The Marlim field was discovered in February 19859 by the exploratory 1 RJS 219 A drilled in a water depth of 850 meters. This pushed the deepwater exploratory campaign culminating in several deep and ultra-deep water discoveries in Campos Basin. The necessity to overcome the environmental conditions, associated with a giant field located in high water depth and reservoir characteristics, were the main challenges in the search for new technologies in the way to operate the field. These developments were achieved by a research program created at Petrobras R&D Center. This program counted on Petrobras expertise acquired during Campos Basin development and with traditional oilfield equipment suppliers through technological agreements that led to the first oil in March 1991. The field extension and the reservoir characteristics required a large number of subsea wells and, consequently, several production platforms, so the development plan was based on the implementation of several phases in different periods. This model, also used in several other developments in Campos Basin, allowed that the required huge investments and resources to be distributed along the field development. Moreover, it allowed innovative solutions to be proposed and introduced by new oilfield equipment suppliers along the project in order to optimize CAPEX. Marlim is a remarkable achievement to the oil industry that culminated with a peak production of 650,000 bopd in 2002. It also served as a laboratory for other deepwater developments offshore Brazil. With the field maturation new challenges are being faced in order to increase the recovery factor and to reduce the OPEX. This paper will provide an overview of Marlim Field, the main achievements and problems faced up to this moment to manage its development. Introduction The Marlim field was discovered in February 1985 by the exploratory well 1 RJS 219 A drilled in a water depth of 850 meters. This discovery pushed the deepwater exploratory campaign culminating in several deep and ultra deepwater discoveries in Campos Basin. Located in the northeastern part of Campos Basin, about 110 km offshore the state of Rio de Janeiro, the Marlim field is part of the Oligocene Carapebus formation and covers an area of approximately 130 Km2, in water depths ranging from 650 meters to 1,050 meters. From rock quality point of view Marlim field Oligocene reservoirs are excellent with average porosity around 30%. The reservoirs have low silt, clay and calcite content. The core analyses of various wells indicate mean permeability of 2000 mD, mean porosity of 30% and highly friable sandstone. Marlim's reservoir exploitation strategy relies heavily on water injection as a source of reservoir energy replenishing. The field development plan was based on various phases by means of subsea wells, subsea manifolds and floating production units whose development had been scheduled in different periods in order to make feasible the huge investments and resources required. It also improved the overall performance of the field development once each phase guided the next ones through the experience obtained during its own development. To support the field development, a research program was created in the company in 1986 - the PROCAP - focusing on all the technologies required to install the first Floating Production Unit for the Marlim field.

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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