Capturing and storing carbon dioxide (CO2) underground for thousands of years is one way to reduce atmospheric greenhouse gases, often associated with global warming. Leakage of CO2 through wells is one of the major concerns when storing CO2 in depleted oil and gas reservoirs. CO2-injection candidates could be new wells, or old wells that are active, closed or abandoned. To prevent the leakage, the possible leakage paths and the mechanisms triggering these paths must be examined and identified. It is known that the leakage paths can occur due to CO2-rock interaction and CO2-water-cement interaction. Interaction between well cement and carbon dioxide has attracted much renewed interest because of its implication in geological storage of carbon dioxide. The diffusion of CO2-water through well cement is a long-term phenomenon which can take many thousand years. Partial pressure, porosity, permeability, cement type, moisture content and temperature are the factors that affect the carbonation of well cement. The objective of this research is to investigate the chemical reactions of the dissolved CO2 in the synthetic formation water with the plugs of well cement. Cement specimens were left in contact with CO2 saturated brine at 1100 psi and 65

ABSTRACT UNCERTAINTY ASSESSMENT IN RESERVE ESTIMATION OF A NATURALLY FRACTURED RESERVOIR ERI&Ccedil / OK, &Ouml / zlen M.S., Department of Petroleum and Natural Gas Engineering Supervisor : Prof. Dr. Fevzi G&Uuml / MRAH December 2004, 169 pages Reservoir performance prediction and reserve estimation depend on various petrophysical parameters which have uncertainties due to available technology. For a proper and economical field development, these parameters must be determined by taking into consideration their uncertainty level and probable data ranges. For implementing uncertainty assessment on estimation of original oil in place (OOIP) of a field, a naturally fractured carbonate field, Field-A, is chosen to work with. Since field information is obtained by drilling and testing wells throughout the field, uncertainty in true ranges of reservoir parameters evolve due to impossibility of drilling every location on an area. This study is based on defining the probability distribution of uncertain variables in reserve estimation and evaluating probable reserve amount by using Monte Carlo simulation method. Probabilistic reserve estimation gives the whole range of probable v original oil in place amount of a field. The results are given by their likelyhood of occurance as P10, P50 and P90 reserves in summary. In the study, Field-A reserves at Southeast of Turkey are estimated by probabilistic methods for three producing zones / Karabogaz Formation, Kbb-C Member of Karababa formation and Derdere Formation. Probability density function of petrophysical parameters are evaluated as inputs in volumetric reserve estimation method and probable reserves are calculated by @Risk software program that is used for implementing Monte Carlo method. Outcomes of the simulation showed that Field-A has P50 reserves as 11.2 MMstb in matrix and 2.0 MMstb in fracture of Karabogaz Formation, 15.7 MMstb in matrix and 3.7 MMstb in fracture of Kbb-C Member and 10.6 MMstb in matrix and 1.6 MMstb in fracture of Derdere Formation. Sensitivity analysis of the inputs showed that matrix porosity, net thickness and fracture porosity are significant in Karabogaz Formation and Kbb-C Member reserve estimation while water saturation and fracture porosity are most significant in estimation of Derdere Formation reserves.