Mechanical stratigraphic controls on natural fracture spacing and penetration

2017 ◽  
Vol 95 ◽  
pp. 160-170 ◽  
Author(s):  
Ronald N. McGinnis ◽  
David A. Ferrill ◽  
Alan P. Morris ◽  
Kevin J. Smart ◽  
Daniel Lehrmann
Keyword(s):  
Natural Fracture ◽  
Fracture Spacing

High-resolution stratigraphic characterization of natural fracture attributes in the Woodford Shale, Arbuckle Wilderness and US-77D Outcrops, Murray County, Oklahoma

2018 ◽  
Vol 6 (1) ◽  
pp. SC29-SC41 ◽  
Author(s):  
Sayantan Ghosh ◽  
John N. Hooker ◽  
Caleb P. Bontempi ◽  
Roger M. Slatt
Keyword(s):  
Natural Fracture ◽  
Fracture Aperture ◽  
Aperture Size ◽  
Fracture Density ◽  
Area Formula ◽  
Woodford Shale ◽  
Fracture Spacing ◽  
Spacing Ratio ◽  
Fracture Intensity ◽  
Bed Thickness

Natural fracture aperture-size, spacing, and stratigraphic variation in fracture density are factors determining the fluid-flow capacity of low-permeability formations. In this study, several facies were identified in a Woodford Shale complete section. The section was divided into four broad stratigraphic zones based on interbedding of similar facies. Average thicknesses and percentages of brittle and ductile beds in each stratigraphic foot were recorded. Also, five fracture sets were identified. These sets were split into two groups based on their trace exposures. Fracture linear intensity (number of fractures normalized to the scanline length [[Formula: see text]]) values were quantified for brittle and ductile beds. Individual fracture intensity-bed thickness linear equations were derived. These equations, along with the average bed thickness and percentage of brittle and ductile lithologies in each stratigraphic foot, were used to construct a fracture areal density (number of fracture traces normalized to the trace exposure area [[Formula: see text]]) profile. Finally, the fracture opening-displacement size variations, clustering tendencies, and fracture saturation were quantified. Fracture intensity-bed thickness equations predict approximately 1.5–3 times more fractures in the brittle beds compared with ductile beds at any given bed thickness. Parts of zone 2 and almost entire zone 3, located in the upper and middle Woodford, respectively, have high fracture densities and are situated within relatively organic-rich (high-GR) intervals. These intervals may be suitable horizontal well landing targets. All observed fracture cement exhibit a lack of crack-seal texture. Characteristic aperture-size distributions exist, with most apertures in the 0.05–1 mm (0.00016–0.0032 ft) range. In the chert beds, fracture cement is primarily bitumen or silica or both. Fractures in dolomite beds primarily have calcite cement. The average fracture spacing indices (i.e., bed thickness-fracture spacing ratio) in brittle and ductile beds were determined to be 2 and 1.2, respectively. Uniform fracture spacing was observed along all scanlines in the studied beds.

Coupled Flow/Geomechanics Modeling of Interfracture Water Injection To Enhance Oil Recovery in Tight Reservoirs

SPE Journal ◽  
2020 ◽  
Author(s):  
Yongzan Liu ◽  
Lijun Liu ◽  
Juliana Y. Leung ◽  
Kan Wu ◽  
George Moridis
Keyword(s):  
Oil Recovery ◽  
Horizontal Well ◽  
Water Injection ◽  
Injection Rate ◽  
Natural Fracture ◽  
Tight Oil ◽  
Coupled Flow ◽  
Fracture Spacing ◽  
Tight Reservoirs ◽  
Enhance Oil Recovery

Summary Unconventional tight reservoirs that are typically characterized by low permeability and low porosity have contributed significantly to the global hydrocarbon production in recent years. Although hydraulic fracturing, along with horizontal well drilling, enables the economic development of such reservoirs, the production rate often declines sharply and results in low primary hydrocarbon recovery. The application of enhanced-oil-recovery (EOR) techniques in tight reservoirs has received much interest. In this study, the feasibility and efficiency of interfracture water injection to enhance oil recovery in multistage fractured tight oil reservoirs are analyzed through an efficient coupled flow/geomechanics model with an embedded discrete-fracture model (EDFM). A combined finite-volume/finite-element scheme is used to discretize the governing equations for flow and geomechanics, and the coupled problem is solved sequentially using a fixed-stress splitting algorithm. A basic numerical model consisting of a 15-stage fractured horizontal well is constructed using the petrophysical and geomechanical properties of a tight oil formation in Ordos Basin, China. Fractures indexed with even numbers are switched into injecting fractures when the production rate has dropped to less than a certain threshold. The improvement of oil recovery is analyzed by comparing the production profiles with and without water injection. In this coupled model, the fracture closure/opening during production/injection is considered according to the constitutive relations between fracture aperture and effective normal stress acting on the fracture faces. The poromechanical response of matrix is modeled by the Biot (1941) theory. The effects of fracture spacing, injection rate, and the presence of a natural-fracture network on oil-recovery enhancement are discussed through sensitivity analysis. The main mechanisms of interfracture water injection for enhancing oil recovery are waterflooding and reservoir-pressure maintenance. Small fracture spacing tends to reduce the oil recovery because of fracture interference and a limited drainage area; therefore, the primary depletion stage is shortened as the fracture spacing is reduced. The influence of interfracture water injection is more pronounced with smaller fracture spacing because the pressure-transient responses near the producing fractures are more dramatic considering the close proximity between the injecting fracture and the producing fracture. Although a higher injection rate results in higher oil recovery, the injectivity in low-permeability reservoirs limits the maximum-allowable injection rate. When secondary (natural)-fracture networks are considered, neighboring hydraulic fractures can be connected to one another via the secondary fractures, particularly if the interfracture spacing is small. Water can break through in the producing fractures quickly, which could also lead to high water cut and suboptimal oil-recovery performance. This study tests the feasibility and efficiency of interfracture injection to enhance tight oil recovery. The results indicate that interfracture injection can be a promising EOR technique for tight oil reservoirs, which sheds lights on future completion strategies and production design in tight reservoirs.

Interaction of static hydraulic fracture under constant fluid pressure with natural fracture

2018 ◽  
pp. 79-92
Author(s):  
A. Akulich ◽  
◽  
Li Kairui ◽  
D. Pestov ◽  
V. Tyurenkova ◽  
...  
Keyword(s):  
Hydraulic Fracture ◽  
Fluid Pressure ◽  
Natural Fracture

scholarly journals Case Study: Effect of Natural Fracture on Stimulation Strategy in Keshen Tight Gas

2020 ◽  
Vol 570 ◽  
pp. 062025
Author(s):  
Y Zhang ◽  
Z Chen ◽  
X Yang ◽  
Y Qiao ◽  
Q Teng ◽  
...  
Keyword(s):  
Natural Fracture ◽  
Tight Gas

scholarly journals Stress-Dependent Deformation and Permeability of a Fractured Coal Subject to Excavation-Related Loading Paths

2021 ◽  
Author(s):  
Wenzhuo Cao ◽  
Qinghua Lei ◽  
Wu Cai
Keyword(s):  
Coal Mining ◽  
Coalbed Methane ◽  
Axial Stress ◽  
Equilibrium Phase ◽  
Natural Fracture ◽  
Equivalent Permeability ◽  
Coal Matrix ◽  
Bedding Planes ◽  
Fractured Coal ◽  
Stress Dependent

AbstractThe deformation and permeability of coal are largely affected by the presence and distribution of natural fractures such as cleats and bedding planes with orthogonal and abutting characteristics, resulting in distinct hydromechanical responses to stress loading during coal mining processes. In this research, a two-dimensional (2D) fracture network is constructed based on a real coal cleat trace data collected from the Fukang mine area, China. Realistic multi-stage stress loading is designed to sequentially mimic an initial equilibrium phase and a mining-induced perturbation phase involving an increase of axial stress and a decrease of confining stress. The geomechanical and hydrological behaviour of the fractured coal under various stress loading conditions is modelled using a finite element model, which can simulate the deformation of coal matrix, the shearing and dilatancy of coal cleats, the variation of cleat aperture induced by combined effects of closure/opening, and shear and tensile-induced damage. The influence of different excavation stress paths and directions of mining is further investigated. The simulation results illustrate correlated variations among the shear-induced cleat dilation, damage in coal matrix, and equivalent permeability of the fractured coal. Model results are compared with results of previous work based on conventional approaches in which natural fracture networks are not explicitly represented. In particular, the numerical model reproduces the evolution of equivalent permeability under the competing influence of the effective stress perpendicular to cleats and shear-induced cleat dilation and associated damage. Model results also indicate that coal mining at low stress rates is conducive to the stability of surrounding coal seams, and that coal mining in parallel to cleat directions is desirable. The research findings of this paper have important implications for efficient and safe exploitation of coal and coalbed methane resources.

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