We study CO2 injection into a saline aquifer intersected by a tectonic fault using a coupled modeling approach to evaluate potential geomechanical risks. The simulation approach integrates the reservoir and mechanical simulators through a data transfer algorithm. MUFITS simulates non-isothermal multiphase flow in the reservoir, while FLAC3D calculates its mechanical equilibrium state. We accurately describe the tectonic fault, which consists of damage and core zones, and derive novel analytical closure relations governing the permeability alteration in the fault zone. We estimate the permeability of the activated fracture network in the damage zone and calculate the permeability of the main crack in the fault core, which opens on asperities due to slip. The coupled model is applied to simulate CO2 injection into synthetic and realistic reservoirs. In the synthetic reservoir model, we examine the impact of formation depth and initial tectonic stresses on geomechanical risks. Pronounced tectonic stresses lead to inelastic deformations in the fault zone. Regardless of the magnitude of tectonic stress, slip along the fault plane occurs, and the main crack in the fault core opens on asperities, causing CO2 leakage out of the storage aquifer. In the realistic reservoir model, we demonstrate that sufficiently high bottomhole pressure induces plastic deformations in the near-wellbore zone, interpreted as rock fracturing, without slippage along the fault plane. We perform a sensitivity analysis of the coupled model, varying the mechanical and flow properties of the storage layers and fault zone to assess fault stability and associated geomechanical risks.

We propose a new method for construction of the absolute permeability map consistent with the interpreted results of well logging and well test measurements in oil reservoirs. Nadaraya-Watson kernel regression is used to approximate two-dimensional spatial distribution of the rock permeability. Parameters of the kernel regression are tuned by solving the optimization problem in which, for each well placed in an oil reservoir, we minimize the difference between the actual and predicted values of (i) absolute permeability at the well location (from well logging); (ii) absolute integral permeability of the domain around the well and (iii) skin factor (from well tests). Inverse problem is solved via multiple solutions to forward problems, in which we estimate the integral permeability of reservoir surrounding a well and the skin factor by the surrogate model. The last one is developed using an artificial neural network trained on the physics-based synthetic dataset generated using the procedure comprising the numerical simulation of bottomhole pressure decline curve in reservoir simulator followed by its interpretation using a semi-analytical reservoir model. The developed method for reservoir permeability map construction is applied to the available reservoir model (Egg Model) with highly heterogeneous permeability distribution due to the presence of highly-permeable channels. We showed that the constructed permeability map is hydrodynamically similar to the original one. Numerical simulations of production in the reservoir with constructed and original permeability maps are quantitatively similar in terms of the pore pressure and fluid saturations distribution at the end of the simulation period. Moreover, we obtained an good match between the obtained results of numerical simulations in terms of the flow rates and total volumes of produced oil, water and injected water.

Rheological experiments and measurements of particle settling velocity under static conditions were conducted for two types of polyacrylamide (PAA-based) fluids. The flow behavior of the viscoelastic fluids is described by a simplified, three-parameter model that integrates a constant viscosity at low shear rates with a power-law viscosity dependency at higher shear rates. The estimated dependencies of the rheological parameters and particle settling velocity on PAA concentration align with the classical power-law scaling for semi-dilute polymer solutions. The identified scaling offers valuable insight for optimizing the chemical composition of fracturing fluids, thereby improving the efficiency of hydraulic fracturing technology. By applying the lubrication approximation to the Navier-Stokes equations, a set of equations for the suspension flow in a vertical plane channel, characterized by the three-parameter rheology model, was derived. In typical fracturing conditions, the conventional power-law viscosity model used in current fracturing simulators significantly overestimates the gap-averaged apparent fluid viscosity compared to the proposed model. The novel model of the suspension flow aims to enhance the accuracy of proppant transport models applied in hydraulic fracturing simulators. Based on the three-parameter rheology model, a new model of particle settling in the studied PAA-based fluids is developed. It is based on smart Stokes' law, where viscosity is calculated according to either the plateau or power-law region, depending on the self-induced shear rate. The new model more accurately approximates experimentally determined settling velocity of proppant under static conditions across a broad range of PAA concentrations than existing models.

The key goal of the work is to optimize the process of flowback in wells after multi-stage hydraulic fracturing in fields with unconventional oil reserves. The procedure for selecting the optimal flowback operation is to tune the model based on field data, adapt the fracture cleanup model using sensitivity analysis on input parameters, and select the most effective scenario of bottomhole pressure decreasing. This article can be separated into three parts. The first one consists cleanup model description. The second one shows sensitivity analysis of the results of flowback modeling with respect to key input parameters. The last one includes optimization and history matching methods to fit the modeling and field data. Model adaptation to field data is carried out using iterative Newton's method (MSE < 10

The paper is devoted to the development of a surrogate model describing Hydraulic Fracture (HF) flowback, which is a short time period after the start of an oil or gas well, during which it is cleaned out of fracturing fluid and set for a long-term production. The model is based on the combination of the in-house mechanistic model and Machine Learning (ML) algorithms. The mechanistic flowback model describes the dynamics of fracture conductivity during the cleanup, considering several hydro- and geomechanical effects. We conducted a series of computations to assemble the synthetic dataset consisting of 10 000 runs covering the range of input parameters typical for Western Siberia’s conventional terrigenous oil reservoirs. We obtained that the constructed surrogate model is sufficiently accurate at solving the forward problem in terms of the Mean Absolute Percentage Error (MAPE) metric showing the difference between the results acquired by the metamodel and the mechanistic simulator. In particular, we obtained MAPE of 5.12

The aim of this study is to create a fast and stable iterative technique for numerical solution of a quasi-linear elliptic pressure equation. We developed a modified version of the Anderson acceleration (AA) algorithm to fixed-point (FP) iteration method. It computes the approximation to the solutions at each iteration based on the history of vectors in extended space, which includes the vector of unknowns, the discrete form of the operator, and the equation's right-hand side. Several constraints are applied to AA algorithm, including a limitation of the time step variation during the iteration process, which allows switching to the base FP iterations to maintain convergence. Compared to the base FP algorithm, the improved version of the AA algorithm enables a reliable and rapid convergence of the iterative solution for the quasi-linear elliptic pressure equation describing the flow of particle-laden yield-stress fluids in a narrow channel during hydraulic fracturing, a key technology for stimulating hydrocarbon-bearing reservoirs. In particular, the proposed AA algorithm allows for faster computations and resolution of unyielding zones in hydraulic fractures that cannot be calculated using the FP algorithm. The quasi-linear elliptic pressure equation under consideration describes various physical processes, such as the displacement of fluids with viscoplastic rheology in a narrow cylindrical annulus during well cementing, the displacement of cross-linked gel in a proppant pack filling hydraulic fractures during the early stage of well production (fracture flowback), and multiphase filtration in a rock formation. We estimate computational complexity of the developed algorithm as compared to Jacobian-based algorithms and show that the performance of the former one is higher in modelling of flows of viscoplastic fluids. We believe that the developed algorithm is a useful numerical tool that can be implemented in commercial simulators to obtain fast and converged solutions to the non-linear problems described above.

The purpose of this study is to develop a model for the flow of suspensions consisting of Herschel-Bulkley fluid mixed with spherical particles. In particular, the focus is to investigate the effect of non- Newtonian rheology of the carrying fluid on the flow behavior of a suspension. Two-dimensional steady flow problem in a vertical channel is considered, in which both the pressure gradient and gravity drive the suspension flow. Dependence of the velocity profile and particle concentration across the channel on the fluid rheology parameters and orientation of the pressure gradient is investigated. It is found that the non-uniform particle distribution in the flow across the channel leads to the non-uniform density of the suspension, which causes sinkage of the denser regions and promotes downward migration of the particles even without slip velocity. Particle and suspension fluxes are calculated for various fluid rheologies and pressure gradient orientations. The effect of slip velocity between the phases is added via filtration term that captures fluid flow once particles reach the maximum concentration and stall, and via the settling term that describes gravitational particle settling.

CO2 injection into a saline aquifer crossed by a tectonic fault is studied with coupled fluid mechanics - geomechanics modeling. The simulation approach is based on coupling of the MUFITS reservoir simulator and the FLAC3D mechanical simulator via an in-house API (i.e., an algorithm for data transfer between simulators). MUFITS simulates the non-isothermal multiphase flow of CO2 and brine in rock formation accounting for phase transitions and thermal effects. The modeling workflow is sequential, so that hydrodynamical simulations are carried out at a certain time interval, after which pressure, temperature, and density distributions are passed to FLAC3D, which calculates the equilibrium mechanical state. Computed deformations and stresses are utilized to update the porosity and permeability fields for the subsequent hydrodynamic modeling. In particular, we focus on the tectonic fault and its behavior during CO2 injection. We distinguish the damage zone and core inside the fault and derive the closure relations for their permeability alteration analytically. The coupled approach developed here is applied to simulate CO2 injection into synthetic and realistic reservoir models. For the former one, we study the effect of formation depth and presence of the tectonic stresses at the initial mechanical state, while for the latter, we consider different injection modes (bottomhole pressure). In each numerical experiment, we describe the evolution of the fault permeability due to the slip along its plane and the development of plastic deformations leading to the loss of reservoir integrity and CO2 leakage. Sensitivity analysis of the coupled model to realistic values of input parameters to assess the fault stability is carried out.

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.

We evaluate the CO2 storage potential for the depositional environments of the West Siberian sedimentary basin. Particularly, we investigate the prospect of storing large volumes of CO2 in the alluvial fan, barrier island, deltaic, and fluvial environments. We employ several detailed 3-D models of petroleum reservoirs as proxies for the saline aquifers occurring in the basin under the listed environments. By simulating supercritical CO2 injection into several reservoir sectors, we compare the environments in terms of their prospects for the underground storage of CO2. We estimate the maximum capacity and storage potential for the entire sectors by considering them the resources licensed for an industrial-scale Carbon Capture and Storage (CCS) project. The scenarios with a single and multiple injection wells are assessed in the evaluation, which might be of interest for the elaboration of feasible regulations and policies in the area. We find out that the barrier island deposits are characterized by maximum potential, whereas the fluvial environments are the least suitable for deploying CCS. We demonstrate that for the barrier island environments, the storage potential is most sensitive to the relative permeability end-points. We also test several scaling concepts for extending our estimates for a single-well injection to a multi-well scenarios and generally from a site-specific to regional scale. We conclude that due to the interference between nearby wells, the storage potential for a single well scenario cannot reliably be scaled to the case of CO2 injection through a group of wells.

Summary We analyze pressure slopes during buildup when proppant placement into a fracture results in tip screenout (TSO), as observed in real field data on pumping of fracturing jobs. The phenomenon is described by proppant packing and jamming near the fracture tip, leading to TSO. Transient evolution of the zone of packed proppant near the tip and associated additional pressure drop along the packed bank are evaluated. Under the assumption of constant fracture height, the additional pressure drop during TSO grows as t(1+α), where tα is the law of proppant concentration growth (pressure drop grows quadratically in time, if the proppant concentration on surface at the blender grows linearly in time). The model is calibrated on field data from fracturing jobs in Western Siberia, Russia. These approximate models are verified with the two-continua model of proppant transport used to describe the process of proppant packing and jamming near the fracture tip. We also show how predictions of bottomhole pressure (BHP) growth during TSO obtained using proppant transport models implemented into existing hydraulic fracturing simulators can be significantly improved by a reasonable (based on behavior of dense suspensions at the packing limit) modification to parameters, describing suspension shear viscosity.

Summary We perform the coupled fluid- and geo-mechanical modeling of CO2 sequestration in a saline aquifer crossed by a tectonic fault. The model is based on hydrodynamical reservoir simulator MUFITS and mechanical simulator FLAC3D linked by the algorithm of the data transfer. The modelling of multiphase filtration of CO2 and brine accounting for phase transitions and thermal phenomena is carried out using MUFITS. At certain time, the hydrodynamical simulation is paused, while current pressure and temperature fields are passed to FLAC3D to calculate the equilibrium mechanical state. Numerically found volumetric strain is used to update the porosity and permeability fields for the subsequent hydrodynamic modelling. The study is focused on the effect of CO2 injection on activation of fault crossing the target aquifer. We derive an analytical expression for the permeability alteration in the rock damage zone due to plastic deformations which is based on the dilatancy evaluated numerically. For the fault core, we apply closure relation available in open literature. Parametric study of fault behavior during CO2 sequestration is carried out by varying the governing parameters including the injection strategy. Safe injection regimes are identified which do not lead to seismic activity and CO2 leakage out of the target aquifer.

Summary In this study we introduce a new method of numerical simulations of fluid flows, in which a certain property of each individual volume (e.g., shear viscosity) depends on the time elapsed since this particular volume entered the flow domain (so-called residence time). In oilfield services applications such fluids are used for well cementing (cement slurry) and hydraulic fracturing (water-based fluids containing cross-linked polymer molecules). Novelty of the method is that it uses a purely Eulerian approach for fluid flow description instead of Lagrangian approaches typically used in existing numerical studies to resolve tracking of individual fluid volumes. The method is based on representing the fluid as a mixture of fictitious fluids, which are being transformed to each other according to a certain time-variation law. By changing the properties of introduced fluids, it is possible to adjust the property of their mixture to any arbitrary residence time dynamics. The suggested method is applicable to numerical schemes that are stable with respect to small perturbations to time-dependent parameters. Multiple implementation strategies are available depending upon the base mathematical model describing fluid flow. To avoid links with particular governing equations describing the flow and numerical schemes, only gneral mathematical problem formulation is provided. This also allows for extension of the method to other fields of studies. Verification of the developed numerical algorithm is carried out for two flow configurations, namely, 1D flow of incompressible fluid with a constant velocity and time-dependent shear viscosity and transport of proppant in a cross-linked polymer fluid through an open hydraulic fracture described using 2D aperture-averaged model. First case demonstrates that even for fluids with unrealistic dependence of material properties on residence time, the proposed method provides accurate results using reasonable number of fictitious fluids. On the basis of second case we show the effect of residual time-dependent fluid rheology on proppant transport as compared to time-dependent rheology (so that in the whole flow domain the rheology parameters are similar at each time instant) and illustrate the necessity to resolve residence-time dependencies of carried fluid properties for accurate proppant placement predictions. Finally, we discuss new algorithm’s advantages, limitations as well as time- and memory- asymptotics. The proposed method can be used to develop effective numerical algorithms for simulations of various processes accompanying oil field development including well cementing and hydraulic fracturing of hydrocarbon-bearing formations, in which fluid properties depend on residence time and require tracking of material volumes.

Injection of water into a rock formation is a common oilfield services technology to maintain high reservoir pressure and increase ultimate recovery of hydrocarbons. While flowing through the well from surface to the rock formation, injected water typically transports fine particles, for example, fine sand grains and calcite precipitated at surface pipeline conditions while mixing water from different sources (e.g., fresh, Cenomanian and formation brine). In the framework of the two-fluid approach to suspension flow modelling, we formulate mathematical model for linear filtration of a particle-laden suspension in the vicinity of a fractured flooding well and transport of ion concentration (salinity). Two major factors of well injectivity decline are described, namely, particle trapping with associated reduction in permeability and porosity of the rock as well as the effect of salinity of injecting water leading to clay swelling, calcite precipitation and change of relative permeabilities of the rock with respect to water and oil. We calibrate suspension filtration model against in-house experiments on clogging of artificial and natural rock cores, in which the profiles of fines concentration along the cores are obtained using X-Ray computed tomography and analysis of 3D rock reconstruction images. The water injection model is adopted to conditions of Priobskoye oilfield of Western Siberia by using the results of standard laboratory experiments on fluid-fluid (calcite precipitation) and fluid-rock (clay swelling, migration of internal fines) compatibility, as well as the effect of salinity on oil displacement and analysis of solid fraction in the injecting water. The calibrated model is then used to describe field data on dynamics of injection rate of three flooding wells. It is obtained that the simulations predict the long-term injectivity dynamics of the wells very well, while at early times (up to 5 months from the start of injection) the model underestimates the injection rate. While fitting the model to field data, we varied only two parameters, namely, solids concentration in the injecting water (in the range provided by lab experiments) and trapping coefficient (the range is limited to result of experiments made with target rock cores). It is demonstrated that only a combination of injectivity decline factors allows to describe the long-term flooding rate of the wells. Ignoring either particle trapping or salinity effects lead to significant overestimation (up to 50%) of the long-term injection rate. Parametric study of water injection showed that two-fold increase in solids concentration in the injecting water as well as oil compressibility lead to similar decrease in long-term injection rate of a well.

We present the results of field experiments campaign on start-up of wells located in a sandstone oilfield of Western Siberia and history matching of coupled "wellbore-hydraulic fracture" model describing well start-up and fracture clean-up. The conclusion is made about the impact of rheological and geomechanical factors on the well cumulative production andfracture conductivity.The results are generalized for four wells of the field experiment and 30 wells of the retrospective analysis. Calculations of well startup are carried out using standalone fracture cleanup model and the coupled model, which includes models for filtration inside closed hydraulic fracture and flow in the wellbore. The data obtained during field tests on well startup is used to history match the fracture clean-up model. The adaptation allows to evaluate the sensitivity of well production to various physical parameters and find the safe operating envelope of operational parameters during well startup. Numerical simulations allow take into account geomechanics effectsand rheology properties of fracturing fluid, study the dynamics of effective (cleaned) fracture length as well as evaluate the influence of pressure drop dynamics on filtration properties of the fracture and cumulative well production. We extended the number of wells to study the impact of flowback scenarios on production andgeneralized the results of our previous study.Key parameters affecting the history match process of the mathematical model are determined,the uncertainty associated with fluid rheology is reduced. Using the history-matched model, we evaluated geomechanics effects on fracture degradation depending on bottom-hole pressure drop dynamics. Based on the obtained dynamics of dimensionless parameters, such as pressure and fracture productivity, we propose an optimized well start-up strategy aimed at maximizing effective fracture length and cumulative production. Additionally, we visualized the dynamics of fracture conductivity distribution along its length. The obtained results are consistent with interpretation of physical processes accompanying well start-up and fracture clean-up. Dimensionless productivity index is chosen to quantify the effects of geomechanics and fluid rheology on well production.On the basis of matched mathematical model, we predict a potential increase in production of the well with optimized start-up.The recommendations are presented in the form of the dynamics of wellhead choke opening and a sequence of choke diameters. We propose an integrated approach for planning a well flowback strategy after multi-stage hydraulic fracturing. The proposed decision-making algorithm considers the effects of geomechanics and yield-stress hydraulic fracturing fluid rheology on cumulative production. It allows to develop a design for the well start-up and fracture cleanup in terms of dynamics of wellheadchoke opening.

We propose a novel approach to data-driven modeling of a transient production of oil wells. We apply the transformer-based neural networks trained on the multivariate time series composed of various parameters of oil wells measured during their exploitation. By tuning the machine learning models for a single well (ignoring the effect of neighboring wells) on the open-source field datasets, we demonstrate that transformer outperforms recurrent neural networks with LSTM/GRU cells in the forecasting of the bottomhole pressure dynamics. We apply the transfer learning procedure to the transformer-based surrogate model, which includes the initial training on the dataset from a certain well and additional tuning of the model's weights on the dataset from a target well. Transfer learning approach helps to improve the prediction capability of the model. Next, we generalize the single-well model based on the transformer architecture for multiple wells to simulate complex transient oilfield-level patterns. In other words, we create the global model which deals with the dataset, comprised of the production history from multiple wells, and allows for capturing the well interference resulting in more accurate prediction of the bottomhole pressure or flow rate evolutions for each well under consideration. The developed instruments for a single-well and oilfield-scale modelling can be used to optimize the production process by selecting the operating regime and submersible equipment to increase the hydrocarbon recovery. In addition, the models can be helpful to perform well-testing avoiding costly shut-in operations.

Numerical simulators for the design of oilfield services technologies are required to be fast and robust, hence the implementation of underlying mathematical models is expected to be highly efficient. We present an optimized numerical algorithm based on the multigrid approach for solving the pressure equation in 2D problems of fluid-fluid displacement. This type of problems arise in oilfield services applications, such as drilling, cementing, hydraulic fracturing and EOR. The displacement of fluids with different properties in a narrow annular gap (drilling, cementing) or a slot (hydraulic fracturing, production) is governed by the 2D width-averaged model in the lubrication approximation. In numerical implementation, the most time-consuming is the elliptic Poisson pressure equation, which has coefficients with discontinuities (jumps) in the case of displacement of fluids with viscosity contrast. Specifically for this case of discontinuous coefficients, we designed and implemented numerically the black-box multigrid algorithm, which resolves the divergence issue typical of standard realization of multigrid algorithm using bilinear prolongation operators. The algorithm is tested on a number of matrices corresponding to discretization of elliptic equation at rectangular staggered meshes with different resolution. The performance of the algorithm is compared against several other sparse solvers available for commercial use: smoothed aggregated algebraic multigrid (PyAMG software package), direct sparse solver from Intel MKL library (DSS), Bi-Conjugate Gradient-Stabilized solver preconditioned by ILUT factorization implemented into BLAS package, and our in-house Conjugated Gradient algorithm preconditioned by ILU(2) factorization. It was found that the performance of the black-box multigrid solver is significantly higher (from 7x to 30x in terms of CPU time depending on the mesh resolution) as compared to the closest solver under consideration, which allows us to recommend this solver for implementation into existing 2D drilling simulators, fracturing design tools, cement placement and production simulators.

We consider the linear stability of a particle-laden vertical Couette flow between two flat plates. The flow is described in the framework of a two-fluid approach with a negligibly small volume fraction of the dispersed phase (the “dusty-gas model”). The carrier-fluid velocity profile in the main flow is modified by the presence of settling particles distributed non-uniformly between the plates. Two types of particle number density distributions are considered, namely, a single layer with a maximum at the flow center line and two symmetric layers located between the center line and the walls. Linearized governing equations are reduced to a modified Orr–Sommerfeld equation for the amplitude of a disturbance in the form of a normal mode. On the basis of a parametric study of the eigenvalues, it is shown that, in contrast to the case of two-phase Couette flow with zero particle velocity slip, the vertical disperse flow is unstable over a wide range of governing parameters, including small Reynolds numbers. In flows with both kinds of particle concentration profiles considered, there are two types of growing modes. A gravitational mode is triggered at low Reynolds numbers and typically small wavenumbers, while a shear mode with the wavelength of the order of the channel width and larger time-amplification rates is triggered at large Reynolds numbers. It is found that both modes are amplified with an increase in the particle mass loading or the ratio of the Reynolds number to squared Froude number, determining the carrier-fluid velocity profile. The results of the study can be used to control the stability of various technological processes involving particle-laden flows.

The paper presents the results of applying the methodology of well flowback and startup after hydraulic fracturing (HF), previously proposed in (Osiptsov et al., 2019), where the preferred conditions for well flowback after hydraulic fracturing are formulated in the form of a field experiment program. The program was implemented in 2019-2020 at four out of ten wells of the Priobskoye field in Western Siberia. The comparison of the two well clean-up designs, "smooth" and "aggressive", aimed to confirm the hypothesis that the choice of a "smooth" mode can reduce undesirable geomechanical effects to preserve the fracture conductivity and increase the recovery. Adapting our own hydrodynamic and geomechanical models to actual data made it possible to control the well clean-up process in the wells of a field experiment. Well site supervision allowed authors to fully implement the research plan, and also provided the opportunity to vary the parameters of the experiment (adjusting flowrate over time, adjusting the sampling and measurement schedules) using history matched models with actual parameters of the wells. Based on the results, the obtained data were analyzed and interpreted: flow rate, water cut, bottomhole and wellhead pressure, bottomhole temperature, suspended particulate matter (SPM) concentration, drain level, expedition pump frequency and wellhead samples. At the planning stage of the experiment, a formation zone of interest (ZOI) was selected with a set of first six pilot wells, where the geomechanical effects during the flowback period have the greatest impact on production. The field experiment program, which contains the wellhead choke steps sequence of diameters and duration of the well clean-up periods for two scenarios - "aggressive" and "smooth" for particular well. In addition to the choke schedule during eruptive period, there is a need to continue the recommended well startup after the ESP run in hole (RIH). Representativeness and repeatability conditions of field tests were formulated, comparison metrics were developed in order to standardize, normalize and estimate the well performance of the well startup a. We carried out the design of a field experiment proposed in 2019 (Osiptsov et al., 2019) and showed in practice that the dynamics of the well flowback and startup affects the well productivity index for a selected ZOI. In addition, we history-matched in-house geomechanical and hydrodynamic in order to quantify the production increase with regards to different flowback scenarios. Based on the available data, the boundaries of the pressure fluctuations opposite the hydraulic fracturing ports in the horizontal well were calculated in the absence of actual measurements to clarify the conditions for maintaining the conductivity of the fracture.