Reducing Energy’s Footprint by Producing Water and Storing CO2

By Thomas A. Buscheck
Group Leader,
Geochemical, Hydrological, and Environmental Sciences,
Physical and Life Sciences Directorate,
Lawrence Livermore National Laboratory
Jeffrey M. Bielicki
Assistant Professor,
Department of Civil, Environmental, and Geodetic Engineering and John Glenn College of Public Affairs,
The Ohio State University

The global energy sector faces many challenges, perhaps the two most important of which are reducing greenhouse gas emissions from fossil fuels, which made up over 86% of primary energy consumption in 2014,1 and addressing the growing challenge of water scarcity. One key aspect of the landmark U.S.-China Joint Announcement on Climate Change is the consideration of a collaborative effort to engage on both challenges simultaneously through research, development, and demonstration of a CO2 capture and storage (CCS) project that would produce freshwater.2

The U.S.-China Clean Energy Research Center’s (CERC) Advanced Coal Technology Consortium (ACTC) is an opportunity to leverage years of experience and research to investigate an emerging CO2 capture, utilization, and storage (CCUS) technology called enhanced water recovery (EWR). To date, CCUS has been deployed by injecting CO2 into petroleum reservoirs for enhanced oil recovery (CO2-EOR). While CCUS/CO2-EOR can make early contributions to reducing CO2 emissions and raising revenue for first mover CCS demonstrations, the total scope is limited. For example, in the U.S., in the year 2013 alone, emissions were 6.7 billion tonnes of CO2. For comparison, total storage capacity using “next generation” CO2-EOR in the U.S. was estimated to be 45 billion tonnes of CO2, with less than half (20 billion) considered to be economic at an oil price of $85/bbl, which would address the equivalent of three years of CO2 emissions.3,4

Unlike CO2-EOR, which has limited deployment potential in many regions of the world, EWR can be deployed in saline aquifers that are well distributed and close to CO2 sources(e.g., coal-fired power plants). EWR can be synergistically integrated with other emerging CCUS technologies that generate geothermal energy,5,6 as well as provide grid-scale energy storage.7,8 By removing brine from a saline CO2 storage reservoir, EWR can augment the development, operation, and performance of CCS, while producing large quantities of water.9,10 In this article we discuss how EWR can be used to help manage environmental and financial risks during the stages of CCS development.


Despite the importance of CCS/CCUS for reducing global emissions, widespread deployment faces some considerable technical challenges. To overcome these, the U.S. Department of Energy (DOE) outlined four major goals for its Carbon Storage Technology Program Plan:11

  1. Develop and validate technologies to ensure 99% storage permanence (i.e., less than 1% of the injected CO2 leaves the storage system due to leakage).
  2. Develop technologies to improve reservoir storage efficiency, while ensuring containment effectiveness.
  3. Support industry’s ability to predict CO2 storage capacity in geologic formations within ±30%.
  4. Develop best practice manuals for monitoring, verification, and accounting; site screening, selection, and initial characterization; public outreach; well management activities, risk analysis, and simulation.

In a CO2 storage reservoir, overpressure is defined as fluid pressure that exceeds the original pressure before CO2 is injected. Overpressure is the limiting metric for CO2 storage capacity because it is the primary factor affecting risks such as induced seismicity, caprock fracture, and CO2 leakage. These risks increase with overpressure. The three most important factors that influence overpressure are

  1. The quantity of CO2 and the rate at which it is injected
  2. The size of the storage reservoir “compartment”, determined by the geology
  3. The permeability (i.e., ability of the CO2 to move) within the storage reservoir

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. However, until injection or production wells are operated, and large quantities of fluid move into and/or out of the storage reservoir, estimates of CO2 storage capacity and permanence may be subject to uncertainty.

Unlike CCUS/CO2-EOR operations conducted at brownfield sites (pre-existing well-fields), CCS in a saline aquifer is typically a greenfield operation. Thus, there may be less geologic information, and little or no production and injection history available to estimate how much CO2 can be safely and securely stored. The ZeroGen project in Australia is one prominent example of a problem resulting from insufficient knowledge about the storage reservoir. The project only advanced to the point of learning that the intended CO2 storage reservoir had too little storage capacity. As a result, a key lesson learned from that project was that storage capacity estimates must be based on long-term, dynamic well testing.12 Thus, uncertainties about CO2 storage capacity and permanence are key reasons why CO2 storage is a primary technical hurdle for the commercialization of CCS, but this hurdle can be addressed through site characterization augmented with brine extraction.

Without adequate site characterization, which can take 5–10 years, CO2 cannot be captured, transported, and stored routinely and reliably at large scale.13 Pore-space ownership and public acceptance are other key challenges. A deployment strategy that extracts brine prior to the injection of any CO2 can address these challenges.


Extracting brine from a CO2 storage reservoir provides multiple benefits. First, extracting brine opens more pore space in the reservoir for CO2 storage, resulting in less overpressure and less required post-injection monitoring for a given quantity of stored CO2.14 In addition, more CO2 can be injected without infringing on the pore-ownership rights of neighboring subsurface operations (e.g., other CCS sites).

Producing brine while increasing CO2 storage capacity could address two of the most important challenges facing today’s energy industry.

Producing brine while increasing CO2 storage capacity could address two of the most important challenges facing today’s energy industry.

Second, produced brine can be partially treated for industrial and saline cooling-water applications or desalinated to produce freshwater; it can also be used to extract valuable minerals, such as lithium.10,15 The efficacy of brine use depends on the location, because of differences in the chemical composition of the brine and applicable utilization options.

Third, when brine is extracted before CO2 injection, the resulting pressure drawdown provides direct information about overpressure that will result from CO2 injection.9 Hence, operational experience with removing brine reduces uncertainties about CO2 storage capacity and permanence, compared to when the first major well operation is CO2 injection itself. This third benefit is valuable for both site selection and characterization. Reducing CO2 storage uncertainty could be necessary prior to final commitments on CO2 capture and transportation infrastructure.

Fourth, brine extraction maximizes storage resource utilization. A “one source, one sink” approach is unlikely given the current regulatory climate and cost of CO2 capture. As brine removal increases CO2 storage capacity, it can allow an individual sink to store CO2 from multiple sources; thus, fixed development costs for that site (e.g., permitting, site characterization, monitoring) are leveraged for multiple sources, reducing CO2 storage cost.16–18

Zero net injection—where the volume of the extracted brine is the same as the volume of the injected CO2—minimizes interference with neighboring owners and users of underground pore space, and it also maximizes all of these benefits.

Brine Extraction as a Pressure Management Strategy

Brine extraction can be scheduled both before (Figure 1) and during CO2 injection (Figure 2). It could also be scheduled after CO2 injection (Figure 3), as part of a reservoir pressure management strategy aimed at reducing the required time for post-injection monitoring, while continuing to produce water.

FIGURE 1. Brine extraction before CO2 injection results in pressure drawdown, making room for CO2 storage.9

FIGURE 1. Brine extraction before CO2 injection results in pressure drawdown, making room for CO2 storage.9

For CCS operations, pre-injection brine extraction has three objectives: 1) minimize the total number of wells required for CCS deployment, 2) maximize the magnitude of overpressure reduction per unit of extracted brine, and 3) acquire pre-injection information on the reservoir from measuring pressure drawdown. When the same well is used first to extract brine and then to inject CO2, pressure drawdown and the information gathered are greatest where needed most—the center of CO2 storage.9 Measuring pressure drawdown in an adjoining deep monitoring well (Figure 1) provides additional information about the size of the reservoir compartment and CO2 storage capacity. Measuring drawdown in a shallow monitoring well provides important information about the potential for CO2 leakage through the caprock and, hence, CO2 storage permanence.

CO2 injection begins where pressure drawdown is greatest, which is where the brine was initially extracted (Figure 2). Then a second brine-extraction well can operate until CO2 from the first well reaches the second well, at which time the second well may be repurposed for CO2 injection (Figure 3). Brine extraction may continue at a third deep well, depending on the CO2 storage goals. Brine extraction could continue long after CO2 injection has ceased. This strategy could nullify residual overpressure, limit pore-space competition with neighbors, and reduce the time required for post-injection monitoring to assure storage integrity.

FIGURE 2. The brine-extraction well shown in Figure 1 is repurposed as a CO2 injection well and the deep monitoring well is repurposed for brine extraction.9

FIGURE 2. The brine-extraction well shown in Figure 1 is repurposed as a CO2 injection well and the deep monitoring well is repurposed for brine extraction.9

FIGURE 3. The brine-extraction well shown in Figure 2 is repurposed as a CO2 injection well; brine extraction is moved to a third deep well and could continue post-CO2 injection.9

FIGURE 3. The brine-extraction well shown in Figure 2 is repurposed as a CO2 injection well; brine extraction is moved to a third deep well and could continue post-CO2 injection.9

Based on data from the Snøhvit CO2 storage project that injected 1.09 million tonnes of CO2 over three years,19,20 a retrospective reservoir modeling study evaluated the potential efficacy of extracting brine prior to injecting CO2.21 Hydrogeologic information and CO2 injection-rate and pressure data provided by Statoil were used to calibrate a reservoir model to predict overpressure from CO2 injection. The results of this model agreed closely with measured values during the three years of CO2 injection (see Figure 4).

FIGURE 4. Overpressure history from the Snøhvit CO2 storage project injection well and as modeled for injection only and with pre-injection brine extraction.21

FIGURE 4. Overpressure history from the Snøhvit CO2 storage project injection well and as modeled for injection only and with pre-injection brine extraction.21

The calibrated model was then used to simulate a scenario where a volume of brine equal to the injected CO2 volume (~1.56 million m3) was extracted over the three years prior to CO2 injection. To continue the modeling exercise beyond the end of the actual Snøhvit CO2 injection phase, it was assumed that the three-year CO2 injection-rate schedule was repeated nine times during the 27 years following the end of the phase. It was also assumed that brine was extracted in the same time-varying fashion.21

At the end of injection at Snøhvit, a peak overpressure of 7.63 MPa was reached; a goal of this modeling exercise was to determine how much additional CO2 could be injected before this overpressure was reached if brine had been extracted. It was found that extracting a volume of brine equal to the volume of the injected CO2 nearly doubled the time (and quantity of CO2) required to reach an overpressure of 7.63 MPa.21 On a volume-for-volume basis, brine extraction was found to be 94% effective, the equivalent of not having injected 1.03 of the 1.09 (actual) million tonnes of CO2, which could enable an additional 1.03 million tonnes of CO2 to be injected before the peak measured overpressure was reached.21

This exercise also showed the value of brine extraction for site characterization. Pressure drawdown history is the mirror image of the overpressure history (Figure 4), and thus this technique provides useful information on overpressure that will result from CO2 injection as well as on the CO2 storage capacity. It is worth noting that three years of pre-injection brine extraction falls within the 5–10-year timeframe attributed to site characterization.13

Brine Extraction as a Site Selection and Characterization Strategy

Extracting brine prior to CO2 injection could be applied to several potential CO2 storage sites to help identify the one that has the best combination of storage capacity, permanence, and efficiency. Brine extraction could then continue at the selected site until enough pressure data is collected and analyzed to assure investors, insurers, and, most importantly, the public that risk has been sufficiently reduced.

The Benefit of Producing Water

The inextricable link between water and energy has been termed the water–energy nexus. Every energy source requires water at some point in the supply chain.22,23 Thermal power plants fueled by coal, natural gas, and nuclear energy serve as the backbone of the modern energy infrastructure and such plants require substantial cooling, which is most often served by water.

EWR through brine extraction produces water as part of an integrated strategy to also dispose of CO2 in the deep subsurface. Thus, thermal power plants begin producing water and some plants, such as those that employ low-water demand technologies like pressurized oxy-combustion or chemical looping with CCS (currently pre-commercialization), could become net water producers. However, brine that is produced from the deep aquifers suitable for CO2 storage contains more dissolved solids and impurities than groundwater in shallow aquifers. Brine from saline aquifers is not usable without treatment. Based on preliminary estimates,10 treatment may cost ~0.3 US¢/kWh for zero net injection, possibly attractive in many water-scarce regions. Moreover, that cost can be offset by other savings (fewer wells, less monitoring, lower insurance costs) and the economic and permitting advantages that arise from reducing uncertainty. There may also be opportunities for synergistic integration of thermal power plants and water purification processes.8,24 Still, the net life-cycle benefits of producing water from CO2 injection need to be investigated.25

The CO2 storage site down-selection criteria, discussed in the previous section, can be broadened to include brine treatability (e.g., energy required and costs of treatment depend on the brine composition and intended application), as well as the proximity of a candidate site to arid regions.

A zero net injection strategy for reservoir pressure management can generate substantial quantities of brine (and product water after treatment) on a per MWh basis. A 1000-MW coal-fired power plant operating at 90% capacity and a 90% CO2 capture rate produces 10–14.4 million m3 (8–11.6 thousand acre feet) of water per year while storing seven million tonnes of CO2 each year.14

If low-water CO2 capture options are used, coal-fired power plants with EWR could become net water producers.

If low-water CO2 capture options are used, coal-fired power plants with EWR could become net water producers.


The potential of EWR was highlighted by its consideration for development in U.S-China collaboration efforts. Under the recent joint climate announcement, the U.S.-China CERC is considering EWR in connection with the GreenGen project in Tianjin, China. The Huaneng Corporation is planning to capture CO2 at a coal integrated gasification combined-cycle (IGCC) power plant.26 The feasibility of injecting this CO2 into a deep saline aquifer for permanent storage, while extracting an equivalent volume of brine to generate freshwater by reverse osmosis desalination, possibly using pre-injection brine extraction, was evaluated with promising results.27


Overall, challenges facing modern energy systems include reducing both CO2 emissions and water intensity, while providing reliable, affordable, and secure energy. These challenges can be addressed simultaneously by injecting CO2 for storage in deep saline aquifers while producing brine from the same aquifers. Producing brine has a number of operational benefits that enhance the efficacy of CO2 storage, while simultaneously producing water that may help alleviate the stress in the water–energy nexus. CCS is a key tranche in the lowest-cost suite of technologies needed to limit global emissions and EWR could play an important role in advancing CCS.


We gratefully acknowledge the Statoil and the Snøhvit Production License for use of data from the Snøhvit CO2 storage project, and Philip Ringrose for useful discussions. 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 Lawrence Livermore National Laboratory under DOE contract DE-AC52-07NA27344.


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