Assessment of Carbon Dioxide Storage Capacity of Selected Aquifers in ‘J’ Field, West Africa

: A combination of seismic data and petrophysical logs from five wells acquired in ‘J’ Field, Niger Delta, Nigeria, have been analyzed to assess the carbon dioxide (CO 2 ) storage potential of some saline aquifers in ‘J’ field. The study aims to evaluate the volume of CO 2 that can be potentially stored in the aquifers and the risk of CO 2 leakages in the storage. The sand aquifers were correlated across the five wells to evaluate their thicknesses and lateral extent. Porosity, permeability, formation water resistivity, and net sand thickness were estimated in the different wells. The Horizons corresponding to the top of the aquifers was mapped, and time and depth structured maps were generated for structural analysis and volumetric estimations. The risk of CO 2 leakages through sealing layers (cap rocks) was evaluated in terms of caprock integrity and pore pressure sealing mechanism. Results of the study showed that four aquifers, namely, L20, N30, M40, and P50, are laterally extensive across the five wells and have thicknesses that range from 14 to 352 m. The individual CO 2 storage capacity of L20, M30, N40, and P50 was estimated to be 6.97×10 10 , 1.48×10 10 , 7.78×10 9 and 1.49×10 10 tons, respectively. The combined aquifer storage capacity was estimated to be 1.07×10 11 tons. The sealing layers have low risk of CO 2 leakages. The study concluded that the aquifers have good potential for CO 2 storage and low risk of leakages. The study ranked L20 as the best among the four aquifers.


INTRODUCTION
Emission of gases by large industries, oil refineries, and automobile engines releases a vast amount of CO2 and other air pollutants to the atmosphere, thereby contributing to the greenhouse gas effect. Globally, about 80% of the greenhouse gas emission is attributed to CO2 released to the atmosphere from fossil fuel during energy production and consumption (Metz et al., 2006;Bachus, 2015;2016;Berghout et al., 2019). Despite the global efforts to generate energy from non-fossil fuel sources such as solar and wind, about 80% of the global energy need is still being met from fossil fuel (IEA 2017;EPA 2018). Therefore, there is a need to develop strategies to deal with the negative consequences of the consumption of fossil fuels while maximizing the efforts to increase non-fossil fuel sources of energy. The leading solution to greenhouse gas and consequential global warming is to isolate and store CO2 away from the atmosphere in a geological storage. Studies that confirmed the safety and reliability of Carbon Capture and Storages and demonstrate the capability of Seismic Tomography for detecting CO2 leakages in geological formations include Saito et al. (2006), Ajo-Franklin et al. (2013), Chadwick et al. (2014), Chadwick et al. (2016), Furre et al. (2015), Raji et al. (2018) and Raji et al. (2021). The new trend in Carbon Capture and Storage, CCS research is to characterize the storage site and quantify the volume of CO2 that can be stored in some of the geological formations.
CCS is the method of capturing carbon dioxide which would have been released to the atmosphere, converting the CO2 to a supercritical state, and injecting them into deep geological formations such as depleted oil and gas reservoirs, deep saline aquifers, deep coal seams, and salt caverns, among others. CO2 storage in a subsurface geological formation requires site characterisation, estimation of the potential storage capacities, and evaluation of the risk of leakages in the geological formation. These three factors are important for the safety of the environment. The prior knowledge of the quantity of CO2 that can be stored in local fields and the property of the regional geological formation is crucial to the successful execution of CCS projects. Estimation of the volume of CO2 that can be stored in the saline aquifers in 'J' Field, Nigeria, and evaluation of the risk of leakages are the key foci of this paper. To the best of the author's knowledge, the only published study on CO2 sequestration potential of saline aquifers in Nigeria is a recent paper by Raji et al. (2021). At the same time, this type of studies are important to demonstrate the readiness of Nigeria to comply with the Kyoto Protocol and United Nations Framework Convention on Climate Change and global warming. Furthermore, the 2015 World Bank report showed that Nigeria is rated number 39 on the global ranking of carbon emission from all sources.
Studies by Saito et al. (2006), Ajo-Franklin et al. (2013), Xu and Lei (2006), Bohm et al. (2015 among others have shown that injection of CO2 into saline water aquifers or hydrocarbon reservoirs can change the seismic velocity of the reservoirs or aquifers by up to 30%. Seismic velocity tomography can be used to image the velocity changes in the CO2-injected geological structures to monitor possible leakages. Raji et al. (2018) simulated the time-lapse CO2 movement in a complex reservoir structure of Marmouzi in Angola. The study showed the capability and effectiveness of Seismic Velocity Tomography for monitoring the movement of CO2 in stratigraphically complex geological storages. The accurate estimates of CO2 containment of a sequestration site are critical for determining the life span of a storage site, facility costing, and field planning prior to injection. Saline aquifers, when compared to other geological formations such as oil reservoirs and coal beds in terms of CO2 storage capacity has the largest storage capacity. This is because some of the aquifers are regional in size and have higher porosities compared to hydrocarbon reservoirs and coal seams. For this reason, saline aquifers are considered as the most abundant geological storage for CO2 (Tomić et al. 2018). This is especially true for Nigeria.
The first project on CO2 storage in offshore saline aquifer in Europe started in 1996 in Sleipner -Norway. More than 17 Mt. of CO2 has been injected into the aquifer (I.E.A., 2017). A large project on CO2 storage in onshore saline aquifer is ongoing in Salah, Algeria and Weyburn, Canada -where over 1 Mt CO2 is being injected into the aquifers per year (Ajofranklin and Orr 2009). Unlike in developed world like U.S.A., Australia, Norway, Canada, and Netherlands where there have been extensive published studies on CO2 storage potentials of subsurface geological media (e.g., Bachus, 2002;Friedman et al., 2005;Solomon, 2007;Kaldi and Gibson-Poole, 2008;Ramirez et al., 2009;Godec et al., 2013;Boyd et al., 2013;Sayer et al., 2013), studies on carbon capture and storage, CCS in Nigerian geologic space are scarcely published. To the best of our knowledge, except (Raji et al. 2021), there are no published studies on CO2 storage potentials of aquifers in Nigeria. However, published research work on CO2 storage potential and leakage assessment in Nigerian are essential to demonstrate prior knowledge and state of the art for future projects.
Further, recent studies showed that the nature of CO2brine-rock behavior in geosequestration site depends on phase of CO2, the mineral composition of the rock, and the age of the storage (Peter et al., 2022). Visco-acoustic modelling of P-and S-waves velocity models of complex structures suitable for CO2 storage and wavefield separation of complex seismic data are described in Raji (2017) and Raji et al. (2019). The future research agenda include large scale storage at GtCO2/year and reservoir characterisation from nano to kilometer scales (Kelemen et al., 2019). The current study extended the work of Raji et al. (2021) which estimates the volume of CO2 storable in some saline aquifers in the Niger Delta of Nigeria by including the computation of spatial petrophysical maps of aquifer properties and the assessing the potential of CO2 leakages in the cap rocks. The overall aim of this study is to evaluate the volume of CO2 that can be potentially stored in the aquifers and the risk of CO2 leakages in them.

DELTA
The study area is located in the Niger Delta Province of Nigeria. A detailed description of the field is not provided for proprietary reasons. The Niger Delta is located between latitude 4 o and 6 o N, longitude 3 o and 9 o E ( Figure 1). It is formed by a rift basin in relation to the opening of the South Atlantic Ocean. It is one of the largest sub-aerial basins in Africa, covering about 300,000 km 2 with sediment fill of 9 -12 km. The geology of the area originally described by (Short and Stauble, 1967;Doust and Omatsola, 1990) is briefly reviewed in this section. The three main lithostratigraphic units in the Niger Delta are: (i) shale dominated Akata Formation, (ii) the sand dominated Agbada Formation, and (iii) the Benin Formation. Akata formation is the lowest and oldest unit. This formation underlies the entire Niger Delta area having sediment thickness up to 7 km in some places (Doust and Omatsola, 1990). Akata formation's age ranges from Paleocene to recent and it primarily consist of shale, clay and silt. The shale in Akata formation forms the potential source rock. The shale is sufficiently thick and rich in organic matter capable of generating hydrocarbon (Evamy et al., 1978).
Agbada formation overlies the Akata formation and is made of sand and shales of fluvio-marine origin. Agbada is the main hydrocarbon-bearing interval in the Niger Delta (Evamy et al., 1978). The formation is about 3700 m thick, dated Eocene to recent. The Agbada formation forms the hydrocarbon-prospective sequence in the Niger Delta. Most exploration wells in the Niger delta have bottomed in the Agbada formation. Hydrocarbon traps in Agbada formation are formed by stratigraphic traps. In few cases, we have structural traps and a combination of structural and stratigraphic traps. Roll-over anticline, which occurs in front of growth faults, is the main target of hydrocarbon explorationists in the Niger Delta of Nigeria. Agbada formation houses the reservoir, the trap, and the seal. In the exploration sense, the Agbada formation is the most important lithofacies in the Niger Delta petroleum system. (Jibrin and Raji 2014; Adeoye et al. 2018).
The Benin formation is the youngest (Oligocene to Recent) and shallowest among the three lithofacies in the Niger Delta. It directly overlies the Agbada formation and consists of coarse-grained to gravelly sandstones. Benin formation hosts the most prolific aquifers in the Niger Delta region of Nigeria. The aquifers range from shallow to intermediate and deep. The deep aquifers in the Benin Formation are the candidate facility for CO2 storage in this study. The deep aquifers have good internal regional hydraulic connections and are separated by shale layers of significant thickness. These shale layers have characteristic low permeability and porosity to serve as cap rocks for the aquifers and hence made these sand layers good candidates for the storage of CO2.

A. Materials
To estimate the potential CO2 storage capacity of any geological formation, the evaluation of the area, thickness, porosity, and permeability, among other properties of the formation are required. This information is often derived from well logs and core data. The data used for this study were provided by the Department of Petroleum Resources (DPR), Nigeria. The data set comprised petrophysical logs from five wells and 3D seismic data covering the 'J' Field.
The wells are named Pearl 01, 02, 03, 04, and X01; the welllogs provided include gamma, resistivity, spontaneous potential, and porosity. Core data from the wells were not available for this study. Five thick and laterally extensive saline sand aquifers penetrated by the wells were selected for the study. Seismic and well logs data were evaluated using volumetric approach and Petrel 2009 (by Schlumberger) was used to plot the maps and correlate the aquifers across the wells in the area.

B. Evaluation of the Selected Aquifers and Estimation of their Storage Capacity
A combination of gamma-ray and spontaneous potential (SP) log was used to discriminate sand from shale layers using a cut of 70 American Petroleum Institute (API). Then, resistivity logs were used to ascertain that the thick sand aquifers selected were saline aquifers, not freshwater aquifers. The values of the deep resistivity logs were examined at the reservoir intervals and compared to the freshwater resistivity in the same area. The resistivity of fresh water in the Niger Delta is typically greater than 10 Ωm (Oteri, 1987).
The selected aquifers were examined for lateral continuity across the five wells using lithologic correlation. The lithologic correlation template in Petrel 2009 version was applied to correlate the sand layer in one well to the equivalent sand layer in another well and then across all the five wells. Consequent to the correlation, one of the five sand layers that were initially selected for the study was rejected due to poor lateral continuity. The four sand layers that have good lateral continuity and vertical extent were further evaluated. For references and clarity, the four saline aquifers were named L20, M30, N40, and P50. The gross thicknesses of the saline aquifers were estimated from the logs, and then the net thicknesses Nt. Other petrophysical parameters such as formation water resistivity, hydraulic conductivity, porosity and permeability of the aquifer were also estimated within the aquifer intervals and plotted for spatial correlation.
The 3D seismic volume has been preprocessed for signal enhancement and interpreted to better define the structural framework of 'J' Field. Well-to-seismic tie were performed to determine the horizons that correspond to the top of the saline aquifers on the seismic section. Synthetic seismic data were generated from density and velocity (inverse sonic log) logs using the reflectivity method and Ricker wavelet as the source impulse. Then, the horizons corresponding to the top of the four aquifers, namely, L20, M30, N40, and P50 were picked using seed detection and line-based interpretation strategy. Time-domain structural maps were generated for each aquifer. Then, the time structured maps were converted to their corresponding depth-structured maps using the check shot data. The depth structured map was used to calculate the aquifer surface area required for volumetric estimations, to evaluate the structural framework and the potential trapping mechanism within the aquifers.
The CO2 storage capacity, G_CO2 of the individual aquifer was calculated following the method of Bachus (2015) as: where: is the average area of the aquifer, ℎ is average thickness of the aquifer, is the average porosity, 2 is the density, E is the storage efficiency factor, and is the average water saturation.
The density of supercritical CO2 at depth interval of 1000 to 2500 and temperature of 67oC is 0.54 g/cm3 (or 540 kg/m3). In addition to the storage property and the viscousity of the fluid, the CO2 storage efficiency, E of an aquifer depend on a combination of four factors described in Bachus (2015). These factors include: (i) the in situ conditions of the aquifer (temperature, pressure, lithology, porosity, permeability, heterogeneity, anisotropy, among others); (ii) characteristics of the confining aquitard or cap-rock (capillary entry pressure and permeability); (iii) characteristics of CO2 operationinjection rate, duration of injection, number of injection wells and their spacing, and (iv) regulatory constraintsthe maximum bottom hole injection pressure, relevant aquifer area, and the scale of assessmentlocal or regional. The results obtained are presented in Figures 2 to 5 and discussed in Section IV.

C. Evaluation of the Caprocks for Leakages
The caprocks (or seals) covering the aquifers were examined for the possibility of CO2 leakages. The sealing layers to the aquifers were mapped, their thickness and lateral coverage were evaluated from the well logs. The densities of each of the four sealing layers were plotted against depths following Skerlec's model (Skelec, 1982) to evaluate the insitu ductile-brittle behaviour of each sealing layer/cap rocks and to predict their response to pressure. The results obtained are presented in Figures 6a and 6b and discussed in the next sections.

IV.
RESULTS AND DISCUSSION The correlation panel in Figure 2 showed that the selected four saline aquifers are sufficiently thick and laterally continuous across the five wells. This suggests that the aquifers can store a significant quantity of CO2.
Further, Figure 2 also shows that saline aquifers are located within a depth range of 910 and 2300 m, which is higher than the minimum depth of 800 m required for a CO2 storage site. The higher the depth, the lower the chance of CO2 leakage to the atmosphere. Figure 2 also shows the depth sequence of the aquifers, indicated that aquifer L20 is the shallowest, while aquifer P50 is the deepest. The average values of porosity, permeability, hydraulic conductivity, water saturation, formation water resistivity, and aquifer thickness estimated in the aquifer intervals are shown in tables 1-4. Core data for the interval under study are not available, however published data on an adjacent oil field (Etu-Efeotor and Akpokodje, 1990) confirmed the validity of the porosity and permeability data. The porosity and permeability models around the wells are shown in Figure 3.
Porosity and permeability are key parameters in storage and fluid flow, bulk resistivity and formation resistivity are important parameters for predicting the nature of the fluid in the aquifer and the chemical reaction CO2 may undergo during storage in the aquifers. Water saturation is important for estimating the fraction of the pore space that is readily available for CO2 storage at in situ condition. When the injection pressure is higher than the pore pressure, the pressure difference can force CO2 to replace formation water in the pore spaces of the aquifers.
Finer details of the petrophysical parameters of the aquifers, from one well to another, are shown in Tables 1-4. The tables show that the four saline aquifers L20, M30, N40, and P50 have sand thicknesses that ranges from 219 to 277 m, 105 to 147 m, 59 to 79 m, 28 -105 m, respectively. Table 1 also shows that the formation water resistivity is very low -ranging from 0.12 to 0.25 Ωm, thereby suggesting that the aquifers contain saltwater, not freshwater. The freshwater aquifers in the Niger Delta area have resistivity values greater than 10 Ωm (Oteri, 1987). The seismic section showing the stratigraphic succession of the saline aquifers is presented in Figure 4. The Horizons corresponding to the tops of the aquifers were picked and some faults were mapped using different colours as shown in Figure 4. The shallowest and deepest horizons correspond to L20 and P50, respectively. The depth maps used for volumetric estimation of CO2 storage in the aquifers are shown in Figure 5. The maps showed the position of the wells, depths (coded in colours), and some structural elements such as fault-assisted closures.
The estimated volumes of CO2 potentially storable in Aquifers L20, M30, N40, and P50 are presented in Table 5, at 1%, 4%, 10% and 15% efficiency factors, respectively. The reason for calculating CO2 volume at different efficiency factors is that there is no consensus among CO2 sequestration researchers on the best or the most appropriate efficiency factor to estimating the CO2 storage potential of aquifers. Also, the efficiency factor depends on a number of factors which are still not completely understood, including the characteristics of the aquifer and the caprock (Bachus, 2015).
The value commonly used in the literature ranges from 1% to 20% ( Van der Meer, 1982:1995Holloway et al., 2006;EERC, 2009). Consequently, the storage potential of aquifers estimated at 1%, 4%, 10%, and 15% are shown in Table 5. Results in Table 5 shows that aquifer L20 has the highest storage capacity at all the efficiency factors, while aquifer P50 has the lowest storage capacity at all the efficiency factors. The total volume of CO2 that can be stored in the combined aquifer are 2.78×10 11 tons, 5.90×10 11 tons, 3.11×10 10 tons, and 5.94×10 10 tons at 1%, 4%, 10%, and 15% efficiency factors, respectively. For this study, the average estimated storage capacity of the individual aquifer was computed as the mean of the storage capacities of the respective aquifers at 1%, 4%, 10% and 15% efficiency factors. The average estimated storage capacities of the individual aquifers are 6.97×10 10 tons, 1.48×10 10 tons, 7.78×10 9 tons and 1.49×10 10 tons for L20, M30, N40, and P50 aquifers, respectively. The estimated combined aquifer storage capacity, being the sum of the estimated average storage capacity of the four aquifers, is 1.07×10 11 tons. The estimated volumes are comparable with those obtained in previous studies (Sayers et al., 2015;Kelemen et al., 2019): keeping other factors constant, the thicker the aquifers the higher the CO2 volume storable in them.
The cap rocks (seals) were found to be laterally extensive, covering the entire aquifer area. Figure 6a shows the estimated thickness of seals 1 -4 in the different wells, where seals 1, 2, 3, and 4 are the respective seal to aquifers L20, N30, M40, and

K(mD) Rw(Ωm) k (m/day) Sw
Pearl 02 Table 3. Petrophysical parameters of aquifer N40 across the five wells. P50. The thicknesses of the seal (Figure 6a) ranges from 14 to 352 m which are above the minimum. The minimum seal thickness required for CO2 sequestration is 10 m (Kaldi et al., 2008). Seal 4 is consistently the thickest in all the wells, while seal 1 is the second thickest. The thicker the seal, the lower the risk of CO2 leakage due to breakage or diffusion. Using Skerlec (1982) model to assess the brittle-ductile behaviour of the cap rocks (seals), Figure 6b shows that all the cap rocks plotted in the lower part of the ductile section within the density values of 2.0 to 2.35 g/cm 3 , at depth range of 910 to 2300 m. This result suggests that the seals are moderately ductile and have a low risk of breakage. Ductility in shale is a function of the compaction state; the more the ductility, the lower the risk of breakage. Overall, Aquifer L20 has the highest storage capacity, and its seal has the second-best rating. Therefore, it is rated as the best aquifer in terms of CO2 storage and risk of leakage. Compacted low-density shale layers are very ductile, while a high density un-compacted shale layers are usually brittle. The ductility of the caprock allows it to deform without developing high permeability pathways for leakages. Redox reaction and carbonate precipitation in caprocks can further reduce CO2 diffusion when there are no large permeability features (Wang and Tokunaga, 2015).
Considering a density range of 1.2 to 2.8 g/cm 3 within a depth range of 100 -5000 m according to Skerlec's model and the result in Figure 6b where the seal (shale) plotted at the medium density values of 2 to 2.35 g/cm 3 within a depth range of 910 to 2300 m. The seals are interpreted to be moderately ductile. Therefore, the seals have a low risk of breakage and CO2 leakages. Further, the depth structured map shown in Figure 5 revealed the presence of fault assisted closures that are potentially useful for CO2 trapping within the aquifers.
Considering capillary pressure and the trapping mechanism for CO2 in storage media, capillary pressure generally serves as either a driving or opposing force for CO2 leakages through the sealing layer depending on the prevailing condition and the L20 Storage Capacity

P50 Storage Capacity
Combined storage capacity of aquifer CO2 storage at 1% Efficiency Factor 9.61x10 9 2.03x10 9 1.07x10 9 2.06x10 9 2.78x10 11 CO2 storage at 4% Efficiency Factor 3.88x10 10 8.14x10 9 4.30x10 9 8.25x10 9 5.90x10 11 CO2 storage at 10% Efficiency Factor 9.61x10 10 2.03x10 10 1.07x10 10 2.06x10 10 3.11x10 10 CO2 storage at 15% Efficiency Factor 1.35x10 11 2.84x10 11 1.52x10 10 2.88x10 10 5.97x10 10 The storage capacity of the aquifer at the average of 1, 4, 10, & 15% E. F 6.97x10 10 1.48x10 10 7.78x10 9 1.48x10 10 1.07x10 11  property of the storage formation especially in the cap rock transition zone. As seen in the log signatures, porosity heterogeneity at the aquifer -cap rock (seal) transition zone will lead to residual trapping of CO2 in the cap rock, and this would play a major role in opposing CO2 leakages in the cap rock (see also, Al-Menhali and Krevor, 2016). Solubility trapping of CO2 is also possible due to the presence of brine in pore spaces of the media. However, core sample analyses are required to describe the detailed trapping mechanisms. Further, the presence of interbedded layers of shale and sand at the top and base of the storage media will cause significant porosity heterogeneity at the top and base of the aquifers. The heterogeneity will limit the capillary pressure driving CO2 migration in the caprock. Furthermore, the stratigraphic traps caused by porosity heterogeneity can store significant CO2 volume, block the pores in the zones, and further reduce the chance of CO2 leaking through the cap rock.
V. CONCLUSION The volume of CO2 that can be stored in the saline aquifers in 'J' Field Niger Delta, Nigeria, has been estimated. Furthermore, the risk of CO2 leakages through the cap rocks overlying the aquifers has been evaluated. The aquifers were found to be sufficiently thick and laterally extensive to store a significant volume of CO2. The storage capacity of the combined aquifers was estimated to be 1.07×10 11 tons, while the individual storage capacity of L20, M30, N40, and P50 aquifers are 6.97×10 10 tons, 1.48×10 10 tons, 7.78×10 9 tons and 1.49×10 10 tons, respectively. The caprocks (seals) are formed by shale that are moderately ductile, sufficiently thick, and laterally extensive, covering the entire surface area of the respective aquifers to be used for storage. Aquifer L20 has the highest storage capacity, and its seal has the second-best rating.
Aquifer P50 has the best sealing layer and the least storage capacity. In terms of storage capacity and the risk of leakages, aquifer L20 is rated as the best. The stratigraphic succession of the selected aquifers made it possible for the aquifers to be sandwiched between the competent top and bottom shale layers, which further reduced the risk of CO2 leakages. The study concludes that aquifers L20, M30, N40 and P50 are good and reliable for safe and secure storage of CO2 in J field. Findings from this study are important for basin-wide evaluation of CO2 storage in Nigerian geological space in the mitigation of greenhouse gas effect. Similar studies on depleted hydrocarbon reservoirs in the Niger Delta of Nigeria is recommended with a view to prepare a template for a pilot study.