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Enick, Robert M.

Publications and source records attributed to Enick, Robert M..

Impact of Flow Configurations on Response Time and Data Quality in Real-Time, In-Line Fourier Transform Infrared (FTIR) Monitoring of Viscous Flows

The real-time, in-line monitoring of continuous flow concentrations is widely conducted via infrared (IR) spectrometry by using a flow cell connected to a reactive flow stream. For protective purposes, the IR sensor tip is typically offset from the flow. This offset can cause the formation of a stagnant boundary layer above the sensor, especially when dealing with high-viscosity fluids. As a result, the IR signal response time is often controlled by the slow diffusional exchange of fluid in the boundary layer, as confirmed via 2D computational fluid dynamics (CFD) simulations. We evaluated several flow configuration modifications in a typical IR flow cell in order to identify the changes to the flow dynamics that enable improved response times with minimal changes to the cell configuration: the use of (i) vertical flow, where the standard horizontal flow over the sensor is redirected to contact vertically with the sensor, (ii) a static mixer to create radial flow momentum above the IR sensor, and (iii) horizontal or vertical nozzles to direct the flow toward the IR sensor. The vertical flow configuration did not show any significant improvement over the standard horizontal flow configuration. However, the static mixer, horizontal nozzle, and vertical nozzle configurations all resulted in markedly improved response times and signal quality, albeit at the expense of a higher pressure drop across the flow cell. These results point toward straightforward, user-accessible modifications of in-line IR flow cells that result in significant improvements in signal stability and acquisition times.

42 ENGINEERING↗

CO 2 -Soluble Nonionic Surfactants for Enhanced CO 2 Storage via In Situ Foam Generation

Geologic carbon storage (GCS) is a rapidly evolving technology with the potential to reduce the environmental impact of fos-sil fuels. Saline aquifers, which comprise a sandstone matrix with brine in the pores, make up much of the pore space availa-ble for CO 2 storage in the United States. When CO 2 is injected in saline aquifers, however, capillary fingering occurs and only a small percentage of the pore space is filled with CO 2 . This is due to the low viscosity of CO 2 , which is roughly ten times less viscous than brine. To address this problem, we tested the ability of inexpensive, commercially available nonionic surfactants to be dissolved in the injected CO 2 and increase the apparent viscosity of CO 2 by generating CO 2 -in-water foams in situ.

37 INORGANIC, ORGANIC, PHYSICAL, AND ANALYTICAL CH↗

Dissolving Nonionic Surfactants in CO 2 to Improve Oil Recovery in Unconventional Reservoirs via Wettability Alteration

CO 2 injection is a promising method for enhanced oil recovery (EOR) in unconventional shale reservoirs. Here, in this work, we postulate that CO 2 EOR may be improved by the dissolution of surfactants into CO 2 . Although CO 2 is a relatively good solvent for oil, we show that CO 2 and Eagle Ford oil are immiscible at compositions above 70 wt % CO 2 , even at pressures as high as 62 MPa. The presence of a CO 2 –oil interface at reservoir conditions indicates that the addition of a surfactant has the potential to improve oil recovery–via wettability alteration from oil-wet to CO 2 -wet, CO 2 –oil interfacial tension (IFT) reduction, or both. Three nonionic surfactants (branched tridecyl ethoxylate Indorama SURFONIC TDA-9, branched nonylphenol ethoxylate Indorama SURFONIC N-100, and linear dodecyl ethoxylate Indorama SURFONIC L12-6) were evaluated for CO 2 -solubility, shale wettability alteration, effect on CO 2 –oil IFT, ability to generate CO 2 –oil foams, and ability to increase oil extraction from Eagle Ford, Mancos, and Bakken shale cores. Each surfactant dissolved in CO 2 up to 1 wt % at pressures and temperatures commensurate with CO 2 EOR. CO 2 -dissolved surfactants did not significantly affect CO 2 –oil IFT or generate CO2–oil foams, but they did induce a dramatic change in the contact angle of an oil droplet on an oil-aged shale chip in CO 2 from strongly oil-wet (11°) toward intermediate CO 2 –oil wettability (82°) (at 80 °C, 27.6 MPa). The branched tridecyl ethoxylated surfactant, SURFONIC TDA-9, afforded the highest oil recovery in core soaking experiments–75%, compared to 71% by pure CO 2 . Analysis of oil extracts by gas chromatography revealed that heavier oil components were produced when the surfactant was added to CO 2 . These results indicate that CO 2 -dissolved surfactants may increase oil recovery from shale by wettability alteration from oil-wet toward CO 2 -wet.

04 OIL SHALES AND TAR SANDS↗

Carbon dioxide and polymer compositions for permeability control and sealing

A method of treating a material to achieve at least one of reducing surface wettability of the material or reducing fluid transport through the material includes exposing the material to a composition including a solution of a polymer portion and carbon dioxide for a period of time. The polymer portion includes at least one of a polyfluoroacrylate or a copolymer of a fluoroacrylate and a comonomer. A pressure of the composition is maintained above the cloud point of the polymer portion at a concentration thereof in the carbon dioxide for the period of time.

Enick, Robert M.↗