scholarly journals An Analytical Model for Capturing the Decline of Fracture Conductivity in the Tuscaloosa Marine Shale Trend from Production Data

Energies ◽  
2019 ◽  
Vol 12 (10) ◽  
pp. 1938 ◽  
Author(s):  
Xu Yang ◽  
Boyun Guo ◽  
Xiaohui Zhang
Keyword(s):  
Flow Regime ◽  
Field Data ◽  
Good Accuracy ◽  
Transient Flow ◽  
Production Data ◽  
Hydraulic Fractures ◽  
Fracture Conductivity ◽  
Dimensionless Coefficient ◽  
Marine Shale ◽  
Proposed Model

Fracture conductivity decline is a concern in the Tuscaloosa Marine Shale (TMS) wells due to the high content of clay in the shale. An analytical well productivity model was developed in this study considering the pressure-dependent conductivity of hydraulic fractures. The log-log diagnostic approach was used to identify the boundary-dominated flow regime rather than the linear flow regime. Case studies of seven TMS wells indicated that the proposed model allows approximation of the field data with good accuracy. Production data analyses with the model revealed that the pressure-dependent fracture conductivity in the TMS in the Mississippi section declines following a logarithmic mode, with dimensionless coefficient χ varying between 0.116 and 0.130. The pressure-dependent decline of fracture conductivity in the transient flow period is more significant than that in the boundary-dominated flow period.

Pressure Depletion Mapping Using Multi-Well DFITs and its Applications in Hydraulic Fracture Characterization and Permeability Estimation: Examples from Montney Formation

2021 ◽  
Author(s):  
Behjat Haghshenas ◽  
Farhad Qanbari
Keyword(s):  
Data Analysis ◽  
Surface Area ◽  
Reservoir Simulation ◽  
Production Data ◽  
Hydraulic Fractures ◽  
Fracture Geometry ◽  
Fracture Conductivity ◽  
Field Case ◽  
Pressure Depletion ◽  
Montney Formation

Abstract Recovery factor for multi-fractured horizontal wells (MFHWs) at development spacing in tight reservoirs is closely related to the effective horizontal and vertical extents of the hydraulic fractures. Direct measurement of pressure depletion away from the existing producers can be used to estimate the extent of the hydraulic fractures. Monitoring wells equipped with downhole gauges, DFITs from multiple new wells close to an existing (parent) well, and calculation of formation pressure from drilling data are among the methods used for pressure depletion mapping. This study focuses on acquisition of pressure depletion data using multi-well diagnostic fracture injection tests (DFITs), analysis of the results using reservoir simulation, and integration of the results with production data analysis of the parent well using rate-transient analysis (RTA) and reservoir simulation. In this method, DFITs are run on all the new wells close to an existing (parent) well and the data is analyzed to estimate reservoir pressure at each DFIT location. A combination of the DFIT results provides a map of pressure depletion around the existing well, while production data analysis of the parent well provides fracture conductivity and surface area and formation permeability. Furthermore, reservoir simulation is tuned such that it can also match the pressure depletion map by adjusting the system permeability and fracture geometry of the parent well. The workflow of this study was applied to two field case from Montney formation in Western Canadian Sedimentary Basin. In Field Case 1, DFIT results from nine new wells were used to map the pressure depletion away from the toe fracture of a parent well (four wells toeing toward the parent well and five wells in the same direction as the parent). RTA and reservoir simulation are used to analyze the production data of the parent well qualitatively and quantitatively. The reservoir model is then used to match the pressure depletion map and the production data of the parent well and the outputs of the model includes hydraulic fracture half-lengths on both sides of the parent well, formation permeability, fracture surface area and fracture conductivity. In Field Case 2, the production data from an existing well and DFIT result from a new well toeing toward the existing wells were incorporated into a reservoir simulation model. The model outputs include system permeability and fracture surface area. It is recommended to try the method for more cases in a specific reservoir area to get a statistical understanding of the system permeability and fracture geometry for different completion designs. This study provides a practical and cost-effective approach for pressure depletion mapping using multi-well DFITs and the analysis of the resulting data using reservoir simulation and RTA. The study also encourages the practitioners to take every opportunity to run DFITs and gather pressure data from as many well as possible with focus on child wells.

scholarly journals A Semianalytical Model for Analyzing the Infill Well-Caused Fracture Interference from Shale Gas Reservoirs

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-13
Author(s):  
Sidong Fang ◽  
Yonghui Wu ◽  
Cheng Dai ◽  
Liqiang Ma ◽  
Hua Liu
Keyword(s):  
Shale Gas ◽  
Control Volume ◽  
Material Balance ◽  
Production Performance ◽  
Production Data ◽  
Model Parameters ◽  
Hydraulic Fractures ◽  
Late Time ◽  
Fracture Characterization ◽  
Proposed Model

Drilling infill well has been widely used in many plays to enhance the recovery of shale gas, but the infill well-caused fracture interference is a very important issue that should be taken into consideration. The well interference makes it difficult for the conventional models to make production predictions, fracture characterization, and production data analysis. In this paper, a semianalytical model is proposed for this purpose by discretizing the whole control volume of the parent and infill wells into several linear flow zones. In this way, three important issues can be further handled very naturally, including fracture connection between the parent and infill wells, different SRV properties for zones with different distances to the wellbore, and different production times for adjacent wellbores. The approximate expressions for different flow regimes are used in making production predictions in the time domain, and a flowing material balance method and a simple iteration are used to update the model parameters step by step. The proposed model is shown to be reasonable and accurate for handling multiwell interference problems after comparing with the commercial numerical simulator tNavigator. The synthetical cases show that the fracture parameters, SRV properties, and well infill time have a significant influence on the production performance of both the parent and infill wells. The results show that the production of the parent well will be dramatically enhanced when it is connected with the infill well via high-conductive hydraulic fractures. Longer unconnected fractures and more fracturing stages/clusters for the infill well will result in higher production for the infill well, but a negative effect is observed for the parent well. The permeability of the distant well SRV has a similar influence on the parent and infill wells. The results also show that late time well interference will result in a more significant increase in production rate on the log-log plots for the severe depletion around the parent well. Finally, the proposed model is used to analyze the production data of a field case from Fuling shale in Southwestern China. After analyzing the production data, several parameters can be obtained for both parent and infill wells, including the fracture lengths and conductivities, numbers of connected fractures, and the near and distant well permeabilities of the SRV. This gives a basic and practical technique for production prediction, formation and fracture evaluation, and well connectivity analysis from shale gas wells with fracture connection.

scholarly journals Numerical Study of Elasto-Plastic Hydraulic Fracture Propagation in Deep Reservoirs Using a Hybrid EDFM–XFEM Method

Energies ◽  
2021 ◽  
Vol 14 (9) ◽  
pp. 2610
Author(s):  
Wenzheng Liu ◽  
Qingdong Zeng ◽  
Jun Yao ◽  
Ziyou Liu ◽  
Tianliang Li ◽  
...  
Keyword(s):  
Plastic Deformation ◽  
Iterative Method ◽  
Hydraulic Fracture ◽  
Iterative Procedure ◽  
Fracture Propagation ◽  
Hydraulic Fractures ◽  
Zone Model ◽  
Dilatancy Angle ◽  
Proposed Model ◽  
Hydraulic Fracture Propagation

Rock yielding may well take place during hydraulic fracturing in deep reservoirs. The prevailing models based on the linear elastic fracture mechanics (LEFM) are incapable of describing the evolution process of hydraulic fractures accurately. In this paper, a hydro-elasto-plastic model is proposed to investigate the hydraulic fracture propagation in deep reservoirs. The Drucker–Prager plasticity model, Darcy’s law, cubic law and cohesive zone model are employed to describe the plastic deformation, matrix flow, fracture flow and evolution of hydraulic fractures, respectively. Combining the embedded discrete fracture model (EDFM), extended finite element method (XFEM) and finite volume method, a hybrid numerical scheme is presented to carry out simulations. A dual-layer iterative procedure is developed based on the fixed-stress split method, Picard iterative method and Newton–Raphson iterative method. The iterative procedure is used to deal with the coupling between nonlinear deformation with fracture extension and fluid flow. The proposed model is verified against analytical solutions and other numerical simulation results. A series of numerical cases are performed to investigate the influences of rock plasticity, internal friction angle, dilatancy angle and permeability on hydraulic fracture propagation. Finally, the proposed model is extended to simulate multiple hydraulic fracture propagation. The result shows that plastic deformation can enhance the stress-shadowing effect.

High-Resolution and Multimaterial Fracture Productivity Calculator for the Successful Design of Channel Fracturing Jobs

2021 ◽  
Author(s):  
Dimitry Chuprakov ◽  
Ludmila Belyakova ◽  
Ivan Glaznev ◽  
Aleksandra Peshcherenko
Keyword(s):  
High Resolution ◽  
Effective Conductivity ◽  
Productivity Index ◽  
Hydraulic Fractures ◽  
Total Production ◽  
Fracture Conductivity ◽  
Hindered Settling ◽  
Accurate Evaluation ◽  
Skin Factor ◽  
Fracture Closure

Abstract We developed a high-resolution fracture productivity calculator to enable fast and accurate evaluation of hydraulic fractures modeled using a fine-scale 2D simulation of material placement. Using an example of channel fracturing treatments, we show how the productivity index, effective fracture conductivity, and skin factor are sensitive to variations in pumping schedule design and pulsing strategy. We perform fracturing simulations using an advanced high-resolution multiphysics model that includes coupled 2D hydrodynamics with geomechanics (pseudo-3D, or P3D, model), 2D transport of materials with tracking temperature exposure history, in-situ kinetics, and a hindered settling model, which includes the effect of fibers. For all simulated fracturing treatments, we accurately solve a problem of 3D planar fracture closure on heterogenous spatial distribution of solids, estimate 2D profiles of fracture width and stresses applied to proppants, and, as a result, obtain the complex and heterogenous shape of fracture conductivity with highly conductive cells owing to the presence of channels. Then, we also evaluate reservoir fluid inflows from a reservoir to fracture walls and further along a fracture to limited-size wellbore perforations. Solution of a productivity problem at the finest scale allows us to accurately evaluate key productivity characteristics: productivity index, dimensional and dimensionless effective conductivity, skin factor, and folds of increase, as well as the total production rate at any day and for any pressure drawdown in a well during well production life. We develop a workflow to understand how productivity of a fracture depends on variation of the pumping schedule and facilitate taking appropriate decisions about the best job design. The presented workflow gives insight into how new computationally efficient methods can enable fast, convenient, and accurate evaluation of the material placement design for maximum production with cost-saving channel fracturing technology.

Efficient Localized Nonlinear Solution Strategies for Unconventional-Reservoir Simulation with Complex Fractures

2021 ◽  
Author(s):  
Jiamin Jiang
Keyword(s):  
Transient Flow ◽  
A Priori ◽  
Time Discretization ◽  
Unconventional Reservoirs ◽  
Hydraulic Fractures ◽  
Nonlinear Solution ◽  
Compositional Model ◽  
Simulation Speed ◽  
Flow Mechanisms ◽  
Solution Accuracy

Abstract It is very challenging to simulate unconventional reservoirs efficiently and accurately. Transient flow can last for a long time and sharp solution (pressure, saturation, compositions) gradients are induced because of the severe permeability contrast between fracture and matrix. Although high-resolution models for well and fracture are required to achieve adequate resolution, they are computationally too demanding for practical field models with many stages of hydraulic fracture. The paper aims to innovate localization strategies that take advantage of locality on timestep and Newton iteration levels. The strategies readily accommodate to complicated flow mechanisms and multiscale fracture networks in unconventional reservoirs. Large simulation speed-up can be obtained if performing localized computations only for the solution regions that will change. We develop an a-priori method to exploit the locality, based on the diffusive character of the Newton updates of pressure. The method makes adequate estimate of the active computational gridblock for the next iterate. The active gridblock set marks the ones need to be solved, and then the solution to local linear system is accordingly computed. Fully Implicit Scheme is used for time discretization. We study several challenging multi-phase and compositional model cases with explicit fractures. The test results demonstrate that significant solution locality of variables exist on timestep and iteration levels. A nonlinear solution update usually has sparsity, and the nonlinear convergence is restricted by a limited fraction of the simulation model. Through aggressive localization, the proposed methods can prevent overly conservative estimate, and thus achieve significant computational speedup. In comparison to a standard Newton method, the novel solver techniques achieve greatly improved solving efficiency. Furthermore, the Newton convergence exhibits no degradation, and there is no impact on the solution accuracy. Previous works in the literature largely relate to the meshing aspect that accommodates to horizontal wells and hydraulic fractures. We instead develop new nonlinear strategies to perform localization. In particular, the adaptive DD method produces proper domain partitions according to the fluid flow and nonlinear updates. This results in an effective strategy that maintains solution accuracy and convergence behavior.

scholarly journals Analysis of the cladding melt relocation along the surface of the fuel pin with help of the SAFR module

2021 ◽  
Vol 2057 (1) ◽  
pp. 012126
Author(s):  
E V Usov ◽  
P D Lobanov ◽  
I A Klimonov ◽  
T V Sycheva ◽  
V I Chuhno ◽  
...  
Keyword(s):  
Flow Regime ◽  
Good Accuracy ◽  
Film Flow ◽  
Main Flow ◽  
Heated Part ◽  
Laminar Film ◽  
Fuel Pin

Abstract The presented work is dedicated to the development of approaches to simulate cladding melt relocation along the surface of the fuel pin. Development of the approaches is based on the results of the experiments carried out at the NSI RAS and IT SB RAS. Features of the melt relocation are studied in the experiments. It is demonstrated that the laminar film flow regime in the heated part of the fuel simulator is the main flow regime. Model of the melt relocation is constructed. This model is the part of the SAFR module of the EUCLID/V2 coupled code. It is shown that the proposed approaches allow simulating the melt relocation with good accuracy.

Unique Fall Off Signatures for Stage Fracture Characterization, Actual Field Cases

2021 ◽  
Author(s):  
Ahmed Farid Ibrahim ◽  
Mazher Ibrahim ◽  
Matt Sinkey ◽  
Thomas Johnston ◽  
Wes Johnson
Keyword(s):  
Flow Regime ◽  
Surface Area ◽  
Fiber Optics ◽  
In Situ Stress ◽  
Tensile Fracture ◽  
Finite Conductivity ◽  
Well Performance ◽  
Fracture Geometry ◽  
Fracture Conductivity ◽  
Diagnostic Plots

Abstract Multistage hydraulic fracturing is the common stimulation technique for shale formations. The treatment design, formation in-situ stress, and reservoir heterogeneity govern the fracture network propagation. Different techniques have been used to evaluate the fracture geometry and the completion efficiency including Chemical Tracers, Microseismic, Fiber Optics, and Production Logs. Most of these methods are post-fracture as well as time and cost intensive processes. The current study presents the use of fall-off data during and after stage fracturing to characterize producing surface area, permeability, and fracture conductivity. Shut-in data (15-30 minutes) was collected after each stage was completed. The fall-off data was processed first to remove the noise and water hammer effects. Log-Log derivative diagnostic plots were used to define the flow regime and the data were then matched with an analytical model to calculate producing surface area, permeability, and fracture conductivity. Diagnostic plots showed a unique signature of flow regimes. A long period of a spherical flow regime with negative half-slope was observed as an indication for limited entry flow either vertically or horizontally. A positive half-slope derivative represents a linear flow regime in an infinitely conductive tensile fracture. The quarter-slope derivative was observed in a bilinear flow regime that represents a finite conductivity fracture system. An extended radial flow regime was observed with zero slope derivative which represents a highly shear fractured network around the wellbore. For a long fall-off period, formation recharge may appear with a slope between unit and 1.5 slopes derivative, especially in over-pressured dry gas reservoirs. Analyzing fall-off data after stages are completed provides a free and real-time investigation method to estimate the fracture geometry and a measure of completion efficiency. Knowing the stage properties allows the reservoir engineer to build a simulation model to forecast the well performance and improve the well spacing.

A Novel Design Method for Optimizing the Diverter Dosage in Hydraulic Fracturing Using Three-Dimensionally Printed Fractures

2021 ◽  
Author(s):  
Meng Wang ◽  
Mingguang Che ◽  
Bo Zeng ◽  
Yi Song ◽  
Yun Jiang ◽  
...  
Keyword(s):  
Shale Gas ◽  
Design Method ◽  
Pressure Rise ◽  
Horizontal Wells ◽  
Optimization Method ◽  
Darcy Law ◽  
Hydraulic Fractures ◽  
Fracture Conductivity ◽  
Fracture Simulation ◽  
3D Printed

Abstract Application of diversion agents in temporarily plugging fracturing of horizontal wells of shale has becoming more and more popular. Nevertheless, the studies on determining the diverter dosage are below adequacy. A novel approach based on laboratory experiments, logging data, rock mechanics tests and fracture simulation was proposed to optimizing the dosage of diversion agents. The optimization model is based on the classic Darcy Law. A pair of 3D-printed rock plates with rugged faces was combined to simulate the coarse hydraulic fractures with the width of 2.0 ~ 7.0 mm. The mixture of the diversion agents and slickwater was dynamically injected to simulate the fracture in Temco fracture conductivity system to mimic the practical treatment to temporarily plugging the fracture. The permeability of the temporary plugging zone in the 3D-printed fractures was measured in order to optimize the dosage of the selected diversion agents. The value of Pnet (also the value of ΔP in Darcy Formula) required for creation of new branched fractures was determined using the Warpinski-Teufel Failure Rules. The hydraulic fractures of target stages were simulated to obtain the widths and heights. The experimental results proved that the selected suite of the diversion agents can temporarily plug the 3D-printed fractures of 2.0 ~ 7.0 mm with blocking pressure up to 15 MPa. The measured permeability of the resulting plugging zones was 0.724 ~ 0.933 D (averaging 0.837 D). The value of Pnet required for creation of branched fractures in shale of WY area (main shale gas payzone of China) was determined as 0.4 ~ 15.6 MPa (averaging 7.9 MPa) which means the natural fractures and/or weak planes with approaching angle less than 70° could be opened to increase the SRV. The typical dosage of the diversion agents used for one stage of the horizontal wells (averaging TVD 3600 m) was calculated as 232 ~ 310 kg. The optimization method was applied to the design job of temporarily plugging fracturing of two shale gas wells. The observed surface pressure rise after injection of diversion agents was 0.6 ~ 11.7 MPa (averaging 4.7 MPa) and the monitored microseismic events of the test stages were 37% more than those of the offset stages.

What are the Dominant Flow Regimes During Carbon Dioxide Propagation in Shale Reservoirs’ Matrix, Natural Fractures and Hydraulic Fractures?

2021 ◽  
Author(s):  
Sherif Fakher ◽  
Youssef Elgahawy ◽  
Hesham Abdelaal ◽  
Abdulmohsin Imqam
Keyword(s):  
Carbon Dioxide ◽  
Viscous Flow ◽  
Flow Regime ◽  
Knudsen Diffusion ◽  
Flow Regimes ◽  
Hydraulic Fractures ◽  
Transition Flow ◽  
Pore Sizes ◽  
Thermodynamic Conditions ◽  
Shale Reservoirs

Abstract Carbon dioxide (CO2) injection in low permeability shale reservoirs has recently gained much attention due to the claims that it has a large recovery factor and can also be used in CO2 storage operations. This research investigates the different flow regimes that the CO2 will exhibit during its propagation through the fractures, micropores, and the nanopores in unconventional shale reservoirs to accurately evaluate the mechanism by which CO2 recovers oil from these reservoirs. One of the most widely used tools to distinguish between different flow regimes is the Knudsen Number. Initially, a mathematical analysis of the different flow regimes that can be observed in pore sizes ranging between 0.2 nanometer and more than 2 micrometers was undergone at different pressure and temperature conditions to distinguish between the different flow regimes that the CO2 will exhibit in the different pore sizes. Based on the results, several flow regime maps were conducted for different pore sizes. The pore sizes were grouped together in separate maps based on the flow regimes exhibited at different thermodynamic conditions. Based on the results, it was found that Knudsen diffusion dominated the flow regime in nanopores ranging between 0.2 nanometers, up to 1 nanometer. Pore sizes between 2 and 10 nanometers were dominated by both a transition flow, and slip flow. At 25 nanometer, and up to 100 nanometers, three flow regimes can be observed, including gas slippage flow, transition flow, and viscous flow. When the pore size reached 150 nanometers, Knudsen diffusion and transition flow disappeared, and the slippage and viscous flow regimes were dominant. At pore sizes above one micrometer, the flow was viscous for all thermodynamic conditions. This indicated that in the larger pore sizes the flow will be mainly viscous flow, which is usually modeled using Darcy's law, while in the extremely small pore sizes the dominating flow regime is Knudsen diffusion, which can be modeled using Knudsen's Diffusion law or in cases where surface diffusion is dominant, Fick's law of diffusion can be applied. The mechanism by which the CO2 improves recovery in unconventional shale reservoirs is not fully understood to this date, which is the main reason why this process has proven successful in some shale plays, and failed in others. This research studies the flow behavior of the CO2 in the different features that could be present in the shale reservoir to illustrate the mechanism by which oil recovery can be increased.

scholarly journals Electrothermal Averaged Model of a Diode-Transistor Switch Including IGBT and a Rapid Switching Diode

Energies ◽  
2020 ◽  
Vol 13 (12) ◽  
pp. 3033 ◽  
Author(s):  
Paweł Górecki ◽  
Krzysztof Górecki
Keyword(s):  
Steady State ◽  
Integrated Circuit ◽  
Good Accuracy ◽  
Bipolar Transistor ◽  
Transistor Switch ◽  
Insulated Gate Bipolar Transistor ◽  
Self Heating ◽  
Proposed Model ◽  
Rapid Switching ◽  
Averaged Model

This study proposes an electrothermal averaged model of the diode–transistor switch including insulated gate bipolar transistor (IGBT) and a rapid switching diode. The presented model has the form of subcircuits dedicated for simulation program with integrated circuit emphasis (SPICE) and it makes it possible to compute characteristics of DC–DC converters at the steady state considering self-heating phenomena, both in the diode and in IGBT. This kind of model allows computations of voltages, currents and internal temperatures of all used semiconductor devices at the steady state. The formulas used in this model are adequate for both: continuous conducting mode (CCM) and discontinuous conducting mode (DCM). Correctness of the proposed model is verified experimentally for a boost converter including IGBT. Good accuracy in modeling these converter characteristics is obtained.

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