Controlled Hydraulic Fracturing of Naturally Fractured Shales - A Case Study in the Marcellus Shale Examining How to Identify and Exploit Natural Fractures

2013 ◽  
Author(s):  
Iraj A. Salehi ◽  
Jordan Ciezobka
Keyword(s):  
Hydraulic Fracturing ◽  
Marcellus Shale ◽  
Natural Fractures ◽  
Naturally Fractured

scholarly journals A numerical investigation on the performance of hydraulic fracturing in naturally fractured gas reservoirs based on stimulated rock volume

2020 ◽  
Vol 10 (8) ◽  
pp. 3333-3345
Author(s):  
Ali Al-Rubaie ◽  
Hisham Khaled Ben Mahmud
Keyword(s):  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Natural Fracture ◽  
Shear Stresses ◽  
Individual Element ◽  
Natural Fractures ◽  
Gas Reservoirs ◽  
Stimulated Reservoir Volume ◽  
Reservoir Volume ◽  
Naturally Fractured

Abstract All reservoirs are fractured to some degree. Depending on the density, dimension, orientation and the cementation of natural fractures and the location where the hydraulic fracturing is done, preexisting natural fractures can impact hydraulic fracture propagation and the associated flow capacity. Understanding the interactions between hydraulic fracture and natural fractures is crucial in estimating fracture complexity, stimulated reservoir volume, drained reservoir volume and completion efficiency. However, because of the presence of natural fractures with diffuse penetration and different orientations, the operation is complicated in naturally fractured gas reservoirs. For this purpose, two numerical methods are proposed for simulating the hydraulic fracture in a naturally fractured gas reservoir. However, what hydraulic fracture looks like in the subsurface, especially in unconventional reservoirs, remain elusive, and many times, field observations contradict our common beliefs. In this study, the hydraulic fracture model is considered in terms of the state of tensions, on the interaction between the hydraulic fracture and the natural fracture (45°), and the effect of length and height of hydraulic fracture developed and how to distribute induced stress around the well. In order to determine the direction in which the hydraulic fracture is formed strikethrough, the finite difference method and the individual element for numerical solution are used and simulated. The results indicate that the optimum hydraulic fracture time was when the hydraulic fracture is able to connect natural fractures with large streams and connected to the well, and there is a fundamental difference between the tensile and shear opening. The analysis indicates that the growing hydraulic fracture, the tensile and shear stresses applied to the natural fracture.

Case Study: Evaluation of an Oxidative Biocide During and After a Hydraulic Fracturing Job in the Marcellus Shale

2011 ◽  
Author(s):  
Shawn M. Rimassa ◽  
Paul R. Howard ◽  
Bruce MacKay ◽  
Kristel Arrington Blow ◽  
Noel Coffman
Keyword(s):  
Hydraulic Fracturing ◽  
Marcellus Shale ◽  
Study Evaluation

Natural Fracture Dominated Distribution of Slurry During a Multi-Cluster Hydraulic Fracturing Stage: A Marcellus DAS/DTS Case Study

2021 ◽  
Author(s):  
Eric Romberg ◽  
Andrew Adams ◽  
Jason Edwards ◽  
Taylor Levon
Keyword(s):  
Fractured Rock ◽  
Marcellus Shale ◽  
Natural Fracture ◽  
Drill Bit ◽  
Natural Fractures ◽  
Working Hypothesis ◽  
Naturally Fractured ◽  
Limited Entry ◽  
Environmental Laboratory ◽  
The Impact

Abstract In this paper, the authors examine the impacts of natural fractures on the distribution of slurry in a well with a permanent fiber installation and drill bit geomechanics data. Additionally, they propose a framework for further investigation of natural fractures on slurry distribution. As part of the Marcellus Shale Energy and Environmental Laboratory (MSEEL), the operator monitored the drilling of a horizontal Marcellus Formation well with drill bit geomechanics, and subsequent stimulation phase with a DAS/DTS permanent fiber installation. Prior to the completion, the authors used an analytical model to examine the theoretical distribution of slurry between perforation clusters from a geomechanics framework. A perforation placement scheme was then developed to minimize the stress difference between clusters and to segment stages by the intensity of natural fractures while conforming to standard operating procedures for the operator's other completions. The operator initially began completing the well with the geomechanics-informed perforation placement plan while monitoring the treatment distribution with DAS/DTS in real time. The operator observed several anomalous stages with treating pressures high enough to cause operational concerns. The operator, fiber provider, and drill bit geomechanics provider reviewed the anomalous stages’ treatment data, DAS/DTS data, and geomechanics data and developed a working hypothesis. They believed that perforation clusters placed in naturally fractured rock were preferentially taking the treatment slurry. This phenomenon appeared to cause other clusters within the stage to sand-off or become dormant prematurely, resulting in elevated friction pressure. This working hypothesis was used to predict upcoming stages within the well that would be difficult to treat. Another perforation placement plan was developed for the second half of the well to avoid perforating natural fractures as an attempt to mitigate operational issues due to natural fracture dominated distribution. Over the past several years, the industry's growing understanding of geomechanical and well construction variability has created new limited-entry design considerations to optimize completion economics and reduce the variability in cluster slurry volumes. Completion engineers working in naturally fractured fields, such as the Marcellus, should consider the impact the natural fractures have on slurry distribution when optimizing their limited-entry designs and stage plan.

Integrated Hydraulic Fracturing Strategy Leads to Successful Execution of the First Highly Deviated Ultra-Deep Well in Tarim Oilfield

2022 ◽  
Author(s):  
Liao Wang ◽  
Bo Cai ◽  
Wentong Fan ◽  
Zhanwei Yang ◽  
Guowei Xu ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
Rock Mechanics ◽  
Treatment Success ◽  
Parameters Optimization ◽  
Natural Fractures ◽  
Breakdown Pressure ◽  
Large Reservoir ◽  
Deep Well ◽  
Fracture Development

Abstract Well K1002 is the first highly deviated ultra-deep well in Tarim Oilfield of China, with the reservoir depth 7060m and the well deviation of 60° ∼ 77.6° in the fractured interval. Because of large deviation angle, high breakdown pressure and in-situ stress, poor effectiveness of natural fractures, large reservoir thickness, it is difficult and risky to implement hydraulic fracturing. In this paper, the fractured well was taken for a case study to illustrate the holistic optimization to guarantee the treatment success, a world-wide difficulty with high engineering risk. For figuring out a reasonable treatment design, comprehensive lab experiments and numerical simulation were conducted to analyze and benchmark the reservoir characteristics, rock mechanics and geological model. Systematic study on reducing breakdown pressure, development of natural fractures evaluation, multi-size combination of diverting agent, separated layer stimulation and fracture parameters optimization, treatment fluid formulation, proppant screening and operation program were carried out. Considering the wellbore trajectory and rock mechanics characteristics of well K1002, a breakdown pressure prediction model was established to optimize the perforation orientation. The best perforation orientation was 28° and 208°, the worst perforation orientation was 148° and 328°, and the breakdown pressure range was 168-175MPa with 60° phase angle. Combination with "imaging logging (0-3m) + far detection acoustic logging (0-30m) + geomechanics (0-300m)", the comprehensive evaluation and prediction of natural fractures in near wellbore area and far wellbore area were realized. Based on this, the stimulation technology of "mechanical layering + diverting agent" was optimized to connect the fracture development zone in near wellbore and far wellbore area. According to the Tight Packing Theory, the idea of "multi-size particles combination of diverting agent" was put forward. Through the experiment study, the combination of 1-5mm and 5-10mm particles was optimized, and the optimal chart of diverting agent size combination was made under different reservoir temperatures. For the fracturing job, totally 2562m3 KCL weighted fracturing fluid and 159.2m3 ceramic proppant of 40-70 mesh were pumped. The operation parameters were in reasonable agreement with the design. The initial test production was 10 times higher than before. The experience gained in this case study has some guiding significance for improving the success rate of hydraulic fracturing treatments in the highly deviated ultra-deep well and for effectively developing such fractured tight sandstone reservoirs, both theoretically and practically.

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