Geological characterization of the Aquistore CO2 storage site from 3D seismic data

International Journal of Greenhouse Gas Control 54 (2016) 330–344

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Geological characterization of the Aquistore CO2 storage site from 3D seismic data D.J. White a,∗ , C.D. Hawkes b , B.J. Rostron c a b c

Geological Survey of Canada, Ottawa, Canada University of Saskatchewan, Saskatoon, Canada University of Alberta, Edmonton, Canada

a r t i c l e

i n f o

Article history: Received 14 June 2016 Received in revised form 23 September 2016 Accepted 3 October 2016 Available online 20 October 2016 Keywords: Site characterization 3D seismic Storage Canada Geology Aquistore Boundary Dam

a b s t r a c t A 30 km2 3D seismic survey was conducted in 2012 at the Aquistore CO2 storage site near Estevan, Saskatchewan, Canada. The purpose of the survey was to investigate the geological suitability of this site for the purposes of long-term CO2 storage. The resultant 3D seismic volume has been interpreted in conjunction with geological and geophysical logs from the 3400 m deep CO2 injection well (01/5-6-2-8-W2M) that was subsequently drilled. The CO2 storage reservoir resides immediately above the Precambrian crystalline basement (3400 m) and is part of a regionally extensive >200 m-thick clastic interval (Winnipeg and Deadwood formations). The reservoir is capped by a 15 m thick laterally-continuous shale unit (Icebox Member of the Winnipeg Formation). A regional evaporite at ∼2500 m depth (Prairie Formation) provides a secondary barrier to vertical flow. It is >150 m thick and shows no salt dissolution features. Above the Prairie Formation are 1500 m of laterally continuous Middle Devonian to Lower Cretaceous strata and 1000 m of Upper Cretaceous and younger sedimentary rocks, including additional regionallyextensive aquitards that provide tertiary seals: Watrous Formation (∼120 m), Colorado Group (>185 m), and Bearpaw Formation. There is no evidence of vertical faulting extending through the Devonian or deeper section. A local sub-vertical Precambrian basement fault is interpreted to exist. It lies beneath a flexure within the overlying Cambrian to Silurian strata. The fault is oriented at an azimuth of 75◦ –85◦ relative to the regional maximum horizontal stress making it less susceptible to reactivation during CO2 injection. There is no clear evidence that the strata in an overlying flexure are ruptured or faulted. Natural seismicity in the area is very low and the nearest known significant seismogenic fault zone is located ∼200 km away. Crown Copyright © 2016 Published by Elsevier Ltd. All rights reserved.

1. Introduction Large-scale implementation of geological CO2 storage will require the use of porous rock formations that are currently saturated with brine (saline formations). In Canada, the storage capacity of saline formations exceeds that of depleted oil and gas reservoirs by at least an order of magnitude (e.g., p. 16, 18, North American Carbon Atlas Partnership, 2012). However, by the end of 2014, no injection of CO2 into a saline formation had occurred in Canada for the purposes of long-term storage with the exception of acid gas (a mixture of H2 S and CO2 ) disposal operations (e.g., Bachu and Gunter, 2004). In 2015, two commercial-scale projects started CO2 injection in saline formations for the purpose of storage: the Shell

∗ Corresponding author. E-mail address: [email protected] (D.J. White). http://dx.doi.org/10.1016/j.ijggc.2016.10.001 1750-5836/Crown Copyright © 2016 Published by Elsevier Ltd. All rights reserved.

Quest Project in Alberta (PR Newswire, 2015) and the Aquistore Project in Saskatchewan (Worth et al., 2014). Aquistore will be the first project in Canada to utilize a saline formation for large-scale storage of CO2 captured from a coal-burning power plant. Carbon dioxide will be supplied from the SaskPower Boundary Dam power plant that began capturing CO2 at a rate of ∼2400 t/day in October 2014. The Aquistore site will act as buffer capacity, intermittently receiving a portion of the captured CO2 , the bulk of which will be transported via pipeline to the Weyburn oil field for the purposes of enhanced oil recovery. The Aquistore storage site anticipates receiving 250–300 ktonnes of CO2 at variable rates of up to 800 t per day. The Aquistore site is located in SE Saskatchewan in the NE part of the Williston basin (Fig. 1). A deep, thick clastic sequence (basal Cambro-Ordovician sandstones of the Winnipeg and Deadwood formations) at the bottom of the sedimentary succession in this area was chosen as the prospective CO2 storage reservoir. This loca-

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Fig. 1. Map showing the location of the Aquistore site and the complete set of detected earthquake locations for the period of 1900–2014. Inset shows the position of the smaller scale map within central North America.

tion and geological storage unit were chosen based on a variety of criteria including: (1) good injectivity based on historical records of waste fluid disposal in the basal sandstone unit elsewhere in the basin (Brunskill, 2004); (2) large capacity given the expected reservoir thickness (>150 m), porosity (10–15%), and regional distribution of the formation (Vigrass, 1971); (3) storage security due to the depth (greater than 3000 m), sealing caprock and multiple thick aquitards above the reservoir; (4) a thick regionally-extensive evaporite unit (Prairie Formation) which provides an excellent regional secondary sealing unit (Khan and Rostron, 2005; Palombi, 2008); (5) low seismic hazard (Geological Survey of Canada, 2015); (6) proximity to the source of CO2 , and therefore a short transport distance; and (7) surface access rights held by SaskPower. Also, the chosen storage formation resides well below the layers which host other natural resources in the area including oil, gas and potash. Thus, there are no wellbore penetrations through the primary seal near the project area. All of these properties indicated that the basal Cambro-Ordovician sandstones would constitute an excellent storage unit. To characterize the storage unit at the chosen injection location in advance of drilling a well, two stages of seismic work were conducted with the following objectives: (1) to map the continuity, thickness and quality of the storage reservoir and by association

the overlying primary seal, (2) to map the basement structure and overlying sedimentary section, (3) to map the secondary regional evaporite sealing unit (Prairie Formation) and determine its continuity and whether dissolution effects are significant, and (4) to identify potential pathways for vertical migration of fluids (e.g., vertical faults, chimney collapses). In stage 1 of the seismic work, an interpretation was made of an existing set of five intersecting 2D seismic profiles in conjunction with geophysical/geological logs from 3 nearby wells (RPS Boyd PetroSearch, 2011). These profiles covered an area of ∼140 km2 and showed no evidence for features that would disqualify the site for storage. Based on that, stage 2 characterization was implemented in which a 30 km2 3D seismic survey was conducted in 2012 (Fig. 2) to provide detailed true3D geological information. The resultant 3D seismic volume has been interpreted in conjunction with the lithostratigraphy from nearby wells and subsequently with the injection well (01/5-6-28-W2M, hereafter referred to as the “injection well”) to identify and correlate seismic reflections with known geological horizons. A preliminary interpretation of the data provided the prognosis for drilling and confirmed the suitability of the proposed injection well location. The results of the 3D interpretation are presented here followed by the implications for the design of the measurement, monitoring and verification program for the site.

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Fig. 2. Aquistore Project site map showing the location of the Boundary Dam Power Plant, the CO2 capture facility, and the CO2 injection well (01/5-6-2-8-W2M well). Also shown is the area of the baseline 3D seismic survey with in-lines (N-S) and cross-lines (E-W) labelled; the numbering system is such that adjacent lines (either inlines or cross-lines) have a corresponding increment of 3. The survey grid is oriented at 358.5◦ .

2. Regional geology The Aquistore storage site is located within the northern part of the Williston Basin which is a regional scale intracratonic basin (Kent and Christopher, 1994). At its geographical centre in North Dakota, the basin reaches a maximum thickness of almost 5000 m, whereas it is 3400 m deep at the Aquistore site. Sedimentary strata of the Williston Basin (Fig. 3) comprise a lowermost Cambro-Ordovician clastic sequence, overlain by Ordovician to Mississippian age rocks that are dominated by carbonates, evaporites and minor shales. In turn, these strata are overlain by Mesozoic rocks that are mostly shales, siltstones and sandstones. The uppermost stratigraphic units consist of a thin sequence of Tertiary and Pleistocene deposits.

The Paleozoic section at the Aquistore site is ∼1700 m thick. Overlying the basal clastic units (Winnipeg and Deadwood formations) is a thick sequence of rocks that are cyclical in nature consisting of porous carbonate intervals capped by non-porous argillaceous carbonates and evaporites. Of the many evaporite sequences within the Paleozoic section, the Middle Devonian Prairie Formation is the best developed and forms a competent regional aquitard that is ∼200 m thick (Marsh and Love, 2014). However, dramatic thinning of the Prairie Evaporite has been observed in places where either carbonate mounds occur in the underlying Winnipegosis Formation resulting in thinner overlying evaporite deposition, or where the evaporite has been subject to post-depositional dissolution (e.g., Dietrich et al., 1999). The basement beneath the basin near the Aquistore site consists of Precambrian metamorphic blocks of the trans-Hudson

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orogen (e.g., Kreis et al., 2000; White et al., 2005) that were variably subjected to relative displacement along basement faults during deposition within the basin (Kent and Christopher, 1994). This influenced depositional patterns, lithofacies, and potentially salt-dissolution within the basin (Whittaker et al., 2004 and references therein). Furthermore, topographic relief on the underlying erosional Precambrian surface directly influenced the resultant thickness of the basal sandstone sequences. Regionally, there are areas where topographic high points on the basement surface result in drastic thinning of the overlying sandstone sequences (Kent and Christopher, 1994). Despite localized areas of reduced thickness, the basal sandstones have been the target of oil production and waste water disposal elsewhere in the basin (Brunskill, 2004). 3. Seismotectonics Southeastern Saskatchewan lies within an intraplate seismotectonic zone and is a region of very low level natural seismicity both in terms of the occurrence frequency and in the range of observed magnitudes. The geographical distribution of recorded earthquakes is shown in Fig. 1. Of the earthquakes shown, the majority (68 of 96) can be associated with industrial activity and primarily potash mining operations near Esterhazy and Saskatoon. These mine-related earthquakes range in magnitude from 2.2 to 4.0 and occurred during the period of 1976–2013. The historical record for minor earthquakes in this area extends back only about 120 years. The ability to locate earthquakes occurring in this area has evolved over time as the density of seismograph stations has increased. The minimum detectable magnitude for events located in this region has decreased from 6 prior to 1936, to 5 in the early 1950s to magnitude 3 by the mid-1960s (Horner and Hasegawa, 1978). The Geological Survey of Canada operated a local seismograph from 1977 to 1992 that provided better coverage during this period. Only two earthquakes were recorded prior to 1968; in 1909 and 1943. The 1909 earthquake is the largest known earthquake (mb = 5.5) from the area. Bakun et al. (2011) have located this earthquake 100 km further west than the epicentre of Horner and Hasegawa (1978), placing it approximately 200 km west of Estevan. This lies on a trajectory defined by earthquake epicentres that correlate with known fault systems (Hinsdale, Weldon-BrocktonFroid), placing the nearest fault system with associated seismicity 200 km to the west of the storage site. Horner and Hasegawa (1978) suggested that reactivation of Precambrian basement faults might be the source of naturally occurring seismicity in the area. 4. Fluid injection history in Saskatchewan

Fig. 3. Lithostratigraphic section modified from Whittaker et al. (2004). Simplified lithologies and hydrogeological classifications (aquifer or aquitard) are defined in the legend.

Fluid injection wells in Saskatchewan have historically served three primary purposes: (1) oil field produced fluid disposal, (2) oil field pressure maintenance and/or miscible flooding, and (3) brine disposal associated with potash mining. To the end of 2003, a comparison of brine injection amounts for oil versus potash activities shows similar cumulative amounts, 656 Mm3 versus 460 Mm3 . However, in the case of oil field activities the quantity of produced brine is similar to the total amount injected (i.e., net injection is close to zero). Also, whereas oil field injection has utilized hundreds of wells, potash brine injection has been implemented using at most 10 wells at an individual injection site resulting in much higher injection rates for the latter. For example, average annual injection rates since 1994 for some potash waste-water disposal wells are as high as 2 Mm3 of brine per year into the Winnipeg and Deadwood formations (Brunskill, 2004). To provide a basis for comparison, 800 t of CO2 per day equates to approximately 0.5 Mm3 of CO2 per year, calculated based on the density of CO2 at pressures and temperatures representative of the Aquistore reservoir.

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Oil-field related water injection has been ongoing in the Weyburn-Midale field to the NW of the Aquistore site since the 1960s with no demonstrable related induced seismicity (see Fig. 1; also, Verdon et al., 2016). Although potash fluid disposal cannot be entirely ruled out as a potential cause of induced earthquakes near the potash mines, early site-specific investigations (Gendzwill et al., 1982; Prugger and Gendzwill, 1990) have concluded that these earthquakes are associated with brittle failure above the mining excavations (Hasegawa et al., 1989; Gendzwill and Stead, 1992). 5. Storage reservoir and caprock The Winnipeg and Deadwood formations, which constitute the deepest units within the sedimentary sequence, have been chosen as the target zone for CO2 injection. The Deadwood Formation is a regionally extensive sandstone of variable grain-size that contains intervals of silty-to-shaley interbeds with some calcareous layers present. The overlying Winnipeg Formation consists of a lower sandstone (Black Island Member) and an upper shale (Icebox Member) that forms the caprock or primary seal impeding vertical migration of CO2 . Hydraulic properties obtained using core analyses and drill-stem tests from sandstones in the Winnipeg-Deadwood interval of a test well ∼200 km north of the Aquistore site (the University of Regina Geothermal) well (3-8-17-29W2) showed permeabilities of ∼100–1000 mD and porosities of ∼11–17% (Vigrass et al., 2007). These values are indicative of good injectivity potential. Furthermore, historical records of brine injection associated with potash mining at Belle Plaine and elsewhere also indicate the Winnipeg-Deadwood interval has excellent injectivity and capacity potential (see previous section). However, well information to the SE in the deeper parts of the basin shows an increase in shale content and reduced porosities within this interval. Thus, reservoir characterization from the initial wells drilled at the Aquistore site was essential. 6. 3D geological characterization The regional geological architecture near the storage site is well known from large-scale compilations (e.g., Whittaker et al., 2004 and references therein). Specific details of the storage site are provided by the analysis of core samples, well logs and injection tests from the two wells (see Rostron et al., 2014). The 3D seismic data acquired at the site in 2012 was designed to provide the lithostratigraphic framework covering an area comparable to the expected areal extent of the CO2 plume. The specific objectives were: (1) to ascertain the continuity, thickness and quality of the storage reservoir and associated caprock/primary seal; (2) to map the basement structure and overlying sedimentary section; (3) to test the regional continuity of evaporites in the Prairie Formation; and (4) to look for pathways for potential vertical migration of fluids. 6.1. 3D seismic data acquisition and processing 3D seismic acquisition was conducted in March, 2012. The acquisition parameters are provided in Table 1. Winter conditions existed at the start of the survey, with the near-surface ground being fully frozen. However, as the survey progressed, the ground thawed rapidly resulting in soft muddy conditions and variable source-to-ground coupling. To compensate for the muddy conditions, the Vibroseis peak force was reduced in some areas resulting in decreased signal-to-noise levels. The seismic processing flow is provided in Table 2. Significant effort was made during processing to reduce the effects of noisy data. This was greatly aided by the dense spatial sampling of the wavefield that was achieved by the 6 m in-line geophone spacing

Table 1 Seismic acquisition parameters and well log list. Survey Area: 30 km2 Acquisition system: UniQ Acquired March 16–22, 2012 Source parameters: Vibroseis source 2–100 Hz sweep 2–12 s sweeps per VP 2 AHV-IV 62,000 lb buggy vibrators, nose-to-tail 5 s record length 2 ms sample rate 288 m line interval, 36 m in-line interval 2411 vibration stations Receiver parameters: Single vertical component geophone per station Schlumberger geophone accelerometer (18 Hz, −3 dB at 2 Hz) 2 ms sample interval, 24-bit sigma-delta A/D conversion 288 m line interval, 6 m in-line interval 18,100 geophones Natural bin size: 3 m × 18 m Full fold: 88 Offset range: 220 m–5388 m Well log acquisition included monopole sonic (Vp, Vs), gamma ray, density, resistivity, neutron porosity, elemental capture spectroscopy, and ultrasonic imaging. Table 2 Seismic processing flow. Stage 1 prestack processing steps 2.1 Survey geometry input 2.2 Grid definition: 18 m × 18 m binning 2.3 Refraction tomography statics: 600 m elevation datum, 2200 m/s replacement velocity, initial weathering velocity 1200 m/s 2.4 Time function gain: t2 2.5 Despike using anomalous amplitude attenuation 2.6 Minimum phase conversion 2.7 F-X coherent noise suppression in shot domain 2.8 Anomalous amplitude attenuation in shot domain 2.9 Anomalous amplitude attenuation in cross-spread domain 2.10 3D random noise attenuation in cross-Spread domain 2.11 Surface consistent deconvolution 2.12 Velocity analysis (1st pass: 1152 × 1152 m analysis spacing) 2.13 Residual statics (1st pass: 600–2000 ms, max shift = 32 ms) 2.14 F-X coherent noise suppression in shot domain 2.15 Anomalous amplitude attenuation in shot domain 2.16 Surface-consistent amplitude compensation 2.17 Anomalous amplitude attenuation in CMP domain 2.18 Anomalous amplitude attenuation in cross-spread domain 2.19 3D random noise attenuation in cross-spread domain 2.20 Velocity analysis (2nd pass: 756 × 756 m analysis spacing) 2.21 Residual statics (2nd pass: 600–2000 ms, max shift = 32 ms) Stage 1A prestack time migration (PSTM) additional processing steps 2.22 Offset definition and regularization: offset group size = 144 m, offset increment = 72 m, offset range = 72–5040 m 2.23 Anisotropic velocity analysis for PSTM (576 m × 576 m analysis spacing) 2.24 Migration velocity preconditioning (smoothing radius: 2 km at 0 ms, 3 km at 5000 ms) 2.25 Anisotropic (VTI) Kirchhoff prestack time migration; single eta(z) function 2.26 Common midpoint sort 2.27 Inverse NMO correction 2.28 Post migration stacking velocity analysis (576 m × 576 m analysis spacing) 2.29 Radon multiple attenuation Stage 2 prestack processing steps 2.30 Box mean scaling 2.31 NMO compensation 2.32 Outer trace mute 2.33 Stack Stage 3 post-stack processing steps 2.34 Post-stack Kirchoff isotropic time migration (non-PSTM flow only) 2.34 Footprint removal (K-Notch Filter) 2.35 3D FK dip filter 2.36 Trace-by-trace time variant spectral whitening (TVSW) 2.37 Zero-phase conversion 2.38 Time-to-depth conversion

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Table 3 Geological unit tops and corresponding two-way reflection travel times for corresponding seismic horizons at the injection well. Depths are from the geological log and are measured relative to the Kelly bushing (575 m elevation). Right-most column displays the interval velocities used for time-to-depth conversion of the 3D seismic volume. Seismic Horizon

Reflection polarity

Time (s)

Depth (m)

Interval Velocity (m/s)

Lower Colorado Mannville Watrous Poplar Bakken shale Torquay Birdbear Dawson Bay Prairie Evaporite Winnipegosis Ashern/Interlake Winnipeg Winnipeg sand Deadwood Precambrian

Peak Peak Peak Peak Trough Peak Peak Peak Trough Peak Peak Trough Peak Peak Peak

0.856 1.001 1.218 1.275 1.448 1.473 1.492 1.594 1.608 1.677 1.739 1.824 1.836 1.854 1.915

996 1147 1506 1625 2120 2150 2208 2493 2540 2694 2715 3156 3181 3224 3410

2279 3023 4650 5264 5260 5674 7290 4452 6527 6110 4363 4872

Fig. 4. Seismic well tie. From left to right are: log-based synthetic seismic trace (gray) superposed on the 3D seismic data at the injection well location, tops of a subset of geological units, compressional-wave velocity log (Vp), acoustic impedance log (AI) calculated from the Vp and density logs, and the natural gamma ray log. As displayed, the two-way travel time axis scale is uniform. The corresponding depths (variable scale here and in Figs. 5–7) are determined using the velocities determined from the well-tie process. A zero-phase wavelet statistically determined from the 3D data was used for the seismogram calculation and well-tie procedure. The correlation value of the synthetic seismogram and the 3D data near the injection well site is 0.91 indicating excellent correlation. Seismic horizons identified by correlation with wellbore geology are labelled. The seismic amplitudes are normalized and thus are unitless here and in subsequent seismic figures.

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Fig. 5. Crossline 4593 (west-to-east section) from the 3D time migrated seismic volume located approximately 100 m north of the injection well. The location of the injection well projected orthogonally onto the section is indicated by the derrick symbol. Inset (left) shows the well-tie between the 3D seismic data and the synthetic seismogram from Fig. 4. Seismic horizons identified by correlation with injection wellbore geology are labelled.

and the use of >18,000 live channels. In particular, several passes of noise attenuation were applied. Processing was implemented in two separate flows. The first processing flow was designed to quickly produce a 3D volume for interpretation and production of a pre-drilling prognosis. It constituted a prestack time processing sequence (stages 1 and 2 in Table 2) followed by post-stack time migration using an isotropic velocity model and time-todepth conversion (stage 3 in Table 2). Time-to-depth conversion was implemented using velocity logs from existing wells in the surrounding area. Well-based interval velocities were combined with seismic horizons picked in the 3D migrated time data vol-

ume to build a velocity model for depth conversion. The second processing flow implemented a prestack time migration with an anisotropic velocity model and Radon multiple suppression (stage 1A in Table 2) in addition to what was implemented in the first processing flow. The injection well had been drilled by the completion of this more sophisticated processing flow and so the velocity model for time-to-depth conversion was built using log-based interval velocities from the injection well (Table 3). The seismic data interpreted and presented below correspond to either the time or depth data volumes resulting from the second processing flow.

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Fig. 6. South-to-north section (inline 3788) from the 3D time migrated seismic volume. The intersection with crossline 4593 (Fig. 5) is indicated by the red line. The location of the injection well on the section is indicated by the derrick symbol.

6.2. 3D seismic interpretation Fig. 4 shows a comparison of the 3D seismic data with a 1D synthetic seismogram calculated for the Aquistore injection well. A very good correlation (0.91) between the synthetic seismogram and the seismic data provides corroboration that the seismic data are accurately portraying the sedimentary section. Vertical sections through the 3D seismic cube are shown in Figs. 5 and 6 with the interpreted geological horizons labelled. Reflections corresponding to the sedimentary layers are generally continuous across the area and dip gently to the SSE at ∼1–2◦ . The reservoir interval (Winnipeg-Precambrian) is observed toward the base of the sec-

tion and the top of the evaporites of the Prairie Formation occurs at ∼1600 ms. Fig. 7 focuses in on the deeper part of the section closer to the reservoir zone where the following can be observed: (1) The reservoir caprock/primary seal (shales of the Ice Box Member) and the top of the regional secondary seal (Prairie Formation) are continuous across the region and show no evidence for vertical offsets. (2) Evaporites of the Prairie Formation (Prairie EvaporiteWinnipegosis) are fully developed with a thickness of ∼150 m. (3) The Precambrian basement shows subdued relief across the section. (4) The reservoir interval (Winnipeg-Precambrian) is continuous and is ∼200 m thick. (5) In general, there are no vertical offsets observed that might be indicative of faults. (6) There are lateral

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Fig. 7. West-to-east section (cross-line 4584) from the 3D time migrated seismic volume across the injection well location showing the depth interval comprising the regional secondary seal (Prairie Formation) down to the Precambrian basement.

Fig. 8. Amplitude determined at the Prairie Formation horizon in the 3D migrated seismic horizon. UTM coordinates (labelled) are in metres here and in subsequent figures.

variations in the reflection amplitudes, but these are thought to be primarily related to the seismic acquisition footprint as opposed to representing geological variations, as will be explained below. Lateral variations in the reflection amplitudes can be illustrated with the Prairie Formation seismic amplitude map (Fig. 8). The carbonate-to-salt interface of the top of the Prairie Formation produces a strong negative amplitude reflection that should be uniform due to the thickness of the evaporite. However, the observed vari-

ability in the amplitudes in Fig. 8 demonstrates the impact that edge effects, acquisition footprint and variable fold have on seismic amplitude. The Precambrian basement reflection is of variable quality over the 3D volume, but it can be picked with some confidence over most of the survey area. The interpreted Precambrian surface shown in Fig. 9a is characterized by topographic relief of up to 60 m. The large-scale topographic highs and lows trend primarily in a NNW-

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Fig. 9. (a) Precambrian surface elevations interpreted from the 3D seismic volume. The elevations indicated are relative to a mean planar surface that was fitted to the seismic picks of the Precambrian seismic horizon. The mean plane dips to the SSE (157◦ clockwise from north) at ∼1◦ . The labels ‘A’ are described in the text. (b) Isopach for Precambrian and Icebox Member horizons corresponding to the storage reservoir interval. The location of the injection well is indicated by the white circle.

SSE direction (e.g., feature A in Fig. 9a) which is subparallel to the trend of basement structural domains interpreted from potential field maps for the area (cf. Kreis et al., 2000; White et al., 2005). The injection well (white circle) is located on the edge of a local topographic low in the Precambrian surface. Fig. 9b shows the reservoir interval thickness including the shale caprock (Icebox Member). Comparison with Fig. 9a indicates a strong correlation between the thickness of the reservoir sedimentary units and the topography on the underlying Precambrian surface. This suggests that most of the topography on the Precambrian surface predates deposition of the overlying Deadwood and Winnipeg formations. Although the reservoir thickness varies by 40 m, it is at least 200 m thick across most of the area. Fig. 10 shows the interpreted depth interval between the top of the reservoir (Winnipeg horizon) and the overlying Winnipegosis horizon. There is a distinct NNW-trending linear structural feature (A in Fig. 10) where this interval thickens abruptly by ∼25 m from west-to-east. This feature corresponds to a flexure in strata below the Prairie Formation with a maximum dip of ∼7.5◦ (28 m over 210 m) as measured at the Winnipeg horizon in the northern part of the survey area (Fig. 11). Attribute plots at the top of the reservoir and extending down into the reservoir (Fig. 12a and b) demonstrate that this lineation extends through the reservoir. This lineation can be traced through to the bottom of the Winnipeg-Deadwood formations. The trend and location of this structural feature also correlates very well with the comparable feature observed on the Precambrian surface (A in Fig. 9a) where the basement surface drops abruptly by ∼20 m across the lineation. This is consistent with the eastward down-warp of the flexure, and suggests that the flexure may be the result of syn- to post-depositional movement on a basement fault. Profiles orthogonal to the flexure suggest the sediments form a monoclinal fold. There is no clear evidence that the strata are ruptured or faulted. The structural deformation is confined to rocks older than the Winnipegosis. As seen in the attribute plots for the Winnipegosis and Prairie Formation (Fig. 12c and d), there is no indication of the structural feature (A) that is observed in the older underlying units. The Prairie Formation isopach (Fig. 13) demonstrates the regional continuity of this unit with a thickness of 140–160 m over most of the region. Furthermore, there is little evidence to sug-

gest that the flexural structure observed in deeper strata affects the Prairie Formation. The Prairie Formation in this region does not appear to have been subject to rapid, local salt solution processes at any time since deposition. However, two small zones of local salt thinning in the NW (M1 and M2 in Fig. 13) correspond to partially developed Winnipegosis mounds. The salt thins to less than 130 m in these regions implying mound height development of up to 40 m. There does not appear to be any expression of the flexure within the strata overlying the Prairie Formation.

7. Discussion The 3D seismic data are devoid of through-going vertical structures that would indicate the presence of potential vertical pathways for the upward migration of CO2 from the reservoir. The Prairie Formation, considered to be the regional secondary seal for CO2 storage, is bereft of salt solution features in this area as indicated by its uniform thickness of ∼150 m and near-constant seismic attributes. Above the Prairie Formation, the seismic data image1500 m of Middle Devonian to Lower Cretaceous strata that are continuous across the area. In turn, these strata are overlain by 1000 m of Upper Cretaceous and younger sedimentary rocks. Lying within the interval above the Prairie Formation are several thick tertiary sealing units including the Watrous Formation (∼120 m), Colorado Group (>185 m), and Bearpaw Formation. It is noteworthy, that the Prairie Formation lies well below the stratigraphic level of CO2 storage at the Weyburn-Midale field (Charles Formation, e.g., Whittaker et al., 2004). This is indicative of the additional sealing security present at the Aquistore site. The only potential vertical pathway identified in the 3D seismic interpretation is the monoclinal flexure that exists in strata below the Prairie Formation. The flexure appears to extend through the Icebox Member and upward to the Winnipegosis Formation. It is interpreted as a monoclinal fold resulting from syn- to-postdepositional movement of the underlying Precambrian fault blocks with east-side-down movement. The ‘convex upward’ shape of the flexure may produce local tensile stress and potentially fracturing in its apex (e.g., Sharp et al., 2000) implying that the reservoir cap may be disturbed. However, there are no occurrences of off-

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Fig. 10. Winnipegosis to Winnipeg isopach map. The labels ‘A’ are described in the text. The location of the injection well is indicated by the white circle.

Fig. 11. West-East line (cross-line 4899) showing the Silurian flexure.

set reflections that would be a clear indication of a fault, though it is possible that faulting exists at a scale below seismic detection. The possibility that this flexure could represent a zone of weakness and hence a leakage pathway during CO2 injection suggests that it should be an observational target during monitoring of the CO2 project. Injection and storage of CO2 within the deepest clastic formations (Winnipeg and Deadwood) within the Williston Basin

provides the storage security associated with having multiple overlying regional seals. However, injection of fluids into reservoir rocks that are either immediately above or in direct pressure communication with the Precambrian basement is known to have a higher occurrence of induced seismicity (e.g., Kim, 2013; Verdon, 2014). The induced seismicity usually results from the reactivation of existing basement faults that is caused by a reduction in effective normal stress across the fault due to increased pore pressure

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Fig. 12. Smoothed dip of maximum similarity attribute calculated for data flattened on the Winnipeg horizon for (a) Winnipeg horizon, and (b) 80 m below the Winnipeg horizon. The lineation trends at 10–20◦ west of north and appears to be subvertical. (c) and (d) show the same attribute at the Winnipegosis and Prairie horizons for data flattened on these horizons, respectively. The location of the injection well is indicated by the white circle. This geometric attribute is determined at each point in the 3D volume by calculating the local data similarity (or semblance) for a range of dips, and then selecting the dip for which the similarity is maximum.

Table 4 Parameters used for fault reactivation analysis. Parameter

Value

Comment/Source

Depth Minimum horizontal stress magnitude

3410 m 61.4 MPa

Vertical stress magnitude

84.2 MPa

Maximum horizontal stress magnitude

84.2 MPa

Maximum horizontal stress azimuth

65◦

Pore pressure

36.5 MPa

Maximum effective stress used for fault reactivation analysis Minimum effective stress used for fault reactivation analysis

47.7 MPa

Approximate top of Precambrian basement Based on gradient of 18 kPa/m, estimated from stress profile calculated using mechanical properties derived from dipole shear sonic log calibrated to wireline microfracture tests conducted at depths of 3140 and 3189 m. Calculated using bulk density logs from ground surface to depth of interest; corresponds to gradient of 24.7 kPa/m. Normal fault stress regime inferred for this area suggests  H min <  H max <  V (Bell and Babcock, 1986). Assumption of  H max =  V used for this analysis represents worst-case scenario for fault reactivation potential. Values ranging from 60◦ to 70◦ interpreted from borehole breakouts visible in ultrasonic borehole imager logs for the Aquistore injection and observation wells. Consistent with regional trend interpreted by Bell and Grasby (2012). Corresponds to gradient of 10.7 kPa/m, interpreted from well tests conducted in Deadwood Formation. Maximum horizontal stress magnitude (84.2 MPa) – pore pressure (36.5 MPa) Minimum horizontal stress magnitude (61.4 MPa) – pore pressure (36.5 MPa)

24.9 MPa

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Fig. 13. Prairie Formation isopach calculated using a salt velocity of 4400 m/s and the two way reflection time measured between the Prairie and Winnipegosis horizons. Note the two small zones of thinning in the NW (M1 and M2) that correspond to mounds in the underlying Winnipegosis carbonate. The location of the injection well is indicated by the white circle.

Fig. 14. Slip analyses for sub-vertical basement fault, using in-situ stress magnitudes and orientations estimated for the Aquistore site, and conservative assumptions for fault strength parameters.

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(e.g., Hubbert and Rubey, 1959) associated with the injection of CO2 . Although the nearest known seismogenic fault zone of significance is ∼200 km away from the CO2 storage site, the basement fault identified in the 3D seismic interpretation could be at risk for reactivation. The likelihood that this interpreted fault could be reactivated during CO2 injection is controlled by the effective insitu stresses acting on it, which in turn are a function of in-situ stress magnitudes and orientations, fault orientation and pore pressure. Using estimates for these parameters derived from available data and literature (see Table 4), a fault reactivation analysis was undertaken using industry-standard methods (e.g., Zoback, 2007). As illustrated in Fig. 14, the results suggest the fault should not be susceptible to reactivation at initial conditions, nor as pressures increase due to injection into the overlying Winnipeg and Deadwood formations. This favourable result is dominated by the azimuth of the fault (10◦ –20◦ west of north) relative to the maximum horizontal stress ( H max ) azimuth (65◦ east of north); more specifically, the fact that the fault azimuth is rotated 75◦ –85◦ from the  H max azimuth. As this relative orientation approaches 90◦ (i.e., the angle  shown in the inset of Fig. 14 approaches 0◦ ), the shear stress acting on the fault plane tends to zero. In spite of this favourable scenario, the interpreted basement fault and overlying flexure will clearly be targets of interest during monitoring of CO2 injection. 8. Conclusions Interpretation of 30 km2 of 3D seismic data around the Aquistore CO2 storage site in conjunction with log information from a 3400 m injection well and consideration of the local seismotectonics indicates that the site has the essential geological features required for large-scale CO2 storage. These features include: (1) A clastic reservoir that is part of a regionally extensive formation and maintains a thickness of >200 m throughout the area. It is overlain by a 15 m thick shale caprock that is laterally continuous and shows no evidence for vertical faulting. (2) The regional evaporitic seal (Prairie Formation) appears to be laterally continuous, is at least 150 m thick and shows no salt dissolution features. (3) Above the Prairie Formation, 1500 m of Middle Devonian to Lower Cretaceous strata are continuous across the area, and in turn are overlain by 1000 m of Upper Cretaceous and younger sedimentary rocks. Included in this sequence are several thick tertiary sealing units including the Watrous Formation (∼120 m), Colorado Group (>185 m), and Bearpaw Formation. (4) There is no evidence of vertical faulting that extends above the Silurian section (or ∼2700 m depth). (5) The site is located in a region of very low natural seismicity with the nearest known significant seismogenic fault zone located ∼200 km away. (6) An interpreted local sub-vertical basement fault is oriented at an azimuth of 75◦ –85◦ relative to the regional maximum horizontal stress making it unlikely that the fault will be susceptible to reactivation during CO2 injection. There is no clear evidence that the strata in a flexure observed in overlying Cambrian to Silurian sedimentary rocks are ruptured or faulted. However, the basement fault and associated flexure will be primary features for monitoring during CO2 injection at the site. Acknowledgements The seismic interpretation presented here was based partly on an internal report provided by RPS Boyd Petrosearch. The Aquistore CO2 Storage Project is managed by the Petroleum Technology Research Centre, Regina, Canada. The 3D seismic data were acquired and processed by Schlumberger-WesternGeco. Funding for this research was provided in part by Natural Resources Canada, Sustainable Development Technology Canada, Saskatchewan Go

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Green Fund, Enbridge, SaskPower, Schlumberger Carbon Services, Korea National Oil Corporation, SaskEnergy and Research Institute of Innovation Technology for the Earth. This is contribution 20150487 of the Geological Survey of Canada.

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