CO2 Storage In Saline Formations Research Articles

Sandstone wettability in supercritical CO2-brine-rock interactions evaluated with 13C and 1H magnetic resonance

During the first decades of geologic CO2 storage in saline formations and depleted reservoirs, structural trapping is the most important storage mechanism. The effectiveness of CO2 containment hinges on the assumption that the sealing formation remains water wet in the presence of dense CO2. In this work, multiple 13C and 1H magnetic resonance (MR) methodologies were employed for the first time to evaluate the interactions between supercritical CO2, brine, and the pore surface of a Berea sandstone core plug under reservoir conditions. These studies employed a novel variable field superconducting MR and magnetic resonance imaging (MRI) instrument which permitted sequential 1H and 13C measurements of core plugs at high-pressure and high-temperature. To systematically study the wettability of rock core exposed to supercritical CO2, four experiments were designed including bulk CO2 in a high-pressure vessel, bulk CO2-brine, 13CO2 in dried rock core, and a 13CO2-brine-rock experiment.The measured 13C and 1H MR relaxation times in this work indicate that the Berea sandstone remained strongly water-wet when the brine saturated core plug was exposed to supercritical CO2 under reservoir conditions. For both 13C and 1H, T1 relaxation times provide more reliable wettability evaluation as compared to T2 due to the impact of molecular diffusion through internal magnetic field gradients. One-dimensional (1D) MRI was employed to spatially resolve 13CO2 and brine in the core plug. Two-dimensional (2D) MRI was able to image 13CO2 and brine in a PEEK vessel. The quantities of CO2 and brine in the core plug were determined from the MR signal intensities of 13CO2 and brine.

Mechanistic modeling and measurement of foamed gas flow resistance in fractures

Geologic heterogeneity is one of the important factors controlling migration and distribution of nonaqueous phase liquids in the subsurface. Heterogeneity, such as fractures, complicates the effectiveness of environmental remediation, and uncharacterized aquifer heterogeneity causes significant uncertainties in the removal of nonaqueous phase liquids. Foaming an injection gas is an effective method to alleviate the challenges in accessing heterogeneous media during remediation processes because foam is nonNewtonian and redirects gas and liquid flow. Foamed gas may also assist in increasing the storage of carbon dioxide in saline formations. This paper investigates foam flow behavior in microscale fractures and develops a mechanistic transient foam flow model using the population balance method. Microscale experiments in fractures with apertures of 25 and 88 μm are used to validate the model for pressure drop, gas saturation, and bubble texture. Key differences related to modeling foam in fractures are the potential for continuously varying gas–liquid curvature in fractures and the relationship of this curvature to apparent foam viscosity. Incorporation of a local foam flow resistance factor is important to representing flow physics accurately. Hence, the results of this study provide foundational understanding for upscaling foam rheology in different sized fractures to ensure successful operations in soil/aquifer remediation and CO2 storage in saline formations.

Application of CO2 injection monitoring techniques for CO2 EOR and associated geologic storage

The Energy & Environmental Research Center (EERC), through its efforts leading the Plains CO2 Reduction (PCOR) Partnership, has successfully developed practices and technologies that can be used in future commercial-scale CO2 storage projects in different geologic formations, including both dedicated CO2 storage in saline formations and associated CO2 storage incidental to enhanced oil recovery (EOR). In this work, reservoir monitoring activities have been conducted in a large-scale CO2 EOR project to understand performance and associated storage. The activities include pulsed-neutron well logs (PNLs), 4D (time-lapse 3D) seismic surveys, and numerical simulation of injection and production. This enabled monitoring at different scales, from individual wells to field-scale reservoir assessments. The oil, water, and CO2 saturations were profiled to identify bypassed oil and high-conductivity CO2 migration pathways in the reservoir. These techniques provided actionable information, enabling better management of CO2 flooding, diagnosing performance and sweep efficiency while ensuring injected CO2 remained within the reservoir.

EAGE, SEG to host CO2 storage research workshop in Trondheim, Norway

Geologic storage of carbon dioxide (CO2) has long been considered an important component of greenhouse gas emissions mitigation ( Pacala and Socolow, 2004 ). Industry experience with CO2 injection for enhanced oil recovery (EOR) (since the 1970s) and CO2 storage in saline formations (since 1996) has produced a strong foundation of knowledge for improving and refining CO2 storage technology. There are many technical challenges at geologic storage sites that require geophysical measurements and monitoring. These challenges include initial site assessment; assuring that injectivity and capacity predictions are reliable; confirming that the fate and configuration of the CO2 plume is acceptable; and that regulatory permitting and compliance is accomplished in a timely manner (e.g., CSFL, 2013; Dixon and Romanak, 2015 ).

Parametric analysis of technology costs for CO2 storage in saline formations

Over the last decade, a substantial amount of economic, engineering, and geoscience research has focused on storing CO2 in geological formations. Of those different formations, storage in saline water-bearing formations represents the largest storage potential. Fossil fuel-based power plants in the U.S. (coal and natural gas) contributed to 40% of all CO2 emissions in 2008 and therefore represent an important factor to address atmospheric CO2 emissions.The Water, Energy and Carbon Sequestration Simulation Model (WECSsim) was developed to calculate water use and treatment options, CO2 injection volumes and the levelized cost of energy (LCOE) results for both a single representative power plant paired with a saline formation scenario, and a full power plant fleet. The details of the analysis presented here broadly demonstrate the sensitivity of CO2 capture and storage (CCS) costs in geologic saline formations with water extraction, treatment and reuse to changes in the water demands associated with implementing CCS across the power plant fleet (coal and natural gas).The majority of the coal and natural gas plants in the U.S. have an avoided cost of $70–200 per tonne of CO2. Storing 1.0Gt/yr of the nation’s 2.3Gt/yr total CO2 emissions returns an avoided (storage) cost of range 79–143 (57–81) $/t ($US 2013) under various scenarios. These scenarios include allowing competition between power plants for saline formation space to store CO2, varying the duration of the storage rights, and permitting the extraction of saline waters for treatment.Under the same 1Gt/yr captured scenario, the extracted and treated water volumes could offset 12% of the added water demand due to the parasitic energy requirements of CCS at the national level. The cost of water treatment, using a reverse osmosis system, ranges between approximately $3.20/m3 water (for larger, older coal-fired plants like the San Juan Power Generating Station) and $2.60/m3 water for natural gas combined cycle plants (such as the Oyster Creek Power Generating Station) with substantial variability in costs based on plant location and design. For context, the levelized cost of energy (LCOE) composition of the pulverized coal-based San Juan Generation Station is 52%, 43% and 5% for the base LCOE, parasitic energy requirements, and water extraction, treatment and utilization costs, respectively. Similarly, for the Oyster Creek natural gas combined cycle plant, these percentages are 64%, 33%, and 2% of the total LCOE, respectively. In both technology cases the parasitic energy requirement costs far outweigh the cost to extract, treat, transport, and utilize saline formation waters.Additional results indicate that of the 325 saline formations included in the national-level analysis, the Mt. Simon formation has an estimated capacity to hold 53% of all the CO2 generated from the U.S. coal and natural gas-based power plants without extracting and treating saline water. The St. Peter Sandstone formation could hold 43%, though with saline water extraction and treatment. These results suggest that focusing research, development and demonstration (RD&D) efforts on careful geologic site selection and reducing the parasitic energy penalty, and its respective costs, will help lower the overall cost of CCS across the U.S. coal and natural gas-based power plant fleet.

Exhaustive brine production and complete CO2 storage in Jianghan Basin of China

Pressure buildup limits CO2 injectivity and storage capacity and pressure loss limits the brine production capacity and security, particularly for closed and semi-closed formations. In this study, we conduct a multiwell model to examine the potential advantages of combined exhaustive brine production and complete CO2 storage in deep saline formations in the Jiangling Depression, Jianghan Basin of China. Simulation results show that the simultaneous brine extraction and CO2 storage in saline formation not only effectively regulate near-wellbore and regional pressure of storage formation, but also can significantly enhance brine production capacity and CO2 injectivity as well as storage capacity, thereby achieving maximum utilization of underground space. In addition, the combination of brine production and CO2 injection can effectively mitigate the leakage risk between the geological units. With regard to the scheme of brine production and CO2 injection, constant pressure injection is much superior to constant rate injection thanks to the mutual enhancement effect. The simultaneous brine production of nine wells and CO2 injection of four wells under the constant pressure injection scheme act best in all respects of pressure regulation, brine production efficiency, CO2 injectivity and storage capacity as well as leakage risk mitigation. Several ways to further optimize the combined strategy are investigated and the results show that increasing the injection pressure and adopting fully penetrating production wells can further significantly enhance the combined efficiency; however, there is no obvious promoting effect by shortening the well spacing and changing the well placement.

Effect of contaminants from flue gas on CO2sequestration in saline formation

SUMMARY Deep saline aquifers are reported to have the largest estimated capacity for CO2 sequestration. Most geochemical studies on CO2 storage in saline formations are focused on the interactions of pure CO2 and do not consider the potential impacts of contaminants such as SO2 found in typical post-composition flue gas streams. This paper reports on results of a combined CO2–co-contaminant–brine–rock experimental and a simple modeling study of the potential impact of flue gas contaminants on saline formations. Chemical reactions of the sandstone from Mount Simon formation exposed to CO2 mixed with other gas species under sequestration conditions were studied (i.e. solid material — representative Mount Simon sandstone; liquid — synthetic Illinois Basin brine; T and P — 50 °C, 110 bar; gas composition — 1% SO2, 4% O2, 95% CO2). The experimental study indicates that the co-injection of 1% SO2 would lead to substantially reduced brine pH due to the formation of sulfuric acid and the formation of bassanite (major) and anhydrites. Preliminary equilibrium computational modeling yielded similar results. Copyright © 2013 John Wiley & Sons, Ltd.

Static and Dynamic Estimates of CO2-Storage Capacity in Two Saline Formations in the UK

Summary Estimation of carbon dioxide (CO2)-storage capacity is a key step in the appraisal of CO2-storage sites. Different calculation methods may lead to widely diverging values. The compressibility method is a commonly used static method for estimating storage capacity of saline aquifers: It is simple, is easy to use, and requires a minimum of input data. Alternatively, a numerical reservoir simulation provides a dynamic method that includes Darcy flow calculations. More input data are required for dynamic simulation, and it is more computationally intensive, but it takes into account migration pathways and dissolution effects, so it is generally more accurate and more useful. For example, the CO2-migration plume may be used to identify appropriate monitoring techniques, and the analysis of the trapping mechanism for a certain site will help to optimize well location and the injection plan. Two hypothetical saline-aquifer storage sites in the UK, one in Lincolnshire and the other in the Firth of Forth, were analyzed. The Lincolnshire site has a comparatively simple geology, while the Forth site has a more complex geology. For each site, both static- and dynamic-capacity calculations were performed. In the static method, CO2 was injected until the average pressure reached a critical value. In the migration-monitoring case, CO2 was injected for 15 years, and was followed by a closure period lasting thousands of years. The fraction of dissolved CO2 and the fraction immobilized by pore-scale trapping were calculated. The results of both geological systems show that the migration of CO2 is strongly influenced by the local heterogeneity. The calculated storage efficiency for the Lincolnshire site varied between 0.34% and 0.65% of the total pore-volume, depending on whether the system boundaries were considered open or closed. Simulation of the deeper, more complex Forth geological system gave storage capacities as high as 1.05%. This work was part of the CO2-Aquifer-Storage Site Evaluation and Monitoring (CASSEM) integrated study to derive methodologies for assessment of CO2 storage in saline formations. Although static estimates are useful for initial assessment when fewer data are available, we demonstrate the value of performing dynamic storage calculations and the opportunities to identify mechanisms for optimizing the storage capacity.

Impact-driven pressure management via targeted brine extraction—Conceptual studies of CO2 storage in saline formations

Large-scale pressure buildup in response to carbon dioxide (CO2) injection in the subsurface may limit the dynamic storage capacity of suitable formations, because elevated pressure can impact caprock integrity, induce reactivation of critically stressed faults, drive CO2 and/or brine through conductive features into shallow groundwater resources, or may affect existing subsurface activities such as oil and gas production. It has been suggested that pressure management involving the extraction of native fluids from storage formations can be used to control subsurface pressure increases caused by CO2 injection and storage, thereby limiting the possibility of unwanted effects. In this study, we introduce the concept of “impact-driven pressure management (IDPM),” which involves optimization of fluid extraction to meet local (not global) performance criteria (i.e., the goal is to limit pressure increases primarily where environmental impact is a concern). We evaluate the feasibility of IDPM for a hypothetical CO2 storage operation in an idealized multi-formation system containing a critically stressed fault zone. Using a newly developed analytical solution, we assess alternative fluid extraction schemes and test whether a predefined performance criterion can be achieved, in this case the maximum allowable pressure near the fault zone. Alternative strategies for well placement are evaluated, comparing near-injection arrays of extraction wells with near-impact arrays. Extraction options include active extraction wells and (passive) pressure relief wells, as well as combinations of both, with and without reinjection into the subsurface. Our results suggest that strategic well placement and optimization of extraction may allow for a significant reduction in the brine extraction volumes. Additional work is required in the future to test the general concept of IDPM for more complex and realistic CO2 storage scenarios.

Combining brine extraction, desalination, and residual-brine reinjection with CO2 storage in saline formations: Implications for pressure management, capacity, and risk mitigation

For industrial-scale CO2 injection in saline formations, pressure increase can be a limiting factor in storage capacity. To address this concern, we introduce Active CO2 Reservoir Management (ACRM), which combines brine extraction and residual-brine reinjection with CO2 injection, contrasting it with the conventional approach, which we call Passive CO2 Reservoir Management. ACRM reduces pressure buildup and CO2 and brine migration, which increases storage capacity. Also, “push-pull” manipulation of the CO2 plume can counteract buoyancy, exposing less of the caprock seal to CO2 and more of the storage formation to CO2, with a greater fraction of the formation utilized for trapping mechanisms. If the net extracted volume of brine is equal to the injected CO2 volume, pressure buildup is minimized, greatly reducing the Area of Review, and the risk of seal degradation, fault activation, and induced seismicity. Moreover, CO2 and brine migration will be unaffected by neighboring CO2 operations, which allows planning, assessing, and conducting of each operation to be carried out independently. In addition, ACRM creates a new product, as extracted brine is available as a feedstock for desalination technologies, such as Reverse Osmosis. These benefits can offset brine extraction and treatment costs, streamline permitting, and help gain public acceptance.

The coupled simulator ECLIPSE–OpenGeoSys for the simulation of CO2 storage in saline formations

The storage of CO2 in deep saline aquifers is due to the large available capacities and the common occurrence of these formations one of the major options for carbon dioxide sequestration. Besides the multiphase flow aspects geochemical, thermal and mechanical processes may alter the conditions within the reservoir as well as in the cap rock. Whereas single aspects of these processes can be investigated with experiments a multi-process simulator allows evaluating their combined consequences for the storage system over short and long time scales. In this paper the newly coupled software ECLIPSE-OpenGeoSys is presented that allows a combined simulation of multiphase flow, transport and geochemical reactions. ECLIPSE provides a fast and efficient solution for the multiphase flow whereas the open-source scientific software OpenGeoSys is used for calculating transport and geochemical reactions. This paper presents the code structure of the interface. Furthermore the coupled software is successfully applied to benchmarks

Defining simple and comprehensive assessment units for CO2 storage in saline formations beneath the UK North Sea and continental shelf

In the UK, by far the largest CO2 storage opportunities lie offshore. The North Sea in particular has a long and complex geological history, with potential reservoirs geographically widespread and occurring at multiple stratigraphic levels. Diverse storage estimates have been made, using a range of working methods, and yielding different values, e.g. SCCS (2009); Bentham (2006). Consequently the UK Storage Appraisal Project (UKSAP), commissioned and funded by the Energy Technologies Institute (ETI), is undertaking the most comprehensive assessment to date, using abundant legacy seismic and borehole data. This study has a remit to use best current practice, consistent between locations, to calculate the CO2 storage capacity of the entire UK Continental Shelf (UKCS) within saline aquifers and hydrocarbon fields. The potential storage formations have been subdivided into units for assessment, and filtered to remove units with only a small estimated storage capacity to concentrate resources on more viable units. The size of potential storage units approximate to a power law distribution, similar to that of hydrocarbon fields, with a large number of small units and a small number of large units.

Variability and uncertainty in the cost of saline formation storage

Cost estimates for CO2 capture and storage (CCS) systems typically focus on details of the CO2 capture process and make simplistic assumptions about the cost per ton of CO2 for the transport and storage components of the system. These ad hoc assumptions ignore the large variability in the storage cost from site-to-site caused by variation in storage reservoir characteristics. Moreover, the typical costs of storage that are widely applied in CCS cost estimates do not fully consider the cost of site characterization and operational monitoring. To address this problem, we have recently developed an engineeringeconomic model for geological storage in deep saline formations. In this paper we briefly describe the newly-developed performance and cost models for CO2 storage in deep saline formations, and use these models to develop a range of cost for CO2 storage. The range of cost is explored using four cases, representing different types of potential storage reservoirs. Results from the four case studies show considerably different capital costs and, consequently, levelized costs of CO2 stored. In addition, the sensitivity of CO2 storage cost to variability and uncertainty in model input parameters for one of the case studies is examined. These results show clearly that the cost of CO2 storage in saline formations is most sensitive to factors affecting site characterization costs, which have been significantly underestimated in most past studies, and are highly dependent on future regulation of geological storage projects. © 2008 Elsevier Ltd. All rights reserved

Measuring permanence of CO2 storage in saline formations: the Frio experiment

If CO2 released from fossil fuel during energy production is returned to the subsurface, will it be retained for periods of time significant enough to benefit the atmosphere? Can trapping be assured in saline formations where there is no history of hydrocarbon accumulation? The Frio experiment in Texas was undertaken to provide answers to these questions. One thousand six hundred metric tons of CO2 were injected into the Frio Formation, which underlies large areas of the United States Gulf Coast. Reservoir characterization and numerical modeling were used to design the experiment, as well as to interpret the results through history matching. Closely spaced measurements in space and time were collected to observe the evolution of immiscible and dissolved CO2 during and after injection. The high-permeability, steeply dipping sandstone allowed updip flow of supercritical CO2 as a result of the density contrast with formation brine and absence of a local structural trap. The front of the CO2 plume moved more quickly than had been modeled. By the end of the 10-day injection, however, the plume geometry in the plane of the observation and injection wells had thickened to a distribution similar to the modeled distribution. As expected, CO2 dissolved rapidly into brine, causing pH to fall and calcite and metals to be dissolved. Postinjection measurements, including time-lapse vertical seismic profiling transects along selected azimuths, cross-well seismic topography, and saturation logs, show that CO2 migration under gravity slowed greatly 2 months after injection, matching model predictions that significant CO2 is trapped as relative permeability decreases.