Permeability (earth sciences)

About: Permeability (earth sciences) is a research topic. Over the lifetime, 15424 publications have been published within this topic receiving 288535 citations.

Characterization of fluid transport properties of reservoirs using induced microseismicity

Abstract: We systematically describe an approach to estimate the large-scale permeability of reservoirs using seismic emission (microseismicity) induced by fluid injection. We call this approach seismicity-based reservoir characterization (SBRC). A simple variant of the approach is based on the hypothesis that the triggering front of hydraulically-induced microseismicity propagates like a diffusive process (pore pressure relaxation) in an effective homogeneous anisotropic poroelastic fluid-saturated medium. The permeability tensor of this effective medium is the permeability tensor upscaled to the characteristic size of the seismically active heterogeneous rock volume. We show that in a homogeneous medium the surface of the seismicity triggering front has the same form as the group-velocity surface of the low-frequency anisotropic, second-type Biots wave (i.e., slow wave). Further, we generalize SBRC for 3-D mapping of the permeability tensor of heterogeneous reservoirs and aquifers. For this we apply an approach similar to the geometric optics approximation. We derive an equation describing kinematic aspects of triggering-front propagation in a way similar to the eikonal equation for seismic wavefronts. In the case of isotropic heterogeneous media, the inversion for the hydraulic properties of rocks follows from a direct application of this equation. In the case of an anisotropic heterogeneous medium, only the magnitude of a global effective permeability tensor can be mapped in a 3-D spatial domain. We demonstrate the method on several field examples and also test the eikonal equation-based inversion.

Effects of in-situ conditions on relative permeability characteristics of CO 2 -brine systems

Abstract: Carbon dioxide capture and geological storage (CCGS) is an emerging technology that is increasingly being considered for reducing greenhouse gas emissions to the atmosphere. Deep saline aquifers provide a very large capacity for CO2 storage and, unlike hydrocarbon reservoirs and coal beds, are immediately accessible and are found in all sedimentary basins. Proper understanding of the displacement character of CO2-brine systems at in-situ conditions is essential in ascertaining CO2 injectivity, migration and trapping in the pore space as a residual gas or supercritical fluid, and in assessing the suitability and safety of prospective CO2 storage sites. Because of lack of published data, the authors conducted a program of measuring the relative permeability and other displacement characteristics of CO2-brine systems for sandstone, carbonate and shale formations in central Alberta in western Canada. The tested formations are representative of the in-situ characteristics of deep saline aquifers in compacted on-shore North American sedimentary basins. The results show that the capillary pressure, interfacial tension, relative permeability and other displacements characteristics of CO2-brine systems depend on the in-situ conditions of pressure, temperature and water salinity, and on the pore size distribution of the sedimentary rock. This paper presents a synthesis and interpretation of the results.

Stimulating Unconventional Reservoirs: Maximizing Network Growth While Optimizing Fracture Conductivity

Abstract: A significant portion of gas production in North America comes from unconventional reservoirs such as gas shales, coalbed methane (CBM) deposits and tight gas sands. Due to their limited permeability, stimulation processes are needed for economic recovery from wells drilled into these formations. This paper described some of the technology-based solutions that have been used to successfully exploit these reservoirs, such as horizontal drilling, multi-stage completions, innovative fracturing, and fracture mapping. Economic production depends on the matrix permeability of these reservoirs as well as the conductivity that can be generated in hydraulic fractures and network fracture systems. Simulations have shown that a fracture network of moderate conductivity is needed in ultra-low shale permeabilities. The spacing between fractures must be small to obtain reasonable recovery factors. Such networks are achievable according to results of microseismic mapping. In contrast, tight gas sands may be successfully depleted without inducing complex fracture networks because they have orders of magnitude greater permeability than gas shales. However, the recovery in tight gas sands is complicated by other issues of damage and zonal coverage in these reservoirs. It was concluded that fracture mapping can help improve the understanding of fractures and improve the ability to change the fracture complexity through operational changes to the well design and treatment implementation. 47 refs., 15 figs.

Biofilm growth and the related changes in the physical properties of a porous medium: 1. Experimental investigation

Abstract: An experimental investigation was conducted to quantify the permeability reduction caused by enhanced biological growth in a porous medium. Studies were conducted using sand-packed column reactors for which variations in piezometric head, substrate concentration, and biomass measured as organic carbon were monitored in space and time. Methanol was used as a growth substrate. Permeability reductions by factors of order 10−3 were observed. The data show that a limit on permeability reduction exists, having a magnitude of 5 × 10−4 in the present study. The limit on permeability reduction and the existence of high densities of bacteria in substrate depleted zones are explained with an open pore model. Permeability reduction was observed to correlate well with biomass density for values less than about 0.4 mg/cm3, and exhibited independence at higher densities.