scholarly journals Diagnosing Hydraulic Fracture Geometry, Complexity, and Fracture Wellbore Connectivity Using Chemical Tracer Flowback

Energies ◽  
2020 ◽  
Vol 13 (21) ◽  
pp. 5644
Author(s):  
Ashish Kumar ◽  
Mukul M. Sharma
Keyword(s):  
Hydraulic Fracture ◽  
Field Tests ◽  
Fracture Network ◽  
Segment Length ◽  
Response Curves ◽  
Fracture Geometry ◽  
Fracture Length ◽  
Complex Fracture ◽  
Chemical Tracer ◽  
Complex Fracture Network

The productivity of a hydraulically fractured well depends on the fracture geometry and fracture–wellbore connectivity. Unlike other fracture diagnostics techniques, flowback tracer response will be dominated only by the fractures, which are open and connected to the wellbore. Single well chemical tracer field tests have been used for hydraulic fracture diagnostics to estimate the stagewise production contribution. In this study, a chemical tracer flowback analysis is presented to estimate the fraction of the created fracture area, which is open and connected to the wellbore. A geomechanics coupled fluid flow and tracer transport model is developed to analyze the impact of (a) fracture geometry, (b) fracture propagation and closure effects, and (c) fracture complexity on the tracer response curves. Tracer injection and flowback in a complex fracture network is modeled with the help of an effective model. Multiple peaks in the tracer response curves can be explained by the closure of activated natural fractures. Low tracer recovery typically observed in field tests can be explained by tracer retention due to fracture closure. In a complex fracture network, segment length and permeability are lumped to define an effective connected fracture length, a parameter that correlates with production. Neural network-based inverse modeling is performed to estimate effective connected fracture length using tracer data. A new method to analyze chemical tracer data which includes the effect of flow and geomechanics on tracer flowback is presented. The proposed approach can help in estimating the degree of connectivity between the wellbore and created hydraulic fractures.

scholarly journals A New Approach for Automatic Optimization of Complex Fracture Network in Shale Reservoirs

Lithosphere ◽  
2021 ◽  
Vol 2021 (Special 1) ◽  
Author(s):  
Haibo Wang ◽  
Tong Zhou ◽  
Fengxia Li
Keyword(s):  
Shale Gas ◽  
Flow Model ◽  
Optimization Method ◽  
Fracture Network ◽  
Gas Reservoirs ◽  
Fracture Length ◽  
Complex Fracture ◽  
Shale Gas Reservoirs ◽  
Automatic Optimization ◽  
Complex Fracture Network

Abstract Shale gas reservoirs have gradually become the main source for oil and gas production. The automatic optimization technology of complex fracture network in fractured horizontal wells is the key technology to realize the efficient development of shale gas reservoirs. In this paper, based on the flow model of shale gas reservoirs, the porosity/permeability of the matrix system and natural fracture system is characterized. The fracture network morphology is finely characterized by the fracture network expansion calculation method, and the flow model was proposed and solved. On this basis, the influence of matrix permeability, matrix porosity, fracture permeability, fracture porosity, and fracture length on the production of shale gas reservoirs is studied. The optimal design of fracture length and fracture location was carried, and the automatic optimization method of complex fracture network parameters based on simultaneous perturbation stochastic approximation (SPSA) was proposed. The method was applied in a shale gas reservoir, and the results showed that the proposed automatic optimization method of the complex fracture network in shale gas reservoirs can automatically optimize the parameters such as fracture location and fracture length and obtain the optimal fracture network distribution matching with geological conditions.

Numerical Simulation of Shale Gas Development Based on Complex Fracture Network Growth

2014 ◽  
Author(s):  
D.. Ye ◽  
C.. Yin ◽  
Y.. Li ◽  
S.. Wang ◽  
G.. Qin ◽  
...  
Keyword(s):  
Shale Gas ◽  
Hydraulic Fracture ◽  
Large Scale ◽  
Fracture Network ◽  
Production Performance ◽  
Network Growth ◽  
Stimulated Reservoir Volume ◽  
Well Production ◽  
Complex Fracture ◽  
Complex Fracture Network

Abstract Micro-seismic result has shown that compared to conventional reservoir, more complex fracture network will be generated in shale gas reservoirs after hydraulic fracturing stimulations, which provides key channels for shale gas to flow in economic rate. It is vitally important to recognize complex fracture network and model such complex system to better understand gas develop process, optimize hydraulic fracturing design, and determine development plans of shale gas reservoirs. Our proposed model enable realistic modeling of complex fracture network growth even with some uncertainty (SPE 157411), but it is possible to represent large-scale fracture network distribution in reservoir modeling and numerical simulation of shale gas development. In this paper, we used this proposed model to generate hydraulic fracture network distribution in shale formation, taking into account interaction between hydraulic fracture and actual large-scale natural fractures. Integrating hydraulic fracture network results and natural fractures in non-stimulated area, highly constrained unstructured gridding and a connection list are constructed, using the Discrete Fracturing Modeling (DFM) method. This model can effectively predict production performance. With real-world well data, the simulation system calibration is done, and the simulated well production performance has good agreement with real-world producing data. Using this simulation system, effective stimulated reservoir volume (ESRV) is also predicted. The proposed approach is capable of modeling complex fracture network propagation and predicting well producing rate, if information data on multi-scale pre-existing natural fracture is available. This approach provide one opportunity to predict well production performance and effective stimulated reservoir volume (ESRV), which is also significant for shale gas development plan.

Predicting Well Performance in Naturally Fractured Reservoir

2013 ◽  
Author(s):  
Yunsuk Hwang ◽  
Jiajing Lin ◽  
David Schechter ◽  
Ding Zhu
Keyword(s):  
Hydraulic Fracture ◽  
Fracture Network ◽  
Darcy Flow ◽  
Natural Fracture ◽  
Hydraulic Fractures ◽  
Natural Fractures ◽  
Well Performance ◽  
Fracture Networks ◽  
Complex Fracture ◽  
Complex Fracture Network

Multiple hydraulic fracture treatments in reservoirs with natural fractures create complex fracture networks. Predicting well performance in such a complex fracture network system is an extreme challenge. The statistical nature of natural fracture networks changes the flow characteristics from that of a single linear fracture. Simply using single linear fracture models for individual fractures, and then summing the flow from each fracture as the total flow rate for the network could introduce significant error. In this paper we present a semi-analytical model by a source method to estimate well performance in a complex fracture network system. The method simulates complex fracture systems in a more reasonable approach. The natural fracture system we used is fractal discrete fracture network model. We then added multiple dominating hydraulic fractures to the natural fracture system. Each of the hydraulic fractures is connected to the horizontal wellbore, and some of the natural fractures are connected to the hydraulic fractures through the network description. Each fracture, natural or hydraulically induced, is treated as a series of slab sources. The analytical solution of superposed slab sources provides the base of the approach, and the overall flow from each fracture and the effect between the fractures are modeled by applying the superposition principle to all of the fractures. The fluid inside the natural fractures flows into the hydraulic fractures, and the fluid of the hydraulic fracture from both the reservoir and the natural fractures flows to the wellbore. This paper also shows that non-Darcy flow effects have an impact on the performance of fractured horizontal wells. In hydraulic fracture calculation, non-Darcy flow can be treated as the reduction of permeability in the fracture to a considerably smaller effective permeability. The reduction is about 2% to 20%, due to non-Darcy flow that can result in a low rate. The semi-analytical solution presented can be used to efficiently calculate the flow rate of multistage-fractured wells. Examples are used to illustrate the application of the model to evaluate well performance in reservoirs that contain complex fracture networks.

scholarly journals Study on the Interaction Mechanism of Hydraulic Fracture and Natural Fracture in Shale Formation

Energies ◽  
2019 ◽  
Vol 12 (23) ◽  
pp. 4477 ◽  
Author(s):  
Heng Zheng ◽  
Chunsheng Pu ◽  
CHOE TONG IL
Keyword(s):  
Hydraulic Fracture ◽  
Shear Failure ◽  
Fracture Network ◽  
Tensile Failure ◽  
Natural Fracture ◽  
Natural Fractures ◽  
Propagation Length ◽  
Complex Fracture ◽  
Geological Conditions ◽  
Complex Fracture Network

Hydraulic fracturing is an essential technique for the development of shale gas, due to the low permeability in formation. Abundant natural fractures contained in a formation are indispensable for the development of a fracture network. In this paper, a damage-stress-seepage coupled hydraulic fracture expansion model, based on the extended finite element method, is established. The simulation results show that shear failure occurs when the hydraulic fracture interacts with a frictional natural fracture, while tensile failure occurs when it interacts with a cement natural fracture. Low interaction angles and high tensile strength of the rock are beneficial for the generation of a complex fracture network. Furthermore, under the same geological conditions and injection parameters, frictional natural fractures are more beneficial for the generation of a complex fracture network, when compared with cement natural fractures. This can not only effectively increase the propagation length of the natural fracture, but also effectively reduce its reactive resistance. This research is of great significance for the efficient exploitation of unconventional oil and gas resources.

Induced Stress and Interaction of Fractures During Hydraulic Fracturing in Shale Formation

2015 ◽  
Vol 137 (6) ◽  
Author(s):  
Desheng Zhou ◽  
Peng Zheng ◽  
Jiao Peng ◽  
Pei He
Keyword(s):  
Hydraulic Fracturing ◽  
Principal Stress ◽  
Hydraulic Fracture ◽  
Fracture Network ◽  
Hydraulic Fractures ◽  
Single Fracture ◽  
Complex Fracture ◽  
Induced Stress ◽  
Transverse Distance ◽  
Complex Fracture Network

Creating complex fracture network by hydraulic fracturing operation in unconventional reservoir development is the key factor of effective exploitation. The mechanism of creating a fracture network is not clear up to today. Conventional hydraulic fracturing theory is based on tensile failure of a rock, and a hydraulic fracture is widely accepted as propagating along the direction of in situ maximum horizontal principal stress in the industry. Based on rock elastic mechanics and fracture mechanics, considering combined tensile and shear failures, the maximum circumferential strain criterion and boundary element method (BEM), the paper studies the induced stress and its variation during a fracture propagation, the interaction between two or more hydraulic fractures, and the interaction between a hydraulic fracture and a natural crack. The paper shows that a propagating fracture will produce induced stresses on surrounding rock and form a stress shadow. Instead of propagation along the direction of maximum horizontal principal stress as a single fracture, the outside two fractures of two or more hydraulic fractures are exclusive and turning away from each other. A natural crack may be awaked and extend at its both tips by a propagating hydraulic fracture before their intersection, and the hydraulic fracture may deflect toward the natural crack. The interaction between a hydraulic fracture and a natural crack depends on the transverse distance between them and the initial length of the crack. The shorter the transverse distance and the longer the crack length are, the higher the possibility of the crack to be awaked is. The research results are helpful in understanding complex fracture network and may be used in determining hydraulic fracture places to create a complex fracture network.

Numerical model on predicting hydraulic fracture propagation in low-permeability sandstone

2020 ◽  
pp. 105678952096320
Author(s):  
Ji Shi ◽  
Jianhua Zhang ◽  
Chunyang Zhang ◽  
Tingting Jiang ◽  
Gang Huang
Keyword(s):  
Hydraulic Fracture ◽  
Fracture Propagation ◽  
Fracture Network ◽  
Natural Fracture ◽  
Low Permeability ◽  
Zone Method ◽  
Crustal Stress ◽  
Complex Fracture ◽  
Complex Fracture Network ◽  
Hydraulic Fracture Propagation

Hydraulic fracture propagation is hard to predict due to natural joints and crustal stress. This process may lead to uncontrollable changes in hydrogeological conditions. Therefore, prediction and control of fracture propagation are paramount to permeability increase in ore-bearing reservoir. The coupled fluid-solid model was utilized to predict the hydraulic fracture propagation in low-permeability sandstone of a uranium mine. For this study, the model was modified to allow fractures to propagate randomly by using the cohesive zone method. The simulation was developed on a three-step process. First, geological data required to run the model, including crustal stress, strength and permeability, were assembled. Next, fracture propagation under different conditions of stress and injection volume were simulated. In the final step, experimental data required to validate the model were obtained. The simulation results indicate that the principal stress, distribution and orientation of natural fracture have vital influence on fracture propagation and induced complex fracture network. This work provides a theoretical basis for the application of hydraulic fracture in low-permeability sandstone reservoir and ensures the possibility to predict the generation of complex fracture network.

Numerical Simulation of Complex Fracture Network Development by Hydraulic Fracturing in Naturally Fractured Ultratight Formations

2013 ◽  
Author(s):  
Hannes Hofmann ◽  
Tayfun Babadagli ◽  
Günter Zimmermann
Keyword(s):  
Fracture Network ◽  
Natural Fracture ◽  
Fracture Networks ◽  
Network Development ◽  
Complex Fracture ◽  
Fracture Patterns ◽  
Fracture Systems ◽  
Fracture Development ◽  
Complex Fracture Network ◽  
Treatment Designs

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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