Optimal dynamic rock-fluid physics template validated by petroelastic reservoir modeling

Abstract

Separation of fluid pore pressure and saturation using inverted time-lapse seismic attributes is a mandatory task for field development. Multiple pairs of inversion-derived attributes can be used in a crossplot domain. We performed a sensitivity analysis to determine an optimal crossplot, and the validity of the separation is tested with a comprehensive petroelastic reservoir model. We simulated a poorly consolidated shaly sandstone reservoir based on a prograding near-shore depositional environment. A model of effective porosity is first simulated by Gaussian geostatistics. Well-known theoretical and experimental petrophysical correlations were then efficiently combined to consistently simulate reservoir properties. Next, the reservoir model was subjected to numerical simulation of multiphase fluid flow to predict the spatial distributions of fluid saturation and pressure. A geologically consistent rock physics model was then used to simulate the inverted seismic attributes. Finally, we conducted a sensitivity analysis of seismic attributes and their crossplots as a tool to discriminate the effect of pressure and saturation. The sensitivity analysis demonstrates that crossplotting of acoustic impedance versus shear impedance should be the most stable way to separate saturation and pressure changes compared to other crossplots (e.g., velocity ratio versus acoustic impedance). We also demonstrated that the saturation and pressure patterns were detected in most of the time-lapse scenarios; however, the saturation pattern is more likely detectable because the percentage in pressure change is often lower than that of the saturation change. Imperfections in saturation and pressure patterns exist in various forms, and they can be explained by the interaction of saturation and pressure, the diffusive nature of pressure, and rapid change in pressure due to production operations.

From Mineral Surfaces and Coreflood Experiments to Reservoir Implementations: Comprehensive Review of Low-Salinity Water Flooding (LSWF)

“…Geochemical models allow the proper investigation of clay content and injected brine compositions in conjunction with certain polar oil components that are found to be influential in electrostatic interactions at rock–oil–brine interfaces. The clay content model from Dang et al’s modeling study was built on the hypothesis that grain size varies inversely with clay content. , Clay-dependent grain sizes were assigned to the 3 different facies considered: fine-grained (FS), medium-grained (MS), and coarse-grained sandstone. Cation exchange capacity as a function of rock organic carbon content and clay as proposed by Breeuwsma et al (1986) was also factored.…”

A New Approach for Optimization and Uncertainty Assessment of Surfactant-Polymer Flooding

“…The base reservoir is assumed to contain three facies including coarse sand, medium sand and fine sand with volume proportion of 0.2, 0.5 and 0.3, respectively. The clay content has a strong relationship with the grain size of sands (Shahin et al, 2012). The higher clay content is, the lower grain size is and the lower porosity and permeability are.…”

Establishing Time-Depth Relationships Constrained by Modes of the Reservoir Architecture

“…However, current approaches do not employ geological features in the process of the seismic well tie [13,14]. The seismic data are the responses of reservoir architectures [15,16]. Thus, constrained by the reservoir architectures, the seismic well tie can be efficiently improved.…”