|Publisher||Society of Petroleum Engineers||Language||English|
|Content Type||Conference Paper|
|Title||CCS Project in a gas field of the Sbaa basin, SW Algeria - What is at stake?|
Y. Mossé, E. Portier, and T. Schaaf, GDF SUEZ
North Africa Technical Conference and Exhibition, 14-17 February 2010, Cairo, Egypt
2010. Society of Petroleum Engineers
|6 Reservoir Description and Dynamics
6.5 Reservoir Simulation
GDF SUEZ and Sonatrach will develop in partnership the main fields of the prolific Sbaa basin, SW Algeria. In this basin, the main gas levels comprise the Cambrian and Upper-Ordovician reservoirs, sealed and sourced by the Silurian “Hot Shales” Formation. Average CO2 content of raw gas is in excess with regard to sales gas specifications. As a result, CO2 removal is required as part of gas treatment and it is intended to install an amine unit in the future Central Processing Plant for such purpose. Regeneration of the amine results in the release of significant quantities of CO2, which amounts to ca 1200 t/day. Looking for a solution to re-inject underground this CO2 was decided, within the project exploitation perimeter. Such an initiative has materialized with the achievement of a screening and feasibility study during the development conceptual phase, which identified the two best structures for underground CO2 sequestration. In both cases, CO2 should be re-injected in the aquifer, in the water leg, away from gas production area. A pilot well will be drilled to address the geological and reservoir uncertainties, so as to validate the concept.
For now, preparatory sensitivity studies, using Cougar® software (developed and marketed by IFP) were performed to identify key parameters controlling the CO2 re-injection performance. These probabilistic results show that, if effective permeability and reservoir heterogeneity are from far the main drivers, the mobility of fluid in place, such as gas or formation water, strongly controls the performance, ranging from 55 to 98 % of CO2 to be injected. Based on experimental design type of approach, this study enable to rank the main uncertain parameters (such as type of wells, number of injectors and maximum operating pressure) and to quantify their respective contribution to the underground CO2 storage performance.
This type of study helps to determine the priority in the data acquisition program of the future pilot well and to set-up the basis of design of the CO2 sequestration facility.
Geological sequestration of CO2 is one of the foreseen solutions envisaged to reduce significantly the atmospheric concentration of this greenhouse effect gas. CCS projects (CO2 capture and sequestration) propose a challenging approach that could lead to a major first step in reducing anthropogenic emissions of CO2. Like some other companies with several ongoing projects, GDF SUEZ is one of the leaders to develop such technology in a near future (Mulders et al, 2008 and Saysset et al., 2006).
The context of this CCS project in Algeria is the removal of the CO2 in excess, from the raw hydrocarbon produced and its injection and retention within the water leg of a producing gas field. The total amount of CO2 to be re-injected corresponds to 3.60 Gsm3 approximately over the whole project duration. Even if efforts have been made to develop this technology for several years, modellization of geological, chemical and physical processes at stake is still the subject of R&D investigations. Main issues to be addressed are various, dealing with well injectivity, performance sustainability, well and storage integrity, short to long term monitoring. The most suitable solutions have to be selected and adapted to the specificity of the project, long in advance. In the G&G domain, sensitivity studies are required to identify key parameters on CO2 storage performance and improve the level of prediction. A screening study was first performed to identify the best candidates for CO2 re-injection among all candidates’ gas fields. The 6 main criteria chosen to rank the fields were: -storage capacity – cap rocks quality – reservoir injectivity – type of fluid originally in place – reservoir depth – distance to the treatment surface facility. At the end of the process, a small field, 4km² area, but with an important vertical relief (300m), was selected (Figure 1). The main reservoir presents high petrophysical properties with porosities and permeabilities up to 20% and 1000 mD respectively, within the Cambro-Ordovician sands. The choice was made to re-inject the CO2 within the water leg in order to not interfere with the gas production at top of the field. However, reservoir parameters of the dynamic model are not fully characterized in this part of the field, far away from any existing wells, and then it makes necessary to cope with a lot of uncertainties.
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