Summary Analytical and numerical methods are used to investigate the mechanism of water production in a high-permeability sandstone reservoir that has a capillary transition zone height comparable to formation thickness. Production rates are well above those for transition-zone water production alone. Consequently all wells are affected production alone. Consequently all wells are affected by coning shortly after the start of production. It is found that water cut is largely insensitive to total fluid production rate for the same recovery. The depth of well penetration and the effect of radial capillary pressure gradients are shown to be of secondary importance pressure gradients are shown to be of secondary importance in these circumstances. The predictions are confirmed by the results of a long-term pilot production test. Introduction This paper considers the mechanism of water production in a highly permeable sandstone reservoir with a 22API [0.9-g/cm3] under saturated oil and a strong edge aquifer drive. The findings are drawn from a study recently performed on the M-1 Sand reservoir of the Fanny field, performed on the M-1 Sand reservoir of the Fanny field, which is located on the eastern flank of the Oriente basin in Ecuador. M-1 Sand belongs to the Napo formation of the Cretaceous Age and consists of moderately to poorly cemented quartzose sands of high permeability. Reservoir depth is approximately 7,700 ft [2347 m]. A characteristic feature of the reservoir is the wells' predisposition to develop substantial water cuts after predisposition to develop substantial water cuts after short periods of production. Attempts have been made in the past to reduce water production by squeeze cement jobs and recompletions. However, these operations have not been effective but for the very short term and consequently the study has concentrated on attempting to define the nature of fluid movement within the drainage area of the wells. Reservoir Description M-1 Sand shows lithological features characteristic of a fluvial channel depositional environment. These features are exemplified by the Induction Electrical Survey of Well 18-B-2 (Fig. 1), which shows a basal unit 45 to 55 ft [14 to 17 m] thick, overlain by a variable number of smaller units that are separated by shale breaks and tight streaks. These upper units are of poor quality and limited lateral continuity. In contrast the basal unit contains no correlatable shale breaks although thin shales were encountered in some wells and early completion practices attempted unsuccessfully to make use of them. Because of this early experience and the absence of correlation it has been concluded that such shale breaks are of limited lateral extent and do not contribute materially to the prevention of water-cone development. prevention of water-cone development. The basal unit contains more than 90% of the original oil in place, estimated at 48 × 10(6) STB [7.6 × 10(6) stocktank m3]. Currently all wells are completed in this unit, which has provided all production to date. The upper units have been neglected for the purposes of this paper. The structural configuration of the reservoir is a faulted asymmetrical anticline of low structural amplitude. Fig. 2 represents the structure on top of the basal sand unit and shows the intersection of the oil/water contact (OWC) with this surface, giving rise to a maximum oil column of 65 to 70 ft [20 to 21 m]. A comparison of sand thickness with oil column height indicates that the base of the sand is everywhere close to the OWC and that all wells have high basal water saturations. Pressure support is by edge aquifer influx, but with strong underrunning giving behavior characteristic of a bottom aquifer. Reservoir and Fluid Properties The basal unit is variable in quality but characterized by high porosity and permeability averaging 20 to 25% and 2 to 3 darcies, respectively. Figs. 3 and 4 are capillary-pressure and relative-permeability curves representative of the basal unit. These curves are typical of a sandstone that contains large, well-interconnected pores. Sands of this unit are generally poorly cemented and friable. No fractures are evident from either cores or logs. There is no evidence of any fracture-induced effects on pressure buildup data, which correspond to a single permeability intergranular system. Average oil and water fluid properties are presented in Table 1. The oil and water viscosities at reservoir conditions are 12 and 0.35 cp [12 and 0.35 mPas] respectively, which give a very unfavorable endpoint mobility ratio. The displacement of oil by the encroaching aquifer is thus an unstable displacement and the strong underrunning of water quickly results in high producing water cuts in the wells. JPT P. 1559