Fractured Hydrocarbon Reservoirs Research Articles

Iron Stress Testing of Oilfield Produced Waters and Hydraulic Fracturing Fluids in the Bakken

Friction reducers are a major additive in almost all water-based hydraulic fracturing fluids. Despite the important role they play in friction reduction during hydraulic fracturing, they pose a veritable threat to the permeability of tight reservoirs upon precipitation. In the industry today, the potential for such precipitation is seldom assessed and as a result, an additional contributor to the formation damage problem has been given little attention. In this work, the sensitivity and affinity of friction reducers to very low concentrations of ferric ions are exploited to provide a qualitative assessment of their propensity to precipitate in hydraulically fractured hydrocarbon reservoirs. Representative samples of produced water and a routinely utilized hydraulic fracturing fluid recipe were spiked with 50ppm Iron (III) trichloride and incubated for 24 hours in a water bath at 200 degrees Fahrenheit. The results showed that precipitation of friction reducers in fracturing fluid is highly likely at low concentrations of ferric ions. This precipitate formed turned from yellow to brown color over time upon heating. The test showed presence of fragmented/unfragmented Partially Hydrolyzed Polyacrylamide (PHPAM) in the produced water, with varying degrees of FR gel precipitation depending on the processing treatment given to the water used for hydraulic fracturing. Evidence for the presence of partially hydrolyzed polyacrylamide was demonstrated in one of the produced waters while the rest did not produce any discernable precipitates. The results indicate that formations with lower iron concentrations may be more vulnerable to Fe3+-PHPAM precipitation than those with higher ferric ion concentration. Therefore, to mitigate formation damage through precipitation of FRs during hydraulic fracturing, a routine iron stress test like the one described herein is required on both hydraulic fracturing fluid and produced water to determine the vulnerability of the reservoir to formation damage by fragmented/unfragmented anionic PHPAMs.

DFN modelling constrained by multiple seismic attributes using the steering pyramid technology

Fracture modelling is essential for understanding fluid flow in fractured hydrocarbon reservoirs, particularly in the phase of production; however, traditional discrete fracture network (DFN) modelling methods lack constraints that reflect characteristics of fracture development. Fractures or fracture networks exhibit a high degree of randomness; as such, it is difficult to model fracture characteristics. This paper proposes a new approach for DFN modelling constrained by seismic attributes. Firstly, the steerable pyramid method is adopted to improve seismic data resolution; secondly, multiple seismic attributes are extracted and combined into a composite attribute to characterize fracture spatial distribution; finally, a DFN modelling method is established by using the composite attribute as a location constraint. To verify the effectiveness of the approach, a case study is conducted in the Bonan Depression, in East China. The results show that, compared with the traditional DFN modelling methods, the DFN modelling with the location constraint create a more realistic fracture model which accurately reflects fracture distribution characteristics. The application demonstrates the potential of wide application prospects in fractured reservoirs.

Simulation of electromagnetic high-frequency wave propagation processes in multilayer geo-structures

The paper describes the research findings on georadar detection of hydraulic fractures in hydrocarbon reservoirs. Numerical and physical modeling enables studying effect exerted by the electromagnetic properties of the created fracture fill and by the properties of the enclosing formation on the coefficient of high-frequency EM wave reflection from the interface.

Utilizing a kinematic and mechanical modelling workflow to constrain fracture network characteristics: Application to the Teapot Dome, Wyoming, USA

Predicting natural fracture networks is critical for unconventional hydrocarbon exploration, carbon capture/storage, and geothermal energy projects. Developing an accurate picture of key fracture network attributes such as intensity and orientation can be challenging, with difficulties arising from the limited and incomplete information typically offered to construct quantitative models.In a new process-based workflow we combine geometrical/kinematic and physics-based mechanical forward models. Realistic geometries guide the evolutionary forward model based on kinematic algorithms derived from naturally deformed rocks, while the mechanisms and conditions dictating fracture attributes are modelled directly as a result of key geomechanical properties and underlying physical laws. Collectively this workflow aims to improve understanding of subsurface fracture distributions by representing the inferred strain history and relating this to fracture attributes; this may go some way to addressing any uncertainty regarding the deformation of key stratigraphic intervals and permit construction of more representative fracture network models.The techniques are applied to a real-world data set from the fractured hydrocarbon reservoirs of the Teapot Dome anticline in Wyoming, USA, and specifically a 2D seismic section through the culmination of the structure. The doubly-plunging, basement-cored anticline developed above a blind fault and is modelled as a fault-propagation/trishear evolutionary forward model while tracking the state of strain. The results illustrate the potential of predicting fracture formation throughout the evolution of a structure with high granularity and detail, and in response to the different rock types and their structural position.

A type-curve method for two-phase flowback analysis in hydraulically fractured hydrocarbon reservoirs

As a powerful technique for quantitative production data analysis, type curves play an essential role in estimating reservoir and fracture properties. However, two-phase flow after hydraulic fracturing furthers the governing equation's nonlinearity and introduces substantial errors in type-curve analysis, which must be extended to two-phase systems. This study presents a new type-curve method to characterize hydraulic fracture (HF) attributes and dynamics by analyzing two-phase flowback data from multi-fractured horizontal wells (MFHWs) in hydrocarbon reservoirs. The proposed method is, to the best of our knowledge, the first semi-analytical type-curve approach that not only considers the two-phase flow in both fracture and matrix, but also takes variable BHP and rate conditions. Meanwhile, a new set of dimensionless groups are proposed to incorporate the complexity of the coupled two-phase flow in fracture and matrix into one unique curve, rather than families of curves, which significantly reduces the non-uniqueness issue of type-curve matching for MFHWs. Unlike other two-phase type curves, the pressure and saturation dependent parameters in the dimensionless groups are rigorously evaluated at the average properties within the HF based on the material balance equations. The accuracy of the proposed method is tested using the synthetic data generated from six numerical simulation cases for shale gas and oil reservoirs. The numerical validation confirms the unique behavior of type curves during fracture boundary dominated flow and verifies the accuracy of the type-curve analysis in the characterization of fracture properties. For field application, the proposed method is applied to two MFHWs in Marcellus shale gas and Eagle Ford shale oil. The agreement of interpreted results between the proposed method and straight-line analysis not only demonstrates the practicality in field application but also illustrates the superiority of the type-curve method as an easy-to-use technique to analyze two-phase flowback data.

Localisation of Ancient Migration Pathways inside a Fractured Metamorphic Hydrocarbon Reservoir in South-East Hungary

Numerous fractured hydrocarbon reservoirs exist in the metamorphic basement of the Pannonian Basin in Hungary. Many decades of experience in production have proven that these reservoirs are highly compartmentalised, resulting in a complex mosaic of permeable and impermeable domains situated next to each other. Consequently, in most fields, only a small amount of the total hydrocarbon reserve can be extracted. This paper aims to locate the potential migration pathways inside the most productive basement reservoir of the Pannonian Basin, using a multiscale approach. To achieve this, evaluation well-log data, DFN modelling and a composition analysis of fluid trapped in a vein-filling zeolite phase are combined. Data on a single well are presented as an example. The results of the three approaches indicate the presence of two highly fractured intervals separated by a barely fractured amphibolite. The two zones are probably part of the communicating fracture system inside the single metamorphic mass. The gas analysis further specifies the migrated fluids and indicates hydrocarbons of a composition similar to that of the recently produced oil. Consequently, we conclude that the two zones do not only form an ancient migration pathway but are also members of a more recent hydrocarbon system.

Lithologically controlled behaviour of the Dorozsma metamorphic hydrocarbon reservoir (Pannonian Basin, SE Hungary)

Numerous fractured hydrocarbon reservoirs occur in the metamorphic basement of the Pannonian Basin in Hungary, and among them, the Dorozsma field is one of the most productive. Here 66 boreholes penetrated the metamorphic massif, making detailed petrographic and microstructural evaluation possible. Well-log data (gamma-ray, density, neutron porosity and compressional slowness) are available for each well, which can be used to extend the petrographic information spatially.The data suggest three basic rock types in the study area, which align along a consequent rock column. In the deepest structural positions, amphibolite is typical, while the top of the basement is dominated by kyanite gneiss. Thermobarometric calculation results prove that the gneiss-rich realm was metamorphosed at a significantly higher temperature than the lowermost amphibolite, suggesting a post-metamorphic structural contact between them. The contact zone, observed in numerous boreholes, contains intensively deformed dolomite marble of a few tens of metres in thickness. The peak metamorphic temperature of this rock type is much lower than those typically seen in the two neighbouring blocks. Localising the position of the dolomite marble horizon in each well was accomplished using petrographic and well-log information, and through this investigation, a flat, low-angle shear zone became visible, cut by a set of younger normal faults. Hydrocarbon production data clearly shows that the best, most productive intervals in each well are strongly correlated to the shear zone between the gneiss- and amphibolite-dominated realms, namely the sheared dolomite marble zone.

The nature and age of basement host rocks and fissure fills in the Lancaster field fractured reservoir, West of Shetland

Hosting up to 3.3 billion barrels of oil in place, the upfaulted Precambrian crystalline rocks of the Lancaster field, offshore west of Shetland, give key insights into how fractured hydrocarbon reservoirs can form in such old rocks. The Neoarchean ( c. 2700–2740 Ma) charnockitic basement is cut by deeply penetrating oil-, mineral- and sediment-filled fissure systems seen in geophysical and production logs and thin sections of core. Mineral textures and fluid inclusion geothermometry suggest that a low-temperature (<200°C) near-surface hydrothermal system is associated with these fissures. The fills help to permanently prop open fissures in the basement, permitting the ingress of hydrocarbons into extensive well-connected oil-saturated fracture networks. U–Pb dating of calcite mineral fills constrains the onset of mineralization and contemporaneous oil charge to the mid-Cretaceous and later from Jurassic source rocks flanking the upfaulted ridge. Late Cretaceous subsidence and deposition of mudstones sealed the ridge, and was followed by buoyancy-driven migration of oil into the pre-existing propped fracture systems. These new observations provide an explanation for the preservation of intra-reservoir fractures (‘joints’) with effective apertures of 2 m or more, thereby highlighting a new mechanism for generating and preserving fracture permeability in sub-unconformity fractured basement reservoirs worldwide. Supplementary material: Analytical methods and isotopic compositions and ages are available at https://doi.org/10.6084/m9.figshare.c.4763237 Thematic Collection: This article is part of the Geology of Fractured Reservoirs collection available at: https://www.lyellcollection.org/cc/the-geology-of-fractured-reservoirs

Coping with uncertainties through an automated workflow for 3D reservoir modelling of carbonate reservoirs

Reliable 3D modelling of underground hydrocarbon reservoirs is a challenging task due to the complexity of the underground geological formations and to the availability of different types of data that are typically affected by uncertainties. In the case of geologically complex depositional environments, such as fractured hydrocarbon reservoirs, the uncertainties involved in the modelling process demand accurate analysis and quantification in order to provide a reliable confidence range of volumetric estimations. In the present work, we used a 3D model of a fractured carbonate reservoir and populated it with different lithological and petrophysical properties. The available dataset also included a discrete fracture network (DFN) property that was used to model the fracture distribution. Uncertainties affecting lithological facies, their geometry and absolute positions (related to the fault system), fracture distribution and petrophysical properties were accounted for. We included all different types of uncertainties in an automated approach using tools available in today’s modelling software packages and combining all the uncertain input parameters in a series of statistically representative geological realizations. In particular, we defined a specific workflow for the definition of the absolute permeability according to an equivalent, single porosity approach, taking into account the contribution of both the matrix and the fracture system. The results of the analyses were transferred into a 3D numerical fluid-dynamic simulator to evaluate the propagation of the uncertainties associated to the input data down to the final results, and to assess the dynamic response of the reservoir following a selected development plan. The “integrated approach” presented in this paper can be useful for all technicians involved in the construction and validation of 3D numerical models of hydrocarbon-bearing reservoirs and can potentially become part of the educational training for young geoscientists and engineers, since an integrated and well-constructed workflow is the backbone of any reservoir study.

Natural fracture system of the Cambro-Permian Wajid Group, Wadi Al-Dawasir, SW Saudi Arabia

This study investigates the regional and outcrop-scale fracture system within the Wajid Group exposures in Wadi Al-Dawasir, southwest Saudi Arabia. The Wajid Group is a Cambro-Permian siliciclastic succession that forms the main groundwater aquifers in the study area and is considered as a potential hydrocarbon reservoir in the Rub' Al-Khali Basin. The succession is composed of fluvial, marine, and glacial to glaciofluvial deposits. This study aims to characterize and model the fracture system within the Wajid Group in the Wadi Al-Dawasir area using satellite imagery and direct field measurements. A further study objective is to define the geological factors controlling the fracture distribution within the Wajid Group succession. Five sets of regional-scale fractures (lineaments) were defined: N000°, N015°, N035°, N075°, and N135°. In addition, five sets of the outcrop-scale fractures were delineated: N015°, N035°, N075°, N135°, and N165°. The N135°- and N035°-oriented fracture sets are predominant at the regional scale. At the outcrop scale, however, the N165°- and N075°-oriented fracture sets are predominant. The trace-length of the regional-scale fractures is distributed according to the negative exponential distribution. The fractures within the Wajid Group outcrops are vertical to sub-vertical extensional fractures (mode 1). Those fractures are open, however, and at some localities, they are sealed or coated with calcite or iron oxides. Fracture swarms with an orientation of N015° were also observed in the southeastern part of the study area. Hierarchical outcrop conceptual models of two fracture sets are proposed. The proposed models show that the regional-scale fractures are not influenced by stratigraphic or lithological variations. In contrast, the outcrop-scale fractures are controlled by the stratigraphic, lithological, and diagenetic variations in the fracture-hosting sandstone. The diagenetic characteristics (cementation and dissolution), bed thickness, and porosity of the fracture-hosting sandstone play a key role in the fracture distribution within the Wajid succession. The results of this study contribute to the understanding of groundwater flow behaviour within fractured aquifers in the study area and will help to enhance gas production from fractured hydrocarbon reservoirs in the Rub' Al-Khali Basin.

Geological Model of a Storage Complex for a CO2 Storage Operation in a Naturally-Fractured Carbonate Formation

Investigation into geological storage of CO2 is underway at Hontomín (Spain). The storage reservoir is a deep saline aquifer formed by naturally fractured carbonates with low matrix permeability. Understanding the processes that are involved in CO2 migration within these formations is key to ensure safe operation and reliable plume prediction. A geological model encompassing the whole storage complex was established based upon newly-drilled and legacy wells. The matrix characteristics were mainly obtained from the newly drilled wells with a complete suite of log acquisitions, laboratory works and hydraulic tests. The model major improvement is the integration of the natural fractures. Following a methodology that was developed for naturally fractured hydrocarbon reservoirs, the advanced characterization workflow identified the main sets of fractures and their main characteristics, such as apertures, orientations, and dips. Two main sets of fracture are identified based upon their mean orientation: North-South and East-West with different fracture density for each the facies. The flow capacity of the fracture sets are calibrated on interpreted injection tests by matching their permeability and aperture at the Discrete Fracture Network scale and are subsequently upscaled to the geological model scale. A key new feature of the model is estimated permeability anisotropy induced by the fracture sets.

Finite-difference modelling of anisotropic wave scattering in discrete fracture model

The presence of fractures in reservoir rocks causes scattering of seismic wave energy. In this paper, we utilize the finite-difference modelling technique to study these scattering effects to gain more insights into the effects and assess the validity of using anisotropic wave scattering energy as a diagnostic tool to characterize fractured hydrocarbon reservoirs. We use a simplified fractured reservoir model with four horizontal layers with a fractured-layer as the third layer. The fractures are represented by grid cells containing equivalent anisotropic medium by the use of the linear slip equivalent model. Our results show that the scattered energy, quantified through estimates of the seismic quality factor (Q) is anisotropic, exhibiting a characteristic elliptical (\(\cos 2\theta \)) variations relative to the survey azimuth angle \(\theta \). The fracture normal is inferred from the minor axis of the Q ellipse. This direction correlates with the direction of maximum wave scattering. Minimum wave scattering occurs in the fracture strike direction inferred from the major axis of the Q ellipse. These results provide more complete insights into anisotropic wave scattering characteristics in fractured media and thus, validate the practical utility of using anisotropic attenuation attribute as an additional diagnostic tool for delineation of fracture properties from seismic data.

Modeling of multicomponent diffusions and natural convection in unfractured and fractured media by discontinuous Galerkin and mixed methods

SummaryComputation of the distribution of species in hydrocarbon reservoirs from diffusions (thermal, molecular, and pressure) and natural convection is an important step in reservoir initialization. Current methods, which are mainly based on the conventional finite‐difference approach, may not be numerically efficient in fractured and other media with complex heterogeneities. In this work, the discontinuous Galerkin (DG) method combined with the mixed finite element (MFE) method is used for the calculation of compositional variation in fractured hydrocarbon reservoirs. The use of unstructured gridding allows efficient computations for fractured media when the cross flow equilibrium concept is invoked. The DG method has less numerical dispersion than the upwind finite‐difference methods. The MFE method ensures continuity of fluxes at the interface of the grid elements. We also use the local DG (LDG) method instead of the MFE to calculate the diffusion fluxes. Results from several numerical examples are presented to demonstrate the efficiency, robustness, and accuracy of the model. Various features of convection and diffusion in homogeneous, layered, and fractured media are also discussed.

Complex analytical solutions for flow in hydraulically fractured hydrocarbon reservoirs with and without natural fractures

• Streamlines in naturally fractured reservoir modeled by new analytical formulation. • Natural fractures may affect time-of-flight contours and drainage contours. • Flow is supported in natural fracture direction and limited normal to the fractures. • Prototype slab as natural analog for flow in hydraulically fractured reservoirs. Reservoir drainage towards producer wells in a hydraulically and naturally fractured reservoir is visualized by using an analytical streamline simulator that plots streamlines, time-of-flight contours and drainage contours based on complex potentials. A new analytical expression is derived to model the flow through natural fractures with enhanced hydraulic conductivity. Synthetic examples show that in an otherwise homogeneous reservoir even a small number of natural fractures may severely affect streamline patterns and distort the drainage contours. Multiple parallel natural fractures result in a drainage region that is narrower in the direction normal to the natural fractures while the drainage reach is larger in the natural fracture direction. Reservoirs with numerous natural fractures are shown to be characterized by more tortuous drainage patterns than reservoirs without natural fractures. Finally, the analytical flow model for naturally fractured reservoirs is applied to a natural analog of flow into hydraulic fractures. The tendency of the injected fluid to stay confined to the fracture network as opposed to matrix flow is entirely controlled by the hydraulic conductivity contrast between the fracture network and the matrix.

Naturally fractured hydrocarbon reservoir simulation by elastic fracture modeling

Accurate fluid flow simulation in geologically complex reservoirs is of particular importance in construction of reservoir simulators. General approaches in naturally fractured reservoir simulation involve use of unstructured grids or a structured grid coupled with locally unstructured grids and discrete fracture models. These methods suffer from drawbacks such as lack of flexibility and of ease of updating. In this study, I combined fracture modeling by elastic gridding which improves flexibility, especially in complex reservoirs. The proposed model revises conventional modeling fractures by hard rigid planes that do not change through production. This is a dubious assumption, especially in reservoirs with a high production rate in the beginning. The proposed elastic fracture modeling considers changes in fracture properties, shape and aperture through the simulation. This strategy is only reliable for naturally fractured reservoirs with high fracture permeability and less permeable matrix and parallel fractures with less cross-connections. Comparison of elastic fracture modeling results with conventional modeling showed that these assumptions will cause production pressure to enlarge fracture apertures and change fracture shapes, which consequently results in lower production compared with what was previously assumed. It is concluded that an elastic gridded model could better simulate reservoir performance.

Applicability of the shape-factor concept for naturally fractured reservoirs and an alternative approach

After 60 years of worldwide scientific efforts, the authors do not see a chance of formulating the matrix-fracture mass transfer rate, as it happens in naturally fractured hydrocarbon reservoirs, in one, generally applicable expression. Numerous approaches for it have been presented, but none of them considered all possible conditions and for none of them experimental evidence was presented. Therefore, the only consistent approach is a numerical calculation on a fine scale single matrix block (SMB) model. Heinemann (2004) suggested using the recovery curves resulting from SMB calculation directly in any dual continuum formulation. Mittermeir (2015) did so in material balance calculation. It is proved that this approach has the potential for being generally applicable.

The application study on the multi-scales integrated prediction method to fractured reservoir description

In this paper, we implement three scales of fracture integrated prediction study by classifying it to macro- (> 1/4λ), meso- (> 1/100λ and < 1/4λ) and micro- (< 1/100λ) scales. Based on the multi-scales rock physics modelling technique, the seismic azimuthal anisotropy characteristic is analyzed for distinguishing the fractures of meso-scale. Furthermore, by integrating geological core fracture description, image well-logging fracture interpretation, seismic attributes macro-scale fracture prediction and core slice micro-scale fracture characterization, an comprehensive multi-scale fracture prediction methodology and technique workflow are proposed by using geology, well-logging and seismic multi-attributes. Firstly, utilizing the geology core slice observation (Fractures description) and image well-logging data interpretation results, the main governing factors of fracture development are obtained, and then the control factors of the development of regional macro-scale fractures are carried out via modelling of the tectonic stress field. For the meso-scale fracture description, the poststack geometric attributes are used to describe the macro-scale fracture as well, the prestack attenuation seismic attribute is used to predict the meso-scale fracture. Finally, by combining lithological statistic inversion with superposed results of faults, the relationship of the meso-scale fractures, lithology and faults can be reasonably interpreted and the cause of meso-scale fractures can be verified. The micro-scale fracture description is mainly implemented by using the electron microscope scanning of cores. Therefore, the development of fractures in reservoirs is assessed by valuating three classes of fracture prediction results. An integrated fracture prediction application to a real field in Sichuan basin, where limestone reservoir fractures developed, is implemented. The application results in the study area indicates that the proposed multi-scales integrated fracture prediction method and the technique procedureare able to deal with the strong heterogeneity and multi-scales problems in fracture prediction. Moreover, the multi-scale fracture prediction technique integrated with geology, well-logging and seismic multi-information can help improve the reservoir characterization and sweet-spots prediction for the fractured hydrocarbon reservoirs.

Advances in the study of naturally fractured hydrocarbon reservoirs: a broad integrated interdisciplinary applied topic

Abstract Naturally fractured reservoirs, within which porosity, permeability pathways and/or impermeable barriers formed by the fracture network interact with those of the host rock matrix to influence fluid flow and storage, can occur in sedimentary, igneous and metamorphic rocks. These reservoirs constitute a substantial percentage of remaining hydrocarbon resources; they create exploration targets in otherwise impermeable rocks, including under-explored crystalline basement, and they can be used as geological stores for anthropogenic carbon dioxide. Their complex fluid flow behaviour during production has traditionally proved difficult to predict, causing a large degree of uncertainty in reservoir development. The applied study of naturally fractured reservoirs seeks to constrain this uncertainty and maximize production by developing new understanding, and is necessarily a broad, integrated, interdisciplinary topic. Some of the methods, challenges and advances in characterizing the interplay of rock matrix and fracture networks relevant to fluid flow and hydrocarbon recovery are reviewed and discussed via the contributions in this volume.

Prediction of accumulated outflow from a fractured hydrocarbon reservoir using metamodeling

Three metamodels have been established for predicting accumulated outflow from a fractured hydrocarbon reservoir over a planning horizon of 18 years. The models have been validated and compared based on the amount of accumulated outflow prediction using dynamic reservoir simulation. The reservoir model was set up first and its basic parameters (porosity, permeability and saturation of water) were estimated. The accumulated outflow of a new well has been estimated as a function of the reservoir parameters using a Hydrocarbon in Place (HIP) equation. Low potential points were excluded using HIP equation and 25 high potential points were chosen for calibrating the metamodels. The three metamodels used are a quadratic model, a multiplicative model and a radial basis function model. These metamodels have been tested at 7 new test points and the predictions have been compared with those obtained by dynamic simulation. Prediction results show that all the three models can fairly predict the accumulated outflow of the reservoir studied in this paper while their computation time is much less than that of dynamic simulation. The results also show that in our case study the RBF model outperforms the other two models.

Wavefield propagation characteristics in fracture-induced TTI double-porosity medium

The direction of symmetry axis of parallel fracture set in fractured hydrocarbon reservoir affects the transmission of seismic waves markedly, so a medium named fracture-induced TTI (tilted transverse isotropy) double-porosity medium is studied here to discuss the effect of different dip and azimuth angles of a fracture system. Based on the theories of fracture-induced HTI (horizental transverse isotropy) double-porosity medium, the softness and dispersion matrixes of fracture-induced TTI double-porosity medium are derived with the application of Bond transform, and finally, single-order velocity-stress equations are obtained. Furthermore, numerical simulations in xoz plane of 2.5 dimensional vector wavefield are carried out by the method of high-order staggered-grid finite-difference under perfect matched layer (PML) boundary conditions. The results show that the dipand azimuth angles of fractures have great impacts on seismic wave propagation, since the angles can cause the phenomena of shear wave splitting and, in the two-layer model of fracture-induced TTI double-porosity, converted shear wave splitting and shear wave sub-splitting. All of these increase the complexity of seismic wavefield and will lay a foundation of further studies on seismic wave propagation in actual earth layers.