Major Obstacles in Production from Hydraulically Re-fractured Shale Formations: Reservoir Pressure Depletion and Pore Blockage by the Fracturing Fluid (original) (raw)
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Simulation of the Impact of Fracturing Fluid Induced Formation Damage in Shale Gas Reservoirs
The unconventional gas resources from tight and shale gas reservoirs have received great attention in the past decade and have become the focus of petroleum industry. Shale gas reservoirs have specific characteristics, such as tight reservoir rock with nanodarcy permeability. Multistage hydraulic fracturing is required for such low-permeability reservoirs to create very complex fracture networks and therefore to connect effectively a huge reservoir volume to the wellbore. During hydraulic fracturing, an enormous amount of water is injected into the formation, where only 25-60% is reproduced during flowback and a long production period. A major concern with hydraulic fracturing is the waterblocking effect in tight formations caused by the high capillary pressure and the presence of water-sensitive clays. High water saturation in the invaded zone near the fracture face may reduce gas relative permeability greatly and may impede gas production. In this paper, we consider the numerical techniques to simulate during hydraulic fracturing the water invasion or formation damage and its impact on the gas production in shale gas reservoirs. Two-phase-flow simulations are considered in a large stimulated reservoir volume (SRV) containing extremely low-permeability tight matrix and multiscale fracture networks including primary hydraulic fractures, induced secondary fractures, and natural fractures. To simulate the water-blocking phenomenon, it is usually required to explicitly discretize the fracture network and use very fine meshes around the fractures. On the one hand, the commonly used single-porosity model is not suitable for this kind of problem, because a large number of gridblocks is required to simulate the fracture network and fracture-matrix interaction. On the other hand, a dual-porosity (DP) model may also be not applicable, because of the long transient duration with large block sizes of ultralow-permeability matrix. In this paper, we study the applicability of the MINC (multiple interacting continuum) method, and use a hybrid approach between matrix and fractures to correctly simulate the fracturing-fluid invasion and its backflow during hydraulic fracturing. This approach allows us to quantify the fracturing water invasion and its formation-damage effect in the whole SRV.
Energy & Fuels, 2020
Hydraulic fracturing enhances the recovery of gas from ultralow permeability shales, into which water-based fracturing fluids, proppants, and activators are typically injected. However, the impacts of the existing complex multidomain response of a heterogeneous mineral and organic matrix and fractures on the resulting heterogeneity of reservoir transport properties caused by the hydraulic fracturing remain poorly understood. To address this defect, a multidomain multiphysics model is constructed to represent a two-phase flow within a three-component heterogeneous solid system (mineral and organic matrix and fractures) representing the functional complexity of the medium. This model partitions the shale reservoir into a stimulated reservoir volume (SRV) enclosed within an unstimulated reservoir volume (USRV). Different from the previous work, the shape of the SRV is treated as the spheroid instead of the rectangular shape and the size can be determined from the spatial distribution of microseismic events rather than artificially assumed. A two-phase flow model is established for both regions with the impacts of the effective stress variation on the fracture permeability considered and solved with a finite element formalism. The fidelity of the model is first verified using two field data sets from the Barnett and Marcellus shales with good fits achieved against time histories of production. Numerical studies then investigate the impacts of relevant parameters on shale gas production behavior; specially, the impacts of the effective stress and the existence of proppants are first reported. The variations in relative permeability and intrinsic permeability within the SRV are shown to dominate the early-time response of the gas flow rate. The long-term response is mainly dependent on the mass supply from the matrix system and the encapsulating USRV region. The effectiveness of hydraulic fracturing optimized as the SRV region is maximally extended in the horizontal direction and where the increase in permeability is a convex function against a concave function. The distal transport and placement of the proppant remarkably enhance the gas production rate and resist its decline as a result of the evolving high formation stress developed by pressure drawdown. For the selection of proppant type and placement, the resulting permeability and compressibility are of complementary importance as the first controls the initial gas flow rate, whereas the second determines the permeability trend with time. Proppant permeability decreases near-linearly for a constant compressibility but exponentially where compressibility is updated to represent the true response of the proppant pack. The proposed model applies a new approach for optimizing the hydraulic fracturing process and for analyzing the shale gas production behavior.
Effect of Re-fracturing on Production Profile in Shale Gas Well
2014
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Geofluids, 2019
Currently, there is no proper method to predict the pore pressure disturbance caused by multistage fracturing in shale gas, which has challenged drilling engineering in practice, especially for the infilling well drilling within/near the fractured zones. A numerical modelling method of pore pressure redistribution around the multistage fractured horizontal wellbore was put forward based on the theory of fluid transportation in porous media. The fracture network of each stage was represented by an elliptical zone with high permeability. Five stages of fracturing were modelled simultaneously to consider the interactions among fractures. The effects of formation permeability, fracturing fluid viscosity, and pressure within the fractures on the pore pressure disturbance were numerically investigated. Modelling results indicated that the pore pressure disturbance zone expands as the permeability and/or the differential pressure increases, while it decreases when the viscosity of the frac...
Production Management for Hydraulic Fracturing in Naturally Fractured Shale Gas Reservoir
Proceedings of the 2013 (4th) International Conference on Engineering, Project, and Production Management
Recently, shale gas reservoirs have become more attractive for the petroleum industry because of the huge amount of reserves. However, without stimulation methods, production from a shale gas reservoir is almost impossible. Nanodarcy permeability can be characteristic of shale reservoirs. For this condition, natural gas does not flow easily or economically from the reservoir to the wellbore. Nowadays, in order to produce the gas from this type of reservoir, hydraulic fracturing is a common stimulation approach to achieve an economical gas production rate. Hydraulic fracturing provides conductive paths through the reservoir so that the gas is allowed to flow more easily. Therefore, the objectives of this study were to manage and improve the gas production from this type of reservoir and to design the hydraulic fracturing strategies in order to maximize gas production while minimizing the production time in naturally fractured shale gas reservoirs. A horizontal-wellbore production was utilized and the effects of several parameters on the production performance were investigated. These parameters were fracture width, fracture spacing, and number of fractures. The results of this study showed improvement of gas recovery. Both the number of fractures and fracture width apparently are important factors used to design hydraulic fracturing strategy. With an optimum strategy, gas recovery in shale gas reservoirs can be improved.
Impact Of Fracturing And Drainage-Wide Production On Tight Gas Reservoirs
Hydraulic fracturing has been established as perhaps the most compelling and attractive production enhancement technique for both conventional and tight gas reservoirs. However a number of formation evaluation considerations must be accounted such as the location and distance of water and hydrocarbon contacts, layering and other barriers which could limit achievable production results.
Energies
This paper describes a new modeling framework for microscopic to reservoir-scale simulations of hydraulic fracturing and production. The approach builds upon a fusion of two existing high-performance simulators for reservoir-scale behavior: the GEOS code for hydromechanical evolution during stimulation and the TOUGH+ code for multi-phase flow during production. The reservoir-scale simulations are informed by experimental and modeling studies at the laboratory scale to incorporate important micro-scale mechanical processes and chemical reactions occurring within the fractures, the shale matrix, and at the fracture-fluid interfaces. These processes include, among others, changes in stimulated fracture permeability as a result of proppant behavior rearrangement or embedment, or mineral scale precipitation within pores and microfractures, at µm to cm scales. In our new modeling framework, such micro-scale testing and modeling provides upscaled hydromechanical parameters for the reservoi...
Effective and Sustainable Hydraulic Fracturing, 2013
A comprehensive geomechanical study was carried out to optimize stimulation for a fractured tight gas reservoir in the northwest Tarim Basin. Conventional gel fracturing and acidizing operations carried out in the field previously failed to yield the expected productivity. The objective of this study was to assess the effectiveness of slickwater or low-viscosity stimulation of natural fractures by shear slippage, creating a conductive, complex fracture network. This type of stimulation is proven to successfully exploit shale gas resources in many fields in the United States. © 2013 Gui et al.; licensee InTech. This is an open access article distributed under the terms of the Creative Commons Attribution License (http://creativecommons.org/licenses/by/3.0), which permits unrestricted use, distribution, and reproduction in any medium, provided the original work is properly cited.
Journal of Petroleum Exploration and Production Technology
All reservoirs are fractured to some degree. Depending on the density, dimension, orientation and the cementation of natural fractures and the location where the hydraulic fracturing is done, preexisting natural fractures can impact hydraulic fracture propagation and the associated flow capacity. Understanding the interactions between hydraulic fracture and natural fractures is crucial in estimating fracture complexity, stimulated reservoir volume, drained reservoir volume and completion efficiency. However, because of the presence of natural fractures with diffuse penetration and different orientations, the operation is complicated in naturally fractured gas reservoirs. For this purpose, two numerical methods are proposed for simulating the hydraulic fracture in a naturally fractured gas reservoir. However, what hydraulic fracture looks like in the subsurface, especially in unconventional reservoirs, remain elusive, and many times, field observations contradict our common beliefs. ...