Modeling the Effect of a Natural Fracture Network and its Properties on Multi-Stage Stimulation

The creation of large complex fracture networks by hydraulic fracturing is imperative for enhanced oil recovery from tight sand or shale reservoirs, tight gas extraction, and Hot-Dry-Rock (HDR) geothermal systems to improve the contact area to the rock matrix. Although conventional fracturing treatments may result in bi-wing fractures, there is evidence by microseismic mapping that fracture networks can develop in many unconventional reservoirs, especially when natural fracture systems are present and the differences between the principle stresses are low. However, not much insight is gained about fracture development as well as fluid and proppant transport in naturally fractured tight formations. In order to clarify the relationship between rock and treatment parameters, and resulting fracture properties, numerical simulations were performed using a commercial Discrete Fracture Network (DFN) simulator. A comprehensive sensitivity analysis is presented to identify typical fracture network patterns resulting from massive water fracturing treatments in different geological conditions. It is shown how the treatment parameters influence the fracture development and what type of fracture patterns may result from different treatment designs. The focus of this study is on complex fracture network development in different natural fracture systems. Additionally, the applicability of the DFN simulator for modeling shale gas stimulation and HDR stimulation is critically discussed. The approach stated above gives an insight into the relationships between rock properties (specifically matrix properties and characteristics of natural fracture systems) and the properties of developed fracture networks. Various simulated scenarios show typical conditions under which different complex fracture patterns can develop and prescribe efficient treatment designs to generate these fracture systems. Hydraulic stimulation is essential for the production of oil, gas, or heat from ultratight formations like shales and basement rocks (mainly granite). If natural fracture systems are present, the fracturing process becomes more complex to simulate. Our simulation results reveal valuable information about main parameters influencing fracture network properties, major factors leading to complex fracture network development, and differences between HDR and shale gas/oil shale stimulations.

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Geomechanical and Fracture Network Interpretation of a Devonian Outcrop

SPE Reservoir Evaluation & Engineering ◽

10.2118/206723-pa ◽

2021 ◽

pp. 1-16

Author(s):

Scott McKean ◽

Simon Poirier ◽

Henry Galvis-Portilla ◽

Marco Venieri ◽

Jeffrey A. Priest ◽

...

Keyword(s):

Large Scale ◽

Multiple Scales ◽

Fracture Network ◽

Natural Fracture ◽

Small Scale ◽

Nugget Effect ◽

Schmidt Hammer ◽

Unconventional Reservoir ◽

Fracture Anisotropy ◽

Fracture Intensity

Summary The Duvernay Formation is an unconventional reservoir characterized by induced seismicity and fluid migration, with natural fractures likely contributing to both cases. An alpine outcrop of the Perdrix and Flume formations, correlative with the subsurface Duvernay and Waterways formations, was investigated to characterize natural fracture networks. A semiautomated image-segmentation and fracture analysis was applied to orthomosaics generated from a photogrammetric survey to assess small- and large-scale fracture intensity and rock mass heterogeneity. The study also included manual scanlines, fracture windows, and Schmidt hammer measurements. The Perdrix section transitions from brittle fractures to en echelon fractures and shear-damage zones. Multiple scales of fractures were observed, including unconfined, bedbound fractures, and fold-relatedbed-parallel partings (BPPs). Variograms indicate a significant nugget effect along with fracture anisotropy. Schmidt hammer results lack correlation with fracture intensity. The Flume pavements exhibit a regionally extensive perpendicular joint set, tectonically driven fracturing, and multiple fault-damage zones with subvertical fractures dominating. Similar to the Perdrix, variograms show a significant nugget effect, highlighting fracture anisotropy. The results from this study suggest that small-scale fractures are inherently stochastic and that fractures observed at core scale should not be extrapolated to represent large-scale fracture systems; instead, the effects of small-scale fractures are best represented using an effective continuum approach. In contrast, large-scale fractures are more predictable according to structural setting and should be characterized robustly using geological principles. This study is especially applicable for operators and regulators in the Duvernay and similar formations where unconventional reservoir units abut carbonate formations.

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Stochastic discrete fracture network modeling in shale reservoirs via integration of seismic attributes and petrophysical data

Interpretation ◽

10.1190/int-2020-0210.1 ◽

2021 ◽

pp. 1-50

Author(s):

Yongchae Cho

Keyword(s):

Seismic Data ◽

Stochastic Approach ◽

Fracture Network ◽

Natural Fracture ◽

Well Logs ◽

Fracture Model ◽

Well Log ◽

Discrete Fracture ◽

Discrete Fracture Network Modeling ◽

Fracture Network Modeling

The prediction of natural fracture networks and their geomechanical properties remains a challenge for unconventional reservoir characterization. Since natural fractures are highly heterogeneous and sub-seismic scale, integrating petrophysical data (i.e., cores, well logs) with seismic data is important for building a reliable natural fracture model. Therefore, I introduce an integrated and stochastic approach for discrete fracture network modeling with field data demonstration. In the proposed method, I first perform a seismic attribute analysis to highlight the discontinuity in the seismic data. Then, I extrapolate the well log data which includes localized but high-confidence information. By using the fracture intensity model including both seismic and well logs, I build the final natural fracture model which can be used as a background model for the subsequent geomechanical analysis such as simulation of hydraulic fractures propagation. As a result, the proposed workflow combining multiscale data in a stochastic approach constructs a reliable natural fracture model. I validate the constructed fracture distribution by its good agreement with the well log data.

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The Stratigraphy of Pre-Tertiary Economic Basement in South Jambi B Block, South Sumatra Basin

10.29118/ipa21-g-271 ◽

2021 ◽

Keyword(s):

Significant Contribution ◽

Fracture Network ◽

Natural Fracture ◽

Fracture Density ◽

The South ◽

The North ◽

Fracture Intensity ◽

Parent Rocks ◽

Major Fault ◽

Essential Function

As one of the most promising plays, the Pre-Tertiary basement play holds a significant contribution to the latest success of exploration efforts in the South Sumatra Basin, which then includes the South Jambi B Block. Yet, the natures of the Pre-Tertiary unit in this block remains unsolved. Lithology variability, spatial irregularity, genetic ambiguity, and different reservoir characteristic are indeterminate subjects in the block are the main focus here. The ultimate goals of this study are to better characterize the unit and gain more understanding in calibrating the remaining potential. Based on this study, The Pre-Tertiary units are mainly originated from layered marine-deltaic sedimentary parent rocks with carbonate, intruded by spotty granite where the concentration of each parent rocks varies at the north, the middle, and southern part. Secondly, both lithology heterogeneity and natural fracture density create distinctive reservoir deliverability at each structure. The storage concept is an essential function of natural fracture intensity and diversity, supported by matrix porosity that varies across a different succession of lithology. Lastly, this study observes that major fault orientation is essential in constructing the fracture network. Evidence from several image logs across the study area concludes that most of the interpreted fractures are oriented subparallel to the major faults. The northern belt area is relatively affected by NW-SE Neogene structure, where the southern area is recognized to be affected by both Neogene compression and pre-existing Paleogene structure.

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

10.5194/se-2018-135 ◽

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.

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Natural-hydraulic fracture interaction: Microseismic observations and geomechanical predictions

Interpretation ◽

10.1190/int-2014-0233.1 ◽

2015 ◽

Vol 3 (3) ◽

pp. SU17-SU31 ◽

Cited By ~ 13

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.

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

Geofluids ◽

10.1155/2019/3138972 ◽

2019 ◽

Vol 2019 ◽

pp. 1-14 ◽

Cited By ~ 1

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.

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Analysis of Fracturing Ability Factors of Tight Reservoir

E3S Web of Conferences ◽

10.1051/e3sconf/202016501004 ◽

2020 ◽

Vol 165 ◽

pp. 01004

Author(s):

Zhenhua Li ◽

Ke Gai ◽

Feng Cao

Keyword(s):

Fracture Toughness ◽

Organic Matter ◽

Organic Carbon ◽

Oil And Gas ◽

Sedimentary Environment ◽

Economic Benefits ◽

Natural Fracture ◽

Organic Carbon Content ◽

Multi Stage ◽

Tight Reservoir

Fracturing ability is the characteristic used to measure whether the tight reservoir could be effectively fractured and form network in the process of hydraulic fracturing in order to improve the production of oil and gas. Research shows that the more brittle the reservoir is, the weaker the fracture toughness is, the more developed the natural fracture is, the higher the maturity of organic matter is, the lower the organic carbon content is, and the better the fracturing ability is. In addition, factors such as crustal stress, sedimentary environment and internal structure of the reservoir also affect the fracturing ability. The analysis of reservoir fracturing ability plays a key role in the strata selection, multi-stage fracturing design and prediction of oilfield economic benefits.

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

Energy Exploration & Exploitation ◽

10.1177/0144598720960833 ◽

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.

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Modelling large-scale fractured reservoirs efficiently for geothermal energy and groundwater flow

10.5194/egusphere-egu2020-9278 ◽

2020 ◽

Author(s):

Simon Oldfield ◽

Mikael Lüthje ◽

Michael Welch ◽

Florian Smit

Keyword(s):

Fluid Flow ◽

Geothermal Energy ◽

Large Scale ◽

Fractured Reservoirs ◽

Fracture Network ◽

Natural Fracture ◽

Fracture Networks ◽

Persistent Problem ◽

Fracture Evolution ◽

Rapid Generation

Large scale modelling of fractured reservoirs is a persistent problem in representing fluid flow in the subsurface. Considering a geothermal energy prospect beneath the Drenthe Aa area, we demonstrate application of a recently developed approach to efficiently predict fracture network geometry across an area of several square kilometres.Using a strain based method to mechanically model fracture nucleation and propagation, we generate a discretely modelled fracture network consisting of individual failure planes, opening parallel and perpendicular to the orientation of maximum and minimum strain. Fracture orientation, length and interactions vary following expected trends, forming a connected fracture network featuring population statistics and size distributions comparable to outcrop examples.Modelled fracture networks appear visually similar to natural fracture networks with spatial variation in fracture clustering and the dominance of major and minor fracture trends.Using a network topology approach, we demonstrate that the predicted fracture network shares greater geometric similarity with natural networks. Considering fluid flow through the model, we demonstrate that hydraulic conductivity and flow anisotropy are strongly dependent on the geometric connection of fracture sets.Modelling fracture evolution mechanically allows improved representation of geometric aspects of fracture networks to which fluid flow is particularly sensitive. This method enables rapid generation of discretely modelled fractures over large areas and extraction of suitable summary statistics for reservoir simulation. Visual similarity of the output models improves our ability to compare between our model and natural analogues to consider model validation.

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