Fault damage zones - observations, dynamic modeling, and implications on fluid flow [electronic resource]
Keywords: Geophysics

This thesis describes a methodology for characterizing fault damage zones, modeling and quantifying damage zone attributes to facilitate integration with reservoir models, and developing a technique for incorporating damage zones in reservoir models for modeling flow and production. This study can help address some of the fundamental questions pertaining to estimating reserves, production performance, improving recovery rates, water production during recovery operations and strategic reservoir development of fractured and faulted reservoirs, all of which are relevant and applicable to a number of current endeavors in industries such as the oil and gas, and geothermal industry. The first part of this thesis uses image and other geophysical logs to analyze sub-surface damage zones in two distinct geologic environments -- granitic rocks in the ConocoPhillips example (CPE) gas field, and arkosic sandstone and conglomerates adjacent the San Andres Fault. The analysis indicates that despite the geologic differences of the two study areas, damage zones in both the areas are similar in terms of damage zone width, peak fracture/fault density and rate of fracture/fault decay with distance from the main fault. Damage zones in both, the CPE gas field and the arkosic section are ~ 50-80 meters wide. The decrease of fracture/fault density with distance from the main fault can approximately be described by a power law F=F0(r^−n) . Fault constant F0 is the fracture density at unit distance (1 meter) from the fault. It ranges from 10-30 fractures/m in damage zones in the CPE gas field, and from 6-17 fractures/m in damage zones in the arkosic section. The decay rate n ranges from 0.68-1.06 in the damage zones in the CPE gas field, and from 0.4-0.75 in the damage zones in the arkosic section. Such a quantification of damage zone attributes facilitates their assimilation in reservoir models. The second part of this thesis uses dynamic rupture propagation models with strongly rate-weakening friction and off-fault plasticity to model damage zones associated with second-order thrust faults observed in the CPE gas field in Indonesia. The region deforming inelastically due to stress perturbations generated by the propagating rupture is assumed to be the damage zone associated with the fault. A single slip event model suggests a spatially heterogeneous width of damage zones (since width scales with propagation distance). The cumulative effect of multiple slip events of various sizes (consistent with the Gutenberg Richter scaling relationship) is considered by superimposing the plastic strain field from individual slip events. Considering multiple slip events homogenizes the spatial heterogeneity in the damage zone widths. Results show that the decay of fracture density with distance from the fault can be described by a power law F=F0(r^−n) . The rate of decay n is approximately 0.85 close to the fault and increases to ~ 1.4 at larger distances (> 10 m). Modeled damage zones are 60-100 meters wide. These attributes are similar to those observed in the CPE gas field, and those reported in various outcrop studies. The third part provides a methodology for incorporating damage zones in reservoir models. Information derived from fracture characterization (image logs) and modeled damage zones (from dynamic rupture modeling) is used to generate a discrete fracture network (DFN) model of a region of the CPE reservoir. DFN models are more representative of fractured, low matrix permeability reservoirs which demonstrate phenomenon such as channeling and preferential flow. Fractures are assigned flow properties using Willis-Richard's and Barton's relations. Simulating flow through discrete fractures in a fracture network is computationally expensive, especially when the fracture density is high (like in damage zones). Therefore, the DFN model is upscaled to an equivalent grid (Oda's method), where individual grid blocks have a unique permeability tensor representative of the fracture properties inside that grid block. Flow simulations are then conducted in a dual porosity framework. Use of dual porosity models is appropriate in highly fractured, low matrix permeability reservoirs (e.g. CPE). Flow simulations are performed on two models, one containing both the background fractures and damage zones, while the other containing only background fractures. The objective is to show the signature of damage zones on the reservoir flow properties. The reservoir models are produced a constant rate of 30 MMSCF/day for 300 days. A distinct difference in the pressure drawdown between the two models is observed, the difference in pressure decay being almost 600 psi after 300 days. This clearly highlights the importance of incorporating fault damage zones in reservoir models for modeling flow correctly, and how ignoring their presence can lead to erroneous results. This study also investigates the effect of various drilling strategies in fractured reservoirs. Simulations suggest that higher flow rates can be achieved by coursing the well through damage zones, increasing the reservoir-wellbore contact length and providing a larger projection of the well in the direction of maximum flow. The last portion of this thesis does not focus on damage zones. This study applies rupture propagation (similar to second part) on a smaller scale to model damage caused due to slip induced on small natural fractures and faults in the vicinity of hydraulic fractures during slick-water hydraulic fracturing operations. The objective is to investigate whether co-seismic slip on natural fractures induced by increase in pore pressure is a dominant deformation mechanism in stimulating the reservoir. Results suggest that this co-seismic slip does not significantly affect the bulk porosity and permeability of the surrounding host rock. However, strain localization features that develop at the tips of poorly-oriented faults as a consequence of slip suggest the formation of new fractures. This increases the percolation zone by not only increasing the total area of fractures hydraulically connected to the well (percolation zone) but also the interconnectivity between the pre-existing fracture network. The pre-existing fracture network, therefore, appears to be critical in determining the stimulation potential of the reservoir. This could, therefore, be a potential mechanism in stimulating the reservoir.