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In Serbia, there are about 1200 abandoned oil and gas wells, which have significant potential to produce thermal energy. Abandoned wells, depending on their location and thermal potential, can be used to produce thermal energy or electricity, or for the combined production of electricity and thermal energy. Thermal energy that is produced from abandoned wells is obtained using geothermal energy, so the electrical energy and/or thermal energy that would be obtained using such heat sources are balanced as energy obtained from renewable energy sources. The costs of equipping deep wells and applying the technology that would be used to produce thermal energy and/or electricity represent a far smaller part of the costs compared to the costs of making deep wells, so these abandoned wells represent an already existing significant material resource. The production of thermal energy from abandoned wells, which is based on pressing the working medium into the well, heating it and pushing it to the surface, is less energy intensive since the same well is used for the transfer of hot energy - through the appropriate working medium through tubing (narrow pipe) to the surface, and then the used cooled water is returned to the same well through the intermediate space. The paper presents a methodology for calculating the theoretical thermal potential of abandoned oil and gas wells, which was applied to the example of wells K-1, T-1, S-1 and M-1 located in Serbia, with a depth of 2.000 m, 2.250 m, 1.700 m and 2.102 m. It is shown that the theoretical temperature of the working fluid on the surface of the earth is in the range of 77.59 to 94.46°C.

Natural gas consists of a mixture of hydrocarbons with the largest share of methane, and non-hydrocarbon impure components such as N2, CO2 and H2S. In order to fulfill the gas market requirements, it is necessary to separate these unwanted components from the natural gas stream. There are several available technologies for the separation of CO2 from natural gas, such as: polymeric membranes, cryogenic distillation, absorption and adsorption. In this paper is presented the mechanism of CO2 separation using membrane technology, as well as the process of separation CO2 depending on the number of membranes in the system for a typical gas reservoir in Serbia.

CO2 storage in geological formations is one of the leading solutions for mitigation of greenhouse gas emissions. Types of geological formations that can be used for CO2 storage, that are discussed in this paper are: depleted oil and gas reservoirs, saline aquifers and injection CO2 in partially depleted oil reservoirs for enhanced oil recovery (EOR-CO2 method). In order to select the most suitable geological storage of CO2, the ranking of these storage options was performed using two methods of multi criteria analysis, PROMETHEE and VIKOR. This paper presents an overview of considered criteria (storage capacity, total storage costs, risk assessment costs, storage time dynamics, risk of CO2 leakage from geological formation and risk of CO2 leakage through the well), description of applied multi criteria analysis methods, selection of optimal CO2 storage option and results of their application.

CO2 storage in geological formations represents today one of the main new technological solutions for CO2 emission mitigation. Carbon capture and storage technology (CCS) includes capture of anthropogenic CO2 from various emitters, its transportation and injection in different types of geological formations such as: depleted oil and gas reservoirs, saline formations, unmined coal beds, partially depleted oil reservoirs for enhanced oil recovery (EOR-CO2 method) and others. The analysis of numerous criteria that are determining the success of process implementation from a technical, safety, ecological and economic point of view is necessary for considering the optimal CO2 geological storage option. In this paper, an overview of CO2 geological storage types is presented, with an emphasis on criteria for selection of most adequate CO2 storage option. They include geological, physical, thermodynamic, hydrodynamic, techno economic, social criteria, as well as the regulatory issues that are key factors for CCS technology development and further deployment.

In the Serbia there are more gas reservoirs with reserves of more than 10 million Sm3 of natural gas. One of the reasons why they have not been exploited yet is that they contain nitrogen and carbon dioxide, that should be separated during the production process. Today, there are many developed technologies for separation of nitrogen and carbon dioxide from natural gas such as cryogenic processes, membrane technology, molecular sieves, nitrogen spinners, etc. So far, none of the mentioned technologies has been applied in our country. The paper presents technologies for separating nitrogen and carbon dioxide from natural gas. In this paper is presented an analysis of the possibility of applying these technologies from the aspect of the capacity, pressure and content of nitrogen and carbon dioxide in natural gas. In particular, it should be noted that all technologies are already commercially applied in the world. Investment and operating costs for the presented technologies were determined. The economic viability of selected technologies for separating carbon dioxide and nitrogen from natural gas directly depends on the required process capacity. For low daily production rate, membrane technology and molecular sieves are excellent for gas reservoirs in our country. Investment costs are the lowest in implementing the membrane technology and molecular sieves and they are ranging from 9.89 to 11.40 $ / Sm3 , while exploitation costs range from 0.010 to 0.020 $ / Sm3 . This is very important for the reasons of the project economic sensitivity when the small gas reservoir are considered.

In this paper is presented the concept of integrated oil production management model. The model's main objective is to provide more efficient tool for oil production process management in terms of the technological and economical aspects. Integrated oil production management model implies multidisciplinary approach which connects oil reservoir development and production with application of risk analysis. Model's task is to simulate behavior of the whole production system, enabling overcoming the weaknesses of conventional deterministic analysis and significantly enhancing oil production, as well as an investment decision making. In the article is presented shortly the application of integrated oil production management model at the oilfield 'K'. The ultimate goal was techno-economic analysis of managing production process, i.e. determination of production economic limit based on production history data, decline analysis and operating costs.

In the world today for the exploitation of oil reservoirs by artificial lift methods are applied different types of deep pumps (piston, centrifugal, screw, hydraulic), water jet pumps and gas lift (continuous, intermittent and plunger). Maximum values of oil production achieved by these exploitation methods are significantly different. In order to select the optimal exploitation method of oil well, the multicriteria analysis models are used. In this paper is presented an analysis of the multicriteria model's application known as VIKOR, TOPSIS, ELECTRE, AHP and PROMETHEE for selection of optimal exploitation method for typical oil well at Serbian exploration area. Ranking results of applicability of the deep piston pumps, hydraulic pumps, screw pumps, gas lift method and electric submersible centrifugal pumps, indicated that in the all above multicriteria models except in PROMETHEE, the optimal method of exploitation are deep piston pumps and gas lift.

Stuck pipe is a common problem with tremendous impact on drilling efficiency and costs in the oil industry. Generally, the stuck pipe troubles are solved after their occurrences by using some standard operational procedures such as working the drill string up or down, attempting to rotate the string and pumping mud at higher flow rates through the drill bit to aid pipe release. One may also place different fluids around the stick area and use a drilling jar. However, in cases where common solutions don't work, then the cutoff is the last resort. To have a successful cutoff operation, estimating the location of the free point and choosing the right cutting tool is of vital importance. This paper presents the Radial Cutting Torch (RCT) as a innovative cutting tool and its oilfield application in stuck pipe events.

Determining the optimal production oil wells represent the harmonization of production characteristics of a given well with the operational parameters of applied artificial methods of exploitation. This means that the optimal production well achieved when balance the amount of fluid that enters the well (defined by number, diameter, length and spatial orientation perforation) with the amount of fluid applied by artificial method of exploitation belong the well. The paper discusses the key parameters for determining the optimum production well from the application of artificial methods of exploitation such as: characteristics of fluid inflow into the well, forecasting future production well, operational parameters of artificial methods, timing of introduction of artificial methods of exploitation and the price of oil.

In extreme environments and remote areas, exploration puts increasing demands on the technology required for developing new reserves. As drilling operations for oil and gas penetrate deeper horizons, wellbore construction faces new challenges. Deeper and larger hole sections, higher formation pressures and higher temperatures, result in wells that cannot be properly or safely completed with conventional cementing techniques. The integrity of cement sheat is commonly measured by its ability to provide long term zonal isolation in the well. It also has to physically support the casing, withstand pressure and temperature changes, and protect the casing from corrosive fluids. The cement bond failure can cause well control situation, losses of reservoir fluid, migration of fluid from one zone to another, and poor stimulations operations. This paper presents some aspects of new technology tailored to these demands from Schlumberger. Advanced Cement Technology provides a range of cement alternatives, tailored to the well, with properties superior to those of conventional cements to achieve zonal isolation in oil field operations for the life of the well.

Tertiary methods in oil production process called 'Enhanced Oil recovery methods' (EOR) are mostly applied in mature oil fields with declining production trend after primary and secondary recovery methods or immediately after primary production phase. These 'Enhanced Oil Recovery' methods implies injection of gases or fluids to mobilize residual oil captured in reservoir rock due to presence of strong viscous and capillary forces and high value of interfacial tension between fluid and rock. Depending on the type of injected fluid, production mechanism, as well as an approach to implementation, EOR methods are divided into thermal methods, chemical methods, miscible/immiscible gas injection methods and other methods that so far have an experimental application. The paper analyzes the key factors influencing the successful implementation of EOR projects: phases of EOR project implementation, the price of crude oil at the world market as a criterion for the beginning and the justification for EOR process application and development of new technologies for more efficient process realization.

In Serbia approx. 70% of the crude oil produced accounts for the heavy oil type, these results in the deposition of paraffin in wells, oil production decrease while increasing the operating costs. Different methods, such as mechanical, chemical and thermal, are applied in effort to solve the paraffin deposition problem. Most methods require an accurate determination of that the deposition zone in well. In this paper, experimental and simulation results of the parameter analysis affecting intensity and zone of paraffin deposition in oil wells are presented. The analysis has been done for heavy oil produced from the oil field Turija, Vojvodina region, Serbia. The paraffin deposition curves and paraffin deposition intensity during time are experimentally defined. The influence of temperature gradient, fluid flow rate and gas content in oil changes on the paraffin deposition zone change was analyzed by the computer simulation. It was found that temperature gradient changes can cause paraffin deposition zone to change approx. 22 m, i.e. maximum 43 m. It was also determined that the length of paraffin deposition zone can change up to 140 m due to the changes in the fluid flow rate or in the gas content in oil. The increase of the flow rate causes paraffin deposition zone to reduce, while increased gas content in oil leads to its increase. On the basis of the obtained results, the optimal working parameters of mechanical method, such as frequency and depth of paraffin scraping as well as temperature and heating cable power of thermal methods can be determined.