The Role Of Geological Storage

Published Date: 02 Nov 2017

In contrast with natural sinks which capture CO2 from atmosphere after it has been released, CCS is an industrial process that is made up of separating and capturing CO2 from large anthropogenic sources (e.g., power plants, cement plant, refineries, etc.), transporting CO2 to appropriate storage sites, and sequestering CO2 from the atmosphere for long periods of time, in the order of centuries to millions of years. Three means of CCS have been considered to date: surface mineral carbonation, ocean storage and geological storage [21]. The former method is converting CO2 to solid inorganic carbonates through chemical reactions, which could be thought as an accelerated process similar to natural weathering. First, this mean is up to the existence and availability of specific minerals like magnesium and calcium, and those certain minerals should be on a large scale. Meanwhile, large amounts of energy are required for crushing the mineral and heating for accelerating the chemical process. Finally, it requires transportation capacity and storage space of the large amounts of produced carbonate rocks from this process. This process would require 1.6–3.7 ton of mineral and produce 2.6–4.7 ton of carbonate rock to be disposed for each ton of stored CO2 [21]. The limitation of rocks availability for mineral carbonation, the high energy requirement, the uncertain environmental impact of the solid product, and the high cost of this technology exclude it from consideration for large-scale implementation, at least for the moment. Ocean storage of CO2 consists of injecting CO2 at great depths where it will dissolve or will form hydrates or heavier-than-water plumes that will sink at the bottom of the ocean [22], thus removing the injected CO2 from the atmosphere for several hundred years [21]. The foundation of this method is to accelerate the transfer of CO2 from the atmosphere to the deep ocean, a process that occurs naturally at an estimated rate of 2GtC/yr and that will lead anyway to the transfer of CO2 to the oceans over a 1000-year period [23]. However, ocean storage involves several key issues, such as poor understanding of physical and chemical processes, storage efficiency, cost, technical feasibility and environmental impact, at the same time, the technology of injection of CO2 from either ships or deep pipelines is still in the development stage. Injection of only a few Gt CO2 would produce a measurable change in ocean chemistry (pH) in the injection region, whereas injection of hundreds of Gt CO2 would eventually produce measurable changes over the entire ocean volume, with corresponding consequences on marine life [21,24]. In addition, ocean circulation may bring to the fore legal, political and international limitations to ocean storage of CO2. Thus, CO2 ocean storage is one potential option.

In contrast with surface mineral carbonation and ocean storage, currently, the geological storage of CO2 represents the best and likely the only short-to-medium term option for significantly reduction of CO2 emissions into the atmosphere. The technology of carbon capture and geological storage (CCGS) is the capture of CO2 directly from anthropogenic stationary sources (e.g., power plants, cement plant, refineries, etc.) and its disposal in geological formation, either permanently (sequestration) or for significant time periods (storage). This technology could be applied immediately as a result of the experience gained in other industries, particularly in oil and gas exploration and production, natural gas storage and deep disposal of liquid wastes and acid gas. Furthermore, the capacity for CO2 storage in geological media is significant, although unevenly distributed around the globe, and the likely retention time is more than adequate, being in the order of millennia to millions of years [21]. As a result of advantages listed above, recently, CO2 geological storage is being actively practiced in North America, northern Europe and some other countries as a promising technology that contributes to the stability and security of national energy systems by making the continued use of coal and natural gas as energy sources for power generation possible.

Desirable geological characteristics of storage site

The storage of CO2 in geological formation has a lot of similar characters with oil and gas trapping in hydrocarbon reservoirs and with CH4 in coal beds. From a technological perspective, there is extensive experience, especially in the oil and gas field. Meanwhile, geophysical data for the detection of the subsurface fluids other than water (i.e., oil and gas) has been collected for a long time in oil and gas exploration as well.

Thus, based on widely experience accumulated in oil and gas industry, when evaluate a CO2 geological storage technically feasible, three elements are considered to be essential:

The geological media must have sufficient pore volume to store the gas (capacity).

An overlying seal layer must be present to guarantee CO2 could be trapped in the reservoir (containment).

The formation characteristics must be such that sufficient injection of CO2 from the wellbore is possible (injectivity).

Different reservoirs have various formation characteristics, thus, specific solutions are generally required to solve site-specific issues. Basically, it is willing to store CO2 at depths below about 800m where CO2 is changed into a super-critical phase or a dense phase because of the high pressure. Storing CO2 as dense phase could enhance not only the storage capacity but the containment ability (by reducing fluid mobility). In this context, the ideal geological characteristics for listed factors are described below. [修改完毕]

Capacity:

The definition of the pore volume available for storage depends primarily on five parameters: thickness of reservoir, area of storage site, rock porosity, the density of CO2 and storage efficiency.

In this case, storage efficiency refers to the proportion of pore volume actually saturated by CO2. In general, CO2 does not totally displace the pore-filled saline fluid (brine). For a given storage site, storage efficiency remains relatively constant while the rest parameters could vary significantly. Porosity is a key parameter, which determines how the pore volume is distributed in the rock. Generally, values of porosity are desirable when the figure is greater than 10% in carbonate formations or 15% in clastic formations.(source) Injectivity is decided by permeability as well, which is closely related to porosity (Figure 1.2). Normally the better the porosity, the better the permeability (and thus injectivity).

Sufficient thickness of storage site is also necessary for a successful injection. Normally, a reservoir thickness of about 20 meters would be regarded as a minimum requirement, but this depends on injection volume requirements.

Figure 1.2: Core Porosity versus Core Permeability measurements – indicating an inherent relationship between these two properties.

Containment:

Containment depends on the geometry and distribution of rocks and pressure systems that limit fluid flow in the subsurface. In the simplest geometrical case – known as a four-way dip closure - one competent sealing package drapes and encloses the reservoir and thereby limits flow in any upward direction. In reality just like oil and gas fields, there will be many variations of effective seal geometries that limit the movement of CO2 in the subsurface including lateral and vertical variations in the reservoir and complex geometries of the ultimate seal, including flow barriers such as faults and naturally over pressured zones. Because of the inherently variable nature of rock units it is best to think in terms of a storage complex and a sealing system – each containing many geological elements. The goal is to show that the geological containment system as a whole is secure.

The role of faults and fractures and their impact on the containment of fluids including CO2 is complicated and are often misunderstood. The presence of a fault does not imply a leakage problem. Most rock units are faulted and fractured in some way over geological time. The critical question for CO2 storage is whether there any faults or fractures that could provide leakage pathways under present-day geological conditions. In addition to the basic geometry of connected rocks and flow paths, this involves the study of geo-mechanics, stress fields and fracture behavior. Simply put many "faults" do not leak at all and many huge oil and gas fields that include faults prove the point. It is also true that the subsurface extent of hydrocarbon accumulations may be limited by faults. However, fluids do not directly flow to the surface along faults that define the limits of hydrocarbon accumulations because faults are not unimpeded leakage pathways to the surface. Trace amounts do sometimes very slowly seep to the surface and advanced geochemical techniques are used to identify these trace amounts.

Injectivity:

Permeability (k), measures the ability of fluids to flow through a formation. High values indicate a well-connected pore space while low values indicate convoluted conduits that disconnect the pores. Porous rocks have a wide range in permeability between around 0.1 milli-Darcy (for very tight rocks) to several Darcies (for very permeable formations). The oil industry usually uses the milli-Darcy unit (mD) for permeability, where 1mD is approximately 10-15 m2 (the Standard International unit more often used in the groundwater industry).

Ideally, CO2 storage requires high permeabilities (>100 mD) to ensure near well bore injectivities for quick access to the pore space. However, this is not always possible and near wellbore permeabilities may need to be enhanced by artificially stimulating the wells to allow for improved injectivity. Permeability is estimated from core sample analysis, interpretation of wire-line log data and well testing (down hole flow and pressure analysis). These different forms of data may give conflicting results, due to the different scales and methods of measurement. There is generally a gradual process in integrating these data to build up a true picture of the large and small-scale variation in permeability within the formation.

While high permeabilities are generally desirable, very high permeability pathways or conduits can enhance CO2 migration along concentrated pathways reducing the effective storage within the target formation. CO2 also reacts geochemically with the rocks and fluids in the formation, and these reactions can affect permeability. In general, permeability may be enhanced in carbonate formations but is more likely to be impaired in clastic formations (sands and shales), particularly with high salinity brines. For example, halite precipitation has been observed in reservoirs with low permeability (<10 mD), and high salinity brines. These effects can be mitigated by modifying injection rates, displacing the saline formation water with low salinity brine or by stimulating the wells with a designed chemical mix (inhibitors) prior to or during injection.

Trapping mechanism

CO2 can be stored in geological media by various means through a variety of physical and chemical trapping mechanisms [31] as a result of its properties at the pressure and temperature conditions found in Earth’s subsurface. At normal standard conditions CO2 is a gas with a density of 1.872 kg /m3 (slightly heavier than air). The critical point for CO2 is Tc = 31.1 1C and Pc = 7.38MPa (equivalent to 738m hydrostatic column of water), where T and P are temperature and pressure, respectively, and the subscript c denotes the critical point. For ToTc(查原文) and pressures above the vaporization curve, CO2 is a liquid, while for temperatures and pressures above the critical point CO2 is a supercritical fluid (Fig. 1a). At supercritical conditions, a fluid has different properties than in either the liquid or gaseous phase, but then most notable and relevant in this case are the high-density characteristic of liquids, and occupying the entire available volume, like a gas. Since both temperature and pressure increase with depth in the subsurface, but have opposite effects on CO2 density (Fig. 2a), the latter increases rapidly with depth and then stabilizes or even decreases, depending on the geothermal regime (Fig. 2b) [35]. Fig. 2 shows that in most cases CO2 injected deep in the subsurface will be a buoyant fluid lighter than water. Only in the case of over-pressured conditions approaching litho-static could CO2 reach densities greater than water [35]. Other relevant CO2 characteristics are its affinity to coal (Fig. 1b), which is greater than that of nitrogen (N2) and CH4 but less than that of hydrogen sulphide (H2S) and sulphur dioxide (SO2), and its solubility in water (Fig. 1c), which increases with increasing pressure and decreases with increasing temperature and water salinity (Fig. 1d).

C:\Users\Zhao Fei\AppData\Roaming\Tencent\Users\419945862\QQ\WinTemp\RichOle\AC{YC0NUK[DT]R@[email protected]

Fig. 1. Relevant characteristics of CO2: (a) phase diagram; (b) adsorption on coal (from [32]); (c) solubility in fresh water (from [33]); and (d) decrease in solubility with increasing water salinity (from [34]).

C:\Users\Zhao Fei\AppData\Roaming\Tencent\Users\419945862\QQ\WinTemp\RichOle\TLNRF5ZD0EVB6J96[EK{43I.jpg

Fig. 3. Characteristics of residual-gas trapping: (a) diagrammatic illustration of disconnected bubbles of non-wetting gas in a water-wet porous medium and (b) relative permeability of CO2 and brine at in situ conditions measured on a sandstone core from Alberta, Canada (from [40]).

Physical trapping:

Physical trapping of CO2 occurs when CO2 is immobilized as a free gas or supercritical fluid and as a process it depends on the available storage volume. There are two types of physical trapping:

static trapping of mobile CO2 in stratigraphic and structural traps,1 or in man-made caverns (mobile in this context means that the flow of CO2 is impeded by a physical low-permeability barrier, and that, if a pathway is found, CO2 will flow driven by its own buoyancy and other forces); and (2) residual-gas trapping in the pore space at irreducible gas saturation, in which case CO2 is immobile because of the interfacial tension between CO2 and formation water, and flow is not possible even if a pathway is available. Residual-gas trapping is based on disconnected gas bubbles (Fig. 3a) being left in the wake of a migrating stream or plume of CO2 (non-wetting phase) when water (wetting phase) moves back into the pore space during an imbibition cycle, after it was expelled from the pore space during the drainage cycle by the injected and/or migrating CO2, and is due to the hysteretic properties of relative permeability2 (Fig. 3b). During injection, CO2 saturation increases in a drainage-like process, and vertical and lateral flow paths are created as CO2 migrates laterally away from the injection wells and to the top of the injection aquifer due to buoyancy forces. Once injection stops, CO2 continues to migrate upward and displace water at the leading edge of the plume, while at the trailing edge water displaces CO2 in an imbibition-like process. A trail of residual, immobile CO2 is left behind the plume as it migrates laterally and upward [41,42]. Thus, residual-gas trapping occurs largely, if not entirely, after injection has stopped.

Chemical trapping:

Chemical trapping occurs when CO2 adsorbs onto organic materials contained on coals and shales (adsorption trapping—Fig. 1b), or dissolves in subsurface fluids (solubility and ionic trapping) and may then be involved in chemical reactions with the rock matrix (mineral trapping).

Coal contains a natural system of fractures called cleats, which imparts some permeability to the system. Between the cleats, the solid coal does not contain macropores through which fluids can flow, but does contain a very large number of micropores into which gas molecules can diffuse from the cleat. In the presence of multiple gases (e.g., CH4, CO2, N2) the amount of each in the adsorbed state would be approximately in the proportion of their respective affinities (Fig. 1b) [43]. Because coal has higher affinity for gaseous CO2 than for methane, which occurs naturally in coals, CO2 storage in coal beds is based on the premise that the injected CO2 will replace the methane in coal and remain adsorbed onto the coal surface. The freed methane, which is also a greenhouse gas with a radiative force 21 times stronger by weight than that of CO2, has to be captured and used as a source of energy (should not be vented) to ensure a net greenhouse gas mitigation outcome, hence the name of the whole process as enhanced coal-bed methane recovery (ECBMR). If the pressure in CO2- saturated coal is subsequently lowered, some but not all CO2 will desorb from the coal surface due to the hysteretic nature of gas adsorption and desorption [44]. However, if the coals are subsequently mined (i.e., coal pressure is brought to atmospheric), then all the CO2 will desorb, cancelling the CO2 storage and also posing a health and safety risk.

The most basic chemical reactions that lead to solubility trapping and mineral carbonation are [31]:

CO2 (gaseous)  CO2 (aqueous) (2)

CO2 (aqueous) + H2O = H2CO3 (aqueous) (3)

Solubility trapping;

H2CO3 (aqueous) + OH- HCO3- (aqueous) + H2O

Ionic trapping;

HCO3- (aqueous) + OH-  CO3= (aqueous) + H2O

CO3= (aqueous) + Ca2+  CaCO3 (solid)

Mineral trapping; (5)

Although more complex reactions may also take place with Ca and Mg rich minerals [31,45]. All the chemical trapping mechanisms depend, of course, on the amount of coal, formation water or rock that is available for reactions, but also on the contact area between free-phase CO2 and coal, water or mineral, and on CO2 saturation at the interface. Under favourable circumstances, injected CO2 may migrate in the subsurface at extremely low velocities such that it would take time on a geological scale (tens of thousands to millions of years) to potentially reach the surface, before which, under the right conditions, it is most likely to be trapped by a combination of the mechanisms outlined above in a process described as hydrodynamic trapping [46,47]. Very large amounts of CO2 could be potentially stored this way.

When CO2 is injected in the subsurface, it is first trapped by primary mechanisms, which are static and hydrodynamic trapping below the caprock in oil and gas reservoirs and deep saline aquifers, and adsorption onto the coal surface in coal beds. Over time, a series of secondary trapping mechanisms start operating, mechanisms that do not necessarily increase the CO2 storage capacity, but definitely increase the storage security (i.e., diminish the potential for leakage and/or the amount of CO2 that may migrate or leak) [21].

C:\Users\Zhao Fei\AppData\Roaming\Tencent\Users\419945862\QQ\WinTemp\RichOle\HAVYIIS9KZL4_%0JWL{NAVI.jpg

Fig. 4. Differences between various CO2 trapping mechanisms in geological media: (a) operating timeframe, and (b) contribution to storage security (after [21]).

Risk

As with any human activity, there are certain risks associated with CO2 geological storage. Risk in its engineering definition is the product of the likelihood of an event to occur and the consequences of the event-taking place. Henceforth, since consequences are highly dependent on location and time, the following discussion will address only the various events that may take place and their potential consequences; furthermore, only the risks associated with CO2 storage will be discussed because the risks associated with surface and injection/production facilities are well understood [76]. Risks associated with CO2 geological storage may occur during the operational (injection) phase and/or afterwards.

五大风险（global，local，short term， long term，equity）

Other challenges and barriers。