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

One of the engineering tasks of hydraulic fracturing design is the correct selection of the propping agent. Ceramic proppant, which is used in most fields in Western Siberia, makes a proppant pack that is several times more permeable than the formation (sometimes even 1000 times). However, the gelling agent used for treatment, depending on the size of the proppant, reduces the permeability of the proppant pack from 2 to 5 times. However, workover operations after hydraulic fracturing and during production period has a significant colmatage effect on the near-wellbore zone and can significantly reduce the productivity of the well. A common practice in the fields of Western Siberia is to prop a fracture at the near-wellbore zone with a proppant of mesh size 12/18. Despite a small difference in the calculated skin factor, the analysis of operations at the Salym group of oilfields shows a significant change in the production decline rate on wells with 16/20 and 12/18 mesh size propping agents. Engineering group of the Salym group of oilfields conducted trials on hydraulic fracturing treatments with a mesh size 10/14 and, after successful results, 6/10 proppant. The treatment results, lessons learned and the analysis of production of these wells is the scope of this work.

Fluids capable of transporting proppant with the least formation and fractures contamination are one of the most relevant areas of the technological development of hydraulic fracturing treatment. In the world in recent years, there has been a tendency to switch from cross-linked guar-based fracturing fluids to synthetic ones. Highly viscous friction reducers find wider application in the new concept of modern industry development. Unlike traditional guar-borate-based fluids, these fluids have a number of advantages - they provide higher residual fracture conductivity, are less sensitive to the mineral composition and temperature of the water source, contain fewer chemical elements in the working formulation and, as a rule, are less demanding of equipping a hydraulic fracturing fleet. Also, in addition to the above features, note the possibility of making changes to an engineering solution immediately in the work process, ensured by the simplicity of fluid making-up and high hydration rate. Despite the obvious advantages in using synthetic fluid systems over standard guar-based systems, until now they have not been widely used in conventional reservoirs. This is supported by poor knowledge of the practical application associated with proppant transport and the absence of selection criteria based on the system rheological properties which significantly affect the hydraulic fracturing success rate. The paper describes a set of rheological studies, including building viscosity and elasticity profiles, as well as an assessment of the fluid system thermal stability. The viscosity behavior was also studied in a wide range of shear rates. The effects of elastic moduli were studied by conducting vibrational-shear tests in a spectrum of various frequencies. Quantitative and qualitative comparative measurements were carried out to study the settling rate of proppant, as well as its viscoelastic properties in a flow. The result of the study is generalized analytical findings on synthetic fluid systems confirmed by practical application in real conditions of conventional reservoirs in West Siberia. This paper will help to understand the key factors affecting the choice of fracturing fluid formulations based on high-viscosity friction reducers and, in the future, may become the basis for creating a methodology for testing synthetic gels.

The volume of drilling horizontal wells with multistage hydraulic fracturing (hydraulic fracturing) in Russia is increasing annually. According to statistics, at the company's licensed sites, drilling with multi-stage hydraulic fracturing currently accounts for over 70% of the volume of commissioning of new wells and sidetracking. The main reason for the growth of wells with multistage fracturing is a decrease in the quality of the reserves structure, the commissioning of low-permeable reservoirs, and a decrease in effective oil-saturated thicknesses in new areas. Currently, the share of horizontal wells with multi-stage hydraulic fracturing in an enterprise exceeds 25% of the existing fund. Wells with cementless multi-section shanks with ball-activated couplings for multistage hydraulic fracturing (ball arrangements) account for 97% of the well stock with multistage hydraulic fracturing. Hydraulic fracturing couplings and insulating annular packers (swellable, hydromechanical) are installed in the liner layout and are lowered into the horizontal wellbore. Further, during multi-stage fracturing, the couplings are activated alternately by dropping balls of different diameters (with an increase from small to large). The ball arrangements described above are disposable and have an uneven cross section after multi-stage fracturing. This multistage fracturing method is widespread, since it has a high speed of work and has no restrictions on the depth of the well. However, unequal borehole cross-section restricts access to the horizontal wellbore, and there is a need for drilling operations (milling) of couplings immediately after hydraulic fracturing or during well operation. The result of monitoring the flow rate of oil wells with multi-stage fracturing showed a decrease in productivity in the range of 55-75% for the first 2 years. In most cases, repeated stimulation is necessary, as there is a loss of productivity due to contamination of the fractures with process fluids and a deterioration in the conductivity of the hydraulic fracture (rock removal, plugging of the pore space of the fracture). For directional wells with hydraulic fracturing ( Economidеs M. et al., 2004 ), there is a well-known method of restoring productivity - repeated hydraulic fracturing (re-fracturing). In the case of hydraulic wells with multi-stage fracturing with single-use ball arrangements, one of the problems is the selection of the optimal cost-effective method of repeated stimulation (multi-stage fracturing), which is technically complicated by the design of the well. In this paper, we consider the experience of applying the technology of re-stimulation of horizontal wells with multi-stage hydraulic fracturing at the company's fields and the results achieved after repeated hydraulic fracturing (increase in oil production rate, economic efficiency of measures). A proprietary method has been developed, which is currently the most acceptable and cost-effective for re-stimulation of horizontal wells with single-use ball arrangements.

A case study is presented discussing a specific completion strategy applied in the Daqing oil field, Block Long26, and the outskirts of tight oil wells. An alternative fracture completion method and enhanced flowback technology were used to develop these tight oil fields. The methodology applied resulted in improved efficiency of the fracture completion strategy and post-stimulation flowback, which reduced operational time and related costs. Optimized fracture cluster spacing length was determined based on the operational time efficiency and engineered fracture completion design. Laboratory testing was performed to select fluid recipes, and field trials were performed for the correlated custom-made microemulsion technology, which enhanced post-fracture flowback to shorten operational time and increase the return on investment ratio and production. Field results and post-fracture completion production are promising. Several post-fracture completion production surveys have been applied in the Daqing field, Block Long26. The most popular completion strategy applied in this field involves using less than three perforation clusters in each fracture stage, applied using multiple, horizontal fracture stages, with longer and (normally) much greater fracture spacing length, thus requiring less fracture cluster treatments along the horizontal laterals. After stimulation, normally, additional days are necessary to observe the oil drop showing; thus, alternative flowback technology is necessary to enhance post-stimulation flowback to help improve the return on investment ratio. Limited entry fracture and/or extreme limited entry fracture technology were part of the intensive fracture cluster completion strategy to benefit fracture completion and production. Field operations involved doubling the current perforation and fracture clusters in one fracture stage. Laboratory methods were used to select the appropriate mircoemulsion additives to form a fracturing fluid recipe to aid oil production and enhance flowback.

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.

As the number of stages of hydraulic fracturing along the horizontal wellbore increases, the cost of fracturing starts to exceed the cost of drilling the well. Therefore, the issue of costs optimization for hydraulic fracturing in general become highly important problem. In this regard, for optimization calculations, it is necessary to operate with such important geometric characteristics of fracture as half-length and height of the fracture, which can be determined by logging, well-testing and micro-seismic studies. This paper analyzes all types of studies to determine the geometric characteristics of the fracture, except its width. Logging surveys, which have been carried out on vertical and inclined wells, allow to determine with some degree of accuracy the height of the fracture, provided that the conditions of applicability of these surveys considering well azimuth and inclined angle in the zone of fracturing & logging. Among the logging methods that have been applied to that kind of problem, the highest priority in terms of the reliability of the results obtained is given. Well testing allow us to determine the effective half-length of a fracture, but with some limitations. Micro-seismic studies allow comprehensively and in three-dimensional view to determine the configuration of a fracture in a orientational well or a system of fractures in a horizontal borehole to a certain degree of accuracy.

The Company has recently completed the first stage of a large-scale program for production of hard-to-recover (HTR) oil reserves from standard terrigenous reservoirs. This program is being worked on within the framework of the Optimal Completion Technologies and Operation Parameters of Oil Wells in Low-Productivity Reservoirs technology project implemented within the Company's perimeter. A high-rate hybrid multistage hydraulic fracturing was successfully performed on a number of horizontal wells at the Achimov Formation reservoirs thus confirming the ambitious well productivity plans. The primary goal of the project was to verify the hypothesis that the sweep area can be increased by means of a high-rate hybrid hydraulic fracturing; the next goal is to check the hypothesis that a developed network of fractures, or stimulate reservoir volume (SRV), can be formed at a hydraulic fracturing injection rate exceeding the standard values by 3-4 times. Keeping in mind the tasks of increasing the drainage area and connecting separate zones of highly compartmentalized reservoirs with each other, the basic hydraulic fracturing technology for the design purposes was a high-rate hybrid hydraulic fracturing with an injection rate of up to 12 m3/min and a combined schedule. At the preparatory data processing and interpretation stage, issues in each discipline involved – petrophysics, geology, geomechanics, and hydrodynamics – were worked out in detail and modeled. The design project of a high-rate hybrid hydraulic fracturing treatment has undergone many optimization iterations in the Planar 3D module, with further testing of the anticipated effects on a hydrodynamic simulator using unstructured three-dimensional PEBI grids. As a result of multi-variant modeling performed by a cross-functional team, a universal hydraulic fracturing design was created which predicted high efficiency of the treatment to create both the SRV and the planar fractures. To make the results of the performed pilot work more reliable, a wide range of studies was performed including production logging tests in horizontal wells with various completion systems. While assessing whether formation of the SRV is possible, downhole micro-seismic monitoring was performed, and downhole pressure was measured at neighboring wells. In the real conditions of the tested target reservoir, formation of the SRV was not confirmed at the actual injection parameters. The Planar 3D module, coupled with the hydrodynamic simulator, is an efficient tool to optimize design of the hybrid hydraulic fracturing treatment. The giant half-lengths of planar fractures predicted in the hydraulic fracturing modeling software have been proved by micro-seismic monitoring and pressure response at submersible pumps of the neighboring wells. At one of the stages, a high-rate hydraulic fracturing with 125 tons of proppant was performed entirely with a hydraulic fracturing fluid based 100% on a synthetic gelatinizing agent which showed the greatest fracture length. The Company pays great attention to this technology solution too – several tests have been initiated with respect to ‘pure’ hydraulic fracturing fluids, and work is underway to develop guideline and methodology documentation on quality control. Results of the project have changed the vision of optimal methods for stimulation of the Achimov low-permeability reservoirs. In the absence of the SRV, formation of long planar fractures by means of a system of horizontal wells with low-density spacing can increase economic viability of currently uneconomical fields or separate reservoirs (zones). The novelty of this work consists in the achieved level of integration of model values from various disciplines with the actual data. The initial and current parameters of stimulated wells demonstrate a broad perspective for optimizing the HTR reserves development system for a standard terrigenous reservoir. Successful reservoir stimulation by high-rate hybrid multistage hydraulic fracturing (MSF) opens the way to even bigger projects that envisage drilling horizontal holes up to 2,000 m long and building wells of the TAML-3 level of complexity.

In this paper, some features of conducting experiments on core samples to determine mechanical properties were established. Detailed description for such type of testing is poorly described in regulatory documents (Russian State Standard, ASTM). Problem of specific test methods selection in accordance to task before the geomechanical modeling is considered. For the most issues, a series of experiments to build a failure envelope is required. Details of sample preparation for compression tests are regarded. In particular, the advantages and disadvantages of different methods for preserving in-situ core saturations are discussed: the collection of an isolated core with subsequent conservation or the preparatory work with the extraction, drying and saturation of samples. While conducting multi-stage compression tests for building Mohr circles, chose of the right moment to stop the loading stage has a significant effect to prevent destruction of the sample in the early stages. This paper demonstrated that for specimens characterized by a shear failure type, it is recommended to focus on the plot "axial stress - volumetric strain". In particular, the inflection point of the curve, that is the moment of reaching the maximum value of volumetric deformation could be selected as a criterion for the loading stage termination. For samples with high porosity, a complete testing cycle to build the Mohr circles and the entire failure curve is given.

As the extensive Russian gas business matures from developing the high-permeability (Cenomanian) formations, into lower-permeability (Turonian) gas deposits, a number of economic challenges will need to be addressed in order to remain effective. The number of wells, pads and associated infra-structure and expenditure in a tight-gas environment will dramatically increase, challenging the economic outcome and environmental impact of using the established approaches. In order to achieve the maximum return, it is imperative that the established pad and well, construction and execution processes, are challenged, re-considered and subsequently optimised for the new reality. This paper will describe a worked example of such reconsideration for a potential tight-gas development in Western Siberia. Well pad construction for Oil and Gas developments in Western Siberia is well established, so very well practiced in fact that often little is changed between one development to the next, and the reservoir and well requirements are only considered through a regulatory lens. However, as the development economics become more challenging in the lower permeability environments, much more optimisation will be required in order to maximise the efficiency. The approach taken here is to start with consideration of the traditional pad design, as was implemented for three pads built during an earlier Turonian Appraisal phase; and then incrementally consider areas of optimisation until the most cost-effective and solely requisite pad design has been achieved. Instead of outsourcing pad design to a disconnected/remote third-party engineering service, hand-cuffed by decades old established practice, the approach taken was to internally create an integrated view on pad functionality, technical requirements and optionality for a successful development. The results of this approach speak for themselves, with areal percentage reductions readily achieving a level of 50%, with an obvious associated cost improvement. Additionally, the flexibility and optionality that can be built into incremental pad design/construction offer new insight into what can be achieved in these very challenging environments. As developments move into more challenging rock quality, the previous approach of delineating and carpet-bombing a field with wells and pads becomes less effective and highly impactful on the overall development economics. Almost all Global tight-rock developments are phased, in multiple stages, based on improving sub-surface, productivity and well-design knowledge incrementally. Additionally, the inherent ability, via this method, to minimise the environmental footprint cannot be overstated. Techniques that will be presented show how a holistic approach will result in the most effective use of limited resources and a reduction of the impact of the surface footprint. The novelty of this approach is that it challenges what has become, over decades, the rigid and inflexible approach for pad construction that is linked with a higher-permeability field development era. It offers a new and refreshing insight into what may be achieved when an integrated and internal approach is taken to such considerations, while remaining cost effective, fully compliant and flexible.

The choice of the optimal trajectory of horizontal and directional wells, the placement of frac-ports for multistage hydraulic fracturing, taking into account prepared input data (using geological and geomechanical modeling with the rock properties anisotropy), provide optimization of hydraulic fracturing operations and field development. Formation T contains more than 3 trillion m 3 of gas, and is already an object of close attention of the largest oil and gas companies. The unique character of the object is due to the high reservoir compartmentalization of the collector and low permeability. Therefore, the main development strategy for the reservoir is to drill low-angle and horizontal wells, followed by multistage hydraulic fracturing. The main goal of multistage hydraulic fracturing is to join productive intervals and at the same time avoid undesirable fracture breaks into neighboring layers. To achieve this goal, several tasks were solved: creation of a petrophysical and geological basis for geomechanical modeling, creation 1D and 3D geomechanical models taking into account the rock properties anisotropy due to the high layering of the reservoir, and preparing input data for hydraulic fracturing design. For the qualitative creation of the geomechanical model at the observation wells of the field, an expanded complex of special well logging studies has been performed, borehole measurements of reservoir pressure and minimum horizontal stress have been carried out according to the results of stress tests, core sampling and research to determine petrophysical and mechanical properties. The analysis of the obtained information revealed the features of the stress state along the section and reservoir area, which were taken into account in the design of hydraulic fracturing. Geomechanical modeling was carried out in a uniform work procedure, which made it possible to unify the result, improve the quality of calculations and forecast parameters for horizontal wells.

Constant growth of commercial hydrocarbon (HC) consumption requires for the oil and gas industry to be involved into exploitation of unusual oil and gas reserves, preventing HC supply shortage on the global market. The fields with conventional reservoirs being actively developed during the last century have a tendency now to reduction of routine parameters of HC production. Now more and more attention is being attracted to tight reserves, which have to be studied in unconventional ways. This article focuses precisely on complex reservoirs, in which reserves are classified as tight. A complex quantitative assessment using several different technologies for long-term monitoring under difficult conditions has shown favorable results.