Storage site analogues and experimental investigations provide quantification of processes occurring during the life of subsurface CO2 capture, and possible escape mechanisms. Analogue investigation provides information at the scale of the storage sites under unique geological conditions and time frames. Experimental investigations under controlled conditions provide detailed data on specific processes observed in analogue sites. St Johns, NM, USA, is a natural laboratory which presents an opportunity to observe measure and model the migration of CO2 through a primary cap-rock and subsequent overburden at geological conditions analogous to the above-seal portions of planned CO2 storage sites. The Fizzy gas reservoir, North Sea, and other reservoirs in the North German Basin (Behrmann et al. 1981) are excellent examples of secure natural CO2 storage sites. By comparing in detail how the cap-rock at St. Johns was breached and the CO2 subsequently migrated to the surface and contrasting how the CO2 has been retained at Fizzy will provide insights on how to avoid for cap-rock failure and how to monitor engineered storage sites. The thermo-tectonic development of the St. Johns and Fizzy analogue sites, i.e. the fluid mobility and compositional variability with time, can be reconstructed on the basis of petrological and fluid inclusion studies, combined with cathodoluminescence (CL) techniques and microstructural analysis (healed microfractures). The changing stress conditions with time are important parameters for the conditions of crack-healing processes and the mechanical stability of the cap rock. Detailed petrological studies allow distinguish carbonate and quartz cement generations, and microstructures related with fluid-rock interaction, like fluid pathways, paleo-porosity, diffusional textures, and healed micro-fractures (Van den Kerkhof and Hein, 2001).  Fluid inclusions reflect fluid migration, notably of CO2-H2O-bearing fluids through the cap rock. Fluid inclusions inform about temperatures and pressures during trapping. By comparing past and present gradients, conclusions can be drawn about uplift or subsidence of the area since the time of fluid entrapment. Furthermore, fluid inclusions allow the comparison of paleo-fluids with present pore and circulating fluids, to establish the deformational evolution of the rock (Vollbrecht et al., 1994; Schild et al. 1998).  Chronology of paleo-stress directions can be derived from the compiled structural data (Schmidt net).

PANACEA has established a number of valuable connections with organizations that are actually involved in the process of CO2 storage for various purposes (disposal, EOR/EGR and scientific prototyping). It has also created a link with one NER300 project.

This CO2 reservoir is characterized by a large anticline at depth forming the trapping structure, surface seepage and evidence of surface carbonate build-up in the form of travertines as a result of the migration of CO2 rich fluids to the surface. Hence, it provides one of the best natural analogues for a failed CO2 storage site in the world. The CO2 in the St. Johns Dome reservoir is contained in the Permian Supai Formation, which is a fine grained alluvial sandstone intercalated with siltstone, anhydrite and dolomite. The reservoir is dissected by a steeply dipping northwest-southeast tending major fault, named the Coyote Wash fault. The cap rock consists of impermeable anhydrites which vertically separate the CO2 into multiple zones. The reservoir is relatively shallow at 200 – 700 m and the CO2 is present in a gas state. The average reservoir porosity is 10% and permeability varies widely from 0.5 to 100 mD, averaging 10 mD.

Previous research at St. Johns has built up a comprehensive background of the geology and structure of the reservoir. Several short projects have been undertaken at the University of Edinburgh on modelling the flow of CO2 to the surface. Recent work on the noble gas and stable isotope composition of the CO2 contained within the reservoir has confirmed a magmatic origin of the CO2 (Gilfillan et al., 2008), most likely related to the igneous activity generated during eruption of the nearby Springerville Volcanic field. This volcanic field is one of many late Pliocene to Holocene, predominantly basaltic, volcanic fields which surrounds the southern margin of the Colorado Plateau. Hence, it is believed that a portion of the CO2 has been stored for at least 0.3 Ma and evidence from the noble gas data indicates the primary means of CO2 storage within the reservoir is via CO2 dissolution into the formation water (Gilfillan et al., 2009). However, a small amount of dawsonite has also been found in a portion of core from one well from the St. Johns Dome CO2 reservoir(Moore et al., 2005). This along with kaolinite represents the youngest pore-filling material, with dawsonite forming 5 to 17 wt.% of the rock (Moore et al., 2005) and indicates that some mineralisation related to the presence of CO2 has occurred. Through drilling investigation and coring carried out by Ridgeway Petroleum (now Enhanced Oil Resources) we have a collection of a wide range of samples from two wells in Edinburgh, representing different strata from the site. This includes caprock and reservoir rock.

 

The Fizzy field analogue is located in the southern sector of the UK North Sea. It has contained large quantities of CO2 (over 50% of the gas contained in the field is CO2) over geological timescales. The Permian Rotliegend Group reservoir rock is similar in age and character to that of St. Johns and the field is overlain by Zechstein halite evaporites, again analogous to the anhydrite that overlies St. Johns.

Core samples are available from two wells drilled in the Fizzy Field, one from the gas zone and one from the water zone. This is currently held in the BGS core store in Edinburgh. The reservoir is 2300m deep, 80-100m thick and currently at a temperature of 80-85 °C. The tectonic history of the area is complex, with the region having undergone at least two separate episodes of uplift that disrupted sedimentation.
Recent research at Edinburgh has documented trace amounts of dawsonite (0.4 ±  0.3 % solid rock volume) and that up to 0.7 (± 2%) of the dolomite cement can be attributed to CO2. This indicates that only 5 to 30% of the CO2 has been trapped via mineral sequestration (Wilkinson et al., 2009).

Sleipner is located in the very middle of the North Sea. It consists of several production platforms in 80 meter of water, producing natural gas and some light condensate. The produced natural gas contains 9% CO2. It has to be extracted and around 1 million tonne CO2 has been removed per year since 1996. After condensation it is injected through one injection well. The behaviour of the CO2 in the reservoir 1000 m below sea bottom has been monitored regularly and with a set of different monitoring methods. International R&D cooperation has been analyzing the gathered data. Results have been published and is available at www.co2store.org book for “Best practice Manual” under page “Archive”. See also at statoil.com announcement.

Snohvit is located on the border line between the North Atlantic and the Barents Sea, 300 km off the Norwegian coast. It is a gas field where all production equipment is installed on the sea bottom at a depth of 350 m. From the Snohvit field a multiphase pipeline transports all well fluids (natural gas condensate and water) to shore. On the Melkoya island, near Hammerfest, the natural gas is being processed into LNG – Liquefied Natural Gas and exported by ship. Before cooling the gas, the CO2 has to be removed and the resulting 0.75 million tonne CO2 is being transported back to the Snohvit field and injected through a sub-sea well more than 2000 m below the sea-bottom. Injection has started in 2008. Also this injection has been monitored by a set of methods. Early results have been published in international literature and conferences. See also: statoil.com article.

In Salah, situated in the middle of Algerian Sahara collect natural gas from several fields and process it at Krechba since 2004. Among  other things about 1 million tonne of CO2 is being removed per year and injected more than 2000 m below the surface in 3 wells. Together with Sonatrac and BP an extensive R&d program is in progress. Preliminary results have been published (See this link).

Maguelone shallow depth site aimed principally at testing and prototyping novel monitoring technologies. With a set of 10 nearby holes deployed at shallow depth (< 25 m), the Maguelone experimental site will be the first one to enable one to conduct precise and high resolution coupled experiments conjugating in a cost-effective manner geophysical, geochemical and hydrodynamic monitoring methods, both from surface and downhole, either in a continuous or in a time-lapse mode.

A heavily instrumented large scale CO2 injection experiment will be carried out in 2012-13, in order to evaluate field scale coupled process integrity of the caprock and the response of the reservoir rock in terms of heterogeneities. The site will comprise three wells: an injection well, a geophysical monitoring well and a hydro-geochemical sampling well. The CO2 will be injected in a dolomitised level of a dome-like structure located at a depth of approximately 1450 m. Data to be gathered data will include: 3D geo-electrical and full wave-field seismic data, pressure, temperature and mechanical deformation data from storage and seal formations, and fluid samples at 5-6 different depths. Several hydro-geochemical characterization experiments will be carried out, including conventional hydraulic tests (high pressure, high flow rate, water injection tests) and CO2 storage specific tests (push-pull tests using brine or CO2 and both reactive and inert tracers).

Most large-scale (industrial) CO2 injection sites have very limited down-hole monitoring equipment, often limited to sensors to measure injection pressure and temperature, and sometimes seismic sensors. More detailed data is only available for a very limited number of experimental CO2 injection sites (i.e. Ketzin, Frio, Cranfield), and data from CO2 injection into carbonate reservoirs is particularly scarce.

Otway is an experimental injection site in which 65,000 tons of CO2 have been injected to date as stage 1. At present have some sub surface storage experiments being established and expected to run April to June/July, 2011. Then there will be a larger injection of 5-10K ton after that. This project is expected to run for several more years.

The Heletz structure is a depleted oil field, which is penetrated by a relatively large number of wells over a rather small area (~10 km2). This is the site of the MUSTANG CO2 injection experiment, which should be conducted during the beginning of 2012. This is a highly controlled experiment in which novel completion approaches are implemented and a large number of MMV technologies will be tested The CO2 injection experiment, planned in the frame of the EU funded MUSTANG project, is to be conducted at the first quarter of 2012. It is a highly controlled experiment consisting comprising two wells: an injection well (a well to be re-entered) and a monitoring well (to be drilled). Injection will occur in sandstone formations of a depleted oil field, containing brine. Instrumentation will allow for continuous measurement of pressure and temperature at both wells, down-hole fluid sampling (one at injection well and 5 at monitoring well), optical fibre for continuous temperature measurement, down-hole geophones at both wells for cross-hole seismic analysis and above the ground seismic surveys. First a number of hydraulic and tracer tests will be conducted for the characterization of the relevant hydraulic and transport properties and for estimating the impact of heterogeneity. Then two CO2 injection tests will be conducted: 1) a single well push-pull experiment of CO2 and water and 2) a dipole experiment of (injection at injection well and pumping at monitoring well) consisting in the sequential injection of CO2 and water. The objectives of the experiment are: 1) determine field-scale value of the main trapping mechanisms (dissolution and capillary trapping); 2) their dependence of heterogeneity; 3) form a consistent and comprehensive dataset to be used for model validation and verification.

The Weyburn-Midale Project is a combination of the world’s largest commercial CO2-enhanced oil recovery storage (CO2-EOR) operations and the world’s largest CO2 monitoring and storage research program.

Cenovus Energy started the Weyburn CO2-EOR project in 2000; Apache Canada began injecting into the adjacent Midale field in 2005. Both projects use CO2 from the Dakota Gasification Company in the USA, which is transported by a 325-km pipeline to the Weyburn-Midale site. Approximately 2.8 Mt of CO2 per year is currently being injected and over 19 Mt has been stored to date. A total of over 40 Mt will have been stored when the operations end in 2035.

The IEAGHG Weyburn-Midale CO2 Monitoring and Storage Project has been studying the injection of CO2 into the underground storage reservoir and monitoring the behaviour of the CO2 plume since injections started in 2000. The project’s technical work is focused on developing monitoring, measuring and verification methods that help to confirm the safety and efficacy of CO2 storage, demonstrate the integrity of the injection wells and the storage reservoir, and determine the information needed to increase our understanding of and confidence in risk assessments and storage mechanisms.

The key deliverable, due in the autumn of 2011, will be a Best Practices Manual for the design, implementation, monitoring and verification of CO2 geological storage projects worldwide, as well as to influence and accelerate good public policy development for storage regulations and public communications and outreach. Over 35 individual research projects encompass the overall research effort. These are undertaken by highly-reputed research scientists, engineers, geologists and geophysicists from 30 different Canadian and international universities, research councils, geological surveys and consultancies. A consortium of six governments and 10 international energy companies is providing the funding for the final phase of this $41-million research project.

The Brazil Oil company (Petrobras) started injecting high-pressure CO2 in 2009 into the Miranga onshore field, in the municipality of Pojuca, state of Bahia, to test technologies that may contribute to future development projects for the Santos Basin's Pre-Salt cluster. The CO2 produced at the future pre-salt fields is injected back into the reservoirs to boost the recovery factor. The Miranga field project foresees the geological sequestration and removal of 370 tons of CO2/day. In addition to the environmental gains, the technology to be applied will considerably increase the recovery percentage of the oil nestled in that field's reservoir. This project is used as a proving ground for new technologies that might be applied to other fields to be developed in Brazil, particularly in new pre-salt discoveries, since the reservoirs there have shown the presence of natural CO2 associated to the oil. The Miranga field was selected for the tests on account of its geological characteristics and existing logistics available at the site. The technique to be used in Miranga is based on injecting CO2 under high pressures. In this case, the CO2 works like a type of solvent that changes the properties of the oil.