Pressure Space: The Key Subsurface Commodity for CCS

At least 50 CO2 storage projects are now in development on the US Gulf of Mexico basin. Via press releases and company websites, they claim more than 7Gt of storage capacity and plan to inject over 300Mtpa, much of it into coastal Oligo-Miocene reservoirs. Many of these announced storage projects appear to plan on filling their pore space with CO2, right up to the lease boundaries. Current CCS practices place considerable attention on the CO2 plume and the pore space occupied by it. Permitting requires defining the expected ultimate extent of the CO2 plume and monitoring its growth over time. Leasing is commonly based on the pore volume to be occupied by CO2 and storage capacity is often calculated as a function of pore volume and expected saturation (“static capacity”). However, injection of CO2 requires displacing native reservoir brines, which generally raises reservoir pressure. The magnitude and area of pressure increase depends on the interplay of injection rate with reservoir thickness, permeability and boundary conditions, but the area of elevated pressure often far exceeds that of the CO2 plume. Elevated pressure can both reduce injectivity and drive the flow of reservoir brines, which may be more hazardous to ground water quality than the CO2 itself. The former poses a commercial risk to the operator. The latter poses an environmental risk to freshwater aquifers and human health, as the displaced brines may contain high salinity, trace hydrocarbons and/or heavy metals. In short, the impact of a given storage project often extends well beyond the footprint of the CO2 plume, raising new questions about injection performance predictions, project spacing and ultimately, total injection capacity. The goal of this work is to address those questions. We begin with the concept of Area of Review (AoR), the area of elevated reservoir pressure related to injection. As defined by the US Underground Injection Control program, the AoR is defined as the area around an injection well where pressure elevation is sufficient to lift injection zone brines up to the lowest freshwater aquifer, given an open wellbore. The magnitude of this pressure threshold depends on the relative densities and depths of the injection zone and the base of freshwater, but it tends to be small, on the order of 1MPa (145psi). Within the AoR, US law requires a storage developer to identify, review and remediate all legacy penetrations of the injection zone, as needed to ensure their integrity under the anticipated pressure increase. The cost of remediation favors minimizing the AoR and tends to push injection projects away from large concentrations of old wells, including depleted fields. We identify a number of strategies for an operator to minimize their AoR, including deep injection and use of multiple, stacked injection zones. However, we also note that the addition of another injection project in the same reservoir can create a larger AoR than either project would have alone. Responsibility for the extra area and the wells within it is an open question, but it suggests that predictive models need to consider not one, but all injection projects in a given zone. Next, we consider the question of storage capacity. Common practice assumes that most storage sites have open boundaries, i.e., that there is effectively no limit to brine displacement and that any pressure buildup is transitory. With a handful of well-documented exceptions, that has historically been a reasonable assumption. Isolated projects in high quality reservoirs (e.g., Sleipner) have indeed behaved as open. However, the generation of Gulf Coast projects now in development includes dense clusters of projects and injection rates that are several times that of Sleipner. Even with open geologic boundaries, these projects are likely to create pressure barriers for each other. Like pattern injectors in a producing field, they cannot all displace their brines into each other’s acreage. Without brine production (and safe, economic disposal), closely spaced projects may struggle to achieve capacity predictions that were based on the assumption of open boundaries. Last, we consider the basin scale, where storage resource assessments commonly run to 100s, even 1000s of gigatons. However, basin-scale storage capacity is ultimately a sum of the possible individual projects, and again, the potential for brine displacement is limited. Faults and pinch-outs create lateral edges for porous zones within basins, and basins themselves have lateral edges where porous and permeable sediments meet basement. Volumes useable for accepting displaced brine are also limited by laws safeguarding laterally equivalent freshwater aquifers, marine and surface environments and downward displacement is limited by basement or geologic overpressure. Geologic properties may vary with depth and geography, but ultimately, basins are effectively closed volumes. Using the example of the Texas coastal Miocene reservoirs, we compare historic static capacity assessment with a newly developed pressure-based assessment. Where the former found 125Gt in available storage resources, we find ~20Gt—still a lot, but the reduction suggests a different view of storage resource value and perhaps a different view of project spacing and therefore pipeline routing. Based on this work, we define a new concept, Pressure Space—the mathematical product of accessible pore volume and allowable pressure increase. It has the units of energy, and we suggest that this, not pore space, is the critical subsurface commodity for storage. Consideration of the pressure space required for a given injection plan suggests larger leases, greater project spacing and perhaps a different land valuation. Most importantly, it suggests that accurate injection performance prediction and effective regulation both require consideration of all projects injecting into a given zone. Irrespective of who contributed what, elevated injection zone pressure affects injectivity and safety for all.