scholarly journals Impacts of relative permeability formulation on forecasts of CO2 phase behavior, phase distribution, and trapping mechanisms in a geologic carbon storage reservoir

2017 ◽  
Vol 7 (5) ◽  
pp. 958-962 ◽  
Author(s):  
Nathan Moodie ◽  
Feng Pan ◽  
Wei Jia ◽  
Brian McPherson
Keyword(s):  
Phase Behavior ◽  
Carbon Storage ◽  
Relative Permeability ◽  
Phase Distribution ◽  
Geologic Carbon Storage ◽  
Storage Reservoir

A New Method To Model Relative Permeability in Compositional Simulators To Avoid Discontinuous Changes Caused by Phase-Identification Problems

SPE Journal ◽  
2012 ◽  
Vol 17 (04) ◽  
pp. 1221-1230 ◽  
Author(s):  
Chengwu Yuan ◽  
Gary A. Pope
Keyword(s):  
Free Energy ◽  
Phase Behavior ◽  
Gibbs Free Energy ◽  
Relative Permeability ◽  
Phase Distribution ◽  
Local Equilibrium ◽  
Difficult Problem ◽  
Phase Identification ◽  
Permeability Model ◽  
Molar Gibbs Free Energy

Summary Simple methods, such as the use of density during compositional simulations, often fail to identify the phases correctly, and this can cause discontinuities in the computed relative permeability values. The results are then physically incorrect. Furthermore, numerical simulators often slow down or even stop because of discontinuities. There are many important applications in which the phase behavior can be single phase, gas/liquid, liquid/liquid, gas/ liquid/liquid, or gas/liquid/solid at different times in different gridblocks. Assigning physically correct phase identities during a compositional simulation turns out to be a difficult problem that has resisted a general solution for decades. We know that the intensive thermodynamic properties, such as molar Gibbs free energy, must be continuous, assuming local equilibrium, but this condition is difficult to impose in numerical simulators because of the discrete nature of the calculations. An alternative approach is to develop a relative permeability model that is continuous and independent of the phase numbers assigned by the flash calculation. Relative permeability is a function of saturation, but also composition, because composition affects the phase distribution in the pores (i.e., the wettability). The equilibrium distribution of fluids in pores corresponds to the minimum in the Gibbs free energy for the entire fluid/rock system, including interfaces. In general, however, this relationship is difficult to model from first principles. What we can easily do is calculate the molar Gibbs free energy (G) of each phase at reference compositions where the relative permeabilities are known or assumed to be known and then interpolate between these values by use of the G calculated during each timestep of the simulation. Relative permeability values calculated this way are unconditionally continuous for all possible phase-behavior changes, including even critical points. We tested the new relative permeability model on a variety of extremely difficult simulation problems with up to four phases, and it has not failed yet. We illustrate several of these applications.

scholarly journals Recommended Practices for Managing Induced Seismicity Risk Associated with Geologic Carbon Storage

2021 ◽  
Author(s):  
Dennise Templeton ◽  
Martin Schoenball ◽  
Corinne Layland-Bachmann ◽  
William Foxall ◽  
Yves Guglielmi ◽  
...  
Keyword(s):  
Carbon Storage ◽  
Induced Seismicity ◽  
Geologic Carbon Storage ◽  
Recommended Practices

scholarly journals Carbon Storage and Enhanced Oil Recovery in Pennsylvanian Morrow Formation Clastic Reservoirs: Controls on Oil–Brine and Oil–CO2 Relative Permeability from Diagenetic Heterogeneity and Evolving Wettability

Energies ◽  
2019 ◽  
Vol 12 (19) ◽  
pp. 3663
Author(s):  
Lindsey Rasmussen ◽  
Tianguang Fan ◽  
Alex Rinehart ◽  
Andrew Luhmann ◽  
William Ampomah ◽  
...  
Keyword(s):  
Carbon Storage ◽  
Enhanced Oil Recovery ◽  
Relative Permeability ◽  
Oil Recovery ◽  
Flow Behavior ◽  
Flow Unit ◽  
Water Production ◽  
Intergranular Porosity ◽  
Diagenetic Processes ◽  
Pore Types

The efficiency of carbon utilization and storage within the Pennsylvanian Morrow B sandstone, Farnsworth Unit, Texas, is dependent on three-phase oil, brine, and CO2 flow behavior, as well as spatial distributions of reservoir properties and wettability. We show that end member two-phase flow properties, with binary pairs of oil–brine and oil–CO2, are directly dependent on heterogeneity derived from diagenetic processes, and evolve progressively with exposure to CO2 and changing wettability. Morrow B sandstone lithofacies exhibit a range of diagenetic processes, which produce variations in pore types and structures, quantified at the core plug scale using X-ray micro computed tomography imaging and optical petrography. Permeability and porosity relationships in the reservoir permit the classification of sedimentologic and diagenetic heterogeneity into five distinct hydraulic flow units, with characteristic pore types including: macroporosity with little to no clay filling intergranular pores; microporous authigenic clay-dominated regions in which intergranular porosity is filled with clay; and carbonate–cement dominated regions with little intergranular porosity. Steady-state oil–brine and oil–CO2 co-injection experiments using reservoir-extracted oil and brine show that differences in relative permeability persist between flow unit core plugs with near-constant porosity, attributable to contrasts in and the spatial arrangement of diagenetic pore types. Core plugs “aged” by exposure to reservoir oil over time exhibit wettability closer to suspected in situ reservoir conditions, compared to “cleaned” core plugs. Together with contact angle measurements, these results suggest that reservoir wettability is transient and modified quickly by oil recovery and carbon storage operations. Reservoir simulation results for enhanced oil recovery, using a five-spot pattern and water-alternating-with-gas injection history at Farnsworth, compare models for cumulative oil and water production using both a single relative permeability determined from history matching, and flow unit-dependent relative permeability determined from experiments herein. Both match cumulative oil production of the field to a satisfactory degree but underestimate historical cumulative water production. Differences in modeled versus observed water production are interpreted in terms of evolving wettability, which we argue is due to the increasing presence of fast paths (flow pathways with connected higher permeability) as the reservoir becomes increasingly water-wet. The control of such fast-paths is thus critical for efficient carbon storage and sweep efficiency for CO2-enhanced oil recovery in heterogeneous reservoirs.

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