Natural Fracture Spacing Research Articles

Effect of compaction and imbibition on benefits of drawdown management in shale oil production: Uncertainty in recovery driving mechanisms

Economic production from shale oil reservoirs relies on the longevity of conductive fractures. Choke or drawdown management is believed to better preserve the fracture conductivity during the early life of the wells, which thus potentially leads to higher ultimate oil recovery. However, there is no strong consensus among the previous literature as to whether choke management can offer incremental oil recovery in the long term. Even if it can, the mechanism is not well understood, and the economic benefit can be challenged, because the choke management slows down the early oil production, which is worth the most in terms of Net Present Value (NPV). In this study, a series of coupled flow-geomechanical numerical simulations is performed to examine the effect of choke management on the ultimate oil recovery and NPV. We built multiple reservoir realization models, each of which is validated based on the same field production data from Middle Bakken shale-oil reservoirs to perform probabilistic production forecasts. The different reservoir realization models are built to assess the uncertainty in the Stimulated Reservoir Volume parameters, including natural fracture spacing, water saturation in the matrix and fracture, and formation compressibility. The different reservoir parameters lead to each model having different primary recovery driving mechanisms of oil recovery, including imbibition and compaction drive. This study quantitatively demonstrates that the choke management seems to increase both the ultimate oil recovery and NPV if the oil recovery is strongly driven by imbibition. A mechanistic discussion for this claim is presented.

Optimising well orientation in hydraulic fracturing of naturally fractured shale gas formations

Complex interactions between hydraulic fractures and natural fractures often result in highly complex fracture networks that might lead to bypassed resources damaging the economic viability of developments. In this study the impact of natural fractures of the formation on production from hydraulically fractured wells is studied using a recently developed fracture upscaling method (FUM). By capturing the distribution of complex fracture networks using FUM, a novel idea of changing the well orientation to optimise recovery is proposed. It is shown that with a natural fracture spacing of 15 m a small change in well orientation up to 30° from the standard orientation can increase the recovery by up to 15% for natural fractures at an angle of at least 60° with σhmax. The increased recovery is a result of the natural fractures and stress orientation complementing each other to assist the propagation of hydraulic fractures deeper into the formation. It is also shown that as natural fracture density increases (fracture spacing decreases) the effect of changing the well orientation becomes more significant. Changing the well orientation when there are two perpendicular planes of natural fractures is also investigated. However, no optimal orientation can be found in these cases, suggesting there needs to be a strong average directionality of the natural fractures in the reservoir to support a beneficial well orientation change. A simple economic analysis shows a small well orientation change can allow a larger well spacing which could lead to a direct reduction in the cost of developing a shale reservoir. The results also show the positive effect this has on the NPV of the project with different gas prices, and a rapid positive NPV status reducing the risk of investment.

Numerical model of CO2 fracturing in naturally fractured reservoirs

Hydraulic fracturing becomes a key technology for unconventional oil and gas development. As a fracturing fluid, CO2 displays considerable advantages, particularly in shale gas exploitation. However, little research has quantitatively analyzed the effectiveness and efficiency of CO2 fracturing in naturally fractured reservoirs. In this study, a CO2 fracturing model is established in naturally fractured reservoirs. A series of fracturing cases in single- and multiple- fracture(s) are conducted based on the simplified three-dimensional displacement-discontinuity-method. Compared to induced fractures by slickwater and gel, the results show that CO2 fracturing can generate relatively longer but narrower fractures due to the low breakdown pressure and pressure drop in fractures. The pressure drop in the single fracture by CO2 fracturing is respectively 60.48% and 78.88% lower than that by slickwater and gel fracturing at the same injection time. Simultaneously, in naturally fractured reservoirs, CO2 fracturing can activate more natural fractures to connect with each other and create a larger stimulated reservoir volume. For a single fracturing, the active natural fractures volume of CO2 fracturing is 3.7 and 9.2 times that of slickwater and gel fracturing, respectively. For multiple fracturing, the active natural fractures volume of CO2 fracturing is 2.5 and 4.4 times that of slickwater and gel fracturing, respectively. Additionally, the sensitivity analyses in natural fracture spacing and length show that both natural fracture spacing and length can significantly determine natural fractures' distribution and connectivity. By CO2 fracturing, a reservoir with relatively smaller natural fracture spacing and longer natural fracture length can be activated more natural fractures. The present work can help the scholars and the readers better understand the effectiveness and efficiency of CO2 fracturing, especially in naturally fractured reservoirs.

An equivalent mathematical model for 2D stimulated reservoir volume simulation of hydraulic fracturing in unconventional reservoirs

ABSTRACT Stimulated reservoir volume (SRV) is a key parameter affecting the post-fracturing production of ultra-low permeability reservoirs. Accurate prediction of the SRV shape and size is of vital significance for pre-fracturing stimulation design and post-fracturing effect evaluation. In this paper, an equivalent mathematical model for simulating two-dimensional SRV growth is proposed by integrating the fracture width equation, tensor permeability conversion, cubic law and calculation method of fracture porosity with mass conservation equation of injected fluid in natural fracture system. The finite difference method is used to derive the numerical discrete equation, and the fluid pressure and average fracture width in each grid block are obtained by solving the coupled fluid conservation equation and fracture width equation. The model is validated by comparing the results obtained from this work with others from literature. A parametric sensitivity study was performed to analyze the effects of some factors incorporating approaching angle, natural fracture spacing, horizontal principal stress difference, pumping rate and fracturing fluid viscosity on the SRV (including size, aspect ratio, and arithmetic mean fracture width in SRV region). The results show that SRV increases with the decrease of approaching angle, principal stress difference, injection rate, viscosity of fracturing fluid and fracture density. The width of branch fracture decreases with the increasing approaching angle and principal stress difference but increases with the increasing pumping rate and fluid viscosity.

Investigation of Shale-Gas-Production Behavior: Evaluation of the Effects of Multiple Physics on the Matrix

Summary Shale gas is a major component of natural-gas supply in the United States. Multistage-fractured horizontal wells significantly improve the production performance of ultralow-permeability shale-gas reservoirs. Researchers have believed that shale-gas-production simulations should take into account the complex-flow behaviors in both fractures and the matrix. However, multiple physics applied on the matrix are generally incomplete in previous studies. In this study, we considered the comprehensive physics that occurred in the matrix including the effective stress, slip flow/pore diffusion, adsorption/desorption, and surface diffusion, as well as the dynamic properties of fractures. We investigated the importance of these features of the physics separately and in an integrated fashion by step-by-step production simulations. Afterward, comprehensive sensitivity analysis was performed with regard to stress dependency of the matrix and fractures. This work shows that natural-fracture spacing is the most prominent factor affecting shale-gas-reservoir performance. The work highlights the importance to gas recovery of mechanical squeezing of the pore volume by the effective stress. Surface diffusion might be essential for gas recovery that depends on surface-diffusivity values. Slip flow and pore diffusion do not significantly contribute to gas recovery even though they increase gas apparent permeability under low pressures.

Development of Acid Fracturing Model for Naturally Fractured Reservoirs

Summary During an acid fracturing treatment in a carbonate reservoir, acid is injected into the formation, thus creating hydraulic fractures and opening existing natural fractures. As the acid flows into natural fractures that intersect hydraulic fractures (main fractures), it etches the walls of the natural fractures, which then increases the natural fractures’ width and generates conductivity. On the other hand, because of the increased acid leakoff into natural fractures, the acid volume in the main fracture decreases, resulting in less conductivity for the main fracture. Existing acid fracturing models estimate the fracture conductivity by assuming that the acid flows and reacts in the hydraulic fractures only. To accurately predict the performance of acid fracturing in naturally fractured carbonate reservoirs, the acid etching of natural fractures should be taken into account when calculating the overall fracture conductivity. A model was developed to predict the acid fracturing performance in naturally fractured reservoirs. The model assumed that the main fracture was intersected by transverse symmetric natural fractures. The model simulated the acid transport, acid/rock reaction, fracture width increase resulting from etching of the fracture walls, and acid leakoff through natural fractures. The model also assumed that the flow (into natural fractures) and the leakoff were pressure–dependent and were changing with time. The conductivity calculation was based on the previously developed correlation that accounts for the heterogeneous nature of carbonate rock. The effect of the natural fractures’ geometry on leakoff and created fracture conductivity was investigated. The results showed that length and dynamic width, as well as the natural–fracture spacing, played a significant role in defining the leakoff rate and the conductivity of the hydraulic fracture and the natural fractures. It was also found that the position of the natural fractures along the hydraulic–fracture length affected the etching of the natural fractures and the resultant conductivity. The aim of the model is to enable better prediction of the acid fracture conductivity for naturally fractured carbonate reservoirs and improve the feasibility of acid fracturing applications for this type of formation.

Gas transport behaviors in shale nanopores based on multiple mechanisms and macroscale modeling

The combined action of multiple transport mechanisms and reservoir characteristics makes gas transport behaviors in nanoporous shale complicated. Accurate apparent gas permeability (AGP) characterization for gas transport in nanopores is crucially essential for macroscale modeling in shale gas reservoirs development. In this study, a new unified AGP model for gas transport in the organic and inorganic nanoporous shale (OM and IM) is presented, incorporating multiple mechanisms, such as real gas effect, viscous-slip flow, Knudsen diffusion, surface diffusion, stress dependence and especially the organic nanopores content. Besides, the effect of multilayer adsorption on gas transport is included. The model is validated by experimental and linearized Boltzmann results and compared with the published AGP models. After that, sensitivity analysis and the contribution of each mechanism to the total AGP are conducted. Moreover, a numerical model for the fractured well in shale based on the presented AGP model and discrete fracture model (DFM) is derived. The finite element method (FEM) is applied to solve the model and then influence factors of gas transport behaviors are discussed. The results show that different transport mechanisms exist in organic and inorganic nanopores respectively. The larger pore radius or pressure causes a smaller ratio of the AGP over the intrinsic permeability. Moreover, the contribution of surface diffusion to the total AGP is significantly influenced by the OM nanopores radius and surface diffusion coefficient. In addition, gas transport is governed by Knudsen diffusion in nanopores with a small radius and low pressure and is controlled by viscous flow under the large pore radius and high-pressure conditions. Then, the presented AGP model is introduced into the macroscale numerical model for a fractured well in shale. Larger hydraulic fracture half-length, OM nanopores content and matrix pore radius as well as smaller natural fracture spacing cause higher gas production. The study provides a new unified AGP model considering gas transport behaviors in nanopores and applies the AGP model to macroscale modeling.

Pressure transient behaviors of hydraulically fractured horizontal shale-gas wells by using dual-porosity and dual-permeability model

A dual-porosity and dual-permeability (DPDP) model was developed to describe the fluids flow and transient pressure behaviors of multistage hydraulically fractured horizontal wells in shale-gas reservoirs by incorporating gas adsorption and gas permeability corrections. This 3-dimensional, 1-phase numerical model was developed using finite volume method and solved implicitly with unstructured PEBI (Perpendicular Bisection) gridding. Parametric studies were conducted to understand the pressure transient behaviors with effects of gas adsorption, permeability correction, transmissibility between fracture and matrix system (called inter-porosity flow ability, IPF), and natural fracture spacing. The results showed that pressure transient behaviors were not only controlled by the individual ultimate adsorption capacity (UAC) and IPF but rather the combination of IPF ability and UAC derived herein. The physics was that for a block by omitting the flow in matrix systems and accumulation term, the flow rate of free gas between the matrix cell and the fracture cell was equal to the flow rate caused by adsorbed or desorbed due to a pressure change in the matrix cell. This was the reason that if the IPF ability was relatively small, large amount of free gas would flow into the wellbore, which affected the pressure transient behaviors. This finding was quantified with a new correlation that was a function of IPF ability, UAC and pressure difference between fracture and matrix.

Fluid flow from matrix to fractures in Early Jurassic shales

The potential of shale reservoirs for gas extraction is largely determined by the permeability of the rock. Typical pore diameters in shales range from the μm down to the nm scale. The permeability of shale reservoirs is a function of the interconnectivity between the pore space and the natural fracture network present. We have measured the permeability of the Whitby Mudstone, the exposed counterpart of the Posidonia Shales buried in the Dutch subsurface and a possible target for unconventional gas, using different methods and established a correlation with the microstructures and pore networks present down to the nanometer scale.Whitby Mudstone is a clay rich rock with a low porosity. The permeability of the Whitby Mudstone is in the range of 10−18m2–10−21m2. 2D microstructures of the Whitby Mudstone show no connected pore networks, but isolated pore bodies mainly situated in the clay matrix, whereas 3D data shows that connected pore networks are present in less compacted parts of the rock. A closely spaced interconnected fracture network is often required to speed up transport of fluids from the matrix into a producing well. For fluids within the matrix the nearest natural fracture is on average at a distance of approximately 10cm in the Whitby Mudstone. The combination of the permeability data and the porosity data with natural fracture spacing of the fractures present in outcrops along the Yorkshire coast (UK) resulted in new insights into possible fluid pathways from reservoir to well.

Mechanical stratigraphic controls on natural fracture spacing and penetration

Fine-grained low permeability sedimentary rocks, such as shale and mudrock, have drawn attention as unconventional hydrocarbon reservoirs. Fracturing – both natural and induced – is extremely important for increasing permeability in otherwise low-permeability rock. We analyze natural extension fracture networks within a complete measured outcrop section of the Ernst Member of the Boquillas Formation in Big Bend National Park, west Texas. Results of bed-center, dip-parallel scanline surveys demonstrate nearly identical fracture strikes and slight variation in dip between mudrock, chalk, and limestone beds. Fracture spacing tends to increase proportional to bed thickness in limestone and chalk beds; however, dramatic differences in fracture spacing are observed in mudrock. A direct relationship is observed between fracture spacing/thickness ratio and rock competence. Vertical fracture penetrations measured from the middle of chalk and limestone beds generally extend to and often beyond bed boundaries into the vertically adjacent mudrock beds. In contrast, fractures in the mudrock beds rarely penetrate beyond the bed boundaries into the adjacent carbonate beds. Consequently, natural bed-perpendicular fracture connectivity through the mechanically layered sequence generally is poor. Fracture connectivity strongly influences permeability architecture, and fracture prediction should consider thin bed-scale control on fracture heights and the strong lithologic control on fracture spacing.

Optimization-Based Unstructured Meshing Algorithms for Simulation of Hydraulically and Naturally Fractured Reservoirs With Variable Distribution of Fracture Aperture, Spacing, Length, and Strike

Summary Multistage hydraulically fractured wells are applied widely to produce unconventional resource plays. In naturally fractured reservoirs, hydraulic-fracture treatments may induce complex-fracture geometries that one cannot model accurately and efficiently with Cartesian and corner-point grid systems or standard dual-porosity approaches. The interaction of hydraulic and naturally occurring fractures almost certainly plays a role in ultimate well and reservoir performance. Current simulation models are unable to capture the complexity of this interaction. Generally speaking, our ability to detect and characterize fracture systems is far beyond our capability of modeling complex natural-fracture systems. To evaluate production performance in these complex settings with numerical simulation, fracture networks require advanced meshing and domain-discretization techniques. This paper investigates these issues by developing natural-fracture networks with fractal-based techniques. After a fracture network is developed, we demonstrate the feasibility of gridding complex natural-fracture behavior with optimization-based unstructured meshing algorithms. Then we can demonstrate that one can simulate natural-fracture complexities such as variable aperture, spacing, length, and strike. This new approach is a significant step beyond the current method of dual-porosity simulation that essentially negates the sophisticated level of fracture characterization pursued by many operators. We use currently established code for fractal discrete-fracture-network (FDFN) models to build realizations of naturally fractured reservoirs in terms of stochastic fracture networks. From outcrop, image-log, and core analysis, it is possible to extract fracture fractal parameters pertaining to aperture, spacing, and length distribution, including center distribution as well as a fracture strike. Then these parameters are used as input variables for the FDFN code to generate multiple realizations of fracture networks mimicking fracture clustering and randomly distributed natural fractures. After incorporating hydraulic fractures, complex-fracture networks are obtained for further reservoir-domain discretization. To discretize the complex-fracture networks, a new mesh-generation approach is developed to conform to nonorthogonal and low-angle intersections of extensively clustered discrete-fracture networks with nonuniform aperture distribution. Optimization algorithms are adopted to reduce highly skewed cells, and to ensure good mesh quality around fracture tips, intersections, and regions of extensive fracture clustering. Moreover, local grid refinement is implemented with a predefined distance function to control cell sizes and shapes around and far away from fractures. Natural-fracture spacing, length, strike, and aperture distribution are explicitly gridded, thus introducing a new simulation approach that is far superior to dual-porosity simulation. Finally, initial sensitivity studies are performed to demonstrate both the capability of the optimization-based unstructured meshing algorithms, and the effect of aforementioned natural-fracture parameters on well performance. This study demonstrates how to incorporate a fractal-based characterization approach into the current work flow for simulating unconventional reservoirs, and most importantly solves several issues such as nonorthogonal intersections, extensive clustering, and nonuniform aperture distribution associated with domain discretization with unstructured grids for complex-fracture networks. The proposed meshing techniques for complex fracture networks can be easily implemented in existing preprocessing, unstructured mesh generators. The sensitivity study and the simulation runs demonstrate the importance of fracture characterization as well as uncertainties associated with naturally fractured reservoirs on well-production performance.

Flowback patterns of fractured shale gas wells

Shale gas reservoirs generally need to be fractured massively to reach the industrial production, however, the flowback ratio of fractured shale gas wells is low. In view of this issue, the effects of natural fracture spacing, fracture conductivity, fracturing scale, pressure coefficient and shut-in time on the flowback ratio were examined by means of numerical simulation and experiments jointly, and the causes of flowback difficulty of shale gas wells were analyzed. The results show that the flowback ratio increases with the increase of natural fracture spacing, fracture conductivity and pressure coefficient and decreases with the increase of fracturing scale and shut-in time. From the perspective of microscopic mechanism, when water enters micro-cracks of the matrix through the capillary self-absorbing effect, the original hydrogen bonds between the particles are replaced by the hydroxyl group, namely, hydration effect, giving rise to the growth of new micro-cracks and propagation of main fractures, and complex fracture networks, so a large proportion of water cannot flow back, resulting in a low flowback ratio. For shale gas well fracturing generally has small fracture space, low fracture conductivity and big fracturing volume, a large proportion of the injected water will be held in the very complex fracture network with a big specific area, and unable to flow back. It is concluded that the flowback ratio of fractured shale gas wells is affected by several factors, so it is not necessary to seek high flowback ratio deliberately, and shale gas wells with low flowback ratio, instead, usually have high production.

Development of innovative and efficient hydraulic fracturing numerical simulation model and parametric studies in unconventional naturally fractured reservoirs

The most effective method for stimulating unconventional reservoirs is using properly designed and successfully implemented hydraulic fracture treatments. The interaction between pre-existing natural fractures and the engineered propagating hydraulic fracture is a critical factor affecting the complex fracture network. However, many existing numerical simulators use simplified model to either ignore or not fully consider the significant impact of pre-existing fractures on hydraulic fracture propagation. Pursuing development of numerical models that can accurately characterize propagation of hydraulic fractures in naturally fractured formations is important to better understand their behavior and optimize their performance.In this paper, an innovative and efficient modeling approach was developed and implemented which enabled integrated simulation of hydraulic fracture network propagation, interactions between hydraulic fractures and pre-existing natural fractures, fracture fluid leakoff and fluid flow in reservoir. This improves stability and convergence, and increases accuracy, and computational speed. Computing time of one stage treatment with a personal computer is now reduced to 2.2min from 12.5min than using single porosity model.Parametric studies were then conducted to quantify the effect of horizontal differential stress, natural fracture spacing (the density of pre-existing fractures), matrix permeability and fracture fluid viscosity on the geometry of the hydraulic fracture network. Using the knowledge learned from the parametric studies, the fracture–reservoir contact area is investigated and the method to increase this factor is suggested. This new knowledge helps us understand and improve the stimulation of naturally fractured unconventional reservoirs.

Porosity and Permeability of Eastern Devonian Gas Shale

Summary High-precision core analysis has been performed on eight Devonian gas shale samples from the Appalachian basin. Seven of the core samples consist of the Upper Devonian Age Huron member of the Ohio shale, six of which came from wells in the Ohio River valley, and the seventh from a well in east-central Kentucky. The eighth core sample consists of Middle Devonian Age Marcellus shale obtained from a well in Morgantown, WV. The core analysis was originally intended to supply accurate input data for Devonian shale numerical reservoir simulation. Unexpectedly, the work has identified a number of geological factors that influence gas production from organic-rich shales. The presence of petroleum as a mobile liquid phase in the pores of all seven Huron shale samples effectively limits the gas porosity of this formation to less than 0.2%, and gas permeability of the rock matrix is commonly less than 0.1 μd at reservoir stress. The Marcellus shale core, on the other hand, was free of a mobile liquid phase and had a measured gas porosity of approximately 10%, and a surprisingly high permeability of 20 μd. Gas permeability of the Marcellus was highly stress-dependent, however; doubling the net confining stress reduced the permeability by nearly 70%. The conclusion reached from this study is that the gas productivity potential of Devonian shale in the Appalachian basin is influenced by a wide range of geologic factors. Organic content, thermal maturity, natural fracture spacing, and stratigraphic relationships between gray and black shales all affect gas content and mobility. Understanding these factors can improve the exploration and development of Devonian shale gas.