TY - THES
T1 - Effect of Fracture Pattern's Geometry on Fluid Flow Behavior in Terms of Areal Sweep Efficiency
AU - Wu, Tao
N1 - embargoed until null
PY - 2015
Y1 - 2015
N2 - Petrophysical properties of both fractures and rock matrix and their geometries in a fracture network determined recovery method in naturally fractured reservoir. Water flooding is a commonly used second recovery method for water-wet naturally fractured reservoir. Frac- tures take only a few percent of total pore volume in a reservoir, however, their several orders of magnitude higher permeability causes injected water preferentially flow in fractures. This leads to early water breakthrough and consequently lower oil recovery from rock matrix. In this work, influence of geometry of fracture network on fluid flow is investigated by using discrete fracture matrix (DFM) model and a control volume finite element (FE) reser- voir simulator. The governing equations for transport modeling are spatial discretized with node-centered FE-FVM. Two different km-scaled naturally fractured joints patterns of ”Moab” member of Entrada sandstone from outcrops on Salt Vally anticline in Arches National Park (Utah, USA) are selected as two-dimensional reservoir analogs. They are mapped with NURBS curves and discretized by using unstructured meshes. In order to examine the effect of geometry to the fluid flow, based on stress dependent fracture aperture distribution, two different fracture permeability distributions in each joints pattern are created by a geomechanical model. In simulations, petrophysical properties of both fractures and adjacent rock matrix are based on field studies in Arches National Park. Fluids are assumed to be incompressible. Two relative permeability models are applied for rock matrix respectively. For fractures, relative permeability model is treated as linear. Water injection rate and production pressure are constant for all simulation runs. Simulation results of these idealized models showed that permeability distribution of the better intersected fracture network pattern is more sensitive to the change of fracture orientations relative to far-field global stress. Either the model applied with Brooks-Corey (1964) relevant model or the model with its modified alternative, i.e., the power-law model, resulted in different production predictions and shape of saturation profile. Power-law relative permeability model predicted earlier water breakthrough time than Brooks-Corey related model. Reversely, in the model, in which fractures have much higher conductivity than rock matrix, it predicted much later water breakthrough time. In most of the simulation models, simulation results showed not too much different be- tween scenarios: viscous flow and viscous flow with capillary force. It confirms that in km-scaled model in ”Moab” sandstone, instead of capillary fracture matrix transfer, but viscous force is dominant in fluid flow. Areal sweep efficiencies (EA) were examined by injecting different volumes of water into models, which have varying viscosity ratios between water and oil. Based on other common correlations, a modified correlation between mobility ratio and areal sweep efficiency for the model used in this thesis is also derived. Simulation results showed that injecting water volumes have less effect on EA for oil having much higher viscosity than that of water and viscosity ratio affects EA easily than water injection volume.
AB - Petrophysical properties of both fractures and rock matrix and their geometries in a fracture network determined recovery method in naturally fractured reservoir. Water flooding is a commonly used second recovery method for water-wet naturally fractured reservoir. Frac- tures take only a few percent of total pore volume in a reservoir, however, their several orders of magnitude higher permeability causes injected water preferentially flow in fractures. This leads to early water breakthrough and consequently lower oil recovery from rock matrix. In this work, influence of geometry of fracture network on fluid flow is investigated by using discrete fracture matrix (DFM) model and a control volume finite element (FE) reser- voir simulator. The governing equations for transport modeling are spatial discretized with node-centered FE-FVM. Two different km-scaled naturally fractured joints patterns of ”Moab” member of Entrada sandstone from outcrops on Salt Vally anticline in Arches National Park (Utah, USA) are selected as two-dimensional reservoir analogs. They are mapped with NURBS curves and discretized by using unstructured meshes. In order to examine the effect of geometry to the fluid flow, based on stress dependent fracture aperture distribution, two different fracture permeability distributions in each joints pattern are created by a geomechanical model. In simulations, petrophysical properties of both fractures and adjacent rock matrix are based on field studies in Arches National Park. Fluids are assumed to be incompressible. Two relative permeability models are applied for rock matrix respectively. For fractures, relative permeability model is treated as linear. Water injection rate and production pressure are constant for all simulation runs. Simulation results of these idealized models showed that permeability distribution of the better intersected fracture network pattern is more sensitive to the change of fracture orientations relative to far-field global stress. Either the model applied with Brooks-Corey (1964) relevant model or the model with its modified alternative, i.e., the power-law model, resulted in different production predictions and shape of saturation profile. Power-law relative permeability model predicted earlier water breakthrough time than Brooks-Corey related model. Reversely, in the model, in which fractures have much higher conductivity than rock matrix, it predicted much later water breakthrough time. In most of the simulation models, simulation results showed not too much different be- tween scenarios: viscous flow and viscous flow with capillary force. It confirms that in km-scaled model in ”Moab” sandstone, instead of capillary fracture matrix transfer, but viscous force is dominant in fluid flow. Areal sweep efficiencies (EA) were examined by injecting different volumes of water into models, which have varying viscosity ratios between water and oil. Based on other common correlations, a modified correlation between mobility ratio and areal sweep efficiency for the model used in this thesis is also derived. Simulation results showed that injecting water volumes have less effect on EA for oil having much higher viscosity than that of water and viscosity ratio affects EA easily than water injection volume.
KW - natürlich geklüftete Lagerstätten
KW - DFM
KW - Geometrie von Kluftnetzwerken
KW - Simulation
KW - Wasserfluten
KW - Flächendurchlaufwirkungsgrad
KW - fractured reservoir
KW - DFM
KW - numerical simulation
KW - fracture network pattern
KW - waterflooding
KW - areal sweep efficiency
M3 - Master's Thesis
ER -