Production development in the Orinoco Oil Belt started with data gathering programs that included high resolution 3D. Although the acquired seismic information was considered of good to very good quality, it was not enough to provide the details needed to maximize the amount of sand contacted through horizontal drilling. The complexity of the reservoir architecture required additional control data to allow the operator to position the well in targets suitable to support the economic of the project. Additional drilling, in the form of stratigraphical (vertical and/or slanted) and observation wells, plus coring programs, well seismic and rock sampling provided the input for an appropriate reservoir description. Once model integrating such data were produced, geostatistical manipulation allowed the estimate of ranges of oil in place, sand body typing, aquifer distribution and so forth. This effort clearly impacted the development programs by suggesting changes to multilateral geometry, pad configuration, draining point location and well spacing. This paper will focus on how should the above mentioned topics to optimize the field performance be linked and still achieve the economic goals for everyone defined in the projects. Introduction The exploration campaign in the Orinoco Oil Belt started in 1979 with the drilling of 662 wells in 54.000 Kms.2 of surface area, which was highly successful in finding oil. During the same period some 14.000 Kms. of seismic lines (2-D) were also acquired, processed and integrated with previous acquisitions to obtain a good area cover of the whole area. Structural and Isopac maps were generated using the information from seismic and wells (logs, cores, etc). Original Oil In Place (OOIP) and recoverable reserves were estimated, resulting in 1,200 billions barrels as OOIP and 92.7 billions of reserves. During these exploration campaign some vertical wells were successfully tested using conventional production methods (beam pumping system). Cyclic Steam Injection was also tested in two (2) different approached:–Disperse wells located in the west area and–One experimental pilot project located northwest. The first case was to analyze production performance and the second case to optimize well spacing, steam volume required per cycle, completion design, etc. In both cases initial rate per well averaged one thousand barrels per day and average cumulative production per well after six months, achieved values in the order of 200.000 barrels. Well production performance indicated that area sands extension surrounding wells was not the most important parameter and that it was sufficient to achieve a good production performance for developing a project. In some other cases, steam was used as a stimulation purpose to improve well production performance. Open Hole Gravel Pack and Inside Gravel Pack completion techniques to avoid sand production were also successfully tested and implemented, as the sole way of producing Extra-heavy/Heavy crude oil in the area. The first projects in the Orinoco Oil Belt were developed using vertical/slanted wells. These wells were initially produced in cold condition to be later injected with consecutive cycles of steam. Well spacing was the normal grid system to exploit the reservoir from Basal sands upwards. Seismic was not a necessary tool to allocate and drill the number of well required. At that time recovery was estimated between 7% to 12% and daily production rate from the two (2) selected areas reached 100.0 MB/D.

Optimization of lifting methods has been used in the oil industry to study both the oil well production and to determine a company's optimal investment policies. The higher costs related with new facilities and artificial lift installations for new fields have created the necessity to review the latest technology available from different lifting methods, especially from the electrical submersible pump (ESP). Few studies ‘rave been published in the area of heavy crude oil production optimization using ESP's as a lifting method. This paper describes the results of a project performed in two different fields and will study the performance of the equipment and the related aplication range. The equipment studied was installed in completions to depths ranging from 6000 to 11000 feet, with crude gravities on the order of 15 to 21 °API and bottomhole temperatures above 180 °F. Some conclusions base shewn that the ESP equipment can perform in similar crudes with even lower °api's, despite a reduction in the pump's efficiency. Higher fluid production rates are also possible to achieve. This survey and supporting data will confirm the submersible pump to be an alternative method for lifting heavy crude oil from relatively deep reservoirs.

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