sea
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Introduction
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Tertiary basins are the main target of petroleum exploration and production in
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Thailand. The Mergui basin is one of important Tertiary basins which located in the
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Andaman Sea, western offshore, Thailand. Many study reported that the Mergui basin
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comprises of good petroleum source rocks and suitable petroleum traps.
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Unfortunately, exploration in the Mergui basin was so far unsuccessful as ten wells
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had been drilled within block No. W-9 showed only a minor and trace gas which were
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observed in Trang-1 and Mergui-1 wells (Polachan and Racey, 1994). Many
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researches concluded that this area is immature stage with presenting the trace oil/gas
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show. However, the petroleum source rock identification is an important task in
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evaluating a petroleum-bearing basin since it is directly related to its petroleum
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resource potential and exploration directions. Organic geochemistry analysis is
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commonly used for oil/gas-source correlation. Previous works on geological history,
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tectonic evolution, general stratigraphy, and subsurface geology in this area were
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reviewed in this study in order to predict possible petroleum migration path way and
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traps. The study area was located between UTM 690000 and 1078786 North, and
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between 120000 and 411636 East of zone 47 which covers approximately 50,000
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square kilometers (Figure 1). Generalized stratigraphy of the Mergui basin and
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stratigraphic correlation to the North Sumatra basin is depicted in Figure 2.
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Materials and Methods
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Materials
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Required data, including geochemical, petrophysic, and geophysical data of 18
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wells drilled in the study area (Figure 1) were collected and prepared to serve the
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objective of the study. All of these required data for this assessment were compiled,
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reviewed, summarized, and documented from relevant literatures. These data were
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allowed and provided by the Department of Mineral Fuels (DMF), Ministry of
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Energy.
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Methods
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Based on available data, this research conducted some geochemical, mapping,
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and reservoir modeling techniques in order to study potential source rocks and
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potential petroleum migration pathway of the Mergui basin. Results from petroleum
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source rock analysis can be used to identify type of organic matter, burial and local
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thermal history which is particularly important for the understanding of petroleum
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source rock maturity evolution. They have generally played a decisive role in the
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timing of migration versus trap formation and in the discrimination of oil and gas.
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Modern tool as PetroMod computer software of Schlumberger Oversea S.A. licensed
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to Suranaree University of Technology is available to unravel the various parameters
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involved. Selected reservoir potential was analyzed in order to draw migration
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pathway of petroleum and important geological structures. Porosity versus depth
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sequence in reservoir distribution was also assessed on sedimentary studies using all
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available geological and geophysical data. According to porosity distribution maps,
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thermal history, geothermal gradient then, petroleum migration pathway could be
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identified. Details of research methodology are described as follows;
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Petroleum source rock study
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In order to study maturity and organic richness of potential source rocks of the
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Mergui basin, some essential geochemical data, including kerogen types, hydrocarbon
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index (HI), oxygen index (OI), total organic carbon (TOC), Production Index (PI)
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and, Tmax, etc., were collected and analyzed from available sources. Three
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geochemical criteria required for a prospective source rock to be classified as an
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“effective” source for oil (effective being defined as capable of generating and
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expelling commercial quantities of oil) are organic enrichment, algal-amorphous
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(hydrogen-enriched) kerogen, and thermal maturity. Additionally, good vertical and
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aerial extent of source rock is also a geologic requirement for considering as an
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effective source rock. Specific cutoffs for the geochemical criteria can be found in
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Espitalie (1977); Hunt (1979); Bissada (1982); Tissot and Welte (1984).
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PetroMod Computer Software
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PetroMod is the petroleum systems modeling software combines with seismic,
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well and geological information to model the evolution of a sedimentary basin. The
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software predicts if, and how, a reservoir has been charged with hydrocarbons,
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including the source and timing of hydrocarbon generation, migration routes,
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quantities, and hydrocarbon type in the subsurface or at surface conditions
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(Schlumberger, 2010).
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This research used to modeling of the source rock maturity range and its
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efficiency in the selected W9-B-1 wells to shown, it was located Eastern of the
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Mergui basin. Selected W9-B-1 wells shown due to using input data and detail of well
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almost perfect well for interpretation by software computer. PetroMod software
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modeling is necessary in order to evaluate the source rock in terms with continuing
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occurrence of subsidence, erosion, and structural of basin.
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The input availability data for generation of computer software using of detail
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as any formation, thickness, lithology, age of deposition, source rock property,
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boundary condition PWD (Paleo Water Depth), SWIT (Sediment Water Interface
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Temperature) and HF (Heat Flow). In order to evaluate heat flow distribution in
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relation, source rock, burial history reconstruction, hydrocarbon generation timing,
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which were highly affected by the thermal condition of rifting. Temperature Index
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(C) and Time Temperature Index (TTI), respectively that depicts distribution with
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respect to the heat flow history, thermal conductivity of the rocks, and sediment water
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interface temperature variation through time first time of expulsion, which depends
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primarily on heat flow history and assigned kinetics.
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Petroleum migration pathway identification
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In general petroleum migration is resulted from a buoyancy force, which is the
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main driving force. The buoyancy force is the principle of density difference, low
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density material can move over high density material, so oil and gas drive over the
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water formation. Obstacle to migration is a capillary force, if the rock has smaller
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pore, water, oil or gas may migrate hardly, or may be trapped within this rock. Fault
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can act to support or obstruct reservoir fluids migration. The appropriate area for
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drilling should be considered from local structure, stratigraphy and distribution of the
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reservoir rocks (Palciauskas, 1991).
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In order to study the petroleum migration pathway of the Mergui basin, this
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research had conducted to some well studies and only the Ranong Formation which
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potential reservoir. The evaluation was correlated their relationship on porosity versus
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depth.
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Results and Discussions
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Potential petroleum source rock in the Mergui basin
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Based on previous studies of source rock richness and kerogen type of the Mergui
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basin that were evaluated using standard Rock-Eval pyrolysis and visual kerogen
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analyses, all of petroleum geochemical studied were reported and re-interpreted.
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Unfortunately, Rock–Eval pyrolysis was analyzed only sidewall cores and cuttings
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from the Yala, Kantang, and Trang Formations.
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Results of source of 18 wells are present total organic carbon (TOC) analysis
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of the Yala Formation indicated that the marine shale of the Late Oligocene to Early
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Miocene has TOC values range between 0.5 and 1.5 percent (Figure 3a) and general
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comprise type III terrestrial, gas prone kerogen (Figure 4). Like the Early Miocene
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Kantang Formation that has fair to good TOC value range between 0.5 and 1.5
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percent (Figure 5a) and consist of mixture of type II and type III kerogen (Figure 6)
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whereas the Middle Miocene Trang Formation has fair to very good range between
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TOC 0.5 and 2.0 percent (Figure 7a) which consist of type II and type III kerogen as
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the older formation (Figure 8), respectively.
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Thermal maturation and timing of hydrocarbon generation and migration
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Thermal maturity of source rocks can be evaluated by using Rock-Eval
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pyrolysis, hydrocarbon geochemistry, and vitrinite reflectance (Ro). Plots of Tmax
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(degree Celsius), production index, and Ro (percentage) versus depth of the Yala,
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Kantang, and Trang Formations are showed in Figure 3, 5 and 7, respectively.
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Results from Tmax and Ro plots indicated that the Yala Formation (Figure 3)
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has Tmax range between 430C to nearly 450C (Figure 3b), and Ro range between 0.6
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and 1.0 percent (Figure 3d). The Kantang Formation has Tmax very close to the Yala
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Formation which is in a range between 420C and 440C (Figure 5b), whereas it has
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lower Ro than the Yala Formation with range between 0.2 and 0.6 percent (Figure 5d).
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The Trang Formation has Tmax and Ro less than both the Yala and the Kantang
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Formation as its Tmax is in range between 400C and 430C (Figure 7b) and its Ro is
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in range between 0.2 and 0.4 percent (Figure 7d).
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The production index (PI) is the ratio of already generated hydrocarbon to
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potential hydrocarbon [S1/ (S1 + S2)] derived from Rock-Eval pyrolysis. PI value in
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range between 0.15 and 0.40 is indicated hydrocarbon generation. Low PI value (less
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than 0.01) indicates immaturity or extreme postmature organic matter. High PI values
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indicate either the mature stage or contamination by migrated hydrocarbons or drilling
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additives. (Peters and Cassa, 1994). Results from PI versus depth plotting of the Yala
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Formation (Figure 3a) indicated that its PI increase regularly with depth from 0.10 to
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nearly 0.4. Whereas the Kantang Formation has lower PI value which it is in range
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between 0.02 and 0.15 (Figure 5a), and the Trang Formation has very narrow PI value
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which it is in range between 0.1 and 0.14 (Figure 7a), respectively.
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PetroMod computer software result
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PetroMod, modeling of burial and thermal history reconstruction was derived
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as PWD, SWIT (using Southeast Asia zone), HF that input regular with age of
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subsidence in case the Mergui basin study. Burial history reconstruction subsidence
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was shown generated on W9-B-1 well (Figure 9). Temperature Index (C) and TTI
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were depicts thermal conductivity of the rocks which time first time of expulsion. TTI
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value in range between 15 and 160 is hydrocarbon generation, TTI value 65 is max
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expulsion hydrocarbon from source bed (Waples, 1980). Results from Temperature
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Index versus depth plotting in the W9-B-1 well which indicated that Temperature
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Index increase regularly with depth from 23.30C to nearly 134.96C (Figure 10).
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Like TTI versus depth plotting of the W9-B-1 well indicated that its TTI increase
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regularly with depth from 0.02 to nearly 25.47 (Figure 11), respectively. Thus,
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PetroMod evaluated on the W9-B-1 well has start early hydrocarbon generation at
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depth greater than 1,900 m. Hydrocarbon generation efficient to calculated and
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measured Ro values, as determined by EASY%Ro (Sweeney and Burnham, 1990).
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Results from Ro versus depth plotting of the W9-B-1 well which indicated mature (cut
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off: Ro between 0.6 and 0.8) depth approximately greater than 2,500 m (Figure 12).
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After comparing the results from analyzed available data sources by
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geochemistry technic and PetroMod computer software of W9-B-1 well, the available
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data source by geochemistry technic is chosen to build basin modeling in this study.
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This is because the model resulting from geochemistry technical worksheet has more
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suitable value than that of PetroMod, hence can generate the best output. The thermal
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history and hydrocarbon generate from PetroMod less than worksheet which analyzed
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sources by geochemistry technic.
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According to re-interpretation geochemistry data and PetroMod computer
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software can predict immature throughout the basin. In study source rock of 18 wells
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was result almost immature source rock while mature source rock was predict
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generation of oil window by geochemistry technical and PetroMod. Vitrinite
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reflectance indicates that the oil window lies around 2,100 m, 3,000 m and 4,500 m in
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the North Mergui basin, Main Mergui basin and Andaman slope areas, respectively.
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The Oligocene to Early Miocene Yala Formation is mature over most of the basin,
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while the Early Miocene Kantang Formation is mature in the depocenters of the
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isolated sub-basins. The Middle Miocene Trang Formation and younger formations
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are immature over most of the basin. The principal control on the distribution of
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mature source rocks appears to be a combination of structural history and geothermal
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gradient.
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Petroleum migration pathway
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Based on available porosity data which were collected from selected wells, the
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relationship between porosity and versus depth of the Ranong Formation had been
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plotted trends as showed in Figure 13.
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According to re-interpretation of sedimentology and petrography of the
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Mergui basin predict sandstone potential reservoirs occurred throughout most of the
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succession, especially in the Ranong, Payang and Surin Formations. Thick deltaic and
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shallow marine sandstones of the Ranong Formation probably rate as the most
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promising reservoir intervals, while mid fan turbidite sands of the Yala Formation and
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shallow marine sandstones of the Payang Formation may also form potential
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reservoirs. The limestones of the Tai Formation may also constitute a potential
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reservoir where they have been fractured and/or karstified. Although petrographically
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these limestone are tight, most of the wells which have penetrated the Tai Formation
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to date have lost circulation due to the presence of large cavities which may have
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formed through karstification during exposure in the Middle Miocene.
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Thermal maturity of the sedimentary section to initiate primary migration
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within the Mergui basin appears to have begun around the Middle Miocene and
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continues today. The occurrence of hydrocarbons within the Mergui basin can be
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explained in terms of mature source rock locations and migration pathways (Figure
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14). Hydrocarbons primarily move laterally from mature source areas updip along
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unconformities and/or via permeable carrier beds while faults tend to block and
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redirect hydrocarbon migration. In Figure 14 depicted the hydrocarbons in the Mergui
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basin are primarily being generated and migrating from the deep East Mergui, West
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Mergui, and Ranong trough. However, this suggestion must be confirmed by the
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location of kitchen areas where have high potential to produce the petroleum and must
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accompany good migration pathways and trap mechanisms within the source beds.
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Uncomfortable, the low expulsion efficiency of the source strata is problematic across
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the Mergui basin and is the result of a high percentage of coarser clastic (silt to very
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fine grain sandstone) contamination.
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Conclusions and Recommendations
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After the study had been accomplished, some conclusions are listed as follows;
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Results from source rock maturation study in the Yala, Kantang, and Trang
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Formations indicated that only the Yala Formation has potential source rocks (gas
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prone kerogen) and they are mature over most of the basin, whereas source rocks of
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the Kantang, and the Trang Formation (oil/gas prone kerogen) are considered
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immature. Vitrinite reflectance indicates that the oil window lies around 2,100 m,
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3,000 m and 4,500 m in North Mergui basin, Main Mergui basin and Andaman slope
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areas, respectively.
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Results from sandstone porosity data study which potential reservoirs on the
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Ranong Formation consider with thermal maturity of the sedimentary which section to
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initiate primary migration. The Mergui basin appears to have initial primary migration
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begun around the Middle Miocene and continues today. Hydrocarbons are primarily
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being generated and migrating from the deep East Mergui, West Mergui, and Ranong
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trough, respectively.
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Acknowledgement
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The research work presented in this paper was supported and fund by Suranaree
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University of Technology. The permission of the Department of Mineral Fuels
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(DMF), Ministry of Energy, to use required data for undiscovered hydrocarbon
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assessment is also greatly appreciated. The authors would like to thank Assoc. Prof.
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Kriangkrai Trisarn and Dr. Chongphan Chonglakmani for their valuable suggestions.
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References
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Bissada, K.K. (1982). Geochemical constraints on petroleum generation and
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migration. Proceedings of the 2nd Association of southeast Asian Nation
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Council on Petroleum (ASCOPE); Manila, Philippines, p. 69-87.
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Espitalie, J., Madec, M., and Tissot, B. (1977). Source rock characterization method
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Habicht, J. K.A. (1979). Paleoclimate, Paleomagnetism and Continental Drift. AAPG
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Hunt, J.M. (1979). Petroleum Geochemistry and Geology. W.H. Freeman and
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Katz, B. J. (1991). Controls on lacustrine source rock development. In: A model for
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Petroleum Association; October 1991; Jakarta, Indonesia, p. 587-619.
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Palciauskas, V.V. (1991). Primary migration of petroleum. In: Source and migration
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processes and evaluation techniques. Merrill, R.K., (eds). AAPG Bull, p.
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65-85.
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Peters, K.E. and Cassa, M.R. (1994), Applied source rock geochemistry. In: The
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petroleum system- from source to trap. Magoon, L.B. and Dows, W.G.,
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(eds.). AAPG. Bull, (60): p. 93-117.
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Polachan, S. (1988). The geological evolution of the Mergui Basin, Southeast
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Andaman Sea, Thailand. Ph.D Thesis. Royal Holloway and Bedford New
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College, University of London. England, 218p.
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Polachan, S. and Racey, A. (1994). Stratigraphy of the Mergui basin, Andaman Sea:
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Implications for petroleum exploration. Journal of Petroleum Geology,
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17(3): p. 373-406.
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Schlumberger Oversea S.A. (2010). Petromod 1D Tutorial Software Version 11.
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Sweeney, J. Jerry and Burham, K. Alan. (1990). Evaluation of a simple Model of
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geochemical data from Kantang-1 Thai Andaman Sea. Mineral Fuels
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Division, Department of Mineral Resources, Ministry of Industry,
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geochemical data from Kathu-1 Thai Andaman Sea. Mineral Fuels
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Figure 1.
Map of study area showing its entire area and its location, and
exploration wells which their data were used in this study
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Relative Changes of
Sea level
(EXXON 1979)
+ present sea level -
AGE
NORTH SUMATRA
BASIN
MERGUI
BASIN
Holocene
Pleistocene
JULU RAYEU
SEURULA
M
L
TAKUAPA
L
E
Pliocene
KEUTAPANG
THALANG
M
BAONG
TRANG
Miocene
SURIN
PEOTU
BELUMAI
ARUN
E
TAI
PAYANG
KANTANG
BAMPO
RANONG
E
Oligocene
M
L
YALA
311
312
Figure 2.
PARAPAT
Major unconformity
Miner unconformity
Generalized stratigraphy of the Mergui basin and stratigraphic
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correlation to the North Sumatra basin (modified after Polachan,
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1988)
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318
319
320
321
322
323
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325
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328
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333
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336
(a)
(b)
(c)
(d)
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Figure 3.
Results of pyrolysis (Rock-Eval) cutting samples of the Yala Formation; (a) TOC in wt. , (b) Tmax (C), (c)
Production Index (PI) [S1/ (S1 + S2), and (d) Vitrinite reflectance (Ro)
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339
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341
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343
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350
351
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Figure 4.
A plot of Hydrogen Index (HI) versus Oxygen Index (OI) of the Yala
Formation indicating Type III kerogen
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357
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363
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365
366
(a)
(b)
(c)
(d)
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Figure 5.
Results of pyrolysis (Rock-Eval) cutting samples of the Kantang Formation; (a) TOC in wt. , (b) Tmax (C), (c)
Production Index (PI) [S1/ (S1 + S2)], and (d) Vitrinite reflectance (Ro)
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369
370
Figure 6.
A plot of Hydrogen Index (HI) versus Oxygen Index (OI) of the
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Kantang Formation indicating a mixing of Type II and Type III
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kerogen
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375
376
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377
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380
381
382
383
384
385
386
387
388
389
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(a)
(b)
(c)
(d)
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Figure 7.
Results of pyrolysis (Rock-Eval) cutting samples of the Trang Formation; (a) TOC in wt. , (b) Tmax (C), (c)
Production Index (PI) [S1/ (S1 + S2)], and (d) Vitrinite reflectance (Ro)
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Figure 8.
A plot of Hydrogen Index (HI) versus Oxygen Index (OI) of the
Trang Formation indicating a mixing of Type II and Type III
kerogen
Figure 9.
Burial history catculated using PetroMod Software of the W9-B-1
well
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Figure 10. Temperature Index (C) catculated using PetroMod Software of the
W9-B-1 well
Hydrocarbon generated
at 1,900 m
Figure 11. Time Temperature Index (TTI) catculated using PetroMod Software
of the W9-B-1 well
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Figure 12. Maturity overlay Ro compare with temperature and depth
catculated using PetroMod Software of the W9-B-1 well
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Figure 13. Relationship between porosity versus depth of the Ranong
Formation
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A
Central High
Figure 14.
Possible migration pathways in the Mergui basin (A,B)
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B