Abstract

Waterflooding in viscous oil fields poses several problems to both the reservoir engineer and the production engineer. Despite unfavorable mobility ratios, it has been pointed that injection performance often exceeds theoretically expected values. In the particular case of the waterflooding pilot project across the Cerro Fortunoso field (Malargue, Argentina), occurrence of several water supplies of widely varying salinity coupled with usual problems. This paper describes a pilot study designed to determine optimal salinity of water to be injected in order to avoid formation damage resulting from clay deflocculation through what is known in the literature as saline shock. As clearly shown by the results of the study, abrupt changes in the salinity of injected water result in significant falls in permeability. According to the study, the problem is minimized over certain ranges.

Introduction

The Cerro Fortunoso field is located in southern Mendoza, Argentina, in an environmental reservation area known as La Payunia, 135 km away from the capital city of Malargue Department (Figs. 1 and 2).

The field is characterized by its complex structure which consists of a NNE-SSW striking narrow, elongated and faulted anticline. Four major east dipping, NNEstriking thrust faults are predominant. The oil bearing region belongs to the Neuquen Group and develops along the anticline flanks. A gas cap consisting mainly of CO2 (85 to 95 % molar content) occurs in the upper part of the structure.

Geologically, the field involves fluvial deposits exhibiting a considerably marked tectonics with high dips (40 to 70 degrees) and intense NE-SW faulting giving rise to compartmentalized lenticular reservoirs of poor areal continuity. These lenses are sand/shale intercalations with an average porosity on the order of 18 % and mean permeability in 50 mD range.

BACKGROUND

There was concern about the feasibility of a secondary recovery project in the above referred field which contains a predominantly asphaltene-based, considerably viscous heavy oil (14 ° API).

Complete information regarding the field main features and its fluids can be found elsewhere (1).

Numerical simulation of the reservoir characterization study performed in Canada together with Teknica Overseas Ltd made completion of the project feasible (2). Such study, warned about the potential negative effects of fresh water injection. This was suggested due to the occurrence of smectite, illite and kaolinite.

At an early stage, the most suitable area for implementation of a pilot project was studied and steps were taken to seek for potential water sources.

Thus, we faced one of the main difficulties to overcame. As described above, the field is located in an extremely desert-like environmental protection area where the nearest river (Rio Grande) is 70 km apart. No lacustrine deposits or natural springs occur.

WATER SOURCES

Use of battery-gathered production water was initially ruled out due to its low production rates, high emulsion content and the significant treatment cost that it would require.

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