Physics-Based Forward Modeling of Multistage Hydraulic Fracturing in Unconventional Plays (original) (raw)
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Geomechanical Principles of Hydraulic Fracturing Method in Unconventional Gas Reservoirs
International Journal of Engineering, 2018
Unconventional gas production from shale formation is not new to oil and gas experts worldwide. But our research work was built around hydraulic fracturing technique with focus on the Perkins Kern-Nordgren (PKN) 1972 hydraulic fracturing model(s). It is a very robust and flexible model that can be used on two major shale reservoirs (with the assumption of a fixed height and fracture fluid pressure). The essence was to compare detailed geo-mechanical parameters extracted from wire-line logs with Perkin-C model to select the right well as candidate for simulation. It aided in the prediction production of shale gas from tight shale formations. These also helped in reviewing safe and economical ways of obtaining clean energy sources. Based on similarities in well and formation properties our research team subjected IDJE-2 well (located in the Agbada shale Formation of Niger Delta, Nigeria) to various conditions, equations and assumptions proposed by the study model while also validating our results with the PENOBSCOT L-30 well, located in Canada (with existing profound results from stimulations). The PENOBSCOT L-30 well (Case 1) and IDJE-2 well (Case 2) were both subjected to same conditions, equations and assumptions as applicable to the study model to enable us compare and evaluate stimulation performances. But both cases tend to react differently. However the fluid behavior at constant injection time increases at about 99.64%. Whereas, the maximum width at wellbore shows that a constant increase of fracture width will yield an increase in propant permeability, tensile strength and Poisson's ratio for Case 1 & 2. Our research results show how rock properties can affect fracture geometry and expected production rates from stimulated shale reservoir formations.
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...
A Novel Approach for Studying Hydraulic Fracturing Success Factors beyond Brittleness Indices
ARMA 18–0187, 2018
1. BACKGROUND United States has benefited economically from the boom in horizontal drilling and hydraulic fracturing technology, which rendered the development of domestic unconventional energy resources possible. US production of liquid fuels surpassed the Middle East in 2013 [Yo and Neff, 2014], adding 169,000 jobs between 2010 and 2012 [Brown and Yucel, 2013]. Reducing a country's dependence on the imported energy helps mitigate economic losses caused by foreign oil supply disruptions [Brown and Huntington, 2009]. The success of investment decisions pertaining to the exploitation of unconventional resources depends strongly on the reliability of models making predictions of post-stimulation performance. However, due to a lack of models based on accurate knowledge of the reservoir and rigorous understanding of the governing physics, there is a technology gap between the current models of stimulation and the field observations in the E&P industry. A major drawback associated with common hydraulic fracturing simulation methods is that they need prior knowledge on the fracturing path, meaning the outcome of the stimulation job should be fed as input to the model, rather than obtained as output. In addition, prevalent approaches for modeling performance of hydraulic fracturing jobs often fail to quantify the job results realistically, as linear elasticity and rock brittleness are the main underlying assumptions of most models. It has been shown, however, that there are a number of influence factors that need to be accounted for in prediction models. Brittle materials demonstrate a shorter period of ductile deformation before failure, which does not necessarily guarantee easier fracturing at lower ultimate rock strength values. Bai, 2016 states that, in fact, certain ductile formations may break at lower downhole pressures based on field measurements. Papanastasiou, 1997 incorporated the effect of plasticity in hydraulic fracturing using a cohesive crack model, showing that ductile rock behavior can lead to higher resulting fracture width values, while creating fractures with a smaller length. These observations suggest that limiting our target rocks and prediction models to linear elastic materials leads to inaccurate conclusions, since both mechanisms of brittle and ductile fracturing need to be considered for better modeling purposes. ABSTRACT: The success of hydraulic fracturing jobs is often related to rock brittleness indices, which are taken as the sole impact factor determining fracturing results. Indeed, hydraulic fractures play a principal role in producing from low-permeability reservoirs; however, brittleness is not the only parameter contributing to productivity of unconventional resources. Under a variety of circumstances, brittleness indices are insufficient to explain rock fracability and permeability enhancement during hydraulic stimulation. For better prediction and design, it is imperative to identify and understand other factors affecting fracture creation and propagation, and to build models that include the effect of these factors on flow enhancement. To numerically model permeability enhancement after injection, we can regard fractured rock as a damaged continuum, which allows simulation of the deformation and fracturing response of the reservoir using material constitutive laws for brittle and ductile regions. We outline a coupled flow-geomechanical simulation framework that fits into available reservoir simulation platforms and does not require pre-specified fracture paths. We develop the fracture growth mechanisms for the coupled simulation framework by analyzing the effect of rock properties and in-situ stresses on the fracture length at different injection pressures. Based on these mechanisms, we propose factors that quantify the success of hydraulic fracturing jobs beyond the simplified rock brittleness indices.
Geomechanical Coupled Modeling of Shear Fracturing in Non-Conventional Reservoirs
2013
Hydraulic fracturing is an essential tool for economical development of shale gas and tight gas reservoirs. Analysis of the performance of fracturing jobs and optimization of the treatment design requires modeling which accounts for all important features of the process and ideally covers both the treatment and post-stimulation production of the well. From micro-seismic monitoring and the stimulated wells production data it is now well established that the productivity of the wells is due not only to the classical tensile single plane fracture (SPF), but to the development of an enhanced permeability region (stimulated reservoir volume or SRV) around it caused by shear fracturing and/or stimulation of existing dual porosity. The shape and size of the SRV, and the permeability enhancement in the SRV depend on both the injection process and on the geomechanics of the reservoir (i.e., development of complex fracturing). Current techniques are not able to predict the SRV dependence on fracturing job and rock mechanics parameters, which precludes any meaningful optimization.
Proceedings of the 6th Unconventional Resources Technology Conference, 2018
The URTeC Technical Program Committee accepted this presentation on the basis of information contained in an abstract submitted by the author(s). The contents of this paper have not been reviewed by URTeC and URTeC does not warrant the accuracy, reliability, or timeliness of any information herein. All information is the responsibility of, and, is subject to corrections by the author(s). Any person or entity that relies on any information obtained from this paper does so at their own risk. The information herein does not necessarily reflect any position of URTeC. Any reproduction, distribution, or storage of any part of this paper by anyone other than the author without the written consent of URTeC is prohibited.
Hydraulic fracturing: a review of theory and field experience
2015
This report summarises the current state-of-the-art knowledge of the hydraulic fracturing process used by the shale gas/oil industry using open peer-reviewed literature and from government commissioned research reports. This report has been written to make statements on our knowledge of the following questions: • How do hydrofractures form? • How far do hydrofractures extend during stimulation? • What dictates where hydrofractures propagate? • How do hydrofractures interact with the existing fracture network? • Can the size and distribution of hydrofractures be controlled? Gaps in our knowledge have been highlighted, with the largest of these resulting from differences between North American and European shale rocks.
We showed the capability of CZM in modeling multiple-stage field-scale fracturing.We successfully substituted the minimum horizontal stress with infinite elements.We proposed a procedure to characterize cohesive layers for hydraulic fracturing.Closely spaced fracturing can disconnect the older fractures from the wellbore.Our model provides a fundamental stress interaction and irregular fracture growth.Economic production from shale gas cannot be achieved by natural mechanisms alone; it requires technologies such as hydraulic fracturing in multiple stages along a horizontal wellbore. Developing numerical models for hydraulic fracturing is essential since a successful fracturing job in a shale formation cannot be generalized to another due to different shale characteristics, and restricted access to the field data acquisition. The cohesive zone model (CZM) identifies the plastic zone and softening effects at the fracture tip in a quasi-brittle rock such as shale, which leads to a more precise fracture geometry and injection pressure compared to those from linear elastic fracture mechanics. The incorporation of CZM in a fully coupled pore pressure–stress, finite element analysis provides a rigorous tool to include also the significant effect of in situ stresses in large matrix deformations on the fracturing fluid flow components, for instance leak-off. In this work, we modeled single and double-stage fracturing in a quasi-brittle shale layer using an improved CZM for porous media besides including the material softening effect and a new boundary condition treatment, using infinite elements connecting the domain of interest to the surrounding rock layers. Due to the lack of experimental data for the cohesive layer properties, we characterized the cohesive layer by sensitivity study on the stiffness, fracture initiation stress, and energy release rate. We demonstrated the significance of rock mechanical properties, pumping rate, viscosity, and leak-off in the pumping pressure, and fracture aperture. Moreover, we concluded that the stress shadowing effects of hydraulic fractures on each other majorly affects not only fractures’ length, height, aperture, and the required injection pressure, but also their connection to the injection spot. Also, we investigated two scenarios in the sequence of fracturing stages, simultaneous and sequential, with various fracture spacing and recommended the best scenario among them.Fracture opening and interaction for the double-stage, sequential fracturing case with 33-ft spacing and fracturing the left perforation before the right one. In Fig. b, the displacements are magnified 200 times for demonstration purposes. The opening contours are in meters.
A Review of Hydraulic Fracturing Simulation
Archives of Computational Methods in Engineering
Along with horizontal drilling techniques, multi-stage hydraulic fracturing has improved shale gas production significantly in past decades. In order to understand the mechanism of hydraulic fracturing and improve treatment designs, it is critical to conduct modelling to predict stimulated fractures. In this paper, related physical processes in hydraulic fracturing are firstly discussed and their effects on hydraulic fracturing processes are analysed. Then historical and state of the art numerical models for hydraulic fracturing are reviewed, to highlight the pros and cons of different numerical methods. Next, commercially available software for hydraulic fracturing design are discussed and key features are summarised. Finally, we draw conclusions from the previous discussions in relation to physics, method and applications and provide recommendations for further research.
Rock deformation models and fluid leak-off in hydraulic fracturing
Geophysical Journal International, 2013
Fluid loss into reservoir rocks during hydraulic fracturing is modelled via a poro-elastoplastic pressure diffusion equation in which the total compressibility is a sum of fluid, rock and pore space compressibilities. Inclusion of pore compressibility and porosity-dependent permeability in the model leads to a strong pressure dependence of leak-off (i.e. drainage rate). Dilation of the matrix due to fluid invasion causes higher rates of fluid leak-off. The present model is appropriate for naturally fractured and tight gas reservoirs as well as for soft and poorly consolidated formations whose mechanical behaviour departs from simple elastic laws. Enhancement of the leak-off coefficient by dilation, predicted by the new model, may help explain the low percentage recovery of fracturing fluid (usually between 5 and 50 per cent) in shale gas stimulation by hydraulic fracturing.
Comprehensive mechanism-based investigation of stimulations in naturally fractured reservoirs promotes the development of new hydraulic fracture models in a finite element method platform, Abaqus. Our triple-stage, triple-wellbore hydraulic fracturing simulations are accomplished using fully coupled pore-pressure-stress analyses, a well-established mechanism-based intersection model based on cohesive zone model, and a novel universal wellbore-perforation model for simultaneous and sequential fracturing scenarios. We quantified cluster stimulation, the activation of a complex natural fracture (NF) network, and fluid infiltration depending on the stimulation scenario, wellbore pressure drop, randomly distributed perforation lengths, and fracturing fluid viscosity. The stimulation patterns are featured by the following: 1) dominant effect of the perforation tunnel lengths in the cluster stimulation in the presence of the wellbore model; 2) doubled cluster stimulation in the absence of the NF network; 3) more control on the cluster stimulation and wider stimulated reservoir volumes in sequential fracturing compared to simultaneous fracturing; and 4) stronger stress shadowing effect in sequential fracturing with hydraulic pressure connectivity of stage clusters through the wellbore. This mechanistic model that integrates the NF network, its intersection with the hydraulic fractures, and the hydraulic connection of perforations through the wellbore clearly demonstrates a technique to refine stimulated reservoir volumes and better explain microseismic anomalies.