scholarly journals Production Decline Analysis and Hydraulic Fracture Network Interpretation Method for Shale Gas with Consideration of Fracturing Fluid Flowback Data

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-9
Author(s):  
Jianfeng Xiao ◽  
Xianzhe Ke ◽  
Hongxuan Wu
Keyword(s):  
Shale Gas ◽  
Hydraulic Fracture ◽  
Early Time ◽  
Fracture Network ◽  
Microseismic Monitoring ◽  
Monitoring Data ◽  
Fracturing Fluid ◽  
Fracture Conductivity ◽  
Fracture Length ◽  
Interpretation Method

After multistage hydraulic fracturing of shale gas reservoir, a complex fracture network is formed near the horizontal wellbore. In postfracturing flowback and early-time production period, gas and water two-phase flow usually occurs in the hydraulic fracture due to the retention of a large amount of fracturing fluid in the fracture. In order to accurately interpret the key parameters of hydraulic fracture network, it is necessary to establish a production decline analysis method considering fracturing fluid flowback in shale gas reservoirs. On this basis, an uncertain fracture network model was established by integrating geological, fracturing treatment, flowback, and early-time production data. By identifying typical flow-regimes and correcting the fracture network model with history matching, a set of production decline analysis and fracture network interpretation method with consideration of fracturing fluid flowback in shale gas reservoir was formed. Derived from the case analysis of a typical fractured horizontal well in shale gas reservoirs, the interpretation results show that the total length of hydraulic fractures is 4887.6 m, the average half-length of hydraulic fracture in each stage is 93.4 m, the average fracture conductivity is 69.7 mD·m, the stimulated reservoir volume (SRV) is 418 × 10 4   m 3 , and the permeability of SRV is 5.2 × 10 − 4   mD . Compared with the interpretation results from microseismic monitoring data, the effective hydraulic fracture length obtained by integrated fracture network interpretation method proposed in this paper is 59% of that obtained from the microseismic monitoring data, and the effective SRV is 83% of that from the microseismic monitoring data. The results show that the fracture length is smaller and the fracture conductivity is larger without considering the influence of fracturing fluid.

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.

scholarly journals Analysis of Hydraulic Fracture Propagation Using a Mixed Mode and a Uniaxial Strain Model considering Geomechanical Properties in a Naturally Fractured Shale Reservoir

Geofluids ◽  
2020 ◽  
Vol 2020 ◽  
pp. 1-14
Author(s):  
Youngho Jang ◽  
Gayoung Park ◽  
Seoyoon Kwon ◽  
Baehyun Min
Keyword(s):  
Shale Gas ◽  
Hydraulic Fracture ◽  
Mixed Mode ◽  
Fracture Propagation ◽  
Fracture Network ◽  
Uniaxial Strain ◽  
Propagation Model ◽  
Geomechanical Properties ◽  
Hydraulic Fracture Propagation ◽  
Strain Model

This study proposes a hydraulic fracture propagation model with a mixed mode comprising opening and sliding modes to describe a complex fracture network in a naturally fractured shale gas formation. We combine the fracture propagation model with the mixed mode and the uniaxial strain model with tectonic impacts to calculate the stress distribution using geomechanical properties. A discrete fracture network is employed to realize the fracture network composed of natural and hydraulic fractures. We compare the fracture propagation behaviours of three cases representing the Barnett, Marcellus, and Eagle Ford shale gas formations. Sensitivity analysis is performed to investigate the effects of the geomechanical properties of the reservoir on the sliding mode’s contribution to the mixed mode. The numerical results highlight the significance of the mixed mode for the accurate assessment of fracture propagation behaviours in shale gas formations with high brittleness.

Use of a CO2-Hybrid Fracturing Design to Enhance Production from Unpropped Fracture Networks

2015 ◽  
Author(s):  
Lionel H. Ribeiro ◽  
Huina Li ◽  
Jason E. Bryant
Keyword(s):  
Fracture Network ◽  
Fracturing Fluid ◽  
Fracture Conductivity ◽  
Low Viscosity ◽  
Bottom Hole ◽  
Complex Fracture Network ◽  
Tight Reservoirs ◽  
The Many ◽  
Fluid Design ◽  
Present Simulation

Abstract This paper introduces a new CO2-hybrid fracturing fluid design that intends to improve production from ultra-tight reservoirs and reduces freshwater usage. The design consists of: (1) injecting pure CO2 as the pad fluid to generate a complex fracture network, and (2) injecting a gelled slurry (water- or foamed-based) to generate near-wellbore conductivity. The motivation behind this design is that while current aqueous fluids provide sufficient primary hydraulic fracture conductivity back to the wellbore, they under-stimulate the reservoir and leave behind damaged stimulated regions deeper in the fracture network. Much of that (unpropped) stimulated area is ineffective for production due to interfacial tension effects, fines generation, and/or polymer damage. We present simulation work that demonstrates how CO2, with its low viscosity, can extend the bottom-hole treating pressure deeper in the reservoir and generate a larger producible surface area. We also present experimental evidence that CO2 leaves behind higher unpropped fracture conductivities than slick water. This paper does not address the many operational and logistical challenges of using CO2 as a fracturing fluid. Rather, it intends to demonstrate the production uplift potential of the proposed design, which seems particularly attractive in reservoirs capable of sustaining production from unpropped fractures (e.g., reservoirs with low stress anisotropy, high Young's modulus, and a pervasive set of natural fractures).

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.

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.

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