The object of this work was Muri Field, which is located in eastern part of Venezuela. The expectations for this field were high at the beginning of the study. Firstly, the high oil quality of 30 °API; secondly, this field is located near another one under enhanced oil recovery processes with high production rate; and finally, the field has been inactive since 1.994. This paper presents the use and results of a detailed Reservoir Characterization Model in the evaluation of opportunities for the drilling of new production wells. Applying conventional petroleum engineering methods, numerical simulation, and teamwork carried out the study. Muri Field had a structural model generated from a 2D seismic interpretation. This model presented high simplicity and little coherence with the actual well information; being necessary to update it. This reservoir study considers a new structural model, based on a 3D seismic interpretation with a structural frame fitting actual data allowing optimizing the exploitation plans. The use of numerical simulation allowed strengthening the conventional reservoir engineering analyses and enhancing the production expectations for the area. The results are based on teamwork and the application of the available technology. This new engineering study enabled to better evaluate the vertical communication in the field as well as the unification of four different reservoirs; all of them located in the geological formation with higher potential. As a consequence the official field limits were extended, and a lateral communication was established with a large producing field in north of Monagas State. The most relevant results were a two (2) fold increase in recoverable reserves and the evaluation of new exploitation scenarios. The locations of new producer wells were defined taking into account the new boundary area between Muri and the surrounding fields, to improve the final recovery. Introduction Muri Field is located in Maturin, Monagas State, Venezuela, Figure 1. It is part of the Oriental Basin of Venezuela (Subbasin of MaturÍn) and was discovered in 1991 with the perforation of MRC-1E well. Light oil reserves were proved in four different reservoirs of the Naricual Superior Formation at Muri Field 1. The neighbors fields to Muri Field have supported along two decades a high percentage of the national production with high expectations associated to the reservoirs in the Naricual Formation. Nevertheless, Muri Field was closed from 1994 by the low productivity of the reservoirs in the Naricual Formation and few expectations associated to the geologic model, 1991. The location of Muri Field with respect to the best producing zones of the North of Monagas was a key point to begin the review of the current reservoirs model. A reservoir characterization based on the right use of the hardware and previous studies maked possible to generate low costs products with the participation of engineers, geologists and geophysical, among others, in a multidisciplinary team. Based on teamwork concept and the vision of assets reactivation, which has not been used in this field until now was generated a work plan that allows to begin of a reservoir characterization study in Muri Field.

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El Carito-Mulata and Santa Bárbara fields are located in Eastern Venezuela in the MaturÍn sub basin and cover almost 300 km2. The asymmetrical anticline of the reservoirs is the result of different tectonic regimes alternating compressive and extensive periods from the late Cretaceous to the Middle Miocene. The fields are producing 240,000 STB/D and their OOIP is estimated to be around 6.5 MMMSTB. The variation of the vertical fluid distribution is predominant. There is a light oil (condensate) at the top of the structure, black oil at the base and free water at different levels in the reservoirs. This vertical fluid distribution is not well represented in the dynamic simulation model, which increases the uncertainty on any prediction or elaboration of the production plan. The main objectives of this study are the determination of the original fluid contacts and the construction of a fluid model, which takes into account the free water presented in the reservoirs. This model can also define the vertical and lateral extension of the oil fields, indispensable for the reserves estimation. The integration of the different kinds of static and dynamic information of 149 wells was necessary in order to obtain a well-supported fluid distribution model. The analysis of the large number of data allowed defining the geometry of the Tar mat (asphaltene content > 20%), which is folded/faulted according to the structure and considered as a sealed layer in reservoir conditions, with thicknesses ranging between 300 and 500 feet. The irregular Tar mat surface limits the reservoirs and controls the free water levels in the fields. This new fluid distribution model was included at the numerical simulation model matching all the wells information about water or type of oil that has been produced or tested. Introduction An accurate description of the fluid distribution in a reservoir is key to reduce uncertainty in the reserves estimates. The complexity of the stratigraphy, sedimentology, structural and fluid distributions were revealed during the evaluation of the reservoir data for El Carito-Mulata and Santa Bárbara fields. The fluid distribution in these fields indicates the evidence of different properties and a strong variation of those with depth. El Carito-Mulata and Santa Bárbara fields are currently sub-divided into four operating areas: North (MUC-2), Central (MUC-1), West (MUC-3) and South (SBC-10). To keep reservoirs pressure constant to avoid asphaltene precipitation, MUC-1 and MUC-3 are currently submitted under natural gas injection project, MUC-2 undergoes water injection while SBC-10 flows naturally. Free water has been identified at different reservoir depths and this fact has not been represented at the previous fluid distribution model, this represents an inconvenience to match the fluids in the numerical model. An asphaltic crude oil, denominated Tar mat for its physical and chemical properties, has also been identified. The term Tar mat is referred to heavy oil zones with high asphaltene content and well-defined limits presenting a local or regional distribution across different stratigraphic levels and depths. The main characteristic of the Tar mat zone is a minimal asphaltene content of 20% on the C15+ molar fraction [1]. A new model for the fluid distribution was generated for the fields in order to consider the original water-oil contacts, identify limits of the reservoirs and zones with Tar mat. Background The previous fluid distribution model is based on a hydrocarbon column whose composition varies with depth, from gas condensate at the structural top to under saturated black oil down the flanks and at the base of the reservoir. A transition zone from gas condensate to volatile oil exists at approximately -14040 ft sub sea (ss). This model contains a water-oil contact, WOC, at -17300 ft ss in the south flank. Two stratigraphic limits are defined for the proven area in the North flank, one at -16800 ft ss and other one at -17400 ft ss (see Figure 1).

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