We investigate by means of numerical simulation a planned year-long field test of depressurization-induced production from a permafrost-associated hydrate reservoir on the Alaska North Slope at the site of the recently-drilled Hydrate-01 Stratigraphic Test Well. The main objective of this study is to assess quantitatively the impact of temporary interruptions (well shutins) on the expected fluid production performance from the B1 Sand of the stratigraphic Unit B during controlled depressurization over different time scales, as well as on other relevant aspects of the system response that have the potential to significantly affect the design of the field test.We consider eight different cases of depressurization, including (a) rapid depressurization over a 60-day period to a terminal bottomhole pressure PW of 2.8 MPa and (b) a slower depressurization rate to a final PW of 0.6 MPa at the end of the year-long production test, in addition to (c) a multi-step depressurization regime and (d) a quasi-linear continuous depressurization strategy. The results of the study indicate that shut-ins obviously reduce gas release and production during and immediately after their occurrence, but their longer-term effects are strongly dependent on the depressurization regime and on the time of observation, covering the entire range of potential outcomes. Shut-ins (a) have a universally strong negative effect when quasi-linear depressurization is involved regardless of the length of the production period, (b) have a strong positive effect in multi-step depressurization schemes that becomes apparent earlier for large initial pressure drops, but (c) can also appear to have practically no effect for slow step-wise depressurization at the end of the year-long production test.Shut-ins lead to a rapid reformation of hydrates, even to the point of disappearance of a free gas phase in the reservoir. Rapid depressurization regimes lead to early maximum rates of hydrate dissociation and gas production, while the maximum rates occur at the end of the production test for the cases of slower depressurization. Shut-ins do not appear to have a significant impact on water production, as the cessation of production is followed by higher rates production when depressurization resumes. Similarly, (a) the fraction of produced CH4 originating from exsolution from the water, (b) the water-to-gas ratio, and (c) the rate of replenishment of produced water by boundary inflows do not appear significantly affected by shut-ins, the effects of which seem to be temporary in the majority of the cases. The study confirmed the superiority of multi-step depressurization methods as the most effective strategies for hydrate dissociation and gas production, and showed that two observation wells (located at distances of 30 m and 50 m from the production well) are appropriately positioned and both able to capture the P, T and SG behavior during the fluid production and shut-ins in any of the eight cases we investigated. over different time scales, as well as on other rel...
Summary Significant conductivity losses of both propped hydraulic fractures and unpropped natural fractures are widely observed by laboratory experiments and field studies in shale-gas reservoirs. Previous studies have not well-considered the effects of dynamic fracture properties, which limit the accurate prediction of well performance and stress evolution. In this study, an efficient coupled flow and geomechanics model is proposed to characterize the dynamic fracture properties and examine their effects on well performance and stress evolution in complex fractured shale-gas reservoirs. In our proposed model, a unified compositional model with nonlinear transport mechanisms is used to accurately describe multiphase flow in shale formations. The embedded discrete fracture model (EDFM) is used to explicitly model the complex fracture networks. Different fracture constitutive models are implemented to describe the dynamic properties of hydraulic fractures and natural fractures, respectively. The finite-volume method (FVM) and finite-element method (FEM) are used for the space discretization of flow and geomechanics equations, respectively, and the coupled problem is solved by the fixed-stress split iterative method. The coupled model is validated against classical analytical solutions. After that, the proposed model is used to investigate the effects of hydraulic-fracture and natural-fracture properties on production behavior as well as pressure and stress evolution of shale-gas reservoirs. With the dynamic fracture properties incorporated, our model can predict the well production more accurately, and provide more realistic stress evolution that is essential for the design and optimization of refracturing and infill-well drilling.
Summary Unconventional tight reservoirs that are typically characterized by low permeability and low porosity have contributed significantly to the global hydrocarbon production in recent years. Although hydraulic fracturing, along with horizontal well drilling, enables the economic development of such reservoirs, the production rate often declines sharply and results in low primary hydrocarbon recovery. The application of enhanced-oil-recovery (EOR) techniques in tight reservoirs has received much interest. In this study, the feasibility and efficiency of interfracture water injection to enhance oil recovery in multistage fractured tight oil reservoirs are analyzed through an efficient coupled flow/geomechanics model with an embedded discrete-fracture model (EDFM). A combined finite-volume/finite-element scheme is used to discretize the governing equations for flow and geomechanics, and the coupled problem is solved sequentially using a fixed-stress splitting algorithm. A basic numerical model consisting of a 15-stage fractured horizontal well is constructed using the petrophysical and geomechanical properties of a tight oil formation in Ordos Basin, China. Fractures indexed with even numbers are switched into injecting fractures when the production rate has dropped to less than a certain threshold. The improvement of oil recovery is analyzed by comparing the production profiles with and without water injection. In this coupled model, the fracture closure/opening during production/injection is considered according to the constitutive relations between fracture aperture and effective normal stress acting on the fracture faces. The poromechanical response of matrix is modeled by the Biot (1941) theory. The effects of fracture spacing, injection rate, and the presence of a natural-fracture network on oil-recovery enhancement are discussed through sensitivity analysis. The main mechanisms of interfracture water injection for enhancing oil recovery are waterflooding and reservoir-pressure maintenance. Small fracture spacing tends to reduce the oil recovery because of fracture interference and a limited drainage area; therefore, the primary depletion stage is shortened as the fracture spacing is reduced. The influence of interfracture water injection is more pronounced with smaller fracture spacing because the pressure-transient responses near the producing fractures are more dramatic considering the close proximity between the injecting fracture and the producing fracture. Although a higher injection rate results in higher oil recovery, the injectivity in low-permeability reservoirs limits the maximum-allowable injection rate. When secondary (natural)-fracture networks are considered, neighboring hydraulic fractures can be connected to one another via the secondary fractures, particularly if the interfracture spacing is small. Water can break through in the producing fractures quickly, which could also lead to high water cut and suboptimal oil-recovery performance. This study tests the feasibility and efficiency of interfracture injection to enhance tight oil recovery. The results indicate that interfracture injection can be a promising EOR technique for tight oil reservoirs, which sheds lights on future completion strategies and production design in tight reservoirs.
Many stimulated shale gas wells experience surprisingly low fracturing fluid recoveries. Fracture closure, gravity segregation, fracture tortuosity, proppant distribution, and shut-in (soaking) time have been widely postulated to be the contributing factors. This study examines the impacts of these factors on fracturing fluid distribution using flow and geomechanical simulations. The results are analyzed to understand the circumstances under which fluid recovery might be beneficial or detrimental to well performance. A series of 3D numerical models are constructed based on petrophysical parameters, fluid properties and operational constraints representative of Horn River shale gas reservoir. Hydraulic fracture is modeled explicitly in the computational domain. Complex partially-propped fracture geometry is computed using numerical constitutive models. The physical process of fracture closure during shut-in and production periods is modeled by adjusting the fracture volume and fracture conductivity dynamically. Non-Darcy behavior due to high gas velocity in fracture and matrix desorption are considered. The coupled effect of multi-phase flow, gravity and geomechanics is simulated to examine the mechanisms responsible for the low fracturing fluid recovery and the ensuing fluid distribution away from the wellbore. Water uptake into the matrix is influenced by forced and spontaneous imbibition due to the large pressure differential across the matrix-fracture interface and matrix capillarity. Additional water is displaced into the matrix as pressure depletes and fracture closes. Gravity segregation may lead to water accumulating near the bottom of a vertical planar fracture, but fracture tortuosity could limit the segregation and promote a more uniform fluid distribution. The influence of proppant distribution is far more complex: results of the geomechanical simulation confirm the formation of a residual opening above of the proppant pack in a partially-propped fracture. Despite gas production is often hampered by non-uniform proppant distribution, the residual opening offers a highly conductive flow path for gas, which is much more mobile than the water-based fracturing fluid; this further aggravates the phenomenon of gravity segregation. Extended shut-in time may enhance the initial gas rate, but lower late-time production is observed. Analysis of the residual opening of a partially-propped fracture and its implications on production performance is novel. The results highlight the interactions between different mechanisms on fracturing fluid distribution in 3D. A few practical insights pertinent to the optimal operation strategy are explained.
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