Carbon capture and storage (CCS) is broadly recognised as having the potential to play a key role in meeting climate change targets, delivering low carbon heat and power, decarbonising industry and, more recently, its ability to facilitate the net removal of CO2 from the atmosphere. However, despite this broad consensus and its technical maturity, CCS has not yet been deployed on a scale commensurate with the ambitions articulated a decade ago. Thus, in this paper we review the current state-of-the-art of CO2 capture, transport, utilisation and storage from a multi-scale perspective, moving from the global to molecular scales. In light of the COP21 commitments to limit warming to less than 2 °C, we extend the remit of this study to include the key negative emissions technologies (NETs) of bioenergy with CCS (BECCS), and direct air capture (DAC). Cognisant of the non-technical barriers to deploying CCS, we reflect on recent experience from the UK's CCS commercialisation programme and consider the commercial and political barriers to the large-scale deployment of CCS. In all areas, we focus on identifying and clearly articulating the key research challenges that could usefully be addressed in the coming decade.

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Carbon capture and storage (CCS): the way forward

https://cyberleninka.org/article/n/22310.pdf

Pore-scale imaging and modelling

In this paper, theoretical and experimental approaches to flow, hydrodynamic dispersion, and miscible and immiscible displacement processes in reservoir rocks are reviewed and discussed. Both macroscopically homogeneous and heterogeneous rocks are considered. The latter are characterized by large-scale spatial variations and correlations in their effective properties and include rocks that may be characterized by several distinct degrees of porosity, a well-known example of which is a fractured rock with two degrees of porosity---those of the pores and of the fractures. First, the diagenetic processes that give rise to the present reservoir rocks are discussed and a few geometrical models of such processes are described. Then, measurement and characterization of important properties, such as pore-size distribution, pore-space topology, and pore surface roughness, and morphological properties of fracture networks are discussed. It is shown that fractal and percolation concepts play important roles in the characterization of rocks, from the smallest length scale at the pore level to the largest length scales at the fracture and fault scales. Next, various structural models of homogeneous and heterogeneous rock are discussed, and theoretical and computer simulation approaches to flow, dispersion, and displacement in such systems are reviewed. Two different modeling approaches to these phenomena are compared. The first approach is based on the classical equations of transport supplemented with constitutive equations describing the transport and other important coefficients and parameters. These are called the continuum models. The second approach is based on network models of pore space and fractured rocks; it models the phenomena at the smallest scale, a pore or fracture, and then employs large-scale simulation and modern concepts of the statistical physics of disordered systems, such as scaling and universality, to obtain the macroscopic properties of the system. The fundamental roles of the interconnectivity of the rock and its wetting properties in dispersion and two-phase flows, and those of microscopic and macroscopic heterogeneities in miscible displacements are emphasized. Two important conceptual advances for modeling fractured rocks and studying flow phenomena in porous media are also discussed. The first, based on cellular automata, can in principle be used for computing macroscopic properties of flow phenomena in any porous medium, regardless of the complexity of its structure. The second, simulated annealing, borrowed from optimization processes and the statistical mechanics of spin glasses, is used for finding the optimum structure of a fractured reservoir that honors a limited amount of experimental data.

Flow phenomena in rocks : from continuum models to fractals, percolation, cellular automata, and simulated annealing

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Recent Advances in Surfactant EOR

[1] We report the results of an experimental investigation into the multiphase flow properties of CO2 and water in four distinct sandstone rocks: a Berea sandstone and three reservoir rocks from formations into which CO2 injection is either currently taking place or is planned. Drainage relative permeability and residual gas saturations were measured at 50 � C and 9 MPa pore pressure using the steady state method in a horizontal core flooding apparatus with fluid distributions observed using x-ray computed tomography. Absolute permeability, capillary pressure curves, and petrological studies were performed on each sample. Relative permeability in the four samples is consistent with general characteristics of drainage in strongly water-wet rocks. Measurements in the Berea sample are also consistent with past measurements in Berea sandstones using both CO2/brine and oil/water fluid systems. Maximum observed saturations and permeabilities are limited by the capillary pressure that can be achieved in the experiment and do not represent endpoint values. It is likely that maximum saturations observed in other studies are limited in the same way and there is no indication that low endpoint relative permeabilities are a characteristic of the CO2/water system. Residual trapping in three of the rocks is consistent with trapping in strongly water-wet systems, and the results from the Berea sample are again consistent with observations in past studies. This confirms that residual trapping can play a major role in the immobilization of CO2 injected into the subsurface. In the Mt. Simon sandstone, a nonmonotonic relationship between initial and residual CO2 saturations is indicative of a rock that is mixed or intermediate wet, and further investigations should be performed to establish the wetting properties of illite-rich rocks. The combined results suggest that the petrophysical properties of the multiphase flow of CO2/water through siliciclastic rocks is for the most part typical of a strongly water-wet system and that analog fluids and conditions may be used to characterize these properties. Further investigation is required to identify the wetting properties of illite-rich rocks during imbibition processes.

https://agupubs.onlinelibrary.wiley.com/doi/pdf/10.1029/2011WR010859

Relative permeability and trapping of CO2 and water in sandstone rocks at reservoir conditions

Interfacial tension measurements and wettability evaluation for geological CO2 storage

Although there are a number of mathematical modeling studies for carbon dioxide (CO2) injection into aquifer formations, experimental studies are limited and most studies focus on injection into sandstone reservoirs as opposed to carbonate ones. This study presents the results of computerized tomography (CT) monitored laboratory experiments to analyze permeability and porosity changes as well as to characterize relevant chemical reactions associated with injection and storage of CO2 in carbonate formations. CT monitored experiments are designed to model fast near well bore flow and slow reservoir flows. Highly heterogeneous cores drilled from a carbonate aquifer formation located in South East Turkey were used during the experiments. Porosity changes along the core plugs and the corresponding permeability changes are reported for different CO2 injection rates and different salt concentrations of formation water. It was observed that either a permeability increase or a permeability reduction can be obtained. The trend of change in rock properties is very case dependent because it is related to distribution of pores, brine composition and thermodynamic conditions. As the salt concentration decreases, porosity and the permeability decreases are less pronounced. Calcite deposition is mainly influenced by orientation, with horizontal flow resulting in larger calcite deposition compared to vertical flow.

CO2 injection into saline carbonate aquifer formations I: laboratory investigation

Oil Recovery by Low-Salinity Brine Injection: Laboratory Results on Outcrop and Reservoir Cores

Foamed-gas injection is a promising technique for achieving mobility control and diverting fluid to low permeability strata within heterogeneous porous media. However, the factors most important for diversion have not been stated and explored definitively. Gas mobility in the presence of foam depends critically on foam-bubble size; bubble size may vary with permeability, porosity, surfactant type and concentration, and the velocity of liquid and gas. This paper adopts a local equilibrium, scaling perspective to describe quantitatively foamed-gas mobility within heterogeneous porous media. Conventional and percolation network scaling ideas are employed. A new closed form expression for the fraction of mobile gas within a foam is derived using statistical network concepts. Additional equations indicate, for instance, that porosity plays an important role in setting gas mobility because it reflects the relative abundance of foam germination and termination sites per unit volume of porous media. Liquid velocity is also important because gas mobility is inversely proportional to this factor.

Foam Mobility in Heterogeneous Porous Media

It's now largely agreed from laboratory and field tests results that brine composition and ionic strength can influence oil recovery (Jadhunandan and Morrow, 1991; Jadhunandan and Morrow, 1995). Morrow et al. in the 90's first carried out a large study on the ability of low salinity waterflooding to become an EOR method (Yildiz and Morrow, 1996; Tang and Morrow, 1999). More recently BP, carried out a large program on low salinity injection and proposed additional recovery mechanisms (Mc Guire and Chatham, 2005; Lager et al. 2006). Although there is substantial evidence of this phenomenon, the physical causes are still uncertain and several possible recovery mechanisms have been put forward in the literature: clay release, wettability alteration, IFT modification, key role of kaolinite etc. In this paper, we present experiments dealing with tertiary and secondary recovery tests performed on an outcrop sandstone containing 9.2% of clays without kaolinite. Each experiment is performed following a three step procedure during which pressure drop, pH, brine composition and oil recovery are monitored. First, the core is saturated with a high salinity brine at ambient temperature until equilibrium is reached (pressure drop and pH are constant and ion exchange is achieved). Second, the initial water saturation is established using a crude oil. Finally, after ageing, high salinity brine waterflooding followed by low salinity brines in the case of tertiary experiment or direct low salinity brines flooding in the case of secondary recovery are performed. Additional oil recovery of about 10% of original oil in place is observed in tertiary experiments when going from 50g/l to 1g/l brine. This oil production occurs after 2 or 3 pore volumes in the form of an oil bank displacement, suggesting a more dispersive behavior of the matrix in the presence of oil. It is worth noting that this additional oil recovery has been obtained in a clayey sandstone that does not contain kaolinite. When low salinity brine was injected, both pH and pressure drop increased. Successive dilutions of injection brine from high salinity did not lead to an oil recovery increase until using 1g/l, showing a salinity concentration threshold, whereas pressure drop and pH were increasing significantly at each salinity dilution. Waterflooding at different temperatures shows that oil recovery in secondary mode increases with increasing displacement temperature. But additional oil recovery in tertiary mode is more positive for moderate temperatures.

Henri Bertin

Papers

Interfacial tension measurements and wettability evaluation for geological CO2 storage

CO2 injection into saline carbonate aquifer formations I: laboratory investigation

Oil Recovery by Low-Salinity Brine Injection: Laboratory Results on Outcrop and Reservoir Cores

Foam Mobility in Heterogeneous Porous Media

Low Salinity Oil Recovery On Clayey Sandstone: Experimental Study