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During the exploitation life of one tray, different influences cause damage to the rocks located in the borehole. Damaged rocks are characterized by the clogging of the hard space, which is manifested by reduced bandwidth, resulting in a decline in fluid production. In order to solve this problem, there are different stimulating methods that are successfully applied around the world. In Serbia, there is a practice that acid treatments are most commonly used when solving the problem of rock damage. These methods are based on the application of acid solutions of different composition, depending on the mineral composition of the rock collector. This paper describes the process of resolving the reduction of production of X-1 and X-2 wells, whose production intervals are represented by rocks with different carbonate content , and the problem-solving approach is different.

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.

Oil and gas reservoirs can contain water as a reservoir fluid. The water precentage ranges from a few (%) to almost total water saturation. The waters found in the oil and gas reservoirs are genetically related to oil origin and represent mixture of organic and inorganic materials. These waters are of marine origin and contain mineral salts such as Na+, K+, Ca2+, Mg2+, Cl-, HCO3, SO4. Produced water must be subjected to a particular treatment before the deposal so as not to contaminate the environment, primarly watercourses. The mineral composition of these waters can cause the occurence of limescale, which in turn result in damage of the equipment such as injection pumps, corrosion of metal parts etc. The paper presents an overview of the hydrochemical characteristics of the groundwaters of oil and gas reservoirs and produced water into the bargain. Produced or wastewater can be used among other things to inject into the aquifers of the oilfield to increase the production of crude oil as well as their treatment.

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.

The problem that arises in the work of wells in the oil field Gaslift Amal to individual wells do not always have the necessary amount of gas for injection. Therefore, in a borehole at a depth of injection, the operating valve, there is not enough dynamic pressure for the removal of oil on the surface. This is particularly evident in wells with increased production of formation water. For this reason, the paper presents the methodology and drafted model for optimal allocation of the amount of gas injected into each well in the work gaslift of the system. The methodology for the allocation of quantities of gas injection through the so-called cumulative curves based on the dynamic characteristics of each well.

This paper is an investigation on North Gialo Field to enhance the oil recovery by stimulating the main reservoir, the Upper Nubian Sandstone, which is affected by pervasive diagenetic modifications of porosity and permeability. The significant increase in the production rate after hydraulic fracturing treatment shows the importance of implementing this method for this formation in Libya for optimising production. And moreover, to gain better recovery of the stored hydrocarbon in this reservoir. The sensitivity of this case that is required a critical treatment with a precaution investigation during the operation such as High Strength Proppant, type of proppant, sieve size, conductivity indication, production estimation, Net Present Value, and the comparison between treated and untreated cases. Furthermore, deeper Nubian Sandstone formation and the treatment temperature up to 149 °C. Therefore, choosing the delayed borate crosslinked fluid by using Hydroxy Propyl Guar (HPG), gelling agent and special additives designed to enhance the viscosity at a higher temperature, to break the viscosity at the end of the end of the pump time and good proppant transport. Another benefit of the additives is stable fluid rheology, low fluid loss properties, and good cleanup properties. Post-stimulation data were collected, and the evaluation was performed in order to calibrate and improve the current models and future stimulation treatment within the North Nubian Sandstones. [ABSTRACT FROM AUTHOR]

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