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Search indexed NASA NTRS and DOE OSTI research on propulsion, heat transfer, battery materials and energy systems. Follow report and document links to the original sources.

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At least 577 records · Page 32
All sourcesNASA NTRSDOE OSTI
DOE OSTI2018

Oil effect on CO 2 foam stabilized by a switchable amine surfactant at high temperature and high salinity

Despite the possible detrimental effect of oil on foam displacement processes in CO 2 EOR the effect of oil on dense CO 2 foams has received little attention relative to air foams or low density CO 2 foams. Herein, the effect of both a first contact miscible hydrocarbon (dodecane) and crude oil on CO 2 /water (C/W) foams generated by a switchable surfactant, C 12–14 N(EO) 2 was examined at dense CO 2 conditions at temperatures up to 120 °C (393 K) and 3400 psia (23 MPa). Upon increasing the fractional flow of dodecane, a gradual decrease in foam viscosity was observed as the foam becomes unstable. Since only two phases are present, traditional destabilization mechanisms for three phase oil/gas/water systems based on the entering and spreading are invalid. Therefore, an alternative mechanism is suggested whereby added dodecane strengthen the surfactant tail interactions with the nonaqueous phase (mixture of CO 2 and dodecane) to shift the hydrophilic-CO 2 philic balance (HCB) towards an unstable region. This mechanism is supported by a decrease of the CO 2 –water interfacial tension from ~5 mN/m to 0.5 mN/m for dodecane–water systems at 120 °C and 3400 psia. The effect of crude oil was more profound than for dodecane, whereby rapid destabilization of foam occurred at an oil fractional flow as low as 0.2. In this case, the immiscible portion of the crude oil can enter and spread at the lamellae to destabilize the foam as is evident in positive entering and spreading coefficients. Also, other foam destabilizing parameters such as temperature and capillary pressure were studied in the presence of oil and the results were consistent with those in the absence of oil.

nuclear (including radiation effects), carbon sequ↗
DOE OSTI2016

Opportunities for increasing CO 2 storage in deep, saline formations by active reservoir management and treatment of extracted formation water: Case study at the GreenGen IGCC facility, Tianjin, PR China

Carbon capture, utilization and storage (CCUS) seeks beneficial applications for CO 2 recovered from fossil fuel combustion. This study evaluated the potential for removing formation water to create additional storage capacity for CO 2 , while simultaneously treating the produced water for beneficial use. Furthermore, the process would control pressures within the target formation, lessen the risk of caprock failure, and better control the movement of CO 2 within that formation. The project plans to highlight the method of using individual wells to produce formation water prior to injecting CO 2 as an efficient means of managing reservoir pressure. Because the pressure drawdown resulting from pre-injection formation water production will inversely correlate with pressure buildup resulting from CO 2 injection, it can be proactively used to estimate CO 2 storage capacity and to plan well-field operations. The project studied the GreenGen site in Tianjin, China where Huaneng Corporation is capturing CO 2 at a coal fired IGCC power plant. Known as the Tianjin Enhanced Water Recovery (EWR) project, local rock units were evaluated for CO 2 storage potential and produced water treatment options were then developed. Average treatment cost for produced water with a cooling water treatment goal ranged from 2.27 to 2.96 US$/m 3 (recovery 95.25%), and for a boiler water treatment goal ranged from 2.37 to 3.18 US$/m 3 (recovery 92.78%). Importance analysis indicated that water quality parameters and transportation are significant cost factors as the injection-extraction system is managed over time. Our study found that in a broad sense, active reservoir management in the context of CCUS/EWR is technically feasible. In addition, criteria for evaluating suitable vs. unsuitable reservoir properties, reservoir storage (caprock) integrity, a recommended injection/withdrawal strategy and cost estimates for water treatment and reservoir management are proposed.

54 ENVIRONMENTAL SCIENCES↗
DOE OSTI2020

Probabilistic risk-based Area of Review (AoR) determination for a deep-saline carbon storage site

Regulatory oversight of a geologic carbon sequestration (GCS) project relies on iterative estimations, throughout the project lifetime, of the area where increased risks to underground sources of drinking water (USDWs) may occur due to injection of CO2. This area, referred to as Area of Review (AoR), is typically delineated by predicting the migration of fluid between the reservoir and the lowermost USDW via an open wellbore using predictions from physics-based reservoir simulators. The inherent uncertainty in input parameters used in reservoir modeling therefore affects the accuracy of determining the AoR for a project. Furthermore, the standard analytical approaches for calculating a critical pressure to delineate the risk area yield an infinite AoR for cases where the injection reservoir is overpressured relative to the USDW. A methodology is presented in this paper to better characterize the risk to USDWs while accounting for the uncertainty in reservoir modeling, with an application to a permitted GCS project with an overpressured injection formation, FutureGen 2.0. The methodology is demonstrated using the National Risk Assessment Partnership’s open-source integrated assessment model (NRAP-Open-IAM) to develop a probabilistic estimate of impact risk to USDW quality. CO2 and pressure predictions from the reservoir modeling conducted using the STOMP-CO2 simulator for the FutureGen 2.0 site are used in a NRAP-Open-IAM model with reservoir, wellbore, and aquifer components to: (1) assess the extent of potential leakage into the USDW for the predicted reservoir pressure conditions; (2) evaluate the extent of potential impact using “no-net-degradation” thresholds; and (3) account for uncertainty in reservoir permeabilities.

03 NATURAL GAS↗
DOE OSTI2022

GCS site selection in saline Miocene formations in South Louisiana

One of the key requirements of a commercial scale geologic carbon sequestration (GCS) site selection process is identifying injection sites to safely inject and retain injected CO 2 over extended time scales. This requires thorough evaluation of site-specific surface and subsurface features. A site screening and selection framework was developed and used to identify potential sites in South Louisiana, incorporating surface data including site proximity to large CO 2 stationary sources, vicinity of large population centres and state lands, land usage, legacy oil and gas wells, and local/regional geologic trends. Regionally the Miocene sediments thicken and dip towards the south, reflecting a prograding deltaic environment during the Miocene which resulted in the deposition of thick packages of fine-grained sandstones suitable for CO 2 storage. The results of three example selected sites that are spatially separated with varying subsurface and surface features are presented in this study. The multiple stacked sand zones at these sites provide ample amount of pore volume for CO 2 storage with varying degree of stratigraphic/structural traps for long terms storage containment. Here, the screening framework presented in this study and the detailed evaluation of three specific sites in South Louisiana provides a process to screen and characterize sites for GCS projects and the suitability of these Miocene sediments for commercial scale CO 2 storage projects. It is envisioned that the analysis described in this paper will be beneficial for a large number of audiences involved in GCS work and aid in the site selection process.

58 GEOSCIENCES↗