scholarly journals Shallow Aquifer Vulnerability From Subsurface Fluid Injection at a Proposed Shale Gas Hydraulic Fracturing Site

2017 ◽  
Vol 53 (11) ◽  
pp. 9922-9940 ◽  
Author(s):  
M. P. Wilson ◽  
F. Worrall ◽  
R. J. Davies ◽  
A. Hart
Keyword(s):  
Hydraulic Fracturing ◽  
Shale Gas ◽  
Aquifer Vulnerability ◽  
Shallow Aquifer ◽  
Fluid Injection ◽  
Subsurface Fluid

scholarly journals Real‐Time Imaging, Forecasting, and Management of Human‐Induced Seismicity at Preston New Road, Lancashire, England

2019 ◽  
Author(s):  
Huw Clarke ◽  
James P. Verdon ◽  
Tom Kettlety ◽  
Alan F. Baird ◽  
J‐Michael Kendall
Keyword(s):  
Hydraulic Fracturing ◽  
Real Time ◽  
Shale Gas ◽  
Statistical Models ◽  
Induced Seismicity ◽  
Red Light ◽  
Fracture Network ◽  
Fluid Injection ◽  
Traffic Light ◽  
Subsurface Fluid

ABSTRACTEarthquakes induced by subsurface fluid injection pose a significant issue across a range of industries. Debate continues as to the most effective methods to mitigate the resulting seismic hazard. Observations of induced seismicity indicate that the rate of seismicity scales with the injection volume and that events follow the Gutenberg–Richter distribution. These two inferences permit us to populate statistical models of the seismicity and extrapolate them to make forecasts of the expected event magnitudes as injection continues. Here, we describe a shale gas site where this approach was used in real time to make operational decisions during hydraulic fracturing operations.Microseismic observations revealed the intersection between hydraulic fracturing and a pre‐existing fault or fracture network that became seismically active. Although “red light” events, requiring a pause to the injection program, occurred on several occasions, the observed event magnitudes fell within expected levels based on the extrapolated statistical models, and the levels of seismicity remained within acceptable limits as defined by the regulator. To date, induced seismicity has typically been regulated using retroactive traffic light schemes. This study shows that the use of high‐quality microseismic observations to populate statistical models that forecast expected event magnitudes can provide a more effective approach.

Fracture Initiation and Propagation in a Deep Shale Gas Reservoir Subject to an Alternating-Fluid-Injection Hydraulic-Fracturing Treatment

SPE Journal ◽  
2019 ◽  
Vol 24 (04) ◽  
pp. 1839-1855 ◽  
Author(s):  
Bing Hou ◽  
Zhi Chang ◽  
Weineng Fu ◽  
Yeerfulati Muhadasi ◽  
Mian Chen
Keyword(s):  
Hydraulic Fracturing ◽  
Shale Gas ◽  
Fracture Initiation ◽  
Fluid Injection ◽  
Hydraulic Fractures ◽  
Stress Difference ◽  
Gas Reservoirs ◽  
Complex Fracture ◽  
Initiation And Propagation

Summary Deep shale gas reservoirs are characterized by high in-situ stresses, a high horizontal-stress difference (12 MPa), development of bedding seams and natural fractures, and stronger plasticity than shallow shale. All of these factors hinder the extension of hydraulic fractures and the formation of complex fracture networks. Conventional hydraulic-fracturing techniques (that use a single fluid, such as guar fluid or slickwater) do not account for the initiation and propagation of primary fractures and the formation of secondary fractures induced by the primary fractures. For this reason, we proposed an alternating-fluid-injection hydraulic-fracturing treatment. True triaxial hydraulic-fracturing tests were conducted on shale outcrop specimens excavated from the Shallow Silurian Longmaxi Formation to study the initiation and propagation of hydraulic fractures while the specimens were subjected to an alternating fluid injection with guar fluid and slickwater. The initiation and propagation of fractures in the specimens were monitored using an acoustic-emission (AE) system connected to a visual display. The results revealed that the guar fluid and slickwater each played a different role in hydraulic fracturing. At a high in-situ stress difference, the guar fluid tended to open the transverse fractures, whereas the slickwater tended to activate the bedding planes as a result of the temporary blocking effect of the guar fluid. On the basis of the development of fractures around the initiation point, the initiation patterns were classified into three categories: (1) transverse-fracture initiation, (2) bedding-seam initiation, and (3) natural-fracture initiation. Each of these fracture-initiation patterns had a different propagation mode. The alternating-fluid-injection treatment exploited the advantages of the two fracturing fluids to form a large complex fracture network in deep shale gas reservoirs; therefore, we concluded that this method is an efficient way to enhance the stimulated reservoir volume compared with conventional hydraulic-fracturing technologies.

Use of Mathematical Model to Predict the Maximum Permissible Stage Injection Time for Mitigating Frac-Driven Interactions in Hydraulic-Fracturing Shale Gas/Oil Wells

2020 ◽  
Vol 143 (8) ◽  
Author(s):  
Nan Zhang ◽  
Boyun Guo
Keyword(s):  
Hydraulic Fracturing ◽  
Analytical Model ◽  
Shale Gas ◽  
General Model ◽  
High Rate ◽  
Fluid Injection ◽  
Injection Time ◽  
Gas Oil ◽  
Fracturing Fluid ◽  
Multiple Fractures

Abstract Frac-driven interactions (FDIs) often lead to sharp decline in gas and oil production rates of wells in shale gas/oil reservoirs. How to minimize the FDI is an open problem in the oil and gas industry. Xiao et al.’s (2019, “An Analytical Model for Describing Sequential Initiation and Simultaneous Propagation of Multiple Fractures in Hydraulic Fracturing Shale Oil/Gas Formations,” Energy Sci Eng., 7(5), pp. 1514–1526.) analytical model for two-fracture systems was extended in this study to obtain a general model for handling multiple fractures. The general model was used to identify engineering factors affecting the maximum permissible stage fluid injection time for minimizing FDI. On the basis of model results obtained, we found that increasing fluid injection rate can create more short fractures and thus increase the maximum permissible stage injection time before FDI occurs. Use of dilatant type of fracturing fluid (n > 1) can reduce the growth of long fractures, promote the creation of more short fractures, and thus increase the maximum permissible stage injection time before FDI occurs. It is also expected that injecting dilatant type of fracturing fluid at high rate will allow for longer injection time and thus larger injection volume, resulting in larger stimulated reservoir volume (SRV) with higher fracture intensity and thus higher well productivity and hydrocarbon recovery factor.

Shale, Quakes, and High Stakes: Regulating Fracking-Induced Seismicity in Oklahoma, USA and Lancashire, UK

2019 ◽  
Vol 3 (1) ◽  
pp. 1-14
Author(s):  
Miriam R. Aczel ◽  
Karen E. Makuch
Keyword(s):  
United States ◽  
Hydraulic Fracturing ◽  
Shale Gas ◽  
Seismic Activity ◽  
Oil And Gas ◽  
Oil And Gas Industry ◽  
High Volume ◽  
The United States ◽  
Horizontal Drilling ◽  
Induced Seismic Activity

High-volume hydraulic fracturing combined with horizontal drilling has “revolutionized” the United States’ oil and gas industry by allowing extraction of previously inaccessible oil and gas trapped in shale rock [1]. Although the United States has extracted shale gas in different states for several decades, the United Kingdom is in the early stages of developing its domestic shale gas resources, in the hopes of replicating the United States’ commercial success with the technologies [2, 3]. However, the extraction of shale gas using hydraulic fracturing and horizontal drilling poses potential risks to the environment and natural resources, human health, and communities and local livelihoods. Risks include contamination of water resources, air pollution, and induced seismic activity near shale gas operation sites. This paper examines the regulation of potential induced seismic activity in Oklahoma, USA, and Lancashire, UK, and concludes with recommendations for strengthening these protections.

Simulation of proppant transport and fracture plugging in the framework of a radial hydraulic fracturing model

2020 ◽  
Vol 35 (6) ◽  
pp. 325-339
Author(s):  
Vasily N. Lapin ◽  
Denis V. Esipov
Keyword(s):  
Numerical Model ◽  
Hydraulic Fracturing ◽  
Oil And Gas ◽  
Oil And Gas Industry ◽  
Injection Rate ◽  
Fluid Injection ◽  
Subtraction Technique ◽  
Gas Industry ◽  
Proppant Transport ◽  
Hydraulic Fracture Propagation

AbstractHydraulic fracturing technology is widely used in the oil and gas industry. A part of the technology consists in injecting a mixture of proppant and fluid into the fracture. Proppant significantly increases the viscosity of the injected mixture and can cause plugging of the fracture. In this paper we propose a numerical model of hydraulic fracture propagation within the framework of the radial geometry taking into account the proppant transport and possible plugging. The finite difference method and the singularity subtraction technique near the fracture tip are used in the numerical model. Based on the simulation results it was found that depending on the parameters of the rock, fluid, and fluid injection rate, the plugging can be caused by two reasons. A parameter was introduced to separate these two cases. If this parameter is large enough, then the plugging occurs due to reaching the maximum possible concentration of proppant far from the fracture tip. If its value is small, then the plugging is caused by the proppant reaching a narrow part of the fracture near its tip. The numerical experiments give an estimate of the radius of the filled with proppant part of the fracture for various injection rates and leakages into the rock.

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