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Abstract: Coupled simulations of fluid injection and extraction in porous media are an important tool for assessing feasibility, safety and productivity of such operations. Different methods for coupling the fluid flow with geomechanics are currently used. In this paper we compare one-way and iterative coupling with full coupling. With the fully coupled two-phase thermo-poromechanical model we simulate the CO2 injection operation, which is ongoing at In Salah, Algeria. The results suggest that pressure increase in the well and ground uplift for a given data set can accurately be modeled using our method. Finally, we illustrate the crucial effect of the temperature difference between injected fluid and reservoir on the possibility of creating and/or re-opening fractures perpendicular to the well in the cap rock that were observed in the field. [Copyright &y& Elsevier]

Abstract: In Salah Gas Project in Algeria has been injecting 0.5–1 million tonnes CO2 per year over the past 5 years into a water-filled strata at a depth of about 1800–1900m. Unlike most CO2 storage sites, the permeability of the storage formation is relatively low and comparatively thin with a thickness of about 20m. To ensure adequate CO2 flow-rates across the low-permeability sand-face, the In Salah Gas Project decided to use long-reach (about 1–1.5km) horizontal injection wells. In an ongoing research project we use field data and coupled reservoir-geomechanical numerical modeling to assess the effectiveness of this approach and to investigate monitoring techniques to evaluate the performance of a CO2 injection operation in relatively low-permeability formations. Among the field data used are ground surface deformations evaluated from recently acquired satellite-based inferrometry (InSAR). The InSAR data shows a surface uplift on the order of 5mm per year above active CO2 injection wells and the uplift pattern extends several km from the injection wells. In this paper we use the observed surface uplift to constrain our coupled reservoir-geomechanical model and conduct sensitivity studies to investigate potential causes and mechanisms of the observed uplift. The results of our analysis indicate that most of the observed uplift magnitude can be explained by pressure-induced, poro-elastic expansion of the 20-m-thick injection zone, but there could also be a significant contribution from pressure-induced deformations within a 100-m-thick zone of shaly sands immediately above the injection zone. [Copyright &y& Elsevier]

Abstract: The Krechba field is one of several gas fields located in the Algerian Sahara desert, and was set in operation in August 2004 as part of a joint venture with BP, Sonatrach and StatoilHydro. The natural gas in the fields contains up to 10% CO2, which has to be reduced to 0.3% before the gas is sold, resulting in the production of around 1 million tonnes/year CO2. Rather than vent the CO2 to the atmosphere (business as usual), it is re-injected into the water leg of the Krechba Carboniferous Sandstone gas producing reservoir (20 m thick) via three horizontal wells at a depth of around 1,900 metres. CO2 injection started in August 2004 and to date nearly 2.5 million tonnes of CO2 have been injected, amounting to approximately 25% of the gas extracted from the Krechba field over the same period. A number of key technologies to monitor the injection, and the subsurface movement and storage of CO2 have been, and will continue to be, deployed to provide long term assurance of sequestration. Time lapse satellite images (using PSInSARTM Technology) which measure ground deformation to assess the movement of CO2 in the subsurface have proven to be much more successful than initially thought, despite the depth of injection and the low voidage replacement rate (25%). Satellite images collected since start of injection show clear increases in ground elevation of up to 30mm around the three injectors while subsidence is also apparent in the area of maximum gas production. The images have also confirmed the CO2 is moving in the direction of preferred fracture orientation at reservoir level. Recent downhole pressure measurements in one of the injectors also indicates that the CO2 is being contained within the injection horizon. Work is ongoing to integrate the satellite images with geomechanical and seismic data to better understand how these images can be used for monitoring of CO2 movement in the subsurface. A key part of the forward monitoring programme will be the acquistion of time-lapse 3D seismic, deployment of tiltmeters and GPS to confirm and calibrate the satellite imagery data, microseismic detectors in shallow boreholes to assess the degree of rock strain and use of shallow wells to monitor the water chemistry in the vadose zone. These will supplement the ongoing tracer, wellhead sampling and satellite imagery data acquistion. This paper shares the latest results of the ongoing CO2 monitoring project. [Copyright &y& Elsevier]

Abstract: In Salah Gas Project in Algeria has been injecting nearly one million tonnes CO2 per year over the past four years into a water-filled strata at a depth of about 1,800 to 1,900 m. Unlike most CO2 storage sites, the permeability of the storage formation is relatively low and comparatively thin with a thickness of about 20 m. To ensure adequate CO2 flow-rates across the low-permeability sand-face, the In Salah Gas Project decided to use long-reach (about 1 to 1.5 km) horizontal injection wells. In this study we are using field data and coupled reservoir-geomechanical numerical modeling of CO2 injection to analyze geomechanical responses and to assess the effectiveness of this approach for CO2 storage in relatively low permeability formations. Among the field data used are surface deformations evaluated from recently acquired satellite-based inferrometry (In SAR). The In SAR data shows a surface uplift on the order of 5 mm per year above active CO2 injection wells and the uplift pattern extends several km from the injection wells. We use the observed surface uplift to constrain our coupled reservoir-geomechanical model. We conduct sensitivity studies to investigate potential causes and mechanisms of the observed uplift. Preliminary results of our analysis presented in this paper indicates that most of the observed uplift magnitude can be explained by poro-elastic expansion of the 20 m thick injection zone, but there could also be a significant contribution from pressure changes within the adjacent caprock. Moreover, we show that surface deformations from In SAR can be useful for tracking the fluid pressure and for detection of a permeable leakage path (e.g. in a permeable fault) through the overlying caprock layers. [Copyright &y& Elsevier]