An Experimental and Numerical Study of Fluid-Rock Interaction Under Continuous Diagenesis Conditions During Basin Evolution

Abstract

Since diagenesis is the most direct factor affecting the reservoir quality, it is necessary to quantitatively investigate the effect of diagenesis on the evolution of reservoir petrophysical properties. A petroleum sandstone reservoir of Cretaceous age, located in the Kuche Depression, Tarim Basin, western China, was selected for the present study. Fluid-rock reaction experiments were conducted under continuous diagenesis conditions (i.e. with a simulation sequence of chemical compaction → background sedimentary environment → organic acid intrusion I → abnormally high temperature/pressure → organic acid intrusion II → background sedimentary environment), mimicking the diagenetic sequences inferred for the region from petrographic-geochemical-geochronological analyses. A total of six models corresponding to different experimental stages were simulated by using TOUGHREACT, a computer program for non-isothermal multiphase reactive transport. Results showed that the diagenetic sequences from the physical experiment and the numerical simulations generally matched well data from the petrographic and geochemical analysis: (1) With the weakening of compaction, chemical cementation was gradually strengthened forming a series of authigenic minerals; (2) In the second stage, since the contemporaneous sedimentary water was alkaline, calcite cement and feldspar overgrowth occurred and porosity subsequently decreased to 18%; (3) In the third stage, along with the first acidic fluid intrusion, most minerals (e.g., k-feldspar, albite, and ankerite) dissolved and porosity increased to 24.5%; (4) In the fourth stage, sudden increases of temperature and pressure caused significant mineral precipitation and the porosity decreased to 8%; (5) In the fifth stage, the cement that formed in the early stages largely dissolved with the second acidic fluid intrusion, which increased the porosity to 15%; (6) In the last stage, the acidic reservoir water was diluted by the intrusion of the surrounding formation water, and the porosity stabilized around 13%. The porosity changes simulated were comparable with the measured values. This study demonstrates that numerical simulation of reservoir diagenesis can not only reconstruct the diagenetic process, but can also provide a quantitative evaluation of the reservoir petrophysical properties for oil and gas exploration.

AAPG Datapages/Search and Discovery Article #90217 © 2015 International Conference & Exhibition, Melbourne, Australia, September 13-16, 2015