Evaluation of in-situ reservoir blocking by sodium carbonate gel formed from sodium metasilicate solution and injected CO2 for CO2 sequestration

Research output: Contribution to journalArticle

Abstract

Preventing channeling flows during enhanced oil recovery targeting heterogeneous or fracture type reservoirs and leakage flows from saline aquifers containing CO2 remains a challenge. This study evaluated the potential of in-situ gelation as a blocking agent in a heterogeneous reservoir using the reaction between aqueous solution of sodium metasilicate (Na2SiO3 · 9H2O; S–MS) and dissolved carbon dioxide (CO2). Both Raman and scanning electron microscopy/energy dispersive X-ray (SEM-EDS) spectroscopy revealed that the gel was a sodium carbonate type (S–C-gel). Physical characterization of the S–C-gel including the gelation time, gel strength and stability, were investigated in respect of S–MS concentration, temperature, salinity (NaCl), divalent ion concentration (calcium, Ca2+) as well as CO2 injection pressure. Gelation time after CO2 gas injection was around 1 to 24 h depending on temperature and pressure. Gel strength increased with higher S–MS concentration (≤ 10 wt%) and CO2 gas pressure (≤ 5.5 MPa). Threshold pressure gradient (TPG) and gas permeability of the sandstone core filled with in-situ gel increased by 2.6 times and decreased about 1/10, respectively, compared with the water saturated core. These promising findings herein could be extended to CO2 sequestration.
Original languageEnglish
Pages (from-to)309-318
Number of pages10
JournalJournal of the Japan Petroleum Institute
Volume62
Issue number6
DOIs
Publication statusPublished - Nov 1 2019

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carbon sequestration
Carbonates
Gels
gel
Sodium
sodium
carbonate
Gelation
gas
Gas permeability
enhanced oil recovery
Sandstone
Pressure gradient
Aquifers
pressure gradient
X-ray spectroscopy
targeting
leakage
in situ
evaluation

All Science Journal Classification (ASJC) codes

  • Geotechnical Engineering and Engineering Geology
  • Energy Engineering and Power Technology

Cite this

@article{e37f8d6893124898874e7f1b7ff44e16,
title = "Evaluation of in-situ reservoir blocking by sodium carbonate gel formed from sodium metasilicate solution and injected CO2 for CO2 sequestration",
abstract = "Preventing channeling flows during enhanced oil recovery targeting heterogeneous or fracture type reservoirs and leakage flows from saline aquifers containing CO2 remains a challenge. This study evaluated the potential of in-situ gelation as a blocking agent in a heterogeneous reservoir using the reaction between aqueous solution of sodium metasilicate (Na2SiO3 · 9H2O; S–MS) and dissolved carbon dioxide (CO2). Both Raman and scanning electron microscopy/energy dispersive X-ray (SEM-EDS) spectroscopy revealed that the gel was a sodium carbonate type (S–C-gel). Physical characterization of the S–C-gel including the gelation time, gel strength and stability, were investigated in respect of S–MS concentration, temperature, salinity (NaCl), divalent ion concentration (calcium, Ca2+) as well as CO2 injection pressure. Gelation time after CO2 gas injection was around 1 to 24 h depending on temperature and pressure. Gel strength increased with higher S–MS concentration (≤ 10 wt{\%}) and CO2 gas pressure (≤ 5.5 MPa). Threshold pressure gradient (TPG) and gas permeability of the sandstone core filled with in-situ gel increased by 2.6 times and decreased about 1/10, respectively, compared with the water saturated core. These promising findings herein could be extended to CO2 sequestration.",
author = "Samnean Chea and K. Sasaki and Ronald Nguele and Yuichi Sugai",
year = "2019",
month = "11",
day = "1",
doi = "10.1627/jpi.62.309",
language = "English",
volume = "62",
pages = "309--318",
journal = "Journal of the Japan Petroleum Institute",
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publisher = "Japan Petroleum Institute",
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TY - JOUR

T1 - Evaluation of in-situ reservoir blocking by sodium carbonate gel formed from sodium metasilicate solution and injected CO2 for CO2 sequestration

AU - Chea, Samnean

AU - Sasaki, K.

AU - Nguele, Ronald

AU - Sugai, Yuichi

PY - 2019/11/1

Y1 - 2019/11/1

N2 - Preventing channeling flows during enhanced oil recovery targeting heterogeneous or fracture type reservoirs and leakage flows from saline aquifers containing CO2 remains a challenge. This study evaluated the potential of in-situ gelation as a blocking agent in a heterogeneous reservoir using the reaction between aqueous solution of sodium metasilicate (Na2SiO3 · 9H2O; S–MS) and dissolved carbon dioxide (CO2). Both Raman and scanning electron microscopy/energy dispersive X-ray (SEM-EDS) spectroscopy revealed that the gel was a sodium carbonate type (S–C-gel). Physical characterization of the S–C-gel including the gelation time, gel strength and stability, were investigated in respect of S–MS concentration, temperature, salinity (NaCl), divalent ion concentration (calcium, Ca2+) as well as CO2 injection pressure. Gelation time after CO2 gas injection was around 1 to 24 h depending on temperature and pressure. Gel strength increased with higher S–MS concentration (≤ 10 wt%) and CO2 gas pressure (≤ 5.5 MPa). Threshold pressure gradient (TPG) and gas permeability of the sandstone core filled with in-situ gel increased by 2.6 times and decreased about 1/10, respectively, compared with the water saturated core. These promising findings herein could be extended to CO2 sequestration.

AB - Preventing channeling flows during enhanced oil recovery targeting heterogeneous or fracture type reservoirs and leakage flows from saline aquifers containing CO2 remains a challenge. This study evaluated the potential of in-situ gelation as a blocking agent in a heterogeneous reservoir using the reaction between aqueous solution of sodium metasilicate (Na2SiO3 · 9H2O; S–MS) and dissolved carbon dioxide (CO2). Both Raman and scanning electron microscopy/energy dispersive X-ray (SEM-EDS) spectroscopy revealed that the gel was a sodium carbonate type (S–C-gel). Physical characterization of the S–C-gel including the gelation time, gel strength and stability, were investigated in respect of S–MS concentration, temperature, salinity (NaCl), divalent ion concentration (calcium, Ca2+) as well as CO2 injection pressure. Gelation time after CO2 gas injection was around 1 to 24 h depending on temperature and pressure. Gel strength increased with higher S–MS concentration (≤ 10 wt%) and CO2 gas pressure (≤ 5.5 MPa). Threshold pressure gradient (TPG) and gas permeability of the sandstone core filled with in-situ gel increased by 2.6 times and decreased about 1/10, respectively, compared with the water saturated core. These promising findings herein could be extended to CO2 sequestration.

U2 - 10.1627/jpi.62.309

DO - 10.1627/jpi.62.309

M3 - Article

VL - 62

SP - 309

EP - 318

JO - Journal of the Japan Petroleum Institute

JF - Journal of the Japan Petroleum Institute

SN - 1346-8804

IS - 6

ER -