Injectivity index: a powerful tool for characterizing CO₂ storage reservoirs—a technical note

Abstract

Injectivity index is a powerful tool that can be easily calculated from field injection and pressure data. Theoretically, injectivity index is linked to reservoir properties such as permeability, thickness of pay, and size of the reservoir. Consequently, injectivity index data can serve as a powerful tool to assess changes in reservoir quality and performance. In this article, we have looked at field data from notable global carbon sequestration projects in order to identify a correlation between injectivity index (J) and the product of reservoir permeability and thickness (kh). Results suggested that there is a linear relationship between J and kh with field data confirming to lower and upper bounds of J = 0.03×kh and J = 0.23×kh respectively. Average trend was calculated to be J = 0.08×kh. This correlative approach can be extremely beneficial when there is a need to estimate pressure buildup corresponding to a target injection or vice versa. The approach can also be used to understand reservoir flowability and performance at a broader scale prior to the need for expensive or time consuming flow and pressure transient testing.

Well Injectivity during CO2 Geosequestration: A Review of Hydro-Physical, Chemical, and Geomechanical Effects

“…Formation permeability and thickness are the first order variables impacting pressure buildup . In fact, there is a direct relationship between injectivity index (eq ) and the product of formation thickness and permeability ( kh ) and the zones benefiting from higher kh are more desirable targets for CO 2 storage as the commercial rates of CO 2 injection can be obtained by fewer number of injection wells. ,, Note that well interface plays a key role in high-permeability formations and increasing the number of wells over a certain threshold does not necessarily impact the CO 2 injectivity…”

“…Figure shows the PFO analysis of the injection of CO 2 in the Tubåen Formation, where four shut-ins were selected based on a long and stable injection period of more than 250 h. Valuable data were inferred from the analysis of drying-out effects on wellbore injectivity. , As the injected CO 2 is in the supercritical state, liquid well testing analyses can be applicable to CO 2 PFO. To date, however, there are limited number of studies providing a proper methodology for interpretation of PFO data in analyzing the fracturing risks in injection wellbores .…”

“…In terms of CO 2 sequestration in deep saline aquifers, monitoring the pressure-build-ups observed in a well is a common approach to assess the influences of CO 2 injection on the features of porous media (see section ). Injectivity index, described by eq , has also been suggested as a useful concept to evaluate wellbore capability to inject fluids into a permeable reservoir: , The present study aims to identify the knowledge gaps through reviewing the major factors contributing to CO 2 injectivity in deep saline aquifers. Moreover, the models proposed to estimate maximum sustainable injection pressure and pressure build-up are critically reviewed, and the existing shortcomings requiring further research and development are discussed.…”