Conference Dates

April 10-14, 2016


Deployment barriers for CO2 capture, utilization, and storage (CCUS) in saline reservoirs can be grouped under three categories: (1) net cost (after accounting for utilization benefits); (2) water intensity of CO2 capture, and (3) uncertainty about storage capacity and permanence. The third category is often considered to be the most challenging. Overpressure, which is fluid pressure that exceeds the original reservoir pressure due to CO2 injection, is the limiting metric for storage capacity and permanence because it drives key physical risks: induced seismicity, caprock fracture, and CO2 leakage. Variables that control overpressure include: (1) the quantity of CO2 and the rate at which it is injected, (2) the size of the reservoir storage compartment, and (3) reservoir permeability. Geologic surveys, geologic logs, and core data from exploration wells provide information that can be used to estimate the size and permeability of the reservoir compartment, but large uncertainties will only be narrowed after there is operational experience with moving large quantities of fluid to move into and/or out of the reservoir. Unlike CCUS applied to CO2 Enhanced Oil Recovery (CO2-EOR) in mature oil fields, CCUS in a saline reservoir will typically (a) have less geologic information and little or no production and injection history to estimate how much CO2 can be safely and permanently stored and (b) not have the advantage of depleted reservoir pressure prior to CO2 injection.

Numerous studies have evaluated strategies for managing CO2 storage reservoirs by producing brine to reduce the pressure buildup due to CO2 injection. Most of these studies assume that separate injection and production wells will be used and that brine production will begin during or after the CO2 injection phase. We present a strategy where brine production begins prior to the CO2 injection phase, using the wells that will subsequently be used for CO2 injection. In this strategy, all wells are initially used for exploration and monitoring and then to produce brine prior to injecting CO2. Our strategy also includes the option of using reservoirs in tandem, including:

  1. CO2-storage reservoirs: due to their high seal integrity, these are preferred for CO2 storage. Brine produced from these reservoirs may or may not be directly used for water generation.
  2. Brine-storage reservoirs: these are used to store brine and/or residual brine and, with treatable brine composition, to produce brine for water generation. For zero net injection, high seal integrity is not required.

This strategy has several advantages. First, pressure drawdown observed during brine production mirrors the pressure buildup during CO2 injection, providing necessary data to directly estimate reservoir storage capacity before any CO2 is injected. Second, pressure drawdown is greatest where CO2 will be injected, which is more efficient both on a per well basis and per mass of removed brine basis. Pre-injection brine production in saline reservoirs shares two key advantages of CO2-EOR: (a) greater knowledge about reservoir properties and storage capacity and (b) depleted reservoir pressure, which increases storage capacity. A third advantage is that the flexibility of our tandem-reservoir approach can be used to improve the economics of Enhanced Water Recovery (EWR). The primary metric for selecting a brine-storage reservoir is for its brine composition to be more amenable for treatment for beneficial uses, such as saline cooling water or water generated through desalination. Where applicable, EWR will reduce the water intensity of CCUS, which is particularly valuable in water-stressed regions.

For a range of tandem-reservoir scenarios, we assess the influence of CO2-storage and brine-storage reservoir properties (e.g., reservoir compartment size, seal permeability, and salinity) on reservoir pressure management and EWR. We also illustrate how pre-injection brine production can be used as a tool for site selection and characterization, including assessments of CO2 storage capacity and permanence.

This work was sponsored by the USDOE Fossil Energy, National Energy Technology Laboratory, managed by Traci Rodosta and Andrea McNemar. This work was performed under the auspices of the USDOE by LLNL under contract DE-AC52-07NA27344.