CO 2  breakthrough pressure and permeability for unsaturated low-permeability sandstone of the Ordos Basin

Zhao, Yan; Yu, Qingchun

doi:10.1016/j.jhydrol.2017.04.050

Cited by 41 publications

(25 citation statements)

References 38 publications

Supporting

Mentioning

Contrasting

Order By: Relevance

“…To determine the range of absolute permeability and breakthrough pressure of CO 2 hydrate-bearing sediments, further experimental studies are required. Hollow circles represent F110 sand, kaolinite clay, and montmorillonite clay [42], hollow diamonds represent low-permeability sandstone cores [43], and hollow triangle represents shale [44]. The vertical and horizontal bars indicate the range of the measured values.…”

Section: Comparison With Other Materialsmentioning

confidence: 99%

Experimental Simulation of the Self-Trapping Mechanism for CO2 Sequestration into Marine Sediments

Kim

Cho

2019

Minerals

View full text Add to dashboard Cite

CO2 hydrates are ice-like solid lattice compounds composed of hydrogen-bonded cages of water molecules that encapsulate guest CO2 molecules. The formation of CO2 hydrates in unconsolidated sediments significantly decreases their permeability and increases their stiffness. CO2 hydrate-bearing sediments can, therefore, act as cap-rocks and prevent CO2 leakage from a CO2-stored layer. In this study, we conducted an experimental simulation of CO2 geological storage into marine unconsolidated sediments. CO2 hydrates formed during the CO2 liquid injection process and prevented any upward flow of CO2. Temperature, pressure, P-wave velocity, and electrical resistance were measured during the experiment, and their measurement results verified the occurrence of the self-trapping effect induced by CO2 hydrate formation. Several analyses using the experimental results revealed that CO2 hydrate bearing-sediments have a considerable sealing capacity. Minimum breakthrough pressure and maximum absolute permeability are estimated to be 0.71 MPa and 5.55 × 10−4 darcys, respectively.

show abstract

Section: Comparison With Other Materialsmentioning

confidence: 99%

Experimental Simulation of the Self-Trapping Mechanism for CO2 Sequestration into Marine Sediments

Kim

Cho

2019

Minerals

View full text Add to dashboard Cite

show abstract

“…Based on the stable upstream pressure ( P 1 , MPa), downstream pressure ( P 2 , MPa) and volumetric flow rate of the gas ( Q g , m 3 /s), the gas permeability ( k g , m 2 ) was obtained from the following expression (Zhao & Yu, 2017):

k_{g} = \frac{2 Q_{g} μ_{g} {LP}_{a} Z}{A ()(, P_{1}^{2} - P_{2}^{2}) Z_{a}}

where P a is the standard atmospheric pressure (Pa), μ g is the gas dynamic viscosity (Pa·s) under the experimental conditions, Z is the compressibility factor under the experimental conditions, Z a is the compressibility factor at the experimental temperature and P a , and L and A are the length (m) and cross‐sectional area (m 2 ) of the core, respectively.…”

Section: Methodsmentioning

confidence: 99%

“…Based on the stable upstream pressure (P 1 , MPa), downstream pressure (P 2 , MPa) and volumetric flow rate of the gas (Q g , m 3 /s), the gas permeability (k g , m 2 ) was obtained from the following expression (Zhao & Yu, 2017):…”

Section: Water Resources Researchmentioning

confidence: 99%

Experimental Investigation on the Movability of Water in Shale Nanopores: A Case Study of Carboniferous Shale From the Qaidam Basin, China

Yang

2020

Water Resources Research

Self Cite

View full text Add to dashboard Cite

The movability of water in shale nanopores intensely affects the transport and storage of other fluids and plays an important role in the geological water cycle. To investigate the movability of water, three shale samples were used to conduct flow experiments using the steady state and step‐by‐step depressurization method. The experimental results show that the movability of water strongly depends on the pressure gradient. Two water‐related mechanisms, shear fluidity and electroviscous effect, are primarily responsible for the difference in movability between free water and bound water. The flow of water in these samples deviates from Darcy's law, and the threshold pressure gradient (TPG) is observed. When the pressure gradient is higher than the TPG, water starts to flow, and the permeability increases with increasing pressure gradient. Based on the analysis of the solid‐liquid interfacial forces, the water in the shale was quantitatively classified into four types (L1, L2, L3, and L4) according to its movability. The calculation results indicate that most of the water, which could be up to 74.46–89.73%, is immovable under the experimental conditions. The proportion of movable water increases with increasing pressure gradient, and the relation can be expressed by a quadratic function. The moving ratio was defined as the ratio of the volume of water involved in flow to the total pore volume. The correlation between the moving ratio and permeability is a power function with exponents ranging from 1.16 to 1.43, indicating that water permeability is sensitive to the moving ratio.

show abstract

“…The LPA data of CO 2 and N 2 and the MICP data were employed to determine the micropore, mesopore, and macropore size distributions, respectively. 39,40 In addition, the porosity (ϕ 1 ) of the samples could be approximately calculated by the combination of LPA and MICP experiments. The resulting PSDs are summarized in Table 3 and shown in Figure 3.…”

Section: Methodsmentioning

confidence: 99%

Experimental Investigation of Spontaneous Water Imbibition into Methane-Saturated Shales under Different Methane Pressures

Zan

2020

Energy Fuels

Self Cite

View full text Add to dashboard Cite

Spontaneous imbibition of hydraulic fracturing fluids is an important mechanism for the development of shale gas reservoirs. Spontaneous imbibition experiments have been widely performed under standard atmospheric pressure conditions, while the study of spontaneous imbibition under high-pressure conditions is rare. In this work, a new experimental approach was developed to perform a series of spontaneous water imbibition experiments on methane-saturated shale samples under different methane pressures (0.1, 1, and 5 MPa). The results indicate that the imbibition rate and imbibed volume decrease with increasing methane pressure. The shale capillary pressure is calculated under different methane pressures. The capillary pressure decreases rapidly with increasing methane pressure up to 1 MPa and then decreases further, but with a smaller slope. A logarithmic relationship between the capillary and methane pressures is discussed. In addition, it is also found that the water saturation behind the imbibition front tends to decrease with the methane pressure.

show abstract

CO 2 breakthrough pressure and permeability for unsaturated low-permeability sandstone of the Ordos Basin

Cited by 41 publications

References 38 publications

Experimental Simulation of the Self-Trapping Mechanism for CO2 Sequestration into Marine Sediments

Experimental Simulation of the Self-Trapping Mechanism for CO2 Sequestration into Marine Sediments

Experimental Investigation on the Movability of Water in Shale Nanopores: A Case Study of Carboniferous Shale From the Qaidam Basin, China

Experimental Investigation of Spontaneous Water Imbibition into Methane-Saturated Shales under Different Methane Pressures

Contact Info

Product

Resources

About