Characterizing the intrinsic complexity of natural fracture networks: A novel fractal-based approach

Natural fractures control primary fluid flow in low-matrix-permeability carbonate hydrocarbon reservoirs, making it important to understand the factors that affect natural fracture distributions and networks. Away from the influence of folds and faults, stratigraphic controls are accepted to be the major control on fracture networks. The influence of carbonate nodular chert rhythmite successions on natural fracture networks is investigated here using a Discrete Element Modelling (DEM) technique that draws on outcrop observations of naturally fractured carbonates in the Eocene Thebes Formation, exposed in the west central Sinai of Egypt, that also form reservoir rocks in the subsurface. Stratally-bound chert nodules below bedding surfaces create lateral heterogeneities that vary over short distances. The resulting distribution of physical properties (differing stiffnesses) caused by chert rhythmites is shown to generate extra complexity in natural fracture networks in addition to that caused by bed thickness and lithological physical properties. Chert rhythmite successions need to be considered as a distinct type of carbonate fractured reservoir. Stratigraphic rules for predicting the distribution, lengths and spacing of natural fractures, and quantitative fracture indices ( P 11 , P 21 , P 22 and fractal dimension) are generated from the DEM outcomes. In a less-stiff carbonate medium, the presence of chert nodules reduces fracture intensity at chert horizons, and fractures per unit area are higher in chert-free vertical corridors. In a stiff carbonate medium, chert has little influence on fracture development. In a peritidal cyclic succession with constant layer thicknesses, the presence of chert in less-stiff carbonate horizons results in a reduction in fracture intensity. When chert is introduced in a subtidal cyclic sequence with constant layer thicknesses, it has little effect on fracture distribution. The study has widespread significance for characterizing naturally fractured reservoirs containing carbonate nodular chert rhythmites.

Fractures and fracture networks play an important role in fluid flow and transport properties of oil and gas reservoirs. Accurate estimation of geometrical characteristics of fracture networks and their hydraulic properties are two key research directions in the fields of fluids flow in fractured porous media. Recent works focusing on the geometrical, fractal and hydraulic properties of fractured reservoirs are reviewed and summarized in this mini-review. The effects of several important parameters that significantly influences hydraulic properties are specifically discussed and analyzed, including fracture length distribution, aperture distribution, boundary stress and anisotropy. The methods for predicting fractal dimension of fractures and models for fracture networks and fractured porous media based on fractal-based approaches are addressed. Some comments and suggestions are also given on the future research directions and fractal fracture networks as well as fractured porous media. Cited as : Wei, W., Xia, Y. Geometrical, fractal and hydraulic properties of fractured reservoirs: A mini-review. Advances in Geo-Energy Research, 2017, 1(1): 31-38, doi: 10.26804/ager.2017.01.03

A numerical modeling study was performed to investigate fluid recovery following hydraulic stimulation in low matrix permeability formations. A simulator was used, CFRAC, that implicitly couples fluid flow with the stresses induced by fracture deformation in two-dimensional discrete fracture networks. An unstructured mesh was created around the fractures to simulate leakoff and flow in the matrix. Four simulations were performed in which fluid was injected, the wells were shut in, and then fluid was produced back to the surface. The baseline simulation contained a single, linear fracture propagating away from the wellbore. The other three simulations used a stochastically generated network of natural fractures and assumed that as hydraulic fractures propagated through the formation, they terminated when they intersected natural fractures. The termination process created complex, branching fracture networks. The simulations showed that fracture network complexity reduced fluid recovery because the natural fractures, which were not perpendicular to the minimum principal stress, closed at an elevated fluid pressure and created barriers for flow between the wellbore and the open, fluid-filled fractures away from the well. However, if the transmissivity of closed fractures was too low, the fracture network was inhibited from becoming complex, and fluid trapping was not as severe. In the two complex fracture network simulations with lower closed fracture transmissivity, the shut-in pressure transient showed abrupt changes in slope, which were caused by episodic growth of the fracture network due to leakoff of fluid into natural fractures, rapid propagation of opening along the natural fractures, and subsequent initiation of new hydrualic fractures. In practical applications, the observation of abrupt changes in slope during shut-in could be taken as evidence that episodic fracture propagation is occurring, which would imply a complex and branching fracture network. In one of the three complex fracture network simulations, it was assumed that closed fractures had relatively high transmissivity, and abrupt changes in the slope of the shut-in transient were not present, even though a complex fracture network developed during stimulation.

This paper presents a robust semi-analytical strategy to simulate natural fracture network system in heterogeneous tight formations. The natural fracture networking is modeled in a more realistically and physically sound manner that enables the capacity to treat actual fracture network data set likely to be acquired from field seismic survey and well logging/core interpretation. The source and sink function method was implemented extensively to study the natural setting of fracture systems. A pseudo- fracture body concept, which can be uniquely named as ghost fracture, has been proposed and implemented in the modeling strategy to achieve an effective handling and computing of random natural fracture and fracture network. This strategy greatly overcomes the modeling challenge in this technical domain and is very useful for future application. The details of fluid entering and leaving the fracture body are scrutinized to help build physically meaningful treatment of fluid flow process and ensure a reliable workflow in computing. This new modeling strategy is applied to simulate natural fracture networking systems with various complexities. Representation of the physics around fracture body with high accuracy greatly enhances our technical confidence to deal with more complex natural fracture system in field, where the involvement of complex fracture physics directly influences the flow regime around a well and its performance. Comparison study using other simulator had been performed to help verify the correctness of the proposed simulation scheme. The results from this new semi-analytical model are consistent with those computed from other commercial simulators under the condition of comparable and simplified fracture network, such as the orthogonal fracture system, which is the normal manner a fracture system constructed in commercial software. However, this new semi-analytical methodology creates results with accuracy near analytical solution and successfully consolidates the ability of rendering more complex and irregular fracture settings to satisfy the real physics in a highly effective computational fashion; thus, helps fulfill the objective of modeling natural fractures in actual reservoir comprehensively. Results for various synthetic cases under different conductivity conditions have been analyzed systematically. The effects of the fracture network pattern and orientation have also been studied. Under the current industry scenario of implementing massive multistage fracturing in horizontal wellbore for tight oil/gas reserve development, there exists a great need in understanding and analyzing the complex interference/communication among artificial and natural fracture systems. The modeling methodology presented here has built a powerful tool to help characterize and diagnose the fracture system and potentially assist in identifying the sweet fractured formation ranges, thus offer a more reliable way to map fracture network and optimize tight formation drilling and fracturing practice.

The formation of complex fracture networks through the fracturing technology is a crucial operation used to improve the production capacity of tight gas/oil. In this study, physical simulation experiments of hydraulic fracturing were conducted with a true triaxial test system on cubic shale oil samples from the Yanchang Formation, China. The fractures were scanned by CT both before and after the experiments and then reconstructed in 3D. The complexity of fracture networks was investigated quantitatively by the fractal theory with topology. Finally, the effect of the horizontal stress ratio, fluid viscosity, and natural fractures on the complexity of the fracture networks was discussed. The results indicate that the method based on fractal theory and topology can effectively characterize the complexity of the fracture network. The change rates of the fractal dimension (K) are 0.45–3.64%, and the fractal dimensions (DNH) of the 3D fracture network after fracturing are 1.9522–2.1837, the number of connections per branch after fracturing (CB) are 1.57–2.0. The change rate of the fractal dimension and the horizontal stress ratio are negatively correlated. However, the change rate of the fractal dimension first increases and then decreases under increasing fluid viscosities, and a transition occurs at a fluid viscosity of 5.0 mPa·s. Whether under different horizontal stress ratios or fluid viscosities, the complexity of the fracture networks after fracturing can be divided into four levels according to DNH and CB. Complex fracture networks are more easily formed under a lower horizontal stress ratio and a relatively low fluid viscosity. A fracturing fluid viscosity that is too low or too high limits the formation of a fracture network.

The interaction between natural and hydraulic fractures (HFs) results in the formation of complex fracture networks. A great deal of uncertainty exists around the geometry and connectivity of these fracture networks. The two primary objectives of this study are: (1) to show how the properties of the natural fracture network (orientation, density, length) control the created hydraulic fracture network, and (2) how microseismic (MS) and fiber optic data obtained during fracturing can be used to obtain better estimates of the fracture geometry in such complex systems. These effects are illustrated by using a new fracture propagation model that accounts for the interaction of the propagating hydraulic fracture with the natural fracture network and also allows us to compute and compare the fiber optic and microseismic data from a field site. A stochastic discrete fracture network (DFN) was constructed, incorporating the density, length, and orientation distribution of natural fractures at the FORGE site in Utah. Hydraulic fracture treatments within the DFN were modeled using the displacement discontinuity method (DDM) for stress. The coupling of strain with fluid flow in the created fracture network was achieved via the finite volume method. Fiber was installed in an observation well and Distributed Acoustic Sensing (DAS) measurements were obtained and analyzed. The influence of natural fractures on the DAS data is demonstrated by systematically varying the following: (1) fracture orientation angles ranging from 0° to 90° from the maximum stress direction, (2) fracture density ranging from 0.0002 to 0.005/m3, (3) lengths varying from 10 meters to 120 meters. The magnitude and moment of the microseismic events were computed to show the expected seismic clouds that would be generated. Fiber optic responses were also computed to show the expected results under different conditions. Finally, the geometry of the created fracture network was diagnosed and related to the microseismic and fiber responses. The intrinsic characteristics of the created fracture network can be identified in DAS waterfall plots. These fracture network characteristics change systematically based on the natural fracture orientation, density and length distribution. Most importantly, variations in these factors affect the number of isolated and branched fractures created in the fracture network. The effect of stress shadowing on the development of continuous fracture systems originating from different perforation clusters is clearly observed. Results are presented for the different sensitivity cases to illustrate the importance of the different properties of the natural fracture system on the final fracture network. This study, for the first time, incorporates and quantifies the impact of natural fractures on DAS and MS monitoring data. The findings of this study allow us to demonstrate how such data, together with geomechanical models, can be used to better characterize hydraulic fracturing networks in naturally fractured reservoirs, thereby improving hydraulic fracturing designs in such complex systems.

Weathered and fractured crystalline Basement emerged as the important unconventional play in the Barmer Basin. Natural fractures play a very significant role in the migration and hydrocarbon storage in crystalline fractured and weathered crystalline Basement reservoirs. Complexity and heterogeneity of the fracture network in the basement is a challenge to the geoscientist. This requires precise fracture characterization which is very significant for estimating the hydrocarbon potential as well as development of these reservoirs. A novel approach of integrating the seismic geometrical and stratigraphic attributes, with the borehole image logs and core data were found to be useful to characterize fractured and weathered crystalline basement reservoir in the Saraswati Field located in the eastern margin of Barmer basin. Seismic data derived Ant track volume calibrated with the core and bore hole image data has predicted NNW-SSE and NE-SW trending natural fractures information. Acoustic impedance and RMS seismic amplitude attributes identified the zones of intense fractured and weathered Basement. Assessment of the natural fracture network helped for appraising the Basement discovery as well as for designing the optimal well path for intersecting the maximum number of fractures for better reservoir performance.

Background: In recent years, CO2 composite fracturing technology has been widely used in unconventional reservoirs. Compared to conventional hydraulic fracturing, CO2 fracturing can create complex fractures, replenish formation energy and reduce oil flow resistance. For shale oil reservoirs with natural fractures, CO2 composite fracturing can not only give full play to the advantages of complex fracture networks created by CO2 but also make use of water-based fracturing fluid to create long fractures with high conductivity. Methods: Based on fracture fluid flow, stress interference, natural fracture description, and CO2 phase change equation, a CO2 composite fracture propagation model was established in this paper to simulate the effects of fracturing fluid type, CO2 proportion, construction scale, natural fracture development, fracturing fluid injection rate and other factors on the propagation morphology of CO2 injection fracture network in shale oil reservoirs. Results: The results show that the water-based fracturing fluid is beneficial to the formation of long main fractures, but the overall complexity of the fracture network and the effective stimulated volume of the fracture network are significantly lower than that of CO2 fracturing. The application of the appropriate proportion of CO2 composite fracturing fluid can give full play to the comprehensive advantages of CO2 and water-based fracturing fluid and realize the full stimulation of the reservoir. CO2 fracturing in shale oil reservoirs with low principal stress difference and high natural fracture development extent can communicate natural fractures in a large range and form a complex fracture network. For shale oil reservoirs with natural fractures, a high fracturing fluid injection rate can significantly improve the complexity of the fracture network. Conclusion: The CO2 composite fracturing technology is applied to horizontal wells in X shale reservoir, and the production after fracturing is significantly higher than that of offset wells, which can be applied in the same type of reservoir and has broad application prospects.

Thermally-induced cracking behaviors of coal reservoirs subjected to cryogenic liquid nitrogen shock

There are still some problems in the study of hydraulic fracture (HF) network evolution in cemented naturally fractured reservoirs, such as microseismic mapping showing exaggerated stimulated reservoir volume in some cases. In addition, the dominant role of natural fracture (NF) cementation strength, injection rate, in situ stress difference, NF distribution, and fracture initiation sequence of perforations in synthetically influencing fracture network formation needs to be further studied. For this purpose, a three‐dimensional matrix hexahedral element global coupled 0‐thickness cohesive element hydraulic fracturing model was developed. Results show that each interaction between HF and NF causes HF diameter shrinkage, which increases the propagation pressure of HF. When the cementation strength of the NF is low, the HF tends to deviate toward the tip of the NF to form a complex fracture network. Increasing the injection rate and the number of NFs can significantly enhance the complexity of the HF network, but does not change the HF and NF interaction pattern. The in situ stress differences dominate the morphology of the HF network when the cementation strength of NFs is constant. The stress interference of multiple fractures under segmented fracturing may form “S”‐shaped HFs, and the HFs are difficult to maintain a symmetrical morphology in the direction of the well axis. In addition, some NFs in inactivated damaged zones have developed a certain width geometrically due to the induced effect of HF, but they are still isolated by the low permeability matrix and might only generate some microseismic events.

Numerical simulation of temporarily plugging staged fracturing (TPSF) based on cohesive zone method

Two-phase flow has generally been of more concern in the hydraulic treatment design of shale gas reservoir, especially, during the flowback period. Investigating the gas and water production data is important to evaluate the stimulation effectiveness. We develop a semianalytical model for multi-fractured horizontal wells by incorporating the two-phase flow in both matrix and fracture of the shale-gas wells. We employ the node-analysis approach to discretize the complex fracture networks into a given number of fracture segments, depending on the complexity of fracture system. The two-phase flow is incorporated by iteratively correcting the relative permeability to gas and water phase and capillary pressure for each fracture segment with the fracture depletion. The model is validated by numerical model and field observation. A good match between them was obtained. Then, the early-time gas and water production performance is analyzed using various fracture properties and geometries. A systematic type curves are obtained with the fracture system from simple to complex geometries. The flow regimes that were identified could assist in constraining the fracture geometry and complexity. Additionally, the gas and water decline rates highly depend on the fracture properties such as initial gas saturation in fractures, fracture conductivity, fracture spacing, fracture geometry and connections with natural fracture networks. The improved network fracture conductivity and complexity especially the connections between hydraulic fracture and natural fractures can enhance the gas production and shorten the dewatering time, illustrating that the effective stimulation could facilitate the fractures to clean up more quickly. The gas/water supply from natural fractures and their flow dynamics controlled by two-phase relative permeability effects could be the major reasons for the formation of "V-shape" behavior on the plot of gas/ water ratio vs. cumulative gas production. This work, for the first time, extends the semianalytical model from single-phase flow to two-phase flow in shale gas reservoir with complex fracture networks. The method is simple and gridless, but is capable of capturing the complex fracture system and gas/water transport mechanisms. Also, it provides an efficient technique to evaluate the hydraulic fracture treatment design in multi-fractured horizontal wells for shale gas reservoirs at early production times.

Numerical investigation of the fracture network morphology in multi-cluster hydraulic fracturing of horizontal wells: A DDM-FVM study

Hydraulic fracture network propagation in a naturally fractured shale reservoir based on the “well factory” model

Factors controlling the formation of complex fracture networks in naturally fractured geothermal reservoirs