Numerical Simulation of the Impact of Natural Fracture on Fluid Composition Variation Through a Porous Medium

2018 ◽  
Vol 141 (4) ◽  
Author(s):  
Ali Papi ◽  
Ali Mohebbi ◽  
S. Ehsan Eshraghi
Keyword(s):  
Fracture Network ◽  
Natural Fracture ◽  
Computational Time ◽  
Single Fracture ◽  
Fracture Aperture ◽  
Fluid Composition ◽  
Composition Distribution ◽  
Engineering Software ◽  
Composition Variation ◽  
The Impact

In order to lessen the computational time in fractured oil reservoir simulations, all fractures are usually assumed to be as one equivalent fracture at the center or around the model. This, specially, has applications in industrial engineering software, where this assumption applies. In this study, using two general contradictory examples, it is shown that ignoring a fracture network and assuming an equivalent single-fracture has no logical justification and results in a considerable error. The effect of fracture aperture on composition distribution of a binary and a ternary mixture was also investigated. These mixtures were C1 (methane)/n-C4 (normal-butane) and C1 (methane)/C2 (ethane)/n-C4 (normal-butane), which were under diffusion and natural convection. Governing equations were numerically solved using matlab. One of the main relevant applications of this study is where permeability and temperature gradient are the key difference between reservoirs. Compositional distribution from this study could be used to estimate initial oil in place. Using this study, one can find the optimum permeability, namely the permeability at which the maximum species separation happens, and the threshold permeability (or fracture aperture), after which the convection imposes its effect on composition distribution. It is found that the threshold permeability is not constant from reservoir to reservoir. Also, one can find that full mixing happens in the model, namely heavy and light densities of top and bottom mix up together in the model. Furthermore, after maximum separation point, convection causes unification of components.

scholarly journals How do we see fractures? Quantifying subjective bias in fracture data collection

2019 ◽  
Author(s):  
Billy J. Andrews ◽  
Jennifer J. Roberts ◽  
Zoe K. Shipton ◽  
Sabina Bigi ◽  
Maria C. Tartarello ◽  
...  
Keyword(s):  
Data Collection ◽  
Fracture Network ◽  
Natural Fracture ◽  
Minimum Length ◽  
Considerable Variability ◽  
Fracture Data ◽  
Personal Bias ◽  
Geological Models ◽  
Subjective Bias ◽  
The Impact

Abstract. The characterisation of natural fracture networks using outcrop analogues is important in understanding sub-surface fluid flow and rock mass characteristics in fractured lithologies. It is well known from decision-sciences that subjective bias significantly impacts the way data is gathered and interpreted. This study investigates the impact of subjective bias on fracture data collected using four commonly used approaches (linear scanlines, circular scanlines, topology sampling and window sampling) both in the field and in workshops using field photographs. Considerable variability is observed between each participant's interpretation of the same scanline, and this variability is seen regardless of geological experience. Geologists appear to be either focussing on the detail or focussing on gathering larger volumes of data, and this innate personality trait affects the recorded fracture network attributes. As a result, fracture statistics derived from the field data and which are often used as inputs for geological models, can vary considerably between different geologists collecting data from the same scanline. Additionally, the personal bias of geologists collecting the data affects the size (minimum length of linear scanlines, radius of circular scanlines or area of a window sample) required of the scanline that is needed to collect a statistically representative amount of data. We suggest protocols to recognise, understand and limit the effect of subjective bias on fracture data biases during data collection.

Natural-hydraulic fracture interaction: Microseismic observations and geomechanical predictions

2015 ◽  
Vol 3 (3) ◽  
pp. SU17-SU31 ◽  
Author(s):  
Jian Huang ◽  
Reza Safari ◽  
Uno Mutlu ◽  
Kevin Burns ◽  
Ingo Geldmacher ◽  
...  
Keyword(s):  
Sensitivity Analysis ◽  
Hydraulic Fracture ◽  
Fracture Network ◽  
Natural Fracture ◽  
Design Parameters ◽  
Reservoir Area ◽  
Complex Fracture ◽  
Model Complex ◽  
Fracture Interaction ◽  
The Impact

Natural fractures can reactivate during hydraulic stimulation and interact with hydraulic fractures producing a complex and highly productive natural-hydraulic fracture network. This phenomenon and the quality of the resulting conductive reservoir area are primarily functions of the natural fracture network characteristics (e.g., spacing, height, length, number of fracture sets, orientation, and frictional properties); in situ stress state (e.g., stress anisotropy and magnitude); stimulation design parameters (e.g., pumping schedule, the type/volume of fluid[s], and proppant); well architecture (number and spacing of stages, perforation length, well orientation); and the physics of the natural-hydraulic fracture interaction (e.g., crossover, arrest, reactivation). Geomechanical models can quantify the impact of key parameters that control the extent and complexity of the conductive reservoir area, with implications to stimulation design and well optimization in the field. We have developed a series of geomechanical simulations to predict natural-hydraulic fracture interaction and the resulting fracture network in complex settings. A geomechanics-based sensitivity analysis was performed that integrated key reservoir-geomechanical parameters to forward model complex fracture network generation, synthetic microseismic (MS) response, and associated conductivity paths as they evolve during stimulation operations. The simulations tested two different natural-hydraulic fracture interaction scenarios and could generate synthetic MS events. The sensitivity analysis revealed that geomechanical models that involve complex fracture networks can be calibrated against MS data and can help to predict the reservoir response to stimulation and optimize the conductive reservoir area. We analyzed a field data set (obtained from two hydraulically fractured wells in the Barnett Formation, Tarrant County, Texas) and established a coupling between the geomechanics and MS within the framework of a 3D geologic model. This coupling provides a mechanics-based approach to (1) verify MS trends and anomalies in the field, (2) optimize conductive reservoir area for reservoir simulations, and (3) improve stimulation design on the current well in near-real-time and well design/stimulation for future wells.

scholarly journals The Role of In Situ Stress in Organizing Flow Pathways in Natural Fracture Networks at the Percolation Threshold

Geofluids ◽  
2019 ◽  
Vol 2019 ◽  
pp. 1-14 ◽  
Author(s):  
Chuanyin Jiang ◽  
Xiaoguang Wang ◽  
Zhixue Sun ◽  
Qinghua Lei
Keyword(s):  
Fluid Flow ◽  
Percolation Threshold ◽  
Fractured Reservoirs ◽  
Fracture Network ◽  
In Situ Stress ◽  
Natural Fracture ◽  
Fracture Aperture ◽  
Dilation Effect ◽  
Stress Dependent

We investigated the effect of in situ stresses on fluid flow in a natural fracture network. The fracture network model is based on an actual critically connected (i.e., close to the percolation threshold) fracture pattern mapped from a field outcrop. We derive stress-dependent fracture aperture fields using a hybrid finite-discrete element method. We analyze the changes of aperture distribution and fluid flow field with variations of in situ stress orientation and magnitude. Our simulations show that an isotropic stress loading tends to reduce fracture apertures and suppress fluid flow, resulting in a decrease of equivalent permeability of the fractured rock. Anisotropic stresses may cause a significant amount of sliding of fracture walls accompanied with shear-induced dilation along some preferentially oriented fractures, resulting in enhanced flow heterogeneity and channelization. When the differential stress is further elevated, fracture propagation becomes prevailing and creates some new flow paths via linking preexisting natural fractures, which attempts to increase the bulk permeability but attenuates the flow channelization. Comparing to the shear-induced dilation effect, it appears that the propagation of new cracks leads to a more prominent permeability enhancement for the natural fracture system. The results have particularly important implications for predicting the hydraulic responses of fractured rocks to in situ stress fields and may provide useful guidance for the strategy design of geofluid production from naturally fractured reservoirs.

scholarly journals Analysis of hydraulic fracture behavior and well pattern optimization in anisotropic coal reservoirs

2020 ◽  
pp. 014459872096083
Author(s):  
Yulong Liu ◽  
Dazhen Tang ◽  
Hao Xu ◽  
Wei Hou ◽  
Xia Yan
Keyword(s):  
Hydraulic Fracture ◽  
Coalbed Methane ◽  
Fracture Network ◽  
Simulation Software ◽  
Natural Fracture ◽  
Hydraulic Fractures ◽  
Natural Fractures ◽  
Well Pattern ◽  
Well Pattern Optimization ◽  
The Impact

Macrolithotypes control the pore-fracture distribution heterogeneity in coal, which impacts stimulation via hydrofracturing and coalbed methane (CBM) production in the reservoir. Here, the hydraulic fracture was evaluated using the microseismic signal behavior for each macrolithotype with microfracture imaging technology, and the impact of the macrolithotype on hydraulic fracture initiation and propagation was investigated systematically. The result showed that the propagation types of hydraulic fractures are controlled by the macrolithotype. Due to the well-developed natural fracture network, the fracture in the bright coal is more likely to form the “complex fracture network”, and the “simple” case often happens in the dull coal. The hydraulic fracture differences are likely to impact the permeability pathways and the well productivity appears to vary when developing different coal macrolithtypes. Thus, considering the difference of hydraulic fracture and permeability, the CBM productivity characteristics controlled by coal petrology were simulated by numerical simulation software, and the rationality of well pattern optimization factors for each coal macrolithotype was demonstrated. The results showed the square well pattern is more suitable for dull coal and semi-dull coal with undeveloped natural fractures, while diamond and rectangular well pattern is more suitable for semi-bright coal and bright coal with more developed natural fractures and more complex fracturing fracture network; the optimum wells spacing of bright coal and semi-bright coal is 300 m and 250 m, while that of semi-dull coal and dull coal is just 200 m.

scholarly journals Evaluating Flow in Fractal-Fracture Networks: Effect of Variable Aperture

2021 ◽  
Vol 56 ◽  
pp. 117-128
Author(s):  
Ajay K. Sahu ◽  
Ankur Roy
Keyword(s):  
Practical Interest ◽  
Fracture Network ◽  
Natural Fracture ◽  
Fracture Aperture ◽  
High Porosity ◽  
Fracture Networks ◽  
Building Models ◽  
Variable Aperture ◽  
Almost All ◽  
Fractal Fracture

Abstract. While fractal models are often employed for describing the geometry of fracture networks, a constant aperture is mostly assigned to all the fractures when such models are flow simulated. In nature however, almost all fracture networks exhibit variable aperture values and it is this fracture aperture that controls the conductivity of individual fractures as described by the well-known cubic-law. It would therefore be of practical interest to investigate flow patterns in a fractal-fracture network where the apertures scale in accordance to their position in the hierarchy of the fractal. A set of synthetic fractal-fracture networks and two well-connected natural fracture maps that belong to the same fractal system are used for this purpose. A set of dominant sub-networks are generated from a given fractal-fracture map by systematically removing the smaller fracture segments with narrow apertures. The connectivity values of the fractal-fracture networks and their respective dominant sub-networks are then computed. Although a large number of fractures with smaller aperture are eliminated, no significant decrease is seen in the connectivity of the dominant sub-networks. A streamline simulator based on Darcy's law is used for flow simulating the fracture networks, which are conceptualized as two-dimensional fracture continuum models. A single high porosity value is assigned to all the fractures. The permeability assigned to fractures within the continuum model is based on their aperture values and there is nearly no matrix porosity and permeability. The recovery profiles and time-of-flight plots for each network and its dominant sub-networks at different time steps are compared. The results from both the synthetic networks and the natural data show that there is no significant decrease in fluid recovery in the dominant sub-networks compared to their respective parent fractal-fracture networks. It may therefore be concluded that in the case of such hierarchical fractal-fracture systems with scaled aperture, the smaller fractures do not significantly contribute to connectivity or fluid flow. In terms of decision making, this result will aid geoscientists and engineers in identifying only those fractures that ultimately matter in evaluating the flow recovery, thus building models that are computationally less expensive while being geologically realistic.

Role of fault and fracture networks to de-risk geological leakage from subsurface energy sites

2021 ◽  
Author(s):  
Roberto Emanuele Rizzo ◽  
Hossein Fazeli ◽  
Florian Doster ◽  
Niko Kampman ◽  
Kevin Bisdom ◽  
...  
Keyword(s):  
Carbon Capture ◽  
Fracture Stress ◽  
Effective Permeability ◽  
Co2 Storage ◽  
Carbon Capture And Storage ◽  
Fracture Network ◽  
Natural Fracture ◽  
Single Fracture ◽  
Fracture Networks ◽  
Geological Co2 Storage

<p>The success of geological carbon capture and storage projects depends on the integrity of the top seal, confining injected CO<sub>2</sub> in the subsurface for long periods of time. Here, faults and related fracture networks can compromise sealing by providing an interconnected pathway for injected fluids to reach overlying aquifers or even the surface or sea bottom. In this work, we apply an integrated workflow [1] that, combining single fracture stress-permeability laboratory measurements and detailed fault and fracture network outcrop data, builds permeability models of naturally faulted caprock formations for in situ stress conditions.</p><p>We focus our study on two-dimensional (2D) fault-related fracturing within caprock sequences cut by extensional faults. 2D data of fault and fracture networks were collected from an Upper Jurassic to Lower Cretaceous shale-dominated succession in the Konusdalen area (Nordenskioldland, Svalbard, Norway). The studied rock succession represents the regional caprock and seal for the reservoir of the nearby Longyearbyen CO<sub>2</sub> Lab. By digitising all the visible features over the images and then inputting them into the open-source toolbox FracPaQ [2], we obtain information about the fault and fracture networks. In particular, we study the variations in fracture size (i.e., length, height) and density distribution near and away from the fault zone(s), together with the connectivity of fractures within the network. These three parameters are fundamental to establish if the network provides permeable pathways. They also enable us to statistically reproduce and upscale a fracture network in a realistic way.</p><p>Combining laboratory single fracture stress-permeability measurements with outcrop fracture network data allow us to create an accurate coupled mechanical-hydromechanical model of the natural fracture network and to evaluate the effective permeability of a fault related fracture network. These results are also compared against analytical estimates of effective permeability [3]. With this workflow, we overcome the geometrical simplifications of synthetic fracture models, thus allowing us to establish representative stress-permeability relationships for fractured seals of geological CO2 storage.</p><p>Reference: [1] March et al., 2020, Preprint; [2] Healy et al., 2017, JSG; [3] Seavik & Nixon, 2017, WRR</p>

Influence of Aperture Distribution on Flow in Fractal-Fracture Networks

2021 ◽  
Author(s):  
Ajay Kumar Sahu ◽  
Ankur Roy
Keyword(s):  
Practical Interest ◽  
Fracture Network ◽  
Natural Fracture ◽  
Fracture Aperture ◽  
Fracture Networks ◽  
Fracture Systems ◽  
Fractal System ◽  
Porosity And Permeability ◽  
Aperture Distribution ◽  
Fractal Fracture

<p>While fractal models are often employed for describing the geometry of fracture networks, a constant aperture is mostly assigned to all the fractures when such models are flow simulated. While network geometry controls connectivity, it is fracture aperture that controls the conductivity of individual fractures as described by the well-known cubic-law. It would therefore be of practical interest to investigate flow patterns in a fractal-fracture network where the apertures also scale as a power-law in accordance to their position in the hierarchy of the fractal. A set of synthetic fractal-fracture networks and two well-connected natural fracture maps that belong to the same fractal system are used for this purpose. The former, with connectivity above the percolation threshold, are generated by spatially locating the fractured and un-fractured blocks in a deterministic and random manner. A set of sub-networks are generated from a given fractal-fracture map by systematically removing the smaller fracture segments. A streamline simulator based on Darcy's law is used for flow simulating the fracture networks, which are conceptualized as two-dimensional fracture continuum models. Porosity and permeability are assigned to a fracture within the continuum model based on its aperture value and there is nearly no matrix porosity or permeability. The recovery profiles and time-of-flight values for each network and its dominant sub-networks at different time steps are compared.</p><p>The results from both the synthetic networks and the natural maps show that there is no significant decrease in recovery in the dominant sub-networks of a given fractal-fracture network. It may therefore be concluded that in the case of such hierarchical fractal-fracture systems with scaled aperture, the smaller fractures do not significantly contribute to the fluid flow.</p><p><strong>Key-words: </strong>Fractal-fracture; Connectivity; Aperture; Dominant Sub-networks; Streamline Simulator; Recovery</p>

scholarly journals A new methodology to train fracture network simulation using Multiple Point Statistic

2018 ◽  
Author(s):  
Pierre-Olivier Bruna ◽  
Julien Straubhaar ◽  
Rahul Pranhakaran ◽  
Giovanni Bertotti ◽  
Kevin Bisdom ◽  
...  
Keyword(s):  
Fluid Flow ◽  
Fracture Network ◽  
Natural Fracture ◽  
Multiple Point ◽  
Fracture Aperture ◽  
Strong Impact ◽  
Data Sampling ◽  
Natural Fractures ◽  
Training Images ◽  
Network Geometry

Abstract. Natural fractures have a strong impact on flow and storage properties of reservoirs. Their distribution in the subsurface is largely unknown mainly due to their sub-seismic scale and to the scarcity of available data sampling them (borehole). Outcrop can be considered as analogues where natural fracture characteristics can be extracted. However, acquiring fracture data on outcrops may produce a large amount of information that needs to be processed and efficiently interpreted to capture the key parameters defining fracture network geometry. Outcrops thus become a natural laboratory where the interpreted fracture network can be tested mechanically (fracture aperture, distribution of strain/stress) and dynamically (fluid flow simulations (Bisdom et al., 2017). The goal of this paper is to propose the multiple point statistics (MPS) method as a new tool to quickly predict the geometry of a fracture network in both surface and subsurface conditions. This sequential simulation method is based on the creation of small and synthetic training images representing fracture distribution parameters observe in the field. These training images represent the complexity of the geological object or processes to be simulated and can be simply designed by the user. In this paper we chose to use multiple training images and a probability map to represent the fracture network geometry and its potential variability in a non-stationary manner. The method was tested on a fracture pavement (2D flat surface) acquired using a drone in the Apodi area in Brazil. Fractures were traced manually on images of the outcrop and constitute the reference on which the fracture network simulations will be based. A sensitivity analysis emphasizing the influence of the conditioning data, the simulation parameters and the used training images was conducted on the obtained simulations. Stress-induced fracture aperture calculations were performed on the best realisations and on the original outcrop fracture interpretation to qualitatively evaluate the accuracy of our simulations. The method proposed here is innovative and adaptable. It can be used on any type of rocks containing natural fractures in any kind of tectonic context. This workflow can also be applied to the subsurface to predict the fracture arrangement and its fluid flow efficiency in water, heat or hydrocarbon reservoirs.

scholarly journals Modeling and Analysis of Diagnostic Fracture Injection Tests DFITs

2021 ◽  
Author(s):  
Recep Bakar ◽  
Erdal Ozkan ◽  
Hossein Kazemi
Keyword(s):  
Effective Permeability ◽  
Function Analysis ◽  
Fracture Network ◽  
Unconventional Reservoirs ◽  
Fracture Aperture ◽  
Modeling And Analysis ◽  
Matrix Permeability ◽  
Straight Line ◽  
Order Of Magnitude ◽  
The Impact

Abstract Diagnostic fracture injection tests (DFIT) are used as an indirect method to determine closure pressure and formation effective permeability in unconventional reservoirs as a first step in formation evaluation. The information obtained from DFIT is particularly useful because it is obtained before any production for a given well is available. In DFIT, a small fracture is created by injecting few barrels of completion fluid until formation breaks down and a fracture is initiated and propagates a short distance into the reservoir. Then, injection is stopped, and the pressure decline (or falloff) is monitored. From this pressure decline, the effective permeability of the formation is estimated by Nolte's G-function, log-log plot, or square root of time analysis. In this research, the viability of the common DFIT analysis techniques was investigated for unconventional reservoirs with and without micro-fractures by using a numerical hydraulic fracturing simulator, CFRAC. The results of numerical simulations were investigated to assess the impact of permeability, residual fracture aperture, and complex fracture networks on conventional DFIT interpretations. For the example considered in this work, the commonly used G-function analysis yielded estimates of permeability over an order of magnitude higher than the simulated matrix permeability. Error in the G-function estimates of permeability were higher for higher matrix permeability and in the existence of a fracture network. On the other hand, straight-line analysis of Ap versus G-time yielded much closer (in the same order of magnitude) estimates of permeability.

scholarly journals Numerical simulation on the effect of fractures geometries for shale gas development with discrete fracture network model

2021 ◽  
Vol 11 (3) ◽  
pp. 1289-1301
Author(s):  
Songze Liu ◽  
Jianguang Wei ◽  
Yuanyuan Ma ◽  
Xuemei Liu ◽  
Bingxu Yan
Keyword(s):  
Shale Gas ◽  
Hydraulic Fracture ◽  
Gas Flow ◽  
Seepage Flow ◽  
Fracture Network ◽  
Natural Fracture ◽  
Fracture Aperture ◽  
Rock Matrix ◽  
Fracture Permeability ◽  
Cumulative Production

AbstractThe shale gas reservoir is regarded as a dual medium consisting of fracture (hydraulic fracture and discrete natural fracture network) and rock matrix, the seepage process in the fracture and rock matrix is fully considered and a mathematical model of seepage flow in accordance with Darcy's law was established. The results show the influence order of hydraulic fracture geometry on the cumulative production. Compared with the hydraulic fracture aperture of 10–4 m, when the aperture is 10–5 m and 10–6 m, the cumulative production is reduced by 88.0% and 99.7%, respectively. Compared with the hydraulic fracture length is 100 m, when the length is 200 m and 300 m, the cumulative production is increased by 38.2% and 62.4%, respectively. The increase in the natural fracture aperture increases the fracture permeability, which make it more conducive to gas flow into the fracture, thereby increasing the cumulative production. The increase in the number of natural fractures makes the connectivity of the shale reservoir becomes better and the cumulative production increases more.

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