Laboratory Study Focuses on Formation-Damage Concerns With CO2 Injection for Carbon Storage
Chris Carpenter_
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 230571, “Formation-Damage Concerns and Laboratory Considerations With CO2 Injection in Carbon-Storage Wells,” by Melissa J. Martin, SPE, Stephen Drylie, SPE, and Jonathan Antia, SPE, Core Laboratories, et al. The paper has not been peer‑reviewed.
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As interest in carbon capture and storage continues to grow, evaluation of the effect of CO2 injection on the reservoir is increasingly important. Among various technical challenges faced in this effort, formation damage is a critical factor influencing reservoir integrity and long-term injectivity. The complete paper presents laboratory testing methods and evaluation criteria designed to improve understanding of both the origin and extent of formation damage associated with CO2 injection.
Background
The work described in this paper is part of a broader study investigating important considerations for CO2 sequestration. Initial research efforts focused on evaluating seal properties and methods for determining entry pressure. As part of this effort, samples from four carbon capture, usage, and storage reservoir seals and one proxy formation were exposed at static conditions to CO2-saturated brine at 150°F and 1,500 psi for periods of 1, 3, and 6 months. Various diagnostic methods were employed, including thin-section description and high-pressure mercury injection with little evidence of rock-property change even in the carbonate-dominated formation.
When injection zones were evaluated the following year, flowing exposure was added to mimic reservoir conditions, increase the potential for reaction, and introduce the possibility of other damage mechanisms such as fines migration. Further characterization was also added to this phase of the study. Relative permeability results have been discussed in previous publications. Static exposure for 1 and 3 months also was incorporated to permit the broad scope of a full geomechanics study on reacted samples.
Samples
Because of the large number of samples required and a desire to ensure consistent starting material for each test series, quarry rock samples were used in this phase of the study. Rock from 12 different formations was used with the distribution of mineralogy and pore-throat distribution from the rock types, consisting of both sandstones and carbonates. The Klinkenberg permeabilities ranged from 6.17–1125 md, with porosities ranging from 10.9–42.9%. One sample, Mt. Gambier, failed during exposure testing and was removed from the program.
The paper concentrates on four rock types: Indiana Limestone, Austin Chalk, Castlegate Sandstone, and Berea Sandstone. Before CO2 exposure, Indiana Limestone was classified as a grainstone, consisting primarily of 98.1% calcite. Austin Chalk is a limestone with a grain size classified as grainstone, consisting primarily of 99.1% calcite. Castlegate Sandstone is an upper fine-grained sandstone with a composition of 89.9% quartz with 6.2% total clay. Berea Sandstone, also an upper fine-grained sandstone, is composed primarily of 85.4% quartz and 7.2% total clay.