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10.1038/s41598-024-66272-x
Article
Basin-scale study of CO2 storage in stacked sequence of geological formations
Wijaya Nur 123
Morgan David 2
Vikara Derek 12
Grant Timothy 2
Cunha Luciane 2
Liu Guoxiang Guoxiang.liu@netl.doe.gov

2
1 grid.451363.6 0000 0001 2206 3094 National Energy Technology Laboratory (NETL) Support Contractor, 626 Cochrans Mill Road, P.O. Box 10940, Pittsburgh, PA 15236 USA
2 grid.451363.6 0000 0001 2206 3094 NETL, 626 Cochrans Mill Road, P.O. Box 10940, Pittsburgh, PA 15236 USA
3 Repsol USA, 2455 Technology Forest Blvd, The Woodlands, TX 77381 USA
12 8 2024
12 8 2024
2024
14 1866122 4 2024
1 7 2024
© This is a U.S. Government work and not under copyright protection in the US; foreign copyright protection may apply 2024, corrected publication 2024
2024
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Commercial scale decarbonization through carbon capture and storage may likely involve many CO2 storage projects located in close proximity. The close proximity could raise concerns over caprock integrity associated with reservoir pressure buildup and interference among adjacent projects. Commercial-scale injection will also require large prospective CO2 storage resource and high injectivity in the targeted storage formations. To accommodate the need for both large resource and high injectivity, project operators could consider injecting CO2 into a stacked sequence of formations. This analysis investigates the benefits of injecting CO2 into a vertically stacked sequence of saline formations, over injecting the same amount of CO2 into a single saline formation, in addressing these challenges. Our analysis shows that injecting into the stacked sequence mitigates the extent of pressure buildup among the stacked formations, while still achieving the same or greater target CO2 storage volumes. Among cases modeled, the resulting pressure buildup front is most reduced when each storage site distributes injection volumes over several wells, each of which injects a portion of the total CO2 mass across the stacked sequence. This favorable case not only results in the smallest CO2 aerial footprint, but also shows the largest reduction in the pressure buildup at the top of perforation at the injection wells (upwards of approximately 46% compared to the single-formation storage), the result of which is crucial to maintain caprock integrity. This analysis provides insights into required decision-making when considering multi-project deployment in a shared basin.

Keywords

Carbon capture and storage
Basin-scale modeling
Saline formations
Pressure buildup
CO2 plume commingling
Subject terms

Energy science and technology
Carbon capture and storage
issue-copyright-statement© Springer Nature Limited 2024
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pmcIntroduction

Carbon capture and storage (CCS) has been proposed as a key decarbonation strategy to control the climate change by capturing anthropogenic carbon dioxide (CO2) from stationary CO2 emitters and storing it permanently in underground geologic formations1–6. The target injection zones mainly consist of three types: saline formations7, depleted oil and gas reservoirs8,9, and unmineable coal beds10,11. Among these, saline formations are identified as promising CO2 injection option12,13 because they offer the greatest prospective CO2 storage resource, which is defined as the mass of CO2 that can theoretically be stored in available pore space at the primary stage of a CO2 storage project14–17. Saline formations are brine-saturated porous and permeable rocks with total dissolved solids (TDS) higher than the cutoff for protected underground sources of drinking water (USDW), which is generally 10,000 parts per million (ppm) in the United States (U.S.)18–20.

The U.S. Department of Energy (DOE)’s National Energy Technology Laboratory (NETL) estimated between 2379 and 21,633 billion metric tons of prospective CO2 storage resource in saline formations in onshore North America based on the onshore CO2 volumetric assessment effort under the Regional Carbon Storage Partnerships (RCSPs)21–23. Through this effort, it was demonstrated that saline formations are widely distributed across onshore North America and co-located with major CO2 stationary emitters24, the setting of which offers a unique opportunity for the decarbonization goals. To foster the deployment of large-scale CO2 storage projects, the U.S. DOE NETL launched the Carbon Storage Assurance Facility Enterprise (CarbonSAFE) Initiatives, which aim to build off the work done by the RCSPs to fund and develop more projects. More importantly, these projects provide lessons learned for commercial-scale CCS projects, which are defined as those in which at least 50 million metric tons (Mt) of CO2 are injected underground over the course of next 20 to 30 years25.

Close proximity among injection wells

To accommodate the extensive target injection rates, the commercial-scale CCS projects may likely involve many CO2 storage projects located in close proximity. The commercial-scale injection may create pressure buildup in the storage formations, the magnitude of which depends on the volumetric size and hydraulic conductivity of storage formations. In this analysis, the pressure buildup is defined as1 ΔPx,y,z,t=Px,y,z,t-Pi(x,y,z)

where ΔPx,y,z,t is the pressure buildup at a given point (x,y,z) in the formation at time t, Px,y,z,t is the instantaneous pressure existing at the corresponding point (x,y,z) at the instant t considered, and Pi(x,y,z) is the initial ambient reservoir pressure at the corresponding point (x,y,z). In the absence of basin-wide pressure management operations (e.g., brine production from the storage formations), the pressure buildup can be extensive, which would limit the amount of CO2 that can be safely stored in the storage formations. The U.S. Environmental Protection Agency (EPA) regulates underground injection activities in order to prevent contamination of current and future USDW through its Underground Injection Control (UIC) program26. CO2 injection for long-term storage is a practice subject to UIC rules under Class VI, which are noted in the Code of Federal Regulations (CFR) parts 40 CFR 146.81–40 CFR 146.95. The U.S. EPA Class VI rules stipulate that the maximum reservoir pressure in the injection zone cannot exceed 90% of fracture pressure26, which this analysis defines as “fracture pressure threshold” given by2 γx,y,z=0.9×Pfx,y,z-Pix,y,z

where γx,y,z is the fracture pressure threshold at a given point (x,y,z) in the formation and Pfx,y,z is the fracture pressure at the corresponding point (x,y,z). Assuming a homogeneous fracture pressure gradient (∇Pf presented in psi/ft in this analysis) across a particular area, as assumed in this analysis, γx,y,z is simplified to γz. This fracture pressure threshold (γ) serves as a critical constraint to avoid large-scale pressure buildup to maintain caprock integrity, avoid any potential existing fault impact, significant stress perturbations, and prevent brine and/or CO2 from leaking into the overlying USDW27–29. Excessive pressure buildup can cause the water table to rise, which could increase the rates of water discharge into surface lakes or streams30,31 and change surface and subsurface flow patterns from land-surface deformation or uplift31.

The close proximity among storage projects may create large pressure interference early in the injection period; this can amplify the magnitude of pressure buildup, especially near the injection wells. Pressure interference is defined in this analysis by:3 ϵi-jx,y,z,t=ΔPix,y,z,t-ΔPjx,y,z,t

where ϵijx,y,z,t is the pressure interference at a given point (x,y,z) in the formation at time t, ΔPix,y,z,t is the pressure buildup of a given case i at the corresponding point (x,y,z) at the instant t considered, and ΔPjx,y,z,t is the pressure buildup of the baseline case j at the corresponding point (x,y,z) at the instant t considered. Pressure interference could result in more rapid pressure buildup and limit the injection rate. Consequently, the anticipated volume of captured CO2 could require other operational strategies (e.g., additional sink options) to store.

Additionally, the close proximity would require another consideration associated with the near-site extent of CO2 plume migration. If the sites are managed by the same operator, CO2 plume commingling among the sites is desirable because it promotes efficient use of the subsurface pore space. Otherwise, CO2 plume commingling could raise concerns regarding long-term legal liability among different storage operators in the event of potential leakage of commingling CO2 plumes.

Large prospective CO2 storage resource and high injectivity

The basin-wide target injection rates of commercial-scale CCS projects are large, sometimes in the range of hundreds of millions of metric tons of CO2 each year (i.e., hundreds of Mt/year)32–35. Therefore, the commercial-scale CCS projects require large prospective CO2 storage resource and high formation injectivity36,37. To accommodate the need for both, project operators could consider injecting CO2 into a stacked sequence of formations. Injection approaches distributed across stacked sequences are perceived to reduce the pressure buildup and interference among injection wells that may otherwise occur with injection into a single formation.

For instance, as part of the CarbonSAFE Initiatives, the Phase II of Integrated Midcontinent Stacked Carbon Storage Hub (IMSCS-HUB) project evaluates the potential of CO2 storage into a stacked sequence in the states of Kansas and Nebraska in the U.S38. One of its target storage hubs is the Patterson site in Kansas, U.S.39. This site is planned to target a vertically stacked sequence of three saline formations (in decreasing depth): Arbuckle (Cambrian-Ordovician), Viola (Ordovician), and Osage zones (Mississippian) that are vertically isolated by thick and tight carbonates and thin shale intervals serving as aquitards (Fig. 1).Figure 1 Generalized stratigraphic chart for Patterson site in southwest Kansas considered in IMSCS-HUB CarbonSAFE project modified from Holubnyak et al.39.

To evaluate the prospective CO2 storage resource in the Patterson site, the U.S. DOE methodology known as NETL CO2-SCREEN was used39,40. To consider injectivity and pressure limitation for storage, Leng et al. reported some valuable efforts based on analytical simulation tools41–43. Tables 1 and 2 summarize their estimates on the geologic properties and probabilistic prospective CO2 storage resource of the Patterson site, respectively. Table 2 shows that if the commercial-scale storage project only targets a single formation, only the Arbuckle formation seems to demonstrate sufficient prospective CO2 storage resource, regardless of the geological realization of variations in the CO2 storage efficiency44. In other words, CO2 injection into the stacked sequence of the three formations is necessary to maximize the potential use of pore spaces present in the Viola and Osage formation.Table 1 Estimated geologic properties in the Patterson site39.

Parameter	Unit	Arbuckle	Viola	Osage	
Area (mean)	km2	130	130	130	
Gross thickness (mean)	m	174	55	46	
Total porosity (mean)	%	7	7	12	
Pressure (mean)	MPa	11.7	11.5	11.4	
Temperature (mean)	°C	58	56	54	
Lithology	–	Dolomite	Dolomite	Limestone	
Storage efficiency—P10	%	8.5	9.5	11	
Storage efficiency—P50	%	14	16	19.5	
Storage efficiency—P90	%	21	23	29	

Table 2 Estimated prospective CO2 storage resource in the Patterson site39.

Prospective CO2 Storage Resource	Unit	Arbuckle	Viola	Osage	Sum	
P10	Mt	56	18	22	96	
P50	Mt	105	28	34	167	
P90	Mt	142	38	46	226	

Another potential of CO2 storage in a stacked sequence is demonstrated in another CarbonSAFE project called Nebraska Integrated Carbon Capture and Storage Pre-Feasibility Study in western Nebraska in the U.S.45. The project identified a vertically stacked sequence of three potential CO2 storage formations (in decreasing depth): Cherokee Group (Middle Pennsylvanian), Cedar Hills (Lower Permian), and Cloverly (Lower Cretaceous). However, this study does not report the estimated prospective CO2 storage resource confidently because of low data availability and absence of characterization wells. Nonetheless, both CarbonSAFE projects demonstrate that the presence of stacked sequence of saline formations provides an opportunity for project operators to accommodate the need for extensive prospective CO2 storage resource and high injectivity.

Comparison between CO2 storage in a stacked sequence and a single formation

While the IMSCS-HUB CarbonSAFE project performed an initial dynamic simulation of CO2 injection into a stacked sequence (i.e., Arbuckle, Viola, and Osage formation), the Nebraska Integrated Carbon Capture and Storage Pre-Feasibility Study CarbonSAFE project performed their injection simulation into a single formation (Cloverly formation) only, despite the identified availability of the stacked sequence (with Cedar Hills formation) in the project. Similarly, a previous study by Birkholzer et al.46 simulated a CO2 injection into a single formation only, although their model domain included a stacked sequence of saline formations with an assumption of the large model domain size to avoid boundary impact in the studies. Furthermore, Birkholzer et al.46 included one injection well only in the model,therefore, although they examined the extent of pressure buildup, the presence of multi-well pressure interference and the likelihood of CO2 plume commingling were not evaluated46. More importantly, while these previous studies included a stacked sequence of saline formations in their simulation model domain, a larger number of previous studies included a single target injection formation only in their simulation model domain16,47–49.

Consequently, there is currently a lack of systematic one-to-one comparative conceptual study between stacked-sequence and single-formation CO2 storage. This current state creates challenges in drawing instructive yet quantitative observations about the potential benefits of injecting into the stacked sequence over injecting into the single formation in accommodating the need for close proximity among storage sites, extensive subsurface prospective CO2 storage resource, and high formation injectivity.

This analysis systematically evaluates how the extents of pressure buildup and CO2 plumes evolve during injection and post-injection stages of a storage project in which commercial-scale multi-well CO2 injection operations located in close proximity occur simultaneously into a stacked sequence of saline formations. This analysis complements these previous studies by quantitatively investigating the benefits of injecting CO2 into a vertically stacked sequence of saline formations, over injecting the same amount of CO2 into a single saline formation. A one-to-one comparison between the stacked-sequence and single-formation storage is carried out to quantify these potential benefits in terms of management of pressure buildup and interference. Overall, this analysis also provides insights into required decision-making when considering multi-project deployment in a shared basin.

Methodology

Reservoir numerical modeling was carried out using the TOUGH3 software50, with the ECO2M equation-of-state module51. TOUGH3 can solve fluid and heat flows of multiphase, multicomponent fluid mixtures in porous and fractured media50. TOUGH3 solves coupled nonlinear mass and energy conservation equations that are closed via the equation of state. The ECO2M module is developed to simulate the injection of CO2 into saline aquifers and the resulting coupled processing of multiphase fluid flow, heat transfer, and chemical reactions (which include partitioning of water and CO2 between the phases and precipitation/dissolution of solid salt). Unlike its predecessor, the ECO2N module, the ECO2M module can describe conditions in which both liquid and gaseous CO2-rich phases are present so that it can describe all possible phase conditions for brine-CO2 mixtures, including the transition between super- and sub-critical conditions and the phase change between liquid and gaseous CO250.

Reservoir model description

3D rectangular-block generic reservoir models were constructed with a set of assumed reservoir properties shown in Table 3. The reservoir models include a stacked sequence of two saline formations as the injection targets and consist of the following individual hydraulic unit layers (in increasing depth): upper seal, upper injection formation, middle seal, lower injection formation, and lower seal, all of which are assumed to be homogeneous. The top depth of upper seal is 940 m (below the surface); therefore, the top depth of upper injection zone is 1000 m, which is a sufficient depth for CO2 to be stored in a supercritical state, based on the in-situ pressure and temperature assumed in this analysis. These reservoir properties are not based on data from specific basins; however, they lie within the range observed in the literature for appraised saline storage reservoirs52,53. All model boundaries are closed (no-flow). The pressure propagation above the upper seal and below the lower seal is not analyzed, and the models in this analysis are run in an isothermal mode after the vertical distribution of thermophysical properties is generated from preceding steady-state initialization runs.Table 3 Reservoir properties in models.

Parameter	Unit	Upper seal	Upper injection formation	Middle seal	Lower injection formation	Lower seal	
Porosity	%	5	10	5	10	5	
Horizontal permeability	mD	0.001	50	0.001	50	0.0001	
Permeability anisotropy (kh/kv)	–	3.3	3.3	3.3	3.3	3.3	
Thickness	m	60	200	60	200	20	
Average initial reservoir pressure	MPa	9.91	11.2	12.6	13.9	15.0	
Average initial temperature	°C	42.4	45.0	47.6	50.2	52.4	
Initial brine concentration	ppm	30,000	30,000	30,000	30,000	30,000	

Reservoir pressure and temperature conditions are selected to ensure that CO2 remains in the supercritical state in the injection zones54,55 because this state allows CO2 storage within a relatively small pore volume56. For illustration, at 0 °C and 1 atmospheric pressure (i.e., sub-critical gaseous state), one metric ton of CO2 occupies 509 m3,meanwhile, at supercritical conditions corresponding to a CO2 density of 700 kg/m3, the same mass of CO2 occupies 1.43 m3 or less than 6 m3 of rock with 30% porosity with 20% irreducible water saturation5. Therefore, in terms of formation depth, the injection formation typically exists at depths greater than 800 m18,57, depending on the regional in-situ fluid pressure and geothermal gradients proximal to candidate storage sites. While there is a great variation in the local geothermal gradients, the average temperature gradients in many sedimentary basins are approximately 25–30 °C/km. Meanwhile, the average pore pressure gradients of sedimentary rocks are generally close to the hydrostatic pressure gradient unless it is under- or over-pressure conditions, that is the pressure generated by a column of water of equal height to the depth of the pore space5.

Modeling cases

Table 4 lists the modeling cases in this analysis. We begin our analysis by modeling single-site cases (Cases 1 and 2) followed by multi-site cases (Cases 3 through 5), as illustrated by the model segmentation schematics in Fig. 2. Case 1 represents the baseline case, which injects CO2 from a single well into a single formation. Although there are two injection wells in Case 2, both wells are located in the same storage site; therefore, Case 2 is categorized as “single-site” but in stacked upper and lower formations. The analysis on Case 1 establishes the baseline for the extent of pressure buildup and CO2 plume migration when there is no pressure interference among different storage sites or injection formations. Because both cases only model a single storage site, the model extent for both cases only include a quarter of a five-spot pattern in this homogenous model (Fig. 3).Table 4 Modeling cases.

Case	Case group	Model segmentation	Number of injection wells in model domain	Number of target injection formations	Target injection formation	Multi-site pressure interference	Model aerial extent (km × km)	
1	Single-site	Quarter five-spot	1	1 (Lower)	Single	No	500 × 500	
2	Single-site	Quarter five-spot	2	2 (Lower and Upper)	Stacked	No	500 × 500	
3	Multi-site	None (full field)	4	1 (Lower)	Single	Yes	1000 × 1000	
4	Multi-site	None (full field)	4	2 (Lower & Upper)	Stacked	Yes	1000 × 1000	
5	Multi-site	None (full field)	8	2 (Lower & Upper)	Stacked	Yes	1000 × 1000	

Figure 2 Modeling domain selected in this analysis (right) extracted from the multi-layered subsurface system (left).

Figure 3 3-D schematics of quarter five spot model segment (right) extracted from the full field model (left). Figure is not drawn based on any specific scale.

On the other hand, Cases 3 through 5 mimic the commercial-scale CO2 storage projects, in which the commercial-scale project unitization area consists of four storage sites to accommodate the target injection rates. The center of the model domain hosts the four storage sites that are placed on a five-spot pattern with a 5-km site spacing (Fig. 4), without any well or site at the center of the five-spot pattern. Cases 3 and 4 are identical from the aerial view; however, in Case 4, two of the sites inject CO2 into the lower injection zone rather than into the upper injection zone.Figure 4 3-D schematics of modeling cases: Cases 1 through 5 in (a), (b), (c), (d), and (e), respectively, with cross sections (N-N’ and S-S’) for the multi-site cases. Figure is not scaled.

Each storage site may consist of one or two wells, depending on the number of target injection zones in each storage site (Fig. 4). Each injection well is assumed to be completed in a single injection zone only. When a particular storage site targets a single formation, this storage site hosts one injection well only with an injection rate of 1 Mt/year (before model segmentation). On the other hand, when a particular storage site targets a stacked sequence of two formations, this storage site hosts two injection wells (spaced only a few meters apart on the ground surface), each of which injects 0.5 Mt/year of CO2 (before model segmentation) into each respective target formation. Therefore, a storage site in this analysis is defined as a localized surface scope consisting of injection well(s) within a relatively narrow distance (i.e., a few meters only). As a result, in Cases 3 through 5, the total injection rate within the unitization area is 4 Mt/year of CO2. All injection wells are perforated throughout the entire thickness of each designated target formation.

In all modeling cases, CO2 is injected continuously (and concurrently when there are a few storage sites or wells) for 30 years. The injection constraint is constant CO2 injection rate. In addition, brine production was not evaluated as part of this work. Afterwards, the injection stops and is followed by 50 years of post-injection site care (PISC) stage (i.e., UIC Class VI well default). It is important to note that Fig. 4 is created as a schematic only, so that the dimensions shown are not based on a specific scale. Table 4 summarizes the correct model extent dimensions (i.e., aerial extent) in each case. The model mesh is laterally refined around the injection well to model the plume-scale processes and gradually coarser towards the model lateral boundaries. Given the large size of the reservoir model, this analysis leverages the parallel processing feature within TOUGH3 and runs all cases on NETL supercomputer Joule 2.0 to allow large memory requirements and higher-speed computation58.

By comparing the results from these modeling cases, this analysis aims to quantify the pressure buildup and CO2 plume extent and how the pressure buildup magnitude under the fracture pressure thresholds/constraints. A quantitative comparison among these cases allows a systematic analysis of the potential benefits of injecting CO2 into a vertically stacked sequence of saline formations, over injecting the same amount of CO2 into a single saline formation in addressing the challenges associated with the proximity among projects and the need for high injectivity.

Results and analysis

In this section, the evolution of CO2 plume and pressure buildup of the five modeling cases as shown in Table 4 is covered consecutively. In both sections of CO2 plume and pressure buildup, Cases 1 and 2 are discussed first to establish the baseline on the extents of CO2 plume and pressure buildup when there is only one storage site in the model. Afterwards, the analysis will be followed by results from Cases 3 through 5 to provide insights into the effects of multi-site multi-well injection.

CO2 plume extent

The results shown for the single-site cases modeled, the radius of CO2 plume by the end of 30-year injection (Fig. 5) for Cases 1 and 2 is approximately 1.82 km and 1.5 km, respectively. Axis ticks in Fig. 5 are in unit of meters. Views in Fig. 5 show areas near the injection well only, rather than the entire model extent. As shown in Fig. 5, the CO2 plume demonstrates a gravity-override shape due to the buoyancy effect. Near the injection well, CO2 saturation is at its highest, while further away from the injection well, CO2 saturation tends to be lower toward the top of the storage formation.Figure 5 Side profile views of CO2 plumes (CO2 saturation range between 0 and 1) at the end of injection stage in single-site cases: (a) Case 1, (b) Case 2, and (c) the difference in CO2 saturation (CO2 saturation range between − 1 and 1) between two cases. The results show that the CO2 plume extent in upper formation in stacked Case 2 is less than in the Case 1.

Comparison between Fig. 5a,b shows that reducing the “per-well” injection rate from 1 Mt/yr in Case 1 to 0.5 Mt/yr in Case 2 (i.e., 50% reduction) does not proportionally decrease the radius of CO2 plume, since the radius only decreases from approximately 2 km in Case 1 to 1.5 km in Case 2 (i.e., 25% CO2 plume radius reduction).

For better visualization, Fig. 5c shows the difference in CO2 saturation between each grid block in Case 1 and Case 2 (i.e., CO2 saturation in Case 1 subtracted from that in Case 2).

CO2 plume radius continues to increase after the end of injection due to the density contrast between CO2 and in-situ brine. CO2 tends to migrate from the previously occupied pores upwards in the storage formation and leaves these previously occupied lower zones with residual CO2 saturation, which represents the portion of CO2 storage volume trapped through the residual trapping mechanism. As shown in Fig. 6, the radius of CO2 plume by the end of 50-year PISC is approximately 2.75 and 2.25 km in Cases 1 and 2, respectively. The increasing radius of CO2 plume during PISC further highlights the importance of careful monitoring and modeling of site-specific storage projects.Figure 6 Side profile views of CO2 plumes (CO2 saturation range between 0 and 1) at the end of PISC stage in single-site cases: (a) Case 1, (b) Case 2, and (c) the difference (CO2 saturation range between − 1 and 1) in CO2 saturation between those cases. The results show that the CO2 plume extent in upper formation in stacked Case 2 is less than in the Case 1.

Multi-site cases demonstrate a site spacing of 5 km in Cases 3, 4, and 5. Figures 7 and 8 show the extent of CO2 plume for multi-site cases by the end of injection and PISC, respectively in top view. Figure 7 illustrates that by the end of 30-year injection, none of the multi-site cases indicates any CO2 plume commingling among the different storage sites. However, the radius of the CO2 plume continues to increase during PISC as shown the result of which appears to cause CO2 plume commingling after 50-year PISC in Cases 3 (Fig. 8a) and 4 (Fig. 8b). In case of potential CO2 leakage, legal challenges could exist associated with CO2 accounting and liability among these projects in carrying out work to remediate the leakage. In this analysis, PISC is assumed to be completed 50 years after the injection stops. It is likely that the CO2 plume continues to slightly increase beyond the modeled timeframe. Therefore, the 5-km site spacing used in this analysis is intended for case-demonstration purposes only, rather than proposing a universal optimum site spacing. The optimum site spacing should also be examined on a site-by-site basis from other standpoints, including storage zone thickness, porosity, injectivity, and maximum pressure buildup allowable per the EPA regulations, among many other considerations.Figure 7 CO2 plumes at the end of injection stage in multi-site cases: (a) Case 3, (b) Case 4, and (c) Case 5.

Figure 8 CO2 plumes at the end of PISC stage in multi-site cases: (a) Case 3, (b) Case 4, and (c) Case 5.

Pressure buildup extent

The results show that the radius of pressure buildup front is in the range of tens of kilometers, depending on the pressure buildup magnitude defining the front while the radius of CO2 plume extends a mere 2.5 km or less. In this analysis, pressure buildup is calculated by subtracting the initial pressure at any grid block of interest from the pressure at that grid block at a certain time of interest as given by Eq. (1). Figure 9 presents a side profile view of contour lines showing the pressure buildup fronts of different pressure buildup magnitudes at the end of 30-year injection in the single-site cases. Axis ticks in Fig. 9 are in the unit of meters from wellbore. Figure 9 shows that in Case 1, the maximum radii of 20-psi and 160-psi pressure buildup are approximately 52 km and 4 km, respectively, while in Case 2, they are approximately 45 and 1 km, respectively. 20 psi is relatively small pressure buildup and almost arbitrarily selected in this analysis to trace the pressure-affected area. Such profiles are for a few pressure buildup magnitudes (i.e., 20, 40, 80, and 160 psi) for illustrative purposes only. Site-specific projects may be interested in other pressure buildup magnitudes, which can be higher than 20 psi.Figure 9 Side profile view of pressure buildup away from the injection well (x=y=0) at the end of injection stage in single-site cases: Case 1 (solid lines) and Case 2 (dashed lines).

Case 2 results in a consistently smaller radius of pressure buildup than Case 1, although both inject the same total volume of CO2. The reduction in the radius is more significant for smaller pressure buildup magnitudes. For example, for 20-psi and 160-psi pressure buildup, the reduction in the radius is approximately 8 km and 3 km, respectively. While from the lateral standpoint, distributing CO2 injection volume across the stacked sequence (Case 2) is shown to reduce the maximum pressure buildup radius, it consequently induces pressure buildup in the lower injection formation, which would have been minimum otherwise (i.e., if injection solely targets the upper injection zone as is modeled in Case 1). Figure 9 shows that in Case 1, pressure buildup propagates vertically across the low-permeability middle seal layer, although CO2 is permanently trapped in the upper injection formation. However, in Case 1, the vertical pressure propagation is minimum (i.e., even the 20-psi pressure buildup contour has not reached the bottom of the lower injection zone). Therefore, there is an exchange in terms of benefits offered between Cases 1 and 2 configurations; although both cases achieve the same injection volume, Case 1 prioritizes more on the preservation of the initial reservoir pressure of the lower injection zone for future or subsequent storage projects that target the lower injection zone, while Case 2 minimizes the magnitude of pressure buildup and interference among nearby storage sites sharing the same injection zones. Lastly, it is worth noting that the model domain in this analysis consists of layers shown in Fig. 9 only with all boundaries closed. It is expected that if the model domain includes additional layers above the upper seal and below the lower seal, the maximum pressure buildup radius in cases modeled in this analysis would decrease. The effect of model boundary condition was not evaluated as a part of this analysis.

The following discussion analyzes the range of ratios of pressure buildup and CO2 plume radius related to the estimation of pressure-affected area size. The radius ratio is given by:4 αΔP,t=rΔPΔP,trCO2t

where αΔP,t is the ratio of the pressure buildup front radius of magnitude ΔP psi from the injection well to the CO2 plume radius at time t, rΔPΔP,t is the radius (km) of ΔP-psi pressure buildup at the instant t considered, and rCO2t is the radius (km) of CO2 plume at the instant t considered. It can also be called CO2-to-pressure-buildup multiplier. By the end of injection, this multiplier can be a useful parameter because it can help provide storage operators with a quick method to obtain a first order estimate of the pressure-affected area size delineated by pressure buildup given a CO2 plume area estimated from monitoring techniques. The pressure-affected area size influences CO2 storage costs because it includes costs associated with the number of monitoring wells that need to be deployed for a given commercial-scale project unitization area and the area of land in which operators need to carry out subsurface characterizations. Therefore, this multiplier could be a convenient parameter to help estimate the storage costs early in the project life before the pressure buildup has even reached its anticipated maximum radius throughout the project lifetime.

Figures 10 and 11 show the pressure buildup radius of varying magnitudes (i.e., 20, 50, and 100 psi) of the same modeling cases. Figure 10 presents a comparison in the aerial extent of 20-psi pressure buildup and CO2 fronts between Cases 1 and 2. The injection site center is located at the center of the diagrams. The radius labels are in the unit of kilometers. 20 psi is relatively small pressure buildup, which can be lower than the magnitude that site-specific projects are interested in. Therefore, 20-psi pressure buildup is discussed for illustration purposes only. The pressure buildup is taken at the depth of interface between the upper seal and upper injection zone. As shown in Fig. 10a, by the end of 30-year injection, the multiplier for 20-psi pressure buildup is approximately 25 and 22 for Cases 1 and 2, respectively.Figure 10 Map of 20-psi pressure buildup fronts and CO2 fronts in Cases 1 and 2 at (a) end of injection and (b) end of PISC stage. Radius labels are distances from the injection well.

Figure 11 Map of pressure buildup fronts and CO2 fronts in Cases 1 and 2 at end of injection for (a) 50-psi; (b) 100-psi pressure buildup. Radius labels are distances from the injection well.

As shown in Fig. 10b, by the end of 50-year PISC, most of the lingering pressure buildup is less than 20 psi since the 20-psi contours disappear. Figure 11 presents a comparison in the aerial extent of 50-psi and 100-psi pressure buildup and CO2 fronts between Cases 1 and 2 at the end of injection. These larger pressure buildup magnitudes no longer exist by the end of PISC due to pressure equilibration, hence no figures shown for end-of-PISC time slice for them.

Given reservoir and injection parameters, it is reasonable to obtain the large multipliers, particularly since 20 psi is a relatively low-pressure buildup magnitude. However, this multiplier will decrease as soon as the injection stops. As shown in Fig. 16b, the multiplier for 20-psi pressure buildup by the end of PISC decreases to approximately 1 for Cases 1 and 2 (i.e., similar radius between CO2 plume and 20-psi pressure buildup). This suggests that the benefit offered by Case 2 configuration (i.e., distributing the same CO2 injection volume into two injection zones) is time-dependent and primarily observed during the injection stage only.

Figure 11 shows that larger pressure buildup magnitudes correspond to a smaller CO2-to-pressure radius multiplier. As shown in Fig. 11a, the multiplier for 50-psi pressure buildup is approximately 12.5 and 7.5 for Cases 1 and 2, respectively. Likewise, as shown in Fig. 11b, the multiplier for 100-psi pressure buildup is approximately 5 and 1.5 for Cases 1 and 2, respectively. Figure 12 summarizes the multipliers at the end of injection for Cases 1 and 2. Figure 12 demonstrates that although larger pressure buildup consistently corresponds to a smaller multiplier, there does not seem to be a linear relationship in the multipliers for different pressure buildup magnitudes, which underscores that the multipliers depend on multiple interplaying factors, including the injection zone configurations (i.e., Case 1 compared to Case 2).Figure 12 Maximum multipliers for CO2 plume to pressure buildup front radius at the end of injection for Cases 1 and 2.

In the case of multiple storage sites (i.e., Cases 3 through 5), the radius of pressure buildup will increase correspondingly, since these cases assume a commercial-scale target CO2 storage volume (Table 4). Because the site spacing is 5 km only (Fig. 4), pressure interference is expected to occur rapidly among storage sites in the injection life and potentially increase the radius of commingled pressure buildup.

Figures 13, 14, and 15 show the pressure buildup radius of varying magnitudes (i.e., 20, 50, and 100 psi) of the same modeling cases. Figure 13 presents a comparison in the aerial extent of 20-psi pressure buildup and CO2 fronts among the multi-site cases (i.e., Cases 3 through 5). The radius label range shown has increased from 60 km in the single-site cases (Fig. 10) to 120 km in the multi-site cases (Fig. 13) to capture the full extent of the fronts of interest in the multi-site cases. Figure 13a shows that by the end of 30-year injection, Case 3 results in the largest pressure buildup radius, because it targets a single injection formation only. In addition, Cases 4 and 5 are shown to have smaller pressure buildup radius than Case 3 but both cases have identical maximum pressure buildup radius, despite Case 5 having twice the number of injection wells as Case 4. This suggests that targeting the stacked sequence (i.e., Cases 4 and 5) rather than a single formation (i.e., Case 3) decreases the pressure buildup radius. However, deploying two wells rather than a single well at each storage site (i.e., Case 5 vs. 4) does not influence the pressure buildup radius. This means that the additional costs for constructing and operating the second injection well at each storage site might not be largely compensated because there seems to be no remarkable reduction in the pressure-affected area size from drilling the additional well. By the end of PISC (Fig. 13b), 20-psi pressure buildup is shown to propagate deeper into the formation due to the pressure equilibration but at a diminishing speed.Figure 13 Map of 20-psi pressure buildup fronts and CO2 fronts in Cases 3 through 5 at (a) end of injection; (b) end of PISC stage. Radius labels are distances from the center.

Figure 14 Map of 50-psi pressure buildup fronts and CO2 fronts in Cases 3 through 5 at (a) end of injection; (b) end of PISC stage. Radius labels are distances from the center.

Figure 15 Map of 100-psi pressure buildup fronts and CO2 fronts in Cases 3 through 5 at end of injection. Radius labels are distances from the center.

The benefits of distributing CO2 injection volume into the stacked sequence for decreasing the pressure buildup radius are consistently observed in other pressure buildup magnitudes as well. Figures 14 and 15 present the comparison for 50-psi and 100-psi pressure buildup for these multi-site cases, respectively. In both figures, injecting into the stacked sequence (i.e., Cases 4 and 5) results in a smaller pressure buildup radius than injecting into a single formation (i.e., Case 3).

Besides the top views from Figs. 13, 14, and 15, cross-sectional comprehensive outlook of the spatiotemporal variability of pressure buildup and CO2 plume is presented in Figs. 16 and 17. In both figures, the distance is measured along the monitoring points illustrated in the 3-D schematics, depending on the model segmentation. The monitoring points are located at the depth of interface between the upper seal and the upper injection zone. The distance is presented in a logarithmic scale to show near-site and far-field monitoring data. The observations from both figures are in agreement with each other with what is shown in Figs. 13, 14, and 15 in top view.Figure 16 Evolution of pressure buildup along the monitoring points (X’s) on the line in the 3-D schematics during injection and PISC for all modeling cases: Cases 1 through 5 from (a) to (e), respectively. Distance is measured from point illustrated by white arrows in the 3-D schematics on the top-left corner: D-D’ for single-site cases and C-C’ for multi-site cases.

Figure 17 Evolution of CO2 saturation along the monitoring points (X’s) on the line in the 3-D schematics during injection and PISC for all modeling cases: Cases 1 through 5, respectively. Distance is measured from point illustrated by white arrows in the 3-D schematics: D-D’ for single-site cases and C-C’ for multi-site cases.

Fracture pressure threshold

Since distributing the injection volume across the stacked sequence is shown to decrease the radius of pressure buildup, it results in milder pressure interference among different storage sites. This could be a significant advantage of injecting into the stacked sequence in terms of avoiding the fracture pressure thresholds (γ) based on the EPA Class VI regulations as given by Eq. (2), which aims to mediate any potential large-scale pressure buildup to maintain the caprock integrity and prevent USDW contamination.

Figure 18 shows the evolution of pressure buildup at the top of perforation of “Injector #1” (Fig. 4) in all cases modeled in this analysis. Since this analysis does not replicate any specific site, a range of fracture pressure gradients (∇Pf) is presented to provide insights into the likelihood of these modeled cases in approaching the fracture pressure thresholds for fracture gradients of 0.6, 0.7, and 0.8 psi/ft. In Fig. 18, Case 1 is treated as the baseline case, from which pressure escalation and/or management can be observed.Figure 18 Pressure buildup (ΔP) at the top of perforation at Injector #1 with varying fracture pressure thresholds in (a) Case 2, (b) Case 3, (c), Case 5 and (d) Case 5, respectively, with Case 1 considered as baseline. (a) Pressure buildup: Case 2 vs. Case 1 with various thresholds. (b) Pressure buildup: Case 3 vs. Case 1 with various thresholds. (c) Pressure buildup: Case 4 vs. Case 1 with various thresholds. (d) Pressure buildup: Case 5 vs. Case 1 with various thresholds.

Among the commercial-scale cases modeled (i.e., Cases 3 through 5), Case 5 consistently shows the lowest pressure buildup at the injection well throughout the project duration. This shows that distributing CO2 injection volumes across the stacked sequence and having separate wells at each storage site (with each well injecting CO2 into different designated target formations in the stack), seems to be a favorable injection configuration for commercial-scale CO2 storage projects in terms of several considerations. For example, this configuration (Case 5) results in a smaller pressure buildup radius (and hence smaller pressure-affected area size) than injecting into a single formation (Case 3), while still achieving the same target injection volume. In fact, Fig. 18d demonstrates that Case 5 is shown to result in similar pressure buildup at the injection well as Case 1, although the total injected mass in Case 5 is four times larger than the mass in Case 1.

Comparison between Fig. 18c,d demonstrates that although Cases 4 and 5 result in a similar pressure-affected area size (Fig. 14), the pressure interference among nearby storage sites is managed more effectively in Case 5 by having two injection wells at each storage site. This could suggest that the additional costs of the drilling and operating the adjacent injection well in Case 5 could be compensated by the reduction in pressure buildup magnitude, which is a significant advantage in terms of avoiding the fracture pressure thresholds. This would allow operators to sustain the target CO2 injection rate for the project lifetime with fewer concerns of having to cut down the injection rate early in the injection stage to avoid the fracture pressure thresholds.

Figure 19 shows the pressure interference (ϵi-j) at the top of perforation at Injector #1 with variable baseline cases. As defined in Eq. (3), pressure buildup escalation (i.e., ϵi-j>0) represents the resulting pressure interference in which the pressure buildup in Case i at the given location and time considered is higher than the pressure buildup in Case j at the corresponding location and time. On the other hand, negative pressure interference using this equation represents the pressure management extent (in psi) of deploying Case i as opposed to Case j. Figure 19 demonstrates that pressure interference shows non-linear time-dependent behavior, especially during the early-time injection. Pressure interference is shown to depend on the selection of the baseline case. Since the primary interest of this analysis is to provide a one-to-one comparison in pressure buildup between stacked-sequence injection and single-formation injection, Case 1 is most frequently treated as the baseline case in Fig. 19. However, whenever potentially relevant, pressure interference calculation using other baseline cases (i.e., Cases 3 and 4) is also presented.Figure 19 Pressure interference (ϵ) at the top of perforation at Injector #1 in (a) Case 2, (b) Case 3, (c) Case 4, and (d) Case 5, respectively, with varying baseline cases. (a) Case 2 versus Case 1. (b) Case 3 versus Case 1. (c) Case 4 versus Cases 1 and 3. (d) Case 5 versus Cases 1, 3, and 4.

Figure 19 shows that stacked-sequence injection is an effective treatment for commercial-scale CO2 storage with narrowly spaced injection sites. When looking at single-site cases, there is approximately 200-psi reduction in pressure buildup throughout the injection stage with staked-sequence injection in single-site cases (i.e., Cases 2 vs. 1) (Fig. 19a); this translates to approximately 40% reduction in the pressure buildup in single-site cases. When looking at the commercial-scale cases, there is approximately 320-psi reduction in pressure buildup throughout the injection stage with stacked-sequence injection in multi-site cases (i.e., Cases 5 vs. 3) (Fig. 19d); this amounts to 42% reduction in the pressure buildup in commercial-scale cases. In all cases, as soon as the injection operation is complete, the pressure reduction benefit quickly diminishes. The pressure interference at the end of PISC is minimum because of pressure equilibration in the formations. However, this analysis evaluates a very specific geologic and injection situation; therefore, this analysis bears further investigation into other situations or specific basins. Future work also needs to combine the technical results on the subsurface dynamics of multi-site injection at each storage site with the economic implications of drilling the additional wells at each storage site.

Discussions

Based on the results and analysis stated above, several points are worth further discussion:

For single injection site with the same amount of the injection such as 1 Mt/yr in Cases 1 and 2, the perforations in only one formation (upper in Case 1) and in both formations (upper and lower in Case 2) show the different CO2 plume extent and pressure movement. Such evidence adds the value for commercial-scale CO2 storage explorations based on the stacked formations. Besides, the results indicate the difference needs of monitoring and risk assessment for stacked storage as shown in the CO2 plume extent regarding to the area of review. The case with perforations in both formation (Case 2) is smaller than the one in upper the formation (Case 1). The similar observations for pressure buildup also illustrate the agreement even though the radius of the Case 2 is less than Case 1 as shown in Fig. 9. Moreover, based on the radius ratio definition, it demonstrates that there seems to be no linear relationship in the multipliers for different pressure buildup magnitude as shown in Fig. 12. More sensitivity analysis with heterogeneity in the following studies will provide solid validation and certain correlations between injection rate and plume extent size for both end of injection and PISC stages due to fluid dynamics in the system.

Multi-site cases are complex especially the control of operations in the case studies. With additional wells and amount of CO2 injection for Cases 3 to 5, the plume extent and pressure buildup are analyzed in detail as shows in Figs. 7, 8, 9, 10, 11, 12, 13, 14, 15, 16, and 17. Within the same amount of the injection target from each well, CO2 plume extent after 30 years injection shows no interference but after PISC, cases 4 and 5 are connected. It means that for multi-site injection, the designs, perforations, and well placements play curial role of reservoir response, even after 30 years of injection and the period for PISC. Though pressure buildup is less than 20 psi after PISC, the plume for both sites still show overlap as shown in Figs. 7, 8, 9, 10, 11, 12, 13, 14, and 15.

Further analysis of the pressure buildups and comparisons demonstrate that the stacked multi-site storage can reduce over 40% of the pressure buildup from the baseline in Case 1 as presented in Figs. 18 and 19. This adds a lot of value for the pressure management and de-risked CO2 storage monitoring and assessment to ensure permeant retention, especially for the large-scale deployment. Moreover, because of the CO2 plume extent and pressure buildup reduction, monitoring requirement and area of review (AOR) are reduced as well, which result in significant cost savings for carbon storage. Furthermore, associated monitoring, reporting and verification (MRV) plan and design are benefited from such reduced footprint impacts. Ultimately, it friendly promotes ecosystem and environmental regulations. Again, sensitivity analysis with heterogeneity, mid-seal zone, boundary condition tuning, and uplift risk in formations are parts of the following studies which will offer systematical optimization design for multi-site CO2 storage and reservoir managements in such large scale in the future work.

Conclusions

Commercial scale decarbonization through CCS may likely involve many CO2 storage projects located in close proximity, which could raise concerns over caprock integrity due to potential large-scale pressure buildup in storage formations. This analysis investigates the benefits of injecting CO2 into a stacked sequence of saline formations in alleviating those concerns and accommodating the need for large prospective CO2 storage resource and high injectivity for the deployment of CCS at the commercial scale. This analysis employs numerical reservoir simulation to perform a systematic one-to-one comparison between injecting into the stacked sequence and into a single formation. A quantitative discussion on the effect of various injection configurations on the extent of CO2 plume and pressure buildup is presented. A range of fracture pressure gradients is analyzed with its regards in making sure that the pressure buildup at the injection well remains below the fracture pressure thresholds per EPA Class VI well regulations.

This analysis demonstrates that injecting CO2 into the stacked sequence offers significant benefits in terms of basin pressure management. This injection configuration results in both smaller overall pressure buildup magnitudes and smaller footprint of the pressure-affected area than injecting into a single formation, despite both configurations achieving the same CO2 storage volume. Deploying separate wells at each storage site with each well targeting different formations is shown to offer a significant additional reduction in pressure buildup magnitude to avoid the fracture pressure thresholds. Collectively, this configuration can offer approximately 40% and 42% reduction in the pressure buildup for single-site and multi-site cases, respectively by comparison of Cases 4 and 5 to baseline Case 1.

This analysis provides insights into the required decision-making when considering multi-project deployment in a shared basin. Because this analysis evaluates a very specific geologic situation, well configuration, and CO2 injection rate, this exploratory analysis bears further investigations across other geologic situations.

Acknowledgements

This study was completed as part of NETL research focus for the U.S. DOE’s Office of Fossil Energy and Carbon Management. The authors would like to thank NETL support contractors Hannah Hoffman and Katie Forrest for editorial review and comments.

Disclaimer

This project was funded by the U.S. Department of Energy, National Energy Technology Laboratory an agency of the United States Government, in part, through a support contract. Neither the United States Government nor any agency thereof, nor any of its employees, nor the support contractor, nor any of their employees, makes any warranty, expressor implied, or assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of any information, apparatus, product, or process disclosed, or represents that its use would not infringe privately owned rights. Reference herein to any specific commercial product, process, or service by trade name, trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, recommendation, or favoring by the United States Government or any agency thereof. The views and opinions of authors expressed herein do not necessarily state or reflect those of the United States Government or any agency thereof.

Author contributions

N.W.: Conceptualization, Methodology, Formal analysis, Visualization, Investigation, Programming, Data curation, Resources, Writing—Original draft, Writing—Review and editing. D.M.: Conceptualization, Methodology, Formal analysis, Writing—Review and editing, Project administration, Funding acquisition. D.V.: Conceptualization, Formal analysis, Writing—Review and editing, Project administration, Supervision. T.G.: Conceptualization, Formal analysis, Writing—Review and editing, Project administration, Funding acquisition. L.C.: Conceptualization, Formal analysis, Writing—Review and editing, Project administration, Funding acquisition, Supervision. G.L.: review and editing, corresponding the manuscript and publishing.

Data availability

The datasets used and/or analyzed during the current study available from the corresponding author on reasonable request.

Competing interests

The authors declare no competing interests.

The original online version of this Article was revised: Luciane Cunha was omitted from the author list in the original version of this Article. The Author Contributions section now reads: “N.W.: Conceptualization, Methodology, Formal analysis, Visualization, Investigation, Programming, Data curation, Resources, Writing—Original draft, Writing—Review and editing. D.M.: Conceptualization, Methodology, Formal analysis, Writing—Review and editing, Project administration, Funding acquisition. D.V.: Conceptualization, Formal analysis, Writing—Review and editing, Project administration, Supervision. T.G.: Conceptualization, Formal analysis, Writing—Review and editing, Project administration, Funding acquisition. L.C.: Conceptualization, Formal analysis, Writing—Review and editing, Project administration, Funding acquisition, Supervision. G.L.: review and editing, corresponding the manuscript and publishing.”

Publisher's note

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Change history

9/24/2024

A Correction to this paper has been published: 10.1038/s41598-024-73100-9
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