|GDP at current price||15,637||16,892||16,369||15,489||14,590||billion baht|
|GDP reference year 2002||10,265||10,932||10,647||10,248||9,848||billion baht|
|GNP per capita||219,796||234,652||225,384||215,041||203,521||baht|
|Total Exports||7,183,568||7,628,400||8,108,300||8,006,265||7,550,704||million baht|
|Total Imports||6,476,267||7,425,649||8,064,039||7,587,118||6,888,187||million baht|
Source : http://www2.ops3.moc.go.th/
|Oil production||43||50||47||53||61||million barrels|
|Gas production||1,050||1,060||1,105||1,063||1,103||billion cubic feet|
|Condensate production||31||34||36||36||36||million barrels|
|Petroleum consumption||1,578||1,756||1,725.10||1,692.40||1,675||thousand BOEPD|
|Indigenous contribution||42||46||45||48||51||% of total consumption|
|Total proved oil reserves||92||126||137||156||178||million barrels|
|Total proved gas reserves||3,948||4,882||6,058||6,410||6,830||billion cubic feet|
|Total proved condensate reserves||103||127||156||166||171||million barrels|
Source : Annual Report, Department of Mineral Fuels
Thailand has been producing domestic petroleum from both onshore and offshore areas as shown in the concession map (Figure 1) since 1981 and its proved petroleum reserves by the end of 2020 consisting 92.44 MMbbl of crude oil, 3,947.90 Bcf of natural gas and 102.65 MMbbl of condensate, or a total of 873.73 MMBOE (Table 1).
In 2020, the country supplied approximately 0.763 MMBOED from indigenous resources, consisting 15% of crude oil, 75% of natural gas (MTJA included) and 10% of condensate. However, these indigenous petroleum supplies are accounted for only 42% of the total country’s daily consumption, while the remaining 58% are acquired from abroad in order to meet the country’s energy demand. For the sake of enhancing the national energy security and to reduce dependency on energy importation, Department of Mineral Fuels, Ministry of Energy has continually promoted and accelerated exploration and development of the indigenous resources by studying petroleum potential in the present non-concessioned areas which had been explored and relinquished through the time by the previous concessionaires. The study reveals that some areas still have interesting petroleum potential and promising high chance of success for future commercial discoveries.
Table 1 Summation of Total Domestic Petroleum Reserves (By the end of 2020)
Source: Annual Report 2021, Department of Mineral Fuels (page 78).
Therefore, the Ministry of Energy would like to announce a new bidding round in order to promote both the continuity of petroleum production and the new discoveries, the 24th bidding round, for a total of 3 exploration blocks in the Gulf of Thailand, namely G1/65 G2/65 and G3/65 (Figure 2). These three offshore blocks have a total area of 35,164.01 sq km. Overall, two out of three blocks cover the previously approved and latter relinquished production areas. Furthermore, all blocks are surrounded by numbers of current production field e.g. Jasmine, Benchamas, Erawan, Pailin, Bongkot and so on.
The three offshore exploration blocks, G1/65 G2/65 and G3/65 located in the Gulf of Thailand. Detailed descriptions of these blocks are shown as follows:
1. Block G1/65 has an area of approximately 8,487.20 sq km divided into 2 areas as follows:
- Area A covers around 8,298.49 sq km and contains relinquished Jamjuree South production area.
- Area B covers around 188.71 sq km.
2. Block G2/65 has an area of approximately 15,030.14 sq km.
3. Block G3/65 has an area of approximately 11,646.67 sq km divided into 2 areas as follows:
- Area A covers around 11,028.22 sq km containing relinquished Bussabong and Chang Dang production area.
- Area B covers around 618.45 sq km and contains relinquished Pikul production area.
The Gulf of Thailand (GoT) is located in Southeast Asia between approximately latitudes 06 00 and 14 00 N and longitudes 99 00 and 103 00 E which covers an area about 300,000 sq km. It is bounded to the west by the Thai-Malay Peninsula, to the east by Cambodia and Vietnam, and to the south by Malaysia (Figure 3).
The petroleum exploration in the GoT began in 1968 under special conditions of the Mineral Act BE 2510. Subsequent to the promulgation of the Petroleum Act BE 2514, the exploration rights were transferred from being under the Mineral Law to the Petroleum Law. The first petroleum production in the GoT, also the first of Thailand has started in 1981 from Erawan gas field.
The petroleum exploration and production activities in the GoT have been carried on since then. Currently, there are 22 petroleum concessions, 29 exploration blocks and 136 production areas in the GoT, thus obviously supporting that the petroleum system in the GoT is proven. The estimated of total proved reserves at the end of 2020 stood at 873.73 MMBOE comprising 92.44 MMbbl of crude oil, 3,947.90 Bcf of natural gas and 102.65 MMbbl of condensate.
The GoT consists of Cenozoic sedimentary basins caused by series of normal faults. As a result, these basins formed graben and half-graben geometry which normally oriented in the north-south direction (Figure 3 and 4). The GoT is separated by the Ko Kra Ridge into two main parts, the western and the eastern parts. The western part is subsequently subdivided into approximately 11 basins. Among of these basins for instance Chumphon Basin, Songkhla Basin, Western Basin and Kra Basin are oil-prone basin. The eastern part so far is the most successful area for petroleum exploration and production in the country comprising two major basins, the Pattani Basin and the North Malay Basin. The production from both basins is exceeding 70% of the total production in the GoT.
According to petroleum system in the GoT, the main source rocks are shale and coal with high organic content deposited in the flood plain, alluvial plain and lacustrine environments during Late Eocene to Miocene. The reservoir rock is sandstone deposited in the fluvial and fluvio-lacustrine environments with average porosity ranging from 10% to 30%. Most of the reservoirs are related to faulting systems. Therefore, petroleum has migrated through faults and rock layers to the most appropriate traps. The main seals are low porosity and low permeability layers e.g. shale, mudstone, siltstone and coal interbedded with reservoir rocks (Figure 5).
Figure 5 The tectono-stratigraphic columns of the main basins in the Gulf of Thailand (Compiled and modified from Chantaraprasert, 2000; Chevron, 2016;Intawong, 2006; Kaewkor, 2018; Morley and Racey, 2011; PTTEP, 2015; Racey, 2011
1) Petroleum Geology of the Pattani Basin
The block G1/65 and G2/65 are located along the western part of the Pattani Basin, which is one of the largest Cenozoic sedimentary basin in the GoT. The basin is approximately 270 km in length and 100 km in width oriented in the north-south direction. The Pattani Basin has the highest total production rate of gas, condensate and oil in the GoT. So far, Erawan field has been recorded as major gas fields in this basin.
The Pattani Basin had rifted during Late Eocene to Late Oligocene followed by post-rifting and thermal sagging since Early Miocene. The main fault pattern aligned with the pre-existing basement fabric is the set of normal faults which are oriented in the north-south direction, forming graben and half-graben geometry.
The Stratigraphy of the Pattani Basin (Figure 6) are divided into 5 sequences (Chantaraprasert, 2000; Chevron, 2016; Jardine, 1997; Morley & Racey, 2011) as follows:
Sequence 1 is the Late Eocene-Oligocene syn-rift sequence consisting of lacustrine shale with high organic content, fluvio-deltaic sandstone and alluvial-fan conglomerate. The extensive lacustrine shale is an important oil-prone source rock in the Pattani Basin.
Sequence 2 is the Early-Mid Miocene post-rift sequence. This sequence is composed of sandstone deposited in the fluvial setting and claystone deposited in the delta plain and intertidal environments. In addition, coal can be found in the upper part of this sequence.
Sequence 3 is the Mid Miocene post-rift sequence deposited in lagoon, fluvial and marginal marine environments. It is mainly composed of carbonaceous shale intercalated with sandstone, siltstone and coal. This sequence is a potential source rock and also reservoir rock in the Pattani Basin.
Sequence 4 is the late Mid-Late Miocene post-rift sequence consisting of claystone interbedded with sandstone, and minor coal. The depositional environment is dominated by the fluvio-deltaic system. The top of Sequence 4 is known as the Middle Miocene Unconformity (MMU).
Sequence 5 is the Late Miocene-recent post-rift sequence. This sequence was deposited in the fluvial, paralic, and shallow marine environments. It consists of grey claystone interbedded with sandstone, coal, and shale.
2) Petroleum System of the Pattani Basin
The petroleum system of the Pattani Basin can be described as follows:
Source Rock: The main source rock is the Oligocene lacustrine shale with high organic content in the Sequence 1 (oil-prone). In addition, the Sequence 2, 3 and lowermost Sequence 4 can also be potential source rocks (gas-prone).
The generation-migration-accumulation (G-M-A): The G-M-A of the Sequence 1 was likely to occur during the latest Oligocene to Mid Miocene before structural inversion (Jardine, 1997). For the Sequence 2, 3 and lowermost Sequence 4 source rocks, the G-M-A has started since Mid Miocene (Chevron, 2011).
Reservoir rock: The main reservoir rocks are fluvio-deltaic sandstones in Sequence 2 and 3. The minor reservoirs are also sandstones found in the Sequence 1 and 4 with the thickness of 2-25 m.
Trap and Seal: Both of structural trap and stratigraphic trap are found in the area. The seals are low porosity and permeability layers e.g. shale, claystone, siltstone and coal interbedded with reservoir rocks to form vertical seal and laterally sealed by faults.
3) Petroleum Geology of the North Malay Basin
The block G3/65 is located in the North Malay Basin, to the southeastern of the Pattani Basin. The North Malay Basin is also one of the largest Cenozoic sedimentary basin in the GoT and contains sediment more than 9 km in thickness. The basin within Thailand territory covers an area of approximately 18,000 sq km. The two major gas fields in the basin are Bongkot and Arthit.
The rifting phase in the North Malay Basin had started in Late Eocene and ended during Late Oligocene followed by post-rifting and thermal sagging since Early Miocene. During the latest of Oligocene, the basin was interrupted by structural inversion. Then, extension resumed in Early Miocene to Mid Miocene. During Mid Miocene, the non-depositional phase occurred, resulting in a huge missing section and Mid Miocene Unconformity (known as MMU). The main fault pattern is the set of normal faults which are oriented in the north-south and northwest-southeast directions, forming graben and half-graben geometry.
The Stratigraphy of the North Malay Basin (Figure 7) can be divided into 4 formations as follows:
Formation 0 (FM-0) is the Late Eocene-Oligocene syn-rift sediment mainly consisting of shale and sandstone. The well results suggest that depositional environments of this formation are lacustrine, alluvial and fluvio-deltaic settings (Shoup, 2008). This formation is stratigraphically equivalent to the Sequence 1 in the Pattani Basin.
Formation (FM-1) is the Late Oligocene-Early Miocene post-rift sediment consisting of coarse-grained sandstone interbedded with shale and mudstone. The dominant depositional environments are lacustrine, fluvial and floodplain. However, alluvial fan can be found locally.
Formation 2 (FM-2) is the Early Miocene-Late Miocene post-rift sediment consisting of sandstone interbedded with shale and coal. The depositional environments of this formation are fluvial, swamp, deltaic and floodplain settings environment. The shale in the upper part is likely to be related to marine incursion.
Formation 3 (FM-3) is the Late Miocene-Pliocene post-rift sediment consisting of shale interbedded with thin sandstone. The main depositional environment of this formation is marine environment.
4) Petroleum System of the North Malay Basin
The petroleum system of the North Malay Basin can be described as follows:
Source rock: The source rocks are coal and organic shale in the FM-2 which contain 53% and 11% of TOC respectively. The other potential source rocks are lacustrine shale in the FM-0, FM-1 and marine shale in the FM-3. These source rocks are all gas-prone.
The generation-migration-accumulation (G-M-A): The G-M-A was likely to occur during Late Miocene to Pliocene.
Reservoir rock: The main reservoir is sandstone in the FM-2 deposited in distributary channels, deltaic bars, delta front and crevasse splays. Moreover, sandstone in the FM-0 and FM-1 deposited in fluvio-lacustrine environment can be alternative potential reservoirs.
Trap and Seal: Both of structural trap e.g. fault trap and 4-way dip closure and stratigraphic trap are found in the area. The seals are low porosity and permeability layers e.g. shale, claystone, siltstone and coal interbedded with reservoir rocks to form vertical seal and laterally sealed by faults.
It is noted that the geological challenge of petroleum production in this area is abnormally high geothermal gradient (5-8 °C/100 m). Furthermore, the produced gas occasionally contains high-very high CO2.
The new invitation (24th Bidding Round) for bidder rights is announced under Production Sharing Contract Regime. Interested companies can submit applications for bidder rights ten working days from 5 to 16 September 2022.
Open acreage with petroleum deposition potential has already been delineated into 3 offshore exploration blocks, located in Gulf of Thailand. Data packages are now available to interested companies for studying prior to their submission of application.
The Department of Mineral Fuels will evaluate the applications based on the merits of the interested companies. The applicant must also propose the work obligation and expenditure obligation of not less than those specified in the announcement together with application fee of Baht 50,000 per block and bid security of Baht 3,000,000 per block on application submission. The bid security will be returned to the unsuccessful applicants. For the successful bidders, the bid security will be returned and to be replaced by a bank guarantee as performance bond.
Qualified companies will be selected based on their exploration proposals (most suitable for the geological conditions of the exploration blocks) development plan and commercial proposals. Qualified companies shall be companies of sufficient assets, machinery, and equipment and have the petroleum expertise to explore for, and produce or sell petroleum. In addition, qualified company is required to submit Bank Guarantee covering expenditure amount of the work commitment. The timeline for 24th Bidding Round is shown in the table below:
|1. Announcement of the Ministry of Energy
(The application for the right to explore and produce petroleum in the offshore exploration blocks)
|7 April 2022|
|2. Public relations||8 April 2022|
|3. Data room and data review information||9 May - 2 September 2022|
|4. Submit applications and evaluate the applications||5 - 16 September 2022|
|5. Announcement of the successful bidder||February 2023|
* A bid conference will be held around July – August 2022 (To be announced subject to COVID-19 situation).
|Contract type||Concession system|
|Contract period (years)|
|• Exploration||6 (with 3 years extendable)|
|• Production||20 (with 10 years extendable) starting immediately after the end of the exploration period|
|• Exploration Block||In accordance with the provisions of the law and the contract.|
|• Production Area||With commercial discovery, production area will be delineated and production can start right away even in the exploration period.|
|Plans and Commitments||The bidders must propose plans and commitments as stated in the bid announcement.|
|Bonuses||As defined in the bid announcement.|
Please refer to Ministerial Regulation Prescribing Form of Production Sharing Contract B.E. 2561 for a copy of the model of the Production Sharing Contract.
|Royalty||To be paid at 10% of the gross petroleum production.|
|Cost Recovery||To be recovered at a maximum of 50% of the annual gross petroleum production.|
|Profit Split||The remainder of gross production after royalty and cost recovery, “petroleum profit”, shall be divided to contractor at a maximum of 50% of the total petroleum profit.|
|Petroleum Income Tax||20% of net profit of the company as stated in Petroleum Income Tax Act.|
Please see available data at www.dmf.go.th