Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
Proppant Transport and Settling in a Narrow Vertical Wedge-Shaped Fracture.
Fernández, M. E. (Universidad Tecnológica Nacional) | Baldini, M. (Universidad Tecnológica Nacional) | Pugnaloni, L. A. (Universidad Tecnológica Nacional) | Sánchez, M. (YPF Tecnología SA) | Guzzetti, A. R. (YPF Tecnología SA) | Carlevaro, C. M. (Inst. Fisica de Liquidos y Sist. Biológicos)
Abstract An appropriate propped fracture is important for oil and gas production (especially in shale formations). The actual proppant placement during fracturing is generally unknown. Any fair prediction of the placement of the proppant may results in significant improvements for the fracture protocol design. We present experimental data on the transport and settling of particles dragged by water through a narrow wedge-shaped vertical fracture. We discuss some basic features of the dynamics of the settlement of the proppant dune and show results on the final placement for different pumping rates and particle sizes. Results are consistent with previous findings by others and confirm that some usual practices in the field are beneficial to maximize the propped volume and minimize arching. 1. INTRODUCTION In recent years, many oil companies have directed their efforts towards developing unconventional reservoirs. The challenges encountered to guarantee a profitable operation in these plays lead the industry to devote significant amounts resources to optimize processes such as hydraulic fracturing, a vital stimulation technique. Hydraulic fracturing consist in the injection of fluids, along with proppants, into the formation aimed at creating and/or enhancing existing fractures to open high conductivity channels connecting the formation and the wellbore [1]. Proppants are granular materials that fill the fracture and support the closing pressure, keeping the fracture conductive during production. Although fracturing techniques have evolved, there is still opportunities to increase efficiency. Many of these opportunities are related with the way in which proppants are transported and deposited into the fracture.
- South America > Argentina (0.30)
- North America > United States (0.28)
Conductivity Evaluation of Cross Propped Fractures in Shale Reservoirs
Ma, L. (State Key Laboratory of Oil & Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Lu, C. (State Key Laboratory of Oil & Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Guo, J. C. (State Key Laboratory of Oil & Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Li, X. Y. (State Key Laboratory of Oil & Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Luo, Y. (State Key Laboratory of Oil & Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Wang, K. J. (Sinopec Southwest Petroleum Engineering Co. Ltd, Chengdu)
ABSTRACT: Volume fracturing is a key technology for shale gas development. It connects hydraulic fractures and natural fractures to form a large-scale cross propped fracture network. The conductivity of cross propped fractures is the key to the effect of shale volume fracturing. Based on the Kozeny model, the conductivity of a single fracture is calculated, and the conductivity of the single fracture is corrected by experimental data, taking into account the effect of formation closure stress. Based on the similarity principle of hydropower, an evaluation model for the conductivity of cross propped fractures is proposed. On the basis of the numerical simulation results of proppant transportation, the factors affecting the conductivity of cross propped fractures are analyzed. The results show that the proppant falls at a low velocity into the narrow natural fracture, and then moves slowly forward in the form of a creep in the fracture, where it is transported for a short distance. For wide natural fractures, the proppant is suspended into the fracture at a greater velocity and transported over a longer distance, forming a "tall and long" proppant dune morphology. When the natural fracture width ratio increases, the proppant is placed more unevenly in the cross fractures, the seepage resistance of proppant dunes in hydraulic fractures gradually increases, the seepage resistance in natural fractures has no obvious change, the total seepage resistance of cross fracture is greater, and the conductivity of the fracture is smaller. The numerical calculation model is used to evaluate the conductivity of cross propped fractures, which provides theoretical guidance for the optimization of shale gas volume fracturing schemes. 1. INTRODUCTION As a kind of clean energy, Chinese shale gas will break through 2 × 10 m and 200 × 10 m respectively in proven geological reserves and total annual production in 2020. Increasing shale gas exploration and development under the "dual carbon" target is an important guarantee to ensure energy security and alleviate environmental problems (Long et al., 2021; Zhang et al., 2021). At present, the development of shale gas reservoirs at home and abroad usually adopts volume fracturing technology. Through the construction method of "fast injection velocity + large liquid volume + large sand volume", hydraulic fractures and natural fractures are connected, so as to realize the effective placement of proppant in the fractures, form large-scale cross propped fractures, and improves fluid seepage channels, thereby greatly increasing gas well productivity (Lu et al, 2019a; Lu et al., 2019b; Zhang, 2022).
- Asia > China (0.96)
- North America > United States (0.68)
- Research Report > New Finding (0.66)
- Research Report > Experimental Study (0.66)
Experimental and Visual Analysis of Proppant-Slickwater Flow in a Large-Scaled Rough Fracture
Qu, Hai (Chongqing University of Science and Technology) | Xu, Yang (Chongqing University of Science and Technology) | Hong, Jun (Chongqing University of Science and Technology) | Chen, Xiangjun (Chongqing University of Science and Technology) | Li, Chengying (Chongqing University of Science and Technology) | Liu, Xu (Chongqing University of Science and Technology)
Summary Understanding proppant transport and distribution in hydraulic fractures is crucial to designing and optimizing hydraulic fracturing treatments in the field. The actual fracture surfaces are typically rough and form a tortuous pathway, significantly affecting proppant migration. However, many rough models are very small in size, and some have only one rough surface. Thus, it is inadequate to display proppant transport behaviors and placement laws. This study proposed a novel method to develop large-scale rough panels reproduced from actual hydraulic fractures. A large transparent slot (2×0.3 m) was successfully constructed to simulate a shear fracture with 5 mm relative displacement of two matched surfaces. Six kinds of proppants were selected to study the effects of particle density and size. Four types of slickwater were prepared to achieve viscous diversity. A high-resolution particle image velocimetry (PIV) system detected the instantaneous velocity and vector fields in the rough pathway to understand particle transport behaviors. The specific parametric study includes a quantitative analysis of the proppant bed profile, equilibrium height, coverage area, injection pressure, and volumes of proppant settled in the slot and outlet tank. Also, five tests are carried out in the smooth slot, which has the same size as the rough slot. The test results demonstrate that the narrow rough fracture would significantly hinder particle transport, especially in the horizontal direction. The proppant bed is higher and closer to the inlet than that in the smooth model. Particles mixed with highly viscous slickwater easily aggregate in the two-sided rough model and gradually form finger-like regions at the lower part of the inlet. The unstable flow and vortices can disperse aggregated particles and avoid particle clogging. Proppants injected at the high volume fraction are prone to settle quickly and build up a higher bed contact with the inlet, leading to more considerable injection pressure. Perforation blockage often occurred in the rough model, and the near-wellbore screenout was induced as the bed blocked all perforations. Enhancing the fluid carrying capacity and using smaller proppant help avoid perforation blockage and improve far-field fracture conductivity. Two correlations were developed to predict the equilibrium height and coverage area of the proppant bed. The experimental results and laws provide novel understandings that can help optimize hydraulic fracturing design and treatment by rationally selecting proppant and fracturing fluid to improve the productivity in tight reservoirs.
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.48)
Abstract A model for the velocity of proppant particles in slot flow is presented. The proppant is either retarded or accelerated relative to the fluid depending on the ratio of the proppant size to the fracture width. It has been found that when this ratio is small, the proppant travels faster than the average fluid velocity at that location because the proppant tends to be confined to the center of the flow channel where the fluid velocity is higher. As the proppant size increases, the effect of the fracture walls becomes more important and the proppant is retarded by the walls. The retardation of particle relative to the fluid is greater for larger particles and greater proximities to the fracture walls due to the hydrodynamic stress exerted on the sphere by the walls in the narrow gap. A higher proppant concentration restricts the area available to flow and increases the drag forces on the particles. A model is presented for the effect of fracture walls and proppant concentration on proppant transport. The effect of this increased drag force is accounted for by modifying the wall - particle interaction. The influence of the surrounding proppant spheres on the drag force on a particle is estimated from the effect of a wall on the drag force acting on a single particle. The equivalent hydraulic diameter is then used to determine the proppant retardation. The effects of wall roughness and fluid leakoff are discussed. Models are suggested that capture these first order effects. The new model for proppant retardation has been incorporated into a 3D fracture simulator. Results show that the proppant placement is substantially different when proppant retardation/acceleration is considered. Comparisons of propped fracture lengths obtained with the new model agree much better with propped and effective fracture lengths reported in the field. 1.Introduction Hydraulic fracturing is a commonly used stimulation technique. Proppant transport is a key factor in determining the productivity of these fractured wells. Water fracs are common stimulation treatments for low permeability gas reservoirs. These treatments use low viscosity Newtonian fluids to create long narrow fractures in the reservoir, without the excessive height growth that is often seen with cross-linked fluids. The low viscosity fluid and the narrow fractures introduce some significant challenges for proper proppant placement. The low viscosity of the carrying fluid leads to high settling velocities for the proppant. The narrow fractures created can have widths comparable to the diameter of the proppant and can alter proppant transport significantly due to the hydrodynamic forces acting on the proppant because of the fracture walls. Other proppant particles create additional hydrodynamic drag forces leading to retardation. Fracture diagnostic studies that have been reported in the literature have observed that the effective propped lengths for both water fracs and conventional gelled fracs are sometimes significantly different than those predicted by fracture models. Designed and created fracture lengths are usually much longer than the effective fracture lengths obtained from post production analysis[1–4]. They can sometimes be an order of magnitude lower. Proppant transport is a key factor determining the effective propped lengths and therefore the productivity of these fractured wells. In current hydraulic fracture models, the proppant is assumed to flow with the fluid in the direction of fracture propagation. It is shown in this paper that the proppant usually flows at a different velocity than the fluid, particularly in narrow fractures.It is important to develop reliable models to predict proppant transport. A detailed model for proppant settling in water fracs was presented earlier by the authors5. Several correlations for modeling proppant settling in water fracs were presented. These UTFRAC correlations allow fracture models to correct the settling velocity for inertial effects, proppant concentration, fracture width and turbulence. The models were implemented in a 3-D hydraulic fracture simulator and results showed that propped fracture lengths could vary significantly when settling was properly accounted for.
An Investigation into Proppant Transport in a Tortuous Fracture During Supercritical CO2 Fracturing
Zheng, Yong (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum (Beijing)) | Wang, Haizhu (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum (Beijing)) | Liu, Mingsheng (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum (Beijing)) | Tian, Ganghua (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum (Beijing)) | Yang, Bing (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum (Beijing))
ABSTRACT: In this paper, laser topography scanning technology is used to extract the fracture morphology after supercritical CO2 fracturing to generate a tortuous fracture model. Then a supercritical CO2 slurry flow model is established based on CFD-DEM coupling method, and the proppant transport in the tortuous fracture is simulated. The flow and proppant transport characteristics of supercritical CO2 slurry in tortuous fractures were analyzed, and the effects of injection velocity, injection temperature and injection pressure on proppant transport and distribution in tortuous fractures were investigated. The results show that the flow of supercritical CO2 slurry in tortuous fractures forms curved dominant channels compared to planar fractures, and the formed proppant dune is not uniformly distributed within the fractures. Low injection velocity in tortuous fractures is more likely to cause sand plugging, and increasing the injection velocity can weaken the effect of fracture structure on proppant transport. Low injection temperature and high injection pressure facilitates the transport and distribution of proppant in tortuous fractures. The results of the study contribute to an in-depth understanding of the flow behavior of supercritical CO2 slurry in tortuous fractures. 1. INTRODUCTION Unconventional oil and gas reservoirs are characterized by low reservoir porosity, poor fluid permeability and low natural production capacity, making it difficult to develop them on a large scale by conventional extraction methods. Thanks to the emergence and development of hydraulic fracturing technology, the process of commercial development of unconventional oil and gas, such as shale gas, has been greatly accelerated (Denney, 2010). However, with the wide application of hydraulic fracturing technology, it also faces a series of challenges such as water consumption, reservoir clay expansion, and groundwater contamination (Hyman et al., 2016; Liu, Jiang, Huang, and Sugimoto, 2018). CO2 plays an important role in enhanced oil recovery (EOR) because of its good solubility and strong extraction ability in crude oil, which can significantly reduce crude oil viscosity, swell and increase capacity, and reduce interfacial tension by mixing phase with crude oil in multiple contacts(Hill, Li, and Wei, 2020; Li et al., 2017). When CO2 is injected into the reservoir, it changes to a supercritical state at the temperature and pressure conditions of the reservoir. Supercritical CO2 has shown great advantages as a fracturing fluid in eliminating reservoir damage, improving shale gas recovery and storing CO2 in the underground, and is a new waterless fracturing technology with broad application prospects(Middleton et al., 2015; Yang et al., 2021).
- Geology > Geological Subdiscipline > Geomechanics (0.70)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.45)