Potential Storage Reservoirs Research Articles

Influence of Clay Content on CO2-Rock Interaction and Mineral-Trapping Capacity of Sandstone Reservoirs

The injection of carbon dioxide (CO2) is an essential technology for maximizing the potential of hydrocarbon reservoirs while reducing the impact of greenhouse gases. However, because of the complexity of this injection, there will be many different chemical reactions between the formation fluids and the rock minerals. This is related to the clay content of sandstone reservoirs, which are key storage targets. Clay content and clay types in sandstone can vary substantially, and the influence of these factors on reservoir-scale CO2-water-sandstone interactions has not been managed appropriately. Consequently, by simulating the process of CO2 injection in two different clay-content sandstones (i.e., high- and low-clay content), we investigated the effect of the sandstone clay concentration on CO2-water-sandstone interactions in this article. High clay content (Bandera Grey sandstone) and low clay content (Bandera Brown sandstone) were considered as potential storage reservoirs and their responses to CO2 injection were computationally assessed. Our results indicate that the mineralogical composition of the sandstone reservoir significantly varies as a result of CO2-water-sandstone interactions. Clearly, the high clay-content sandstone (Bandera Grey) had a higher maximum CO2 mineral-trapping capacity (6 kg CO2/m3 sandstone) than Bandera Brown Sandstone (low clay content), which had only 3.3 kg CO2/m3 sandstone mineral-storage capacity after 400 years of storage. Interestingly, pH was decreased by ~3 in Bandera Grey sandstone and by ~2.5 in Bandera Brown sandstone. Furthermore, porosity increased in Bandera Grey sandstone (by +5.6%), more than in Bandera Brown Sandstone (+4.4%) after a 400-year storage period. Overall, we concluded that high clay-content sandstone shows more potential for CO2 mineral-trapping.

A framework for assessing economics of blue hydrogen production from steam methane reforming using carbon capture storage & utilisation

Hydrogen (H2) generation using Steam Methane Reforming (SMR) is at present the most economical and preferred pathway for commercial H2 generation. This process, however, emits a considerable amount of CO2, ultimately negating the benefit of using H2 as a clean industrial feedstock and energy carrier. That has prompted growing interest in enabling CO2 capture from SMR for either storage or utilisation and producing zero-emission “blue H2”. In this paper, we propose a spatial techno-economic framework for assessing blue hydrogen production SMR hubs with carbon capture, utilisation and storage (CCUS), using Australia as a case study. Australia offers a unique opportunity for developing such ‘blue H2’ hubs given its extensive natural gas resources, availability of known carbon storage reservoirs and an ambitious government target to produce clean/zero-emission H2 at the cost of <A$2 kg−1 by 2030. Our results highlight that the H2 production costs are unsurprisingly dominated by natural gas, with the additional capital requirement of carbon capture and storage (CCS) also playing a critical role. These outcomes are especially pertinent for eastern Australian states, as they are experiencing high natural gas costs and would generally require extensive CO2 transport and storage infrastructure to tap potential storage reservoirs, ultimately resulting in a higher cost of producing H2 (>A$2.7 kgH2−1). On the other hand, Western Australia offers lower gas pricing and relatively lesser storage costs, which would lead to more economically favourable hydrogen production (<A$2.2 kgH2−1). We further explore the possibility of utilising the emissions captured at blue SMR hubs by converting them into formic acid through CO2 electroreduction, yielding revenue that will decrease the cost of blue H2 and reduce the reliance on CO2 storage. Our analysis reveals that formic acid production utilising a 10 MW CO2 electrolyser can potentially reduce H2 production costs by between 4 and 9%. Further cost reduction is possible by scaling the CO2 electrolyser capacity to convert a larger portion of the emissions captured, albeit at the cost of higher capital investment, electricity consumption and saturating the market for formic acid. Thus, carbon utilisation for a range of products with high market demand represents a more promising approach to replacing the need for costly carbon storage. Overall, our modelling framework can be adapted for global application, particularly for regions interested in generating blue H2 and extended to include other CO2 utilisation opportunities and evaluate other hydrogen production technologies.

A new methodology to assess the maximum CO2 geosequestration capacity of shale reservoirs with SRV based on wellbore pressure

Shale reservoirs are promising geological sites for CO2 storage due to their high total organic content (TOC) and the large-scale hydraulic fracturing operations. In order to critically evaluate a potential storage reservoir, fast, robust tools are needed to assess the CO2 storage capacity. Based on our previous work, an efficient method based on semi-analytical solution for calculating the maximum CO2 storage capacity in shale formations is derived, based on the injection wellbore pressure. The new methodology fully reflects the flow, diffusion, and adsorption processes of CO2 in shales. It also simulates natural fractures, hydraulic fractures, and the stimulated reservoir volume (SRV). The semi-analytical solution utilizing a Laplace transform and Stehfest numerical inversion is developed to evaluate the wellbore pressure and storage capacity in shale formations, which is verified using numerical simulations. A case study of the derived method on the Bakken Shale shows that the CO2 storage capacity is strongly controlled by the CO2 injection rate, adsorption index, and storage ratio. It is also found that the effective diffusion coefficient and mobility ratio affect the CO2 storage capacity during different periods of the CO2 storage process.

Potential for brine storage near the gas storage facility at Lille Torup, northern Jylland, Denmark

This study is based on a feasibility study for the Danish Energinet. dk to identify potential formations for brine storage near the gas storage facility at Lille Torup, northern Jylland, Denmark (Fig. 1; Hjuler et al. 2017). Located on top of a salt structure, the gas storage facility comprises seven caverns, which have been washed out by circulating water in the salt dome. One cavern contains c. 520.000 m3 of intrusive brine that must be disposed of in order to increase the storage volume for gas. One option is to inject the brine into the subsurface if a target with appropriate storage properties can be identified, but it is a prerequisite that the stored brine does not compromise freshwater reservoirs. Due to cost considerations, the brine storage should be situated within a radius of 50 km of the gas storage facility and at a depth not exceeding 2000 m. Based on the national geothermal research conducted during the last decade, a number of sandy formations are considered potential storage reservoirs (Fig. 2; e.g. Mathiesen et al. 2009; Vosgerau et al. 2016). Around Lille Torup, these include the Bunter Sandstone/Skagerrak, Gassum, Haldager Sand and Frederikshavn formations where the two former formations are discarded due to present-day burial depths exceeding 2000 m. In addition, the Chalk Group is considered a potential storage formation due to its importance as a hydrocarbon reservoir in the North Sea, however, due to risk of leakage to the younger sediments and risk of environmental issues, the chalk was discarded as potential storage zone.

Introduction to special section: Multidisciplinary studies for geologic and geophysical characterization of CO2 storage reservoirs

There are currently 15 large-scale carbon capture and storage (CCS) projects and multiple pilot injection projects operating across the world. A critical challenge for successful CCS programs is to reliably and economically predict long-term behavior of CO2 in potential storage reservoirs. As with

‘Best practice’ community dialogue: The promise of a small-scale deliberative engagement around the siting of a carbon dioxide capture and storage (CCS) facility

In New Zealand the Taranaki region has been identified as a likely place for carbon dioxide sequestration as a result of its oil and gas industry, potential storage reservoirs and skilled local workforce. As yet there are no plans to deploy the carbon dioxide capture and storage (CCS) technology in this particular region but this presented an opportunity for pro-active engagement with local stakeholders, including the urban community, farmers and landowners, local iwi (Māori), local and regional councils and the oil/gas industry. As an alternative to a standard consultation technique, a small-scale dialogue-based method was used, based on the principles of deliberative engagement. In this context, the emphasis was on developing an informed understanding of different viewpoints and solution-focused decision-making. This method of engagement was found to be cost-effective, revealed some unexpected viewpoints and identified some important precursors to risk perception in New Zealand. The empowerment of participants, assisted by independent scientists and the opportunity for facilitated dialogue, were key success factors. Moreover, the approach was valued by the wider community and perceived as a means to open up dialogue around other regional energy issues. In summary, small-scale deliberative engagement processes are a viable alternative or complement to standard community consultation techniques for engagement around the siting of CCS facilities.

Influence of impurities (nitrogen and methane) on the CO2 storage capacity as sediment-hosted gas hydrates – Application in the area of the Celtic Sea and the Bay of Biscay

Deep saline aquifers are the most important potential storage reservoirs for CO2 under supercritical conditions. Another option is the trapping of CO2 in deep-sea sediments at low temperature, either in liquid state or as gas hydrates. The Negative Buoyancy Zone (NBZ) and the Gas Hydrate Stability Zone (GHSZ) are used to calculate the theoretical storage volume. It depends essentially on the geothermal gradient and on the quality of the injected CO2. A sensitivity analysis shows that the storage volume in the Celtic Sea and the Bay of Biscay area is one order of magnitude lower if the injected fluid contains impurities like nitrogen or methane. Overall, the storage capacity in the French Exclusive Economic Zone (EEZ) exceeds 100 years of storage of the current French CO2 emissions from large point sources. The conservative estimate of the EEZ storage capacity is found to be higher than in the deep saline aquifers of the Paris Basin. Moreover, the CO2 storage capacity in this area is doubled when considering the zone beyond 200miles from the shores. The implications of these results are potentially important for the long-term deployment strategy for CO2 storage in France and in Western Europe.

Rates of mineral dissolution under CO2 storage conditions

Evaluating the potential of a sedimentary basin reservoir to securely store CO2 benefits from a comprehensive understanding of the geochemical reactions that take place once CO2 is injected into a formation. In particular, models that predict the transport and reaction of CO2 within a reservoir require a definition of the types of reactions affected by enhanced levels of CO2 and how the kinetics of these reactions will affect a heterogeneous mineralogy and formation waters within a reservoir over time. In this review we evaluate rate models used to describe mineral dissolution kinetics and compare the range in values reported for the kinetic parameters used to describe the reactivity of various minerals relevant to mainly siliciclastic reservoirs. Parameters that have a significant impact on model results include the reactive surface area of a mineral, the apparent activation energies used to extrapolate reaction rates to the temperatures of potential storage reservoirs (c. 50–125°C) and the in-situ pH of formation waters with elevated concentrations of dissolved CO2. The variation in reported values for these parameters can lead to predicted rates that span many orders of magnitude for a given mineral. Despite these uncertainties recent success with geochemical models has been made by applying a Monte Carlo approach to optimise the kinetic parameters for minerals where robust thermodynamic and kinetic data do not exist.

The geo-database of caprock quality and deep saline aquifers distribution for geological storage of CO 2 in Italy

One of the most promising options to stabilize and reduce the atmospheric concentration of greenhouse gases is Carbon Capture and Storage (CCS). This technique consists of separating CO 2 from other industrial flue gases and storing it in geological reservoirs, such as deep saline aquifers, depleted oil and/or gas fields, and unminable coal beds. A detailed reworking of all available Italian deep-drilling data was performed to identify potential storage reservoirs in deep saline aquifers. Data were organized into a GIS geo-database containing stratigraphic and fluid chemistry information as well as physiochemical characteristics of the geological formations. Caprock efficiency was evaluated via numerical parameterization of rock permeabilities, defining the “ Caprock Quality Factor” ( Fbp) for each well. The geo-database also includes strategic information such as the distribution of deep aquifers, seismogenic sources and areas, seismic events, Diffuse Degassing Structures, heat flow, thermal anomalies, and anthropogenic CO 2 sources. Results allow the definition of potentially suitable areas for future studies on CO 2 geological storage located in the fore-deep domains of the Alps and Apennines chains, where efficient marly-to-clayish caprocks lie above deep aquifers hosted in sands or limestones. Most of them are far form seismogenic sources and Diffuse Degassing Structures.

The Wyoming carbon underground storage project: Geologic characterization of the Moxa Arch and Rock Springs Uplift

The Wyoming carbon underground storage project: Geologic characterization of the Moxa Arch and Rock Springs Uplift

Development of CCS technology for coal-fired power plant in Taiwan

Abstract Safe candidate sites of reservoir for geologic storage including some oil or gas bearing structures on-shore or off-shore of the Taiwan island, and some near off-shore sedimentary basins were studied and screened. After screening out several potential engineering sites, an AHP ranking method was applied for ranking and selecting the preferred candidate on account of the economy factors, safety requirements, storage effectiveness, and potential storage capacity volume etc. As a result, preferred engineering site for pilot and demonstration plans were recommended. A deep saline aquifer under a Miocene basin near the western coast of Central Taiwan with estimated storage capacity up to 4 Gt- CO 2 is now regarded as a very high potential storage reservoir with advantages of its high capacity volume, geological stability and the short distance away from the largest emission plants. More detailed investigation will be implemented during the year of 2010 to 2013 including works of site conformation, characterization prior to performing a pilot test with injection depth down to 2500 ∼3000 m. In this paper, the process and methodology of the screening potential reservoir and ranking of preferred engineering site are depicted and furthermore the tentative road map concerning Tai-Power’s CCS technology development for coal- fired power plant is introduced.

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

How to Determine if a Depleted Reservoir is a Candidate for Underground Storage of Natural Gas

Underground storage of natural gas has become a hot commodity. With the proximity of the Appalachian basin to the expanding gas markets of the northeast, and in light of the changes occurring in the natural gas marketplace, the Appalachian basin is deal for developing additional storage capacity. This capacity is needed right now and there is a high potential for additional growth for storage services. This paper examines the criteria used by Equitrans, Inc., in evaluating potential storage reservoirs form the geologic, reservoir engineering, and economic perspectives. It should served as an aid to exploration and production companies in determining whether or not storage is a viable option for depleted reservoirs in which they have an interest.

Studies of the MT simon sandstone as a potential storage reservoir for compressed air : Pincus, H J Proc 22nd US Symposium on Rock Mechanics, Cambridge, Mass, 29 June-2 July 1981, P150–155. Publ Cambridge, Mass: MIT, 1981

Studies of the MT simon sandstone as a potential storage reservoir for compressed air : Pincus, H J Proc 22nd US Symposium on Rock Mechanics, Cambridge, Mass, 29 June-2 July 1981, P150–155. Publ Cambridge, Mass: MIT, 1981