Mecanisme de stocare geologica a CO2

Mecanisme de stocare geologica a CO2

Cuprins

Introducere. Prezentarea problemei

a. 

b.

Stadiul la nivel international / national.

a.  Platforme existente (scurta descriere)

b. Proiecte de cercetare : internationale, romanesti

i. CASTOR

ii. CO2 Club

iii. CO2 NET

Tipuri de (roci potential) rezervoare geologice. Caracteristici. Avantaje/dezavantaje. Capacitati de stocare.

Proprietati de transport ale CO2: densitate, vascozitate, solubilitate, mobilitate, flotabilitate, miscibilitate

Mecanisme de stocare geologica a CO2 (fizica + chimica)

a.  Capcane structurale, stratigrafice

b. Dizolvare

c.  Saturatie reziduala

d. Precipitare/mineralizare

Particularitati ale stocarii geologice in formatiuni acvifere de adancime

a

b

Riscuri associate stocarii geologice a CO2

Concluzii

Bibliografie

Introducere. Prezentarea problemei

a. 

b.

Today the climate change issue has become a major concern, and is perhaps one of the most severe challenges of our time. Quick actions are required in order to stabilise the global warming at 2-3 Centigrade within the 21^st century. Although this elevated level (to adapt to) results from the more optimistic trajectories in climate modelling, it is still foreseen to have substantial environmental impacts.

It was first suggested by SINTEF (Erik Lindeberg) in 1986 to combine CO₂ absorption techniques with geological storage of CO₂ as a climate change mitigation option. Since then, CCS has become part of the scientific domain, and already spun off industrial actions merged with political influence and public awareness. Still substantial research and development efforts are required in order to deem CCS viable on techno-economic terms.

Figure 1a - Évolution de la consummation d'énergie mondiale en millions de tones d'équivalent pétrole.

Fig. 1b - Répartition de la consummation d'énergie mondiale en 2003 en fonction des sources d'énergie.

Geological timelines in years

It can be seen from the geological timeline that CO2 will be stored for a very long time, also in comparison with the other geological processes that take millions of years. Source: Stanley (1999).

Age of the earth  4.6 billion (

Differentiation 

Plate tectonic cycle   

Formation of mountains

Formation of sedimentary basins 

Formation of fossil fuels   

Radioactive waste 

CO₂ storage

Reservoir production lifetime    <50

2. Stadiul la nivel international / national.

Platforme/proiecte de stocare existente (scurta descriere)

Proiecte de cercetare : internationale, romanesti

CASTOR

CO2 Club

CO2 NET

2.1 Examples of storage projects

Sleipner, North Sea (saline reservoir)

In-Salah, Algeria (gas reservoir)

K12B, North Sea (gas reservoir)

Weyburn, Canada (oil reservoir)

Enhanced Coal Bed Methane projects

Alisson (New Mexico)

Recopol (Poland)

Locations of CO2 storage activities

3. Tipuri de (roci potential) rezervoare geologice. Caracteristici. Avantaje/dezavantaje. Capacitati de stocare.

In analiza formatiunilor geologice candidate ca rezervor pentru stocarea CO2 se folosesc urmatoarele criterii de selectie:

a) distanta fata de sursa de CO₂,

b) dimensiunea rezervorului

c) caracteristici geologice si hidrogeologice,

d) proprietatile fluidului (din rezervor).

Din marea diversitate de formatiuni geologice, doar trei sunt considerate optiuni de stocare a CO2 in subteran, pe scara larga (figure 1): oil and gas reservoirs, deep saline aquifers, and coal beds. Fiecare se caracterizeaza prin mecanisme fizice, care actioneaza la diverse scari de timp, pentru distribuirea CO2 injectat in cadrul formatiunii si evolutia sa pe termen lung.

Bazinele sedimentare sunt cele mai promitatoare sisteme geologice pentru stocarea CO2. Desi cu raspandire larga pe suprafata pamantului, trebuie mentionat ca nu intotdeauna sunt indeplinite conditiile de stocare. Exista diverse posibilitati pentru stocarea geologica a CO2: campuri gazeifere epuizate, acvifere sarate, zacaminte de petrol si strate de carbune, cu varianta de recuperare suplimentara de gaze si petrol.

• Avantaje si dezavantaje

IEA, GHG, 2004

• Capacitate de stocare potentiala

^a These numbers would increase by 25% if "undiscovered" oil and gas fields were included in this assessment. Compare worldwide CO2 emissions: 25 GtCO2/yr.

Conform datelor din tabel formatiunile acvifere sarate de adancime ofera capacitati de stocare immense, atat comparativ cu celelalte optiuni de stocare cat si cu emisiile de CO2 la nivel mondial.

Tipuri de medii geologice

Au fost identificate 5 formatiuni geologice majore potential favorabile stocarii subterane a CO2: formatiuni acvifere saline, strate de carbune, rezervoare de petrol si gaze, sisturi, roci bazaltice.

a. Formatiuni acvifere sarate

Formatiunile acvifere sarate sunt reprezentate prin roci poroase-permeabile, saturate cu saramuri si izolate prin una sau mai multe formatiuni impermeabile cu extindere regionala care asigura captura CO2 injectat. Saramura este o apa cu o concentratie foarte mare in saruri: de regula TDS > 10,000 ppm. Au cea mai mare resursa potentiala de stocare.

b. Rezervoare de petrol si gaze

Sunt reprezentate de un strat de roci permeabile, in care se afla petrolul/gazele si un strat de roci impermeabile deasupra care nu permite migrarea fluidelor. Aceasta structura (capcana) geologica este principala caracteristica pentru stocarea pe termen lung a CO2.

Ca un avantaj suplimentar, injectarea de CO2 intr-o astfel de structura poate creste cantitatea de petrol recuperata. O parte din CO2 se va dizolva in petrol avand ca efect cresterea volumului, scaderea vascozitatii si favorizarea curgerii petrolului catre forajele de exploatare.

In acest fel (EOR) se poate estima o crestere cu 10-15% a factorului final de recuperare (30-40% in urma recuperarii primare si secundare).

c. Strate de carbune

Toti carbunii au cantitati variabile de metan adsorbit pe suprafetele porilor. Pentru stratele de carbune neexploatabile se pot executa foraje pentru recuperarea gazului metan (CBM). Metodele initiale (conventionale) de recuperare a metanului, precum asecarea, scaderea presiunii, lasa cantitati considerabile de metan in formatiune. O recuperare suplimentara se poate obtine prin injectarea de CO2. Functie de tipul de carbune, intre 3 si 13 molecule de CO2 pot fi adsorbite pentru fiecare molecula de metan eliberata. Astfel se asigura un excellent mediu de stocare a CO2 pe langa avantajele economice ale recuperarii metanului (ECBM).

Atribute cheie ale unui rezervor pentru stocarea CO2:

Injectivitate = Permeabilitate + grosime corespunzatoare

. poate fi imbunatatita

- strategii de injectare (numar de foraje, lungime tronsoane de injectie),

- stimulare (hidrofracturare).

. posibile influente ale interactiunii CO2-roca-fluid asupra permeabilitatii

Capacitate de stocare = volumul corespunzator al porilor accesibili; depinde de: grosimea si extinderea formatiunii; porozitatea efectiva; compresibilitate; heterogeneitate; gradul de saturatie al porilor cu CO2; extinderea penei de CO2;

. Depinde/ este in stransa legatura cu adancimea pe care sunt indeplinite conditiile supercritice de stocare;

. Atentie la dizlocuirea si deplasarea saramurii fara a induce efecte negative asupra mediului.

Izolarea / etansarea

Proprietati de etansare: bariera capilara, bariera permeabila, bariera de presiune.

. Continuitate si grosime,

. Extindere geografica,

. Stabilitate geomecanica

. Stabilitate geochimica

. Absenta faliilor continue si conductive

. Evidenta forajelor abandonate

Probabil cel mai greu de caracterizat

Caracterizarea/descrierea site-ului trebuie sa fie specifica tipului de stocare

Campuri petroliere/gazeifere epuizate

+ Injectivitate si capacitate bine stabilite

+ Capacitate dovedita de a retine/stoca hidrocarburi

+ In general bine caracterizate

- Site-uri nu sunt intotdeauna disponibile la momentul si la locatia dorita

Aspect important privind izolarea: posibile scurgeri/pierderi prin foraje (cunoasterea forajelor abandonate, integritatea forajelor).

Formatiuni saline adanci

+ Cea mai mare capacitate de stocare

+ In general nu exista problema competitiei cu o alta resursa, datorita salinitatii foarte mari

- Incertitudini in estimarea injectivitatii si capacitatii

- Izolarea/etansarea dificil de caracterizat si demonstrate (ecran > 100 km2, etc)

- De regula informatii disponibile limitate, necesare foraje noi, investigatii geofizice etc.

Aspect important privind izolarea: posibile scurgeri pe falii/fracture (detectarea faliilor, caracteristicile faliilor, integritatea ecranului in timp).

Proprietati de transport ale CO2:

densitate, vascozitate, solubilitate, mobilitate, flotabilitate, miscibilitate

In conditii normale CO₂ este un gaz termodinamic foarte stabil, mai greu decat aerul (densitate 1.872 kg/m³ in conditii normale). La temperaturi mai mari decat Tc=31.1°C si presiuni mai mari decat Pc=7.38 MPa (punctul critic), CO₂ este in stare supercritica, cu o densitate care creste, functie de presiune si temperatura, de la 150 la > 800 kg/m³ , pentru conditiile specifice bazinelor sedimentare. Daca se preconizeaza injectarea de CO₂ in formatiuni geologice adanci, atunci se pot estima proprietatile CO₂ functie de conditiile tipice locatiei de injectare.

Figure 2. Densitatea CO₂ functie de P si T.

Densitatea CO2 in functie de T & p

Graficul prezinta variatia densitatii cu adancimea, considerand presiunea hidrostatica si un gradient geotermic 25°C/km (de la 15°C la suprafata. Densitatea creste rapid pana la aproximativ 800 m unde CO2 atinge starea supercritica.

Cuburile reprezinta volumul relativ ocupat de CO2 si, pana la 800 m se observa scaderea dramatica a volumului cu adancimea. De la cca. 1.5 km, densitatea si volumul specific devin aproximativ constante. Cresterea temperaturii la adancimi mai mari determina o densitate mai mica, in vreme ce din cresterea presiunii rezulta o densitate mai mare.

Flotabilitatea (buoyancy) - este o forta foarte puternica ce depinde de temperatura si presiune prin variatia densitatii. In conditii normale densitatea apei este aproximativ constanta comparative cu densitatea CO2. Cu toate acestea apa ce contine saruri si/sau CO2 este mai grea decat apa pura. In subteran CO2 are densitate mai mica decat a apei, astfel ca CO2 tinde sa se deplaseze ascendent. Acest efect va deveni mai puternic pe parcursul migrarii ascendente deoarece reducerea presiunii determina o scadere a densitatii. Pe de alta parte scaderea temperaturii, la aceeasi presiune conduce la o densitate mai mare. Aceasta dependenta este foarte puternica la temperaturi si presiuni mici, asa cum este indicat de limita supercritica. In aceste conditii densitatea, la adancimea de 1 km, este in jur de 600 kg/m3.

• Vascozitatea CO2

La temperaturi ridicate corespunde o vascozitate redusa, ceea ce inseamna o rezistenta mai mica la curgere si deci o injectie mai buna a CO2. In stare supercritica CO2 este mult mai putin vascos decat apa si petrolul (cu cel putin un ordin de marime), astfel ca exista un mare contrast de mobilitate intre CO2 si fluidele in situ din formatiune. In acest caz migrarea este controlata de aceste fluide (Nordbotten et al., 2005a; Celia et al., 2005).

Datorita mobilitatii comparativ ridicate a CO2, doar o parte a apei si petrolului va fi dizlocuita la injectarea CO2 is injected, in schimb o mare parte va fi saturata cu CO2, cu o valoare medie de 30-60%. Procesul de viscous fingering apare in frontul CO2 injectat unde o parte a CO2 dizlocuieste petrolul si apa iar o alta parte este saturat in petrol si apa. Aceasta poate determina ca CO2 sa bypass mare parte din spatiul poros, functie de heterogeneitatea si anizotropia permeabilitatii (van der Meer, 1995; Ennis-King and Paterson, 2001; Flett et al., 2005). Pentru rezervoarele de gaze naturale, CO2 este mult mai vascos decat gazul in situ astfel ca "frontul" va fi stabil iar viscous fingering limitata.

• Solubilitatea CO2 in apa

In saramuri solubilitatea CO2 scade pe masura ce salinitatea creste (salting-out effect).

Din grafic se observa ca la p = 100 bari si T = 50 C, 50 kg de CO2 se pot dizolva intr-un volum de 1 m3 de apa. In continuare, mai mult CO2 se poate dizolva in apa si astfel stocat in acvifer, la temperaturi mai mici. Functie de conditiile de presiune, temperatura si salinitate din acvifer circa 20-60 kg de CO₂ pot fi dizolvate intr-un metru cub de apa. The red circle marks the area for underground CO2 storage. Atingerea echilibrului poate dura zeci de ani, pana la 100 de ani.

• Miscibilitatea

Gazul natural si CO2 sunt miscibile si formeaza o singura faza fluida. CO2 (lichid sau lichid in stare supercritica) si apa sunt imiscibile (dar CO2 se poate dizolva in apa). CO2 si petrolul sunt miscibile sau nemiscibile functie de compozitia petrolului si conditiile termodinamice. CO2 and carbune: interactiune foarte complex in care adsorbtia joaca un rol important.

Proprietati ale CO2 injectat in stare supercritica:

Miscibilitate redusa cu saramura (limita de solubilitate  ~ )

Densitate mai mica decat saramura (raportul densitatilor 0.25-0.75)

vascozitate mai mica decat saramura (raportul vascozitatilor 0.2 - 0.02)

Apa se poate evapora in CO2 (uscat)

Interactiuni  CO2 - rezervor. Mecanisme de imobilizare si stocare a CO2: fizica + chimica

a.  Capcane structurale, stratigrafice

b. Dizolvare

c.  Saturatie reziduala

d. Precipitare/mineralizare

Several mechanisms work in combination to ensure that CO2 remains in the storage reservoir. Supercritical CO2 is buoyant, and will migrate upward. This migration can be prevented by a confining zone overlying the injection formation. Storage through this physical trapping contains very high fractions of CO2, and acts immediately to limit vertical CO2 migration. Capillary trapping can immobilize a substantial fraction of CO2. This mechanism also acts immediately and is sustained over long time scales. CO2 trapped this way may be considered permanently trapped. A fraction of the CO2, will dissolve into other pore fluids, including hydrocarbons (oil and gas) or brines. Depending on the fluid composition and reservoir condition, this may occur rapidly (seconds to minutes) or over a period of tens to hundreds of years. Over very long time scales, much of the dissolved CO2 may react with minerals in the rock volume to dissolve or precipitate new carbonate minerals, often called mineral trapping. Precipitation of carbonate minerals permanently binds CO2 in the subsurface; dissolution of minerals generally neutralizes carbonic acid species and increases local pH, buffering the solutions and trapping CO2 as an ionic species (usually bicarbonate) in the pore volume.

• Physical blocking by
• structural traps (anticlines, unconformities or faults)
• stratigraphic traps (change in type of rock layer)

Physical blocking by structural and stratigraphic traps occurs only when CO2 is less dense than reservoir fluid, so that fluid migrates upwards. Anticline is an arch shaped fold in a rocks, closing upwards.

Unconformity trap is a trap formed by a sealing formation, that has been created by the folding, uplift and erosion of porous strata, followed by the deposition of later beds that can act as a seal.

structural traps (folding and anticlines)

Faults and unconformities

(Fault consists of different material)

• Chemical blocking

Adsorption onto coal or organic-rich shales: permanently reduced mobility

Mineralization into carbonate mineral phases: permanently reduced mobility

Solubility trapping: CO2 dissolved in formation waters forming one single phase:
greatly reduced mobility

Adsorption is the attachment of an ion, molecule or compound to the (oppositely) charged surface of a particle.

• Hydrodynamic trapping by extremely slow migration rates of reservoir brine

• Residual gas trapping by capillary forces in pore spaces

Residual Saturation Trapping

As CO2 migrates through the formation, some of it is captured and permanently remained in the pore space, which is referred to "residual CO2 trapping" (Obdam et al., 2003). When the rate of this trapping is relatively high and CO2 is injected at the bottom of a sufficiently thick formation, almost all of the injected CO2 can be trapped by the mechanism before it reaches the surface boundary of the formation. Likewise, the residual trapping mechanism plays a significant role in capturing CO2 to be immobile.

From the simulation results (shown in Figure 9), we can easily figure out that all of grid blocks which CO2 passes though show residual gas saturation: the blue color indicates 0.2 of gas saturation, which is the value of residual gas saturation, Sgr. Consequently, this case represents quite similar trend of CO2 primarily-upward migration compared with the base case due to isotropic condition; however, the explicit difference is that CO2 cannot reach the upper surface of the reservoir.

• Negative buoyancy in case CO2 is denser than its host rock.

Following the injection of anthropogenic CO2 below a typical depth of 800 m, the storage mechanism is initially hydrodynamic as the CO2 is immobilized as a dense supercritical fluid. On a separate timescale, and following the dissolution of CO2 in brine, chemical interactions with the brine may form mineral carbonates [4]. CO2 reacts with brine's metal cations to form carbonate precipitates via the following reaction sequence, in which selected likely precipitates are shown [5,6]:

CO2(g)fCO2(aq)    (1)

CO2(aq)+H2OfH2CO3   (2a)

H2CO3fH++HCO3_   (2b)

CO2 (aq)+OH_fHCO3_ (3)

HCO3_fH++CO32_    (4)

Ca2++CO32_ fCaCO3 A (5a)

Mg2++CO32_f MgCO3 A (5b)

Ca2++Mg2++2CO32_f CaMg(CO3)2 A (5c)

The dissolution of CO2 in water (reaction 1) is dependent on temperature, pressure, and brine salinity. Reactions 2a and 2b represent the formation of carbonic acid, which reduces the pH of the system, and the dissociation of carbonic acid to form bicarbonate, respectively. The bicarbonate ion may then dissociate (reaction 4) to form the carbonate ion. The metals then react with the carbonate ion to form the carbonate minerals in reactions 5a, 5b, and 5c, which are calcite, magnesite, and dolomite, respectively.

The pH determines which steps dominate the reaction sequence, and accordingly the proportions of the carbonic species [5]. At a low pH (~4), the production of H2CO3 dominates, at a mid pH (~6) HCO3_ production dominates, and at a high pH (~9) CO32_ dominates [6]. Therefore, at a basic pH the precipitation of carbonate minerals is favored because of the availability of carbonate ions. Conversely, the dissolution of carbonates increases as the solution becomes increasingly more acidic.

The rate of the mineral trapping process is slow and serves as the major disadvantage of this technology [6]. In the low to mid pH range, the rate limiting step of this reaction is the hydration of CO2 to form carbonic acid in reaction 2a, which has a forward reaction rate constant of 6.2_10_2 s_1 at 25 8C [7]. However, in the high pH range the rate limiting step is the first dissociation of carbonic acid to form bicarbonate [6].

The parameters that affect the efficiency of the carbonate forming process for both above and underground sequestration operations are brine composition, temperature, pressure, and pH. These parameters must be further understood since they determine both the economic viability of the technology as well as help to identify locations that favor sequestration.

Soong et al. [6] suggest that pH has a significant effect on both conversion rates and on the specific species that are precipitated. The formation of carbonates can thus be promoted by increasing brine pH through the addition of a strong base. Their research qualitatively identifies the effects of various parameters on carbonate precipitation. However, pH evolution throughout the reaction is not documented.

Adequate containment of stored CO2 for sufficiently long periods of time (enough that it can be considered to be safely removed from atmospheric circulation) is a critical part of any assessment of potential for CO2 storage in the subsurface. CO2 can be stored by a number of different trapping mechanisms, such as:

. Physical trapping in structural or stratigraphic traps, where the free-phase CO2 is physically trapped by the geometric arrangement of the reservoir and seal rock units (in a similar manner to hydrocarbon accumulations, e.g. Biddle & Wielchowsky, 1994);

. Hydrodynamic trapping, where the dissolved and immiscible CO2 travels with the formation water for very long residence (migration) times (Bachu et al., 1994);

. Residual trapping, where the CO2 becomes trapped in the pore spaces by capillary pressure forces (Ennis-King & Paterson, 2001; Holtz, 2002; Flett et al., 2005);

. Solubility trapping, where the CO2 dissolves into the formation water (Koide et al., 1992);

. Mineral trapping, where the CO2 precipitates as new carbonate minerals (Gunter et al., 1993); and

. Adsorption trapping, where the CO2 adsorbs onto the surface of the coal (Gunter et al., 1997a).

CO2 Trapping Mechanisms

The subsurface flow behaviour of CO2, as well as the length of time involved, will influence the ultimate trapping mechanism. There are a number of different trapping mechanisms for geological storage of CO2, which include structural/stratigraphic trapping, hydrodynamic trapping, residual trapping, solubility trapping, mineral trapping and adsorption trapping. The following discussion is mostly extracted or modified from Gibson-Poole (2008).

Structural/Stratigraphic Trapping

Structural/stratigraphic trapping relates to the free-phase (immiscible) CO2 that is not dissolved in formation water. When supercritical CO2 rises upwards by buoyancy it can be physically trapped in a structural or stratigraphic trap (as a result of the CO2 being the non-wetting phase) in exactly the same manner as a hydrocarbon accumulation. The nature of the physical trap depends on the geometric arrangement of the reservoir and seal units. Common structural traps include anticlinal folds or tilted fault blocks (Figure 11a) and typical stratigraphic traps include those created by a lateral change in facies up-dip or a depositional pinch-out (Figure 11b). As with hydrocarbon accumulations, there are numerous variations of structural and stratigraphic traps, plus combinations of both structural and stratigraphic elements, that can provide physical traps for geological storage of CO2. In a dipping formation with no defined structural closure, any small bumps in the seal geometry will behave like small anticlinal structural traps and free-phase CO2 will fill these to the spill point (due to buoyancy) before migration continues (Bergman & Winter, 1995; Lindeberg, 1997; Ennis-King & Paterson, 2002).

Hydrodynamic Trapping

In a storage project, supercritical CO2 will be injected as a single phase, but once in the geological

formation it will partition into free-phase (immiscible) CO2 and a CO2-rich brine. The flow of the freephase

CO2 is dependant on the dip of the sealing horizon and the flow velocity and direction of the in situ formation water. In horizontal or gently dipping reservoirs, this can lead to very long residence times, of

the order of thousands to millions of years (Figure 12) (Bachu et al., 1994). The dissolved CO2 will travel

with the moving formation water. Saline aquifers generally have very low flow velocities, of the order of

tens of cm/year. This slow flow velocity leads to residence times of millions of years. This geological timescale trapping of CO2 in deep regional aquifers is called hydrodynamic trapping and avoids the need for structural or stratigraphic traps (Bachu et al., 1994). This trapping mechanism can be considered a 'rate

seal', as opposed to traditional 'rock seal' traps associated with structural and stratigraphic traps.

Figure 12: Hydrodynamic trapping of CO2, where the CO2 migration pathway is 10s to 100s km long

allowing for a long residence time.

Limited work on hydrodynamic trapping for CO2 storage has been done in Australia. Notable are the studies by Hennig et al. (2006) on the Showgrounds Aquifer at the Wunger Ridge site in Queensland and Henning & Otto (2007) on the offshore Vlaming Sub-basin of Western Australia. During the injection phase of a storage project (of the order of 20 to 40 years), the migration of the CO2 away from the injection well involves both gravity override and viscous fingering, as a result of the CO2 being significantly less dense and less viscous than the saline formation water under typical reservoir conditions (Ennis-King & Paterson, 2001; Nordbotten et al., 2005). Simulations by Holt et al. (1995) determined that the rate at which the CO2 is injected can have an impact on this displacement behaviour. At high injection rates, viscous forces dominate and the CO2 plume develops rapidly along the most permeable paths. At lower injection rates gravity forces dominate and buoyancy causes the CO2 to rise upwards. The heterogeneity in the permeability distribution also has a significant impact on the flow behaviour of injected CO2. If the degree of heterogeneity is large, particularly with respect to the ratio between horizontal and vertical permeability, then channelling of CO2 along the most permeable paths will be the dominant flow behaviour (van der Meer, 1995; Ennis-King & Paterson, 2001).

After cessation of injection, migration of the CO2 plume continues during the relaxation of the pressure gradient driving the lateral migration. The CO2 then continues to migrate under the influence of gravity (or buoyancy) and the natural formation water flow (Ennis-King & Paterson, 2001, 2002; Flett et al., 2003; Flett et al., 2005). The dissolved CO2 moves with the formation water. The relationship between these two phases determines which storage mechanism dominates and how far the CO2 will migrate from the injection site before no free-phase, mobile CO2 remains. The longer the migration pathway and the slower the migration rate, the more CO2 will become trapped residually or in solution such that eventually no mobile, free-phase CO2 will exist in the system, as modelled in various numerical simulations, (McPherson & Cole, 2000; Ennis-King & Paterson, 2005a). The length of the migration pathway is controlled by geological parameters such as stratigraphic heterogeneities, for example, intraformational siltstones, shales and coals, which play a crucial role in determining the tortuosity of the CO2 flow path. The intraformational seals act as barriers or baffles to the buoyancy-driven upward flow and induce lateral migration until CO2 is able to breach the barrier or get past it (Ennis-King & Paterson, 2002; Hovorka et al., 2004; Flett et al., 2005). The flow velocities are dependant on a number of factors, including the fluid properties (both freephase CO2 and formation water), the mechanism of transport (diffusion, dispersion, convection), buoyancy, rate of dissolution, the hydrodynamic drive and direction, permeability, tortuosity, the impact of any geochemical reactions, temperature (which affects viscosity and density), structural dip, relative permeability, and so on.

Residual Trapping

Residual trapping occurs when the CO2 becomes trapped in the pore space as a residual immobile phase by capillary forces (Figure 13) (Ennis-King & Paterson, 2001; Flett et al., 2005). At the tail of the migrating CO2 plume, imbibition processes are dominant as the formation water (wetting-phase) imbibes behind the migrating CO2 (non-wetting phase). When the concentration of the CO2 falls below a certain level it becomes trapped by capillary pressure forces and ceases to flow (Ennis-King & Paterson, 2001; Holtz, 2002; Flett et al., 2003; Flett et al., 2005). Therefore, a trail of residual, immobile CO2 is left behind the plume as it migrates upward (Juanes et al., 2006). Residual CO2 saturation values vary between 5-30 % based on typical relative permeability curves (Ennis-King & Paterson, 2001). Over time, the residually trapped CO2 dissolves into the formation water (Ennis-King & Paterson, 2001; Flett et al., 2005).

Figure 13: Residual trapping of CO2

Solubility Trapping

Solubility trapping relates to the CO2 dissolved into the formation water (Koide et al., 1992). Carbon dioxide solubility increases with increasing pressure and decreases with increasing temperature and water

salinity. Carbon dioxide may mix with, and then dissolve in, formation water through the processes of diffusion, dispersion and convection.

Thus, time is an important factor in the solubility trapping of CO2. With increasing time, more CO2 dissolves into the formation water (Bachu et al., 1994; Ennis-King & Paterson, 2001). As the CO2

continues to dissolve into the formation water, it can lead to a phenomenon known as convective mixing.

The density of the CO2-saturated water increases to become about 1 % more than that of the unsaturated

water when CO2 dissolves into the formation water. The dense CO2-saturated water overlying less dense

unsaturated water creates a density instability and plumes of CO2-rich water flow downward (Figure 14)

(Lindeberg & Wessel-Berg, 1997; Ennis-King & Paterson, 2002; Lindeberg & Bergmo, 2003; Ennis-King

& Paterson, 2005a). The time-scale for complete dissolution is critically dependent on the vertical permeability and the geometry of the top seal, but is predicted to occur on a scale of hundreds to thousands of years (Ennis-King & Paterson, 2002). The success of solubility trapping is aided by slow flow velocities of the in situ formation water, as this will lead to a greater residence time and allow more time for CO2 to improve solubility trapping, as they increase the tortuosity of the CO2 migration path and accordingly the CO2 is able to contact larger volumes of formation water into which it can dissolve (Lindeberg, 1997; Hovorka et al., 2004; Flett et al., 2005). Convective mixing (resulting from density instability) is important for solubility trapping of CO2, as it is orders of magnitude faster than pure diffusion mechanisms, and so accelerates the overall dissolution of the CO2 into the formation water (Ennis-King & Paterson, 2002, 2005b).

Figure 14: Convective mixing of CO2: example of a numerical simulation showing the high-density plumes of CO2-saturated brine (grey colours) sinking into the brine column below (white colour) (kv/kh = 0.01,

after 14400 years) (Ennis-King & Paterson, 2005a).

Mineral Trapping

Mineral trapping results from the precipitation of new carbonate minerals (Gunter et al., 1993). This storage mechanism is the most permanent of the trapping types discussed as it renders the CO2 immobile

(Bachu et al., 1994, 1996). The time-scale for mineral precipitation is typically long, of the order of tens to thousands of years, depending on the initial minerals present (Perkins & Gunter, 1995; Kirste et al., 2004). Siliciclastic reservoirs are favoured over carbonate reservoirs, in particular calcium-, magnesium- or ironrich siliciclastic reservoirs, as they have the best potential for mineral trapping of CO2 (Gunter et al., 1993; Bachu et al., 1994; Perkins & Gunter, 1995; Gunter et al., 1997b).

The potential for mineral trapping is quite variable from formation to formation and thus needs to be examined as part of the site characterisation process for storage site selection. Mineral trapping is a

function of the mineralogy of the reservoir rock, the chemical composition of the formation water and the

formation temperature and pressure. In addition, potential reactions depend on the contact surface

(interface) between the mineral grains and the formation water containing dissolved CO2, and on the flow

rate of fluids through the rock (Gunter et al., 2004). Due to the specific information required to model

mineral storage of CO2, it is appropriate that it be undertaken as part of site characterisation rather than

basin-scale assessment (CSLF, 2007). Detailed modelling of injection of CO2 into the White Rim

Sandstone, Utah, using the reactive chemical simulator ChemTOUGH, found that 1000 years after the 30

year injection period began approximately 21 % of the injected CO2 was permanently stored as a mineral

and 52 % was free-phase gas or dissolved in the groundwater (White et al., 2005b). As in residual and

solubility trapping, mineral trapping is a time-dependent process operating on the scale of millennia (Bachu et al., 2007).

Storage Security for Saline/Hydrocarbon Formations

In any geological storage site, the injected CO2 will ultimately be trapped by a number of the mechanisms

described above. The type of trapping that occurs, and when, is dependent on the dynamic flow behaviour

of the CO2 and the time-scale involved. With increasing time, the dominant storage mechanism will change and typically the storage security also increases. Figure 15 is a simple representation of CO2 storage and how the trapping mechanism might alter over time. For example, the initial storage mechanism will dominantly be physical structural and stratigraphic trapping of the immiscible-phase CO2. With increasing time and migration, more CO2 is trapped residually in the pore space or is dissolved in the formation water, increasing the storage security. Finally, mineral trapping may occur by precipitation of carbonate minerals after geochemical reaction of the dissolved CO2 with the host rock mineralogy, permanently trapping the CO2 (IPCC, 2005).

Figure 15: Schematic representation of the change of dominant trapping mechanisms and increasing CO2

storage security with time (from IPCC, 2005).

6. Particularitati ale stocarii geologice in formatiuni acvifere de adancime

a

b

Deep Saline Formations are layers of porous rock that are saturated with brine. They are much more extensive than coal seams or oil- and gas-bearing rock, and represent an enormous potential for CO2 geologic storage. However, much less is known about saline formations because they lack the characterization experience that industry has acquired through resource recovery from oil and gas reservoirs and coal seams. Therefore, there is a greater amount of uncertainty regarding the suitability of saline formations for CO2 storage.

Saline formations are deep porous sedimentary rocks saturated with formation waters that are considered unsuitable for human consumption or agricultural or industrial use. They have been identified by many studies as one of the best potential options for large volume geological storage of CO2 (e.g. Bachu, 2000; Bradshaw et al., 2002). Supercritical CO2 can be effectively stored in deep saline formations because of its high density and high solubility in formation water at the relatively high formation pressures encountered.

However, these formations are commonly less understood (in comparison to shallow freshwater aquifers or hydrocarbon bearing reservoirs) and any assessment of their CO2 storage potential typically includes significant uncertainty because of the lack or scarcity of subsurface data. In addition, the containment potential of the seal rock is usually untested and there is uncertainty regarding potential for undiscovered natural resources. However, their main advantages are that they are distributed widely over the world and their potential storage capacity is large (Koide et al., 1992; Hendriks & Blok, 1993; Rigg et al., 2001; IPCC, 2005). CO2 can be stored in saline formations by a number of different trapping mechanisms, including structural/stratigraphic, hydrodynamic, residual, solubility and mineral trapping (see Appendix A

for a detailed technical discussion on CO2 trapping mechanisms).

Proprietati ale geo-fluidelor

All rocks in the crust contain fluids (water, oil, natural gas, CO2)

Transport of fluids depends on: Density, Viscosity, Solvability, Miscibility

When CO2 is injected into geological formations transport will take place, which depends on certain properties of fluids already present in these formations and of the CO2 that is injected. The most important parameters (density, viscosity, solvability and miscibility) influencing transport will be described. After that the relation of these mechanisms with CO2 storage will be explained.

Buoyancy and density: In case there is a difference in density between two substances, either gas or liquid, the substance with the lowest density will rise upwards.

Viscosity: The internal resistance of a substance to flow when a stress is applied

Solvability: The ability of a substance to go into solution

Miscibility: The ability of different fluids (gases and liquids) to mix (a miscible fluid are those that mix in any proportion).

Desired fluid properties for CO2 storage

High density

High viscosity

High solvability

High miscibility

So: low temperature and high pressure

To store CO2 it is necessary to have a highly dense, viscous, solvable and miscible injection fluid. The first is to prevent it from escaping upwards since a dense fluid tense to descend. The efficiency of CO2 storage in geological media, defined as the amount of CO2 stored per unit volume increases with increasing CO2 density. A high viscosity of the injection fluid makes injection more difficult, but on the other hand it prevents CO2 to escape from the reservoir. Both solvability and miscibility also have to be high because when CO2 is coupled with the in situ fluid already present in a reservoir rapid escape from the reservoir is prevented again. On the other hand enhanced recovery from oil and gas fields can only occur when there is no solvability and miscibility. The actual trapping mechanisms are described in the next slides.

CO2 trapping forms in aquifers (in ordinea crescatoare a importantei cu timpul)

Physical trapping

Dense supercritical CO2 phase (> 31°C at 73 bars)

Chemical trapping

Solubility trapping: CO2(aq), HCO3-, CaHCO3+, MgHCO3+, NaHCO30, .

Mineral trapping: CaCO3 (calcite), FeCO3 (siderite), NaAlCO3(OH)2 (dawsonite),

The injected CO2 is trapped in several forms: dense CO2 phase, dissolved form, mineral form. Depends on the brine chemistry (salinity and detailed chemistry), the precise mineralogy, the pressure and the temperature. Chemical trapping increases with time due to slow kinetics of mineral dissolution and precipitation reactions. The balance with time of the CO2 trapping forms is the result of complex interdependent thermodynamic, kinetic, flow and transport processes.

Contribution of physical and chemical trapping options over time

Right after the injection, structural and stratigraphic blocking contribute most to the trapping of CO2. Although it is not included in this graph, adsorption is also contributing significantly to CO2 trapping quickly after injection, in case CO2 is injected into a coal seam. After 10 to 100 years after injection has stopped this amount is for a large part replaced by residual and solubility trapping. After a period of roughly 1000 to 10000 years mineral trapping starts to contribute significantly. In time the change in contribution of different trapping mechanisms results in an increased storage security.

Saline Formation CO2 Resource Estimating

Background: Saline formations are composed of porous rock saturated with brine and capped by one or more regionally extensive impermeable rock formations enabling trapping of injected CO2. A saline formation assessed for storage is defined as a porous and permeable body of rock containing water with total dissolved solids (TDS) greater than 10,000 parts per million (ppm), which can store large volumes of CO2. A saline formation can include more than one named geologic formation or be defined as only part of a formation.

This saline formation storage assessment includes the following assumptions: (1) saline formations are heterogeneous and therefore under multiphase conditions; (2) only 20 to 80 percent of the area inventoried and 25 to 75 percent of the formation thickness assessed would be occupied by CO2; and (3) the efficiency factor accounts for net-to-effective porosity, areal displacement efficiency, vertical displacement efficiency, gravity effects, and microscopic displacement efficiency.

Screening Criteria: Saline formations assessed for storage are restricted to those meeting the following basic criteria for the storage: (1) pressure and temperature conditions in the saline formation are adequate to keep the CO2 in dense phase (liquid or supercritical); (2) a suitable seal is present to limit vertical flow of the CO2 to the surface (caprock); and (3) a combination of hydrogeologic conditions isolates the CO2 within the saline formation. These criteria also apply to existing UIC and other regulations, and are relevant to capacity assessment as well, but the criteria are first incorporated into resource assessments.

Depths: The storage of CO2 in saline formations is limited to sedimentary basins with vertical flow barriers and depth exceeding 800 meters. Sedimentary basins include porous and permeable sandstone and carbonate rocks. The 800-meter cutoff is an attempt to select a depth that reflects pressure and temperature that yields high density liquid or supercritical CO2. This is arbitrary and does not necessarily designate a lower limit of depth conducive to CO2 storage. Several natural gas reservoirs exist at shallower depths; this infers that CO2 gas may be stored at shallower depths but only at pressure and temperatures most likely to sustain gas-phase CO2 density. Because of the large difference in density between liquid-phase and gas-phase CO2, the additional storage of shallow saline formations is not anticipated to provide any substantial increase in resource estimates for Atlas II, but this could be considered in a site-specific assessment.

Caprocks: All sedimentary rocks included in the saline formation resource estimate must have caprocks (vertical seals) consisting of shale, anhydrite, and evaporites. Thickness of these seals is not considered in this assessment. For increasing confidence in a storage estimate (determining CO2 capacity) other criteria including seal effectiveness (e.g. salinity and pressure above and below the caprock), minimum permeability, minimum threshold capillary pressure, and fracture propagation pressure of a caprock should be considered.

Injection Pressure

All geologic formations have a threshold pore pressure that will begin to propagate a fracture within the injection formation if exceeded. Some caprocks withstand this pressure and the fracture terminates at the caprock. Many relatively thick shales constrain the growth of a fracture; however, in addition to a threshold fracture pressure, shales have a capillary pressure threshold that if exceeded, will breech and allow an injected fluid to pass through it. Every formation (reservoirs and caprocks) has a pressure threshold that must be included in site-specific CO2 capacity estimates. However, this pressure constraint can be managed during the planning and operation stages of development and should not influence the CO2 resource estimate. A storage site with limited injection and/or pore pressure may reduce the CO2 capacity, but due to the number of injection wells required or length of pipeline, it may be economically the best choice. Moreover, drilling more wells can reduce the injection pressure into each well and keep reservoir pressure lower. Horizontal wells tend to have lower injection pressure as compared to vertical wells. Additionally, similar to natural gas storage, if regulations and economics are favorable, water production wells can be used to reduce

pressure and increase capacity at a particular storage site.

Injectivity

The daily or annual rate of CO2 that can be injected into a specific geologic formation is described or inferred by the term "injectivity." Relatively low or high injectivity for a formation is determined by the flow characteristics of the formation (e.g., pressure, permeability, and thickness), the type and size of wellbore drilled, the type of completion, and the number of wells.

No injectivity (zero) means there is no injection rate under any circumstances and as such

a geologic formation without injectivity cannot be considered a CO2 resource. However, a geologic formation with low injectivity that provides a CO2 injection rate greater than zero does provide the opportunity to store CO2 and is considered a CO2 resource.

For selecting and designing specific storage sites, a minimum acceptable injection rate for a well is required to meet the capture rate of CO2 emitted by the industrial site or utility.

For example, if injectivity and storage for 1 million tons per year from an industrial plant is desired for 30 years, the first step in selecting an injection site is to find a geologic unit or group of units as close to the emission site as feasible (to minimize transportation costs) that has adequate CO2 resource of at least 30 million tons. This industrial plant would likely have a budget (or economic limits) for capturing and storing CO2 on a per-ton basis (e.g, $15/ton). One of the next steps is to establish the most affordable means of injecting CO2 that does not exceed the $15/ton economic limit. One single well that could inject at least 1 million tons per year might be the least-cost option. However, if one well cannot provide this high rate of injectivity, additional wells or more expensive well types and completions will be considered.

INJECTIVITY

Injectivity describes the rate of injection that can take place in a given well and reservoir. As indicated in Table 9, injectivity is calculated based on a variety of data, including effective thickness over the injection interval, reservoir permeability, bulk connectivity, and reservoir pressure. The units of injectivity can vary with the data source, and include m3/day/Pascal/m and barrels/day/psi/ft. Much of the data exist for oil and gas fields, but would be available only on a limited basis for other targets, such as saline formations.

However, conventional wells, geophysical surveys, and core analysis would be able to provide reasonable estimates of injectivity for a project. Crucially, the injectivity depends on the interval of reservoir exposed to the wellbore; thus, injectivity may be increased through drilling long-reach horizontal wells or increasing well count. If there is damage to the reservoir at the wellbore that restricts injectivity, a small hydraulic fracture or acid stimulation may be applied to correct it.

The amount of data needed to properly quantify injectivity may vary by site, but it is highly unlikely that one well and a limited geological or geophysical survey could alone provide enough data to prove a reservoir has the needed injectivity. In many commercial applications, the degree of reservoir connectivity is not well understood for many years. Empirical and theoretical approaches will be important and can provide additional information and allow for consideration of multiple scenarios. In many cases, injectivity

data from neighboring oil, gas, and water wells, plus information from analogous reservoirs, can provide this information.

CAPACITY

Storage capacity is measured in units of volume (standard cubic feet, barrels). Several parameters are used to generate a capacity estimate, of which pore volume is the most important. Pore volume is a bulk term based on effective formation thickness and porosity. Estimates of pore volume can be derived from data generated through core analysis, wireline logs, or geophysical surveys. In some cases, 3-D seismic surveys may be combined with well data to estimate the formation porosity (Saggaf et al. 2003; Bachrach

and Dutta 2004). Often, a hydrodynamic simulation is needed to estimate overall storage capacity.

A second key parameter in capacity estimates is the utilization factor, or the effective pore volume. This is the fraction of the pore volume that would actually retain or store injected CO2. Utilization factor is a function of the fluid already present in the reservoir, and reservoir heterogeneity at all scales, ranging from pore-throat diameters to kilometer-scale connectivity, unit architecture, and residual phase (or capillary) trapping (Juanes et al. 2006; Ide et al. 2007). The utilization factor is also a function of the development strategy and well planning, such that capacity can be increased by more wells or better well design. Utilization factors vary from site to site, and can range between 5 and 50 percent, although most are less than 25 percent. An important consideration is that estimates of capacity are affected by reservoir heterogeneity, which determines the shape of the CO2 plume. Reservoir pressure constraints also affect the ultimate capacity of a reservoir.

Inherent in any discussion regarding capacity are the assumptions about storage mechanisms. Capacity assessments for saline formations sometimes assume or calculate a dissolved fraction of CO2 of 3-6 percent (Bachu and Adams 2003). In the case of a structural or stratigraphic closure, a substantial fraction of the pore volume might be filled with CO2 as a pure phase. Moreover, CO2 buoyancy may make it difficult to store CO2 in a substantial fraction of the available pore space. Finally, it may be extremely difficult to predict the amount of residual phase trapping (capillary trapping) without extensive sampling and analysis, and this is a focus of research efforts (Holtz and Bryant 2005). Site characterizations should be used to estimate the volume that would be stored as a dissolved phase, as a trapped residual phase, or as a trapped contiguous, buoyant phase (these proportions will also affect effectiveness or storage integrity). Statements of these assumptions would allow for easy updating of initial capacity estimates once new data become available. In practical terms, analog and empirical data sets should be considered for initial capacity estimates, but further scientific understanding regarding trapping mechanism assumptions is needed; this is an important area for additional research.

CO2 storage capacity is an estimate of the amount of CO2 that can be stored in subsurface geologic formations. Because of uncertainties inherent to subsurface evaluation, exact quantification of geological properties is not possible and therefore storage capacity is always at best an approximation of the amount of CO2 that can be stored. Storage capacity estimates therefore rely on the integrity, skill and judgment of the evaluator and are affected by the geological complexity, stage of exploration or development, amount of existing storage and of available data. Use of the definitions should sharpen the distinction between the various classifications and provide more consistent reporting.

Factors affecting CO2 storage capacity include the density of the CO2 at subsurface reservoir conditions, the amount of interconnected pore volume of the reservoir rock and the nature of the formation fluids. Due to the flow behaviour of CO2 in the subsurface, not all potentially available pore volume of the reservoir will become occupied during injection and migration, with flow preferentially occurring either upward due to buoyancy forces or laterally below low permeability zones (i.e. spreading out in thin layers beneath intraformational seals or the regional top seal rather than filling the entire pore volume). This can make CO2 storage capacity volumes difficult to calculate, particularly in the reservoir rocks underlying defined structural or stratigraphic closures, where much of the available rock pore volume can be bypassed by CO2 preferentially utilising higher permeability zones (Gibson-Poole, 2008). The potential CO2 storage capacity should therefore be assessed in terms of available interconnected pore space, accounting for factors such as injection rate, rate of CO2 migration, the dip of the reservoir, the heterogeneity of the reservoir and the potential for fill-to-spill structural closures encountered along the migration path. In addition, long-term prospects for storage, including residual trapping, dissolution into the formation water or mineral trapping (formation of new minerals) can also be considered (especially for estimating potential storage volume within deep saline formations) (Gibson-Poole, 2008). Such issues are best addressed by building geological models and running numerical flow simulations to test the importance of the various factors inherent to each specific site. The numerical flow simulations can give a more accurate assessment of how much of the available pore volume is actually used (sweep efficiency) in each particular type of trapping (Gibson-Poole, 2008).

Methodology for Storage Capacity Estimation in Saline Formations

DOE (2006) provides a relatively simple volumetric equation for the calculation of CO2 storage capacity in saline formations (Equation 1 and Table 1) based on the concept that CO2 occupies the pore space (or parts of it) within a permeable rock:

GCO2 = A hg tot E  (1)

Table 1: Volumetric equation parameters for capacity calculation in saline formations (from DOE, 2006).

The storage efficiency factor (E) adjusts total gross thickness to net gross thickness, total area to net area and total porosity to effective (interconnected) porosity actually containing CO2. Without E, Equation 1 presents the Total Pore Volume or maximum upper limit to capacity. Inclusion of E provides a means of estimating storage volume for a basin or region with the level of knowledge (uncertainty) in specific parameters determining the type of CO2 storage capacity estimated.

A reasonable maximum Prospective Storage Volume may be estimated by assuming CO2 injection wells may be placed regularly throughout the basin, or region, and multiplying the storage efficiency terms in Table 2 together to determine the storage efficiency factor for the basin or region. In Table 2, the first three terms An/At, hn/hg and φe/φtot are used to define the regional effective pore volume, and the next three terms EA, EI and Eg are used to define the fraction of that volume accessed by CO2 from injection wells. The remaining term Ed in Table 2 accounts for the proportion of the effective pore volume filled with CO2.

Ideally, the last four terms would be determined for each potential well site and combined to estimate the total storage volume; however, practically it may be easier to determine the average volume of pore space accessed by injecting CO2 into a single well and then multiplying by the expected number of wells.

Table 2: Terms included in storage efficiency factor for saline formations (from DOE, 2006).

Geoscience Characterisation: Injectivity

Injectivity is the rate at which CO2 can be injected into a given reservoir interval (a volume of CO2 per unit

of time) and the ability of the subsequent CO2 plume to migrate away from the injection well. Low

injectivity potential for an interval might result in a site with otherwise excellent capacity and containment

characteristics turning out to be uneconomic and, therefore, unsuitable for CO2 storage. During CO2

injection into a reservoir, the injectivity and nature of plume migration will depend on parameters such as

the viscosity ratio, injection rate and relative permeability. These parameters will in turn depend on

variables such as depositional environment and reservoir heterogeneity, stratigraphic architecture, postdepositional

diagenetic alteration, structural dip, fault distribution and fault seal capacity, pressure

distribution, and the nature of the formation fluids. Injectivity issues that can be assessed through the

geoscience characterisation include the geometry and connectivity of individual flow units, the nature of

the heterogeneity within those units (i.e., the likely distribution and impact of baffles such as interbedded

siltstones and shales) and the physical quality of the reservoir in terms of porosity and permeability

characteristics (Figure 7).

Reservoir quality can be assessed by evaluating core (porosity and permeability) and wireline logs

(petrophysical interpretations) of existing wells. Well data is one-dimensional and away from these points,

rock properties have to be inferred through well log correlation and use of analogues, guided by seismic

interpretation. Geological (static reservoir) models need to be constructed to provide likely reservoir

distribution and horizontal and vertical connectivity of flow units. These are best placed in a sequence

stratigraphic framework, which allow improved predictions of heterogeneity and barrier/baffle distribution.

Since important levels of heterogeneity can fall below seismic resolution, uncertainties in interpretation

increase with distance from the wells. These uncertainties are best handled by allowing for multiple model

realisations. Both favourable and unfavourable outcomes must be considered, with the overriding parameter that all realisations honour existing data. The uncertainties will greatly decrease if the site has

pre-existing boreholes or is in an area with 3D seismic coverage.

Evaluation of injectivity for a site should also incorporate examination of the mineralogical composition of

the reservoir for potential post-injection effects. CO2 dissolution into the formation water may result in

CO2-water-rock interactions, which may alter the mineralogy and pore system of the rock (Watson et al.,

2004). This can have important implications for injectivity, as mineral dissolution may lead to increased

porosity and permeability. However, it could also result in mobilisation of fine clay particles or the

precipitation of new minerals, either of which can occlude the porosity and permeability of the reservoir

rock, thereby decreasing injectivity. Determination of which, if any, of these reactions might occur is

dependent on the specific geological properties at each site.

Injectivity in Low Permeability Reservoirs

CO2 storage in saline formations has several advantages over other geological storage options (i.e. depleted

oil and gas reservoirs, coal seams), such as greater storage volume potential and less risk of compromising

existing resources. However, many deep saline formations suffer from low permeability, due either to

depositional processes (fine grained sediments and corresponding small pore throat sizes) or diagenetic

processes (post-depositional mineralogical modification of pores and pore throats). Numerical

investigations show that formation permeability is one of the main controlling parameters of CO2 storage in

geological formations (van der Meer, 1995; Law & Bachu, 1996; Ennis-King & Paterson, 2001).

For low permeability formations, numerical simulations show that there will be large pressure gradients

near the wellbore, which will restrict the injectivity considerably. Thus, high permeability formations

would be desirable for injection. However, high permeability formations would allow relatively fast

migration of CO2, lowering the proportion of CO2 trapped behind the main plume by residual trapping.

Slower movement provides greater residence time and thus several advantages such as enhancement of the

dissolution potential of CO2 in formation water and high volumes of CO2 trapped by capillarity (Flett et al.,

2005). Bachu et al. (1994) suggest that while higher permeability may be required near the wellbore to

increase injectivity, lower permeability is desirable outside the radius of influence of the wellbore to

increase residence times and encourage the rate of residual trapping, dissolution and mineral trapping.

Geoscience Characterisation: Containment

Containment refers to the retention of injected CO2 within the subsurface site relative to the overall risk of

its escape. Containment is an issue in CO2 storage because injected supercritical CO2 is less dense than

water and has the tendency to be driven upward due to buoyancy forces. Loss of containment can occur

through vertical fluid migration via the top seal, faults/fractures and existing well penetrations, or lateral

migration to a point where stratigraphic loss of seal occurs. Possible containment issues, therefore, include

the distribution and continuity of the seal, the seal capacity (maximum CO2 column height retention), CO2-

water-rock interactions (potential for mineral trapping), potential migration pathways (structural

orientations and dips), distribution and extent of intraformational seals (acting as localised barriers and

baffles to flow), hydraulic gradient (formation water flow direction and rate) and the integrity of the

reservoir and seal (rock strength, fault/fracture stability and maximum sustainable pore fluid pressures)

(Figure 7). Migration through existing well bores and leaking faults are considered the greatest containment

risks in CO2 storage (Celia & Bachu, 2003).

CO2 injection into the geological subsurface increases the formation pressure, which can then potentially

reactivate pre-existing faults or generate new fractures. Opening of fractures or causing slip (movement) on

faults could lead to a loss of containment (Holloway & Savage, 1993; Bergman & Winter, 1995; Streit &

Hillis, 2004). Thus, an understanding of the pressure regime and geomechanical modelling needs to be

undertaken to estimate maximum sustainable fluid pressures for CO2 injection that will not induce

fracturing and faulting. This requires the determination of prevailing stresses, fault geometries and rock

strengths. Details of geomechanical modelling techniques are described in Streit and Hillis (2004).

The properties of the seal, both in terms of CO2 retention capacity as well as distribution and continuity,

can be assessed by a combination of laboratory and sequence stratigraphic analyses. The seal capacity of regional top seals and localised intraformational seals is calculated by determining the capillary pressure

properties of the sealing rock and the physio-chemical properties of both the CO2 and formation water (e.g.

density, wettability and interfacial tension). Seal capacity is best assessed by Mercury Injection Capillary

Pressure (MICP) analysis. MICP tests are a measurement of the pressures required to move mercury

through the pore network system of a core sample. The air/mercury capillary pressure data can then be

translated to equivalent CO2/brine data at reservoir conditions and converted into seal capacity for CO2,

expressed as the column height that the seal rock would be capable of holding (sealing). Standard

procedures for MICP analysis are reviewed by Vavra et al. (1992), Dewhurst et al. (2002) and Daniel and

Kaldi (in press).

CO2 introduced into a reservoir system can also chemically interact with the host rock. Detailed reservoir

petrology, water chemistry and pressure-temperature conditions provides information necessary for

modelling of potential mineral reactions associated with CO2, including dissolution, alteration and

precipitation. Whereas for injectivity, CO2-water-rock interactions could either enhance or reduce the

injectivity through mineral dissolution or mobilisation, mineral precipitation can lead to mineral trapping of

CO2 and therefore increased containment security as the CO2 is permanently trapped (Bachu et al., 1996;

Perkins & Gunter, 1996; Watson et al., 2004; Watson & Gibson-Poole, 2005).

Sequence stratigraphic assessment of both the reservoir and the seal can predict facies distribution even in

areas of poor data coverage. This is based on predictable occurrence of strata packages with changes in

potential space available for sedimentation and sediment supply, which can be inferred from subsurface

wireline and seismic data. In a homogeneous reservoir, the buoyancy of the free-phase (immiscible) CO2

will cause it to migrate vertically up to the top of the reservoir. Stratigraphic heterogeneities, such as

intraformational siltstones and shales, have the potential to reduce this type of flow and create a more

tortuous migration pathway. Once the CO2 plume has reached the top of the reservoir, the structural dip and

geometry at the base of the overlying sealing unit will have a strong influence on the subsequent migration

direction and rate. The details of the exact geometries and heterogeneities at the reservoir/seal boundary

can prove especially important and can result in unexpected plume migration and possible loss of

containment. Trapping mechanisms that can be identified through geoscience characterisation include

physical structural closures and stratigraphic pinch-outs, and potential hydrodynamic (Bachu et al., 1994)

or 'rate seal' traps.

An understanding of the existing formation water flow system within a geological reservoir is important for

site characterisation as the rate and direction of flow of the formation water system will impact the

effectiveness of hydrodynamic trapping, as well as dissolution and residual trapping along the migration

pathway. Hydrodynamic modelling assesses the vertical communication between reservoir units, and hence

the effectiveness of a seal, and provides information about the horizontal hydraulic continuity (e.g. fault

compartments) and the impact of low permeability zones. In areas where there has been fluid removal from

the subsurface (e.g. water extraction or oil production), an assessment of the pre-production hydrodynamic

regime is used to provide an understanding of the long-term (hundreds to thousands of years) influence of

the formation water flow systems on the injected CO2. However, it is also necessary to interpret the

present-day hydrodynamic regime, as it may have been affected by hydrocarbon/water production-induced

pressure decline. The present-day (post-production) hydrodynamic regime can be used to evaluate the

potential short-term (tens to hundreds of years) influence on the predicted migration pathway of CO2

immediately after injection. The past and present formation water flow systems can be characterised from

pressure-elevation plots and hydraulic head distribution maps using standard hydrodynamic analysis

techniques as presented by Dahlberg (1995), Bachu (1995), Otto et al. (2001) and Bachu and Michael

Geoscience Characterisation: Capacity

Storage capacity evaluates the commercially available pore volume for CO2 storage at a particular site. This

is controlled by parameters such as the size of the containment area, the thickness of the reservoir, the

effective porosity and the density of the CO2. Storage capacity is discussed in detail earlier in this report.

7. Riscuri associate stocarii geologice a CO2

Risks associated with CO2 storage in geological reservoirs

CO2 and/or CH4 leakage from the reservoir to the atmosphere

Micro-seismicity due to pressure and stress changes in the reservoir, causing small earth quakes and faults

Ground movement, subsidence or uplift due to pressure changes in the reservoir

Displacement of brine from an open reservoir to other formations, possibly containing fresh water

It is important to determine what the risks are when storing CO2 underground.

CO2 and CH4 leakage

Depends on thickness of overlying formations and trapping mechanisms and occurs when:

Inability of cap rock to prevent upward migration, due to:

too high permeability (possibility for diffusion of CO2)

dissolving of cap rock by reaction with CO2

cap rock failure (fracturing and faulting due to over pressuring of the reservoir)

Escape through (old) wells through:

Improper plugging

Diffusion through cement or steel casing

Dissolving of CO2 in fluid that flows laterally

Local and global effect of CO2 leakage

Local: Health effects at elevated CO2 concentration (accumulation of CO2 can occur in confined areas)

Local: Decrease of pH of soils and water, causing:

Calcium dissolution

Increase in hardness of the water

Release of trace metals

Global: leakage reduces the CO2 mitigation option, effect depends on stabilization of greenhouse gas concentration

Stabilization targets

Extend and timing of CO2 storage (simulation models)