Petrophysical studies of north American carbonate rock samples and evaluation of pore-volume compressibility models Gilberto Peixoto da Silva Jr a , Daniel R. Franco a, ⁎, Giovanni C. Stael a , Maira da Costa de Oliveira Lima b , Ricardo Sant'Anna Martins c , Olívia de Moraes França d , Rodrigo B.V. Azeredo b a Department of Geophysics, National Observatory, R. Gal. José Cristino, 77, 20921-400, Rio de Janeiro, RJ, Brazil b Institute of Chemistry, Fluminense Federal University, Outeiro de São João Batista, s/n°, 24020-141, Niterói, RJ, Brazil c School of Oceanography, State University of Rio de Janeiro, R. São Francisco Xavier, 524, 20550-013, Rio de Janeiro, Brazil d Institute of Geosciences, Fluminense Federal University, Av. Gal. Milton Tavares de Souza, s/n°, 24210-346, Niterói, RJ, Brazil abstract article info Article history: Received 2 August 2014 Received in revised form 12 August 2015 Accepted 28 October 2015 Available online xxxx Keywords: Carbonate rocks Petrophysics Pore volume compressibility Hydrocarbon reservoirs NMR MICP porosimetry Michigan basin Edwards formation Burlington-Keokuk formation In this work, we evaluate two pore volume compressibility models that are currently discussed in the literature (Horne, 1990; Jalalh, 2006b). Five groups of carbonate rock samples from the three following sedimentary basins in North America that are known for their association with hydrocarbon deposits were selected for this study: (i) the Guelph Formation of the Michigan Basin (Middle Silurian); (ii) the Edwards Formation of the Central Texas Platform (Middle Cretaceous); and (iii) the Burlington-Keokuk Formation of the Mississippian System (Lower Mississippian). In addition to the evaluation of the compressibility model, a petrophysical evaluation of these rock samples was conducted. Additional characterizations, such as grain density, the effective porosity, absolute grain permeability, thin section petrography, MICP and NMR, were performed to complement constant pore-pressure compressibility tests. Although both models presented an overall good representation of the com- pressibility behavior of the studied carbonate rocks, even when considering their broad porosity range (~2–38%), the model proposed by Jalalh (2006b) performed better with a confidence level of 95% and a prediction interval of 68%. © 2015 Elsevier B.V. All rights reserved. 1. Introduction Increasing demand for hydrocarbons has resulted in greater interest in improving techniques for studying the behavior of oil reservoirs, which are complex systems with interacting rock/oil/water/gas and allow for the storage of fluid phases (Sok et al., 2009). Generally, efforts to characterize these reservoirs are based on descriptions of the spatial distribution of petrophysical parameters, such as porosity, permeability and fluid saturation (Harari et al., 1995; Lucia, 2007). These param- eters are important for evaluating the properties of rocks regarding their transport of fluids and for improving knowledge of rock-fluid interactions that may influence the flow of hydrocarbons (Tiab and Donaldson, 2004). In compaction or rock drive reservoirs, the movement of hydrocar- bons toward the wellbore can be driven by an increase in the net confin- ing pressure caused by the collapse of pore space (Tiab and Donaldson, 2004; Lucia, 2007; Oliveira et al., 2013). The degree of the resulting compaction depends on the compressibility of the rock. Compressibility is related to changes in volume and changes in applied stress. Rock pore-volume compressibility (C PV ; equal to the C PC discussed by Zimmerman et al. (1986)) is a measure of the changes in pore volume caused by a change in applied stress (Chertov and Suarez-Rivera, 2014). For hydrostatic compression with a constant pore pressure (P P ), the pore-volume compressibility can be written as follows: C PV ¼ - 1 V P ∂V P ∂P c   Pp ð1:1Þ where Vp = pore volume and P c = confining pressure. The compressibility value depends on the rock composition and depositional history. Despite the positive effect of compaction on pro- duction, the matrix permeability generally decreases as the pore spaces collapse, the cross-section of the pore throats decrease and the open fractures are closed (Doornhof et al., 2006), resulting in an increased resistance to the passage of fluid (Walsh, 1981). Studies that estimate the evolution of rock pore-volume compress- ibility as a function of porosity play an important role in providing continuous C PV -depth profile modeling soon after wireline logging pro- cedures are concluded (Wolfe et al., 2005). A better understanding of its Journal of Applied Geophysics 123 (2015) 256–266 ⁎ Corresponding author. E-mail address: drfranco@on.br (D.R. Franco). http://dx.doi.org/10.1016/j.jappgeo.2015.10.018 0926-9851/© 2015 Elsevier B.V. All rights reserved. Contents lists available at ScienceDirect Journal of Applied Geophysics journal homepage: www.elsevier.com/locate/jappgeo