Flowback Model Research Articles

Shale gas effective fracture network volume prediction and analysis based on flow back data: A case study of southern Sichuan Basin shale

Fracture network fracturing is the key technology to achieve the economic and effective development of shale gas, and the fracturing stimulation performance is seriously affected by the connectivity of fracture network. The effective stimulated reservoir volume is affected by many factors such as geological and engineering. But the current control factors affecting the effective fractures network volume (EFNV) are not well understood, resulting in blindness in the construction of high-quality effective fracture network. Thus, a new method is proposed for predicting the EFNV of shale gas under multiple factors. The EFNV of the field fracturing well was calculated based on the two-phase flow back model, which was established to invert the effective fracture network volume. Taking this inversion result as the goal, a prediction model of EFNV based on genetic expression programming (GEP) was developed, and the influence of influencing factors on the EFNV is analyzed quantitatively. The results show that with the cluster spacing and Poisson's ratio increase, the EFNV shows a downward trend. The increase of liquid strength, single-stage clusters, brittleness index, displacement and Young's modulus promotes the formation of EFNV. The optimal reservoir stimulation performance can be obtained by optimizing the fracturing operation parameters.

New Pump-In Flowback Model Verification with In-Situ Strain Measurements and Numerical Simulation

This study presents an analytical model for estimating minimum horizontal stress in hydraulic fracturing stimulations. The conventional Diagnostic Fracture Injection Test (DFIT) is not practical in ultra-tight formations, leading to the need for pump-in/flowback tests. However, ambiguities in the results of these tests have limited their application. The proposed model is based on the linear diffusivity equation and material balance, which is analytically solved and verified using a commercially available numerical simulator. The model generates a linear graph in which the pressure drop and its derivative are plotted versus the developed solution time function. The closure pressure is determined when the slope of the derivative deviates from linearity. The model was applied to several cycles of field flowback tests and found to eliminate the ambiguity associated with identifying the fracture closure. Furthermore, the minimum In-situ stresses estimated using this approach are verified via downhole strain measurement and synthetic data from a fully 3D commercial fracturing simulator. The proposed technique outperformed other conventional methods in analyzing challenging injection/shut-in tests, showing improved results and reducing uncertainty in estimated fracture parameters. This model is expected to scale down the need for multiple field trials and provide a reliable estimation of minimum stress.

Integrated modeling of fracturing-flowback-production dynamics and calibration on field data: Optimum well startup scenarios

We aim at the development of a general modelling workflow for design and optimization of the well flowback and startup operation on hydraulically fractured wells. Fracture flowback model developed earlier by the authors is extended to take into account several new fluid mechanics factors accompanying flowback, namely, viscoplastic rheology of unbroken cross-linked gel and coupled “fracture-reservoir” numerical submodel for influx from rock formation. We also developed models and implemented new geomechanical factors, namely, (i) fracture closure in gaps between proppant pillars and in proppant-free cavity in the vicinity of the well taking into account formation creep; (ii) propagation of plastic deformations due to tensile rock failure from the fracture face into the fluid-saturated reservoir.We carried out parametric calculations to study the dynamics of fracture conductivity during flowback and its effect on well production for the set of parameters typical of oil wells in Achimov formation of Western Siberia, Russia. The first set of calculations is carried out using the flowback model in the reservoir linear flow regime. It is obtained that the typical length of hydraulic fracture zone, in which tensile rock failure at the fracture walls occurs, is insignificant. In the range of rock permeability in between 0.01 mD and 1 D, we studied the effect of non-dimensional governing parameters as well as bottomhole pressure drop dynamics on oil production. We obtained a map of pressure drop regimes (fast, moderate or slow) leading to maximum cumulative oil production. The second set of parametric calculations is carried out using integrated well production modelling workflow, in which the flowback model acts as a missing link in between hydraulic fracturing and reservoir commercial simulators. We evaluated quantitatively effects of initial fracture aperture, proppant diameter, yield stress of fracturing fluid, pressure drop rate and proppant material type (ceramic and sand) on long-term well production beyond formation linear regime. The third set of parametric calculations is carried out using the flowback model history-matched to field data related to production of four multistage hydraulically fractured oil wells in Achimov formation of Western Siberia, Russia. On the basis of the matched model we evaluated geomechanics effects on fracture conductivity degradation. We also performed sensitivity analysis in the framework of the history-matched model to study the impact of geomechanics and fluid rheology parameters on flowback efficiency.

Mathematical Modeling and Numerical Simulation of Water‐Rock Interaction in Shale Under Fracturing‐Fluid Flowback Conditions

AbstractWater‐rock interaction cannot be ignored for shale reservoirs with high‐salinity formation brine and complex rock composition, and stimulated by massive slick‐water fracturing treatment. However, there have been few studies on the flowback model fully coupled with different effects of water‐rock interaction. This paper presents the development of a coupled hydro‐chemical‐mechanical model for modeling water‐rock interaction in fractured shale during the post‐fracturing flowback period. The model considers distinguishing water‐rock interaction phenomena, that is, mineral dissolution, clay swelling and chemical osmosis, and accounts for multi‐phase flow in a fractured shale reservoir. The coupling and solution method and a numerical simulator were developed. Numerical simulation indicates that the swelling volume of clay minerals occupies the pores and leads to a decline in matrix porosity, while mineral dissolution increases both the matrix porosity and the solute concentration in the aqueous phase in matrix pores. Clay swelling mainly affects the shape of the porosity ratio profiles. The effect of mineral dissolution becomes increasingly stronger as flowback progresses. Mineral dissolution mainly affects the relative positions of the porosity ratio curves with the progress of flowback. The water‐rock interaction coupled flowback modeling and the numerical simulation results in this study quantify the effects of chemical osmosis, clay swelling and mineral dissolution. Results from this study provide new insights into the mechanisms of fracturing‐fluid flowback and value to flowback transient analysis.

Optimization on fracturing fluid flowback model after hydraulic fracturing in oil well

As an important part in the process of hydraulic fracturing, fracturing fluid flowback after fracturing will directly affect the productivity of the fractured wells. It is of great significance to carry out optimization research on the flowback working system of fracturing fluid (the time of flowback beginning and the size of flowback nozzles) to enhance the efficiency of fracturing. At present, researches on optimization model of fracturing fluid flowback have taken into account the effects of fracturing fluid loss and proppant reflux, while ignoring the effects of proppant sedimentation. A new calculation model of proppant regurgitation velocity has been established in recent years, but it is rarely used in the research of flowback working system. This study innovatively integrated the calculation model of modified proppant sedimentation velocity obtained through experiments, the new calculation model of critical proppant regurgitation velocity, and the wellhead pressure calculation model to form a comprehensive flowback model of fracturing fluid. Then coupled with the flowback criteria of quickly flowback, reducing proppant reflux, and maintaining proppant settlement degree (ratio of proppant settlement distance to crack height) less than 60%, an optimization model of fracturing fluid flowback is constructed and realized by MATLAB software programs. The optimization model were verified by four fractured wells in DaQing Oilfield. The effects of reservoir permeability, reservoir porosity, fracturing fluid density, and proppant particle size on wellhead pressure drop, fracturing fluid flowback rate, and proppant settlement degree were calculated and analyzed by using the above flowback model. The verification results show that the simulated wellhead pressure and flowback flowrate are in good agreement with the actual dataset, with the average errors of 11.9% and 11.6% respectively, which proves the accuracy of the flowback optimization model. Parametric analysis shows that, with the increase of reservoir permeability and reservoir porosity, the wellhead pressure drop velocity increases. When the permeability increases from 1mD to 5mD, the flowback rate of fracturing fluid and proppant settlement degree are reduced by 12.3% and 69.8% respectively. When the porosity increases from 9% to 36%, the proppant settlement degree fall by 25.2%. Moreover, the flowback rate of fracturing fluid decreases linearly and the proppant settlement degree increases linearly with the increase of fracturing fluid density; and the proppant settlement degree increases by 3.5 times when the proppant particle size increases from 0.25 mm to 1.65 mm. Therefore, choosing smaller fracturing fluid density and smaller proppant particle size can ensure higher fluid flowback efficiency and lower proppant settlement degree. • A new flowback model of fracturing fluid is constructed to optimize the flowback working system, which takes the influence of proppant settling into account. • The optimization model is realized by programming with MATLAB software and its accuracy is verified by four fracturing wells of Daqing Oilfield. • Then the influences of reservoir permeability, reservoir porosity, fracturing fluid density and proppant particle size on the wellhead pressure drop, fracturing fluid flowback rate and proppant settlement degree are clarified.

A multi-mechanism multi-pore coupled salt flowback model and field application for hydraulically fractured shale wells

Flowback records matching has been increasingly used for reservoir and fracture parameters inversion for hydraulically fractured unconventional oil and gas wells. However, previous publications mainly focus on flowback water transients but flowback salinity transient analyses are few. In this study, a salt flowback model characterizing salt transport in a hydraulically fractured shale reservoir has been proposed. The physical model treats the hydraulically fractured shale reservoir as a multi-pore medium, which includes wellbore, primary hydraulic fracture, secondary hydraulic fracture, clay-dominant pore and other matrix pore. The salt transport accounts for three mechanisms, i.e. advection, diffusion and clay-dominant adsorption. We apply semi-implicit algorithm for mathematical model solution and numerical simulator development. The simulation results indicate that advection predominates in the salt flowback. Salts and water flow into shale matrix from secondary hydraulic fractures at the beginning of flowback and then the flowing direction reverses. The cumulative flowback salinity of well exhibits an increase with the flowback time. However, the instant flowback salinity of well first increases and then decreases along with the increase in shut-in time. Finally, 2 wells from field in X shale formation, have been applied to match the flowback salinity and water records. The parameter combinations of the conductivity and half-length of hydraulic primary fractures, as well as the number of secondary fractures are recovered based on the good match of flowback salinity records and water load recovery. This study provides another way for post-stimulation evaluation and supplements existing flowback model.

A Semianalytical Method for Two-Phase Flowback Rate-Transient Analysis in Shale Gas Reservoirs

Summary We propose a new semianalytical method for analyzing flowback water and gas production data to estimate hydraulic fracture (HF) properties and to quantify HF dynamics. The method includes a semianalytical flowback model, a set of two-phase diagnostic plots, and a workflow to evaluate initial fracture volume and permeability, as well as fracture compressibility and permeability modulus. The flowback model incorporates two-phase water and gas flow in both HF and matrix domains and considers variations of fluid and rock properties with pressure. The HF domain is modeled by boundary-dominated flow, whereas an infinite-acting linear flow is assumed for the matrix domain. The flowback model is developed by assigning the variable average pressure in the fracture as the inner boundary condition for matrix according to Duhamel's principle. The average pressure in the fracture and distance of investigation (DOI) in the matrix are calculated from a modified material-balance equation by updating the matrix DOI as well as phase saturation and relative permeability in both the fracture and matrix domains. A modified DOI equation is used for two-phase flow in the matrix, which considers the pressure-dependent fluid and rock properties in pseudotime. The diagnostic plots shed light on the identification of flow regimes during the coupled two-phase flow in both fracture and matrix. The proposed workflow quantifies the HF dynamics through the loss of both fracture volume and fracture permeability by reconciling flowback and long-term production data. The accuracy of the new method is tested against numerical simulations conducted by a commercial numerical simulator. The validation results confirm that the proposed method accurately predicts initial fracture volume, permeability, and permeability modulus. Further, we use production data from a multifractured horizontal well (MFHW) drilled in Marcellus Shale to test the practicality of the proposed method. The results show a significant reduction in fracture volume and permeability during production attributable to the HF closure.

Fracturing-Fluid Flowback Simulation with Consideration of Proppant Transport in Hydraulically Fractured Shale Wells.

Involving the fluid-particle hydrodynamic process and hydraulically created fracture network, fracturing-fluid flowback in hydraulically fractured shale wells is a complex transport behavior. However, there is limited research on investigating the influence of proppant transport on the fracturing-fluid flowback behavior and flowback data analysis. In this paper, a flowback model is developed to simulate the flowback behaviors of the carrying fluid and proppant from the recompacted fracture system in shale wells. The development of fluid pressure and proppant concentration profiles of the fractured shale well are presented. The fluid and proppant fluxes among the hydraulic primary fracture and the induced fracture are also calculated. The influences of proppant consideration or not, proppant density, proppant size, fracturing-fluid viscosity, and fracturing-fluid density on the flowback behavior are investigated. The simulation results are useful for fracturing-fluid optimization in the design phase. Finally, two field cases from the Longmaxi Formation, Southern Sichuan Basin, China are used for matching the actual flowback data with the model results. The results prove that the proppant transport has influence on the flowback behavior to some degree and should be considered in the flowback model for a rather elaborate flowback analysis and post-treatment fracture evaluation.

Semi-Analytical Model for Two-Phase Flowback in Complex Fracture Networks in Shale Oil Reservoirs

Flowback data is the earliest available data for estimating fracture geometries and the assessment of different fracturing techniques. Considerable attention has been paid recently to analyze flowback data quantitively in order to obtain fracture properties such as effective half-length and effective conductivity by simply assuming fractures having bi-wing planar geometries and constant fracture compressibility. However, this simplifying assumption ignores the complexity of fracture networks. To overcome this limitation, we proposed a semi-analytical method, which can be used as a direct model for fast inverse analysis to characterize complex fracture networks generated during hydraulic fracturing. A two-phase oil–water flowback model with a matrix oil influx for wells with bi-wing planar fractures is also presented to identify limitations of the former solution. Since most available flowback studies use constant fracture properties and the assumption of planar fractures, considering variable fracture properties and complex fracture geometries gives this model more robustness for modeling fracture flow during flowback, more realistically. The proposed models have been validated by numerical simulations. The presented procedure provides a simple way for modeling early flowback in complex fracture networks and it can be used for inverse analysis.

Multiphase flowback rate-transient analysis of shale gas reservoirs

Multi-fractured horizontal well (MFHW) is commonly used in the development of unconventional reservoirs. Flowback data after hydraulic fracturing is of critical importance in the characterization of hydraulic fracture, stimulation evaluation, and reservoir simulation. This study presents a two-phase diagnostic plot and a semi-analytical flowback model for the early-time flowback period when fluid influx from matrix remains insignificant and production is mainly from the fracture network. The developed model considers the changes of water saturation in hydraulic fracture (HF) under fracture depletion mechanism and pressure-dependent permeability and porosity, and is able to predict HF attributes, such as fracture half-length, initial fracture permeability, and initial pore volume of fracture network. A new method of calculating average pressure in the fracture is developed based on the solution of water-phase diffusivity equation and is compared with the traditional material balance approach based on the tank model. Three iterative workflows are proposed using the successive substitution method to calculate fracture attributes under different production conditions. Validation of the developed flowback model, average pressure calculation method, and the analysis workflow, as well as their application in an MFHW drilled in Horn River Shale show the applicability of this study to interpret flowback data quickly and estimate HF properties accurately.

A Two-Phase Flowback Model for Multiscale Diffusion and Flow in Fractured Shale Gas Reservoirs

A shale gas reservoir is usually hydraulically fractured to enhance its gas production. When the injection of water-based fracturing fluid is stopped, a two-phase flowback is observed at the wellbore of the shale gas reservoir. So far, how this water production affects the long-term gas recovery of this fractured shale gas reservoir has not been clear. In this paper, a two-phase flowback model is developed with multiscale diffusion mechanisms. First, a fractured gas reservoir is divided into three zones: naturally fractured zone or matrix (zone 1), stimulated reservoir volume (SRV) or fractured zone (zone 2), and hydraulic fractures (zone 3). Second, a dual-porosity model is applied to zones 1 and 2, and the macroscale two-phase flow flowback is formulated in the fracture network in zones 2 and 3. Third, the gas exchange between fractures (fracture network) and matrix in zones 1 and 2 is described by a diffusion process. The interactions between microscale gas diffusion in matrix and macroscale flow in fracture network are incorporated in zones 1 and 2. This model is validated by two sets of field data. Finally, parametric study is conducted to explore key parameters which affect the short-term and long-term gas productions. It is found that the two-phase flowback and the flow consistency between matrix and fracture network have significant influences on cumulative gas production. The multiscale diffusion mechanisms in different zones should be carefully considered in the flowback model.

Estimating Effective Fracture Pore Volume From Flowback Data and Evaluating Its Relationship to Design Parameters of Multistage-Fracture Completion

Summary Flowback data from seven multifractured horizontal tight oil/gas wells in Anadarko Basin show two separate regions during the single-phase water production. Region 1 shows a dropping casing pressure, and Region 2 shows a flattening casing pressure. This paper investigates the flowback behavior of the two regions, and illustrates how flowback data can be interpreted to estimate effective fracture pore volume, and to investigate its relationship to completion-design parameters. We construct diagnostic plots to understand the physics of Regions 1 and 2. Region 1 represents pressure depletion in fractures, and Region 2 represents the hydrocarbon breakthrough into the effective fracture network. The results of our analyses indicate that the duration of Region 1 depends on initial reservoir pressure and hydrocarbon type. We apply a previous flowback model (Abbasi et al. 2012, 2014) on Region 1 to estimate effective fracture pore volume, and also propose a procedure to estimate fracture compressibility by use of diagnostic-fracturing-injection-test (DFIT) data. The results suggest that the estimated effective fracture pore volume is very sensitive to fracture compressibility, and is generally larger than the final load-recovery volume, and less than the total injected-water volume. The results also suggest that most of the effective fractures are unpropped, and host the nonrecovered fracturing water. We investigate the relationship between the estimated effective fracture pore volumes and completion-design parameters, including total injected-water volume, proppant mass, gross perforated interval, and number of clusters, by use of the Pearson correlation-coefficient method. The results show that total injected-water volume, gross perforated interval, and the number of clusters are among the key design parameters for an optimal fracturing treatment. Higher total injected-water volume and closer cluster spacing generally lead to a larger effective fracture pore volume.

Modeling fracturing-fluid flowback behavior in hydraulically fractured shale gas under chemical potential dominated conditions

Shale with high clay content has caused instability from hydration during the hydraulic fracturing process. Macro-level migration phenomenon of water molecules is induced by the chemical potential difference between low-salinity fracturing fluid and high-salinity formation brine. This study aims to establish the equation for the chemical potential difference between fracturing fluid and formation brine by theoretical deduction in order to investigate the effect of the aforementioned phenomenon on fracturing flowback. Accordingly, a mathematical model was established for the gas–water two-phase flow which driven by the chemical potential difference. Viscous force, capillarity and chemiosmosis were considered as the driving forces. A numerical simulation of fracturing fluid flowback with or without considering of the effect of chemiosmosis was performed. A simulation analysis of the water saturation and salinity profiles was also conducted. Results show that capillarity and chemiosmosis hinder fracturing fluid flowback in different degrees. As the condition worsens, they inhibit more than 80% of water to flow back out of the formation, forming a permanent water lock. This study contributes to improvement of the theory on shale gas–water two-phase flow, establishment of a flowback model that suitable for shale gas wells, and accurate evaluation of the fracturing treatment.

A complementary approach for uncertainty reduction in post-flowback production data analysis

A key limitation of conventional post-flowback production data analysis is non-uniqueness of solution. This causes uncertainty in reservoir parameter estimates and hydrocarbon forecasts. This paper proposes a complementary approach, using flowback data analysis to constrain post-flowback data analysis and reduce uncertainty in output results.This study history-matches two-phase pressure and rate data from seven multifractured Horn River shale-gas wells to investigate the benefits of analysing both flowback and post-flowback data together. The flowback history-match result estimates the pore-volume of active fracture networks, effective half-lengths and initial gas volume in hydraulic fractures during flowback. Also, the field production forecasts from the flowback history-match yield lower gas rates compared to actual post-flowback production data. On the other hand, the post-flowback history-match results overestimate effective half-lengths when compared to flowback history-match results. These observations are due to neglecting the secondary fracture and gas desorption effects on the dual-porosity based flowback model used in this study. The communication interface between secondary fractures and hydraulic fractures significantly increases during post-flowback periods (when most of the water in the active secondary fractures have been displaced by gas influx from the matrix and matrix pressure drops below the critical desorption pressure). Therefore, post-flowback analysis should properly couple flowback history, and account for secondary fracture and gas desorption effects to yield reasonable results.This paper shows how to perform a complementary flowback and post-flowback data analysis for comprehensive fracture/reservoir characterization. This complementary approach provides engineers with a tool to estimate fracture parameters (such as half length) from flowback analysis and use them as inputs for post-flowback analysis. Although a dual-porosity framework is sufficient for flowback data analysis, proper post-flowback analysis should account for both secondary fracture effects (using a triple-porosity framework) and gas desorption effects.

Optimization of Fracturing Fluid Flowback Based on Fluid Mechanics for Multilayer Fractured Tight Reservoir

The purpose of frac fluid flowback is to outflow the fracturing fluid and prevent the proppant backflow, which determines the effect of fracturing fluid flowback. The fracturing treatment in field lacks relevant theoretical models for prediction. Therefore, this work focuses on establishing the flowback model of hydraulic fracturing for multilayer fractured wells. Then the wellhead pressure and fluid flowback volume are predicted based on the actual parameters of fracturing treatment in the process of flowback and are compared with the field data of frac fluid flowback. Results show that the wellhead pressure and fluid flowback volume calculated by the model are consistent with the field data. The sand production ratio of the three wells during the flowback process is lower than 1% indicating that the optimized parameters achieve the purpose of flowback operations and reduce the flowback volume of the proppant.