Influence of Fluid Viscosity on the Hydraulic Fracturing Mechanism

Ishida, Tsuyoshi; Qu, Chao; Mizuta, Yoshiaki; Roegiers, J.-C.

doi:10.1115/1.1791651

Cited by 142 publications

(78 citation statements)

References 18 publications

Supporting

Mentioning

Contrasting

Unclassified

Order By: Relevance

“…Another possible reason for CO 2 having the highest breakdown pressure followed by N 2 and then H 2 O could be stress corrosion (Anderson and Grew 1977). In this case, time- Ishida et al (2004Ishida et al ( , 2012. This viscosity dependent behavior can be explained through the fluid loss equation, which indicates that a fracturing fluid with high viscosity results in a low rate of fluid-loss.…”

Section: Discussionmentioning

confidence: 87%

Breakdown pressure and fracture surface morphology of hydraulic fracturing in shale with H 2 O, CO 2 and N 2

Feng

Han

et al. 2016

Geomech. Geophys. Geo-energ. Geo-resour.

125

View full text Add to dashboard Cite

Slick-water fracturing is the most routine form of well stimulation in shales; however N 2 , LPG and CO 2 have all been used as ''exotic'' stimulants in various hydrocarbon reservoirs. We explore the use of these gases as stimulants on Green River shale to compare the form and behavior of fractures in shale driven by different gas compositions and states and indexed by breakdown pressure and the resulting morphology of the fracture networks. Fracturing is completed on cylindrical samples containing a single blind axial borehole under simple triaxial conditions with confining pressure ranging from 10 to 25 MPa and axial stress ranging from 0 to 35 MPa (r 1 [ r 2 = r 3 ). Results show that: (1) under the same stress conditions, CO 2 returns the highest breakdown pressure, followed by N 2 , and with H 2 O exhibiting the lowest breakdown pressure; (2) CO 2 fracturing, compared to other fracturing fluids, creates nominally the most complex fracturing patterns as well as the roughest fracture surface and with the greatest apparent local damage followed by H 2 O and then N 2 ; (3) under conditions of constant injection rate, the CO 2 pressure build-up record exhibits condensation between *5 and 7 MPa and transits from gas to liquid through a mixed-phase region rather than directly to liquid as for H 2 O and N 2 which do not; (4) there is a positive correlation between minimum principal stress and breakdown pressure for failure both by transverse fracturing (r 3 axial) and by longitudinal fracturing (r 3 radial) for each fracturing fluid with CO 2 having the highest correlation coefficient/slope and lowest for H 2 O. We explain these results in terms of a mechanistic understanding of breakdown, and through correlations with the specific properties of the stimulating fluids.

show abstract

Section: Discussionmentioning

confidence: 87%

Breakdown pressure and fracture surface morphology of hydraulic fracturing in shale with H 2 O, CO 2 and N 2

Feng

Han

et al. 2016

Geomech. Geophys. Geo-energ. Geo-resour.

125

View full text Add to dashboard Cite

show abstract

“…Ishida et al [51] carried out hydraulic fracturing experiment using injection fluid of different viscosities in laboratory and their study shows that the viscosity of the fracturing fluid has an influence on the mechanism of crack generation, crack initial pressure and breakdown pressure. Chen et al [52] also investigated how the viscosity of the fracturing fluid affects fracture propagation using three different viscosities (viscous oil, water, and supercritical CO 2 ), and the results show that hydraulic fracturing with low viscosity fluids form a more complex fracture network in rocks.…”

Section: The Influence Of Fluid Viscositymentioning

confidence: 99%

Numerical Modeling and Investigation of Fluid-Driven Fracture Propagation in Reservoirs Based on a Modified Fluid-Mechanically Coupled Model in Two-Dimensional Particle Flow Code

et al. 2016

View full text Add to dashboard Cite

Hydraulic fracturing is a useful tool for enhancing rock mass permeability for shale gas development, enhanced geothermal systems, and geological carbon sequestration by the high-pressure injection of a fracturing fluid into tight reservoir rocks. Although significant advances have been made in hydraulic fracturing theory, experiments, and numerical modeling, when it comes to the complexity of geological conditions knowledge is still limited. Mechanisms of fluid injection-induced fracture initiation and propagation should be better understood to take full advantage of hydraulic fracturing. This paper presents the development and application of discrete particle modeling based on two-dimensional particle flow code (PFC 2D ). Firstly, it is shown that the modeled value of the breakdown pressure for the hydraulic fracturing process is approximately equal to analytically calculated values under varied in situ stress conditions. Furthermore, a series of simulations for hydraulic fracturing in competent rock was performed to examine the influence of the in situ stress ratio, fluid injection rate, and fluid viscosity on the borehole pressure history, the geometry of hydraulic fractures, and the pore-pressure field, respectively. It was found that the hydraulic fractures in an isotropic medium always propagate parallel to the orientation of the maximum principal stress. When a high fluid injection rate is used, higher breakdown pressure is needed for fracture propagation and complex geometries of fractures can develop. When a low viscosity fluid is used, fluid can more easily penetrate from the borehole into the surrounding rock, which causes a reduction of the effective stress and leads to a lower breakdown pressure. Moreover, the geometry of the fractures is not particularly sensitive to the fluid viscosity in the approximate isotropic model.

show abstract

“…Hydraulic fracturing behavior of different granites has been reported by Haimson (1975Haimson ( , 1999, Haimson and Lee (1980), Solberg et al (1980), Haimson and Doe (1983), Haimson and Zhao (1991), Zhao et al (1996), Ishida et al (1997Ishida et al ( , 2000Ishida et al ( , 2004Ishida et al ( , 2012 and Chen et al (2015). However, in these studies granites were mainly treated as low-permeability rocks and the influence of infiltration of injection fluid has rarely been discussed.…”

Section: Introductionmentioning

confidence: 98%

Effect of Water Infiltration, Injection Rate and Anisotropy on Hydraulic Fracturing Behavior of Granite

et al. 2018

View full text Add to dashboard Cite

Hydraulic fracturing tests on Pocheon granite cylinders at seven different injection rates varying from 1 to 100 mm 3 /s were conducted. They were compared with sleeve fracturing tests in which borehole was sleeved, and therefore, water infiltration influence was excluded. Hydraulic fracturing behavior of granite is significantly influenced by water infiltration, which is closely related to the preexisting microcracks in granite as well as the cleavage anisotropy. There was a threshold injection rate to fracture the granite specimen under given stress conditions. When the injection rate is below the threshold, water infiltrated granite matrix with slow increment of injection pressure, and the specimen finally reached a full saturation without fracturing. Injection pressure developed nonlinearly with time during water infiltration, while approximately linearly when infiltration was excluded. For both hydraulic and sleeve fracturing tests, breakdown pressure increases with increasing injection rate. The breakdown pressures by sleeve fracturing were more than two times higher than those in hydraulic fracturing. X-ray computed tomography (CT) observations show that induced fractures are along the weaker cleavage parallel to the direction of the vertical stress. The higher breakdown pressure results in a larger aperture of fractures in hydraulic fracturing tests.

show abstract

Influence of Fluid Viscosity on the Hydraulic Fracturing Mechanism

Cited by 142 publications

References 18 publications

Breakdown pressure and fracture surface morphology of hydraulic fracturing in shale with H 2 O, CO 2 and N 2

Breakdown pressure and fracture surface morphology of hydraulic fracturing in shale with H 2 O, CO 2 and N 2

Numerical Modeling and Investigation of Fluid-Driven Fracture Propagation in Reservoirs Based on a Modified Fluid-Mechanically Coupled Model in Two-Dimensional Particle Flow Code

Effect of Water Infiltration, Injection Rate and Anisotropy on Hydraulic Fracturing Behavior of Granite

Contact Info

Product

Resources

About