Analysis, occurrence, and reactions of dawsonite in AMSO well CH-1

Burnham, Alan K.; Levchenko, Andre; Herron, Michael M.

doi:10.1016/j.fuel.2014.12.018

Cited by 11 publications

(4 citation statements)

References 9 publications

Supporting

Mentioning

Contrasting

Order By: Relevance

“…This suggests that the H 2 O-soluble alkaline material (and neutral H 2 O-solubles) was at least in part generated during the reaction, and one possible mechanism for the formation of alkaline H 2 O-solubles would be the decomposition of dawsonite. This will take place in the temperature range of the reactions (see section ), ,− , and dawsonite peaks were not observed in the XRD spectra of the THF-insolubles (Figure ). Furthermore, the amount of Na 2 CO 3 formed from the 2–3 wt % dawsonite in the oil shale would account for the alkaline H 2 O-solubles in the THF-insolubles.…”

Section: Resultsmentioning

confidence: 97%

“…At the reaction temperature of 320 °C, no decomposition of dolomite or calcite would be expected, and prominent dolomite peaks were observed. The long time at 320 °C was sufficient to decompose the dawsonite despite the significant pressures of H 2 O and CO 2 , which would be expected to inhibit dawsonite decomposition. ,− However, there was a big difference in the intensity ratio of the two major peaks, with the lowest-conversion THF-insolubles having a lower ratio of plagioclase to calcite plus dolomite. (The XRD analysis of the THF-insolubles from the lowest-conversion 320 °C CO reaction also showed a low ratio of plagioclase to calcite plus dolomite.)…”

Section: Resultsmentioning

confidence: 99%

See 1 more Smart Citation

Long-Time-Period, Low-Temperature Reactions of Green River Oil Shale

Marshall

Jackson

et al. 2018

Energy Fuels

View full text Add to dashboard Cite

Reactions of water-washed chunks of a deeply buried Green River oil shale (2880–2920 ft, well below the water table) have been carried out in N2–H2O and CO–H2O for up to 28 days at temperatures in the range of 280–370 °C. Large variations in yields of liquid products were observed for reactions below 330–340 °C. These were attributed to varying mineralogy in the chunks because the variations disappeared for reactions of ground samples or reactions above 330–340 °C, at which point the chunks disintegrated. Liquid-product yields of up to 70 wt % dry mineral matter free could be obtained from the chunks at temperatures as low as 320 °C, provided that long reaction times of 14 or 28 days were used. In particular, at lower temperatures, yields were higher under N2 than under CO, but the quality of the CO–H2O petroleum or oil/gas products tended to be better than that of N2–H2O products. The liquid products contained 1–2 wt % nitrogen, were high in aliphatic material, and contained significant amounts of heavily substituted aromatic rings.

show abstract

Section: Resultsmentioning

confidence: 97%

Section: Resultsmentioning

confidence: 99%

Long-Time-Period, Low-Temperature Reactions of Green River Oil Shale

Marshall

Jackson

et al. 2018

Energy Fuels

View full text Add to dashboard Cite

show abstract

“…Numerical simulations and water–rock experiments indicate that dawsonite, NaAl(CO 3 )(OH) 2 , is one of the main CO 2 ‐trapping minerals that formed after the injection of CO 2 into sandstones (Burnham, Levchenko, & Herron, ; Li & Li, ; Okuyama, Todaka, Sasaki, Ajima, & Akasaka, ; Xu, Apps, & Pruess, , ; Zerai, Saylor, & Matisoff, ). Field observations indicate that the emergence of dawsonite is closely related to regional magmatic activities and tectonic faulting events (Golab, Carr, & Palamara, ; Liu, Liu, Yang, Gui, & Li, ; J. Moore, Adams, Allis, & Rauzic, ).…”

Section: Introductionmentioning

confidence: 99%

“…Sequestering CO 2 with stable carbonate minerals such as dawsonite has long been considered an effective technique (Gao, Liu, & Hu, 2009;Kharaka et al, 2006;Klusman, 2003;Liu et al, 2011a;Zhu et al, 2014). The authigenic mineral type of dawsonite-bearing sandstone has previously been investigated in various locations worldwide, including those of the Bowen-Gunnedah-Sydney Basin system (Baker, Bai, Hamilton, Golding, & Keene, 1995), the Yemen Basin (Worden, 2006), the Springerville-St. Johns Field (Moore et al, 2005), Upper Hunter Valley (Golab et al, 2006), Hailaer Basin (Gao, Liu, Qu, & Liu, 2008), Songliao Basin (Li, 2009;Li, Cao, Li, & Zhang, 2017a;Li, et al, 2017b), South of Osaka (Okuyama et al, 2011), and Piceance Basin (Burnham et al, 2015). Most regions above show relatively high geothermal gradients.…”

mentioning

confidence: 99%

Shengli Oilfield, China as a natural analogue of CO₂ storage: Diagenetic fluid evolution mode and potentials for carbon sequestration

2017

Geological Journal

View full text Add to dashboard Cite

The Shengli Oilfield is discussed to investigate CO2 trapping mechanisms involved in geothermal oil reservoir systems. Diagenetic fluid evolution of the dawsonite‐bearing sandstones from the Dongying Sag, Bohai Bay Basin, China, was studied to understand the CO2 migration and accumulation and the formation of dawsonite, as a possible mechanism for mineral trapping of CO2 in geothermal fields. Information about the petrology, dawsonite‐forming fluid, authigenic mineral associations, and diagenetic fluid evolution mode was analysed using techniques including thin‐section identification, scanning electron microscope observation, X‐ray diffraction analysis, X‐ray fluorescence spectrum analysis, hydrochemistry, and stable isotope analyses. The paragenetic sequence, from early to late, is early calcite (A)–compaction–dissolution–quartz overgrowth–late calcite (B1)–ferrocalcite (A)–dawsonite–late calcite (B2)–ferrocalcite (B)–ankerite–siderite or pyrite. The current in situ formation water type of the dawsonite‐bearing sandstone strata is NaHCO3, with the typical characteristics of weak alkaline, high mineralization, and high Na+ + K+ and HCO3− content. The formation fluid from which the dawsonite forms is mainly sealed underground brine, which has been affected by atmospheric precipitation and magmatic activity, and is thus mixed with surface meteoric water and subsurface hydrothermal fluid. The fluid evolution process sequence is alkaline fluid environment prior to CO2 influx, an early micritic or sparry calcite (A) association; acidic fluid environment after CO2 influx, a quartz overgrowth and kaolinite association; alkalescent fluid environment, an association of late calcite (B1), ferrocalcite (A), and illite; alkaline fluid environment, a dawsonite and late calcite (B2) association; and weak‐alkaline fluid environment, an association of ferrocalcite (B), ankerite, siderite, and pyrite.

show abstract