Evaluating Fracture Volume Loss During Flowback and Its Relationship to Choke Size: Fastback vs. Slowback

Fu, Yingkun; Dehghanpour, Hassan; Motealleh, Siyavash; Lopez, Carlos; Hawkes, Robert

doi:10.2118/195595-pa

Cited by 9 publications

(3 citation statements)

References 21 publications

Supporting

Mentioning

Contrasting

Order By: Relevance

“…The early stage of the hydration process is believed to be the main stage of microdamage to the rock samples. With increasing immersion time, the propagation speed of the microfractures gradually decreases. , The expansion of the microfractures is restrained under the confining pressure, and the original mineral particle arrangement, cementation, and microfracture development of the rock have significant impact on the formation of dissolution pores and particle shedding after hydration. Siddiqui et al conducted an experiment using two cylindrical cores of organic-rich shale.…”

Section: Imbibition Mechanisms At the Core Scalementioning

confidence: 99%

Imbibition Mechanisms of Fracturing Fluid in Shale Oil Formation: A Review from the Multiscale Perspective

et al. 2023

View full text Add to dashboard Cite

The breakthrough of shale oil in North America led to a worldwide energy revolution. Shale reservoirs show multiscale properties and a large proportion of nanopores compared to conventional reservoirs, which makes the imbibition mechanisms of fracturing fluids within shale reservoirs exceptionally complicated. For instance, the fracturing fluid shows a distinct imbibition behavior at different scales. Traditional models face significant challenges in imbibition characterization. Understanding the imbibition mechanisms in shale oil formations from a multiscale perspective can help to make full use of the positive effect and enhance oil recovery. We review imbibition mechanisms in shale reservoirs from the nanoscale to the reservoir scale. The imbibition principles in a single nanopore and the improvement of the traditional characterization models are clarified. Then, at the pore scale, we elaborate on the imbibition laws obtained from the microfluidic chip, pore network model, and direct simulations. We also outline the imbibition dynamics at the core scale, the influences of capillary forces and osmotic pressure, and the variations of the pore structure. Finally, the imbibition behavior at the reservoir scale and field examples considering the imbibition effect are introduced. We analyze the existing problems on each scale and discuss the future trends in this area. This work is expected to help readers systematically understand the mechanisms and behavior of fracturing fluid imbibition in shale oil reservoirs at different scales and accelerate the exploitation of shale resources.

show abstract

Section: Imbibition Mechanisms At the Core Scalementioning

confidence: 99%

Imbibition Mechanisms of Fracturing Fluid in Shale Oil Formation: A Review from the Multiscale Perspective

et al. 2023

View full text Add to dashboard Cite

show abstract

“…Gas-condensate production has been reported from wells completed in Eagle Ford [79], Woodford [80], Duvernay [81], and Montney formations [82,83]. Flowback data from lean-gas wells completed in the Woodford formation have shown condensate production after about 10 days of flowback [80].…”

Section: On Phase Behaviors Of Gas-condensate Wellsmentioning

confidence: 99%

The Effect of Temperature on Flowback Data Analysis in Shale Gas Reservoirs: A Simulation-Based Study

Yang

Lai

et al. 2019

Energies

Self Cite

View full text Add to dashboard Cite

During hydraulic fracturing, there is a temperature difference between the injected water and formation rock for shale gas wells. The objective of this study is to investigate how this temperature difference changes with time, and how it affects multiphase-flow modeling during the shut-in and flowback periods. We conducted numerical simulations to investigate the behaviors of fracture temperature in shale gas wells. The results show a significant increase in fracture temperature during the shut-in and flowback periods. Sensitivity analysis suggests that this temperature increase is strongly related to the thermal conductivity of formation rock, matrix permeability, and initial reservoir temperature. Simulation scenarios were further compared to investigate the effect of temperature on flowback data analysis. Without considering the thermal effect, flowback data analysis may yield an earlier fracture cleanup and overestimated fracture volume. In addition, this study suggests that the thermal effect may also have implications for optimizing flowback operations.

show abstract

“…Jones and Blasingame [40,41] applied hyperbolic and modified hyper-bolic models to predict multiphase flow during reverse discharge. Fu et al [42,43] and Fu et al [44] observed the harmonic decline behavior of the water return discharge and estimated the initial fracture volume versus final water production via decreasing curve analysis.…”

Section: Introductionmentioning

confidence: 99%

A Novel Mathematical Model for Fracturing Effect Evaluation Based on Early Flowback Data in Shale Oil Reservoirs

Wang

Lei

et al. 2021

Geofluids

View full text Add to dashboard Cite

For shale oil reservoirs, the horizontal well multistage fracturing technique is mostly used to reform the reservoir in order to achieve economic and effective development. The size of the reservoir reconstruction volume and the quantitative characterization of the fracture system are of great significance to accurately predict the productivity of shale oil wells. There are few flowback models for shale oil reservoirs. To solve this problem, first, a physical model of the simultaneous production of oil, gas, and water in the early flowback stage of shale oil development is established using the material balance equation for a fracture system. Second, the physical model of the underground fracture system is simplified, which is approximately regarded as a thin cylindrical body with a circular section. The flow of the fluid in the fracture system is approximately regarded as radial flow. In this model, the expansion of the fluid and the closure of the fracture are defined as integrated storage coefficients to characterize the storage capacity of the fracture system. Then, the curves illustrating the relationships between the oil-water ratio and the cumulative oil production and between the gas-water ratio and the cumulative gas production are drawn, and the curves are used to divide the flowback stage into an early stage and a late stage because the flowback process of shale oil wells exhibits obvious stage characteristics. Finally, the reservoir reconstruction volume and the related hydraulic fracture parameters are estimated based on the material balance method, and the rationality of the model is verified via numerical simulation. The interpretation results of this novel model are more accurate, making it an effective way to evaluate the hydraulic fracture parameters and transformation effect, and it has guiding significance for the evaluation of the hydraulic fracturing effect in the field.

show abstract

Evaluating Fracture Volume Loss During Flowback and Its Relationship to Choke Size: Fastback vs. Slowback

Cited by 9 publications

References 21 publications

Imbibition Mechanisms of Fracturing Fluid in Shale Oil Formation: A Review from the Multiscale Perspective

Imbibition Mechanisms of Fracturing Fluid in Shale Oil Formation: A Review from the Multiscale Perspective

The Effect of Temperature on Flowback Data Analysis in Shale Gas Reservoirs: A Simulation-Based Study

A Novel Mathematical Model for Fracturing Effect Evaluation Based on Early Flowback Data in Shale Oil Reservoirs

Contact Info

Product

Resources

About