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<p>Lateral compressional (P-wave) velocity heterogeneity within a single sandstone reservoir interval poses a persistent challenge to seismic amplitude interpretation and hydrocarbon volume estimation. This study investigates the petrophysical controls on 350&#xa0;m/s P-wave velocity contrast observed between two well locations (K4 and K5) separated by only 1.6&#xa0;km within reservoir Sand E of the coastal swamp depobelt, onshore Niger Delta. Despite comparable burial depths and an identical total porosity range of 0.21–0.30, the two wells exhibit markedly different velocity profiles. Integration of 3D post-stack seismic data with five composite well log suites and rock physics textural diagnostics reveals that both reservoirs conform to the Dvorkin–Nur friable sand model, confirming an uncemented microstructure. This uncemented grain arrangement indicates that compressional velocity in both reservoir sands is governed primarily by confining pressure rather than by diagenetic cementation at grain contacts. Multilinear regression analysis, stratified across five shale volume intervals (0–50% in 10% increments), demonstrates that the cumulative abundance of shale within the reservoir is the principal driver of velocity suppression. At well K5, 59.8% of Sand E samples fall within the higher shale volume range (21–50%), compared to only 22.5% at well K4, where 77.5% of samples occupy the low shale volume range (0–20%). This compositional asymmetry directly explains the lower P-velocities at K5. Root-mean-square amplitude extraction further shows that the velocity contrast manifests as a measurable difference in the seismic amplitude spectrum at the two well locations, creating a risk of misattributing amplitude anomalies to fluid effects rather than lithological variation. These findings underscore the importance of integrating shale volume diagnostics into amplitude-based reservoir characterisation workflows in clastic deltaic settings.</p>

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Rock physics evaluation of shale volume effects on compressional velocity and seismic amplitude in friable sandstone reservoirs, Coastal Swamp, Niger Delta

  • 期刊论文

  • 出版模式：

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  • 发表日期：

    2026年8月4日

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  • Olawale Johnson Allo,
  • Elijah Adebowale Ayolabi,
  • Anthony Aduojo Ameloko,
  • Okezie Uchegbulam

摘要

Lateral compressional (P-wave) velocity heterogeneity within a single sandstone reservoir interval poses a persistent challenge to seismic amplitude interpretation and hydrocarbon volume estimation. This study investigates the petrophysical controls on 350 m/s P-wave velocity contrast observed between two well locations (K4 and K5) separated by only 1.6 km within reservoir Sand E of the coastal swamp depobelt, onshore Niger Delta. Despite comparable burial depths and an identical total porosity range of 0.21–0.30, the two wells exhibit markedly different velocity profiles. Integration of 3D post-stack seismic data with five composite well log suites and rock physics textural diagnostics reveals that both reservoirs conform to the Dvorkin–Nur friable sand model, confirming an uncemented microstructure. This uncemented grain arrangement indicates that compressional velocity in both reservoir sands is governed primarily by confining pressure rather than by diagenetic cementation at grain contacts. Multilinear regression analysis, stratified across five shale volume intervals (0–50% in 10% increments), demonstrates that the cumulative abundance of shale within the reservoir is the principal driver of velocity suppression. At well K5, 59.8% of Sand E samples fall within the higher shale volume range (21–50%), compared to only 22.5% at well K4, where 77.5% of samples occupy the low shale volume range (0–20%). This compositional asymmetry directly explains the lower P-velocities at K5. Root-mean-square amplitude extraction further shows that the velocity contrast manifests as a measurable difference in the seismic amplitude spectrum at the two well locations, creating a risk of misattributing amplitude anomalies to fluid effects rather than lithological variation. These findings underscore the importance of integrating shale volume diagnostics into amplitude-based reservoir characterisation workflows in clastic deltaic settings.