An Operations Perspective on Injectivity and Capacity
14 Pages Posted: 4 Apr 2019 Last revised: 27 Oct 2020
Injectivity and capacity are two of the most important criteria of a CO2 storage site’s screening and selection process. A geologic formation can be characterized directly to quantify injectivity and capacity via the permeability-thickness and porosity- thickness products, respectively. After a project starts, the importance of each to the project is slightly different. Maintaining injection rate is one primary challenge during active injection operations, while the long-term storage capacity is one primary challenge to the storage project. For specific projects, the daily injection rate of CO2 and the ultimate storage quantity desired are based on the capture and compression facility, and the CO2 source is the driver to determine the mandatory qualifications of a site.
Injectivity is defined as the ratio of the injection rate to the pressure change between the well and the storage zone, which is proportional to the permeability-thickness product. The initial start-up and subsequent start-ups of CO2 injection following short and extended shut-in periods are ideal times for multirate CO2 injection. These injection tests performed periodically can show injectivity behavior over longer periods of time so that the trends of the injection interval response can be analyzed and projected for longer terms when a stimulation or another sub-interval perforation may be required for injection. Because rate and pressure are generally direct measurements, injectivity-time, rate-pressure-time, and rate-pressure relationships can be used to diagnose trends in injection operations that are not apparent from injection rate alone.
Capacity is defined as a quantity (mass or volume) of CO2 that can be injected and stored in a specific geologic formation from a specific injection project; it is proportional to porosity-thickness product. While permeability and capillary pressure are not part of the capacity calculation, both properties determine the accessibility of the porosity to injected CO2, hence the part of the pore space that can be used for storage. Furthermore, local geologic heterogeneity and architecture will strongly influence petrophysical flow properties and determine the plume size and shape. Storage efficiency has been used to define the fraction of the pore volume (or bulk volume) in which CO2 can be stored. It includes geologic (e.g. ratio of net to gross thickness), macroscopic (e.g. gravity), and microscopic (e.g. saturation) terms.
It is relatively simple to quantify capacity if the location and distribution of CO2 is not required; however, if approximate dimensions of CO2 plume is necessary, it is very difficult to quantify confidently capacity. Prior to CO2 injection, statistical methods, numerical simulation, and a limited number of analytical methods are available. During injection, the most direct measurement is cased hole logging (e.g. neutron capture logs), which only measures very near wellbore CO2 saturation above a threshold saturation (e.g. 5%). Once the CO2 plume area, thickness, and saturation are adequate to make a detectable seismic contrast, a seismic survey may be helpful, but it detects only the thicker and higher CO2 saturation parts of the plume.
Real-time analyses of injectivity and capacity during CO2 injection can provide operators with information necessary to plan for contingencies that increase certainty and meet the CO2 project goals. During site screening and selection, project risk can be reduced, but only after actual CO2 injection can these properties be more convincingly estimated.
Injection operation results and observations, from the US Department of Energy sponsored Illinois Basin Decatur Project at Decatur, Illinois, USA, are used to demonstrate changes in injectivity and capacity through time and their influence on operations.
Keywords: CO2 injectivity, GHGT-14
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