BP Colombia has been producing gas and condensate since 1996 from the heavily fractured Cupiagua reservoir, located in the Piedemonte area of Colombia, 195 km northwest of the capital city of Bogotá (Fig. 1). The field contains an extremely rich gas condensate with a yield of about 280 STB/MMscf. Field data confirm that the natural-fracture network in Cupiagua has a major influence on recovery and well production performance. Although fractures apparently play a major role in the recovery potential of the field, it is very difficult to predict their behavior. For starters, reservoir data are not good enough to characterize fracture density and orientation in the formation more than 200 m from a well-bore. Hence, a multitude of fracture patterns are possible. Each pattern can lead to a recovery that differs markedly from the others. Secondly, on a practical level, it is not possible to create multiple detailed models representing the range of possible patterns in a realistic time period. Ecopetrol, the Colombian state oil company, is directing its exploration efforts within the Piedemonte trend where the Cupiagua field is located. This is an area of extensive tectonic activity, so fractures are expected within the hydrocarbon structures. Ecopetrol seeks to benefit from the experience of BP with Cupiagua and is using the field as a benchmark for evaluating the potential of its exploration prospects. Instead of using simple volumetric methods and assumed recovery factors, which are notoriously unreliable under these conditions, Ecopetrol is building on the ideas used by BP to obtain better estimates of its potential in this region. Cupiagua Field-Development Decisions To maximize recovery and brake the decline, BP Colombia has implemented a gas-reinjection plan since early in the field life when the pressure was still above dewpoint. Injection above saturation pressure allows maximizing recovery from gas/condensate reservoirs. However, with a voidage/replacement ratio of roughly 0.8, injection clearly cannot arrest the falling pressure. The average reservoir pressure is about 5,000 psia—significantly below the dewpoint, so condensate accumulation is widespread. Under these conditions, given the richness of the gas, the condensate saturation can exceed 35% of formation pore volume. Although gas injection is less effective below dewpoint, BP has pursued its injection strategy because the gas vaporizes a large fraction of the liquid, increasing recovery, and provides pressure support, boosting well rates. Reservoir modeling reveals the potential gains achievable with injection. Under natural depletion, a maximum recovery of 18% of initial equivalent oil in place (IEOIP) is achievable. However, with gas injection, the recovery can exceed 60%. Furthermore, the modeling shows that this maximum recovery can be reached with the injection of less than 3 pore volumes of gas. Apparently, gas reinjection is the obvious development strategy.