Many prolific oil reservoirs in the Mexico part of the Gulf of Mexico are fractured Carbonate systems. Their hydrocarbon production mechanisms generally include combination drive of aquifer, gas cap, and oil expansion and rock compaction. In some cases water injection is used as an additional means of energy. At late production life of these reservoirs where production decline is experienced, the usual problems are the lack of well potential, increased water production, or combination of the two. In such cases, it is imperative to find out efficient techniques of maintaining the pressure at reasonable levels for improving production while minimizing the water withdrawal rates.

One of the techniques to challenge the decline in production may be gas injection in the form of Nitrogen or re-injection of produced gas and additional make up gas when necessary. However, the possibility of premature breakthrough due to the fractures may result in low sweep efficiencies in these reservoirs.

This paper presents our investigation into the applicability of gas injection into Chuc reservoir located at Campeche Bay of Mexico, and that contains vugular and fractured Breccia and generally fractured sequences of Upper, Middle and Lower Cretaceous, which is typical to many reservoirs in the region. The methodology developed during this work is used to examine the relative contributions of pressure maintenance by gas injection; formation of secondary gas cap as an additional source of energy; immiscible and miscible displacement of the in situ oil; controlling the advancing water; molecular diffusion; reduction of the interfacial tension resulting in the improvement of relative flow characteristics of oil and gas; and gravity drainage, through a series of comparative case studies based on a real field data.

In our methodology, we developed a systematic procedure of attaining an appropriate characterization of the fluid PVT and molecular diffusion. We also demonstrated by a number of numerical experiments that even for simpler cases where miscibility is not possible, the simplifications in the modeling could result in severe under estimation of the reservoir performance. With the comparative case studies we present, we show that even under adverse reservoir heterogeneity conditions, if the process is carefully designed and some of the key reservoir parameters are taken into advantage, it is possible to increase the recovery well over the expected recoveries from the conventional techniques.

The methodology we designed and demonstrated in an application to real field cases is believed to be a useful vehicle for technical feasibility evaluation of other possible candidates in the region.

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