Capillary pressure relationships (drainage) is of importance in both, reservoir engineering and petrophysics. Reservoir engineers use capillary pressure relationships in reservoir engineering calculations and petrophysicists use such relationships in saturation-height modelling. The overall objective of the study presented is to perform a comparative study of various capillary pressure models commonly used by the petroleum industry and to access their ability to match diverse laboratory data. Over the years many capillary pressure formulations have been proposed to match laboratory data, from the well-known Leverett J-function approach to more recent methods. Generally, formulations may be theoretical, semi-empirical, empirical or statistical basis. The comparative study presented involves the following analytical formulations: modified Leverett J-function, modified Brooks-Corey (MBC), Thomeer, Skelt-Harrison, Lambda (λ) and the more recently established, Modified Carman-Kozeny-Purcell (MCKP) model. Various types of pore structures may be modelled: homogeneous (narrow), broad (poorer sorting) and bimodal (two distinct distributions) where one of the distributions is often related to pore-fill, or a mixture of distribution types. Results presented in this paper compare application of the above-mentioned methods for homogeneous plugs. It is demonstrated that the MCKP method consistently outperforms the other methods and it is the only method that is able to identify the type of pore throat distribution without any further input data. The advantage of the MCKP method is that it does not contain any fitting parameters. The degree of accuracy of the MCKP model is typically R2 > 0.99. The MCKP model also lends itself very easily to predict capillary pressure relationships from more basic parameters. Presented are examples with data from two Australian fields, one offshore and one onshore.

Routine laboratory permeability measurements require both overburden correction and in the case of lower permeability gas measurements also Klinkenberg-type correction, accounting for slippage of gas when flowing through a porous medium. These corrections are necessary for obtaining representative permeability values for dynamic simulation. The objective of this paper is to determine the most suitable technique for determining representative, equivalent reservoir permeability. Laboratory permeability is routinely measured using different types of gases, most often helium and air, less often liquid. Single phase permeability measurements should be independent of the measuring fluid. However, laboratory permeability measurements using gas tend to overestimate sample permeability due to gas slippage. This effect was first reported by Klinkenberg (1941). Influencing factors are type of gas, mean experimental pressure and rock properties. The so called ‘Square-root model’ (Florence et al. 2007) accounts for all of these factors and is an extension of Klinkenberg’s original equation. The applicability of the Square-root model and earlier Klinkenberg-type models of Jones and Owens (1979) and Sampath and Keighin (1981) for correcting single-point laboratory gas permeability measurements are investigated on a comparative basis. Furthermore, Klinkenberg-type corrections are best made after overburden correction. The study presented involves a parametric approach of the gas slippage influencing factors, in addition to a comparison of alternative formulations. In comparing various Klinkenberg-type corrections, it is shown that the Square-root model compares most favourably and is most suitable for correcting laboratory data in the absence of specific measurements, as validated by comparison with laboratory deduced measurements. Datasets from the Asia-Pacific region and elsewhere are used to exemplify the methodology.

Reservoir quality from cored intervals has traditionally been described by grouping similar intervals according to rock type. The main shortcoming of this static modelling approach is that it lacks clarity and it is not conducive for setting up a dynamic simulation model. The alternative is to use a modelling approach based on Hydraulic Flow Zone Units (HFZUs). First proposed in the late 1980s and extensively published in the early 1990s such formulation uses the well-known Carman-Kozeny (C-K) equation. More recently, this approach has been extended to cover a wider range of geological formations with diverse pore structure types. In using a HFZU approach, a preprocessing step is customarily undertaken to first overburden correct the data and where necessary also to correct for the Klinkenberg effect (lower permeability formations, lab testing with gas). The study presented compares corrected and uncorrected data sets, to see if correction alters the overall outcome of HFZU analysis. Specifically, data sets are compared at three different conditions: ambient, overburden (only) corrected and finally data that has been corrected for both, overburden and Klinkenberg effects. In all cases it is the Flow Zone Indicator (FZI), an index representative of formation quality that is tracked, together with the type of relationship. Several comparative analysis examples are given for diverse formations. The results show that uncorrected data can yield a different correlation and FZI, especially for intervals that include low permeability samples. Results indicate that Overburden and Klinkenberg corrections should be applied before HFZU analysis.

Dynamic reservoir simulation models are used to predict reservoir performance, and to forecast production and ultimate recovery. Such simulation models are also used to match historic production. The success of such models depends critically on optimal gridding, particularly vertical definition and the choice of rock parameters, especially relative permeability. This paper compares simulation results as a function of utilising alternative relative permeability relationships as simulation input: Unaltered laboratory data Modified Brooks-Corey (MBC) relationships derived by fitting lab data (Lake,1989), including MBC and Sor extrapolation (Stiles, 1994) Relationships based on the more recently derived two-phase Modified Carman-Kozeny (2pMCK) formulation (Behrenbruch and Goda, 2006) For maximum clarity, comparisons are made on a single layer basis but covering a range of permeability and porosity values, and capillary pressure relationships are based on modelled lab data using the Modified Carman-Kozeny Purcell (MCKP) model (Goda and Behrenbruch, 2011). Study results show that very different production responses may be realised, depending on the validity of original lab data and choice of modelled relationships deployed. It is concluded that the use of the 2pMCK model in combination with auxiliary investigative tools is optimal in rationalising lab data. Some tested plugs show the influence of heterogeneity, as well as procedural shortcomings and even plug failure. It is shown how such test results can be identified by the 2pMCK model and then optimally modified. In comparison with the MBC model, it is also evident that the use of Corey coefficients may at times be too prescriptive, and even flawed when it is assumed that exponents are only a function of wettability rather than also considering plug heterogeneity and possible lab issues. Relative permeability and capillary pressure data sets are taken from lab results for the Laminaria and Corallina fields, Timor Sea.