|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
Abstract In this case study, we apply a novel fracture imaging and interpretation workflow to take a systematic look at hydraulic fractures captured during thorugh fracture coring at the Hydraulic Fracturing Test Site (HFTS) in Midland Basin. Digital fracture maps rendered using high resolution 3D laser scans are analyzed for fracture morphology and roughness. Analysis of hydraulic fracture faces show that the roughness varies systematically in clusters with average cluster separation of approximately 20' along the core. While isolated smooth hydraulic fractures are observed in the dataset, very rough fractures are found to be accompanied by proximal smoother fractures. Roughness distribution also helps understand the effect of stresses on fracture distribution. Locally, fracture roughness seems to vary with fracture orientations indicating possible inter-fracture stress effects. At the scale of stage lengths however, we see evidence of inter-stage stress effects. We also observe fracture morphology being strongly driven by rock properties and changes in lithology. Identified proppant distribution along the cored interval is also correlated with roughness variations and we observe strong positive correlation between proppant concentrations and fracture roughness at the local scale. Finally, based on the observed distribution of hydraulic fracture properties, we propose a conceptual spatio-temporal model of fracture propagation which can help explain the hydraulic fracture roughness distribution and ties in other observations as well.
Ju, Yang (China University of Mining and Technology (Corresponding author) | Wu, Guangjie (emails: email@example.com or firstname.lastname@example.org)) | Wang, Yongliang (China University of Mining and Technology) | Liu, Peng (China University of Mining and Technology) | Yang, Yongming (China University of Mining and Technology)
Summary In this paper, we introduce the entropy weight method (EWM) to establish a comprehensive evaluation model able to quantify the brittleness of reservoir rocks. Based on the evaluation model and using the adaptive finite element-discrete element (FE-DE) method, a 3D model is established to simulate and compare the propagation behavior of hydraulic fractures in different brittle and ductile reservoirs. A failure criterion combining the Mohr-Coulomb strength criterion and the Rankine tensile criterion is used to characterize the softening and yielding behavior of the fracture tip and the shear plastic failure behavior away from the crack tip during the propagation of a fracture. To understand the effects of rock brittleness and ductility on hydraulic fracture propagation more intuitively, two groups of ideal cases with a single failure mode are designed, and the fracture propagation characteristics are compared and analyzed. By combining natural rock core scenarios with single failure mode cases, a comprehensive evaluation index BIf for reservoir brittleness and ductility is constructed. The simulation experiment results indicate that fractures in brittle reservoirs tended to form a complex network. With enhanced ductility, the yielding and softening of reservoirs hamper fracture propagation, leading to the formation of a simple network, smaller fracture area (FA), larger fracture volume, and the need for higher initiation pressure. The comprehensive index BIf can be used to define brittleness or ductility as the dominant factor of fracturing behavior. That is, 0 < BIf ≤ 0.46 indicates that the reservoir has enhanced ductility and ductile fracturing prevails; 0.72 < BIf < 1 indicates that the reservoir has enhanced brittleness and brittle fracturing prevails; and 0.46 < BIf ≤ 0.72 means a transition from brittle to ductile fracturing. Based on fitting analysis results, the relationship between the calculated FAr and BIf is constructed to quantify the influence of reservoir brittleness and ductility on fracturing. The study provides new perspectives for designing, predicting, and optimizing the fracturing stimulation of tight reservoirs with various brittleness and ductility.
Hui, Zhao (School of Petroleum Engineering, Yangtze University) | Guanglong, Sheng (School of Petroleum Engineering, Yangtze University) | Luoyi, Huang (School of Petroleum Engineering, Yangtze University) | Xun, Zhong (School of Petroleum Engineering, Yangtze University) | Jingang, Fu (School of Petroleum Engineering, China University of Petroleum, East China) | Yuhui, Zhou (School of Petroleum Engineering, Yangtze University) | Jialing, Ma (School of Petroleum Engineering, Yangtze University) | Jiayu, Ruan (School of Petroleum Engineering, Yangtze University) | Zhouxiang, Hu (Shenzhen Branch, China National Offshore Oil Corporation) | Shumin, Sun (School of Petroleum Engineering, Yangtze University)
Abstract Accurately characterizing fracture network morphology is necessary for flow simulation and fracturing evaluation. The complex natural fractures and reservoir heterogeneity in unconventional reservoirs make the induced fracture network resulting from hydraulic fracturing more difficult to describe. Existing fracture propagation simulation and fracture network inversion methods cannot accurately match actual fracture network morphology. Considering the lightning breakdown similar as fracture propagation, a new efficient approach for inversion of fracture network morphology is proposed. Based on the dielectric breakdown model (DBM) for lightning breakdown simulation and similarity principle, an induced fracture propagation algorithm integrating reservoir in-situ stress, rock mechanical parameters, and stress shadow effect is proposed. The fractal index and random function are coupled to quantitatively characterize the probability distribution of induced fracture propagation path. At the same time, a matching rate function is proposed to quantitatively evaluate the fitting between fracture network morphology and the micro seismic data. Combined with automatic history matching method, the actual fracture network morphology can be inverted with the matching rate as objective function. The proposed approach is applied to fracture network simulation of mult-fractured horizontal wells of shale oil reservoir in China, and the fracture networks from inversion fit well with the micro seismic data. A simulation of 94 fractures in the 32 section of Well X2 shows that the well propagates more obvious branch fractures. The single-wing fracture network communicates approximately 200m horizontally and approximately 10m vertically. In single fracture flow simulation, it is necessary to consider the influence of complex fracture network morphology, but when simulating fluid flow for a single well or even a reservoir, only the main fracture needs to be considered. This paper proposes an induced fracture propagation algorithm that integrates reservoir in-situ stress, rock mechanical parameters, and stress shadowing effects. This algorithm greatly improves the calculation efficiency on the premise of ensuring the accuracy of induced fracture network morphology. The approach in this paper provides a theoretical basis for flow simulation of stimulated reservoirs and optimization of fracture networks.
Liu, Wenzheng (China University of Petroleum (East China) and University of Lille) | Zeng, Qingdong (Shandong University of Science and Technology) | Yao, Jun (China University of Petroleum (East China) (Corresponding author)
Summary In this paper, we propose a hydromechanical model to simulate hydraulic fracture propagation in deep shale formations. The Drucker-Prager plasticity theory, Darcy’s law, Reynolds lubrication theory, and Kirchoff’s laws are adopted to describe the plastic deformation, matrix flow, fracture flow, and wellbore flow, respectively. A global embedded cohesive zone model is constructed to achieve the free evolution of hydraulic fractures and the characterization of natural fractures. The finite element method (FEM) and finite volume method (FVM) are used for the spatial discretization of the stress field and pressure field. On the basis of Newton-Raphson iteration, fixed-stress iteration, and Picard iteration, a mixed numerical scheme is built up to solve the strong nonlinear coupling problem. The proposed model is verified against several reference cases and experimental results. Finally, some numerical cases are carried out to investigate the influences of rock properties, natural fracture distribution, and fracturing fluid properties on the complex hydraulic fracture development. The results show that rock plasticity leads to a decrease in stimulated fracture area, an increase in average fracture width, and an increase in propagation pressure. As the cluster number increases, the adverse effect of rock plasticity on multiple hydraulic fracturing in deep shale formations increases significantly. In addition, appropriate optimization of cluster spacing could weaken the adverse effect of rock plasticity on fracturing treatment to a certain extent by using the stress interference effect.
Summary A modular multiphysics reservoir-simulation system is developed that has the capability of simulating multiphase/multicomponent/thermal flow, poro-elasto/plastic geomechanics, and hydraulic-fracture evolution. The focus of the work is on the full-physics hydraulic-fracture-evolution-simulation capability of the multiphysics simulation system. Fracture-growth computations use a cohesive-zone model as part of the computation of fracture-propagation criterion. The cohesive-zone concept is developed using energy-release rates and cohesive stresses. They capture the strain-softening behavior of deforming porous material consistent with real-life observations of poro-plastic deformation. Thus, they can be reliably used within both poro-elastic and poro-plastic geomechanics applications, unlike the conventional stress-intensity-factor-based fracture-propagation criterion. The partial-differential equations (PDEs) that govern the Darcy-scale multiphase/multicomponent/thermal flow, poro-elasto/plastic geomechanics, hydraulic-fracture evolution, and laminar channel flow in the fracture are tightly coupled to each other to give rise to a numerical protocol solvable by the fully implicit method. The ensuing nonlinear system of equations is solved by use of a novel adaptively damped Newton-Raphson method. Example fully coupled single-phase isothermal-flow, geomechanics, and hydraulic-fracture-growth simulations are analyzed to demonstrate the predictive power of the simulation system. Numerical-model predictions of fracture length/radius and width are validated against analytical solutions for plane-strain and ellipsoid-shaped fractures, respectively. Results indicate that the simulation system is capable of modeling hydraulic-fracture evolution accurately by use of the cohesive-zone model as the propagation criterion. We also simulate and explore the sensitivities around a real-life hydraulic-fracture-growth problem by fully accounting for the thermal-, multiphase-, and compositional-flow effects.
This paper introduces a new carbon dioxide (CO2) -hybrid fracturing-fluid design that intends to improve production from ultratight reservoirs and reduces freshwater usage. The authors present simulation work that demonstrates how CO2, with its low viscosity, can extend the bottomhole treating pressure deeper into the reservoir and generate a larger producible surface area. They also present experimental evidence that CO2 leaves behind higher unpropped-fracture conductivities than slickwater (hereafter designated as FR water). The theory of improved recovery with the CO2-hybrid fracturing design is predicated on the assumption that current stimulation treatments with water-based fluids understimulate the reservoir by leaving behind damaged (conductivity-inhibited) stimulated regions deeper in the reservoir. Conversely, O2 can improve drainage and recovery from these unpropped regions by (1) extending the bottomhole treating pressure deeper into the reservoir, (2) improving the stimulated fracture coverage by increasing both the number of stimulated fractures and their density (number of fractures per unit of volume), and (3) improving the conductivity of the stimulated unpropped channels.
Abstract This paper will describe a workflow undertaken to address potential risks highlighted by a review of a well abandonment plan. The specific issue is described by the potential for failure of a secondary abandonment plug, should the primary plug set relatively deeper had failed. In the case of these events, pressures were sufficient to generate a risk of uncontrolled fracture propagation at the second plug. The initial high fracturing risk was evaluated based on a simple comparison of fracture pressure vs. reservoir pressure column analysis; e.g. the reservoir would deliver a pressure greater than the original fracture pressure at the second and shallower plug depth. To better evaluate the real fracture behaviour and the risk associated with failure of the first plug, a more comprehensive approach was deemed necessary. The main objective of the more detailed study was to investigate the likelihood of fracture initiation, the associated height growth and containment within immediate plug depth formation and overburden. This would be based on the charging pressure and flow volume from the reservoir zone into the plug depth formation. A comprehensive coupled reservoir-geomechanics-fracturing numerical approach was adopted. This included a dynamic fracturing calculation using a non-linear Barton-Bandis material model embedded in a coupled finite-element geomechanical and a multiphase thermal finite-difference flow simulator. In the coupled solution, the fracture propagation is controlled by the nonlinear fracture stiffness and the normal effective stress. The fracture permeability is a function of the fracture width resulting from the poroelastic stress-strain coupled calculations triggered by the reservoir inflow pressure. The modelling results have shown that when a simple low shale permeability was assumed for the second plug and overburden formations, a fracture will rapidly develop vertically up to seabed due to the lower stresses at shallower depths in this low leakoff scenario. However, it was noted that the worst case scenario (uncontrolled fracture growth) was for minimal permeable intervals up to the seabed. In reality the geology using more realistic lithological data showed that overburden has several permeable zones. Accounting for these intervals in the coupled model, the same fracture growth through tight zones was seen, but the growing fracture became vertically contained when reached the permeable intervals. A permeable layer acts as a pressure sink and causes the propagating fracture to lose the energy required for further vertical growth. Sensitivities with overburden permeability, thickness and the estimated reservoir volume were performed. These illustrated that the fracture lateral extension below the overburden permeable sand is largest when the sand permeability and thickness are smaller in magnitudes, and that permeability is the dominant factor. The modelling analysis served to de-risk the likely fracture propagation and containment in an abandoned well in the hypothetical case were failure of the first plug exposes high pressure at a second plug. Even if such failure occurs, it will be a safer (and more cost-effective) alternative, to leave the second plug as its current depth rather than to perform a well re-entry to remove and set it deeper.
Medina, Pablo (Buenos Aires Institute of Technology) | Jin, Manuel (Buenos Aires Institute of Technology) | D’hers, Sebastián (Buenos Aires Institute of Technology) | Frydman, Marcelo (Independent Geomechanics Advisor)
Oil operators have faced technical challenges while drilling and producing wells in the Vaca Muerta formation (Argentina). Wells must be hydraulically fractured for stimulation and in situ stress strongly influence this process. During stimulation, several geomechanics-related issues can occur, which have the potential to negatively impact the operation of the field. Different studies suggest a strike-slip regime in the Vaca Muerta formation. Furthermore, several sections of the formation exhibit intercalations of organic shale with limestone, ash beds, and carbonate veins. The combined effect of the reduced stress difference and the material fabric may promote horizontal fractures. The present paper discusses numerical modeling of the stresses during hydraulic fracture propagation considering actual properties for Vaca Muerta formation. A case study is presented, where the effects of different features are being quantified.
Shale is characterized by thin laminate or parallel layering and exhibits transversely isotropic properties with symmetric axes perpendicular to the bedding. The rock behavior is modeled using Biot’s poroelastic theory (Detournay
This paper presents numerical modeling and results of hydraulic fracture growth in a shale reservoir. This fracture growth is limited by a limestone layer, and there is a weak interface between the limestone and the organic shale. The analysis is focused on the interaction mechanism between this weak interface and the hydraulic fracture. Three possible ways of propagation may occur, which are: arrest, crossing and T-shapes fractures. In order to represent this phenomenon, a cohesive model with mixed damage (mode I and mode II)is developed.
Fracture-interface interaction mechanisms have been first studied by Blanton (Blanton
Currently, most geomechanical models used by the industry are based on simple assumptions. Vaca Muerta cannot be evaluated with traditional models or on the basis of planar vertical fractures (Geertsma
This paper discusses one of the required steps to move forward to a more realistic numerical representation. It has developed a consistent geomechanical characterization and applications for completion strategy in unconventional reservoirs. This information is critical for completion design and must be used as a decision maker for fracture stages and landing points.
Plug and Perf (PnP) completions have been the most widely used multistage hydraulic fracturing methods in unconventional wells. In a PnP completion, isolation between stages is achieved by setting frac plugs inside the horizontal liner. The number of perforation clusters and perforation holes are designed using limited entry perforating techniques.
While PnP is a proven method, there are also some downsides, particularly when considering the inability to pump plugs due to changes in casing integrity and casing deformation occurring in 20-30% of horizontal wells. Casing damage has been increasingly recognized as a challenge to well integrity in active or child wells during multistage hydraulic fracturing. Casing deformation and reduction in casing inside diameter (ID) prevent the use of PnP operations due to frac plugs being unable to pass through deformed casing.
Cemented multi-entry ball-activated fracturing sleeves (ME-BAFS) allow users to imitate the limited entry effect of PnP completions while eliminating the need to deploy large OD frac plugs for each stage. The multiple entry points are activated using various-sized frac balls dropped from the surface as the stimulation treatment is pumped, eliminating the need to rig up and rig down between stages. After fracturing is complete, the frac balls either dissolve or are flowed to surface allowing production to begin immediately eliminating through-tubing intervention. The multi-entry ball-activated fracturing sleeves use graduated balls and ball seats to open as many as five sleeves per stage with a single frac ball for increased efficiency. Number of clusters and entry points are calculated based on limited entry techniques similar to PnP.
Within this study, two limited entry techniques, PnP and multi-entry sleeve systems, are evaluated using commercial fracture modeling software, and well production modeling to compare the steady-state production between PnP and multi-entry ball-activated fracturing sleeves. Hydraulic fracture modeling is also used to evaluate limited entry perforation design, perf erosion, stress shadowing, and fracture propagation.
Fractures serve as important conduits for subsurface fluid flow and their presence can transform an otherwise unproductive rock formation into an economic hydrocarbon reservoir. Natural fractures have a vivid impact on reservoirs, especially the low perm, as they control the hydraulic flow as conductors (open fractures) or barriers (sealed fractures). Abu Dhabi carbonates are dissected by many fracture clusters, but most of them are sealed, therefore it is critical to investigate, which sets are predicted to reactivate. Hydraulic fracturing in horizontal drilling are the primary enabling technology to gain economical production from the low perm reservoirs. However, fracture parameters are poorly constrained by reservoir data, due to they are subseismic and hard to predict their behaviour through the life-cycle of the reservoir. Addressing the structural patterns and using the geomechanical data along well bores help to assess their roles in production enhancement and sensitivity to hydraulic fractures initiation and propagation.
The spatial distribution of microfaults, hybrid fractures and pure opening mode fissures with wide variations in strike appears related to their location with respect to the deformation zones of the nearby fault segments in the reservoirs of Abu Dhabi. Usually not all fracture sets enhancing production and the best approach is to predict those sets that playing these roles.
The ability of fractured bedrock to transmit fluids depends upon the physical characteristics of the fractures and opening-mode fractures that make up the fracture system, such as fracture aperture, fracture length, fracture density, fault displacement and gouge thickness. Many of the hydraulically significant fractures at the reservoir scale cannot directly detected, neither by borehole imaging tools nor by seismic imaging. Thus, reservoir characterization, in terms offracture architecture models, are derived from a combination of well data and the factors that control fracture development in carbonate reservoirs of Abu Dhabi. These factors include stratigraphy, rock properties, kinematics, especially orientations and mechanics of fracture growth and principally their relation to the present day in situ stresses.
The results showing that, hydraulic fractures propagation is dependent on the natural fractures and bedding planes orientations and the well location relative to the fault segments deformation zones. Understanding and predicting the behavior of fractures involves the identification and location of hydraulically significant fractures. Such fractures are conduits for fluid flow, and are connected to other hydraulically conductive fractures to form conduit systems. Conductive fracture networks may include a large number of interconnected hydraulically active fractures, or may be limited to a very small proportion of the total fractures in the rock mass.