The paper presents the experience of using downhole microseismic monitoring to determine the direction of working agent losses while maintaining formation pressure in Baitugan oil field in Orenburg region. Studies were aimed at history matching and elaboration of the further strategy for formation pressure maintenance (FPM) and field development as a whole. The seismic monitoring method was used in the downhole version, when observations are done from the observation well located nearby the injection one. For reliable recording of weak microseismic events, high sensitivity receivers were used with 4 sensors per component. A special injection program was developed. Its first stage consisted in optimization of modes that ensure the maximum injection into formation of a fluid supplied at the wellhead. During acquisition parameter testing, passive recording of the seismic signal was done at all stages of injection during two weeks in various modes, including a short-term stop of injection with subsequent increase in injection to a maximum injection rate with exceeding the fracture gradient. Fracture growth zones were identified below the target formation. Starting from the second week of recording, fracture propagations to the overlying formations were observed under increased injection pressure. Based on data obtained, a three-dimensional map of microseismic events recorded in the formation was created. It was used for interpretation and allowed to specify geometry of self-induced hydraulic fractures depending on injection modes. Microseismic mapping of self-induced fractures in injection wells was done in Russia for the first time. The results of observations allow to optimize the formation pressure maintenance system through optimizing injection modes depending on local fracture gradients and injection shutting off in the zones with uncontrolled self-induced fractures that develop under minimum wellhead pressures. The obtained data also make it possible to significantly improve quality of history matching for carbonate deposits with reduced formation pressure through determining the injection efficiency. This result directly improves both the quality of forecast analysis and economic impact of formation pressure maintenance.

The increase in the count of fields with deteriorating flow properties and, as a result, long nonstationary flow, leads to an increasing spread of periodic lift method. Classic multiphase pipe flow models used by most commercial simulators are not able to account for transient processes occurring during intermittent operation. The purpose of this work is to develop a method for calculating the pressure distribution in the wellbore and pipelines, taking into account the unsteadiness of the multiphase flow, as well as its testing on the example of solving various problems of production management: analysis of bringing wells on to stable production, monitoring and optimization of periodic well performance, analysis of processes during the start-up and shutdown of processing trains of the oil gathering system.

Flow and injection profile monitoring in horizontal wells enhances the oil and gas field development efficiency, which is of particular importance when the target reservoirs have a complex geological structure, as is the case with oil-rim reservoirs located below a gas cap. The objective of this paper is to present the results of multi-well diagnostics carried out in order to estimate the flow and injection rates in Yarudey Field wells (Russia) and assess the downhole completion integrity status. When developing oil-rim reservoirs, flow and injection profiles need to be closely monitored so that gas and water breakthroughs along the length of thin beds and fractures could be promptly detected and appropriate remedial jobs planned. This task becomes more challenging in completions where multistage hydraulic fracturing was earlier performed, or the wells were cased with uncemented liners equipped with swell packers. To monitor the reservoir performance, advanced downhole diagnostics was performed in a group of wells in the field, where such reservoir-oriented techniques as passive acoustics and high-precision temperature logging were used. Application of the passive acoustic logging technique helped to identify reservoir flow zones and detect crossflows behind casing. The flow and injection rates were estimated through temperature simulations. Both these techniques were found to be useful, including those instances when the integrity of complex downhole completions was to be assessed. On the whole, the obtained results have proved the effectiveness of supplementing conventional production logging (PLT) with reservoir-oriented techniques.

The article presents the projected results of the offshore development option in the zone of deteriorated filtration-capacitance properties. To involve additional oil reserves in the development, it is proposed to use multi-stage hydraulic fracturing technology at the projected horizontal wells. The analysis was executed using modern methods of geological, hydrodynamic and geomechanical modeling. Method of most favorable zones’ isolation for carrying out multi-stage hydraulic fracturing of formation based on maps of permeability, current formation pressure, density of residual movable oil reserves and cover power is proposed. Taking into account the selected zones and the expected direction of crack development, the trajectories of new horizontal wells with a large deviation from the vertical were optimized. Efficiency assessment was carried out by comparing the technical and economic parameters of the proposed development option (horizontal wells with multi-stage hydraulic fracturing of the formation) with the basic version (horizontal wells with traditional completion). A hydrodynamic model was used to calculate oil production levels according to options. As a result, it was proved that the use of multi-stage hydraulic fracturing technology will involve additional oil reserves in the development and increase the efficiency of expensive offshore drilling.

During several decades high viscous guar-based gels remained main and single fluid type on Russian fracturing market. Having high viscosity and excellent proppant carrying capacity, crosslinked gel possesses damaging nature–it results in low retained conductivity of proppant pack even in case of oxidative destructors usage (<50%). In 2016-2017 low viscosity fluids based on synthetic polymer – polyacrylamide (High Viscosity Friction reducer, HiVis FR, HVFR, Viscous slickwater) started to be actively used in North America for shale fracturing. Along with improved sand carrying capacity in comparison with conventional FR due to its elastic properties, fluid demonstrated high retained conductivity of sand packs (~80%) confirmed during laboratory investigations, firstly performed by Stim-Lab (Stim-Lab Proppant Consortium 2015 – Fracturing Fluid Cleanup of various Low Polymer Fluid Systems; Stim-Lab Proppant Consortium - 2016 – Historical and current Friction Reducer Studies). However, fracturing design and job execution on conventional sandstones in Russia significantly differs from shales stimulations, i.e. serious work was required in order to start implementation of HiVis FR (Viscous slickwater) on sandstones in Russia. First field trials of Viscous slickwater were performed in Russia in the end of 2018 on conventional sandstones owned by "Gazpromneft-Khantos" - Gazpromneft subsidiary. In spring 2019 first time in the world full scale fracturing jobs, where Viscous slickwater with only ~30 cP at 511 s -1 demonstrated high transport efficiency to carry and place ceramic proppant at moderate rates (4-4.5 m 3 /min), as in combination with crosslinked gel as well as single fracturing fluid. Prior HiVis FR was qualified for application on sandstones as alternative to guar-based high viscous gels, major laboratory investigations were performed on novel fluid rheology, dynamic proppant transport, mechanical fluid properties, influence of breakers, etc ( Loginov at al. 2019 ). Later, in field trials phase, additional laboratory testing was carried out to address specific fluid performance questions. New technology field trials for "Gazpromneft-Khantos" were executed with high operational success–according to initial fracturing design. Viscous slickwater was pumped as single fracturing fluid, as well in combination with crosslinked guar gels (≥50%). Jobs were performed on vertical, inclined and horizontal wells. Despitê20 fold difference in viscosity, high proppant transport efficiency of HiVis FR allowed to place standard for South part of Priobskoe oilfield designs in case of hybrids and slightly less aggressive designs in case of 100% jobs on slickwater. Application of Viscous slickwater allowed to identify number of advantages of novel fluid over traditional guar-based fluids both in terms of operational efficiency, location and environmental footprint and fluid performance characteristics. It was shown that start production of wells treated with slickwater were ~10-20% higher, and current production rate were comparable in comparison with traditional designs with higher proppant volume. Field trials on implementation of Viscous slickwater - fluids based on polyacrylamide on low viscosity reservoirs owned by "Gazpromneft Khantos" were proven to be successful both from operational and technological point of view and have become a new milestone in history of Russian fracturing. This basis could be key to the future effective development of analogical oilfields in the world.

Modern technology of drilling and construction of horizontal wells allows for effective development of complex oil fields hard-to-recover oil reserves includes off low-permeability (less than 1-2 mD) and hyper-low-permeable (0.01-0.0001mD) fields. The latter in Russia include Bazhen, Domanic and Achimov fields. Their development provides for the mandatory completion of HW with Multiple-Fractured Horizontal Wells (MFHW). Experience in the development of layers of the specified type for Gazpromneft PJSC shows that the highest oil production rate is achieved if the MFHW system reveals not only the low-permeability rock matrix, but also captures the highly conductive (typically fractured) streaks — "strata-conveyors" (the latter may also be located in neighboring geological and stratigraphic differences). The difference in the permeability of such highly conductive layers and the hyper-low-permeable matrix of the host rocks can be very significant (up to 10 6 !). In addition to the positive aspects of the presence of highly conductive layers in the section associated with the achievement of high initial oil flow rates in new wells, in the process of further development, negative consequences may arise as a result of premature (even unpredictable) gas and water breakthroughs through narrow fractured layers. Is it possible to take into account the risks of loss of well productivity as a consequence of the pronounced geological heterogeneity of these fields, even if the scale of the impact of this heterogeneity is still difficult to assess by modern research methods? In this paper analyzes some of the results of core, logging, well testing and indicator studies with the allocation of characteristic features indicating the presence of local highly conductive fractured layers in the section of the oil the Bazhen-Abalak complex (BAC).

Due to the deterioration of petroleum resources in the Republic of Belarus, unconventional reservoirs, which contain hydrocarbons in "shale-like" low-permeable rocks, which include Domanic deposits, become increasingly important. These rocks containing hydrocarbons are both producing oil and at the same time they are not reservoirs in the traditional sense ( Varlamov A. I. et al., 2017 ). The most common technology for developing unconventional reservoirs is drilling horizontal wells with multi-stage hydraulic fracturing. The technological efficiency of drilling such wells will primarily depend on getting into the so - called "sweet spots" - places characterized by the best petrophysical, pyrolytic and geomechanical properties. This ultimately determines the need for a comprehensive study of hydrocarbon deposits in unconventional reservoirs. This article describes the workflow for studying unconventional reservoirs of one of the fields of the Pripyat trough of the Republic of Belarus. Studying these reservoirs was a challenge because due to geological and surface conditions no seismic data was available. The first well logging results showed the absence of significant rock anisotropy detected by standard methods of acoustic logging. This caused difficulties in determining the direction of drilling horizontal wells. There were also insufficient results of core studies of wells, including fully geochemical and geomechanical studies. Carrying out a comprehensive study of promising formations and confirming their oil bearing capacity required making a comprehensive program presented below, which outlined the types of studies that would provide necessary information about lithological, petrophysical, pyrolytic, and geomechanical characteristics of unconventional reservoirs of the field under study. Core studies performed within the integrated study confirmed that the studied sediments are source rocks. At the same time, according to the results of pyrolytic research, it was found that the rocks contain both in-situ hydrocarbons, and the ones which migrated from the underlying formations. The set of geophysical studies carried out on the legacy wells, including logging, hydraulic fracturing and surface seismic monitoring, allowed determining the direction of maximum stress, which eventually allowed determining the direction of drilling horizontal wells. The set of studies described in this article can be used in the study of other unconventional deposits of the Pripyat trough, belonging to the Domanic type.

The "shale revolution" experience on the example of the Bazhenov formation (BF) development required a serious development program review and implementation. The modern approach to the Bazhenov formation development in the Russian Federation is approaching the final stage of the existing formation stimulation technologies improvement. The technical limit in completion is about to be reached. It becomes obvious that existing stimulation technologies do not allow creating more efficient "reservoir factories" in the Bazhenov formation. The paper's objective is an attempt to identify hypotheses and prerequisites, as well as possible prospects for the stimulation technologies development, to justify the use of new alternative systems for hydraulic fracturing (HF) with an assessment of their potential at the BF reservoirs.

This article includes review of evolution of multistage fracturing completions for conventional oil reserves in continental Russia and focuses on attempts of the LLC "RN-Yuganskneftegaz", the one of the largest operator company in Russia, to solve the challenge of well life extension by implementing new completion technologies allowing reliable means of re-fracturing on the well after several years of service as well as the means to isolate gas or water break-through. A comparative analysis of different types of multistage fracturing completions was performed by LLC "RN-Yuganskneftegaz" with the aim to select the most suitable technology to address the above-mentioned goals without sacrifice of time required to drill, complete and stimulate the well. As the result of the analysis the technology of the frac valves activated by single-sized dissolvable balls was selected as a most appropriate. The successful field trial on 2 wells is described in this paper.

In this paper, rheological properties of fracturing fluid samples on polymer and non-polymer basis are studied. The interdependence between effective viscosity, viscoelastic properties and the proppant carrying capacity of the studied composite systems is shown. The advantage of using the method of oscillatory rheometry in the amplitude sweep mode when predicting the sedimentation rate of proppant is observed. The possibility of using this method to study viscoelastic properties of fracturing fluids,both on the basis of classical and alternative gelling agents, was experimentally confirmed.

In this paper, the properties of an alternative fluid for hydraulic fracturing (HF) technology based on hydrophobically modified polyacrylamide (HM-PAAm) are studied. HM-PAAm forms gels as a result of cross-linking of polymer chains by hydrophobic domains. Such cross-links are strong enough to impart resistance to temperature, but they can break and recombine under external influences, which makes it possible to restore properties after strong mechanical shear stresses. In the work, the influence of polymer concentration, temperature, and shear rate on the rheological properties of the gels was studied and the conditions for producing gels promising for use in hydraulic fracturing technology were determined.

Massive implementation of multi-stage fracturing treatments increased demands in water. Huge number of oil fields haven't got access to the fresh water sources. This fact forces service companies to utilize high TDS water sources for hydraulic fracturing. Currently available solutions for preparation of crosslinked fluid based on high TDS water involve implementation of organometallic systems which are too expensive and operationally complicated. This paper describes approach for preparation of borate- based fluid utilising high TDS water. Thorough laboratory optimization of the fracturing fluid has been performed and novel approach for fracturing fluid composition has been involved to develop next generation of robust borate fracturing fluids being able to withstand high TDS of the water. Fluid was evaluated in terms of both stability and viscosity recovery after application of high shear stress. Optimized fluid formulation has been used during multi-stage fracturing treatment with 7 stages. High TDS water of Cenomanian formations was utilized as a water source. During treatments as high as 700 kgPA proppant concentration has been reached. During optimization novel approach involving implementation of low boron containing fluid with massive content of alkali was introduced. Low boron content is required for preventing syneresis in high ionic strength media caused by Debye-Huckel effect. High alkali concentration meantime required to keep fluid at high pH and avoid weakening of bonds between borates and polymer. Too high alkali concentration worsens viscosity recovery after high shear stress application and this fact dictates implementation of both immediate and delayed alkali compounds. Pre-job water treatment is also important. Addition of reagents being able to convert natural radical oxidizing aids in less damaging forms is imperative. During the treatment fluid was additionally tuned to reduce frictional losses in tubing by compensating effect of proppant on the rate of crosslinking components diffusion. And treatment design was modified to address increased efficiency of the fluid caused by filter-cake enhancement by delayed alkali. The study showed availability of approaches which allow to implement high TDS water sources for preparation of borate crosslinked fluids confirmed by successful field implementation. These practices can be widely used in industry for performing multi-stage fracturing treatments in areas with lack of fresh water sources and to shorten water preparation cycle time.

Even though products made of soluble metals are widely used in the oil and gas industry, the issue of the cumulative effect of downhole conditions on the rate and nature of dissolution of products in the well is still insufficiently studied. This problem is especially acute when predicting the time of dissolution of frac balls. The generally accepted methods for testing frac balls for dissolution rate do not allow predicting with enough accuracy two most important parameters: the time during which the ball retains the ability to provide hydraulic isolation of the fracturing intervals and the time of complete dissolution of the ball. In this paper, the dependence of the rate of dissolution of frac balls on the geometry of the unit in which dissolution occurs, the temperature of the unit heating, the pressure in the well, and the influence of various technological media are considered. A test procedure is proposed that allows one to consider the combined effect of the above factors on the dissolution of frac balls. The work of the presented technique is illustrated by the example of validation tests of a frac ball in downhole conditions.

In the case of many workover operations associated with fluid loss inside the well or multistage refracturing, one of the most significant uncertainties is the fluid entry point. Starting from uneven depletion of the horizontal part of the well, not knowing the fluid entry point may lead to ineffective well restimulation and absence of any positive effect. In this paper new technique will be reviewed for several locations across Russia. Implementation of high-frequency pressure monitoring (HFPM) method and based on it, Well Watcher Stim technology, allows locating downhole events caused during well workover and refracturing without interruption of the well stimulation operations. The high frequency pressure monitoring technology is based on automatic processing of wellbore pressure oscillations recorded at the wellhead. The wellbore completion elements such as hydraulic fractures, casing diameter changes or wellbore restrictions serve as effective reflectors for the tube waves. In this paper, we will demonstrate an integrated approach to the utilization of high-frequency pressure monitoring technique, which has served as an engineering tool for fluid entry point validation in the projects all across Russia. The project validated the intrinsic benefits of the new approach in solving uncertainties about the fluid entry point. The Well Wacther Stim technology requires minimum changes in operational procedures, is easy and safe to install and provides real-time answers that allow the frac engineer to take decisions on location and optimize the re-fracturing process Selected stimulation approach enables the horizontal well refracturing operation to be concluded within 2-3 days, minimizing well intervention operations and reducing the overall costs and risks of the restimulation. The selected workover approach demonstrates reliable technique for fluid loss extensional control in well workover. One of the opportunities which is became available with high-frequency monitoring is analyze of conditions of well construction and downhole equipment. That was practically confirmed at a well with completion for multi-stage fracturing. Suspicion about damage of casing or sliding sleeves and corrosion of isolation packers was verified and localized. Further application of Well Watcher Stim made possible to decrease leakages by conventional reservoir dynamic fracture diversion technology and provide multi-stage fracturing with constant control of identified zones. This paper presents case studies of the technology that was used widely in Russia in the recent years proving reliability of high-frequency pressure monitoring technique. It will provide meaningful insight for the petroleum engineer who will look after solving uncertainties during well workover operations and refracturing.

Rheology of fracturing fluids described by power law model. The coeffects n and K of this model is using for all fracturing stimulators. Rheology measurements of real fracturing fluid frequently provide values with n >1, which is contradicted with Power Law model.Transfer this number to a fracturing simulator software gives wrong fracture simulation. The paper describes a new approach for modeling of fluid viscosity which resolves wrong assumptions of previously used model. Fluid viscosity measured with high-pressure-high-temperature (HPHT) rotational rheometer. The conventional fluid testing procedure based on ISO 13503-1 standard requirements provided erroneous and inexplicable results. The investigation of fluid rheological behavior was done by measurement of fluid viscosity in extended range of shear rates. Contrary to usual measurements of viscosity at 25, 50, 75 and 100 s -1 , during this approach shear rates range was extended to 340 s -1 and 5 s -1 . Fluid behavior was analyzed using log-log regression approach. Base on this analysis the corrected rheology numbers calculated and used tor a stimulation software. As a result of laboratory research, Power Law model inapplicability in several cases was confirmed. Number of rheological measurements revealed boundary conditions for implementation of Power Law model and enlighten the factors which causes non-linear relation of viscosity at log-log plot. It has been found that pH, temperature and polymer degrading material cause abnormal fluid behavior at 1-100 s -1 shear rates range. Therefore, limitations for measurements according to ISO 13503-1 standard was stated. Additionally, impact of recently introduced oil and gas producing companies’ fracturing fluid quality standards on fluid viscosity behavior was evaluated. It was revealed that tough requirements for fracturing fluid viscosity recovery after passing through high shear rate region provoke abnormal viscosity loss at low shear rates and errors in determination of consistency and behavior indexes. Finally impact of wrong data obtained with Power Law approximation on fracture geometry calculated with currently available fracturing simulators was estimated and requirements for next-generation fracturing simulators in terms of fluid viscosity modeling was claimed. The study shows weak points in implementation of currently used Power Law fluid viscosity model for fracturing simulation. Implementation of practices described in this study allow to either don't cross the border of power law model or to enrich fracturing simulators with more precise rheology model.

During the Bazhenov shale development, a new integrated approach to planning the multistage hydraulic fracturing was developed. This approach is applied to each drilled well,thus implementing the strategy of technological experiment, where the well serves as a separate testing ground for testing the developed methods and implementing new technologies.With the help of modern multistage hydraulic fracturing modeling tools, developed jointly with technological partners for the project tasks, a technological experiment plan is drawn up for the well and contains new,potentially effective solutions, as well as the already accumulated experience. In accordance with the developed plan,the multistage hydraulic fracturing operation is modeled, taking into account the geological and geomechanical features of the object, such as lateral and zonal heterogeneity and the existing natural fracture zones. Using the developed approach, multistage hydraulic fracturing operations were performed on more than 25 wells drilled at the Bazhenov shale, which is equivalent to 450 well operations.During this time, various technological solutions have been developed, tested and implemented,which include the use of new hydraulic fracturing fluid samples, the selection of optimal well perforating scheme,the use of combined proppant packs and hydraulic fracturing using mainly low-viscosity fluids.Active use of specialized software for modeling the hydraulic fracturing process and close cooperation of software developers with hydraulic fracturing engineers has led to the expansion of the functionality of the developed software product, improving its quality, convenience and stability of operation. According to the initial assessment,the implementation of the technological experiment strategy in conjunction with the use of specialized software led to a reduction in drilling hazard mitigation during multistage hydraulic fracturing operations,as well as to an increase in accumulated oil production by an average of 37 %.A database of knowledge and individual,successful technological solutions available for use in similar projects has been created. Due to the Bazhenov shale unique structure and properties,it was necessary to adapt existing solutions in the industry for conducting multistage hydraulic fracturing in ultra-low layer permeability.The process of searching and creating new technologies, tools for modeling the multistage hydraulic fracturing process and analyzing the results was also successfully initiated. The developed approaches have already shown their effectiveness, and the work results can be replicated on subsequent wells, as well as on similar objects.

Nowadays, the vast majority of the oil fields of the Republic of Belarus are at the last stage of development. In this connection, the goal of Belarusian oil industry is to search, to explore and to develop ultra-low permeable tight fractured carbonate rocks. Commercial production of such resources is only possible with the use of advanced stimulation methods, such as hydraulic fracturing / multi-stage hydraulic fracturing. Taking into account the features of tight carbonate rocks, the use of conventional hydraulic fracturing technologies cannot provide optimal results, and therefore, selection of more advanced approaches to hydraulic fracturing is necessary. Selection and optimization of technologies based on theoretical research is not possible, instead it requires practical implementation, and according to our experience, flexibility in decision making. This article presents the experience of unconventional reservoir development in the Republic of Belarus from 2014 to 2020. We briefly described the main technologies used and how these technologies evolved depending on the resulting operational and economic effect. The technology of repeated multi-stage hydraulic fracturing in an unconventional reservoir is described; the possibility of producing from previously untapped reservoir zones within the horizontal wellbore by creating additional flow channels (hydraulic fractures) was confirmed.

Production history fitting in Weiyuan shale gas shows that the length and height of supporting fractures are short, which limits the long-term conductivity of fractures. Due to the limited volume of reconstruction, the production decreases rapidly, which makes it difficult to achieve the purpose of economic and effective exploitation. In view of the above problems, an enhanced hydraulic fracturing technology (EHFT) which has been verified and applied is proposed to increase effective SRV. according to the different characteristics of shale reservoir, EHFT optimizs the performance parameter of fracturing fluid and matchs different modes of proppant injection, which can be classified in 4 major patterns, including modes of proppant injection in long/short slug type and densifying proppant injection in long / short slug type. First, based on brittleness evaluation and mineral composition, and combined with interpretation results of the natural fracture, the pumping plan is made according to the design goal. Then, modes of proppant injection is adjusted and optimized in real time through the construction curve and micro-seismic data during fracturing. The hydraulic fracture propagates along the dominant channel in the process of fracturing and there is the risk of the fracture communicating with the adjacent well. The fracture control technology of multi cluster perforating can effectively avoid it. Through field application, the following conclusions are drawn: (1) For reservoirs with high clay content, high viscosity fracturing fluid is recommended to improve the fracture width and reduce the complexity of construction; modes of proppant injection in long slugs of low concentration can control the construction scale, improve quality of proppant per meter, establish continuous fracture support and improve the long-term conductivity; modes of proppant injection in short slug type can control the fluid loss and avoid the occurrence of complex conditions, which is especially suitable for reservoir with natural fracture. (2) In the process of fracturing, the combination of various modes can achieve good results through real-time analysis and judgment. (3) The effectiveness of EHFT is verified by construction parameters, fracturing curve and micro-seismic monitoring. The construction scale (total volume of fracturing fluid) is reduced by 10%; quality of proppant per meter is increased by 10-20%; the fluctuation range of construction pressure is controllable/small; and the SRV and micro-seismic events are significantly increased. (4) The test production of well A which is the highest in Weiyuan is 71.2×10 4 m 3 with this technology. EHFT is suitable for the complexity of shale reservoir reconstruction. Multiple modes of real-time control can reduce the occurrence probability of complex conditions, improving the effective SRV and achieving efficient fracturing. Most importantly, the technology is feasible and effective in the overall goal of cost reduction and efficiency increase

The Turonian siltstone is widely spread through the Siberian region in northern Russia. It is a laminated, heterogeneous and high-shale content formation with low permeability (1-3 mD) and low reservoir temperature (15 degC), with more than 300 trillion m3 of natural gas in place. Hydraulic fracturing is a necessity for economic and sustained development of the field in the described geological conditions. High montmorillonite contentand extremely low temperatures make the Turonian reservoir a true challenge for frac experts. A pilot stage of project development has been executed with horizontal drilling and multistage fracturing. A well has been constructed with 168-mm casing and 114-mm liner, with the liner separated into discrete segments with hydraulic packers. Each zone is equipped with filters integrated with the inflow control devices (ICD)plus frac portsenabling multistage frac jobs and subsequent controlled, solids-free production.Frac ports and ICDs are shifted using coiled tubing (CT) equipped with a downhole hydraulic key. Significant innovations were implemented for the frac fluid design in terms of a noveldiesel-based fluid breaker package.Additionallab investigation of proppant transport capacity has revealed some elastic properties of diesel-based fluid, that are not typical for crosslinked guar-borate water-based fluids. This provided the opportunity to significantly increase proppant concentration and frac design aggressiveness for the successful completion of a trial campaign.With the optimized fluid, the engineering team has achieved outstanding results in frac design, when large-sized proppant has been pumped at concentrations up to 1400 kg/m3 during multistage frac operations in horizontal wells.The combination of technologies led to rapid well cleanup with a quick transition to stable gas flow to sales. New achievements in well completion techniques andwater-free frac fluid optimization can be implemented when dealing with similar low-temperature reservoirs with high content of water-sensitive clays.

Nowadays, Machine Learning (ML) is actively used in geophysical prospecting including seismic exploration. This study focuses on the applicability and feasibility of Deep Learning for the inverse problem in seismic exploration that is the estimation of the rock-physics parameters for a fractured reservoir, from seismic data. The main goal of this paper is to prove the efficiency of a neural network in estimating fractured medium parameters, represented as anisotropy parameters of HTI model. (HTI is "Horizontal Transverse Isotropy".) As such fracture parameters, we consider the normal and tangential weaknesses of fractures Δ N and Δ T , Thomsen anisotropy parameters ε, δ, γ, as well as the crack density e and the crack aspect ratio α (fracture opening). In addition, we consider a fractured medium, in which there are two fracture networks, characterized by two pairs of weaknesses (Δ N1 , Δ T1 ) and (Δ N2 , Δ T2 ); this is the so-called orthorhombic model. We validate the accuracy of our neural network by comparing the predicted parameter values with the a priori given. We use mathematic formulae, which relate the considered parameters estimation to different effective-medium anisotropy models of a fractured medium, such as Schoenberg's Linear Slip model, Hudson's model for penny-shaped cracks and Thomsen's model for aligned cracks in porous rock. In our study, seismic signatures (seismograms of the reflected waves PP and PS) of both the vertical U Z -component and the horizontal one U X are the inputs for the neural network. At the output, the network predicts fracture parameters and anisotropy parameters. The neural network is trained on synthetic seismograms of reflected waves, which were generated using 2D-elastic numerical finite-difference modelling. Thus we demonstrate the applicability of Deep Learning for estimation of the fractured medium parameters, by training the neural network on synthetic seismograms. The normal and tangential weaknesses of fractures Δ N and Δ T , the crack density and the crack aspect ratio (crack opening) are successfully estimated as well as the anisotropy parameters ε (V) , δ (V) and γ (V) . In the prediction of Δ N and Δ T , the relative error does not exceed 1.7% and 1.4%, respectively, and in the prediction of crack density e — from 0.9% to 1.4%. In predicting the anisotropy parameters ε (V) , δ (V) and γ (V) , the error does not exceed 1.6%, 1.7%, and 1.8%, respectively. However, in estimating the value of crack opening α , the result is an order of magnitude worse, an error of 14.2%. For the orthorhombic model, the prediction results are slightly worse than for the HTI model, but still within the acceptable accuracy. In predicting the fracture parameters for the first fracture network (Δ N1 , Δ T1 and e 1 ) the error does not exceed 2.3%, 4.2%, and 2.3%, respectively, and for the second fracture network (Δ N2 , Δ T2 and e 1 ) — respectively 4.3%, 5.7%, and 3.7%. This slight deterioration in the results (in comparison with HTI) is explained by the complicated formulation of the last task with the orthorhombic model, in which various deviations in the inclination of cracks were introduced (the angles β 1 and β 2 ). In general, we have successfully developed a neural network to solve the problem on fractured reservoir characterization. Finally, it produces fairly accurate results that prove the effectiveness of Deep Learning in inversion for fracture parameters from the seismic data.