In this study a hybrid Pore Network (PN) model that simulates two-phase (water-oil) drainage and imbibition mechanisms is developed. The developed model produces Nuclear Magnetic Resonance (NMR) T2 relaxation times using correlations available in the literature. The developed PN was calibrated using experimental relative permeability data obtained for Berea Sandstone, Kuzey Marmara Limestone, Yenik&ouml / y Dolostone and Dolomitic Limestone core plugs. Pore network body and throat parameters were obtained from serial computerized tomography scans and thin section images. It was observed that pore body and throat sizes were not statistically correlated. It was also observed that the developed PN model can be used to model different displacement mechanisms. By using the synthetic data obtained from PN model, an Artificial Neural Network (ANN) model was developed and tested. It has been observed that the developed ANN tool can be used to estimate oil &ndash / water relative permeability data very well (with less than 0.05 mean square error) given a T2 signal. It was finally concluded that the developed tools can be used to obtain multiphase flow functions directly from an NMR well log such as Combinable Magnetic Resonance (CMR).

The Nil&uuml / fer Unit of the Karakaya Complex at the pre-Liassic basement of the Sakarya Composite Terrane is composed mainly of metabasaltic lithologies with limestones, and minor cherts and mudstones. These metabasic assemblages show OIB- and E-MORB-type geochemical signatures with variable enrichment in the most incompatible elements relative to N-MORB. The Eymir Unit consists of variably deformed metaclastics, and constitutes the matrix in which the Nil&uuml / fer-type blocks are embedded. In the Ankara region, the Eymir Unit is intruded by metadiabase dikes that display intra-oceanic SSZ-type signatures with a marked negative Nb anomaly combined with a slightly depleted HFSE budget relative to N-MORB. The wide range in trace element ratios displayed by the Nil&uuml / fer metabasic rocks can be explained by melt-mixing processes that has taken place within the spinel-garnet transition zone. Pb-Nd-Hf radiogenic isotope systematics reveal that the Nil&uuml / fer samples has been derived from enriched mantle sources, and a multi-component source mixing is required to explain their genesis. The Eymir metadiabases, however, require contribution from a sediment component that mixes with a depleted mantle source. The geochemical data when combined with the geological and petrographical observations suggest that the Nil&uuml / fer metabasic rocks represent ancient oceanic islands that were created by a heterogeneous mantle plume rising beneath the Palaeotethyan oceanic lithosphere. During the latest Triassic, these oceanic islands were incorporated into a subduction/accretion prism, where they mixed with the continental-derived assemblages of diverse origin, creating the Karakaya Complex. The intrusion of the SSZ-type metadiabases postdates the formation and deformation of the Complex.

In the Central Anatolian Crystalline Complex (CACC) the Late Cretaceous post-collisional granitic magmatism is followed by Eocene extension, resulting in formation of roughly E-W trending transtensional basins. Formation of these basins was accompanied by calc- alkaline- mildly alkaline volcanism. The volcanic rocks, mainly subaques lava flows and subareal domes are concentrated along these basins and associated with Middle Eocene (Bartonian) Mucur Formation. They are basic to intermediate and are classified as basalt, basaltic andesite and rarely alkali basalt and trachy-andesite. All studied samples are strongly and variably LREE enriched relative to chondrite with the (La/Sm)N ratio of 2.26- to 6.17. They have negative Nb-Ta and Ti anomalies in the primitive mantle normalized diagram, and are characterized by low Nb/La (0.21 to 0.62), Ce/Pb (3.70-34.90) and Nb/U ratios (1.11-30), which may indicate an interaction with the Late Cretaceous granitic host rocks in the course of their ascent. The volcanic rocks display similar but variable ranges of Sr, Nd and Pb isotope values. Relatively high values of &epsilon / Nd (0.53 to 4.33) indicate an isotopically depleted mantle source. Combined trace element and isotope compositions of the Eocene samples suggest that they were derived from a heterogeneous lithospheric mantle source that had been metasomatized by subduction related agents such as fluids and/or melts during a previous geodynamic event. Geochemistry and geotectonic setting point out that lithospheric delamination was the most likely mechanism to generate these calc-alkaline to mildly alkaline volcanic rocks in the CACC.

Most investments in the oil and gas industry involve considerable risk with a wide range of potential outcomes for a particular project. However, many economic evaluations are based on the &ldquo / most likely&rdquo / results of variables that could be expected without sufficient consideration given to other possible outcomes and it is well known that initial estimates of all these variables have uncertainty. The data is usually obtained during drilling of the initial oil well and the sources are geophysical (seismic surveys) for formation depths and areal extent of the reservoir trap, well logs for formation tops and bottoms, formation porosity, water saturation and possible permeable strata, core analysis for porosity and saturation data and DST (Drill-Stem Test) for possible oil production rates and samples for PVT (Pressure Volume Temperature) analysis to obtain FVF (Formation Volume Factor) and others. The question is how certain are the values of these variables and what is the probability of these values to occur in the reservoir to evaluate the possible risks. One of the most highly appreciable applications of the risk assessment is the estimation of volumetric reserves of hydrocarbon reservoirs. Monte Carlo and moment technique consider entire ranges of the variables of Original Oil in Place (OOIP) formula rather than deterministic figures. In the present work, predictions were made about how statistical distribution and descriptive statistics of porosity, thickness, area, water saturation, recovery factor, and oil formation volume factor affect the simulated OOIP values. The current work presents the case of two different oil fields in Turkey. It was found that both techniques produce similar results for 95%. The difference between estimated values increases as the percentages decrease from 50% and 5% probability.

The aim of this study is to investigate the petrography, geochemistry and evolution of quartz-tourmaline-rich rocks occurring in a wide breccia zone within the Late Cretaceous Kerkenez Granitoid (Central Anatolian Crystalline Complex (CACC), Turkey). The approximately 40-m wide main breccia zone has a NE-SW trend and is characterized by intense cataclastic deformation. The breccia zone can be traced several kilometers towards the west and generally occurs as tourmaline-filled faults and 1mm-30cm-thick veins within the granitoid. On the basis of mineralogical and textural features, rocks within this zone are defined as tourmaline veins, tourmaline-breccias and quartz-tourmaline rocks. These rocks are generally composed of quartz, tourmaline and granitic fragments. Petrographical investigations and electron-microprobe analyses indicate that, there are three optically and chemically different tourmaline generations. From oldest to youngest, the tourmalines are classified as blue pleochroic feruvites, blue-green pleochroic schorls and green-light green pleochroic schorls. The chemistry of the tourmalines suggests that these tourmalines crystallized from boron rich fluids derived from an evolving magma. Consequently, the quartz tourmaline-breccia zone is considered to have formed by the injection of overpressured boron rich fluids into faults and fractures present within the Kerkenez Granitoid. Fluid-filled faults and fractures were sealed by quartz-tourmaline crystallization. This led to further fractionation in the magma, new fluid pressure accumulations, reactivation of faults and crystallization of different tourmaline generations. Tourmaline-breccia zones are scarce in the literature and the presence of such rocks within the CACC is first reported in this study.

The aim of this thesis is to study water saturation models available in the literature and to apply a proper one to a real field case. Archie equation is the most well-known water saturation model. However, it is formulated on some assumptions and is applicable to only clean sands. Archie equation cannot be used for shaly formation. There are many shaly water saturation models that account for shale effect for water saturation estimation. In this study, 3 wells, namely Well-01, Well-02 and Well-03 are studied. These wells lie in a fractured carbonate reservoir located in Southeastern part of Turkey. From well log recordings, the production formation is seen almost clean. In other words, the shale amount of the formation is so small that it can be neglected. Thus, to calculate the water saturation in those wells, the well-known Archie water saturation equation is used. Since the formation is fractured carbonate, the cementation factor (m ) and saturation exponent (n ) of conventional value of 2 each cannot be used for the water saturation calculation. Instead, these parameters are obtained from generalized crossplot of log-derived porosity and resistivity technique. Finally, each well is divided into zones using porosity data. Zonation is conducted based on statistical method, ANOVA (analysis of variance). Well-01 and Well-02 are both divided into two zones. On the other hand, the statistical method was initially divided Well-03 into three zones. However, Well-03 is better described as a whole zone, depending on the geological analysis and engineering judgment. After the zonation, the zones are correlated from well to well. The water saturations in significantly correlated zones are examined. Also, using the same statistical method, the water saturation zones are identified. However, these zones do not coincide with the porosity zones. This difference is attributed to pore size distribution and wettability which affect saturation distribution.

This study aims to reveal the geochemical signatures of the basic igneous rocks with well-determined age within the Karakaya Complex in Central and NW Anatolia and also exhibit the relationships between the studied units in terms of geological and petrographical features. The Karakaya Complex comprise a number of tectono-stratigraphic units in the studied regions (the Olukman Melange, the Bah&ccedil / ecik Formation, the Ortaoba Unit and the informally named pillow basalt-limestone association) and the pre-Karakaya basement unit (the Eymir Complex). The basic igneous rocks have been all intensely affected by hydrothermal metamorphism as reflected by the secondary products strongly overprinting the primary mineral phases and most of them exhibit vesicular structures which are filled by mainly calcite. The primary mineral assemblage dominating the basaltic rocks is clino-pyroxene, plagioclase and olivine, whereas secondary phases are characterized by actinolite, pistacite, zoisite/clinozoisite group and chlorite. Kaersutite, as a late stage magmatic mineral, is distinctive for Ti-augite bearing imrahor basalts / on the other hand, the diabase dykes include hornblende as an essential primary phase. The basic rocks are represented by three groups / sub-alkaline, alkaline and transitional. The alkaline samples from imrahor, Hasanoglan, Kadirler and Ortaoba are of Anisian age and akin to oceanic-island basalts (OIB). The sub-alkaline and transitional samples from imrahor and Ortaoba reflect P-MORB features and are younger than the first group. The diabase dykes cross-cutting the Eymir Complex, on the other hand, are too dissimilar, indicating back-arc basin signatures. Based on the data obtained from this study, the Karakaya Complex is characterized by a number of tectonic components (seamount, plume-related mid ocean ridge and back-arc basin) with different ages and origins, which were later amalgamated during the Cimmerian orogeny.

The large amount of produced oil and gas come from conventional resources all over the world and these resources are being depleted rapidly. This fact and the increasing oil and gas prices force the producing countries to find and search for new methods to recover more oil and gas. In order to meet the demand, the oil and gas industry has been turning towards to unconventional oil and gas reservoirs which become more popular every passing day. In recent years, they are seriously considered as supplementary to the conventional resources although these reservoirs cannot be produced at an economic rate or cannot produce economic volumes of oil and gas without assistance from massive stimulation treatments, special recovery processes or advanced technologies. The vast increase in demand for petroleum and gas has encouraged the new technological development and implementation. A wide range of technologies have been developed and deployed since 1980. With the wellbore technology, it is possible to make use of highly deviated wellbores, extended reach drilling, horizontal wells, multilateral wells and so on. All of the new technologies and a large number of new innovations have allowed development of increasingly complex economically marginal fields where shale gas and coal bed methane are found. In this study, primary target is to compare different production methods in order to obtain better well performance and improved production from different types of reservoirs. It is also be given some technical information regarding the challenges such as hydraulic fracturing and multilateral well configuration of the unconventional gas reservoir modeling and simulation. With the help of advances in algorithms, computer power, and integrated software, it is possible to apply and analyze the effect of the different well trajectories such as vertical, horizontal, and multilateral well on the future production performance of coal bed methane, shale gas, and tight gas reservoirs. A commercial simulator will be used to run the simulations and achieve the best-case scenarios. The study will lead the determination of optimum production methods for three different reservoirs that are explained above under the various circumstances and the understanding the production characteristic and profile of unconventional gas systems.

Producing since 1995, Bozova Field is a mature oil field to be re-evaluated. When evaluating an oil field, the common approach followed in a reservoir simulation study is: Generating a geological model that is expected to represent the reservoir / building simulation models by using the most representative dynamic data / and doing sensitivity analysis around a best case in order to get a history-matched simulation model. Each step deals with a great variety of uncertainty and changing one parameter at a time does not comprise the entire uncertainty space. Not only knowing the impact of uncertainty related to each individual parameter but also their combined effects can help better understanding of the reservoir and better reservoir management. In this study, uncertainties associated only to fluid properties, rock physics functions and water oil contact (WOC) depth are examined thoroughly. Since sensitivity analysis around a best case will cover only a part of uncertainty, a full factorial experimental design technique is used. Without pursuing the goal of a history matched case, simulation runs are conducted for all possible combinations of: 19 sets of capillary pressure/relative permeability (Pc/krel) curves taken from special core analysis (SCAL) data / 2 sets of pressure, volume, temperature (PVT) analysis data / and 3 sets of WOC depths. As a result, historical production and pressure profiles from 114 (2 x 3 x 19) cases are presented for screening the impact of uncertainty related to aforementioned parameters in the history matching of Bozova field. The reservoir simulation models that give the best match with the history data are determined by the calculation of an objective function / and they are ranked according to their goodness of fit. It is found that the uncertainty of Pc/krel curves has the highest impact on the history match values / uncertainty of WOC depth comes next and the least effect arises from the uncertainty of PVT data. This study constitutes a solid basis for further studies which is to be done on the selection of the best matched models for history matching purposes.

To meet the goal of atmospheric stabilization of carbon dioxide (CO2 ) levels a technological transformation should occur in the energy sector. One strategy to achieve this is carbon sequestration. Carbon dioxide can be captured from industrial sources and sequestered underground into depleted oil and gas reservoirs. CO2 injected into geological formations, such as mature oil reservoirs can be effectively trapped by hydrodynamical (structural), solution, residual (capillary) and mineral trapping methods. In this work, a case study was conducted using CMG-STARS software for CO2 sequestration in a mature oil field. History matching was done with the available production, bottom hole pressures and water cut data to compare the results obtained from the simulator with the field data. Next, previously developed optimization methods were modified and used for the case of study. The main object of the optimization was to determine the optimal location, number of injection wells, injection rate, injection depth and pressure of wells to maximize the total trapped amount of CO2 while enhancing the amount of oil recovered. A second round of simulations was carried out to study the factors that affect the total oil recovery and CO2 &not / storage amount. These include relative permeability end points effect, hysteresis effect, fracture spacing and additives of simultaneous injection of carbon dioxide with CO and H2S. Optimization runs were carried out on a mildly heterogeneous 3D model for variety of cases. When compared with the base case, the optimized case led to an increase of 20% in the amount of oil that is recovered / and more than 95% of the injected CO2 was trapped as solution gas on and as an immobile gas. Finally, an investigation of the economical feasibility was accomplished. NPV values for various cases were obtained, selected and studied yielding in a number of cases that are found to be applicable for the field of concern.