Numerical Simulation of Permeability Change in Wellbore Cement

Article pubs.acs.org/est

Numerical Simulation of Permeability Change in Wellbore Cement Fractures after Geomechanical Stress and Geochemical Reactions Using X‑ray Computed Tomography Imaging Senthil Kabilan,† Hun Bok Jung,‡ Andrew P. Kuprat,† Anthon N. Beck,† Tamas Varga,† Carlos A. Fernandez,† and Wooyong Um*,†,§ †

Pacific Northwest National Laboratory, Richland, Washington 99354, United States New Jersey City University, Jersey City, New Jersey 07305, United States § Pohang University of Science and Technology (POSTECH), Pohang, South Korea ‡

S Supporting Information *

ABSTRACT: X-ray microtomography (XMT) imaging combined with three-dimensional (3D) computational fluid dynamics (CFD) modeling technique was used to study the effect of geochemical and geomechanical processes on fracture permeability in composite Portland cement−basalt caprock core samples. The effect of fluid density and viscosity and two different pressure gradient conditions on fracture permeability was numerically studied by using fluids with varying density and viscosity and simulating two different pressure gradient conditions. After the application of geomechanical stress but before CO2-reaction, CFD revealed fluid flow increase, which resulted in increased fracture permeability. After CO 2-reaction, XMT images displayed preferential precipitation of calcium carbonate within the fractures in the cement matrix and less precipitation in fractures located at the cement−basalt interface. CFD estimated changes in flow profile and differences in absolute values of flow velocity due to different pressure gradients. CFD was able to highlight the profound effect of fluid viscosity on velocity profile and fracture permeability. This study demonstrates the applicability of XMT imaging and CFD as powerful tools for characterizing the hydraulic properties of fractures in a number of applications like geologic carbon sequestration and storage, hydraulic fracturing for shale gas production, and enhanced geothermal systems.

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INTRODUCTION A proposed method to mitigate global warming and decrease atmospheric carbon dioxide (CO2) concentration is the capture and storage of CO2 in deep geologic formations including oil and gas reservoirs. During geologic carbon storage, CO2 leakage can occur through wellbores, damage underground sources of drinking water, and consequently affect human health, as well as the ecosystem.1−3 Portland cement is commonly used as a sealing material in wellbores at carbon storage sites. During typical well construction, cement slurry is placed in the annulus between the wellbore steel casing and formation rocks to prevent vertical fluid migration and to provide mechanical support.4 Hydrated products formed by mixing Portland cement with water are primarily a semiamorphous gel-like calcium silicate hydrate (C−S−H) and a crystalline phase of portlandite [Ca(OH)2(s)].4,5 Potential leakage pathways of stored CO2 may occur at the interface between casing and cement, cement plug and casing, and cement and host rock, or through the cement pore spaces and fractures.6−8 Wellbore cement may contain fractures and defects because of changes in pressure and temperature within the wellbore during field operation, cement shrinkage during hydration, mechanical shock from pipe tripping, poor cement slurry placement, and residues of drilling mud and drill cuttings.9 After well © XXXX American Chemical Society

completion, changes in downhole conditions can also induce sufficient stresses to damage the integrity of the cement sheath. The presence of mechanical defects such as gaps in bonding between the casing and the formation, or fractures in the cement annulus itself, leads to flow paths that have significant effective permeability.10 In addition, geochemical reactions of cement weathering and secondary mineral precipitation by reacting CO2 either in gas, supercritical, or aqueous form in the deep subsurface can affect fracture permeability.11,12 Due to the complex nature of the fracture geometry, computational fluid dynamics (CFD) has been used to study fluid flow and hydraulic properties of fractures. Javadi et al. investigated nonlinear flow in artificially generated 3D roughwalled fracture geometry using both laminar and turbulent flow models.13 To overcome the artifacts of using synthetic geometry and with the evolution of advanced imaging techniques, X-ray microtomography (XMT) imaging combined with CFD is frequently used to study hydraulic properties and its changes due to geochemical and geomechanical processes in Received: January 11, 2016 Revised: May 17, 2016 Accepted: May 20, 2016

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DOI: 10.1021/acs.est.6b00159 Environ. Sci. Technol. XXXX, XXX, XXX−XXX

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Environmental Science & Technology

Figure 1. Isosurfaces for the three cases corresponding to Sample 1: Case 1, before compression; Case 2, after compression; and Case 3, after CO2 reaction. Case 4 and Case 5 correspond to before compression and after compression for Sample 2. Case 1 and Case 3 consisted of two fractures, whereas Case 2 consisted of three fractures. Fracture 3 in Case 2 was connected to Fractures 1 and 2 due to the application of compressive loading, which became disconnected again in Case 3 due to precipitation of CaCO3. For Sample 2, the fracture network was assumed to be a single fracture and hence was not separated into individual fractures like Sample 1.

interface samples due to geomechanical and geochemical processes using CFD modeling, and (2) to numerically investigate the effect of different fluids (supercritical CO2 and CO2-saturated brine) density and viscosity and pressure gradient (pressure difference of 20 and 200 kPa) on fracture permeability. Cement-basalt interface samples are of interest since Columbia River Basalt Group, which is predominantly a volcanic flood basalt province are currently being considered as a geologic storage option for CO2 because they can rapidly convert injected CO2 into more stable carbonate minerals and isolate CO2 permanently from the atmosphere.

realistic 3D fracture geometries. A number of research groups including ours have used XMT-based 3D-CFD modeling to investigate changes in fracture permeability.12,14−16 Crandall et al. studied the effect of wall roughness on fluid flow in computed tomography (CT)-based fracture geometries in Berea sandstone.16 They observed that the transmissivity in the roughest fracture mesh was nearly 35 times smaller than in the smoothest one. The roughness was quantified using the Joint Roughness Coefficient and the fractal dimension. Deng et al. studied the effect of CO2-acidified brine flow on fracture permeability and transmissivity in a carbonate caprock fracture.12 They used CT imaging to create 3D reconstructions of fracture before and after CO2-acidified brine flow to investigate changes in permeability and transmissivity. They observed that the 1D statistical model and 2D local cubic law were incapable of capturing the discrepancy between mechanical aperture, the actual opening displacement of the fracture, and hydraulic aperture, the equivalent aperture through which fluids can flow. They also suggested that coupling the detailed fracture geometry reconstructed from micro-CT images combined with CFD modeling provides more accurate estimations of fracture permeability and transmissivity. Because fracture permeability is affected by changes in fracture geometry after geomechanical and geochemical processes, the aims of the current research work are (1) to study the fracture permeability changes of cement−basalt

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MATERIALS AND METHODS Preparation of Cement Samples. A low-permeability basalt caprock from the Grande Ronde Basalt Formation in Washington State was used to prepare the cement−basalt interface samples with Portland cement slurry (Lafarge North America, Type I−II). The cement slurry was prepared by thoroughly mixing Portland cement with water by hand at a water-to-cement ratio of 0.38 and pouring it into a plastic cylindrical mold (25 mm diameter and 50 mm height) with a half-cylinder shaped basalt (approximately 13 mm diameter by 35−45 mm length). The hardened cement samples were removed from the molds after 2 days and continuously cured for 28 days under ambient conditions (20 °C temperature and atmospheric pressure with a relative humidity of 30%) to create

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preserving hybrid median filter and background normalization were applied to remove high- and low-frequency background noise, respectively. Intensity thresholds followed by manual validation were performed to identify the fracture boundaries. An isosurface was generated using a variant of the marching cube algorithm on the segmented binary image sequence,22 and the resulting surface was smoothed using the volumeconserving smoothing algorithm.23 The final surface was imported into Magics (Materialise, Plymouth, MI, USA) to remove any overlapping and intersecting triangles and to define the inlet and outlet planes that would be used during CFD modeling. For Sample 1, Case 1 (before compressive loading) and Case 3 (after CO2 reaction) consisted of two fractures (Figure 1), while Case 2 (after compressive loading) consisted of three fractures. Fracture 1 was formed along the interface between cement and basalt, while Fracture 2 and Fracture 3 were formed within the cement matrix and propagated from the corner or the side of the basalt column. Fracture 3 in Case 2 was connected to Fractures 1 and 2 due to the application of compressive loading, which became disconnected in Case 3 due to precipitation of CaCO3. Though Fracture 3 was found in the XMT data for Case 1 and Case 3, it was not included in the modeling because it was disconnected from Fracture 1 and Fracture 2 and did not communicate between the inlet and the outlet of the sample. Unlike Sample 1, in which fractures communicated just between the top and bottom of the sample, fractures in Sample 2 communicated through the sides or along the circumference of the cylindrical sample (Figure 1). Hence, inlets and outlets for Sample 2 were defined for all connected fractures that communicated between the top surface and the bottom or sides of the cylinder. Only connected fractures of samples were used for CFD modeling. The volume mesh for Sample 1 was generated using an in-house code and consisted mainly of tetrahedral elements. For Sample 2, the final volume mesh was generated using the standard polyhedral and prism layer meshing utilities in STARCCM+ (CD-Adapco). The volume mesh consisted of tightly packed prism layer elements close to the fracture wall to successfully resolve any boundary layer formation. The core mesh consisted mainly of polyhedral and hexahedral mesh elements. The final volume mesh for Case 1, 2, and 3 of Sample 1 consisted of 0.58, 1.24, and 0.64 million nodes, respectively. The total numbers of tetrahedral elements for the three cases were 2.92, 6.46, and 3.34 million. Similarly, the final volume mesh for Case 4 (before compressive loading) of Sample 2 (Figure 1) consisted of 4.2 million nodes and 1.32 million elements, while the Case 5 (after compressive loading) of Sample 2 consisted of 6.86 million nodes and 2.17 million elements. To confirm that the results were independent of the mesh density used, the volume mesh for Case 4 was increased by 2.5 times and an additional boundary layer was included in the prism layer mesh. The bulk permeability changed by a mere 1.29%, suggesting that the original mesh was adequate to accurately capture the flow characteristics. OpenFOAM (OpenCFD Ltd., Reading, UK) was used as the main flow solver. The flow estimations were based on turbulent, 3D, incompressible Navier−Stokes equations for fluid mass and momentum:

artificial fractures caused by drying shrinkage during cement curing.17 The two samples used in the current research work are shown in Supporting Information (SI) Figure S1. Compressive loading was applied to both cement samples to simulate mechanical stress in downhole conditions (e.g., overpressure during CO2 injection).18 Both ends of the cement samples were cut to prepare flat surfaces before applying a compressive load of 2.7 MPa vertically to the samples at 1.8 MPa/min to form internal fractures using servohydraulic test frames (MTS 10 Kip) with load cells (Lebow 10 Kip 3116). Compressive loading at 2.7 MPa can reasonably represent the mechanical stress for existing wellbores during CO2 injection and storage for decades.11 After compressive loading, cement samples were imaged using XMT to capture any fractures formed due to the application of mechanical stresses. Later, the sample was placed in pressure vessels (Parr Instrument Company; 300 mL volume with 64 mm internal diameter ×102 mm depth) containing 130 mL of synthetic groundwater consisting of 2 mM NaHCO3, 0.5 mM MgCl2·6H2O, and 0.5 mM CaSO4·2H2O. The experiment to determine the geochemical reaction with CO2-saturated groundwater was conducted under a pressure of 10 MPa and at a temperature of 50 °C; CO2(g) was injected into the vessel with a highpressure syringe pump (Teledyne Isco) through a gas inlet valve. In the vessel, the cement column was completely submerged in 130 mL of synthetic groundwater for 3 months. After CO2 reaction, the pressure vessel was slowly depressurized for 24 h before cement samples were collected for XMT imaging. Due to integrity issues with Sample 2 that occurred before CO2 reaction, only Sample 1 was subjected to the geochemical reaction experiment for CFD modeling. X-ray Microtomography Imaging. Cement samples were scanned using a high-resolution microfocus X-ray CT scanner (X-Tek/Metris XTH 320/225 kV) to visualize the formation, growth, and sealing of internal fractures. Scans were performed at 98 kV and 536 μA X-ray energy ranges with a 0.1 mm Cu filter for optimum image quality and contrast. The samples were rotated continuously during the scans with momentary stops to collect each projection (shuttling mode) to minimize ring artifacts. A total of approximately 3142 projections were collected over 360 deg with a 0.5 s exposure time and 1 frame per projection with an isotropic voxel resolution of ∼10−25 μm depending on specimen dimensions. The images were reconstructed to get 3D data sets using CT Pro 3D (Metris XT 2.2, Nikon Metrology, UK). CFD Modeling. The CFD modeling technique was used to visualize the complex flow characteristics within the fracture and to investigate the changes in the permeability of the fracture due to application of geomechanical stress and geochemical processes. The different cases that were modeled for Samples 1 and 2 are shown in Figure 1. Three different casesCase 1, before compressive loading; Case 2, after compressive loading; and Case 3, after CO2 reactionwere modeled for Sample 1. Because of sample integrity issue before geochemical CO2 reaction with Sample 2, only two cases-Case 4, before compressive loading and Case 5, after compressive loading were modeled for Sample 2. Sample 2 was included in the modeling effort to study the differences (or similarities) in hydraulic properties between two samples undergoing similar geomechanical stress as estimated by CFD. The procedure followed for segmenting the XMT data was the same as that described by Carson et al.19,20 Briefly, the image sequence was read into ImageJ21 and a 3D edge-

∂uj ∂xj C

=0 (1) DOI: 10.1021/acs.est.6b00159 Environ. Sci. Technol. XXXX, XXX, XXX−XXX

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Figure 2. Streamtraces colored by absolute velocity and contours of absolute velocity in Sample 1 for Case 1, Case 2, and Case 3 under the 20 kPa condition with supercritical CO2 as the working fluid.

⎛ ∂u ∂u ⎞ ∂ 2ui ∂p ∂ ρ⎜⎜ i + u j i ⎟⎟ = − + ρg i + μ − ρu′iu′j t x x x x ∂ ∂ ∂ ∂ ∂ ∂ ⎝ j⎠ i j j xj

kPa pressure difference condition was simulated. An impermeable, rigid, no-slip boundary condition was applied to the fracture walls. To predict the intrinsic permeability of the fracture, the estimated flow rate and applied pressure gradient from the CFD model was used in the following Darcy’s law:

(2)

In the above equations, ui or uj is the mean fluid velocity component, and repeated subscripts denote summation; gi is the gravity vector, ρ is the gas density, p is the pressure, and μ is dynamic viscosity. The ui′ and uj′ in the right-most term of eq 2 are velocity fluctuations about the mean velocity, and the overbar indicates the time averaging of the products of these fluctuations. The two different working fluids used in the CFD modeling of Sample 1 included (1) supercritical CO2 at 50 °C with a density of 384.3 kg/m3 and a kinematic viscosity of 7.38 × 10−8 m2/s, and (2) CO2-saturated brine (1 mol/kg NaCl) at 50 °C with a density of 1035 kg/m3 and a kinematic viscosity of 5.99 × 10−7 m2/s. For Sample 2, only supercritical CO2 at 50 °C was used as the working fluid. For Sample 1 cases, the models were driven by a pressure difference of 20 and 200 kPa (henceforth referred to as the 20 and 200 kPa conditions) applied between the inlet and outlet, which correspond to a pressure gradient of 1 MPa/m and 10 MPa/m along ∼2 cm long cement fractures, respectively. For Sample 2, only the 20

q = − k / μ × ∇P

(3)

where q is the flux (m/s), μ is the dynamic viscosity of fluid, and ∇P is the pressure gradient vector (Pa/m).

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RESULTS AND DISCUSSION Sample 1. SI Table S1 summarizes the fracture aperture (surface) area, flow rate, average velocity, and permeability of the individual fractures and the bulk fracture permeability for Cases 1 through 3 (Case 1-before compressive loading; Case 2after compressive loading; and Case 3-after CO2 reaction) under the 20 and 200 kPa conditions using supercritical CO2 as the working fluid. The application of compressive loading increased the aperture area of Fracture 1 and Fracture 2 by 17% and 11%, respectively. The reaction with CO 2 also interconnected Fracture 3 to Fracture 2 (Figure 1). Under D


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cement due to the limited diffusion of CO2-dissolved water into the small pores of low permeable basalt caprock. Despite the decrease in the permeability of Fracture 2, the bulk permeability of the sample increased by a factor of 2. There was hardly any difference in flow characteristics other than the absolute velocity of the flow field for all three cases under the 20 and 200 kPa pressure gradients with supercritical CO2 as the working fluid (SI Figure S2). Due to the higher flow rate and velocity observed under 200 kPa conditions, higher frictional loss near the fracture wall and higher kinetic energy loss due to turbulence was found (not shown here). This resulted in decreasing individual permeabilities and bulk permeabilities for all three cases under 200 kPa condition compared to 20 kPa condition. Models using CO2-saturated brine as the working fluid showed flow patterns similar to the supercritical CO2 models but differ quantitatively. Comparing Cases 1 and 2, under both the 20 and 200 kPa conditions, the flow rate, average velocity, and permeability for Fracture 1 increased by approximately 7− 38% (SI Table S2). Similarly, comparing Cases 2 and 3 under the 20 and 200 kPa conditions, the flow rate, average velocity, and permeability for Fracture 1 increased between 9% and 50%. For Fracture 2, comparing Cases 1 and 2, the compressive loading led to an increase in flow rate, average velocity, and permeability by factors of 26, 23, and 22, respectively, under the 20 kPa condition and by factors of 8, 7, and 7, respectively under the 200 kPa condition. Unlike supercritical CO2, subtle differences in flow characteristics were evident along with higher fluid velocity in simulations using CO2-saturated brine solution as the working fluid for the 20 and 200 kPa pressure gradient simulations (shown by arrows in SI Figure S3). Despite noticeable changes in flow characteristics using CO2saturated brine models, comparative changes in individual permeabilities and bulk permeabilities between the 20 and 200 kPa conditions were similar to those using supercritical CO2 models. When comparing the results from supercritical CO2 and CO2-saturated brine simulations under the same simulation pressure conditions, there was a significant difference in simulated fluid velocity and calculated permeability. For the Case 1, 20 kPa condition with supercritical CO2 as the working fluid, for Fracture 1, the average fluid velocity was higher by approximately 2.3 times than it was when using CO2-saturated brine. Similarly, for Fracture 2, the flow velocity was ∼7.7 times greater for supercritical CO2 than for CO2-saturated brine. For Case 1, 200 kPa condition, the flow velocity was higher by a factor of 1.8 for supercritical CO2 than for CO2-saturated brine in Fracture 1. Similarly, for Fracture 2, the fluid velocity was 4.1 times greater for supercritical CO2. The higher flow velocity observed for supercritical CO2 could be due to the significantly lower kinematic viscosity of supercritical CO2 (7.38 × 10−8 m2/ s) compared to CO2-saturated brine (5.99 × 10−7 m2/s) at 50 °C and 10 MPa. Accordingly, the calculated permeability for Fracture 1 was higher by a factor of ∼9−12 for CO2-saturated brine than for supercritical CO2 under the 20 and 200 kPa conditions. For Fracture 2, the permeability was greater by ∼3−16 times for CO2-saturated brine than for supercritical CO2. The intrinsic permeability values, calculated using Darcy’s law are not consistent for the flow of supercritical CO2 and CO2-saturated brine. This is attributed to turbulent flow of the CO2-fluids through cement fracture as indicated by the Reynolds (Re) numbers higher than 100 for the cement samples.12,27

the 20 kPa simulation condition after compressive loading, for Fracture 1, the flow rate and average velocity increased by 35% and 16%, respectively, and they increased by factors of 4.5 and 4.1, respectively, for Fracture 2. This suggests that mechanical stress increases the fracture permeability in a fracture that is entirely in the cement (Fracture 2) more than an interface fracture (Fracture 1). Similar increases in flow rate, velocity, and permeability were observed while comparing Case 1 and Case 2 under the 200 kPa condition for Fracture 1. However, for Facture 2, the maximum increase (in flow rate) was only by a factor of ∼3. This suggests greater turbulence kinetic energy loss in Fracture 2 due to the higher applied pressure gradient combined with fracture geometry. While the permeabilities of both Fracture 1 and Fracture 2 increased after the application of compressive loading, Fracture 1 permeability changed by a mere 11% compared to Fracture 2, which changed by a factor of 4. This could be attributed to the differences in flow pattern observed between Case 1 and Case 2 as shown in Figure 2. A large portion (shown in arrow) of Fracture 2 in Case 1 exhibited recirculation flow and very low fluid velocity before the application of compressive loading. The same portion of Fracture 2 had more fluid flow after the application of compressive loading. The compressive loading changed the fracture network between Fracture 1 and Fracture 2 in a way that diverted more flow from Fracture 1 to Fracture 2. This flow diversion was also evident from the fact that the flow ratio between Fracture 1 and Fracture 2 decreased from 40.5 in Case 1 to 12.1 in Case 2. Additionally, the bulk permeability of the sample increased by 4% due to the application of compressive loading. For Case 3, due to the precipitation of CaCO3 during the chemical reaction with CO2-saturated brine, the aperture area for Fracture 1 increased by 36% compared to Case 2, while the aperture area of Fracture 2 decreased by 73%. The widening of Fracture 1 is attributed to the increase in aperture width of Fracture 2 because both fractures were fully interconnected. The widening of Fracture 2 may have resulted from the crystallization-induced pressure (up to ∼75 MPa for calcite) due to the growth of calcium carbonate with high molar volume at the fracture surfaces.24−26 Due to this decrease in aperture area, the flow of working fluid (supercritical CO2) through Fracture 2 was significantly reduced. Comparing Cases 2 and 3, under 20 and 200 kPa conditions, the flow rate, average velocity, and permeability of Fracture 1 in Case 3 increased by factors of 1.4, 1.1, and 1.2, respectively. Similarly, comparing Cases 2 and 3 under 20 and 200 kPa conditions, for Fracture 2, the flow rate, average velocity, and permeability decreased by factors of 41, 11, and 10, respectively. While precipitation of CaCO3 increased the aperture width, flow rate, average velocity, and permeability of Fracture 1, it had the opposite and greater effect on Fracture 2. From Figure 2C, it is evident that precipitation of CaCO3 nearly blocked all available flow paths in Fracture 2, thereby decreasing the individual permeability. This suggests that precipitation of CaCO3 has a preference for fractures that are entirely in cement (Fracture 2) rather than for interface fractures between basalt and cement (Fracture 1). This could be due to 1. difference between the fracture wall surface smoothness of the two types of fractures; 2. difference in pH and reactivity to CO2-saturated water between cement and basalt surfaces; 3. availability of local Ca2+ dissolved from cement in entire cement fractures; 4. presence of CaCO3 seeds in case of fracture in cement; and 5. slower dissolution rate of basalt caprock by CO2−saturated water than the hydrated E


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Figure 3. Streamtraces colored by absolute velocity in Sample 1 under the 20 kPa condition using supercritical CO2 (left column) and CO2-saturated brine solution (right column) as the working fluids for the different cases.

Significant differences in flow characteristics and fluid velocity can be observed for the two different working fluids, supercritical CO2 and CO2-saturated brine solution, for the same geometry and pressure gradient (20 kPa). This is mainly due to the differences in fluid density and viscosity. For all three cases, simulations using supercritical CO2, which has a lower density and dynamic viscosity than CO2-saturated brine solution, have higher fluid velocity compared to simulations using CO2-saturated brine solution as the working fluid. Due to the higher velocity and higher momentum observed in supercritical CO2 simulations, the major flow path from Fracture 1 to Fracture 2 is pushed closer to the distal portion of the fracture geometry as shown by the arrows in Figure 3, thereby decreasing the area available for fluid flow from Fracture 1 to Fracture 2. Despite the reduced area available for fluid flow from Fracture 1 to Fracture 2 in supercritical CO2

simulations, the higher fluid velocity increases the overall flow rate in Fracture 2 by a factor of ∼8 compared to CO2-saturated brine simulations for Case 1. Though Fracture 2 receives more flow from Fracture 1 in supercritical CO2 simulations, the permeability of Fracture 2 is less compared to the permeability computed from the CO2-saturated brine simulation, mainly due to the lower viscosity of supercritical CO2. Similar flow pattern differences between supercritical CO2 and CO2-saturated brine solution can be seen in Case 2 and Case 3 in Figure 3. Like Case 1, the permeabilities of fractures computed using supercritical CO2 are always greater than permeabilities computed using CO2-saturated brine simulations. Similar flow differences and resulting changes in individual and bulk permeabilities were observed between supercritical CO2 and CO2-saturated brine solution simulations under the 200 kPa condition. F


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Environmental Science & Technology Table 1. Comparison of Area, Velocity and Permeability for Sample 1 and Sample 2a Sample 1 area (m2)

a

average velocity (m/s)

20 kPa with supercritical CO2

permeability (m2)

20 kPa with supercritical CO2

before compression after compression before compression after compression before compression after compression

5.25 8.06 2.58 2.80 6.43 6.69

× 10−06 × 10−06

× 10−11 × 10−11

Sample 2 8.76 1.11 2.71 4.77 6.31 8.52

× 10−07 × 10−06

× 10−11 × 10−11

The permeability values are determined by a 20 kPa pressure gradient simulation with supercritical CO2 as the working fluid.

Figure 4. Streamtraces colored by absolute velocity and contours of absolute velocity for Case 4 and Case 5 corresponding to Sample 2 using supercritical CO2 as the working fluid and a 20 kPa pressure difference simulation.

Sample 2. Sample 2 consisted of a primary fracture communicating between the inlet and the outlet of the sample with secondary fractures branching from the primary fracture at nearly right angles. Similar to Sample 1, application of compressive loading resulted in an increase in the aperture area, which caused higher flow rate, average velocity, and permeability (Table 1 and SI Table S3). The Sample 2 fracture aperture increased by 27%, which was greater than the aperture size increase seen in Sample 1 after geomechanical loading. The volume of the fracture increased by 62% and the surface area of the fracture increased by 67%. Overall differences in flow rate, average velocity, and bulk fracture permeability due to the application of compressive loading were similar to Sample 1. The flow rate and average velocity for Case 5 was greater than for Case 4 by factors of 2.3 and 1.8, respectively. As shown in Figure 4, application of compressive loading results in new fracture formation as well as existing fractures communicating

with the external environment (shown by solid arrows in Figure 4). The higher flow rate, altered geometry, and an additional outlet at the distal end for Case 5 results in increased flow into the distal (or bottom) portion of the sample. Similarly, the increase in fracture aperture and higher flow rate in Case 5 increases the flow into the fracture on the right and the curved fracture (shown by dashed arrow in Figure 4). Due to better fracture connectivity in the bottom left fracture (highlighted by a solid arrow in Figure 4) in Case 5, more flow exits the fracture than it does in Case 4. The aforementioned differences between Case 4 and Case 5 result in a 35% increase in sample permeability due to the application of compressive loading. Limitations. While XMT imaging combined with CFD modeling can be used as a powerful tool to study the effect of compressive loading and reaction with CO2 on fracture permeability, there are still several limitations to the current approach that should be noted: G


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supercritical CO2 or CO2-saturated brine). During CO2 injection, the injection well will be in contact with dry supercritical CO2 because a dry-out zone is developed within a few meters of the injection well,28,29 while the existing wells (e.g., EOR sites) can be exposed to either wet supercritical CO2 or CO2-saturated formation water.9 After CO2 injection ceases, the dry-out zone will disappear and the injection well will be in contact with wet supercritical CO2 or CO2-rich brine. Therefore, the risk of CO2 leakage through wellbores should be assessed considering the type of CO2-fluid, which can vary temporally and spatially depending on the distance from the injection well. During the reaction with CO2-saturated brine or supercritical CO2 with different pressure gradients, fracture permeability of a wellbore can continuously decrease or increase by either CaCO3 precipitation or dissolution of cement phases. It is shown that carbonation process is dominant and induces permeability decrease and leakage mitigation for extremely low CO2-brine flow rate condition, while for medium to high CO2-brine flow rate condition the hydraulic aperture and permeability increase or remain constant.30 Therefore, cement carbonation in wellbore cement fractures and hence, permeability decrease is more likely to occur during slow CO2 leakage under a low pressure gradient.

1. Capturing fracture connectivity and interconnectivity depends on the resolution of the imaging modality. Therefore, features beyond the resolution of the XMT imaging technique were not captured. Flow in such features is expected in reality and the current estimated permeability is expected to change by their inclusion once XMT resolution increases with technical advancement. Since the flow in microfractures is dominated by diffusion, the permeability is expected to decrease marginally due to fracture sealing by CaCO3 precipitation. 2. Despite the fact that permeability is an intrinsic property of the rock sample and is independent of flow conditions and fluid properties, in the current study, difference in numerically estimated permeabilities was noticed for different pressure conditions and the two different working fluids used. This is due to the fact that Darcy’s law is applicable only for laminar flow where the Re number is less than 10. Though the Re in the current study is greater than 100, the applicability of Darcy’s law is justified by the previous work by Jung et al. (2014) who showed good correlation between experimentally determined permeability and numerically determined permeability though the Re was greater than 10.11

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ASSOCIATED CONTENT

S Supporting Information *

IMPLICATION XMT imaging and CFD modeling were successfully applied to evaluate the effect of geochemical reactions and compressive loading on wellbore cement fractures. CFD modeling was able to highlight the changes in permeability due to the application of compressive loading and the effect of CaCO3 precipitation within the fractures. In a previous publication by Jung et al. (2014), CFD estimations of fracture permeability were successfully validated against experimentally determined permeability using the constant head permeability measurement technique,11 thereby demonstrating the powerful fracture characterization capability of the XMT-imaging−based CFD modeling technique. XMT combined with CFD modeling can provide detailed 3D fracture distribution and fluid characteristics including individual fracture permeability compared to experimental bulk permeability measurements. This method could be used to study changes in the hydraulic properties of fractures in geologic materials for energy and environmental researches (e.g., subsurface activities like shale gas production, induced caving in mining industry, thermal energy extraction using enhanced geothermal systems, and contaminant transport and chemical reactions in subsurface porous media). The flow of various fluids such as water, steam, and natural gas through bedrock fractures can be simulated at field scale by applying upscaling methods to incorporate small-scale hydraulic properties into field scale models. The CFD modeling in this study showed that geomechanical stress increased permeability of wellbore cement fractures, while geochemical reactions with CO2 and precipitation of CaCO3 decreased permeability of wellbore cement, suggesting that the risk of CO2 leakage through fractured wellbore is likely to be reduced during the storage of CO2 because of cement carbonation processes. However, the CaCO3 sealing of wellbore cement fractures may not occur along a large fracture aperture (e.g., aperture size > ∼200 μm along the cement−caprock interface).11 The CFD modeling also revealed that the rate of CO2 leakage through wellbore fractures is controlled by the type of CO2-fluid (e.g.,

The Supporting Information is available free of charge on the ACS Publications website at DOI: 10.1021/acs.est.6b00159. XMT images of cement−basalt interface samples and additional results of simulations for flow rate, average velocity, individual fracture permeability and bulk permeability (PDF)

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AUTHOR INFORMATION

Corresponding Author

*Phone: 509-372-6227; fax: 509-376-1638; e-mail: Wooyong. [email protected]. Notes

The authors declare no competing financial interest.

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ACKNOWLEDGMENTS Funding for this research was provided by the National Risk Assessment Partnership (NRAP) in the U.S. Department of Energy Office of Fossil Energy’s Carbon Sequestration Program. Part of this research was performed at the W.R. Wiley Environmental Molecular Sciences Laboratory (EMSL), a national scientific user facility at PNNL managed by the Department of Energy’s Office of Biological and Environmental Research, and simulations were performed using PNNL Institutional Computing. PNNL is operated by Battelle for the U.S. DOE under contract DE-AC06-76RLO 1830.

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REFERENCES

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Numerical Simulation of Permeability Change in Wellbore Cement

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