Simulating Oil Recovery During CO&lt;sub&gt;2&lt;/sub&gt; Sequestration Into a Mature Oil Reservoir

Pamukcu, Yusuf; Gümrah, F.

doi:10.2118/2007-017

Cited by 6 publications

(6 citation statements)

References 12 publications

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“…This can be ascribed to poor pressure dissipation over the relatively short injection time scale, causing near-well congestion that hampers subsequent injectivity [41][42] . This can be ascribed to poor pressure dissipation over the relatively short injection time scale, causing near-well congestion that hampers subsequent injectivity [41][42] .…”

Section: Closed Systemmentioning

confidence: 99%

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An Improved Estimation of the Storage Capacity of Potential Geologic Carbon-Sequestration Sites

Lawal¹

2011

All Days

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The ideas of open and closed-boundary systems are explored to investigate the technical limits of storage capacity of subsurface porous media, as required for the CO2-mitigation technology of carbon capture and storage (CCS). In particular, the effects of reservoir characteristics as well as the nature and mix of fluids that originally saturate the porous media are elucidated. An improved analytic method, premised on the concept of in-situ fluid displacement and replacement, of estimating the storage capacity of open systems is proposed and evaluated.For closed systems, our analyses show that the general order of attractiveness (technical storage capacity) of potential sites is aquifer < water-depleted oil < undepleted oil < gas-depleted oil < depleted gas < undepleted gas formations. However, owing to the complexity of microscopic and macroscopic events, similar simple conclusion can not be drawn on the relative attractiveness of various open-boundary sinks.As a case study, we examine the applicability of CCS in Nigeria. From first-order estimates of the pore volumes and other reservoir-fluid properties in Nigeria, we quantify the limits and time-scale of "available" geologic sinks to accommodate current and future loads of anthropogenic CO2 emissions from the Nigerian fossil-fired power sources.Due to the relatively poor storage capacity of the potential sites compared to the anticipated CO2 load from power plants, which is just one of the CO2 sources, sequestration into underground formations may not, on its own, be a sustainable technical solution for Nigeria. Additionally, for the open systems, which define the upper limits of storage capacity, the potential challenges of managing displaced formation brine (and other less valuable fluids) may be overwhelming. As a complement, we offer some potential outlets for CO2 generated from these captive and other sources. Finally, long-term carbon-mitigation strategies hinged on mixed solutions are enumerated.

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Section: Closed Systemmentioning

confidence: 99%

“…According to Pamukcu and Gumrah 42 , the rate of CO2 emissions from a typical 500 MW power plant is about 5 million tonnes per annum. Using this rate and the 20 GW capacity, the average CO2 load from the Nigerian power industry is roughly 200 Mtons/year.…”

Section: Applicability Of Ccs To Nigerian Power Sectormentioning

confidence: 99%

An Improved Estimation of the Storage Capacity of Potential Geologic Carbon-Sequestration Sites

Lawal¹

2011

All Days

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“…The main goal of utilization processes such as EOR and EGR is production of more hydrocarbons from oil and gas reservoirs (Baines and Worden 2004;Moberg 2001;Monger et al 1991;Holm and Josendal 1974). Storage and sequestration of CO 2 are recently considered in these processes (Pamukcu and Gumrah 2008). In purely storage options, CO 2 is injected without any direct financial benefits, e.g., saline aquifers, although carbon tax credits may improve the financial viability of this option.…”

Section: Nomenclature Amentioning

confidence: 99%

“…CO 2 is usually injected into oil reservoirs at pressures higher than or close to minimum miscibility pressure (MMP) (Sohrabi et al 2008) for the purpose of EOR and recently CO 2 storage/sequestration (Pamukcu and Gumrah 2008;Gozalpour et al 2005). At pressures above MMP, injected CO 2 and oil mix properly to make a system that is close to single-phase flow (Javadpour and Fisher 2008).…”

Section: Co 2 Injection In Oil Reservoirsmentioning

confidence: 99%

CO2 Injection in Geological Formations: Determining Macroscale Coefficients from Pore Scale Processes

Javadpour

2008

Transp Porous Med

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Carbon dioxide (CO 2 ) injections in geological formations are usually performed for enhanced hydrocarbon recovery in oil and gas reservoirs and storage and sequestration in saline aquifers. Once CO 2 is injected into the formation, it propagates in the porous rock by dispersion and convection. Chemical reactions between brine ions and CO 2 molecules and consequent reactions with mineral grains are also important processes. The dynamics of CO 2 molecules in random porous media are modeled with a set of differential equations corresponding to pore scale and continuum macroscale. On the pore scale, convectivedispersive equation is solved considering reactions on the inner boundaries in a unit cell. A unit cell is the smallest portion of a porous media that can reproduce the porous media by repetition. Inner boundaries in a unit cell are the surfaces of the mineral grains. Dispersion process at the pore scale is transformed into continuum macroscale by adopting periodic boundary conditions for contiguous unit cells and applying Taylor-Aris dispersion theory known as macrotransport theory. Using this theory, the discrete porous system changes into a continuum system within which the propagation and interaction of CO 2 molecules with fluid and solid matrix of the porous media are characterized by three position-independent macroscopic coefficients: the mean velocity vectorŪ * , dispersivity dyadicD * , and mean volumetric CO 2 depletion coefficientK * . 123 88 F. Javadpour Nomenclature A A-function (cf. Eq. 19) B B-field (cf. Eq. 23) C Concentration, mol m −3 D Dispersivity dyadic, m 2 s −1 DMolecular diffusion coefficient, m 2 s −1 D g Diameter of a mineral grain, m D x Macrotransport dispersivity coefficient in x-direction, m 2 s −1 D * Macrotransport dispersivity dyadic coefficient, m 2 s −1 J ∞ 0 Asymptotic probability flux density, m −2 s −1 K Permeability tensor, m 2 K * Macroscale depletion rate, or mean volumetric CO 2 sequestration coefficient, s −1 K x Macrotransport depletion rate coefficient in x-direction, s −1 lBasic lattice vectors, m l Unit cell length, m L Length of porous bed, m p Pressure, kPa P ∞ 0 Steady state conditional probability density, fraction r Radial vector, m R Macroscale position vector, m R n Discrete position vector specifying the location of the nth unit cell, m s Ratio of reactive surface to the interstitial space volume, m −1 (m 2 m −3 ) s g

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“…CO 2 injection has emerged as an important method for enhancing oil recovery. Experimental tests and simulations have been undertaken to evaluate the improvement of recovery by CO 2 injections. − In the context of the shale oil and gas field, CO 2 can be used to stimulate the development of shale oil and gas via adsorption and replacement processes. Researchers have carried out experimental and dynamic simulation studies on CO 2 -enhanced recovery in shale formations. , These experimental analysis included mechanical characterization, modification in pore-throat structures, alterations in mineral content, changes in adsorption–desorption, and variations in pore and permeability levels. − Existing experimental studies conducted under conventional temperature and pressure settings have found that the interaction between CO 2 and reservoir rocks considerably influences the rock properties.…”

Section: Introductionmentioning

confidence: 99%

Study on the Influence of Supercritical CO₂ with High Temperature and Pressure on Pore-Throat Structure and Minerals of Shale

Wang,

Sun,

Guo

et al. 2024

ACS Omega

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Injection of carbon dioxide offers substantial social and economic advantages for reduction of carbon emission reduction. Utilizing CO 2 in shale formations can significantly enhance the extraction of shale oil or gas. Conducting fundamental research on how CO 2 affects shale rock's physical properties is crucial for enhancing its porosity and permeability. Particularly for deep shale layers, the effects of supercritical CO 2 on shale physical properties should be investigated at a high temperature and pressure, differing from the standard conditions applied in shallower layers. A study examined the impact of supercritical CO 2 under such conditions on the pore-throat structure and mineral composition of the shale. The experimental parameters included immersing shale rock in supercritical CO 2 at pressures ranging from 10 to 70 MPa and temperatures between 55 and 95 °C. This study evaluated changes in mineral composition, pore-throat structure (using scanning electron microscopy and nitrogen adsorption tests), and the porosity and permeability of the shale rocks. Findings indicated that the dissolution of CO 2 altered the relative content of certain minerals. The average quartz content rose and, potassium feldspar and the average contents of plagioclase declined conversely. When increasing the pressure, an increase in the relative content of I/S mixed layer and a decrease in illite content were observed and kaolinite content experienced minor changes. When increasing the temperature, kaolinite, I/S mixed layer, and chlorite all exhibited a decreasing trend with increasing temperature, while the relative contents of illite increased. Some of the pores become rounded in a high-magnification view under the impact of CO 2 dissolution. Additionally, the Brunauer−Emmett−Teller specific surface area, pore volume, porosity, and permeability generally improved with increasing pressure and temperature. With the temperature and pressure of CO 2 increased, the curves of nitrogen absorption had moved first upward and then downward. However, under specific CO 2 conditions, the permeability enhancement effect could diminish or even negatively impact the shale's permeability. These findings underscore the need to optimize supercritical CO 2 injection parameters under high-temperature and high-pressure conditions. This research aims to provide theoretical guidance for the efficient use of CO 2 in deep shale applications to increase the shale gas output.

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Simulating Oil Recovery During CO<sub>2</sub> Sequestration Into a Mature Oil Reservoir

Cited by 6 publications

References 12 publications

An Improved Estimation of the Storage Capacity of Potential Geologic Carbon-Sequestration Sites

An Improved Estimation of the Storage Capacity of Potential Geologic Carbon-Sequestration Sites

CO2 Injection in Geological Formations: Determining Macroscale Coefficients from Pore Scale Processes

Study on the Influence of Supercritical CO₂ with High Temperature and Pressure on Pore-Throat Structure and Minerals of Shale

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Simulating Oil Recovery During CO<sub>2</sub> Sequestration Into a Mature Oil Reservoir

Cited by 6 publications

References 12 publications

An Improved Estimation of the Storage Capacity of Potential Geologic Carbon-Sequestration Sites

An Improved Estimation of the Storage Capacity of Potential Geologic Carbon-Sequestration Sites

CO2 Injection in Geological Formations: Determining Macroscale Coefficients from Pore Scale Processes

Study on the Influence of Supercritical CO2 with High Temperature and Pressure on Pore-Throat Structure and Minerals of Shale

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Study on the Influence of Supercritical CO₂ with High Temperature and Pressure on Pore-Throat Structure and Minerals of Shale