Optimizing Number of Fractures in Horizontal Well

Summary Horizontal wells with multiple hydraulic fractures have become a standard completion for the development of tight oil and gas reservoirs. Successful optimization of multiple-fracture design on horizontal wells began empirically in the Barnett Shale in the late 1990s (Steward 2013; Gertner 2013). More recently, research has focused on further improving fracturing performance by developing a model-derived optimum. Some researchers have focused on an economic optimum on the basis of multiple runs of an analytical or numerical model (Zhang et al. 2012; Saputelli et al. 2014). With such an approach, a new set of model runs is necessary to optimize the design each time the input parameters change significantly. Running multiple simulations for every optimization case might not always be practical. An alternative approach is to develop well-performance curves with dimensionless variables on the basis of the performance model. Such an approach was the basis for unified fracture design (UFD) for a single fracture in a vertical well (Economides et al. 2002). However, a similar systemized method to calculate the optimum for a horizontal well with multiple hydraulic fractures was missing. The objective of this study was to develop a rigorous and unified dimensionless optimization technique with type curves for the case of multiple transverse fractures in a horizontal well—an extension of UFD. The mathematical problem was solved in dimensionless variables. Multiple fractures include the proppant number (NP), penetration ratio (Ix), dimensionless conductivity (CfD), and aspect ratio (yeD) for each fracture, which is inversely proportional to the number of fractures. The direct boundary element (DBE) method was used to generate the dimensionless productivity index (JD) for a given range of these parameters (28,000 runs) for the pseudosteady-state case. Finally, total well JD was plotted as a function of the number of fractures for various NP. The effect of minimum fracture width was studied, and the optimization curves were adjusted for three cases of minimum fracture width. The provided dimensionless type curves can be used to identify the optimized number of fractures and their geometry for a given set of parameters, without running a more complicated numerical model multiple times. First, the proppant mass (and hence, NP) used for the fracture design can be selected on the basis of economic or other considerations. For this purpose, a relationship between total JD and NP, which accounts for the minimum fracture width requirement, was provided. Then, the optimal number of fractures can be calculated for a given NP using the generated type curves with minimum width constraints. The following observations were made during the study on the basis of the performed runs: For a given volume or proppant, NP, total JD for multiple fractures increases to an asymptote as the number of fractures increases. This asymptote represents a technical potential for multiple fractures and for high proppant numbers (NP≥100), with a technical potential of 3πNP. Below this asymptote, the more fractures that are created for a fixed NP, the larger the JD. In practice, minimum fracture width constrains the fracture geometry, and therefore maximum JD. For the case when 20/40 sand is used for multiple hydraulic fracturing of a 0.01-md formation with square total area, the optimal number of factures is approximately NP25. Application of horizontal drilling technology with multiple fractures assumes the availability of high proppant numbers. It was shown mathematically that the alternative low proppant numbers (NP≤20 for the previous case) are impractical for multiple fractures, because total JD cannot be significantly higher than JD for an optimized single fracture in the same area. This means that low formation permeability and/or high proppant volumes are needed for multiple fracture treatments.

Numerical simulation of stress shadow in multiple cluster hydraulic fracturing in horizontal wells based on lattice modelling

The number of horizontally drilled wells has continued to increase in the past few years. Nearly all of these well s have been completed as "drainholes" with slotted or perforated liner and without a cement sheath. The majority of these have been successful in their designed intent. Hydraulic fracturing treatments have been performed on a relatively small number of these wells. To be effectively fracture stimulated, a horizontally drilled well must be cased and cemented through the horizontal producing section of the well. Casing and cementing the horizontal section allows fracture initiation points to be controlled in placing multiple fractures. In situ stresses greatly influence the potential effectiveness of any fracturing treatment procedure. The one factor which most directly affects horizontal wellbore fracturing is the least principal stress, which is at a right angle to the induced fracture. The direction of the horizontal segment of the borehole dictates whether or not the induced fracture will be parallel or at an angle to the borehole. The use of properly applied controlled entry techniques at several fracture initiation points will help allow equal placement of proppant or reactive fluids in one stimulation treatment. Ei ther fracturi ng wi th proppant or fracture acidizing can be used in the stimulation treatment. The potential economic benefit to be derived from a successful multiple entry fracturing treatment merits strong consideration be given to the development of fracturing techniques to help obtain maximum wellbore drainage. Subject paper explains techniques and methods to be used in creating and placing proppant and/or reactive fluids in each of the multiple fractures in a horizontally drilled well. Economic considerations of the simultaneous stimulation treatment procedure are presented and compared to a vertical well under similar conditions.

SummaryThe classic plots of dimensionless fracture conductivity (CfD) vs. equivalent wellbore radius or equivalent negative skin are useful for evaluating the performance of hydraulic fractures (HFs) in vertical wells targeting conventional reservoirs (Prats 1961; Cinco-Ley and Samaniego-V. 1981). The increase in well productivity after hydraulic stimulation can be estimated from the “after fracturing” effective wellbore radius or from the “after fracturing” equivalent negative skin. However, this earlier work does not apply to the case of horizontal wells with multiple fractures. A revision of the diagnostic plots is needed to account for the combination of the resulting radial-flow regime and the transient effect in unconventional reservoirs with ultralow permeability. This paper reviews and extends this earlier work with the objective of making it applicable in the case of horizontal wells with multiple fractures. It also demonstrates practical application of this new technique for fracture-design optimization for horizontal wells.The influence of finite fracture conductivity (FC) on the HF flow efficiency is evaluated through analytical models, and it is confirmed by a 3D transient numerical-reservoir simulation. This work demonstrates that a redefined dimensionless fracture conductivity for horizontal wells CfD,h = 4 is found to be optimal by use of the maximum of log-normal derivative (subject to economics) for HFs in horizontal wells, and this value of CfD,h can provide 50% of the fracture-flow efficiency and 90% of the estimated ultimate recovery (EUR) that would have been obtained from an infinitely conductive fracture for the same production period. This new master plot can provide guidance for hydraulic-fracturing design and its optimization for hydrocarbon recovery in unconventional reservoirs through hydraulic fracturing in horizontal wells.

Summary The economic feasibility of the exploitation of unconventional resources is highly dependent on the ability of the operator to maximize individual well productivity, making hydraulic fracture design and implementation the defining factor for a successful field development in most cases. Some unconventional reservoirs, as shallow coal bed methane and over-pressured oil and gas shale formations, commonly present the minimum principal stress in the vertical direction, resulting in the occurrence of horizontal hydraulic fractures. Models for the transient flow and pressure behavior of horizontal fractures emanating from vertical wells exist and clearly show distinct performance from those for vertical fractures. This suggests that the widely accepted unified fracture design (UFD) approach to maximize well productivity for vertical and horizontal wells with vertical hydraulic fractures cannot be used for horizontal fractures. Thereafter, the necessity for guidelines to model and design horizontal fractures becomes evident. This investigation begins by presenting a new set of equations for horizontal fracture design based on the UFD approach, which allows the direct calculation of fracture width, half-length and conductivity for a given proppant number. Later, a reservoir numerical simulator is used to model well productivity behavior for horizontal fractures in homogeneous formations, with or without vertical to horizontal permeability anisotropy and for different aspect ratios as a function of suitably-defined proppant number, dimensionless fracture conductivity, and fracture penetration index parameters. The findings of this work reveal a complex behavior for horizontal fractures that prohibits the extrapolation of previous generalizations between proppant number, penetration index and dimensionless fracture conductivity established for vertical fractures. For a number of scenarios, new relationships among these variables are provided to guide horizontal fracture design. Anisotropy and reservoir aspect ratio were also found to significantly impact fracture performance. Additionally, a set of multi-variable functions that permit the estimation of maximum achievable productivity index for the horizontal fracture has been fitted, based on commonly known reservoir parameters and the proppant number. This investigation provides a comprehensive framework to assist the design of optimal horizontal fracture geometry that maximizes productivity for a given mass of proppant.

This work investigates the combined use of horizontal wells and hydraulic fracturing technology to improve steam utilization and process efficiency on steamflood operations. Enhancement of the production response obtained when combining both technologies was modeled using a fully implicit 3-D thermal reservoir simulator. The advantages of using hydraulic fracturing for thermal processes and especially for steam injection operations are explained by the "Heat Plane Source" concept presented here. Different scenarios for fractured horizontal wells were modeled: orthogonal, longitudinal, horizontal and multiple fractures. During conventional steam injection operations, heat convection and gravity effects become dominant in the near-wellbore region resulting in excessive heat losses and a heat chest of limited extent. Simulation results indicate that inclusion of hydraulic fractures will ensue better steam utilization and sweep efficiency improvement while minimizing convective oil override and reduction of operational costs. The cost effectiveness of the combined approach was evaluated using a decision analysis process and incorporating the production response into an economic model. Profitability was evaluated based on the Net Present Value response. Results suggest an accelerated and marked increase in cash flow, particularly during the early life of the project. The application of fracturing technology for steamflood operations will accelerate the response and overall performance from heavy crude reservoirs. The discussed approach is applicable to thinner reservoirs, dipping reservoirs, steam distillation drives and especially effective in layered reservoirs. Approach The main objective of this work is to investigate the performance of hydraulically fractured horizontal wells and their advantageous application for thermal recovery processes. Reservoir simulation was used to evaluate the combined use of horizontal wells and hydraulic fracturing as production techniques for improved steam management, effective field development, accelerate recovery, development of depleted zones, target bypassed oil banks, assisted gravity drainage scenarios and alternative completion/recompletion approaches. Analysis based on the productivity increase and ultimate cumulative recoveries indicate that the proposed approach may be an attractive production strategy for more efficient thermal recovery processes in heavy and intermediate oil reservoirs. Thermal Recovery Processes In-situ combustion, cyclic steam stimulation (Huff-n-Puff), continuous steam injection and hot water flooding are the basic thermal recovery processes. Thermal methods rely on several displacement mechanisms to recover oil. The relative importance of each mechanism depends on the type of oil being displaced and the related recovery process. Mechanisms such as; distillation drives and thermal expansion of the heated oil will add to recovery as crude distillation tends to reduce residual oil saturation. Lighter oil fractions vaporizes providing a miscible flood front in advance of the thermal front. However, thermal processes rely on crude viscosity reduction due to temperature increases as the most important recovery mechanism. P. 479

Compositional Simulation of Well Performance for Fractured and Multiple Fractured Horizontal Wells in Stratified Gas Condensate Reservoirs. Introduction The work for this paper has been carried out to improve development concepts in gas condensate reservoirs in the North Sea. While early North Sea oil fields were characterized by very large dimensions, thick homogeneous layers, and high permeabilities, newer discoveries have not been as blessed. Fields in the Haltenbanken area, such as Asgard have large extensions and reserves, but are found in deeper water and deep formations, characterized by hot reservoir temperatures of more than 300 degrees Fahrenheit, pressures from 7,500 to 13,000 psi, and most importantly, in heterogeneous, low permeable rocks. The need to make these high cost discoveries economic and accurate prediction of reservoir performance is more important than ever. In this context, the application of advanced well technologies such as multi-laterals and hydraulic fracturing takes on more significance. The primary advantages of fracturing are increasing productivity from low permeable rocks and improving the connectivity of the well in stratified formations (Abou-Sayed et. al. (1)). In gas condensate reservoirs, however, fracturing has additional advantages: stimulation reduces pressure drawdown and thus leads to less liquid dropout. Non-Darcy effects are minimized and the well will suffer less productivity reduction once liquid blocking occurs (Setari et. al. (2)). Simulation models developed for these applications differ from conventional approaches. The correct representation of geological features is normally the main gridding criterion. In fractured well simulation, however, the size and aspect ratio of the grid cells have a strong influence in predicting the flow behavior for different well types, fluid compositions, and recovery processes correctly. The goal of this paper is to determine practical simulation guidelines in modeling fractured well productivity in gas condensate fields. Analytical Methods Several analytical methods are available to predict the productivity and performance for vertical fractured wells. New models for horizontal wells have been developed by Babu/Odeh and Joshi, and for multiple fracture wells by Babu, Horne and Temeng, and others. Some of them have now the capability to model stratified reservoirs. The complex equations in these methods can be handled easily with the new faster PCs. Programs such as MEPFRAC/HYFRAC, a Mobil internal analytical software, can predict the productivity in time of multiple fractured wells with different fracture sizes in a stratified reservoir in only a few minutes. Unfortunately, different analytical models were found to have individual restrictions. One limitation of all analytical models is in the definition of fluids because they permit only one set of PVT data and no compositional modeling at all. Therefore, most of the methods are only highly accurate for dry gas or almost incompressible fluids but cannot model gas condensate characteristics. In most cases, simulation and analytical model results agree only during certain flow periods depending on the assumptions used in the analytical model. Another limitation is that either uniform flux or infinite conductivity descriptions are applied in the individual methods. After comparing the benefits of a number of analytical models with simulation results, our conclusion is that no analytical method is available to predict fractured well productivity reductions due to liquid effects in gas-condensate systems with sufficient detail. The only complete tool to predict this is fully-compositional simulation. Even a black oil representation is inadequate when finely-gridded models are used, since incorrect predictions result if improper fluid models are selected. See Coats and Hwang. Simulation of Fractured Wells in Coarse-Grid Gas Condensate Models Fracture representation in coarse simulation models depends on the selection of well productivity corrections derived from analytical techniques or locally fine gridded simulations. The necessary correction depends upon the timeframe, or flow regime, which needs to be treated most accurately. Figure 1 illustrates the timeframes and flow regimes for one example and the drainage patterns along fractures for infinite flow and uniform-pressure fracture systems. The flow periods begin with linear flow in the fracture and progress to pseudo-radial flow as the drainage area increases. P. 175

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 167770, ’Design Optimization of Horizontal Wells With Multiple Hydraulic Fractures in the Bakken Shale,’ by Luigi Saputelli, SPE, Frontender Corporation; Carlos Lopez, SPE, BP; Alejandro Chacon, SPE, Halliburton; and Mohammed Soliman, SPE, Texas Tech University, prepared for the 2014 SPE/EAGE European Unconventional Resources Conference and Exhibition, Vienna, Austria, 25-27 February. The paper has not been peer reviewed. The ultimate performance of fractured wells in tight reservoirs is affected severely by the interfering effects inside the fracture and interfractures. The most important parameters for determining the optimum fracture length have been shown to be the formation permeability and the stimulated reservoir volume. Although studies have examined the performance of horizontal fractured wells and the fracture-geometry effect, fracture spacing and intersecting angles in vertical and horizontal wells should be investigated further. This study presents the results of a tight-oil-reservoir analogy. Introduction An efficient way to improve the productivity of ultratight shale formations is to increase the density of hydraulic fractures. Decreasing hydraulic-fracture spacing increases the productivity of the well, but the incremental production gain for each additional hydraulic fracture decreases. The current field practice is to develop 640- to 1,280-acre leases with 4,000- to 10,000-ft horizontal wells with multiple fractures. However, the determination of the optimal number of fractures is a challenge. Historically, many of the first horizontal wellbores were drilled using the openhole method in the pay zone. This allowed a significant portion of the wellbore to be in contact with the reservoir. In 2004, a coiled-tubing-deployed jetting assembly was successfully used to focus the stimulation treatments in the openhole wellbore. This further demonstrated that openhole horizontal wells can be successful. Another completion method of that period that is still used is the plug-and-perforation technique in cased holes. The disadvantage of using this completion method, however, is that fracturing fluids can come in contact with the formation for an extended period of time. Near the wellbore, the flow configuration in a transverse fracture intersecting a horizontal well can be of two types. Outside the fracture, the flow from the reservoir into the fracture is linear; inside the fracture, the flow is converging radial. Additionally, turbulence effects, fracture-conductivity impairment, scaling, and unstable wellbore flow regimes can play an important role in creating pressure drops, which affect well performance.

The accuracy of the production forecast of fractured horizontal well not only affects the result of the optimum design and economic evaluation, but also affects the success and effectiveness of the fractured horizontal well. Therefore, it is quite essential to present new models fit for the actual seepage phenomenon to calculate the fractured horizontal well production. Multi-fractures propped when the horizontal well is fractured. But due to the stress difference along the horizon well and the restriction of the fracturing technology, the formed factures are different in length, conductivity, azimuth angle and so on. Moreover, during the production process, the fractures mutual disturbance makes the prediction of fractured horizontal well become more difficult, This paper combines the shape of formed fractures and the fluid peculation mechanism together to present a new model, which is based on superposition theory to predict the fractured horizontal well production The new model considers the effect of the fracture number, fracture length, fracture interval, the symmetry of the fractures, azimuth angle and conductivity We applied the new model to predict the productions of three fractured horizontal wells in China; the accordance is very well, up to 97.4%. Introduction Horizontal well can greatly increase the contact area of the well bore and the pay zone, so it is an important means to exploit the low permeability oil reservoir and to enhance the production and ultimate recovery. Sometimes due to the low permeability, large seepage resistance, low connectivity in the low permeability reservoir, the production of the horizontal well is still low. Therefore, it is necessary to frac the horizontal well to enhance the production. The accuracy of the fractured horizontal well production not only affects the result of the optimization design and economic evaluation, but also affects the success and effectiveness of the fractured horizontal wells, so it is vital to calculate the production exactly. According to related literature home and aboard, we found that it is a difficult problem to predict fractured horizontal well production. Soliman[1] et al researched the production model for the horizontal well with finite conductivity fracture in an infinite thick oil reservoir, and drawed the conclusion that larger conductivity can overcome the additional pressure drop caused by the linear influx flow. Li [2] et al presented a stable production model for the fractured wells. When the fracture plane is perpendicular to the well bore, he separated the n fractures into N flowing areas, and the each fracture is the center of the every area, supposing that each fracture produced only in its own area, this method didn't consider the fracture disturbance. B.Guo's [3] model is still fit for the stationary state flow, in this method, it should first to calculate one single fracture production, and then multiply single fracture production with N to get the N fractures production. Clearly, this method still didn't consider the fractures disturbance. Guo Jianchun[4] et al based on the fracture-reservoir system two dimension oil-water two phases model to simulate the production of horizontal wells, and combine the economic evaluation to presented an fractures optimum model for the fractured horizontal well.

Natural fractures are widely distributed in hydrate reservoirs, resulting in a fracture-filling type of gas hydrate. However, the complexity of fracture networks, including both hydraulic and natural fractures, complicates the evaluations of gas well productivity. This study investigates the heat and mass transfer dynamics in fracture-filling gas hydrate reservoirs developed using a multi-stage fractured horizontal well. A coupled thermal-hydraulic-mechanical model was developed based on the embedded discrete fracture method, and the model was validated against a commercial numerical simulator, demonstrating high accuracy in predicting gas–water production rates and reservoir pressure, temperature, and hydrate saturation field evolution. The simulation results revealed significant insights into gas and water production rates, flux distributions, and field map distributions. Furthermore, we analyzed the impact of various hydraulic fracture parameters, including fracture numbers, angles, lengths, and morphologies. The simulation results show that fractured wells perform better than non-fractured wells, and the initial daily gas production of a multi-stage fractured horizontal well is 4.05 times that of a fractured vertical well. Besides, fracture geometry critically influences the productivity of the multi-stage fractured horizontal well. The greater the number of hydraulic fractures and the longer the fracture length, the higher the daily and cumulative gas production of the gas well due to higher drainage areas. The cumulative gas production is increased by 131.98% as the number of hydraulic fractures is increased from 3 to 9, whereas the increase is 91.66% as the fracture length is increased from 50 to 200 m. A narrower intersection angle between hydraulic fractures and the wellbore corresponds to a diminished drainage area, thereby exacerbating fracture-driven interference effects and accelerating production decline rates. The intersection density between hydraulic fractures and natural fracture systems serves as the primary determinant of drainage efficiency in fracture-filling gas hydrate reservoirs. The findings have important implications for improving gas well productivity and enhancing the efficient exploitation of fracture-filling gas hydrates.

We investigate the rate-transient behavior of multistage fractured horizontal wells in conventional and unconventional homogeneous and naturally fractured reservoirs, the latter of which can contain any spatial distribution of finite- or infinite-conductivity fractures of arbitrary length and orientation. The number and type of fractures (hydraulic or natural) intersecting the wellbore and self-intersecting is unlimited. We show that there are many factors that dominate the ratetransient behavior of horizontal wells intersected by multiple hydraulic fractures in naturally fractured reservoirs, such as fracture conductivity, length, and distribution, as well as whether or not fractures intersect the wellbore. It is shown that the magnitude of the fracture conductivity is one of the most important parameters that affects the production performance of multistage fractured horizontal wells. It is also shown that, as the space increases between hydraulic and natural fractures intersecting a horizontal well, the fracture pseudosteady-state flow regime tends to disappear. Using the pressure and flow rate equivalency principle, we show that a production rate and/or cumulative production data set can be transformed into an equivalent pressure or pressure derivative data set. This is also very important for unconventional gas and oil reservoirs, where the boundary-dominated pseudosteady-state flow regime takes years to develop. A new technique is presented for determining stimulated reservoir volume (SRV) and production forecasting. It is shown that rate derivatives exhibit unusual behavior, from which system identification and flow regime analysis become impossible. The material balance time does not totally correct the unusual behavior of the rate derivative. However, the deconvolved pressure of the cumulative production derivatives behave like pressure derivatives.

The present paper evaluates the development effectiveness of fractured shale gas reservoirs by fractured horizontal wells based on discrete fracture model. In this model, the flow in matrix meets "non-Darcy law" because of the ultralow permeability when using "Cubic law" to describe the flow in fracture that is high flow conductivity and the simulation is carried out by solving the nonlinear partial differential equations using finite element method. The method of fracture treatment in this model is more suitable to characterize the function of individual fracture than the traditional method. Establishing several conceptual models with different fracture parameters to investigate the exploitation characteristic by multistage fracturing horizontal well. The preliminary simulation results show that: (1) Horizontal well is superior to vertical well when developing the fractured shale gas reservoir. (2) Multistage fracturing horizontal well is an effective method to amplify drainage area and raise well production. (3) Improving the natural fracture properties, such as fracture aperture that connect to hydraulic fracture, is important to improve development effect. (4) Well type, horizontal well length, hydraulic fracture number, spacing, length and natural fracture aperture are the main factors that determining the development effect of fractured shale gas reservoir. Therefore, Horizontal well development, multistage fracturing horizontal well, extending horizontal well length, enhancing the natural fracture aperture that connect to hydraulic fractures, increasing hydraulic fracture number and shorting hydraulic fracture spacing is helpful to improve the development effect of shale gas reservoir.

Shale oil is mainly extracted by fracturing. However, it is difficult to determine the optimum construction parameters to obtain maximum productivity. In this paper, a fuzzy comprehensive production evaluation model for fractured shale oil horizontal wells based on random forest algorithm and coordinated principal component analysis is proposed. The fracturing parameters of the target wells are optimized by combining this model with an orthogonal experimental design. The random forest algorithm was used to calculate the importance of data sample factors. The main controlling factors of the production of fractured horizontal wells in shale oil were obtained. To reduce the noise of the sample data, principal component analysis was used to reduce the dimensions of the main control factors. Furthermore, the random forest algorithm was used to determine the weight of the principal components after reducing the dimensionality. The membership function of the main control factors after reducing dimensionality was established by combining the fuzzy statistics and assignment methods. In addition, the membership matrix of the effect prediction of fractured horizontal wells in shale oil was determined. The fuzzy comprehensive evaluation method is used to score and evaluate the effect of fractured horizontal wells. Combined with the orthogonal experimental design method, the optimized parameter design of a fractured horizontal well considering the comprehensive action of multiple parameters is realized. After construction according to the optimized parameters, production following fracturing increases significantly. This verifies the rationality of the optimization method that is proposed in this paper.

Background Hydraulic fracturing is a most effective way of bottomhole zone treatment. This method is used for field development in order to increase oil and gas wells productivity and the absorptive capacity of injection wells, while isolating the reservoir waters, etc. The process of hydraulic fracturing is aimed to create an artificial and to expand the existing cracks in the formation bottom zone by fluid pumped into the well under high pressure. Due to the high pressure in the reservoir cracks or existing cracks expand. This whole system of cracks connects well with the remote productive parts of the reservoir. In order to prevent cracks closure the sand is pumped down the well with the wellbore fluid. Thus, the radius of fractures could reach several tens of meters. Increase of the active surface area of the well, draining the reservoir, is the key to success of operation of long horizontal wells. The reason of that is long time production of oil and gas from the easy-to-recover carbonate reservoirs. Moreover, although horizontal wells play a significant role in increasing the area of contact with a producing formation, it can further be increased by hydraulic fracturing. Aims and Objectives Review of existing methods and implementation analysis of multi-zone hydraulic fracturing in horizontal wells. Implementation of multi-zone hydraulic fracturing in horizontal well of the formation ЮС-1, pad 98, well 1744Г Tevlinsko-Russkinskoye field. The Results On the basis of the received data it was shown the effectiveness of multi-zone hydraulic fracturing in horizontal wells.

Pressure transient analysis of multi-stage fractured horizontal wells in boxed reservoirs