2nd EAGE International Conference KazGeo

The main feature of large-volume gold deposits of Central Asia and Kazakhstan (resources more than 100 tons, low gold grade) is their relation to the suture zones created in the environment of subduction and collision of microplates during amalgamation of Eurasia continent. These deposits have common geology-geochemical features that point out their origin from dehydrated parts of subducted crust. New principle of assessment of suture zones provides capabilities to define new objects for prospecting and exploration of new large volume gold deposits in Kazakhstan and Central Asia.

The regional prospectivity of the South Mangyshlak, North Caspian and North Ustyurt basins is hereby presented based on seismic stratigraphic interpretation of 2D seismic lines acquired by CGGVeritas between 2006-2009 in both the central and northern Caspian Sea. The seismic dataset covers part of the offshore extension of each basin. We have identified four mega-sequences within the North Caspian Basin, two mega-sequences within the North Ustyurt basin and three mega-sequences within the South Mangyshlak Basin. The mega-sequences represent discrete phases of basin-fill mainly caused by a combination of tectonic subsidence, sedimentation rate and relative sea level change. These mega-sequences were identified based on seismic reflection terminations on bounding regional unconformities and their correlative conformities. These represent key plate re-organisation episodes and relative sea level change. In the North Caspian Basin, we have identified Devonian-Carboniferous, Permian-Triassic, Jurassic-Cretaceous and Tertiary mega-sequences. The Jurassic-Cretaceous and Tertiary mega-sequences occur in all three basins with similar depositional facies. The Permian-Triassic sequence is different in both depositional history and petroleum play elements in all three basins whilst the Devonian-Carboniferous sequence has been drilled only in the North Caspian basin.

The miscibility condition is determined by conducting displacement tests at various pressures. Recovery is expected to increase by raising the displacement pressure, and however, it will stay almost constant above the MMP. In this study to estimate MMP of one of the Iranian oil reservoirs with pure CO2, a slim-tube test was performed under constant CO2 injection rate at different displacement pressure above the bubble point. Input and output pressures were continusly monitored during the test. The effluent liquid was flashed to atmospheric conditions; it is weighed and its density is measured for calculating the volumetric oil recovery. The produced gases are passed through gas chromatography for compositional analysis. The oil recovery was plotted against the injection pressure at 1.2 pore volume of injection fluid. The results show that the oil recoveries are more than 90% of original oil in place for all pressures with a constant slop above the bubble point pressure. Therefore, MMP should be the same as bubble point pressure. In addition, effluent gas composition, pressure drop across the slim-tube and no methane bank existence confirm the miscible condition.

The Great Caspian is a leading, prolific producer of hydrocarbons; this region consists of the North, Middle and South Caspian. A major issue in exploiting these hydrocarbons is an understanding the varying pressure regimes therein, that are a direct result of the interaction between tectonics, lithology (e.g. salt, carbonates) and rates of sedimentation. Accurate pore pressure prediction is vital for successful and safe drilling in order to exploit these accumulations. We state that a geological approach is vital to supplement the other numerous methods for pore pressure prediction used worldwide and applied commonly in this region. These other methods often rely on shale-dominant lithologies – therefore, in this region using standard shale interpretations will be inaccurate. For instance, In the North Caspian, the Tengiz Field is located under less than 500 feet of Permian salt; above the salt the sediments are hydrostatic, below the Carboniferous carbonate reservoirs are close to lithostatic pressures; in these cases, traditional low temperature shale analysis will give only a partial solution at best. In the South Caspian, reservoirs may be up to 5000 psi naturally drawn-down relative to the shales in fields such as Shah-Deniz via lateral drainage

A range of different techniques are being utilized during the determination of the geological, petrophysical and geomechanical properties in the petroleum reservoirs. Possibility in express characterisation of their heterogeneity is one of the promising new techniques, which can be used for the field investigation process. In general, understanding in distribution of heterogeneous characteristic, such as geological facies, permeability and porosity helps to delineate the properties of the petroleum field and better understand its structure. The optimized ways of production can be evaluated based on the received data from such analysis.

The Paleozoic reservoir at Kashagan field is characterized by a relatively porous carbonate platform interior surrounded by a highly-cemented margin called the rim. Most of the faults and fractures are concentrated near the rim. Despite low matrix porosity and permeability, rim wells experience lost circulation, bit drops, and high Kh, suggesting a well-developed secondary porosity system. Understanding the role of fractures in this secondary porosity system will be key to reservoir quality prediction. At the seismic scale, faults commonly strike parallel to the rim boundary. At the borehole-scale, image logs also show a fracture set striking parallel to the rim, with secondary sets at high angles to the rim. Rim parallel features are consistent with their formation during early syndepositional margin collapse and differential compaction of the platform and rim.

Деятельность любой сервисной компании сопряжена с обработкой большого объема разнотипной информации, потребность в которой возникает на различных стадиях работы над проектом. Получение надежных результатов интерпретации сейсмических данных возможно только при проведении комплексного анализа всех исходных данных. Анализ данных предполагает обработку имеющегося фактографического материала, в том числе его систематизацию и проведение необходимых преобразований для последующего использования при построении различных моделей. Результаты моделирования, в свою очередь, также требуют систематизации и преобразования к виду, доступному для оперативного анализа, в том числе, на основе 3D-представления и соответствующих технологий.

Delhi Field is located in northeastern Louisiana. The reservoir is the Holt-Bryant zone that consists of Upper Cretaceous (Tuscaloosa) and Lower Cretaceous (Paluxy) sandstones. Currently, the field is undergoing a tertiary CO2 flood of the Holt-Bryant zone for enhanced oil recovery. To better understand the complexity of the reservoir, seismic and well log data were used to determine petrophysical properties within the reservoir. Correlations were established between: density and gamma ray; P-impedance and porosity. Pre-stack, model-based inversion was performed on the seismic data to obtain volumes of density and P-impedance. At the same time, synthetic seismic traces were created by changing the petrophysical properties, and correlations found previously were examined again.

Nowadays, various methods are used for identification of reservoir fractures. Seismic curvature attributes are a group of attributes that can measure the curvature of surface and detect the faults and fractures on that surface. These attributes can be estimated on a definite horizon or in a volume of seismic data. In this paper, the ability of these attributes in fractures detection in one of Iranian south reservoirs by carrying out these attributes on a seismic horizon is studied. Then, the results obtained from curvature attributes are compared with similarity attribute. The results of this study show that curvature attributes such as most positive and most negative curvature can detect fractures on a seismic horizon. In addition, there is a high correlation between curvature and similarity attributes results.

Formation of mineral deposits is encountered in oil and gas production, transportation and processing causing obstruction of technological operations from the initial stage of hydrocarbon production. It has been recognized to be a major operational problem in subsurface and surface oil and gas installations that causes damage to hydrocarbon-producing formations. In order to identify ways of combating this problem we propose study of the detection method for reservoir mineral deposits formed during production. Real-time detection and monitoring of petroleum scales may be possible since the magnetic susceptibilities of scales are distinctly different from crude oils and formation waters. Continuous monitoring or selected measurements of the magnetic susceptibility of petroleum reservoir fluids at the petroleum operational site, or of fluid samples at the laboratory is an effective method to help control scale.