Three Phase Oil Relative Permeability Determination As A Key Point In The Evaluation Of A Tertiary Gas Gravity Drainage Project

Abstract

G. CHALIER, V. GIRY, K. MADAOUI, S. SAKTHIKUMAR and Ph. MAQUIGNON, TOTAL S.A. (FRANCE) Abstract For several years a dual energy gamma-ray absorption measurement apparatus has been routinely performing in situ three phase saturation monitoring during coreflood experiments in reservoir conditions, This paper presents this sophisticated equipment and the application of the technique to determine the three phase oil relative permeability at low oil saturations during a tertiary gas gravity drainage experiment. The oil relative permeability was thought to be a crucial point to validate the economic feasibility of this tertiary oil recovery process for a waterflooded reservoir in the Far East. Using the gamma-ray absorption technique it was possible to visualize the fluid saturation distribution in the core as a function of the volume of gas injected. The production of tertiary oil by gravity drainage was put into evidence at the top of the core. The three phase oil relative permeability curve was deduced from the oil saturation profiles using an analytical calculation. The experiment was finally correctly reproduced with a generalized compositional simulator, emphasis being put on the match of saturation profiles. A triphasic relative permeability model was then validated. Introduction The declining oil production from large waterflooded reservoirs after several decades of exploitation and the significant amount of oil still remaining in place are of great concern for oil companies and fully justify their interest in tertiary recovery processes. However these processes such as gas injection, water alternate gas (WAG) injection or gas gravity drainage in waterflooded reservoirs all involve three phase flow and, consequently, are much more complex to handle than the now well-known two phase processes. As surveyed by R.B.Guzman et al., the numerical simulation of three phase flow is often the weak point in our quest to understand and predict the phenomenon. Several theoretical three phase relative permeability models are available, Stone models being the most commonly used, but the choice between one or another more often proceeds from the experience or intuition than from the confirmation of suitable experimental data. It would not be such a serious issue if the total additional oil recovery and its dynamics predicted by the simulation were not so drastically dependent upon the three phase relative permeability model used. Decisions about the economic feasibility of field developments based on such doubtful simulations remain hazardous and may lead to unexpected results. Before this statement a multidisciplinary study was conducted to support field development decisions concerning a major oil field in the Far East. In this field more than three hundred reservoirs with rather good characteristics have been recognized ranging from 400 m ss to 3000 m ss. The field is being produced since 1975 and the development scheme using conventional recovery methods extends to the total oil in place. After natural depletion and water injection the field has produced more than 90% of its conventional reserves. However the significant volume of oil still in place justified a detailed study to ascertain the most adapted tertiary oil recovery process. This study involved sophisticated laboratory experiments, numerical simulations, detailed reservoir description, surface and well design and cost estimates. This paper retraces the path of this study and presents the most recent laboratory experiments and their contributions to the determination of reliable data for field-scale predictive numerical simulations. P. 607