|GDP at current price||16,898||16,369||15,489||14,590||13,743||billion baht|
|GDP reference year 2002||10,932||10,647||10,248||9,848||9,521||billion baht|
|GNP per capita||234,806||225,384||215,041||203,521||191,723||baht|
|Total Exports||7,628,400||8,108,299.80||8,006,265.20||7,587,118.40||7,225,723||million baht|
|Total Imports||7,425,649||8,064,038.90||7,587,118.40||6,888,187||6,906,079||million baht|
Major Trade Partners : ASEAN, EU, NAFTA, Japan and Middle East
|Oil production||50||47||53||61||56||million barrels|
|Gas production||1,060||1,105||1,063||1,103||1,088||billion cubic feet|
|Condensate production||34||36||36||36||35||million barrels|
|Petroleum consumption||1,756||1,725.10||1,692.40||1,675||1,662||thousand BOEPD|
|Indigenous contribution||46||45||48||51||53||% of total consumption|
|Total proved oil reserves||126||137||156||178||219||million barrels|
|Total proved gas reserves||4,882||6,058||6,410||6,830||7,304||billion cubic feet|
|Total proved condensate reserves||127||156||166||171||178||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 (Fig.1) since 1981 and its proved petroleum reserves by the end of 2019 consisting of 4,882.33 Bcf of natural gas, 127.21 MMbbl of condensate and 125.54 MMbbl of crude oil, or a total of 1,091.99 MMBOE (Table 1).
In 2019, the country supplied approximately 0.85 million barrels of oil equivalent per day (MMBOED) from indigenous resources, consisting of 15% of crude oil, 11% of condensate and 74% of natural gas (MTJA included). However, these indigenous petroleum supplies are accounted for only 40% of the total country’s daily consumption, while the remaining 60% are acquired from abroad. Thus, there is still a need for such an importation to meet the country’s energy demand.
In order to enhance the national energy security and to reduce dependency on the importation, Department of Mineral Fuels (DMF) has continually promoted and accelerated exploration and development of the indigenous mineral fuels by studying petroleum potential in production areas and also surrounding areas which had been relinquished through the time by the concessionaires. The study reveals that some areas still have interesting petroleum potential and promising high chance of success for future commercial discoveries.
Source: Annual Report 2019, Department of Mineral Fuels (page 93).
Therefore, the Ministry of Energy would like to announce a new bidding round, the 23rd round, for an exploration block, namely L1/64 (Fig. 2). This onshore block has a total area of 78.90 km2, consisting of two areas: L1/64 Area A 67.66 km2, and L1/64 Area B 11.24 km2. Overall, the block covers an old production area and its surrounding area in order to promote both the continuity of petroleum production and the new discoveries.
The L1/64 block comprising of two separated areas, Area A covering an area of approximately 67.66 km2 and Area B covering an area of approximately 11.24 km2. Unlike Area A which is identified as a Greenfield, Area B is classified as a Brownfield because it is an expired oil production field, i.e., former NC production area license.
The entire of L1/64 block is located in the eastern part of the Phitsanulok Basin (Fig. 3). This basin is the largest Cenozoic rift basins onshore Thailand. The terrigenous sediments were deposited in the basin up to the maximum thickness of around 8 km (Flint and others, 1988; Ainsworth and others, 1999). These sediments were deposited in alluvial fan, fluvial, deltaic, lacustrine, and alluvial plain environments (Pinyo, 2011). The structural evolution of this basin began during the Oligocene with extension, which was the most pronounced in the middle Miocene (Morley and others, 2001) and continued to the upper Miocene. The basin was developed into an asymmetric half-graben due to the extension along the Western Boundary Fault. This extension also involved with minor inversion during the Miocene.
Stratigraphy and Petroleum System
Stratigraphy of the Phitsanulok Basin is shown in Fig. 4. The early stage of rifting (Oligocene to Early Miocene) was dominated by coarse clastic sediment of the Sarabop Fm, deposited as alluvial fans against the Western Boundary Fault and fluvial-deltaic to lacustrine environments of Nong Bua Fm. During the Early Miocene, it was dominated by fine-grained sediment, lacustrine shales of Chum Saeng Fm and fluvio-deltaic sandstones of Lan Kraubu Fm in the central part of the basin. In the Middle to Late Miocene the Pratu Tao and Yom Fm were deposited in alluvial-plain and braided stream environment. During Late Miocene to Recent the sediment is deposited in alluvial plain environment of Ping Fm.
The main source rock is lacustrine shales of Chum Saeng Fm (Fig. 4) which is generally intercalated with the main fluvio-deltaic sandstones reservoir of the Lan Krabu Fm. The sandstone of the Pratu Tao is an alternative secondary younger reservoir.
Trap types in the basin are consisting of structural traps which are directly related to antithetic and synthetic faults, rollover, faulted anticline, tilted fault blocks, stratigraphic traps i.e., sand pinch-out and channel sand lens, combination traps and locally pre-Cenozoic buried hill structure.
The L1/64 block is situated within the biggest oil producing basin onshore Thailand and surrounded by major oil fields, i.e., Sirikit, Bung Ya West-Nong Sa, Bung Ya West_Nong Sa Extension. Petroleum risk map of the Phitsanulok Basin was constructed based on literatures and petroleum concessionaires’ studies. It is demonstrated that L1/64 located inside the high petroleum potentiality with low to moderate risk (Fig. 5)
Area A: there are only five 2D seismic lines available over this area. The seismic profiles integrated with literatures and neighbor’s analogue were interpreted. The hydrocarbon could migrate from Chum Saeng Fm both vertically along the fault planes and horizontally along the rock bedding and probably accumulated in sandstones of Lan Krabu, Sarabop and Pratu Tao Fm. The existing data suggested that petroleum has highly trapping potential along the Western Boundary Fault (i.e., combination trap and stratigraphic trap) and normal fault-related structural closures. The prospective resources (2U; undiscovered recoverable; risked) were estimated based on volumetric method, which was found to be around 2.64 MMbbl. However, due to the considered poor quality of the existing seismic data, this area really still needs further sub-surface exploration. The new technology of 2D and 3D seismic acquisition are recommended for future additional seismic survey in order to improve the quality of seismic data and to achieve a better sub-surface understanding as a whole.
Area B: this area was once the NC block’s production area license and recently expired. However, the contingent resources (2C) are estimated to be approximately 3.4 MMbbl of leftover crude oil in sandstones of Lan Krabu Fm, especially the K and L member.
Hence, this block has already proven successful petroleum system and considered low risk potential which is fair enough to render the attractive investment. The Department of Mineral Fuels has strongly intention to promote and expedite petroleum exploration and production in this block, in order to exploit the remaining resources as much as possible. For more detail pertaining sub-surface data and related information, please kindly take your time visiting L1/64 data room (Fig. 6).
Figure 5 Petroleum risk distribution zone in the Phitsanulok Basin overlaid by existing petroleum concession blocks (combined from, CNPCHK, MOECO, PTTEP and Sino). L1/64 is situated in the low to moderate risk area.
Figure 6 The example of available data in L1/64 data room service (2D and 3D seismic data, well data, production data, and other relevance).
The new invitation (23rd Bidding Round) for concession rights is announced. Interested companies can submit applications for concession rights three working days from 29th July 2021 to 2nd August 2021
Open acreage with petroleum deposition potential has already been delineated into 1 onshore exploration block, located in Central 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. Such companies, individual oil companies or joint ventures must submit evidences showing their corporate profile, financial strength and petroleum exploration and production capability to be verified before they can be considered to be concessionaires. If the applicant does not possess the specified qualifications, the applicant will be required to submit a Letter of Guarantee from the company which has relationship in capital or management with the applicant guaranteeing to provide the applicant necessary supports to an extent that the applicant be capable to explore for, produce, sell and dispose of petroleum.
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 block) and development plan.
Qualified companies that have been selected as concessionaires 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 for the first 6-year obligation before signing the concession agreement.
|Contract type||Concession system|
|Contract period (years)|
|• Exploration||3 + 3 (with 3 years extendable)|
|• Production||20 (with 10 years extendable) starting immediately after the end of the exploration period|
|• Exploration Block||As defined in the bid announcement. Area relinquishment is 50% at the end of year 4 and another 25% at the end of year 6.|
|• Production Area||With commercial discovery, production area will be delineated and production can start right away even in the exploration period.|
|• Reserved Area||In the case the production area is declared, 12.5% of the original exploration area can be reserved for further exploration for another period of 5 years after the end of the exploration period.|
|• Exploration Work||After careful evaluation of geological data|
|Program||Available the bidders will propose an exploration work program for each period. The work program can be revised to suit the information acquired from the work performed. Reduction of work commitment for extra area relinquished or waive of work commitment for area surrendered is allowed beyond the first three years.|
|Royalty||To be paid in a sliding scale rate corresponding with the revenue from petroleum sold or disposed of as follows:|
10 million BTU/Barrel is used as conversion factor for natural gas.
|Petroleum Income Tax||50% of net profit of the company and no ringfence for cost deduction. Royalty and SRB paid can be treated as tax-deductible expenses.|
|Supplemental Tax||Special Remuneratory Benefit (SRB) is designed for extra government's take from windfall profit which will only be used if:
|Incentives||Exemption of any other corporate taxes, duties and taxes on imported equipment and materials.|
|Markets Pricing||Petroleum produced can be sold for domestic consumption or overseas. At present, natural gas is for domestic use only due to readily market and sufficient infrastructure at fair price.|
Please see available data at www.dmf.go.th