The aim of this work is to create a tool that can help in making difficult investment decisions about the sequence and commissioning periods of new hydrocarbons fields, maximizing expected monetary value and considering infrastructure constraints across a group of assets in terms geological uncertainties. The approach is to use probabilistic calculations and the modern portfolio theory, adapted to the conditions of the sphere of petroleum exploration and production. The goal of optimization is finding a strategy for new assets development that would have the maximum profit with minimal economic or technological risk. Measures of spread of a random variable (a.g. NPV) around its expected value are used to measure an economic risk. Also, we propose a method of technological risk assessment, reflecting the probability of hydrocarbon production in the required range. To obtain a probability distribution of the objective function according to uncertainties in input data the stochastic Monte-Carlo simulation and "Latin hypercube" technique were used. Due to high dimensionality of the problem, heuristic optimization methods have been used to solve the optimization task. A proxy model, based on the change in recoverable reserves volumes, starting production rates and decline rates of hydrocarbon production for newly drilled wells is proposed in this paper. The model combined with the calculation of economic measures. The combination of simulation models with an optimization algorithm allows to analyze a set of mathematical equations, containing a number of decision variables (e.g., years of commissioning periods and/or the paces of drilling wells) and to determine their optimum values, leading to a solution with the desired ratios of the expected economic effect and risk value. As a result, the numerical experiment revealed that application of the portfolio optimization methods allows to find new non-obvious solutions. The result of portfolio analysis is not a final product of project works, but, however, may be a basis for explanation of optimal development scenarios for a group of assets and can help in finding non-obvious, but more effective investment and project decisions. A comparison of four heuristic algorithms in the single-criterion optimization problem was conducted. Conclusions about the effectiveness of the algorithms in terms of time and the fitness function values were made. The developed model and methods were used in task of searching the optimal development strategy for a group of real hydrocarbons fields.

This paper considers methodology aspects for constructing one-dimensional (1D) geomechanical models and stability calculations for the case of viscoplastic behavior of rock under stress with a case study of the Vikulovskaya sandstone from the Em-Egovskoe Field in West Siberia.

The paper presents an algorithm for estimating the error of the 1D geomechanical model taking into account the measurement errors of the instruments and the correlation dependencies used. The sensitivity analysis of the resulting error to the quality of the source information was also performed. A confidence parameter has been introduced to assess the contribution of a measurement to the calculations. An approach is proposed for the transition from the convergence of correlation dependencies to the error of the correlation used. The application of this methodology allows at the initial stage to draw a conclusion about the quality of simulation results and take measures to increase the reliability of calculations.

The article is devoted to increasing the efficiency of using equipment with a solid bulk layer due to the application of the developed technology for dense laying. This technology is applicable for loading solid granular materials, for example, catalysts and adsorbents. The current issue of adsorbent bulk layer compaction in the apparatus for drying associated petroleum gas in the oil field is considered in the article. The article investigates the hydrodynamics of the gas flow through the adsorbent bulk layer by the computational hydrodynamics method, performed in a specialized software package with finite element analysis, to determine the effective method of laying the material. The numerical calculation results are verified by analytical calculation, and then effective values of the bulk layer porosity are determined. The dependence of the pressure drop in the adsorbent layer on the feedstock flow velocity at the inlet is established. The dense laying efficiency is confirmed by hydrodynamic modeling, made it possible to develop a new device for bulk material dense laying and the technology for its use in the apparatus. The developed device efficiency has confirmed by experimental studies, expressed by the compaction coefficient. An industrial device design was developed to increase the industrial equipment efficiency and a verification strength calculation was performed by a stress-strain state modeling method. The technology of the device using in an industrial apparatus has been developed.

When operating production oil wells with electric submersible pump units in conditions of high free gas content in the pump, the mode of flowing through the annular (FTA) may occur due to a combination of factors, such as: relatively high pump intake pressure sufficient to maintain self-flowing conditions through annulus, large amount of gas coming to annulus, high degradation of ESP parameters which prevents decreasing BHP and others. The authors of the article have reviewed literary sources, formulated the relevance of the problem of flowing in annular space of artificially lifted wells. The full characteristics of ESP was adapted by the results of flow loop tests with gas-liquid mixture. It made it possible to develop the model of ESP operation under FTA conditions, which was proven on field cases (four examples). Recommendations for FTA mode optimization discussed.

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.

Development of oil rims at oil-gas-condensate fields is accompanied by a high risk of gas coning which leads to well productivity losses followed by conversion of such wells to an idle stock. In order to increase the oil recovery factor of oil rims and to eliminate early gas breakthroughs, horizontal wells drilled in thin oil rims are equipped with autonomous inflow control system. The study describes the experience of AICD application for one of the largest fields in East Siberia with an oil rim and a large gas cap, where an integrated analysis of the AICD well performance was conducted for the first time in Russia. This analysis includes: choosing well-candidates, performing AICD lab testing, sector reservoir simulation, modeling of AICD effect, followed by the actual well performance analysis after running AICDs. All this became possible due to the well-organized cooperative work of the operator and the contractor. The wells included in this study were successfully put into production at lower GOR values compared to their surrounding wells

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.

The purpose of this paper is to generalize the experience of applying the thermo-gas-chemical treatment methods (TGCT) using binary mixtures based on ammonium nitrate to enhance the inflow at oil fields. More than a decade of industrial tests of binary mixtures injection into mature fields’ marginal wells showed a multiple long-term increase in oil inflow. The positive experience of TGCT application to Tatarstan oil fields strongly suggests the perspective of its application to the layers with high content of organic substance in rock matrix including Bazhenov formation reservoirs for those technologies have been only battle-tested. The development of mathematical methods for describing the TGCT process considering the multiphase and multi-component nature of the process, chemical reactions and transformation of the reservoir structure allow to respond to the features of each field at the macro scale, to identify micro-scale features and changes in the reservoir matrix structure, using a percolation approach, and allowed to assess the current state of the bottom-hole zone adequately and conduct pilot tests on specific wells in strict accordance with the established technological regulations and control of hydrodynamic parameters.

The era of production of readily available oil, which requires a relatively low level of capital costs, engineering solutions and the lack of use of new technological solutions, is over. At the moment, in the world and, specifically, in the perimeters of Gazpromneft, the bulk of the assets of hydrocarbon fields are complex in type and structure deposits with sufficiently high oil reserves, requiring both high capital costs and the adaptation of new technologies for effective development. Achimov formations Ach18-1 of the Yamburg deposit are bright representatives of the reservoir with a complex structure and very low, even for Achim formations, permeability. Average permeability of formation Ah 18-1 0.15 mD. At the moment, the only technology that allows achieving the profitability of the project is the use of wells with multi-stage hydraulic fracturing. However, a high share of hydrocarbon raw materials remains in the formation and for development, new technologies are being sought that will increase the level of net discounted income, as well as increase the oil recovery ratio. For consideration, the technology of mixing oil displacement with gas was chosen as one of the most promising technologies for the conditions of the Yamburg oil field. Gas injection technology was tested in a number of countries: the USA, Canada, Brazil, Venezuela and Norway, including was considered on some projects of Russia (USSR) ( Figure 1 ). There are no direct analogues for Yamburg conditions, however, this technology allows us to obtain a REF increase of 1.5 to 2 times among the fields considered, on average, REF with the use of mixing displacement is about 46%, the increase relative to the standard Flooding is 7-12%. The promise of this method is that it can be used in deep-lying formations with low filtration-capacitive properties, high thermobaric conditions, the method allows not only to maintain formation pressure, but also to increase the oil recovery coefficient. Increase of oil recovery coefficient is achieved due to achievement of mixing pressure during gas injection, which leads to decrease of residual oil saturation and increase of phase permeability in gas-oil system. It is worth noting that the characteristics of the reservoir oil of the object under consideration (high gas content, a significant proportion of light fractions in the reservoir fluid composition) favor the use of gas methods to increase oil recovery, since the values of minimum mixing pressures for various types of injected gases (including pure methane and nitrogen) are lower than the initial reservoir pressure. Figure 1 REF when applying mixing displacement technology. To assess the efficiency of mixing displacement at the Yamburg field, analytical calculations were carried out to determine the minimum mixing pressure with the formation oil of the Ach18-1 formation (the main development object). Based on the results of the calculations, the following conclusions were made: The mixing pressure for the formation oil of the Yamburg field varies from 417-500 depending on the composition of the injection gas. Mixing pressure practically does not depend on the degree of depressurization of reservoir oil (possibility of development in dissolved gas mode with switching to gas injection at any moment) To clarify the MMP values, it is necessary to conduct slim tube for different injection gases and on a larger number of oil samples.

The aim of this work is to develop an approach to multivariate optimization of development systems for tight oil reservoirs of the Achimov formation, where large volume of drilling of RN-Yuganskneftegaz LLC are currently concentrated on. The approach described in the paper is an integral part of the corporate module "Decision Support System for drilling out new sections of tight oil reservoirs", which allows making quick design decisions for new drilling sites of target objects. The main factors that reduce the development efficiency of such objects, in particular with the use of water flooding methods, are the low piezoconductivity and high heterogeneity of a reservoir that leads to relatively high rates of decline in fluid production and, in particular, to long response productivity time for production wells to injection. In this paper, we consider a multi-criteria assessment of the effectiveness of various well placement systems in various conditions that characterize the geological features of tight oil reservoirs and low-connected reservoirs. A specific example is considered - tight oil heterogeneous reservoir of the northern part of Priobskoye field, for which oil production is calculated by numerical hydrodynamic modeling methods. As a result of development and testing of the approach: Main geological and technological parameters are estimated that affect development indicators and empirical dependencies derivation (of the development indicators) on the geological features of the selected clusters of Priobskoye field target objects; A method being proposed for description of a various geological features of the reservoirs of Achimov formation target objects by using synthetic stochastic 3D geological models; A physically-meaningful approach is proposed for adaption of well dynamics that reveal tight oil reservoirs of target objects using synthetic 3D geological and hydrodynamic models. Based on the actual data of development (well operation), formation parameters are determined for each cluster (section) of the target objects of Priobskoye field, which differ in geological features and development indicators; Prediction multivariate numerical calculations were carried out for various well placement systems under various geological conditions (≈ 3 million calculations). A database of calculated development indicators has been formed for each variation of the well placement system; Different options are presented for visualization of calculation results in the form of dimensional templates of optimal development systems for tight oil reservoirs; Various options for sensitivity analysis visualization for the effectiveness assessment are presented of various well placement systems to changes in geological, technological and scenario conditions.

The near-critical initial state of the formation fluid with a unique content of C 5+ components in a tight reservoir with high temperature and abnormally high reservoir pressure (AHRP) causes significant difficulties in collecting samples of the formation fluid and assessing their adequacy to the actual reservoir mixture both in composition and identified phase state (gas condensate or oil) and phase behavior. The paper presents the result of the work of the project multidisciplinary team, which includes specialists from the PJSC «NOVATEK» group of companies and the leading Russian Institute of Oil and Gas Problems (OGRI RAS), of studying the near-critical gas condensate system in a HPHT tightreservoir. The effect of well completion and sampling conditions on the composition, phase state and phase behavior of fluid samples is shown. The influence of formation water and residual liquid hydrocarbons (HC), capillary effects, adsorption, and the specifics of the PVT-model tuning on the dew point pressure, the condensate lossdynamics, and the variation of composition and phase state of the fluid with depth is assessed. The results made it possible to clarify the understanding of the reservoir system,develop a program for further research, and improve the history matching of the flow model. The performed modeling of various factors in a porous medium for the conditions of the studied reservoir showed that the presence of formation water and capillary effects do not noticeably affect the phase behavior of the fluid, but the possible presence of scattered hydrocarbons and the adsorption / desorption of hydrocarbon components can lead to considerable changes in the dew point pressure and the condensate loss dynamics. The significant influence of the PVT model tuning on the calculated distribution of the initial fluid composition over the reservoir volume is demonstrated, including the position of the gas-oil contact and its type (classical gas-liquid contact or supercritical transition to the liquid state).

The prevailing economic situation warrants oil production emerging realities. Increased producibility and efficiency are promising ways of oil industry developing for now. That's why the advanced use of digital technology in the oil industry is one of the priorities today. Digital technology adoption helps to reduce costs by improving existing workflows, and also provides the capability over the longer term to achieve high levels of economic efficiency in the hard-to-recover reserves development. The study presents key principles for geological and technical measures (GTM) efficiency improving based on machine learning using an accumulated data of previous work statistical data. The study also demonstrates a method based on the results obtained that allows modifying the existing methodology for developing reserves and involving reserves that are unprofitable today. The use of machine learning has been examined from a different approaches point of view, such as linear regression and decision tree. The convergence of actual and predicted data was more than 80%, based on a test sample. The proposed methods and workflows are only the first steps in the technology development to improve the next-generation GTM efficiency. Automatic recruiting helps to improve workflows and optimize productivity. That's why the company doesn't go beyond its initial costs, and can also use reserves that are unprofitable today by changing the investment projects setup methodology.

Most of the Russian oil fields consist of the complex reservoirs and it is required to apply secondary reservoir development methods, such as waterflooding, in order to increase reservoir development efficiency. However, for highly heterogeneous reservoir with viscous oil, "classical" waterflooding is not enough and there is a need to use enhanced oil recovery methods, one of which is polymer flooding. The prospects polymer solutions injection have been proved in different fields worldwide, including the East-Messoyakhskoye field at the PK1-3 reservoir with high-viscosity oil. At this field, polymer flooding pilots were carried out and taking into account the obtained field data, the geological and dynamic model were updated, which helped to improve the process physics understanding and evaluate the possibility of sweep efficiency increase during project implementation. This paper describes the challenges, difficulties, applied approaches, results and experience obtained in reservoir simulation of polymer flooding.

The uniqueness of this work lies in the application of the approaches and experience of geomechanical modeling accumulated in the oil and gas industry to solve the problems of building mines, which reduced accident rate and, as a result, minimized the cost of eliminating the consequences of complications, as well as accelerating the commissioning of the mine. The peculiarity of the simulation was to take into account the temperature of the rock mass and freezing wells, which affected the stress state, safe drilling window and cementing parameters during the construction of additional freezing loop wells, as well as during the strengthening of the rock mass. Based on the results of the well logging, seismic surveys and geomechanical modeling, the stress state of the decompression zone is estimated and the parameters of the cement slurry injection when attaching wells and strengthening the rock mass to isolate the shaft from aquifers are recommended.

In this paper we present the methodology to predict the value of the complex optimality criteria from the parameters of the oil field development system such as well spacing, the distortion factor, the type of well completion, the horizontal length of the end of switching time, etc. The method presented in this paper is based on the results of multivariate calculations in a hydrodynamic simulator and the use of correlation models of machine learning (ML).

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.

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.

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.

A concept has been developed for gas, gas-condensate and oil fields exploitation planning in the Arctic region, taking into account the limitations of the existing external and internal infrastructure. The work was carried out as part of an integrated project management system to determine business opportunities and initiate the transition of field development projects to the pre - project development phase (Pre - FEDD). The paper considers the formations and geological structures of the Bolshekhetskaya Depression in the license areas: License area "Nakhodkinskiy" Licensed area "Pyakyakhinsky" License area "South Messoyakhsky" License area "Halmerpayutinsky" License area "Salekaptsky" Licensed area "West Tazovsky" License area "Vareisky" The choice of the profile of the horizontal section of the well is one of the main issues in the design and affects not only the final gas and condensate recovery, but also helps to clarify the geological structure of the formation during the well construction, as well as include all productive layers in the development, reduce the risk of complications during operation. Usage of longer horizontal wells will reduce drill footage; to increase the flow rate and profitability of wells; it is more rational to use formation energy due to lower values of depression on the formation and correspondingly reduced losses of condensate in the formation.