TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe discovery of new fields in the Amazon forest and in deep water offshore Campos Basin, all of them consisted of unconsolidated sand, led Petrobras to adopt non conventional wells and sand control techniques. The main goals were to increase productivity, delay gas/water conning and support unconsolidated formations in water injection wells.The first horizontal well was completed in December 94 in Rio Urucu field. Since there was only one zone to drain the barefoot completion was suitable to all fields. This paper will describe the experience acquired running screens in 28 horizontal open hole wells in Brazil. Among them 19 have been producing oil and 1 injecting water. The other 8 haven't been connected yet to platforms so only results of production( or injection) tests will be reported.Several improvements were made on the equipment, drilling fluid, procedures and in the well design due to the problems faced during the execution of the jobs.As a result, the main objectives were achieved and new trends were established aimed at deep water fields development.Recently, some horizontal wells have been gravel packed and better productivity indexes were reached. The main issues and results for those gravel packings( three jobs so far) will be mentioned.

Reliability of completion equipment and rig time are becoming more and more critical for subsea completions because of continually increasing water depths in which operators are being required to complete wells. In addition, completion designs must reflect the more stringent economic requirements of today's oil and gas industry. This paper will describe the use of a single-trip completion system that has been successfully and economically installed in the offshore Marimba and Bonito fields of South America. This new completion system has the capability to land the tubing hanger and install it in the wellhead before setting the packer and compensating for subsequent tubing movement. The new system also can employ pre-job calculations - based on initial well conditions and anticipated conditions during production - that help determine appropriate completion configurations and bottomhole equipment compatibility. Many failures in offshore wells, whether platform or subsea, can be attributed to inappropriate application of downhole completion tools or methods. Use of pre-job calculations during the equipment design stage can facilitate proper selection of design criteria and can help ensure operational safety and cost efficiency. The development of this new completion system will be discussed in detail. Three case histories that document successful test completions will be reviewed along with the economic gains and advantages that the reduction in rig time generated. Introduction Subsea completions were introduced to offshore operations in Brazil in 1977. Early "wet" installations were run in the Enchova field in water depths of approximately 400 feet [120 m] with production back to a floating production system. To date, 448 completions have been installed offshore and account for almost 60 percent of the country's production. Of these, 198 subsea completions have been installed in increased water depths. In 1985, discoveries were made in the giant deep-water Albacora, Marimba and Marlim fields at water depths ranging from 650 feet [200 m] to 6,500 feet [2,000 m]. There are indications that a new field exists south of Marlim at even greater water depths (Figure 1). History Subsea completions that were run in increased water depths during the late ‘70’s and early ‘80’s identified several problems. The traditional completion design called for a standard hydraulically-set retrievable packer, and movement compensation was accomplished through use of a tubing seal divider (TSD). A traditional subsea completion design is shown in Figure 2. P. 181^

Reliability of completion equipment and rig time are becoming more and more critical for subsea completions because of continually increasing water depths in which operators are being required to complete wells. In addition, completion designs must reflect the more stringent economic requirements of today's oil and gas industry. This paper will describe the use of a single-trip completion system that has been successfully and economically installed in the offshore Marimba and Bonito fields of South America. This new completion system has the capability to land the tubing hanger and install it in the wellhead before setting the packer and compensating for subsequent tubing movement.1 The new system also can employ pre-job calculations-based on initial well conditions and anticipated conditions during production-that help determine appropriate completion configurations and bottomhole equipment compatibility. Many failures in offshore wells, whether platform or subsea, can be attributed to inappropriate application of downhole completion tools or methods.2 Use of pre-job calculations during the equipment design stage can facilitate proper selection of design criteria and can help ensure operational safety and cost efficiency. The development of this new completion system will be discussed in detail. Three case histories that document successful test completions will be reviewed along with the economic gains and advantages that the reduction in rig time generated. Introduction Subsea completions were introduced to offshore operations in Brazil in 1977. Early "wet" installations were run in the Enchova field in water depths of approximately 400 feet [120 m] with production back to a floating production system. To date, 448 completions have been installed offshore and account for almost 60 percent of the country's production. Of these, 198 subsea completions have been installed in increased water depths. In 1985, discoveries were made in the giant deep-water Albacora, Marimba and Marlim fields at water depths ranging from 650 feet [200 m] to 6,500 feet [2,000 m].3 There are indications that a new field exists south of Marlim at even greater water depths (Figure 1). History Subsea completions that were run in increased water depths during the late '70's and early '80's identified several problems. The traditional completion design called for a standard hydraulically-set retrievable packer, and movement compensation was accomplished through use of a tubing seal divider (TSD). A traditional subsea completion design is shown in Figure 2. Since gas lift is the only artificial lift method available for subsea wells in this area, the design criteria for most of these completions reflect future gas lift operations.4 In these completions, the bottomhole assembly (packer and TSD pinned in the fully-closed position) would be run into the wellbore to the desired setting depth. Once the packer was anchored, the TSD was shear released. Completion times for these conventional subsea well completions averaged approximately four days from the time the tubing and bottomhole assembly were started into the wellbore until the tubing hanger was set and tested.

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This paper was prepared for presentation at the 1998 SPE International Conference on Horizontal Well Technology held in Calgary, Alberta, Canada, 1-4 November 1998.