The SPE has split the former "Management & Information" technical discipline into two new technical discplines:
- Data Science & Engineering Analytics
The SPE has split the former "Management & Information" technical discipline into two new technical discplines:
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Zheng, Shuang (Aramco Americas) | Ates, Harun (Aramco Americas) | Gupta, Anuj (Aramco Americas) | Crumpton, Paul (Saudi Aramco)
Abstract Fracture diagnostic data for shale wells show that the fracture system after hydraulic fracturing is quite complex. Accurate and efficient simulation modeling of complex hydraulic and natural fracture networks is critical for evaluation of well performance and stimulation effectiveness in unconventional oil and gas reservoirs. The traditional method based on local grid refinement (LGR) has limitations in handling 3D hydraulic and natural fracture geometry. In addition, its computational efficiency is low, especially for dealing with a large number of hydraulic fractures and multiple horizontal wells. In this study, we develop a new workflow which, for the first time, utilizes embedded discrete fracture model (EDFM) method coupled with a parallel reservoir simulator (PRS) to simulate all types of 3D hydraulic and natural fractures. EDFM can easily avoid re-gridding matrix cells containing hydraulic and natural fractures. More realistic 3D fracture geometry from either fracture propagation simulation or user definition and geological model with corner point can be accurately honored. The input fractures can be smoothly embedded into the model grid through EDFM processing We validated the parallel reservoir simulator with EDFM by comparing the simulation results using dual porosity dual permeability (DPDP) model. After benchmarking, we applied this new workflow to simulate three synthetic field cases. The simulation results are also compared with a commercial reservoir simulator (CRS) with the EDFM method. Well performance for the real case with and without natural fractures can be efficiently simulated. The new EDFM workflow enables to model 3D hydraulic and natural fractures with any strike and dip angels efficiently and accurately in the parallel reservoir simulator. Modifications of fracture properties can be easily done. This new workflow enables a much faster and more robust fracture modeling process, which is highly effective for the fracture model calibration and development optimization in unconventional oil and gas reservoirs.
Abstract The Clair field could be described as an ‘unconventional’ conventional reservoir. The rock matrix permeability places reservoir into the conventional category, for which conventional fracturing design in terms of high proppant concentration and fracture conductivity are required for production uplift. However, the presence of natural fractures brings the Clair field a similarity to unconventional reservoirs where impact and contribution of natural fractures must be taken into the equation. This paper describes the integrated fracturing and production optimization study that was conducted to optimize multistage hydraulic fracturing design in the presence of natural fractures of various density in the Clair field. The production uplift of hydraulic fracturing in conventional reservoirs is well understood. However, the presence of natural fractures adds an unconventional twist of complexity and uncertainty to fracturing design and even more so to production uplift estimates. To reduce the uncertainty of hydraulic fracturing uplift in the presence of natural fractures, specialized software was used to explicitly model cases with a range of density discrete fracture networks (DFNs) and the interaction with hydraulic fractures. Then the resulting fracture geometries were input into production modelling software to estimate uplift and calibrated back to producers in the segment. This process was repeated for several reservoir scenarios and fracturing designs to establish the production uplift range and ultimately inform optimal hydraulic fracturing design recommendations. One of the most valuable, yet not most intuitive observations was that the natural fractures and the hydraulic fractures can have a synergistic effect on production. All DFN cases modelled showed benefit from using hydraulic fracturing including high density DFNs. Even when natural fractures are already present, hydraulic fractures will help in connecting the natural fractures to the well and increase production. Higher numbers of hydraulic fractures were associated with the best uplift predictions. The described work has been instrumental in changing how hydraulic fracturing is being considered for naturally fractured reservoirs in general and for the Clair field in particular. Hydraulic fracturing had originally just been seen as a mitigation to a poorly fractured (low/no DFN) outcome. With the results of this study however it is evident that hydraulic fracturing is also an enabler for increased production in a wide range of DFN cases. Several practical recommendations have resulted from this study such as multistage fracture spacing, number of fractures, optimized proppant placement between stages and fracture geometry. The impact of fracture vs wellbore orientation and overflush were also modelled. This is the first time such a workflow has been applied for a conventional yet naturally fractured reservoir. The proposed modelling workflow allows for optimization and robust fracturing design in environment of reservoir and geological uncertainties.
Qian, Wang (CNPC Engineering Technology R & D Company Limited) | Shengxian, Zhao (Petrochina SourthWest Oil & Gas field Company Shale Gas Research Institute) | Chenxi, Ye (CNPC Engineering Technology R & D Company Limited) | Wenbao, Zhai (CNPC Engineering Technology R & D Company Limited) | Chao, Fang (CNPC Engineering Technology R & D Company Limited) | Peng, Tan (CNPC Engineering Technology R & D Company Limited)
ABSTRACT: Horizontal drilling and large-scale hydraulic fracturing are currently used to increase artificial fracture networks and per well production in unconventional reservoirs. Due to the differences of regional geological characteristics, natural fracture characteristics and geomechanical characteristics, different wellbore directions may lead to different hydraulic fracturing effects and post-frac productivity. If the well orientation is not correct, it can result in poor hydraulic fracturing propagation and inefficient production. The high precision geological model and geomechanical model of platform of typical shale gas blocks in Sichuan were established. First, considering the interaction of hydraulic fracture and natural fracture, interaction of hydraulic fracture each other, hydraulic fracturing network distribution in different in-situ stress orientation, natural fracture azimuth, wellbore azimuth combination cases were simulated. Second, high-precision unstructured grid numerical model was established on the basis of hydraulic fracturing fractures to accurately characterize fracture network morphology and fracture conductivity. The flow characteristics of hydraulic fracturing network was simulated, and post-frac productivity were predicted. Finally, the optimal wellbore orientation under various in-situ stresses and natural fracture combination cases was obtained by combining the fracturing effect and post-frac productivity. The research results show that, under the typical fracturing construction and production conditions in Sichuan shale gas block, the optimal well orientation is not affected by the natural fracture orientation. The fracturing effect and production within the range of 0-30 degrees of horizontal minimum in-situ stress are better. When the angle between natural fracture orientation and horizontal minimum in-situ stress is more than 50°, the overall production becomes better in various well directions. 1. INTRODUCTION Hydraulic fracturing in horizontal well can greatly improve the production capacity of a single well in unconventional oil and gas resources. Due to regional differences in geological characteristics, natural fracture characteristics and geomechanical characteristics of unconventional reservoirs, variability in in-situ stress directions, natural fracture directions and wellbore directions may lead to different fracturing effects and post-frac productivity under the same fracturing construction and production conditions. Therefore, it is very important for horizontal well orientation optimization.
Summary The productivity and injectivity of hydraulically fractured geothermal wells in naturally fractured formations depend on the connectivity of fracture networks created by the interaction of hydraulic fractures with natural fractures. The primary objectives of this paper are (a) to define quantitatively the connectivity of the created fracture network, (b) to determine the factors that control the connectivity of fracture networks bounded by wells, and (c) to propose ways in which the flow capacity and fracture connectivity can be improved by changes to the hydraulic fracture design. A fully 3D hydraulic fracturing simulator has been developed that considers the interaction of hydraulic fractures with natural fractures by solving for the stresses, fluid flow, heat transfer, fracture growth, and intersection. These propagated fractures, which include hydraulic fractures and reactivated natural fractures, are divided into backbone, dead-end, and isolated fractures. Different well patterns that aim to optimize the connectivity of the injector to the producer (optimize the area of the backbone fractures) are simulated. A sensitivity analysis is conducted to investigate the effect of various parameters on the connectivity of wells through fractures. An optimal well pattern is needed to maximize the connected fracture area that provides a conductive path for heat extraction from naturally fractured geothermal reservoirs. Our results show that the connectivity of fracture networks is dramatically impacted by the degree of deflection, crossing, and merging of hydraulic fractures with natural fractures. An example is used to investigate the effect of backbone and dead-end fractures on heat extraction from an enhanced geothermal system (EGS). The detailed parametric study helps us better understand the factors that influence the geometry and connectivity of fracture networks and guide us in hydraulic fracture design and well spacing optimization in naturally fractured geothermal reservoirs.
Abstract 4D DAS VSP is a real-time in-situ monitoring technique of stimulated rock volume in unconventional shale reservoirs. Latest field experiments using active seismic sources and wells permanently equipped with fiber optic have shown promising 4D seismic signatures to monitor the growth of hydraulic fractures. To gain quantitative intuitions on the characteristics of this 4D signature, we implement a pragmatic 4D modeling workflow with geomechanical fracture characterization. The stacking of all the 4D DAS time shifts signals associated with each stimulation stage on one map is best characterized by the magnitude and the size of the 4D anomaly. The modeling results suggest that the magnitude and the spatial distribution of the 4D DAS signature are mainly governed by the fracture density, fracture aspect ratio, fracture half-height, fracture azimuth, cumulative induced confining stress accompanying hydraulic stimulation, and survey design. In the upper diagonal half of the time shifts map, the size of the 4D anomaly band merely depends on the fracture aspect ratio and the induced confining horizontal stress. However, the stretch of the 4D fracture shadowing seen in the lower diagonal half of the map is mainly influenced by the fracture half-height and the DAS survey design. Additionally, the modeling results emphasize the need to account for shale rocks’ intrinsic transversely isotropic elastic behavior when predicting 4D DAS time shifts for far offsets monitoring surveys. Furthermore, placing the monitoring source at an optimized distance from the well toe ensures the recovery of reliable time shifts, and detectable 4D fracture shadowing signature that can be used to estimate the fracture properties, and hence provide recommendations on whether further targeted stimulations are needed to optimize production safely. Introduction The time-lapse DAS survey is quickly developing into an adequate and cost-effective seismic surveillance technique for unconventional reservoirs. It provides a wealth of information on the evolution of the stimulated rock volume during the hydraulic stimulation operations. Recent field trials revealed promising 4D seismic signatures associated with hydraulic fracturing. Byerley et al. (2018) reported 4D DAS observations recorded after every stimulation stage during the well treatment operations in the Wolfcamp shale formation in the Permian Basin. In this case, detectable time shifts response directly related to the induced hydraulic fractures are published. Zhao et al. (2020) replicated this field experiment at the Hereford oil field in Colorado. They detected P-wave 4D time shifts anomalies of up to 3 ms from two horizontal wells.