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.

The production of paraffin-base crude is expensive and more complex then of other oil types. In northern Serbia, where majority of oil and gas fields are located, about 25% of oil production accounts for the high paraffin oil. During this oil type production, the paraffin deposition occurs in tubing's upper zone, ranging from 700 m depth upwards. In this article is presented original way of heating cable application, for solving paraffin deposition problem in tubing that can be easy and quickly installed in the well. Paraffin deposition problem is solved by heating, and at the same time the increased temperature causes the oil viscosity reduction resulting with improved oil flow rate. Application of this method and the results are exemplified by the flowing well B-3 where are used two different heating cables. This method, which is very successfully solves the problem of paraffin deposition in the tubing, can also be applied to wells producing by different artificial lift methods.

The water produced at the Amal oil field in Libya is directly stored for evaporation in in-ground-pits. As there are a large number of oil production wells, there is a risk of environmental pollution because of the waste water’s eventual penetration into subsoil and surface waterways. From a technical point of view, the existing system of reservoir water disposal into storage pits will not be adequate to meet the increasing water production. Besides, the discharge of produced water without previous treatment is ecologically unacceptable. In this paper, a modern concept of produced water preparation is proposed, and the method of its disposal defined, applying an integrated approach to solving this problem, including technological, economic and environmental aspects. Produced water preparation in an oil field in Libya was chosen for the proposed implementation of an option with the lowest operating costs (storage tanks and liquid hydrophobic filter tank).

In this article we present a model for determination of optimal parameters of main distributive gas pipelines by dynamic programming (DP) methods. The basic characteristic of this gas pipeline system is that the transported gas quantities are variables. This article presents DP techniques for solving the problem of minimizing investment costs of gas pipeline building. The main objective of this program is to determine the optimal location of compressor station and the optimal diameter of gas pipeline under the constraint of pressure value achievement for all users. The proposed model develops an improved numerical searching technique with the purpose of finding the optimal solution quickly.Applications for this method for optimal parameter determination of gas pipelines and the results are exemplified by the design of a gas pipeline in Belgrade-Valjevo. The model presented will be applied in a feasibility study to define the optimal parameters of a future gas pipeline, South Stream, from the Russian Federation to central Europe.

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.