B. Harrison (Enterprise Oil) and X.D. Jing (Imperial College, London)
Copyright 2001, Society of Petroleum Engineers Inc. This paper was prepared for presentation at the 2001 SPE Annual Technical Conference and Exhibition held in New Orleans, Louisiana, 30 September–3 October 2001. This paper wasselected for presentation by an SPE Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Society of Petroleum Engineers, itsofficers, or members. Papers presented at SPE meetings are subject to publication review by Editorial Committees of the Society of Petroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of notmore than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435.
Abstract The paper reviews four of the more popular saturation-height methods employed in the oil and gas industry, namely those proposed by Leverett,Johnson, Cuddy and Skelt. The advantages and drawbacks of each method are highlighted. Each technique is compared by investigating how accurately they model the saturation-height profiles of a Palaeocene oil well from the UK Central Graben and a Permian gas well from the UK Southern North Sea. Both wells have complete data sets including conventional core, SCAL and a comprehensive suite ofelectric logs. Besides comparing each of the methods on a well basis, the paper applies the resultant saturationheight relationships to the reservoir structures to see the effect on the computed hydrocarbon-in-place estimates. By moving to an areal field-wide basis, the effects of reservoir structural relief and the relative importance of the transition zone modelling is brought into focus. IntroductionA former colleague of ours once stated that petrophysicists only produce three numbers of any interest to others, namely, porosity, saturation and net to gross. While there may be a grain of truth in his cynicism, he forgot to mention that one other major deliverable of petrophysics, the saturation-height function. Armed with this algorithm, the geologist or reservoir engineer is able to predictthe saturation anywhere in the reservoir for a given height above the free water level and for a given reservoir permeability or porosity, or to estimate permeability once water saturation is known. So far, so good, but the fly in the ointment is that there are many saturationheight methods to choose from. Which method should one use? Does it really matter?
To investigate these questions, weapplied four of the more commonly used saturation-height routines to two complete data sets from wells in the North Sea; one oil well and one gas well. Each of the subsequent predictive equations was then integrated with a gross rock area vs. depth curve in order to compute the in place hydrocarbon volumes for each reservoir. Based on the results, we then attempted (maybe foolishly, given howstubbornly some analysts defend their favourite methods) to recommend which approach should be used for particular circumstances. You will see that (as usual in petrophysical and indeed any subsurface geoscience and reservoir engineering matters) the outcome is not cut and dried. Background Theory(1,2) Capillary pressure reflects the interaction of rock and fluids, and is controlled by the pore...