This paper presents the results of the numerical simulation model of the highly faulted reservoir C40/44 located in the West Flank, Block I, Lake Maracaibo western Venezuela. Based on an Integrated Approach study1, the 3D dynamic model allowed to evaluate the impact of the sealing character of the inverse faults and their potential influences in the migration and fluid distribution across the faults, and consequently, the grade of difficulty in the adjustment of the historical production subjected to the water injection influence from Dic/71. In spite of the simulation model is highly sensitive to the changes of the reservoir parameters, it is considered that the feasibility grade of the model is enough (85%), to understand the relative movement of the fluids for blocks, to quantify with certainty the recurrent remaining reserves and to identify the field development opportunities and exploitation. Introduction The study area is located within Block I on the west flank of the Icotea Fault in the north-central portion of Lake Maracaibo in Zulia State, western Venezuela. The sands C4, which belong to the Misoa C Formation, were deposited during the Eocene. The C Sands are about 2500 feet thick and were deposited in fluvial-deltaic to shallow-marine environments. In 1996 was initiated an integrated reservoir study covering all the production zones of the field. One of the main results from that study was the new structural pattern of the area. This interpretation trends to compartamentalize the reservoir in 3 bigger blocks. The C-4 reservoir of the V-31 area has been produced since December 1959, when the well V-316 flowed. It is basically a heterogeneous multi-layer reservoir, which has been producing commingled. It is composed of seven units, from C-40 to C-46. The C-42 and C-43 units have the best petrophysical characteristics while the C-45 and C-46 units have the worst. This mature reservoir produces an average API oil gravity of 31. Its initial pressure was 3500 psi at a datum of 7500. The bubble pressure was estimated in 2300 psi, which indicated that the oil in the reservoir was above bubble point. Currently, the mechanism of production of the reservoir is a combination of water injection and water influx. Due to geological complexities, which were not detected in the past, there is little efficiency in the maintenance of pressure due to water injection, which was started in Dic/71.. Several water injector wells have been added to improve the performance of the water injection project. The daily production from the field is 2854 bbl/d with an average water cut of 29 percent and a GOR of 802 scf/bbl (March 1999) using 13 wells. Cummulative production has been 62.5 MMbl of oil, 60.5 MMMscf of gas and 18.1 MMbl s of water, until March 1999. This reservoir has been under the influence of an extensive aquifer, which seems to have a moderate activity, as indicated by the pressure history and water production history of the wells. A reservoir simulation study was based on the static model derived from the integrated study. The objectives of the study were to provide a more realist estimated of remaining reserves to explore field development opportunities and to improve production potential of the area under study.

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TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractFor the first time, in Venezuela, a detailed, complete study of naturally fractured reservoirs using the recent technological advances was performed. Since the first drilled well within the very tight (5 mD) cretaceous sandstone (San Juan Formation) diagenetically highly cemented by quartz overgrowth, the existence of natural fractures was suspected due to high production rates (3000 bopd) after hydraulic fracturing an interest in fractures characterization became important for the field. Furthermore, these assumptions were growing with the analysis of pressure transient tests of several DST and Buildup surveys, which have shown double-porosity behaviour. During the drilling it was frequently observed strong lost of circulation at several depths within the San Juan Formation.Orocual Field, within El Furrial Trend, located in North Monagas area, East of Venezuela, is structurally a Fold Propagation Fault resulting in anticlines associated with thrust faults. San Juan Formation, a complex barrier island deposits, bearing condensated fluids (41° API) is the most important reservoir within Orocual Field. Cores and Well Logs provided the basis to strongly confirm the presence of a fracture network within the reservoir. With the use of recent technological advances (core scanning and imaging, side-by-side display) which permits a detailed corelog calibration and integration, a NNW-SSE orientation of the fractures observed and measured in the cores was possible, the findings are consistent with the regional tectonical stress. Integrated analysis with breakouts borehole image processing, 3D seismic structural interpretation, in-situ stress measurements and second derivatives maps yield us to establish the first maps of fractures orientation and density. Parameters such as aperture, spacing, density, length and angles have been measured to define patterns and tendencies that it will feed the simulated dynamic fractures model. A better understanding of the historical production behaviour has been reached and a simulated, geostatistical fractures modelling is under development to establish correlative trends matching between production and fractures network orientation, density and dynamical properties of the fractured system.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractCarbon Oxygen ratio (C/O) logging has been used in the oilfield for a long time as a solution to determine oil and water saturations independent of the formation water salinity. The traditional S w computation methodologies rely on the use of the tool under standard and uniform completions, and are based either on a data base characterization or on deterministic models. These techniques fail when the casing size, along the logging interval, is variable, or when the tool characterization is not available for unusual casing sizes.Uncertainties are also encountered in complex lithologies, particularly in the presence of carbonates, due to deposition or diagenesis. In this case, it becomes difficult to compute the correct carbon content of the rock to correct the final volume of oil estimated.This paper describes a case study with a very atypical completion including downhole sensors as part of the casing, and the presence of a variable carbonate volume in the reservoir rock matrix. It is part of a project to define the evolution of a water flooding between two nearby wells, one the injector and the other the monitoring well. Here, a new computation methodology to calculate the volume of oil using the openhole computed S w , as a reference, and different time lapse C/O logging passes to define the change in volume of oil in the reservoir during the water injection, is presented. This variation (∆V uoi ), applied to the openhole S w , enables the computation of precise saturation results, where it is possible to observe the quantitative change in fluid volumes in depth over a period of approximately six months in spite of the nonstandard completion type and complex lithology.