Pressure maintenance through immiscible nitrogen injection has proved to be one of the best methods as a secondary oil recovery on depleted and naturally fractured light-oil reservoirs (NFR). The 190 MMscfd of immiscible nitrogen injection project that is currently developed in the Antonio J. Bermudez Complex, a giant NFR in Southern Mexico, is the second large pressure maintenance project in Mexico, after the world famous Cantarell project. A lot of challenges dealing with injection well locations, injection rate control, fracture system effect on nitrogen breakthrough and impact on hydrocarbon gas contamination, have been managed the last six years of project performance. A comprehensive description of the pressure data acquisition program, the importance of the real time and planned chromatography to monitor the reservoir performance, the methodology to determine the net oil recovery contribution and the methods to define the vertical and horizontal efficiencies are described in this paper focused on learning lessons and best practices. The experience gained over the six years of the nitrogen injection project show that this process is beneficial to extend the life of a depleted light oil reservoir as remedial solutions for mature oil fields revitalization.

A new method is proposed to estimate the matrix and fracture’s effective compressibilities by using the material balance equation (MBE) and production data. Assuming the behavior of naturally fractured reservoir (NFR), accordingly to the pressure tests analysis, it is then possible to replace the effective compressibilities into a MBE of double porosity to determine original oil from both systems. Due to the lack of information from cores and the problem that implies acquiring it, this method represents a useful alternative for analytical models. Generally, it is complicated to determine representative values of fracture compressibilities for the entire reservoir; especially when this is very heterogeneous. The calculated compressibility of the matrix and fractures can be compared with formation compressibility correlations when there are no core analysis or pressure tests available. This is an innovative method to obtain reliable compressibilities for the analysis of material balance of double porosity (MBDP). In addition, with this method it is also possible to obtain the original ratio of the volume stored in the fractures to the total volume in the reservoir; which is a crucial factor in the determination of the final oil recovery.

No abstract

This work presents a general, straight-line method to estimate the original oil and gas in-place in a reservoir without restrictions on fluid composition. All past efforts are applicable to only restricted ranges of reservoir fluids. The work supersedes these and it is applicable to the full range of reservoir fluids-including volatile-oils and gas-condensates. The work is based on the new generalized materialbalance equation recently introduced by Walsh. The superiority of the new method is illustrated by showing the error incurred by preexisting calculation methods; guidelines are offered to help identify when preexisting calculation methods must be abandoned and when the new methods featured herein must be employed. Empirical correlations for the volatile oil-gas ratio Rv for volatile-oils and gascondensates have been introduced to accurately define how much fluid volatility a reservoir oil can exhibit before one can no longer justifiably use the CMBE and one must apply the generalized material balance equation (GMBE). Thus, if there is interest in applying the conventional material-balance equation (CMBE) and its applicability is in question, we recommend measuring the fluid's volatile oilgas ratio Rv at its saturation pressure and comparing it to the critical value offered herein.