Erik Lindeberg

Vertical convection in an aquifer column under a gas cap of CO2

Abstract The basic equation for volume, heat and CO 2 flux in a porous medium which is subject to both a temperature field and molecular diffusion have been analysed with respect to the stability criteria for convectional vertical flow in a porous medium. This analysis reveals under what condition vertical convection may occur, which is important for the total storage capacity of CO 2 in aquifers.

The Long-Term Fate of CO2 Injected into an Aquifer

Publisher Summary More than 4 million tones of CO2 from the Sleipner gas processing plant has been injected into the Utsira formation in the North Sea and eventually 25 million tones will be injected before gas production has ceased. The CO2 is injected near the bottom of the approximately 200 m thick sand. The migration of injected CO2 is being monitored by 4D seismic, which shows that the CO2 is retained in large thin clouds under what is expected to be horizontal semi-permeable shales within the formation. Assuming that an underground aquifer is capped by a capillary seal, preventing the injected CO2 from migrating into the atmosphere, the CO2 will eventually accumulate under this seal. The topography of the seal will determine the CO2 migration on the 1000 years time-scale. CO2 diffusing into the underlying aquifer column will set up convective currents in the aquifer, enhancing the solution rate of CO2. Most of the CO2 will have dissolved into the aquifer after 5000–50,000 years, mostly dependent on the vertical permeability of the aquifer and the contact area between CO2 and brine. On a time scale of several hundred thousand years, molecular diffusion through the capillary seal will be the dominating transport mechanism and will eventually deplete the formation of CO2 by transporting it into the atmosphere if reactions between CO2 and rock minerals are neglected.

Escape of CO2 from aquifers

Abstract Many large aquifers consist of wide structures only confined by a horizontal cap rock with no distinct traps. By numerical simulations the distribution of injected CO 2 into this type of aquifers has been analysed. The results show that the distribution of CO 2 is controlled by gravity forces and the horizontal permeability just below the cap rock. The escape rate through a possible open periphery or fractures 8000 m from an injection well was simulated. Some of the injected CO 2 will escape from a high permeable aquifer, but the long residence times showed that an effective storage will still be provided in a strategy to combat accumulation of atmospheric CO 2 .

The Quality of a CO2 Repository: What Is the Sufficient Retention Time of CO2 Stored Underground

Publisher Summary This chapter develops a tool to determine the minimum retention time required for underground storage of CO2 if credits should be awarded to an operator of a CO2 injection project. A climate model has been established that relates climate change to escaping CO2 from possible large-scale deposits. The model does not only feature the carbon sinks that are usually accounted for in climate modeling, but also sinks effective on a much longer time-scale—that is, seabed absorption and carbonate rock weathering, which have time-constants of several thousand years. The model has been tested on different escape scenarios with varying residence time and different reservoir performance. The results suggest that the minimum average residence time in the typical reservoirs should be at least 10,000 years if the impact of leaking CO2 on the climate is to be avoided for coming generations. One advantage of storing CO2 underground is that long retention times can be achieved compared to some of the alternative storage options. However, in underground storage, the retention time can vary depending on the quality of the geological seal and the technical solution for the injection scheme. Currently, no generally accepted criteria for qualifying a CO2 depository exists and so far only simple estimates have been suggested on the required residence time.

Towards a methodology for top seal efficacy assessment for underground CO2 storage

Publisher Summary This chapter highlights that the quantitative assessment of leakage risk and leakage rates from planned underground CO 2 storage sites is a primary requirement for public acceptance, formal site approval, and credit for stored CO 2 quantities under CO 2 emission schedules. Leakage through the top seal can basically occur by three processes: diffusion through the pore system, capillary transport through the pore system of the seal, and multiphase migration through a fracture network; or by a combination of any of these. Diffusion results in very low leakage rates; maximum rates typically attained after several 100 000 years, being in the ppm range. Multiphase capillary migration is characterized by two main parameters: capillary breakthrough pressure and effective permeability to the non-wetting phase. The dependence of effective permeability to CO 2 on capillary pressure, which in turn is a function of CO 2 column height, is hysteretic in character with generally higher effective permeability during pressure decrease than during increase, at the same capillary pressure. Leakage is likely to stop at approximately 20 to 50% of the breakthrough pressure as suggested by the snap-off theory. Capillary breakthrough pressure and effective permeability is very difficult to measure for low-permeable rocks.

A large-scale infrastructure model for CO2 disposal and EOR—economic and capacity potential in the North Sea

Publisher Summary This chapter illustrates an injection scenario that includes most of the Norwegian oil reservoirs in the North Sea oil reservoir. In order to elucidate the possibility of combining CO 2 storage with EOR, a techno-economic model for a large scale scheme for CO 2 deposition in Norways North Sea oil provinces has been developed. A CO 2 -transportation module calculates the transportation costs for CO 2 from export terminals to the oil provinces. An EOR module predicts the increased oil recovery due to CO 2 injection in water-flooded reservoirs. In order to convert from a water-injection scheme to CO 2 injection large modifications of the oil production installations are needed. A possible solution for this has been sketched, and the costs for the necessary modifications and new installations for CO 2 injection have been estimated and are also included into the techno-economic model.

An innovative European integrated project: Castor—CO2 from capture to storage

This chapter gives an overview of the CASTOR (CO2, from Capture to Storage) R and D project, funded by the European Union (EU) under the 6th Framework Program. With a partnership involving Industry and Research organizations, CASTOR aims at developing new technologies for post-combustion capture and at studying 4 new European storage sites. The main goal of this project is to develop and validate, in public/private partnerships, all of the innovative technologies needed to capture CO2 at the post-combustion stage and store CO2. The CASTOR R and D target aims to enable the capture and geological storage of 10% of the CO2 emissions of Europe that corresponds to about 30% of CO2 emitted by European power and industrial plants. To achieve this goal, CASTOR would need to improve current techniques and develop, validate, and generalize previously nonexistent methodologies and technologies for the capture of CO2 and its subsequent secure underground storage.

Experimental and Numerical Simulation of CO2 Injection Into Upper-Triassic Sandstones in Svalbard, Norway

Sequestration of carbon dioxide in a saline aquifer is currently being evaluated as a possible way to handle carbon dioxide emitted from a coal-fuelled power plant in Svalbard. The chosen reservoir is a 300 m thick, laterally extensive, shallow marine formation of late Triassic-mid Jurassic age, located below Longyearbyen in Svalbard. The reservoir consists of 300 m of alternating sandstone and shale and is capped by 400 meter shale. Experimental and numerical studies have been performed to evaluate CO2 storage capacity and long term behaviour of the injected CO2 in rock pore space. Laboratory core flooding experiments were conducted during which air was injected into brine saturated cores at standard conditions. Analysis of the results shows that the permeability is generally less than 2 millidarcies and the capillary entry pressure is high. For most samples, no gas flow was detected in the presence of brine, when employing a reasonable pressure gradient. This poses a serious challenge with respect to achieving viable levels of injectivity and injection pressure. A conceptual numerical simulation of CO2 injection into a segment of the planned reservoir was performed using commercial reservoir simulation software and available petrophysical data. The results show that injection using vertical wells yields the same injectivity but more increases in field pressure compare to injection through horizontal wells. In order to keep induced pressure below top-seal fracturation pressure and preventing the fast propagation and migration of CO2 plume, slow injection through several horizontal wells into the lower part of the “high” permeability beds appears to offer the best solution. The high capillary pressure causes slow migration of the CO2 plume, and regional groundwater flow provides fresh brine for CO2 dissolution. In our simulations, half of the CO2 was dissolved in brine and the other half dispersed within a radius of 1000 meter from the wells after 4000 years. Dissolution of CO2 in brine and lateral convective mixing from CO2 saturated brine to surrounding fresh brine are the dominant mechanisms for CO2 storage in this specific site and this guarantees that the CO2 plume will be stationary for thousands of years.

The Atzbach-Schwanenstadt gas field—a potential site for onshore CO2 storage and EGR

As a part of the EU-supported CASTOR project, four sites for potential or actual underground CO2 sequestration in Europe are being investigated. One of these sites is Atzbach-Schwanenstadt gas field in Upper Austria, operated by Rohol-Aufsuchungs AG. The CASTOR project is a feasibility study which aims:

CO2 from industrial sources as injection gas in oil reservoirs

A study of CO2 injection into an oil reservoir on the Norwegian Continental Shelf has been conducted. With a numerical reservoir simulator a production profile from a scenario where the reservoir pressure is maintained by displacing oil with CO2 has been performed on a three dimensional reservoir model using reservoir properties measured in the laboratory. The forecasted production profile was compared to the profile that was obtained when CO2 was substituted by water. The simulations showed that considerably more oil could be recovered with CO2 injection, approximately 60% of original oil in place, compared to approximately 40% by water injection. A technical/economical evaluation of CO2 separation from industrial sources, transport and injection into oil reservoirs has also been made. The results show positive economics only when some sort of CO2 tax avoidance is imposed on the source which alternatively would release CO2 into the atmosphere.