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<p>The Nam Con Son Basin (NCSB), offshore SE Vietnam, is a prolific hydrocarbon province where coals are widely considered the dominant sources, yet the role of shale- and siltstone-dominated intervals remains under-evaluated. This study presents the first integrated geochemical evaluation of 94 fine-grained samples (90 shales, 4 siltstones) from Well A-1X, combining bulk geochemistry, organic petrology and biomarkers to assess organic richness, maturity and depositional setting. Shales yield Total Organic Carbon (TOC) values of 0.50–2.60 wt%, with Oligocene intervals systematically richer than Miocene. Vitrinite reflectance and Rock-Eval parameters indicate immature to marginally mature Miocene shales and early-oil-window Oligocene shales containing mixed Type II/III kerogen. Biomarker data show vertical shifts from algal signatures (n-C17–C18 dominance) to higher-plant input (n-C25–C31 enrichment); Pristane/Phytane ratios of 4–9 and CPI values near unity imply suboxic–oxic deltaic settings and early-oil maturity. These characteristics closely parallel Oligocene shale successions in the Malay and Pattani basins, which also contribute significantly to oil charge alongside coals. Collectively, the shale and siltstone successions of the NCSB represent effective secondary oil-prone source rocks that complement coal-sourced charge. Their stratigraphic continuity and confirmed maturity enhance the robustness of the NCSB petroleum system and highlight Oligocene intervals as key contributors to oil and condensate accumulations, with implications for both conventional exploration and deeper unconventional opportunities.</p>

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Depositional environment and petroleum system significance of shale- and siltstone-dominated source rocks: evidence from well A-1X, Nam Con Son Basin, offshore Vietnam

  • 期刊论文

  • 发表日期：

    2026年3月18日

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  • Ngoc Ba Thai,
  • Thanh Quoc Truong

摘要

The Nam Con Son Basin (NCSB), offshore SE Vietnam, is a prolific hydrocarbon province where coals are widely considered the dominant sources, yet the role of shale- and siltstone-dominated intervals remains under-evaluated. This study presents the first integrated geochemical evaluation of 94 fine-grained samples (90 shales, 4 siltstones) from Well A-1X, combining bulk geochemistry, organic petrology and biomarkers to assess organic richness, maturity and depositional setting. Shales yield Total Organic Carbon (TOC) values of 0.50–2.60 wt%, with Oligocene intervals systematically richer than Miocene. Vitrinite reflectance and Rock-Eval parameters indicate immature to marginally mature Miocene shales and early-oil-window Oligocene shales containing mixed Type II/III kerogen. Biomarker data show vertical shifts from algal signatures (n-C17–C18 dominance) to higher-plant input (n-C25–C31 enrichment); Pristane/Phytane ratios of 4–9 and CPI values near unity imply suboxic–oxic deltaic settings and early-oil maturity. These characteristics closely parallel Oligocene shale successions in the Malay and Pattani basins, which also contribute significantly to oil charge alongside coals. Collectively, the shale and siltstone successions of the NCSB represent effective secondary oil-prone source rocks that complement coal-sourced charge. Their stratigraphic continuity and confirmed maturity enhance the robustness of the NCSB petroleum system and highlight Oligocene intervals as key contributors to oil and condensate accumulations, with implications for both conventional exploration and deeper unconventional opportunities.