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Oilfield development optimization plays a vital role in maximizing the potential of hydrocarbon reservoirs. Decision-making in this complex domain can rely on various objective functions, including net present value (NPV), expected monetary value (EMV), cumulative oil production (COP), cumulative gas production (CGP), cumulative water production (CWP), project costs, and risks. However, EMV is often the main function when optimization is performed under uncertainty. The behavior and performance of different objective functions has been investigated in this paper, when EMV is the primary criterion for optimization under reservoir and economic uncertainty. One of the goals of this study is to provide insights into the advantages and limitations of employing EMV as the sole objective function in oil field development decision-making. The designed optimization problem included sequential optimization of design variables including well positions, well quantity, well type, platform capacity, and internal control valve placements. A comparative analysis is presented, contrasting the outcomes obtained from optimizing the EMV-based objective function against traditional objective functions. The study underscores the importance of incorporating multiple objective functions alongside EMV to guide decision-making in oilfield development. Potential benefits in minimizing CGP and CWP are revealed, aiding in the mitigation of environmental impact and optimization of resource utilization. A strong correlation between EMV and COP is identified, highlighting EMV's role in improving COP and RF. [ABSTRACT FROM AUTHOR]

The purpose of the article is to study the opportunities of innovative development of the Russian oil and gas complex amid current challenges. The subject of the article is modern features of functioning of the Russian oil and gas sector. As a methodology, it is necessary to high-light the analysis of Internet resources and articles relevant to the research topic, statistical data, their synthesis and generalisation. Among the main results of the work we will indicate structuring sanctions in terms of the direction of impact on innovation activities, identifying opportunities and prospects for innovative development of companies in the oil and gas sector in the current conditions. The results obtained can be applied as part of assessing the prospects with consideration to the modern situation and in the educational process. The directions for further research on a given topic include studying the operating features of companies of various sizes during their activities as well as identifying the most effective technological designs that can be used in the industry, including domestic ones. We have made the following main conclusions. Firstly, the impact of the sanctions is aimed largely at the technological development of oil and gas companies. Secondly, the prohibitive measures have stimulated the use and implementation of domestic innovations. Thirdly, the application of new decisions makes it possible to optimise the processes of the technological development, including those that until recently were determined to be unprofitable. Fourthly, innovations help to increase the number of organisations in the oil and gas sector by involving small-sized companies whose activities cover a minor segment that is not attractive to large corporations.

Abstract Oilfield development optimization plays a vital role in maximizing the potential of hydrocarbon reservoirs. Decision-making in this complex domain can rely on various objective functions, including net present value (NPV), expected monetary value (EMV), cumulative oil production (COP), cumulative gas production (CGP), cumulative water production (CWP), project costs, and risks. However, EMV is often the main function when optimization is performed under uncertainty. The behavior and performance of different objective functions has been investigated in this paper, when EMV is the primary criterion for optimization under reservoir and economic uncertainty. One of the goals of this study is to provide insights into the advantages and limitations of employing EMV as the sole objective function in oil field development decision-making. The designed optimization problem included sequential optimization of design variables including well positions, well quantity, well type, platform capacity, and internal control valve placements. A comparative analysis is presented, contrasting the outcomes obtained from optimizing the EMV-based objective function against traditional objective functions. The study underscores the importance of incorporating multiple objective functions alongside EMV to guide decision-making in oilfield development. Potential benefits in minimizing CGP and CWP are revealed, aiding in the mitigation of environmental impact and optimization of resource utilization. A strong correlation between EMV and COP is identified, highlighting EMV’s role in improving COP and RF.

Current problems in mature oil fields are high water cut and flow profile estimating of oil and associated brines from different layers. To establish the flow profile in production wells, geophysical research (Production Logging) is traditionally used by lowering special equipment into the well. Production Logging requires production stops and labor costs. Geochemical methods (Production Geochemistry) are used as an alternative solution: sampling is simple and efficient, which makes it possible to cover all the interesting area. Moreover, sampling does not require stopping the well. The geochemical method uses individual indicators of the composition of formation fluids produced from different perforation intervals. In this work, geochemical studies were carried out using wellhead samples from more than 100 wells, with single perforation for carbonate and terrigenous reservoirs. Some wells have joint exploitation of these formations. An automated algorithm was used to identify the distinctive characteristics of each formation based on the composition of the produced brines and oils. Data on the chemical composition of fluids from different development objects made it possible to determine the flow profiles in wells with joint production. Based on the results of the studies, the Devonian reservoir of the field under consideration is divided into 2 parts – northern and southern, which differ in the chemical composition of formation fluids. The same separation of the deposits into 2 parts is noted by field development analysis: over the past 50 years, the main production of oil and associated brines has been concentrated in the southern part of the deposit, confined to the fault, where the active work of the aquifer is assumed. It is recommended to use the obtained data for history matching of the reservoir simulation model.

Optimization of the “mature” fields development in machine learning algorithms is one of the urgent problems nowadays. The task is set to extend the effective operation of wells, optimize production management at the late stage of field development. Based on the task set, the article provides an overview of possible solutions in waterflooding management problems. Production management technology is considered as an alternative to intensification of operation, which is associated with an increase in the produciton rate and involves finding solutions aimed at reducing the water cut of well production. The practical implementation of the “Neural technologies for production improvement” includes the following steps: evaluation, selection, predictive analytics. The result is a digital technological regime of wells that corresponds to the set goal and the solution of the optimization problem in artificial intelligence algorithms using the software and hardware complex “Atlas – Waterflood Management”.“Neural technologies for production improvement” have been successfully tested at the pilot project site of the productive formation of the Vatyeganskoe field. The article provides a thorough and detailed analysis of the work performed, describes the algorithms and calculation results of the proxy model using the example of the pilot area, as well as the integration of the “Atlas – Waterflood Management” and the organization of the workflow with the field professionals of the Territorial Production Enterprise Povkhneftegaz.

Field development is an important part of natural resource utilization and exploration because it involves a systematic evaluation and optimization of a specific area. This study examines the geothermal field development in the Gandhar region of Gujarat, India. Gandhar for the past several decades has been a flourishing field for hydrocarbon extraction. However, as the world is dealing with environmental issues and the need to shift to cleaner and more sustainable energy sources, geothermal energy has emerged as a feasible and ecologically sound option. This study aims to understand the potential of regions in and around Gandhar as a prospective geothermal field of the west coast continental margin of India. Three primary disciplines namely geological, geochemical, and geophysical surveys are employed on the surface to assess the potential of Gandhar's geothermal resources. Geological assessments provide information about underlying geological formations, which might help to locate possible geothermal resources. The Deccan basement is a prominent source of magmatic heat, with a thermal gradient ranging from 1.29 to 1.87 W/K. This enhances Gandhar's geothermal potential by heating the underlying water in conjunction with radionuclides found in the Earth's core. The temperatures range from 60 to 80 ℃ according to Giggenbach triangle method. Gandhar's geothermal potential is further highlighted by the fact that its water is bicarbonate-rich, which connects it to possible subterranean aquifers. These results are verified by geophysical studies. Prospective geothermal reserves and four way closures can be found by as anomalies. Gravity survey reveal a doubly plunging antiform, with gravity high value of 5.4 and 5.3 mGa l respectively, which is corroborated by magnetic peaks of 58 and 56.2 nT Areas with higher conductivity are identified by resistivity studies, which also indicate possible fluid paths and geothermal reservoirs. The paper outlines a conceptual field development plan for the identified prospect. The basic infrastructure and the cost associated with it for field development is worked out. The cost of production/MWe of energy generation is also highlighted. [ABSTRACT FROM AUTHOR]

Field development is an important part of natural resource utilization and exploration because it involves a systematic evaluation and optimization of a specific area. This study examines the geothermal field development in the Gandhar region of Gujarat, India. Gandhar for the past several decades has been a flourishing field for hydrocarbon extraction. However, as the world is dealing with environmental issues and the need to shift to cleaner and more sustainable energy sources, geothermal energy has emerged as a feasible and ecologically sound option. This study aims to understand the potential of regions in and around Gandhar as a prospective geothermal field of the west coast continental margin of India. Three primary disciplines namely geological, geochemical, and geophysical surveys are employed on the surface to assess the potential of Gandhar's geothermal resources. Geological assessments provide information about underlying geological formations, which might help to locate possible geothermal resources. The Deccan basement is a prominent source of magmatic heat, with a thermal gradient ranging from 1.29 to 1.87 W/K. This enhances Gandhar's geothermal potential by heating the underlying water in conjunction with radionuclides found in the Earth's core. The temperatures range from 60 to 80 °C according to Giggenbach triangle method. Gandhar's geothermal potential is further highlighted by the fact that its water is bicarbonate-rich, which connects it to possible subterranean aquifers. These results are verified by geophysical studies. Prospective geothermal reserves and four way closures can be found by as anomalies. Gravity survey reveal a doubly plunging antiform, with gravity high value of 5.4 and 5.3 mGa l respectively, which is corroborated by magnetic peaks of 58 and 56.2 nT Areas with higher conductivity are identified by resistivity studies, which also indicate possible fluid paths and geothermal reservoirs. The paper outlines a conceptual field development plan for the identified prospect. The basic infrastructure and the cost associated with it for field development is worked out. The cost of production/MWe of energy generation is also highlighted.

In this paper we present the results of studies of the Botuobin, Talakh, and Khamakin reservoirs of the Vendian period in the Chayanda hydrocarbon field (Eastern Siberia). Based on an analysis of variations in the petrophysical parameters of reservoirs upon an increase in effective pressure from 37 to 57 MPa, i.e., under conditions simulating the development of a field for depletion, changes in the volume and compressibility of the pore space are estimated. In this case, the porosity coefficient decreases by 0.043 abs. %, while the compressibility of the pore space decreases by 0.228 1/GPa. The average volumetric compression strain increases by 0.096%, which means a reduction in the volume of developed reservoirs by almost 0.1% relative to the beginning of development. A deformable formation model developed by Yu.O. Kuzmin based on the geodynamic history of the development of deposits is applied to estimate the magnitude of possible subsidence of the ground surface during development. The maximal values of possible surface subsidence (drawdowns) upon a decrease in reservoir fluid pressure by 5 MPa are estimated to be 0.33 m with allowance for the dynamics of petrophysical parameters and 0.335 m with no allowance for it. The maximal drawdowns are already estimated at 0.60 and 0.65 m upon a decrease in reservoir pressure by 10 MPa and 0.78 and 0.83 m upon a complete depletion of reservoir energy, respectively. The results of the studies show that taking into account the changes in petrophysical characteristics caused by the field development processes alters the estimate of the deformation state of the rock massif and the ground surface above the deposit and, consequently, the estimate of the level of geodynamic risk of oil-and-gas complex objects. [ABSTRACT FROM AUTHOR]

In binary multi-objective well placement optimization, multiple conflicting objective functions must be optimized simultaneously in reservoir simulation models containing discrete decision variables. Although multi-objective algorithms have been developed or adapted to tackle this scenario, such as the derivative-free evolutionary algorithms, these methods are known to generate a high number of duplicated strategies in discrete problems. Duplicated strategies negatively impact the optimization process since they: (i) degrade the efficiency of recombination operators in evolutionary algorithms; (ii) slow the convergence speed as they require more iterations to find a well-distributed set of strategies; and (iii) perform unnecessary re-evaluations of previously seen strategies through reservoir simulation. To perform multi-objective well placement optimization while avoiding duplicated strategies, this paper investigates the application of a newly proposed algorithm named MOEA/D-NFTS, with a modified diversity preservation mechanism that incorporates prior knowledge of the problem, on a multi-objective well placement optimization problem. The proposed methodology is evaluated on the UNISIM-II-D benchmark case, a synthetic carbonate black-oil simulation model in a well placement optimization problem using a binary strategy representation, indicating the presence or absence of a given candidate well position in the final strategy. The objective functions are the maximization of the Net Present Value, the maximization of the Cumulative Oil Production, and the minimization of Cumulative Water Production. The modified MOEA/D-NFTS performance is compared with a baseline algorithm without diversity preservation, and the evidence shows that the MOEA/D-NFTS produces statistically significant superior results, and is suitable for binary multi-objective well placement optimization. [ABSTRACT FROM AUTHOR]

The current RF (recovery factor) of the subject reservoir is

the purpose of this article is to consider the problem of flaring associated petroleum gas (APG), as one of the most relevant and acute for our country, because Russia occupies a leading position in the world in terms of APG flaring volumes. Burning APG leads to environmental damage, contributes to the greenhouse effect, harms public health, as well as the country's economy - valuable chemical raw materials and energy resources are simply thrown away. According to the Ministry of Natural Resources of the Russian Federation, out of 55 billion m3 of APG produced annually in Russia, only 26% (14 billion m3) is sent for processing, 47% (26 billion m3) goes to the needs of the fields, or is written off as technological losses and 27 % (15 billion m3) is flared.

The prevailing offshore field development solutions, i.e., dry tree and wet tree systems, are confronted with serious technical and economic challenges in deep and ultra-deep waters resulting from the large depth of water, far offshore distance, and harsh ocean environmental conditions, as well as high cost. In response to these challenges, an innovative Deepwater Artificial Seabed (DAS) production system is proposed in this article. The DAS production system concentrates on well access and riser design, which enables shallow-water-rated subsea production systems to develop Deepwater (DW) and Ultra-Deepwater (UDW) fields. First, DW & UDW field development drivers are discussed and presented. This is followed by a detailed discussion of the merits and demerits of the prevailing dry tree and wet tree field development solutions. On this basis, the design philosophy and main characteristics of the DAS production system are presented and discussed in detail. Dynamic survival analysis for the fully coupled Floating Production Storage and Offloading (FPSO)-DAS production system is carried out. The artificial seabed stability is systematically investigated for both intact and damaged conditions. The global analysis results indicate that the DAS production system as developed experiences quasi-static responses even under extreme storm conditions, due to the location of the artificial seabed and the decoupling effects of the flexible jumpers. The new DAS production system is considered to be a competitive and cost-effective field development solution in depths of up to 3000 m. [ABSTRACT FROM AUTHOR]

Abstract The installed capacity of geothermal systems for direct use of heat is increasing worldwide. As their number and density is increasing, the their interaction with subsurface faults becomes more important as they could lead to safety risks from induced seismicity. Assessment and management of such risks is essential for the further development and extension of geothermal energy for heating. At the same time, the economic output of geothermal systems can be marginal and is hence often supported by subsidy schemes. A combined assessment of fault stability and economic output could help operators to balance economic and safety aspects, but this is currently not common practice. In this study we present a methodology to assess field development plans based on fault stability and Net Present Value (NPV) using reservoir simulations of a fluvial, heterogeneous sandstone representative of the majority of direct-use Dutch geothermal systems. We find that the highest friction coefficient leading to exceedance of the Mohr–Coulomb failure criteria in this sandstone is 0.17; such values could be encountered in clay-rich fault gouges. Similar or lower fault permeability compared to the reservoir results in no changes and an increase respectively of both NPV and fault stability with larger Fault-to-Well Distance (FWD). Fault permeability higher than the reservoir permeability results in a minor increase in NPV with smaller FWD. Our results demonstrate that a combined analysis of thermal, hydraulic, mechanical and economic assessment supports a responsible and viable development of geothermal resources at a large scale. The importance of a high spatial density of supporting stress data will be essential for a better understanding and quantification of economic and fault stability effects of geothermal operations.

The planning and developmental decisions succeeding the discovery of an unconventional oil and gas field is of utmost importance in attaining successful exploitation and production from these tight reservoirs. The development and production of hydrocarbon from these unconventional reservoirs require requires adequate planning and execution which could be challenging, due to the sequence of heterogeneous lithologies of these formations. In this study, we designed and presented a comprehensive field development and production program that is representative of the unconventional oil and gas development in the Central sub-basin of the Permian Basin. To design and achieve optimal field development and production for unconventional reservoirs in the Central sub-basin of the Permian Basin, New Mexico, we utilized field data from an oil and gas well that was drilled to a TVD/MD of 2290 m with a PBTD of 2270 m. Subsequently, we conducted the petrophysical evaluation of the logs and utilized a decline curve analysis for reservoir evaluation of all the members of the formation. We also designed and developed comprehensive drilling, completions, and facilities programs. Lastly, we incorporated an economic analysis of our optimized field development and production design. Our results provide a valuable plan and critical decision-making insight for optimizing field development and production of unconventional reservoirs in the Permian Basin and across the world.

The relevance. The East-Messoyakhskoe field is unique not only in terms of geological reserves, but also in its geological characteristics. Main reservoir PK 1-3 contains about 65 % of the reserves and is an unconsolidated reservoir with a high-viscosity oil. There is practically no experience in development of similar oil fields in the Arctic conditions. The study of geological and physical characteristics of unconsolidated reservoirs with viscous oil is a relevant objective. The main aim of the research is to analyze and identify the key geological and physical characteristics of the field development of unconsolidated viscous oil reservoirs in order to find methods and technologies for improving field development efficiency. Objects of the research are unconsolidated viscous oil reservoir under development of the East- East-Messoyakhskoe field. Methods: critical analysis, content analysis, analysis and generalization of existing experience in the development of unconsolidated viscous oil reservoirs on the example of the PK 1-3 reservoir of the East-Messoyakhskoe field. Results. The authors have carried out the critical analysis of the key geological and physical characteristics of the PK 1-3 reservoir and its fluids research, which must be taken into account in order to develop it with maximum efficiently. The list of key characteristics was made. Their impact on the field development efficiency was shown. The analysis of waterflooding experience and aquifer impact reservoir development was performed. The need for the use of secondary development methods for PK 1-3 reservoir and reservoir pressure maintaining system was proved. However, due to the characteristics described above, the traditional waterflooding of unconsolidated viscous oil reservoirs carries with it high risks of early water breakthrough and poor sweep efficiency, which will have a great impact on the field development efficiency and the final oil recovery factor. It was concluded about the requirement of alternative technologies and flooding agents research, including the application of physico-chemical enhanced oil recovery methods with a systemic approach, which is a relevant and interesting task.

Intelligent or smart completion wells vary from conventional wells. They have downhole flow control devices like Inflow Control Devices (ICD) and Interval Control Valves (ICV) to enhance reservoir management and control, optimizing hydrocarbon output and recovery. However, to explain their adoption and increase their economic return, a high level of justification is necessary. Smart horizontal wells also necessitate optimizing the number of valves, nozzles, and compartment length. A three-dimensional geological model of the As reservoir in AG oil field was used to see the influence of these factors on cumulative oil production and NPV. After creating the dynamic model for the As reservoir using the program Petrel (2017.4), we improve the robustness of forecasting production from smart wells using reservoir simulation. High-level details in the rock and fluid flow properties are required in the horizontal well region to capture the flow dynamics accurately. Thus, the study offers an enhanced method for predicting the performance of intelligent or smart wells in reservoir modeling. This model was history matched for a period of 20 years for three horizontal wells by using program Petrel (2017.4) and ECLIPS (2011). After successful validation of model on a field scale and well level, performance prediction was carried out to see the effect of (number of valves, number of nozzle and compartment length) using PICD/AFCV completion. Optimizing well performance entails lowering water-cut. From an economic viewpoint, the goal is to maximize NPV or profit, depending on the situation, from PICD wells, which compared to other wells. [ABSTRACT FROM AUTHOR]

The demand of energy in the world will increase due to the increasing population and industrial activity. Currently, the fossil energy is relatively cheaper compared to other energy sources, especially natural gas. The “CJ” field is a gas field located in the South Sumatra Basin, Indonesia with a reservoir located in the Basalt Telisa Limestone (BTL) formation. This gas field consists of 3 wells namely Well GTA-1, GTA-2, and GTA-3 which produced from 1951 to 1991. In 1991 the three wells were suspended and will be reopened in 2021 due to request from buyers for 10 years. The research method is collecting and consisting of data on reservoir, production, and physical properties of the gas. The next step is to calculate the value of the gas formation volume factor and Z-factor (gas compressibility factor/gas deviation factor) with various pressures. After it, determine the type of drive mechanism using the Cole Plot method. After knowing the type of drive mechanism, determine the current OGIP value using the material balance method. If the OGIP value is known, the next calculation is the Recovery Factor (percentage of the amount of gas that can be produced to the surface), Ultimate Recovery (UR) and finally the value of Remaining Reserve (RR). Based on the calculation, the OGIP value obtained by the material balance method with P/Z vs GP plots is 83.46 BSCF, Recovery Factor of 80.22%, Ultimate Recovery of 66.96 BSCF, and remaining gas reserve 15.45 BSCF. The maximum flow rate could be obtained by remaining reserve divided contract period. From these results, the maximum reserve value that can be produced to the surface for 10 years is 4.23 MMSCFD. Therefore “CJ" Field meet the needs of buyer to fulfil the requirement number which is only 4 MMSCFD.

The prevailing offshore field development solutions, i.e., dry tree and wet tree systems, are confronted with serious technical and economic challenges in deep and ultra-deep waters resulting from the large depth of water, far offshore distance, and harsh ocean environmental conditions, as well as high cost. In response to these challenges, an innovative Deepwater Artificial Seabed (DAS) production system is proposed in this article. The DAS production system concentrates on well access and riser design, which enables shallow-water-rated subsea production systems to develop Deepwater (DW) and Ultra-Deepwater (UDW) fields. First, DW & UDW field development drivers are discussed and presented. This is followed by a detailed discussion of the merits and demerits of the prevailing dry tree and wet tree field development solutions. On this basis, the design philosophy and main characteristics of the DAS production system are presented and discussed in detail. Dynamic survival analysis for the fully coupled Floating Production Storage and Offloading (FPSO)-DAS production system is carried out. The artificial seabed stability is systematically investigated for both intact and damaged conditions. The global analysis results indicate that the DAS production system as developed experiences quasi-static responses even under extreme storm conditions, due to the location of the artificial seabed and the decoupling effects of the flexible jumpers. The new DAS production system is considered to be a competitive and cost-effective field development solution in depths of up to 3000 m.

We have developed a machine-learning (ML) accelerated optimization method for challenging real-life well-location optimization (WLO) applications. The optimization protocol encompasses a stage at which the objective function is computed by a proxy ML model trained to accurately approximate the objective function that would be otherwise calculated using a computationally more intensive reservoir simulation run. As ML algorithms for proxy development, we have used two variants of the support-vector regression (SVR) technique, namely, ε-SVR and ν-SVR. In the proposed proxy-accelerated optimization workflow, WLO starts with the conventional approach of using the reservoir simulator as the objective-function evaluator for a relatively small number of iterations of a global optimizer that conducts explorative search. This initial simulation investment is utilized not only to deliver optimization improvements but also to train an SVR proxy for the objective function of the investigated WLO problem. Subsequent to initial iterations, the SVR proxy is activated to serve as the objective-function evaluator for the global optimizer. Upon convergence, optimal model parameters estimated by the proxy-based optimization protocol are input to the flow simulator to access the full set of simulation results and also to re-evaluate the proxy accuracy. Optionally, the optimal model configuration can be supplied as initial guess to an efficient local optimizer to evaluate the further improvement potential for a few iterations using the reservoir simulator as the objective-function evaluator. The proposed SVR-accelerated optimization method is tested on a real field WLO problem. We have observed a 40 to 60% reduction in the overall computational cost with the SVR-accelerated protocol. It is important to note that the training time of the SVR proxy is negligibly short for small datasets (with 100s to 1000s data points) such as the ones generated over the course of WLO iterations. However, the main challenge associated with the proposed method is tuning the hyper-parameters of the SVR proxy for a given problem of interest and striking a good balance between accuracy and generalizability of proxy predictions. While some experimentation is still required with SVR hyper-parameters, especially in the first application, we accelerate this step through an auditable optimization process in our implementation. Results of our study demonstrate that the SVR-accelerated WLO method is applicable for real-life problems. [ABSTRACT FROM AUTHOR]

Engineering practice of a field complicated by high level of uncertainty in geological structure, abnormal properties and composition of formation water, and presence of halite in pore space of the reservoir is described. Maintaining reservoir pressure is fundamental for ensuring target production levels, yet its implementation is not always a trivial task. The problem of a saline reservoir simulation has been studied on an East Siberian field with reservoir’s high heterogeneity, low permeability, and salination. Practice of determining the optimal system of development using modern methods of simulation, analysis and calculation is considered. Multivariate calculations were conducted using a hydrodynamic model based on the probabilistic geological model. The methodology of selecting the basic variants of the geological model corresponding to the probability of 10, 50, and 90 % was used subject to two factors: initial geological reserves and reservoir connectivity. Qualitative and quantitative estimations of changes in production wells productivity due to problems caused by organic and inorganic sedimentation in the bottomhole formation zone were performed. Formation water and mineral composition of the rock formation were analysed. These data were used to simulate the organic and inorganic sedimentation in the bottomhole formation zone due to changes in pressure and temperature during production and fluid injection into the formation. The simulation of solids build-up during fluid flow in the bottomhole formation zone allowed us to determine threshold values of well producing characteristics and bottomhole pressure levels, as well as dependencies of decrease in reservoir properties of the bottomhole formation zone on the amount of pumped fluid under the selected well operation parameters.

The article analyzes the organizational structure of the project management development with regard to the field of traditional oil reserves, functional responsibilities and areas of responsibility of its participants, as well as the mechanisms of their interaction during the implementation of work to form the organizational structure of managing a large and unique project -- the development of high-viscosity oil deposits. It has been revealed that in modern business conditions the implementation of projects for the development and recovery of high-viscosity oil fields based on the traditional organizational structure of management is not effective enough. The main reasons that impede the successful implementation of projects for the development of new deposits based on the traditional organizational structure of management are identified. A new organizational structure for managing a field development project is proposed, which includes a single center of responsibility for the field development project. By the example of the Ashalchinskoye field, the economic effect of using the formed organizational structure for managing the project for developing the field in the form of a possible additional annual oil production was calculated. [ABSTRACT FROM AUTHOR]

Geothermal energy is gaining momentum as a renewable energy source. Reservoir simulation studies are often used to understand the underlying physics interactions and support decision making. Uncertainty related to geothermal systems can be substantial for subsurface and operational parameters and their interaction with regards to the output in terms of lifetime, energy and economic output. Specifically, for geothermal systems with the fault acting as the main fluid pathway the relevant field development uncertainties have not been comprehensively addressed. In this study we show how the produced energy, system lifetime and NPV are affected considering a range of subsurface and operational parameters as uncertainty sources utilizing an ensemble of 16,200 3D Hydraulic-Thermal (HT) reservoir simulations, conceptually based on the Rittershoffen field. A well configuration with oblique angles with respect to the main permeability anisotropy axes results in higher system lifetime, generated energy and NPV. A well spacing of 600 m consistently yields a higher economic efficiency (€/MWh) under all uncertainty parameters considered. More robust development options could be utilized in the absence of fault permeability characterization to ensure improved output prediction under uncertainty. Studies based on the methodology presented can improve investment efficiency for field development under subsurface and operational uncertainty. [ABSTRACT FROM AUTHOR]

Due to the global oil price crisis in 2014, one of the MOL's preventive/reactive measures was to identify geologically or commercially risky elements within their portfolio. This involved reevaluation of all geologic data from Field A in the Volga-Urals Basin. In re-evaluating Field A, several unexpected challenges, problems and pitfalls were faced by the interdisciplinary team performing the task of building a new database, quality checking, and interpreting data dating back to 1947. To overcome these challenges related to this mature field, new approaches and fit-for-purpose methods were required in order to achieve the overall goal of obtaining a reliable estimation of remaining hydrocarbon potential. In the first phase a first-pass 3D geologic model was constructed, along with wrangling, cleaning and interpreting 70 years of subsurface data. This paper focuses on the main challenges involved in evaluating or reevaluating reservoir aspects of a mature field. The primary challenges were related to the estimation of remaining in-place hydrocarbon volumes, the optimization of infill well placement, the identification of primary and secondary well targets, the identification of critical data gaps, and the planning of new data acquisitions. The hands-on experience gained during the development of the geologic model provided invaluable information for the next steps needed in the redevelopment of the field. [ABSTRACT FROM AUTHOR]

The installed capacity of geothermal systems for direct use of heat is increasing worldwide. As their number and density is increasing, the their interaction with subsurface faults becomes more important as they could lead to safety risks from induced seismicity. Assessment and management of such risks is essential for the further development and extension of geothermal energy for heating. At the same time, the economic output of geothermal systems can be marginal and is hence often supported by subsidy schemes. A combined assessment of fault stability and economic output could help operators to balance economic and safety aspects, but this is currently not common practice. In this study we present a methodology to assess field development plans based on fault stability and Net Present Value (NPV) using reservoir simulations of a fluvial, heterogeneous sandstone representative of the majority of direct-use Dutch geothermal systems. We find that the highest friction coefficient leading to exceedance of the Mohr–Coulomb failure criteria in this sandstone is 0.17; such values could be encountered in clay-rich fault gouges. Similar or lower fault permeability compared to the reservoir results in no changes and an increase respectively of both NPV and fault stability with larger Fault-to-Well Distance (FWD). Fault permeability higher than the reservoir permeability results in a minor increase in NPV with smaller FWD. Our results demonstrate that a combined analysis of thermal, hydraulic, mechanical and economic assessment supports a responsible and viable development of geothermal resources at a large scale. The importance of a high spatial density of supporting stress data will be essential for a better understanding and quantification of economic and fault stability effects of geothermal operations. [ABSTRACT FROM AUTHOR]

Abstract In most reservoirs with oil rims, as the production begins, the gas–oil and oil–water fluid interfaces start deforming because of the imbalance between viscous and gravitational forces, leading to coning or cusping. This can be overcome using proper withdrawal rate, offset from water–oil contact and horizontal length. Further smart horizontal wells require optimization of nozzle size and compartment length also. To see the effect of these parameters on recovery, a three-dimensional geological model of a clastic reservoir from Upper Assam Basin has been used. This model was history matched for a period of 16 years on 46 wells. After successful validation of model on field scale and well level, performance prediction was carried out to see the effect of withdrawal rate, offset from water–oil contact, horizontal length, compartment length and nozzle size using vertical/horizontal and ICD completion. From the analysis, it is evident that application of advanced well completion, ICD, is suitable for such reservoir. Depending on the scenario, maximum cumulative oil production was obtained from ICD wells with 1.08 MMm3 compared to vertical well with cum oil production of 0.63 MMm3. Economic analysis has been carried out for the examined scenarios.

At preschool age, it is generally accepted that children's main pursuit is play. In particular, pretend play has a major role in supporting a preschooler's learning processes. Early pretend play involves object substitution, before later progressing to the incorporation of invisible objects. The purpose of the presented study was to validate that pretend play contributes significantly to children's emotional, social, physical and intellectual development and can achieve the skills promoted by The Curriculum for Preschool Education in Romania. A questionnaire-based survey was undertaken, consisting of factual items (age, grade teacher), closed questions with pre-coded answers that were easily quantifiable and open questions that required analysis. The questionnaire was administered to a non-probabilistic sample, consisting of 80 kindergarten educators which were arbitrarily selected from nine kindergartens. The findings support the hypothesis of the advantages of pretend play in relation to The Curriculum for Preschool Education in Romania. [ABSTRACT FROM AUTHOR]

The general field development optimization problem is complex due to the potentially large number of controls of mixed type and discontinuities in the objective function related to varying numbers and types of wells being placed in a discretized grid. This may make the problem challenging or even unsuitable for certain types of optimization methods that rely on, e.g., the availability of (adjoint) gradients. It is not yet clear which alternative approaches will be most useful. Here we investigate the application of stochastic gradient-based optimization techniques to field development optimization. Since their initial application to large-scale well rate and pressure control problems, such techniques have been shown to produce useful results of practical value also for other types of reservoir optimization problems such vertical well placement, well drilling scheduling, and water-alternating-gas strategy optimization. Here we introduce an efficient parameterization for well trajectory optimization and discuss a simple way to handle the number of wells that is placed. The full field development problem is split into subproblems that are addressed sequentially. The sequential workflow is applied to the Olympus benchmark model which represents a complex green field development optimization challenge. Initial experiments show that the proposed approach based on stochastic gradient methods is able to find much improved development strategies, as defined by the number and trajectories of wells, a platform location and a drilling sequence, at relatively low computational cost. We additionally identify a number of possible improvements to the applied workflow that are expected to make it applicable to other field cases of intermediate complexity. [ABSTRACT FROM AUTHOR]

The "Olympus challenge" is defined as an open benchmark study on field development optimization under geological uncertainty. This work describes a structured approach to the Olympus challenge. It combines a systematic performance delivery analysis based on multiple reservoir model realizations with optimization strategies including well controls, field development scenarios, and combined strategies. The ambition of this work is to design practical and robust workflows integrating economic, reservoir geology, and delivery performance that can be applied to current real field studies. Probabilistic assessments on economic performance and reservoir opportunities are used for project framing and to define start points for optimization strategies. A sequential optimization strategy is applied to handle discrete control parameters with a time-dependent impact on economic performance over the life cycle of the reservoir. Probability maps are applied to identify reservoir opportunities and a probabilistic well ranking is introduced to investigate the robustness of a well location design. Objective measures for probabilistic evaluations are described and applied for result comparison between an optimized and a reference solution in the presence of multiple realizations. In conclusion, this work provides solution proposals for multiple optimization objectives of the Olympus challenge. Standardized workflow designs deliver manageable and repeatable work steps and give an outlook to automation. [ABSTRACT FROM AUTHOR]

Field development strategies are crucial for reservoir management, and over the last decade there has been quite some development of new optimization algorithms for solving this problem when the uncertainty in the reservoir description is provided by a set of reservoir models. To compare different approaches for this problem, the OLYMPUS benchmark challenge (Fonseca et al. 2018; TNO 2017) was defined, with three different tasks: well control optimization (task 1), field development optimization (task 2), and joint field development and well control optimization (task 3). This work presents solutions to the three exercises with two main optimization methods and problem-specific workflows. The main algorithms used in all three exercises are the ensemble-based optimization (EnOpt) and the line search derivative-free (LSDF) method. EnOpt is constructed for solving optimization problems where the uncertainty is represented by an ensemble of models, and in general it produced good results. However, we also found that the LSDF played an important role in quality checking the results obtained by EnOpt, and in some cases it provided superior results. [ABSTRACT FROM AUTHOR]

Offshore oil and gas reservoirs comprise a significant portion of the world's reserve base, and their development is expected to help close a potential gap in the supply of hydrocarbons in the near future. Continuous advances in technology have helped the oil and gas industry to extend the exploration and production activities to deep and ultra-deep waters in harsher environments. Field development in the offshore environment is associated with numerous significant challenges in different phases including exploration, reservoir description and characterization, development planning, drilling, production, improved oil recovery (IOR) and enhanced oil recovery (EOR), transportation, and decommissioning. These challenges are further complicated by economic restrictions, especially in periods when low or unstable oil prices weaken the incentives of investments due to the high risks and uncertainties involved. Environmental concerns including the adverse effects of seismic surveys, drilling activities, discharge of waste material and produced water, and accidental spills and blowouts add another level of complexity to the design and implementation of offshore projects. Safe, reliable, and efficient development of offshore hydrocarbon reservoirs can be achieved through the proper identification of the challenges and use of modern technologies and innovative methods. This work is an effort to provide a comprehensive review of the history, global distribution, production share, classification, characteristics, and characterization methods of offshore reservoirs, and some of the main aspects and challenges of the experimental and modeling works as well as IOR/EOR planning and implementations from the reservoir engineering and production standpoint. These challenges are categorized based on their area of impact, i.e., characterization and recovery (production) phases. Furthermore, economic and environmental challenges are reviewed. After the recent downturn that caused a decline in offshore investments, current investment trends and the forecasts show that the offshore industry is booming again with more focus on cost saving and operational efficiency. The key technologies that can expedite the growth of the offshore petroleum industry have also been discussed. [ABSTRACT FROM AUTHOR]

Many years have passed in oil field development but primary challenges faced by the X reservoir are the rapid decline of formation pressure and the significant solution gas released from the formation, which impairs production. Based on these challenges, a compositional simulation model of the X reservoir was constructed and run to establish the future development plans. The basic reservoir data collection and processing, quality assurance of the data, characteristic pressure-volume-temperature (PVT) matching by ECLIPSE PVTi, and simulation of various adjustment strategies to forecast development plans, as well as data sensitivity analysis and optimization has been included in this study. In addition, to establish a desirable development plan, the simulation model is set-up in great consistency with the geological model resulted from the seismic and logging interpretations. Also, emphases are paid on establishing matches with the reported lab data from production wells by PVTi. Results revealed that the specific reservoir development plan intends to reinstate or maintain formation pressure of the X reservoir. All design and optimization studies are set to comprehend the reservoir with the numerical model. [ABSTRACT FROM AUTHOR]

The article discusses the problem of resource deterioration and the exhaustion of natural resources as well as the involvement in economic circulation of waste production, resources of technogenic deposits in order to maintain natural capital and support “green” economic growth. This necessitates the development of the mechanism for the environmental management optimization. This mechanism aims at using technogenic deposits in the economy to decrease of both the nature intensity of production and the cost of production. Furthermore, the environmental management optimization should reduce the negative impact of production on the environment. The authors propose to construct a model of economic relevance for the use of waste based on the theory of sustainable development and the theory of substitution of primary natural resources. Under substitutes, we consider useful products, resources from technogenic deposits, resulting from past economic activities. The article considers the problem of accumulation of municipal solid waste and industrial wastes in the regions of Russia in terms of forming and operating the ever-growing technogenic deposits. The authors propose a set of models for the optimum exploitation of technogenic deposits taking into account various factors of the external and internal environment as well as the time factor. The proposed models allow to substantiate and choose the best technologies for the processing of accumulated waste in terms of the reduction of pollution and “green” revenues from the exploitation of technogenic deposits. To account the probabilistic assessments of the geological structure of the technogenic deposits, we propose to use a combination of Monte-Carlo method and of developed optimization models. The authors describe the calculation results and the prospects for the development of a comprehensive model using regional technogenic deposits. The results of the research allow forming an optimal set of projects for waste processing and rehabilitation of disturbed territories at the regional level. The proposed economic and mathematical tools will be useful for updating the federal target program “Elimination of accumulated environmental damage” for 2015–2026.

The article is devoted to development of natural resources of Yakutia in the first decades of the 20th century, when under the influence of political change and the growing crisis in the economy the issues of use of local raw materials to meet the needs of the population have become more relevant. The steps are discussed, taken in the early 20th century by private entrepreneurs, cooperative bodies and government organizations for scientific and engineering research of mineral resources of Yakutia, examining the prospects of their extraction and further processing. It is shown that in the period after the revolution of 1917 the role of private business initiatives for development of mineral resources began to decline significantly, the initiative in this direction passed into the hands of rural and cooperative bodies. It is noted that with the establishment of the Soviet power in Yakutia in December 1919, all the initiatives of the private and cooperative sectors in the development of handicraft production from local raw materials was terminated. It is emphasized that the state concentrated in its hands all the activities, including scientific research, in searching, exploration and industrial processing of mineral resources of Yakutia. The authors conclude that in the studied period the study of natural resources increasingly was not only of scientific, but above all of practical interest, which was linked with the need to find solutions to the economic crisis caused by the war and revolution of 1917.

In most reservoirs with oil rims, as the production begins, the gas–oil and oil–water fluid interfaces start deforming because of the imbalance between viscous and gravitational forces, leading to coning or cusping. This can be overcome using proper withdrawal rate, offset from water–oil contact and horizontal length. Further smart horizontal wells require optimization of nozzle size and compartment length also. To see the effect of these parameters on recovery, a three-dimensional geological model of a clastic reservoir from Upper Assam Basin has been used. This model was history matched for a period of 16 years on 46 wells. After successful validation of model on field scale and well level, performance prediction was carried out to see the effect of withdrawal rate, offset from water–oil contact, horizontal length, compartment length and nozzle size using vertical/horizontal and ICD completion. From the analysis, it is evident that application of advanced well completion, ICD, is suitable for such reservoir. Depending on the scenario, maximum cumulative oil production was obtained from ICD wells with 1.08 MMm3 compared to vertical well with cum oil production of 0.63 MMm3. Economic analysis has been carried out for the examined scenarios. [ABSTRACT FROM AUTHOR]

ADOC, Abu Dhabi Oil Co., Ltd. (Japan), marks another historical milestone with the commencement of oil production from a new oil field in November 2017. ADOC was established in 1968, and since then has been conducting stable operations through utilization of the best production technology that fully copes with the environment protection rules and regulations. The new oil field was granted as an additional oil field to its existing three oil fields when ADOC renewed its concession agreement in December 2012. Soon after the renewal of the concession, ADOC launched the new oil field development activities. The development plan of the field consisted of; 3D seismic acquisition, subsurface studies, drilling of appraisal wells and production wells, dredging of a channel and construction of the new artificial island and surface facilities. This paper will summarize the various challenges of field development in an environmentally sensitive area and the measures that were implemented. [ABSTRACT FROM AUTHOR]