Insights and Commentaries
Institute report provides new insights on measurement of relative permeability
15th July 2015
Topic(s): Carbon capture, CO2 storage, Engineering and project delivery, use and storage (CCUS)
Relative permeability is an important factor in predicting the performance of geological storage. A recently released Global CCS Institute report prepared by Stanford University considers the measurement of relative permeability and addresses knowledge gaps. In this Insight, Neil Wildgust, the Institute’s Principal Manager – Storage, discusses how measurement of relative permeability is used to predict the behavior of geologically stored carbon dioxide (CO2), and outlines key findings from the report.
A new report commissioned by the Global CCS Institute, based on recent research, provides new perspectives on the measurement of relative permeability in CO2-brine systems relevant to geological storage. Research described in this report has been undertaken by a consortium of organisations led by Stanford University, following publication of an earlier Institute report on the subject in August 2013.
Predictive modeling of CO2 geological storage is a key requirement of emerging carbon capture and storage (CCS) standards and regulations. Calibrated against monitoring data collected during the operational and closure phases of a project, models can demonstrate the long term security of storage by showing that CO2 is conforming to predicted behavior. Relative permeability is an important input parameter for many storage models, as explained below.
Relative Permeability and geological storage
Most geological storage reservoirs consist of porous rocks. The amount of pore space between the constituent mineral grains in any rock, coupled with the connectivity between these pore spaces, controls the ability of fluids to flow through the rock – a property referred to as permeability. This is a critical parameter for storage reservoirs, since injected CO2 must be able to flow away from an injection well to accommodate the supply rate from the capture source. Permeability is an intrinsic property of porous rocks that can be estimated or measured with a variety of techniques in either the field or laboratory, and is measured in units of square meters (m2) or Darcies (D), 1D being equivalent to 10-12 m2.
The pore spaces of reservoir rocks can be occupied by a variety of fluid phases, including groundwater, oil, natural gas, or natural CO2. For storage in deep saline formations, where pore spaces are occupied by highly saline groundwater (brine), injection of CO2 leads to displacement of brine but also mixing of the two fluids in those pore spaces. The different physical properties of the two fluids complicate flow – in effect, the two fluids ”interfere” with each other. The term “relative permeability” is used to describe this phenomenon, and is an important property for reservoir engineers to understand in order to predict CO2 migration in deep saline formations.
Relative permeability is not an intrinsic property of rocks, since the physical nature of the respective fluids present and the temperature and pressure in the reservoir all have an effect on the property. In the case of the brine-CO2 systems in deep saline formations, measurement is made more difficult by the high contrast in viscosity between the two fluids. Laboratory experiments also face the challenges of obtaining sufficient representative rock samples from any given reservoir and effectively replicating field conditions. For these and other technical reasons, there is still some uncertainty over how to best measure relative permeability and derive realistic values to inform predictive models of CO2 storage. It should be noted that relative permeability is a dimensionless property, and is usually shown in graphical form whereby the relative permeability for each fluid phase is plotted against the saturation of one phase (the plots being commonly referred to as ”curves”).
New report findings
The new Institute report, prepared by Stanford University, provides fresh insights on relative permeability measurements, and addresses knowledge gaps identified by the earlier 2013 Institute report:
- Influence of interfacial tension on drainage relative permeability: Interfacial tension is the force that holds intact the physical boundary between two different fluid phases; drainage in this context refers to the displacement of brine by injected CO2. Results from two sets of laboratory experiments indicated that for a range of conditions typical of CO2 storage reservoirs, variations of interfacial tension between the two fluids are unlikely to have a major impact on relative permeability.
- Comparison of methods for making relative permeability measurements: Numerical simulations were carried out for steady-state and unsteady state measurements over a wide range of conditions. Results indicated that the wide range of relative permeability values reported in the scientific literature are unlikely to be due to different measurement techniques.
- Investigation of the low end-point relative permeability and high irreducible water saturations: Relative permeability measurements were made using a new method to shed light on the anomalous values commonly reported towards the end-points of experiments; results indicated that low end-point relative permeability values and high irreducible brine saturations may be an experimental artefact of commonly employed methods.
- Development of a larger data set for imbibition relative permeability curves: Imbibition in this context refers to the brine migrating back into pore spaces as CO2 flows away. A new set of imbibition relative permeability curves were measured over three successive drainage and imbibition cycles, adding to the body of available data.
- Identification of best practices for making relative permeability measurements: Research indicated that for homogeneous rocks, both steady-state and unsteady-state methods provide reliable relative permeability measurements for low CO2 saturations. Reliable measurement of irreducible brine saturations and end-point relative permeability values requires alternative techniques such as the stationary fluid method or centrifuges. Obtaining reliable relative permeability curves for rocks with significant heterogeneity should be the subject of further research.
The new report makes a series of recommendations for further work, including tests on a wider variety of rock types, establishment of an open access database and development of best practices.