Modeling of deep fracture zone opening and transient ground surface uplift at KB-502 CO2 injection well, In Salah, Algeria

International Journal of Greenhouse Gas Control 12 (2013) 155–167

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Modeling of deep fracture zone opening and transient ground surface uplift at KB-502 CO2 injection well, In Salah, Algeria Antonio P. Rinaldi ∗ , Jonny Rutqvist Lawrence Berkeley National Laboratory, Earth Sciences Division, CA, USA

a r t i c l e

i n f o

Article history: Received 16 August 2012 Received in revised form 27 October 2012 Accepted 29 October 2012 Available online 20 December 2012

a b s t r a c t The Krechba gas field at In Salah (Algeria), the site of the first industrial scale on-shore CO2 storage demonstration project, is also known for satellite-based ground-deformation monitoring data of remarkable quality. In this work, we focus on the In Salah injection well KB-502, where a double-lobe uplift pattern has been observed in the ground-deformation data. On the basis of previous numerical results, semi-analytical inverse deformation solutions, and seismic analyses, we explain this pattern of uplift as resulting from injection-induced deformation in a deep vertical fracture zone. In this study, we simulate a fracture zone characterized by high permeability and low mechanical stiffness, which activates after a few months of injection, causing irreversible changes in permeability. We study the transient evolution of uplift using the observed injection rate and compare it to the field Interferometric Synthetic Aperture Radar (InSAR) data using the displacement in the satellite line-of-sight. We also carry out a sensitivity study, analyzing the extent of the fracture zone, particularly its height from the reservoir depth. Our analysis supports the notion that the fracture zone is confined within the caprock and does not penetrate into the overlying aquifer. Published by Elsevier Ltd.

1. Introduction Geological carbon sequestration (GCS) is one of several technologies considered for reducing CO2 emissions to the atmosphere (Pacala and Socolow, 2004). One GCS option is the injection of supercritical CO2 directly into deep saline geological formations under an overpressure that may cause detectable ground surface deformations. Scientists are at present looking to geomechanical modeling to study how such ground-surface deformation can be related to injection-induced reservoir and deep-structural responses. Rutqvist (2012) recently provided a state-of-the-art review on the geomechanics associated with geological carbon sequestration in deep sedimentary formations. Geomechanics plays a key role in the understanding of reservoir stress–strain and microseismicity (e.g., Vasco et al., 2008, 2008; Mathieson et al., 2009; Rutqvist et al., 2010; Zhou et al., 2010; Myer and Daley, 2011), well integrity (e.g., Tsang et al., 2008), caprock sealing performance (e.g., Rutqvist and Tsang, 2002; Evans, 2009; Vilarrasa et al., 2010), and the potential for fault reactivation and notable (felt) seismic events (e.g., Cappa and Rutqvist, 2011; Nicol et al., 2011; Mazzoldi et al., 2012).

∗ Corresponding author at: Lawrence Berkeley National Laboratory, Earth Sciences Division, 1 Cyclotron Road, Berkeley, CA, USA. E-mail addresses: [email protected] (A.P. Rinaldi), [email protected] (J. Rutqvist). 1750-5836/$ – see front matter. Published by Elsevier Ltd. http://dx.doi.org/10.1016/j.ijggc.2012.10.017

Moreover, there are concerns that fracturing or fault reactivation may lead to CO2 leakage (e.g., Mazzoldi et al., 2012, and references therein) and that the overpressure needed to inject the CO2 into saline formations may displace the brine either vertically (e.g., Birkholzer et al., 2011; Oldenburg and Rinaldi, 2011) or laterally (e.g., Nicot, 2008), potentially degrading shallower groundwater aquifers. The In Salah CO2 storage project (a joint venture among Statoil, BP, and Sonatrach) is one of the most important sites for understanding the geomechanics associated with carbon dioxide injection. At the Krechba gas field (In Salah, Algeria), over a period of about 8 years, 0.5 to 1.0 million tons of CO2 per year have been injected into a 20 m thick water-filled carboniferous formation with a relatively low permeability, through horizontal wells (about 1–1.5 km long at a 2 km depth), ensuring adequate flow rate. The CO2 is coproduced with hydrocarbons, then separated from these hydrocarbons to be re-injected through three wells (KB-501, KB502, and KB-503) into the saline formation, in the water leg of the Krechba gas field. Fig. 1a shows the position of both the production and injection wells. Interferometric Satellite Aperture Radar (InSAR) data evaluated for the first years of injection (2004–2007) show a ground-surface uplift of 5–10 mm per year for each of the injection wells (Fig. 1b). Using both semi-analytical (Vasco et al., 2008, 2008) and coupled numerical modeling (Rutqvist et al., 2010), investigators have explained the ground uplift, which extended laterally for several

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Fig. 1. (a) Krechba gas field at In Salah, Algeria. The figure highlights position of the production and injection wells; (b) InSAR data of range change evaluated by TeleRivelamento Europa (TRE); (c–e) three independent InSAR analyses of KB502 double-lobe uplift: TRE, JGI, and MDA/Pinnacle, respectively.

kilometers, by pressure changes and associated vertical expansion within the 20 m injection zone. However, heterogeneities such as minor faults and fractures may affect the observed uplift at the ground surface. Recently, several studies (using inversion techniques or forward numerical modeling) related the ground displacement data to fracture zones intersecting the CO2 storage formation (Ringrose et al., 2009; Mathieson et al., 2009; MacNab et al., 2010; Vasco et al., 2010; Morris et al., 2011; Rutqvist et al., 2011; Fokker et al., 2011; Vasco et al., 2011; Gemmer et al., 2012). Furthermore, the presence of minor faults and fractures may influence the pore-pressure and CO2 plume distribution (Ringrose et al., 2009; MacNab et al., 2010; Bissell et al., 2011; Durucan et al., 2011), and the reactivation of pre-existing faults or fractures may cause changes in permeability distribution within the injection zone (Shi et al., 2012). The opening (or reactivation) of a fault zone may produce a double-lobe pattern of deformation, as in the case observed through satellite-based measurements at the KB-502 injection well. Both semi-analytical inverse deformation analysis (Vasco et al., 2010; Vasco et al., 2011) and coupled numerical modeling of fluid flow and geomechanics (Rutqvist et al., 2011) have shown that this pattern of displacement can be explained by injection-induced deformation in a deep vertical fracture zone or faults intersecting the injection well and extending a few hundred meters up to a depth of 1600 m. Ringrose et al. (2009) suggested that the permeability at KB-502 is affected by the degree of fracturing and by an intersecting fault.

The presence of such a fault, or fracture zone, has been also confirmed by a recent 3D seismic survey (Gibson-Poole and Raikes, 2010; Wright, 2011). Here, we present modeling results from a forward analysis of the KB-502 injection well, using the coupled fluid flow and geomechanical simulator TOUGH-FLAC (Rutqvist et al., 2002). Starting from the results obtained by Rutqvist et al. (2010, 2011), here we implement a new, finer grid within a larger domain (20 km × 20 km, centered at the horizontal well) to enable a detailed analysis of deformation in the fracture zone region and of the double-lobe uplift. While the previous analyses in Rutqvist et al. (2010, 2011) were conducted using a constant overall average rate, here we study the transient evolution of uplift using the monitored injection rate as a model input and assuming the activation or creation of a fracture zone (or damage zone) after some months of CO2 injection. Such an activation or creation of a fracture zone may produce changes in reservoir permeability, simulated as a step function in time in order to match the measured bottomhole pressure at the KB-502 well. Calculated displacements are then compared to the data, both along two profiles and in time. We then conclude with a sensitivity study, to evaluate the effects of changing the extent of the fracture zone. One objective of such a sensitivity study is to explore whether it is possible to constrain the upward extent of the fracture zone – whether we can determine if the zone could extend through the overburden and into the overlying groundwater aquifer.

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Fig. 2. Results from 2009 3D seismic survey at Krechba (figure from Rutqvist (2012)) showing a linear feature and its correlation with ground uplift, natural fractures, and stress orientation: (a) 3D seismic contour at the top of C20.1 (lower caprock) from Gibson-Poole and Raikes (2010) and Wright (2011); (b) seismic contour and ground displacement from InSAR data of MDA/Pinnacle (Wright, 2011; Davis, 2011).

2. Ground uplift evolution at KB-502 injection well Fig. 1b shows an InSAR image (from TeleRivelamento Europa, TRE) of the rate of distance change (uplift) in the satellite’s line-ofsight after 3 years of operation. The rate of distance change above injection wells KB-501, KB-502, and KB-503 is as high as 5 mm/year. In the gas field, located between the three injection wells, small subsidence has been associated with production-induced pressure depletion (Rutqvist et al., 2010; Rucci et al., 2010). In this study, we focus on the deformation produced at the injection well KB-502. Three independent satellite analyses (TRE and Vasco et al. (2010), Onuma and Ohkawa (2009), and MDA/Pinnacle (Davis, 2011)) show the same complex pattern of deformation (Fig. 1c–e); the uplift pattern features two parallel uplift lobes rather than one single uplift lobe. As mentioned, this double-lobe uplift has been interpreted as arising from an opening of a vertical tensile feature at the depth of the reservoir (MacNab et al., 2010; Vasco et al., 2010; Rutqvist et al., 2011). This interpretation would confirm a strongly heterogeneous permeability near KB-502, affected by fracturing and intersecting faults, as suggested by Ringrose et al. (2009). Recently, a 3D seismic analysis also confirms the presence of such a fault/fracture zone, intersecting the injection well (see Fig. 2 and Gibson-Poole and Raikes, 2010). Some recent studies suggest that such a fault/fracture zone was activated because of an increase in the bottomhole pressure. Bissell et al. (2011) in analyzing the injection data, found an abrupt increase in the injectivity when the estimated bottomhole pressure exceeded 28.6 MPa, indicating a sudden fracture opening. Another detailed analysis of the injectivity was recently performed by Shi et al. (2012), who interpreted increases in injectivity as resulting from the tensile reactivation of a pre-existing fault/fracture zone. Their analysis indicated that the fault/fracture zone reactivated when the injection pressure peaked (at the beginning of 2006), and (using changes in the fracture transmissibility) they obtained a precise match between simulated and calculated bottomhole pressure at KB-502. Fig. 3 shows the temporal evolution of the ground uplift at KB502. Although it is not possible to determine when the fracture zone activates from the displacement evolution at a point located above the well (Fig. 3a), an analysis of the deformation pattern shows that a double lobe first appears around January/February 2006 (Fig. 3d), as suggested by Shi et al. (2012). Injection at KB-502 started in April 2005 (Fig. 3b). The transient evolution shows a ground uplift of less than 5 mm during the first 6

months of injection (April–September 2005, Fig. 3c). Then, around September 2005, the injection pressure increases sharply (see next section); the fracture zone was possibly activated in 2006, with the ground uplift reaching a value of 10 mm, along with a first sighting of a double-lobe uplift pattern (Fig. 3d). With continued injection, the ground uplift kept increasing and after 2 years of injection reached a displacement of around 15 mm (Fig. 3e). The KB-502 well was shut in mid-2007 after almost 3 years of injection, but almost 20 mm of ground uplift remained 1 year after the shut in (Fig. 3a and f). Then a small subsidence phase occurred, but at a rate much lower than the uplift phase. 3. Numerical modeling Numerical simulations were carried out using the TOUGHFLAC/ECO2N simulator for coupled deformation and fluid flow (a detailed description of the TOUGH2/ECO2N model and its coupling with FLAC3D can be found elsewhere – Pruess et al., 1999; Rutqvist et al., 2002; Pruess, 2005; Itasca, 2009; Rutqvist, 2011). We used a three-dimensional grid, 20 km × 20 km wide and 4 km deep (Fig. 4a). Following the model proposed by Rutqvist et al. (2010,][and references therein), the model consists of four layers: (1) cretaceous sandstone and mudstone overburden (0–900 m), (2) carboniferous mudstone (caprock, 900–1800 m), (3) C10.2 sandstone (CO2 reservoir, 1800–1820 m), and (4) D70 mudstone basement (below 1820 m). Table 1 presents the values for the hydraulic properties used in the coupled hydromechanical simulations. These sets of properties are chosen considering both numerical results (Rutqvist et al., 2010; Shi et al., 2012) and in situ observation (Iding and Ringrose, 2010). Parameters for capillarity pressure and relative permeability are taken from former numerical modeling studies of CO2 injection in a deep saline aquifer (Zhou et al., 2008; Pruess et al., 2001). Mechanical properties are based on Statoil log analysis (Gemmer et al., 2012) and are listed in Table 2. Values in the table are slightly modified in depth when compared to the original Statoil log, in order to fit our geological model. Initial temperature, pressure, and stress gradient are derived from site investigations at Krechba. With these gradients, at reservoir depth we have a temperature of about 90 ◦ C and an initial pressure of 17.9 MPa. Lateral boundaries are set to constant temperature, fluid pressure, and stress. The bottom (about 4 km) is a no-flow, no-vertical-displacement boundary. We consider a linear poroelastic medium; thus, no failure processes like fracturing or

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Fig. 3. (a) Transient evolution of vertical ground displacement at KB-502 well. (b–f) The black star indicates the point for the transient evolution results. First sighting of the double lobe uplift after about 8 months of CO2 injection (January/February 2006) (d). Injection started in April 2005, and lasted for about 2 years. The shut in occurred in mid-2007. InSAR data evaluated by MDA (MacDonald, Dettwiler and Associates Ltd.) Canada and Pinnacle Technology.

shear are taken into account. Initial stress conditions follow the regional data, which show a strike-slip regime, within which the maximum horizontal stress (NW–SE) is greater than the vertical stress (Iding and Ringrose, 2010). Hydraulic parameters are kept constant in all the geological units, with the exception of the CO2 injection zone permeability (see below). A simulation is composed of an initial period of 5 months with intact layers, then an opening in the caprock as an activation of an orthotropic zone (fracture zone) to explain the double-lobe uplift behavior. The following subsections provide details related to the applied fracture zone, injection and reservoir permeability, and deriving bottomhole pressure. 3.1. Opening and fracture zone Seismic 3D analysis has shown the presence of a linear feature that is visible up to a few hundred meters above the injection zone (Gibson-Poole and Raikes, 2010; Wright, 2011). As shown by Rutqvist (2012), and here reproduced in Fig. 2, this linear feature is parallel with the dominant orientation of natural fractures, perpendicular to the minimum horizontal compressive stress, and very well correlated with the double-lobe uplift. This correlation may indicate the opening or creation of multiple fractures in a wider fracture zone (or damage zone). An inverse analysis of the double lobe pattern suggested (even before the 3D seismic analysis

results were available) that an opening of a tensile zone may explain the observed pattern of deformation (Vasco et al., 2010). Geomechanical numerical modeling also explained this double-lobe uplift as caused by pressure inflation of a vertical feature (Morris et al., 2011; Rutqvist et al., 2011). For example, Rutqvist et al. (2011) simulated a vertical feature about 50 m wide, extending up to 200 m from the reservoir, and characterized by strongly anisotropic elastic moduli. Their simulation showed that the pressure inflation caused an opening of about 8 cm at reservoir level, resulting in a doublelobe uplift at ground surface with a magnitude of about 2 cm after 2 years of injection, with the two lobes laterally spread about 1.5 km apart. Here we simulate such a fracture zone/opening as a highly permeable zone, 80 m wide, with a series of three 20 m wide zones, separated from each other by 10 m of intact caprock (see Fig. 4b). The same results (at least from a geomechanical point of view) would be achieved considering only a 80 m wide fracture, hence simulating this fracture zone as a one grid block wide region. Such a modeling would then decrease the precision in simulating the pressure variations. We arbitrarily chose to model three zones, but the results would hold even using a higher (or lower) number of zones, keeping constant the total width. Moreover, assigning very soft mechanical properties over the entire 80 m resulted in localized very large (unrealistic) displacements at some numerical nodes that adversely affected the entire surface uplift calculation. The fracture

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Fig. 4. (a) Mesh grid used in the coupled model TOUGH-FLAC (about 30,000 gridblocks); and (b) enlargement of the injection area and fracture zone.

Table 1 Hydraulic properties used in the numerical modeling for the four layers. Permeability of the injection zone (reservoir) changes with time (see Fig. 5b). Layer

Shallow

Caprock

Injection zone

Basement

Depth (m) Effective porosity  Permeability  (m2 ) Residual CO2 saturation Residual liquid saturation Van Genuchten (1980), P0 (kPa) Van Genuchten (1980), m

0–900 0.1 10−12 0.05 0.3 19.9 0.457

900–1800 0.01 10−21 0.05 0.3 621 0.457

1800–1820 0.17 Variable 0.05 0.3 19.9 0.457

>1820 0.01 10−19 0.05 0.3 621 0.457

Table 2 Geomechanical properties based on Statoil log analysis (Gemmer et al., 2012) and slightly modified to fit the mesh dimensions. Note the use of more layers than the hydrogeological model. Layer

Young’s modulus E (GPa)

Shallow aquifer (Cretaceous) Main Caprock, (Mudstone, C20) Lower Caprock, (C20.1–C20.3) Tight sandstone (C10.3) Reservoir (C10.2) Underburden (Devonian)

3 5 2 20 10 15

0.25 0.3 0.3 0.25 0.2 0.3

zone extends up to 350 m above the CO2 injection zone, 3500 m long in the x-direction (roughly NW–SE in the field direction). We simulated this fracture zone using an orthotropic model, characterized by a strong plane anisotropy: the porous medium can deform more normally to the xz-plane rather than in the z-direction. An orthotropic model accounts for three orthogonal planes of elastic symmetry. The incremental strain–stress relation have the form:

⎡ 1 xy xz ⎤ − − ⎛ ⎞ ⎢ Ex ⎞ Ey Ez ⎥ ⎛ xx xx ⎢ yx ⎥  1 yz ⎥ ⎜ ⎜ ⎟ ⎢ ⎟ − − yy ⎟ ⎜ yy ⎟ = ⎢ Ey Ex Ez ⎥ ⎥=⎜ ⎝ ⎠ ⎢ ⎝ ⎠ ⎢ zx zy 1 ⎥ ⎢ ⎥ zz zz − − ⎣ Ex Ey Ez ⎦ ⎡ 1 ⎢ Gxy 2xy ⎢ ⎜ ⎟ ⎢ ⎝ 2zx ⎠ = ⎢ ⎢ ⎣ 2zy ⎛

(1)

⎤

⎞

1 Gxz

⎛ ⎞ ⎥ xy ⎥ ⎥ ⎜ ⎟ ⎥ = ⎝ zx ⎠ ⎥ ⎦ zy 1 Gyz

Poisson’s ratio 

(2)

Depth (m) 0–900 900–1650 1650–1780 1780–1800 1800–1820 1820–4000

where Eq. 1 refers to the volumetric components and Eq. 2 is for the shear components (Itasca, 2009). This orthotropic model, used only for the fracture zone, involves nine independent elastic constant, and the values we used for a base case simulation are listed in Table 3. The fracture-zone properties were determined by model calibration to achieve a good match with field data for a fracture zone 3500 m long and extending 350 m above the reservoir. The fracturezone dimensions are consistent with current interpretations of the 2009 3D seismic survey. They are also consistent with the inverse semi-analytical analysis by Vasco et al. (2010) and Vasco et al. (2011), as well as those of coupled numerical modeling by Rutqvist et al. (2010), Morris et al. (2011), and Gemmer et al. (2012). However, these analyses, such as in Morris et al. (2011), concluded that it was difficult to constrain the height of the fracture zone. Moreover, an alternative inverse semi-analytical analysis by Davis (2011) indicated the possibility of surface deformations induced by pressure changes occurring as shallow as 900 m below the ground surface. The permeability of the fracture zone is a key element, and its field initial value is unknown. Here we consider a spatially uniform permeability of 10−13 m2 , i.e., a high value in agreement with the permeability of a highly fractured zone. The total volume of this fracture zone is small when compared to the total volume of the reservoir, hence the use of a higher (or lower) permeability within

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Table 3 Fracture zone properties. We simulated the fracture zone (80 m-wide in total) as a series of three 20 m-wide zones with orthotropic mechanical properties, separated each other by a 10 m-wide intact caprock (see Fig. 4b). Fracture zone activate after about 5 months of injection. Before activation properties are the same as the caprock (see Tables 1 and 2). Ej Young’s modulus in direction j, Gij shear modulus in planes parallel to axes i–j, ij Poisson’s ratio characterizing lateral contraction in direction i when tension is applied in direction j. Property Permeability Porosity Length Height from reservoir Width single fracture Total width fracture zone Ex Ey Ez Gxy , Gxz , Gyz xy , xz yz

Value 10−13 m2 1% 3500 m 350 m 20 m 80 m 0.17 GPa 0.14 GPa 1.0 GPa 1.0 GPa 0.18 0.25

the fracture zone has a low impact on the average permeability of the reservoir, producing negligible changes on the simulated displacement as long as the match with the field pressure is kept. We are aware that the assumption of a spatially uniform permeability may produce a trade-off between fracture-zone geometry and flow properties. The propagation of the fracture as a function of stress, and hence a stress-dependent permeability within the fracture zone, will be the subject of future studies. For our analysis, starting with the base-case fracture zone dimensions, we conducted a detailed transient study of both injection parameters and surface deformations to explore the possibilities of constraining the height of the fracture zone. An important part of this exploration is determining the stress-dependent hydraulic properties evolving along with the activation or creation of the fracture zone, as presented below in the next section. 3.2. CO2 Injection, reservoir permeability, and bottomhole pressure Following the model proposed by Rutqvist et al. (2011), CO2 injection was conducted through a 1 km long well, located within the 20 m thick CO2 reservoir. In this study, however, the injection well, while not explicitly considered in the simulation of the mechanical effects, produces a pressure increase in the reservoir gridblocks, connected to the well through the white area in Fig. 4b. In contrast to past studies (Rutqvist et al., 2010, 2011), which considered a constant injection rate, here we use a variable injection rate. As shown in Fig. 5a, the injection rate simulated (red line in the figure) closely follows the real values of CO2 injected at KB-502 during the period 2005–2007 (black line in the figure). The permeability of the CO2 injection zone plays a key role in evaluating the bottomhole pressure. In order to match the bottomhole pressure at KB-502, we assumed that the permeability of the reservoir may change with time, as the pressure evolves and fractures activate. Fig. 5b shows the values we used for the reservoir permeability and the zone connected to the injection well (white zone in Fig. 4b). At the beginning of the simulation, we assumed a homogeneous permeability for the reservoir (8 × 10−15 m2 ). When the fractures activate, the permeability within them change from the caprock value (10−19 m2 ) to 10−13 m2 , and at the same time we assigned a 2.5-times increase in the reservoir permeability, first in the elements connected to the injection well (i.e., where the fracturing/reactivation first occurs), and then after some months (i.e., when the pressure perturbation propagates as well as the fracturing/reactivation front) in the entire reservoir (Fig. 5b). The small changes in permeability at later times are needed to achieve the

Fig. 5. (a) Simulated injection rate with TOUGH-FLAC (red line) and measured CO2 rate at KB-502 (black line); (b) assumed changes in permeability at CO2 injection zone level for the entire reservoir (blue line) and for the zone connected to the injection well (red line). The biggest change (2.5 times of initial value) occurs when the fracture zone activates, after 5 months of injection; (c) Measured wellhead pressure (WHP, red line), calculated bottomhole pressure (BHP, green line), and simulated BHP pressure with TOUGH-FLAC (blue line). Throughout our formulation we obtained an excellent math between calculated and simulated pressures. (For interpretation of the references to color in this figure legend, the reader is referred to the web version of the article.)

bottomhole pressure fit (Fig. 5c, blue line). The same procedure was recently used by Shi et al. (2012): using a very detailed discretization in time for dynamic fracture transmissibility, they obtained a very good match between simulated and observed bottomhole pressure. Although we change the permeability as a time-step function, the values we use are in agreement with a stress-dependent permeability formulation. Assuming a dual continuum model, Liu and Rutqvist (2012) present a relationship between stress and elastic strain, accounting for the natural strain and considering rock heterogeneities by dividing a rock body into two distinct parts: a “hard” part and a “soft” part corresponding to the pore volume subject to fracturing or cracking. They derive a relationship that enables relating the fracture aperture b and porosity to the effective normal stress: f b = = e,f + t,f exp b0 0,f

 −

f Kt,f

 (3)

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Fig. 6. Results of the TOUGH-FLAC simulation after about 2 year of CO2 injection (December 2006). Note that the x, y-plane in the model does not correspond to the NS-EW plane, hence here the results are rotated to permit a comparison with the measurements at KB-502. (a) Simulated vertical ground displacement; (b) simulated horizontal displacement in the NS direction; (c) simulated horizontal displacement in the EW direction. The black solid line indicates the injection well position, the green dashed line indicates the linear feature. (For interpretation of the references to color in this figure legend, the reader is referred to the web version of the article.)

where b is the aperture, f is the porosity of the fractured medium,  e,f and  t,f represent volumetric fractions of the hard and soft parts, respectively,  f is the effective stress, and Kt,f is the bulk modulus of the soft part. The index 0 refers to unstressed conditions. Here we calculated the effective stress ( f ) accounting for the calculated bottomhole pressure (Fig. 5c, green line), and the resulting permeability changes calculated with Eq. 3 are shown in Fig. 5b (black line), assuming the ratio  e,f / t,f =8 and Kt,f =5.5 MPa. We are aware that the permeability and the stress are closely related, and further studies in the future will include such a coupling. However, the values we chose were not totally arbitrary; they closely follow a constitutive law (Liu and Rutqvist, 2012), and permit a good match with the bottomhole pressure. The bottomhole pressure, while not directly measured in the field, can be estimated using the measured injection pressure (wellhead pressure) and temperature, along with the injection rate. In this case, a separate wellbore simulation was conducted to calculate the bottomhole pressure and temperature (Rutqvist et al., 2011). In this model simulation, we used Berkeley Lab’s T2 well simulator, based on TOUGH2 multiphase flow simulator, which models multiphase flow and heat transport within the well and heat exchange with the surrounding formation (Pan et al., 2011). When CO2 injection was relatively high, the calculated bottomhole temperature was about 40 ◦ C cooler than the formation temperature. (The estimated bottomhole pressure and temperature calculated with the T2 well simulator are consistent with independent calculation results using a commercial well simulation package – Bissell

et al., 2011). Fig. 5c shows both the calculated bottomhole pressure (green line) and the measured wellhead pressure at KB-502 (red line). The blue line in the figure represents the simulated bottomhole pressure. We obtained a very good match between calculated and simulated bottomhole pressure by assigning relatively small changes in average reservoir permeability. These changes could be related to the opening of small fractures caused by the CO2 injection and associated effective stress changes within the reservoir. Although the match of the bottomhole pressure is excellent during the injection phase, small differences arise after shut in. 4. Results Resulting vertical and horizontal displacements for the simulation described above are shown in Fig. 6. With the assumed mechanical model (see Table 2) and properties for the fracture zone (see Table 3), the simulation resulted in a vertical displacement of about 15 mm (Fig. 6a) after about 2 years of CO2 injection (618 days of injection, corresponding to Dec, 23, 2006, see Fig. 3). The vertical displacement features a double-lobe uplift, with two similar lobes, symmetric with respect to the fracture zone (green dashed line in Fig. 6a), and laterally spaced at about 1.5 km apart. An enlargement of the simulated vertical ground displacement is shown in Fig. 7a. Although the simulation was performed in an x, y, z-coordinate system, here we present the results on a NS–EW plane for easier comparison with measured InSAR displacement. For the same purpose, horizontal displacements are presented as NS- and

Fig. 7. (a) Enlargement of the simulated vertical ground displacement at KB-502; (b) displacement in the satellite line of sight (LOS) for the comparison with InSAR measurements. The considered LOS vector is (0.35, −0.08, −0.93). Blue and green dashed lines represent the profile for the comparison between simulation results and InSAR measurements, at 500 m and 1700 m from the injection well, respectively. The black solid line indicates the injection well position, the white dashed line indicates the linear feature. (For interpretation of the references to color in this figure legend, the reader is referred to the web version of the article.)

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Fig. 8. Comparison between simulated displacement and InSAR data. (a) Resulting displacement in the satellite line of sight. Black segment represents the KB-502 injection well. White, dashed segment represents the simulated fracture zone direction. Green and blue, dashed lines represent the direction of two profiles for the comparison with InSAR data at 500 m and 1700 m from the injection well, respectively. (b) InSAR data after 618 days of injection (23 December 2006). (c) Comparison between simulation (red line) and InSAR data (green, dashed line) along the profile 1 (500 m from the injection well). (d) Comparison between simulation (red line) and InSAR data (green, dashed line) along the profile 2 (1700 m from the injection well). InSAR data evaluated by MDA (MacDonald, Dettwiler and Associates Ltd.) Canada and Pinnacle Technology. (For interpretation of the references to color in this figure legend, the reader is referred to the web version of the article.)

EW-components, rather than x- and y-components. We considered a fracture zone oriented in the NW–SE direction; the resulting horizontal displacement, shown in Fig. 6b and c for the NS-component and EW-component, respectively, is about 8 mm, which is within the same order of magnitude of results reported by Vasco et al. (2011), both for InSAR data and analytical inverse solution. Using these horizontal displacements, it is straightforward to calculate the displacement in the satellite line-of-sight (LOS). InSAR measurements are generally distance changes in LOS of the satellite orbit, and do not precisely represent the vertical displacement, but rather a mix of both horizontal and vertical displacement. Considering a look vector uLOS = (uˆ EW = 0.35, uˆ NS = −0.08, uˆ z = −0.93) for descending data (Donald Vasco, Berkeley Lab, personal communication), we calculated the displacement in satellite LOS. Fig. 7a and b shows an enlargement around the KB-502 well for both the simulated ground uplift and the LOS displacement calculated from the simulation results. Although the maximum displacement is the same for both the figures (about 15 mm), differences arise in the magnitude and size of the two lobes. In fact, the symmetric lobes for the simulated vertical uplift (Fig. 7a) become asymmetric when the calculation for the LOS displacement is made (Fig. 7b).

At this point, it is possible to compare the simulation results with the InSAR data, using the LOS displacement. Fig. 8a shows the resulting LOS displacement, which is in reasonably good agreement with the measured InSAR displacement, both in magnitude and distribution (Fig. 8b). The main differences between simulated and measured displacement occur far from the injection well, where the simulated uplift exceeds the measured one. Specifically, simulation results show a small displacement (about 5 mm) a few kilometers away from the well, a couple of millimeters higher than the InSAR data. However, for a better comparison between data and simulation, we also present results along two arbitrarily selected profiles at 500 m and 1700 m from the injection well, respectively. Results show a very good match between data and simulation (Fig. 8c and d, red line for the simulation results and green dashed line for the InSAR data), particularly in the region where the double lobe is present (−2 to 2 km along the profiles), with a couple of millimeters difference in the far field. Differences may be explained as caused by our simplified simulation of permeability evolution, in which we change permeability for the entire reservoir homogeneously, thus allowing the pressure increase to propagate far from the injection zone, and hence increasing the displacement in the far field. Thus, permeability changes with time in a homogeneous medium,

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Fig. 9. Transient evolution of the vertical displacement at KB-502 in a point at ground surface over the injection well (about 600 m away from the fracture zone along the injection well direction). Results for both the simulated vertical displacement (red line) and the displacement in the line of sight (black line) are compared with the measured displacement in the same point (green marker). (b and c) Contour of the simulated and measured ground displacement after about 2 years, respectively. The black line indicates the injection well. The black star indicates the point for the transient evolution. (For interpretation of the references to color in this figure legend, the reader is referred to the web version of the article.)

whereas in the field, most permeability changes may occur close to the well region. Transient evolution of both the vertical ground displacement and LOS displacement is shown in Fig. 9 (red line and black line, respectively). Evolution was compared to InSAR data (green marker in Fig. 9) at a ground-surface point over the injection well, about 600 m from the fracture zone along the well direction. Although the LOS and vertical displacements are somewhat different in magnitude, they are both in good agreement with the InSAR data during the uplift phase, whereas larger differences occur after shut in. These differences may be explained by the fact that we do not consider pressure-dependent fracturing; although we consider strongly anisotropic properties, the mechanical model is still elastic. Then, in the simulation, once the shut-in occurs, the fractures tend to close in a reversible manner, producing a lower displacement than in the field, where inelastic fracturing might have occurred within the fracture zone. 5. Sensitivity analysis In this section, we present a parameter study, changing the geometry of the fracture zone and comparing the resulting LOS displacement along the two profiles. For all the simulated cases, we kept the match between calculated and simulated bottomhole pressure. A first set of simulations was performed changing the length of the fracture zone (Fig. 10a and b). The fracture-zone length does not affect the resulting displacement along profile 1 (500 m from the injection well), and all the results are in good agreement with the field data (black dashed line in Fig. 10a), unless the considered length is less than 1500 m (1000 m, blue line in Fig. 10a). However, a comparison of displacements along profile 2 (1700 m from the injection well) shows that only a long fracture zone (length greater than 3000 m) may explain the double lobe uplift at that distance from the injection well (Fig. 10b). The second set of simulations was conducted to study the effects of the number of fractures within the fracture zone, and hence of the fracture zone width. The base-case simulation presented earlier was performed with a fracture zone (80 m wide) composed of a series of three 20 m wide zones (fracture zones with orthotropic

mechanical properties), separated from each other by a 10 m-wide intact caprock. Here we performed two more simulations considering two parallel fracture zones and one single fracture zone, and then we compared the resulting LOS displacement with the base case and the field InSAR data (Fig. 10c and d, for the two profiles, respectively). Results show that considering a narrow fracture zone produces a displacement of a few millimeters lower than in the base case and the InSAR data, along both the considered profiles. The last set of simulations was performed assuming different heights of the fracture zone above the reservoir depth. In some of the simulated cases (900 m and 1200 m), we slightly recalibrated the permeability changes step functions, in order to keep a good match between calculated and simulated bottomhole pressure. Results are shown in Fig. 10e and f along the two profiles, respectively. The resulting displacement does not show a linear correlation with the fracture-zone height. Rather, the largest displacement arises for a fault 700 m in height (about 28 mm, green line in Fig. 10e and f). The double lobe feature is still present for all the simulated cases, but the displacement drops to a value less than 10 mm along profile 1 and less than 5 mm along profile 2 when the fracture zone is assumed to break into the upper aquifer (900 m and 1200 m, red and cyan line respectively in Fig. 10e and f). Substantial differences between InSAR data and simulation results appear when looking at the transient evolution (Fig. 11). The 700 m case seems to follow the same evolution as the base case, but with a higher displacement magnitude (green line in Fig. 11). The temporal evolution of the LOS displacement is completely different for the cases at 900 m and 1200 m (red and cyan lines in Fig. 11). In both cases, the displacement first increases, reaching a maximum about 8 mm; then, a period of somewhat constant displacement begins while the CO2 injection is still active, with the maximum displacement value less than 10 mm. This trend is not observed in the field data at all, indicating that the fracture zone is unlikely to extend all the way up the caprock into the upper aquifer. The almost-constant displacement after about 1 year of injection may be explained by the fact that the pressure buildup at reservoir depth needs some time to inflate the entire fracture zone. Once the whole zone is pressurized, the pressure spreads laterally in the upper aquifer and decreases in maximum magnitude, preventing the ground uplift from reaching higher values.

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Fig. 10. Sensitivity analysis. (a and b) Effects of the fracture zone length along profile 1 and 2, respectively. (c and d) Effects of the number of fractures within the fracture zone, hence effects of the fracture zone width along profile 1 and 2, respectively. (e and f) Effects of the fracture zone height (from the reservoir depth) along profile 1 and 2, respectively. (For interpretation of the references to color in this figure legend, the reader is referred to the web version of the article.)

The increased height of the fracture zone will also increase the risk of CO2 plume leakage into the upper aquifer. Fig. 12 shows the resulting plume for the different fracture zone heights about 2 years after the shut in (November 2009) and the CO2 mass fraction within the fracture zone and upper aquifer, calculated as: CO2 =

Mfracture + Mupper Minj

where Mfracture is the total CO2 mass within the fault, Mupper is the CO2 mass in the upper aquifer, and Minj is the total CO2 mass injected after about 2 years. When the fracture zone is confined within the caprock (height smaller than 900 m from the reservoir depth, red line in all the figures), the CO2 plume induces a higher gas saturation (up to 0.5) and spreads along the x-direction, but the plume itself is confined within the fracture zone and does not reach shallower depths

(Fig. 12a and b). The CO2 mass fraction in these cases is 24.9% and 26.3% for 350 m and 700 m, respectively, and the CO2 is only present within the fault (Mupper = 0). On the other hand, when assuming that the fracture zone penetrates all the caprock layer (height 900 m) or even at shallower depth into the upper aquifer (height 1200 m), the CO2 plume does not spread in the x-direction, but rather moves upward by buoyancy, reaching the upper aquifer (Fig. 12c and d). In these cases the CO2 mass fraction within the fault and leakage into the upper aquifer reaches values higher than 30% of the total injected CO2 . It might be relevant to compare the lateral spread of the CO2 plume in Fig. 12 with that of the 3D seismic results in Fig. 2. If the linear feature seen in Fig. 2 is a result of CO2 saturation within a fracture zone (i.e., a push down caused by a gas replacing the liquid phase), then the result from Fig. 12a is the only case in agreement with the 3D seismic results. For a fracture zone extending only 350 m up from the reservoir, the CO2 can spread laterally several

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Fig. 11. Transient evolution of the ground displacement at KB-502 for the different fracture zone thickness (height from the reservoir depth). (For interpretation of the references to color in text, the reader is referred to the web version of the article.)

Fig. 12. CO2 plume for fracture zones with different height from the reservoir depth. Dashed rectangle indicates the fracture zone size in the x, z-plane. Star indicates the well position. (a) Fracture zone height 350 m. (b) Fracture zone height 700 m. (c) Fracture zone height 900 m. (d) Fracture zone height 1200 m. The red line indicates the upper aquifer depth. (For interpretation of the references to color in this figure legend, the reader is referred to the web version of the article.)

thousand meters, with sufficient high saturation to be visible as a linear feature extending horizontally for several thousand meters, but only for a few hundred meters vertically. Also, for a fracture extending 700 m up from the reservoir the CO2 spread laterally for few thousand meters (Fig. 12b), but in this case the highly saturated region extends in depth from 350 m to 700 m up from the reservoir. This is not in agreement with the 3D seismic results, which showed the linear feature at reservoir level.

6. Concluding remarks and discussion This paper presents an analysis of the ground displacement and deep fracture-zone deformations induced by CO2 injection into a deep saline aquifer at In Salah, Algeria. We focused on the displacement observed at injection well KB-502, where InSAR data showed a double lobe uplift pattern, and where a 3D seismic analysis confirmed the presence of linear features at reservoir depth. Following

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this 3D seismic analysis and InSAR inverse analytical solutions, we interpreted such a feature as a fracture zone that activates in response to increasing reservoir pressure after only a few months of CO2 injection. We carried out numerical modeling with the coupled geomechanical and fluid flow simulator TOUGH-FLAC, assuming a time-dependent reservoir permeability and fracture zone, to get an excellent fit of the pressure changes within the injection zone. Such changes in permeability can be explained as the opening and/or extension of existing fractures within the injection zone, and fracturing, or fracture-zone reactivation, which increases the average permeability as a function of the injection pressure. Thus, in our modeling, we simulated activation of the fracture zone by substantially increasing its permeability, enabling the fluid to propagate along the fracture zone. Mechanically, the assumed fracture zone was modeled as an elastic medium, with highly anistropic properties. Numerical results show that such modeling may produce a vertical displacement featuring a double-lobe uplift and a magnitude close to the measured InSAR data. Considering also the horizontal displacement, we were able to calculate displacement on the satellite line-of-sight, and hence to compare the resulting uplift with the InSAR data. Results show a very good agreement with field data, particularly in the region where the double lobe is present, whereas small differences are noticeable far from the injection well. We attribute these small differences in uplift away from the injection well as being a result of our simplified model, which changes the permeability homogeneously for the entire reservoir in steps (although this remains to be fully investigated). An important result of our analysis is that the double-lobe feature appears to be asymmetric as in the field observation only when a calculation for the displacement in the line of sight of the satellite is made, although the true calculated displacement may result in a more symmetric shape. Transient surface-displacement evolution at a single point is also in good agreement with the InSAR data, especially during the uplift phase. Differences arise after shut-in occurs, and we explain such differences as resulting from the assumption of an elastic model, which during the pressure decline tends to close the fracture in a reversible manner, rather than keeping them open. Including an inelastic material model could improve the match to the apparent irreversible uplift seen after shut-in, and it could have some effect during initial uplift and injection. The failure calculated with an inelastic model would cause some softening, i.e. it would make the fracture zone more deformable, allowing an easier opening. In the current model, we account for this softening by inserting a mechanically soft and permeable fracture zone after a few months of injection. Future studies will strive toward modeling this process explicitly using an elasto-plastic model. The set of properties we used does not represent a unique solution. However, given the high number of parameters involved in the calculation of the ground-surface displacement, the properties minimizing the mismatch between simulated and field-observed ground displacement might be confined within a small range of values. Further studies will clarify how wide is the range of parameters that would allow a good fit with field observations, and this forward modeling will represent a good starting point for a complete inverse analysis. Finally, we conducted a sensitivity study on the geometry of the fracture zone. Although the width, the number of fractures, and the length all play a role in the resulting displacement, simulated results are always similar to the field data, and could be matched to field data by varying the fault properties. On the other hand, changes in the fracture-zone height from reservoir depth produce results that in some cases significantly deviated from field observations. When the fracture is confined within the caprock,

the higher the fracture zone, and the higher the resulting displacement. On the other hand, when the fracture zone penetrates into the upper aquifer, a double-lobe pattern is still achieved, but the calculated uplift evolution is different from observed, including a much smaller uplift magnitude. The poor fit occurs as soon as we assume a substantial pressure release up into the shallow aquifer. As long as the fracture zone is confined within the caprock, and no such pressure release occurs, theoretically it is possible to match the data with the current model by changing the mechanical properties within the fracture zone. A match with the field data is still possible when the mechanical properties of the layers (caprock,upper aquifer, etc.) are changed. Moreover, model simulations show that if the fracture-zone height were to penetrate the upper permeable aquifer, a vertical CO2 plume forms, not extending horizontally along the fracture zone. If the linear feature seen in the 3D seismic is a result of CO2 saturation, this result provides another indication that the fracture zone is limited in height a few hundred meters up from the reservoir. One of the goals of this modeling study was to investigate whether we could use transient coupled fluid flow and geomechanical analysis to more conclusively constrain the height of the fracture zone. Overall, our analysis supports the notion that the fracture zone is confined within the caprock and does not penetrate the overlying aquifer. First, assuming a fracture zone of limited height, our modeling could match all available field observations reasonably well, including all time evolutions and the shape of surface deformation, time-evolution of injection pressure, and the 3D seismic indications of the CO2 saturated fracture zone extending thousands of meters laterally (but only a few hundred meters vertically). Second, our analysis for a fracture zone extending through the entire caprock results in pressure release into the upper aquifer, which strongly affects the time-evolution of bottomhole pressure and surface displacements (as well as the double-lobe pattern) in a way that does not match field observations. Third, our analysis for the assumption of a permeable fracture all the way through the caprock shows that CO2 would quickly move up via buoyancy into the aquifer, whereas in the field, no anomalies have been noted from the soil gas, surface flux, shallow aquifer, or microbiology monitoring work (Mathieson et al., 2011). Using this model, as soon as we allowed the fracture zone to extend up to the shallow aquifer, we simply did not find a way to satisfactorily match all the different types of field observations. However, while our current analysis of KB-502 data is the most complete and detailed to date, this analysis still includes a number of simplifications and uncertainties. For example, our analysis of the permeability changes instantaneously affecting the entire fracture zone, in steps, may be different from the field in which the zone could have opened and propagated in a more gradual manner over time. We are aware that the assumption of a spatially uniform permeability within the fracture zone may have a significant impact on the sensitivity analysis, especially when such a damage zone penetrates into the upper aquifer. For example, a fracture zone might have a higher permeability in the region close to the reservoir, and a lower one close to the upper aquifer. Such a fracture zone (with heterogeneous permeability) may mechanically behave as a confined (short vertical extension) zone, but then leakage into the upper aquifer cannot be excluded, since a direct pathway would still exist. Model simulations including such potential fracture propagations and stress-dependent permeability changes will be the subject of future studies.

Acknowledgements This work was jointly supported by the Assistant Secretary for Fossil Energy, Office of Natural Gas and Petroleum Technology, through the National Energy Technology Laboratory, and the In

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