Propagation, Proppant Transport, and the Evolution of Transport Properties of Fluid-Driven Fractures
Open Access
- Author:
- Wang, Jiehao
- Graduate Program:
- Energy and Mineral Engineering
- Degree:
- Doctor of Philosophy
- Document Type:
- Dissertation
- Date of Defense:
- December 06, 2019
- Committee Members:
- Derek Elsworth, Dissertation Advisor/Co-Advisor
Derek Elsworth, Committee Chair/Co-Chair
Shimin Liu, Committee Member
Arash Dahi Taleghani, Committee Member
Li Li, Outside Member
Mort D Webster, Program Head/Chair - Keywords:
- Hydraulic fracturing
Proppant transport
Fracture conductivity
Natural fracture
Gas fracturing
Dynamic gas fracturing - Abstract:
- Hydraulic fracturing is one of the most effective and widely-used methods to stimulate production from unconventional oil and gas reservoirs exhibiting micro- and nano-Darcy native permeability. This requires the pumping of highly-pressurized fluids (e.g., slickwater, gases, and foam-based fluids) into an isolated portion of a well to initiate and propagate a fracture through the formation. The volume of the propagating fracture exactly balances the input of the fracturing fluid with the (i) advance of the fracture tip, (ii) its concurrent inflation, and (iii) leak-off into the formation where natural fractures may exist at a variety of length-scales. At some point, a proppant pad is introduced in the pumping and fracture-driving sequence to prop open the fractures for when pumping ultimately stops, and fractures deflate under the in situ stress. Permeability, or fluid conductivity, of the hydraulic fracture is a crucial parameter to determine the ensuing fluid production rate. It is principally conditioned by fracture geometry and the distribution of the encased proppant, which is in turn regulated by operational parameters as well as the properties of formation, pre-existing natural fractures, fracturing fluid and proppant. Part I of this thesis (Chapters 1-3) develops deformation-transport-closure models to investigate the dependence of fracture geometry and proppant distribution on various input parameters and the conductivity evolution of fully/partially proppant-filled hydraulic fractures. Part II (Chapters 4-6) examines the performance of various gases as an alternative to water-based fracturing fluids, with both quasi-static and dynamic loadings, in terms of fracture-inducing potential, proppant-carrying capacity, breakdown pressure, and fracture complexity. Chapter 1 introduces a numerical model to describe proppant transport within a propagating blade-shaped fracture towards defining the fracture conductivity and reservoir production after fracture closure. Fracture propagation is formulated based on the PKN-formalism coupled with advective transport of an equivalent slurry representing a proppant-laden fluid. Empirical constitutive relations are incorporated to define rheology of the slurry, proppant transport with bulk slurry flow, proppant gravitational settling, and finally, the transition from Poiseuille (fracture) flow to Darcy (proppant pack) flow. At the maximum extent of the fluid-driven fracture, as driving pressure is released, the fracture closure model developed in Chapter 2 is employed to follow the evolution of fracture conductivity with the decreasing fluid pressure. This model is capable of accommodating the mechanical response of the proppant pack, fracture closure of potentially contacting rough surfaces, proppant embedment into fracture walls, and, most importantly, flexural displacement of the unsupported spans of the fracture. Results show that reduced fluid viscosity increases the length of the resulting fracture, while rapid leak-off decreases it, with both characteristics minimizing fracture width over converse conditions. Proppant density and size do not significantly influence fracture propagation. Proppant settling ensues throughout fracture advance and is accelerated by a lower viscosity fluid or greater proppant density or size, resulting in the accumulation of a proppant bed at the fracture base. "Screen-out" of proppant at the fracture tip can occur where fracture aperture is only several times the diameter of the individual proppant particles. After fracture closure, proppant packs comprising larger particles exhibit higher conductivity. More importantly, high-conductivity flow channels are necessarily formed around proppant banks due to the flexural displacement of the fracture walls, which offer preferential flow pathways and significantly influence the distribution of fluid transport. Higher compacting stresses are observed around the edge of proppant banks, resulting in greater depths of proppant embedment into the fracture walls and/or increased potential for proppant crushing. Unconventional oil and gas formations often contain natural fractures which are fluid-pressure sensitive and dilate in response to the inflation of the hydraulic fracture, increasing fluid loss and slowing down and potentially prematurely arresting fracture propagation. The hydraulic fracturing model introduced in Chapter 1 assumes 1-D single-porosity/permeability (Carter) leakoff perpendicular to the hydraulic fracture. However, the leakoff process in naturally fractured formations is considerably more complicated. Chapter 3 extends the model to accommodate leakoff into a pressure-sensitive dual porosity medium. The model is capable of providing a rapid estimation of the morphology of hydraulic fractures in naturally fractured formations and the corresponding proppant distribution. The simulation results illustrate that the leakoff into a dual porosity medium, where fracture permeability is a strong function of applied fluid pressure, results in a reduced length of the propagating fracture due to the fugitive fluid leakoff from the fracture into the surrounding formation and that this, in turn, results in a reduced maximum width during the treatment. The ability to infuse proppants in fluid-driven fractures penetrating large distances from the injection wellbore is further limited by premature screen-out. This may compromise the ultimate efficiency of the final hydraulic fracture regarding gas recovery. Reduced propagation and premature screen-out are limited by low permeability and large spacing of the natural fractures. The presence of an existing network of natural fractures, including those adjacent to the hydraulic fracture that may become propped, aids in the recovery of the resource by reducing diffusion lengths of the hydrocarbon to the main fracture. Gases show promise as an alternative to water-based fracturing fluids because they are non-damaging to water-sensitive formations, show some potential to create complex fracture networks, flow back to the well rapidly after treatment, and deliver some environmental benefits (e.g. conservation of water as a resource, reduction of induced earthquakes, and sequestration of greenhouse gases underground). However, the ability of gases to transport proppant has been questioned due their relatively low viscosity and density. In Chapter 4, the fracturing then proppant-carrying capacity of various gases is investigated to determine the form and function of the emplaced proppant pack. First, fracture propagation and proppant transport driven by several commonly-used pure gases (CO2, LPG, ethane, and N2) is simulated and compared against common slickwater fracturing – generally identifying inferior reach and functionality. Several methods are then investigated to improve the proppant-carrying capacity of the pure gases, including the use of gelled gases, foam-systems, and ultra-light-weight proppants. Results show that, compared with slickwater, gases create shorter and narrower fractures and carry proppant shorter distances from the well due to their lower viscosity and faster leak-off. Among the gases examined in this study, LPG and CO2 return the deepest proppant penetration along the fracture, followed by ethane, and with N2 unable to carry proppant into the fracture due to the resulting narrow fracture. However, gases might be injected at higher rates than slickwater during operation due to the lower frictional loss, which could elevate the proppant-transport capability of gases and the resulting hydrocarbon production rate to a level competitive with that of slickwater. Gas viscosity may be enhanced by creating a gelled or foam-based system. A near-uniform proppant distribution may be achieved by using a gelled gas, with an approximately two order-of-magnitude enhancement in viscosity, or a foam-based fluid with a high quality. The fracture length may also be extended by limiting leak-off due to the increased viscosity. Moreover, due to decelerated proppant settling, ultra-light-weight proppants (ULWPs) also perform better with gases than the commonly-used sands in terms of proppant vertical coverage and horizontal penetration downrange along the propagating fracture. Reservoir simulations show significant improvement in well performance by fracturing with gelled gases or foams instead of pure gases or by pumping ULWPs instead of normal sands. Among them, the low-quality foam returns the highest production rate, while the ULWP returns the lowest. This is possibly because a long fracture, even one with a relatively low conductivity, is more productive for the ultra-low-permeability reservoir than a short fracture with high conductivity. Experimental observations have shown that different fracturing fluids yield variations in the induced fracture. During the hydraulic fracturing process, fracturing fluids will penetrate the borehole wall, and the evolution of the fracture(s) then results from the coupled phenomena of fluid flow, solid deformation and damage. To represent this, Chapter 5 presents coupled models of rock damage mechanics and fluid flow for both slightly compressible fluids and CO2. We investigate the fracturing processes driven by pressurization of three kinds of fluids: water, viscous oil, and supercritical CO2. Simulation results indicate that SC-CO2-based fracturing indeed has a lower breakdown pressure, as observed in experiments, and may develop fractures with greater complexity than those developed with water-based and oil-based fracturing. We explore the relation between the breakdown pressure to both the dynamic viscosity and the interfacial tension of the fracturing fluids. Modeling demonstrates an increase in the breakdown pressure with both an increase in the dynamic viscosity and in the interfacial tension, consistent with experimental observations. Chapter 6 examines the reach and geometry of multiple fractures driven by dynamic gas pressure (e.g., high energy gas fracturing and high-pressure gas blasting/fracturing). This dynamic loading exhibits rise-times and peak pressures intermediate between conventional hydraulic fracturing and explosive fracturing. Two consecutive stages are involved during this process: (i) generation and propagation of a dynamic stress wave driven by rapid rise of gas pressure creating multiple radial fractures around borehole, followed by (ii) quasi-static pressurization and further extension of those starter-fractures by the expanding gas. A dynamic analysis is first performed to follow the evolution of the stress wave emitted from the borehole. Results show that tensile tangential peak stress attenuates as a power function of the reciprocal of radial distance in the vicinity of the borehole with an increasing power exponent as the pressure-rise time increases. This rapid attenuation generally limits the length of the body-wave-generated radial cracks to several radii of the borehole. Short rise-times accompany initial compressive tangential stress counter the creation of multiple fractures. Stability analysis of the pressurized borehole with body-wave-generated radial fractures follows the high-pressure gas penetration into the fractures. The fracture system transits from a non-uniform growth regime to a uniform growth regime with up to six dominant fractures and finally back to a non-uniform growth regime again. This restricts the maximum number of the dominant fractures to six at the conclusion of the treatment - a common observation in both in situ and laboratory experiments. The chapters of this thesis correspond with a series of six papers, either published or in-submittal. By order of chapter appearance, these papers are: Wang, J., Elsworth, D., Denison, M. (2018) Propagation, Proppant Transport and the Evolution of Transport Properties of Hydraulic Fractures. Journal of Fluid Mechanics, 855, 503-534. Wang, J., Elsworth, D. (2018) Role of Proppant Distribution on the Evolution of Hydraulic Fracture Conductivity. Journal of Petroleum Science and Engineering, 166, 249-262. Wang, J., Elsworth, D., Denison, M. (2018) Hydraulic Fracturing with Leakoff in a Pressure-Sensitive Dual Porosity Medium. International Journal of Rock Mechanics and Mining Sciences, 107, 55-68. Wang, J., Elsworth, D. (2019) Fracture Penetration and Proppant Transport in Gas- and Foam-Fracturing. Manuscript submitted: Applied Energy. Wang, J., Elsworth, D., Wu, Y., Liu, J., Zhu, W., Liu, Y. (2018) The Influence of Fracturing Fluids on Fracturing Processes: a Comparison between Water, Oil and SC-CO2. Rock Mechanics and Rock Engineering, 51(1), 299-313. Wang, J., Elsworth, D., Cao, Y., Liu, S. (2019) Reach and Geometry of Dynamic Gas-Driven Fractures. Manuscript submitted: International Journal of Rock Mechanics and Mining Sciences.