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.

The structure and composition of oil reserves deteriorate in the course of a mature oil field development due to geological and technological factors. The geological factors include vertical and lateral macro-and micro-heterogeneity of the reservoirs under development. At the same time, macro-heterogeneity leads to the formation of bypassed residual oil in low- permeability and stagnant layers, zones and lenses that are not exposed to stimulation, while micro-heterogeneity contributes to the formation of residual reserves of capillary oil and oil films. Technological factors include impossibility to fully account for reservoir heterogeneity when substantiating well spacing, pressure gradient, or flooding technology. The key problem here is the lack of clear understanding of the distribution pattern, quantity and deterioration of the quality of residual oil in water-flooded reservoirs, which makes it challenging to reasonably select a technology for effective oil extraction. Despite the improvements constantly made to the production logging, hydrodynamic and interpretive, seismic, lithofacies and other methods of exploration and residual reserves modeling, it is often impossible to obtain timely reliable information about the percentage of reserves depletion and their coverage with the development activities. This paper proposes another method — optical — that, in combination with well logging and hydrodynamic surveys as well as geological and hydrodynamic simulation, has been tested to assess the quantity and spatial pattern of residual oil reserves of the Kynovian ( D o ) and Pashian ( D 1 ) horizons at the experimental site of the Romashkinskoye oil field (Devonian formation). From the theoretical and methodological standpoint, this method is underlain by the results of in vitro studies of core columns and involves the selection and research of optical properties of oil wellhead samples, mathematical processing and correlation of the obtained optical and field data. The obtained estimate of residual reserves is compared with data derived from geological simulation, the most promising automated method for identifying, geometrizing and calculating residual recoverable oil reserves ( RROR ). The proposed method offers such advantages as ease of use, promptness, reliability, functionality and cost-effectiveness. It uses actual data on cumulative well production and takes into account the current reservoir and fluid porosity and permeability ( P&P ), which provides the possibility to obtain more precise estimates of the RROR quantity and spatial pattern.

The article covers methodology for rapid assessment of optimal development parameters for offshore fields. The first stage determines maximum allowable expenditures for field construction that make the project efficient, following selection of the offshore facility type required for production. The second stage evaluates the well density for every cost-effective offshore facility considering the best economical option for field development.

The paper considers gas option beginning and forcing in case of U 2-6 reservoir of oil and gas condensate Novoportovskoye field, which is an underlaying-typed oil rim with a massive gas cap. Based on conducted analysis the recommendations for the further gas option development with oil production losses minimization and gas production maximization were formulated.

The aim of the work is to create a scenario modeling technique based on adaptation of metaheuristic multi-objective optimization algorithms to construct Pareto-optimal investment portfolios taking into account multiple restrictions on the company's portfolio. Investment portfolio is a tool for company's resources management. The process of portfolio construction through a combination of individual investment projects aims to optimize available resources utilization. Currently, there is no single approach to determining the optimal portfolio, since portfolio requirements depend on a particular company. Due to its simplicity in terms of implementation, approaches based on the ranking of projects according to individual technical and economic indicators are widely used. However, if a company needs to take into account several indicators, then this approach is not applicable. An effective solution to this problem is to create a technique that allows to find Pareto-optimal portfolios. In this work, the problem statement and analysis of existing solving approaches were carried out. Based on that, methodology of scenario modeling of a company's portfolio was created. The posed problem belongs to the class of NP-hard problems and for its efficient solving it is necessary to use metaheuristic algorithms. These algorithms include genetic algorithms, variable neighborhood search, bees algorithm, etc. Genetic algorithm NSGA-II is widely used for solving multi-objective optimization problems due to its high performance and ease of use. This algorithm was adapted to solve proposed problem. Based on it, a methodology was developed for the formation of Pareto-optimal investment portfolios, taking into account financial and infrastructural restrictions. Testing of the methodology was carried out on a dataset of synthetic projects simulating real investment projects. Various combinations of this projects simulated investment portfolios. The optimization objectives were maximization of net present value (NPV), maximization of cumulative oil production and minimization of total investments. In order to control the quality of the results obtained using genetic algorithm, the problem was also solved by using variable neighborhood search. However, the quality of the results obtained using genetic algorithm was higher. Analysis of the results allows us to consider the use of multi-objective optimization as a tool for forming a pool of investment portfolios, which provides flexible company management. In the proposed work, it is shown that the problem of scenario-based modeling of company's investment portfolio can be considered as a multi-objective optimization problem. Based on the existing metaheuristic algorithms, a Pareto-optimal investment portfolio search methodology has been developed. Proposed methodology can effectively solve the problem of managing company resources.

The well integrity monitoring including Sustained Annulus Pressure (SAP) assessment on offshore stationary platforms in the conditions of a limited number of well slots plays an important role in the development of oilfield with thin oil rims and a massive gas cap. The presence of SAP leads to uncontrolled release of gas or liquid to the surface, disruption the operating condition of the wells and its completion components, that overall can result to severe accidents at the offshore oil and gas production facility. Another difficulty that SAP brings is secondary gas cap accumulation across untargeted reservoir zones that might lead to blowouts in operating wells. To identify the causes of SAP, constant monitoring of annulus pressure, as well as proper diagnostics are needed. One of the most reliable and effective methods for identifying SAP causes is Through-Barrier Diagnostics that able to accurately localize reservoir-sources of SAP behind multiple casing strings in the wells, which helps production engineers further production strategy and weighted workover planning. Conventional diagnostics on identifying SAP sources is significantly limited by complexity of the well construction and downhole equipment. This paper describes using of Through-Barrier Diagnostics on the sources of SAP identification on the ice-resistant stationary platform named after Yuri Korchagin, detailly explains the approach and challenges on real case studies. High precision temperature and passive spectral acoustics play a key role in described technique. Passive spectral acoustics, which have a scanning radius of about a few meters, helps to detect fluid flows in the reservoir and behind casing channels in cracked cement.

The effective development of thin oil rims by horizontal wells is an urgent area of technological development of oil and gas companies in the context of an increase in the portfolio of new fields with significant reserves of free gas. A key feature of the development of oil rims is gas coning and therefore it is necessary to limit the productivity of wells, which leads to a high sensitivity of project profitability to reservoir properties, economic conditions and the development system. For successful development it is necessary to optimize all the components of the project – wells count, downhole equipment, transport system. Some works relating to the theory and methodology of developing oil rims describe approaches to calculating the optimal well spacing [ Khasanov et.al. ], the number of wells per bush [ Samolovov , Mozhchil et.al. ], and ground facility [ Povyshev et.al. ]. Special cases of comparing different well placement systems are widely represented in the literature, for example, in [ Sugaipov et.al. ]. An increase in the share of oil rims production leads to the need to find common solutions to such optimization problems. In this paper, we consider the question of determining the optimal location of wells by systematic selection of an in-line or radial development system. When horizontal wells are placed on oil rims in the form of an in-line development system, optimal conditions are created for the uniform production of oil reserves, since the distance between the horizontal wells is the same for all cross sections of the well and the gas cone is formed uniformly along the direction of the horizontal wells. However, when combining well trajectories into one bush, in this case there is a need for large reach from the wellhead or in a small number of wells in the bush. When horizontal wells are placed on oil rims in radial development system, optimal conditions are created to minimize well reach, however, interference occurs between wells in the reservoir due to the distance between wells changing along the direction of the horizontal wellbore. The purpose of the work is to determine the conditions under which in-line or radial well placement is optimal.

The present work is dedicated to the problem of developing oil and gas condensate pools with thin oil rims for neocomian deposits in the Urengoy region, and to the search for effective methods of oil production from thin rims. The key problems in the development of thin rims are the low cumulative oil production per well, as a result - low profitability and oil recovery ratio. The reasons are known: a sharp decline in initial oil rate due to the rapid increase in water cut and growth of gas factor associated with the water and gas coning. The results of hydrodynamic modeling at early stage in the development of oil rims often lead to optimistic forecasts that are not confirmed in practice. The paper provides an analysis of the reasons for optimistic calculations, tuning up models for the results of the development and operation of oil wells with different completion relative to the GOC. Obtaining history-matched oil and gas production systems made it possible to obtain a more reliable production forecast for oil wells, to substantiate the preferred target subsea depth for the completed interval in the rim and the type of completion. Scenarios with the completion of the horizontal section at a distance of one third from the GOC and OWC, or in the middle between the contacts, have been considered and analyzed. A comparison of the calculated performance of the wells with the actual one had been made. An economic evaluation of the operational efficiency of wells drilled on thin rims shows that their profitability based on oil production is marginal. The closer completion intervals of the oil horizontal wells to the GOC the higher economic efficiency of their operation due to additional volumes of gas and condensate production from the gas cap. The use of double-wellbore and multi-lateral completion of horizontal wells in the oil rim increases the economic attractiveness of the project. The integrated approach proposed in the paper to the organization of production and oil and gas processing systems from such oil wells makes it possible to technologically efficiently operate wells and ensure almost full utilization of associated gas. The joint development of gas condensate pools with thin oil rims allows for the cost-effective development of the ones.

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.

This work describes the technological solutions that were used in the development of the Novoportovskoye field - a large oil and gas condensate field in the Yamalo-Nenets Autonomous Okrug. In particular, optimization of the associated gas utilization strategy is considered by organizing the reservoir pressure maintenance. The decisions were based on 3D mathematical calculations, analytical estimates, analysis of field information and reservoir simulation. The paper presents the results of calculations performed to determine the specific efficiency of gas injection at productive formation. Additionally, weight coefficients of gas injection were calculated for gas well sites to identify the best injection zones. The paper provides the estimation of the current effect of the continuous two-year gas injection. The formation response to the gas injection into the gas cap was estimated by the usage of pressure-observation wells data, data from wells equipped with fiber-optic monitoring systems and by performing retrospective simulation. The calculations made it possible to achieve complete utilization of associated petroleum gas and significantly increase the oil recovery factor.

Significant acceleration of the calculations used to create three-dimensional geological and hydrodynamic models is discussed. Detailed 3D models of large and giant reservoirs requires significant computing power for their creation. All available seismic, geological and hydrodynamic data on the oil and gas field, which must be taken into account in a detailed model, require the construction of a grid from several hundred million to several billion blocks. A method proposed for integrated static and dynamic model calculation allows the most efficient usage of a parallel computing cluster system capabilities.

A new approach for numerical modeling of a set of compositional dynamic models of oil and gas fields coupled by the same surface network is considered. A unified coupled system of equations is constructed to jointly model reservoir and surface network processes in the method proposed. A new integrated model "reservoir-well-surface network" is a unified system of equations that includes a description of the physical processes in the reservoir, frictional and static pressure losses in wells and the surface network. The model includes technological constraints induced by well operation modes and surface network equipment. The unified system is solved fully implicitly at each time step. The fluid model can be described both with tables in Black Oil format or with equations of state. If several fields with compositional fluid models are coupled by one surface network then specially designed algorithm is applied to automatically derive a single equation of state. The latter is then used to calculate the fluids properties of the mixture in the surface network.

The paper describes the experience of lift models creating in case of oil rims of the Tazovskoe and Novoportovskoye fields. There is analysis of the actual well performance with high gas oil ratio, the software capacity to the gas-liquid flow modeling in the well, and review of existing analytical techniques for unknown model parameters prediction. The problems and limitations of existing methods are emphasized and approaches to their solution are proposed.

At present, in the oil community due to active implementation of information systems, modern well survey technologies, systems of registration of various data coming from oil fields, interest in the tasks of building mathematical models of oil and gas production processes has increased. The «Smart Field» concept is a set of organizational, technological and information solutions for managing oil fields and oil production facilities, based on formalized models of business processes, enterprise operating model, asset integrated model ensuring optimal management of the asset, while meeting targets and existing limitations. It is based on a mandatory procedure of complex analysis and decision-making based on integration of information, technology and personnel. An integral part of the «Smart Field» project is an Integrated Oil Field Model (IM), which includes the following components: formation model, well model, gathering and transportation system (G&TS) model, formation pressure maintenance system (FPM) model. The integrated model is a tool for calculating potential capacity and limitations, production optimization and performance indicators planning, taking into account mutual influence of the integrated model components. Vostochno-Lambeishorskoye field is located in Usinsk District of the Republic of Komi in the Russian Federation. The average oil flow rate for this field is about 100-150 tons per day, field watercut - 15.5%, the field is under the first stage of development. Taking into account the asset development prospects the integrated model construction and its further application will make it possible to increase the economic efficiency of this field development. In view of existing problems associated with the specifics of operation of electrical submersible pump (ESP) units at fields with high content of hydrogen sulfide, it is proposed to introduce a gas-lift operation method. In order to assess the technological feasibility of converting the well to gas-lift operation method and the project profitability, this article provides equipment selection and simulation with the use of a specialized software product. The aim of the article is to solve the problem of low efficiency of high-sulfur field operation by designing a gas-lift method using integrated simulation tools. The following tasks have been considered and solved as part of this work: Gaslift calculation for the entire production well stock in well simulation models; Sensitivity analysis of the obtained layouts for changes in formation parameters; Creation of a simulation model of a ground gas injection system; Conducting a series of calculations using an integrated field simulation model, where Visual basic for applications (VBA) script acts as a control element; Economic assessment of the proposed options. The integrated model is updated for the field operation parameters as of 10.01.2020. The data are provided by the Customer and are assessed as reliable.

For decades, computer simulation has been an inevitable part of hydrocarbon reservoir development. 3D reservoir models of productive reservoirs and gathering system pipeline models exist for almost all operated fields. The recent concept of digital oilfield relies much upon performing computer simulation in order to automate the development process. Operational field development management is one of the processes that can be automated within this concept. However, conventional computer simulation techniques based on the above-mentioned 3D reservoir models are ill-suited for automation of operational development management. This can be attributed to the fact that creating, history matching, updating, and calculations of such integrated models are very time-consuming. Integrated models based on simplified models of productive reservoirs can be regarded as a basic means of operational field management. A case in point are models built on material balance equations. However, this approach has its drawbacks. The main problem lies in having to do double the work. One has to have two models for each productive reservoir: one model for operational development management (simplified model) and the other for conventional modeling (3D reservoir model). This paper considers solving the stated problem by transforming a conventional 3D reservoir model of a productive reservoir into a material balance model and provides comparative analysis of both modeling approaches.

The paper considers a new approach to working with mature fields, assessing the effectiveness of current development, searching and forming case studies on optimization of development and associated costs. The approach is based on several consecutive steps: – the most accurate understanding of the composition of current costs, their correct accounting for calculating the profitability of the well stock, – the definition of low-profit wells and clusters, – search and evaluation of measures to optimize the development system and work with the wells, – search and assessment of possible measures to reduce existing costs based on best practices. In the framework of the described methodology, each individual producing well is considered as an independent business unit, the combination of which ultimately forms the overall economy of the field. The field, in turn, is considered as a closed system of the well - wellbore - BPS / CPS, each of whose elements is interconnected. The results of applying this approach are presented on the example of the Renovation pilot project, within the framework of which a number of optimization cases were formed and successfully implemented at one of the fields of Gazprom Neft PJSC. Also, during the implementation of the project, a tool program was created that allows economic evaluation of all possible activities in the logic described above, to assess the impact of each element of the system on each other as a result of the implementation of the events. Thus, a new algorithm has been formed and partially automated for continuous monitoring of current production at the field, identifying "problem" areas and the formation of optimization measures for such areas.

The article is devoted to development of optimization methodology for parameters of oil rims exploitation system by line drive pattern of depletion type horizontal wells. Solution for transformation of flanking oil rim to subjacent oil rim with massive gas cap has been obtained. Moreover, empirical equation which includes gas cone height under exploitation of subjacent oil rim by horizontal well has been also derived. Known analytical solution has been supplemented with derived corrections with a view to convergence of the solution in the case of flanking oil rims. The solution includes set of dimensionless parameters which depend on formation characteristics and economic features of the project. Solution of the problem allows to determine the oil rim profitability without using complicated hydrodynamic computations at the stage of estimation.

The purpose of the article is describing a tool for analysis and waterflooding management of large fields with a long development history. The developed tool contains a physical and mathematical model of the reservoir, which is a self-consistent solution of the equations of material balance, filtration and PVT correlation for each waterflood cell. To verify a simplified reservoir model, it is possible to forecast using historical well control parameters with their automatic adaptation. The paper describes the main stages of user interaction with the tool and its functionality. The results of a retrospective forecast for two different development reservoirs has been presented, the lacks and conditions of the model applicability were described. Integration with the tool on the basis of optimization algorithms was made and the results of multivariate calculations for the search for a scenario for developing a large oil and gas field with the best economic effect are presented.

The article demonstrates features of using an Integrated Asset Model (IAM). The description is given for assessing of model reliability with main criteria emphasis. Also acceptable deviations for those criteria are analyzed. The solutions are proposed for problems arising when IAM is used for forecast calculation. A methodical approach is presented that allows to verify production data and to calibrate network elements in fast and effective way. The paper shows IAM updating algorithm which allows to perform calculations with the necessary accuracy.

Severneftegazprom OJSC is the operator of the Yuzhno-Russkoye field. In accordance with the field development strategy, in 2018 the commercial development of the Turonian formation began, envisaging the drilling of more than 100 wells to a formation with abnormally high pressure and low permeability and their tie-in to the existing gas gathering network. The task that faces the company is to assess the attainability of the planned targets on the basis of the existing field development concept and surface facilities configuration. A separate focus is on the geological uncertainties analysis of the Turonian formation and their impact on the gas production profile. For the uncertainty analysis, a sector hydrodynamic model was built and history matched, which included the first launch clusters with the U-shaped wells and the multistage hydraulically fractured wells (MSHF). The assessment was made for the impact of geological uncertainties, the alternative well locations, as well as the number of hydraulic fracture stages and fracture parameters on the cumulative gas production. To study the interference of new wells with the existing network, an integrated model was created, which combined the full-scale Black Oil hydrodynamic models of the Cenoman and Turonian reservoirs with the unified compositional gathering network with more than 250 wells.