Date of Award

Fall 2020

Degree Type

Thesis

Degree Name

Master of Science (MS)

Committee Chair

Mary North Abbott

First Advisor

Burt Todd

Second Advisor

David Reichhardt

Third Advisor

Mary MacLaughlin

Abstract

Current subterranean injection of anthropogenic Carbon Dioxide (CO2), or CO2 resulting from human activity, is occurring at multiple locations in both the domestic United States and abroad. It involves the capture of CO2 from stationary industrial sources such as power plants and processing facilities, and subsequent injection into suitable subsurface environments. Injection is an alternative to the release of CO2 and reduces the environmental impact of increased atmospheric carbon levels. The three scenarios for CO2 injection are: the sequestration of captured anthropogenic CO2, the re-injection of produced CO2, and the use of CO2 for tertiary hydrocarbon recovery. If injected at conditions allowing for supercritical behavior, CO2 can interact with the near wellbore environment. The result of that interaction is of interest to the longevity of injection operations.

Produced oil and gas are accompanied by some level of CO2 production. This CO2 is often separated and is sometimes re-injected near its source, reducing the percentage of CO2 in the transported product. In contrast, tertiary hydrocarbon recovery introduces injected CO2 for a distinctly different reason. Tertiary injection, also called Enhanced Oil Recovery (EOR), utilizes injected CO2 to recover entrained oil. Tertiary CO2 injection has been historically successful in the Permian Basin of West Texas and New Mexico and is currently being utilized in many other mature fields in the western US. Whether injection occurs for sequestration, disposal, or production, captured CO2 is transported down existing wellbores into in-situ reservoir environments where it may theoretically stay for perpetuity.

In light of the increasing injection of CO2, recent reservoir completion methods often involve the use of CO2 resistant cements. These cements contain fluid loss additives, dispersants, and fly ash to improve strength and reduce permeability. The effect of CO2 on these resistant forms of cements is still being empirically studied. However, many injection environments utilize older wellbores in mature fields. The ability of these older cement sheaths to structurally contain and segregate the wellbore and rock structure during and after the exposure to CO2 is uncertain. To what extent CO2 injection destabilizes these environments impacts global injection projects and the practicality of CO2 injection in general. These potential issues are elevated when it is considered that because of geothermal temperatures and injection pressures, CO2 will be supercritical in nature, where distinct liquid and gas phases do not exist. Supercritical CO2 possesses the dissolving properties of a strong solvent, the ability to transport mass like a liquid, and the ability to permeate small pores and fissures with the diffusivity of a gas. It is possible that when exposed to the destructive properties of supercritical CO2, cement may be chemically altered. Resulting increases in permeability and porosity may lead to breaches in the wellbore’s ability to control the injected CO2 and the surrounding reservoir fluids. Alternately, it is possible that the chemical changes in the cement induced by supercritical CO2 will strengthen the wellbore and increase the containment longevity. This research investigates the effects of supercritical CO2 on laboratory prepared cement core samples by replicating an elevated pressure and temperature flow environment like that of CO2 injection efforts. The resulting permeability, porosity, and strength changes were recorded and analyzed allowing for conclusions regarding the resilience of well-bore cements in the presence of CO2 injection.

Despite lower quantities of successfully exposed samples, results indicate that the presence of supercritical CO2 in a dynamic reservoir environment caused an anecdotal change in porosity and permeability. During subsequent unconfined strength analysis, the experimental values of maximum strength of unexposed experimental controls were found to be greater than almost all exposed cores. Exposed cores were separately examined for statistical significance under the experimental criteria of Young’s Modulus, max stress, and Yield Point. Utilizing a two sample unpaired t-test analysis performed with a significance level of α = 0.095, it can be shown that the experimentally observed decreases in the unconfined stress criteria likely correlate to the presence of super critical CO2 under dynamic reservoir conditions.

Comments

A thesis submitted in partial fulfillment of the requirements for the degree of Master of Science in Petroleum Engineering

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