Dissertation/Thesis Abstract

A Practical Approach for Formation Damage Control in Both Miscible and Immiscible CO2 Gas Flooding in Asphaltenic Crude Systems Using Water Slugs and Injection Parameters
by David, Sergio Z., Ph.D., University of Louisiana at Lafayette, 2016, 372; 10196386
Abstract (Summary)

CO2 flooding has proven to be an effective technique for enhanced oil recovery. However, the application of CO2 flooding in the recovery process of asphaltenic crude systems is often avoided, as high asphaltene precipitation rates may occur. While the effects of asphaltene concetration and CO2 injection pressure on asphaltene precipitation rate have been the focus of many studies, asphaltene precipitation rate is not a reliable factor to predict the magnitude of asphaltene-induced formation damage. Wettability alteration is only caused by the immobile asphaltene deposits on the rock surface. The enternmaint of flocs may occur at high fluid velocity. Morover, the effective permeability reduction is only caused by the flocs, which have become large enough to block the pore throats. The dissociation of the flocs may occur under certain flow conditions. In this study, a compositional reservoir simulation was conducted using Eclipse 300 to investigate the injection practice, which avoids asphaltene-induced formation damage during both immiscible and miscible CO2 flooding in asphaltenic crude system. Without injection, at pressure above bubble point, slight precipitation occurred in the zone of the lowest pressure near the producing well. As pressure approached the bubble point, precipitation increased due to the change in the hydrocarbon composition, which suggested that the potential of asphaltene-induced formation damage is determined by the overall fluid composition. At very low pressure, precipitation decreased due to the increase in the density.

As CO2 was injected below the minimum miscibility pressure, a slight precipitation occurred in the transition zone at the gas-oil interface due to the microscopic diffusion of the volatile hydrocarbon components caused by the local concentration gradients. The increase in CO2 injection rate did not significantly increase the precipitation rate.

As CO2 was injected at pressure above the minimum miscibility pressure, precipitation occurred throughout the entire reservoir due to the vaporizing drive miscibility process. While precipitation increased with the injection rate, further increase in the injection rate slightly decreased the deposition due to shear. The pressure drop in the water phase caused by the pore throat increased the local water velocity, resulting in a more effective removal of the clogging asphaltene material.

Indexing (document details)
Advisor: Boukadi, Fathi
Commitee: Feng, Yin, Hayatdavoudi, Asadollah, McIntyre, Carl, Pratt, Michael, Seibi, Abdennour
School: University of Louisiana at Lafayette
Department: Petroleum Engineering
School Location: United States -- Louisiana
Source: DAI-B 78/12(E), Dissertation Abstracts International
Subjects: Petroleum Geology, Petroleum engineering, Energy
Keywords: Asphaltene deposition, Asphaltene solubility, CO2 flood, Carbon Dioxide flood, Formation damage, Oil recovery, Permeability reduction
Publication Number: 10196386
ISBN: 978-0-355-11276-4
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