Improved Characterisation And Modelling Of Carbonate Reservoirs For Predicting Waterflood Performance

Abstract

Abstract Carbonate reservoirs are highly heterogeneous and often show oil-wet or mixed-wet characteristics. Both geological heterogeneity and wettability have strong impact on capillary pressure (Pc) and relative permeability (Kr) behaviour, which is controlled by the pore size distribution, interfacial tension and interactions between rock and fluids as well as the saturation history. Capillary pressure data are essential input in both static and dynamic modelling of heterogeneous carbonate reservoirs. Drainage Pc is generally used for initialising reservoir static models while imbibition Pc is used to model secondary and tertiary recovery processes. The objective of this paper is to present an improved reservoir characterisation and modelling procedure for predicting waterflood performance of a Cretaceous carbonate reservoir in the Middle East. We focus on the characterisation of multi-phase fluid flow properties, in particular the capillary pressure characteristics in both drainage and imbibition, and their assignments in reservoir simulation models. We show that for modelling initial saturation distribution in the reservoir, assigning saturation functions based on permeability or porosity classes alone is not adequate. Moreover the petrophysical correlations often used for clastic reservoirs (e.g., Leverett J-function) may not be applicable to carbonate reservoirs without careful pore-type examination and core analysis/calibration. A novel procedure is described to derive imbibition capillary pressure curves from the primary drainage Pc curves taking into account of wettability and fluid trapping. The results lead to an improved understanding of capillary pressure characteristics in carbonate reservoirs, in particular, the contact angle distributions and hysteresis behaviour in both drainage and imbibition. This paper also presents a mathematical model for implementing both drainage and imbibition capillary pressure functions in dynamic reservoir simulation. This model takes into account the complex pore size distribution and wettability characteristics in carbonates as observed in experimental special core analysis (SCAL) measurements. Furthermore, how to assign imbibition Pc for the different porosity and permeability classes will be examined and its impact on modelling waterflooding performance and remaining oil saturation distributions assessed. Introduction The complexity of carbonate reservoirs and the importance of a consistent approach in defining rock types have been a subject of several recent papers (Marzouk et al. 2000; Ramakrishnam et. al. 2000; Leal et. al. 2001; Porrai and Campos 2001; Giot et. al 2000; Silva et. al. 2002; Hamon 2002; Masalmeh and Jing 2004). Current practices in general are either based on petrophysical properties (i.e., porosity, permeability and drainage Pc curves) or geological description (facies and depositional environment) or a combination of both. The underlying assumption is that static rock characterisation and the resultant rock-typing scheme remain valid when assigning saturation functions (Pc & Kr) in dynamic reservoir modelling. In this paper, we will incorporate conventional core analysis (porosity, permeability), thin section and SEM analysis, mercury-air capillary pressure (Pc)/ NMR with special core analysis data, in particular, the imbibition Pc and residual oil saturation. Several experimental techniques are available to measure capillary pressure (Pc) curves, both in drainage and imbibition cycles. Mercury injection is frequently used for measuring drainage Pc curves as the technique is relatively cheap, fast and requires relatively straightforward data interpretation. The measured data, however, need to be converted to in situ reservoir conditions by taking into account the differences in interfacial tension and contact angle between the rock/fluid systems used in the laboratory and that found in reservoir. The porous-plate equilibrium method is a reliable and accurate technique for measuring Pc in drainage and imbibition under representative reservoir conditions of fluids, pressure and temperature. The main drawback of this technique is the lengthy time required to reach capillary equilibrium, which renders the technique impractical for certain field applications especially for tight and heterogeneous carbonates. The multi-speed centrifuge method can be used for both drainage and imbibition Pc measurements using representative reservoir fluids. Compared with the porous-plate equilibrium technique, the centrifuge method is relatively fast, which is a clear advantage for studying tight carbonates. However, the design of the centrifuge experiment and the interpretation of the data are not straightforward and numerical simulation of centrifuge experiments is generally required to derive capillary pressure data (Maas and Schulte 1997).