Abstract
Fault seal analysis is a key part of understanding the hydrocarbon trapping mechanisms in the petroleum industry. Fault seal research has also been expanded to CO2–brine systems for the application to carbon capture and storage (CCS). The wetting properties of rock-forming minerals in the presence of hydrocarbons or CO2 are a source of uncertainty in the calculations of capillary threshold pressure, which defines the fault sealing capacity. Here, we explore this uncertainty in a comparison study between two fault-sealed fields located in the Otway Basin, SE Australia. The Katnook Field in the Penola Trough is a methane field, while Boggy Creek in Port Campbell contains a high-CO2–methane mixture. Two industry standard fault seal modelling methods, one based on laboratory measurements of fault samples and the other based on a calibration of a global dataset of known sealing faults, are used to discuss their relative strengths and applicability to the CO2 storage context. We identify a range of interfacial tensions and contact angle values in the hydrocarbon–water system under the conditions assumed by the second method. Based on this, the uncertainty related to the spread in fluid properties was determined to be 24% of the calculated threshold capillary pressure value. We propose a methodology of threshold capillary pressure conversion from hydrocarbons–brine to the CO2–brine system, using an input of appropriate interfacial tension and contact angle under reservoir conditions. The method can be used for any fluid system where fluid properties are defined by these two parameters.Supplementary material: (1) Fault seal modelling methods and calculations, and (2) hydrocarbon and CO2 interfacial tensions and contact angle values collected in the literature are available at https://doi.org/10.6084/m9.figshare.c.4877049This article is part of the Energy Geoscience Series available at https://www.lyellcollection.org/cc/energy-geoscience-series
Highlights
Faults can be either pathways for, or barriers to fluid migration in the subsurface and to the surface
Fault seal research has expanded to applications to Carbon Capture and Storage (CCS), where faults can act to: decrease the maximum storage capacity of the reservoir; become unwanted barriers to fluid migration along the planned injection pathway, causing pressure increase and limiting the maximum rate of injection; or, provide a conduit for leakage of CO2
While the above concerns are valid for the CO2 storage, the existing uncertainties associated with contact angle (CA) and interfacial tension (IFT) exist in the hydrocarbons. This is because of the wide range of chemical compositions of crude oil and the difficulty of sampling undegassed reservoir fluids. In this contribution we investigate the uncertainty associated with the fluid properties (CA, IFT) as well as geological assumptions required for the model in two field examples
Summary
Faults can be either pathways for, or barriers to fluid migration in the subsurface and to the surface. Two distinct methodologies of predictive modelling of the threshold capillary pressure, which is a proxy for fault sealing capacity to hydrocarbons, have been developed in the last two decades: one based on a calibration of a global dataset of known sealing faults (Bretan et al, 2003; Yielding et al, 2010), and another, based on laboratory measurements of fault samples (Sperrevik et al, 2002). Both of these techniques have been widely applied to hydrocarbon systems. Fault capacity to seal for CO2 has been explored in theoretical studies (Iglauer, 2018; Miocic et al, 2019; Naylor et al, 2010), yet there have been few attempts to test the methodology with real geological examples (Bretan, 2016; Bretan et al, 2011; Yielding et al, 2011)
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