TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractAlbacora Leste, one of the largest Campos Basin deep-water oilfields, was discovered in March of 1986. Oil field development area involves 141km 2 and water depth ranges from 800 to 2000m. In order to exploit the field, 30 horizontal wells -16 producers and 14 injectors -will be connected to an FPSO unit (P-50). Expected total reserves are 565 million barrels of oil.Albacora Leste main reservoirs are Miocene sandstones with high porosity and permeability. The depositional model is interpreted as a complex turbidity system, mainly represented by channels, lobes and overbank facies. Net thickness ranges from 5 to 35m, suggesting horizontal well drilling. After the deposition stage, erosive channels introduced flow barriers that generated different reservoir compartments. These compartments impacted drainage pattern design and were checked through reservoir pressure data after long term pilot well production, log interpretation, and fluid samples analyses. Small gas caps showing different gas/oil contacts were detected all over the field area, introducing an additional challenge for field development.Intensive application of the following technologies was important to make field development technically and economically successful: (1) high quality 3D seismic; (2) image logs and LWD (logging while drilling); (3) long gravelpacked horizontal wells; (4) thermally insulated flowlines, allowing flow assurance for distant satellite wells; and (5) massive sea water injection for sweep, and reservoir pressure maintenance. In order to avoid scale deposition as a result of sea water injection, a Sulphate Removal Unit was installed in the P-50 FPSO.This paper presents the key aspects of the reservoirs, the drainage modeling and design, as well as the strategy adopted during project implementation, in order to overcome main reservoir uncertainties, such as fluid type, connectivity, and net pay, accomplishing at the end a successful project execution.

A project was undertaken to verify new technology for handling gas using an electrical submergible pumping (ESP) system and to assess the production increase potential for wells in the Venezuelan Lake of Mamcaibo. There is also a potential application for the technology in the Venezuelan field north of Monagas where gas venting through the annulus presents hazards due to the high corrosiveness level. Tests were performed in the Tia Juana Experimental Test Well facilities to determine the viable amount of gas that could be produced through the equipment on a percent by volume basis. An analysis and summarization was performed on 290 historical files recorded during the testing. The results indicate that there is now the potential to produce four to five times more gas through an ESP system with this technology than has been previously accepted in the industry. The application of this technology to the Lake of Maracaibo is expected to affect 250 wells providing additional production of 75,000 STB/D of oil and a savings of 180 MMSCF/D of gas used to gas lift these wells. Installation of the system in the first three wells in the Lake of Mamcaibo has substantiated the test results. The purpose of this paper is to present the test parameters, results, application potential and initial field results. Introduction The need to operate electric submergible pumping systems in wells having free gas fractions greater than those traditionally handled has generated the development of new technologies such as the Advanced Gas Handling system (AGH)1, U.S. patent number 5628616. A project was undertaken to verify this new technology. The objective was to evaluate the performance of the ESP system with the Advanced Gas Handler in controlled field conditions, handling different flow rates and free gas fractions at pump intake level. Problems with producing high gas fractions through ESP systems have been well documented.2.3,4.5,6 During fluid flow through a pump, the gas bubbles tend to lag behind the liquid in the lower pressure area of the impeller. The gas accumulates in that low-pressure area over a period of time. Once this gas accumulates into a long continuous column in the pump such that the pump no longer generates any discharge pressure, gas-locking occurs, and the equipment shuts down on amperage underload. The amount of gas a pump can handle without the threat of gas-locking has depended on stage designs and sizes. The smaller flow pumps with radial stages have been known to handle 10% to 15% free gas by volume or .11 to .17 vapor-to-liquid ratio, whereas the larger flow pumps with mixed flow staging can tolerate 20010 to 25 % free gas by volume or .25 to .33 vapor-to-liquid ratio. Many ESP applications today are requiring the ability to handle 30% to 50010 free gas by volume in the smaller flow pumps and 40010 to 60% free gas by volume in the larger flow pumps. The Lake of Mamcaibo wells have high gas-oil-ratios. Producing them with the standard ESP configuration was not considered a feasible option. However, the present gas lift production is declining and is resource costly. If it could be determined that the new AGH technology expanded the envelope to at least 40010 free gas by volume capability for an ESP system, it would be a production option for these wells.