The ultimate success of carbon capture and storage project will be ensured only when there is a safe and effective permanent storage of CO₂ for a significant amount of time without any leakages. Credible monitoring and verification is one of the most important aspects of CO₂ sequestration. Accurate reservoir characterization is an important pre-requisite for the design, operation and economic success of processes like CO₂ sequestration. The techniques available include geophysical and geochemical monitoring as well as numerical simulations using models replicating the field. In conducting the numerical simulations, it is required to assess the reservoir heterogeneity correctly. Previous work has shown that the injection data from wells can be utilized for developing models during CO₂ sequestration to understand the spatial distribution of heterogeneities in the formation. In this research, we first understand and examine the information contained in the injection data for a wide range of reservoir models demonstrating different kinds of heterogeneities and rate fluctuations. We will confirm that the reservoir heterogeneities have an imprint on the injection pressure response and they influence CO₂ plume migration significantly. Later we show that the effect of high or low permeability features along with rate fluctuations can provide considerable information about permeability heterogeneity in the reservoir. The applicability of this observation is made using field data from In-Salah gas field from central Algeria. Thus we demonstrate the feasibility of developing an inexpensive method of modeling reservoir heterogeneity by employing readily available measurements of injection pressure and rate to track CO₂ migration. Later we describe method to find out what characteristics of the reservoir heterogeneities can be quantified using injection data (pressure and rate). The injection pressure response during CO₂ sequestration will depend strongly on reservoir, fluid and well properties. A 3-D analytical model with infinite acting boundary is developed in CMG-GEM. Compositional reservoir simulation results from CMG-GEM simulator will be obtained and combined with pressure transient analysis and optimization algorithm for the prediction of reservoir parameters. In case of multiple injection wells in a heterogeneous formation, the analysis yield spatial variations in reservoir parameter groups like transmissibility (kh), permeability to porosity ratio ([kappa]/[phi]) in different part of the reservoir. These parameter groups can subsequently be used to constrain models of reservoir thickness, permeability and porosity. Thus, we imply that multiple reservoir attributes affect migration of CO₂ plume and there is uncertainty associated with the estimation of these attributes. We present an approach to resolve some of that uncertainty using information extracted from injection well response. / text
| Identifer | oai:union.ndltd.org:UTEXAS/oai:repositories.lib.utexas.edu:2152/20021 |
| Date | 24 April 2013 |
| Creators | Punase, Aarti Dinesh |
| Source Sets | University of Texas |
| Language | en_US |
| Detected Language | English |
| Format | application/pdf |
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