Offshore Oil Field Development Research Articles

Влияние мелкозалегающего газа на проектные решения по освоению морских газоконденсатных месторождений на шельфе арк­тических и суб­арк­тических морей

The article discusses issues related to shallow gas influence on design decisions for the development of offshore oil and gas condensate fields. The authors show the presence and distribution of shallow gas accumulations in the upper part of the geological section and its influence on the quality of seismic surveys. The release of shallow gas has caused many serious accidents at offshore drilling rigs and oil and gas production platforms. The main danger of shallow gas deposits is when drilling intervals for the conductor and surface casing due to the lack of blowout equipment at the wellhead. The authors analyze the areal and depth distribution of shallow gas in the Arctic and subarctic seas, and find out that small deposits of several hundred meters in size are most common. The main methods of detecting and studying shallow gas accumulations above gas-bearing structures are high-resolution seismic exploration, drilling of engineering-geological wells and pilot holes with well logging. The researchers reveal the main features of the wave pattern indicating the gas saturation in the upper part of the section. They present the main technical solutions for the development of the Lunsky, Kirinsky and Yuzhno-Kirinsky oil and gas condensate fields located on the self of Sakhalin Island and suggest changes in design solutions during their development in view of the shallow gas presence in the upper part of the geological section. The authors substantiate the need to create Russian software systems and methods of automated design for developing offshore oil and gas fields in the Arctic, taking into account geological and geophysical uncertainty, the shallow gas presence and technical factors.

Transforming offshore field developments with Pivotree™: an innovative technology solution for fast, cost effective, and low footprint projects

Pivotree™ represents a technology paradigm shift in offshore oil field development, reducing cost and providing a route to market for the operators of stranded resources. Conventional standalone projects, characterised by substantial upfront capital expenditures with complex equipment and high installation costs, are juxtaposed against the Pivotree™ solution, with a markedly reduced capital outlay that retains all the requisite safety and operational features associated with larger systems. A comparative study of activities, materials, and risks concomitant with different field development concepts are analysed for a range of reservoir characteristics, highlighting the financial advantages of the Pivotree™ technology using Multiple-Criteria Decision Analysis (MCDA). MCDA allows a systematic assessment and comparison of a broad spectrum of qualitative factors including safety, environmental impact, operability, maintainability, time to deploy, water depth, independence, and abandonment burden and development of a set of economic scenarios with the costs of different development concepts compared over the lifecycle phases from Drilling to Abandonment, and the Net Present Value (NPV) and Internal Rate of Return (IRR) calculated against a range of oil prices, and operating expenditures. A case study ‘Concept Select’ activity is performed using MCDA to evaluate the range of development options against the listed set of project and technology attributes. A set of weightings is provided for the purpose of analysis by the author equating to the corporate values and strategy of a fictional energy company. The MCDA analysis demonstrates that the Pivotree™ technology can unlock production from the global store of stranded offshore discovered resources.

Synthesis of biological nanocomposite fluids and enhanced crude oil recovery

Aiming at the problems of small pores, complex structure, large seepage resistance, and poor recovery effect in the development process of offshore medium and low permeability reservoirs, a green and environmental friendly biological nanocomposite fluid (BNF) was developed to enhanced crude oil recovery (EOR). Fe3O4@SiO2-Ag nanoparticles (NPs) were synthesized in the laboratory, and citric acid, tannic acid, sodium alginate, and trehalose lipids were used as surface modifiers for NPs and as fluid stabilizers. The nanocomposites were characterized by SEM–EDS, TEM, FTIR, XPS, XRD, and VSM. The EOR mechanism of BNF was studied by laboratory experiments, in which the interfacial tension can be reduced by 80 %. Moreover, 500 ppm BNF could keep oil and water emulsified for more than 3 months. Static separation of oil droplets and dynamic stripping of oil film exhibited obvious effects, and the bioactive substances’ dispersant and NPs can jointly drive away residual oil. The experiment on core displacement of crude oil showed that 500 ppm BNF can enhance oil recovery by 15.56 % on the basis of water flooding. The BNF oil displacement agent is economic and environmental friendly, providing a new method for the green and high-quality development of offshore oil fields.

Study on formation of methane hydrate in rotating packed bed

Offshore oilfield development process often carries a large amount of associated gas, most of it needs to be emptied or burned, resulting in a large amount of waste and environmental pollution. Hydrate storage and transportation technology has the advantages of simple process treatment, good offshore adaptability, good safety and relatively low investment. It is one of the important recovery technologies for associated gas in offshore oil fields. However, the long induction period of hydrate formation, the difficulty of gas dissolution, and the difficulty of continuous formation hinder the improvement of hydrate formation rate and gas storage density, and hinder the development of hydrate storage and transportation technology. High-gravity technology may be one of the development directions of new hydrate rapid formation reactors due to its small size and high mass transfer capacity. In this paper, a small-scale RPB was designed independently, and the effects of high-gravity factor, initial pressure, and packing type on hydrate formation were assessed by calculating the gas consumption, gas consumption rate, gas storage density, and gas conversion rate of hydrate formation under each experimental condition. The results show that in the range of high-gravity factor and pressure tested in the experiment, the increase of high-gravity factor and pressure can significantly accelerate the hydrate formation rate, which can be increased by up to 177 %, and the maximum gas storage density can reach 148.88 V/V. The type of packing has a strong influence on the rate of hydrate formation, and the principle of packing selection changes when dealing with solid-containing systems, and the rate of hydrate formation can be increased by 20 % with the proper selection of packing type. This study can provide a basis for subsequent high-gravity hydrate experiments and industrial applications.

Study on Fracturing Parameters Optimization of Horizontal Wells in Low-Permeability Reservoirs in South China Sea

The oil and gas resources in the deep Paleogene system of the South China Sea are abundant. However, due to its poor reservoir physical properties and strong heterogeneity, the deep Paleogene system needs to be commercially exploited by hydraulic fracturing technology. In view of the challenges of offshore low-permeability reservoirs, large-scale fracturing is not allowed because of the limited operation sites and complex string structure. Taking the H oilfield in the South China Sea as the target, based on the concept of the integration of geologic and engineering techniques, parameters such as the number of fracturing stages and the fracture length were optimized by a numerical simulation, and a study on the slurry rate and fracturing scale was carried out based on the type of fracturing and the pipe string structure. The results show that multistage fracturing technology is available in low-permeability offshore oil fields. It is suggested to adopt networking fracturing technology with a “slick water + high slurry rate” framework. A higher rate is recommended, and the fracturing scale of each stage should be 50 m3 of the sands and 700 m3 of the fluids. This research provides a new model for offshore low-permeability oilfield development.

Review of Offshore Chemical Flooding Field Applications and Key Lessons Learned

Summary This paper presents an overview of both current advancements and field applications of offshore chemical flooding technologies. Along with offshore oilfield development strategies that require the maximization of oil production in a short development cycle, chemical flooding can become a potential avenue to accelerate oil production in secondary oil recovery mode. This makes it different from onshore chemical flooding processes that mostly focus on enhanced oil recovery in mature or maturing reservoirs. The advancements in offshore chemical flooding field applications are reviewed and analyzed. By summarizing offshore application cases, the presented analysis also assesses the chemical formulations applied or studied and injection/production facilities required in offshore environments. The main technical challenges are also discussed for scaling up the applications on offshore platforms or floating production storage and offloading (FPSO) systems. The chemical flooding technologies reviewed include polymer flooding, surfactant-polymer (SP) flooding, and alkaline-surfactant-polymer (ASP) flooding. By assessing the technology readiness level of these technologies, this study presents their perspectives and practical relevance for offshore chemical flooding applications. It has been long realized that chemical flooding, especially polymer flooding, can improve oil recovery in offshore oil fields. The applications in Bohai Bay (China), Dalia (Angola), and Captain (North Sea) provide the know-how workflows for offshore polymer flooding from laboratory to full-field applications. It is feasible to implement offshore polymer injection either on a platform or in an FPSO system. It is recommended to implement polymer flooding at an early stage of reservoir development to maximize the investment in offshore facilities. By tuning the chemistry of polymer products, they can present very good compatibility with seawaters. Therefore, choosing a proper polymer is no longer a big issue for offshore polymer flooding. There are also some interesting findings reported on the development of novel surfactant chemistries for offshore applications. The outcome from a number of small-scale trials, including the single-well chemical tracer tests on surfactant, alkaline-surfactant (AS), and SP in offshore Malaysia, Abu Dhabi, Qatar, and South China Sea, provided valuable insights for the feasibility of chemical flooding in offshore environments. However, the technology readiness levels of surfactant-based chemical flooding processes are still low, partially due to their complex interactions with subsurface fluids and the lack of interest in producing residual oil from matured offshore reservoirs. Based on the lessons learned from offshore applications, it can be concluded that several major challenges still need to be overcome in terms of large well spacing, reservoir voidage, produced fluid treatment, and high operational expense to successfully scale up surfactant-based chemical flooding processes for offshore applications. Key Terms and Phrases offshore chemical flooding; polymer flooding; surfactant-based chemical flooding; offshore application cases; lessons learned

Sand Production Prediction and Safe Differential Pressure Determination in a Deepwater Gas Field

Sand production is a critical issue during the development of offshore oil and gas fields. Certain gas fields (e.g. the AB gas field) have high porosity and high permeability, and with water at the bottom of the reservoir, the risk of sand production greatly increases at high differential pressures. Based on reservoir properties, geological conditions, production requirements, and well logging data, in this study an ultrasonic time difference method, a B index method, and a S index method are used together with a model of rock mass failure (accounting for water influx and pressure depletion) to qualitatively predict sand production. The results show that considered sample gas field has an overall high risk of sand production. The critical differential pressure (CDP) without water influx is in the range of 1.40 to 2.35 MPa, the CDP after water influx is from 0.60 to 1.41MPa. The CDP under pressure depletion is in the range of 1.20 to 1.92 MPa. The differential pressure charts of sand production are plotted, and the safe differential pressure windows with or without water influx are obtained. The model calculation results and the experimental results are consistent with the field production data, which indicates that the implemented prediction method could be taken as a reference for sand production prediction in similar deep water gas fields.

Thermoplastic composite pipe failure envelopes under axisymmetric and thermomechanical loading

Thermoplastic composite pipes are considered to be the next riser design generation for deep and ultra-deep water offshore oil field development. They typically consist of polymeric (e.g. PEEK or PVDF for high temperature applications) and composite laminate (e.g. carbon/glass fibers) layers. Theoretical and finite element (FE) analyses of thermoplastic composite pipes under axisymmetric loadings with thermal gradient due to internal surface temperature and external convection to the seawater are presented in this work. The pipe consists of an inner and outer isotropic homogeneous polymeric layers and intermediate transversely isotropic perfectly bonded laminate ply layers. The through-thickness failure indexes related to the von Mises and Maximum Stress criteria are respectively evaluated for polymer and laminate layers. The pipe is assumed to fail when one of the failure indexes across the pipe thickness reaches 1. In the case study, the pipe through-thickness temperature profiles and stress states obtained from analytical and FE models agree well. The linearity response behavior of thermoplastic composite pipe under isolated mechanical and thermal loadings is investigated. Based on the failure analyses, the pipe maximum load envelopes under axisymmetric loading condition and the related failure layer illustration are given. The pipe axial stiffness is invariable regardless of the internal and external pressures, but slightly decreases as the prescribed temperature increases.

Bridging the integration gap—simultaneous optimization of well placement, well trajectory, and facility layout

We present an integrated field development planning framework that bridges the integration gap through concurrently optimizing well placement, well trajectory, and facility layout. The novel algorithms implemented in the proposed framework break organizational silos between the reservoir, wells, and facility domains and provide reservoir engineers, drilling engineers, facility engineers, and economists with a shared planning platform. The presented solution is modular, flexible, and allows for multiple layers of granularity and, hence, a spectrum of solutions with different trade-offs between accuracy and efficiency needed as the field development plan is refined through its history. Multiple scenarios and example cases are presented illustrating the features of the integrated optimization framework and their applicability in different potential onshore and offshore oil and gas field development projects.A novel machine learning based optimization algorithm for well trajectory design is presented and achieves significant improvements in computational time compared to traditional optimization approaches. Using a machine learning model to design a well trajectory was three orders of magnitude faster than the differential evolution algorithm which, in turn, was the fastest among the different optimization algorithms that we have tested. The proposed machine learning model drastically reduced the CPU requirements of the integrated solution and enabled the modeling of complex cases of hundreds of wells and associated facility building blocks.

Price stress testing in offshore oil field development planning

Oil & gas field development planning has the objectives of maximizing economic value and also mitigating potential risk. An optimal development concept and strategy depend on the selected oil price trajectory. The conventional scenario-analysis assuming a fixed hydrocarbon price over the lifetime is often inadequate as oil price shocks are likely to occur in the 20-year plus production horizon. In this work, we argue that stress testing, a method widely used in the financial domain, can valuably support field development planning. This work explores the adoption of stress testing to quantify the resilience of field development concepts in the early field development phase. The empirical analysis is presented, a MILP model is formulated, and a new metric is introduced to conduct the price stress testing for field development planning. Additionally, the developed method is applied to a real-world planning case of selecting the development concept and choosing the optimal variables. Results from the case study reveal that the timing and magnitude of oil price shocks can significantly affect the economic value of a project. Consequently, when considering sudden hydrocarbon price drops, it is preferable to chose a resilient field development concept at the early stage of field planning.

Characterization of volcanic reservoirs; insights from the Badejo and Linguado oil field, Campos Basin, Brazil

The Badejo and Linguado oil fields are hosted within non-conventional volcanic reservoirs which produced commercial hydrocarbons from the Lower Cretaceous Cabiúnas Formation, Campos Basin, offshore Brazil. Despite over 30 years of production, limited characterization of the nature and reservoir properties of the volcanic reservoirs have been presented to date. A comprehensive reappraisal of the Cabiúnas Formation volcanic reservoirs is presented in this study incorporating extensive existing and new data including core descriptions, laboratory petrophysical analyses, petrography, QEMSCAN, SEM, wireline, and microtomography results from five cored intervals of wells spanning the main reservoirs of the Badejo and Linguado fields. Volcanic facies analyses of the sequences reveal a predominance of subaerial effusive basic volcanic rocks interbedded with sediment and in several cases comprising peperites revealing intricate lava-sediment interaction products. Four volcano-sedimentary units are identified, showing alternations between low (compound pahoehoe lava dominated Units 1 and 3) and high (tabular rubbly pahoehoe lava dominated Units 2 and 4) effusion rates. Paleoenvironmental conditions also varied between units with extensive oxidation present in Unit 1 inferred to relate to extended periods of subaerial exposure and weathering in an arid environment. Overlying Units 2–4 reveal an increase in humidity evidenced by an increase in the presence of well sorted fine-grained sediment interlayers, peperites, and non-marine ostracods. Both original facies and alteration reveal key controls on reservoir properties. Extensive weathering and alteration of Unit 1 caused pervasive filling of original porosity (vesicles and fractures) and resulted in reservoir degradation. Lesser weathering of overlying Units 2, 3 and 4, resulted in improved reservoir properties which can be clearly linked to volcanic intra-facies including vesiculated and autobrecciated lava flow tops which commonly reveal extensive oil staining. This study reveals the intricate interplay between primary volcanic facies and subsequent alteration history in dictating volcanic reservoir properties in a successful offshore oil field development.

A Realistic and Integrated Model for Evaluating Offshore Oil Development

With the rising consumption of oil resources, major oil companies around the world have increasingly engaged in offshore oil exploration and development, and offshore oil resources have accounted for an increasing proportion. Offshore oil engineering projects are capital intensive, and the development of offshore oil fields faces a tough battle, especially in a period of low oil prices. Thus, a comprehensive evaluation model is highly needed to help assess economic benefits and provide meaningful and valuable information for operators and investors to make sensible decisions. This study firstly proposed a realistic and integrated evaluation model for offshore oil development based on actual historical project data. This evaluation model incorporated modules from the underwater system to the platform system and processes from oil reservoir extraction to oil, gas and water treatment. The uncertain parameters in the evaluation process are dealt with by sensitivity analysis and Monte Carlo simulation. The proposed model is applied to a typical offshore oil development project in Bohai Bay, China. The results reveal that the recovery factor and oil price have the greatest impact on the economic benefits. In the case of deterministic analysis, the breakeven oil price of the project is 40.59 USD/bbl. After considering the uncertainty of project parameters, the higher the oil price, the greater the probability of NPV > 0. When the oil price is higher than 70 USD/bbl, even with uncertain project parameters, the probability of NPV > 0 can still be as high as 97.39%.

Export markets of Russian shipbuilding

Subject. I consider export capacity-building of civil shipbuilding products. Objectives. The focus is on the analysis of the current state of the Russian shipbuilding industry and consumer qualities of its production, exploration of current and future needs of potential foreign customers of civil shipbuilding products. Methods. The study rests on general scientific methods of research. Results. Products having high export capacity include liquid and dry cargo vessels of inland and mixed navigation, icebreakers, vessels for development of offshore oil and gas fields, high-speed hydrofoils and hovercraft, and floating power units. Conclusions. Products of civil shipbuilding are the main ones from the perspective of export growth. They are associated with cost-effective implementation of orders in large-scale manufacturing.

Sequential production of two oil fields with an option to switch

Re-using existing infrastructure has become a standard approach for the development of marginal offshore oil fields. Many small discoveries are, however, located in remote areas or require unreasonably high costs to be tied back to already installed production facilities. Feasible solutions must be found to develop such prospects in a cost-efficient way. In this paper, we analyze whether sequential development of two stand-alone small fields (A and B) using the same production facilities can be an economical strategy compared to the investment in parallel development. We apply and compare two different approaches to evaluate such a sequential strategy. The first considers that the decision maker maximizes the recovery factor of Field A first and then invests in Field B disregarding the information about uncertain factors (“myopic” approach). The second approach allows accounting for the decision maker’s ability to optimize the development strategy given it can learn about uncertainties over time and initiate switching between two fields when it is optimal, or leave Field B undeveloped (“options” approach). We account for several sources of uncertainty affecting the project value: Fields A and B reservoir uncertainty that is replicated by a benchmark reservoir model, oil price, operational expenditure (OPEX), and capital expenditure (CAPEX) to switch between two fields. Our findings are threefold: (1) sequential investment can be the preferred development concept for small stand-alone discoveries; (2) the sequential development strategy allows the downside risks of the investment to be partly hedged, including the reservoir, oil price, and cost risks; (3) the “options” approach is needed to capture the additional monetary value of such a strategy and is considered to be a superior method to assess the value of the sequential production as opposed to a “myopic” approach.

Simulation of the operation of two-roll screw piercing of steels of the 13Cr type

The development of new offshore oil and gas fields is impossible when using pipes made of carbon and low-alloy steel grades, due to their inability to effectively withstand an aggressive environment. Therefore, the urgent task of pipe manufacturers is to develop and master the technology of mass production of seamless pipes from martensitic steels with a high chromium content. This article discusses the peculiarities of the technology for the production of seamless pipes from steel grades of the 13Cr type when piercing a billet on a two-roll screw rolling mill with a non-driven guide tool - a ruler. The results of physical modeling at the MISIS laboratory screw rolling mill are presented. To identify the features of the piercing during physical modeling, the elongation coefficient was changed (due to the use of piercing mill mandrels of different diameters and due to a change in the thickness of the sleeve wall), the feed angle was varied, and the workpieces were pierced at different temperatures. In addition, for a comparative analysis, steel 45 was pierced. During the research, the machine time of the piercing and the force on the roll of the piercing mill were recorded. Underrolls were obtained, on which the pitch of the sleeve was measured, and the area of the contact surface of the pierced metal with the rolls was also determined. The energypower parameters of the piercing were evaluated at various settings of the piercing semi-industrial mill "MISiS -130D". To compare the obtained force values, the piercing process was simulated in the QForm software package. As the material of the billet workpiece, the material C.20Сr13 was chosen with deformation resistance characteristics obtained from the results of testing samples on the Gleeble System 3800.

Automation of the Control of Electric Drive of Manned Submersibles

Currently, there is an intensive development of manned and unmanned submersibles due to development of offshore oil and gas fields, development of underwater archaeology and exploration activities in transit zones regarding seabed mineral extraction. The depth of immersion and the nature of the underwater technical works performed determine not only the design of the underwater vehicle, its power-to-weight ratio and technical equipment, but also impose high requirements on reliability, survivability, and habitability, if the underwater vehicle implies that the operator is on board inside a pressure hull. The main objectives of the study carried out by the authors were to achieve high reliability and survivability of the main elements of the propulsion-steering complex, which ensure movement of a human-occupied vehicle in the water column, its positioning and retention at a given point in the water area.For this purpose, it was proceeded to development of an automated control system for the electric drive of the propulsive device of manned immersible. The proposed developments include a flowchart of the movement control system, circuitry engineering solutions using power semiconductor devices to maintain operability of the electric drive in extreme and emergency operating conditions, and movement control algorithms. Electromagnetic calculations of the active part of the electric machine were performed by the finite element method, considering the geometric features of the dental zone of the rotor and stator. The proposed mathematical apparatus served to calculate optimal control actions of the electric drive and to quantitatively assess the reduction in electrical losses once optimal control was applied. The calculation of the optimal control parameters was carried out using the maximum principle. The initial conditions for auxiliary functions are determined by the Newton‒ Raphson method. A comparison of various modes of operation of the electric drive was made regarding their influence on duration of the campaign, and other parameters.The calculations did not consider the parameters and geometry of the propulsive device (the propeller) since the developers of electric propulsion systems for manned and unmanned underwater vehicles of various classes often deliberately reduce the efficiency of the propeller to increase speed of the electric motor shaft, resulting in a decrease in the dimensions and weight of the latter.

Formulations for automatic optimization of decommissioning timing in offshore oil and gas field development planning

A mathematical programming formulation has been developed to optimize the drilling program, the production allocation, and the decommissioning time in early-stage field development planning. Various abandonment constraints are considered in the optimization model when searching for the best decommissioning time for the long-term field development strategy. The model is tested on a real field development planning consisting of two reservoirs produced with subsea wells to an offshore facility. The novelty of this work is the utilization of mathematical programming to formulate and solve early-stage field development planning considering the variable decommissioning time. The results show that considering a variable decommissioning time in early-stage field development planning yields improved economic margins. Further, it provides operators a decision-support tool with enhanced capabilities of forecasting the best decommissioning time, improving the forecasts for processing and production planning, expected revenue and lifetime of facilities, and anticipating and preparing for field abandonment in advance. The optimization model is capable of determining the drilling and production schedules, and the optimal decommissioning time that yielded the maximum net present value for the project.

Survey of reliability of offshore oil and gas infrastructure in South Baltic conditions

The development of the hydrocarbon resources of the Kaliningrad Region shelf has been carried out systematically since the late 1980s. In the existing offshore oil and gas infrastructure of the region should be mentioned drilling platforms (C-9 and D-6), an underwater oil pipeline from the D-6 platform to the Romanovo oil collection point, the Pionersky marine regasification terminal. The experience of operating these infrastructure facilities shows that despite the low salinity of the Baltic Sea and the practical absence of ice conditions in this area, oil and gas infrastructure objects are subject to significant technical degradation. The existing offshore pipeline, which transports oil from the D-6 platform, is influenced by a complex of external factors, internal corrosion and erosion wear associated with sulphur compounds, oxygen, and the presence of abrasive particles. The study presents a factor analysis of the causes of corrosion wear of infrastructure oil and gas facilities on the shelf of the Kaliningrad region, analyses the dynamics of the processes of physical and chemical degradation of equipment surfaces. Various solutions of the reliability ensuring of these units in marine conditions are considered. The results of observations of corrosion and erosion processes in the oil and gas infrastructure of the Kaliningrad Region shelf should be taken into consideration during the development of project documentation and the selection of equipment and materials for new projects being implemented (offshore oilfield development project D-6 South and D-33).

Impact of Integration of the Production Systems and Reservoir of a Benchmark Based on Carbonate Fields

AbstractIntegrating production system and reservoir is used in several studies of offshore oilfield development and management for improved production forecasts through more realistic boundary conditions. This study evaluates the influence of the parameters in a production strategy of a reference model (carbonate oil reservoir) on financial and production performance. We first considered nonintegrated system (NI) with the reservoir and fixed boundary conditions for well and gathering system. We then considered integrated system (I) with the variable boundary conditions for the wells and gathering system. Finally, we compared both systems. Our analysis involved several steps to define the best production strategy for both systems based on net present value (NPV) and how integrated modeling helps define production strategy. For NI, three stages were considered: number of wells, placement of wells, and platform capacity. For I, five stages were evaluated (all NI parameters) with diameters and gas lift evaluation, and platform placement. The results are similar, but the simplifications (NI) may affect financial performance. The cross analysis indicated (in the hypothesis that the integrated system is closer to reality) that integrating the NI case resulted in considerable financial and production differences and may be useful in simplified systems. Since the main aspects of the object-function financial return were related to reservoir model behavior, one can first apply the nonintegrated optimization cycles, then add the integrated cycles, obtaining an intermediate time of the integrated model optimization in similar cases.

Влияние разработки нефтяных и газовых месторождений на окружающую среду Арктики

This article will focus on the analysis of environmental impacts directly related to the development of offshore oil and gas fields in the Arctic, namely, hydrocarbon spills, pollutants, and underwater noise pollution.