Fracture Network Growth Research Articles

In situ dynamic X-ray imaging of fluid-rock interactions inside tight sandstone during hydraulic fracturing: fluid flow process and fracture network growth

Hydraulic fracturing plays a fundamental role in unconventional hydrocarbon production and the development of enhanced geothermal systems. Thus, studying the fluid flow process and fracture network growth during hydraulic fracturing is necessary to provide guidance for creating and sustaining fracture networks in target reservoirs. The actual formation stress state and hydraulic fracturing process can be simulated in the laboratory for small-scale rock samples in hydraulic fracturing experiments. High-energy industrial X-ray computed tomography (CT) has been used to directly track the fracture propagation in millimeter-scale samples under triaxial stress loading. In this study, a large-scale fracture network with economic benefits for unconventional energy exploitation was the target of the experiment; therefore, centimeter-scale samples were used. A hydraulic fracturing simulation experiment was conducted on tight sandstone by applying triaxial compression and injection pressures. With the assistance of the PEEK core holder and third-generation medical X-ray CT scanner, in situ dynamic X-ray imaging of the fluid-rock interactions inside the sample was conducted for the first time. The fluid-rock interactions and fracture network growth can be dynamically observed, revealing the fluid-rock interactions during the hydraulic fracturing process and how macroscopic failure develops from the microfracture.

Propagation simulation and structural characterization of multiple hydraulic fractures in naturally fractured unconventional hydrocarbon reservoirs

Multiple hydraulic fractures in naturally fractured unconventional hydrocarbon reservoirs often induce complex fracture network growth, as revealed by microseismic monitoring data from Maxwell et al. (2002), Fisher et al. (2005) and Daniels et al. (2007). History matching and production forecasting from an unconventional hydrocarbon reservoir are possible only if a complex fracture network can be clearly described through the engineering parameters. However, the current integrated technology of propagation simulation and structural characterization of a complex fracture network still presents extreme challenges. A new propagation modeling and characterization technique has been developed for complex fracture network expansion that combines the improved displacement discontinuity method (DDM) and pseudo-3D fracture propagation model to simulate the propagation process of complex fracture networks and increase stimulation accuracy. These improvements are very important for modeling and simulation of multifracture propagation in an unconventional hydrocarbon reservoir with natural fractures. The theoretical model includes the calculation model of the combined stress field, the mechanical model of fracture propagation patterns and corresponding propagation criteria, the injection fluid distribution model, and the mathematical model for structural description and morphological characterization as a postprocessing program. The propagation simulation results for a complex fracture network are implicitly and directly entered into the postprocessing program and further characterized by some engineering parameters. Simulation results show that different fracture network propagation patterns are produced, which are governed by the in situ stress anisotropy, hydraulic fracture density, and distribution modes of pre-existing natural fractures as well as the fracture interaction angle. More importantly, the simulation results can be characterized by different engineering parameters. The presented comprehensive workflow could assist reservoir engineers in clearly understanding and evaluating complex fracture networks, including the geometric morphology, spatial distribution and conductivity of complex fracture networks. This technique can help identify stimulation and forecasting strategies that will significantly improve well performance and ultimate recovery from unconventional hydrocarbon reservoirs.

The role of rock strength heterogeneities in complex hydraulic fracture formation – Numerical simulation approach for the comparison to the effects of brittleness –

It is imperative to develop deep understanding of the behavior of hydro fracture propagation, in which numerous rock-physics factors could be involved, to manage or control fracturing to form a network of interconnected fluid pathways. Since it is known that the strength heterogeneities of rock mass are one of the factors, we conduct numerical experiments using the discrete element method to estimate how the formation of fractures are quantitatively influenced by the strength heterogeneities in the process of fracture network formation. We first justify the validity to introduce the heterogeneities in the numerical models under an assumption that the microscopic strengths of our numerical models conform to the Weibull distribution, and then the simulation of hydraulic fracturing is conducted. In our heterogeneous models, a complex fracture network growth is induced by branching of micro cracks around the tip of main fracture and pores depending on the uniformness of the surrounding stress field. It is revealed that the complication caused by the strength heterogeneities is quite different from that introduced by the brittleness, although the complication factor is thought directly related to the brittleness in practice in the field. Our results indicate that the effect of the strength heterogeneities of rock should be considered as a key factor of the complication of fracture networks, and the evaluation accuracy could be improved by taking into account the strength heterogeneities of rock.

Effect of CO2–brine–rock interaction on fracture mechanical properties of CO2 reservoirs and seals

The effect of CO2–water–rock interactions on fracture mechanical properties of reservoir and seal rocks due to injection of CO2 in the subsurface may impact long-term (102–104 yr) storage security. At the Crystal Geyser and Salt Wash field sites near Green River, Utah, sandstone of the Salt Wash Member of the Morrison Formation and Mancos Shale have undergone chemical alteration associated with flow of CO2-bearing water under natural conditions over geologic time scales of 103–105 yrs. To quantify the effects of these diagenetic changes on rock fracture mechanical properties we conducted opening-mode fracture mechanics tests using the double torsion method on a suite of CO2-altered and unaltered siliciclastic samples. We show that dissolution of hematite and carbonate cement in Entrada Sandstone by CO2-rich brine lowers fracture toughness by nearly 40% relative to adjacent, unaltered samples from the same unit. In contrast, precipitation of calcite pore cement in a sandstone of the Salt Wash Member of the Morrison Formation, attributed to CO2 degassing during upward fluid flow along the Little Grand Wash Fault, results in a 100–700% increase in fracture toughness. Similarly, precipitation of carbonate mineral cements and replacement of matrix measurably strengthens Mancos Shale, considered a regional top seal. Subcritical fracture growth index (SCI) which quantifies reaction-assisted subcritical fracture propagation is also affected by CO2-related alteration. Based on previous numerical simulations of fracture network growth with varying fracture mechanical parameters, we find that the measured variations in fracture mechanical properties qualitatively match observed differences in opening-mode fracture distributions along the fault, with short, non-connected fractures in CO2-bleached rock, long, throughgoing fractures in calcite-cemented shale, and short, closely spaced, interconnected fracture networks in highly altered rock directly adjacent to fault conduits. Our fracture mechanics tests demonstrate that fracture mechanical properties of reservoir and seal rock can change as a result of chemical CO2–brine–rock interaction. These chemical interactions may favor or inhibit subcritical fracture growth processes and thus reservoir and seal flow properties. In regions of CO2-related mineral dissolution, subcritical fracture growth may reduce seal integrity over time scales beyond those of active injection and reservoir monitoring, thus negatively affecting seal integrity over the expected design lifetime of a CO2 reservoir.

Modeling and simulation of complex fracture network propagation with SRV fracturing in unconventional shale reservoirs

Multiple hydraulic fractures in naturally fractured unconventional shale reservoirs have often induced complicated fracture network expansion, as revealed by micro-seismic fracture mapping. As productivity of conventional energy resources decreases and the proportion of reserves in unconventional oil/gas increases, the theoretical method about the modeling and simulation of complex fracture network propagation needs to be improved to innovate stimulated reservoir volume (SRV) fracturing technology. To simulate the fracture network growth, a new model based on the modified displacement discontinuity method (MDDM) coupling pseudo-3D fracture propagation model is proposed introducing the propagation pattern and criterion. The numerical result of this model is solved and the process of fracture network propagation is simulated in different natural fracture (NF) distribution and fracturing parameters. The effects of NF distribution, hydraulic fracture (HF) spacing, bottomhole pressure and segmented and multi-cluster fracturing mode on the fracture network propagation are discussed. The simulation results of complex fracture network are characterized by four parameters as well. The results show that there are reasonable fracturing parameters technically during the SRV fracturing in unconventional shale reservoirs. It is significant to reasonably and efficiently develop the unconventional shale resources by researching the fracture network propagation rules.

Complex Fracture Network Modeling and Production Evaluation in Shale Gas Reservoirs

Shale gas reservoir development has gained more importance in the past few years with the growing demand for gas and the advancement in petroleum technologies. Slickwater fracturing and Multi-stage fracture treatments in horizontal wellbores are the two key technologies in shale gas reservoir. Most conventional fracture treatments result in bi-wing fractures, but microseismic mapping has shown that hydraulic fracturing in naturally-fractured shale gas reservoir often resulted in complex fracture network growth. Taking the Longmaxi group shale gas as research objective, this paper established reservoir simulation model for complex fracture network, and analysis the factors which influence production capacity such as fracture spacing, fracture conductivity, stimulated reservoir volume (SRV) and adsorbed gas. Stimulated reservoir volume is a correlation parameter for well performance, and larger SRV will result in better gas production. The fracture spacing, fracture conductivity, and the matrix permeability have higher influence on the productivity. Increasing fracture conductivity and decreasing the fracture spacing could provide some production benefit, and the desorbed gas has an important impact on ultimate recovery.

Stress- and fluid-driven failure during fracture array growth: Implications for coupled deformation and fluid flow in the crust

Brittle experimental deformation on dolomite rocks shows for the fi rst time the differ- ence in growth of fracture networks by ordinary percolation and invasion percolation processes. Stress-driven fracture growth, in the absence of fl uid pressure, is an ordinary percolation process characterized by distributed nucleation and growth of microfractures, which coalesce with increasing strain to form a connected fracture network. Fluid pres- sure-driven fracture growth is more akin to an invasion percolation process characterized by preferential fracture growth occurring initially at the high fl uid pressure part of the rock. With progressive deformation, the network propagates rapidly through the sample and away from the high fl uid pressure reservoir. X-ray microtomography analysis suggests that the fracture network in three dimensions (3-D) is probably a fully connected network at peak stress conditions, whereas conventional 2-D analysis suggests that connectivity only occurs at shear failure. The development of 3-D fracture connectivity prior to shear failure has important implications for fl uid fl ow and fl uid pressure changes immediately prior to rupture nucleation in active fault zones, for fl uid migration in ore-producing hydrothermal systems, and for reservoir integrity in hydrocarbon systems.

Predictive Modelling of Naturally Fractured Reservoirs Using Geomechanics and Flow Simulation

ABSTRACT To optimise recovery in naturally fractured reservoirs, the field-scale distribution of fracture properties must be understood and quantified. We present a method to systematically predict the spatial distribution of natural fractures related to faulting and their effect on flow simulations. This approach yields field-scale models for the geometry and permeability of connected fracture networks. These are calibrated by geological, well test and field production data to constrain the distributions of fractures within the inter-well space. First, we calculate the stress distribution at the time of fracturing using the present-day structural reservoir geometry. This calculation is based on a geomechanical model of rock deformation that represents faults as frictionless surfaces within an isotropic homogeneous linear elastic medium. Second, the calculated stress field is used to govern the simulated growth of fracture networks. Finally, the fractures are upscaled dynamically by simulating flow through the discrete fracture network per grid block, enabling field-scale multi-phase reservoir simulation. Uncertainties associated with these predictions are considerably reduced as the model is constrained and validated by seismic, borehole, well test and production data. This approach is able to predict physically and geologically realistic fracture networks. Its successful application to outcrops and reservoirs demonstrates that there is a high degree of predictability in the properties of natural fracture networks. In cases of limited data, field-wide heterogeneity in fracture permeability can be modelled without the need for field-wide well coverage.