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Abstract Complex fracture networks are formed when hydraulic fractures grow in naturally fractured reservoirs. Current planar fracture models are inadequate for capturing the effect of natural fractures on fracture propagation and addressing the important question of optimum fracture spacing and well spacing. Stress interference due to three-dimensional fracture networks can result in intricate fracture geometries, which are usually neglected by fracture models. In this paper, we present a three-dimensional hydraulic fracturing simulator that models the deformation and stress fields induced by both the dilation and shear failure of all existing and propagating hydraulic or natural fractures. It is shown that the simulator allows us to capture the complex fracture geometries, and microseismic signatures often observed in heterogeneous and naturally fractured rocks. Fracture geomechanics is modeled in a computationally efficient manner using a fully three-dimensional displacement discontinuity method. The simulator captures the physics of fracture growth, fracture turning, fluid distribution in fracture networks, and the intersection of hydraulic fractures with pre-existing natural fractures. The model captures the interaction between multiple branches of a hydraulic fracture (stress shadow effect). The model also simulates the shear failure of hydraulically disconnected natural fractures to simulate microseismic activity and can account for the effect of shear failure and slippage along bed boundaries and along natural fractures on hydraulic fracture propagation. The effect of pre-existing natural fracture density and orientation on the geometry of the fracture network generated is systematically studied. It is shown that natural fractures play an important role in determining the propagation direction of hydraulic fractures and this effect is quantified. At high natural fracture density, the propagation direction of a hydraulic fracture is dominated by the orientation of natural fractures rather than the far field stress magnitude and direction. The density of the natural fractures also affects the complexity of the final created fracture geometry.
Quasi-Static Fracture Height Growth in Laminated Reservoirs: Impacts of Stress and Toughness Barriers, Horizontal Well Landing Depth, and Fracturing Fluid Density
Mehrabi, Mehran (Cockrell School of Engineering, The University of Texas at Austin) | Pei, Yanli (Cockrell School of Engineering, The University of Texas at Austin) | Haddad, Mahdi (Bureau of Economic Geology, Jackson School of Geosciences, The University of Texas at Austin) | Javadpour, Farzam (Bureau of Economic Geology, Jackson School of Geosciences, The University of Texas at Austin) | Sepehrnoori, Kamy (Cockrell School of Engineering, The University of Texas at Austin)
Abstract In this study, we revisit a semi-analytical fracture height growth model and propose a fast-marching procedure to obtain the full height map of a given fracture growing in a multi-layered formation. A full height map offers substantial information about fracture growth, which can help infer fracture tip locations, estimate required pressure buildup, and evaluate operational parameters in a stimulation practice. We provide a detailed derivation of the underlying complex mathematical formulations and develop a procedural solution to construct the equilibrium height map. Our fast-marching solution algorithm can consider numerous interbedded laminations with a negligible increase in computational expenses, and it has been tested in various conceptual cases. Subsequently, the impacts of stress and toughness barriers, lateral landing depth of a horizontal well, and fracturing fluid density on fracture height growth and fracture-mouth pressure are studied to illustrate their associated potential consequences on an effective hydraulic-fracture design. Our results show that the stress barriers contribute more to the containment of fracture height than the toughness barriers. A higher minimum horizontal stress leads to more evident fracture aperture loss of that specific layer as the fracture-mouth pressure drops. Breaking through a relatively tough layer (e.g., ash bed), regardless of the layer thickness, requires substantial pressure buildup. This pressure buildup potentially leads to fracture arrest at the bedding plane and fracture growth diversion toward the bedding plane. Such fracture diversion probably creates a step-over that is detrimental to proppant transport and further fracture-height growth. The farther the horizontal well from tough layers, the lower the required pressure buildup for breaking through these layers, thus minimizing step-overs in the fracture height growth. Also, a lower-density fracturing fluid gives more symmetric fracture geometry. In contrast, a high-density fracturing fluid helps avoid undesirable upward fracture growth toward a possibly overlying shallow aquifer. Introduction Improved hydrocarbon production from usually laminated unconventional resources owes to effective hydraulic fracture propagation. A production-effective hydraulic fracture growing normal to a horizontal well needs to propagate through several bedding planes overlying or underlying the horizontal-drilling landing zone. This is due to the fact that shale layers hold sub-micro scale intrinsic permeability values, and pore fluid is almost locked against diffusion through the interfaces of these layers toward the horizontal lateral. However, the bedding planes between these laminated layers can perform as areal conduits to drain hydrocarbons to a transverse high-permeability pathway; in our case, a cross-cutting hydraulic fracture generated during a stimulation practice. The effectiveness of this drainage depends on fracture height growth; the larger the fracture height, the larger the number of laminated layers penetrated by a transverse hydraulic fracture and the higher the probability of tapping into a production sweet spot.
- Geology > Geological Subdiscipline > Stratigraphy (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.69)
- Geology > Structural Geology > Tectonics > Plate Tectonics (0.46)
Abstract Fracturing fluid that remains in the fracture and formation after a hydraulic fracture treatment can decrease the productivity of a gas well by reducing the relative permeability to gas in the region invaded by this fluid. This fluid can block the gas flow into the fracture, thus reducing the effective fracture length. Pressure transient tests performed on hydraulically fractured wells often reveal that the effective fracture half-lengths are substantially less than the designed length from fracture stimulation. In this work we used reservoir simulation to determine the relationship between fracture fluid production, effective fracture length, and gas productivity. While the effective fracture length is affected by such factors as non-Darcy flow, it is related directly to fracture cleanup, and increases with time. From this study we found that the rate of fracture fluid production is affected significantly by the conductivity of the fracture. Greater dimensionless fracture conductivity results in more effective well cleanup, longer effective fracture lengths versus time, and greater effective stimulation of the well. The results of this study provide a better understanding of the gas production behavior from wells hydraulically fractured using water-based fracturing fluids. The relationships between fracture conductivity, effective fracture length, and gas productivity presented in this paper can be used in economic calculations to balance the costs of higher fracture conductivity against the additional revenue resulting from longer effective fracture lengths. Results presented will allow operators to better design optimal fracture lengths for typical gas reservoirs. Introduction The productivity of hydraulically fractured gas wells is often not optimal because of the presence of fracturing fluid in the fracture and formation around the fracture. This fluid reduces the relative permeability to gas in the invaded zone around the fracture and, in some cases, may damage the formation resulting in a significant reduction in formation permeability at the face of the fracture. If the fracturing fluid remains in the fracture or formation, the effective fracture length of the well can be significantly lower than the designed length. Effective fracture half-lengths (and fracture conductivities) determined from pressure buildup tests are typically low. Lee and Holditch presented the results of pressure transient analysis from hydraulically-fractured, low permeability gas reservoirs. The results indicate that fracture half-lengths calculated based on achieving pseudoradial flow average only 5% to 11% of the designed lengths, while fracture lengths determined from reservoir simulation history matching average about 68% of the designed lengths. Alvarez, et. al. recently conducted a study that showed the effects of non-Darcy flow on pressure transient analysis of hydraulically fractured gas wells. This study revealed that calculated fracture half-lengths and fracture conductivities can be reduced by over 90% due to non-Darcy flow effects. These authors suggested that the best estimates of formation permeability, fracture half-length, and fracture conductivity can be obtained using a reservoir simulator that is capable of handling non-Darcy flow and fracture closure effects. The relationship between fracture fluid production and effective fracture length has not been thoroughly discussed in the literature. The objectives of our work were to further investigate this relationship and, in particular, to determine the effect of fracture conductivity on fracture fluid cleanup and effective fracture length. We have used reservoir simulation of hydraulically fractured wells to determine the relationships between reservoir and fracture properties and well performance. In this paper we determine effective fracture lengths by both direct observation of simulation results and by analysis of simulation pressure transient data for a range of reservoir and fracture properties.
Abstract During an acid fracturing treatment in a carbonate reservoir, acid is injected into the formation creating hydraulic fractures and opening existing natural fractures. As the acid flows into natural fractures intersecting hydraulic fractures (main fractures), it etches the walls of the natural fracture, which increases the natural fractures' width and generates conductivity. On the other hand, because of the existence of natural fractures, the acid volume in the main fracture reduces, resulting in less conductivity for the main fracture. Existing acid fracturing models estimate the fracture conductivity by assuming the acid flows and reacts in the hydraulic fractures only. In order to accurately predict the performance of acid fracturing in naturally fractured carbonate reservoirs, the acid etching of natural fractures should be taken into account when calculating the overall fracture conductivity. A model is developed to predict the acid fracturing performance in naturally fractured reservoirs. The model assumes that the main fracture is intersected by transverse symmetric natural fractures. The model simulates the acid transport, acid-rock reaction, fracture width increase due to etching of fracture walls, and acid leakoff through natural fractures. The model also assumes that the flow into natural fractures and the leakoff are pressure dependent and are changing with time. The conductivity calculation is based on the previously developed correlation that takes into account the small scale rock heterogeneities. The conductivity of natural fractures was found to be a strong function of the leakoff Peclet number, which depends on the velocity of acid flow into natural fractures from an intersecting hydraulic fracture. The effect of natural fractures' geometry on leakoff Peclet number and created fracture conductivity was investigated. The results show that both length and dynamic width, as well as the number of natural fractures, play a significant role in defining the leakoff rate and the conductivity of the hydraulic fracture and the natural fractures. It was also found that the position of the natural fractures along the hydraulic fracture length affects the etching of the natural fractures and the resultant conductivity. The model will enable the prediction of acid fracture conductivity for naturally fractured reservoirs and improve the feasibility of acid fracturing applications for these type of formations.
Hydraulic Fracture Propagation In Unconventional Reservoirs: The Role of Natural Fractures
Keshavarzi, R. (Young Researchers Club, Science and Research Branch, Islamic Azad University) | Mohammadi, S. (School of Civil Engineering, University of Tehran) | Bayesteh, H. (School of Civil Engineering, University of Tehran)
Meanwhile, a thorough understanding of this stimulation of unconventional reservoirs to obtain complex pattern is still lacking whereas complex fracture commercial production. As fracture stimulation is an patterns have significant consequences for the design of important aspect of well completion in unconventional the fracturing treatment and the conventionally used reservoirs to unlock the hydrocarbon from low-proppant might not be able to be transported to the tip of permeability formations, basic information about the fracture network [10, 11] due to interaction of fractures such as the direction of fracture propagation hydraulic and natural fracture which can lead to and the impact of natural fractures on hydraulic fracture premature screen-out. Recent years, have witnessed the propagation as well as the rate of production are the growing interest in the role of natural fractures in critical points while fracturing. Although hydraulic hydraulic fracturing process and the productivity fractures usually open in the direction of the minimum increase. So, the industry has focused more on the principal stress and propagate perpendicular to this activation of natural fractures commonly found in shale direction, but it's been proven to be more complex than reservoirs to create a network of connectivity within the initially thought [1]. Hydraulic fracture propagation in reservoir and improve the rate of production. In most the presence of natural fractures is substantially different shales, however, the stress anisotropy can affect the from fracture propagation in reservoirs without natural hydraulic fracture propagation behavior as well as the fractures due to interaction between pre-existing natural activation of natural fractures during stimulation fractures and the advancing hydraulic fracture.
- North America > United States > Texas (0.28)
- North America > United States > California (0.28)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.46)