Transient Wellbore Research Articles

Integrated wellbore-reservoir-geomechanics modeling for enhanced interpretation of distributed fiber-optic strain sensing data in hydraulic-fracture analysis

Fiber-optic distributed strain sensing (FO-DSS) has been successful in monitoring strain changes along horizontal wellbores in hydraulically fractured reservoirs. However, the mechanism driving the various FO-DSS responses associated with near-wellbore hydraulic fracture properties is still unclear. To address this knowledge gap, we use coupled wellbore-reservoir-geomechanics simulations to study measured strain-change behavior and infer hydraulic fracture characteristics. The crossflow among fractures is captured through explicit modeling of the transient wellbore flow. In addition, local grid refinement is applied to accurately capture strain changes along the fiber. A Base Case model was designed with four fractures of varying properties, simulating strain change signals when the production well is shut-in for 10 d after 240 d of production and reopened for 2 d. Strain-pressure plots for different fracture clusters were used to gain insights into inferring fracture properties using DSS data. When comparing the model with and without the wellbore, distinct strain change signals were observed, emphasizing the importance of incorporating the wellbore in FO-DSS modeling. The effects of fracture spacing and matrix permeability on strain change signals were thoroughly investigated. The results of our numerical study can improve the understanding of the relation between DSS signals and fracture hydraulic properties, thus maximizing the value of the dataset for fracture diagnostics and characterization.

Fully transient coupled prediction model of wellbore temperature and pressure for multi-phase flow during underbalanced drilling

Considering gas-liquid-solid three-phase flow and heat transfer, the accurate simulation of wellbore temperature and pressure profile while underbalanced drilling (UBD) has been predicted significantly in deep well drilling. Firstly, the research presents a fully transient coupled prediction model of wellbore temperature and pressure field and the thermophysical properties of circulating fluid are taken into consideration, and a double-cycle iterative algorithm for the axial and radial coupled solution of wellbore temperature and pressure is proposed. The model is discretized by using the finite volume method and is verified by the two-phase flow temperature and pressure data from the Louisiana full-size experiments. Then, qualitatively and quantitatively comparisons with water-based mud (WBM) and oil-based mud (OBM) to analyze the coupled variation of transient wellbore temperature and pressure. The sensitivity analysis between WBM and OBM is carried out and WBM is more sensitive to the thermophysical properties compared with OBM. Finally, the feasibility study of calculating bottom-hole pressure according to simple linear temperature is launched. It is found that the average of formation temperature and linear cyclic temperature (AFLT) model that a simplification of the temperature model due to the approximate method is more accurate and convenient between WBM and OBM. This research on wellbore temperature and pressure profile intuitively understands the complex problems of wellbore multi-phase flow, and further provides a theoretical reference for controlling well kick and extending to horizontal, highly deviated well and geothermal wells.

High-precision nonisothermal transient wellbore drift flow model suitable for the full flow pattern domain and full dip range

A reliable multiphase flow simulator is an important tool to improve wellbore integrity and production decision-making. To develop a multiphase flow model with high adaptability and high accuracy, we first build a multiphase flow database with 3561 groups of data and developed a drift closure relationship with stable continuity and high adaptability. Second, a high-order numerical scheme with strong fault capture ability is constructed by effectively combining MUSCL technology, van Albada slope limiter and AUSMV numerical scheme. Finally, the energy equation is coupled into the AUSMV numerical scheme of the drift flow model in the form of finite difference. A transient non-isothermal wellbore multiphase flow model with wide applicability is formed by integrating the three technologies, and the effects of various factors on the calculation accuracy are studied. The accuracy of the simulator is verified by comparing the measurement results with the blowout experiment of a full-scale experimental well.

Techno-economic coupling model of U-shaped closed-loop geothermal system

Recently, geothermal energy has gained attention from researchers and enterprises as a form of clean energy with zero carbon emissions. U-shaped closed-loop geothermal system (UCLGS) shows great application potential because of its unique well structure. However, there is a big debate on whether they can be economic because no economic evaluation model is available. The method of net present value (NPV) is used in this study to establish a techno-economic coupling model of UCLGS. The proposed model was applied and analyzed in a UCLGS in Xi'an, China. The results indicate the following. (a) The fully implicit transient wellbore heat transfer model established in this study is in good agreement with the field test data, and the relative error is <6%. (b) The outlet temperature and heat extraction power increase with the increase in the horizontal section length, but the rate of increase slows down; the longer the horizontal section length, the higher the drilling cost. The proposed techno-economic model can be used to design an optimal horizontal section length of UCLGS. (c) The service life, government financial subsidies, and drilling costs have a great impact on the profitability of UCLGS projects.

Solution and Analysis of Wellbore Temperature and Pressure Field Coupling Model under Lost Circulation.

The fluid in the annulus is in a variable mass flow state under the lost circulation condition, significantly affecting wellbore pressure distribution and the heat transfer efficiency between wellbore and formation. Therefore, based on the hydrodynamics and energy conservation law, a coupling model of transient wellbore temperature and pressure field under lost circulation conditions is established, which fully considers the casing program, bottom hole assembly, and heat source generated in drilling, as well as the influence of the temperature and pressure coupling in wellbore on the physical parameters of drilling fluid. The calculation results of the model in this paper are in good agreement with the field measured data and the previous research results, which verifies the rationality and accuracy of the model in this paper. The effects of the loss rate and the lost circulation zone location on the wellbore temperature and pressure distribution are analyzed, and the variation rule of the physical parameters of drilling fluid under the lost circulation condition is studied. The numerical simulation results show that the density and viscosity of drilling fluid in the annulus and bottom hole pressure increase with the increase in the circulation time; the annulus temperature decreases gradually with the increase in cycle time and tends to become stable after 8 h of the cycle. The annulus temperature and bottom hole pressure decrease with the increase in loss rate and closeness of the loss zone to the well bottom. When the loss zone is in the upper open-hole section, an inflection point consistent with the location of the loss zone appears on the annular temperature difference curve between the loss circulation and the nonloss circulation, and the position of the loss zone can be judged according to the inflection point.

A new two-dimensional transient forecast model of wellbore temperature based on precise time step integration method

Dramatic temperature changes in the wellbore can lead to the severe deformation and breakage of the wellbore string, packer seal malfunction, and other operational accidents. A new two-dimensional (2D) transient forecast model of the wellbore temperature is established to provide accurate temperature parameters for the precision mechanical analysis of the wellbore string and the safety evaluation of well integrity. Furthermore, a precise time step integration scheme of the forecast model using the precise time step integration method of a one-point subdomain is proposed. A solution method for the 2D transient forecast model of the wellbore temperature is proposed by combining the precise time step integration method. Finally, a case study focused on a high-temperature deep gas well with a transient wellbore temperature is presented by comparing the calculation results of the different models and solution methods. The sensitivity analysis of the wellbore temperature is performed as well. The results indicate that the forecast model in this paper has higher accuracy than the existing two-dimensional transient model. By contrast analysis of the finite difference method and the solution method that combines the precise time step integration method, the solution method has the advantages of better convergence and faster calculation speed. The major sensitive parameters that affect the stability time of wellbore temperature are ranked as follows: gas production rate, tubing size, specific heat, temperature gradient, gas relative density, and thermal conductivity. The work presented can provide a theoretical foundation and technological basis for the transient forecast of the wellbore temperature, which is critical for well completion design and wellbore safety evaluation.

Wellbore multiphase flow behaviors during gas invasion in deepwater downhole dual-gradient drilling based on oil-based drilling fluid

Knowledge of wellbore multiphase flow characteristics is important for early gas invasion identification and treatment, especially in oil-based drilling fluid. The wellbore multiphase flow law in downhole dual-gradient drilling (DDGD) is more complex than that in conventional single-gradient drilling. There was no relevant literature report at present. In this paper, considering the synergistic feedback relationship of multiphase flow, interphase mass transfer, and wellbore temperature, a fully transient wellbore multiphase flow model was established based on oil-based drilling fluid in deepwater DDGD. The model also coupled the variable temperature–mass flows caused by the dynamic transfer of hollow glass balls and formation gas. The bubble interface mass transfer theory was adopted to describe the interphase mass transfer rate. The model was verified through the experimental measurement data. The calculated results indicated that the dynamic transfer of hollow glass balls varied the wellbore pressure gradient and flow rate in DDGD, resulting in a sudden decrease in gas fraction and gas solubility along the flow direction at the separator. Additionally, the transient interphase mass transfer and wellbore temperature had large impact on the wellbore multiphase flow behaviors. Moreover, the model based on bubble interface mass transfer theory could more accurately characterize the development of the wellbore multiphase flow. This research could provide a certain theoretical basis for the detection and treatment of gas invasion in deepwater DDGD.

Unsteady model for wellbore pressure transmission of carbon dioxide fracturing considering limited-flow outlet

The outlet flow rate is limited during CO2 fracturing, which significantly affects the CO2 property distribution and pressure transmission in the wellbore. In this paper, a transient wellbore flow model with a limited-flow outlet is developed to simulate the pressurization process of CO2 injection, which incorporates the compressible fluid flow governing equations, CO2 compressibility, and wellbore heat transfer. The calculation results show a good accordance with field data. The results show that the wellbore pressure and pressurization rate increase gradually with CO2 injecting under a constant inlet pump rate, and the variations in CO2 crucial properties are dominated by borehole pressurization with time increasing. Regarding the two injection patterns, a larger pressurization rate can be obtained under a lower inlet pump rate for tubing injection, while the friction pressure loss can be effectively reduced for commingled injection. Moreover, the pressurization rate increases with inlet pump rate, but also the frictional ratio and its growth rate, hence, the inlet pump rate should not be excessive. Furthermore, the inlet pressure must exceed a lower limit to prevent CO2 from gasifying, which is 4.52 MPa under the calculation condition. The model can provide more insights for the design, control, and optimization of CO2 fracturing.

Transient non-isothermal coupled wellbore-reservoir modeling of CO2 injection — Application to CO2 injection tests at the CaMI FRS site, Alberta, Canada

We investigate the dynamics of a CO2 injection wellbore using a fully-coupled non-isothermal transient multiphase wellbore-reservoir flow model. The focus of this study is on the transient behavior of the wellbore parameters in injection tests undertaken at the CaMI Field Research Station (FRS) in Alberta, Canada. Wellbore transient pressure and temperature and subsequent CO2 phase behavior through the wellbore were analyzed, and the impacts of the reservoir parameters on the wellbore transient flow behavior are characterized. Our results show that the presence of gas-liquid transient flow in the wellbore and the subsequent liquid CO2 build-up in the wellbore significantly increases the bottom hole pressure. The results show that the mean permeability of the target formation layer represents the most important controlling effect on the wellbore transient functions. We used the concepts and understanding developed through the wellbore flow dynamics characterization and the sensitivity analysis to redesign injection tests to control the CO2 wellbore transient flow. We also performed history-matching of the injection tests to examine various combinations of porosity and permeability multipliers in an attempt to match the historical pressure and temperature data obtained during the CO2 injection tests. The outcomes of this study provide an improved understanding of the transient wellbore behavior during CO2 injection over certain pressure-temperature ranges. Results developed here may be used to monitor the injection performance, well and reservoir responses under different injection scenarios.

Prediction of transient wellbore cement circulating temperature distribution using CFD simulation

Accurate prediction of the cement slurry temperature while being circulated downhole is critical for a successful cement job. Failure to predict the cement slurry temperature correctly may result in premature or delayed cement setting. Due to the practical limitations of using temperature sensors for direct measurement and the complexity of the bottomhole circulating conditions, it is difficult to gather accurate information about how the temperature of cement slurry changes as it is being circulated through the well. To overcome these challenges and help with designing a cement system more accurately, a computational fluid dynamics (CFD) model is developed. The model simulates the balanced-plug cementing operation, which considers the continuous displacement of the drilling fluid by the cement slurry and the cement slurry by water. The CFD model predicts the transient changes in the temperatures of the cement slurry and near wellbore formation during this displacement process involving three different fluids. A new dynamic mesh method was developed to effectively handle the interface mixing of different fluids, and thus model the three-fluid displacement process in the annulus more realistically. The CFD model can also deal with complex well conditions such as deviated wellbores, variable geothermal gradients and formation rock properties. Most importantly, in the absence of the measurements allowing direct monitoring of the downhole conditions, the new CFD model allows for continuous monitoring of downhole transient fluid and formation temperature at any position along the wellbore. The results of CFD transient simulations indicate that the bottomhole circulation temperature (BHCT) values predicted by using API method are significantly overestimated. The highest cement slurry temperature in the annulus was observed at some distance above the bottom of the well. Results also confirmed the existence of an equilibrium plane (extending horizontally) into the formation across which a temperature reversal was observed. The formations above and below the equilibrium plane have opposite heat transfer patterns. The depth of the equilibrium plane rises steadily while its temperature gradually decreases as the circulation continues. The change of the cement/drilling fluid interface temperature is traced dynamically. CFD simulation is proven to be a realistic and reliable approach for prediction of the cement circulating temperature and can be easily used in combination with real time operational data. Practical guidelines and solutions derived from the simulation results can be useful for improved cement job design in field applications.

Multi-Dimensional CFD Analysis for the Prediction of Transient Wellbore Circulating Temperature Profile to Guide Offshore Cementing Job

This study investigates how temperature profile changes with time during fluid circulation through the wellbore and annulus by using ANSYS Fluent, to help designing offshore cementing job in the petroleum industry. The use of two-dimensional nature of transient computational-fluid-dynamics (CFD) simulations shows that both flow rheology and fluid distribution in the well affect heat transfer calculations and such an effect is more pronounced at the bottom hole where the flow direction changes from downward to upward. When compared with one-dimensional (1D) simulation, multi-dimensional simulation results predict a longer time for heat transfer consistently, implying that simple 1D simulation techniques tend to under-predict the amount of time associated with cementing job. How fluid distribution within the well changes with time and how the resulting pressure and temperature calculations are affected at different times and locations are also visualized in this study.

Transient wellbore temperature and pressure calculation model for supercritical CO2 jet fracturing

ABSTRACT Supercritical carbon dioxide (SC-CO2) jet fracturing is a new technology, and it has many significant advantages compared with hydraulic fracturing. Ensuring the CO2 at supercritical state at the jet point is the key to the effective implementation of this technology. Therefore, this research proposes a numerical model to predict the jet point CO2 temperature and pressure for SC-CO2 jet fracturing. In this model, the effect of the tubing, casing, and cement sheath on heat transfer are all taken into consideration; the heat transfer is considered to be transient. The numerical results show that under the condition of high tubing injection rate, increase injection temperature and annulus injection rate both are not effective ways to make sure the CO2 temperature at the jet point exceeds its critical value. Therefore, in order to keep the CO2 at the jet point remains in a supercritical state, the tubing injection rate needs to be optimized. The CO2 pressure at the jet point is always exceeded its critical value during the process of supercritical carbon dioxide jet fracturing.

Integrated production optimisation and monitoring of multi-zone intelligent wells

Multi-zone intelligent wells (I-wells) completed with interval control valves and downhole sensors divide the well completion into a number of production intervals that can be managed individually. The production rate from these wells is optimised using either reactive or proactive control strategy. Zonal inflow property values are often used to estimate the zonal multi-phase flow rates (MPFRs) to inform such control strategies. Real-time measurements of the zonal downhole pressure and temperature can be used to estimate the zonal MPFRs, which are considered the main input information to production optimisation algorithms. This paper presents an integrated control and monitoring (ICM) algorithm to maximise production from multi-zone I-wells. The algorithm includes two-level optimisation to design optimum number of required flow tests and optimise either reliability of estimated zonal production (monitoring) or oil production (control). An in-house optimiser has been developed to initiate the required flow tests to perform the ICM workflow, while active soft-sensing algorithm is used to design further flow tests required either to maximise the reliability of estimated zonal properties or maximise oil production. The algorithm was validated using a commercial transient wellbore simulator OLGA™ in which a five-zone intelligent well was modelled. The simulator results were used as inputs into the ICM algorithm to test the applicability of proposed workflow. Two different workflows of ICM and MPFR were compared in this synthetic case study, and both workflows achieve satisfactory estimates of the zonal properties. However, the ICM workflow attempts to achieve the maximum oil production with a reduced number of flow tests and results in higher cumulative oil production compared to the MPFR workflow. This confirmed that there is a potential to monitor and control zonal production simultaneously with less flow tests in comparison with applying a separate control and monitoring approach. The findings of this study showed it is not necessary to have the accurate estimation of zonal properties in order to maximise the oil production from a multi-zone I-well. The proposed ICM algorithm can also be applied in multi-well flow rate allocation of an interest production system network and optimisation of start-up of multi-zone I-wells.

Analysis of Transient Flow to an Extended Fully Penetrating Well at Constant-Head Pumping.

Vertical wells with radial extension at the well bottom can improve the rate of water production. No study has yet investigated the effects of the transient state and anisotropy in directional hydraulic conductivities on the wellbore flux rate for this type of well. This study derives a semianalytical transient drawdown solution for constant-head pumping at a fully penetrating well radially extended at the bottom of a confined, anisotropic aquifer by applying Laplace transform and separation of variables as well as conducting a Fourier analysis. The results of this new solution indicate that transient and steady-state wellbore flux rates can be increased by a factor of two for greater radial extension of the well. Compared with an isotropic aquifer (a ratio of vertical and horizontal hydraulic conductivities equal to one), an anisotropic aquifer with the ratio less than one may produce a higher transient wellbore flux rate and lower steady-state wellbore flux rate. Moreover, the time required to achieve the steady-state wellbore flux rate can be substantially affected by anisotropy of the aquifer.

A Coupled Transient Wellbore/Reservoir-Temperature Analytical Model

Summary This work presents a new coupled transient wellbore/reservoir thermal analytical model, consisting of a combined reservoir/casing/tubing system. The analytical model considers flow of a slightly compressible, single–phase fluid in a homogeneous infinite–acting reservoir system and provides temperature–transient data for drawdown and buildup tests at any gauge location along the wellbore. The model accounts for Joule–Thomson (J–T), adiabatic–fluid–expansion, conduction, and convection effects. The wellbore–fluid mass density is modeled as a function of temperature, and the analytical solution makes use of the Laplace transformation to solve the transient heat–flow differential equation, accounting for a transient wellbore–temperature gradient ∂T/∂z. The solutions presented assume moderate– to high–permeability reservoirs and do not consider skin effects in the formation. Results of the analytical model are compared with those of a commercial thermal simulator and with those of available models in the literature. Our model provides more accurate transient–temperature–flow profiles along the wellbore in comparison with previous analytical models in the literature. Furthermore, a generalization of a well–known parameter–estimation method from transient–temperature data is provided.

A New Fracture-Unit Model and Its Application to a Z-Fold Fracture

Summary Following the Cinco-Ley fracture model (Cinco-Ley et al. 1978) and the Luo-Tang wing model (Luo and Tang 2015a), we developed a new fracture-unit model. By coupling the Fredholm integral equation for a fracture with a reservoir equation, we present a new semianalytical method in the Laplace domain, and an example of a Z-fold fracture is then presented to demonstrate the applicability of the fracture-unit model. The effects of fracture conductivity, fracture geometry, and branch length on the transient wellbore pressure are discussed in detail. Our work provides a novel forward model to implement the law of fluid flow in complex fractures.

Transient Coupling of Swab/Surge Pressure and In-Situ Stress for Wellbore-Stability Evaluation During Tripping

Summary This paper identifies wellbore-stability concerns caused by transient swab/surge pressures during deepwater-drilling tripping and reaming operations. Wellbore-stability analysis that couples transient swab/surge wellbore-pressure oscillations and in-situ-stress field oscillations in the near-wellbore (NWB) zone in deepwater drilling is presented. A transient swab/surge model is developed by considering drillstring components, wellbore structure, formation elasticity, pipe elasticity, fluid compressibility, fluid rheology, and the flow between wellbore and formation. Real-time pressure oscillations during tripping/reaming are obtained. On the basis of geomechanical principles, in-situ stress around the wellbore is calculated by coupling transient wellbore pressure with swab/surge pressure, pore pressure, and original formation-stress status to perform wellbore-stability analysis. By applying the breakout failure and wellbore-fracture failure in the analysis, a work flow is proposed to obtain the safe-operating window for tripping and reaming processes. On the basis of this study, it is determined that the safe drilling-operation window for wellbore stability consists of more than just fluid density. The oscillation magnitude of transient wellbore pressure can be larger than the frictional pressure loss during the normal-circulation process. With the effect of swab/surge pressure, the safe-operating window can become narrower than expected. The induced pore pressure decreases monotonically as the radial distance increases, and it is limited only to the NWB region and dissipates within one to two hole diameters away from the wellbore. This study provides insight into the integration of wellbore-stability analysis and transient swab/surge-pressure analysis, which is discussed rarely in the literature. It indicates that tripping-induced transient-stress and pore-pressure changes can place important impacts on the effective-stress clouds for the NWB region, which affect the wellbore-stability status significantly.

Predictive model for bottomhole pressure based on machine learning

The objective of this work is to develop a predictive model for multiphase wellbore flows using the machine learning approach. The artificial neural network is developed and then trained on the dataset generated using the numerical simulator of the full-scale transient wellbore flows. After the training is completed, the neural network is used to predict one of the key parameters of the wellbore flow, namely, the bottomhole pressure. The novelty of this work is related to the application of the neural network to analyze highly transient processes taking place in wellbores. In such processes, most of the parameters of interest can be represented by interdependent time series of variables linked through complex physical phenomena pertinent to the nature of multiphase flows. The proposed neural network with two hidden layers demonstrated the capability to predict the bottomhole pressure within 5% of the normalized root mean squared error for many complex wellbore configurations and flows. It is also shown that relatively higher prediction errors are mainly observed in the case of slug flows where the transient nature of flows is pronounced the most. Finally, the developed model is tested on data affected by noise. It is demonstrated that although the error of prediction slightly increases in contrast to the data without noise, the model captures essential features of the studied transient process. Description of the developed models, analysis of various test use cases, and possible future research directions are outlined.

Liquid loading in gas wells: From core-scale transient measurements to coupled field-scale simulations

Liquid loading is a major operational constraint in mature gas fields around the world. It manifests itself as an increasing back pressure on the reservoir due to a rising liquid column in the well, which initially decreases deliverability, then ultimately causes the gas well to cease production. Theoretically, every gas well will experience this debilitating phenomenon in the latter stages of its producing life.In this paper, both laboratory experiments and numerical simulations are presented to shed more light on the physical process of liquid loading, with a focus on reservoir responses. On the one hand, core-flooding experimental setups of different scales were designed and constructed to investigate back pressure effects on transient flow through the near-wellbore region of the reservoir. On the other hand, the modelling of a gas well undergoing controlled flow and shut-in cycles was performed to validate core-scale observations at reservoir scale, using commercial integrated numerical software that connects a transient wellbore model to a transient reservoir model. The simulated transient characteristics of short-term downhole dynamics (e.g. liquid re-injection and co-current/counter-current flows) supported the U-shaped concept observed in the experiments.The detected temporal distribution of pore fluid pressure within the reservoir medium itself (referred to as the U-shaped pressure profile) was observed both experimentally at the core-scale and numerically at the reservoir-scale. This pressure distribution can be used to explain re-injection of the denser phases into the near-wellbore region of the reservoir.

Temperature Behavior During Multistage Fracture Treatments in Horizontal Wells

Summary Downhole temperature measured by distributed-temperature sensors (DTSs) shows distinct response to injection and shut-in during multistage fracture treatments in horizontal wells. A thermal model predicting temperature distribution along the wellbore is essential to use the DTS technology to quantitatively diagnose fracture treatments. With inversion, the model can be used to translate downhole-temperature measurement to downhole flow distribution, and therefore to estimate fracture efficiency. In this paper, we present a thermal/flow model that predicts temperature distribution in a system that contains reservoir, wellbore, and fractures during fracture propagation and after well shut-in. We coupled a wellbore-flow model with a simple fracture-propagation model to predict fracture half-length and fluid distribution. For a single-stage fracture treatment, a transient wellbore thermal model is coupled with the fracture and formation thermal models, which are derived from the energy-conservation equations. A sequential simulation method is then applied for multistage fracture treatments by considering the treatment schedule. The full model has three modes: no fracture, fracture propagation, and warm back for shut-in. The full model is used to simulate the stage that is under fracturing. Once the fracture pumping is finished, warm back of the entrained fracture fluid during shut-in periods is simulated by removing the convection term and implementing the corresponding boundary conditions. Numerical solutions are necessary for time-dependent fluid loss and complex nonlinear heat exchange. Mass- and energy-conservation equations are solved by use of the fully implicit finite-difference approach for the conjoint gridding system. The results of the fracture and formation model are verified by analytical solutions for simplified cases. This paper provides synthetic case studies in a low-permeability reservoir by use of the integrated model. The influences of fluid distribution, fluid loss caused by natural and induced fractures, DTS-deployment locations, and reservoir-heat-transfer parameters on temperature behavior are investigated. At the creation and propagation of fractures, injection flow rate (convection) plays an important role on fracture propagation and leakoff front movements. Heat conduction is the dominant mechanism governing temperature response during shut-in. By use of the algorithm for single-stage treatment, a work flow for multistage fracture simulation is created by performing a single-stage stimulation, shutting in the stage, and moving to the next stage along the wellbore. For a shale reservoir, the time frame to reach thermal equilibrium is on the order of weeks, and this gives the possibility to identify the flow-rate distribution from temperature measurements. Sensitivity of fluid distribution, fluid loss, DTS fiber-cable locations for different completion methods, and reservoir parameters is examined, which helps us to understand temperature behavior for fracture diagnosis by use of DTS data during stimulation operations. The methodology developed in this work can be a complementary component to a model that predicts temperature behavior during production to provide better boundary conditions, and it can also be a standalone tool to analyze fracturing-fluid distribution.