State of Integrated Formation Evaluation for Site-Specific Evaluation, Optimization, and Permitting of Carbon Storage Projects

Participation in over 80 carbon capture and storage (CCS) projects spanning 25 years has led to the evolution of a recommended well-based appraisal workflow for sequestration in saline aquifers. Interpretation methods are expressly adapted for CCS applications to resolve key reservoir parameters, constrain field-scale modeling, provide answers required for the permitting process, and de-risk unique CCS technical challenges, such as: • Storage capacity – a more challenging parameter to evaluate than hydrocarbon reserves since the reservoir is at zero CO2 saturation during evaluation. • Injectivity – key to minimizing wells needed to safely achieve the target storage rate. • Containment – does the field provide a permanent and safe trap for CO2? Contrary to hydrocarbon reservoirs, the caprocks of these reservoirs have never held a column of buoyant fluid, and the reservoirs will be subject to elevated pressures never seen before. A further challenge complicating the above is the eventual impact of the three-way interaction between matrix, brine, and impure CO2 streams. Most logging, sampling, and laboratory techniques are adapted from established domains such as enhanced oil recovery, underground gas storage, and unconventional reservoir evaluation, though some CCS-specific innovation is also needed. Storage evaluation begins with established methods for lithology, porosity, permeability, and pressure, while special core analysis (SCAL) determines CO2 storage efficiency and relative permeability. Containment evaluation spans multiple disciplines and methods: the petrophysicist’s task to quantify seal capacity relies heavily on laboratory analysis, while geologists leverage downhole imaging tools to verify caprock structural/tectonic integrity. Geomechanics engineers define safe injection pressure via mechanical earth models (MEMs) built on advanced acoustic logs calibrated by core geomechanics, wellbore failure observations, and in-situ stress tests. The impact of matrix-brine-CO2 interactions is studied via custom SCAL experiments and/or pore-scale digital rock simulations that faithfully represent chemical and thermal processes. Wireline formation tester samples provide representative formation brine as feedstock for SCAL. Water samples also enable operators to prove injection within regulatory limits while establishing baselines for the future monitoring program. Examples applied to recent CCS projects in North America are presented. At present, a well-planned integrated approach making optimum use of cores, logs, and fluid samples can affirmatively address the main challenges of CCS. There remain opportunities for improvement; wireline logs cannot provide all the answers, and SCAL is absolutely necessary to determine elusive parameters such as eCO2 having a critical impact on simulation outcome, project footprint, and economics. We envision that practical limits on the quantity of SCAL experiments will be overcome by smarter methods of SCAL-log integration and by digital rock simulations as opposed to new measurement technologies. CCS evaluation programs are among the most comprehensive ever seen, but this investment is proportional to the technical, commercial, regulatory, and social risks these capital-intensive projects must successfully navigate. The value of information to this end is supported and enhanced by fit-for-purpose commercial software for dynamic simulation of CO2 storage, fully honoring the details, providing operators better visibility for decision making, risk management, and preservation of the regulatory and social license to operate throughout a project lifetime that may last more than 100 years.