An operations perspective on injectivity and capacity

Injectivity and capacity are two of the most important criteria during the screening and selection process of a CO2 storage site. A geologic formation can be characterized directly to quantify injectivity and capacity via the permeability-thickness and porosity-thickness products, respectively. Afte... Full description

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Authors:Frailey, S.M.; Okwen, R.T.; Yang, F.
Volume Title:Greenhouse gas control technologies conference 14
Source:Greenhouse Gas Control Technologies Conference, Vol.14, 14p.; Greenhouse gas control technologies conference 14, Melbourne, Victoria, Australia, Oct. 23, 2018. Publisher: International Energy Agency's (IEA) Greenhouse Gas R&D Programme, varies, International
Publication Date:2018
Note:In English; illus., incl. 1 table
Subjects:Carbon dioxide; Carbon sequestration; Darcy's law; Equations; Fluid injection; Petroleum engineering; Real-time methods; Storage
Record ID:2020050465
Copyright Information:GeoRef, Copyright 2020 American Geosciences Institute.
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Injectivity and capacity are two of the most important criteria during the screening and selection process of a CO2 storage site. 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 are slightly different. During active injection operations, maintaining injectivity is one of the primary challenges, while one of the primary challenges to the storage project is the long term storage capacity. However, for specific projects, the daily injection rate of CO2 and the ultimate storage quantity desired will be based on the capture and compression facility, and the CO2 source will be the drivers 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 (at the midpoint of the injection interval) and the reservoir, which is proportional to the permeabilitythickness product. Because rate and pressure are generally direct measurements, compared to permeability-thickness (which ideally includes relative permeability), injectivity-time, injectivitypressure, injectivity-cumulative injection, and injectivity-rate relationships can be used to diagnose trends in injection operations that are not apparent from injection rate alone. Prior to flow testing, petrophysical properties derived from well logs and/or core analyses can be used to estimate injectivity, but are rarely a substitute for in situ flow tests. Prior to CO2 injection, water production and injection tests are reliable for injectivity estimates. However, the simplicity of these tests and project logistics may lead to complacency, assumptions, and misguided priorities, such that the test results do not support project goals. Ideally, more than one subinterval within the geologic formation will be tested, and the test will include multiple rates and flowing pressures that use relatively precise pressure gauges and flow meters. The tests can be combined with drilling operations (e.g. drill stem tests and closed chamber tests), well completion procedures (e.g. perforation work), and permit required tests (e.g. step rate test for fracture pressure). The initial start-up of CO2 injection, and subsequent start-ups following short and extended shut-in periods are ideal times for multirate CO2 injection tests, which if performed periodically shows injectivity behaviour over longer periods of time. Thus, trends of the injection interval response can be analysed and projected for longer terms when a stimulation may be required or another sub-interval perforated for injection. Capacity is defined as a quantity (mass or volume) of CO2 that can be injected and stored in a specific geologic formations from a specific injection project; it is proportional to porosity-thickness product. Although not part of the capacity calculation, both permeability and capillary pressure properties determine the accessibility of the porosity to injected CO2, hence the part of the pore space that can be used for CO2 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. Storage efficiency can include 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 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 CO2 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 impedance contrast, a seismic survey may be helpful but will be limited to detect only the thicker and higher CO2 saturation part of the plume. Underlying the concepts and analyses of this study is that not all porosity and permeability is "created equal". For example in the presence of 100 milliDarcy permeability, 10s of milliDarcy permeability is injectable; however, in the presence of Darcy-scale permeability, 10s of milliDarcy permeability rock will be "seen" by the injection well as impermeable. Likewise, in the presence of coarse grain sands, fine grain sand with similar porosity may not contribute to capacity due to relatively high capillary pressure. Real-time analyses of injectivity and capacity during CO2 injection can provide operators with information necessary to plan for contingencies that increase certainty that they can meet the CO2 project goals through the life of the project. During site screening and selection project risk can be reduced, but only after actual CO2 injection can these properties be more convincingly estimated. Results and observations from the US Department of Energy sponsored Illinois Basin Decatur Project and Illinois Basin-Industrial Carbon Capture and Storage Project at Decatur, Illinois, USA, are used to demonstrate changes in injectivity and capacity through time and their influence on operations.