*Article* **Quantitative Evaluation of CO<sup>2</sup> Storage Potential in the Offshore Atlantic Lower Cretaceous Strata, Southeastern United States**

**Dawod S. Almayahi 1,2,\* , James H. Knapp <sup>1</sup> and Camelia Knapp <sup>1</sup>**


**Abstract:** The geological storage of CO<sup>2</sup> in the Earth's subsurface has the potential to significantly offset greenhouse gas emissions for safe, economical, and acceptable public use. Due to legal advantages and vast resource capacity, offshore CO<sup>2</sup> storage provides an attractive alternative to onshore options. Although offshore Lower Cretaceous reservoirs have a vast expected storage capacity, there is a limited quantitative assessment of the offshore storage resource in the southeastern United States. This work is part of the Southeast Offshore Storage Resource Assessment (SOSRA) project, which presents a high-quality potential geological repository for CO<sup>2</sup> in the Mid- and South Atlantic Planning Areas. This is the first comprehensive investigation and quantitative assessment of CO<sup>2</sup> storage potential for the Lower Cretaceous section of the outer continental shelf that includes the Southeast Georgia Embayment and most of the Blake Plateau. An interpretation of 200,000 km of legacy industrial 2D seismic reflection profiles and geophysical well logs (i.e., TRANSCO 1005-1-1, COST GE-1, and EXXON 564-1) were utilized to create structure and thickness maps for the potential reservoirs and seals. We identified and assessed three target reservoirs isolated by seals based on their effective porosity values. The CO<sup>2</sup> storage capacity of these reservoirs was theoretically calculated using the DOE-NETL equation for saline formations. The prospective storage resources are estimated between 450 and 4700 Mt of CO<sup>2</sup> , with an offshore geological efficiency factor of dolomite between 2% and 3.6% at the formation scale.

**Keywords:** carbon dioxide (CO<sup>2</sup> ); carbon capture and storage (CCS); offshore Atlantic; efficiency factors; southeastern United States

### **1. Introduction**

Offshore geologic storage of carbon dioxide (CO2) as a form of carbon capture and storage (CCS) technology has recently attracted considerable scientific attention. CCS technology is a potentially vital tool to reduce the levels of CO<sup>2</sup> emissions in the atmosphere and to prevent the most dangerous consequences of climate change [1–8]. The term offshore CO<sup>2</sup> storage refers to the injection of CO<sup>2</sup> into the geological strata beneath the seabed for safe and permanent storage [9–12]. Due to legal considerations and the vast resource storage capacity, offshore storage offers an attractive alternative to the onshore options. After many failed attempts, the Sleipner project in the North Sea was an early successful opportunity for commercial deployment of CO<sup>2</sup> storage. Although offshore Lower Cretaceous reservoirs have an extensive expected storage capacity, there has been no comprehensive assessment of the offshore storage resource estimate in the southeastern United States. An analysis of a 25,900 km<sup>2</sup> area of offshore Alabama and the western Florida Panhandle suggested that approximately 170 Gt of CO<sup>2</sup> could be stored in Miocene sandstone, whereas at least 30 Gt could be stored in the deeper Cretaceous formations [13]. Around 32 Gt of CO<sup>2</sup> could be stored within 190,000 km<sup>2</sup> of the Upper Cretaceous strata in

**Citation:** Almayahi, D.S.; Knapp, J.H.; Knapp, C. Quantitative Evaluation of CO<sup>2</sup> Storage Potential in the Offshore Atlantic Lower Cretaceous Strata, Southeastern United States. *Energies* **2022**, *15*, 4890. https://doi.org/10.3390/en15134890

Academic Editors: Dongdong Feng, Jian Sun and Zijian Zhou

Received: 2 June 2022 Accepted: 30 June 2022 Published: 4 July 2022

**Publisher's Note:** MDPI stays neutral with regard to jurisdictional claims in published maps and institutional affiliations.

**Copyright:** © 2022 by the authors. Licensee MDPI, Basel, Switzerland. This article is an open access article distributed under the terms and conditions of the Creative Commons Attribution (CC BY) license (https:// creativecommons.org/licenses/by/ 4.0/).

**<sup>\*</sup>** Correspondence: dalmaya@okstate.edu

the offshore southeastern United States [14]. A study offshore of the northeastern United States has recently concluded that the Cretaceous and Jurassic sandstone is able to store approximately 37–403 Mt of CO2, with geological storage efficiency of 1–13% [15]. Realizing that the US Environmental Protection Agency estimates that about 40% of anthropogenic CO<sup>2</sup> emissions in the US are produced in the southeast, the lack of an offshore CO<sup>2</sup> assessment constitutes a significant gap in understanding of this prospective regional storage resource [16–19]. stone is able to store approximately 37–403 Mt of CO2, with geological storage efficiency of 1–13% [15]. Realizing that the US Environmental Protection Agency estimates that about 40% of anthropogenic CO<sup>2</sup> emissions in the US are produced in the southeast, the lack of an offshore CO<sup>2</sup> assessment constitutes a significant gap in understanding of this prospective regional storage resource [16–19]. The research area is located offshore of the southeastern United States, covering the southern part of the Mid-Atlantic Planning Area (including the Carolina Trough) and the

formations [13]. Around 32 Gt of CO<sup>2</sup> could be stored within 190,000 km<sup>2</sup> of the Upper Cretaceous strata in the offshore southeastern United States [14]. A study offshore of the northeastern United States has recently concluded that the Cretaceous and Jurassic sand-

*Energies* **2022**, *15*, x FOR PEER REVIEW 2 of 19

The research area is located offshore of the southeastern United States, covering the southern part of the Mid-Atlantic Planning Area (including the Carolina Trough) and the South Atlantic Planning Area (including the Southeast Georgia Embayment and Blake Plateau), as defined by the Bureau of Ocean Energy Management (BOEM) (Figure 1). Within the Mid-Atlantic Planning Area and South Atlantic Planning Area, there is a thick sequence of post-rift stratigraphy, which is considered to be a semi-closed saline aquifer, with sediments ranging in age from Jurassic to Pleistocene [20,21]. In these areas, the significant sedimentary deposits from north to south include the Carolina Trough, the Southeast Georgia Embayment, and the Blake Plateau Basin, with a range in sediment column thicknesses from 3048 to 7010 m [22–25]. A regional unconformity under the post-rift sediments known as the post-rift unconformity (PRU) cuts the entire region after rifting between Africa and North America ceases. This unconformity marks the transition to a widespread sediment deposition zone during the drifting stage. South Atlantic Planning Area (including the Southeast Georgia Embayment and Blake Plateau), as defined by the Bureau of Ocean Energy Management (BOEM) (Figure 1). Within the Mid-Atlantic Planning Area and South Atlantic Planning Area, there is a thick sequence of post-rift stratigraphy, which is considered to be a semi-closed saline aquifer, with sediments ranging in age from Jurassic to Pleistocene [20,21]. In these areas, the significant sedimentary deposits from north to south include the Carolina Trough, the Southeast Georgia Embayment, and the Blake Plateau Basin, with a range in sediment column thicknesses from 3048 to 7010 m [22–25]. A regional unconformity under the post-rift sediments known as the post-rift unconformity (PRU) cuts the entire region after rifting between Africa and North America ceases. This unconformity marks the transition to a widespread sediment deposition zone during the drifting stage.

**Figure 1.** Location map of the study area. Panel (**A**) is the location of the study area in the regional map, panel (**B**) is the study area map, and panel (**C**) is the well locations. **Figure 1.** Location map of the study area. Panel (**A**) is the location of the study area in the regional map, panel (**B**) is the study area map, and panel (**C**) is the well locations.

This research evaluates the potential offshore CO<sup>2</sup> storage capacity within the Lower

Cretaceous strata in the Mid- and South Atlantic Planning areas.

This research evaluates the potential offshore CO<sup>2</sup> storage capacity within the Lower Cretaceous strata in the Mid- and South Atlantic Planning areas.

### **2. Geological Framework**

The evolution of the Atlantic continental margin, including the study area, is broadly characterized by the terminal collision of the Laurentian and Gondwanan continents in the Late Paleozoic Era, followed by continental rifting beginning in the Early Triassic [9,20,23,25,26]. Mesozoic rifting involved local tectonic subsidence in early restricted extensional basins, followed by regional thermal subsidence along the eastern North American margin [21,24,26–28]. Stratigraphic sequences on this passive margin show extensive lateral continuity and relatively minor structural disturbance [25–27]. There is a thick sequence of post-rift stratigraphy ranging from Jurassic- to Pleistocene-aged sediments in the Mid-Atlantic and South Atlantic Planning Areas. The significant depositional centers in these areas from north to south include the Baltimore Canyon Trough, the Carolina Trough, the Southeast Georgia Embayment, and the Blake Plateau Basin. The oldest post-rift sediments are of Jurassic age, and are the product of rapid clastic sedimentation from erosion, followed by a period of evaporate deposition and then initiation of broad, shallow-water, carbonate deposition with some terrigenous intrusions [28,29]. The Jurassic section thickens seaward, and estimates from geophysical and stratigraphic studies suggest thicknesses of at least 7–8 km in the basins [20,21]. Typically, the Cretaceous section is characterized by more clastic sedimentation in the north and more carbonate deposition in the south, forming an extensive carbonate platform over the Blake Plateau and offshore Florida. From the Late Cretaceous to the Cenozoic, strong paleocurrents controlled the deposition of the clastic offshore sediments. The Late Cretaceous in the Blake Plateau exhibited a distinct facies change to the neighboring offshore Florida and Bahamas carbonate platforms [23–25]. The Suwannee Strait eventually evolved into the current Gulf Stream, providing strong erosive power that eroded most of the Paleogene sediments on the Blake Plateau and prevented deposition off the Florida–Hatteras slope, where it continues to the north along the shelf edge [25,28].

### **3. Materials and Methods**

This study involves the integration of geological and geophysical data, combining regional 2D seismic reflection surveys, published sidewall core analyses, and well logs from commercial exploration wells. Seismic reflection data provide fundamental structural control over the subsurface geology, confirmed by accessible exploration wells. A total of 36 separate 2D seismic surveys was integrated and analyzed (Figure 1B), and a seismic mistie analysis was conducted to merge the individual surveys for this study. The well logs were then calibrated with the seismic reflection profiles. The seismic surveys were interpreted regionally for key stratigraphic horizons, and then porosities and permeabilities were derived from the log data and core reports. Subsequently, the porosity and permeability estimates were compared between the published sidewall core data and the derived values.

### *3.1. Well Sections*

Seven commercial exploratory offshore wells (GETTY 913, TRANSCO 1005-1-1, TEN-NECO 208, COST GE-1, TENNECO 427, EXXON 472, and EXXON 564-1) (Figure 1C) were drilled in the Southeast Georgia Embayment from 1979 to 1980. These wells were stratigraphically correlated by Poppe et al. [25], and have also been seismic-stratigraphically interpreted and correlated with similar Mesozoic sedimentary sequences [30]. TRANSCO 1005-1, COST GE-1, and EXXON 564-1—the deepest three wells in the Southeast Georgia Embayment—were used in the present study. TRANSCO 1005-1 and COST GE-1 are the only two wells that penetrate the pre-rift sedimentary sequences from the Paleozoic Era. The EXXON 564-1 well penetrates only the post-rift sedimentary sequence from the Mesozoic Era.

The TRANSCO 1005-1-1 well encounters the pre-rift unconformity at a depth of ~2743 m, and bottoms in Paleozoic sedimentary rocks at a total depth (TD) of 3546 m [25]. The Paleozoic section in the TRANSCO 1005-1 well is a weakly metamorphosed shale and sandstone with meta-igneous intrusions (Figure 2). The log suite for this well includes mud logs, electric logs, drill cuttings, and biostratigraphic data. The Paleozoic rocks in the TRANSCO 1005-1 well have been correlated with Devonian strata in the COST GE-1 well [25]. The Paleozoic section in the TRANSCO 1005-1 well is a weakly metamorphosed shale and sandstone with meta-igneous intrusions (Figure 2). The log suite for this well includes mud logs, electric logs, drill cuttings, and biostratigraphic data. The Paleozoic rocks in the TRANSCO 1005-1 well have been correlated with Devonian strata in the COST GE-1 well [25].

*Energies* **2022**, *15*, x FOR PEER REVIEW 4 of 19

**Figure 2.** TRANSCO 1005-1-1, COST GE-1, and EXXON 564-1, stratigraphically and geophysically correlated by logs and lithology, modified and adapted with permission from Ref. [25]. Copyright 1995, copyright Poppe et al., and Ref. [31]. Copyright 2016, copyright Boote and Knapp. **Figure 2.** TRANSCO 1005-1-1, COST GE-1, and EXXON 564-1, stratigraphically and geophysically correlated by logs and lithology, modified and adapted with permission from Ref. [25]. Copyright 1995, copyright Poppe et al., and Ref. [31]. Copyright 2016, copyright Boote and Knapp.

The COST GE-1 well penetrates the pre-rift unconformity at 3200 m, drilling approximately 686 m of the Paleozoic sedimentary sequences and reaching 4040 m [9]. The COST GE-1 well showed a thick sequence from Paleozoic to Cenozoic (Figure 2). The Paleozoic section generally consists of non-fossiliferous quartzite, shale, and salt, underlain by metamorphic and meta-volcanic rocks [9]. The COST GE-1 well penetrates the pre-rift unconformity at 3200 m, drilling approximately 686 m of the Paleozoic sedimentary sequences and reaching 4040 m [9]. The COST GE-1 well showed a thick sequence from Paleozoic to Cenozoic (Figure 2). The Paleozoic section generally consists of non-fossiliferous quartzite, shale, and salt, underlain by metamorphic and meta-volcanic rocks [9].

Scholle [9] provided an analysis of the COST GE-1 well data, and described the stratigraphic units, porosity, and permeability measurements by both a conventional core and a sidewall core with respect to depth. The thickness of fossiliferous chalky limestone below the drill platform reaches 1006 m, corresponding to strata of Tertiary age. The Upper Cretaceous section is marked at a depth ranging from 1006 m to 1798 m, and is composed of calcareous shale, dolomite, and limestone. The section from 1798 to 2195 m is the Lower Cretaceous. Rocks encountered below 3353 m depth consist of highly indurated to weakly metamorphosed Paleozoic strata [9]. Scholle [9] provided an analysis of the COST GE-1 well data, and described the stratigraphic units, porosity, and permeability measurements by both a conventional core and a sidewall core with respect to depth. The thickness of fossiliferous chalky limestone below the drill platform reaches 1006 m, corresponding to strata of Tertiary age. The Upper Cretaceous section is marked at a depth ranging from 1006 m to 1798 m, and is composed of calcareous shale, dolomite, and limestone. The section from 1798 to 2195 m is the Lower Cretaceous. Rocks encountered below 3353 m depth consist of highly indurated to weakly metamorphosed Paleozoic strata [9].

The EXXON 564-1 well encounters the pre-rift unconformity at a depth of 3737 m [30]. The last 183 m, under the post-rift unconformity in the EXXON 564-1 well, is a weakly metamorphosed shale and sandstone with meta-igneous intrusion of Triassic rocks. The EXXON 564-1 well has been correlated with the Devonian rocks in the COST GE-1 well The EXXON 564-1 well encounters the pre-rift unconformity at a depth of 3737 m [30]. The last 183 m, under the post-rift unconformity in the EXXON 564-1 well, is a weakly metamorphosed shale and sandstone with meta-igneous intrusion of Triassic rocks. The EXXON 564-1 well has been correlated with the Devonian rocks in the COST GE-1 well (Figure 2).

(Figure 2).

#### *3.2. Seismic Interpretation Energies* **2022**, *15*, x FOR PEER REVIEW 5 of 19

The primary dataset consists of legacy 2D seismic reflection profiles offshore of the southeastern United States in the Atlantic Ocean. The dataset has been released by the Bureau of Ocean and Energy Management (Figure 1B). We interpreted and correlated a continuous surface stratigraphy of the storage elements (sinks and reservoir seals) along 200,000 km of the seismic profiles, covering approximately 200,000 km<sup>2</sup> . Seismic interpretation started with picking high-frequency stratigraphy sequences targeted at creating three-dimensional maps of the reservoirs and seals. The TRANSCO 1005-1 well, COST GE-1 well, and EXXON 564-1 well were tied with the seismic profiles (Figure 3). The Schlumberger Petrel software can generate advanced velocity models using check-shot data. The velocity model uses input parameters such as tops and surfaces and the time– depth link [32]. The velocity model is created based on the time–depth relationship from the well data. The time–depth conversion uses linear velocity related to the depth functions (V = V<sup>0</sup> + K × Z) and (V = V<sup>0</sup> + K × (Z − Z0)) for evaluating a velocity model [33]. Both K and the linear velocity slope indicate that the velocity increases with depth and reflects layer compaction. The compaction factor K is estimated with the fewest mistakes feasible and used to generate a V<sup>0</sup> surface; any modifications incorporated into the velocity model are reflected on the V<sup>0</sup> surface. The check-shot data of the three wells (COST GE-1, Exxon 564-1, and Transco 1005-1) were used to identify the depth of the upper and bottom surfaces of the Lower Cretaceous section. *3.2. Seismic Interpretation* The primary dataset consists of legacy 2D seismic reflection profiles offshore of the southeastern United States in the Atlantic Ocean. The dataset has been released by the Bureau of Ocean and Energy Management (Figure 1B). We interpreted and correlated a continuous surface stratigraphy of the storage elements (sinks and reservoir seals) along 200,000 km of the seismic profiles, covering approximately 200,000 km<sup>2</sup> . Seismic interpretation started with picking high-frequency stratigraphy sequences targeted at creating three-dimensional maps of the reservoirs and seals. The TRANSCO 1005-1 well, COST GE-1 well, and EXXON 564-1 well were tied with the seismic profiles (Figure 3). The Schlumberger Petrel software can generate advanced velocity models using check-shot data. The velocity model uses input parameters such as tops and surfaces and the time– depth link [32]. The velocity model is created based on the time–depth relationship from the well data. The time–depth conversion uses linear velocity related to the depth functions (V = V<sup>0</sup> + K × Z) and (V = V<sup>0</sup> + K × (Z − Z0)) for evaluating a velocity model [33]. Both K and the linear velocity slope indicate that the velocity increases with depth and reflects layer compaction. The compaction factor K is estimated with the fewest mistakes feasible and used to generate a V<sup>0</sup> surface; any modifications incorporated into the velocity model are reflected on the V<sup>0</sup> surface. The check-shot data of the three wells (COST GE-1, Exxon 564-1, and Transco 1005-1) were used to identify the depth of the upper and bottom surfaces of the Lower Cretaceous section.

**Figure 3.** Seismic-well tie analysis for three wells: (**A**) The location map of the commercial wells in the Southeast Georgia Embayment. (**A1**) The seismic profile Number GE-75-112A intersecting the TRANSCO 1005-1-1 well. (**A2**) The seismic profile Number MME-101 intersecting the COST GE-1 well. (**A3**) The seismic profile Number E8-78-7065 intersecting the EXXON 564-1 well.

*3.3. Calculation of CO2 Storage Capacity* 

*3.3. Calculation of CO2 Storage Capacity* 

*Energies* **2022**, *15*, x FOR PEER REVIEW 6 of 19

*Energies* **2022**, *15*, x FOR PEER REVIEW 6 of 19

**Figure 3.** Seismic-well tie analysis for three wells: (**A**) The location map of the commercial wells in the Southeast Georgia Embayment. (**A1**) The seismic profile Number GE-75-112A intersecting the

#### *3.3. Calculation of CO<sup>2</sup> Storage Capacity 3.3. Calculation of CO2 Storage Capacity*  **Figure 3.** Seismic-well tie analysis for three wells: (**A**) The location map of the commercial wells in the Southeast Georgia Embayment. (**A1**) The seismic profile Number GE-75-112A intersecting the TRANSCO 1005-1-1 well. (**A2**) The seismic profile Number MME-101 intersecting the COST GE-1

*Energies* **2022**, *15*, x FOR PEER REVIEW 6 of 19

We developed an estimate of the regional CO<sup>2</sup> storage capacity offshore of the Lower Cretaceous section in the Mid–South Atlantic Ocean using the US Department of Energy (DOE) National Energy Technology Laboratory (NETL) method [16,34,35]. We developed an estimate of the regional CO2 storage capacity offshore of the Lower Cretaceous section in the Mid–South Atlantic Ocean using the US Department of Energy (DOE) National Energy Technology Laboratory (NETL) method [16,34,35]. TRANSCO 1005-1-1 well. (**A2**) The seismic profile Number MME-101 intersecting the COST GE-1 well. (**A3**) The seismic profile Number E8-78-7065 intersecting the EXXON 564-1 well. *3.3. Calculation of CO2 Storage Capacity*  well. (**A3**) The seismic profile Number E8-78-7065 intersecting the EXXON 564-1 well. **Figure 3.** Seismic-well tie analysis for three wells: (**A**) The location map of the commercial wells in the Southeast Georgia Embayment. (**A1**) The seismic profile Number GE-75-112A intersecting the TRANSCO 1005-1-1 well. (**A2**) The seismic profile Number MME-101 intersecting the COST GE-1

**Figure 3.** Seismic-well tie analysis for three wells: (**A**) The location map of the commercial wells in the Southeast Georgia Embayment. (**A1**) The seismic profile Number GE-75-112A intersecting the TRANSCO 1005-1-1 well. (**A2**) The seismic profile Number MME-101 intersecting the COST GE-1

well. (**A3**) The seismic profile Number E8-78-7065 intersecting the EXXON 564-1 well.

The US-DOE approach estimates CO<sup>2</sup> storage volume based on geological parameters such as formation area, thickness, and porosity [16,17,36]. Some articles such as the work of Teletzke et al. [37] criticize the DOE method or the Goodman method. However, the DOE method is the most comprehensive and well-documented storage method available at this time. The DOE method estimates carbon storage resources at the prospective scale in subsurface saline formations. This information plays an important role in establishing the scale of carbon capture and storage activities for governmental policy and commercial project decision making. When calculating the storage efficiency terms, the DOE method accounts for several parameters, as presented in Gorecki et al. [35]: reservoir width, reservoir length, thickness, domain discretization, rock properties, porosity, permeability (lateral), permeability anisotropy, relative permeability, capillary pressure, reservoir properties, initial pressure, pressure gradient, initial temperature, temperature gradient, brine concentration, pore compressibility, operation properties, injection rate, injection period, and perforation. Goodman et al. [16] used the static volumetric methodology and the CO<sup>2</sup> storage prospective resource estimation Excel analysis (CO2-SCREEN) tool developed by the US Department of Energy National Energy Technology Laboratory (DOE-NETL) (Equation (1)). Equation (1) is mathematically expressed as follows: The US-DOE approach estimates CO2 storage volume based on geological parameters such as formation area, thickness, and porosity [16,17,36]. Some articles such as the work of Teletzke et al. [37] criticize the DOE method or the Goodman method. However, the DOE method is the most comprehensive and well-documented storage method available at this time. The DOE method estimates carbon storage resources at the prospective scale in subsurface saline formations. This information plays an important role in establishing the scale of carbon capture and storage activities for governmental policy and commercial project decision making. When calculating the storage efficiency terms, the DOE method accounts for several parameters, as presented in Gorecki et al. [35]: reservoir width, reservoir length, thickness, domain discretization, rock properties, porosity, permeability (lateral), permeability anisotropy, relative permeability, capillary pressure, reservoir properties, initial pressure, pressure gradient, initial temperature, temperature gradient, brine concentration, pore compressibility, operation properties, injection rate, injection period, and perforation. Goodman et al. [16] used the static volumetric methodology and the CO2 storage prospective resource estimation Excel analysis (CO2-SCREEN) tool developed by the US Department of Energy National Energy Technology Laboratory (DOE-NETL) (Equation (1)). Equation (1) is mathematically expressed as follows: We developed an estimate of the regional CO2 storage capacity offshore of the Lower Cretaceous section in the Mid–South Atlantic Ocean using the US Department of Energy (DOE) National Energy Technology Laboratory (NETL) method [16,34,35]. The US-DOE approach estimates CO2 storage volume based on geological parameters such as formation area, thickness, and porosity [16,17,36]. Some articles such as the work of Teletzke et al. [37] criticize the DOE method or the Goodman method. However, the DOE method is the most comprehensive and well-documented storage method available at this time. The DOE method estimates carbon storage resources at the prospective scale in subsurface saline formations. This information plays an important role in establishing the scale of carbon capture and storage activities for governmental policy and commercial project decision making. When calculating the storage efficiency terms, the DOE method accounts for several parameters, as presented in Gorecki et al. [35]: reservoir width, reservoir length, thickness, domain discretization, rock properties, porosity, permeability (lateral), permeability anisotropy, relative permeability, capillary pressure, reservoir properties, initial pressure, pressure gradient, initial temperature, temperature gradient, brine concentration, pore compressibility, operation properties, injection rate, injection period, and perforation. Goodman et al. [16] used the static volumetric methodology and the CO2 storage prospective resource estimation Excel analysis (CO2-SCREEN) tool developed by the US Department of Energy National Energy Technology Laboratory (DOE-NETL) (Equation (1)). Equation (1) is mathematically expressed as follows: We developed an estimate of the regional CO2 storage capacity offshore of the Lower Cretaceous section in the Mid–South Atlantic Ocean using the US Department of Energy (DOE) National Energy Technology Laboratory (NETL) method [16,34,35]. The US-DOE approach estimates CO2 storage volume based on geological parameters such as formation area, thickness, and porosity [16,17,36]. Some articles such as the work of Teletzke et al. [37] criticize the DOE method or the Goodman method. However, the DOE method is the most comprehensive and well-documented storage method available at this time. The DOE method estimates carbon storage resources at the prospective scale in subsurface saline formations. This information plays an important role in establishing the scale of carbon capture and storage activities for governmental policy and commercial project decision making. When calculating the storage efficiency terms, the DOE method accounts for several parameters, as presented in Gorecki et al. [35]: reservoir width, reservoir length, thickness, domain discretization, rock properties, porosity, permeability (lateral), permeability anisotropy, relative permeability, capillary pressure, reservoir properties, initial pressure, pressure gradient, initial temperature, temperature gradient, brine concentration, pore compressibility, operation properties, injection rate, injection period, and perforation. Goodman et al. [16] used the static volumetric methodology well. (**A3**) The seismic profile Number E8-78-7065 intersecting the EXXON 564-1 well. We developed an estimate of the regional CO2 storage capacity offshore of the Lower Cretaceous section in the Mid–South Atlantic Ocean using the US Department of Energy (DOE) National Energy Technology Laboratory (NETL) method [16,34,35]. The US-DOE approach estimates CO2 storage volume based on geological parameters such as formation area, thickness, and porosity [16,17,36]. Some articles such as the work of Teletzke et al. [37] criticize the DOE method or the Goodman method. However, the DOE method is the most comprehensive and well-documented storage method available at this time. The DOE method estimates carbon storage resources at the prospective scale in subsurface saline formations. This information plays an important role in establishing the scale of carbon capture and storage activities for governmental policy and commercial project decision making. When calculating the storage efficiency terms, the DOE method accounts for several parameters, as presented in Gorecki et al. [35]: reservoir width, reservoir length, thickness, domain discretization, rock properties, porosity, permeability (lateral), permeability anisotropy, relative permeability, capillary pressure, reservoir properties, initial pressure, pressure gradient, initial temperature, temperature gradient, brine concentration, pore compressibility, operation properties, injection rate, injection period, and perforation. Goodman et al. [16] used the static volumetric methodology

$$\text{GCO}\_2 = A \times \text{b} \theta \times \text{q} \times \rho \times E \tag{1}$$

where CO2 is the total mass of CO2 in gigatons (Gt), *A* is the target area (in square meters), ℎ is the gross strata thickness (in meters), *φ* is the effective porosity, is the CO2 density in kilograms per cubic meter (kg/m3), and CO2 is the average CO2 density evaluated at pressure and temperature, representing storage conditions anticipated for a specific deep saline aquifer. Ennis-King and Paterson [38] pointed out that the CO2 density rises with a decrease in volume in the reservoir at depths ranging from 600 to 1000 m, depending on the specific geothermal conditions and pressure. Due to heat transfer, the average temperature in several geological formations increases by approximately 25–30.8 °C/km below the sea bed [39]. However, geothermal gradients vary significantly between local and global basins [40]. Nevertheless, the subsurface units suitable for geological carbon sequestration are 800 m or deeper below the seafloor, and seem to have higher pressure and temperature at depths greater than the CO2 critical point [12]. The critical point indicates that CO2 is injected at supercritical temperatures and pressures. CO2 and certain other supercritical gases possess gas viscosity, which reduces resistance to flow compared to liquid and semi-liquid density, significantly reducing the volume required to store a given mass of fluid. Carbon dioxide behaves as a supercritical fluid at temperatures and pressures above the critical points of 30.85 °C and 7.38 MPa, respectively [39]. The 800 m depth requirement is a reasonable guess that varies based on the geothermal gradient and formation pressure at a given location [41]. The pressure in the pore spaces of sedimentary rocks is identical to hydrostatic pressure. This pressure is generated by a water column at a corresponding elevation to the depth of the pore space, since the pore space is frequently filled with water and, although in a convoluted manner, is connected to the ground surface. When the pore space is not connected with the surface at equilibrium, the hydrostatic pressure can be exceeded, and overpressure occurs [38]. where CO2 is the total mass of CO2 in gigatons (Gt), *A* is the target area (in square meters), ℎ is the gross strata thickness (in meters), *φ* is the effective porosity, is the CO2 density in kilograms per cubic meter (kg/m3), and CO2 is the average CO2 density evaluated at pressure and temperature, representing storage conditions anticipated for a specific deep saline aquifer. Ennis-King and Paterson [38] pointed out that the CO2 density rises with a decrease in volume in the reservoir at depths ranging from 600 to 1000 m, depending on the specific geothermal conditions and pressure. Due to heat transfer, the average temperature in several geological formations increases by approximately 25–30.8 °C/km below the sea bed [39]. However, geothermal gradients vary significantly between local and global basins [40]. Nevertheless, the subsurface units suitable for geological carbon sequestration are 800 m or deeper below the seafloor, and seem to have higher pressure and temperature at depths greater than the CO2 critical point [12]. The critical point indicates that CO2 is injected at supercritical temperatures and pressures. CO2 and certain other supercritical gases possess gas viscosity, which reduces resistance to flow compared to liquid and semi-liquid density, significantly reducing the volume required to store a given mass of fluid. Carbon dioxide behaves as a supercritical fluid at temperatures and pressures above the critical points of 30.85 °C and 7.38 MPa, respectively [39]. The 800 m depth requirement is a reasonable guess that varies based on the geothermal gradient and formation pressure at a given location [41]. The pressure in the pore spaces of sedimentary rocks is identical to hydrostatic pressure. This pressure is generated by a water column at a corresponding elevation to the depth of the pore space, since the pore space is frequently filled with water and, although in a convoluted manner, is connected to the ground surface. When the pore space is not connected with the surface at equilibrium, the hydrostatic pressure can be exceeded, and overpressure occurs [38]. Scholle [9] pointed out that pressure and temperature data for the COST GE-1 well were identified based on three temperature logs. The Lower Cretaceous temperature was where *G*CO<sup>2</sup> is the total mass of CO<sup>2</sup> in gigatons (Gt), *A* is the target area (in square meters), (DOE-NETL) (Equation (1)). Equation (1) is mathematically expressed as follows: CO2= × ℎ × × × (1) where CO2 is the total mass of CO2 in gigatons (Gt), *A* is the target area (in square meters), ℎ is the gross strata thickness (in meters), *φ* is the effective porosity, is the CO2 density in kilograms per cubic meter (kg/m3), and CO2 is the average CO2 density evaluated at pressure and temperature, representing storage conditions anticipated for a specific deep saline aquifer. Ennis-King and Paterson [38] pointed out that the CO2 density rises with a decrease in volume in the reservoir at depths ranging from 600 to 1000 m, depending on the specific geothermal conditions and pressure. Due to heat transfer, the average temperature in several geological formations increases by approximately 25–30.8 °C/km below the sea bed [39]. However, geothermal gradients vary significantly between local and global basins [40]. Nevertheless, the subsurface units suitable for geological carbon sequestration are 800 m or deeper below the seafloor, and seem to have higher pressure and temperature at depths greater than the CO2 critical point [12]. The critical point indicates that CO2 is injected at supercritical temperatures and pressures. CO2 and certain other supercritical gases possess gas viscosity, which reduces resistance to flow compared to liquid and semi-liquid density, significantly reducing the volume required to store a given mass of fluid. Carbon dioxide behaves as a supercritical fluid at temperatures and pressures above the critical points of 30.85 °C and 7.38 MPa, respectively [39]. The 800 m depth requirement is a reasonable guess that varies based on the geothermal gradient and formation pressure at a given location [41]. The pressure in the pore spaces of sedimentary rocks is identical to hydrostatic pressure. This pressure is generated by a water column at a corresponding elevation to the depth of the pore space, since the pore space is frequently (DOE-NETL) (Equation (1)). Equation (1) is mathematically expressed as follows: CO2= × ℎ × × × (1) where CO2 is the total mass of CO2 in gigatons (Gt), *A* is the target area (in square meters), ℎ is the gross strata thickness (in meters), *φ* is the effective porosity, is the CO2 density in kilograms per cubic meter (kg/m3), and CO2 is the average CO2 density evaluated at pressure and temperature, representing storage conditions anticipated for a specific deep saline aquifer. Ennis-King and Paterson [38] pointed out that the CO2 density rises with a decrease in volume in the reservoir at depths ranging from 600 to 1000 m, depending on the specific geothermal conditions and pressure. Due to heat transfer, the average temperature in several geological formations increases by approximately 25–30.8 °C/km below the sea bed [39]. However, geothermal gradients vary significantly between local and global basins [40]. Nevertheless, the subsurface units suitable for geological carbon sequestration are 800 m or deeper below the seafloor, and seem to have higher pressure and temperature at depths greater than the CO2 critical point [12]. The critical point indicates that CO2 is injected at supercritical temperatures and pressures. CO2 and certain other supercritical gases possess gas viscosity, which reduces resistance to flow compared to liquid and semi-liquid density, significantly reducing the volume required to store a given mass of fluid. Carbon dioxide behaves as a supercritical fluid at temperatures and pressures above the critical points of 30.85 °C and 7.38 MPa, respectively [39]. The 800 m depth requirement is a reasonable guess that varies based on the geothermal gradient and formation pressure at a given location [41]. The pressure in the pore spaces of sedimentary rocks is identical to hydrostatic pressure. This pressure is generated by a water column at a corresponding elevation to the depth of the pore space, since the pore space is frequently filled with water and, although in a convoluted manner, is connected to the ground surface. When the pore space is not connected with the surface at equilibrium, the hydrostatic pressure can be exceeded, and overpressure occurs [38]. Scholle [9] pointed out that pressure and temperature data for the COST GE-1 well is the gross strata thickness (in meters), *ϕ* is the effective porosity, *ρ* is the CO<sup>2</sup> density in kilograms per cubic meter (kg/m<sup>3</sup> ), and *ρ*CO<sup>2</sup> is the average CO<sup>2</sup> density evaluated at pressure and temperature, representing storage conditions anticipated for a specific deep saline aquifer. Ennis-King and Paterson [38] pointed out that the CO<sup>2</sup> density rises with a decrease in volume in the reservoir at depths ranging from 600 to 1000 m, depending on the specific geothermal conditions and pressure. Due to heat transfer, the average temperature in several geological formations increases by approximately 25–30.8 ◦C/km below the sea bed [39]. However, geothermal gradients vary significantly between local and global basins [40]. Nevertheless, the subsurface units suitable for geological carbon sequestration are 800 m or deeper below the seafloor, and seem to have higher pressure and temperature at depths greater than the CO<sup>2</sup> critical point [12]. The critical point indicates that CO<sup>2</sup> is injected at supercritical temperatures and pressures. CO<sup>2</sup> and certain other supercritical gases possess gas viscosity, which reduces resistance to flow compared to liquid and semiliquid density, significantly reducing the volume required to store a given mass of fluid. Carbon dioxide behaves as a supercritical fluid at temperatures and pressures above the critical points of 30.85 ◦C and 7.38 MPa, respectively [39]. The 800 m depth requirement is a reasonable guess that varies based on the geothermal gradient and formation pressure at a given location [41]. The pressure in the pore spaces of sedimentary rocks is identical to hydrostatic pressure. This pressure is generated by a water column at a corresponding elevation to the depth of the pore space, since the pore space is frequently filled with water and, although in a convoluted manner, is connected to the ground surface. When the pore space is not connected with the surface at equilibrium, the hydrostatic pressure can be exceeded, and overpressure occurs [38].

Scholle [9] pointed out that pressure and temperature data for the COST GE-1 well were identified based on three temperature logs. The Lower Cretaceous temperature was filled with water and, although in a convoluted manner, is connected to the ground surface. When the pore space is not connected with the surface at equilibrium, the hydrostatic pressure can be exceeded, and overpressure occurs [38]. Scholle [9] pointed out that pressure and temperature data for the COST GE-1 well were identified based on three temperature logs. The Lower Cretaceous temperature was were identified based on three temperature logs. The Lower Cretaceous temperature was Scholle [9] pointed out that pressure and temperature data for the COST GE-1 well were identified based on three temperature logs. The Lower Cretaceous temperature was estimated as 72.3 ◦C at the top and 81.4 ◦C at the bottom, with a geothermal gradient of 16 ◦C/km, based on a geothermal gradient that was only available at the COST GE-1 well. The parameters (*A*, *h*¯, and *ϕ*) are the yield of the total pore volume of the studied section. The *ρ* parameter is the volume conversion to the mass of CO2, and the efficiency factor

(*E*) reduces the total CO<sup>2</sup> mass for storage to an accurate, realistic value [41,42]. The CO<sup>2</sup> storage efficiency factor is the portion of rock suitable for CO<sup>2</sup> storage, and is defined as the fraction of pore space where injected CO<sup>2</sup> can permanently displace formation fluids [43]. Table 1 shows efficiency factors for different lithologies and estimated with different methods, including numerical and Monte Carlo simulations [11,16,35,44]. According to the US DOE approach, storage efficiency is a function of aquifer characteristics such as area, thickness, and porosity—the product of which represents the aquifer pore volume—as well as displacement efficiency components such as areal, vertical, and microscopic components, and is expressed as the product of these individual efficiencies [16,35,45].

**Table 1.** Numerical and Monte Carlo estimates for saline formation efficiency factors at the formation scale. Adapted with permission from Ref. [16]. Copyright 2011, Copyright Goodman et al., Ref. [35]. Copyright 2009, copyright Goreckie et al., and Ref. [46]. Copyright 2009, copyright Preston et al.


Goodman et al. [16] used Monte Carlo sampling to calculate local- and regionalscale storage efficiency values based on statistical properties (i.e., mean values, standard deviation, ranges, and distributions) that describe geological and displacement parameters for three lithologies: clastics, dolomite, and limestone. They obtained slightly lower values for storage efficiency (E) than Gorecki et al. [35]. Efficiency in saline formations can be calculated using Equation (2):

$$\mathbf{E} = \mathbf{E}\_{\mathrm{An}/\mathrm{At}} \times \mathbf{E}\_{\mathrm{Hn}/\mathrm{Hg}} \times \mathbf{E}\_{\mathrm{Oe}/\mathrm{Ot}} \times \mathbf{E}\_{\mathrm{A}} \times \mathbf{E}\_{\mathrm{V}} \times \mathbf{E}\_{\mathrm{d}} \tag{2}$$

where EAn/At is the percentage-to-total-area ratio ideal for CO<sup>2</sup> storage; EHn/Hg is the fraction-to-gross-thickness ratio that meets the porosity and permeability standards for CO<sup>2</sup> storage; EØe/Øt represents the ratio of linked porosity to total porosity; E<sup>A</sup> is the effective aquifer area; E*<sup>v</sup>* is the volumetric displacement; and E<sup>d</sup> is the microscopic displacement. The net-to-total-area ratio EAn/At is the proportion of the aquifer area suitable for CO<sup>2</sup> storage, expressed as a net-to-gross-thickness ratio. EHn/Hg is the fraction of the geological formation in the vertical dimension that meets the porosity and permeability requirements for CO<sup>2</sup> injection and storage, and EØe/Øt is the effective (interconnected)-porosity-to-totalporosity ratio. The storage efficiency factor reflects the total pore volume filled with CO2. There is no comparison established between the CO<sup>2</sup> stored by different processes. For a 15–85% certainty value, Monte Carlo simulations generate an E range between 1 and 4% of the bulk volume of a deep saline aquifer, with an average of 2.4% for 50% confidence. The Monte Carlo simulated by USDOE-NETL [47] that established the proposed range for E varied several calculation factors, i.e., from 0.20 to 0.80 of the saline aquifer appropriate for CO<sup>2</sup> storage; 0.25 to 0.75 of the geological unit has the porosity and permeability required for CO<sup>2</sup> injection; the interconnected porosity fraction ranges from 0.6 to 0.95; the areal displacement efficiency ranges between 0.5 and 0.8, while the vertical displacement efficiency ranges between 0.6 and 0.9. Due to CO<sup>2</sup> buoyancy, CO<sup>2</sup> occupies between 0.2 and 0.6 percent of the net aquifer thickness. The effectiveness of pore-scale displacement ranges from 0.5 to 0.8. The maximum and minimum values for each parameter were calculated to reflect varied lithologies and geological depositional systems in North America, with the maximum and minimum values representing reasonably high and low values, respectively.

Several analogies are found in the US DOE method [48]; the effect of total water saturation is included in the efficiency factor E through the pore-scale displacement efficiency. The salty aquifers with TDS more than 10,000 ppm and deeper than 800 m should be considered, as this is the minimum depth required to assure that CO<sup>2</sup> is in a dense liquid

or supercritical phase confined by aquitards or aquicludes (caprock), which include shale, anhydrite, and evaporite. The considerations of the US DOE method introduce storage efficiency coefficient calculations through Monte Carlo simulations of CO<sup>2</sup> storage within deep saline aquifers in North America. The US DOE obtained a range of values for these storage efficiency coefficients for the 0.15 and 0.85 confidence intervals, ranging between 0.1 and 0.4 for deep saline aquifers. Based on the IPCC [1] report, the US DOE screening requirements were assumed, and these coefficients have a value of unity in local-scale assessments or, more broadly, when the effective aquifer area, thickness, and porosity are known. In this study, we used the value of the efficiency factor suggested by the US DOE [35] (Table 1).

Goodman et al. [16] demonstrated that geological uncertainty has a greater impact on storage estimation than the approach used. Thus, it is critical to determine the geological estimates and ranges of storage efficiency factors for certain geological parameters to improve or refine storage estimates. In addition, due to the legacy of seismic data and the relatively limited well data available over the 200,000 km<sup>2</sup> study area, uncertainty associated with the subsurface data gap must be assumed in the storage resource assessment. The potential capacity of the several reservoirs of the Lower Cretaceous section was calculated using all parameters in Equation (1).

### **4. Results and Discussions**

### *4.1. Well Data Analysis*

The well log interpretation is the most fundamental geophysical approach for geological and geophysical reservoir characterizations. The density log (RHOB) provides lithology interpretation, porosity calculation, and petrophysical properties. The gamma ray (GR) log is used to interpret lithology, porosity, and permeability. The spontaneous potential (SP) log is useful for lithology identification and permeability calculation. Both GR and SP have a similar response to porous layers, and can determine lithology and correlate stratigraphy. Density logs (RHOB) provide a continuous record of the bulk density, determined by the porosity of the formation and the fluid content of the pore spaces. GR and ROHB logs for the TRANSCO 1005-1 well, COST GE-1 well, and EXXON 564-1 well were stratigraphically interpreted and correlated in this study to obtain similar equivalents in the sedimentary sequences (Figure 2). Related to the sidewall core analysis on the COST GE-1 well, the porosity was valued between 0.12 and 0.35, and the permeability was estimated between 9.87 <sup>×</sup> <sup>10</sup>−<sup>18</sup> and 5.4 <sup>×</sup> <sup>10</sup>−<sup>13</sup> <sup>m</sup><sup>2</sup> , within the Lower Cretaceous strata [9].

The Lower Cretaceous strata, between depths of 1798 m and 2195 m, have 14 lithological intervals, which are mainly composed of varying proportions of calcite, clay, shale, sandstone, limestone, and dolomite with carbonite materials [9] (Table 2).

**Table 2.** The 14 lithological intervals of the Lower Cretaceous strata, between depths of 1798 and 2195 m in the COST GE-1 well, based on [9]. Adapted with permission from Ref. [9]. Copyright 1979, copyright Scholle.




For the COST GE-1 well, the net porosity was geophysically derived by the ratio of the density log (RHOB) and the gamma ray log (GR). The values calculated from the log data were then compared with the measured values from the conventional and sidewall cores for the Lower Cretaceous lithological units to identify potential reservoirs and seals (Figure 4). Significant CO<sup>2</sup> storage was predicted where high primary and secondary porosity values ranged from 0.20 to 0.33, accounting for the greatest permeability range of 1.97 <sup>×</sup> <sup>10</sup>−13–5.43 <sup>×</sup> <sup>10</sup>−<sup>13</sup> <sup>m</sup><sup>2</sup> recorded in the Lower Cretaceous section. *Energies* **2022**, *15*, x FOR PEER REVIEW 10 of 19

**Figure 4.** Analysis of density logs and gamma ray logs to generate porosity logs, compared with **Figure 4.** Analysis of density logs and gamma ray logs to generate porosity logs, compared with estimated porosity from analysis of core samples from the COST GE-1 well.

faulted strata or capillary entry pressure is present.

estimated porosity from analysis of core samples from the COST GE-1 well.

In a practical CO<sup>2</sup> storage evaluation, Chadwick et al. [42] concluded that a generic

single anticlinal aquifer structure. The effective size of the reservoir is a critical parameter

to determine water displacement, with high pressure leading to increased porosity of 20%

or higher, which is a requirement for safe injection into porous strata. While the CO<sup>2</sup> in-

jection pressure significantly increases from 5 to 10 MPa in the injection zone, the effective

storage capacity in the caprocks increases when the pressure of the injected CO<sup>2</sup> exceeds

the initial formation pressure [49]. Table 3 demonstrates atypical geological criteria of the

static and dynamic storage capacities for the reservoir depth of 1000–2500 m with a thick-

ness of 21–50 m, where the porosity is greater than 0.20 and the permeability is greater

**Table 3.** Ideal geological CO<sup>2</sup> storage criteria for reservoir properties and caprocks. Reprinted with

permission from Ref. [42]. Copyright 2008, copyright Chadwick et al., and Ref. [50]. Copyright

**Media Properties Positive Indicators Cautionary Indicators**

Evaluated effective CO<sup>2</sup> stor-

age capacity greater than total

injected CO<sup>2</sup>

Predicted injection-induced

pressures below the rate of in-

ducing geomechanical damage

to the reservoir or caprock.

tal injected CO<sup>2</sup>

Stratigraphy Capacity much larger than to-

Depth (m) Greater than 800 Less than 800

Porosity Greater than 0.20 Less than 0.10

Greater than 4.93 × 10−1<sup>2</sup> Less than 1.97 × 10−1<sup>3</sup>

Thickness (m) Greater than 50 Less than 20

. The ideal seal thickness is 100 m with lateral continuity, and non-

Evaluated effective CO<sup>2</sup> stor-

age capacity equal to total in-

jected CO<sup>2</sup>

Geomechanical instability lim-

its reaching the predicted in-

jection-induced pressures.

Capacity ≤ total injected CO<sup>2</sup>

*4.2. Geological CO<sup>2</sup> Storage*

than 1.978 × 10−1<sup>3</sup> m<sup>2</sup>

2017, copyright Chadwick et al.

ReservoirStatic storage ca-

pacity

Dynamic stor-

age capacity

Permeability

(m<sup>2</sup> )

### *4.2. Geological CO<sup>2</sup> Storage*

In a practical CO<sup>2</sup> storage evaluation, Chadwick et al. [42] concluded that a generic case may be associated with injecting large quantities—reaching 400 Mt—of CO<sup>2</sup> into a single anticlinal aquifer structure. The effective size of the reservoir is a critical parameter to determine water displacement, with high pressure leading to increased porosity of 20% or higher, which is a requirement for safe injection into porous strata. While the CO<sup>2</sup> injection pressure significantly increases from 5 to 10 MPa in the injection zone, the effective storage capacity in the caprocks increases when the pressure of the injected CO<sup>2</sup> exceeds the initial formation pressure [49]. Table 3 demonstrates atypical geological criteria of the static and dynamic storage capacities for the reservoir depth of 1000–2500 m with a thickness of 21–50 m, where the porosity is greater than 0.20 and the permeability is greater than 1.978 <sup>×</sup> <sup>10</sup>−<sup>13</sup> <sup>m</sup><sup>2</sup> . The ideal seal thickness is 100 m with lateral continuity, and non-faulted strata or capillary entry pressure is present.

**Table 3.** Ideal geological CO<sup>2</sup> storage criteria for reservoir properties and caprocks. Reprinted with permission from Ref. [42]. Copyright 2008, copyright Chadwick et al., and Ref. [50]. Copyright 2017, copyright Chadwick et al.


The Lower Cretaceous section from the COST GE-1 well was described in terms of lithology and rock properties through 14 core samples [9]. Dolomite rocks are the most dominant rocks in this section. The porosity and permeability of the different stratigraphic intervals were the primary basis for identifying the main storage units. The reservoirs and seals were classified and evaluated with the observance of the positive indicators of the CO<sup>2</sup> storage criteria described by Chadwick et al. [42] (Figure 5). Three reservoirs separated by three seals were identified within the Lower Cretaceous section. Figure 3 illustrates the 14 intervals that appear most suitable for permanent offshore CO<sup>2</sup> storage. Figure 6 reveals structural maps for the top and bottom topographic surfaces and the thickness of the Lower Cretaceous strata. The Lower Cretaceous section ranges in depth between 1798 m and 2539 m, and consists of dolomite interbedded with sandstones and calcareous silty shales. Based on the rock composition and physical rock properties, this section (Table 2) records the lithological description and porosity values with depth for the COST GE-1 well, based on core analyses and geophysical logs. Figure 5 shows the potential CO<sup>2</sup> storage reservoirs and seals based on the rock properties compared with the favorable conditions for CO<sup>2</sup> storage [42]. Scholle [9] noted impermeable shale with

calcareous shale layers interbedded with highly permeable dolomite in the COST GE-1 well. However, a few samples of sandstone were marked between 1768 m and 2530 m, with high primary and secondary porosity and high permeability, suitable as reservoir rock for CO<sup>2</sup> storage. This section is dominated by dolomite with porosities that vary widely and unsystematically, with depth from 0.17 to 0.32 and permeability between 2.096 <sup>×</sup> <sup>10</sup>−<sup>13</sup> and 5.43 <sup>×</sup> <sup>10</sup>−<sup>13</sup> <sup>m</sup><sup>2</sup> . The porosity log was derived and calculated from well logs to fill in the gaps between the core intervals (Figure 4). *Energies* **2022**, *15*, x FOR PEER REVIEW 12 of 19


**Figure 5.** Characterizations of the storage elements, seals, and reservoirs identified based on the geological and geophysical data at the COST GE-1 well. **Figure 5.** Characterizations of the storage elements, seals, and reservoirs identified based on the geological and geophysical data at the COST GE-1 well.

**Figure 6.** Structural maps of the study area: (**A**) the location map of the study area, (**B**) the depth map for the top topographic surface of the Lower Cretaceous section, (**C**) the depth map for the bottom topographic surface of the Lower Cretaceous section, (**D**) the thickness map of the Lower Cretaceous section, and (**E**) is the cross-section AB shown in panels (**B**,**C**) in this figure. The crosssection AB demonstrates the lateral extension and thickness of the reservoirs and seals across the Lower Cretaceous strata in the study area. **Figure 6.** Structural maps of the study area: (**A**) the location map of the study area, (**B**) the depth map for the top topographic surface of the Lower Cretaceous section, (**C**) the depth map for the bottom topographic surface of the Lower Cretaceous section, (**D**) the thickness map of the Lower Cretaceous section, and (**E**) is the cross-section AB shown in panels (**B**,**C**) in this figure. The crosssection AB demonstrates the lateral extension and thickness of the reservoirs and seals across the Lower Cretaceous strata in the study area.

#### *4.3. CO<sup>2</sup> Storage Capacity Calculations 4.3. CO<sup>2</sup> Storage Capacity Calculations*

The capacity for CO<sup>2</sup> storage potential of the Lower Cretaceous section was calculated based on the rock compositions and petrophysical properties at the COST GE-1 well. Three potential reservoirs were associated with four potential seals characterized and assessed in the Lower Cretaceous section. The three reservoirs are sealed by thick caprocks mainly composed of shale, siltstone, anhydrite, and limestone. These reservoirs are marked as R1, R2, and R3, and their seals are marked as S1, S2, S3, and S4 (Figure 5). According to Scholle [9], the trapping mechanism, characterized as an overlying seal, involves stratigraphic trapping through lateral facies variations. Figure 5 shows that reservoir R1 ranges in depth from 1855 to 1989 m, reservoir R2 ranges in depth from 2119 to 2210 m, and reservoir R3 ranges in depth from 2349 to 2442 m. The three reservoirs are The capacity for CO<sup>2</sup> storage potential of the Lower Cretaceous section was calculated based on the rock compositions and petrophysical properties at the COST GE-1 well. Three potential reservoirs were associated with four potential seals characterized and assessed in the Lower Cretaceous section. The three reservoirs are sealed by thick caprocks mainly composed of shale, siltstone, anhydrite, and limestone. These reservoirs are marked as R1, R2, and R3, and their seals are marked as S1, S2, S3, and S4 (Figure 5). According to Scholle [9], the trapping mechanism, characterized as an overlying seal, involves stratigraphic trapping through lateral facies variations. Figure 5 shows that reservoir R1 ranges in depth from 1855 to 1989 m, reservoir R2 ranges in depth from 2119 to 2210 m, and reservoir R3 ranges in depth from 2349 to 2442 m. The three reservoirs are composed as follows: (1) R1 is composed of calcareous shale, anhydrite, and gypsum; (2) R2 is composed

composed as follows: (1) R1 is composed of calcareous shale, anhydrite, and gypsum; (2) R2 is composed of limestone and shale; and (3) R3 is composed of calcareous shale, anhy-

developed earlier by Goodman et al. [16], for applying the dolomite efficiency factor (Equation (2)) at the formation scale to give 2.58%, 3.26%, and 5.54% for probabilities of

of limestone and shale; and (3) R3 is composed of calcareous shale, anhydrite, fossil fragments, and gypsum. The average porosities of the reservoirs (R1, R2, and R3) are 0.23–0.28, 0.28–0.32, and 0.25–0.32, respectively. We used Equation (1), which was developed earlier by Goodman et al. [16], for applying the dolomite efficiency factor (Equation (2)) at the formation scale to give 2.58%, 3.26%, and 5.54% for probabilities of 0.10, 0.50, and 0.90, respectively. This work considers the probabilities for the area (A) parameter with a wide range of thickness values over the area (Table 4) to apply Equation (1). The uncertainty of CO<sup>2</sup> density with depth and thickness in the Lower Cretaceous section can be reduced by calculating the density of CO<sup>2</sup> based on the depth of each reservoir (Figure 6). For accuracy of CO<sup>2</sup> density values, the Lower Cretaceous section is divided into three depth zones: (1) the shallow depth (SLK) is in the 300–1000 m range, (2) the depth of the COST GE-1 well (GLK) is in the 1600–2450 m range, and (3) the deep reservoir (DLK) ranges from 3000 to 3500 m. To identify the temperature of the reservoirs in the three depth zones, we assumed that the geothermal gradient at COST GE-1 well (16 ◦C) is constant across the study area (Figure 7A; Table 5). Based on the temperature–pressure–density graph [41] (Figure 7B), the density values of supercritical CO<sup>2</sup> were estimated based on the depth and temperature considered in the NETL CO<sup>2</sup> calculation method [47]. *Energies* **2022**, *15*, x FOR PEER REVIEW 14 of 19 0.10, 0.50, and 0.90, respectively. This work considers the probabilities for the area (A) parameter with a wide range of thickness values over the area (Table 4) to apply Equation (1). The uncertainty of CO<sup>2</sup> density with depth and thickness in the Lower Cretaceous section can be reduced by calculating the density of CO<sup>2</sup> based on the depth of each reservoir (Figure 6). For accuracy of CO<sup>2</sup> density values, the Lower Cretaceous section is divided into three depth zones: (1) the shallow depth (SLK) is in the 300–1000 m range, (2) the depth of the COST GE-1 well (GLK) is in the 1600–2450 m range, and (3) the deep reservoir (DLK) ranges from 3000 to 3500 m. To identify the temperature of the reservoirs in the three depth zones, we assumed that the geothermal gradient at COST GE-1 well (16 °C) is constant across the study area (Figure 7A; Table 5). Based on the temperature–pressure–density graph [41] (Figure 7B), the density values of supercritical CO2 were estimated based on the depth and temperature considered in the NETL CO<sup>2</sup> calculation method [47].

**Figure 7.** (**A**) The three reservoirs in three depth zones plotted in the geothermal gradient at the COST GE-1 well. (**B**) The time–depth–pressure graph to identify the density of supercritical CO<sup>2</sup> for three reservoirs in the three depth zones of the Lower Cretaceous section. **Figure 7.** (**A**) The three reservoirs in three depth zones plotted in the geothermal gradient at the COST GE-1 well. (**B**) The time–depth–pressure graph to identify the density of supercritical CO<sup>2</sup> for three reservoirs in the three depth zones of the Lower Cretaceous section.

(1)) in the local and regional zones. **Zone Reservoir Area (km²) Gross Thickness (m) Total Porosity (%) Pressure (MPa) Temperature (°C) Table 4.** The physical parameters for the three reservoirs applied in the NETL method (Equation (1)) in the local and regional zones.

**Table 4.** The physical parameters for the three reservoirs applied in the NETL method (Equation



**Table 5.** CO<sup>2</sup> density values estimated based on depth, temperature, and overburden pressure for the reservoirs in the three depth zones.

We estimated the potential storage resources of the three reservoirs for local and regional areas. The local area was detected where seismic profiles and well data were densely concentrated in the Southeast Georgia Embayment, which covers approximately 10,000 km<sup>2</sup> . The regional storage resource covers approximately 200,000 km<sup>2</sup> , which we detected based on the abundance and density of the data. We considered three probabilities (P10, P50, and P90) for each reservoir to determine the geological storage efficiency factor in both areas. For the integrity and safety of CO<sup>2</sup> storage, we interpreted and evaluated impermeable rock units that were denoted as seals. Although the seismic interpretation indicated no significant faults in the Lower Cretaceous section, the uniform lateral stratigraphy was a considerable concern due to the lack of wells in the study area. Table 4 demonstrates the required parameters that were applied in Equation (1) to identify the probabilistic estimate of the efficiency factor from P10 to P90 in Equation (2), as shown in Table 6.

**Table 6.** The probabilities from P10 to P90 of the ratio parameters that were considered in Equation (2) to identify the efficiency factor (E) at the formation scale for dolomite reservoirs of the Lower Cretaceous section.


Table 7 shows the results of the quantitative estimates of CO<sup>2</sup> storage capacity in the local and regional potential storage resources for the Lower Cretaceous potential reservoirs. The total capacity of the three storage resources with a geological storage efficiency (E) of dolomite between 0.65 and 5.40% ranges between 48.98 and 376.70 Mt of CO<sup>2</sup> at P10 to P90 for the local area (Figure 8), and the E ranges between 450.85 and 4705.46 Mt of CO<sup>2</sup> for the regional area (Figure 9).

**Table 7.** Volumetric CO<sup>2</sup> storage capacity (GCO<sup>2</sup> ) in Mt with the storage efficiency factor (E%) at P10, P50, and P90 for the three Lower Cretaceous reservoirs within local and regional zones in the Mid–South Atlantic Ocean.


than 0.42 Gt of CO2, and R3 is greater than 0.59 Gt of CO<sup>2</sup> at P50.

than 0.42 Gt of CO2, and R3 is greater than 0.59 Gt of CO<sup>2</sup> at P50.

*Energies* **2022**, *15*, x FOR PEER REVIEW 16 of 19

**Figure 8.** The total CO<sup>2</sup> storage capacity (in gigatons) for the Lower Cretaceous section: (**A**) the total capacity at P10, (**B**) P50, and (**C**) P90 in the local area. **Figure 8.** The total CO<sup>2</sup> storage capacity (in gigatons) for the Lower Cretaceous section: (**A**) the total capacity at P10, (**B**) P50, and (**C**) P90 in the local area. **Figure 8.** The total CO<sup>2</sup> storage capacity (in gigatons) for the Lower Cretaceous section: (**A**) the total capacity at P10, (**B**) P50, and (**C**) P90 in the local area.

2 88.54 414.75 1574.37 0.67 2.22 5.4 3 179.67 597.97 1502.37 0.67 2.17 5.3

2 88.54 414.75 1574.37 0.67 2.22 5.4 3 179.67 597.97 1502.37 0.67 2.17 5.3

At P50, the average CO<sup>2</sup> storage in the Lower Cretaceous section is approximately 1.65 Gt. Reservoir R1 has a maximum storage capacity value of 0.63 Gt of CO2. R2 is greater

At P50, the average CO<sup>2</sup> storage in the Lower Cretaceous section is approximately 1.65 Gt. Reservoir R1 has a maximum storage capacity value of 0.63 Gt of CO2. R2 is greater

**Figure 9.** The total CO<sup>2</sup> storage capacity (in gigatons) for the Lower Cretaceous section: (**A**) the total capacity at P10, (**B**) P50, and (**C**) P90 in the regional area. **Figure 9.** The total CO<sup>2</sup> storage capacity (in gigatons) for the Lower Cretaceous section: (**A**) the total capacity at P10, (**B**) P50, and (**C**) P90 in the regional area. **Figure 9.** The total CO<sup>2</sup> storage capacity (in gigatons) for the Lower Cretaceous section: (**A**) the total capacity at P10, (**B**) P50, and (**C**) P90 in the regional area.

**5. Summary and Conclusions** This work presents the first comprehensive study to identify and evaluate the CO<sup>2</sup> storage potential of the Lower Cretaceous section of the Mid–South Atlantic offshore southeastern United States. Based on the analysis of three wells in the Southeast Georgia **5. Summary and Conclusions** This work presents the first comprehensive study to identify and evaluate the CO<sup>2</sup> storage potential of the Lower Cretaceous section of the Mid–South Atlantic offshore At P50, the average CO<sup>2</sup> storage in the Lower Cretaceous section is approximately 1.65 Gt. Reservoir R1 has a maximum storage capacity value of 0.63 Gt of CO2. R2 is greater than 0.42 Gt of CO2, and R3 is greater than 0.59 Gt of CO<sup>2</sup> at P50.

#### Embayment, the CO<sup>2</sup> geological storage capacity estimate provides evidence of three southeastern United States. Based on the analysis of three wells in the Southeast Georgia Embayment, the CO<sup>2</sup> geological storage capacity estimate provides evidence of three **5. Summary and Conclusions**

This work presents the first comprehensive study to identify and evaluate the CO<sup>2</sup> storage potential of the Lower Cretaceous section of the Mid–South Atlantic offshore southeastern United States. Based on the analysis of three wells in the Southeast Georgia Embayment, the CO<sup>2</sup> geological storage capacity estimate provides evidence of three significant permeable storage strata that are isolated by impermeable seals in the depth interval of 1767.84–2529.84 m. Based on an analysis of the COST GE-1 well, we identified wide and unsystematic porosity ranges from 0.17 to 0.32, and permeabilities between 2.1 <sup>×</sup> <sup>10</sup>−<sup>13</sup> and 5.43 <sup>×</sup> <sup>10</sup>−<sup>13</sup> <sup>m</sup><sup>2</sup> (low percentage of sandstone and high percentage of dolomite). These layers are suitable reservoir rocks qualified for permanent CO<sup>2</sup> storage.

The US DOE methodology was used for calculating pore volume spaces to estimate the geological CO<sup>2</sup> storage potential capacity in megatons (Mt). The CO<sup>2</sup> storage potential of the Lower Cretaceous section was calculated based on the rock compositions and petrophysical properties at the COST GE-1 well. Three potential reservoirs were associated with four potential seals that were characterized and assessed. According to Scholle [9], the trapping mechanism indicated by an overlying seal involves stratigraphic variations. The prospective storage resources of the three reservoirs were calculated locally, where seismic profiles and well data were densely concentrated in the Southeast Georgia Embayment (10,000 km<sup>2</sup> ), and regionally, where we suggested a regional storage resource of 200,000 km<sup>2</sup> . We considered three probability values (P10, P50, and P90) of each reservoir for determining the geological storage efficiency factor in both areas. This study suggests that the CO<sup>2</sup> storage capacity ranges approximately from 48.98 to 376.70 Mt locally, and from 450.85 to 4705.46 Mt regionally, in the three Lower Cretaceous reservoirs, with geological storage efficiencies from 0.65% to 5.4%.

The average storage potential is approximately 82 tons of CO2, which could be safely stored per 1 km<sup>2</sup> offshore of the Lower Cretaceous section, at a probability of 0.5. The largest CO<sup>2</sup> storage capacity value for reservoir R1 was >3.2 tons/km<sup>2</sup> . The intermediate and lowest values at P50 in reservoirs R3 and R2 were less than or equal to 2.7 tons/km<sup>2</sup> . Since the reservoir heterogeneity impacts the pressure distribution, and the CO<sup>2</sup> plume migration is significantly affected by the permeability, we suggest that reservoir R2 and seals S2 and S3 can provide additional protection for safe injection and storage in case unpredictable leakage occurs due to unexpected natural hazards.

The uncertainty associated with subsurface data gaps was incorporated into the storage resource evaluation due to the legacy of seismic data and the relatively limited well data available over the study area.

**Author Contributions:** Formal analysis, D.S.A.; Investigation, D.S.A.; Supervision, J.H.K.; Writing original draft, D.S.A.; Writing—review & editing, J.H.K. and C.K. All authors have read and agreed to the published version of the manuscript.

**Funding:** This research received no external funding.

**Institutional Review Board Statement:** This study did not require ethical.

**Informed Consent Statement:** Not applicable.

**Data Availability Statement:** https://walrus.wr.usgs.gov/namss/search/ (accessed on 1 June 2022).

**Acknowledgments:** We thank the Iraqi Ministry of Higher Education and Scientific Research (MO-HESR), the Marine Science Center (MSC)–Basrah University, and the Iraqi Cultural office in Washington DC for funding and supporting the first author. This material is based upon work supported by the US Department of Energy National Energy Technology Laboratory, through a Cooperative Agreement DE-FE0026086 with the Southern States Energy Board. Cost sharing and research support were provided by the Project Partners and an Advisory Committee. The SOSRA team also includes the Virginia Polytechnic Institute and State University/Virginia Center for Coal and Energy Research; the Virginia Department of Mines, Minerals, and Energy; the South Carolina Geological Survey; Oklahoma State University; the Geological Survey of Alabama; the State Oil and Gas Board of Alabama; and Advanced Resources International, Inc. In addition, we would like to thank Schlumberger for providing access to Petrel software, and we are grateful to the Schlumberger technical team for their support. We would like to thank the US Department of Energy National Energy Technology Laboratory and Angela Goodman for providing further information about the DOE approach and CO<sup>2</sup> -SCREEN techniques. We also thank the University of South Carolina and Susannah Boote for assistance in downloading and organizing the database at the University of South Carolina.

**Conflicts of Interest:** The authors declare no conflict of interest.

### **References**

