Oil shales and coals occur in Cenozoic rift basins in central and northern Thailand. Thermally immature outcrops of these rocks may constitute analogues for source rocks which have generated oil in several of these rift basins. A total of 56 oil shale and coal samples were collected from eight different basins and analysed in detail in this study. The samples were analysed for their content of total organic carbon (TOC) and elemental composition. Source rock quality was determined by Rock‐Eval pyrolysis. Reflected light microscopy was used to analyse the organic matter (maceral) composition of the rocks, and the thermal maturity was determined by vitrinite reflectance (VR) measurements. In addition to the 56 samples, VR measurements were carried out in three wells from two oil‐producing basins and VR gradients were constructed. Rock‐Eval screening data from one of the wells is also presented. The oil shales were deposited in freshwater (to brackish) lakes with a high preservation potential (TOC contents up to 44.18 wt%). They contain abundant lamalginite and principally algal‐derived fluorescing amorphous organic matter followed by liptodetrinite and telalginite (Botryococcus‐type). Huminite may be present in subordinate amounts. The coals are completely dominated by huminite and were formed in freshwater mires. VR values from 0.38 to 0.47%Ro show that the exposed coals are thermally immature. VR values from the associated oil shales are suppressed by 0.11 to 0.28%Ro. The oil shales have H/C ratios >1.43, and Hydrogen Index (HI) values are generally >400 mg HC/g TOC and may reach 704 mg HC/ gTOC. In general, the coals have H/C ratios between about 0.80 and 0.90, and the HI values vary considerably from approximately 50 to 300 mg HC/gTOC. The HImax of the coals, which represent the true source rock potential, range from ∼160 to 310 mg HC/g TOC indicating a potential for oil/gas and oil generation. The steep VR curves from the oil‐producing basins reflect high geothermal gradients of ∼62°C/km and ∼92°C/km. The depth to the top oil window for the oil shales at a VR of ∼0.70%Ro is determined to be between ∼1100 m and 1800 m depending on the geothermal gradient. The kerogen composition of the oil shales and the high geothermal gradients result in narrow oil windows, possibly spanning only ∼300 to 400 m in the warmest basins. The effective oil window of the coals is estimated to start from ∼0.82 to 0.98%Ro and burial depths of ∼1300 to 1400 m (∼92°C/km) and ∼2100 to 2300 m (∼62°C/km) are necessary for efficient oil expulsion to occur.

Oil is produced from the Suphan Buri, Phitsanulok and Fang Basins onshore central and northern Thailand. Most of the Cenozoic rift‐basins onshore Thailand are 2–4 km deep, but the Phitsanulok Basin is the deepest with a basin‐fill up to 8 km thick. In this basin, the Sirikit field produces ∼18,000–24,000 bbl/day of crude oil. In the Suphan Buri Basin, about 400 bbl/day of crude oil is produced from the U Thong and Sang Kajai fields. Approximately 800 bbl/day of crude oil is produced from the Fang field (Fang Basin), which in reality consists of a number of minor structures including Ban Thi, Pong Nok, San Sai, Nong Yao and Mae Soon. A total of eight oil samples were collected from these structures and from the Sirikit, U Thong and Sang Kajai fields. The oils were subjected to MPLC and HPLC separation and were analysed by gas chromatography (GC) and gas chromatography‐mass spectrometry (GC‐MS and GC‐MS‐MS). The U Thong oil was investigated in more detail by separating the oil into a number of fractions suited for the analysis of various specific compounds. The Sirikit oil appears to be the most mature, whereas the Suphan Buri oils and the oil from the San Sai structure (Fang Basin) are the least mature. Apart from the San Sai oil, the other oils in the Fang Basin are of similar maturity. The oils contain small amounts of asphaltenes and the asphaltene‐free fractions are completely dominated by saturated hydrocarbons (generally >60%). Long‐chain n‐alkanes extend to at least C40 and the oils are thus highly waxy. In general the oils were generated from freshwater lacustrine source rocks containing a large proportion of algal material, as indicated by the presence of long‐chain n‐alkanes, low C3122R/C30 hopane ratios, the presence of 28‐Nor‐spergulane, T26/T25 (tricyclic triterpanes) ratios of 1.07–1.57 and tetracyclic polyprenoid (TTP) ratios close to 1. Occasional saline conditions may have occurred during deposition of the Sirikit, Ban Thi and Pong Nok source rocks. The Fang Basin oils were sourced from two different kitchens, one feeding the Ban Thi and Pong Nok structures and one feeding the Mae Soon, Nong Yao and San Sai structures. The presence ofcadalene, tetracyclic C24 compounds, oleanane, lupane, bicadinane and trace amounts ofnorpimarane or norisopimarane indicate a contribution from higher land plant organic matter to the oils. The terrestrial organic matter may occur disseminated in the lacustrine facies or concentrated in coal seams associated with the lacustrine mudstones. Thermally immature oil shales (lacustrine mudstones) and coals exposed in numerous basins in central and northern Thailand could upon maturation generate oils with a composition comparable to the investigated oils.

The Fang Basin is one of a series of Cenozoic rift-related structures in northern Thailand. The Fang oilfield includes a number of structures including the Mae Soon anticline on which well FA-MS-48-73 was drilled, encountering oil-filled sandstone reservoirs at several levels. Cuttings samples were collected from the well between depths of 532 and 1146 m and were analysed for their content of total organic carbon (TOC, wt%), total carbon (TC, wt%) and total sulphur (TS, wt%); the petroleum generation potential was determined by Rock-Eval pyrolysis. Organic petrography was performed in order to determine qualitatively the organic composition of selected samples, and the thermal maturity of the rocks was established by vitrinite reflectance (VR) measurements in oil immersion. The TOC content ranges from 0.75 to 2.22 wt% with an average of 1.43 wt%. The TS content is variable with values ranging from 0.12 to 0.63 wt%. Rock-Eval derived S 1 and S 2 yields range from 0.01-0.20 mg HC/g rock and 1.41-9.51 mg HC/g rock, respectively. The HI values range from 140 to 428 mg HC/g TOC, but the majority of the samples have HI values >200 mg HC/g TOC and about one-third of the samples have HI values above 300 mg HC/g TOC. The drilled section thus possesses a fair to good potential for mixed oil/gas and oil generation. On an HI/T max diagram, the organic matter is classified as Type II and III kerogen. The organic matter consists mainly of telalginite (Botryococcus-type), lamalginite, fluorescing amorphous organic matter (AOM) and liptodetrinite which combined with various TS-plots suggest deposition in a freshwater lacustrine environment with mild oxidising conditions. T max values range from 419 to 436 o C, averaging 429 o C, and VR values range from ~0.38 to 0.66% R o , indicating that the drilled source rocks are thermally immature with respect to petroleum generation. The encountered oils were thus generated by more deeply buried source rocks.