Antonio Carlos Capeleiro Pinto

Marlim Complex Development: A Reservoir Engineering Overview

Since the discovery of the Garoupa Field in the Campos Basin, Rio de Janeiro, Brazil, in 1973, Petrobras has been moving to deeper waters. Subsea engineering and well technologies have been developed and applied to overcome the environmental restrictions. Today more than 50% of Brazil’s oil production comes from fields located offshore in water depths over 1,000 m. In this scenario, the Marlim Complex – which comprises the Marlim, Marlim Sul and Marlim Leste fields – plays an important role. Discovered in 1985, the Marlim Field started production in 1991, with a pilot system comprising 7 wells connected to a semi-submersible unit moored in a water depth of 600 m. Currently, the field production is about 85,000 m/d (535,000 bpd), with 60 producers and 32 water injectors connected to 7 floating production units. As with other Campos Basin turbidites, the Oligocene/Miocene reservoir of Marlim Field presents 3 outstanding characteristics: predictability, from seismic data and geological modeling, excellent petrophysical properties and good hydraulic connectivity. The extensive use of 3D seismics as a reservoir characterization tool allows the reduction of risks and the optimization of well locations. Additionally, 3D visualization techniques provide a new environment for teamwork, where seismic data is interpreted and input into detailed reservoir simulation models. Among the deep water well technologies employed to develop the Marlim Complex it is worth mention: slender wells, high rate well design, horizontal and high angle wells in unconsolidated sands, efficient low cost sand control mechanisms, selective frac-pack with isolation between zones, pressure downhole gauges (PDG’s), new techniques for the connection of flowlines and X-mas trees, subsea multiphase pumping and special techniques to remove paraffin in the flowlines. However, new developments are required, such as extended reach wells, selective completion in gravel-packed wells, isolation inside horizontal gravel-packed wells with External Casing Packers (ECP’s), smart completion and improved recovery techniques for viscous oil. Much has been learned during the planning and development of the Marlim Field and this knowledge is currently being applied in the development of Marlim Sul and Marlim Leste fields. Some important points must always be observed: a) the development plans must be defined by using optimization techniques considering the geological risks; b) the number of wells of the initial development plan must be defined through a detailed optimization study, considering economic indicators, oil recovery and risks; c) the wells must be designed to allow high production rates, with “rest of life” completions, as simple as possible; d) the sand control mechanisms must be simple, efficient and low cost, e) the seismic resolution or the production data analysis must be of sufficient quality to guarantee that there will be good hydraulic connectivity between the producers and the corresponding injectors; f) the pipelines and risers must be designed to avoid bottle-necks or conditions for deposition of wax or hydrates and g) the reservoir management and particularly the water injection system management must be made with an integrated teamwork approach. In this paper we present some aspects of the reservoir engineering and of the development plan of the Marlim Field and briefly discuss how this experience is being used in the development of the neighboring Marlim Sul and Marlim Leste fields. Introduction The Marlim Complex comprises 3 giant deepwater oil fields – Marlim, Marlim Sul and Marlim Leste – located in the Campos Basin, 110 km offshore Rio de Janeiro, Brazil (Fig. 1). Besides the geographic location, these fields have other similarities: the main reservoirs are turbidites of Oligocene / Miocene age; 3D seismic data allows accurate prediction of the reservoir occurrence; rock characteristics are excellent; relative permeabilities are favorable to water injection and well productivities are very high. SPE 69438 Marlim Complex Development: A Reservoir Engineering Overview Antonio C. Capeleiro Pinto, SPE, Solange S. Guedes, SPE, Carlos H. L. Bruhn, J. Adilson T. Gomes, SPE, Andrea N. de Sá, SPE, and J. R. Fagundes Netto, PETROBRAS S. A. 2 PINTO, A. C. C., GUEDES, S. S., BRUHN, C. H. L., GOMES, J. A. T., N. DE SÁ, A. AND FAGUNDES NETTO, J. R. SPE 69438 The Marlim Field was discovered in 1985 by an exploratory well drilled in a water depth of 850 m, which found 70 m of the Oligocene / Miocene reservoir saturated with 20 API oil. Four additional appraisal wells delimited the accumulation, and the STOIIP is estimated at 1,020 million STD m (6,416 million STB). The field area is 165 km and the water depth range is 600 1100 m. The oil API changes from 18 and 21 in the main field area, the oil viscosity in the reservoir is between 4 and 8 cp and the saturation pressure is 22 kgf/cm below the original pressure of 287 kgf/cm. Rock characteristics are excellent. To investigate well performance, reservoir connectivity, oil flow in low temperature pipelines, and also to test well completion and subsea technology, a production pilot was implemented in 1991. Seven subsea wells located in the northern field area were connected to a semi-submersible unit, Petrobras-20 (P-20), moored outside the field area in order to reduce interference with development. All of the seven wells were perforated in the uppermost sand of the reservoir. The production pilot supplied important information which guided subsequent phases of the field development: a) RFT’s in new wells showed that all sands depleted at almost the same rate, showing that the reservoir has good vertical communication; b) subsequent wells drilled in the southern part of the field also depleted, proving reservoir continuity; c) material balance could be used to calibrate the reservoir volume calculated from geological mapping; d) for the longer flowlines, paraffin deposition reduced well potential, requiring remedial actions. In 1994 the first production unit of the definitive system, a semi-submersible unit named P-18 started operation, moored in a water depth of 910 m. This unit was designed considering oil processing capacity of 16,000 m/d (100,000 bpd) and water injection capacity of 24,000 m/d (150,000 bpd). Five additional units were installed in the field, and the present situation is shown in Table 1. Currently, Marlim Field production is around 85,000 m/d (540,000 bpd), the water injection is 101,000 m/d (640,000 bpd) and the recovery factor to date is 7.2%. The water production is 3,300 m/d (BSW = 3.7%) and GOR is equal to the initial solubility ratio, 80 m/m. A total of 92 wells are operating, with 60 producers and 32 water injectors. The field development will be completed by the end of the year 2001, when the production peak will be reached. The Marlim Sul Field is located directly south of Marlim, comprising an area of more than 600 km, under water depths ranging from 1,000 to 2,600 m. The field was discovered in 1987 by an exploratory well drilled in 1250 of water depth which found 40 m of the Oligocene / Miocene age reservoir saturated with 25 API oil. Subsequently, 12 appraisal wells completed the field delimitation. The field STOIIP is estimated at 1,400 million STD m (8,806 million STB), 90% in Oligocene / Miocene reservoirs and 10% in Eocene reservoirs. Oil API reaches 28 at the northern part of the field and decreases as water depth increases. As for the neighboring Marlim Field, reservoir characteristics are excellent. However, stratigraphy is more complex, and predicting and identifying the reservoir compartments is an important and difficult task. To date 19 reservoir blocks have been identified and mapped in Marlim Sul, but hydraulic connectivity between them is not completely understood. To investigate the reservoir performance 3 production pilots were implemented in the field: (1) In 1994 Well MRL-4, drilled in 1,027 m of water depth, started production to the platform P-20 in Marlim Field, flowing through 20 km of subsea pipeline. Currently it produces to P-26 through a 7 km flowline with a rate of about 1,800 m/d. The material balance indicated that this well produced from a 170 million m STOIIP reservoir. In 1999 an injector in this block was connected to P-26, for pressure maintenance; (2) In 1997 the subsea completion world-record well MLS-3B, drilled in a water depth of 1709 m, was connected to a Floating Production Storage and Offloading (FPSO) through 3 km of subsea flowline. This well produced 16.5 API oil during almost one year, having reached a production peak of 1,500 m/d. New subsea technology developed by the Petrobras Technological Program on UltraDeep Water Explotation Systems (PROCAP) were successfully tested in this well. Besides, information regarding low temperature oil flow in pipes and gas-lift performance were obtained and allowed the calibration of the multiphase flow correlations. (3) Finally, in 1999 Well MLS-2, drilled in a water depth of 1,230 m was connected to the aforementioned FPSO, now repositioned to a shallower water depth. This well produces 2,500 m/d of 22 API oil through a 3.5 km flowline. Again, production has allowed for material balance and the calculation of the oil volume connected to the well. The information obtained in these pilot production systems guided the development plan of the Marlim Sul field. The first production unit, the semi-submersible P-40, is schedule to start production in July, 2001, and 17 of its 28 development wells have already been drilled. New seismic data, acquired in the beginning of the year 2000, is helping to define the reservoir structure and internal stratigraphy and consolidate the development plan for the whole field. The Marlim Leste Field was discovered in 1987 by an exploratory well drilled in a water depth of 1230 m. The well found 70 m of the Oligocene / Miocene reservoir saturated with 19.5 API oi

4D integrated technologies for deep-water turbidite reservoirs:from petrophysics to fluid flow simulation

Petrobras has been developing its 4D seismic technological programme since 1998, focused on the Brazilian deep-water fields in the Campos Basin, and considering the technical, operational and economic challenges involved in the development plan and reservoir management in this environment. The first step was to align the objectives of the project with the company goals for the following 15 years, in terms of earnings growth, production growth and reserves replacement. This information guided how the 4D reservoir management should be employed: as hedging technology to ensure that production targets would be achieved in several key fields at once, or as a direct technology investment to increase the production of individual, independent fields. The mission of reservoir management for each field involved was understood and new deep-water seismic technologies were developed to face the global operational and economic targets. 3D seismic reservoir monitoring, or 4D seismic study, was defined as an ‘integration of multidisciplinary technologies that includes the time-lapse monitoring of the drainage efficiency, using cores, well logs, seismic data, production history and pressure management’. Water injection is the preferable recovery method for the deep-water reservoirs in Brazil. Therefore, seismic monitoring should be able to distinguish contrasts of both fluids – injected water and remaining oil – that normally produce small seismic impedance values. This characteristic has brought the first technical challenge: the use of the 3D P-wave surface legacy data from the 1980s and 1990s, when the major fields started production, as 4D base-volumes to be correlated with future recommended 3D seismic data (surface or ocean bottom systems) as 4D monitor-volumes. In addition to all developed seismic technologies for data processing, a general 4D work flow was designed and the concept of the integrated reservoir model was adapted to relate all such technologies to the reservoir engineering needs and to the field economics, generating reliable 4D images for each reservoir study. This paper summarizes the multidisciplinary technical integration, including geological and seismic modelling, petrophysical simulations, seismic processing and interpretation, and reservoir simulation. A 4D methodology was implemented to integrate all such technical development and economic analysis, identifying where, when and how seismic monitoring can contribute to the reservoir management. This methodology has been applied to the Campos Basin deep-water reservoir, Rio de Janeiro State, Brazil.